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 6 th Avenue Portland, OR 97204

Re: Comment: Portland General Electric Boar dman Plant BART Analysis Revision 3-- 2020 Alternative Analysis

Dear Mr. Finneran:

These comments are submitted on behalf of Si erra 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 Po rtland General Electric’s (PGE) letter of October 22, 2010 as not in compliance with federa l law and regulation; and (2) retain BART compliance alternatives consistent with the ear lier cessation of coal-f ired operations at the Boardman plant (the “Plant”).

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

closure of the Boardman Plant as part of the BART process. Th at 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 Pl an, adopted in 2009, requires: new low Nitrogen Oxides (NO

x ) burners, with a modified over-fire ai r control system to be installed in 2011, and selective catalytic reduction (“SCR”) de vices to be installed in 2017, to control the
Plant’s NO

x emissions; as well as semi-dry flue gas de sulfurization (“FGD”) to be installed in 2014 to control the Plant’s sulfur dioxide (“SO 2 ”) emissions.

This year, the Department proposed amendmen ts 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 emi ssions to 0.19 lb/MMBtu; and a semi-dry FGD system in 2014 to control SO 2 emissions to a level of 0.12 lb/MMBtu. The Department’s 2018Brian Finneran Oregon Department of Environmental Quality November 15, 2010 Page - 2 -

closure alternative includes the same NOx c ontrols, but requires only Dry Sorbent Injection (“DSI) by 2014, to reduce the Plant’s SO 2 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 stringen t requirements: a “BART Approach” that
would allow it to continue co al-fired operations until Decemb er 31, 2020, employing only DSI to
control the Plant’s SO 2 emissions to a level of 0.4 lb/MMBtu in 2014, and 0.3 lbs/MMBtu in 2018, contingent upon “testing . . . of the installed SO 2 control system to confirm the applicable

SO 2 emissions limit is achievable without causing an exceedance of PM10 or PM2.5 ambient standards, preventing PGE from meeting merc ury reduction goals, or causing significant operational issues.” Letter fr om Stephen Quennoz to Dick Pedersen dated October 22, 2010 (“PGE Letter”); Portland Genera l Electric Boardman Plant Be st Available Retrofit Technology Reasonable Progress Analysis Revision 3: Boardman 2020 Alte rnative (“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 PG E’s alternative, it s hould retain a 2018 a lternative (as detailed below). The Boardman plant will soon be s ubject to National Emissions Standards for Hazardous Air Pollutants. It is currently in vi olation of the Act’s Prevention of Significant
Deterioration and New Source Performance Standa rd requirements. Impending regulatory or judicial actions will, therefore, likely rende r 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 satisf y the Act’s other requirements. The Department should, therefore, ensure that t hose alternatives remain availa ble 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 de monstrate how PGE and the Department’s BART analysis for SO 2 and NOx overestimates cost and is incorrect in its feasibility determinations for certain BART tec hnologies. Finally, this letter will address how the Department’s cost-effectiveness determinations must take into accoun t the very large number of Class I areas that are affected by these dete rminations and the failure of the 2020 Alternative to achieve an acceptable level of reasonabl e further progress required by the law.Brian Finneran Oregon Department of Environmental Quality November 15, 2010 Page - 3 -

I. PGE’S 2020 BART ANALYSIS MI S-APPLIES THE G OVERNING LEGAL

FRAMEWORK.

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

.

PGE’s proffered 2020 alternative requires PG E 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 Revi sions”) p.3. It does not require PGE to install and operate the system unless: (a) opera tion of the DSI system triggers no further obligations under Oregon’s mercury rule; (b) op eration 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 “s ignificant operational issu es.” PGE Letter at 2, Proposed Revisions at 4. Unless those conditions are met, PGE n eed only utilize relatively lowsulfur coal, thereby limiting its SO 2 emissions to .6 lb/MMBtu. PGE justifies those conditions – effectively, an exemption from BART – by contendi ng that DSI is not tec hnically feasible unless they are satisfied. PGE 2020 Alternative Analys is 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”) im plementing regulations make clear, “[c]ontrol technologies are technically feas ible 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 sour ce 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 th e 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 th at DSI is technically infeasible because it would interfere with PGE’s compliance with stat e mercury reduction goals, or result in adverse impacts to the particulate matter air quality standards. As a le gal 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 or der to avoid another (Prevention of Significant Deterioration or “PSD”). Moreover, as a practi cal matter, even if operation of DSI triggers additional legal obligations, thos e obligations will not prevent PG E from continuing to operate the Plant. Should DSI result in particulate matte r emissions sufficient to trigger Prevention of Significant Deterioration Review, and to affect compliance with particulate matter air qualityBrian Finneran Oregon Department of Environmental Quality November 15, 2010 Page - 4 -

standards, PGE would be required either to inst all a bag-house at the Plan t, or to secure offsetting reductions in partic ulates. New Source Review Workshop Manual: Prevention of Significant Deterioration and Nonattainment Ar ea Permitting (U.S.E.P.A. Draft October 1990) at p. C.52-53. While those additional steps might en tail 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 tec hnically feasible BART limit. 42 U.S.C. § 7491(b)(2)(A). DSI is technically feasible, as explaine d in greater detail below. But if it were not feasible, the Department would need to undertake a full five-fact or BART analysis that specifies a limit based on some other, feasible control technology. PGE instead asks the De partment to set a limit of 0.6 lb/mmBTU, based on the reductions available thro ugh 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 “f easibility” exemption from compliance with full BART requirements. PGE must comply with all applicable Clean Air Act requirements.

B. The Department Cannot Give “Remaini ng 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 m odifying 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 considerat ion 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 annuali zed figures reflecting th e useful life of the facility, EPA’s regulations accomplish the consider ation 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 cost s over a limited time-frame, the Department should limit its BART obligations b ecause DSI has lower capital costs, and higher operating costs, than an FGD sy stem. PGE 2020 Alternative Analys is at 8-2. The Department

1 While this has been described as a “50% reduc tion 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’ re gional haze SIPs include emission limitations representing BART for each BART-eligible sour ce. 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 con tinuous 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 consider ation the technology available, the costs of compliance, th e energy and non-air quality environmental impacts of compliance, any pollution contro l 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 anti cipated to result from the use of such technology.

40 C.F.R. § 51.301.

BART is to be determined based on a five fact or analysis. 40 C.F. R. Part 51, Subpart Y,
Section I.F.1. EPA’s five factor analysis requiremen ts 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-eligib le source that is subject to BART within the State. In this analysis, th e State must take into consideration the technology available, the costs of comp liance, the energy and nonair quality environmental impacts of compliance, a ny 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 anti cipated 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 si gnificant deterioration permitting requirements. EPA guidance requires that in evaluating BACT for a particular source, if similar sources have had to bear ce rtain 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”), a nd 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 in to account in determining BART. Another is the degree of visibility improvement expected fro m the controls being evaluated as BART. The Department, along with many other states and the FL Ms, have evaluated the cost per deciview of visibility improvement ($/dv) in its BART analysis. And, again, co mparing this to the costs that have been required to be borne by similar s ources helps to ensure BART is interpreted consistently across similar source categories.

EPA has also published BART guidelines to en sure 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). Rega rdless, states are required to have a reasoned basis for their case-by-case BA RT determinations and the methodology laid out in the BART guidelines provides a solid fr amework 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 wild erness areas. EPA’s regi onal haze regulations set a target date for natural visibility conditi ons 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 “gli de path” to reach natu ral background visibility conditions by 2064. The first reasonable prog ress milestone is 2018. 40 C.F.R. §51.308(f). Indeed, EPA refers to the BART re quirements as one of the “princip al 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 SI P (pursuant to 40 C.F.R. §51.308(e)(1)(iv)), the BART requirements will greatly he lp states in achieving the firs t reasonable progress milestone
in 2018.

B. A Semi-Dry FGD System Is a Cost-Effective BART Control For SO 2 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 Work shop 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-d ry FGD system designed to meet an SO 2 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 Pl ant at 18. Specifically, the Department determined that a semi-dry FGD system designed to meet an SO 2 limit of 0.12 lb/MMBtu at Boardman but with a 6.5 year life would cost $5,535/ton of SO 2 removed. Id. at 11. The Department found this cost was within the range of costs required as BART for SO 2 at other

sources. Id. at 18. The Department also determined th at a semi-dry FGD system would be costeffective when evaluated on a dollar per deci view improvement basi s. 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 indica tes; the Department’s costs estimates for the system are far too high and include cost s 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 esti mates for semi-dry FGD to the cost estimates provided in its December 2008 report (which we re in 2007 dollars) shows that the increase reflected in the Department’s 2010 cost estimates is not justified. Specifica lly, the capital cost of a semi-dry FGD in the Department’s 2010 BA RT 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 E ngineering Plant Cost Index (CEPCI), there was only a 5.9% increase in plan t 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).” EP A’s Control Cost Manual does not include AFUDC costs in determining capit al 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 pr ojects, but rather reta in engineering firms,

5 The EPA’s BART guidance specif ically recommends the use of th e EPA Control Cost Manual. See 70 Fed. Reg. 39166.

6 See Attachment B DEQ 2010 BART data spread sheet as compared to December 2008 DEQ BART Report at 19 (Table 15).

7 In June 2010, the CEPCI index was 556.4, as co mpared 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 se parately 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 exam ple, EPA rejected the inclusion of "owner's costs" in a cost analysis fo r 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 CEPC I 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 a nnualized 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 SO 2 removed. 10 The Department’s cost effectiveness numbers presented in its 2010 BART report for an semi-d ry FGD with a 6.5 year life are too high.

2. PGE’s estimates and analysis.

In contrast to both the Department’s analys is 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 SO 2 removal at Boardman. See PGE’s July 30, 2010 Letter to the Department at 13. Given the CEPCI index da ta for 2006 and June 2010, PGE’s projected cost increase is not justified.

A closer evaluation of the deta ils that went into PGE’s new semi-dry FGD cost analysis shows that PGE improperly included costs th at 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 Re gional 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 Depart ment’s cost data, Attachment B to its 2010 Boardman BART Analysis Boardman. The De partment’s projections of annual operating expenses or the assumed SO 2 removed per year were not revise d. 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 Depart ment also improperly included such owner’s cost, but at a much lower amount ($6.4 million per year 11 ). 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 million 12 ). PGE’s revised semi-dry FGD cost analysis also includes $9.8 million in property taxe s in the capital cost estimate. Id. Pollution control equipment is typically exempt fr om property and sales taxes, wh ich are usually assumed to be

zero. 13

These discrepancies with th e EPA’s Control Cost Manual, and with the CEPCI data, show that PGE’s cost estimates for semi-dry FG D 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 SO 2 emission rate of 0.12 lb/MMBtu, whic h only reflects approximately 80% SO 2 removal from current coal used at Boardman. Semi-dry FGD system can achieve 90-95% SO 2 removal. 14
Proper consideration of the SO 2 reductions that can actually be achieved with a semi-dry FGD system would thus show an even lower le vel of cost effectiveness than $4,697/ton.

Finally, a review of the SO 2 control costs required in othe r BART determinations shows
that even an SO 2 control cost of $6,500/ton is not out of the range of other SO 2 BART determinations. According to the Nati onal Park Service’s summary data of SO 2 BART determinations, the costs for SO 2 BART determinations ranges up to $7,309/ton of SO 2 removed. 15 And it must be noted that the National Park Service summary spreadsheet does not
include the cost data for the San Juan Genera ting 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 SO 2 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 Co nservation Association at 12-13.

15 See National Park Service Spreadsh eet EGUs with Proposed BART SO 2 Controls, Updated August 2010, Exhibit 1.

16 As discussed in the Department’s BART Repor t 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 effectiven ess 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 technica l feasibility of DS I 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 boile r 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 un its equipped with electrostatic precipitators (ESPs), and the units burn low su lfur 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 inconsequentia l as to whether DSI is technically feasible

at Boardman. The factors that a ffect 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, Dr y Sorbent Injection as an Alternative to Scrubbers, 8 th slide (Exhibit 12).

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

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

19 See ENSR Corporation, BART An alysis for the Kincaid Power Plant, January 2009, at 1-2 (Exhibit 3).

20 See “Edison Mission Energy to Use Trona for SO 2 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 1500oF 21

Most of these factors are irrelevant to th e boiler type or size. While the flue gas temperature can impact the SO 2 removal efficiency with DSI, sorbent injection can work at a wide range of flue gas temperatur es. The question is not whether DS I is technically feasible with
the 600 MW Boardman boiler. It is more a matter of the level of SO 2 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 SO 2 control effectiveness when compared to other SO 2 control technologies like semi-dry or wet scrubbers, not t echnical feasibility. Because more sorbent is required with higher SO 2 emissions from larger boilers, the cost of sorbent for DSI and potential need for additional particulate controls or upgrades likely make other SO 2 control technologies like dry scrubbers more cost effectiv e. These factors do no t render DSI technically
infeasible for SO 2 control at Boardman. It is feasible for use at a boiler like Boardman, and DSI can achieve a much higher level of SO 2 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 SO 2 , PGE claimed that it would reduce SO 2 to 0.6 lb/MMBtu with the use of lower su lfur coal and that DSI could reduce SO 2 to a rate of 0.4
lb/MMBtu. 22 That is, the DSI evalua ted by PGE would only reduce SO 2 by 33% from the
uncontrolled emission rate that would be achie ved through the burning of lower sulfur coal. 23

PGE’s baseline SO 2 emission rate is 0.61 lb/MMBtu, wh ich is already based on burning lowsulfur coal at Boardman. 24 Thus, an SO 2 limit of 0.4 lb/MMBtu only reflects a 34% SO 2 removal efficiency with DSI. To achieve this rate, PG E assumed a sorbent inject ion 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 SO 2 Mitigation at A Coal-Fired Power Plant, Electric Powe r 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” SO 2 emission rate. PGE’s August 2010 BART Alternative Submittal at 8-3. Given
that Boardman does not emit SO 2 at its current allowable SO 2 emission rate, this comparison is irrelevant for visibility protec tion 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 PG E’s August 2010 BART alternative submittal to the Department. However, PGE failed to provide th e details behind its costs estimates. The design

and cost details must be obtaine d and analyzed by the Department in order for the state and the public to fully evaluate its estimates of contro l 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 millio n 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 th at PGE stated would be needed to achieve the proposed 0.40 lb/MMBtu SO 2 emission limit.

Based on available information, 4 tons per hour is a very high sorbent injection rate to
achieve 33-34% SO 2 removal. According to information from Solvair, a vendor of trona and sodium bicarbonate, an SO 2 removal rate of 33-34% should be achievable with trona injection at

a normalized stoichiometr ic ratio (NSR) of 0.5. 27 At an NSR of 1.0, it takes 2.41 pounds of trona per pound of SO 2

. 28 Thus, an NSR of 0.5 equates to 1.21 pounds of trona per pound of SO 2 to achieve a 33-34% SO 2 removal rate. The amount of SO 2 emitted per hour on average by Boardman would range from 1.66 to 1.99 t ons per hour, depending on capacity factor 29 and
whether lower sulfur coal was utilized. To achieve 33-34% SO 2 removal with trona injection at Boardman should take approximately 2 to 2.4 to ns per hour of sorbent injection. Yet, PGE assumed 4 tons per hour of sorbent injection, whic h is correlated with an NSR of 1.0 and which
should obtain an SO 2 removal efficiency of approximately 60%. 30 Thus, PGE overestimated the amount of sorbent to be inje cted based on its claimed SO 2 removal efficiency and/or it
underestimated the amount of SO 2 that would be removed with DSI at Boardman. Either way, the result is that the costs of DSI per ton of SO 2 removed were overstated.

Assuming only 33-34% removal of SO 2 needed and an average of 2.2 tons per hour of trona with operations at an 85% capacity factor, that would m ean 16,400 tons of trona would be

26 Id. , Appendix D at D-8.

27 See SOLVAir® Select 200 Applica tion Guide, Exhibit 6, at 4 th page, available at http://www.solvair.us/mediali brary/1,,59154-2-1,00.html#brochures.

28 Id. at 3 rd 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 ba sis for evaluation of other BART controls. See Appendix C of PGE’s August 27, 2010 PGE Boar dman BART/Reasonable Progress Analysis,
Revision 3: Boardman 2020 Alternat ive and, in particular, page C-13.

30 See SOLVAir® Select 200 Applica tion Guide, Exhibit 6, at 4 th pageBrian Finneran Oregon Department of Environmental Quality November 15, 2010 Page - 13 -

needed per year at Boardman to meet the proposed 0.40 lb/MMBtu SO 2 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, PG E 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 fo r 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 s eem justifiable to add in the cost of milling the trona for PGE’s proposed SO 2 limit.

If sodium bicarbonate is used in stead of trona, the cost per to n is higher but less has to be
used to achieve the same level of SO 2 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 maximu m 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 SO 2 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% SO 2 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 operati ng cost based solely on the amount and costs of sorbent improves cost-effectiveness of DS I from PGE’s estimate of $3,380/ton to $2,090/ton

of SO 2 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 SOLV Air Solutions, November 4, 2010.

35 Id.

36 See Norman, Jon et al., Decision Matrix for Dry So rbent Duct Injection for Control of Sulfur Oxide Emissions from Combustion Processes, Figure 1 at 2 (Exhibit 8). If less than 50% control
of SO 2 is required, then use of trona or hydrated lime is recommended.

37 This dollar per ton SO 2 removed figure assumes, as PGE did, that sorbent injection wouldBrian Finneran Oregon Department of Environmental Quality November 15, 2010 Page - 14 -

The costs for waste disposal are also overestimat ed, especially given the overstatement of the
amount of sorbent needed to achieve 34% SO 2 removal. PGE assumed $4.06 million per year for waste disposal. 38 Assuming 16,400 tons of trona are required to achieve 34% SO 2 removal at Boardman, this cost for waste disposal is $240 per ton of trona injected. This seems exorbitantly high. PGE did not provide any deta ils that went in to its cost calculations, but one could assume
that PGE overestimated the amount of waste fo r 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. Ad justing 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 SO 2 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 i ndicates 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 system s 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 in jection was hauled off-site, a disposal cost of $120/ton – half of what it appears PGE assume d - 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% SO 2 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 operationa l 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, includi ng owner’s costs, allowance for funds used during construction (AFUDC), and taxes. Thes e costs that were improperly included in the

reduce SO 2 by 5,188 tpy. See PGE’s August 27, 2010 Boardman BART/Reasonable Progress Analysis, Revision 3: Boardman 202 0 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 Me rcury and MultiPollutant Emission Control Technology Applications on Elect ric Utility Boilers, EPA-600/R-03-110 (October 2003) at 52-

53.

41 See United Conveyor Corporation, UCC Dry Sorbent Injection, Dr y Sorbent Injection as an Alternative to Scrubbers, 44 th 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 woul d need to be added to the cap ital costs of a DSI system at

Boardman.

The capital costs also appear overstated fo r the purchase of the sorbent injection equipment. SOLVAir has indicated that the capit al 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 th e 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 in jection 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 pur chase and installation is still too high. A 2007 paper indicates the costs of DSI to achieve 50-60% SO 2 reduction were projected to be $15-25/kW. 44 A recent presentation by United Conveyor Co rporation states that capital costs for installation of a DSI system designed to achieve 50% SO 2 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 injecti on system could be readily installed in a years’

time. 46 Thus, a December 2011 installation date an d 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 SOLV Air Solutions, November 4, 2010.

43 See PGE’s August 27, 2010 PGE Boardman BART/R easonable Progress Analysis, Revision 3: Boardman 2020 Alternative, Appendix D at D-9.

44 See Day, Keith C., Duct Injection for Control ling SO3, SO2, CO2, Hg & NOx, Electric Power, May 2007, at 13 (Exhibit 9).

45 See United Conveyor Corporation, UCC Dry Sorbent Injection, Dr y Sorbent Injection as an Alternative to Scrubbers, 44 th slide (Exhibit 12).

46 See Day, Keith C., Duct Injection for Control ling 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 cost 47 would equate to an annualized capital cost of $2.7 millio n 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 wh ich 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 SO 2 , an annual cost of $6.92 million reflects a cost effectiveness of $1,334 per ton of SO 2 removed at Boardman. However, as set forth below, DSI can achieve even greater SO 2 control than 34%, which would correspondingly lower the costs per ton of SO 2 removed with DSI even more.

4. DSI can achieve greater SO 2 emission reductions than assumed by

PGE.

As previously noted, PGE assumed that DSI could remove 33-34% of the SO 2 . This assumption was on the low end of the SO 2 removal efficiency that can be achieved with DSI. The removal efficiency of sorbent injection typica lly increases as more sorbent is injected. For example, trial testing with Solvair Select 200 (trona) shows that 90% SO 2 removal can be
achieved with a NSR of 1.8-2.0. 48 Tests from a permanent installation of unmilled trona showed
70-85% SO 2 removal achieved with trona injected at an NSR of 1.5 to 3.0. 49 Sodium bicarbonate injection was ab le to achieve 70-85% SO 2 removal but at an NSR of 0.5 to 1.5. 50

As previously discussed, dry sorbent injection is planned as BART for SO 2 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 SO 2 emission rate of the two units was 0.623 lb/MMBtu and 0.638 lb/MMBtu for Units 1 and 2, respec tively, and the company proposed SO 2 BART limits of 0.18
– 0.20 lb/MMBtu with DSI. 51 The Illinois EPA has proposed a 0.18 lb/MMBtu SO 2 limit as

47 Reducing PGE’s estimated capital costs by th e 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 Applica tion Guide, at 4 (Exhibit 6).

49 See Kong, Yougen et al., Dry Sorbent Inj ection of Sodium Bicarbonate for SO 2 Mitigation, Power-Gen International 2008, Orlando, December 2-4, 2008 at 21 (Exhibit 11).

50 Id. In fact, Solvay indicates that about half th e amount of sodium bicarbonate is needed to
achieve the same level of SO 2 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 An alysis 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 SO 2 control at several Illinois pow er plants. The SO 2 reductions are required pur suant to a 2006 Illinois EPA agreement and also under the forthcoming Tran sport Rule requirements. The company has proposed trona injection to be installed in the next few years at numerous of its electrical generating units includ ing Waukegan 7 and 8, Fisk 19, Craw ford 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 Complia nce 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 SO 2 emission rates are being required than PGE’s proposed 0.40 lb/MMBtu w ith the same SO2 pollution controls.

The Gallagher Units 2 and 4 are required pursu ant to a consent decree with EPA to install a dry sorbent injection system and meet SO 2 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 appr oximately 3 lb/MMBtu in 2009. According to testimony provided on behalf of Duke Energy Indiana to the Indian a Utility Regulatory Commission, the dry sorbent injection system wo uld achieve at least 50% SO2 removal based on coal with an average SO 2 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 refl ect a limit determined through BACT or BART. 57 Yet, the units will still achieve a higher SO 2 removal efficiency than

52 See Illinois EPA, Draft Techni cal Support Document Regional Haze State Implementation Plan for Illinois, October 7. 2010, at 22, avai lable at http://www.epa.state.il.us/air/.

53 See “Edison Mission Energy to Use Trona for SO 2 Control on Illinois Power Plants,” FGD and DeNox Newsletter, October 2010, No. 390, Exhibit 4.

54 Id.

55 See Partial Consent Decree betwee n United States of America and Cynergy Corp., et al., 2009, at 17 (paragraph 51), available at http://www.epa.gov/compliance/resources/cas es/civil/caa/dukeenergy-infosht.html.

56 See September 8, 2010 Approval by Indiana Utility Regulatory Commissi on, Petition of Duke Energy Indiana, Inc., 1) for Issuance of a Certif icate of Public Conveni ence and Neccessity for Use of Clean Coal Technology for a Project, Dr y Sorbent Injection, at Petitioners’ Gallagher Generating Station; and 2) To Conduct Ongoing Review of the Im plementation 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 ofBrian 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 bur n Central Appalachian coal. Testing of sorbent injection at these units showed up to 80% SO 2 removal was achieved. 58 Trona and sodium bicarbonate injec tion both achieved 70-80%+ SO 2 removal, but the sodium
bicarbonate achieved 80% SO 2 removal at lower injection rates. 59 A comparison of SO 2 emissions data from 2004, before sorbent inject ion was tested or inst alled, to 2009 emissions shows that the units are achieving 77% SO 2 removal on average. The 2009 annual average SO 2 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 SO 2 emission reductions at Boardman than the 33-34% control assumed by PGE. Indeed, based on emission limits that ha ve been proposed for several of the Edison Mission Energy electrical generating units, an SO 2 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% SO 2 removal from baseline SO 2 emission rates at Boardman. Such levels of SO 2 removal have been proposed and achieved at
coal-fired boilers with DSI.

In addition, by combining DSI with use of lowe r sulfur coal, PGE should readily be able
to reduce SO 2 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 re duced sulfur coal SO 2 emission rate of 0.60 lb/MMBtu.

If Boardman was subject to an SO 2 BART emission limit of 0.13 lb/MMBtu rather than its proposed limit of 0.40 lb/MMBtu, its em issions would be reduced to 3,098 tpy 61 or 11,804 tpy
of SO 2 reduced from baseline emissions. This is much lower than the 9,714 tpy that would be emitted under PGE’s proposed SO 2 BART limit of 0.40 lb/MMBtu, which only reflects 5,100

the Gallagher units. See Partial Consent Decree between Unit ed States of America and Cynergy Corp., et al., 2009, at 3, available at http://www.epa.gov/compliance/resources/ cases/civil/caa/dukeen ergy-infosht.html.

58 See Kong, Yougen et al., Dry Sorbent Inj ection of Sodium Bicarbonate for SO 2 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 cap acity, per Table 1-1 of PGE’s August 2010 BART alternative submittal, and op erations at 85% capacity factor.Brian Finneran Oregon Department of Environmental Quality November 15, 2010 Page - 19 -

tpy of SO 2 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 2 014 compliance timeframe for meeting SO 2 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 SO 2 limit because its coal supplies do not expire until the end of 2011, that is not suffici ent justification to delay implementation of DSI. PGE does not

need to burn reduced sulfur coal in order to in stall and begin using a DS I system. If DSI is required as BART, the Department should require it to be inst alled no later than December 2011.

D. Selective Catalytic Reduction T echnology is BART for NOx in the 2020
Alternative.

The Coalition adopts and supports the comme nts of the National Park Service (“NPS”) dated October 1, 2010 regarding BART for NOx generally and under either a 2020 or 2018 alternative. Specifically, Sel ective Catalytic Reduction technology (“SCR”) is BART for NOx
control under at least th e 2020 alternative. As set forth in the NPS comments, PGE and the Department significantly overestimate the cost s 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 de tailed 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 th e 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 ur ge 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 Control ling 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-EFFEC TIVENESS 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 a lternatives. That thre shold is particularly inappropriate in light of two impor tant factors that must drive the Department’s decisions in this

matter.

First, Oregon’s options for meeting haze re duction requirements are very constrained. There are truly only two major regional sour ces 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 pr ogress on visibility goals and requirements: the Boardman Plant and the Tran sAlta Centralia Generation L.L.C. facility in Centralia, Washington. Without st rict 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 poten tial benefit from strict app lication of BART requirements on

Boardman and TransAlta. As noted in the N PS Comments, cost-effectiveness is not the only
determinative of BART and it does not make sens e 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 utili ze 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 determ ining BART. This is at the very bottom of the $7,000-10,000 range which itself re flects the historical low-end as noted by the NPS. Given the unique situation in Oregon and the large number of Class I areas that mu st be protected with BART from a handful of sources, the Department must use a thres hold that is at the top end of this range.

Similarly, Oregon’s threshold when analyzi ng cost-effectiveness fr om 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 m illion 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 situati on in Oregon of protecting so large an area in the region coupled with so few opport unities to make the n ecessary reductions, the Department has a responsibility to reassess BA RT and the 2020 proposal with higher thresholds
for cost-effectiveness determinati ons and err on the more protectiv e side of the analysis. In doing so, the evidence will demonstrate that se mi-dry FGD and SCR are well within the costeffectiveness range for a 2020 option (and ma y very well be even for a 2018 option.)

IV. THE PGE 2020 ALTERNATIVE WI LL 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, stat es must demonstrate that they are on task for meeting natural conditions in the nation’s Clas s I areas by 2064. To th at end, state’s must demonstrate progress on goals at periodic milestone s 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 cl osure dates for the Boardman Plant with relaxed BART requirements, the Department’s own an alysis 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 th at BART be determined based upon meeting the first milestone, as noted above, the Departme nt has limited other options for demonstrating reasonable further progress. Therefore, furthe r relaxation of the BART requirements, proposed by PGE, directly interferes with meeting the re asonable further progress goa ls, will ensure those goals are not met by a fairly substantial marg in, 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 cont inue to consider and maintain 2018 and fiveyear options for closure of the Boardman Plant. To that end, the De partment should look at

additional cost-benefit and t echnical analysis for the 2018 opt ion 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 201 8 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.