National Park Service (NPS) Comments on

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

Best Available Retrofit Technology (BART) Determination for the

Boardman Power Plant 

October 1, 2010

Present Unit Operation

The Boardman Power Plant (Boardman) is operated by Portland General
Electric (PGE) and includes one dry-bottom, wall-fired boiler burning
pulverized sub-bituminous coal (8,020 Btu/lb, 0.3% sulfur, 9% ash) and
is rated at 617 MW. This electric generating unit is equipped with an
electrostatic precipitator to control particulate matter. 

Current Actual NOx Emission Rates

Baseline emission rates proposed by the Oregon Department of
Environmental Quality (OR DEQ) for the cost evaluation steps are 14,902
tons per year (tpy) SO2 (0.61 lb SO2/mmBtu) and 10,349 tpy NOX (0.43 lb
NOx/mmBtu). Based upon our review of EPA’s Clean Air Markets (CAM)
data for this facility, these estimates of actual SO2 and NOx emissions
appear reasonable for the annual cost analyses. According to the CAM
database, facility SO2 emissions have averaged 13,025 tons per year
(tpy) and 0.65 lb/mmBtu during 2000 – 2009. Facility NOX emissions
have averaged 8,535 tpy and 0.43 lb/mmBtu during the same period.
(Because we used the slightly lower average annual emissions from the
CAM database, our estimates of the amount of emissions that could be
reduced by various control options are somewhat lower than had we used
the OR DEQ data.)

BART analysis for NOX  

Consistent with the Environmental Protection Agency (EPA)’s BART
Guidelines, the five steps for a case-by-case BART analysis were
followed.

Step 1 – Identify all available retrofit control technologies

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

NPS: OR DEQ evaluated a reasonable suite of options.

Step 2 – Eliminate technically infeasible options

OR DEQ: DEQ eliminated from further analysis those control technology
options that could not meet the BART presumptive limit (0.23 lb/MMBtu
for NOX).

NPS: We agree with OR DEQ’s approach.

Step 3 – Evaluate the control effectiveness of the remaining
technologies 

OR DEQ: The basis for the control effectiveness of new LNB with modified
over-fire air, SCR…was discussed in the previous report and there is
no new information to suggest revising the previous conclusions. 

NPS: We are presenting new information that shows that OR DEQ has
underestimated the ability of SCR to reduce emissions. It is generally
understood that NOX reductions of approximately 90% or more may be
achieved with SCR systems. And, according to the June 13, 2009
“Power” magazine article “Air Quality Compliance: Latest Costs for
SO2 and NOX Removal (effective coal clean-up has a higher–but
known–price tag)” by Robert Peltier, “An excellent example of the
significant investment many utilities have made over the past decade is
American Electric Power (AEP), one of the largest public utilities in
the U.S. with 39,000 MW of installed capacity with 69% of that capacity
coal-fired. AEP is under a New Source Review (NSR) consent decree signed
in 2007 that requires the utility install air quality control systems to
reduce NOX by 90%...”

If we assume a 90% reduction by SCR from the 0.23 lbNOX/mmBtu emission
rate predicted for the LNB+OFA option at Boardman, outlet emissions
would be reduced to 0.02 lb/mmBtu. Instead, for the LNB+OFA+SCR option,
OR DEQ assumed 0.07 lb/mmBtu; this represents only a 70% reduction from
the LNB+OFA emission estimate. We are now including (in Appendix A) new
2009 CAM data that shows that SCR can achieve year-round emissions of
0.05 lb/mmBtu or lower at 27 coal-fired EGUs, nine of which are
wall-fired units like Boardman. Although we believe that SCR is capable
of even lower annual NOx emissions at Boardman, we will continue to
assume 0.05 lb/mmBtu in our analyses to reflect our understanding of
vendor guarantees.

STEP 4 –Evaluate Impacts and Document the Results

OR DEQ: PGE calculated the capital investment and annual operating cost
for each technically feasible add-on control option based on the
following: 

CUECost Workbook, Version 1.0 

EPA Air Pollution Control Cost Manual – Sixth Edition 

Budgetary quotes from equipment vendors 

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

NPS:  Both OAQPS and EPA Region 8 have advised against the use of
CUECost. Instead, the BART Guidelines recommend use of the OAQPS Control
Cost Manual: 

The basis for equipment cost estimates also should be documented, either
with data supplied by an equipment vendor (i.e., budget estimates or
bids) or by a referenced source (such as the OAQPS Control Cost Manual,
Fifth Edition, February 1996, 453/B-96-001). In order to maintain and
improve consistency, cost estimates should be based on the OAQPS Control
Cost Manual, where possible.  The Control Cost Manual addresses most
control technologies in sufficient detail for a BART analysis.  The cost
analysis should also take into account any site-specific design or other
conditions identified above that affect the cost of a particular BART
technology option.

EPA’s belief that the Control Cost Manual should be preferred over
CUECost for developing cost analyses that are transparent and consistent
across the nation and provide a common means for assessing costs is
further supported by this November 7, 2007, statement from EPA Region 8
to the North Dakota Department of Health:

The SO2 and PM cost analyses were completed using the CUECost model.
According to the BART Guidelines, in order to maintain and improve
consistency, cost estimates should be based on the OAQPS Control Cost
Manual. Therefore, these analyses should be revised to adhere to the
Cost Manual methodology.

NPS: OR DEQ has overestimated the cost of LNB, OFA, and SCR. OR DEQ
“discussed PGE’s cost estimates in the previous report and agreed
with their estimates. PGE has revised the costs to reflect 2010 dollars
rather than 2007 dollars, as used in the previous report.” OAQPS has
advised use of the Chemical Engineering Plant Cost Index (CEPCI) to
adjust costs for inflation. The CEPCI for 2007 was 525.4 and 521.9 for
2009, which indicates a decrease in costs. PGE should explain and
justify its escalated costs.

According to PGE, “The cost estimates are consistent in format with
the guidance from the EPA’s Office of Air Quality Planning and
Standards Cost Manual.” However, PGE’s estimation methods bear no
resemblance to the Cost Manual methods for estimating SNCR and SCR
costs. And, PGE’s cost estimates for LNB+OFA were 47% higher than the
estimates provided by ERG (OR DEQ’s consultant) in its June 26, 2008
“Technical Memorandum #2” to OR DEQ. We have accordingly used the
ERG estimate of $36/kW in our cost calculations for LNB+OFA.

PGE did not provide adequate justification or documentation for its cost
estimates. We were not provided with any vendor estimates or bids, and
PGE did not use the Control Cost Manual. As a result, we believe that
capital and annual costs are overestimated. For example, the PGE
estimate for SCR equates to a capital cost of $246/kW for the routine
SCR installation compared to the $50 - $267/kW cost of SCR found in
survey data (Appendix B). 

In the absence of adequate cost estimates by PGE, we applied the methods
described in the Cost Manual, with some modifications to compensate for
what we believe to be a tendency to underestimate Direct Capital Costs
(DCC). All of the Indirect Capital Costs estimated by the Cost Manual
method are proportional to the DCC, so DCC becomes a very important
parameter. While the Excel Workbook (“NPS SCR modified Cost manual
approach for Boardman”) in Appendix B estimates DCC = $27 million (in
2009 dollars), we will instead use the PGE estimate of $91 million for
DCC. By applying the Cost manual ratios to the PGE DCC estimate, we
arrive at a Total Capital Investment (TCI) of $129 million (versus
PGE’s estimate of $192 million), or $209/kW (versus PGE’s estimate
of $246/kW), exclusive of the combustion controls and boiler
modifications. Our estimates are more commensurate with industry data,
as discussed below.

Further evidence that PGE has overestimated its SCR costs can be found
in a June 2009 article in “Power” magazine: 

“One more current data set is the historic capital costs reported by
AEP averaged over several years and dozens of completed projects. For
example, AEP reports that their historic average capital costs for SCR
systems are $162/kW for 85% to 93% NOX removal...”

“…historical data finds the installed cost of an SCR system of the
700MW-class as approximately $125/kW over 22 units with a maximum
reported cost of $221/kW in 2004 dollars. This data was reported prior
to the dramatic increase in commodity prices of 14% per year average
experienced from 2004 to 2006 (from the FGD survey results). Applying
those annual increases to the 2004 estimates for three years (from the
date of the survey to the end of 2007) produces an average SCR system
installed cost of $185/kW…”

“Overall, costs were reported to be in the $100 to $200/kW range for
the majority of the systems, with only three reported installations
exceeding $200/kW.”

Five industry studies conducted between 2002 and 2007 have reported the
installed unit capital cost of SCRs, or the costs actually incurred by
owners, expressed in dollars per kilowatt. These actual costs are
generally lower than estimated by PGE for Boardman. 

The first study evaluated the installed costs of more than 20 SCR
retrofits from 1999 to 2001. The installed capital cost ranged from $106
to $213/kW, converted to 2007 dollars. Costs are escalated through using
the CEPCI. 

The second survey of 40 installations at 24 stations reported a cost
range of $76 to $242/kW, converted to 2007 dollars. 

The third study, by the Electric Utility Cost Group, surveyed 72 units
totaling 41 GW, or 39% of installed SCR systems in the U.S. This study
reported a cost range of $118/kW to $261/kW, converted to 2007 dollars.

A fourth study, presented in a course at PowerGen 2005, reported an
upper bound range of $180/kW to $202/kW, converted to 2007 dollars. 

A fifth summary study, focused on recent applications that become
operational in 2006 or were scheduled to start up in 2007 or 2008,
reported costs in excess of $200/kW on a routine basis, with the highest
application slated for startup in 2009 at $300/kW.

Thus, the overall range for these industry studies is $50/kW to $300/kW.
The upper end of this range is for highly complex retrofits with severe
space constraints, such as Belews Creek, reported to cost $265/kW, or
Cinergy's Gibson Units 2-4. Gibson, a highly complex, space-constrained
retrofit in which the SCR was built 230 feet above the power station
using the largest crane in the world, only cost $251/kW in 2007 dollars.

PGE has overestimated Direct Annual Costs (DAC) for SCR. For example,
PGE states (in its Appendix D) that Maintenance & Labor materials cost
3% of the DCC, while the Cost Manual assumes 1.5% of the TCI; this
results in about a $1 million annual overestimate. Other examples of
PGE’s higher-than-Cost Manual estimates can be found in the “Ann
Cost” tab of the “NPS SCR modified Cost manual approach for
Boardman” workbook. All told, PGE estimates $5.7 million/yr versus
$3.8 million using the Cost Manual.

We agree with OR DEQ that “remaining useful life” is a very
important factor in the economics of the BART analysis. For example, if
we assume a remaining useful life of 20 years (the SCR default) in cell
C38 in the “Given/Assume” tab of the “NPS SCR modified Cost manual
approach for Boardman” workbook, our estimate (“Ann Cost” tab cell
D50) of Indirect Annual Cost (to amortize the SCR investment) is $16
million/yr and the cost/ton of the LNB+OFA+SCR system becomes $3,000/ton
(cell D64 of the “Ann Cost” tab). However, if one enters a shorter
life, e.g., five years, into cell C38 in the “Given Assume” tab of
the workbook, the Indirect Annual Cost (“Ann Cost” tab cell D50)
rises to $41 million and the cost/ton rises to almost $7,000/ton (cell
D64 of the “Ann Cost” tab) over five years. Nevertheless, based upon
OR DEQ’s cost-effectiveness threshold of $7,300/ton, one would
conclude that SCR would be cost-effective if used for only five years
before plant shut-down.

There is a wide discrepancy between SCR cost estimates presented by PGE
and by NPS using the EPA Control Cost Manual. Following is a breakdown
of the specific areas where PGE's results differ substantially from
ours:

PGE’s estimates are based upon achieving 0.07 lb/mmBtu, which
represents 70% NOx reduction from the 0.23 lb/mmBtu to be achieved by
combustion controls. Although modern SCR systems are typically designed
to achieve 90+% NOx reductions, we assumed a 0.05 lb/mmBtu (a 78%
reduction) “target” for SCR based upon the performance of the
eastern boiler retrofits discussed above.

PGE estimated that SCR would have a Total Capital Investment (TCI) of
$192 million. When we modified the Cost Manual approach to produce a
more realistic estimate, we estimated a TCI of $129 million. PGE’s
estimate of $246/kW is excessive when compared to real-world industry
data, while our $209/kW appears reasonable. PGE should provide detailed
descriptions of how its SCR TCI costs were derived.

PGE has overestimated Direct Annual Costs and should provide detailed
descriptions of how these costs were derived.

The combination of overestimates for Total Capital Investment and Direct
Annual Costs had resulted in inflated costs from PGE without the
supporting justifications required by the BART Guidelines.

For remaining useful life of five years or more, LNB+OFA+SCR meets OR
DEQ’s $7,300/ton criterion.

A similar situation exists with respect to SNCR, and PGE’s estimates
are even more devoid of detail and apparently inflated. Once again, we
applied the Cost Manual method to OR DEQ’s expected emission rates and
our results are summarized in the “Boardman SNCR” tab in the “NPS
version of OAQPS Cost Manual SNCR for Boardman” workbook in Appendix
B. Even if the remaining useful life of the LNB+OFA+SNCR system is only
two years (cell C27 of the “Given/Assume” tab), the
cost-effectiveness is still well below OR DEQ’s $7,300 ton threshold.

STEP 5 – Evaluate Visibility Impacts

Base Case: According to OR DEQ, Mt. Hood is the most-impacted Class I
area with a 98th percentile value of 4.98 deciview (dv), and the
cumulative impact across all 14 Class I areas is 31.46 dv. (Boardman
ranks as having the fourth-highest cumulative impact of any BART source
we have reviewed to date.)

LNB+OFA+SCR would result in a 12.5 dv cumulative improvement. Assuming a
five year remaining useful life, the cost-effectiveness expressed in
$/dv would be $4 million, well below the OR DEQ threshold of $10
million/dv.

LNB+OFA+SNCR would result in a 9.9 dv cumulative improvement. Assuming a
two year remaining useful life, the cost-effectiveness expressed in $/dv
would be $2 million, well below the OR DEQ threshold of $10 million/dv.

BART analysis for SO2  

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

Step 1 – Identify all available retrofit control technologies

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

NPS: OR DEQ evaluated a reasonable suite of options.

Step 2 – Eliminate technically infeasible options

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

NPS: We agree with OR DEQ’s approach.

Step 3 – Evaluate the control effectiveness of the remaining
technologies 

OR DEQ: The basis for the control effectiveness of…semi-dry FGD, wet
FGD…was discussed in the previous report and there is no new
information to suggest revising the previous conclusions.

NPS: We call attention to the permit issued by Nevada to Newmont Nevada
requiring its SDFGD to meet the following limits:

Section V. Specific Operating Conditions (continued)

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

2. NAC 445B.3405

a. Emission Limits (continued)

(7) Article 8.2.1.2 Federally Enforceable SIP - The discharge of sulfur
to the atmosphere will not exceed 1,218.0 pounds per hour.

(8) NAC 445B.305 BACT Emission Limit – The discharge of SO2 to the
atmosphere will not exceed:

(i) While combusting coal with a Sulfur content equal to or greater than
0.45 percent (30-day rolling period), based on daily ASTM sampling:

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

(b) 95% minimum SO2 removal efficiency will be maintained across the
system, based on a 30-day rolling period.

(ii) While combusting coal with a Sulfur content less than 0.45 percent
(30-day rolling period), based on daily ASTM sampling:

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

(b) 91% minimum SO2 removal efficiency will be maintained across the
system, based on a 30-day rolling period.

STEP 4 –Evaluate Impacts and Document the Results

NPS: According to PGE, “The cost estimates are consistent in format
with the guidance from the EPA’s Office of Air Quality Planning and
Standards Cost Manual.” However, while PGE’s estimation methods
resemble the Cost Manual method for estimating scrubber costs, the
values and estimation factors actually used by PGE are consistently
higher than those used by the Cost Manual. PGE has also included a $37
million Allowance for Funds During Construction (AFUDC) which may not be
creditable. As a result, PGE has estimated a TCI of $247 million versus
a straightforward application of the Cost Manual method which yields
$168 million.

For Direct Annual Costs, PGE estimated $13.0 million versus the Cost
Manual estimate of $8.5 million.

Again, we agree with OR DEQ that “remaining useful life” is a very
important factor in the economics of the BART analysis. For example, if
we assume a remaining useful life of 15 years (the scrubber default) in
cell C29 in the “Given/Assume” tab of the “Boardman dry scrubber
cost effectiveness” workbook, our estimate (“Ann Cost” tab cell
K31) of Indirect Annual Cost (to amortize the scrubber investment) is
$25 million/yr and the cost/ton of the LNB+OFA+SCR system becomes
$2,900/ton (cell C11 of the “$T” tab). However, if one enters a
shorter life, e.g., three years, into cell C29 in the “Given Assume”
tab of the workbook, the Indirect Annual Cost rises to $71 million and
the cost/ton rises to almost $7,000/ton over three years. Nevertheless,
based upon OR DEQ’s cost-effectiveness threshold of $7,300/ton, one
would conclude that SDFGD would be cost-effective if used for only three
years before plant shut-down.

STEP 5 – Evaluate Visibility Impacts

Base Case: According to OR DEQ, Mt. Hood is the most-impacted Class I
area with a 98th percentile value of 4.98 deciview (dv), and the
cumulative impact across all 14 Class I areas is 31.46 dv. (Boardman
ranks as having the fourth-highest cumulative impact of any BART source
we have reviewed to date.)

Addition of the SDFGD would result in a 10.6 dv cumulative improvement.
Assuming a three year remaining useful life, the cost-effectiveness
expressed in $/dv would be $7.5 million, well below the OR DEQ threshold
of $10 million/dv.

The BART Determination

Cost-Effectiveness Metrics

BART is not necessarily the most cost-effective solution. Instead, it
represents a broad consideration of technical, economic, energy, and
environmental (including visibility improvement) factors. We agree with
OR DEQ that it is appropriate to consider both the degree of visibility
improvement in a given Class I area as well as the cumulative effects of
improving visibility across all of the Class I areas affected. It simply
does not make sense to use the same metric to evaluate the effects of
reducing emissions from a BART source that impacts only one Class I area
as for a BART source that impacts multiple Class I areas. And, it does
not make sense to evaluate impacts at one Class I area, while ignoring
others that are similarly significantly impaired. If we look at only the
most-impacted Class I area, we ignore that the other Class I areas are
all suffering from impairment to visibility “caused” by the BART
source. It follows that, if emission from the BART source are reduced,
the benefits will be spread well beyond only the most impacted Class I
area, and this must be accounted for.

The BART Guidelines represent an attempt to create a workable approach
to estimating visibility impairment. As such, they require several
assumptions, simplifications, and shortcuts about when visibility is
impaired in a Class I area, and how much impairment is occurring. The
Guidelines do not attempt to address the geographic extent of the
impairment, but assume that all Class I areas are created equal, and
that there is no difference between widespread impacts in a large Class
I area and isolated impacts in a small Class I area. To address the
problem of geographic extent, we have been looking at the cumulative
impacts of a source on all Class I areas affected, as well as the
cumulative benefits from reducing emissions. While there are certainly
more sophisticated approaches to this problem, we believe that this is
the most practical, especially when considering the modeling techniques
and information available. 

We note that OR DEQ has established a cost/ton threshold of $7,300 based
upon actions in other states (e.g., MN, NM), and upon the premise that
improving visibility in multiple Class I areas warrants a higher
cost/ton than where only one Class I area is affected. We support this
premise, and add that Wisconsin is using $7,000 - $10,000/ton as its
BART threshold.

One of the options suggested by the BART Guidelines to evaluate
cost-effectiveness is cost/deciview. Compared to the typical control
cost analysis in which estimates fall into the range of $2,000 - $10,000
per ton of pollutant removed, spending millions of dollars per deciview
(dv) to improve visibility may appear extraordinarily expensive.
However, our compilation of BART analyses across the U.S. reveals that
the average cost per dv proposed by either a state or a BART source is
$14 - $18 million, with a maximum of $51 million per dv proposed by
South Dakota at the Big Stone power plant. We note that OR DEQ has
chosen $10 million/dv as a cost criterion, which is somewhat below the
national average. 

We have a concern with the way in which the incremental cost analysis is
used by OR DEQ. According to EPA’s BART Guidelines, “You should
consider the incremental cost effectiveness in combination with the
average cost effectiveness [emphasis added] when considering whether to
eliminate a control option…You should exercise caution not to misuse
these [average and incremental cost effectiveness] techniques… [but
consider them in situations where an option shows]…slightly greater
emission reductions…” However, incremental costs are rarely
estimated and evaluated, so the much higher numbers that result appear
quite high at first glance. For example, all of the incremental costs
estimated by OR DEQ are much higher than the average costs, yet OR DEQ
is using the same $10 million/dv threshold for both average and
incremental costs. However, a rigid use of incremental cost
effectiveness will always result in the choice of the cheapest option if
carried to the extreme. (For example, if only incremental costs were
used to evaluate PM controls, it is likely that all controls more
expensive than a multiple cyclone would be rejected.) To use incremental
costs properly, they must be compared to incremental costs for similar
situations. We do not have data on incremental cost/dv, nor has OR DEQ
presented any data to show how its $10 million/dv threshold for
incremental cost-effectiveness compares to other BART determinations.

Option 1: Plant closure by 12/31/20 

Sulfur dioxide: 

OR DEQ: The SDFGD control technology is considered BART because it
provides significant visibility improvement and is cost effective even
with plant closure on 12/31/20. 

NPS: We agree.

Nitrogen oxides: 

OR DEQ has determined that LNB with SNCR is BART if the plant closes on
12/31/20. At a cost of $8,337/ton, SCR is not considered cost effective
for the purposes of BART. 

NPS: We have shown that PGE has overestimated the costs of SCR and
underestimated its effectiveness. The analyses which we are now
providing demonstrate that, if SCR is operated for at least five years,
its cost meets the OR DEQ $7,300/ton threshold, and that the cost/dv of
$4 million is also well below the OR DEQ threshold of $10 million/dv.

Option 2: Plant closure by 12/31/18 

Sulfur dioxide: 

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

WFGD and SDFGD are not cost effective if the Boardman Plant closes on
12/31/18. The cost of SDFGD is approximately $7,300/ton, which is not
considerable reasonable. WFGD is even more costly than SDFGD. 

Dry sorbent injection (DSI) is a demonstrated technology, albeit on
smaller units than the Boardman Plant. DSI can achieve 70 to 90%
emission reductions. Taking into consideration the size of the Boardman
Plant, it is estimated that a DSI system could achieve a 35% emission
reduction. DSI is cost effective and provides 0.84 deciview improvement
in the Mt. Hood Wilderness area and greater than 7 deciview improvement
for all Class I areas. DSI was considered feasible in at least one other
BART analysis (Stanton Station Unit 1). The effectiveness of the control
was also estimated at 35%. 

NPS: Not only has PGE overestimated the cost and underestimated the
effectiveness of SDFGD, OR DEQ is using the PGE estimates in an
inconsistent manner by stating that SDFGD at $7,300/ton is not
cost-effective in this specific instance, while $7,300/ton was accepted
in other cases. We have demonstrated that, even if SDFGD is used for
only three years, its $6,800/ton and $7.4 million/dv costs would meet OR
DEQ’s acceptance criteria.

If OR DEQ decides that DSI is BART, it should require PGE to design and
install the DSI system to achieve 90% efficiency and require that PGE
optimize its effectiveness for the duration of its operation.

Nitrogen oxides: 

OR DEQ evaluated the same control technologies for Option 2 as for
Option 1 and concluded that BART is the same for both Options. Even with
an earlier closure date, LNB with SNCR is still considered cost
effective. PGE determined that SNCR can achieve an emission rate of 0.19
lb/mmBtu. LNB with SNCR will result in a 1.62 deciview improvement in
the Mt. Hood Class I area and 9.87 deciview improvement for all Class I
areas. 

NPS: We agree.

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

OR DEQ recommends adding an option to the regional haze requirements
that would exempt PGE from complying with the emission limits and
standards effective on and after 7/1/14, if the coal-fired plant is shut
down within 5 years of the date EPA approves DEQ’s regional haze plan
as a revision to the state implementation plan. This option is based on
40 CFR 51.302(c)(4)(iv): 

(iv) The plan must require that each existing stationary facility
required to install and operate BART do so as expeditiously as
practicable but in no case later than five years after plan approval. 

NPS: The cited portion of the BART Guidelines cited by OR DEQ contains a
requirement that BART be implemented “as expeditiously as
practicable.” We have demonstrated that, even if the remaining useful
life of the LNB+OFA+SNCR system is only two years, its
cost-effectiveness is still well below OR DEQ’s $7,300 ton threshold.
Although OR DEQ has not provided sufficient data on the costs of Dry
Sorbent Injection (DSI), it is possible that DSI could also meet OR
DEQ’s cost-effectiveness threshold even if used for only a few years.
OR DEQ should require that Boardman install those emission controls that
can be expected to meet its acceptance criteria over the remaining
useful life of the plant if those controls are, indeed, installed “as
expeditiously as practicable.”

Conclusions & Recommendations

OR DEQ has produced one of the best BART analyses we have seen to date.
Nevertheless, we believe that improvements could be made: 

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

Consider the permit issued by NV to Newmont Nevada as a strong indicator
that SDFGD can achieve lower emission than assumed by PGE.

Give preference to costs estimated in accordance with the BART
Guidelines instead of those presented by PGE.

Do not use incremental costs unless a basis for comparison to other
incremental costs is also used.

Require that Boardman install those emission controls that can be
expected to meet the OR DEQ acceptance criteria over the remaining
useful life of the plant “as expeditiously as practicable.”

 According to the Institute of Clean Air Companies white paper titled
“Selective Catalytic Reduction (SCR) Control of NOx Emissions from
Fossil Fuel-Fired Electric Power Plants” (published in May 2009),
“By proper catalyst selection and system design, NOX removal
efficiencies exceeding 90 percent may be achieved.”

 Our review of operating data suggests that a NOX limit of 0.06 lb/mmBtu
is appropriate for LNB/SOFA+SCR for a 30-day rolling average, and 0.07
lb/mmBtu for a 24-hour limit and for modeling purposes, but a lower rate
(e.g., 0.05 lb/mmBtu or lower) should be used for annual average and
annual cost estimates.

 For example, Minnesota Power has stated in its Taconite Harbor BART
analysis that “The use of an SCR is expected to achieve a NOX 
emission rate of 0.05 lb/mmBtu based on recent emission guarantees
offered by SCR system suppliers.”

 E-mail from Larry Sorrels, EPA OAQPS, to Don Shepherd dated 7/21/10.
“On cost indexes, I prefer the CEPCI for escalating/deescalating costs
for chemical plant and utility processes since this index specifically
covers cost items that's pertinent to pollution control equipment
(materials, construction labor, structural support, engineering &
supervision, etc.). The Marshall & Swift cost index is useful for
industry-level cost estimation, but is not as accurate at a
disaggregated level when compared to the CEPCI.   Thus, I recommend use
of the CEPCI as a cost index where  possible.”

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

 No unusual installation issues were noted aside from the boiler
modifications that have already been accounted for.

 June 13, 2009 “Power” magazine article “Air Quality Compliance:
Latest Costs for SO2 and NOx Removal (effective coal clean-up has a
higher–but known–price tag)” by Robert Peltier.
http://www.masterresource.org/2009/06/air-quality-compliance-latest-cost
s-for-so2-and-nox-removal-effective-coal-clean-up-has-a-higher-but-known
-price-tag/

 Bill Hoskins, Uniqueness of SCR Retrofits Translates into Broad Cost
Variations, Power Engineering, May 2003. Ex. 2. The reported range of
$80 to $160/kW $123 - $246/kW was converted to 2008 dollars ($116 -
$233/kW) using the ratio of CEPCI in 2008 to 2002: 575.4/395.6. 

  J. Edward Cichanowicz, Why are SCR Costs Still Rising?, Power, April
2004, Ex. 3; Jerry Burkett, Readers Talk Back, Power, August 2004, Ex.
4. The reported range of $56/kW - $185/kW was converted to 2008 dollars
($83 - $265/kw)using the ratio of CEPCI for 2008 to 1999 (575.4/.390.6)
for lower end of the range and 2008 to 2003 (575.4/401.7) for upper end
of range, based on Figure 3. 

 M. Marano, Estimating SCR Installation Costs, Power, January/February
2006. Ex. 5. The reported range of $100 - $221/kW was converted to 2008
dollars ($130 - $286/kW) using the ratio of CEPCI for 2008 to 2004:
575.4/444,2.
http://findarticles.com/p/articles/mi_qa5392/is_200602/ai_n21409717/prin
t?tag=artBody;col1 

 PowerGen 2005, Selective Catalytic Reduction: From Planning to
Operation, Competitive Power College, by Babcock Power, Inc. and LG&E
Energy, December 2005, Ex. 6. The reported range of $160 - $180/kW) was
converted to 2008 dollars ($197 - $221/kW) using the ratio of CEPCI for
2008 to 2005 (575.4/468.2). 

 J. Edward Cichanowicz, Current Capital Cost and Cost-Effectiveness of
Power Plant Emissions Control Technologies, June 2007, pp. 28-29, Figure
7-1 (Ex. 1).  

 Steve Blankinship, SCR = Supremely Complex Retrofit, Power Engineering,
November 2002, Ex. 7. The unit cost: ($325,000,000/1,120,000
kW)(608.8/395.6) = $290/kW.
http://pepei.pennnet.com/display_article/162367/6/ARTCL/none/none/1/SCR-
=-Supremely-Complex-Retrofit/ 

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

 McIlvaine, NOX Market Update, August 2004, Ex. 9. SCR was retrofit on
Gibson Units 2-4 in 2002 and 2003 at $179/kW. Assuming 2002 dollars,
this escalates to ($179/kW)(608.8/395.6) = $275.5/kW.
http://www.mcilvainecompany.com/sampleupdates/NoxMarketUpdateSample.htm 


 E-mail from Larry Sorrels, EPA OAQPS, to Don Shepherd dated 7/21/10.
“I agree with including AFUDC in a capital cost estimate if this is
already included in the base case as per a utility commission decision. 
Otherwise, I do not agree with its inclusion.”

 For example, our analysis, which is described later, indicates that the
cumulative benefits of reducing NOx emissions from NGS are seven times
greater than the benefit at the most-impacted Class I area.

 “The Department used cost-per-ton reduced as the primary metric for
determining the BART level of control.  The upper limit for this metric
was $7,000 to $10,000 per ton, which reflects historical low-end costs
for controls required under BACT.” BEST AVAILABLE RETROFIT TECHNOLOGY
AT NON-EGU FACILITIES April 19, 2010, WISCONSIN DEPARTMENT OF NATURAL
RESOURCES

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

 For example, PacifiCorp has stated in its BART analysis for its Bridger
Unit #2 that “The incremental cost effectiveness for Scenario 1
compared with the baseline for the Bridger WA, for example, is
reasonable at $580,000 per day and $18.5 million per deciview.”

 PAGE   

 PAGE   

 PAGE   12 

