State of Wisconsin
DEPARTMENT OF NATURAL RESOURCES
101 S. Webster Street
Box 7921
Madison WI 53707-7921
Scott Walker, Governor
Cathy Stepp, Secretary
Telephone 608-266-2621
Toll Free 1-888-936-7463
TTY Access via relay - 711
November 28, 2011
Attn: Docket ID EPA-HQ-OAR-2009-0491
Air and Radiation Docket and Information Center
U.S. Environmental Protection Agency (EPA)
Mail Code 6102T, Pennsylvania Ave., NW
Washington, DC, 20460
Subject: Comments on Proposed Revisions to the Cross-State Air Pollution Rule
Dear Administrator Jackson:
The Wisconsin Department of Natural Resources (WDNR) herby submits comments on the proposal from the
U.S. EPA entitled "Revisions to Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate
Matter and Ozone" as published in the Federal Register on October 14, 2011 (76 FR 63860). These comments
relate to Wisconsin's final nitrogen oxide (N0,3 and sulfur dioxide (50 2) emission budgets under the Cross-State
Air Pollution Rule (CSAPR). Additional electric generating unit emission corrections beyond what has been
currently proposed have been identified. These corrections meet the U.S. EPA's criteria for acceptable technical
adjustments.
It should be noted that the comments provided solely focus on the proposed emission budget corrections as they
relate to the finalized CSAPR and proposed technical adjustments for the State of Wisconsin. These comments
are not intended to replace or supersede our request for reconsideration to the CSAPR brought forth by the state.
Thank you for the opportunity to comment on the proposed CSAPR revisions. Specific technical comments are
provided in'the enclosed attachment. Please feel free to contact Mr. Joseph Hoch, Regional Pollutant and Mobile
Source Section Chief, at (608) 267-7543 or [email protected] if you have any questions regarding
these comments.
Sincerely,
13
na44,4%,
21-44-
William B. Baumann, Acting Air Management Bureau Director
Wisconsin Department of Natural Resources
cc:
Pat Stevens — AD/8
Joseph Hoch — AM/7
nr.wi gov
wisconsin.gov
Naturally WISCONSIN
Attachment 4 - (Palmer CSAPR Presentation)
C,
PRINTED
' ON RECYCLED
PAPER
Attachment 4 - (Palmer CSAPR Presentation)
Attachment: 1
Attn: Docket ID EPA-HQ-OAR-2009-0491
Air and Radiation Docket and Information Center
Environmental Protection Agency
Mail Code 6102T, Pennsylvania Ave., NW
Washington, DC, 20460
Wisconsin Department of Natural Resources Comments
to
Technical Adjustments to the Finalized Cross-State Air Pollution Rule
Docket ID EPA-HQ-OAR-2009-0491
Federal Register October 14, 2011, Vol 76, No 199, page 63860; FRL-9479-1.
EPA Requested Comments
1. Generation Unit Specific Assumptions WDNR supports the EPA proposed corrections with modifications.
The WDNR also requests additional corrections meeting EPA's criteria for technical adjustments.
—
a) EPA identified specific corrections to control equipment assumptions for several individual generating
units. These EPA identified technical corrections along with WDNR comments are listed in Table 1. For
Wisconsin generation unit Weston 3, EPA is proposing no SO 2 scrubber in either the baseline assumption or
remedy solutions through 2014. This adjustment is correct. Similarly, the EPA had assumed an SCR in place
for the John P. Madgett coal fired generating unit under CSAPR, whereas EPA has now correctly identified
that no SCR will be available for this unit by 2014.
For the Columbia power plant, EPA assumed wet scrubbers operating at generating units 1 and 2 beginning
January 1, 2014 under both the finalized Cross-State Air Pollution Rule (CSAPR) baseline and remedy
emission budgets. EPA in this rule making is correctly identifying that dry scrubbers rather than wet
scrubbers will be installed on the Columbia units as approved by the Wisconsin Public
Table . EPA proposed corrections and WDNR requested modifications
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Generation Unit
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Reductions
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Control
Weston 3
No FGD in baseline
controls
NA
Columbia 1
dry FGD @ 92%
control
01/01/2014
Columbip 2
dry FGD @ 92%
control
01/01/2014
John P. Madgett 1
No.SCR in baseline
controls
NA
Correct. No FGD has been approved or
committed; therefore installation cannot occur by
2014.
Partially correct. The units being installed are dry
FGD, however, completion of the project cannot be
expected before 3/1/2014(1).
Partially correct. The units being installed are dry
FGD, however, completion of the project cannot be
expected before 3/1/2014(1).
Correct. No SCR installation has been initiated;
therefore installation cannot occur by 2014.
Attachment 4 - (Palmer CSAPR Presentation)
.s:
',A,In . ,f.
--I-' --swa.
Reductions
First Applied
NA
05/01/2014
05/01/2014
Page 2
Service Commission (PSC) in March 2012 1 . However, in making this change EPA is still assuming SO 2
scrubingeyJa1,204.Thisumptoncre.Iisapovl,WcnPSC
anticipates the project will take up to 36 months to complete. Based on this anticipated installation schedule,
the WDNR believes Columbia scrubber emission reductions cannot be expected prior to April 2014 and that
emissions budgets should not reflect SO 2 scrubbing beginning before May 2014. In fact, the most reasonable
approach to developing emission budgets is to expect variable operation and shakedown of these scrubber
units throughout the remainder of 2014. Therefore, the preferred technical solution is to first apply operation
of the Columbia 502 scrubber equipment to a 2015 emission budget (refer to the discussion of phasing
emission budgets). In general, WDNR believes EPA should not incorporate emission reductions from post
combustion pollution control equipment until the full year after it becomes operational in order to account for
initial operating issues and variability.
b) In addition to the corrections already identified in this proposed rule making, EPA is looking for any
additional technical corrections which meet the same criteria. Basically, EPA is requesting corrections to the
assumptions of existing, planned, or remedy identified pollution control equipment relative to achievable
control levels and installation schedules. EPA states that these corrections do not alter the methodology used
in establishing each state's significant contribution...i.e the changes do not alter the cost thresholds and
emission reduction groupings applied under the finalized CSAPR. In this context, for Wisconsin NOx
emissions, the CSAPR control cost ceiling is 500 $/ton in both 2012 and 2014. For 50 2, EPA set the control
cost ceiling at $500/ton and $2,300/ton in 2012 and 2014, respectively. WDNR, here, is identifying
additional corrections for applying fuel switching based both on technical feasibility and meeting the
applicable cost ceiling. WDNR is also providing information for "must run" generation units as requested by
EPA. Lastly, WDNR is providing information to include generation units which have been omitted from the
emission budgets.
Existing and Committed Control Equipment
In order to assume that new post-combustion control equipment will be operating by 2014, the equipment
must already be approved and preferably already in the construction process. Further, to be available for
2012 emission budgets the control equipment must already be in place or have a near term start-up date.
Several corrections are identified in Table 2 based on existing equipment or the required start-up date of
equipment currently under construction.
EPA, under the finalized CSAPR, identified SCR equipment operating in 2012 at the Wisconsin coalfired units Valley 2 and 3, and at Edgewater unit 5. Currently, there are no SCR installations approved or
planned for the Valley units. Further, in developing Wisconsin NOx RACT rules in 2007, the WDNR
estimated SCR controls for Valley to cost well in excess of the $500/ton cost level identified for
Wisconsin NOx emissions under CSAPR. Therefore, assuming SCRs at Valley is incorrect. WDNR
recommends that emission budgets through 2014 reflect the current NOx emission rate for Valley units.
The Edgewater 5 unit is currently in the process of installing an SCR to meet lower NOx RACT emission
requirements starting May 1, 2013. The owner utility, Wisconsin Power and Light (WPL), originally
submitted a request for construction to the Wisconsin PSC in early 2008 with an anticipated start-up date
late in 2011. The PSC, however, did not grant approval until May 2010 2 . The most recent construction
1 (Wisconsin PSC, 2011), Certificate of Authority to Install Emission Reduction Systems at the Columbia Energy Center
Units 1 and 2, PSC ref# 145848, Docket 5-CE-138, Wisconsin Public Service Commission.
2 (Wisconsin PSC, 2010), Certificate of Authority to Install a Selective Catalytic Reduction System for Nitrogen Oxide
Removal on Unit 5, ref# 132485, Docket 5-CE-137, Wisconsin Public Service Commission.
Attachment 4 - (Palmer CSAPR Presentation)
Page 3
progress report from WPL forecasts an in-service date of December 2012 for the SCR 3 . Therefore
assuming a 2012 start date under CSAPR is incorrect. WDNR recommends that full emission reduction
be applied to emission budgets from May 1, 2013 and after. This is the effective date for the state RACT
requirement and allows adequate shakedown operation of the pollution control equipment. The original
construction request specifies the Edgewater 5 SCR is being installed to meet a 0.06 lbs/mmbtu NOx
emission rate. Therefore this rate should be applied in determining emission reductions for Edgewater 5
no sooner than May 1, 2013. The WDNR is providing NOx emission rates for Edgewater units 3 and 4 to
correctly reflect emission reductions before and after the Edgewater 5 SCR is available. Operation of
existing NOx controls on the Edgewater units is in response to Wisconsin NOx RACT requirements that
began in 2009 and become more restrictive May 1, 2013. Prior to the SCR, units 3 and 4 need to operate
combustion and urea injection controls to maximum levels in order for the whole facility to meet RACT
requirements. After the SCR, the NOx emission rates for units 3 and 4 are attenuated to reflect levels
consistent with good operation and combustion efficiency. Corrected NOx emission rates are provided in
Table 2 for all Edgewater generating units.
Selective Catalytic Reduction (SCR) and wet scrubber equipment are under construction at Oak Creek
units 5 through 8 as required under We Energies' consent decree with EPA. According to We Energies'
latest progress report to the Wisconsin PSC, this equipment is on schedule for service on all four units by
December 31, 20124. On this basis and because this is the emission requirement deadline under the
consent decree, WDNR recommends that emission reductions from SCR and wet scrubber equipment for
thepak Creek plant should not be considered available prior to December 31, 2012.
Table 2. WDNR Corrections for Existing and Committed Controls
AMR
111111
Reductions First
Applied
11111:141111:111
Control
Columbia 1*
Wet scrubber
01/01/2014
Dry Scrubber
05/01/2014
Columbia 2*
Wet scrubber
01/01/2014
Dry Scrubber
05/01/2014
Valley 2
SCR
01/01/2012
Valley 3
SCR
01/01/2012
Edgewater 3
OFA - RRI
OFA - RRI
Edgewater 4
Control
Reductions First
Applied
Generation Unit
No SCR approved or planned
NA
Prior to 05/01/2013 NOx = 0.20 lbs/mmbtu
after 05/01/2013 NOx = 0.25 lbs/mmbtu
01/01/2012
01/01/2012
01/01/2012
01/01/2012
Prior to 05/01/2013 NOx = 0.15 lbs/mmbtu
after 05/01/2013 NOx = 0.15 lbs/mmbtu
SCR is for NOx RACT requirement starting
5/1/2013; prior to SCR NOx = 0.15 lbs/mmbtu
after SCR NOx = 0.06 lbs/mmbtu
Edgewater 5
SCR
01/01/2012
Oak Creek 5
wet scrubber / SCR
01/01/2014
Oak Creek 6
wet scrubber / SCR
01/01/2014
Oak Creek 7
wet scrubber / SCR
01/01/2012
Oak Creek 8
wet scrubber / SCR
01/01/2012
.
Manitowoc Public
Utilities 9
502: from 0.26
(actual) to 0.61; NOx =
0.05 lbs/mmbtu
01/01/2012
We Energies Consent Decree Requirement is
12/31/2012
Existing fuel and controls - SNCR and lime
injection. NOx = 0.1 lbs/mmbtu, SO2 = 0.26
lbs/mmbtu
05/01/2013
01/01/2013
01/01/2012
* Columbia units included here for correction to availability assumption. EPA is proposing correction from wet
scrubber to the approved dry scrubber installation.
(WPL, 2011), Edgewater 5 SCR Progress Report — Third Quarter 2011, PSC ref#154810, Docket 5-CE-137, submitted by
Wisconsin Power and Light, October 21, 2011.
4 (WE, 2011) South Oak Creek Air Quality Control System Project Progress Report — 3 rd Quarter 2011, PSC ref# 154880,
Docket 6630-CE-299, submitted by We Energies, October 25, 2011.
3
Attachment 4 - (Palmer CSAPR Presentation)
Page 4
The last item with respect to existing operations and control equipment is correcting the Manitowoc
Public Utilities (MPU) unit 9 NOx and SO2 emission rates. The emission rates applied by the IPM model
are significantly different in the remedy run versus emission rates resulting from existing equipment and
operations at a current emission rate of 0.26 lbs/rnmbtu. Conversely, the model predicts reducing the
NOx emission rate further. The current emission rate is 0.1 lbs/mmbtu with SNCR on the already
inherently low emitting fluidized bed boiler. Both the current SO2 and NOx emission rates should be
used in determining emissions from MPU unit 9.
Fuel Switching Assumptions
The cost of 500 $/ton ceiling is used for 2012 control levels to ensure existing controls operate and that
SO2 emission reductions reasonably available through fuel switching occurs. WDNR here provides
corrections to fuel switching assumptions applied by the IPM model under the finalized 2012 and 2014
emission budgets. The corrections consider both the cost level ceiling and questions concerning
feasibility.
Table 3 shows WDNR identified corrections where fuel switching is appropriate by 2012 under the
$500/ton threshold. For the Madison Gas and Electric (MGE) owned Blount Street facility, the IPM
remedy run fuel switched to a high sulfur coal fuel. However MGE has committed to fire natural gas in
the Blount Street generation units beginning 2012 and after. For JP Madgett unit 1, the IPM model
switched to coal with higher sulfur content than that currently under contract. This current coal has an
average emission rate of 0.44 lbs/mmbtu. Likewise, IPM switched South Oak Creek to higher sulfur
content coal. The recent historic average is 0.46 lbs/mmbtu. No change in SO 2 emission rate for South
Oak Creek is warranted until the committed wet scrubbers come online. The 50 2 corrected SO2 emission
rates for JP Madgett and South Oak Creek reflect 2010 and 2011 CAMD reported emissions rates.
WDNR recommends EPA adopt corrections, summarized in Table 3, to reflect current conditions at the
Blount Street, JP Madgett, and South Oak Creek generation units.
Table 3. WDNR Corrections for Fuel Switching to Reflect Actual Operations.
bowl(
Reductions First
Applied
Generation Unit
Fuel Switch
Bount Street 7
From 0.19 (actual) to
0.66 lbs/mmbtu
01/01/2012
Blount Street 8
From 0.93 (actual) to
0.66 lbs/mmbtu
01/01/2012
Blount Street 9
From 1.21 (actual) to
0.66 lbs/mmbtu
01/01/2012,
JP Madgett 1
From 0.42 (actual) to
0.58 lbs/mmbtu
01/01/2012
,South Oak Creek 5
From 0.42 (actual) to
0.56 lbs/mmbtu
Reductions First
Applied
Facility under agreement to fire natural gas only:
estimated emission rates are SO2 = 0.004
lbs/mmbtu, NOx = 0.20 lbs/mmbtu
01/01/2012
No fuel switch. Coal on contract at 0.44
lbs/mmbtu
01/01/2012
•
01/01/2012,
South Oak Creek 7
From 0.42 (actual) to
0.56 lbs/mmbtu
From 0.45 (actual) to
0.07 lbs/mmbtu
(controlled)
01/01/2012
South Oak Creek 8
From 0.45 (actual) to
0.06 lbs/mmbtu
(controlled)
01/01/2012
South Oak Creek 6
Fuel Switch
01/01/2012
No fuel switch. Use average content of historic
fuel at 0.46 lbs/mmbtu
Attachment 4 - (Palmer CSAPR Presentation)
01/01/2012
Page 5
In applying fuel switching the EPA analysis assumed wide applicability of ultra-low sulfur subbituminous
coal to the Wisconsin sources listed in Table 4. The SO 2 emission rate applied for the ultra-low sulfur
fuel ranges from 0.56 to 0.58 lbs/mmbtu for the affected generation units. However, simply switching to
ultra-low sulfur coal does not appear to meet the cost and feasibility constraints. At best this level of fuel
switching is proving challenging. Wisconsin Power and Light (WPL), which operates the Columbia,
Edgewater, and Nelson Dewey facilities, currently fires an ultra-low sulfur coal in the Edgewater Unit 4
boiler. WPL explored obtaining more of this coal from their supplier for firing at their other units 5 . In this
case the utility was not able to withdraw from their existing contracts for low sulfur coal although the
utility also offered to pay an added premium. Further, the supplier is requiring substantially longer
contracts for ultra-low sulfur coal compared to the 2 to 3 year contracts for the normal low sulfur coal.
Based on this result, EPA cannot assume fuel switching is available to those sources identified in Table 4.
Table 4. WDNR Corrections for Fuel Switching to Based on Existing Contracts and Cost Exceeding 500
$/ton.
&Tic,• •
Reductions First
Applied
Generation Unit
Fuel Switch
Alma 4
From 2.27 (actual) to
0.50 lbs/mmbtu
01/01/2012
Alma 5
From 2.27 (actual) to
0.50 lbs/mmbtu
01/01/2012
Nelson Dewey 1
From 1.83 (actual) to
0.58 lbs/mmbtu
01/01/2012
Nelson Dewey 2
From 1.83 (actual) to
0.58 lbs/mmbtu
01/01/2012
Columbia 1
From 0.71 (actual) to
0.58 lbs/mmbtu
01/01/2012
Columbia 2
From 0.71 (actual) to
0.58 lbs/mmbtu
Edgewater 3
From 0.54 (actual) to
0.58 lbs/mmbtu
Edgewater 4
From 0.56 (actual) to
0.57 lbs/mmbtu
Reductions First
Applied
01/01/2012
Eliminate Petroleum Coke firing. Use average
content of low sulfur coal on contract at 0.75
lbs/mmbtu.
01/01/2012
01/01/2012
No fuel switch. Use average content of coal on
contract at 0.68 lbs/mmbtu
01/01/2012
01/01/2012
No fuel switch. Use average content of coal on
contract at 0.71 lbs/mmbtu
01/01/2012
01/01/2012
No Fuel switch. Use average content of coal on
contract at 0.58 lbs/mmbtu
01/01/2012
01/01/2012
No fuel switch. Use average content of coal on
contract at 0.71 lbs/mmbtu
01/01/2012
No fuel switch. Use average content of historic
fuel at 0.77 lbs/mmbtu
01/01/2012
Valley 2
.
Valley 3
From 0.76 (actual) to
0.66 lbs/mmbtu
01/01/2012
Valley 4
From 0.76 (actual) to
0.66 lbs/mmbtu
01/01/2012
Valley 1
Fuel Switch
Fuel switch to available subbituminous coal at
0.70 lbs/mmbtu
From 0.56 (actual) to
0.57 lbs/mmbtu
From 0.76 (actual) to
0.66 lbs/mmbtu
From 0.76 (actual) to
0.66 lbs/mmbtu
Edgewater 5
,,,,
01/01/2012
01/01/2012
Relative to current low sulfur fuels used, WPL also found that the ultra low sulfur coal would cost
significantly more than their current low sulfur coal. At least for the Nelson Dewey plant the fuel switch
would cost close to $1000/ton of SO 2 reduced compared to the current low sulfur coal currently under
contract for that facility. This condition obviously exceeds EPA's threshold for applying fuel switching in
2012. This same cost issue is anticipated for other units currently firing low sulfur fuels.
Another feasibility issue for using ultra-low sulfur fuels is the potential impact to generation heat rates,
particularly for small units. A prevalent example, is the Valley power boilers which are designed for high
5
(WPL, 2011), personal communication, Steve Jackson, Wisconsin Power and Light.
Attachment 4 - (Palmer CSAPR Presentation)
Page 6
heat release fuels such as bituminous coals. The facility already burns a low sulfur bituminous coal at
0.76 lbs/mmbtu. Switching to a lower sulfur content likely means using a low sulfur subbituminous coal
with significantly different heat release characteristics.
Because of these identified issues WDNR requests EPA not apply fuel switching and use current SO2
emission rates found in the CAMD database for the Columbia (pre-scrubber), Edgewater, and Valley
generation units. For generation units at Alma and Nelson Dewey a fuel switch to the low sulfur fuel
currently available to each facility is appropriate under the $500/ton cost ceiling. The recommended
corrections and SO 2 emission rates are listed in Table 4.
"Must Run" Sources
The Valley power plant is specifically designed and operated as a combined heat and power plant. The
plant is contracted to supply heat and cooling to customers in downtown Milwaukee as well as generate
electricity. Currently this facility is last in dispatch across the We Energies coal-fired power plants. As
such, a reasonable surrogate for minimum operating levels may be the recent operation of these units
from 2008 through 2010. This operation level is closely tied to actual heat and cooling needs versus
operational levels dispatch of only electric generation to the grid. However, the 1PM model remedy run
predicted higher operation and dispatch in 2012 than this 2008 to 2010 historic average. Because the
model found this configuration of Valley to economically dispatch at higher levels in 2012, WDNR
recommends EPA use the 2012 operation for projecting minimum operation of the Valley unit through
2014.
Table 5. WDNR Corrections for "Must Run" Sources
rrent CUM medAssumption
Ofilt
Generation Uni. Fuel consumption
First Applied
Valley 1
Economic dispatch;
2014 no operation
01/01/2012
Valley 2
Economic dispatch;
2014 no operation
01/01/2012
Valley 3
Economic dispatch;
2014 no operation
01/01/2012
Valley 4
Economic dispatch;
2014 no operation
01/01/2012
.‘
. riection:
Fuel consumption
First Applied
.
Use IPM 2012 operation and dispatch
01/01/2012
Sources Not Included in the Emission Budgets
The IPM Remedy run for the final CSAPR does not appear to include several generation units at two
Wisconsin utility plants which feed generators greater than 25 MW: the Manitowoc Public Utility plant
unit 8, and Bay Front plant units 1, 2, and 5. The Bay Front units 1 and 2 burn primarily biomass but fire
coal intermittently as needed. Further evaluation may be needed whether these two units are actually
fossil fuel fired and subject to the CSAPR. The emission characteristics of the Manitowoc and Bayfront
missing units are summarized in Table 6.
Attachment 4 - (Palmer CSAPR Presentation)
Page 7
Table 6. Wisconsin Generation Sources not Included in CSAPR Emission Budgets
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Missing Generation Unit
'
•
First Applied
2011 Fuel Consumption and Emissions •
01/01/2012
Bayfront 1
2011 Fuel Consumption and Emissions
01/01/2012
front 2
_ 2011 Fuel Consumption and Emissions
_ _2011 Fuel Consumption and Emissions
01/01/2012,
Manitowoc Public Utility
Bayfront 5
01/01/2012
Summary of Wisconsin Emission Budgets after Proposed Corrections
In the proposed rule making EPA provided a total amount of NOx and SO 2 emission adjustment due to
the identified corrections. An estimate of the resulting "EPA Proposed" emission budgets is shown in
Table 7. As can be seen the EPA corrections increase SO 2 emissions in 2014 compared to the finalized
CSAPR emission budgets. The NOx emission budget increases in both 2012 and 2014. These budgets
assume that the same corrections will be reflected in the ozone season NOx emission budgets.
Table 7. CSAPR Proposed Wisconsin Annual Emission Budgets
SO2
Emission
Budgets
2012
2014
2012
NOx
2014
Finalized CSAPR
79,480
40,126
31,628
30,398
EPA Proposed
79,480
47,883
34,100
32,870
WDNR
Requested
88,088
63,491
34,616
33,016
Notes :
i. EPA proposed SO2 adjustment = 7,757 tons annually starting 2014; NO„ adjustment = 2,473 tons
annually starting 2012.
ii. WDNR additional proposed adjustments: SO2 = 8,608 tons annually starting 2012, 23,365 tons
annually starting 2014; NOx = 2,988 tons annually starting 2012, 2,618 tons annually starting 2014.
After incorporating the additional corrections WDNR proposes here, the SO 2 emission budgets increase in
both 2012 and 2014 when compared to EPA's proposed CSAPR budgets. For NOx the emission budget
increases for 2012 but is the same as EPA's proposal for 2014. The unit-by-unit list of corrections and
calculated emissions proposed by WDNR are presented in Appendix A.
2. Threshold for Technical Corrections — WDNR believes EPA should incorporate all technical corrections
into the emissions budgets regardless of magnitude of emissions change.
EPA in the rule making is proposing to accept unit-level operational information which results in a change
greater than 1% difference from the finalized CSAPR emission budget. The explanation of this approach in
the rule making notice leads WDNR to believe that EPA is only considering each correction individually for
whether the resulting change is greater than the 1% threshold. That approach does not have merit. EPA
should accept all changes which meet the aforementioned criteria and methodology used in determining
significant contribution under the finalized CSAPR. Obviously a number of corrections can yield a total
change in the emission budgets greater than 1%. An example specific to Wisconsin is the faulty assumption
of fuel ;witching from the current low sulfur fuel to ultra-low sulfur fuels over multiple units. For one
Attachment 4 - (Palmer CSAPR Presentation)
Page 8
generation unit the resulting emission budget increase is likely less than 1% of the emission budget.
However, correcting the fuel switch assumption over multiple units will have a larger impact.
In summary, a correction should not be discounted based on the change in emissions but rather based on the
technical merit itself.
3. Delay of Assurance Penalty Provisions — The WDNR strongly supports EPA's proposal to delay assurance
penalty measures in the CSAPR rule. The WDNR further believes that the assurance penalty provision should
first begin the year after the lowest emission budget levels comes into place
In the context of this proposed rule making, delaying the CSAPR assurance penalty measure to 2014 or later
is a prudent step for a number of reasons. Several Wisconsin utilities with projected shortfalls in allowances
versus their 2010 and 2011 operations have submitted requests to the Wisconsin Public Service Commission
for recovering costs related to CAPR compliance. In their submittals these utilities have indicated that
primary compliance mechanisms for 2012 is purchasing of allowances and/or curtailing operations coupled
with purchasing electricity.
EPA inaccurately assumed under the finalized CSAPR that Wisconsin could effectively meet emission
budgets under a restricted emissions trading program. In actuality, the finalized CSAPR set several conditions
which will likely require higher levels of out-of-state trading than that allowed under the restricted trading
program. Additional trading is needed for several reasons. First, the CSAPR allowance distribution leaves
some utilities with more allowances and some utilities fewer allowances than the individual source emission
levels used in calculating the emissions budgets. Consequently this approach inherently forces utilities to
trade emissions or curtail generation beyond that assumed in setting the budgets. Second, the finalized
CSAPR emissions budgets reflect specific generation for each utility unit as predicted by EPA's analysis.
Any utility, due to electric demand and uncontrollable emissions in any one year, can and will generate more
electricity than predicted. Therefore, without control options available in the early CSAPR years, utilities are
likely to trade more emissions than expected.
In addition, EPA cannot expect that all excess allowances generated in Wisconsin will be available to
Wisconsin utilities with allowance deficits. One logical action by a Wisconsin utility holding excess
allowances is to bank allowances in 2012 and 2013 to apply later against the deeper 2014 requirements at its
facilities. In addition, Wisconsin utilities have generation units in other states for which allowances may be
used. Therefore, WDNR does not anticipate all excess allowances generated in the state will be available for
sale. A factor that must also be considered is that any utility will obviously sell allowances to the highest
bidder whether in or out of state. In order for certain utilities not to be forced into a higher cost purchase they
must be able to secure allowances from the widest pool possible. Until a robust market of banked and excess
emission allowances is established, WDNR believes utilities should be able to purchase allowances without
restriction from any utility in their respective emission budget group.
In evaluating delay of the assurance provision, WDNR did not find an analysis in which EPA accounts for all
of these factors. Without knowing actual compliances and availability of allowances, EPA should allow for a
more open trading program through the initial CSAPR compliance years. In fact, EPA should err on the side
of implementing assurance provisions only when strong confidence exists for a viable allowance market.
Lastly, EPA should consider delaying the assurance penalty provision until some time after final emission
budget levels are in place. Based on reasonable installation schedules, scrubber and SCR equipment planned
as a result of the CSAPR finalized emission budgets will not be fully available until some time after 2014.
This means that utilities will be seeing a reduction in allowances in 2014 but as yet may still not have the
Attachment 4 - (Palmer CSAPR Presentation)
Page 9
necessary equipment in place to meet these requirements. Ultimately, WDNR believes purchasing allowances
or electricity will still be a primary short-term compliance mechanism through 2015 and after.
Phasing of Emission Budgets
The CSAPR sets the final emission budget level beginning in 2014. In the case where an additional SCR or
scrubber beyond the committed units is identified by IPM remedy runs, EPA cannot reasonably apply the
resulting emission reductions until some time after 2014. Clearly, a sharply accelerated approval and
installation schedule is necessary for any newly planned SCR or scrubber to apply before 2015. Further, as
evidenced by WPL's Columbia dry scrubber project, even pollution control equipment approved prior to the
finalized CSAPR will not be operating until sometime in 2014. In both cases of committed or newly planned
control equipment, the most appropriate approach is to incorporate emission reductions beginning in the first
full year after operation begins. In addressing the Columbia plant, this approach means SO 2 scrubber
reductions are first applied to a 2015 emissions budget and not in 2014 as currently proposed. This "full year"
concept holds true as well for any SCR and scrubber installation which is committed to occur before 2014 in
determining CSAPR emission budgets.
WDNR also recommends that EPA address appropriate fuel switching to ultra-low sulfur coal in emission
budgets after 2014. By 2015 and after more existing coal contracts will be expired or can potentially be
amended. In determining the timing for this option EPA needs to clearly show the wide availability of ultralow sulfur fuel and account for coal contract conditions. The time frame also needs to avoid creating artificial
market Conditions for ultra-low sulfur coal in early years before control equipment is online. In any
determination this fuel switching must still meet the CSAPR SO 2 cost-effectiveness ceiling of $2,300/ton or
other cost thresholds determined through reconsideration of the rule as applied to Wisconsin. Finally, fuel
switching to ultra-low sulfur coal should not be applied to generation units at any time that will be or have
received scrubber controls.
Another factor EPA should consider in phasing requirements is that the same utilities responding to CSAPR
emission budgets will be responding to EGU MACT requirements. Under MACT, utilities will need to
reduce emissions at all generating units and for different pollutants — not just at those units which can most
effectively meet CSAPR requirements. Because MACT is a unit-by-unit requirement, utilities may need to
spread resources to smaller and additional units. Whereas under CSAPR utilities would focus installations to
large generation sources to obtain the most cost-effective and largest amount possible of emission reductions
by 2014. These two rule compliance pathways seem to fight each other to some degree with regards to
equipment installations. In fact, the IPM modeling supporting EPA's proposed MACT rule shows that
equipment installations will likely be occurring for up to four years or at least through 2015. This analysis
demonstrates that utilities will be faced with a complex set of installations and operational decisions for all
units through both the initial CSAPR compliance years and into 2015. The utilities should be provided the
time frame necessary to achieve both CSAPR and MACT using the most logical and cost-effective
installation approach.
In summary, all emission reductions related to significant contribution (as currently determined under
CSAPR) should not be fully implemented for Wisconsin until some time after 2014. Proceeding with final
control levels by 2014 does not allow adequate time for equipment installations and allowance market
development. Likewise, the interim 2012 emission budgets are based on equipment that began operation in or
before 2011 and the 2014 emissions budgets are based on pollution control equipment coming online in 2012
and 2013.
For Wisconsin, implementing emission budgets in this manner will result in several installations being
counted in the following budget years compared to the current proposed emission budgets. These
Attachment 4 - (Palmer CSAPR Presentation)
Page 10
installations include: South Oak Creek Air Quality project available in calculating 2014 emission budgets;
Edgewater 5 SCR available in calculating the 2014 emission budget; and, Columbia dry scrubbers available in
calculating a 2015 emission budget. The resulting emission budgets are shown in Table 8. This calculation
for 2015 does not assume switching to ultra-low sulfur fuel which requires further evaluation as previously
discussed.
Table 8. Potential Phasing of Wisconsin Emission Budgets.
Emission
Budgets
NOx
SO2
2012
2014
2015
2012
2014
2015
Finalized
CSAPR
79,480
40,126
40,126
31,628
30,398
30,398
EPA
Corrections
79,480
47,883
47,883
34,100
32,870
32,870
WDNR
Requested
w/ Phasing
88,088
78,097
56,037
34,616
33,016
33,016
Notes:
i. EPA proposed SO2 adjustment = 7,757 tons annually starting 2014; NO,, adjustment = 2,473 tons
annually starting 2012.
ii. WDNR additional proposed adjustments: SO2 = 8,608 tons annually starting 2012, 37,971 tons
annually starting 2014, 19,911 tons annually starting 2015; NOx = 2,988 tons annually starting 2012,
2,618 tons annually starting 2014.
Attachment 4 - (Palmer CSAPR Presentation)
Page 11
Appendix A
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Attachment 4 - (Palmer CSAPR Presentation)
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Attachment 4 - (Palmer CSAPR Presentation)