BEFORE THE ILLINOIS POLLUTION CONTROL BOARD

IN THE MATTER OF:

NITROGEN OXIDES EMISSIONS FROM

VARIOUS SOURCE CATEGORIES:

AMENDMENTS TO 35 ILL. ADM. CODE

PARTS

211 AND 217

)

)

)

)

)

)

R08-19

(Rulemaking - Air)

NOTICE

TO:

John Therriault

Assistant Clerk

Illinois Pollution Control Board

James

R.

Thompson Center

100 West Randolph St., Suite 11-500

Chicago,IL 60601

SEE ATTACHED SERVICE LIST

PLEASE TAKE NOTICE that I have today filed with the Office

ofthe Clerk ofthe

Illinois Pollution Control Board the ILLINOIS ENVIRONMENTAL PROTECTION

AGENCY'S ANSWERS TO MIDWEST GENERATION'S QUESTIONS

FOR AGENCY

WITNESSES, a copy

of which is herewith served upon you.

ILLINOIS ENVIRONMENTAL

PROTECTION AGENCY

BY:~~

G

~occaforte

Assistant Counsel

Division

of Legal Counsel

DATED: September 30, 2008

1021 North Grand Avenue East

P.

O. Box 19276

Springfield,

IL 62794-9276

217/782-5544

TillS FILING IS SUBMITTEO

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BEFORE THE ILLINOIS POLLUTION CONTROL BOARD

IN THE MATTER OF:

NITROGEN OXIDES EMISSIONS FROM

VARIOUS SOURCE CATEGORIES:

AMENDMENTS TO

35 ILL. ADM. CODE

PARTS 211 AND 217

)

)

)

)

)

)

R08-19

(Rulemaking - Air)

THE ILLINOIS ENVIRONMENTAL PROTECTION AGENCY'S ANSWERS TO

MIDWEST GENERATION'S QUESTIONS FOR AGENCY WITNESSES

NOW COMES the lllinois Environmental Protection Agency ("Illinois EPA"), by its

attorneys, and pursuant to the Hearing Officer'sOrder dated June 12,2008, respectfully submits

the Illinois EPA'sAnswers to Midwest Generation's Questions for Agency Witnesses:

Questions for Mr. Kaleel

1.

Please explain the relationship between these proposed rules establishing reasonably

available control technology ("RACT")/reasonably available control measures ("RACM")

for the current ozone and fine particulate matter ("PM2.5") national ambient air quality

standards ("NAAQS") and what may be required for the revised ozone and PM2.5

NAAQS.

Unless USEPA issues new guidance regarding NOx control technology, we expect

that this RACT proposal will satisfy requirements to implement NOx RACT under

the revised NAAQS for the source categories and geographic areas to which this

proposal applies. The Illinois EPA has not yet determined the emissions reduction

measures needed to attain the revised ozone and PM

2.5 NAAQS.

It

may be

necessary to implement more stringent measures, however,

if additional measures

are necessary for attainment.

2.

What distinction, in the definitions or use, between industrial boilers, fossil fuel-fired

boilers, and electric generating units ("EGUs") does the Agency make or intend in this

rule?

EGU boilers are used primarily to generate electricity to sell on the electricity grid.

Industrial boilers are used primarily to generate power (steam

or electricity) for use

at the source. Both types of boilers may use fossil fuels, coal, oil, or gas.

3.

Ifthere are no cement kilns in the nonattainrnent areas, why are cement kilns included in

this rulemaking? Likewise, ifthere are no aluminum melting furnaces affected, why does

the rule include that sector?

There is an aluminum melting furnace in the Chicago non-attainment area (NAA),

although it has not operated for several years. To the best of

our knowledge, the

emission unit has not been torn down,

so it is possible that the company, or a future

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owner, will seek to operate the furnace in the future. There are no cement kilns in

the

current NAAs, although there is a cement kiln in Massac County, which USEPA

intends to designate as nonattainment for the 24-hour PM2.5 NAAQS.

The attached

letter shows USEPA's inteut regarding Massac County. See, Attachment 1.

4.

How will the limitation of a unit to only one emissions averaging plan in this rule interact

with the averaging plan provisions

of other rules? That is, is it the Agency's intent for this

rule

to preclude participation or inclusion of a unit that is in an averaging plan under this

rule from participating in averaging plans under other rules and vice versa?

It

is the Illinois EPA's intent that an emission unit be included

in

only one seasonal

and one annual averaging plan. Units affected by Subpart Q (Engine Rule) can be

included in an averaging plan with units affected by this proposal.

5.

In Section 217.150(a)(2), the regulatory language uses the word "emits." How will the

Agency determine whether a unit is subject to the rule? That is, how will the Agency

determine whether a unit emits, as opposed

to having the potential to emit, at the

threshold levels?

In general, the Illinois EPA intends to rely on Annual Emission Reports submitted

by owners/operators

of emissions sources.

6.

Applicability ofSubpart M and the nonapplicability of Subpart D are premised upon the

applicability

of the Part 225, Subparts C, D, and E ("the Illinois [Clean Air Interstate

Rule] CAIR") to electric generating units ("EGUs"). However, the federal rule

underlying the Illinois CAIR has been overturned (assuming that the D.C. Circuit Court

issues the mandate for its decision in appeal

ofthe rule), thus invalidating the Illinois

CAIR. Therefore, it appears that EGUs, which the Agency apparently intended to cover

in Subpart M

ofthis rulemaking, are covered by Subpart D. Does the Agency intend to

amend the language in Subpart M?

If

so, how?

The Illinois EPA does not agree with the Underlying premise

of this question;

however, the Illinois

EPA is amenable to amending Sections 217.340, 217.342,

211.3100,

and 217.160 as set forth in the response to Question 20, below.

7.

What does the Agency consider to be the nominal cost per ton for RACT for nitrogen

oxides ("NOx")?

The USEPA and the Illinois EPA have not established a specific cost threshold for

RACT, although the Illinois EPA has used $2500 to $3000

per ton as a range for cost

effectiveness.

8.

Does a load shaving unit (Section 211.3475) include a peaker power plant?

Yes.

9.

Section 217.150(a) says, "The provisions of this Subpart and Subparts D, E, F, G, H, and

M" ofthis Part apply to ... 1) All sources.... " (Emphasis added.) Is it the Agency's intent

2

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---

that all of these subparts actually apply to all sources in the specified geographic areas?

Isn't actually the Agency's intent that only one subpart will apply

to a unit or units at

threshold sources, as determined by the characteristics

of the unit?

It

is the Illinois EPA's intent that each respective Subpart apply to sources that meet

the applicability criteria and individual emission units

at such sources that meet the

applicability criteria, i.e., the provisions

of a respective Subpart apply to the extent a

source includes emission units

of the type covered under that Subpart.

10.

The "all industrial boilers" language in Section 217.160(a) and similar language in the

other subparts could be construed

to expand the scope of Section 217.150(a)(2), which

refers to "any industrial boiler [and other types

of emission units] that emits NOx in an

amount equal

to or greater than 15 tons per year and equal to or greater than five tons per

ozone season." Is it the Agency's intent to expand the applicability

ofthe rule in this

way?

The Illinois EPA's intent is that each Subpart apply to all of the affected emission

units

at an affected source, e.g., "any" emission unit that meets the applicability

criteria.

1I.

Is it the Agency's intent that the proposed rule applies to areas designated nonattainment

for either ozone or PM2.5?

Yes.

12.

What comprises the second compliance period ifthe first is May 1, 2010, through April

30,2011, and then is subsequently on a calendar year basis?

See

Section 217.152.

January 1, 2011, through December 31, 2011.

13.

How is the second sentence of Section 217.152(b) ("The owner or operator of an

emission unit that is subject to Subpart D, E, F,

G, H, or M must operate such unit in a

manner consistent with good air pollution control practice to minimize NOx emissions."

related to the compliance date?

There is no relation.

14.

Can the recordkeeping systems that sources already have in place comprise the "Iogs"

required at Sections 217.156(b)(8) and (9), assuming all

of the information required by

the rule is included?

Yes, as long as all ofthe required information under the rule is included.

15.

What is an "applicable compliance period" referred to in Section 21 7. I56(g)?

The annual or ozone season compliance period.

3

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16.

Does Section 217.156(k), which requires compliance certifications, recordkeeping, and

reporting for Subpart M units pursuant to 40 CFR Part 96, supersede the other

recordkeeping and reporting requirements

of Section 217.156?

The Illinois EPA's intent is that electric generating nnits subject to Subpart M

comply with

the compliance certifications, recordkeeping, and reporting

requirements

pursuant to 40 CFR Part 96, in conjunction with the other

recordkeeping and reporting requirements under Section 217.156, to the extent the

requirements

are not duplicative.

17.

Does the Agency have information confirming that the stacks at affected units that are

typically small can be tested safely, as required by Section 217.1517

No.

18.

Section 21 7.158(b) requires that averaging plans be submitted by May 1, 2010. What if

a source decides in 2010 that it does not want to average, but in 2015 it decides that it

does want to average?

Is that source precluded from establishing an averaging plan? Is

this a "once out/always out" provision?

Averaging plans can be amended once per year at the discretion of the

owner/operator. Units not previously included in an averaging plan can

be included

at a date later than May 1, 2010.

It

is not the Illinois EPA's intent to establish a

"once out/always

out" provision.

19.

What is the Agency's basis for establishing a rate ofO.08Ib/mmBtu rate for gas-fired

industrial boilers greater than 100 mmBtu? (Section 217.164(a))

The basis for this limit is set forth in the TSD, at page 43, specifically, Table 2-17a:

Cost Effectiveness

Data for Natural Gas-Fired ICI Boilers.

20.

Based upon the proposed applicability language in Subpart M, Section 217.340, assuming

the D.C. Circuit Court issues the mandate implementing its decision in the appeal

ofthe

CAIR, EGUs would be subject to the provisions

of Subpart D. Is the Agency amenable

to amending Sections 217.340, 217.342, 211.3100, and 217.160, as follows:

Section 217.340

Applicability [Subpart M)

Notwithstanding Subpart V or W

ofthis Part, the provisions of Subpart C of this

Part and this Subpart apply to all fussil fuel firee statienary beilers s\fbjeet te the

CAIR

1>10)(

Traeing Pregrams \fneer 81!llpart D er E efPart 225 any fossil fuel-

fired stationary boiler serving a generator that has a nameplate capacity greater

than

25 MWe and produces electricity for sale, excluding any units listed in

Appendix D

ofthis Part, located at sources subject to this Subpart pursuant to

Section 217.150

of this Part.

Section 217.342

Exemptions

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a)

Notwithstanding Section 217.340 ofthis Subpart, the provisions ofthis

Subpart do not apply to a fossil fuel-fired stationary boiler operating under

a federally enforceable limit

of NOx emissions from such boiler to less

than

15 tons per year and less than five tons per ozone season.

b)

Notwithstanding Section 217.340

ofthis Subpart, the provisions ofthis

Subpart

do not apply to a coal-fired stationary boiler that commenced

operation before January 1,2008, that is complying with Part 225.Subpart

B through the multi-pollutant standard under Section 225.233

of Part 225

or the combined pollutant standards under Subpart F

ofPart 225.

Section 211.3100

Industrial Boiler

"Industrial boiler" means, for purposes

ofPart 217, an enclosed vessel in which

water is heated and circulated either as hot water or as steam for heating or for

power, or both. This term does not include boilers serving a generator that has a

nameplate capacity greater than

25 MWe and produces electricity for sale, and

cogeneration units, as that term

is defined in Section 225.130 ofPart 225, if sueh

bailers

ar eageaeratiaauaits are subjeet ta the CAlR

~IOl(

TFaBiag Pragrams

uaBer Subpart

Dar II afPart 225.

Section 217.1

60

Applicability [Subpart D]

b)

The provisions ofthis Subpart do not apply to boilers serving a generator

that has a nameplate capacity greater than

25 MWe and produces

electricity for sale, and cogeneration units, as that term

is defined

in

Section 225.230 of Part 225, ifsueh bailers ar eageaeratiaauaits are

slllJjeet ta the CAlR

~IOl(

TraBiag Pragrams llI1Ber Subpart D ar II afPart

m.

The lIIinois EPA is amenable to amending Sections 217.340, 217.342, 211.3100, and

217.160 as follows:

Section 217.340

Applicability [Subpart

M]

Notwithstanding Subpart V or W of this Part, the provisions of Subpart C of

this Part and this Subpart apply to all fessil fuel fired stationary boilers

subjeet to the

CAIR NOx Trading Programs under Subpart D or E of Part

m any fossil fuel-fired stationary boiler serving at any time a generator that

has a nameplate capacity greater than 25 MWe and produces electricity for

sale, excluding any units listed in Appendix D

of this Part, located at sources

subject to this

Subpart pursuant to Section 217.150 of this Part.

Section 217.342

Exemptions

a)

Notwithstanding Section 217.340 of this

Subpart, the provisions of

this Subpart do not apply to a fossil fuel-fired stationary boiler

operating

under a federally enforceable limit of NOx emissions from

5

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such boiler to less than 15 tons per year and less than five tons per

ozone season.

b)

Notwithstanding Section 217.340

ofthis Subpart, the provisions of

this Subpart do not apply to a coal-fired stationary boiler that

commenced operation before January 1, 2008, that is complying with

Part 225.Subpart B through the multi-pollutant standard under

Section 225.233 ofPart 225 or the combined pollutant standards

under Subpart F of Part 225.

Section 211.3100

Industrial Boiler

"Industrial boiler" means, for purposes

of Part 217, an enclosed vessel in

which water

is heated and circulated either as hot water or as steam for

heating

or for power, or both. This term does not include boilers serving a

generator

that has a nameplate capacity greater than 25 MWe and produces

electricity for sale,

and eogeneration units, as dlat term is defiBed in Seetion

22S.HO of Part 22S, if such boilers or eogeneration units are subjed to meet

the applicability criteria

under Subpart M of Part 217 the

CUR NOll:

Trading Programs under Subpart D or E of Part 22S.

Section 217.160

Applicability [Subpart

D]

b)

The provisions ofthis Subpart do not apply to boilers serving a

generator

that has a nameplate capacity greater than 25 MWe and

produces electricity for sale, and eogeneration units, as dlat term is

defined

in

Seetion

22S.2~O

of Part 22S, if such boilers or eogeneration

units

are subjeet to meet the applicability criteria under Subpart M of

Part 217 die CAIR

NOll:

Trading Programs under Subpart

D

or

E

of

Part 22S.

21.

What is the basis for determining that the O.091b/mmBtu rate at Section 217.344(a) is

RACT?

The technologies to control utility boilers to below 0.09 Ib/MMBtu

are certainly

available

as evidenced by the number of utility boilers in Illinois and throughout tbe

United States

that currently control to that level or less. Emissions data for over 100

coal units equipped with SCRs and other low NOx technology were examined in a

comprehensive study by Erickson and Staudt with the results presented

at the EPA-

DOE-EPRI Combined Power Plant Air Pollution Control Symposium (the MEGA

Symposium) in 2006. See, Attachment

29 to the TSD, Selective Catalytic Reduction

System Performance

and Reliability Review, the 2006 MEGA Symposium, Paper

#121, by Clayton A. Erickson and James E. Staudt. Without a doubt, coal-fired

units have demonstrated

that emissions under 0.09 Ib/MMBtu are possible using

combustion controls, post-combustion controls,

or combinations of the two. In fact,

Illinois' own Baldwin Unit

#3 achieves below 0.091b1MMBtu using only combustion

control.

Otber units in Illinois achieve under 0.09 Ib/MMBtu using SCR.

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So, from the perspective of RACT, the only remaining question is whether or not the

technology is reasonable in cost. As a benchmark of what is reasonable, the United

States Environmental Protection Agency (USEPA) determined in its Clean Air

Interstate Rule analysis, which motivated installation of SCRs,

that

The EPA's analysis indicates that emissions reductions from electric

generating units (EGUs) are highly cost effective,

and EPA encourages States

to adopt controls for EGUs.

See, 70 Fed. Reg. 25162, 25165 (May 12, 2005).

Further, in describing

what is "highly cost effective" USEPA stated:

(II) Determination

of Highly Cost-Effective Amount

The EPA determined the dollar amount considered to be highly cost effective

by reference to the cost effectiveness

of recently promulgated or proposed

NOX controls. The EPA determined

that the average cost effectiveness of

controls in the reference list ranged up to approximately $1,800 per ton of

NOX removed (1990$), on an annual basis. The EPA considered the controls

in the reference list to be cost effective.

See,

70 Fed. Reg. 25162, 25173 (May 12, 2005).

It

is widely recognized that combustion controls are reasonable in cost. However,

SCR also provides NOx reductions

at reasonable costs. Figure 2-17 from the TSD

can be used to make this point. A capital cost of

$200/KW

is near the high end of

what a utility SCR retrofit would typically be expected to cost and this translates

roughly to $20,000IMMBtulbr, assuming a heat rate on the

order of 10,000

Btu/kWhr.

Using Figure 2-17 and an assumed uncontrolled NOx level of 0.50

IbIMMBtu, one arrives

at $2000/ton of NOx removed. Uncontrolled units would

typically have an emissions rate

of at least 0.50 IbIMMBtu. But, even at

uncontrolled NOx levels of 0.40 IbIMMBtu, the cost is estimated at about $2500/ton.

For more typical capital cost numbers in the range of $100/KW to

$150/KW

(roughly $10,000-$15,00 OIMMBtu/hr on Figure 2-17), the cost of NOx reduction

would be below $2000/ton. Companies typically do not publish their cost data. But,

fortunately, cost data is available for some SCR retrofits.

As shown in the attached

report submitted by Progress Energy to the North Carolina Public Utilities

Commission, the Asheville Unit 1 SCR retrofit cost

$28 million on the 191 MW unit

- $149/KW.

See, Attachment 2. And, as reported in Power Engineering Magazine,

(http://pepei.pennnet.com/display_

article/162367/61

ARTCL/none/none/l/SCR-=-

Supremely-Complex-Retrofitl), in an article titled

"SCR =Supremely Complex

Retrofit), Duke Power'stwo Belews Creek Units

(2 times 1120 MW) were retrofit

for $325 million,

or $145/KW. See, Attachment 3. Thus, a "Supremely Complex

Retrofit" cost $145/KW.

According to a study of SCR costs published by Murano and

Sharp in February

2006, (http://findarticles.com/p/articles/mi_qa5392/is_200602lai_n21409717)

7

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"Overall, costs were reported to be in the $100 to $200/kW range for the

majority

of the systems (Figure 2), with only three reported installations

exceeding $200IkW. System size (with a 644-MW average unit size in the

$100 to $1501kW range) seems to dominate; larger average system costs

are

significantly less than the next survey category (the $150 to $200/kW range,

with a 309-MW average unit size)."

See, Attachment

4. As a result, multiple studies have affirmed the cost of SCR to be

in a capital cost range where they

are shown to provide reductions below the "highly

cost effective" level established by USEPA.

Earlier studies using capital costs in the range of

$70-$90/KW

determined that NOx

could be controlled from

SCR at costs in the range of

$400-$17681

ton. See,

Attachment 22 to the TSD,

and Attachment 5, Cichanowicz, "SCR for Coal-Fired

Boilers: A Survey

of Recent Utility Cost Estimates," EPRl-DOE-EPA Combined

Power Plant Air Pollutant Control Symposium, the MEGA Symposium, August 25-

29, 1997, Washington, DC. This

is below the

$1800/ton

(in 1990$) that USEPA

determined to be "highly cost effective." However, SCR costs have gone

up faster

than inflation. But, even doubling

that cost range to

$800-$3536/ton

of NOx

reduced to account for escalation

of SCR costs, keeps the cost in the range of what

USEPA determined to be "highly cost effective" except

at the very highest end.

22.

The Technical Support Document ("TSD") indicates on page 130 that there are a total of

12 industrial boilers subject to the NOx SIP call affected by this proposed rule while the

Statement

ofReasons on page 10 states that there are 80 industrial boilers affected by the

proposed rule. Are these additional

50 industrial boilers all less than 250 mmBtu?

The additional

68 industrial boilers are less than 250 mmBtu and are not subject to

the NOx SIP Call.

23.

The TSD claims there are a total of 18 EGUs subject to the rule, while the Statement of

Reasons says there are 20 "fossil fuel-fired stationary boilers" subject to the rule. Are

there fossil fuel-fired stationary boilers that are not EGUs that

are subject to the rule?

No, there are 20 EGU boilers. Table E-l of the TSD Appendices lists units;

however, there

are two instances in which one unit is comprised of two boilers (see,

Midwest Generation LLC, Joilet 29: Unit 7, Boilers

71 and 72, and Joliet 29: Unit 8,

Boilers 81 and 82).

Ouestions for Dr. Staudt

24.

Are NO and N0

2

the only components ofNOx?

Yes, however, they are reported on a mass basis as if they were all in the form of

NO

z•

For boilers, the majority of the NOx is in the form of NO as it leaves the stack.

However, the NO subsequently oxidizes to

NO

z

in the atmosphere.

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25.

Explain oxy-combustion. In your testimony, you say that NOx is reduced by reducing

the amount

of oxygen available for the nitrogen to combine with, yet oxy-combustion

appears to provide even more oxygen in the combustion chamber.

Oxycombustion

is described in my testimony as a nitrogen-depletion approach.

Normally, nitrogen comprises 79%

of combustion air. By having an enriched

oxygen environment, nitrogen

is depleted in the combustion air to much lower

amounts. One benefit

of this is that there is less nitrogen available to oxidize at high

temperature to NO

or N02.

26.

Your testimony suggests there are other post-combustion controls besides SCR and

SNCR. What are those other types

of post-combustion controls?

Other approaches include oxidation of the NO to water soluble oxides using ozone,

peroxide,

or with an electric barrier discharge reactor, and then scrubbing them out

with a wet scrubber, and injection of Trona. Duct injection of Trona (sodinm

sesquicarbonate) will remove some NOx as well as S02. However, SNCR and SCR

are the most widely used post-combustion controls.

27.

Is SCR RACT? Or is it beyond RACT?

SCR can be RACT.

In fact, the first retrofit of SCR on a coal fired utility boiler was

at Public Service Company of New Hampshire'sMerrimack Unit #2 in 1995, and

this was in response to

New Hampshire'sNOx RACT rule that was implemented at

that time. SCR has been retrofit on several other coal fired boilers in response to

the Ozone

Transport Commission NOx budget rule (PSNH Merrimack 1) and on a

number of Group 2 boilers in response to regulations enacted under Title IV of the

Clean

Air Act. Both of these regulations were ostensibly intended to impose NOx

controls

at a cost ($/ton of NOx) similar to low NOx burners, which are widely

regarded

as within RACT.

If

$2500-$3000/ton is to be the guide for what is RACT,

Figure 2-17

of the TSD demonstrates that SCR is capable of being RACT. However,

having said that, I do not believe

that SCR is likely to be necessary under the

proposed rule. I expect

that less expensive controls or combinations of less

expensive controls

are most likely to be used.

28.

Would a wet scrubber intended to reduce S02 be a NOx scrubber as well if the NOx were

first oxidized?

See

Section 1.2.2, page 4 of the TSD.

Yes,

if the NOx were both oxidized to a water-soluble form and subsequently

captured in the scrubber.

29.

What does the following mean: nNOx emissions from residual oil-fire boilers can be

controlled level by using residual

fuel oil. ...n (Emphasis added.)

See

Section 2.1, page 5

ofthe TSD.

The term "level"

is a typographical error. Once you remove that, the sentence

should make sense. But, to explain, reducing fuel nitrogen

is a way of controlling

NOx emissions.

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30.

Is it the case that there are currently no wood-fired boilers that would be subject to the

proposed rule?

That is my understanding.

31.

Does the fact that pulverized coal is used in wall-fired boilers contribute to the NOx

levels?

See

Section 2.2.1, page 9

ff.

of the TSD.

Yes, coal contains significant levels of fuel nitrogen, which contributes to NOx.

32.

Page

13 ofthe TSD says that Cleaver Brooks illustrates that with proper control, NOx

emissions can be reduced, and page 15 ofthe TSD says that Cleaver Brooks illustrates

that with proper retrofits, NOx emissions can be reduced. What are those "proper"

controls and retrofits? How are they effective

in reducing NOx? Who is Cleaver

Brooks?

The

"proper" retrofits referred to are low NOx burners. The effectiveness of these

controls in reducing NOx is shown in Tables

2-2 and 2-3 of the TSD, wbich are from

Cleaver Brooks

and referenced in a letter, dated May 19, 2006, submitted by Daniel

J. Willems of Cleaver Brooks to the New Hampshire Division of Environmental

Services (see, Attachment 8 to the TSD). The data in these tables demonstrate

that

these burners are capable of achieving emission rates at extremely low levels - well

below the proposed limits.

As noted in the TSD, at page 13, Cleaver Brooks is the

largest producer of hot water

and steam boilers in the United States.

33.

How do excess air and complete combustion affect safety?

See

Section 2.3.1, page 20 of

the TSD.

Reducing excess

air too far can make the flame unstable or even extinguish it. In

this case there is a risk

of high combustible levels remaining in the gas that can

affect safety.

In a worst-case scenario there is risk of a boiler explosion. However,

operating limitations and control devices prevent these conditions from occurring.

As excess air is reduced, operating limitations on CO emissions or high unburned

carbon in the case of coal-fired boilers will be reached well before unsafe conditions

are reached, preventing the operator from reducing excess

air further. Also, boilers

have flame monitors as

part of their controls that also assure safety by alerting the

operator to a problem with the flame. So, a boiler is capable

of operating at low

excess

air to reduce NOx while also operating in a safe manner.

34.

Page 22 of the TSD refers to 100-600 hp boilers. How large are these boilers in terrns of

mrnBtu heat input capacity?

One

hp is 2524 Btu/hr. So, 100-600 hp boilers are in the range of 252,000 Btulbr to

about 1.5 million Btu/br. The specific reference you have identified is in the section

on combustion tuning (mostly

of interest for small boilers) and relates to the cost of

oxygen

trim systems in the range of $6000-$7000 for boilers of that size. And, as

noted in the TSD, for larger boilers the cost would be somewhat higher.

Of course,

10

???????????

??????? ?? ??????????

???????? ???????? ??????????

???? ????

---

100-600 hp boilers are well below the size of boilers that are subject to emissions

limitations. However, small boilers may be subject to the combustion tuning

requirement, depending upon the emissions

ofthe boiler.

35.

Please describe the combustion tuning training requirement and where companies may

obtain such training.

This is described in the TSD. Boiler manufacturers

and private companies offer

such training. The American Boiler Manufacturer'sAssociation website

(www.abma.comltraining.html) lists training courses

that are available.

36.

Regarding SNCR, the TSD says that there need to be several injection points to inject the

reagent

at proper temperatures for large boilers. What happens ifthe reagent is injected at

an improper temperature?

See

page 30 of the TSD.

The injectors

are placed in locations on the boiler designed to inject the reagent into

a temperature zone where the desired chemical reactions occur. The

proper

temperature zone changes as boiler conditions, such as load, change. So, multiple

injection zones may be needed. SNCR systems have control systems to determine

the

proper injectors to use for a given load snch that the reagent is injected in the

correct location (and therefore, the correct temperature)

at all times. Since there

are hundreds of SNCR systems installed on industrial and utility boilers, this is

something that engineers have good experience with.

If

the reagent were not

injected in the

proper location (where the correct temperature is), then poor NOx

reduction

or high ammonia slip would result.

37.

Why would the cost ofSNCR on a wood-fired boiler be about the same as for a coal-fired

boiler

ofthe same size?

The capital cost

of an SNCR system depends primarily on the number of injectors,

which

is largely related to the boiler size and heat input, and the amount of reagent

used (which determines the size

of the storage tank). So, for solid fuel boilers of

similar heat input and similar NOx levels, you would expect similar costs.

38.

Looking at Table 2-12a, what is a "Wood Fired IPP"?

In

this same column, the table says

that the fuels are "Biomass Wood/Coal." What does this mean?

A "Wood fired

IPP" is an Independent Power Producer that has a boiler that burns

wood. Fuels "Biomass Wood /Coal" mean

that the boiler fires those fuels - and may

fire combinations

of these fuels.

39.

Page 30 of the TSD states, "For EGU's SNCR capital cost is in the range of about

$15/KW, and in most cases NOx reductions in the rage

of about 30% are possible." How

does this translate

to dollars per ton ofNOx removed?

Figures 2-14a

and 2-14b of the TSD, which are data for

Industrial/Commercial/Institutional (ICI) boilers,

are also useful for getting a sense

ofthe cost for utility boilers if you look at the far right where the information for

11

???????????

??????? ?? ??????????

???????? ???????? ??????????

???? ????

---

large ICI boilers is shown. As shown in Figure 2-14b, the capital cost is about

$1500/MMBtu for large ICI boilers, which is roughly equivalent to $15/KW. And,

as shown in Figure 2-14a, the $/tou

of NOx reduced is in the range of about

$1500/ton on an annual basis.

40.

On page

36 ofthe TSD is a discussion of the cost of SCR; the TSD appears to essentially

argue that a cost expressed

in dollars per mmBtu is a better measure of RACT because an

expression in dollars per ton removed depends upon baseline NOx. Please explain.

This does not argue for

or even suggest a different measure for RACT. The reason

the cost in $IMMBtu is showu

is to give the cost in terms offuel use, which may be

useful for industrial boiler owners in the same sense

that $/MWhr would be of

interest to a power plant owner.

41.

Have the cost calculations for industrial/commercial/institutional ("ICI") boilers included

retrofit issues?

Yes

42.

It

appears that the TSD includes a number of evaluations of cost-effectiveness of

proposed rule from a number of different sources. What is the bottom line,

i.e.,

the

Agency'sdetermination

of the cost-effectiveness ofthe proposed rule, in at least 2006

dollars?

See

TSD pages 41-42.

The bottom line is as stated in my prefiled testimony.

"Fortunately, for each

of the source categories affected there are available controls

that can be used to provide the NOx reductions required by the rule at costs

envisioned to be within the expectations for RACT."

43.

What is the significance

ofthe statement on page 126 of the TSD that "the [USEPA cost]

model does not allow for differences

in stack height, or explicitly distinguish between

Part 60 and Part

75 systems"?

The significance of this statement is that the model used was developed primarily

for utility boilers, which generally have taller stacks

than industrial boilers and Part

75 systems. Therefore, I would expect that an industrial boiler continuous emissions

monitoring system's(CEMS) costs would likely be less since the stacks

are smaller

and also they would likely have a Part 60 CEMS.

44.

The TSD

at page 126 suggests that opacity monitoring is required by this rule where a

source, because

of the size ofthe affected unit, must employ Part 75 monitoring. Is it the

intent

of this rule to require opacity monitoring? If so, why is opacity monitoring part of

a NOx RACT rule?

No.

45.

What is a "point source"?

See

TSD page 130. Is the term defined in the rule?

12

???????????

??????? ?? ??????????

???????? ???????? ??????????

???? ????

---

A point source is an individual stationary emission unit. No, the term is used in the

TSD, but is not defined in the rule.

46.

The TSD states on page 131, "The NOx inventory was generated through the use of year

2005 annual emission reports submitted pursuant to 35

Ill.

Adm. Code Part 234. For our

purpose, year 2005, instead of year 2002, was selected because some sources have been

either shut down or modified since 2002." What is the significance of 2002 that the TSD

would explain using 2005 data instead?

USEPA'simplementation rules for ozone and PM2.5 require the use of 2002 as the

base year for emissions inventories and determining reasonable further progress.

The I1Iinois EPA used 2005 emissions data to identify potentially affected units

because 2005 data are more current.

47.

Please explain the difference between Tables H-I and I-I. Appendix pages 31 and 33.

Table

0-1

sorts all sources by the ID number, whereas Table

1-1

groups them by

emission category and nonattainment area.

48.

In

Appendix A, Table A-4, what does "703" in the first column mean?

It

means uncontrolled emissions are 703 tons per year for the gas fired refinery

boiler that was being evaluated in Table A-4.

Respectfully submitted,

ILLINOIS ENVIRONMENTAL

PRO~ON

AGENCY

BY:~

Gina Roccaforte

Assistant Counsel

Division of Legal Counsel

DATED: September 30,2008

1021 North Grand Avenue East

P. O. Box 19276

Springfield, IL 62794-9276

217/782-5544

13

THIS FILING IS SUBMITTED

ON RECYCLED PAPER

???????????

??????? ?? ??????????

???????? ???????? ??????????

???? ????

---

STATE OF ILLINOIS

COUNTY OF SANGAMON

)

)

)

)

SS

CERTIFICATE OF SERVICE

I, the undersigned, an attorney, state that I have served electronically the attached

ILLINOIS ENVIRONMENTAL PROTECTION AGENCY'S ANSWERS TO

MIDWEST GENERATION'S OUESTIONS

FOR AGENCY WITNESSES, upon the

following person:

John Therriault

Assistant Clerk

Illinois Pollution Control Board

James

R. Thompson Center

100 West Randolph St., Suite 11-500

Chicago,IL 60601

and mailing it

by first-class mail from Springfield, Illinois, with sufficient postage affixed

to the following persons:

SEE ATTACHED SERVICE LIST

ILLINOIS ENVIRONMENTAL

PROTECTION AGENCY,

Assistant

G~

Counsel

Division

of Legal Counsel

Dated: September 30, 2008

1021 North Grand Avenue East

Springfield, Illinois 62794-9276

(217) 782-5544

???????????

??????? ?? ??????????

???????? ???????? ??????????

???? ????

---

SERVICE LIST 08-19

Timothy

J. Fox

Hearing Officer

Illinois Pollution Control Board

100

W. Randolph St., Suite 11-500

Chicago, IL 60601

Virginia Yang

Deputy Legal Counsel

Illinois Department

ofNatural Resources

One Natural Resources Way

Springfield,

IL

62702-1271

Katherine D. Hodge

Monica

T. Rios

Hodge Dwyer Zeman

3150 Roland Ave.

P.O. Box 5776

Springfield,

IL

62705-5776

Matthew Dunn

Chief

Environmental Bureau North

Office

ofthe Attorney General

69

W. Washington St., Suite 1800

Chicago, IL 60602

Kathleen

C. Bassi

Sheldon A. Zabel

Stephen

J. Bonebrake

SchiffHardin LLP

6600 Sears Tower

233

S. Wacker Drive

Chicago, IL 60606-6473

Alec M. Davis

General Counsel

Illinois Environmental Regulatory Group

215

E. Adams St.

Springfield, IL 62701

???????????

??????? ?? ??????????

???????? ???????? ??????????

???? ????

---

IEPA ATTACHMENT No.l

UNITED STATES ENVIRONMENTAL PROTECTION AGENCY

REGION 5

77 WEST JACKSON BOULEVARD

CHICAGO, IL 60604.3590

AUG 1 82008

REPLY TO THE ATIENTION OF'

R-19J

The Honorable Rod Blagojevich

Governor of Illinois

Springfield, Illinois

62706

Dear

Governor Blagojevich:

Thank

you for your recommendations on the status of fine particle (PMZ,5) pollution

throughout

D1inois. As you know, fine particle pollution represents one of the most significant

baniers to clean air facing our

nation today. Health studies link these tiny particles - about

I130

1h

the diameter of a human hair - to serious human health problems including aggravated

asthma, increased respiratory symptoms

like coughing and difficult or painful breathing, chronic

bronchitis, decreased

lung function, and even premature

death

in people with heart and lung

disease. Fine particle pollution

can remain suspended in the air for long periods of time and

create public health problems

far away from emission sources. Reducing levels of fine particle

pollution

is an important part of our nation'scommitment to clean, healthy air.

We have reviewed the December 18, 2007, and June 2,2008, letters from Laurel

L.

Kroack, Chief of the Bureau of Air, D1inois Environmental Protection Agency, and the August 6,

2008, letter from Douglas Scott, Director, D1inois Environmental Protection Agency, submitting

the

D1inois recommendations on air quality designations for the 2006 24-hour PM

Z

.5 standards.

We have also reviewed the technical information submitted to support the D1inois

recommendations. We appreciate the effort your State has made to develop this supporting

information. Consistent

with the Clean Air Act, this letter is to inform you that the U.S.

Environmental Protection Agency intends to make modifications to the designations and

boundaries recommended

by D1inois.

We have enclosed a detailed description of areas where EPA intends to modify your state

recommendations, and

the basis for such modifications. Your Environmental Director will also

receive a copy

of this letter and the enclosure. Should you have additional information that you

wish EPA to consider in this process, please provide it to us by October 20, 2008.

EPA has taken steps to reduce fine particle pollution across the country, such as the Clean

Diesel Program, which

we expect to dramatically reduce emissions from highway, non-road and

stationary diesel engines.

In addition, State programs to attain the 1997 PM

z

.5 standards will

help to reduce unhealthy levels of fine particle pollution.

RecycledlRecyciable • Pnnted with Vegetable Oil eased Inks 00 100% Recycled Paper (50% Poslconsurner)

???????????

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---

We intend to make final designation decisions for the 2006 24-Hour PM2.S standards by

December

18. W08. Please also be aware that EPA plans to publish a notice in the Federal

Register

in the near future in order to solicit public comments on our intended designation

decisions. If

you have any questions. please do not hesitate to contact me. We look fOlward to a

continued dialogue

with you as we work together to implement the PM2.S standards.

Sincerely,

~r.:-0uJJ

Regional Administrator

Enclosure

cc: Douglas P. Scott

Director

D1inois Environmental Protection Agency

2

???????????

??????? ?? ??????????

???????? ???????? ??????????

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---

Review of Designations in Illinois

For the Particulate Matter Air Quality Standard

The table below identifies the counties in l1linois that EPA intends to designate as not

attaining the 2006 24-hour fine particle (pM2.5) standard.' A county will

be designated

as nonattainment

if it has an air quality monitor that is violating the standard or if the

county

is determined to be contributing to the violation of the standard.

Where EPA intends to include only part

of a county in a nonattainment area, we have

indicated the boundaries

of the portion of the county that will be included. Following this

table

is a discussion of each area and the basis for EPA's intended designations and then a

description

of the data EPA examined. EPA intends to designate as attainment!

unclassifiable all other l1linois counties or parts thereof not identified

in the table below.

Area

Current PMZ.5

Illinois Recommended

EPA'sIntended

Nonattainment Area Nonattainment Counties

Nonattainment Counties

Chicago-

Cook

Cook

Cook

Gary-

DuPage

DuPage

Du Page

Kenosha,

Kane

Kane

Kane

IL-IN-WI

Lake

Lake

Lake

Mc Henry

Mc Henry

Mc Henry

Will

Will

Will

Grundy:

Grundy:

Grundy:

Aux Sable Township

Aux Sable Township

Aux Sable Township

Goose Lake Twp.

Goose Lake Township

Goose Lake Township

Kendall:

Kendall:

Kendall:

Oswel!o Townshio

Oswel!o Townshio

Oswel!o Townshio

Davenport-

None

None

Rock Island

Rock Island,

IA-IL

Paducah,

None

None

Massac

KY-IL

Saint Louis, Madison

Madison

Madison

MO-IL

Monroe

Monroe

Monroe

St Clair

St Clair

St Clair

Randolph:

Randolph:

Randolph:

Baldwin Townshio

Baldwin Townshio*

Baldwin Township

• IllInOIS recommended a slightly smaller partIal county area, excludmg a portIon of Baldwm TownshIp

from the nonattainment area. EPA intends to retain the entire Baldwin Township'in the nonattainment area.

1 EPA designated nonattainment areas for the 1997 fine particle standards in 2005. In

2006, the 24-hour PM2.5 standard was revised from 65 micrograms per cubic meter

(average

of9S

th

percentile values for 3 consecutive years) to 35 micrograms per cubic

meter; the level

ofthe annwil standard for PM2.5 remained unchanged at 15 micrograms

per cubic meter (average

of annual averages for 3 consecutive years).

???????????

??????? ?? ??????????

???????? ???????? ??????????

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---

On June 8, 2007, in a memorandum from Robert Meyers to the EPA Regional

Administrators, EPA issued guidance on a timetable for designation

of areas violating the

PM2.5 air quality standards promulgated in 2006 and factors that EPA urged states to

consider as they prepared recommendations for nonattainment area boundaries. This

guidance was sent to the Governor

of Illinois as an attachment to a letter dated July 9,

2007, requesting the State'srecommendations.

Pursuant to section 107(d) of the Clean Air Act, EPA must designate as nonattainment

those areas that violate the NAAQS and those areas that contribute to violations. The

technical analysis for each area identifies the counties with monitors that violate the 24-

hour PM2.5 standard and evaluates the counties that potentially contribute

to fine particle

concentrations

in the area. EPA has evaluated these counties based on the weight of

evidence of the following nine factors recommended in EPA guidance and any other

relevant information:

- pollutant emissions

- air quality data

- population density and degree

of urbanization

- traffic and commuting patterns

- growth

- meteorology

- geography and topography

- jurisdictional boundaries

- level of control of emissions sources

Additional background information on each

of the nine factors can also be found in the

background section below.

EPA also computed a Contributing Emissions Score (CES) for each county. The CES is

a metric that takes into consideration emissions data, meteorological data, and air quality

monitoring information

to provide a relative ranking of potential impacts of counties in

and near an area on violating monitors. While this metric provides a useful synthesis of

important relevant information, including weighting the emissions ofvarious pollutants

according

to estimates of the relative importance of each pollutant, the CES is not the

exclusive variable EPA uses to consider these factors. A summary

of the CES is included

in the background section, and a more detailed description can be found at

http://www.epa.gov/ttn/naags/pm/pm252006techinfo.html#C.

Review for the Illinois Portion of the Chicago-GaIT-Kenosha. IL-IN-WI

Metropolitan Area

Discussion:

EPA reviewed relevant information for the ten counties (including eight counties in

Illinois) partly or fully within the area designated nonattainment for the 1997 standards as

well as for surrounding counties. There are violating monitors in Cook and Will

Counties and

in Lake County, Indiana. Illinois recommended a definition ofthe

2

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??????? ?? ??????????

???????? ???????? ??????????

???? ????

---

nonattainment area for the 2006 standards that reflects the same boundaries within

Illinois as were established for the 1997 standards, including (within Illinois) Cook, Du

Page, Kane, Lake, Mc Henry, and Will counties, Aux Sable and Goose Lake Townships

in Grundy County, and Oswego Township

in Kendall County. EPA agrees with this

recommendation.

EPA also examined information for other counties within and adjacent to the Combined

Statistical Area as well as for adjacent counties. The bulk

of emissions and population

are captured without including DeKalb, Grundy, Kankakee and Kendall Counties, since

these counties have limited emissions and population. Nevertheless, we support the

recommendation by the Illinois EPA to include the three townships

in Grundy and

Kendall counties in the nonattainment area to maintain consistency with the ozone

designations and the prior PM

25

designations and thereby facilitate planning, as well as to

include slightly more emissions

in the planning area.

Emissions for other surrounding counties are relatively low, and no other factor

warranted designating these other counties nonatlainment.

Figure I is a map of the counties in the area and other relevant information such as the

locations and design values

of air quality monitors, the metropolitan area boundary, and

counties recommended as nonattainment by the States.

sin

ROf'

~

<1"

I!!>

l!"

Illinois

.

.,

o

Stlle

1~1Idaton

!Of I'ICI"l3tl!inment

-34,

0

Sl.r.ereoJmleMatcmforparbal oonattalmntll1

SII:e retOll\'Tlel1daSOllIOta (ilfe{enz rr:t1tO area

Mo&.or Yiola:ing 24-tlr PU2.S NAAQS

(pre'imin.

2005.2001

design

'ti1!Ues)

Mi.

M~r.rairl'ng24-IlrPM2.5NMas

lpre"min. 2005-2001 des'gn va:t.les)

M~\'IoIating

24.flr PM2.S NMOS

Iprl!rrmln_ 2005-2007 incomplete

~I!sig:l ~arues)

National higllway$

c::J 2006 Combined

Sla~cal

Area

'~

PM2.SNoniIlIainmentArea

(1997 NMOS)

JiI

~~,..---

r::::::I

All 1'1.'2.5 NonattainmentAleas

11991 NMOS).

r-t--1

NonallaM1tim'Ma~enantIJ

Atea

......... for 8-1W Olone

~

EGUnilh!IUJCAP

emissiOns>

5.000

tDllSr'year in

2002

@

o:tlef

Point

Source

with total CAP

emissions>

5.000

tDf15fYUr

il2002

.-

Com~~~_~(49~1

Indiana ••

,

Figure 1- Note: Map produced prior to Indiana's nonattainment recommendation for Lake County, Ind.

3

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---

Factor 1: Emissions data

Table 1 shows emissions of PM2.5 components (given in tons per year) and the CESs for

potentially contributing counties in the Chicago area. Counties that are part

ofthe

Chicago nonattainment area for the 1997 PM

2

.

5

NAAQS are shown in boldface. Counties

are listed

in descending order by CES.

Tbl

a e 1. PM

~"

24h

- our Comt anent EmISSions an

d

CESs.

County

State

CES

PM"

PM,.,

PM,.,

SO,

NOx

VOCs

NH,

Recommended

emissions

emissions

emissions

(tpy)

(tpy)

(tpy)

(tpy)

Nonattainment?

total

carbon

other

(tnv)

(tnv)

(tnv)

Cook

IL

Yes

100

10081

5407

4674

35.354

175.267

152288

4550

Lake IN.

No

100

7079

1219

5861

39500

54.203

24679

3784

Will IL

Yes

95

5432

1.236

4195

78792

46028

19886

1407

Porter IN

No

41

3901

719

3183

24458

29930

9795

909

DuPa2e

IL

Yes

16

2075

1259

816

2013

36880

29541

1.385

Jasper, IN

No

14

2641

280

2360

40723

20,104

3,367

2,929

Kankakee, IL

No

9

1,660

419

1242

366

7,351

6,830

1699

Kane

IL

Yes

4

1997

733

1263

1037

16528

15578

1293

Grundy, IL

Partial

3

1105

248

857

362

4057

4223

1027

Lake

IL

Ves

3

2,657

1070

1587

14719

29478

32778

747

Kendall,IL

Partial

2

811

230

581

351

3697

3693

753

MeHenry,IL

Ves

1

2102

634

1,468

592

9493

10596

1224

Kenosha WI

No

I

1489

460

1,030

33,988

15967

7,857

647

Within lIlinois, emissions are highest in Cook, Will, DuPage, Lake, Kane, and McHenry

Counties. Emissions are moderate in Kankakee, Grundy, and Kendall Counties.

Factor 2:

Air

quality data

The 24-hour PM2.5 design values for counties in the Chicago area are shown in Table 2.

Table 2. Air Oualitv Dala

County

State

Design Values

Design Values

Recommended

2004.06 (j.tglm')

2005.07 (j.tglm')

Nonattainment?

Cook IL

Yes

42

40

Lake IN

No

38

37

Will IL

Yes

36

37

Porter IN

No

31

32

DuPa2e IL

Yes

33

35

Kane IL

Yes

32

35

Grundv. IL

Partial

Lake IL

Yes

33

35

Kendall IL

Partial

McHenry,IL

Yes

31

31

For purposes of its review, EPA used data available from the Chemical Speciation

Network and the Interagency Monitoring

ofProtected Visual Environments (IMPROVE)

4

???????????

??????? ?? ??????????

???????? ???????? ??????????

???? ????

---

network to estimate the composition of fine particle mass on days with the highest fine

particle concentrations. On high concentration days during cold weather months in this

area, EPA found on average a total urban contribution

of 8.8 flg/m

3

,

consisting of

004

flg/m

3

of sulfate, no nitrate,

804

flg/m

3

of organic particles, and no miscellaneous

inorganic particulate. On high concentration days during warm weather months

in this

area, EPA found on

avera~e

a total urban contribution of3.9 flg/m

3

, consisting of 0.5

flg/m

3

of sulfate, 3.1 flg/m of organic particles, and 0.3 flg/m

3

of miscellaneous

inorganic particulate. These estimates were used for weighting

of the emissions of

different pollutants in calculating the contributing emissions scores.

Factor 3: Population density and 'degree of urbanization (including commercial

development)

Table 3 shows the 2005 population for each county in the area being evaluated, as well as

the population density for each county in that area. Population data give an indication

of

whether it is likely that population-based emissions might contribute to violations of the

24-hour

PM25 standards.

Table 3. Ponulation

County

State

2005

2005 Population

Recommended

Population

Density (pop/sq

Nonattainment?

mil

Cook,IL

Yes

5,303,943

5545

Lake, IN

No

491706

980

Will, IL

Yes

642,625

758

Porter IN

No

157,408

375

DuPaoe IL

Yes

931,219

2769

Kane IL

Yes

483,208

923

Grundv IL

Partial

43736

102

Lake lL

Yes

704,086

1504

Kendall IL

Partial

79,597

247

McHen~

IL

Yes

304,701

499

Kankakee

No

107,824

158

Within Illinois, the counties with the greatest population are Cook, DuPage, Lake, Will,

Kane, and McHenry Counties. The populations and population densities

of Kankakee,

Grundy, and Kendall Counties are significantly lower.

Factor 4: Traffic and commuting patterns

Table 4. Traffic and Commutino Patterns

County

State

2005

Number

Percent

Number

Percent

Recommended

VMT

Commuting to

Commuting to

Commuting

Commuting

Nonattainment?

(10' mil

any violating

any violating

into statistical

into statistical

counties

counties

area

area

Cook

IL

Yes

35294

2.113930

89

2.352.120

99

Lake:" IN

No

4588

193610

93

206."50

99

Will IL

Yes

4.605

185.690

77

239-l40

99

Porter. IN

No

1.677

25.470

35

70940

98

DuPa~e

IL

Yes

8.802

161.940

35

464 630

99

Kane IL

Yes

3.517

36.290

19

190780

99

5

???????????

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???? ????

---

Grundy.IL

Partial

623

6.990

38

I7--nO

95

Lake.IL

Yes

6016

83.930

26

313 250

99

Kendall

IL

Partial

678

4,230

15

27860

99

McHenry,IL

Yes

2104

31.680

24

130520

98

The listing of counties on Table 4 reflects a ranking based on the number ofpeople

commuting to other counties. The counties that are in the nonattainment area for the 1997

PM25 NAAQS are shown in boldface. All counties in this table are highly integrated into

the Chicago area.

Factor 5: Growth rates and patterns

Table 5 below shows population, population growth, VMT and VMT growth for counties

that are included in the Chicago area. Counties are listed in descending order based on

VMT growth between 1996 and 2005.

Table

5. PoouIatlon

.

and VMT Growth and Percent Chan e.

County

Population

Population %

2005 VMT

VMT%change

(2005)

chanee (2000-05)

00'mil

0996-05\

Kane, IL

483,208

18

3,517

364

McHenry,IL

304701

I

16

2,104

196

Kendall,IL

79597

44

678

166

Will, IL

642,625

26

4,605

135

Lake,IL

704,086

9

6016

82

DuPaee,IL

931,219

3

8802

43

GrundV,IL

43,736

16

623

30

Porter,

IN

157,408

7

1,677

10

Lake,IN

491,706

I

4588

0

Cook,IL

5,303,943

-1

35,294

-14

The growth rates are not expected to yield significant changes in the distribution of

population in the area, so this factor did not significantly influence the decision-making

process.

Factor 6: Meteorology (weather/transport patterns)

The pollution rose for the Chicago area is provided in the map above. Winds on high

concentration days predominantly come from the southwest and southeast, but it

is

appropriate to include counties in all directions from the violations.

Factor 7: Geography/topography (mountain ranges or other air basin boundaries)

The Chicago area does not have any geographical or topographical barriers significantly

limiting air-pollution iransport within its air shed. Therefore, this factor did not

playa

significant role in the decision-making process.

Factor 8: Jurisdictional boundaries (e.g., existing PM and ozone areas)

6

???????????

??????? ?? ??????????

???????? ???????? ??????????

???? ????

---

The Chicago Area Transportation Study (CATS) Policy Committee is the Metropolitan

Planning Organization (MPO) for the northeastern Illinois region. CATS webpage:

http://www.catsmpo.coml.

The Illinois portion

of the Chicago ozone nonattainment area consists of the following

counties: Cook, Du Page, Kane, Lake, Mc Henry, Will,

Aux Sable and Goose Lake

Townships in Grundy County, and Oswego Township in Kendall County. Designating a

nonattainment area matching these boundaries will facilitate planning.

Factor 9: Level of control of emission sources

The emission estimates on Table 1 include any control strategies implemented by the

States in the Chicago area before 2005 that may influence emissions

of any component of

PM2.5 emissions (i.e., total carbon, S02, NOx, and crustal PM2.s).

Review for the Davenport-Moline-Rock Island Metropolitan Statistical Area

Discussion:

The Davenport-Moline-Rock Island area is currently designated attainment for PM2.5. A

monitor in Davenport (Scott County) is showing violations

of the standard. Illinois

recommended including no part

of Illinois in the nonattainment area. EPA reviewed

relevant information for the four counties in

the metropolitan statistical area and for

surrounding counties.

EPA believes that the nonattainment area should include Rock Island County in Illinois.

Rock Island County has moderate emissions that commonly are blown toward the

violating monitor is Scott County. We also believe

that sufficient commuting occurs

between Rock Island County and Scott County that Rock Isiand County must

be

considered an integral part of the Davenport area.

EPA recognizes that emissions in close proximity to the monitor may make an important

contribution to the violations. Indeed, EPA recognizes the possibility that reduction

of

the emissions close to the monitor may suffice to address the violation. Nevertheless, our

obligation under Clean Air Act section 107 in defining a nonattainment area is to identify

the area that is violating the standard and the area that is contributing to the violation.

The area that contributes to the violation is then included in the planning area evaluated

for measures for attaining the standard. Even

if the state already suspects that its control

strategy will focus on sources in the immediate vicinity

of the violating monitor, EPA

must apply a nonattainment designation to the entire area that contributes to the violation,

such that the SIP planning will address the entire contributing area.

Furthermore, the available evidence suggests that local emissions contribute only a

fraction

of the concentrations in Davenport. A much larger fraction of the concentrations

in Davenport arise from emissions farther from the monitor. EPA believes that

an

important component of these concentrations arises from a contribution from emissions

throughout the Quad Cities area. While the impact

of Rock Island County appears to be

7

???????????

??????? ?? ??????????

???????? ???????? ??????????

???? ????

---

less than that of Scott Counties, Iowa, the impact nevertheless appears sufficiently

substantial to include Rock Island County in the nonattainment area.

EPA also examined information for Henry and Mercer Counties as well as for nearby

counties outside the metropolitan area.

EPA found that these other counties have

relatively low emissions, and no other factor warranted inclusion

of the counties in the

nonattainment area.

Figure 2

is a map of the counties in the area and other relevant information such as the

locations and design values

of air quality monitors, the metropolitan area boundary. Iowa

did not make formal recommendations, and Illinois recommended that no Illinois

counties be included, so this map shows no state recommended nonattainment area.

Iowa

o Sla:le'lecommerclalion for nc::l3t1amme:nt

o

Slale recommendation for partial nonattal.'lmell1

St.alll recomnendatiofl for ad:trerent metro area

MCritot

~iOIali'ltl24·llf

pt12.5 NMOS

~

12

@

ipretmin. 2005-2007 dMign vah.e!l1

Whir~

Mcrli::l!' atIi'nng2U!r PM2,5I'WtOS

IllttIini'l.2005-2007 des9'lvalles}

C<!"

Mcnilor ¥0Iali'.g2+lu Pt.l2.5 NMOS

Iprelinn. 200S-2001 irlcetnll!etB desi;n ..-alias)

Nalionalllighl'l1)'$

c:J 2006

Co'! Based

Stitistita1

Area

""

~

PM2.5f\>Onor.ai'mentArea

~

(1997 NAAQS)

:::::I

AI PP.l2.5 Nonatl21M::ent

Areas

(l997NAAOSI

.

He~1Y

J:!:+j

~~"JI:a

8I1t~au

br

UlOUr Otone

.,

EGUwllhlolalCAP

l~

em;sslons;>

5.«01ons.')'earin2002

f.t8f..

cer

"

OtIler Polnl Source

\mt1latalCN'

em:ssiOns > S,COO lQnSfyeal in

2002

St!fk

.-

COrr:rtutin9E~l!"1401,lrt\$)

~

illinois

~"'"

w

...

........

".

s

Figure 2

Factor 1: Emissions data

Table I shows emissions of PM25 components (given in tons per year) and the CESs for

potentially contributing counties in the Quad Cities area. Counties are listed in

descending order by CES.

Table 1. PM,s 24.hour Component Emissions, and CESs.

8

???????????

??????? ?? ??????????

???????? ???????? ??????????

???? ????

---

County

State

CES

PM"

PM"

PM"

SO,

NOx

VOCs

NH,

Recommended

emissions

emissions

emissions

(tpy)

(tpy)

(tpy)

(tpy)

Nonattainment?

total

carbon

other

(tDV)

(tDV)

(tDV)

No

Scoll IA

recommendation

100

2,034

395

1639

9 173

11 317

9323

1986

No

Muscatine

IA

recommendation

80

1702

283

1419

27020

10717

4910

1083

Clinton. IA

No

52

2,711

354

2357

II 506

13217

11 503

4870

Rock Island IL

No

27

932

269

663

2 169

6 140

7359

664

Henrv. IL

No

7

1,273

252

1021

268

6,648

3,431

2805

Mercer IL

No

4

793

149

644

133

1,120

1,469

1026

Rock Island County has a substantial fraction of the area's emissions.

Factor 2: Air quality data

The 24-hour PM

25

design values for counties in the Quad Cities area are shown in Table

2.

Table 2. Air Oualitv Data

County

State

Design Values

Design Values

Recommended

2004-06

2005-07

Nonaltainment?

(~glm')

(~glm')

Scott,IA

No recommendation

32

37

Rock Island, IL

No

30

31

Henrv,IL

No

Mercer IL

No

Muscatine,

IA

No recommendation

34

36

Clinton

IA

No recommendation

34

32

For purposes of its review, EPA used data available from the Chemical Speciation

Network and the Interagency Monitoring

of Protected Visual Environments (IMPROVE)

network to estimate the composition

of fine particle mass On days with the highest fine

particle concentrations. On high concentration days during cold weather months

in this

area, EPA found

On

avera~e

a total urban contribution of7.1

~glm3,

consisting of2.0

~glm3

of sulfate, 2.5

~glm

of nitrate, 2.3 j!glm

3

of organic particles, and 0.3 j!g/m

3

of

miscellaneous inorganic particulate. On high concentration days during warm weather

months

in this area, EPA found On average a total urban contribution of 4.3 j!g/m

3

,

consisting of 3.9

~glm3

of sulfate and 0.4 j!glm

3

of organic particulate emissions. These

estimates were used for weighting

of the emissions of different pollutants in calculating

the contributing em'issions scores.

Factor 3: Population density and degree of urbanization (including commercial

development)

Table 3 shows the 2005 population for each county in the area being evaluated, as well as

the population density for each county in that area. Population data give an indication

of

9

???????????

??????? ?? ??????????

???????? ???????? ??????????

???? ????

---

whether it is likely that population-based emissions might contribute to violations ofthe

24-hour PM

2

.5 standards.

T

a

bl

e

3

.

Popu

I'

atmo

County

State Recommended

2005

2005

Nonattainment?

Population

Population

Density

(DoD/sa mil

Scott

[A

No recommendation

161 170

345

Rock [sland IL

No

147454

327

Henrv.

[L

No

50508

61

Mercer IL

No

16840

30

Muscatine [A

No recommendation

42567

95

Clinton IA

No recommendation

49744

70

Rock Island County has a substantial fraction of the area'spopulation. Other Illinois

counties have substantially lower populations.

Factor 4: Traffic and commuting patterns

Tbl4Tffi

a e

fa Ie an

dC

ommutmg

P

attems

County

State

2005

Number

Percent

Number

Percent

Recommended

VMT

Commuting to

Commuting to

Commuting

Commuting

Nonattainment?

(10'mil

any violating

any violating

into

into

counties

counties

statistical

statistical

area

area

No

Scott IA

recommendation

[,614

61500

79

74,020

95

Rock [sland IL

No

1,313

14,240

20

67,530

97

Henrv,IL

No

695

1870

8

22,340

91

Mercer IL

No

135

1200

15

6570

85

.No

Clinton IA

recommendation

423

2610

\I

3600

15

No

Muscatine,

[A

recommendation

372

17330

85

1,060

5

The listing of counties on Table 4 reflects a ranking based on the number ofpeople

commuting to other counties. The percentage

of Rock Island County commuters

commuting into Scott County, Iowa, is moderate but sufficient to view Rock Island

County as integrated into a Quad Cities area.

Factor 5: Growth rates and patterns

Table 5 below shows population, population growth, VMT and VMT growth for counties

that are included in the Quad Cities area. Counties are listed

in descending order based

on VMT growth between 1996 and 2005.

Table 5.

PI'

opu atlon and VMT

Growlh

andP

ercent

Ch

anl!c.

Location

Population

Population

2005 VMT

VMT

(2005)

% change

(10'mil

% change

(2000-05)

11996-2005)

Muscatine [A

42,567

2

372

43

Clinton [A

49,744

-1

423

39

10

???????????

??????? ?? ??????????

???????? ???????? ??????????

???? ????

---

Scott IA

161 170

2

1614

25

Henrv.IL

50508

-1

695

7

Rock Island IL

147454

-I

1 313

3

Mercer IL

16,840

-I

135

-12

The growth rates are not likely to yield significant changes in the distribution of

population during the SIP planning time horizon.

Factor 6: Meteorology (weather/transport patterns)

The pollution rose for the Quad Cities area is provided in the map above. The pollution

rose for this area suggests that Rock Island County

is upwind of Davenport on most high

concentration days.

Factor 7: Geography/topography (mountain ranges or other air basin boundaries)

The Quad Cities area does not have any geographical or topographical barriers

significantly limiting air-pollution transport within its air shed. Therefore, this factor did

not

playa significant role in the decision-making process.

Factor 8: Jurisdictional boundaries (e.g., existing PM and ozone areas)

Bi-State Regional Commission represents the Metropolitan Planning Organization

(MPO) for urbanized area transportation planning in the Quad Cities area. The MPO

serves Henry, Mercer, and Rock Island Counties in Illinois and Scott and Muscatine

Counties

in Iowa. Its web site is: www.bistateonline.org.This suggests that the MPO is

already engaged in multi-county planning, which would facilitate multi-county SIP

planning.

Factor 9: Level of control of emission sources

The emission estimates on Table I include any control strategies implemented by the

States in the Quad Cities area before 2005 that may influence emissions of any

component

of PM2.

S

emissions (i.e., total carbon, S02, NOx, and crustal PM2.

S

).

Review for the Paducah-Mayfield Combined Statistical Area

The only monitor in the Paducah-Mayfield area is in McCracken County,

Kentucky. Kentucky requested concurrence on several claims that elevated

concentrations were attributable

to exceptional events, in particular due to wildfires.

EPA reviewed this request, denied some

of these claims, and concluded that the Paducah

area

is violating the 24-hour PM2.s standard.

The Paducah-Mayfield combined statistical area includes one county in Illinois:

Massac County. This county has a relatively high fraction

of the emissions in the area,

and the winds commonly blow from Massac County into McCracken County on high

1I

???????????

??????? ?? ??????????

???????? ???????? ??????????

???? ????

---

concentration days.

A

substantial fraction of the Massac County emissions are

attributable to the Joppa Steam Plant.

In considering county-level emissions, EPA considered 2005 emissions data from

the National Emissions Inventory. EPA recognizes that the Joppa Steam Plant may have

installed emission controls

or otherwise significantly reduced emissions since 2005 and

that this information may not be reflected

in this analysis. EPA will consider additional

information on emission controls

in making final designation decisions. In cases where

specific plants already have installed emission controls or plan to install such controls

in

the near future, EPA requests additional information on:

- the plant name, city, county, and township

- identification

of emission units at the plant, fuel use, and megawatt capacity

- identification

of emission units on which controls will be installed, and units on which

controls will not be installed

- identification

of the type of emission control that has been or will be installed on each

unit, the date on which the control device became / will become operational, and the

emission reduction efficiency

ofthe control device

- the estimated pollutant emissions for each unit before and after implementation

of

emission controls

- whether the requirement

to operate the emission control device will be federally

enforceable by December 2008, and the instrument by which federal enforceability will

be ensured (e.g. through source-specific SIP revision, operating permit requirement,

consent decree)

In the designation process for the 1997 PM2.5 standards, in some cases EPA

identified a nearby county

as contributing to a violating monitor, and it was determined

that a very high percentage

of the county'semissions came from a large power plant. In

certain cases, EPA concluded that only the portion

of the county including the source

with the'contributing emissions needed to be designated as nonattainment.

If Illinois

. believes that a similar situation exists for Massac County, the State should provide EPA

the necessary information to demonstrate that the source dominates the overall county

emissions and to identify a reasonable partial county boundary.

In its designations for the 1997 standards, EPA included portions

of counties in a

number

of cases in which large sources dominated the emissions from the county, such

that EPA concluded that the relevant portion

of the county was the only portion of the

county that contributed to the violations.

If Illinois believes this is the case in Massac

County, for example

if Illinois believes that only a single township containing the Joppa

Steam plant contributes to violations in Paducah, Illinois should provide the information

necessary to support this view.

EPA also examined information for other Illinois counties around the Paducah-

Mayfield area. These other counties have relatively low emissions, and no other factor

warrants their inclusion

in the Paducah-Mayfield nonattainment area.

12

???????????

??????? ?? ??????????

???????? ???????? ??????????

???? ????

---

Figure 3 is a map of the counties in the area and other relevant information such as the

locations and design values

of air quality monitors, the metropolitan area boundary.

Kentucky recommended that Paducah be found to be attaining the standard, and Illinois

recommended that no Illinois counties be included

if in fact the area was found to be

violating, so this map shows no state recommended nonattainment area.

wH++-f':'+'~4-+-HE

o SIn reecmmenllaticn b'nonll'..ainmenl

o State re«nunel"odaticll

b'

pallial nonattainmenl

SID!

fecommen~alian

rar a

c"f.'erentme:ro

illl!3

Monitor

riclIaSng

24-t>.r PM2.S

NMOS

1pre'1m1i,2005-2007 de$.ign values)

UiWtlr

at!aIlIng

2,J.f1r PM2.5 NMOS

fpre'"IlIl'n. 21):5-2001

des'gn

'talll!5)

Monitllr

~t:lin;

2.u.r PM2.5 NMOS

i;re'6I'J:n.

ms.-2m7

in~deSgn ~akJHI

Na:ior,at h'gh?'!)'S

c:::J

2006 Co:ntJined

~

Area

~

PM2,S NtwIanaimentArea

(1991 NAAOSI

t:::J -

AI PM2.5

N~Ntas

(l!l97NAAOSI

r+--I

Norlmi'mltntiMairmanceArea

,.a......r-

rof 8-houI'

Ozone

EGUwitllotalC/IP

@

emisskt'ts.. 5.000 tonstyeilf

in

21m

Qlher

Pll'1'll Source 11th ttt.al

CAP

@

ert\i$SiCInS :>

5.000 tons.')'ear

in

2002

.-

C(llltl'jbll'3ng_E_~~_~_('!9~).

Kentucky

Tennessee

Illinois

Uilf!naII

Trip<

"'~111

G~"s

Coil~ay

..J

Ot;;m

IBI

Jolt!'.')'

r~y

Missouri

,

Figure 3

Factor 1: Emissions data

Table I shows emissions of PMz.5 components (given in tons per year) and the CESs for

potentially contributing counties in the Paducah area. Counties are listed in descending

order by CES.

Table 1. PM. - 24-hour Comoonent Emissions and CESs.

County

State

CES

PM"

PM,.,

PM,.,

SO,

NOx

VOCs

NH,

Recommended

emissions

emissions

emissions

(tpy)

(tpy)

(tpy)

(tpy)

Nonattainment?

total

carbon

other

(tnv)

(tnv)

(tov)

McCracken KY

No

100

1339

293

1046

38956

24803

6661

366

Massac IL

No

66

1958

159

I

799

26884

12369

2612

417

Graves KY

No

6

797

278

520

413

1735

1.867

2538

Ballard KY

No

5

596

140

456

927

2785

1661

855

Livin-"ston

KY

No

3

318

121

197

337

2155

1200

239

13

???????????

??????? ?? ??????????

???????? ???????? ??????????

???? ????

---

McCracken and Massac Counties have substantially greater emissions than any other

nearby county.

Factor 2: Air quality data

The 24-hour PM25 design values for counties in the Paducah area are shown in Table 2.

The design value

of McCracken County, Kentucky is above the 2006 PM2.5 standard.

There

is no PM2.5 air quality data for the other area counties.

Table 2. Air Qualitv Data

County

State

Design Values

Design Values

Recommended

2004-06

2005-07

Nonattainment?

(ltg/m')

(ltg/m')

McCracken, KY

No

33

36

Massac,IL

No.

Graves, KY

No

Ballard

KY

No

Livingston, KY

No

For purposes of its review, EPA used data available from the Chemical Speciation

Network and the Interagency Monitoring

of Protected Visual Environments (IMPROVE)

network to estimate the composition

of fine particle mass on days with the highest fine

particle concentrations. On high concentration days during cold weather months in this

area, EPA found on average a total urban contribution

of 4.3

~g/m3,

consisting of 0.9

I!g/m

3

of sulfate, 2.2

~g/m3

of nitrate, 1.2

~g/m3

of organic particles, and no

miscellaneous inorganic particulate. On high concentration days during warm weather

months

in this area, EPA found on average a total urban contribution of 5.2

~g/mJ,

consisting of 3.0

~g/m3

of sulfate and 2.2

~g/m3

of organic particulate emissions. These

estimates were used for weighting

of the emissions of different pollutants in calculating

the contributing emissions scores.

Factor 3: Population density and degree of urbanization (including commercial

development)

Table 3 shows the 2005 population for each county in the area being evaluated, as well as

the population density for each county in that area. Population data give an indication

of

whether it is likely that population-based emissions might contribute to violations of the

24-hour

PM2.5 standards.

.

Tbl3P

a e

oou

I'

atlon

County

State

200S

200S.

Recommended

Population

Population

Nonattainment?

Density

(pop/sq mil

McCracken KY

No

64690

241

Massac IL

No

15,225

63

Graves, KY

No

37,650

68

Ballard KY

No

8,262

30

14

???????????

??????? ?? ??????????

???????? ???????? ??????????

???? ????

---

I

Livingston, KY

No

9,783

McCracken County has most of the area'spopulation; the population of Massac County

is not a significant factor in determining the nonattainment area boundaries.

Factor 4: Traffic and commuting patterns

T bl 4 T

fli

dC

a e

ra Ie an

ommuhng

P

attems

County

State

2005

Number

Percent

Number

Percent

Recommended

VMT

Commuting to

Commuting to

Commuting

Commuting

Nonattainment?

(

10

6

m

i)

any violating

any violating

into

into statistical

counties

cQu'nties

statistical

area

area

McCracken KY

No

832

24200

84

26830

93

Graves KY

No

435

2,350

15

12880

83

Massac,IL

No

225

I

950

30

5860

90

Livineston, KY

No

174

I

770

41

3580

82

Ballard

KY

No

102

I

290

35

3380

92

The listing of counties on Table 4 reflects a ranking based on the number of people

commuting t6 other counties. A modest number

ofpeople from Massac County commute

into McCracken County.

Factor 5: Growth rates and patterns

Table 5 below shows population, population growth, VMT and VMT growth for counties

that are included in the Paducah area. Counties are listed in descending order based on

VMT growth between 1996 and 2005.

Ta

bl

e 5. Popu

I

atlon

.

an

dVMTG

rowt

h

an

dPereent Change.

County

Population.

Population

2005 VMT

VMT

(2005)

% change

(10

6

mil

% change

(2000-0~;)

(] 996-2005)

McCracken KY

64,690

-I

832

26

Massac lL

15,225

1

225

25

Graves KY

37650

2

435

21

Ballard KY

8262

-1

102

12

Livineston KY

9783

0

174

56

The growth rates are not expected to change the population distribution of the area

significantly during the SIP planning time horizon.

Factor 6: Meteorology (weather/transport patterns)

A pollution rose for the Paducah area is provided

in the map above. Both the pollution

roses and the trajectory frequency information suggest that emissions from the full range

.

of directions, including from the direction of Massac County, contribute to PM2.5 on

high concentration days

in Paducah.

Factor 7: Geography/topography (mountain ranges or other air basin boundaries)

15

???????????

??????? ?? ??????????

???????? ???????? ??????????

???? ????

---

The Paducah area does not have any geographical or topographical barriers significantly

limiting air-pollution transport within its air shed. Therefore, this factor did not

playa

significant role in the decision-making process.

Factor 8: Jurisdictional boundaries (e.g., existing PM and ozone areas)

The Paducah maintenance area from its former one-hour ozone designation was

comprised

of Livingston and Marshall Counties in Kentucky. No portion of Illinois was

in the Paducah ozone nonattainment area.

Factor 9: Level of control of emission sources

The emission estimates on Table 1 include any control strategies implemented by the

States

in the Paducah area before 2005 that may influence emissions of any component of

PM2.5 emissions (i.e., total carbon, S02, NOx, and crustal PM2.5).

Review for the Saint Louis Combined Statistical Area

Discussion:

EPA reviewed relevant information for the nine counties (including four counties

in

Illinois) partly or fully within the area designated nonattainment for the 1997 standards as

well as for surrounding counties. There are violating monitors in Madison County.

llIinois recommended a definition

of the nonattainment area for the 2006 standards that is

similar to the boundaries that were established for the 1997 standards, including Madison,

Monroe and St. Clair Counties along with a portion

of Randolph County. Illinois

recommended that the nonattainment area for the 2006 standards differ from the

nonattainment area

for the 1997 standards by the exclusion of the portion of Baldwin

Township in Randolph County that

is west of the Kaskaskia River.

EPA concurs with Illinois's recommendation to include Madison, Monroe, and St. Clair

Counties

in the St. Louis nonattainment area. However, EPA believes that all of Baldwin

Township

of Randolph County should be included as well. The most impoitant factor

influencing this judgment

is the factor relating to jurisdictional boundaries. The inclusion

of a.full township will make nonattainment requirements easier to administer, since

information on emissions and source locations are more readily available on a township

basis than with respect to a specially defined subset

of the township. Furthermore, EPA

believes that establishment

of a nonattainment area that fully matches the nonattainment

area established for the 1997 standards would simplify nonattainment planning by

assuring that identical requirements apply for an identical area.

At the same time, as

addressed in more detail

in our documentation of our designations for the 1997 standards,

Baldwin Township contains almost all

of the emissions and therefore makes almost the

entirety

of the contribution of Randolph County to the violations, so that a designation of

just Baldwin Township as nonattainment will suffice to address the contribution of this

portion

of the area.

16

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---

In considering county-level emissions, EPA considered 2005 emissions data from the

National Emissions Inventory. EPA has signed a consent decree that requires Dynegy to

install and operate highly effective

502 control equipment at its Baldwin power plant by

the end

of 2010, 20

II,

and 2012 for its first, second, and third unit installations,

respectively. EPA notes that these dates are between 2 and 4 years after the time we are

judging what areas contribute to nonattainment. The company has already installed

effective NOx control equipment. EPA welcomes any further relevant information that

Illinois may have. EPA will consider additional information on emission controls in

making final designation decisions. In cases where specific plants already have installed

emission controls or plan to install such controls in the near future, EPA requests

additional information on:

- the plant name, city, county, and township

- identification

of emission units at the plant, fuel use, and megawatt capacity

- identification

of emission units on which controls will be installed, and units on which

controls will not be installed

- identification

of the type of emission control that has been or will be installed on each

unit, the date on which the control device became / will become operational, and the

emission reduction efficiency

ofthe control device

- the estimated pollutant emissions for each unit before and after implementation

of

emission controls

- whether the requirement to operate the emission control device will be federally

enforceable by December 2008, and the instrument by which federal enforceability will

be ensured (e.g. through source-specific SIP revision, operating permit requirement,

consent decree)

EPA reviewed the relevant information for other counties within the combined statistical

area as well

as counties adjacent to the combined statistical area in order to determine the

appropriate nonattainment area. Sangamon County has moderate emissions but is rarely

upwind on days with elevated 24-hour

PM25 concentrations. Other Illinois counties in or

near the combined statistical area have relatively low emissions, and no other factor

warranted inclusion

of the counties in the nonattainment area.

Figure 4 is a map

of the counties in the area and other relevant information such as the

locations and design values

of air quality monitors, the metropolitan area boundary, and

the counties recommended as nonattainment by the states.

17

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~

Progress Energy

Ms. Renne Vance

ChiefClerk

North Carolina Utilities Commission

4325 Mail Service Center

Raleigh, NC

27699-4325

IEPA ATTACHMENT NO. Z

OFFICIAL Copy

March 31, 2008

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./lV/itlIlS. OlficB

cQlITmlsSion

Re:

Annual NC Clean Smokestacks Act Compliance Report

Docket

No. E-2, Sub 815

Dear Ms. Vance:

Progress Energy Carolinas, Inc. submits the attached report for calendar year

2007 regarding the status

of compliance with the provisions of the North Carolina Clean

Smokestacks Act. Section 9(i)

of the Act requires that an annual report of compliance

progress

be submitted to the Commission by April

1

of each year for the previous

calendar year.

Very truly yours,

£iPV

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Attachment

232822

Progress Energy SenriG8 Company, ltG

P,O.

Box

1551

Raleigh. NC 27602

ot.....- <J.

~ (Pr~)

Len

S. Anthony

General Counsel-Progress Energy Carolinas

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Progress Energy

March 31, 2008

OFFICIAL Copy

Mr. William G. Ross,

Ir.

Secretary

North Carolina Department ofEnvironment

and

Natural Resources

1601 Mail Service Center

Raleigh, NC 27699-1601

DearS~Rt4~

Progress Energy Carolinas, Inc. (pEC, Company) subnrits the attached report for calendar

year

2007 regarding the status ofits compliance with the provisions ofthe North Carolina

Clean Smokestacks Act (Act).

As you know, 2007 was a significant year for the Clean Smokestacks Act - the first year

in

which the nitrogen oxides (NOx) emissions

cap

became effective. During 2007, we

completed installation of the NOx controls necessary to meet our limit. As the report

shows, the Company'sannual NOx emissions from its North Carolina coal-fired units

totaled less than 25,000 tons. We have developed plans

and

processes to assure that we

continue to meet the requirement.

We regularly review and refine oUI compliance strategy, weighing a number of metors

such as system load projections, expected fuel selection, available control equipment and

anticipated performance and costs ofemissions controls. Because ofthe increased cost

for Furnace Sorbent Injection (pSI) technology, continuing development ofdry scrubber

technology,

changes in the fuel markets,long-tenn impact of (Clean

Air

Interstate Rule)

requirements

and continuing evolution ofour resource plans (including the impact of

Senate Bill 3), we are studying the compliance options for Cape Fear 5

and

6 to

determine whether FSI

still represents the most cost-effective long-tenn compliance

option.

This study, to be completed later this year, will reflect the results ofthe Robinson

FSI testing and the latest available information regarding PSI and dry scrubber costs and

performance. At this time, we are maintaining an option for either

PSI

or

dry

scrubber

technology

for Cape Fear 5 and 6, whichever our studies indicate to be most cost.

effective.

Prn9J1lSS Enllrgy Scrvleo Compllny.

UC

po

Rll~

l!lSI

f/;f!-Jiilh

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---

We appreciate the excellent work ofthe Department staff, particularly those

in

the

Air

Quality and Water Quality divisions, who support our efforts to complete the projects

in

a

timely manner to assure compliance with the Acfs requirements. We look forWard to

continuing our positive working relationship to facilitate fulfillment ofthe Company's

obligations with

this

important law.

Please don'thesitate

to

contact me at (919) 546-3775

if

you have any questions.

Caroline Choi

Director, Energy Policy and Strategy

c:

North Carolina Utilities

Commission

Keith Overcash., DAQ

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---

Progress Energy Carolinas, Inc. (pEe)

North Carolina Clean Smokestacks Act

Calendar Year 2007 Progress Report

On

June 20, 2002, North Carolina Senate Bill 1078, also known as the "Clean

Smokestaclcs Act," was signed into effecl

This

law requires significant reductions in the

emissions

ofnitrogen oxides (NOx) and sulfur dioxide (SO:z) from utility owned coal-

fired power plants located in North Carolina. Section 9(i), which is now incorporated as

Section 62-133.6(i) ofthe North Carolina General Statutes, requires that an annual

progress report regarding compliance

with the Clean Smokestacks Act be submitted on or

before April I

ofeach year. The report must contain the following elements, taken

verbatim

from the statute:

I. A detailed report

on the investor-owned public utility'splans for meeting the

emissions limitations

set out in G.S. 143-215.1070.

2. The

actua1

environmental compliance costs incurred by the investor-owned public

utility in the previous calendar year, including a description

ofthe construction

undertaken and

completed

that

year.

3. The amount ofthe investor-owned public utility'senvironmental compliance

costs amortized in the previous calendar

year.

4.

An

estimate ofthe investor-owned public utility's environmental compliance

costs

and

the basis for any revisions ofthose estimates when compared

to

the

estimates submitted during the previous

year.

5. A description ofall permits required in order to comply with

the

provisions of

O.S. 143-215.1070 for which the investor-owned public utility has applied and

the status ofthose permits or permit applications.

6. A description of the construction related to compliance with the provisions of

G.S. 143.215.1070

that

is anticipated during the following year.

7. A description of the applications for permits required in order to comply with the

provisions ofG.S. 143-215.1070 that are anticipated during the following year.

8. The results of equipment testing related

to

compliance with G.S. 143-215.1070.

9. The nwnber oftons ofoxides ofnitrogen (NOx) and sulfur dioxide (SO:z) emitted

during the previous calendar year from the coal-fired generating units that are

subject

to

the emissions limitations

set

out in G.S. 143-215.1 070.

10. The emissions allowances described in O.S. 143-215.107O(i)

that

are acquired by

the investor-owned public utility

that

result from compliance with the emissions

limitations set out in G.S. 143.215.1070.

II. Any other information requested by the Commission or the Department of

Environment and Natural Resources.

Information reaponsive to

each

ofthese report elements follows.

The

responses are given

by item nwnber in the order in which they are presented above.

1

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---

1. A detailed report on the investor-owned pubUe utility's

plans

for meeting the

emissions Jimitations

set

out In G.S. 143-215.107D.

Under

G.S. § 143-215.l07D(f), "each investor-owned public utility...may detennine how

it will achieve the collective emissions limitations imposed by this section."

PEC

originally submitted

its

compliance plan on July 29,2002. Appendix A contains an

updated version

of this plan, effective April

I ,

2008. We continue

to

evaluate various

design, technology

and generation options that could affect our future compliance plans.

2. The actual environmental compliance costs incurred by the investor-owned

public ntility

in tile previous calendar year, inclnding a description of tile

construction undertaken

and completed that year.

In 2007, Progress Energy Carolinas, Inc. incurred actual capital

COlIts

of$330,124,OOO.

Asheville

Construction

was completed, and Asheville Unit

I

SCR was successfully placed in

service

in May 2007. This completed the Clean Smokestacks Act work planned for the

Asheville plant.

For Unit 3, we completed tuning ofthe Rotamix equipment for NOx emissions control

and placed the system

in service in March 2007. This completed the Clean Smokestacks

Act work planned

fur

the Lee plant

In 2007, we executed contracts

fur

the wastewater treatment bioreactor equipment and

engineering, and initialed work on the wastewater treatment systems. With respect to wet

scrubber

scope ofwork, engineering, procurement and construction activities continued

throughout

2007. Major milestones include: completed conslIUction of the chimney

shell; initiated installation

of the absoIber lower internals; received onsite a majority of

absoIber recycle pump, oxidation air blower, ID Fan and ball mill pieces/parts; and

obtained authorization to construct the wastewater treatment facility. At year

end,

the

Mayo scrubber project was 41

%

complete.

Roxboro

Construction work

on the scrubber project continued for all four units in 2007. Specific

project activities include the

following:

Common

In the common

area,

conslIUction ofthe limestone handling and preparation, gypsum

dewatering and handling, oxidation air system, make-up and service water

system,

and

2

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---

major piping was completed and connnissioned in support ofUnit 2 scrubber startup in

April. Work

was also

started

on installation ofthe limestone silo. Limestone conveyors

and stack-out conveyors were completed as well.

Unit

I

Significant construction included completion offoundations for the booster fan and duct

supports. Fabrication ofthe duct was also completed. Erection ofthe absorber shell was

completed in October, and assembly ofthe absomer internals began. Erection ofthe

pump-house

and electrical building structural steel started in September 2007 and is

planned to be completed in the first quarter of2008. We also started installation ofthe

recycle

pumps, bleed pumps, and booster fans.

Unit 2

Significant milestones for 2007 include completion ofthe duct tie-in outage in April and

the successful startup

ofthe Unit 2 scrubber on April 24, 2007.

Unit 3

Significant construction included completion ofthe duet support and booster

fan

foundations, insta1lation ofthe booster fans, and installation ofduct

support

steel and

duct work. The absorber erection was completed as well as installation ofabsomer

internals

and absorber hood/elbow. Commissioning

began

checkout ofseveral systems in

preparation for the April 2008 tie-in outage

and

scrubber startup.

Unit 4

The significant milestone

was completion ofthe duct tie-in outage in December and the

successful startup

ofthe Unit 4 scrubber on December 1, 2007.

Wastewater Project

Significant construction activities included

completion ofthe wastewater blow-down line,

settling

and flush ponds. Construction ofthe bio-reactor facility was started and

completed in 2007. Commissioning activities started in De=nber with the first two

trains planned to be operational in early 2008. The remaining two trains are planned for

commissioning later in the second quarter of2008.

3. The amount of the investor-owned public utility'senvironmental compliance

costs amortized

in the previous calendar year.

Progress Energy Carolinas, Inc. amortized $33,881,190 in 2007.

4.

An

estimate of the Investor-owned pnbUc utility'senvironmental compliance

costs

and the basis for any revisious of those estimates when compared to the

estimates submitted

during the previons year.

Appendix B contains the capital costs incurred toward compliance with G.S. § 143-

215.1070 through 2007 and the projected costs for

future years through

2013. The costs

shown are the net costs to PEC, excluding the portion for which the Power Agency is

3

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---

responsible. The estimated total capital costs, including escalation, are currently

projected

to be between $1.5

and

$1.6 billion, with the current point estimate being

$1.546 billion.

This

represents an increase from the 2007 cost estimate of $1.355 billion.

Prior reports have discussed the cost

impact ofproject scope changes and the impact of

significant increases in the cost ofmaterials and labor which have impacted construction

projects across the Southeast.

The current estimates continue to reflect those impacts as

well as the impact ofadditional planning, especially with respect to the emission controls

for Sutton Unit 3 and Cape Fear Units 5

and

6.

The current estimate for a dry scrubber at Sutton 3, while still conceptu.a1, reflects the

impact ofmore definitive site characteristics on the overall cost ofthe project. Space is

at a

premiwn at this site, the coastal location requires more stringent wind loading

criteria,

and

the soil characteristics are quite different from what we have at our other

plants

where we have installed scrubbers. As these criteria are reflected in the

conceptusl design,

we are seeing quantity increases (structural steel, concrete, and piping)

due

to the need for stronger foundations, increased structural steel, longer duct runs and

othet utilities

than

previously envisioned. To the extent

that

these increases can be

quantified based on the litnited

engineering completed to date, the costs have been

reflected in the current estimate.

In our last filing we noted that Furnace Sorbent Injection (FSI) technology offeted a

potentially more

cost

effective compliance option for our Cape Fear Units 5 and 6 and

discussed our plans to test

that

technology at our Robinson Unit I. Instal1ation of the test

unit

at Robinson is nearing completion and the testing should begin this sununer with

operating results available by the

end oftho year. The engineering knowledge we have

gained

to

date from the installation ofthe FSI test system at Robinson is being reflected

in updated cost estimates

for the installation ofFSI technology at Cape Fear. One

significant unknown regarding the use ofthis technology at Cape Fear

is

whether the

precipitator will have

to be replaced in order to maintain compliance with existing

particulate emission limits. A

final determination will require further engineering

analysis

and

the benefit oftest results from the Robinson demonstration. At this time, the

estimate for

Cape Fear Units 5 and 6 includes an allowance for replacement of the

precipitator.

Because

ofthe increased cost for FSI technology, continuing development ofdry

scrubber technology, changes in the fuel markets, the long

term

impact ofthe CAIR

requirements, and continuing evolution ofour resource plans (including the impact of

Senate 8ill3), PEC has initiated a study to revisit the compliance options for Cape Fear 5

and 6. This study, to be completed 1ater this year, will reflect the results of

the

Robinson

FSI testing and the latest available information regarding FSI

and

dry scrubber costs and

perfonnance. At this time, we are maintaining an option for either FSI or dry scrubber

technology, whichever our studies indicate

to be most cost-effective.

s. A description of all permits required

in

order to

l!OIDply

with the provisloDS of

G.S. 143-215.107D for wbich the lovestor-owned public utWty has applied and the

status of those permits or penni! applieatioDs.

4

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---

Progress Energy applied for the following pennits in 2007:

Roxboro Plant

Air Pennit

An

update to the air pennit for coal handling and limestone equipment was submitted on

November 14, 2006. This request was approved on March 15, 2007.

A Notice for Intent to Construct for a diesel-fired emergency fire water pump was

approved on Febtuary 8, 2007

and

Air Quality Permit revision No. 01oo1T39 was issued

on AprilS. 2007.

Agency approval was received August 22, 2007 for oor request for Alternative Method of

Reporting ofAnnual Average Opacity for units equipped with Flue Gas Desulfurization.

A

Renewal Tide V Air Permit application was submitted on November 27. 2007. This

renewal application met the requirements ofthe Construction Permit for

the

Flue Gas

Desulfurization (FGD) System to submit a complete Title V Air Quality Pennit

Application onor before

12 months after commencing operation.

MavoPlant

NPDES

A request for authorization

to

construct a Flue Gas Desulfmization (FGD) Wastewater

Treatment System, submitted May 4, 2007, was approved and issued on November 28,

2007.

NPDES Permit modification approving our request for a mixing zone for chlorides was

issued on December 14, 2007.

Erosion

and

Sediment Control Plan

Revision G.

to

the Erosion and Sediment Control Plan for the increase in disturbed land

(from 35 acres to 98 acres) for the fiue gas desulfurization system was submitted January

29,2007 and was approved on April 12, 2007.

Lee Plant

AirPennit

A Title V Air Permit

application was submitted on April 19, 2007

in

accordance with

pennit requirements associated with the Low NOx Burner installation. This application

was required by the Construction Permit to be submitted within 12 months after

5

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---

commencing operation ofthe 10w-NOx Burner.

NPDES

The NPDES Pennit revision for the Rotamix Urea Injection System on Unit 3 was issued

on

March 23, 2007.

6. A description of the construction related to compllanee

wltb

the provisions of

COS. t43-215.t07D that

is

anticipated during the following year.

During 2008, construction activities will focus on completion ofthe chimney lining and

installation

ofabsorber internals. Concurrently, placement ofID

fan

fOlDldations,

placement ofthe wastewater treatment bioreactor cells, erection ofstIUctural steel,

fabrication

offield

erected

tanks, and installation ofelectrical and I&C will be

completed. Engineering activities will continue, with the

focus

shifting

to

the wastewater

treatment related scope ofwork. Starting

in

the summer, commissioning activities will

intensitY in prq!8ration for

the

spring 2009 plant outage and subsequent mechanical

completion

and placement in service ofthe wet scrubber

and

wastewater treatment

systems.

Roxboro

Common

For 2008, significant construction activities planned in the common area include

completion

ofthe railroad track installation,

and

final site grading and paving. Specific

unit activities are described below:

Unit 1

Significant construction activities planned include completion

ofUnit I absoroer

internals, installation

of the absorber hood/elbow, completion ofthe pump-house and

electrical building, and installation ofthe booster fans and duct work. Commissioning

is

planning

to

start activities in June in preparation for the October tie-in outage.

Unit 3

Significant construction activities planned include completing electrical

power

and

control cabling and the balance ofcommissioning activities in preparation for the April

tie-in outage.

Unit 4

In service. Major activities include issue

ofas-built drawings, evaluation ofperfonnance,

and conducting performance tests as needed.

Wastewater

Significant construction activities planned

for the bio-reactor include completing

6

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---

commissioning activities for the tim two bio-reactor

trains

with a contiouation of

commissioning activities

on

the remaining two bio-reactor

trains

in the 2

nd

quarter.

7. A description of the applications for permits

required in

order to comply with

the provisions of

G.5.

143-215.107D that are anddpated during the following

year.

General

We appreciate the collaborative efforts the DAQ and DWQ staffs have made to assure

our construction

and

installation schedules

remain

on

track.

However, the potential for

longer permit processing

times continue to

be

a serious concern for future projects.

PEe

will work collaboratively with

the

agency staffto prevent any delays from occurring.

The following permit applications and permit approvals are anticipated for 2008:

Roxboro Plant

Erosion

and

Sedimentation Control Plan

Plan revisions may be necessary as construction plans are further developed.

Mayo Plant

NPDES Permit

A

request for authorization to construct a new oil/water separator was submitted on

March 7, 2008 with a response expected by the end ofApril.

Erosion

and

Sedimentation Control Plan

Plan revisions may be necessary as construction plans are further developed.

Sutton

Plant

Air Permit

An

application for construction of a DIy Scrubber for Unit 3 is expected to be submitted

during the fourth quarter 2008 with

response expected

in the second quarter 2009.

8. The results ofequipment testing related to compliance with

G.8.

143-215.107D.

Performance testing

ofthe SCR at Asheville Unit I was completed in October 2007.

The testing indicated that

the system

met its performance guaranteed emissions rate of

O.04lb NOxIMMBtu.

7

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---

Performance testing ofthe SNCR

system

at

Lee

Unit 3 was completed

in

March 2007.

The testing demonstrated

that

the system met its performance

gullIllDtee

of a 31

%

reduction in NO. emissions over the load range ofthe unit

Performance testing ofthe Scrubber at Roxboro Unit 2 was completed in September

2007. The testing confumed that the scrubber achieved its performance guarantee of

97"10

802

removal efficiency.

9. The number of tons ofoxides of nitrogen (NOx) and slllfur dioldde (SOz) emitted

during the previous ealeadar year from the

colli-fired

generating units that are

subject to the emlsslODllllmltatlons set out

In

G.S.143-215.107D.

The affected coal.fired PEe units have achieved a

59%

reduction

in

NOx and a

25%

reduction in

802

since 2002.

The

total calendar year 2007 emissions from the affected

coal-fired

Progress

Energy Carolinas units

are:

NOx 24,383 tons

802

147,242 tons

10.

The emissions allowances described

In

G.8. 143-215.107D(i) that are acquired by

the InVllfltor-owned public utility that result from eompllance with the eorlssions

Umitatiolls

set out

In

G.8. 143-215.107D.

During

2007, PEC did not acquire any allowances as a result ofcompliance

with

the

emission limitations

set

out

in

N.C. General Statute 143-215.1070.

11.

Any other Infonnation requested I!Y the Commission or the Department of

Environment lUld Natural Resources.

There

have been no additional requests for information from the North Carolina Utilities

Commission or the

Department ofEnvironment

and

Natural Resources since the last

report

8

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---

Appendix A

Progress Energy Carolinas, In.:'s(pEC) AIr Quality Improvement Plan Supplement

April 1, 2008

On

June 20, 2002, Governor Easley signed inlo law SB1078, which

C8p5

emissions of

nitrogen oxides (NOx) and sulfur dioxide (S0:2) from utility owned coal-fired power

plants

located in North Carolina. Under the law, G.S. § 143-215.1070, PEC'sannual

NOx emissions must not exceed 25,000 Ions beginning in 2007 and annual S0:2 emissions

must

not exceed 100,000 Ions beginning

in

2009 and 50,000 tons beginning in 2013.

These caps represent a 56% reduction

in

NOx emissions from 2001 levels and a 74%

reduction

in

S0:2 emissions from 2001 levels for PEe.

PEe owns and operates 18 coal-fired units at seven plants in North Carolina. The

locations

ofthese plants are shown on Attachment

I.

Under G.S. § 143.215.107D(f),

"each investor-owned public utility...may

determine

how

it will achieve the collective

emissions limitations imposed by this section."

111trogen Oxides EmissIons Control Plan

PEC has been evaluating

and

installing NOx emissions controls on its coal-fired power

plants since

1995

in

order to comply with Tide IV of

the

Clean Air Act and the NOx SIP

Call TUle adopted by the Environmental Management Commission (EMC). Substantial

NOx emissions reductions have

been

achieved (24,383 tons ofNOx

in

2007 compared

with 112,000 tons

in

1997),

and

compliance with

the

Clean Smokestacks Act's25,000

ton

cap was achieved

in

calendar year 2007. This target was achieved with a mix of

combustion controls (which minimize the fonnation ofNOx), such as 10w-NOx burners

and over-fire air technologies,

and

post-eombustion controls (which reduce NOx

produced

during

the combustion offossil fuel to molecular nitrogen), such as selective

catalytic reduction

(SCR) and selective non-catalytic reduction (SNCR) technologies.

Attachment 2 details PEC'sNorth Carolina coal-fired electric generating units, their

name plale generation capacity, and installed NOx control technologies.

Sulfnr Dioxide Emissions Control Plan

PEC is installing wet flue gas desulfurization systems (FGD or "scrubbers") 10 remove

97% ofthe S0:2 from the flue gas at its Asheville, Roxboro and Mayo boilers. PEC

is

continuing its evaluation ofthe potential to use Furnace Soroent Injection (FSI)

technology

at our

Cape

Fear Plant. Use ofthe FSI technology eliminates the need for a

cosdy wastewater treatment

system. We plan

to

test the FSI technology at PEC'g

Robinson Unit I beginning in summer

2008. Since Robinson Unit I is similar in design

to the Cape Fear units, the Robinson test wiII indicate whether the use ofthis technology

will be effective at Cape Fear. While PEC continues 10 evaluate the use ofFSI at Cape

???????????

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---

Fear, because of expected inaeased

cost

fur Furnace Sorbem Injection (PSI) technology,

continuing development

ofdry saubber technology, changes in

the

fuel markets, the long

term impact ofthe CAIR requirements and continuing evolution ofour resource plans

(including the impact

of Senate Bill 3), we are re-evaluating all compliance options for

Cape Fear 5 and 6.

The current compliance plan also contemplates the use ofa dry scrubber at Sutton Unit 3.

A

dry

scrubber at that unit represents a more cost-effective compliance solution and also

eliminates the need for a costly wastewater

treatment system.

Wet scrubbers produce unique

waste and byproduct streams. Issues related to wasteWater

permitting and solid waste

disposal

are being addressed for each site.

PEe

is treating the

scrubber wastewater

stream

at

the

Asheville Plant using an innovative constructed

wetlands treatment system

to ensure compliance with discharge limits. A bioreactor

technology will be

used

for the Roxboro and Mayo Plants

A contract

has

been

executed with a gypsum product end-user that will construct a

facility near

the

Roxboro Plant to use the synthetic gypsum produced by the Roxboro and

Mayo Plants for the manufacture ofdrywall products. PEe also has entered into an

agreement

that

enables PEC to market and sell synthetic gypsum produced at the

Asheville Plant.

Attachment 3 details PEC'sNorth Carolina coal-fired electric generating

units, their

summer net generation capability, installed

S~

control technologies and those planned

for installation. As technologies evolve or other cUcumstanccs change, a different

mix

of

controls may be selected. Attachment 3 also projects annual

S~

emissions on a unit-by-

unit basis based

on the energy demand forecast and expected efficiencies ofthe

S~

emissions controls employed. These projections are based on the planned removal

technologies

and PEC'scurrent fuel and operating furecasts. This information is provided

only

to

show how compliance may be achieved and is not intended in any way to suggest

unit-specific emission limits. Actual emissions for each unit may be substantially

different.

???????????

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---

Asheville

Attachment 1: Location ofPEC's Coal-Fired

Power Plants

in

North Carolina

Weatherspoon

:f

-Lee

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---

Attachment 2: PEC's 2008 NOx Control Plan for North Carolina Coal-fired Units

Unit

MWRatlnll:

Control Technolol!Y

Operation Date'

Asheville 1

191

LNBfAEFLGRISCR

2007

Asheville 2

185

LNBlOFAfSCR

Cape Fear 5

144

ROFAfROTAMIX

Cane Fear 6

172

ROFAfROTAMIX

Lee 1

74

WIR

Lee

2

77

LNB

2006

Lee

3

248

LNBlROTAMIX

2007

Mayo 1

742

LNBfOFAfSCR

Roxboro 1

369

LNBfOFAISCR

Roxboro 2

671

TFS2000fSCR

Roxboro 3

705

LNBfOFAfSCR

Roxboro 4

698

LNBfOFAfSCR

Sutton 1

93

SAS

Sutton 2

102

LNB

2006

Sutton 3

403

LNBfROFAfROTAMtX

Weathersooon 1

48

Weath

n2

49

Weath

n3

76

WIR

Total

5,047

AEFLOR - Amin.,.Enhanaxl Flue

Lean

<las Rebum

LNB

~

Low NOx BllJll<:r

SNCR

a Selective

Non-eatalytic Reduction

OFA~Ov~Air

ROFA - Rotating Opposed-filed Air

ROTAMIX

~

Injcaion or""" to IImbened_ NOx

WIR

~

Undcrfin: Air

11'S2OOO

~

Combination Low.NOx

Bum...

/~

Air

SAS

= Separated Air

SIllging

, This Is

!he

o"",,,lIon <late

lor !he

oontrol technology InsCaned 10 comply

with !he

North C8roIIna ImP'0"81Vr QualItylElo<tric: UlII_1>&l. 0I11y

(sllovm

In

1loI<l).

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---

. Attachment 3: PEC's2008 SOt Control Plan for North CaroUna Coal-Fired Units

Unit

MWRating

Technology

Operation Date

Projected 802

Projected

S~

Tons. 2009

1

TOIII.2013

Asheville 1

191

8crnbber

2005

296

333

Asheville 2

185

Scrubber

2006

280

352

CaDeFear 5

144

PSI

2011

6791

3634

CaDe Fear 6

172

FSI

2012

8274

4,330

Lee

1

74

2947

2,902

Lee

2

77

2694

2,671

Lee

3

248

9,906

9.265

MayO I

742

Scrubber

2009

7,183

1,602

Roxboro 1

369

Scrubber

2008

685

942

Roxboro 2

671

Scrubber

2007

1,048

1,235

Roxboro 3

70S

Scrubber

2008

1046

1,493

Roltboro 4

698

Scrubber

2007

976

1.394

Sutton 1

93

4534

3851

Sutton 2

102

5381

4429

Sutton 3

403

Scrubber

2012

19,614

884

Weathersooon 1

48

1,628

1138

Weathersooon 2

49

1,583

1214

Weatherspoon 3

76

2997

2792

Total

5047

77863

44461

PSI

~

Puma« Sorbent lDjectIon

, Unit by unit emissions ....

ilustralllle only

and speQlIc omloslono imlls should not be _.Aclual emissions In 2009 and 2013 may ba dlflerenlln>m untt 10 unn.

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---

AppendixB

PEC'sActual Costs Through 2007 and Projected Costs Through 2013

for Clean Smokestacks Act Compliance (in thousands

560.919

$

1.545,657

so

$ 958

I

!

S 7.029! S 3.877

I

S 4,571 • S 18.214 : S 27.760 :

J

I

!

Ii!

S 26.528, 580.187

I

$ 18l,274 1 5

m.819

!

$ 330.124

!

S 16U96

554.587

$ 92,309 ' 5204,323 : $138.875 :

~o

'1"

.;:_~~"

r

"',2m~.:j,.'l00i

A':'::'tll04'.:,J-,;1ii6sf.L..<-io06

I

20Q7.

1·~0ll8~_J

20b9L2Qi!L:zoji

~L.

loi2";

~o:i3l-:-,Tot~t

.,-

"""'-,::.';;.<.. "

5\QQ.L

S9652.~.33.57~}!,~:'769

.hS,].•

930~~l~50~

so:

JO;__

~ol

..

$_O~

._ $.0-,-.

50

$81175

">:>

'Ai

$0'

SO

~,;

.

-t~1'413""'~tof.§Q!;

S..ill!£l....1~:_

..

.1.q

L__$.o_ .. _Sli..

_._~..

so

528400

~'!',:'~"'.~

5100

$7,z4~ ~28,390

I

524,238

5117011

-SI.54~L

. 1.0.1 _ .!2: .. .1.0+,.h .. dS.Q.j

!l0 C. so

$70,629

ilUno."::'f,i

5467. ..

so

so!

$ 0

sol

-s 479 !

$ 0 ;

S O.i

}Jl. __ sQ..1

.--!.Q.L.

so

-$12

a"i,

1..

S11[7 4-S !Li..

~.276

!

5

~i.

§

22.z~~.u!~~86

5

70,99(q.!34'~}hl..

• $

L

u. S

~

.. JOe""!0

$134405

~::'I.~.!12..;.

S 5.560

j

$

10.9.~

I-S 51.717

S 72,934 : S 36,491

S 11.893 :. $ 2,208 :

~

9_.

-...1.Q.L..

$ 0 :

$ o.

5191252

:;';0,.1

.$0;

sol

$0

$3135512164 .$.32.84'1

~2.475.Lp,79I!

.~Q..:

_

SOL

SOt

_~O

594406

slio.

$35741 561148 $30782 546014 S18.9,75

S5731

._to-L_~oJ._.li.:

__..!.QL

so

$106885

SOl

sol

5244 .$:;\'0628 S36661 .$49,9851 Sl3.sssL SI,275 1

SO;.

so,

so:

SO

$111.349

__s.o.l.

~O

I'

.S.O

1_.!9~.$28,SSO

.-1S7,6I:01.

S~,7041..

S916.iu

so_~

so

t

u

.~<L[

.

so

$98854

SO!

_SJl:

SO'

so:

S88+_

-~-4-.

SO! $7752"1 S42383

1

$.11,9141

so _

so

561137

SOt' ...S 0..;... .. S.o ...

$0 .'J,g. .. _.$O_l .' 52

;.~O

L

S 01 539636 J27.191

I.~.Q

$ 116.828

S0

$0 ;

50 ,.. $.198

$6424

S600 '

SO!

SO ,

S0

i

S0

50!

S0

$ 7.'

:~_ll. ~

$Q

I.:~

50.."

50•..

..J.Q._

.~.o I!_~ .so.~.

S!~!±~~2!i

I

515!l.172_r!IP~31

~~Sg

5316.100

c'"

~

SO,

S133~

S 1.886 __

..!Q... _..

29J .. _ $.Oj ... $ 0 Iso I

so

I..

so

51,291

;"" _..E.L_SOI_._ ..

~0-I~

SI.9001.

SOi

__ .

.!.Q:

SO'.~

.

..!Q.!

so _ ..SO

$1136

$1.193

j

S 16.52S! S 80184

i

$ 168118 5259654

i

$ 309.456

i

S 141934

I

551.'24

i

592,309 I $ 204.313

I

S 138875

I

$ 958

$1475056

$0 _

J!O

. . S.Q.

.!..g.365!~I

..289! _

-~}26

j

..21?~

.. S

Qj _

_~.o!.

S

Qi..

.$ 0.1

so

513.348

_~.O

.•. .!i0 _ .. so

1--_

S.Q.I

~o ~_$~.042

iSI~,95~':

53.120:

so

I ... H.L ..

s~._

50

521,221

~j

_.~~

i.._

:~.

~6 f-_~.7;~

r

11,~S~~

_~16'9:'}f

..

s.~~O~!

$

l~~ t~_~ ~

L

._;~J

.

:~

..

~ ~

_

$35~:

I

:

I

;

;

i

;

$ 0

i

$ 0

$ 0 S 13.156 . S 13,253

$ 20.668 ! S 20,262! S3.263

!

SO.

$ 0

i

$ 0

!

$ 0

570.601

Note5: Costs reDect the Power Agency contribution. Historic year costs are actual, curreDt yesr costs are projected, and future year costs are escalated.

~

.

. . S02 Controls Des!gn and Construction

.'.

.:. ... •.., S02 Contro!. In-service

~~,~~:

~~: ~o:::::: ~:~!;;d

Construction

.

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???????? ???????? ??????????

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---

.

PEC's Clean Smokestacks Act Compliance Plan

PlantP~

General

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

&0""''''6'

~"n

Asllll'Jlle 1 FGO

,,,,.,..,,,, 1;:>""

AsIlll'JIIe 1 SCR

'Asllll'Jlle 2 FGO,Ashevlle 2 FGI5

Mayo 1

u

FGO

IMayo 1 FGD

Roxboro 1 FGO

IRoxboro

1 FGO

Roxboro

2 FGOTROibOiu 2 FGD

Roxboro

:l FGO

IRoxbOro:!

FGO

Roxboro

4 FGO

rROxboro 4

FGO

·r~·~1r.i.

'~~~f

'-'.--

"~

;t;~~~~

.•.

':-.

;:.~-";\_;"""n:

-.;:sr...

~-~~.,

_.:- "-. -

;~:;W:::::·Fj.~

. ...

t'::.-~

3-::":

:,,:4;'"...

f~.::

.::~::;~~,-.£.~

~"r

.--:!":

Cape Fear-S

FSI

I~

Fear 5 FSI I

I

I

I

I

I

I

fr~~'?-t/.$:;;'~"'

.:",:"

cape FearS FSI

cape

FearSFSII I

I --..I""ci;lL,i§1§.!,j

Lea 3 Rolamlx

lee 3 RoIamlx

Sutton 3 FGD

utton 3 FGD

"

""'c.,,, ."

~~,~'.

'.;;i

Lee 2

LNB

Lee

2

LNB

Sutton 2 LNB

Sutton 2 LNB

~""""""'

-,,--',;.... ;';'.c 502

Controls

........

In-6enice

-

NOx Controls

Design

and

Construction

NOx Controls 1n-ser.iC9

???????????

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???????? ???????? ??????????

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---

VERIFICATION

STATE OF NORTH CAROLINA

)

)

COUNTY OF WAKE

)

NOW, BEFORE ME, the undersigned, personally came and appeared,

Paula Sims, who

first

duly sworn by me, did depose and say:

That she is Paula Sims, Senior Vice President-Power Operations

of

Carolina Power

&

Light Company, d/b/a Progress Energy Carolinas, Inc.;

she

has

the authority to verify the foregoing Progress Energy Carolinas, Inc.

North Carolina Clean Smokestacks Act Calendar Year 2007 Progress

Report; that she has read said Report and knows the contents thereof; are

true and correct

to the

best

ofher knowledge and beliefs.

Subscribed and sworn

to me

this~day

of March, 2008.

246373

???????????

??????? ?? ??????????

???????? ???????? ??????????

???? ????

---

Power Engineering - SCR = Supremely Complex Retrofit

P!!PIcmlOTH

r-~'

INNOVATIONS IN

~

ll.1~

I

ASH HANDLING

Page 1 0[2

IEPA ATTACHMENT NO.

..3..

IJ!smlDTH

SCR = Supremely Complex Retrofit

Take one giant Manitowoc crane used in the recovery efforts

at the World Trade Center, 12,000-plus tons of

structural steel, 2,000 cubic yards of concrete, SOO-plus workers, and twin 1120 MW net supercritical boiler

units, and what have you got?

An engineer's playground, for sure, but also one of the largest selective

catalytic reduction (SCR) projects in

the U.S., at Duke Energy's Belews Creek Station in north-central North

Carolina.

Click here

to enlarge image

Duke Energy is installing SCR systems for NOx

control at its two-unit Belews Creek power

station

in north-central North Carolina. The

units, which wiIJ reduce NOx emissions from

0.50 Ib/MMBtu to 0.10 Ib/MMBtu, are

scheduled to come on./ine in 2003 and 2004.

Photo courtesy of Duke Energy.

The $325 million Belews Creek project is a shining example of the

challenges inherent to many of the large-scale SCR retrofits currently

underway around the country. Tucked

on a spit of land adjacent to

Belews Lake, Duke Energy and its project partners - Duke/Fluor

Daniel and Babcock Borsig Power - have had

to fit the proverbial

square

peg in a round hole, adapting system design to space

constraints and integrating construction activities with operational

and maintenance priorities.

Despite

their critical importance to NOx compliance strategies, SCR

installations are primarily structural and civil projects, with a splash

of process work thrown in. As the Duke workers joke at Belews, the

SCR reactor is really just a "wide spot in the duct." The structural

and civil challenges, however, are prodigious. At Belews Creek, for

example, the

SCR structure will extend above the boiler building,

more than

2S0 feet above ground level. A key design consideration,

therefore, concerned wind loads. The

SCR framework had to be able

to accommodate high wind loads, up

to and including hurricane-force

winds.

To keep the SCR structure from experiencing up-lift or tip-over, it had to be structurally anchored to the

ground and

to the existing boiler bUilding, according to Harold Backman, Duke Energy Generation Services'

Project Director.

At ground level, rock anchors - using anchor bolts 14 feet long and 4 inches in diameter - tie

the SCR addition to Mother Earth. At plant level, horizontal steel beams mate the new SCR facility to the

existing boiler structure, and vertical booster columns have been built around a number of the existing steel

columns

to handle the additional loading from the ductwork and structure located above the existing fan

room. The booster coiumns consist

of a set of four steel members welded to the corners of the original vertical

coiumns. A significant amount

of electrical, instrumentation and plant services had to be relocated during on-

line operation

to facilitate these tie-ins - a significant, but not unusual, occurrence in complex SCR retrofit

projects.

Some

of the other unique challenges associated with the Belews Creek retrofit include:

oIncreased

air demand - Supply of an additional 600 scfm dedicated air compressor to satisfy all of the extra

project

air requirements.

oID/FD fan upgrades - New impellers installed in all fans

to handle a gas flow of 10,272,000 Ib/hr. The

primary air fans will

be downsized as a result of the increased capacity in the FD fans.

http://pe.articles.printthis.clickability.com/pt/cpt?action=cpt&title=Power+Engineering+-+... 9/26/2008

???????????

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???????? ???????? ??????????

???? ????

---

Power Engineering - SCR = Supremely Complex Retrofit

Page 2

of2

.Equipment staging - The staging yard is located about one mile from the work site, demanding coordinated

and

timely movement of parts and supplies to match construction schedule.

• Air preheater design - The new vertical shaft rotary regenerative secondary

air preheaters are being installed

on the SCR structure beneath the SCR on both units. Outage work will require the removal of existing

secondary

air preheaters and associated ductwork in order to install new duct configuration.

The

SCRs for Belews Creek are scheduled to come on-line in Spring 2003 (Unit 1) and Spring 2004 (Unit 2).

The units are designed for a nominal 80 percent

NOx reduction, from 0.50 Ib/MMBtu to 0.10 Ib/MMBtu, at 2

ppm slip. The

SCR reactor will initially be charged with two layers of Ti02-V205-W03 catalyst from

Cormetech, with two spare layers available

for operating flexibility. Although Belews Creek could have

installed a bypass system and operated the

SCRs only during the ozone season to comply with the NOx SIP

Call, Duke decided

that the more cost-effective option was to eliminate the bypass since year-round operation

of the SCRs would be required to meet the NOx reduction provisions of the state's Clean Smokestacks

legislation by 2007.

Correction:

In the October article, "Inlet Air Filtration Adapts to Evolving Gas Turbine Technology," the caption

accompanying the photo

on page 51 is incorrect. The correct caption should be, "Coalescer fiiter." Power

Engineering regrets the error.

Power Engineering

November, 2002

Author(s):

Steve Blankinship

Find this article at:

htip:llpepei.pennnel.com/displar-arlicleJ162367/6/ARTCLInoneJnoneJ1/SCR-=-Supremely-Complex-Retrofrl

o

Check the box to inducte the list of links referenced in the article.

Copyright «} PennWell Corporation.

P!PIcmlDTH

rrJ

INNOVATIONS IN

~

J~l

ASH HANDLING

http://pe.articles.printthis.clickability.com/ptlcpt?action=cpt&title=Power+Engineering+-+...

9/2612008

???????????

??????? ?? ??????????

???????? ???????? ??????????

???? ????

---

Established 1882 • Vol. 150 • No.1

January/February 2006

www.powermag.platts.com

IEPA LIBRARY

DEPARTMENTS

On the cover

The Tennessee Valley Authority's Allen Plant

represented a unique challenge for catalyst

management

due to its two-layer catalyst

limitation

and because the units were built

without a selective catalytic reduction

bypass.

The units started with an B.2-mm-pitch

Cormetech honeycomb catalyst

but

a

7-mm

catalyst was also qualified during the initial

design and installation. In the second year of

service, after approximately

16,000

hours of

operation, catalyst management options

were investigated ranging from in-kind

replacement to in-situ washing, external

washing, .

and rejuvenation. The solution

involved

an in-situ replacement of" the 8.2-

mm-pitch product with an extension of the

prequalified 7-mm-pitch prodUct.

The same

process has been successfully carried out on

all three units over the.past 18 months.

Photo

courtesy of Tennessee Valley Authority

IEPA ATTACHMENT NO..!:L

mImCOIlIlW!lrID

FEB 2 7 Z006

24 LEGAL & REGULATORY

4 SPEAKING OF POWER

7 GLOBAL MONITOR

7 Frame 6C debuts in Turkey

7 1,200 MW in two years

.

8

Atlantic City bets on renewables

11 Peru commissions hydro plant

12 New edition of steam plant bible

15 FOCUS ON O&M

t5 CFB refractory repair

11 Upgrading conductivity monitoring

21 low-cost maintenance of spinning

reserve

_.powflrmeg.platt5.c:om

STEAM GENERATOR DESIGN

40 Constant and sliding-pressure options for new supercritical plants

The design and operating mode of a supercritical-pressure boiler should reflect the

economic practices

of its plant's market, which means a sliding-pressure unit could

be

harder to cost-justify in the

U.S.

than in Europe or Japan.

.SPECIAL REPORT

REFACTORY DESIGN

48 Understanding refractory failures

A five-step process for discovering the cause of those pesky refractory failures

(so

you don't encounter them again).

COAL COMBUSTION

54 CCPI bears firstfruit

Early results from a first-round Clean Coal Power Initiative project show promise for

a software-only solution to plant optimization.

32 Estimatmg CR installetion costs

According to the EUCG. the average installed system cost is $128/kW, with the

nebulous

"retrofit difficulty" the major cost-driving variable:

SCRSYSTEMS

26 Long-tenn catalyst health care

Careful analysis of catalyst- activity and consideration of operating requirements

and -limitations are essential

to ensuring long-term optimum catalyst performance

capable of producing significant cost savings.

FEATURES

EVENTS

60 The 2005 Global Energy Awards

In the words of Platts President Victoria Pao, .... The winners ... are the' companies

and individuals

who are building the future of our economies, our societies, and

our environment.

n

COVER STORY

J8nuaI'(/February 200!1 I

POWER

36 Catalyst regeneration: The business case.

The dollars saved have enough zeros to make the proposition worthwhile, the cost

can be capitalized, and

it

might even be possible to increase catalytic activity

beyond the original leveL

???????????

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???????? ???????? ??????????

???? ????

---

,All

(72

unitsl

:'1417%1

. -:,3

1.03IMW

5218/1:W

-

>5100

POwaR

I

January/February 2006

>900

lations in the U.S., so the survey results can

be

considered a valid top-level view of sys-

tem costs.

Economies of scale

As Figure

I

shows, although almost

three-fourths of the surveyed units have a

capacity of 300 to 900 MW, together they

601-900

Unit size (MWj

5100-149.99

$150--199.99

$(k.W

cost category

301-800

E ''''1'

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1. SCR cost survey results. Survey results. categorized by plant size, covered

approximately 39% of

the

new selective catalytic reduction (SeA) capacity installed through

early 2004.

Source: EUCG Inc.

2. What they spent. Most surveyed utilities spent between $100 and $200/kW for a

selective catalytic reduction system.

Source: EUCG Inc.

Responses to the survey yielded scope,

cost,

and design information on 72 individ-

ual units totaling

41 GW (representing 39%

of installed

SeE{

systems

i

MW at the time of the study) owned by

eight large utilities from SIP

Can states

located in the East and Midwest. The sam-

ple also reflected the distribution

of instal-

by 66%, relative

W

2tltl3 levels, acwss 28

eastern states and the District of Columbia

by 20I5. Though SCR systems worth more

than $4 billion

are expected to be pur-

chased worldwide next year, in the U.S.

more than

40 GW of capacity in CAIR-

affected states

are expected to

be

equipped

with the technology by 2010.

This increased level

of SCR installation

activity cnmes

on the heels of the 1995

NO, SIP (State Implementation Plan) Call

Rule, which motivated

the installation of

almost 8S GW of SCR installations at cen-

tral station steam plants over the past

decade. Many utilities will have to place

orders this year to comply with the NO.

Phase I in-service deadline of 2009. Full

implementation of CAIR will occur in

2015. One

of the challenges facing utilities

affected by

CAlR and ,actively analyzing

their cap-aDd-trade options is to understand

the capital costs involved in retrofitting an

SCR system.

T

he goal of the Clean Air Interstate

Rule (CAIR) signed into law almost a

year ago is to reduce

NO~

emissions

Estimating 8CH installation

co'sts

The EUCG surveyed 72 separate installations of selective catalytic reduction

(SCR) systems at coal-fired units totaling 41 GW of capacity to identify the

systems'

major cost drivers. The results, summarized in this article, provide

excellent first-order estimates and guidance

for utilities considering

installing the downstream emissions-control technology.

By

Mark Marano and George Sharp, American Electric Power, and the EUCG Fossil Productivity Committee

Survey results

The EUCG, an association of 24 electric

utilities representing 302 individual coal-

fired units, is a forum through which the

utilities can enhance their

O&M and con-

struction practices

to improve their opera-

tional and cost performance.

. One vehicle used by the EUCG is mem-

ber surveys. One recently completed survey

focused on SCR system installation costs

and the project and design attributes that

contrihute

to them. Specifically,.it identified

the costs

of construction labor; equipment;

materials~

and project management, engi-

neering

I

and construction management

(PMEC). The survey addressed II specific

scope/design unit attributes such as

the

type

of ammonia system used, the

NO~-removal

efficiency design basis of the system. and

SCR-related plant upgrades (such as econo-

mizer, air heater, and fans) on a $IkW basis.

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f

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they

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ough

for a

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,

a:

a:

c

u

I

lHE

NASC

STU

1

PMEC

PO'Wa'R

IJanuary/February 2DD6

l1J

Project

m~nagement.

engineering,

construction management

• Average total cost, $/kW

Interestingly. the variation in material

costs was constant over the survey peri-

od, most Hkcly reflecting increased com-

petitiveness among SCR suppliers. By

contrast, PMEC costs showed higher

variability, which-as in the case of con-

struction labor costs-reflected the

greater complexity of later projects.

Average cost variation

by

cost category is

summarized in the table.

One survey, many conclusions

Although the survey results provide useful

insight into expected installed costs, they

• <=1003

• >1003

• Construction labor

• Equipment

&

material costs

.~

"

o

3. Cost by unit size. The cost distribution for 72 units with SCR installed shows expect-

ed economies of scale.

Source: EUCG Inc.

4. Timing affected costs. The deviation of category costs as a function of SCHproj-

ect completion date shows that early adopters paid less than those that lagged behind.

Source: EUCG Inc.

project complexity - lleasier" projects

were already completed-but also per-

haps increased competition for skilled

labor resources as the number of SCR

installation projects under way. in the

U.S. skyrocketed.

The variation in material costs was

constant over the survey period, most

likely reflecting increased competitiveness

among SCR suppliers.

represent only a little over half of the

total capacity studied. Overall, costs were

reported to be in the $100 to $200/kW

range for the majority of the systems

(Figure 2). with only three reported

installations exceeding $200/kW. System

size

(with a 644

4

MW average unit size in

the $100 to $150/kW range) seems 10

dominate; Iw:ger average system costs are

significantly less than the next survey

category

t

e

to

range,

with a 309-MW average unit size). The

data also suggest that the larger units

were installed earlier: The average unit

size retrofit before 2003

was 623 MW,

versus 466

MW since 2003.

The range of category costs

by

unit

size ($/kW) provides

insight into SCR

projects' relative complexities. For exam-

ple. the aggregated reported costs in the

defined categories (Figure 3) point to sev-

eral conclusions:

IIIlsCH

SYSTEMS

• The cost of construction labor on smaller

projects exceeds the average construe.

tion labor cost in all categories

by

about

50%. The implication is that small plants

will be cost-penalized

by their lack of

economies of scale because they may

be

more difficult to retrofit.

• Construction labor costs were relatively

constant for plants larger than 300 MW.

with an

av~rage

cost of just over

$64IkW.

• As expected, economies of scale also

affect

SCR material costs, with larger

units costing less

to retrofit, on a $IkW

basis, than smaller units.

•

Sophisticated regression modeling

techniques (multivariate analysis) gen-

erally did a poor job of predicting

overall installed costs; too many site-

specific variables impact construction

costs.

• PMEC costs are relatively consistent.

regardless of unit size.

The good old days

The survey data also revealed that devi-

ations from average installation costs

correlate strongly with project timing,

.,: .:'. ':',especiallyfor those units installed after

"M;:;~·:.;~_»OO.3

~\_;j-,-.",;:,,:w-"_<

,. - :. ,':

(Figure,

,

;'.'

4), The

.

significantly high-

Overall

Construction labor

Equipment

&

material

~l:~~:;;",:;r~;·eJ, ~~5)nstr,uct,lon'

lab~)r,

cpsts,,'for later

Notes: Numbers in parentheses indicate number of collected survey datapoints for grouping.

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,~

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...

more difficult to retrofit than those in

other size ranges.

Because SCRs are unitized, greater

economies of scale were expected from the

survey results. Some possible explanations,

for the modest advantage of scale inelude:

sen

SYSTEMS

III,

systems, which reduces their capital

costs but still requires them to be

deliv~

ered by sea or river.

•

-Marlr Marano

is

VP, financial

planning-corporate planning and

budgeting for AfP. George Sherp is a

senior member ofAfP Generation's

Business Planning Group. For more

information about the fUeG, contact

Pat Kovalesky, executive director, at

623-572-4140

or

visit www.eucg.org.

• The impact of newer plants' tighter lay-

outs, which often necessitate much more

complex duct installations, which raises

costs).

II

Plants' limited ability to use the most

cost-effective method of equipment

transportation, Some

41 % of the units

surveyed

in the

600-

to

900-MW

range

are close to navigable waters, versus

76% of units larger than 900 MW.

•

The increasingly modular design of SCR

601-900

>900

Unit size (MW)

much higher than anticipated, Together.

these conclusions suggest

that "retrofit

difficulty" is indeed relative. Units with a

capacity of

600

to

900

MW appear to be

<300

301-600

,166.89

. '186.20',

Source: EUCG Inc.

also confirm that there is no

one-size~fits­

all SCR design. What the data also make

clear is that site-specific characteristics of

units

and plants can drive a project's cost

'i'

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SCR FOR COAL.FIRED BOILERS:

A SURVEY OF RECENT UTILITY COST ESTIMATES

J. E. Cichanowicz

Consultant

236 N. Santa Cruz Ave. Suite 202"

Los Gatos, Ca 95030

jecinc@batnet.com

Abstract

Accurate projections of SCR capital cost are critical both for prudent NOx

contiol rulemaking

by federal and local environmental regulators, and to

establish realistic utility compliance plans. Within the last few years, many

utilities have engaged architect/engineers

and/or SCR vendors to project SCR

cost for selected units in their system, employing detailed site-specific

assessments.

This

paper reports results of SCR cost studies conducted by

eleven utility companies, addressing 24 dry-bottom boilers, and 27 Group 2

boilers. The results

show Significant uncertainty characterizes SCR capital

cost estimates, as a

wide range of values is projected for both boiler types.

This

paper discusses and evaluates cost trends, demonstrates the impact of

capital cost uncertainty

on the cost per ton of NOx removed, and compares

capital cost results

with those from a computer algorithm widely used in NOx

control rulemaking.

Introduction

The availability of selective catalytic reduction (SCR) NOx control technology

at reasonable cost is a key consideration

in the promulgation of NOx emission

limits

by federal and local environmental agencies. The cost of SCR is a topic

of considerable disagreement among the various "stakeholders" participating

in the NOx emissions debate. most significantly the utility industry, federal

and local environmental regulatory agencies, and

vendo~

of SCR technology.

This

disagreement is capital cost translates into equal uncertainty regarding

projections for cost

per ton of NOx reduced. Specific concerns have been

summarized

in written comments submitted by the utility industry (UARG,

1997) to the Environmental Protection Agency's Acid Rain Division

(ARD),

and in technical reports submitted by industry for use by the Ozone Transport

Assessment Group (OTAG, 19960). Rebuttal positions have been formally

issued by the EPA ARD (EPA, 1996a), and OTAG stakeholders that support

SCR-based NOx limits (OTAG, 1996b).

-1-

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---

In

December 1996, the EPA ARD issued NOx emissions for Group 2 boilers

based on an evaluated cost per ton of NOx removed, which required EPA to

project SCR capital cost for the national boiler population.

In

June of 1997,

. the OTAG Policy Committee issued general recommendations for the control

of

NOx emissions, which may require broad application of SCR from

generating units

in the 38 states that comprise OrAG'sinterest. Both the EPA

ARD

and the OrAG Policy Committee base their understanding of SCR cost

on discussions with equipment suppliers, and experience from Europe. EPA

ARD developed a cost algorithm to project

SCR capital cost as a function of

generating capacity, and used this algorithm to select the NOx levels proposed

in December 1996 (EPA,

1996b), as well as support OrAG analysis.

During approximately the same time period, many utilities sponsored

detailed studies

by architect/engineering firms and/or SCR vendors to

estimate SCR capital and operating cost. Given the significant cost

implications

of NOx policy decisions, it is prudent to summarize cost results

derived from these utility-sponsored engineering studies, for discussion and

comparison with other cost sources.

Objective

The objective of this paper is to report the range of SCR capital cost

determined by Site-specific engineering studies, estimated by either

architect/engineering firms and/or SCR technology vendors.

Subsequently,

the impact of capital cost on the cost per ton of NOx removed is

calculated. The influence

of two economic parameters that strongly dictate

SCR cost - capacity factor and capital recovery factor - is also demonstrated.

Approach

Utilities known to have sponsored major NOx planning studies that

employed detailed site assessments were requested to volunteer cost results

for

summary and comparison.

Given

the competitive climate within the utility industry, disclosure of

factors

that affect the cost of generation has become extremely sensitive. With

the exception

of two studies entered into the public record as part of CAAA

Section 407 rulernaking

(OVEC, 1997, and TEeO, 1996), utility companies only

shared cost information on the basis that specific uni

Is

remain anonymous.

This evaluation considered only engineering studies that employed a site

assessment

by the architect/engineer, or SCR vendor. Cost estimates were

required to be developed from specific equipment lists, derived after

considering

plant layout, design specifications of the plant and components,

and condition of existing equipment (e.g. flue gas handling components).

In

-2-

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---

most cases, the studies employed a general arrangement drawing to identify

the location of the reactor and ancillary eqUipment, as well as flue gas routing.

Eleven utility

companies prOVided engineering studies for review that

addressed SCR capital cost for selected units in their system. These utilities

are located in the midwest, portions of the northeast, and the mid-Atlantic

states. The

data set consists of a total of 24 dry-bottom boilers (e.g. wall- and

tangential-fired), and 27 Group 2 boilers (cyclone, wet-bottom, and cell-fired).

The number of boilers represented is a small fraction of the national

inventory.

Within the 38 state OTAG region alone, approximately 700 dry-

bottom boilers exist. The total number of cyclone, wet-bottom, and cell-fired

boilers nationally

number approximately 140. No rigorous statistical analysis

is possible

with this data set, as the details of sites are unknown.

Description Of Cost Methodology

This

section summarizes the cost methodology followed by most studies.

Cost Methodology

A detailed description of SCR cost methodology has been presented in an

earlier. paper (Cichanowicz, 1993).

This

discussion highlights the following

cost elements that are of particular interest in this evaluation: Process

Capital, Installation Charge, Process/Project Contingency, Utility Indirect

Charge, and Allowance for Funds During Construction (AIDC)

Process Capital.

Process Capital reflects acquisition cost for equipment

required for both the SCR process, and modifications to the balance-of-plant

or ancillary components. The Process Capital reflects the sum of expenditures

for

equipment delivered to the site, but not an installation charge.

Table 1 summarizes the major Process Capital components. The first three

items (SCR catalyst, reactor, reagent storage, and reagent vaporization) are

direct SCR capital requirements, with remaining items denoted as balance-of-

plant components or installation expenditures. A subsequent section of this

paper addresses how costs partition between these two categories.

Installation Charge.

The Installation Charge reflects primarily the labor

charge and lease of special equipment required for installation/erection, as

well the upgrade of balance-of-plant equipment or ancillary components.

ProcesS/Project Contingency.

These cost elements comprise a "reserve"

fund for unanticipated expenses due to either project-spedfic or process-

specific issues.

Most of the engineering studies used 15-20% (of Process

Capital and Installation Charge) for the sum of both contingency funds.

-3-

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---

Utility indirect Charge.

Utility-incurred costs are comprised of staff

engineering, project management, and facilities such as access roads,

buildings, etc.,

and is usually 5-10% of Process Capital and Installation Charge.

Allowance for Funds During Construction (AFDC).

AFDC is a finance

charge, incurred for time periods when equipment is

not employed in power

production. Although not necessarily a significant cost component compared

to the

sum of ali other components, AFDC represents a real incurred cost, and

is included for completeness. All planning studies reviewed included a

modest charge of nominally 4-5% annually, for a period of usually 1-2 years.

Most results were derived for a 1995-1997 dollar basis, and for generally

similar process conditions (major exceptions are noted). These similarities,

and the desire to observe only gross trends, allow the use of results as directly

reported,

thus not corrected for cost year basis and process conditions.

Capital Cost Components

Two cost indices are proposed to further characterize capital cost: (a) the

Process Capital/Installation Charge ratio,

and (b) the sum of the catalyst,

reactor,

and reagent storage/vaporization components to the Process Capital.

These cost ratios

are further described as foliows:

Ratio of Process Capitalllnstallation.

Process Capital/Installation Cost

ratio, determined before application of Process/Project Contingencies, Utility

Indirect Costs,

and AFDC indicates whether the bulk of direct costs are driven

by capital procurement (ratio >1) or manpower for installation (ratio

<1).

It

is anticipated a difficult retrofit site with signIficant obstacles that

complicate access of construction equipment would be characterized by a

relatively low Process Capital/Installation Cost ratio; a site

with relatively

unrestricted

acCesS would be characterized by Process Capital/Installation Cost

ratio of

>1.

Ratio of SCR ProcesslProcess Capital.

SCR Process/Process Capital

ratio, determined before application of Process/Project Contingencies, Utility

Indirect Costs,

and AFDC indicates whether the bulk of process equipment

acquisition costs are for SCR components, or balance-of-plant equipment to

allow

the boiler/plant to accommodate SCR process impacts.

It

is anticipated that sites requiring

few

modifications would be characterized

by a relatively high SCR Process/Process Capital ratio; retrofit sites that

require boiler modifications and upgrades to accommodate the SCR process

would be characterized by a relatively low SCR Process/Process Cost ratio.

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---

Results

Results from

this

survey are presented according to two major boiler

categories:

dry bottom and Group 2 (cyclone, wet-bottom, and cell-fired).

Ideally, separate cost comparisons would

be developed for each of the five

major boiler categories. However, the relatively small

number of units and

the desire to observe only general trends allows this simplification. Results

are discussed according to (a) capital cost, and (b) components of capital cost.

Capftal Cost

Dry-Bottom Boilers,

Figure 1 summarizes SCR capital cost for dry-bottom

boilers,

presented as a function of generating capacity. The NOx reduction

efficiency for all units is 80-90%, with residual NH3 a

maximum of 5 ppm

(2 ppm for selected sites). With the exception of two units, boiler initial NOx

production rates are approximately equivalent to the Phase 1, Group 1 limits

of 0.45-0.50 Ibs/MBtu, depending on boiler type (e.g. tangential- or wall-fired).

Note several of the data represent multiple units at the same station.

Group

2

Boilers.

Figure 2 summarizes SCR capital cost for cyclone, wet-

bottom,

and cell-fired boilers, presented as a function of generating capacity.

The wet-bottom boilers, all which feature SCR designed for 50% NOx

removal from approximately 1.1-1.3 Ibs/MBtu, are identified separate from

the cyclone and cell-fired boilers. The SCR NOx reduction efficiency for the

cyclone

and cell-fired boilers

is

80%, with one case at 50% noted. Except as

indicated, all cyclone/cell-fired boiler NOx production rates are 12-1.5

Ibs/MBtu. All costs reflect sufficient catalyst to maintain a

residual NH3 level

of at most 5 ppm, throughout the entire operating period.

Capital Cost Components

Figure 3 presents trends in both the Process Capital/Installation Cost and SCR

Process/Process Capital cost ratios, as a function of projected capital cost, for

dry-bottom boilers. As suggested, the highest capital cost sites are

charactenzed by a Process Capital/Installation Cost ratio of 1-1.25; the lowest

capital cost sites can have values exceeding

2. The SCR Process/Process Capital

ratio

ranges from 0.50 for high cost sites, to 0.75 for low cost sites.

Results Discussion

Results

presented in this paper are based upon an extremely small sample of

the boilers, compared to the candidates considered to deploy SCR NOx

control. Clearly, caution should be exercised in extrapolating any results or

observations in cost trends from

this

sample to the national or the OTAG

regional

population.

-5-

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---

Average Capital Cost

Dry-Borrom Boilers.

The average of capital cost for dry-bottom boilers for

all

24 boilers presented in Figure 1 is $86/kW. The average for units greater

than

175 MW capacity

is

$75/kW.

Figure 1 demonstrates the

wide variation in capital cost depending on site-

specific conditions.

If

only generating capacity

is

considered as an indicator of

"average".SCR capital cost, significant variations from the

$75/kW average

for units

>175 MW are witnessed. Specifically, within the cluster of units at

approximately 550

and 625 MW, any unit can vary in cost by $30-50/kW.

Group

2

Boflers.

The average of capital cost for Group 2 boilers for all units

presented in Figure 2, calculated

with four different averaging techniques,

ranges from $79-86/kW. The lowest cost ($79/kW)

was determined by

eliminating boilers of less

than 200 MW capacity, using only 2 boilers at each

of the Kyger

and Clifty Creek sites in the average, and eliminating balance-of-

plant upgrades necessary

to accommodate SCR at three large cyclones. The

highest cost

was determined by employing all boilers in Figure 2 in the

average

(allll Kyger and Clifty Creek units, and not eliminating small

boilers), and including balance-of-plant costs for the large cyclones.

For units above 200

MW capacity,

if

generating capacity alone is used to

project

SCR capital cost, significant variations from the nominal $83/kW

average are witnessed. These variations appear to be $15-50/kW.

Economies of Scale

SCR is generally recognized by most observers to exhibit economies of scale

with respect

to capital cost.

This

trend is dependent upon the assumption

that all other plant and SCR process design factors are maintained equivalent,

as generating capacity increases.

Figure 1 shows

that cost per unit capacity decreases as generating capacity

increases from 100

to 200 MW. The average SCR cost for the units at

approximately 600 MW suggests continued cost reduction at larger capacities.

For

the

Group 2 boilers, the different boiler designs prevent identifying any

trend between cost and generating capacity.

For

both boiler categories, the reduction in SCR unit cost with increasing

generating capacity is

most pronounced for increases from lowest (-100 MW)

to intermediate capacities (-175-200 MW). SCR capital cost may not exhibit

economies-of-scale anticipated

at larger capacities, as the design basis for the

SCR process and host unit changes significantly with increased capacity. An

example is the utilization of two reactors (each of 50% treating capacity) in

place of one reactor (at 100% capacity), to maintain turndown for larger units.

I

1

1

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---

Cost Per Ton Evaluation

The cost of NOx control per ton of NOx removed - sometimes referred to as

cost-effectiveness -

is an important cost index. The EPA ARD has issued NOx

regulations for Group 2 boilers based

on the "cost-effectiveness" of low NOx

burners on Group 1 boilers compared to the "cost-effectiveness" of candidate

NOx control technologies on Group 2 boilers. Essentially all NOx trading

programs proposed or presently

in

place employ this cost index. Also, several

states have proposed definitions of Reasonably Available Control Technology

(RACT) depending on the "cost-effectiveness" of NOx reduction achieved by

any given technology.

It

is instructive to examine the significance of the

uncertainty

in capital cost observed in Figures 1 and 2 on the evaluated cost

per ton of NOx removed. Also, the impact on cost-effectiveness of two

economic factors of particular significance for

SCR - the capital recovery factor

and generation capacity factor -

is addressed.

Capital Cost

Table 2 summarizes NOx control cost per ton provided by SCR, as applied to

(a)

dry

bottom boilers

in

a "post-RACT" mode, and (b) Group 2 (cyclone) .

boilers.. Table 2 also presents the sensitivity of cost

per ton to uncertainties in

capital cost, capacity factor

(CF), and capital recovery factor (CRF).

Dry-Bottom Boilers.

Cost results apply only to the specified conditions of

80% NOx reduction, initial NOx production rates of 0.45-0.50 Ibs/MBtu, 4 year

mean catalyst life, and a

final

space velocity of 3200 l/h. The generation

capacity factor

and annual capital recovery factor are 65% and 0.15,

respectively. For the average SCR cost (as approximated from Figure 1) of

$75/kW, Table 2 shows that

SCR NOx control cost is $1600-1768/ton, for boiler

NOx production rates of

0.50 and 0.45 Ibs/MBtu, respectively.

Table 2 also

shows the impact of $15/kW variations in capital cost. mcreasing

capital cost

by $15/kW to $90/kW would increase the $1600-1768/ton cost

range by $220-25O/ton. Similarly, decreasing capital cost by $15/kW to

$60/kW would decrease the $1600-1768/ton range by approximately the same.

Group

2

Boilers.

Cost results apply only to the specified conditions of 80%

NOx reduction, 4 year average catalyst life, initial NOx production rate of 1.3

Ibs/MBtu, and a

final

space velocity of 2000 l/h.

For the average SCR cost (as approximated from Figure 1) of $79/kW, Table 2

shows that SCR NOx control cost

is $696/ton, for NOx production rates of 1.3

Ibs/MBtu. Adjustments to capital cost by $15/kW impact cost by $80/ton.

-7-

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---

Sensitivity Analysis: Additional Factors

Although the focus of this paper is SCR capital cost, it is prudent to briefly

consider two other factors that can dominate the evaluated cost per ton of

NOx reduced by SCR. The ability to recover capital cost, as determined by \illit

capacity factor and financing conditions, is particularly important with SCR,

due to the high capital requirement compared to alternatives.

This

section

demonstrates how the range of capacity factor and capital recovery factor .

impact the evaluated cost per ton.

Capacity Factor.

Future projections of capacity factor for the deregulated

industry have received considerable attention recently. Projections for system

capacity factor averages range from 65% to as high as 85%, depending on the

economic conditions presumed for the relevant time period. This differential

of 20 percentage points translates into a considerable difference in cost per ton

of NOx. As shown in Table 2, Simply increasing capacity factor from

historical norrns of 65% to 85% lowers SCR cost per ton for dry-bottom boilers

by $340 to $380/ton, for boiler NOx productions rates of 0.50 and 0.45

Ibs/MBtu. For Group 2 boilers, the same increl\Se in capacity factor lowers

evaluated cost by approximately $120/ton.

Capital Recovery Factor.

Utility planning studies reviewed documented

the range in capital recovery factor employed for cost evaluations.

This

factor

depends not only on the details of financing capital, but also the secondary

cost of equipment ownership, such as property taxes, insurance, etc. Most

significantly,

the term over which the utility intends to operate the facility -

either 10, 15, or 20 years - exerts a dominant role in determining the capital

recovery factor. The studies reviewed for this paper show the range in capital

recovery factor to be 0.14- 0.167. Within the NOx policy debates, stakeholders

supporting the application of SCR have proposed a capital recovery factor of

0.115, for a 20 year plant

life.

Accordingly, a sensitivity analysis was conducted

to determine the impact of capital recovery factor to levels as low as 0.115.

Table 2 shows for dry bottom boilers reducing capital recovery factor to 0.115

lowers evaluated cost by $650/ton, for a boiler NOx production rate of 0.50

Ibs/MBtu. For Group 2 boilers, the same variation in capital recovery factor

lowers evaluated cost by $90/ton. Accordingly, the role of capital recovery

factor is Significant, and

is

equal to or greater than the impact of reasonable

changes in capacity factor or capital cost.

Observation

Results from this evaluation highlight how Wlcertainty in capital cost,

capacity factor, and capital recovery factor impact cost per ton of NOx.

-8-

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---

Depending on the value of capital cost, capacity factor, and capital recovery

factor, the evaluated cost per ton of NOx can vary by almost 50%. Specifically,

Table 2 reports cost per ton for both dry-bottom and cyclone boilers,

employing inputs that based on the studies reviewed for this paper,

discussions with utilities, and economic projections, appear extreme. These

values are $60/kW capital cost, 85% capacity factor, and 0.115 capital recovery

factor. Employing these values for dry-bottom boilers produces a cost of $935-

1029/ton, approximately 55% of that estimated for the "baseline" case. For

cyclone boilers, cost is $424/ton, or 60% of the 'baseline"

The cost per ton is further reduced, when employing capital cost estimates

based on the computer algorithm describing capital cost versus generating

capacity, that was derived by EPA ARD. For dry-bottom boilers, using 550

MW as a reference case, this correlation used in OTAG rulemaking projects a

capital requirement of $47/kW, for an SCR process designed for 80% NOx

removal from Phase l/Group 1 boiler NOx production rates. A generating

capacity of 650 MW is anticipated to require SCR capital cost of $44/kW,

according to this correlation.

These algorithm-derived estimates are 60-65% of the average capital cost at

550 and 650 MW presented in Figure 1. Using these algorithm-derived capital

costs results in estimates of cost per ton of $791-818/ton, half of the baseline

~

Similar trends were noted with Group 2 boilers, where the algorithm

also significantly underpredicted cost for 50% NOx reduction cases.

Summary

Engineering studies submitted by 11 utility companies revealed trends in SCR

capital cost, based on detailed site-specific assessments. For dry bottom

boilers, the projected cost for SCR was $86/kW, and reduced to $75/kW when

boilers less than 175 MW were eliminated. For cyclone boilers, the average

cost was $79-86/kW, depending on how the average was calculated.

This significant capital cost uncertainty translates into equivalent uncertainty

in cost per ton. Economic and technical premises selected from this survey

suggest deploying SCR delivers NOx reduction for $160D-1768/ton, in a post-

LNB application. For cyclone boilers, the cost per ton anticipated for these

conditions is $674/ton.

Both capacity factor and capital recovery factor exert significant impact on cost

per ton. By using values for these inputs that

ba~ed

on the utility site-specific

studies appear to be extreme, evaluated cost can be reduced to 55-62% of the

previously cited values. Further complicating the matter is the apparent

tendency of the SCR capital cost algorithm developed for NOx rulernaking by

EPA ARD to underpredict SCR capital cost, prodUcing estimates

approximately 60-65%% of those inferred from Figure 1.

In

summary,

-9-

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---

estimates ofSCR cost that do not employ a detailed site-specific analysis could

be significantly in error, and generating capacity and capital recovery factor

should be carefully considered to reflect authentic

industry experience.

References

Cichanowicz,

1993

EPA,1996a

EPA,1996b

OTAG,1996a

OTAG,1996b

OVEC, 1997

TEeO, 1996

UARG,1997

Cichanowicz et. a!., "Factors Affecting SCR Capital Costs For

Utility Boilers",

paper prepared for The Utility

Air

Regulatory

Group, October,

1993

Investigation of Performance and Cost of NOx Controls As

Applied to Group 2 Boilers, prepared

by The Cadmus Group,

August

1996, EPA Contract No. 68-D2-Q168, Work

Assignment No. 4C-02

..

Distributions

Of

NOx Emission Control Cost-Effectiveness By

Technology, prepared by rCF Incorporated, October 31, 1996,

EPA Contract No.

68-D3-Q005, Work Assignment No. 5F-Q1.

"Electric Utility Nitrogen Oxides Reduction Technology

Options For Application by The Ozone Transport Assessment

Group", January 1996, prepared by UARG for Consideration

by the OTAG Control Technologies

&

Options Workgroup.

"Electric Utility Nitrogen Oxides Reduction Technology

Options For Application

by The Ozone Transport Assessment

Group", April i996, prepared by Selected States

&

Stakeholders for Consideration by the OTAG Control

Technologies

&

Options Workgroup.

"SCR Capital and Operating Cost Estimate for Kyger Creek

and Clifty Creek", final report prepared for the Ohio Valley

Electric Corporation, May 1997

"Nitrogen Oxide Limitation Study",

prepared for Tampa

Electric Company, March 15,

1996

Comments Filed

On

Behalf of the Utility Air Regulatory

Group, In Response to The January 19, 1997 Proposed Rules

Implementing The Second Phase Of The Nitrogen Oxides

Reduction Provisions In Title

N

Of The Oean air Act, Docket

No. A-95-28.

-10-

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---

TABLE 1

SUMMARY OF PROCESS CAPITAL COMPONENTS

FOR SCR RETROFIT

rnot

Comment

SCR Catalyst, Reactor

usually the largest cost components

Reagent Storage

facilities for the unloading, transfer,

and

storage for aqueous or anhydrous ammonia

reaj!ent

Reagent

equipment to vaporize reagent, and

Vaporization/Injection monitor and control injection rate

Sootblowers

included in almost all

SCR designs and cost

estimates; sometimes

not seperately

identified

Foundations

re-inforcing of existing foundations,

or

construction of new foundations depending

on reactor location

Structural Steel

re-inforcing of existing structures, or

construction of

new structures depending

on reactor location

Ductwork Modifications modifications to existing ductwork to

accommodate

SCR equipment

New Ductwork

new ductwork for process bypass, reactor

access, etc.

ProcessI&C

control systems for process operation

Fan Modifications

improvements to existing fans to increase

flow rate rating, or replacement with

new

fans

Balanced Draft

reinforcement of ductwork structure,

and

Conversion

addition of fans as necessary to convert

from forced to balanced

draft.

Electrical

additional auxiliary power supply for

reagent

t

blowers, etc. can require an increase

in power delivery capabilities on-site

Boiler Modifications

installation of economizer bypass, removal

or addition of heat absorbing surface area as

necessary to provide correct flue gas

temperature

vs. load

Other

(BOP)

modifications to the

air

heater to improve

tolerance to increased

503; improvements

to particulate control equipment to tolerate

residual NH3, 503; etc.

Duct Burner, Gas/Gas

heat exchange equipment necessary for

Heater

I

post-FGD applications

Misc/General

flow modeling, construction management,

demolition

charj!e, etc.

I

I

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1000

I

I

800

,

T

700

3x

;.11;

it

-.!

'~Ii'l

•

Ii

','11i'

jlli

lH

,h

i11'11~INi

,

-qx

\

~II~

~

:f;

~i

'II'J

I

;

"

I

:J

,'

i

;

i~,

.~

f

,L

!

:

~

I

Hlou

I:'

IPtrll·~1

1

500

FIGURE 1. DRY BOTTOM BOILERS:

SCR CAPITAL COST VS. CAPACITY

~

>

2x

"

1 il

~'

'JI

Iii'

~!!

j

~x

2x

lJ

~

~

I

q'

fI II

~'

~Irl

I~!

:j,

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¥

I~

~

Ii.

~1

~I

If

,

~,'WJ,

Ii

111,

100

200

300

400

;'11:

liiu

140

>

~127

60 -h-

IiI:

70 --+-

III

,K

1

80-1-

50

-+-

I~II!

40

gO-+-

$/kW

2x

I~I~~,

'i

~6

~-~~~~~~~~=.::.:._-----,

11 0

-'---\1~

' __•

~~

__• __J""-

'

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.......

,--

..............

-_

......_--"

.~'-'

~. _.~_."

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,

2

~

__ 00,

1

1

7

:.

r

~

I'

I;, 'tl

pi

we~:~:~:~e~::~~~:~

BOP Costs

:~: ~'.:",:i§i:,,,:%¥:':SF:'=:'

:.m"-""-""~wt

-~

,;:

1-:.:1:",

'tl'

% /

~~

.~

,f;

"Ii

(Ii

1<-::"

)I*,I

I~~'

1?:1

o

I}

In;

,

".~

'~'

,~

,

~I!>

'~-

Ie

It

'~lb

~I

1Jl3

Ii

~I

Ii

I~H

,;~

5

IiI

~

I'

~

'II!

r~ ~l

90

60

80

70

50

40

100

FIGURE 2. GROUP 2 BOILERS:

$/kW

125+U;

1;25+

SCR CA""PITAL COST VS. CAPACITY

110

" ;

125.

I

'

-

I!l'""---------:----------.

,.

~I

I

Generating Capacity, MW

100

200

300

400

500

600

700

1000

Nole

Scale Change

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3.16

,.J

TOTAL PROCESS CAPITAUINSTALLATION,

SCR PROCESSITOTAL PROCESS CAPITAL

,:'

.~

~

,<',

,~.

.1.

it!

,

!

ii,

140

I

130

~

!

.::

~I

I

::~;

.~

it!

';}

,I,,'

:f

II

I

120

~

,oj

-i;

-~

;\1

<

'fl

i:

I

'il

I

110

:i.\

i-,

'1'.

d

,

, 1"

.~

i

-~i

I

fi

~~lItJ

I'

i-&

TOTAL PROCESS CAPITAUINSTALLATION

Ii I::' &!iTi!n

SCR PROCESS EQUIPMENTfTPC •

it

!,;,'"

I~\I

I{

<h

•

:~

ii

.~.

!

::f

I

I

I

70

80

90

Capital Cost,

$/kW

1""

r1.

if

;1

i~

ij

11I!.

",

~li

~.

~.;

~

f,

%

1*

Iii Ii

i

~Cl

fj"

J

f

~

I~

l j

I

I

50

60

g

~

,J

':!

~:

§

{'

:t.

[

II"

I

0.75

0.25-1-

2.00

i

'.il.

!ill.

IiI

i

~.

t

if

1.25-+-

__.. __

.~~.

__ .....__. _.

.~

__......__._.

..__._

~.~

..

_~

__

~_.r

....

_"

_,__

.,_~

,_",

.~,~_.

__ ,

._._,_~_.~

..

_~._.

~

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._.__ ---........ __

.~----".-

".

-."'-----...

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---

TABLE 2

COST PER

TON EVALUAnON

SCR ON POST.LNB DRY.BOTTOM, AND GROUP 2 BOILER

(Baseline Case And Sensitivity Analysis)

Cost Per Ton

$/T

(NOx)

Economic

~

Process

F.

ya

I

ua

!.

IOD

C

OD

d.ti

Ions

on

Baseline:

SCR Applied

80% NOx reduction!

$75/kW,65%

1600 (0.50)

to P05!.LNB, Dry-

S ppm slip, 3200 l!h SV,

CF, 0.15 CRF

1768 (0.45)

bottom Boiler

4

yr catalyst life

(Baseline)

Baseline:

SCR

Applied

80% NOx reduction!

$79/kW, 65%

696 (1.3)

to Group 2 (Cyclone)

5

ppm slip, 2000 l!h SV, 4 CF, 0.15 CRF

Boiler

yr catalyst life,

(Baseline)

Sensitivity:

Incremental

Dry-Bottom Baseline

same

<I

220 (0.50)

Capital

Boiler Case

<I

250 (0.45)

(+!- $15!kW)

Group 2 Boiler Baseline

same

<180 (1.3)

Case

Sensitivity:

Dry-Bottom Baseline

same, except

<I

340 (0.50)

Capacity Factor (65% to

Boiler Case

CF

<I

380 (0.45)

85% increase)

Group 2 Boiler Baseline

same, except

<1120 (1.3)

Case

CF

Sensitivity:

Dry-Bottom Boiler

same, except

Capital Recovery Factor Baseline Case

CRF

<1650 (0.50)

(0.15 to 0.115 decrease)

Group 2 Boiler Baseline

same, except

<190 (1.3)

Case

CRF

SCR!Dry-Bottom

Dry-Bottom Case, except as

as noted

($60/kW, 85% CF, 0.115

noted

935 (0.50)

CRF

1029 (0.45)

SCR!Group2

Group 2 Baseline Case,

as noted

424

(1.3)

($60!kW, 85% CF, 0.115

except as noted

eRF

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