ILLINOIS POLLUTION CONTROL BOARD

ILLINOIS POLLUTION CONTROL BOARD
TITLE 35: ENVIRONMENTAL PROTECTION
SUBTITLE B: AIR POLLUTION

April 16, 2009

IN THE MATTER OF:

AMENDMENTS TO 35 ILL. ADM. CODE

225: CONTROL OF EMISSIONS FROM

LARGE COMBUSTION SOURCES

Proposed Rule. Second Notice.

OPINION AND ORDER OF THE BOARD (by A.S. Moore):

Today the Board adopts for second notice a proposal amending Part 225 of its air

pollution regulations. On October 3, 2008, the Illinois Environmental Protection Agency

(Agency or IEPA or Illinois EPA) initiated this proceeding by filing a proposal under the general

rulemaking provisions of Sections 27 and 28 of the Environmental Protection Act (Act) (415

ILCS 5/27 (2006)). Generally, the Agency proposed to recreate certain monitoring provisions of

the federal Clean Air Mercury Rule (CAMR), which the United States Court of Appeals recently

vacated, by adding those provisions to Illinois’ mercury rule. On October 28, 2008, the Agency

filed a motion for expedited review of its proposal.

In an order dated November 5, 2008, the Board, among other actions, granted the

Agency’s motion for expedited review and sent the Agency’s proposal to first notice publication

in the

Illinois Register

without commenting on the substantive merits of the proposal.

See

32 Ill.

Reg. 18507-18826 (Dec. 5, 2008). The Board has now held two hearings on the Agency’s

proposal: the first on December 17, 2008, in Springfield; and the second on February 10, 2009,

in Chicago. In its order below, the Board directs the Clerk to file the proposal with the Joint

Committee on Administrative Rules for second-notice review.

In this opinion and order, the Board first provides the procedural history of this

rulemaking. The Board then addresses a number of preliminary issues, including motions to

correct the transcript of the Board’s second hearing and motions to file

instanter

. After

providing a brief background on Illinois’ regulation of mercury emissions, the Board summarizes

participants’ post-hearing comments. The Board then makes its findings on the economic

reasonableness and technical feasibility of the second-notice proposal before proceeding to a

section-by-section summary. Finally, the Board directs the Clerk to file the proposed

amendments to Part 225 with the Joint Committee on Administrative Rules for second-notice

review.

PROCEDURAL HISTORY

On October 3, 2008, the Agency filed a rulemaking proposal (Prop.) under the general

rulemaking provisions of Sections 27 and 28 of the Act (415 ILCS 5/27, 28 (2006)). A

Statement of Reasons (Statement) and Technical Support Document (TSD) accompanied the

proposal. A motion for waiver of various filing requirements also accompanied the proposal.

On October 28, 2008, the Agency also filed a motion for expedited review in this matter.

In an order dated November 5, 2008, the Board accepted the Agency’s proposal for

hearing and granted the Agency’s motions for waiver of filing requirements and expedited

review. In the same order, the Board sent the proposal to first-notice publication in the

Illinois

Register

without commenting on its substantive merits.

See

32 Ill. Reg. 18507-18826 (Dec. 5,

2008). In a letter dated November 7, 2008, the Board requested that the Department of

Commerce and Economic Opportunity (DCEO) conduct an economic impact study of the

Agency’s rulemaking proposal.

See

415 ILCS 5/27(b) (2006). DCEO has not responded to this

request.

In an order dated November 7, 2008, the hearing officer scheduled a first hearing on

December 17, 2008, in Springfield and a second hearing on January 13, 2009, in Chicago.

On December 2, 2008, the Board received pre-filed testimony on behalf of the Agency by

Mr. Jim Ross, Mr. David E. Bloomberg, Mr. Rory A. Davis, and Mr. Kevin J. Mattison. Also on

December 2, 2008, the Agency filed its First

Errata

Sheet (

Errata

1). On December 10, 2008,

the Board received amended testimony on behalf of the Agency from Mr. Ross and Mr.

Bloomberg.

The first hearing in this proceeding took place as scheduled on December 17, 2008, in

Springfield. At the first hearing, the hearing officer admitted into the record seven exhibits: the

pre-filed testimony of Mr. Mattison (Exh. 1); the original pre-filed testimony of Mr. Bloomberg

(Exh. 2); the pre-filed testimony of Mr. Davis (Exh. 3); the original pre-filed testimony of Mr.

Ross (Exh. 4); the first

errata

sheet (Exh. 5 or

Errata

1); the amended pre-filed testimony by Mr.

Bloomberg (Exh. 6); and the amended pre-filed testimony of Mr. Ross. (Exh. 7). The Board

received the transcript of the first hearing (Tr.1) on December 29, 2008.

In an order dated December 23, 2008, the hearing officer cancelled the second hearing

originally scheduled on January 13, 2009, and rescheduled that hearing to February 10, 2009.

See

Tr.1 at 203.

On January 14, 2009, the Agency filed post-hearing comments (PC 1) addressing

questions raised and requests for information at the first hearing. Also on January 14, 2009, the

Agency filed its Second

Errata

Sheet (

Errata

2) and a motion for waiver of filing requirements.

On January 30, 2009, the Board received pre-filed testimony on behalf of Midwest

Generation from Mr. Scott Millerand a request from Midwest Generation to replace specified

language within proposed regulatory language submitted by Mr. Miller. On February 2, 2009,

the Board received pre-filed testimony on behalf of Dynegy Midwest Generation, Inc. (Dynegy)

from Mr. Aric D. Diericx, pre-filed testimony on behalf of Kincaid Generation LLC (Kincaid)

from Mr. David Nuckols, and pre-filed testimony on behalf of Ameren Energy Generating

Company, AmerenEnergy Resources Generating Company, and Electric Energy, Inc.

(collectively, Ameren) from Mr. Michael L. Menne. On February 5, 2009, Ameren filed a

motion to file

instanter

the testimony of Mr. Gary M. Rygh.

In an order dated February 5, 2009, the Board granted the Agency’s January 14, 2009,

motion for waiver of filing requirements.

On February 6, 2009, the Agency filed its Third

The second hearing in this proceeding took place as re-scheduled on February 10, 2009,

in Chicago. At the re-scheduled second hearing, the hearing officer admitted into the record nine

exhibits: the Agency’s proposed amendments to Section 225.260(b), Appendix B, Section 1.8,

and Section 225.290(b)(3)(C) (Exh. 8); the Agency’s proposed amendment to Appendix B,

Section 1.4(b)(3)(G)(iv) (Exh. 9); the pre-filed testimony of Mr. Nuckols (Exh. 10); “Stay of the

Effectiveness of Requirements for Air Emission Testing Bodies,” 73 Fed. Reg. 65554-56 (Nov.

4, 2008) (Exh. 11); the pre-filed testimony of Mr. Miller (Exh. 12); the request to replace

specified language within proposed regulatory language submitted by Mr. Miller (Exh. 13); the

pre-filed testimony of Mr. Diericx (Exh. 14); the pre-filed testimony of Mr. Menne (Exh. 15);

and the motion to file

instanter

the pre-filed testimony of Mr. Rygh, accompanied by his pre-

filed testimony (Exh. 16). The Board received the transcript of the re-scheduled second hearing

(Tr.2) on February 19, 2008.

During the re-scheduled second hearing, four persons offered public comment: Ms.

Heather Hampton-Knodle of the Montgomery County Economic Development Corporation (Tr.2

at 95-99), Mr. Terry L. Denison of the Jacksonville Regional Economic Development

Corporation (Tr.2 at 100-04), Mr. Alvis L. Martin of the Illinois AFL-CIO (Tr.2 at 104-06), and

Mr. Robert M. Lewis of Development Strategies (Tr.2 at 106-09).

On February 19, 2009, and as requested at the re-scheduled second hearing, the Agency

filed its proposal as revised by each of its

errata

sheets and by the two hearing exhibits

proposing amendments (Rev. Prop.).

See

Exhs. 8, 9; Tr.2 at 111. Also on February 19, 2009,

the Agency filed its fourth

errata

sheet (

Errata

4), which is reflected in its revised proposal filed

on the same date.

On March 5, 2009, the Board received from the Agency, Midwest Generation, Dynegy,

and Ameren a joint motion to correct the transcript of the February 10, 2009, hearing. On March

6, 2009, the Board received from Kincaid a motion to correct the transcript of the February 10,

2009, hearing.

On March 5, 2009, the Board received the post-hearing comments of Midwest Generation

(MG Comment) and Dynegy (Dynegy Comment). On March 6, 2009, the Board received post-

hearing comments from the Agency (Agency Comment), Kincaid (Kincaid Comment), and

Ameren (Ameren Comment).

On March 11, 2009, the Board received a motion to file

instanter

Midwest Generation’s

response to the Agency’s post-hearing comments (MG Mot.), accompanied by Midwest

Generation’s response to the Agency’s post-hearing comments (MG Resp.). On March 13, 2009,

the Board received a motion to file

instanter

Dynegy’s response to the Agency’s post-hearing

comments (Dynegy Mot.), accompanied by Dynegy’s response to the Agency’s post-hearing

comments (Dynegy Resp.).

PRELIMINARY ISSUES

Motions to Correct Transcript

Joint Motion

As noted above under “Procedural History,” the Board on March 5, 2009, received from

the Agency, Midwest Generation, Dynegy, and Ameren (jointly, movants) a joint motion to

correct the transcript of the February 10, 2009, hearing (Joint Mot.). In their motion, the

movants identified errors in that transcript.

See

Joint Mot. at 1-9,

see

35 Ill. Adm. Code 101.604

(Formal Board Transcript). The movants requested that the Board order correction and

republication of the transcript of the February 10, 2009, hearing “because of the significant

number of errors in this transcript and because of the significance of some of those errors.”

. at

The Board notes the movant’s request to “search entire document for ‘board’ and change

to ‘Board.’” Joint Mot. at 1. Having reviewed the transcript of the February 10, 2009, hearing,

the Board locates such a change at page five of the transcript on lines 8, 12, 17, 18, 19, 21, 23,

and 24; on page 16 of the transcript at line 24; and on page 95 of the transcript at line 11.

See

Tr.2 at 5, 16, 95. The Board also notes the movants’ request that, “[w]here ‘member’ follows

‘Board,’ ‘member’ should be capitalized in the entire document.” Joint Mot. at 1. The Board

locates such a change at page two of the transcript on lines 2, 3, and 4 and on page five of the

transcript on lines 18, 19, 21, and 23.

See

Tr.2 at 2, 5.

Kincaid’s Motion

As noted above under “Procedural History,” the Board on March 6, 2009, received from

Kincaid a motion to correct the transcript of the February 10, 2009, hearing (Kincaid Mot.). In

its single proposed correction, Kincaid seeks on page 42 at line 19 to “[c]hange ‘can’t’ to ‘can.’”

Kincaid Mot. at 1. Kincaid requests that, “because of the significance of this error,” the Board

order correction and republication of the transcript.

. The Board notes that movants’ requested

corrections included this proposed change.

See

Joint Mot. at 5.

Discussion of Motions to Correct

Section 101.500(d) of the Board’s procedural rules provides in pertinent part that,

“[w]ithin 14 days after service of a motion, a party may file a response to the motion. If no

response is filed, the party will be deemed to have waived objection to the granting of the

motion, but the waiver of objection does not bind the Board or the hearing officer in its

disposition of the motion.” 35 Ill. Adm. Code 101.500(d). The Board has received no response

to either movants’ or Kincaid’s motion to correct.

Based on its review of the movants’ and Kincaid’s motions to correct, and in the absence

of any response to either of those motions, the Board grants both motions to correct. The Board

directs the Clerk to obtain corrections of the transcript of the February 10, 2009, hearing as set

forth in the motions and to obtain republication of the transcript. The Board notes that, on March

23, 2009, the Board received and included in the record of this proceeding a corrected transcript

of the second hearing.

Motions to File

Instanter

Midwest Generation’s Motion

On March 11, 2009, the Board received from Midwest Generation a motion to file

instanter

its response to the Agency’s post-hearing comments. Midwest Generation notes that,

in its own post-hearing comments filed on March 5, 2009, it proposed that the Board amend

Section 225.294(j)(2) to correspond to the Agency’s proposed language for Section

225.294(g)(4). MG Mot. at 1, citing MG Comments at 4. Midwest Generation also noted that

the Agency filed post-hearing comments on March 6, 2009. MG Mot. at 1;

see

Agency

Comments. Midwest Generation states that, “[i]n its Post-Hearing Comments, the Agency

responded to Midwest Generation’s suggested amendment to Section 225.294(j)(2) by

suggesting different language and by adding amendments to Section 225.294(j)(1) as well.” MG

Mot. at 2, citing Agency Comments at 16. Midwest Generation concludes that “[a]ccepting and

considering Midwest Generation’s Response to the Agency’s Post-Hearing Comments will not

delay the Board’s decision in this matter and will provide the Board with a statement of Midwest

Generation’s support of the Agency’s proposed changes to Section 225.294(j)(1) and (2).” MG

Mot. at 2.

Dynegy’s Motion

On March 13, 2009, the Board received from Dynegy a motion to file

instanter

its

response to the Agency’s post-hearing comments. Dynegy notes that, in its own post-hearing

comments filed on March 5, 2009, it proposed that the Board amend Section 225.265(a)(1)(C)

“to allow for compositing coal samples to correspond to the period that sorbent traps, or excepted

monitoring systems, remain in the stack.” Dynegy Mot. at 1, citing Dynegy Comments at 2-3.

Dynegy notes that it also proposed that the Board amend Section 225.233(c)(5)(B) to correspond

to the Agency’s proposed language for Section 225.233(c)(2)(D). Dynegy Mot. at 1, citing

Agency Comments at 3-4. Dynegy also notes that it proposed amending Section 225.290(b)(4)

“to allow additional time for companies using excepted monitoring systems to submit their

quarterly reports.” Dynegy Mot. at 2, citing Dynegy Comments at 4.

Dynegy states that the Agency filed post-hearing comments on March 6, 2009. Dynegy

Mot. at 2;

see

Agency Comments. Dynegy further states that the Agency’s post-hearing

comments responded to Dynegy “either by pointing out that sufficient flexibility already exists

or by proposing slightly different language.” Dynegy Mot. at 2;

see

Agency Comments at 14-17.

Dynegy concludes that granting the motion to file

instanter

will not delay the Board’s decision in

this matter and will provide the Board with a response supporting the Agency’s proposed

changes. Dynegy Mot. at 2.

Discussion of Motions to File

Instanter

Section 101.500(d) of the Board’s procedural rules provides in pertinent part that,

“[w]ithin 14 days after service of a motion, a party may file a response to the motion. If no

response is filed, the party will be deemed to have waived objection to the granting of the

motion, but the waiver of objection does not bind the Board or the hearing officer in its

disposition of the motion.” 35 Ill. Adm. Code 101.500(d). The Board has received no response

to either Midwest Generation’s or Dynegy’s motion to file

instanter

Based on its review of the motions, and in the absence of any response to either of them,

the Board grants both Midwest Generation’s and Dynegy’s motion to file

instanter

. The Board

accepts Midwest Generation’s response to the Agency’s post-hearing comments (MG Resp.) and

also accepts Dynegy’s response to the Agency’s post-hearing comments (Dynegy Resp.). The

statements and arguments made in those responses are included below in the summaries of post-

hearing comments and in the Board’s second-notice proposal.

BACKGROUND ON REGULATION OF MERCURY EMISSIONS

The United States Environmental Protection Agency (USEPA) promulgated CAMR on

May 18, 2005. Statement at 6, citing 70 Fed. Reg. 28606. The Agency states that it determined,

“and still believes,” that CAMR would not result in sufficient reductions of mercury in a timely

manner, and that CAMR would impede its efforts to encourage clean-coal technology that will

allow Illinois’ abundant coal reserves to be used in an environmentally responsible manner.”

Statement at 6-7. Noting that CAMR did not preclude states from adopting more stringent

mercury controls, the Agency concluded that “the optimum method to comply with the federal

requirements under CAMR, and protect the health of Illinois citizens, was to adopt mercury

emission standards for coal-fired power plants in Illinois.”

. at 7, 10, citing 70 Fed. Reg.

28632.

The Agency filed its mercury rulemaking proposal with the Board on March 14, 2006. In

the Matter of: Proposed New 35 Ill. Adm. Code 225 Control of Emissions From Large

Combustion Sources (Mercury)

The Agency states that, “[o]n February 8, 2008, the United States Court of Appeals for

the District of Columbia vacated CAMR.” Statement at 11, citing

, R06-25. The Board adopted Part 225 on December 21, 2006.

See

31 Ill. Reg. 129 (Jan. 5, 2007);

see

35 Ill. Adm. Code Part 225, Exh. 7 at 2-3, Agency

Comment at 1.

CAMR required each state to comply with the provisions of Part 75 of the Code of

Federal Regulations “with regard to monitoring emissions of mercury to the atmosphere.”

Statement at 10, citing 70 Fed. Reg. 28649;

see

40 C.F.R. 75. Illinois required affected sources

to comply with the provisions of Section 225.240 through 225.290, “which specifically required

compliance with 40 C.F.R. Part 75.” Statement at 10-11.

New Jersey v. Envtl. Prot.

Agency, 517 F.3d 574, 578-81 (D.C. Cir. 2008);

see

PC 1 at 5-6. The Agency argues that,

“[a]lthough the court’s decision vacated the portions of 40 C.F.R 75 enacted as part of CAMR,

including those provisions that authorize the continuous emissions monitoring of mercury, the

court’s

vacatur

had nothing to do with the technical or economic reasonableness of CAMR’s

monitoring provisions.” Statement at 11. The Agency claims that the court objected to

USEPA’s approach to regulating mercury but nonetheless, “whether intending to or not, removed

the entire monitoring scheme relied on by USEPA to monitor mercury emissions.”

. The

Agency concludes that, although USEPA is likely to have to recreate federal monitoring

provisions, “it is necessary for Illinois’ rules to reference its own monitoring provisions.”

. at

12,

see

Exh. 7 at 3, Agency Comment at 2.

Accordingly, the Agency proposes to “replace the relied-upon federal monitoring

references with appropriate monitoring provisions for the Illinois mercury rule in the absence of

the vacated CAMR program by incorporating the sections of Part 75 that were previously relied

upon.” TSD at 6. Specifically, the Agency proposed amendments including “the appropriate

provisions of Part 75 monitoring requirements, with noted changes. “Such changes include the

removal of provisions that were appropriate only with the existence of a national mercury trading

program and a state-by-state emissions cap (

e.g.

, bias adjustment factor, missing data

substitution).” Agency Comment at 3.

SUMMARY OF POST-HEARING COMMENTS

In consecutive subsections below, the Board summarizes the post-hearing comments filed

by the following participants: Midwest Generation, Dynegy, Kincaid, Ameren, and the Agency.

The Board then summarizes the responses to the Agency’s post-hearing comments filed by

Midwest Generation and Dynegy.

Midwest Generation

Midwest Generation states that it “generally supports” the Agency’s proposal as it has

been amended in the course of these proceedings and as it is reflected in the February 19, 2009,

filing compiling the Agency’s proposed amendments. MG Comment at 1;

see generally

Rev.

Prop. Nonetheless, Midwest Generation proposes one further amendment to Section

225.294(j)(2), as described in the following subsection, and raises other issues that “deserve

particular attention,” which the Board addresses in subsequent subsections. MG Comment at 2.

Regarding the Agency’s proposed Section 225.294(g)(4), Midwest Generation

encourages the Board to adopt the Agency’s proposal to delete the requirement for temperature

correction. MG Comment at 3;

see Errata

3 at 11. Midwest Generation first supports its request

by arguing that this deletion “would allow for a reasonable implementation of the sorbent

injection requirements of the Combined Pollutant Standard (CPS) as our understanding of the

most effective design of sorbent injection systems evolves.”

. Specifically, Midwest

Generation claims that “[t]his revision allows sources to increase the amount of time and space

in which flue gas is exposed to sorbent without unnecessarily imposing an increase in the amount

of sorbent that must be injected.”

Id.

Midwest Generation also claims that its proposed revision

“more faithfully reflects the Agency’s understanding of the effect that injecting sorbent at a rate

Deletion of Temperature Correction and Proposed Amendment of Section 225.294(j)(2)

of 5 lb/macf [pounds per million actual cubic feet] has on removing mercury from the flue gas

stream.”

Midwest Generation argues that, if the Board adopts the proposal to remove from Section

225.294(g)(4) the temperature correction factor for units other than those equipped with sorbent

injection prior to a hot-side electrostatic precipitator (ESP), the Board should also remove from

Section 225.294(j)(2) the monitoring, recordkeeping, and reporting of “flue gas temperature at

the point of sorbent injection” for all units except those injecting sorbent prior to a hot-side ESP.

MG Comment at 4. Midwest Generation claims that “[t]his particular point was not identified

during the discussions that addressed Section 225.294(g)(4), but the correction corresponds to

that revision.”

. Midwest Generation proposes specific language amending Section

225.294(j)(2) and “encourages the Board to adopt both of these revisions to the proposal.”

Stack Testing and Monitor Availability

Midwest Generation notes that the Agency proposes to add Section 225.239 “to provide

for stack testing as the means for demonstrating compliance with the mercury rule through June

30, 2012.” MG Comment at 2. Midwest Generation emphasizes Mr. Miller’s testimony, which

describes difficulties with CEMS and states that the company, despite approximately two years

of experience with the systems, had at that time monitor availability of zero percent.

., citing

Tr.2 at 75, Exh. 12 at 12-18. Midwest Generation states that, because of the amount of time that

CEMS is not available, it favors the Agency’s proposal to add Section 225.239. MG Comment

at 3.

Coal Sampling

First, Midwest Generation notes that the Agency has proposed in Section 225.140(h)(7)

to incorporate by reference ASTM D6722-01, “Standard Test Method for Total Mercury in Coal

and Coal Combustion Residues by Direct Combustion Analysis (2001),” as a method for

determining the amount of mercury in coal. MG Comment at 5. Midwest Generation states that

it “supports this addition and urges the Board to adopt this amendment to the mercury rule.”

Second, Midwest Generation claims that the Agency’s proposal did not clearly allow

weighted averaging in monthly determinations of the amount of mercury in coal burned. MG

Comment at 5. Midwest Generation argues that the Agency’s testimony clarifies “that

companies may use weighted averaging. . . .”

., citing Tr.2 at 21 (Bloomberg testimony). In

support of this clarification, Midwest Generation expresses the belief “that weighted averaging

will provide a more accurate report of the amount of mercury in the coal burned.” MG Comment

at 5.

Third, “Midwest Generation supports the Agency’s proposal to reduce the frequency of

coal sampling to monthly from daily for CPS units where the units have not opted in to the 90%

reduction requirement.” MG Comment at 5;

see

Rev. Prop. at 176 (proposed Section

225.265(a)(1)(A).

Approved Sorbents

Midwest Generation notes that the Agency proposes to add to the regulation’s list of

approved sorbents two sorbents manufactured by Calgon. MG Comment at 5. Midwest

Generation states that it “appreciates the Agency’s willingness to codify its approval of these two

sorbents, Calgon Carbon’s FLUEPAC CF Plus and Calgon Carbon’s FLUEPAC MC Plus, and

urges the Board to adopt that amendment.”

Matching Inlet Mercury Emissions to Quality-Assured Monitor Operating (QAMO) Outlet

Emissions

Midwest Generation notes that the Agency “proposed to allow the option of utilizing the

inlet mercury emissions based on coal sampling that matches in time the QAMO hours of the

outlet mercury emissions when calculating the percent mercury reduction.” MG Comment at 6;

see

Rev. Prop. at 3 (proposed Section 225.290(b)(3)(F)). Midwest Generation states that it

“agrees that this is a more accurate method for calculating mercury emission reductions and

urges the Board to adopt this amendment.” MG Comment at 6.

Retroactive Noncompliance Under Section 225.239(g)(2)

Midwest Generation states that the Agency’s revised proposal responds to its questions

regarding retroactive noncompliance under the stack testing alternative. MG Comment at 6;

see

Rev. Prop. at 58 (proposed Section 225.239(g)(2)). Midwest Generation states that the Agency

limits “the period of time during which a company relying on stack testing as its means of

demonstrating compliance could be found noncompliant as a result of a failed stack test.” MG

Comment at 6. Midwest Generation further states that the Agency would limit noncompliance

“retrospectively to the more recent of the first day of the quarter in which the failed stack test

occurred, the last day of certified CEMS data demonstrating compliance, or the date on which a

significant change occurred that would require retesting and continuing until compliance is

demonstrated.”

. Midwest Generation characterizes this as an “acceptable” approach and

encourages the Board’s adoption of the proposed Section 225.239(g)(2).

Id.

However, Midwest

Generation argues that this approach does not necessarily apply with regard to other pollutants

for which stack testing may be the method for demonstrating compliance.

“Optimum Manner”

Midwest Generation states that it has had questions regarding the requirement that units

subject to the CPS must inject sorbent in an “optimum manner.” MG Comment at 7;

see

Rev.

Prop. at 85 (proposed Section 225.294(g). Midwest Generation states that the Agency has

clarified this issue and that it “seeks no further clarification or other action from the Board

regarding “optimum manner.” MG Comment at 7, citing Tr.2 at 12-16 (statement by Jim Ross).

Dynegy states that it “generally supports” the Agency’s proposal as it has been amended

in the course of these proceedings and as it is reflected in the February 19, 2009, filing compiling

the Agency’s proposed amendments. Dynegy Comment at 1, 6;

see generally

Rev. Prop.

Dynegy

Nonetheless, Dynegy proposes three further amendments and also raises other issues that it

“wishes particularly to address.” Dynegy Comment at 1, 6. The Board summarizes these

proposed amendments and other issues in subsequent subsections.

Coal Analysis

On the issue of coal sampling, Dynegy expresses the understanding that, under the

Agency’s proposed rule, semi-annual reports submitted by MPS companies relying on stack

testing for units that do not opt into the 90% reduction standard before the compliance deadline

are not required to include coal data. Dynegy Comment at 1-2. Dynegy states that, “this data is

to be maintained at each power station and made available to the Agency upon request.”

. at 2.

Dynegy also expresses the understanding that MPS units relying on stack testing that

comply with the mercury standard before 2015 “must collect and analyze coal samples for

mercury content for each day during stack testing and then on a monthly basis between stack

tests.” Dynegy Comment at 2. Dynegy states that “the coal sampling requirement is

contemporaneous with the emission sampling period.”

Dynegy also expresses the understanding that MPS units complying with the mercury

emission standard through 90% reduction and relying on sorbent traps for monitoring “must

collect daily coal samples.” Dynegy Comment at 2. Dynegy argues that the Agency’s proposed

Section 225.265 addresses sampling, analyzing, and averaging those analyses “but does not

specifically allow or prohibit compositing of samples prior to analysis.”

see

Rev. Prop. at

71-72 (proposed Section 225.265). Dynegy claims that, “[i]n other words, the daily coal

sampling requirement is much more frequent than the emission sampling period.” Dynegy

Comment at 2.

Dynegy proposes that the Board allow the period for analyzing daily coal samples to

correspond with the period for sorbent trap data capture. Dynegy Comment at 2. Dynegy states

that this data capture period “varies depending on the flue gas flow rate in the stack and the

mercury emission rate.”

. Dynegy expects that sorbent traps will capture data in stacks for

periods of seven to eight days, during which they effectively create a composite of mercury

emissions during that period.

Dynegy also proposes that “coal samples could be composited over a period of time

corresponding to the sorbent trap sampling period.” Dynegy Comment at 2. Dynegy argues that

“[t]his practice would produce more relevant data because the data analyzed would have been

collected over a similar period of time.”

. Dynegy offers language reflecting these comments

with which to amend the Agency’s proposed Section 225.265(a)(1)(C).

see

Rev. Prop. at 72.

Dynegy notes removal of the temperature correction factor for units other than those

equipped with sorbent injection prior to a hot-side electrostatic precipitator (ESP). Dynegy

Comment at 3;

see errata

3 at 3-4, Rev. Prop. at 32 (proposed Section 225.233(c)(2)(D)).

Dynegy argues that, in conjunction with this removal, “the monitoring, recordkeeping, and

Temperature Correction Factor

reporting of ‘flue gas temperature at the point of sorbent injection’ should be removed from

Section 225.233(c)(5)(B) for all units except those injecting sorbent prior to a hot-side ESP.”

Dynegy Comment at 3;

see

Rev. Prop. at 34 (proposed Section 225.233(c)(5)(B)). Dynegy

proposes specific language to effect this revision. Dynegy Comment at 3-4.

Reporting Deadline

Dynegy expresses the understanding that “EGUs using excepted monitoring systems will

be hard-pressed to have their end-of-quarter emission measurements collected, sent off-site for

analysis, and the reported data then included in the quarterly report for submittal to the Agency,

all within 45 days.” Dynegy Comment at 4. Dynegy argues that “[a] 60-day reporting deadline

is more appropriate for the additional transportation and analytical steps associated with excepted

monitoring systems.”

see

Rev. Prop. at 78 (proposed Section 225.290(b)(4)) Dynegy

proposes specific language to effect this revision. Dynegy Comment at 3-4.

Dynegy states that it injects SO

“prior to the ESP on some units to enhance particulate

capture. However, the presence of SO

in the flue gas can inhibit mercury capture by

halogenated activated carbon.” Dynegy Comment at 4 (citations omitted). Dynegy argues that

the scientific literature indicates that it “should expect reduced mercury removal at those units

where it injects SO

, even, perhaps, those units controlled by both an ESP and a baghouse.”

Sulfur Trioxide (SO

) Injection

at 4-5. Dynegy concludes its discussion of this issue by stating that its “units injecting SO

may

not be able to achieve mercury reductions at levels normally anticipated to be achieved through

injection of sorbent at a rate of 5 lb/macf, despite that the injection system is ‘designed for

effective absorption of mercury’ in accordance with Section 225.233(c)(2).”

. at 5.

“Optimum Manner”

Dynegy states that it had questions regarding the Agency’s application of the requirement

that MPS units must inject sorbent in an optimum manner. Dynegy Comment at 5;

see

35 Ill.

Adm. Code 225.233(c)(2). Dynegy states that the Agency has clarified this issue and that it

“seeks no further clarification or other action from the Board regarding “optimum manner.”

Dynegy Comment at 5, citing Tr.2 at 12-16 (statement by Jim Ross).

Dynegy specifically cites two documents: Ramsay Change and Katherine Dombrowski, “Near

and Long Term Options for Controlling Mercury Emissions from Power Plants,” Paper #25,

MEGA Symposium (2008) at 9; and Thomas J. Feeley, III,

et al

., “DOE/NETLS’s Mercury

Control Technology R&D Program –

Taking Technology from Concept to Commercial Reality

,”

Paper #42, MEGA Symposium (2008) at 6. Dynegy notes that these documents are,

respectively, Exhibit 4 and 5 to its recent petition for a variance (Dynegy Midwest Generation v.

IEPA, PCB 09-48 (Jan. 9, 2009)) and that the documents “so are readily available to the Board

for further review.” Dynegy Comment at 5 n.1.

Kincaid

Kincaid states that it participated in the Board’s second hearing in order to raise two

issues. Kincaid Comment at 1. First, Kincaid sought greater flexibility with requirements for the

availability of CEMS.

. Kincaid states that the Agency addressed this issue “with language

submitted during the hearing allowing quarterly stack tests to be performed during the first three

years of this regulation. Three years of experience with mercury CEMS should allow for

development of availability information sufficient to comply with the rule at that time.”

see

Exh. 8.

Second, Kincaid states that it “alerted the Board about the potential inconsistency

between state and federal rules should the Board adopt the Agency’s proposed Appendix B

restating the language of 40 C.F.R. 75 as it applies to constituents other than mercury.” Kincaid

Comment at 1. Kincaid notes that Mr. Nuckols testified and responded to questions regarding

this issue at the second hearing and that Kincaid continued after the hearing to discuss the issue

with the Agency.

. On the basis of these discussions, Kincaid believes, “with respect to any

conflict between Appendix B and 40 C.F.R. 75 as they relate to monitoring for constituents other

than mercury, that the IEPA would resolve conflicts in favor of the federal rules.”

. Kincaid

expresses concern about including provisions regarding these other constituents in Appendix B.

. Nonetheless, Kincaid understands that “IEPA will work with a source to resolve any issues

that arise.”

Ameren

Ameren states that it “generally supports” the Agency’s revised proposal filed on

February 19, 2009, which encompasses a number of clarifications and corrections offered over

the course of this proceeding. Ameren Comment at 2;

see

Rev. Prop. Ameren states that the

Agency’s revised proposal “helps clarify how the Agency intends to administer the Mercury

Rule and consequently assists companies such as Ameren in developing appropriate compliance

strategies and implementing procedures.” Ameren Comment at 2. While Ameren professes that

the proposed rules offer “valuable flexibility,” it offers comments on the issues of activated

carbon injection, emission monitoring, and coal sampling as clarifications rather than as

objections to those elements of the Agency’s revised proposal.

Id.; see id

. at 16 (Miscellaneous

Comments Regarding Agency Fourth

Errata

Sheet).

Ameren also proposes that the Board amend the Agency’s revised proposal by adding a

Section 225.233(e)(3) changing SO

and NO

emission rates under the MPS for specified years.

Ameren Comment at 2, Exh. 15 at 5-6;

see

Ameren Energy Generating Co., Amerenenergy

Resources Generating Company, and Electric Energy, Inc. v. IEPA, PCB 09-21, slip op. at 28-29

(Oct. 1,2008) (petition for variance). Ameren states that it seeks this relief “consistent with and

pursuant to the Agency’s Recommendation in the PCB 09-21 proceeding.” Ameren Comment at

2, citing Ameren Energy Generating Co., Amerenenergy Resources Generating Company, and

Electric Energy, Inc. v. IEPA, PCB 09-21, slip op. at 10 (Nov. 17, 2008). Ameren claims that,

“[a]t no time prior to or during the Hearing has the Agency substantively or procedurally

objected to Ameren’s proposed revision to add Section 225.233(e)(3) to the Mercury Rule.

Ameren Comment at 3.

The Board summarizes Ameren’s comment on its proposal to add Section 225.233(e)(3)

in the following subsections of the opinion.

Introduction

Ameren cites “extreme financial conditions and the near collapse of capital markets

within the U.S.” to argue that compliance with the SO

emission rates of the MPS beginning in

2013 would cause it significant economic hardship. Ameren Comment at 3, citing Exh. 15 at 7-

11, Ameren Energy Generating Co., Amerenenergy Resources Generating Company, and

Electric Energy, Inc. v. IEPA, PCB 09-21, slip op. at 8-12 (Dec. 30, 2008) (Ameren public

comments). Ameren argues that its proposal alleviates this hardship by deferring capital

expenditures while including more stringent emission rates that will “more than offset the

impact” of this deferral. Ameren Comment at 3, citing Exh. 15 at 14-17; Ameren Comment,

Atts. B, C; Ameren Energy Generating Co., Amerenenergy Resources Generating Company, and

Electric Energy, Inc. v. IEPA, PCB 09-21 (Nov. 17, 2008) (Agency Recommendation). Ameren

further argues that, “largely because the proposed revision changes only the compliance dates

and emission rates for NO

and SO

as they apply to Ameren’s MPS Group and because the

technologies used to control NO

and SO

have already been found to be economically

reasonable and technically feasible, the revisions is both economically reasonable and technically

feasible. Ameren Comment at 3, citing In the Matter of Proposed New 35 Ill. Adm. Code 225:

Control of Emissions from Large Combustion Sources (Mercury), R06-25, slip op. at 37-38, 77-

78 (Nov. 2, 2006).

Authority

Ameren argues that, although the Agency is the original proponent of the amendments to

Part 225, “[t]he Board has the authority to adopt Ameren’s proposal as an amendment to the

Amended Proposal.” Ameren Comment at 4. Ameren states that the Agency’s original proposal

included amendments to the MPS, opening Section 225.233 to revision.

Id.

Ameren further

states that the Board has statutory authority to revise rulemaking in response to suggestions such

as its own written and oral testimony.

., citing 415 ILCS 5/28(a) (2006), Exhs. 15, 16. In

addition, Ameren claims that the Agency has lodged no objection to its request to add Section

225.233(e)(3). Ameren Comment at 5.

Summary of MPS and Ameren’s Proposed New Section 225.233(e)(3)

The MPS requires eligible EGUs to “achieve the more stringent of either enumerated SO

and NO

emission rates or emission limits equivalent to a percentage of the base emission rate

for that pollutant (“percent of baseline”).” Ameren Comment at 7-8, citing 35 Ill. Adm. Code

225.130 (establishing baseline period of 2003-05). Ameren states that, when it opted into the

MPS, it “provided the requisite demonstration indicating that the enumerated emission rates in

the MPS were, in fact, the more stringent of the regulatory requirements.” Ameren Comment at

8, citing Ameren Energy Generating Co., Amerenenergy Resources Generating Company, and

Electric Energy, Inc. v. IEPA, PCB 09-21 (Oct. 1,2008) (Exhibit 2 to Attachment A of petition

for variance).

Applying the enumerated rate, the MPS requires that eligible EGUs attain a system-wide

emission rate of 0.33 lbs/mmBtu beginning January 1, 2013 and continuing through

December 31, 2014. Ameren Comment at 5;

see

35 Ill. Adm. Code 225.233(e)(2)(A), Exh. 15 at

4. The MPS then requires a final SO

emission rate of 0.25 lbs/mmBtu beginning on January 1,

2015, and continuing in each calendar year thereafter. Ameren Comment at 5-6;

see

35 Ill. Adm.

Code 225.233(e)(2)(B), Exh. 15 at 4.

Applying the enumerated rates, the MPS also requires that, beginning in calendar year

2012 and continuing in each calendar year thereafter, eligible EGUs attain a system-wide overall

annual emission rate of no more than 0.11 lbs/mmBtu. 35 Ill. Adm. Code 225.233(e)(1)(A).

Beginning in the 2012 ozone season and continuing in each ozone season thereafter, the MPS

also requires that eligible EGUs attain a system-wide overall NO

seasonal emission rate of no

more than 0.11 lbs/mmBtu. 35 Ill. Adm. Code 225.233(e)(1)(B).

Ameren states that it proposed MPS revision includes the following provisions:

(i) earlier seasonal and annual NO

emission rates in calendar years 2010 and

2011 of 0.11 lb/mmBtu and 0.14 lb/mmBtu, respectively; (ii) an earlier SO

emission rate of 0.50 lbs/mmBtu in calendar years 2010 through 2013; (iii) an

emission rate of 0.43 lbs/mmBtu in calendar year 2014; (iv) an SO

emission

rate of 0.25 lbs/mmBtu in calendar years 2015 and 2016; and (iv) a more stringent

emission rate of 0.23 lbs/mmBtu beginning in 2017 and continuing

thereafter. Ameren Comment at 6, citing Exh. 15 at 5-6 (proposed new

subsection 225.233(e)(3));

see

Exh. 15 at 4-6,

, Attachment A (Ameren’s

Proposed Amendment vs. MPS Requirements: Emission Limits and Compliance

Dates).

Under subsection (b) of the MPS, owners of EGUs intending to comply with the

requirements of Part 225 through the MPS must notify the Agency of their election to do so no

later than December 31, 2007. 35 Ill. Adm. Code 225.233(b). Ameren states that it notified the

Agency on December 27, 2007, that it elected to make all 21 of its EGUs at its seven coal-fired

power stations in the state

Affected Sources

subject to the NO

and SO

provisions of the MPS. Ameren

Comment at 7, citing Ameren Energy Generating Co., Amerenenergy Resources Generating

Company, and Electric Energy, Inc. v. IEPA

Ameren identifies these seven coal-fired power stations as the Coffeen Power Station in

Montgomery County, the Duck Creek Power Station in Fulton County, the E.D. Edward Power

Station in Peoria County, the Joppa Power Station in Massac County, the Hutsonville Power

Station in Crawford County, the Meredosia Power Station in Morgan County, and the Newton

Power Station in Jasper County. Ameren Comment at 6-7. “These are primarily base load

facilities which provide electricity for central and southern Illinois homes and businesses.” Exh.

15 at 2.

, PCB 09-21 (Oct. 1,2008) (Exhibit 2 to Attachment

A to petition for variance);

see

Exh. 15 at 2.

Ameren states that its proposal “revises NO

and SO

emission rates for only Ameren’s

MPS Group.” Ameren Comment at 7. Ameren further states that “[t]he proposed revision does

not revise eligibility requirements for opting in the MPS and, to that extent, does not permit

EGUs not already subject to the pending SO

and NO

emission rates under Section 225.233(e)

to be subject to the revised emission rates under Ameren’s proposal.”

. Ameren also describes

the pollution control equipment necessary to comply with the MPS and argues that its proposed

revision does not relieve Ameren from having to install that equipment at its EGUs to comply

with emission limits.

Stringency of Proposed Section 225.233(e)(3)

Ameren notes that the Board asked during the second hearing why Ameren’s proposal

“did not provide for the more stringent of the specified emission rates or percent of baseline.”

Ameren Comment at 8, citing Tr.2 at 89. Ameren states that the alternate emission limits

effectively recognize that “each system’s generation and emission profile is different” and that

“the MPS had to express emission reduction requirements in terms as encompassing as possible.”

Ameren Comment at 8. Ameren states that, in negotiating the MPS, it reached agreement with

the Agency on specific emission rates.

. Ameren further states that the Agency itself added

the “percent of baseline” alternative, “presumably in anticipation of other EGU systems choosing

the MPS.”

. at n.4.

Ameren states that, because the enumerated emission rates are the more stringent

alternative for its system, it “has always intended to comply with the enumerated rates” rather

than the “percent of baseline” reduction.

. at n.4. Ameren argues that a “percent of baseline”

alternative would not make its proposal more stringent and is therefore “not necessary or

valuable.”

. at 9; citing

., Attachment D (comparing alternative limits); Ameren Energy

Generating Co., Amerenenergy Resources Generating Company, and Electric Energy, Inc. v.

IEPA, PCB 09-21 (Oct. 1,2008) (Exhibit 2 to Attachment A to petition for variance).

Ameren emphasizes that its proposal does not eliminate its “obligation to comply with

the MPS through the installation of pollution control equipment” but does allow Ameren “to

defer capital expenditures from 2009-2012 to 2013-2015.” Ameren Comment at 10, citing Exh.

15 at 3 (estimating deferred amount of $500 million). Specifically, the revision allows Ameren

to defer the cost of constructing flue gas desulfurization (FGD) “necessary to achieve the 0.33

lbs/mmBtu SO

emission rate in calendar years 2013 and 2014.” Ameren Comment at 10, citing

Tr.2 at 92. Ameren stresses that this deferral does not affect its mercury controls, which it will

have regardless of the Board’s action on this proposal, but affects only FGD associated with SO

emissions. Ameren Comment at 10-11. Ameren concludes that, with the deferral of significant

Economic Reasonableness and Technical Feasibility

Ameren states that “[c]ompliance with the MPS requires substantial long-term capital

investments associated with the installation of pollution control equipment.” Ameren Comment

at 10. Ameren further states that its ability to obtain financing has suffered as a result both of

tight credit markets and “the downturn of future power price expectations.”

., citing Exh. 15 at

8-9, Exh. 16 at 3-5.

capital expenditures to 2013-15, it proposal is economically reasonable.

. at 11;

see

Exh. 15 at

12-13.

Ameren argues that the technology require to meet the limits in its proposal “are no

different in kind or scope than the technologies necessary to meeting the current emission limits

under Section 225.233(e).” Ameren Comment at 11. Ameren further argues that the Board in

the original mercury rulemaking has found these technologies to be technically feasible and

economically reasonable.

., citing In the Matter of Proposed New 35 Ill. Adm. Code 225:

Control of Emissions from Large Combustion Sources (Mercury), R06-25, slip op. at 37-38, 77-

78 (Nov. 2, 2006);

see

Exh. 15 at 12-13.

Emission Reductions Under Proposal

Ameren argues that it has cooperated with the Agency to reduce the environmental

impact of its proposal. Ameren Comment at 12, citing Exh. 15 at 14-16. Ameren further argues

that, because it “has agreed to commit to earlier and more stringent SO

and NO

emission rates,

the restructuring of the MPS compliance commitments will not result in environmental harm.”

Ameren Comment at 12.

Ameren states that it worked with the Agency to evaluate “projected mass emissions

under the MPS and the [Ameren] proposal over an eleven-year period. Ameren Comment at 14;

see

Ameren Energy Generating Co., Amerenenergy Resources Generating Company, and

Electric Energy, Inc. v. IEPA, PCB 09-21. An evaluation performed in the fall of 2008

confirmed that Ameren’s proposal resulted in a projected environmental benefit of 842 tons of

emissions. Ameren Comment at 14, citing

., Attachment B;

see

Exh. 15 at 14-15. Ameren

states that it later repeated this analysis to include calendar year 2008 and found that the proposal

“will reduce the total SO

and NO

emissions for the period between 2010 and 2020 by 851

tons”. Ameren Comment at 14, citing

., Attachment C;

see

Exh. 15 at 16.. Noting that the

proposed more stringent SO

emission rates continue beyond 2017, Ameren argues that the

projected environmental benefit will increase over time.

. at 15, Exh. 15 at 16-17.

Agency

The Agency notes that, during the first hearing, it addressed the issue of its interpretation

of the term “optimum manner” as that term is employed in the Board’s mercury emission

regulations. Agency Comment at 5, citing 35 Ill. Adm. Code 225.233(c)(2), 225.615(g);

see

Rev. Prop. at 85 (proposed Section 225.294(g)). Specifically, the Agency states that it responded

to questions regarding “what data companies needed to submit and how the data submitted by

companies will be used to evaluate compliance with the requirement that units inject sorbent in

an optimum manner.” Agency Comment at 5. The Agency indicates that it discussed these

matters with industry between the two hearings and clarified its position.

. The Agency notes

that it began the second hearing with a statement on the issue of “optimum manner” that

addressed industry’s concerns.

. at 6;

see

Tr.2 at 12-16 (statement by Jim Ross). The Agency

expresses the belief “that this issue is resolved and no further action is necessary.”

see

Comment at 7, Dynegy Comment at 5 (seeking no further clarification or Board action on the

issue).

The Agency also notes that the first hearing included discussion of “coal sampling data

from units that have opted into the MPS and CPS.” Agency Comment at 6. Although the

Agency believes that it has resolved this issue, it offers final comments on it. Specifically, the

Agency argues that it has justified its need for coal sampling data and mercury control efficiency.

. The Agency states that the mercury content of coal “is needed to determine inlet mercury,

which is necessary to determine mercury control efficiency and the level of mercury reduction

obtained.”

. The Agency further states that data on control efficiency provides a basis to

determine “the effectiveness of control systems on the various types of configurations and units.”

. The Agency also stresses that this information will assist it “in future decisions regarding

mercury control and in demonstrations that may be required by USEPA regarding mercury

control and reductions in Illinois.”

The Agency states that it has negotiated with regulated entities “throughout the

rulemaking process to resolve outstanding issues and address expressed concerns.” Agency

Comment at 4. The Agency emphasizes that, before the second hearing, it resolved all contested

issues with Midwest Generation.

. at 5, citing Tr.2 at 65 (statement by Scott Miller). The

Agency also stresses that it has resolved all contested issues with Dynegy. Agency Comment at

5, citing Tr.2 at 79 (statement by Aric Diericx). Nonetheless, the Agency addresses specific

issues raised by various regulated entities, including Midwest Generation and Dynegy. The

following subsections separately address those entities.

The Agency also addresses Midwest Generations’ comment that “the corrections made to

Section 225.233(c)(2)(D) and Section 225.294(g)(4) to account for units equipped with sorbent

injection prior to a hot-side ESP necessitate changes to Sections 225.233(c)(5)(B) and

225.294(j)(2) as well.” Agency Comment at 14, citing MG Comment at 3-4. Although the

Agency agrees that additional changes are necessary, it argues that Midwest Generation’s

Midwest Generation

The Agency notes that Mr. Miller’s prefiled testimony on behalf of Midwest Generation

raised three specific issues, each of which the Agency claims to have resolved. Agency

Comment at 7;

see generally

Exh. 12 (Miller Pre-filed Testimony). First, the Agency states that

Mr. Miller addressed the Agency’s definition or interpretation of the term “optimum manner.”

Agency Comment at 7;

see

Exh. 12 at 3-12. The Agency claims that it has settled this issue.

Agency Comment at 7;

see

MG Comment at 7, citing Tr.2 at 12-16 (statement by Jim Ross).

Second, the Agency states that Mr. Miller had addressed “the 75% monitor uptime requirements

and suggested calculating monitor availability on an annual basis.” Agency Comment at 7;

see

Exh. 12 at 12-18. The Agency notes Mr. Miller’s statement during the second hearing that the

Agency has presented revised language that “satisfactorily addresses this issue.” Agency

Comment at 7, citing Tr.2 at 66. Third, the Agency notes that “Mr. Miller requested that the

Board amend or delete the requirement n Section 225.294(g)(4) for correcting injection rates for

the difference in temperature in certain plant configurations.” Agency Comment at 7;

see

Exh.

12 at 18-24. The Agency states that its third

errata

sheet proposed amended language for this

subsection and that it resolved Midwest Generation’s concerns.

., citing Tr.2 at 66;

see Errata

3 at 11.

proposed language is “insufficient.” Agency Comment at 14. The Agency proposes

modification of its February 19, 2009, proposal.

. at 14-16.

Dynegy

The Agency claims that Mr. Diericx’s pre-filed testimony raised five specific issues, each

of which has “been put to rest.” Agency Comment at 7;

see generally

Exh. 14 (Diericx Pre-filed

Testimony). First, the Agency states that Mr. Diericx addressed the Agency’s definition or

interpretation of the term “optimum manner.” Agency Comment at 8;

see

Exh. 14 at 3-4. The

Agency claims that it has resolved this issue. Agency Comment at 8;

see

Dynegy Comment at 5.

Second, the Agency refers to a “supposed” exposure to retrospective noncompliance but

emphasizes Mr. Diericx’s statement at the second hearing that a proposed revision of the relevant

language had resolved the issue. Agency Comment at 8, citing Tr.2 at 79;

see

Exh. 14 at 4-6.

Third, the Agency notes that Mr. Diericx had also raised the issue of flue gas temperature

correction. Agency Comment at 7-8;

see

Exh. 14 at 6-7. Again, the Agency argues that its

proposed amendments have resolved the issue. Agency Comment at 8, citing Tr.2 at 78;

see

Errata

3 at 3-4. Fourth, the Agency notes that Mr. Diericx had questioned the Agency’s use of

ther term “excepted” and “accepted.” While the Agency’s post-hearing comment did not

specifically address this matter, the Board notes Mr. Diericx’s testimony that the Agency has

“satisfactorily explained that. . . .” Tr.2 at 78;

see

Tr.2 at 21-23 (Bloomberg testimony). Finally,

the Agency states that Mr. Diericx had raised the issue of “mercury emission reduction

calculation procedures.” Agency Comment at 7-8;

see

Exh. 14 at 7-8. The Agency notes Mr.

Diericx’s statement that Dynegy does not intend to pursue any further discussion on that issue

and his testimony that all of the issue raised in his pre-filed testimony had been resolved.

Agency Comment at 8, citing Tr.2 at 78, 79.

The Agency also responds to Dynegy’s post-hearing comments. First, the Agency notes

Dynegy’s statement that “sources in the MPS complying by stack testing are not required to

submit coal data in semi-annual reports, but that such information must be maintained at the

source.” Agency Comment at 13, citing Dynegy Comment at 1-2. The Agency acknowledges

that this view “is correct” but notes that sources need to submit this data with each required

emissions test report. Agency Comment at 13.

Second, the Agency notes Dynegy’s proposal “that the Board allow for the period over

which the daily samples are analyzed to correspond with the sorbent trap data capture period”

and that “the coal samples could be composited over a period o time corresponding to the sorbent

trap sampling period.” Agency Comment at 13, citing Dynegy Comment at 2. The Agency

notes that the proposed rule includes no specification describing this composting, and the

Agency opposes Dynegy’s proposed language. Agency Comment at 13. Nonetheless, the

Agency states that it “does not oppose the concept of composting proposed by Dynegy.”

The Agency notes that its proposal allows alternative monitoring and measurement to be

submitted for its approval.

Id.

, citing Rev. Prop. at 19, 20 (proposed Sections 225.202(a) and

225.210(b)(1)). The Agency stresses that any request for an alternative should include, among

other elements, “modified versions of the appropriate ASTM standards.” Agency Comment at

14.

The Agency also addresses Dynegy’s comment that “the corrections made to Section

225.233(c)(2)(D) and Section 225.294(g)(4) to account for units equipped with sorbent injection

prior to a hot-side ESP necessitate changes to Sections 225.233(c)(5)(B) and 225.294(j)(2) as

well.” Agency Comment at 14, citing Dynegy Comment at 3-4. Although the Agency agrees

that additional changes are necessary, it argues that Dynegy’s proposed language is

“insufficient.” Agency Comment at 14. The Agency proposes modification of its February 19,

2009, proposal.

. at 14-16.

Finally, the Agency notes Dynegy’s request for “an extension of time to submit end-of-

quarter reports when using excepted monitoring systems.” Agency Comment at 17, citing

Dynegy Comment at 4. The Agency states that it “agrees that Dynegy’s request is reasonable.”

Agency Comment at 17. The Agency claims that, for clarification, Dynegy’s request requires

“slightly different language,” which the Agency proposed for Section 225.290.

Id.

The Agency argues with regard to other issues raised by Kincaid that it “has worked to

reduce or dispel any confusion.” Agency Comment at 9. The Agency notes that Mr. Nuckols

testified on the status of relative accuracy testing by the Air Emissions Testing Bodies (AETB)

as a result of a federal stay.

see

Exh. 10 at 14-16, Exh. 11 (Stay of the Effectiveness of

Requirements for Air Emission Testing Bodies, 73 Fed. Reg. 65554-56 (Nov. 4, 2008)).

Specifically, Mr. Nuckols expressed concern that “sources would be required to comply with

Kincaid

The Agency claims that Mr. Nuckols’ pre-filed testimony on behalf of Kincaid raised

seven unresolved issues. Agency Comment at 8-9;

see generally

Exh. 10. Before turning to

those, the Agency noted Mr. Nuckols’ statement that “[o]ur biggest concerns involve the use of

missing data substitution and bias adjustment factors[,] which have been addressed.”

Id.

at 9,

citing Tr.2 at 35-36.

Of the unresolved issues, the Agency first notes Kincaid’s concern with the period for

calculating data availability. Agency Comment at 8, 9;

see

Exh. 10 at 9-11. The Agency

stresses Mr. Nuckols’ testimony at the second hearing that the Agency had proposed a

“reasonable” approach to this issue. Agency Comment at 9, citing Tr.2 at 37. Second, the

Agency notes Kincaid’s position in favor of removing “the single trap adjustment factor for data

collected by a single sorbent trap when one of the traps in a pair is invalid.” Agency Comment at

9; Exh. 10 at 16-17. The Agency emphasizes that “it had already proposed deleting this

adjustment factor in its Third

Errata

.” Agency Comment at 9, citing Tr. 2 at 40;

see Errata

3 at

44-45.

The Agency also notes Mr. Nuckols’ position that “the Agency should eliminate the

CEMS 75% uptime requirements for the first year.” Agency Comment at 11;

see

Exh. 10 at 11-

12. The Agency stresses Mr. Nuckols’ testimony that the Agency addressed this concern with

proposed revisions regarding monitor data availability. Agency Comment at 11, citing Tr.2 at

46-47, 59-60. Emphasizing that it is willing to work with sources to overcome any difficulties,

the Agency states that “no further changes to the Agency’s proposal on this issue are necessary.”

Agency Comment at 11.

certain stayed requirements under the Agency’s proposal.” Agency Comment at 9, citing Tr.2 at

53, 55. The Agency states that it has clarified this issue: “the Illinois mercury rule would

impose no burdens upon sources while the federal stay is in place, and that it is the Agency’s

position that, ‘assuming that the federal accreditation requirements are still stayed as of July ’09,

. . . there will be no requirements under the Illinois rule for accreditation.’” Agency Comment at

9, citing Tr.2 at 55, 56.

The Agency also addressed Kincaid’s concerns with weekly system integrity tests.

Agency Comment at 10;

see

Exh. 10 at 12-14. The Agency stresses Mr. Nuckol’s

acknowledgement that “there are no differences between the Agency’s proposal and USEPA’s

original Part 75 requirements.” Agency Comment at 10, citing Tr.2 at 49. In addition, the

Agency argues that Kincaid presented “inadequate justification for any revisions to weekly

systems integrity test measurements.” Agency Comment at 10.

The Agency also notes Mr. Nuckols’ concern that the Agency’s proposed Appendix B

and its exhibits included references to NO

and SO

. Agency Comment at 10. The Agency

expresses the belief that it has succeeded in removing such references from its proposal.

. The

Agency adds that, “[a]s far as references to other non-mercury monitoring, such as CO

or flow,

it was the Agency’s intent to replicate the appropriate Part 75 provisions into the Illinois rule.”

. The Agency continues that “[i]f at some point an unintentional deviation is brought to the

Agency’s attention, the Agency is willing to work with sources to resolve the issue.”

. The

Agency also states that it does not favor language providing that “all conflicts between the

Agency’s Appendix B and 40 C.F.R. Part 75 regarding monitoring for pollutants other than

mercury will be resolved in favor of Part 75.”

. Noting that it is willing to resolve issues of

this nature in the event that they arise, the Agency claims that such language would be

unnecessary and overly broad and may present unforeseen consequences.

The Agency states that only Kincaid among the utilities has proposed making the stack

testing alternative permanent. Agency Comment at 11. The Agency argues that this alternative

allows sources three years to overcome technical problems and for CEMS technology to mature.

. Furthermore, the Agency states that it “anticipates that during the three-year window in

which stack testing is allowed as an alternative, new federal regulations will prescribe

monitoring provisions for mercury emissions and the Illinois EPA will either adopt or otherwise

allow the use of those provisions to demonstrate compliance with the Illinois mercury rule going

forward.”

. at 11-12. The Agency argues that the stack testing alternative provides “maximum

flexibility for sources” and demonstrates the lengths to which it has gone to allay utilities’

concerns.

. at 12.

The Agency notes that Ameren’s testimony addressed only its proposed revisions to the

MPS at Section 225.233(c)(2). Agency Comment at 12;

see

Exhs. 15, 16. The Agency states

that it “is neutral on the proposed revisions” and “does not oppose the proposed Ameren

revisions.” Agency Comment at 12. The Agency acknowledges that “there exists some

regulatory uncertainty, and that these are challenging economic times.” Id. Although stressing

that it “worked with Ameren to ensure that the proposed revision would result in a slight

Ameren

environmental benefit,” the Agency argues that the original MPS was negotiated and accepted in

good faith.

. The Agency emphasizes that it “wants to make clear that our position is that the

language in the MPS should not generally be amended, and that our neutral position in this case

is not indicative of how we will treat any future attempt to further amend the MPS.”

Summary

The Agency claims that

vacatur

of CAMR justifies limited revisions to the Part 225.

Agency Comment at 17. The Agency argues that its proposal does not change emission or

control requirements and merely addresses measuring mercury emissions for demonstrating

compliance.

. The Agency concludes by urging the Board to adopt its proposed revisions.

RESPONSES TO AGENCY’S POST-HEARING COMMENTS

Midwest Generation’s Response

Midwest Generation states that, in its post-hearing comments file March 5, 2009, it

proposed amending Section 225.294(j)(2) in order to correspond with an amendment to Section

225.924(g)(4) “deleting the temperature correction factor for units that do not have hot-side

electrostatic precipitators.” MG Resp.at 1, citing MG Comment at 4;

see

Rev. Prop. at 86, 88.

Midwest Generation further notes that the Agency’s post-hearing comment suggests “slightly

different” language and also suggests amending Section 225.294(j)(1). MG Resp. at 1, citing

Agency Comment at 16. Responding to that comment, Midwest Generation states that “[t]he

Agency’s proposed language is acceptable to Midwest Generation, and Midwest Generation

encourages the Board to adopt the amendatory language proposed by the Agency for both of

these sections.” MG Resp. at 1.

Second, Dynegy states that it “suggested an amendment to Section 225.233(c)(5)(B) to

correspond to the amendment to Section 225.233(c)(2)(D) deleting the temperature correction for

all units except those with hot-side electrostatic precipitators.” Dynegy Resp. at 2, citing

Dynegy’s Response

Dynegy states that, in its post-hearing comments filed March 6, 2009, it suggested several

amendments to the Agency’s proposal as the proposal is reflected in the February 19, 2009,

filing compiling the Agency’s proposed amendments. Dynegy Resp. at 1,

see

Dynegy Comment

at 3-4. Dynegy notes that the Agency’s post-hearing comments suggested “slightly different”

language for each of these suggested amendments. Dynegy Resp. at 1.

First, Dynegy states that it “suggested an amendment to Section 225.265(a)(1)(C) to

allow for compositing coal samples so that they would correspond to the emission sampling

period of a sorbent trap, or excepted, monitoring system.” Dynegy Resp. at 1, citing Dynegy

Comment at 3. Dynegy notes the Agency’s response that there exists sufficient flexibility

through Sections 225.202(a) and 225.210(b)(1) for Dynegy to propose this compositing. Dynegy

Resp. at 1-1, citing Agency Comment at 13. Dynegy characterizes the Agency’s response as

“satisfactory.” Dynegy Resp. at 2.

Dynegy Comment at 3-4. Dynegy notes that the Agency’s post-hearing comments offer “slightly

different language” and also offer an amendment to Section 225.233(c)2)(C). Dynegy states that

the Agency’s proposed language is “acceptable.” Dynegy Resp. at 2.

Third, Dynegy states that it “proposed an amendment to Section 225.290(b)(4) to allow

additional time at the end of a quarter for companies using excepted monitoring systems to

submit their reports.” Dynegy Resp. at 2, citing Dynegy Comment at 4. Dynegy notes that the

Agency agreed with this proposal “in concept but suggested different language in its

Comments.” Dynegy Resp. at 2, citing Agency Comment at 17. Dynegy states that “[t]he

Agency’s proposed language is acceptable.” Dynegy Resp. at 2. Dynegy concludes by

encouraging the Board to accept the changes proposed by the Agency and summarized in the

preceding paragraphs.

DISCUSSION OF THE BOARD’S SECOND-NOTICE PROPOSAL TO AMEND PART

225

In an order dated November 5, 2008, the Board sent the Agency’s original proposal to

first-notice publication in the

Illinois Register

without commenting on the substantive merits of

the proposal.

See

32 Ill. Reg. 18507-18826 (Dec. 5, 2008); In the Matter of: Amendments to 35

Ill. Adm. Code 225: Control of Emissions from Large Combustion Sources (Mercury

Monitoring), R09-10 (Nov. 5, 2008). The Board has carefully reviewed and largely adopted the

revisions to the Agency’s original proposal offered by the Agency itself and by participants

including Ameren. Below, after reaching its findings on the economic reasonableness and

technical feasibility of the amended proposal, the Board provides a detailed section-by-section

discussion of its second-notice proposal.

Economic Reasonableness and Technical Feasibility

The Agency argues that “[t]he methods for monitoring mercury from EGUs that were

considered in the initial mercury rulemaking remain valid, technically feasible, and economically

reasonable.” TSD at 8;

see

Exh. 1 at 2. Claiming that the federal court did not vacate CAMR

because of any doubt about the reasonableness of the cost of monitoring, the Agency states that it

seeks merely to reconstitute those provisions at 40 C.F.R. into Part 225. TSD at 8;

see

Exh. 1 at

2. The Agency claims that both USEPA and the Board have considered the costs and feasibility

of this monitoring and that both have found it to be reasonable and feasible. TSD at 9-10;

see

Exh. 1 at 2. The Agency argues that the

vacatur

of CAMR casts no doubt on these findings.

at 9;

see

Exh. 3 at 2-3.

On the issue of economic reasonableness, the Agency stresses that its proposal includes

provisions for monitoring alternatives in order to “provide a greater degree of flexibility and

potentially lower costs in mercury monitoring.” TSD at 10;

see

Exh. 1 at 3, Prop. at 49-56

(proposed new Section 225.239). The Agency claims that its proposed alternative is an

additional option for demonstrating compliance, and that “it is considered to be an economically

reasonable addition to the Illinois mercury rule without consideration of specific cost estimates

for emissions testing.” TSD at 13. Nonetheless, the Agency estimates that this alternative

testing would result in average costs of approximately $50,000 per test.

see

Exh. 3 at 3. The

Agency also stresses that, “through discussion with vendors of mercury monitoring systems and

USEPA, [] the great majority of coal-fired EGUs originally affected by CAMR have already

purchased monitoring systems complaint with Part 75 requirements.” TSD at 10.

On the issue of technical feasibility, the Agency argues that it proposes three approved

test methods for demonstrating compliance with emissions standards. TSD at 12, Exh. 1 at 3-4.

The Agency emphasizes that these “methods were approved by USEPA for initial certification

and relative accuracy test audits (“RATA”) of Part 75 monitoring equipment.

On the basis of its review of the record, the Board finds that the Agency’s revised

proposal, as amended by Ameren’s proposed language for Section 225.233, is both technically

feasible and economically reasonable. Accordingly, in its order below, the Board will direct the

Clerk to file the proposal with the Joint Committee on Administrative Rules for second-notice

review.

The Board proceeds below with its section-by-section discussion of the proposal.

Subpart A: General Provisions

Section 225.120: Abbreviations and Acronyms

Section 225.120 provides abbreviations and acronyms used in Part 225. 35 Ill. Adm.

Code 225.120. In its original proposal, the Agency sought to include “additional abbreviations

and acronyms used in Part 225, as well as abbreviations and acronyms used in the new Appendix

B to Part 225.” Statement at 16;

see

Prop. at 4-5. In its second

errata

sheet, the Agency sought

to amend its proposal by adding to this section the acronym “QAMO,” or “quality-assured

monitor operating.”

Errata

2 at 1. The Agency states that this addition stems “from a change to

the monitoring calculation provisions.”

see id

. at 5-9 (amending calculations in Section

225.230). Also in its second

errata

sheet, the Agency proposes under the acronym “QC” to

change the reference from “quality certification” to “quality control,” which the Agency

describes as “the proper term.”

. at 1.

Section 225.130: Definitions

Section 225.130 provides definitions applicable for the purposes of Part 225. 35 Ill.

Adm. Code 225.130. In its original proposal, the Agency sought to amend the definition of

“designated representative” and add definitions for terms appearing in Appendix B to Part 225.

Statement at 16;

see

Prop. at 5-13. In its second

errata

sheet, the Agency amended its proposal

in a number of ways. First, the Agency responded to questions at the first hearing by changing

the definition of “designated representative” in order “to account for the separation of the Illinois

Mercury Rule and the federal Clean Air Interstate Rule” and “to remove any confusion about the

need to refer to federal programs when implementing the Illinois Mercury Rule.”

Errata

2 at 1-

2. Second, the Agency added a definition of “Sorbent Trap Monitoring System” that it had

inadvertently omitted from the original proposal.

. at 1, 3. Third, the Agency amended the

definition of “NIST traceable elemental mercury standards” to respond to USEPA’s comment

that “interim versions of the mercury generator protocols will be issued in early 2009 and are

acceptable until final protocols are issued.”

. at 1-2. Fourth, the Agency proposed “for clarity”

to add to this section a definition of “excepted monitoring system.”

. at 2.

In its third

errata

sheet, the Agency proposed two additional amendments to this section.

First, the Agency proposed to correct punctuation errors in the definition of “NIST traceable

elemental mercury standards” and “NIST traceable source of oxidized mercury” in the second

2 at 2. Second, the Agency proposed to remove the

definition of “designated representative” “in response to industry comment that the term is not

necessary and would lead to confusion.”

Errata

3 at 2.

Section 225.140: Incorporations by Reference

Section 225.140 provides various materials incorporated by reference. 35 Ill. Adm. Code

225.140. In its original proposal, the Agency sought “to remove various Sections of 40 C.F.R 60

and 40 C.F.R. 75 that were vacated by the Court and to add specific Sections of 40 C.F.R. 75 that

were unaffected by the

see

et al

Protection Agency, 517 F.3d 574 (D.C. Cir. 2008), Prop. at 13-15. The Agency’s original

proposal also seeks “to add several additional ASTM [American Society for Testing and

Materials] standards as well and incorporate definitions from 40 C.F.R 72.2.” Statement at 16;

see

Prop. at 14.

In its second

errata

sheet, the Agency proposed additional amendments. First,

responding to USEPA and to provide greater clarity, the Agency sought to cite more accurately

to the provision of the Code of Federal Regulations.

Errata

2 at 3. Second, the Agency seeks to

amend its proposal by incorporating 40 C.F.R. 75, as it proposes to add two references to Part 75.

see id.

at 37-46 (proposing amendment to Section 225.290). Third, the Agency proposes to

add an incorporation of ASTM D6722-01, Standard Test Method for Total Mercury in Coal and

Coal Combustion Residues by Direct Combustion Analysis (2001).

Id.

at 3-4. Midwest

Generation has urged the board to adopt this proposed incorporation. MG Comment at 5.

Subpart B: Control of Mercury Emissions from Coal-Fired Electric Generating Units

Section 225.202: Measurement Methods

Section 225.202 provides methods for measuring mercury under Part 225. 35 Ill. Adm.

Code 225.202. In its original proposal, the Agency sought to replace references to the vacated

40 C.F.R. 75 “with references to the newly created Appendix B to Part 225.” Statement at 16-

17;

see

Prop. at 16-17. The Agency also proposed language allowing sources to submit

alternative monitoring plans to the Agency for approval. Statement at 17;

see

Prop. at 16.

Finally, the Agency also sought to add a citation to Appendix A of 40 C.F.R. 60 regarding

emissions testing. Statement at 17;

see

Prop. at 17 (proposing new subsection 225.202(g)).

In its second

errata

sheet, the Agency proposed additional amendments to this section.

First, the Agency seeks to include as an allowable test method for determining mercury content

of coal ASTM D6722-01, Standard Test Method for Total Mercury in Coal and Coal

Combustion Residues by Direct Combustion Analysis (2001), which the Agency has proposed to

incorporate by reference.

Errata 2

at 4-5 (proposed new subsection 225.202(f))

; see id.

at 3-4.

The Agency also proposes to expand the citation to 40 C.F.R. 60 in order “to specify the proper

test methods.”

. at 5 (listing Methods 29, 30A, and 30B in Appendix A-8).

Section 225.210: Compliance Requirements

Section 225.210 specifies various compliance requirements for EGUs subject to Subpart

B. 35 Ill. Adm. Code 225.210. In its original proposal, the Agency sought to create “an

alternative monitoring scheme and method of determining compliance based on periodic

emissions testing and provides a mechanism for sources to submit alternative monitoring plans to

the Agency for approval.” Statement at 17;

see

Prop. at 18-19. The proposal also requires

recordkeeping and reporting of periodic emissions testing. Statement at 17;

see

Prop. at 19.

In post-hearing comments filed on January 14, 2009, the Agency noted that, in response

to a question during the first hearing, it had “agreed to identify the rule provisions that allow

submission of alternative mercury monitoring plans.” PC 1 at 1 (¶3);

see

Tr.1 at 18. The

Agency identifies these provisions as Sections 225.210(b)(1) and (b)(2). PC 1 at 1;

see

Prop. at

18.

Section 225.220: Clean Air Act Permit Program (CAAPP) Permit Requirements

Section 225.220 provides CAAPP permit requirements for sources with one or more

EGUs subject to Subpart B. 35 Ill. Adm. Code 225.220. In its original proposal, the Agency had

proposed to amend this language only by requiring “that CAAPP permit applicants describe their

intended approach to the emissions testing requirements” if relying upon alternative testing under

the proposed Section 225.239. Statement at 17;

see

Prop. at 20.

In post-hearing comments filed on January 14, 2009, the Agency noted that, in response

to a question during the first hearing, it had “agreed to consider deferring the December 31, 2008

date in Section 225.220(a)(2)(A). as the current rulemaking will not be completed by that date.”

PC 1 at 1 (¶2);

see

35 Ill. Adm. Code 225.220(a)(2)(A), Tr.1 at 5. In its post-hearing comment,

the Agency expresses the belief “that the date in the current proposal is appropriate. All of the

subject sources have already submitted their initial permit applications and thus no revision is

necessary.” PC 1 at 1.

Section 225.230: Emission Standards for EGUs at Existing Sources

Section 225.230 establishes emissions standards for EGUs at existing sources. 35 Ill.

Adm. Code 225.230. In its original proposal, the Agency seeks to add language to Section

225.230(a)(1) establishing that alternatives under Sections 225.230(b), 225.230(d), and 225.232

through 225.234 are exceptions to the general mercury emission standard. Statement at 17;

see

Prop. at 20-21. The proposal also provides additional alternatives under Section 225.239 and

225.291 through 225.299. Statement at 17;

see

Prop. at 20-21. Also, in language addressing

EGUs that are served by a single stack, the Agency seeks to replace references to 40 C.F.R. 75

with references to the newly created Appendix B to Part 225. Statement at 17,

see

Prop. at 23.

In its second

errata

sheet, the Agency proposes amendments responding to comments by

the USEPA and relating to the elimination of data substitution procedures.

Errata

2 at 5-9. The

Agency states that,

[b]ecause EGUs could potentially have monitor downtime of up to 25% during a

given quarter, allowable emissions must be based upon emissions that are

recorded during quality-assured monitor operating (“QAMO”) hours. Sources

recording emissions for less than 100% of operating hours cannot calculate an

emission rate or control efficiency based on only the emissions recorded during

monitor up time while averaging emissions over 100% of operating hours.

Emission rates and control efficiencies will be calculated using emissions from

QAMO hours and an average of mercury input or electrical output for a given

month based upon the uptime of the monitor system recording emissions.

. at 5.

In its third

errata

sheet, the Agency proposes to amend Section 225.230(a)(1) to clarify that

Section 225.235, addressing units scheduled for permanent shutdown, is also an exception to the

general mercury emission standard.

Errata

3 at 2-3.

Section 225.232: Averaging Demonstrations for Existing Sources

Section 225.232 provides for averaging demonstrations on the part of existing sources.

35 Ill. Adm. Code 225.232. In its second

errata

sheet, the Agency proposed to amend

subsection (a) to remove the word “actual,” which was necessitated by changes to emissions

calculations in Section 225.230.

Errata

2 at 9-10;

see id

. at 5-9 (amending Section 225.230).

Section 225.233: Multi-Pollutant Standards

Section 225.233 provides the multi-pollutant standards as an alternative to compliance

with the emissions standards of Section 225.230(a). 35 Ill. Adm. Code 225.233;

see

35 Ill. Adm.

Code 225.230(a), TSD at 14. In its original proposal, the Agency first sought to “add a sorbent

to the list of approved sorbents for the injection of halogenated activated carbon.” Statement at

18;

see

Prop. at 28, Exh. 6 at 3, Exh. 7 at 5 (Approved Sorbents). The Agency also sought to

provide that, “as an alternative to the CEMS monitoring, recordkeeping, and reporting

requirements in Section 225.240 through 225.290, the owner or operator of an EGU may elect to

comply with the applicable emissions testing, monitoring, recordkeeping, and reporting

requirements in Section 225.239.” Statement at 18;

see

Prop. at 31, Exh. 6 at 2-3. In addition,

the Agency sought to provide that, as an alternative to demonstrating compliance with the

subsection (d) emissions standards, “the owner or operator of an EGU may elect to comply with

the applicable emissions testing requirements in Section 225.239.” Statement at 18;

see

Prop. at

32, TSD at 14. Finally, the Agency’s original proposal also “replaced references to the CAIR

trading program with references to any trading program due to the recent

vacatur

of CAIR.

Statement at 18, TSD at 4;

see

Prop. at 34.

In its first

errata

sheet, the Agency proposed to amend subsection (c)(2)(B)to add Calgon

Carbon’s FLUEPAC CF Plus to the list of sorbents that meet criteria for use under Part 225.

Errata

1 at 2. The Agency argues that “[t]his will add even greater flexibility for sources

seeking to comply with the rule.”

In its comments filed after the first hearing and responding to questions raised there, the

Agency identified subsection (d)(4) as a provision limiting “a source’s ability to switch” between

CEMS and the emissions testing alternative. PC 1 at 1;

see

Tr.1 at 27-28.

Also in those comments, the Agency noted that it had “agreed to consider amending the

date in Section 225.233(f)(5) in light of the dates in Section 225.233(f)(1) and (f)(2).” PC 1 at 2,

citing Tr.1 at 92. The Agency characterizes the date as “appropriate.” PC 1 at 2. The Agency

states that

[b]ecause CAIR allowances are allocated several years in advance, such that

sources can trade them before the date on the allowance, even though the rule

does not restrict trading until ‘vintage years 2012 and beyond,’ the source will

have those allowances in their accounts probably by 2009 and almost certainly by

2010. Allowances for 2012 and beyond do not need to be retired until those

years, and sources will not necessarily be able to determine which allowances are

available due to over compliance until that year has actually passed.

The Agency stresses that the report required by subsection (f)(5) requests information including

“‘identification of any allowances that were sold, gifted, used, exchanged, or traded because they

became available due to over-compliance,’ and it is possible that sources may be able to make a

determination of such actions ahead of time.”

. The Agency argues that, “[s]ince the report

only covers the previous calendar year, the Agency would not be provided with the necessary

information in cases when trading occurred in 2010 or 2011.”

. The Agency therefore claims

that “it is necessary to have sources begin submitting reports in 2021, as currently required in the

rule.”

Also in those comments filed after the first hearing, the Agency noted that it “had agreed

to consider changing the date in Section 225.233(f)(5) to May 1.” PC 1 at 5, citing Tr.1 at 190.

The Agency declined to propose such a change, stating that “[t]he information required under

subsection (f)(5) is different from other information that sources are required to submit to the

Agency, such as information submitted in Title V annual compliance certifications.” PC 1 at 5.

The Agency concludes that “[t]here is therefore no overlap and no need for a revision.”

Also in those comments filed after the first hearing, the Agency noted that it had “agreed

to address whether Section 225.233(d)(4) accomplishes the same purpose as Section

225.233(c)(6).” PC a at 2, citing Tr.1 at 91. The Agency responds that “[t]he subsections do not

accomplish the same purpose. Section 225.233(c)(6) addresses monitoring, while Section

225.233(d)(4) addresses compliance with emission limits.” PC at 2. In its second

errata

sheet,

however the Agency proposed to amend subsection (c)(6) “to clarify the ability to use an

excepted monitoring system and clarify that the sunset date of June 30, 2012 applies.”

Errata

at 10 (stating that language inadvertently omitted from original proposal). The Agency also

proposed in the second

errata

sheet to amend subsection (d)(4) “to provide the proper citation to

emission testing in Section 225.239.”

The Agency proposed additional changes in its second

errata

sheet. First, the Agency

responded to a request at the first hearing by proposing to amend subsection (d)(3) “to clarify

that EGUs in the MPS may utilize the averaging provisions set forth in Section 225.232 until

December 31, 2013.”

Errata

2 at 10. Second, the Agency proposed to amend subsection (f)(4)

in order to make it “consistent with the terms and conditions agreed to by the affected sources in

their multi-pollutant reduction agreements with the Agency regarding the treatment of NO

and

allowances.”

. The Agency states that this revision stems from uncertainty regarding the

federal CAIR and the expectation that a new or modified version of it is forthcoming from

USEPA.

In his testimony on behalf of Dynegy pre-field for the Second hearing, Mr. Diericx

acknowledges that the Agency intended “to amend the methodology for correction of the flue gas

temperature so that if there is a difference between the temperature of the stack and the

temperature at the point of sorbent injection, it will not increase her pounds of sorbent required

to be injected on an hourly basis.’ Exh. 14 at 6. He states that Dynegy supports amending the

Agency’s proposal in a manner consistent with language he offers for subsection (c)(2)(D).

at 6-7.

In its third

errata

sheet, the Agency proposed to amend Section 225.233(c)(2)(D) to

reflect new information indicating that some sources “with particulate control devices

downstream of the air preheater may inject activated carbon upstream of the air preheater.”

Errata

3 at 3. The Agency states that

[t]his injection point was not contemplated during the original determination of

the required injection rates for units opting into the MPS and CPS. It also brings

to light a need to revise the rule so as to avoid an incentive to inject at a point in

the ductwork that may not be the most desirable. This is because determination of

the flow rate at the point of injection creates an incentive to inject where the flow

rate is low (

e.g.

, near the back end of the ductwork close to the stack), thereby

potentially making the injection point location decision based on factors other

than the ability to best control mercury emissions.

The Agency also expresses the belief that “measurement of gas flow rate at the point of injection

is likely less reliable in comparison to gas flow rte measurement at the stack due to there

typically being a higher level of operating experience, quality control, and quality assurance of

stack gas flow meters.”

Errata

3 at 3, 11. The Agency states that “[t]he requirement for gas

flow rate to be obtained from stack gas flow meters, which are operated under the Acid Rain

Program, will also result in a standardized point of gas flow measurement rather than such

measurements being taken at variable points in the gas flow configuration.”

The Agency explains its proposed revision of Section 225.233(c)(2)(D) as requiring

“determination of the gas flow rate at the stack except in the case of units

equipped with activated carbon injection prior to a hot-side electrostatic

precipitator. For these units, the gas flow rate will still be determined at the inlet

to the hot-side electrostatic precipitator. For this purpose, the gas flow rate would

actually be measured at the stack, however, the stack gas flow rate will be

adjusted for the differences in temperature in the stack and at the inlet to the hot-

side electrostatic precipitator. This adjustment is required since the Agency was

aware in its original determination of the required injection rates that units

equipped with hot-side electrostatic precipitators would be injecting activated

carbon prior to the hot-side electrostatic precipitator and it was recognized that

such units would typically get lower mercury control than those with more

common configurations (

e.g.

cold-side electrostatic precipitators).

Errata

3 at 3-

The Agency states that it recognizes “that some units with hot-side electrostatic precipitators

may be equipped with secondary particulate control devices downstream of the hot-side

electrostatic precipitator and will inject activated carbon downstream of the hot-side electrostatic

precipitator.”

. at 4. The Agency further states that “[s]uch units will be treated like other

units and will not be required to adjust the gas flow rate for temperature differences but will

simply measure the gas flow rate at the stack.”

In its post-hearing comments, Dynegy notes that the Agency has removed the

temperature correction factor “from Section 225.233(c)(2)(D) for all units except those equipped

with sorbent injection prior to a hot-side electrostatic precipitator.” Dynegy Comment at 3.

Dynegy argues that this removal necessitates a corresponding change in Section

225.233(c)(5)(B) and proposes language for that subsection.

. at 3-4. Although the Agency in

its post-hearing comments agrees that “changes need to be made,” the Agency proposes

alternative language “to address the totality of changes previously made.” Agency Comment at

14-15. In its response to the Agency’s post-hearing comments, Dynegy states that the Agency’s

proposal “is acceptable.” Dynegy Resp. at 2.

Finally, the Board above summarized Ameren’s proposal to amend the MPS by adding a

Section 225.233(e)(3) changing SO

and NO

emission rates under the MPS for specified years.

See supra

at 12-16;

see generally

Exh. 15, Exh. 16, Ameren Comment, Tr.2 at 81-94. On the

basis of its review of the record, particularly the projected environmental benefit and the absence

of any objection on the part of the Agency, the Board finds that the proposal by Ameren is

technically feasible and economically reasonable and includes Ameren’s proposed language in

its order below.

Section 225.234: Temporary Technology-Based Standard for EGUs at Existing Sources

Section 225.234 provides a temporary technology-based standard (TTBS) for EGUs at

existing sources. 35 Ill. Adm. Code 225.234. In its original proposal, the Agency sought to

provide that, “as an alternative to the CEMS monitoring, recordkeeping, and reporting

requirements in Section 225.240 through 225.290, the owner or operator of an EGU may elect to

comply with the applicable emissions testing, monitoring, recordkeeping, and reporting

requirements in Section 225.239.” Statement at 18;

see

Prop. at 35-41.

In its first

errata

sheet, the Agency reported that it “has learned of a new sorbent that

meets the criteria for use in the Illinois Mercury Rule.”

Errata

1 at 3. Accordingly, the Agency

seeks to amend its proposal by adding Calgon Carbon’s FLUEPAC CF Plus to the list of

acceptable sorbents.

see

Prop. at 36, Exh. 7 at 5 (amended pre-filed testimony of Jim Ross);

see also Errata

4 at 8-9 (restating listing of sorbent). The Agency argues that “[t]his will add

even greater flexibility for sources seeking to comply with the rule.”

sheet, the Agency notes that it was asked during the first hearing to

“clarify whether references to ‘CEMS’ include sorbent trap monitoring systems as well.”

Errata

2 at 14 (¶8);

see

Tr.1 at 96, 172-74. Accordingly, the Agency proposes to amend Section

225.234(a)(4) to include a reference to excepted monitoring systems.

Errata

2 at 14. The

Agency also proposes to amend Section 225.234(b)(3)(B) to remove an unnecessary word

inadvertently left in the original proposal.

In its third

errata

sheet, the Agency proposes to amend Section 225.234(b)(2).

Errata

at 5. The Agency states that it proposes this amendment for the same reason it proposed

amending Section 225.233(c)(2)(D).

. The Agency proposed amending that section in order to

address the issue of determining the flue gas flow rate, as described in the preceding subsection

of this opinion.

See id

. at 3-5.

Section 225.235: Units Scheduled for Permanent Shut Down

Section 225.235 addresses EGUs that will be permanently shut down. 35 Ill. Adm. Code

225.235. In its original proposal, the Agency sought to provide “that an EGU that has completed

the requirements of subsection (a) of this Section, or is scheduled for permanent shut down

pursuant to Section 225.294(b), be exempt from the monitoring and testing requirements in

Section 225.239 and 225.240.” Statement at 18;

see

Prop. at 43.

Section 225.237: Emission Standards for New Sources with EGUs

Section 225.237 provides mercury emission standards for new sources with EGUs. 35

Ill. Adm. Code 225.237. In its original proposal, the Agency sought to “establish as exceptions

to the general mercury emission standard under Section 225.237(a)(1) the alternatives provided

in Sections 225.238 and 225.239.” Statement at 18-19;

see

Prop. at 43. The Agency also

proposed to correct a reference to the Code of Federal Regulations in order to reflect that a cited

provision had been vacated. Statement at 19;

see

Prop. at 43.

In its second

errata

sheet, the Agency notes that it was asked during the first hearing to

“clarify whether references to ‘CEMS’ include sorbent trap monitoring systems as well.”

Errata

2 at 14 (¶9);

see

Tr.1 at 96, 172-74. Accordingly, the Agency proposes to amend Section

225.237(b) to include a reference to excepted monitoring systems.

Errata

2 at 14-15.

Section 225.238: Temporary Technology-Based Standard for New Sources with EGUs

Section 225.238 provides a temporary technology-based standard (TTBS) for new

sources with eligible EGUs. 35 Ill. Adm. Code 225.238. In its original proposal, the Agency

sought to provide that, “as an alternative to the CEMS monitoring, recordkeeping, and reporting

requirements in Section 225.240 through 225.290, the owner or operator of an EGU using the

TTBS may elect to comply with the emissions testing, monitoring, recordkeeping, and reporting

requirements in Section 225.239.” Statement at 19;

see

Prop. at 43-49.

In its first

errata

sheet, the Agency reported that it “has learned of a new sorbent that

meets the criteria for use in the Illinois Mercury Rule.”

Errata

1 at 3. Accordingly, the Agency

seeks to amend its proposal by adding Calgon Carbon’s FLUEPAC CF Plus to the list of

acceptable sorbents.

see

Prop. at 36, Exh. 7 at 5 (amended pre-filed testimony of Jim Ross);

see also Errata

4 at 8-9 (restating listing of sorbent). The Agency argues that “[t]his will add

even greater flexibility for sources seeking to comply with the rule.”

sheet, the Agency notes that it was asked during the first hearing to

“clarify whether references to ‘CEMS’ include sorbent trap monitoring systems as well.”

Errata

2 at 15 (¶10);

see

Tr.1 at 96, 172-74. Accordingly, the Agency proposes to amend Section

225.238(a)(4) to include a reference to excepted monitoring systems.

sheet, the Agency proposes to amend Section 225.238(b)(2).

Errata

at 6. The Agency states that it proposes this amendment for the same reason it proposed to

amend Section 225.233(c)(2)(D).

. The Agency proposed amending that section in order to

address the issue of determining the flue gas flow rate, as described in the summary of Section

225.233 above.

See id

. at 3-5.

Section 225.239: Periodic Emissions Testing Alternative Requirements

The Agency states in its original proposal that it generally seeks to create an emissions

testing alternative to CEMS available until June 30, 2012. Statement at 19;

see

Prop. at 49-56.

The Agency anticipates that USEPA will adopt mercury monitoring provisions during this three-

year period and that the Agency will either adopt or allow the use of those provisions to

demonstrate compliance with the Board’s regulations. Agency Comment at 3. The Agency

argues that this “[s]tack testing provides a measure of flexibility and certainty for sources in

demonstrating compliance and therefore is being proposed as a temporary means to demonstrate

compliance during this time of uncertainty.”

. The Agency claims that it has broad knowledge

of and experience with stack testing.

; TSD at 3, 11; Exh. 7 at 4. The Agency argues that the

alternative “is a technically feasible method for the measurement of mercury emissions, and in

many cases may be a lower cost option for mercury measurement than CEMS,” indicating its

economic reasonableness. TSD at 3;

see id

. at 11, 13.

Citing numerous problems it had experienced in operating CEMS, Midwest Generation

stated in its post-hearing comment that it “supports the Agency’s proposal to add Section

225.239” and encouraged the Board to adopt it. MG Comment at 3, citing Exh. 12 at 14 (Miller

pre-filed testimony). Midwest Generation further states that it is likely to rely on the stack

testing alternative while operating CEMS in parallel in order to try to improve CEMS’

availability. MG Comment at 3, citing Tr.2 at 75.

Before addressing this proposed alternative below on a subsection-by-subsection basis,

the Board first notes that, in his prefiled testimony on behalf of Kincaid, Mr. Nuckols expressed

support for this stack testing alternative to CEMS but urged adoption of the option on a

permanent basis. Exh. 10 at 17. Mr. Nuckols also stated that, if the option is not made a

permanent one, Kincaid had provided justification for extending it to 2015 or a later year.

see

Tr.2 at 38. The Agency in its post-hearing comment responded specifically to this position

by noting that only Kincaid had proposed making the stack testing alternative permanent.

Agency Comment at 11. The Agency argued that the alternative allows sources three years to

overcome technical problems with CEMS and for CEMS technology to mature.

Furthermore, the Agency states that it “anticipates that during the three-year window in which

stack testing is allowed as an alternative, new federal regulations will prescribe monitoring

provisions for mercury emissions and the Illinois EPA will either adopt or otherwise allow the

use of those provisions to demonstrate compliance with the Illinois mercury rule going forward.”

. at 11-12. Based on its review of the record and particularly on the expectation of new federal

monitoring provisions, the Board today declines to extend the availability of the stack testing

option beyond the June 30, 2012, date proposed by the Agency and will reflect that deadline

below in its order.

Subsection (a): General.

In its original proposal, the Agency states that it seeks to

create “a new alternative emissions testing requirement to CEMS based on quarterly emissions

testing, which may be used until June 30, 2012.” Statement at 19;

see

Prop. at 49 (proposed new

Sections 225.239(a)(1), (a)(3)). The Agency’s proposed language also establishes recordkeeping

and reporting requirements for sources opting to demonstrate compliance through this emissions

testing alternative. Statement at 19;

see

Prop. at 49 (proposed new Section 225.239(a)(3)); Exh.

6 at 2 (amended pre-filed testimony of David Bloomberg).

The Agency also proposes that, “[i]f an owner or operator of an EGU demonstrating

compliance pursuant to Section 225.230 or 225.237 discontinues use of CEMS before collecting

a full 12 months of CEMS data and elects to demonstrate compliance pursuant to this Section,

the data collected prior to that point must be averaged to determine compliance for such period.”

Statement at 19;

see

Prop. at 49 (proposed new Section 225.239(a)(4)). In its comments filed

after the first hearing and responding to questions raised there, the Agency identified this

subsection as a provision limiting “a source’s ability to switch” between CEMS and the

emissions testing alternative. PC 1 at 1;

see

Tr.1 at 27-28.

In its second

errata

sheet, the Agency responded to a request for clarification at the first

hearing by proposing to specify that subsection (a)(4) “applies to EGUs in the MPS and CPS.”

Errata

2 at 15, 17.

Finally, in its second

errata

sheet, the Agency notes that it was asked during the first

hearing to “clarify whether references to ‘CEMS’ include sorbent trap monitoring systems as

well.”

Errata

2 at 15 (¶11);

see

Tr.1 at 96, 172-74. Accordingly, the Agency proposes to amend

subsections (a)(1), (a)(3), and (a)(4) to include references to “an excepted monitoring system”.

Errata

2 at 15-17.

Subsection (b): Emission Limits.

In its original proposal, the Agency stated that it

seeks to require that existing units must begin complying, as determined through quarterly

emissions testing, in the calendar quarter beginning July 1, 2009. Statement at 19;

see

Prop. at

49-50 (proposed new Section 225.239(b)(1)). The Agency also sought to require that new units

must comply, as determined through quarterly emissions testing, within the first 2,160 hours

after commencing commercial operations. Statement at 19;

see

Prop. at 50 (proposed new

Section 225.239(b)(2)).

Subsection (c): Initial Emissions Testing Requirements for New Units.

In its original

proposal, the Agency proposed language requiring that “[t]he owner or operator of an EGU that

commences commercial operation after June 30, 2009, must also conduct an initial performance

test within the first 2,160 hours after the commencement of commercial operations.” Statement

at 19;

see

Prop. at 50 (proposed new Section 225.239(c)).

Subsection (d): Emissions Testing Requirements.

In its original proposal, the Agency

proposed language providing that “[s]ources are required to perform quarterly emissions testing,

except those in the MPS or CPS, which must perform semi-annual emissions testing.” Statement

at 19;

see

Prop at 50 (proposed Sections 225.239(d)(1), (d)(2)). In its second

errata

sheet, the

Agency proposed to amend to amend Section 225.239(d)(2) “to specify that EGUs in the MPS

and CPS that opt into either the 0.0080 lb mercury/GWh gross electric output emission limit or

90% control efficiency requirement early are excepted from performing emissions testing on a

semi-annual calendar basis, and instead must perform such testing on a quarterly basis.”

Errata

2 at 15, 18.

In subsection (d)(3), the Agency originally proposed that “[e]missions tests which

demonstrate compliance must be performed at least 45 days apart.” Statement at 20;

see

Prop.

at 50 (proposed Section 225.239(d)(3)). The Agency also sought to provide that,

if an emissions test fails to demonstrate compliance or the emissions test is being

performed subsequent to a significant change in the operations of an EGU under

subsection (h)(2) of this Section, the owner or operator of an EGU may perform

additional emissions test(s) using the same test protocol submitted in the same

period, with less than 45 days between tests. Statement at 20;

see

Prop. at 50

(proposed Section 225.239(d)(3)).

In subsection (d)(4), the Agency originally proposed that “[e]missions test must consist

of a minimum of three and a maximum of nine emissions test runs, lasting at least one hour each,

and averaged to determine compliance.” Statement at 20;

see

Prop. at 51 (proposed Section

225.239(d)(4)). The Agency also seeks to provide that “[a]ll test runs performed must be

reported.” Statement at 20;

see

Prop. at 51.

In subsection (d)(5), the Agency originally proposed that,

[i]f an EGU shares a common stack with one or more other EGUs, the owner or

operator of the EGU must conduct emissions testing in the duct to the common

stack from each unit, unless the owner or operator of the EGU considers the

combined emissions measured at the common stack as the mass mercury

emissions for the EGUs for recordkeeping and compliance purposes. Statement at

20;

see

Prop. at 51 (proposed Section 225.239(d)(5)).

In subsection (d)(6), the Agency originally proposed that, “[i]f an owner or operator of an

EGU demonstrating compliance pursuant to this Section later elects to demonstrate compliance

pursuant to the CEMS monitoring provisions in Section 225.230 of this Subpart, the owner or

operator must comply with the emissions monitoring deadlines in Section 225.240(b)(4).”

Statement at 20;

see

Prop. at 51 (proposed Section 225.239(d)(6)). In its comments filed after

the first hearing and responding to questions raised there, the Agency identified this subsection

as a provision limiting “a source’s ability to switch” between CEMS and the emissions testing

alternative. PC 1 at 1;

see

Tr.1 at 27-28. Also, in its second

errata

sheet, the Agency notes that

it was asked during the first hearing to “clarify whether references to ‘CEMS’ include sorbent

trap monitoring systems as well.”

Errata

2 at 15 (¶11);

see

Tr.1 at 96, 172-74. Accordingly, the

Agency proposes to amend subsection (d)(6) to include a reference to “excepted monitoring

system provisions”.

Errata

2 at 15, 18.

Subsection (e): Emissions Testing Procedures.

In its original proposal, the Agency

sought to provide that “[o]wners and operators are required to conduct a compliance test in

accordance with Method 29, 30A, or 30B of 40 C.F.R. 60, Appendix A.” Statement at 20;

see

Prop. at 51 (proposed Section 225.239(e)(1). In his pre-field testimony on behalf of the Agency,

Mr. Mattison stated that these methods “were approved by USEPA for initial certification and

relative accuracy test audits (“RATA”) of Part 75 monitoring equipment, and are considered to

be accurate methods for the measurement of mercury from coal-fired EGU stacks.” Exh. 1 at 3.

Specifically, Mr. Mattison stated that Method 29 determines emissions of various elements and

“has been an approved method for measuring metal emissions from stationary sources since

1996.”

Id.

at 4;

see

40 C.F.R. 60, Appendix A. Mr. Mattison further stated that USEPA

approved alternative Methods 30A and 30 B in 2007 for the measurement of mercury emissions

from stationary sources. Exh. 1 at 4;

see

40 C.F.R. 60, Appendix A-8. Mr. Mattison

characterizes Methods 30A and 30B, compared to the wet chemistry methodology of Method 29,

as “a lot simpler to use.” Tr.1 at 200-01.

In subsection (e)(2), the Agency originally proposed that “[m]ercury emissions or control

efficiency must be measured while the affected unit is operating at or above 90% of peak load.”

Statement at 20;

see

Prop. at 51 (proposed new Section 225.239(e)(2)).

In subsection (e)(3), the Agency originally proposed that, “[f]or units complying with the

control efficiency standard of subsection (b)(1)(B) or (b)(2)(B) of this Section, the owner or

operator must perform coal sampling in accordance with Section 225.265 at least once during

each day of emissions testing and monthly coal sampling at all other times.” Statement at 21;

see

Prop. at 51 (proposed new Section 225.239(e)(3)). In its first

errata

sheet, the Agency stated that

“a comment from a regulated source suggested the addition of language to address situations

when a boiler has not operated over a given time period.´

Errata

1 at 1, 2. Accordingly, the

Agency proposed to amend its language by providing that monthly coal sampling is not required

when “the boiler did not operate or combust coal at all during that month.”

. at 2. Also, in its

second

errata

sheet, the Agency proposed an additional amendment to this subsection “to clarify

that EGUs in the MPS or CPS complying with the 90% control efficiency requirement and

electing to demonstrate compliance pursuant to the emissions testing requirements in Section

225.239 are included in the group that must perform coal sampling according to the schedule set

forth in subsection (e)(3).”

Errata

2 at 15, 19.

In subsection (e)(4), the Agency originally proposed that, “[f]or units complying with the

output-based emission standard of subsection (b)(1)(A) or (b)(2)(A) of this Section, the owner or

operator must monitor gross electrical output for the duration of the testing.” Statement at 21;

see

Prop. at 51 (proposed new Section 225.239(e)(4)).

In subsection (e)(5), the Agency originally proposed that “[t]he owner or operator of an

EGU may use an alternative emissions testing method if such alternative is submitted to the

Agency in writing and approved in writing by the Manager of the Bureau of Air’s Compliance

Section.” Statement at 21;

see

Prop. at 51 (proposed new Section 225.239(e)(5)).

Subsection (f): Notification Requirements.

In its original proposal, the Agency sought

to provide that “[t]he owner or operator of an EGU must submit a testing protocol to the Agency

at least 45 days prior to a schedule emissions test, except as provided in Section 225.239(h)(2) or

(h)(3).” Statement at 21;

see

Prop. at 52 (proposed new Section 225.239(f)(1). In subsection

(f)(2), the Agency originally proposed that “[n]otification of a scheduled emissions test must be

submitted to the Agency in writing, directed to the Manager of the Bureau of Air’s Compliance

Section, at least 30 days prior to the expected date of the emissions test.” Statement at 21;

see

Prop. at 52 (proposed new Section 225.239(f)(2)). The Agency also originally proposed that

“[n]otification of the actual date and expected time of testing must be submitted in writing,

directed to the Manager of the Bureau of Air’s Compliance Section, at least five working days

prior to the actual date of the test.” Statement at 21;

see

Prop. at 52 (proposed new Section

225.239(f)(3)). In subsection (f)(3), the Agency proposed that, “[i]f an emissions test performed

under the requirements of this Section fails to demonstrate compliance with the limits of

subsection (b) of this Section, the owner or operator of an EGU may perform a new emissions

test using the same test protocol previously submitted in the same period” by submitting

notification at least five working days prior to the actual date of the test. Statement at 21;

see

Prop. at 52 (proposed new Section 225.239(f)(3)).

In subsection (f)(4), the Agency originally proposed to require that, in addition to the

testing protocol required by subsection (f)(1),

[t]he owner or operator of an EGU that has elected to demonstrate compliance by

use of the emission standards of subsection (b) of this Section must submit a

Continuous Parameter Monitoring Plan to the Agency at least 45 days prior to a

scheduled emissions test. The Continuous Parameter Monitoring Plan must detail

how the EGU will continue to operate within the parameters enumerated in the

testing protocol and how those parameters will ensure compliance with the

appropriate mercury limit. Statement at 21-22;

see

Prop. at 52-52 (proposed new

Section 225.239(f)(4).

In pre-filed testimony on behalf of the Agency, Mr. Bloomberg elaborated that sources relying

upon the stack testing alternative “must operate the EGU and all associated relevant controls in a

manner similar to that under which the unit was tested and compliance was determined.” Exh. 6

at 2;

see

TSD at 12. Mr. Bloomberg further states that the Continuous Parameter Monitoring

Plan ensures such operation. Exh. 6 at 2. In its second

errata

sheet, the Agency proposed to

amend subsection (f)(4) “to specify that EGUs in the MPS or CPS that opt into either the 0.0080

lb/GWh emission limit or the 90% control efficiency requirement early and that elect to

demonstrate compliance pursuant to the emissions testing requirements in Section 225.239 must

submit a Continuous Parameter Monitoring Plan.”

Errata

2 at 16, 20-21.

Subsection (g): Compliance Determination.

In its original proposal, the Agency

sought to require that “[e]ach quarterly emissions test shall determine compliance with Subpart B

for that quarter.” Statement at 22;

see

Prop. at 53 (proposed new Section 225.239(g)(1)). The

Agency also originally proposed that,

[i]f emission testing conducted pursuant to this Section fails to demonstrate

compliance, the owner or operator of the EGU will be deemed to have been out of

compliance with this Subpart beginning on the day after the most recent emissions

test that demonstrated compliance or the last day of certified CEMS data

demonstrating compliance on a rolling 12-month basis, and the EGU will remain

out of compliance until a subsequent emissions test successfully demonstrates

compliance with the limits of this Section. Statement at 22;

see

Prop. at 53

(proposed new Section 225.239(g)(2)).

In its comments filed after the first hearing and responding to questions raised there, the Agency

identified this subsection as a provision limiting “a source’s ability to switch” between CEMS

and the emissions testing alternative. PC 1 at 1;

see

Tr.1 at 27-28. Also, in its second

errata

sheet, the Agency notes that it was asked during the first hearing to “clarify whether references

to ‘CEMS’ include sorbent trap monitoring systems as well.”

Errata

2 at 15 (¶11);

see

Tr.1 at

96, 172-74. Accordingly, the Agency proposes to amend subsection (g)(2) to include a reference

to “excepted monitoring system provisions”.

Errata

2 at 15, 21.

In his pre-filed testimony on behalf of Dynegy, Mr. Diericx states that “Dynegy generally

supports the Agency’s proposal to include the stack testing option at Section 225.239.” Exh. 14

at 4. Mr. Diericx argues, however, that the proposed language providing that noncompliance

shown by one stack test dates back to the most recent complaint stack test “is inconsistent with

general practice regarding reliance on stack testing to demonstrate compliance with a standard.”

. Dynegy “requests that the Board revise this section to provide that noncompliance is

prospective – from the noncompliant stack test to the next compliant stack test.”

. at 4-5.

In its third

errata

sheet, the Agency proposed amending this subsection in response to

industry comments “to provide that an unsuccessful sack test only indicates noncompliance

dating back to the beginning of the quarter, the last day of certified CEMS data (or certified data

from an excepted monitoring system) demonstrating compliance, or to the date on which a

significant change was made.”

Errata

3 at 6-7. The Agency states that “[t]he language is now

consistent with the Agency’s statements that a successful stack test determines compliance for an

entire quarter, and it also acknowledges that a significant change could be the event that triggers

noncompliance, so noncompliance should not be assumed to predate such a change.”

. at 6. In

his testimony at the second hearing, Mr. Diericx noted the language proposed in the third

errata

sheet by stating that it was “acceptable to Dynegy and resolves this issue.” Tr.2 at 79;

see

Comment at 8.

Subsection (h): Operation Requirements.

In its original proposal, the Agency sought

to require that “EGUs must continue to operate commensurate with the Continuous Parameter

Monitoring Plan until the next compliance demonstration.” Statement at 22;

see

Prop. at 53

(proposed Section 225.239(h)(1).

The Agency also proposes that, “[i]f the owner or operator makes a significant change to

the operations of an EGU subject to this Section, such as changing from bituminous to

subbituminous coal, the owner or operator must submit a testing protocol to the Agency with a

new Continuous Parameter Monitoring Plan and perform an emissions test within seven

operating days of the significant change.” Statement at 22;

see

Prop. at 53 (proposed Section

225.239(h)(2)). In its second

errata

sheet, the Agency responded to a request at the first hearing

that it “clarify what is meant by a ‘significant change.’”

Errata

2 at 16;

see

Tr.1 at 146-50. The

Agency proposed to amend this subsection to specify that any “change that would render the

most recent test no longer representative of current operations according to the parameters listed

in the Continuous Parameter Monitoring Plan” is a significant change.

Errata

2 at 16, 21. The

Agency also proposed in response to a request at the second

errata

sheet “to give sources

additional time to perform an emissions test following a significant change.”

Id.

at 16;

see id

. at

22, Tr.1 at 149.

In subsection (h)(3), the Agency proposed language providing that, if an EGU combusts a

blend of coal, then “the owner or operator of the EGU must ensure that the EGU continues to

operate using the same blend that was used during the most recent successful emissions test. If

the blend of coal changes, the owner or operator of the EGU must re-test in accordance with

subsections (d), (e), (f), and (g) of Section 225.239 within 30 days of the change in coal blend.”

Statement at 22;

see

Prop. at 54 (proposed new Section 225.239(h)(3)).

Subsection (i): Recordkeeping.

In its original proposal, the Agency sought to provide

that “[t]he owner or operator of an EGU and its designated representative must comply with all

applicable recordkeeping and reporting requirements in this Section.” Statement at 22;

see

Prop.

at 54 (proposed new Section 225.239(i)(1)). In its third

errata

sheet, the Agency proposed to

amend this subsection to reflect removal of the term “designated representative.”

Errata

3 at 7.

The Agency proposed generally to remove it “in response to industry comment that the term is

not necessary and would lead to confusion.”

. at 2.

The Agency also sought to provide in subsection (i)(2) that these recordkeeping and

reporting requirements include records substantiating “that the EGU is operating in compliance

with the parameters listed in the Continuous Parameter Monitoring Plan.” Statement at 22;

see

Prop. at 54 (proposed new Section 225.239(i)(2)). In its second

errata

sheet, the Agency

proposed to amend subsection (i)(2) “to require use of parts per million rather than pounds per

trillion BTUs when recording the daily mercury content of coal used.”

Errata

2 at 16, 22.

In subsection (i)(3), the Agency proposed that “EGUs using activated carbon injection

must also maintain records of the usage of sorbent, the exhaust gas flow rate from the EGU, and

the sorbent feed rate, in pounds per million actual cubic feet of exhaust gas at the injection point,

on a weekly average.” Statement at 23;

see

Prop. at 54 (proposed new Section 225.239(i)(3(A)).

The Agency also proposed that, “if a blend of coal is fired in the EU, the owner or operator of the

EGU must keep records of the amount of each type of coal burned and the required injection rate

for injection of activated carbon, on a weekly basis.” Statement at 23;

see

Prop. at 54 (proposed

new Section 225.239(i)(3)(B)).

In subsection (i)(4), the Agency originally proposed that “[t]he owner or operator of an

EGU must retain all records required by this Section at the source unless otherwise provided in

the CAAPP permit issued for the source and must make a copy of any record available to the

Agency upon request.” Statement at 23;

see

Prop. at 55 (proposed new Section 225.239(i)(4)).

In its second

errata

sheet, the Agency in response to a request at the first hearing proposed to

amend this subsection “to require that records be retained for five years.”

Errata

2 at 16, 23;

see

Tr.1 at 155-56.

In subsection (i)(5), the Agency proposed language providing that “[t]he owner or

operator of an EGU demonstrating compliance pursuant to this Section must monitor and report

the heat input rate at the unit level.” Prop. at 55 (proposed new Section 225.239(i)(5);

see

Statement at 23. Also, in subsection (i)(6), the Agency proposed that “[t]he owner or operator of

an EGU demonstrating compliance pursuant to the Section must perform and report coal

sampling in accordance with subsection 225.239(e)(3).” Prop. at 55 (proposed new Section

225.239(i)(6);

see

Statement at 23.

Subsection (j): Reporting Requirements.

In its original proposal, the Agency sought

to require that “[a]n owner or operator of an EGU shall submit to the Agency a Final Source Test

Report for each periodic emissions test within 45 days after the test is completed.” Statement at

23;

see

Prop. at 55 (proposed new Section 225.239(j)(1). The Agency proposes that this Final

Source Test Report will at a minimum include a summary of results; a description of test

method(s), including a description of sampling points, sampling train, analysis equipment, and

test schedule; and a detailed description of test conditions, including process information, control

equipment information, a discussion of any preparatory actions taken, and data and calculations.

Statement at 23;

see

Prop. at 55 (proposed new Section 225.239(j)(1)(B)(i-iv)).

In subsection (j)(2), the Agency proposes that “[t]he owner or operator of a source with

one or more EGUs demonstrating compliance with Subpart B in accordance with this Section

must submit to the Agency a Quarterly Certification of Compliance within 45 days following the

end of the calendar quarter covered by this certification.” Statement at 23;

see

Prop. at 55

(proposed new Section 225.239(j)(2)). The Agency also proposed that “[q]uarterly certification

of compliance must indicate whether compliance existed for each EGU for the previous calendar

quarter and it must certify to that effect.” Statement at 23-24;

see

Prop. at 55. In the event that

an EGU fails to comply during the quarter covered by the certification, the Agency seeks to

require that “the owner or operator must provide the reasons the EGU or EGUs failed to comply

and a full description of the noncompliance.” Statement at 24;

see

Prop. at 55-56. Also, the

Agency proposes that, for each EGU, the owner or operator must provide a list of all emissions

tests performed within the calendar quarter and any deviations or exceptions each month.

Statement at 24;

see

Prop. at 56. The Agency also proposed to require that all Quarterly

Certifications of Compliance required to be submitted must include a certification by a

responsible official. Statement at 24;

see

Prop. at 56.

In subsection (j)(3), the Agency proposed that “[f]or each EGU, the owner or operator

must promptly notify the Agency of deviations from requirements of this Subpart B.” Statement

at 24;

see

Prop. at 56 (proposed new Section 225.239(j)(3)). The Agency specifies that, “[a]t a

minimum, these notifications must include a description of such deviations within 30 days after

discovery of the deviations, and a discussion of the possible cause of such deviations, any

corrective actions, and any preventative measures taken.” Statement at 24;

see

Prop. at 56.

Section 225.240: General Monitoring and Reporting Requirements

Section 225.240 provides general monitoring and reporting requirements for the Board’s

mercury emissions regulations. 35 Ill. Adm. Code 225.240. In its original proposal, the Agency

first seeks to replace “citations to vacated sections of 40 C.F.R. 75 with equivalent citations to

the newly created Appendix B to Part 225.” Statement at 24;

see

Prop. at 56-60. The Agency

also seeks to change the emissions monitoring deadline from January 1, 2009, to July 1, 2009.

Statement at 24;

see

Prop. at 57, 58.

The Agency’s original proposal also provided that “owners or operators of EGUs that

originally elected to demonstrate compliance pursuant to the emissions testing requirements in

Section 225.239 must record, report, and quality-assure data from the CEMS by the first day of

the calendar quarter following the last emissions test demonstrating compliance with Section

225.239.” Statement at 24;

see

Prop. at 58 (proposed new Section 225.239(b)(4). In addition,

the Agency proposes to replace “citations to vacated portions of 40 C.F.R. 75 regarding reporting

data with citations to the newly created alternative reporting data requirements in Section

225.239.” Statement at 24;

see

Prop. at 58-60. Finally, the Agency also seeks to provide that the

Agency will approve alternative systems and methods instead of USEPA. Statement at 24;

see

Prop. at 59.

The Agency argues that USEPA researched and considered the economic reasonableness

and the technical feasibility of mercury monitoring methods before it promulgated CAMR and

that it determined that the Part 75 monitoring provisions were both reasonable and feasible.

See

TSD at 8. The Agency states that the federal court vacated CAMR on the basis of USEPA’s

regulatory approach and not because of the cost or feasibility of monitoring.

. at 8-9.

Consequently, the Agency seeks to reconstitute the CAMR monitoring provisions as

amendments to Part 225.

Id.

at 8. The Agency stresses that the Board already considered these

provisions in adopting Part 225 and found them to be reasonable and feasible.

Id.

at 8-9, citing

In the Matter of Proposed New 35 Ill. Adm. Code 225: Control of Emissions from Large

Combustion Sources (Mercury), R06-25, slip op. at 78 (Nov. 2, 2006). The Agency also claims,

on the basis of discussion with monitoring system vendors, “that the great majority of coal-fired

EGUs originally affected by CAMR have already purchased monitoring systems compliant with

Part 75 requirements in anticipation of the January 1, 2009 effective date of the now vacated

CAMR.” TSD at 10. The Agency adds that it has proposed in this proceeding both to extend the

monitoring deadline and to provide flexibility through the stack testing alterative at Section

225.239.

. at 10.

In comments filed January 14, 2009, after the first hearing and responding to questions

raised there, the Agency identified this Section 225.239(b)(4) as a provision limiting “a source’s

ability to switch” between CEMS and the emissions testing alternative. PC 1 at 1;

see

Tr.1 at 27-

28. In the same comments, the Agency noted that it had been asked to explain the relationship

between dates in Sections 225.240(b)(1) and (b)(3). PC 1 at 2;

see

Tr. 1 at 156-59. The Agency

responds that no relationship exists because the different dates “deal with two different topics.”

PC 1 at 2. The Agency explains that

Section 225.240(b)(1) covers the deadline date by which monitoring is required

for existing sources; (b)(3) deals with the monitoring date for sources that later

add on a control device. Thus, an existing source needs to begin monitoring with

a certified CEMS by July 1, 2009. . . . If the source then adds a control system

described in (b)(3), the modified CEMS has the lesser of 90 unit operating days

or 180 calendar days to re-certify the CEMS. PC 1 at 2-3.

In its second

errata

sheet, the Agency proposed to delete subsection (c)(2) on the basis

that it is redundant.

Errata

2 at 25, 27. The Agency also proposed to delete the title of

subsection (c), “as it does not accurately reflect the content of the subsection.”

. Also in its

second

errata

sheet, the Agency noted that it was asked during the first hearing to “clarify

whether references to ‘CEMS’ include sorbent trap monitoring systems as well.”

Errata

2 at 25

(¶12);

see

Tr.1 at 96, 172-74. Accordingly, the Agency proposes to amend subsections (d)(3)

and (d)(4) to include references to excepted monitoring systems”.

sheet, the Agency proposed additional changes to the originally-

proposed language. First, the Agency proposed amending Section 225.240(b)(3) “in response to

a request by Midwest Generation that the monitor date match the control installation date.”

Errata

3 at 7-8. Second, the Agency proposed striking the term “all” from Section 225.240(d)(2)

“because EGUs are not actually required to account for all

emissions (as a result of the removal

of data substitution requirements and the addition of the 75% monitor availability requirement,

for example).”

. at 8 (emphasis in original). Third, the Agency also proposed to amend

Section 225.240(d)(4)(B) “to reflect the removal of the term ‘designated representative.’”

. at

8-9. The third

errata

sheet proposed to remove the term “in response to industry comment that

the term is not necessary and would lead to confusion.”

. at 2. In its fourth

errata

sheet, the

Agency proposed a technical amendment to Section 225.240(a)(1).

Errata

4 at 1 (reinserting

parenthesis).

Section 225.250: Initial Certification and Recertification Procedures for Emissions

Monitoring

Section 225.250 establishes procedures for the initial certification and recertification for

emissions monitoring systems. 35 Ill. Adm. Code 225.250. In its original proposal, the Agency

sought to replace “citations to vacated sections of 40 C.F.R. 75 with equivalent citations to the

newly created Appendix B to Part 225.” Statement at 25;

see

Prop. at 60-65. The proposal also

provides that written notice of certification testing must be submitted to the Agency instead if

USEPA. Prop. at 61-62 (Section 225.250(a)(3)(A)). The Agency also proposes to remove

“references to missing data substitution procedures relating to CEMS.” Statement at 25;

see

Prop. at 63-64.

In its second

errata

sheet, the Agency noted that it was asked during the first hearing to

“clarify whether references to ‘CEMS’ include sorbent trap monitoring systems as well.”

Errata

2 at 29 (¶13);

see

Tr.1 at 96, 172-74. Accordingly, the Agency proposes to amend subsections

(a)(1) and (a)(3) to include references to excepted monitoring systems”.

sheet, the Agency proposed to amend Section 225.250(a)(3)(D)(iv) “to correct an

erroneous citation” in a cross-reference.

Errata

3 at 45. Similarly, in its fourth

errata

sheet, the

Agency also proposed Section 225.250(a) to correct a technical error.

Errata

4 at 1-2 (deleting

parenthesis).

Section 225.260: Out of Control Periods and Data Availability for Emissions Monitors

Section 225.260 addresses out of control periods for emission monitors. 35 Ill. Adm.

Code 225.260. In its original proposal, the Agency sought to replace “citations to vacated

sections of 40 C.F.R. 75 with equivalent citations to the newly created Appendix B to Part 225.”

Statement at 25;

see

Prop. at 65. The Agency’s proposal “also removes references to missing

data substitution procedures relating to CEMS and establishes minimum monitor data

availability requirements.” Statement at 25;

see

Prop. at 65, TSD at 17. In his testimony on

behalf of the Agency, Mr. Bloomberg stated that this availability requirement replaces missing

data procedures. Exh. 6 at 4. He further states that USEPA has found the requirement to be

achievable and that it “is comparable to the level of monitor availability for mercury monitoring

of new sources required by 40 C.F.R. 60.49Da(p)(4)(i).”

Id.

In its second

errata

sheet, the Agency proposed to amend Section 225.260 “to clarify that

MPS and CPS sources are subject to the 75% data availability uptime requirement.”

Errata

2 at

33-34, citing Tr.1 at 160. Also in the second

errata

sheet, the Agency proposed in subsection (c)

to change the term “must” to “will.”

Errata

2 at 33-34. In its third

errata

sheet, the Agency

proposed to amend subsection (b) “to clarify that all units using CEMS are subject to the 75%

uptime requirement.”

Errata

3 at 9. The Agency states that it offered this clarification “[i]n

response to comments by industry and to ensure the regulation matches the Agency’s original

intent.”

In his pre-filed testimony for the second hearing on behalf of Kincaid, Mr. Nuckols

expresses the belief that “a phase-in of the 75% data availability requirement is warranted. We

suggest the IEPA program begin with a 65% data availability requirement in July 2010 rising to

a 75% standard in July 2011.” Exh. 10 at 11-12. In his pre-filed testimony for the second

hearing on behalf of Midwest Generation, Mr. Miller cites difficulty in operating CEMS to

“propose an availability calculation based on a rolling annual basis as opposed to the quarterly

basis.” Exh. 12 at 12;

see

Prop. at 65.

At the second hearing, the Agency proposed additional revisions to Section 225.260

regarding monitor data availability. Exh. 8. In its post-hearing comment, the Agency states that

it has addressed Kincaid’s objections on this issue. Agency Comment at 11, citing Tr.2 at 46-47,

59-60;

see

Kincaid Comment at 1. Also in its post-hearing comments, the Agency states that it

has satisfactorily addressed Midwest Generation’s position on data availability. Agency

Comment at 7, citing Tr.2 at 66;

see

MG Comment at 2-3.

Section 225.261: Additional Requirements to Provide Heat Input Data

Section 225.261 establishes additional requirements with regard to providing heat input

data. 35 Ill. Adm. Code 225.261. In its original proposal, the Agency sought in this section to

replace citations to vacated sections of 40 C.F.R. 75 with equivalent citations to the newly

created Appendix B to Part 225.” Statement at 25;

see

Prop. at 66.

Section 225.265: Coal Analysis for Input Mercury Levels

Section 225.265 addresses analysis of coal for input mercury levels. 35 Ill. Adm. Code

225.265. In its original proposal, the Agency first sought to correct an erroneous cross-reference

to Section 225.230 in subsection (a). Statement at 25;

see

Prop. at 66. The Agency then

proposed to require “sources complying via Section 225.233, 225.239, or 225.291 through

225.299 to perform coal sampling in accordance with this Section.” Statement at 25;

see

Prop. at

66. Specifically, the Agency sought to require that “EGUs complying by means of Section

225.233 or Sections 225.291 through 225.299 perform coal sampling at least once a month,

EGUs complying by means of Section 225.239 perform coal sampling according to the schedule

provided in Section 225.239(e)(3), and all other EGUs subject to this requirement perform coal

sampling on a daily basis.” Statement at 25;

see

Prop. at 66-67.

In its first

errata

sheet, the Agency proposed amending Section 225.265(a)(1).

Errata

at 1-2. First, the Agency sought to add language clarifying the frequency of required coal

analysis.

Id.

at 1. The Agency also responded to a regulated source, which had “suggested the

addition of language to address situations when a boiler has not operated over a given time

period and asked for clarification about how to handle the testing of multiple coal samples.”

Id.

In its second

errata

sheet, the Agency proposes a number of changes to Section 225.265.

First, the Agency proposes in subsection (a) to “clarify that the coal sampling requirements in

this Section apply to EGUs in the MPS and CPS, except EGUs subject to the 0.0080 lb/GWh

emission limit.”

Errata

2 at 34, 35. The Agency states that “this exception includes EGUs that

opt into the emission limit early.”

. Second, the Agency proposes to clarify the provisions of

subsection (a)(1) by dividing into subsection (a)(1)(A) through (a)(1)(C).

. at 34, 36. The

Agency states that “[t]he proposed revisions to subsection (a)(1)(A) specify that, of the EGUs

that need to perform coal sampling, those in the MPS or CPS, except EGUs complying with the

90% control efficiency standard or utilizing emissions testing to demonstrate compliance, must

perform coal sampling at least once each month.”

. at 34, 35, 36. The Agency further states

that “[t]he proposed revisions to subsection (a)(1)(B) clarify that EGUs in the MPS or CPS

complying with the 90% control efficiency standard, including EGUs that opt into such limit

early, and that utilize emissions testing to demonstrate compliance must perform coal sampling

according to the schedule set forth in Section 225.239.”

. The Agency also states that “[t]he

proposed revisions to subsection (a)(1)(C) clarify that EGUs in the MPS and CPS subject to the

90% control efficiency standard, including EGUs that opt into such limit early, and that utilize

CEMS to demonstrate compliance must perform coal sampling daily.”

. at 34-35, 36. Third,

the Agency proposed to amend subsection (a)(2) “to include ASTM D6722-01 as an approved

method for measuring mercury content of coal “in response to a request by a regulated entity.

at 35, 36.

In its third

errata

sheet, the Agency responds to a comment by Ameren by proposing to

amend Section 225.265(a)(1) “to provide greater flexibility regarding the location at which

sources are required to collect a grab sample.”

Errata

3 at 9-10.

In its post-hearing comment, Midwest Generation addressed two aspects of this section.

First, Midwest Generation voices its support for including ASTM D6722-01 in “the list of

methods for determining the amount of mercury in coal.” MG Comment at 5. Midwest

Generation also states that it “supports the Agency’s proposal to reduce the frequency of coal

sampling to monthly from daily for CPS units where the units have not been opted in to the 90%

reduction requirement.”

Dynegy’s post-hearing comments also address this section. First, Dynegy expresses the

understanding that

the rule does not require the inclusion of coal data in the semi-annual reports

submitted by companies complying with the mercury rule through the Multi-

Pollutant Standard (“MPS”), Section 225.233, that are relying on the periodic

stack testing provisions of proposed Section 225.239 for units that are not early

compliers with the 90% reduction standard,

i.e.

, that have not ‘opted in’ to the

90% reduction requirement prior to the compliance deadline. Rather, this data is

to be maintained at each power station and made available to the Agency upon

request. Dynegy Comment at 1-2.

Dynegy also expresses the understanding that MPS units complying with the mercury

emission standard through 90% reduction and relying on sorbent traps for monitoring “must

collect daily coal samples.” Dynegy Comment at 2. Dynegy argues that the Agency’s proposed

Section 225.265 addresses sampling, analyzing, and averaging those analyses “but does not

specifically allow or prohibit compositing of samples prior to analysis.”

. Dynegy claims

that, “[i] other words, the daily coal sampling requirement is much more frequent than the

emission sampling period.”

. at 2.

To address this, Dynegy proposes that the Board allow the period for analyzing daily coal

samples to correspond with the period for sorbent trap data capture. Dynegy Comment at 2.

Dynegy states that this data capture period “varies depending on the flue gas flow rate in the

stack and the mercury emission rate.”

. Dynegy expects that sorbent traps will capture data in

stacks for periods of seven to eight days, during which they effectively create a composite of

mercury emissions over that period.

. Dynegy also proposes that “coal samples could be

composited over a period of time corresponding to the sorbent trap sampling period.”

Id.

at 2.

Dynegy argues that “[t]his practice would produce more relevant data because the data analyzed

would have been collected over a similar period of time.”

. at 3.

Responding to Dynegy’s post-hearing comments, the Agency first notes Dynegy’s

statement that “sources in the MPS complying by stack testing are not required to submit coal

data in semi-annual reports, but that such information must be maintained at the source.”

Agency Comment at 13, citing Dynegy Comment at 1-2. The Agency acknowledges that this

view “is correct” but notes that sources need to submit this data with each required emissions test

report. Agency Comment at 13.

Second, the Agency notes Dynegy’s proposal “that the Board allow for the period over

which the daily samples are analyzed to correspond with the sorbent trap data capture period”

and that “the coal samples could be composited over a period of time corresponding to the

sorbent trap sampling period.” Agency Comment at 13, citing Dynegy Comment at 2. The

Agency notes that the proposed rule includes no specification describing this compositing, and

the Agency opposes Dynegy’s proposed language. Agency Comment at 13. Nonetheless, the

Agency states that it “does not oppose the concept of compositing proposed by Dynegy.”

The Agency notes that its proposal allows alternative monitoring and measurement to be

submitted for its approval.

Id.

, citing Rev. Prop. at 19, 20 (proposed Sections 225.202(a) and

225.210(b)(1)). The Agency stresses that any request for an alternative should include, among

other elements, “modified versions of the appropriate ASTM standards.” Agency Comment at

14.

In its response to the Agency’s post-hearing comment, Dynegy noted the Agency’s view

that there exists sufficient flexibility under Sections 225.202(a) and 225.210(b)(1) to propose

compositing as an alternative to the requirements of Section 225.265(a)(1)(C). Dynegy Resp. at

1-2. Dynegy states that “[t]his response is satisfactory.”

. at 2.

Section 225.270: Notifications

Section 225.270 addresses notification by sources to the Agency. 35 Ill. Adm. Code

225.270. The Agency’s original proposal seeks to replace “citations to vacated sections of 40

C.F.R. 75 with equivalent citations to the newly created Appendix B to Part 225.” Statement at

26;

see

Prop. at 67.

Section 225.290: Recordkeeping and Reporting

Section 225.290 provides recordkeeping and reporting requirements for the owner or

operator of an EGU. 35 Ill. Adm. Code 225.290. In its original proposal, the Agency sought a

number of amendments to this provision. First, the Agency proposed to replace “citations to

vacated sections of 40 C.F.R. 75 with equivalent citations to the newly created Appendix B to

Part 225.” Statement at 26;

see

Prop. at 68-73. Second, the Agency proposed to add

“[r]ecertfication testing that has been performed for any CEMS and the status of the results” as a

required element of quarterly reports. Statement at 26;

see

Prop. at 70. Third, the Agency

proposes to remove reference to data substitution procedures for CEMS. Statement at 26;

see

Prop. at 70-71. Finally, the Agency also proposed to correct technical errors in two cross-

references to Section 225.230. Statement at 26;

see

Prop. at 68.

In comments filed January 14, 2009, after the first hearing and responding to questions

raised there, the Agency stated that it had “agreed to consider allowing additional time for

sources to submit original monitoring reports.” PC 1 at 6. The Agency stated that it “is not

proposing such a change, as it has not identified any reports that would require additional time.

For example, the quarterly reports required pursuant to Section 225.290(b) are due 45 days after

the end of a quarter, meaning the first report will not be due until mid-November.”

. The

Agency offers that, [i]f there is a different report that sources believe requires additional time,

the Agency will consider extending the deadline if such report is identified.”

Id.

In its first

errata

sheet, the Agency proposed to amend Section 225.290(d)(2)(F) by

deleting unnecessary references to data substitution.

sheet, the Agency proposed a number of amendments to Section

225.290. First, the Agency proposes to amend Section 225.290(a)(2)(A) “to require use of parts

per million rather than pounds per trillion BTUs when recording the mercury content of coal.”

Errata

2 at 37, 38. Second, the Agency responds to requests at the first hearing and

acknowledges that USEPA will not be accepting electronic reports from sources by proposing to

delete subsection (a)(6) referring to electronic reporting.

. at 37, 39. Third, the Agency

proposed to amend the renumbered subsection (a)(6) “to specify that sources must only retain

records for five years.”

. at 37, 39.

Also in its second

errata

sheet, the Agency responds “to requests at hearing and

USEPA’s inability to accept electronic reports” by proposing effectively to replace the original

subsection (b) regarding the content of quarterly reports with new language.

Errata

2 at 37, 39-

42 (proposed new subsection (b)(1) through (b)(4)). The Agency attached a draft reporting form,

which it had “previously provided to affected sources and revised based upon comments

received from such sources.”

. at 37;

see id

., Exh. 1 (Mercury Monitoring Reporting Form).

The Agency also proposed to clarify subsection (c)(2) by replacing a “reference to missing data

with a reference to data that is unavailable or out of control.”

. at 37, 43. The Agency also

proposes to amend subsection (c) by replacing “two references to Appendix B with references to

40 C.F.R. 75.”

. at 37, 43. Finally, The Agency proposes to amend subsection (d) “to add

several references to QAMO, resulting from a change to the monitoring calculation provisions.”

. at 37, 44-45; citing

. at 5.

In its third

errata

sheet, the Agency first proposed to amend Section 225.290(a)(1) “to

reflect the removal of the term ‘designated representative.’”

Errata

3 at 10. The Agency also

proposed to amend Section 225.290(b)(3)(F) to respond to comments that certain data

acquisition and handling systems are able to record the amount of coal combusted during QAMO

hours.

In its fourth

errata

sheet, the Agency proposes several technical corrections to errors

contained in the second

errata

sheet.

Errata

4 at 2-6 (adding underlining). The Agency also

proposes to amend Section 225.290(b)(3)(C) to reflect revisions contained in Exhibit 8.

. at 2;

see

Exh. 8. For clarification of those revisions, the Agency also proposes to add the term “basis”

in that section.

Errata

4 at 2, 3.

In its post-hearing comment, Midwest Generation addressed Section 225.290(b)(3)(F),

noting that “the Agency proposed to allow the option of utilizing the inlet mercury emissions

based on coal sampling that matches in time the QAMO hours of the outlet mercury emissions

when calculating the percent mercury reduction.” MG Comment at 6. Midwest Generation

expresses agreement “that this is a more accurate method for calculating mercury emission

reductions.”

In its post-hearing comment, Dynegy claimed that “EGUs using excepted monitoring

systems will be hard-pressed to have their end-of-quarter emission measurements collected, sent

off-site for analysis, and the reported data then included in the quarterly report for submittal to

the Agency, all within 45 days.” Dynegy Comment at 4. Dynegy further argues that “[a] 60-day

reporting deadline is more appropriate for the additional transportation and analytical steps

associated with excepted monitoring systems.´

. Accordingly, Dynegy proposes that, for

EGUs using excepted monitoring systems, the Board amend Section 225.290(b)(4) to provide 60

days for submitting quarterly reports to the Agency.

In its post-hearing comment, the Agency noted Dynegy’s request for an extension of the

deadline for EGUs using excepted monitoring systems to submit quarterly reports. Agency

Comment at 17, citing Dynegy Comment at 4. The Agency suggested that the Board adopt

slightly different language than that proposed by Dynegy in order to clarify the provision.

Agency Comment at 17. In its response to the Agency’s post-hearing comment, Dynegy stated

with regard to Section 225.290(b)(4) that “[t]he Agency’s proposed language is acceptable.”

Dynegy Resp. at 2.

CPS Generally

The Agency and Midwest Generation negotiated the CPS during the original mercury

rulemaking process. TSD at 4, Exh. 7 at 5;

see

35 Ill Adm. Code 225 Subpart F. “Similar to the

MPS, the CPS allows flexibility in complying with the mercury provisions in exchange for SO

reductions, NO

reductions, and other considerations agreed to by the parties.” TSD at 4; Exh. 7

at 5. At the time it was negotiated, the parties to the CPS desired to include it in the mercury

rule. TSD at 4; Exh. 7 at 5. As the mercury rule was then in its final stages of adoption, the

parties included the CPS in Illinois’ CAIR. TSD at 4; Exh. 7 at 5. “Consistent with the original

desire and determination that the more appropriate place for the CPS was in the Illinois mercury

rule, the CPS will now be removed from CAIR and included in the Illinois mercury rule. TSD at

4; Exh. 7 at 5;

see

Prop. at 74-97.

Section 225.291: Combined Pollutant Standard: Purpose

While this proposed new section effectively restates the existing Section 225.600

regarding the purpose of the CPS, it also “replaces citations to Subpart F of Part 225 with

equivalent citations to Section 225.291 through 225.299, including internal cross-citations.”

Statement at 26;

see

Prop. at 74 (proposed new Section 225.291), Prop. at 85 (deleting Section

225.600);

see also

35 Ill Adm. Code 225.600 (Purpose).

Section 225.292: Applicability of the Combined Pollutant Standard

While this proposed new section effectively restates the existing Section 225.605

regarding applicability of the CPS, it also “replaces citations to Subpart F of Part 225 with

equivalent citations to Section 225.291 through 225.299, including internal cross-citations.”

Statement at 26;

see

Prop. at 74-75 (proposed new Section 225.292), Prop. at 86 (deleting

Section 225.605;

see also

35 Ill Adm. Code 225.605 (Applicability).

In its second

errata

sheet, the Agency proposed to amend subsection (e) “to delete a

reference to the CAIR designated representative.”

Errata

2 at 46. In its third

errata

sheet, the

Agency proposed the further amendment of deleting the entire reference to a “designated

representative.”

Errata

3 at 10-11.

Section 225.293: Combined Pollutant Standard: Notice of Intent

While this proposed new section effectively restates the existing Section 225.610

regarding notice of intent to comply with the CPS, it also “replaces citations to Subpart F of Part

225 with equivalent citations to Section 225.291 through 225.299, including internal cross-

citations.” Statement at 26;

see

Prop. at 75 (proposed new Section 225.293), Prop. at 86-87

(deleting Section 225.610);

see also

35 Ill Adm. Code 225.610 (Notice of Intent).

Section 225.294: Combined Pollutant Standard: Control Technology Requirements and

Emissions Standards for Mercury

While this proposed new section effectively replaces the existing Section 225.615

regarding the control technologies and emissions standards for the CPS, it also “replaces

citations to Subpart F of Part 225 with equivalent citations to Section 225.291 through 225.299,

including internal cross-citations.” Statement at 26;

see

Prop. at 75-80 (proposed new Section

225.294);

see also

35 Ill Adm. Code 225.615 (Control Technology Requirements and Emissions

Standards for Mercury).

In his testimony pre-filed for the first hearing, Mr. Bloomberg stated that the Agency

proposed only “minimal technical changes” for the CPS. Exh. 6 at 2. Summarizing those

changes, the first stated that, for three years, CPS sources can opt to rely on alternative emissions

testing instead of the CEMS.

. at 2-3, citing Exh. 1 (Mattison pre-filed testimony). The

Agency concludes that “[s]emi-annual stack testing, along with existing recordkeeping and

reporting, is adequate for evaluation and verification by the Illinois EPA that the installed

mercury control system has been designed for effective absorption of mercury, is utilizing an

approved sorbent, and is injecting sorbent at the required minimum rates, as required by the

rule.” TSD at 14. Mr. Bloomberg also stated that the Agency’s proposal provided flexibility by

adding two new approved sorbents for use at Illinois sources: Calgon Carbon’s FLUEPAC MC

Plus and Calgon Carbon’s FLUEPAC CF Plus. Exh. 6 at 3,

see

Exh. 7 at 5;

see also

Prop. at 77

(adding FLUEPAC MC Plus),

Errata

1 at 4 (adding FLUEPAC CF Plus).

In comments filed January 14, 2009, after the first hearing and responding to questions

raised there, the Agency identified this Section 225.294(e)(1)(B) as a provision limiting “a

source’s ability to switch” between CEMS and the emissions testing alternative. PC 1 at 1;

see

Tr.1 at 27-28. In its second

errata

sheet, the Agency proposed “amending Section

225.294(e)(1)(B) to correct an error in the Agency’s original proposal regarding the frequency of

emission testing for CPS sources utilizing Section 225.239 to demonstrate compliance.”

Errata

2 at 46. The Agency stated that, “[w]hile EGUs in the CPS that are complying with the sorbent

injection rate requirement must perform emissions testing on a semi-annual basis, if such EGUs

opt into either the 0.0080 lb/GWh emission limit or 90% control efficiency requirement early,

they must perform quarterly emissions testing.”

. at 46-47, 48. The Agency also proposed to

amend Section 225.294(e)(1)(B) in response to requests at the first hearing for clarification “to

specify which subsections of Section 225.239 are applicable to EGUs in the CPS that utilize

emissions testing to demonstrate compliance.”

. at 47, 48.

In it second

errata

sheet, the Agency also proposed in response to a request at the first

hearing to amend Section 225.294(f) “to clarify that EGUs in the CPS may utilize the averaging

provisions set forth in Section 225.232.”

Errata

2 at 47, 49, citing Tr.1 at 88-89;

see

35 Ill.

Adm. Code 225.232. The Agency also proposed to amend subsection (l) “to clarify the ‘sunset

date’ for the emissions testing alternative in Section 225.239.”

Errata

2 at 47, 52. Finally, the

Agency also proposed in response to a request at the first hearing to amend subsection (l) to

clarify whether reference to CEMS include sorbent trap monitoring systems as well by including

references to “excepted monitoring systems.”

. at 47, 52.

In his pre-filed testimony for the second hearing on behalf of Midwest Generation, Mr.

Miller noted the Agency’s suggestion that injecting halogenated activated carbon in an optimum

manner “may require that sorbent be injected upstream of the air heater.” Exh. 12 at 18. Mr.

Miller stated that “Section 225.294(g)(4) requires for a correction in the flow rate used in

determining the amount of sorbent to be injected when there is at least a 100ºF difference in

temperature between the point of measurement of the flow rate and the point of injection of the

sorbent.”

. Although Mr. Miller recognizes that “injecting sorbent upstream of the air heater

may be more “optimum” or, better put, may reflect more effective absorption considering the

configuration of the particular unit in some cases, Midwest Generation is concerned about

IEPA’s potential requirement that sorbent be injected upstream of the air heater . . . for several

reasons.

. (emphasis in original). Nonetheless, Mr. Miller states the understanding “that IEPA

will propose to amend this requirement for adjusting for the temperature differences.”

Indeed, in its third

errata

sheet, the Agency proposed to amend Section 225.294(g)(4) to

reflect new information indicating that some sources “with particulate control devices

downstream of the air preheater may inject activated carbon upstream of the air preheater.”

Errata

3 at 3, 11. The Agency states that

[t]his injection point was not contemplated during the original determination of

the required injection rates for units opting into the MPS and CPS. It also brings

to light a need to revise the rule so as to avoid an incentive to inject at a point in

the ductwork that may not be the most desirable. This is because determination of

the flow rate at the point of injection creates an incentive to inject where the flow

rate is low (

e.g.

, near the back end of the ductwork close to the stack), thereby

potentially making the injection point location decision based on factors other

than the ability to best control mercury emissions.

The Agency also expresses the belief that “measurement of gas flow rate at the point of injection

is likely less reliable in comparison to gas flow rte measurement at the stack due to there

typically being a higher level of operating experience, quality control, and quality assurance of

stack gas flow meters.”

Errata

3 at 3, 11. The Agency states that “[t]he requirement for gas

flow rate to be obtained from stack gas flow meters, which are operated under the Acid Rain

Program, will also result in a standardized point of gas flow measurement rather than such

measurements being taken at variable points in the gas flow configuration.”

The Agency explains its proposed revision of Section 225.294(g)(4) as requiring

“determination of the gas flow rate at the stack except in the case of units

equipped with activated carbon injection prior to a hot-side electrostatic

precipitator. For these units, the gas flow rate will still be determined at the inlet

to the hot-side electrostatic precipitator. For this purpose, the gas flow rate would

actually be measured at the stack, however, the stack gas flow rate will be

adjusted for the differences in temperature in the stack and at the inlet o the hot-

side electrostatic precipitator. This adjustment is required since the Agency was

aware in its original determination of the required injection rates that units

equipped with hot-side electrostatic precipitators would be injecting activated

carbon prior to the hot-side electrostatic precipitator and it was recognized that

such units would typically get lower mercury control than those with more

common configurations (

e.g.

cold-side electrostatic precipitators).

Errata

3 at 3-

The Agency states that it recognizes “that some units with hot-side electrostatic precipitators

may be equipped with secondary particulate control devices downstream of the hot-side

electrostatic precipitator and will inject activated carbon downstream of the hot-side electrostatic

precipitator.”

. at 4. The Agency further states that “[s]uch units will be treated like other

units and will not be required to adjust the gas flow rate for temperature differences but will

simply measure the gas flow rate at the stack.”

In its post-hearing comments, Midwest Generation “encourage the Board to adopt the

deletion of the requirement for temperature correction in Section 225.294(g)(4).” MG Comment

at 3. Midwest Generation claims that “[t]his revision allows sources to increase the amount of

time and space in which flue gas is exposed to sorbent without unnecessarily imposing an

increase in the amount of sorbent that must be injected.”

. However, Midwest Generation

proposes a corresponding amendment: “the monitoring, recordkeeping, and reporting of ‘flue

gas temperature at the point of sorbent injection’ should be removed from Section 225.294(j)(2)

for all units except those injecting sorbent prior to a hot-side ESP.”

. Midwest Generation

states that “this particular point was not identified during the discussion that addressed Section

225.294(g)(4)” but offers language to revise Section 225.294(j)(2).

In its post-hearing comment addressing this language, the Agency “agrees that changes

need to be made” but proposes alternative language “to address the totality of changes previously

made. . . .” Agency Comment at 14, 16. In its response to the Agency’s comment, Midwest

Generation states that “[t]he Agency’s proposed language is acceptable.” MG Resp. at 1.

Section 225.295: Combined Pollutant Standard: Emissions Standards for NO

and SO

Section 225.295 addresses the treatment of mercury allowances allocated to the Agency

by USEPA. 35 Ill. Adm. Code 225.295. In its original proposal, the Agency first seeks to repeal

this language. Statement at 27;

see

Prop. at 73-74. The Agency states that, [a]s CAMR is

vacated, the trading program authorized by CAMR has ceased to exist as well. Accordingly,

there was no need for this section.” Statement at 27.

Also in its original proposal, the Agency seeks effectively to restate the existing Section

225.620 regarding emissions standards under the CPS for NO

and SO

. Statement at 27;

see

Prop. at 80-82 (proposed new Section 225.295, Prop. at 91-93 (deleting Section 225.620);

see

also

35 Ill Adm. Code 225.610 (Notice of Intent). The Agency also seeks to replace “citations to

Subpart F of Part 225 with equivalent citations to Section 225.291 through 225.299, including

internal cross-citations.” Statement at 26;

see

Prop. at 80-82.

Section 225.296: Combined Pollutant Standard: Control Technology Requirements for

, SO

, and PM Emissions

While this proposed new section effectively restates the existing Section 225.610

regarding control technology requirements for NO

, SO

, and PM emissions under the CPS, it

also “replaces citations to Subpart F of Part 225 with equivalent citations to Section 225.291

through 225.299, including internal cross-citations.” Statement at 27;

see

Prop. at 82-83

(proposed new Section 225.296), Prop. at 93-94 (deleting Section 225.625);

see also

35 Ill Adm.

Code 225.625.

Section 225.297: Combined Pollutant Standard: Permanent Shut Downs

While this proposed new section effectively restates the existing Section 225.630

regarding permanent shut downs under the CPS, it also “replaces citations to Subpart F of Part

225 with equivalent citations to Section 225.291 through 225.299, including internal cross-

citations.” Statement at 27;

see

Prop. at 83-84 (proposed new Section 225.297), Prop. at 94-95

(deleting Section 225.630);

see also

35 Ill Adm. Code 225.630.

Section 225.298: Combined Pollutant Standard: Requirements for NO

and SO

Allowances

While this proposed new section generally restates the existing Section 225.635 regarding

, and SO

, and PM allowances, it also “replaces citations to Subpart F of Part 225 with

equivalent citations to Section 225.291 through 225.299, including internal cross-citations.”

Statement at 27-28;

see

Prop. at 84-85 (proposed new Section 225.298), Prop. at 95-96 (deleting

Section 225.635);

see also

35 Ill Adm. Code 225.635. The Agency’s original proposal also

replaces “references to the CAIR trading program with references to any trading program due to

the recent

vacatur

of CAIR.” Statement at 27-28;

see

TSD at 4, Prop. at 84-85.

In its third

errata

sheet, the Agency proposes to amend subsection (a) “consistent with

the terms and conditions agree to by the affected sources in their multi-pollutant reduction

agreements with the Agency regarding NO

Agency attributes the need for this amendment to “the uncertainty surrounding the future of the

federal CAIR as adopted by Illinois.”

Id.

, citing 35 Ill. Adm. Code 225.310, 225.410, 225.510.

Also in the third

errata

sheet, the Agency proposed amendments reflecting the deletion of the

term “designated representative.”

Errata

3 at 11-12. Also, in response to industry requests, the

Agency clarifies deadlines by proposing to replace the term “before” with “by.”

Section 225.299: Combined Pollutant Standard: Clean Air Act Requirements

While this proposed new section effectively restates the existing Section 225.640

regarding Clean Air Act requirements, it also “replaces citations to Subpart F of Part 225 with

equivalent citations to Section 225.291 through 225.299, including internal cross-citations.”

Statement at 28;

see

Prop. at 85 (proposed new Section 225.299), Prop. at 96-97 (deleting

Section 225.640);

see also

35 Ill Adm. Code 225.640.

Subpart F: Combined Pollutant Standards

At the time of its adoption, the Board codified the CPS in Illinois’ CAIR. TSD at 4; Exh.

7 at 5;

see

35 Ill Adm. Code 225, Subpart F. The Agency claims that the more appropriate place

for the CPS is the mercury rule and proposes to remove the CPS from CAIR in order to

reconstitute it as part of Illinois’ mercury regulations. TSD at 4; Exh. 7 at 5;

see

Prop. at 74-97.

Specifically, the Agency’s proposal seeks to repeal Subpart F, which is comprised of Sections

225.600, 225.605, 225.610. 225.615, 225.620, 225.625, 225.630, 225.635, and 225.640 and

reconstitute that language as Sections 225.291, 225.292, 225.293, 225.294, 225.295, 225.296,

225.297, 225.298, and 225.299. Statement at 29;

see

Prop. at 74-97.

225.APPENDIX A: Specified EGUs for Purposes of the CPS (Midwest Generation’s Coal-

Fired Boilers as of July 1, 2006)

This appendix identifies Midwest Generation’s EGUs for the purposes of the CPS. 35 Ill.

Adm. Code 225.APPENDIX A. In its proposal, the Agency seeks to replace “citations to

Subpart F of Part 225 with equivalent citations to Section 225.291 through 225.299, including

internal cross-citations.” Statement at 28;

see

Prop. at 97.

225.APPENDIX B: Continuous Emission Monitoring Systems for Mercury

In its original proposal, the Agency recreates “necessary sections” of 40 C.F.R. 75 as part

of Part 225. Statement at 28. The Agency also “revised Appendices A, B, F, and K to Part 75,

converting them to Exhibits to Appendix B of Part 225.”

. The Agency states that, in doing

so, it converted the outline and citation system of the federal authorities to make them consistent

with Illinois regulations.

Id.

In recreating the federal language, the Agency states that it had

“removed references to, and sections regarding, pollutants that are not necessary to monitor

mercury, removed references to missing data substitution procedures and bias adjustment factors,

replaced references to the Administrator of the USEPA with references to the Agency, and

changed cross references to vacated portions of CAMR.” Statement at 30.

In his testimony pre-filed on behalf of the Agency for the first hearing, Mr. Bloomberg

noted that USEPA had promulgated a bias adjustment factor (BAF) for mercury monitoring at 40

C.F.R. Part 75, Appendix A, Section 7.6. Exh. 6 at 4. Mr. Bloomberg states that the BAF “was

intended to ensure that CEMS did not record mercury readings lower than emissions measured

by a reference method. The BAF was intended to account for underestimation of mercury

emissions from a CEMS that failed a bias test, resulting in higher reported emissions.”

Id.

see

generally

TSD at 15-16. He states, however, that the language establishing the BAF “was

vacated along with CAMR.” Exh. 6 at 4. He argues that, “[w]hile conservatively reporting

higher emissions was necessary when CAMR and its associated federal trading and monitoring

regulations were in force, the BAF is unnecessary in the current situation.”

., TSD at 15.

Therefore, in reconstituting the vacated CAMR monitoring provisions, the Agency “did not

include the BAF in the new regulatory language that was taken from Part 75, and struck

references to the BAF where it might have appeared in the previously-promulgated Illinois

Mercury Rule.” Exh. 6, TSD at 15-16 (comparing bias adjustment provisions promulgated in

New Source Performance Standards).

In his testimony pre-filed on behalf of the Agency for the first hearing, Mr. Bloomberg

stated that the Agency “is also proposing to delete references to missing data substitution

procedures.” Exh. 6 at 4. Characterizing these procedures as typical of rules that include a

trading program, he states that they “are used when monitors are offline to produce a

conservative estimate of mercury emissions during that period, and were included to ensure that

affected sources would operate their CEMS with the least possible down time in order to

generate a complete record of a source’s mass mercury emissions.”

., TSD at 16. He further

states, however, that after the vacation of CAMR, the procedures are not necessary for the

Illinois regulations. Exh. 6 at 4, TSD at 16. Instead, the Agency proposes a monitor availability

requirement. Exh. 6 at 4, TSD at 17 (comparing to monitoring requirements at 40 C.F.R.

60.49Da(p)(4)(i)). The Agency stresses that its proposal offers stack testing as a monitoring

alternative. Exh. 6 at 4, TSD at 17.

In his testimony pre-filed on behalf of the Agency for the first hearing, Mr. Davis states

that “[t]he omission of the Bias Adjustment Factor and the missing data procedures should have

no negative economic impact on any source affected by the Illinois mercury rule.” Exh. 3 at 2.

Section 1.1: Applicability

In its original proposal, the Agency sought to recreate federal language at 40 C.F.R. 75.2

regarding applicability. Statement at 28;

see

40 C.F.R 75.2. The Agency states that, in

recreating Section 75.2, it “deleted subsections (a), (b), (c) and revised subsection (d). Statement

at 30.

Section 1.2: General operating requirements

In its original proposal, the Agency sought to recreate federal language at 40 C.F.R.

75.10 regarding general operating requirements. Statement at 28;

see

40 C.F.R 75.10. The

Agency states that, in recreating Section 75.10, it “deleted subsection (a) and (d)(2).” Statement

at 30.

In its second

errata

sheet, the Agency addressed comments by USEPA. Specifically, in

subsections (a) and (c) the Agency sought to include in the proposed equipment performance

requirements “auxiliary monitors such as auxiliary flow monitors, diluent gas monitors, moisture

monitors, or other auxiliary monitors.”

Errata

2 at 52-53. In its third

errata

sheet, the Agency

proposed to amend subsection (f) “to reflect the removal of the term ‘designated representative.’”

Errata

3 at 13.

Section 1.3: Special provisions for measuring mercury mass emissions using the excepted

sorbent trap monitoring methodology

In its original proposal, the Agency sought to recreate federal language at 40 C.F.R.

75.15 regarding special provisions for measuring emissions using the excepted sorbent trap

monitoring methodology. Statement at 28-29;

see

40 C.F.R 75.15. In its fourth

errata

sheet, the

Agency sought to amend the proposal by deleting a “reference to electronic quarterly reports, as

the Agency is not requiring such electronic reporting.”

Errata

4 at 7.

Section 1.4: Initial certification and recertification procedures

In its original proposal, the Agency sought to recreate federal language at 40 C.F.R.

75.20 regarding initial certification and recertification procedures. Statement at 29;

see

40 C.F.R

75.20. The Agency states that, in recreating Section 75.20, it “deleted references to deadlines

specified in 40 C.F.R. 75.4 and references to the Acid Rain Program.” Statement at 30. The

Agency further states that it revised subsection (a)(5) by replacing references to missing data

substitution with references to the proposed Section 225.239 and revised subsection (b)(3)(A) by

replacing references to missing data substitution with references to requirements regarding

estimation of mercury emission.

. The Agency also states that it “deleted subsections

(a)(4)(iv), (c)(3), (c)(8), (c)(10)(ii), (d)(2)(iv), (g), and (h).”

In its second

errata

sheet, the Agency proposes a number of revisions to this section.

First, in response to comments by USEPA, the Agency proposed to amend subsection (a) by

including references to auxiliary monitoring systems.

Errata

2 at 53-55. Second, the Agency

proposes to amend subsection (b) to include references to auxiliary monitoring systems. In the

same subsection, the Agency responded to USEPA by proposing to delete the term “continuous

mercury emission” twice in order “to clarify that all monitors within the monitoring system in

the recertification approval process are included.”

. at 55-56. Third, the Agency again

responds to USEPA by seeking in subsection (b)(3)(C) to delete the word “mercury” in order “to

include all relevant CEMS in the recertification process.”

. at 56. Fourth, the Agency again

responds to USEPA by seeking to amend subsection (b)(3)(D)(i) “in order to include a system

integrity check in the recertification process.:

Id.

at 56-57, citing 40 C.F.R. 72.2. Fifth, the

Agency again responds to USEPA by proposing in various subsections of Section 1.4(b) to

delete the term “mercury” in order “to include all relevant CEMS.´

Errata

2 at 57-58. Sixth, the

Agency again responds to USEPA by proposing in subsection (b)(3)(G)(ii) “in order to include a

system integrity check in the recertification process.”

. at 58-59. Seventh, the Agency

proposes to amend subsection (b)(3)(G)(iv) by removing the term “twice” in order to clarify that

“[a] daily calibration error test is failed when the results of the test exceed the performance

specifications, not by exceeding twice the specification.”

. at 59. Eighth, the Agency responds

to changes recommended by USEPA by proposing the amend subsection (b)(3)(G)(v) in order

“to reflect the appropriate technical specifications and conditions for when trial gas injections

and trial RATA runs are permissible.”

. at 59-60.

Ninth, the Agency responds to USEPA by proposing to amend subsection (b)(3)(H) in

order to include a system integrity check in its provisions.

. at 60-61. Tenth, the Agency

proposes in subsection (b)(3)(I) to delete references to electronic reporting, which it will not

require.

. at 60-61. Eleventh, the Agency responds to USEPA by proposing to amend

subsection (b)(4) to strike the term “mercury” from a reference to emission monitoring systems.

. at 61. Twelfth, the Agency proposes to amend subsection (c) be deleting the term “mercury”

and the redundant term “or components” from references to emission monitoring systems.

. at

62. Thirteenth, the Agency proposes to delete subsection (c)(1)(D), which refers to bias testing

that it will not require, and renumbers the subsequent subsections.

. at 62-63. Fourteenth, the

Agency responds to USEPA by proposing to strike references to “level” from subsection

(c)(2)(B).

. at 63. The Agency states that “[a]ll EGUs have load, and the references to levels

apply only to non-EGU sources.”

. Fifteenth, the Agency proposes to delete Subsection

(c)(2)(C), (c)(2)(D), and (c)(7), which refer to bias testing that it will not require.

. at 63-64.

Sixteenth, the Agency responds to USEPA by proposing to strike subsection (c)(9)(A) referring

to cyclonic flow during performance testing.

. at 64. The Agency states that “the absence of

cyclonic flow is not essential to the testing.”

. Seventeenth, the Agency proposes to amend

subsection (d)(2) in order to delete additional references to electronic data submissions.

. at

65-66. Eighteenth, the Agency proposes to amend subsection (d)(2)(H) in order to correct a

sheet, the Agency proposes to amend subsections (a)(1), (a)(4)(B) ,

(a)(5)(B), (b)(2), (b)(4), (b)(5), and (f) by deleting the term “designated representative.”

Errata

3 at 13-17. The Agency also proposed a number of technical changes to clarify language in the

. at 14-15 (addressing punctuation errors).

Finally, in its fourth

errata

sheet, the Agency proposed a number of technical changes to

Exhibit 9, which modified Section 1.4(b)(3)(G)(v).

Errata

4 at 7-8;

see

Exh.9.

Section 1.5: Quality assurance and quality control requirements

In its original proposal, the Agency sought to recreate federal language at 40 C.F.R.

75.21 regarding quality assurance and quality control requirements. Statement at 29;

see

C.F.R 75.21. The Agency states that, in recreating Section 75.21, it “deleted subsections (a)(4)

through (a)(10), (b), (d), and (e).” Statement at 30.

Section 1.6: Reference test methods

In its original proposal, the Agency sought to recreate federal language at 40 C.F.R.

75.22 regarding reference test methods. Statement at 29;

see

40 C.F.R 75.22. The Agency states

that, in recreating Section 75.22, it “deleted subsections (a)(5) (a)(6), (b)(2), (b)(3), and (c)(2).”

Statement at 30.

In its second

errata

sheet, the Agency responded to USEPA by proposing to amend

Section 1.6 by including “more accurate references to the appendices to 40 C.F.R. 60.”

Errata

at 66-70. In its third

errata

sheet, the Agency proposed technical corrections to these

amendments.

Errata

3 at 17.

Section 1.7: Out-of-control periods

In its original proposal, the Agency sought to recreate federal language at 40 C.F.R.

75.24 regarding out-of-control periods. Statement at 29;

see

40 C.F.R 75.24. The Agency states

that, in recreating Section 75.24, it “deleted subsections (c)(1) and (e).” Statement at 30. In its

second

errata

sheet, the Agency responded to USEPA by proposing to add subsection (a)(4)

“specifying what an out of control period is for a weekly system integrity check.”

Errata

2 at 70.

The Agency also proposed to strike a reference to bias testing in subsection (d).

Section 1.8: Determination of monitor data availability

In its original proposal, the Agency sought to recreate federal language at 40 C.F.R.

75.32 regarding determination of monitor data availability. Statement at 29;

see

40 C.F.R 75.32.

The Agency states that, in recreating Section 75.32, it “changed the title of the Section, deleted

subsections (a)(1), (a)(2), and (b), deleted references to Equation 9, [and] added a new subsection

requiring use of Equation 8 to calculate percent monitor data availability.” Statement at 31.

In post-hearing comments filed on January 14, 2009, the Agency noted that it “was asked

to review a list to be submitted by Midwest Generation detailing references to bias adjustment

factor and missing data substitution procedures and strike such references from the proposed rule

where appropriate. PC 1 at 3;

see

Tr.1 at 172. Midwest Generation provided such a list, which

also included references to records, reports, electronic data, AETB, NIST, and designated

representatives.” PC 1 at 3. The Agency states that its second

errata

sheet revises several of the

items on that list.

. However, the Agency states that proposes no changes in Section 1.8(a).

. The Agency elaborates that “[t]he monitor availability calculations in 40 C.F.R 75, suggested

for use here by Midwest generation, are to be performed for missing data substitution

calculations for a trading regulations and are not appropriate for this command and control rule.

In addition, these calculations are for annual calculations, while the Illinois Mercury Rule uses a

quarterly standard.”

In its second

errata

sheet, the Agency proposes to amend Equation 8 by adding the term

“or stack” in the numerator and denominator for clarification of the operating hours.

Errata

2 at

71.

In his testimony on behalf of Kincaid filed for the second hearing, Mr. Nuckols stated

that “the compliance determination for the monitoring systems should be based on the same

period as the mercury emissions standard, which is 12-month rolling average.” Exh. 10 at 9. In

its post-hearing comments, the Agency argues that it had resolved this issue with Kincaid and

that Mr. Nuckols had described the Agency’s approach as a “reasonable” one. Agency Comment

at 9, citing Tr.2 at 37;

see

Exh. 8 (amending Section 1.8(a)(1)).

Section 1.9: Determination of sorbent trap monitoring systems data availability

In its original proposal, the Agency sought to recreate federal language at 40 C.F.R.

75.39 regarding determination of sorbent trap monitoring systems data availability. Statement at

29;

see

40 C.F.R 75.39. The Agency states that, in recreating Section 75.39, it “changed the title

of the Section.” Statement at 31. The Agency also states that it “replaced references to

maximum potential mercury concentration with references to quarterly emissions testing under

Section 225.239” and “deleted subsections (c), (e), and (f).”

Section 1.10: Monitoring plan

In its original proposal, the Agency sought to recreate federal language at 40 C.F.R.

75.53 regarding monitoring plans. Statement at 29;

see

40 C.F.R 75.53. The Agency states that,

in recreating Section 75.53, it “deleted subsections (a)(1), (c), (d), (e), (f)(1) through (f)(3),

(f)(5), (f)(6), (g)(1)(i)(G), (g)(1)(viii)(B) through (E), and (h).” Statement at 31. The Agency

also states that it “deleted references to dual range mercury monitors and peaking units.”

In post-hearing comments filed on January 14, 2009, the Agency noted that it “was asked

to review a list to be submitted by Midwest Generation detailing references to bias adjustment

factor and missing data substitution procedures and strike such references from the proposed rule

where appropriate. PC 1 at 3;

see

Tr.1 at 172. Midwest Generation provided such a list, which

also included references to records, reports, electronic data, AETB, NIST, and designated

representatives.” PC 1 at 3. The Agency states that its second

errata

sheet revises several of the

items on that list.

. With specific regard to Section 1.10(d)(1)(A-I), the Agency states that it

removed references to electronic reporting but also states that “the electronic storage of data will

be required to be furnished to the Agency upon request.” PC 1 at 3.

In its second

errata

sheet, the Agency proposes to eliminate subsection (c) regarding

electronic data submission and to renumber subsections accordingly.

Errata

2 at 71. In addition,

the Agency proposed to add language “to require electronic storage of data and to make the data

available to the Agency upon request.”

. at 71-72. The Agency also proposed to amend

subsection (c)(1)(B) to include moisture as a monitored parameter.

. at 72. The Agency

responded to USEPA by proposing to delete subsection (c)(1)(E)(vii) because “references to

default high range value only apply to SO

and NO

and are inappropriate for this section.”

Finally, the Agency also propose a technical correction to a cross-reference in subsection

(c)(2)(B).

Section 1.11: General recordkeeping requirements

In its original proposal, the Agency sought to recreate federal language at 40 C.F.R.

75.57 regarding general recordkeeping requirements. Statement at 29;

see

40 C.F.R 75.57. The

Agency states that, in recreating Section 75.57, it “deleted subsections (c), (d), (e), (f), (i)(1)(iv),

(i)(5)(iii), and (j)(1)(iv)” and the second sentence regarding common stacks from subsection (a).

Statement at 31. The Agency states that it also “added a new subsection (b)(4) regarding steam

load information.”

In post-hearing comments filed on January 14, 2009, the Agency noted that it “was asked

to review a list to be submitted by Midwest Generation detailing references to bias adjustment

factor and missing data substitution procedures and strike such references from the proposed rule

where appropriate. PC 1 at 3;

see

Tr.1 at 172. Midwest Generation provided such a list, which

also included references to records, reports, electronic data, AETB, NIST, and designated

representatives.” PC 1 at 3. The Agency states that its second

errata

sheet revises several of the

items on that list.

. With specific regard to Section 1.11(a), the Agency states that it removed

references to electronic reporting but also states that “the electronic storage of data will be

required to be furnished to the Agency upon request.” PC 1 at 3. Regarding Section 1.11(b-f),

the Agency proposes no revisions on the basis that the language involves a decision to be made

by the owner or operator and a vendor.

In its second

errata

, the Agency first proposes to amend Section 1.11(a)(5) “to require

hardcopy submission of monitoring plans submitted to the Agency.”

Errata

2 at 73. Second, the

Agency responds to USEPA by proposing to delete language in subsections (b)(4) and (b)(7) to

reflect a revision to 40 C.F.R. 75.

. Third, the Agency proposed to amend subsections (b)(3)

through (b)(7) “so that sources are required to submit hourly gross load or steam load, and not

both.”

Id.

Fourth, the Agency proposed to amend subsection (e)(1)(C) to remove an erroneous

reference to sorbent trap systems from a section dealing only with CEMS monitoring.

. at 74.

Finally, the Agency also proposes to amend Table 4a at subsection (f)(8) in order to strike “Code

55” referring to data substitution.

In its third

errata

sheet, the Agency proposes to amend subsection (a) “to require five

years for record retention so as to be consistent with Section 225.290(a)(6).”

Errata

3 at 18. The

Agency also proposed various technical corrections.

Section 1.12: General recordkeeping provisions for specific situations

In its original proposal, the Agency sought to recreate federal language at 40 C.F.R.

75.58 regarding general recordkeeping requirements under specific situations. Statement at 29;

see

40 C.F.R 75.58. The Agency states that, in recreating Section 75.57, it “deleted subsections

(a), (b)(1), (b)(2), (b)(3)(iii), (b)(3)(iv), (c), (d), and (e).” Statement at 31.

In post-hearing comments filed on January 14, 2009, the Agency noted that it “was asked

to review a list to be submitted by Midwest Generation detailing references to bias adjustment

factor and missing data substitution procedures and strike such references from the proposed rule

where appropriate. PC 1 at 3;

see

Tr.1 at 172. Midwest Generation provided such a list, which

also included references to records, reports, electronic data, AETB, NIST, and designated

representatives.” PC 1 at 3. The Agency states that its second

errata

sheet revises several of the

items on that list.

. With specific regard to Section 1.12(a-b), the Agency states that it

proposes no revisions.

. The Agency further states that this language “does not concern

missing data substitution, but rather parametric monitoring when the mercury CEMS is

unavailable.”

Section 1.13: Certification, quality assurance, and quality control record provisions

In its original proposal, the Agency sought to recreate federal language at 40 C.F.R.

75.59 regarding certification, quality assurance, and quality control records. Statement at 29;

see

40 C.F.R 75.59. The Agency states that, in recreating Section 75.59, it deleted subsections

(a)(5)(iii)(G), (a)(5)(v), (a)(7)(iv)(V) and (W), (a)(12)(iii), (a)(13), (b), and (d). Statement at 31.

In post-hearing comments filed on January 14, 2009, the Agency noted that it “was asked

to review a list to be submitted by Midwest Generation detailing references to bias adjustment

factor and missing data substitution procedures and strike such references from the proposed rule

where appropriate. PC 1 at 3;

see

Tr.1 at 172. Midwest Generation provided such a list, which

also included references to records, reports, electronic data, AETB, NIST, and designated

representatives.” PC 1 at 3. The Agency states that its second

errata

sheet revises several of the

items on that list.

. With specific regard to Section 1.13(a)(1-7), the Agency states that it

removed references to electronic reporting but also states that “the electronic storage of data will

be required to be furnished to the Agency upon request.” PC 1 at 3. With specific regard to

Section 1.13(b), the Agency states that it proposes no revisions.

. The Agency further states

that this language “does not concern missing data substitution, but rather parametric monitoring

when the mercury CEMS is unavailable.”

In its second

errata

sheet, the Agency responds to USEPA by proposing to amend

subsection (a) “to include a requirement that EGUs use ‘calibration gas’ to calibrate and certify

applicable equipment.”

Errata

2 at 75. Second, with the addition of this general language, the

Agency proposes to revise and re-number subsequent subsections.

Id.

Third, the Agency the

Agency responds to USEPA by proposing to amend subsection (a)(1) to require system integrity

checks on a weekly and not daily basis.

. Fourth, the Agency proposes to amend subsection

(a)(3)(H) by adding language referring to “measurement error.”

. at 76. Fifth, the Agency

again responds to USEPA by proposing to amend subsections (a)(5)(B)(xii) and (a)(5)(C)(v) in

order to remove language applicable only to non-EGUs.

. Sixth, the Agency proposes to

amend subsection (a)(5)(C)(vi) to remove a reference to bias testing.

. at 77. Seventh, the

Agency responds to USEPA by rewording subsection (a)(5)(E) for clarification.

. Eighth, the

Agency proposes to amend subsection (a)(7)(D) by adding language clarifying that 3A is a

reference method.

. Ninth, throughout subsection (a)(7)(G), the Agency proposes to correct

the abbreviation of “gram.”

. Tenth, the Agency proposes in subsection (a)(10) in order “to

remove unnecessary references to testing for SO

and NO

equipment.”

. at 77-78. Eleventh,

the Agency proposes to amend subsection (a)(12)(A)(vi) by removing language applying “only

to SO

monitor RATA exemptions” and renumbering accordingly.

. Twelfth, the Agency

proposes to delete subsection (a)(12)(C) “because it refers only to fuel flow meters” that coal-

fired units do not use.

. Thirteenth, the Agency proposes to strike from subsection

renumbered subsection (a)(12)(C) language applying only to non-EGUs.

. at 78-79. Finally,

the Agency also proposes to amend subsection (d) to strike a reference to missing data

procedures.

. at 79.

Section 1.14: General provisions

In its original proposal, the Agency sought to recreate federal language at 40 C.F.R.

75.80 regarding general provisions. Statement at 29;

see

40 C.F.R 75.80. The Agency states

that, in recreating Section 75.59, it “deleted subsections (a)(2), (d), and (f).” Statement at 31.

In its second

errata

sheet, the Agency proposed to replace an “unnecessarily vague”

reference to “such a program” with a reference to the more specific “Part 225.”

sheet, the Agency first proposed to amend subsections (a), (c)(4)(C),

(f)(1), and (f)(3) to strike a reference to “designated representative.”

Errata

3 at 19. Second, the

Agency proposes in subsection (c)(2) to strike the word “all” because “EGUs are not actually

require to account for all emissions (as a result of the removal of data substitution requirements

and the addition of the 75% monitor availability requirements, for example).”

. (emphasis in

original).

Section 1.15: Monitoring of mercury mass emissions and heat input at the unit level

In its original proposal, the Agency sought to recreate federal language at 40 C.F.R.

75.81 regarding monitoring of mercury mass emissions and heat input at the unit level.

Statement at 29;

see

40 C.F.R 75.81. The Agency states that, in recreating Section 75.81, it

added a description of mercury concentration monitoring system.” Statement at 32. In its

second

errata

sheet, the Agency proposed in subsection (d)(1) to strike a reference to electronic

data submission and in subsection (d)(4)(c) to make a “minor rewording.”

Errata

2 at 80.

Section 1.16: Monitoring of mercury mass emissions and heat input at common and

multiple stacks

In its original proposal, the Agency sought to recreate federal language at 40 C.F.R.

75.82 regarding monitoring of mercury mass emissions and heat input at the unit level.

Statement at 29;

see

40 C.F.R 75.82. In its third

errata

sheet, the Agency proposed to strike the

term “designated representative” in subsection (b)(2).

Errata

3 at 21-22.

Section 1.17: Calculation of mercury mass emissions and heat input rate

In its original proposal, the Agency sought to recreate federal language at 40 C.F.R.

75.83 regarding monitoring of mercury mass emissions and heat input at the unit level.

Statement at 29;

see

40 C.F.R 75.83.

Section 1.18: Recordkeeping and reporting

In its original proposal, the Agency sought to recreate federal language at 40 C.F.R.

75.84 regarding monitoring of mercury mass emissions and heat input at the unit level.

Statement at 29;

see

40 C.F.R 75.84.

In post-hearing comments filed on January 14, 2009, the Agency noted that it “was asked

to review a list to be submitted by Midwest Generation detailing references to bias adjustment

factor and missing data substitution procedures and strike such references from the proposed rule

where appropriate. PC 1 at 3;

see

Tr.1 at 172. Midwest Generation provided such a list, which

also included references to records, reports, electronic data, AETB, NIST, and designated

representatives.” PC 1 at 3. The Agency states that its second

errata

sheet revises several of the

items on that list.

With specific regard to Section 1.18(a)(1), the Agency states that it proposes no revisions

on the basis that the language involves a decision to be made by the owner or operator and a

vendor. PC 1 at 3. Regarding Section 1.18(a)(2), the Agency states that it propose no revisions

as the section “”does not concern missing data substitution, but rather parametric monitoring

when the mercury CEMS is unavailable.

. at 2. Regarding Section 1.18(c)(1) and (f)(1), the

Agency states that it made revisions to remove electronic reporting but will require electronic

storage of data to be furnished to the Agency upon request.

In its second

errata

sheet, the Agency proposes to amend subsection (c)(3) to correct a

cross-reference.

Errata

2 at 80. The Agency also proposes to amend subsection (e) to strike

references to electronic data submission.

. at 80-81. The Agency also proposes to amend

subsection (f) “to include requirements for submitting quarterly reports in the appropriate

manner, and to remove references to electronic data submission.”

. at 81-85. In its third

errata

sheet, the Agency proposes to amend subsection (d) to remove the term “designated

representative.”

Errata

3 at 22-24.

EXHIBITS TO APPENDIX B

The Agency states that, similar to the recreation of Part 75, it “revised Appendices A, B,

F, and K to Part 75, and converted them to Exhibits A, B, C, and D to Appendix B of Part, 225,

respectively.” Statement at 32. In recreating the federal language, the Agency states that it had

“removed references to, and sections regarding, pollutants that are not necessary to monitor

mercury, removed references to missing data substitution procedures and bias adjustment factors,

replaced references to the Administrator of the USEPA with references to the Agency, and

changed cross references to vacated portions of CAMR.”

Exhibit A to Appendix B: Specifications and Test Procedures

Section 1: Installation and Measurement Location

In its original proposal, the Agency sought to recreate federal language at Section 1 of

Appendix A to 40 C.F.R. 75 regarding installation and measurement location. Prop, Exh. A at 1-

see

40 C.F.R 75 Appendix A. In recreating this language, the Agency states that it deleted

Section 1.1.2. Statement at 32.

Section 2: Equipment Specifications

In its original proposal, the Agency sought to recreate federal language at Section 2 of

Appendix A to 40 C.F.R. 75 regarding installation and measurement location. Prop, Exh. A at 2-

10;

see

40 C.F.R 75 Appendix A. In recreating this language, the Agency states that it deleted

Sections 2.1.1, 2.1.1.1, 2.1.1.2, 2.1.1.3, 2.1.1.4, 2.1.1.5, 2.1.2, 2.1.2.1, 2.1.2.2, 2.1.2.3, 2.1.2.4,

2.1.2.5, 2.1.3.1, 2.1.3.2, 2.1.3.3, 2.1.5, and 2.1.6. Statement at 32-33.

In post-hearing comments filed on January 14, 2009, the Agency noted that it “was asked

to review a list to be submitted by Midwest Generation detailing references to bias adjustment

factor and missing data substitution procedures and strike such references from the proposed rule

where appropriate. PC 1 at 3;

see

Tr.1 at 172. Midwest Generation provided such a list, which

also included references to records, reports, electronic data, AETB, NIST, and designated

representatives.” PC 1 at 3. The Agency states that its second

errata

sheet revises several of the

items on that list.

. With specific regard to Sections 2.1.3.1, 2.1.3.2, 2.1.3.3(b), and 2.1.3.4,

the Agency states that it proposes no revisions. PC 1 at 4. The Agency further states that the

sections do “not concern missing data substitution, and the value(s) needed for calculating the

proper span and range of the CEMS.”

In its second

errata

sheet, the Agency proposed to amend Section 2.1 “to reflect language

in Exhibit A, Section 2.1.3.4, which provides that Section 2.1 does not apply to mercury

monitoring systems.”

Errata

2 at 85. The Agency also, in response to a request at the first

hearing, proposed to amend Section 2.1.1 by deleting references to electronic recordkeeping and

reporting requirements, where appropriate.

. The Agency also responds to USEPA by

amending Section 2.1.2.1 “to delete portions regarding units that do not produce electrical or

thermal output, as such units are not subject to the Agency’s proposed rule.”

. at 85-86.

In its third

errata

sheet, the Agency proposed to amend Section 2.1.3.4 in order “to add

an option to certify additional calibration points rather than ordering new calibration materials.”

Errata

3 at 24.

Section 3: Performance Standards

In its original proposal, the Agency sought to recreate federal language at Section 3 of

Appendix A to 40 C.F.R. 75 regarding performance standards. Prop, Exh. A at 10-13;

see

C.F.R 75 Appendix A. In recreating this language, the Agency states that it deleted Sections

3.3.1, 3.3.2, 3.3.5, 3.3.7, and 3.4.1. Statement at 33-34.

In its second

errata

sheet, the Agency, in response to a request at the first hearing,

proposed to delete references to a bias adjustment factor, where appropriate.

sheet, the Agency responded to USEPA by proposing a number of amendments to

Section 3.

Errata

3 at 24-25. First, the Agency proposed to amend Section 3.2 “to include

system integrity checks.”

. The Agency also proposed to amend the section by changing

“linearity error” to “measurement error” and by including system integrity checks in the

definition for “measurement error.”

Section 4: Data Acquisition and Handling Systems

In its original proposal, the Agency sought to recreate federal language at Section 4 of

Appendix A to 40 C.F.R. 75 regarding data acquisition and handling systems. Prop, Exh. A at

13;

see

40 C.F.R 75 Appendix A.

In post-hearing comments filed on January 14, 2009, the Agency noted that it “was asked

to review a list to be submitted by Midwest Generation detailing references to bias adjustment

factor and missing data substitution procedures and strike such references from the proposed rule

where appropriate. PC 1 at 3;

see

Tr.1 at 172. Midwest Generation provided such a list, which

also included references to records, reports, electronic data, AETB, NIST, and designated

representatives.” PC 1 at 3. The Agency states that its second

errata

sheet revises several of the

items on that list.

. With specific regard to Section 4, the Agency states that it revised the

language to strike references to electronic reporting. PC 1 at 4. The Agency further states that

electronic storage of data will be required to be furnished to the Agency upon request.”

In its third

errat

a sheet, the Agency proposed to amend Section 4 “to eliminate references

to electronic submission of data, and to require hardcopy recordkeeping.

Errata

3 at 25-26. The

Agency also “removed references to the bias adjustment factor.”

Section 5: Calibration Gas

In its original proposal, the Agency sought to recreate federal language at Section 5 of

Appendix A to 40 C.F.R. 75 regarding calibration gas. Prop, Exh. A at 13-16;

see

40 C.F.R 75

Appendix A.

In post-hearing comments filed on January 14, 2009, the Agency noted that it “was asked

to review a list to be submitted by Midwest Generation detailing references to bias adjustment

factor and missing data substitution procedures and strike such references from the proposed rule

where appropriate. PC 1 at 3;

see

Tr.1 at 172. Midwest Generation provided such a list, which

also included references to records, reports, electronic data, AETB, NIST, and designated

representatives.” PC 1 at 3. The Agency states that its second

errata

sheet revises several of the

items on that list.

. With specific regard to Section 5.1.9, the Agency states that it propose no

revisions, as it “believes that there will be NIST traceable source standards for oxidized mercury

prior to January 10, 2010.”

In its third

errata

sheet, the Agency responded to USEPA by proposing to revise Section

5 “to include mercury monitors in span requirements for various concentrations.”

Errata

3 at 26.

Section 6: Certification Tests and Procedures

In its original proposal, the Agency sought to recreate federal language at Section 6 of

Appendix A to 40 C.F.R. 75 regarding certification tests and procedures. Prop, Exh. A at 16-32;

see

40 C.F.R 75 Appendix A. In recreating this language, the Agency states that it deleted

Section 6.5.3. Statement at 34.

In post-hearing comments filed on January 14, 2009, the Agency noted that it “was asked

to review a list to be submitted by Midwest Generation detailing references to bias adjustment

factor and missing data substitution procedures and strike such references from the proposed rule

where appropriate. PC 1 at 3;

see

Tr.1 at 172. Midwest Generation provided such a list, which

also included references to records, reports, electronic data, AETB, NIST, and designated

representatives.” PC 1 at 3. The Agency states that its second

errata

sheet revises several of the

items on that list.

. With specific regard to Section 6.1.2(a-c), the Agency states that “these

provisions will be stayed indefinitely pending an outcome by the USEPA.”

In its first

errata

sheet, the Agency proposed to amend Section 6.1.2 “to ad a citation that

was inadvertently omitted from the original proposal.”

Errata

1 at 4-5. In its second

errata

sheet, the Agency proposed to amend Sections 6.3.2 and 6.4 by changing the date “to July 1,

2009, in order to be consistent with dates in Part 225.”

Errata

2 at 87-89. The Agency

responded to a request at the first hearing by proposing in Section 6.5 to delete the reference

there to bias test.

. at 89. The Agency responded to USEPA by proposing to delete subsection

(e) of Section 6.5.2 and amend Section 6.5.2.1, “as units that do not produce electrical or thermal

output are not subject to the Agency’s proposed rule.”

. at 89-92. Reflecting the deletion of

subsection (e) of Section 6.5.2, the Agency proposes to amend Section 6.5.2.2 to strike a

reference to that deleted language.

. at 92-93.

In its third

errata

sheet, the Agency responded to USEPA by proposing to amend

Sections 6.2(h) and 6.3.1 “to include chlorine in mercury monitor linearity checks” and to strike

language considered to be inaccurate.

Errata

3 at 26-27. The Agency also proposed to amend

Sections 6.5.2, 6.5.2.1, 6.5.2.2, and 6.5.8 to strike references to “operating levels,” which pertain

strictly to non-EGUs.

. at 27-30, 32. The Agency also proposes to amend Section 6.5.3 to

strike a reference to bias adjustment.

. at 30. The Agency also proposes to amend Section

6.5.5.3 by including the term “RATA,” correcting units for some measurements, and

incorporating preferred terms.

. at 31-32. The Agency also responds to USEPA by proposing

to amend Section 6.5.6 “to refer to mercury monitoring systems more specifically than the

previously more general ‘pollutant concentration monitor.’”

. at 31-32. Finally, the Agency

responds to USEPA by proposing to amend Section 6.5.9 “to allow appropriate reference method

testing and to correct [an] improper citation.”

. at 32-33.

In his testimony on behalf of Kincaid pre-filed for the second hearing, Mr. Nuckols

argued that the Board should strike Section 6.1.2 regarding requirements for Air Emission

Testing Bodies. Exh. 10 at 14-16. He notes that USEPA has withdrawn this portion of the rules

pending review of legal issues.

. at 14, citing 73 Fed. Reg. 65554 (Nov. 4, 2008). In its post-

hearing comments, the Agency stressed that it had responded to this concern and “clarified at the

hearing that the Illinois mercury rule would impose no burdens upon sources while the federal

stay is in place, and that it is the Agency’s position that, ‘assuming that the federal accreditation

requirements are still stayed as of July ’09, . . . there will be no requirement under the Illinois

rule for accreditation.’” Agency Comment at 14, citing Tr.2 at 55.

Section 7: Calculations

In its original proposal, the Agency sought to recreate federal language at Section 7 of

Appendix A to 40 C.F.R. 75 regarding calculations. Prop, Exh. A at 32-42;

see

40 C.F.R 75

Appendix A. In recreating this language, the Agency states that it deleted Sections 7.4, 7.4.1,

7.4.2, 7.4.3, 7.5, and 7.6.5. Statement at 34-35.

In its second

errata

sheet, the Agency responded to a request at the first hearing by

proposing to delete remaining references to a bias adjustment factor.

Errata

2 at 93. The

Agency responds to USEPA by proposing in Section 7.6 “to delete portions of the Section

concerning units that do not produce electrical or thermal output, as such units are not subject to

the Agency’s proposed rule.”

. at 94.

In its third

errata

sheet, the Agency proposed to amend Section 7.1 “to amend the title to

include system integrity checks, to change linearity error to measurement error, and to add

language to include system integrity checks in the definition for measurement error.”

Errata

3 at

33.

Exhibit B to Appendix B: Quality Assurance and Quality Control Procedures

Section 1: Quality Assurance/Quality Control Program

In its original proposal, the Agency sought to recreate federal language at Section 1 of

Appendix B to 40 C.F.R. 75 regarding a quality assurance/quality control program. Prop, Exh. B

at 43-46;

see

40 C.F.R 75 Appendix B. In recreating this language, the Agency states that it

deleted Sections 1.3, and 1.4. Statement at 35.

In post-hearing comments filed on January 14, 2009, the Agency noted that it “was asked

to review a list to be submitted by Midwest Generation detailing references to bias adjustment

factor and missing data substitution procedures and strike such references from the proposed rule

where appropriate. PC 1 at 3;

see

Tr.1 at 172. Midwest Generation provided such a list, which

also included references to records, reports, electronic data, AETB, NIST, and designated

representatives.” PC 1 at 3. The Agency states that its second

errata

sheet revises several of the

items on that list.

. With specific regard to Section 1.2.4, the Agency states that it proposes no

revisions to this language, which “does not concern missing data substitution, but rather

parametric monitoring when the mercury CEMS is unavailable.”

. at 5.

Section 2: Frequency of Testing

In its original proposal, the Agency sought to recreate federal language at Section 2 of

Appendix B to 40 C.F.R. 75 regarding frequency of testing. Prop, Exh. B at 46-71;

see

40 C.F.R

75 Appendix B. In recreating this language, the Agency states that it deleted Section 2.3.4.

Statement at 35.

In post-hearing comments filed on January 14, 2009, the Agency noted that it “was asked

to review a list to be submitted by Midwest Generation detailing references to bias adjustment

factor and missing data substitution procedures and strike such references from the proposed rule

where appropriate. PC 1 at 3;

see

Tr.1 at 172. Midwest Generation provided such a list, which

also included references to records, reports, electronic data, AETB, NIST, and designated

representatives.” PC 1 at 3. The Agency states that its second

errata

sheet revises several of the

items on that list.

. With specific regard to Section 2.6, the Agency states that it proposes no

revisions to this language. PC 1 at 5. The Agency states that “Exhibit A, Section 5.1.9 has

already addressed the use of a NIST traceable source for oxidized mercury standards.”

In its second

errata

sheet, the Agency responded to USEPA by proposing to amend

Section 2.3.1.3(b) and Footnote 1 to Figure 1 in order to strike a cross-reference to language that

has been deleted from Exhibit A.

Errata

2 at 94-95, 96;

see id

. at 89-90 (deleting Section

6.5.2(e) of Exhibit A). The Agency also proposes in response to a request at hearing to amend

Section 2.3.2 to strike references to bias tests.

. at 95-96.

In its third

errata

sheet, the Agency first proposes to amend Section 2.2.1 “to remove an

exemption for linearity checks that would apply only to SO

35. The Agency also proposes to amend Section 2.3.1.1 “to specify that each moisture monitor

must undergo a RATA.”

. at 38. The Agency also proposes to amend Sections 2.3.1.3, 2.3.2

and 2.4 to remove references to operating levels, which apply strictly to non-EGUs.

. at 38-40,

40-41. The Agency also proposed to amend Section 2.4 to clarify requirements regarding RATA

frequency.

. at 41. The Agency also responds to USEPA by proposing to amend Section 2.5

“to include an alternative to an additional audit test that is successful.”

. at 42. In its third and

fourth

errata

sheets, the Agency also proposes to amend Exhibit B by making a number of

technical corrections.

E.g.

. at 34 (correcting erroneous citation),

errata

4 at 8 (removing

comma).

In his testimony on behalf of Kincaid pre-filed for the second hearing, Mr. Nuckols noted

that Section 2.6 “specifies failed integrity tests as an ‘out-of-control period.” Exh. 10 at 12. He

argues that, because “[t]hese tests are difficult to pass,” the Board should consider less stringent

criteria.

. at 12-14 (proposing revision). In its post-hearing comments, the Agency stresses

that Mr. Nuckols acknowledged that “there are no differences between the Agency’s proposal

and USEPA’s original Part 75 requirements.” Agency Comment at 10, citing Tr.2 at 49. The

Agency also argued that he had not sufficiently justified “any revisions to weekly systems

integrity test requirements.” Agency Comment at 10.

Exhibit C to Appendix B: Conversion Procedures

Section 1: Applicability

In its original proposal, the Agency sought to recreate federal language at Section 1 of

Appendix F to 40 C.F.R. 75 regarding applicability. Prop, Exh. B at 72;

see

40 C.F.R 75

Appendix F. In recreating this language, the Agency states that it deleted Sections 2, 3, 4, 7, and

8 of the federal language. Statement at 35-36.

Section 2: Procedures for Heat Input

In its original proposal, the Agency sought to recreate federal language at Section 5 of

Appendix F to 40 C.F.R. 75 regarding procedures for heat input. Prop, Exh. B at 72-77;

see

C.F.R 75 Appendix F. In recreating this language, the Agency states that it deleted Sections 5.4,

5.5, and 5.8. Statement at 36.

Section 3: Procedure for Converting Volumetric Flow to STP

In its original proposal, the Agency sought to recreate federal language at Section 6 of

Appendix F to 40 C.F.R. 75 regarding the procedure for converting volumetric flow to STP.

Prop, Exh. B at 78;

see

40 C.F.R 75 Appendix F.

Section 4: Procedures for Mercury Mass Emissions

In its original proposal, the Agency sought to recreate federal language at Section 9 of

Appendix F to 40 C.F.R. 75 regarding applicability. Prop, Exh. B at 78-80;

see

sheet, the Agency in response to a request at the first hearing

proposed to amend Section 4.1.1 “to remove references to bias adjustment factors from the

equation.”

Errata

2 at 96-97. The Agency proposes a similar amendment to Section 4.1.2.

at 97-98. The Agency also proposes a technical amendment to Section 4.3.

. at 98. In its third

errata

sheet, the Agency proposes a number of technical changes in Sections 4.1.1 and 4.1.2.

E.g, errata

3 at 43-44 (correcting capitalization error).

Section 5: Moisture Determination From Wet and Dry O

Readings

In its original proposal, the Agency sought to recreate federal language at Section 10 of

Appendix F to 40 C.F.R. 75 regarding moisture determination from wet and dry O

readings.

Prop, Exh. B at 80-81;

see

40 C.F.R 75 Appendix F.

Exhibit D to Appendix B: Quality Assurance and Operating Procedures for Sorbent Trap

Monitoring Systems

Section 1: Scope and Application

In its original proposal, the Agency sought to recreate federal language at Section 1 of

Appendix K to 40 C.F.R. 75 regarding scope and application. Prop, Exh. B at 81-82;

see

C.F.R 75 Appendix K.

Section 2: Principle

In its original proposal, the Agency sought to recreate federal language at Section 2 of

Appendix K to 40 C.F.R. 75 regarding principles. Prop, Exh. B at 82;

see

40 C.F.R 75 Appendix

K. In its third

errata

sheet, the Agency responded to USEPA by proposing to remove from

Section 2.0 “language that has subsequently been removed from 40 C.F.R. Part 75.”

Errata

3 at

44.

Section 3: Clean Handling and Contamination

In its original proposal, the Agency sought to recreate federal language at Section 3 of

Appendix K to 40 C.F.R. 75 regarding clean handling and contamination. Prop, Exh. B at 82;

see

40 C.F.R 75 Appendix K.

Section 4: Safety

In its original proposal, the Agency sought to recreate federal language at Section 4 of

Appendix K to 40 C.F.R. 75 regarding safety. Prop, Exh. B at 81-82;

see

40 C.F.R 75 Appendix

Section 5: Equipment and Supplies

In its original proposal, the Agency sought to recreate federal language at Section 5 of

Appendix K to 40 C.F.R. 75 regarding equipment and supplies. Prop, Exh. B at 83-85;

see

C.F.R 75 Appendix K.

Section 6: Reagents and Standards

In its original proposal, the Agency sought to recreate federal language at Section 6 of

Appendix K to 40 C.F.R. 75 regarding reagents and standards. Prop, Exh. B at 85;

see

40 C.F.R

75 Appendix K.

Section 7: Sample Collection and Transport

In its original proposal, the Agency sought to recreate federal language at Section 7 of

Appendix K to 40 C.F.R. 75 regarding sample collection and transport. Prop, Exh. B at 85-88;

see

40 C.F.R 75 Appendix K.

Section 8: Quality Assurance and Quality Control

In its original proposal, the Agency sought to recreate federal language at Section 8 of

Appendix K to 40 C.F.R. 75 regarding quality assurance and quality control. Prop, Exh. B at 88-

92;

see

40 C.F.R 75 Appendix K.

In its third

errata

sheet, the Agency responded to industry comments by proposing to

amend Table K-1 Footnote FN** “to remove language involving [a] multiplying factor of 1.11

for single trap data.”

Errata

3 at 44-45. The Agency elaborates that. “[w]hen one trap fails to

meet QA requirements the valid trap may be used.”

. at 44. In its post-hearing comments, the

Agency argues that this proposed amendment ought to satisfy Kincaid’s concern with the issue.

Agency Comment at 9, citing Tr.2 at 40;

see

Exh. 10 at 16-17 (Nuckols’ pre-filed testimony).

Section 9: Calibration and Standardization

In its original proposal, the Agency sought to recreate federal language at Section 9 of

Appendix K to 40 C.F.R. 75 regarding calibration and standardization. Prop, Exh. B at 92-94;

see

40 C.F.R 75 Appendix K.

Section 10: Analytical Procedures

In its original proposal, the Agency sought to recreate federal language at Section 10 of

Appendix K to 40 C.F.R. 75 regarding analytical procedures. Prop, Exh. B at 94-96;

see

C.F.R 75 Appendix K.

Section 11: Calculations and Data Analysis

In its original proposal, the Agency sought to recreate federal language at Section 1 of

Appendix K to 40 C.F.R. 75 regarding scope and application. Prop, Exh. B at 81-82;

see

C.F.R 75 Appendix K. In recreating this language, the Agency states that it deleted the federal

Section 11.5. Statement at 37. In its third

errata

sheet, the Agency responded to USEPA by

proposing to amend Section 11.7”to correct two erroneous references.”

Errata

3 at 45.

TITLE 35: ENVIRONMENTAL PROTECTION

ORDER

The Board directs the Clerk to file the following proposed amendments with the Joint

Committee on Administrative Rules for second-notice review. Proposed additions are

underlined, and proposed deletions appear stricken.

SUBTITLE B: AIR POLLUTION

CHAPTER I: POLLUTION CONTROL BOARD

SUBCHAPTER c: EMISSION STANDARDS AND LIMITATIONS FOR STATIONARY

SOURCES

PART 225

CONTROL OF EMISSIONS FROM LARGE COMBUSTION SOURCES

SUBPART A: GENERAL PROVISIONS

Abbreviations and Acronyms

225.130

Definitions

225.140

Incorporations by Reference

225.150

Commence Commercial Operation

SUBPART B: CONTROL OF MERCURY EMISSIONS FROM COAL-FIRED ELECTRIC

Compliance Requirements

225.220

Clean Air Act Permit Program (CAAPP) Permit Requirements

225.230

Emission Standards for EGUs at Existing Sources

225.232

Averaging Demonstrations for Existing Sources

225.233

Multi-Pollutant Standard (MPS)

225.234

Temporary Technology-Based Standard for EGUs at Existing Sources

225.235

Units Scheduled for Permanent Shut Down

225.237

Emission Standards for New Sources with EGUs

225.238

Temporary Technology-Based Standard for New Sources with EGUs

225.239

Periodic Emissions Testing Alternative Requirements

225.240

General Monitoring and Reporting Requirements

225.250

Initial Certification and Recertification Procedures for Emissions Monitoring

225.260

Out of Control Periods and Data Availability for Emission Monitors

225.261

Additional Requirements to Provide Heat Input Data

225.263

Monitoring of Gross Electrical Output

225.265

Coal Analysis for Input Mercury Levels

225.270

Notifications

225.290

Recordkeeping and Reporting

225.291

Combined Pollutant Standard: Purpose

225.292

Applicability of the Combined Pollutant Standard

225.293

Combined Pollutant Standard: Notice of Intent

225.294

Combined Pollutant Standard: Control Technology Requirements and Emissions

Standards for Mercury

225.295

Combined Pollutant Standard: Emissions Standards for NO

and SO

Treatment

of Mercury Allowances

225.296

Combined Pollutant Standard: Control Technology Requirements for NO

, SO

and PM Emissions

225.297

Combined Pollutant Standard: Permanent Shut-Downs

225.298

Combined Pollutant Standard: Requirements for NO

and SO

Allowances

225.299

Combined Pollutant Standard: Clean Air Act Requirements

SUBPART C: CLEAN AIR ACT INTERSTATE RULE (CAIR) SO

Compliance Requirements

ANNUAL TRADING PROGRAM

Compliance Requirements

Annual Trading Budget

225.430

Timing for Annual Allocations

225.435

Methodology for Calculating Annual Allocations

225.440

Annual Allocations

225.445

New Unit Set-Aside (NUSA)

225.450

Monitoring, Recordkeeping and Reporting Requirements for Gross Electrical

Output and Useful Thermal Energy

225.455

Clean Air Set-Aside (CASA)

225.460

Energy Efficiency and Conservation, Renewable Energy, and Clean Technology

Projects

225.465

Clean Air Set-Aside (CASA) Allowances

225.470

Clean Air Set-Aside (CASA) Applications

225.475

Agency Action on Clean Air Set-Aside (CASA) Applications

225.480

Compliance Supplement Pool

SUBPART E: CAIR NO

OZONE SEASON TRADING PROGRAM

Compliance Requirements

Ozone Season Trading Budget

225.530

Timing for Ozone Season Allocations

225.535

Methodology for Calculating Ozone Season Allocations

225.540

Ozone Season Allocations

225.545

New Unit Set-Aside (NUSA)

225.550

Monitoring, Recordkeeping and Reporting Requirements for Gross Electrical

Output and Useful Thermal Energy

225.555

Clean Air Set-Aside (CASA)

225.560

Energy Efficiency and Conservation, Renewable Energy, and Clean Technology

Projects

225.565

Clean Air Set-Aside (CASA) Allowances

225.570

Clean Air Set-Aside (CASA) Applications

225.575

Agency Action on Clean Air Set-Aside (CASA) Applications

SUBPART F: COMBINED POLLUTANT STANDARDS

225.600

Purpose (Repealed)

225.605

Applicability (Repealed)

225.610

Notice of Intent (Repealed)

225.615

Control Technology Requirements and Emissions Standards for Mercury

(Repealed)

225.620

Emissions Standards for NO

and SO

(Repealed)

225.625

Control Technology Requirements for NO

, SO

, and PM Emissions (Repealed)

225.630

Permanent Shut-Downs (Repealed)

225.635

Requirements for CAIR SO

, CAIR NO

, and CAIR NO

Ozone Season

Allowances (Repealed)

225.640

Clean Air Act Requirements (Repealed)

225.APPENDIX A

Specified EGUs for Purposes of the CPSSubpart F (Midwest Generation’s

Coal-Fired Boilers as of July 1, 2006)

225.APPENDIX B

Continuous Emission Monitoring Systems for Mercury

AUTHORITY: Implementing and authorized by Section 27 of the Environmental Protection Act

[415 ILCS 5/27].

SOURCE: Adopted in R06-25 at 31 Ill. Reg. 129, effective December 21, 2006; amended in

R06-26 at 31 Ill. Reg. 12864, effective August 31, 2007; amended in R09-10 at 33 Ill. Reg.

_______, effective __________.

SUBPART A: GENERAL PROVISIONS

Section 225.100 Severability

If any Section, subsection or clause of this Part is found invalid, such finding must not affect the

validity of this Part as a whole or any Section, subsection or clause not found invalid.

Section 225.120 Abbreviations and Acronyms

Unless otherwise specified within this Part, the abbreviations used in this Part must be the same

as those found in 35 Ill. Adm. Code 211. The following abbreviations and acronyms are used in

this Part:

Act

Environmental Protection Act [415 ILCS 5]

ACI

activated carbon injection

AETB

Air Emission Testing Body

Agency

Illinois Environmental Protection Agency

Btu

British thermal unit

CAA

Clean Air Act [42 USC 7401 et seq.]

CAAPP

Clean Air Act Permit Program

CAIR

Clean Air Interstate Rule

CASA

Clean Air Set-Aside

CEMS

continuous emission monitoring system

carbon dioxide

CPS

Combined Pollutant Standard

CGO

converted gross electrical output

CRM

certified reference materials

CUTE

converted useful thermal energy

DAHS

data acquisition and handling system

dscm

dry standard cubic meters

EGU

electric generating unit

ESP

electrostatic precipitator

FGD

flue gas desulfurization

fpm

feet per minute

gross electrical output

International Organization for Standardization

kilogram

pound

MPS

Multi-Pollutant Standard

MSDS

Material Safety Data Sheet

National Ambient Air Quality Standards

NIST

National Institute of Standards and Technology

nitrogen oxides

NTRM

NIST Traceable Reference Material

NUSA

New Unit Set-Aside

ORIS

Office of Regulatory Information Systems

oxygen

2.5

particles less than 2.5 micrometers in diameter

quality assurance

QAMO

quality-assured monitor operating

quality control

RATA

relative accuracy test audit

RGFM

reference gas flow meter

sulfur dioxide

SNCR

selective noncatalytic reduction

TTBS

Temporary Technology Based Standard

TCGO

total converted useful thermal energy

UTE

useful thermal energy

USEPA

United States Environmental Protection Agency

year

(Source: Amended at 33 Ill. Reg. _____, effective _____)

Section 225.130 Definitions

The following definitions apply for the purposes of this Part. Unless otherwise defined in this

Section or a different meaning for a term is clear from its context, the terms used in this Part

have the meanings specified in 35 Ill. Adm. Code 211.

“Agency” means the Illinois Environmental Protection Agency.

[415 ILCS 5/3.105]

“Averaging demonstration” means, with regard to Subpart B of this Part, a demonstration

of compliance that is based on the combined performance of EGUs at two or more

sources.

“Base Emission Rate” means, for a group of EGUs subject to emission standards for NOx

and SO

pursuant to Section 225.233, the average emission rate of NO

or SO

from the

EGUs, in pounds per million Btu heat input, for calendar years 2003 through 2005 (or,

for seasonal NO

, the 2003 through 2005 ozone seasons), as determined from the data

collected and quality assured by the USEPA, pursuant to the 40 CFR 72 and 96 federal

Acid Rain and NO

Budget Trading Programs, for the emissions and heat input of that

group of EGUs.

“Board” means the Illinois Pollution Control Board.

[415 ILCS 5/3.130]

“Boiler” means an enclosed fossil or other fuel-fired combustion device used to produce

heat and to transfer heat to recirculating water, steam, or other medium.

“Bottoming-cycle cogeneration unit” means a cogeneration unit in which the energy

input to the unit is first used to produce useful thermal energy and at least some of the

reject heat from the useful thermal energy application or process is then used for

electricity production.

“CAIR authorized account representative” means, for the purpose of general accounts, a

responsible natural person who is authorized, in accordance with 40 CFR 96, subparts

BB, FF, BBB, FFF, BBBB, and FFFF to transfer and otherwise dispose of CAIR NO

, and NO

Ozone Season allowances, as applicable, held in the CAIR NO

, SO

, and

Ozone Season general account, and for the purpose of a CAIR NO

compliance

account, a CAIR SO

compliance account, or a CAIR NO

Ozone Season compliance

account, the CAIR designated representative of the source.

“CAIR designated representative” means, for a CAIR NO

source, a CAIR SO

source,

and a CAIR NO

Ozone Season source and each CAIR NO

unit, CAIR SO

unit and

CAIR NO

Ozone Season unit at the source, the natural person who is authorized by the

owners and operators of the source and all such units at the source, in accordance with 40

CFR 96, subparts BB, FF, BBB, FFF, BBBB, and FFFF as applicable, to represent and

legally bind each owner and operator in matters pertaining to the CAIR NO

Annual

Trading Program, CAIR SO

Trading Program, and CAIR NO

Ozone Season Trading

Program, as applicable. For any unit that is subject to one or more of the following

programs: CAIR NO

Annual Trading Program, CAIR SO

Trading Program, CAIR NO

Ozone Season Trading Program, or the federal Acid Rain Program, the designated

representative for the unit must be the same natural person for all programs applicable to

the unit.

“Coal” means any solid fuel classified as anthracite, bituminous, subbituminous, or

lignite by the American Society for Testing and Materials (ASTM) Standard

Specification for Classification of Coals by Rank D388-77, 90, 91, 95, 98a, or 99

(Reapproved 2004).

“Coal-derived fuel” means any fuel (whether in a solid, liquid or gaseous state) produced

by the mechanical, thermal, or chemical processing of coal.

“Coal-fired” means:

For purposes of Subparts B and F, or for purposes of allocating allowances under

Sections 225.435, 225.445, 225.535, and 225.545, combusting any amount of coal

or coal-derived fuel, alone or in combination with any amount of any other fuel,

during a specified year;

Except as provided above, combusting any amount of coal or coal-derived fuel,

alone or in combination with any amount of any other fuel.

“Cogeneration unit” means, for the purposes of Subparts C, D, and E, a stationary, fossil

fuel-fired boiler or a stationary, fossil fuel-fired combustion turbine of which both of the

following conditions are true:

It uses equipment to produce electricity and useful thermal energy for industrial,

commercial, heating, or cooling purposes through the sequential use of energy;

and

It produces either of the following during the 12-month period beginning on the

date the unit first produces electricity and during any subsequent calendar year

after that in which the unit first produces electricity:

For a topping-cycle cogeneration unit, both of the following:

Useful thermal energy not less than five percent of total energy

output; and

Useful power that, when added to one-half of useful thermal

energy produced, is not less than 42.5 percent of total energy input,

if useful thermal energy produced is 15 percent or more of total

energy output, or not less than 45 percent of total energy input if

useful thermal energy produced is less than 15 percent of total

energy output; or

For a bottoming-cycle cogeneration unit, useful power not less than 45

percent of total energy input.

“Combined cycle system” means a system comprised of one or more combustion

turbines, heat recovery steam generators, and steam turbines configured to improve

overall efficiency of electricity generation or steam production.

“Combustion turbine” means:

An enclosed device comprising a compressor, a combustor, and a turbine and in

which the flue gas resulting from the combustion of fuel in the combustor passes

through the turbine, rotating the turbine; and

If the enclosed device described in the above paragraph of this definition is

combined cycle, any associated duct burner, heat recovery steam generator and

steam turbine.

“Commence commercial operation” means, for the purposes of Subparts B and F of this

Part, with regard to an EGU that serves a generator, to have begun to produce steam, gas,

-or other heated medium used to generate electricity for sale or use, including test

generation. Such date must remain the unit's date of commencement of operation even if

the EGU is subsequently modified, reconstructed or repowered. For the purposes of

Subparts C, D and E, “commence commercial operation” is as defined in Section

225.150.

“Commence construction” means, for the purposes of Section 225.460(f), 225.470,

225.560(f), and 225.570, that the owner or owner’s designee has obtained all necessary

preconstruction approvals (e.g., zoning) or permits and either has:

Begun, or caused to begin, a continuous program of actual on-site construction of

the source, to be completed within a reasonable time; or

Entered into binding agreements or contractual obligations, which cannot be

cancelled or modified without substantial loss to the owner or operator, to

undertake a program of actual construction of the source to be completed within a

reasonable time.

For purposes of this definition:

“Construction” shall be determined as any physical change or change in

the method of operation, including but not limited to fabrication, erection,

installation, demolition, or modification of projects eligible for CASA

allowances, as set forth in Sections 225.460 and 225.560.

“A reasonable time” shall be determined considering but not limited to the

following factors: the nature and size of the project, the extent of design

engineering, the amount of off-site preparation, whether equipment can be

fabricated or can be purchased, when the project begins (considering both

the seasonal nature of the construction activity and the existence of other

projects competing for construction labor at the same time, the place of the

environmental permit in the sequence of corporate and overall

governmental approval), and the nature of the project sponsor (e.g.,

private, public, regulated).

“Commence operation”, for purposes of Subparts C, D and E, means:

To have begun any mechanical, chemical, or electronic process, including, for the

purpose of a unit, start-up of a unit’s combustion chamber, except as provided in

40 CFR 96.105, 96.205, or 96.305, as incorporated by reference in Section

225.140.

For a unit that undergoes a physical change (other than replacement of the unit by

a unit at the same source) after the date the unit commences operation as set forth

in the first paragraph of this definition, such date will remain the date of

commencement of operation of the unit, which will continue to be treated as the

same unit.

For a unit that is replaced by a unit at the same source (e.g., repowered), after the

date the unit commences operation as set forth in the first paragraph of this

definition, such date will remain the replaced unit’s date of commencement of

operation, and the replacement unit will be treated as a separate unit with a

separate date for commencement of operation as set forth in this definition as

appropriate.

“Common stack” means a single flue through which emissions from two or more units

are exhausted.

“Compliance account” means:

For the purposes of Subparts D and E, a CAIR NO

Allowance Tracking System

account, established by USEPA for a CAIR NO

source or CAIR NO

Ozone

Season source pursuant to 40 CFR 96, subparts FF and FFFF in which any CAIR

allowance or CAIR NO

Ozone Season allowance allocations for the CAIR

units or CAIR NO

Ozone Season units at the source are initially recorded

and in which are held any CAIR NO

or CAIR NO

Ozone Season allowances

available for use for a control period in order to meet the source’s CAIR NO

CAIR NO

Ozone Season emissions limitations in accordance with Sections

225.410 and 225.510, and 40 CFR 96.154 and 96.354, as incorporated by

reference in Section 225.140. CAIR NO

allowances may not be used for

compliance with the CAIR NO

Ozone Season Trading Program and CAIR NO

Ozone Season allowances may not be used for compliance with the CAIR NO

Annual Trading Program; or

For the purposes of Subpart C, a “compliance account” means a CAIR SO

compliance account, established by the USEPA for a CAIR SO

source pursuant

to 40 CFR 96, subpart FFF, in which any SO

units at the source are initially

recorded and in which are held any SO

allowances available for use for a control

period in order to meet the source’s CAIR SO

emissions limitations in

accordance with Section 225.310 and 40 CFR 96.254, as incorporated by

reference in Section 225.140.

“Control period” means:

For the CAIR SO

and NO

Annual Trading Programs in Subparts C and D, the

period beginning January 1 of a calendar year, except as provided in Sections

225.310(d)(3) and 225.410(d)(3), and ending on December 31 of the same year,

inclusive; or

For the CAIR NO

Ozone Season Trading Program in Subpart E, the period

beginning May 1 of a calendar year, except as provided in Section 225.510(d)(3),

and ending on September 30 of the same year, inclusive.

“Designated representative ” means, for the purposes of Subpart B of this Part, the natural

person as defined in 40 CFR 60.4102, and is the same natural person as the person who is

the designated representative for the CAIR trading and Acid Rain programs.

“Electric generating unit” or “EGU” means a fossil fuel-fired stationary boiler,

combustion turbine or combined cycle system that serves a generator that has a

nameplate capacity greater than 25 MWe and produces electricity for sale.

“Excepted monitoring system” means a sorbent trap monitoring system, as defined in this

section.

“Flue” means a conduit or duct through which gases or other matter is exhausted to the

atmosphere.

“Fossil fuel” means natural gas, petroleum, coal, or any form of solid, liquid, or gaseous

fuel derived from such material.

“Fossil fuel-fired” means the combusting of any amount of fossil fuel, alone or in

combination with any other fuel in any calendar year.

“Generator” means a device that produces electricity.

“Gross electrical output” means the total electrical output from an EGU before making

any deductions for energy output used in any way related to the production of energy.

For an EGU generating only electricity, the gross electrical output is the output from the

turbine/generator set.

“Heat input” means, for the purposes of Subparts C, D, and E, a specified period of time,

the product (in mmBtu/hr) of the gross calorific value of the fuel (in Btu/lb) divided by

1,000,000 Btu/mmBtu and multiplied by the fuel feed rate into a combustion device (in lb

of fuel/time), as measured, recorded and reported to USEPA by the CAIR designated

representative and determined by USEPA in accordance with 40 CFR 96, subpart HH,

HHH, or HHHH, if applicable, and excluding the heat derived from preheated

combustion air, recirculated flue gases, or exhaust from other sources.

“Higher heating value” or “HHV” means the total heat liberated per mass of fuel burned

(Btu/lb), when fuel and dry air at standard conditions undergo complete combustion and

all resultant products are brought to their standard states at standard conditions.

“Input mercury” means the mass of mercury that is contained in the coal combusted

within an EGU.

“Integrated gasification combined cycle” or “IGCC” means a coal-fired electric utility

steam generating unit that burns a synthetic gas derived from coal in a combined-cycle

gas turbine. No coal is directly burned in the unit during operation.

“Long-term cold storage” means the complete shutdown of a unit intended to last for an

extended period of time (at least two calendar years) where notice for long-term cold

storage is provided under 40 CFR 75.61(a)

(7).

“Nameplate capacity” means, starting from the initial installation of a generator, the

maximum electrical generating output (in MWe) that the generator is capable of

producing on a steady-state basis and during continuous operation (when not restricted by

seasonal or other deratings) as of such installation as specified by the manufacturer of the

generator or, starting from the completion of any subsequent physical change in the

generator resulting in an increase in the maximum electrical generating output (in MWe)

that the generator is capable of producing on a steady-state basis and during continuous

operation (when not restricted by seasonal or other deratings), such increased maximum

amount as of completion as specified by the person conducting the physical change.

“NIST traceable elemental mercury standards” means either:

Compressed gas cylinders having known concentrations of elemental

mercury, which have been prepared according to the "EPA Traceability

Protocol for Assay and Certification of Gaseous Calibration Standards"; or

Calibration gases having known concentrations of elemental mercury,

produced by a generator that fully meets the performance requirements of

the "EPA Traceability Protocol for Qualification and Certification of

Elemental Mercury Gas Generators," or an interim version of that protocol

until such time as a final protocol is issued.

“NIST traceable source of oxidized mercury” means a generator that is capable of

providing known concentrations of vapor phase mercuric chloride (HgCl

), and that fully

meets the performance requirements of the "EPA Traceability Protocol for Qualification

and Certification of Mercuric Chloride Gas Generators," or an interim version of that

protocol until such time as a final protocol is issued.

“Oil-fired unit” means a unit combusting fuel oil for more than 15.0 percent of the annual

heat input in a specified year and not qualifying as coal-fired.

“Output-based emission standard” means, for the purposes of Subpart B of this Part, a

maximum allowable rate of emissions of mercury per unit of gross electrical output from

an EGU.

“Potential electrical output capacity” means 33 percent of a unit’s maximum design heat

input, expressed in mmBtu/hr divided by 3.413 mmBtu/MWh, and multiplied by 8,760

hr/yr.

“Project sponsor” means a person or an entity, including but not limited to the owner or

operator of an EGU or a not-for-profit group, that provides the majority of funding for an

energy efficiency and conservation, renewable energy, or clean technology project as

listed in Sections 225.460 and 225.560, unless another person or entity is designated by a

written agreement as the project sponsor for the purpose of applying for NO

allowances

or NO

Ozone Season allowances from the CASA.

“Rated-energy efficiency” means the percentage of thermal energy input that is recovered

as useable energy in the form of gross electrical output, useful thermal energy, or both

that is used for heating, cooling, industrial processes, or other beneficial uses as follows:

For electric generators, rated-energy efficiency is calculated as one kilowatt hour

(3,413 Btu) of electricity divided by the unit’s design heat rate using the higher

heating value of the fuel, and expressed as a percentage.

For combined heat and power projects, rated-energy efficiency is calculated using

the following formula:

Rated-energy efficiency, expressed as percentage.

Gross electrical output of the system expressed in Btu/hr.

UTE =

Useful thermal output from the system that is used for

heating, cooling, industrial processes or other beneficial uses, expressed in

Btu/hr.

Heat input, based upon the higher heating value of fuel, in

Btu/hr.

“Repowered” means, for the purposes of an EGU, replacement of a coal-fired boiler with

one of the following coal-fired technologies at the same source as the coal-fired boiler:

Atmospheric or pressurized fluidized bed combustion;

Integrated gasification combined cycle;

Magnetohydrodynamics;

Direct and indirect coal-fired turbines;

Integrated gasification fuel cells; or

As determined by the USEPA in consultation with the United States Department

of Energy, a derivative of one or more of the technologies under this definition

and any other coal-fired technology capable of controlling multiple combustion

emissions simultaneously with improved boiler or generation efficiency and with

significantly greater waste reduction relative to the performance of technology in

widespread commercial use as of January 1, 2005.

“Rolling 12-month basis” means, for the purposes of Subparts

B and F of this Part, a

determination made on a monthly basis from the relevant data for a particular calendar

month and the preceding 11 calendar months (total of 12 months of data), with two

exceptions. For determinations involving one EGU, calendar months in which the EGU

does not operate (zero EGU operating hours) must not be included in the determination,

and must be replaced by a preceding month or months in which the EGU does operate, so

that the determination is still based on 12 months of data. For determinations involving

two or more EGUs, calendar months in which none of the EGUs covered by the

determination operates (zero EGU operating hours) must not be included in the

determination, and must be replaced by preceding months in which at least one of the

EGUs covered by the determination does operate, so that the determination is still based

on 12 months of data.

“Sorbent Trap Monitoring System” means the equipment required by Appendix B of this

Part for the continuous monitoring of Hg emissions, using paired sorbent traps containing

iodated charcoal (IC) or other suitable reagents. This excepted monitoring system

consists of a probe, the paired sorbent traps, an umbilical line, moisture removal

components, an air tight sample pump, a gas flow meter, and an automated data

acquisition and handling system. The monitoring system samples the stack gas at a rate

proportional to the stack gas volumetric flowrate. The sampling is a batch process.

Using the sample volume measured by the gas flow meter and the results of the analyses

of the sorbent traps, the average mercury concentration in the stack gas for the sampling

period is determined, in units of micrograms per dry standard cubic meter (μg/dscm).

Mercury mass emissions for each hour in the sampling period are calculated using the

average Hg concentration for that period, in conjunction with contemporaneous hourly

measurements of the stack gas flow rate, corrected for the stack moisture content.

“Total energy output” means, with respect to a cogeneration unit, the sum of useful

power and useful thermal energy produced by the cogeneration unit.

“Useful thermal energy” means, for the purpose of a cogeneration unit, the thermal

energy that is made available to an industrial or commercial process, excluding any heat

contained in condensate return or makeup water:

Used in a heating application (e.g., space heating or domestic hot water heating);

Used in a space cooling application (e.g., thermal energy used by an absorption

chiller).

(Source: Amended at 33 Ill. Reg._____, effective _____)

Section 225.140 Incorporations by Reference

The following materials are incorporated by reference. These incorporations do not include any

later amendments or editions.

Appendices A-1 through A-8, Subpart A, and Performance Specifications 2 and 3

of Appendix B of 40 CFR 60, 60.17, 60.45a, 60.49a(k)(1) and (p), 60.50a(h), and

60.4170 through 60.4176 (2005).

40 CFR 72.2 (2005).

cb)

40 CFR 75 (2006), Sections 2.1.1.5, 2.1.1.2, 7.7, and 7.8 of Appendix A to 40

CFR 75, Appendix C to 40 CFR 75, Section 3.3.5 of Appendix F to 40 CFR 75

(2006).40 CFR 75 (2006).

Trading Program, subparts AAA (excluding 40 CFR

96.204 and 96.206), BBB, FFF, GGG, and HHH (2006).

fe)

40 CFR 96, CAIR NO

Annual Trading Program, subparts AA (excluding 40

CFR 96.104, 96.105(b)(2), and 96.106), BB, FF, GG, and HH (2006).

gf)

40 CFR 96, CAIR NO

Ozone Season Trading Program, subparts AAAA

(excluding 40 CFR 96.304, 96.305(b)(2), and 96.306), BBBB, FFFF, GGGG, and

HHHH (2006).

hg)

ASTM. The following methods from the American Society for Testing and

Materials, 100 Barr Harbor Drive, P.O. Box C700, West Conshohocken PA

19428-2959, (610) 832-9585:

ASTM D388-77 (approved February 25, 1977), D388-90 (approved

March 30, 1990), D388-91a (approved April 15, 1991), D388-95

(approved January 15, 1995), D388-98a (approved September 10, 1998),

or D388-99 (approved September 10, 1999, reapproved in 2004),

Classification of Coals by Rank.

ASTM D3173-03, Standard Test Method for Moisture in the Analysis

Sample of Coal and Coke (Approved April 10, 2003).

ASTM D3684-01, Standard Test Method for Total Mercury in Coal by the

Oxygen Bomb Combustion/Atomic Absorption Method (Approved

October 10, 2001).

ASTM D4840-99, Standard Guide for Sampling Chain-of-Custody

Procedures (Reapproved 2004).

54)

ASTM D5865-04, Standard Test Method for Gross Calorific Value of

Coal and Coke (Approved April 1, 2004).

65)

ASTM D6414-01, Standard Test Method for Total Mercury in Coal and

Coal Combustion Residues by Acid Extraction or Wet Oxidation/Cold

Vapor Atomic Absorption (Approved October 10, 2001).

76)

ASTM D6722-01, Standard Test Method for Total Mercury in Coal and

Coal Combustion Residues by Direct Combustion Analysis (2001).

ASTM D6784-02, Standard Test Method for Elemental, Oxidized,

Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired

Stationary Sources (Ontario Hydro Method) (Approved April 10, 2002).

ASTM D6911-03, Standard Guide for Packaging and Shipping

Environmental Samples for Laboratory Analysis.

10)

ASTM D7036-04, Standard Practice for Competence of Air Emission

Testing Bodies.

ih)

Federal Energy Management Program, M&V Guidelines: Measurement and

Verification for Federal Energy Projects, US Department of Energy, Office of

Energy Efficiency and Renewable Energy, Version 2.2, DOE/GO-102000-0960

(September 2000).

(Source: Amended at 33 Ill. Reg. _____, effective _____).

Section 225.150 Commence Commercial Operation

Commence commercial operation means, for the purposes of Subparts C, D and E, with regard to

a unit:

To have begun to produce steam, gas, or other heated medium used to

generate electricity for sale or use, including test generation, except as

provided in 40 CFR 96.105, 96.205, or 96.305, as incorporated by

reference in Section 225.140.

For a unit that is a CAIR SO

unit, CAIR NO

unit, or a CAIR NO

Ozone Season unit pursuant to Sections 225.305, 225.405, and

225.505, respectively, on the date the unit commences commercial

operation on the later of November 15, 1990 or the date the unit

commences commercial operation as defined in subsection (a) of

this Section and that subsequently undergoes a physical change

(other than replacement of the unit by a unit at the same source),

such date will remain the unit’s date of commencement of

commercial operation, which will continue to be treated as the

same unit.

For a unit that is a CAIR SO

unit, CAIR NO

unit, or a CAIR NO

Ozone Season unit pursuant to Sections 225.305, 225.405, and

225.505, respectively, on the later of November 15, 1990 or the

date the unit commences commercial operation as defined in

subsection (a) of this Section and that is subsequently replaced by

a unit at the same source (e.g., repowered), such date will remain

the replaced unit’s date of commencement of commercial

operation, and the replacement unit will be treated as a separate

unit with a separate date for commencement of commercial

operation as defined in subsection (a) or (b) of this Section as

appropriate.

Notwithstanding subsection (a) of this Section and except as provided in

40 CFR 96.105, 96.205, or 96.305 for a unit that is not a CAIR SO

unit,

CAIR NO

unit, or a CAIR NO

Ozone Season unit pursuant to Section

225.305, 225.405, or 225.505, respectively, on the later of November 15,

1990 or the date the unit commences commercial operation as defined in

subsection (a) of this Section, the unit’s date for commencement of

commercial operation will be the date on which the unit becomes a CAIR

unit, CAIR NO

unit, or CAIR NO

Ozone Season unit pursuant to

Section 225.305, 225.405, or 225.505, respectively.

For a unit with a date for commencement of

commercial operation as defined in subsection (b) of this Section

and that subsequently undergoes a physical change (other than

replacement of the unit by a unit at the same source), such date will

remain the unit’s date of commencement of commercial operation,

which shall continue to be treated as the same unit.

For a unit with a date for commencement of commercial operation

as defined in subsection (b) of this Section and that is subsequently

replaced by a unit at the same source (e.g., repowered), such date

will remain the replaced unit’s date of commencement of

commercial operation, and the replacement unit will be treated as a

separate unit with a separate date for commencement of

commercial operation as defined in subsection (a) or (b) of this

Section as appropriate.

(Source: Added at 31 Ill. Reg. 12864, effective August 31, 2007)

SUBPART B: CONTROL OF MERCURY EMISSIONS

FROM COAL-FIRED ELECTRIC GENERATING UNITS

Section 225.200 Purpose

The purpose of this Subpart B is to control the emissions of mercury from coal-fired EGU

operating in Illinois.

Section 225.202 Measurement Methods

Measurement of mercury must be according to the following:

Continuous emission monitoring pursuant to Appendix B to this Part or an

alternative emissions monitoring system, alternative reference method for

measuring emissions, or other alternative to the emissions monitoring and

measurement requirements of Sections 225.240 through 225.290, if such

alternative is submitted to the Agency in writing and approved in writing by the

Manager of the Bureau of Air’s Compliance Section. 40 CFR 75 (2005).

ASTM D3173-03, Standard Test Method for Moisture in the Analysis Sample of

Coal and Coke (Approved April 10, 2003), incorporated by reference in Section

225.140.

ASTM D3684-01, Standard Test Method for Total Mercury in Coal by the

Oxygen Bomb Combustion/Atomic Absorption Method (Approved October 10,

2001), incorporated by reference in Section 225.140.

ASTM D5865-04, Standard Test Method for Gross Calorific Value of Coal and

Coke (Approved April 1, 2004), incorporated by reference in Section 225.140.

ASTM D6414-01, Standard Test Method for Total Mercury in Coal and Coal

Combustion Residues by Acid Extraction or Wet Oxidation/Cold Vapor Atomic

Absorption (Approved October 10, 2001), incorporated by reference in Section

225.140.

ASTM D6722-01, Standard Test Method for Total Mercury in Coal and Coal

Combustion Residues by Direct Combustion Analysis (2001), incorporated by

reference in Section 225.140.

fg)

ASTM D6784-02, Standard Test Method for Elemental, Oxidized, Particle-Bound

and Total Mercury in Flue Gas Generated from Coal-Fired Stationary Sources

(Ontario Hydro Method) (Approved April 10, 2002), incorporated by reference in

Section 225.140.

Emissions testing pursuant to Methods 29, 30A, and 30B in Appendix A-8 to 40

CFR 60.

(Source: Amended at 33 Ill. Reg. _______, effective ________)

Section 225.205 Applicability

The following stationary coal-fired boilers and stationary coal-fired combustion turbines are

EGUs and are subject to this Subpart B:

Except as provided in subsection (b) of this Section, a unit serving, at any time

since the start-up of the unit’s combustion chamber, a generator with nameplate

capacity of more than 25 MWe producing electricity for sale.

For a unit that qualifies as a cogeneration unit during the 12-month period starting

on the date the unit first produces electricity and continues to qualify as a

cogeneration unit, a cogeneration unit serving at any time a generator with

nameplate capacity of more than 25 MWe and supplying in any calendar year

more than one-third of the unit's potential electric output capacity or 219,000

MWh, whichever is greater, to any utility power distribution system for sale. If a

unit qualifies as a cogeneration unit during the 12-month period starting on the

date the unit first produces electricity but subsequently no longer qualifies as a

cogeneration unit, the unit must be subject to subsection (a) of this Section

starting on the day on which the unit first no longer qualifies as a cogeneration

unit.

Section 225.210 Compliance Requirements

Permit Requirements.

The owner or operator of each source with one or more EGUs subject to this

Subpart B at the source must apply for a CAAPP permit that addresses the

applicable requirements of this Subpart B.

Monitoring and Testing Requirements.

The owner or operator of each source and each EGU at the source must

comply with either the monitoring requirements of Sections 225.240

through 225.290 of this Subpart B, the periodic emissions testing

requirements of Section 225.239 of this Subpart B, or an alternative

emissions monitoring system, alternative reference method for measuring

emissions, or other alternative to the emissions monitoring and

measurement requirements of Sections 225.240 through 225.290, if such

alternative is submitted to the Agency in writing and approved in writing

by the Manager of the Bureau of Air’s Compliance Section.

The compliance of each EGU with the mercury requirements of Sections

225.230 and 225.237 of this Subpart B must be determined by the

emissions measurements recorded and reported in accordance with either

Sections 225.240 through 225.290 of this Subpart B, Section 225.239 of

this Subpart B, or an alternative emissions monitoring system, alternative

reference method for measuring emissions, or other alternative to the

emissions monitoring and measurement requirements of Sections 225.240

through 225.290, if such alternative is submitted to the Agency in writing

and approved in writing by the Manager of the Bureau of Air’s

Compliance Section.

Mercury Emission Reduction Requirements

The owner or operator of any EGU subject to this Subpart B must comply with

applicable requirements for control of mercury emissions of Section 225.230 or

Section 225.237 of this Subpart B.

Recordkeeping and Reporting Requirements

Unless otherwise provided, the owner or operator of a source with one or more

EGUs at the source must keep on site at the source each of the documents listed in

subsections (d)(1) through (d)(3) of this Section for a period of five years from the

date the document is created. This period may be extended, in writing by the

Agency, for cause, at any time prior to the end of five years.

All emissions monitoring information gathered in accordance with

Sections 225.240 through 225.290 and all periodic emissions testing

information gathered in accordance with Section 225.239.

Copies of all reports, compliance certifications, and other submissions and

all records made or required or documents necessary to demonstrate

compliance with the requirements of this Subpart B.

Copies of all documents used to complete a permit application and any

other submission under this Subpart B.

Liability.

The owner or operator of each source with one or more EGUs must meet

the requirements of this Subpart B.

Any provision of this Subpart B that applies to a source must also apply to

the owner and operator of such source and to the owner or operator of

each EGU at the source.

Any provision of this Subpart B that applies to an EGU must also apply to

the owner or operator of such EGU.

Effect on Other Authorities. No provision of this Subpart B may be construed as

exempting or excluding the owner or operator of a source or EGU from

compliance with any other provision of an approved State Implementation Plan, a

permit, the Act, or the CAA.

(Source: Amended at 33 Ill. Reg. _______, effective _______)

Section 225.220 Clean Air Act Permit Program (CAAPP) Permit Requirements

Application Requirements.

Each source with one or more EGUs subject to the requirements of this

Subpart B is required to submit a CAAPP permit application that

addresses all applicable requirements of this Subpart B, applicable to each

EGU at the source.

For any EGU that commenced commercial operation:

on or before December 31, 2008, the owner or operator of such

EGUs must submit an initial permit application or application for

CAAPP permit modification that meets the requirements of this

Section on or before December 31, 2008.

after December 31, 2008, the owner or operator of any such EGU

must submit an initial CAAPP permit application or application for

CAAPP modification that meets the requirements of this Section

not later than 180 days before initial startup of the EGU, unless the

construction permit issued for the EGU addresses the requirements

of this Subpart B.

Contents of Permit Applications.

In addition to other information required for a complete application for CAAPP

permit or CAAPP permit modification, the application must include the following

information:

The ORIS (Office of Regulatory Information Systems) or facility code

assigned to the source by the U.S. Department of Energy, Energy

Information Administration, if applicable.

Identification of each EGU at the source.

The intended approach to the monitoring requirements of Sections

225.240 through 225.290 of this Subpart B, or, in the alternative, the

applicant may include its intended approach to the testing requirement of

Section 225.239 of this Subpart B.

The intended approach to the mercury emission reduction requirements of

Section 225.230 or 225.237 of this Subpart B, as applicable.

Permit Contents.

Each CAAPP permit issued by the Agency for a source with one or more

EGUs subject to the requirements of this Subpart B must contain federally

enforceable conditions addressing all applicable requirements of this

Subpart B, which conditions must be a complete and segregable portion of

the source’s entire CAAPP permit.

In addition to conditions related to the applicable requirements of this

Subpart B, each such CAAPP permit must also contain the information

specified under subsection (b) of this Section.

(Source: Amended at 33 Ill. Reg. _______, effective _______)

Section 225.230 Emission Standards for EGUs at Existing Sources

Emission Standards.

Except as provided in Sections 225.230(b) and (d), 225.232 through

225.235, 225.239, and 225.291 through 225.299 of this Subpart B,

beginning Beginning July 1, 2009, the owner or operator of a source with

one or more EGUs subject to this Subpart B that commenced commercial

operation on or before December 31, 2008, must comply with one of the

following standards for each EGU on a rolling 12-month basis:

An emission standard of 0.0080 lb mercury/GWh gross electrical

output; or

A minimum 90-percent reduction of input mercury.

For an EGU complying with subsection (a)(1)(A) of this Section, the

actual mercury emission rate during quality-assured monitor operating

“QAMO” hours of the EGU for each 12-month rolling period, as

monitored in accordance with this Subpart B and calculated as follows,

must not exceed the applicable emission standard:

∑

=÷

Where:

ER = MercuryActual mercury emissions rate of the EGU during QAMO

hours for the particular 12-month rolling period, expressed in

lb/GWh.

MercuryActual mercury emissions of the EGU during QAMO

hours, in lbs, in an individual month in the 12-month rolling

period, as determined in accordance with the emissions monitoring

provisions of this Subpart B.

Gross electrical output of the EGU during QAMO hours, in GWh,

in an individual month in the 12-month rolling period, as

determined in accordance with Section 225.263 of this Subpart B.

For an EGU complying with subsection (a)(1)(B) of this Section, the

actual control efficiency for mercury emissions achieved by the EGU for

each 12-month rolling period, as monitored in accordance with this

Subpart B and calculated as follows, must meet or exceed the applicable

efficiency requirement:

CE = ControlActual control efficiency for mercury emissions of the

EGU during QAMO hours for the particular 12-month rolling

period, expressed as a percent.

MercuryActual mercury emissions of the EGU, in lbs during

QAMO hours, in an individual month in the 12-month rolling

period, as determined in accordance with the emissions monitoring

provisions of this Subpart B.

Amount of mercury in the fuel fired in the EGU during QAMO

hours, in lbs, in an individual month in the 12-month rolling

period, as determined in accordance with Section 225.265 of this

Subpart B. I

is determined by multiplying the amount of mercury

in the fuel fired in the EGU in month

by the number of QAMO

hours in that month, and dividing that product by the number of

EGU operating hours in that month.

Alternative Emission Standards for Single EGUs.

As an alternative to compliance with the emission standards in subsection

(a) of this Section, the owner or operator of the EGU may comply with the

emission standards of this Subpart B by demonstrating that the actual

emissions of mercury from the EGU are less than the allowable emissions

of mercury from the EGU on a rolling 12-month basis.

For the purpose of demonstrating compliance with the alternative emission

standards of this subsection (b), for each rolling 12-month period, the

actual emissions of mercury from the EGU, as monitored in accordance

with this Subpart B, must not exceed the allowable emissions of mercury

from the EGU, as further provided by the following formulas:

≤

∑

Where:

= MercuryActual mercury emissions of the EGU during QAMO hours

for the particular 12-month rolling period.

= Allowable mercury emissions of the EGU during QAMO hours for

the particular 12-month rolling period.

= MercuryActual mercury emissions of the EGU during QAMO hours

in an individual month in the 12-month rolling period.

= Allowable mercury emissions of the EGU during QAMO hours in an

individual month in the 12-month rolling period, based on either the input

mercury to the unit (A

Input i

) or the electrical output from the EGU (A

Output

), as selected by the owner or operator of the EGU for that given month.

is determined by multiplying the allowable mercury emissions based on

either input mercury or electrical output in month i by the number of

QAMO hours in that month, and dividing that product by the number of

EGU operating hours in that month.

Input i

= Allowable mercury emissions of the EGU in an individual month

based on the input mercury to the EGU, calculated as 10.0 percent (or

0.100) of the input mercury to the EGU.

Output i

= Allowable mercury emissions of the EGU in a particular month

based on the electrical output from the EGU, calculated as the product of

the output based mercury limit, i.e., 0.0080 lb/GWh, and the electrical

output from the EGU, in GWh.

If the owner or operator of an EGU does not conduct the necessary

sampling, analysis, and recordkeeping, in accordance with Section

225.265 of this Subpart B, to determine the mercury input to the EGU, the

allowable emissions of the EGU must be calculated based on the electrical

output of the EGU.

If two or more EGUs are served by common stacks and the owner or operator

conducts monitoring for mercury emissions in the common stacks, as provided for

by Sections 1.14 through 1.18 of Appendix B to this Part, 40 CFR 75, Subpart

I,such that the mercury emissions of each EGU are not determined separately,

compliance of the EGUs with the applicable emission standards of this Subpart B

must be determined as if the EGUs were a single EGU.

Alternative Emission Standards for Multiple EGUs.

As an alternative to compliance with the emission standards of subsection

(a) of this Section, the owner or operator of a source with multiple EGUs

may comply with the emission standards of this Subpart B by

demonstrating that the actual emissions of mercury from all EGUs at the

source during QAMO hours are less than the allowable emissions of

mercury from all EGUs at the source on a rolling 12-month basis.

For the purposes of the alternative emission standard of subsection (d)(1)

of this Section, for each rolling 12-month period, the actual emissions of

mercury from all the EGUs at the source during QAMO hours, as

monitored in accordance with this Subpart B, must not exceed the sum of

the allowable emissions of mercury from all the EGUs at the source, as

further provided by the following formulas:

≤

∑

Where:

= Sum of the actual mercury emissions of the EGUs at the source

during QAMO hours.

= Sum of the allowable mercury emissions of the EGUs at the source

during QAMO hours.

= MercuryActual mercury emissions of an individual EGU at the source

during QAMO hours

, as determined in accordance with subsection (b)(2)

of this Section.

= Allowable mercury emissions of an individual EGU at the source

during QAMO hours, as determined in accordance with subsection (b)(2)

of this Section.

n = Number of EGUs covered by the demonstration.

If an owner or operator of a source with two or more EGUs that is relying

on this subsection (d) to demonstrate compliance fails to meet the

requirements of this subsection (d) in a given 12-month rolling period, all

EGUs at such source covered by the compliance demonstration are

considered out of compliance with the applicable emission standards of

this Subpart B for the entire last month of that period.

(Source: Amended at 33 Ill. Reg._______, effective _______)

Section 225.232 Averaging Demonstrations for Existing Sources

Through December 31, 2013, as an alternative to compliance with the emission

standards of Section 225.230(a) of this Subpart B, the owner or operator of an

EGU may comply with the emission standards of this Subpart B by means of an

Averaging Demonstration (Demonstration) that demonstrates that the actual

emissions of mercury from the EGU and other EGUs at the source and other

EGUs at other sources covered by the Demonstration are less than the allowable

emissions of mercury from all EGUs covered by the Demonstration on a rolling

12-month basis.

The EGUs at each source covered by a Demonstration must also comply with one

of the following emission standards on a source-wide basis for the period covered

by the Demonstration:

An emission standard of 0.020 lb mercury/GWh gross electrical output; or

A minimum 75 percent reduction of input mercury.

For the purpose of this Section, compliance must be demonstrated using the

equations in Section 225.230(a)(2), (a)(3), or (d)(2), as applicable, addressing all

EGUs at the sources covered by the Demonstration, rather than by using only the

EGUs at one source.

Limitations on Demonstrations.

The owners or operators of more than one existing source with EGUs can

only participate in Demonstrations that include other existing sources that

they own or operate.

Single Existing Source Demonstrations

The owner or operator of only a single existing source with EGUs

(i.e., City, Water, Light & Power, City of Springfield, ID

167120AAO; Kincaid Generating Station, ID 021814AAB; and

Southern Illinois Power Cooperative/Marion Generating Station,

ID 199856AAC) can only participate in Demonstrations with other

such owners or operators of a single existing source of EGUs.

Participation in Demonstrations under this Section by the owner or

operator of only a single existing source with EGUs must be

authorized through federally enforceable permit conditions for

each such source participating in the Demonstration.

A source may be included in only one Demonstration during each rolling 12-

month period.

The owner or operator of EGUs using Demonstrations to show compliance with

this Subpart B must complete the determination of compliance for each 12-month

rolling period no later than 60 days following the end of the period.

If averaging is used to demonstrate compliance with this Subpart B, the effect of a

failure to demonstrate compliance will be that the compliance status of each

source must be determined under Section 225.230 of this Subpart B as if the

sources were not covered by a Demonstration.

For purposes of this Section, if the owner or operator of any source that

participates in a Demonstration with an owner or operator of a source that does

not maintain the required records, data, and reports for the EGUs at the source, or

that does not submit copies of such records, data, or reports to the Agency upon

request, then the effect of this failure will be deemed to be a failure to

demonstrate compliance and the compliance status of each source must be

determined under Section 225.230 of this Subpart B as if the sources were not

covered by a Demonstration.

Section 225.233 Multi-Pollutant Standards (MPS)

General.

As an alternative to compliance with the emissions standards of Section

225.230(a), the owner of eligible EGUs may elect for those EGUs to

demonstrate compliance pursuant to this Section, which establishes

control requirements and standards for emissions of NO

and SO

, as well

as for emissions of mercury.

For the purpose of this Section, the following requirements apply:

An eligible EGU is an EGU that is located in Illinois and which

commenced commercial operation on or before December 31,

2004; and

Ownership of an eligible EGU is determined based on direct

ownership, by the holding of a majority interest in a company that

owns the EGU or EGUs, or by the common ownership of the

company that owns the EGU, whether through a parent-subsidiary

relationship, as a sister corporation, or as an affiliated corporation

with the same parent corporation, provided that the owner has the

right or authority to submit a CAAPP application on behalf of the

EGU.

The owner of one or more EGUs electing to demonstrate compliance with

this Subpart B pursuant to this Section must submit an application for a

CAAPP permit modification to the Agency, as provided in Section

225.220, that includes the information specified in subsection (b) of this

Section and which clearly states the owner’s election to demonstrate

compliance pursuant to this Section 225.233.

If the owner of one or more EGUs elects to demonstrate

compliance with this Subpart pursuant to this Section, then all

EGUs it owns in Illinois as of July 1, 2006, as defined in

subsection (a)(2)(B) of this Section, must be thereafter subject to

the standards and control requirements of this Section, except as

provided in subsection (a)(3)(B). Such EGUs must be referred to

as a Multi-Pollutant Standard (MPS) Group.

Notwithstanding the foregoing, the owner may exclude from an

MPS Group any EGU scheduled for permanent shutdown that the

owner so designates in its CAAPP application required to be

submitted pursuant to subsection (a)(3) of this Section, with

compliance for such units to be achieved by means of Section

225.235.

When an EGU is subject to the requirements of this Section, the

requirements apply to all owners or operators of the EGU, and to the

designated representative for the EGU.

Notice of Intent.

The owner of one or more EGUs that intends to comply with this Subpart B by

means of this Section must notify the Agency of its intention by December 31,

2007. The following information must accompany the notification:

The identification of each EGU that will be complying with this Subpart B

by means of the multi-pollutant standards contained in this Section, with

evidence that the owner has identified all EGUs that it owned in Illinois as

of July 1, 2006 and which commenced commercial operation on or before

December 31, 2004;

If an EGU identified in subsection (b)(1) of this Section is also owned or

operated by a person different than the owner submitting the notice of

intent, a demonstration that the submitter has the right to commit the EGU

or authorization from the responsible official for the EGU accepting the

application;

The Base Emission Rates for the EGUs, with copies of supporting data

and calculations;

A summary of the current control devices installed and operating on each

EGU and identification of the additional control devices that will likely be

needed for the each EGU to comply with emission control requirements of

this Section, including identification of each EGU in the MPS group that

will be addressed by subsection (c)(1)(B) of this Section, with information

showing that the eligibility criteria for this subsection (b) are satisfied; and

Identification of each EGU that is scheduled for permanent shut down, as

provided by Section 225.235, which will not be part of the MPS Group

and which will not be demonstrating compliance with this Subpart B

pursuant to this Section.

Control Technology Requirements for Emissions of Mercury.

Requirements for EGUs in an MPS Group.

For each EGU in an MPS Group other than an EGU that is

addressed by subsection (c)(1)(B) of this Section for the period

beginning July 1, 2009 (or December 31, 2009 for an EGU for

which an SO

scrubber or fabric filter is being installed to be in

operation by December 31, 2009), and ending on December 31,

2014 (or such earlier date that the EGU is subject to the mercury

emission standard in subsection (d)(1) of this Section), the owner

or operator of the EGU must install, to the extent not already

installed, and properly operate and maintain one of the following

emission control devices:

A Halogenated Activated Carbon Injection System,

complying with the sorbent injection requirements of

subsection (c)(2) of this Section, except as may be

otherwise provided by subsection (c)(4) of this Section, and

followed by a Cold-Side Electrostatic Precipitator or Fabric

Filter; or

ii)

If the boiler fires bituminous coal, a Selective Catalytic

Reduction (SCR) System and an SO

Scrubber.

An owner of an EGU in an MPS Group has two options under this

subsection (c). For an MPS Group that contains EGUs smaller

than 90 gross MW in capacity, the owner may designate any such

EGUs to be not subject to subsection (c)(1)(A) of this Section. Or,

for an MPS Group that contains EGUs with gross MW capacity of

less than 115 MW, the owner may designate any such EGUs to be

not subject to subsection (c)(1)(A) of this Section, provided that

the aggregate gross MW capacity of the designated EGUs does not

exceed 4% of the total gross MW capacity of the MPS Group. For

any EGU subject to one of these two options, unless the EGU is

subject to the emission standards in subsection (d)(2) of this

Section, beginning on January 1, 2013, and continuing until such

date that the owner or operator of the EGU commits to comply

with the mercury emission standard in subsection (d)(2) of this

Section, the owner or operator of the EGU must install and

properly operate and maintain a Halogenated Activated Carbon

Injection System that complies with the sorbent injection

requirements of subsection (c)(2) of this Section, except as may be

otherwise provided by subsection (c)(4) of this Section, and

followed by either a Cold-Side Electrostatic Precipitator or Fabric

Filter. The use of a properly installed, operated, and maintained

Halogenated Activated Carbon Injection System that meets the

sorbent injection requirements of subsection (c)(2) of this Section

is defined as the “principal control technique.”

For each EGU for which injection of halogenated activated carbon is

required by subsection (c)(1) of this Section, the owner or operator of the

EGU must inject halogenated activated carbon in an optimum manner,

which, except as provided in subsection (c)(4) of this Section, is defined as

all of the following:

The use of an injection system designed for effective absorption of

mercury, considering the configuration of the EGU and its

ductwork;

The injection of halogenated activated carbon manufactured by

Alstom, Norit, or Sorbent Technologies, Calgon Carbon’s

FLUEPAC CF Plus, or Calgon Carbon's FLUEPAC MC Plus, or

the injection of any other halogenated activated carbon or sorbent

that the owner or operator of the EGU has demonstrated to have

similar or better effectiveness for control of mercury emissions;

and

The injection of sorbent at the following minimum rates, as

applicable:

For an EGU firing subbituminous coal, 5.0 lbs per million

actual cubic feet or, for any cyclone-fired EGU that will

install a scrubber and baghouse by December 31, 2012, and

which already meets an emission rate of 0.020 lbs

mercury/GWh gross electrical output or at least 75 percent

reduction of input mercury, 2.5 lbs per million actual cubic

feet;

ii)

For an EGU firing bituminous coal, 10.0 lbs per million

actual cubic feet for any cyclone-fired EGU that will install

a scrubber and baghouse by December 31, 2012, and which

already meets an emission rate of 0.020 lb mercury/GWh

gross electrical output or at least 75 percent reduction of

input mercury, 5.0 lbs per million actual cubic feet;

iii)

For an EGU firing a blend of subbituminous and

bituminous coal, a rate that is the weighted average of the

above rates, based on the blend of coal being fired; or

iv)

A rate or rates set lower by the Agency, in writing, than the

rate specified in any of subsections (c)(2)(C)(i),

(c)(2)(C)(ii), or (c)(2)(C)(iii) of this Section on a unit-

specific basis, provided that the owner or operator of the

EGU has demonstrated that such rate or rates are needed so

that carbon injection will not increase particulate matter

emissions or opacity so as to threaten noncompliance with

applicable requirements for particulate matter or opacity.

For the purposes of subsection (c)(2)(C) of this Section, the flue

gas flow rate must be determined for the point of sorbent injection;

provided that this flow rate may shall be assumed to be identical to

the stack gas flow rate in the stack for all units except for those

equipped with activated carbon injection prior to a hot-side

electrostatic precipitator; for units equipped with activated carbon

injection prior to a hot-side electrostatic precipitator, the flue gas

flow rate shall be the gas flow rate at the inlet to the hot-side

electrostatic precipitator, which shall be determined as the stack

flow rate adjusted through the use of Charles’s Law for the

differences in gas temperatures in the stack and at the inlet to the

electrostatic precipitator (V

flow rate in acf and T = gas temperature in Kelvin or Rankine). if

the gas temperatures at the point of injection and the stack are

normally within 100

F, or the flue gas flow rate may otherwise be

calculated from the stack flow rate, corrected for the difference in

gas temperatures.

The owner or operator of an EGU that seeks to operate an EGU with an

activated carbon injection rate or rates that are set on a unit-specific basis

pursuant to subsection (c)(2)(C)(iv) of this Section must submit an

application to the Agency proposing such rate or rates, and must meet the

requirements of subsections (c)(3)(A) and (c)(3)(B) of this Section, subject

to the limitations of subsections (c)(3)(C) and (c)(3)(D) of this Section:

The application must be submitted as an application for a new or

revised federally enforceable operating permit for the EGU, and it

must include a summary of relevant mercury emission data for the

EGU, the unit-specific injection rate or rates that are proposed, and

detailed information to support the proposed injection rate or rates;

and

This application must be submitted no later than the date that

activated carbon must first be injected. For example, the owner or

operator of an EGU that must inject activated carbon pursuant to

subsection (c)(1)(A) of this subsection must apply for unit-specific

injection rate or rates by July 1, 2009. Thereafter, the owner or

operator of the EGU may supplement its application; and

Any decision of the Agency denying a permit or granting a permit with

conditions that set a lower injection rate or rates may be appealed to the

Board pursuant to Section 39 of the Act; and

The owner or operator of an EGU may operate at the injection rate or rates

proposed in its application until a final decision is made on the

application, including a final decision on any appeal to the Board.

During any evaluation of the effectiveness of a listed sorbent, an

alternative sorbent, or other technique to control mercury emissions, the

owner or operator of an EGU need not comply with the requirements of

subsection (c)(2) of this Section for any system needed to carry out the

evaluation, as further provided as follows:

The owner or operator of the EGU must conduct the evaluation in

accordance with a formal evaluation program submitted to the

Agency at least 30 days prior to commencement of the evaluation;

The duration and scope of the evaluation may not exceed the

duration and scope reasonably needed to complete the desired

evaluation of the alternative control technique, as initially

addressed by the owner or operator in a support document

submitted with the evaluation program;

The owner or operator of the EGU must submit a report to the

Agency no later than 30 days after the conclusion of the evaluation

that describes the evaluation conducted and which provides the

results of the evaluation; and

If the evaluation of the alternative control technique shows less

effective control of mercury emissions from the EGU than was

achieved with the principal control technique, the owner or

operator of the EGU must resume use of the principal control

technique. If the evaluation of the alternative control technique

shows comparable effectiveness to the principal control technique,

the owner or operator of the EGU may either continue to use the

alternative control technique in a manner that is at least as effective

as the principal control technique, or it may resume use of the

principal control technique. If the evaluation of the alternative

control technique shows more effective control of mercury

emissions than the control technique, the owner or operator of the

EGU must continue to use the alternative control technique in a

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manner that is more effective than the principal control technique,

so long as it continues to be subject to this subsection (c).

In addition to complying with the applicable recordkeeping and

monitoring requirements in Sections 225.240 through 225.290, the

owner or operator of an EGU that elects to comply with this Subpart B

by means of this Section must also comply with the following additional

requirements:

For the first 36 months that injection of sorbent is required, it must

maintain records of the usage of sorbent, the flueexhaust gas flow

rate from the EGU (and, if the unit is equipped with activated

carbon injection prior to a hot-side electrostatic precipitator, flue

gas temperature at the inlet of the hot-side electrostatic precipitator

and in the stack), and the sorbent feed rate, in pounds per million

actual cubic feet of flueexhaust gas at the injection point, on a

weekly average;

After the first 36 months that injection of sorbent is required, it

must monitor activated sorbent feed rate to the EGU, flue gas

temperature at the point of sorbent injection, and exhaust gas flow

rate in the stackfrom the EGU, and, if the unit is equipped with

activated carbon injection prior to a hot-side electrostatic

precipitator, flue gas temperature at the inlet of the hot-side

electrostatic precipitator and in the stack. It must automatically

recording this data and the sorbent carbon feed rate, in pounds per

million actual cubic feet of flueexhaust

gas at the injection point,

on an hourly average; and

If a blend of bituminous and subbituminous coal is fired in the

EGU, it must keep records of the amount of each type of coal

burned and the required injection rate for injection of activated

carbon, on a weekly basis.

Until June 30, 2012, as an alternative to the CEMS or excepted monitoring

system (sorbent trap system) monitoring, recordkeeping, and reporting

requirements in Sections 225.240 through 225.290, the owner or operator

of an EGU may elect to comply with the emissions testing, monitoring,

recordkeeping, and reporting requirements in Section 225.239(c), (d), (e),

(f)(1) and (2), (h)(2), (i)(3) and (4), and (j)(1).

76)

In addition to complying with the applicable reporting requirements in

Sections 225.240 through 225.290, the owner or operator of an EGU that

elects to comply with this Subpart B by means of this Section must also

submit quarterly reports for the recordkeeping and monitoring conducted

pursuant to subsection (c)(5) of this Section.

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Emission Standards for Mercury.

For each EGU in an MPS Group that is not addressed by subsection

(c)(1)(B) of this Section, beginning January 1, 2015 (or such earlier date

when the owner or operator of the EGU notifies the Agency that it will

comply with these standards) and continuing thereafter, the owner or

operator of the EGU must comply with one of the following standards on

a rolling 12-month basis:

An emission standard of 0.0080 lb mercury/GWh gross electrical

output; or

A minimum 90-percent reduction of input mercury.

For each EGU in an MPS Group that has been addressed under subsection

(c)(1)(B) of this Section, beginning on the date when the owner or

operator of the EGU notifies the Agency that it will comply with these

standards and continuing thereafter, the owner or operator of the EGU

must comply with one of the following standards on a rolling 12-month

basis:

An emission standard of 0.0080 lb mercury/GWh gross electrical

output; or

A minimum 90-percent reduction of input mercury.

Compliance with the mercury emission standard or reduction requirement

of this subsection (d) must be calculated in accordance with Section

225.230(a) or (d), or Section 225.232 until December 31, 2013.

Until June 30, 2012, as an alternative to demonstrating compliance with

the emissions standards in this subsection (d), the owner or operator of an

EGU may elect to comply with the emissions testing requirements in

Section 225.239(a)(4), (b), (c), (d), (e), (f), (g), (h), (i), and (j) of this

Subpart.

Emission Standards for NO

and SO

Emission Standards.

Beginning in calendar year 2012 and continuing in each calendar

thereafter, for the EGUs in each MPS Group, the owner and

operator of the EGUs must comply with an overall NOx annual

emission rate of no more than 0.11 lb/million Btu or an emission

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rate equivalent to 52 percent of the Base Annual Rate of NO

emissions, whichever is more stringent.

Beginning in the 2012 ozone season and continuing in each ozone

season thereafter, for the EGUs in each MPS Group, the owner and

operator of the EGUs must comply with an overall NO

seasonal

emission rate of no more than 0.11 lb/million Btu or an emission

rate equivalent to 80 percent of the Base Seasonal Rate of NO

emissions, whichever is more stringent.

Emission Standards.

Beginning in calendar year 2013 and continuing in calendar year

2014, for the EGUs in each MPS Group, the owner and operator of

the EGUs must comply with an overall SO

annual emission rate

of 0.33 lb/million Btu or a rate equivalent to 44 percent of the Base

Rate of SO

emissions, whichever is more stringent.

Beginning in calendar year 2015 and continuing in each calendar

year thereafter, for the EGUs in each MPS Grouping, the owner

and operator of the EGUs must comply with an overall annual

emission rate for SO

of 0.25 lbs/million Btu or a rate equivalent to

35 percent of the Base Rate of SO

emissions, whichever is more

stringent.

Ameren MPS Group Multi-Pollutant Standard

Notwithstanding the provisions of subsections (e)(1) and (2) of this

Section, this subsection (e)(3) applies to the Ameren MPS Group

as described in the notice of intent submitted by Ameren Energy

Resources in accordance with subsection (b) of this Section.

Emission Standards.

Beginning in the 2010 ozone season and continuing in

each ozone season thereafter, for the EGUs in the Ameren

MPS Group, the owner and operator of the EGUs must

comply with an overall NO

seasonal emission rate of no

more than 0.11 lb/million Btu.

ii)

Beginning in calendar year 2010 and continuing in calendar

year 2011, for the EGUs in the Ameren MPS Group, the

owner and operator of the EGUs must comply with an

overall NO

annual emission rate of no more than 0.14 lb/

million Btu.

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iii)

Beginning in calendar year 2012 and continuing in each

calendar year thereafter, for the EGUs in the Ameren MPS

Group, the owner and operator of the EGUs must comply

with an overall NO

annual emission rate of no more than

0.11 lb/million Btu.

Emission Standards

Beginning in calendar year 2010 and continuing in each

calendar year through 2013, for the EGUs in the Ameren

MPS Group, the owner and operator of the EGUs must

comply with an overall SO

annual emission rate of 0.50

lbs/million Btu.

ii)

In calendar year 2014, for the EGUs in the Ameren MPS

Group, the owner and operator of the EGUs must comply

with an overall SO

annual emission rate of 0.43 lbs/million

Btu.

iii)

Beginning in calendar year 2015 and continuing in calendar

year 2016, for the EGUs in the Ameren MPS Group, the

owner and operator of the EGUs must comply with an

overall SO

annual emission rate of 0.25 lbs/million Btu.

iv)

The owner or operator of EGUs in an MPS Group must not sell or trade to

any person or otherwise exchange with or give to any person NO

allowances allocated to the EGUs in the MPS Group for vintage years

2012 and beyond that would otherwise be available for sale, trade, or

exchange as a result of actions taken to comply with the standards in

subsection (e) of this Section. Such allowances that are not retired for

compliance must be surrendered to the Agency on an annual basis,

Beginning in calendar year 2017 and continuing in each

calendar year thereafter, for the EGUs in the Ameren MPS

Group, the owner and operator of the EGUs must comply

with an overall SO

annual emission rate of 0.23 lbs/million

Btu.

34)

Compliance with the NO

and SO

emission standards must be

demonstrated in accordance with Sections 225.310, 225.410, and 225.510.

The owner or operator of EGUs must complete the demonstration of

compliance before March 1 of the following year for annual standards and

before November 1 for seasonal standards, by which date a compliance

report must be submitted to the Agency.

beginning in calendar year 2013. This provision does not apply to the use,

sale, exchange, gift, or trade of allowances among the EGUs in an MPS

Group.

The owners or operators of EGUs in an MPS Group must not sell or trade

to any person or otherwise exchange with or give to any person SO

allowances allocated to the EGUs in the MPS Group for vintage years

2013 and beyond that would otherwise be available for sale or trade as a

result of actions taken to comply with the standards in subsection (e) of

this Section. Such allowances that are not retired for compliance, or

otherwise surrendered pursuant to a consent decree to which the State of

Illinois is a party, must be surrendered to the Agency on an annual basis,

beginning in calendar year 2014. This provision does not apply to the use,

sale, exchange, gift, or trade of allowances among the EGUs in an MPS

Group.

The provisions of this subsection (f) do not restrict or inhibit the sale or

trading of allowances that become available from one or more EGUs in a

MPS Group as a result of holding allowances that represent over-

compliance with the NO

or SO

standard in subsection (e) of this Section,

once such a standard becomes effective, whether such over-compliance

results from control equipment, fuel changes, changes in the method of

operation, unit shut downs, or other reasons.

For purposes of this subsection (f), NO

and SO

allowances mean

allowances necessary for compliance with Sections 225.310, 225.410, or

225.510, 40 CFR 72, or

subparts Subparts AA and AAAA of 40 CFR 96,

or any future federal NO

or SO

emissions trading programs that modify

or replace these programs. This Section does not prohibit the owner or

operator of EGUs in an MPS Group from purchasing or otherwise

obtaining allowances from other sources as allowed by law for purposes of

complying with federal or state requirements, except as specifically set

forth in this Section.

By Before March 1, 2010, and continuing each year thereafter, the owner

or operator of EGUs in an MPS Group must submit a report to the Agency

that demonstrates compliance with the requirements of this subsection (f)

for the previous calendar year, and which includes identification of any

allowances that have been surrendered to the USEPA or to the Agency and

any allowances that were sold, gifted, used, exchanged, or traded because

they became available due to over-compliance. All allowances that are

required to be surrendered must be surrendered by August 31, unless

USEPA has not yet deducted the allowances from the previous year. A

final report must be submitted to the Agency by August 31 of each year,

verifying that the actions described in the initial report have taken place

or, if such actions have not taken place, an explanation of all changes that

105

have occurred and the reasons for such changes. If USEPA has not

deducted the allowances from the previous year by August 31, the final

report willmust be due, and all allowances required to be surrendered must

be surrendered, within 30 days after such deduction occurs.

Notwithstanding 35 Ill. Adm. Code 201.146(hhh), until an EGU has complied

with the applicable emission standards of subsections (d) and (e) of this Section

for 12 months, the owner or operator of the EGU must obtain a construction

permit for any new or modified air pollution control equipment that it proposes to

construct for control of emissions of mercury, NO

, or SO

(Source: Amended at 33 Ill. Reg. _______, effective ______)

Section 225.234 Temporary Technology-Based Standard for EGUs at Existing Sources

General.

At a source with EGUs that commenced commercial operation on or

before December 31, 2008, for an EGU that meets the eligibility criteria in

subsection (b) of this Section, the owner or operator of the EGU may

temporarily comply with the requirements of this Section through June 30,

2015, as an alternative to compliance with the mercury emission standards

in Section 225.230, as provided in subsections (c), (d), and (e) of this

Section.

An EGU that is complying with the emission control requirements of this

Subpart B by operating pursuant to this Section may not be included in a

compliance demonstration involving other EGUs during the period that is

operating pursuant to this Section.

The owner or operator of an EGU that is complying with this Subpart B by

means of the temporary alternative emission standards of this Section is

not excused from any of the applicable monitoring, recordkeeping, and

reporting requirements set forth in Sections 225.240 through 225.290.

Until June 30, 2012, as an alternative to the CEMS (or an excepted

monitoring system) monitoring, recordkeeping, and reporting

requirements in Sections 225.240 through 225.290, the owner or operator

of an EGU may elect to comply with the emissions testing, monitoring,

recordkeeping, and reporting requirements in Section 225.239(c), (d), (e),

(f)(1) and (2), (h)(2), (i)(3) and (4), and (j)(1).

Eligibility.

To be eligible to operate an EGU pursuant to this Section, the following criteria

must be met for the EGU:

106

The EGU is equipped and operated with the air pollution control

equipment or systems that include injection of halogenated activated

carbon and either a cold-side electrostatic precipitator or a fabric filter.

The owner or operator of the EGU is injecting halogenated activated

carbon in an optimum manner for control of mercury emissions, which

must include injection of Alstrom, Norit, Sorbent Technologies, Calgon

Carbon’s FLUEPAC CF Plus, Calgon Carbon's FLUEPAC MC Plus, or

other halogenated activated carbon that the owner or operator of the EGU

has demonstrated to have similar or better effectiveness for control of

mercury emissions, at least at the following rates set forth in subsections

(b)(2)(A) through (b)(2)(D) of this Section, unless other provisions for

injection of halogenated activated carbon are established in a federally

enforceable operating permit issued for the EGU, using an injection

system designed for effective absorption of mercury, considering the

configuration of the EGU and its ductwork. For the purposes of this

subsection (b)(2), the flue gas flow rate shall be the flow rate in the stack

for all units except for those equipped with activated carbon injection prior

to a hot-side electrostatic precipitator; for units equipped with activated

carbon injection prior to a hot-side electrostatic precipitator, the flue gas

flow rate shall be the gas flow rate at the inlet to the hot-side electrostatic

precipitator, which shall be determined as the stack flow rate adjusted

through the use of Charles’s Law for the differences in gas temperatures in

the stack and at the inlet to the electrostatic precipitator (V

, where V = gas flow rate in acf and T = gas temperature in

Kelvin or Rankine).must be determined for the point of sorbent injection

(provided, however, that this flow rate may be assumed to be identical to

the stack flow rate if the gas temperatures at the point of injection and the

stack are normally within 100º F) or may otherwise be calculated from the

stack flow rate, corrected for the difference in gas temperatures.

For an EGU firing subbituminous coal, 5.0 lbs per million actual

cubic feet.

For an EGU firing bituminous coal, 10.0 lbs per million actual

cubic feet.

For an EGU firing a blend of subbituminous and bituminous coal,

a rate that is the weighted average of the above rates, based on the

blend of coal being fired.

A rate or rates set on a unit-specific basis that are lower than the

rate specified above to the extent that the owner or operator of the

EGU demonstrates that such rate or rates are needed so that carbon

injection would not increase particulate matter emissions or

107

opacity so as to threaten compliance with applicable regulatory

requirements for particulate matter or opacity.

The total capacity of the EGUs that operate pursuant to this Section does

not exceed the applicable of the following values:

For the owner or operator of more than one existing source with

EGUs, 25 percent of the total rated capacity, in MW, of all the

EGUs at the existing sources that it owns or operates, other than

any EGUs operating pursuant to Section 225.235 of this Subpart B.

For the owner or operator of only a single existing source with

EGUs (i.e., City, Water, Light & Power, City of Springfield, ID

167120AAO; Kincaid Generating Station, ID 021814AAB; and

Southern Illinois Power Cooperative/Marion Generating Station,

ID 199856AAC), 25 percent of the total rated capacity, in MW, of

the all the EGUs at the existing sources, other than any EGUs

operating pursuant to Section 225.235.

Compliance Requirements.

Emission Control Requirements.

The owner or operator of an EGU that is operating pursuant to this Section

must continue to maintain and operate the EGU to comply with the criteria

for eligibility for operation pursuant to this Section, except during an

evaluation of the current sorbent, alternative sorbents or other techniques

to control mercury emissions, as provided by subsection (e) of this

Section.

Monitoring and Recordkeeping Requirements.

In addition to complying with all applicable reporting monitoring and

recordkeeping requirements in Sections 225.240 through 225.290 or

Section 225.239(c), (d), (e), (f)(1) and (2), (h)(2), and (i)(3) and (4), the

owner or operator of an EGU operating pursuant to this Section must also:

Through December 31, 2012, it must maintain records of the usage

of activated carbon, the flueexhaust gas flow rate from the EGU

(and, if the unit is equipped with activated carbon injection prior to

a hot-side electrostatic precipitator, flue gas temperature at the inlet

of the hot-side electrostatic precipitator and in the stack), and the

activated carbon feed rate, in pounds per million actual cubic feet

of flueexhaust gas at the injection point, on a weekly average.

108

Beginning January 1, 2013, it must monitor activated carbon feed

rate to the EGU, flue gas temperature at the point of sorbent

injection, and exhaust gas flow rate from the EGU, in the stack,

and, if the unit is equipped with activated carbon injection prior to

a hot-side electrostatic precipitator, flue gas temperature at the inlet

of the hot-side electrostatic precipitator and in the stack. It must

automatically recording this data and the activated carbon feed

rate, in pounds per million actual cubic feet of flueexhaust gas at

the injection point, on an hourly average.

If a blend of bituminous and subbituminous coal is fired in the

EGU, it must maintain records of the amount of each type of coal

burned and the required injection rate for injection of halogenated

activated carbon, on a weekly basis.

Notification and Reporting Requirements.

In addition to complying with all applicable reporting requirements in

Sections 225.240 through 225.290 or Section 225.239(f)(1), (f)(2), and

(j)(1), the owner or operator of an EGU operating pursuant to this Section

must also submit the following notifications and reports to the Agency:

Written notification prior to the month in which any of the

following events will occur:

The EGU will no longer be eligible to operate under this

Section due to a change in operation;

ii)

The type of coal fired in the EGU will change; the mercury

emission standard with which the owner or operator is

attempting to comply for the EGU will change; or

iii)

Operation under this Section will be terminated.

Quarterly reports for the recordkeeping and monitoring or

emissions testing conducted pursuant to subsection (c)(2) of this

Section.

Annual reports detailing activities conducted for the EGU to

further improve control of mercury emissions, including the

measures taken during the past year and activities planned for the

current year.

Applications to Operate under the Technology-Based Standard

Application Deadlines.

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The owner or operator of an EGU that is seeking to operate the

EGU pursuant to this Section must submit an application to the

Agency no later than three months prior to the date on which

compliance with Section 225.230 of this Subpart B would

otherwise have to be demonstrated. For example, the owner or

operator of an EGU that is applying to operate the EGU pursuant

to this Section on June 30, 2010, when compliance with applicable

mercury emission standards must be first demonstrated, must apply

by March 31, 2010 to operate under this Section.

Unless the Agency finds that the EGU is not eligible to operate

pursuant to this Section or that the application for operation

pursuant to this Section does not meet the requirements of

subsection (d)(2) of this Section, the owner or operator of the EGU

is authorized to operate the EGU pursuant to this Section

beginning 60 days after receipt of the application by the Agency.

The owner or operator of an EGU operating pursuant to this

Section must reapply to operate pursuant to this Section:

If it operated the EGU pursuant to this Section 225.234

during the period of June 2010 through December 2012 and

it seeks to operate the EGU pursuant to this Section

225.234 during the period from January 2013 through June

2015.

(ii)

If it is planning a physical change to or a change in the

method of operation of the EGU, control equipment or

practices for injection of activated carbon that is expected to

reduce the level of control of mercury emissions.

Contents of Application. An application to operate an EGU pursuant to

this Section 225.234 must be submitted as an application for a new or

revised federally enforceable operating permit for the EGU, and it must

include the following documents and information:

A formal request to operate pursuant to this Section showing that

the EGU is eligible to operate pursuant to this Section and

describing the reason for the request, the measures that have been

taken for control of mercury emissions, and factors preventing

more effective control of mercury emissions from the EGU.

The applicable mercury emission standard in Section 225.230(a)

with which the owner or operator of the EGU is attempting to

110

comply and a summary of relevant mercury emission data for the

EGU.

If a unit-specific rate or rates for carbon injection are proposed

pursuant to subsection (b)(2) of this Section, detailed information

to support the proposed injection rates.

An action plan describing the measures that will be taken while

operating under this Section to improve control of mercury

emissions. This plan must address measures such as evaluation of

alternative forms or sources of activated carbon, changes to the

injection system, changes to operation of the unit that affect the

effectiveness of mercury absorption and collection, changes to the

particulate matter control device to improve performance, and

changes to other emission control devices. For each measure

contained in the plan, the plan must provide a detailed description

of the specific actions that are planned, the reason that the measure

is being pursued and the range of improvement in control of

mercury that is expected, and the factors that affect the timing for

carrying out the measure, together with the current schedule for the

measure.

Evaluation of Alternative Control Techniques for Mercury Emissions.

During an evaluation of the effectiveness of the current sorbent,

alternative sorbent, or other technique to control mercury emissions, the

owner or operator of an EGU operating pursuant to this Section need not

comply with the eligibility criteria for operation pursuant to this Section as

needed to carry out an evaluation of the practicality and effectiveness of

such technique, subject to the following limitations:

The owner or operator of the EGU must conduct the evaluation in

accordance with a formal evaluation program that it has submitted

to the Agency at least 30 days prior to beginning the evaluation.

The duration and scope of the formal evaluation program must not

exceed the duration and scope reasonably needed to complete the

desired evaluation of the alternative control technique, as initially

addressed by the owner or owner in a support document that it has

submitted with the formal evaluation program pursuant to

subsection (e)(1)(A) of this Section.

Notwithstanding 35 Ill. Adm. Code 201.146(hhh), the owner or

operator of the EGU must obtain a construction permit for any new

or modified air pollution control equipment to be constructed as

part of the evaluation of the alternative control technique.

111

The owner or operator of the EGU must submit a report to the

Agency, no later than 90 days after the conclusion of the formal

evaluation program describing the evaluation that was conducted,

and providing the results of the formal evaluation program.

If the evaluation of the alternative control technique shows less effective

control of mercury emissions from the EGU than achieved with the prior

control technique, the owner or operator of the EGU must resume use of

the prior control technique. If the evaluation of the alternative control

technique shows comparable control effectiveness, the owner or operator

of the EGU may either continue to use the alternative control technique in

an optimum manner or resume use of the prior control technique. If the

evaluation of the alternative control technique shows more effective

control of mercury emissions, the owner or operator of the EGU must

continue to use the alternative control technique in an optimum manner, if

it continues to operate pursuant to this Section.

(Source: Amended at 33 Ill. Reg._______, effective _______)

Section 225.235 Units Scheduled for Permanent Shut Down

The emission standards of Section 225.230(a) are not applicable to an EGU that

will be permanently shut down as described in this Section:

The owner or operator of an EGU that relies on this Section must

complete the following actions before June 30, 2009:

Have notified the Agency that it is planning to permanently shut

down the EGU by the applicable date specified in subsection (a)(3)

or (4) of this Section. This notification must include a description

of the actions that have already been taken to allow the shut down

of the EGU and a description of the future actions that must be

accomplished to complete the shut down of the EGU, with the

anticipated schedule for those actions and the anticipated date of

permanent shut down of the unit.

Have applied for a construction permit or be actively pursuing a

federally enforceable agreement that requires the EGU to be

permanently shut down in accordance with this Section.

Have applied for revisions to the operating permits for the EGU to

include provisions that terminate the authorization to operate the

unit in accordance with this Section.

112

The owner or operator of an EGU that relies on this Section must, before

June 30, 2010, complete the following actions:

Have obtained a construction permit or entered into a federally

enforceable agreement as described in subsection (a)(1)(B) of this

Section; or

Have obtained revised operating permits in accordance with

subsection (a)(1)(C) of this Section.

The plan for permanent shut down of the EGU must provide for the EGU

to be permanently shut down by no later than the applicable date specified

below:

If the owner or operator of the EGU is not constructing a new EGU

or other generating unit to specifically replace the existing EGU,

by December 31, 2010.

If the owner or operator of the EGU is constructing a new EGU or

other generating unit to specifically replace the existing EGU, by

December 31, 2011.

The owner or operator of the EGU must permanently shut down the EGU

by the date specified in subsection (a)(3) of this Section, unless the owner

or operator submits a demonstration to the Agency before the specified

date showing that circumstances beyond its reasonable control (such as

protracted delays in construction activity, unanticipated outage of another

EGU, or protracted shakedown of a replacement unit) have occurred that

interfere with the plan for permanent shut down of the EGU, in which case

the Agency may accept the demonstration as substantiated and extend the

date for shut down of the EGU as follows:

If the owner or operator of the EGU is not constructing a new EGU

or other generating unit to specifically replace the existing EGU,

for up to one year, i.e., permanent shut down of the EGU to occur

by no later than December 31, 2011; or

If the owner or operator of the EGU is constructing a new EGU or

other generating unit to specifically replace the existing EGU, for

up to 18 months, i.e., permanent shutdown of the EGU to occur by

no later than June 30, 2013; provided, however, that after

December 31, 2012, the existing EGU must only operate as a back-

up unit to address periods when the new generating units are not in

service.

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Notwithstanding Sections 225.230 and 225.232, any EGU that is not required to

comply with Section 225.230 pursuant to this Section must not be included when

determining whether any other EGUs at the source or other sources are in

compliance with Section 225.230.

If an EGU, for which the owner or operator of the source has relied upon this

Section in lieu of complying with Section 225.230(a) is not permanently shut

down as required by this Section, the EGU must be considered to be a new EGU

subject to the emission standards in Section 225.237(a) beginning in the month

after the EGU was required to be permanently shut down, in addition to any other

penalties that may be imposed for failure to permanently shut down the EGU in

accordance with this Section.

An EGU that has completed the requirements of subsection (a) of this Section is

exempt from the monitoring and testing requirements in Sections 225.239 and

225.240.

An EGU that is scheduled for permanent shut down pursuant to Section

225.294(b) is exempt from the monitoring and testing requirements in Sections

225.239 and 225.240.

(Source: Amended at 33 Ill. Reg. _______, effective _______)

Section 225.237 Emission Standards for New Sources with EGUs

Standards.

Except as provided in Sections 225.238 and 225.239, the owner or

operator of a source with one or more EGUs, but that previously had not

had any EGUs that commenced commercial operation before January 1,

2009, must comply with one of the following emission standards for each

EGU on a rolling 12-month basis:

An emission standard of 0.0080 lb mercury/GWh gross electrical

output; or

A minimum 90 percent reduction of input mercury.

For this purpose, compliance may be demonstrated using the equations in

Section 225.230(a)(2), (a)(3), or (b)(2).

The initial 12-month rolling period for which compliance with the emission

standards of subsection (a)(1) of this Section must be demonstrated for a new

EGU will commence on the date that the initial performance testing commences

under 40 CFR 60.8. for the mercury emission standard under 40 CFR 60.45a also

commences. The CEMS (or excepted monitoring system) monitoring required by

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this Subpart B for mercury emissions from the EGU must be certified prior to this

date. Thereafter, compliance must be demonstrated on a rolling 12-month basis

based on calendar months.

(Source: Amended at 33 Ill. Reg_______, effective _______)

Section 225.238 Temporary Technology-Based Standard for New Sources with EGUs

General.

At a source with EGUs that previously had not had any EGUs that

commenced commercial operation before January 1, 2009, for an EGU

that meets the eligibility criteria in subsection (b) of this Section, as an

alternative to compliance with the mercury emission standards in Section

225.237, the owner or operator of the EGU may temporarily comply with

the requirements of this Section, through December 31, 2018, as further

provided in subsections (c), (d), and (e) of this Section.

An EGU that is complying with the emission control requirements of this

Subpart B by operating pursuant to this Section may not be included in a

compliance demonstration involving other EGUs at the source during the

period that the temporary technology-based standard is in effect.

The owner or operator of an EGU that is complying with this Subpart B

pursuant to this Section is not excused from applicable monitoring,

recordkeeping, and reporting requirements of Sections 225.240 through

225.290.

Until June 30, 2012, as an alternative to the CEMS (or excepted

monitoring system) monitoring, recordkeeping, and reporting

requirements in Sections 225.240 through 225.290, the owner or operator

of an EGU may elect to comply with the emissions testing, monitoring,

recordkeeping, and reporting requirements in Section 225.239(c), (d), (e),

(f)(1) and (2), (h)(2), (i)(3) and (4), and (j)(1).

Eligibility.

To be eligible to operate an EGU pursuant to this Section, the following criteria

must be met for the EGU:

The EGU is subject to Best Available Control Technology (BACT) for

emissions of sulfur dioxide, nitrogen oxides, and particulate matter, and the

EGU is equipped and operated with the air pollution control equipment or

systems specified below, as applicable to the category of EGU:

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For coal-fired boilers, injection of sorbent or other mercury control

technique (e.g., reagent) approved by the Agency.

For an EGU firing fuel gas produced by coal gasification,

processing of the raw fuel gas prior to combustion for removal of

mercury with a system using a sorbent or other mercury control

technique approved by the Agency.

For an EGU for which injection of a sorbent or other mercury control

technique is required pursuant to subsection (b)(1) of this Section, the

owner or operator of the EGU is injecting sorbent or other mercury control

technique in an optimum manner for control of mercury emissions, which

must include injection of Alstrom, Norit, Sorbent Technologies, Calgon

Carbon’s FLUEPAC CF Plus, Calgon Carbon's FLUEPAC MC Plus, or

other sorbent or other mercury control technique that the owner or

operator of the EGU demonstrates to have similar or better effectiveness

for control of mercury emissions, at least at the rate set forth in the

appropriate of subsections (b)(2)(A) through (b)(2)(C) of this Section,

unless other provisions for injection of sorbent or other mercury control

technique are established in a federally enforceable operating permit

issued for the EGU, with an injection system designed for effective

absorption of mercury. For the purposes of this subsection (b)(2), the flue

gas flow rate shall be the gas flow rate in the stack for all units except for

those equipped with activated carbon injection prior to a hot-side

electrostatic precipitator; for units equipped with activated carbon

injection prior to a hot-side electrostatic precipitator, the flue gas flow rate

shall be the gas flow rate at the inlet to the hot-side electrostatic

precipitator, which shall be determined as the stack flow rate adjusted

through the use of Charles’s Law for the differences in gas temperatures in

the stack and at the inlet to the electrostatic precipitator (V

, where V = gas flow rate in acf and T = gas temperature in

Kelvin or Rankine).must be determined for the point of sorbent injection

or other mercury control technique (provided, however, that this flow rate

may be assumed to be identical to the stack flow rate if the gas

temperatures at the point of injection and the stack are normally within

100º F) , or the flow rate may otherwise be calculated from the stack flow

rate, corrected for the difference in gas temperatures.

For an EGU firing subbituminous coal, 5.0 pounds per million

actual cubic feet.

For an EGU firing bituminous coal, 10.0 pounds per million actual

cubic feet.

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For an EGU firing a blend of subbituminous and bituminous coal,

a rate that is the weighted average of the above rates, based on the

blend of coal being fired.

A rate or rates set on a unit-specific basis that are lower than the

rate specified in subsections (b)(2)(A), (B), and (C) of this Section,

to the extent that the owner or operator of the EGU demonstrates

that such rate or rates are needed so that sorbent injection or other

mercury control technique would not increase particulate matter

emissions or opacity so as to threaten compliance with applicable

regulatory requirements for particulate matter or opacity or cause a

safety issue.

Compliance Requirements.

Emission Control Requirements.

The owner or operator of an EGU that is operating pursuant to this Section

must continue to maintain and operate the EGU to comply with the criteria

for eligibility for operation under this Section, except during an evaluation

of the current sorbent, alternative sorbents, or other techniques to control

mercury emissions, as provided by subsection (e) of this Section.

Monitoring and Recordkeeping Requirements.

In addition to complying with all applicable reporting monitoring and

recordkeeping requirements in Sections 225.240 through 225.290 or

Section 225.239(c), (d), (e), (f)(1) and (2), (h)(2), and( i)(3) and (4), the

owner or operator of a new EGU operating pursuant to this Section must

also:

Monitor sorbent feed rate to the EGU, flue gas temperature at the

point of sorbent injection or other mercury control technique,gas

flow rate in the stack, and, exhaust gas flow rate from the EGU,if

the unit is equipped with activated carbon injection prior to a hot-

side electrostatic precipitator, flue gas temperature at the inlet of the

hot-side electrostatic precipitator and in the stack. It must

automatically recording this data and the sorbent feed rate, in

pounds per million actual cubic feet of flueexhaust gas at the

injection point, on an hourly average.

If a blend of bituminous and subbituminous coal is fired in the

EGU, maintain records of the amount of each type of coal burned

and the required injection rate for injection of sorbent, on a weekly

basis.

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If a mercury control technique other than sorbent injection is

approved by the Agency, monitor appropriate parameter for that

control technique as specified by the Agency.

Notification and Reporting Requirements.

In addition to complying with all applicable reporting requirements of

Sections 225.240 through 225.290 or Section 225.239(f)(1) and (2) and

(j)(1), the owner or operator of an EGU operating pursuant to this Section

must also submit the following notifications and reports to the Agency:

Written notification prior to the month in which any of the

following events will occur: the EGU will no longer be eligible to

operate under this Section due to a change in operation; the type of

coal fired in the EGU will change; the mercury emission standard

with which the owner or operator is attempting to comply for the

EGU will change; or operation under this Section will be

terminated.

Quarterly reports for the recordkeeping and monitoring or

emissions testing conducted pursuant to subsection (c)(2) of this

Section.

Annual reports detailing activities conducted for the EGU to

further improve control of mercury emissions, including the

measures taken during the past year and activities planned for the

current year.

Applications to Operate under the Technology-Based Standard.

Application Deadlines.

The owner or operator of an EGU that is seeking to operate the

EGU pursuant to this Section must submit an application to the

Agency no later than three months prior to the date that

compliance with Section 225.237 would otherwise have to be

demonstrated.

Unless the Agency finds that the EGU is not eligible to operate

pursuant to this Section or that the application for operation under

this Section does not meet the requirements of subsection (d)(2) of

this Section, the owner or operator of the EGU is authorized to

operate the EGU pursuant to this Section beginning 60 days after

receipt of the application by the Agency.

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The owner or operator of an EGU operating pursuant to this

Section must reapply to operate pursuant to this Section if it is

planning a physical change to or a change in the method of

operation of the EGU, control equipment, or practices for injection

of sorbent or other mercury control technique that is expected to

reduce the level of control of mercury emissions.

Contents of Application.

An application to operate pursuant to this Section must be submitted as an

application for a new or revised federally enforceable operating permit for

the new EGU, and it must include the following information:

A formal request to operate pursuant to this Section showing that

the EGU is eligible to operate pursuant to this Section and

describing the reason for the request, the measures that have been

taken for control of mercury emissions, and factors preventing

more effective control of mercury emissions from the EGU.

The applicable mercury emission standard in Section 225.237 with

which the owner or operator of the EGU is attempting to comply

and a summary of relevant mercury emission data for the EGU.

If a unit-specific rate or rates for sorbent or other mercury control

technique injection are proposed pursuant to subsection (b)(2) of

this Section, detailed information to support the proposed injection

rates.

An action plan describing the measures that will be taken while

operating pursuant to this Section to improve control of mercury

emissions. This plan must address measures such as evaluation of

alternative forms or sources of sorbent or other mercury control

technique, changes to the injection system, changes to operation of

the unit that affect the effectiveness of mercury absorption and

collection, and changes to other emission control devices. For

each measure contained in the plan, the plan must provide a

detailed description of the specific actions that are planned, the

reason that the measure is being pursued and the range of

improvement in control of mercury that is expected, and the factors

that affect the timing for carrying out the measure, with the current

schedule for the measure.

Evaluation of Alternative Control Techniques for Mercury Emissions.

During an evaluation of the effectiveness of the current sorbent,

alternative sorbent, or other technique to control mercury emissions, the

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owner or operator of an EGU operating pursuant to this Section does not

need to comply with the eligibility criteria for operation pursuant to this

Section as needed to carry out an evaluation of the practicality and

effectiveness of such technique, further subject to the following

limitations:

The owner or operator of the EGU must conduct the evaluation in

accordance with a formal evaluation program that it has submitted

to the Agency at least 30 days prior to beginning the evaluation.

The duration and scope of the formal evaluation program must not

exceed the duration and scope reasonably needed to complete the

desired evaluation of the alternative control technique, as initially

addressed by the owner or operator in a support document that it

has submitted with the formal evaluation program pursuant to

subsection (e)(1)(A) of this Section.

Notwithstanding 35 Ill. Adm. Code 201.146(hhh), the owner or

operator of the EGU must obtain a construction permit for any new

or modified air pollution control equipment to be constructed as

part of the evaluation of the alternative control technique.

The owner or operator of the EGU must submit a report to the

Agency no later than 90 days after the conclusion of the formal

evaluation program describing the evaluation that was conducted

and providing the results of the formal evaluation program.

If the evaluation of the alternative control technique shows less effective

control of mercury emissions from the EGU than was achieved with the

prior control technique, the owner or operator of the EGU must resume

use of the prior control technique. If the evaluation of the alternative

control technique shows comparable effectiveness, the owner or operator

of the EGU may either continue to use the alternative control technique in

an optimum manner or resume use of the prior control technique. If the

evaluation of the alternative control technique shows more effective

control of mercury emissions, the owner or operator of the EGU must

continue to use the alternative control technique in an optimum manner, if

it continues to operate pursuant to this Section.

(Source: Amended at 33 Ill. Reg. _______, effective _______)

Section 225.239 Periodic Emissions Testing Alternative Requirements

General.

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As an alternative to demonstrating compliance with the emissions

standards of Sections 225.230(a) or 225.237(a), the owner or operator of

an EGU may elect to demonstrate compliance pursuant to the emission

standards in subsection (b) of this Section and the use of quarterly

emissions testing as an alternative to the use of CEMS or an excepted

monitoring system;

The owner or operator of an EGU that elects to demonstrate compliance

pursuant to this Section must comply with the testing, recordkeeping, and

reporting requirements of this Section in addition to other applicable

recordkeeping and reporting requirements in this Subpart;

The alternative method of compliance provided under this subsection may

only be used until June 30, 2012, after which a CEMS (or an excepted

monitoring system) certified in accordance with Section 225.250 of this

Subpart B must be used.

If an owner or operator of an EGU demonstrating compliance pursuant to

Section 225.230, 225.233(d)(1) or (2), 225.237, or 225.294(e)(1)(A)

discontinues use of CEMS (or an excepted monitoring system) before

collecting a full 12 months of data and elects to demonstrate compliance

pursuant to this Section, the data collected prior to that point must be

averaged to determine compliance for such period. In such case, for

purposes of calculating an emission standard or mercury control efficiency

using the equations in Section 225.230(a) or (b), the “12” in the equations

will be replaced by a variable equal to the number of full and partial

months for which the owner or operator collected data from a CEMS or an

excepted monitoring system.

Emission Limits.

Existing Units: Beginning July 1, 2009, the owner or operator of a source

with one or more EGUs subject to this Subpart B that commenced

commercial operation on or before June 30, 2009, must comply with one

of the following standards for each EGU, as determined through quarterly

emissions testing according to subsections (c), (d), (e), and (f) of this

Section:

An emission standard of 0.0080 lb mercury/GWh gross electrical

output; or

A minimum 90-percent reduction of input mercury.

New Units: Beginning within the first 2,160 hours after the

commencement of commercial operations, the owner or operator of a

source with one or more EGUs subject to this Subpart B that commenced

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commercial operation after June 30, 2009, must comply with one of the

following standards for each EGU, as determined through quarterly

emissions testing in accordance with subsections (c), (d), (e), and (f) of

this Section:

An emission standard of 0.0080 lb mercury/GWh gross electrical

output; or

A minimum 90-percent reduction of input mercury.

Initial Emissions Testing Requirements for New Units. The owner or operator of

an EGU that commenced commercial operation after June 30, 2009, and that is

complying by means of this Section must conduct an initial performance test in

accordance with the requirements of subsections (d) and (e) of this Section within

the first 2,160 hours after the commencement of commercial operations.

Emissions Testing Requirements

Subsequent to the initial performance test, emissions tests must be

performed on a quarterly calendar basis in accordance with the

requirements of subsections (d), (e), and (f) of this Section;

Notwithstanding the provisions in subjection (d)(1)(1), owners or

operators of EGUs demonstrating compliance under Section 225.233 or

Sections 225.291 through 225.299, and which have not opted in to the

emission limit provisions of Section 225.233(d)(1) or (d)(2), or Section

225.294(c) pursuant to Section 225.294(e)(1)(B), must perform emissions

testing on a semi-annual calendar basis, where the periods consist of the

months of January through June and July through December, in

accordance with the requirements of subsections (d), (e), and (f)(1) and (2)

of this Section;

Emissions tests which demonstrate compliance with this Subpart must be

performed at least 45 days apart. However, if an emissions test fails to

demonstrate compliance with this Subpart or the emissions test is being

performed subsequent to a significant change in the operations of an EGU

under subsection (h)(2) of this Section, the owner or operator of an EGU

may perform additional emissions tests using the same test protocol

previously submitted in the same period, with less than 45 days in between

emissions tests;

A minimum of three and a maximum of nine emissions test runs, lasting at

least one hour each, shall be conducted and averaged to determine

compliance. All test runs performed will be reported.

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If the EGU shares a common stack with one or more other EGUs, the

owner or operator of the EGU will conduct emissions testing in the duct to

the common stack from each unit, unless the owner or operator of the

EGU considers the combined emissions measured at the common stack as

the mass emissions of mercury for the EGUs for recordkeeping and

compliance purposes.

If an owner or operator of an EGU demonstrating compliance pursuant to

this Section later elects to demonstrate compliance pursuant to the CEMS

monitoring provisions (or excepted monitoring system provisions) in

Section 225.240 of this Subpart, the owner or operator must comply with

the emissions monitoring deadlines in Section 225.240(b)(4) of this

Subpart.

Emissions Testing Procedures

The owner or operator must conduct a compliance test in accordance with

Method 29, 30A, or 30B of 40 CFR 60, Appendix A, as incorporated by

reference in Section 225.140;

Mercury emissions or control efficiency must be measured while the

affected unit is operating at or above 90% of peak load;

For units complying with the control efficiency standard of subsection

(b)(1)(B) or (b)(2)(B) of this Section, Section 225.233(d)(1)(B) or

(d)(2)(B) and electing to demonstrate compliance pursuant to Section

225.233(d)(4), or Section 225.294(c)(2) pursuant to Section

225.294(e)(1)(B), the owner or operator must perform coal sampling as

follows:

in accordance with Section 225.265 of this Subpart at least once

during each day of testing; and

in accordance with Section 225.265 of this Subpart, once each

month in those months when emissions testing is not performed

unless the boiler did not operate or combust coal at all during that

month;

For units complying with the output-based emission standard of

subsection (b)(1)(A) or (b)(2)(A) of this Section, the owner or operator

must monitor gross electrical output for the duration of the testing.

The owner or operator of an EGU may use an alternative emissions testing

method if such alternative is submitted to the Agency in writing and

approved in writing by the Manager of the Bureau of Air’s Compliance

Section.

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Notification Requirements

The owner or operator of an EGU must submit a testing protocol as

described in USEPA’s Emission Measurement Center’s Guideline

Document #42 to the Agency at least 45 days prior to a scheduled

emissions test, except as provided in Section 225.239(h)(2) and (h)(3).

Upon written request directed to the Manager of the Bureau of Air’s

Compliance Section, the Agency may, in its sole discretion, waive the 45-

day requirement. Such waiver shall only be effective if it is provided in

writing and signed by the Manager of the Bureau of Air’s Compliance

Section, or his or her designee;

Notification of a scheduled emissions test must be submitted to the

Agency in writing, directed to the Manager of the Bureau of Air’s

Compliance Section, at least 30 days prior to the expected date of the

emissions test. Upon written request directed to the Manager of the

Bureau of Air’s Compliance Section, the Agency may, in its sole

discretion, waive the 30-day notification requirement. Such waiver shall

only be effective if it is provided in writing and signed by the Manager of

the Bureau of Air’s Compliance Section, or his or her designee.

Notification of the actual date and expected time of testing must be

submitted in writing, directed to the Manager of the Bureau of Air’s

Compliance Section, at least five working days prior to the actual date of

the test;

For an EGU that has elected to demonstrate compliance by use of the

emission standards of subsection (b) of this Section, if an emissions test

performed under the requirements of this Section fails to demonstrate

compliance with the limits of subsection (b) of this Section, the owner or

operator of an EGU may perform a new emissions test using the same test

protocol previously submitted in the same period, by notifying the

Manager of the Bureau of Air’s Compliance Section or his or her designee

of the actual date and expected time of testing at least five working days

prior to the actual date of the test. The Agency may, in its sole discretion,

waive this five-day notification requirement. Such waiver shall only be

effective if it is provided in writing and signed by the Manager of the

Bureau of Air’s Compliance Section, or his or her designee;

In addition to the testing protocol required by subsection (f)(1) of this

Section, the owner or operator of an EGU that has elected to demonstrate

compliance by use of the emission standards of subsection (b) of this

Section, that opts into Section 225.233(d)(1) or (d)(2) early and elects to

demonstrate compliance pursuant to Section 225.233(d)(4), or that opts

into Section 225.294(c) pursuant to Section 225.294(e)(1)(B), must submit

a Continuous Parameter Monitoring Plan to the Agency at least 45 days

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prior to a scheduled emissions test. Upon written request directed to the

Manager of the Bureau of Air’s Compliance Section, the Agency may, in

its sole discretion, waive the 45-day requirement. Such waiver shall only

be effective if it is provided in writing and signed by the Manager of the

Bureau of Air’s Compliance Section, or his or her designee. The

Continuous Parameter Monitoring Plan must detail how the EGU will

continue to operate within the parameters enumerated in the testing

protocol and how those parameters will ensure compliance with the

applicable mercury limit. For example, the Continuous Parameter

Monitoring Plan must include coal sampling as described in Section

225.239(e)(3) of this Subpart and must ensure that an EGU that performs

an emissions test using a blend of coals continues to operate using that

same blend of coal. If the Agency disapproves the Continuous Parameter

Monitoring Plan, the owner or operator of the EGU has 30 days from the

date of receipt of the disapproval to submit more detailed information in

accordance with the Agency’s request.

Compliance Determination

Each successful quarterly emissions test shall determine compliance with

this Subpart for that quarter, except for days in the quarter before and after

a failed test and until a successful re-test as described in subsection(g)(2)

below, where the quarterly periods consist of the months of January

through March, April through June, July through September, and October

through December;

If emissions testing conducted pursuant to this Section fails to demonstrate

compliance, the owner or operator of the EGU will be deemed to have

been out of compliance with this Subpart beginning on the first day of the

current quarter, the last day of certified CEMS data (or certified data from

an excepted monitoring system) demonstrating compliance, or the date on

which a significant change was made pursuant to subsection (h)(2) of this

Section if such a change was made, whichever is later; the EGU will

remain out of compliance until a subsequent emissions test successfully

demonstrates compliance with the limits of this Section.

Operation Requirements

The owner or operator of an EGU that has elected to demonstrate

compliance by use of the emission standards of subsection (b) of this

Section must continue to operate the EGU commensurate with the

Continuous Parameter Monitoring Plan until another Continuous

Parameter Monitoring Plan is developed and submitted to the Agency in

conjunction with the next compliance demonstration, in accordance with

subsection (f)(4) of this Section.

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If the owner or operator makes a significant change to the operations of an

EGU subject to this Section, such as changing from bituminous to

subbituminous coal or any other change that would render the most recent

test no longer representative of current operations according to the

parameters listed in the Continuous Parameter Monitoring Plan, the owner

or operator must submit a testing protocol to the Agency within seven

operating days of the significant change and perform an emissions test

within 30 days of the change if the change takes place more than 30 days

before the end of the current calendar quarter, or within 30 days of the

beginning of the new quarter if the change takes place less than 30 days

before the end of the current calendar quarter. In addition, the owner or

operator of an EGU that has elected to demonstrate compliance by use of

the emission standards of subsection (b) of this Section, Section

225.233(d)(1) or (d)(2), or Section 225.294(c) pursuant to Section

225.294(e)(1)(B) must submit an updated Continuous Parameter

Monitoring Plan within seven operating days of the significant change.

If a blend of bituminous and subbituminous coal is fired in the EGU, the

owner or operator of the EGU must ensure that the EGU continues to

operate using the same blend that was used during the most recent

successful emissions test. If the blend of coal changes, the owner or

operator of the EGU must re-test in accordance with subsections (d), (e),

(f), and (g) of this Section within 30 days of the change in coal blend,

notwithstanding the requirement of subsection (d)(3) of this Section that

there must be 45 days between emissions tests.

Recordkeeping

The owner or operator of an EGU and its designated representative must

comply with all applicable recordkeeping and reporting requirements in

this Section.

Continuous Parameter Monitoring. The owner or operator of an EGU

must maintain records to substantiate that the EGU is operating in

compliance with the parameters listed in the Continuous Parameter

Monitoring Plan, detailing the parameters that impact mercury reduction

and including the following records related to the emissions of mercury:

For an EGU for which the owner or operator is complying with

this Subpart B pursuant to Section 225.239(b)(1)(B) or

225.239(b)(2)(B), records of the daily mercury content of coal

used (parts per million) and the daily and quarterly input mercury

(lbs).

For an EGU for which the owner or operator of an EGU complying

with this Subpart B pursuant to Section 225.239(b)(1)(A) or

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225.239(b)(2)(A), records of the daily and quarterly gross

electrical output (MWh) on an hourly basis.:

The owner or operator of an EGU using activated carbon injection must

also comply with the following requirements:

Maintain records of the usage of sorbent, the exhaust gas flow rate

from the EGU, and the sorbent feed rate, in pounds per million

actual cubic feet of exhaust gas at the injection point, on a weekly

average;

If a blend of bituminous and subbituminous coal is fired in the

EGU, keep records of the amount of each type of coal burned and

the required injection rate for injection of activated carbon, on a

weekly basis.

The owner or operator of an EGU must retain all records required by this

Section at the source for a period of five years from the date the document

is created unless otherwise provided in the CAAPP permit issued for the

source and must make a copy of any record available to the Agency

promptly upon request. This period may be extended in writing by the

Agency, for cause, at any time prior to the end of five years.

The owner or operator of an EGU demonstrating compliance pursuant to

this Section must monitor and report the heat input rate at the unit level.

The owner or operator of an EGU demonstrating compliance pursuant to

this Section must perform and report coal sampling in accordance with

subsection 225.239(e)(3).

Reporting Requirements

An owner or operator of an EGU shall submit to the Agency a Final

Source Test Report for each periodic emissions test within 45 days after

the test is completed. The Final Source Test Report will be directed to the

Manager of the Bureau of Air’s Compliance Section, or his or her

designee, and include at a minimum:

A summary of results;

A description of test methods, including a description of sampling

points, sampling train, analysis equipment, and test schedule, and a

detailed description of test conditions, including:

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Process information, including but not limited to modes of

operation, process rate, and fuel or raw material

consumption;

ii)

Control equipment information (i.e., equipment condition

and operating parameters during testing);

iii)

A discussion of any preparatory actions taken (i.e.,

inspections, maintenance, and repair); and

iv)

Data and calculations, including copies of all raw data

sheets and records of laboratory analyses, sample

calculations, and data on equipment calibration.

The owner or operator of a source with one or more EGUs demonstrating

compliance with Subpart B in accordance with this Section must submit to

the Agency a Quarterly Certification of Compliance within 45 days

following the end of each calendar quarter. Quarterly certifications of

compliance must certify whether compliance existed for each EGU for the

calendar quarter covered by the certification. If the EGU failed to comply

during the quarter covered by the certification, the owner or operator must

provide the reasons the EGU or EGUs failed to comply and a full

description of the noncompliance (i.e., tested emissions rate, coal sample

data, etc.). In addition, for each EGU, the owner or operator must provide

the following appropriate data to the Agency as set forth in this Section.

A list of all emissions tests performed within the calendar quarter

covered by the Certification and submitted to the Agency for each

EGU, including the dates on which such tests were performed.

Any deviations or exceptions each month and discussion of the

reasons for such deviations or exceptions.

All Quarterly Certifications of Compliance required to be

submitted must include the following certification by a responsible

official:

I certify under penalty of law that this document and all

attachments were prepared under my direction or supervision in

accordance with a system designed to assure that qualified

personnel properly gather and evaluate the information submitted.

Based on my inquiry of the person or persons directly responsible

for gathering the information, the information submitted is, to the

best of my knowledge and belief, true, accurate, and complete. I

am aware that there are significant penalties for submitting false

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information, including the possibility of fine and imprisonment for

knowing violations.

Deviation Reports. For each EGU, the owner or operator must promptly

notify the Agency of deviations from any of the requirements of this

Subpart B. At a minimum, these notifications must include a description

of such deviations within 30 days after discovery of the deviations, and a

discussion of the possible cause of such deviations, any corrective actions,

and any preventative measures taken.

(Source: Added at 33 Ill. Reg_______, effective _______)

Section 225.240 General Monitoring and Reporting Requirements

The owner or operator of an EGU must comply with the monitoring, recordkeeping, and

reporting requirements as provided in this Section, Sections 225.250 through 225.290 of this

Subpart B, and Sections 1.14 through 1.18 of Appendix B to this Part. Subpart I of 40 CFR 75

(sections 75.80 through 75.84), incorporated by reference in Section 225.140. If the EGU

utilizes a common stack with units that are not EGUs and the owner or operator of the EGU does

not conduct emissions monitoring in the duct to the common stack from each EGU, the owner or

operator of the EGU must conduct emissions monitoring in accordance with Section 1.16(b)(2)

of Appendix B to this Part 40 CFR 75.82(b)(2) and this Section, including monitoring in the duct

to the common stack from each unit that is not an EGU, unless the owner or operator of the EGU

counts the combined emissions measured at the common stack as the mass emissions of mercury

for the EGUs for recordkeeping and compliance purposes.

Requirements for installation, certification, and data accounting. The owner or

operator of each EGU must:

Install all monitoring systems required pursuant to this Section and

Sections 225.250 through 225.290 for monitoring mercury mass emissions

(including all systems required to monitor mercury concentration, stack

gas moisture content, stack gas flow rate, and CO

or O

concentration, as

applicable, in accordance with Sections 1.15 and 1.16 of Appendix B to

this Part). 40 CFR 75.81 and 75.82).

Successfully complete all certification tests required pursuant to Section

225.250 and meet all other requirements of this Section, Sections 225.250

through 225.290, and Sections 1.14 through 1.18 of Appendix B to this

Part subpart I of 40 CFR Part 75 applicable to the monitoring systems

required under subsection (a)(1) of this Section.

Record, report, and assure the quality of the data from the monitoring

systems required under subsection (a)(1) of this Section.

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If the owner or operator elects to use the low mass emissions excepted

monitoring methodology for an EGU that emits no more than 464 ounces

(29 pounds) of mercury per year pursuant to Section 1.15(b) of Appendix

B to this Part 40 CFR 75.81(b), it must perform emissions testing in

accordance with Section 1.15(c) of Appendix B to this Part 40 CFR

75.81(c) to demonstrate that the EGU is eligible to use this excepted

emissions monitoring methodology, as well as comply with all other

applicable requirements of Section 1.15(b) through (f) of Appendix B to

this Part. 40 CFR 75.81(b) through (f). Also, the owner or operator must

submit a copy of any information required to be submitted to the USEPA

pursuant to these provisions to the Agency. The initial emissions testing

to demonstrate eligibility of an EGU for the low mass emissions excepted

methodology must be conducted by the applicable of the following dates:

If the EGU has commenced commercial operation before July 1,

2008, at least by July January 1, 2009, or 45 days prior to relying

on the low mass emissions excepted methodology, whichever date

is later.

If the EGU has commenced commercial operation on or after July

1, 2008, at least 45 days prior to the applicable date specified

pursuant to subsection (b)(2) of this Section or 45 days prior to

relying on the low mass emissions excepted methodology,

whichever date is later.

Emissions Monitoring Deadlines. The owner or operator must meet the emissions

monitoring system certification and other emissions monitoring requirements of

subsections (a)(1) and (a)(2) of this Section on or before the applicable of the

following dates. The owner or operator must record, report, and quality-assure

the data from the emissions monitoring systems required under subsection (a)(1)

of this Section on and after the applicable of the following dates:

For the owner or operator of an EGU that commences commercial

operation before July 1, 2008, by July January 1, 2009, except that an

EGU in an MPS Group for which an SO

scrubber or fabric filter is being

installed to be in operation by December 31, 2009, as described in Section

225.233(c)(1)(A), shall have a date of January 1, 2010.

For the owner or operator of an EGU that commences commercial

operation on or after July 1, 2008, by 90 unit operating days or 180

calendar days, whichever occurs first, after the date on which the EGU

commences commercial operation.

For the owner or operator of an EGU for which construction of a new

stack or flue or installation of add-on mercury emission controls, a flue

gas desulfurization system, a selective catalytic reduction system, a fabric

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filter, or a compact hybrid particulate collector system is completed after

the applicable deadline pursuant to subsection (b)(1) or (b)(2) of this

Section, by 90 unit operating days or 180 calendar days, whichever occurs

first, after the date on which emissions first exit to the atmosphere through

the new stack or flue, add-on mercury emission controls, flue gas

desulfurization system, selective catalytic reduction system, fabric filter,

or compact hybrid particulate collector system.

For an owner or operator of an EGU that originally elected to demonstrate

compliance pursuant to the emissions testing requirements in Section

225.239, by the first day of the calendar quarter following the last

emissions test demonstrating compliance with Section 225.239.

Reporting Data.

Except as provided in subsection (c)(2) of this Section, Thethe owner or

operator of an EGU that does not meet the applicable emissions

monitoring date set forth in subsection (b) of this Section for any

emissions monitoring system required pursuant to subsection (a)(1) of this

Section must begin periodic emissions testing in accordance with Section

225.239., for each such monitoring system, determine, record, and report

the maximum potential (or, as appropriate, the minimum potential) values

for mercury concentration, the stack gas flow rate, the stack gas moisture

content, and any other parameters required to determine mercury mass

emissions in accordance with 40 CFR 75.80(g).

The owner or operator of an EGU that does not meet the applicable

emissions monitoring date set forth in subsection (b)(3) of this Section for

any emissions monitoring system required pursuant to subsection (a)(1) of

this Section must, for each such monitoring system, determine, record, and

report substitute data using the applicable missing data procedures as set

forth in40 CFR 75.80(f), in lieu of the maximum potential (or, as

appropriate, minimum potential) values for a parameter, if the owner or

operator demonstrates that there is continuity between the data streams for

that parameter before and after the construction or installation pursuant to

subsection (b)(3) of this Section.

Prohibitions.

No owner or operator of an EGU may use any alternative emissions

monitoring system, alternative reference method for measuring emissions,

or other alternative to the emissions monitoring and measurement

requirements of this Section and Sections 225.250 through 225.290, unless

such alternative is submitted to the Agency in writing and approved in

writing by the Manager of the Bureau of Air’s Compliance Section, or his

or her designee. promulgated by the USEPA and approved in writing by

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the Agency, or the use of such alternative is approved in writing by the

Agency and USEPA.

No owner or operator of an EGU may operate its EGU so as to discharge,

or allow to be discharged, mercury emissions to the atmosphere without

accounting for all such emissions in accordance with the applicable

provisions of this Section, Sections 225.250 through 225.290, and

Sections 1.14 through 1.18 of Appendix B to this Part, unless

demonstrating compliance pursuant to Section 225.239, as applicable.

subpart I of 40 CFR 75.

No owner or operator of an EGU may disrupt the CEMS (or excepted

monitoring system), any portion thereof, or any other approved emission

monitoring method, and thereby avoid monitoring and recording mercury

mass emissions discharged into the atmosphere, except for periods of

recertification or periods when calibration, quality assurance testing, or

maintenance is performed in accordance with the applicable provisions of

this Section, Sections 225.250 through 225.290, and Sections 1.14 through

1.18 of Appendix B to this Part. subpart I of 40 CFR 75.

No owner or operator of an EGU may retire or permanently discontinue

use of the CEMS (or excepted monitoring system) or any component

thereof, or any other approved monitoring system pursuant to this Subpart

B, except under any one of the following circumstances:

The owner or operator is monitoring emissions from the EGU with

another certified monitoring system that has been approved, in

accordance with the applicable provisions of this Section, Sections

225.250 through 225.290 of this Subpart B, and Sections 1.14

through 1.18 of Appendix B to this Part, subpart I of 40 CFR 75,

by the Agency for use at that EGU and that provides emission data

for the same pollutant or parameter as the retired or discontinued

monitoring system; or

The owner or operator or designated representative submits

notification of the date of certification testing of a replacement

monitoring system for the retired or discontinued monitoring

system in accordance with Section 225.250(a)(3)(A).

The owner or operator is demonstrating compliance pursuant to the

applicable subsections of Section 225.239.

Long-term Cold Storage.

The owner or operator of an EGU that is in long-term cold storage is subject to

the provisions of 40 CFR 75.4 and 40 CFR 75.64, incorporated by reference in

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Section 225.140, relating to monitoring, recordkeeping, and reporting for units in

long-term cold storage.

(Source: Amended at 33 Ill. Reg. ________, effective _______)

Section 225.250 Initial Certification and Recertification Procedures for Emissions

Monitoring

The owner or operator of an EGU must comply with the following initial

certification and recertification procedures for a CEMS (i.e., a CEMS or an

excepted monitoring system (sorbent trap monitoring system) pursuant to Section

1.3 of Appendix B to this Part 40 CFR 75.15, incorporated by reference in Section

225.140) required by Section 225.240(a)(1). The owner or operator of an EGU

that qualifies for, and for which the owner or operator elects to use, the low-mass-

emissions excepted methodology pursuant to Section 1.15(b) of Appendix B to

this Part 40 CFR 75.81(b), incorporated by reference in Section 225.140, must

comply with the procedures set forth in subsection (c) of this Section.

Requirements for Initial Certification. The owner or operator of an EGU

must ensure that, for each CEMS (or excepted monitoring system)

required by Section 225.240(a)(1) (including the automated data

acquisition and handling system), the owner or operator successfully

completes all of the initial certification testing required pursuant to Section

1.4 of Appendix B to this Part 40 CFR 75.80(d), incorporated by reference

in Section 225.140, by the applicable deadline in Section 225.240(b). In

addition, whenever the owner or operator of an EGU installs a monitoring

system to meet the requirements of this Subpart B in a location where no

such monitoring system was previously installed, the owner or operator

must successfully complete the initial certification requirements of Section

1.4 of Appendix B to this Part40 CFR 75.80(d).

Requirements for Recertification. Whenever the owner or operator of an

EGU makes a replacement, modification, or change in any certified

CEMS, or an excepted monitoring system (sorbent

trap monitoring

system) pursuant to Section 1.3 of Appendix B to this Part 40 CFR 75.15,

and required by Section 225.240(a)(1), that may significantly affect the

ability of the system to accurately measure or record mercury mass

emissions or heat input rate or to meet the quality-assurance and quality-

control requirements of Section 1.5 of Appendix B to this Part 40 CFR

75.21 or Exhibit B to Appendix B to this PartAppendix B to 40 CFR 75,

each incorporated by reference in Section 225.140, the owner or operator

of an EGU must recertify the monitoring system in accordance with

Section 1.4(b) of Appendix B to this Part. 40 CFR 75.20(b), incorporated

by reference in Section 225.140. Furthermore, whenever the owner or

operator of an EGU makes a replacement, modification, or change to the

flue gas handling system or the EGU’s operation that may significantly

133

change the stack flow or concentration profile, the owner or operator must

recertify each CEMS, and each excepted monitoring system (sorbent trap

monitoring system) pursuant to Section 1.3 to Appendix B to this Part, 40

CFR 75.15, whose accuracy is potentially affected by the change, all in

accordance with Section 1.4(b) to Appendix B to this Part. 40 CFR

75.20(b). Examples of changes to a CEMS that require recertification

include, but are not limited to, replacement of the analyzer, complete

replacement of an existing CEMS, or change in location or orientation of

the sampling probe or site.

Approval Process for Initial Certification and Recertification. Subsections

(a)(3)(A) through (a)(3)(D) of this Section apply to both initial

certification and recertification of a CEMS (or an excepted monitoring

system) required by Section 225.240(a)(1). For recertifications, the words

“certification” and “initial certification” are to be read as the word

“recertification”, the word “certified” is to be read as the word

“recertified”, and the procedures set forth in Section 1.4(b)(5) of Appendix

B to this Part 40 CFR 75.20(b)(5) are to be followed in lieu of the

procedures set forth in subsection (a)(3)(E) of this Section.

Notification of Certification. The owner or operator must submit

written notice of the dates of certification testing to the Agency,

directed to the Manager of the Bureau of Air’s Compliance

SectionUSEPA Region 5, and the Administrator of the USEPA

written notice of the dates of certification testing, in accordance

with Section 225.270.

Certification Application. The owner or operator must submit to

the Agency a certification application for each monitoring system.

A complete certification application must include the information

specified in 40 CFR 75.63, incorporated by reference in Section

225.140.

Provisional Certification Date. The provisional certification date

for a monitoring system must be determined in accordance with

Section 1.4(a)(3) of Appendix B to this Part. 40 CFR 75.20(a)(3),

incorporated by reference in Section 225.140. A provisionally

certified monitoring system may be used pursuant to this Subpart B

for a period not to exceed 120 days after receipt by the Agency of

the complete certification application for the monitoring system

pursuant to subsection (a)(3)(B) of this Section. Data measured

and recorded by the provisionally certified monitoring system, in

accordance with the requirements of Appendix B to this Part 40

CFR 75, will be considered valid quality-assured data (retroactive

to the date and time of provisional certification), provided that the

Agency does not invalidate the provisional certification by issuing

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a notice of disapproval within 120 days after the date of receipt by

the Agency of the complete certification application.

Certification Application Approval Process. The Agency must

issue a written notice of approval or disapproval of the certification

application to the owner or operator within 120 days after receipt

of the complete certification application required by subsection

(a)(3)(B) of this Section. In the event the Agency does not issue a

written notice of approval or disapproval within the 120-day

period, each monitoring system that meets the applicable

performance requirements of Appendix B to this Part 40 CFR 75

and which is included in the certification application will be

deemed certified for use pursuant to this Subpart B.

Approval Notice. If the certification application is

complete and shows that each monitoring system meets the

applicable performance requirements of Appendix B to this

Part, 40 CFR 75, then the Agency must issue a written

notice of approval of the certification application within

120 days after receipt.

ii)

Incomplete Application Notice. If the certification

application is not complete, then the Agency must issue a

written notice of incompleteness that sets a reasonable date

by which the owner or operator must submit the additional

information required to complete the certification

application. If the owner or operator does not comply with

the notice of incompleteness by the specified date, the

Agency may issue a notice of disapproval pursuant to

subsection (a)(3)(D)(iii) of this Section. The 120-day

review period will not begin before receipt of a complete

certification application.

iii)

Disapproval Notice. If the certification application shows

that any monitoring system does not meet the performance

requirements of Appendix B to this Part, 40 CFR 75, or if

the certification application is incomplete and the

requirement for disapproval pursuant to subsection

(a)(3)(D)(ii) of this Section is met, the Agency must issue a

written notice of disapproval of the certification

application. Upon issuance of such notice of disapproval,

the provisional certification is invalidated, and the data

measured and recorded by each uncertified monitoring

system will not be considered valid quality-assured data

beginning with the date and hour of provisional

certification (as defined pursuant to Section 1.4(a)(3) of

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Appendix B to this Part). 40 CFR 75.20(a)(3)). The owner

or operator must follow the procedures for loss of

certification set forth in subsection (a)(3)(E) of this Section

for each monitoring system that is disapproved for initial

certification.

iv)

Audit Decertification. The Agency may issue a notice of

disapproval of the certification status of a monitor in

accordance with Section 225.260(cb).

Procedures for Loss of Certification. If the Agency issues a notice

of disapproval of a certification application pursuant to subsection

(a)(3)(D)(iii) of this Section or a notice of disapproval of

certification status pursuant to subsection (a)(3)(D)(iv) of this

Section, the owner or operator must fulfill the following

requirements:

The owner or operator must substitute the following values

for each disapproved monitoring system and for each hour

of EGU operation during the period of invalid data

specified pursuant to 40 CFR 75.20(a)(4)(iii) or 75.21(e),

continuing until the applicable date and hour specified

pursuant to 40 CFR 75.20(a)(5)(i), each incorporated by

reference in Section 225.140. For a disapproved mercury

pollutant concentration monitor and disapproved flow

monitor, respectively, the maximum potential concentration

of mercury and the maximum potential flow rate, as

defined in sections 2.1.7.1 and 2.1.4.1 of Appendix A to 40

CFR 75, incorporated by reference in Section 225.140. For

a disapproved moisture monitoring system and disapproved

diluent gas monitoring system, respectively, the minimum

potential moisture percentage and either the maximum

potential CO

concentration or the minimum potential O

concentration (as applicable), as defined in 2.1.5, 2.1.3.1,

and 2.1.3.2 of Appendix A to 40 CFR 75, incorporated by

reference in Section 225.140. For a disapproved excepted

monitoring system (sorbent trap monitoring system)

pursuant to 40 CFR 75.15 and disapproved flow monitor,

respectively, the maximum potential concentration of

mercury and maximum potential flow rate, as defined in

sections 2.1.7.1 and 2.1.4.1 of Appendix A to 40 CFR 75,

incorporated by reference in section 225.140.

iii)

The owner or operator must submit a notification of

certification retest dates and a new certification application

136

in accordance with subsections (a)(3)(A) and (B) of this

Section.

iiiii)

The owner or operator must repeat all certification tests or

other requirements that were failed by the monitoring

system, as indicated in the Agency’s notice of disapproval,

no later than 30 unit operating days after the date of

issuance of the notice of disapproval.

Exemption.

If an emissions monitoring system has been previously certified in

accordance with Appendix B to this Part 40 CFR 75 and the applicable

quality assurance and quality control requirements of Section 1.5 and

Exhibit B to Appendix B to this Part 40 CFR 75.21 and Appendix B to 40

CFR 75 are fully met, the monitoring system will be exempt from the

initial certification requirements of this Section.

The recertification provisions of this Section apply to an emissions

monitoring system required by Section 225.240(a)(1) exempt from initial

certification requirements pursuant to subsection (a)(1) of this Section.

Initial certification and recertification procedures for EGUs using the mercury low

mass emissions excepted methodology pursuant to Section 1.15(b) of Appendix B

to this Part. 40 CFR 75.81(b). The owner or operator that has elected to use the

mercury-low-mass-emissions-excepted methodology for a qualified EGU

pursuant to Section 1.15(b) to Appendix B to this Part

40 CFR 75.81(b) must

meet the applicable certification and recertification requirements in Section

1.15(c) through (f) to Appendix B to this Part. 40 CFR 75.81(c) through (f),

incorporated by reference in Section 225.140.

Certification Applications. The owner or operator of an EGU must submit an

application to the Agency within 45 days after completing all initial certification

or recertification tests required pursuant to this Section, including the information

required pursuant to 40 CFR 75.63, incorporated by reference in Section 225.140.

(Source: Amended at 33 Ill. Reg. _______, effective _______)

Section 225.260 Out of Control Periods and Data Availability for Emission Monitors

Out of control periods must be determined in accordance with Section 1.7 of

Appendix B.

ba)

Monitor data availability for all EGUs using a CEMS (or an excepted monitoring

system) shall be greater than or equal to 75 percent; that is, quality assured data

must be recorded by a certified primary monitor, a certified redundant or non-

137

redundant backup monitor, or reference method for that unit at least 75 percent of

the time the unit is in operation. Monitor data availability must be determined in

accordance with Section 1.8 of Appendix B following initial certification of the

required CO

, O

, flow monitor, or mercury concentration or moisture monitoring

system(s) at a particular unit or stack location; monitor data availability shall be

determined on a calendar quarterly basis until June 30, 2012, and on a rolling 12-

month average basis from July 1, 2012, forward (the first such 12-month period

will cover July 1, 2012, through June 30, 2013). Compliance with the percent

reduction standard in Section 225.230(a)(1)(B), 225.233(d)(1)(B) or (d)(2)(B),

225.237(a)(1)(B), or 225.294(c)(2), or the emissions concentration standard in

Section 225.230(a)(1)(A), 225.233(d)(1)(A) or (d)(2)(A), 225.237(a)(1)(A), or

225.294(c)(1), can only be demonstrated if the monitor data availability is equal

to or greater than 75 percent. Whenever any emissions monitoring system fails to

meet the quality-assurance and quality-control requirements or data validation

requirements of 40 CFR 75, incorporated by reference in Section 225.140, data

must be substituted using the applicable missing data procedures in Subparts D

and I of 40 CFR 75, each incorporated by reference in Section 225.140.

cb)

Audit Decertification. Whenever both an audit of an emissions monitoring

system and a review of the initial certification or recertification application reveal

that any emissions monitoring system should not have been certified or recertified

because it did not meet a particular performance specification or other

requirement pursuant to Section 225.250 or the applicable provisions of Appendix

B to this Part, 40 CFR 75, both at the time of the initial certification or

recertification application submission and at the time of the audit, the Agency

must issue a notice of disapproval of the certification status of such monitoring

system. For the purposes of this subsection (cb)

, an audit must be either a field

audit or an audit of any information submitted to the Agency. By issuing the

notice of disapproval, the Agency revokes prospectively the certification status of

the emissions monitoring system. The data measured and recorded by the

monitoring system willmust

not be considered valid quality-assured data from the

date of issuance of the notification of the revoked certification status until the date

and time that the owner or operator completes subsequently approved initial

certification or recertification tests for the monitoring system. The owner or

operator must follow the applicable initial certification or recertification

procedures in Section 225.250 for each disapproved monitoring system.

(Source: Amended at 33 Ill. Reg. _______, effective _______)

Section 225.261 Additional Requirements to Provide Heat Input Data

The owner or operator of an EGU that monitors and reports mercury mass emissions using a

mercury concentration monitoring system and a flow monitoring system must also monitor and

report the heat input rate at the EGU level using the procedures set forth in Appendix B to this

Part. 40 CFR 75, incorporated by reference in Section 225.140.

138

(Source: Amended at 33 Ill. Reg. _______, effective _______)

Section 225.263 Monitoring of Gross Electrical Output

The owner or operator of an EGU complying with this Subpart B by means of Section

225.230(a)(1) or using electrical output (O

) and complying by means of Section 225.230(b) or

(d) or Section 225.232 must monitor gross electrical output of the associated generator(s) in

MWh on an hourly basis.

(Source: Amended at 33 Ill. Reg. _______, effective _______)

Section 225.265 Coal Analysis for Input Mercury Levels

The owner or operator of an EGU complying with this Subpart B by means of

Section 225.230(a)(12)(B); or using input mercury levels (I

) and complying by

means of Section 225.230(b) or (d) or Section 225.232; electing to comply with

the emissions testing, monitoring, and recordkeeping requirements under Section

225.239; demonstrating compliance under Section 225.233, except an EGU in an

MPS Group that elects to comply with the emission standard in Section

225.233(d)(1)(A) or (d)(2)(A); or demonstrating compliance under Sections

225.291 through 225.299, except an EGU in a CPS Group that elects to comply

with the emission standard in Section 225.294(c)(1) or that opts into the emission

standard in Section 225.294(c)(1) pursuant to Section 225.294(e)(1), must fulfill

the following requirements:

Perform daily sampling of the coal combusted in the EGU for mercury

content. The owner or operator of such EGU must collect a minimum of

one 2-lb. grab sample per day of operation from the belt feeders anywhere

between the crusher house or breaker building and the boiler or, in cases

where a crusher house or breaker building are not present, at a reasonable

point close to the boiler of a subject EGU, according to the schedule

below. The sample must be taken in a manner that provides a

representative mercury content for the coal burned on that day. If multiple

samples are tested, the owner or operator must average those tests to arrive

at the final mercury content for that time period. The owner or operator of

the EGU must perform coal sampling as follows:

EGUs complying by means of Section 225.233, except an EGU in

an MPS Group that elects to comply with the control efficiency

standard in Section 225.233(d)(1)(B) or (d)(2)(B) or elects to

comply with Section 225.233(d)(4), or Sections 225.291 through

225.299, except an EGU in a CPS Group that elects to comply with

the control efficiency standard in Section 225.294(c)(2) or that opts

into the emission standard in Section 225.294(c)(2) pursuant to

Section 225.294(e)(1), must perform such coal sampling at least

139

once per month unless the boiler did not operate or combust coal at

all during that month;

EGUs complying by means of the emissions testing, monitoring,

and recordkeeping requirements under Section 225.239 or Section

225.233(d)(4), or EGUs that opt into the emission standard in

Section 225.294(c)(2) pursuant to Section 225.294(e)(1)(B), must

perform such coal sampling according to the schedule provided in

Section 225.239(e)(3) of this Subpart;

All other EGUs subject to this requirement, including EGUs in an

MPS or CPS Group electing to comply with the control efficiency

standard in Section 225.233(d)(1)(B) or (d)(2)(B), Section

225.294(c)(2), or Section 225.294(c)(2) pursuant to Section

225.294(e)(1)(A), must perform such coal sampling on a daily

basis when the boiler is operating and combusting coal.

Analyze the grab coal sample for the following:

Determine the heat content using ASTM D5865-04 or an

equivalent method approved in writing by the Agency.

Determine the moisture content using ASTM D3173-03 or an

equivalent method approved in writing by the Agency.

Measure the mercury content using ASTM D6414-01, ASTM

D3684-01, ASTM D6722-01,

or an equivalent method approved in

writing by the Agency.

The owner or operator of multiple EGUs at the same source using the

same crusher house or breaker building may take one sample per crusher

house or breaker building, rather than one per EGU.

The owner or operator of an EGU must use the data analyzed pursuant to

subsection (b) of this Section to determine the mercury content in terms of

parts per millionlbs/trillion

Btu.

The owner or operator of an EGU that must conduct sampling and analysis of coal

pursuant to subsection (a) of this Section must begin such activity by the

following date:

If the EGU is in daily service, at least 30 days before the start of the month

for which such activity will be required.

If the EGU is not in daily service, on the day that the EGU resumes

operation.

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(Source: Amended at 33 Ill. Reg. _______, effective _______)

Section 225.270 Notifications

The owner or operator of a source with one or more EGUs must submit written notice to the

Agency according to the provisions in 40 CFR 75.61, incorporated by reference in Section

225.140 (as a segment of 40 CFR 75), for each EGU or group of EGUs monitored at a common

stack and each non-EGU monitored pursuant to Section 1.16(b)(2)(B) of Appendix B to this Part.

40 CFR 75.82(b)(2)(ii), incorporated by reference in Section 225.140.

(Source: Amended at 33 Ill. Reg. _________, effective _________)

Section 225.290 Recordkeeping and Reporting

General Provisions.

The owner or operator of an EGU and its designated representative must

comply with all applicable recordkeeping and reporting requirements in

this Section and with all applicable recordkeeping and reporting

requirements of Section 1.18 to Appendix B to this Part. 40 CFR 75.84,

incorporated by reference in Section 225.140.

The owner or operator of an EGU must maintain records for each month

identifying the emission standard in Section 225.230(a) or 225.237(a) of

this Section with which it is complying or that is applicable for the EGU

and the following records related to the emissions of mercury that the

EGU is allowed to emit:

For an EGU for which the owner or operator is complying with

this Subpart B by means of Section 225.230(a)(12)(B) or

225.237(a)(1)(B) or using input mercury levels to determine the

allowable emissions of the EGU, records of the daily mercury

content of coal used (parts per millionlbs/trillion Btu) and the daily

and monthly input mercury (lbs), which must be kept in the file

pursuant to Section 1.18(a) of Appendix B to this Part. 40 CFR

75.84(a).

For an EGU for which the owner or operator of an EGU complying

with this Subpart B by means of Section 225.230(a)(1)(A) or

225.237(a)(1)(A) or using electrical output to determine the

allowable emissions of the EGU, records of the daily and monthly

gross electrical output (GWh), which must be kept in the file

required pursuant to Section 1.18(a) of Appendix B to this Part 40

CFR 75.84(a).

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The owner or operator of an EGU must maintain records of the following

data for each EGU:

Monthly emissions of mercury from the EGU.

For an EGU for which the owner or operator is complying by

means of Section 225.230(b) or (d) of this Subpart B, records of

the monthly allowable emissions of mercury from the EGU.

The owner or operator of an EGU that is participating in an Averaging

Demonstration pursuant to Section 225.232 of this Subpart B must

maintain records identifying all sources and EGUs covered by the

Demonstration for each month and, within 60 days after the end of each

calendar month, calculate and record the actual and allowable mercury

emissions of the EGU for the month and the applicable 12-month rolling

period.

The owner or operator of an EGU must maintain the following records

related to quality assurance activities conducted for emissions monitoring

systems:

The results of quarterly assessments conducted pursuant to Section

section 2.2 of Exhibit B to Appendix B to this Part Appendix B of

40 CFR 75, incorporated by reference in Section 225.140; and

Daily/weekly system integrity checks pursuant to Section section

2.6 of Exhibit B to Appendix B to this Part

Appendix B of 40 CFR

75, incorporated by reference in Section 225.140.

The owner or operator of an EGU must maintain an electronic copy of all

electronic submittals to the USEPA pursuant to 40 CFR 75.84(f),

incorporated by reference in Section 225.140.

67)

The owner or operator of an EGU must retain all records required by this

Section at the source for a period of five years from the date the document

is created unless otherwise provided in the CAAPP permit issued for the

source and must make a copy of any record available to the Agency upon

request. This period may be extended in writing by the Agency, for cause,

at any time prior to the end of five years.

Quarterly Reports. The owner or operator of a source with one or more EGUs

using CEMS or excepted monitoring systems at any time during a calendar

quarter must submit quarterly reports to the Agency as follows:

These reports must include the following information for operation of the

EGUs during the quarter:

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The total operating hours of each EGU and the mercury CEMS, as

also reported in accordance with 40 CFR 75, incorporated by

reference in Section 225.140.

A discussion of any significant changes in the measures used to

control emissions of mercury from the EGUs or the coal supply to

the EGUs, including changes in the source of coal.

Summary information on the performance of the mercury CEMS.

When the mercury CEMS was not inoperative, repaired, or

adjusted, except for routine zero and span checks, this must be

stated in the report.

If the CEMS downtime was more than 5.0 percent of the total

operating time for the EGU: the date and time identifying each

period during which the CEMS was inoperative, except for routine

zero and span checks; the nature of CEMS repairs or adjustments

and a summary of quality assurance data consistent with 40 CFR

i.e., the dates and results of the Linearity Tests and any RATAs

during the quarter; a listing of any days when a required daily

calibration was not performed; and the date and duration of any

periods when the CEMS was out-of-control as addressed by

Section 225.260.

Recertification testing that has been performed for any CEMS and

the status of the results.

Source information such as source name, source ID number, and the

period covered by the report;

A list of all EGU(s) at the source that identifies the applicable Part 225

monitoring and reporting requirements with which each EGU is

complying for the reported quarter, including the following EGUs, which

are excluded from subsection (b)(3) of this Section:

All EGUs using the periodic emissions testing provisions of

Section 225.239, 225.233(d)(4), or Section 225.294(c) pursuant to

Section 225.294(e)(1)(B) for the quarter.

All EGUs using the low mass emissions (LME) excepted

monitoring methodology pursuant to Section 1.15(b) of Appendix

B to this Part.

For only those EGUs using CEMS or excepted monitoring systems at any

time during a calendar quarter:

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An indication of whether the identified EGUs were in compliance

with all applicable monitoring, recordkeeping, and reporting

requirements of Part 225 for the entire reporting period.

The total quarterly operating hours of each EGU.

The CEMS or excepted monitoring system quality-assured monitor

operating (QAMO) hours on a quarterly basis and percentage data

availability on a quarterly or rolling 12-month basis (for each

concluding 12-month period in that quarter), as appropriate

according to the schedule provided in Section 225.260(b). The

data availability shall be determined in accordance with Sections

1.8 (CEMS) or 1.9 (excepted monitoring system) of Appendix B to

this Part.

The average monthly mercury concentration of the coal combusted

in each EGU in parts per million (determined by averaging all

analyzed coal samples in the month) and the quarterly total amount

of mercury (calculated by multiplying the total amount of coal

combusted each month by the average monthly mercury

concentration and converting to ounces, then adding together for

the quarter) of the coal combusted in each EGU. If the EGU is

complying by means of Sections 225.230(a)(1)(A),

225.233(d)(1)(A), 225.233(d)(2)(A), or Section 225.294(c)(1),

reporting of the data in this subparagraph D is not required.

The quarterly mercury mass emissions (in ounces), determined

from the QAMO hours in accordance with Section 4.2 of Exhibit C

to Appendix B to this Part. If the EGU is complying by means of

Sections 225.230(a)(1)(A), 225.233(d)(1)(A), 225.233(d)(2)(A), or

Section 225.294(c)(1), reporting of the data in this subparagraph E

is not required.

The average monthly and quarterly mercury control efficiency.

This is determined by dividing the mercury mass emissions

recorded during QAMO hours, calculated each month and quarter,

by the total amount of mercury in the coal combusted weighted by

the monitor availability (total mercury content multiplied by the

percent monitor availability, or QAMO hours divided by total

hours) for each month and quarter. If the DAHS for the EGU has

the ability to record the amount of coal combusted during QAMO

hours, the average monthly and quarterly control efficiency shall

be reported without the calculation above. If the EGU is complying

by means of Sections 225.230(a)(1)(A), 225.233(d)(1)(A),

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225.233(d)(2)(A), or Section 225.294(c)(1), reporting of the data in

this subparagraph F is not required.

The average monthly and quarterly mercury emission rate (in

lb/GWh) for each EGU, determined in accordance with Section

225.230(a)(2). Only those EGUs complying by means of Sections

225.230(a)(1)(A), 225.233(d)(1)(A), 225.233(d)(2)(A), or Section

225.294(c)(1) are required to report the data in this subparagraph

The 12-month rolling average control efficiency (percentage) or

emission rate (in lb/GWh) for each month in the reporting period,

as applicable (or the rolling average control efficiency or emission

rate for a lesser number of months if a full 12 months of data is not

available). This applicable data is determined according to the

following requirements:

The 12-month rolling average control efficiency is required

for those sources complying by means of Sections

225.230(a)(1)(B), 225.233(d)(1)(B), 225.233(d)(2)(B),

225.294(c)(2), 225.230(b), 225.230(d), 225.232(b)(2), or

225.237(a)(1)(B).

ii)

The 12-month rolling average emission rate is required for

those sources complying by means of Sections

225.230(a)(1)(A), 225.233(d)(1)(A), 225.233(d)(2)(A), or

Section 225.294(c)(1), 225.230(b), 225.230(d),

225.232(b)(1), or 225.237(a)(1)(A).

If the CEMS or excepted monitoring system percentage data

availability was less than 95.0 percent of the total operating time

for the EGU, the date and time identifying each period during

which the CEMS was inoperative, except for routine zero and span

checks; the nature of CEMS repairs or adjustments and a summary

of quality assurance data consistent with Appendix B to this Part,

i.e., the dates and results of the Linearity Tests and any RATAs

during the quarter; a listing of any days when a required daily

calibration was not performed; and the date and duration of any

periods when the CEMS was unavailable or out-of-control as

addressed by Section 225.260.

The owner or operator must submit each quarterly report to the Agency

within 45 days following the end of the calendar quarter covered by the

report, except that the owner or operator of an EGU that used an excepted

monitoring system at any time during a calendar quarter must submit each

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quarterly report within 60 days following the end of the calendar quarter

covered by the report.

Compliance Certification. The owner or operator of a source with one or more

EGUs must submit to the Agency a compliance certification in support of each

quarterly report based on reasonable inquiry of those persons with primary

responsibility for ensuring that all of the EGUs' emissions are correctly and fully

monitored. The certification must state:

That the monitoring data submitted were recorded in accordance with the

applicable requirements of this Section, Sections 225.240 through 225.270

and Section 225.290 of this Subpart B, and Appendix B to this Part 40

CFR 75, including the quality assurance procedures and specifications;

and

For an EGU with add-on mercury emission controls, a flue gas

desulfurization system, a selective catalytic reduction system, or a

compact hybrid particulate collector system and for all hours where

mercury data is unavailable or out of control that: are substituted in

accordance with 40 CFR 75.34(a)(1):

That:

Ai)

The mercury add-on emission controls, flue gas desulfurization

system, selective catalytic reduction system, or compact hybrid

particulate collector system was operating within the range of

parameters listed in the quality assurance/quality control program

pursuant to Exhibit B to Appendix B to this Part Appendix B to 40

CFR 75; or

Bii)

With regard to a flue gas desulfurization system or a selective

catalytic reduction system, quality-assured SO

emission data

recorded in accordance with Appendix B to this Part

the 40 CFR

75 document that the flue gas desulfurization system was operating

properly, or quality-assured NO

emission data recorded in

accordance with Appendix B to this Part the 40 CFR 75 document

that the selective catalytic reduction system was operating

properly, as applicable; and

The substitute data values do not systematically underestimate

mercury emissions.

Annual Certification of Compliance.

The owner or operator of a source with one or more EGUs subject to this

Subpart B must submit to the Agency an Annual Certification of

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Compliance with this Subpart B no later than May 1 of each year and must

address compliance for the previous calendar year. Such certification

must be submitted to the Agency, Air Compliance and Enforcement

Section, and the Air Regional Field Office.

Annual Certifications of Compliance must indicate whether compliance

existed for each EGU for each month in the year covered by the

Certification and it must certify to that effect. In addition, for each EGU,

the owner or operator must provide the following appropriate data as set

forth in subsections (d)(2)(A) through (d)(2)(E) of this Section, together

with the data set forth in subsection (d)(2)(F) of this Section:

If complying with this Subpart B by means of Section

225.230(a)(1)(A) or 225.237(a)(1)(A):

Actual Emissionsemissions rate during QAMO hours, in

lb/GWh, for each 12-month rolling period ending in the

year covered by the Certification;

ii)

Actual Emissionsemissions during QAMO hours, in lbs,

and gross electrical output, in GWh, for each 12-month

rolling period ending in the year covered by the

Certification; and

iii)

Actual Emissionsemissions during QAMO hours, in lbs,

and gross electrical output, in GWh, for each month in the

year covered by the Certification and in the previous year.

If complying with this Subpart B by means of Section

225.230(a)(1)(B) or 225.237(a)(1)(B):

Actual

Controlcontrol efficiency for emissions during

QAMO hours for each 12-month rolling period ending in

the year covered by the Certification, expressed as a

percent;

ii)

Actual Emissionsemissions during QAMO hours, in lbs,

and mercury content in the fuel fired in such EGU, in lbs,

for each 12-month rolling period ending in the year covered

by the Certification; and

iii)

Actual Emissionsemissions during QAMO hours, in lbs,

and mercury content in the fuel fired in such EGU, in lbs,

for each month in the year covered by the Certification and

in the previous year.

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If complying with this Subpart B by means of Section 225.230(b):

Actual Emissionsemissions and allowable emissions during

QAMO hours for each 12-month rolling period ending in

the year covered by the Certification; and

ii)

Actual Emissionsemissions and allowable emissions during

QAMO hours, and which standard of compliance the owner

or operator was utilizing for each month in the year covered

by the Certification and in the previous year.

If complying with this Subpart B by means of Section 225.230(d):

Actual Emissionsemissions and allowable emissions during

QAMO hours for all EGUs at the source for each 12-month

rolling period ending in the year covered by the

Certification; and

ii)

Actual Emissionsemissions and allowable emissions during

QAMO hours, and which standard of compliance the owner

or operator was utilizing for each month in the year covered

by the Certification and in the previous year.

If complying with this Subpart B by means of Section 225.232:

Actual Emissionsemissions and allowable emissions during

QAMO hours for all EGUs at the source in an Averaging

Demonstration for each 12-month rolling period ending in

the year covered by the Certification; and

ii)

Actual

Emissionsemissions and allowable emissions during

QAMO hours, with the standard of compliance the owner

or operator was utilizing for each EGU at the source in an

Averaging Demonstration for each month for all EGUs at

the source in an Averaging Demonstration in the year

covered by the Certification and in the previous year.

Any deviations, data substitutions,

or exceptions each month and

discussion of the reasons for such deviations, data substitutions, or

exceptions.

All Annual Certifications of Compliance required to be submitted must

include the following certification by a responsible official:

I certify under penalty of law that this document and all attachments were

prepared under my direction or supervision in accordance with a system

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designed to assure that qualified personnel properly gather and evaluate

the information submitted. Based on my inquiry of the person or persons

directly responsible for gathering the information, the information

submitted is, to the best of my knowledge and belief, true, accurate, and

complete. I am aware that there are significant penalties for submitting

false information, including the possibility of fine and imprisonment for

knowing violations.

The owner or operator of an EGU must submit its first Annual

Certification of Compliance to address calendar year 2009 or the calendar

year in which the EGU commences commercial operation, whichever is

later. Notwithstanding subsection (d)(2) of this Section, in the Annual

Certifications of Compliance that are required to be submitted by May 1,

2010, and May 1, 2011, to address calendar years 2009 and 2010,

respectively, the owner or operator is not required to provide 12-month

rolling data for any period that ends before June 30, 2010.

Deviation Reports. For each EGU, the owner or operator must promptly notify

the Agency of deviations from requirements of this Subpart B. At a minimum,

these notifications must include a description of such deviations within 30 days

after discovery of the deviations, and a discussion of the possible cause of such

deviations, any corrective actions, and any preventative measures taken.

Quality Assurance RATA Reports. The owner or operator of an EGU must

submit to the Agency, Air Compliance and Enforcement Section, the quality

assurance RATA report for each EGU or group of EGUs monitored at a common

stack and each non-EGU pursuant to Section 1.16(b)(2)(B) of Appendix B to this

Part 40 CFR 75.82(b)(2)(ii), incorporated by reference in Section 225.140, within

45 days after completing a quality assurance RATA.

(Source: Amended at 33 Ill. Reg. _______, effective ______)

Section 225.291 Combined Pollutant Standard: Purpose

The purpose of Sections 225.291 through 225.299 (hereinafter referred to as the Combined

Pollutant Standard (“CPS”)) is to allow an alternate means of compliance with the emissions

standards for mercury in Section 225.230(a) for specified EGUs through permanent shut-down,

installation of ACI, and the application of pollution control technology for NO

, PM, and SO

emissions that also reduce mercury emissions as a co-benefit and to establish permanent

emissions standards for those specified EGUs. Unless otherwise provided for in the CPS,

owners and operators of those specified EGUs are not excused from compliance with other

applicable requirements of Subparts B, C, D, and E.

(Source: Added at 33 Ill. Reg. _______, effective _______)

Section 225.292 Applicability of the Combined Pollutant Standard

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As an alternative to compliance with the emissions standards of Section

225.230(a), the owner or operator of specified EGUs in the CPS located at Fisk,

Crawford, Joliet, Powerton, Waukegan, and Will County power plants may elect

for all of those EGUs as a group to demonstrate compliance pursuant to the CPS,

which establishes control requirements and emissions standards for NO

, PM,

, and mercury. For this purpose, ownership of a specified EGU is determined

based on direct ownership, by holding a majority interest in a company that owns

the EGU or EGUs, or by the common ownership of the company that owns the

EGU, whether through a parent-subsidiary relationship, as a sister corporation, or

as an affiliated corporation with the same parent corporation, provided that the

owner or operator has the right or authority to submit a CAAPP application on

behalf of the EGU.

A specified EGU is a coal-fired EGU listed in Appendix A, irrespective of any

subsequent changes in ownership of the EGU or power plant, the operator, unit

designation, or name of unit.

The owner or operator of each of the specified EGUs electing to demonstrate

compliance with Section 225.230(a) pursuant to the CPS must submit an

application for a CAAPP permit modification to the Agency, as provided for in

Section 225.220, that includes the information specified in Section 225.293 that

clearly states the owner’s or operator’s election to demonstrate compliance with

Section 225.230(a) pursuant to the CPS.

If an owner or operator of one or more specified EGUs elects to demonstrate

compliance with Section 225.230(a) pursuant to the CPS, then all specified EGUs

owned or operated in Illinois by the owner or operator as of December 31, 2006,

as defined in subsection (a) of this Section, are thereafter subject to the standards

and control requirements of the CPS. Such EGUs are referred to as a Combined

Pollutant Standard (CPS) group.

If an EGU is subject to the requirements of this Section, then the requirements

apply to all owners and operators of the EGU. and to the CAIR designated

representative for the EGU.

(Source: Added at 33 Ill. Reg. _______, effective _______)

Section 225.293 Combined Pollutant Standard: Notice of Intent

The owner or operator of one or more specified EGUs that intends to comply with Section

225.230(a) by means of the CPS must notify the Agency of its intention on or before

December 31, 2007. The following information must accompany the notification:

The identification of each EGU that will be complying with Section 225.230(a)

pursuant to the CPS, with evidence that the owner or operator has identified all

150

specified EGUs that it owned or operated in Illinois as of December 31, 2006, and

which commenced commercial operation on or before December 31, 2004;

If an EGU identified in subsection (a) of this Section is also owned or operated by

a person different than the owner or operator submitting the notice of intent, a

demonstration that the submitter has the right to commit the EGU or authorization

from the responsible official for the EGU submitting the application; and

A summary of the current control devices installed and operating on each EGU

and identification of the additional control devices that will likely be needed for

each EGU to comply with emission control requirements of the CPS.

(Source: Added at 33 Ill. Reg. _______, effective _______)

Section 225.294 Combined Pollutant Standard: Control Technology Requirements and

Emissions Standards for Mercury

Control Technology Requirements for Mercury.

For each EGU in a CPS group other than an EGU that is addressed by

subsection (b) of this Section, the owner or operator of the EGU must

install, if not already installed, and properly operate and maintain, by the

dates set forth in subsection (a)(2) of this Section, ACI equipment

complying with subsections (g), (h), (i), (j), and (k) of this Section, as

applicable.

By the following dates, for the EGUs listed in subsections (a)(2)(A) and

(B), which include hot and cold side ESPs, the owner or operator must

install, if not already installed, and begin operating ACI equipment or the

Agency must be given written notice that the EGU will be shut down on or

before the following dates:

Fisk 19, Crawford 7, Crawford 8, Waukegan 7, and Waukegan 8

on or before July 1, 2008; and

Powerton 5, Powerton 6, Will County 3, Will County 4, Joliet 6,

Joliet 7, and Joliet 8 on or before July 1, 2009.

Notwithstanding subsection (a) of this Section, the following EGUs are not

required to install ACI equipment because they will be permanently shut down, as

addressed by Section 225.297, by the date specified:

EGUs that are required to permanently shut down:

On or before December 31, 2007, Waukegan 6; and

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On or before December 31, 2010, Will County 1 and Will County

Any other specified EGU that is permanently shut down by December 31,

2010.

Beginning on January 1, 2015, and continuing thereafter, and measured on a

rolling 12-month basis (the initial period is January 1, 2015, through December

31, 2015, and, then, for every 12-month period thereafter), each specified EGU,

except Will County 3, shall achieve one of the following emissions standards:

An emissions standard of 0.0080 lbs mercury/GWh gross electrical output;

A minimum 90 percent reduction of input mercury.

Beginning on January 1, 2016, and continuing thereafter, Will County 3 shall

achieve the mercury emissions standards of subsection (c) of this Section

measured on a rolling 12-month basis (the initial period is January 1, 2016,

through December 31, 2016, and, then, for every 12-month period thereafter).

Compliance with Emission Standards

At any time prior to the dates required for compliance in subsections (c)

and (d) of this Section, the owner or operator of a specified EGU, upon

notice to the Agency, may elect to comply with the emissions standards of

subsection (c) of this Section measured on either:

a rolling 12-month basis, or;

a quarterly calendar basis pursuant to the emissions testing

requirements in Section 225.239(a)(4), (c), (d), (e), (f), (g), (h), (i),

and (j) of this Subpart until June 30, 2012.

Once an EGU is subject to the mercury emissions standards of subsection

subsections (g), (h), (i), (j) and (k) of this Section.

Compliance with the mercury emissions standards or reduction requirement of

this Section must be calculated in accordance with Section 225.230(a) or (b), or

Section 225.232 until December 31, 2013.

For each EGU for which injection of halogenated activated carbon is required by

subsection (a)(1) of this Section, the owner or operator of the EGU must inject

halogenated activated carbon in an optimum manner, which, except as provided in

subsection (h) of this Section, is defined as all of the following:

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The use of an injection system for effective absorption of mercury,

considering the configuration of the EGU and its ductwork;

The injection of halogenated activated carbon manufactured by Alstom,

Norit, or Sorbent Technologies, Calgon Carbon’s FLUEPAC CF Plus, or

Calgon Carbon's FLUEPAC MC Plus, or the injection of any other

halogenated activated carbon or sorbent that the owner or operator of the

EGU has demonstrated to have similar or better effectiveness for control

of mercury emissions; and

The injection of sorbent at the following minimum rates, as applicable:

For an EGU firing subbituminous coal, 5.0 lbs per million actual

cubic feet or, for any cyclone-fired EGU that will install a scrubber

and baghouse by December 31, 2012, and which already meets an

emission rate of 0.020 lb mercury/GWh gross electrical output or

at least 75 percent reduction of input mercury, 2.5 lbs per million

actual cubic feet;

For an EGU firing bituminous coal, 10.0 lbs per million actual

cubic feet or, for any cyclone-fired EGU that will install a scrubber

and baghouse by December 31, 2012, and which already meets an

emission rate of 0.020 lb mercury/GWh gross electrical output or

at least 75 percent reduction of input mercury, 5.0 lbs per million

actual cubic feet;

For an EGU firing a blend of subbituminous and bituminous coal,

a rate that is the weighted average of the rates specified in

subsections (g)(3)(A) and (B), based on the blend of coal being

fired; or

A rate or rates set lower by the Agency, in writing, than the rate

specified in any of subsection (g)(3)(A), (B), or (C) of this Section

on a unit-specific basis, provided that the owner or operator of the

EGU has demonstrated that such rate or rates are needed so that

carbon injection will not increase particulate matter emissions or

opacity so as to threaten noncompliance with applicable

requirements for particulate matter or opacity.

For purposes of subsection (g)(3) of this Section, the flue gas flow rate

shall be the gas flow rate in the stack for all units except for those

equipped with activated carbon injection prior to a hot-side electrostatic

precipitator; for units equipped with activated carbon injection prior to a

hot-side electrostatic precipitator, the flue gas flow rate shall be the gas

flow rate at the inlet to the hot-side electrostatic precipitator, which shall

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be determined as the stack flow rate adjusted through the use of Charles’s

Law for the differences in gas temperatures in the stack and at the inlet to

the electrostatic precipitator (V

rate in acf and T = gas temperature in Kelvin or Rankine).

The owner or operator of an EGU that seeks to operate an EGU with an activated

carbon injection rate or rates that are set on a unit-specific basis pursuant to

subsection (g)(3)(D) of this Section must submit an application to the Agency

proposing such rate or rates, and must meet the requirements of subsections (h)(1)

and (h)(2) of this Section, subject to the limitations of subsections (h)(3) and

(h)(4) of this Section:

The application must be submitted as an application for a new or revised

federally enforceable operation permit for the EGU, and it must include a

summary of relevant mercury emissions data for the EGU, the unit-

specific injection rate or rates that are proposed, and detailed information

to support the proposed injection rate or rates; and

This application must be submitted no later than the date that activated

carbon must first be injected. For example, the owner or operator of an

EGU that must inject activated carbon pursuant to subsection (a)(1) of this

Section must apply for unit-specific injection rate or rates by July 1, 2008.

Thereafter, the owner or operator may supplement its application; and

Any decision of the Agency denying a permit or granting a permit with

conditions that set a lower injection rate or rates may be appealed to the

Board pursuant to Section 39 of the Act; and

The owner or operator of an EGU may operate at the injection rate or rates

proposed in its application until a final decision is made on the application

including a final decision on any appeal to the Board.

During any evaluation of the effectiveness of a listed sorbent, alternative sorbent,

or other technique to control mercury emissions, the owner or operator of an EGU

need not comply with the requirements of subsection (g) of this Section for any

system needed to carry out the evaluation, as further provided as follows:

The owner or operator of the EGU must conduct the evaluation in

accordance with a formal evaluation program submitted to the Agency at

least 30 days prior to commencement of the evaluation;

The duration and scope of the evaluation may not exceed the duration and

scope reasonably needed to complete the desired evaluation of the

alternative control techniques, as initially addressed by the owner or

operator in a support document submitted with the evaluation program;

and

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The owner or operator of the EGU must submit a report to the Agency no

later than 30 days after the conclusion of the evaluation that describes the

evaluation conducted and which provides the results of the evaluation; and

If the evaluation of alternative control techniques shows less effective

control of mercury emissions from the EGU than was achieved with the

principal control techniques, the owner or operator of the EGU must

resume use of the principal control techniques. If the evaluation of the

alternative control technique shows comparable effectiveness to the

principal control technique, the owner or operator of the EGU may either

continue to use the alternative control technique in a manner that is at least

as effective as the principal control technique or it may resume use of the

principal control technique. If the evaluation of the alternative control

technique shows more effective control of mercury emissions than the

control technique, the owner or operator of the EGU must continue to use

the alternative control technique in a manner that is more effective than

the principal control technique, so long as it continues to be subject to this

Section.

In addition to complying with the applicable recordkeeping and monitoring

requirements in Sections 225.240 through 225.290, the owner or operator of an

EGU that elects to comply with this Subpart B by means of Section 225.291

through 225.299 must also comply with the following additional requirements:

For the first 36 months that injection of sorbent is required, it must

maintain records of the usage of sorbent, the flue gas flow rate from the

EGU (and, if the unit is equipped with activated carbon injection prior to a

hot-side electrostatic precipitator, flue gas temperature at the inlet of the

hot-side electrostatic precipitator and in the stack), and the sorbent feed

rate, in pounds per million actual cubic feet of flue gas, on a weekly

average;

After the first 36 months that injection of sorbent is required, it must

monitor activated sorbent feed rate to the EGU, gas flow rate in the stack,

and, if the unit is equipped with activated carbon injection prior to a hot-

side electrostatic precipitator, flue gas temperature at the inlet of the hot-

side electrostatic precipitator and in the stack. It must automatically

record this data and the sorbent carbon feed rate, in pounds per million

actual cubic feet of flue gas, on an hourly average; and

If a blend of bituminous and subbituminous coal is fired in the EGU, it

must keep records of the amount of each type of coal burned and the

required injection rate for injection of activated carbon on a weekly basis.

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In addition to complying with the applicable reporting requirements in Sections

225.240 through 225.290, the owner or operator of an EGU that elects to comply

with Section 225.230(a) by means of the CPS must also submit quarterly reports

for the recordkeeping and monitoring conducted pursuant to subsection (j) of this

Section.

Until June 30, 2012, as an alternative to the CEMS (or excepted monitoring

system) monitoring, recordkeeping, and reporting requirements in Sections

225.240 through 225.290, the owner or operator of an EGU may elect to comply

with the emissions testing, monitoring, recordkeeping, and reporting requirements

in Section 225.239(c), (d), (e), (f)(1) and (2), (h)(2), (i)(3) and (4), and (j)(1).

(Source: Added at 33 Ill. Reg. _______, effective _______)

Section 225.295 Combined Pollutant Standard: Emissions Standards for NO

and SO

Treatment of Mercury Allowances

Any mercury allowances allocated to the Agency by the USEPA must be treated as follows:

No such allowances may be allocated to any owner or operator of an EGU or

other sources of mercury emissions into the atmosphere or discharges into the

waters of the State.

The Agency must hold all allowances allocated by the USEPA to the State. At

the end of each calendar year, the Agency must instruct the USEPA to retire permanently all

such allowances.

Emissions Standards for NO

and Reporting Requirements.

Beginning with calendar year 2012 and continuing in each calendar year

thereafter, the CPS group, which includes all specified EGUs that have not

been permanently shut down by December 31 before the applicable

calendar year, must comply with a CPS group average annual NO

emissions rate of no more than 0.11 lbs/mmBtu.

Beginning with ozone season control period 2012 and continuing in each

ozone season control period (May 1 through September 30) thereafter, the

CPS group, which includes all specified EGUs that have not been

permanently shut down by December 31 before the applicable ozone

season, must comply with a CPS group average ozone season NO

emissions rate of no more than 0.11 lbs/mmBtu.

The owner or operator of the specified EGUs in the CPS group must file,

not later than one year after startup of any selective SNCR on such EGU, a

report with the Agency describing the NO

emissions reductions that the

SNCR has been able to achieve.

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Emissions Standards for SO

. Beginning in calendar year 2013 and continuing in

each calendar year thereafter, the CPS group must comply with the applicable

CPS group average annual SO

emissions rate listed as follows:

Compliance with the NO

and SO

emissions standards must be demonstrated in

accordance with Sections 225.310, 225.410, and 225.510. The owner or operator

of the specified EGUs must complete the demonstration of compliance pursuant

to Section 225.298(c) before March 1 of the following year for annual standards

and before November 30 of the particular year for ozone season control periods

(May 1 through September 30) standards, by which date a compliance report must

be submitted to the Agency.

The CPS group average annual SO

emission rate, annual NO

emission rate and

ozone season NO

emission rates shall be determined as follows:

= average annual or ozone season emission rate in

lbs/mmBbtu of all EGUs in the CPS group.

i ,

heat input for the annual or ozone control period of each

EGU, in mmBtu.

actual annual SO

tons of each EGU in the CPS group.

actual annual or ozone season NO

tons of each EGU in

the CPS group.

N =

number of EGUs that are in the CPS group

each EGU in the CPS group.

(Source: Amended at 33 Ill. Reg. _______, effective _______)

Section 225.296 Combined Pollutant Standard: Control Technology Requirements for

, SO

, and PM Emissions

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Control Technology Requirements for NO

and SO

On or before December 31, 2013, the owner or operator must either

permanently shut down or install and have operational FGD equipment on

Waukegan 7;

On or before December 31, 2014, the owner or operator must either

permanently shut down or install and have operational FGD equipment on

Waukegan 8;

On or before December 31, 2015, the owner or operator must either

permanently shut down or install and have operational FGD equipment on

Fisk 19;

If Crawford 7 will be operated after December 31, 2018, and not

permanently shut down by this date, the owner or operator must:

On or before December 31, 2015, install and have operational

SNCR or equipment capable of delivering essentially equivalent

reductions on Crawford 7; and

On or before December 31, 2018, install and have operational FGD

equipment on Crawford 7;

If Crawford 8 will be operated after December 31, 2017 and not

permanently shut down by this date, the owner or operator must:

On or before December 31, 2015, install and have operational

SNCR or equipment capable of delivering essentially equivalent

emissions reductions on Crawford 8; and

On or before December 31, 2017, install and have operational FGD

equipment on Crawford 8.

Other Control Technology Requirements for SO

. Owners or operators of

specified EGUs must either permanently shut down or install FGD equipment on

each specified EGU (except Joliet 5), on or before December 31, 2018, unless an

earlier date is specified in subsection (a) of this Section.

Control Technology Requirements for PM. The owner or operator of the two

specified EGUs listed in this subsection that are equipped with a hot-side ESP

must replace the hot-side ESP with a cold-side ESP, install an appropriately

designed fabric filter, or permanently shut down the EGU by the dates specified.

Hot-side ESP means an ESP on a coal-fired boiler that is installed before the

boiler's air-preheater where the operating temperature is typically at least 550º F,

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as distinguished from a cold-side ESP that is installed after the air pre-heater

where the operating temperature is typically no more than 350º F.

Waukegan 7 on or before December 31, 2013; and

Will County 3 on or before December 31, 2015.

Beginning on December 31, 2008, and annually thereafter up to and including

December 31, 2015, the owner or operator of the Fisk power plant must submit in

writing to the Agency a report on any technology or equipment designed to affect

air quality that has been considered or explored for the Fisk power plant in the

preceding 12 months. This report will not obligate the owner or operator to install

any equipment described in the report.

Notwithstanding 35 Ill. Adm. Code 201.146(hhh), until an EGU has complied

with the applicable requirements of subsections 225.296(a), (b), and (c), the

owner or operator of the EGU must obtain a construction permit for any new or

modified air pollution control equipment that it proposes to construct for control

of emissions of mercury, NO

, PM, or SO

(Source: Added at 33 Ill. Reg. _______, effective _______)

Section 225.297 Combined Pollutant Standard: Permanent Shut-Downs

The owner or operator of the following EGUs must permanently shut down the

EGU by the dates specified:

Waukegan 6 on or before December 31, 2007; and

Will County 1 and Will County 2 on or before December 31, 2010.

No later than 8 months before the date that a specified EGU will be permanently

shut down, the owner or operator must submit a report to the Agency that includes

a description of the actions that have already been taken to allow the shutdown of

the EGU and a description of the future actions that must be accomplished to

complete the shutdown of the EGU, with the anticipated schedule for those

actions and the anticipated date of permanent shutdown of the unit.

No later than six months before a specified EGU will be permanently shut down,

the owner or operator shall apply for revisions to the operating permits for the

EGU to include provisions that terminate the authorization to operate the unit on

that date.

If after applying for or obtaining a construction permit to install required control

equipment, the owner or operator decides to permanently shut-down a Specified

EGU rather than install the required control technology, the owner or operator

159

must immediately notify the Agency in writing and thereafter submit the

information required by subsections (b) and (c) of this Section.

Failure to permanently shut down a specified EGU by the required date shall be

considered separate violations of the applicable emissions standards and control

technology requirements of the CPS for NO

, PM, SO

, and mercury.

(Source: Added at 33 Ill. Reg. _______, effective _______)

Section 225.298 Combined Pollutant Standard: Requirements for NO

and SO

allowances

The following requirements apply to the owner and operator with respect to SO

and NO

allowances, which mean, for the purposes of this Section 225.298,

allowances necessary for compliance with Section 225.310, 225.410, or 225.510,

40 CFR 72, or Subparts AA and AAAA of 40 CFR 96, or any future federal NO

or SO

emissions trading programs that modify or replace these programs:

The owner or operator of specified EGUs in a CPS group is permitted to

sell, trade, or transfer SO

and NO

emissions allowances of any vintage

owned, allocated to, or earned by the specified EGUs (the "CPS

allowances") to its affiliated Homer City, Pennsylvania, generating station

for as long as the Homer City Station needs the CPS allowances for

compliance.

When and if the Homer City Station no longer requires all of the CPS

allowances, the owner or operator of specified EGUs in a CPS group may

sell any and all remaining CPS allowances, without restriction, to any

person or entity located anywhere, except that the owner or operator may

not directly sell, trade, or transfer CPS allowances to a unit located in

Ohio, Indiana, Illinois, Wisconsin, Michigan, Kentucky, Missouri, Iowa,

Minnesota, or Texas.

In no event shall this subsection (a) require or be interpreted to require any

restriction whatsoever on the sale, trade, or exchange of the CPS

allowances by persons or entities who have acquired the CPS allowances

from the owner or operator of specified EGUs in a CPS group.

The owner or operator of EGUs in a specified CPS group is prohibited from

purchasing or using SO

and NO

allowances for the purposes of meeting the SO

and NO

emissions standards set forth in Section 225.295.

By March 1, 2010, and continuing each year thereafter, the owner or operator of

the EGUs in a CPS group must submit a report to the Agency that demonstrates

compliance with the requirements of this Section for the previous calendar year

and ozone season control period (May 1 through September 30), and includes

identification of any NO

or SO

allowances that have been used for compliance

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with any NO

or SO

trading programs, and any NO

or SO

allowances that were

sold, gifted, used, exchanged, or traded. A final report must be submitted to the

Agency by August 31 of each year, providing either verification that the actions

described in the initial report have taken place, or, if such actions have not taken

place, an explanation of the changes that have occurred and the reasons for such

changes.

(Source: Added at 33 Ill. Reg. _______, effective _______)

Section 225.299 Combined Pollutant Standard: Clean Air Act Requirements

The SO

emissions rates set forth in the CPS shall be deemed to be best available retrofit

technology (“BART”) under the Visibility Protection provisions of the CAA (42 USC 7491),

reasonably available control technology (“RACT”) and reasonably available control measures

(“RACM”) for achieving fine particulate matter (“PM

2.5

”) requirements under NAAQS in effect

on August 31, 2007, as required by the CAA (42 USC 7502). The Agency may use the SO

and

emissions reductions required under the CPS in developing attainment demonstrations and

demonstrating reasonable further progress for PM

2.5

and 8 hour ozone standards, as required

under the CAA. Furthermore, in developing rules, regulations, or State Implementation Plans

designed to comply with PM

2.5

and 8 hour ozone NAAQS, the Agency, taking into account all

emission reduction efforts and other appropriate factors, will use best efforts to seek SO

and

emissions rates from other EGUs that are equal to or less than the rates applicable to the

CPS group and will seek SO

and NO

reductions from other sources before seeking additional

emissions reductions from any EGU in the CPS group.

(Source: Added at 33 Ill. Reg._______, effective _______)

SUBPART F: COMBINED POLLUTANT STANDARDS

Section 225.600 Purpose (Repealed)

The purpose of this Subpart F is to allow an alternate means of compliance with the emissions

standards for mercury in Section 225.230(a) for specified EGUs through permanent shut-down,

installation of ACI, and the application of pollution control technology for NO

, PM, and SO

emissions that also reduce mercury emissions as a co-benefit and to establish permanent

emissions standards for those specified EGUs. Unless otherwise provided for in this Subpart F,

owners and operators of those specified EGUs are not excused from compliance with other

applicable requirements of Subparts B, C, D, and E.

(Source: Repealed at 33 Ill. Reg. _______, effective _______)

Section 225.605 Applicability (Repealed)

As an alternative to compliance with the emissions standards of Section

225.230(a), the owner or operator of specified EGUs in this Subpart F located at

Fisk, Crawford, Joliet, Powerton, Waukegan, and Will County power plants may

161

elect for all of those EGUs as a group to demonstrate compliance pursuant to this

Subpart F, which establishes control requirements and emissions standards for

, PM, SO

, and mercury. For this purpose, ownership of a specified EGU is

determined based on direct ownership, by holding a majority interest in a

company that owns the EGU or EGUs, or by the common ownership of the

company that owns the EGU, whether through a parent-subsidiary relationship, as

a sister corporation, or as an affiliated corporation with the same parent

corporation, provided that the owner or operator has the right or authority to

submit a CAAPP application on behalf of the EGU.

A specified EGU is a coal-fired EGU listed in Appendix A, irrespective of any

subsequent changes in ownership of the EGU or power plant, the operator, unit

designation, or name of unit.

The owner or operator of each of the specified EGUs electing to demonstrate

compliance with Section 225.230(a) pursuant to this Subpart must submit an

application for a CAAPP permit modification to the Agency, as provided for in

Section 225.220, that includes the information specified in Section 225.610 that

clearly states the owner’s or operator’s election to demonstrate compliance with

Section 225.230(a) pursuant to this Subpart F.

If an owner or operator of one or more specified EGUs elects to demonstrate

compliance with Section 225.230(a) pursuant to this Subpart F, then all specified

EGUs owned or operated in Illinois by the owner or operator as of December 31,

2006, as defined in subsection (a) of this Section, are thereafter subject to the

standards and control requirements of this Subpart F. Such EGUs are referred to

as a Combined Pollutant Standard (CPS) group.

If an EGU is subject to the requirements of this Section, then the requirements

apply to all owners and operators of the EGU, and to the CAIR designated

representative for the EGU.

(Source: Repealed at 33 Ill. Reg. _______, effective _______)

Section 225.610 Notice of Intent (Repealed)

The owner or operator of one or more specified EGUs that intends to comply with Section

225.230(a) by means of this Subpart F must notify the Agency of its intention on or before

December 31, 2007. The following information must accompany the notification:

The identification of each EGU that will be complying with Section 225.230(a)

pursuant to this Subpart F, with evidence that the owner or operator has identified

all specified EGUs that it owned or operated in Illinois as of December 31, 2006,

and which commenced commercial operation on or before December 31, 2004;

162

If an EGU identified in subsection (a) of this Section is also owned or operated by

a person different than the owner or operator submitting the notice of intent, a

demonstration that the submitter has the right to commit the EGU or authorization

from the responsible official for the EGU submitting the application; and

A summary of the current control devices installed and operating on each EGU

and identification of the additional control devices that will likely be needed for

each EGU to comply with emission control requirements of this Subpart F.

(Source: Repealed at 33 Ill. Reg._______, effective _______)

Section 225.615 Control Technology Requirements and Emissions Standards for Mercury

(Repealed)

Control Technology Requirements for Mercury.

For each EGU in a CPS group other than an EGU that is addressed by

subsection (b) of this Section, the owner or operator of the EGU must

install, if not already installed, and properly operate and maintain, by the

dates set forth in subsection (a)(2) of this Section, ACI equipment

complying with subsections (g), (h), (i), (j), and (k) of this Section, as

applicable.

By the following dates, for the EGUs listed in subsections (a)(2)(A) and

(B), which include hot and cold side ESPs, the owner or operator must

install, if not already installed, and begin operating ACI equipment or the

Agency must be given written notice that the EGU will be shut down on or

before the following dates:

Fisk 19, Crawford 7, Crawford 8, Waukegan 7, and Waukegan 8

on or before July 1, 2008; and

Powerton 5, Powerton 6, Will County 3, Will County 4, Joliet 6,

Joliet 7, and Joliet 8 on or before July 1, 2009.

Notwithstanding subsection (a) of this Section, the following EGUs are not

required to install ACI equipment because they will be permanently shut down, as

addressed by Section 225.630, by the date specified:

EGUs that are required to permanently shut down:

On or before December 31, 2007, Waukegan 6; and

On or before December 31, 2010, Will County 1 and Will County

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Any other specified EGU that is permanently shut down by December 31,

2010.

Beginning on January 1, 2015 and continuing thereafter, and measured on a

rolling 12-month basis (the initial period is January 1, 2015, through December

31, 2015, and, then, for every 12-month period thereafter), each specified EGU,

except Will County 3, shall achieve one of the following emissions standards:

An emissions standard of 0.0080 lbs mercury/GWh gross electrical output;

A minimum 90 percent reduction of input mercury.

Beginning on January 1, 2016, and continuing thereafter, Will County 3 shall

achieve the mercury emissions standards of subsection (c) of this Section

measured on a rolling 12-month basis (the initial period is January 1, 2016

through December 31, 2016, and, then, for every 12-month period thereafter).

At any time prior to the dates required for compliance in subsections (c) and (d)

of this Section, the owner or operator of a specified EGU, upon notice to the

Agency, may elect to comply with the emissions standards of subsection (c) of

this Section measured on a rolling 12-month basis for one or more EGUs. Once

an EGU is subject to the mercury emissions standards of subsection (c) of this

Section, it shall not be subject to the requirements of subsections (g), (h), (i), (j)

and (k) of this Section.

Compliance with the mercury emissions standards or reduction requirement of

this Section must be calculated in accordance with Section 225.230(a) or (b).

For each EGU for which injection of halogenated activated carbon is required by

subsection (a)(1) of this Section, the owner or operator of the EGU must inject

halogenated activated carbon in an optimum manner, which, except as provided in

subsection (h) of this Section, is defined as all of the following:

The use of an injection system for effective absorption of mercury,

considering the configuration of the EGU and its ductwork;

The injection of halogenated activated carbon manufactured by Alstom,

Norit, or Sorbent Technologies, or the injection of any other halogenated

activated carbon or sorbent that the owner or operator of the EGU has

demonstrated to have similar or better effectiveness for control of mercury

emissions; and

The injection of sorbent at the following minimum rates, as applicable:

164

For an EGU firing subbituminous coal, 5.0 lbs per million actual

cubic feet or, for any cyclone-fired EGU that will install a scrubber

and baghouse by December 31, 2012, and which already meets an

emission rate of 0.020 lb mercury/GWh gross electrical output or

at least 75 percent reduction of input mercury, 2.5 lbs per million

actual cubic feet;

For an EGU firing bituminous coal, 10.0 lbs per million actual

cubic feet or, for any cyclone-fired EGU that will install a scrubber

and baghouse by December 31, 2012, and which already meets an

emission rate of 0.020 lb mercury/GWh gross electrical output or

at least 75 percent reduction of input mercury, 5.0 lbs per million

actual cubic feet;

For an EGU firing a blend of subbituminous and bituminous coal,

a rate that is the weighted average of the rates specified in

subsections (g)(3)(A) and (B), based on the blend of coal being

fired; or

A rate or rates set lower by the Agency, in writing, than the rate

specified in any of subsection (g)(3)(A), (B), or (C) of this Section

on a unit-specific basis, provided that the owner or operator of the

EGU has demonstrated that such rate or rates are needed so that

carbon injection will not increase particulate matter emissions or

opacity so as to threaten noncompliance with applicable

requirements for particulate matter or opacity.

For purposes of subsection (g)(3) of this Section, the flue gas flow rate

must be determined for the point sorbent injection; provided that this flow

rate may be assumed to be identical to the stack flow rate if the gas

temperatures at the point of injection and the stack are normally within

100º F, or the flue gas flow rate may otherwise be calculated from the

stack flow rate, corrected for the difference in gas temperatures.

The owner or operator of an EGU that seeks to operate an EGU with an activated

carbon injection rate or rates that are set on a unit-specific basis pursuant to

subsection (g)(3)(D) of this Section must submit an application to the Agency

proposing such rate or rates, and must meet the requirements of subsections (h)(1)

and (h)(2) of this Section, subject to the limitations of subsections (h)(3) and

(h)(4) of this Section:

The application must be submitted as an application for a new or revised

federally enforceable operation permit for the EGU, and it must include a

summary of relevant mercury emissions data for the EGU, the unit-

specific injection rate or rates that are proposed, and detailed information

to support the proposed injection rate or rates; and

165

This application must be submitted no later than the date that activated

carbon must first be injected. For example, the owner or operator of an

EGU that must inject activated carbon pursuant to subsection (a)(1) of this

Section must apply for unit-specific injection rate or rates by July 1, 2008.

Thereafter, the owner or operator may supplement its application; and

Any decision of the Agency denying a permit or granting a permit with

conditions that set a lower injection rate or rates may be appealed to the

Board pursuant to Section 39 of the Act; and

The owner or operator of an EGU may operate at the injection rate or rates

proposed in its application until a final decision is made on the application

including a final decision on any appeal to the Board.

During any evaluation of the effectiveness of a listed sorbent, alternative sorbent,

or other technique to control mercury emissions, the owner or operator of an EGU

need not comply with the requirements of subsection (g) of this Section for any

system needed to carry out the evaluation, as further provided as follows:

The owner or operator of the EGU must conduct the evaluation in

accordance with a formal evaluation program submitted to the Agency at

least 30 days prior to commencement of the evaluation;

The duration and scope of the evaluation may not exceed the duration and

scope reasonably needed to complete the desired evaluation of the

alternative control techniques, as initially addressed by the owner or

operator in a support document submitted with the evaluation program;

and

The owner or operator of the EGU must submit a report to the Agency no

later than 30 days after the conclusion of the evaluation that describes the

evaluation conducted and which provides the results of the evaluation; and

If the evaluation of alternative control techniques shows less effective

control of mercury emissions from the EGU than was achieved with the

principal control techniques, the owner or operator of the EGU must

resume use of the principal control techniques. If the evaluation of the

alternative control technique shows comparable effectiveness to the

principal control technique, the owner or operator of the EGU may either

continue to use the alternative control technique in a manner that is at least

as effective as the principal control technique or it may resume use of the

principal control technique. If the evaluation of the alternative control

technique shows more effective control of mercury emissions than the

control technique, the owner or operator of the EGU must continue to use

the alternative control technique in a manner that is more effective than

166

the principal control technique, so long as it continues to be subject to this

Section.

In addition to complying with the applicable recordkeeping and monitoring

requirements in Sections 225.240 through 225.290, the owner or operator of an

EGU that elects to comply with Section 225.230(a) by means of this Subpart F

must also comply with the following additional requirements:

For the first 36 months that injection of sorbent is required, it must

maintain records of the usage of sorbent, the exhaust gas flow rate from

the EGU, and the sorbent feed rate, in pounds per million actual cubic feet

of exhaust gas at the injection point, on a weekly average;

After the first 36 months that injection of sorbent is required, it must

monitor activated sorbent feed rate to the EGU, flue gas temperature at the

point of sorbent injection, and exhaust gas flow rate from the EGU,

automatically recording this data and the sorbent carbon feed rate, in

pounds per million actual cubic feet of exhaust gas at the injection point,

on an hourly average; and

If a blend of bituminous and subbituminous coal is fired in the EGU, it

must keep records of the amount of each type of coal burned and the

required injection rate for injection of activated carbon on a weekly basis.

In addition to complying with the applicable reporting requirements in Sections

225.240 through 225.290, the owner or operator of an EGU that elects to comply

with Section 225.230(a) by means of this Subpart F must also submit quarterly

reports for the recordkeeping and monitoring conducted pursuant to subsection (j)

of this Section.

(Source: Repealed at 33 Ill. Reg._______, effective _______)

Section 225.620 Emissions Standards for NO

and SO

(Repealed)

Emissions Standards for NO

and Reporting Requirements.

Beginning with calendar year 2012 and continuing in each calendar year

thereafter, the CPS group, which includes all specified EGUs that have not

been permanently shut down by December 31 before the applicable

calendar year, must comply with a CPS group average annual NO

emissions rate of no more than 0.11 lbs/mmBtu.

Beginning with ozone season control period 2012 and continuing in each

ozone season control period (May 1 through September 30) thereafter, the

CPS group, which includes all specified EGUs that have not been

permanently shut down by December 31 before the applicable ozone

167

season, must comply with a CPS group average ozone season NO

emissions rate of no more than 0.11 lbs/mmBtu.

The owner or operator of the specified EGUs in the CPS group must file,

not later than one year after startup of any selective SNCR on such EGU, a

report with the Agency describing the NO

emissions reductions that the

SNCR has been able to achieve.

Emissions Standards for SO

. Beginning in calendar year 2013 and continuing in

each calendar year thereafter, the CPS group must comply with the applicable

CPS group average annual SO

emissions rate listed as follows:

Compliance with the NO

and SO

emissions standards must be demonstrated in

accordance with Sections 225.310, 225.410, and 225.510. The owner or operator

of the specified EGUs must complete the demonstration of compliance pursuant

to Section 225.635(c) before March 1 of the following year for annual standards

and before November 30 of the particular year for ozone season control periods

(May 1 through September 30) standards, by which date a compliance report must

be submitted to the Agency.

The CPS group average annual SO

emission rate, annual NO

emission rate and

ozone season NO

emission rates shall be determined as follows:

average annual or ozone season emission rate in lbs/mmBbtu

of all EGUs in the CPS group.

heat input for the annual or ozone control period of each EGU,

in mmBtu.

actual annual SO

tons of each EGU in the CPS group.

actual annual or ozone season NO

tons of each EGU in the

CPS group.

n =

number of EGUs that are in the CPS group

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I =

each EGU in the CPS group.

(Source: Repealed at 33 Ill. Reg._______, effective _______)

Section 225.625 Control Technology Requirements for NO

, SO

, and PM Emissions

(Repealed)

Control Technology Requirements for NO

and SO

On or before December 31, 2013, the owner or operator must either

permanently shut down or install and have operational FGD equipment on

Waukegan 7;

On or before December 31, 2014, the owner or operator must either

permanently shut down or install and have operational FGD equipment on

Waukegan 8;

On or before December 31, 2015, the owner or operator must either

permanently shut down or install and have operational FGD equipment on

Fisk 19;

If Crawford 7 will be operated after December 31, 2018, and not

permanently shut down by this date, the owner or operator must:

On or before December 31, 2015, install and have operational

SNCR or equipment capable of delivering essentially equivalent

reductions on Crawford 7; and

On or before December 31, 2018, install and have operational FGD

equipment on Crawford 7;

If Crawford 8 will be operated after December 31, 2017 and not

permanently shut down by this date, the owner or operator must:

On or before December 31, 2015, install and have operational

SNCR or equipment capable of delivering essentially equivalent

emissions reductions on Crawford 8; and

On or before December 31, 2017, install and have operational FGD

equipment on Crawford 8.

Other Control Technology Requirements for SO

. Owners or operators of

specified EGUs must either permanently shut down or install FGD equipment on

each specified EGU (except Joliet 5), on or before December 31, 2018, unless an

earlier date is specified in subsection (a) of this Section.

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Control Technology Requirements for PM. The owner or operator of the two

specified EGUs listed in this subsection that are equipped with a hot-side ESP

must replace the hot-side ESP with a cold-side ESP, install an appropriately

designed fabric filter, or permanently shut down the EGU by the dates specified.

Hot-side ESP means an ESP on a coal-fired boiler that is installed before the

boiler's air-preheater where the operating temperature is typically at least 550º F,

as distinguished from a cold-side ESP that is installed after the air pre-heater

where the operating temperature is typically no more than 350º F.

Waukegan 7 on or before December 31, 2013; and

Will County 3 on or before December 31, 2015.

Beginning on December 31, 2008, and annually thereafter up to and including

December 31, 2015, the owner or operator of the Fisk power plant must submit in

writing to the Agency a report on any technology or equipment designed to affect

air quality that has been considered or explored for the Fisk power plant in the

preceding 12 months. This report will not obligate the owner or operator to install

any equipment described in the report.

Notwithstanding 35 Ill. Adm. Code 201.146(hhh), until an EGU has complied

with the applicable requirements of subsections 225.625(a), (b), and (c), the

owner or operator of the EGU must obtain a construction permit for any new or

modified air pollution control equipment that it proposes to construct for control

of emissions of mercury, NO

, PM, or SO

(Source: Repealed at 33 Ill. Reg._______, effective _______)

Section 225.630 Permanent Shut Downs (Repealed)

The owner or operator of the following EGUs must permanently shut down the

EGU by the dates specified:

Waukegan 6 on or before December 31, 2007; and

Will County 1 and Will County 2 on or before December 31, 2010.

No later than 8 months before the date that a specified EGU will be permanently

shut down, the owner or operator must submit a report to the Agency that includes

a description of the actions that have already been taken to allow the shutdown of

the EGU and a description of the future actions that must be accomplished to

complete the shutdown of the EGU, with the anticipated schedule for those

actions and the anticipated date of permanent shutdown of the unit.

No later than six months before a specified EGU will be permanently shut down,

the owner or operator shall apply for revisions to the operating permits for the

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EGU to include provisions that terminate the authorization to operate the unit on

that date.

If after applying for or obtaining a construction permit to install required control

equipment, the owner or operator decides to permanently shut-down a Specified

EGU rather than install the required control technology, the owner or operator

must immediately notify the Agency in writing and thereafter submit the

information required by subsections (b) and (c) of this Section.

Failure to permanently shut down a specified EGU by the required date shall be

considered separate violations of the applicable emissions standards and control

technology requirements of this Subpart F for NO

, PM, SO

, and mercury.

(Source: Repealed at 33 Ill. Reg._______, effective _______)

Section 225.635 Requirements for CAIR SO

, CAIR NO

, and CAIR NO

Ozone Season

Allowances (Repealed)

The following requirements apply to the owner, the operator and the designated

representative with respect to CAIR SO

The owner, operator, and CAIR designated representative of specified

EGUs in a CPS group is permitted to sell, trade, or transfer SO

and NO

emissions allowances of any vintage owned, allocated to, or earned by the

specified EGUs (the "CPS allowances") to its affiliated Homer City,

Pennsylvania generating station for as long as the Homer City Station

needs the CPS allowances for compliance.

When and if the Homer City Station no longer requires all of the CPS

allowances, the owner, operator, or CAIR designated representative of

specified EGUs in CPS group may sell any and all remaining CPS

allowances, without restriction, to any person or entity located anywhere,

except that the owner or operator may not directly sell, trade, or transfer

CPS allowances to a CAIR NO

or CAIR SO

unit located in Ohio,

Indiana, Illinois, Wisconsin, Michigan, Kentucky, Missouri, Iowa,

Minnesota, or Texas.

In no event shall this subsection (a) require or be interpreted to require any

restriction whatsoever on the sale, trade, or exchange of the CPS

allowances by persons or entities who have acquired the CPS allowances

from the owner, operator, or CAIR designated representative of specified

EGUs in a CPS group.

The owner, operator, and CAIR designated representative of EGUs in a specified

CPS group is prohibited from purchasing or using CAIR SO

Ozone Season allowances for the purposes of meeting the SO

and

emissions standards set forth in Section 225.620.

Before March 1, 2010, and continuing each year thereafter, the CAIR designated

representative of the EGUs in a CPS group must submit a report to the Agency

that demonstrates compliance with the requirements of this Section for the

previous calendar year and ozone season control period (May 1 through

September 30), and includes identification of any CAIR allowances that have

been used for compliance with the CAIR Trading Programs as set forth in

Subparts C, D, and E, and any CAIR allowances that were sold, gifted, used,

exchanged, or traded. A final report must be submitted to the Agency by August

31 of each year, providing either verification that the actions described in the

initial report have taken place, or, if such actions have not taken place, an

explanation of the changes that have occurred and the reasons for such changes.

(Source: Repealed at 33 Ill. Reg._______, effective _______)

Section 225.640 Clean Air Act Requirements (Repealed)

The SO

emissions rates set forth in this Subpart F shall be deemed to be best available retrofit

technology (“BART”) under the Visibility Protection provisions of the CAA (42 USC 7491),

reasonably available control technology (“RACT”) and reasonably available control measures

(“RACM”) for achieving fine particulate matter (“PM

2.5

”) requirements under NAAQS in effect

on August 31, 2007, as required by the CAA (42 USC 7502). The Agency may use the SO

and

emissions reductions required under this Subpart F in developing attainment demonstrations

and demonstrating reasonable further progress for PM

2.5

and 8 hour ozone standards, as required

under the CAA. Furthermore, in developing rules, regulations, or State Implementation Plans

designed to comply with PM

2.5

and 8 hour ozone NAAQS, the Agency, taking into account all

emission reduction efforts and other appropriate factors, will use best efforts to seek SO

and

emissions rates from other EGUs that are equal to or less than the rates applicable to the

CPS group and will seek SO

and NO

reductions from other sources before seeking additional

emissions reductions from any EGU in the CPS group.

(Source: Repealed at 33 Ill. Reg._______, effective _______)

225.APPENDIX A Specified EGUs for Purposes of the CPS

Subpart F (Midwest

Generation’s Coal-Fired Boilers as of July 1, 2006)

Will County 197810AAK

(Source: Amended at 33 Ill. Reg._______, effective _______)

225.APPENDIX B Continuous Emission Monitoring Systems for Mercury

Section 1.1 Applicability

The provisions of this Appendix apply to sources subject to 35 Ill Admin. Code Part 225

mercury (Hg) mass emission reduction program.

Section 1.2 General Operating Requirements

Primary Equipment Performance Requirements. The owner or operator must

ensure that each continuous mercury emission monitoring system and each

auxiliary monitoring system required by this Appendix meets the equipment,

installation and performance specifications in Exhibit A to this Appendix and is

maintained according to the quality assurance and quality control procedures in

Exhibit B to this Appendix.

Heat Input Rate Measurement Requirement. The owner or operator must

determine and record the heat input rate, in units of mmBtu/hr, to each affected

unit for every hour or part of an hour any fuel is combusted following the

procedures in Exhibit C to this Appendix.

Primary Equipment Hourly Operating Requirements. The owner or operator must

ensure that all continuous mercury emission monitoring systems and all auxiliary

monitoring systems required by this Appendix are in operation and monitoring

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unit emissions at all times that the affected unit combusts any fuel except during

periods of calibration, quality assurance, or preventive maintenance, performed

pursuant to Section 1.5 of this Appendix and Exhibit B to this Appendix, periods

of repair, periods of backups of data from the data acquisition and handling

system, or recertification performed pursuant to Section 1.4 of this Appendix.

The owner or operator must ensure that each continuous emission

monitoring system is capable of completing a minimum of one cycle of

operation (sampling, analyzing and data recording) for each successive 15-

minute interval. The owner or operator must reduce all volumetric flow,

concentration, O

concentration and mercury concentration data

collected by the monitors to hourly averages. Hourly averages must be

computed using at least one data point in each 15-minute quadrant of an

hour, where the unit combusted fuel during that quadrant of an hour.

Notwithstanding this requirement, an hourly average may be computed

from at least two data points separated by a minimum of 15 minutes

(where the unit operates for more than one quadrant of an hour) if data are

unavailable as a result of the performance of calibration, quality assurance,

or preventive maintenance activities pursuant to Section 1.5 of this

Appendix and Exhibit B to this Appendix, or backups of data from the

data acquisition and handling system, or recertification, pursuant to

Section 1.4 of this Appendix. The owner or operator must use all valid

measurements or data points collected during an hour to calculate the

hourly averages. All data points collected during an hour must be, to the

extent practicable, evenly spaced over the hour.

Failure of a CO

or O

emissions concentration monitor, mercury

concentration monitor, flow monitor, or a moisture monitor to acquire the

minimum number of data points for calculation of an hourly average in

subsection (c)(1) of this Section must result in the failure to obtain a valid

hour of data and the loss of such component data for the entire hour. For a

moisture monitoring system consisting of one or more oxygen analyzers

capable of measuring O

on a wet-basis and a dry-basis, an hourly average

percent moisture value is valid only if the minimum number of data points

is acquired for both the wet-and dry-basis measurements.

Optional Backup Monitor Requirements. If the owner or operator chooses to use

two or more continuous mercury emission monitoring systems, each of which is

capable of monitoring the same stack or duct at a specific affected unit, or group

of units using a common stack, then the owner or operator must designate one

monitoring system as the primary monitoring system, and must record this

information in the monitoring plan, as provided for in Section 1.10 of this

Appendix. The owner or operator must designate the other monitoring systems as

backup monitoring systems in the monitoring plan. The backup monitoring

systems must be designated as redundant backup monitoring systems, non-

redundant backup monitoring systems, or reference method backup systems, as

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described in Section 1.4(d) of this Appendix. When the certified primary

monitoring system is operating and not out-of-control as defined in Section 1.7 of

this Appendix, only data from the certified primary monitoring system must be

reported as valid, quality-assured data. Thus, data from the backup monitoring

system may be reported as valid, quality-assured data only when the backup is

operating and not out-of-control as defined in Section 1.7 of this Appendix (or in

the applicable reference method in appendix A of 40 CFR 60, incorporated by

reference in Section 225.140) and when the certified primary monitoring system

is not operating (or is operating but out-of-control). A particular monitor may be

designated both as a certified primary monitor for one unit and as a certified

redundant backup monitor for another unit.

Minimum Measurement Capability Requirement. The owner or operator must

ensure that each continuous emission monitoring system is capable of accurately

measuring, recording, and reporting data, and must not incur an exceedance of the

full scale range, except as provided in Section 2.1.2.3 of Exhibit A to this

Appendix.

Minimum Recording and Recordkeeping Requirements. The owner or operator

must record and report the hourly, daily, quarterly, and annual information

collected under the requirements as specified in subpart G of 40 CFR 75,

incorporated by reference in Section 225.140, and Section 1.11 through 1.13 of

this Appendix.

Section 1.3 Special Provisions for Measuring Mercury Mass Emissions Using the Excepted

Sorbent Trap Monitoring Methodology

For an affected coal-fired unit under 35 Ill Adm. Code 225 if the owner or operator elects to use

sorbent trap monitoring systems (as defined in Section 225.130) to quantify mass emissions, the

guidelines in subsections (a) through (l) of this Section must be followed for this excepted

monitoring methodology:

For each sorbent trap monitoring system (whether primary or redundant backup),

the use of paired sorbent traps, as described in Exhibit D to this Appendix, is

required;

Each sorbent trap must have a main section, a backup section and a third section

to allow spiking with a calibration gas of known mercury concentration, as

described in Exhibit D to this Appendix;

A certified flow monitoring system is required;

Correction for stack gas moisture content is required, and in some cases, a

certified O

or CO

monitoring system is required (see Section 1.15(a)(4));

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Each sorbent trap monitoring system must be installed and operated in accordance

with Exhibit D to this Appendix. The automated data acquisition and handling

system must ensure that the sampling rate is proportional to the stack gas

volumetric flow rate.

At the beginning and end of each sample collection period, and at least once in

each unit operating hour during the collection period, the gas flow meter reading

must be recorded.

After each sample collection period, the mass of mercury adsorbed in each

sorbent trap (in all three sections) must be determined according to the applicable

procedures in Exhibit D to this Appendix.

The hourly mercury mass emissions for each collection period are determined

using the results of the analyses in conjunction with contemporaneous hourly data

recorded by a certified stack flow monitor, corrected for the stack gas moisture

content. For each pair of sorbent traps analyzed, the average of the 2 mercury

concentrations must be used for reporting purposes under Section 1.18(f) of this

Appendix. Notwithstanding this requirement, if, due to circumstances beyond the

control of the owner or operator, one of the paired traps is accidentally lost,

damaged, or broken and cannot be analyzed, the results of the analysis of the

other trap may be used for reporting purposes, provided that the other trap has met

all of the applicable quality-assurance requirements of this Part.

All unit operating hours for which valid mercury concentration data are obtained

with the primary sorbent trap monitoring system (as verified using the quality

assurance procedures in Exhibit D to this Appendix) must be reported in the

electronic quarterly report under Section 1.18(f) of this Appendix. For hours in

which data from the primary monitoring system are invalid, the owner or operator

may, in accordance with Section 1.4(d) of this Appendix, report valid mercury

concentration data from: A certified redundant backup CEMS or sorbent trap

monitoring system; a certified non-redundant backup CEMS or sorbent trap

monitoring system; or an applicable reference method under Section 1.6 of this

Appendix.

Initial certification requirements and additional quality-assurance requirements

for the sorbent trap monitoring systems are found in Section 1.4(c)(7), in Section

6.5.6 of Exhibit A to this Appendix, in Sections 1.3 and 2.3 of Exhibit B to this

Appendix, and in Exhibit D to this Appendix.

During each RATA of a sorbent trap monitoring system, the type of sorbent

material used by the traps must be the same as for daily operation of the

monitoring system. A new pair of traps must be used for each RATA run.

However, the size of the traps used for the RATA may be smaller than the traps

used for daily operation of the system.

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Whenever the type of sorbent material used by the traps is changed, the owner or

operator must conduct a diagnostic RATA of the modified sorbent trap

monitoring system within 720 unit or stack operating hours after the date and hour

when the new sorbent material is first used. If the diagnostic RATA is passed,

data from the modified system may be reported as quality-assured, back to the

date and hour when the new sorbent material was first used. If the RATA is

failed, all data from the modified system must be invalidated,back to the date and

hour when the new sorbent material was first used, and data from the system must

remain invalid until a subsequent RATA is passed. If the required RATA is not

completed within 720 unit or stack operating hours, but is passed on the first

attempt, data from the modified system must be invalidated beginning with the

first operating hour after the 720 unit or stack operating hour window expires and

data from the system must remain invalid until the date and hour of completion of

the successful RATA.

Section 1.4 Initial Certification and Recertification Procedures

Initial Certification Approval Process. The owner or operator must ensure that

each continuous mercury emission monitoring system or auxiliary monitoring

system required by this Appendix meets the initial certification requirements of

this Section. In addition, whenever the owner or operator installs a continuous

mercury emission monitoring system in order to meet the requirements of Section

1.3 of this Appendix and 40 CFR sections 75.11 through 75.14 and 75.16 through

75.18, incorporated by reference in Section 225.140, where no continuous

emission monitoring system was previously installed, initial certification is

required.

Notification of initial certification test dates. The owner or operator must

submit a written notice of the dates of initial certification testing at the unit

as specified in 40 CFR 75.61(a)(1), incorporated by reference in Section

225.140.

Certification application. The owner or operator must apply for

certification of each continuous mercury emission monitoring system and,

if not previously certified, for each auxiliary monitoring system. The

owner or operator must submit the certification application in accordance

with 40 CFR 75.60, incorporated by reference in Section 225.140, and

each complete certification application must include the information

specified in 40 CFR 75.63, incorporated by reference in Section 225.140.

Provisional approval of certification (or recertification) applications. Upon

the successful completion of the required certification (or recertification)

procedures of this Section, each continuous mercury emission monitoring

system and each auxiliary monitoring system must be deemed

provisionally certified (or recertified) for use for a period not to exceed

120 days following receipt by the Agency of the complete certification (or

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recertification) application under subsection (a)(4) of this Section. Data

measured and recorded by a provisionally certified (or recertified)

continuous emission monitoring system, operated in accordance with the

requirements of Exhibit B to this Appendix, will be considered valid

quality-assured data (retroactive to the date and time of provisional

certification or recertification), provided that the Agency does not

invalidate the provisional certification (or recertification) by issuing a

notice of disapproval within 120 days of receipt by the Agency of the

complete certification (or recertification) application. Note that when the

conditional data validation procedures of subsection (b)(3) of this Section

are used for the initial certification (or recertification) of a continuous

emissions monitoring system, the date and time of provisional certification

(or recertification) of the CEMS may be earlier than the date and time of

completion of the required certification (or recertification) tests.

Certification (or recertification) application formal approval process. The

Agency will issue a notice of approval or disapproval of the certification

(or recertification) application to the owner or operator within 120 days

after receipt of the complete certification (or recertification) application. In

the event the Agency does not issue such a notice within 120 days after

receipt, each continuous emission monitoring system which meets the

performance requirements of this Part and is included in the certification

(or recertification) application will be deemed certified (or recertified) for

use under 35 Ill Adm. Code 225.

Approval notice. If the certification (or recertification) application

is complete and shows that each continuous emission monitoring

system meets the performance requirements of this part, then the

Agency will issue a notice of approval of the certification (or

recertification) application within 120 days of receipt.

Incomplete application notice. A certification (or recertification)

application will be considered complete when all of the applicable

information required to be submitted in 40 CFR 75.63,

incorporated by reference in Section 225.140, has been received by

the Agency. If the certification (or recertification) application is

not complete, then the Agency will issue a notice of

incompleteness that provides a reasonable timeframe for the owner

or operator to submit the additional information required to

complete the certification (or recertification) application. If the

owner or operator has not complied with the notice of

incompleteness by a specified due date, then the Agency may issue

a notice of disapproval specified under paragraph (a)(4)(C) of this

Section. The 120-day review period will not begin prior to receipt

of a complete application.

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Disapproval notice. If the certification (or recertification)

application shows that any continuous emission monitoring system

does not meet the performance requirements of this part, or if the

certification (or recertification) application is incomplete and the

requirement for disapproval under subsection (a)(4)(B) of this

Section has been met, the Agency must issue a written notice of

disapproval of the certification (or recertification) application

within 120 days after receipt. By issuing the notice of disapproval,

the provisional certification (or recertification) is invalidated by the

Agency, and the data measured and recorded by each uncertified

continuous emission or opacity monitoring system must not be

considered valid quality-assured data as follows: from the hour of

the probationary calibration error test that began the initial

certification (or recertification) test period (if the conditional data

validation procedures of subsection (b)(3) of this Section were

used to retrospectively validate data); or from the date and time of

completion of the invalid certification or recertification tests (if the

conditional data validation procedures of subsection (b)(3) of this

Section were not used). The owner or operator must follow the

procedures for loss of initial certification in subsection (a)(5) of

this Section for each continuous emission monitoring system that

is disapproved for initial certification. For each disapproved

recertification, the owner or operator must follow the procedures of

subsection (b)(5) of this Section.

Procedures for loss of certification. When the Agency issues a notice of

disapproval of a certification application or a notice of disapproval of

certification status (as specified in subsection (a)(4) of this Section), then:

Until such time, date, and hour as the continuous mercury emission

monitoring system can be adjusted, repaired, or replaced and

certification tests successfully completed (or, if the conditional

data validation procedures in subsections (b)(3)(B) through (I) of

this Section are used, until a probationary calibration error test is

passed following corrective actions in accordance with subsection

(b)(3)(B) of this Section), the owner or operator must perform

emissions testing pursuant to Section 225.239.

The owner or operator must submit a notification of certification

pretest dates as specified in Section 225.250(a)(3)(A) and a new

certification application according to the procedures in Section

225.250(a)(3)(B); and

The owner or operator must repeat all certification tests or other

requirements that were failed by the continuous mercury emission

monitoring system, as indicated in the Agency’s notice of

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disapproval, no later than 30 unit operating days after the date of

issuance of the notice of disapproval.

Recertification Approval Process. Whenever the owner or operator makes a

replacement, modification, or change in a certified continuous mercury emission

monitoring system or auxiliary monitoring system that may significantly affect

the ability of the system to accurately measure or record the gas volumetric flow

rate, mercury concentration, percent moisture, or to meet the requirements of

Section 1.5 of this Appendix or Exhibit B to this Appendix, the owner or operator

must recertify the monitoring system, according to the procedures in this

subsection. Examples of changes that require recertification include: replacement

of the analyzer; change in location or orientation of the sampling probe or site;

and complete replacement of an existing monitoring system. The owner or

operator must also recertify the continuous emission monitoring systems for a unit

that has recommenced commercial operation following a period of long-term cold

storage as defined in Section 225.130. Any change to a flow monitor or gas

monitoring system for which a RATA is not necessary will not be considered a

recertification event. In addition, changing the polynomial coefficients or K

factors of a flow monitor will require a 3-load RATA, but is not considered to be

a recertification event; however, records of the polynomial coefficients or K

factors currently in use must be maintained on-site in a format suitable for

inspection. Changing the coefficient or K factor(s) of a moisture monitoring

system will require a RATA, but is not considered to be a recertification event;

however, records of the coefficient or K factor(s) currently in use by the moisture

monitoring system must be maintained on-site in a format suitable for inspection.

In such cases, any other tests that are necessary to ensure continued proper

operation of the monitoring system (e.g., 3-load flow RATAs following changes

to flow monitor polynomial coefficients, linearity checks, calibration error tests,

DAHS verifications, etc.) must be performed as diagnostic tests, rather than as

recertification tests. The data validation procedures in subsection (b)(3) of this

Section must be applied to RATAs associated with changes to flow or moisture

monitor coefficients, and to linearity checks, 7-day calibration error tests, and

cycle time tests, when these are required as diagnostic tests. When the data

validation procedures of subsection (b)(3) of this Section are applied in this

manner, replace the word "recertification" with the word "diagnostic."

Tests required. For all recertification testing, the owner or operator must

complete all initial certification tests in subsection (c) of this Section that

are applicable to the monitoring system, except as otherwise approved by

the Agency. For diagnostic testing after changing the flow rate monitor

polynomial coefficients, the owner or operator must complete a 3-level

RATA. For diagnostic testing after changing the K factor or mathematical

algorithm of a moisture monitoring system, the owner or operator must

complete a RATA.

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Notification of recertification test dates. The owner or operator or

designated representative must submit notice of testing dates for

recertification under this subsection as specified in 40 CFR 75.61(a)(1)(ii),

incorporated by reference in Section 225.140, unless all of the tests in

subsection (c) of this Section are required for recertification, in which case

the owner or operator must provide notice in accordance with the notice

provisions for initial certification testing in 40 CFR 75.61(a)(1)(i),

incorporated by reference in Section 225.140.

Recertification test period requirements and data validation. The data

validation provisions in subsections (b)(3)(A) through (b)(3)(I) of this

Section will apply to all mercury CEMS recertifications and diagnostic

testing. The provisions in subsections (b)(3)(B) through (b)(3)(I) of this

Section may also be applied to initial certifications (see Sections 6.2(a),

6.3.1(a), 6.3.2(a), 6.4(a) and 6.5(f) of Exhibit A to this Appendix) and may

be used to supplement the linearity check and RATA data validation

procedures in Sections 2.2.3(b) and 2.3.2(b) of Exhibit B to this Appendix.

The owner or operator must report emission data using a reference

method or another monitoring system that has been certified or

approved for use under this Part, in the period extending from the

hour of the replacement, modification, or change made to a

monitoring system that triggers the need to perform recertification

testing, until either: the hour of successful completion of all of the

required recertification tests; or the hour in which a probationary

calibration error test (according to subsection (b)(3)(B) of this

Section) is performed and passed, following all necessary repairs,

adjustments, or reprogramming of the monitoring system. The first

hour of quality-assured data for the recertified monitoring system

must either be the hour after all recertification tests have been

completed or, if conditional data validation is used, the first

quality-assured hour must be determined in accordance with

subsections (b)(3)(B) through (I) of this Section. Notwithstanding

these requirements, if the replacement, modification, or change

requiring recertification of the CEMS is such that the historical

data stream is no longer representative (e.g., where the mercury

concentration and stack flow rate change significantly after

installation of a wet scrubber), the owner or operator must estimate

the mercury emissions over that time period and notify the Agency

within 15 days after the replacement, modification, or change

requiring recertification of the CEMS.

Once the modification or change to the CEMS has been completed

and all of the associated repairs, component replacements,

adjustments, linearization and reprogramming of the CEMS have

been completed, a probationary calibration error test is required to

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establish the beginning point of the recertification test period. In

this instance, the first successful calibration error test of the

monitoring system following completion of all necessary repairs,

component replacements, adjustments, linearization and

reprogramming must be the probationary calibration error test. The

probationary calibration error test must be passed before any of the

required recertification tests are commenced.

Beginning with the hour of commencement of a recertification test

period, emission data recorded by the CEMS are considered to be

conditionally valid, contingent upon the results of the subsequent

recertification tests.

Each required recertification test must be completed no later than

the following number of unit operating hours (or unit operating

days) after the probationary calibration error test that initiates the

test period:

For a linearity check, a system integrity check, and/or cycle

time test, 168 consecutive unit operating hours, as defined

in 40 CFR 72.2, incorporated by reference in Section

225.140, or, for CEMS installed on common stacks or

bypass stacks, 168 consecutive stack operating hours, as

defined in 40 CFR 72.2;

ii)

For a RATA (whether normal-load or multiple-load), 720

consecutive unit operating hours, as defined in 40 CFR

72.2, incorporated by reference in Section 225.140, or, for

CEMS installed on common stacks or bypass stacks, 720

consecutive stack operating hours, as defined in 40 CFR

72.2; and

iii)

For a 7-day calibration error test, 21 consecutive unit

operating days, as defined in 40 CFR 72.2, incorporated by

reference in Section 225.140.

All recertification tests must be performed hands-off. No

adjustments to the calibration of the CEMS, other than the routine

calibration adjustments following daily calibration error tests as

described in Section 2.1.3 of Exhibit B to this Appendix, are

permitted during the recertification test period. Routine daily

calibration error tests must be performed throughout the

recertification test period, in accordance with Section 2.1.1 of

Exhibit B to this Appendix. The additional calibration error test

requirements in Section 2.1.3 of Exhibit B to this Appendix, must

also apply during the recertification test period.

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If all of the required recertification tests and required daily

calibration error tests are successfully completed in succession

with no failures, and if each recertification test is completed within

the time period specified in subsection (b)(3)(D)(i), (ii) or (iii) of

this Section, then all of the conditionally valid emission data

recorded by the CEMS will be considered quality assured, from the

hour of commencement of the recertification test period until the

hour of completion of the required tests.

If a required recertification test is failed or aborted due to a

problem with the CEMS, or if a daily calibration error test is failed

during a recertification test period, data validation must be done as

follows:

If any required recertification test is failed, it must be

repeated. If any recertification test other than a 7-day

calibration error test is failed or aborted due to a problem

with the CEMS, the original recertification test period is

ended, and a new recertification test period must be

commenced with a probationary calibration error test. The

tests that are required in the new recertification test period

will include any tests that were required for the initial

recertification event that were not successfully completed

and any recertification or diagnostic tests that are required

as a result of changes made to the monitoring system to

correct the problems that caused the failure of the

recertification test. For a 2- or 3-load flow RATA, if the

relative accuracy test is passed at one or more load levels,

but is failed at a subsequent load level, provided that the

problem that caused the RATA failure is corrected without

re-linearizing the instrument, the length of the new

recertification test period must be equal to the number of

unit operating hours remaining in the original

recertification test period, as of the hour of failure of the

RATA. However, if re-linearization of the flow monitor is

required after a flow RATA is failed at a particular load

level, then a subsequent 3-load RATA is required, and the

new recertification test period must be 720 consecutive unit

(or stack) operating hours. The new recertification test

sequence must not be commenced until all necessary

maintenance activities, adjustments, linearization and

reprogramming of the CEMS have been completed;

ii)

If a linearity check, RATA system integrity check, or cycle

time test is failed or aborted due to a problem with the

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mercury CEMS, all conditionally valid emission data

recorded by the CEMS are invalidated, from the hour of

commencement of the recertification test period to the hour

in which the test is failed or aborted, except for the case in

which a multiple-load flow RATA is passed at one or more

load levels, failed at a subsequent load level, and the

problem that caused the RATA failure is corrected without

re-linearizing the instrument. In that case, data invalidation

will be prospective, from the hour of failure of the RATA

until the commencement of the new recertification test

period. Data from the CEMS remain invalid until the hour

in which a new recertification test period is commenced,

following corrective action, and a probationary calibration

error test is passed, at which time the conditionally valid

status of emission data from the CEMS begins again;

iii)

If a 7-day calibration error test is failed within the

recertification test period, previously-recorded

conditionally valid emission data from the mercury CEMS

are not invalidated. The conditionally valid data status is

unaffected, unless the calibration error on the day of the

failed 7-day calibration error test exceeds twice the

performance specification in Section 3 of Exhibit A to this

Appendix, as described in subsection (b)(3)(G)(iv) of this

Section.

iv)

If a daily calibration error test is failed during a

recertification test period (i.e., the results of the test exceed

the applicable performance specification in Section 2.1.4 of

Exhibit B to this Appendix), the CEMS is out-of-control as

of the hour in which the calibration error test is failed.

Emission data from the CEMS will be invalidated

prospectively from the hour of the failed calibration error

test until the hour of completion of a subsequent successful

calibration error test following corrective action, at which

time the conditionally valid status of data from the

monitoring system resumes. Failure to perform a required

daily calibration error test during a recertification test

period will also cause data from the CEMS to be

invalidated prospectively, from the hour in which the

calibration error test was due until the hour of completion

of a subsequent successful calibration error test. Whenever

a calibration error test is failed or missed during a

recertification test period, no further recertification tests

must be performed until the required subsequent calibration

error test has been passed, re-establishing the conditionally

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valid status of data from the monitoring system. If a

calibration error test failure occurs while a linearity check

or RATA is still in progress, the linearity check or RATA

must be re-started.

Trial gas injections and trial RATA runs are permissible

during the recertification test period, prior to commencing a

linearity check or RATA, for the purpose of optimizing the

performance of the CEMS. The results of such gas

injections and trial runs must not affect the status of

previously-recorded conditionally valid data or result in

termination of the recertification test period, provided that

they meet the following specifications and conditions: for

diluent gas injections, the stable, ending monitor response

is within ±5 percent of the tag value of the reference gas or

0.5% CO

or O

. For Hg vapor injections, the stable,

ending monitor response is within ± 10 percent of the value

of the reference gas or 0.8 μg/scm; for RATA trial runs, the

average reference method reading and the average CEMS

reading for the run differ by no more than ± 10% of the

average reference method value (for flow, diluent gas, and

moisture monitors), or ± 20% of the average reference

method value or 1.0μg/scm (for mercury monitors), or

differ by no more than 1.0% CO

or O2, 1.5% H

O from

the average reference method value, as applicable. No

adjustments to the calibration of the CEMS shall be made

following the trial injections or runs, other than the

adjustments permitted under Section 2.1.3 of Exhibit B to

this Appendix and the CEMS is not repaired, re-linearized

or reprogrammed (e.g., changing flow monitor polynomial

coefficients, linearity constants, or K-factors) after the trial

injections or runs

vi)

If the results of any trial gas injections or RATA runs are

outside the limits in subsection (b)(3)(G)(v) of this Section

or if the CEMS is repaired, re-linearized, or reprogrammed

after the trial injections or runs the trial injections or runs

will be counted as a failed linearity check or RATA

attempt. If this occurs, follow the procedures pertaining to

failed and aborted recertification tests in subsections

(b)(3)(G)(i) and (b)(3)(G)(ii) of this Section.

If any required recertification test is not completed within its

allotted time period, data validation must be done as follows.: for

a late linearity test, RATA system integrity check or cycle time test

that is passed on the first attempt, data from the monitoring system

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will be invalidated from the hour of expiration of the recertification

test period until the hour of completion of the late test. For a late 7-

day calibration error test, whether or not it is passed on the first

attempt, data from the monitoring system will also be invalidated

from the hour of expiration of the recertification test period until

the hour of completion of the late test. For a late linearity test,

RATA system integrity check, or cycle time test that is failed on

the first attempt or aborted on the first attempt due to a problem

with the monitor, all conditionally valid data from the monitoring

system will be considered invalid back to the hour of the first

probationary calibration error test that initiated the recertification

test period. Data from the monitoring system will remain invalid

until the hour of successful completion of the late recertification

test and any additional recertification or diagnostic tests that are

required as a result of changes made to the monitoring system to

correct problems that caused failure of the late recertification test.

If any required recertification test of a monitoring system has not

been completed by the end of a calendar quarter and if data

contained in the quarterly report are conditionally valid pending

the results of tests to be completed in a subsequent quarter, the

owner or operator must indicate this by means of a notification

within the quarterly report for that quarter. The owner or operator

must resubmit the report for that quarter if the required

recertification test is subsequently failed. If any required

recertification test is not completed by the end of a particular

calendar quarter but is completed no later than 30 days after the

end of that quarter (i.e., prior to the deadline for submitting the

quarterly report under 40 CFR 75.64, incorporated by reference in

Section 225.140), the test data and results may be submitted with

the earlier quarterly report even though the test dates are from the

next calendar quarter. In such instances, if the recertification tests

are passed in accordance with the provisions of subsection (b)(3)

of this Section, conditionally valid data may be reported as quality-

assured. The Agency may invalidate any conditionally valid data

that remains unresolved at the end of a particular calendar year.

Recertification application. The owner or operator must apply for

recertification of each continuous emission monitoring system. The owner

or operator must submit the recertification application in accordance with

40 CFR 75.60, incorporated by reference in Section 225.140, and each

complete recertification application must include the information specified

in 40 CFR 75.63, incorporated by reference in Section 225.140.

Approval or disapproval of request for recertification. The procedures for

provisional certification in subsection (a)(3) of this Section apply to

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recertification applications. The Agency will issue a notice of approval,

disapproval, or incompleteness according to the procedures in subsection

(a)(4) of this Section. Data from the monitoring system remain invalid

until all required recertification tests have been passed or until a

subsequent probationary calibration error test is passed, beginning a new

recertification test period. The owner or operator must repeat all

recertification tests or other requirements, as indicated in the Agency’s

notice of disapproval, no later than 30 unit operating days after the date of

issuance of the notice of disapproval. The owner or operator must submit a

notification of the recertification retest dates, as specified in 40 CFR

75.61(a)(1)(ii), incorporated by reference in Section 225.140, and must

submit a new recertification application according to the procedures in

subsection (b)(4) of this Section.

Initial Certification and Recertification Procedures. Prior to the applicable

deadline in 35 Ill Adm.. Code 225.240(b), the owner or operator must conduct

initial certification tests and in accordance with 40 CFR 75.63, incorporated by

reference in Section 225.140, the designated representative must submit an

application to demonstrate that the continuous emission monitoring system and

components of the system meet the specifications in Exhibit A to this Appendix.

The owner or operator must compare reference method values with output from

the automated data acquisition and handling system that is part of the continuous

mercury emission monitoring system being tested. Except as otherwise specified

in subsections (b)(1), (d), and (e) of this Section, and in Sections 6.3.1 and 6.3.2

of Exhibit A to this Appendix, the owner or operator must perform the following

tests for initial certification or recertification of continuous emission monitoring

systems according to the requirements of Exhibit B to this Appendix:

For each mercury concentration monitoring system:

A 7-day calibration error test;

A linearity check, for mercury monitors, perform this check with

elemental mercury standards;

A relative accuracy test audit must be done on a μg/scm basis;

A cycle time test;

For mercury monitors a 3-level system integrity check, using a

NIST-traceable source of oxidized mercury, as described in

Section 6.2 of Exhibit A to this Appendix. This test is not required

for a mercury monitor that does not have a converter.

For each flow monitor:

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A 7-day calibration error test;

Relative accuracy test audits, as follows:

A single-load RATA at the normal load, as defined in

Section 6.5.2.1(d) of Exhibit A to this Appendix, for a flow

monitor installed on a peaking unit or bypass stack, or for a

flow monitor exempted from multiple-load RATA testing

under Section 6.5.2(e) of Exhibit A to this Appendix;

ii)

For all other flow monitors, a RATA at each of the three

load levels corresponding to the three flue gas velocities

described in Section 6.5.2(a) of Exhibit A to this Appendix;

For each diluent gas monitor used only to monitor heat input rate:

A 7-day calibration error test;

A linearity check;

A relative accuracy test audit, where, for an O

monitor used to

determine CO

concentration, the CO

reference method must be

used for the RATA; and

A cycle-time test.

For each continuous moisture monitoring system consisting of wet- and

dry-basis O

analyzers:

A 7-day calibration error test of each O

analyzer;

A cycle time test of each O

analyzer;

A linearity test of each O

analyzer; and

A RATA directly comparing the percent moisture measured by the

monitoring system to a reference method.

For each continuous moisture sensor: A RATA directly comparing the

percent moisture measured by the monitor sensor to a reference method.

For a continuous moisture monitoring system consisting of a temperature

sensor and a data acquisition and handling system (DAHS) software

component programmed with a moisture lookup table: A demonstration

that the correct moisture value for each hour is being taken from the

moisture lookup tables and applied to the emission calculations. At a

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minimum, the demonstration must be made at three different temperatures

covering the normal range of stack temperatures from low to high.

For each sorbent trap monitoring system, perform a RATA, on a μg/dscm

basis.

For the automated data acquisition and handling system, tests designed to

verify the proper computation of hourly averages for pollutant

concentrations, flow rate, pollutant emission rates and pollutant mass

emissions.

The owner or operator must provide adequate facilities for initial

certification or recertification testing that include:

Sampling ports adequate for test methods applicable to such

facility, such that volumetric flow rate, pollutant concentration and

pollutant emission rates can be accurately determined by

applicable test methods and procedures; and

Basic facilities (e.g., electricity) for sampling and testing

equipment.

Initial Certification and Recertification and Quality Assurance Procedures for

Optional Backup Continuous Emission Monitoring Systems.

Redundant backups. The owner or operator of an optional redundant

backup CEMS must comply with all the requirements for initial

certification and recertification according to the procedures specified in

subsections (a), (b) and (c) of this Section. The owner or operator must

operate the redundant backup CEMS during all periods of unit operation,

except for periods of calibration, quality assurance, maintenance or repair.

The owner or operator must perform upon the redundant backup CEMS all

quality assurance and quality control procedures specified in Exhibit B to

this Appendix, except that the daily assessments in Section 2.1 of Exhibit

B to this Appendix are optional for days on which the redundant backup

CEMS is not used to report emission data under this Part. For any day on

which a redundant backup CEMS is used to report emission data, the

system must meet all of the applicable daily assessment criteria in Exhibit

B to this Appendix.

Non-redundant backups. The owner or operator of an optional non-

redundant backup CEMS or like-kind replacement analyzer must comply

with all of the following requirements for initial certification, quality

assurance, recertification and data reporting:

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Except as provided in subsection (d)(2)(E) of this Section, for a

regular non-redundant backup CEMS (i.e., a non-redundant backup

CEMS that has its own separate probe, sample interface, and

analyzer), or a non-redundant backup flow monitor, all of the tests

in subsection (c) of this Section are required for initial certification

of the system, except for the 7-day calibration error test.

For a like-kind replacement non-redundant backup analyzer (i.e., a

non-redundant backup analyzer that uses the same probe and

sample interface as a primary monitoring system), no initial

certification of the analyzer is required.

Each non-redundant backup CEMS or like-kind replacement

analyzer must comply with the daily and quarterly quality

assurance and quality control requirements in Exhibit B to this

Appendix for each day and quarter that the non-redundant backup

CEMS or like-kind replacement analyzer is used to report data, and

must meet the additional linearity and calibration error test

requirements specified in this subsection. The owner or operator

must ensure that each non-redundant backup CEMS or like-kind

replacement analyzer passes a linearity check (for mercury

concentration and diluent gas monitors) or a calibration error test

(for flow monitors) prior to each use for recording and reporting

emissions. When a non-redundant backup CEMS or like-kind

replacement analyzer is brought into service, prior to conducting

the linearity test, a probationary calibration error test (as described

in subsection (b)(3)(B) of this Section), which will begin a period

of conditionally valid data, may be performed in order to allow the

validation of data retrospectively, as follows. Conditionally valid

data from the CEMS or like-kind replacement analyzer are

validated back to the hour of completion of the probationary

calibration error test if the following conditions are met: if no

adjustments are made to the CEMS or like-kind replacement

analyzer other than the allowable calibration adjustments specified

in Section 2.1.3 of Exhibit B to this Appendix between the

probationary calibration error test and the successful completion of

the linearity test; and if the linearity test is passed within 168 unit

(or stack) operating hours of the probationary calibration error test.

However, if the linearity test is performed within 168 unit or stack

operating hours but is either failed or aborted due to a problem

with the CEMS or like-kind replacement analyzer, then all of the

conditionally valid data are invalidated back to the hour of the

probationary calibration error test, and data from the non-

redundant backup CEMS or from the primary monitoring system

of which the like-kind replacement analyzer is a part remain

invalid until the hour of completion of a successful linearity test.

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Notwithstanding this requirement, the conditionally valid data

status may be re-established after a failed or aborted linearity

check, if corrective action is taken and a calibration error test is

subsequently passed. However, in no case will the use of

conditional data validation extend for more than 168 unit or stack

operating hours beyond the date and time of the original

probationary calibration error test when the analyzer was brought

into service.

For each parameter monitored (i.e., CO

, O

, Hg or flow rate) at

each unit or stack, a regular non-redundant backup CEMS may not

be used to report data at that affected unit or common stack for

more than 720 hours in any one calendar year (in accordance with

40 CFR 75.74(c), incorporated by reference in Section 225.140),

unless the CEMS passes a RATA at that unit or stack. For each

parameter monitored at each unit or stack, the use of a like-kind

replacement non-redundant backup analyzer (or analyzers) is

restricted to 720 cumulative hours per calendar year, unless the

owner or operator redesignates the like-kind replacement analyzers

as components of regular non-redundant backup CEMS and each

redesignated CEMS passes a RATA at that unit or stack.

For each regular non-redundant backup CEMS, no more than eight

successive calendar quarters must elapse following the quarter in

which the last RATA of the CEMS was done at a particular unit or

stack, without performing a subsequent RATA. Otherwise, the

CEMS may not be used to report data from that unit or stack until

the hour of completion of a passing RATA at that location.

Each regular non-redundant backup CEMS must be represented in

the monitoring plan required under Section 1.10 of this Appendix

as a separate monitoring system, with unique system and

component identification numbers. When like-kind replacement

non-redundant backup analyzers are used, the owner or operator

must represent each like-kind replacement analyzer used during a

particular calendar quarter in the monitoring plan required under

Section 1.10 of this Appendix as a component of a primary

monitoring system. The owner or operator must also assign a

unique component identification number to each like-kind

replacement analyzer, beginning with the letters LK (e.g., LK1,

LK2, etc.) and must specify the manufacturer, model and serial

number of the like-kind replacement analyzer. This information

may be added, deleted or updated as necessary, from quarter to

quarter. The owner or operator must also report data from the like-

kind replacement analyzer using the system identification number

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of the primary monitoring system and the assigned component

identification number of the like-kind replacement analyzer.

When reporting data from a certified regular non-redundant backup

CEMS, use a method of determination code “02”(MODC). When

reporting data from a like-kind replacement non-redundant backup

analyzer, use a MODC of "17" (see Table 4a under Section 1.11 of

this Appendix).

For non-redundant backup mercury CEMS and sorbent trap

monitoring systems, and for like-kind replacement mercury

analyzers, the following provisions apply in addition to, or, in

some cases, in lieu of, the general requirements in subsections

(d)(2)(A) through (H) of this Section:

When a certified sorbent trap monitoring system is brought

into service as a regular non-redundant backup monitoring

system, the system must be operated according to the

procedures in Section 1.3 of this Appendix and Exhibit D

to this Appendix;

ii)

When a regular non-redundant backup mercury CEMS or a

like-kind replacement mercury analyzer is brought into

service, a linearity check with elemental mercury standards,

as described in subsection (c)(1)(B) of this Section and

Section 6.2 of Exhibit A to this Appendix, and a single-

point system integrity check, as described in Section 2.6 of

Exhibit B to this Appendix, must be performed.

Alternatively, a 3-level system integrity check, as described

in subsection (c)(1)(E) of this Section and subsection (g) of

Section 6.2 in Exhibit A to this Appendix, may be

performed in lieu of these two tests.

iii)

The weekly single-point system integrity checks described

in Section 2.6 of Exhibit B to this Appendix are required as

long as a non-redundant backup mercury CEMS or like-

kind replacement mercury analyzer remains in service,

unless the daily calibrations of the mercury analyzer are

done using a NIST-traceable source or other approved

source of oxidized mercury.

Reference method backups. A monitoring system that is operated as a

reference method backup system pursuant to the reference method

requirements of Methods 2, 3A, 30A and 30B in appendix A of 40 CFR

60, incorporated by reference in Section 225.140, need not perform and

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pass the certification tests required by subsection (c) of this Section prior

to its use pursuant to this subsection.

Certification/Recertification Procedures for Either Peaking Unit or By-pass

Stack/Duct Continuous Emission Monitoring Systems. The owner or operator of

either a peaking unit or a by-pass stack/duct continuous emission monitoring

system must comply with all the requirements for certification or recertification

according to the procedures specified in subsections (a), (b), and (c) of this

Section, except as follows: the owner or operator need only perform one Nine-run

relative accuracy test audit for certification or recertification of a flow monitor

installed on the by-pass stack/duct or on the stack/duct used only by affected

peaking units. The relative accuracy test audit must be performed during normal

operation of the peaking units or the by-pass stack/duct.

Certification/Recertification Procedures for Alternative Monitoring Systems. The

owner or operator of each alternative monitoring system approved by the Agency

as equivalent to or better than a continuous emission monitoring system according

to the criteria in subpart E of 40 CFR 75, incorporated by reference in Section

225.140, must apply for certification to the Agency prior to use of the system

under Subpart B of this Part, and must apply for recertification to the Agency

following a replacement, modification, or change according to the procedures in

subsection (c) of this Section. The owner or operator of an alternative monitoring

system must comply with the notification and application requirements for

certification or recertification according to the procedures specified in subsections

(a) and (b) of this Section.

Section 1.5 Quality Assurance and Quality Control Requirements

Continuous Emission Monitoring Systems. The owner or operator of an affected

unit must operate, calibrate and maintain each continuous mercury emission

monitoring system used to report mercury emission data as follows:

The owner or operator must operate, calibrate and maintain each primary

and redundant backup continuous emission monitoring system according

to the quality assurance and quality control procedures in Exhibit B to this

Appendix.

The owner or operator must ensure that each non-redundant backup

CEMS meets the quality assurance requirements of Section 1.4(d) of this

Appendix for each day and quarter that the system is used to report data.

The owner or operator must perform quality assurance upon a reference

method backup monitoring system according to the requirements of

Method 2 or 3A in appendix A of 40 CFR 60, incorporated by reference in

Section 225.140 (supplemented, as necessary, by guidance from the

Administrator or the Agency), or one of the mercury reference methods in

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Section 1.6 of this Appendix, as applicable, instead of the procedures

specified in Exhibit B of this Appendix.

Calibration Gases. The owner or operator must ensure that all calibration gases

used to quality assure the operation of the instrumentation required by this

Appendix must meet the definition in 40 CFR 72.2, incorporated by reference in

Section 225.140.

Section 1.6 Reference Test Methods

The owner or operator must use the following methods, which are found in

appendices A-1 through A-8 to 40 CFR 60, incorporated by reference in Section

225.140, or have been published by ASTM, to conduct the following tests:

monitoring system tests for certification or recertification of continuous mercury

emission monitoring systems; the emission tests required under Section 1.15(c)

and (d) of this Appendix; and required quality assurance and quality control tests:

Methods 1 or 1A in appendix A-1 to 40 CFR 60 are the reference methods

for selection of sampling site and sample traverses.

Method 2 or its allowable alternatives, as provided in appendix A-1 to 40

CFR 60, incorporated by reference in Section 225.140, except for Methods

2B and 2E, are the reference methods for determination of volumetric

flow.

Methods 3, 3A or 3B in appendix A-2 to 40 CFR 60 are the reference

methods for the determination of the dry molecular weight O

and CO

concentrations in the emissions.

Method 4 in appendix A-3 to 40 CFR 60 (either the standard procedure

described in Section 8.1 of the method or the moisture approximation

procedure described in Section 8.2 of the method) must be used to correct

pollutant concentrations from a dry basis to a wet basis (or from a wet

basis to a dry basis) and must be used when relative accuracy test audits of

continuous moisture monitoring systems are conducted. For the purpose of

determining the stack gas molecular weight, however, the alternative wet

bulb-dry bulb technique for approximating the stack gas moisture content

described in Section 2.2 of Method 4 may be used in lieu of the

procedures in Sections 8.1 and 8.2 of the method.

ASTM D6784-02, Standard Test Method for Elemental, Oxidized,

Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired

Stationary Sources (Ontario Hydro Method) (incorporated by reference

under Section 225.140) is the reference method for determining mercury

concentration.

194

Alternatively, Method 29 in appendix A-8 to 40 CFR 60,

incorporated by reference in Section 225.140, may be used, with

these caveats: The procedures for preparation of mercury standards

and sample analysis in Sections 13.4.1.1 through 13.4.1.3 ASTM

D6784-02 (incorporated by reference under Section 225.140) must

be followed instead of the procedures in Sections 7.5.33 and 11.1.3

of Method 29 in appendix A-8 to 40 CFR 60, and the QA/QC

procedures in Section 13.4.2 of ASTM D6784-02 (incorporated by

reference under Section 225.140) must be performed instead of the

procedures in Section 9.2.3 of Method 29 in appendix A-8 to 40

CFR 60. The tester may also opt to use the sample recovery and

preparation procedures in ASTM D6784-02 (incorporated by

reference under Section 225.140) instead of the Method 29 in

appendix A-8 to 40 CFR 60 procedures, as follows: Sections 8.2.8

and 8.2.9.1 of Method 29 in appendix A-8 to 40 CFR 60 may be

replaced with Sections 13.2.9.1 through 13.2.9.3 of ASTM D6784-

02 (incorporated by reference under Section 225.140); Sections

8.2.9.2 and 8.2.9.3 of Method 29 in appendix A-8 to 40 CFR 60

may be replaced with Sections 13.2.10.1 through 13.2.10.4 of

ASTM D6784-02 (incorporated by reference under Section

225.140); Section 8.3.4 of Method 29 in appendix A-8 to 40 CFR

60 may be replaced with Section 13.3.4 or 13.3.6 of ASTM

D6784-02 (as appropriate) (incorporated by reference under

Section 225.140); and Section 8.3.5 of Method 29 in appendix A-8

to 40 CFR 60 may be replaced with Section 13.3.5 or 13.3.6 of

ASTM D6784-02 (as appropriate) (incorporated by reference

under Section 225.140).

Whenever ASTM D6784-02 (incorporated by reference under

Section 225.140) or Method 29 in appendix A-8 to 40 CFR 60,

incorporated by reference in Section 225.140 is used, paired

sampling trains are required. To validate a RATA run or an

emission test run, the relative deviation (RD), calculated according

to Section 11.6 of Exhibit D to this Appendix, must not exceed 10

percent when the average concentration is greater than 1.0 μg/m3.

If the average concentration is less than or equal to 1.0 μg/m3, the

RD must not exceed 20 percent. The RD results are also acceptable

if the absolute difference between the mercury concentrations

measured by the paired trains does not exceed 0.03 μg/m3. If the

RD criterion is met, the run is valid. For each valid run, average

the mercury concentrations measured by the two trains (vapor

phase only).

Two additional reference methods in appendix A-8 to 40 CFR 60

that may be used to measure mercury concentration are: Method

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30A, Determination of Total Vapor Phase Mercury Emissions

from Stationary Sources (Instrumental Analyzer Procedure) and

Method 30B, "Determination of Total Vapor Phase Mercury

Emissions from Coal-Fired Combustion Sources Using Carbon

Sorbent Traps".

When Method 29 in appendix A-8 to 40 CFR 60, incorporated by

reference in Section 225.140, or ASTM D6784- 02 (incorporated

by reference under Section 225.140) is used for the mercury

emission testing required under Section 1.15(c) and (d) of this

Appendix, locate the reference method test points according to

Section 8.1 of Method 30A, and if mercury stratification testing is

part of the test protocol, follow the procedures in Sections 8.1.3

through 8.1.3.5 of Method 30A.

The owner or operator may use any of the following methods, which are found in

appendix A to 40 CFR 60, incorporated by reference in Section 225.140, or have

been published by ASTM, as a reference method backup monitoring system to

provide quality-assured monitor data:

Method 3A in appendix A-2 to 40 CFR 60 for determining O

or CO

concentration;

Method 2 in appendix A-1 to 40 CFR 60, or its allowable alternatives, as

provided in appendix A to 40 CFR 60, incorporated by reference in

Section 225.140, except for Methods 2B and 2E, for determining

volumetric flow. The sample points for reference methods must be located

according to the provisions of Section 6.5.4 of Exhibit A to this Appendix.

ASTM D6784-02, Standard Test Method for Elemental, Oxidized,

Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired

Stationary Sources (Ontario Hydro Method) (incorporated by reference

under Section 225.140) for determining mercury concentration;

Method 29 in appendix A-8 to 40 CFR 60, incorporated by reference in

Section 225.140, for determining mercury concentration;

Method 30A in appendix A-8 to 40 CFR 60 for determining mercury

concentration; and

Method 30B in appendix A-8 to 40 CFR 60 for determining mercury

concentration.

Instrumental EPA Reference Method 3A in appendix A-2 of 40 CFR 60,

incorporated by reference in Section 225.140, must be conducted using calibration

gases as defined in Section 5 of Exhibit A to this Appendix. Otherwise,

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performance tests must be conducted and data reduced in accordance with the test

methods and procedures of this Part unless the Agency:

Specifies or approves, in specific cases, the use of a reference method with

minor changes in methodology;

Approves the use of an equivalent method; or

Approves shorter sampling times and smaller sample volumes when

necessitated by process variables or other factors.

Section 1.7 Out-of-Control Periods

If an out-of-control period occurs to a monitor or continuous emission monitoring

system, the owner or operator must take corrective action and repeat the tests

applicable to the "out-of-control parameter" as described in Exhibit B to this

Appendix.

For daily calibration error tests, an out-of-control period occurs when the

calibration error of a pollutant concentration monitor exceeds the

applicable specification in Section 2.1.4 of Exhibit B to this Appendix.

For quarterly linearity checks, an out-of-control period occurs when the

error in linearity at any of three gas concentrations (low, mid-range and

high) exceeds the applicable specification in Exhibit A to this Appendix.

For relative accuracy test audits, an out-of-control period occurs when the

relative accuracy exceeds the applicable specification in Exhibit A to this

Appendix.

For weekly system integrity checks, an out-of-control period occurs when

the error exceeds the applicable specification in Exhibit A to this

Appendix.

When a monitor or continuous emission monitoring system is out-of-control, any

data recorded by the monitor or monitoring system are not quality-assured and

must not be used in calculating monitor data availabilities pursuant to Section 1.8

to this Appendix.

When a monitor or continuous emission monitoring system is out-of-control, the

owner or operator must take one of the following actions until the monitor or

monitoring system has successfully met the relevant criteria in Exhibits A and B

to this Appendix as demonstrated by subsequent tests:

Use a certified backup monitoring system or a reference method for

measuring and recording emissions from the affected units; or

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Adjust the gas discharge paths from the affected units with emissions

normally observed by the out-of-control monitor or monitoring system so

that all exhaust gases are monitored by a certified monitor or monitoring

system meeting the requirements of Exhibits A and B to this Appendix.

Section 1.8

Determination of Monitor Data Availability

Following initial certification of the required CO

, O

, flow monitoring systems,

Hg concentration, or moisture monitoring system(s) at a particular unit or stack

location (i.e., the date and time at which quality-assured data begins to be

recorded by CEMSs at that location), the owner or operator must begin

calculating the percent monitor data availability as described in subsection (a)(1)

of this Section, by means of the automated data acquisition and handling system,

and the percent monitor data availability for each monitored parameter.

Following initial certification, the owner or operator must use Equation 8

to calculate, hourly, percent monitor data availability for each calendar

quarter or 12-month rolling period, as applicable according to the schedule

provided in Section 225.260(b).

Total unit or stack operating hours

for which quality-assured data

Percent

was recorded for the appropriate time period

Total unit or stack operating hours

for the appropriate time period

When calculating percent monitor data availability using Equation 8, the

owner or operator must include all unit operating hours, and all monitor

operating hours for which quality-assured data were recorded by a

certified primary monitor; a certified redundant or non-redundant backup

monitor or a reference method for that unit.

Section 1.9 Determination of Sorbent Trap Monitoring Systems Data Availability

If a primary sorbent trap monitoring system has not been certified by the

applicable compliance date specified under Subpart B of this Part, and if quality-

assured mercury concentration data from a certified backup mercury monitoring

system, reference method or approved alternative monitoring system are

unavailable, the owner or operator must perform quarterly emissions testing in

accordance with Section 225.239 until such time the primary sorbent trap

monitoring system has been certified.

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For a certified sorbent trap system, a missing data period will occur in the

following circumstances, unless quality-assured mercury concentration data from

a certified backup mercury CEMS, sorbent trap system, reference method or

approved alternative monitoring system are available:

A gas sample is not extracted from the stack during unit operation (e.g.,

during a monitoring system malfunction or when the system undergoes

maintenance); or

The results of the mercury analysis for the paired sorbent traps are missing

or invalid (as determined using the quality assurance procedures in Exhibit

D to this Appendix). The missing data period begins with the hour in

which the paired sorbent traps for which the mercury analysis is missing

or invalid were put into service. The missing data period ends at the first

hour in which valid mercury concentration data are obtained with another

pair of sorbent traps (i.e., the hour at which this pair of traps was placed in

service), or with a certified backup mercury CEMS, reference method or

approved alternative monitoring system.

Following initial certification of the sorbent trap monitoring system, begin

reporting the percent monitor data availability in accordance with Section 1.8 of

this Appendix.

Section 1.10 Monitoring Plan

The owner or operator of an affected unit must prepare and maintain a mercury

emissions monitoring plan.

Whenever the owner or operator makes a replacement, modification or change in

the certified CEMS, including a change in the automated data acquisition and

handling system or in the flue gas handling system, that affects information

reported in the monitoring plan (e.g., a change to a serial number for a component

of a monitoring system), then the owner or operator must update the monitoring

plan, by the applicable deadline specified in 40 CFR 75.62, incorporated by

reference in Section 225.140, or elsewhere in this Appendix.

Contents of the Mercury Monitoring Plan. The requirements of subsection (d) of

this Section must be met on and after July 1, 2009. Each monitoring plan must

contain the information in subsection (d)(1) of this Section in electronic format

and the information in subsection (d)(2) of this Section in hardcopy format.

Electronic storage of all monitoring plan information, including the hardcopy

portions, is permissible provided that a paper copy of the entire monitoring plan

can be furnished upon request for audit purposes.

The following information must be retained on site in electronic storage

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and furnished to the Agency in hardcopy, upon request for audit purposes.

The facility ORISPL number developed by the Department of

Energy and used in the National Allowance Data Base (or

equivalent facility ID number assigned by USEPA, if the facility

does not have an ORISPL number). Also provide the following

information for each unit and (as applicable) for each common

stack and/or pipe, and each multiple stack and/or pipe involved in

the monitoring plan:

A representation of the exhaust configuration for the units

in the monitoring plan. Provide the ID number of each unit

and assign a unique ID number to each common stack,

common pipe, multiple stack, and/or multiple pipe

associated with the units represented in the monitoring

plan. For common and multiple stacks and/or pipes,

provide the activation date and deactivation date (if

applicable) of each stack and/or pipe;

ii)

Identification of the monitoring system locations (e.g., at

the unit-level, on the common stack, at each multiple stack,

etc.). Provide an indicator (flag) if the monitoring location

is at a bypass stack or in the ductwork (breeching);

iii)

The stack exit height (ft) above ground level and ground

level elevation above sea level, and the inside cross-

sectional area (ft

) at the flue exit and at the flow

monitoring location (for units with flow monitors, only).

Also use appropriate codes to indicate the materials of

construction and the shapes of the stack or duct cross-

sections at the flue exit and (if applicable) at the flow

monitor location;

iv)

The types of fuels fired by each unit. Indicate the start and

(if applicable) end date of combustion for each type of fuel,

and whether the fuel is the primary, secondary, emergency,

or startup fuel;

The types of emission controls that are used to reduce

mercury emissions from each unit. Also provide the

installation date, optimization date, and retirement date (if

applicable) of the emission controls, and indicate whether

the controls are an original installation; and

vi)

Maximum hourly heat input capacity of each unit.

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For each monitored parameter (i.e., mercury concentration, diluent

concentration, moisture or flow) at each monitoring location,

specify the monitoring methodology for the parameter. If the

unmonitored bypass stack approach is used for a particular

parameter, indicate this by means of an appropriate code. Provide

the activation date/hour, and deactivation date/hour (if applicable)

for each monitoring methodology.

For each required continuous emission monitoring system and each

sorbent trap monitoring system (as defined in Section 225.130),

identify and describe the major monitoring components in the

monitoring system (e.g., gas analyzer, flow monitor, moisture

sensor, DAHS software, etc.). Other important components in the

system (e.g., sample probe, PLC, data logger, etc.) may also be

represented in the monitoring plan, if necessary. Provide the

following specific information about each component and

monitoring system:

For each required monitoring system, assign a unique, 3-

character alphanumeric identification code to the system;

indicate the parameter monitored by the system; designate

the system as a primary, redundant backup, non-redundant

backup, data backup or reference method backup system, as

provided in Section 1.2(d) of this Appendix; and indicate

the system activation date/hour and deactivation date/hour

(as applicable).

ii)

For each component of each monitoring system represented

in the monitoring plan, assign a unique, 3-character

alphanumeric identification code to the component;

indicate the manufacturer, model and serial number;

designate the component type; for gas analyzers, indicate

the moisture basis of measurement; indicate the method of

sample acquisition or operation, (e.g., extractive pollutant

concentration monitor or thermal flow monitor); and

indicate the component activation date/hour and

deactivation date/hour (as applicable).

Explicit formulas, using the component and system identification

codes for the primary monitoring system, and containing all

constants and factors required to derive the required emission rates,

heat input rates, etc. from the hourly data recorded by the

monitoring systems. Formulas using the system and component ID

codes for backup monitoring systems are required only if different

formulas for the same parameter are used for the primary and

backup monitoring systems (e.g., if the primary system measures

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pollutant concentration on a different moisture basis from the

backup system). Provide the equation number or other appropriate

code for each emissions formula (e.g., use code F-1 if Equation F-1

in Exhibit C to this Appendix is used to calculate SO

mass

emissions). Also identify each emissions formula with a unique

three character alphanumeric code. The formula effective start

date/hour and inactivation date/hour (as applicable) must be

included for each formula.

For each parameter monitored with CEMS, provide the following

information:

Measurement scale;

ii)

Maximum potential value (and method of calculation);

iii)

Maximum expected value (if applicable) and method of

calculation;

iv)

Span values and full-scale measurement ranges;

Daily calibration units of measure;

vi)

Effective date/hour, and (if applicable) inactivation

date/hour of each span value.

If the monitoring system or excepted methodology provides for the

use of a constant, assumed or default value for a parameter under

specific circumstances, then include the following information for

each such value for each parameter:

Identification of the parameter;

ii)

Default, maximum, minimum, or constant value, and units

of measure for the value;

iii)

Purpose of the value;

iv)

Indicator of use, i.e., during controlled hours, uncontrolled

hours or all operating hours;

Value effective date and hour;

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viii)

Date and hour value is no longer effective (if applicable);

and

Unless otherwise specified in Section 6.5.2.1 of Exhibit A to this

Appendix, for each unit or common stack on which hardware

CEMS are installed:

Maximum hourly gross load (in MW, rounded to the

nearest MW, or steam load in 1000 lb/hr (i.e., klb/hr),

rounded to the nearest klb/hr, or thermal output in

mmBtu/hr, rounded to the nearest mmBtu/hr), for units that

produce electrical or thermal output;

ii)

The upper and lower boundaries of the range of operation

(as defined in Section 6.5.2.1 of Exhibit A to this

Appendix), expressed in megawatts, thousands of lb/hr of

steam, mmBtu/hr of thermal output or ft/sec (as

applicable);

iii)

Except for peaking units, identify the most frequently and

second most frequently used load (or operating) levels (i.e.,

low, mid or high) in accordance with Section 6.5.2.1 of

Exhibit A to this Appendix, expressed in megawatts,

thousands of lb/hr of steam, mmBtu/hr of thermal output or

ft/sec (as applicable);

iv)

An indicator of whether the second most frequently used

load (or operating) level is designated as normal in Section

6.5.2.1 of Exhibit A to this Appendix;

The date of the data analysis used to determine the normal

load (or operating) levels and the two most frequently-used

load (or operating) levels (as applicable); and

vi)

Activation and deactivation dates and hours, when the

maximum hourly gross load, boundaries of the range of

operation, normal load (or operating) level(s) or two most

frequently-used load (or operating) levels change and are

updated.

For each unit for which CEMS are not installed, the maximum

hourly gross load (in MW, rounded to the nearest MW, or steam

load in klb/hr, rounded to the nearest klb/hr or steam load in

mmBtu/hr, rounded to the nearest mmBtu/hr);

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For each unit with a flow monitor installed on a rectangular stack

or duct, if a wall effects adjustment factor (WAF) is determined

and applied to the hourly flow rate data:

Stack or duct width at the test location, ft;

ii)

Stack or duct depth at the test location, ft;

iii)

Wall effects adjustment factor (WAF), to the nearest

0.0001;

iv)

Method of determining the WAF;

WAF effective date and hour;

vi)

WAF no longer effective date and hour (if applicable);

vii)

WAF determination date;

viii)

Number of WAF test runs;

ix)

Number of Method 1 traverse points in the WAF test;

Number of test ports in the WAF test; and

xi)

Number of Method 1 traverse points in the reference flow

RATA.

Hardcopy

Information, including (as applicable): Identification of the test

strategy; protocol for the relative accuracy test audit; other relevant

test information; calibration gas levels (percent of span) for the

calibration error test and linearity check and span; and

apportionment strategies under Sections 1.2 and 1.3 of this

Appendix.

Description of site locations for each monitoring component in the

continuous emission monitoring systems, including schematic

diagrams and engineering drawings specified in 40 CFR

75.53(g)(2)(iv) and (g)(2)(v), incorporated by reference in Section

225.140 and any other documentation that demonstrates each

monitor location meets the appropriate siting criteria.

A data flow diagram denoting the complete information handling

path from output signals of CEMS components to final reports.

204

For units monitored by a continuous emission monitoring system, a

schematic diagram identifying entire gas handling system from

boiler to stack for all affected units, using identification numbers

for units, monitoring systems and components, and stacks

corresponding to the identification numbers provided in

subsections (c)(1)(A) and C) of this Section. The schematic

diagram must depict stack height and the height of any monitor

locations. Comprehensive and/or separate schematic diagrams

must be used to describe groups of units using a common stack.

For units monitored by a continuous emission monitoring system,

stack and duct engineering diagrams showing the dimensions and

location of fans, turning vanes, air preheaters, monitor

components, probes, reference method sampling ports and other

equipment that affects the monitoring system location,

performance, or quality control checks.

Section 1.11 General Recordkeeping Provisions

The owner or operator must meet all of the applicable recordkeeping requirements of Section

225.290 and of this Section.

Recordkeeping Requirements for Affected Sources. The owner or operator of any

affected source subject to the requirements of this Appendix must maintain for

each affected unit a file of all measurements, data, reports, and other information

required by Subpart B of this Part at the source in a form suitable for inspection

for at least 5 years from the date of each record. The file must contain the

following information:

The data and information required in subsections (b) through (h) of this

Section, beginning with the earlier of the date of provisional certification

or July 1, 2009;

The supporting data and information used to calculate values required in

subsections (b) through (g) of this Section, excluding the subhourly data

points used to compute hourly averages under Section 1.2(c) of this

Appendix, beginning with the earlier of the date of provisional

certification or July 1, 2009;

The data and information required in Section 1.12 of this Appendix for

specific situations, beginning with the earlier of the date of provisional

certification or July 1, 2009;

The certification test data and information required in Section 1.13 of this

Appendix for tests required under Section 1.4 of this Appendix, beginning

205

with the date of the first certification test performed, the quality assurance

and quality control data and information required in Section 1.13 of this

Appendix for tests, and the quality assurance/quality control plan required

under Section 1.5 of this Appendix and Exhibit B to this Appendix,

beginning with the date of provisional certification;

The current monitoring plan as specified in Section 1.10 of this Appendix,

beginning with the initial submission to the Agency required by 40 CFR

75.62, incorporated by reference in Section 225.140; and

The quality control plan as described in Section 1 of Exhibit B to this

Appendix, beginning with the date of provisional certification.

Operating Parameter Record Provisions. The owner or operator must record for

each hour the following information on unit operating time, heat input rate and

load, separately for each affected unit and also for each group of units utilizing a

common stack and a common monitoring system:

Date and hour;

Unit operating time (rounded up to the nearest fraction of an hour (in

equal increments that can range from one hundredth to one quarter of an

hour, at the option of the owner or operator));

Hourly gross unit load (rounded to nearest MWge), or steam load in 1000

lbs/hr at stated temperatures and pressures, rounded to the nearest 1000

lbs/hr;

Operating load range corresponding to hourly gross load of 1 to 10, except

for units using a common stack, which may use up to 20 load ranges for

stack gas flow rate, as specified in the monitoring plan;

Hourly heat input rate (mmBtu/hr, rounded to the nearest tenth);

Identification code for formula used for heat input, as provided in Section

1.10 of this Appendix; and

For Mercury CEMS units only, F-factor for heat input calculation.

Diluent Record Provisions. The owner or operator of a unit using a flow monitor

and an O

diluent monitor to determine heat input, in accordance with Equation F-

17 or F-18 of Exhibit C to this Appendix, or a unit that accounts for heat input

using a flow monitor and a CO

diluent monitor (which is used only for heat input

determination and is not used as a CO

pollutant concentration monitor) must

keep the following records for the O

or CO

diluent monitor:

206

Component-system identification code as provided in Section 1.10 of this

Appendix;

Date and hour;

Hourly average diluent gas (O

or CO

) concentration (in percent, rounded

to the nearest tenth);

Percent monitor data availability for the diluent monitor (recorded to the

nearest tenth of a percent) calculated pursuant to Section 1.8 of this

Appendix; and

Method of determination code for diluent gas (O

or CO

) concentration

data using Codes 1-55 in Table 4a of this Section.

Missing Data Records. The owner or operator must record the causes of any

missing data periods and the actions taken by the owner or operator to correct

such causes.

Mercury Emission Record Provisions (CEMS). The owner or operator must

record for each hour the information required by this subsection for each affected

unit using mercury CEMS in combination with flow rate, and (in certain cases)

moisture, and diluent gas monitors, to determine mercury concentration and (if

applicable) unit heat input under Subpart B of this Part.

For mercury concentration during unit operation, as measured and

reported from each certified primary monitor, certified back-up monitor or

other approved method of emissions determination:

Component-system identification code as provided in Section 1.10

of this Appendix;

Date and hour;

Hourly mercury concentration (μg/scm, rounded to the nearest

tenth);

Method of determination for hourly mercury concentration using

Codes 1-55 in Table 4a of this Section; and

The percent monitor data availability (to the nearest tenth of a

percent) calculated pursuant to Section 1.8 of this Appendix.

For flue gas moisture content during unit operation (if required), as

measured and reported from each certified primary monitor certified back-

up monitor or other approved method of emissions determination (except

207

where a default moisture value is approved under 40 CFR 75.66,

incorporated by reference in Section 225.140):

Component-system identification code, as provided in Section 1.10

of this Appendix;

Date and hour;

Hourly average moisture content of flue gas (percent, rounded to

the nearest tenth). If the continuous moisture monitoring system

consists of wet-and dry-basis oxygen analyzers, also record both

the wet- and dry-basis oxygen hourly averages (in percent O

rounded to the nearest tenth);

Percent monitor data availability (recorded to the nearest tenth of a

percent) for the moisture monitoring system calculated pursuant to

Section 1.8 of this Appendix; and

Method of determination for hourly average moisture percentage

using Codes 1-55 in Table 4a of this Section.

For diluent gas (O

or CO

) concentration during unit operation (if

required), as measured and reported from each certified primary monitor,

certified back-up monitor or other approved method of emissions

determination:

Component-system identification code as provided in Section 1.10

of this Appendix;

Date and hour;

Hourly average diluent gas (O

or CO

) concentration (in percent,

rounded to the nearest tenth);

Method of determination code for diluent gas (O

or CO

)

concentration data using Codes 1-55 in Table 4a of this Section;

and

The percent monitor data availability (to the nearest tenth of a

percent) for the O

or CO

monitoring system (if a separate O

monitoring system is used for heat input determination)

calculated pursuant to Section 1.8 of this Appendix.

For stack gas volumetric flow rate during unit operation, as measured and

reported from each certified primary monitor, certified back-up monitor or

other approved method of emissions determination, record the information

208

required under 40 CFR 75.57(c)(2)(i) through (vi), incorporated by

reference in Section 225.140.

For mercury mass emissions during unit operation, as measured and

reported from the certified primary monitoring systems, certified

redundant or non-redundant back-up monitoring systems, or other

approved methods of emissions determination:

Date and hour;

Hourly mercury mass emissions (ounces, rounded to three decimal

places);

Identification code for emissions formula used to derive hourly

mercury mass emissions from mercury concentration, flow rate

and moisture data, as provided in Section 1.10 of this Appendix.

Mercury Emission Record Provisions (Sorbent Trap Systems). The owner or

operator must record for each hour the information required by this subsection,

for each affected unit using sorbent trap monitoring systems in combination with

flow rate, moisture, and (in certain cases) diluent gas monitors, to determine

mercury mass emissions and (if required) unit heat input under this Part.

For mercury concentration during unit operation, as measured and

reported from each certified primary monitor, certified back-up monitor or

other approved method of emissions determination:

Component-system identification code as provided in Section 1.10

of this Appendix;

Date and hour;

Hourly mercury concentration (μg/dscm, rounded to the nearest

tenth). For a particular pair of sorbent traps, this will be the flow-

proportional average concentration for the data collection period;

Method of determination for hourly average mercury concentration

using Codes 1- 55 in Table 4a of this Section; and

Percent monitor data availability (recorded to the nearest tenth of a

percent) calculated pursuant to Section 1.8 of this Appendix;

For flue gas moisture content during unit operation, as measured and

reported from each certified primary monitor certified back-up monitor, or

other approved method of emissions determination (except where a default

moisture value is approved under 40 CFR 75.66, incorporated by reference

209

in Section 225.140), record the information required under subsections

(e)(2)(A) through (E) of this Section;

For diluent gas (O

or CO

) concentration during unit operation (if

required for heat input determination), record the information required

under subsections (e)(3)(A) through (E) of this Section.

For stack gas volumetric flow rate during unit operation, as measured and

reported from each certified primary monitor, certified back-up monitor or

other approved method of emissions determination, record the information

required under 40 CFR 75.57(c)(2)(i) through (vi), incorporated by

reference in Section 225.140.

For mercury mass emissions during unit operation, as measured and

reported from the certified primary monitoring systems, certified

redundant or non-redundant back-up monitoring systems or other

approved methods of emissions determination, record the information

required under subsection (e)(5) of this Section.

Record the average flow rate of stack gas through each sorbent trap (in

appropriate units, e.g., liters/min, cc/min, dscm/min).

Record the gas flow meter reading (in dscm, rounded to the nearest

hundredth) at the beginning and end of the collection period and at least

once in each unit operating hour during the collection period.

Calculate and record the ratio of the bias-adjusted stack gas flow rate to

the sample flow rate, as described in Section 11.2 of Exhibit D to this

Appendix.

Table 4a -

Codes for Method of Emissions and Flow Determination Code

Hourly emissions/flow measurement or estimation method

Certified primar emission/flow monitoring system.

Certified backup emission/flow monitoring system.

Approved alternative monitoring system.

Reference method.

Like-ind replacement non-redundant backup analyzer

Hourly HG concentration determined rom analysis of a

Single trap invalidated or damaged (See Exhibit D,

section 8.

Hourly HG concentration determined from the trap

resulting in the higher HG concentration when the

relative deciation criterion for the paired trap is not

met (See Exhibit D, section 8).

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Fuel Specific default value (or prorated default value)

used for the hour

Other quality assured methodologies approved through

petition. These hours are included in missing data

lookback and are treated as unavailable hours for

percent monitor availability calculations.

Section 1.12 General Recordkeeping Provisions for Specific Situations

The owner or operator must meet all of the applicable recordkeeping requirements of this

Section. In accordance with 40 CFR 75.34, incorporated by reference in Section 225.140, the

owner or operator of an affected unit with add-on emission controls must record the applicable

information in this Section for each hour of missing mercury concentration data. Except as

otherwise provided in 40 CFR 75.34(d), incorporated by reference in Section 225.140, for units

with add-on mercury emission controls, the owner or operator must record:

Parametric data that demonstrate, for each hour of missing mercury emission data,

the proper operation of the add-on emission controls, as described in the quality

assurance/quality control program for the unit. The parametric data must be

maintained on site and must be submitted, upon request, to the Agency.

Alternatively, for units equipped with flue gas desulfurization (FGD) systems, the

owner or operator may use quality-assured data from a certified SO

monitor to

demonstrate proper operation of the emission controls during periods of missing

mercury data;

A flag indicating, for each hour of missing mercury emission data, either that the

add-on emission controls are operating properly, as evidenced by all parameters

being within the ranges specified in the quality assurance/quality control program,

or that the add-on emission controls are not operating properly.

Section 1.13 Certification, Quality Assurance, and Quality Control Record Provisions

The owner or operator must meet all of the applicable recordkeeping requirements of this

Section.

Continuous Emission Monitoring Systems

The owner or operator must record the

applicable information in this Section for each certified monitor or certified

monitoring system (including certified backup monitors) measuring and recording

emissions or flow from an affected unit. Further, the owner or operator must

verify (e.g., by means of a certificate or data from the cylinder gas vendor or

CEMS vendor) that only “calibration gas” (as defined in 40 CFR 72.2,

incorporated by reference in Section 225.140 and in Exhibit A to this Appendix)

is used for all required calibration error test, linearity checks, and system integrity

checks.

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For each flow monitor, mercury monitor or diluent gas monitor (including

wet- and dry-basis O

monitors used to determine percent moisture), the

owner or operator must record the following for all daily and 7-day

calibration error tests, all weekly system integrity checks and all off-line

calibration demonstrations, including any follow-up tests after corrective

action:

Component-system identification code (on and after January 1,

2009, only the component identification code is required);

Instrument span and span scale;

Date and hour;

Reference value (i.e., calibration gas concentration or reference

signal value, in ppm or other appropriate units);

Observed value (monitor response during calibration, in ppm or

other appropriate units);

Percent calibration or measurement error (rounded to the nearest

tenth of a percent) (flag if using alternative performance

specification for low emitters or differential pressure flow

monitors);

Reference signal or calibration gas level;

For 7-day calibration error tests, a test number and reason for test;

Description of any adjustments, corrective actions, or maintenance

prior to a passed test or following a failed test; and

Indication of whether the unit is off-line or on-line.

For each flow monitor, the owner or operator must record the following

for all daily interference checks, including any follow-up tests after

corrective action.

Component-system identification code (after January 1, 2009, only

the component identification code is required);

Date and hour;

Code indicating whether monitor passes or fails the interference

check; and

212

Description of any adjustments, corrective actions or maintenance

prior to a passed test or following a failed test.

For each mercury concentration monitor, or diluent gas monitor (including

wet- and dry-basis O

monitors used to determine percent moisture), the

owner or operator must record the following for the initial and all

subsequent linearity checks and 3-level system integrity checks (mercury

monitors with converters, only), including any follow-up tests after

corrective action:

Component-system identification code (on and after July 1, 2009,

only the component identification code is required);

Instrument span and span scale (only span scale is required on and

after July 1, 2009);

Calibration gas level;

Date and time (hour and minute) of each gas injection at each

calibration gas level;

Reference value (i.e., reference gas concentration for each gas

injection at each calibration gas level, in ppm or other appropriate

units);

Observed value (monitor response to each reference gas injection

at each calibration gas level, in ppm or other appropriate units);

Mean of reference values and mean of measured values at each

calibration gas level;

Linearity error or measurement error at each of the reference gas

concentrations (rounded to nearest tenth of a percent) (flag if using

alternative performance specification);

Test number and reason for test (flag if aborted test); and

Description of any adjustments, corrective action, or maintenance

prior to a passed test or following a failed test.

For each differential pressure type flow monitor, the owner or operator

must record items in subsections (a)(4)(A) through (E) of this Section, for

all quarterly leak checks, including any follow-up tests after corrective

action. For each flow monitor, the owner or operator must record items in

subsections (a)(4)(F) and (G) of this Section for all flow-to-load ratio and

gross heat rate tests:

213

Component-system identification code (on and after July 1, 2009,

only the system identification code is required).

Date and hour.

Reason for test.

Code indicating whether monitor passes or fails the quarterly leak

check.

Description of any adjustments, corrective actions or maintenance

prior to a passed test or following a failed test.

Test data from the flow-to-load ratio or gross heat rate (GHR)

evaluation, including:

Monitoring system identification code;

ii)

Calendar year and quarter;

iii)

Indication of whether the test is a flow-to-load ratio or

gross heat rate evaluation;

iv)

Indication of whether bias adjusted flow rates were used;

Average absolute percent difference between reference

ratio (or GHR) and hourly ratios (or GHR values);

vi)

Test result;

vii)

Number of hours used in final quarterly average;

viii)

Number of hours exempted for use of a different fuel type;

ix)

Number of hours exempted for load ramping up or down;

Number of hours exempted for scrubber bypass;

xi)

Number of hours exempted for hours preceding a normal-

load flow RATA;

xii)

Number of hours exempted for hours preceding a

successful diagnostic test, following a documented monitor

repair or major component replacement;

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xiii)

Number of hours excluded for flue gases discharging

simultaneously thorough a main stack and a bypass stack;

and

xiv)

Test number.

Reference data for the flow-to-load ratio or gross heat rate

evaluation, including (as applicable):

Reference flow RATA end date and time;

ii)

Test number of the reference RATA;

iii)

Reference RATA load and load level;

iv)

Average reference method flow rate during reference flow

RATA;

Reference flow/load ratio;

vi)

Average reference method diluent gas concentration during

flow RATA and diluent gas units of measure;

vii)

Fuel specific F

-or F

-factor during flow RATA and F-

factor units of measure;

viii)

Reference gross heat rate value;

ix)

Monitoring system identification code;

Average hourly heat input rate during RATA;

xi)

Average gross unit load;

xii)

Operating load level; and

xiii)

An indicator (flag) if separate reference ratios are

calculated for each multiple stack.

For each flow monitor, each diluent gas (O

or CO

) monitor used to

determine heat input, each moisture monitoring system, mercury

concentration monitoring system, each sorbent trap monitoring system and

each approved alternative monitoring system the owner or operator must

record the following information for the initial and all subsequent relative

accuracy test audits:

215

Reference methods used.

Individual test run data from the relative accuracy test audit for the

flow monitor, CO

emissions concentration monitor-diluent

continuous emission monitoring system, diluent gas (O

or CO

)

monitor used to determine heat input, moisture monitoring system,

mercury concentration monitoring system, sorbent trap monitoring

system or approved alternative monitoring system, including:

Date, hour and minute of beginning of test run;

ii)

Date, hour and minute of end of test run;

iii)

Monitoring system identification code;

iv)

Test number and reason for test;

Operating level (low, mid, high or normal, as appropriate)

and number of operating levels comprising test;

vi)

Normal load (or operating level) indicator for flow RATAs

(except for peaking units);

Run value from CEMS being tested, in the appropriate

units of measure;

Run value from reference method, in the appropriate units

of measure;

xi)

Flag value (0, 1 or 9, as appropriate) indicating whether run

has been used in calculating relative accuracy and bias

values or whether the test was aborted prior to completion;

xii)

Average gross unit load, expressed as a total gross unit

load, rounded to the nearest MWe, or as steam load,

rounded to the nearest 1000 lb/hr; and

xiii)

Flag to indicate whether an alternative performance

specification has been used.

Calculations and tabulated results, as follows:

216

Arithmetic mean of the monitoring system measurement

values, of the reference method values and of their

differences, as specified in Equation A–7 in Exhibit A to

this Appendix;

ii)

Standard deviation, as specified in Equation A–8 in Exhibit

A to this Appendix;

iii)

Confidence coefficient, as specified in Equation A–9 in

Exhibit A to this Appendix;

iv)

Statistical t value used in calculations;

Relative accuracy test results, as specified in Equation A–

10 in Exhibit A to this Appendix. For multi-load flow

monitor tests the relative accuracy test results must be

recorded at each load level tested. Each load level must be

expressed as a total gross unit load, rounded to the nearest

MWe, or as steam load, rounded to the nearest 1000 lb/hr;

Description of any adjustment, corrective action or maintenance

prior to a passed test or following a failed or aborted test.

For flow monitors, the equation used to characterize the flow

monitor and the numerical values of the polynomial coefficients or

K factors of that equation.

For moisture monitoring systems, the coefficient or K factor or

other mathematical algorithm used to adjust the monitoring system

with respect to the reference method.

For each mercury concentration monitor, and each CO

or O

monitor

used to determine heat input, the owner or operator must record the

following information for the cycle time test:

Component-system identification code (on and after July 1, 2009,

only the component identification code is required);

Date;

Start and end times;

Upscale and downscale cycle times for each component;

Stable start monitor value;

217

Stable end monitor value;

Reference value of calibration gases;

Calibration gas level;

Total cycle time;

Reason for test; and

Test number.

In addition to the information in subsection (a)(5) of this Section, the

owner or operator must record, for each relative accuracy test audit,

supporting information sufficient to substantiate compliance with all

applicable Sections and Appendices in this Part. Unless otherwise

specified in this part or in an applicable test method, the information in

subsections (a)(7)(A) through (H) of this Section may be recorded either

in hard copy format, electronic format or a combination of the two, and

the owner or operator must maintain this information in a format suitable

for inspection and audit purposes. This RATA supporting information

must include, but must not be limited to, the following data elements:

For each RATA using Reference Method 2 (or its allowable

alternatives) in appendix A to 40 CFR 60, incorporated by

reference in Section 225.140, to determine volumetric flow rate:

Information indicating whether or not the location meets

requirements of Method 1 in appendix A to 40 CFR 60,

incorporated by reference in Section 225.140; and

ii)

Information indicating whether or not the equipment passed

the required leak checks.

For each run of each RATA using Reference Method 2 (or its

allowable alternatives in appendix A to 40 CFR 60, incorporated

by reference in Section 225.140) to determine volumetric flow

rate, record the following data elements (as applicable to the

measurement method used):

Operating level (low, mid, high or normal, as appropriate);

ii)

Number of reference method traverse points;

iii)

Average stack gas temperature (°F);

218

iv)

Barometric pressure at test port (inches of mercury);

Stack static pressure (inches of H

O);

vi)

Absolute stack gas pressure (inches of mercury);

vii)

Percent CO

and O

in the stack gas, dry-basis;

viii)

and O

reference method used;

ix)

Moisture content of stack gas (percent H

O);

Molecular weight of stack gas, dry-basis (lb/lb-mole);

xi)

Molecular weight of stack gas, wet-basis (lb/lb-mole);

xii)

Stack diameter (or equivalent diameter) at the test port (ft);

xiii)

Average square root of velocity head of stack gas (inches of

O) for the run;

xiv)

Stack or duct cross-sectional area at test port (ft

);

xv)

Average velocity (ft/sec);

xvi)

Average stack flow rate, adjusted, if applicable, for wall

effects (scfh, wet-basis);

xvii)

Flow rate reference method used;

xviii) Average velocity, adjusted for wall effects;

xix)

Calculated (site-specific) wall effects adjustment factor

determined during the run, and, if different, the wall effects

adjustment factor used in the calculations; and

xx)

Default wall effects adjustment factor used.

For each traverse point of each run of each RATA using Reference

Method 2 (or its allowable alternatives in appendix A to 40 CFR

60, incorporated by reference in Section 225.140) to determine

volumetric flow rate, record the following data elements (as

applicable to the measurement method used):

Reference method probe type;

219

ii)

Pressure measurement device type;

iii)

Traverse point ID;

iv)

Probe or pitot tube calibration coefficient;

Date of latest probe or pitot tube calibration;

vi)

Average velocity differential pressure at traverse point

(inches of H

O) or the average of the square roots of the

velocity differential pressures at the traverse point ((inches

, stack temperature at the traverse point (°F);

viii)

Composite (wall effects) traverse point identifier;

ix)

Number of points included in composite traverse point;

Yaw angle of flow at traverse point (degrees);

xi)

Pitch angle of flow at traverse point (degrees);

xii)

Calculated velocity at traverse point both accounting and

not accounting for wall effects (ft/sec); and

xiii)

Probe identification number.

For each RATA using Reference Method 3A in appendix A to 40

CFR 60, incorporated by reference in Section 225.140, to

determine, CO

, or O

concentration:

Pollutant or diluent gas being measured;

ii)

Span of reference method analyzer;

iii)

Type of reference method system (e.g., extractive or

dilution type);

iv)

Reference method dilution factor (dilution type systems

only);

Reference gas concentrations (zero, mid, and high gas

levels) used for the 3-point pre-test analyzer calibration

error test (or, for dilution type reference method systems,

220

for the 3-point pre-test system calibration error test) and for

any subsequent recalibrations;

vi)

Analyzer responses to the zero- mid- and high-level

calibration gases during the 3-point pre-test analyzer (or

system) calibration error test and during any subsequent

recalibrations;

vii)

Analyzer calibration error at each gas level (zero, mid and

high) for the 3-point pre-test analyzer (or system)

calibration error test and for any subsequent recalibrations

(percent of span value);

viii)

Upscale gas concentration (mid or high gas level) used for

each pre-run or post-run system bias check or (for dilution

type reference method systems) for each pre-run or post-

run system calibration error check;

ix)

Analyzer response to the calibration gas for each pre-run or

post-run system bias (or system calibration error) check;

The arithmetic average of the analyzer responses to the

zero-level gas, for each pair of pre- and post-run system

bias (or system calibration error) checks;

xi)

The arithmetic average of the analyzer responses to the

upscale calibration gas for each pair of pre- and post-run

system bias (or system calibration error) checks;

xii)

The results of each pre-run and each post-run system bias

(or system calibration error) check using the zero-level gas

(percentage of span value);

xiii)

The results of each pre-run and each post-run system bias

(or system calibration error) check using the upscale

calibration gas (percentage of span value);

xiv)

Calibration drift and zero drift of analyzer during each

RATA run (percentage of span value);

xv)

Moisture basis of the reference method analysis;

xvi)

Moisture content of stack gas, in percent, during each test

run (if needed to convert to moisture basis of CEMS being

tested);

221

xvii) Unadjusted (raw) average pollutant or diluent gas

concentration for each run;

xviii) Average pollutant or diluent gas concentration for each run,

corrected for calibration bias (or calibration error) and, if

applicable, corrected for moisture;

xix)

The F-factor used to convert reference method data to units

of lb/mmBtu (if applicable);

xx)

Date(sof the latest analyzer interference tests;

xxi)

Results of the latest analyzer interference tests; and

xxii) For each calibration gas cylinder used during each RATA,

record the cylinder gas vendor, cylinder number, expiration

date, pollutants in the cylinder, and certified gas

concentrations.

For each test run of each moisture determination using Method 4 in

appendix A to 40 CFR 60, incorporated by reference in Section

225.140, (or its allowable alternatives), whether the determination

is made to support a gas RATA to support a flow RATA,or to

quality assure the data from a continuous moisture monitoring

system, record the following data elements (as applicable to the

moisture measurement method used):

The beginning date, hour and minute of the run;

iv)

The ending date, hour and minute of the run;

Unit operating level (low, mid, high or normal, as

appropriate);

vi)

Moisture measurement method;

vii)

Volume of H

O collected in the impingers (ml);

viii)

Mass of H

O collected in the silica gel (g);

ix)

Dry gas meter calibration factor;

222

Average dry gas meter temperature (°F);

xi)

Barometric pressure (inches of mercury);

xii)

Differential pressure across the orifice meter (inches of

O);

xiii)

Initial and final dry gas meter readings (ft

);

xiv)

Total sample gas volume, corrected to standard conditions

(dscf); and

xv)

Percentage of moisture in the stack gas (percent H

O).

The raw data and calculated results for any stratification tests

performed in accordance with Sections 6.5.5.1 through 6.5.5.3 of

Exhibit A to this Appendix.

For each RATA run using the Ontario Hydro Method to determine

mercury concentration:

Percent CO

and O

in the stack gas, dry-basis;

ii)

Moisture content of the stack gas (percent H

O);

iii)

Average stack temperature (°F);

iv)

Dry gas volume metered (dscm);

Percent isokinetic;

vi)

Particle-bound mercury collected by the filter, blank and

probe rinse (μg);

vii)

Oxidized mercury collected by the KCl impingers (μg);

viii)

Elemental mercury collected in the HNO

Total mercury, including particle-bound mercury (μg); and

Total mercury, excluding particle-bound mercury (μg)

All appropriate data elements for Methods 30A and 30B.

223

For a unit with a flow monitor installed on a rectangular stack or

duct, if a site-specific default or measured wall effects adjustment

factor (WAF) is used to correct the stack gas volumetric flow rate

data to account for velocity decay near the stack or duct wall, the

owner or operator must keep records of the following for each flow

RATA performed with EPA Method 2 in appendices A–1 and A–2

to 40 CFR 60, incorporated by reference in Section 225.140,

subsequent to the WAF determination:

Monitoring system ID;

RATA end date and time;

Number of Method 1 traverse points; and

vi)

Wall effects adjustment factor (WAF), to the nearest

0.0001.

For each RATA run using Method 29 in appendix A–8 to 40 CFR

60, incorporated by reference in Section 225.140, to determine

mercury concentration:

Percent CO

and O

in the stack gas, dry-basis;

ii)

Moisture content of the stack gas (percent H

O);

iii)

Average stack gas temperature (°F);

iv)

Dry gas volume metered (dscm);

Percent isokinetic;

vi)

Particulate mercury collected in the front half of the

sampling train, corrected for the front-half blank value

(μgm); and

vii)

Total vapor phase mercury collected in the back half of the

sampling train, corrected for the back-half blank value

(μg).

For each certified continuous emission monitoring system, excepted

monitoring system, or alternative monitoring system, the date and

224

description of each event that requires certification, recertification, or

certain diagnostic testing of the system and the date and type of each test

performed. If the conditional data validation procedures of Section

1.4(b)(3) of this Appendix are to be used to validate and report data prior

to the completion of the required certification, recertification or diagnostic

testing, the date and hour of the probationary calibration error test must be

reported to mark the beginning of conditional data validation.

Hardcopy relative accuracy test reports, certification reports,

recertification reports or semiannual or annual reports for gas or flow rate

CEMS, mercury CEMS, or sorbent trap monitoring systems are required

or requested under 40 CFR 75.60(b)(6) or 75.63, incorporated by

reference in Section 225.140, the reports must include, at a minimum, the

following elements (as applicable to the types of tests performed:

Summarized test results.

DAHS printouts of the CEMS data generated during the calibration

error, linearity, cycle time and relative accuracy tests.

For pollutant concentration monitor or diluent monitor relative

accuracy tests at normal operating load:

The raw reference method data from each run, i.e., the data

under subsections (a)(7)(D)(xvii) of this Section (usually in

the form of a computerized printout, showing a series of

one-minute readings and the run average);

ii)

The raw data and results for all required pre-test, post-test,

pre-run and post-run quality assurance checks (i.e.,

calibration gas injections) of the reference method

analyzers, i.e., the data under subsections (a)(7)(D)(v)

through (xiv) of this Section;

iii)

The raw data and results for any moisture measurements

made during the relative accuracy testing, i.e., the data

under subsections (a)(7)(E)(i) through(xv) of this Section;

and

iv)

Tabulated, final, corrected reference method run data (i.e.,

the actual values used in the relative accuracy calculations),

along with the equations used to convert the raw data to the

final values and example calculations to demonstrate how

the test data were reduced.

For relative accuracy tests for flow monitors:

225

The raw flow rate reference method data, from Reference

Method 2 (or its allowable alternatives) under appendix A

to 40 CFR 60, incorporated by reference in Section

225.140, including auxiliary moisture data (often in the

form of handwritten data sheets), i.e., the data under

subsections (a)(7)(B)(i) through )(xx), subsections

(a)(7)(C)(i) through ( (xiii), and, if applicable, subsections

(a)(7)(E)(i) through (xv) of this Section; and

ii)

The tabulated, final volumetric flow rate values used in the

relative accuracy calculations (determined from the flow

rate reference method data and other necessary

measurements, such as moisture, stack temperature and

pressure), along with the equations used to convert the raw

data to the final values and example calculations to

demonstrate how the test data were reduced.

Calibration gas certificates for the gases used in the linearity,

calibration error and cycle time tests and for the calibration gases

used to quality assure the gas monitor reference method data

during the relative accuracy test audit.

Laboratory calibrations of the source sampling equipment. For

sorbent trap monitoring systems, the laboratory analyses of all

sorbent traps and information documenting the results of all leak

checks and other applicable quality control procedures.

A copy of the test protocol used for the CEMS certifications or

recertifications, including narrative that explains any testing

abnormalities, problematic sampling, and analytical conditions that

required a change to the test protocol, and/or solutions to technical

problems encountered during the testing program.

Diagrams illustrating test locations and sample point locations (to

verify that locations are consistent with information in the

monitoring plan). Include a discussion of any special traversing or

measurement scheme. The discussion must also confirm that

sample points satisfy applicable acceptance criteria.

Names of key personnel involved in the test program, including

test team members, plant contacts, agency representatives and test

observers on site.

226

10)

Whenever reference methods are used as backup monitoring systems

pursuant to Section 1.4(d)(3) of this Appendix, the owner or operator must

record the following information:

For each test run using Reference Method 2 (or its allowable

alternatives in appendix A to 40 CFR 60, incorporated by reference

in Section 225.140) to determine volumetric flow rate, record the

following data elements (as applicable to the measurement method

used):

Unit or stack identification number;

ii)

Reference method system and component identification

The data in subsection (a)(7)(B) of this Section, except for

subsections (a)(7)(B)(i), (vi), (viii), (xii) and (xvii) through

(xx); and

The data in subsection (a)(7)(C), except on a run basis.

For each reference method test run using Method 3A in appendix

A to 40 CFR 60, incorporated by reference in Section 225.140, to

determine CO

, or O

concentration:

Unit or stack identification number;

ii)

The reference method system and component identification

Run start date and hour;

Run end date and hour;

vi)

The data in subsections (a)(7)(D)(ii) through (ix) and (xii)

through (xv); and (vii) Stack gas density adjustment factor

(if applicable).

For each hour of each reference method test run using Method 3A

in appendix A to 40 CFR 60, incorporated by reference in Section

225.140, to determine CO

, or O

concentration:

227

Unit or stack identification number;

ii)

The reference method system and component identification

Pollutant or diluent gas being measured;

vi)

Unadjusted (raw) average pollutant or diluent gas

concentration for the hour; and

vii)

Average pollutant or diluent gas concentration for the hour,

adjusted as appropriate for moisture, calibration bias (or

calibration error) and stack gas density.

11)

For each other quality-assurance test or other quality assurance activity,

the owner or operator must record the following (as applicable):

Component/system identification code;

Parameter;

Test or activity completion date and hour;

Test or activity description;

For each request for a quality assurance test extension or exemption, for

any loss of exempt status, and for each single-load flow RATA claim

pursuant to Section 2.3.1.3(c)(3) of Exhibit B to this Appendix, the owner

or operator must record the following (as applicable):

For a RATA deadline extension or exemption request:

Monitoring system identification code;

RATA expiration date without extension;

iv)

RATA expiration date with extension;

Type of RATA extension of exemption claimed or lost;

vi)

Year to date hours of non-redundant back-up CEMS usage

at the unit/stack; and

vii)

Quarter and year.

For a linearity test or flow-to-load ratio test quarterly exemption:

Component-system identification code;

Quarter and year; and

Span scale.

For a single-load flow RATA claim:

Monitoring system identification code;

ii)

Ending date of last annual flow RATA;

iii)

The relative frequency (percentage) of unit or stack

operation at each load level (low, mid and high) since the

previous annual flow RATA, to the nearest 0.1 percent;

iv)

End date of the historical load data collection period; and

Indication of the load level (low, mid or high) claimed for

the single-load flow RATA.

13)

For the sorbent traps used in sorbent trap monitoring systems to quantify

mercury concentration under Sections 1.14 through 1.18 of this Appendix

(including sorbent traps used for relative accuracy testing), the owner or

operator must keep records of the following:

The ID number of the monitoring system in which each sorbent

trap was used to collect mercury;

229

The unique identification number of each sorbent trap;

The beginning and ending dates and hours of the data collection

period for each sorbent trap;

The average mercury concentration (in μgm/dscm) for the data

collection period;

Information documenting the results of the required leak checks;

The analysis of the mercury collected by each sorbent trap; and

Information documenting the results of the other applicable quality

control procedures in Section 1.3 of this Appendix and in Exhibits

B and D to this Appendix.

Except as otherwise provided in Section 1.12(a) of this Appendix, for units with

add-on mercury emission controls, the owner or operator must keep the following

records on-site in the quality assurance/quality control plan required by Section 1

of Exhibit B to this Appendix:

A list of operating parameters for the add-on emission controls, including

parameters in Section 1.12 of this Appendix, appropriate to the particular

installation of add-on emission controls; and

The range of each operating parameter in the list that indicates the add-on

emission controls are properly operating.

Excepted Monitoring for Mercury Low Mass Emission units under Section

1.15(b) of this Appendix. For qualifying coal-fired units using the alternative low

mass emission methodology under Section 1.15(b), the owner or operator must

record the data elements described in Section 1.13(a)(7)(G), Section 1.13(a)(7)(H)

or Section 1.13(a)(7)(J) of this Appendix, as applicable, for each run of each

mercury emission test and re-test required under Section 1.15(c)(1) or Section

1.15(d)(4)(C) of this Appendix.

DAHS Verification

For each DAHS (formula) verification that is required for

initial certification, recertification or for certain diagnostic testing of a monitoring

system, record the date and hour that the DAHS verification is successfully

completed. (This requirement only applies to units that report monitoring plan

data in accordance with Section 1.10(d) of this Appendix.)

Section 1.14 General Provisions

Applicability. The owner or operator of a unit must comply with the requirements

of this Appendix to the extent that compliance is required by this Part. For

230

purposes of this Appendix, the term "affected unit" means any coal-fired unit (as

defined in 40 CFR 72.2, incorporated by reference) that is subject to this Part. The

term "non-affected unit" means any unit that is not subject to this Part, the term

"permitting authority" means the Agency.

Compliance Dates. The owner or operator of an affected unit must meet the

compliance deadlines established by Subpart B of this Part.

Prohibitions.

No owner or operator of an affected unit or a non-affected unit under

Section 1.16(b)(2)(B) of this Appendix will use any alternative monitoring

system, alternative reference method, or any other alternative for the

required continuous emission monitoring system without having obtained

prior written approval in accordance with subsection (f) of this Section.

No owner or operator of an affected unit or a non-affected unit under

Section 1.16(b)(2)(B) of this Appendix will operate the unit so as to

discharge, or allow to be discharged, emissions of mercury to the

atmosphere without accounting for such emissions in accordance with the

applicable provisions of this Appendix.

No owner or operator of an affected unit or a non-affected unit under

Section 1.16(b)(2)(B) of this Appendix will disrupt the continuous

emission monitoring system, any portion of thesystem, or any other

approved emission monitoring method, and thereby avoid monitoring and

recording mercury mass emissions discharged into the atmosphere, except

for periods of recertification or periods when calibration, quality assurance

testing or maintenance is performed in accordance with the provisions of

this Appendix applicable to monitoring systems under Section 1.15 of this

Appendix.

No owner or operator of an affected unit or a non-affected unit under

Section 1.16(b)(2)(B) will retire or permanently discontinue use of the

continuous emission monitoring system, any component of the system, or

any other approved emission monitoring system under this Appendix,

except under any one of the following circumstances:

During the period that the unit is covered by a retired unit

exemption that is in effect under this Part; or

The owner or operator is monitoring mercury mass emissions from

the affected unit with another certified monitoring system

approved, in accordance with the provisions of Section 250 of this

Part; or

231

The owner or operator submits notification of the date of

certification testing of a replacement monitoring system in

accordance with Part 225.240(d).

Quality Assurance and Quality Control Requirements. For units that use

continuous emission monitoring systems to account for mercury mass emissions,

the owner or operator must meet the applicable quality assurance and quality

control requirements in Section 1.5 and Exhibit B to this Appendix for the flow

monitoring systems, mercury concentration monitoring systems, moisture

monitoring systems and diluent monitors required under Section 1.15 of this

Appendix. Units using sorbent trap monitoring systems must meet the applicable

quality assurance requirements in Section 1.3 of this Appendix, Exhibit D to this

Appendix, and Sections 1.3 and 2.3 of Exhibit B to this Appendix.

Reporting Data Prior to Initial Certification. If, by the applicable compliance date

under this Part, the owner or operator of an affected unit has not successfully

completed all required certification tests for any monitoring systems, he or she

must determine, record, and report data prior to initial certification in accordance

with Section 239 of this Part.

Petitions.

The owner or operator of an affected unit that is also subject to the Acid

Rain Program may submit a petition to the Agency requesting an

alternative to any requirement of Sections 1.14 through 1.18 of this

Appendix. Such a petition must meet the requirements of 40 CFR 75.66,

incorporated by reference in Section 225.140, and any additional

requirements established by Subpart B of this Part. Use of an alternative to

any requirement of Sections 1.14 through 1.18 of this Appendix is in

accordance with Sections 1.14 through 1.18 of this Appendix and with

Subpart B of this Part only to the extent that the petition is approved in

writing by the Agency.

Notwithstanding subsection (f)(1) of this Section, petitions requesting an

alternative to a requirement concerning any additional CEMS required

solely to meet the common stack provisions of Section 1.16 of this

Appendix must be submitted to the Agency and will be governed by

paragraph (f)(3) of this Section. Such a petition must meet the

requirements of 40 CFR 75.66, incorporated by reference in Section

225.140, and any additional requirements established by Subpart B of this

Part.

The owner or operator of an affected unit that is not subject to the Acid

Rain Program may submit a petition to the Agency requesting an

alternative to any requirement of Sections 1.14 through 1.18 of this

Appendix. Such a petition must meet the requirements of 40 CFR 75.66,

232

incorporated by reference in Section 225.140, and any additional

requirements established by Subpart B of this Part. Use of an alternative to

any requirement of Sections 1.14 through 1.18 of this Appendix is in

accordance with Sections 1.14 through 1.18 of this Appendix only to the

extent that it is approved in writing by the Agency.

Section 1.15 Monitoring of Mercury Mass Emissions and Heat Input at the Unit Level

The owner or operator of the affected coal-fired unit must:

Meet the general operating requirements in Section 1.2 of this Appendix for the

following continuous emission monitors (except as provided in accordance with

subpart E of 40 CFR 75, incorporated by reference in Section 225.140):

A mercury concentration monitoring system (consisting of a mercury

pollutant concentration monitor and an automated DAHS, which provides

a permanent, continuous record of mercury emissions in units of

micrograms per standard cubic meter (μg/scm)) or a sorbent trap

monitoring system to measure the mass concentration of total vapor phase

mercury in the flue gas, including the elemental and oxidized forms of

mercury, in micrograms per standard cubic meter (μg/scm);

A flow monitoring system;

A continuous moisture monitoring system (if correction of mercury

concentration for moisture is required), as described in 40 CFR 75.11(b),

incorporated by reference in Section 225.140. Alternatively, the owner or

operator may use the appropriate fuel-specific default moisture value

provided in 40 CFR 75.11, incorporated by reference in Section 225.140,

or a site-specific moisture value approved by petition under 40 CFR 75.66,

incorporated by reference in Section 225.140; and

If heat input is required to be reported under this Part, the owner or

operator must meet the general operating requirements for a flow

monitoring system and an O

or CO

monitoring system to measure heat

input rate.

For an affected unit that emits 464 ounces (29 lb) of mercury per year or less, use

the following excepted monitoring methodology. To implement this methodology

for a qualifying unit, the owner or operator must meet the general operating

requirements in Section 1.2 of this Appendix for the continuous emission

monitors described in subsections (a)(2) and (a)(4) of this Section, and perform

mercury emission testing for initial certification and on-going quality-assurance,

as described in subsections (c) through (e) of this Section.

To determine whether an affected unit is eligible to use the monitoring provisions

233

in subsection (b) of this Section:

The owner or operator must perform mercury emission testing within 18

months before the compliance date in Section 1.14(b) of this Appendix to

determine the mercury concentration (i.e., total vapor phase mercury) in

the effluent.

The testing must be performed using one of the mercury reference

methods listed in Section 1.6(a)(5) of this Appendix, and must

consist of a minimum of 3 runs at the normal unit operating load,

while combusting coal. The coal combusted during the testing

must be representative of the coal that will be combusted at the

start of the mercury mass emissions reduction program (preferably

from the same sources of supply).

The minimum time per run must be 1 hour if Method 30A is used.

If either Method 29 in appendix A-8 to 40 CFR 60, incorporated

by reference, ASTM D6784-02 (the Ontario Hydro method)

(incorporated by reference under Section 225.140) or Method 30B

is used, paired samples are required for each test run and the runs

must be long enough to ensure that sufficient mercury is collected

to analyze. When Method 29 in appendix A-8 to 40 CFR 60,

incorporated by reference, or the Ontario Hydro method is used,

the test results must be based on the vapor phase mercury collected

in the back-half of the sampling trains (i.e., the non-filterable

impinger catches). For each Method 29 in appendix A-8 to 40 CFR

60, incorporated by reference, Method 30B or Ontario Hydro

method test run, the paired trains must meet the relative deviation

(RD) requirement specified in Section 1.6(a)(5) of this Appendix

or Method 30B, as applicable. If the RD specification is met, the

results of the two samples must be averaged arithmetically.

If the unit is equipped with flue gas desulfurization or add-on

mercury emission controls, the controls must be operating

normally during the testing, and, for the purpose of establishing

proper operation of the controls, the owner or operator must record

parametric data or SO

concentration data in accordance with

Section 1.12(a) of this Appendix.

If two or more of units of the same type qualify as a group of

identical units in accordance with 40 CFR 75.19(c)(1)(iv)(B),

incorporated by reference in Section 225.140, the owner or

operator may test a subset of these units in lieu of testing each unit

individually. If this option is selected, the number of units required

to be tested must be determined from Table LM-4 in 40 CFR

75.19, incorporated by reference in Section 225.140. For the

234

purposes of the required retests under subsection (d)(4) of this

Section, it is strongly recommended that (to the extent practicable)

the same subset of the units not be tested in two successive retests,

and that every effort be made to ensure that each unit in the group

of identical units is tested in a timely manner.

Based on the results of the emission testing, Equation 1 of this

Section must be used to provide a conservative estimate of the

annual mercury mass emissions from the unit:

max

(Equation 1)

Where:

E = Estimated annual mercury mass emissions from the affected

unit, (ounces/year)

K = Units conversion constant, 9.978 x 10

-10

oz-scm/μ-scf

N =

Either 8,760 (the number of hours in a year) or the

maximum number of operating hours per year (if less than

8,760) allowed by the unit's Federally-enforceable

operating permit.

= The highest mercury concentration (μg/scm) from any of

the test runs or 0.50 μg/scm, whichever is greater

max

= Maximum potential flow rate, determined according to

Section 2.1.2.1 of Exhibit A to this Appendix, (scfh)

Equation 1 of this Section assumes that the unit operates at its

maximum potential flow rate, either year-round or for the

maximum number of hours allowed by the operating permit (if unit

operation is restricted to less than 8,760 hours per year). If the

permit restricts the annual unit heat input but not the number of

annual unit operating hours, the owner or operator may divide the

allowable annual heat input (mmBtu) by the design rated heat input

capacity of the unit (mmBtu/hr) to determine the value of "N" in

Equation 1. Also, note that if the highest mercury concentration

measured in any test run is less than 0.50 μg/scm, a default value

of 0.50

μg

/scm must be used in the calculations.

If the estimated annual mercury mass emissions from subsection (c)(2) of

this Section are 464 ounces per year or less, then the unit is eligible to use

the monitoring provisions in paragraph (b) of this Section, and continuous

monitoring of the mercury concentration is not required (except as

235

otherwise provided in subsections (e) and (f) of this Section).

If the owner or operator of an eligible unit under subsection (c)(3) of this Section

elects not to continuously monitor mercury concentration, then the following

requirements must be met:

The results of the mercury emission testing performed under subsection

permitting authority, no later than 45 days after the testing is completed.

The calculations demonstrating that the unit emits 464 ounces (or less) per

year of mercury must also be provided, and the default mercury

concentration that will be used for reporting under Section 1.18 of this

Appendix must be specified in the hard copy portions of the monitoring

plan for the unit. The methodology is considered to be provisionally

certified as of the date and hour of completion of the mercury emission

testing.

Following initial certification, the same default mercury concentration

value that was used to estimate the unit's annual mercury mass emissions

under subsection (c) of this Section must be reported for each unit

operating hour, except as otherwise provided in subsection (d)(4)(D) or

(d)(6) of this Section. The default mercury concentration value must be

updated as appropriate, according to subsection (d)(5) of this Section.

The hourly mercury mass emissions must be calculated according to

Section 4.1.3 in Exhibit C to this Appendix.

The mercury emission testing described in subsection (c) of this Section

must be repeated periodically, for the purposes of quality-assurance, as

follows:

If the results of the certification testing under subsection (c) of this

Section show that the unit emits 144 ounces (9 lb) of mercury per

year or less, the first retest is required by the end of the fourth QA

operating quarter (as defined in 40 CFR 72.2, incorporated by

reference) following the calendar quarter of the certification

testing; or

If the results of the certification testing under subsection (c) of this

Section show that the unit emits more than 144 ounces of mercury

per year, but less than or equal to 464 ounces per year, the first

retest is required by the end of the second QA operating quarter (as

defined in 40 CFR 72.2, incorporated by reference) following the

calendar quarter of the certification testing; and

Thereafter, retesting will be required either semiannually or

236

annually (i.e., by the end of the second or fourth QA operating

quarter following the quarter of the previous test), depending on

the results of the previous test. To determine whether the next

retest is due within two or four QA operating quarters, substitute

the highest mercury concentration from the current test or 0.50

μg

/scm (whichever is greater) into the equation in subsection (c)(2)

of this Section. If the estimated annual mercury mass emissions

exceeds 144 ounces, the next test is due within two QA operating

quarters. If the estimated annual mercury mass emissions is 144

ounces or less, the next test is due within four QA operating

quarters.

An additional retest is required when there is a change in the coal

rank of the primary fuel (e.g., when the primary fuel is switched

from bituminous coal to lignite). Use ASTM D388-99

(incorporated by reference under Section 225.140) to determine the

coal rank. The four principal coal ranks are anthracitic, bituminous,

subbituminous and lignitic. The ranks of anthracite coal refuse

(culm) and bituminous coal refuse (gob) must be anthracitic and

bituminous, respectively. The retest must be performed within 720

unit operating hours of the change.

The default mercury concentration used for reporting under Section 1.18

of this Appendix must be updated after each required retest. This includes

retests that are required prior to the compliance date in Section 1.14(b) of

this Appendix. The updated value must either be the highest mercury

concentration measured in any of the test runs or 0.50 μg/scm, whichever

is greater. The updated value must be applied beginning with the first unit

operating hour in which mercury emissions data are required to be

reported after completion of the retest, except as provided in subsection

(d)(4)(D) of this Section, where the need to retest is triggered by a change

in the coal rank of the primary fuel. In that case, apply the updated default

mercury concentration beginning with the first unit operating hour in

which mercury emissions are required to be reported after the date and

hour of the fuel switch.

If the unit is equipped with a flue gas desulfurization system or add-on

mercury controls, the owner or operator must record the information

required under Section 1.12 of this Appendix for each unit operating hour,

to document proper operation of the emission controls.

For units with common stack and multiple stack exhaust configurations, the use of

the monitoring methodology described in subsections (b) through (d) of this

Section is restricted as follows:

The methodology may not be used for reporting mercury mass emissions

237

at a common stack unless all of the units using the common stack are

affected units and the units' combined potential to emit does not exceed

464 ounces of mercury per year times the number of units sharing the

stack, in accordance with subsections (c) and (d) of this Section. If the test

results demonstrate that the units sharing the common stack qualify as low

mass emitters, the default mercury concentration used for reporting

mercury mass emissions at the common stack must either be the highest

value obtained in any test run or 0.50

μg

/scm, whichever is greater.

The initial emission testing required under subsection (c) of this

Section may be performed at the common stack if the following

conditions are met. Otherwise, testing of the individual units (or a

subset of the units, if identical, as described in subsection (c)(1)(D)

of this Section) is required:

The testing must be done at a combined load corresponding

to the designated normal load level (low, mid or high) for

the units sharing the common stack, in accordance with

Section 6.5.2.1 of Exhibit A to this Appendix;

ii)

All of the units that share the stack must be operating in a

normal, stable manner and at typical load levels during the

emission testing. The coal combusted in each unit during

the testing must be representative of the coal that will be

combusted in that unit at the start of the mercury mass

emission reduction program (preferably from the same

sources of supply);

iii)

If flue gas desulfurization and/or add-on mercury emission

controls are used to reduce the level of the emissions

exiting from the common stack, these emission controls

must be operating normally during the emission testing

and, for the purpose of establishing proper operation of the

controls, the owner or operator must record parametric data

or SO

concentration data in accordance with Section

1.12(a) of this Appendix;

iv)

When calculating E, the estimated maximum potential

annual mercury mass emissions from the stack, substitute

the maximum potential flow rate through the common stack

(as defined in the monitoring plan) and the highest

concentration from any test run (or 0.50

μg

/scm, if greater)

into Equation 1;

The calculated value of E must be divided by the number of

units sharing the stack. If the result, when rounded to the

238

nearest ounce, does not exceed 464 ounces, the units

qualify to use the low mass emission methodology; and

vi)

If the units qualify to use the methodology, the default

mercury concentration used for reporting at the common

stack must be the highest value obtained in any test run or

0.50

μg

/scm, whichever is greater; or

The retests required under subsection (d)(4) of this Section may

also be done at the common stack. If this testing option is chosen,

the testing must be done at a combined load corresponding to the

designated normal load level (low, mid, or high) for the units

sharing the common stack, in accordance with Section 6.5.2.1 of

Exhibit A to this Appendix. Provided that the required load level is

attained and that all of the units sharing the stack are fed from the

same on-site coal supply during normal operation, it is not

necessary for all of the units sharing the stack to be in operation

during a retest. However, if two or more of the units that share the

stack are fed from different on-site coal supplies (e.g., one unit

burns low-sulfur coal for compliance and the other combusts

higher-sulfur coal), then either:

Perform the retest with all units in normal operation; or

ii)

If this is not possible, due to circumstances beyond the

control of the owner or operator (e.g., a forced unit outage),

perform the retest with the available units operating and

assess the test results as follows. Use the mercury

concentration obtained in the retest for reporting purposes

under this Part if the concentration is greater than or equal

to the value obtained in the most recent test. If the retested

value is lower than the mercury concentration from the

previous test, continue using the higher value from the

previous test for reporting purposes and use that same

higher mercury concentration value in Equation 1 to

determine the due date for the next retest, as described in

subsection (e)(1)(C) of this Section.

If testing is done at the common stack, the due date for the next

scheduled retest must be determined as follows:

Substitute the maximum potential flow rate for the common

stack (as defined in the monitoring plan) and the highest

mercury concentration from any test run (or 0.50

μg

/scm, if

greater) into Equation 1; and

239

ii)

If the value of E obtained from Equation 1, rounded to the

nearest ounce, is greater than 144 times the number of units

sharing the common stack, but less than or equal to 464

times the number of units sharing the stack, the next retest

is due in two QA operating quarters; or

iii)

If the value of E obtained from Equation 1, rounded to the

nearest ounce, is less than or equal to 144 times the number

of units sharing the common stack, the next retest is due in

four QA operating quarters.

For units with multiple stack or duct configurations, mercury emission

testing must be performed separately on each stack or duct, and the sum of

the estimated annual mercury mass emissions from the stacks or ducts

must not exceed 464 ounces of mercury per year. For reporting purposes,

the default mercury concentration used for each stack or duct must either

be the highest value obtained in any test run for that stack or 0.50

μg

/scm,

whichever is greater.

For units with a main stack and bypass stack configuration, mercury

emission testing must be performed only on the main stack. For reporting

purposes, the default mercury concentration used for the main stack must

either be the highest value obtained in any test run for that stack or 0.50

μg

/scm, whichever is greater. Whenever the main stack is bypassed, the

maximum potential mercury concentration, as defined in Section 2.1.3 of

Exhibit A to this Appendix, must be reported.

At the end of each calendar year, if the cumulative annual mercury mass

emissions from an affected unit have exceeded 464 ounces, then the owner must

install, certify, operate and maintain a mercury concentration monitoring system

or a sorbent trap monitoring system no later than 180 days after the end of the

calendar year in which the annual mercury mass emissions exceeded 464 ounces.

For common stack and multiple stack configurations, installation and certification

of a mercury concentration or sorbent trap monitoring system on each stack

(except for bypass stacks) is likewise required within 180 days after the end of the

calendar year, if:

The annual mercury mass emissions at the common stack have exceeded

464 ounces times the number of affected units using the common stack; or

The sum of the annual mercury mass emissions from all of the multiple

stacks or ducts has exceeded 464 ounces; or

The sum of the annual mercury mass emissions from the main and bypass

stacks has exceeded 464 ounces.

240

For an affected unit that is using a mercury concentration CEMS or a sorbent trap

system under Section 1.15(a) of this Appendix to continuously monitor the

mercury mass emissions, the owner or operator may switch to the methodology in

Section 1.15(b) of this Appendix, provided that the applicable conditions in

subsections (c) through (f) of this Section are met.

Section 1.16 Monitoring of Mercury Mass Emissions and Heat Input at Common and

Multiple Stacks

Unit Utilizing Common Stack with Other Affected Units. When an affected unit

utilizes a common stack with one or more affected units, but no non-affected

units, the owner or operator must either:

Install, certify, operate and maintain the monitoring systems described in

Section 1.15(a) of this Appendix at the common stack, record the

combined mercury mass emissions for the units exhausting to the common

stack. Alternatively, if, in accordance with Section 1.15(e) of this

Appendix, each of the units using the common stack is demonstrated to

emit less than 464 ounces of mercury per year, the owner or operator may

install, certify, operate and maintain the monitoring systems and perform

the mercury emission testing described under Section 1.15(b) of this

Appendix. If reporting of the unit heat input rate is required, determine the

hourly unit heat input rates either by:

Apportioning the common stack heat input rate to the individual

units according to the procedures in 40 CFR 75.16(e)(3),

incorporated by reference in Section 225.140; or

Installing, certifying, operating and maintaining a flow monitoring

system and diluent monitor in the duct to the common stack from

each unit; or

Install, certify, operate and maintain the monitoring systems and (if

applicable) perform the mercury emission testing described in Section

1.15(a) or Section 1.15(b) of this Appendix in the duct to the common

stack from each unit.

Unit utilizing Common Stack with Nonaffected Unit. When one or more affected

units utilizes a common stack with one or more nonaffected units, the owner or

operator must either:

Install, certify, operate and maintain the monitoring systems and (if

applicable) perform the mercury emission testing described in Section

1.15(a) or Section 1.15(b) of this Appendix in the duct to the common

stack from each affected unit; or

241

Install, certify, operate and maintain the monitoring systems described in

Section 1.15(a) of this Appendix in the common stack; and

Install, certify, operate and maintain the monitoring systems and (if

applicable) perform the mercury emission testing described in

Section 1.15(a) or (b) of this Appendix in the duct to the common

stack from each non-affected unit. The owner or operator must

submit a petition to the Agency to allow a method of calculating

and reporting the mercury mass emissions from the affected units

as the difference between mercury mass emissions measured in the

common stack and mercury mass emissions measured in the ducts

of the non-affected units, not to be reported as an hourly value less

than zero. The Agency may approve such a method whenever the

owner or operator demonstrates, to the satisfaction of the Agency,

that the method ensures that the mercury mass emissions from the

affected units are not underestimated; or

Count the combined emissions measured at the common stack as

the mercury mass emissions for the affected units, for

recordkeeping and compliance purposes, in accordance with

subsection (a) of this Section; or

Submit a petition to the Agency to allow use of a method for

apportioning mercury mass emissions measured in the common

stack to each of the units using the common stack and for reporting

the mercury mass emissions. The Agency may approve such a

method whenever the owner or operator demonstrates, to the

satisfaction of the Agency, that the method ensures that the

mercury mass emissions from the affected units are not

underestimated.

If the monitoring option in subsection (b)(2) of this Section is selected,

and if heat input is required to be reported under this Part, the owner or

operator must either:

Apportion the common stack heat input rate to the individual units

according to the procedures in 40 CFR 75.16(e)(3), incorporated

by reference in Section 225.140; or

Install a flow monitoring system and a diluent gas (O

or CO

)

monitoring system in the duct leading from each affected unit to

the common stack, and measure the heat input rate in each duct,

according to Section 2.2 of Exhibit C to this Appendix.

Unit With a Main Stack and a Bypass Stack. Whenever any portion of the flue

gases from an affected unit can be routed through a bypass stack to avoid the

242

mercury monitoring systems installed on the main stack, the owner and operator

must either:

Install, certify, operate, and maintain the monitoring systems described in

Section 1.15(a) of this Appendix on both the main stack and the bypass

stack and calculate mercury mass emissions for the unit as the sum of the

mercury mass emissions measured at the two stacks;

Install, certify, operate and maintain the monitoring systems described in

Section 1.15(a) of this Appendix at the main stack and measure mercury

mass emissions at the bypass stack using the appropriate reference

methods in Section 1.6(b) of this Appendix. Calculate mercury mass

emissions for the unit as the sum of the emissions recorded by the installed

monitoring systems on the main stack and the emissions measured by the

reference method monitoring systems;

Install, certify, operate and maintain the monitoring systems and (if

applicable) perform the mercury emission testing described in Section

1.15(a) or (b) of this Appendix only on the main stack. If this option is

chosen, it is not necessary to designate the exhaust configuration as a

multiple stack configuration in the monitoring plan required under Section

1.10 of this Appendix, since only the main stack is monitored; or

If the monitoring option in subsection (c)(1) or (c)(2) of this Section is

selected, and if heat input is required to be reported under this Part, the

owner or operator must:

Use the installed flow and diluent monitors to determine the hourly

heat input rate at each stack (mmBtu/hr), according to Section 2.2

of Exhibit C to this Appendix; and

Calculate the hourly heat input at each stack (in mmBtu) by

multiplying the measured stack heat input rate by the

corresponding stack operating time; and

Determine the hourly unit heat input by summing the hourly stack

heat input values.

Unit With Multiple Stack or Duct Configuration. When the flue gases from an

affected unit discharge to the atmosphere through more than one stack, or when

the flue gases from an affected unit utilize two or more ducts feeding into a single

stack and the owner or operator chooses to monitor in the ducts rather than in the

stack, the owner or operator must either:

Install, certify, operate, and maintain the monitoring systems and

(if applicable) perform the mercury emission testing described in

243

Section 1.15(a) or (b) of this Appendix in each of the multiple

stacks and determine mercury mass emissions from the affected

unit as the sum of the mercury mass emissions recorded for each

stack. If another unit also exhausts flue gases into one of the

monitored stacks, the owner or operator must comply with the

applicable requirements of subsections (a) and (b) of this Section,

in order to properly determine the mercury mass emissions from

the units using that stack;

Install, certify, operate, and maintain the monitoring systems and

(if applicable) perform the mercury emission testing described in

Section 1.15(a) or Section 1.15(b) of this Appendix in each of the

ducts that feed into the stack, and determine mercury mass

emissions from the affected unit using the sum of the mercury

mass emissions measured at each duct, except that where another

unit also exhausts flue gases to one or more of the stacks, the

owner or operator must also comply with the applicable

requirements of paragraphs (a) and (b) of this Section to determine

and record mercury mass emissions from the units using that stack;

If the monitoring option in subsection (d)(1) or (d)(2) of this

Section is selected, and if heat input is required to be reported

under this Part, the owner or operator must:

Use the installed flow and diluent monitors to determine

the hourly heat input rate at each stack or duct (mmBtu/hr),

according to Section 2.2 of Exhibit C to this Appendix; and

Calculate the hourly heat input at each stack or duct (in

mmBtu) by multiplying the measured stack (or duct) heat

input rate by the corresponding stack (or duct) operating

time; and

Determine the hourly unit heat input by summing the

hourly stack (or duct) heat input values.

Section 1.17 Calculation of Mercury Mass Emissions and Heat Input Rate

The owner or operator must calculate mercury mass emissions and heat input rate in accordance

with the procedures in Sections 4.1 through 4.3 of Exhibit F to this Appendix.

Section 1.18 Recordkeeping and Reporting

General recordkeeping provisions. The owner or operator of any affected unit

must maintain for each affected unit and each non-affected unit under Section

244

1.16(b)(2)(B) of this Appendix a file of all measurements, data, reports, and other

information required by this part at the source in a form suitable for inspection for

at least 5 years from the date of each record. Except for the certification data

required in Section 1.11(a)(4) of this Appendix and the initial submission of the

monitoring plan required in Section 1.11(a)(5) of this Appendix, the data must be

collected beginning with the earlier of the date of provisional certification or the

compliance deadline in Section 1.14(b) of this Appendix. The certification data

required in Section 1.11(a)(4) of this Appendix must be collected beginning with

the date of the first certification test performed. The file must contain the

following information:

The information required in Sections 1.11(a)(2), (a)(4), (a)(5), (a)(6), (b),

The information required in Section 1.12 of this Appendix, for units with

flue gas desulfurization systems or add-on mercury emission controls;

For affected units using mercury CEMS or sorbent trap monitoring

systems, for each hour when the unit is operating, record the mercury mass

emissions, calculated in accordance with Section 4 of Exhibit C to this

Appendix.

Heat input and mercury methodologies for the hour; and

Formulas from the monitoring plan for total mercury mass emissions and

heat input rate (if applicable);

Certification, quality assurance and quality control record provisions. The owner

or operator of any affected unit must record the applicable information in Section

1.13 of this Appendix for each affected unit or group of units monitored at a

common stack and each non-affected unit under Section 1.16(b)(2)(B) of this

Appendix.

Monitoring plan recordkeeping provisions.

General provisions. The owner or operator of an affected unit must

prepare and maintain a monitoring plan for each affected unit or group of

units monitored at a common stack and each non-affected unit under

Section 1.16(b)(2)(B) of this Appendix. The monitoring plan must contain

sufficient information on the continuous monitoring systems and the use

of data derived from these systems to demonstrate that all the unit's

mercury emissions are monitored and reported.

Updates. Whenever the owner or operator makes a replacement,

modification, or change in a certified continuous monitoring system or

alternative monitoring system under 40 CFR 75, subpart E, incorporated

245

by reference in Section 225.140, including a change in the automated data

acquisition and handling system or in the flue gas handling system, that

affects information reported in the monitoring plan (e.g., a change to a

serial number for a component of a monitoring system), then the owner or

operator must update the monitoring plan.

Contents of the monitoring plan. Each monitoring plan must contain the

information in Section 1.10(c)(1) of this Appendix in electronic format

and the information in Section 1.10(c)(2) in hardcopy format.

General reporting provisions.

The owner or operator of an affected unit must comply with all reporting

requirements in this Section and with any additional requirements set forth

in 35 Ill. Adm. Code Part 225.

The owner or operator of an affected unit must submit the following for

each affected unit or group of units monitored at a common stack and each

non-affected unit under Section 1.16(b)(2)(B) of this Appendix:

Monitoring plans in accordance with subsection (e) of this Section;

and

Quarterly reports in accordance with subsection (f) of this Section.

Other petitions and communications. The owner or operator of an affected

unit must submit petitions, correspondence, application forms, and

petition-related test results in accordance with the provisions in Section

1.14(f) of this Appendix.

Quality assurance RATA reports. If requested by the Agency, the owner

or operator of an affected unit must submit the quality assurance RATA

report for each affected unit or group of units monitored at a common

stack and each non-affected unit under Section 1.16(b)(2)(B) of this

Appendix by the later of 45 days after completing a quality assurance

RATA according to Section 2.3 of Exhibit B to this Appendix or 15 days

after receiving the request. The owner or operator must report the

hardcopy information required by Section 1.13(a)(9) of this Appendix to

the Agency.

Notifications. The owner or operator of an affected unit must submit

written notice to the Agency according to the provisions in 40 CFR 75.61,

incorporated by reference in Section 225.140, for each affected unit or

group of units monitored at a common stack and each non-affected unit

under Section 1.16(b)(2)(B) of this Appendix.

246

Monitoring plan reporting. The owner or operator of an affected unit must submit

all of the hardcopy information required under Section 1.10 of this Appendix, for

each affected unit or group of units monitored at a common stack and each non-

affected unit under Section 1.16(b)(2)(B) of this Appendix, to the Agency prior to

initial certification. Thereafter, the owner or operator must submit hardcopy

information only if that portion of the monitoring plan is revised. The owner or

operator must submit the required hardcopy information as follows: no later than

21 days prior to the commencement of initial certification testing; with any

certification or recertification application, if a hardcopy monitoring plan change is

associated with the recertification event; and within 30 days of any other event

with which a hardcopy monitoring plan change is associated, pursuant to Section

1.10(b) of this Appendix.

Quarterly reports. EGUs using CEMS or excepted monitoring systems must

submit quarterly reports pursuant to the requirements in Section 225.290(b).

Exhibit A to Appendix B--Specifications and Test Procedures

1. Installation and Measurement Location

1.1 Gas and Mercury Monitors

Following the procedures in Section 8.1.1 of Performance Specification 2 in Appendix B to 40

CFR 60, incorporated by reference in Section 225.140, install the pollutant concentration

monitor or monitoring system at a location where the pollutant concentration and emission rate

measurements are directly representative of the total emissions from the affected unit. Select a

representative measurement point or path for the monitor probes (or for the path from the

transmitter to the receiver) such that the CO

, O

, concentration monitoring system, mercury

concentration monitoring system, or sorbent trap monitoring system will pass the relative

accuracy test (see Section 6 of this Exhibit).

It is recommended that monitor measurements be made at locations where the exhaust gas

temperature is above the dew-point temperature. If the cause of failure to meet the relative

accuracy tests is determined to be the measurement location, relocate the monitor probes.

1.1.1 Point Monitors

Locate the measurement point (1) within the centroidal area of the stack or duct cross section, or

(2) no less than 1.0 meter from the stack or duct wall.

1.2 Flow Monitors

Install the flow monitor in a location that provides representative volumetric flow over all

operating conditions. Such a location is one that provides an average velocity of the flue gas flow

over the stack or duct cross section and is representative of the pollutant concentration monitor

247

location. Where the moisture content of the flue gas affects volumetric flow measurements, use

the procedures in both Reference Methods 1 and 4 of appendix A to 40 CFR 60, incorporated by

reference in Section 225.140, to establish a proper location for the flow monitor. The Illinois

EPA recommends (but does not require) performing a flow profile study following the

procedures in 40 CFR 60, appendix A, Method 1, Sections 11.5 or 11.4, incorporated by

reference in Section 225.140, for each of the three operating or load levels indicated in Section

6.5.2.1 of this Exhibit to determine the acceptability of the potential flow monitor location and to

determine the number and location of flow sampling points required to obtain a representative

flow value. The procedure in 40 CFR 60, appendix A, Test Method 1, Section 11.5, incorporated

by reference in Section 225.140, may be used even if the flow measurement location is greater

than or equal to 2 equivalent stack or duct diameters downstream or greater than or equal to 1/2

duct diameter upstream from a flow disturbance. If a flow profile study shows that cyclonic (or

swirling) or stratified flow conditions exist at the potential flow monitor location that are likely

to prevent the monitor from meeting the performance specifications of this part, then the Agency

recommends either (1) selecting another location where there is no cyclonic (or swirling) or

stratified flow condition, or (2) eliminating the cyclonic (or swirling) or stratified flow condition

by straightening the flow, e.g., by installing straightening vanes. The Agency also recommends

selecting flow monitor locations to minimize the effects of condensation, coating, erosion, or

other conditions that could adversely affect flow monitor performance.

1.2.1 Acceptability of Monitor Location

The installation of a flow monitor is acceptable if either (1) the location satisfies the minimum

siting criteria of Method 1 in appendix A to 40 CFR 60, incorporated by reference in Section

225.140 (i.e., the location is greater than or equal to eight stack or duct diameters downstream

and two diameters upstream from a flow disturbance; or, if necessary, two stack or duct

diameters downstream and one-half stack or duct diameter upstream from a flow disturbance), or

(2) the results of a flow profile study, if performed, are acceptable (i.e., there are no cyclonic (or

swirling) or stratified flow conditions), and the flow monitor also satisfies the performance

specifications of this part. If the flow monitor is installed in a location that does not satisfy these

physical criteria, but nevertheless the monitor achieves the performance specifications of this

part, then the location is acceptable, notwithstanding the requirements of this Section.

1.2.2 Alternative Monitoring Location

Whenever the owner or operator successfully demonstrates that modifications to the exhaust duct

or stack (such as installation of straightening vanes, modifications of ductwork, and the like) are

necessary for the flow monitor to meet the performance specifications, the Agency may approve

an interim alternative flow monitoring methodology and an extension to the required certification

date for the flow monitor.

Where no location exists that satisfies the physical siting criteria in Section 1.2.1, where the

results of flow profile studies performed at two or more alternative flow monitor locations are

unacceptable, or where installation of a flow monitor in either the stack or the ducts is

demonstrated to be technically infeasible, the owner or operator may petition the Agency for an

alternative method for monitoring flow.

248

2. Equipment Specifications

2.1 Instrument Span and Range

In implementing Sections 2.1.1 through 2.1.2 of this Exhibit, set the measurement range for each

parameter (CO

, O

, or flow rate) high enough to prevent full-scale exceedances from occurring,

yet low enough to ensure good measurement accuracy and to maintain a high signal-to-noise

ratio. To meet these objectives, select the range such that the majority of the readings obtained

during typical unit operation are kept, to the extent practicable, between 20.0 and 80.0 percent of

the full-scale range of the instrument. These guidelines do not apply to mercury monitoring

monitors used to measure CO

emissions or percentage

moisture), select a span value between 15.0 and 25.0 percent O

. For a CO

monitor installed on

a boiler, select a span value between 14.0 and 20.0 percent CO

. For a CO

monitor installed on a

combustion turbine, an alternative span value between 6.0 and 14.0 percent CO

may be used.

An alternative CO

span value below 6.0 percent may be used if an appropriate technical

justification is included in the hardcopy monitoring plan. An alternative O

span value below

15.0 percent O

may be used if an appropriate technical justification is included in the

monitoring plan (e.g., O

concentrations above a certain level create an unsafe operating

condition). Select the full-scale range of the instrument to be consistent with Section 2.1 of this

Exhibit and to be greater than or equal to the span value. Select the calibration gas concentrations

for the daily calibration error tests and linearity checks in accordance with Section 5.1 of this

Exhibit, as percentages of the span value. For O

monitors with span values

≥21.0 perc

ent O

purified instrument air containing 20.9 percent O

may be used as the high-level calibration

material. If a dual-range or autoranging diluent analyzer is installed, the analyzer may be

represented in the monitoring plan as a single component.

2.1.2 Flow Monitors

Select the full-scale range of the flow monitor so that it is consistent with Section 2.1 of this

Exhibit and can accurately measure all potential volumetric flow rates at the flow monitor

installation site.

2.1.2.1 Maximum Potential Velocity and Flow Rate

For this purpose, determine the span value of the flow monitor using the following procedure.

Calculate the maximum potential velocity (MPV) using Equation A-3a or A-3b or determine the

MPV (wet basis) from velocity traverse testing using Reference Method 2 (or its allowable

alternatives) in appendix A to 40 CFR 60, incorporated by reference in Section 225.140. If using

test values, use the highest average velocity (determined from the Method 2 traverses) measured

at or near the maximum unit operating load. Express the MPV in units of wet standard feet per

minute (fpm). For the purpose of providing substitute data during periods of missing flow rate

249

data in accordance with 40 CFR 75.31 and 75.33 and as required elsewhere in this part, calculate

the maximum potential stack gas flow rate (MPF) in units of standard cubic feet per hour (scfh),

as the product of the MPV (in units of wet, standard fpm) times 60, times the cross-sectional area

of the stack or duct (in ft

) at the flow monitor location.

MPV

F H

MPV

F H

MPV = maximum potential velocity (fpm, standard wet basis).

= dry-basis F factor (dscf/mmBtu) from Table 1, Section 3.3.5 of Appendix F ,

40 CFR Part 75.

= carbon-based F factor (scf CO

/mmBtu) from Table 1, Section 3.3.5 of

Appendix F , 40 CFR Part 75.

= maximum heat input (mmBtu/minute) for all units, combined, exhausting to

the stack or duct where the flow monitor is located.

A = inside cross sectional area (ft

) of the flue at the flow monitor location.

= maximum oxygen concentration, percent dry basis, under normal

operating conditions.

= minimum carbon dioxide concentration, percent dry basis, under normal

operating conditions.

= maximum percent flue gas moisture content under normal operating

conditions.

2.1.2.2 Span Values and Range

Determine the span and range of the flow monitor as follows. Convert the MPV, as determined

in Section 2.1.2.1 of this Exhibit, to the same measurement units of flow rate that are used for

daily calibration error tests (e.g., scfh, kscfh, kacfm, or differential pressure (inches of water)).

Next, determine the "calibration span value" by multiplying the MPV (converted to equivalent

daily calibration error units) by a factor no less than 1.00 and no greater than 1.25, and rounding

up the result to at least two significant figures. For calibration span values in inches of water,

250

retain at least two decimal places. Select appropriate reference signals for the daily calibration

error tests as percentages of the calibration span value, as specified in Section 2.2.2.1 of this

Exhibit. Finally, calculate the "flow rate span value" (in scfh) as the product of the MPF, as

determined in Section 2.1.2.1 of this Exhibit, times the same factor (between 1.00 and 1.25) that

was used to calculate the calibration span value. Round off the flow rate span value to the nearest

1000 scfh. Select the full-scale range of the flow monitor so that it is greater than or equal to the

span value and is consistent with Section 2.1 of this Exhibit. Include in the monitoring plan for

the unit: calculations of the MPV, MPF, calibration span value, flow rate span value, and full-

scale range (expressed both in scfh and, if different, in the measurement units of calibration).

2.1.2.3 Adjustment of Span and Range

For each affected unit or common stack, the owner or operator must make a periodic evaluation

of the MPV, span, and range values for each flow rate monitor (at a minimum, an annual

evaluation is required) and must make any necessary span and range adjustments with

corresponding monitoring plan updates, as described in subsections (a) through (c) of this

Section 2.1.2.3. Span and range adjustments may be required, for example, as a result of changes

in the fuel supply, changes in the stack or ductwork configuration, changes in the manner of

operation of the unit, or installation or removal of emission controls. In implementing the

provisions in subsections (a) and (b) of this Section 2.1.2.3, note that flow rate data recorded

during short-term, non-representative operating conditions (e.g., a trial burn of a different type of

fuel) must be excluded from consideration. The owner or operator must keep the results of the

most recent span and range evaluation on-site, in a format suitable for inspection. Make each

required span or range adjustment no later than 45 days after the end of the quarter in which the

need to adjust the span or range is identified.

If the fuel supply, stack or ductwork configuration, operating parameters, or other

conditions change such that the maximum potential flow rate changes

significantly, adjust the span and range to assure the continued accuracy of the

flow monitor. A "significant" change in the MPV means that the guidelines of

Section 2.1 of this Exhibit can no longer be met, as determined by either a

periodic evaluation by the owner or operator or from the results of an audit by the

Agency. The owner or operator should evaluate whether any planned changes in

operation of the unit may affect the flow of the unit or stack and should plan any

necessary span and range changes needed to account for these changes, so that

they are made in as timely a manner as practicable to coordinate with the

operational changes. Calculate the adjusted calibration span and flow rate span

values using the procedures in Section 2.1.2.2 of this Exhibit.

Whenever the full-scale range is exceeded during a quarter, provided that the

exceedance is not caused by a monitor out-of-control period, report 200.0 percent

of the current full-scale range as the hourly flow rate for each hour of the full-

scale exceedance. If the range is exceeded, make appropriate adjustments to the

flow rate span, and range to prevent future full-scale exceedances. Calculate the

new calibration span value by converting the new flow rate span value from units

of scfh to units of daily calibration. A calibration error test must be performed and

251

passed to validate data on the new range.

Whenever changes are made to the MPV, full-scale range, or span value of the

flow monitor, as described in subsections (a) and (b) of this Section, record and

report (as applicable) the new full-scale range setting, calculations of the flow rate

span value, calibration span value, and MPV in an updated monitoring plan for

the unit. The monitoring plan update must be made in the quarter in which the

changes become effective. Record and report the adjusted calibration span and

reference values as parts of the records for the calibration error test required by

Exhibit B to this Appendix. Whenever the calibration span value is adjusted, use

reference values for the calibration error test that meet the requirements of Section

2.2.2.1 of this Exhibit, based on the most recent adjusted calibration span value.

Perform a calibration error test according to Section 2.1.1 of Exhibit B to this

Appendix whenever making a change to the flow monitor span or range, unless

the range change also triggers a recertification under Section 1.4 of this Appendix.

2.1.3 Mercury Monitors

Determine the appropriate span and range values for each mercury pollutant concentration

monitor, so that all expected mercury concentrations can be determined accurately.

2.1.3.1 Maximum Potential Concentration

The maximum potential concentration depends upon the type of coal combusted in the unit. For

the initial MPC determination, there are three options:

Use one of the following default values: 9 μg/scm for bituminous coal; 10

μg/scm for sub-bituminous coal; 16 μg/scm for lignite, and 1 μg/scm for

waste coal, i.e., anthracite culm or bituminous gob. If different coals are

blended, use the highest MPC for any fuel in the blend; or

You may base the MPC on the results of site-specific emission testing

using one of the mercury reference methods in Section 1.6 of this

Appendix, if the unit does not have add-on mercury emission controls or a

flue gas desulfurization system, or if you test upstream of these control

devices. A minimum of 3 test runs are required at the normal operating

load. Use the highest total mercury concentration obtained in any of the

tests as the MPC; or

You may base the MPC on 720 or more hours of historical CEMS data or

data from a sorbent trap monitoring system, if the unit does not have add-

on mercury emission controls or a flue gas desulfurization system (or if

the CEMS or sorbent trap system is located upstream of these control

devices) and if the mercury CEMS or sorbent trap system has been tested

for relative accuracy against one of the mercury reference methods in

Section 1.6 of this Appendix and has met a relative accuracy specification

252

of 20.0% or less.

2.1.3.2 Maximum Expected Concentration

For units with FGD systems that significantly reduce mercury emissions (including fluidized bed

units that use limestone injection) and for units equipped with add-on mercury emission controls

(e.g., carbon injection), determine the maximum expected mercury concentration (MEC) during

normal, stable operation of the unit and emission controls. To calculate the MEC, substitute the

MPC value from Section 2.1.3.1 of this Exhibit into Equation A-2 in Section 2.1.1.2 of appendix

A to 40 CFR 75, incorporated by reference in Section 225.140. For units with add-on mercury

emission controls, base the percent removal efficiency on design engineering calculations. For

units with FGD systems, use the best available estimate of the mercury removal efficiency of the

FGD system.

2.1.3.3 Span and Range Values

For each mercury monitor, determine a high span value, by rounding the MPC

value from Section 2.1.3.1 of this Exhibit upward to the next highest multiple of

10 μg/scm.

For an affected unit equipped with an FGD system or a unit with add-on mercury

emission controls, if the MEC value from Section 2.1.3.2 of this Exhibit is less

than 20 percent of the high span value from subsection (a) of this Section, and if

the high span value is 20 μg/scm or greater, define a second, low span value of 10

μg/scm.

If only a high span value is required, set the full-scale range of the mercury

analyzer to be greater than or equal to the span value.

If two span values are required, you may either:

Use two separate (high and low) measurement scales, setting the range of

each scale to be greater than or equal to the high or low span value, as

appropriate; or

Quality-assure two segments of a single measurement scale.

2.1.3.4 Adjustment of Span and Range

For each affected unit or common stack, the owner or operator must make a periodic evaluation

of the MPC, MEC, span, and range values for each mercury monitor (at a minimum, an annual

evaluation is required) and must make any necessary span and range adjustments, with

corresponding monitoring plan updates. Span and range adjustments may be required, for

example, as a result of changes in the fuel supply, changes in the manner of operation of the unit,

or installation or removal of emission controls. In implementing the provisions in subsections (a)

and (b) of this Section, data recorded during short-term, non-representative process operating

253

conditions (e.g., a trial burn of a different type of fuel) must be excluded from consideration. The

owner or operator must keep the results of the most recent span and range evaluation on-site, in a

format suitable for inspection. Make each required span or range adjustment no later than 45

days after the end of the quarter in which the need to adjust the span or range is identified, except

that up to 90 days after the end of that quarter may be taken to implement a span adjustment if

the calibration gas concentrations currently being used for calibration error tests, system integrity

checks, and linearity checks are unsuitable for use with the new span value and new calibration

materials must be ordered or additional Hg generator calibration points must be certified.

The guidelines of Section 2.1 of this Exhibit do not apply to mercury monitoring

systems.

Whenever a full-scale range exceedance occurs during a quarter and is not caused

by a monitor out-of-control period, proceed as follows:

For monitors with a single measurement scale, report that the system was

out of range and invalid data was obtained until the readings come back

on-scale and, if appropriate, make adjustments to the MPC, span, and

range to prevent future full-scale exceedances; or

For units with two separate measurement scales, if the low range is

exceeded, no further action is required, provided that the high range is

available and is not out-of-control or out-of-service for any reason.

However, if the high range is not able to provide quality assured data at

the time of the low range exceedance or at any time during the

continuation of the exceedance, report that the system was out-of-control

until the readings return to the low range or until the high range is able to

provide quality assured data (unless the reason that the high-scale range is

not able to provide quality assured data is because the high-scale range has

been exceeded; if the high-scale range is exceeded follow the procedures

in subsection (b)(1) of this Section).

Whenever changes are made to the MPC, MEC, full-scale range, or span value of

the mercury monitor, record and report (as applicable) the new full-scale range

setting, the new MPC or MEC and calculations of the adjusted span value in an

updated monitoring plan. The monitoring plan update must be made in the quarter

in which the changes become effective. In addition, record and report the adjusted

span as part of the records for the daily calibration error test and linearity check

specified by Exhibit B to this Appendix. Whenever the span value is adjusted, use

calibration gas concentrations that meet the requirements of Section 5.1 of this

Exhibit, based on the adjusted span value. When a span adjustment is so

significant that the calibration gas concentrations currently being used for

calibration error tests, system integrity checks and linearity checks are unsuitable

for use with the new span value, then a diagnostic linearity or 3-level system

integrity check using the new calibration gas concentrations must be performed

and passed. Use the data validation procedures in Section 1.4(b)(3) of this

254

Appendix, beginning with the hour in which the span is changed.

2.2 Design for Quality Control Testing

2.2.1 Pollutant Concentration and CO

or O

Monitors

Design and equip each pollutant concentration and CO

or O

monitor with a

calibration gas injection port that allows a check of the entire measurement

system when calibration gases are introduced. For extractive and dilution type

monitors, all monitoring components exposed to the sample gas, (e.g., sample

lines, filters, scrubbers, conditioners, and as much of the probe as practicable) are

included in the measurement system. For in-situ type monitors, the calibration

must check against the injected gas for the performance of all active electronic

and optical components (e.g. transmitter, receiver, analyzer).

Design and equip each pollutant concentration or CO

or O

monitor to allow

daily determinations of calibration error (positive or negative) at the zero- and

mid-or high-level concentrations specified in Section 5.2 of this Exhibit.

2.2.2 Flow Monitors

Design all flow monitors to meet the applicable performance specifications.

2.2.2.1 Calibration Error Test

Design and equip each flow monitor to allow for a daily calibration error test consisting of at

least two reference values: Zero to 20 percent of span or an equivalent reference value (e.g.,

pressure pulse or electronic signal) and 50 to 70 percent of span. Flow monitor response, both

before and after any adjustment, must be capable of being recorded by the data acquisition and

handling system. Design each flow monitor to allow a daily calibration error test of the entire

flow monitoring system, from and including the probe tip (or equivalent) through and including

the data acquisition and handling system, or the flow monitoring system from and including the

transducer through and including the data acquisition and handling system.

2.2.2.2 Interference Check

Design and equip each flow monitor with a means to ensure that the moisture

expected to occur at the monitoring location does not interfere with the proper

functioning of the flow monitoring system. Design and equip each flow monitor

with a means to detect, on at least a daily basis, pluggage of each sample line and

sensing port, and malfunction of each resistance temperature detector (RTD),

transceiver or equivalent.

Design and equip each differential pressure flow monitor to provide an automatic,

periodic back purging (simultaneously on both sides of the probe) or equivalent

method of sufficient force and frequency to keep the probe and lines sufficiently

255

free of obstructions on at least a daily basis to prevent velocity sensing

interference, and a means for detecting leaks in the system on at least a quarterly

basis (manual check is acceptable).

Design and equip each thermal flow monitor with a means to ensure on at least a

daily basis that the probe remains sufficiently clean to prevent velocity sensing

interference.

Design and equip each ultrasonic flow monitor with a means to ensure on at least

a daily basis that the transceivers remain sufficiently clean (e.g., back purging

system) to prevent velocity sensing interference.

2.2.3 Mercury Monitors

Design and equip each mercury monitor to permit the introduction of known concentrations of

elemental mercury and HgCl2 separately, at a point immediately preceding the sample extraction

filtration system, such that the entire measurement system can be checked. If the mercury

monitor does not have a converter, the HgCl2 injection capability is not required.

3. Performance Specifications

3.1 Calibration Error

The calibration error performance specifications in this Section apply only to 7-

day calibration error tests under Sections 6.3.1 and 6.3.2 of this Exhibit and to the

offline calibration demonstration described in Section 2.1.1.2 of Exhibit B to this

Appendix. The calibration error limits for daily operation of the continuous

monitoring systems required under this part are found in Section 2.1.4(a) of

Exhibit B to this Appendix.

The calibration error of a mercury concentration monitor must not deviate from

the reference value of either the zero or upscale calibration gas by more than 5.0

percent of the span value, as calculated using Equation A-5 of this Exhibit.

Alternatively, if the span value is 10 μg/scm, the calibration error test results are

also acceptable if the absolute value of the difference between the monitor

response value and the reference value, R-A in Equation A-5 of this Exhibit, is

R A

CE = Calibration error as a percentage of the span of the instrument.

R = Reference value of zero or upscale (high-level or mid-level, as applicable)

calibration gas introduced into the monitoring system.

256

A = Actual monitoring system response to the calibration gas.

S = Span of the instrument, as specified in Section 2 of this Exhibit.

3.2 Linearity and System Integrity Checks

For CO

or O

monitors (including O

monitors used to measure CO

emissions or percent

moisture):

The error in linearity for each calibration gas concentration (low-, mid-, and high-

levels) must not exceed or deviate from the reference value by more than 5.0

percent as calculated using Equation A-4 of this Exhibit; or

The absolute value of the difference between the average of the monitor response

values and the average of the reference values, R-A in Equation A-4 of this

Exhibit, must be less than or equal to 0.5 percent CO

or O

, whichever is less

restrictive.

For the linearity check and the 3-level system integrity check of a mercury

monitor, which are required, respectively, under Section 1.4(c)(1)(B) and

(c)(1)(E) of this Appendix, the measurement error must not exceed 10.0 percent

of the reference value at any of the three gas levels. To calculate the measurement

error at each level, take the absolute value of the difference between the reference

value and mean CEM response, divide the result by the reference value, and then

multiply by 100. Alternatively, the results at any gas level are acceptable if the

absolute value of the difference between the average monitor response and the

average reference value, i.e.,

−

in Equation A-4 of this Exhibit, does not

exceed 0.8 μg/m

. The principal and alternative performance specifications in this

Section also apply to the single-level system integrity check described in Section

2.6 of Exhibit B to this Appendix.

R A

ME = Percentage measurement error, for a linearity check or system integrity

check, based upon the reference value.

R =

Reference value of low-, mid-, or high-level calibration gas introduced

into the monitoring system.

A =

Average of the monitoring system responses.

3.3 Relative Accuracy

257

3.3.1 Relative Accuracy for CO

and O

Monitors

The relative accuracy for CO

and O

monitors must not exceed 10.0 percent. The relative

accuracy test results are also acceptable if the difference between the mean value of the CO

monitor measurements and the corresponding reference method measurement mean value,

calculated using equation A-7 of this Exhibit, does not exceed ±1.0 percent CO

Number of data points.

The difference between a reference method value and the corresponding

continuous emission monitoring system value (RM

–CEM

) at a given

point in time i.

3.3.2 Relative Accuracy for Flow Monitors

The relative accuracy of flow monitors must not exceed 10.0 percent at any load

(or operating) level at which a RATA is performed (i.e., the low, mid, or high

level, as defined in Section 6.5.2.1 of this Exhibit).

For affected units where the average of the flow reference method measurements

of gas velocity at a particular load (or operating) level of the relative accuracy test

audit is less than or equal to 10.0 fps, the difference between the mean value of

the flow monitor velocity measurements and the reference method mean value in

fps at that level must not exceed ±- 2.0 fps, wherever the 10.0 percent relative

accuracy specification is not achieved.

3.3.3 Relative Accuracy for Moisture Monitoring Systems

The relative accuracy of a moisture monitoring system must not exceed 10.0 percent. The

relative accuracy test results are also acceptable if the difference between the mean value of the

reference method measurements (in percent H

O) and the corresponding mean value of the

moisture monitoring system measurements (in percent H

O), calculated using Equation A-7 of

this Exhibit does not exceed ±- 1.5 percent H

3.3.4 Relative Accuracy for Mercury Monitoring Systems

The relative accuracy of a mercury concentration monitoring system or a sorbent trap monitoring

system must not exceed 20.0 percent. Alternatively, for affected units where the average of the

reference method measurements of mercury concentration during the relative accuracy test audit

is less than 5.0 μg/scm, the test results are acceptable if the difference between the mean value of

the monitor measurements and the reference method mean value does not exceed 1.0 μg/scm, in

cases where the relative accuracy specification of 20.0 percent is not achieved.

258

3.4 Cycle Time

The cycle time for mercury concentration monitors, oxygen monitors used to determine percent

moisture, and any other monitoring component of a continuous emission monitoring system that

is required to perform a cycle time test must not exceed 15 minutes.

4. Data Acquisition and Handling Systems

Automated data acquisition and handling systems must read and record the full range of pollutant

concentrations and volumetric flow from zero through span and provide a continuous, permanent

record of all measurements and required information as a computer data file capable of being

reproduced in a readable hard copy format. These systems also must have the capability of

interpreting and converting the individual output signals from a flow monitor, a CO

monitor, an

monitor, a moisture monitoring system, a mercury concentration monitoring system, and a

sorbent trap monitoring system, to produce a continuous readout of pollutant emission rates or

pollutant mass emissions (as applicable) in the appropriate units (e.g., lb/hr, lb/MMBtu,

ounces/hr, tons/hr). These systems also must have the capability of interpreting and converting

the individual output signals from a flow monitor to produce a continuous readout of pollutant

mass emission rates in the units of the standard. Where CO

emissions are measured with a

continuous emission monitoring system, the data acquisition and handling system must also

produce a readout of CO

mass emissions in tons.

Data acquisition and handling systems must also compute and record monitor calibration error;

flow rate data, or mercury emission rate data.

5. Calibration Gas

5.1 Reference Gases

For the purposes of this Appendix, calibration gases include the following:

5.1.1 Standard Reference Materials (SRM)

These calibration gases may be obtained from the National Institute of Standards and

Technology (NIST) at the following address: Quince Orchard and Cloppers Road, Gaithersburg,

MD 20899-0001.

5.1.2 SRM-Equivalent Compressed Gas Primary Reference Material (PRM)

Contact the Gas Metrology Team, Analytical Chemistry Division, Chemical Science and

Technology Laboratory of NIST, at the address in Section 5.1.1, for a list of vendors and

cylinder gases.

5.1.3 NIST Traceable Reference Materials

259

Contact the Gas Metrology Team, Analytical Chemistry Division, Chemical Science and

Technology Laboratory of NIST, at the address in Section 5.1.1, for a list of vendors and

cylinder gases that meet the definition for a NIST Traceable Reference Material (NTRM)

provided in 40 CFR 72.2, incorporated by reference in Section 225.140.

5.1.4 EPA Protocol Gases

An EPA Protocol Gas is a calibration gas mixture prepared and analyzed

according to Section 2 of the "EPA Traceability Protocol for Assay and

Certification of Gaseous Calibration Standards" September 1997, EPA-600/R-

97/121 or such revised procedure as approved by the Administrator (EPA

Traceability Protocol).

An EPA Protocol Gas must have a specialty gas producer-certified uncertainty

(95-percent confidence interval) that must not be greater than 2.0 percent of the

certified concentration (tag value) of the gas mixture. The uncertainty must be

calculated using the statistical procedures (or equivalent statistical techniques)

that are listed in Section 2.1.8 of the EPA Traceability Protocol.

A copy of EPA-600/R-97/121 is available from the National Technical

Information Service, 5285 Port Royal Road, Springfield, VA, 703-605-6585 or

http://www.ntis.gov, and from http://www.epa.gov/ttn/emc/news.html or http://

www.epa.gov/appcdwww/tsb/index.html.

5.1.5 Research Gas Mixtures

Research gas mixtures must be vendor-certified to be within 2.0 percent of the concentration

specified on the cylinder label (tag value), using the uncertainty calculation procedure in Section

2.1.8 of the "EPA Traceability Protocol for Assay and Certification of Gaseous Calibration

Standards" September 1997, EPA-600/R-97/121. Inquiries about the RGM program should be

directed to: National Institute of Standards and Technology, Analytical Chemistry Division,

Chemical Science and Technology Laboratory, B-324 Chemistry, Gaithersburg, MD 20899.

5.1.6 Zero Air Material

Zero air material is defined in 40 CFR 72.2, incorporated by reference in Section 225.140.

5.1.7 NIST/EPA-Approved Certified Reference Materials

Existing certified reference materials (CRMs) that are still within their certification period may

be used as calibration gas.

5.1.8 Gas Manufacturer's Intermediate Standards

Gas manufacturer's intermediate standards is defined in 40 CFR 72.2, incorporated by reference

in Section 225.140.

260

5.1.9 Mercury Standards

For 7-day calibration error tests of mercury concentration monitors and for daily calibration error

tests of mercury monitors, either NIST-traceable elemental mercury standards (as defined in

Section 225.130) or a NIST-traceable source of oxidized mercury (as defined in Section

225.130) may be used. For linearity checks, NIST-traceable elemental mercury standards must

be used. For 3- level and single-point system integrity checks under Section 1.4(c)(1)(E) of this

Appendix, Sections 6.2(g) and 6.3.1 of this Exhibit, and Sections 2.1.1, 2.2.1 and 2.6 of Exhibit

B to this Appendix, a NIST-traceable source of oxidized mercury must be used. Alternatively,

other NIST-traceable standards may be used for the required checks, subject to the approval of

the Agency. Notwithstanding these requirements, mercury calibration standards that are not

NIST-traceable may be used for the tests described in this Section until December 31, 2009.

However, on and after January 1, 2010, only NIST-traceable calibration standards must be used

for these tests.

5.2 Concentrations

Four concentration levels are required as follows.

5.2.1 Zero-level Concentration

0.0 to 20.0 percent of span, including span for high-scale or both low- and high-scale for Hg,

and O

monitors, as appropriate.

5.2.2 Low-level Concentration

20.0 to 30.0 percent of span, including span for high-scale or both low- and high-scale for Hg,

and O

monitors, as appropriate.

5.2.3 Mid-level Concentration

50.0 to 60.0 percent of span, including span for high-scale or both low- and high-scale for Hg,

and O

monitors, as appropriate.

5.2.4 High-level Concentration

80.0 to 100.0 percent of span, including span for high-scale or both low-and high-scale for Hg,

and O

monitors, as appropriate.

6. Certification Tests and Procedures

6.1 General Requirements

6.1.1 Pretest Preparation

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Install the components of the continuous emission monitoring system (i.e., pollutant

concentration monitors, CO

or O

monitor, and flow monitor) as specified in Sections 1, 2, and

3 of this Exhibit, and prepare each system component and the combined system for operation in

accordance with the manufacturer's written instructions. Operate the units during each period

when measurements are made. Units may be tested on non-consecutive days. To the extent

practicable, test the DAHS software prior to testing the monitoring hardware.

6.1.2 Requirements for Air Emission Testing Bodies

On and after January 1, 2009, any Air Emission Testing Body (AETB) conducting

relative accuracy test audits of CEMS and sorbent trap monitoring systems under

Part 225, Subpart B, must conform to the requirements of ASTM D7036-04

pursuant to 40 CFR Part 75 Appendix A Section 6.1.2 (incorporated by reference

in Section 225.140). This Section is not applicable to daily operation, daily

calibration error checks, daily flow interference checks, quarterly linearity checks

or routine maintenance of CEMS.

The AETB must provide to the affected sources certification that the AETB

operates in conformance with, and that data submitted to the Agency has been

collected in accordance with, the requirements of ASTM D7036-04 pursuant to 40

CFR Part 75 Appendix A Section 6.1.2 (incorporated by reference in Section

225.140). This certification may be provided in the form of:

A certificate of accreditation of relevant scope issued by a recognized,

national accreditation body; or

A letter of certification signed by a member of the senior management

staff of the AETB.

The AETB must either provide a Qualified Individual on-site to conduct or must

oversee all relative accuracy testing carried out by the AETB as required in

ASTM D7036-04 pursuant to 40 CFR Part 75 Appendix A Section 6.1.2

(incorporated by reference under Section 225.140). The Qualified Individual must

provide the affected sources with copies of the qualification credentials relevant

to the scope of the testing conducted.

6.2 Linearity Check (General Procedures)

Check the linearity of each CO

, Hg, and O

monitor while the unit, or group of units for a

common stack, is combusting fuel at conditions of typical stack temperature and pressure; it is

not necessary for the unit to be generating electricity during this test. For units with two

measurement ranges (high and low) for a particular parameter, perform a linearity check on both

the low scale and the high scale. For on-going quality assurance of the CEMS, perform linearity

checks, using the procedures in this Section, on the ranges and at the frequency specified in

Section 2.2.1 of Exhibit B to this Appendix. Challenge each monitor with calibration gas, as

defined in Section 5.1 of this Exhibit, at the low-, mid-, and high-range concentrations specified

262

in Section 5.2 of this Exhibit. Introduce the calibration gas at the gas injection port, as specified

in Section 2.2.1 of this Exhibit. Operate each monitor at its normal operating temperature and

conditions. For extractive and dilution type monitors, pass the calibration gas through all filters,

scrubbers, conditioners, and other monitor components used during normal sampling and

through as much of the sampling probe as is practical. For in-situ type monitors, perform

calibration checking all active electronic and optical components, including the transmitter,

receiver, and analyzer. Challenge the monitor three times with each reference gas (see example

data sheet in Figure 1). Do not use the same gas twice in succession. To the extent practicable,

the duration of each linearity test, from the hour of the first injection to the hour of the last

injection, must not exceed 24 unit operating hours. Record the monitor response from the data

acquisition and handling system. For each concentration, use the average of the responses to

determine the error in linearity using Equation A-4 in this Exhibit. Linearity checks are

acceptable for monitor or monitoring system certification, recertification, or quality assurance if

none of the test results exceed the applicable performance specifications in Section 3.2 of this

Exhibit. The status of emission data from a CEMS prior to and during a linearity test period must

be determined as follows:

For the initial certification of a CEMS, data from the monitoring system are

considered invalid until all certification tests, including the linearity test, have

been successfully completed, unless the conditional data validation procedures in

Section 1.4(b)(3) of this Appendix are used. When the procedures in Section

1.4(b)(3) of this Appendix are followed, the words “initial certification”apply

instead of "recertification" and complete all of the initial certification tests by

January 1, 2009, rather than within the time periods specified in Section

1.4(b)(3)(D) of this Appendix for the individual tests.

For the routine quality assurance linearity checks required by Section 2.2.1 of

Exhibit B to this Appendix, use the data validation procedures in Section 2.2.3 of

Exhibit B to this Appendix.

When a linearity test is required as a diagnostic test or for recertification, use the

data validation procedures in Section 1.4 (b)(3) of this Appendix.

For linearity tests of non-redundant backup monitoring systems, use the data

validation procedures in Section 1.4(d)(2)(C) of this Appendix.

For linearity tests performed during a grace period and after the expiration of a

grace period, use the data validation procedures in Sections 2.2.3 and 2.2.4,

respectively, of Exhibit B to this Appendix.

For all other linearity checks, use the data validation procedures in Section 2.2.3

of Exhibit B to this Appendix.

For mercury monitors, follow the guidelines in Section 2.2.3 of this Exhibit in

addition to the applicable procedures in Section 6.2 when performing the system

integrity checks described in Section 1.4(c)(1)(E) and in Sections 2.1.1, 2.2.1, and

263

2.6 of Exhibit B to this Appendix.

For mercury concentration monitors, if moisture and/or chlorine is added to the

calibration gas during the required linearity checks or system integrity checks, the

dilution effect of the moisture and/or chlorine addition on the calibration gas

concentration must be accounted for in an appropriate manner.

6.3 7-Day Calibration Error Test

6.3.1 Gas Monitor 7-day Calibration Error Test

Measure the calibration error of each mercury concentration monitor and each CO

or O

monitor while the unit is combusting fuel (but not necessarily generating electricity) once each

day for 7 consecutive operating days according to the following procedures. For mercury

monitors, you may perform this test using either elemental mercury standards or a NIST-

traceable source of oxidized mercury. Also for mercury monitors, if moisture and/or chlorine is

added to the calibration gas, the dilution effect of the added moisture and/or chlorine on the

calibration gas concentration must be accounted for in an appropriate manner. (In the event that

unit outages occur after the commencement of the test, the 7 consecutive unit operating days

need not be 7 consecutive calendar days.) Units using dual span monitors must perform the

calibration error test on both high- and low-scales of the pollutant concentration monitor. The

calibration error test procedures in this Section and in Section 6.3.2 of this Exhibit must also be

used to perform the daily assessments and additional calibration error tests required under

Sections 2.1.1 and 2.1.3 of Exhibit B to this Appendix. Do not make manual or automatic

adjustments to the monitor settings until after taking measurements at both zero and high

concentration levels for that day during the 7-day test. If automatic adjustments are made

following both injections, conduct the calibration error test such that the magnitude of the

adjustments can be determined and recorded. Record and report test results for each day using

the unadjusted concentration measured in the calibration error test prior to making any manual or

automatic adjustments (i.e., resetting the calibration). The calibration error tests should be

approximately 24 hours apart, (unless the 7- day test is performed over non-consecutive days).

Perform calibration error tests at both the zero-level concentration and high-level concentration,

as specified in Section 5.2 of this Exhibit. Alternatively, a mid-level concentration gas (50.0 to

60.0 percent of the span value) may be used in lieu of the high-level gas, provided that the mid-

level gas is more representative of the actual stack gas concentrations. Use only calibration gas,

as specified in Section 5.1 of this Exhibit. Introduce the calibration gas at the gas injection port,

as specified in Section 2.2.1 of this Exhibit. Operate each monitor in its normal sampling mode.

For extractive and dilution type monitors, pass the calibration gas through all filters, scrubbers,

conditioners, and other monitor components used during normal sampling and through as much

of the sampling probe as is practical. For in-situ type monitors, perform calibration, checking all

active electronic and optical components, including the transmitter, receiver, and analyzer.

Challenge the pollutant concentration monitors and CO

or O

monitors once with each

calibration gas. Record the monitor response from the data acquisition and handling system.

Using Equation A-5 of this Exhibit, determine the calibration error at each concentration once

each day (at approximately 24-hour intervals) for 7 consecutive days according to the procedures

given in this Section. The results of a 7-day calibration error test are acceptable for monitor or

264

monitoring system certification, recertification or diagnostic testing if none of these daily

calibration error test results exceed the applicable performance specifications in Section 3.1 of

this Exhibit. The status of emission data from a gas monitor prior to and during a 7-day

calibration error test period must be determined as follows:

For initial certification, data from the monitor are considered invalid until all

certification tests, including the 7-day calibration error test, have been

successfully completed, unless the conditional data validation procedures in

Section 1.4(b)(3) of this Appendix are used. When the procedures in Section

1.4(b)(3) of this Appendix are followed, the words “initial certification”apply

instead of “recertification” and complete all of the initial certification tests by

January 1, 2009, rather than within the time periods specified in Section

1.4(b)(3)(D) of this Appendix for the individual tests.

When a 7-day calibration error test is required as a diagnostic test or for

recertification, use the data validation procedures in Section 1.4(b)(3) of this

Appendix.

6.3.2 Flow Monitor 7-day Calibration Error Test

Flow monitors installed on peaking units (as defined in 40 CFR 72.2, incorporated by reference

in Section 225.140) are exempted from the 7-day calibration error test requirements of this part.

In all other cases, perform the 7-day calibration error test of a flow monitor, when required for

certification, recertification or diagnostic testing, according to the following procedures.

Introduce the reference signal corresponding to the values specified in Section 2.2.2.1 of this

Exhibit to the probe tip (or equivalent), or to the transducer. During the 7-day certification test

period, conduct the calibration error test while the unit is operating once each unit operating day

(as close to 24-hour intervals as practicable). In the event that unit outages occur after the

commencement of the test, the 7 consecutive operating days need not be 7 consecutive calendar

days. Record the flow monitor responses by means of the data acquisition and handling system.

Calculate the calibration error using Equation A-6 of this Exhibit. Do not perform any corrective

maintenance, repair, or replacement upon the flow monitor during the 7-day test period other

than that required in the quality assurance/quality control plan required by Exhibit B to this

Appendix. Do not make adjustments between the zero and high reference level measurements on

any day during the 7-day test. If the flow monitor operates within the calibration error

performance specification (i.e., less than or equal to 3.0 percent error each day and requiring no

corrective maintenance, repair, or replacement during the 7-day test period), the flow monitor

passes the calibration error test. Record all maintenance activities and the magnitude of any

adjustments. Record output readings from the data acquisition and handling system before and

after all adjustments. Record and report all calibration error test results using the unadjusted flow

rate measured in the calibration error test prior to resetting the calibration. Record all

adjustments made during the 7-day period at the time the adjustment is made, and report them in

the certification or recertification application. The status of emissions data from a flow monitor

prior to and during a 7-day calibration error test period must be determined as follows:

For initial certification, data from the monitor are considered invalid until all

265

certification tests, including the 7-day calibration error test, have been

successfully completed, unless the conditional data validation procedures in

Section 1.4(b)(3) of this Appendix are used. When the procedures in Section

1.4(b)(3) of this Appendix are followed, the words “initial certification”" apply

instead of “recertification” and complete all of the initial certification tests by

July 1, 2009, rather than within the time periods specified in Section 1.4(b)(3)(D)

of this Appendix for the individual tests.

When a 7-day calibration error test is required as a diagnostic test or for

recertification, use the data validation procedures in Section 1.4(b)(3).

R A

CE = Calibration error as a percentage of span.

Low or high level reference value specified in Section 2.2.2.1 of this

Exhibit.

Actual flow monitor response to the reference value.

Flow monitor calibration span value as determined under Section 2.1.2.2

of this Exhibit.

6.3.3

For gas or flow monitors installed on peaking units, the exemption from performing the 7-day

calibration error test applies as long as the unit continues to meet the definition of a peaking unit

in 40 CFR 72.2, incorporated by reference in Section 225.140. However, if at the end of a

particular calendar year or ozone season, it is determined that peaking unit status has been lost,

the owner or operator must perform a diagnostic 7-day calibration error test of each monitor

installed on the unit, by no later than December 31 of the following calendar year.

6.4 Cycle Time Test

Perform cycle time tests for each pollutant concentration monitor and continuous emission

monitoring system while the unit is operating, according to the following procedures. Use a zero-

level and a high-level calibration gas (as defined in Section 5.2 of this Exhibit) alternately. For

mercury monitors, the calibration gas used for this test may either be the elemental or oxidized

form of mercury. To determine the downscale cycle time, measure the concentration of the flue

gas emissions until the response stabilizes. Record the stable emissions value. Inject a zero-level

concentration calibration gas into the probe tip (or injection port leading to the calibration cell,

for in-situ systems with no probe). Record the time of the zero gas injection, using the data

acquisition and handling system (DAHS). Next, allow the monitor to measure the concentration

of the zero gas until the response stabilizes. Record the stable ending calibration gas reading.

266

Determine the downscale cycle time as the time it takes for 95.0 percent of the step change to be

achieved between the stable stack emissions value and the stable ending zero gas reading. Then

repeat the procedure, starting with stable stack emissions and injecting the high-level gas, to

determine the upscale cycle time, which is the time it takes for 95.0 percent of the step change to

be achieved between the stable stack emissions value and the stable ending high-level gas

reading. Use the following criteria to assess when a stable reading of stack emissions or

calibration gas concentration has been attained. A stable value is equivalent to a reading with a

change of less than 2.0 percent of the span value for 2 minutes, or a reading with a change of less

than 6.0 percent from the measured average concentration over 6 minutes. Alternatively, the

reading is considered stable if it changes by no more than 0.5 ppm, 0.5 μg/m

(for mercury) for

two minutes. (Owners or operators of systems that do not record data in 1-minute or 3-minute

intervals may petition the Agency for alternative stabilization criteria). For monitors or

monitoring systems that perform a series of operations (such as purge, sample, and analyze),

time the injections of the calibration gases so they will produce the longest possible cycle time.

Refer to Figures 6a and 6b in this Exhibit for example calculations of upscale and downscale

cycle times. Report the slower of the two cycle times (upscale or downscale) as the cycle time

for the analyzer. On and after July 1, 2009, record the cycle time for each component analyzer

separately. For time-shared systems, perform the cycle time tests at each of the probe locations

that will be polled within the same 15-minute period during monitoring system operations. To

determine the cycle time for time-shared systems, at each monitoring location, report the sum of

the cycle time observed at that monitoring location plus the sum of the time required for all

purge cycles (as determined by the continuous emission monitoring system manufacturer) at

each of the probe locations of the time-shared systems. For monitors with dual ranges, report the

test results for each range separately. Cycle time test results are acceptable for monitor or

monitoring system certification, recertification or diagnostic testing if none of the cycle times

exceed 15 minutes. The status of emissions data from a monitor prior to and during a cycle time

test period must be determined as follows:

For initial certification, data from the monitor are considered invalid until all

certification tests, including the cycle time test, have been successfully completed,

unless the conditional data validation procedures in Section 1.4(b)(3) of this

Appendix are used. When the procedures in Section 1.4(b)(3) of this Appendix

are followed, the words “initial certification” apply instead of “recertification”

and complete all of the initial certification tests by July 1, 2009, rather than within

the time periods specified in Section 1.4(b)(3)(D) of this Appendix for the

individual tests.

When a cycle time test is required as a diagnostic test or for recertification, use

the data validation procedures in Section 1.4(b)(3) of this Appendix.

6.5 Relative Accuracy (General Procedures)

Perform the required relative accuracy test audits (RATAs) as follows for each flow monitor,

each O

or CO

diluent monitor used to calculate heat input, each mercury concentration

monitoring system, each sorbent trap monitoring system, and each moisture monitoring system.

267

Except as otherwise provided in this subsection, perform each RATA while the

unit (or units, if more than one unit exhausts into the flue) is combusting the fuel

that is a normal primary or backup fuel for that unit (for some units, more than

one type of fuel may be considered normal, e.g., a unit that combusts gas or oil on

a seasonal basis). For units that co-fire fuels as the predominant mode of

operation, perform the RATAs while co-firing. For mercury monitoring systems,

perform the RATAs while the unit is combusting coal. When relative accuracy

test audits are performed on CEMS installed on bypass stacks/ducts, use the fuel

normally combusted by the unit (or units, if more than one unit exhausts into the

flue) when emissions exhaust through the bypass stack/ducts.

Perform each RATA at the load (or operating) levels specified in Section 6.5.1 or

6.5.2 of this Exhibit or in Section 2.3.1.3 of Exhibit B to this Appendix, as

applicable.

For monitoring systems with dual ranges, perform the relative accuracy test on the

range normally used for measuring emissions. For units with add-on mercury

controls that operate continuously rather than seasonally, or for units that need a

dual range to record high concentration "spikes" during startup conditions, the

low range is considered normal. However, for some dual span units (e.g., for units

that use fuel switching or for which the emission controls are operated

seasonally), provided that both monitor ranges are connected to a common probe

and sample interface, either of the two measurement ranges may be considered

normal; in such cases, perform the RATA on the range that is in use at the time of

the scheduled test. If the low and high measurement ranges are connected to

separate sample probes and interfaces, RATA testing on both ranges is required.

Record monitor or monitoring system output from the data acquisition and

handling system.

Complete each single-load relative accuracy test audit within a period of 168

consecutive unit operating hours, as defined in 40 CFR 72.2, incorporated by

reference in Section 225.140 (or, for CEMS installed on common stacks or bypass

stacks, 168 consecutive stack operating hours, as defined in 40 CFR 72.2,

incorporated by reference in Section 225.140). Notwithstanding this requirement,

up to 336 consecutive unit or stack operating hours may be taken to complete the

RATA of a mercury monitoring system, when ASTM 6784-02 (incorporated by

reference in Section 225.140) or Method 29 in appendix A-8 to 40 CFR 60,

incorporated by reference in Section 225.140, is used as the reference method. For

2-level and 3-level flow monitor RATAs, complete all of the RATAs at all levels,

to the extent practicable, within a period of 168 consecutive unit (or stack)

operating hours; however, if this is not possible, up to 720 consecutive unit (or

stack) operating hours may be taken to complete a multiple-load flow RATA.

The status of emission data from the CEMS prior to and during the RATA test

period must be determined as follows:

268

For the initial certification of a CEMS, data from the monitoring system

are considered invalid until all certification tests, including the RATA,

have been successfully completed, unless the conditional data validation

procedures in Section 1.4(b)(3) of this Appendix are used. When the

procedures in Section 1.4(b)(3) of this Appendix are followed, the words

“initial certification” apply instead of “recertification”and complete all of

the initial certification tests by January 1, 2009, rather than within the time

periods specified in Section 1.4(b)(3)(D) of this Appendix for the

individual tests.

For the routine quality assurance RATAs required by Section 2.3.1 of

Exhibit B to this Appendix, use the data validation procedures in Section

2.3.2 of Exhibit B to this Appendix.

For recertification RATAs, use the data validation procedures in Section

1.4(b)(3).

For quality assurance RATAs of non-redundant backup monitoring

systems, use the data validation procedures in Section 1.4(d)(2)(D) and (E)

of this Appendix.

For RATAs performed during and after the expiration of a grace period,

use the data validation procedures in Sections 2.3.2 and 2.3.3, respectively,

of Exhibit B to this Appendix.

For all other RATAs, use the data validation procedures in Section 2.3.2

of Exhibit B to this Appendix.

For each flow monitor, each CO

or O

diluent monitor used to determine heat

input, each moisture monitoring system, each mercury concentration monitoring

system, and each sorbent trap monitoring system, calculate the relative accuracy,

in accordance with Section 7.3 of this Exhibit, as applicable.

6.5.1 Gas and Mercury Monitoring System RATAs (Special Considerations)

Perform the required relative accuracy test audits for each CO

or O

diluent

monitor used to determine heat input, each mercury concentration monitoring

system, and each sorbent trap monitoring system at the normal load level or

normal operating level for the unit (or combined units, if common stack), as

defined in Section 6.5.2.1 of this Exhibit. If two load levels or operating levels

have been designated as normal, the RATAs may be done at either load level.

For the initial certification of a gas or mercury monitoring system and for

recertifications in which, in addition to a RATA, one or more other tests are

required (i.e., a linearity test, cycle time test, or 7-day calibration error test), the

269

Agency recommends that the RATA not be commenced until the other required

tests of the CEMS have been passed.

6.5.2 Flow Monitor RATAs (Special Considerations)

Except as otherwise provided in subsection (b) of this Section, perform relative

accuracy test audits for the initial certification of each flow monitor at three

different exhaust gas velocities (low, mid, and high), corresponding to three

different load levels within the range of operation, as defined in Section 6.5.2.1 of

this Exhibit. For a common stack/duct, the three different exhaust gas velocities

may be obtained from frequently used unit/load or operating level combinations

for the units exhausting to the common stack. Select the three exhaust gas

velocities such that the audit points at adjacent load or operating levels (i.e., low

and mid or mid and high), in megawatts (or in thousands of lb/hr of steam

production or in ft/sec, as applicable), are separated by no less than 25.0 percent

of the range of operation, as defined in Section 6.5.2.1 of this Exhibit.

For flow monitors on bypass stacks/ducts and peaking units, the flow monitor

relative accuracy test audits for initial certification and recertification must be

single-load tests, performed at the normal load, as defined in Section 6.5.2.1(d) of

this Exhibit.

Flow monitor recertification RATAs must be done at three load levels, unless

otherwise specified in subsection (b) of this Section or unless otherwise specified

or approved by the Agency.

The semiannual and annual quality assurance flow monitor RATAs required

under Exhibit B to this Appendix must be done at the load levels specified in

Section 2.3.1.3 of Exhibit B to this Appendix.

6.5.2.1 Range of Operation and Normal Load Levels

The owner or operator must determine the upper and lower boundaries of the

"range of operation" as follows for each unit (or combination of units, for

common stack configurations): The lower boundary of the range of operation of a

unit must be the minimum safe, stable loads for any of the units discharging

through the stack. Alternatively, for a group of frequently-operated units that

serve a common stack, the sum of the minimum safe, stable loads for the

individual units may be used as the lower boundary of the range of operation. The

upper boundary of the range of operation of a unit must be the maximum

sustainable load. The "maximum sustainable load" is the higher of either: the

nameplate or rated capacity of the unit, less any physical or regulatory limitations

or other deratings; or the highest sustainable load, based on at least four quarters

of representative historical operating data. For common stacks, the maximum

sustainable load is the sum of all of the maximum sustainable loads of the

individual units discharging through the stack, unless this load is unattainable in

270

practice, in which case use the highest sustainable combined load for the units that

discharge through the stack. Based on at least four quarters of representative

historical operating data. The load values for the units must be expressed either in

units of megawatts of thousands of lb/hr of steam load or mmBtu/hr of thermal

output.

The load levels for relative accuracy test audits will, except for peaking units, be

defined as follows: the "low" load level will be the first 30.0 percent of the range

of operation; the "mid" load level will be the middle portion (>30.0 percent, but

≤60.0 percent) of the range of operation; and the "high" load level will be the

upper end (>60.0 percent) of the range of operation. For example, if the upper and

lower boundaries of the range of operation are 100 and 1100 megawatts,

respectively, then the low, mid, and high load levels would be 100 to 400

megawatts, 400 to 700 megawatts, and 700 to 1100 megawatts, respectively.

The owner or operator must identify, for each affected unit or common stack, the

"normal" load level or levels (low, mid or high), based on the operating history of

the units. To identify the normal load levels, the owner or operator must, at a

minimum, determine the relative number of operating hours at each of the three

load levels, low, mid and high over the past four representative operating quarters.

The owner or operator must determine, to the nearest 0.1 percent, the percentage

of the time that each load level (low, mid, high) has been used during that time

period. A summary of the data used for this determination and the calculated

results must be kept on-site in a format suitable for inspection. For new units or

newly-affected units, the data analysis in this subsection may be based on fewer

than four quarters of data if fewer than four representative quarters of historical

load data are available. Or, if no historical load data are available, the owner or

operator may designate the normal load based on the expected or projected

manner of operating the unit. However, in either case, once four quarters of

representative data become available, the historical load analysis must be

repeated.

Determination of normal load.

Based on the analysis of the historical load data described in subsection (c) of this

Section, the owner or operator must designate the most frequently used load level

as the normal load level for the unit (or combination of units, for common stacks).

The owner or operator may also designate the second most frequently used load

level as an additional normal load level for the unit or stack. If the manner of

operation of the unit changes significantly, such that the designated normal loads

or the two most frequently used load levels change, the owner or operator must

repeat the historical load analysis and must redesignate the normal loads and the

two most frequently used load levels, as appropriate. A minimum of two

representative quarters of historical load data are required to document that a

change in the manner of unit operation has occurred. Update the electronic

monitoring plan whenever the normal load levels and the two most frequently-

271

used load levels are redesignated.

The owner or operator must report the upper and lower boundaries of the range of

operation for each unit (or combination of units, for common stacks), in units of

megawatts or thousands of lb/hr or mmBtu/hr of steam production (as applicable),

in the electronic monitoring plan required under Section 1.10 of this Appendix.

6.5.2.2 Multi-Load Flow RATA Results

For each multi-load flow RATA, calculate the flow monitor relative accuracy at each load level.

If a flow monitor relative accuracy test is failed or aborted due to a problem with the monitor on

any load level of a 2-load (or 3-load) relative accuracy test audit, the RATA must be repeated at

that load level. However, the entire 2-load (or 3-load) relative accuracy test audit does not have

to be repeated unless the flow monitor polynomial coefficients or K-factors are changed, in

which case a 3-load RATA is required.

6.5.3 Calculations

Using the data from the relative accuracy test audits, calculate relative accuracy in accordance

with the procedures and equations specified in Section 7 of this Exhibit.

6.5.4 Reference Method Measurement Location

Select a location for reference method measurements that is (1) accessible; (2) in the same

proximity as the monitor or monitoring system location; and (3) meets the requirements of

Performance Specification 3 in appendix B of 40 CFR 60, incorporated by reference in Section

225.140, for CO

or O

monitors, or Method 1 (or 1A) in appendix A of 40 CFR 60, incorporated

by reference in Section 225.140, for volumetric flow, except as otherwise indicated in this

Section or as approved by the Agency.

6.5.5 Reference Method Traverse Point Selection

Select traverse points that ensure acquisition of representative samples of pollutant and diluent

concentrations, moisture content, temperature, and flue gas flow rate over the flue cross Section.

To achieve this, the reference method traverse points must meet the requirements of Section

8.1.3 of Performance Specification 2 ("PS No. 2") in appendix B to 40 CFR 60, incorporated by

reference in Section 225.140 (for moisture monitoring system RATAs), Performance

Specification 3 in appendix B to 40 CFR 60, incorporated by reference in Section 225.140 (for

and CO

monitor RATAs), Method 1 (or 1A) (for volumetric flow rate monitor RATAs),

Method 3 (for molecular weight), and Method 4 (for moisture determination) in appendix A to

40 CFR 60, incorporated by reference in Section 225.140. The following alternative reference

method traverse point locations are permitted for moisture and gas monitor RATAs:

For moisture determinations where the moisture data are used only to determine

stack gas molecular weight, a single reference method point, located at least 1.0

meter from the stack wall, may be used. For moisture monitoring system RATAs

272

and for gas monitor RATAs in which moisture data are used to correct pollutant

or diluent concentrations from a dry basis to a wet basis (or vice-versa), single-

point moisture sampling may only be used if the 12-point stratification test

described in Section 6.5.5.1 of this Exhibit is performed prior to the RATA for at

least one pollutant or diluent gas, and if the test is passed according to the

acceptance criteria in Section 6.5.5.3(b) of this Exhibit.

For gas monitoring system RATAs, the owner or operator may use any of the

following options:

At any location (including locations where stratification is expected), use a

minimum of six traverse points along a diameter, in the direction of any

expected stratification. The points must be located in accordance with

Method 1 in appendix A to 40 CFR 60, incorporated by reference in

Section 225.140.

At locations where Section 8.1.3 of PS No. 2 allows the use of a short

reference method measurement line (with three points located at 0.4, 1.2,

and 2.0 meters from the stack wall), the owner or operator may use an

alternative 3-point measurement line, locating the three points at 4.4, 14.6,

and 29.6 percent of the way across the stack, in accordance with Method 1

in appendix A to 40 CFR 60, incorporated by reference in Section

225.140.

At locations where stratification is likely to occur (e.g., following a wet

scrubber or when dissimilar gas streams are combined), the short

measurement line from Section 8.1.3 of PS No. 2 (or the alternative line

described in subsection (b)(2) of this Section) may be used in lieu of the

prescribed "long" measurement line in Section 8.1.3 of PS No. 2, provided

that the 12-point stratification test described in Section 6.5.5.1 of this

Exhibit is performed and passed one time at the location (according to the

acceptance criteria of Section 6.5.5.3(a) of this Exhibit) and provided that

either the 12-point stratification test or the alternative (abbreviated)

stratification test in Section 6.5.5.2 of this Exhibit is performed and passed

prior to each subsequent RATA at the location (according to the

acceptance criteria of Section 6.5.5.3(a) of this Exhibit).

A single reference method measurement point, located no less than 1.0

meter from the stack wall and situated along one of the measurement lines

used for the stratification test, may be used at any sampling location if the

12-point stratification test described in Section 6.5.5.1 of this Exhibit is

performed and passed prior to each RATA at the location (according to the

acceptance criteria of Section 6.5.5.3(b) of this Exhibit).

For mercury monitoring systems, use the same basic approach for traverse point

selection that is used for the other gas monitoring system RATAs, except that the

273

stratification test provisions in Sections 8.1.3 through 8.1.3.5 of Method 30A must

apply, rather than the provisions of Sections 6.5.5.1 through 6.5.5.3 of this

Exhibit.

6.5.5.1 Stratification Test

With the units operating under steady-state conditions at the normal load level (or

normal operating level), as defined in Section 6.5.2.1 of this Exhibit, use a

traversing gas sampling probe to measure diluent (CO

or O

) concentrations at a

minimum of 12 points, located according to Method 1 in appendix A to 40 CFR

60, incorporated by reference in Section 225.140.

Use Method 3A in appendix A to 40 CFR 60, incorporated by reference in

Section 225.140, to make the measurements. Data from the reference method

analyzers must be quality assured by performing analyzer calibration error and

system bias checks before the series of measurements and by conducting system

bias and calibration drift checks after the measurements, in accordance with the

procedures of Method 3A.

Measure for a minimum of 2 minutes at each traverse point. To the extent

practicable, complete the traverse within a 2-hour period.

If the load has remained constant (±-3.0 percent) during the traverse and if the

reference method analyzers have passed all of the required quality assurance

checks, proceed with the data analysis.

Calculate the average CO

(or O

) concentrations at each of the individual

traverse points. Then, calculate the arithmetic average CO

(or O

) concentrations

for all traverse points.

6.5.5.2 Alternative (Abbreviated) Stratification Test

With the units operating under steady-state conditions at the normal load level (or

normal operating level), as defined in Section 6.5.2.1 of this Exhibit, use a

traversing gas sampling probe to measure the diluent (CO

or O

) concentrations

at three points. The points must be located according to the specifications for the

long measurement line in Section 8.1.3 of PS No. 2 (i.e., locate the points 16.7

percent, 50.0 percent, and 83.3 percent of the way across the stack). Alternatively,

the concentration measurements may be made at six traverse points along a

diameter. The six points must be located in accordance with Method 1 in

appendix A to 40 CFR 60, incorporated by reference in Section 225.140.

Method 3A in appendix A to 40 CFR 60, incorporated by reference in Section

225.140, to make the measurements. Data from the reference method analyzers

must be quality assured by performing analyzer calibration error and system bias

checks before the series of measurements and by conducting system bias and

274

calibration drift checks after the measurements, in accordance with the procedures

of Method 3A.

Measure for a minimum of 2 minutes at each traverse point. To the extent

practicable, complete the traverse within a 1-hour period.

If the load has remained constant (+-3.0 percent) during the traverse and if the

reference method analyzers have passed all of the required quality assurance

checks, proceed with the data analysis.

Calculate the average CO

(or O

) concentrations at each of the individual

traverse points. Then, calculate the arithmetic average CO

(or O

) concentrations

for all traverse points.

6.5.5.3 Stratification Test Results and Acceptance Criteria

For each diluent gas RATA, the short reference method measurement line

described in Section 8.1.3 of PS No. 2 may be used in lieu of the long

measurement line prescribed in Section 8.1.3 of PS No. 2 if the results of a

stratification test, conducted in accordance with Section 6.5.5.1 or 6.5.5.2 of this

Exhibit (as appropriate; see Section 6.5.5(b)(3) of this Exhibit), show that the

concentration at each individual traverse point differs by no more than ±10.0

percent from the arithmetic average concentration for all traverse points. The

results are also acceptable if the concentration at each individual traverse point

differs by no more than ±0.5 percent CO

(or O

) from the arithmetic average

concentration for all traverse points.

For each diluent gas RATA, a single reference method measurement point,

located at least 1.0 meter from the stack wall and situated along one of the

measurement lines used for the stratification test, may be used for that diluent gas

if the results of a stratification test, conducted in accordance with Section 6.5.5.1

of this Exhibit, show that the concentration at each individual traverse point

differs by no more than ±5.0 percent from the arithmetic average concentration

for all traverse points. The results are also acceptable if the concentration at each

individual traverse point differs by no more than ±0.3 percent CO

(or O

) from

the arithmetic average concentration for all traverse points.

The owner or operator must keep the results of all stratification tests on-site, in a

format suitable for inspection, as part of the supplementary RATA records

required under Section 1.13(a)(7) of this Appendix.

6.5.6 Sampling Strategy

Conduct the reference method tests so they will yield results representative of the

pollutant concentration, emission rate, moisture, temperature, and flue gas flow

rate from the unit and can be correlated with mercury monitor, CO

or (O

275

moisture, flow monitoring system, and mercury CEMS (or excepted monitoring

system) measurements (as applicable). The minimum acceptable time for a gas

monitoring system RATA run or for a moisture monitoring system RATA run is

21 minutes. For each run of a gas monitoring system RATA, all necessary

pollutant concentration measurements, diluent concentration measurements, and

moisture measurements (if applicable) must, to the extent practicable, be made

within a 60-minute period. For flow monitor RATAs, the minimum time per run

must be 5 minutes. Flow rate reference method measurements may be made either

sequentially from port to port or simultaneously at two or more sample ports. The

velocity measurement probe may be moved from traverse point to traverse point

either manually or automatically. If, during a flow RATA, significant pulsations

in the reference method readings are observed, be sure to allow enough

measurement time at each traverse point to obtain an accurate average reading

when a manual readout method is used (e.g., a "sight-weighted" average from a

manometer). Also, allow sufficient measurement time to ensure that stable

temperature readings are obtained at each traverse point, particularly at the first

measurement point at each sample port, when a probe is moved sequentially from

port-to-port. A minimum of one set of auxiliary measurements for stack gas

molecular weight determination (i.e., diluent gas data and moisture data) is

required for every clock hour of a flow RATA or for every three test runs

(whichever is less restrictive). Alternatively, moisture measurements for

molecular weight determination may be performed before and after a series of

flow RATA runs at a particular load level (low, mid, or high), provided that the

time interval between the two moisture measurements does not exceed three

hours. If this option is selected, the results of the two moisture determinations

must be averaged arithmetically and applied to all RATA runs in the series.

Successive flow RATA runs may be performed without waiting in-between runs.

If an O

-diluent monitor is used as a CO

continuous emission monitoring system,

perform a CO

system RATA (i.e., measure CO

, rather than O

, with the

reference method). For moisture monitoring systems, an appropriate coefficient,

"K" factor or other suitable mathematical algorithm may be developed prior to the

RATA, to adjust the monitoring system readings with respect to the reference

method. If such a coefficient, K-factor or algorithm is developed, it must be

applied to the CEMS readings during the RATA and (if the RATA is passed), to

the subsequent CEMS data, by means of the automated data acquisition and

handling system. The owner or operator must keep records of the current

coefficient, K factor or algorithm, as specified in Section 1.13(a)(5)(F) of this

Appendix. Whenever the coefficient, K factor or algorithm is changed, a RATA

of the moisture monitoring system is required. For the RATA of a mercury CEMS

using the Ontario Hydro Method, or for the RATA of a sorbent trap system

(irrespective of the reference method used), the time per run must be long enough

to collect a sufficient mass of mercury to analyze. For the RATA of a sorbent trap

monitoring system, the type of sorbent material used by the traps must be the

same as for daily operation of the monitoring system; however, the size of the

traps used for the RATA may be smaller than the traps used for daily operation of

the system. Spike the third section of each sorbent trap with elemental mercury, as

276

described in Section 7.1.2 of Exhibit D to this Appendix. Install a new pair of

sorbent traps prior to each test run. For each run, the sorbent trap data must be

validated according to the quality assurance criteria in Section 8 of Exhibit D to

this Appendix.

To properly correlate the mercury, volumetric flow rate, moisture, CO

)

monitoring system data with the reference method data, annotate the beginning

and end of each reference method test run (including the exact time of day) on the

individual chart recorders or other permanent recording devices.

6.5.7 Correlation of Reference Method and Continuous Emission Monitoring System

Confirm that the monitoring system and reference method test results are on consistent moisture,

pressure, temperature, and diluent concentration basis (e.g., since the flow monitor measures

flow rate on a wet basis, Method 2 test results must also be on a wet basis). Compare flow-

monitor and reference method results on a scfh basis. Also, consider the response times of the

pollutant concentration monitor, the continuous emission monitoring system, and the flow

monitoring system to ensure comparison of simultaneous measurements.

For each relative accuracy test audit run, compare the measurements obtained from the

continuous emission monitoring system (in μg/m

applicable) against the corresponding reference method values. Tabulate the paired data in a

table such as the one shown in Figure 2.

6.5.8 Number of Reference Method Tests

Perform a minimum of nine sets of paired monitor (or monitoring system) and reference method

test data for every required (i.e., certification, recertification, diagnostic, semiannual, or annual)

relative accuracy test audit. For 2-load and 3-load relative accuracy test audits of flow monitors,

perform a minimum of nine sets at each of the load levels.

6.5.9 Reference Methods

The following methods are from appendix A to 40 CFR 60, incorporated by reference in Section

225.140, or have been published by ASTM, and are the reference methods for performing

relative accuracy test audits under this part: Method 1 or 1A in appendix A-1 to 40 CFR 60 for

siting; Method 2 or its allowable alternatives in appendices A-1 and A-2 to 40 CFR 60 (except

for Methods 2B and 2E) for stack gas velocity and volumetric flow rate; Methods 3, 3A or 3B in

appendix A-2 to 40 CFR 60 for O

and CO

; Method 4 in appendix A-3 to 40 CFR 60 for

moisture; and for mercury, either ASTM D6784-02 (the Ontario Hydro Method, incorporated by

reference under Section 225.140), or Method 29 , Method 30A, or Method 30B in appendix A-8

to 40 CFR 60.

7. Calculations

7.1 Linearity and System Integrity Checks

277

Analyze the linearity check data for Hg, CO

, and O

monitors and the system integrity check

data for Hg CEMS as follows. Calculate the percentage measurement error based upon the

reference value at the low-level, mid-level, and high-level concentrations specified in Section 6.2

of this Exhibit. Perform this calculation once during the certification test. Use the following

equation to calculate the measurement error for each reference value.

R A

ME = Percentage measurement error, based upon the reference value.

R =

eference value of Low, mid, or high-level calibration gas introduced into

the monitoring system.

A =

Average of the monitoring system responses.

7.2 Calibration Error

7.2.1 Pollutant Concentration and Diluent Monitors

For each reference value, calculate the percentage calibration error based upon instrument span

for daily calibration error tests using the following equation:

R A

CE = Calibration error as a percentage of the span of the instrument.

R =

Reference value of zero or upscale (high-level or mid-level, as applicable)

calibration gas introduced into the monitoring system.

A =

Actual monitoring system response to the calibration gas.

S =

Span of the instrument, as specified in Section 2 of this Exhibit.

7.2.2 Flow Monitor Calibration Error

For each reference value, calculate the percentage calibration error based upon span using the

R A

CE = Calibration error as a percentage of span.

R =

Low or high level reference value specified in Section 2.2.2.1 of this

Exhibit.

A =

Actual flow monitor response to the reference value.

S =

Flow monitor calibration span value as determined under Section 2.1.2.2

of this Exhibit.

7.3 Relative Accuracy for O

Monitors, Mercury Monitoring Systems,

and Flow Monitors

Analyze the relative accuracy test audit data from the reference method tests for CO

or O

monitors used only for heat input rate determination, mercury monitoring systems used to

determine mercury mass emissions under Sections 1.14 through 1.18 of Appendix B, and flow

monitors using the following procedures. Summarize the results on a data sheet. An example is

shown in Figure 2. Calculate the mean of the monitor or monitoring system measurement values.

Calculate the mean of the reference method values. Using data from the automated data

acquisition and handling system, calculate the arithmetic differences between the reference

method and monitor measurement data sets. Then calculate the arithmetic mean of the

difference, the standard deviation, the confidence coefficient, and the monitor or monitoring

system relative accuracy using the following procedures and equations.

7.3.1 Arithmetic Mean

Calculate the arithmetic mean of the differences, d, of a data set as follows.

∑

(Equation A-7)

Where:

N = Number of data points.

The difference between a reference method value and the corresponding

continuous emission monitoring system value (RM

–CEM

) at a given

point in time i.

7.3.2 Standard Deviation

Calculate the standard deviation, S

, of a data set as follows:

Number of data points.

The difference between a reference method value and the corresponding

continuous emission monitoring system value (RM

–CEM

) at a given

point in time i.

7.3.3 Confidence Coefficient

Calculate the confidence coefficient (one-tailed), cc, of a data set as follows:

cc t

0.025

(Equation A-9)

Where:

t0.025=t value (see Table 7-1).

Table 7-1 t-Values

----------------------------------------------

----------------------------------------------

----------------------------------------------

7.3.4 Relative Accuracy

280

Calculate the relative accuracy of a data set using the following equation.

×100

(Equation A-10)

Where:

= Arithmetic mean of the reference method values.

= The absolute value of the mean difference between the reference method

values and the corresponding continuous emission monitoring system

values.

= The absolute value of the confidence coefficient.

7.5 Reference Flow-to-Load Ratio or Gross Heat Rate

Except as provided in Section 7.6 of this Exhibit, the owner or operator must

determine

ref

, the reference value of the ratio of flow rate to unit load, each time

that a passing flow RATA is performed at a load level designated as normal in

Section 6.5.2.1 of this Exhibit. The owner or operator must report the current

value of

ref

in the electronic quarterly report required under 40 CFR 75.64,

incorporated by reference in Section 225.140, and must also report the completion

date of the associated RATA. If two load levels have been designated as normal

under Section 6.5.2.1 of this Exhibit, the owner or operator must determine a

separate

ref

value for each of the normal load levels. The reference flow-to-load

ratio must be calculated as follows:

−

=×

avg

ref

(Equation A-13)

Where:

ref

= Reference value of the flow-to-load ratio, from the most recent normal-load

flow RATA, scfh/megawatts, scfh/1000 lb/hr of steam, or scfh/ (mmBtu/hr

of steam output).

ref

= Average stack gas volumetric flow rate measured by the reference method

during the normal-load RATA, scfh.

281

avg

= Average unit load during the normal-load flow RATA, megawatts, 1000

lb/hr of steam, or mmBtu/hr of thermal output.

In Equation A-13, for a common stack, determine

avg

by summing, for each

RATA run, the operating loads of all units discharging through the common stack,

and then taking the arithmetic average of the summed loads. For a unit that

discharges its emissions through multiple stacks, either determine a single value

ref

for the unit or a separate value of

ref

for each stack. In the former case,

calculate

ref

by summing, for each RATA run, the volumetric flow rates through

the individual stacks and then taking the arithmetic average of the summed RATA

run flow rates. In the latter case, calculate the value of

ref

for each stack by

taking the arithmetic average, for all RATA runs, of the flow rates through the

stack. For a unit with a multiple stack discharge configuration consisting of a

main stack and a bypass stack (e.g., a unit with a wet SO

scrubber), determine

ref

separately for each stack at the time of the normal load flow RATA. Round

off the value of

ref

to two decimal places.

In addition to determining

ref

or as an alternative to determine

ref

, a reference

value of the gross heat rate (GHR) may be determined. In order to use this option,

quality assured diluent gas (CO

or O

) must be available for each hour of the

most recent normal-load flow RATA. The reference value of the GHR must be

determined as follows:

avg

ref

GHR

ref

Reference value of the gross heat rate at the time of the

most recent normal-load flow RATA, Btu/kwh, Btu/lb

steam load, or Btu heat input/mmBtu steam output.

(

HeatInput

)

avg

Average hourly heat input during the normal-load flow

RATA, as determined using the applicable equation in

Exhibit C to this Appendix, mmBtu/hr. For multiple stack

configurations, if the reference GHR value is determined

separately for each stack, use the hourly heat input

measured at each stack. If the reference GHR is determined

at the unit level, sum the hourly heat inputs measured at the

individual stacks.

282

avg

Average unit load during the normal-load flow RATA,

megawatts, 1000 lb/hr of steam, or mmBtu/hr thermal

output.

In the calculation of

avg

ref

, the average volumetric flow rate

measured by the reference method during the RATA, and use the average diluent

gas concentration measured during the flow RATA (i.e., the arithmetic average of

the diluent gas concentrations for all clock hours in which a RATA run was

performed).

7.6 Flow-to-Load Test Exemptions

For complex stack configurations (e.g., when the effluent from a unit is divided and discharges

through multiple stacks in such a manner that the flow rate in the individual stacks cannot be

correlated with unit load), the owner or operator may petition the USEPA under 40 CFR 75.66,

incorporated by reference in Section 225.140, for an exemption from the requirements of Section

7.7 to Appendix A to 40 CFR Part 75 and Section 2.2.5 of Exhibit B to Appendix B. The petition

must include sufficient information and data to demonstrate that a flow-to-load or gross heat rate

evaluation is infeasible for the complex stack configuration.

Figures for Exhibit A to Appendix B

Figure 1. Linearity Error Determination

----------------------------------------------------------------------------------------------

-----------------------------------------------------------------------------------------------

Figure 2. Relative Accuracy Determination (Pollutant Concentration Monitors)

-------------------------------------------------------------------------------------------------

(ppm [FNc])

(Pollutant) (ppm [FNc])

------------------------------------------- -------------------------------------------

-------------------------------------------------------------------------------------------------

----- -------- -------- -------- -------- -------- -------- -------- --------

Arithmetic Mean Difference (Eq. A-7).

Confidence Coeffecient (Eq. A-9).

Relative Accuracy (Eq. A-10).

-------------------------------------------------------------------------------------------------

284

[FNa] RM means "reference method data".

[FNb] M means "monitor data".

[FNc] Make sure the RM and M data are on a consistent basis, either wet or dry.

285

Figure 3. Relative Accuracy Determination (Flow Monitors)

-------------------------------------------------------------------------------------------------

---------------------------

--------------------------

-------------------------------------------------------------------------------------------------

----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----

Arithmetic Mean Difference (Eq. A-7).

Confidence Coeffecient (Eq. A-9).

Relative Accuracy (Eq. A-10).

-------------------------------------------------------------------------------------------------

[FNa] Make sure the RM and M data are on a consistent basis, either wet or dry.

Figure 4. Relative Accuracy Determination (NO

/Dilent Combined System)

-------------------------------------------------------------------------------------------------

Reference method data NO

system (lb/mmBtu)

286

-----------------------------------------------------------------------------------------

--------------------------------------------------------------------------------------------------

----- ---------- ---------- ---------- ---------- ---------- ---------- -----------

Arithmetic Mean Difference (Eq. A-7).

Confidence Coeffecient (Eq. A-9).

Relative Accuracy (Eq. A-10).

-------------------------------------------------------------------------------------------------

[FNa] Specify units: ppm, lb/dscf, mg/dscm.

----------------------------------------------------------------------------------------------------------

Figure 5. Cycle Time

Date of test

Component/system ID#:

Analyzer type

Serial Number

High level gas concentration:

ppm/% (circle one)

Zero level gas concentration:

ppm/% (circle one)

Analyzer span setting:

ppm/% (circle one)

Upscale:

287

Stable starting monitor value:

ppm/% (circle one)

Stable ending monitor reading:

Stable starting monitor value:

ppm/% (circle one)

Stable ending monitor reading:

ppm/% (circle one)

Elapsed time:

seconds

Component cycle time =

seconds

System cycle time =

seconds

A. To determine the upscale cycle time (Figure 6a), measure the flue gas emissions until

the response stabilizes. Record the stabilized value (see Section 6.4 of this Exhibit for the

stability criteria).

B. Inject a high-level calibration gas into the port leading to the calibration cell or thimble

(Point B). Allow the analyzer to stabilize. Record the stabilized value.

C. Determine the step change. The step change is equal to the difference between the

final stable calibration gas value (Point D) and the stabilized stack emissions value (Point

A).

D. Take 95% of the step change value and add the result to the stabilized stack emissions

value (Point A). Determine the time at which 95% of the step change occurred (Point C).

E. Calculate the upscale cycle time by subtracting the time at which the calibration gas

was injected (Point B) from the time at which 95% of the step change occurred (Point C).

In this example, upscale cycle time = (11-5) = 6 minutes.

F. To determine the downscale cycle time (Figure 6b) repeat the procedures above,

except that a zero gas is injected when the flue gas emissions have stabilized, and 95% of

the step change in concentration is subtracted from the stabilized stack emissions value.

G. Compare the upscale and downscale cycle time values. The longer of these two times

is the cycle time for the analyzer.

Exhibit B to Appendix B--Quality Assurance and Quality Control Procedures

1. Quality Assurance/Quality Control Program

Develop and implement a quality assurance/quality control (QA/QC) program for the continuous

emission monitoring systems, and their components. At a minimum, include in each QA/QC

program a written plan that describes in detail (or that refers to separate documents containing)

complete, step-by-step procedures and operations for each of the following activities. Upon

288

request from regulatory authorities, the source must make all procedures, maintenance records,

and ancillary supporting documentation from the manufacturer (e.g., software coefficients and

troubleshooting diagrams) available for review during an audit. Electronic storage of the

information in the QA/QC plan is permissible, provided that the information can be made

available in hardcopy upon request during an audit.

1.1 Requirements for All Monitoring Systems

1.1.1 Preventive Maintenance

Keep a written record of procedures needed to maintain the monitoring system in proper

operating condition and a schedule for those procedures. This must, at a minimum, include

procedures specified by the manufacturers of the equipment and, if applicable, additional or

alternate procedures developed for the equipment.

1.1.2 Recordkeeping and Reporting

Keep a written record describing procedures that will be used to implement the recordkeeping

and reporting requirements in subparts E and G of 40 CFR 75, incorporated by reference in

Section 225.140, and Sections 1.10 through 1.13 of Appendix B, as applicable.

1.1.3 Maintenance Records

Keep a record of all testing, maintenance, or repair activities performed on any monitoring

system or component in a location and format suitable for inspection. A maintenance log may be

used for this purpose. The following records should be maintained: date, time, and description of

any testing, adjustment, repair, replacement, or preventive maintenance action performed on any

monitoring system and records of any corrective actions associated with a monitor's outage

period. Additionally, any adjustment that recharacterizes a system's ability to record and report

emissions data must be recorded (e.g., changing of flow monitor or moisture monitoring system

polynomial coefficients, K factors or mathematical algorithms, changing of temperature and

pressure coefficients and dilution ratio settings), and a written explanation of the procedures used

to make the adjustments must be kept.

1.1.4

The requirements in Section 6.1.2 of Exhibit A to this Appendix must be met by any Air

Emissions Testing Body (AETB) performing the semiannual/annual RATAs described in Section

2.3 of this Exhibit and the mercury emission tests described in Sections 1.15(c) and 1.15(d)(4) of

Appendix B.

1.2 Specific Requirements for Continuous Emissions Monitoring Systems

1.2.1 Calibration Error Test and Linearity Check Procedures

Keep a written record of the procedures used for daily calibration error tests and linearity checks

289

(e.g., how gases are to be injected, adjustments of flow rates and pressure, introduction of

reference values, length of time for injection of calibration gases, steps for obtaining calibration

error or error in linearity, determination of interferences, and when calibration adjustments

should be made). Identify any calibration error test and linearity check procedures specific to the

continuous emission monitoring system that vary from the procedures in Exhibit A to this

Appendix.

1.2.2 Calibration and Linearity Adjustments

Explain how each component of the continuous emission monitoring system will be adjusted to

provide correct responses to calibration gases, reference values, and/or indications of

interference both initially and after repairs or corrective action. Identify equations, conversion

factors and other factors affecting calibration of each continuous emission monitoring system.

1.2.3 Relative Accuracy Test Audit Procedures

Keep a written record of procedures and details peculiar to the installed continuous emission

monitoring systems that are to be used for relative accuracy test audits, such as sampling and

analysis methods.

1.2.4 Parametric Monitoring for Units With Add-on Emission Controls

The owner or operator shall keep a written (or electronic) record including a list of operating

parameters for the add-on mercury emission controls, as applicable, and the range of each

operating parameter that indicates the add-on emission controls are operating properly. The

owner or operator shall keep a written (or electronic) record of the parametric monitoring data

during each mercury missing data period.

1.3 Requirements for Sorbent Trap Monitoring Systems

1.3.1 Sorbent Trap Identification and Tracking

Include procedures for inscribing or otherwise permanently marking a unique identification

number on each sorbent trap for tracking purposes. Keep records of the ID of the monitoring

system in which each sorbent trap is used, and the dates and hours of each mercury collection

period.

1.3.2 Monitoring System Integrity and Data Quality

Explain the procedures used to perform the leak checks when sorbent traps are placed in service

and removed from service. Also explain the other QA procedures used to ensure system integrity

and data quality, including, but not limited to, gas flow meter calibrations, verification of

moisture removal, and ensuring air-tight pump operation. In addition, the QA plan must include

the data acceptance and quality control criteria in Section 8 of Exhibit D to this Appendix. All

reference meters used to calibrate the gas flow meters (e.g., wet test meters) must be periodically

290

recalibrated. Annual, or more frequent, recalibration is recommended. If a NIST-traceable

calibration device is used as a reference flow meter, the QA plan must include a protocol for

ongoing maintenance and periodic recalibration to maintain the accuracy and NIST-traceability

of the calibrator.

1.3.3 Mercury Analysis

Explain the chain of custody employed in packing, transporting, and analyzing the sorbent traps

(see Sections 7.2.8 and 7.2.9 in Exhibit D to this Appendix.). Keep records of all mercury

analyses. The analyses must be performed in accordance with the procedures described in

Section 10 of Exhibit D to this Appendix.

1.3.4 Laboratory Certification

The QA Plan must include documentation that the laboratory performing the analyses on the

carbon sorbent traps is certified by the International Organization for Standardization (ISO) to

have a proficiency that meets the requirements of ISO 17025. Alternatively, if the laboratory

performs the spike recovery study described in Section 10.3 of Exhibit D to this Appendix and

repeats that procedure annually, ISO certification is not required.

1.3.5 Data Collection Period

State, and provide the rationale for, the minimum acceptable data collection period (e.g., one

day, one week, etc.) for the size of the sorbent trap selected for the monitoring. Include in the

discussion such factors as the mercury concentration in the stack gas, the capacity of the sorbent

trap, and the minimum mass of mercury required for the analysis.

1.3.6 Relative Accuracy Test Audit Procedures

Keep records of the procedures and details peculiar to the sorbent trap monitoring systems that

are to be followed for relative accuracy test audits, such as sampling and analysis methods.

2. Frequency of Testing

A summary chart showing each quality assurance test and the frequency at which each test is

required is located at the end of this Exhibit in Figure 1.

2.1 Daily Assessments

Perform the following daily assessments to quality-assure the hourly data recorded by the

monitoring systems during each period of unit operation, or, for a bypass stack or duct, each

period in which emissions pass through the bypass stack or duct. These requirements are

effective as of the date when the monitor or continuous emission monitoring system completes

certification testing.

2.1.1 Calibration Error Test

291

Except as provided in Section 2.1.1.2 of this Exhibit, perform the daily calibration error test of

each gas monitoring system (including moisture monitoring systems consisting of wet- and dry-

basis O

analyzers) according to the procedures in Section 6.3.1 of Exhibit A to this Appendix,

and perform the daily calibration error test of each flow monitoring system according to the

procedure in Section 6.3.2 of Exhibit A to this Appendix. When two measurement ranges (low

and high) are required for a particular parameter, perform sufficient calibration error tests on

each range to validate the data recorded on that range, according to the criteria in Section 2.1.5 of

this Exhibit.

For units with add-on emission controls and dual-span or auto-ranging monitors, and other units

that use the maximum expected concentration to determine calibration gas values, perform the

daily calibration error tests on each scale that has been used since the previous calibration error

test. For example, if the pollutant concentration has not exceeded the low-scale value (based on

the maximum expected concentration) since the previous calibration error test, the calibration

error test may be performed on the low-scale only. If, however, the concentration has exceeded

the low-scale span value for one hour or longer since the previous calibration error test, perform

the calibration error test on both the low- and high-scales.

2.1.1.1 On-line Daily Calibration Error Tests

Except as provided in Section 2.1.1.2 of this Exhibit, all daily calibration error tests must be

performed while the unit is in operation at normal, stable conditions (i.e., "on-line").

2.1.1.2 Off-line Daily Calibration Error Tests

Daily calibrations may be performed while the unit is not operating (i.e., "off-line") and may be

used to validate data for a monitoring system that meets the following conditions:

An initial demonstration test of the monitoring system is successfully completed

and the results are reported in the quarterly report required under 40 CFR 75.64,

incorporated by reference in Section 225.140. The initial demonstration test,

hereafter called the "off-line calibration demonstration", consists of an off-line

calibration error test followed by an on-line calibration error test. Both the off-line

and on-line portions of the off-line calibration demonstration must meet the

calibration error performance specification in Section 3.1 of Exhibit A to

Appendix B. Upon completion of the off-line portion of the demonstration, the

zero and upscale monitor responses may be adjusted, but only toward the true

values of the calibration gases or reference signals used to perform the test and

only in accordance with the routine calibration adjustment procedures specified in

the quality control program required under Section 1 of this Exhibit. Once these

adjustments are made, no further adjustments may be made to the monitoring

system until after completion of the on-line portion of the off-line calibration

demonstration. Within 26 clock hours after the completion hour of the off-line

portion of the demonstration, the monitoring system must successfully complete

the first attempted calibration error test, i.e., the on-line portion of the

292

demonstration.

For each monitoring system that has passed the off-line calibration demonstration,

off-line calibration error tests may be used on a limited basis to validate data, in

accordance with subsection (2) in Section 2.1.5.1 of this Exhibit.

2.1.2 Daily Flow Interference Check

Perform the daily flow monitor interference checks specified in Section 2.2.2.2 of Exhibit A to

this Appendix while the unit is in operation at normal, stable conditions.

2.1.3 Additional Calibration Error Tests and Calibration Adjustments

In addition to the daily calibration error tests required under Section 2.1.1 of this

Exhibit, a calibration error test of a monitor must be performed in accordance

with Section 2.1.1 of this Exhibit, as follows: whenever a daily calibration error

test is failed; whenever a monitoring system is returned to service following repair

or corrective maintenance that could affect the monitor's ability to accurately

measure and record emissions data; or after making certain calibration

adjustments, as described in this Section. Except in the case of the routine

calibration adjustments described in this Section, data from the monitor are

considered invalid until the required additional calibration error test has been

successfully completed.

Routine calibration adjustments of a monitor are permitted after any successful

calibration error test. These routine adjustments must be made so as to bring the

monitor readings as close as practicable to the known values of the calibration

gases or to the actual value of the flow monitor reference signals. An additional

calibration error test is required following routine calibration adjustments where

the monitor's calibration has been physically adjusted (e.g., by turning a

potentiometer) to verify that the adjustments have been made properly. An

additional calibration error test is not required, however, if the routine calibration

adjustments are made by means of a mathematical algorithm programmed into the

data acquisition and handling system. It is recommended that routine calibration

adjustments be made, at a minimum, whenever the daily calibration error exceeds

the limits of the applicable performance specification in Exhibit A to this

Appendix for the pollutant concentration monitor, CO

or O

monitor, or flow

monitor.

Additional (non-routine) calibration adjustments of a monitor are permitted prior

to (but not during) linearity checks and RATAs and at other times, provided that

an appropriate technical justification is included in the quality control program

required under Section 1 of this Exhibit. The allowable non-routine adjustments

are as follows. The owner or operator may physically adjust the calibration of a

monitor (e.g., by means of a potentiometer), provided that the post-adjustment

zero and upscale responses of the monitor are within the performance

293

specifications of the instrument given in Section 3.1 of Exhibit A to this

Appendix. An additional calibration error test is required following such

adjustments to verify that the monitor is operating within the performance

specifications at both the zero and upscale calibration levels.

2.1.4 Data Validation

An out-of-control period occurs when the calibration error of a CO

or O

monitor

(including O

monitors used to measure CO

emissions or percent moisture)

exceeds 1.0 percent CO

or O

, or when the calibration error of a flow monitor or

a moisture sensor exceeds 6.0 percent of the span value, which is twice the

applicable specification of Exhibit A to this Appendix. Notwithstanding, a

differential pressure-type flow monitor for which the calibration error exceeds 6.0

percent of the span value will not be considered out-of-control if

−

, the

absolute value of the difference between the monitor response and the reference

value in Equation A-6 of Exhibit A to this Appendix, is < 0.02 inches of water.

For a mercury monitor, an out-of-control period occurs when the calibration error

exceeds 5.0% of the span value. Notwithstanding, the mercury monitor will not be

considered out-of-control if

−

in Equation A-5 does not exceed 1.0 μg/scm.

The out-of-control period begins upon failure of the calibration error test and ends

upon completion of a successful calibration error test. Note, that if a failed

calibration, corrective action, and successful calibration error test occur within the

same hour, emission data for that hour recorded by the monitor after the

successful calibration error test may be used for reporting purposes, provided that

two or more valid readings are obtained as required by Section 1.2 of this

Appendix. Emission data must not be reported from an out-of-control monitor.

An out-of-control period also occurs whenever interference of a flow monitor is

identified. The out-of-control period begins with the hour of completion of the

failed interference check and ends with the hour of completion of an interference

check that is passed.

2.1.5 Quality Assurance of Data With Respect to Daily Assessments

When a monitoring system passes a daily assessment (i.e., daily calibration error test or daily

flow interference check), data from that monitoring system are prospectively validated for 26

clock hours (i.e., 24 hours plus a 2-hour grace period) beginning with the hour in which the test

is passed, unless another assessment (i.e., a daily calibration error test, an interference check of a

flow monitor, a quarterly linearity check, a quarterly leak check, or a relative accuracy test audit)

is failed within the 26-hour period.

2.1.5.1 Data Invalidation with Respect to Daily Assessments

The following specific rules apply to the invalidation of data with respect to daily assessments:

294

Data from a monitoring system are invalid, beginning with the first hour

following the expiration of a 26-hour data validation period or beginning

with the first hour following the expiration of an 8-hour start-up grace

period (as provided under Section 2.1.5.2 of this Exhibit), if the required

subsequent daily assessment has not been conducted.

For a monitor that has passed the off-line calibration demonstration, a

combination of on-line and off-line calibration error tests may be used to

validate data from the monitor, as follows. For a particular unit (or stack)

operating hour, data from a monitor may be validated using a successful

off-line calibration error test if: a) An on-line calibration error test has

been passed within the previous 26 unit (or stack) operating hours; and b)

the 26 clock hour data validation window for the off-line calibration error

test has not expired. If either of these conditions is not met, then the data

from the monitor are invalid with respect to the daily calibration error test

requirement. Data from the monitor must remain invalid until the

appropriate on-line or off-line calibration error test is successfully

completed so that both conditions in subsections a) and b) are met.

For units with two measurement ranges (low and high) for a particular

parameter, when separate analyzers are used for the low and high ranges, a

failed or expired calibration on one of the ranges does not affect the

quality-assured data status on the other range. For a dual-range analyzer

(i.e., a single analyzer with two measurement scales), a failed calibration

error test on either the low or high scale results in an out-of-control period

for the monitor. Data from the monitor remain invalid until corrective

actions are taken and "hands-off" calibration error tests have been passed

on both ranges. However, if the most recent calibration error test on the

high scale was passed but has expired, while the low scale is up-to-date on

its calibration error test requirements (or vice-versa), the expired

calibration error test does not affect the quality-assured status of the data

recorded on the other scale.

2.1.5.2 Daily Assessment Start-Up Grace Period

For the purpose of quality assuring data with respect to a daily assessment (i.e. a daily calibration

error test or a flow interference check), a start-up grace period may apply when a unit begins to

operate after a period of non-operation. The start-up grace period for a daily calibration error test

is independent of the start-up grace period for a daily flow interference check. To qualify for a

start-up grace period for a daily assessment, there are two requirements:

The unit must have resumed operation after being in outage for 1 or more

hours (i.e., the unit must be in a start-up condition) as evidenced by a

change in unit operating time from zero in one clock hour to an operating

time greater than zero in the next clock hour.

295

For the monitoring system to be used to validate data during the grace

period, the previous daily assessment of the same kind must have been

passed on-line within 26 clock hours prior to the last hour in which the

unit operated before the outage. In addition, the monitoring system must

be in-control with respect to quarterly and semi-annual or annual

assessments.

If both of the above conditions are met, then a start-up grace period of up to 8 clock hours

applies, beginning with the first hour of unit operation following the outage. During the start-up

grace period, data generated by the monitoring system are considered quality-assured. For each

monitoring system, a start-up grace period for a calibration error test or flow interference check

ends when either: (1) a daily assessment of the same kind (i.e., calibration error test or flow

interference check) is performed; or (2) 8 clock hours have elapsed (starting with the first hour of

unit operation following the outage), whichever occurs first.

2.1.6 Data Recording

Record and tabulate all calibration error test data according to month, day, clock-hour, and

magnitude in either ppm, percent volume, or scfh. Program monitors that automatically adjust

data to the corrected calibration values (e.g., microprocessor control) to record either: (1) the

unadjusted concentration or flow rate measured in the calibration error test prior to resetting the

calibration, or (2) the magnitude of any adjustment. Record the following applicable flow

monitor interference check data: (1) sample line/sensing port pluggage, and (2) malfunction of

each RTD, transceiver, or equivalent.

2.2 Quarterly Assessments

For each primary and redundant backup monitor or monitoring system, perform the following

quarterly assessments. This requirement applies as of the calendar quarter following the calendar

quarter in which the monitor or continuous emission monitoring system is provisionally certified.

2.2.1 Linearity Check

Perform a linearity check, in accordance with the procedures in Section 6.2 of Exhibit A to this

Appendix, for each primary and redundant backup, mercury monitor and each primary and

redundant backup CO

or O

monitor (including O

monitors used to measure CO

emissions or

to continuously monitor moisture) at least once during each QA operating quarter, as defined in

40 CFR 72.2, incorporated by reference in Section 225.140. For mercury monitors, perform the

linearity checks using elemental mercury standards. Alternatively, you may perform 3-level

system integrity checks at the same three calibration gas levels (i.e., low, mid, and high), using a

NIST-traceable source of oxidized mercury. If you choose this option, the performance

specification in Section 3.2(c) of Exhibit A to this Part must be met at each gas level. For units

using both a low and high span value, a linearity check is required only on the ranges used to

record and report emission data during the QA operating quarter. Conduct the linearity checks no

less than 30 days apart, to the extent practicable. The data validation procedures in Section

2.2.3(e) of this Exhibit must be followed.

296

2.2.2 Leak Check

For differential pressure flow monitors, perform a leak check of all sample lines (a manual check

is acceptable) at least once during each QA operating quarter. For this test, the unit does not have

to be in operation. Conduct the leak checks no less than 30 days apart, to the extent practicable.

If a leak check is failed, follow the applicable data validation procedures in Section 2.2.3(g) of

this Exhibit.

2.2.3 Data Validation

A linearity check must not be commenced if the monitoring system is operating

out-of-control with respect to any of the daily or semiannual quality assurance

assessments required by Sections 2.1 and 2.3 of this Exhibit or with respect to the

additional calibration error test requirements in Section 2.1.3 of this Exhibit.

Each required linearity check must be done according to subsection (b)(1), (b)(2)

or (b)(3) of this Section:

The linearity check may be done "cold," i.e., with no corrective

maintenance, repair, calibration adjustments, re-linearization or

reprogramming of the monitor prior to the test.

The linearity check may be done after performing only the routine or non-

routine calibration adjustments described in Section 2.1.3 of this Exhibit

at the various calibration gas levels (zero, low, mid or high), but no other

corrective maintenance, repair, re-linearization or reprogramming of the

monitor. Trial gas injection runs may be performed after the calibration

adjustments and additional adjustments within the allowable limits in

Section 2.1.3 of this Exhibit may be made prior to the linearity check, as

necessary, to optimize the performance of the monitor. The trial gas

injections need not be reported, provided that they meet the specification

for trial gas injections in Section 1.4(b)(3)(G)(v) of this Appendix.

However, if, for any trial injection, the specification in Section

1.4(b)(3)(G)(v) is not met, the trial injection must be counted as an aborted

linearity check.

The linearity check may be done after repair, corrective maintenance or

reprogramming of the monitor. In this case, the monitor must be

considered out-of-control from the hour in which the repair, corrective

maintenance or reprogramming is commenced until the linearity check has

been passed. Alternatively, the data validation procedures and associated

timelines in Sections 1.4(b)(3)(B) through (I) of this Appendix may be

followed upon completion of the necessary repair, corrective maintenance,

or reprogramming. If the procedures in Section 1.4(b)(3) are used, the

words “quality assurance” apply instead of the word “recertification”.

297

Once a linearity check has been commenced, the test must be done hands-off.

That is, no adjustments of the monitor are permitted during the linearity test

period, other than the routine calibration adjustments following daily calibration

error tests, as described in Section 2.1.3 of this Exhibit. If a routine daily

calibration error test is performed and passed just prior to a linearity test (or

during a linearity test period) and a mathematical correction factor is

automatically applied by the DAHS, the correction factor must be applied to all

subsequent data recorded by the monitor, including the linearity test data.

If a daily calibration error test is failed during a linearity test period, prior to

completing the test, the linearity test must be repeated. Data from the monitor are

invalidated prospectively from the hour of the failed calibration error test until the

hour of completion of a subsequent successful calibration error test. The linearity

test must not be commenced until the monitor has successfully completed a

calibration error test.

An out-of-control period occurs when a linearity test is failed (i.e., when the error

in linearity at any of the three concentrations in the quarterly linearity check (or

any of the six concentrations, when both ranges of a single analyzer with a dual

range are tested) exceeds the applicable specification in Section 3.2 of Exhibit A

to this Appendix) or when a linearity test is aborted due to a problem with the

monitor or monitoring system. The out-of-control period begins with the hour of

the failed or aborted linearity check and ends with the hour of completion of a

satisfactory linearity check following corrective action and/or monitor repair,

unless the option in subsection (b)(3) of this Section to use the data validation

procedures and associated timelines in Section 1.4(b)(3)(B) through (I) of this

Appendix has been selected, in which case the beginning and end of the out-of-

control period must be determined in accordance with Sections 1.4(b)(3)(G)(i)

and (ii). For a dual-range analyzer, "hands-off" linearity checks must be passed on

both measurement scales to end the out-of-control period.

No more than four successive calendar quarters must elapse after the quarter in

which a linearity check of a monitor or monitoring system (or range of a monitor

or monitoring system) was last performed without a subsequent linearity test

having been conducted. If a linearity test has not been completed by the end of the

fourth calendar quarter since the last linearity test, then the linearity test must be

completed within a 168 unit operating hour or stack operating hour "grace period"

(as provided in Section 2.2.4 of this Exhibit) following the end of the fourth

successive elapsed calendar quarter, or data from the CEMS (or range) will

become invalid.

An out-of-control period also occurs when a flow monitor sample line leak is

detected. The out-of-control period begins with the hour of the failed leak check

and ends with the hour of a satisfactory leak check following corrective action.

298

For each monitoring system, report the results of all completed and partial

linearity tests that affect data validation (i.e., all completed, passed linearity

checks; all completed, failed linearity checks; and all linearity checks aborted due

to a problem with the monitor, including trial gas injections counted as failed test

attempts under subsection (b)(2) of this Section or under Section 1.4(b)(3)(G)(vi)

of Appendix B), in the quarterly report required under 40 CFR 75.64,

incorporated by reference in Section 225.140. Note that linearity attempts that are

aborted or invalidated due to problems with the reference calibration gases or due

to operational problems with the affected units need not be reported. Such partial

tests do not affect the validation status of emission data recorded by the monitor.

A record of all linearity tests, trial gas injections and test attempts (whether

reported or not) must be kept on-site as part of the official test log for each

monitoring system.

2.2.4 Linearity and Leak Check Grace Period

When a required linearity test or flow monitor leak check has not been completed

by the end of the QA operating quarter in which it is due or if, due to infrequent

operation of a unit or infrequent use of a required high range of a monitor or

monitoring system, four successive calendar quarters have elapsed after the

quarter in which a linearity check of a monitor or monitoring system (or range)

was last performed without a subsequent linearity test having been done, the

owner or operator has a grace period of 168 consecutive unit operating hours, as

defined in 40 CFR 72.2, incorporated by reference in Section 225.140 (or, for

monitors installed on common stacks or bypass stacks, 168 consecutive stack

operating hours, as defined in 40 CFR 72.2) in which to perform a linearity test or

leak check of that monitor or monitoring system (or range). The grace period

begins with the first unit or stack operating hour following the calendar quarter in

which the linearity test was due. Data validation during a linearity or leak check

grace period must be done in accordance with the applicable provisions in Section

2.2.3 of this Exhibit.

If, at the end of the 168 unit (or stack) operating hour grace period, the required

linearity test or leak check has not been completed, data from the monitoring

system (or range) will be invalid, beginning with the first unit operating hour

following the expiration of the grace period. Data from the monitoring system (or

range) remain invalid until the hour of completion of a subsequent successful

hands-off linearity test or leak check of the monitor or monitoring system (or

range). Note that when a linearity test or a leak check is conducted within a grace

period for the purpose of satisfying the linearity test or leak check requirement

from a previous QA operating quarter, the results of that linearity test or leak

check may only be used to meet the linearity check or leak check requirement of

the previous quarter, not the quarter in which the missed linearity test or leak

check is completed.

2.2.5 Flow-to-Load Ratio or Gross Heat Rate Evaluation

299

Applicability and methodology. Unless exempted from the flow-to-load ratio test

under Section 7.6 of Exhibit A to this Appendix, the owner or operator must, for

each flow rate monitoring system installed on each unit, common stack or

multiple stack, evaluate the flow-to-load ratio quarterly, i.e., for each QA

operating quarter (as defined in 40 CFR 72.2, incorporated by reference in Section

225.140). At the end of each QA operating quarter, the owner or operator must

use Equation B-1 to calculate the flow-to-load ratio for every hour during the

quarter in which: the unit (or combination of units, for a common stack) operated

within ±10.0 percent of

avg

, the average load during the most recent normal-load

flow RATA; and a quality assured hourly average flow rate was obtained with a

certified flow rate monitor. Alternatively, for the reasons stated in subsections

(c)(1) through (c)(6) of this Section, the owner or operator may exclude from the

data analysis certain hours within ±10.0 percent of

avg

and may calculate

values for only the remaining hours.

= Hourly value of the flow-to-load ratio, scfh/megawatts, scfh/1000

lb/hr of steam, or scfh/(mmBtu/hr thermal output).

= Hourly stack gas volumetric flow rate, as measured by the flow

rate monitor, scfh.

= Hourly unit load, megawatts, 1000 lb/hr of steam, or mmBtu/hr

thermal output; must be within + 10.0 percent of

avg

during the

most recent normal-load flow RATA.

In Equation B-1, the owner or operator may use either bias-adjusted flow

rates or unadjusted flow rates, provided that all of the ratios are calculated

the same way. For a common stack,

will be the sum of the hourly

operating loads of all units that discharge through the stack. For a unit that

discharges its emissions through multiple stacks or that monitors its

emissions in multiple breechings,

will be either the combined hourly

volumetric flow rate for all of the stacks or ducts (if the test is done on a

unit basis) or the hourly flow rate through each stack individually (if the

test is performed separately for each stack). For a unit with a multiple

stack discharge configuration consisting of a main stack and a bypass

stack, each of which has a certified flow monitor (e.g., a unit with a wet

300

scrubber), calculate the hourly flow-to-load ratios separately for each

stack. Round off each value of

to two decimal places.

Alternatively, the owner or operator may calculate the hourly gross heat

rates (GHR) in lieu of the hourly flow-to-load ratios. The hourly GHR

must be determined only for those hours in which quality assured flow rate

data and diluent gas (CO

or O

) concentration data are both available

from a certified monitor or monitoring system or reference method. If this

option is selected, calculate each hourly GHR value as follows:

GHR

GHR

Hourly value of the gross heat rate, Btu/kwh, Btu/lb steam load, or

1000 mmBtu heat input/mmBtu thermal output.

(

HeatInput

)

= Hourly heat input, as determined from the quality assured flow

rate and diluent data, using the applicable equation in Exhibit C to

this Appendix, mmBtu/hr.

Hourly unit load, megawatts, 1000 lb/hr of steam, or mmBtu/hr

thermal output; must be within + 10.0 percent of

avg

during the

most recent normal-load flow RATA.

In Equation B-1a, the owner or operator may either use bias-adjusted flow

rates or unadjusted flow rates in the calculation of

that all of the heat input values are determined in the same manner.

The owner or operator must evaluate the calculated hourly flow-to-load

ratios (or gross heat rates) as follows. A separate data analysis must be

performed for each primary and each redundant backup flow rate monitor

used to record and report data during the quarter. Each analysis must be

based on a minimum of 168 acceptable recorded hourly average flow rates

(i.e., at loads within ± 10 percent of

avg

). When two RATA load levels

are designated as normal, the analysis must be performed at the higher

load level, unless there are fewer than 168 acceptable data points available

at that load level, in which case the analysis must be performed at the

lower load level. If, for a particular flow monitor, fewer than 168

acceptable hourly flow-to-load ratios (or GHR values) are available at any

of the load levels designated as normal, a flow-to-load (or GHR)

301

evaluation is not required for that monitor for that calendar quarter.

For each flow monitor, use Equation B-2 in this Exhibit to calculate

the absolute percentage difference between each hourly

value and

ref

, the reference value of the flow-to-load ratio, as determined in

accordance with Section 7.5 of Exhibit A to this Appendix. Note that

ref

must always be based upon the most recent normal-load RATA, even if

that RATA was performed in the calendar quarter being evaluated.

ref

= Absolute percentage difference between the hourly average flow-

to-load ratio and the reference value of the flow-to-load ratio at

normal load.

= The hourly average flow-to-load ratio, for each flow rate recorded

at a load level within ±10.0 percent of

avg

ref

= The reference value of the flow-to-load ratio from the most recent

normal-load flow RATA, determined in accordance with Section

7.5 of Exhibit A to this Appendix.

Equation B-2 must be used in a consistent manner. That is, use

ref

and

if the

flow-to-load ratio is being evaluated, and use (GHR)ref and (GHR) h if the gross

heat rate is being evaluated. Finally, calculate

, the arithmetic average of all of

the hourly

values. The owner or operator must report the results of each

quarterly flow-to-load (or gross heat rate) evaluation, as determined from

Equation B-2, in the electronic quarterly report required under 40 CFR 75.64,

incorporated by reference in Section 225.140.

Acceptable results. The results of a quarterly flow-to-load (or gross heat rate)

evaluation are acceptable, and no further action is required, if the calculated value

is less than or equal to: (1) 15.0 percent, if

avg

for the most recent normal-

load flow RATA is

≥60 megawatts (or ≥500 klb/hr of steam) and if unadjusted

flow rates were used in the calculations; or (2) 10.0 percent, if

avg

for the most

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recent normal-load flow RATA is

≥60 megawatts (or ≥500 klb/hr of steam) and if

bias-adjusted flow rates were used in the calculations; or (3) 20.0 percent, if

avg

for the most recent normal-load flow RATA is <60 megawatts (or <500 klb/hr of

steam) and if unadjusted flow rates were used in the calculations; or (4) 15.0

percent, if

avg

for the most recent normal-load flow RATA is <60 megawatts (or

<500 klb/hr of steam) and if bias-adjusted flow rates were used in the

calculations. If

is above these limits, the owner or operator must either:

implement Option 1 in Section 2.2.5.1 of this Exhibit; or perform a RATA in

accordance with Option 2 in Section 2.2.5.2 of this Exhibit; or re-examine the

hourly data used for the flow-to-load or GHR analysis and recalculate

, after

excluding all non-representative hourly flow rates. If

is above these limits, the

owner or operator must either: implement Option 1 in Section 2.2.5.1 of this

Exhibit; perform a RATA in accordance with Option 2 in Section 2.2.5.2 of this

Exhibit; or (if applicable) re-examine the hourly data used for the flow-to-load or

GHR analysis and recalculate

, after excluding all non-representative hourly

flow rates, as provided in subsection (c) of this Section.

Recalculation of

. If the owner or operator did not exclude any hours within

±10 percent of

avg

from the original data analysis and chooses to recalculate

the flow rates for the following hours are considered non-representative and may

be excluded from the data analysis:

Any hour in which the type of fuel combusted was different from the fuel

burned during the most recent normal-load RATA. For purposes of this

determination, the type of fuel is different if the fuel is in a different state

of matter (i.e., solid, liquid, or gas) than is the fuel burned during the

RATA or if the fuel is a different classification of coal (e.g., bituminous

versus sub-bituminous). Also, for units that co-fire different types of fuels,

if the reference RATA was done while co-firing, then hours in which a

single fuel was combusted may be excluded from the data analysis as

different fuel hours (and vice-versa for co-fired hours, if the reference

RATA was done while combusting only one type of fuel);

For a unit that is equipped with an SO

scrubber and which always

discharges its flue gases to the atmosphere through a single stack, any

hour in which the SO

scrubber was bypassed;

Any hour in which "ramping" occurred, i.e., the hourly load differed by

more than ±15.0 percent from the load during the preceding hour or the

subsequent hour;

For a unit with a multiple stack discharge configuration consisting of a

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main stack and a bypass stack, any hour in which the flue gases were

discharged through both stacks;

If a normal-load flow RATA was performed and passed during the quarter

being analyzed, any hour prior to completion of that RATA; and

If a problem with the accuracy of the flow monitor was discovered during

the quarter and was corrected (as evidenced by passing the abbreviated

flow-to-load test in Section 2.2.5.3 of this Exhibit), any hour prior to

completion of the abbreviated flow-to-load test.

After identifying and excluding all non-representative hourly data in

accordance with subsections (c)(1) through (6) of this Section, the owner

or operator may analyze the remaining data a second time. At least 168

representative hourly ratios or GHR values must be available to perform

the analysis; otherwise, the flow-to-load (or GHR) analysis is not required

for that monitor for that calendar quarter.

If, after re-analyzing the data,

meets the applicable limit in subsection

(b)(1), (b)(2), (b)(3), or (b)(4) of this Section, no further action is required.

If, however,

is still above the applicable limit, data from the monitor

will be declared out-of-control, beginning with the first unit operating

hour following the quarter in which

exceeded the applicable limit.

Alternatively, if a probationary calibration error test is performed and

passed according to Section 1.4(b)(3)(B) of this Appendix, data from the

monitor may be declared conditionally valid following the quarter in

which

exceeded the applicable limit. The owner or operator must then

either implement Option 1 in Section 2.2.5.1 of this Exhibit or Option 2 in

Section 2.2.5.2 of this Exhibit.

2.2.5.1 Option 1

Within 14 unit operating days of the end of the calendar quarter for which the

value is above

the applicable limit, investigate and troubleshoot the applicable flow monitors. Evaluate the

results of each investigation as follows:

If the investigation fails to uncover a problem with the flow monitor, a RATA

must be performed in accordance with Option 2 in Section 2.2.5.2 of this Exhibit.

If a problem with the flow monitor is identified through the investigation

(including the need to re-linearize the monitor by changing the polynomial

coefficients or K factors), data from the monitor are considered invalid back to the

first unit operating hour after the end of the calendar quarter for which

was

304

above the applicable limit. If the option to use conditional data validation was

selected under Section 2.2.5(c)(8) of this Exhibit, all conditionally valid data will

be invalidated, back to the first unit operating hour after the end of the calendar

quarter for which

was above the applicable limit. Corrective actions must be

taken. All corrective actions (e.g., non-routine maintenance, repairs, major

component replacements, re-linearization of the monitor, etc.) must be

documented in the operation and maintenance records for the monitor. The owner

or operator then must either complete the abbreviated flow-to-load test in Section

2.2.5.3 of this Exhibit, or, if the corrective action taken has required

relinearization of the flow monitor, must perform a 3-load RATA. The

conditional data validation procedures in Section 1.4(b)(3)of this Appendix may

be applied to the 3-load RATA.

2.2.5.2 Option 2

Perform a single-load RATA (at a load designated as normal under Section 6.5.2.1 of Exhibit A

to this Appendix) of each flow monitor for which

is outside of the applicable limit. If the

RATA is passed hands-off, in accordance with Section 2.3.2(c) of this Exhibit, no further action

is required and the out-of-control period for the monitor ends at the date and hour of completion

of a successful RATA, unless the option to use conditional data validation was selected under

Section 2.2.5(c)(8) of this Exhibit. In that case, all conditionally valid data from the monitor are

considered to be quality-assured, back to the first unit operating hour following the end of the

calendar quarter for which the

value was above the applicable limit. If the RATA is failed,

all data from the monitor will be invalidated, back to the first unit operating hour following the

end of the calendar quarter for which the

value was above the applicable limit. Data from the

monitor remain invalid until the required RATA has been passed. Alternatively, following a

failed RATA and corrective actions, the conditional data validation procedures of Section

1.4(b)(3) of this Appendix may be used until the RATA has been passed. If the corrective actions

taken following the failed RATA included adjustment of the polynomial coefficients or K-factors

of the flow monitor, a 3-level RATA is required, except as otherwise specified in Section 2.3.1.3

of this Exhibit.

2.2.5.3 Abbreviated Flow-to-Load Test

The following abbreviated flow-to-load test may be performed after any

documented repair, component replacement, or other corrective maintenance to a

flow monitor (except for changes affecting the linearity of the flow monitor, such

as adjusting the flow monitor coefficients or K factors) to demonstrate that the

repair, replacement, or other maintenance has not significantly affected the

monitor's ability to accurately measure the stack gas volumetric flow rate. Data

from the monitoring system are considered invalid from the hour of

commencement of the repair, replacement, or maintenance until either the hour in

which the abbreviated flow-to-load test is passed, or the hour in which a

probationary calibration error test is passed following completion of the repair,

305

replacement, or maintenance and any associated adjustments to the monitor. If the

latter option is selected, the abbreviated flow-to-load test must be completed

within 168 unit operating hours of the probationary calibration error test (or, for

peaking units, within 30 unit operating days, if that is less restrictive). Data from

the monitor are considered to be conditionally valid (as defined in 40 CFR 72.2,

incorporated by reference in Section 225.140), beginning with the hour of the

probationary calibration error test.

Operate the units in such a way as to reproduce, as closely as practicable, the

exact conditions at the time of the most recent normal-load flow RATA. To

achieve this, it is recommended that the load be held constant to within ±10.0

percent of the average load during the RATA and that the diluent gas (CO

or O

)

concentration be maintained within ±-0.5 percent CO

or O

of the average

diluent concentration during the RATA. For common stacks, to the extent

practicable, use the same combination of units and load levels that were used

during the RATA. When the process parameters have been set, record a minimum

of six and a maximum of 12 consecutive hourly average flow rates, using the flow

monitors for which

was outside the applicable limit. For peaking units, a

minimum of three and a maximum of 12 consecutive hourly average flow rates

are required. Also record the corresponding hourly load values and, if applicable,

the hourly diluent gas concentrations. Calculate the flow-to-load ratio (or GHR)

for each hour in the test hour period, using Equation B-1 or B-1a. Determine

for each hourly flow- to-load ratio (or GHR), using Equation B-2 of this Exhibit

and then calculate

, the arithmetic average of the Eh values.

The results of the abbreviated flow-to-load test will be considered acceptable, and

no further action is required if the value of

does not exceed the applicable

limit specified in Section 2.2.5 of this Exhibit. All conditionally valid data

recorded by the flow monitor will be considered quality assured, beginning with

the hour of the probationary calibration error test that preceded the abbreviated

flow-to-load test (if applicable). However, if

is outside the applicable limit, all

conditionally valid data recorded by the flow monitor (if applicable) will be

considered invalid back to the hour of the probationary calibration error test that

preceded the abbreviated flow-to-load test, and a single-load RATA is required in

accordance with Section 2.2.5.2 of this Exhibit. If the flow monitor must be re-

linearized, however, a 3-load RATA is required.

2.3 Semiannual and Annual Assessments

For each primary and redundant backup monitoring system, perform relative accuracy

assessments either semiannually or annually, as specified in Section 2.3.1.1 or 2.3.1.2 of this

Exhibit for the type of test and the performance achieved. This requirement applies as of the

calendar quarter following the calendar quarter in which the monitoring system is provisionally

certified. A summary chart showing the frequency with which a relative accuracy test audit must

306

be performed, depending on the accuracy achieved, is located at the end of this Exhibit in Figure

2.3.1 Relative Accuracy Test Audit (RATA)

2.3.1.1 Standard RATA Frequencies

Except for mercury monitoring systems, and as otherwise specified in Section

2.3.1.2 of this Exhibit, perform relative accuracy test audits semiannually, i.e.,

once every two successive QA operating quarters (as defined in 40 CFR 72.2,

incorporated by reference in Section 225.140) for each primary and redundant

backup flow monitor, CO

or O

diluent monitor used to determine heat input, and

each moisture monitoring system. For each primary and redundant backup

mercury concentration monitoring system and each sorbent trap monitoring

system, RATAs must be performed annually, i.e., once every four successive QA

operating quarters (as defined in 40 CFR 72.2). A calendar quarter that does not

qualify as a QA operating quarter must be excluded in determining the deadline

for the next RATA. No more than eight successive calendar quarters must elapse

after the quarter in which a RATA was last performed without a subsequent

RATA having been conducted. If a RATA has not been completed by the end of

the eighth calendar quarter since the quarter of the last RATA, then the RATA

must be completed within a 720 unit (or stack) operating hour grace period (as

provided in Section 2.3.3 of this Exhibit) following the end of the eighth

successive elapsed calendar quarter, or data from the CEMS will become invalid.

The relative accuracy test audit frequency of a CEMS may be reduced, as

specified in Section 2.3.1.2 of this Exhibit, for primary or redundant backup

monitoring systems which qualify for less frequent testing. Perform all required

RATAs in accordance with the applicable procedures and provisions in Sections

6.5 through 6.5.2.2 of Exhibit A to this Appendix and Sections 2.3.1.3 and 2.3.1.4

of this Exhibit.

2.3.1.2 Reduced RATA Frequencies

Relative accuracy test audits of primary and redundant backup CO

or O

diluent monitors used

to determine heat input, moisture monitoring systems, flow monitors may be performed annually

(i.e., once every four successive QA operating quarters, rather than once every two successive

QA operating quarters) if any of the following conditions are met for the specific monitoring

system involved:

The relative accuracy during the audit of a CO

or O

diluent monitor used to

determine heat input is

≤7.5 percent;

The relative accuracy during the audit of a flow monitor is

≤7.5 percent at each

operating level tested;

307

For low flow (≤10.0

fps), as measured by the reference method during the RATA

stacks/ducts, when the flow monitor fails to achieve a relative accuracy

≤7.5

percent during the audit, but the monitor mean value, calculated using Equation

A-7 in Exhibit A to this Appendix and converted back to an equivalent velocity in

standard feet per second (fps), is within ± 1.5 fps of the reference method mean

value, converted to an equivalent velocity in fps;

For a CO

or O

monitor, when the mean difference between the reference method

values from the RATA and the corresponding monitor values is within ± 0.7

percent CO

or O

; and

When the relative accuracy of a continuous moisture monitoring system is

≤ 7.5

percent or when the mean difference between the reference method values from

the RATA and the corresponding monitoring system values is within ±1.0 percent

2.3.1.3 RATA Load Levels and Additional RATA Requirements

For CO

or O

diluent monitors used to determine heat input, mercury

concentration monitoring systems, sorbent trap monitoring systems, moisture

monitoring systems, the required semiannual or annual RATA tests must be done

at the load level designated as normal under Section 6.5.2.1(d) of Exhibit A to this

Appendix. If two load levels are designated as normal, the required RATAs may

be done at either load level.

For flow monitors installed and bypass stacks all required semiannual or annual

relative accuracy test audits must be single-load audits at the normal load, as

defined in Section 6.5.2.1(d) of Exhibit A to this Appendix.

For all other flow monitors, the RATAs must be performed as follows:

An annual 2-load flow RATA must be done at the two most frequently

used load levels, as determined under Section 6.5.2.1(d) of Exhibit A to

this Appendix. Alternatively, a 3-load flow RATA at the low, mid, and

high load levels, as defined under Section 6.5.2.1(b) of Exhibit A to this

Appendix, may be performed in lieu of the 2-load annual RATA.

If the flow monitor is on a semiannual RATA frequency, 2-load flow

RATAs and single-load flow RATAs at the normal load level may be

performed alternately.

A single-load annual flow RATA may be performed in lieu of the 2-load

RATA if the results of an historical load data analysis show that in the

time period extending from the ending date of the last annual flow RATA

to a date that is no more than 21 days prior to the date of the current

annual flow RATA, the unit (or combination of units, for a common stack)

308

has operated at a single load level (low, mid, or high), for

≥85.0 percent of

the time. Alternatively, a flow monitor may qualify for a single-load

RATA if the 85.0 percent criterion is met in the time period extending

from the beginning of the quarter in which the last annual flow RATA was

performed through the end of the calendar quarter preceding the quarter of

current annual flow RATA.

A 3-load RATA, at the low-, mid-, and high-load levels, as determined

under Section 6.5.2.1 of Exhibit A to this Appendix, must be performed at

least once every twenty consecutive calendar quarters, except for flow

monitors that are exempted from 3-load RATA testing under Section

6.5.2(b) of Exhibit A to this Appendix.

A 3-load RATA is required whenever a flow monitor is re-characterized,

i.e., when its polynomial coefficients or K factors are changed, except for

flow monitors that are exempted from 3-load RATA testing under Section

6.5.2(b) of Exhibit A to this Appendix. For monitors so exempted under

Section 6.5.2(b), a single-load flow RATA is required.

For all multi-level flow audits, the audit points at adjacent load levels or at

adjacent operating levels (e.g., mid and high) must be separated by no less

than 25.0 percent of the "range of operation," as defined in Section 6.5.2.1

of Exhibit A to this Appendix.

A RATA of a moisture monitoring system must be performed whenever

the coefficient, K factor or mathematical algorithm determined under

Section 6.5.6 of Exhibit A to this Appendix is changed.

2.3.1.4 Number of RATA Attempts

The owner or operator may perform as many RATA attempts as are necessary to achieve the

desired relative accuracy test audit frequencies. However, the data validation procedures in

Section 2.3.2 of this Exhibit must be followed.

2.3.2 Data Validation

A RATA must not commence if the monitoring system is operating out-of-control

with respect to any of the daily and quarterly quality assurance assessments

required by Sections 2.1 and 2.2 of this Exhibit or with respect to the additional

calibration error test requirements in Section 2.1.3 of this Exhibit.

Each required RATA must be done according to subsections (b)(1), (b)(2) or

(b)(3) of this Section:

The RATA may be done "cold," i.e., with no corrective maintenance,

repair, calibration adjustments, re-linearization or reprogramming of the

309

monitoring system prior to the test.

The RATA may be done after performing only the routine or non-routine

calibration adjustments described in Section 2.1.3 of this Exhibit at the

zero and/or upscale calibration gas levels, but no other corrective

maintenance, repair, re-linearization or reprogramming of the monitoring

system. Trial RATA runs may be performed after the calibration

adjustments and additional adjustments within the allowable limits in

Section 2.1.3 of this Exhibit may be made prior to the RATA, as

necessary, to optimize the performance of the CEMS. The trial RATA

runs need not be reported, provided that they meet the specification for

trial RATA runs in Section 1.4(b)(3)(G)(v) of this Appendix. However, if,

for any trial run, the specification in Section 1.4(b)(3)(G)(v) of this

Appendix is not met, the trial run must be counted as an aborted RATA

attempt.

The RATA may be done after repair, corrective maintenance, re-

linearization or reprogramming of the monitoring system. In this case, the

monitoring system will be considered out-of-control from the hour in

which the repair, corrective maintenance, re-linearization or

reprogramming is commenced until the RATA has been passed.

Alternatively, the data validation procedures and associated timelines in

Sections 1.4(b)(3)(B) through (I) of this Appendix may be followed upon

completion of the necessary repair, corrective maintenance, re-

linearization or reprogramming. If the procedures in Section 1.4(b)(3) of

this Appendix are used, the words “quality assurance” apply instead of the

word “recertification”.

Once a RATA is commenced, the test must be done hands-off. No adjustment of

the monitor's calibration is permitted during the RATA test period, other than the

routine calibration adjustments following daily calibration error tests, as described

in Section 2.1.3 of this Exhibit. If a routine daily calibration error test is

performed and passed just prior to a RATA (or during a RATA test period) and a

mathematical correction factor is automatically applied by the DAHS, the

correction factor must be applied to all subsequent data recorded by the monitor,

including the RATA test data. For 2-level and 3- level flow monitor audits, no

linearization or reprogramming of the monitor is permitted in between load levels.

For single-load RATAs, if a daily calibration error test is failed during a RATA

test period, prior to completing the test, the RATA must be repeated. Data from

the monitor are invalidated prospectively from the hour of the failed calibration

error test until the hour of completion of a subsequent successful calibration error

test. The subsequent RATA must not be commenced until the monitor has

successfully passed a calibration error test in accordance with Section 2.1.3 of this

Exhibit. Notwithstanding these requirements, when ASTM D6784-02

(incorporated by reference under Section 225.140) or Method 29 in appendix A-8

310

to 40 CFR 60, incorporated by reference in Section 225.140, is used as the

reference method for the RATA of a mercury CEMS, if a calibration error test of

the CEMS is failed during a RATA test period, any test runs completed prior to

the failed calibration error test need not be repeated; however, the RATA may not

continue until a subsequent calibration error test of the mercury CEMS has been

passed. For multiple-load flow RATAs, each load level is treated as a separate

RATA (i.e., when a calibration error test is failed prior to completing the RATA

at a particular load level, only the RATA at that load level must be repeated; the

results of any previously-passed RATAs at the other load levels are unaffected,

unless re-characterization of the monitor is required to correct the problem that

caused the calibration failure, in which case a subsequent 3-load RATA is

required), except as otherwise provided in Section 2.3.1.3(c)(5) of this Exhibit.

For a RATA performed using the option in subsection (b)(1) or (b)(2) of this

Section, if the RATA is failed (that is, if the relative accuracy exceeds the

applicable specification in Section 3.3 of Exhibit A to this Appendix) or if the

RATA is aborted prior to completion due to a problem with the CEMS, then the

CEMS is out-of-control and all emission data from the CEMS are invalidated

prospectively from the hour in which the RATA is failed or aborted. Data from

the CEMS remain invalid until the hour of completion of a subsequent RATA that

meets the applicable specification in Section 3.3 of Exhibit A to this Appendix. If

the option in subsection (b)(3) of this Section to use the data validation

procedures and associated timelines in Sections 1.4(b)(3)(B) through(b)(3)(I) of

this Appendix has been selected, the beginning and end of the out-of-control

period must be determined in accordance with Section 1.4(b)(3)(G)(i) and (ii) of

this Appendix. Note that when a RATA is aborted for a reason other than

monitoring system malfunction (see subsection (g) of this Section), this does not

trigger an out-of-control period for the monitoring system.

For a 2-load or 3-load flow RATA, if, at any load level, a RATA is failed or

aborted due to a problem with the flow monitor, the RATA at that load level must

be repeated. The flow monitor is considered out-of-control and data from the

monitor are invalidated from the hour in which the test is failed or aborted and

remain invalid until the passing of a RATA at the failed load level, unless the

option in subsection (b)(3) of this Section to use the data validation procedures

and associated timelines in Section 1.4(b)(3)(B) through (b)(3)(I) of this

Appendix has been selected, in which case the beginning and end of the out-of-

control period must be determined in accordance with Section 1.4(b)(3)(G)(i) and

(ii) of this Appendix. Flow RATAs that were previously passed at the other load

levels do not have to be repeated unless the flow monitor must be re-characterized

following the failed or aborted test. If the flow monitor is re-characterized, a

subsequent 3-load RATA is required, except as otherwise provided in Section

2.3.1.3(c)(5) of this Exhibit.

For each monitoring system, report the results of all completed and partial

RATAs that affect data validation (i.e., all completed, passed RATAs; all

311

completed, failed RATAs; and all RATAs aborted due to a problem with the

CEMS, including trial RATA runs counted as failed test attempts under

subsection (b)(2) of this Section or under Section 1.4(b)(3)(G)(vi)) in the

quarterly report required under 40 CFR 75.64, incorporated by reference in

Section 225.140. Note that RATA attempts that are aborted or invalidated due to

problems with the reference method or due to operational problems with the

affected units need not be reported. Such runs do not affect the validation status of

emission data recorded by the CEMS. However, a record of all RATAs, trial

RATA runs and RATA attempts (whether reported or not) must be kept on-site as

part of the official test log for each monitoring system.

2.3.3 RATA Grace Period

The owner or operator has a grace period of 720 consecutive unit operating hours,

as defined in 40 CFR 72.2, incorporated by reference in Section 225.140 (or, for

CEMS installed on common stacks or bypass stacks, 720 consecutive stack

operating hours, as defined in 40 CFR 72.2), in which to complete the required

RATA for a particular CEMS whenever:

A required RATA has not been performed by the end of the QA operating

quarter in which it is due; or

A required 3-load flow RATA has not been performed by the end of the

calendar quarter in which it is due.

The grace period will begin with the first unit (or stack) operating hour following

the calendar quarter in which the required RATA was due. Data validation during

a RATA grace period must be done in accordance with the applicable provisions

in Section 2.3.2 of this Exhibit.

If, at the end of the 720 unit (or stack) operating hour grace period, the RATA has

not been completed, data from the monitoring system will be invalid, beginning

with the first unit operating hour following the expiration of the grace period.

Data from the CEMS remain invalid until the hour of completion of a subsequent

hands-off RATA. The deadline for the next test will be either two QA operating

quarters (if a semiannual RATA frequency is obtained) or four QA operating

quarters (if an annual RATA frequency is obtained) after the quarter in which the

RATA is completed, not to exceed eight calendar quarters.

When a RATA is done during a grace period in order to satisfy a RATA

requirement from a previous quarter, the deadline for the next RATA must be

determined as follows:

If the grace period RATA qualifies for a reduced, (i.e., annual), RATA

frequency the deadline for the next RATA will be set at three QA

operating quarters after the quarter in which the grace period test is

312

completed.

If the grace period RATA qualifies for the standard, (i.e., semiannual),

RATA frequency the deadline for the next RATA will be set at two QA

operating quarters after the quarter in which the grace period test is

completed.

Notwithstanding these requirements, no more than eight successive

calendar quarters must elapse after the quarter in which the grace period

test is completed, without a subsequent RATA having been conducted.

2.4 Recertification, Quality Assurance, and RATA Frequency (Special Considerations)

When a significant change is made to a monitoring system such that

recertification of the monitoring system is required in accordance with Section

1.4(b)of this Appendix, a recertification test (or tests) must be performed to

ensure that the CEMS continues to generate valid data. In all recertifications, a

RATA will be one of the required tests; for some recertifications, other tests will

also be required. A recertification test may be used to satisfy the quality assurance

test requirement of this Exhibit. For example, if, for a particular change made to a

CEMS, one of the required recertification tests is a linearity check and the

linearity check is successful, then, unless another recertification event occurs in

that same QA operating quarter, it would not be necessary to perform an

additional linearity test of the CEMS in that quarter to meet the quality assurance

requirement of Section 2.2.1 of this Exhibit. For this reason, EPA recommends

that owners or operators coordinate component replacements, system upgrades,

and other events that may require recertification, to the extent practicable, with

the periodic quality assurance testing required by this Exhibit. When a quality

assurance test is done for the dual purpose of recertification and routine quality

assurance, the applicable data validation procedures in Section 1.4(b)(3) must be

followed.

Except for Hg monitoring systems (which always have an annual RATA

frequency), whenever a passing RATA of a gas monitor is performed, or a

passing 2-load RATA or a passing 3-load RATA of a flow monitor is performed

(irrespective of whether the RATA is done to satisfy a recertification requirement

or to meet the quality assurance requirements of this Exhibit, or both), the RATA

frequency (semi-annual or annual) must be established based upon the date and

time of completion of the RATA and the relative accuracy percentage obtained.

For 2-load and 3-load flow RATAs, use the highest percentage relative accuracy

at any of the loads to determine the RATA frequency. The results of a single-load

flow RATA may be used to establish the RATA frequency when the single-load

flow RATA is specifically required under Section 2.3.1.3(b) of this Exhibit or

when the single-load RATA is allowed under Section 2.3.1.3(c) of this Exhibit for

a unit that has operated at one load level for

≥85.0 percent of the time since the

last annual flow RATA. No other single-load flow RATA may be used to

313

establish an annual RATA frequency; however, a 2-load or 3-load flow RATA

may be performed at any time or in place of any required single-load RATA, in

order to establish an annual RATA frequency.

2.5 Other Audits

Affected units may be subject to relative accuracy test audits at any time. If a monitor or

continuous emission monitoring system fails the relative accuracy test during the audit, the

monitor or continuous emission monitoring system will be considered to be out-of-control

beginning with the date and time of completion of the audit, and continuing until a successful

audit test is completed following corrective action. Alternatively, the conditional data validation

procedures and associated timelines in Sections 1.4(b)(3)(B) through (I) of this Appendix may be

used following the corrective actions.

2.6 System Integrity Checks for Mercury Monitors

For each mercury concentration monitoring system (except for a mercury monitor that does not

have a converter), perform a single-point system integrity check weekly, i.e., at least once every

168 unit or stack operating hours, using a NIST-traceable source of oxidized mercury. Perform

this check using a mid- or high-level gas concentration, as defined in Section 5.2 of Exhibit A to

this Appendix. The performance specifications in subsection (3) of Section 3.2 of Exhibit A to

this Appendix must be met, otherwise the monitoring system is considered out-of-control, from

the hour of the failed check until a subsequent system integrity check is passed. If a required

system integrity check is not performed and passed within 168 unit or stack operating hours of

last successful check, the monitoring system will also be considered out of control, beginning

with the 169th unit or stack operating hour after the last successful check, and continuing until a

subsequent system integrity check is passed. This weekly check is not required if the daily

calibration assessments in Section 2.1.1 of this Exhibit are performed using a NIST-traceable

source of oxidized mercury.

[Note: The following TABLE/FORM is too wide to be displayed on one screen. You must print

it for a meaningful review of its contents. The table has been divided into multiple pieces with

each piece containing information to help you assemble a printout of the table. The information

for each piece includes: (1) a three line message preceding the tabular data showing by line # and

character # the position of the upper left-hand corner of the piece and the position of the piece

within the entire table; and (2) a numeric scale following the tabular data displaying the character

positions.]

Figure 1 for Exhibit B of Appendix B Part 75.

− Quality Assuruiaremencnts e Test Req

--------------------------------------------------------------------------------------------------------------

Test

Basic QA test frequency requirements [FN*]

--------------------------------------------------------------------------------------------------------------

Calibration Error Test (2 pt.)

Interference Check (flow)

Flow-to-Load Ratio

Leak Check (DP flow monitors)

Linearity Check or System

Integrity Check [FN**] (3 pt.)

Single-point System Integrity

RATA (All Hg monitoring

systems)

RATA (flow) [FN1] [FN2]

--------------------------------------------------------------------------------------------------------------

[FN*] "Daily" means operating days, only. "Weekly" means once every 168 unit or stack

operating hours. "Quarterly" means once every QA operating quarter. "Semiannual" means once

every two QA operating quarters. "Annual" means once every four QA operating

quarters.[FN**] The system integrity check applies only to Hg monitors with converters. The

single-point weekly system integrity check is not required if daily calibrations are performed

using a NIST-traceable source of oxidized Hg. The 3-point quarterly system integrity check is

not required if a linearity check is performed.

[FN1] Conduct RATA annually (i.e., once every four QA operating quarters), if monitor meets

accuracy requirements to qualify for less frequent testing. [FN2] For flow monitors installed on

peaking units, bypass stacks conduct all RATAs at a single, normal load (or operating level). For

other flow monitors, conduct annual RATAs at two load levels (or operating levels). Alternating

single-load and 2-load (or single-level and 2-level) RATAs may be done if a monitor is on a

semiannual frequency. A single-load (or single-level) RATA may be done in lieu of a 2-load (or

2-level) RATA if, since the last annual flow RATA, the unit has operated at one load level (or

five calendar years and whenever a flow monitor is re-linearized, except for flow monitors

exempted from 3-level RATA testing under Section 6.5.2(b) of Exhibit A to this Appendix.

Figure 2 for Exhibit B of Appendix B

− Relative Accuracy Test Frequency Incentive System

----------------------------------------------------------------------------------------------------------------

315

RATA

Semiannual [FNW] (percent)

Annual [FNW]

----------------------------------------------------------------------------------------------------------------

or NO

[FNY]

7.5% < RA

≤ 10.0% or ± 15.0 ppm

----------------------------------------------------------------------------------------------------------------

[FNW] The deadline for the next RATA is the end of the second (if semiannual) or fourth (if

annual) successive QA operating quarter following the quarter in which the CEMS was last

tested. Exclude calendar quarters with fewer than 168 unit operating hours (or, for common

stacks and bypass stacks, exclude quarters with fewer than 168 stack operating hours) in

determining the RATA deadline. For SO2 monitors, QA operating quarters in which only very

low sulfur fuel as defined in 40 CFR 72.2, incorporated by reference in Section 225.140, is

combusted may also be excluded. However, the exclusion of calendar quarters is limited as

follows: the deadline for the next RATA will be no more than 8 calendar quarters after the

quarter in which a RATA was last performed. [FNX] The difference between monitor and

reference method mean values applies to moisture monitors, CO2, and O2 monitors, low emitters

of SO2, NOX, or Hg, or and low flow, only. The specifications for Hg monitors also apply

to sorbent trap monitoring systems.[FNY] A NOX concentration monitoring system used to

determine NOX mass emissions under 40 CFR 75.71, incorporated by reference in Section

225.140.

Exhibit C to Appendix B--Conversion Procedures

1. Applicability

Use the procedures in this Exhibit to convert measured data from a monitor or continuous

emission monitoring system into the appropriate units of the standard.

2. Procedures for Heat Input

316

Use the following procedures to compute heat input rate to an affected unit (in mmBtu/hr or

mmBtu/day):

2.1

Calculate and record heat input rate to an affected unit on an hourly basis. The owner or operator

may choose to use the provisions specified in 40 CFR 75.16(e), incorporated by reference in

Section 225.140, in conjunction with the procedures provided in Sections 2.4 through 2.4.2 to

apportion heat input among each unit using the common stack or common pipe header.

2.2

For an affected unit that has a flow monitor (or approved alternate monitoring system under

subpart E of 40 CFR 75, incorporated by reference in Section 225.140, for measuring volumetric

flow rate) and a diluent gas (O

or CO

) monitor, use the recorded data from these monitors and

one of the following equations to calculate hourly heat input rate (in mmBtu/hr).

2.2.1

When measurements of CO

concentration are on a wet basis, use the following equation:

Hourly heat input rate during unit operation, mmBtu/hr.

= Hourly average volumetric flow rate during unit operation, wet basis, scfh.

= Carbon-based F-factor, listed in Section 3.3.5 of appendix F to 40 CFR 75

for each fuel, scf/mmBtu.

= Hourly concentration of CO

during unit operation, percent CO

wet basis.

2.2.2

When measurements of CO

concentration are on a dry basis, use the following equation:

HI Qh

HI = Hourly heat input rate during unit operation, mmBtu/hr.

= Hourly average volumetric flow rate during unit operation, wet basis, scfh.

= Carbon-based F-factor, listed in Section 3.3.5 of appendix F to 40 CFR 75

for each fuel, scf/mmBtu.

= Hourly concentration of CO

during unit operation, percent CO

wet

basis.

= Moisture content of gas in the stack, percent.

2.2.3

When measurements of O

concentration are on a wet basis, use the following equation:

HIQF

Hourly heat input rate during unit operation, mmBtu/hr.

Hourly average volumetric flow rate during unit operation,

wet basis, scfh.

F =

Carbon-based F-factor, listed in Section 3.3.5 of appendix F

to 40 CFR 75 for each fuel, dscf/mmBtu.

= Hourly concentration of O

during unit operation, percent

wet basis.

= Hourly average stack moisture content, percent by volume.

2.2.4

When measurements of O

concentration are on a dry basis, use the following equation:

HI Q

H O

(Equation F-18)

Where:

HI = Hourly heat input rate during unit operation, mmBtu/hr.

= Hourly average volumetric flow during unit operation, wet basis, scfh.

F =

Dry basis F-factor, listed in Section 3.3.5 of appendix F to 40 CFR 75 for

each fuel, dscf/mmBtu.

= Moisture content of the stack gas, percent.

= Hourly concentration of O

during unit operation, percent O

dry basis.

2.3

Heat Input Summation (for Heat Input Determined Using a Flow Monitor and Diluent Monitor)

2.3.1

Calculate total quarterly heat input for a unit or common stack using a flow monitor and diluent

monitor to calculate heat input, using the following equation:

∑

hour

(Equation F-18a)

Where:

= Total heat input for quarter “q”, mmBtu.

= Heat input rate for hour “i” during unit operation, using Equation F-15, F-

16, F-17, or F-18, mmBtu/hr.

Hourly operating time for the unit or common stack, hour or fraction of an

hour (in equal increments that can range from one hundredth to one

quarter of an hour, at the option of the owner or operator).

n =

Number of unit operating hours in the quarter.

2.3.2

319

Calculate total cumulative (year-to-date) heat input for a unit or common stack using a flow

monitor and diluent monitor to calculate heat input, using the following equation:

∑

the current quarter

(Equation F-18b)

Where:

= Total heat input for the quarter,, mmBtu.

= Total heat input for quarter “q”, mmBtu.

2.4 Heat Input Rate Apportionment for Units Sharing a Common Stack or Pipe

2.4.1

Where applicable, the owner or operator of an affected unit that determines heat input rate at the

unit level by apportioning the heat input monitored at a common stack or common pipe using

megawatts must apportion the heat input rate using the following equation:

MW t

Heat input rate for a unit, mmBtu/hr.

Heat input rate at the common stack or pipe, mmBtu/hr.

Gross electrical output, MWe.

Unit operating time, hour or fraction of an hour (in equal increments

that can range from one hundredth to one quarter of an hour, at the

option of the owner or operator).

= Common stack or common pipe operating time, hour or fraction of an

hour (in equal increments that can range from one hundredth to one

quarter of an hour, at the option of the owner or operator).

320

n =

Total number of units using the common stack or pipe.

i =

Designation of a particular unit.

2.4.2

Where applicable, the owner or operator of an affected unit that determines the heat input rate at

the unit level by apportioning the heat input rate monitored at a common stack or common pipe

using steam load must apportion the heat input rate using the following equation:

SF t

= Heat input rate for a unit, mmBtu/hr.

= Heat input rate at the common stack or pipe, mmBtu/hr.

SF = Gross steam load, lb/hr, or mmBtu/hr.

Unit operating time, hour or fraction of an hour (in equal increments that

can range from one hundredth to one quarter of an hour, at the option of

the owner or operator).

= Common stack or common pipe operating time, hour or fraction of an

hour (in equal increments that can range from one hundredth to one

quarter of an hour, at the option of the owner or operator).

n =

Total number of units using the common stack or pipe.

i =

Designation of a particular unit.

2.5 Heat Input Rate Summation for Units with Multiple Stacks or Pipes

The owner or operator of an affected unit that determines the heat input rate at the unit level by

summing the heat input rates monitored at multiple stacks or multiple pipes must sum the heat

input rates using the following equation:

321

Unit

HI t

∑

(Equation F-21c)

Where:

Unit

Heat input rate for a unit, mmBtu/hr.

Heat input rate for the individual stack, duct, or pipe, mmBtu/hr.

Unit

Unit operating time, hour or fraction of the hour (in equal increments

that can range from one hundredth to one quarter of an hour, at the

option of the owner or operator).

Operating time for the individual stack or pipe, hour or fraction of the

hour (in equal increments that can range from one hundredth to one

quarter of an hour, at the option of the owner or operator).

s =

Designation for a particular stack, duct, or pipe.

3. Procedure for Converting Volumetric Flow to STP

Use the following equation to convert volumetric flow at actual temperature and pressure to

standard temperature and pressure.

STP

Actual

(

Std

Stack

)(

Stack

Std

)

(Equation F-22)

Where:

STP

= Flue gas volumetric flow rate at standard temperature and pressure, scfh.

Actual

= Flue gas volumetric flow rate at actual temperature and pressure, acfh.

Std

Standard temperature=528 degreesR.

Stack

= Flue gas temperature at flow monitor location, degreesR, where

degreesR=460+degreesF.

Stack

= The absolute flue gas pressure=barometric pressure at the flow monitor

322

location + flue gas static pressure, inches of mercury.

Std

Standard pressure=29.92 inches of mercury.

4. Procedures for Mercury Mass Emissions.

4.1

Use the procedures in this Section to calculate the hourly mercury mass emissions (in ounces) at

each monitored location for the affected unit or group of units that discharge through a common

stack.

4.1.1

To determine the hourly mercury mass emissions when using a mercury concentration

monitoring system that measures on a wet basis and a flow monitor, use the following equation:

(Equation F-28)

Where:

= Mercury mass emissions for the hour, rounded off to three decimal places,

(ounces).

K =

Units conversion constant, 9.978 x 10

-10

oz-scm/μg-scf

= Hourly mercury concentration, wet basis (μg/wscm).

= Hourly stack gas volumetric flow rate, (scfh)

Unit or stack operating time (hr), as defined in 40 CFR 72.2, incorporated

by reference in Section 225.140.

4.1.2

To determine the hourly mercury mass emissions when using a mercury concentration

monitoring system that measures on a dry basis or a sorbent trap monitoring system and a flow

monitor, use the following equation:

= Mercury mass emissions for the hour, rounded off to three decimal places,

(ounces).

K =

Units conversion constant, 9.978 x 10

-10

oz-scm/μg-scf

= Hourly mercury concentration, dry basis (μg/dscm). For sorbent trap

systems, a single value of

(i.e., a flow-proportional average

concentration for the data collection period), is applied to each hour in the

data collection period, for a particular pair of traps.

= Hourly stack gas volumetric flow rate (scfh).

= Moisture fraction of the stack gas, expressed as a decimal (equal to %H

100)

Unit or stack operating time (hr), as defined in 40 CFR 72.2, incorporated

by reference in Section 225.140.

4.1.3

For units that are demonstrated under Section 1.15(d) of this Appendix to emit less than 464

ounces of mercury per year, and for which the owner or operator elects not to continuously

monitor the mercury concentration, calculate the hourly mercury mass emissions using Equation

F-28 in Section 4.1.1 of this Exhibit, except that "

" will be the applicable default mercury

concentration from Section 1.15(c), (d), or (e) of this Appendix, expressed in μg/scm. Correction

for the stack gas moisture content is not required when this methodology is used.

4.2

Use the following equation to calculate quarterly and year-to-date mercury mass emissions in

time

= Mercury mass emissions for the given time period i.e., quarter or

year-to-date, rounded to the nearest thousandth, (ounces).

324

= Mercury mass emissions for the hour, rounded to three decimal places,

(ounces).

n =

The number of hours in the given time period (quarter or year-to-date).

4.3

If heat input rate monitoring is required, follow the applicable procedures for heat input

apportionment and summation in Sections 2.3, 2.4 and 2.5 of this Exhibit.

5. Moisture Determination From Wet and Dry O

Readings

If a correction for the stack gas moisture content is required in any of the emissions or heat input

calculations described in this Exhibit, and if the hourly moisture content is determined from wet-

and dry-basis O

readings, use Equation F-31 to calculate the percent moisture, unless a "K"

factor or other mathematical algorithm is developed as described in Section 6.5.6(a) of Exhibit A

H O

= Hourly average stack gas moisture content, percent H

Dry-basis hourly average oxygen concentration, percent O

Wet-basis hourly average oxygen concentration, percent O

Exhibit D to Appendix B--Quality Assurance and Operating Procedures for Sorbent Trap

Monitoring Systems

1.0 Scope and Application

This Exhibit specifies sampling, and analytical, and quality-assurance criteria and procedures for

the performance-based monitoring of vapor-phase mercury (Hg) emissions in combustion flue

gas streams, using a sorbent trap monitoring system (as defined in Section 225.130). The

principle employed is continuous sampling using in-stack sorbent media coupled with analysis of

the integrated samples. The performance-based approach of this Exhibit allows for use of various

suitable sampling and analytical technologies while maintaining a specified and documented

level of data quality through performance criteria. Persons using this Exhibit should have a

thorough working knowledge of Methods 1, 2, 3, 4 and 5 in appendices A-1 through A-3 to 40

325

CFR 60, incorporated by reference in Section 225.140, as well as the determinative technique

selected for analysis.

1.1 Analytes

The analyte measured by these procedures and specifications is total vapor-phase mercury in the

flue gas, which represents the sum of elemental mercury (Hg

, CAS Number 7439-97-6) and

oxidized forms of mercury, in mass concentration units of micrograms per dry standard cubic

meter (μg/dscm).

1.2 Applicability

These performance criteria and procedures are applicable to monitoring of vapor-phase mercury

emissions under relatively low-dust conditions (i.e., sampling in the stack after all pollution

control devices), from coal-fired electric utility steam generators which are subject to Sections

1.14 through 1.18 of Appendix B. Individual sample collection times can range from 30 minutes

to several days in duration, depending on the mercury concentration in the stack. The monitoring

system must achieve the performance criteria specified in Section 8 of this Exhibit and the

sorbent media capture ability must not be exceeded. The sampling rate must be maintained at a

constant proportion to the total stack flow rate to ensure representativeness of the sample

collected. Failure to achieve certain performance criteria will result in invalid mercury emissions

monitoring data.

2.0 Principle

Known volumes of flue gas are extracted from a stack or duct through paired, in-stack, pre-

spiked sorbent media traps at an appropriate nominal flow rate. Collection of mercury on the

sorbent media in the stack mitigates potential loss of mercury during transport through a

probe/sample line. Paired train sampling is required to determine measurement precision and

verify acceptability of the measured emissions data.

The sorbent traps are recovered from the sampling system, prepared for analysis, as needed, and

analyzed by any suitable determinative technique that can meet the performance criteria. A

section of each sorbent trap is spiked with Hg

prior to sampling.

3.0 Clean Handling and Contamination

To avoid mercury contamination of the samples, special attention should be paid to cleanliness

during transport, field handling, sampling, recovery, and laboratory analysis, as well as during

preparation of the sorbent cartridges. Collection and analysis of blank samples (field, trip, lab) is

useful in verifying the absence of contaminant mercury.

4.0 Safety

4.1 Site hazards.

326

Site hazards must be thoroughly considered in advance of applying these

procedures/specifications in the field; advance coordination with the site is critical to understand

the conditions and applicable safety policies. At a minimum, portions of the sampling system

will be hot, requiring appropriate gloves, long sleeves, and caution in handling this equipment.

4.2 Laboratory safety policies

Laboratory safety policies should be in place to minimize risk of chemical exposure and to

properly handle waste disposal. Personnel must wear appropriate laboratory attire according to a

Chemical Hygiene Plan established by the laboratory.

4.3 Toxicity or carcinogenicity.

The toxicity or carcinogenicity of any reagents used must be considered. Depending upon the

sampling and analytical technologies selected, this measurement may involve hazardous

materials, operations, and equipment and this Exhibit does not address all of the safety problems

associated with implementing this approach. It is the responsibility of the user to establish

appropriate safety and health practices and determine the applicable regulatory limitations prior

to performance. Any chemical should be regarded as a potential health hazard and exposure to

these compounds should be minimized. Chemists should refer to the Material Safety Data Sheet

(MSDS) for each chemical used.

4.4 Wastes

Any wastes generated by this procedure must be disposed of according to a hazardous materials

management plan that details and tracks various waste streams and disposal procedures.

5.0 Equipment and Supplies

The following list is presented as an example of key equipment and supplies likely required to

perform vapor-phase mercury monitoring using a sorbent trap monitoring system. It is

recognized that additional equipment and supplies may be needed. Collection of paired samples

is required. Also required are a certified stack gas volumetric flow monitor that meets the

requirements of Section 1.2 to this Appendix and an acceptable means of correcting for the stack

gas moisture content, i.e., either by using data from a certified continuous moisture monitoring

system or by using an approved default moisture value (see 40 CFR 75.11(b), incorporated by

reference in Section 225.140).

5.1 Sorbent Trap Monitoring System

A typical sorbent trap monitoring system is shown in Figure K-1. The monitoring system must

include the following components:

5.1.1 Sorbent Traps

The sorbent media used to collect mercury must be configured in a trap with three distinct and

327

identical segments or sections, connected in series, that are amenable to separate analyses.

Section 1 is designated for primary capture of gaseous mercury. Section 2 is designated as a

backup section for determination of vapor-phase mercury breakthrough. Section 3 is designated

for QA/QC purposes where this section must be spiked with a known amount of gaseous Hg

prior to sampling and later analyzed to determine recovery efficiency. The sorbent media may be

any collection material (e.g., carbon, chemically-treated filter, etc.) capable of quantitatively

capturing and recovering for subsequent analysis, all gaseous forms of mercury for the intended

application. Selection of the sorbent media must be based on the material's ability to achieve the

performance criteria contained in Section 8 of this Exhibit as well as the sorbent's vapor-phase

mercury capture efficiency for the emissions matrix and the expected sampling duration at the

test site. The sorbent media must be obtained from a source that can demonstrate the quality

assurance and control necessary to ensure consistent reliability. The paired sorbent traps are

supported on a probe (or probes) and inserted directly into the flue gas stream.

5.1.2 Sampling Probe Assembly

Each probe assembly must have a leak-free Exhibit to the sorbent traps. Each sorbent trap must

be mounted at the entrance of or within the probe such that the gas sampled enters the trap

directly. Each probe/sorbent trap assembly must be heated to a temperature sufficient to prevent

liquid condensation in the sorbent traps. Auxiliary heating is required only where the stack

temperature is too low to prevent condensation. Use a calibrated thermocouple to monitor the

stack temperature. A single probe capable of operating the paired sorbent traps may be used.

Alternatively, individual probe/sorbent trap assemblies may be used, provided that the individual

sorbent traps are co-located to ensure representative mercury monitoring and are sufficiently

separated to prevent aerodynamic interference.

5.1.3 Moisture Removal Device

A robust moisture removal device or system, suitable for continuous duty (such as a Peltier

cooler), must be used to remove water vapor from the gas stream prior to entering the gas flow

meter.

5.1.4 Vacuum Pump

Use a leak-tight, vacuum pump capable of operating within the candidate system's flow range.

5.1.5 Gas Flow Meter

A gas flow meter (such as a dry gas meter, thermal mass flow meter, or other suitable

measurement device) must be used to determine the total sample volume on a dry basis, in units

of standard cubic meters. The meter must be sufficiently accurate to measure the total sample

volume to within 2 percent and must be calibrated at selected flow rates across the range of

sample flow rates at which the sorbent trap monitoring system typically operates. The gas flow

meter must be equipped with any necessary auxiliary measurement devices (e.g., temperature

sensors, pressure measurement devices) needed to correct the sample volume to standard

conditions.

328

5.1.6 Sample Flow Rate Meter and Controller

Use a flow rate indicator and controller for maintaining necessary sampling flow rates.

5.1.7 Temperature Sensor

Same as Section 6.1.1.7 of Method 5 in appendix A-3 to 40 CFR 60, incorporated by reference in

Section 225.140.

5.1.8 Barometer

Same as Section 6.1.2 of Method 5 in appendix A-3 to 40 CFR 60, incorporated by reference in

Section 225.140.

5.1.9 Data Logger (Optional)

Device for recording associated and necessary ancillary information (e.g., temperatures,

pressures, flow, time, etc.).

5.2 Gaseous Hg

Sorbent Trap Spiking System

A known mass of gaseous Hg

must be spiked onto section 3 of each sorbent trap prior to

sampling. Any approach capable of quantitatively delivering known masses of Hg

onto sorbent

traps is acceptable. Several technologies or devices are available to meet this objective. Their

practicality is a function of mercury mass spike levels. For low levels, NIST-certified or NIST-

traceable gas generators or tanks may be suitable, but will likely require long preparation times.

A more practical, alternative system, capable of delivering almost any mass required, makes use

of NIST-certified or NIST-traceable mercury salt solutions (e.g., Hg(NO3)2). With this system,

an aliquot of known volume and concentration is added to a reaction vessel containing a

reducing agent (e.g., stannous chloride); the mercury salt solution is reduced to Hg

and purged

onto section 3 of the sorbent trap using an impinger sparging system.

5.3 Sample Analysis Equipment

Any analytical system capable of quantitatively recovering and quantifying total gaseous

mercury from sorbent media is acceptable provided that the analysis can meet the performance

criteria in Section 8 of this procedure. Candidate recovery techniques include leaching, digestion,

and thermal desorption. Candidate analytical techniques include ultraviolet atomic fluorescence

(UV AF); ultraviolet atomic absorption (UV AA), with and without gold trapping; and in situ X-

ray fluorescence (XRF) analysis.

6.0 Reagents and Standards

Only NIST-certified or NIST-traceable calibration gas standards and reagents must be used for

the tests and procedures required under this Exhibit.

329

7.0 Sample Collection and Transport

7.1 Pre-Test Procedures

7.1.1 Selection of Sampling Site

Sampling site information should be obtained in accordance with Method 1 in appendix A-1 to

40 CFR 60, incorporated by reference in Section 225.140. Identify a monitoring location

representative of source mercury emissions. Locations shown to be free of stratification through

measurement traverses for gases such as SO

and NO

may be one such approach. An estimation

of the expected stack mercury concentration is required to establish a target sample flow rate,

total gas sample volume, and the mass of Hg

to be spiked onto section 3 of each sorbent trap.

7.1.2 Pre-sampling Spiking of Sorbent Traps

Based on the estimated mercury concentration in the stack, the target sample rate and the target

sampling duration, calculate the expected mass loading for section 1 of each sorbent trap (for an

example calculation, see Section 11.1 of this Exhibit). The pre-sampling spike to be added to

section 3 of each sorbent trap must be within ±50 percent of the expected section 1 mass loading.

Spike section 3 of each sorbent trap at this level, as described in Section 5.2 of this Exhibit. For

each sorbent trap, keep an official record of the mass of Hg

added to section 3. This record must

include, at a minimum, the ID number of the trap, the date and time of the spike, the name of the

analyst performing the procedure, the mass of Hg

added to section 3 of the trap (μg), and the

supporting calculations. This record must be maintained in a format suitable for inspection and

audit and must be made available to the regulatory agencies upon request.

7.1.3 Pre-test Leak Check

Perform a leak check with the sorbent traps in place. Draw a vacuum in each sample train.

Adjust the vacuum in the sample train to mercury. Using the gas flow meter, determine leak rate.

The leakage rate must not exceed 4 percent of the target sampling rate. Once the leak check

passes this criterion, carefully release the vacuum in the sample train then seal the sorbent trap

inlet until the probe is ready for insertion into the stack or duct.

7.1.4 Determination of Flue Gas Characteristics

Determine or measure the flue gas measurement environment characteristics (gas temperature,

static pressure, gas velocity, stack moisture, etc.) in order to determine ancillary requirements

such as probe heating requirements (if any), initial sample rate, proportional sampling

conditions, moisture management, etc.

7.2 Sample Collection

7.2.1

330

Remove the plug from the end of each sorbent trap and store each plug in a clean sorbent trap

storage container. Remove the stack or duct port cap and insert the probes. Secure the probes and

ensure that no leakage occurs between the duct and environment.

7.2.2

Record initial data including the sorbent trap ID, start time, starting dry gas meter readings,

initial temperatures, set-points, and any other appropriate information.

7.2.3 Flow Rate Control

Set the initial sample flow rate at the target value from Section 7.1.1 of this Exhibit. Record the

initial gas flow meter reading, stack temperature (if needed to convert to standard conditions),

meter temperatures (if needed), etc. Then, for every operating hour during the sampling period,

record the date and time, the sample flow rate, the gas flow meter reading, the stack temperature

(if needed), the flow meter temperatures (if needed), temperatures of heated equipment such as

the vacuum lines and the probes (if heated), and the sampling system vacuum readings. Also,

record the stack gas flow rate, as measured by the certified flow monitor, and the ratio of the

stack gas flow rate to the sample flow rate. Adjust the sampling flow rate to maintain

proportional sampling, i.e., keep the ratio of the stack gas flow rate to sample flow rate constant,

to within ±25 percent of the reference ratio from the first hour of the data collection period (see

Section 11 of this Exhibit). The sample flow rate through a sorbent trap monitoring system

during any hour (or portion of an hour) in which the unit is not operating must be zero.

7.2.4 Stack Gas Moisture Determination

Determine stack gas moisture using a continuous moisture monitoring system, as described in 40

CFR 75.11(b), incorporated by reference in Section 225.140. Alternatively, the owner or

operator may use the appropriate fuel-specific moisture default value provided in 40 CFR 75.11,

incorporated by reference in Section 225.140, or a site-specific moisture default value approved

by the Agency.

7.2.5 Essential Operating Data

Obtain and record any essential operating data for the facility during the test period, e.g., the

barometric pressure for correcting the sample volume measured by a dry gas meter to standard

conditions. At the end of the data collection period, record the final gas flow meter reading and

the final values of all other essential parameters.

7.2.6 Post Test Leak Check

When sampling is completed, turn off the sample pump, remove the probe/sorbent trap from the

port and carefully re-plug the end of each sorbent trap. Perform a leak check with the sorbent

traps in place, at the maximum vacuum reached during the sampling period. Use the same

general approach described in Section 7.1.3 of this Exhibit. Record the leakage rate and vacuum.

The leakage rate must not exceed 4 percent of the average sampling rate for the data collection

331

period. Following the leak check, carefully release the vacuum in the sample train.

7.2.7 Sample Recovery

Recover each sampled sorbent trap by removing it from the probe, sealing both ends. Wipe any

deposited material from the outside of the sorbent trap. Place the sorbent trap into an appropriate

sample storage container and store/preserve in appropriate manner.

7.2.8 Sample Preservation, Storage, and Transport

While the performance criteria of this approach provide for verification of appropriate sample

handling, it is still important that the user consider, determine, and plan for suitable sample

preservation, storage, transport, and holding times for these measurements. Therefore,

procedures in ASTM D6911-03 "Standard Guide for Packaging and Shipping Environmental

Samples for Laboratory Analysis" (incorporated by reference under Section 225.140) must be

followed for all samples.

7.2.9 Sample Custody

Proper procedures and documentation for sample chain of custody are critical to ensuring data

integrity. The chain of custody procedures in ASTM D4840-99 (reapproved 2004) "Standard

Guide for Sample Chain-of-Custody Procedures" (incorporated by reference under Section

225.140) must be followed for all samples (including field samples and blanks).

8.0 Quality Assurance and Quality Control

Table K-1 summarizes the QA/QC performance criteria that are used to validate the mercury

emissions data from sorbent trap monitoring systems, including the relative accuracy test audit

(RATA) requirement (see Section 1.4(c)(7), Section 6.5.6 of Exhibit A to this Appendix, and

Section 2.3 of Exhibit B to this Appendix). Except as provided in Section 1.3(h) of this

Appendix and as otherwise indicated in Table K-1, failure to achieve these performance criteria

will result in invalidation of mercury emissions data.

Table K-1.--Quality Assurance/Quality Control Criteria for Sorbent Trap

Monitoring Systems

---------------------------------------------------------------------------------------------------------------------

---------------------------------------------------------------------------------------------------------------------

leak check is passed.

the hourly ratios or 5

Sorbent trap section 2

Deviation (RD) if the

average concentration

is > 1.0<<mu>>g/m

≤ 20% RD if the

average concentration

≤ 1.0<<mu>>

g/m

Results are also

acceptable if absolute

Either invalidate the

data from the paired

traps or report the

results from the trap

with the higher Hg

concentration.

Spike Recovery Study Average recovery

between 85% and

115% for each of the

3 spike concentration

not be analyzed until

the percent recovery

criteria has been met

Multipoint analyzer

calibration

Each analyzer reading

analyzing any samples

calibration, prior to

analyzing field

samples

Recalibrate and repeat

For initial certification

and annually

thereafter

Data from the system

are invalidated until a

RATA is passed.

Gas flow meter

calibration

Calibration factor (Y)

At three settings prior

to initial use and at

least quarterly at one

setting thereafter. For

mass flow meters,

initial calibration with

stack gas is required

Recalibrate the meter

at three orifice

settings to determine a

Prior to initial use and

at least quarterly

thereafter

Recalibrate. Sensor

may not be used until

specification is met.

Barometer calibration Absolute pressure

Prior to initial use and

at least quarterly

thereafter

Recalibrate.

Instrument may not be

used until

specification is met.

-------------------------------------------------------------------------------

[FN**] Note: If both traps fail to meet the acceptance criteria, the data from the pair of traps are

invalidated. However, if only one of the paired traps fails to meet this particular acceptance

criterion and the other sample meets all of the applicable QA criteria, the results of the valid trap

may be used for reporting under this part. When the data from both traps are invalidated and

quality-assured data from a certified backup monitoring system, reference method, or approved

alternative monitoring system are unavailable, missing data substitution must be used.

9.0 Calibration and Standardization.

9.1

Only NIST-certified and NIST-traceable calibration standards (i.e., calibration gases, solutions,

etc.) must be used for the spiking and analytical procedures in this Exhibit.

9.2 Gas Flow Meter Calibration

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9.2.1

Preliminaries. The manufacturer or supplier of the gas flow meter should perform all necessary

set-up, testing, programming, etc., and should provide the end user with any necessary

instructions, to ensure that the meter will give an accurate readout of dry gas volume in standard

cubic meters for the particular field application.

9.2.2

Initial Calibration. Prior to its initial use, a calibration of the flow meter must be performed. The

initial calibration may be done by the manufacturer, by the equipment supplier, or by the end

user. If the flow meter is volumetric in nature (e.g., a dry gas meter), the manufacturer,

equipment supplier, or end user may perform a direct volumetric calibration using any gas. For a

mass flow meter, the manufacturer, equipment supplier, or end user may calibrate the meter

using a bottled gas mixture containing 12 +- 0.5% CO

, 7 +- 0.5% O

, and balance N

, or these

same gases in proportions more representative of the expected stack gas composition. Mass flow

meters may also be initially calibrated on-site, using actual stack gas.

9.2.2.1

Initial Calibration Procedures. Determine an average calibration factor (Y) for the gas flow

meter, by calibrating it at three sample flow rate settings covering the range of sample flow rates

at which the sorbent trap monitoring system typically operates. You may either follow the

procedures in Section 10.3.1 of Method 5 in appendix A-3 to 40 CFR 60, incorporated by

reference in Section 225.140, or the procedures in Section 16 of Method 5 in appendix A-3 to 40

CFR 60. If a dry gas meter is being calibrated, use at least five revolutions of the meter at each

flow rate.

9.2.2.2

Alternative Initial Calibration Procedures. Alternatively, you may perform the initial calibration

of the gas flow meter using a reference gas flow meter (RGFM). The RGFM may either be: (1)

A wet test meter calibrated according to Section 10.3.1 of Method 5 in appendix A-3 to 40 CFR

60, incorporated by reference in Section 225.140; (2) a gas flow metering device calibrated at

multiple flow rates using the procedures in Section 16 of Method 5 in appendix A-3 to 40 CFR

60; or (3) a NIST-traceable calibration device capable of measuring volumetric flow to an

accuracy of 1 percent. To calibrate the gas flow meter using the RGFM, proceed as follows:

While the sorbent trap monitoring system is sampling the actual stack gas or a compressed gas

mixture that simulates the stack gas composition (as applicable), connect the RGFM to the

discharge of the system. Care should be taken to minimize the dead volume between the sample

flow meter being tested and the RGFM. Concurrently measure dry gas volume with the RGFM

and the flow meter being calibrated the for a minimum of 10 minutes at each of three flow rates

covering the typical range of operation of the sorbent trap monitoring system. For each 10-

minute (or longer) data collection period, record the total sample volume, in units of dry standard

cubic meters (dscm), measured by the RGFM and the gas flow meter being tested.

335

9.2.2.3

Initial Calibration Factor. Calculate an individual calibration factor Yi at each tested flow rate

from Section 9.2.2.1 or 9.2.2.2 of this Exhibit (as applicable), by taking the ratio of the reference

sample volume to the sample volume recorded by the gas flow meter. Average the three Yi

values, to determine Y, the calibration factor for the flow meter. Each of the three individual

values of Yi must be within ±0.02 of Y. Except as otherwise provided in Sections 9.2.2.4 and

9.2.2.5 of this Exhibit, use the average Y value from the three level calibration to adjust all

subsequent gas volume measurements made with the gas flow meter.

9.2.2.4

Initial On-Site Calibration Check. For a mass flow meter that was initially calibrated using a

compressed gas mixture, an on-site calibration check must be performed before using the flow

meter to provide data for this part. While sampling stack gas, check the calibration of the flow

meter at one intermediate flow rate typical of normal operation of the monitoring system. Follow

the basic procedures in Section 9.2.2.1 or 9.2.2.2 of this Exhibit. If the on-site calibration check

shows that the value of Yi, the calibration factor at the tested flow rate, differs by more than 5

percent from the value of Y obtained in the initial calibration of the meter, repeat the full 3-level

calibration of the meter using stack gas to determine a new value of Y, and apply the new Y

value to all subsequent gas volume measurements made with the gas flow meter.

9.2.2.5

Ongoing Quality Assurance. Recalibrate the gas flow meter quarterly at one intermediate flow

rate setting representative of normal operation of the monitoring system. Follow the basic

procedures in Section 9.2.2.1 or 9.2.2.2 of this Exhibit. If a quarterly recalibration shows that the

value of Yi, the calibration factor at the tested flow rate, differs from the current value of Y by

more than 5 percent, repeat the full 3-level calibration of the meter to determine a new value of

Y, and apply the new Y value to all subsequent gas volume measurements made with the gas

flow meter.

9.3 Thermocouples and Other Temperature Sensors

Use the procedures and criteria in Section 10.3 of Method 2 in appendix A-1 to 40 CFR 60,

incorporated by reference in Section 225.140, to calibrate in-stack temperature sensors and

thermocouples. Dial thermometers must be calibrated against mercury-in-glass thermometers.

Calibrations must be performed prior to initial use and at least quarterly thereafter. At each

calibration point, the absolute temperature measured by the temperature sensor must agree to

within +- 1.5 percent of the temperature measured with the reference sensor, otherwise the sensor

may not continue to be used.

9.4 Barometer

Calibrate against a mercury barometer. Calibration must be performed prior to initial use and at

336

least quarterly thereafter. At each calibration point, the absolute pressure measured by the

barometer must agree to within ±10 mm mercury of the pressure measured by the mercury

barometer, otherwise the barometer may not continue to be used.

9.5 Other Sensors and Gauges

Calibrate all other sensors and gauges according to the procedures specified by the instrument

manufacturers.

9.6 Analytical System Calibration

See Section 10.1 of this Exhibit.

10.0 Analytical Procedures

The analysis of the mercury samples may be conducted using any instrument or technology

capable of quantifying total mercury from the sorbent media and meeting the performance

criteria in Section 8 of this Exhibit.

10.1 Analyzer System Calibration

Perform a multipoint calibration of the analyzer at three or more upscale points over the desired

quantitative range (multiple calibration ranges must be calibrated, if necessary). The field

samples analyzed must fall within a calibrated, quantitative range and meet the necessary

performance criteria. For samples that are suitable for aliquotting, a series of dilutions may be

needed to ensure that the samples fall within a calibrated range. However, for sorbent media

samples that are consumed during analysis (e.g., thermal desorption techniques), extra care must

be taken to ensure that the analytical system is appropriately calibrated prior to sample analysis.

The calibration curve ranges should be determined based on the anticipated level of mercury

mass on the sorbent media. Knowledge of estimated stack mercury concentrations and total

sample volume may be required prior to analysis. The calibration curve for use with the various

analytical techniques (e.g., UV AA, UV AF, and XRF) can be generated by directly introducing

standard solutions into the analyzer or by spiking the standards onto the sorbent media and then

introducing into the analyzer after preparing the sorbent/standard according to the particular

analytical technique. For each calibration curve, the value of the square of the linear correlation

coefficient, i.e., r

, must be

≥ 0.99, and the anamlusyt zbe ewir

thi

n ±e10

speponsrcent

reference value at each upscale calibration point. Calibrations must be performed on the day of

the analysis, before analyzing any of the samples. Following calibration, an independently

prepared standard (not from same calibration stock solution) must be analyzed. The measured

value of the independently prepared standard must be within ±10 percent of the expected value.

10.2 Sample Preparation

Carefully separate the three sections of each sorbent trap. Combine for analysis all materials

associated with each section, i.e., any supporting substrate that the sample gas passes through

prior to entering a media section (e.g., glass wool, polyurethane foam, etc.) must be analyzed

337

with that segment.

10.3 Spike Recovery Study

Before analyzing any field samples, the laboratory must demonstrate the ability to recover and

quantify mercury from the sorbent media by performing the following spike recovery study for

sorbent media traps spiked with elemental mercury.

Using the procedures described in Sections 5.2 and 11.1 of this Exhibit, spike the third section of

nine sorbent traps with gaseous Hg

, i.e., three traps at each of three different mass loadings,

representing the range of masses anticipated in the field samples. This will yield a 3 x 3 sample

matrix. Prepare and analyze the third section of each spiked trap, using the techniques that will

be used to prepare and analyze the field samples. The average recovery for each spike

concentration must be between 85 and 115 percent. If multiple types of sorbent media are to be

analyzed, a separate spike recovery study is required for each sorbent material. If multiple ranges

are calibrated, a separate spike recovery study is required for each range.

10.4 Field Sample Analysis

Analyze the sorbent trap samples following the same procedures that were used for conducting

the spike recovery study. The three sections of each sorbent trap must be analyzed separately

(i.e., section 1, then section 2, then section 3). Quantify the total mass of mercury for each

section based on analytical system response and the calibration curve from Section 10.1 of this

Exhibit. Determine the spike recovery from sorbent trap section 3. The spike recovery must be

no less than 75 percent and no greater than 125 percent. To report the final mercury mass for

each trap, add together the mercury masses collected in trap sections 1 and 2.

11.0 Calculations and Data Analysis

11.1 Calculation of Pre-Sampling Spiking Level

Determine sorbent trap section 3 spiking level using estimates of the stack mercury

concentration, the target sample flow rate, and the expected sample duration. First, calculate the

expected mercury mass that will be collected in section 1 of the trap. The pre-sampling spike

must be within ±50 percent of this mass. Example calculation: For an estimated stack mercury

concentration of 5 μg/m

, a target sample rate of 0.30 L/min, and a sample duration of 5 days:

(0.30 L/min) (1440 min/day) (5 days) (10

-3

/liter) (5μg/m

) = 10.8 μg

A pre-sampling spike of 10.8 μg ± 50 percent is, therefore, appropriate.

11.2 Calculations for Flow-Proportional Sampling.

For the first hour of the data collection period, determine the reference ratio of the stack gas

volumetric flow rate to the sample flow rate, as follows:

338

ref

(Equation K-1)

Where:

ref

= Reference ratio of hourly stack gas flow rate to hourly sample flow rate

ref

= Average stack gas volumetric flow rate for first hour of collection period

ref

= Average sample flow rate for first hour of the collection period, in appropriate

units (e.g., liters/min, cc/min, dscm/min)

K =

Power of ten multiplier, to keep the value of

ref

between 1 and 100. The

appropriate K value will depend on the selected units of measure for the sample

flow rate.

Then, for each subsequent hour of the data collection period, calculate ratio of the stack gas flow

rate to the sample flow rate using the equation K-2:

(Equation K-2)

Where:

= Ratio of hourly stack gas flow rate to hourly sample flow rate

= Average stack gas volumetric flow rate for the hour

= Average sample flow rate for the hour, in appropriate units (e.g., liters/min,

cc/min, dscm/min)

K =

Power of ten multiplier, to keep the value of

between 1 and 100. The

appropriate K value will depend on the selected units of measure for the sample

flow rate and the range of expected stack gas flow rates.

Maintain the value of

within +- 25 percent of

ref

throughout the data collection period.

11.3 Calculation of Spike Recovery.

Calculate the percent recovery of each section 3 spike, as follows:

= Percentage recovery of the pre-sampling spike

= Mass of mercury recovered from section 3 of the sorbent trap, (μg)

= Calculated mercury mass of the pre-sampling spike, from Section 7.1.2 of this

Exhibit, (μg)

11.4 Calculation of Breakthrough.

Calculate the percent breakthrough to the second section of the sorbent trap, as follows:

Mass of mercury recovered from section 2 of the sorbent trap, (μg)

Mass of mercury recovered from section 1 of the sorbent trap, (μg)

11.5 Calculation of Mercury Concentration

Calculate the mercury concentration for each sorbent trap, using the following equation:

(Equation K-5)

Where:

C =

Concentration of mercury for the collection period, μgm/dscm)

340

Total mass of mercury recovered from sections 1 and 2 of the sorbent trap, μg)

Total volume of dry gas metered during the collection period, (dscm). For the

purposes of this Exhibit, standard temperature and pressure are defined as 20 °

C and 760 mm mercury, respectively.

11.6 Calculation of Paired Trap Agreement

Calculate the relative deviation (RD) between the mercury concentrations measured with the

paired sorbent traps:

Relative deviation between the mercury concentrations from traps "a" and "b"

(percent)

Concentration of mercury for the collection period, for sorbent trap "a"

(μgm/dscm)

Concentration of mercury for the collection period, for sorbent trap "b"

(μgm/dscm)

11.7 Calculation of Mercury Mass Emissions

To calculate mercury mass emissions, follow the procedures in Section 4.1.2 of Exhibit C to this

Appendix. Use the average of the two mercury concentrations from the paired traps in the

calculations, except as provided in Section 1.3(h) of Exhibit A to this Appendix or in Table K-1.

12.0 Method Performance

These monitoring criteria and procedures have been applied to coal-fired utility boilers

(including units with post-combustion emission controls), having vapor-phase mercury

concentrations ranging from 0.03 μg/dscm to 100 μg/dscm.

IT IS SO ORDERED.

341

I, John T. Therriault, Assistant Clerk of the Illinois Pollution Control Board, certify that

the Board adopted the above opinion and order on April 16, 2009, by a vote of 5-0.

___________________________________

John T. Therriault, Assistant Clerk

Illinois Pollution Control Board