1
1 BEFORE THE ILLINOIS POLLUTION CONTROL BOARD
2
3 IN THE MATTER OF: )
4 )
5 PROPOSED AMENDMENTS TO 35 ILL. ) R-01-16
6 ADM CODE 217, SUBPART V, )
7 ELECTRIC POWER GENERATION. )
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12 The following is a transcript of the
13 above-entitled cause taken before TERRY A. STRONER,
14 CSR, a notary public within and for the County of
15 Cook and State of Illinois before HEARING OFFICER
16 BOBB BEAUCHAMP, at Room 9-040, 100 West Randolph
17 Street, Chicago, Illinois, on the 28th day of
18 November, A.D., 2000, commencing at 11:10 o'clock
19 a.m.
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L.A. REPORTING (312) 419-9292
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1 A P P E A R A N C E S:
2 ILLINOIS POLLUTION CONTROL BOARD,
100 West Randolph Street
3 Suite 11-500
Chicago, Illinois 60601
4 (312) 814-6926
BY: BOBB BEAUCHAMP, HEARING OFFICER
5
6 POLLUTION CONTROL BOARD MEMBERS:
Marili McFawn, Dr. Ronald Flemal, Kathy Glenn,
7 Alicia Liu, Joel Sternstein
8 ILLINOIS ENVIRONMENTAL PROTECTION AGENCY:
Vera Herst, Robert Sharpe, Robert Kaleel,
9 Dennis Lawler, Yoginder Mahajan, Berkley Moore,
10 Christopher Romaine, Laurel Kroack
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12 OTHERS WERE PRESENT BUT NOT LISTED ON THIS
13 APPEARANCE PAGE.
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L.A. REPORTING (312) 419-9292
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1 THE WITNESSES:
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3 TESTIMONY OF DENNIS LAWLER............. 14-32
4 TESTIMONY OF ROBERT KALEEL............. 32-53
5 TESTIMONY OF BERKLEY MOORE............. 54-62
6 TESTIMONY OF YOGINDER MAHAJAN.......... 63-79
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L.A. REPORTING (312) 419-9292
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1 HEARING OFFICER BEAUCHAMP: Good morning. My
2 name is Bob Beauchamp and I'm the hearing officer in
3 this proceeding. I'd like to welcome you to this
4 hearing being held by the Illinois Pollution Control
5 Board in the matter of Proposed Amendments to 35
6 Illinois Administrative Code 217, Subpart V,
7 Electric Power Generation.
8 Today's hearing is the first day of the
9 first of three scheduled hearings in this
10 rulemaking. Present today on behalf of the Illinois
11 Pollution Control Board and seated to my right is
12 Board member Marili McFawn, the Board member
13 coordinating this rulemaking and on my left is Board
14 member Dr. Ronald Flemal. Also, present today are
15 several members of the Board's staff starting with
16 Dr. Flemal's left is Kathy Glenn, Dr. Flemal's
17 assistant, starting from Board member McFawn's right
18 we have Alicia Liu of the Board's technical staff
19 and on her right Joel Sternstein, attorney assistant
20 to Board member Nicholas Melas.
21 We have placed copies of the notice and
22 service list sign-up sheets in addition to current
23 copies of the notice and service lists by the table
24 by the entrance. Please note that if your name is
L.A. REPORTING (312) 419-9292
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1 on the notice list you will only receive copies of
2 the Board's opinions and orders and all hearing
3 officer orders. If your name is on the service list
4 not only will you receive copies of the Board's
5 opinions and orders and all hearing officer orders,
6 but you will also receive copies of all documents
7 filed by all persons in this proceeding. However,
8 also keep in mind that if your name is on the
9 service list, you are also required to serve all
10 persons on the service list with all documents you
11 file with the Board.
12 Copies of the Board's October 19th, 2000,
13 opinion and order containing the proposed rule and
14 the October 27th, 2000, hearing officer order are
15 also located by that table. In addition, you will
16 also find copies of the Agency's prefiled testimony
17 there.
18 On October 16th of 2000, the Illinois
19 Pollution -- excuse me, the Illinois Environmental
20 Protection Agency filed this proposal for a
21 rulemaking to amend 35 Illinois Administrative Code,
22 Part 217, Subpart V, Electric Power Generation.
23 On October 19th of 2000, the Board adopted
24 the first notice of the Agency's proposal. This
L.A. REPORTING (312) 419-9292
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1 proposal was published in the Illinois Register on
2 November 3rd, 2000, at page 16,200. This proposal
3 was filed pursuant to Section 28.5 of the
4 Environmental Protection Act entitled Clean Air Act
5 Rules Fastrack. Pursuant to Subsection (g) of that
6 section, the Board is required to proceed within set
7 time frames for the adoption of this regulation. As
8 stated in the Board's October 19th, 2000, opinion,
9 the Board has no discretion to adjust these time
10 frames under any circumstances.
11 Pursuant to Section 28.5 of the act, the
12 Board scheduled three hearings. As announced in the
13 October 27th of 2000 hearing officer order today's
14 hearing is confined to testimony by the Agency
15 witnesses concerning the scope, applicability and
16 basis of the rule. Pursuant to Section 28.5, this
17 hearing will begin today and continue on the record
18 from day-to-day if necessary until completed.
19 The second hearing is currently scheduled
20 for Tuesday, December 19th, 2000, at 11 a.m. in Room
21 9-040 of the James R. Thompson Center in Chicago.
22 That's this room that we're sitting in. It will be
23 devoted to economic impact considerations and
24 presentation of testimony, documents and comments by
L.A. REPORTING (312) 419-9292
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1 affected entities and all other interested parties.
2 Prefiling deadlines for the second hearing may be
3 found on the October 27th, 2000, hearing officer
4 order.
5 The third hearing currently is scheduled
6 for Tuesday, January 2nd, 2001, at 11 a.m. in Room
7 9-040 of the James R. Thompson Center, again, here
8 in Chicago. It will be devoted solely to any Agency
9 response to the material submitted at the second
10 hearing. The third hearing will be canceled if the
11 Agency indicates to the Board that it does not
12 intend to introduce any additional material. If the
13 third hearing is canceled, all persons listed on the
14 notice list will be so advised through a hearing
15 officer order.
16 As stated in the October 19th, 2000,
17 opinion, the Board is holding today's hearing
18 consecutively with the hearings in Docket No. R01-17
19 in the matter of Proposed New 35 Illinois
20 Administrative Code 217, Subpart U, NOx Control and
21 Trading Program for Specified NOx Generating Units,
22 Subpart X, Voluntary NOx Emissions Reduction Program
23 and Amendments to 35 Illinois Administrative Code
24 211.
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1 The hearing in R01-17 is scheduled to
2 begin at 9:30 tomorrow in this room. In the event
3 that today's hearing carries over into tomorrow, the
4 hearing for R01-17 will begin at the conclusion of
5 this hearing. However, we do not anticipate that
6 today's hearing will require more than this
7 afternoon to complete.
8 Today's hearing will be governed by the
9 Board's procedural rules for regulatory proceedings.
10 All information which is relevant and not repetition
11 or privileged will be admitted. All witnesses will
12 be sworn and subject to cross questioning.
13 Again, the purpose of today's hearing is
14 to allow the Agency to present testimony in support
15 of this proposal and to allow questioning of the
16 Agency. The Agency will present any testimony it
17 may have regarding this proposal.
18 At the conclusion of the Agency's
19 testimony, we will allow for questioning of the
20 Agency regarding its testimony. I would prefer that
21 during the questioning period any person wishing to
22 ask a question would raise their hand and wait for
23 me to acknowledge you. Once I have recognized you,
24 if you could please state your name and the
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1 organization you represent, if any, before
2 proceeding with your question.
3 Are there any questions regarding the
4 procedure we will follow this afternoon? All right.
5 Seeing none, I'd like to go off the record for a
6 moment and discuss our break schedule and when we're
7 going to break for lunch, if we may.
8 (Whereupon, a discussion
9 was had off the record.)
10 HEARING OFFICER BEAUCHAMP: While off the
11 record we just discussed our lunch plans. We're
12 going to try to press through with the Agency
13 testimony and complete that before we break for
14 lunch and possibly reconvene this afternoon if we
15 need to.
16 At this time I'd like to ask Board member
17 McFawn if she has anything else she would like to
18 add to my comments?
19 MS. McFAWN: Just a few comments. I would like
20 to thank the Agency for bringing such a wonderful
21 panel to this hearing. It's a great collection of
22 their Bureau of Air and we have a pretty large task
23 in front of us. We have two rulemakings, not one,
24 and we are discussing three subparts, not one, and
L.A. REPORTING (312) 419-9292
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1 we hope to do so in the next three days and then
2 another set of hearings of three days and a third
3 hearing in January if need be. So we are doing
4 things in sets of three, aren't we?
5 With your help and through questions from
6 the participants in this rulemaking here in the
7 audience with us, I hope that we can make a clear
8 record as to how these three subparts will work in
9 the Board's air rule regulations as they stand alone
10 and also in the context of the current -- the NOx
11 rules that are currently at second notice, that
12 would be R01-9, which was sent a second notice under
13 the direction of Dr. Flemal just last Board meeting,
14 and we also have pending before the Board another
15 NOx rulemaking having to do with cement kilns and
16 that is under direction of member Melas and that is
17 currently only at first notice, but it is my hope
18 that we can make clear on the record how all these
19 NOx rules work individually and collectively. With
20 your help, I'm sure we can do that. Thank you again
21 for coming. In advance I want to thank you because
22 I know it will be a hard set of hearings.
23 HEARING OFFICER BEAUCHAMP: Thank you, Board
24 member McFawn. At this time, Ms. Herst, do you have
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1 an opening statement?
2 MS. HERST: Yes, I do. I'd like to say good
3 morning to everyone --
4 MS. McFAWN: Good morning.
5 MS. HERST: -- hearing officer, the Board,
6 regulating committee, we're pleased to see everyone
7 here today. A slightly smaller group than for
8 Subpart W, which is also fine. I'd like to
9 introduce myself and the representatives of the
10 Agency here today. I'm Vera Herst, assistant
11 counsel in the division of legal counsel, to my left
12 is Dennis Lawler, who is manager of the division of
13 air pollution control, to his left is Robert Kaleel,
14 who is manager of the air quality modeling unit, and
15 to Mr. Kaleel's left is Yoginder Mahajan, who is in
16 the air quality planning section and then to my
17 right is Robert Sharpe, deputy counsel, Bureau of
18 Air, to his right is Berkley Moore, who is in the
19 air quality planning section, Christopher Romaine,
20 who is manager of the utilities unit in the permit
21 section who is sitting kind of behind me and the
22 other person trying to hide in the back is
23 Mr. Forbes, who is manager of the ozone regulatory
24 unit.
L.A. REPORTING (312) 419-9292
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1 As Hearing Officer Beauchamp stated, the
2 Agency is proposing amendments to Subpart V of 35
3 Illinois Administrative Code, Part 217. These
4 amendments are proposed to control the emissions of
5 nitrogen oxides or NOx as we will refer throughout
6 this proceeding and they will control -- proposed to
7 control the emissions during the control period of
8 May 1st through September 30th of each year
9 beginning in 2003. The proposed amendments are
10 intended to meet Illinois' obligation under the
11 Clean Air Act to submit control strategies necessary
12 to demonstrate attainment in the one-hour ozone
13 standard ozone of National Ambient Air Quality
14 Standards for the Metro-East/St. Louis moderate
15 ozone nonattainment area. These proposed amendments
16 are also intended to address concerns related to
17 litigation that could result in a bump up of the
18 Metro-East/St. Louis area from a moderate to a
19 serious nonattainment area.
20 And at this time I would like to submit
21 the prefiled testimony of Mr. Lawler and Mr. Kaleel
22 into the record as if read.
23 HEARING OFFICER BEAUCHAMP: Thank you.
24 MS. HERST: They will be presenting truncated
L.A. REPORTING (312) 419-9292
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1 versions of their testimony and will also be using
2 overheads and at the end of their testimony I will
3 submit copies of their overheads into the record.
4 Mr. Moore and Mr. Mahajan will be reading
5 their testimony into the record. I have provided
6 copies of the overheads to Board members, Hearing
7 Officer Beauchamp and the court reporter. There are
8 additional copies of the testimony and overheads
9 available on the table to the audience's left.
10 Mr. Romaine and Mr. Forbes will not be
11 testifying, but will be available to answer
12 questions during the comment and question period as
13 appropriate. With that, I turn the proceedings back
14 to you, Mr. Beauchamp.
15 HEARING OFFICER BEAUCHAMP: Thank you,
16 Ms. Herst. You move to admit the prefiled testimony
17 of Mr. Kaleel and Mr. Lawler into the record so we
18 will mark the testimony of Mr. Kaleel as Exhibit 1
19 and the testimony of Mr. Lawler as Exhibit 2. We'd
20 also like to mark the copies of the overheads that
21 you submitted as 1A and 2A so that when we refer to
22 them during your presentations and admit them into
23 the record.
24 MS. McFAWN: So that would mean the one
L.A. REPORTING (312) 419-9292
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1 entitled One-Hour Ozone Attainment Demonstration
2 St. Louis Nonattainment Area by Rob Kaleel dated
3 November 28th, 2000, would be marked as Exhibit 1A
4 and EGU Rulemaking Proposal by Dennis Lawler would
5 be marked as Exhibit 2A?
6 HEARING OFFICER BEAUCHAMP: 2A.
7 MS. McFAWN: Thank you.
8 HEARING OFFICER BEAUCHAMP: Very good. At this
9 time I ask the Agency if you'd like to offer any
10 testimony then?
11 MS. HERST: Mr. Lawler will begin.
12 HEARING OFFICER BEAUCHAMP: You may begin after
13 you're all sworn in. We will have the court
14 reporter swear the witnesses in as a panel.
15 THE REPORTER: Do you all swear to tell the
16 truth, the whole truth and nothing but the truth so
17 help you God?
18 THE WITNESSES: We do.
19 HEARING OFFICER BEAUCHAMP: Very good.
20 Mr. Lawler, proceed with your testimony, please.
21 MR. LAWLER: Good morning. I've done a series
22 of overheads that I'm going to use this morning and
23 they're also available back on the table for
24 everybody to get a copy of. A lot of these folks
L.A. REPORTING (312) 419-9292
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1 have already been at earlier hearings, there's
2 familiar faces on the Board side and familiar faces
3 in the crowd so a few things I'm not going to spend
4 much detail on. There's a few things that are
5 unique to this particular rulemaking that I'll spend
6 a little bit more time, but I'll try to go through
7 it all in a fairly succinct fashion.
8 The purpose of my testimony this morning
9 is to explain the purpose of the rulemaking itself
10 and then to give you a little bit of detail on the
11 development of the proposal. There is a lot of
12 background in all this, but I'm going to try to
13 summarize it just as much as possible in going
14 through this.
15 It also would be probably good to mention
16 that EGU that -- for those of you that haven't been
17 at earlier hearings or involved in any of the
18 processes the last couple of years stands for
19 electrical generating unit. Generally, it's
20 associated with electric utilities. NOx that you
21 already heard this morning, nitrogen oxides, you
22 will hear the term used and as we go through the
23 rest of it we'll try to define the terms that you
24 may hear during the rulemaking. You'll also hear us
L.A. REPORTING (312) 419-9292
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1 refer to this as Subpart V and it might be worth
2 just taking a second to mention, Subpart W is the
3 rulemaking that -- you'll hear us refer to Subpart W
4 and that's the rulemaking that had to do with the --
5 the other rulemaking that had to do with utilities,
6 that's at second notice now. Subpart T, that's the
7 Subpart that deals with cement kilns and Subparts U
8 and X and they're the ones that address the
9 non-EGUs, nonutility components of the NOx SIP Call
10 and again, I'll just mention those now and you'll
11 probably hear us use those terms for the next hour
12 or so as we talk about things.
13 The purpose of this rulemaking is to
14 satisfy the obligations of the state to submit the
15 control strategies to demonstrate ozone attainment
16 for the Metro-East area.
17 The second purpose is to address concerns
18 relating to a potential bump up of the Metro-East
19 area because of a lawsuit that was filed in the U.S.
20 District Court for the District of Columbia. The
21 state's intent -- initially, we had intended --
22 MR. RIESER: Excuse me, Mr. Lawler.
23 MR. LAWLER: Yes.
24 MR. RIESER: Mr. Lawler, Mr. Hearing Officer, I
L.A. REPORTING (312) 419-9292
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1 notice this issue come up in the Subpart W in the
2 hearing. It will be useful if the witnesses -- I
3 think for purpose of the record the witnesses could
4 refer to the fact that they're changing slides --
5 MR. LAWLER: Oh, good point.
6 MR. RIESER: -- and either identify the heading
7 of the slide or the number of the slide or something
8 so that somebody following the transcript and
9 looking at the exhibit will know which slide they're
10 referring to as part of their presentation. I don't
11 mean to burden the presentation, but it's easier
12 when you're looking at the transcript.
13 MR. LAWLER: No, that's no burden. That's a
14 good point.
15 MS. McFAWN: Mr. Rieser, could you identify
16 yourself for the record?
17 MR. RIESER: Mr. Rieser with the law firm of
18 Ross & Hardies and I'm here on behalf of Ameren
19 Corporation.
20 MS. McFAWN: Thank you.
21 MR. LAWLER: This particular chart is the third
22 one in Exhibit 2A and it's entitled State Intent for
23 Metro-East. Again, on this one -- at this point we
24 have intended to address attainment for Metro-East
L.A. REPORTING (312) 419-9292
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1 through the NOx SIP Call portion rulemaking that
2 dealt with EGUs and this is the rulemaking that we
3 would call Subpart W. This was submitted to the
4 Board last July and is going through the process
5 right now.
6 In late August -- on August 30th, the U.S.
7 Court of Appeals, D.C. Circuit, changed the SIP Call
8 date -- the effective date of the SIP Call or the
9 compliance date from 2004 -- from 2003 to 2004 and
10 because that was done, we now need Subpart W to
11 address this change that was brought about by a
12 Court decision.
13 MS. McFAWN: Mr. Lawler, did you mean Subpart V
14 or Subpart W?
15 MR. LAWLER: Subpart V is the last one I
16 referred to. Did I say subpart W?
17 MS. McFAWN: That's fine. Thank you.
18 Also, can I ask you a question, when you
19 refer to the court case in the D.C. Circuit, are you
20 referring to Michigan versus EPA as it's commonly
21 referred to?
22 MR. LAWLER: Yes.
23 MS. McFAWN: Thank you.
24 MR. LAWLER: The next overhead is entitled the
L.A. REPORTING (312) 419-9292
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1 Two EGUs Rulemakings and it's intended to help
2 people to distinguish between Subpart W rulemaking
3 and this Subpart V rulemaking.
4 First of all, Subpart W is a NOx trading
5 program for EGUs and is generally considered to be
6 one that will be multi-state in nature. It has a
7 state NOx budget in it and the budget is based on a
8 limit of .15 pounds per million BTU applied to all
9 the BTUs, but it is a state-wide budget. It's based
10 on the NOx SIP Call -- the requirements of the NOx
11 SIP Call and intended to meet the requirements of
12 the NOx SIP Call and the compliance date for Subpart
13 W is now May 31st, 2004.
14 Subpart V, which is the subject of this
15 particular rulemaking, is a rate-based rule for EGUs
16 and that rate-based limit is .25 pounds per million
17 BTU and it has state-wide applicability. It's also
18 to address attainment, as I mentioned earlier, and
19 address the bump up possibility in the Metro-East
20 and the compliance date is May 1st, 2003.
21 So that's kind of the overall purpose for
22 this particular rulemaking. I think this will help.
23 You have copies of these overheads. This particular
24 one is entitled Ozone Formation Process and it's
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1 here to illustrate that ozone is formed through a
2 chemical process that involves generally nitrogen
3 oxide emissions and volatile organic materials.
4 When those materials are heated like in the
5 summertime on very hot days, you get ozone formation
6 and the sources of emissions for those particular
7 materials are industrial sources, mobile source, the
8 common cars that everybody has, and normal products
9 that we use around the house. A lot of those also
10 emit VOCs. Also, it's worth mentioning that you'll
11 hear us use the term VOCs and VOMs sort of
12 interchangeably. VOCs are volatile organic
13 compounds. VOM is volatile organic materials and
14 again we end up using the terms pretty much
15 interchangeably.
16 I always have to put this chart here for
17 anyone who isn't aware of this, the good ozone and
18 the bad ozone. It's the same ozone that's in the
19 stratosphere that protects us from the sun's
20 radiation that also causes a problem for us -- us
21 humans at ground level if we inhale it, but it's the
22 same ozone.
23 HEARING OFFICER BEAUCHAMP: Mr. Lawler, for the
24 record your referring to which slide?
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1 MR. LAWLER: I'm referring to the slide called
2 Ozone in the Atmosphere.
3 HEARING OFFICER BEAUCHAMP: Thank you.
4 MR. LAWLER: The next overhead is called Ozone
5 Air Quality and again, this is some background
6 information. The rulemaking that we're proposing is
7 for the purpose of the one-hour ozone National
8 Ambient Air Quality Standard. We need to meet that
9 standard. The standard itself is -- the level is
10 .12 parts per million or 125 parts per billion. The
11 fourth high value at an individual monitor over a
12 three-year period is the critical value. If that
13 value exceeds the levels that I mentioned above, you
14 have a violation of the standard.
15 The Clean Air Act, Section 181, provides
16 for classifications of nonattainment areas.
17 Nonattainment areas are those areas that don't
18 achieve the National Ambient Air Quality Standards.
19 In Illinois we have the Metro-East/St.
20 Louis area, that's a moderate area, the Chicago area
21 and the rest -- and some other areas around Lake
22 Michigan are a severe nonattainment area. The
23 attainment dates for these areas, the Metro-East was
24 initially 1996 and for the Lake Michigan area it's
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1 2007.
2 Now, referring to a chart called Lake
3 Michigan Region One-hour Nonattainment Areas. This
4 indicates the areas that I mentioned earlier that
5 are nonattainment around Lake Michigan and in the
6 St. Louis area both on the Illinois side and
7 Missouri side. We need to point out here that the
8 state does have an obligation to provide for
9 attainment in any areas that we affect.
10 Specifically, in Illinois and I refer to
11 the chart called Illinois Ozone Nonattainment Areas.
12 The nonattainment areas as indicated here in the
13 Chicago area is a six-county -- six complete
14 counties and parts of two others and in the
15 Metro-East there's three counties that are
16 nonattainment.
17 We have an extensive -- I'm referring to
18 the chart called Illinois Ozone Monitoring Network.
19 We have an extensive monitoring network in the state
20 for measuring ozone, 40 monitors. The little dots
21 shown on the chart indicate where the monitors are.
22 You'll notice a lot of them are in the Chicago area,
23 in the Metro-East area again because those are
24 the -- our nonattainment areas in the state.
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1 In looking at -- let me give you the name
2 of the chart, Metro-East Ozone Trends Average
3 Maximum One-hour Concentrations. In looking at the
4 monitoring data from the monitoring data from the
5 network in the Metro-East area, you'll notice that
6 from the late 1970s to the current time there's been
7 a substantial decrease in the ozone levels and this
8 particular chart averages all of the monitors that
9 are in the St. Louis area and it shows a pretty
10 drastic decline. So the control measures that have
11 been in place in the Metro-East area and those
12 generally reflect VOC controls, controls on VOC
13 sources, have worked. We've got a substantial
14 increase -- or decrease in ozone levels, but we're
15 still not in attainment in those areas.
16 This is a very busy chart called Tracking
17 the Ozone and I don't believe there's a copy of that
18 in the material that you have just because it's a
19 very difficult chart to copy, but I will -- it's put
20 up here for a couple of reasons. First of all, the
21 state of Illinois working jointly with the states of
22 Wisconsin, Indiana and Michigan and with USEPA
23 formed an organization called LADOC, Lake Michigan
24 Air Directors' Consortium in 1989. In the early
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1 1990s, there was some extensive studies that were
2 done in order to look at the air quality that was in
3 the area around Lake Michigan and as this chart
4 shows there were aircraft, boats, balloons, a lot of
5 measurements were taken. The point that I want to
6 point out to you is along the southern edge of this
7 little map that kind of shows the Lake Michigan
8 area, if you look at the southern edge there were
9 aircraft flights that took place between central
10 Indiana and central Illinois during this study and
11 the results of those were fairly significant to
12 looking at the way that we needed to -- what we need
13 to do to reduce ozone further.
14 The next chart entitled Ozone
15 Concentrations Measured Along the Southern LMOS
16 Boundary gives an indication of what those aircraft
17 measured along that southern boundary that I showed
18 you on the other chart. If you consider this a
19 slice of air, you're in southern Illinois looking
20 northward and you can just take a slice of the air
21 across these two states and you can get an
22 indication of what the ozone values were at ground
23 level and above the ground. The numbers showing up
24 on this chart indicate ozone values as high as 90 to
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1 100 to 110 parts per billion being transported into
2 the nonattainment area from the south on this
3 particular day and many other days that look just
4 like this. All this indicated to us that while we
5 need to get reductions of VOCs in the nonattainment
6 area itself there's also a substantial amount of
7 ozone and ozone precursors that are being
8 transported into the Chicago nonattainment area as
9 well.
10 Out of all that and similar work that was
11 being done in other parts of the country, and this
12 next chart is called OTAG Participating States, the
13 Ozone Transport Assessment Group was formed
14 involving states, the federal government, industrial
15 groups and environmental groups and many others to
16 study the ozone transport in the eastern part of the
17 country.
18 The next chart called OTAG Findings are
19 the results of that particular study and a couple of
20 these specifically indicate that regional NOx
21 reductions are effective in reducing ozone values in
22 the nonattainment areas. Also, that essentially the
23 more NOx you can get reduced, the more of an effect
24 you have on the ozone. Ozone benefits diminish with
L.A. REPORTING (312) 419-9292
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1 distance, that VOMs controls are still effective
2 locally and that some indication of how far the NOx
3 itself travels and that you can have some
4 disbenefits in the local area.
5 Again, the important thing that came out
6 of all this was a recognition that we needed to
7 control NOx emissions that was being transported
8 into our nonattainment areas in the eastern part of
9 the country.
10 The next chart is called Metro-East/St.
11 Louis NAA Attainment Demonstration moves us now into
12 a requirement that we have to be able to demonstrate
13 attainment. The state has to be able to show how
14 we'll get attainment in the Metro-East of the
15 National Ambient Air Quality Standards for ozone.
16 We were not attaining the standards and as part of
17 the requirements that we needed to do, the state
18 provided an attainment demonstration to USEPA in
19 October of 1999 and we supplemented that in February
20 of 2000 and that was provided to USEPA as part of
21 our demonstration for attainment in the Metro-East.
22 In April of 2000, the USEPA proposed
23 federal approval of our submittal, although it
24 was -- the approval was based on us submitting
L.A. REPORTING (312) 419-9292
27
1 regulations that achieved the reductions that we
2 needed as part of the attainment demonstration and
3 later I think Rob Kaleel will explain a little bit
4 more about the particular attainment work that was
5 done here.
6 In July of 2000 we submitted Subpart W to
7 the Pollution Control Board. Again, at that point
8 the idea that that would be the rule that would take
9 care of this particular need that we had to fulfill
10 and as I mentioned earlier, a court action at the
11 end of August required us -- or we ended up needing
12 to submit Subpart V to the Board to supplement that
13 earlier work that was done because the rule -- the
14 court proceeding in the end of August changed the
15 effective date for the NOx SIP Call leaving us
16 vulnerable beginning in 2003 when our attainment
17 demonstration showed attainment.
18 The last point on here is the -- we had
19 expected that the adoption by the Board of Subpart V
20 in December -- or near the December time frame again
21 would take care of the obligation, but it's not
22 going to completely.
23 I've got a couple overheads dealing with
24 the NOx SIP Call. This first one is called NOx SIP
L.A. REPORTING (312) 419-9292
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1 Call Chronology and I'm not really going to go into
2 any detail in that because we have done so in other
3 proceedings. The important point here is that as
4 we've gone through the SIP Call, there's an
5 interaction between the attainment demonstration and
6 the SIP Call requirements and some of the important
7 dates that are relevant to the SIP Call are shown on
8 this particular chart.
9 The elements of the -- of the required NOx
10 SIP Call, it affected 23 jurisdictions in the
11 eastern part of the country. There are four
12 different types of sources that need to be addressed
13 in the NOx SIP Call. The one that's most relevant
14 to this proceeding is the requirement on EGUs. It's
15 indicated on this chart.
16 HEARING OFFICER BEAUCHAMP: Mr. Lawler, could
17 you identify the chart you're looking at, please?
18 MR. LAWLER: Yes. It's NOx SIP Call Elements.
19 HEARING OFFICER BEAUCHAMP: Thank you.
20 MR. LAWLER: And the SIP Call itself encourages
21 participation in a National Cap and Trade Program.
22 This chart called the Road to the Illinois
23 Regulatory Proposal, I'll take a couple of minutes
24 and kind of go through this, but this is what led us
L.A. REPORTING (312) 419-9292
29
1 up to kind of where we are today.
2 In late 1998 the Agency began meetings
3 with interested groups on the NOx SIP Call, which
4 had just at that time been published in the Federal
5 Register. We ended up meeting with various groups.
6 We had a group of folks called the Policy Group. We
7 had many meetings with affected sources and we had a
8 technical group of folks that were more interested
9 in the inventories and modeling that met essentially
10 on a monthly basis for the next year after this
11 point.
12 The Court issued a stay for the NOx SIP
13 Call on May 25th, 1999, based on requests by a
14 number of different groups. At that point the
15 Agency shifted most of our efforts away from the NOx
16 SIP Call and this was based on discussions that we
17 had with all the folks participating on the
18 different groups and focused more on the attainment
19 demonstrations both for the Metro-East and for the
20 Lake Michigan area.
21 The next chart is entitled Continued Road
22 to Illinois Regulatory Proposal. As I mentioned on
23 an earlier chart, based on the work that was done
24 then, the state submitted for the
L.A. REPORTING (312) 419-9292
30
1 Metro-East/St.Louis area the attainment
2 demonstration, October 1999, and supplemented it in
3 February of 2000. This attainment demonstration was
4 based on a limit of .25 pounds per million BTU for
5 EGUs in the state of Illinois. The Agency is
6 working -- continuing to work with -- LADCO has
7 worked on the attainment demonstration for the Lake
8 Michigan area and in March of -- March 3rd of 2000,
9 the SIP Call was upheld by the courts and at that
10 point, the Agency again shifted direction back to
11 addressing the SIP Call itself. We resumed meetings
12 that we had earlier and we were notified by USEPA
13 that we did, indeed, have to meet the requirements
14 of the SIP Call and then that gets us into the
15 various rulemakings that I talked about earlier
16 including the ones for the EGUs.
17 In this chart entitled Purpose of Proposed
18 Rulemaking, again, this particular rulemaking,
19 Subpart V, is intended to satisfy the obligations of
20 the state to submit control strategies to
21 demonstrate attainment for the one-hour ozone NAAQS
22 and to address concerns regarding the potential bump
23 up in the Metro-East area, and from the other
24 testimony that will be given this morning, you'll be
L.A. REPORTING (312) 419-9292
31
1 given more of an explanation of the rulemaking
2 itself, of the modeling that went into this to
3 develop it and the technical support information
4 associated with those.
5 HEARING OFFICER BEAUCHAMP: Thank you. Before
6 we proceed with the Agency's next witness, I think
7 it might be helpful to enter for the record the
8 docket numbers of the other rulemakings that you
9 referred to during your testimony. Subpart W is
10 being -- is before the Board in Docket No. R01-09
11 and Subpart T is before the Board in Docket No.
12 R01-11.
13 MS. McFAWN: And that has to do with cement
14 kilns.
15 HEARING OFFICER BEAUCHAMP: The Agency, you
16 have another witness?
17 MS. HERST: Do we need to submit a copy of the
18 overheads into the record?
19 HEARING OFFICER BEAUCHAMP: Yes. His
20 overheads.
21 MS. HERST: 2A.
22 HEARING OFFICER BEAUCHAMP: Would you like to
23 have those submitted as Exhibit 2A?
24 MS. HERST: Yes, please.
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32
1 HEARING OFFICER BEAUCHAMP: Okay. Who is your
2 next witness?
3 MS. HERST: Our next witness is Robert Kaleel.
4 HEARING OFFICER BEAUCHAMP: Mr. Kaleel, again,
5 I'd ask to remind you to identify the title of each
6 overhead as in going through it in your testimony.
7 MR. KALEEL: I'll try to remember to do that.
8 HEARING OFFICER BEAUCHAMP: Thank you. If I
9 might interrupt just before we move on, Ms. Herst,
10 will Mr. Lawler be presenting a copy of the slide
11 that was not in the package, the Tracking the Ozone
12 slide?
13 MS. HERST: We can do that.
14 HEARING OFFICER BEAUCHAMP: Thank you.
15 MR. KALEEL: My name is Rob Kaleel. I'm with
16 the air quality planning section modeling unit in
17 the Bureau of Air. I have been involved with the
18 performance or the preparation of the one-hour ozone
19 attainment demonstration for the St. Louis area.
20 I've also been involved with the one for Chicago.
21 I'm going to present the results, hopefully,
22 briefly -- the results for the St. Louis
23 nonattainment area, which includes the area in
24 Illinois referred to as the Metro-East area.
L.A. REPORTING (312) 419-9292
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1 This slide is referred to in the package
2 that was submitted to the Board. Hopefully, there's
3 extra copies still available for other interested
4 people. I'd like to begin the discussion with a
5 comparison of air quality levels observed in
6 the St. Louis area between 1987 through 1989 and
7 present conditions, 1997 to 1999.
8 The chart shows -- first off, the shaded
9 area on both sides of the Mississippi River, the
10 Missouri side and the Illinois side. The area
11 shaded in blue or I guess it looks more like gray is
12 the extent of the nonattainment area referred to as
13 the St. Louis nonattainment area.
14 HEARING OFFICER BEAUCHAMP: Mr. Kaleel, just
15 for the record, I'd like to identify that you're
16 referring to Figure 1 in his submitted testimony.
17 MR. KALEEL: Yes, sir.
18 The area in the little darker shade is the
19 area that encompasses the locations of ambient
20 monitors in the St. Louis nonattainment area that
21 exceeded the level of the one-hour standard in two
22 different time periods, 1987 to 1989 on the left and
23 more recently, the '97 to 1999 period on the right.
24 Three years of data are used to be able to compare
L.A. REPORTING (312) 419-9292
34
1 to the level of the ozone standard and in particular
2 the fourth high value at any given site recorded in
3 three years is the level that is compared to the
4 standard. Net value is referred to as the design
5 value or the design concentration. So the numbers
6 that appear on the slides reflect areas where the
7 design value exceeds the level of the air quality
8 standard.
9 In 1987 through 1989 there were 13
10 monitoring stations throughout the nonattainment
11 area that were exceeding the level of the ozone
12 standard. The highest design value in the region
13 occurred in northern Jefferson County, Missouri.
14 The level of that violation, that level of air
15 quality of the design value, was 156 parts per
16 billion. In the more recent three-year period, the
17 area that is still in violation of the air quality
18 standard is greatly reduced showing a definite
19 improvement in air quality levels in the region.
20 There were only two monitors in the nonattainment
21 area. Actually, this one in Jersey (sic) County is
22 not in the nonattainment area, but is immediately
23 downwind. These two monitors are the only ones that
24 still record concentrations in excess of the
L.A. REPORTING (312) 419-9292
35
1 standard. The highest design value in the region
2 currently is 131.
3 So over the ten-year period we've greatly
4 reduced the spacial extent of the violation and the
5 number of people that are exposed to levels of air
6 quality in excess of the standard and we've reduced
7 the magnitude of those concentrations from 156 down
8 to 131. As Mr. Lawler had mentioned, the programs
9 that we have in place are working, but violations in
10 the region are still occurring so we still need to
11 do more.
12 This slide is referred to simply as
13 Chronology. As Mr. Lawler mentioned, there's been a
14 long history of involvement by the Agency and the
15 Board and the state of Missouri in trying to deal
16 with air quality issues in the St. Louis region. I
17 won't take you all the way back to the beginning,
18 but at least the events that have taken place since
19 the 1990 Clean Air Act Amendments.
20 The 1990 Amendments required that the
21 St. Louis region, which is considered a moderate
22 nonattainment area, be able to demonstrate
23 attainment and, in fact, reach attainment by 1996.
24 The 1990 Amendments also required the states to
L.A. REPORTING (312) 419-9292
36
1 begin planning and to put together an attainment
2 demonstration based on the use of air quality models
3 by 1994. The use of models in the context of
4 attainment demonstration are in a predicted sense.
5 We try to track emission changes that are
6 anticipated in the future years to be able to see
7 whether or not those emission changes are going to
8 be sufficient to attain the standard by the
9 deadline. So in this case, November 1994, the
10 states of Illinois and Missouri jointly prepared an
11 attainment demonstration using models to look at
12 1996, the attainment year, to look at all control
13 measures that were expected by that time to see
14 whether or not those measures would be sufficient to
15 attain the standard. What we found at that time
16 was, in fact, we could not achieve the air quality
17 standards by 1996 with the local measures that --
18 mostly VOC measures that were anticipated at that
19 time. The model concluded that the transport of
20 ozone and ozone precursor emissions, particularly
21 NOx and some VOCs, would prevent the area from
22 reaching attainment in 1996.
23 Other areas of the country were making the
24 same finding that ozone transport have not been
L.A. REPORTING (312) 419-9292
37
1 properly dealt with, that many areas in the eastern
2 United States could not attain without looking
3 upwind into areas that were actually classified as
4 attainment.
5 The Ozone Transport Assessment Group was
6 formed in 1995 by the environmental commissioners of
7 the states east of the Mississippi River and a few
8 western states to look at the phenomenon of ozone
9 transport and try to recommend mitigative measures
10 to USEPA. Their findings, as Dennis Lawler had
11 mentioned the finding from the OTAG group, their
12 findings were made public in 1997 to follow shortly
13 thereafter by USEPAs proposal of the NOx SIP Call
14 which we've tried to deal with ozone transport.
15 I mentioned before that this St. Louis
16 area was to be in attainment by 1996 and couldn't
17 make it as a result of ozone transport. The EPA
18 never bumped the area up in 1996, which was the
19 prescribed sequence that was supposed to happen
20 based on the Clean Air Act. They recognized that
21 because of transport, the area could not attain and
22 they basically were silent on the issue of
23 attainment dates from 1996 until July of 1998. At
24 that point they issued a new policy called the
L.A. REPORTING (312) 419-9292
38
1 Extension Policy for areas whose attainment dates
2 had already past. These were areas affected by
3 transport and I'll talk a little bit more about the
4 Extension Policy.
5 Missouri and Illinois both agreed that
6 St. Louis was such an area that should have an
7 extension of the attainment date for some future
8 time. We had both requested an extension under this
9 policy in December of 1998. One of the requirements
10 of the Extension Policy as we revised our attainment
11 demonstration to look beyond the 1996 time frame out
12 to the time frame when upward reductions were to
13 occur, and we have submitted the revised attainment
14 demonstration in October of 1999 as required by that
15 policy.
16 This slide is called the Policy on
17 Extension of Attainment Dates. I mentioned the
18 guidance was issued -- I believe I got that date
19 wrong. There's a typo on that -- the policy was
20 issued in July of 1998. This guidance was issued by
21 USEPA to specifically deal with areas like
22 St. Louis and there are a few others in the eastern
23 United States where -- these were moderate areas
24 that had earlier attainment dates, but were affected
L.A. REPORTING (312) 419-9292
39
1 by ozone transport. The basic idea of the policy is
2 to move the attainment date back to some point in
3 time when upwind reductions in particular NOx
4 reductions would have occurred to allow the region
5 to come into attainment. In the case of the St.
6 Louis area what we had projected or what we
7 anticipated when we began this modeling process was
8 that all these reductions would be in place by the
9 year 2003.
10 This slide is just called Assumptions and
11 I'll try to walk you through the assumptions that we
12 used to develop and implement the air quality model
13 that is used to predict air quality concentrations
14 for the future attainment year.
15 The modeling is -- the model in particular
16 that isn't shown on the slide is called the Urban
17 Airshed Model, Version V or Version 5. It's the
18 same model that was used for the Chicago attainment
19 demonstration, the same model used by OTAG, the same
20 model used by USEPA in their technical support
21 efforts for the NOx SIP Call. So it's a very widely
22 used photochemical model.
23 We had implemented the model just for a
24 Midwestern region to really focus in on the very
L.A. REPORTING (312) 419-9292
40
1 high resolution, very high level of precision just
2 on the Midwestern region most likely to affect
3 Illinois, both St. Louis and Chicago. This area is
4 referred to as Grid M and I'll show you a picture of
5 that in a moment. We did model an area outside of
6 the Midwest called the OTAG coarse-grid to try to
7 look at the effects of future emission changes
8 outside of the Midwest to see whether or not those
9 areas would have a substantial affect on air quality
10 levels in St. Louis.
11 We originally began this effort using
12 three episodes. I think in my testimony it refers
13 to the use of two episodes. We dropped one episode
14 because it just didn't work very well and I'll
15 mention which one that is in a moment.
16 We also applied, getting a little
17 technical I guess, a correction to USEPA's biogenics
18 emissions model. Biogenics being the amount of
19 naturally occurring VOCs from things like trees and
20 in particular in the Missouri Ozarks, there are a
21 very high percentage of oak trees in the Missouri
22 Ozarks and the predictions of EPA's Beis-2 model was
23 found to be greatly overstating the amount of VOCs
24 in the region. So we had worked with USEPA to
L.A. REPORTING (312) 419-9292
41
1 perform a specific field measurement program in that
2 region to try to fine tune those emission factors
3 and we and USEPA agreed that some correction was
4 needed.
5 This figure is called Figure 2, Midwest
6 Modeling Domain or Grid M. I've mentioned before
7 that we had developed a modeling domain that covers
8 most of the Midwest, the areas that we think are
9 contributing the greatest amount to the ozone
10 transport problem. This area is modeled with a
11 resolution, a grid spacing if you will, of only four
12 kilometers, which is a very high resolution way to
13 implement the model, but we've also accounted for
14 the effects of emission changes in areas surrounding
15 Grid M. This larger domain is called the OTAG
16 domain. The grid cell spacing or resolution, if you
17 will, in this larger domain is a 36 kilometer
18 spacing. That's the same way that OTAG developed
19 this grid back in '95 through 1997. So we are
20 looking at emission changes within Grid M with a
21 very high resolution and then again emission changes
22 outside of that region. The areas right along this
23 edge here are referred to as boundary conditions I
24 think on the previous slide.
L.A. REPORTING (312) 419-9292
42
1 HEARING OFFICER BEAUCHAMP: Mr. Kaleel, could
2 you specifically describe which edge on that chart
3 you were referring to just now?
4 MR. KALEEL: The edge that I intended to meet
5 my boundary conditions are shown on this slide in
6 red is the boundary or the edges of the Grid M
7 domain.
8 HEARING OFFICER BEAUCHAMP: Thank you.
9 MR. KALEEL: This slide is called Modeling
10 Episodes and you can't see the colors very well. We
11 had originally started to look at three historical
12 ozone episodes using the air quality model.
13 Historical episodes are used to evaluate the
14 performance of the model. You would try to
15 reproduce with the model events that actually
16 occurred in historical time periods during high
17 ozone events. July 16th through 19th, 1991, and
18 July 10th through 14th, 1995, these are both
19 episodes very representative of the kinds of
20 conditions that occur in St. Louis when ozone levels
21 are elevated. This period in June of 1996 was also
22 a very good episode as far as high concentrations
23 observed in the St. Louis region. I'm showing this
24 one in red, however, because this is the one that we
L.A. REPORTING (312) 419-9292
43
1 weren't able to get to work very well when we did
2 our Basecase evaluation of the model. We were not
3 able to reproduce with the model the ozone levels
4 that were actually observed in St. Louis. So we
5 abandoned the use of that one and finished our
6 attainment demonstration with the July '91 and July
7 1995 episode.
8 HEARING OFFICER BEAUCHAMP: Again, just to
9 clarify the record, the red time period that you
10 referred to is the third time period on this slide?
11 MR. KALEEL: Yes. It's the one on the slide
12 from June 27th to the 29th, 1996. That's the
13 episode that we did not use for the final attainment
14 modeling.
15 This slide is called Modeling Scenarios.
16 Once we're able to evaluate the performance of the
17 model and have some level of comfort that the model
18 was actually accurately reproducing the ozone and
19 precursor concentration fields throughout the
20 St. Louis region for the Basecase and in this case
21 we're using the 1995 emissions inventory as the
22 Basecase inventory, we used the model then in a
23 predicted way for the year 2003, which is the year
24 that we anticipated that the NOx SIP Call would be
L.A. REPORTING (312) 419-9292
44
1 in place. We evaluated three different emission
2 scenarios using the model for both of the episodes
3 that I mentioned previously. One scenario, the
4 first one, referred to here is just CAA 2003. CAA
5 is the Clean Air Act scenario. It reflects all the
6 emission changes that are required by the Clean Air
7 Act, things like the state's 15 percent rate of
8 progress plan are included in there. They're
9 requirements for enhanced I/M in the nonattainment
10 areas. Those are included in there. There was an
11 initial phase of title four control measures that
12 were implemented by that time. So those are
13 examples of the types of control measures that are
14 included in the Clean Air Act scenario.
15 The next scenario assumes that all EGUs,
16 electric generating units, are meeting a level of
17 .25 pounds per million BTU. This is for NOx. This
18 is an assumed NOx control scenario and when I say
19 all EGUs what I'm referring to are all EGUs in the
20 area identified by USEPA's NOx SIP Call. So it's 22
21 states, most of which are east of the Mississippi
22 River, but it also includes the state of Missouri.
23 Finally, for the year 2003 as an
24 additional scenario we model the actual NOx SIP Call
L.A. REPORTING (312) 419-9292
45
1 scenario which include the EGUs controlled to a
2 level of .15 pounds per million BTU. There are also
3 other requirements of a NOx SIP Call affecting
4 cement kilns, nonEGUs and other source categories.
5 This slide is entitled Figure 3,
6 Domain-wide Total Anthropogenic Emissions. What I'm
7 comparing on this particular slide are emission
8 levels evaluated using the model both for NOx
9 emissions on the left and for VOC emissions on the
10 right. Each of the four bars on this chart show
11 emission levels for each of the scenarios. The
12 Basecase, the Clean Air Act level of controls, the
13 .25 pounds per million NOx control and the NOx SIP
14 Call. So that each of the four scenarios I've just
15 mentioned are shown on there.
16 Looking at the part of the chart that's on
17 the left which reflect NOx emission changes tested
18 in the model, and again, these are emissions
19 throughout the entire Grid M domain, not just in the
20 St. Louis nonattainment area.
21 From this chart each successive scenario
22 results in successively lower levels of NOx
23 emissions. The 1996 Basecase emissions for the
24 entire Grid M area was in excess of 16,000 tons of
L.A. REPORTING (312) 419-9292
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1 NOx per day. The Clean Air Act Amendments and in
2 particular the requirements of the title four Acid
3 Rain Control Program would reduce those NOx
4 emissions in the Grid M domain by over 2000 tons to
5 a level almost 14,000 tons per day. The .25
6 scenario reduces emissions by about another 2000
7 tons to a level of about 11,000 tons per day and
8 finally, the NOx SIP Call brings those levels of
9 emissions down about another 1,600 tons to a level
10 almost 10,000 tons per day in the Grid M domain.
11 So each successive scenario looks at
12 tighter and tighter levels of NOx control or lower
13 levels of NOx emissions.
14 On the VOC side, the predominant VOC
15 strategy evaluated is the Clean Air Act strategy
16 with fairly dramatic reduction of the VOC emissions
17 shown between the Basecase and the 2003 Clean Air
18 Act scenario. These are the reductions referred to
19 before, things like the 15 percent control plans,
20 efforts to reduce the amount of VOCs emitted from
21 automobiles, the enhanced I/M program, low RVP
22 fuels in the Metro-East area, reformulated gasoline
23 on the Missouri side, those are all contained within
24 the scenario called Clean Air Act scenario. Again,
L.A. REPORTING (312) 419-9292
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1 the .25 and the NOx SIP call scenarios are NOx
2 strategies. VOC levels really are not changed in
3 those subsequent scenarios.
4 HEARING OFFICER BEAUCHAMP: Mr. Kaleel, on this
5 current slide, Figure 3, you have one of your
6 scenarios listed as '96 Basecase. On the previous
7 slide, Modeling Scenarios, you have identified it as
8 1995 Basecase?
9 MR. KALEEL: Yes. I should explain that.
10 When we refer to the scenarios that we call our
11 Basecase it, in a way, is reflected of '95 slash
12 '96. I apologize for the confusion. Most of the
13 inventory reflects 1995, but through the process of
14 developing this inventory we worked with utilities
15 in the USEPA's Acid Rain Program to look at the
16 results of their continuous emissions monitors for
17 NOx and for utilities. We're really reflecting more
18 of the 1996 case. So both terms are right. I
19 should have been consistent on the way I referred to
20 them.
21 HEARING OFFICER BEAUCHAMP: Okay.
22 MR. KALEEL: This slide is called Figure 4,
23 Peak One-hour Ozone Concentrations. I apologize the
24 colors are not showing up real well, but what this
L.A. REPORTING (312) 419-9292
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1 four-panel plot is trying to show is the results of
2 each of the four emission control scenarios that I
3 described previously for one example day. In this
4 case the day that we're trying to reflect is July
5 18th, 1991. We're not trying to reproduce 1991
6 here, but rather we're using the meteorology that
7 occurred on that day to look at emission scenarios
8 for each of these subsequent periods. In this case,
9 the base year period versus the three scenarios for
10 2003. The color scales are a little difficult to
11 see, but basically on this one particular day the
12 model is showing predicted violations, levels of air
13 quality, ozone air quality above the level of the
14 one-hour standard, above .25 to exceed downwind of
15 the St. Louis nonattainment area. Areas of other --
16 of elevated concentrations of ozone, but below the
17 standard are shown here in yellow. If you can kind
18 of compare visually the red area, the most central
19 contour area, to subsequent scenarios you can see
20 that the area gets successively small -- areas of
21 elevated ozone concentration gets successively
22 smaller indicating that each of the successive
23 strategies would yield air quality benefits.
24 Actually, on this particular day, the Clean Air Act
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1 levels of control reduce concentrations to below the
2 level of the standard. Again, this is just one day
3 out of several that we looked at and unfortunately,
4 the Clean Air Act scenario didn't solve all the
5 days, but to illustrate the improvements I've used
6 this day. Comparing the Clean Air Act contours to
7 the .25 scenario, again, further reductions in the
8 size of each contour again indicating successively
9 better and better air quality predicted by the
10 model. There isn't a lot of difference between the
11 .25 and the NOx SIP Call scenario. In fact, in
12 comparing those two charts you see very little
13 difference at all. On other days and even on this
14 day what we've seen is about a one to three part per
15 billion improvement in predicted ozone near the
16 St. Louis region when you look at the difference
17 between NOx SIP Call scenario and the .25 scenario.
18 HEARING OFFICER BEAUCHAMP: If I could just
19 clarify for the record, the chart that we have is in
20 black and white. The red area that you referred to
21 appears to be showing up on your chart as the
22 darkest color and the yellow appears to be showing
23 up as the lightest color on the exhibit that you
24 submitted?
L.A. REPORTING (312) 419-9292
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1 MR. KALEEL: I think that's right.
2 MS. McFAWN: Also, for the record, note that
3 this figure as well as the other ones designated as
4 figures are attached to your testimony which I
5 believe would be admitted into evidence and they are
6 shown attached at least on our copies of your
7 testimony in color.
8 MR. KALEEL: In color.
9 MS. McFAWN: This is for benefit of the reader
10 more than the panel.
11 MR. KALEEL: On the previous slide we indicated
12 that really there wasn't a lot of difference in air
13 quality predicted in St. Louis between the .25
14 scenario and the NOx SIP Call. In fact, the
15 difference was in the range of about one to three
16 parts per billion. What we were able to find and I
17 think this slide, which I forgot to mention is
18 Figure 5, the Attainment Strategy Modeling Results.
19 What we, in fact, found is that the .25 pounds per
20 million BTU NOx scenario was, in fact, adequate to
21 demonstrate attainment for the St. Louis region.
22 The NOx SIP Call scenario maybe provides more
23 reductions than are needed specifically to meet this
24 test of demonstrating attainment. I think this
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1 slide shows it pretty well. What this slide is
2 trying to show is not just the results on an
3 individual day, but the results on all of the days
4 in kind of a relative context. This particular
5 analysis was included in the attainment
6 demonstration as a quote, weight of evidence, type
7 of demonstration, and again, the -- what this
8 particular slide is trying to show is the difference
9 in measured air quality, in this case the '95 to
10 1997 ozone design value. This is the measured value
11 not modeled. When we used the model in a relative
12 way look at the percent change from the base year to
13 each of the strategies, use that percentage change
14 to apply it to the design value to predict what the
15 future design value would look like or the 2003
16 design value. What we see in looking at each of the
17 successive bars on this chart is that the Clean Air
18 Act measure is commensurate with the amount of
19 emission reductions that we showed to provide ozone
20 benefits. Concentrations should come down based on
21 just implementation of the Clean Air Act control
22 measures. However, we don't expect that the Clean
23 Air Act measured by themselves will yield attainment
24 for the region. Predicted concentrations will still
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1 exceed the level of the ozone standard of .125 or
2 124.9. The .25 scenario does reduce predicted
3 concentrations to below the level of the air quality
4 standard. That is the level that we chose for the
5 attainment demonstration that we submitted to USEPA,
6 and again, the NOx SIP Call provides a little bit
7 more air quality benefit giving air quality levels
8 slightly lower than the .25 scenario.
9 This slide is called the Attainment
10 Strategy Control Measures and this is just kind of a
11 final review of the measures that were contained in
12 the attainment demonstration submitted by both
13 Illinois and Missouri originally last October,
14 October 1999, with some updates in February and June
15 of this past year. The strategy includes both VOC
16 measures and NOx measures. The VOC measures
17 implemented locally include the 15 percent plans,
18 the enhanced I/M program, Missouri's reformulated
19 gasoline program. In addition to that not shown is
20 Illinois' low RVP gasoline program and all other
21 measures required by the Clean Air Act by the year
22 2003.
23 In terms of regional measures the
24 attainment demonstration assumes that electric
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1 utilities or EGUs would be controlled -- NOx
2 emissions would be controlled to a level of .25
3 pounds per million BTU in Illinois and the eastern
4 one-third of Missouri. In the western third of
5 Missouri, the EGU control level is .35 pounds per
6 million BTU and all other EGUs in the NOx SIP Call
7 states east of the Mississippi River would be
8 controlled to a level of .25 pounds of NOx per
9 million BTU. That concludes my testimony.
10 HEARING OFFICER BEAUCHAMP: Thank you. At this
11 time would you like to move to admit the copies of
12 your slides as an exhibit?
13 MS. HERST: Yes.
14 HEARING OFFICER BEAUCHAMP: We will admit those
15 as Exhibit 1A. Let's take a few moments off the
16 record.
17 (Whereupon, a discussion
18 was had off the record.)
19 HEARING OFFICER BEAUCHAMP: Does the Agency have
20 another witness they would like to present?
21 MS. HERST: Yes. Mr. Moore is going to read
22 his testimony.
23 HEARING OFFICER BEAUCHAMP: Mr. Moore, please
24 proceed with your testimony.
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1 MR. MOORE: Good afternoon. My name is Berkley
2 L. Moore. I'm a licensed professional engineer in
3 Illinois and since 1970 I have been employed as an
4 Environmental Protection Engineer or as an
5 Environmental Protection specialist in the Illinois
6 Environmental Protection Agency's (the Agency)
7 Bureau of Air.
8 I have a bachelor of science degree
9 majoring in chemical engineering which I received
10 from Grove City College in Pennsylvania and have
11 completed all the course work for a master's degree
12 in environmental engineering from Southern Illinois
13 University.
14 The purpose of my testimony today is to
15 discuss the technical aspects, section by section,
16 of the Agency's Part 217, Subpart V, Electric Power
17 Generation, proposal for regulating the emissions of
18 nitrogen oxides, (NOx).
19 Section 217.700 simply states that the
20 purpose of Subpart V is to control NOx emissions
21 during the May 1 through September 30 control
22 period, beginning in the year 2003. Control of NOx
23 during the control period will have the effect of
24 reducing ambient concentrations of ozone because it
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1 is the chemical reaction of NOx, in the presence of
2 heat and sunlight, with volatile organic compounds
3 that are also emitted to the atmosphere, which is
4 the primary mechanism leading to the formation of
5 ozone in the lower atmosphere.
6 The May 1 to September 30 dates
7 denominating the control period are, of course,
8 dates that encompass the period of most intense
9 sunlight during the year. The year of applicability
10 is 2003.
11 Section 217.702. This section simply
12 states that if any section, subsection or clause of
13 Subpart V is found invalid, such finding shall not
14 affect the validity of any of those portions of
15 Subpart V not found invalid.
16 Section 217.704, applicability. This
17 section sets forth the type of emission unit to
18 which Subpart V applies. It is written to apply to
19 all fossil fuel-fired stationary boilers, combustion
20 turbines or combined cycle systems that serve a
21 generator with a nameplate capacity exceeding 25
22 megawatts of electricity, if such electricity is
23 sold. This section excludes the nonEGUs listed in
24 Appendix D to Subpart W, which was filed with the
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1 Board on July 11th, 2000, and docketed as R01-9.
2 Subpart V also applies to any fossil
3 fuel-fired unit with a maximum design heat input of
4 greater than 250 million BTU per hour if the unit
5 has the potential to use more than 50 percent of its
6 potential electrical output capacity of the unit.
7 Subsection (a) provides that if the
8 generator served by these emission units exceeds a
9 capacity of 25 megawatts of electricity for sale,
10 the unit is subject to Subpart V unless the unit is
11 located at a source listed in Appendix D to Part 217
12 of the Board's air pollution regulations. The
13 sources listed in Appendix D are sources whose
14 primary business is not the production of
15 electricity, and that are not being modeled as part
16 of the proposed Subpart V NOx emission rate in the
17 Agency's attainment demonstration for the
18 Metro-East/St. Louis ozone nonattainment area.
19 Subsection (b) applies to emission units
20 commencing operation after January 1, 1999, and
21 provides the method to determine whether a large;
22 that is, more than 250 million BTU per hour heat
23 capacity unit is designed primarily for the
24 production of electricity rather than to provide
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1 steam or heat for process emission units. The
2 0.0488 factor by which a unit's heat input is to be
3 multiplied to determine the primary purpose of the
4 unit is based on standard conversion factors
5 relating British thermal units per hour, the
6 preprinted testimony inadvertently omits per hour,
7 to watts. The fact that only one-third of a unit's
8 heat input is ordinarily converted into electricity
9 and that if a generator requires more than one-half
10 of the unit's heat input to generate the electricity
11 at full capacity, the emission unit's primary
12 purpose must be for the production of electricity.
13 Two sources indicated that there should be
14 a low emitter exemption for units with low; that is,
15 five percent or less capacity factors that burn
16 natural gas or oil. The concern appears to be the
17 higher cost of requiring controls and continuous
18 emissions monitors for units that operate
19 infrequently. Units with such low capacity factors
20 are usually peaking units. As I noted earlier, the
21 proposal already excludes smaller units those
22 serving a generator with a nameplate capacity that
23 is 25 megawatts of electricity or less.
24 The Agency believes it is reasonable for
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1 the proposal to include large units with a low
2 capacity factor.
3 Section 217.206 (sic) emission
4 limitations. This section would limit NOx emissions
5 from affected units to 0.25 pounds per million BTU
6 as well as to any more stringent limit that might
7 also apply. The Subpart V limit of 0.25 pounds per
8 million BTU must be achieved by each individual unit
9 or alternatively by participating in an averaging
10 demonstration via the provisions of Section 217.708.
11 HEARING OFFICER BEAUCHAMP: Mr. Moore, I
12 believe when you were speaking you said Section
13 217.206 and in your prefiled testimony it says
14 217.706.
15 MR. MOORE: Okay. Yes. 706 is correct.
16 Section 217.798, NOx averaging. This
17 section applies only to those emission units listed
18 in Appendix F to Subpart W, and to any unit at
19 Soyland Power that commenced commercial operation
20 before January 1st, 2000. Units listed in Appendix
21 F are units that commenced commercial operation
22 before 1996. Therefore, units that commenced
23 commercial operation after this date and units at
24 Soyland Power that commenced commercial operation
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1 after January 1st, 2000, will have to meet the 0.25
2 pounds per million BTU limit on an individual basis.
3 The units to which Section 217.708
4 applies, however, will be able to meet the Subpart V
5 limit in a more cost-effective manner averaging
6 their emissions rates with other units under Section
7 217.708. The mathematical representation of the
8 averaging formula is given in Subsection (b).
9 A simple illustration of the Subsection
10 (b) formula is to consider two boilers each of 1,500
11 million BTU per hour heat input capacity. If one of
12 those boilers had an average control period NOx
13 emissions rate of 0.15 pounds per million BTU and
14 the other an average control period emissions rate
15 of 0.35 pounds per million BTU, then taken together
16 their average emissions rate would be 0.15 plus
17 0.35, that quantity divided by two or 0.25 pounds
18 per million BTU, just enough to meet compliance.
19 Use of the 217.708 formula would give the
20 same result and more importantly would give a
21 correct result regardless of any varying heat inputs
22 of the units or number of units in the averaging
23 plan and regardless of operating for a different
24 number of hours, the illustration assumes operating
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1 for the same number of hours during the control
2 period.
3 Subsection (c) provides that emission
4 averaging must be conducted via federally
5 enforceable permit conditions and Subsection (d)
6 allows each unit to be included only once in a NOx
7 averaging demonstration during a control period.
8 This latter provision is designed so as to prevent
9 double counting of over-complying emission units;
10 that is, the difference in allowable and actual
11 emissions from each averaging unit can be used only
12 one time by other undercomplying units.
13 Subsection (e) requires compliance by
14 averaging to be demonstrated within two months of
15 the end of the control period while Subsection (f)
16 provides that should compliance not be demonstrated
17 by averaging, each unit participating in the
18 averaging demonstration shall be treated as though
19 it were attempting to comply on an individual basis.
20 Thus overcomplying units would be deemed to be in
21 full compliance, while undercomplying units would be
22 deemed to fall short by the actual magnitude of
23 their undercompliance.
24 Section 217.710, monitoring. This section
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1 requires affected units to demonstrate compliance
2 with NOx emission limits by using continuous
3 emissions monitors that meet the requirements of 40
4 Code of Federal Regulations Part 75, Subpart B.
5 There is an exemption in Subsection (b),however,
6 allowing oil or gas-fired peaking units to use the
7 emissions estimations protocol of 40 CFR Part 75,
8 Subpart E. This emissions protocol provides that
9 other kind of monitoring systems may be used so long
10 as they can be shown to be of equivalent precision,
11 reliability, accessibility and timeliness.
12 Thus, this section imposes on affected
13 units identical with monitoring requirements to
14 those imposed by the proposed Part 217, Subpart W
15 regulations that would apply to the same affected
16 units that are currently before the Board -- the
17 regulations are currently before the Board, but for
18 the fact that Subpart V monitoring will be required
19 approximately a year earlier, and that such
20 monitoring will entail an additional calculation
21 step; that is, the step of determining emissions in
22 pounds per million BTU.
23 Section 217.712. Reporting and
24 recordkeeping. This section requires affected units
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1 to comply with the recordkeeping and reporting
2 requirements of 40 CFR Part 75, but only insofar as
3 these requirements are related to NOx emissions
4 during the control period; to certify that the
5 report is true and accurate; to show that the unit
6 complies with the control season average NOx
7 emissions rate not exceeding 0.25 pounds per million
8 BTU, either individually or as part of an averaging
9 demonstration; to keep and maintain for five years
10 all records and data necessary to demonstrate such
11 compliance and to have such records and data
12 available for submittal to the Agency within 30 days
13 of any written request by the Agency. These records
14 and data must be available or submitted by November
15 30 of each year beginning in 2003. This concludes
16 my testimony.
17 HEARING OFFICER BEAUCHAMP: Thank you,
18 Mr. Moore. Any rebuttal for Mr. Moore?
19 MS. HERST: No.
20 HEARING OFFICER BEAUCHAMP: Do you have any
21 other witnesses you'd like to present today?
22 MS. HERST: Yes. We have one more,
23 Mr. Mahajan. He will also read his testimony into
24 the record.
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1 HEARING OFFICER BEAUCHAMP: Mr. Mahajan, please
2 proceed with your testimony.
3 MR. MAHAJAN: Good morning. My name is
4 Yoginder Mahajan. I am employed as an environmental
5 protection engineer in the air quality planning
6 section in the Bureau of Air of the Illinois
7 Environmental Protection Agency hereafter called
8 Illinois EPA. I have been employed in this capacity
9 since March 1992.
10 HEARING OFFICER BEAUCHAMP: Mr. Mahajan, could
11 I get you to slow down for the court reporter,
12 please?
13 MR. MAHAJAN: Prior to my employment with the
14 Illinois EPA I worked for various metal fabrication
15 industries for nine years. My educational
16 background includes a bachelor of engineering degree
17 in mechanical engineering from Bhopal University at
18 Bhopal, India.
19 As part of my regular duties in the air
20 quality planning section, I have prepared emission
21 estimates for various source categories used in the
22 development of the 1990 ozone season weekday
23 emissions inventories; evaluated control
24 technologies applicable to volatile organic
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1 materials hereafter called VOM emissions sources
2 utilized in the preparation of the Rate-of-Progress
3 plans for the Chicago and St. Louis ozone
4 nonattainment areas; and assisted in the development
5 of regulations for the control of VOM emissions from
6 source categories included in the Rate-of-Progress
7 plans.
8 Regarding the proposal before you today, I
9 have been involved in the development of the NOx
10 regulations for electrical generating units
11 hereafter called EGU, and I have prepared the
12 Technical Support Document hereafter called TSD for
13 this proposal.
14 As the TSD points out, the rotary motion
15 of the turbines through a magnetic field generates
16 the electricity that is produced by the utility
17 industry. A large output of electricity, the amount
18 that is required every day of the year is ordinarily
19 generated by the turbines turned by a flow of steam
20 produced in boilers. This more or less constant
21 electrical load is termed base load. Base load
22 units are supplemented, as needed, by cycling units
23 which may be gas- or oil-fired. An extra amount of
24 electricity, such as that required to run many air
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1 conditioners during very hot summer days, is
2 generated in turbines turned by a flow of steam
3 produced in gas- or oil-fired boilers that can be
4 quickly brought on line, or in gas- or oil-fired gas
5 turbines, wherein the same turbine that is making
6 the electricity is turned by the flow of combustion
7 gases produced from burning gas or fuel oil. Units
8 producing electricity that are required only on high
9 demand days are called peaking units or simply
10 peakers. Smaller coal-fired units are also
11 sometimes used as peakers, although they cannot come
12 on line as quickly as gas- or oil-fired units.
13 Combustion of fuel in the boilers and gas
14 turbines produces nitrogen oxides hereafter called
15 NOx. The ambient air consists of about 20 percent
16 oxygen which when heated to elevated temperatures
17 will combine with the elements of coal, fuel oil, or
18 natural gas, carbon and hydrogen, to yield carbon
19 dioxide and water vapor, and to generate still more
20 heat which will sustain combustion. Ambient air,
21 however, also contains almost 80 percent nitrogen,
22 which does not react with its oxygen component to
23 form NOx at ambient temperatures, but will do so at
24 the elevated temperatures that occur during a fuel's
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1 combustion. This reaction takes place at an
2 increased rate as the temperature of combustion
3 rises, and also with increasing amounts of excess
4 air. In addition, coal and fuel oil contain
5 appreciable amounts of nitrogen that can also
6 combine with oxygen to form still more NOx at
7 combustion temperatures.
8 Today's proposal is to control NOx
9 emissions from the large fossil-fuel-fired EGUs that
10 have nameplate capacities greater than 25 megawatts
11 of electricity. As part of the evaluation of the
12 control of NOx emissions from EGUs, the Illinois EPA
13 identified several sources of guidance. The United
14 States Environmental Protection Agency, hereafter
15 called USEPA, published two Alternative Control
16 Techniques, hereafter called ACT, documents
17 regarding control of NOx emissions from utility
18 boilers and gas turbines. These ACT documents
19 contain detailed information which describe the
20 sources of NOx emissions, various techniques for
21 controlling NOx emissions, and the costs of these
22 controls. The Illinois EPA used information
23 contained in the ACT as background information, but
24 relied on the information contained in the
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1 Regulatory Impact Analysis for the NOx SIP Call
2 published as part of the regulatory docket for the
3 NOx SIP Call, 63 Federal Register, 57356, October
4 27, 1998, the proposed Federal Implementation Plan,
5 hereafter called FIP, published at 63 Federal
6 Register 56394, October 21, 1998, and USEPA's
7 proposed findings on the various petitions filed
8 under Section 126 of the CAA, Section 126 Petitions,
9 published at 65 Federal Register, 2674, January
10 18th, 2000, for the costs and economic impacts of
11 today's proposal.
12 To determine the NOx emissions for the
13 existing large Illinois EGUs, the Illinois EPA used
14 the actual 1996 heat input data reported by the
15 existing emissions units to the Acid Rain Division
16 of the USEPA. The heat input of the fuel burning
17 equipment is the amount of heat energy, usually as
18 measured in millions of British thermal units,
19 hereafter called MMBTU, produced by the burning of
20 the fuel for a given period of time, usually an
21 hour. Base 2003 heat input values were calculated
22 by multiplying actual 1996 heat input with a
23 1996-2003 growth factor, which was calculated based
24 on the 1996-2007 growth factor of 1.08 as predicted
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1 by the USEPA's Integrated Planning Model, hereafter
2 called IPM. The 2003 base emissions were calculated
3 by multiplying the unit's base 2003 heat input with
4 an emission rate in pounds per million BTU and
5 divided by 2,000 pounds per ton. The emissions
6 rates used for calculations were the Acid Rain
7 Control limits and when the unit was not subject to
8 Acid Rain Control limit, an actual average 1996
9 emission rate reported by the sources to the USEPA
10 was used. The total 2003 base NOx emissions from
11 the existing impacted 103 EGUs were calculated to be
12 113,340 tons per control period.
13 The 2003 controlled NOx emissions from the
14 103 affected units by the proposal were calculated
15 by applying a proposed emission rate of 0.25 pounds
16 per million BTU to each unit's 203 -- sorry, 2003
17 heat input. The total regulated 2003 control period
18 NOx emissions were estimated to be 49,790 tons.
19 This represents a reduction of 63,550 tons of NOx
20 emissions or an average reduction of 56 percent from
21 the base 2003 NOx emission levels. Attachment A to
22 the TSD identifies each of the 103 impacted EGUs and
23 each unit's associated NOx emissions data.
24 The largest number of units affected by
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1 the proposal are coal-fired units which can be
2 classified as either dry bottom pulverized
3 coal-fired boilers or as cyclone boilers, with the
4 pulverized coal-fired boilers further classified as
5 to firing method either as tangentially-fired or as
6 wall-fired. These classifications are important
7 because each classification has different
8 characteristics uncontrolled NOx emissions and
9 control costs.
10 The units having the highest total NOx
11 emissions in Illinois are cyclone boilers. Cyclone
12 boilers are those in which crushed coal is fed
13 tangentially in a stream of primary air to a
14 horizontal cylindrical furnace. In a cyclone
15 boiler, much of the ash forms a liquid slag on the
16 furnace walls and must be drained to the furnace
17 bottom where it can be removed through a slag tap
18 opening. There are 22 cyclone boilers affected by
19 the proposed regulations, having projected base 2003
20 NOx emissions of 56,579 tons during the May 1
21 through September 30 control period.
22 The units having the second highest total
23 NOx emissions are tangentially-fired dry bottom
24 pulverized coal boilers having uncontrolled NOx
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1 emissions. Tangentially-fired units fire fuel in
2 burners mounted in a corner or in opposing corners
3 of a furnace with a rectangular cross section. The
4 fuel is called pulverized coal because the coal is
5 pulverized to the consistency of talcum powder in
6 mills designed for that purpose. The term dry
7 bottom refers to the fact that the furnace is
8 designed so that no ash collects in a liquid state
9 on its walls. There are no wet bottom pulverized
10 coal boilers in Illinois. Projected base 2003 NOx
11 emissions from the 34 tangentially-fired dry bottom
12 pulverized coal boilers affected by the regulatory
13 proposal total 43,047 tons during the control
14 period.
15 Wall-fired dry bottom pulverized coal
16 boilers are the third largest NOx emitting category
17 of units affected by the regulatory proposal.
18 Wall-fired units are similar to tangentially-fired
19 units except that the burners are mounted in a wall,
20 or in opposite walls, of the furnace rather than in
21 the corners. There are only eight wall-fired dry
22 bottom pulverized coal boilers affected by the
23 proposal with projected base 2003 control period NOx
24 emissions of 9,130 tons.
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1 The fourth NOx emitting category of EGUs
2 affected by the regulatory proposal is gas- and
3 oil-fired boilers. There are 25 gas- and oil-fired
4 boilers impacted by the proposal and which account
5 for 2,234 tons of 2003 base control period NOx
6 emissions.
7 The last category of EGUs affected by the
8 regulatory proposal is gas turbines. There are 14
9 existing gas turbines affected by the proposal and
10 they are generally used to meet peak electricity
11 demand. The total NOx emissions from this category
12 are 2,351 tons per 2003 base control period.
13 A number of NOx control technologies are
14 available to reduce NOx emissions from EGUs. They
15 can be either combustion controls or post combustion
16 controls. Combustion controls consist of changing
17 the circumstances of boiler or turbine combustion so
18 as to minimize the amount of NOx generated during
19 that combustion, while post combustion control
20 treats already generated combustion gases so as to
21 reduce those gases' NOx component to nitrogen and
22 water vapor.
23 Most combustion controls are designed to
24 prolong combustion at lower temperatures rather than
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1 quickly completing it at higher temperatures (called
2 stating the combustion), by creating combustion
3 zones that are fuel rich and thus oxygen poor, and
4 by creating lower overall temperatures. Combustion
5 control techniques include taking burners out of
6 service, hereafter called BOOS, to maintain a
7 staging atmosphere within the furnace, using low
8 excess air, hereafter called LEA, so as to limit the
9 contact between oxygen and nitrogen, and staging
10 combustion via biased firing, hereafter called BF,
11 of air-fuel rations in some burners, flue gas
12 recirculation, called FGR, which lower peak flame
13 temperature by adding a large mass of cool, inert
14 gas to the fuel air mixture, reducing air to the
15 primary burners and adding ports for overfire air,
16 and providing for reburning wherein a portion of the
17 fuel is burned in a second combustion area above the
18 main combustion area.
19 The most common single combustion control
20 technique, however, is the low NOx burner or LNB, a
21 burner especially designed to stage combustion and
22 to provide for lower combustion temperatures. LNBs
23 can achieve a 35 to 45 percent NOx reduction when
24 installed on tangentially-fired pulverized coal
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1 boilers, a 40 to 50 percent reduction when installed
2 on wall-fired pulverized coal boilers, and a 30 to
3 50 percent reduction when installed on gas- or
4 oil-fired boilers. The burner's NOx reduction
5 efficiency can be improved still further when used
6 in conjunction with other control techniques such as
7 OFA. LNBs, however, are not available for cyclone
8 boilers.
9 The only other single combustion control
10 technique that can equal, or even exceed, the
11 efficiency of Low NOx burner is reburn. Reburn with
12 natural gas is usually a more suitable technique
13 than reburn with coal or oil, even if those latter
14 fuels are the boiler's primary fuel. Reburn alone
15 is capable of achieving a 50 to 60 percent NOx
16 reduction from gas- to oil- and coal-fired boilers,
17 including cyclone boilers.
18 The other combustion control technique
19 besides reburn is low NOx burner, which can allow
20 gas- and oil-fired boilers to meet the proposed
21 regulatory requirements.
22 Gas- or oil-fired gas turbines can be
23 controlled by the injection of either water or steam
24 into the intake of the turbine. This control
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1 technique retards NOx formation by lowering the
2 operating temperature of the turbine and can provide
3 a 70 to 90 percent reduction in NOx emissions, which
4 may be sufficient to meet the requirements of the
5 regulatory proposal. A special retrofit firing
6 configuration, known as the low NOx combustor, is
7 available for some gas turbines. This technique can
8 provide a 60 to 90 percent reduction in NOx
9 emissions.
10 Two post-combustion control techniques
11 that are available for fossil-fuel-fired boilers are
12 selective non-catalytic reduction, hereafter called
13 SNCR, and selective catalytic reduction, hereafter
14 called SCR. Both these techniques are called
15 reduction techniques because the NOx is reduced back
16 to elemental nitrogen and oxygen with the oxygen
17 combining with hydrogen to form water in the
18 process.
19 Both techniques are called selective
20 because both specifically select NOx for reduction
21 unlike the catalytic reduction that is applied to
22 the exhaust of motor vehicles and which reduces a
23 wide variety of pollutants. In both SNCR and SCR,
24 ammonia, a compound of nitrogen and hydrogen, is
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1 made to react with NOx in order to liberate the
2 nitrogen from each reactant and produce gaseous
3 nitrogen and water. In SNCR, urea, another nitrogen
4 and hydrogen compound, which also contains carbon,
5 is often used instead of ammonia.
6 The advantage of SNCR over SCR is cost,
7 because the SNCR reactions take place without the
8 use of a catalyst, the chief component of the cost
9 of an SCR system. The disadvantages of SNCR are
10 that it effectively operates over a rather narrow
11 range of temperatures which may not be appropriate
12 for some boilers, that it is difficult to control
13 the loss of ammonia, an air pollutant in its own
14 right, to the ambient air atmosphere, and that its
15 NOx removal efficiencies, 30 to 60 percent, compare
16 unfavorably with SCR's 75 to 85 percent NOx removal
17 efficiencies for coal-fired boilers.
18 In general, gas- and oil-fired boilers
19 SNCR's reduction efficiencies are even poorer, 25 to
20 40 percent, while SCR's efficiencies are even
21 better, 80 to 90 percent. SNCR may not be suitable
22 for gas turbine applications, while SCR is capable
23 of providing 90 percent NOx reductions for such
24 turbines.
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1 Th TSD for this proposal has a summary of
2 the costs of various NOx control technologies and
3 their combinations under various load conditions
4 based on the information contained in the ACT
5 documents. The costs of combustion controls for
6 gas- and oil-fired boilers vary widely depending
7 upon the size of the unit, the load conditions, and
8 the type of control technology employed. Table 5-2
9 in the TSD provides a summary of the large variety
10 of cost effectiveness values for the NOx control
11 options for these boilers. For gas turbines that
12 continue to operate as peakers, the most likely
13 control that would be utilized is water and steam
14 injection. The cost effectiveness range for this
15 control option is $1,210 to $2,350 per ton of NOx
16 removed. If these units are used more often than as
17 peaking units, the cost per ton would be less.
18 Control costs for coal-fired boilers
19 relying on SNCR technology also vary widely for base
20 load units with an average range of cost
21 effectiveness of $725 to $880 per ton of NOx
22 reduced. Control costs relying on SCR technology
23 have a similar average range of cost effectiveness
24 of $1,035 to $2,035 per ton for base load units.
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1 In order to estimate the cost
2 effectiveness of the proposal, Illinois EPA is
3 relying on USEPA's cost data presented in the
4 Regulatory Impact Analysis for the NOx SIP Call.
5 USEPA analyzed the results of cost effectiveness
6 based on the .15 uniform alternative without trading
7 between sources within state boundaries. The cost
8 difference between uniform alternative with
9 interstate trading and without interstate trading is
10 approximately two percent. If states adopt
11 rate-based approaches, the cost could be expected to
12 be higher. The RIA document indicated that costs
13 could be as much as 30 percent higher if trading is
14 restricted.
15 Table 5-4 of the TSD shows the various NOx
16 emissions reductions levels and the annual costs and
17 cost effectiveness that the USEPA estimates for the
18 potentially affected part of the electric power
19 industry in the years 2003, 2005, 2007 and 2010. As
20 shown in the table, the average costs per control
21 season ton of NOx is removed under the 0.25 uniform
22 alternative with trading for 2003 is $1,127 per ton
23 of NOx removed. The Illinois EPA used this
24 information and estimated the cost effectiveness to
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1 comply with its proposal of 0.25 pounds per million
2 BTU rate-based NOx emission standard with no cap and
3 trading program to be $1,465 (1990 dollars) per ton
4 of NOx reduced in a 2003 control period, an increase
5 of 30 percent in the average cost effectiveness
6 under the 0.25 uniform alternative with trading.
7 The Illinois EPA believes that the cost estimates
8 are conservative. The proposal allows emission
9 averaging among the Appendix F EGUs and certain
10 units at Soyland Power. The Illinois EPA
11 anticipates the cost effectiveness of this proposal
12 to be much less than the estimated cost
13 effectiveness of $1,465 per ton of NOx reduced when
14 the affected sources participate in the mutually
15 agreed upon NOx averaging plans.
16 In summary, the results of Illinois EPA's
17 modeling and analysis indicates that an emission
18 rate of 0.25 pounds per million BTU for large EGUs
19 is sufficient to demonstrate attainment of the
20 one-hour ozone standard in the Metro-East/St. Louis
21 area. All of these controls are assumed to be in
22 place by May 1, 2003.
23 The Illinois EPA has relied on the
24 information contained in the NOx SIP Call and
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1 USEPA's guidance documents in developing the
2 proposed Subpart V that requires the NOx emissions
3 from large EGUs greater than 25 megawatts of
4 electricity capacities to meet a rate-based NOx
5 emission limit of 0.25 pounds per million BTU. The
6 requirements of the proposed regulations will impact
7 103 existing emission units in Illinois and will
8 result in an overall 56 percent reduction in base
9 2003 NOx emissions or a total of 63,550 tons of NOx
10 reduced per ozone season. A number of control
11 technologies are available to allow sources to meet
12 the required level of control, although it is
13 anticipated that the most likely control will be the
14 use of combustion controls and some SCR or SNCR or
15 some combination of such technologies. The cost
16 effectiveness of NOx controls to meet the reduction
17 requirements of the proposed rule has been
18 determined to be, in 1990 dollars, $1,465 per ton of
19 NOx reduced. Thank you, Mr. Mahajan.
20 HEARING OFFICER BEAUCHAMP: All right. Ms.
21 Herst, does the Agency have anything further they'd
22 like to offer in support of this proposal?
23 MS. HERST: No.
24 HEARING OFFICER BEAUCHAMP: All right. We're
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1 going to break for lunch then. I have ten after one
2 on my watch now. An hour and 15 minutes from now
3 will be 2:25 and we'll break for lunch and reconvene
4 at 2:25. I guess we'll break for lunch and we'll
5 reconvene at 2:30 to make it even.
6 (Whereupon, after a short
7 break was had, the
8 following proceedings
9 were held accordingly.)
10 HEARING OFFICER BEAUCHAMP: Before we enter the
11 question period, Ms. Herst, does the Agency have any
12 other matters they'd like to introduce before?
13 MS. HERST: Yes. Mr. Lawler is going to speak
14 a little bit on our economic and budgetary analysis.
15 HEARING OFFICER BEAUCHAMP: Thank you,
16 Mr. Lawler.
17 MR. LAWLER: Yes. We had a few words we wanted
18 to say about the document entitled "Agency Analysis
19 of Economic and Budgetary Effects of Proposed
20 Rulemaking" and the statement we wanted to make is
21 contrary to the original submittal of this document,
22 the Agency does anticipate that the rulemaking will
23 result in an increase in costs to the Agency in the
24 implementation of these regulations.
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1 The Agency did not originally indicate
2 that there would be additional costs to the Agency
3 because we did not believe that we'll be able to
4 obtain additional monies to pay for the
5 implementation efforts and because no specific
6 technical support or equipment is needed. However,
7 it is more accurate to indicate that these costs
8 will occur and to make a general estimate of the
9 cost.
10 The Agency will submit a formal change to
11 this document after completion of the first round of
12 hearings. The preliminary estimate based on
13 full-time equivalent work years and other materials
14 is 300,000 to $400,000 the first fiscal year
15 expected to be the state fiscal year FY03. This
16 represents time spent in revising permits,
17 monitoring compliance, reviewing reports and so
18 forth. This should decline somewhat after the first
19 year.
20 As I indicated, a more refined estimate
21 will be submitted later. The other aspects of the
22 submittal will be unchanged and are based on cost
23 estimates performed by the USEPA.
24 HEARING OFFICER BEAUCHAMP: Very good. Thank
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1 you. Any other matters before we go to the question
2 period?
3 MS. HERST: No.
4 HEARING OFFICER BEAUCHAMP: Thank you. As a
5 preliminary matter, I note that you've got a few
6 members up on your panel who have not yet been sworn
7 in. If we can have the court reporter swear them in
8 before we begin.
9 MS. HERST: I think they were all sworn the
10 first round. They didn't testify, but they --
11 HEARING OFFICER BEAUCHAMP: Okay. Well, then
12 that's taken care of.
13 We will now proceed with questions for the
14 Agency witnesses. As I previously mentioned, if you
15 have a question for the Agency witnesses, please
16 raise your hand and wait for me to acknowledge you.
17 When I do acknowledge you, please state your name
18 and the organization you represent, if any.
19 Are there any questions for the Agency
20 witnesses? And let me apologize at the outset, I'm
21 a little bit newer to the whole process than maybe
22 some of the other Board members are so I'm not so
23 familiar with people. I'm sure after the three days
24 here, I will be. Your name first?
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1 MR. MILLER: My name is Scott Miller, Midwest
2 Generation, Chicago.
3 When the rule was being drafted, we
4 commented on combustion turbine peaking units and
5 exemptions being provided in the rule. Part of the
6 testimony mentions 14 existing gas turbines. I
7 think we own 12 of those.
8 THE REPORTER: Could we have them step up if
9 they are going to speak?
10 HEARING OFFICER BEAUCHAMP: Could we get you to
11 step up or move your chair towards the center or
12 speak up so the court reporter can hear you a little
13 better?
14 THE REPORTER: Thank you.
15 MR. MILLER: My question concerns existing
16 combustion turbines. The testimony stated there
17 were 14 that are affected by the rule. I think we
18 own 12 of those. I've looked at the records over
19 the last few years. They've only operated about one
20 to 200 hours per year each. That's why we asked for
21 an exemption based on a capacity factor of less than
22 five percent.
23 If we put them in, we probably wouldn't
24 put in control technologies. We have averaged those
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1 using the averaging rule. However, the monitoring
2 is very strict, Part 75 monitoring, require fuel
3 full filled monitors and a lot of electronics all
4 hooked up to a data acquisition system. Since Part
5 75 reporting is the protocol, it would add an
6 additional burden of keeping all the records and
7 doing all the recording on our Part 75.
8 HEARING OFFICER BEAUCHAMP: I'm sorry,
9 Mr. Miller. Could I ask that we pause for a moment
10 so that the court reporter can swear you in?
11 Please swear him.
12 THE REPORTER: Do you swear to tell the truth,
13 the whole truth and nothing but the truth so help
14 you God?
15 MR. MILLER: Yes.
16 HEARING OFFICER BEAUCHAMP: Sorry. Thank you.
17 Please continue.
18 MR. MILLER: So I guess I thought it was
19 reasonable to at least exempt these small peakers
20 using an exemption similar to a 1992 draft rule for
21 NOx RACT. That would exempt these small turbines.
22 My calculations show that they only emit about 200
23 tons per year. I think the testimony had a couple
24 thousand tons per year for all four units. So I
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1 thought five percent was a reasonable cut off, but I
2 know there's another rule that would require us to
3 put it in the SIP Call, but I think you have to look
4 at this rule. It's a .25 rule for a one-hour
5 nonattainment. We don't know the future of the SIP
6 Call. It would be a large burden to have these low
7 capacity factor units into the coal combustion
8 turbine peaking units, which we own 14. I'm sure
9 it's most of these 12 out of the 14. The Agency
10 mentions that it was reasonable to include these
11 large units in the program, the low capacity factor.
12 MR. LAWLER: The point you raised is one that
13 we did consider seriously and we talked with you
14 about it and others as we went ahead with this
15 rulemaking, but I think you raised one of the points
16 which is that it will be required by Subpart W also
17 as part of the SIP Call and so we think it's
18 reasonable from that standpoint.
19 Also, these are -- they're large units and
20 they certainly could operate more often than a few
21 hundred hours a control period and so rather than
22 take the chance that we don't -- that we aren't
23 monitoring -- that we aren't sufficiently monitoring
24 for these, we thought it was reasonable to go ahead
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1 and put them in. Again, they're big units and they
2 have the potential to operate a lot more than they
3 do.
4 MR. ROMAINE: And I could supplement one other
5 point, because these are peaking units, the rule in
6 Section 217.710 does specifically allow that they
7 determine their NOx emissions by fuel-filled
8 monitors. They are not required to install the more
9 expensive continuous emission monitoring. So they
10 are subject to a less extensive methodology for
11 determining emissions. So that factor is already in
12 there as well.
13 MR. MILLER: I agree with that. The
14 recordkeeping and the reporting are also another
15 factor for Part 75. You have to have the computer
16 operating system, you have to do electronic
17 reporting with certain record types and then all the
18 data has to be checked before it's submitted if you
19 are going to use a Part 75 protocol and for 12 units
20 for measuring only a few hundred tons, it's a huge
21 burden. I'd rather spend the money on my 20 large
22 units. It would be a better bet on those. Probably
23 the noise of the air of the 16 of my 20 units would
24 be -- wouldn't be worth the time in general for a
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1 few hundred times on a smaller unit.
2 I could recommend that maybe we add
3 another protocol to the monitoring. If we submit a
4 monitoring plan that's similar to Part 75, that
5 would capture the information. Part 75 does give
6 you a default emission rate for the NOx. I could
7 take that times 100 hours and come up with a real
8 accurate number instead of spending hundreds of
9 thousands of dollars to follow Part 75 protocol.
10 That's another option, something other than Part 75
11 to monitor emissions for low emitting units.
12 HEARING OFFICER BEAUCHAMP: Thank you,
13 Mr. Miller.
14 MS. McFAWN: Oh, Mr. Miller, before you leave,
15 did you have any other questions for the Agency?
16 MR. MILLER: No.
17 MS. McFAWN: Could I just ask, I was listening
18 and I might not have grasped everything you had to
19 say. You mentioned the cost for the monitoring and
20 that's seems to be one of your major if not -- is
21 that your major concern?
22 MR. MILLER: Yeah. That's the major point.
23 MS. McFAWN: And then you said it would cost
24 hundreds of thousands of dollars. Would that be per
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1 unit or collectively?
2 MR. MILLER: That would probably -- for each
3 site, I would say 100,000 per site.
4 MS. McFAWN: Per site being per peaker unit
5 or --
6 MR. MILLER: One site has eight peakers. One
7 site has four. The rule does allow to not measure
8 fuel at our common site. So you wouldn't have to
9 monitor eight separate fuel meters. The electronics
10 to get all that into a computer based system that
11 has to follow the EPA protocol for Part 75 is where
12 the manpower dollars go.
13 The capital cost would be about 100,000
14 per site, but the O & M would be burdensome. You're
15 adding maybe a half -- you're doubling the work of
16 the -- of each site to track these emissions. When
17 you're in Part 75, you have to record not only when
18 the one unit is operating, but when it's not
19 operating. Those hours -- you have to have -- send
20 a signal to the computer to tell that the unit is
21 off for every hour during the ozone season. All
22 I'll ask is that it be quality assured before it's
23 submitted to the Agency if you're going to use Part
24 75 recordkeeping and reporting. There's a lot
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1 easier ways to do it for the amount of emissions
2 since they're such low emitters. That's why I
3 recommended five percent cut off for capacity
4 factor.
5 MS. McFAWN: All right. And you said there's
6 an easier way to do it. You mean the exception or
7 an exemption or do you mean that there's an easier
8 way than Part 75?
9 MR. MILLER: Yes. There's an easier way than
10 Part 75.
11 MS. McFAWN: To part 75?
12 MR. MILLER: An easier way.
13 MS. McFAWN: And you mentioned you could
14 propose such an alternative to the Agency and to the
15 Board?
16 MR. MILLER: Yes.
17 MS. McFAWN: Is that something the Agency could
18 entertain?
19 MR. LAWLER: Yes.
20 MS. McFAWN: Yes. Perhaps through the course
21 of these hearings, you could work together on that
22 and maybe propose something to the Board or submit
23 it to the Board independently or collectively and
24 also, I think the Board would be very interested in
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1 the costs you estimated because even just in these
2 few questions, I learned a lot more, but not the
3 hard dollars.
4 I also have another question. The Agency
5 mentioned that you will be subject to the NOx rules,
6 the NOx SIP Call rules. I think you mentioned the
7 same thing. I assume that means to Subpart W. Is
8 that what you were referring to?
9 MR. MOORE: Yes.
10 MS. McFAWN: The Agency is indicating yes.
11 So does that mean the money you invest,
12 should you equip these with monitors, fuel monitors,
13 these sites, would that be money that you will have
14 to invest in 2004 because of Subpart W?
15 MR. MILLER: With Subpart W there's no option.
16 So I guess I would have to invest the same amount of
17 dollars.
18 MS. McFAWN: Okay. So you're just really
19 seeking to put that off a year?
20 MR. MILLER: Yeah. And I mentioned that you
21 have to look at this rule as a separate rulemaking.
22 We don't know the future of Subpart W.
23 MS. McFAWN: That's correct.
24 MR. MILLER: One way you could look at it, yes,
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1 I'm putting the costs off for a year and another way
2 I'm looking at it as it's burdensome to put this
3 monitoring on a peaking unit, an existing peaking
4 unit.
5 MS. McFAWN: That's a valid point.
6 MR. MILLER: Subpart W had some options. I'd
7 probably pursue that --
8 MS. McFAWN: Okay.
9 MR. MILLER: -- Part 96 protocol so...
10 MS. McFAWN: Versus the Part 75?
11 MR. LAWLER: Yes. Part 96 and 75 work together
12 with Subpart W, so there's really no options for
13 more monitoring. However, this rule the Agency --
14 Part 75 is a good rule. It's going to give you real
15 accurate emissions. That's probably what the Agency
16 was thinking with this rulemaking, but I think for
17 units that run maybe one or 200 hours a year at low
18 capacity factors there can be alternatives.
19 MS. McFAWN: All right. And that would be what
20 you would be investigating if you and the Agency
21 were to talk about alternatives to Part 75?
22 MR. MILLER: Yes.
23 MS. McFAWN: Thank you for answering those
24 questions.
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1 MR. MILLER: Sure.
2 HEARING OFFICER BEAUCHAMP: Thank you,
3 Mr. Miller.
4 Other questions for the Agency?
5 Mr. Rieser?
6 MR. RIESER: David Rieser with the law firm of
7 Ross & Hardies. I'm here on behalf of Amerem. Can
8 you hear me okay?
9 I have a couple of questions about the
10 language in the proposal and some other issues.
11 Turning to 217.706A the standard is based on a,
12 quote, control period average, unquote, for that
13 unit.
14 What's the definition for a control period
15 average? Is that defined in the rules? Are there
16 rules adopted by the Board?
17 MR. MOORE: Okay. Well, that is -- the control
18 period average would be the average emissions in
19 pounds per million BTU over the entire control
20 period. So that it would be determined -- for an
21 individual unit, it would be determined by dividing
22 the number of pounds of NOx that were emitted during
23 a control -- during the entire control period by the
24 number of million BTU of heat input sustained
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1 throughout the entire control period.
2 MR. RIESER: Thank you. With respect to the
3 NOx averaging described in 708, how is that intended
4 to work administratively?
5 MR. ROMAINE: I guess, do you have specific
6 areas that you're interested in or just very
7 generally?
8 MR. RIESER: Well, for example -- let's start
9 with the general and let's go to the specific. I
10 mean, you've got two -- is it two sources come to an
11 agreement and then go to the Agency and have permits
12 written for each of them that embody that agreement
13 or how is that going to work in practice?
14 MR. ROMAINE: I think I'm going to back up and
15 say we believe that there's nothing in these rules
16 that really requires us to review a particular
17 averaging plan as such.
18 Our concern is simply to make it clear
19 that a particular unit qualifies for averaging, it's
20 on the list and that there's an understanding of how
21 relevant information has to be submitted. So the
22 thought would be that they would apply to us in a
23 federally enforceable permit, we review that they're
24 on the list, we'd agree what the appropriate
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1 procedures would be for confirming data substitution
2 and also the administrative details of the process
3 and beyond that, the identification of particular
4 averaging plans could be something that could be
5 submitting for the actual compliance report.
6 So it's really an authorization to perform
7 averaging that would be made in the permit. It
8 would not be a review of a particular averaging
9 plan.
10 MR. RIESER: So the permit itself would specify
11 an emission rate that might be different than .25?
12 MR. ROMAINE: No. There's no reason even for
13 the permit to do that. It would simply say this
14 unit is qualified to perform averaging. It's on the
15 list. There are some fine, you know, clarifying
16 conditions to make it as data substitution
17 provisions and the Acid Rain Program apply and that
18 averaging compliance reports have to be submitted by
19 a responsible official. If there are several
20 parties, you need responsible officials from all the
21 parties, but there wouldn't be as elaborate
22 averaging provisions as you might find in the Acid
23 Rain Program.
24 We're trying to keep this very simple and
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1 we have confidence that the Acid Rain Program gives
2 excellent emission data. The data should be there,
3 if we could just have the appropriate reports and
4 signatures filed with us by November 30th of each
5 year.
6 MR. RIESER: So the averaging really isn't
7 embodied in the permit other than the authorization
8 to use it as a method for evaluating and determining
9 compliance that the November 30th report date that
10 you got set in this rule?
11 MR. ROMAINE: That's correct.
12 MR. RIESER: Subpart -- excuse me, Subsection
13 (f) of 708 says if averaging is used to demonstrate
14 compliance, the effect of the failure to demonstrate
15 compliance shall be the compliance status of each
16 EGU pursuant to Section 217.706A as if the NOx
17 emission rates of such EGU were not averaged.
18 What is that intended to do, that section?
19 MR. MOORE: As I said in my testimony, it
20 simply provides that overcomplying units are in
21 compliance with the rule and undercomplying units
22 are undercomplying by the magnitude of their
23 undercompliance.
24 For example, I talked about a unit that
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1 might average .35 pounds per million BTU and a unit
2 that might average .15, but suppose it turned out
3 that one of the units emitted a little more, say,
4 the 0.15 pound unit emitted 0.16, that would throw
5 the undercomplying unit out of compliance.
6 Similarly, of course, the overcomplying
7 unit could be emitting its authorized -- expected,
8 let's say, 0.15, but the undercomplying unit would
9 be emitting at a little more than .035 (sic). It
10 could work either way, but if compliance is not
11 shown by averaging, the overcomplying unit is home
12 scott-free as long as it's not in itself above .25
13 and the undercomplying unit is undercomplying by
14 whatever its actual emission rate differs from 0.25.
15 MR. RIESER: So would the undercomplying unit
16 in that example, say the unit that's emitting a .25
17 rate, be treated for enforcement purposes exactly
18 the same as another unit that was emitting .25 that
19 hadn't -- didn't include an averaging plan as part
20 of its permit?
21 MR. MOORE: Yes.
22 MR. RIESER: So even though it had worked with
23 another company to develop the averaging plan used
24 as a compliance methodology, it would be treated the
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1 same as --
2 MR. MOORE: Right. It's grievance would be
3 against the company that failed to provide
4 sufficient --
5 MR. ROMAINE: I guess that's the answer in
6 terms of how it would be treated under the rule.
7 Obviously, we can't speak to how the actual
8 enforcement action would be pursued in this
9 particular case.
10 MR. RIESER: Okay. Well, if you can't speak to
11 that, what's the purpose of this particular section
12 because it seems to identify a particular -- make a
13 particular statement about units that use certain
14 compliance methodologies and how they're to be
15 treated as opposed to other units that are also out
16 of compliance for entirely different reasons?
17 So I guess the point is what's -- why are
18 these companies singled out in this way and this
19 particular statement made?
20 MR. LAWLER: I guess, maybe to follow through
21 on the other answers, the options you would have
22 here would be to say that both entities that
23 participated in this averaging could be considered
24 out of compliance because the average itself was out
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1 of compliance and what we're trying to do here is
2 say that obviously if there was one of the companies
3 or one of the units that is overcomplying, there's
4 no reason to think he would be enforced against or,
5 you know, that would be the logical approach and so
6 it would be the unit that really is not meeting the
7 .25 limit that's at risk, if they do something like
8 this.
9 MR. RIESER: So there really is not an attempt
10 by the Agency to include as one of the factors for
11 evaluating, say, penalties that one company had an
12 averaging plan that didn't work and another company
13 didn't have an averaging plan at all?
14 MR. LAWLER: We're not trying to get into --
15 in -- by this particular statement what penalties
16 would or wouldn't be -- you know, would or wouldn't
17 be applied to the situation, but we want to try to
18 differentiate between the two different units
19 because one made it and one didn't.
20 MR. RIESER: So what you're really saying is
21 it's the -- just reminding people that the
22 overcomplying unit that was subject to an averaging
23 plan that failed, as long as they're meeting the .25
24 limit, they're still in compliance?
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1 MR. LAWLER: That's right.
2 MR. RIESER: Looking again at 708C, you say
3 averaging under the subpart must be authorized
4 through federally enforceable permit conditions for
5 such EGU. Am I correct, Mr. Romaine, based on your
6 statement that what those conditions will be is a
7 section in the permit that will simply authorize the
8 use of averaging not the establishment of the
9 different emission level than .25?
10 MR. ROMAINE: That's correct. That's my
11 understanding and that's what the language
12 specifically says, averaging must be authorized. It
13 does not provide for review of a specific averaging
14 plan. It certainly does not provide for an
15 averaging plan that has to be reviewed and revised
16 every time the plan changes.
17 MR. RIESER: Thank you.
18 MS. McFAWN: Do you have to identify who you'll
19 be averaging with?
20 MR. ROMAINE: No. Well, not in times of the
21 permit. Obviously, when you submit your compliance
22 demonstration we'll obviously have to know who the
23 team is.
24 MS. McFAWN: Thank you, Mr. Romaine.
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1 MR. RIESER: Well, let me clarify that, so when
2 you submit your permit application or modification
3 that says you intend to use averaging as a
4 compliance methodology, you don't have to say in
5 that modification who you're averaging with or
6 whether or not you have an averaging agreement?
7 You're simply saying that that will maybe be one of
8 the mechanisms that you would use for achieving
9 compliance, is that correct.
10 MR. ROMAINE: That's my understanding, yes.
11 MR. RIESER: And so the only time you really
12 have to identify who you're averaging with is if at
13 the November 30th report date, of course, that
14 person can't average with somebody else or use the
15 same credits for averaging.
16 MR. ROMAINE: That's correct.
17 MR. RIESER: I think you addressed the Agency
18 about the statement of reasons, but I need to ask it
19 here anyway, why is the averaging limited to
20 Appendix F sources?
21 MR. LAWLER: I think this was -- probably was
22 addressed, but it's limited to Appendix F sources
23 because these are the larger sources in the state
24 from one standpoint. Secondly, the air quality
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1 analyses that were done assumed that it was these
2 sources that met the .25 limit in the modeling that
3 Rob explained a little bit earlier.
4 MR. ROMAINE: And I can add to that, the
5 purpose of this rule is to reduce emissions. If we
6 allowed averaging from new units that are developed,
7 they almost certainly will have emission rates that
8 are well below .25 pounds per million BTU. So by
9 adding a new unit that adds emission to the
10 atmosphere would -- if it were allowed to average,
11 perpetuate higher emissions and our goal is, in
12 fact, to average across existing emission units to
13 get reductions overall to .25 pounds per million BTU
14 pursuant to this rule.
15 MR. RIESER: What happens with this rule if and
16 when Subpart W becomes effective? Is there any
17 coordination between the two or how would things
18 work?
19 MR. LAWLER: The rule is written that it will
20 stand. This rule, once adopted, would just become
21 effective.
22 MR. RIESER: When -- if and when Subpart W
23 becomes effective, are there issues of coordination
24 between the two rules?
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1 MR. LAWLER: I'm not sure I understand your
2 question. Are there -- is there coordination
3 between the two rules, but a company would have to
4 meet both rules. Our general thought is that if
5 they meet the .15 rule -- they meet -- I'm sorry,
6 they meet the NOx SIP Call rule, which is Subpart W
7 rule, in almost all instances they would be meeting
8 this one, too, or we would assume that they'll be
9 meeting this one also.
10 MR. RIESER: Certain provisions are made in the
11 rule for Soyland Power. I am interested in who they
12 are and what the basis for this specific
13 identification of them is.
14 MR. ROMAINE: Soyland Power is a real
15 cooperative entity. Recently it developed its own
16 peaking station in Alsey, Illinois, which is a
17 little bit southwest of Jacksonville. They, in
18 fact, purchased used turbines from I think a utility
19 in Arizona. Their turbines, given their age, cannot
20 comply with the .25 pounds per million BTU per hour
21 limit. They would otherwise qualify as new units
22 for purposes of Illinois. The only realistic way
23 for them to operate in compliance with this rule
24 would be to undertake emission averaging. We would
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1 not expect it to be feasible for them to do the
2 measures to actually reduce the emissions from their
3 units given their age and again, they're in the
4 operations of peaking facilities. So the purpose of
5 this was to accommodate that very special
6 circumstance of this real cooperative and purchased
7 used equipment that for Illinois purposes counts as
8 new, but will nevertheless have to average to
9 demonstrate compliance.
10 MR. RIESER: Did any of their units commence
11 operation as of January 1st, 2000?
12 MR. ROMAINE: I believe so.
13 MR. RIESER: There was testimony from
14 Mr. Kaleel this morning regarding part of the
15 attainment demonstration for Metro-East was --
16 included in that was in the necessity for Missouri
17 to adopt its own standards applying both to the
18 eastern west half or two-thirds of the state. Where
19 is Missouri in that process?
20 MR. KALEEL: Missouri has completed their
21 rulemaking that would implement or require the
22 limits that I had shown on my slide, the .25 pounds
23 per million BTU in the eastern one-third, .35 pounds
24 per million in the western two-thirds. They
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1 completed that rulemaking this past spring and it
2 requires an implementation date of 2003, and
3 effective date.
4 MR. RIESER: In Mr. Lawler's last statement he
5 talked about the potential for additional costs
6 associated with the adoption of those -- of this
7 rule. I, unfortunately, I don't recall from Subpart
8 W proceedings whether these are more different in
9 addition to the Subpart W anticipated costs or how
10 they relate to what costs were anticipated with the
11 implementation of Subpart W.
12 MR. LAWLER: Well, the point that I was making
13 was that the cost to the Agency to implement the
14 regulations -- I don't remember what we had in there
15 for Subpart W, but the concept would be the same
16 that -- I mean, obviously there will take -- there
17 will be some resources within the Agency that would
18 have to be dedicated to implementing this particular
19 set of rules, but we may not be given any additional
20 resources from either the state or the federal
21 government to do that. So it makes it a little hard
22 to make these estimates when you're just going to
23 have to absorb it. That was the point that I wanted
24 to make in that.
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1 MR. RIESER: I don't have anything further.
2 Thank you very much.
3 HEARING OFFICER BEAUCHAMP: Thank you,
4 Mr. Rieser. Are there any other questions for the
5 Agency? Yes, sir?
6 MR. MURRAY: My name is William Murray. I'm
7 with the City of Springfield office of public
8 utilities and we're affected sources.
9 THE REPORTER: Could you please stand up here?
10 Thank you. There's an echo.
11 MR. MURRAY: I'd like to try to clarify a
12 couple of the items in the prefiled testimony.
13 Mr. Kaleel, in the last sentence of the first full
14 paragraph of page five of your prefiled testimony
15 you say implementation of the NOx SIP Call in 2004
16 should help to maintain ozone levels in years after
17 the area's 2003 attainment date. Are you inferring
18 that this proposal would not be sufficient to
19 maintain attainment after 2003?
20 MR. KALEEL: I guess what I was saying there is
21 that the NOx SIP Call will provide additional
22 benefit to the area and it will help keep the area
23 in attainment.
24 MR. MURRAY: A cushion so to speak?
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1 MR. KALEEL: Kind of a cushion, yeah.
2 MR. MURRAY: Okay. Mr. Lawler, I have a couple
3 questions on your testimony that was prefiled. On
4 pages two and three you discussed the possibility of
5 USEPA extending the attainment deadline to May 2004.
6 If this extension was instituted and how does that
7 relate to the pending litigation regarding the bump
8 up? I believe it's the Sierra Club case.
9 MR. LAWLER: First of all, you're correct or at
10 least our understanding of what USEPA is considering
11 at this point is whether to change attainment dates
12 for areas like St. Louis to the 2004 date instead of
13 the 2003 date and it is something that they're
14 working on and they're considering and their legal
15 folks are trying to figure out whether it's the
16 right thing to do or not the right thing to do, but
17 even if they should end up doing that as far as the
18 court case that you mentioned, the Sierra Club court
19 case, we don't know if the Court would end up
20 accepting that 2004 date as the new attainment date
21 for Metro-East. So we feel that the state would
22 still be at risk for getting a bump up in the
23 Metro-East because the Court could do -- end up
24 doing anything. The Court may not listen to EPA
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1 even if EPA ends up doing this. So we sort of think
2 that we're taking maybe the responsible position or
3 prudent position at this point to keep the area from
4 being bumped up.
5 MR. MURRAY: Okay. So in other words, even if
6 the extension were to be granted, barring the Court
7 making some rulings on that extension, you would
8 think the Board would still need to proceed with
9 Subpart V?
10 MR. LAWLER: That's correct.
11 MR. MURRAY: Okay. And continuing on a line
12 that Mr. Rieser was asking you about the interplay
13 between Subpart V and Subpart W assuming all the
14 contingencies that would bring Subpart W in full
15 effect for example 9.9 of the Equal Protection
16 Act -- or the Environmental Protection Act, in
17 Illinois if all of those contingencies played out I
18 believe your testimony was that in all cases you
19 thought that if you -- a utility was in compliance
20 with Subpart W that they would be in compliance with
21 Subpart V?
22 MR. LAWLER: Well, you changed my words a
23 little bit there, but --
24 MR. MURRAY: Well, you said in most instances.
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1 MR. LAWLER: We probably never should say
2 never, but we think certainly in almost all cases or
3 maybe all case --
4 MR. ROMAINE: I want to jump in. I'm sure you
5 can come up with an exception where that wasn't the
6 case.
7 MR. MOORE: Right.
8 MR. MURRAY: Then I understand the answer to be
9 that in spite of the budget number that we have
10 under Subpart W that's based on an 8 percent growth
11 factor and I believe there was a lot of testimony in
12 the Subpart W hearings to the effect that in
13 Illinois the utilities would actually be in
14 compliance with a level or emission rate much lower
15 than .15, and your opinion would still be there
16 might be a possibility that there will be somebody
17 out there that still could not have to comply with
18 Subpart V and still comply with Subpart W?
19 MR. MOORE: Sure.
20 MR. LAWLER: I guess it's possible.
21 MR. MURRAY: So would it be your testimony that
22 there would be no need to repeal Subpart V at any
23 time or include sum sort of self-repealing provision
24 within it should Subpart W become fully effective?
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1 MR. LAWLER: Well, we think that Subpart V
2 should end up staying there and for a number of
3 reasons that we've all been either talking to or
4 talking around. There are a lot of -- there are
5 legal challenges that are still out there for the
6 NOx SIP Call and there's a lot of other reasons
7 that -- it's probably good from the Metro-East
8 standpoint to have a certain degree of certainty out
9 there because we don't know.
10 MR. MURRAY: I understand that. I was
11 referring to if all those contingencies had come to
12 pass and we have Subpart V, full proof, unchallenged
13 with Subpart W, would there still be a need for
14 Subpart V?
15 MR. LAWLER: I guess we believe we'd be more
16 comfortable with it staying, yes.
17 MR. ROMAINE: Given the nature of things I
18 think it would be appropriate to do it with a
19 separate rulemaking if you did decide to repeal it.
20 Just the nature of the legal system is such that who
21 knows what the circumstance will be in the future.
22 MR. MURRAY: And just so the record will kind
23 of reflect what I'm getting to, would you agree
24 there would be two sets of recordkeeping, reporting
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1 requirements under the rules that are different for
2 the regulated community?
3 MR. ROMAINE: Yes. Clearly one of the problems
4 with saying you wouldn't have contradictions is the
5 budget is based on a mass number of tons,
6 allowances, where the rate-based rules is intact,
7 the rate in terms of pounds per million BTU, you
8 might meet the pounds per million BTU and not meet
9 the times. You might meet the times and slightly go
10 over the rate.
11 MR. MURRAY: Yeah. But in the reports that the
12 utilities would have to file would be actually
13 different for each rule?
14 MR. ROMAINE: Yes.
15 HEARING OFFICER BEAUCHAMP: Do you have any
16 further questions, Mr. Murray?
17 MR. MURRAY: No. Are there any other questions
18 for the Agency witnesses?
19 THE REPORTER: Could he step up?
20 HEARING OFFICER BEAUCHAMP: You might have to
21 step up, sir.
22 MR. RODRIQUEZ: I just have one question. For
23 the record Gabe Rodriguez, I'm an attorney for
24 Dynergy Midwest Generation. The only question I
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1 have really is a follow-up to Mr. Rieser's as well
2 as about this interplay between Subpart V and
3 Subpart W. The question is is whether the
4 reductions that are achieved through compliance with
5 this rule whether it's going to have any impact on
6 your ability to -- the availability of early
7 reduction credits under the other rule if the other
8 rule does go final?
9 MR. ROMAINE: I think the answer is obvious,
10 but maybe we want to confer a little bit.
11 MR. LAWLER: We should know the answer to that.
12 HEARING OFFICER BEAUCHAMP: Let's go off the
13 record.
14 (Whereupon, a discussion
15 was had off the record.)
16 HEARING OFFICER BEAUCHAMP: We're back on the
17 record.
18 MR. LAWLER: I think Mr. Romaine's answer that
19 it's obvious, but we just kind of wanted to make
20 sure it was obvious, but there is -- they would be
21 able to use early reduction credits.
22 MR. RODRIGUEZ: They would be?
23 MR. LAWLER: Yes.
24 MR. RODRIGUEZ: It would not affect your -- the
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1 availability of claiming reductions achieved in 2002
2 or 2003 to comply with this rule? This rule
3 wouldn't have an impact on the ability to --
4 MR. LAWLER: That' correct. It's a separate
5 rulemaking.
6 HEARING OFFICER BEAUCHAMP: Okay. Thank you.
7 Thank you, Mr. Rodriguez. Mr. Rieser, again.
8 MR. RIESER: Well, if I could briefly follow-up
9 on that point. My recollection is that the Subpart
10 W ERC provide only for reductions 30 percent below
11 permitted levels. So as of 2003 the permitted level
12 would at least be .25 -- .25 rate. So would they
13 only provide -- would the rule only provide for
14 early reduction credits in 2003 to the extent that
15 they reduced 30 percent below that rate -- to the
16 extent there are any ERCs available in 2003?
17 MR. LAWLER: Let us just respond to that maybe
18 in comments or at a later time.
19 MR. RIESER: Perhaps at the next hearing.
20 Maybe something we can discuss at the next hearing.
21 MR. LAWLER: That would be fine.
22 HEARING OFFICER BEAUCHAMP: Thank you, Mr.
23 Rieser. Are there any further questions for the
24 Agency witnesses? Any questions from the members of
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1 the Board present or staff?
2 MS. McFAWN: I have some questions. I'm going
3 to have to backtrack a little bit and maybe we've
4 covered some of this ground, but my first question
5 is -- I just want to verify that this rule is not
6 filed under Section 9.9, is that correct?
7 MR. LAWLER: That's correct.
8 MS. McFAWN: Your statement of reason says that
9 it is, but I couldn't see any nexus between the two.
10 MR. LAWLER: The statement of reason says it is
11 filed under 9.9 --
12 MS. McFAWN: Yes.
13 MR. LAWLER: Or 28.5?
14 MS. McFAWN: Both.
15 MS. HERST: It shouldn't be under --
16 MR. LAWLER: If it says -- it's a misstatement
17 that we'll check over that.
18 MS. McFAWN: That's fine. I just want to
19 verify that. Then this is a much broader question.
20 I was curious as to why this rule is being imposed
21 state-wide since a number of the sources are a
22 downwind from East St. Louis? They don't seem to be
23 contributing to the problem in East St. Louis and
24 this rule, as I understand it, is intended to
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1 address the nonattainment of that area.
2 MR. LAWLER: Actually, the -- I think we made
3 in discussing the modeling this morning and in other
4 statements that we've made, we tried to stress that
5 the regionalness of the -- of getting the NOx
6 reductions, that it isn't necessarily one particular
7 plume from an individual plant, but the whole group
8 of sources that are -- that contribute to the ozone
9 problem and it, to some degree, there's an ozone
10 soup out there and everybody is adding to the soup
11 and so the analyses that have been done, we don't
12 try to draw a distinction or magic line in the state
13 that says this particular source contributes and
14 that particular one doesn't because when you get
15 into individual sources that's very difficult -- you
16 know, a very difficult thing to do. So there's no
17 magic line that we can draw and from that standpoint
18 and from an equity standpoint this would apply to
19 all the sources in the state and the modeling that
20 was done essentially assumed all the sources in the
21 state would be at that level.
22 MS. McFAWN: So you didn't do any modeling that
23 would just assume, like, the impact of the Missouri
24 sources and maybe down state Illinois sources?
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1 MR. LAWLER: No. That's correct.
2 MS. McFAWN: But when you studied Lake Michigan
3 you had a boundary line, didn't you? The Lake
4 Michigan ozone area.
5 MR. LAWLER: When we studied, and Rob may want
6 to add to this, but when we studied the Lake
7 Michigan area we drew boundaries that were out away
8 from the areas far enough that anything coming in
9 from outside that area, while it still could come
10 into the area, it still comes into from outside the
11 square that Rob showed us as Grid M, it will come
12 in, but the area that's inside contributes more and
13 again, even in none of that modeling did we try to
14 say that this group of sources does contribute and
15 that group of sources doesn't contribute because in
16 effect everybody is contributing to the problem and
17 so when you go back and take that down to an
18 Illinois level you really can't get into individual
19 sources and try to say that this person is causing
20 or not causing the problem because of the soup
21 situation.
22 MR. KALEEL: I would agree with the way Dennis
23 characterized it and I guess I'm a little confused
24 by the one question about dividing Illinois for the
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1 Lake Michigan region. We did not do that. The
2 applicability of the NOx reductions for the Lake
3 Michigan attainment plan rely on state-wide
4 application of emission limits as well.
5 MS. McFAWN: Maybe I misunderstood some of the
6 overheads that Mr. Lawler relied on; namely, the one
7 that you didn't have a copy of in your attachment.
8 MR. LAWLER: Yes.
9 MS. McFAWN: We just note that for the record.
10 I have seen it before at other NOx hearings, but I
11 thought for sure you told us there was a boundary
12 there and it was drawn in blue and it was where
13 they took the readings to distinguish between an
14 area south of Lake Michigan and further down state
15 of Illinois?
16 MR. LAWLER: This was -- there was a particular
17 focus that was part of the LADCO study back in the
18 early 90s and for purposes of that study we put in a
19 very dense monitoring network in the area right
20 around Lake Michigan and that's probably what you're
21 thinking of on the chart. That's where we ended up
22 because that's where we really wanted to get the
23 dense measurements of the ozone and the ozone
24 precursors because, to some degree, we are also
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1 trying to figure out the impact of the lake at that
2 point. So we put a very dense network of the
3 monitors in the areas right around the lake and to
4 kind of go with that we put these aircraft -- the
5 aircraft ended up flying in the same area and to the
6 south, the aircraft had to cut across someplace to
7 take their measurements and that's where they took
8 them and we were able to find out from those
9 aircraft measurements that you did have this, I'm
10 going to say soup, that was coming in from the -- in
11 that case that was the southerly wind. It was
12 coming in from the south into the area.
13 So that particular chart didn't mean to
14 say that -- there's two points, it didn't mean to
15 necessarily say that that was a beginning point or
16 an ending point or anything else, and then the
17 second point is it was also done almost ten years
18 ago now and the modeling -- we can model much bigger
19 areas also right now, but the main point is there
20 was no particular reason for that line.
21 DR. FLEMAL: Do we ever encounter ozone
22 exceedances on other than southerly wind conditions?
23 MR. LAWLER: Yes.
24 DR. FLEMAL: So it is not true that the
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1 exceedances always occur in a roughly northerly
2 direction from the main source?
3 MR. LAWLER: And maybe some of the confusion is
4 because of that example that I used with what
5 Ms. McFawn was talking about was a southerly wind
6 and southerly wind is probably the most common, but
7 we do get exceedances and violations with winds from
8 other directions also, but that particular example
9 was a southerly wind.
10 DR. FLEMAL: Okay. And you also choose to show
11 us when you were talking about Grid M the southern
12 line and I think you were talking at that stage
13 about this showed that there was movement from south
14 to north into Grid M, that it was an outside source
15 and having a southerly boundary and the implications
16 were that things come from the south and go towards
17 the north and are you telling us that that is maybe
18 common, but it's not an exclusive situation?
19 MR. LAWLER: That's correct. It's probably an
20 oversimplification on our part for purposes of
21 trying to explain the concept and we may have said
22 it a little stronger than we should have, but it's
23 the concept that we are trying to explain. So
24 that's yes to answer your question.
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1 MS. McFAWN: Now, I have a series of very
2 detailed questions so anybody jump in if they have a
3 bigger question that's related to the one I'm going
4 to pose. I was reading over the parts in the
5 language of the rule and because when push comes to
6 shove sometimes we want to modify language in the
7 rule, but we are reluctant to do so from that
8 proposed by the Agency unless we fully understand
9 the ramifications of such changes. That's why my
10 questions may be somewhat detailed.
11 Beginning with the purpose statement, in
12 other sections; namely, Subpart W and the subpart
13 you will discuss tomorrow you talk about the control
14 period in the purpose sections as being the ozone
15 control period. Would that be proper to do so in
16 this case? You modify control period with the word
17 ozone is what I'm asking.
18 MR. LAWLER: It's an ozone control period so...
19 MS. McFAWN: Okay. So we could parallel the
20 language of the other two parts with no problem?
21 MR. LAWLER: Yes.
22 MS. McFAWN: Subpart W also has a further
23 explanation of the purpose which is -- explains that
24 the purpose is more than just to control NOx and I
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1 wonder if the Agency could consider either a phrase
2 or a second sentence that would summarize what this
3 Subpart V is intended to do. I won't ask you to do
4 that now, but maybe in the future for the next
5 hearing. Then also as part of this, I find it
6 curious that we have defined control period here as
7 May 1 through the 30th beginning in 2003. That
8 would seem to work, but we do have a definition of
9 control period currently proposed in Subpart W at
10 Part 211 which will cause a problem.
11 MR. LAWLER: If we understand your question
12 correctly, Subpart W now identifies a period for the
13 first year of May 31st through September 30th to
14 make it consistent with what the court decision was
15 on the -- when the NOx SIP Call should begin and
16 then after that we say that it's -- it would be
17 applicable that the control period for purposes of
18 that is May 1st through September 30th, and the
19 reason we put this in here is for purposes of this
20 subpart. We wanted to make sure it was clear that
21 the control period is May 1st through September 30th
22 for this subpart.
23 MS. McFAWN: Well, what I guess I'm asking you
24 to look to is the language proposed at Section
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1 211.1515 and make sure that it doesn't apply to this
2 Subpart V because it does have that caveat about the
3 year 2004.
4 MR. LAWLER: Okay. We'll check that.
5 MS. McFAWN: Okay. Another general question
6 about definitions, as I can determine we have never
7 defined the word EGU, electric generating unit, and
8 I'm wondering if that would not be prudent to do. I
9 couldn't find it as far as the definition goes.
10 MR. LAWLER: We'll check that.
11 MS. McFAWN: Would you like to answer that
12 tomorrow?
13 MS. KROACK: Certainly.
14 MS. McFAWN: That was Laurel Kroack.
15 THE REPORTER: Could you spell the last name?
16 MS. KROACK: Could you spell your last name to
17 make sure it's correct?
18 MS. KROACK: K-r-o-a-c-k.
19 MR. LAWLER: She's a little hoarse today.
20 MS. McFAWN: That's fine. It will be relevant
21 tomorrow. Sometimes in the rules you say person,
22 sometimes you say owner/operator and sometimes you
23 say responsible person. I assume that there are
24 reasons for using each one of those terms as opposed
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1 to just using the owner/operator throughout. I
2 shouldn't assume that, I'm asking. Is there a
3 reason for each one of those terms being used? If
4 you'd like, I can cite you to the sections.
5 MR. LAWLER: Maybe we can get the cites from
6 you and we'll check it.
7 MS. McFAWN: Sure. Okay. The cite where
8 person is used is Section 217.706 and the
9 responsible person is the one about concerning
10 certification which is -- actually, it's a
11 responsible official, at Section 217.712.
12 MR. ROMAINE: Responsible official certainly
13 has a very specific usage. It identifies a
14 particular person that has submitted Title 5
15 application for a facility and provides an
16 authoritative signature for the filing of the report
17 from the Agency.
18 MS. McFAWN: And that is a better person than
19 the owner or operator of the source?
20 MR. ROMAINE: Yes, it is. For that particular
21 -- for purposes of reporting, it is certainly much
22 more appropriate to use the term responsible
23 official.
24 MS. McFAWN: Thank you. That answers a large
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1 part of my question.
2 At Section 217.708, the NOx averaging
3 rule, Subparagraph (a) the last clause defines that
4 the units must have commenced commercial operation
5 on or before January 1st of 2000. Someone asked you
6 if that's actually a fact at Soyland Power and you
7 responded yes, that there were some that commenced
8 prior to that date and so maybe my question is moot,
9 but I was wondering when I read that, does that
10 clause just modify units at Soyland Power or units
11 at other EGUs?
12 MR. ROMAINE: It simply modifies Soyland Power.
13 MS. McFAWN: Thank you.
14 MR. ROMAINE: Soyland Power actually has five
15 peaking units there. Only two of them are above
16 the about 25 megawatts. When I questioned when they
17 started operation, they certainly have had trouble
18 actually keeping them operating. So they've met the
19 date, but I'm not sure if they're operating at the
20 present time or they're back under repair again.
21 MS. McFAWN: Can they average -- they can't
22 average across those five then, can they?
23 MR. ROMAINE: The smaller three units don't
24 qualify as EGUs for the purpose of this rule --
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1 whatever this thing is.
2 MS. McFAWN: Thank you.
3 MS. LIU: Good afternoon. As I understand it,
4 this is a rate-based rule versus a rule based on
5 total emissions. I was wondering is there a
6 mechanism in place that would limit the total BTUs
7 and therefore limit the total pounds of NOx?
8 MR. LAWLER: No, not in this rule.
9 MS. LIU: Could you describe to me the
10 rationale or the history behind why this was made a
11 rate-based rule versus a rule based on total
12 emissions?
13 MR. LAWLER: Actually, most of our rules -- let
14 me rephrase that. Typically, our rules are
15 rate-based rules and most rules probably in other
16 states are rate-based rules and unusual -- the NOx
17 SIP Call is the one that's a little more unusual
18 because it actually does limit -- provide a state
19 limit, a state budget, on it and that was the way
20 the federal government decided to do it and there is
21 some -- certainly some rationale for doing that, but
22 to make this one more consistent with the rules that
23 we have in the state at this point and which we have
24 found, you know, generally effective, we made this
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1 one a rate-based rule and it will be easier for --
2 for people to read and I think it will have maybe
3 more meaning to some of the industrial sources in
4 that kind of an approach.
5 MS. LIU: To follow-up on some of what
6 Mr. Rieser said about companies cooperating to
7 average their emissions, could you help me to
8 picture how owners and operators would contact each
9 other so that they could begin the averaging
10 process? Will they need to register with the IEPA?
11 Will they set up their own network?
12 MR. LAWLER: We won't, ourselves, be in any
13 kind of a position to suggest to any of these
14 companies that they should be considering averaging
15 with another company or not. It will be totally up
16 to the companies themselves and the utilities in the
17 state are very well aware of all these rulemakings
18 and are very knowledgeable on this, and I think
19 probably it's a situation where the companies will
20 end up contacting each other. Conceivably, there
21 could be middle men on this. I don't know if it
22 would get to that point or not, but the companies do
23 contact each other and have discussions on different
24 things and they're aware of these rules. So I would
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1 suspect that they would just work it out between
2 themselves.
3 MR. ROMAINE: Obviously, we also expect that
4 most averaging will simply kind of occur within a
5 single company. Obviously, many of these facilities
6 have multiple plants, multiple units and simply
7 having the ability to average among your own units
8 is a great benefit.
9 MS. LIU: Mr. Mahajan had testified that the
10 cost effectiveness of adding control options was
11 around $1,465 per ton. If companies do trade
12 amongst each other for the averaging, how much would
13 the Agency estimate a ton of NOx would go for?
14 MR. MAHAJAN: This rule is based on the
15 emission rate. It is not a Cap and Trade Program.
16 There's no -- the Agency don't expect any -- you
17 know, cannot predict any costs for that trading.
18 MR. LAWLER: What we've given you is the -- to
19 some degree I guess from that standpoint more of a
20 worse case scenario. If they do averaging within
21 the plant or averaging with another plant, we assume
22 the cost would be less, but because we don't know
23 exactly what they'll do and what options are open to
24 them, we've not made an estimate of that.
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1 MS. LIU: Again, to follow-up on what
2 Mr. Rieser had said about singling out units that
3 were participating in the averaging for applying
4 penalties if they were undercomplying, could you
5 describe what those penalties might be?
6 MR. LAWLER: I don't think we've -- for
7 purposes of this rulemaking, we really haven't got
8 into exactly what penalties would be, you know,
9 imposed on people. For this rulemaking they would
10 be -- a company could end up being out of compliance
11 and then it would kind of go through the state
12 enforcement process where there's an Agency
13 component and then if it goes on from there maybe an
14 attorney general's component of an enforcement case.
15 We just -- we couldn't address that because it
16 generally -- you know, the particular instance that
17 somebody is out of compliance is generally unique
18 and it just has to be worked out.
19 MS. LIU: Mr. Mahajan also referred to a growth
20 factor of 1.08 for the years from 1996 to 2007 and
21 that that same growth factor was applied for this
22 rulemaking. Is that a linear growth factor?
23 MR. MAHAJAN: Yeah.
24 MS. LIU: There was also a description in the
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1 statement of reasons about a term called potential
2 electrical output capacity and an equation used to
3 derive that. I was wondering, in the equation
4 itself they take the maximum design heat input and
5 divide it by three and then apply a conversion
6 factor. I was wondering where that divided by three
7 part comes in?
8 MR. MOORE: That comes from the fact that on
9 the average only one-third of the heat output of a
10 fuel combustion device is available to become
11 electricity and two-thirds of that heat is lost in
12 the process. So that's the typical efficiency of an
13 electrical generating unit.
14 MS. LIU: Mr. Miller was also talking about a
15 five percent capacity factor. Could you explain
16 what that is a little bit, please?
17 MR. ROMAINE: A capacity factor is a way to
18 evaluate how much a generating unit operates. One
19 hundred percent capacity factor would assume that
20 the unit operated at full load continuously 8,760
21 hours per year. A five percent capacity factor
22 indicates that compared to what maximum could do, in
23 fact, it's been operating at a load in hours to be a
24 five percent utilization.
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1 In terms of -- a simple example is if
2 there's 8,760 hours in a year and if it operated at
3 full load whenever it was operating that would
4 result in operating at full load for 438 hours would
5 be a five percent capacity factor.
6 MS. LIU: Okay. Thank you. There's an
7 existing section in Subpart V that's going to be
8 left unchanged. It deals with the Lake of Egypt
9 Power Plant. That provision actually gives relief
10 to that plant from meeting certain requirements for
11 new emissions sources, and I was just wondering if
12 they would be giving special treatment under the
13 proposed new sections of this Subpart V or if they'd
14 be required to meet the .25 pounds per NOx -- or
15 pounds of NOx per unit each year like all the other
16 sources would?
17 MR. MOORE: The special provision for Lake of
18 Egypt Power Plant is merely a reflection of the new
19 source performance standard emission limit for that
20 plant. When it burns more than a certain percentage
21 of coal waste, then there is no new source
22 performance standard. So the exemption for them is
23 an exemption from an existing new source performance
24 standard and it's not an exemption from Subpart V.
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1 So our regulations proposed that that plant does
2 comply with Subpart V.
3 MS. LIU: Mr. Moore, you also spoke about
4 reporting and recordkeeping requirements. A simple
5 question, would they be required to keep their
6 records in hard copies or would electronic form be
7 acceptable?
8 MR. MOORE: Well, I'm sure electronic
9 recordkeeping will be very acceptable at which -- at
10 the time that the Agency is on line and is able to
11 receive it that way, which my understanding is right
12 at the present moment we wouldn't be able to handle
13 that way of reporting electronically, but we hope
14 that will change in the near future such that they
15 can submit it whatever way they wish to submit it as
16 long as the data is accurate, et cetera, and we have
17 the wherewithal to receive the report.
18 MS. McFAWN: Could they keep it electronically
19 on site so that when your inspectors are there they
20 could make it available to them or do they have to
21 keep hard copies on site?
22 MR. ROMAINE: There's nothing in this rule that
23 would require them to keep hard copies on site.
24 Data that is generated electronically could be
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1 stored electronically. Our concern, as Berkley has
2 said, is to make sure that we can have access to the
3 data as we need, which could require that they print
4 it out for specific areas, days, types of
5 information.
6 MS. McFAWN: Can they -- do they have to keep
7 the records? If they are providing averaging from a
8 different location, a unit at a different location
9 or from a different owner/operator, do they have to
10 keep those records for five years or just the
11 company that -- or the site that is -- where the
12 unit is located?
13 MR. ROMAINE: I think we'll take that under
14 advisement.
15 MS. McFAWN: To follow-up on one of Ms. Liu's
16 questions, she was talking about it being a
17 rate-based rule and one question we had was if it's
18 rate-based there's no mechanism in place, is there,
19 to limit emissions?
20 MR. MOORE: Well, yes. The capacity of the
21 unit to generate heat input. I mean, they all
22 have -- they cannot run at over 100 percent capacity
23 for a very long time.
24 MS. McFAWN: Correct, that is correct. That
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1 would be the maximum?
2 MR. MOORE: Right.
3 MS. McFAWN: Is that what you used in the
4 modeling then?
5 MR. KALEEL: Yes. We assumed full operation of
6 all the sources in the state plus growth.
7 MS. McFAWN: Okay. Thanks.
8 Mr. Lawler, when you submitted our SIP
9 demonstrations, did -- especially those that were
10 submitted for the Metro-East area, did they include
11 rules such as this rate-based rule or did those SIP
12 attainment demonstrations just anticipate trading?
13 MR. LAWLER: What we submitted as part of our
14 attainment demonstration was an indication of --
15 like in the case of the Metro-East that if we had a
16 .25 limit on the sources, we would be able to
17 demonstrate attainment.
18 So either with a .25 rule or the NOx SIP
19 Call we would be able to demonstrate attainment and
20 that's -- that would be -- I believe that answers
21 your question. The actual demonstration that we
22 submitted showed that a .25 limit would also
23 demonstrate attainment.
24 MS. McFAWN: So it was an either or
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1 proposition?
2 MR. LAWLER: We didn't submit it as an either
3 or. We just said that at least a .25 limit would be
4 needed to show attainment.
5 HEARING OFFICER BEAUCHAMP: Why don't we take a
6 brief five-minute break and we'll reconvene at five
7 minutes to four.
8 (Whereupon, after a short
9 break was had, the
10 following proceedings
11 were held accordingly.)
12 MS. McFAWN: I just -- thank you for that
13 time-out. I needed to find some more questions for
14 you, Mr. Lawler.
15 I was listening very closely to your
16 testimony and I have some questions about your
17 slides.
18 On slide 12, which is one that says OTAG
19 Findings on page three of the attachment --
20 MR. LAWLER: Yes.
21 MS. McFAWN: -- you had the last sentence which
22 says urban disbenefits from NOx controls is one of
23 the findings. I was at a different hearing and I
24 heard testimony that that has been discredited. Is
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1 that still a valid finding by OTAG?
2 MR. LAWLER: Yes, it is.
3 MS. McFAWN: I just wanted to verify that.
4 MR. LAWLER: And there's -- at one time I think
5 we didn't -- I guess a complete answer to your
6 question is there are days where there's disbenefits
7 and there are days when there's not disbenefits and
8 that's probably why -- that may be what you heard
9 and somebody only presented part of it to you. I'm
10 not sure.
11 MR. ROMAINE: I have been at hearings where
12 members of the public has suggested that's been
13 disproved by the OTAG process, but that is not our
14 belief or our understanding of what OTAG decided.
15 MR. LAWLER: Right.
16 MS. McFAWN: Okay. And this phrase, just to
17 make sure I understand it correctly, you are saying
18 that there actually -- that controlling NOx cannot
19 be beneficial because that ozone formation might
20 occur at a greater rate if the NOx is not present?
21 MR. KALEEL: What I think we're referring to
22 is if you were to control NOx within the urbanized
23 area not the areas further upwind of an urban area,
24 but there is a phenomenon where ozone actually
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1 increases as a result of reductions of NOx.
2 MS. McFAWN: It's very localized?
3 MR. KALEEL: Those are very localized.
4 MS. McFAWN: Thank you.
5 DR. FLEMAL: And that's because NOx scavenges
6 some of the ozone?
7 MR. KALEEL: Right. NOx is actually two
8 components of it; one component is nitrogen oxide or
9 NO and it has a tendency to break down the ozone
10 molecule fairly close to the source.
11 MR. ROMAINE: Let me further clarify that when
12 NOx is formed by emission units, the general rule of
13 thumb is about 90 percent of it comes out as NO so
14 it then further oxidizes the atmosphere. So that
15 reaction has to cook in the soup before the NOx
16 takes the chemical form where it then participates
17 in the ozone reactive formation.
18 MS. McFAWN: Thank you. This kind of
19 backtracks to a question I asked you earlier, slide
20 13, which is labeled Metro-East/St. Louis
21 Nonattainment Area Demonstration there is a bullet
22 point there that says in October of 1999 and
23 February 2000, Illinois EPA submitted attainment
24 demonstrations to USEPA, is that a correct
L.A. REPORTING (312) 419-9292
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1 paraphrasing of that bullet?
2 MR. LAWLER: That's correct.
3 MS. McFAWN: Okay. And that was -- in those
4 submittals we did propose a rate-based rule of .25,
5 is that correct, to demonstrate achievement for East
6 St. Louis?
7 MR. LAWLER: In those particular submittals,
8 since we didn't have any rule that we could submit
9 with them, we didn't specify exactly, but had we
10 done it at that time, we could have submitted a .25
11 rate-based submittal as part of that, that's
12 correct.
13 MS. McFAWN: The proposed federal approval,
14 which was issued in April, said that we needed to
15 submit rules and it was in response to that proposed
16 approval that we went forward with the trading rule?
17 MR. LAWLER: We went forward with the NOx SIP
18 Call rule for several different reasons, but the NOx
19 SIP Call rule itself would take care of this
20 requirement.
21 MS. McFAWN: Okay. I think I understand you.
22 In other words, the Agency opted to submit to the
23 Board the trading rule believing it would take care
24 of the Metro-East area as well as our entire SIP
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1 approval process?
2 MR. LAWLER: Correct, that's correct.
3 MS. McFAWN: The last bullet in that slide says
4 that our docket rules are due to the USEPA by the
5 end of this year and we are on track, hopefully, to
6 do that with our trading rule. It doesn't seem
7 possible to do that with this set of rules and are
8 we, in fact, obligated to propose -- or adopt it as
9 final this set of rules to USEPA by the end of
10 December?
11 MR. LAWLER: Well, you're -- like you say, we
12 couldn't have this done by the end of September to
13 submit to EPA -- I'm sorry, the end of December to
14 go to EPA and so what we have done is we're trying
15 to do as much with EPA to kind of show our good
16 faith at this point. They know we've got Subpart W
17 and they know where that stands and that's being
18 submitted to them and a final rule will be submitted
19 to them. We have submitted -- this Subpart V when
20 we submitted it to the Board, we also sent it to
21 USEPA for parallel processing, again, to indicate
22 good faith that it's going through the state
23 process, and so I think what our hope is that come
24 the end of December EPA will use some discretion to
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1 say look, the state is doing everything they can at
2 this point. Something changed at the end of August
3 that the state is now addressing, they're doing
4 everything they can and so we'll cut the state a
5 little slack on this.
6 MS. McFAWN: Okay. And do you think the court
7 case where you made the commitment to do this rule
8 will have the same -- do you think the Court will
9 have the same attitude?
10 MR. LAWLER: It's harder to say what a Court
11 will do. I think at this point what our -- at least
12 a view of it is the state needs to make as much of a
13 good faith effort as possible and hope to convince
14 -- you know, hope that the Court is convinced of
15 that also.
16 MS. McFAWN: Is the state obligated to make
17 status reports to the Court on this proceeding?
18 MR. LAWLER: No. You're asking a little bit
19 more of a legal question than maybe I can answer,
20 but we -- I know we're -- USEPA is the one that
21 makes -- that's obligated to make responses to the
22 Court. We're an intervenor and we can make
23 responses, but we've been comfortable with what EPA
24 has been saying on our behalf at this point on this
L.A. REPORTING (312) 419-9292
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1 issue.
2 MS. McFAWN: Okay. Thank you for that
3 clarification.
4 At slide 15, NOx SIP Call and the elements
5 of it, it says the elements of control program and
6 there are four things listed, and the last is large
7 internal combustion engines at 90 percent control.
8 Which part of our rulemaking does that refer to?
9 MR. LAWLER: This particular element was one
10 that was remanded back to USEPA in one of the court
11 proceedings, in Michigan versus EPA, and so it will
12 be a future requirement that the state will have to
13 meet, but at this point it's back in EPA's court and
14 so we have no real obligation to do anything right
15 now as far as the SIP Call goes on that until EPA
16 again moves that into the -- moves that into part of
17 the SIP Call.
18 MS. McFAWN: Is this the same term as -- in
19 using our -- stationary internal combustion engine?
20 MR. LAWLER: Yes, yes, it is.
21 MS. McFAWN: And under Section 9.9 we are
22 obligated to do that, but that can also be stayed
23 for this time being, do you believe?
24 MR. LAWLER: Yes.
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1 MS. McFAWN: In slide 14 it makes a reference
2 at the last bullet point, which is -- that slide is
3 NOx SIP Call Chronology, of a court stay being
4 removed on June 22nd. That stay being removed, I
5 assume, lifted the stay imposed by the Court on May
6 25th, 1999, which is referred to in the next -- in
7 slide 16?
8 MR. LAWLER: That's correct.
9 MS. McFAWN: Slide 16 being labeled Road to
10 Illinois Regulatory Proposal.
11 And then my question is for Mr. Kaleel, I
12 was looking and listening to your testimony and at
13 Figure 4, which is also slide 11 of your testimony
14 -- attached to your testimony, it shows that there's
15 not much difference between the reductions we'll
16 achieve if we impose the rate-based rule and/or the
17 NOx SIP Call rule, which I refer to as the trading
18 rule. Why are they so comparable?
19 MR. KALEEL: Well, on this particular day there
20 isn't a lot of change and I think we've seen it
21 fairly consistently in St. Louis that the NOx SIP
22 Call does provide additional benefits, but not a lot
23 of benefit. A limit of three parts per billion is
24 fairly typical and depending upon what scale we use
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1 to show those results graphically it may or may not
2 be enough to tip it into a different colored scale
3 or different region.
4 MS. McFAWN: Will we -- I'm not sure that I
5 understand this, but will we actually -- will they
6 overlap or will we by implementing the .25 rule as
7 well as the NOx SIP call rules will we achieve both
8 reductions?
9 MR. KALEEL: Well, when we implement the NOx
10 SIP Call the figure on the lowest right would be
11 what we would expect air quality to look like under
12 those meteorological conditions. So I think we
13 typically think of the NOx SIP Call as being more
14 stringent and providing greater benefit.
15 MS. McFAWN: So the effect is cumulative? It's
16 not --
17 MR. KALEEL: It kind of supersedes it in a
18 way -- I guess in my way of thinking since it's more
19 stringent, we'll get slightly more benefit. We've
20 kind of gone past the point too far.
21 MS. McFAWN: Just to make sure -- I probably
22 haven't phrased this correctly -- to make sure I
23 understand this, if we weren't to adopt the .25
24 rule, would we achieve the entire results predicted
L.A. REPORTING (312) 419-9292
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1 by this bar graph under the NOx SIP Call rule?
2 MR. KALEEL: We're looking at the one called
3 Figure 5 now?
4 MS. McFAWN: Yes.
5 MR. KALEEL: I guess the way I'm interpreting
6 that is that the NOx SIP Call would provide greater
7 benefit. We'd see lower ozone under the NOx SIP
8 Call scenario than we would under just the .25
9 pounds per million BTU rule and that's because it's
10 more stringent on utilities and there are some
11 additional source categories that it will address.
12 Am I missing your question?
13 MS. McFAWN: But if weren't -- maybe this is --
14 maybe I'm missing the point of the graph actually,
15 but if we were not to adopt the .25, would we still
16 see all the reductions that's reflected in the bar
17 for the NOx SIP Call rule?
18 MR. KALEEL: Yes, we would.
19 MS. McFAWN: Okay. That was -- that was all
20 the questions I have. Thank you for your patience.
21 HEARING OFFICER BEAUCHAMP: Dr. Flemal, do you
22 have any questions?
23 DR. FLEMAL: No.
24 HEARING OFFICER BEAUCHAMP: Any others from
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1 members of the Board?
2 MR. STERNSTEIN: I have a couple very short
3 ones. Mr. Lawler, this is a follow-up to one of the
4 questions that Board member McFawn was asking a
5 couple minutes ago. On page three of the shrunken
6 slides exhibit, Exhibit 2A, the elements of the
7 control program, the large internal combustion
8 engines, 90 percent control has been remanded back
9 to USEPA. I recall this from an earlier hearing,
10 are those internal combustion engines primarily used
11 to push gas through gas pipelines?
12 MR. LAWLER: That's correct.
13 MR. STERNSTEIN: Okay. I just wanted to double
14 check on that, and then a question for Mr. Kaleel.
15 On the -- I think it's the fifth slide on the first
16 page of Exhibit 1A under assumptions. I just wanted
17 to make sure I heard you correctly. The last bullet
18 point there that there was a correction applied to
19 Biogenic emissions in the Missouri Ozarks and you
20 had said something, and again I'm paraphrasing here,
21 I just wanted to have you clarify it for me that
22 you're subtracting ozone that comes from oak trees
23 in the Ozarks?
24 MR. KALEEL: Well, no, not exactly. To back up
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1 a step or two here, the model uses all categories of
2 emissions in predicting ozone concentrations. The
3 primary constituents of emissions inventory are
4 three precursor compounds or family of compounds,
5 VOCs or VOMs, NOx and carbon monoxide. Biogenic
6 emissions are typically VOCs and in particular, one
7 group of VOCs called isoprene. There are certainly
8 other types of VOCs and even some nitrogen compounds
9 that are emitted naturally from forest, from crops,
10 from other types of naturally occurring vegetation,
11 but the way we applied the correction was after
12 performance of a measurement study where we measured
13 VOCs and other meteorological parameters in the
14 Ozarks in an area of very high density of oak
15 forests, we found that the model emissions modeled
16 that is prescribed by USEPA called Beis-2 overstates
17 the amount of VOCs from oak trees. So we applied
18 the correction to the VOC inventory before we ever
19 put it into the air quality model.
20 MR. STERNSTEIN: And there's no other large
21 forested areas that contribute -- contribute those
22 kind of VOCs around the St. Louis nonattainment
23 area?
24 MR. KALEEL: Not nearly to the extent that what
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1 we saw there and again, it seemed to be a factor
2 that was unique to the high percentage of oak trees
3 in the Ozarks. It seems unique in the entire
4 eastern United States to just that region of the
5 Ozarks.
6 MR. STERNSTEIN: Okay. That's all I have.
7 Thanks.
8 HEARING OFFICER BEAUCHAMP: Thank you,
9 Mr. Sternstein.
10 HEARING OFFICER BEAUCHAMP: Any other questions
11 from members of the Board or other staff? Are there
12 any other questions from members of the public in
13 attendance today? Seeing none, we move to wrap up
14 the hearing today.
15 Please note that the second hearing for
16 this rulemaking is scheduled to begin Tuesday,
17 December 19th, 2000, at 11 a.m. in Room 9-040 in the
18 James R. Thompson Center, this building, this room
19 located at 100 West Randolph Street in Chicago.
20 The third hearing is scheduled to begin
21 Tuesday, January 2nd, 2001, at 11 a.m. also in Room
22 9-040 in the James R. Thompson Center.
23 Once again, if the Agency does not request
24 a third hearing, the Board will cancel that third
L.A. REPORTING (312) 419-9292
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1 hearing.
2 We have requested an expedited transcript
3 in this matter which should be available Friday.
4 The Board will post the transcript to its website.
5 The website is located at www.ipcb.state.il.us.
6 The transcript should be posted to the
7 Board's website next week, either Tuesday or
8 Wednesday. You may also obtain a hard copy of the
9 transcript from the court reporter or you may
10 request a hard copy from the Board, although the
11 Board charges .75 cents a page.
12 I'd like to remind the Agency that any
13 issues which the Agency has agreed to address at the
14 request of any of the parties present today should
15 be answered at the beginning of the second hearing
16 on December 19th.
17 We will see you all again on that date.
18 We have a question from Laurel?
19 MS. KROACK: Yes. Prefiled testimony that they
20 have to file before, we'd like the Board to ask that
21 that testimony be served on us the same manner it
22 was served to the Board because we were receiving
23 some of that rather late in the last set of W
24 hearings, in fact, so it was difficult to prepare
L.A. REPORTING (312) 419-9292
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1 for that second set of hearings.
2 MS. McFAWN: Let's go off the record for a
3 moment if you don't mind.
4 HEARING OFFICER BEAUCHAMP: Sure.
5 (Whereupon, a discussion
6 was had off the record.)
7 HEARING OFFICER BEAUCHAMP: The Agency has
8 requested that members of the public who are wishing
9 to prefile testimony for the second hearing serve
10 those copies on the Agency in the same manner as
11 they do so for the Board and members of the public
12 who are present have indicated that they'd be
13 willing to do so.
14 I'd like to state for the record that
15 prefiled testimony is due on December 8th to be
16 filed with the Board and the mailbox rule does not
17 apply to that date. So it needs to be here within
18 the date stamped by the clerk on the 8th.
19 Are there any other matters that need to
20 be addressed at this time? Hearing none, this
21 matter is hereby adjourned. Thank you very much for
22 your attendance and participation in this hearing.
23 (Whereupon, no further
24 proceedings were had.)
L.A. REPORTING (312) 419-9292
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1 STATE OF ILLINOIS )
2 ) SS.
3 COUNTY OF C O O K )
4
5
6 I, TERRY A. STRONER, CSR, do
7 hereby state that I am a court reporter doing
8 business in the City of Chicago, County of Cook, and
9 State of Illinois; that I reported by means of
10 machine shorthand the proceedings held in the
11 foregoing cause, and that the foregoing is a true
12 and correct transcript of my shorthand notes so
13 taken as aforesaid.
14
15
16 _____________________
17 Terry A. Stroner, CSR
18 Notary Public, Cook County, Illinois
19
20 SUBSCRIBED AND SWORN TO
before me this ___ day
21 of ________, A.D., 2000.
22
_________________________
23 Notary Public
24
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