1
1 BEFORE THE ILLINOIS POLLUTION CONTROL BOARD
2
3 IN THE MATTER OF: )
)
4 PROPOSED NEW 35 ILL. ADM. CODE 217, ) R01-09
SUBPART W, THE NOx TRADING PROGRAM ) (Rulemaking-Air)
5 FOR ELECTRICAL GENERATING UNITS, )
AND AMENDMENTS TO 35 ILL. ADM. )
6 CODE 211 AND 217 )
7
8 The following proceedings were
9 held in the above-referenced title, held before
10 MS. CATHERINE F. GLENN, Hearing Officer, taken
11 before GEANNA M. IAQUINTA, CSR, a notary public
12 within and for the County of Cook and State of
13 Illinois, at the James R. Thompson Center, 100
14 West Randolph Street, Room 9-031, Chicago,
15 Illinois, on the 26th day of September, A.D.,
16 2000, scheduled to commence at 9:30 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
3 100 West Randolph Street
Suite 11-500
4 Chicago, Illinois 60601
BY: MS. CATHERINE F. GLENN
5
6 ILLINOIS POLLUTION CONTROL BOARD MEMBERS PRESENT:
7 Mr. Bobb Beauchemp Dr. Ronald Flemal
Ms. Marili McFawn Mr. Nicholas Melas
8 Mr. Anand Rao Mr. Joel Sternstein
9
ILLINOIS ENVIRONMENTAL PROTECTION AGENCY MEMBERS
10 PRESENT:
11 Ms. Laurel Kroack Mr. Dennis Lawler
12 Mr. Yoginder Mahajan Mr. Robert Kaleel
13 Mr. Robert Messina Ms. Vera Herst
14 Ms. Kathleen Bassi Mr. Richard Forbes
15 Ms. Shannon Loveless-Bilbruck
16
17
18 OTHER MEMBERS OF THE PUBLIC WERE IN ATTENDANCE
AT THE MEETING, BUT NOT NOTED ON THIS APPEARANCE
19 PAGE.
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24
L.A. REPORTING (312) 419-9292
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1 I N D E X
2 THE WITNESSES:
3 PAGES:
4 TESTIMONY OF TONY SHEA............ 14
5 TESTIMONY OF JOSEPH DARGUZAS...... 22
6 TESTIMONY OF MICHAEL MENNE........ 30
7 TESTIMONY OF BRIAN URBASZEWSKI.... 77
8 TESTIMONY OF LENNY DUPUIS........ 115
9 TESTIMONY OF DEREK FURSTENWERTH.. 147
10 TESTIMONY OF SCOTT MILLER........ 167
11 TESTIMONY OF MARY SCHOEN......... 184
12 TESTIMONY OF ARIC DIERICX........ 233
13
E X H I B I T S
14
Marked for
15 Identification
16 Exhibit No. 30.................... 20
Exhibit No. 31.................... 23
17
Public Comment No. 2.............. 24
18 Exhibit No. 32.................... 30
19 Exhibit No. 33.................... 64
Exhibit No. 34.................... 76
20
Exhibit Nos. 35 and 36 .......... 114
21 Exhibit No. 37................... 147
22 Exhibit Nos. 38 and 39........... 167
Exhibit No. 40................... 184
23 Exhibit No. 41................... 232
24
L.A. REPORTING (312) 419-9292
4
1 HEARING OFFICER GLENN: Good morning,
2 everyone. My name is Catherine Glenn, hearing
3 officer in this proceeding. I'd like to welcome
4 you here to this hearing being held by the
5 Illinois Pollution Control Board in the matter
6 of Proposed New 35 Illinois Administrative Code
7 217 Subpart W, The NOx Trading Program For
8 Electrical Generating Units, and Amendments to
9 35 Illinois Administrative Codes 211 and 217.
10 Present today on behalf of the
11 Illinois Pollution Control Board and seated to
12 my left is Dr. Ronald Flemal. Dr. Flemal is the
13 board member coordinating this rulemaking.
14 Seated to Dr. Flemal's left is Board Member
15 Nicholas Melas. Seated to Member Melas' left is
16 his attorney assistant, Joel Sternstein. Seated
17 directly to my right, from our technical unit,
18 is Anand Rao, and seated next to Mr. Rao is
19 Board Member Marili McFawn, hidden behind our
20 court reporter, and seated to Member McFawn's
21 right is her attorney assistant Bobb Beauchemp.
22 I have placed copies of the notice
23 and service list sign-up sheets on the table in
24 the back. Please note that if your name is on
L.A. REPORTING (312) 419-9292
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1 the notice list, you will only receive copies of
2 the Board orders and hearing officer orders. If
3 your name is on the service list, you will
4 receive copies of Board orders, hearing officer
5 orders, and any prefiled testimony that may be
6 filed.
7 Keep in mind if your name is on the
8 service list, you must also serve anything you
9 file with the Board with the members on the
10 service list. Copies of the Board's proposed
11 rule and the hearing officer order are also
12 located on the table in the back.
13 Also on the table in the back is a
14 letter from the Department of Community Affairs
15 -- Commerce and Community Affairs and a letter
16 from the Board to DCCA. On July 11th, 2000, the
17 Illinois Environmental Protection Agency filed
18 this proposal for rulemaking to create 35
19 Illinois Administrative Code Part 217 Subpart W,
20 The NOx Trading Program For Electrical
21 Generating Units, and Amendments to 35 Illinois
22 Administrative Codes 211 and 217. On July 13th,
23 2000, the Board adopted for first notice the
24 Agency's proposal.
L.A. REPORTING (312) 419-9292
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1 This proposal was published in the
2 Illinois Register on August 4th, 2000, at pages
3 11473 and 11493. Pursuant to Section 28.5(h) of
4 the Illinois Environmental Protection Act, the
5 Board shall accept evidence and comments on the
6 economic impact of any provision of the rule and
7 shall consider the economic impact of the rule
8 based on the record.
9 Under Section 27(b) of the Act, the
10 Board shall request the Department of Commerce
11 and Community Affairs, or DCCA, to conduct an
12 economic impact study, or ECIS, on certain
13 proposed rules prior to adoption of those
14 rules. If DCCA chooses to conduct the economic
15 impact study, DCCA has 30 to 45 days after such
16 request to produce a study on the economic
17 impact of the proposed rules.
18 The Board must make the economic
19 impact study or DCCA's explanation for not
20 conducting the study available to the public at
21 least 20 days before a public hearing on the
22 economic impact of the proposed rules. In
23 keeping with Section 27(b), the Board has
24 requested, by a letter dated August 1st, 2000,
L.A. REPORTING (312) 419-9292
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1 that DCCA conduct an ECIS for the aforementioned
2 rulemaking.
3 In addition to requesting that DCCA
4 conduct an ECIS, the Board requested that DCCA
5 notify the Board within ten days after receipt
6 of the request whether DCCA intended to conduct
7 the economic impact study. The Board further
8 noted that if it did not receive such
9 notification, the Board would rely on a record
10 -- on a letter from DCCA dated March 10th,
11 2000, from DCCA as the required explanation for
12 not conducting the economic impact study.
13 The March 10th, 2000, letter from
14 DCCA notified the Board that DCCA would not be
15 conducting economic impact studies on rules
16 pending before the Board because DCCA lacked
17 staff and financial resources to conduct such
18 studies. The ten days for DCCA to notify the
19 Board have expired, and the Board has not
20 received any notification from DCCA that it will
21 conduct an economic impact study on the
22 above-referenced rulemaking. Accordingly, the
23 Board will rely on the March 10th letter from
24 DCCA as DCCA's explanation for not producing a
L.A. REPORTING (312) 419-9292
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1 study. Copies of the letters from the Board and
2 to DCCA and a letter from DCCA to the Board are
3 at the table in the back.
4 The Board holds this hearing,
5 therefore, to conduct public comment on DCCA's
6 explanation for not conducting an economic
7 impact study in this rulemaking and also for the
8 purpose of presenting testimony, documents, and
9 comments by affected entities and other
10 interested parties. Like any other regulatory
11 -- like any other regulatory hearing, any
12 person who testifies will be sworn and subject
13 to questioning.
14 Moreover, this hearing will be
15 governed by the Board's procedural rules for
16 regulatory proceedings. All information which
17 is relevant and not repetitious or privileged
18 will be admitted. Currently, we have a third
19 hearing scheduled for Tuesday, October 10th,
20 2000 at 1:00 p.m. in the Board's hearing room on
21 the 11th floor of the James R. Thompson Center.
22 It will be devoted to any Agency response to the
23 materials submitted at the second hearing
24 today.
L.A. REPORTING (312) 419-9292
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1 I intend to ask the Agency during
2 today's proceedings whether or not they will,
3 indeed, request this third hearing. Let's see.
4 Before taking testimony regarding the economic
5 impact of the proposal, the Agency, I believe,
6 would like to say a few words regarding a motion
7 they intend to present a little later this
8 morning. So, perhaps, Ms. Kroack, if you'd like
9 to tell us about that motion, and after that we
10 will get started with hearing from our witnesses
11 who filed prefiled testimony.
12 MS. KROACK: Thank you. Good morning.
13 I'm Laurel Kroack with the Illinois EPA. I
14 think most of you know me. I'm representing the
15 Agency today in this matter. As most of you,
16 I'm sure, are aware, on August 30th, 2000, the
17 United States Court of Appeals, the D.C.
18 Circuit, issued an order extending the date for
19 full implementation of the NOx SIP Call from May
20 1st, 2003, to May 31st, 2004.
21 USEPA has not issued any guidance,
22 whether formal or informal at this point in
23 time, to indicate how it intends to respond to
24 that order. In light of the order, though,
L.A. REPORTING (312) 419-9292
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1 Illinois EPA is intending to submit an
2 additional rulemaking to the Board, probably on
3 October 2nd. That rulemaking will propose a
4 rate-based rule to address attainment for the
5 Metro East Nonattainment Area, and it will have
6 a compliance date of May 1st, 2003, to cover the
7 period between May 1st, 2003, and when the NOx
8 SIP Call is effective.
9 The rate-based rule will affect the
10 same class of units. However, it will be at an
11 emission rate of 0.25 pounds per million Btu.
12 We have shared that rulemaking with all of you
13 in the room. We've had some -- I believe all of
14 you in the room have had some discussions on
15 it. We're fairly close to final, but we are not
16 quite ready to submit it at this point in time,
17 probably next Monday. If anything happens with
18 USEPA in the interim, we may propose changes to
19 that rule or changes to the rule we're currently
20 addressing today.
21 Later today, and hopefully in a few
22 hours, we're going to submit a motion to amend.
23 That motion will address the compliance date.
24 We'll move it from May 1st, 2003, to May 31st,
L.A. REPORTING (312) 419-9292
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1 2004. In that motion to amend, we will not be
2 adjusting at this point in time the allocations,
3 size of the compliance supplement pool, or any
4 of those issues until we get further guidance
5 from USEPA on what it intends to do with those
6 matters.
7 The motion to amend has some other
8 housekeeping measures, some additional items
9 that we've received, comments from several of
10 the EGUS about suggested language changes that
11 we agree with, and we also have a proposed
12 approval of the rule from USEPA that was
13 published in the Federal Register, and they've
14 raised a couple of issues that we intend to
15 correct with this motion as well.
16 Just to be clear, we may be
17 suggesting additional language changes in the
18 comment period if necessary, but we hope this
19 covers most of them, if not all of them, and
20 that's all I have. Thank you.
21 HEARING OFFICER GLENN: Thank you,
22 Ms. Kroack. Before we get started then this
23 morning, I would like to ask if Board Member
24 Flemal would like to add anything?
L.A. REPORTING (312) 419-9292
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1 BOARD MEMBER FLEMAL: Welcome everybody,
2 and I look forward to today's proceeding.
3 HEARING OFFICER GLENN: What I'd like to
4 do first is see if there's anybody who would
5 like to testify regarding DCCA's lack of an
6 economic impact study. If there is someone who
7 would like to testify, please raise your hand,
8 and we will get you sworn in.
9 Okay. Seeing that no one wants to
10 testify on DCCA's lack of an ECIS study, let's
11 get to the matter at hand then. We did receive
12 prefiled testimony from eight people. I would
13 like to have them testify in the following
14 order. After I read all of your names, let's
15 get you all sworn in at the same time, and then
16 we can proceed accordingly.
17 The first witness today will be Tony
18 Shea from Goodwin Environmental Consultants.
19 The second witness will be Joseph Darguzas of
20 Goodwin Environmental Consultants, Michael Menne
21 from the Ameren Corporation, Brian Urbaszewski
22 from the American Lung Association of
23 Metropolitan Chicago, Mr. Lenny Dupuis from
24 Dominion Environmental, followed by Derek
L.A. REPORTING (312) 419-9292
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1 Furstenwerth of Reliant Energy. Scott Miller
2 will follow him, and he's from Midwest
3 Generation, and our last witness today will be
4 Mary Schoen of Enron Corp.
5 Pursuant to Section 28.5, prefiled
6 testimony will be accepted into the record
7 without reading of the testimony at hearing
8 provided that the witness swears to the
9 testimony and is available for questioning.
10 Therefore, it's up to all of you individually.
11 If you'd like to read it in, that's fine. If
12 you'd like to summarize your testimony, that is
13 welcome as well, whatever you are comfortable
14 doing. I would ask after you all are sworn in
15 and as you come up individually to testify that
16 you present a copy of your testimony if you have
17 it with you to me and we will admit it as if
18 read as an exhibit.
19 So are there any questions, I guess,
20 on any of that first of all? All right. Well,
21 let's begin. Mr. Shea, would you like to start
22 things this morning? I'm sorry. Could all of
23 you that are testifying first get sworn in, and
24 then we'll start with Mr. Shea.
L.A. REPORTING (312) 419-9292
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1 (Witnesses sworn.)
2 HEARING OFFICER GLENN: Thank you. Okay,
3 Mr. Shea.
4 MR. SHEA: Hello. My name is Tony Shea.
5 First, I'd like to thank you for allowing me
6 this opportunity to speak at today's hearing,
7 and just a correction, I'm actually employed by
8 ABB Energy Ventures of Princeton, New Jersey, as
9 project manager, and Goodwin Environmental, they
10 are a consultant of ours who we had asked to
11 submit my prefiled testimony on my behalf.
12 Through our subsidiary, Grand
13 Prairie Energy, our company is developing a 500
14 megawatt combined cycle electric generating
15 facility in Bartlett, which is in DuPage County,
16 Illinois. We're also considering future
17 development of additional units at the Bartlett
18 site, although no definite plans for such units
19 exist as yet. We currently project start-up of
20 our facility may occur during the second quarter
21 of 2003.
22 The recently issued IEPA
23 construction permit for Grand Prairie's Bartlett
24 facility provides for a maximum NOx emission
L.A. REPORTING (312) 419-9292
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1 rate of 0.017 pounds per million Btu when
2 burning gas and 0.043 pounds per million Btu
3 when burning oil, both at maximum load. This is
4 far below the target average emission rate of
5 0.15 pounds per million Btu for all budget
6 EGUs. Nevertheless, we project that our May 1st
7 through September 30th seasonal NOx emissions
8 for 2002 and for subsequent years may be as much
9 as 90 tons and that we would be in competition
10 for allocation of the required NOx allowances
11 from the new source set-aside for the years
12 2003, 2004, and 2005.
13 Previous testimony by Agency
14 witnesses suggests that 50 or more new power
15 plants may be competing for a share of the 1,535
16 allowances available from the new source
17 set-aside for 2003, 2004, and 2005. Testimony
18 by Richard Bulley, Executive Director of MAIN,
19 at the August 23rd, 2000, Board hearing on
20 peaker plants indicates that additional
21 generating capacity beyond that which presently
22 exists in the MAIN region is essential for
23 provision of reserve generating capacity margins
24 necessary for reliable service.
L.A. REPORTING (312) 419-9292
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1 We believe the proposed number of
2 allowances for new sources will fall far short
3 of what is needed to accommodate this additional
4 capacity. We recognize that the number of new
5 source set-aside allowances is limited by
6 statute to five percent of the total EGU budget,
7 but we're also very concerned about the
8 availability of sufficient allowances on the
9 open market as a reasonable and affordable cost
10 to meet the needs of all new sources that will
11 have a need for them.
12 If allowances are not available or
13 cannot be purchased at an affordable price, we
14 would be left at a serious competitive
15 disadvantage and unable to produce the revenue
16 stream during the May through September control
17 period necessary to recover our investment.
18 Equally important, electric energy
19 customers in Illinois may see a supply shortage
20 during summer peak demand periods if newly-added
21 generating capacity cannot be operated because
22 allowances are not available.
23 We recommend, therefore, that the
24 Board maintain the new source set-aside at the
L.A. REPORTING (312) 419-9292
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1 statutory maximum and that the Agency seek
2 legislative approval to increase the maximum new
3 source set-aside to a level commensurate with
4 need to meet the projected increasing demand and
5 to maintain adequate capacity reserve. The size
6 of the new source set-aside should be whatever
7 is required to allow allocation to new sources
8 at the same ratio of allowances allocated to
9 allowances needed as is applicable to existing
10 sources listed in Appendix F of proposed Subpart
11 W.
12 We also urge that the percent new
13 source set-aside proposed by the Agency for 2006
14 and subsequent years be increased to the
15 statutory maximum with a provision that any such
16 allowances not allocated to new sources be
17 distributed to existing budget EGUs on a pro
18 rata basis. This would help new EGUs compete
19 with existing EGUs on a more nearly level
20 playing field than provided in the Agency's
21 proposal.
22 We also question the fairness of the
23 Agency's proposal to charge a fee for allowances
24 allocated from the new source set-aside for EGUs
L.A. REPORTING (312) 419-9292
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1 which begin operation after January 1st, 2003,
2 which exceeds what the Agency requires to
3 administer the NOx trading program.
4 As proposed, any fee revenue which
5 exceeds the Agency's cost for administering the
6 NOx trading program will be distributed to
7 existing EGUs. This effectively results in new
8 EGUs being forced to subsidize the operations
9 of their competitors in what is supposed to be a
10 free market for wholesale electrical power. It
11 is our contention that it is unreasonable and
12 unfair to place such a disproportionate cost
13 burden on new sources. The legislation allows,
14 but does not mandate fees for new source
15 allowances.
16 We urge the Board to reject this
17 part of the Agency's proposal or at least to
18 limit the fees to a level commensurate with the
19 Agency's administrative costs. Another concern
20 we have is that the Agency's proposal encourages
21 continued operation of old, comparatively
22 inefficient EGUs because allocation of
23 allowances is based on historic heat input
24 rather than either future heat input or net
L.A. REPORTING (312) 419-9292
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1 electric output. A much more environmentally
2 friendly approach would reward energy efficiency
3 by basing the allocation of allowances on net
4 generation or adjusting the allocations for net
5 heat rate so that comparatively efficient EGUs
6 would receive more allowances.
7 This would cause less reliance on
8 older units and greater reliance on newer units
9 and would result in lower aggregate emissions of
10 not just NOx, but particulate matter, carbon
11 monoxide, sulfur dioxide, VOM, and carbon
12 dioxide as well.
13 We believe that with these changes
14 this would result in a more equitable and
15 environmentally sound program for limiting NOx
16 emissions from electric generating facilities.
17 Thank you.
18 HEARING OFFICER GLENN: Thank you, Mr. Shea.
19 Before we ask questions of you, could I ask that
20 you make a motion to have your prefiled
21 testimony admitted as an exhibit, please?
22 MR. SHEA: I move to have my prefiled
23 testimony admitted as --
24 HEARING OFFICER GLENN: An exhibit?
L.A. REPORTING (312) 419-9292
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1 That's fine. Anyone object? The motion is
2 granted. I'm going to get a copy of your
3 testimony. Do you have one? This will be
4 marked as Exhibit 30. At the Board's hearing on
5 August 28th, we already admitted Exhibits 1
6 through 29. Just give a moment to mark this,
7 and then we will have some questions.
8 (Exhibit No. 30 marked
9 for identification,
10 9-26-00.)
11 HEARING OFFICER GLENN: Okay. Let's
12 see. What I'd like to do is see if there are
13 any questions from the Board first of Mr. Shea
14 and then go to the Agency and then the members
15 of the public that are present.
16 BOARD MEMBER FLEMAL: A clarification on
17 your own anticipated emissions at Bartlett, that
18 is 90 tons for the ozone season is what you're
19 anticipating would be your --
20 MR. SHEA: That would be the maximum.
21 BOARD MEMBER FLEMAL: It would be your
22 maximum. It could be less than that depending
23 upon how much you need to run the facility?
24 BOARD MEMBER FLEMAL: That's correct.
L.A. REPORTING (312) 419-9292
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1 HEARING OFFICER GLENN: Anyone else from
2 the Board have a question for Mr. Shea?
3 MR. RAO: That 90 tons, is that a
4 permitted rate or an annual --
5 MR. SHEA: The 90 tons is based on the
6 permitted number, yes.
7 MR. RAO: And in your testimony you --
8 you know, your reference to cost allowances, you
9 said, you know, you'd like it to be a reasonable
10 and affordable cost.
11 Has your company made any estimates
12 of what it thinks is a reasonable and affordable
13 cost for allowances?
14 MR. SHEA: The fee for the allowances?
15 MR. RAO: Uh-huh.
16 MR. SHEA: What we think would be
17 reasonable and fair would be no more than what
18 is required for the administrative cost for the
19 Agency to handle this creating program.
20 MR. RAO: Thank you.
21 HEARING OFFICER GLENN: Would the Agency
22 like to ask any questions of Mr. Shea?
23 MS. KROACK: We have no questions of this
24 witness. Thank you.
L.A. REPORTING (312) 419-9292
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1 HEARING OFFICER GLENN: Members of the
2 public? Okay.
3 MS. McFAWN: I have a question.
4 Based on your answer to Mr. Rao, if
5 the fees are limited to the Agency's
6 administrative costs, then it will always be
7 cheaper to do your trading through the Agency?
8 MR. SHEA: The problem that we have with
9 the proposal as it stands is that any fees above
10 the costs required by the Agency would be
11 redistributed back to the existing EGUs.
12 MS. McFAWN: So that's what the real
13 problem is?
14 MR. SHEA: Yes.
15 MS. McFAWN: Thank you.
16 HEARING OFFICER GLENN: Are there any
17 other questions of Mr. Shea this morning?
18 Seeing none, Mr. Shea, thank you very much for
19 your testimony this morning.
20 MR. SHEA: Thank you.
21 HEARING OFFICER GLENN: Next we will hear
22 from Mr. Darguzas, please. Good morning.
23 MR. DARGUZAS: Good morning. Members of
24 the Board, Madam Hearing Officer, Agency
L.A. REPORTING (312) 419-9292
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1 representatives, good morning, and thank you for
2 the time and courtesy of hearing us out today.
3 I would like to ask that my previously filed
4 written testimony be entered into the record,
5 and I also have a summary of the remarks that
6 I'd like to mark this morning that I would also
7 like to ask be entered this morning as a public
8 comment.
9 HEARING OFFICER GLENN: That's fine.
10 Let's do that now, if you don't mind.
11 MR. DARGUZAS: Do you mind if I
12 approach?
13 HEARING OFFICER GLENN: Please.
14 MR. DARGUZAS: This is the prefiled.
15 HEARING OFFICER GLENN: Okay. We will
16 mark the prefiled testimony of Mr. Darguzas as
17 Exhibit 31 and we will mark the supplemental
18 testimony of Mr. Darguzas as Public Comment No.
19 2.
20 (Exhibit No. 31 marked
21 for identification,
22 9-26-00.)
23
24
L.A. REPORTING (312) 419-9292
24
1 (Public Comment No. 2
2 marked for identification,
3 9-26-00.)
4 MR. DARGUZAS: Does that mean I have to
5 try harder?
6 HEARING OFFICER GLENN: Mr. Darguzas, I
7 would ask that you would send a copy of this
8 public comment to everyone on our service list.
9 MR. DARGUZAS: Yes, ma'am.
10 HEARING OFFICER GLENN: Thank you very
11 much. Please begin.
12 MR. DARGUZAS: I'd like to just summarize
13 a few of what I believe are key points that I
14 would like to bring forward for your attention.
15 My name, again, is Joe Darguzas. I'm an officer
16 with a newly formed company called EnviroPower.
17 We're headquartered in Lexington, Kentucky, but,
18 in fact, have a project going through the
19 permitting process in southern Illinois.
20 I'd like to distinguish our project,
21 perhaps, from some of the other gas turbine
22 combined cycle units that are kind of the rage
23 here in Illinois at this time. We are proposing
24 to build a solid fuel, in fact, coal waste -
L.A. REPORTING (312) 419-9292
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1 primarily coal waste fired circulation fluidized
2 bed in central Illinois. In addition to meeting
3 all of the best available control technology air
4 emissions, our project will also eliminate a
5 solid and a water waste problem that exists in
6 and around coal mines. We will use the refuse,
7 the coal refuse and the coal tailings that were
8 produced in the coal cleaning process, perhaps,
9 as long as 50 years ago as our fuel source for
10 our project.
11 With that introduction, I would like
12 to, again, highlight a few items of confusion
13 that I have about the proposed rule. I don't
14 understand why the Agency seems to be favoring
15 the existing or the so-called Appendix F
16 generating units in this rulemaking. This and
17 what I would consider the more restrictive new
18 source set-aside program proposed by the Agency
19 will hurt small start-up companies like
20 EnviroPower.
21 I really strongly believe that
22 Agency rulemaking should not shift economic
23 development opportunities to other parts of the
24 country by imposing rules that are more
L.A. REPORTING (312) 419-9292
26
1 stringent than those being proposed or being
2 considered in the states contiguous to
3 Illinois.
4 Just to give an example of, again,
5 why I believe that our clean coal fluidized bed
6 technology deserves special consideration is
7 that our uncontrolled NOx emissions will be
8 about .2 pounds per million Btu, which is lower
9 than all of the existing generating unit sources
10 listed in the Agency's technical support
11 document. We are proposing SNCR's control
12 technology and our target NOx emission with SNCR
13 on a solid fuel waste fuel whole refuse plant is
14 about .07, which, again, puts us among the best
15 of the best in the Agency's technical support
16 document.
17 To be a little more specific, our
18 project is scheduled to start up about the same
19 time as the ozone season in 2004. Based on
20 advice that we've received from the Agency, our
21 air permit application is suggesting a testing
22 program where we will try to demonstrate
23 sustainable NOx emission levels no greater
24 than .12 pounds per million and perhaps as low
L.A. REPORTING (312) 419-9292
27
1 as the .07 number that I just mentioned.
2 I presume that the Agency will then
3 make the number we demonstrate our permit
4 limit. If I understand the rules correctly, in
5 a matter of only a few years after we
6 demonstrate the lowest possible NOx emission
7 levels that we can achieve, we'll only be
8 granted allowances that are about half of what
9 we've just demonstrated as the best we can do.
10 That seems to me to be unfair on its face. We
11 would rather support -- we do support and we'd
12 rather see a rulemaking that would either grant
13 us allowances based on the .15 pounds per
14 million Btu that EPA is suggesting or our
15 permitted NOx level, whichever is lower, but not
16 to then -- then to cut us in half after we've
17 demonstrated the best that we can possibly do.
18 Thank you very much for hearing me
19 out this morning.
20 HEARING OFFICER GLENN: Thank you, Mr. Darguzas.
21 MR. DARGUZAS: Joe would be fine.
22 HEARING OFFICER GLENN: Are there any
23 questions for our witness from the Board this
24 morning?
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1 BOARD MEMBER FLEMAL: Let me just try to
2 clarify those numbers that you're talking about
3 in terms of the emissions in the units of tons.
4 In your prefiled testimony, Exhibit 31, you say
5 that your expected seasonal NOx emissions is
6 1,100 tons.
7 MR. DARGUZAS: Approximately, yes, sir.
8 BOARD MEMBER FLEMAL: And is that the
9 figure that's already halved that you speak of,
10 or do you anticipate that the allocation would
11 actually be half of this 1100?
12 MR. DARGUZAS: As best I can recall, that
13 number is based on the before half number. It's
14 based on the .12 pounds per million.
15 BOARD MEMBER FLEMAL: So 550 tons over
16 the season is what you're anticipating?
17 MR. DARGUZAS: If we can demonstrate our
18 control technology, yes, sir.
19 HEARING OFFICER GLENN: Any further
20 questions from the Board? Does the Agency have
21 any questions of this witness?
22 MS. KROACK: Yes. We just have one
23 question. Good morning, Mr. Darguzas.
24 MR. DARGUZAS: Joe.
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1 MS. KROACK: Joe.
2 Are you aware that the allocation
3 methodology for a source such as yours would
4 allow it to roll into the flex portion of our
5 allocation methodology after you've been in
6 operation for three or four years?
7 MR. DARGUZAS: Yes, ma'am.
8 MS. KROACK: Are you aware that once
9 you've rolled in the flex portion, no fee will
10 be charged for those allowances?
11 MR. DARGUZAS: Yes.
12 MS. KROACK: Thank you. That's all the
13 questions we have.
14 HEARING OFFICER GLENN: Thank you, Ms. Kroack.
15 Do any members of the public have a question for
16 our witness this morning?
17 Seeing that there are no further
18 questions of Mr. Darguzas, we thank you very
19 much for your time.
20 MR. DARGUZAS: You're welcome.
21 HEARING OFFICER GLENN: Okay. Mr.
22 Menne.
23 MR. RIESER: Good morning, Madam Hearing
24 Officer. My name is David Rieser with the law
L.A. REPORTING (312) 419-9292
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1 firm of Ross and Hardies, and I'm looking for an
2 extra copy of our testimony that was prefiled,
3 there you go, to have it marked as I believe it
4 would be Exhibit 32.
5 HEARING OFFICER GLENN: Thank you,
6 Mr. Rieser. We will mark the prefiled testimony
7 of Mr. Michael Menne as Exhibit 32.
8 (Exhibit No. 32 marked
9 for identification,
10 9-26-00.)
11 MR. RIESER: My name is David Rieser with
12 Ross and Hardies. I'm here on behalf of Ameren
13 Corporation. I would like to call Mr. Menne to
14 summarize his testimony that we've already
15 prefiled. I also have at the table Mr. Steven
16 Whitworth with Ameren Corporation to respond to
17 specific technical questions that the Board and
18 the public might have as to the operation of the
19 facilities, but I'd like to call Mr. Menne.
20 He'll be our principal witness.
21 HEARING OFFICER GLENN: Thank you, Mr.
22 Rieser. Mr. Menne.
23 MR. MENNE: Good morning. As was
24 mentioned, my name is Mike Menne. My title is
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1 manager of the environmental, safety, and health
2 department, Ameren Services division of Ameren
3 Corporation. Our offices are based in downtown
4 St. Louis, Missouri, and I'm responsible for
5 providing guidance and developing strategies for
6 environmental compliance throughout the Ameren
7 system. My staff and I have followed the
8 development of the NOx control regulations at
9 both the state and national level for the past
10 several years. I will be basically just doing a
11 summary of the written statements. So I may be
12 jumping around a little bit to try and just
13 summarize what I have to say.
14 Ameren operates six large generating
15 stations in Illinois. We burn a variety of
16 fuels, including coal, oil, and natural gas with
17 a total generating capacity of nearly 3300
18 megawatts. These are identified as EGUs under
19 this proposal and are listed in Appendix F.
20 These are base load facilities which provide
21 electricity for central and southern Illinois
22 homes and businesses. Ameren has also installed
23 over 600 megawatts of new peaking capacity in
24 Illinois over the past two years and is planning
L.A. REPORTING (312) 419-9292
32
1 several additional units may be located within
2 the state.
3 As such, Ameren should be viewed as
4 a company representing both extensive existing
5 units and a significant number of new units that
6 will be affected by this rule. I wish to note
7 for the record that Ameren has been acknowledged
8 as a leader in NOx control accomplishments at
9 our coal-fired generating facilities. Beginning
10 in 1991, AmerenUE began a series of research
11 projects and installed advanced combustion
12 control technologies on several of our
13 generating units. Our continuing commitment and
14 goal is to achieve the lowest possible NOx
15 emissions on these units which has resulted in
16 unprecedented success.
17 For the year 1999, AmerenUE operated
18 the lowest NOx emitting large coal-fired
19 generating unit in the nation and six out of the
20 ten lowest emitting units in the country. Our
21 work with the Electric Power Research Institute
22 in applying these technologies -- new
23 technologies on one of our cyclone-fired boilers
24 fire, which is a boiler with particularly high
L.A. REPORTING (312) 419-9292
33
1 NOx emissions, resulted in that cyclone-fired
2 boiler being the lowest NOx emitting
3 cyclone-fired unit in the nation, and it earned
4 the company the Governor's Pollution Prevention
5 Award for Missouri in 1998.
6 We're currently working to install
7 these technologies on all our other Ameren
8 generating units, including our largest units in
9 Illinois and are planning to install additional
10 innovative technologies on our Illinois units
11 within the next couple of years.
12 I wish to express our appreciation
13 for all the hard work that the Illinois EPA
14 staff has given to this process. This rule
15 represents the most stringent and costly
16 pollution control requirement in the history of
17 the operation of our existing generating units.
18 I believe the Agency knew this going into this
19 process and knew this would be a difficult and
20 contentious regulation. We have discussed the
21 issues with the other generators in the state
22 and have attempted to arrive at consensus
23 positions with the Illinois EPA.
24 While we do have a few minor issues
L.A. REPORTING (312) 419-9292
34
1 with the proposed rule, we believe the Agency
2 has worked hard to seek participation of
3 stakeholders and to provide consensus solutions
4 to difficult problems. Ameren commends the IEPA
5 for its hard work in developing the proposal and
6 its thoroughness in presenting its proposal to
7 the Board and to the public.
8 There are three main issues I wish
9 to cover in my testimony today. These are with
10 regard to the so-called .25 rule which was
11 alluded to earlier by the Illinois EPA, the
12 allocation of allowances, which I think is
13 probably going to be the main subject that you
14 hear from different people here today, and also
15 the issue of early reduction credits.
16 With regard to the .25 rule, you
17 might ask the question why am I bringing up the
18 .25 rule? We're talking about a SIP Call rule,
19 which is a .15 rule. The first thing I would
20 like the Board to understand is that in the
21 development of coming up with a control -- NOx
22 control program for the state, we believe that
23 we were very close to having a consensus on
24 developing this .25 rule that the Agency
L.A. REPORTING (312) 419-9292
35
1 referenced earlier.
2 The .25 rule was a rule that a
3 number of states had proposed as their answer to
4 the SIP Call. We believe the .25 rule not only
5 is all that is necessary for attainment of the
6 one-hour standard in the St. Louis area, but we
7 also believe that the additional modeling work
8 that is being done on the .25 controls in the
9 state would also have shown attainment with the
10 one-hour standard in the Chicago area.
11 We also believe that the .25 rule
12 can satisfy all the requirements under the Clean
13 Air Act for downwind transport of emissions from
14 Illinois sources on their impacts to
15 nonattainment areas. In other words, what I'm
16 suggesting is we believe, and I think the Agency
17 was concurring with us, and we're still working
18 on some modeling studies and things, that a .25
19 rule was what we needed to do to satisfy the SIP
20 Call issues. Now, since the court upheld the
21 SIP Call and the EPA has now come in and
22 basically forced NOx tonnage budgets on the
23 state, that is the reason why we're examining
24 the rule that is before you today.
L.A. REPORTING (312) 419-9292
36
1 We wanted to make you aware and we
2 feel that the .25 rule was all that was legally
3 and technically required to satisfy the SIP Call
4 if it wasn't for the fact that the federal EPA
5 is forcing the states' hand to adopt the SIP
6 Call measure.
7 I wanted to address a little bit of
8 the difference in the cost between compliance
9 with the .25 rule and the proposed rule with
10 points that I'll make later on. In the Ameren
11 electric generating units in Illinois,
12 compliance to meet the .25 rule would be roughly
13 around $30,000,000 on our units, and for that --
14 for that kind of cost, we would reduce about
15 12,000 tons of NOx. The rule that's before you
16 today is going to cost us around $130,000,000.
17 For that additional $100,000,000, you reduce
18 about 2800 tons. So the point I'm trying to
19 make is simply as you get down to these lower
20 levels, that the benefit you get for the money
21 you're applying, it really diminishes. You have
22 a point of diminish in returns. The costs go up
23 very expedientially as you get to lower and
24 lower levels. When you start talking about the
L.A. REPORTING (312) 419-9292
37
1 allowance allocation schemes, that's an
2 important concept to remember.
3 The second reason I wanted to bring
4 up the .25 rule is simply because of the fact
5 that there's still a lot of litigation going on
6 out there with regard to the NOx SIP Call. A
7 number of industries and states are going to be
8 appealing this NOx SIP Call rule to the Supreme
9 Court. There's already litigation ongoing with
10 regard to the NOx tonnage budgets that are being
11 allocated to the states. There's also
12 litigation going on with Clean Air Act, Section
13 1.6 petitions.
14 So a lot of these things can have an
15 effect on whether or not the federal NOx SIP
16 Call rule will ultimately be put in place, and
17 if that is not put in place in a number of
18 neighboring states, then we would like to see
19 the .25 rule implemented here in the state of
20 Illinois and not go forward with the NOx SIP
21 Call, and that's one reason we have encouraged
22 the Agency to develop a .25 rule for the May
23 2003 compliance time. So that rule will be in
24 place if something happens with the NOx SIP Call
L.A. REPORTING (312) 419-9292
38
1 rule.
2 There's a second area I wanted to
3 address with regard to allowance allocations.
4 You're going to hear a lot today about different
5 schemes for allocating allowances to new units
6 and to existing units. I think it's important
7 for the Board to understand that the Agency has
8 been working on this issue for a long time,
9 probably the last couple of years or more, and
10 they have looked at a lot of different
11 allocation schemes.
12 The basic problem we have here is
13 that the EPA has not given us enough tons to go
14 around. That's what it really amounts to. So
15 existing units are going to be required to
16 expend exorbitant costs to try and get their
17 emissions down to a level to try and meet this
18 rule. At the same time, there's a lot of new
19 generation coming in. They're going to have to
20 take units from the set-aside from the existing
21 units as well as they may have to go into the
22 market to purchase allowances in order for them
23 to operate each year.
24 This is a bad situation for both
L.A. REPORTING (312) 419-9292
39
1 types of units as far as I'm concerned because
2 the NOx budget is simply too low, but, in our
3 view, what the Agency has come up with is
4 probably the most and fair equitable approach.
5 You start with a five percent set-aside for the
6 new units, and then after a couple of years, you
7 begin to go into a flex portion where the new
8 units that have been in operation will gradually
9 begin to get more and more of the allowance
10 share, and then over the next couple of years,
11 they get a greater percentage until you get out
12 to ten years where basically everybody gets
13 shares based on the heat input, and we think
14 that it took a lot of thought to go into that
15 process. It considered the fact that there's a
16 lot of generation that has gone in the last
17 couple of years and is coming in on line, and it
18 is gradually allowing those new units as they
19 come in to get access to more tons.
20 At the same time what it's doing for
21 existing units, the existing units, we don't
22 know what our allocations are going to be once
23 those flex -- fixed/flex portions start to kick
24 in. We know that this will continue to ratchet
L.A. REPORTING (312) 419-9292
40
1 our emissions over time. We're going to have to
2 install more pollution control equipment over
3 time, but it creates a large uncertainty for us
4 because we're not sure exactly how many
5 allowances we're going to have to get. We're
6 not sure of the level and the degree of
7 pollution control equipment we might have to add
8 in those future years. So it does create an
9 uncertainty for us. It's a problem for us, but
10 we do believe that the system the Agency has
11 come up with is probably the most fair and
12 equitable approach.
13 I would like to address a couple of
14 things that have come up in the prefiled
15 testimony of others and that you've already
16 heard a little bit today. One is with regard to
17 new units suggesting that they should get a
18 point -- NOx allocation scheme for their new
19 units associated with .15 pounds per million
20 baseline, and they say that's what the existing
21 units allocation scheme is based on so that they
22 are making a plea that they should get the same
23 sort of NOx allocations.
24 First of all, I think it's important
L.A. REPORTING (312) 419-9292
41
1 for the Board to note that existing units will
2 not be getting enough tons allowances in NOx
3 tons to allow us to us operate at a .15 level.
4 It's going to be much lower than, and that's for
5 a couple of reasons. First of all, when EPA set
6 up a baseline tonnage budget for these states,
7 they did that based on Btus generated in 95-96
8 time frame from the electrical generating units
9 in the state. They then applied a growth
10 projection factor to the Btus that were
11 generated in those historic years out to 2007
12 and predicted what Btus would be generated in
13 the state after you assume a certain amount of
14 growth.
15 The Btus that they projected were
16 supposed to account for both new and existing
17 units. In fact, the Btus that were generated in
18 the state just by existing generators during
19 1998 already exceeded what EPA projected our
20 Btus would be in the state for the year 2007,
21 and they went higher than that in '99. They're
22 going to go higher again this year. So what
23 that causes us to do is instead of having a .15
24 tonnage allowance system that we have that would
L.A. REPORTING (312) 419-9292
42
1 allow us to operate at .15 pounds per million,
2 we have to subtract out the growth that is
3 incurring in the state, and that is going to
4 require our units to meet something like a .12
5 or .11 pounds per million Btu average just at
6 the start of this program. This is for existing
7 units.
8 Another reason for that is because
9 of the five percent set-aside for new sources.
10 That also comes out of our budget. So that
11 drives the actual emission rate that we will
12 have to meet on our existing generating units
13 down, and, as I said, that will go down lower
14 than that over time.
15 So our point is simply that even the
16 existing units are not getting NOx allocation
17 tons equivalent to .15 times our current
18 emission levels. It's much lower than that. So
19 we would strongly disagree with giving new units
20 something at .15 pounds per million level
21 because we're not even getting those kind of
22 tonnage allocations.
23 The second thing is simply that most
24 new units will operate or will need much less
L.A. REPORTING (312) 419-9292
43
1 than that level of tonnage for operation. Most
2 units will -- most new units will need 50 to 100
3 tons, a couple hundred tons per year during the
4 ozone season. There are some exceptions like
5 the gentleman who just testified who has a much
6 larger database for units.
7 However, to allow them to get
8 allowances based on .15 would be two to three
9 times as many tons as they actually need to
10 operate during the season. Existing units are
11 not asking for any excess allowances. It's
12 going to be difficult enough for us just to get
13 down to the allowances that we are given under
14 this program. So we would not want to see
15 allowances just given away to new sources.
16 That's going to make it much more difficult for
17 all of us to live under the permit.
18 I also just wanted to address
19 something that may come up since some of the
20 prefiled testimony is with regard to retiring
21 existing generators. We've worked with most of
22 the generators in the state, the companies that
23 operate generating facilities in the state and
24 have for many years and have a number of
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44
1 committees to discuss a number of issues. I am
2 not aware of any existing generators in the
3 state that have any plans for retirement over
4 the lifetime or at least until 2010 when these
5 allocations basically become equal for all
6 sources, and after 2010, the allocations are
7 based on actual heat input. So those retired
8 units, if a unit does retire after that, they're
9 not going to get allowances anymore. So I don't
10 think there's really an issue with retirement of
11 the units.
12 The last issue I wanted to discuss
13 was with regard to early reduction credits. If
14 you're trying to follow along with my testimony,
15 this picks up about three pages from the end
16 right at the bottom. Early reduction credits
17 are extremely valuable to existing units in the
18 state because they provide the time for the
19 development and installation of new innovative
20 and possibly less costly control technologies,
21 and they also provide the time necessary to
22 install and start up most expensive and
23 long-lead time control technologies.
24 Again, the problem here is that
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45
1 there are a very limited number of early
2 reduction credits available. Under the proposed
3 rule, half of the early reduction credits will
4 be made available for reductions in 2001 and the
5 other half in 2002. We believe the Agency
6 should stick with this schedule because of the
7 shift in the compliance date for this rule that
8 was alluded to earlier, allowing the early
9 reduction credits to be used in 2004 and 2005,
10 assuming that the federal EPA will allow that to
11 happen. One of the things that's in the
12 proposed rule, as I understand it, is that the
13 years in which you will earn early reduction
14 credits will slide if the compliance date for
15 the SIP Call slides, which it now has, and
16 basically what we're saying is we would not like
17 to see that happen. We'd like to see the early
18 reduction credits remain in 2001 and 2002, and
19 then apply in 2004 and 2005.
20 Our logic for this is as follows:
21 First, we fully expect that the pool of early
22 reduction credits will be oversubscribed. Thus,
23 companies will prorate the amount of early
24 reduction credits they can earn. This results
L.A. REPORTING (312) 419-9292
46
1 in considerable uncertainty as to the amount of
2 early reduction credits any given company might
3 be able to obtain, thus reducing the ability of
4 a company to know what controls will be needed
5 to comply with during -- to comply with the rule
6 during the 2004 and presumably 2005 ozone
7 season. If you delay all or part of the
8 distribution of early reduction credits, it will
9 result in a greater oversubscription of the pool
10 and increase the uncertainty for those companies
11 trying to earn those credits, and it will
12 penalize companies which have expended
13 considerable time and cost to reduce emissions
14 at an early date.
15 Second, during the development of
16 the Federal NOx SIP Call rule, it's always been
17 assumed that early reduction credits will be
18 earned in 2001 and 2002. To delay this schedule
19 will be a major setback in the achievement of
20 early air quality improvements and the
21 scheduling of NOx control projects planned for
22 EGUs. We also do not believe that one or two
23 pollution control projects at any one site
24 should consume a major portion of the available
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1 ERCs in any one year.
2 To get the most air quality benefit
3 and the largest variety of sources without
4 significant penalties to early NOx reduction
5 plans, we firmly believe the Agency should keep
6 the original early reduction credits baseline
7 and schedule for obtaining the early reduction
8 credits as proposed in the rule without the date
9 adjustment provisions.
10 The other concern we have is with
11 regard to the schedule of how the Agency is
12 planning to issue the early reduction credits.
13 Basically, their schedule would call for them to
14 issue the credits in May of the following year.
15 In other words, if they were to
16 allow early reduction credits to be earned in
17 year 2003, we would not know what our early
18 reduction credits were until May of 2004, which
19 is right at the beginning of that ozone season.
20 So really although they might provide a little
21 buffer in terms of tons, we would not be able to
22 count on them for how we were going to manage
23 compliance in the year 2004. We believe that
24 since early reduction credits are based on
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1 continuous emission monitoring information that
2 the Agency will have by the end of October of
3 the year in which they are earned, we would
4 really ask the Board to accelerate the schedule
5 in terms of when they would issue early
6 reduction credits.
7 This is also another reason why we
8 believe early reduction credits should remain in
9 the years 2001 and 2002 because that will give
10 us some certainty as to how many credits we have
11 for compliance in the 2004 ozone season. It
12 will at least give us a year's worth of time to
13 plan on what level of control we're going to
14 need for that particular season.
15 With that, I'd just like to say that
16 we appreciate the opportunity to provide these
17 comments today. I'd be happy to address any
18 questions you might have.
19 HEARING OFFICER GLENN: Thank you,
20 Mr. Menne. Do we have questions from the
21 Board?
22 BOARD MEMBER FLEMAL: Perhaps, you could
23 clarify for me just a little bit your position
24 with respect to the .25 rule.
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1 My understanding is that you believe
2 that the .25 rule would be adequate to meet our
3 requirements to come into compliance with the
4 national ambient air quality standards; is that
5 correct?
6 MR. MENNE: That's correct.
7 BOARD MEMBER FLEMAL: And that if that
8 was the only requirement before us, what we
9 ought to be entertaining is just the .25 rule
10 and nothing more stringent?
11 MR. MENNE: That's correct.
12 BOARD MEMBER FLEMAL: However, we do have
13 something else before us, and that's Part 96,
14 the NOx SIP Call, and Section 9.9 of the
15 Environmental Protection Act requires us to
16 adopt a trading program, which is also Part 96.
17 MR. MENNE: That's correct.
18 BOARD MEMBER FLEMAL: If, in fact, those
19 latter requirements remain before us, then is
20 there any utility to be entertaining .25 at
21 all?
22 MR. MENNE: First of all, let me say that
23 under the Clean Air Act, had the NOx SIP call
24 Process worked the way we believe it should have
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1 under the Clean Air Act, states should have been
2 allowed to develop their own plans to address
3 the transport issue, which I think is the Part
4 96. It's not only nonattainment. It's the
5 transport issue.
6 We believe the .25 rule would have
7 satisfied the requirements under the Clean Air
8 Act from both an air quality standpoint and a
9 legal standpoint because the 96 rules were
10 basically being forced upon the states and
11 saying that if you don't do this, we're going to
12 issue a federal implementation permit, then we
13 have to agree with this rule, and I should say
14 at the outset that we support the rule the way
15 it has been developed from the standpoint that
16 we have to meet a .15 cap and trade program.
17 You ask why it should be entertained
18 anyway, and I still think that there is some
19 chance that things will happen at the federal
20 level and the Part 96 rule will be challenged.
21 It may be thrown out. Parts of them may
22 change. If that happens under the state
23 legislation, as I understand it, if other states
24 do not come in full compliance with the SIP
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1 Call, that would prohibit the state of Illinois
2 from doing the same thing, as I understand it.
3 So what we believe is that we should
4 have a .25 rule in place so we have something to
5 make sure that we address the attainment and
6 standard in the St. Louis and Chicago area
7 and have a fall-back position for the transport
8 issue as well.
9 BOARD MEMBER FLEMAL: Should we adopt,
10 though, a transport program, as you put it, a
11 Part 96 program, even though there are these
12 uncertainties at the federal and maybe state
13 level as well?
14 MR. MENNE: Are you asking that we try to
15 make the 25 rule also presumed to be the
16 attainment -- part of the attainment for the
17 Chicago area and the transport issue as well as
18 attainment for --
19 BOARD MEMBER FLEMAL: I'm wondering what
20 your perspective I guess on that would be. I
21 think I know the answer, but let's put it on the
22 record.
23 MR. MENNE: I think it would be nice to
24 have that record. I'm not sure in the time
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1 frame that we have to deal with trying to get
2 that rule in that you can do all the modeling
3 studies and demonstrations that's necessary to
4 do that. A lot of that work was ongoing, but I
5 don't know where that stands.
6 I think once the court upheld the
7 SIP Call, I think a lot of the modeling that was
8 being done in the Midwest on the .25 control
9 strategies may have been delayed indefinitely or
10 some of it may be going on. I'm not sure.
11 You have to make a number of other
12 demonstrations to make the case for that rule
13 addressing those other issues, and while that's
14 ongoing, I don't know if it can be done in time
15 to address the time requirements in the SIP Call
16 and the need to get a .25 rule in by 2004.
17 BOARD MEMBER FLEMAL: I want to ask Mr.
18 Menne about another subject matter. Is there
19 anybody who wants to follow up on that?
20 It seems to me that if we're going
21 to have a trading program at all, a functional
22 trading program as opposed maybe to something
23 that's just on paper, you have to have both a
24 supply and demand. I think we're hearing
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1 abundantly that there's going to be a big demand
2 for allowances from your perspective.
3 Will there be a supply for
4 allowances over this next decade if we put in
5 this program?
6 MR. MENNE: Yes, there will be. For one
7 thing, utility companies are fairly notorious
8 for overcompliance, and they do that for obvious
9 reasons, but when you get down to a certain
10 level, particularly with the program that's
11 established here, a .15 cap and trade, the only
12 way to get down there on most -- I should say on
13 several of the existing generating units, you're
14 going to have to apply certain expensive control
15 technologies. The one that's out there that's
16 most selected is catalytic reduction.
17 If you apply that technology, you're
18 going to overcomply with these regulations. If
19 you do that, you're going to have excess tons
20 available. I should also say that any other
21 state, as I understand it, any other state that
22 also adopts a compliance SIP Call rule, we will
23 be allowed to trade with them, and so there will
24 be a market that opens up across numerous states
L.A. REPORTING (312) 419-9292
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1 that they will be able to get their tons from.
2 BOARD MEMBER FLEMAL: Do you see that
3 there are likely to be states that will be
4 supply states and demand -- others that will be
5 demand states just because of the regulatory
6 structure that we're dealing with?
7 MR. MENNE: That's possible. It's really
8 hard to predict because we're going into new
9 territory here because of the stringency of the
10 standard. It really is going to drive people to
11 go to very low levels on existing units, but I
12 am confident that -- you know, portions of this
13 program have already been put in place in the
14 northeast.
15 There is a market that has developed
16 there. There will be a market that will develop
17 in this case as well. It will happen simply
18 because of the need to overcomply with the
19 regulations for some certainty, and, as I say,
20 as you get down to lower levels, that will
21 create excess tons for others to purchase.
22 Our company is going to be on both
23 sides of this equation because we have quite a
24 few new units coming in as well as a lot of
L.A. REPORTING (312) 419-9292
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1 existing units.
2 MR. RAO: I have a couple of questions
3 regarding the cost impact that you discussed in
4 your prefiled testimony.
5 This $130,000,000 cost figure that
6 you present, is that for all your existing and
7 new proposed facilities in Illinois?
8 MR. MENNE: These are retrofit costs for
9 our existing units. The new units are basically
10 operating at pretty much the best available
11 technology now. We would not envision having to
12 do more on those other than somehow limit the
13 operation of those units.
14 MR. RAO: Do you have some kind of a
15 break down of the cost of how you arrive at this
16 130,000,000 dollar figure?
17 MR. MENNE: Yeah. We can provide that.
18 Basically, the 30 million is broken up into
19 multiple projects over multiple years as opposed
20 to the existing generating units. The
21 $100,000,000, which is the bulk of it, is for
22 selective catalytic reduction on two units.
23 Now, these are fairly firm costs. Those are
24 costs that come from actual bids from suppliers.
L.A. REPORTING (312) 419-9292
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1 MR. RAO: If you have, you know, that
2 information, that could helpful, and if you can
3 provide that information to the Board.
4 And, also, you referenced to a study
5 performed by H. Zinder & Associates in your
6 prefiled testimony?
7 MR. MENNE: Yes.
8 MR. RAO: And you indicate that this
9 report would be released shortly?
10 MR. MENNE: Yes.
11 MR. RAO: Do you have any idea when that
12 report is going to come out?
13 MR. MENNE: Well, we hope it will be
14 completed before the filing date of comments
15 closes for this hearing. We would be happy to
16 provide that.
17 MR. RAO: Thank you.
18 MR. STERNSTEIN: I have one minor point,
19 Mr. Menne. You earlier testified that, as
20 Mr. Rao was saying, there being an extra
21 $100,000,000 cost to reduce emissions under, I
22 believe, it was .15 standard that the Agency is
23 proposing, and how many extra tons would that be
24 of emissions reductions?
L.A. REPORTING (312) 419-9292
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1 MR. MENNE: I believe we came up with a
2 figure of 2800 tons.
3 MR. STERNSTEIN: It's 2800 tons. Okay.
4 I just wanted to clarify that. Thank you.
5 HEARING OFFICER GLENN: Are there any
6 further questions from the Board?
7 MS. McFAWN: You made a statement in your
8 testimony that the approach concerning the 0.25
9 rule would require existing EGUs to reduce their
10 NOx to 40 to 75 percent --
11 MR. MENNE: That's correct.
12 MS. McFAWN: -- below the current, and
13 then you say already reduced?
14 MR. MENNE: That's correct.
15 MS. McFAWN: Why were those already
16 reduced?
17 MR. MENNE: They're already reduced
18 because of the NOx control requirements under
19 the Federal Acid Rain program.
20 MS. McFAWN: Thank you.
21 HEARING OFFICER GLENN: Does the Agency
22 have any questions?
23 MS. KROACK: Yes. We have a number of
24 questions. Thank you. Good morning, Mr. Menne.
L.A. REPORTING (312) 419-9292
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1 You made a number of statements in
2 your prefiled testimony here today about 0.25
3 pounds of NOx per Btu as being sufficient to
4 demonstrate attainment for the Lake Michigan
5 area.
6 Can you tell me what the basis for
7 those statements are?
8 MR. MENNE: The basis for that statement,
9 really, I believe it was a statement that your
10 office made. We're not suggesting that that
11 demonstration has been made. From what we
12 understand, the -- I believe it was in
13 Mr. Kaleel's testimony the improvements between
14 a .25 rule and a .15 rule in the Chicago area is
15 on the order of one to three parts per million.
16 I believe that, from what I
17 understand of the way the modeling has come out,
18 we're still right on the edge whether or not the
19 attainment can be demonstrated in Chicago within
20 the 25 standard. My understanding is part of my
21 staff has worked very closely with the Agency
22 and LADCO and other groups in doing modeling
23 work on the Lake Michigan study, and my
24 understanding is that a demonstration could be
L.A. REPORTING (312) 419-9292
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1 made possibly using an alternative model.
2 There are two acceptable models that
3 the EPA will allow in making attainment
4 demonstrations. Additional refinements and
5 adjustments to existing modeling work may erase
6 that one or two parts per million to make it
7 attainable. That's the basis of my statement.
8 I don't know that we said that, in fact, that it
9 would make it, but I believe we said it could
10 make it.
11 MS. KROACK: Do you know that attainment
12 modeling is still going on in each of the
13 individual jurisdictions in the Lake Michigan
14 region?
15 MR. MENNE: Yes.
16 MS. KROACK: And did you know that the
17 Agency itself is conducting additional
18 modeling?
19 MR. MENNE: Yes.
20 MS. KROACK: And did you know that part
21 of that is to help for additional emissions from
22 NOx emissions from the so-called peaker units
23 and for other adjustments, such as mobile
24 emissions?
L.A. REPORTING (312) 419-9292
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1 MR. MENNE: Yes.
2 MS. KROACK: Back to your testimony on
3 costs for a minute, just a couple of questions.
4 When you evaluated the cost per ton
5 of NOx removed, did you use the same basis as
6 USEPA used in the NOx SIP Call for assessing the
7 cost, overall cost, of the NOx SIP Call?
8 MR. MENNE: We tried to. I'm not sure if
9 we used the exact formula that they did or not.
10 I believe we attempted to use the same
11 depreciation over, I think it was a 15-year
12 basis, that we based those costs on, annualized
13 costs over 15 years.
14 MS. KROACK: So did you look at emissions
15 from the base 2007 emissions to the expected
16 reductions from the NOx SIP Call to calculate
17 cost effect based on tonnage reduction from that
18 2007 base to the NOx SIP Call base?
19 MR. MENNE: By the 2007 base, you mean
20 uncontrolled?
21 MS. KROACK: Uncontrolled with growth,
22 growth factor applied.
23 MR. MENNE: Yes. I believe that's the
24 way we kept the cost was based on what was
L.A. REPORTING (312) 419-9292
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1 assumed in that baseline in terms of controls
2 already being on to some extent, but it's
3 uncontrolled, that baseline, to the NOx SIP
4 Call.
5 The marginal cost I'm talking about
6 in my testimony, I'm talking a marginal
7 reduction cost of 8200 tons. That is the
8 difference between .25 and the SIP Call.
9 MS. KROACK: Thank you for clarifying
10 that. I think I have one more question. Give
11 me a moment here.
12 The next question I have is you made
13 a statement here today about the 0.25 pounds per
14 NOx emission rate being sufficient to address
15 transport in the region covered by NOx SIP Call.
16 Can you tell me what the basis for
17 that statement is?
18 MR. MENNE: The basis for that statement
19 is modeling work that has been done by the
20 Midwest Ozone Group and their consultants.
21 MS. KROACK: So that actually was
22 modeling?
23 MR. MENNE: Right.
24 MS. KROACK: Okay. Thank you.
L.A. REPORTING (312) 419-9292
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1 HEARING OFFICER GLENN: Does anyone else
2 have any questions of Mr. Menne? Yes, Mr.
3 Urbaszewski.
4 MR. URBASZEWSKI: Mr. Menne, is LaGrange
5 Power an Ameren Company?
6 MR. MENNE: Yes, it is.
7 MR. URBASZEWSKI: I believe Ameren is in
8 the process of switching that unit from coal to
9 gas-fired generation, correct?
10 MR. MENNE: That's correct.
11 MR. URBASZEWSKI: And under the rules,
12 you view that as not a shutdown of the unit, but
13 a control technology?
14 MR. MENNE: It is a repowering of the
15 unit.
16 MR. URBASZEWSKI: Repowering?
17 MR. MENNE: Yes.
18 MR. URBASZEWSKI: However, you are going
19 to be getting an allocation for that facility
20 based on coal generation, correct?
21 MR. MENNE: Initially, I would assume
22 that's the way it would work.
23 MR. URBASZEWSKI: However, it will
24 operate under gas and needing far fewer NOx
L.A. REPORTING (312) 419-9292
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1 allocations?
2 MR. MENNE: Under the flex provisions, it
3 would eventually get the amount of heat input
4 that goes into that unit.
5 MR. URBASZEWSKI: Thank you.
6 HEARING OFFICER GLENN: Does anyone else
7 have questions this morning of Mr. Menne? All
8 right. Seeing there are no more questions
9 Mr. Menne, thank you very much for your time
10 this morning.
11 Let's go off the record for just a
12 few minutes, please.
13 (Discussion had
14 off the record.)
15 HEARING OFFICER GLENN: We're going to
16 take a ten-minute break. If everyone would
17 please return at 11:00 o'clock. Thank you.
18 (Break taken.)
19 HEARING OFFICER GLENN: It is 11:10. We
20 are back on the record, and the Agency would
21 like to present a motion to amend. So what I
22 would like to do at this point is suspend the
23 testimony for a little while and give the Agency
24 an opportunity to present their motion, walk us
L.A. REPORTING (312) 419-9292
64
1 through it, and then take questions on the
2 motion, and then we will resume testimony.
3 If the time comes that we need to
4 break for lunch, we will do that, and without
5 further ado, Ms. Kroack, would you like to --
6 MS. KROACK: Actually, Ms. Herst will
7 submit it since she was the drafter.
8 HEARING OFFICER GLENN: Great. Ms.
9 Herst, would you like to present your motion to
10 amend?
11 MS. HERST: We would like to submit this
12 motion to amend as whatever exhibit it comes out
13 to be.
14 HEARING OFFICER GLENN: I have a copy
15 here. We will admit it as Exhibit No. 33.
16 (Exhibit No. 33 marked
17 for identification,
18 9-26-00.)
19 HEARING OFFICER GLENN: Did you have
20 enough copies of the motion to amend to give to
21 the audience today?
22 MS. KROACK: Does anybody need a copy of
23 the motion to amend?
24 HEARING OFFICER GLENN: If we need more
L.A. REPORTING (312) 419-9292
65
1 copies, we'll get them made. Are there enough
2 copies of the motion, or do we need to make
3 more? All right.
4 Ms. Herst?
5 MS. KROACK: Actually, I'll go through
6 it. Ms. Herst is the attorney of record on the
7 motion. So I felt she should submit it.
8 I think the best way to do this, to
9 go through this, is to go through the attachment
10 B, which is in the back of the motion. When we
11 put the motion together, we broke it down to
12 changes we were making in response to the
13 court's August 30th, 2000, order in the NOx SIP
14 Call litigation. The next number of changes
15 were changes that we were making to respond to
16 USEPA's conditional approval published in the
17 Federal Register on March -- it was -- the
18 proposed conditional approval published at
19 volume 65 of the Federal Register, page 52967 on
20 August 31st, 2000, and then there had been some
21 additional comments we had received from
22 representatives of the electrical generating
23 units here today on minor language changes that
24 we agreed to make.
L.A. REPORTING (312) 419-9292
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1 So rather than breaking it down that
2 way and skipping through the rule, I'll just
3 start what the attachment. We're proposing to
4 amend Sections 211.1320 and 211.1324 to add the
5 language allocation of allowances as described
6 in as you can see in the underlined language.
7 Just to denote that, for the
8 purposes of commence commercial operation and
9 commence operation, those terms, as applied to
10 part 217, deal with allocation of allowances,
11 and this was a comment of Ameren through their
12 attorney, Mr. Rieser. Section 211.1515, the
13 change there is the change necessitated by the
14 court's ruling denoting that in the 2004 control
15 period, it's a partial control period beginning
16 on May 31st rather than May 1st.
17 The next change, it's Part 217,
18 217.750, purpose. Again, the change there is
19 adding the language to reflect the 2004 control
20 period as a partial control period. 217.736
21 compliance requirements, we make a change in
22 Subsection D, as in dog, (3), again, the
23 language is to denote the change in the start of
24 this program from May 1st, 2003, to May 31st,
L.A. REPORTING (312) 419-9292
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1 2004.
2 The next change we make in that
3 section is Subsection F. We had it broken into
4 Subsections F(5)(a) and F (5)(b), and Mr. Rieser
5 pointed out to us that the owner or the operator
6 of the budget electrical generating unit has
7 excess emissions is the one that's subject to
8 the fine rather than the account
9 representative. It was a drafting error. We
10 broke that section into two sections, Subsection
11 F(5) and Subsection F(6) to the account
12 representative's responsibility is to surrender
13 allowances and the owner/operator is the
14 responsible party for fines, penalties, or other
15 assessments.
16 Section 217.758, permitting
17 requirements, these changes, again, are tied to
18 the date of the NOx SIP Call moving them forward
19 one year as the NOx program moved forward one
20 year. We didn't attempt to account for any
21 partial adjustments making the rule too
22 complicated and only applicable for one year.
23 So we moved those dates from 2002 to 2003, and
24 that would be in Subsections A(4), A(5), and
L.A. REPORTING (312) 419-9292
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1 A(6) in section 758.
2 A comment in 217.758, Subsection (3)
3 was a change we made based on Mr. Rieser's
4 request stating basically how the permit --
5 budget permit works in that it's folded into an
6 existing permit, federally enforceable permit,
7 for the unit if one exists already. It was
8 clarifying language.
9 Section 217.760, NOx trading budget,
10 we made changes in Subsections A(1) and A(2) to
11 change the dates -- to slide the dates by one
12 year based on the court's order. Subsection
13 217.760(b), we changed the Agency may to the
14 Agency shall based on a comment of Mr. Rieser on
15 behalf of Ameren, and this is the language that
16 requires us to adjust the budget available for
17 allocation for units opting into the program.
18 217.764, we made changes in
19 subsections, or proposing changes to be more
20 accurate, Subsections A, B, C, D, E, and F to,
21 again, slide the dates one year to reflect the
22 change of the court in the NOx SIP Call
23 implementation date, and I don't intend to go
24 through those one by one. It's self-explanatory
L.A. REPORTING (312) 419-9292
69
1 I think.
2 217.768 is the new source set-asides
3 for new budget EGUs. We are proposing a change
4 to a number of subsections here. Again, these
5 changes are to reflect the slide of the dates
6 from implementation of the NOx SIP Call based on
7 court order, and these changes appear in
8 Subsections B, C, F, G, H, I, J, K, and L.
9 Section 217.770 is the early reduction credits
10 for budget electrical generating units. When we
11 looked at this section, we weren't -- it wasn't
12 clear to us what USEPA was going to do with the
13 early reduction credits portion of the NOx SIP
14 Call, whether they will slide the dates that
15 allowances may be earned to add years to allow
16 2003 to be an additional year which you may earn
17 early reduction credits or whether they'll keep
18 the same two years or whether they'll make it
19 instead of '01, '02, and '03, it will be '02 and
20 '03.
21 We also weren't clear what dates
22 they would require that those early reduction
23 credits be used, whether it would remain '04 or
24 whether they would add '05. Obviously, '03
L.A. REPORTING (312) 419-9292
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1 doesn't work because the program isn't in
2 effect. Based on that and the comments from the
3 electrical generating units in our last meeting
4 following the issuance of this order, we
5 proposed to do the following: We are going to
6 allow early reduction credits to be earned in
7 '01, '02, and '03 to be used in '04, and we've
8 added language, where later control periods
9 authorized by USEPA, which we hope will allow us
10 to allow the EGUs to use those early reduction
11 credits in later years if USEPA so authorizes.
12 For reductions in '03, we are
13 allowing reductions to be earned in '03 only if
14 the compliance supplement pool set aside for '01
15 isn't fully distributed, and the reason for that
16 is we are concerned that our SIP revision may
17 not be approved by USEPA. If it is not, the NOx
18 SIP Call currently provides that if your SIP
19 isn't approved, you may not distribute early
20 reduction credits prior to that date. So we are
21 concerned that that might happen. We also
22 wanted to provide the flexibility that it they
23 weren't used in -- weren't earned
24 in '01 or '02, they could be earned in '03 as
L.A. REPORTING (312) 419-9292
71
1 well.
2 No. If USEPA does not approve it by
3 May 1st -- our SIP revision by May 1st of '01
4 and we wanted to slide the dates, early
5 reduction credits could be used for two years,
6 and those are the reasons that we made the
7 changes in Subsection (2), and it shows that
8 early reduction credits can be earned over three
9 years, and Subsection F(2)(a), it says if USEPA
10 has approved this subpart as a SIP revision, not
11 more than one-half the total early reduction
12 credit allowances can be earned, the reductions
13 made in the control period 2001, and, B, not
14 more than one-half of the total early reduction
15 credit allowances for reductions made in the
16 control period 2002 and, C, any early reduction
17 allowances not allocated pursuant to the
18 Subsections F(2)(a) or (b) of the section
19 reductions made in the control period 2003.
20 In Subsection E, going back one, we,
21 again, provide for the use of the early
22 reduction credits for later years if USEPA
23 permits this in any rulemaking or guidance. In
24 G, we had concerns that -- concern was expressed
L.A. REPORTING (312) 419-9292
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1 by Ameren, among others, that the date by which
2 the Agency informed the electrical generating
3 units whether they were getting ERCs and how
4 many they would be getting was too late. So we
5 moved that date from May to March, and we added
6 Subsection G(3) to allow for any early reduction
7 credits that are earned in 2003, and H and I,
8 again, reflect the movement of the NOx SIP Call
9 implementation date by one year, and I also
10 reflect when early reduction allowances may be
11 used allows for additional time as USEPA might
12 authorize, and then the last changes that we're
13 proposing are in 217.782, and this is allowance
14 allocations to budget opt in units. We are
15 adding Subsection A(6) to provide that sources
16 that may opt in may not be any unit located at a
17 source listed in Appendix D of this part.
18 Appendix D of this part, as you may
19 recall, are the nonelectrical generating units
20 which will be subject to a similar rulemaking in
21 a future proceeding, and for the purposes of
22 integrity of their different allowance
23 allocation pools, we felt that we need to make
24 this language clear that they could not opt in
L.A. REPORTING (312) 419-9292
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1 to Subpart W, but had to opt instead to Subpart,
2 to be proposed, U, and the last change in here,
3 217.782(b)(2)(b) of the language change was
4 based on a comment by USEPA stating that we
5 would allow -- allocate allowances to the budget
6 opt in unit by multiplying it by the lesser of
7 the unit's baseline NOx emission rate determined
8 pursuant to Section 217.776(c) or the lowest NOx
9 emissions limitation applicable to that unit for
10 the year of the control period in which
11 allowance allocations are given as opposed to
12 the control period a year prior, and this was a
13 USEPA approvability comment, and we felt it
14 appropriate to suggest that change today.
15 I believe I've covered them, and I
16 am more than happy -- I will provide various
17 Agency people to answer any questions you might
18 have on the proposed changes.
19 HEARING OFFICER GLENN: Thank you,
20 Ms. Kroack. Do any members of the Board have
21 questions of anything in the motion? Let's open
22 it up to the public. Does anyone in attendance
23 today have any specific questions? Let's go
24 with Mr. Rieser and then we'll go to Mr.
L.A. REPORTING (312) 419-9292
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1 Urbaszewski.
2 MR. RIESER: Thank you, Madam Hearing
3 Officer. Looking at 217.756(f), page two of the
4 attachment you modified the original F(5), F(5)
5 and F(6), but F(6) still has the -- states that
6 the owner/operator of the budget EGU shall pay
7 any fine. I think we had suggested that the
8 shall pay suggested that there was a regulatory
9 requirement that any fine levied be paid and
10 that would be both a regulatory requirement and
11 a permit requirement since I think these things
12 are also incorporated into the permit.
13 I had suggested language that would
14 say that the owner/operator would be potentially
15 liable for a fine in addition to the removal of
16 the surrender of the allowances, rather than
17 there being an apparent regulatory requirement
18 that the owner/operator must pay a fine in this
19 circumstance.
20 MS. KROACK: Okay. I'm not sure that we
21 understood your comment on that level. We'll
22 look at it and we'll address it in our written
23 comments.
24 MR. RIESER: Thank you very much.
L.A. REPORTING (312) 419-9292
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1 HEARING OFFICER GLENN: Mr. Urbaszewski,
2 did you have a question?
3 MR. URBASZEWSKI: Yes. Just for the
4 allocations for the 2004 season, the abbreviated
5 season taking one month of a five-month ozone
6 season, that May 31st date, is it your
7 understanding that all allocations are going to
8 be given out for that four-month period rather
9 than five-month period and, therefore, EGUs will
10 be allowed essentially at a 20 percent increase
11 in emissions over the control period?
12 MR. LAWLER: This is an issue that USEPA
13 will have to address, and at this point, we
14 don't know how they're going to address it. We
15 know they're considering different options, and
16 so at this point, we've written it the way we've
17 written it, and we're going to have to see.
18 So it's possible. In answer to your
19 question, it's possible that if EPA decides,
20 because they issued the allocations, and they
21 decide that all of those will be available in
22 the first year, that's the way we'll view it
23 also, but we don't know.
24 MR. URBASZEWSKI: But it's your
L.A. REPORTING (312) 419-9292
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1 understanding that it has to be consistent
2 across the domain because of trading reasons?
3 MR. LAWLER: Yes.
4 HEARING OFFICER GLENN: For the record,
5 that was Mr. Lawler from the Agency.
6 MR. LAWLER: Sorry.
7 HEARING OFFICER GLENN: Are there any
8 other questions on the motion? If after lunch
9 people come up with more questions, we will open
10 the floor back up so you'll have a chance to
11 look at this more closely during the lunch
12 hour.
13 If there are no more questions right
14 now on the motion, however, we will go back to
15 hearing from our witnesses that filed prefiled
16 testimony. Okay. Mr. Urbaszewski, would you
17 like to present your testimony, please?
18 MR. URBASZEWSKI: Shall I?
19 HEARING OFFICER GLENN: Yes, please.
20 We'll admit Mr. Urbaszewski's testimony as
21 Exhibit No. 34.
22 (Exhibit No. 34 marked
23 for identification,
24 9-26-00.)
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1 MR. URBASZEWSKI: My name is Brian
2 Urbaszewski. I'm the director of environmental
3 health programs for the American Lung
4 Association in Metropolitan Chicago. However, I
5 am filing joint comments on behalf of the Lung
6 Association, the Illinois Environmental Council,
7 the Environmental Law and Policy Center, and
8 the Illinois Public Interest Research Group or
9 Illinois PIRG.
10 The American Lung Association of
11 Metropolitan Chicago was founded in 1906 to
12 concur tuberculosis. Today the Lung Association
13 is committed in eliminating all respiratory
14 diseases, including cancer, emphysema, and
15 asthma. Our mission is to promote the
16 importance of lung health to reduce the pain and
17 suffering caused by lung disease, the third
18 leading cause of death and disability in the
19 United States. We represent more than a million
20 people in Chicago and the suburbs who suffer
21 from some form of lung disease, including more
22 than 96,000 children with asthma. With that
23 intro, I'd like to go directly to my testimony.
24 These groups support the Illinois
L.A. REPORTING (312) 419-9292
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1 Environmental Protection Agency's proposal to
2 implement a control level of .15 pounds per
3 million Btu standard for electrical generation
4 units in Illinois. We disagree with the Agency
5 on how best to implement this NOx reduction
6 program that incorporates this level of
7 emissions reduction. Although the state is
8 allowed flexibility in adopting the EPA model
9 rule, the .15 level emission standard for EGUs
10 must be met if the state chooses to participate
11 in an interstate market in which tradable NOx
12 pollution allowances can be bought and sold.
13 The standard should not be weakened since in
14 addition to the federal requirement for
15 interstate ozone transport control and the
16 threat of federal implementation plan if the
17 state fails to meet this obligation, the
18 proposed level of NOx reduction is also
19 necessary, we believe, for the Agency's plan to
20 meet one-hour ozone standard in the Chicago
21 Ozone Nonattainment area, and I'm basing that
22 allegation on the information that was presented
23 by the Agency as an exhibit at the last
24 meeting.
L.A. REPORTING (312) 419-9292
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1 In fact, several significant
2 uncertainties provide serious doubts as to
3 whether the proposed rule will adequately
4 protect public health. The reasons are the
5 Agency has miscalculated ozone precursor
6 emission reductions in the recent past and
7 underestimated them. Federally approved methods
8 for calculating those ozone precursor emissions
9 used by the Agency substantially underestimate
10 actual real world emissions of ozone precursors,
11 and it is unclear how a .15 pounds per million
12 Btu rule would ensure that citizens of the state
13 do not suffer from ozone levels deemed
14 unhealthful for sensitive individuals.
15 Environmentalists, therefore,
16 propose an alternative proposal which will
17 significantly increase the likelihood that the
18 health of the citizens of Illinois are
19 adequately protected. Our proposal, as set
20 forth, go into the details, utilizes an
21 output-based allocation and reallocation
22 methodology that has already been proposed
23 previously; includes a new source set-aside that
24 will award NOx allowances sufficient to allow
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1 post-1995 EGUs to operate; requires an equal
2 reallocation of NOx allowances to existing old
3 and new EGU units based on the rate of 1.5
4 pounds per megawatt hours; continues a new
5 source set-aside of at least five percent of the
6 EGU budget in the out years beyond the first
7 reallocation period, and, five, includes an
8 additional set-aside that awards NOx allowances
9 to energy efficiency and renewable energy
10 projects that displace NOx emissions from EGUs.
11 I'll skip what I allege are miscalculations of
12 past emissions reductions by the Agency. They
13 have been corrected in the nine percent rate of
14 progress plan for the Chicago Nonattainment
15 Area, and I would also like to say that although
16 the Lake Michigan Air Directors Consortium, the
17 entity that models attainment strategies for
18 Illinois and the Midwestern states also assures
19 us that the same mistakes did not occur in the
20 attainment model presented to the Board. I
21 wanted to present this, however, as a fact that
22 mistakes do happen and that mistakes
23 overestimating emissions reductions have been
24 made.
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1 In addition, shortfalls in emission
2 reductions needed for an attainment
3 demonstration may also be beyond the control of
4 the Agency. Much of Illinois' emissions
5 inventory of ozone precursors, and the Agency
6 may be seriously underestimating the actual real
7 world emissions from these courses even while
8 using approved federal methodologies. I want to
9 say on May 12th, 2000, the National Academy of
10 Sciences issued a report, Modeling Mobile Source
11 Emissions, which noted that the mobile model
12 substantially underestimates VOC emissions of
13 unburned fuel from cars and nitrogen oxides from
14 diesel trucks. Both are major sources of ozone
15 precursors in the Chicago area. On-road mobile
16 sources are responsible for 37 percent of all
17 VOC emissions and 55 percent of the NOx
18 emissions in the Chicago nonattainment area
19 according to the Agency.
20 The likelihood that emissions
21 reductions have been underestimated from mobile
22 sources makes a .15 pound per million Btu NOx
23 rule or a 1.5 pounds per megawatt hour NOx rule,
24 all the more important to ensure that the
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1 Chicago Ozone Nonattainment Area meets the
2 one-hour standard by 2007 attainment deadline.
3 Illinois was also required to submit
4 an attainment plan for meeting the one-hour
5 standard back in 1994 and this plan is still not
6 in place, but we hope it will be in by the end
7 of the year. To the state's credit, Illinois
8 EPA was a leader in the Ozone Transport
9 Assessment Group's, OTAG's, search for a
10 regional approach to the ozone problem, and this
11 development led to the NOx SIP Call from USEPA.
12 Yet, even if the Agency believes the
13 reductions required by the NOx SIP Call are
14 sufficient in scope to bring the Chicago
15 Nonattainment Area into attainment with the
16 one-hour standard, significant health problems
17 will persist due to unhealthful ozone levels in
18 the region.
19 Recent medical studies have shown
20 that ground-level ozone is even more of a
21 persistent and damaging phenomena than
22 previously thought, and this knowledge led to
23 the more protective eight-hour National Ambient
24 Air Quality standard promulgated by USEPA in
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1 1997.
2 In addition, in 1999, the USEPA
3 chose the eight-hour concentration level of
4 ozone corresponding to the eight-hour ozone
5 National Ambient Air Quality Standard as, quote,
6 unhealthy for sensitive populations in its use
7 in the Air Quality Index. The AQI, or Air
8 Quality Index, is used nationally to communicate
9 air quality to the general public, and it's
10 governed by Section 319 of the federal Clean Air
11 Act, which requires USEPA to establish this
12 uniform Air Quality Index. This requirement is
13 independent of the statutory provisions
14 governing establishment and revision of the
15 National Ambient Air Quality Standards.
16 However, USEPA noted in using this level to
17 provide information to the public on air quality
18 and health that the scientific record and
19 conclusions underlying studies that examined the
20 health impacts of ozone are more than sufficient
21 as a basis for decisions on the levels at which
22 the public should be notified about health risks
23 associated with daily air quality.
24 So even though health warnings are
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1 issued on days when the eight-hour ozone
2 concentration reaches levels unhealthy for
3 sensitive groups, it is unclear how much
4 improvement the .15 pounds per million Btu
5 standard proposed by the Agency for EGUs will
6 provide in lowering these eight-hour ozone
7 levels. As the Agency stated in the first
8 hearing on this matter, the Lake Michigan region
9 endured 36 days in 1999 alone when the ambient
10 ozone levels exceeded ozone levels deemed
11 unhealthy for sensitive groups.
12 In fact, based on medical and
13 epidemiological research that documents health
14 effects related to ozone exposure and using
15 actual 1997 ambient ozone measurements, a study
16 has been done that estimates the impact of ozone
17 levels on the populations of 37 states covered
18 in the OTAG region, which is a larger group of
19 states than the actual number of states that
20 have to comply with the NOx SIP Call, but it was
21 the original study area.
22 The study concluded that ambient
23 levels of ozone in Illinois were responsible for
24 numerous health impacts, including 7,200
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1 emergency room visits, 2,400 hospital emissions
2 for respiratory reasons, as well as over an
3 additional 310,000 asthma attacks. Short-term
4 exposure to ozone has also been linked to a
5 variety of minor symptoms, including cough, sore
6 throat, head cold. This study estimated that
7 over 4,000,000 instances of such minor symptoms
8 occur in Illinois as well.
9 At best, the draft rule, along with
10 subsequent rules for other NOx emission sources,
11 coming forth from the Agency may comply with the
12 legal requirements of the NOx SIP Call, but will
13 still leave Illinois with air unhealthy for
14 sensitive groups. Great uncertainty still
15 exists whether the Agency proposed rules will
16 meet federal requirements protect and public
17 health in Illinois. This is true since we know
18 actual ozone precursor emissions are
19 underestimated and computer modeling based on
20 those emissions inventories is being used to
21 bolster claims of attainment with the one-hour
22 standard. Illinois citizens face continuing
23 health danger from ozone levels even below the
24 one-hour National Ambient Air Quality Standard
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1 for ozone that has been designated unhealthy for
2 -- has been designated as unhealthful.
3 In short, the Agency approach is not
4 consistent with the Illinois Constitution, which
5 states that each person has the right to a
6 healthful environment and that the public policy
7 of the state and the duty of each person is to
8 provide and maintain a healthful environment for
9 the benefit of this future generation.
10 Given the uncertainty, the Board
11 must therefore decide which interested party
12 should get the benefit of this doubt, the
13 polluting industry which has an interest in
14 limiting emissions controls, or the citizens of
15 Illinois who have no choice but to breathe these
16 emission by-products and suffer the health
17 consequences. We believe that the public
18 deserves the benefit of that doubt.
19 I'd like to now go into some
20 suggested rule changes. The methods proposed by
21 the Agency for awarding initial NOx allowances
22 to EGUs and the fixed-flex system which delays
23 the full implementation of the USEPA proposed
24 model rule trading system beyond 2011 are
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1 flawed, and forgive me if I'm off about a year
2 or two. I tried to adjust my dates to account
3 for the 2004 date that the court just came out
4 with. Environmentalists recommend that the
5 draft Illinois NOx reduction rule should be
6 modified to, again, use an output-based
7 allocation and reallocation methodology; include
8 a new source set-aside that will award NOx
9 allowances sufficient to allow post-1995 EGUs to
10 be operated; require and equal reallocation of
11 NOx allowances to existing old and new EGU units
12 based on a rate of 1.5 pounds per megawatt
13 output-base standard; continue the new source
14 set-aside of at least five percent in the out
15 years beyond the first reallocation period; and
16 include an additional set-aside for energy
17 efficiency and renewable energy projects.
18 A NOx reduction rule for Illinois
19 should create an incentive for all EGUs to
20 produce electricity with the least amount of
21 smog-forming or ozone forming pollution per unit
22 of electrical power generated. Within the scope
23 of an Illinois NOx trading program, NOx
24 allocations should be allocated on an
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1 output-based measure such as pounds of NOx per
2 megawatt hour that directly reflect the
3 pollution efficiency of electrical generation.
4 The states of Massachusetts, New Jersey, and
5 Connecticut have adopted such a system and are
6 using a rate of 1.5 pounds per megawatt hour. A
7 modified heat-input based allocation
8 methodology, as proposed by the Agency, awards
9 NOx credits based simply on the amount of fuel
10 burned and does not encourage pollution
11 efficiency and rewards existing older and
12 pollution inefficient generation facilities by
13 minimizing incentives to achieve higher
14 efficiency in generation. By higher
15 efficiencies, I mean pollution per electricity
16 generated.
17 A new source set-aside should also
18 be sufficient to provide allocations to all
19 generators expected to be operating at the start
20 of the program in 2004. Even though this is
21 currently prohibited by a state law passed in
22 1999, which limits the new source set-aside to
23 five percent of the EGU budget, and Illinois
24 rule should reflect the goals of the national
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1 USEPA model NOx reduction rule in treating both
2 older and post-1995 generation facilities
3 equally in any allocation and reallocation
4 methodology. It is our contention that the
5 Agency and the General Assembly severely
6 underestimate the demand for new source
7 set-aside allocations, and as structured, the
8 five percent cap in the new source set-aside
9 unfairly raised the operating costs of new, more
10 pollution efficient, electrical generation units
11 while favoring older, more polluting, pre-1995
12 electrical generation units.
13 After the period covered by the
14 initial three-year allocation is complete and
15 assuming a new source set-aside is adequate to
16 cover the needs of all new EGUs in the first
17 three years of the program, EGUs that operated
18 prior to 1995 and received initial NOx
19 allocations and the newer post-1995 EGUs should
20 be treated equally in a reallocation methodology
21 based on generation efficiency. We believe both
22 subsets of the EGUs should have equal access to
23 credits awarded.
24 In short, both groups, pre and
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1 post-1995 EGUs, should receive allocations for
2 the fourth and fifth years of the program based
3 on the standard of 1.5 pounds per megawatt
4 hour. If there is an oversubscription of the
5 available allowances, they should be prorated
6 among these EGU sources based on recent
7 historical electrical generation.
8 Facilities that do not operate
9 within an allocation period and receive NOx
10 allocations from the state for that period
11 should not be granted allowances for subsequent
12 periods. Initial baseline heat input for EGUs
13 operational prior to 1995 should not be used to
14 lock in guaranteed allocations until the eighth
15 year of the program as the Agency has proposed.
16 The Agency itself has noted that an allowance
17 allocated by the Agency or by USEPA under the
18 NOx trading program does not constitute a
19 property right. If a facility has permanently
20 ceased operation prior to reallocation, it does
21 not need a NOx allocation for subsequent control
22 periods, and gifting NOx allocations to a
23 nonoperational or possibly even nonexistent EGU
24 is inconsistent with the principle that the
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1 allocation is not a property right.
2 We also believe that a five percent
3 new source set-aside should be kept in the sixth
4 year of the program. The energy efficiency and
5 renewable energy set-aside, the Agency's draft
6 rule also misses an exceptional opportunity to
7 establish an energy efficiency and renewable
8 energy set-aside, which would simultaneously
9 reduce the costs of complying with the NOx SIP
10 Call while providing Illinois with major
11 economic and environmental benefits. We
12 strongly recommend that the Board reject the
13 Agency's shortsighted action in dismissing the
14 need for this program and require the creation
15 of an energy efficiency and renewable energy
16 set-aside. The set-aside should include at
17 least ten percent of the Illinois EGU NOx
18 budget.
19 As the USEPA stated in a Guidance
20 Document describing how states could set up
21 set-asides, states have a great opportunity to
22 take advantage of the economic and environmental
23 benefits of energy efficiency and renewable
24 energy in developing a NOx transport mitigation
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1 strategy. By including an energy efficiency and
2 renewable energy set-aside in a state's NOx
3 Budget Trading Program, states can prevent
4 growth in NOx emissions, avoid building
5 additional generating capacity, save energy and
6 consumer dollars, and put additional jobs and
7 money into their local economies. This is from
8 -- the reference is from the USEPA guidelines.
9 USEPA succinctly stated three key
10 reasons for a state to include an energy
11 efficiency and renewable energy set-aside; to
12 reduce the total economic cost of meeting the
13 proposed NOx cap; to promote energy efficiency
14 by accelerating the adoption of energy efficient
15 practices and technologies; and to reduce future
16 C02-related liabilities by recognizing the
17 positive impacts of energy efficiency and
18 renewable energy on carbon emissions. Such a
19 set-aside would possibly also assist in reducing
20 electrical demand and may reduce stress on the
21 regional transmission and distribution system or
22 electricity transport that would otherwise be
23 expected to occur due to electrical load
24 growth.
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1 Detailed written public comments
2 setting forth recommendations on how Illinois
3 should establish its set-aside will be provided
4 in the near future by the Environmental Policy
5 Center and will draw on two subsequent documents
6 that the USEPA has come out with for guidance on
7 how to design such a set-aside.
8 Environmentalists strongly believe
9 the above elements in an output-based rule are
10 necessary to construct the most equitable and
11 efficient system for improving air quality and
12 public health in the Chicago region, while
13 meeting the demands of the NOx SIP Call. It
14 would be unfortunate if, due to the fast-track
15 nature of this rulemaking, these provisions were
16 not included in the final rule and the rule
17 implemented -- and the rule was not implemented
18 right the first time. If, due to lack of time
19 under the fast-track requirements, the Board
20 determines that it is prevented from
21 incorporating these admittedly major
22 restructuring elements into the final rule,
23 there is still an opportunity for improvement in
24 the framework the Agency has put forth as the
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1 proposed rule.
2 The following describes how to move
3 the rule towards providing the necessary public
4 health protections: Using an input-based
5 system, as the Agency has proposed, all EGUs
6 should be treated equally in the NOx allocation
7 -- the NOx allowance reallocation process.
8 At the first reallocation for the
9 fourth year of the program, EGUs given
10 allocations based on pre-1995 operational status
11 or from the new source set-aside or which were
12 not awarded allocations because of the small
13 size, but were forced to buy NOx credits on the
14 open market should receive NOx allocations based
15 solely on the recent heat input of that facility
16 and a rate of .15 pounds per Btu. Reallocation
17 in subsequent years should continue this
18 methodology.
19 The General Assembly deregulated the
20 electricity industry in Illinois in 1997 in part
21 to promote competition in the supply of
22 electricity. Yet, in early 1999, the General
23 Assembly limited the new source set-aside for
24 the post-1995 EGUs in the NOx trading program to
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1 a maximum of five percent of the total EGU
2 budget. As the Agency has noted, in recent
3 months, it has become apparent that this is
4 insufficient to cover the allocations needed by
5 these new EGUs and could underestimate the
6 actual need by more than a factor of six.
7 Deliberately depriving the vast
8 majority of new sources, many of which are
9 already operating or are under construction, of
10 NOx allocations that they will need several
11 years in the future to put new electric
12 providers at a competitive disadvantage. They
13 must incur additional costs to meet more
14 stringent environmental regulations than the
15 older, pre-1995 generation facilities must meet,
16 yet they are being forced to pay their direct
17 competitors for NOx allocations they need if
18 they wish to operate.
19 Meanwhile, older, more polluting
20 facilities are given credits necessary to
21 operate at a far higher emissions. The state is
22 operating at cross-purposes here by encouraging
23 competitive sources of generation and cleaner
24 sources of generation, yet installing
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1 competitive barriers to the new generation
2 sources that would provide energy.
3 Although the five percent new source
4 set-aside maximum is written into Illinois law,
5 the Agency still has the opportunity to operate
6 a more equitable NOx reallocation system. The
7 model rule would have all EGUs operating in 2004
8 that were given allocation based on pre-1995
9 operational status given the allocations from
10 the new source set-aside or those facilities not
11 awarded allocations, but which were operational
12 and purchased NOx credits on the open market, an
13 equitable NOx reallocation based solely on the
14 heat input of that facility. Also, such EGUs
15 would be awarded NOx allocations at the first
16 reallocation period for the fourth year of the
17 program based on their heat input times a rate
18 Btu of .15 pounds per megawatt Btus. No dual
19 track emissions rate structure would exist as
20 the Agency has proposed for those EGUs in
21 operation prior to 1995 and those which became
22 operational after this date.
23 If there were not enough credits to
24 award all such EGUs under this methodology an
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1 amount necessary to cover emissions at those
2 EGUs, such allocation would be prorated among
3 these sources based on heat input. Such a
4 system would be repeated in subsequent periods
5 as additional new source EGUs became operational
6 and were then added to the inventory of EGUs
7 that would periodically receive reallocated NOx
8 allocations.
9 Similar to the output-based system,
10 this model rule system also rewards generation
11 efficiency. Awarding NOx allowances to all
12 generators at a rate of .15 pounds per million
13 Btus or less if allowances are prorated among an
14 oversubscribed pool of EGUs would likely award
15 the EGUs with the lowest NOx rates a number of
16 allowances greater than would be needed to cover
17 actual emission at these facilities. These
18 extra NOx allowances, achieved simply because of
19 such low emission rates, would provide some
20 compensation for the expenses incurred in
21 achieving extremely low NOx emission rates.
22 If the Agency believes this system,
23 suggested by the USEPA in the model rule, it too
24 austere a program for existing, pre-1995 EGUs,
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1 there is still additional room for improvement
2 over the system currently proposed by the
3 Agency. However, it should be noted that this
4 last proposal offer the least amount of
5 improvement over the Agency's approach and of
6 the three approaches listed from
7 environmentalists as a way to create a
8 responsible NOx EGU rule for the state, this
9 garners the least amount of enthusiasm.
10 As noted previously, the number of
11 new EGUs already operating, under construction,
12 or which have applied for a permit vastly
13 oversubscribe the five percent new source
14 set-aside for the first three years of the NOx
15 program. Due to growth in the electrical
16 generation industry, unforeseen by the Agency or
17 the General Assembly, or even by Commonwealth
18 Edison and spoken to this fact in Board hearings
19 on peakers, the Board should avoid repeating the
20 short changing of new EGUs in subsequent years.
21 The board should ensure that in and beyond the
22 fourth year of the program, NOx allocations
23 adequate to cover actual emissions should be
24 provided through the reallocation mechanism to
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1 new, post-1995 EGUs in operation at the start of
2 the program. True equal allocations, which was
3 the previous proposal, this is our second, based
4 solely on heat input would commence at the
5 second reallocation in the sixth of the year
6 program.
7 Again, the Agency has stated that
8 the demand for NOx allocations from these new
9 facilities now stands at approximately 11,000
10 tons if all are constructed and operated.
11 Although, it is unlikely all of the projects
12 currently proposed will be built and operated as
13 proposed today, it would be prudent to assume
14 that over the next several years prior to the
15 start of the program the same amount of capacity
16 would be built, especially since demand for
17 electrical capacity continues to rise.
18 At present, under the provisions of
19 the proposed rule, the Agency notes that in the
20 fourth year of the program, 6,017 NOx allowances
21 would be made available to new EGUs that
22 commenced operation four years previous.
23 However, this is still approximately half the
24 number of allocations such new EGUs are expected
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1 to need to operate. In order to right the
2 proposed inequitable distribution of credits in
3 the initial allocation, the rule should expand
4 the flex portion and decrease the fixed portion
5 of the allocations for the reallocation in the
6 fourth year of the program.
7 Rather than the 80 percent of the
8 initial allocation reserved for the use of older
9 or pre-1995 EGUs in the first reallocation known
10 as the fixed portion, this percentage should be
11 significantly lower. If a ten percent energy
12 efficiency and renewable energy set-aside is
13 created and a five percent new source set-aside
14 remains in the fourth year of the program, the
15 remaining 85 percent of EGU allocations
16 available should number 26,096. If the need for
17 post-1995 EGUs that were in operation prior to
18 the first year of the program is expected to be
19 at least 11,000 tons, then the percentage of
20 allowances that is reserved for pre-1995 EGUs
21 should only be 15 percent rather than 80
22 percent.
23 Even if the Agency eliminates the
24 energy efficiency and renewable energy set-aside
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1 and keeps the new source set-aside at two
2 percent, the percentage of allowances that are
3 reserved for pre-1995 EGUs should represent only
4 63 percent of the available EGU budget. Again,
5 this compares to 80 percent in the Agency's
6 proposed rule.
7 In 2009, or the sixth year of the
8 program, EGU allocations should be based on heat
9 input alone. This is what the USEPA model rule
10 proposes should occur in the first reallocation
11 period for the fourth year of the program. All
12 EGUs should be awarded allocations based on heat
13 input times a rate of .15 pounds per megawatt
14 Btu. Again, if the pool is oversubscribed, such
15 allocations should be prorated among all EGU
16 sources based on heat input.
17 Heat input used should closely
18 reflect the actual heat input in that future
19 time, not the original heat input numbers the
20 Agency used to set the allocations for pre-1995
21 EGUs at the start of the program. Reallocation
22 should be tied to actual operation of the plants
23 preceding the reallocation. If a facility has
24 permanently ceased operation in the period prior
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1 to reallocation it does not need a NOx
2 allocation for subsequent control periods.
3 Again, presenting NOx allocations to a
4 nonoperational or possibly even nonexistent EGU
5 casts doubt on the claim that this allocation is
6 not a property right.
7 Again, this system would belatedly
8 award facilities with low rates of NOx emissions
9 for achieving such rates and providing
10 electrical power to the public while imposing
11 the least amount of pollution.
12 The proposal put forth by the Agency
13 indicates that Illinois is attempting to do the
14 bare minimum in controlling levels of air
15 pollution, rather than doing what is right and
16 necessary to protect the health of Illinois
17 citizens, especially young children, the
18 elderly, and those with serious medical
19 conditions. Even with an eventual final
20 attainment strategy for the one-hour ozone
21 standard based on the federal NOx SIP Call, this
22 plan will still fail to actually get the Chicago
23 region to a point where air quality is
24 reasonably protective of public health. Thank
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1 you.
2 HEARING OFFICER GLENN: Thank you,
3 Mr. Urbaszewski. Do any members of the Board
4 have any questions regarding this testimony? Do
5 any members of the Agency have any questions of
6 Mr. Urbaszewski?
7 MS. KROACK: We have no questions.
8 HEARING OFFICER GLENN: Any members of
9 the public wish to ask Mr. Urbaszewski any
10 questions?
11 MS. McFAWN: Then I have some questions.
12 HEARING OFFICER GLENN: Okay.
13 MS. McFAWN: I thought maybe the audience
14 would have some. I like to hear those first
15 actually.
16 On page seven of your prepared
17 testimony, you talk about fixing the current
18 Agency proposal, and you have a framework that
19 you've described, and at paragraph 1a you talk
20 about allocations being based solely on the
21 recent heat input of that facility, and in your
22 scheme, what would you consider the recent heat
23 input?
24 MR. URBASZEWSKI: Well, I think the way
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1 the Agency proposes it is that anywhere from six
2 years previous counts as recent heat input,
3 which would put it in 2001 through 2003. That
4 would be acceptable to us.
5 I think if you use 2003, four years
6 before the start of the program, you would only
7 get the heat input for that year. You could
8 also average 2002 and 2003 or if you were in
9 operation by 2001, I think you could pick the
10 two highest heat inputs between 2001 and 2003;
11 is that correct? So it would use the existing
12 Agency proposal for that.
13 MS. McFAWN: Okay. You talk about
14 permanently closed facilities being allocated
15 NOx allowances.
16 Are you -- if they get that
17 allocation, how do you see them using those --
18 using the allocation since they are closed?
19 MR. URBASZEWSKI: Well, we view the
20 initial allocation process as unequal and
21 significantly favoring the owners and operators
22 of older coal-fired power plants as gas-fired
23 power plants built prior to 1995. I asked that
24 question of the gentleman from Ameren. They
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1 said we need as many allocations as we can get
2 from 95 percent of the EGU budget because we're
3 not going to be able to meet this level of .15,
4 but yet Ameren is actually switching one of
5 their coal plants to gas.
6 They are getting an allocation based
7 on their coal heat input and their NOx emission
8 needs, but yet when the program is going to be
9 up and running, that facility is going to be
10 running on gas, and it's going to have far less
11 NOx emissions. They're capturing that element
12 and using it to cover emissions for that
13 facility and perhaps other facilities. They may
14 also be able to monitorize that and sell it on
15 the open market. That's good for Ameren, but
16 that also excludes a lot of other companies that
17 are coming on and building cleaner facilities.
18 MS. McFAWN: But if they make that
19 change, they have a cleaner facility?
20 MR. URBASZEWSKI: That's true.
21 MS. McFAWN: So isn't that comparable to
22 other facilities coming on line that have a
23 cleaner facility?
24 MR. URBASZEWSKI: It should be, but why
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1 should that company get allocations when another
2 company that's building, perhaps, the same type
3 of facility, meets the same environmental
4 standards, the same low emission rates, not get
5 that issue?
6 MS. McFAWN: You talk about -- at the
7 very conclusion, you talk about that right now,
8 even if we were to adopt the Agency's proposal,
9 you don't believe that we will reach attainment
10 in Chicago; is that correct?
11 MR. URBASZEWSKI: I don't know if we'll
12 reach attainment in Chicago. Again, that goes
13 back to my basic -- earlier in my testimony I
14 say that the mobile model severely
15 underestimates it. The National Academy of
16 Sciences has said that the mobile model, which
17 is a process for calculating the emissions --
18 ozone precursor emissions from mobile sources,
19 trucks and cars in the metropolitan area,
20 severely underestimated what's actually coming
21 out of those cars and trucks.
22 That would mean that we're
23 underestimating the ozone precursors in the
24 region, but the mobile model output, which is
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1 underestimated, actually goes into the modeling
2 that proves whether we're making attainment. My
3 contention is is that the actual emissions are a
4 lot higher than that model says. Therefore, the
5 emissions total that's going into the attainment
6 modeling is also likely higher, which would make
7 it less likely that we would actually meet the
8 one-hour standard.
9 MS. McFAWN: Just give me a moment.
10 MR. URBASZEWSKI: That's fine.
11 MS. McFAWN: I don't know if you have any
12 comment on this or not. One of the persons
13 testifying, I believe, stated that there's a
14 balancing factor from the existing EGUs in that
15 they provide a steady source of power; whereas,
16 peaker plants are not the base load plants and
17 that maybe Illinois needs the existing EGUs and
18 the structure of this trading program to favor
19 them for that reason.
20 Do you have any comment on that?
21 MR. URBASZEWSKI: Well, I can't speak
22 directly to that point, but I can say that in
23 addition to peaking units in the various
24 proposals, and I forget what the number is, I
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1 think it's up to almost 50 proposals right now,
2 there's also a number of combined cycle units,
3 which are used for more intermediate power
4 generation.
5 So it's not just peak units. There
6 are larger units coming on line, and that would
7 almost say that we need to give large grants of
8 pollution emissions to plants because we're
9 going to have an electrical reliability
10 problem. If they don't get the credits, they
11 would shut down. Of course, they could also buy
12 them from cleaner generators on the open market.
13 I can't really speak to that because
14 I don't know enough about the electrical system
15 reliability and what the capacity coming on line
16 with new facilities would be relative to old
17 facilities, and, like I said with Ameren,
18 there's also complicated factors where older
19 facilities are being repowered, is that the
20 correct term, are being repowered with cleaner
21 systems or cleaner fuels.
22 MS. McFAWN: Thank you.
23 HEARING OFFICER GLENN: Thank you, Mr.
24 Urbaszewski.
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1 MR. MELAS: Mr. Urbaszewski, if I could
2 boil it down to just one or two sentences, your
3 main objective is to see that we have a system
4 that is going to substantially reduce the NOx
5 emissions in this area?
6 MR. URBASZEWSKI: Correct.
7 MR. MELAS: And one of the ways that you
8 think that this can be accomplished is that this
9 program should treat all of the generating units
10 equally, whether they are pre-1995 older
11 gas-fired or whatever, in order to increase the
12 number of the more efficient producers? When I
13 say efficient, meaning efficiency in terms of
14 NOx reductions, pollution reductions?
15 MR. URBASZEWSKI: Correct.
16 MR. MELAS: That's all of it down into
17 one sentence.
18 MR. URBASZEWSKI: That is our main
19 contention.
20 MR. MELAS: Thank you.
21 HEARING OFFICER GLENN: Are there any
22 other questions from Mr. Urbaszewski? Yes, Mr.
23 Goodwin. Would you please identify yourself for
24 the record.
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1 MR. GOODWIN: Daniel Goodwin with Goodwin
2 Environmental Consultants.
3 If I've done my math correctly, your
4 proposal that the allocation be done on the
5 basis of 1.5 pounds per million Btu -- excuse
6 me, 1.5 pounds per megawatt hour, that works out
7 to be equivalent to the .15 pounds per million
8 Btus for a unit that has a net heat rate of
9 10,000 Btus per kilowatt hour.
10 Does that sound right to you?
11 MR. URBASZEWSKI: The engineering is a
12 little bit beyond me. From what I understand,
13 that is approximately correct and three states
14 are already using this, and that is deemed
15 acceptable by USEPA and in compliance with the
16 NOx SIP Call.
17 MR. GOODWIN: So the way your proposal
18 would work is, in contrast to the Agency'S
19 proposal, units that had a heat rate less than
20 10,000 Btus per kilowatt hour, assuming my
21 conversion was correct, those units would
22 receive proportionately greater allocation, and
23 units that had a heat rate above that number
24 would receive proportionately lower; is that
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1 correct?
2 MR. URBASZEWSKI: I really can't speak to
3 it because I haven't done the engineering work
4 on this. All I can say is that this has been
5 accepted and used by other states.
6 HEARING OFFICER GLENN: Thank you, Mr.
7 Goodwin.
8 MS. McFAWN: Following along that line,
9 when you say you haven't done the engineering
10 work, then you just accepted the number because
11 of those states or did you have someone assist
12 you in developing your testimony?
13 MR. URBASZEWSKI: Because of those states
14 using it.
15 MS. McFAWN: Thank you.
16 MR. URBASZEWSKI: And the fact that it's
17 accepted by USEPA.
18 MR. STERNSTEIN: Mr. Urbaszewski,
19 regarding the energy efficiency and renewable
20 energy set-aside, I'm just wondering are any of
21 the other states pursuing the NOx SIP Call
22 considering this agency guidance document in
23 developing their programs?
24 MR. URBASZEWSKI: I believe so, but I
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1 don't have the states with me. Mr. Dan
2 Rosenblum from the ELPC is doing much more
3 detailed work on this. Unfortunately, he was
4 unavoidably not able to be here for personal
5 reasons, but he will be submitting written
6 testimony and comments that should address that.
7 MR. STERNSTEIN: And, again, if this is
8 beyond your area of expertise, we can wait for
9 the comments, but with such a program, would
10 that allow nonelectrical generating units to
11 receive credits that they could trade with
12 EGUs?
13 I'm just picturing that an office
14 facility, say, that reduces its -- installs,
15 say, energy efficient lighting and is available
16 to reduce its electricity consumption by 20 or
17 30 percent, would that management company or
18 that office facility actually receive credits
19 that they would actually trade with electrical
20 generating units?
21 MR. URBASZEWSKI: Yes. The main idea
22 behind the energy -- renewable energy set-aside
23 is that these are projects that would create or
24 save electricity and reduce the need for
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1 electricity from power plants that would be
2 emitting NOx in the production of that
3 electricity.
4 Since the power plants are not
5 emitting the NOx, they don't need the credit.
6 The credit, which can be monitorized in the
7 market, and you can sell it, should go to the
8 people who have taken the initiative to reduce
9 that NOx from going into the atmosphere, i.e.,
10 the people who have installed an energy
11 efficiency lighting system, updated
12 air-conditioning, heating system, or have
13 installed solar/wind generation that doesn't
14 have emissions, but they would take that credit
15 that this would generate and do with it as
16 the -- they could sit on it. They could donate
17 it. They could sell it on the open market, and
18 the cash they would receive from the sale of
19 that allowance would go to offset the expense
20 they occurred in constructing the energy
21 efficiency project or the alternative energy
22 system.
23 HEARING OFFICER GLENN: Are there any
24 further questions of Mr. Urbaszewski this
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1 morning -- afternoon? Okay. Mr. Urbaszewski,
2 thank you for coming.
3 Mr. Dupuis, could I ask you to
4 submit your prefiled testimony as an exhibit,
5 please?
6 MR. DUPUIS: Yes. I can make a motion to
7 do so.
8 HEARING OFFICER GLENN: Thank you.
9 MR. DUPUIS: I'd also like to file this
10 errata sheet as well.
11 HEARING OFFICER GLENN: Do you have an
12 extra copy of your testimony with you this
13 morning, or shall we get one from the table?
14 MR. DUPUIS: We can get one.
15 HEARING OFFICER GLENN: Okay. Let me get
16 that. I will admit Mr. Dupuis' prefiled
17 testimony as Exhibit No. 35 and then a copy of
18 his errata sheet as Exhibit No. 36. Just give
19 me a moment to mark those.
20 (Exhibit Nos. 35 and 36
21 marked for identification,
22 9-26-00.)
23 HEARING OFFICER GLENN: Mr. Dupuis, I
24 request when you return to your office that you
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1 submit the errata sheet also to the service list
2 people so they're aware of the change in your
3 testimony.
4 MR. DUPUIS: Okay.
5 HEARING OFFICER GLENN: Thank you. I
6 guess we're ready to begin.
7 MR. DUPUIS: Good afternoon. My name is
8 Lenny Dupuis. I am manager of environmental
9 policy for Dominion Generation. Dominion is a
10 fully integrated, investor owned electric and
11 gas energy provider headquartered in Richmond,
12 Virginia, with power generating facilities
13 located in Illinois, Virginia, West Virginia,
14 North Carolina, Ohio, and Pennsylvania. Our
15 corporation operates the 1200 megawatt
16 coal-fired Kincaid generating station located in
17 Kincaid, Illinois, and this consists of two
18 coal-fired cyclone boilers that are identified
19 as Subpart W Appendix F units that will be
20 required to meet the requirements of the NOx SIP
21 Call rule, the Subpart W rule.
22 As you've already heard today, this
23 SIP Call rule is potentially one of the most
24 stringent and costly air quality regulations
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1 that utility generators in Illinois and
2 elsewhere have had to face to date. The rule
3 will require existing electric generating units
4 in Illinois to significantly reduce ozone season
5 NOx emissions to comply with the emission
6 budgets or caps or caps that have been set by
7 USEPA based on a .15 pound per million Btu limit
8 heat input. New generation already built after
9 the baseline year from which the emission caps
10 are calculated as well as future planned
11 generation in the state will also have to secure
12 emission allowances under this cap. This means
13 that existing base load generation that has
14 served the energy needs of the Illinois public
15 in the past and newer generation that will be
16 needed to serve increasing energy demands in the
17 future will be competing for a limited number of
18 emission allowances for years to come.
19 Dominion fully recognizes the
20 pressure the state is currently facing given the
21 deadlines imposed upon them to develop and
22 submit a plan to address EPA's NOx SIP Call by
23 late October of this year. We also realize the
24 difficulty the Agency has had in developing the
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1 rule that would address as equitably as possible
2 the many issues and concerns of all affected
3 parties. Dominion commends the IEPA for its
4 efforts over the last year in allowing affected
5 stakeholders the opportunity to provide
6 meaningful input through face-to-face meetings
7 and written comment throughout the development
8 of this Subpart W rule.
9 There are, however, some issues
10 associated with this rule that are of particular
11 concern to Dominion that I'd like to address
12 with you today. Some of these issues have
13 already been addressed to some extent by the
14 motion for amendment of the Subpart W rule that
15 was recently filed by the Agency, but these
16 issues do deal with the U.S. Court of Appeals
17 August 30th order extending the compliance date
18 of the NOx SIP Call, issues related to the
19 generation and use of early reduction credits in
20 the compliance supplement pool, issues relating
21 to the growth factor that USEPA used in setting
22 the NOx budget cap for electric generating units
23 in Illinois additional allocations for existing
24 or Appendix F sources in the Subpart W rule can
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1 finally be use of the Subpart W rule in state's
2 attainment demonstration plans, and I'll address
3 each of those issues.
4 The Subpart W compliance date, as we
5 heard earlier today, the Agency has filed a
6 motion to modify its rule to reflect the
7 extension of the SIP Call requirement from May
8 1st, 2003, to May 31st, 2004, and Dominion
9 supports this modification.
10 In terms of the 2004 ozone season
11 budget, we also heard that they intend at least
12 at this time to allocate the full EGU NOx budget
13 for the 2004 ozone season, and we also
14 understand that they are awaiting some further
15 guidance if that, indeed, comes from USEPA on
16 that decision.
17 However, if, for any reason, IEPA is
18 compelled to adjust the budget to reflect a
19 four-month ozone season instead of a full ozone
20 season as they are proposing right now, we would
21 urge the Agency to adequately account for
22 intraseasonal generation and emission patterns
23 in a reasonable manner and not simply to reduce
24 the budget by 20 percent.
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1 I'd like now to address early
2 reduction credits in the compliance supplement
3 pool. The Subpart W rule provides the
4 opportunity for sources to earn early reduction
5 credits, or ERCs, from a compliance supplement
6 pool that has been established by USEPA under
7 the SIP Call rule by achieving emission
8 reductions prior to the rule's prior compliance
9 deadline. Dominion appreciates USEPA's
10 recognition, at least to some degree, of the
11 difficulty that utilities will face in having to
12 retrofit a number of units in a short time frame
13 in order to comply with the SIP Call reductions
14 and EPA's subsequent creation of the compliance
15 supplement pool. We further appreciate Illinois
16 EPA's incorporation of early reduction credits
17 and the compliance supplement pool into its
18 Subpart W rule. Early reduction credits are
19 good for the environment and should be
20 encouraged, but decisions to early comply are
21 also serious business decisions involving
22 significant early investments in capital and
23 labor in order to be assured the ability to
24 compensate for unexpected delays or
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1 complications in installing and operating
2 control technologies that will be needed to meet
3 the required emission reductions.
4 We believe that some of the
5 provisions governing the generation and use of
6 the early reduction credits currently embedded
7 in EPA's SIP Call rule and in the Subpart W rule
8 limit, to some extent, the usefulness of these
9 credits do not provide sufficient certainty for
10 planning purposes for which they were intended.
11 Such restrictions could discourage source owners
12 from installing and operating control technology
13 earlier than required.
14 Some of these limitations are as
15 follows: The total number of early reduction
16 credits that can be awarded are presently
17 limited by the amount of available allowances
18 under the state's compliance supplement pool,
19 which has been set by EPA -- USEPA. In the
20 total amount -- if the total amount of requested
21 ERCs exceeds the total number of allowances
22 available in the compliance supplement pool,
23 source specific allocations of this pool will be
24 awarded on a prorated basis. Thus, there is the
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1 possibility that sources will not receive full
2 credit on a ton-for-ton basis or all of the
3 early reductions made below the designated
4 baseline levels.
5 Illinois EPA intends to award half
6 of the compliance supplement allowances for
7 reductions made in the 2001 ozone season in the
8 remaining half of the year 2002 ozone season.
9 Sources must apply for these credits by November
10 1st of the year during which the ozone season
11 reductions are achieved. IEPA will award the
12 early reduction credits by now March 1st of the
13 year following the ozone season during which the
14 reductions were achieved. While this schedule
15 does help, to some extent, it still results in
16 delays certainty as to the amount of ERCs that
17 have been obtained, making it difficult to
18 adequately incorporate the use of these credits
19 for compliance strategy planning purposes for
20 which the compliance supplement pool allowances
21 were designed.
22 Given the extension of the
23 compliance deadline to May 31st, 2004, the use
24 of early reduction credits is now restricted to
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1 just one year. The current rule retires unused
2 credits at the end of the 2004 ozone season,
3 although we did just hear in the motion to amend
4 that they will consider extending that ability
5 through the 2005 ozone season pending further
6 guidance and approval by USEPA, and we would
7 support that.
8 Given the substantial cost and
9 difficulties associated with meeting
10 requirements of the SIP Call rule, we would urge
11 the state to try to incorporate as much
12 flexibility as possible into the provisions of
13 the early reduction credit portion of the rule
14 that will help to ease the financial burden to
15 affected sources and provide more certainty to
16 the process. We believe there might be such an
17 opportunity by modifying the early reduction
18 provisions to maximize their usefulness and
19 provide added incentive for source owners to
20 generate early emission reductions.
21 First of all, given the extension of
22 the compliance deadline for the SIP Call to May
23 2004, the ability to generate early reduction
24 credits should be extended through the 2003
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1 ozone season. We heard from their motion to
2 amend moments ago that they do intend to do
3 that. As it stands right now, they will be
4 allocating emissions in 2001 and 2002, and
5 whatever is left over, if there is anything left
6 over, will be considered for distribution in the
7 year 2003, and we would support this extension
8 to the year 2003.
9 We also urge the Agency to extend
10 the use of the early reduction credits to at
11 least the 2005 ozone season, which they intend
12 that they will consider doing given the extended
13 deadline for compliance with the SIP Call rule
14 to May 31st, 2004. This would at least maintain
15 status quo in the rule, which under the initial
16 May 2003 compliance deadline allowed the use of
17 early reduction credits for two ozone seasons
18 beyond the compliance deadline.
19 In its currently proposed form, the
20 Subpart W rule incorporates the banking
21 provisions of EPA's model rule Part 96. Under
22 the model rule provisions, banked allowance as
23 well as early reduction credits awarded from the
24 compliance supplement pool are subject to a flow
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1 control mechanism beginning in the 2004 ozone
2 season. Dominion believes that given the
3 limitations already imposed upon the generation,
4 use, and lifetime of the early reduction credits
5 obtained from the compliance supplement pool
6 that these early reduction credits should not be
7 subject to additional flow control. We note
8 that in USEPA's Part 97 rules in which they
9 implement the Federal NOx trading program, which
10 EPA intends to implement in states which become
11 subject to a federal implementation plan or are
12 subject to the Section 126 rule, EPA is not
13 subjecting early reduction credits allocated
14 from the compliance supplement pool to flow
15 control and is not implementing the banking
16 provision flow control mechanism for the first
17 two years of the trading program until the early
18 reduction credits have all been used or retired.
19 Dominion urges this Board and the
20 IEPA to consider doing the same, that is, do not
21 subject the early reduction credits to flow
22 control and amend the rules to delay the
23 implementation of the flow control mechanism in
24 the banking provisions at least until the early
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1 reduction credits from the compliance supplement
2 pool have been used up or retired.
3 We believe that USEPA would not
4 object to this alteration of the model rule
5 provision since the Agency itself applied this
6 concept in its Part 97 rule. The state should
7 consider awarding compliance supplement
8 allowances as soon as possible following the
9 ozone season during which the reductions are
10 achieved. This would provide source owners more
11 lead time as to exactly how many early reduction
12 credits they have been allotted and would
13 provide some additional time to incorporate this
14 knowledge into compliance plans and schedules.
15 There is no absolute requirement
16 that states adopt a compliance supplement pool
17 provision within their rules. The state could
18 consider developing an early reduction credit
19 program totally independent of EPA's compliance
20 supplement pool that would not limit the number
21 of early reduction credits that could be
22 achieved. Removing such a limitation, while at
23 the same time providing a more up front
24 guarantee that early reduction credits will be
L.A. REPORTING (312) 419-9292
126
1 awarded or rewarded in the form of equivalent
2 emission credits, would greatly enhance the
3 incentive for source owners to install and
4 operate control technology earlier than
5 required.
6 I'd like now to turn to the growth
7 issue. During the August 28th public hearing,
8 there was mention of and several questions
9 raised about the growth factor that USEPA
10 assumed in Illinois to account for expected
11 growth in electric generation over the period
12 from the baseline year 1996 to the 2007 budget
13 year. In my prefiled testimony, I have provided
14 an explanation of how EPA derived these growth
15 factors, and I'd like to take some time here
16 just to emphasize a few key points.
17 First, the growth factors play a
18 significant role in the determination of the
19 final state specific EGU NOx budgets that were
20 set in the SIP Call rule. During the course of
21 the SIP Call rulemaking process, the growth
22 factor assumed by USEPA in Illinois ranged from
23 a high of 34 percent to the current eight
24 percent, which was used in the final NOx budget
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1 rule. At one time during the rulemaking
2 process, the NOx EGU budget in Illinois was as
3 high as 36,570 tons, a 30 percent increase over
4 the current 32,372 tons. A 34 percent growth
5 factor applied to the current baseline for
6 sources in the trading budget are those that are
7 established in Appendix F of the Subpart W rule
8 would increase the tonnage trading budget from
9 the current 30,701 tons to over 38,000 tons, an
10 increase of almost 25 percent. So you can see
11 the relative importance of this growth factor in
12 what the final budgets in Illinois were.
13 The eight percent growth rate
14 assumed in Illinois over the 11-year period is
15 simply inappropriate. In many cases, growth
16 over the last several years has already exceeded
17 the projected 2000 levels that EPA assumed in
18 the NOx SIP Call. EPA produced surrogate growth
19 rates for the 1996 through 2007 period that was
20 based on year 2001 and year 2010
21 projections from the integrated planning model.
22 EPA's methodology does not adequately address
23 growth in the earlier years of this period,
24 mainly 1996 through 2001.
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1 In fact, IPM projections for year
2 2001 and 2010 used by EPA in the IPM model to
3 determine the growth rate exceed the 2007 levels
4 that have been projected by the EPA in the SIP
5 Call rule. The EPA growth factors also vary
6 considerably from state to state ranging from an
7 actual negative growth factor in Rhode Island to
8 a high of 59 percent in the state of
9 Massachusetts. The disparity in quote
10 assumptions from state to state results in
11 substantial differences in the amount of growth
12 tonnage that's added on to the baseline
13 emissions.
14 This underestimation of growth in
15 setting the NOx emission budgets directly
16 affects the ultimate emission rate a given
17 utility system will have to meet to comply with
18 the seasonal allocations provided under the
19 state NOx budget. For states where EPA has
20 significantly underestimated the growth, the
21 effective emission rate to comply with the
22 budget will be much lower than .15 pound per
23 million Btu. For example, at our Kincaid
24 generating station, we will have to achieve an
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1 emission rate well below the .15 pound per
2 million Btu rate that's assumed by EPA in
3 deriving the budget in order to comply with the
4 seasonal NOx allocations in appendix F of the
5 Subpart W rule if these units continue to
6 operate at levels experienced over the last
7 several ozone seasons.
8 We suspect and we've already heard
9 to some degree this morning from previous
10 testimony that other sources in Illinois will
11 share the same thing. USEPA claims that the
12 regional trading program will mitigate these
13 flaws and discrepancies. However, EPA has said
14 individual state budgets, that individual states
15 must meet it. It did not set an overall
16 regional 22 state budget. Therefore, EPA's
17 methodology has subjectively set certain states
18 as potential net buyers of allowances and other
19 states as potential net sellers of allowances.
20 Sources in states, such as Illinois where EPA
21 has underestimated growth, may very well be
22 forced to spend their money on purchasing
23 emission allowances to comply with the NOx
24 budget, while other states with larger growth
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1 rates have more flexibility for meeting the
2 reduction requirements and for incorporating new
3 sources into their budgets.
4 This provides the higher growth
5 states with an economic advantage over other
6 states with lower growth rates, such as
7 Illinois. Several industry groups have
8 petitioned for review of the state specific NOx
9 budgets that USEPA has established in the SIP
10 Call rule in the U.S. Court of Appeals, D.C.
11 Circuit for some of the very same reasons that
12 I've described above.
13 The briefing litigation schedule was
14 recently set by the court. A decision from the
15 court is not expected until at least the second
16 quarter of next year at the earliest. This
17 ongoing legal review presents the possibility
18 that the SIP Call budgets could be rejected by
19 the court and/or remanded back to USEPA for
20 further consideration and review.
21 Therefore, the total NOx budget for
22 electric generating units referenced in the
23 Subpart W rule of Illinois may at some point in
24 the future need to be adjusted pending the
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1 outcome of this litigation. The Illinois EPA
2 has incorporated a provision within its Subpart
3 W rule that allows the Agency to adjust the
4 state budget should USEPA adjust the trading
5 budget for any reason. Dominion believes that
6 this provision should be specifically tied to
7 the ongoing litigation of the budget which, if
8 successful, in our opinion, will increase the
9 budget in Illinois.
10 I would also note that there are
11 some states that are considering submitting SIP
12 Call rules requiring a cap based on the .15
13 pound per million Btu, but with alternative
14 budgets that will be derived from more
15 representative growth factors in those states.
16 I'd now like to address initial
17 allocations for the Appendix F sources.
18 Dominion believes that Illinois EPA should
19 re-examine the allocations established for the
20 Appendix F sources for the initial three-year
21 control period. We believe that a more
22 equitable approach would be to adopt a
23 methodology similar to that used by USEPA in its
24 Part 97 rule, which bases the allocations for
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1 each unit on the average of the two highest
2 ozone season heat inputs over a multi-year
3 period, adjusted by normalizing the total state
4 EGU tonnage so obtained with the state EGU
5 budget established by EPA in the SIP Call rule.
6 This, in fact, is the methodology that Subpart W
7 rule applies in subsequent allocation periods
8 for the flex portion of the fixed/flex
9 approach.
10 Finally, I'd like to address the
11 state ozone attainment demonstrations. The
12 Agency had envisioned using the Subpart W rule
13 as a means to achieve attainment of the National
14 Ambient Air Quality Standard for Ozone in the
15 Metro-East St. Louis Nonattainment Area and the
16 Lake Michigan Chicago Nonattainment Area and has
17 submitted the rule to USEPA for pre-approval and
18 review prior to actual adoption by the state in
19 support of attainment demonstration which must
20 be submitted to USEPA by December of 2000. In
21 that submittal, the state does commit the state
22 to the SIP Call controls beginning in May 2003.
23 Given the court's extension of the SIP Call
24 compliance date to May 31st, 2004, and the fact
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1 that Agency modeling indicates that attainment
2 can be achieved for the Metro-East St. Louis
3 area with a rate base .25 pound per million Btu
4 statewide control level, we suggest that the
5 Subpart W rule will be removed from the
6 attainment demonstration plans for the St. Louis
7 and Chicago nonattainment areas at this time.
8 The states should proceed with an
9 attainment demonstration plan independent from
10 the SIP Call rule and move forward with a rate
11 base .25 pounds per million Btu control
12 requirement for the 2003 ozone season, and I
13 believe we heard that the state is considering
14 taking this approach earlier this morning. This
15 approach would adequately address the St. Louis
16 nonattainment problem while not subjecting
17 sources in Illinois to a more stringent level of
18 control earlier than is required of sources in
19 other surrounding states subject to the NOx SIP
20 Call. This would also protect the state should
21 a review of the NOx SIP call rule in the Supreme
22 Court, if so granted, results in additional
23 delay or overturning of the NOx SIP Call rule.
24 We thank you for this opportunity to
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1 comment, and I would be very happy to hear any
2 questions. Thank you.
3 HEARING OFFICER GLENN: Thank you,
4 Mr. Dupuis. Do any members of the Board have
5 any questions for Mr. Dupuis? Let's go over to
6 the Agency and see if they have any questions.
7 MS. KROACK: We have a few for you,
8 Mr. Dupuis.
9 You stated in your testimony that
10 the Subpart W rule should provide for allocation
11 of total statewide NOx budget for EGUs in the
12 2004 control period or 30,700 for allowances
13 even though the control period has been
14 shortened by 30 days.
15 Do you understand that USEPA
16 administers the NOx trading program?
17 MR. DUPUIS: Yes.
18 MS. KROACK: Do you also understand that
19 the Agency can only allocate those allowances
20 that USEPA gives us?
21 MR. DUPUIS: Yes.
22 MS. KROACK: So then if USEPA elects to
23 decrease that budget, isn't it also true that we
24 can only allocate to you what they give us to
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1 allocate to our pool of electrical generating
2 units?
3 MR. DUPUIS: Yes. I believe that's the
4 case, but, again, I would hope that the Agency
5 would make an argument that USEPA consider that
6 in most years generation in May is lower than
7 most of the other ozone season months and would
8 reflect that in the allocation, and that's what
9 we would ask.
10 MS. KROACK: We would just like to state
11 for the record that we understand that, and we
12 intend to make that and other arguments to USEPA
13 as well when the time is appropriate.
14 The other question, you said the
15 other states are opting into the federal trading
16 program. I believe this is what you said in
17 your testimony just now, and I didn't find it in
18 your written testimony. So maybe I misheard
19 you.
20 But they're opting into the federal
21 NOx trading program, but they're setting their
22 own budgets?
23 MR. DUPUIS: They are not opting in.
24 They are part of the SIP Call rule. So I guess
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1 you could say they're going to try to opt into
2 the trading program, but they're going to submit
3 a different -- a different budget than USEPA.
4 Yes. That's correct.
5 MS. KROACK: Do you know which states
6 these are?
7 MR. DUPUIS: I do, but I'm not at liberty
8 to say right now because they have not submitted
9 the rules.
10 MS. KROACK: So they haven't put anything
11 out to the public?
12 MR. DUPUIS: No, they have not.
13 MS. KROACK: This is just internal
14 discussions?
15 MR. DUPUIS: This is internal
16 discussions.
17 MS. KROACK: Do you understand that the
18 Federal NOx Trading Program sets requirements
19 for opting in within Part 96 rules that it says
20 the state must meet to opt in?
21 MR. DUPUIS: Uh-huh.
22 MS. KROACK: Thank you. And I just want
23 to clarify one point. The Agency has said today
24 that it intends next week, we hope, to submit a
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1 rate-based rule to address attainment, but only
2 for the Metro-East Nonattainment Area. I just
3 -- I know I said that, but I wanted to make
4 that clear.
5 HEARING OFFICER GLENN: Thank you, Ms.
6 Kroack. Did members of the Board have
7 questions? Any members of the public, would any
8 of you like to ask any questions?
9 MS. McFAWN: I do. Like I stated before,
10 I always like to hear from the audience first
11 because if you have a question that I have, I'm
12 glad when it comes from the audience.
13 In your testimony, you talked about
14 compliance supplemental provisions, and you made
15 a suggestion that we are to consider developing
16 an early reduction credit program independent of
17 EPA's CSP. Can we do that? Is that one of our
18 discretionary approaches?
19 MR. DUPUIS: I don't know for sure
20 whether you can or not. I think it would have
21 to be totally independent of the compliance
22 supplement pool. I believe the state does have
23 -- they have a discretion whether to accept the
24 compliance supplement pool or not. They have
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1 that choice, and what I'm suggesting here is
2 that if to provide more flexibility or
3 assurances of early reduction credits in that
4 they could be generated on a one-for-one basis
5 that the state could consider having an early
6 reduction program that is separate from the
7 compliance supplement pool.
8 Now, they would have to work out
9 with USEPA a way to move those credits into the
10 trading program. So there would have to be some
11 discussion with USEPA as to whether or not. The
12 other option would be to just track those
13 separately within the state.
14 MS. McFAWN: If we were to do that and we
15 failed in convincing the USEPA to allow that
16 into the CSP, can we use that then to be
17 allocated or would the companies that had taken
18 steps to achieve early reduction credits maybe
19 not be able to use them in the federal trading
20 program?
21 MR. DUPUIS: If EPA were to come back and
22 disapprove that option, then the state would
23 have the option of amending its SIP in applying
24 the compliance supplement pool. It would have
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1 that ability to do so.
2 MS. McFAWN: Okay. Thank you. You said
3 that at Kincaid you will have to achieve a
4 level -- an emission rate much less than 0.15
5 emission rates?
6 MR. DUPUIS: Yes. That's correct.
7 MS. McFAWN: We've heard from other
8 generators, they, too, would have to.
9 Do you think that Kincaid will be
10 significantly less than your competitors?
11 MR. DUPUIS: I don't know what level they
12 would have to go down to. I do know that if we
13 were to maintain the generation or the
14 utilization that we have experienced in the last
15 several ozone seasons that we would likely be
16 down in the range somewhere around .10. I don't
17 know how others are affected by that.
18 MS. McFAWN: Okay. I think it was under
19 -- in the part of your testimony where you talk
20 about growth factors, you suggest that we should
21 use a different period of time, is that correct,
22 for establishing --
23 MR. DUPUIS: No. What I was trying to
24 indicate to you is that when USEPA tried to
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1 apply a growth rate, what they were seeking to
2 do was to apply a growth factor from the
3 baseline year, which is 1996, out to the year
4 2007, but in order to do, they ran what they --
5 the integrated planning model. It's a
6 forecasting model that the Agency used, and they
7 ran the model for two projection years 2001 and
8 2010. Based on the modeling results from those
9 two years, they computed a growth rate from 2001
10 to 2010 period.
11 They then calculated that growth
12 rate over that nine-year period, prorated it to
13 11 years, and then went back to the 1996
14 baseline and used that rate to adjust 1996 up to
15 2007. Now, our point is that they were using
16 two projections to the future, from 2001 to
17 2010, but nowhere is the growth from 1996 to
18 2001 part of that assessment, and we have seen a
19 substantial growth in the last few years, which
20 essentially is not part of that equation.
21 MS. McFAWN: Okay. Thank you for that
22 clarification. I don't think I have any other
23 questions.
24 HEARING OFFICER GLENN: Are there any
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1 further questions of Mr. Dupuis this afternoon.
2 Mr. Dupuis, thank you very much for coming and
3 giving us your comments this afternoon.
4 MR. DUPUIS: Thank you.
5 HEARING OFFICER GLENN: Let's break for
6 lunch. We will resume in an hour. It is
7 12:45. So we will resume at 1:45 promptly. We
8 will begin with Mr. Furstenwerth and then
9 proceed with Mr. Miller and then we'll get
10 Ms. Schoen sworn in and we will hear her
11 testimony as well, and then also during the
12 lunch hour, if any of you look at the Agency's
13 motion and determine you have further questions,
14 we will entertain those after lunch as well. So
15 we will go off the record now and resume at
16 1:45. Thank you.
17 (Whereupon, further proceedings
18 were adjourned pursuant to the
19 lunch break and reconvened
20 as follows.)
21 HEARING OFFICER GLENN: Let's go back on
22 the record. Good afternoon, again, and welcome
23 back to this, our second hearing in our R01-9,
24 the Proposed New 35 Illinois Administrative Code
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1 217, Subpart W, The NOx Trading Program for
2 Electrical Generating Units.
3 Before we resume hearing from the
4 our witnesses this afternoon, I'd like to take
5 care of just a couple of housekeeping items.
6 First, I would like to ask the Agency if they
7 intend to request a third hearing which is
8 currently scheduled for October 10th?
9 MS. KROACK: We do not.
10 HEARING OFFICER GLENN: In light of the
11 Agency's request not to have a third hearing,
12 there will be some deadlines that you might want
13 to listen up for. We intend to get an expedited
14 transcript in this matter, which would mean the
15 Board would have the transcript on September
16 29th. Assuming that the transcript does arrive
17 at the Board on September 29th, the public
18 comment period runs for 14 days, which would
19 mean the record in this matter would officially
20 close on Friday, October 13th, at 4:30. The
21 mailbox rule does not apply to any public
22 comments. So you would have to file this
23 comment with the Board by 4:30 on October 13th.
24 If you file a public comment, I
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1 would remind you that the Board is to receive an
2 original and nine copies of this comment.
3 Additionally, we would ask that you would serve
4 a copy of your public comments on all people on
5 the service list. We have copies of that
6 service list here today. You can take one with
7 you or you can ask us for -- ask me for one at a
8 later date, but you are required to serve the
9 service list people with your public comments.
10 I would discourage anyone from
11 filing fact filings on the 13th, but if you get
12 desperate, give me a call. Now, if in the event
13 we do not get the transcript on the 29th, those
14 dates are going to change. So what I will do is
15 I will put out a hearing officer order as soon
16 as we get the transcript so everybody on the
17 service list and notice list will know what the
18 final dates are, but I'm optimistic that we will
19 get it on the 29th.
20 Also, the transcript will be placed
21 on the Board's web page, but I don't anticipate
22 that happening, assuming we get it on September
23 29th, I don't anticipate that will happen before
24 Tuesday, October 3rd. Hopefully, we will get it
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1 put on the web page that Tuesday. Keep
2 checking. It will be on there.
3 Are there any questions regarding
4 that matter? Okay.
5 MS. KROACK: Cathy -- excuse me. Hearing
6 Officer Glenn, do you intend if you receive the
7 transcript on the 29th to send it to the service
8 list or only to make it available?
9 HEARING OFFICER GLENN: We will only make
10 it available. We will not be sending hard
11 copies of the transcript to the service list.
12 The Board has a policy of 75 cents a page for
13 something like that. So if you wanted us to
14 send it to you, please let me know, but you will
15 be getting a bill. I would recommend the
16 transcript off the web or come to the Board's
17 offices and I can get you a copy that you can
18 copy for yourself.
19 Yes. Do you have a question, Ms. Schoen.
20 MS. SCHOEN: After the 13th date, what
21 are the next milestones?
22 HEARING OFFICER GLENN: Oh. Thank you.
23 After October -- assuming we get the transcript
24 on September 29th and the record closes on
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1 October 13th, pursuant to the Board's order on
2 July -- excuse me a moment, July 13th. We did
3 announce that if the third hearing is cancelled,
4 the Board would go to second notice by November
5 20th, and the Board meeting preceding November
6 20th is November 16th.
7 So the latest we would be going to
8 second notice would be that meeting on November
9 16th, and I would remind you that under Section
10 28.5, those time frames are -- those are
11 statutory. The Board doesn't have any
12 flexibility on that schedule. After we proceed
13 to second notice, final adoption would be 21
14 days after we receive JCAR's certificate of no
15 objection, and, I'm sorry, I don't know what
16 JCAR's meeting calendar is in December, but
17 those are the deadlines we are working with now.
18 Any more questions about those
19 deadlines? Again, I will put out a hearing
20 officer order to clarify everything once we
21 receive the transcript. If the transcript is
22 delayed in getting to us, the time frames will
23 adjust accordingly, but I will contact all of
24 you via hearing officer order so you will know
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1 precisely what is going on. If you haven't
2 signed up to be on our notice list or our
3 service list and you want to get this hearing
4 officer order, please sign up. There's a
5 sign-up sheet for either the notice or service
6 list on the table by the door there.
7 Any more questions regarding that?
8 Okay. Seeing none, before we get to our witness
9 testimony, I would like to ask if anyone else
10 has any questions for the Agency regarding the
11 motion to amend that it filed this morning?
12 Okay. No more questions. So let's get back to
13 our witness testimony. I believe we were going
14 to start this afternoon with Mr. Furstenwerth.
15 Before we get to Mr. Furstenwerth, I do have
16 additional copies of testimony on the table that
17 we ran out of this morning. So if you didn't
18 get copies of something, I know we ran out of
19 Mr. Dupuis' and some others. So help yourself.
20 If you still don't see what you need, let me
21 know afterwards and I'll get you a copy before
22 you leave here today.
23 Without further ado, Mr.
24 Furstenwerth.
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1 MR. FURSTENWERTH: Thank you members of
2 the Board. Before I start my comments, I'd like
3 to move to enter my testimony into the record.
4 HEARING OFFICER GLENN: So granted. We
5 will mark Mr. Furstenwerth's prefiled testimony
6 as Exhibit No. 37.
7 (Exhibit No. 37 marked
8 for identification,
9 9-26-00.)
10 MR. FURSTENWERTH: Thank you. My name is
11 Derek Furstenwerth. I'm a leader in the Air
12 Resources Division of the Environmental
13 Department of Reliant Energy Incorporated.
14 Reliant Energy is an international energy
15 services and energy delivery company based in
16 Houston, Texas. Reliant Energy owns and
17 operates over 26,000 megawatts of power
18 generation in the U.S. and western Europe. In
19 Illinois, Reliant Energy began operation this
20 summer at its 345 megawatt facility in Shelby
21 County and has under construction an 870
22 megawatt peaking facility in Aurora. As a
23 result, Reliant Energy will be impacted by the
24 final NOx trading rule regulations promulgated
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1 by the Pollution Control Board. We appreciate
2 the opportunity to present this testimony.
3 As you're aware, the electric
4 industry is in the process of being
5 deregulated. Because of uncertainty regarding
6 the shape that deregulation would take, there's
7 little investment in new power generation
8 facilities in the United States in the late
9 1980s and the 1990s. As a result, there's now a
10 shortage of generation capacity during periods
11 of peak electric demand. In response to the
12 shortage and the passage of Illinois'
13 deregulation law, there's been a significant
14 amount of activity in the siting of electric
15 power generation facilities in Illinois in the
16 last two years.
17 Work on the proposed Illinois NOx
18 trading rule began in 1998 after the USEPA
19 issued the NOx SIP Call, which ordered states in
20 the eastern U.S. to develop NOx trading rules as
21 a cost-effective way to ensure ozone
22 nonattainment areas in the eastern U.S. would
23 reach attainment. This SIP Call occurred prior
24 to the current period of significant electric
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1 generation development in Illinois. As a
2 result, the proposed rule developed by the IEPA
3 contains a number of provisions that do not
4 accurately reflect the present marketplace of
5 generating facilities in the state.
6 These new market entrants are part
7 and parcel of the development of the
8 infrastructure within the state of Illinois that
9 will allow the current economic expansion in the
10 state to continue. Moreover, the facilities
11 being built generally have significantly lower
12 NOx emissions than older generating units in the
13 state. In effect, the proposed rule insulates
14 older generating sources from having to install
15 pollution control equipment and forces potential
16 new sources to compete for an insufficient
17 amount of NOx allowances available to them under
18 the provisions of the proposed rule. Surely one
19 quality of a successful NOx trading rule would
20 be to reduce NOx as cost-effectively as possible
21 while allowing the continued development of the
22 new, clean, efficient generation the state needs
23 to foster continued economic growth. To this
24 end, Reliant Energy suggests four substantive
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1 changes to the propose Illinois NOx trading
2 rule.
3 First, USEPA's model rule allowance
4 allocation methodology should be applied
5 beginning in 2006 or now with this morning's
6 proposal, 2007. In general, the proposed
7 Illinois NOx trading rule is modeled after
8 USEPA's model rule. The model rule was issued
9 as part of the NOx SIP Call to provide states a
10 template upon which to build their own state
11 budget rules. The proposed Illinois NOx trading
12 rule uses many of the concepts from USEPA's
13 model rule, but strays from the model rule
14 approach in several ways. The allocation
15 methodology is one area in which the NOx trading
16 rule differs from the model rule.
17 Both the model rule and the proposed
18 Illinois NOx trading rule allocate a fixed
19 number of allocations to existing sources for
20 the first three years of the program. These
21 allocations amount to 95 percent of the total
22 state NOx budget, and the remainder of the
23 budget resides in the new source set-aside,
24 which is discussed in greater detail later in my
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1 testimony.
2 Facilities receiving fixed
3 allocation in 2003 through 2005 are listed in
4 Appendix F of the proposed rule and for the
5 purpose of this discussion will be referred to
6 hereafter as Appendix F sources. Only sources
7 in operation prior to 1995 are listed in
8 Appendix F. In other words, from 2003 through
9 2005, sources which began operating after 1994
10 will receive no fixed allocations, but will
11 instead be allocated allowances only from the
12 new source set-aside.
13 In USEPA's model rule, beginning in
14 2006, all existing sources, including those
15 built after 1995, are allocated allowances based
16 on their historical heat input, which is the
17 same essentially as fuel use, multiplied by a
18 target NOx emission rate .15 pounds per million
19 Btu. The purpose of this calculation approach
20 is to allocate allowances to sources in the
21 state based on their level of operations, more
22 operations, more allowances. Conversely, the
23 less a source operates, the fewer allowances it
24 receives.
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1 Bear in mind, however, that the
2 state's NOx budget is fixed. If more sources
3 are built in the state or older sources are
4 operated more than they were historically,
5 individual allocations are reduced for all
6 sources. As a result, as more new clean sources
7 begin operating in the state and as older
8 sources operate more to meet increased demand,
9 all sources receive a smaller piece of the pie.
10 The Illinois NOx trading rule
11 differs from the model rule in two significant
12 ways at this point. One is discussed here, and
13 one is discussed in my second comment. While
14 the model rule allocates NOx allowances
15 beginning in 2006, based on historical
16 operations, the proposed Illinois NOx trading
17 rule utilizes what IEPA describes a fixed/flex
18 allocation methodology for allowance allocations
19 from 2006 through 2009. In 2006 and seven,
20 Appendix F sources receive 80 percent of their
21 fixed allocation amount regardless of historical
22 operations.
23 Sources not listed in Appendix F
24 receive their allocations based on historical
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1 operations from the left over 20 percent of the
2 state budget. These allocations are then
3 reduced by 20 percent. If any allocations
4 remain, they are divided among all sources
5 according to historical operations. In 2008 and
6 2009, Appendix F sources receive 50 percent of
7 their fixed allocations, again, regardless of
8 historical operations. Non-Appendix F sources
9 receive 50 percent of the allocation to which
10 they would be entitled based on historical
11 operations. Any remaining allowances are,
12 again, divided among all sources based on
13 historical operation.
14 The net result of this is to lock
15 non-Appendix F sources out of the majority of
16 allowance allocations for the first seven years
17 of the program. This will force newer sources,
18 which are already the cleanest in the state, to
19 force technology to unprecedented levels to
20 control emissions to within their allowance
21 allocations or attempt to buy additional NOx
22 allowances in the marketplace.
23 Existing sources, meanwhile, can
24 simply stockpile allowances from the early years
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1 of the program delaying the implementation of
2 controls for many years, even though these
3 controls may be more cost-effective than the
4 incremental controls on the newer, cleaner
5 sources. As a result, newer cleaner sources
6 will be discouraged from locating in Illinois at
7 a time when such facilities are needed to
8 provide cheaper and more reliable electricity to
9 the state.
10 In order for a market-based NOx
11 control rule to work, the NOx allowance
12 allocation scheme must reflect the historical
13 operations of the sources affected by the rule.
14 The fixed/flex allowance allocation scheme runs
15 directly counter to this precept. Accordingly,
16 Reliant Energy recommends that the proposed
17 Illinois NOx trading rule be revised to apply
18 the model rule allowance allocation methodology
19 beginning in 2006 rather than delaying full
20 implementation of this methodology until 2010.
21 My second point is NOx allowance
22 should be allocated to all sources based on a
23 target emission rate of .15 pounds per million
24 Btu. Another important difference in allocation
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1 methodology between the NOx trading rule and
2 USEPA's model rule lies in the disparate
3 treatment of Appendix F sources and newer
4 sources with respect to emission rates. The
5 model rule allocates allowances to all affected
6 sources based on historical operations
7 multiplied by .15 pounds per million Btu NOx.
8 These allocations are then prorated to all
9 sources to ensure that the total allocations do
10 not exceed the state NOx budget.
11 The result of this is to allow NOx
12 reductions to be made most cost-effectively by
13 installing controls on the sources best-suited
14 to such controls and allowing lesser controls on
15 other sources. For example, one unit may be
16 particularly well-suited to installing pollution
17 control equipment and another may not. In
18 effect, this approach rewards the lowest
19 emitters because any allowances they receive
20 above their actual emissions level can be either
21 used at other sources owned by the same owner or
22 sold on the market to recoup some of the costs
23 of installing control. This is another central
24 concept in a market-based emission control
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1 rule.
2 The proposed Illinois NOx trading
3 rule differs from the model rule in its
4 treatment of non-Appendix F sources. As noted
5 above, the model rule allocates allowances to
6 all sources based on a target emission rate of
7 .15 pounds per million Btu. The proposed
8 trading rule, on the other hand, only proffers
9 this treatment to Appendix F sources. Newer,
10 cleaner sources are allocated allowances based
11 on their permitted NOx emission limits, which
12 are much lower than .15 pounds per million
13 Btus. Current emission limits for new units are
14 approaching one-tenth of that level. Here's an
15 example of the disparity thus created. Source A
16 began operating in 1960 and consumes ten million
17 Btus of fuel in the baseline period. As a
18 result of the NOx budget rule, Source A was
19 equipped with pollution control equipment that
20 reduces NOx to .05 pounds per million Btu.
21 Source B began operating in 2000. Source B also
22 consumed ten million Btus of fuel in the
23 baseline period and also has NOx emissions of
24 .05 pounds per million Btu.
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1 Under the proposed rule, Source A
2 would receive 750 NOx allowances, while Source B
3 would receive 250. I would like to editorialize
4 here that this is assuming that I'm ignoring the
5 idea that the entire budget is likely to be
6 oversubscribed and these would all be prorated.
7 This is just a relative proportion. It's an
8 example of the proportions.
9 In effect, Source B is penalized for
10 being built after 1995. Consider also the fact
11 that the source built in 2000 is almost
12 certainly more efficient than the source built
13 in 1960, and the imbalance of this approach
14 becomes even more pronounced. In this way, the
15 proposed trading rule provides another barrier
16 to the new electric generation facilities
17 Illinois needs and rewards older, less efficient
18 units simply for being older. Reliant Energy
19 strongly recommends that all existing units be
20 allocated allowances based on a target emission
21 rate of .15 pounds per million Btu.
22 The new source set-aside should be
23 maintained at five percent of the total state
24 NOx budget for the life of the program. The
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1 current proposal reduces the size of the new
2 source set-aside to two percent of the total NOx
3 budget beginning in 2006. This will further
4 limit the allowances available to new sources
5 wishing to locate in Illinois raising additional
6 barriers to economic development. The new
7 source set-aside is the pool of allowances which
8 is used to provide allowances to new sources
9 until they have been operating long enough to
10 enter the main program.
11 This recommendation is consistent
12 with the Illinois Pollution Control Act, which
13 stipulates five percent of total state NOx
14 budget as the maximum size of the new source
15 set-aside. Other states have maintained the new
16 source set-aside at five percent of the total
17 NOx budget in order to encourage continued
18 economic development. In fact, New Jersey has a
19 new source set-aside equal to ten percent of the
20 state NOx budget.
21 I'd also like to point out here that
22 one of the previous witnesses was discussing
23 their facility, which was a CFB boiler facility
24 burning coal waste and so forth, and they were
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1 talking about NOx emissions during the control
2 period of, if memory serves, about 1100 tons,
3 and the new source set-aside when it drops to
4 two percent of the state budget will be about
5 600 tons of NOx. So with one source of that
6 size of that new source set-aside, it would
7 already be two percent -- excuse me, two times
8 oversubscribed.
9 Item four, IEPA should not charge
10 fee withdrawals from the new source set-aside.
11 The IEPA has proposed to charge an equal to the
12 market index price for each NOx allowance
13 allocated from the new source set-aside. The
14 proceeds from these fees are then returned to
15 Appendix F sources. In effect, this further
16 increases the cost of doing business in Illinois
17 for new sources, but provides very little return
18 to Appendix F sources to help them offset
19 pollution control costs.
20 The new source set-aside is simply a
21 mechanism to provide allowances to new sources
22 until they have operated for long enough to
23 enter the main program. No fee is charge for
24 allowance allocations in any other part of the
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1 program. There's no benefit for charging a fee
2 to a source simply because they're in this
3 interim program. Furthermore, Reliant Energy is
4 unaware of any other states that are proposing
5 to charge for withdrawals from the new source
6 set-aside.
7 In summary, the proposed Illinois
8 NOx trading rule, with some important changes,
9 should provide for clean air in the state by
10 balancing the interests of existing electric
11 generation facilities with those of new entrants
12 into the electric generation market. Reliant
13 Energy appreciates the opportunity to provide
14 input on this important topic, and we are
15 prepared to answer any questions that the
16 Pollution Control Board may have regarding our
17 comments or anybody else for that matter.
18 HEARING OFFICER GLENN: Thank you,
19 Mr. Furstenwerth. Why don't we go to members of
20 the public first. Would anyone like to ask a
21 question of Mr. Furstenwerth's testimony? Such
22 a quiet group. Okay. Members of the Agency,
23 anything?
24 MS. KROACK: We have no questions.
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1 HEARING OFFICER GLENN: Okay. Members of
2 the Board, any questions for Mr. Furstenwerth?
3 MS. McFAWN: I have some. I didn't want
4 to disappoint you all. The first page of your
5 prepared testimony, you say that, in effect, the
6 proposal will insulate older generating sources
7 from having to install pollution control
8 equipment. I didn't realize that. I thought
9 they had to install pollution control equipment,
10 but they were going to have a difficult time
11 cost and retrofitting.
12 MR. FURSTENWERTH: I think the intent
13 there was to say that some of the provisions of
14 the rule tend to minimize the impact of some of
15 the pollution control equipment that would have
16 to be installed on those, in my opinion, at the
17 -- to the detriment of new sources in the
18 state.
19 MS. McFAWN: So they will have to install
20 equipment?
21 MR. FURSTENWERTH: Yes.
22 MS. McFAWN: How would -- maybe I didn't
23 understand your answer correctly.
24 How would the installation of that
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1 equipment be a detriment to the new sources?
2 MR. FURSTENWERTH: Because the way that
3 it does that is by preserving a larger portion
4 of the total allowance pool and dedicating it to
5 existing sources. So while new sources are
6 being built in the state and competing for a
7 relatively small portion of the allowance pool,
8 the existing sources are still entitled to a
9 fixed portion of that pool through the first
10 seven years of the program.
11 MS. McFAWN: Okay. Thank you.
12 Further on in your testimony under
13 your first point still, you were talking about
14 new sources and cleaner sources being
15 discouraged from locating in Illinois at a time
16 when such facilities are needed to provide
17 cheaper and more reliable electricity to the
18 state.
19 Why, you know, if we set aside the
20 cost of the allocations, why would the new
21 sources provide cheaper electricity?
22 MR. FURSTENWERTH: The presumption here
23 is that the will of the Illinois Assembly or
24 their perception of the way the electric
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1 industry should work is correct in that more
2 generation in the -- excuse me, more competition
3 in the electric generation sector will drive
4 prices down for all the end users of
5 electricity.
6 MS. McFAWN: All right. But if you're
7 using like a cleaner fuel like gas, it can be a
8 more costly --
9 MR. FURSTENWERTH: I wouldn't dispute
10 that natural gas costs more than coal. That's
11 right.
12 MS. McFAWN: Under your fourth point
13 towards the end of your prepared testimony, you
14 say -- you're talking about the market index
15 price which will be the fee, and you said that
16 the proceeds from these fees are then returned
17 to the Appendix F sources, okay, and that, in
18 effect, this provides very little return to help
19 the sources in the main program offset pollution
20 control costs.
21 By that, I think you're referring to
22 the Appendix F sources; is that correct?
23 MR. FURSTENWERTH: What I'm referring to
24 is that with the size of the new source
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1 set-aside, if the entire new source set-aside
2 were sold at a market index price of, you know,
3 whatever that may be, maybe it's $3,000 a ton of
4 NOx, and I don't really know what that would be,
5 when you take the proceeds from the entire new
6 source set-aside, which will be 600 tons after
7 the first three years of the program, divide it
8 over all the existing sources in the existing
9 source pool -- I think I misspoke here.
10 I believe that this is distributed
11 to all of the existing sources of folks in the
12 existing pool. At any rate, when you divide it
13 over all of those sources, the net return to any
14 one of those sources is very small compared to
15 their total pollution control costs.
16 MR. RAO: Just clarification on your
17 reply.
18 The proceeds from the sale of new
19 source set-aside, part of it is for -- is meant
20 for the Ageny's administration of this program,
21 right? So only, you know, the monies that are
22 generated in excess of whatever the Agency's
23 costs are there, that is distributed to the
24 existing sources?
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1 MR. FURSTENWERTH: Right. I should
2 clarify. We would support a fee for the cost of
3 administering the program. It's the cost over
4 and above that we feel are not justified.
5 MR. RAO: Thank you.
6 MR. MELAS: Just a couple of
7 clarification questions. On your opening
8 paragraph, that 345 megawatt facility in Shelby,
9 is that a base load unit or is that a peaker
10 unit?
11 MR. FURSTENWERTH: That's a peaker.
12 MR. MELAS: Is it simple cycle?
13 MR. FURSTENWERTH: Yes, sir.
14 MR. MELAS: And what about the one you're
15 planning in Aurora, what's that going to be?
16 MR. FURSTENWERTH: That will also be a
17 simple cycle plant.
18 MR. MELAS: Are there any plans down the
19 road to maybe go combined cycle on that Aurora
20 plant?
21 MR. FURSTENWERTH: I'm not aware of any
22 at this time.
23 MR. MELAS: Do you have adequate space on
24 your site if you so decide that three years down
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1 the line you want to do that?
2 MR. FURSTENWERTH: I'm not sure. I don't
3 know if that was something that was anticipated
4 or not.
5 HEARING OFFICER GLENN: Any more
6 questions of Mr. Furstenwerth? Okay. Seeing
7 none, thank you very much for coming. Let's
8 move on to Mr. Miller.
9 MS. FAUR: My name is Cynthia Faur. I'm
10 from Sonnenschein, Nath & Rosenthal. I'm here
11 today representing Midwest Generation EME. We
12 have one primary witness today, Scott Miller.
13 Kent Wanninger is also at the table with us to
14 answer any more technical questions that the
15 Board, the Agency, or members of the public may
16 have. Mr. Miller is going to summarize his
17 testimony today, but I do have copies of his
18 prefiled testimony and his summary to submit to
19 the Board as exhibits.
20 HEARING OFFICER GLENN: Please present
21 those now, Ms. Faur. Mr. Wanninger, could we
22 swear you in actually. Could we get him sworn
23 in first, and then I'll do the exhibits.
24 (Witness sworn.)
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1 HEARING OFFICER GLENN: And then now I
2 will mark Mr. Miller's prefiled testimony as
3 Exhibit No. 38 and then Mr. Miller's -- the
4 summary of Mr. Miller's testimony as Exhibit No.
5 39.
6 (Exhibit Nos. 38 and 39
7 marked for identification,
8 9-26-00.)
9 HEARING OFFICER GLENN: Okay. Please
10 begin.
11 MR. MILLER: Good afternoon. My name is
12 Scott Miller. I represent Midwest Generation
13 where I am employed as a senior environmental
14 engineer in the corporate environmental health
15 and safety department. I have been working for
16 Midwest Generation since the fossil generation
17 assets of Commonwealth Edison Company were
18 purchased by Edison Mission Energy on December
19 15th, 1999. Prior to that, I held a similar
20 position at Commonwealth Edison where I was
21 involved mainly with air quality planning,
22 permitting, monitoring, and compliance.
23 I've been following NOx regulation
24 development issues since the Clear Air Act was
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1 amended in 1990, and I have participated in the
2 development of several proposed rulemakings
3 concerning NOx emissions, including the Illinois
4 Draft NOx RACT regulation and the Chicago
5 nonattainment area NOx cap and trade design team
6 which was the predecessor to the VOM cap and
7 trade system and regulation. I also
8 participated as a stakeholder in the development
9 of the NOx trading program for electrical
10 generating units, which is the of this
11 rulemaking.
12 As the Board may be aware, Midwest
13 Generation is a new company to Illinois, and it
14 is based in Chicago. Midwest Generation is a
15 subsidiary of Edison Mission Energy, which is
16 one of the largest independent power producers
17 in the world with an installed capacity of over
18 27,000 megawatts of electrical. Midwest
19 Generation, which consists of coal, oil, and
20 natural gas power plants in Illinois and
21 Pennsylvania, has an installed capacity of
22 10,000 megawatts in Illinois and 2,000 megawatts
23 in Pennsylvania. In Illinois, Midwest
24 Generation operates coal-fired plants in
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1 Chicago, Waukegan, Will County, Joliet, and
2 Pekin, Illinois.
3 When Midwest Generation purchased
4 ComEd's fossil assets, it made a commitment to
5 reduce nitrogen oxides from those plants by 50
6 percent both on a rate basis and a tonnage basis
7 by the end of the year 2002. This commitment
8 was not based upon any future regulatory
9 requirements or the prospect of early reduction
10 credits, but based upon a desire to improve air
11 quality in Midwest Generation's operating area.
12 Earlier this year, we have
13 retrofitted three tangentially fired boilers at
14 our Joliet, Waukegan, and Will County stations
15 with low NOx burners utilize close-coupled and
16 separated overfire air ports known as the ABB
17 TFS-2000 system. All three units have achieved
18 NOx reductions as low as 1.3 pounds per million
19 and collectively will reduce NOx emmissions by
20 4500 tons in this year's ozone season and 9,000
21 tons annually. This newly achieved emissions
22 rate at all three units is greater than a 50
23 percent reduction.
24 Next year, Midwest Generation plans
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1 to install NOx controls at an additional five
2 units. These controls will reduce NOx by an
3 additional 7,000 tons during the ozone season
4 and 14,000 tons annually.
5 Midwest Generation generally
6 supports the proposed rule including the NOx
7 budget allowance allocations. The purpose of my
8 testimony is to comment on three aspects of the
9 rule; the compliance date for the rule in light
10 of a recent court ruling extending the
11 compliance date for the SIP Call until March
12 31st, 2004; the appropriateness of the fixed
13 allocation method; and the manner in which early
14 reduction credits will be determined.
15 First, Midwest Generation requests
16 that the Board amend the proposed rule to
17 postpone the compliance date for the NOx SIP
18 Call from May 1, 2003, to May 31st, 2004. We
19 heard this morning a motion to amend, and we
20 would agree with that. On August 30th, 2000,
21 the U.S. Court of Appeals for the District of
22 Columbia, as part of the ongoing litigation of
23 the USEPA rules known as the SIP Call, postponed
24 the compliance date for the SIP call until May
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1 31st, 2004. Consequently, it is my
2 understanding that implementation of the
3 proposed rule, which is Illinois' response to
4 the NOx SIP Call, could be delayed until May
5 31st, 2004, in accordance with that order.
6 Midwest Generation believes that an extension
7 will better enable sources to install the
8 pollution control equipment necessary to meet
9 the requirements of the rule by the compliance
10 date.
11 It is Midwest Generation's
12 understanding that the Illinois EPA intends to
13 propose an interim rule that would require EGUs
14 to meet a rate-based limit of .25 pounds per
15 million Btu by May 1st, 2003. Midwest
16 Generation would, in concept, support such an
17 interim rule giving sources time to comply with
18 the additional stringent requirements of the SIP
19 Call.
20 Second, I would like to comment on
21 the fixed allocation method proposed by the
22 Agency in the initial years of the program.
23 Midwest Generation supports this approach
24 because it provides existing coal burning
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1 facilities with certainty coming into this
2 stringent NOx reduction program. There has not
3 been a great deal of experience on the retrofit
4 of control technologies on existing coal-fired
5 burning units, using fixed allotments for the
6 initial years of the program will facilitate a
7 smooth transition of existing EGUs, those in
8 service before 1995, into this program.
9 Finally, I would like to comment on
10 two aspects of the early reduction credit
11 program included in Section 217.770 of the
12 rule. Before I summarize Midwest Generation's
13 comment on 217.770, I would like to withdraw a
14 portion of my prefiled testimony on the early
15 reduction program. In my prefiled testimony, I
16 suggested that the Board amending 217.770 of the
17 proposed rule to allow sources to generate early
18 reduction credits over a three-year period, 2001
19 through 2003, instead of the two-year period
20 currently proposed.
21 After filing my prefiled testimony
22 with the Board, however, I learned that the
23 Agency intends to amend this proposed rule to
24 delay implementation of the NOx trading rule
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1 until May 2004, and to propose to the Board an
2 interim NOx rule that would become applicable to
3 EGUs in May 2003.
4 Since the Agency intends to propose
5 an interim rule to the Board that would require
6 emission reductions from EGUs in May 2003,
7 Midwest Generation no longer believes that would
8 be appropriate to allow sources to generate ERCs
9 in the year 2003.
10 Therefore, I am withdrawing my
11 comments in the prefiled testimony that
12 reference options for three-year early reduction
13 credit program. In my oral testimony, I will
14 summarize our comments on the two-year early
15 reduction program as originally proposed by the
16 Agency.
17 Midwest Generation strongly believes
18 that an early reduction credit program should be
19 included in the final rule adopted by the
20 Board. An early reduction credit program will
21 provide sources with the incentive to reduce
22 their NOx emissions before the required
23 compliance date, but this incentive will be lost
24 if the years of the early reduction program can
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1 slide back with delays in the program. Under
2 Section 217.770(e), as currently proposed, if
3 the date for implementing the NOx SIP Call is
4 delayed, the dates for use of the ERCs will
5 shift to correspond with the first two years of
6 the trading program and the years in which ERCs
7 can be generated will be delayed until two years
8 before implementation of the trading program.
9 While Midwest Generation agrees that
10 ERCs should be available to be used during the
11 first two years of the trading program, it does
12 not believe that there should be a shift in the
13 years in which ERCs can be generated. Midwest
14 Generation, therefore, requests that 217.770(e)
15 be revised to provide that if there's a delay
16 in implementation of the SIP Call, which there
17 seems to be, the dates for submitting an early
18 reduction request will remain as provided in
19 217.770(d)(3), but the other dates in the
20 section shall be adjusted accordingly. The
21 proposed revision will lock in 2001 and 2002 as
22 the dates for the early reduction program.
23 Only an early reduction program that
24 locks in 2001 and 2002 as the years for early
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1 reduction credit generation will truly encourage
2 early reduction. If the dates for early
3 reduction credit generation are allowed to slide
4 with the implementation of the trading rule,
5 sources that reduce emissions in 2001 and 2002
6 will be penalized because other sources that did
7 not intend to reduce their emissions early, but
8 instead planned to install their control
9 equipment just in time to comply with the rules
10 would also be eligible for a share of the
11 limited number of ERCs.
12 To further encourage early
13 reductions, Midwest Generation also requests
14 that the Board advise the allocation of ERCs
15 contained in section 217.770(f)(2) of the
16 proposed rule to provide a larger pool of
17 available credits in 2001 and 2002. As
18 currently proposed, Section 217.770(f)(2)
19 provides that the 15,621 ERCs will be divided
20 equally over the two years of the early
21 reduction credit program. Midwest Generation
22 believes that to truly encourage and reward
23 early reductions, this pool should be divided so
24 more credits are available in 2001.
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1 Specifically, Midwest Generation requests that
2 the Board revise a proposed rule to allocate
3 two-thirds of the available credits, or 10,184
4 ERCs, to the ERC pool in 2001 and to allocate
5 the remaining one-third of the credits, or
6 5,887 -- 5,087 ERCs to the 2002 pool. Since the
7 allowances carry forward, no unused allowances
8 would be lost by this proposed method, and the
9 proposed method would encourage earlier
10 reductions.
11 Midwest Generation also requests
12 that the Board revise the calculation
13 methodology contained in 217.770(c) of the
14 proposed rule, which is used to determine if
15 early reductions are eligible for the ERC
16 program. Specifically, Midwest Generation
17 requests that the Board delete the requirement
18 contained in Section 217.770(c)(2) that EGUs
19 with units that are part of a NOx averaging plan
20 achieve emission reductions from those units as
21 a whole equivalent to a 30 percent reduction
22 from the emission rate required under that NOx
23 averaging plan.
24 A NOx averaging plan is a means of
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1 demonstrating compliance with the annual NOx
2 limitations under the Federal Acid Rain Program,
3 and Midwest Generation does not believe that
4 this annual averaging plan should be applied on
5 a five-month basis because under the averaging
6 plan, there can be variation annually in the
7 emissions from the units included in the
8 average. For example, in the summer months, all
9 the units in the NOx averaging plant may meet or
10 exceed the individual NOx limitations applicable
11 to their particular boiler type without
12 averaging, but averaging may be needed to meet
13 the NOx limits of the Acid Rain Program in
14 another part of the year.
15 In that example, some units may be
16 achieving emission reductions that exceed 30
17 percent of their individual acid rain
18 limitations, but the other units included in the
19 averaging plan may not be performing at a level
20 that would demonstrate 30 percent reduction from
21 the emission rate in the averaging plan even if
22 the other units were actually in compliance with
23 their individual acid rain NOx limitations for
24 the ozone season.
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1 As demonstrated by my example, each
2 EGU could be penalized for using an annual NOx
3 averaging plan for acid rain compliance in a way
4 that another source that was not participating
5 in an averaging plan would not. To address this
6 potential problem, Midwest Generation requests
7 that the Board delete the requirement in Section
8 217.770(c)(2) that EGUs participating in an
9 annual NOx averaging plan for acid rain
10 compliance be required to demonstrate a 30
11 percent reduction from the emission rate
12 contained in the averaging plan across the units
13 in the average plan, and to revise Section
14 217.770(c)(1) to require that all EGUs subject
15 to acid rain requirements demonstrate a 30
16 percent reduction from the applicable acid rain
17 program on a unit-by-unit basis. Midwest
18 Generation thanks the Board for allowing comment
19 on this regulation and thanks the Illinois EPA
20 for many years of developing even back to 1990
21 with the RACT regulations to this day on
22 developing those regulations.
23 HEARING OFFICER GLENN: Thank you, Mr. Miller.
24 Before we take questions of Mr. Miller, Ms.
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1 Faur, could I impose upon you to at some point
2 serve the service list with a summary of the
3 testimony?
4 MS. FAUR: Certainly.
5 HEARING OFFICER GLENN: That way if the
6 transcript isn't available on the web right
7 away, at least people will be aware of what Mr.
8 Miller has changed today from his prefiled
9 testimony.
10 MS. FAUR: Certainly. We will serve the
11 service list.
12 HEARING OFFICER GLENN: Thank you very
13 much. Do members of the public have any
14 questions of Mr. Miller? Yes, please, Mr.
15 Darguzas.
16 MR. DARGUZAS: Just a quickie techno
17 meaning point. On page two of your prefiled
18 testimony, did you mean to say that you had
19 reductions of .13 pounds per million Btu, and,
20 if so, what are the before and after limits?
21 MR. MILLER: The peak-fired units are
22 baseline emissions. The baseline was about
23 between .4 and .5 pounds per million Btus.
24 MR. DARGUZAS: And you're actually down
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1 to .12 on a continuous basis?
2 MR. MILLER: Yes.
3 BOARD MEMBER FLEMAL: I was trying while
4 you were running through, particularly Section
5 217.770, to flip back and forth to where you
6 were suggesting your changes, and I'm going to
7 have to go back and do that a little bit more.
8 Maybe you can help me, though, as I pursue that
9 effort.
10 Are there any of those
11 recommendations that you made regarding 217.770
12 that the Agency has also recommended in its
13 motion? I'm not sure whether you were
14 supporting their changes or whether you were
15 offering changes in addition to what they add or
16 wanted to say where we were?
17 MR. MILLER: I think they added three
18 years to the early reduction credit program, and
19 that our comments refer to a two-year program,
20 2001 and 2002.
21 BOARD MEMBER FLEMAL: To stay with
22 basically the proposal as is rather than the
23 motion made by the Agency to make that a
24 three-year program.
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1 MR. WANNINGER: And the other
2 recommendation was to move -- to have a split in
3 the early reduction credits, two-thirds of them
4 earned in the first year, one-third in the
5 second year to encourage cleaning up the
6 environment earlier.
7 BOARD MEMBER FLEMAL: Thank you.
8 HEARING OFFICER GLENN: Any other
9 questions of Mr. Miller from the Agency?
10 MS. KROACK: We have no questions.
11 HEARING OFFICER GLENN: Thank you,
12 Ms. Kroack. Anyone else from the public or
13 members of the Board?
14 MS. McFAWN: I have a question. Your
15 second point was that you agree with the fixed
16 allocation method; is that right?
17 MR. MILLER: Right.
18 MS. McFAWN: Okay. And the reason is is
19 that there has not been a great deal of
20 experience in retrofitting; is that right?
21 MR. MILLER: On large cycle and boilers
22 like with SCR control technology, add-on control
23 technology, for large coal-fired units.
24 MS. McFAWN: Is that the kind of
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1 retrofit -- did you do retrofitting to lower
2 your numbers?
3 MR. MILLER: Most of the projects we've
4 done so far are burners and tangentially fired
5 boilers. The more difficult retrofits would be
6 on larger units, greater than 500 megawatts. We
7 have quite a few cyclone boilers that are high
8 NOx emitters, emit greater than 1.0 pounds per
9 million Btu. There's not a lot of actual
10 commercial demonstrations of SCR in large
11 coal-fired units, especially that burn powder.
12 MS. McFAWN: What was that last part?
13 I'm sorry.
14 MR. MILLER: There's not a lot of
15 retrofits on cyclone boilers that burn powder
16 and river basin coal, western coal.
17 MS. McFAWN: Do you anticipate having to
18 do that type of retrofitting in the near
19 future?
20 MR. MILLER: If the budget is based on
21 a .15 rate.
22 MR. WANNINGER: We have plans right now
23 to do a retrofit in our powering station. We've
24 sent out for bids.
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1 MS. McFAWN: That was all. Thank you.
2 Any other questions of Mr. Miller this
3 afternoon? Okay. Seeing none, Mr. Miller and
4 Mr. Wanninger, thank you very much. We
5 appreciate your time.
6 Before moving to Ms. Schoen, it has
7 come to my attention that Mr. Menne would like
8 to come back this afternoon and say a few more
9 words. If anybody else that has already
10 testified today would like to come back up after
11 we've heard from Ms. Schoen, I will ask you to
12 indicate so when she's finished.
13 Otherwise, we'll hear from Mr. Menne
14 following Ms. Schoen and then any other members
15 of the public that didn't file prefiled
16 testimony, but would like to say a few words,
17 are welcome to do so also. So, let's see, Ms.
18 Schoen, we'll hear from you, please.
19 MS. SCHOEN: Should I be sworn?
20 HEARING OFFICER GLENN: Yeah. Please
21 spell your name for the record, please?
22 MS. SCHOEN: It's S-c-h-o-e-n.
23 HEARING OFFICER GLENN: Thank you. I
24 apologize for the pronunciation.
L.A. REPORTING (312) 419-9292
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1 (Witness sworn.)
2 MS. SCHOEN: I would like to submit my
3 prefiled testimony.
4 HEARING OFFICER GLENN: Okay. We will
5 admit Ms. Schoen's prefiled testimony as Exhibit
6 No. 40.
7 (Exhibit No. 40 marked
8 for identification,
9 9-26-00.)
10 HEARING OFFICER GLENN: Ms. Schoen, you
11 might want to speak just a little loudly in
12 case -- I couldn't hear you very well. I'm kind
13 of loud. Thank you.
14 MS. SCHOEN: Good afternoon. My name is
15 Mary Schoen, and I'm manager of environmental
16 strategies for Enron Corporation. Before I get
17 started, I'd like to thank the Illinois EPA as
18 well as for the willingness to engage in an open
19 dialogue on these important issues and for their
20 active encouragement in the industry public's
21 participation in this rulemaking effort.
22 Enron Corporation is a diversified
23 energy and communications business. We're the
24 largest wholesale marketer of natural gas and
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1 electricity in the U.S. We're a leading
2 developer of clean merchant generation, and our
3 business, Enron Energy Services, is a leading
4 provider of retail energy solutions for
5 customers around the U.S. and here in Illinois.
6 Finally, speaking from a trading market
7 perspective, we're one of the leading emissions
8 traders of NOx and SO2 allowances in the U.S.
9 today. We're particularly proud of our Lincoln
10 Energy Center here in Illinois. This natural
11 gas-fired facility meets the most stringent air
12 requirements for a simple cycle generating
13 plant. Using GE's dry load NOx technology,
14 we're able to keep emissions at nine parts per
15 million NOx.
16 That being said, we're still very
17 concerned with the NOx SIP being developed here
18 in Illinois. We've already paid a high price to
19 build a facility that needs these stringent
20 clean energy requirements. We believe that the
21 rule being developed by Illinois EPA will add
22 significant economic costs to doing business
23 here in Illinois.
24 First, let's discuss what the goals
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1 of the rulemaking were. As you've already
2 heard, the USEPA in a work group consisting of
3 states and industry determined that in order to
4 meet clean air standards for ozone attainment,
5 NOx would have to be addressed on a regional
6 basis. USEPA then developed budgets of these
7 NOx allowances for the affected states that it
8 determined contributes to transportation of
9 ozone in affected regions.
10 As I stated in my written submittal,
11 each state had its discretion on how to allocate
12 allowances to affected sources, but they must
13 stay within the budget given them by the USEPA
14 in order to participate in the trading program.
15 This allowance allocation is a
16 critical factor of the trading program since, as
17 I stated in my testimony, it compromises the
18 distribution of wealth, so to speak, in the
19 trading program. The USEPA provided a model
20 emissions trading program for states to use as
21 guidelines, and the theory behind this cap and
22 trade program proposed by the EPA is that the
23 market, if allowed, will determine where the
24 most cost-effective emissions reductions can be
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1 made, and that as long as there is a cap, in
2 this case, a budget on the emissions, the
3 environmental goals will be met.
4 I think the history is showing that
5 cap and trade programs can be very effective
6 ways to achieve environmental regulations. The
7 SO2 market established an acid rain program and
8 has achieved reductions at much lower costs than
9 anticipated when the rule was developed, and the
10 states currently participating in NOx trading
11 programs on the east coast have also achieved
12 NOx reductions at much lower costs than
13 originally anticipated when the rule was being
14 developed, but, again, the key to successful cap
15 and trade programs is that the market determines
16 where these cost-effective reductions can be
17 made.
18 If allowances are distributed
19 equally to all affected sources, then the
20 sources and the market can determine a rational
21 economic basis on how to achieve reduction,
22 whether it is to install control technology or
23 whether it is to buy emissions on the market,
24 whether it is to shut down and sell emissions
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1 that they have available to them.
2 If, however, the allocations are
3 skewed to one group or another, then the
4 cost-saving functions of the cap and trade
5 program will be skewed and the lowest cost
6 reduction will not be made. The design of the
7 program is critical to ensuring the market
8 mechanisms envisioned by the USEPA work.
9 Unfortunately, the Illinois EPA's proposed rules
10 go against these key principles of letting the
11 market determine where to make reductions, and
12 while the air may be cleaner, the citizens and
13 electric consumers of the state of Illinois will
14 ultimately pay the price of a NOx SIP that
15 disincentivizes the development of clean
16 generation to prevent the lowest cost reductions
17 from being made.
18 I'm going to my written testimony
19 now under Subpart W comments if you want to
20 follow there. In developing Subpart W, as I
21 said, Illinois diverged significantly from the
22 allocation philosophy recommended by the USEPA.
23 IEPA developed the allocation approach after
24 extensive negotiations with existing affected
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1 sources. Developers of new power plants were
2 not included in this process. This is the
3 subpart or the Appendix F, I think, it's
4 called. The resulting allocation methodology is
5 referred to as the fixed/flex approach.
6 The initial allocation of allowances
7 in 2003 provides allowances, tongue twister,
8 allowances only to plants that were in operation
9 by January 1st, 1995. Under the fixed/flex
10 approach, the allocations to existing sources
11 are fixed to varying degrees until 2008. That
12 means that the existing sources receive the
13 majority of the allowances through 2008,
14 regardless of how much they run or how much they
15 emit. They will receive these allowances even
16 if they are shut down and have no emissions.
17 In the EPA model rule, which we
18 advocate, the plants that actually provide the
19 state's power receive the allowances. In
20 Subpart W, the existing plants receive
21 grandfathered allowances regardless of whether
22 they provide any power to the state.
23 Under the flex portion of the rule,
24 some of the remaining allowances are allocated
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1 to the new sources at their very low permitted
2 emissions levels. The formula is designed in
3 such a way that new sources will not receive
4 enough allowances to cover their actual
5 emissions, even though they are as much as ten
6 times cleaner than the nominal .15 pounds per
7 MM/Btu emissions rate. Despite the high cost
8 systems required of these new plants, as I said,
9 to meet new stringent technology requirements,
10 they will be required to purchase allowances,
11 possibly even from our competitors, in order to
12 operate under this rule.
13 While IEPA and the owners of
14 existing plants argue that retrofit controls on
15 existing plants are more costly than controls on
16 new plants, actual experience indicates the
17 opposite. The cost of NOx controls for large
18 coal-fired plants is expected to range from
19 $1500 to $5,000 a ton of NOx reduced. However,
20 the reduction cost of installing SCR on an
21 already low-emitting gas-combined cylcle can be
22 much higher.
23 Having already, as I said, paid this
24 high price to control emissions, the new plants
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1 have as much claim as existing plants to the
2 benefits of the trading program and should be
3 treated equitably.
4 Finally, although there's a new
5 source set-aside, as we've heard from other
6 testimonies today, the large number of new
7 plants being built in Illinois will rapidly
8 exhaust that set-aside and there will not be
9 enough allowances to go around. Moreover,
10 plants that go on line after May 1st, 2002, will
11 be required to pay for any new source set-asides
12 they receive at market prices.
13 Existing sources argue that the EGU
14 budget is based upon their continued operation
15 and that they should be compensated for loss of
16 allowances allocated to new EGUs. This
17 misstates the development and philosophy of the
18 trading program. The EGU budget set by the EPA
19 was based on growth and power generation in
20 Illinois at a constant allocation rate of .15
21 pounds per MMBtu, and while we've heard there is
22 controversy surrounding the budget that was
23 determined for EPA, but the fact is that this
24 budget number did not specify which entities
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1 would provide the growth in that state. In
2 fact, new plants will actually provide much of
3 that growth that was anticipated by the USEPA.
4 Those new plants should be allocated the growth
5 portion of the budget at the full allocation
6 level set by the EPA.
7 The suggestion that existing plants
8 are losing allowances suggests that they own or
9 have a right to those allowances. The rules
10 clearly state that allowances are not a property
11 right. The allowances are created by the
12 federal and the state governments as a mechanism
13 to provide clean air at the lowest cost to
14 consumers and citizens. They represent these
15 citizens right to clean air and should be
16 allocated in the manner which best accomplishes
17 that goal. They certainly do not belong to
18 existing power plants as a reward for past
19 pollution of the environment.
20 The USEPA's model rule sets a five
21 percent new source set-aside for the initial
22 period to cover all the new sources that come on
23 line between 1995 and now 2004, I assume.
24 That's a two percent per year set-aside for
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1 subsequent annual reallocations. Since the
2 subsequent reallocation in Subpart W takes place
3 only every two years, we believe that the
4 set-aside should be increased to at least four
5 percent and not the maximum five percent. There
6 is no risk to setting a higher level for the
7 state of Illinois. If the growth does not
8 materialize, the unused set-aside allowances
9 will simply be allocated to existing sources.
10 On the other hand, if the growth is needed to
11 support Illinois' economy and electric needs,
12 the availability of set-asides will be assured.
13 In summary, there are several
14 aspects of the fixed/flex approach that will not
15 achieve emissions reductions in the state of
16 Illinois in an equitable or cost-effective
17 manner: The setting aside of a fixed portion of
18 the allowances for the existing plants; the
19 allocation of allowances for new sources based
20 on their very low permitting emissions levels
21 rather than at the same level used for existing
22 sources; the new source set-aside is not granted
23 freely to new sources, but is made available as
24 a pool of allowances to be purchased at market
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1 price; and, finally, the new source set-aside
2 being reduced to two percent, even though the
3 reallocation period is longer than one-year
4 reallocation recommended by the EPA model rule.
5 So what are the negative impacts of
6 this Subpart W? The fixed portion of the
7 allocation constitutes an anticompetitive grant
8 of economic value to the existing plants in the
9 state of Illinois. This subsidizes continued
10 greater operation of higher emitting plants.
11 Since the overall emissions are capped, the
12 plants must invest in pollution control
13 equipment. Increased operation of the plants
14 means higher control costs which are passed on
15 to the public. By subsidizing the operation of
16 the old plants, the fixed/flex approach
17 increases the cost of the program to the
18 public. The new plants, on the other hand, have
19 already invested in clean equipment. The
20 transfer of generation from the older plants to
21 the new plants would decrease the future control
22 costs for the old plants and reduce the overall
23 cost to the public.
24 The allocation to new sources based
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1 only on their low permitted levels denies them
2 any value in the trading program for their low
3 emissions. This reduces effectiveness of the
4 trading program in reducing the program cost.
5 It also makes Illinois less attractive as a site
6 for new, clean generation. Without a reliable
7 power supply, Illinois is a less attractive
8 place for new businesses and new economic
9 growth. We heard a lot from existing sources
10 that they need the fixed portion of the budget
11 in order to assure reliability, but not allowing
12 for growth in the state affects future liability
13 of the system, and there needs to be some
14 analysis on what the true impacts of that fixed
15 portion are on the liability in the state.
16 Illinois has recently gone through a long
17 process of restructuring the electric generating
18 sector.
19 A major goal of this effort was to
20 create open competition among electric
21 generators. By creating a vested interest for
22 older power plants, this rule nullifies some of
23 that value of that process. It slows the growth
24 of competitive power and reduces the potential
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1 cost savings and reliability improvements for
2 Illinois consumers.
3 Charging new sources for new source
4 set-asides exacerbates the economic
5 disincentives for new generation. It has been
6 suggested that this policy is a logical
7 extension of past programs such as the SO2
8 trading program or the new source offset
9 policies. However, the SIP Call is a new
10 program that was designed by the EPA to include
11 new source set-asides at no charge.
12 In summary, our recommendations are
13 as follows: In order to encourage the growth of
14 clean, efficient power generation in Illinois,
15 provide the open competition that is
16 contemplated by electric restructuring in
17 Illinois, and minimize the cost of the program
18 to Illinois citizens, we recommend that the
19 allocation process of Subpart W be substantially
20 restored to the provision of the EPA model rule;
21 that is, allocation to all sources based on
22 actual heat input during the appropriate
23 historical period;
24 allocation to all sources at the same emissions
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1 rate; new source set-asides be distributed free
2 of charge like other allowances; the new source
3 set-aside level should be maintained at five
4 percent throughout the program.
5 These changes will allow the trading
6 program to function properly and encourage the
7 growth of clean, efficient power generation that
8 can provide the electricity needed to support a
9 growing Illinois economy. We appreciate -- I
10 appreciate this opportunity to comment. We're
11 happy to answer any questions.
12 HEARING OFFICER GLENN: Thank you, Ms. Schoen.
13 Do any members of the public have any questions
14 of Ms. Schoen? Let's go to Mr. Furstenwerth and
15 then we'll go to Mr. Wanninger.
16 MR. FURSTENWERTH: Ms. Schoen, in the
17 third page of your testimony, I believe you
18 talked about the cost of NOx controls on SCR,
19 specifically on a combined cycle gas-fired
20 turbine-based plant.
21 MS. SCHOEN: Uh-huh.
22 MR. FURSTENWERTH: Does Enron have any
23 estimates or are you aware of any installations
24 of SCR on simple cycles which are so prevalent
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1 in current development in the state?
2 MS. SCHOEN: SCR is, A, not
3 cost-effective in cycling and, B, not
4 particularly feasible for simple cycle because
5 of the temperatures of the facilities.
6 HEARING OFFICER GLENN: Mr. Wanninger?
7 MR. WANNINGER: Ms. Schoen, in your
8 testimony, you say there's no risk of setting a
9 higher level for new source set-aside after the
10 first three years of the program. You state
11 that set-aside allowances that are not allocated
12 are not subscribed to or allocated back to
13 existing sources.
14 Is it not true that they actually go
15 into a pool and then are allocated out once that
16 pool exceeds a certain value, which would
17 probably be in two or three years?
18 HEARING OFFICER GLENN: Could you repeat
19 that? We cannot hear you.
20 MS. SCHOEN: I'm just trying to
21 understand the question.
22 MR. WANNINGER: Is it not true that the
23 set -- the allocated set-aside goes into a bank
24 and then is only distributed once that bank
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1 achieves a certain value of allowances, which
2 would be a future year so the reallocation would
3 not occur in the same year that they were not
4 subscribed?
5 MS. SCHOEN: I'm talking about creating a
6 process closer in line --
7 HEARING OFFICER GLENN: Could you repeat
8 that, please, Ms. Schoen? I'm sorry. The court
9 reporter can't hear you.
10 BOARD MEMBER FLEMAL: Face the court
11 reporter.
12 MS. SCHOEN: I'm advocating a new source
13 set-aside that's closer in line with the EPA's
14 model rule.
15 MR. WANNINGER: Are you advocating that
16 the reallocation of unused goes back in the same
17 year that they're subscribed?
18 MS. SCHOEN: Right.
19 HEARING OFFICER GLENN: Ms.Dorge, could
20 you please identify yourself for the record?
21 MS. DORGE: I'm Carol Dorge. I'm
22 interested in your thoughts on something that
23 was said by the natural gas plants to --
24 HEARING OFFICER GLENN: We can't hear
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1 you, Ms. Dorge. Could you stand up, please?
2 Thank you.
3 MS. DORGE: Is the standard based pounds
4 per megawatt hours or something as opposed to --
5 HEARING OFFICER GLENN: I'm sorry. I
6 couldn't hear you there. If everyone could just
7 shout, that would actually help.
8 MS. DORGE: An output performance base
9 standards, is that what you're talking about?
10 Do you have any thoughts on that?
11 MS. SCHOEN: To be honest, I haven't done
12 that kind of analysis on how it affects simple
13 cycle plants and peaking plants. So I wouldn't
14 care to comment at this point.
15 BOARD MEMBER FLEMAL: You at one point
16 mentioned that there was a successful NOx
17 trading market in the northeast states.
18 Do you know at what rate NOx
19 allowances are trading roughly?
20 MS. SCHOEN: When the market first
21 opened, they traded at $7,000 a ton, and that
22 was I think a fear that that would be the cost
23 in order to reduce NOx. Now, they trade below
24 half that value.
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1 BOARD MEMBER FLEMAL: What states are
2 involved in that trading program?
3 MS. SCHOEN: Twelve east coast states.
4 Maine is not. It's not Maine down to D.C.,
5 Maryland, D.C., another ozone transport -- I
6 think it's --
7 BOARD MEMBER FLEMAL: I don't know that I
8 need it on the record.
9 MS. SCHOEN: There's 12 northeast
10 mid-Atlantic states.
11 BOARD MEMBER FLEMAL: That's sufficient
12 for my purposes.
13 Assuming that the full 22 states
14 that are under the current NOx SIP Call also are
15 involved in NOx trading, do you anticipate that
16 there will be a market that's in any way similar
17 to what's going on in those 12 states?
18 MS. SCHOEN: I would anticipate it would
19 be similar, yes, if enough states opt into the
20 trading program, which it looks like they will.
21 BOARD MEMBER FLEMAL: And you would
22 anticipate that there will actually be
23 allowances to be traded, that there will be
24 places where there are unused allowances?
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1 MS. SCHOEN: Yes.
2 MS. McFAWN: That trading program, maybe
3 you can tell us a little bit more about it. I'm
4 not familiar with it, and couple of points,
5 like, when did it begin and is it the same type
6 of trading program as advocated by Part 96?
7 MS. SCHOEN: It actually began last
8 year. It will be replaced by the NOx SIP
9 program. So it goes out of effect when the NOx
10 SIP program goes into effect in states where
11 there's duplication of 12 states on the east
12 coast. The NOx SIP program supersedes.
13 MS. McFAWN: When that happens, do you
14 think that the trading program will be very much
15 different from that that they used for the past
16 year?
17 MS. SCHOEN: There obviously will be more
18 sources affected and the reductions required
19 will be greater. So I would assume the costs of
20 the program may be more, may be higher than they
21 are today.
22 MS. McFAWN: The cost of administering
23 the program?
24 MS. SCHOEN: The cost of the emissions.
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1 MS. McFAWN: The cost of the emissions?
2 MS. SCHOEN: Yes.
3 MS. McFAWN: Do you know why the price
4 dropped from 7,000 to half?
5 MS. SCHOEN: I think we heard earlier
6 utilities found ways to refire the boilers and
7 do controls that didn't require -- do reductions
8 that didn't require installation of controls.
9 They found ways to, you know, switch fuels, to
10 refire the boiler in a different way that didn't
11 require a control technology to be put on the
12 units.
13 MS. McFAWN: I had some questions on a
14 different topic.
15 You had mentioned in your testimony
16 that the allocations or the allowances are only
17 provided under the EPA model if the plant
18 actually provides the states power, okay, and
19 under ours or Illinois' proposed one, that they
20 will get the allowances even if they shut down,
21 but earlier you had stated that some of the
22 trading or the allowances available for trading
23 come about because plants shut down older
24 facilities and then use that credit towards
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1 trading. So I'm kind of befuddled.
2 How does this work?
3 MS. SCHOEN: Lower their emissions rate
4 or lower their previous year's allowances. It's
5 short-term versus kind of long-term and
6 permanent.
7 MS. McFAWN: So explain that in a little
8 bit more detail for me.
9 They shut down and then they get
10 credit so they can then market, right?
11 MS. SCHOEN: There are, unfortunately,
12 kind of different emissions programs on the
13 market today. There are emissions offset
14 programs, and then there are the allowance
15 trading programs.
16 The offset program in nonattainment
17 areas people can go and pay plants to cease
18 operations in order to buy offsets from those
19 plants in order to install new generation or
20 added generation.
21 MS. McFAWN: And is that a permanent
22 remedy in the offset programs?
23 MS. SCHOEN: It can be, yes.
24 MS. McFAWN: And how does that differ
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1 from the allowance programs?
2 MS. SCHOEN: The allowance programs,
3 again, are based on a historical operation. So
4 in the NOx program today, you're not going to
5 continue to get allowances -- if you're not in
6 the EPA's model rule, you're not going to
7 continue to get allowances if you're not
8 operating.
9 MS. McFAWN: Would you get them for one
10 year? Is that what you meant by short-term
11 benefit?
12 MS. SCHOEN: One or two years. I'm not
13 sure.
14 MS. McFAWN: Okay. And under Illinois,
15 Illinois is the one proposed by the IEPA today,
16 you don't see that happening?
17 MS. SCHOEN: Through 2009 they have the
18 right to buy, wholesale those Appendix F
19 allowances.
20 MS. McFAWN: Okay. Thank you. That was
21 very nice to hear. The clarification was very
22 helpful.
23 You talked about the combined cycle
24 plants and that it would cost $5,000 a ton or
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1 higher to install an SCR.
2 Is that the type of plant Enron is
3 operating?
4 MS. SCHOEN: We have a simple cycle
5 facility.
6 MS. McFAWN: So by your testimony about
7 these costs and what it costs an existing plant
8 versus a new gas-fired combined cycle, are you,
9 in essence, trying to say that the costs are the
10 same for the new as for the old?
11 MS. SCHOEN: No. I'm saying if a new
12 facility had to install a control technology,
13 the cost would be higher.
14 MS. McFAWN: When you say that, do you
15 mean --
16 MS. SCHOEN: Per ton of NOx reduced.
17 MS. McFAWN: If they had to -- but they
18 are installing control technologies. They're
19 just doing it at the front end, right.
20 MS. SCHOEN: Correct. Some are, some
21 aren't. We use load NOx technology on our
22 facility. We didn't put a control technology
23 SCR on our facility. It's not feasible for
24 simple cycles.
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1 MS. McFAWN: But just talking about the
2 combined cycle, when you talk about the SCR
3 being installed, that's at the construction
4 point, the initial construction?
5 MS. SCHOEN: For a new plant today having
6 to meet clean technology standards, some do,
7 some don't. I think it depends.
8 MS. McFAWN: What I mean is if, in fact,
9 they installed the SCR, it's at the time they're
10 constructing the new plant.
11 MS. SCHOEN: I'm sorry. That cost --
12 does that cost come from installing it at the
13 time, yes.
14 MS. McFAWN: So then it does -- if you
15 have to install that technology, you're saying
16 that's comparable to the same price that an
17 existing facility has to pay to retrofit?
18 MS. SCHOEN: I'm saying that an existing
19 facility can install control technology and
20 reduce their NOx emissions less costly than a
21 new facility.
22 MS. McFAWN: Oh, okay. So less costly?
23 MS. SCHOEN: Correct.
24 MR. RAO: On that, just a clarification.
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1 The statement that you made just now, does that
2 apply only in cases where they're, you know,
3 installing SCR, you know --
4 MS. SCHOEN: As opposed to some other
5 kind of --
6 MR. RAO: Yeah. Like combustion
7 modification for a simple cycle, will that be
8 comparable too?
9 MS. SCHOEN: For a new facility or for
10 the existing facilities?
11 MR. RAO: When you compare the add-on
12 controls or retrofitting for existing facilities
13 with a new facility.
14 MS. SCHOEN: The 1500 to $5,000 a ton
15 means that they can reduce their NOx without
16 putting SCR on. There's some things they can do
17 first to get to the standard in the rule. They
18 may have to put on SCR, and their costs will
19 increase. There's some low-hanging fruit that
20 they can do first to reduce the NOx emissions.
21 MR. MELAS: Ms. Schoen, on the second
22 page of your testimony, the last sentence at
23 that bottom paragraph, that's just before
24 Subpart W comments, when you were reading that
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1 sentence, you added a phrase that's not in the
2 printed version. You said although the air will
3 be cleaner, the citizens of Illinois will
4 ultimately pay the price of NOx SIP rule that
5 disincentivizes the development of clean
6 generation.
7 What did you mean by that, although
8 the air will be cleaner? Did you mean
9 immediately, in the long run? Did you mean only
10 in the short run?
11 MS. SCHOEN: No. Illinois' rule, USEPA
12 model rule, both cap NOx allowances in the state
13 of Illinois and in the region, the affected
14 region. So the air is going to get cleaner.
15 It's just a matter of how much that costs us and
16 who the winners and losers are in the process.
17 MR. MELAS: The air will get cleaner
18 either way?
19 MS. SCHOEN: The air will get cleaner
20 either way.
21 MR. MELAS: No difference between the
22 two?
23 MS. SCHOEN: Not in terms -- there
24 shouldn't be in terms of the effect on the
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1 environment.
2 MR. MELAS: Or sooner or later?
3 MS. SCHOEN: Sooner or later.
4 MR. MELAS: If the air gets cleaner
5 sooner, isn't that a worthy objective than
6 getting cleaner two, three, four, five years
7 down the line?
8 MS. SCHOEN: I would agree with that.
9 HEARING OFFICER GLENN: Ms. Kroack, did
10 you have a question?
11 MS. KROACK: I do, Ms. Schoen. You
12 testified -- you were talking about NOx credits
13 in the ozone transport commission as being
14 roughly half of $7,000, which would make it
15 3500.
16 Are you familiar with NAP Source?
17 MS. SCHOEN: Yes.
18 MS. KROACK: Would it surprise you to
19 learn that NAP Source quoting as of August 24th,
20 2000, 1999 vintage NOx allowances at $480 a
21 ton?
22 MS. SCHOEN: No.
23 MS. KROACK: Okay. And for the 2002
24 vintage, it's $560 a ton?
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1 MS. SCHOEN: (Shaking head.)
2 MS. KROACK: I just wanted to put that
3 information before the Board.
4 HEARING OFFICER GLENN: Ms. Kroack, what
5 is NAP Source?
6 MS. KROACK: NAP Source is an emissions
7 brokerage index that brokers SO2 and NOx
8 allowance and does other air quality type
9 programs.
10 MS. SCHOEN: I wasn't aware of the market
11 value. I know it had fallen below half the last
12 time I really looked at what the values were,
13 but the point being that trading programs are
14 very effective at reducing the costs of
15 emissions reductions. For a market that opened
16 at $7,000 a ton, because that's what the
17 industry was worried it would cost, has now
18 fallen down that low.
19 HEARING OFFICER GLENN: Mr. Wanninger,
20 did you have another question?
21 MR. WANNINGER: Isn't it true that the
22 ozone transport region that was referred to has
23 a much less stringent NOx standard than what is
24 proposed in the Illinois rulemaking?
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1 MS. SCHOEN: As I said, the costs will
2 likely go up in the future as more sources are
3 affected as reductions are created.
4 MR. WANNINGER: And didn't you say that
5 that program was going to be phased out with
6 the .15 SIP Call?
7 MS. SCHOEN: Yes.
8 MR. WANNINGER: Would you speculate that
9 a number of utilities are starting to install
10 overcontrolled NOx to meet that 2003 or 2004
11 deadline and consequently are generating lots of
12 excess allowances which would dilute that
13 market?
14 MS. SCHOEN: That would be an interesting
15 analysis. I think if you look at the back
16 orders on control technologies today as
17 utilities look to reduce their emissions in the
18 future, it would be interesting to say whether
19 there is an overcontrol happening right now or
20 if there were more cost-effective ways to reduce
21 emissions without --
22 HEARING OFFICER GLENN: Could you repeat
23 just that last part?
24 MS. SCHOEN: I'm not -- I don't know
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1 enough to say whether the bulk of the reductions
2 in NOx in the 12 area ozone transport region
3 came from the 12 state area early reductions in
4 anticipation of the NOx SIP or whether utilities
5 were able to reduce their NOx emissions without
6 installing control technologies. I do know that
7 there's a large back order on control
8 technologies right now as states look to come
9 into compliance with the SIP.
10 HEARING OFFICER GLENN: Thank you. Does
11 anyone else have any further questions for Ms.
12 Schoen?
13 MS. McFAWN: I do.
14 HEARING OFFICER GLENN: Okay. Board
15 Member McFawn.
16 MS. McFAWN: I hope I didn't preempt
17 anybody there. I just didn't want you to get
18 away, Ms. Schoen.
19 I'm curious because you said that
20 you're a leader in this industry. I'm just
21 going to explore some questions I have. You
22 talk about that -- where were your words? That
23 we need -- that the proposed NOx SIP
24 disincentivizes the development of clean
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1 generation.
2 What are we talking about when we
3 talk about future clean generation? Would you
4 explain that a bit?
5 MS. SCHOEN: I hate to be controversial,
6 but if you look at what happened in California,
7 and there is a shortfall in energy development
8 in California right now, and one of the
9 shortfalls for that is very stringent air
10 permitting requirements.
11 So if a new generator has an option
12 where to build their plant, they're going to
13 build it in a state that's got flexibility in
14 terms of the rules.
15 MS. McFAWN: But what kind of generation
16 are they going to build? Right now, our base
17 loads are coal-fired.
18 MS. SCHOEN: Right.
19 MS. McFAWN: And you, rightly so, say we
20 should move towards cleaner generation. Will
21 that involve retrofitting our coal-fired
22 primarily or will we find our base load replaced
23 with gas-fired or alternatives?
24 MS. SCHOEN: I think in the short-term,
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1 you're going to see retrofits on coal plants. I
2 think in the longer term, you're going to see a
3 shift to more natural gas generation across the
4 U.S.
5 You know, as natural gas prices get
6 higher and higher, does it make sense to start
7 developing cleaner coal technology? Maybe. I
8 mean, there's a lot of variables.
9 MS. McFAWN: But if we have to depend on
10 our coal-fired for the near future, sometimes I
11 look at this rule and I think the Agency may be
12 proposing it and took that into consideration
13 the reliability of the coal-fired in the next
14 five to ten years.
15 Isn't that a valid premise for their
16 proposal on allowances?
17 MS. SCHOEN: Does this rule mean that
18 coal plants are going to shut down if their
19 costs increase? I don't know. That's a market
20 decision. Does it mean that Illinois won't have
21 enough power? That, again, depends on a lot of
22 variables, what are the transmission constraints
23 in the state, how much new generation can come
24 on quickly. We can't build a plant in less than
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1 two years. I mean, there are a lot of variables
2 in that question.
3 MS. McFAWN: So do you think new plants
4 could provide the same amount, those, like you
5 mentioned, would be built in the two-year span,
6 could they actually replace?
7 MS. SCHOEN: Versus -- when you think
8 about importing power as well. I just don't
9 know what the transmission constraints are
10 versus the market.
11 MS. McFAWN: No. That's a whole
12 different issue. I just --
13 MS. SCHOEN: Can enough gas go up today
14 to shut down a large base load coal plant?
15 Probably not. Will that plant shut down if
16 there's that much market need? Probably not.
17 It's a matter of who pays. They'll just have to
18 buy allowances for that plant. It's all an
19 economic decision whether to run that plant and
20 buy allowances or run the plant less and not buy
21 as many allowances. That's a market decision
22 and that's all we're advocating is let the
23 market decide what's the most efficient way to
24 get clean generation in the state.
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1 MS. McFAWN: You had mentioned at the
2 outset of your testimony that you have a
3 facility in Lincoln Energy or Lincoln is it?
4 MS. SCHOEN: It's in Will County.
5 MS. McFAWN: Where is it?
6 MS. SCHOEN: Wilton County?
7 MS. KROACK: Will.
8 MS. SCHOEN: Will County. Sorry.
9 MS. McFAWN: And I take it that is your
10 single cycle?
11 MS. SCHOEN: Yes. It's 925 megawatts.
12 MS. McFAWN: When you talk about that
13 plant, the new generation providing low cost
14 reliable power and jobs and tax revenues, do you
15 mean as an offshoot of providing the energy or
16 do you mean the plant itself provides all that?
17 MS. SCHOEN: Both.
18 MS. McFAWN: How many jobs are there in
19 the Will County plant?
20 MS. SCHOEN: Not a lot. I think nine or
21 ten.
22 MS. McFAWN: I just was curious. Thank
23 you, Ms. Schoen.
24 HEARING OFFICER GLENN: Are there any
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1 other -- yes, please. In the back identify
2 yourself.
3 MR. HOPKINS: My name is Leonard
4 Hopkins. Just to follow up on Mr. Melas'
5 question, do you claim that the model rule or
6 the Illinois rule, one, will meet -- one, will
7 reduce the NOx quicker than the other or will
8 they both reduce at the same time?
9 MS. SCHOEN: In theory, they should both
10 reduce the same amount at the same time.
11 MR. HOPKINS: I was curious on the
12 clarification because Mr. Melas asked the rule
13 about whether it was quicker or sooner or later,
14 both rules will do it at the same time; is that
15 correct?
16 MS. SCHOEN: Absolutely, but let's also
17 look at the other associated emissions --
18 HEARING OFFICER GLENN: I'm sorry.
19 MS. SCHOEN: The other associated
20 emissions of pollution control from coal-fired
21 generation versus gas generation.
22 HEARING OFFICER GLENN: Versus what
23 generation?
24 MS. SCHOEN: Natural gas.
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1 HEARING OFFICER GLENN: Thank you. Any
2 further questions of Ms. Schoen?
3 MR. HOPKINS: I'd like to follow up.
4 HEARING OFFICER GLENN: Yes, Mr.
5 Hopkins. On the comparison between the
6 emissions control on the dual cycle gas unit
7 compared with a coal unit, 1500 to 5,000 tons,
8 the controls -- the actual tonnage controlled by
9 the controls on the gas unit are quite small in
10 comparison to the tonnage that is controlled on
11 the coal unit; is that correct.
12 MS. SCHOEN: This was a cost per ton.
13 MR. HOPKINS: Right. That's on a per
14 ton. So the actual tonnage on the gas is very
15 small compared to the actual tonnage that's
16 produced from a coal-fired unit; is that
17 correct?
18 MS. SCHOEN: I'm not sure I understand
19 the question.
20 MR. HOPKINS: Total tons that would be
21 controlled by the control device on a gas unit
22 compared to the total tons that would be
23 controlled on a coal-fired unit --
24 MS. SCHOEN: Yes.
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1 MR. HOPKINS: -- are very small?
2 MS. SCHOEN: That's correct.
3 MR. HOPKINS: For the amount that's
4 controlled on the gas, the final tonnage, for
5 instance, if it went from .15 on a coal unit to
6 .10, that amount would be very expensive to
7 control, wouldn't that be right, on a coal
8 unit?
9 MS. SCHOEN: I'm not sure what the margin
10 will cost.
11 HEARING OFFICER GLENN: Where the what
12 cost?
13 MS. SCHOEN: The margin will cost, where
14 they shift from, you know, where you hit that
15 point between possible --
16 MR. HOPKINS: And there would be tonnage
17 that would be astronomically high to you to get
18 the lower amounts or to control a small tonnage
19 of natural gas?
20 MS. SCHOEN: (Shaking head.)
21 HEARING OFFICER GLENN: Yes, Mr.
22 Urbaszewski.
23 MR. URBASZEWSKI: You earlier alluded to
24 additional environmental benefits, and I can
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1 think of other pollutants that come out of power
2 plants like sulfur dioxide, fine particulates,
3 and mercury --
4 HEARING OFFICER GLENN: We can't hear you
5 up here.
6 MR. URBASZEWSKI: Let me think how to
7 rephrase the question again, you talked about
8 additional environmental benefits that might be
9 had from some of the new plants that might be
10 running on gas, and I can think of several
11 pollutants that come out of power plants, be it
12 nitrogen oxides, but you also have sulfur
13 dioxides, which gets oxidized as fine
14 particulate matter and mercury.
15 Could you give us an understanding,
16 perhaps, of what the difference would be between
17 a typical older coal plant and a new gas plant
18 that might have to meet these additional
19 regulations that you're talking about in terms
20 of those pollutants?
21 MS. SCHOEN: I think you hit two
22 pollutants that are being talked about as
23 possibly being regulated in the future, which
24 are fine particulates and mercury, and, you
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1 know, what the costs are. I'm not sure coal
2 predominately generates. The mercury are
3 man-made mercury emissions that are generated in
4 the U.S. Fine particulates, predominately it's
5 from coal generation, but your question is in
6 terms of the cost and differences between --
7 MR. URBASZEWSKI: I was just asking about
8 the relative difference. Would one be far less
9 than the other?
10 MS. SCHOEN: Yeah. I mean, natural gas,
11 mercury is a -- mercury comes from coal, I mean,
12 that coal generation that doesn't come from
13 natural gas generation. Fine particulates are
14 due to both fuels and combustion, but coal-fired
15 generators generate more fine particulates
16 matter. Coal-fired generators generate more
17 fine particulates than natural gas generation.
18 MR. URBASZEWSKI: Thank you.
19 HEARING OFFICER GLENN: Any other
20 questions of Ms. Schoen before I give her the
21 award for answering the most questions today?
22 MS. SCHOEN: I'm glad I could be so
23 controversial at the end of the day.
24 HEARING OFFICER GLENN: Okay. We really
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1 appreciate your patience. Let's take a
2 five-minute break.
3 (Break taken.)
4 HEARING OFFICER GLENN: I believe Mr. Menne
5 wanted to say some additional comments. If
6 after Mr. Menne speaks, anyone else would like
7 to say anything, regardless of whether you filed
8 prefiled testimony or not, I will inquire after
9 Mr. Menne if you'd like to do that. Mr. Menne,
10 please begin.
11 MR. MENNE: Thank you. First, I'd just
12 like to say that for the questioning Ms. Schoen
13 just got, I don't know if I really want to say
14 anything else, but I appreciate the opportunity
15 just for a quick clarification.
16 One of our units, the Grand Tower
17 unit, which is a coal-fired plant that's being
18 converted to gas was mentioned earlier, and I
19 just wanted to inform the Board what the
20 situation is with regard to that plant and how
21 it will be affected by this rule.
22 First of all, I think for one thing,
23 you can consider a conversion from coal to gas
24 as a method of pollution control. Certainly,
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1 the Agency, I believe, considers it that way,
2 and EPA, in their evaluations of controlling
3 various emissions from coal-fired power plants
4 often use it as conversions from coal to gas as
5 a means of a pollution control and they cost it
6 out that way.
7 So I think for one -- in one
8 respect, you can look at it from the standpoint
9 of it is no different than if we were to
10 overcontrol with some postcombustion technology
11 or SCR on another coal-fired unit where we would
12 get our emissions down lower than what the tons
13 would be allocated for that unit and, therefore,
14 create excess emissions. You can simply look at
15 it as a different type of control technology.
16 Secondly, while I would like to say
17 that it might be nice if we were to be getting
18 all kinds of tons associated with this plant
19 because it was a coal-fired plant and we're
20 converting it to gas and that we're going to
21 have lots of excess allowances that we can sell
22 on the market, in fact, that won't be the case
23 in the situation of Grand Tower. Just looking
24 at the numbers that I have as the rule would
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1 play out, Grand Tower would initially get
2 allowances less than 300 tons of allowances in
3 the first year of the program, 2004, and the
4 fixed allowances would drop down to about 150
5 tons less than that in the second phase of the
6 program.
7 That is not all that much -- that is
8 fairly comparable to a new gas-fired unit we get
9 or receive or we need to operate in the same
10 situation. Also, because we're only getting
11 that number of allowances for those units
12 because it was utilized on a very low basis
13 during the baseline period. There wasn't a lot
14 of generation down there. After we repower this
15 unit, it is going to be a cleaner unit. It's
16 going to be a more efficient unit. We expect a
17 capacity factor on that unit will be
18 considerably higher than it was during the
19 baseline.
20 In fact, we will be needing more
21 allowances than we will be getting for that unit
22 to operate that plant after it's converted to
23 gas. So I just didn't want the Board to be left
24 with the impression that we were getting
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1 allowances as a coal-fired unit and going to get
2 a big windfall down at Grand Tower to sell to
3 the state. So I just wanted to clarify that. I
4 appreciate the opportunity.
5 HEARING OFFICER GLENN: Thank you, Mr.
6 Menne. Does anyone have any questions of Mr.
7 Menne's comments? Yes, Mr. Urbaszewski.
8 MR. URBASZEWSKI: I just wanted to follow
9 up. Maybe I just didn't hear you, but you said
10 there's an increase in capacity at that plant?
11 I was wondering what the increase was.
12 MR. MENNE: The capacity factor --
13 HEARING OFFICER GLENN: Could you please
14 answer the question this way? That would be
15 helpful.
16 MR. MENNE: In other words, the
17 utilization that we had that set the baseline
18 for the number of tons that we got on that, the
19 capacity factor of those units was fairly low.
20 I don't have that number offhand, but it might
21 have been 20, 30, or 40 percent. I don't know.
22 After we make this conversion, we
23 intend to have -- the capacity factor will
24 increase. In other words, we will be generating
L.A. REPORTING (312) 419-9292
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1 many more Btus from those units after this
2 conversion takes place.
3 So even though it is -- it is
4 converted to gas which is a cleaner fuel, we
5 will actually be utilizing it much more than we
6 did in the past. So as a result, because the
7 tons allocations are based on a much reduced
8 emission rate, we're actually going to be
9 needing more tons to operate that in the future
10 than we are being allocated.
11 MR. URBASZEWSKI: So, in general, you're
12 saying that it was a coal plant that wasn't
13 utilized all that much and now it's going to be
14 turned into a gas plant -- gas-fired plant that
15 is going to be utilized in a much higher level?
16 MR. MENNE: That's correct.
17 MR. URBASZEWSKI: So in general, the
18 plant is going to be producing a lot more
19 electricity than it did in the past?
20 MR. MENNE: That's correct, but it will
21 be much more efficient.
22 MR. URBASZEWSKI: Thank you. Are there
23 any further questions?
24 MR. MELAS: Mr. Menne, what's the
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1 megawatt production of that Grand Tower plant
2 before and after?
3 MR. MENNE: It was actually rated for
4 around 200 megawatts. I don't have the actual
5 rating on those units. I believe repowering is
6 closer to 500 megawatts.
7 MR. MELAS: As long as -- a thought just
8 ran through my mind a moment ago, not directly
9 on the point, but maybe switching from
10 coal-fired operations to natural gas, you're to
11 achieve this, isn't the source of natural gas
12 finite much more so than coal, obviously? I
13 know that.
14 MR. MENNE: That's very definitely. The
15 industry recently did a study on the prospect of
16 switching a lot of coal-fired plants to natural
17 gas and what that does to gas supply and the
18 cost of gas and things of that nature, and
19 there's some interesting figures in there in
20 terms of potential increases and the cost of
21 gas, the tremendous amount of natural gas
22 infrastructure that would be necessary if you
23 wanted to convert many power plants to gas.
24 I mean, Illinois has an advantage
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1 because you have some major gas lines running
2 through the state. This particular gas line is
3 within a mile of the Grand Tower facility. So
4 it makes it very convenient from that
5 standpoint, but your question is a good one in
6 that it is going to be difficult to supply a lot
7 of different existing coal-fired plants with
8 natural gas, and if the Board would be
9 interested in that study, I would be happy to
10 supply them with that.
11 MS. McFAWN: Would you?
12 MR. MENNE: Yes.
13 MS. McFAWN: That would be great.
14 MR. MELAS: Yeah. I'd like to see it.
15 HEARING OFFICER GLENN: Thank you. Any
16 other questions of Mr. Menne this afternoon?
17 Yes, Mr. Urbaszewski.
18 MR. URBASZEWSKI: I actually have a
19 question of you. If that study is provided to
20 the Board, can the service list also get a copy
21 of it?
22 HEARING OFFICER GLENN: How big is the
23 study?
24 MR. MENNE: It's a pretty thick study.
L.A. REPORTING (312) 419-9292
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1 HEARING OFFICER GLENN: You know what,
2 Mr. Urbaszewski, I think we'll just have a copy
3 available here, and you're welcome to come over
4 and look at it.
5 MR. MENNE: If there's an executive
6 summary or something like that, I'd certainly be
7 happy to do that for the service list.
8 HEARING OFFICER GLENN: If you would give
9 that to the service.
10 MR. MENNE: I'll see what's available.
11 HEARING OFFICER GLENN: We appreciate you
12 trying to accommodate everyone. Thank you.
13 If we do receive that study, by the
14 way, I'll add that to the exhibit list or file
15 it as a public comment. So it will hopefully be
16 indicated on the web site one way or another.
17 Any other questions of Mr. Menne?
18 All right. Thank you very much for your
19 additional comments. Would anyone else this
20 afternoon like to say anything more?
21 MR. RODRIGUEZ: Madam Hearing Officer,
22 Gabe Rodriguez for Dynegy Midwest Generation.
23 As you know, Mr. Diericx submitted comments as
24 public comments for Dynegy Midwest. As I
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1 understand it, the Agency has some questions of
2 him that they wanted to ask. If that's still
3 true, Mr. Diericx is willing to -- he has
4 nothing prepared to present to the Board today
5 other than his written comments, but if there
6 are questions that might be put to him, he's
7 more than willing to answer them.
8 HEARING OFFICER GLENN: We appreciate
9 that, Mr. Rodriguez. For those of you, the
10 public comment Mr. Rodriguez is referring to is
11 available on the table. Ms. Kroack, did you
12 have questions of Mr. Diericx?
13 MS. KROACK: I only had one, and I just
14 wanted to state that we're -- the Agency will
15 respond to Mr. Diericx's public comment in our
16 written comments, that he has alluded to what he
17 calls considerable uncertainty regarding the NOx
18 SIP Call and how that might affect the
19 rulemaking, and we do not agree with the
20 statements in there, but since they go to
21 questions of law, we think they're best
22 addressed in written comments.
23 HEARING OFFICER GLENN: If you do have a
24 question, then we -- could we swear him in
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1 first, please?
2 MS. KROACK: Sure.
3 MR. RODRIGUEZ: Could we place this in
4 the record?
5 HEARING OFFICER GLENN: Oh, his
6 comments. Let's -- we already have them
7 admitted as a public comment, but, what the
8 heck, let's have it as an exhibit, too, for good
9 measure. Our clerk at the Board will be very
10 excited. We're going to admit these comments
11 by, I'm sorry, Mr. Diericx as Exhibit No. 41.
12 (Exhibit No. 41 marked
13 for identification,
14 9-26-00.)
15 MR. DIERICX: By the way, I was sworn in
16 at the last hearing.
17 HEARING OFFICER GLENN: Thank you. We'll
18 have to do it again today anyway.
19 (Witness sworn.)
20 HEARING OFFICER GLENN: Okay. Ms.
21 Kroack, if you --
22 MR. DIERICX: Before answering questions,
23 could I make a couple opening statements?
24 HEARING OFFICER GLENN: Please, by all
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1 means. Go ahead.
2 MR. DIERICX: Again, for the record, my
3 name is Aric Diericx. I'm employed at Dynegy
4 Midwest Generation, Inc. I am the manager of
5 environmental resources for DMG. I have been
6 with DMG and its predecessor company, Illinois
7 Power Company, for the past 21 years, and my
8 entire career there has been involved with the
9 environmental issues, primarily air quality
10 management issues.
11 I'm not going to read the written
12 comments we submitted. I'll just briefly touch
13 upon them to give a flavor for the Board here.
14 The first comments were in response to a
15 question, I believe, the Board asked at the last
16 hearing about what other ongoing litigation was
17 out there that might affect the Subpart W rules
18 that are being proposed here by the Agency, and
19 the first part of our comments were our opinion
20 of what those key issues were and how they may
21 eventually affect the Subpart W rules whenever
22 the litigation is finalized.
23 Again, it was just opinions.
24 There's multiple legal points in these cases
L.A. REPORTING (312) 419-9292
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1 that are being discussed. This is just examples
2 of what is going on and what could result from
3 that litigation. We also submitted additional
4 comments supporting the Agency's fixed/flex
5 approach to the allocations. We thought it was
6 a very innovative approach the Agency has taken
7 to address the needs of both the new and
8 existing EGUs in Illinois, and we offer that
9 support not only as a company with existing
10 EGUs, but also as a company with several new EGU
11 units in the state. This support is given even
12 though the greatest economic burden is placed on
13 the existing EGUs in the state. Our projected
14 compliance costs, similar to Ameren, I think,
15 we're projecting capital compliance costs in
16 excess of $100,000,000 to comply with the
17 Subpart W SIP Call rules, and of that
18 $100,000,000, all of that is earmarked for our
19 existing EGU sources. We do not reject any
20 additional capital is going to be expended upon
21 our new EGUs sources for the purposes of the SIP
22 Call rule, and the reason for that is because
23 new EGUs for us and possibly other new EGU
24 sources in the state have made their
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1 expenditures for NOx controls due to the best
2 available control technology requirements of the
3 PSD program and also the new source performance
4 standards that apply to those new EGUs.
5 So for that reason, we are
6 projecting all of our NOx compliance costs for
7 the existing EGUs and none for our new EGUs,
8 and, again, that trend may be similar for other
9 units in the state. We also support in our
10 comments the heat input based allocation scheme
11 in the Agency rules. This is consistent with
12 the federal EPA Acid Rain program. It's one
13 sources and regulators have dealt with for many
14 years and it's effective, and we think that
15 should continue.
16 We submitted some comments also on
17 the growth factor that several other people
18 identified in their testimony. The growth
19 factor we feel is driven by the economics within
20 the state and the weather conditions from season
21 to season. In our testimony, we identified that
22 actual 1998 heat input was approximately ten
23 percent higher than the 2007 projected heat
24 input from the USEPA IPM model, and if, in fact,
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1 the heat input projections for EGUs in Illinois
2 is low in 2007, then also the percent NOx
3 reductions that need to be made by the existing
4 EGUs is also being underestimated, and if those
5 control -- amounts of controls are
6 underestimated, the control costs are going to
7 be greater than what's indicated in the record.
8 I feel this is important because of
9 the Board's inquiry at the last hearing about
10 how the cost of controls on EGUs compared to the
11 cost of other ozone season controls from other
12 programs that are currently in Illinois.
13 Finally, we offered some comments also about the
14 early reduction credit program. We are
15 supportive of the Agency's proposal to award
16 early reduction credits for the 2001/2002
17 control seasons and the rest of the early year
18 reduction credits awarded in 2003 if that
19 flexibility is, in fact, provided by the SIP
20 Call rules.
21 HEARING OFFICER GLENN: Thank you.
22 Ms. Kroack, why don't you proceed with your
23 question, and then we'll open it up to anyone
24 else that may have a question on those
L.A. REPORTING (312) 419-9292
237
1 comments?
2 MS. KROACK: Sure. Mr. Diericx, you
3 stated that USEPA severely underestimated the
4 growth rate for EGUs in calculating the base
5 2007 budget, and you went on to give the 1998
6 seasonal heat input for the existing EGUs
7 450,495,863 million Btus, and that the 2007 base
8 budget for these same units was 411,298,433
9 Btus.
10 Do you know what the heat input for
11 these units was in 1999?
12 MR. DIERICX: For these exact units, no,
13 I do not.
14 MS. KROACK: Would it surprise you to
15 learn it was 418,258,674 million Btus?
16 MR. DIERICX: That number sounds like a
17 number less than the 1998 ozone season heat
18 input, but a number still greater than the 2007
19 projected heat input.
20 MS. KROACK: Correct. But it's a
21 downward adjustment from the 1998 figure.
22 MR. DIERICX: And I think I indicated in
23 my opening comments that that number will vary
24 year to year based on economic conditions and
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1 whether that drives the heat input for the
2 state.
3 MS. KROACK: That was our comment. Thank
4 you.
5 HEARING OFFICER GLENN: Thank you, Ms.
6 Kroack. Does anyone else have any questions of
7 Mr. Diericx?
8 BOARD MEMBER FLEMAL: We have over our
9 three days together heard many times a
10 suggestion that the eight percent growth factor
11 is substantially underestimated of what is and
12 can be anticipated to happen in Illinois.
13 What I'm not sure I've heard anybody
14 say, and I offer you the opportunity to give me
15 an answer, is what do we do about that?
16 MR. DIERICX: I do not have a
17 recommendation on how to adjust that. There is,
18 I think we mentioned at the last hearing,
19 ongoing litigation. I think it's short-handed.
20 The litigation gets the technical amendments,
21 SIP Call. That might provide some relief for
22 that. We won't know that for several months
23 until that case is decided.
24 I think the point of my comments was
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1 that if the growth number is underestimated, the
2 control costs for the existing EGUs will be
3 greater, and just to properly reflect that fact
4 in the record when the Board compares these
5 costs to other ozone control programs.
6 MR. MILLER: Just to give you an example,
7 Indiana has the same small fossil capacity as
8 Illinois. There is 47,000.
9 HEARING OFFICER GLENN: 47,000 tons?
10 MR. MILLER: Yes.
11 HEARING OFFICER GLENN: Would anyone else
12 like to ask a question of Mr. Diericx? Okay.
13 Thank you very much. We appreciate your time.
14 Would anyone else present this
15 afternoon like to say anything further? This is
16 sort of a going once, going twice since we will
17 not be having our third hearing.
18 Okay. If you'll bear with me for
19 just a moment then. I just want to reiterate
20 that we will not be having the third hearing
21 scheduled for October 10th. I will put out and
22 send to all of you on the notice and service
23 lists a hearing officer order explaining the
24 precise deadlines for public comment, but as it
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1 stands right now, we anticipate public comments
2 will be due by Friday, October 13th, at 4:30 in
3 the Board's Chicago office.
4 Please keep in mind if you file a
5 public comment, you are obligated to file an
6 original and nine copies with the Board as well
7 as serve copies of public comments on the
8 members of the service list. Our transcript of
9 today's proceeding will hopefully be posted on
10 our Board's web site next Tuesday, October 3rd.
11 The Board's web site is
12 www.ipcb.state.il.us. You want to go to the
13 rules and regulations section and then click on
14 the transcript for Docket R01-9. Are there any
15 other matters that need to be addressed at this
16 time? Ms. Kroack, do you have anything to add?
17 MS. KROACK: No. Thank you.
18 HEARING OFFICER GLENN: Well, then on
19 behalf of the Pollution Control Board, I would
20 sincerely like to thank all of you present here
21 today that have contributed so greatly to the
22 development of this rule, and we look forward to
23 tackling everything you have given us now to put
24 something together for our November 16th Board
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1 meeting.
2 Again, thank you to the Agency for
3 all of your time and for all of you making the
4 trip up from Springfield today, and thank you
5 members of the regulated community for your much
6 appreciated attention to this matter and the
7 environmental community as well. Thank you.
8 Have a nice afternoon.
9 (Whereupon, these were all
10 the proceedings held in the
11 above-entitled matter.)
12
13
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L.A. REPORTING (312) 419-9292
242
1 STATE OF ILLINOIS )
) SS.
2 COUNTY OF C O O K )
3
4 I, GEANNA M. IAQUINTA, CSR, do
5 hereby state that I am a court reporter doing
6 business in the City of Chicago, County of Cook,
7 and State of Illinois; that I reported by means
8 of machine shorthand the proceedings held in the
9 foregoing cause, and that the foregoing is a
10 true and correct transcript of my shorthand
11 notes so taken as aforesaid.
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______________________________
14 Geanna M. Iaquinta, CSR
Notary Public, Cook County, IL
15 Illinois License No. 084-004096
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17 SUBSCRIBED AND SWORN TO
before me this_____day
18 of_______, A.D., 2000.
19 _______________________
Notary Public
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L.A. REPORTING (312) 419-9292