1 BEFORE THE ILLINOIS POLLUTION CONTROL BOARD
2
3
4 IN THE MATTER OF:
5
6 PROPOSED NEW 35 ILL. ADM. CODE 217,
7 SUBPART W, THE NOx TRADING PROGRAM R01-9
8 FOR ELECTRICAL GENERATING UNITS, (Rulemaking-Air)
9 AND AMENDMENTS TO 35 ILL. ADM. CODE
10 211 AND 217
11
12
13 Proceedings held on August 29, 2000, at 9:00 a.m., at City
14 Hall Chambers, Municipal Center West, 300 South Seventh Street,
15 Springfield, Illinois, before Catherine F. Glenn, Hearing
16 Officer.
17
18
19 VOLUME II
20
21 Reported by: Darlene M. Niemeyer, CSR, RPR
CSR License No.: 084-003677
22
23 KEEFE REPORTING COMPANY
11 North 44th Street
24 Belleville, IL 62226
(618) 277-0190
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1 A P P E A R A N C E S
2
3 Members of the Board present:
4
Board Member Ronald C. Flemal, Ph.D.
5 Board Member Elena Kezelis
Board Member G. Tanner Girard, Ph.D.
6 Board Member Marili McFawn
Board Member Nicholas J. Melas
7 Anand Rao, Senior Environmental Scientist
8
9
ILLINOIS ENVIRONMENTAL PROTECTION AGENCY
10 BY: Ms. Laurel Kroack
Assistant Counsel
11 Division of Legal Counsel
1021 North Grand Avenue East
12 Springfield, Illinois 62794-9276
On behalf of the Illinois EPA.
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1 I N D E X
2 QUESTIONER PAGE NUMBER
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4 RICK DIERICX 143
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WILLIAM MURRAY 150, 227
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7 CYNTHIA FAUR 167
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JOE McGERVEY 171, 225
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10 DAVID RIESER 180
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DANIEL GOODWIN 190
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13 BRIAN URBASZEWSKI 216
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BOARD MEMBERS 232
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16 LAUREL KROACK 264
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1 P R O C E E D I N G S
2 (August 29, 2000; 9:00 a.m.)
3 HEARING OFFICER GLENN: Good morning. Welcome back to our
4 second day of the hearings In the Matter of: Proposed New 35
5 Illinois Administrative Code 217, Subpart W, the NOx Trading
6 Program for Electrical Generating Units and Amendments to 35
7 Illinois Administrative Code 211 and 217.
8 My name is Cathy Glenn. I am the Hearing Officer in this
9 proceeding. I would like to introduce the Board Members that are
10 present here with us this morning. Seated to my left is the
11 Board Member coordinating the rulemaking, Dr. Ronald Flemal.
12 Seated next to Dr. Flemal is Board Member Nicholas Melas. Seated
13 next to Member Melas is Anand Rao from our technical unit.
14 Seated to my right is Dr. Tanner Girard.
15 BOARD MEMBER GIRARD: Good morning.
16 HEARING OFFICER GLENN: Next to Dr. Girard is Marili
17 McFawn.
18 BOARD MEMBER McFAWN: Hello.
19 HEARING OFFICER GLENN: Next to Marili McFawn is Board
20 Member Elena Kezelis.
21 BOARD MEMBER KEZELIS: Good morning.
22 HEARING OFFICER GLENN: We will just take care of a few
23 housekeeping matters and then plunge right in this morning.
24 First I would like to bring to your attention that on the table
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1 over there in front of the Agency is a letter to the Department
2 of Commerce and Community Affairs that the Board Chairman, Claire
3 Manning, sent to DCCA and requested that an Economic Impact Study
4 be done in this matter.
5 The second hearing that we will be having in this matter,
6 which will be on September 26th, will be for the purpose of
7 discussing any Economic Impact Study that is made available by
8 DCCA. However, it would appear that DCCA is not doing an
9 Economic Impact Study because they have not responded to the
10 letter, and the letter says if DCCA does not get back to the
11 Board by a certain date we will assume that they don't intend to
12 do a study.
13 However, the second hearing will also be devoted to
14 interested parties that want to testify in front of the Board
15 regarding their concerns in this matter. To clarify, there will
16 be members of the Agency present at that second hearing.
17 However, the purpose of the second hearing is not to ask the
18 Agency more questions at that point. To the extent the time
19 allows and to the extent that the Agency has people available at
20 the second hearing that can answer your questions, they will be
21 willing to do so.
22 However, we would ask that anybody that knows they want to
23 ask any questions in advance to please prefile those questions in
24 the form of prefiled testimony, which is due to the Board no
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1 later than 4:30 in the afternoon on September 15th, 2000. Again,
2 just because you file those questions does not mean the Agency
3 will have answers for you at the second hearing, but they will do
4 their best to address your concerns.
5 With that, I think where we left off yesterday was we had
6 already taken testimony from the Agency witnesses and we had
7 begun the questioning process.
8 If any members of the public here today would like to
9 begin, please raise your hand and I will recognize you and then
10 please step to the podium, state your name, who you represent,
11 and feel free to ask your questions. The Board will interject
12 with questions also as is appropriate.
13 Who would like to start? Yes, please. I am sorry. Before
14 you begin, are there any questions about what the procedure is
15 here today?
16 Okay. Please begin. Please state your name for the
17 record.
18 MR. DIERICX: Thank you. My name is Rick Diericx. I am
19 the Manager of Environmental Resources for Dynegy Midwest
20 Generation. For those of you not familiar, those would be the
21 plants formerly associated with Illinois Power Company.
22 I would like to start out by first agreeing with an
23 observation that I think Mr. Lawler made several years ago, one
24 where he identified that 90 percent of rulemakings such as this
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1 is spent on ten percent of the issues. I think that's kind of
2 where we are today. We have no major comments on probably 90
3 percent of the allocation and reallocation methodology set forth
4 by the Agency in this rulemaking, but I would like to ask a few
5 questions to the Agency in an attempt to try to get them to
6 reconsider how the final ten percent of the allocations,
7 specifically those in the Compliance Supplement Pool would be
8 allocated.
9 As a follow-up to Mr. Rodriguez's questions that he had
10 yesterday, my first questions deal with Section 217.770 (e).
11 Yesterday the Agency stated first that the early NOx reductions
12 would be beneficial to ozone levels, and that the Agency wanted
13 to use the Compliance Supplement Pool as an incentive to reward
14 sources that make early NOx reductions. In order to make early
15 NOx reductions the source will need to expend capital, incur
16 carrying costs for that capital, and in the case of SCRs, SNCRs,
17 gas reburning and some other NOx control technologies, sources
18 will need to expend operating costs to make the NOx controls
19 actually function.
20 If the Board adopts the rule with a moving target, such as
21 the potentially variable dates of the qualifying ozone season
22 reductions for early reduction credits, doesn't that enhance the
23 risk that the source may not qualify for early reduction credits
24 in 2001.
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1 MS. BASSI: Would you repeat your question without all of
2 the preliminary, just the question itself?
3 MR. DIERICX: All right. If the Board adopts the rule with
4 variable dates for the qualifying early reduction credits,
5 doesn't that create and enhance the risk that sources that make
6 reductions in 2001 will not see any qualifying early reduction
7 credits for those reductions?
8 MS. BASSI: Yes, I would agree with that, that that is
9 possible. But as you pointed out earlier, the environment still
10 sees the benefit.
11 MR. DIERICX: That's true. But if a source feels that
12 there is a greater risk of not qualifying for early reduction
13 credits, wouldn't that eliminate part of the incentive for them
14 to make those early reduction credits, those early reductions?
15 MS. BASSI: I don't know. That is something that the
16 companies will have to answer.
17 MR. DIERICX: Okay. If the early reduction credits were
18 not awarded for NOx reductions during the 2001 and 2002 control
19 periods but instead for the 2002 and 2003 control periods,
20 wouldn't the Agency expect more sources to have installed NOx
21 controls and more persons applying for the early reduction
22 credits?
23 MS. BASSI: I think that is possible because of the longer
24 lead time to plan for and install the early reduction credits.
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1 At the same time, if a company has planned for and installed the
2 early reduction mechanisms, you know, whatever it is going to be
3 for 2001 and 2002, I would also expect those to still be in place
4 in 2003 and 2004. And so --
5 MR. DIERICX: Yes.
6 MS. BASSI: And so I think there is probably a greater
7 benefit in that sense. The greatest benefit would be if the
8 program does not slide.
9 MR. DIERICX: Yes. But I think you agree that there would
10 be more people -- with the later dates there would be more people
11 potentially applying for those early reduction credits as they
12 have more time to install NOx controls?
13 MS. BASSI: Probably.
14 MR. DIERICX: Okay. So if there were more people applying
15 for early reduction credits, such that the pool was now
16 oversubscribed, wouldn't the early reduction credits be awarded
17 on a pro rata basis, that is, less than a one-for-one basis?
18 MS. BASSI: Yes.
19 MR. DIERICX: Okay. If only a fraction of an early
20 reduction credit is awarded for each early ton of NOx reduction,
21 wouldn't that also provide less incentive for sources to make
22 those early NOx reductions than a one-for-one award of NOx --
23 MS. BASSI: I really don't know. Again, this is something
24 I think the companies would have to answer. You are asking about
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1 motivation. I guess from my perspective, if we have to issue --
2 if we issue these allowances on a pro rata basis and so that the
3 companies are getting less than one-for-one, then, again, the
4 environment benefits, because the reduction is there. But,
5 unfortunately, there are not enough allowances to go around.
6 MR. DIERICX: I think my questions are -- I am trying to
7 focus on the question of how to create the best incentive to get
8 those reductions and get them as early as possible.
9 Another question, though, is if the early reduction credits
10 were deferred for some reason until the 2002, 2003 control
11 seasons, wouldn't all of the early reduction credits now need to
12 be used by the sources in the following one control season rather
13 than the following two control seasons?
14 MS. BASSI: I don't know. The model rule does not provide
15 for an extension of time for implementation as it is right now.
16 And, really, in order to specifically or surely answer your
17 question, there would have to be -- the USEPA would have to amend
18 the model rule. The way the model rule reads right now I think
19 the answer to your question is yes. If the program were delayed
20 because of various things that could happen or if the program
21 were overturned, then I think there would have to be a federal
22 rulemaking.
23 MR. DIERICX: Okay. I guess my final question at this
24 point is doesn't this even more limited shelf life, if they don't
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1 amend the rules, the model trading rule, if it is only -- you
2 have to use early reduction credits now in 2003 and 2004, but if
3 it is delayed and you don't get them until the 2002 and 2003
4 season, and you have to use them all in 2004, doesn't this even
5 more limited shelf life of early reduction credits again seem to
6 remove some of the incentives for the early reductions?
7 MS. BASSI: I don't know. I would -- again, that is a
8 planning tool. Because you are right, they cannot be -- they
9 would be retired at the end of 2004. They are tradeable,
10 however.
11 MR. DIERICX: But even --
12 MS. BASSI: You certainly have to do something with them in
13 a hurry.
14 MR. DIERICX: Yes. Even if you traded them, though, the
15 person you traded them to would have to use begin using them in
16 2004?
17 MS. BASSI: That is correct.
18 MR. DIERICX: With that limited shelf life?
19 MS. BASSI: Yes.
20 MR. DIERICX: One of the reasons USEPA created the
21 Compliance Supplement Pool was the potential inability of the
22 Electrical Generating Units to install the required NOx controls
23 in a timely manner and maintain a reliable supply of electricity
24 to its customers. This issue was highlighted several times in
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1 the case before the DC Circuit Court and has been raised by the
2 Illinois EGUs in the preproposal stage of this rulemaking. In
3 its proposal to the Board at Section 217.770 (f) the Agency has
4 reserved only a portion of the Compliance Supplement Pool for the
5 EGU sector.
6 I guess my question is has any other industry expressed a
7 concern with its ability to install the required NOx controls and
8 continue to provide an essential product or service to the
9 public?
10 MS. BASSI: To date no industry has expressed that concern.
11 However, we are not completed with our development of the other
12 side of this rule for the non EGUs. There was -- the reason --
13 one of the reasons why we -- as I said yesterday, one of the
14 reasons why we stated it in Section 770 as we did, that at least
15 this number of allowances was preserved for the EGUs is because
16 we had not yet completed that other development of a rulemaking.
17 In the model rule the USEPA does not distinguish between who the
18 Compliance Supplement Pool is available to, at least the way I
19 have read it. And that is why we felt that it was appropriate to
20 preserve a specific number specifically for EGUs, leaving the
21 other number ultimately available if it is not used.
22 MR. DIERICX: Okay. Thank you. That concludes my
23 questions at this time.
24 HEARING OFFICER GLENN: Thank you, Mr. Diericx. Does
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1 anyone else have questions this morning?
2 Yes, please, Mr. Murray.
3 MR. MURRAY: Good morning. My name is William Murray. I
4 am the Regulatory Affairs Manager for the Office of Public
5 Utilities of the City of Springfield. We are more commonly known
6 as City, Water, Light & Power locally. I would like to probably
7 cover some subjects that were lost upon yesterday and maybe we
8 can see if we can get a little further.
9 Mr. Kaleel, it is my understanding from your testimony that
10 you have been involved in the modeling efforts that the Illinois
11 EPA has undertaken?
12 MR. KALEEL: That's right.
13 MR. MURRAY: And you also have been involved in the
14 modeling efforts at LADCO?
15 MR. KALEEL: Yes, I have.
16 MR. MURRAY: And I believe it was also your testimony
17 yesterday that you also participated in the modeling efforts of
18 the ozone transfer assessment?
19 MR. KALEEL: Yes.
20 MR. MURRAY: Okay. And, again, you have been involved in
21 the modeling efforts that have been undertaken in -- I guess it
22 would be referred to as the subregional modeling since the OTAG
23 process has been completed?
24 MR. KALEEL: That's correct.
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1 MR. MURRAY: Can you tell me whether you have also been
2 involved in a modeling group called the Ad Hoc Modeling Group
3 since OTAG?
4 MR. KALEEL: Actually, I am a part of that committee, yes.
5 MR. MURRAY: Could you explain for the Board and the
6 members of the audience what the Ad Hoc Modeling Group is?
7 MR. KALEEL: The Ad Hoc Modeling Group is I guess a
8 committee that was established kind of at the initiative of Mr.
9 Michael Curber (spelled phonetically) who is the Director of the
10 Lake Michigan Air Directors Consortium and another person that is
11 a modeler on the staff the Tennessee Valley Authority, Mr. Larry
12 Gotney (spelled phonetically). I think it was the recognition of
13 both of those gentlemen that since the OTAG process was completed
14 that there was perhaps an insufficient communication amongst the
15 modeling community as to what comes after OTAG and what kind of
16 coordination should happen amongst the various parties preparing
17 attainment demonstrations and further modeling after OTAG was
18 concluded. So they had established this Ad Hoc Modeling
19 Committee, invited industry representatives, consultants, some
20 state representatives, and the USEPA to attend these meetings and
21 to share information.
22 MR. MURRAY: It is my understanding -- about how often does
23 that group meet?
24 MR. KALEEL: We meet generally about once a quarter and
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1 have conference calls perhaps a little bit more frequently.
2 MR. MURRAY: And at these quarterly meetings it is my
3 understanding that the different modeling efforts that are going
4 on are demonstrated and critiqued and analyzed, or the results of
5 them are given out?
6 MR. KALEEL: Not in a real great detail. Each of the
7 members of relays I guess or reports to the other members on
8 topics of interest to them or difficulties or issues that each of
9 them are facing as they try to complete their modeling studies.
10 MR. MURRAY: Would it be fair to say that you probably have
11 seen most of the information on most of the modeling efforts that
12 have been ongoing on this issue of ozone transport?
13 MR. KALEEL: I think I am familiar at least a little bit
14 with some of the efforts going on in other parts of the country,
15 yes.
16 MR. MURRAY: In your testimony, which was submitted as
17 Exhibit Number 23, on the bottom of page two and the top of page
18 three you address some findings about USEPA reducing NOx
19 emissions. In my reading of your testimony I did not see any
20 conclusions regarding attainment; is that correct?
21 MR. KALEEL: I am still trying to find the specific part of
22 the testimony that you are -- I think in this part of the
23 testimony all I was referring to was that USEPA did issue the NOx
24 SIP Call and there are some findings from the OTAG process and
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1 the NOx SIP Call using that to establish the basis of some of the
2 modeling that we have been involved with since that time.
3 MR. MURRAY: Based upon all of the modeling efforts that
4 you have been involved with and have seen the work of others, can
5 you tell me whether there is any conclusion that can be given
6 with regard to attainment in the northeast part of the United
7 States as a result of the NOx SIP Call?
8 MR. KALEEL: I am certainly not an expert on the modeling
9 that is going on in the northeast. My understanding is that
10 northeast, the eastern states for the most part are still having
11 difficulty demonstrating attainment even with the NOx SIP Call
12 controls built in. There are probably additional measures that
13 would be required in the northeast.
14 MR. MURRAY: Okay. Going again to your testimony, Exhibit
15 Number 23, I assume that Figures 4 and 7 of the prefiled
16 testimony was part of that submitted exhibit?
17 MR. KALEEL: Could you repeat the question?
18 MR. MURRAY: In the prefiled testimony you had an exhibit
19 entitled Figure 4 and Figure 7.
20 MR. KALEEL: Yes.
21 MR. MURRAY: And is that part of Exhibit Number 23?
22 MR. KALEEL: I guess I would refer to our attorneys or to
23 the Board. I don't --
24 HEARING OFFICER GLENN: I have marked here Exhibit Number
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1 23 and, indeed, Figures 4 and 7 are part of that submission.
2 MR. KALEEL: Thank you.
3 MR. MURRAY: I just wanted it clear so the record reflected
4 the right figures.
5 MR. KALEEL: Sure, sure.
6 MR. MURRAY: With regard to Figure 4, I believe you
7 testified yesterday on the slide that that represented the NOx
8 tonnage reduction based on various control efforts; is that
9 correct?
10 MR. KALEEL: Yes.
11 MR. MURRAY: And that showed a fairly steep decline which
12 you testified yesterday that we continued to see that decline
13 with the NOx SIP Call?
14 MR. KALEEL: Yes.
15 MR. MURRAY: And pretty much on the same slope, would you
16 agree?
17 MR. KALEEL: I guess I am not sure about the slope, but I
18 agree that the NOx SIP Call would provide further NOx reductions.
19 MR. MURRAY: With regard to Figure Number 7, it is my
20 understanding that this figure represents the results of the
21 modeling effort with regard to ozone concentrations; is that
22 correct?
23 MR. KALEEL: Yes.
24 MR. MURRAY: And that would be ozone concentrations in the
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1 nonattainment area rather than at the boundary line?
2 MR. KALEEL: This particular figure, Figure 7, reflects the
3 -- what we would expect to be the adjusted design value at the
4 monitor, the highest monitor in the Lake Michigan region. So
5 this does not represent boundary condition ozone. This
6 represents the ozone expected at the highest monitor in the
7 region, yes.
8 MR. MURRAY: And would it be fair to say that looking at
9 that depiction it appears that the ozone levels are leveling off
10 as controls become more strict?
11 MR. KALEEL: I think the way I would interpret that is that
12 to some extent the response of the model or the model is
13 responding to the amount of emissions that are I guess removed or
14 reduced in between or relative to each of those different
15 scenarios.
16 MR. MURRAY: I guess would it be fair to say that the slope
17 for the ozone reductions is a lot less severe than the slope of
18 the NOx tonnage reductions on a comparison basis?
19 MR. KALEEL: I guess I don't know about your reference to
20 the slope.
21 MR. MURRAY: Figure 4 versus Figure 7.
22 MR. KALEEL: I mean, an awful lot of that depends on the
23 scale that we use for computing these charts. I have not
24 actually computed a slope in any kind of technical way. I think
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1 I would agree that the responses are not one-for-one. The model
2 does not respond in a linear way or a one-to-one way to emission
3 changes. It is a much more complex system than that.
4 MR. MURRAY: Based on all of the modeling efforts you have
5 been involved with and have seen with your involvement with the
6 Ad Hoc Modeling Group, would you say that this is a fairly common
7 effect in different modeling results that we are seeing, the
8 relationship that you just described between NOx tonnage
9 reductions and the ozone reductions in a nonattainment area?
10 MR. KALEEL: I think that these results are typical of the
11 kinds of results that we would see in other parts of the country.
12 MR. MURRAY: In your testimony on page seven, regarding the
13 difference between 0.25 pounds per million btu control strategy
14 and NOx SIP Call control strategy, I believe your testimony
15 indicates that you found an additional limited air benefit in the
16 two control strategies in the amount of one-to-three parts per
17 billion?
18 MR. KALEEL: That's right.
19 MR. MURRAY: Based on this conclusion and your other
20 involvement in the other modeling groups, can you tell whether
21 this is also a consistent result between the two different
22 control strategies?
23 MR. KALEEL: I think what is obvious from the Figure 7 and
24 what I tried to characterize is that a great deal of the benefit
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1 that we are achieving, and maybe this is where you are headed,
2 but a great deal of the benefit that we would be achieving
3 locally and regionally comes from the NOx reduction level tested
4 at the 0.25 pounds per million btu scenario. There are further
5 benefits to the NOx SIP Call in relation to the amount of NOx
6 tonnage that we are removing out of the model that we would
7 expect to see in the environment.
8 So there is certainly a great deal of improvement looking,
9 again, at Figure 7 between the 1996 base case and the Clean Air
10 Act controls. As I have testified yesterday, the Clean Air Act
11 measures are a combination of -- or the effect that we are seeing
12 is a combination of both local controls, typically VOC controls,
13 and some regional controls, primarily regional controls presented
14 by the Clean Air Act, the Title 4 or the Acid Rain controls as
15 they relate to NOx emissions. The 0.25 scenario is a further
16 reduction of NOx emissions in the amount of about 2,400 tons, I
17 believe, was the number in my testimony on page six relative to
18 the Clean Air Act control. And we are seeing a large response to
19 that control scenario.
20 The NOx SIP Call does not remove quite as much NOx, and
21 there are no local VOC controls associated with that particular
22 scenario. And because of the less NOx tonnage and the fact that
23 there are no VOC controls you see a lesser model response.
24 MR. MURRAY: Thank you.
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1 MR. KALEEL: Okay.
2 MR. MURRAY: Mr. Lawler, in your testimony and I believe
3 also in Mr. Forbes' testimony there is a variety of references to
4 the concept called -- referred to as highly cost-effective
5 measure or highly cost-effective control measure. Could you
6 define what you mean by highly cost-effective measure?
7 MR. LAWLER: I think the way that I was referring to it in
8 the testimony is USEPA essentially defined the control measures
9 that we talked about yesterday as highly cost-effective and part
10 of the OTAG process and the follow-up work that they did to the
11 OTAG process, they use the term highly cost-effective for
12 controls on these particular sources to the levels that they
13 proposed.
14 MR. MURRAY: Okay. So I can conclude, based on your
15 testimony and Mr. Forbes' testimony yesterday and what was filed
16 that highly cost-effective control measure would be something
17 that would be in the range of $1,460.00 to $1,488.00 a ton of
18 NOx removed?
19 MR. LAWLER: No.
20 MR. MURRAY: I mean, if Mr. Forbes can answer that, that is
21 fine.
22 MR. LAWLER: Well, let me add a little bit before Mr.
23 Forbes does. We need to put things into perspective a little
24 bit, that at this point the VOC controls that we have been
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1 proposing for the nonattainment areas up to this point were well
2 over the amount that you had just mentioned. They are in the
3 ballpark sometimes as high as $10,000.00 a ton for the VOC
4 controls. So in the USEPA's statements this has been taken into
5 account, and I think probably what Dick is going to also add to
6 this is that you have to kind of look at a broader picture rather
7 than just this particular set of numbers. And the numbers
8 themselves to maybe the nearest dollar are not important as much
9 as the magnitude. This magnitude of cost that you are mentioning
10 is generally consistent with what the highly cost-effective
11 numbers that EPA has come up with.
12 MR. MURRAY: All right. Would there be a point when
13 something didn't become highly cost-effective or no longer was
14 highly cost-effective?
15 MR. LAWLER: I couldn't give you a number on that.
16 MR. MURRAY: In terms of -- you mention the VOC reductions.
17 It is my understanding that was in the nonattainment area and
18 that is not a regional program?
19 MR. LAWLER: That's correct. That was in the nonattainment
20 area.
21 MR. MURRAY: I think Mr. Forbes, we had some testimony or
22 questions yesterday about the IPM growth factors for Illinois. I
23 believe the growth factor is eight percent and referred to as
24 1.08 when it is used in the formula?
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1 MR. FORBES: That's correct.
2 MR. MURRAY: In the budget for EGUs the baseline is 1996,
3 is that correct, for heat input?
4 MR. FORBES: Right, the base year that EPA used in SIP Call
5 was 1996 for EGUs.
6 MR. MURRAY: You testified yesterday that the Illinois EPA
7 did submit comments to the USEPA regarding the growth factor?
8 MR. FORBES: We did.
9 MR. MURRAY: Okay. Can you tell me whether or not those
10 comments addressed what growth had occurred in Illinois in terms
11 of heat input for electric generation at the time the comments
12 were made?
13 MR. FORBES: I believe that the comments that we made were
14 based on information we received from the existing utilities. We
15 asked them to provide information to assist us to what
16 historically had occurred in the way of growth for utilities and
17 what their expectations were for their own individual units in
18 order that we could make a reasonable comment to the EPA about
19 what the growth should be -- how growth should be represented in
20 the estimates.
21 MR. MURRAY: Do you recall what that estimate was?
22 MR. FORBES: I believe it was 34 percent.
23 MR. MURRAY: Okay. It was 34 percent. That was four and a
24 half times what the growth factor assigned for Illinois in the
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1 budget was?
2 MR. FORBES: That's correct.
3 MR. MURRAY: Can you tell me whether or not you are aware
4 as to whether Illinois utilities have exceeded that eight percent
5 growth factor at this point in time?
6 MR. FORBES: I believe that question was asked yesterday
7 and my response at that point is we will have to go back and look
8 at -- I don't have the information available to answer you today.
9 MR. MURRAY: Okay.
10 MR. FORBES: I would -- you know, I would probably say that
11 eight percent would -- that it is likely eight percent is
12 exceeded, but I will have to verify that.
13 MR. MURRAY: Okay. Well, if we could, then, perhaps assume
14 that it has been exceeded.
15 MR. FORBES: (Nodded head up and down.)
16 MR. MURRAY: How does this relate to the Illinois budget
17 for EGUs?
18 MR. FORBES: Well, obviously, the numbers -- if we have
19 exceeded the eight percent then we would have exceeded the
20 budget, because the budget was based on eight percent growth.
21 MR. MURRAY: So I -- so would it be fair to say we have
22 already seen 2007 if that was true?
23 MR. FORBES: Yes.
24 MR. MURRAY: With regard to the emission rate that the NOx
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1 budget is based on, I believe that is 0.15 --
2 MR. FORBES: That's correct.
3 MR. MURRAY: -- pounds per million btu?
4 MR. FORBES: That's correct.
5 MR. MURRAY: Would you have an opinion, if the growth rate
6 was 34 percent by the year 2007, how that would translate to an
7 emission rate for these EGUs in the year 2007, based upon what
8 the budget is.
9 MR. FORBES: Well, obviously, it would have to be less than
10 0.15 in order to meet the budget. I think the other thing I
11 should mention, however, is in USEPA's running on the actual
12 model it is a very complicated, complex economic forecast model.
13 It is also based on what activity is going on within 23 states.
14 And it was expected that a substantial amount of trading would go
15 on.
16 So I think EPA did expect that some of the actual emissions
17 in 2007 at the compliance rate would potentially be exceeded in
18 different states, but that the reductions would be available
19 throughout the full 23 state jurisdiction to be able to comply.
20 In other words, they were assuming substantial trading to occur
21 that in all would allow the NOx SIP Call jurisdictions to meet
22 the total NOx budget.
23 MR. MURRAY: Your testimony also makes reference to the
24 availability of purchasing extra allowances as a compliance
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1 strategy.
2 MR. FORBES: Yes.
3 MR. MURRAY: Has any of the material that has been
4 submitted with the filing for Subpart W contain an estimate of
5 what the price of such an allowance would cost?
6 MR. FORBES: I don't believe so.
7 MR. MURRAY: Okay. Are you independently aware of what the
8 current market price for the year a 2003 vintage allowance is?
9 MR. FORBES: No, I am not.
10 MR. MURRAY: On pages five and six of your testimony, you
11 discuss the various categories of affected boilers. I believe we
12 are referring to Appendix F units there. Could you tell the
13 Board how many of those affected units are coal-fired boilers?
14 MR. FORBES: I believe 64.
15 MR. MURRAY: That is out of a total of 103 affected?
16 MR. FORBES: That's correct.
17 MR. MURRAY: Those, again, are units that were in existence
18 prior to 1995?
19 MR. FORBES: That's correct.
20 MR. MURRAY: Has Illinois EPA or any other state agency
21 conducted any study on the feasibility of retro fitting all 103
22 of these emission units by May 1 of 2003?
23 MR. FORBES: Could you clarify what kind of study that you
24 are -
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1 MR. MURRAY: A feasibility of that time line being met by
2 all units?
3 MR. FORBES: All 103?
4 MR. MURRAY: Yes.
5 MR. FORBES: I don't believe that we have conducted such a
6 study, but I believe the EPA in its evaluation of the NOx SIP
7 Call did look at the time frames that would be required for all
8 of the units within the SIP Call domain to comply. And my
9 understanding is that their conclusion was that it would not be
10 feasible. Again, considering the basis for the NOx SIP Call is
11 that trading would exist, that not all units would need to have a
12 full retrofit, that many units would be able to make marginal
13 reductions and purchase additional reductions from other units in
14 the market. And my understanding is that their conclusion was
15 that it was feasible for all of the units to comply under that
16 scenario.
17 MR. MURRAY: And in that feasibility they concluded that
18 there was sufficient engineering material and skilled labor
19 resources to complete that task in that time frame?
20 MR. FORBES: I assume that was part of the evaluation that
21 they did.
22 MR. MURRAY: I believe I have one question for Ms. Bassi.
23 It has to do with Part 97. I must admit I have not read Part 97
24 yet. I believe there was testimony yesterday that the Part 97
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1 rule, which is the -- if I understand the new and improved
2 trading program for the Section 126 petitions, that does not have
3 the flow control going in until 2005?
4 MS. BASSI: Part 97 is the trading program that USEPA would
5 administer if it imposes the NOx controls that are necessary for
6 whatever reason, either through the -- in response to the 126
7 findings or for a FIP that might be imposed. In January of this
8 year they amended Part 97 in conjunction with the 126 petitions
9 and it provides that flow control would not start -- flow control
10 for the Compliance Supplement Pool would not start until 2005.
11 USEPA's stated intention with parts 96 and 97 was that the
12 two would be the same, that they would work together seamlessly.
13 But then they have made these changes to Part 97. They have also
14 changed the allocation methodology in future years and as I
15 mentioned yesterday, the basis for determining eligibility for
16 allowances to what we call modified FIP.
17 MR. MURRAY: I know we have -- you had testimony that
18 related to the fact that you have to adopt the trading program
19 along certain parameters.
20 MR. FORBES: Uh-huh.
21 MR. MURRAY: For it to get the automatic approval or the
22 fast-track approval.
23 FORBES: Well, not just fast-track approval, but --
24 MR. MURRAY: I don't mean the Board fast-track.
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1 MR. FORBES: No. But you are correct. USEPA has said that
2 if you -- if states adopt what they have and they don't deviate
3 from it that they will get streamlined approval of their SIPs.
4 We have deviated from it sufficiently that they are going to
5 look. But there is not flexibility to deviate from certain parts
6 of the trading program, the federal trading program, in order to
7 participate in it at all.
8 MR. MURRAY: Is it my understanding that you do not believe
9 that we could use a flow control delay until 2005 ?
10 MR. FORBES: The states do not have -- the states do no
11 control flow control. This is an administrative portion that
12 USEPA imposes as the administrator of the whole trading system.
13 So it is something that is beyond our -- it is not something that
14 we --
15 MR. MURRAY: So it is possible that the differences in Part
16 97 will be what the USEPA follows on the trading program?
17 MR. FORBES: I really don't know.
18 MR. MURRAY: Okay.
19 MR. FORBES: It was something that I noted because it was a
20 change from Part 96 and so far maybe they don't think they are
21 going to implement 97, that everybody will comply. Who knows.
22 MR. MURRAY: Okay. Thank you. That's all of the questions
23 I have for now.
24 HEARING OFFICER GLENN: Thank you, Mr. Murray. Are there
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1 any other questions?
2 Yes, please, Ms. Faur.
3 MS. FAUR: Good morning. I am Cynthia Faur from
4 Sonnenschein, Nath & Rosenthal. I am hear on behalf of Midwest
5 Generation, and we just have a few questions on the early
6 reduction credit provisions, which are Section 217.770. First
7 off, with regard to I guess the emission reduction threshold, the
8 threshold to which credits can be allocated, that is contained in
9 Section 217.770 (c). Does the model rule provide discretion as
10 to how this threshold is determined?
11 MS. BASSI: We have interpreted that it does. The model
12 rule provides for the Compliance Supplement Pool that states may
13 choose to use. It limits what the allowances may be allocated
14 for, the activity on the part of the utility that the allowance
15 may be allocated for. We have interpreted it to allow us
16 flexibility beyond that point.
17 MS. FAUR: So that there is flexibility it determining
18 let's say -- well, actually, 217.770 (c), it contains different
19 provisions for whether or not you are regulated under Title 4 or
20 if you are -- have units that are included in a NOx averaging
21 plan or units that the are not included in the NOx averaging
22 plan, there is discretion in determining how credits are going to
23 be allocated to those units based on differences?
24 MS. BASSI: We have interpreted Part 96 to allow this and
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1 they have come up with this.
2 MS. FAUR: Okay. For units that are included in a NOx
3 averaging plan, can you clarify how the affect that they are in a
4 NOx averaging plan would affect their ability to obtain an early
5 reduction credit? For example, there is an individual unit that
6 has itself decrease emissions more than 30 percent beyond what it
7 would be required if it were subject to an individual limitation,
8 but does that mean it needed to be 30 percent below the average
9 number in the NOx averaging plan or how is this going to work for
10 individual units?
11 MS. BASSI: The bottom line is that the units or the -- the
12 units for which a company is seeking early reduction credits must
13 control 30 percent -- well, they must control more than 30
14 percent below whatever the applicable requirement is. If a
15 company has decided to include the unit in a NOx averaging plan,
16 then we would view all of the units that are included in the NOx
17 averaging plan as a whole. So what we would be looking -- so the
18 early reduction credits that would be available would be -- what
19 the reduction from that group is, as opposed to the reduction of
20 a single unit that is included in the group.
21 MS. FAUR: Okay.
22 MS. BASSI: Once a company has submitted a NOx averaging
23 plan to the USEPA then, in essence, what it has done is taken a
24 group of units and said this is how we are going to treat these
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1 units in order to comply with Title 4. Because we are looking at
2 this as a reduction below applicable requirements, then it seemed
3 logical to us to treat them as a whole just as the company had
4 when they did the NOx averaging plan. That's the reason why we
5 distinguished between units that are in a plan and units that are
6 individual and also tried to tie it to applicable requirements as
7 opposed to what any individual unit does outside of that.
8 MS. FAUR: The NOx averaging plan is an annual plan. Has
9 the Agency determined how they are going to handle the fact that
10 the NOx budget has a seasonal component?
11 MS. BASSI: My understanding is that information is
12 available to companies and is probably even out on the Web that
13 will show how they operated during the ozone season or during the
14 control period and what the average heat rate was for the -- for
15 those units that are included in the plan and that it is possible
16 to perform the mathematics that will determine whether or not
17 they are eligible for early reduction credits. This is
18 information that the companies also would be submitting to us.
19 Just as in any other report we would review it and check it and
20 verify it and go from there.
21 MS. FAUR: Okay. Now moving on to the actual pool of
22 credits that you have to allocate, under Section 217.770,
23 Subsection F (2), the Agency has 15,261 credits to allocate over
24 the two years prior to the start date of the program, hopefully
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1 2001-2002. The Agency has proposed to allocate these one half in
2 the first year and one half in the second year. Could you
3 explain the basis for determining to split these half and half?
4 MS. BASSI: The rational was that this would --
5 this would allow us to -- or would allow the companies to do some
6 planning, that they would know that this is the number of
7 allowances that were available, and that they would apply for
8 them and we would notify them fairly early on, as opposed to what
9 it might be if we didn't notify them until the end, of how many
10 allowances that they were going to receive from this pool. But
11 also, we allowed for these to carry over to the second year in
12 order to distribute all of the allowances. So our intent here is
13 not to restrict on the whole the number of early reduction
14 credits that units may earn. It is merely to try to put some
15 kind of -- I don't know -- organization, I guess, to how they are
16 distributed.
17 MS. FAUR: Since there is going to be a carry-over from the
18 first year to the second year, did the Agency ever consider a
19 different allocation method, let's say two-thirds in the first
20 year, one-third in the second year, which is a method that would
21 encourage earlier reductions?
22 MS. BASSI: That is another approach that has as much
23 validity as the one we have. Perhaps some of Mr. Diericx's
24 concerns about the incentives for the reductions might be
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1 reduced. In other words, if you reduce in one year and then you
2 don't reduce in the next. There is nothing that says that once
3 you reduce you have to stay reduced.
4 MS. FAUR: But if you do stay reduced you can apply for
5 credits in the subsequent year?
6 MS. BASSI: Yes.
7 MS. FAUR: Thank you.
8 HEARING OFFICER GLENN: Thank you, Ms. Faur. Does anyone
9 else this morning have questions?
10 Yes, please, Mr. McGervey.
11 MR. McGERVEY: Good morning. My name is Joe McGervey. I am
12 an analyst with Energy and Environmental Analysis. I have got
13 four sets of questions this morning for the Agency. Most of them
14 related to the treatment of new sources.
15 The first one, the proposed rule provides a stream of
16 allowances through 2009 for the Appendix F units. Regardless of
17 how the plan is operated or whether it is shut down, the EPA
18 model rule suggests that allocations should reflect actual plant
19 operations. The proposed rule, in its fixed flex mechanism,
20 presents the appearance of granting a property right to the
21 existing facility owners that they would receive from the state,
22 and this represents a significant advantage for their planning as
23 well as for their finances.
24 Can one of you briefly explain to me how the allocation
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1 mechanism was developed and how the allocations for the existing
2 units were determined for that period and also were any new
3 source developers involved in the development of that allocation
4 process?
5 MS. BASSI: As we submitted with our testimony or with our
6 package when we filed the proposal with the Board, we met -- we
7 have met with the effected community and others many, many times
8 over the past two years. As Mr. Lawler testified yesterday, we
9 started meeting with people in late 1998, shortly after the SIP
10 Call was promulgated. Initially we met with the Appendix F --
11 representatives of the Appendix F EGUs, and for a long period of
12 time haggled over how we would distribute the allowances to the
13 Appendix F units.
14 In the spring of 1999, we began meeting also with
15 representatives of new EGUs, and also -- and explained to them
16 the approach that we were in the process of developing. They
17 participated in that process or they had the opportunity to
18 participate in that process from that point forward. The initial
19 allocations that are listed in Appendix F were negotiated.
20 MR. McGERVEY: Okay.
21 MS. BASSI: Just flat out negotiated. The allocation
22 methodology, as I testified yesterday, was one that we feel
23 reflects comments that Illinois EPA has filed with USEPA on
24 several occasions that there should be a phasing in of this
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1 program. And you are right, it does give the Appendix F EGUs the
2 opportunity to plan.
3 MR. McGERVEY: Thank you. That does answer the question
4 there. The second question is related to that. The nominal
5 allocations in the proposed rule are based on an emission rate of
6 0.15 pounds per -- as the rule -- my reading of it looked like if
7 was based on approximately 0.15 pounds per million btu for the
8 existing units which, you know, you are saying it was actually
9 negotiated?
10 MS. BASSI: Yes, it was a negotiated number.
11 MR. McGERVEY: Okay.
12 MS. BASSI: The 0.15 pounds per million btu comes in only
13 in determining the number of allocations that are -- that that
14 unit would be eligible for when we get into what we call the
15 flexible portion of the allowance allocations.
16 MR. McGERVEY: Okay. As it proceeds in the years?
17 MS. BASSI: Uh-huh.
18 MR. McGERVEY: For the new units, they would be eligible
19 for the lower of 0.15 of the permitted levels for the new units,
20 and I think one of the benefits of a fully implemented cap and
21 trade system is that it encourages low emission generation, and
22 the rule does seem to provide that encouragement for the existing
23 sources in the system. However, there is not that encouragement
24 for lower emissions from the new sources.
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1 Was there any analysis performed to determine whether it
2 was more cost effective to have the separate treatment of the
3 existing and new sources or was there any other way that that was
4 determined?
5 MS. BASSI: With regard to cost analysis, no, we did not do
6 a cost analysis of that different treatment.
7 What was the second half of your question? I am sorry.
8 MR. McGERVEY: Well --
9 MS. BASSI: Some other analysis?
10 MR. McGERVEY: Yes, or any other analysis to say, well, we
11 should treat new and existing differently based on something
12 other than cost analysis.
13 MS. BASSI: I don't know that I could say that there was a
14 specific point by point by point analysis of -- in terms of how I
15 think analysis would roll out. A rationale for why we took this
16 particular approach is that new units are subject to certain
17 limitations on their operation that reflect or that will result
18 in fewer NOx emissions than what we would expect to see from
19 coal-fired units. In an attempt to distribute our allowances --
20 the number of allowances that we have available to us to as many
21 units as possible this appeared to us to be one approach that
22 would allow us to do that.
23 As Mr. Murray was alluding to, because of the number of
24 allowances that are available to Illinois sources to be issued by
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1 the state as opposed to going out on the market and participating
2 in the trading program itself. Units in Illinois, particularly
3 the coal-fired units in Illinois, will be operating at -- will
4 have to operate at a rate much lower than 0.15. If you consider
5 that and compare that with the allowance scheme that we have set
6 up for the new EGUs, they are probably reasonably equitable.
7 MR. McGERVEY: Okay. But they are different?
8 MS. BASSI: But they are different and they are different
9 from what Part 96 provides.
10 MR. McGERVEY: My third question regards the set-aside. I
11 have some question about whether the new source set-aside should
12 change from five percent to two percent in 2006. The set-aside
13 provides a source of allowances for new sources until they have
14 accumulated enough data to enter into the main part of the
15 allowance allocation system. Restricting the size of the
16 set-aside may present a barrier to new clean sources that want to
17 locate in Illinois. The Illinois EPA has stated that they
18 expected the five percent set-aside to be oversubscribed in the
19 early years of the program.
20 And my question is, was there any analysis done to
21 determine whether the new source set-aside should be adjusted
22 downward in 2006?
23 MS. BASSI: Again, there was no formal step-by-step
24 analysis in the terms that I think of as an analysis. The two
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1 percent was a number that we had discussed with both existing and
2 new EGUs at a number of the meetings that we held with them prior
3 to submitting our proposal. And while some individual new --
4 while representatives of some individual new EGUs had suggested
5 that perhaps two percent is a bit low, the general feeling seemed
6 to be that it was a reasonable number. That the number of new
7 units that would be entering the state -- or I should not say
8 entering the state -- that would appear, would probably start
9 leveling off within the next few years.
10 Also, in some instances -- we have to distinguish between a
11 new unit a unit that has been modified. Some units that are
12 being modified may appear on a list of new units that we have,
13 but they are actually being modified, perhaps switched from coal
14 firing to natural gas firing. Units retain their commenced
15 commercial operation date, and so in some instances while it
16 might appear that it is a new unit it is actually control
17 technology or it is viewed in this program as a control
18 technology.
19 MR. McGERVEY: Going from coal to gas, would that be --
20 (Ms. Kroack and Ms. Bassi confer briefly.)
21 MS. BASSI: I was also reminded here that new -- that units
22 that have received allowances from the new source set-aside do
23 fold into our flexible portion. So the first -- all this big
24 group of units that have come on line by 2002 should -- well,
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1 most of them anyway will fold into our existing pool. They will
2 become existing EGUs in 2006. So there is going to be a big
3 influx of units in 2006 and the number of new units will
4 diminish.
5 MR. McGERVEY: I think you referred to this yesterday.
6 There is the period between 1995 and 2000?
7 MS. BASSI: And 2005 essentially, yes.
8 MR. McGERVEY: Where all of those will be rolling in?
9 MS. BASSI: Uh-huh.
10 MR. McGERVEY: Stepping back just a minute, you mentioned
11 units switching from coal to gas --
12 MS. BASSI: Uh-huh.
13 MR. McGERVEY: -- and their treatment. Is that
14 specifically just boilers converting from coal to gas or would
15 this also include facilities that are repowered or that may be
16 leveled and replaced with a gas combined cycle unit on the same
17 site?
18 MS. BASSI: There is a definition of repowering that is
19 included in our proposal that goes beyond or that is different
20 from the Title 4 definition of repowering.
21 MR. McGERVEY: Okay.
22 MS. BASSI: And if an existing unit -- wait a minute. One
23 of you guys has to answer this because this is getting into the
24 technology stuff.
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1 You are asking me about how boilers work. Mr. Forbes will
2 take over now.
3 MR. FORBES: Essentially, any particular existing unit that
4 would repower -- as Kathleen mentioned, we have included a
5 definition in the proposal. Essentially, the Agency is viewing
6 the repowering as a control technique.
7 MR. McGERVEY: Okay.
8 MR. FORBES: It is a methodology to enable an existing unit
9 to reduce emissions. That is how we are viewing that. So that
10 would still remain as an exist unit.
11 MR. McGERVEY: For this rulemaking?
12 MR. FORBES: For this rulemaking.
13 MR. McGERVEY: Otherwise it is different?
14 MR. FORBES: Right.
15 MR. McGERVEY: My last question touches on something that I
16 didn't hear in the testimony yesterday, but I saw in my reading
17 of Section 217.768, Paragraph H, and this is regarding new
18 sources again. And my reading of paragraph H is that new sources
19 that come on line after January 1st, 2003 are charged a fee to
20 draw allowances from a new source set-aside. The monies
21 collected from this fee will be passed back to the existing
22 sources. Again, this treats the -- it seems to treat the
23 allowances as a property right of the existing power plant
24 owners. To my knowledge, there are no other states that have
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1 this type of arrangement. Is my understanding of Paragraph H
2 approximately accurate? And what is the rationale for charging
3 the new sources for taking these allowances from the new source
4 set-aside?
5 MS. BASSI: Except for your comment that this creates a
6 property right, which I think we very explicitly say there are no
7 property rights here, your interpretation of this is accurate.
8 The rationale comes from the General Assembly, the General
9 Assembly's adoption of Section 9.9, which is the enabling an
10 directing legislation for this particular program. The Section
11 9.9 provides that the Agency may charge for allowances that are
12 issued from the new source set-aside for units that commence
13 operation on or after January 1, 2003. We interpreted that as an
14 expression of the intent of the General Assembly that we move
15 forward with this particular -- consistent with that language
16 that is in there.
17 Also in Illinois my understanding is that our ERMS program
18 that we referred to briefly yesterday, the Emissions Reduction
19 Market System, also provides for the purchase of allowances. And
20 so even though this may not be common in the SIP Call domain, it
21 is not contrary to the manner in which Illinois has approached a
22 trading program and the issuance of allowances to new sources in
23 the past.
24 MR. McGERVEY: Okay. Thank you.
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1 HEARING OFFICER GLENN: Thank you, Mr. McGervey. Does
2 anyone else have questions this morning? Mr. Rieser.
3 MR. RIESER: Thank you very much. Again, for the record,
4 my name is David Rieser. I am with the law firm of Ross &
5 Hardies. I am here on behalf of Ameren.
6 I had suggested that I had some comments or questions
7 directed to the specific language in the proposal. So we are
8 going to thumb through here. The first question has to do with
9 211.1320 and 1324, which is the definitions of commence
10 commercial operations and commence operations. Is it accurate
11 that these definitions are intended to apply solely to Subpart W
12 and have no -- they are not intended to have any impact with any
13 other determination or program including, for example, new source
14 review and things of that nature?
15 MS. BASSI: That is correct. It is limited to Part 217,
16 which has to do with NOx.
17 MR. RIESER: Okay. So it is limited to 217, Subpart W?
18 MS. BASSI: The language says 217. There will be other
19 regulatory proposals that the Agency will make with regard to
20 this particular overall program, which is why it is limited at
21 this time to only 217 as opposed to only Subpart W in 217. But
22 your interpretation is correct. It is not related to or intended
23 to be related to new source review.
24 MR. RIESER: Or any other --
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1 MS. BASSI: Or any other program.
2 MR. RIESER: Okay. Thank you. With respect to 756 (d)(2),
3 the language says each ton of NOx emitted in excess of the number
4 of NOx allowances held by the owner or operator for each budget
5 EGU for each control period shall constitute a separate violation
6 of this Part and the Act. Do you see where I am?
7 MS. BASSI: Yes.
8 MR. RIESER: My understanding is that is taken directly
9 from 40 CFR 96?
10 MS. BASSI: That's correct.
11 MR. RIESER: Would it also be the case that each -- that
12 there would be a violation of each day of the control period, as
13 is also suggested by 96, or has the Agency determined that that
14 is not an appropriate method for calculating penalties under this
15 program?
16 MS. BASSI: No, there could be a violation for each day of
17 the control period to the extent -- that is mitigated, however,
18 by demonstrations that sources or units may make. So if a unit
19 can demonstrate that at some point in the control period that it
20 did not do this, then it would be reduced.
21 MR. RIESER: So that would be a discussion that would be
22 taking place during an enforcement proceeding and not an
23 automatic regulatory determination?
24 MS. BASSI: That's correct.
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1 MR. RIESER: All right. With respect to (d)(6) --
2 MS. BASSI: I am sorry? You said (d)(6)?
3 MR. RIESER: The same section, Section 756 (d)(6) talks
4 about that the allowance is a limited authorization and it goes
5 on to say that no provision of the NOx trading program and no
6 provision of any of the regulations shall be construed to limit
7 the authority of the United States or the state to terminate or
8 limit this authorization. What does this language mean?
9 MS. BASSI: Can I have a second, please?
10 (Ms. Kroack and Ms. Bassi confer briefly.)
11 MS. BASSI: The intention of this language, with all of its
12 words, is to say that this is not a property right.
13 MR. RIESER: But you say that someplace else.
14 MS. BASSI: We want the message to get across.
15 MR. RIESER: Does that -- does that mean that a source can
16 have an allowance and it can be simply taken away for reasons or
17 for procedures not described in these regulations?
18 MS. BASSI: No. If a unit has an allowance, then the
19 allowance is not going to be taken away in a manner that is not
20 provided for either here or in the incorporations by reference to
21 Part 96. Yesterday I referred to USEPA's authority to make
22 corrections, and those corrections could perhaps result in the
23 taking away of an allowance from an account. It could perhaps
24 result in the addition of an allowance to an account. I think
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1 that this language goes to that, to a degree. The other thing is
2 that I think that this allows for the whole program to be
3 terminated, if necessary, without any compensation for allowances
4 that may be banked.
5 MR. RIESER: But nothing -- allowances cannot be removed
6 without some type of regulatory or statutory activity and
7 regulatory would be as provided for in these regulations or in
8 the Part 96 regulations?
9 (Ms. Kroack and Ms. Bassi confer briefly.)
10 MS. BASSI: There can be adjustments that are made without
11 a rulemaking. This is that correction thing that the USEPA can
12 do. And the notice is after they have made the correction,
13 within ten days after they have made the correction.
14 MR. RIESER: But the corrections would be according to
15 their evaluations of the accumulated allowances under Part 96,
16 correct?
17 MS. BASSI: Correct. It would be consistent with what is
18 provided in Part 96.
19 MR. RIESER: They would use some type of notice provision
20 to advise people of the fact of the --
21 MS. BASSI: Yes, that's correct.
22 MR. KROACK: And when you say it is not a property right,
23 what is that intended to mean?
24 (Ms. Kroack and Ms. Bassi confer briefly.)
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1 MS. KROACK: Mr. Rieser, we really view this question as
2 calling for a legal conclusion. We will be happy to respond in
3 written comments. The real theory is all of the things you
4 think of when you hear about property right is what we are
5 intending to convey, but as to more specifically than that, we
6 prefer to respond in written comments.
7 MR. RIESER: Thank you. With respect to 756 (d)(8), again,
8 this is the automatic removal of allowances as a penalty that the
9 USEPA would do for exceedance of the allowances. Is there any
10 resource by the EGU to this action by the USEPA?
11 MS. BASSI: Part 96 does provide for the recourse that you
12 are talking about. I don't know exactly the section in 96
13 offhand where this is provided, but it does provide for a kind of
14 appeal. I don't believe they call it an appeal. But it is a
15 kind of appeal.
16 MR. RIESER: So the recourse of an Illinois unit would be
17 to some type of federal process for this action by the USEPA?
18 MS. BASSI: That's correct, because USEPA is the sole party
19 that is -- that is administering the banking part of the program.
20 MR. RIESER: Thank you. Looking at 217.758 (b)(1), it
21 takes about the duty to apply for a permit and then goes on to
22 say the owner or operator of any source with one or more budget
23 EGUs shall reapply for a budget permit for the source as required
24 by the subpart and then etcetera.
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1 Do these budget permits have a duration or when would the
2 duty to reapply come into play?
3 MS. BASSI: The budget permits would have the same duration
4 as the sources regular state or Title 5 permit. It is a piece of
5 that Title 5 or state permit, and so it would just be -- come
6 under those rules.
7 MR. RIESER: So whenever they had -- the duration would be
8 the same as the permit under to which this was attached?
9 MS. BASSI: Correct.
10 MR. RIESER: And they would have to reapply at the same
11 point in time whenever they reapplied for that permit?
12 MS. BASSI: That's correct. One of the things, though,
13 that is necessary that we are trying to get across here is that
14 at the initiation of this program there is a duty on the part of
15 the effected units to apply for this permit to contact the Agency
16 with an application.
17 MR. RIESER: With respect to (b)(2)(c) of that same
18 section, 758, it says that it includes among the information
19 requirements for a budget permit application the compliance
20 requirements of Section 217.756. What information is the unit
21 supposed to apply that meets that requirement?
22 (Ms. Kroack and Ms. Bassi confer briefly.)
23 MS. BASSI: What we would expect to have included in an
24 application would be the monitoring, you know, some reflection of
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1 the monitoring that the source is doing, or that the unit is
2 doing. That the unit will provide the requisite record keeping
3 and recording. I think there also has to be an acknowledgment
4 that they do have an account representative, and that is most of
5 it. You know, it is just general participation in the -- or
6 subject to the provisions of Subpart W and Part 96.
7 MR. RIESER: So those are the elements of 756 which you are
8 seeking to have addressed in this part of the application,
9 correct?
10 MS. BASSI: That's correct.
11 MR. RIESER: You will be issuing a permit application at
12 some point when the time comes to do that?
13 MS. BASSI: Developing something, yes.
14 MR. RIESER: Okay. With respect to 217.764, which has to
15 do with allocations, is it accurate that the IEPA, for
16 allocations after 2005, will make those allocations three years
17 prior to the control period in which they are applying?
18 MS. BASSI: That's correct.
19 MR RIESER: Okay. What will the process be for the IEPA to
20 announce those allocations?
21 MS. BASSI: We are to inform USEPA of how the allowance
22 allocations are to be distributed among the units. And we have
23 not yet determined the process, the internal process that we
24 would use to notify the units, but there would be some process
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1 that we would develop. We would let the account representatives
2 know.
3 MR. RIESER: And the general public as well?
4 MS. BASSI: Yes.
5 MR. RIESER: Okay.
6 MS. BASSI: Also the general public will have access to
7 this over USEPA's web site. The USEPA will have a web site, if
8 it doesn't already yet, that contains all of this information.
9 MR. RIESER: Okay. Thank you. In the questions this
10 morning you had some questions with respect to new EGUs pursuant
11 to 217.768. I just want to clarify the difference between the
12 new EGU, the newer EGU and the existing EGU, just so that it is
13 clear.
14 MS. BASSI: Okay.
15 MR. RIESER: A new EGU for the period of 2003, 2004, 2005
16 is one that commences operations after January 1st, 1995; is that
17 correct?
18 MS. BASSI: That's correct.
19 MR. RIESER: For the period of 2006 on, a new EGU is one
20 that commenced operation less than four years prior to the
21 control period?
22 MS. BASSI: That's correct.
23 MR. RIESER: For which the Agency is providing the
24 allocations?
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1 MS. BASSI: That's correct.
2 MR. RIESER: And new EGUs are defined as the ones that get
3 allocations from the two -- well, it would be the two percent
4 set-aside for the years 2006 forward?
5 MS. BASSI: That's correct.
6 MR. RIESER: Under the flexed portion of this, when you
7 have an 80/20 split during 2006 and 2007, the 80 percent is for
8 the Appendix F EGUs?
9 MS. BASSI: Appendix F, yes.
10 MR. RIESER: And the 20 percent goes to the non Appendix F
11 EGUs that are not new EGUs that you just defined.
12 MS. BASSI: The 80 percent goes to those existing EGUs that
13 are not Appendix F first. The 20 percent.
14 MR. RIESER: The 20 percent?
15 MS. BASSI: The 20 percent. I am sorry.
16 MR. RIESER: Don't apologize to me. It is all of the
17 people having the heart attacks in the room.
18 (Laughter.)
19 MS. BASSI: It goes to the non Appendix F existing EGUs
20 first. If it is not fully distributed at that point then any
21 remainder is prorated among all of the existing EGUs, including
22 the Appendix F EGUs.
23 MR. RIESER: Okay. One more question on the early
24 reduction issue. Section 217.770 (e), this, again, has to do
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1 with the change in dates, should there be a change in the NOx SIP
2 Call. It requires the early reduction request must be submitted
3 by November 1st of the year two years before the allocation date
4 for the reductions made in the control period. Are people going
5 to know when that time is, what two years before the
6 implementation date is going to be?
7 MS. BASSI: I am not sure. If the date is not 2003, I am
8 not -- it is not clear to us. It is total speculation as to what
9 the date would be and whether anyone would know, which provides a
10 problem for us also in providing how we would divide the early
11 reduction credits up prospectively.
12 MR. RIESER: The last sentence of this says should this
13 occur, the other dates in the section shall be adjusted
14 accordingly. What does the "this" refer to?
15 MS. BASSI: "This" refers to a delay in implementation of
16 the entire program.
17 MR. RIESER: Okay. Thank you. That was all of the
18 questions. Thanks very much.
19 HEARING OFFICER GLENN: Thank you, Mr. Rieser. Would any
20 anyone else like to ask questions this morning?
21 Yes, sir. Please state your name.
22 MR. GOODWIN: I am Daniel Goodwin with Goodwin
23 Environmental Consultants. We are advising several of our
24 clients who are potential participants in this program.
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1 I would like to start with some questions about the new
2 source set-aside. As I understand it, the total allowance pool
3 of 30,701 tons reflect a growth assumption of eight percent. But
4 only five percent of that is being used for the new source
5 set-aside. What is the rationale for that difference?
6 MS. BASSI: Part of the rationale is Section 9.9 limits the
7 new source set-aside to five percent. So we have a statutory
8 limitation on the maximum size of the new source set-aside. Part
9 of the rationale for whether there is eight percent growth or
10 some other level of growth is that this is a growth in heat
11 input, not necessarily a growth in just new EGUs. So the
12 increase in heat input in the state could come from existing EGUs
13 as well as new units that are built.
14 MR. GOODWIN: So implicit in that, then, is that if there
15 is not an overall increase in utilization of the existing units
16 of three percent, those allowances will simply be up for grabs in
17 the trading system and whoever happens to receive those
18 allowances stands to benefit financially; is that a fair
19 statement?
20 (Ms. Kroack and Ms. Bassi confer briefly.)
21 MS. BASSI: We can't comment on financial benefit. I mean,
22 we don't know. The three percent difference I think that you are
23 alluding to between the growth that was estimated by the USEPA
24 and the new source set-aside is -- if the new source set-aside is
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1 undersubscribed then the allowances generally go back into the
2 pool for distribution among existing units. I think you have
3 heard -- you can tell from the tenor of the questions that most
4 of the existing units do not believe there will be three percent
5 that is up for grabs, as you put it.
6 MR. GOODWIN: Well, the three percent I was referring to
7 was the difference between the eight percent growth assumption
8 and the five percent that has been set-aside for allocation to
9 new sources.
10 MS. BASSI: I think that you are equating growth with new
11 sources and that is not how growth was anticipated.
12 MR. GOODWIN: I understand that. I guess I understand what
13 your answer is.
14 MR. GOODWIN: Regarding the annual fee, the fee that is
15 required for new EGUs that begin operation after January 1st of
16 2003, how will that fee actually be determined?
17 MS. BASSI: The amount of the fee will be based upon the
18 average price that NOx allowances traded for in the previous
19 control period. In 2003 that will be dependent upon the trading
20 of NOx allowances in the Ozone Transport Region, which is in the
21 northeastern part of the country. They have a NOx trading
22 program currently operating and those prices are published.
23 MR. GOODWIN: Who will make that determination?
24 MS. BASSI: The Agency will.
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1 MR. GOODWIN: Where will you get your information for that?
2 MS. BASSI: We have not yet identified the source for that
3 information. We expect that there will be an index of prices
4 that would be available like standard indices for other prices
5 that are available. I believe we will need to do Agency rules
6 that will address how this will actually be carried out and we
7 will address that at that time.
8 MR. GOODWIN: Is it expected that there will be a legal
9 obligation on the participants in these trades to reveal the
10 financial terms of the trades?
11 MS. BASSI: You mean on a domain basis, a domain wide
12 basis?
13 MR. GOODWIN: I mean on any -- on whatever basis you intend
14 to use as your database for setting the fee.
15 (Ms. Kroack and ms. Bassi confer briefly.)
16 MS. BASSI: Our assumption is that this is a regional NOx
17 trading market and with other trading -- and as with other
18 regional trading markets, financial information will become
19 known.
20 MR. GOODWIN: As far as you know, right now at least, there
21 is no contemplation that any -- there will be any legal
22 obligation for the participants in the trades to reveal how much
23 they pay?
24 MS. BASSI: I don't know if there is a legal obligation or
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1 not. There will be enough financial information available.
2 Based on what we have seen so far trading in the Ozone Transport
3 Region a price, a market price, an average market price can be
4 determined.
5 MR. GOODWIN: Do you know what that average market price
6 has been recently?
7 MS. BASSI: No. I don't know an average price. I watch
8 it, you know, once in awhile. And the price for NOx allowances,
9 as published by Air Daily, which is a publication out of
10 Washington DC, it publishes Canter Fitzgerald's prices that it is
11 trading at. It has ranged from $600.00 a ton to $750.00 a ton in
12 the last several months.
13 MR. GOODWIN: Is there any expectation that that price is
14 going to change dramatically in either direction as additional
15 states get into the NOx trading business?
16 MS. BASSI: Mr. Goodwin, if I knew that I wouldn't be here.
17 (Laughter.)
18 MR. GOODWIN: So is it correct to say that the Agency at
19 this point has not attempted to put any total cost or cost for a
20 typical new EGU associated with this ruling?
21 MS. BASSI: That's correct.
22 MR. GOODWIN: But you had determined that it is
23 economically reasonable?
24 MS. BASSI: We have determined that this particular program
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1 has a certain economic cost associated with it that Mr. Forbes
2 has testified to. The USEPA has called this program highly
3 cost-effective. When I say this program, I mean the program in
4 terms of an approach for obtaining regional NOx reductions.
5 MR. GOODWIN: What I am trying to focus on is the
6 difference in cost burden between a new EGU and that is required
7 to pay the fee and an existing EGU that is not required to pay
8 the fee. What I am trying to ascertain is whether the Agency has
9 made a determination that that incremental cost burden on new
10 EGUs is economically reasonable?
11 (Ms. Kroack and Ms. Bassi confer briefly.)
12 MS. BASSI: Section 9.9 provides that we may charge for
13 these allowances from new sources after January 1st of 2003.
14 That is the basis for this. It does not require further
15 analysis. We have taken this as legislative intent.
16 MR. ROMAINE: Let me add to that. I look at this very
17 similar to the new source review off-set provision, that there is
18 a requirement that under the new source review program that new
19 sources provide emission off-sets. That is a statutory
20 obligation and that is something that we have to do. We did not
21 adopt it with the specific understanding of what those costs
22 might be. As time goes on in the program those costs will
23 change, but those are simply a cost that a company developing a
24 new project has to take into consideration as one of the
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1 environmental obligations as part of coming into a particular
2 area. This is certainly different than nonattainment new source
3 review, which has an off-set requirement, because it applies to
4 an entire region, but in other respects I think it is very
5 similar.
6 MR. GOODWIN: With regard to the language of Section 9.9
7 that you alluded to, Ms. Bassi, doesn't it use the word may?
8 MS. BASSI: Yes, it does.
9 MR. GOODWIN: As you --
10 MS. BASSI: But it --
11 MR. GOODWIN: As you know, I am not an attorney. But my
12 understanding of that is that that gives the Agency some leeway
13 in how much of a fee might be charged or perhaps even gives the
14 Agency the authority not to charge a fee at all. Would you
15 disagree with that?
16 MS. BASSI: I would agree that "may" is less directive than
17 "shall" which also appears in the language. At the same time, I
18 would point out that it is included in the language at 9.9 and
19 other things are not. Which suggests to us that the General
20 Assembly is providing that this is something that -- that their
21 intent is that after a certain period of time new EGUs that
22 receive allowances from the new source set-aside will be charged
23 a fee for those.
24 MR. ROMAINE: Let me add to that, as well. I think it is
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1 appropriate to look at the specific methodology that applies to
2 these units. If you read the provisions that deal with the use
3 of this set-aside, the heat input rate is simply the heat input
4 rate requested by the applicant as limited by its permit. So in
5 the absence of any cost for these allowances, the source could
6 simply request the full heat input rate as allowed by its permit.
7 Permits for major new sources may not, in fact, have any
8 restrictions on heat input for the unit, and the source could, in
9 fact, request considerably more allowances that it might
10 otherwise require for its actual operation.
11 Putting a fee on the allowances for new sources that are
12 entitled to set-aside and sort of an economic control on the
13 number of allowances that such a source would request, because it
14 is going to have to pay for any allowance that it receives. In
15 that respect it is somewhat sort of a different situation from
16 the people that are going after the five percent set-aside
17 because certainly during that period of time we expect that there
18 will be a large number of sources going after the pool and it
19 could be oversubscribed. We are not at all certain that the
20 set-aside for new sources will be oversubscribed.
21 Again, the set-aside is a provision that continues into
22 perpetuity and there could be periods in the future where there
23 would be only one source that would be applied for this
24 set-aside. And it is appropriate to have some restrictions on
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1 how many allowances would go to that source, while at the same
2 time facilitating the ability of that source to begin operation
3 with a known stream and supply of allowances coming to it.
4 MS. BASSI: One other point that I would add to that, this
5 does not start until 2003. It applies only to sources that
6 commence commercial operation after January 1st, 2003.
7 Therefore, there is lots of notice to new units that are coming
8 into Illinois or that want to build. I should not say coming in.
9 That want to build in Illinois. This adds to a point that Mr.
10 Romaine was making earlier, that this is a cost of doing business
11 after that point in time.
12 MR. GOODWIN: Let me work through an example with you, if I
13 may. This happens to be a proposed facility for which an air
14 permit application was recently submitted to the Agency which, as
15 I estimate, or my understanding of these proposed rules would
16 need somewhere in the neighborhood of 1,000 to 1,200 allowances
17 per control period. And it will begin operation, optimistically,
18 perhaps, late 2003. If we use your dollar figure for that, they
19 are looking at a fee each year of somewhere in the three-quarter
20 of a million to a million dollar range, which is going to
21 probably approach their annual payroll as a cost item.
22 MS. BASSI: They won't pay a fee that high because there
23 are not 1,100 or 1,200 allowances available.
24 MR. GOODWIN: Well, if there are not 1,100 or 1,200
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1 allowances available --
2 MS. BASSI: In 2003 there are 1,535; is that correct?
3 MR. FORBES: Yes.
4 MS. BASSI: Allowances that will be prorated among all new
5 source. One source will not likely get 1,200 of those.
6 MR. GOODWIN: What, then, is the outcome of that scenario?
7 Is it simply going to be the case that Illinois will not host
8 additional fuel-fired electrical generating capacity after 2003?
9 MS. BASSI: No. The outcome of that is there is a regional
10 trading system. And we have a certain limited number of
11 allowances that are available for new sources, and actually for
12 all of our sources or units. And the trading program is -- would
13 have to -- or whatever arrangements that source could make with
14 other companies in Illinois or elsewhere in the region is where
15 it would have to obtain its allowances.
16 MR. GOODWIN: Well, whether they get the allowances -- let
17 me back up. If they acquire allowances through the regional
18 trading program, as opposed to -- or some portion of them, as
19 opposed to receive an allocation from the Agency, are they --
20 will they be required to pay a fee for the allowances that they
21 obtain elsewhere?
22 MS. BASSI: Not a fee to us. They will be -- whatever
23 arrangements they make in the market is up to them.
24 MR. GOODWIN: But it is true, is it not, that the fee that
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1 they would pay the Agency or the price that they would pay on the
2 open market are going to be approximately the same?
3 MS. BASSI: I don't know.
4 MR. GOODWIN: Well, you have said that the fee that the
5 Agency will set will be based on the prices being paid in trades
6 in other states; is that true?
7 MS. BASSI: The fee that the Agency will charge for new
8 sources will be the average fee from the previous control period.
9 A unit or an account representative can make whatever bargain it
10 will elsewhere. It can get them for nothing. It could get them
11 for $10,000.00 more than what we might charge.
12 MR. GOODWIN: Well, but if you make the assumption that the
13 market is reasonably stable, and I would submit that if you are
14 not willing to make that assumption that we had better not get
15 into this program at all, so assuming a reasonably stable market
16 year-to-year, the price that they would have to pay in the open
17 market for whatever allowances that they can't obtain from the
18 state should bear some resemblance to what is required for the
19 fee. Do you disagree with that?
20 MS. BASSI: I have no opinion.
21 MR. GOODWIN: Okay. But if it were the case that they
22 could get all of the allowances from the Agency --
23 MS. BASSI: Okay.
24 MR. GOODWIN: Hypothetically, and if the price for those
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1 was $750.00 per allowance, using the figure that you mentioned
2 earlier, and they made 1,000 to 1,200 allowances per control
3 period, wouldn't you agree that their cost, whether it is in the
4 form of a fee or a purchase of allowances elsewhere is going to
5 be in excess of $750,000.00 per year? Isn't that math pretty
6 straightforward?
7 MS. BASSI: Yes.
8 MR. ROMAINE: I don't think it is quite that
9 straightforward. That is simply the cost for purchasing
10 allowances. But, again, they are also providing electricity. I
11 don't know if they will, in fact, be taking away a load from
12 other coal burning power plants so that as part of their sales of
13 electricity there might, in fact, be allowances available. So
14 simply to say that that is a flat cost could very well be true,
15 but in terms of costing out an entire arrangement per emissions
16 control for new power plants, you have to look at it more broadly
17 and see what are the fuller arrangements that that particular
18 entity has entered into.
19 MR. GOODWIN: I use this example in order to try to be
20 concrete in drawing the Agency out on its policy intentions here.
21 To move on just a little bit on this, the fees collected by the
22 Agency in the aggregate for the -- for whatever the number of
23 allowances you said would be available -- was it 1,400?
24 MR. FORBES: 1,535.
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1 MR. GOODWIN: 1,535. What will be done with those fees?
2 MS. BASSI: Section 9.9 allows the Agency to retain an
3 amount that approximates our administrative costs and then the
4 balance is to distributed back to those units from whom -- to
5 those units to whom allowances were issued but not from the new
6 source set-aside. In other words, to whatever the pool of
7 existing units happens to be at the time.
8 MR. GOODWIN: Okay. That is the administrative costs
9 associated just with the assessment and collection and
10 redistribution of the fees, or is it the administrative costs for
11 the whole Subpart W program? What administrative costs are
12 included there?
13 (Ms. Kroack and Ms. Bassi confer briefly.)
14 MS. BASSI: According to the language in 9.9 it says to
15 finance the reasonable costs incurred by the Agency in the
16 administration of the NOx trading system.
17 MR. GOODWIN: Okay. Has the Agency made any estimate of
18 what those costs might be?
19 MS. BASSI: Not at this point.
20 MR. GOODWIN: Is that information that you intend to put on
21 the record at this proceeding before the record is closed?
22 MS. BASSI: No. That would be on the record of the Agency
23 rulemaking that would be necessary to set up that particular
24 portion of the program.
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1 MR. GOODWIN: Okay. Now you have collected the fees and
2 you have taken out your administrative costs. What happens to
3 the rest of it.
4 MS. BASSI: We have collected the fees and have taken out
5 our administrative costs?
6 MR. GOODWIN: Yes.
7 MS. BASSI: It is to be disbursed back to those units that
8 are existing at the time. In other words, those units who
9 received allowances from other than the new source set-aside.
10 MR. GOODWIN: Could you explain to me what the rationale is
11 for that particular redistribution of wealth?
12 MS. BASSI: This is part of Section 9.9. It is something
13 that the General Assembly put forth.
14 MR. GOODWIN: So it does not have to have a rationale; is
15 that your meaning?
16 (Laughter.)
17 MS. BASSI: You are asking me to speculate.
18 MR. GOODWIN: Well, I am sure you had nothing to do with
19 the drafting of that legislation.
20 MS. BASSI: This part?
21 MS. KROACK: Mr. Goodwin, really, I am going to have object
22 to that. Section 9.9 was passed by the General Assembly, not by
23 this Agency. To the extent that you have issues with it, we are
24 happy to respond to questions about how we are going to implement
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1 it, but really not to its intent or how it is directed.
2 MR. GOODWIN: I think the reason it is a legitimate
3 question, Ms. Kroack, is that the Agency clearly does have some
4 discretion on the level at which it accepts these fees. And if
5 these fees are being set at a level far greater than is necessary
6 to cover the Agency's administrative costs, so that those
7 additional funds can be distributed to others, it seems to me
8 that the Board has a legitimate reason to know what is the
9 rationale for doing it that way.
10 (Ms. Kroack and Ms. Bassi confer briefly.)
11 MR. LAWLER: I would like to comment on that, too. I think
12 this is not the time to address that. Right now the -- we have
13 said what was in the Act, what the legislature intends and there
14 have to be more proceedings in a different venue to address that
15 question.
16 MR. GOODWIN: Well, you have proposed in this set of rules
17 for the Board to adopt a method for determining the amount of the
18 fee that any individual new EGU is required to pay. So I don't
19 think that you can say that this is not the place to discuss
20 whether or not that formula for setting the amount of the fee is
21 the best way of doing it.
22 MS. KROACK: Well, Mr. Goodwin, Section 9.9 allows us to
23 set these fees and makes these determinations in an Agency
24 proceeding. We did include a reference to that in this rule for
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1 informational purposes for new sources who would be coming into
2 the program. It really was not intended to be a full expression
3 of what the fee is -- what the actual fee is going to be, how we
4 are going to determine our administrative costs or how we are
5 going to circulate those monies back to EGUs.
6 Again, I can understand and accept your comments on what
7 the level of that fee should be, okay. It is a valid comment
8 within the context of the Agency rulemaking. A valid comment
9 would be whether we need to charge a fee at all in the context of
10 the Agency rulemaking. And a description of how we circulate the
11 excess funds back to the regulated community, again, a valid
12 comment within the context of the Agency rulemaking. The
13 inclusion of it in this is for informational purposes, just to
14 tell the sources that we intend to do this because Section 9.9
15 has given us that authority. And to the extent that you have
16 comments on the level of that fee, please make them to the Board.
17 That's great. But we really don't want to get into arguments
18 with you or argumentative about whether we should charge that fee
19 or what it should be.
20 MR. GOODWIN: If the Board adopts that part of the rules as
21 you have proposed it, will that then mean that the Agency is
22 bound to set the fee in accordance with that Board rule and has
23 given up its discretion to do it some other way?
24 MS. KROACK: That's a good question. I am not sure that we
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1 have thought about that. We, in putting this rulemaking forth
2 and adding this language, we really included it in this
3 proceeding for informational purposes to tell new sources that we
4 have this authority. To the extent we make distributions from
5 the new source set-aside you will be charged a fee and they won't
6 be coming to you free. We had not gone through the Agency
7 proceeding. We were doing the Board proceeding first and,
8 obviously, this part will follow. We had not addressed at this
9 point in time exactly how we were going to set our administrative
10 costs.
11 MS. BASSI: Could we have a second, please?
12 (Ms. Kroack and Ms. Bassi confer briefly.)
13 HEARING OFFICER GLENN: Let's break for about --
14 MS. KROACK: We will have another response to Mr. Goodwin's
15 question. We just wanted to --
16 HEARING OFFICER GLENN: Yes, I don't mean to shut this down
17 at all. We just want to stop for a moment. Let's get together
18 again at 11:05 and we will resume with Mr. Goodwin and he will
19 get an answer to his question. Thank you.
20 (Whereupon a short recess was taken.)
21 HEARING OFFICER GLENN: All right. Let's go back on the
22 record, please.
23 MS. KROACK: Mr. Goodwin, we actually took a little closer
24 look at that language and had a discussion about it, and there a
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1 couple of things. We agree that the manner in which we have
2 included it in this rule has invited the Board into the process
3 of how we are going to set that fee. We didn't need to do that.
4 The legislation clearly gives us the authority to do it through
5 Agency rulemakings. However, invited the Board into the process
6 we have said that we were going to charge the average market
7 price. We did say that once we set our administrative costs we
8 would return those to the existing EGUs.
9 The intent of this really was initially informational. We
10 wanted to let new sources know that we were going to charge a
11 fee. We wanted to let them know that we are going to take out
12 our administrative costs. We wanted to let them know that any
13 excess would be returned to existing EGUs.
14 The other point is that we wanted to make sure that they
15 understood that they were not getting an allocation unless they
16 paid for that allocation. As Mr. Romaine points out, and as you,
17 yourself pointed out in your question, your source will have to
18 go for those allowances somewhere, either to the Agency from our
19 pool from the new source set-aside or to the market. To the
20 extent that our fee is the market, then that allows a couple of
21 things. That allows us to collect our administrative costs for
22 this program and it is no more or less, in our opinion, onerous
23 than your other option, which is going to the market. So that is
24 really our answer. That is correct, by the manner in which we
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1 have included this in the rule we have invited the Board into the
2 process of how we determine those fees.
3 MR. GOODWIN: Thank you. I have just one last question
4 concerning the fees. Just so I am sure I understand it
5 correctly, for a new EGU commencing operation in let's say 2003,
6 and subject to the fee, how many years will that EGU be required
7 to pay the fee?
8 MS. BASSI: The EGU would be required to pay the fee for
9 the number of years that it obtains allowances from the new
10 source set-aside. If it commences commercial operation in 2003
11 for the 2000 -- for the 2003 control period, then it would be a
12 period of three years, 2003, 2004 and 2005. By 2006 it would be
13 considered -- it would roll into the existing pool.
14 MR. GOODWIN: And would no longer be required to pay a fee
15 for --
16 MS. BASSI: That's correct.
17 MR. GOODWIN: -- whatever allowances it then --
18 MS. BASSI: That's correct.
19 MR. GOODWIN: Okay. Thank you. Let me move to another
20 subject. The Agency is required to make certain determinations
21 under these rules which appear to be in the nature of permit
22 determinations. It is not clear to me whether or not there will
23 always be a permit document issued which memorializes those
24 determinations. Will there be?
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1 MS. KROACK: Mr. Goodwin, can you clarify what you mean by
2 permit determinations? Can you give us a specific --
3 MR. GOODWIN: Well, the Agency has to make allocations, has
4 to inform all of the recipients of those allocations, what they
5 are to receive from the coming control period. That is a
6 determination. It is not clear to me whether or not that
7 determination then finds its way into the budget permit or not.
8 So let me change the question to that.
9 Does an allocation determination become final at the time
10 the Agency issues the notice to the recipients of the
11 allocations?
12 MS. BASSI: We would not consider the determination of the
13 number of allowances that a unit is to receive to be a permitting
14 determination. The permitting determination or the permitting
15 requirement is simply that the unit have an allowance for each
16 ton of NOx that is emitted during the control period. The
17 allowance -- and then the Agency will be issuing allowances or
18 allocating allowances on an annual basis for three years into the
19 future. It is not something -- you are right. It is not
20 something that would appear in the permit because it is not a
21 permitting determination.
22 MR. GOODWIN: If it is not a permitting determination and
23 if the party disagrees with the Agency's determination, what
24 recourse is there?
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1 (Ms. Kroack and Ms. Bassi confer briefly.)
2 MS. BASSI: First of all, backing up a minute. The
3 requirement under Subpart W is that there be an allowance, that
4 you surrender an allowance for each ton of NOx that is emitted
5 during the season, during the control period. As I said, these
6 are not permitting determinations. These are -- the allowances
7 that we allocate will not exceed 30,701. We recognize that there
8 could be more than 30,701 tons of NOx emitted during a control
9 period in Illinois. Therefore, if it were to be considered
10 something beyond -- if it were to be considered a permitting
11 determination, then theoretically any ton of NOx emitted beyond
12 30,701 would be a violation.
13 So a permit -- to characterize these as a permitting
14 determination, we can't give more then 30,701 allowances out. As
15 far as, then, the recourse if you disagree or if a unit disagrees
16 with the number of allowances that we have issued, under Part 96
17 our provisions allow for a limited level of recourse with USEPA
18 on that matter.
19 MR. GOODWIN: So you are saying that when you issue your
20 allocation of allowances in the spring each year, you will -- you
21 indicated that you would -- that there would be some kind of a
22 public revelation of that information, and each of the EGUs would
23 also get a notice with respect to their particular situation; is
24 that correct?
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1 MS. BASSI: I expect that is what we would do.
2 MR. GOODWIN: Something like that?
3 MS. BASSI: Yes.
4 MR. GOODWIN: All right. Now, at that time, if an EGU does
5 not get the number of allowances that it believes it is entitled
6 to in that allocation, what is its recourse in order to resolve
7 that dispute?
8 MS. BASSI: Part 96 provides for some recourse through
9 USEPA. The recourse may not occur prior to that control period.
10 It might be one that takes place in the future. It is very
11 limited.
12 MR. GOODWIN: So you are saying that you are passing to the
13 USEPA the obligation to resolve any claims of errors on the
14 Agency's part, the IEPA's part?
15 MS. BASSI: It would -- just one second.
16 (Ms. Kroack and Ms. Bassi confer briefly.)
17 MS. BASSI: You are assuming that the error is on our part.
18 MR. GOODWIN: No, I am saying --
19 MS. BASSI: Some of the errors could be on the part of the
20 -- there are corrections to the calculation of heat input and so
21 forth, and that is the type -- and those, as well as the issuance
22 of allowances, are the types of recourse that the USEPA
23 anticipates. There is no -- according to the federal trading
24 program, there is no right to appeal an allocation that is made
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1 to the USEPA, but there is a method to require the USEPA -- there
2 is not a method to require USEPA to reallocate for that period.
3 But any errors that do occur, you know, we would certainly work
4 with the company and USEPA to make whatever corrections could be
5 done.
6 MR. GOODWIN: But that would all be done on a negotiated
7 informal basis and there would be no formal rules of any kind
8 governing the resolution of a dispute over an allocation
9 determination?
10 MS. BASSI: We indicated earlier that there may need to be
11 Agency procedures regarding certain elements of determining the
12 allowances that are to be issued. For example, the rounding
13 convention, we apply the traditional rounding convention and
14 things do not -- they do not prorate nicely. They just don't.
15 To the extent that an error, as you put it, or a dispute might
16 arise out of something like that, then it would be addressed in
17 the Agency rulemaking proceeding, not in this proceeding. To the
18 extent that there is an error in the determination of heat input
19 or in our forwarding to USEPA of the number of allowances that a
20 source is entitled to after, you know, all of the information is
21 in, that is provided for under Part 96.
22 MR. GOODWIN: Okay. For new EGUs -- this is on the subject
23 of permits. For new EGUs for the period between commencement of
24 operation and the date their cap application is due to be filed,
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1 which is one year after they begin operation, as defined in the
2 Title 5 rules, what will be the permit mechanism for this program
3 during that time period?
4 MS. BASSI: The budget permit?
5 MR. GOODWIN: Yes.
6 MS. BASSI: It would be the construction permit. For a new
7 EGU, they -- new EGUs or new sources operate for a period of time
8 pursuant to conditions included in a construction permit, and
9 that construction permit would be deemed for that period of time
10 the budget permit.
11 MR. GOODWIN: So will it be the case that where that
12 construction permit has been issued prior to the effective date
13 of these rules that there will be a need to amend the
14 construction permit to --
15 MS. BASSI: Yes.
16 MR. GOODWIN: -- incorporate these requirements?
17 MS. BASSI: Yes.
18 MR. ROMAINE: Could I just interrupt for a moment?
19 (Mr. Romaine and Ms. Bassi confer briefly.)
20 MS. BASSI: Mr. Romaine points out that we could also do
21 this as part of the acid rain permitting process.
22 MR. GOODWIN: Okay. Overall, is this proposal intended to
23 be fuel neutral, meaning that it intends no preference for one
24 type of fuel, such as natural gas, over some other type of fuel,
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1 such as coal?
2 (Ms. Kroack and Ms. Bassi confer briefly.)
3 MS. BASSI: I don't think that are program could be
4 construed as fuel neutral, although it was not intended or it was
5 not intended to be fuel favoring. It was intended to distribute
6 allowances to as many units as possible in as equitable a manner
7 as we were able to do.
8 MR. GOODWIN: If it is not fuel neutral in its effect, what
9 fuels does it favor?
10 MS. BASSI: It obviously is providing for a higher rate of
11 -- less stringent rate in determining eligibility for allowances
12 for coal-fired units or for units that historically have had
13 higher rates -- that are associated with them. And from what we
14 have been issuing, the rates that we have been issuing new
15 permits or new construction permits for new sources that have
16 natural gas fire, those, the rates we see there are considerably
17 lower. We have structured the eligibility for allowances for
18 these new units to be reflective of that lower rate as we have
19 said earlier, in an attempt to issue as many allowances as
20 possible to as many units as possible.
21 MR. GOODWIN: Okay. But there was not a specific objective
22 for this program of encouraging the use of one fuel over another?
23 MS. BASSI: No.
24 MR. GOODWIN: Is it the case that the thermal efficiency or
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1 the heat rate of a given EGU does not directly affect the
2 allocation of allowances for that EGU?
3 MS. BASSI: The efficiency of it?
4 MR. GOODWIN: Yes.
5 MR. FORBES: That's true.
6 MR. GOODWIN: Okay. Then wouldn't it also be true that all
7 other factors other than heat rate being equal, older relatively
8 inefficient EGUs will be awarded more allowances per megawatt
9 hour of electrical output than will new high-efficiency EGUs?
10 MR. FORBES: Yes, that's true.
11 MR. GOODWIN: Do you think that is good policy for the
12 environment?
13 MS. BASSI: I think that the environment --
14 MR. LAWLER: That is not a question we can really answer,
15 Dan.
16 MR. GOODWIN: Okay. That's all of the questions I have.
17 MS. BASSI: I have one more point to make in response to
18 some questions that you were asking earlier regarding appealing,
19 essentially appealing allocations that we make.
20 The purpose of Subpart W is to set up a mechanism for us to
21 issue allowances. We have described the allocation methodology
22 that we believe is most appropriate for issuing allowances to
23 units that are subject to this program. Subpart W also provides
24 the limitations on emissions of NOx by virtue of the allowances
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1 that we are to allocate.
2 While it is required that sources have a permit that
3 subjects them essentially to the requirements of Subpart W, to
4 assume that there can be a mechanism in the short period of time
5 during which we have to issue allowances for appealing those
6 allocations that are made to the Board and expect the Board to
7 deal with those appeals within that very short period of time
8 would make it unworkable. Hopefully the program -- well, I am
9 confident the program will work quite well, that the -- any
10 disputes over the allowance allocations that are made will be
11 more centered around whether or not we have the right numbers
12 that we are working with at the time. And it will require a
13 great deal of cooperation on the part the account representatives
14 and the Agency in arriving at those allowance allocations before
15 they are issued or conveyed to the USEPA.
16 MR. GOODWIN: Well --
17 MS. BASSI: I am confident --
18 MR. GOODWIN: Is there implied in that, Kathy, that you
19 think that the Agency can resolve any disagreements that may
20 arise within that time frame, even though the Board may not be
21 able to?
22 MS. BASSI: Well, at the time frame that I am talking about
23 with regard to the Board is the 120 days that are available for
24 making permit appeal decisions, is which is the appeal that you
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1 were suggesting that would be appropriate by suggesting that
2 these are permitting determinations. That 120 days won't be
3 there. And to expect the Board to make that kind of
4 determination or that appeal process on this, you know, it would
5 be -- it would probably or it has the potential of expedientially
6 increasing their work load or their case load. I hope -- no.
7 Again, I am confident that we can work out any disputes. I don't
8 think that there will be many, if any.
9 MR. GOODWIN: Well, I hope you are -- for the record, I was
10 not intending to advocate that the permit appeal mechanism was
11 necessarily the best way to do it. I was simply tying to find
12 out what you envisioned.
13 MS. BASSI: Well, you raised a very good issue that we have
14 made note of.
15 MR. GOODWIN: Thank you.
16 HEARING OFFICER GLENN: Thank you, Mr. Goodwin.
17 MR. GOODWIN: Thank you.
18 HEARING OFFICER GLENN: Yes, please, sir.
19 MR. URBASZEWSKI: My name is Brian Urbaszewski. I am the
20 Director of Environmental Health Programs for the American Lung
21 Association of Metropolitan Chicago.
22 My first question is, I think, to Mr. Kaleel on the
23 attainment modeling. You said that demonstration with the 1-hour
24 standard was part of one of three points that this rule was
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1 designed to address. I have questions that revolve around the
2 margin of error on the modeling. The goal of the EGU control
3 system is through a multi-state tradeable system of NOx credits,
4 and basically I am trying to find out, the modeling that was done
5 assumed that the Illinois EGUs emit only the number of tons
6 allowed in the Illinois EPA EGU budget?
7 MR. KALEEL: That's right.
8 MR. URBASZEWSKI: Okay. Taking that, that assumes that
9 there are -- the modeling assumes that the EGUs cannot emit any
10 more NOx than is allocated strictly by the State of Illinois?
11 MR. KALEEL: The total sum of NOx emissions that were
12 incorporated in the model for Illinois matches the budget number.
13 MR. URBASZEWSKI: Okay. Yet Mr. Forbes indicated that
14 USEPA's economic model that assumed growth assumed an eight
15 percent growth, correct?
16 MR. FORBES: That's correct.
17 MR. URBASZEWSKI: Yet Illinois EPA, through communication
18 to USEPA, said that the growth estimate is more in the line of 34
19 percent, correct?
20 MR. FORBES: That was our original estimate.
21 MR. URBASZEWSKI: Then you were very careful in what you
22 said, Mr. Forbes, and said that the USEPA likely assume that
23 there would be trading between the states. But you didn't make
24 an indication as to which way you thought the trading would go.
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1 Based on what has been said so far, and in my estimation, you
2 would see Illinois as a net NOx importer that although we have a
3 state budget the EGUs in the state would have to emit more than
4 that budget allows, so we would be underestimating the actual
5 amount of NOx that is being emitted from EGUs in the attainment
6 demonstration, correct?
7 MR. LAWLER: Is that -- are we at the question, Brian?
8 (Laughter.)
9 MR. URBASZEWSKI: Yes. I may have follow-up to this one.
10 MR. LAWLER: I think what -- to answer that, you have to
11 say -- first of all, you have kind of taken a bunch of different
12 numbers from a bunch of different places and you have drawn some
13 conclusions from them that we might not necessarily draw. As
14 part of a multi-state trading program, the ultimate assumption is
15 that everything ends up balancing out. That you have trades that
16 go this way, you have trades that go that way, and it is driven
17 on economics, it is driven, you know -- and it happens where it
18 needs to happen.
19 And if years from now we get to a point where we see that
20 there has been an influx of a bunch of additional emissions in
21 Illinois and we couldn't show attainment anymore, then we would
22 have to come back to the Board again probably and propose some
23 new regulations specific to Illinois or a group of Illinois
24 sources. But we don't expect that we are going to have to do
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1 that and the federal trading program assumes that that is not
2 going to happen. It assumes that everything is going to balance
3 itself out.
4 MR. URBASZEWSKI: Okay. My question was more to the point
5 of is there a margin of error? And in Mr. Kaleel's Figure 7
6 there are very exact bars saying 0.25 is right about at the max,
7 and the NOx SIP Call and the 0.15 level is perhaps a little below
8 it. But there is no mechanism to account for uncertainty in what
9 the actual emissions are going to be. The reason I brought up
10 the fact that I thought Illinois would have more NOx emissions
11 than are actually budgeted for in the attainment demonstration
12 modeling is that this has happened in the past under the sulfur
13 trading program for acid rain. Illinois, I believe, is a net
14 importer of sulfur oxide credits, meaning other states -- overall
15 in the entire system everybody met the requirements. Illinois
16 reduced far less than other states, though. So there was
17 actually more sulfur in Illinois than you would expect from a
18 level trading program across the country, where every state did
19 emit at the overall level as opposed to an average level.
20 So the fact that it has happened in Illinois, with respect
21 to sulfur oxides, I would expect that the Agency would come up
22 with a contingency plan, given the demands that you estimate are
23 out there for electricity and future capacity, that there would
24 be some way of dealing with this in the rule rather than leaving
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1 it up to, you know, in the future coming before the Board. Why
2 fix something after it is broken when you know it may have
3 problems right now and anticipate them?
4 MR. LAWLER: Well, again, it is not a problem that we think
5 will happen. If it should happen we have really got -- in the
6 case of the Chicago area we have until 2007 when we have to
7 demonstrate attainment. If we see something happening that we
8 are not expecting, and that is always possible in anything, if we
9 see a massive influx in emissions into the state and we think we
10 are not going to be able to any longer demonstrate attainment, we
11 will have to be back doing something about it. At this point we
12 don't expect it.
13 MR. URBASZEWSKI: A second point to just clarify yet
14 another reason why I think this is important, you noted that
15 within USEPA's modeling domain you expect or they expect
16 everything to even out and trading will settle between the
17 states. Yet there are specific meteorological considerations
18 with NOx. One is that it is unlikely, very unlikely that much of
19 the NOx emitted in New York or Massachusetts is ever going to
20 arrive going east to west, back into Illinois. The general flow
21 across the country is west to east. Therefore, there are not
22 many NOx sources that are directly up wind during the summer
23 control period so --
24 HEARING OFFICER GLENN: Mr. Urbaszewski, I hate to cut you
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1 off. You are sort of getting into some testimony, I think.
2 MR. URBASZEWSKI: Okay.
3 HEARING OFFICER GLENN: We would rather hear your testimony
4 at the second batch of hearings. If you could just direct a
5 question to the Agency.
6 MR. URBASZEWSKI: Okay. I have two more questions.
7 HEARING OFFICER GLENN: Thank you.
8 MR. URBASZEWSKI: I also wanted to ask Mr. Lawler again how
9 many exceedances of the eight hour standard did we have last
10 year? Would you say it was above 20?
11 MR. LAWLER: Actually, I said the eight hour standard is
12 not really involved with what we are doing right now. This is --
13 what we are looking at is the 1-hour air quality standard that we
14 have to have the attainment demonstrations for. The NOx SIP Call
15 is supposed to address the 1-hour attainment demonstration. So
16 while there may be an eight hour standard that we all think is
17 going to come on the horizon out there, I don't know the answer
18 to that question. It is really not part of this.
19 MR. URBASZEWSKI: Okay. I just wanted to address this to
20 you (indicating the Board Members). I believe that the Board has
21 to implement rules that provide for public health of all the
22 Illinois citizens. The air quality index used by the USEPA uses
23 the level of an eight hour standard to determine health. So I
24 wanted to see if -- how far does this rule go in addressing that
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1 health issue. May I ask that question or is that also --
2 HEARING OFFICER GLENN: You can ask that question. We are
3 not going to be answering questions today. If you would like to
4 --
5 MR. URBASZEWSKI: No, to Mr. Lawler.
6 HEARING OFFICER GLENN: To Mr. Lawler. I think Mr. Lawler
7 did answer that this rule does not --
8 MR. URBASZEWSKI: So the health issue is irrelevant in this
9 rulemaking?
10 HEARING OFFICER GLENN: I am not going to say the health
11 issue is irrelevant.
12 Mr. Lawler, do you want to answer that question, or would
13 you like to respond to that in written comments or do you feel
14 that that is not relevant?
15 MS. KROACK: It is truly not relevant to this rulemaking,
16 Mr. Urbaszewski, because we are not dealing with the eight hour
17 standard, which as you know, has been remanded and while we have
18 to be planning for it, there is no requirement to implement it on
19 any jurisdiction in the United States, much less Illinois. But
20 we understand that it is out there and we understand that it may
21 be coming.
22 We have some preliminary information. I don't know how
23 correct it is and to the extent that Mr. Lawler can answer that
24 off-the-cuff, he is welcome to do so. I am not sure what
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1 information he has with him. It is really our statement to the
2 Board Members and in this proceeding in general that the eight
3 hour standard is not really relevant to the attainment of the
4 1-hour standard the SIP Call.
5 MR. URBASZEWSKI: I was not particularly asking about the
6 eight hour standard. I am saying that the level of ozone in
7 ambient air that is determined to be unhealthful for sensitive
8 groups is equivalent to the 1-hour standard, but currently under
9 the air quality index, the system that the USEPA asks states to
10 use to provide air quality information to the public, it has
11 independently determined that that level of ozone is unhealthy,
12 irrespective of the enforcement issues over the eight hour
13 standard. It is a medical determination and not a legal
14 determination on an enforceable standard.
15 MR. LAWLER: We do have the number of the eight hour
16 exceedances from last year that Rob can provide that information
17 just for the record if the Board wants it.
18 BOARD MEMBER FLEMAL: Yes.
19 HEARING OFFICER GLENN: Certainly. Go right ahead,
20 please.
21 MR. KALEEL: I think just factually to answer your
22 question, Brian, there is a table of numbers that my staff had
23 provided me that gives the number of exceedance days in the Lake
24 Michigan region. It is not specific to Chicago, but includes all
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1 of the monitoring sites in the Lake Michigan region. In 1999
2 there were 36 exceedance days of the eight hour standard.
3 MR. URBASZEWSKI: The reason I asked that was to illustrate
4 not our progress or lack of progress towards meeting an eight
5 hour enforceable standard, but just to show that irrespective of
6 the exhibits that were shown by the state agency, that there were
7 only very few exceedances of the 1-hour standard and that the
8 ozone level that is determined to be unhealthful for sensitive
9 groups is still significant. That was my reason for asking.
10 HEARING OFFICER GLENN: Thank you.
11 MR. URBASZEWSKI: My last question revolves around the fact
12 that USEPA also provided several guidance documents on
13 encouraging states to provide for an energy efficiency and
14 renewable energy set-aside. And structurally it would be similar
15 to a new source set-aside within the context of the rule.
16 New York has incorporated this energy efficiency renewable
17 energy set-aside in their rule. The idea that it would provide
18 electric power through renewable energy or through energy
19 efficiency methods without producing the pollution or producing
20 greatly reduced amounts of pollution. I have suggested this to
21 the Agency.
22 I wanted to know what the rationale basis was for rejecting
23 this suggested program that the USEPA put together?
24 MS. BASSI: During the course of development of this rule,
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1 I can confirm that Mr. Urbaszewski did suggest that we provide
2 set-aside for energy efficiency, and that at least New York and I
3 was thinking Massachusetts had also included this or was planning
4 to include this set-aside. It was a determination -- it was just
5 something that we did not include. In the development of the
6 rule as we were meeting with various groups, it was not something
7 that received that great of a level of support, but Mr.
8 Urbaszewski was insistent.
9 MR. URBASZEWSKI: Thank you for the opportunity.
10 HEARING OFFICER GLENN: Thank you for your questions, Mr.
11 Urbaszewski.
12 Are there further questions this morning? I tell you what,
13 Mr. McGervey, why don't we have you and followed by Mr. Murray.
14 Would that be all right? Alphabetical.
15 MR. McGERVEY: Joe McGervey again from earlier. I have a
16 follow-up question on a subject that Daniel Goodwin brought up
17 earlier about the use of an allocation mechanism based on pounds
18 per million btu versus pounds per megawatt hour of generation.
19 My understanding is that the way the cap and trade system would
20 work is that there is a budget region-wide for NOx in that
21 however the allocations are done, whether the allocations are
22 given to renewables or new sources or existing sources, or
23 however it is done, that generally in the long-run emissions will
24 be approximately the cap, no matter how those other variables
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1 play out. So there may not be a direct environmental benefit but
2 it seems there may be a -- an efficiency benefit, a cost benefit
3 that may be there if the allocations were done on an output basis
4 versus an input basis.
5 My question is did the state consider using an output basis
6 for making these allocations in the program and just how that
7 decision came about?
8 MS. BASSI: We discussed very briefly an output based
9 allocation methodology. USEPA has included this as one of the
10 amendments to Part 97 that I had alluded to earlier, but they do
11 not have -- even USEPA has not yet figured out how they would
12 proceed with allocating allowances on an output based approach.
13 For those -- because of that reason, because of many reasons, we
14 decided to proceed with heat input as the basis for allocations.
15 MR. McGERVEY: Is that something that -- well, I guess the
16 way the rule is written, that is something that will happen but
17 could be changed in the future --
18 MS. BASSI: Rules can be amended.
19 MR. McGERVEY: -- at additional rulemakings? Okay. It
20 seemed to me that megawatt hour generation is something that EGUs
21 would keep very good track of and there should be data on that
22 somewhere to use.
23 MS. BASSI: And that was part of our problem. We have
24 traditionally dealt with emissions and the emissions were
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1 determined by heat input, and so it seemed an approach that was
2 more easily verified by us than the output.
3 MR. McGERVEY: Okay. Thank you.
4 HEARING OFFICER GLENN: Thank you, Mr. McGervey. All
5 right, Mr. Murray.
6 MR. MURRAY: Yes. Thanks. I also had some questions
7 raised by Mr. Goodwin that leads me to believe we need to clarify
8 a few things.
9 Ms. Bassi, the allowance price that you quoted from Air
10 Daily quoting Canter Fitzgerald's index, was that a vintage 2003
11 allowance?
12 MS. BASSI: I don't know, Mr. Murray. I just -- I check
13 that every once in awhile in the Air Daily just to keep kind of a
14 ballpark idea of what NOx allowances are going for. I have not
15 noticed that they attach a vintage to them, although I am sure
16 they do.
17 MR. MURRAY: Let me ask this, then. Is that -- are you
18 aware as to the source of that market that they are quoting?
19 MS. BASSI: No, I guess not.
20 MR. MURRAY: If I suggested that it was the Ozone Transport
21 Region --
22 MS. BASSI: Oh.
23 MR. MURRAY: -- would that --
24 MS. BASSI: Yes.
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1 MR. MURRAY: Okay. So the Canter Fitzgerald prices quoted
2 is the Ozone Transport Region price?
3 MS. BASSI: That's correct.
4 MR. MURRAY: Are the allowances currently trading in the
5 Ozone Transport Region allowances that would be tradeable in this
6 program?
7 MS. BASSI: Part 96 limits the number of allowances that
8 the states in the Ozone Transport Region can carry into this
9 particular program. Essentially it is limited to whatever number
10 of allowances they would be given, if you will, under the
11 Compliance Supplement Pool, as I understand it. But the Ozone
12 Transport Region is proceeding with its NOx trading program now
13 as part of its memorandum of agreement for the regional
14 attainment approach that the OTR is taking. USEPA is
15 administering that trading program and it is expected to flow
16 into this one, but only to that limited extent, this one will
17 overtake that one.
18 MR. MURRAY: Are you aware of any unusual factors that are
19 occurring in the northeast this year that might influence the
20 price?
21 MS. BASSI: No.
22 MR. MURRAY: You are not aware that the weather in the
23 northeast has been primarily cool and rainy?
24 MS. BASSI: No, I have not paid attention to the northeast.
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1 I have been paying attention to Illinois, though.
2 MR. MURRAY: With regard to new sources and the requirement
3 that they are going to need to buy allowances from the state at
4 first, if my organization wants to bring a new unit on line, say
5 in 2005, and not retiring any units, how do I get allowances for
6 that unit?
7 MS. BASSI: You would have to apply for allowances from the
8 new source set-aside and you would have to pay the fee.
9 MR. ROMAINE: Now, you are not prohibited from buying
10 allowances on the open market.
11 MR. MURRAY: Oh, I understand that. The point I wanted to
12 make is that everybody is in this same boat.
13 MS. BASSI: That's correct.
14 MR. MURRAY: We all have to buy allowances, and we are all
15 going to have to pay whatever the price is, whether it is the
16 price for set-aside set by the pool or out on the market,
17 whatever that may be.
18 Continuing further, we have had some discussion -- at least
19 I tried to have some discussion that the affect of this program
20 is that it is really more than a 0.15 reduction or a reduction
21 below 0.15 because of the way growth has been handled. It would
22 seem to me, and I guess I am looking for a concurrence, that all
23 of the sources are going to have to make a series of decisions on
24 whether they are going to be buying in the market or buying or
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1 producing more reductions.
2 Has the Agency reached a conclusion as to whether there is
3 any correlation between the cost and effectiveness of those
4 additional tons of removal versus what it costs just to get down
5 to the 0.15?
6 MS. BASSI: Our cost analysis -- and perhaps Mr. Forbes
7 should address this. Our cost analysis was based upon the --
8 (Mr. Forbes and Ms. Bassi confer briefly.)
9 MS. BASSI: Our cost analysis was based upon -- essentially
10 upon the analysis that USEPA performed on the region-wide basis.
11 MR. MURRAY: If I was to conclude that it would cost our
12 system approximately $5,000.00 a ton to reduce from a .2 to a .1,
13 the incremental cost for NOx, would that seem to be something
14 that would be beyond the Agency's expectations?
15 (Ms. Kroack, Ms. Bassi and Mr. Forbes confer briefly.)
16 MR. FORBES: I guess we wouldn't necessarily be surprised
17 by that cost but, again, we are looking at the overall cost
18 effectiveness of the program.
19 MR. MURRAY: I understand. But in terms of the decision
20 that the EGUs have to make, they either have to make these costly
21 control expenditures to achieve these reductions or go out and
22 buy the same allowances that everybody else is going to be trying
23 to buy. So the point I am trying to make is is there any real
24 difference between the treatment of the two types of sources in
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1 that respect?
2 MR. FORBES: Between new sources and --
3 MR. MURRAY: And existing sources?
4 MR. FORBES: -- existing sources? Probably in that sense
5 it is not. I mean, they are all complex questions, depending on
6 the kind of control, the type of existing arrangement, fuel type,
7 load arrangement. I mean, all of those things vary from one unit
8 to another. New sources have to make the same kind of decisions.
9 MR. MURRAY: And with regard to the acid rain program, is
10 there anybody in the Agency that can address acid rain issues?
11 MS. KROACK: It would depend on the question.
12 MR. MURRAY: Is there a new source set-aside in the acid
13 rain program?
14 MR. ROMAINE: I don't believe there is.
15 MR. MURRAY: And all sources, all new sources that came
16 into existence since that program was instituted I believe in the
17 Clean Air Act amendments of 1990, that weren't existing units in
18 1990 have had to buy allowances to operate?
19 MR. ROMAINE: They had to acquire allowances if they were
20 big enough to be subject to the program, yes.
21 MR. MURRAY: So this program is not setting a precedent for
22 new sources to have to buy allowances?
23 MR. ROMAINE: No, it is certainly not.
24 MR. MURRAY: Thank you. That's all of the questions I
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1 have.
2 HEARING OFFICER GLENN: Thank you, Mr. Murray. Are there
3 further questions this morning?
4 Okay. I think we are going to go to the Board Members,
5 then.
6 BOARD MEMBER MELAS: I think this question would be
7 directed to Mr. Forbes. Help me understand the meaning of the
8 growth factor. Are you measuring the economic growth? Are you
9 measuring heat input? Exactly what is it? Because I have heard
10 five percent. I have heard eight percent. I have heard 34
11 percent. I would just like to get an understanding of what
12 exactly is it that we are projecting or measuring.
13 MR. FORBES: What the EPA was trying to estimate was the
14 amount of increase in utility generation that would occur between
15 1996 and 2007, so that they could determine what the emissions
16 increase would be due to that additional electrical generation.
17 They used a model called the integrated planning model, and that
18 model incorporated all kinds of factors, including economic
19 factors, fuel costs, electricity demand, deregulation, emissions
20 market trading, all of those kinds of things were factored into
21 this model to project what the increase in emissions ultimately
22 would be. That factor turned out to be eight percent, such that
23 the factor was 1.08 that you would multiply in 1996 the input by
24 in order to estimate 2007 heat input. At that point they could
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1 then calculate what the emission level would be and use a control
2 emission rate of 0.15 pounds per million btu times that projected
3 2007 rate. That particular growth rate is specific for Illinois.
4 The EPA determined for each of the 23 jurisdictions what their
5 particular growth rates would be from the IPM modeling they did.
6 BOARD MEMBER KEZELIS: What was the range of growth among
7 the states, if you can tell us?
8 MR. FORBES: I am not sure that -- what I recall the range
9 was -- I know we had eight percent. I think there were some
10 states that had over 20 percent in terms of their growth rates.
11 We will see if we can find that in the support documents to the
12 SIP Call.
13 MS. KROACK: If we can't answer that today or before we
14 will get back to you. We will answer that.
15 BOARD MEMBER KEZELIS: Okay.
16 BOARD MEMBER FLEMAL: I have a series of questions I would
17 like to pose to the Agency, but before doing so I would like to
18 complement the Agency on the thoroughness of their presentation
19 to the Board. It has helped me, who had to start fairly low down
20 on the learning curve on this topic, to at least try to get up to
21 the speed necessary to understand what is going on in this
22 proceeding.
23 I trust that the regulated community will in the future
24 hearing assist me further along that learning curve. I know
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1 there is some perspectives that are obvious in the questioning
2 that we are hearing that may not be the same perspective that the
3 Agency had in its presentation. I certainly look forward to our
4 next hearing to have you share with us that additional part of
5 the understanding that the Board is going to have to have to make
6 the necessary decisions in this rulemaking.
7 The questions that I have are largely of the sort of
8 questions that I believe are worth addressing to the extent that
9 it would be useful to have the record reflect some additional
10 bits of information or expansions on the information that the
11 Agency has already presented to us. I have tried to organize
12 these a bit, although they may seem to wonder, let me at least
13 try to do them in some categories.
14 There are several questions that I have that are of the
15 terminology sort that I think would be useful for the record to
16 reflect on. Let me begin that by noting that in much of what the
17 Board has dealt with previously regarding ozone nonattainment
18 areas, we have used the term Chicago nonattainment area to refer
19 to that portion of the nonattainment area in the northeastern
20 part of the State of Illinois. In fact, we have a whole part of
21 our regulations that deal specifically under -- in its very title
22 with the Chicago nonattainment area. One can't help but notice
23 in the presentations of the Agency at least in most of the places
24 that that term is not used. We are talking now about the Lake
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1 Michigan nonattainment area. There is a similar change for
2 difference in use of the terminology for the Southwestern
3 Illinois nonattainment area where that has become the
4 Metro-East/St. Louis nonattainment area.
5 My question with that preface is why are we changing the
6 terms and is there any regulatory significance in the fact that
7 this terminology is today different?
8 MR. LAWLER: I guess the answer to the last part of your
9 question really is from an Illinois standpoint there is no
10 regulatory importance to the fact that we use different terms, a
11 little bit different terms. What we have referred to as the Lake
12 Michigan nonattainment area is the nonattainment counties in the
13 states that are around Lake Michigan, and it includes Wisconsin,
14 Illinois, Indiana and did include some Michigan counties. So
15 just in terms of when we look at the air quality, or when we look
16 at the air monitoring data or the modeling data we usually just
17 refer to it as Lake Michigan nonattainment area because we are
18 trying to solve the whole Lake Michigan problem, because Illinois
19 sources do contribute to the other states also. As far as the
20 official attainment area in Illinois, it is six counties and the
21 parts of two other counties that you are familiar with.
22 In the Metro-East area it is kind of a similar situation.
23 USEPA sort of sees the whole urbanized area of St. Louis and then
24 the Metro-East Illinois side as one area together. And so when
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1 we model it or when we talk about it or when we look at
2 monitoring data, since the flow of ozone does not stop at the
3 state, we talk about the area as a whole. But from an Illinois
4 standpoint, the nonattainment area is the three counties in the
5 Metro-East, Madison, Monroe and St. Clair Counties.
6 BOARD MEMBER FLEMAL: I take it, then, that your answer to
7 the -- what was the second part of that question, that there is
8 no regulatory consequence in this change in terminology, that
9 that is your answer, that there is no regulatory consequence.
10 MR. LAWLER: Right, right.
11 BOARD MEMBER FLEMAL: Okay.
12 MR. LAWLER: I could add just a little bit, another point to
13 that is really in the official designations that USEPA makes, it
14 is considered multi-state nonattainment area in both of those.
15 But, again, from an Illinois standpoint and for our regulations,
16 the nonattainment areas are the ones that you are familiar with.
17 BOARD MEMBER FLEMAL: In the attempts to determine, by a
18 modeling, what the resultant ozone concentrations would be,
19 occasioned by the NOx regulations, there are several times the
20 term is mention of the NOx disbenefit. Could it be explained,
21 for the record, what is the NOx disbenefit, and how it functions
22 and what its magnitude is?
23 MR. KALEEL: The term NOx disbenefit -- I think what it
24 refers to is a particular phenomenon that we see in the
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1 atmosphere in a chemical reaction related to nitrogen oxide, one
2 component of what we call NOx, just the NO or the nitrogen oxide
3 part, that initially upon release to the atmosphere actually
4 breaks down ozone molecules. It scavenges or titrates, I guess,
5 are other terminologies that have been used. It will break down
6 an ozone molecule.
7 The tendency for that phenomenon to occur, it typically
8 happens fairly quickly, close to an emission source, and does not
9 necessarily extend to a great distance downwind. It depends on a
10 great deal on the mix of VOCs and NOx in that particular airshed.
11 So the magnitude of it almost varies on a day-to-day basis as the
12 relative mix of precursors change on a day-to-day basis. It is
13 typical for a particular ozone episode to start with fairly
14 limited amounts of VOC and then for those VOC concentrations to
15 increase on successive days and that changes the signal or the
16 response of the system to the introduction of NOx or specifically
17 NO emissions.
18 So the magnitude changes on a day-to-day basis. Early in
19 an ozone episode the airshed is very responsive to NO emissions.
20 A scavenging phenomenon of 10 parts per billion, 15 parts per
21 billion is not unusual. Late in an ozone episode that scavenging
22 phenomenon might be very small or even completely absent. So it
23 isn't always there of the same magnitude.
24 BOARD MEMBER FLEMAL: Would it be correct, then, to draw
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1 the conclusion that the NOx disbenefit is a phenomenon that
2 occurs mostly proximal to emissions sources because of the time?
3 MR. KALEEL: I think that is a pretty good assumption. It
4 is a phenomenon that certainly is evident within the Chicago
5 nonattainment area, perhaps more so in Chicago than in other
6 places in the country. The effect is typically seen in the model
7 30 to 50 miles from the Chicago area downwind, so it does extend
8 to some distance and, again, that varies on a day-to-day basis.
9 BOARD MEMBER FLEMAL: And the reason for that proximate
10 location to Chicago is because of the NO emissions associated
11 with the Chicago area itself?
12 MR. KALEEL: It relates to the relative amounts of VOC and
13 NOx in the atmosphere. It seems to be a fairly unique
14 characteristic of Chicago that our ozone episodes are limited in
15 the amounts of VOC emissions that are present in the atmosphere
16 and a relative abundance of NOx emissions and it is not just
17 point sources that contribute to that relative balance. A large
18 measure of it, and maybe even the majority of it is due to the
19 presence of motor vehicles and the emissions of NOx from motor
20 vehicles.
21 BOARD MEMBER FLEMAL: I see. My recollection is that early
22 in our understanding of the generation of ozone there was some
23 feeling that controlling NOx was, in fact, counter-productive
24 because of this disbenefit. First, am I correct that that at one
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1 time that was a perspective?
2 MR. KALEEL: I think that is still our perspective, that
3 there are certainly days that we are trying to model and try and
4 plan and account for in our attainment demonstration that local
5 NOx controls are not all that helpful. What I mean by local, the
6 controls right within the Chicago nonattainment area. The
7 further away those NOx controls occur, the less important the
8 disbenefit phenomenon is in effecting the areas peak
9 concentration. So we typically try to think of the best control
10 path, and this was one of the findings of OTAG. And it has been
11 a finding that we have made pretty consistently through the years
12 that the best control strategy for reducing ozone in the Chicago
13 area near the nonattainment area would be a combination of
14 regional NOx controls, in other words, widespread NOx controls
15 with a focus of VOC controls within the nonattainment area.
16 BOARD MEMBER FLEMAL: Another term which has been in the
17 record so far fairly extensively that I think may be useful to
18 explore is the term model rule. I believe Ms. Bassi referred to
19 that commonly. Can you define for us what is the model rule,
20 where that occurs?
21 MS BASSI: The model rule is what USEPA promulgated at 40
22 CFR Part 96.
23 BOARD MEMBER FLEMAL: It is synonymous, then, with Part 96,
24 when we are talking about the model rule?
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1 MS. BASSI: That's correct.
2 BOARD MEMBER FLEMAL: That's the promulgation that was back
3 in October of 1998; is that correct?
4 MS. BASSI: Yes.
5 BOARD MEMBER FLEMAL: Has that been modified in terms of
6 actual modifications of Part 96 at any time since October of
7 1998?
8 MS. BASSI: No. Part 96 has not been amended.
9 BOARD MEMBER FLEMAL: Okay. I would like to turn to the
10 prefiled testimony of Mr. Forbes. There are a number of portions
11 of that testimony that I would like to explore a bit further.
12 I think perhaps the best way to do that would be maybe to
13 ask Mr. Forbes first to, if you would, be so kind as to summarize
14 a few portions and then that will allow us to focus on some of
15 the particulars in them or in that portion.
16 I would like to begin with the testimony that is in -- for
17 the record, I would note that I am referring to Exhibit Number
18 27, which is the prefiled testimony of Richard Forbes. I would
19 like to begin with that portion of the testimony that beings on
20 page four at the bottom and runs through the middle portion of
21 page six. It is entitled types of EGUs and associated NOx
22 emissions. Would you be so kind, Mr. Forbes, to just summarize
23 for us what it is that this particular portion of your testimony
24 does, what is the information that is there?
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1 MR. FORBES: Okay. This part of the testimony was trying
2 to identify the types of EGUs that are covered by the proposal
3 and also the associated NOx emissions. To kind of summarize, I
4 guess I will just go through the groups here. The units that are
5 covered by the proposal having the highest total NOx emissions in
6 Illinois are the coal-fired cyclone boilers, having uncontrolled
7 emission rates ranging from 0.8 to 2.0 pounds per million btu's.
8 There are 22 cyclone boilers affected by the proposed
9 regulations, having projected base 2007 NOx emissions of 58,146
10 tons during the May 1st through September 30th control period.
11 The units having the second highest total NOx emissions are
12 tangentially-fired dry bottom pulverized coal boilers, having
13 uncontrolled NOx emissions ranging from 0.4 to 1.0 pounds per
14 million btu. Projected base 2007 NOx emissions from the 34
15 tangentially-fired dry bottom pulverized coal boilers affected by
16 the proposal total 44,239 tons during the control period.
17 Wall-fired dry bottom pulverized coal boilers are the third
18 largest NOx emitting category of units affected by the proposal.
19 There are eight wall-fired boilers of this type covered by the
20 proposal, having projected base 2007 control period NOx emissions
21 of 9,383 tons.
22 The fourth NOx emitting category EGUs affected by the
23 proposal are gas and oil-fired boilers. There are 25 of these
24 types of boilers impacted by the proposal, accounting for 2,294
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1 tons of base control period NOx emissions in 2007.
2 Then the last category of EGUs affected by the proposal are
3 gas turbines. There are 14 gas turbines affected by the
4 proposal. Their NOx emissions are 2,416 tons for the 2007 base
5 control period.
6 BOARD MEMBER FLEMAL: Thank you. Now, I have attempted to
7 add up the total number of affected units in those five
8 categories that you mentioned. I come up with 103. I know that
9 number has been used before, so I take it the 103 affected units
10 are those that you have identified.
11 MR. FORBES: Yes, that's correct.
12 BOARD MEMBER FLEMAL: And 64 of those are coal-fired.
13 Those are the first three categories, the sum of which is there
14 are 22, 34 and eight?
15 MR. FORBES: That's correct.
16 BOARD MEMBER FLEMAL: When you say these are the affected
17 units, how does that relate to the use of the terms existing and
18 new? Of these 103, are they all existing.
19 MR. FORBES: Those are all existing units.
20 BOARD MEMBER FLEMAL: So this 103 does not include any
21 units that have commenced operation after 1995, is that my
22 understanding?
23 MR. FORBES: That's correct.
24 BOARD MEMBER FLEMAL: Do you have any idea how many such
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1 units there are posed in 1995 who fall in the new category?
2 MR. FORBES: Mr. Romaine, I believe, has that information.
3 MR. ROMAINE: We have a rough idea. If you look at the
4 number of applications and permits that have been issued for new
5 gas turbine facilities, we have roughly 200 new individual
6 turbines that could conceivably be subject to the rule at this
7 point if they were all actually built and developed. In terms of
8 the number that are actually under construction or operating at
9 this point, 70 new units that we are fairly certain will all come
10 to pass. That does not include the new boiler that Mr. Goodwin
11 referred to, the boiler facility that has just came in. The
12 application just came in to us in the last couple of weeks. It
13 is a dynamic number with regard to new EGUs.
14 BOARD MEMBER FLEMAL: In awareness that that is a dynamic
15 number, we are nonetheless talking about a population of units at
16 this stage in time which is roughly 170? That is 100 existing
17 category, 70 new category?
18 MR. ROMAINE: That's correct, looking at the 70 that are
19 actually permitted or under construction.
20 BOARD MEMBER FLEMAL: That is an in counting number.
21 That's the number of units that is obviously not reflecting size
22 of unit or emissions of unit. Let's explore that part of the
23 number game here, if we might.
24 The 103 units that are referred to here, my understanding
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1 with the numbers are that the uncontrolled base emissions for
2 those 103 units is the number 116,478 tons.
3 MR. FORBES: That is correct. However, when you motioned
4 uncontrolled, these -- it is not exactly true that they are
5 uncontrolled. This represents the estimated 2007 base emissions
6 and that would include any acid rain phase one or phase two
7 control limits that would apply to them.
8 BOARD MEMBER FLEMAL: You are actually one step ahead of me
9 on there. So let's go to that spot first. The unit, if you
10 like, of emissions is that uncontrolled emission. Can you
11 explain to me how you determined -- where does that number come
12 from? What does uncontrolled mission mean, starting perhaps with
13 the 1995 data? Where does that number come from?
14 MR. FORBES: Well --
15 BOARD MEMBER FLEMAL: Is it a theoretical emission even in
16 the 1995 data, or is that what was actual --
17 MR. FORBES: Okay. 1995 actual emissions are -- 1995
18 emissions are actual emissions based on data that was reported by
19 each of the utilities in the 103 numbered group to the acid rain
20 divisions program. They are required to submit actual emissions
21 based on continuous emission monitors. So those represent actual
22 emissions.
23 BOARD MEMBER FLEMAL: Those are actual emissions. Were
24 some of those emissions controlled emissions in 1995 in the sense
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1 that there was some kind of control device intending to reduce
2 the total NOx emissions present in 1995?
3 MR. FORBES: Yes, some were controlled.
4 BOARD MEMBER FLEMAL: But not all?
5 MR. FORBES: But not all.
6 BOARD MEMBER FLEMAL: Okay. There is no credit in effect
7 for facilities that try to get ahead of the game as early as
8 1995, in terms of NOx reductions?
9 MR. FORBES: Not in the sense of an allowance or credit as
10 such that would be issued in the program. Of course, the acid
11 rain program has two phases of controls, phase one and phase two.
12 Phase one is applicable in 1995 to those units subject to phase
13 one and then phase two, that goes -- that went into effect in
14 2000. I believe all of the units are subject to either phase one
15 or phase two of the acid rain program, or coal-fired units, one
16 or the other.
17 BOARD MEMBER FLEMAL: The 70 or so new units, do we have
18 any estimation of what their emissions, NOx emissions are either
19 at some base time or projected out to 2007?
20 MR. ROMAINE: The only emission data that we have for those
21 facilities in total is their permitted emissions that we have
22 issued permits for these facilities. While some of them are
23 operating, most of them have not begun operation. We don't have
24 emissions data for those. In terms of permitted seasonal
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1 emissions from those facilities, it is probably somewhere in the
2 order of 4,500 tons of NOx.
3 BOARD MEMBER FLEMAL: So something roughly 40 percent -- I
4 did that math fast in my head -- of the existing units? I am
5 trying to get some balance of where our emissions are projected
6 to come from.
7 MR. ROMAINE: Well, I guess I would caution simply that the
8 majority of those emissions are coming from peaker facilities.
9 Peaker facilities aren't getting themselves permitted for maximum
10 utilization of those facilities quite frequently at the 245 ton
11 per year range for the minor sources, with some higher number, in
12 fact, gone through major source permitting. It is difficult for
13 us to actually project what level of utilization will occur for
14 those facilities. All we can say is that the total permitted
15 emissions from this group is on the order of 4,500 tons. So that
16 is -- I guess the main difference, I think, is that the number
17 for the existing units is, in fact, actual emission data
18 reflecting the actual utilization. The data for new facilities
19 for the most part is simply projected.
20 BOARD MEMBER FLEMAL: I think I just heard you say 4,500
21 tons, not 45,000.
22 MR. ROMAINE: Oh, I am sorry.
23 BOARD MEMBER FLEMAL: I think the first time I -- got
24 another decimal twice in there. Okay.
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1 BOARD MEMBER FLEMAL: Back to Mr. Forbes' prepared
2 testimony. There is present as part of the testimony an
3 attachment which consists of both a map which locates 24 sources
4 and then a table which I believe correlates directly to that map
5 in which there are names, counties and the nearest county town
6 for those 24 sources. First off, am I correct in my
7 understanding of the nexus between your two attachments?
8 MR. FORBES: Yes.
9 BOARD MEMBER FLEMAL: One is the location and the other is
10 the list. How do these 24 named facilities relate to the 103
11 facilities in your presentation and the Appendix F facilities?
12 What is the way that these work together?
13 MR. FORBES: Okay. This map and the list attached actually
14 identify all of the 103 units. For example, if you look at -- on
15 the table of Existing EGUs Impacted by Proposed Rulemaking R01-9,
16 point number one being the Hutsonville, it is Ameren, EGC. What
17 this is intended to do is to identify the location of the
18 facilities. For example, Hutsonville station actually has two
19 units. The next one, Grand Tower, it is an Ameren facility,
20 located in Jackson County. Grand Tower, I believe, has two
21 units. It is three units.
22 What the map represents is the location of all of the
23 facilities that contain 103 units that are covered in my
24 testimony as well as a part of Appendix F in the proposal.
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1 BOARD MEMBER FLEMAL: If we had before us the number of
2 units that were present at each of the members of this 24 list of
3 EGUs, that would add up to 103?
4 MR. FORBES: Yes.
5 BOARD MEMBER FLEMAL: Okay. How do those 103 units or the
6 24 facilities relate to the list of facilities that are in
7 Appendix F of the proposal?
8 MR. FORBES: Those are the same 103 units.
9 BOARD MEMBER FLEMAL: Okay. So this is, in fact, the list
10 of the 24 facilities now with the addition of the individual
11 units at each of those facilities?
12 MR. FORBES: Right.
13 BOARD MEMBER FLEMAL: There was a comment I heard in the
14 back. Do we want to get it on the record?
15 MR. GUPTA: What I wanted to say was that this table points
16 out the location of those 103 facilities.
17 HEARING OFFICER GLENN: Could we get your name for the
18 record, please?
19 MR. GUPTA: Vir Gupta.
20 HEARING OFFICER GLENN: Thank you.
21 BOARD MEMBER FLEMAL: Thank you. I think that that
22 run-through of the numbers was enlightening, at least for me.
23 Let's move on in your testimony, Mr. Forbes, to another section
24 which is a portion that deals with admission controls an
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1 associated costs. In fact, it is the costs in particular that I
2 would like to focus on, and that occurs, as I look at it, in the
3 main on the bottom of page nine and extending on to page ten.
4 Once more, for the purposes of the record, I would note that I am
5 referring to Exhibit Number 27, which is entitled the testimony
6 of Richard Forbes.
7 Could you be so kind as to just briefly review for us that
8 information that you presented there in your prepared statement?
9 MR. FORBES: Okay. What I tried to identify in this
10 section was review of the kinds of control equipment that we are
11 generally familiar with that would work on the sources that are
12 covered in this proposal. I am not going to necessarily go
13 through each one of the kinds of control, but just indicate that
14 there is a number of different control devices and combinations
15 thereof that can be used to achieve significant reductions in
16 emissions.
17 We have within the TSD provided a table that identifies the
18 range of controls, and it does depend on whether it is a
19 coal-fired unit, whether it is -- the type of coal firing that is
20 occurring, how it is fired, if it is tangentially or wall-fired,
21 whether it is a gas-fired or oil-fired unit. With respect to the
22 costs themselves, we have provided several tables within the TSD,
23 mostly because of the large range in variety of cost
24 effectiveness depending on the type and load conditions. It gets
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1 a little difficult to summarize or provide some averages.
2 However, we have -- I have attempted to do that.
3 Maybe I can just read the last portion of this paragraph
4 that would summarize this. The TSD for this proposal has a
5 summary of the costs of various NOx control technologies and
6 their combinations under various load conditions based on the
7 information contained in the ACT documents. That is the USEPA
8 documents that we have referred to in the testimony. The costs
9 of combustion controls for gas fired and oil-fired boilers vary
10 widely depending upon the size of the unit, the load conditions,
11 and the type of control technology employed.
12 Table 5-2 in the TSD provides a summary of the large
13 variety of cost effectiveness values for the NOx control options
14 for these boilers. For gas turbines that continue to operate as
15 peakers, the most likely control that would be utilized is water
16 and steam injection. The cost effectiveness range for this
17 control option is $1,210.00 to $2,350.00 per ton of NOx removed.
18 If these units are used more often as peaking units, the cost per
19 ton would, obviously, go down and be less.
20 Control costs for coal-fired boilers relying on SNCR
21 technology also vary widely for base load units with an average
22 range of cost-effectiveness of $725.00 to $880.00 per ton of NOx
23 reduced. The control costs relying on the SCR technology would
24 have a similar average range of cost effectiveness of $1,035.00
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1 to $2,035 per ton for base load units. This was the most common
2 control that we would envision being used for these kinds of
3 coal-fired base load units.
4 BOARD MEMBER FLEMAL: Thank you. Could you explain for us
5 what elements go into the calculation of cost effectiveness, what
6 kind of costs are considered?
7 MR. FORBES: Well, there is, of course, the cost for energy
8 to run the control device, the cost for the first cost, the
9 installation costs, the operation and maintenance costs, all of
10 those kinds of costs to maintain the unit itself. Then in
11 addition to that the amount of tonnage that would be achieved
12 from application of that control device together giving the
13 dollars per ton.
14 BOARD MEMBER FLEMAL: So the costs include both capital
15 costs, the up-front costs or continuing capital costs that may be
16 associated?
17 MR. FORBES: Yes.
18 BOARD MEMBER FLEMAL: And then operational costs as well?
19 MR. FORBES: Yes.
20 BOARD MEMBER FLEMAL: Since the operational costs are
21 continuous and presumably occur more or less each year, are we to
22 interpret this figure, then, as an average or an annual value?
23 MR. FORBES: This particular cost out of the ACT is an
24 annual based cost.
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1 BOARD MEMBER FLEMAL: So it is an annual cost?
2 MR. FORBES: Yes.
3 BOARD MEMBER FLEMAL: And it has spread the capital costs,
4 I take it, over some life time of the capital equipment and that
5 is how the capitalization is involved?
6 MR. FORBES: Yes. I think the EPA typically uses a ten
7 year period to amortize the costs.
8 BOARD MEMBER FLEMAL: We have -- we, the Board, the Agency,
9 the regulated community regularly encountered these costs per ton
10 figures in other ozone related proceedings. Can you now or would
11 you otherwise at some future time give us some perspective on
12 these costs by comparing them with costs that we have encountered
13 in other proceedings?
14 MR. FORBES: Yes, we can do that. I don't have that with
15 me at this point, but we could do that, relate those two previous
16 rulemakings on cost-effectiveness figures?
17 BOARD MEMBER FLEMAL: Yes, I think in terms of being able
18 to get our hands around these figures, it would be helpful to
19 compare them to other cost-effectiveness values that have been
20 encountered previously.
21 I do have other questions, but since I have been focusing
22 on Mr. Forbes, is there anything any of the other Board Members
23 or Mr. Rao would like to explore in this arena with Mr. Forbes?
24 MR. FORBES: I did find the variation in the growth factors
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1 if I could go ahead and --
2 BOARD MEMBER FLEMAL: Sure.
3 MR. FORBES: From the support documents to the USEPA NOx
4 SIP Call, we found that there was a range in growth from -- first
5 I will give you the factor and then I will give you what that
6 means in terms of the percent. Rhode Island had the lowest
7 growth factor, which was 0.47. And Massachusetts had the
8 highest, which was 1.59. What that represents for Rhode Island
9 is actually a decrease in growth. It is a 53 percent reduction
10 or a factor of 0.47. In the case of Massachusetts that 1.59
11 growth factor represents a 59 percent growth rate. That was the
12 range of factors.
13 BOARD MEMBER FLEMAL: This is anticipated growth and
14 emissions, not in power output, not the number of units, not in
15 economics of the area or anything of that sort, just emissions?
16 MR. FORBES: It is supposed to be electrical generation
17 growth, which then is translated directly into emissions. In
18 other words, like heat input. This is what was applied to the
19 1996 or 1995 heat input to project 2007 heat input from which
20 they could then calculate emissions.
21 BOARD MEMBER FLEMAL: Thank you. I did have a
22 misunderstanding of that. I appreciate you straightening me out.
23 Let me move to questions that relate to Section 9.9 of the
24 Act. I know we have touched on this a bit this morning, but I
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1 think it is worth revisiting for at least a couple of
2 perspectives. I think maybe the appropriate way to start this --
3 I wonder if the Agency could first off simply describe for us,
4 for the record, what Section 9.9 is of the Act, and if you would
5 like maybe some history of how this happened to get into the Act?
6 Will someone accept that challenge?
7 MS. BASSI: Section 9.9 of the Act is a finding by the
8 General Assembly that reducing NOx emissions -- it recognizes
9 that the SIP Call was issued and that reducing NOx emissions in
10 the state would help us to meet the National Ambient Air Quality
11 Standard for Ozone, and that emissions trading is a cost
12 effective means of obtaining these NOx emission reductions.
13 It proceeds then to essentially enable us and you to
14 propose and adopt the rules that would allow us to enter into the
15 NOx trading program that USEPA would administer so that we would
16 be participating in an interstate NOx trading program as to
17 opposed to one that we might devise ourselves that would be
18 limited to only the state. The Section 9.9 then addresses some
19 specifics about elements of the rules that are to be included,
20 and we have reflected those that are related to EGUs in this
21 proposal.
22 BOARD MEMBER FLEMAL: When did Section 9.9 -- when was it
23 born? When did it come into being? I guess I can help by saying
24 it happens to be Public Act 91-0631.
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1 MS. BASSI: I never understand those Public Act 91 numbers.
2 I believe it was in 1999.
3 MS. KROACK: We can get that answered for you in a moment.
4 MS BASSI: Dr. Flemal, it was enacted in 1999, because the
5 SIP Call was promulgated in 1998, and it was not this year that
6 it was enacted.
7 BOARD MEMBER FLEMAL: Ms. Bassi, you use the word enabling
8 in the sense that this enables you to propose and the Board to
9 adopt regulations. Let me test the use of that word. I want to
10 read Section 9.9 (b), at least a portion of the first sentence
11 there. It says the Agency shall propose and the Board shall
12 adopt regulations to implement an interstate NOx trading program
13 as provided for in 40 CFR, Part 96.
14 Is that not saying to us that there is a mandate that we
15 adopt a trading program?
16 MS. BASSI: Yes.
17 BOARD MEMBER FLEMAL: And that it is an interstate program
18 and it is not a local program?
19 MS. BASSI: Yes.
20 BOARD MEMBER FLEMAL: And that the program is the program
21 that is in CFR 96?
22 MS. BASSI: Yes.
23 BOARD MEMBER FLEMAL: Part 96?
24 MS. BASSI: Yes.
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1 BOARD MEMBER FLEMAL: And that is the model rule?
2 MS. BASSI: The model rule, yes, sir.
3 BOARD MEMBER FLEMAL: Let me read what I see in Section 9.9
4 (c). It says allocations of NOx allowances to large Electric
5 Generating Units, as defined by 40 CFR, Part 96 (4)(a) shall not
6 exceed the state's trading budget for those source categories to
7 be included in the state implementation plan for NOx. Tell me
8 what that is telling us.
9 MS. BASSI: Section 96.4 in the model rule is the -- I
10 believe it is the applicability section. Let me check that very
11 quickly.
12 That is the applicability section. In 96.4 with regard to
13 large EGU says that any unit that anytime on or after January 1,
14 1995, serves a generator with a nameplate capacity greater than
15 25 megawatts and sells any amount of electricity. And so what we
16 have in Section 9.9 (c) of the Environmental Protection Act is
17 that our State Implementation Plan with regard to NOx, as
18 envisioned by Section 9.9, would apply to these particular units.
19 BOARD MEMBER FLEMAL: Is it implicit or explicit in any of
20 that analysis that says our emissions trading program has to be
21 capped at 30,701 tons?
22 (Ms. Kroack and Ms. Bassi confer briefly.)
23 MS. BASSI: The language in 9.9 (c) that says shall not
24 exceed the state's trading budget for those sources categories, I
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1 think is the -- perhaps is the explicit statement that we must
2 comply with the budget cap that is set for the state for large
3 EGUs and then later non EGUs.
4 BOARD MEMBER FLEMAL: Is there any way within these
5 constraints that are set up with the combination of Part 96 and
6 this mandate that we have from the General Assembly for us to do
7 an emission trading program that does not use the 0.15 million
8 btu underlying premise?
9 MS. BASSI: The 0.15 million btu, as used to determine our
10 allocations that we will make to units, is not -- there is no
11 restriction on that. That happens to be the number that USEPA
12 used in the model rule when it was determining eligibility for
13 allowances and we carried that forward. Another reason why we
14 carried that forward was that the 0.15 pounds per million btu is
15 the number that was used by the USEPA in determining the caps
16 that apply to EGUs in all of the states that are -- and the
17 District of Columbia that are subject to the SIP Call. It is --
18 but there is nothing that restricts us in this or in Part 96 to
19 rely on 0.15 for determining allocations within the State of
20 Illinois. Allocation methodology is a flexible portion.
21 And I was just handed this. Section 9.9, as you said, is
22 Public Act 91-631. It was signed by the Governor on August 19th,
23 1999 and codified at what we have here.
24 BOARD MEMBER FLEMAL: Okay. I guess I understand that we
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1 are not obligated to meet a 0.15 million btu limit, but that
2 factors in in the sense that USEPA used that number to derive
3 what is really our key number, the 30,701 tons.
4 MS. BASSI: That is correct.
5 BOARD MEMBER FLEMAL: Okay. I still wonder, though, from
6 your perspective, whether this combination of the language in
7 Section 9.9 allows us any deviation from that federal limit, the
8 30,701?
9 MS. BASSI: No, I don't believe --
10 BOARD MEMBER FLEMAL: It does not?
11 MS. BASSI: I do not believe it does.
12 BOARD MEMBER FLEMAL: I certainly anticipate or at least I
13 hope that we -- if there is another side to this coin that it
14 will be brought out by -- to us by those people who see another
15 side to the coin. But, frankly, I do have a concern that there
16 are some pretty strong constraints in Section 9.9. I want to
17 enlighten this to what specifically those constraints are in
18 terms of what latitude the Board have when it says we shall adopt
19 a program. I leave it there for something that will be picked up
20 I indeed hope at our next session.
21 Let me just try one last question here. I think it is a
22 fairly broad question, but in some sense I think it is also at
23 the real heart and guts of what it is that we have to do here.
24 If at the end of the day, or perhaps more better put at the end
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1 of September, or maybe even at the end of August, a facility, for
2 whatever reason, has emissions that have already occurred or has
3 projected to occur that are greater than its allowances, what
4 options does it have? What does it do?
5 MS. BASSI: At the end of the control period, it must
6 reconcile the number of tons of NOx that it has emitted with the
7 number of allowances that are available in its compliance or
8 overdraft accounts with USEPA. If it finds at the end of the
9 control period that it is short allowances, there is a period of
10 a month during which it may seek to buy allowances from whomever
11 so that it balances.
12 BOARD MEMBER FLEMAL: The assumption is that there will be
13 allowances to be purchased.
14 MS. BASSI: That is the assumption underlying this trading
15 program.
16 BOARD MEMBER FLEMAL: Okay. But if I am one of those
17 facilities and I need allowances and I am not unique, I look
18 around and I find that everybody else needs allowances, is it
19 possible that there is a national overdraft of the allowances?
20 MS. BASSI: Theoretically, that is --
21 BOARD MEMBER FLEMAL: Will we face that?
22 MS. BASSI: Theoretically, that is possible. You suggested
23 in your hypothetical that the facility or the unit recognizes
24 that it is running over what it might have projected, and it
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1 recognizes this at the end of August or, you know, before the end
2 of the control period. Theoretically, they could plan -- I mean,
3 if there is a recognition that this particular unit is running
4 over and they do not foresee an opportunity to buy allowances
5 somewhere, theoretically they could cut back on the operation of
6 that particular unit. That goes to questions of reliability of
7 electricity in the system. But, nevertheless, this,
8 theoretically, is an approach that the unit could take as opposed
9 to relying on trading for allowances. Perhaps there are other
10 units that it could rely upon that might be more costly to
11 operate, but that might be more efficient in producing
12 electricity.
13 BOARD MEMBER FLEMAL: When judgment day comes and the
14 accounts have to be balanced and they don't get balanced, then
15 what?
16 MS. BASSI: Then the emissions -- the excess emissions
17 provisions of Part 96 would be exercised by USEPA, and
18 additionally a unit could be subject to enforcement by either or
19 both the state and USEPA because this would be part of a SIP,
20 which makes the rule itself federally enforceable.
21 BOARD MEMBER FLEMAL: So enforcement action might will
22 ensue?
23 MS. BASSI: It could occur.
24 BOARD MEMBER FLEMAL: For failure to having accumulated the
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1 necessary allowances to balance the actual emissions.
2 MS. BASSI: But there would be the automatic deduction of
3 allowances for excess emissions that USEPA would undertake
4 separate and apart from an enforcement action.
5 HEARING OFFICER GLENN: Okay. Thank you. Could we go off
6 the record for a moment, please?
7 (Whereupon a short recess was taken.)
8 HEARING OFFICER GLENN: All right. We are back on the
9 record.
10 Dr. Girard, would you like to ask questions, and then we
11 will turn it over to Ms. Kroack.
12 BOARD MEMBER GIRARD: Thank you. I would like to go back
13 to the growth rate and hearing that range of growth rates,
14 Massachusetts gets 1.59 and we get 1.08. As I understand it,
15 then, if our state budget cap had the same growth rate allowed as
16 Massachusetts instead of approximately 31,000 tons we would be
17 allowed approximately 45,000 tons? Is that correct?
18 MR. FORBES: That is correct, just on the basis of applying
19 the growth factor. I am not sure offhand what Massachusetts
20 budget actually is. I don't think it is as high as ours.
21 BOARD MEMBER GIRARD: Now, in thinking back on some of the
22 other testimony we have had, we have heard that possibly the
23 growth rate is going to be more than that, and we could be
24 looking at 1.34 as maybe more realistic where it should have
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1 been. Is this growth factor now set in concrete? Is there any
2 way to challenge it? Or are we way past that point?
3 MR. FORBES: I would say from a nonlegal answer that it was
4 set in concrete. The EPA had extend periods of comment time to
5 submit, you know, various comments, and I think all of the
6 utility sources and Illinois EPA provided a lot of comments in
7 this area as did the other states and other utilities and 23
8 jurisdictions and the EPA weighed all of those things and made
9 very little changes in their growth factors that they ended up
10 staying with.
11 I think that may have been part of the challenges in some
12 of the court challenges, dealing with growth rates and such. I
13 think that pretty much has been accepted, that that is the EPA
14 growth rate. So I don't know what challenges are left out there.
15 There that are still pending, but my opinion is that it is
16 probably not likely that that will be changed.
17 HEARING OFFICER GLENN: Yes, do you have a question?
18 MR. DIERICX: I have additional information that may help
19 the Agency respond on that. I believe there is additional
20 litigation in the DC Circuit Court concerning the technical
21 amendments to the SIP Call that address the state budgets and the
22 state growth factors. The court has not acted on that in that
23 case yet. I don't think they have even had oral arguments yet.
24 So that is still pending before the Court.
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1 I think another piece of information, prior to the final
2 SIP Call growth numbers, the State of Illinois did have a higher
3 growth rate. In the proposed state budget I think the growth
4 factor may have been 1.34 or something in that range.
5 MR. FORBES: 1.23 percent, I believe.
6 MR. DIERICX: 1.23. Okay. Something like that originally.
7 And then before it was finalized the USEPA included some
8 additional factors in the IPM model, such as implementation of
9 the keoto (spelled phonetically) protocol that adjusted the
10 growth factors for the state. As a result of that, Illinois'
11 number went from 1.23, as Mr. Forbes identified, down to 1.08.
12 HEARING OFFICER GLENN: Thank you, Mr. Diericx.
13 BOARD MEMBER GIRARD: Thank you.
14 HEARING OFFICER GLENN: Mr. Diericx, could we get you sworn
15 in? I think we better do that. My apologies to Mr. Urbaszewski.
16 I didn't mean to allow his testimony and not allow yours. Let's
17 get you sworn in. If you could raise your hand.
18 (Whereupon the witness was sworn by the Notary Public.)
19 HEARING OFFICER GLENN: I apologize. Thank you. We
20 appreciate the background. Thank you.
21 Any further questions? If not, we will hear some wrap-up,
22 then, from the Agency. They have a few things to add, I believe.
23 MS. KROACK: I just have a couple of questions for some of
24 our witnesses because I think during some of the responses we may
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1 have created some confusion. So this is for Mr. Hutton. He is
2 in our Source Monitoring Unit. He is the manager. I want to ask
3 him about Part 75, the monitoring.
4 Mr. Hutton, what parameters are monitored under Part 75 for
5 the Electrical Generating Units?
6 MR. HUTTON: Typically the hours of operations, heat input,
7 and amounts of emissions and the pounds per million btu's.
8 MR. RIESER: I am sorry. We can't hear.
9 MR. HUTTON: Typically NOx emission rates and pounds per
10 million btu, heat input, and hour of operation.
11 MS. KROACK: Okay. Thank you. Do all of the existing EGUs
12 currently monitor via Part 75, the ones listed in Appendix F, to
13 your knowledge?
14 MR. HUTTON: There are a few small peaker units. Other
15 than that, all of them that I know of are, yes.
16 MS. KROACK: Does our proposal require Part 75 monitoring
17 for all participating units?
18 MR. HUTTON: Yes.
19 MS. KROACK: And does it require that monitoring a year
20 prior to when the program begins?
21 MR. HUTTON: Excuse me?
22 MS. KROACK: Does it not require that monitoring a year
23 prior to when our program begins?
24 MR. HUTTON: Yes.
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1 MS. KROACK: So, Mr. Hutton, then the inputs necessary to
2 calculate allowances are known to the Agency prior to when
3 allocations are --
4 MR. HUTTON: That's correct.
5 MS. KROACK: And should a source's monitoring system fail
6 or they were to have errors or problems, what do the rules
7 provide for in those circumstances?
8 MR. HUTTON: There is a statistical procedure for
9 developing numbers to fill in, missing data procedures. And
10 those are well spelled out.
11 MS. KROACK: So there is some default numbers that would
12 then be relied upon to determine emissions and heat input during
13 a control period?
14 MR. HUTTON: That's true. There are default numbers.
15 There are also numbers that are very specific to that particular
16 unit and fuel combustion.
17 MS. KROACK: Thank you. These questions next are for Mr.
18 Kaleel.
19 HEARING OFFICER GLENN: Ms. Kroack, sorry to interrupt. I
20 just wanted to be sure. I can't remember from yesterday. Did
21 Mr. Hutton get sworn in?
22 MR. HUTTON: Yes.
23 MS. KROACK: Yes.
24 HEARING OFFICER GLENN: Thank you. Please continue.
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1 MS. KROACK: Mr. Kaleel, there were some questions about
2 why we suddenly started calling -- maybe not suddenly, but we are
3 now referring to the Chicago nonattainment area as the Lake
4 Michigan nonattainment area. When the design value was set for
5 the Chicago nonattainment area, which is a part of the
6 multi-state nonattainment area, what was the monitor that was
7 used for determining what the design value was back in the 1990
8 Clean Air Act amendments?
9 MR. KALEEL: My understanding is that the monitor that was
10 used back in the 1990 Clean Air Act amendments was one that was
11 actually operated by the State of Wisconsin at a site called
12 Chawaukee Prairie, which is right at the Illinois-Wisconsin state
13 line.
14 MS. KROACK: Okay. For the St. Louis portion of
15 Metro-East/St. Louis multi-state nonattainment area, do you know
16 which monitor was used to determine the design value for the
17 area?
18 MR. KALEEL: Actually, I guess I don't know. I would have
19 to figure out which one that was.
20 MS. KROACK: Okay. Is it fair to say, though, that in all
21 of our efforts towards demonstrating attainment of the 1-hour
22 standard we have had to show attainment within the region and not
23 merely within the six counties in the Chicago area and the three
24 counties in the Metro-East area.
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1 MR. KALEEL: Yes, that is true. I could state I think with
2 some confidence that the monitoring site in the Metro-East/St.
3 Louis area was on the Missouri side. I don't remember exactly
4 which site, which monitoring site. It was in Missouri. Not in
5 Illinois.
6 MS. KROACK: And that monitor you also set the design value
7 for the three counties in Illinois?
8 MR. KALEEL: It sets the design value for the entire
9 bi-state nonattainment area.
10 MS. KROACK: Okay. Thank you. I have a couple of quick
11 follow-up questions for Ms. Bassi. During the rulemaking, was it
12 true that for the new source set-aside in the early reduction
13 that there were people that both wanted the ability to earn those
14 credits to slide, the implementation for the program to slide,
15 and those that did not?
16 MS. BASSI: Yes, that's true.
17 MS. KROACK: Secondly, during those discussions, did we
18 invite comment on the proposal to charge the market price for
19 allowances from the new source set-aside?
20 MS. BASSI: Yes, we did.
21 MS. KROACK: Were there also comments that we received that
22 several of the Electrical Generating Units wanted us to waive the
23 early reduction credits in the first year of the program versus
24 the second year of the program, thus that 17,561 or the
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1 approximate number, you could earn more during the first year of
2 the program and to be available to earn during the first year of
3 the program and the second year?
4 MS. BASSI: I don't recall that specific comment. There
5 were a number of comments on how the early reduction credits
6 should be earned. The proposal that we have set forth seemed
7 most close to the -- I wanted to say the majority view, within
8 the constraints that are set by the timing of when we are doing
9 this rule and what the SIP Call itself provides.
10 MS. KROACK: That's all I have.
11 HEARING OFFICER GLENN: Thank you, Ms. Kroack. Are there
12 any further questions of the Agency today?
13 Is there anything else the Agency would like to state at
14 this time, then?
15 MS. KROACK: We had prepared, but have not finalized an
16 errata sheet, with some errors that we had discovered both in the
17 text of the rule and within our supporting documents. For the
18 most part I would characterize them as not significant and a
19 couple of them are based on we have received a draft conditional
20 approval of this proposal from USEPA -- a draft Federal Register,
21 which they have not put out for publication, raising some of
22 these things as comment.
23 We are just not quite finished with that document. We are
24 here again this morning and we have not had it finalized. So I
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1 suspect that what we will do is submit them as part of our
2 written comments. If I can find my sheet I would just like to go
3 over them quickly so that the members of the audience will know
4 what it is that we are proceeding with. I am just trying to find
5 my sheet.
6 HEARING OFFICER GLENN: All right. Let's go off the
7 record, then, for a moment.
8 MS. KROACK: Okay. Thank you.
9 (Whereupon a short recess was taken.)
10 HEARING OFFICER GLENN: All right. We are back on the
11 record, please.
12 MS. KROACK: One of the things that we are requesting to be
13 changed by the Board is in our statement of reasons when we refer
14 to the potential electrical output capacity in the equation, we
15 reversed the number, such that we have a number in there 0.0967,
16 which should read 0.0976.
17 In the rule itself, we are proposing to be added to Section
18 217.101, new Subsection C, monitoring -- not monitoring --
19 determination of NOx emissions according to the determination of
20 nitrogen oxide emissions from stationary sources, paren,
21 instrumental analyzed procedure, close paren, comma, 40 CFR 60,
22 comma, Appendix A, comma, method 70, paren, 1999, close paren.
23 Again, in our discussions with USEPA they added the lack of this
24 method in determining NOx emissions as an approvability -- as a
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1 potential approvability issue.
2 In Section 217.756 (g) we are striking the reference to 40
3 CFR 96.4 (b), that appears the second reference, and inserting
4 instead Section 217.754 (c) of the subpart. And the reason for
5 that change -- just a moment. The proper reference should be our
6 proposed rules and not 40 CFR 96.4 (b), because we don't
7 incorporate the low emitter provisions by reference. Instead, we
8 adopt our own provisions, so we should refer to our own rule.
9 In 217.768 (e)(4), we refer to new budget EGUs that have
10 not operated for more than half of a control period. In the
11 interest of clarity, we are going to change that to for new
12 budget EGUs that have commenced -- the addition of commenced
13 commercial operation but have before not operated for, and then
14 strike more than half of a full, and then insert at least 77 days
15 of the control period. The reason for that is that USEPA was
16 concerned that there was not sufficient clarity about how much
17 time a unit had to operate, and we didn't reference commenced
18 commercial operation, so that it could potentially apply to
19 existing EGUs who shut down and then restarted.
20 The same is true for Section 217.768 (i), where we again
21 strike less than one half and insert but have operated for 76 or
22 fewer days of a control period.
23 The next change would be a substantive change. It would be
24 in Section 217.774 (a)(2). These are the types of units that may
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1 opt-in to the program, and we had limited that to any operating
2 fossil fuel-fired, stationary boiler, combustion turbine or
3 combined cycle system. We would like to expand that to include
4 cement kiln or stationary internal combustion engine. Although
5 we don't have final rules for cement kilns and have not proposed
6 rules for stationary internal combustion engines at this point in
7 time, we anticipate that those units will also be allowed to opt
8 into this program if they meet the criteria.
9 In Subsection (a)(2) of that same Section, 217.774, we want
10 to strike everything after vents all of its emissions to a stack,
11 period, and strike the rest of that subsection. USEPA, in our
12 discussions, stated that any unit that would opt-in must vent to
13 a stack. We had allowed for opt-ins if they obtained a FESOP to
14 cover units that did not emit to a stack.
15 In Section 217.776 (b), we had referred to -- this is
16 Continuous Emissions Monitoring System Availability, and we had a
17 percentage in there of 80 percent. The federal rule, as well as
18 Part 75, require monitoring system availability of 90 percent.
19 Not less than 90 percent. So we are striking 80 percent and
20 inserting 90 percent. That is also true in Section 217.770 (a).
21 The other changes that we will be submitting to the Board
22 generally are not substantive. They are just corrections in the
23 language to make it clearer. And rather than going through that
24 today, we will submit that to the Board sooner rather than later
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1 and to everyone on the service list to give you an opportunity to
2 comment.
3 HEARING OFFICER GLENN: Thank you, Ms. Kroack. Okay. I
4 have just a few remarks here at the end, then. I would like to
5 reiterate that the second hearing will be in Chicago on September
6 26th. That is a Tuesday, beginning at 9:30 in the morning, at
7 the James R. Thompson Center, 100 West Randolph, Room 9-31. That
8 will continue day-to-day, as needed. Under 28.5 the scope of
9 that hearing is to be devoted to presentation of testimony,
10 documents and comments by affected entities and all other
11 interested parties. To the extent that the Agency is there and
12 is willing to answer any questions, that is a possibility, but
13 that is not the focus of the second hearing.
14 Also, in my Hearing Officer Order I had stated that for
15 those people that wanted to testify at the second hearing please
16 get all of the testimony filed with the Board no later than 4:30
17 in the afternoon on September 15th, 2000. That also is a
18 statutory deadline, and the mailbox rule will not apply. So the
19 Board must have that prefiled testimony at the end of business
20 day on September 15th. I am certainly willing to entertain fax
21 filings, but I would like to get a phone call on that date. If
22 you want to file something on the 15th by fax please give me a
23 call and I will accommodate you, but I need to know that in
24 advance, please.
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1 Also, if you do file prefiled testimony, you are obligated
2 to also send copies of that testimony to the people on the
3 service list. You can obtain the most recent copy of the service
4 list by calling me. Actually, at the end of the day September
5 14th is when it becomes final. So please get in touch with me.
6 I think that's the right date. Excuse me. It becomes final
7 September 11th, the service list at the end of the day, 4:30,
8 September 11th. Please call me or email me and request that
9 service list so that you can send a copy of your prefiled
10 testimony to those people on the list.
11 My phone number is on the web page and so is my email
12 address. For the record it is 312-814-6923, and my email is
13 glennc@ipcb.state.il.us.
14 Finally, the transcript from the proceedings yesterday and
15 today will be on the Board's web page. We anticipate getting the
16 transcript in the Board's offices this coming Friday. Then, of
17 course, we have the Labor Day weekend, but we hope to have the
18 transcript posted on the web page Tuesday of next week. If not
19 then, soon thereafter, but it will be on there next week. So
20 please check there and download that. If you don't have Web
21 access the Board will be happy to copy every page for you at 75
22 cents a page.
23 Regarding the third hearing, if the Agency -- I intend to
24 ask the Agency at the second hearing whether or not they want the
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1 third hearing. Hopefully they will be in a position to know that
2 by then, and then we can announce the date when the record will
3 close and that sort of thing.
4 Are there any other matters that need to be addressed at
5 this time or are there any other questions regarding the
6 procedures for the end of September? Yes, Mr. Murray.
7 MR. MURRAY: I would ask for a clarification on the
8 deadline for filing written comments. That is 14 days after the
9 close of the record?
10 HEARING OFFICER GLENN: That's correct. Under the statute
11 the record closes 14 days upon receipt of the transcript. Let me
12 just double-check that. Just a moment. At 28.5 (l), following
13 the hearing the Board shall close the record 14 days after the
14 availability of the transcript. So after -- let's assume the
15 second hearing is the last hearing. We would again request an
16 expedited transcript, so we would receive it three days after the
17 end of the testimony, and then starting that third day is when we
18 would start counting the 14 days. I will send out a Hearing
19 Officer Order, though, for clarification to announce when the
20 record will close. So everyone on the notice and service list
21 will get a Hearing Officer Order in time to know the deadline.
22 I think that's it. I want to thank the Agency for helping
23 us understand further the submissions you have given us. We
24 really appreciate all of the efforts you have put towards this
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1 proposal. We know you have been working on it for quite some
2 time, and we appreciate everything you have done for us the last
3 two days as well as in preparation for these days.
4 I also want to thank the members of the public that came
5 and we really do encourage you to prefile some testimony for us
6 next time and we look forward to hearing from you and seeing you
7 all in Chicago at the end of September. Thank you very much for
8 coming.
9 (Hearing exhibits retained by Hearing Officer Catherine F.
10 Glenn.)
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1 STATE OF ILLINOIS )
) SS
2 COUNTY OF MONTGOMERY)
3 C E R T I F I C A T E
4
5 I, DARLENE M. NIEMEYER, a Notary Public in and for the
6 County of Montgomery, State of Illinois, DO HEREBY CERTIFY that
7 the foregoing 138 pages comprise a true, complete and correct
8 transcript of the proceedings held on the 29th of August A.D.,
9 2000, at 300 South Seventh Street, Springfield, Illinois, In the
10 Matter of: Proposed New 35 Illinois Administrative Code 217,
11 Subpart W, the NOx Trading Program for Electrical Generating
12 Units, and Amendments to 35 Illinois Administrative Code 211 and
13 217, in proceedings held before Catherine F. Glenn, Hearing
14 Officer, and recorded in machine shorthand by me.
15 IN WITNESS WHEREOF I have hereunto set my hand and affixed
16 my Notarial Seal this 1st day of September A.D., 2000.
17
18
19
20
Notary Public and
21 Certified Shorthand Reporter and
Registered Professional Reporter
22
CSR License No. 084-003677
23 My Commission Expires: 03-02-2003
24
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