INDEX
Permits and Technology Subcommittee Papers
March 20 - 22, 1991
Document Number Title
P-20 Permits and Technologies Conference Call 1
Minutes January 22, 1991
p~21 Subcommittee Meeting Minutes at the Omni 9
Shorham, January 28, 1991
p~22 Principles for Acid Rain Permits 39
p-23 Fact Sheet: Reduced Utilization 47
p~24 Topics Covered in Acid Rain Permit 53
Regulations
P-25 Primer on the Clean Water Act Permit 55
Program
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ARAC Subcommittee on Permits and Technologies
Conference Call Minures
January 22, 1991
A conference call was conducted on Tuesday, January 22, 1991 from
2-00 to 4:00 PM with members of the Acid Rain Advisory Committee
(ARAC) Subcommittee on Permits and Technologies and EPA. A list.
of participants is included as an attachment. Mark Steinberg,
substituting for Richard Abdoo, led the discussion by
Subcommittee members; Rachel Hopp led the discussion by EPA. The
conference call began with a roll call and a brief review of the
agenda.
substitution Plans
Luther Heckman had faxed a copy of his paper on substitution
plans to Subcommittee members and took the lead in the discussion
of this issue. Several Subcommittee members, including Bill
Roberts, strongly disagreed with Mr. Heckman's view that, in the
case of a substitution unit, the NOX requirements under Section
408 apply only to the substitution unit and not to the original
unit. Mr. Roberts stated that Sections 404 and 407 do not allow
for this interpretation and that in his paper, Mr. Heckman
suggests that the original unit would still receive allowances.
Mr Steinberg stated that he did not see the NOX requirements
being associated with substitution plans for SO2 requirements.
Mr Heckman explained his argument that if a unit is substituted
for this new unit becomes the "affected" unit and the original
unit is no longer an "affected" unit. He said that this concept
is supported by the Act. Bill Roberts said that the language
under Section 404(c)(2) clearly indicates that both the original
and substitute unit are affected units. Mr. Roberts reiterated
that if Mr. Heckman assumes that the original unit is no longer
an affected unit, this unit would not be eligible for allowances.
Jerry Eyster briefly recapped his understanding of substitution
units related to SO2 which correspond to the language in Section
404(b). He agreed that both the original and substitute units
would be affected Phase I units. However, since the language in
Section 404(b) specifically refers to the "sulfur dioxide •
reduction requirements", he feels it is questionable whether the
NOX requirements kick in. Bill Roberts cited language from
Section 404(c)(2) that "each source with such a unit, shall be
deemed affected under this title". He then referred to Section
407 which provides when a source becomes affected for S02, it
becomes affected for NOX, depending on boiler type.
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Mr. Heckman disagreed with the interpretation that both units
were affected units. He argued that EPA should resist ragularir.g
both units under Section 407 and said that such an interpretation
would deter substitution proposals and diminish the use or
substitution as a compliance strategy.
Mr. Steinberg asked for clarification regarding whether the
purpose of the substitute unit was to transfer the entire
reduction to the another unit. Mr. Roberts stated that the
language says "in whole or in part".
One Subcommittee member asked about the language in 404(c)(2) -
whether the phrase "shall be deemed affected" means affected
under Phase I or under Phase II. Rachel Hopp stated that
substitution language appears only in Section 404 dealing with
Phase I. However, the intent of the legislation was that sources
coming in as substitute units would be Phase II units (or
possibly opt/in units). She clarified that these units become
affected dSring Phase I as substitutes, but that the legislation
had Phase II units in mind. Bill Roberts agreed that once the
unit becomes part of the substitution plan, it is affected during
Phase I.
Mr. Heckman reiterated that EPA would be doing away with
substitution as a compliance strategy, and referred to this
approach as NOX "double jeopardy". He feels the intent of the
Act was to allow for substitution. However, if the
interpretation is that both units are affected, substitution
would not be one of the cheapest compliance strategies and • •
Serefore, would not be used. He felt that the utilities will go
with the cheapest compliance strategy available. He asked for
input from the utilities.
Ms. Hopp mentioned that the legislation allowed for NOX averaging
(407 (e)) for owners of two or more units. Mr. Heckman did not
feel this would address his concern and restated that he does not
think that both the original and substitute units are affected.
several Subcommittee members (Jim Markowsky, Tom Maiman, Steve
Burton) restated that they believe, the language is clear and that
both units are affected.
Mr. Heckman asked for comments on this issues and Mr. Steinberg
asked members to fax these to Mr. Heckman before the next
Subcommittee meeting on Monday.
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Repowerina Extensions
Several Subcommittee members (Ned Helme, Jim Markowsky, Bill
Roberts) stated that they felt the language in the options paper
on the definition of eligible technologies was too broad and
should be narrowed to be consistent with the legislation.
Jim Markowsky raised the issue of the timing on the repowering
notification. He stated that the 3/91 date.was too early to make
a commitment and suggested that the date be extended.to.1/96. He
also suggested that this date should not be binding on either
industry or EPA. He mentioned that AEP is presently the only
utility with clean coal technology already underway, yet AEP will
not be ready to make a decision on repowering until '96. Steve
Winberg said that the 3/91 date would tell EPA nothing, since
everyone will notify just to meet the requirement and keep their
options open.
The purpose of the 3/91 notification date was discussed. Several
Subcommittee members said they felt the intent of this date was
to give EPA an idea of how many units were to be repowered and
what the tap on the allowances might be. Mr. Roberts said the
3/91 date would lead to a "lowball" of the number of- allowances
required for Phase II. However, he felt that if EPA were to
periodically revise this estimate as it gets closer to Phase II
(as required in the statute), this will give industry a more
accurate reading. Rachel Hopp asked whether the Subcommittee
members viewed the 3/91 date as informational only. She
suggested that if they felt this way, the Subcommittee should
consider develop a recommendation regarding the 3/91 notification
date and suggest an alternative.
Ned Helme said that the purpose of the repowering provision was
to allow for the development of technologies and that extending
the notification date to 1/96 would allow for this development to
take place. He suggested a notification date of 1/96, the due
date for the Phase II permit applications, with a final
commitment to repower by 1/97. Jim Markowsky said 1/96 might be
too soon to expect a utility to have a full permit application
developed which included details for repowering. He suggested
that the permit application of 1/96 include a notification of the
intent to repower, with details provided in 1997. Ms. Hopp said
that the 1997 change would be considered a modificettion to the
permit application.
Mr. Markowsky recapped the discussion:
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o first indication of repowering in 1/96
o confirmation of commitment by 12/97
o submission of detailed plans by 1/2000
Ms. Hopp asked the subcommittee to develop a paper on these
suggestions.
Bill Steinmeier asked for further clarification on the - 31 date
and whether the information provided by this date was t oe used
just for informational purposes'. Mr. Markowskyrestater cha^ the
utilities will not have this information by 3/91. He said the
utilities can not make a decision now on repowering since the
technology is in its early phases and the costs for repowering
a?e not Sown at this time. Steve Winberg said that he would
like to know what the utilities might be giving up before
recommending that EPA drop the ,3/91 notification.
Rachel Hopp stated that the idea behind the 3/91 notification
date is to give EPA and industry an idea on what the tap on the
allowances might be. If EPA does not know by 3/91 how many
allowances may be requested for repowering, EPA will not be able
to inform the industry of what;the worst case scenario mignt be.
She stated that without this information, it makes it difticult
for the utilities to plan.
Steve Winberg said that the Phase II allowances are still up in
the air. Ms! Hopp agreed but reiterated that this would allow
EPA to estimate the worst case/maximum tap on the allowances.
One subcommittee member stated:that the only way to know the
maximum number of allowances would be to make the 3/91 deadline
binding on the utility. Steve!Winberg agreed that the
information from this notification would be worthwhile. He
suggested that the Subcommittee not recommend dropping^the
notification requirement and ,instead, recommend that the date
for the notification be extended.
The timeframe for this notification was then discussed. Ms. Hopp
asked about the time needed for utilities to conduct advanced
olannina for repowering. Several Subcommittee members said about
6 yellrs f orrepowering? which would mean a notification date of
1994. They mentioned that about 5 years was required tor a
scrubber. Jim Markowsky did not think a utility could make a
decision bv '94 or '95. One Subcommittee member disagreed,
stating the utility will know if it is considering repowering by
Ihis time. He said that by '95, the utility will have made a
decision if they are on a dual track (scrub/repower). Another
Subcommittee member said that there is no incentive for the
utility to take any risk and that EPA needs to provide more
flexibility.
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Bill Roberts asked if it would be helpful to know who is not
interested in repowering. Jim Markowsky asked Ms. Hopp if EPA
could keep the 3/91 date, but make it absolutely non-binding.
Rachel Hopp told him that she could not commit to this; that it
was the Subcommittee's task to develop these positions for
consideration by EPA.
Eligible Phase I Extensions
One Subcommittee member asked Rachel about EPA progress in
considering an earlier date for the regulation. Mss. Hopp said
that she was working on a briefing outlining the options and that
she was hoping to have something to the Subcommittee for review
by Monday. She stated that this requires input from other parts
of EPA. She mentioned that she had requested a half-hour on the
agenda for the Subcommittee to present the issue at the full ARAC
meeting on Tuesday.
Tom Maiman said that the language on first come/first serve was
clear and he did not see a need to spend time interpreting this.
Several Subcommittee members disagreed and summarized discussions
from the last meeting, which included: the minimum unit of time
should be one day to avoid the mechanics of trying to
differentiate what was received during the day; pro-rating the
allowances - that this was not intended in the legislative
language. One Subcommittee member said that the statute may not
be served if there is no pro-rating, since it might be possible
for a few companies to take all the allowances.
Rachel Hopp had sent a fax to Subcommittee members outlining
several qualifying Phase I technology allowance allocation
scenarios. She briefly reviewed these scenarios and asked
Subcommittee members to start thinking about this.
Mr. Markowsky said that AEP did a survey of vendors for nine
utilities (20 units, 16,000 MWe) that have contracts on
scrubbers. The survey indicated that this would result in 4.5
million tons of allowances being used. Bill Steinraeier argued
that no one should be left out. Jerry Eyster stated that if
there was a minimum unit of time of one day for submittals, this
would deal with the equity issue. Jim Markowsky stated that
there is a need to establish a procedure for dealing with the
first come/first serve issue and that the decision needs to
include allocation of all or none of the allowances to a utility.
Rachel Hopp said that the issue of allocating allowances on an
all or nothing basis needed to be given further consideration by
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the Subcommittee. For example, if on day 1 there is
oversubscription, should each Unit be treated separately or
should all the units from one utility be treated together? She
also asked if it should be left up to the utility to decide if
they want to receive partial allocation of allowances? Ned Helme
said he felt it should be left at the unit level rather than by
utility and mentioned the option of a lottery.'
One Subcommittee member asked iabout what would happen if a
transfer unit were to be picked up, but the control unit was not.
Rachel Hopp said that the application would have to link the
transfer and control unit so that they would be considered
together.
One Subcommittee member mentioned that the utility would have to
have a strategy behind their submissions - that they need to
think about multiple submissions to increase their chances in a
lottery. He felt that multiple submissions would also result in
spreading out of allowances.
Bill Roberts mentioned that the quality of the applications will
vary and asked how this would 'impact on allocating allowances.
Ms. Hopp stated that although ;EPA was exploring ways of giving
the industry an early indication of their presumptive place in
line, a successful utility would lose its place if the subsequent
permit application submission 'was not adequate. One Subcommittee
member said that EPA needs to identify the basic elements of a
permit application up-front. I Rachel Hopp said that the elements
would be defined as part of the rulemaking process, and that an
initial submittal, for the purposes of an early presumptive
ranking, may not have all the components of a complete permit
application.
Jim Markowsky talked about what it takes to get a scrubber in
service. He estimated it would take 36 months to design the
scrubber and 4 months to install, plus time for licensing and
permitting. Therefore, he felt oversubscription will be more
likely for '96 than for '95. He said that if EPA sticks with the
first come/first serve legislation and a utility does not make
the cut, this could cause problems. Bill Roberts mentioned that
if the unit were down during this time, allowances would not be
as much of an issue as the reduction. Mr. Markowsky cited
another survey conducted by AEP (which is confidential) of
utilities considering more than one scrubber. He said these
utilities will run into problems because the statute does not
allow for allowances over a fraction of a year, e.g., 1 1/2
years. Rachel Hopp said that;the utility would only get the
allowances for the years they;are needed and that he needed to
consider that units with scrubbers in-place can bank the
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allowances. She said it would not be advisable to start changing
the allowances as they are laid out in the statute.
One Subcommittee member said the main issue is that the utilities
need to know early if they are going to get these allowances and
that a reasonable mechanism is needed for choosing between all
the applications received on one day. Ms. Hopp said that the
mechanism for determining first come/first serve needed to
consider not only the applications received on the one day but
also the applications received before that date.
Jim Markowsky said that he felt the Subcommittee should focus
first on the extension mechanism then on a mechanism for
determining who is first. Rachel Hopp asked Subcommittee members
to develop suggestions for dealing with the first come/first
serve issue. The Subcommittee agreed to do this.
Reduced Utilization
The discussion on reduced utilization began with the issue of
compensating units and the applicability of NOX requirements to
these units. Mark Steinberg said that there is no NOX target for
Phase I. However, he said that if the original Phase I unit
already had NOX controls in-place, he did not see why the
compensating unit should not be subject to NOX controls. Bill
Roberts cited Section 408(c)(1)(b). Mr. Heckman said this was
similar to the substitution unit issue. Mr. Steinberg said there
was a difference between substitution units and compensating
units. For substitution units, the planning was always forward
looking. For compensating units, the planning could not always
be forward looking, since the utility could not predict
situations like outages. He argued that if the cause of reduced
utilization was something that could not be planned for, the
utility should not be subject to the reduced utilization
requirements.
Bill Roberts asked Mark if he was saying that the compensating
unit was not covered. Mark said this was his original thinking,
but that he feels this flies in the face of the staitute. He
proposed a compromise - in the case where something can be
predicted, the reduced utilization requirements should apply; in
the case where something can not be predicted, these requirements
should not apply.
EPA staff had to leave the call at about 3:45 PM because of a
fire alarm. Rachel Hopp asked one of the Subcommittee members to
take minutes on the remainder of the meeting. These will be
appended to these minutes.
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Attachment
List of Attendees
Subcommittee Members Attending via Teleconference:
Richard Abdoo, Wisconsin Electric Power
Tony Earl, Quarles and Brady
Steven Winberg, Consolidated Natural Gas
William Steinmeier, Missouri Public Service Commission
i
William Samuel, United Mine Workers of America :
James Markowsky, AEP Services Corp.
Ned Helme, Alliance for Acid Rain Control
James Hambright, PADER Bureau of Air Quality control
Paul Feira, Wheelabrator Air Ppllution Control
Jerry Eyster, A.T. Massey Coal Company
Thomas Maiman, Commonwealth Edison
Steve Burton, Sithe Energies
Luther Heckman, Coalition for Environment-Energy Balance
John Daniel, VA Department of Air Pollution Control
List of Subcommittee Members Npt Attending
C.V. Mathai, Arizona Public Service Commission
Vicki Tschinkel, Landers and Parsons
EPA Attendees:
Rachel Hoppf OAR/ARD
Joe Kruger, OAR/ARD
Karen Kent, OAR/ARD j
Claudia O'Brien, OAR/ARD
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Meeting of the-ARAC-Subcommittee on Permits and Technologies
Omni Shoreham, Washington, D.C.
January 28, 1991
9:00 AM to 5:00 PM
Meeting Minutes
The Acid Rain Advisory Committee (ARAC) Subcommittee on Permits
and Technologies held an open meeting on January 28, 1991 from
9:00 AM to 5:00 PM at the Omni Shoreham Hotel in Washington, D.C.
A list of the ARAC Subcommittee members and EPA representatives
participating in this meeting is included as an attachment. Mr.
Richard Abdoo served as meeting chairman.
Mr. Abdoo opened the meeting at 9:10 AM by introducing the
Subcommittee members and EPA representatives. Mr. Abdoo briefly
reviewed the meeting agenda and the approach for meeting
discussions. He noted that the Subcommittee may not reach full
consensus on every issue raised during this meeting. It was
agreed that if the Subcommittee was not moving forward on an
issue, the issue would be set aside and revisited, if time
allowed. Tony Earl mentioned that the members had agreed at the
last Subcommittee teleconference, during which he represented Mr.
Abdoo, on the need for an early rulemaking on Qualifying Phase I
Technology Extensions. He then asked Rachel Hopp to summarize
EPA's Draft Options paper of 1/24/91 on an early rulemaking for
qualifying Phase I extensions (item P17 in the package of
materials).
Discussion of an Early Rulemakina for Qualifying Phase I
Extensions
Rachel Hopp began the discussion by saying that this issue has
been raised to Bill Rosenberg. She noted that a key factor in
determining the timeframe for an advanced rulemaking is the OMB
review process. She described that in the 18-month rulemaking
process, the proposed and final rule (along with the RIA and
other supporting documentation) will be sent to OMB for review
prior to publication in the Federal Register. In order to
conduct an early rulemaking, OMB would need to waive or
streamline the traditional review (three months), and would need
to feel comfortable that any unresolved issues will be addressed
during the 18-month rulemaking process. She also noted that
disadvantages, to an early rulemaking include the increased
possibility of litigation, and the resource drain on EPA.
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Ms. Hopp briefly reviewed the I Draft Options paper, which included
four scenarios for "Qualifying Phase I Extensions Allowance
Allocations". She reviewed the assumptions used for these
scenarios (page 9 of item P17), followed by a review of each
scenario. (See attachments) . '•
Scenario 1 - Extension Unit Orily - Ms. Hopp discussed the impact
on the reserve under this scenario and briefly reviewed the
calculations in each column. There were no comments on this
scenario.
Scenario 2 - Extension Unit and One Transfer Unit - Ms. Hopp
reviewed this scenario, noting the increase in the impact on the
reserve due to the addition of one transfer unit. She noted that
the more transfer units that are added, the greater the impact on
the reserve to cover emissions during 1995 and 1996.
Ned Helme asked for clarification as to how the transfer unit
would impact the reserve. Ms. Hopp explained that the, drawdown
from the reserve by the transfer unit was only for years 1995-96
and that the transfer unit would not receive bonus allowances.
Jim Hambright said it would seem that there would be a point
where adding transfer units would result in an allowance deficit.
Ms. Hopp referred him to Scenario 4, which illustrated the
addition of multiple transfer units to the point where the
emissions reductions achieved by the 90% control unit would be
overcommited. She stated that this was an issue for the
Subcommittee to discuss.
Jeff White of AEP was asked by Jim Markowsky to discuss a paper
he had developed on this issue. Mr. White said he had talked
with John Wood of Senator Bird's office regarding this issue. He
said that a transfer unit should be thought of in terms of an
"allowance flow", rather than;in terms of a transfer of a
"reduction". He then gave an example. If 100,000 tons is
reduced by 90% to 10,000 tons, and the unit has a Phase I basic
allowance allocation of 50,000 tons, then 40,000 tons is amenable
for transfer. He mentioned that he sees several problems in the
statute - in some places in Section 404(d), it is not clear
whether the Phase I unit is a control unit or a transfer unit.
His reading of Section 404(d)(5), however, is that the statute
allows for "flux" from the reserve. He said that the bonus (two-
for-one) allowances in 404(d)(6) should be thought of as base
allowances that were not consumed by virtue of control. Rachel
Hopp noted that his presentation seemed consistent with the
calculations in Scenario 2. Mr. White and several Subcommittee
members agreed the formula for calculating bonus allowances was
correct.
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Several Subcommittee members expressed confusion over how this
would apply for multiple units.
Tony Ahern of AEP was asked by Jim Markowsky to give an example.
If 100,000 tons is reduced with 90% control to 10,000 tons and
the basic Phase I allocation is 50,000 tons, then the unit is
underemitting by 40,000 tons. The 40,000 tons can then be
applied to other units. He referred to Scenario 3 - showing 2
units, each assigned 20,000 tons. Several Subcommittee members
asked for clarification on how this would result in a "drawdown"
from the reserve. Mr. Ahern referred them to Scenario 3
(multiple transfer units), which shows a total impact of 222,000
vs. 182,000 in Scenario 2 (one transfer unit). Jim Hambright
clarified that the 40,000 tons was not a "bonus" but, rather, the
difference between the Phase I allocation and the achieved
reduction.
Jerry Eyster said that a transfer unit could be: (l) a Phase I
unit, (2) a Phase II unit, or (3) a unit from outside of the
program. Brian McLean added that a utility would not bring a
Phase II unit in, unless it was economical to bring it in via
substitution. Jerry Eyster said that, in a Phase I to Phase I
transfer, both units are already in the program; therefore, why
does this type of trade need to be called a "transfer"? Brain
McLean responded that the advantage has to do with the utility
not wanting to control one of the Phase I units.
Jim Hambright referred to Scenario 4 and the question "If
multiple transfer units are permitted, should this
overcommittment be allowed?" He said he was not sure if the type
of grouping described in Scenario 4 was allowed under the
statute. Brain McLean asked for clarification as to why Scenario
4 would not work within the statute. Rachel Hopp responded that
this scenario is not expressly prohibited under the statute, but
that it would be helpful to the Subcommittee to consider whether
this should be allowed. She said the Subcommittee should
consider: (1) whether overcommitment to a control unit should be
allowed; and (2) whether Phase I units should come in as transfer
units.
Jerry Eyster said that once a unit transfers its obligations to
another, the limiting factor becomes the emissions allowed. He
added that the Subcommittee needed to decide if they were in
agreement that Phase I to Phase I transfers were contemplated and
allowed under the statute.
Rachel Hopp asked the Subcommittee if the allowances for the
transfer unit(s) under the scenarios presented should not exceed
40,000 tons, i.e., the emissions reductions achieved by the
control unit. The Subcommittee agreed that such a limit on
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transfer units should be implied, in order to avoid depletion of
the reserve by multiple transfer units with little or no
scrubbing occurring. '
Ms. Hopp asked the Subcommittee if there was agreement! that Phase
I to Phase I transfers were allowed. She added that the text of
the law would allow for this. : Jerry Eyster said that if the law
allows for this, how can the Subcommittee disallow it, and added
that the Subcommittee should stay with the approach that allows
for maximum flexibility. Rachel Hopp added, if the utility
applied for an extension and the extension unit was not the
control unit, then the utility would need to bring the control
unit in and would need additional allowances to allow for
operation. Jim Markowsky asked if this was something that should
be allowed? He said that thete could be cases where the utility
scrubs one Phase I unit, but has enough allowances left to cover
a second Phase I unit as a "transfer" unit and therefore, does
not have to scrub this second unit - this would be the least cost
approach. Vicki Tschinkel asked if this would be a fair
approach. Tom Maiman added that he did not think it was an issue
of fairness. Bill Samuel said it was his understanding that the
Senate proposal looked at "bubbling-in" plans to allow the
extensions to work. :
Dick Abdoo asked if there were ways to build in fairer allocation
techniques. Jim Markowsky said he read the statute to allow for
transfer to Phase I units - with the utility that asks for the
extension first getting it. Jerry Eyster said that the
Subcommittee needs to contemplate the structure of the statute -
under the statute, a Phase I unit can apply for an extension, but
the idea of a "Phase I umbrella" is not clear. He noted that
some of the confusion can be attributed to the fact that parts of
the statute were written at different times. He said that the
Subcommittee needed to come to a conclusion on the direction that
should be taken. Rachel Hopp added that the Phase I to Phase I
transfer will drawdown from the reserve, resulting in fewer
control units. Bill Samuel sa£d he feels this was contemplated
in the legislation. :
Ned Helme asked about partial transfers, i.e., only move 10,000
tons of the 40,000 tons available for transfer. He noted that
the scenarios in P17 look at what happens if the entire 40,000
tons is transferred, but do not address partial transfers.
Specifically, he asked whether! the remaining 30,000 tons could be
used for other units and how this would impact the drawdown on
the reserve (i.e., how do you f'score" a partial transfer?) Jerry
Eyster responded that the compliance plan should credit those
allowances towards that transfer. Dick Abdoo added that the
"leftover", in this case 30,000 tons, could either be applied to
other units or sold. Both Rachel Hopp and Jim Markowsky added
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that the additional drawdown from the reserve for the transfer
units occurs only in 1995-96, and that the units would have to
meet the 2.5 Ibs/mmBTU emissions rate in 1997 as a whole.
Jeff White AEP added that 404(d)(l) defines an eligible extension
unit as: (1) a unit that employs eligible Phase I technology; or
(2) transfers its emissions reduction obligations to a unit
employing eligible Phase I technology. Jerry Eyster agreed that
either interpretation can apply.
Dick Abdoo asked the Subcommittee if there was consensus that
Phase I to Phase I transfers are allowed. The Subcommittee said
there was consensus.
He asked if there was consensus that Phase I units can transfer
their emissions reductions obligations to Phase II 90% control
substitution units, as long as there is no overcommitment. The
Subcommittee said there was consensus.
Rachel Hopp mentioned that the cap for overcomittment is
determined by the control unit. Jim Hambright clarified that
this was the case only until 1997. Brian McLean asked about the
impact on the bonus allowances. Rachel Hopp asked the
Subcommittee whether bonus allowances should be included in
assuming overcommittment, and what their understanding was of how
overcommittment was determined. Several Subcommittee members
responded that the determination is based on emissions reductions
by the control unit over its basic allocations; they added that
it should not include the 2-for-l bonus allowances for 1997-99.
Dick Abdoo asked if there was consensus that multiple transfer
units are allowed, not to exceed emissions reductions achieved.
The Subcommittee said there was consensus.
He asked whether transfer units should be limited to one plant or
whether they could be any unit within a system. The Subcommittee
agreed the unit could be any unit within a system and did not
need to be within the same plant.
Jim Hambright asked whether the transfer unit could be part of
another system. Rachel Hopp said that this could be done from a
permitting standpoint. She said the Designated Representative
concept could be used to deal with the "control" issue, and that
cross-referencing compliance plans would be needed.
Ned Helme added he felt that the transfer should be allowed to
any eligible unit, and not limited to a plant or system. Jim
Hambright,said he did not think this would be a problem for the
control agency, but noted it could pose a problem for the PUC.
Rachel Hopp added that if there was one Designated
Representative, this could deal with the concerns about
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transferring to a unit outside a plant or system. Jim Markowsky
asked Bill Steinmeier to comment on what problems transferring
across states present. Bill Steinmeier replied he could not
anticipate what the problems might be at this point in time.
Rachel Hopp suggested that, in developing the compliance plan, a
utility might need to make it clear to the PUC that this was the
approach they were going to take. She added that this might
create some uncertainty for the utility. Bill Steinmeier said he
would bring this issue up at the NRRI meeting. Dick Abdoo said
he thought the Subcommittee should recommend that transfer to
different systems in different states be allowed and said that
the PUCs will need to consider how they want to deal with this.
Vicki Tschinkel mentioned cross-jurisdictional boundaries - that
the state or, more likely, the local jurisdiction, could disallow
this type of transfer. Jim Hambright added that, if there were
concerns about general environmental impacts, the state would
definitely be concerned. Vicki Tschinkel added that another
concern was how permits were coordinated between local
jurisdictions and states. Rachel Hopp restated the importance of
having a clear definition of Designated Representative.
Jerry Eyster asked whether a decision had been made about
transferring to a Phase II unit. Rachel Hopp noted that the
general thought had been that utilities would scrub their
"dirtiest" units (i.e., would'scrub a Phase I unit). Jerry
Eyster said that, in some cases, the amount of emissions from a
Phase I and Phase II unit could be close; therefore, it might
make sense in some cases to scrub a Phase II unit. Ned Helme
clarified that the Phase II unit come in as a substitute unit.
Jerry Eyster responded that this might result in a restriction on
the Phase II unit that it must be within the same system. Rachel
Hopp clarified that the limitation on substitution units is that
they must be "under the control" of the same owner/operator as
the Phase I unit, but that the term "under the control" was not
expressly defined in the law. She added that the regulatory
definition should allow for maximum flexibility. She preferred to
her earlier discussions of Designated Representative as possibly
providing the necessary leveliof control. Jerry Eyster said that
if substitution is used, the utility could get more "bang for the
buck" (he briefly described the need for allowances in 1995-96
vs. waiting until 1997 to scrub). Jim Hambright asked for
clarification and whether it yas the intent of the Act to allow
this reserve of allowances to be used for Phase II units. Brian
McLean explained that this would allow a utility to defer part of
its Phase I control - the substitute unit would serve as
"backfill" for the Phase I unit.
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Jerry Eyster asked whether a substitution will consume the
available allowances. Brian McLean and Rachel Hopp explained
that the allocation to the substitute unit does not impact the
3.5 million allowances. Since the Phase II unit would not
consume the 1995 and 1996 allowances from reserve if it was
operating at less than 2.5 Ibs/mmBTU.
Dick Abdoo asked if the Subcommittee had reached consensus that A
Phase I unit can transfer to a Phase II unit. The Subcommittee
said there was consensus.
He asked if there was agreement that transfers could occur
outside the unit's system, if there was a single Designated
Representative responsible for the control of the unit. The
Subcommittee said there was consensus.
Rachel Hopp noted that this issue relates back to the issue of
Designated Representative, and added that the Subcommittee had
not agreed on how this concept would work. Dick Abdoo said that
the definition of Designated Representative was more of a legal
question than a technical question. He suggested that the owners
could warrant a representative. Rachel Hopp suggested that,
rather than try to define this term here, EPA will develop some
procedural options for designating a representative and will send
them to the Subcommittee for review. Mr. Abdoo agreed with this
approach.
Regarding minimal criteria for ranking applications, Rachel Hopp
explained the need to specify criteria for the applications for
presumptive rankings. She clarified she was not discussing the
requirements for full permit application, as these will be
defined through the 18-month rulemaking process. The purpose
would be to ensure that ranking applicants who are not making a
good faith effort do not tie up a presumptive place in line. Tom
Maiman asked about penalties for false certifications. Rachel
Hopp said that EPA had not considered this, at this time.
Jim Hambright asked about the timeline. Jim Markowsky said that,
in order to get a scrubber in-place by 1996, utilities should
have drawings completed and signed contracts in place with
vendors by August. Jerry Eyster said that if this wais the case,
why was an expedited rulemaking needed and asked whait information
was needed to influence their decisions. Jim Markowsky responded
that while the utility will need to have signed a contract with a
vendor by August in order to install by 1996, the utility still
needs to know as early as possible whether they will get the
extension -i.e., whether they can move forward with the contract,
which will include some type of cancellation or escaipe clause, or
whether they need to develop an alternative compliance strategy.
He reiterated that the planning process is very lengthy and that
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if a utility will have to change its plans, it needs to know as
soon as possible.
With respect to what should be; included in an application for a
presumptive ranking, Mr. Markowsky argued that the requirements
should be rigorous, and include the detailed drawings and
specifications for the scrubber, in addition to certification
that a contract had been signed. Rachel Hopp asked whether this
approach would result in some futilities being excluded. Bill
Samuel added he did not think j utilities who were "not as far
along" should be penalized. Jim Hambright said that the industry
cannot afford to have frivolou|s applications tying up places in
line - by the time EPA has made the determination that these
applications are inadequate, it will be too late to reallocate
these allowances. ! -
i
Dick Abdoo suggested the application include preliminary
engineering drawings, preliminary cost estimates and preliminary
alternatives (similar to the level of detail of what might be
included in a notification for; repowering). He added that EPA
should not require a copy of tjie contract itself, in order to
protect the competition between vendors. Several Subcommittee
members concurred with this idea.
Jim Markowsky argued that the "minimum" requirements for the
application should be rigorous;, to ensure that only utilities who
are serious apply. He added this approach will reward those
utilities who have done their homework and made an effort to move
forward. Vicki Tschinkel suggested that the application include
a sign-off by the PUC. She added this would avoid the ineed for
including the actual contract in the application, which she feels
does not make sense. Dick Abdpo pointed out that PUCs operate
differently as far as approval and sign-off procedures ;and that
not all PUCs require that approval. Several Subcommittee members
mentioned that they had not been aware of this, but agreed that
such a sign-off would not be practical since it was not required
by all PUCs. |
Luther Heckman stated that thejapplication should not be of such
length that EPA has to go through "reams" of paper. Rachel Hopp
mentioned, as an option, that the applicant certify that there
has been some type of public involvement. She asked whether EPA
should create a process, through the early rulemaking, that would
ensure minimal due process. Several Subcommittee members
disagreed with this approach, i Tony Earl said he strongly
disagreed with a public involvement step, adding that every state
and PUC works differently as far as PUC requirements and as far
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as public participation requirements. He recommended that public
involvement not be applied at this stage. Rachel noted that
delaying public involvement increases uncertainty, since there is
the possibility for public opposition later in the process.
Jerry Eyster said that the criteria for the application should be
such that the people who have moved forward - who have reached
some threshold first - are rewarded. He argued that equity was
not an issue; rather, the Subcommittee needed to define what the
"threshold" or "test" should be to determine if a utility can
qualify for a presumptive ranking. Paul Feira asked what would
happen to those who were not planning to get their scrubbers on
until later - would this approach exclude these people? Rachel
Hopp noted that if the criteria are too strict and people feel
they are being excluded, this could impact on the success of an
early rulemaking. She reiterated that, if people in the
regulated community disagreed with this approach, the rule may be
challenged, resulting in a delay or blocking of the early
rulemaking.
In terms of possibly excluding people, Tom Maiman said" he did not
feel that the Act contemplated equity and that the intent was to
reward those who are prepared. Rachel Hopp said that the intent
of Act was to provide maximum flexibility and that the permit
application was not intended to impose an undue burden on the
regulated community. Tom Maiman responded that because there is
a fixed number of allowances available, the Act contemplates that
someone will get left out. Rachel Hopp reiterated that, if the
criteria are too strict, the early rulemaking will not get off
the ground.
Bill Samuel asked if the purpose of the criteria was to try to
define a "minimal level of seriousness" on the part of the
applicant. Dick Abdoo said that there needs be trade-offs for
this early rulemaking and reiterated some of Rachel Hopp's points
on the difference between this type of rulemaking and the 18-
month rulemaking. He said that under the 18 month schedule, EPA
can be firm with the permit application requirements, since there
will be greater opportunity for public involvement, a full OMB
review, and other "safeguards" in the rulemaking process. This
will minimize the possibility that EPA will be sued over the
final rule. In an expedited rulemaking, these "safeguards" will
be limited. Therefore, unless everyone is in agreement with the
approach, th'ere is a high probability of a lawsuit. He,
therefore, recommends that the requirements be more liberal for
this expedited rulemaking. He said the question for the
Subcommittee to deal with is how to keep the requirements liberal
enough to avoid litigation, yet stringent enough to avoid
frivolous applications.
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Jerry Eyster suggested that one alternative might be to limit the
extent to which a permit application could be modified, i.e.,
hold people to what they say they are going to do in the
application (with the understanding that the application will
need some fine tuning).
Jim Markowsky asked Rachel about the schedule for an early
rulemaking. Rachel Hopp used Jan example that to promulgate in
August, with a one month comment period in July, would mean the
rule would be proposed in June. She added that the full ARAC
Committee still needs to reach agreement on this issue and that
the decision to waive OMB review rests with OMB and not with EPA.
[NOTE: During the full ARAC meeting on January 29,1991, Eileen
Claussen made it clear that the earliest date for publication of
an early rule would be November and that OMB review would not be
waived.]
Jim Markowsky said that the utilities who are serious are
thinking about this now, and hjave been looking at compliance
strategies for the last several months. Therefore, he feels that
these utilities will not object to stringent application
requirements, including drawings and contracts. Rachel Hopp
added since EPA will not have the full permit review process in
place for an early rulemaking, the more straightforward the
review for a presumptive ranking the better.
Jerry Eyster suggested that another way to reduce frivolous
applications would be to prohibit utilities from selling or
transferring their "place in line". There was general agreement
that this criteria be added. !'
John Daniel asked Rachel how comfortable she was that OMB will
allow the expedited rulemaking. She replied that this issue had
not been discussed with OMB, so she could not say. She noted,
however, that if there is full ARAC Committee consensus, this
will help. She added that the ARAC Committee needs to reach
consensus, not only on the need for an expedited rulemaking, but
also on what needs to be in the rule (i.e., the scope of the
expedited rulemaking). Dick Abdoo suggested that 2-3 members of
the Subcommittee meet to try to define the "minimum" requirements
for an application. Rachel Hopp mentioned that they should
develop options and that these options could be put forward for
comment in the proposed rulemaking. Brian McLean asked if anyone
was aware of other types of certifications or "statements of
tests" that might be appropriate for this circumstance. Jim
Hambright said he was not aware of any binding certifications.
10
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Dick Abdoo suggested that another incentive to avoid frivolous
applications would be to consider how the PUC categorizes project
planning costs (which the PUC may allow the utility to recover
through rate increases, etc) vs. expenses (which generally cannot.
be recovered through such things as rate increases) ., He said
that if an applicant were to file with a PUC, the dollars for
developing the application could be accumulated as planning
dollars. If the utility backs out, the dollars would become
expense dollars. Vicki Tschinkel said that not all states
operate this way.
Rachel Hopp asked if there was any way to run some of these ideas
by some of the utilities. Dick Abdoo mentioned the NRRI and UARG
meetings this week. Ms. Hopp asked the Subcommittee members to
please emphasize in their discussions with utilities, that the
early rulemaking is a preliminary suggestion. She reminded the
members that EPA has been advising utilities not to submit
applications, and that EPA will not review applications until the
final rules are promulgated in May of 1992; and that this will
not change until there is a formal decision by EPA to move
^forward with an expedited rulemaking. Dick Abdoo concluded that
the Subcommittee is not in a position to take the details of this
recommendation to the full Committee tomorrow; this will have to
-be done in February. However, it was agreed that the
Subcommittee had reached consensus on the need for an expedited
rulemaking and he will bring this to the full ARAC Committee.
Rachel reminded the Subcommittee that: under the expedited
rulemaking, the reserve will not have been established, i.e., the
3.5 millon will be the presumptive reserve. Under the full
rulemaking, this reserve will be established, using the specific
formula in the statute.
Break
Rachel Hopp referred to Scenario 2 and raised the cjuestion - if a
unit scrubs before 1995 but after enactment, does the unit get
the 50,000 allowances from the reserve during 1995 and 1996, as
if it were not controlling, or only bank the difference between
its basic allocation of 50,000 allowances and the 90% reduction.
Tom Maiman said the unit gets all the allowances. Jim Hambright
said that this would minimize the pool available for units that
need the additional time to add a scrubber.
Rachel Hopp asked the Subcommittee if they were in agreement that
the statute contemplated this allocation as indicated by Mr.
Maiman. -The Subcommittee members were in agreement.
She then asked about a unit that was scrubbing before enactment.
Several Subcommittee members suggested this would not be a Phase
I unit.
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Vicki Tschinkel asked Ms. Hopp to clarify the timeframe for
"already" scrubbing. Ms. Hopp responded this meant scrubbing
before enactment. Tony Ahern ;asked about retrofit scrubbers.
Jerry Eyster and Jim Hambright said that any retrofit unit would
need to be listed as a Phase i unit in Table A to be eligible to
receive Phase I extension allowances. There was a general
discussion among Subcommittee members about the list of Phase I
units. Rachel Hopp explained that the table was based,on 1985
data and some of the units may have installed scrubbers between
1985 and enactment. The question was whether a unit was still in
the system, if it no longer met the requirements. Jerry Eyster
said that once a unit is listed in Table A, it can not "get off"
the table. It was agreed that if the unit was listed on Table A,
the unit was a Phase I unit.
Rachel Hopp mentioned that the intent of the provision was to
encourage scrubbing. Several Subcommittee members agreed and
said that it clearly was the intent of the Act to exclude those
units that were scrubbing prior to enactment. The question was
whether there are any listed Phase I units that are already
scrubbing. Jerry Eyster suggested that the Subcommittee find out
how many Phase I units are already scrubbing. Dick Abdoo said,
based on information available to him, there are no Phase I units
that have gone out and installed scrubbers. He, however, agreed
to verify this information. Jerry Eyster raised the issue that
some states have acid rain provisions and these may have forced
early scrubbing. Rachel Hopp added that there are some units
that will scrub regardless of this provision. Steve Winberg said
that the Subcommittee should not redefine an "affected unit".
Dick Abdoo then asked the Subcommittee to discuss the "lottery"
concept. Rachel Hopp said that a lottery had been discussed as a
way to deal with applications coming in on the day the 3.5
million allowance reserve was exceeded, and as a mechanism for
determining first in line. She mentioned that she had spoken to
OGC and was advised that this could be done. Tom Maiman
expressed concern that utilities might sue if they do riot "win"
in rhe lottery. He also suggested that utilities might feel
pressure to sue from the PUC, since it is not clear what the PUC
would do if their utilities did not receive the extension.
Rachel Hopp clarified that Section 307 of the CAA allows only 60
days for a rule to be challenged. If there is no challenge
during this 60 days, then the rule will stand. If the rule is
challenged after 60 days, the suit would not have standing and
would be defeated. She said, though, that the rule will have to
get through the 60-day period. Jerry Eyster asked if any suit,
regardless of merit, could stop the lottery. Ms. Hopp said if
there is any challenge, this would need to be resolved first
before any lottery could give the applicants the level of
certainty desired. ;
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Jim Hambright suggested that an alternative plan was needed, in
case a lawsuit was filed. Ms. Hopp said that the key to limiting
the possibility of a challenge was to get full agreement
(Subcommittee, Committee and with the regulated community) on the
approach to the extensions.
Jim Markowsky said he did not feel a utility could run their
business by lottery. Rachel Hopp said there seemed to be two
options for the lottery: (1) conduct a lottery only for those who
come in on day one (i.e., everyone who comes in on or before this
first day is treated the same); or (2) rank everyone who comes
in, based on the day they come in and have a lottery for those
applications that arrive on the same day.
Jim Markowsky said that a utility might have an application for
each unit (e.g., a large utility might have 13 applications).
Rachel Hopp and Dick Abdoo reminded him that the utility must tie
the control and transfer units into one application. However,
beyond that, it would be up to the utility to decide on a
strategy - either submit one application for all units (win or
lose "big") or submit multiple applications (win smaller but
increase chances of winning).
Bill Samuel suggested proration as an alternative to a lottery.
If the applications received on day one were oversubscribed, the
allowances would be prorated (e.g./everyone would get say 92%).
He added that the intent of this provision was to encourage
scrubbing and to protect the economics involved. He argued that
an all or nothing lottery would not be consistent with this
intent.
Ned Helme commented that proration had been considered in
Congress and rejected by the Conferees.
Jim Hambright said that if a utility had only one unit, and the
allowances for this unit were prorated, the utility would have a
major problem. He added that even with multiple units, there
would be problems if the allowances needed were "clipped". Dick
Abdoo said that for a system, the utility could drop-off the
least economic unit and still be O.K. However, a utility with a
single unit would have a problem, as they have no other units to
"drop-off". Jerry Eyster said that the legislation does not
allow for proration. He said the law is specific on the order.
Vicki Tschinkel added that a lottery would also fly in the face
of the legislation. Rachel Hopp said that proration was
discussed and was rejected by Congress. Shelly Fidler (from the
audience) said that the conferees rejected proration, but that it
was not specifically discussed by Congress. She said it was
13
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E
included in a package of House! technical amendments that were
rejected, but that proration was not rejected specifically. Bill
Samuel agreed that this issue had not been specifically discussed
by Congress. !
Steve Winberg said that it is likely that there will be
oversubscription on day one. He commented that he did not think
the Subcommittee could develop, a procedure for addressing first
come/first serve. Dick Abdoo said that if the Subcommittee can
develop a procedure for notifying the utilities that there is
oversubscription, then the utilities may be able to negotiate
between themselves. Tony Earl;added that it would be the
utilities choice to "unbundle";an application and go with a unit-
by-unit approach. Steve Winberg asked what the options are for
utilities with only one or two units. Dipk Abdoo reiterated that
if a utility has multiple units, they could work with a proration
system; a utility with only one unit would not be,able to do
much. • i
Rachel Hopp asked the Subcommittee to look at three options: (l)
strict construction, (2) lottery, and (3) proration. Jim
Markowsky said he thought the statute's intent was "all or none",
and both he and Jerry Eyster stated that proration could not be
an issue, as it was not allowed by the statute (Jerry Eyster read
the wording from the Act). Rachel Hopp noted that it is an issue
since it has been raised by Bill Samuel as an option. Ned Helme
agreed that there was no basis for proration in the statute.
Bill Samuel argued that EPA cannot act "in order of receipt" if
there is no mechanism for establishing the order.
Jim Markowsky asked what the view of the PUC would be if a
utility were to tell the PUC that they did not receive the
extension because their number;"did not come up" in the lottery.
Bill Steinmeier responded that, while he has a problem with the
proration idea (he feels it would upset the economics), he would
be more likely to understand a|loss in a lottery - if the utility
could show that they had done the required planning and made a
good faith effort, but were not successful because of lack of
"luck", he would be inclined to allow the utility to recover the
costs of the planning. Dick Abdoo added that this seemed
reasonable. Bill Samuel asked how proration would upset
economics. Jim Markowsky responded that there was the issue of
frivolous applications. Tom Maiman added that proration may
force people out. Bill Samuel:argued that a lottery (1) had no
basis in the Act, and (2) does not serve the purpose or the
intent of the Act.
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P21
Steve Winberg asked how much a utility would have to invest in
order to be allowed to participate in the lottery. Dick Abdoo
said that was something the Subcommittee was going to address and
mentioned that several members had agreed to develop a draft of
the criteria.
Dick Abdoo summarized the alternatives discussed by the
Subcommittee - (1) stand in line; (2) treat all applications
received on day one equally, and, if oversubscribed, conduct a
lottery; (3) proration. He then conducted two strawman votes of
the Subcommittee members - for the first vote, stand in line and
lottery were grouped. The results were 2 members for proration;
the remainder for stand in line or lottery.
Jim Markowsky said he would like to see how other utilities felt
about these options. Luther Heckman pointed out that the stand
in line option might be one of the best in terms of ensuring the
seriousness of the applicants.
Dick Abdoo suggested that the Subcommittee take a strawman
position on stand in line or lottery and try to get feedback from
the utilities during the NRRI and UARG meetings.
Bill Samuel asked if the vote could be taken again, separating
stand in line from lottery. The strawman vote was retaken and
resulted in 2 members for proration; 6 for lottery; 4 for stand
in line.
Rachel Hopp asked whether frivolous applications could be
minimized by requiring the Designated Representative to be the
one to stand in line. The Subcommittee members felt this would be
too restrictive.
Vicki Tschinkel said that the Subcommittee needed to discuss the
proration issue further. Jim Hambright suggested the possibility
of proration for the transfer units only. Rachel Hopp asked what
would happen if the allowances were used-up on the control unit,
and nothing were left for the transfer'unit. She added that if a
utility submitted an application linking the control and transfer
unit(s), it can be assumed this was done for economic reasons.
Jerry Eyster added that proration creates another set of outcomes
and increases the level of uncertainty. Bill Samuel argued
whether the role of the Subcommittee was to reduce uncertainty.
Rachel Hopp responded that the need for certainty is what the
Subcommittee has said is needed, and is the basis for requesting
the expedited rulemaking.
Vicki Tschinkel asked about Scenario 3 and whether the charts
were right. Jim Markowsky said that the charts were consistent
15
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with his paper and explained the basis for the calculations, as
follows: the 40,000 tons was the amount available for
distribution, regardless of the number of transfer units (i.e.,
the emissions reductions from the control unit was the limiting
factor, not the number of transfer units). There was a general
discussion among Subcommittee1 members regarding the chart in
Scenario 3. Rachel Hopp clarified that the column for "annual
reserve allowances needed" applied only to 1995-96, and repeated
the Subcommittee's earlier agreement that the allowances
available to the transfer units could not exceed the allowances
generated by "overcontrol" ofj the control unit (in this case the
control unit overcontrolled by 40,000 tons; therefore, 40,000
tons is available for distribution to the transfer units). Only
the control unit receives bonus allowances in 1997-99. John Wood
(from the audience) added that, in determining the cumulative
allowances from the reserve for the control unit, the allowances
in years 1997-99 were added together i.e., 14,000 tons per year
for a total of 42,000 tons, which must be added to the annual
reserve allowances needed in 1995-96 (50,000 tons/yr) to
determine the drawdown from tljie reserve. Jim Hambright added
that the bonus allowances are;not available for use in 1995-96.
Dick Abdoo suggested the Subcommittee seek input from NRRI and
UARG. He noted that the Subcommittee was divided at this point.
Tom Maiman questioned how useful this input might be, considering
that this will be the first time many of the members of NRRI and
UARG have heard about this issue. Dick Abdoo responded that he
did not expect this input to be definitive, rather this was an
opportunity to obtain additional information.
Dick Abdoo then took a strawman pole of preferences for (1)
proration if no lottery - no hands; (2) stand in line if no
lottery - few hands; (3) stand in line if no proration - no
hands. Steve Winberg added that it was hard to vote without
knowing what the ranking application requirements will be. Jim
Hambright suggested these requirements not be too restrictive.
Dick Abdoo agreed, but said that some restrictions were
necessary.
Dick Abdoo summarized that four Subcommittee members had agreed
to develop recommendations on what constitutes a valid permit
application for the purposes of the presumptive ranking. He said
this will be discussed with NRRI and UARG. He asked for
volunteers to draft recommendations regarding the Designated
Representative issue. Rachel Hopp suggested that EPA develop the
first draft. She said that EPA would need to have minimal
procedural safeguards for establishing a person's Designated
Representative status. In that way, if someone were to challenge
a designation, EPA could rely on the representative's
demonstration that the procedure was followed. Dick Abdoo asked
; 16
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Rachel to get this to the Subcommittee for the conference call in
February. She agreed to try .to have something drafted by that
time. Dick Abdoo said he was looking to have a draft of the
ranking application requirements by next week.
Break
Dick Abdoo suggested a reverse in the agenda order for the
afternoon discussions - substitution plans, reduced utilization,
then repowering if there is time. He then suggested that they
move to the next topic, as Luther Heckman had not returned from
the break.
Reduced Utilization
Ned Helme led the discussion. He handed out a revised options
paper. He briefly reviewed the main points of his paper
regarding the threshold test for utilization applied on a system-
wide basis. He said that, during the last conference call, the
Subcommittee had agreed with this concept of a system-wide
approach, and the idea that the utility would only need to look
at the individual units if utilization fell below the threshold
level (the,baseline established during 1985-87). He said that
the issue that was not resolved was whether this test applies
prospectively or retrospectively.
He mentioned that if a plant goes down unexpectedly, the
allowances are freed up. In this case, the utility needs to
identify the compensating unit and the allowances that need to be
recovered. Alternatively, the utility could give-up those
allowances. He mentioned that there is a need to be
retrospective, and he feels Section 408 requires that the utility
be retrospective, in addition to being prospective. Dick Abdoo
asked what would happen if utilization were reduced because of
conservation. Ned said that if there is demonstrated/certified
conservation, the utility should be able to keep these
allowances. Tom Maiman added that it may be difficult to certify
that the change was due to conservation vs. a shift in load. Ned
Helme agreed.
Jim Markowsky added that other unforseen causes of reduced
utilization include weather and economics. He mentioned that the
approach presented by Ned could almost be viewed as a "cap". Ned
Helme agreed that the statute sets no cap on emissions during
Phase I. Tom Maiman clarified that he was concerned about what
happens to a Phase I unit in the case of- a catastrophic event .
He said that the utility would now have to pick-up the capacity
with a Phase II unit or a non-affected unit and asked what
happens to these units. Ned Helme responded he did. not think
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that the utility should have to bring-in a non-affected unit
under such circumstances (e.g.!, if a turbine blows), in this
case, the allowances would be |freed-up for use. Rachel Hopp
asked for clarification as to how this would be handled in the
compliance plan. Ned Helme and Brain McLean said that the
utility would need to indicate;, as part of the compliance plan,
that the utilization of the Phase II unit would be increased.
Jerry Eyster added that there would need to be an administrative
presumption that the utility would use the allowances freed-up by
the catastrophe on a compensating unit (i.e., the utility could
not "benefit" from a catastrophe). Several Subcommittee members
agreed. He added that the utility would want to avoid bringing
a compensating unit into Phase I, along with the associated
implications of a Phase I unit.
Brian McLean said that the utility could include reduced
utilization of a Phase I unit 'in the compliance plan, but that
there was no way to include a "planned" catastrophe in the
compliance plan. Rachel Hopp asked how other "unplanned causes"
of reduced utilization (e.g., weather, economic) should be
handled. Ned Helme said these should be treated the same way as
discussed for the blown turbine - if the utilization is less than
the baseline, then the utility either forfeits the allowances or
identifies a compensating unit. With respect to unforseen
changes in economics as a cause of reduced utilization; Jim
Markowsky asked what should happen in the case where the
economics changed by 10%. Ned Helme said he did not think a 10%
change would occur within the timeframe they were concerned with
(about 10 years' from the baseline years of 1985-87). Jim
Markowsky agreed.
Jim Markowsky said there is a need to remain flexible and to be
prospective, but that he does hot agree with Ned Helme about the
need to be retrospective. He feels this is a major point of
departure that needs to be dis|cussed by the Subcommittee. Rachel
Hopp said that, if reduced utilization is used as a compliance
method, then there needs to be some level of retrospective review
to ensure compliance. Jim Marjkowsky responded that the utility
cannot predict changes in weather or economics. He said that the
utility uses the best information available at the time the
compliance plan is prepared to make projections. He argued that
there is no need for the utility to be retrospective when: (1)
the change in utilization is not under the utility's control; and
(2) the utility is not exceeding its emissions limits.
Rachel Hopp said, without being retrospective a utility would not
know if the utilization had been transferred to a compensating
18
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unit or if there had been a shift in load. Jim Markowsky said
that this type of accounting is already done on a state basis,
and that it is an accounting nightmare. Dick Abdoo reiterated
the complexity of this issue and asked Walter from his staff to.
discuss.
Walter Wolf (from the audience) said that the purpose of Section
408 is to prevent "gaming", but that there are also normal
fluctuations in utilization, as when a unit is taken off-line for
repairs. He said that: (1) any compliance plan must be in good
faith and must be enforceable; and (2) if a utility is running
under Phase I and something unplanned occurred to the extent that
this unit is no longer operational, the utility should not be in
a position to loose allowances. He feels Ned Helme has ignored
the scenario where all utilization would come from Phase II
units.
Rachel Hopp raised the issue of enforceability. If the
compliance plan says that allowances will be provided to
compensating units, how is this enough information on which to
make a compliance decision? She said that without information on
generation, there is no way to verify reduced utilization by the
unit. She argued that some type of check is needed.
Jeff White (audience) said that the Congressional Record (May 17,
1990) does not support Ned's "retrospective" concept. He said
the Senate and House reports spoke in prospective terms. He said
that Section 408 differs from earlier versions and that
408(c)(l)(B) is extremely broad and general, and mentioned that
the compensating unit provision was written over two years ago.
He feels, however, that if Congress intended this provision to be
"retrospective", this would be explicit in the legislation. He
argued that if EPA's intent was to develop an independent
regulatory system, this should have been done through the
legislation and not at this point in time. He said that the
primary parameter is tonnage of SO2 and that no where in the
legislation is it suggested that the compensating unit is a
regulated parameter. He agrees with Ned's concepts on a
prospective basis, but argues that, based on the House and Senate
reports, the retrospective concept is not supported.
Dick Abdoo said that with Jeff's interpretation, a decrease in
utilization of a Phase I unit that is "made up" by a compensating
unit would never be part of the compliance plan. Jeff White
(audience) argued that if Congress intended for this, they would
have included specific language regarding a "retrospective look".
He questioned how well this was debated in Congress. Ned Helme
pointed out that a 20% fluctuation in generation threshold was
considered by Congress and taken out, and said he did not believe
Congress fully debated this issue.
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Brain McLean noted that much of the legislation was written two
years ago, and since that time, a number of things have changed.
Originally it was assumed that the compliance plan would be
extensive. Now this is questionable; it depends on how EPA
defines the compliance plan. '
Rachel Hopp noted that, if reduced utilization .is identified as
an alternative method of compliance, then the compliance plan
would not need to be revised.; If, however, it is not identified,
the compliance plan would need to be revised in order for the
utility to use reduced utilization as a method of compliance.
Brian McLean asked what happens if reduced utilization is not
identified, but that at the end of the year it turns out that
this happened - would the compliance plan need to be amended?
Rachel Hopp responded that the statute would appear to require an
amendment, and that this is where the need for a retrospective
look comes into play. If the :utility fails to revise and meet
the plan, it is in violation of the regulations.
Jerry Eyster said that Ned's approach to accounting is fairly
simple, but he is concerned about any requirements that would
cause the utility to count on |a "minute-by-minute" or "hour-by-
hour" basis. He said the Subcommittee needs to discuss what
level of detail is needed. Ned Helme added that the compliance
plans need to be stringent, yet flexible - the utilities should
be allowed to trade to compensating units, but if they are
allowed to shift load, this could destroy the concept. Jeff
White added that the line of thinking could be advanced either
way - that it was hard to say what might trigger a lawsuit. Dick
Abdoo said that Ned's proposal seemed to leave the decision in
the hands of the owner/operator to trade the allowances or
identify compensating units and keep the allowances. He did not
see a basis for a lawsuit. Jejff White restated his argument that
a retrospective approach would have been spelled out in the
legislation, if this had been Congress's intent. Dick Abdoo
argued a retrospective approach is not precluded. Jeff White
argued that it is precluded, citing the verb tenses from the
Congressional reports. !
i . .
Rachel Hopp explained that the term "proposed compliance plan",
refers to the plan which is submitted by the applicant," and that
it is distinct from the term "final compliance plan" referring to
the plan that has been signed-pff on by EPA and for which a
permit has been issued. She stated that she did not believe the
term "proposed" was meant to imply that the compliance plan
should be prospective only, and that this terminology is used
consistently, regardless of which compliance alternative is
chosen. Finally she noted that the statute made the planning
obligation enforceable, requiring a retrospective look.
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Dick Abdoo .asked Jeff White what alternative suggestions he had.
Jeff White said that he has strongly argued that the compensating
unit provision is prospective. Therefore, he proposes that
companies can "discharge the duty" of this provision simply by
submitting projections of utilization for the Phase I unit. If
the projection is equal to or higher than the baseline and EPA
agrees that the projection is reasonable, then the company has
meet the obligations under this provision. Rachel Hopp asked
what criteria EPA would use to determine if this projection was
sensible. Jeff said that EPA could compare the projection to the
Energy Administration data available, and apply the readily
foreseeable growth rates to verify the projection.
Brian McLean asked about a 35 year old unit and how would EPA
know if there had been a drop? Jim Markowsky said that there is
no basis to assume that this unit would cycle; the age of the
unit is not important. Brian McLean clarified that what he was
asking was how valid 35 year old data were in projecting future
utilization? Rachel Hopp added that she was concerned about the
resources needed to do this. Permit application reviews to
determine if the projection was reasonable would be very resource
intensive. She did not think these reviews could be done in a
timely manner, and asked what happens if EPA disagrees with a
utility's own forecast? Jeff White said that Ned had opened the
door on making utilization a regulated parameter. He then asked
Rachel if she was concerned that companies might falsify
forecasts. Dick Abdoo said it was not an issue of whether the
company would falsify a forecast, but. rather the difficulty in
developing a correct forecast. Rachel Hopp reitereited her
concerns about the resource drain of such an approach. Jeff
White asked which was more resource intensive - reviewing the
reasonableness of a forecast once or conducting retrospective
reviews year-by-year? Rachel argued that EPA has to do the
latter to determine the success of the program and that the
reviews would be based on actual data, not on forecasts. Jerry
Eyster said the burden for a utility to calculate on an annual
basis if they went up or down is trivial compared to the bigger
burden of developing a 5-year forecast.
Jeff White and Luther Heckman asked about civil penalties. Ned
Helme said he thought they would not apply. He said his approach
is trying to support a simpler approach to compliance. Dick
Abdoo suggested the Subcommittee give this further
consideration. He suggested they not focus on the "lack of
discussion" in the Congressional record about a retrospective
view, since it seems clear that the Subcommittee members disagree
with Jeff White; and believe that the Act does allow a
retrospective approach.
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Jeff White argued that, under,Ned Helme's approach, the use of
compensating units creates continuing obligations on the part of
the^utility. He argued that his approach is a "one shot"
obligation and that a continuing obligation with EPA ijs not
advisable. He also said that he does not read the law as
requiring a threshold level, therefore, it should not apply. Ned
Helme responded that he is only talking about an approach
applicable until the year 2000. He said the law does not
preclude his approach and that the law actually lays the
groundwork for his arguments. Jeff White responded he did not
feel this was valid. He said jthe absence of language should not
be used as a basis for an argument.
To clarify the issues, Rachel ;Hopp paraphrased Jeff White's paper
of 1/11 for AEP: his argument is that the initial permit
application submission has to !have a compliance plan strategy and
if reduced utilization is proposed, then this must be addressed
in the plan. Once the plan is submitted, there is no further
obligation on the part of the company. At the time of initial
submittal, therefore, if the qompany is planning to use
compensating units, it needs to say so in the plan. However, if
at the time of the initial submittal, the company does not plan
to do this, this would not be 'in the plan. If this company later
decided to use reduced utilization as a compliance methods, the
company would be under no obligation to amend and resubmit the
compliance plan. Jeff said this was a correct description of his
position. An amendment of the Title IV compliance plan has to be
with the consent of the owner/'operator, per Section 408 (b).
Rachel Hopp asked him if he agreed that the compliance plan was
binding. He said he did, but that 408(b)(2)(c) only requires a
statement. Rachel Hopp clarified that the statement language
applies only in cases where the company plans to meet the
emissions limit by the compliance deadline (i.e., if the company
did not plan to use any alternative compliance strategies). If
the company planned to use an alternative method for compliance,
then the additional information required by EPA regulations would
need^to be included in the compliance plan. The compliance plan
is binding and enforceable, but the plan can be amended at any
time, if a different alternative is used at a later point in
time. Jeff agreed with this. : • .
Jim Hambright said the plan shpuld be amended prospectively.
Dick Abdoo asked who had the obligation to amend the plan. Jim
Hambright said the utility hasithe burden. Rachel Hopp added
that the test Ned proposes provides the basis. Dick Abdoo said
that if the utility files a compliance plan, then determining if
the plan needs to be modified should be easy for the utility.
Whereas for EPA to make this determination, he was not sure how
EPA would get enough information to determine if a compliance
plan needed to be modified.
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Tom Maiman added that weather and cither unforseen deviations
should not trigger a change to the compliance plan,. Dick Abdoo
said that if abnormal weather causes a change, how does the
company explain its plans to keep the utilization up? He said
that it might look like the company had a compensating unit that
it had not told EPA about.
Vicki Tschinkel asked whether the compliance plan should include
recordkeeping requirements. Dick Abdoo suggested there be an
annual report of some type on how the company complied. Vicki
Tschinkel added that the definition of success is difficult.
Rachel Hopp said that if a company can demonstrate that the
utilization fell below the baseline due to unplanned events, such
as weather or economics, this might be treated differently than
cases where the company makes no demonstration. She then asked
the Subcommittee about the reporting requirement isssue. Jim
Markowsky said that a year-end accounting might be part of some
type of year end report. Jerry Eyster said there are a number of
routine reports that utilities file already, though he did not
think these reports would dove-tail well with the information on
utilization.
Jim Hambright said that the reporting requirement should be
somewhat dependent on EPA resources. He suggested that reporting
on a more frequent basis might make more sense then sending in
reams of paper at year end. Rachel Hopp agreed. Jerry Eyster
mentioned monthly generation reports. Rachel said these would be
hard to use to tell the variation for the year. Dick Abdoo said
that if the load is dropped off the dirty units, then the company
could get into trouble.
Jerry Eyster asked if there was agreement regarding the issue of
retrospective? Jeff White said that there seemed to be agreement
regarding the use of the system-wide approach and the threshold
test, but that the hang-up seemed to be the legal issue of
prospective vs. retrospective. Tony Ahern, in the audience, also
of AEP, said he agreed with Jeff, especially for smaller
utilities. For example, he said that the Buckeye utility has
only 2 units. With the "fix" that has been offered, he said this
utility would have to turn over its allowances. Rachel Hopp and
Jerry Eyster both suggested that the utility can buy power as an
option. Tony asked what the utility was to do if the unit was
out for 6 months? Rachel Hopp suggested it could go to another
unit, bring in a compensating unit - the goal is to ensure that
there is no increase in emissions. Tony asked how a small
utility could do this - does the utility have to certify the
emission rate of the power they are sold? He added that, even if
the small utility had a compensating unit, this unit becomes a
Phase I affected unit, which would pose problems for the utility.
If the small utility does not have a compensating unit, then
23
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i
turning in the allowances is the only option for smaller
utilities. !
Rachel Hopp asked if the ability to "track" compensation is lost
as power is transferred over the grid (i.e., do we know where the
energy is coming from?) Ned Helme said that the utility selling
the power needs to look at this; the utility would need to
determine this in order to make a decision about the rate for
selling the power to another utility.
Dick Abdoo said it did not lopk like the Subcommittee was going
to reach consensus at this time. He added that he sees no fatal
flaws in Ned Helme's approach, and recommended that the
Subcommittee give this issue additional thought.
Steve Mindak (audience) said that many utilities are planning to
reduce utilizations at their "dirty" units and increase use of
the "cleaner" units. He said he does not want to see ;any
disincentive for this. He referred to the cost of dispatch in
1995 and added he did not wan^ utilities to have to wait until
the year 2000 to make these changes. Dick Abdoo noted that the
Subcommittee needed to work within the confines of the law. He
added that any Phase II unit that is used to compensate becomes a
Phase I affected unit and will have to meet NOX requirements.
I
Dick said there was more work to do on this and asked the
Subcommittee to try to come up with something next week.
Substitution Units ;
Luther Heckman led the discussion. He said he did not receive
any comments on his paper since the last conference call.
Several members indicated they had not had time to focus on the
issues. He recapped the main points of the paper, and asked if
there were any items to be discussed specifically. Rachel Hopp
said she would like to Subcommittee to discuss the argument
raised in the paper of whether, if a substitute unit is brought
in, the original unit is no Ibnger affected.
Tom Maiman said that for the affected units listed on Table A,
there is no way to make these ; units "unaffected". Luther Heckman
said that this interpretation :makes substitution a disadvantage
to a utility. Rachel Hopp cited Section 404(c)(2) which says
that both the original and substitute units are affected under
this title. Luther Heckman suggested the need to consider
another interpretation, in order to make substitution a viable
compliance alternative. Brain McLean said he does not see any
way around the interpretation that both units are affected. Dick
Abdoo asked Luther to clarify |what happens if both units are
affected. Luther said his concern was the NOX requirements.
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Rachel referred him to the NOX averaging provision.. Luther
responded that this was a double NOX requirement and asked the
Subcommittee to recognize that this interpretation essentially
removed substitution as a compliance tool. Tom Maiman reiterated
that the law does not permit this interpretation. He added that
there were a number of cyclone units for which the NOX
requirements would not apply. These units could be effectively
used as substitution units. .
Dick Abdoo asked if there was consensus that both the original
and substitute units were affected units. The Subcommittee
members agreed.
Luther mentioned that in addition to this issue, he would like, to
receive comments on the other issues discussed in his paper.
Rachel Hopp asked for discussion on the question of "control" by
the owner/operator, and whether the Designated Representative has
adequate "control" to take care of this, or whether control
requires "significant ownership". Luther Heckman said that if
someone can state to EPA that they have significant ownership and
had agreement to control the unit, the language of the Designated
Representative would need to parallel this idea. Rachel
clarified that the idea of the Designated Representative was not
ownership, but control. Jerry Eyster referred to the earlier
discussions on the Designated Representative (during the
discussion of transfer units). Rachel Hopp said the question is
what does the term "control" mean, since this term might imply
within the same company. She asked if the Designated
Representative could cover different utilities involved in
central dispatching? Brain McLean said that they need to
recognize the differences between transfer units arid substitution
units. He said, while the law does not preclude the Designated
Representative covering different utilities, it may not be
practical for addressing the control requirements in the case of
substitution units. Jim Hambright asked if "control" meant
control of dispatch? Rachel Hopp said the term meant sufficient
control to bind owners and operators, and could include control
over dispatch. Tom Maiman said this could be a problem, since
the person who controls the dispatch may not be in control of the
unit. The Subcommittee had a general discussion of the
dispatcher's responsibilities.
Jim Hambright asked Vincent (audience) for clarification.
Vincent said that the operator just runs the boiler; the load
could come from anywhere. Rachel Hopp said that the Subcommittee
is not bound by traditional CAA definitions of "operator". They
can define operator broadly to include the dispatcher. Jim
Hambright asked about legal actions? Rachel Hopp referring to
Section 402, said that the Designated Representative needs to be
25
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able to legally bind the owner;/operator. Although the
ramifications of this have not! been discussed, she said maximum
flexibility cannot be achieved; unless there is at a minimum,
joint and several liability. Tom Maiman said the operator has
control over compliance. Rachel Hopp said the question of
liability , if there is multiple ownership, may be resolved
between the owners; however, EPA does not want to become involved
in those disputes, which are governed by contract and property
law. Instead, EPA wants to deal with one Designated
Representative. Tom Maiman said the Designated Representative
would need to get agreement from each dispatcher on compliance.
Rachel Hopp said this would be an issue for the utilities to deal
with internally. Jim Hambright asked if the Designated
Representative would be criminally liable if he signed records
incorrectly? Rachel Hopp said; there is no criminal negligence
provisions for recordkeeping violations. She said liability
would be similar to that of corporate officials. Dick Abdoo
mentioned the NRC.
Dick Abdoo suggested EPA explore the role of the Designated
Representative. Rachel Hopp s;aid that if the Designated
Representative is properly certified by some standardized
procedure, EPA will have what they need. EPA wants to avoid
complex demonstrations.
Luther Heckman agreed to revise his paper, based on both the
original and substitute units being affected.
Dick Abdoo asked about issue B in this paper - should any
limitations be imposed on units that are considered substitute
units? Tom Maiman said that what if there are multiple units?
Rachel said the paper needs to be modified to reflect this.
Dick Abdoo asked about issue C - representation based on
ownership and how to deal with a change in ownership. Rachel said
this had been discussed in terms of the Designated
Representative. Dick Abdoo said that a change in ownership (if
it required recertification - i.e., the utility wants to change
Designated Representatives) would require a modification to the
compliance plan. Jerry Eyster added that this should not affect
the initial approval. Dick Abdoo said that any change in
ownership should require recertification of the designated
representative. Luther will add this to the paper.
Dick Abdoo asked about issue D - adequate documentation. Luther
said he read from the Act regarding what was needed. Rachel Hopp
said that if the Act specifies 5 items, then all five need to be
provided. Brian McLean asked if there was anything beyond the 5
items that needed to be provided? Luther mentioned the idea of
commitment, but that he does not see anything beyond that.
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Dick Abdoo mentioned that issue E was going to be revised per
today's discussions, then asked about issue F - demonstrations of
attainment. Rachel Hopp explained there was a prevision in Title
IV that allows the Administrator to require demonstrations of
attainment, Jim Hambright said the underlying value of this is
that the utility must be able to certify it is in attainment.
Rachel Hopp explained as further background, that generally under
the CAA, states are obligated to develop a SIP that attains the
NAAQS; the utility is responsible for meeting the SIP
requirements. Jim Hambright said that a number of units assume
they are in compliance with the NAAQS. Rachel asked if this was
a basis to require a demonstration in the case of a substitution
unit? Jim Hambright said only if the substitution unit is not in
an area in compliance with the NAAQS.
Jerry Eyster said that as part of the submission, do we want this
type of certification for each unit? Jim Hambright said that
there should be a general permitting requirement for
certification - not just for Title IV. Rachel Hopp said that the
Subcommittee needed to clarify the concept of "certification" vs
"may require demonstration". Dick Abdoo said that, the
certification was that the utility is in compliance with the
NAAQS. Jerry Eyster said that if the state SIP is not in
compliance with the NAAQS, how can you hold the utility liable
for the inadequate SIP? John Daniel said that in Virginia, there
is no grandfathering. If model a new source, you assume that the
existing source is running wide open, therefore it. is common for
the model to show that there are NAAQS violations. Jerry Eyster
asked under Title V, is there a certification requirement to get
an operating permit? David Novello of OGC responded that not for
NAAQS; the certification is for compliance with the SIP.
Rachel Hopp asked for clarification. Jerry Eyster said that he
did not see why, if every unit already had a permit under Title
V, there was a need to duplicate efforts. Rachel Hopp said that
the sate operating permits may not be in effect at the time
Phase I of Title IV is underway. She reviewed the timing for
permitting under the Title IV vs. Title V; and noted that the
states have 3 years after enactment to develop their Title V
programs.
Walter Wolf (audience) said that he would caution against
certifying compliance with the SIP. He said that in the case of
Wisconsin, the SIP has been pending for 6 years; therefore, a
utility would not know what the SIP is. He added that SIPs have
been around for 20 years and that EPA has had time to enforce
against these. He suggested EPA not add an extra certification
requirement.
27
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j
Vicki Tschinkel added that on'e way of eliminating flexibility
would be to require a certification that you meet all state
requirements. A state may try to come in and eliminate things
like trading. Rachel Hopp said that outreach to states will be
needed. She clarified that, regardless of the certification
issue, EPA's issuance of the permit does not limit what a state
can do, if there is a compliance problem with the SIP. Jim
Hambright added that EPA does have responsibility for enforcing
the SIP. ! . .
Dick Abdoo said that it now appears that the Subcommittee does
not want certifications in acid rain permit applications for any
non-acid rain program requirements.
He then asked if there were any comments on issue G. Jim
Hambright said no utility should be allowed to raise this as a
defense. Jerry Eyster asked if an example could be provided.
Luther Heckman said he would include one.
i
Dick Abdoo asked about issue H - need for constraints. The
Subcommittee responded they did not think there should be any
unnecessary constraints; Rachel Hopp added other than Phase I.
For issue I - partial substitution units, Dick Abdoo said this
does not make sense, he does not know why anyone would do this.
Several Subcommittee members agreed. Rachel Hopp explained that
a utility might want several units to make-up for the emission
reduction requirements at the;original unit, referring to the "in
whole or in part" language. |
Luther Heckman will revise his paper based on these discussions.
i
At 4:30 PM, Dick Abdoo said that the Subcommittee discussions on
the options papers were concluded. The remainder of the meeting
would be a presentation by Dayid Novello, EPA OGC, on ^Title V.
David Novello said, given the[limited time remaining, he would
provide a quick overview of Title V as it related to Title IV.
[
He began with an overview of who must have a permit. He said
Section 501 and 502(b) deal with this. Sources include "affected
sources" under Title IV, new sources subject to Part C&D, new
sources, and major sources. He added that there were no
exemptions for major sources which is the biggest category. He
mentioned that EPA is allowed to add or exempt other categories
(unless it is a major source)^ if EPA has determined that it is
too burdensome or impractical to regulate. He mentioned in the
draft Title V rule, EPA is considering exempting non-major
categories. Rachel Hopp added that EPA was not proposing to
exempt sources under Title IV.
28
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He mentioned that much of the Acid Rain permit requirements will
be deferred to the acid rain rulemaking. He mentioned some
general Title V rules and some of the differences between Title V
and Title IV:
o If the utility has a timely and complete permit
application under Title V, it is allowed to operate,
even if the state has not issued a permit.
o Under Title IV, what is in the permit applications and
the compliance plan is binding on the source and
governs the operation. This is not the case for
permits generally.
o The permit shield is modified and limited by the
statute as to program requirements.
o Timing - applications for Title IV may be coming in
before the state programs under Title V are in place.
o Under Title V, the permit is reopened to. reflect new
changes; if EPA or the state reopen for cause, this
could impact the Acid Rain program.
o Title V permits are issued for "up to" 5 years; Title
IV for a definite term of 5 years.
Rachel Hopp referred the Subcommittee to the draft Title V
regulations table of contents, which references 3 sections that
explain EPA's thinking on Title IV and V integration. She said
the Subcommittee will have an opportunity to discuss this at a
later date. She mentioned National Consistency - and the need
for the states to feel comfortable with whatever EPA decides.
Jim Hambright and Tom Madman added that Title V does not provide
for standard permitting other than for Acid Rain.
David Novello mentioned the Title IV NAAQS demonstration
authority. He said, although this type of authority also exists
under Title V, EPA's approach will be to not require a
demonstration, if there is compliance with the emissions limits.
Dick Abdoo thanked the Subcommittee for participating in the
meeting. The meeting was adjourned at 5:05 PM.
29
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Attachment
Subcommittee Members Attending Meeting
i
I
Richard Abdoo, Wisconsin Electlric Power
i
Steven Winberg, Consolidated Natural Gas
William Steinmeier, Missouri public Service Commission
William Samuel, United Mine Wprkers of America
James Markowsky, AEP Services iCorp.
Ned Helme, Alliance for Acid Rain Control
James Hambright, PADER Bureau of Air Quality Control
i
Paul Feira, Wheelabrator Air Pollution Control
Jerry Eyster, A.T. Massey Coal Company
Thomas Maiman, Commonwealth Edison
Steve Busrton, Sithe Energies i
Luther Heckman, Coalition for ; Environment-Energy Balance
John Daniel, VA Department of Air Pollution Control
Vicki Tschinkel, Landers and Parsons
Howard Fox for Bill Roberts, Environmental Defense Fund
Robbie Aiken for Mark DeMichele, Arizona Public Service Co,
EPA Representatives:
Rachel Hopp, ARD/OAR |
Brian McLean, ARD/OAR ;
30
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P 22
33
PRINCIPLES
FOR ACID RAIN PERMITS
-------
? 22
NOr
EMISSIONS
AVERAGING
OMPOANCE OPOONS
-------
P 22
ACID RAIZV PERMIT
DESIGNATED
SOURCE
REPRESENTATIVE
IDENTIFICATION
OPERATING
INFORMATION
MONITORING
INFORMATION
ALLOWANCE
ALLOCATION
STANDARD CONDITIONS
C INFORMATION
-------
P 22
ACID RAIN PERMIT
STANDARD
PROHIBITIONS
RECORDKEEPING
*^W&&'S? ."'-
; •>;••«*. £»•> ^as^ -.^ /s ^ „ , '
SPECIFIC
''
SOURCE
IDENTIFICATION
DESIGNATED
REPRESENTATIVE
OPERATING
INFORMATION
MONITORING
INFORMATION
ALLOWANCE
ALLOCATION
SPECIFIC INFORfilATION
-------
p 2:
ACID RAJIV PERMIT
NOx
ALTERNATIVE
EMISSIONS
LIMITS
EXTENSIONS
SUB-
STITUTION
PLANS
EMISSIONS
AVERAGING
CON-
SERVATION/
RENEWABLE®
REDUCED
UTILIZATION
REPOWERING
EXTENSIONS
OPT-IN
UNITS
NEW UNITS
-------
P 22
ACID RAIPf PERMIT
PHASE I
NOx
ALTERNATIVE
EMISSIONS
LIMITS
PHASE I
EXTENSIONS
NOx
EMISSIONS
AVERAGING
SUB-
STITUTION
PLANS
CON-
SERVATION/
RENEWABLES
REDUCED
UTILIZATION
OPT-IN
UNITS
PHASE I ONLY
ANY TIME
-------
P 22
ACID RAIN PERMIT
PHASE II
NOx
ALTERNATIVE
EMISSIONS
LIMITS
REPOWERING
EXTENSIONS
NOx
EMISSIONS
AVERAGING
CON-
SERVATION/
RENEWABLES
OPT-IN
UNITS
NEW UNITS
PHASE II ONLY
ANY TIME
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FACT SHEET: REDUCED UTILIZATION
Section 408 of the Clean Air Act Amendments of 1990 details
requirements for acid rain permits. Section 408(c)(1)(B) (dealing
with First Phase permitting) introduces the concept of reduced
utilization. This section provides, in relevant part/as follows:
In the case of a compliance plan for an affected source under
section 404 or 407 for which the owner or operator proposes to
meet the requirements of that section by reducing utilization
of the unit as compared with its baseline, or by shutting down
the unit, the owner or operator shall include in the proposed
compliance plan a specification of the unit or units that will
provide electrical generation to compensate for the reduced
output at the affected source, or a demonstration that such
reduced utilization will be accomplished through energy
conservation or improved unit efficiency. The unit to be used
for such compensating generation . . . shall be deemed an
affected unit under section 404, subject to all of the
requirements for such units under this title . ...
Regulatory treatment of reduced utilization has significant
implications for all Phase I sources and for the environment.
Identified Concern
In the absence of the reduced utilization provision, Phase I
sources could, theoretically, comply with the reduction
requirements by shifting a portion of their electrical generation
(and with it, their emissions) to presently unregulated Phase II
sources. This could lead to a significant increase in emissions
from Phase II sources, and a reduction in the environmental
benefits expected during Phase I.
Operation of the Reduced Utilization Px-ovision
The reduced utilization provision seeks to remove this possibility
by requiring sources planning to comply with the Phase I
requirements by reducing their emissions below their baseline
levels to:
a. identify a "compensating unit" - a unit which will provide
electrical generation to compensate for the reduced output at the
affected source. It should be noted that once a unit is designated
as a compensating unit, it becomes a Phase I affected unit and is
required to comply with all Phase I requirements, including those
related to emissions monitoring and NOsc.
OR
b. demonstrate that the reduced utilization will be accomplished
through energy conservation or improved unit efficiency. It should
be noted that in this latter case, since generation is not being
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transferred (and related increases in emissions at Phase II units
do not occur), reduced utilization at the Phase I source is
environmentally neutral or, given the pollution prevention result
of this option, environmentally beneficial.
But what of sources that do not plan to comply through reduced
utilization, yet do, in fact, reduce their utilization of Phase I
units and shift some of their load to unregulated Phase II sources
for reasons of economics or unexpected repairs?
In terms of environmental protection, this can raise serious
problems. As noted above, reduced utilization which is not
compensated for within the regulated system will lead to a lower
level of emissions reductions than that contemplated by the Act's
Phase I requirements.
An Illustration :
Figures 1 and 2 provide a simplified example of the potential
environmental concerns raise'd by reduced utilization. Figure 1
illustrates normal Phase I compliance in which reduced utilization
is not an issue. In that example, a Phase I unit (Unit A) complies
with acid rain requirements by cutting its SO2 emissions rate in
half (from 5.0 Ibs/mmBtu to 2.5 Ibs/mmBtu), while keeping its
baseline utilization (heat (input) constant. By reducing its
emissions rate, the unit reduces its annual SO2 emissions to the
level for which the utility has received allowances (50,000).
During the same year a Phase II unit (Unit B) owned by the same
utility emits 25,000 tons of:SO2, at a rate of .2.5 Ibs/mmBtu.
In Figure 2, the utility does not control the emissions rate at its
Phase I unit (Unit A). Instead Unit A continues to emit S02 at a
rate of 5 Ibs/mmBTU while reducing its utilization to one half of
its baseline. Assuming there has been no overall (e.g.. system-
wide) decrease in demand for electricity, the utility must increase
its utilization at some other unit in its system to compensate for
the reduced generation at Unit A. For the purposes of this
illustration, a Phase II unit (Unit B) increases its utilization.
The result of this transferred utilization is that the utility's
Phase I unit reduces its tons of SO2 to the level for which it has
received allowances, and tfee utility's Phase II unit, which
increased its generation to compensate for Unit A's reduced
utilization, increases its emissions by 25,000 tons. If this
"compensating unit" is not identified by the affected source, this
extra 25,000 tons of S02 is outside of, and unaccounted for by, the
allowance system. The environmental result in this case would be
an increase in emissions over and above the level of S02 emissions
envisioned by the statute for Phase I.
A similar increase can occur in NOx emissions. Indeed the
environmental implications of increases in NOx emissions at Phase
II units providing compensating generation is potentially more
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problematic since Phase II units are not by definition cleaner than
Phase I units for NOx purposes.
It should be noted that while this example shows one unit
compensating for the reduced utilization at Unit A, reduced
utilization from a Phase I unit could be picked up in part by a
number of Phase II units, making accounting more difficult. This
is particularly true for utilities that participate in large
central dispatch systems.
Potential Economic Benefits
Given the fact that "compensating units11 have to comply with Phase
I retirements, won't all utilities try to avoid reduced
utilization?
The fact is, units have variable utilization, and some utilities
may not be able to avoid the unplanned application of this
provision. However, there may be significant economic benefits for
utilities which designate compensating units as part of their
overall compliance strategy:
0 Some Phase II units will want to be brought into the
regulated system in Phase I to get credit for earlier reductions
0 Since Phase II units emit at a rate substantially below 2.5,
it is possible that use of this provision would free up allowances
for sale or future use while achieving equivalent reductions.
0 Since all Phase II units are required to have monitors in
place in 1995, depending on a units NOx control requirements, early
compliance with Phase I requirements for compensating units might
not be onerous, and given the benefits described above, may be
economically advantageous.
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P24
TOPICS COVERED IN ACID RAIN
PERMIT REGULATIONS
DESIGNATED REPRESENTATIVE
COMPLIANCE CERTIFICATIONS
APPLICATION REQUIREMENTS/CONTENTS
1. General Plant Information
2. Certifications
a. Monitoring
b. Reporting/Recordkeeping
c. Prohibitions
d. Excess Emissions
3. Compliance Plan Required
REQUIREMENTS FOR OPTIONAL METHODS OF COMPLIANCE
1. General - New
2. General - Opt-
3. General - NOx
4. General - NOx
5. Phase I Only -
6. Phase I Only -
7. Phase I Only -
8. Phase I Only -
9. Phase II Only
PERMIT CONTENTS
Units
•Ins
Alternative Emissions Limitations
Emissions Averaging
• Reduced Utilizcition
• Qualifying Extensions
• Substitutions
'• Renewable Energy/Energy Conservation
- Repowering
1. Initial Allowance Allocation
2. Standard Conditions
3. Permit Shield
4. Prohibitions
5. Reporting/Recordkeeping
6. Compliance Plan
7. Monitoring Requirements
8. Excess Emissions
PHASE I IMPLEMENTATION
1. Procedures for Early Ranking for Qualifying Phase I
Extensions
2. Deadlines for Applications/Compliance Plans
3. Deadlines for EPA Action
4. Effective Date of Phase I Permit
PHASE I - PHASE II TRANSITION
FEDERAL PERMIT ISSUANCE/CHALLENGES PROCEDURES
STATE PROGRAM PERMIT ISSUANCE REQUIREMENTS
EXCESS EMISSIONS REGULATIONS
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P25
PRIMER
ON THE
GLEAM WATER ACT
PERMIT PROGRAM
(National Pollutant Discharge Elimination System)
March 13, 1991
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IAPTER 3 I,RW- AUTHORITY FOR A PERMIT PROGRAM AND PERMIT ISSUANCE PROCEDURES •
I
FIGURE 3-1. COMMON ELEMENTS OF THE PERMIT ISSUANCE PROCESS
SIU Hies Permit Application
1
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r
VufcSite
Drift Pomit
1
Send Draft Ptrmit to
Nocfy Ofce Imerea
Odw Public P«tkap«ion
for Review
gyj Revue
Draft Pennii
Judicul Review
No
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i
MOOJUT CfmPi'*tv'> ftttc*rmifra
During Effective Period of Permit
Agpbcnt FUe* Renewil Appiicaion
: industViaYller Permitting Guidance Manual, USEPA, Office of Water (EN336) Sept. 1989
NPDES TDermit issuance procedures; (40 C.F.R. Part 124).
tS fcTSgnif icant industrial! user" , which means an
municipal sewer system. The procedure!, however, applies to all NPDES
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CLEAN WATER ACT:
PUBLIC NOTICE PROVISIONS
(Also used in the Resource Conservation and Recovery Act,
Underground Injection Control, and Prevention of
Significant Deterioration Programs)
40 C.F.R. 124.10 . • . '
WHO GETS NOTICE OP THE DRAFT PERMIT?
1. The applicant; :
2. Any agency which has issued a solid or hazardous waste
disposal permit, and underground injection permit, a
prevention of significant deterioration permit, a
wastewater permit, a dredging permit, a sludge manage-
ment permit, or an ocean dumping permit for the facili-
ty;
3. Federal and State agencies with jurisdiction over fish,
shellfish, and wildlife resources;
4. Any State agency responsible for development of an
areawide waste treatment plan under CWA §208(b);
5. .Army Corps of Engineers;
6. U.S. Fish and Wildlife Service;
7. National Marine Fisheries Service;
8. Persons on a mailing list developed by:
— Including those who request to be on the list; and
- Periodic publications in the local press of the
opportunity to be on the mailing list;
9. Any unit of local government with jurisdiction over the
area where the facility is proposed to be located;
10. Any State agency having,authority under State law with
respect to the construction or operation of the facili-
ty.
WHAT OTHER PUBLIC NOTICE IS REQUIRED?
Part 124 also requires that notice be published in a daily or
weekly newspaper within the area affected by the source, and that
the permitting authority use any other method reasonably calcu-
lated to give actual notice of the action to the person poten-
tially affected by it.
WHO CAN SUBMIT PUBLIC COMMENTS?
Any person can submit written comments on the permit.
WHO CAN REQUEST A PUBLIC HEARING?
Any person can request a public hearing.
WHEN WILL A REQUEST FOR A PUBLIC HEARING BE GRANTED?
Requests for a public hearing will be granted when there is
significant public interest or when the permitting authority
believes that holding a hearing will clarify issues involved in
the permitting decision.
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CLEAN WATER ACT:
FEDERAL PERMIT CHALLENGE PROCEDURES
40 C.F.R. §§124.71 - 124.91
WHO CAN CHALLENGE A PERMIT?
Any interested person can petition to challenge a Federally-
issued wastewater disposal permit, but that person can only
submit issues or evidence which were raised during the public
comment period (or public hearing), unless good cause is shown
for failure to do so. !
WHEN CAN A PERMIT BE CHALLENGED?
A permit can be challenged v^ithin 30 days of permit issuance.
WHAT PROCESS IS USED?
If the Regional Administrator grants the petition, there will be
a formal evidentiary hearing on the issues raised. An Adminis-
trative Law Judge is appointed to preside over the hearing and
rule on the issues. The decision of the Administrative Law Judge
can be appealed to the Administrator within 30 days after that
decision. Only following an unsuccessful appeal to the Adminis-
trator is judicial review available.
i
WHEN IS A PETITION GRANTED?
A petition for an evidentiary hearing is granted when it sets
forth a material issue of fact relevant to the issuance of the
permit. Petitions which raised only issues of law will be
denied, but can be appealed to the Administrator, who will review
and rule on legal issues.
WHEN IS JUDICIAL REVIEW GRANTED?
Judicial review is available only after a party has appealed to
the Administrator. A party can appeal the Administrator's
ruling, or the denial of an;evidentiary hearing. Judicial review
takes place in federal courts.
WHAT PROC»TOES DO STATES USE?
State permit challenge procedures follow the rules of the State
Administrative Procedures Apts, which may or may not be similar
to the Federal evidentiary hearing process. Judicial review of
State-issued permits takes place in State courts. (This is not
codified in regulations, but Clean Water Act case law since 1973
has held that Federally-issued permits are challenged in Federal
court, and State-issued permits are challenged in State court.)
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