BEFORE
THE ILLINOIS
POLLUTION
CON
-ROL
IN
THE
MATTER OF:
>
PROPOSED NEW 35 ILL. ADM. CODE 217,
)
SUBPART W FOR ELECTRICAL GENERATING
i
ROl-9
UNITS, AND AMENDMENTS TO
1
(RULEMAKING-AIR)
35 ILL. ADM. CODE 211 AND 217
>
TESTIMONY OF AMEREN CORPORATION
My name is Michael Menne and my title is Manager of the Environmental, Safety
and Health Department, Ameren Services Division of Ameren Corporation.
I am based at the
Ameren corporate offices in downtown St. Louis, Missouri and I am responsible for providing
guidance and developing strategies for environmental compliance throughout the Ameren system
including compliance with air pollution control requirements.
My staff and I have followed the
development of
NOx control regulations at both the state and national level for the past several
years.
In my testimony today, I would like to commend the Agency for its efforts and to state
Ameren’s position in support of the proposal to the extent that it is being done to meet the
requirements of the
NOx SIP Call and to raise relatively minor issues with respect the language
of the proposal.
First, however, I would like to describe briefly Ameren and its facilities in
Illinois. Ameren Corporation is the St. Louis based holding company formed by the 1998
merger of Union Electric
(LLUE”) and Central Illinois Public Service
(“CIPS”).
Arneren has two
gcncrating
subsidiaries which will bc
affcctcd
by this rule:
AmerenUE, a regulated company
which operates the power plants formerly run by Union Electric, one of which is located in
31646\00003\CH135007.WPD
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SUBMITTED ONRECYCLED PAPER
Illinois; and Ameren Electric Generating Company
(“Al%“), a deregulated company which
currently operates plants exclusively in the State of Illinois.
Ameren has six large generating stations in Illinois, burning a variety of fuels
including coal, oil and natural gas, with a total generating capacity of nearly 3,300 megawatts.
These are identified as
EGUs under this proposal and are listed in Appendix F. These are
primarily base load facilities which provide electricity for central and southern Illinois homes
and businesses. Ameren has also installed over 600 MW of new peaking capacity in Illinois
over the past two years, and is planning several additional units which may be located within the
state.
As such, Ameren should be viewed as a company representing both extensive existing
units and a significant number of new units
that will be affected by this rule.
I wish to note for the record, that Ameren has been acknowledged as a leader in
NOx control accomplishments at our coal-fired generating stations. Beginning in 199
1,
Ameren‘l
JE began a series of research projects and installed advanced combustion control
technologies on several generating units. Our continuing commitment and goal to achieve the
lowest possible
NOx emissions on these units has resulted in unprecedented success.
For the
year
lYY9,
AmerenUE operated the lowest
NOx emitting large coal-fired generating unit in the
country and six out of the ten lowest emitting units in the nation.
Our work with the Electric
Power Research Institute, in applying new technologies on one of our cyclone-fired boilers
- a
boiler with particularly high
NOx emissions
-
has resulted in achieving the lowest
NOx emitting
cyclone coal-fired unit in the nation, and earned the company the Governor’s Pollution
Prevention Award in Missouri for 1998. We are currently working to install these technologies
2
on our other Ameren generating units, including our largest units in Illinois, and also
planmng to
install additional new innovative technologies on our Illinois units within the next two years.
I wish to express our appreciation for all the hard work that the Illinois EPA staff
has given to this process.
I was contacted by the Chief of the Bureau of Air over three years ago,
when he began a collaborative effort of working with the utilities and other industries in Illinois
to develop a
NOx control program. This rule represents the most stringent and costly air
pollution control requirement in the history of the operation of our existing generating units.
I
believe the Agency knew this going into this process, and knew this would be a difficult and
contentuous
regulation.
W
C
have discussed the issues with other generators in the state and have
attempted to arrive at consensus positions with the IEPA. While we do have certain issues with
the
IEPA’s
approach as we describe below, we believe the IEPA worked hard to seek the
participation of stakeholders and to provide consensus solutions to these difficult problems.
Ameren
commends the
TEPA for its hard work in developing this proposal and its thoroughness
in presenting its proposal to the Board and the public.
In our opinion, we were very close to arriving at a consensus on an approach to a
utility
NOx control regulation in Illinois which would have achieved the air quality benefits of
this proposed rule at much less cost.
This approach would have required all
EGUs in the state to
meet a 0.25 lbs
NOx/mmbtu emission rate, hereafter referred to as the 0.25 rule. The 0.25 rule
would have required most existing generating units to reduce
NOx emissions 40%
- 75% below
current, already reduced,
NOx
emission
levels,
aud at significant costs.
IIowever,
the
intervention of the
USEPA
in issuing the
NOx SIP Call requiring today’s proposed regulation
prevented the Agency from moving forward with that alternative.
In general, if it is deemed necessary that Illinois adopt a rule which meets the
requirements of the
USEPA’s
NOx SIP Call, Ameren generally
supports
Subpart W of Part 217.
Yet the Board must understand that the record presented in this proceeding does not support the
adoption of this regulation to meet the attainment demonstrations for either the Metro East/St.
Louis or Lake Michigan non-attainment areas in the absence of the SIP call. It is clear from the
information presented by the IEPA and other available information that the attainment
demonstrations can be made without the stringent standards and requirements imposed in this
proposed regulation and that those standards and requirements are justified only to comply with
the SIP call.
Furthcrmorc,
WC
bclicvc
the continuing air quality modeling work being conducted
by LADCO, and other organizations will show that 0.25 rule for Illinois as well as for other
states in the Midwest could have satisfied not only the attainment demonstrations for Illinois but
also the interstate transport issue which the
NOx SIP Call is intended to address.
A number
of states and
industry
groups are
planning to petition the U.S. Supreme
Court on the
NOx SIP Call.
If the SIP Call is subsequently overturned, the Board would not be
justified in imposing these regulations to meet the attainment demonstrations. As Mr. Kaleel
testified, the modeling demonstrates that the U.25 rule would achieve attainment for Metro East
St. Louis and would probably achieve attainment for the Lake Michigan area. Additionally, as
stated by Mr. Kaleel, implementing the
NOx SIP Call provides only
” . ..limited benefits
(generally l-3 ppb)” in the Lake Michigan area over the 0.25 rule. The costs of achieving the
.15
lb/mmblu cap and trade standard imposed by the SIP Call and this regulation will be extremely
high for numerous reasons.
To name one, the growth factor selected by the
USEPA for setting
the Illinois
NOx budget is absurdly low. In 1998, Ameren and several other utilities in Illinois
4
were already exceeding the generating capacity that
USEPA
predicted would not be achieved
until 2007, based on its growth analysis. As a result, the control level Illinois
EGUs will have to
achieve is far lower than the initial
.15
lb/mmbtu standard used as the basis of this proposed
regulation.
The Board should also understand the tremendous costs these rules will impose on
EGUs,
and appreciate the difference in costs between the 0.25 rule and this proposal. As I have
stated, Ameren has pursued the development of new, low cost
NOx control technologies over the
past nine years.
To meet the
NOx control requirements of the current acid rain provisions and a
0.25
rate-based rule, AEG will have
spent
approximately $30 million and
have
rcduccd
NOx
emissions by about 12,000 tons equivalent to a 62% reduction.
This results in a cost of about
$2,200 per ton of
NOx removed.
On the other hand, AEG will need to spend an additional $100
million to get an additional 15% (or approximately 2,800 tons) reduction to meet the initial
requirements
ofthis program
based on
the emission cap with
limited or very
little growth. This
marginal reduction is roughly equivalent to $8,200 per ton of
NOx removed.
Overall, AEG
expects to spend approximately $130 million to comply with Subpart W which equates to a cost
of $5,300 per ton of
NOx removed. This number
signiticantly
exceeds the number calculated
by
the IEPA in Dick Forbes’ testimony or the number used by the
USEPA in determining that its
SIP Call requirements were “highly cost effective.”
These costs are based on our experience in
installing
NOx control technologies and actual bids by suppliers to retrofit the technologies on
our
ABG units. These costs are also supported by a study performed by H. Zinder
& Associates
(to be released shortly) where the costs of meeting a 0.25 rule and the
NOx SIP Call were
evaluated for the eastern U.S.
This study shows that the costs of compliance with a 0.25 rule is
5
50% higher than the costs cited in Mr. Forbes’ testimony on compliance costs associated with the
NOx SIP Call. Additionally, costs for compliance with the
NOx SIP Call were shown to be more
than twice
that
of EPA estimates.
It is Ameren’s understanding that the IEPA will propose the 0.25 rule if the SIP
Call is overturned.
The IEPA so indicated in its Statement of Reasons in submitting this
proposal and has so indicated in its discussions with the electrical generators. Ameren would
like to be assured of this outcome.
There is simply no justification for this cap and trade
proposal absent the SIP Call.
Ameren also bclicvcs that
the allocation of allowances included in the proposal
is
fair and should be adopted by the Board.
Given the unfair budget imposed by the
USEPA, there
are far fewer allowances than potential generating capacity, but we believe that the Agency’s
approach fairly balances the public
and private interests and provides an equitable division of
allowances among the competing parties. While the
bulk of the allowances are initially reserved
for existing
EGUs,
this is necessary since most of these are the base load units which provide the
necessary system reliability to ensure that Illinois consumers continue to receive a consistent and
reliable supply of power.
Many of these facilities represent substantial investments in the
communities which they serve and provide ongoing and long term economic benefits to those
communities.
In deliberations over the allowance allocations provided in this rule, operators of
new units have argued that their facilities are much
cleauer, low emitting facilities that should be
encouraged by the Agency, and thus, should receive a greater portion of the allowances.
The
existing units, however, will be required to expend exorbitant costs to retrofit their facilities to
6
meet this proposed rule. Further, while the rule properly allocates set allowances to current base
local
EGUs during the first three years of the program to assure system reliability, that certainty
quickly vanishes. Because this rule caps
NOx emissions throughout the state, and many new
generating and industrial facilities are planned in Illinois, the proposal’s fixed/flex provisions
continually reduces those
NOx emissions for existing facilities. New sources will need to install
the best available
NOx control technologies in any event pursuant to BACT and LAER and may
be forced to use the open market to secure
NOx allowances to cover their operations. Existing
units have to operate with the uncertainty over how many allowances they will receive in future
years.
They will be given fewer allowances over time and must plan on additional controls and
retrofits, the degree of which is uncertain. The continually ratcheting down of allowances for
existing units has the potential to jeopardize the viability of operating some units with their
current fuel supply in the future.
Many allowance allocation alternatives were debated in the course of the
development of this rule.
Since Ameren is an owner and operator of both existing units, new
units and planned additional units in the future, we may not agree that the method proposed in
the rule is the best for our planned operations, but we believe the Agency has chosen a scheme to
accommodate all types of facilities in the fairest manner possible.
Another area of debate in the proposed rules is the Early Reduction Credits
(ERCs).
This is especially true with the recent U.S. District
Court order to extend the
compliance deadline for
the SIP Call
rules until May 3
1,2004.
As
the Agency discussed in the
first hearing, this could result in changing the years in which
ERCs may be earned from 2001
-
2002 to 2002
- 2003.
ERCs are extremely valuable to the existing units in the State, because
7
they provide time for the development and installation of new, innovative and possibly less
costly control technologies, and also provide the time necessary to install and start up the most
expensive and long
- lead time control technologies, such as Selective Catalytic -Reduction.
Again, there is a very limited nurnber of
ERCs
available. Under the proposed
rule, half of the
ERCs will be made available for early reductions in 200 1, and the other half in
2002.
We believe the Agency should stick with this schedule, but allow the
ERCs to be used in
2004 and 2005 (assuming compliance with the rule is also extended until 2004) and not “slide”
the years for which
ERCs can be earned. Our logic is as follows. First, we fully expect that the
pool of
ERCs will be oversubscribed, thus companies will be pro-rated the
amount of
ERCs
they
can earn. This results in considerable uncertainty as to the amount of
ERCs any given company
might be able to obtain, thus reducing the ability of a company to know what controls will be
needed to comply with the rule during the 2004 (and presumably the 2005) ozone season.
Delaying all or part of the distribution of
ERCs will result in a greater over-subscription of the
pool, and will thus increase this uncertainty and penalize those companies which have expended
considerable time and cost to reduce emissions at an early date.
Second, during the development of the Federal
NOx SIP Call, it was always
assumed that
ERCs could be earned in
200~1 and 2002.
To delay this schedule would be a major
setback in the achievement of early air quality improvements and the scheduling of
NOx control
projects planned for
EGUs.
Since Ameren is the owner and operator of several large existing
units, it is simply not practical to install technologies on many units over a short time frame.
While we have been working to reduce our
NOx emissions for several years, this effort requires
extensive lead times and scheduling unit down times to install these technologies over our
8
system.
We also do not believe that one or two pollution control projects at any one site should
consume a major portion of
the available
ERCs in any one year.
To get the most air quality
benefit from the largest variety of sources without significant penalties to early
NOx reduction
plans, we firmly believe the Agency should keep the original ERC baseline and schedule for
obtaining
ERCs as proposed in the rule without the date adjustment provisions.
Ameren is also concerned with the schedule in the proposed rule to issue the
ERCs in May of 2002 for
ERCs earned in 2001 and in May 2003 for
ERCs earned in 2002
although the
CEMs data on which the ERC application is based will have been submitted by
October 30 of the prior year.
This gives a company very little time to know what
ERCs may
be
counted upon for compliance. Since
ERCs will be calculated using CEM information, it should
be possible for the Agency to determine quickly what
ERCs have been earned and prorated to a
given company. The Agency will determine allowances for new units within 30 days and there
seems to be no reason for a six month period for determining
ERCs.
We urge the Board to
encourage the Agency to accelerate this schedule.
This is another reason for not extending the
schedule to earn
ERCs. How can a company plan to comply with the rule in 2004, if they do not
know how many
ERCs they are prorated until just a few months before the compliance deadline?
By keeping the schedule to earn
ERCs in 2001 and 2002, companies will have some assurance of
the
ERCs they can count on to help comply with the rule.
This is necessary in order to plan the
timing of control project expenditures and maintain reliable generating capacity.
Once again, for
all the above reasons, we strongly encourage the Agency to keep the schedule and
50/50 split of
ERC opportunities in the years 2001 and 2002.
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We are preparing selected revisions to the proposal for the Agency’s review.
These address several issues which we raised in our questions to the Agency at the first hearing.
These include changes to clarify the permitting process, the process for adjusting the allowance
and liability provisions.
We will work with the Agency to achieve consensus on these revisions
and will then present them to the Board.
Thank you for allowing us to present this testimony and I will be happy to answer
any questions.
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