EXHIBIT 99.5
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RESPONDENT'S EXHIBIT JBW-1
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STATE OF INDIANA
INDIANA UTILITY REGULATORY COMMISSION
IN THE MATTER OF THE PETITION OF )
THE CITY OF GARY, INDIANA )
REQUESTING THE INDIANA UTILITY )
REGULATORY COMMISSION ESTABLISH )
THE TERMS AND CONDITIONS OF THE )
SALE OF CERTAIN PROPERTY OF )
NORTHERN INDIANA PUBLIC SERVICE ) Cause No. 42643
COMPANY TO THE CITY OF GARY AND )
FOR A DETERMINATION OF THE VALUE )
OF SUCH PROPERTY UNDER INDIANA )
CODE SECTIONS 8-1-2-92 AND 8-1-2-93 )
RESPONDENT: NORTHERN INDIANA )
PUBLIC SERVICE COMPANY. )
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PREPARED DIRECT TESTIMONY OF
JEROME B. WEEDEN
ON BEHALF OF NORTHERN INDIANA PUBLIC SERVICE COMPANY
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Daniel W. McGill, Atty No. 9489-49
Claudia J. Earls, Atty No. 8468-49
Barnes & Thornburg LLP
11 S. Meridian St.
Indianapolis, IN 46204
Telephone: (317) 231-7229
Fax: (317) 231-7433
Email: dmcgill@btlaw.com
Attorneys for Respondent
July 9, 2004 NORTHERN INDIANA
PUBLIC SERVICE COMPANY
PREPARED DIRECT TESTIMONY OF JEROME B. WEEDEN
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Q: Please state your name, job title, and business address.
A: My name is Jerome B. Weeden. My title is Vice President,
Generation, for Northern Indiana Public Service Company
("Company" or "NIPSCO"). My business address is 801 East 86th
Avenue, Merrillville, Indiana 46410.
Q: What is your educational background?
A: I graduated from Michigan Technological University in 1970 with a
BS Degree in Mechanical Engineering.
Q: Are you a registered Professional Engineer?
A: I was a registered Professional Engineer in the state of
Wisconsin prior to moving to Indiana in 1995. I have never
pursued registration in the State of Indiana.
Q: Are you a member of any professional organizations?
A: I am a member of the American Society of Mechanical Engineers.
Q: Please describe your employment experience with NIPSCO.
A: I began employment with NIPSCO on October 1, 1995, as the
Director, Production Engineering. On January 1, 1997, I was
assigned additional responsibilities covering production and
maintenance of the generating facilities. I was promoted to
Executive Director, Electric Production on January 1, 2001, and
on August 1, 2002, I was promoted to Vice President, Generation
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and was assigned the additional responsibility for fuel supply at
that time.
Q: What was your employment history prior to joining NIPSCO?
A: I was employed by the Wisconsin Electric Power Company ("WEPCO")
from June of 1970 until joining NIPSCO in October of 1995. My
time with WEPCO was spent almost exclusively in the field of
electric power generation, using primarily coal as the fuel
source. I held various management positions in the areas of
engineering support and generating station management, including
serving for three years as the Plant Manager of WEPCO's Oak Creek
Power Plant, a four-unit 1100 MW facility. I also spent close to
12 years of my time with WEPCO involved with the design,
permitting, construction and start-up of the Pleasant Prairie
Power Plant, a two-unit 1200 MW facility.
Q: What are your responsibilities as Vice President, Generation?
A: My responsibilities include the operation, maintenance,
engineering and project management activities associated with the
NIPSCO electric generation facilities. My responsibilities also
cover the procurement of fuel for these same facilities.
Q: For what purpose are you submitting Direct Testimony in this
proceeding?
A: I am submitting Direct Testimony to describe the generation
resources available to NIPSCO. I will provide a detailed
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description of the particular operating characteristics of the
Dean H. Mitchell Generating Station ("Mitchell"), and I will
summarize the steps and costs associated with a startup of
Mitchell.
Q: Please describe NIPSCO's existing generation resources.
A: The NIPSCO generating facilities have a net demonstrated
capability of 3,392 MW and consist of six separate generation
sites, including the Company's R.M. Schahfer Generating Station,
Michigan City Generating Station, Bailly Generating Station, Dean
H. Mitchell Generating Station, and two hydro electric generating
sites near Monticello, Indiana.
The R.M. Schahfer Generating Station is located
approximately two miles south of the Kankakee River in Jasper
County, near Wheatfield, Indiana. This station is the newest and
largest of the Company's generating stations and provides over
50% of NIPSCO's electric generation capacity. Its four baseload
and two peaking units came on line over an eleven-year period
ending in 1986. The characteristics of each unit at this station
are as follows:
AGC
Year Net Primary Capability AGC
Unit # Installed Capacity Fuel MW/min. Range
------ --------- -------- ------ ---------- -----
14 1976 431 Coal 5 40
15 1979 472 Coal 5 40
16A 1979 78 Natural Gas 0 0
16B 1979 77 Natural Gas 0 0
17 1983 361 Coal 20 50
18 1986 361 Coal 8 50
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The Bailly Generating Station is located on the shore of Lake
Michigan in Porter County. The Bailly Station utilizes a Pure
Air Flue Gas Desulfurization ("FGD") facility to allow it to use
Midwestern, high sulfur coal, while meeting strict clean air
requirements. The individual characteristics of the Bailly units
are as follows:
AGC
Year Net Primary Capability AGC
Unit # Installed Capacity Fuel MW/min. Range
------ --------- -------- ------- ---------- -----
7 1962 160 Coal 0 0
8 1968 320 Coal 5 40
10 1968 31 Natural Gas 0 0
The Michigan City Generating Station is located on the shore of
Lake Michigan in Michigan City, Indiana. It has the two oldest
generating units on NIPSCO's system, Units 2 and 3, which were
converted from coal to burn natural gas for peak system loads.
The newer Unit 12 burns low sulfur coal. The characteristics of
these units are as follows:
AGC
Year Net Primary Capability AGC
Unit # Installed Capacity Fuel MW/min. Range
------ --------- -------- ------- ---------- -----
2 1950 60 Natural Gas 0 0
3 1951 60 Natural Gas 0 0
12 1974 469 Coal 7 50
The Dean H. Mitchell Generating Station is located on a 100-
acre site in the northwest corner of Gary, Indiana, directly
north of the Gary Airport on the shore of Lake Michigan. There
are five generating units at the station with the following
characteristics:
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Original Current AGC
Year Net Net Primary Capacity AGC
Unit # Installed Capacity Capacity Fuel MW/min. Range
----- --------- -------- -------- ------- --------- -----
4 1956 138 125 Coal/Natural Gas 0 0
Gas
5 1959 138 125 Coal 0 0
6 1959 138 125 Coal 0 0
9 1966 17 17 Natural Gas 0 0
11 1970 115 110 Coal 2 15
Q: Each of the tables above includes a figure for AGC, measured in
megawatts per minute. What is AGC?
A: AGC stands for "Automatic Generation Control" and indicates the
ramp rate at which an individual generating unit can increase or
decrease its output. A high AGC figure is important for serving
the highly variable and instantaneous electric demands of certain
industrial customers' applications and processes. There is a
lesser requirement for serving the residential and commercial
customer base, where the demand tends to change gradually over a
broader period of time.
Q: What factors determine a generating unit's AGC capability?
A: A unit's AGC is determined by the design characteristics of the
unit at the time it was constructed. The initial design is based
on the anticipated usage of the unit, and whether the unit is
intended to serve base load, intermediate load, or peaking
service. For the most part, NIPSCO's generating units were
designed for base load operating conditions with the ability to
follow a typical residential/commercial/industrial load as it
changes during a normal day. AGC capabilities can change from
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one day to another due to equipment conditions and fuel quality.
In addition, a unit's AGC capability can be significantly reduced
or eliminated when running at either minimum or maximum load
conditions.
Q: Can a generating unit's AGC capability be increased?
A: Yes, this is normally accomplished through control system
upgrades. However, there are limits to such upgrades imposed by
the design of the original equipment, and by the need to avoid
the potential adverse effects that load variations can have on
the performance of equipment that is operated to meet regulatory
requirements such as environmental emissions limits. This
equipment includes electrostatic precipitators, Flue Gas
Desulfurization systems and Selective Catalytic Reduction
systems.
Q: Are there other adverse effects that can result from operating
units with high ramp rates?
A: Yes, as discussed in a November 2002 report published by Electric
Power Research Institute and titled DETERMINING THE COST OF
CYCLING AND VARIED LOAD OPERATIONS: METHODOLOGY, the operational
practices of fossil fueled steam power plants can significantly
impact the remaining life of equipment and ancillary systems.
Changing or alternating between unit design parameters (i.e. base
load to cyclic duty operation) negatively impacts component
thermal stresses, material properties and the creep-fatigue
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interaction. These damaging conditions are cumulative and can
take years to develop before problems arise. Consequential
results include premature failures, increased maintenance costs,
reduced unit reliability/availability factors, higher heat rates
and higher forced outage rates.
The damage mechanisms of creep (continuous stress with
steady state load) and fatigue (fluctuating stress with varying
load) have been studied metallurgically for decades. The creep-
fatigue interaction has just recently been identified and many
technical questions remain unanswered. What is known is that
this creep-fatigue interaction causes significantly more material
damage and reduces component life at a much higher rate than
either damage mechanism would on its own. This is significant
due to the relationship of stresses for base load (continuous
stress - creep) and cyclic modes (fluctuating stress-fatigue).
Cyclic related problems on units operating at high
temperatures and pressures (> 1800 psi and 1000 degrees F), as is
the case with the NIPSCO units, are generally more severe. Thick
walled components used in this application are susceptible to
fatigue damage due to temperature gradients between the inner and
outer surfaces and subsequent differential rates of expansion.
The heavier walled components also increase the probability of
thermal fatigue.
From an operations standpoint, running with high AGC levels
will result in a reduction of the unit's efficiency, and
therefore a higher unit heat rate. It also increases the
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possibility of the unit becoming operationally unstable which
could result in an automatic runback (i.e., a reduction) in the
unit's output including a forced trip and potentially an unsafe
condition.
Q: Has NIPSCO taken steps to improve its AGC capabilities?
A: Yes. NIPSCO invested $5.6 million to complete a major control
upgrade project on Unit 17 at the Schahfer Generating Station.
This project was completed in 2003, and resulted in a ramp rate
improvement from 10 MW to approximately 20 MW per minute over a
50 MW range. A similar investment is being made on Schahfer Unit
18 with the project scheduled for completion in 2005, which
should result in a corresponding improvement in AGC capability.
Q: Could NIPSCO perform similar upgrades to other units, including
the Mitchell units?
A: Yes, other NIPSCO units besides those listed above are scheduled
for control upgrades to replace obsolete and inadequate systems,
but because of equipment design factors associated with these
units, the upgrades will not result in similarly significant AGC
improvements.
Due to the age and overall condition of the Mitchell units,
the control philosophies associated with those units, and the
environmental compliance concerns that are associated with unit
cycling, it would not make economic sense or be technically
feasible to attempt such major control improvements at Mitchell.
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Q: Please describe the Mitchell plant.
A: The four coal fired units at the Mitchell station range in age
from 34 to 48 years old. Units 4, 5, 6, and 11 were originally
designed to burn bituminous coal from Indiana and Illinois with a
heating value of 10,000-11,300 BTU/lb of coal. The units were
converted to low sulfur coal in the 1970's when the passage of
the Clean Air Act limited sulfur dioxide emissions to meet local
air quality requirements. The change to sub-bituminous coal,
which has a heating value of only 8,000 to 8,800 BTU/lb.,
resulted in modification to the units' operating characteristics
and the current net demonstrated capability ratings.
Mitchell is configured with two units sharing one stack.
Units 4 and 5 share one stack, while units 6 and 11 share a
second stack. In 1988 a nozzle was added to the stack on units 6
and 11. The nozzle was required to allow the plant to meet the
local ambient air quality standards for the State of Indiana SO2
(sufur dioxide) control plan for Lake County.
Q: Please describe the AGC capabilities of Mitchell.
A. The AGC capabilities of the units at Mitchell are limited. The
existing unit control systems will not maintain plant equipment
or systems within the control parameters during load changes.
The size and design of the electrostatic precipitators, and the
relatively low opacity limit, do not allow the units to stay in
compliance with environmental parameters during automated ramping
of the generation. The precipitator controls were upgraded on
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Units 5 and 6. Additionally, the Unit 5 precipitator was
upgraded to a modern design configuration. However, to allow the
units to operate at the required opacity limit and accommodate
AGC operation would require significantly increasing the size of
the electrostatic precipitators. Physical space limitations do
not allow for such a modification. It would also be necessary to
completely change out the control systems plus other plant
equipment on all four base load units. Prior to the indefinite
shutdown of Mitchell in 2002, Unit 11 operated in AGC mode at 2-
4 MW per-minute through a 15 MW load range and Units 4, 5 and 6
were not able to operate in AGC mode.
Q: What were the reasons for temporarily shutting down Mitchell in
January 2002?
A. The local economic outlook in the fall of 2001 was the primary
driver that led to Mitchell's indefinite shutdown. As part of
this outlook, steel production was on the decline, local
unemployment was on the rise, and the Kelley School of Business
had predicted unemployment could reach 8.5% with the loss of LTV,
which had filed for liquidation. The market conditions for
electricity were characterized by a projected increase in
capacity from new generation construction and a forecast for
significantly lower market prices for the foreseeable future.
From an operational standpoint, NIPSCO was operating Mitchell at
a 40% capacity factor, which was less than optimal, and was
running into minimum load problems on the other units in the
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fleet due to the drop in demand for power during the off peak
periods. This deep cycling for low load was having a negative
effect on the operating efficiencies of the generating units, as
well as increasing the potential for equipment damage and an
increase in forced outages. These adverse conditions were
mitigated with the indefinite shutdown of Mitchell.
Q: Could NIPSCO build new generating facilities with ramping
capabilities sufficient to handle the regulation needs of its
customers, especially the industrial load?
A: Yes, but it would be costly, and I estimate it would take from
four to eight years to design and build and obtain the necessary
permits.
Q: What condition is Mitchell in now?
A: The plant has been well operated and maintained over its
lifetime, but as you would expect from a facility where the
newest unit is 34 years old, performance issues do exist and its
reliability is not good. NIPSCO took measures to preserve the
facility and equipment when it was temporarily shutdown in
January 2002. Although the plant was well maintained, there are
major components that require replacement to operate reliably,
including the replacement of various heat transfer surfaces in
the boilers, and extensive electrostatic precipitator repair
work. The unit control systems are obsolete, and no longer
supported by the manufacturers. If a control system were
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replaced on a Mitchell unit, it would only be done to meet the
basic requirements to operate the unit under base load
conditions.
Q: What would it cost to start up Mitchell?
A: NIPSCO estimates the cost to start up Mitchell would be
$5,522,000. This includes $3,875,000 in capital equipment
upgrades and $1,647,000 in maintenance to existing equipment.
Respondent's Exhibit JBW-2, which is attached to my Direct
Testimony, provides greater detail on the capital equipment
upgrades that were planned. The items listed in Respondent's
Exhibit JBW-2 were approved as a part of NIPSCO's 2004 capital
budgeting process. Respondent's Exhibit JBW-3, also attached,
provides additional detail on items listed in Respondent's
Exhibit JBW-2, including a detailed description, cost estimate
breakdown, time frame, and explanation why the item (and its
cost) is necessary for a startup. Both of these Exhibits were
prepared under my supervision.
The Company projects that capital expenditures of $39.5
million would be required over the next five years (2005-2009) to
effectively operate the Mitchell Station. This figure does not
include investments potentially required to comply with future
environmental requirements, which are addressed by Mr. Arthur E.
Smith, Jr. in his Direct Testimony. To the preceding costs, one
must add the operating & maintenance costs of actually operating
the facility. Those costs totaled $9.7 million in calendar 2001,
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excluding the cost of fuel. The projected fuel cost for 2005
would be $36 million.
Q: What steps are involved in starting up Mitchell?
A: Shortly after Mitchell was idled in 2002, a detailed startup plan
was prepared that identified more than 2,000 activities necessary
to start up the plant. The plan indicated that starting up
Mitchell would take approximately 12 to 15 months to accomplish,
with the first unit returning to service in approximately 6
months. The most time-consuming task, and in my opinion the most
critical, would be hiring and training the personnel necessary to
start up the facility and to staff it once it was started up.
This is problematic because a number of workers took early
retirement when the facility was temporarily shutdown, and others
were transferred to other NIPSCO generating facilities. It is my
opinion that it would be difficult for NIPSCO to find personnel
possessing the necessary skills and experience to run the
Mitchell facility. Therefore, a significant training program
would have to be implemented.
Q: Shortly after the City of Gary filed its Petition initiating this
Cause, NIPSCO filed a motion requesting an expedited hearing, in
part based on a deadline for negotiating a new fuel contract.
Can you provide additional information?
A: When the City of Gary filed its Petition, NIPSCO was in the
process of negotiating the quantity and price for coal purchases
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under a contract that would include part of the Mitchell fuel
supply portfolio for calendar year 2005. The projected coal burn
for Mitchell in 2005 would have been approximately 1.56 million
tons. The contract negotiations were scheduled to conclude on
June 30, 2004.
Q: Have the contract negotiations concluded? What was the result?
A: The negotiations were concluded on July 1 with no coal contracted
for Mitchell.
Q: Please discuss any other issues that you foresee regarding the
startup of Mitchell.
A: The Mitchell plant will likely not be dispatched in the dynamic
marketplace, which is expected to be created by MISO, due to the
excess of base load capacity in the ECAR Region.
Q: Does this conclude your Prepared Direct Testimony?
A: Yes, it does.
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