<DOCUMENT>
<TYPE>EX-99
<SEQUENCE>5
<FILENAME>xex99_4.txt
<DESCRIPTION>99.4 PREPARED DIRECT TESTIMONY OF FRANK A. VENHUIZEN
<TEXT>
EXHIBIT 99.4
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RESPONDENT'S EXHIBIT FAV-1
--------------------------
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 )
2-93 RESPONDENT: NORTHERN )
INDIANA PUBLIC SERVICE COMPANY. )
=====================================================
PREPARED DIRECT TESTIMONY OF
FRANK A. VENHUIZEN
ON BEHALF OF NORTHERN INDIANA PUBLIC SERVICE COMPANY
======================================================
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 FRANK A. VENHUIZEN
-----------------------------------------------
Q: Please state your name, job title, and business address.
A: My name is Frank A. Venhuizen. I am the Director of Electric
Transmission and Market Services 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 Purdue University with a Bachelor of Science
degree in Electrical Engineering in 1972 and a Master of Science
degree in Engineering in 1976.
Q: Are you a registered Professional Engineer?
A: Yes. I am a registered Professional Engineer in the State of
Indiana.
Q: Are you a member of any professional organizations?
A: Yes. I am a Senior Member of the Institute of Electrical and
Electronic Engineers. In addition, I have chaired the Electric
Power Research Institute ("EPRI") Power System Planning and
Operations Task Force. I am a member of the EPRI Grid Operations
and Planning Business Area Council and a past member of the
Edison Electric Institute Transmission Strategic Area Committee,
as well as its Transmission Policy Task Force. I have served on
the Mid-America Interconnected Network ("MAIN") Engineering
Committee. I currently serve on the East Central Area
Reliability Council ("ECAR") Coordination Review Committee, and I
am the alternate representative on the ECAR Executive Board. I
am also the Participant Committee Member for NIPSCO for the
GridAmerica ITC.
Q: Please describe your employment experience with NIPSCO.
A: I began my employment with NIPSCO in 1972 as an Electrical
Engineer in the Technical Services Department. Since that time,
I have held various engineering and planning positions. In 1979,
I became Supervisor, Generation Planning. In January 1988, I was
promoted to Manager, Wholesale Power and Resource Planning. In
May 1991, I was promoted to Director, Electric Supply Strategic
Planning. In April 1993, I was promoted to Director, Electric
Operations. In January 1994, in connection with a corporate
reorganization, I was assigned to Manager, Electric System
1
Operations. In November 2000, I was promoted to my current
position.
Q: What are your responsibilities as Director, Electric Transmission
and Market Services?
A: I am responsible for the planning, coordination and development
of short-term electric system power supply requirements and the
direction of the operation of the Company's electric transmission
system.
Q: For what purpose are you submitting Direct Testimony in this
proceeding?
A: Considering the City of Gary's requested relief in this
proceeding, I am submitting Direct Testimony regarding some of
the uncertainties that I perceive surrounding the status of Dean
H. Mitchell Generating Station ("Mitchell"), and their impacts
upon NIPSCO's energy requirements and electric supply portfolio
needs. As part of my discussion of these uncertainties
surrounding NIPSCO's energy requirements, I will discuss (i) the
current operating requirements placed upon NIPSCO's generating
system by the North American Electric Reliability Council
("NERC"), (ii) the current near term status of NIPSCO's native
load requirements, including certain of its volatile industrial
customers' applications and processes, (iii) the potential impact
of the energy markets tariff - Midwest Market Initiative ("MMI")
- proposed by the Midwest Independent Transmission System
Operator, Inc. ("MISO"), and (iv) the electric supply portfolio
planning process and needs for NIPSCO's electric retail native
load customers, including its firm and some of its interruptible
customers.
Q: Please define some of the common terms that you and the other
NIPSCO witnesses submitting Direct Testimony will be utilizing in
your discussion.
A: 1) AREA CONTROL ERROR ("ACE"): The instantaneous difference
between net actual and scheduled interchange, taking into
account the effects of frequency bias including a correction
for meter error.
2) BULK ELECTRIC SYSTEM: The aggregate of electric generating
plants, transmission lines, and related equipment. The term
may refer to those facilities within one electric utility,
or within a group of utilities in which the transmission
lines are interconnected.
2
3) CONTROL AREA: A Control Area is an electrical system bounded
by interconnection (tie-line) metering and telemetry. A
Control Area controls generation directly to maintain its
Interchange Schedule with other Control Areas and
contributes to frequency regulation of the Interconnection.
NIPSCO's system is defined as a Control Area.
4) FREQUENCY: The number of cycles through which an alternating
current passes per second. Frequency has been generally
standardized in the United States of America electric
utility industry at 60 cycles per second, or 60 hertz.
5) INTERCHANGE: Energy transfers that cross Control Area
boundaries.
6) INTERCHANGE SCHEDULE: The planned Interchange between two
adjacent Control Areas that results from the implementation
of one or more Interchange transactions.
7) INTERCONNECTION: When capitalized, any one of the three bulk
electric system networks in North America: Eastern, Western,
and ERCOT. When not capitalized, the facilities that
connect two systems or Control Areas.
8) LOAD FOLLOWING: The use of online generation and changes in
interchange schedules to follow the trend of changes in
customer loads. For purposes of this discussion, a trend is
defined as 5 minutes or greater.
9) REGULATION: The use of online generation units that are
equipped with automatic generation control ("AGC") and that
can change output quickly - i.e., megawatts per minute - to
follow moment-to-moment fluctuations in customer loads.
Q: Please describe the role of NERC with respect to the
implementation of operating requirements for electric utilities.
A: NERC's mission is to ensure that the bulk electric system in
North America is reliable, adequate and secure. Since its
formation in 1968, NERC has operated successfully as a voluntary
organization, relying on reciprocity, peer pressure and the
mutual self-interest of all those involved. Through this
voluntary approach on a generic basis across North America, NERC
has helped to make the North American bulk electric system the
most reliable system in the world. To fulfill its mission, NERC:
(1) sets standards for the reliable operation and planning of the
bulk electric system; (2) monitors, assesses and enforces
compliance with standards for bulk electric system reliability;
(3) provides education and training resources to promote bulk
electric system reliability; (4) assesses, analyzes and reports
on bulk electric system adequacy and performance; (5) coordinates
with Regional Reliability Councils and other organizations; (6)
3
coordinates the provision of applications (tools), data and
services necessary to support the reliable operation and planning
of the bulk electric system; (7) certifies reliability service
organizations and personnel (including NIPSCO personnel); (8)
coordinates critical infrastructure protection of the bulk
electric system; (9) enables the reliable operation of the
interconnected bulk electric system by facilitating information
exchange and coordination among reliability service
organizations; and (10) administers procedures for appeals and
conflict resolution for reliability standards development,
certification, compliance and other matters related to bulk
electric system reliability.
Q: Please describe the critical operating requirements placed upon
NIPSCO's generating system by NERC.
A: In 1998, NERC replaced the previous reliability standards
applicable to Control Areas with Control Performance Standards 1
and 2 ("CPS1" and "CPS2", respectively), which are the measures
by which all Control Areas are evaluated.
CPS1 is a measurement on how well each Control Area supports
the Interconnection frequency. When a Control Area such as
NIPSCO achieves a CPS1 of 100% it means the Control Area is
adjusting its generation in a manner that meets its minimum
obligation to maintain the Interconnection's scheduled frequency.
In addition to CPS1, NERC's CPS2 is designed to limit the
magnitude of unscheduled Interchange. In order to comply with
CPS2, each Control Area must keep its ACE within bounds as
determined by ECAR (a control region of NERC), 90% of the time
each month. Both of these requirements introduce a challenging
standard given NIPSCO's load characteristics, as I will discuss
later.
Q: Mr. Venhuizen, how are Control Areas able to manage these CPS1
and CPS2 requirements?
A: AGC is the means by which Control Areas are able to regulate and
manage performance against CPS1 and CPS2.
Q: Considering NERC's measurement of CPS1, what is the importance of
frequency to the bulk electric system?
A: Simply stated, frequency is the measure of the health of the
Interconnection. Specifically, customer processes and equipment
in this country are designed to consume electric energy that is
at 60 hertz. As such, it is a reliability measure from a
customer's perspective.
4
Q: How are load following and regulation related and
distinguishable?
A: Load following matches the electric supply resources to the trend
of the increase or decrease of customer load. Regulation matches
the instantaneous changes within that trend.
Q: Why is regulation important to the bulk electric system?
A: Regulation helps to maintain Interconnection frequency, manage
differences between actual and scheduled power flows between
Control Areas, and match generation to load within the Control
Area. In fact, the Federal Energy Regulatory Commission ("FERC")
recognized the importance of regulation when it promulgated Order
888 and included regulation as an ancillary service.
As I will discuss later, this is also important for purposes
of the new energy market proposal - MMI - by the MISO. While an
ancillary market including regulation is expected in the future,
MISO has not begun development of this market; therefore, the
burden of regulation remains on the Control Areas. As described
by Mr. Mark T. Maassel in his Direct Testimony, NIPSCO will
diligently strive to comply with the policy directives of NERC
and FERC (through the proposed MISO MMI), but there are some
uncertainties that must be acknowledged. In addition, it is
important to note that even though NERC has set up voluntary
requirements and operating standards, NIPSCO, through its
arrangements with ECAR, has committed to comply with CPS1 and
CPS2. In addition, as part of NIPSCO's operating agreement with
MISO, NIPSCO has an obligation to remain in compliance with
NERC's standards. Given these arrangements, NIPSCO essentially
considers NERC's standards mandatory.
Q: Mr. Venhuizen, how has NIPSCO's compliance with the NERC
performance policies been in recent years?
A: NIPSCO's performance against the standards CPS1 and CPS2 has been
declining, which is reflected in the attached Respondent's
Exhibit FAV-2. The y-axis on the chart represents the
compliance percentage and the timeline is listed on the x-axis.
The three curves are (1) CPS1 performance on a monthly basis, (2)
CPS1 on a rolling 12-month basis and (3) CPS2 performance on a
monthly basis.
Although NIPSCO has made diligent efforts to comply with
these NERC standards, it is NIPSCO's reasonable expectation that
this trend of declining performance will continue in the near
future unless NIPSCO can utilize additional regulation
capability.
5
Q: What are the consequences to NIPSCO of not meeting NERC's
operating performance policies?
A: As previously mentioned, NIPSCO has contractual obligations
through its relationship with MISO and ECAR to comply with NERC's
standards. Also, financial consequences in the form of monetary
penalties are under development, although not yet in effect. In
his Direct Testimony, Mr. Pierre R.H. Landrieu also addresses
some of the consequences associated with not complying with these
standards. Even more important than maintaining contractual
commitments and avoiding financial consequences is the fact that
NERC standards help support the health of the Interconnection,
and affect the reliable service of electric power to NIPSCO's and
other utilities' customers. Therefore, as stated above NIPSCO
will take all reasonable steps to comply with the NERC standards.
Q: Does NIPSCO's declining performance against NERC's standards
represent one of the uncertainties affecting the status of
Mitchell?
A: Yes. I believe that this declining performance against NERC's
standards is a concern for NIPSCO's electric supply operations.
In turn, this plays a factor in deciding whether to startup
Mitchell. Mr. Landrieu also addresses this concern.
Q: Would starting up Mitchell alleviate the problem of NIPSCO's
declining compliance with NERC's standards?
A: No. It is my expectation that starting up Mitchell would not
significantly improve NIPSCO's compliance with NERC's standards
because of the continuing and increasing volatility of NIPSCO's
industrial load, specifically, certain industrial customers'
applications and processes. These industrial applications and
processes include, for example, arc furnaces, rolling mills and
forging operations.
Q: Please explain the characteristics of NIPSCO's industrial load
profile.
A: As noted by Mr. Landrieu, NIPSCO's native load requirements are
one of the most unique in the electric utility industry,
considering the significant power needs and load patterns of
certain industrial customers and their applications and processes
located in northern Indiana. To the best of my knowledge and
given my own experience, I believe NIPSCO has one of the most
volatile load swings of any electric utility in the country. As
an example, Respondent's Exhibit FAV-3 represents these
industrial applications and processes where they have very large
6
load swings in very short periods of time. The y-axis represents
the time of day, which as reflected in Respondent's Exhibit FAV-3
only covers approximately one hour of one day, and the x-axis
represents the amount of megawatts from certain of NIPSCO's
industrial load. Respondent's Exhibit FAV-3 illustrates these
large load swings where between approximately 1:00 PM and 1:05
PM, NIPSCO's industrial load moved nearly 250 MW from 550 MW to
nearly 800 MW. Then, during the next six to seven minutes, the
industrial load returned below 550 MW. Finally, during the
following five to six minutes, this industrial load returned once
again to 800 MW. As Respondent's Exhibit FAV-3 reflects, NIPSCO
faces a significant challenge to supply this load, including
complying with NERC standards surrounding this provision of
supply.
Q: Why do you believe this is a significant challenge for NIPSCO?
A: First, I believe that the volatile activity of certain NIPSCO
industrial customers' applications and processes will continue.
In recent years and even months, NIPSCO's industrial customers
have accelerated their activity - i.e., increased volatility,
which places additional burden on NIPSCO's generating operations.
Second, NIPSCO's generating assets currently have the
regulation resources to meet these moment-by-moment fluctuations
caused by NIPSCO's industrial customers' applications and
processes. With these load characteristics, NIPSCO faces large
fluctuations on a moment-by-moment basis, such that it needs an
unusually large proportion of AGC or regulation resources to
arrest and reverse its declining performance against NERC
standards. Later, I will discuss this gap between NIPSCO's
current AGC capability, as described by Mr. Jerome B. Weeden in
his Direct Testimony, versus the regulation needs of NIPSCO's
industrial customers' applications and processes.
Q: What actions of NIPSCO's industrial customers' applications and
processes have led to the increasing volatility of their usage of
electric energy?
A: Over the past few years and even months, some of NIPSCO's
industrial customers have increased their electric consumption.
This is due, in part, to the noticeable increase in steel
production and finishing demands as a result of developments in
the global economy. This increased consumption has resulted in
increased volatility, or the rate of change, in each of the
customer's loads upon NIPSCO's electric system.
7
Q: Besides increasing volatility, what other factors contribute to
the uncertainty of NIPSCO's AGC capabilities versus the
regulation needs of its industrial customers' applications and
processes?
A: The most notable factor outside of NIPSCO's control is that of
MISO's proposed MMI, which encompasses MISO's footprint,
including NIPSCO. MISO's proposed energy markets tariff
currently before the FERC includes a provision intended to
address the issue of load following, which will ultimately impact
NIPSCO's ability to regulate. As part of MISO's proposed real-
time energy market, MISO will be providing a five-minute forecast
of NIPSCO's Control Area that MISO will use in the determination
of generating unit set points. In other words, MISO will direct
each online generator regardless of its AGC status to ramp up or
down to a certain output every five minutes. To enforce
compliance, MISO will impose penalties, called uninstructed
deviation charges, on generators that do not stay within a
defined tolerance band. Considering NIPSCO's unique customer
load, we have concern that MISO's five-minute forecast will have
a negative impact on our ability to regulate and our ability to
improve NIPSCO's performance against NERC's standards.
Historically, NIPSCO has worked diligently to remain in
compliance with NERC's standards; however, bearing in mind (1)
the continued decline in performance against NERC standards, (2)
NIPSCO's industrial customer load activity, and (3) MISO's
proposed uninstructed deviation requirements, NIPSCO's current
generating capabilities, with or without Mitchell, will not
likely match tomorrow's needs. This represents an uncertainty
surrounding NIPSCO's future generating needs and the status of
Mitchell.
Q: In summary, are you suggesting that starting up Mitchell may not
alleviate NIPSCO's declining performance against NERC's standards
and the uncertainty of MISO's proposed uninstructed deviation
requirements?
A: Yes. It is my expectation that starting up Mitchell would not
arrest and reverse the declining performance with NERC's
policies, and may not improve NIPSCO's ability to meet MISO's
proposed uninstructed deviation requirements.
Q: Please elaborate about this gap between NIPSCO's AGC capabilities
and the regulation needs of its customers.
A: Certain industrial processes alone account for approximately 160
MW load swing within NIPSCO's Control Area, and such swings can
occur instantaneously, and often concurrently. In addition to
these industrial processes, NIPSCO's load swings are
8
approximately 200 MW; altogether representing a total load swing
of potentially 360 MW with the industrial processes online. With
all of NIPSCO's generating units (excluding Mitchell) online,
NIPSCO has approximately 50 MW per minute of AGC capabilities,
and is able to comply with NERC's current standards when the
industrial processes are offline. Nonetheless, due to planned
maintenance schedules, there are only three months of the year
when all of the generating units are available to support AGC.
During the planned maintenance periods, anywhere from 5 - 20 MW
per minute of AGC is unavailable. Additionally, there may be
online maintenance and forced outages that may further reduce AGC
capabilities.
Q: Mr. Venhuizen, what actions have been taken by NIPSCO or are
planned to address this gap and NIPSCO's decline in NERC
compliance performance?
A: NIPSCO has invested capital to improve the AGC capability and
availability of its current generating units. As stated by Mr.
Weeden, NIPSCO has plans to improve its Unit 18 AGC capabilities
for completion in 2005 at R.M. Schahfer Generating Station. This
improvement will accommodate the maintenance and outages as
stated above. Nonetheless, even with the planned improvement of
Unit 18's AGC capabilities, when these industrial processes are
online, additional AGC is needed to arrest and reverse the
current decline of NIPSCO's compliance with NERC's standards, and
to potentially avoid penalties under MISO's proposed uninstructed
deviation requirements. There is uncertainty as to what MISO's
ultimate uninstructed deviation requirements will be in the long
term and how the MMI ancillary services market will develop.
Since the current regulation requirements focus on 5 minute
intervals, it is quite conceivable that ultimately these
requirements will be more stringent than the current NERC rules.
For example, for the industrial processes described above,
it is anticipated that NIPSCO needs approximately 40 MW per
minute of AGC capability over a range of approximately 160 MW of
regulation response for the total impact of these industrial
processes. As stated above, the current 50 MW per minute of AGC
capability will allow NIPSCO to meet NERC's standards when
serving approximately 200 MW load swings when these industrial
processes are offline. Based upon this ratio, in order to serve
the additional 160 MW load swing from the industrial processes,
NIPSCO needs an estimated additional 40 MW per minute of AGC
capability.
9
CURRENT: ESTIMATED ADDITIONAL NEED:
Ratio: 50 MW per min. AGC (x) MW per min. AGC
------------------ -------------------
200 MW swing = 160 MW swing
(x) MW per minute AGC = 40
Q: Mr. Venhuizen, are you suggesting that absent certain industrial
customers' application and processes, NIPSCO would not expect to
experience a gap between its AGC capabilities and the regulation
needs of these customers?
A: Yes, that is correct. With the improvement of Unit 18's AGC
capabilities, it is expected that NIPSCO would be able to meet
NERC's standards absent such industrial customers' applications
and processes. However, I am not certain as to the effect if
MISO's MMI is approved by FERC.
Q: Given this explanation, do you believe that starting up Mitchell
would alleviate this gap and reduce this uncertainty associated
with NIPSCO's declining performance against NERC's standards, as
well as the uncertainty associated with the potential MISO
uninstructed deviation provision?
A: No. As highlighted by Mr. Weeden, Mitchell does not provide any
significant contribution to the AGC or regulation abilities of
NIPSCO. Thus, NIPSCO's generating capabilities, even with
Mitchell, do not alleviate the uncertainty surrounding NIPSCO's
abilities to arrest and reverse the declining performance against
NERC's compliance policies and to avoid MISO's potential
financial penalties associated with uninstructed deviations.
More importantly, if NIPSCO's declining performance against
NERC's policies continues, NIPSCO will need the ability to
dispatch resources with AGC capability to meet these needs. This
is achieved through intermediate dispatchable resources.
This discussion highlights one critical uncertainty
surrounding the decision of starting up Mitchell. From my
perspective, Mitchell does not provide the necessary operating
characteristics.
Q: Mr. Venhuizen, please define intermediate dispatchable power.
A: Intermediate dispatchable power, which is sometimes referred to
as cycling capacity, provides the operator with the ability to
cycle and ramp up or down, including cycling offline for periods
of time such as overnight, more than typical base load facilities
without damaging or decreasing the useful life of the generating
10
unit. It can swing much more rapidly and regulate load when it
moves on a moment-by-moment basis.
Q: Can Mitchell supply intermediate dispatchable power?
A: No. Mitchell does not meet this definition since, as described
by Mr. Weeden, Mitchell was designed and constructed to serve as
a base load facility. If started up, Mitchell would not operate
with the necessary AGC or regulation abilities, including the
ability to cycle offline when it is unnecessary. As I discuss
below, Mitchell is not necessary to meet the near term energy
requirements of NIPSCO's firm customers.
Q: Could NIPSCO build new generating facilities with ramping
capabilities sufficient to handle the regulation needs of
NIPSCO's industrial customers' applications and processes?
A: Although Mr. Weeden indicates this could be accomplished in four
to eight years, I believe there is a real question whether such a
facility would be needed four to eight years from now. At
present, it is my understanding that there is an estimated 19,328
MW of available margin in the ECAR region for July 2004. While
we do not know with certainty how much AGC capability is
available as part of this figure, it is reasonable to expect that
some of the available margin could have this ability.
Furthermore, assuming the new MMI takes effect, it is also
reasonable to believe market forces will cause the owners of
available capacity to redesign their generating units to provide
further amounts of AGC capability to satisfy the regulation
demand of NIPSCO's industrial customers. By the time a new
NIPSCO facility went online, the economics motivating the
construction would likely have changed due to the evolution of
the marketplace.
With regard to the immediate future, even more merchant
power plants could be reconfigured to provide the necessary AGC
capability, given the proper economic conditions. Of course, the
owners of those facilities would likely require long-term
contracts as a condition of performing the necessary
modifications. I would note that presently, the interruptible
industrial customer loads served under Rate Schedule 845 and
Rider 846 do not want NIPSCO to enter into forward contracts for
purchased power in order to serve their needs. NIPSCO is
presently adhering to their wishes and not procuring power for
them under forward contracts.
Q: Mr. Venhuizen, you mentioned that you would discuss NIPSCO's
electric supply portfolio needs. Please explain.
11
A: As part of my job responsibilities, I am responsible for the
planning, coordination and development of short-term electric
system power supply requirements and the direction of the
operation of the Company's electric transmission system. This
covers the load requirements of NIPSCO's firm and interruptible
retail customers. My department also monitors the energy needs
of NIPSCO's Fuel Cost Adjustment Clause ("FAC") customers in
order to provide reliable electric supplies from an energy cost
perspective, while making every reasonable effort to utilize
purchased power so as to provide electricity at the lowest energy
cost reasonably possible.
Q: Are there customers unaffected by the FAC mechanism?
A: Yes. As part of my department's monitoring of the energy needs
and energy costs of NIPSCO's native load, there are two
fundamental energy cost "blocks" within the electric retail
system: (1) FAC customers and (2) loads served under Rate
Schedule 845 and Rider 846. Customer loads served under Rate
Schedule 845 and Rider 846 are not subject to the FAC factor, and
more importantly, are interruptible loads for purposes of
purchased power planning activities. My department must consider
these two categories separately for short term planning purposes
since the Rate Schedule 845 and Rider 846 loads do not utilize
forward purchased power resources and FAC loads may utilize such
resources. Rate Schedule 845 and Rider 846 contain a large
portion of NIPSCO's industrial load. In addition, it is
important to note that there are interruptible loads subject to
the FAC factor - e.g., customers under Rate Schedules 836, 835
and 825.
Q: Please explain the short-term planning process for serving
NIPSCO's firm load.
A: NIPSCO utilizes EPRI's Advanced Artificial Neural Network Short-
Term Load Forecaster to generate a seven-day load forecast. A
determination is made of available electric supply resources to
meet load requirements. NIPSCO also evaluates market prices, and
if the market prices are less expensive than NIPSCO's own
internal generating resources, economy purchases are made to
offset more expensive internal resources. If the load exceeds
available resources, a determination is made to purchase forward
or spot market power.
Q: Please explain the intermediate-term planning process for serving
NIPSCO's firm load (i.e., between one month and one year).
A: The intermediate-term planning process starts when NIPSCO
prepares an Annual Fuel Budget study. NIPSCO uses a production
12
costing software package to model its system. NIPSCO obtains
updated values for the various inputs, such as fuel costs, load
forecasts, planned unit outage schedules, emission rates, etc.
NIPSCO also considers available monthly market prices in order to
determine the most economic mixture of resources to meet NIPSCO's
electric retail firm load requirements. If the study indicates
that it would be less expensive to purchase forward resources,
then this is incorporated into NIPSCO's plan. NIPSCO reviews
this plan at least quarterly when NIPSCO prepares the studies for
its FAC mechanism filings at the Commission.
Q: What impact does the possible acquisition of Mitchell have upon
NIPSCO's electric supply portfolio process for firm electric
retail load for the near-term future?
A: None. NIPSCO plans to continue to utilize short-term purchased
power transactions to displace more expensive internal generating
resources when appropriate to provide a lower energy cost for FAC
and Rate Schedule 845 and Rider 846 loads. This process of
utilizing economy purchases would not change regardless of
Mitchell's availability. In addition, NIPSCO expects to continue
to utilize purchased power transactions to replace any forced
outages occurring at its generating facilities when resources
from its other generating facilities are also unavailable.
Q: Mr. Venhuizen, please define the near term future for purposes of
this discussion.
A: Considering the uncertainty of MISO's energy market proposal in
general, my discussion above only covers the process and planning
through March 1, 2005. NIPSCO will continue to participate in
the FERC regulatory process and FERC's consideration of MISO's
MMI proposal, but I cannot offer any guidance beyond March 1,
2005, when the MISO MMI proposal is scheduled to become
effective. Considering this definition, this represents another
noteworthy uncertainty surrounding the status of Mitchell.
Q: Mr. Venhuizen, do you expect that the utilization of short-term
purchased power transactions for NIPSCO's firm load under the FAC
would increase from today if Mitchell were not started up?
A: No, absent needs due to load growth, I do not expect that the
utilization of short-term purchased power transactions would
increase from today if Mitchell were not started up. However, if
short-term purchased power prices declined such that they
displaced more expensive internal generating resources at a
greater frequency than today, then NIPSCO would utilize such
economy purchases more often, to its customers' benefit. It is
important to note, though, that this would still be the policy
13
with or without the availability of Mitchell. As I discussed
above, if and when MISO's proposed MMI becomes effective, I am
not certain as to the utilitization of short-term purchased power
transactions beyond March 1, 2005, with or without Mitchell.
Q: Turning to loads served under Rate Schedule 845 and Rider 846,
what impact does the possible acquisition of Mitchell as
requested by the City of Gary have upon your electric supply
portfolio process for these loads for the near-term future?
A: If Mitchell were not started up, NIPSCO's electric supply
portfolio process for Rate Schedule 845 and Rider 846 loads would
not change from today. With or without Mitchell, it is important
to note that I would have the same concerns surrounding NIPSCO's
lack of AGC capability to serve the industrial customers'
regulation needs considering NERC's policies. Nonetheless,
assuming MISO's proposed MMI becomes effective, my department's
planning process for Rate Schedule 845 and Rider 846 customers
and other industrials may change significantly in order to
address the regulation needs of these customers and other
industrial customers. As highlighted by Mr. Landrieu, there is a
sense of uncertainty surrounding this new market and how NIPSCO's
electric supply resources will react, and it is not known at this
time how any such changes will impact the energy requirements of
NIPSCO's customers.
Q: Mr. Venhuizen, even with this uncertainty beyond the proposed
effective date of MISO's MMI, what is NIPSCO's projected reserve
margin for its firm customers if Mitchell is acquired by the City
of Gary?
A: During preparation of its 2003 Integrated Resource Plan, NIPSCO
generally reviewed its reserve margin. NIPSCO has since reviewed
and updated its IRP short term forecast. It is projected that
NIPSCO will have a very limited deficiency during the peak hours
of June, July and August 2005. This situation is summarized in
Respondent's Exhibit FAV-4. It should be noted that consistent
with industry practice calculation of the reserve margin, this
excludes interruptible loads (e.g. loads under Rate Schedules
836, 845 and Rider 846). It is important to note that this
deficiency does not occur around the clock, thus making addition
of base load capacity an inappropriate solution for this issue.
Q: What conclusions are you able to draw from this reserve margin
situation?
A: Before I discuss any conclusions, there are a number of
assumptions that weigh heavily on this snapshot of NIPSCO's
reserve margin situation. For example, as I have stated before,
NIPSCO cannot adequately determine the impacts of MISO's MMI.
Additionally, NIPSCO will continue to take steps to serve its
14
interruptible customers, but this is just a reliability snapshot
of NIPSCO's firm electric customers.
In order to serve NIPSCO's firm electric customers during
those limited peak hours for 2005, 2006 and 2007, NIPSCO would
evaluate its needs as part of its intermediate planning process,
and secure any short term purchased power resources as needed.
Nonetheless, Respondent's Exhibit FAV-4 clearly shows the limited
deficiency during those peak hours would not warrant a startup of
a base load facility such as Mitchell. Therefore, this case
study illustrates that NIPSCO has adequate resources to serve its
firm electric retail customers absent Mitchell.
On April 22, 2004, NIPSCO provided a presentation to the
Commission regarding the ECAR and NIPSCO's summer assessment,
which included a table showing the net available generation
resources within ECAR. Respondent's Exhibit FAV-5 reflects that
during July 2004, it is anticipated that ECAR would have an
estimated 19,328 MW of available resources. This amount of
resources accessible to NIPSCO presents an additional source of
supply for NIPSCO's firm electric customers with reliable
power. ECAR projects available margins of 13.5 to 17.7 percent,
including serving interruptible customers, scheduled maintenance
and random outages, scheduled purchases and sales, and operating
reserve requirements. As shown on the attached Respondent's
Exhibit FAV-6, the actual full reserve margin for the ECAR region
is approximately 28 percent for 2004, and for MAIN it is
approximately 24 percent for 2004.
Q: Given this picture of the ECAR and MAIN capacity situation, is
there excess base load in the market?
A: Based upon on a review of Respondent's Exhibit FAV-6 (the 2004
EIA 411 report for both MAIN and ECAR), there appears to be
excess base load capacity projected in both regions such that it
may render marginal base load facilities, such as Mitchell,
uneconomical to operate. In addition, Mr. Weeden further
discusses uncertainties surrounding the startup of Mitchell.
Q: In summary, what does this discussion suggest to you regarding
NIPSCO's electric supply portfolio needs and any possible
acquisition of Mitchell?
A: In conclusion, this suggests to me that NIPSCO continues to
observe a situation with a great deal of uncertainty surrounding
the decision to startup Mitchell. From an electric system
operating perspective, NIPSCO's continuing decline of performance
against NERC's standards concerns me. Mitchell will not likely
contribute to NIPSCO's AGC capability to meet the regulation
needs of NIPSCO's industrial customers' applications and
15
processes, which is a factor that should be a factor considered
in this proceeding. However, in the near term, NIPSCO does not
require the startup of Mitchell for purposes of serving its firm
electric retail customers with reliable energy while the City of
Gary's requested relief is considered.
Q: Mr. Venhuizen, were Respondent's Exhibits FAV-2 through FAV-6
prepared under your direct supervision and control?
A: Yes.
Q: Are Respondent's Exhibits FAV-2 through FAV-6 accurate and
complete, to the best of your knowledge, information and belief?
A: Yes, they are.
Q: Does this conclude your Prepared Direct Testimony?
A: Yes, it does.
16
NORTHERN INDIANA PUBLIC SERVICE COMPANY
CAUSE NO. 42643
RESPONDENT'S EXHIBIT FAV-2
Month/Yr. CPS-1 Mon. CPS-1/12 CPS-2
--------- ---------- -------- -----
Jan-02 135.11 131.00 95.90
Feb-02 140.26 131.10 94.78
Mar-02 136.30 134.20 93.50
Apr-02 121.06 134.00 93.39
May-02 122.20 133.00 90.81
Jun-02 109.40 131.00 90.53
Jul-02 99.70 128.00 91.19
Aug-02 113.70 126.00 91.26
Sep-02 106.10 125.00 91.20
Oct-02 114.40 123.00 93.81
Nov-02 118.55 123.00 94.00
Dec-02 117.03 121.00 93.29
Jan-03 115.28 119.00 92.88
Feb-03 115.59 117.00 92.75
Mar-03 119.98 116.00 92.52
Apr-03 121.06 115.00 94.76
May-03 124.57 115.00 93.67
Jun-03 128.72 116.00 94.04
Jul-03 126.60 117.00 93.92
Aug-03 107.85 118.00 92.30
Sep-03 115.74 118.00 92.49
Oct-03 121.28 119.00 92.04
Nov-03 109.60 118.00 92.79
Dec-03 104.18 117.00 92.93
Jan-04 114.62 117.00 92.10
Feb-04 101.51 116.00 91.52
Mar-04 110.42 116.00 90.86
Apr-04 101.41 114.00 90.31
May-04 105.64 113.00 91.15
NORTHERN INDIANA PUBLIC SERVICE COMPANY
CAUSE NO. 42643
RESPONDENT'S EXHIBIT FAV-3
[LINE GRAPH OMITTED]
Respondent's Exhibit FAV-3 represents NIPSCO's industrial applications
and processes where they have very large load swings in very short
periods of time. The y-axis represents the time of day, which as
reflected in Respondent's Exhibit FAV-3 only covers approximately one
hour of one day, and the x-axis represents the amount of megawatts
from certain of NIPSCO's industrial load. Respondent's Exhibit FAV-3
illustrates these large load swings where between approximately 1:00
PM and 1:05 PM, NIPSCO's industrial load moved nearly 250 MW from 550
MW to nearly 800 MW. Then, during the next six to seven minutes, the
industrial load returned below 550 MW. Finally, during the following
five to six minutes, this industrial load returned once again to 800
MW. As Respondent's Exhibit FAV-3 reflects, NIPSCO faces a
significant challenge to supply this load, including complying with
NERC standards surrounding this provision of supply.
<TABLE>
<CAPTION>
Northern Indiana Public Service Company
Cause No. 42643
Respondent's Exhibit FAV-4
CASE EXCLUDE ENERGIES SOLD UNDER RATE 836 AND RATE 845. ALLOW NO LOAD INTERRUPTIONS.
MW Transactions Firm MW Load
MW -------------------- Adjusted ------------------------- Total Calculate Target Reserve
Internal Other MW Gen Gen Sys1 Sys1 Sys1 Firm Reserve MW Margin Margin MW
Year Month Capacity WVPA Argos Purchase Capacity 845 Firm Int 845 Firm MW Load Margin MW Using 11% Deficiency
-------- ---- ----- -------- -------- --- ---- ---- ---- ---- ------- --------- --------- ----------
<s> <c> <c> <c> <c> <c> <c> <c> <c> <c> <c> <c> <c> <c> <c> <c>
2005 1 2,770 (110) (3) 2,657 0 1,662 0 0 373 2,035 622 224 -
2005 2 2,770 (110) (3) 2,657 0 1,558 0 0 400 1,959 698 215 -
2005 3 2,770 (110) (3) 2,657 0 1,533 0 0 369 1,902 755 209 -
2005 4 2,770 (110) (3) 2,657 0 1,500 0 0 380 1,880 777 207 -
2005 5 2,770 (110) (3) 2,657 0 1,801 0 0 367 2,167 490 238 -
2005 6 2,770 (110) (4) 2,656 0 2,121 0 0 367 2,488 168 274 (106)
2005 7 2,770 (110) (4) 2,656 0 2,369 0 0 368 2,737 (81) 301 (382)
2005 8 2,770 (110) (4) 2,656 0 2,349 0 0 372 2,721 (65) 299 (364)
2005 9 2,770 (110) (3) 2,657 0 2,008 0 0 381 2,389 267 263 -
2005 10 2,770 (110) (3) 2,657 0 1,539 0 0 364 1,903 754 209 -
2005 11 2,770 (110) (3) 2,657 0 1,549 0 0 374 1,923 735 211 -
2005 12 2,770 (110) (2) 2,658 0 1,647 0 0 364 2,011 647 221 -
2006 1 2,770 - 2,770 0 1,697 0 0 378 2,075 695 228 -
2006 2 2,770 - 2,770 0 1,584 0 0 406 1,990 780 219 -
2006 3 2,770 - 2,770 0 1,556 0 0 374 1,931 839 212 -
2006 4 2,770 - 2,770 0 1,524 0 0 386 1,910 860 210 -
2006 5 2,770 - 2,770 0 1,834 0 0 372 2,206 564 243 -
2006 6 2,770 - 2,770 0 2,152 0 0 372 2,524 246 278 (32)
2006 7 2,770 - 2,770 0 2,395 0 0 372 2,768 2 304 (302)
2006 8 2,770 - 2,770 0 2,383 0 0 377 2,760 10 304 (293)
2006 9 2,770 - 2,770 0 2,044 0 0 386 2,430 340 267 -
2006 10 2,770 - 2,770 0 1,560 0 0 369 1,930 840 212 -
2006 11 2,770 - 2,770 0 1,569 0 0 379 1,948 822 214 -
2006 12 2,770 - 2,770 0 1,674 0 0 369 2,044 726 225 -
2007 1 2,770 - 2,770 0 1,733 0 0 383 2,116 654 233 -
2007 2 2,770 - 2,770 0 1,610 0 0 411 2,021 749 222 -
2007 3 2,770 - 2,770 0 1,581 0 0 379 1,960 810 216 -
2007 4 2,770 - 2,770 0 1,550 0 0 391 1,940 830 213 -
2007 5 2,770 - 2,770 0 1,868 0 0 377 2,245 525 247 -
2007 6 2,770 - 2,770 0 2,185 0 0 377 2,562 208 282 (73)
2007 7 2,770 - 2,770 0 2,423 0 0 378 2,800 (30) 308 (338)
2007 8 2,770 - 2,770 0 2,418 0 0 382 2,800 (30) 308 (338)
2007 9 2,770 - 2,770 0 2,081 0 0 391 2,472 298 272 -
2007 10 2,770 - 2,770 0 1,583 0 0 374 1,957 813 215 -
2007 11 2,770 - 2,770 0 1,591 0 0 384 1,974 796 217 -
2007 12 2,770 - 2,770 0 1,703 0 0 374 2,077 693 229 -
OBJECTIVE: Determine the generating system reliability at the time of the monthly system peak hour, given the specified
--------- system loads over 2005-2007.
ASSUMPTIONS
-----------
a. Units 2, 3 and all DHMGS units are unavailable and do not contribute to reserve margin as of 12/31/04.
b. Internal capacity can adequately regulate firm load.
c. Exclude energy and demand sales under rate 836 and rate 845. Consequently do not interrupt rate 836 and rate 845 loads.
COMMENTS CONCERNING CALCULATED RESERVE MARGIN DEFICIENCY
--------------------------------------------------------
a. Deficiencies occur only in June, July and August each year.
b. Given historic load profiles, these deficiencies occur during on peak periods, not round the clock.
</TABLE>
<TABLE>
<CAPTION>
NORTHERN INDIANA PUBLIC SERVICE COMPANY
CAUSE NO. 42643
RESPONDENT'S EXHIBIT FAV-5
ECAR/NIPSCO SUMMER ASSESSMENT
JUNE - AUGUST 2004
RESERVE MARGINS (MW)
---------------------------------------------------------------------
ECAR (Serving Interruptibles) ECAR (Not Serving Interruptibles)
June July August June July August
---- ---- ------ ---- ---- ------
<s> <c> <c> <c> <c> <c> <c>
Net Available
Resources 123,498 124,577 124,695 123,498 124,577 124,695
Total Obligations 101,582 107,720 107,371 99,138 105,249 104,889
Available Margins
MW 21,916 16,857 17,324 24,360 19,328 19,806
% 17.7 13.5 13.9 19.7 15.5 15.9
</TABLE>
<TABLE>
<CAPTION>
Northern Indiana Public Service Company
Cause No. 42643
Respondent's Exhibit FAV-6
MAIN
----
PROJECTED
-----------------------------------------------------------
2004 2005 2006 2007 2008 2009 2010
---- ---- ---- ---- ---- ---- ----
<s> <c> <c> <c> <c> <c> <c> <c>
DEMAND
01 Internal Demand 57867 58666 59716 60468 61324 62235 63169
02 Standby Demand 1 1 1 1 1 1 1
03 Total Demand (01 + 02) 57868 58667 59717 60469 61325 62236 63170
04 Direct Control Load Management 817 823 826 830 833 838 842
05 Interruptible Demand 2446 2350 2351 2356 2356 2356 2357
06 Net Internal Demand (03 - 04 - 05) 54605 55494 56540 57283 58136 59042 59971
CAPACITY
07 Comitted Resources 57914 53239 53111 53289 53584 53227 53925
08 Distributed Generator Capacity >= 1MW 409 409 409 409 409 409 409
09 Other Capacity >= 1MW 57450 52775 52647 52825 53120 52763 53461
10 Distributed Generator Capacity < 1MW 35 35 35 35 35 35 35
11 Other Capacity < 1MW 20 20 20 20 20 20 20
12 Uncomitted Resources 10944 17738 19329 21168 21778 24252 24577
13 Total Capacity (07 + 12) 68858 70977 72440 74457 75362 77479 78502
13.1 Nuclear 14648 14335 14405 14405 14405 14405 14405
13.2 Hydro 596 596 596 596 596 596 596
13.3 Pumped Storage 440 440 440 440 440 440 440
13.4 Geothermal 0 0 0 0 0 0 0
13.5 Steam 33801 33569 33632 34380 34740 36857 37880
13.5.1 Coal 29050 28825 28888 29636 29996 32113 33136
13.5.2 Oil 424 424 424 424 424 424 424
13.5.3 Gas 527 520 520 520 520 520 520
13.5.4 Dual Fuel 3800 3800 3800 3800 3800 3800 3800
13.6 Combustion Turbine 15818 16469 17399 18268 18268 18268 18268
13.6.1 Oil 1308 1308 1308 1308 1308 1308 1308
13.6.2 Gas 11773 12424 13354 14102 14102 14102 14102
13.6.3 Dual Fuel 2737 2737 2737 2858 2858 2858 2858
13.7 Combined Cycle 2946 4781 4781 4781 5326 5326 5326
13.7.1 Oil 33 33 33 33 33 33 33
13.7.2 Gas 2276 4111 4111 4111 4656 4656 4656
13.7.3 Dual Fuel 637 637 637 637 637 637 637
13.8 Other 609 787 1187 1587 1587 1587 1587
14 Inoperable Capacity 1401 1409 1409 1409 1409 1409 1409
15 Net Operable Capacity (13 - 14) 67457 69568 71031 73048 73953 76070 77093
16 Capacity Purchases - Total 1241 1208 2009 2115 1950 1895 1919
17 Full Responsibility Purchases 319 249 254 261 191 221 227
18 Capacity Sales - Total 918 959 1586 1657 1651 1519 1521
19 Full Responsibility Sales 208 260 287 358 352 196 198
20 Adjustment to Purchases and Sales 0 0 0 0 0 0 0
21 Net Capacity Resources (15 + 16 - 18 + 20) 67780 69817 71454 73506 74252 76446 77491
Page 1 of 2
Northern Indiana Public Service Company
Cause No. 42643
Respondent's Exhibit FAV-6
ECAR
----
PROJECTED
-----------------------------------------------------------
2004 2005 2006 2007 2008 2009 2010
---- ---- ---- ---- ---- ---- ----
DEMAND
01 Internal Demand 102423 104765 107689 109852 112007 113674 115579
02 Standby Demand 0 0 0 0 0 0 0
03 Total Demand (01 + 02) 102423 104765 107689 109852 112007 113674 115579
04 Direct Control Load Management 172 207 240 274 289 290 291
05 Interruptible Demand 2471 2426 2395 2385 2361 2302 2308
06 Net Internal Demand (03 - 04 - 05) 99780 102132 105054 107193 109357 111082 112980
CAPACITY
07 Comitted Resources 128406 128406 128406 128406 128406 128406 128406
08 Distributed Generator Capacity >= 1MW 0 0 0 0 0 0 0
09 Other Capacity >= 1MW 128370 128370 128370 128370 128370 128370 128370
10 Distributed Generator Capacity < 1MW 0 0 0 0 0 0 0
11 Other Capacity < 1MW 36 36 36 36 36 36 36
12 Uncomitted Resources 2480 7008 7935 9435 10167 10167
13 Total Capacity (07 + 12) 128406 130886 135414 136341 137841 138573 138573
13.1 Nuclear 7733 8001 10561 10561 12061 12793 12793
13.2 Hydro 1052 1052 1052 1052 1052 1052 1052
13.3 Pumped Storage 2138 2138 2138 2138 2138 2138 2138
13.4 Geothermal 0 0 0 0 0 0 0
13.5 Steam 86642 86642 86642 86642 86642 86642 86642
13.5.1 Coal 82715 82715 82715 82715 82715 82715 82715
13.5.2 Oil 1570 1570 1570 1570 1570 1570 1570
13.5.3 Gas 2357 2357 2357 2357 2357 2357 2357
13.5.4 Dual Fuel 0 0 0 0 0 0 0
13.6 Combustion Turbine 21137 21365 21893 21893 21893 21893 21893
13.6.1 Oil 1796 1796 1796 1796 1796 1796 1796
13.6.2 Gas 19341 19569 20097 20097 20097 20097 20097
13.6.3 Dual Fuel 0 0 0 0 0 0 0
13.7 Combined Cycle 8988 10972 12412 13339 13339 13339 13339
13.7.1 Oil 0 0 0 0 0 0 0
13.7.2 Gas 8988 10972 12412 13339 13339 13339 13339
13.7.3 Dual Fuel 0 0 0 0 0 0 0
13.8 Other 716 716 716 716 716 716 716
14 Inoperable Capacity 1943 1943 1943 1943 1943 1943 1943
15 Net Operable Capacity (13 - 14) 126463 128943 133471 134398 135898 136630 136630
16 Capacity Purchases - Total 2902 0 0 0 0 0 0
17 Full Responsibility Purchases 0 0 0 0 0 0 0
18 Capacity Sales - Total 1200 0 0 0 0 0 0
19 Full Responsibility Sales 0 0 0 0 0 0 0
20 Adjustment to Purchases and Sales 0 0 0 0 0 0 0
21 Net Capacity Resources (15 + 16 - 18 + 20) 128165 128943 133471 134398 135898 136630 136630
Page 2 of 2
</TABLE>
</TEXT>
</DOCUMENT>