EX-99 5 xex99_4.txt 99.4 PREPARED DIRECT TESTIMONY OF FRANK A. VENHUIZEN EXHIBIT 99.4 ------------ 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.