EX-99 6 xex99_5.txt 99.5 PREPARED DIRECT TESTIMONY OF JEROME B. WEEDEN EXHIBIT 99.5 ------------ RESPONDENT'S EXHIBIT JBW-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 ) RESPONDENT: NORTHERN INDIANA ) PUBLIC SERVICE COMPANY. ) ======================================================== PREPARED DIRECT TESTIMONY OF JEROME B. WEEDEN 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 JEROME B. WEEDEN --------------------------------------------- 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 1 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 2 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 3 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: 4 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 5 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 6 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 7 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. 8 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 9 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 10 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 11 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, 12 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 13 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. 14