-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, HppEo6/pBvNsEWYsHoI0QOMv4zyaF3j885wbGyviUYl2PArjNL/v3zcA4LymT5+n 1SHSmMqiFIcf6A8ocaiV1g== 0000895813-04-000115.txt : 20040713 0000895813-04-000115.hdr.sgml : 20040713 20040712174509 ACCESSION NUMBER: 0000895813-04-000115 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 20040709 ITEM INFORMATION: Other events FILED AS OF DATE: 20040713 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NISOURCE INC/DE CENTRAL INDEX KEY: 0001111711 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 352108964 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-16189 FILM NUMBER: 04910793 BUSINESS ADDRESS: STREET 1: 801 EAST 86TH AVE CITY: MERRILLVILLE STATE: IN ZIP: 46410-6272 BUSINESS PHONE: 2196475200 MAIL ADDRESS: STREET 1: 801 EAST 86TH AVE CITY: MERRILLVILLE STATE: IN ZIP: 46410-6272 FORMER COMPANY: FORMER CONFORMED NAME: NEW NISOURCE INC DATE OF NAME CHANGE: 20000412 8-K 1 x0712-8k.txt SECURITIES AND EXCHANGE COMMISSION WASHINGTON, DC 20549 FORM 8-K CURRENT REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Date of Report (Date of earliest event reported): July 9, 2004 NISOURCE INC. ------------- (Exact Name of Registrant as Specified in Its Charter) Delaware 001-16189 35-2108964 -------- --------- ---------- (State or Other Jurisdiction (Commission File (IRS Employer of Incorporation) Number) Identification No.) 801 E. 86th Avenue, Merrillville, Indiana 46410 --------------------------------------------------------------------- (Address of Principal Executive Offices) (Zip Code) Registrant's telephone number, including area code (877) 647-5990 -------------- ---------------------------------------------------------------------- (Former Name or Former Address, if Changed Since Last Report) Item 5. Other Events and Required FD Disclosure. NiSource Inc. is furnishing this Report on Form 8-K in connection with the filing by its subsidiary, Northern Indiana Public Service Company, with the Indiana Utility Regulatory Commission on July 9, 2004 of testimony relating to NIPSCO's Dean H. Mitchell Generating Station. This testimony will also be published on NiSource's website (www.nisource.com). NiSource does not have, and expressly disclaims, any obligation to release publicly any updates or any changes in NiSource's expectations or any changes in events, conditions or circumstances on which any forward-looking statement is based. Exhibit 99.1 Prepared Direct Testimony of Pierre R. H. "Pete" Landrieu on behalf of Northern Indiana Public Service Company. Exhibit 99.2 Prepared Direct Testimony of Mark T. Maassel on behalf of Northern Indiana Public Service Company. Exhibit 99.3 Prepared Direct Testimony of Arthur E. Smith, Jr. on behalf of Northern Indiana Public Service Company. Exhibit 99.4 Prepared Direct Testimony of Frank A. Venhuizen on behalf of Northern Indiana Public Service Company. Exhibit 99.5 Prepared Direct Testimony of Jerome B. Weeden on behalf of Northern Indiana Public Service Company. SIGNATURE Pursuant to the requirement of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. NISOURCE INC. (Registrant) Dated: July 12, 2004 By: /s/ Gary W. Pottorff -------------------------- Name: Gary W. Pottorff Title: Secretary Index to Exhibits ----------------- Exhibit Number Exhibit Title -------------- ------------- 99.1 Prepared Direct Testimony of Pierre R. H. "Pete" Landrieu on behalf of Northern Indiana Public Service Company. 99.2 Prepared Direct Testimony of Mark T. Maassel on behalf of Northern Indiana Public Service Company. 99.3 Prepared Direct Testimony of Arthur E. Smith, Jr. on behalf of Northern Indiana Public Service Company. 99.4 Prepared Direct Testimony of Frank A. Venhuizen on behalf of Northern Indiana Public Service Company. 99.5 Prepared Direct Testimony of Jerome B. Weeden on behalf of Northern Indiana Public Service Company. EX-99 2 xex99_1.txt 99.1 PREPARED DIRECT TESTIMONY OF PIERRE R. H. LANDRIEU EXHIBIT 99.1 ------------ RESPONDENT'S EXHIBIT PRL-1 --------------------------- STATE OF INDIANA INDIANA UTILITY REGULATORY COMMISSION IN THE MATTER OF THE PETITION OF ) ) THE CITY OF GARY, INDIANA ) REQUESTING THE INDIANA ) UTILITYREGULATORY COMMISSION ) ESTABLISH THE TERMS AND ) CONDITIONS OF THE SALE OF CERTAIN ) Cause No. 42643 PROPERTY OF NORTHERN INDIANA ) PUBLIC SERVICE 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 PIERRE R.H. "PETE" LANDRIEU 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 PIERRE R.H. "PETE" LANDRIEU -------------------------------------------------------- I. INTRODUCTION Q: PLEASE STATE YOUR NAME, OCCUPATION, AND BUSINESS ADDRESS. A: My name is Pierre R.H. "Pete" Landrieu. I am President of PLP3, a consultancy specializing in electric power generation, transmission, wholesale electric markets, Independent System Operators ("ISOs"), Regional Transmission Organizations ("RTOs") and associated regulatory policies. My business address is 10 Sentinel Drive, Basking Ridge, N.J. 07920. Q: WHAT IS YOUR EDUCATIONAL BACKGROUND? A: I graduated from Lehigh University with a Bachelor of Science degree in Electrical Engineering. Q: PLEASE DESCRIBE YOUR EMPLOYMENT EXPERIENCE. A: In 1963, I began a 40 year career at Public Service Electric and Gas Company ("PSE&G"), a large combination electric and gas utility in New Jersey, where I performed transmission and distribution system planning and engineering studies and contributed to the construction and operation of fossil and nuclear generating facilities. I was Project Manager for the building of the Hope Creek Nuclear Generating Station during the early 1980s. I became Vice-President of Engineering and Construction in 1986; Vice-President of Fossil Generation in 1989; Vice-President of Electric Transmission in 1995 and Vice- 2 President of Federal Regulatory Policy in early 2003. I retired from PSE&G in August 2003. I have experience managing a variety of business components of the electric industry, including generation and transmission assets, industry restructuring activities, wholesale electric markets, PJM and system reliability. For six years I was the executive in charge of PSE&G's fossil-fueled Generation Business, during which time I installed environmental upgrades on three coal generating stations, converted a former coal station to combined cycle operation and converted simple cycle gas turbines to combined cycle operation. The environmental upgrades I directed included installation of low NOx burners with over-fire air, electrostatic precipitators, selective catalytic reduction technology, waste water treatment facilities, cooling towers and pond liners. In the course of my career I have participated in the operation, design, construction and start-up of over forty electric generation units including combustion turbines ("CTs"), combined cycle, hydro, coal-fired steam units and nuclear units. For five years I served on the Board of Directors of Clean Air Action, a business venture formed in the early 1990s to promote and profit from trading and banking of air emissions. I have been involved with the PJM Mid-Atlantic power pool and ISO for over thirty five years and participated in its restructuring as PJM evolved from a tight power pool into an ISO and subsequently into a RTO. I participated in PJM task forces 3 in the 1960s and 1970s which culminated in papers published by the Institute of Electrical and Electronic Engineers. During the 1990s, I served as Chairman of the PJM Management Committee, the owners committee charged with directing the activities of PJM. In 1995, after the Federal Energy Regulatory Commission ("FERC") issued an "open access" Notice of Proposed Rulemaking that accelerated the restructuring of the electric industry, I chaired the PJM Market Issues Resolution Group that developed and planned the design for PJM's conversion from a tight power pool to an ISO and electricity market. In December 1995, I testified at FERC regarding the planned design features of the PJM ISO. I participated in the preparation of filings at FERC that led to the approval of PJM as an ISO in 1996. I have participated for the last eight years in various PJM committees and testified at U.S. Senate hearings regarding PJM and workable wholesale electricity markets. In 2003, I testified at FERC regarding transmission-generator interconnections on behalf of the Edison Electric Institute, the industry association of investor owned utilities in the United States. For eight years during the period of electric industry unbundling and restructuring, I led PSE&G's Transmission Business Unit. During that time, I was involved in three separate initiatives to develop independent stand-alone transmission companies. In that connection I worked extensively with the financial community regarding the valuation and financing of transmission companies. 4 I have made presentations to FERC, the Harvard Electric Policy Group, congressional representatives and numerous industry forums regarding the business propositions and issues surrounding transmission, generation and wholesale market issues. For the past six years I served as Chairman of the Mid- Atlantic Area Council ("MAAC"), the Regional Council with oversight of reliability in the PJM region. I represented MAAC in the Fact Finding investigation by the Department of Energy ("DOE"), FERC and the North American Electric Reliability Council ("NERC") into the August 14, 2003 electric blackout in the Northeast. In August 2003 I retired from PSE&G and established a consultancy specializing in electric power issues and policy. Q: HAVE YOU PREVIOUSLY TESTIFIED BEFORE OTHER REGULATORY COMMISSIONS AND COMMITTEES? A: In addition to the aforementioned FERC testimony, I have testified before the New Jersey Board of Public Utilities and the Senate Committee on Energy and Natural Resources. Q: WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS PROCEEDING? A: I was retained by Northern Indiana Public Service Company ("NIPSCO") to review and express an opinion on the advisability of starting up NIPSCO's Dean H. Mitchell Generating Station ("Mitchell"), giving consideration to NIPSCO's load profile, 5 current and impending operating and regulatory requirements and the evolving electric energy marketplace. Q: PLEASE DESCRIBE THE INVESTIGATION YOU MADE AND THE INFORMATION YOU REVIEWED IN PERFORMING THIS ANALYSIS AND IN DEVELOPING YOUR OPINION. A: I reviewed the testimony of NIPSCO's witnesses in this proceeding and discussed the issues with them and other representatives of the Company. I have reviewed NIPSCO's FERC Form One and other documents relating to the issues. I have also reviewed documents provided by PJM regarding the planned PJM/MISO joint and common market. Q: HOW DOES THE STATE OF THE PJM WHOLESALE ENERGY MARKET COMPARE TO MISO'S MIDWEST MARKET INITIATIVE? A: The PJM energy market started in 1997 and was modified in 1998. It has continued to grow in size with the addition of PJM West, the recent addition of Commonwealth Edison and the pending additions of AEP, Duquesne and Dominion. The PJM energy market has also continued to become more sophisticated with the development of features such as a regulation market, capacity market, and the auction of financial transmission rights. PJM is about eight years ahead of MISO with respect to operating wholesale energy markets. In my opinion, the PJM experience is relevant to evaluating how the MISO energy market will develop. 6 Q: PLEASE SUMMARIZE THE MATTERS COVERED IN YOUR DIRECT TESTIMONY. A: My Direct Testimony will discuss my opinion that the regulatory, environmental and market uncertainties in the electric industry as well as the unique load profile of NIPSCO's electric customers make Mitchell's return to service unwise. In the course of my testimony, I will explain that: (a) NIPSCO's unique load profile presents challenges to which the Mitchell plant is ill suited, particularly given new standards, enforcement, audits, disclosure policy and penalties of NERC; (b) the environmental and associated financial risks which attend return to service of a 1950s era coal plant are large and unquantifiable at present; (c) the competitive wholesale markets for electricity which MISO is endeavoring to establish are problematic for a base load coal plant like Mitchell; (d) the timing of MISO energy markets becoming established is uncertain and why this increases the risk of investment in a startup of Mitchell; (e) the rules and regulations in the electric industry are in the midst of significant change in several regulatory venues as the industry restructures; and that resolution of the many issues in play is not close at hand nor are the outcomes predictable; and (f) the restructuring and regulatory initiatives in Congress, FERC, NERC, and DOE, are wildcards that could bear 7 heavily on the viability of Mitchell and these initiatives do not yet promise near-term predictable outcomes. Because of the above substantial financial and regulatory risks that would attend a startup of Mitchell, a very certain and very high benefit would be required to justify startup; I see no such certain, high benefit. II. NIPSCO LOAD PROFILE AND SUPPLY ------------------------------ Q: WHAT IS UNIQUE ABOUT NIPSCO'S LOAD PROFILE AND HOW DOES THIS BEAR ON THE STARTUP OF MITCHELL? A: As discussed by Mr. Frank A. Venhuizen in his direct testimony and as shown by his exhibits, it is apparent that NIPSCO's customer load profile is unique with regard to its regulation needs. Coal base load plants such as Mitchell are poorly suited to provide the type of regulation that this severe load profile demands. NIPSCO is already fine-tuning the automatic generation control ("AGC") capabilities of its plants and has plans to provide the best load following capability inherent in the equipment. As Mr. Venhuizen explains, NERC's Control Performance Standards (CPS1 and CPS2) require a Control Area operator to readjust generator outputs to match changes in load. Another NERC standard, Disturbance Control Standard (DCS) requires a Control Area operator to readjust generator outputs after a 8 disturbance on the system in order to reestablish system security and prevent overloads from any subsequent disturbance. The August 14, 2003 blackout resulted when these NERC standards were violated and generators were not adjusted in a timely fashion to prevent transmission overloads. Inability to meet NERC standards is an increasingly serious concern. Prompted in part by the August 14, 2003 blackout, and in part by the failure of Congress to pass electric reliability language, NERC, with support from FERC and DOE, has moved to conduct readiness audits of all Control Area operators and security coordinators at least once every three years, as well as require Control Area operators, security coordinators and regions to report all violations of NERC standards to NERC. In the past, the identity of those violating NERC standards has been confidential and not disclosed. Until present, not even the NERC Board has known the identity of violators; these were deemed confidential by the utilities. However, at the June 15, 2003 meeting of the NERC Board of Trustees, NERC determined that in the future it will disclose publicly all reported violations and audit results. In my mind this is a far more serious penalty than the monetary penalties that are envisioned in pending federal legislation. A volatile load profile could also impact a generator's profitability in MISO's future real time energy market. I discuss this future market later in my testimony. This market will set Locational Marginal Prices ("LMPs") every 5 minutes and 9 the volatility of NIPSCO's load will be reflected in volatility of the LMPs. The LMPs are the prices the market pays to generators in the real time energy market. A generator earns money when the LMP at its bus location is higher than its marginal cost to generate, and loses money when the LMP at its location is lower than its marginal cost to generate. A generator therefore needs to be able to produce at maximum output when it is profitable to do so, and minimum or zero output when the LMP falls below its marginal cost to generate. Experience of generators in the PJM real time energy market have demonstrated that a plant such as Mitchell is poorly-suited to be profitable in a volatile LMP market. As Mr. Venhuizen has also explained, MISO also plans to establish a regulation market for which Mitchell is ill-suited. Q: IS IT POSSIBLE THAT THIS SITUATION WILL IMPROVE OVER TIME? A: Yes. With sufficient interconnection capacity, NIPSCO's load could be supplied by other generators in the regulation market. But the timing for establishing a regulation market in MISO is uncertain. MISO and PJM have announced plans to develop a joint and common market that eventually will produce very large regional energy and regulation markets and a security constrained dispatch equivalent to that of a much larger control area. As discussed later, the timing of this initiative has slipped and is uncertain. However, these same market forces that potentially will improve NIPSCO's ability to meet these volatile demand 10 characteristics through additional intertie capacity could negatively affect the value of the Mitchell plant as discussed in Mr. Venhuizen's testimony. Q: IS THERE A NEED FOR ADDITIONAL BASE LOAD CAPACITY IN THE REGION? A: No. There is a surplus of low cost base load generation. Startup of Mitchell would exacerbate the surplus and the inefficiency of the oversupply condition by increasing overall fixed costs for supplying load while not decreasing the variable costs. III. ENVIRONMENTAL ISSUES -------------------- Q: PLEASE DESCRIBE THE ENVIRONMENTAL ISSUES ATTENDING A STARTUP OF MITCHELL. A: Mitchell is a 1950s era coal fired plant. Environmental concerns have grown greatly since that era. Today's air and water regulations are far more stringent than those the plant was designed to meet, and tighter environmental regulations are on the horizon. Although upgrades have been made over the time the plant was in operation, a startup initiative would invite new scrutiny of the plant's environmental profile. As Mr. Arthur E. Smith, Jr. explains, the extent of upgrades that might be required by environmental regulators will be affected by the structure of future emission standards and whether an allowance trading program is included in the regulations. If applications 11 and fees for a startup were put forward, the determination of required upgrades would probably not be forthcoming for at least a year. In my experience, the engineering and cost estimates to perform the upgrades would require another year. My experience has also shown that actual final costs can escalate by as much as 100% over early cost estimates due to the unpleasant surprises that opening up a 50 year old boiler entails, as well as due to regulatory creep and scope increases. The financial risks imposed by the environmental risk issues are very large. Several of the upgrades currently available and well known to environmental regulators entail injection of chemicals or other processes that raise the cost of generation, so that what once seemed low fuel cost incremental power is no longer as low cost after the costs of required upgrades chemicals injected are factored in. However there are even larger environmental risks in the future. As Mr. Mr. Smith explains, at present, in both the EPA and Congress, decisions are pending that will affect the costs and viability of coal fired plants everywhere. These include decisions on three vs. four pollutant standards, mercury in coal, particulates, fly ash disposal, fresh waters, etc. These could render a startup decision based on today's standards inappropriate. Initiatives are underway at both the federal and state levels to promote integrated coal gasification combined cycle as a clean coal alternative that would also better fit unique load 12 profiles such as NIPSCO's. These initiatives could hasten retirement of existing base load coal plants. I believe that the risks created by the environmental upgrade cost overhangs I have described are very large, and it would require very large proven long term benefits to justify the taking of such risks. IV. MISO RTO AND MARKETS -------------------- Q: DOES THE TIMING OF MISO'S MARKET IMPLEMENTATION AFFECT STARTUP OF MITCHELL? A: Yes, but the impact is unclear. I expect that MISO's wholesale energy marketplace will evolve much as PJM, becoming more sophisticated and complete over a period of years. When MISO's wholesale electricity marketplace is fully developed, there will be a common economic least-cost security constrained dispatch involving many more generators over a much larger region. The dispatch patterns are certain to differ from current patterns, and some generators will benefit at others' expense. Generators will be paid at the locational marginal prices at their bus. These prices will be high where there is a shortage of supply and low where there is an excess of supply, so that generators in an area of oversupply will have a more difficult time covering fixed costs and variable costs and achieving a profit. For load serving entities that want to self-schedule or contract bi- laterally with specific generators, hedging instruments will 13 provide a mechanism to protect the contract parties from varying locational prices and provide delivered price certainty. These hedging instruments will be tradable or saleable but only some will be desirable and so valued; others may be undesirable to own and have little or negative value. A market for regulation service will exist so that those whose generation cannot follow load variations can procure that service from those who can in the wider market. Obviously, the financial outlook for a generator can be very different in this post-market world than it was in the pre-market world. Q: YOU HAVE SAID THAT STARTUP OF MITCHELL IS UNWISE DUE TO INABILITY TO FOLLOW NIPSCO'S UNIQUE LOAD PROFILE AND THE UNCERTAINTY OF ENVIRONMENTAL COST OVERHANG; WILL THIS CHANGE IN THE MISO POST- MARKET ENVIRONMENT? A: It would almost certainly be different due to the larger market, more generators in the dispatch, locational pricing, hedging instruments and a market for regulation services. Older less efficient units such as Mitchell are likely to have a difficult time competing in a fully developed marketplace. However, whether the post-market environment would be beneficial or harmful to Mitchell's financial viability is unknown to me at this time. While modeling studies might be able to forecast an outcome, such studies are time-consuming and expensive to perform and have proven to be prone to inaccurate projections. This is due to the numerous assumptions they require and the low 14 probability that all the assumed inputs will occur as forecast, especially when moving from the more controlled economic state currently to a more complex and dynamic market state in the future. The economy can change; load forecasts change; new generators come on line; old generators retire; market policies and protocols change due to stakeholder input; fuel prices change; new transmission may be built; etc. The very timing of the MISO market implementation is uncertain; there is no reason to assume that the slippages which have occurred to date in MISO markets, are not to be followed by more slippages. V. REGULATORY UNCERTAINTY IN THE ELECTRIC UTILITY INDUSTRY Q: WHAT IS THE STATE OF THE ELECTRIC INDUSTRY AND THE REGULATORY UNCERTAINTIES THAT INFLUENCE INVESTMENT DECISIONS SUCH AS THE STARTUP OF THE MITCHELL COAL PLANT? A: For almost past two decades the electric industry enjoyed a lack of the energy price volatility that followed the Arab oil embargo of the 1970s. However, more recently there have been structural changes resulting from deregulation initiatives. The National Energy Policy Act of 1992 greatly increased prospective competition for the production and sale of power at the wholesale level. FERC Orders 888 and 2000 mandated open access to the transmission systems of jurisdictional electric utilities. In 1996, following issuance of FERC Order 888, Merrill Lynch stated that "the industry is in a monumental transition state The risk 15 profile of the electric utility industry is clearly reaching higher levels than in the past and will further increase." Since FERC issued its Open Access NOPR in 1995 (and subsequent Orders 888 and 2000), ISOs and RTOs have been emerging across much of the United States. Understandably, due to the pre-existence of tight power pools, ISO/RTOs emerged in the Northeast earlier than in many other parts of the nation. Q: WHY HAVE ISO/RTOS DEVELOPED ALONG SUCH DIFFERENT TIME LINES? A: This is because of regional histories and cultural differences, political forces and industry crisis: (a) The transmission owners in the Northeast enjoyed a longstanding cultural realization that sharing of transmission and generation resources brings about both economic and reliability benefits and thereby lower operational and financial risk. PJM Power Pool was formed in 1927 by three utilities, grew to ten utilities by the 1970s and is still growing to the west and south. NEPOOL was formed in 1971 and has a 33 year history of success. NY Power Pool was also formed in the early 1970s. (b) The tight power pools, having existed in the Northeast for many years, already had many of the features, infrastructure, staffing, policies and practices that an ISO requires, so the transition from tight power pool to ISO was a small, easy and relatively inexpensive, low-risk step. In parts of the United ___________________ Merrill Lynch, ELECTRIC UTILITY INDUSTRY REPORT, p. 3 (June 24, 1966). 16 States where ISOs/RTOs are less mature than in the Northeast, such as MISO, the timing of achieving the establishment of competitive markets is uncertain. This is because the difficulties and costs of creating the infrastructure, staff, markets, and protocols with no pre-existing infrastructure are significantly greater than in the Northeast where a foundation already existed with the tight power pools. (c) In places where there is not a cultural heritage of tightly pooled operation, as there was in PJM, important issues regarding ISO/RTO design and structure tend to be resolved through compromise and politics rather than based on the physics of the grid. (d) There is greater risk of getting something wrong when trying to build an ISO/RTO from scratch rather than in converting from an existing tight power pool. (e) The California energy crisis and Enron disaster in 2000 caused many to pause and reevaluate. (f) Inexperienced system operators in a nascent ISO/RTO are more prone to operational errors than those where there is an experienced staff available from a tight power pool. This was a contributing factor to the August 14, 2003 blackout which originated in MISO, a nascent RTO. ____________________ Platts ELECTRIC UTILITY WEEK (July 9, 2001) noted that the "crisis saps investor confidence" and that fallout from the financial deteriora- tion of California's utilities had spread beyond the state as "investors have turned away, spooked by the political and regulatory climate." 17 Q: DESCRIBE THE VARIOUS REGULATORY UNCERTAINTIES THAT EXIST GOING FORWARD. A: I will briefly summarize several of them. FERC: FERC followed Orders 888 and 2000 with its Standard Market Design ("SMD") that went farther than the two orders in detailing new markets. The criticism of the SMD was intense and caused Congress to modify the electricity bill provisions to prevent FERC from proceeding. FERC retreated by issuing a whitepaper that softened many of the SMD provisions; however, there has been no subsequent rulemaking. FERC in its whitepaper championed Regional State Committees that would have input on several regional matters, but it is too early for me to draw conclusions about the impact these committees will have in the future. FERC is also unclear about its market power screen. NERC: NERC has been seeking congressional legislation to give it the authority to enforce compliance with mandatory reliability standards. The legislative language NERC has pushed for over four years is tied up in a comprehensive energy bill that has included issues far removed from electricity, such as Alaskan drilling, ethanol and liability for gasoline additives. Congress so far has been unwilling to remove the NERC provisions and move them as stand alone legislation. Meanwhile the blackout of August 14, 2003 called a time out on regulatory policy initiatives as fact finding and analysis occurred. 18 CONGRESS: As described above, Congress continues to be stalled on passing its energy bill, and unless another blackout pushes it into action, expectations for passage are gloomy for the near term. DOE: Having just established and staffed an electric transmission and distribution office in the past year, DOE is busy trying to define its role in the electric industry. So far it has spoken enthusiastically regarding new technologies and a HVDC super-grid, neither of which assist in making investment decisions in the short term. Q: WHAT IMPACTS OCCURRED TO GENERATORS WITHIN PJM AS A RESULT OF RESTRUCTURING AND THE ESTABLISHMENT OF MARKETS? A: After PJM's wholesale electric markets were in place, generators reacted in several ways: (a) Generators invested to lower startup cost, lower minimum load operating capability, improve ramp rates, and reduce forced and scheduled maintenance outages; generators also invested to improve their ability to sell into ancillary markets such as the regulation, black start and capacity markets; (b) generators were shut down or mothballed in areas of oversupply; (c) generators were built aggressively in areas of undersupply to capture the higher locational marginal prices; (d) FTRs, the congestion hedging instruments in PJM's LMP marketplace, became an important component of increasingly 19 sophisticated portfolio sales contracts between suppliers and load serving entities. These interdependencies and complexities, along with the fact that generation tends to be capital intensive and subject to multiple regulators, make generation the most difficult of the industry components - generation, transmission, and distribution - to manage well. VI. CONCLUSION ---------- Q: WHAT IS YOUR OVERALL CONCLUSION REGARDING STARTUP OF MITCHELL? A: Startup would likely increase NIPSCO's capital costs, its generation fixed and variable costs, and its exposure to very large and uncertain environmental expenditures. Startup would not resolve the problems associated with NIPSCO's unique and unfavorable load profile. The timing and end-state of MISO's market initiative is unknown as is its effect on Mitchell's financial viability. Startup would fly in the face of regulatory uncertainties at the federal level that neither NIPSCO nor the State of Indiana are in a position to resolve. I conclude that for the reasons put forth in the foregoing testimony the startup of Mitchell would be a very costly and risky investment that does not entail commensurate benefits. 20 Q: DOES THAT CONCLUDE YOUR PREPARED DIRECT TESTIMONY? A: Yes, it does. 21 EX-99 3 xex99_2.txt 99.2 PREPARED DIRECT TESTIMONY OF MARK T. MASSEL EXHIBIT 99.2 ------------ RESPONDENT'S EXHIBIT MTM-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 MARK T. MAASSEL 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 MARK T. MAASSEL -------------------------------------------- Q: Please state your name and business address. A: My name is Mark T. Maassel and my business address is 801 E. 86th Avenue, Merrillville, Indiana 46410. Q: What is your current position with Northern Indiana Public Service Company ("NIPSCO")? A: I am the President of NIPSCO. In this role, I am responsible for maintaining strong relationships in NIPSCO's marketplace, particularly in the regulatory, legislative, and public affairs areas. Q: What is your educational background? A: I earned a bachelor's degree in civil engineering from the University of Minnesota, and a juris doctorate degree with high honors from the Chicago-Kent College of Law at the Illinois Institute of Technology. Q: Please describe your employment history. A: I have served in various leadership roles with NIPSCO and its parent company, NiSource Inc. ("NiSource"), including vice president, Regulatory and Governmental Policy for NiSource; vice president, Marketing and Sales for NiSource; vice president of Electric Service and Sales for NIPSCO; director of the Central Region for NIPSCO; and manager of Environmental Programs at NIPSCO. In these roles, I have been involved in virtually all aspects of NIPSCO's business. Q: You previously testified before this or any other regulatory commissions? A: Yes, I have previously testified before the Indiana Utility Regulatory Commission, the Kentucky Public Service Commission, the Pennsylvania Public Utilities Commission, the Massachusetts Department of Telecommunications and Energy, the Maine Public Utilities Commission, and the New Hampshire Public Utilities Commission. Q: What is the purpose of your Direct Testimony in this proceeding? 1 A: The purpose of my Direct Testimony is to provide the Commission with a brief overview of NIPSCO's response to the City of Gary's filing, including: (i) issues related to the uncertainty concerning the evolving electric marketplace, (ii) implications to NIPSCO and its customers that are related to the Midwest Independent Transmission System Operator, Inc. ("MISO"), including its recently proposed energy markets tariff - the Midwest Market Initiative ("MMI"), (iii) the operating capabilities of the temporarily shutdown Dean H. Mitchell Generating Station ("Mitchell") in relation to NIPSCO's customers' needs and load characteristics in particular, (iv) and NIPSCO's assessment of whether starting up Mitchell is the most reasonable decision in consideration of NIPSCO's customers, investors, and the regional economy. Finally, I will introduce the other witnesses who will be providing detailed Direct Testimony on various aspects of NIPSCO's response. Q: Please describe the City of Gary's Petition. A: The City of Gary ("City"), in its Petition filed May 7, 2004, has stated its intention to acquire certain NIPSCO property, namely, NIPSCO's Dean H. Mitchell Generating Station ("Mitchell"), located within the City's boundaries. The City's stated purpose for the acquisition of Mitchell is for expansion of the Gary airport, as well as for commercial, residential and recreational development. The City's Petition goes on to ask the Commission to value the site for the City's acquisition, and establish the terms and conditions upon which the City may exercise its claimed right to acquire the Mitchell property. Mayor King's Direct Testimony further elaborates on these issues, and the City's position regarding its intended acquisition of the Mitchell site. Q: Please briefly describe Mitchell, and how it fits into NIPSCO's electric supply portfolio. A: NIPSCO has 4 major generating stations and 2 hydroelectric facilities, with a total net demonstrated capability of 3,392 MWs, as described below. Coal Gas Water Station Capacity (MW) Capacity (MW) Capacity (MW) ------- ------------- ------------- ------------- Michigan City 469 120 0 Mitchell 485 17 0 Bailly 480 31 0 R.M. Schahfer 1625 155 0 Norway/Oakdale 0 0 10 As later described in more detail by Mr. Jerome B. Weeden in his Direct Testimony, Mitchell has several of the oldest generating 2 units in NIPSCO's fleet. Mitchell is primarily a coal-fired station, with a net demonstrated capability of 502 MWs, as set forth below: Year In Net Primary Unit No. Service Capacity Fuel -------- ------- -------- ------- 4 1956 125 MW Nat. Gas/Coal 5 1959 125 MW Coal 6 1959 125 MW Coal 9A 1968 17 MW Nat. Gas 11 1970 110 MW Coal Mitchell is located along the shore of Lake Michigan, just north of the Gary airport, and was originally built beginning in the 1950's. Mitchell was designed and built during a completely different era, reflecting power needs that were vastly different than what NIPSCO experiences today and will likely experience tomorrow. Mitchell was built to serve as a base load plant (a plant intended to operate steadily at constant output for longer periods of time, except for scheduled outages). Mitchell has extremely limited ramp capability - that is, its ability to rapidly increase or decrease the amount of generation measured in megawatts per minute. For this reason, Mitchell is a less attractive generating resource in both the short and long term for purposes of serving NIPSCO's current electric retail customers. This lack of ramping capability is primarily due to the fact that the plant is old and its technology is outdated. Mr. Frank A. Venhuizen describes the impacts related to this limiting characteristic in more detail in his Direct Testimony. Mitchell was temporarily shutdown in January 2002, due to the declining economy in general, weakening industrial demand for electricity on NIPSCO's system (including during the off-peak periods) and environmental concerns. Q: What has been NIPSCO's position with respect to starting up Mitchell? A: NIPSCO has been continually reviewing its options for starting up Mitchell, including consideration of whether operating and economic conditions warrant a startup. Q: Please briefly describe today's energy marketplace in the region in which NIPSCO operates, and tomorrow's expectations regarding this energy marketplace. A: As early as 1996, the Federal Energy Regulatory Commission ("FERC") began to promote the regional operation of electric transmission facilities among public utilities in an effort to 3 encourage wholesale competition. MISO has since become an official regional transmission organization by order of FERC, and has continued to evaluate its role as congestion manager and energy market operator for its footprint. Through various filings and declaratory orders at FERC, this has ultimately led to MISO's current proposal at FERC regarding a revised Open Access Transmission and Energy Markets Tariff - the Midwest Market Initiative ("MMI"), whereby MISO would implement a centralized, security constrained economic dispatch for its entire region, which would be supported by a day-ahead and real- time energy markets, and congestion management provisions based on locational marginal pricing and financial transmission rights. NIPSCO has joined MISO as a transmission owner and provider - through its membership in GridAmerica LLC; in addition, NIPSCO has registered as a market participant in MISO's proposed energy market. Q: Why is the MISO proposal important to NIPSCO? A: The MISO proposal will fundamentally affect the manner in which NIPSCO provides adequate and reliable electric service to its retail customers in many ways. MISO's energy market filing will change the manner in which NIPSCO's generation will operate in conjunction with its transmission and distribution facilities. Under MISO's proposal, loads within its entire region will be served by the resources that are the least expensive to dispatch, based upon any transmission or other constraints across the region. No longer will NIPSCO's control area dispatch its own generating resources within its own selected resource order; MISO proposes to calculate location-specific prices for practically every major substation and generating unit in its region, in an effort to reflect the most economical dispatch, taking into account transmission constraints, for all generating resources in its region. MISO also has proposed, as part of the MMI, a five- minute forecast of NIPSCO's control area that will be used in the determination of generating unit set points (five minute balancing rule). Although still being reviewed at FERC, this five minute balancing rule represents a new energy market paradigm that will change the coordination and operation of generating resources used by NIPSCO to adequately and reliably serve NIPSCO's retail electric customers. Q: How will MISO's location-specific pricing affect the use of NIPSCO's generating resources? A: MISO's location-specific pricing, i.e., "locational marginal pricing," is the calculation of the cost of the next available unit of energy for a specific location, taking into account the deliverability of energy due to transmission congestion and line losses. The purpose of this pricing initiative is to implement a 4 security constrained economic dispatch system across the entire MISO footprint in order to essentially ramp up the next lowest incremental megawatt available from a greater number of generating resources (as opposed to individual control areas), when that next megawatt is needed to serve customers across the MISO footprint. Since NIPSCO's generation is located within MISO's footprint, NIPSCO's generation will be subject to the economic dispatch calculations across the entire Midwest as opposed to NIPSCO's control area. Q: How does the five minute balancing rule affect NIPSCO? A: As a result of the five minute forecast discussed above, MISO will direct each online generator to ramp up or down to a certain output every five minutes. Failure to comply with such direction within a certain tolerance band will result in uninstructed deviations, and may ultimately yield financial consequences in the form of penalties. Q: What are uninstructed deviations? A: As explained in greater detail by Mr. Venhuizen, MISO's proposed uninstructed deviation requirements are designed to encourage compliance with MISO's dispatch schedules. MISO considers significant deviations from dispatch schedules as additional costs for the entire market that must be recovered from market participants. At this time, it is unclear what the MISO requirements and parameters regarding uninstructed deviations will look like over the long term, but due to its limited ramping capabilities, Mitchell is not likely to contribute significantly to NIPSCO's compliance efforts with any uninstructed deviation requirements. Q: Given NIPSCO's current performance against reliability standards as described by Mr. Venhuizen, what does this new paradigm mean for NIPSCO and its customers? A: Effectively, even after considering the uncertainty surrounding the longer-term implications of MISO's proposed five minute balancing rule, NIPSCO will likely need to purchase electric supplies from generators that have the capability to regulate - that is, ramp up and down quickly. Whether Mitchell is on-line and generating or not, NIPSCO will probably be required to obtain resources capable of regulation in order to comply with the North American Electric Reliability Council's ("NERC") standards and potential MISO operating parameters. I will discuss NERC's standards below. 5 Q: Given a reasonable anticipation of what MISO's balancing requirements might look like in the short term, what specific kind of energy product will NIPSCO need to satisfy MISO's five minute balancing rule? A: Intermediate dispatchable power, which is power that has the ability to cycle and ramp up or down more than typical base load facilities, without damaging or decreasing the useful life of the generating unit. In order to be assured that the electricity will be there when needed on very short notice, and that the price is not prohibitive, a term power purchase agreement with the characteristics described above will probably be required. A term power purchase agreement will likely require NIPSCO to pay demand, i.e., capacity reservation, charges. NIPSCO recently conducted a Request for Proposal ("RFP") for electricity, and of the responses received, seventeen offered to provide dispatchable power, and all seventeen required some sort of demand charge. Additionally, logic further suggests that capacity reservation and associated fees will be necessary, since in today's market, no rational generator would agree to build or maintain capacity and hold it in reserve on a purely speculative basis. Q: So far, your Direct Testimony has discussed MISO's operating requirements. Can you further discuss the NERC operating requirements? A: NERC has established operating requirements concerning the performance of control areas. As Mr. Venhuizen discusses more fully, the relevant operating standards are Control Performance Standards 1 and 2. Q: Is complying with MISO and NERC requirements optional? A: NIPSCO will not knowingly violate MISO's approved tariffs or NERC's standards. While taking every step necessary to reliably serve its customers, NIPSCO cannot pick and choose which requirements it will comply with. If NERC and FERC (through the approval of MISO's energy markets tariff) require utilities to improve regulation on their systems, then NIPSCO will take the steps necessary to comply. In his Direct Testimony, Mr. Venhuizen explains that NIPSCO essentially considers current NERC's standards mandatory, and Mr. Pierre R. H. Landrieu describes some of the implications of violating these standards in his Direct Testimony. Q: Under what conditions does NIPSCO utilize purchased power to serve its interruptible customers? 6 A: In circumstances when NIPSCO's generating capability is unavailable (e.g., forced outages), NIPSCO currently purchases power on the spot market in order to serve its interruptible customers, primarily consisting of large industrial customers served under Rate Schedule 845 and Rider 846. Those customers have insisted that NIPSCO not purchase power under forward contracts in order to serve them; thus, all of the power purchased to serve this segment of NIPSCO's customer base is purchased on the spot market. Q: Does NIPSCO purchase power to serve its firm customers? A: As further explained by Mr. Venhuizen, as part of its short-term planning process for serving firm customers, NIPSCO performs an evaluation to determine whether market prices are less expensive than NIPSCO's own internal generating resources. If market prices are below NIPSCO's internal generating resources' cost, then economy purchases are made to offset these more expensive resources. If the load exceeds available resources, a determination is made to purchase forward or spot market power. Additionally, in order to serve NIPSCO's firm electric customers during those limited peak hours for 2005, 2006 and 2007 as described by Mr. Venhuizen, NIPSCO would evaluate those needs as part of its intermediate planning process, and secure any short term purchased power resources as needed. Q: What will the impact be on NIPSCO's customers if the Commission grants the City's Petition and Mitchell is permanently closed? A: Residential, commercial and small industrial customers should see only minimal price impacts directly attributable to Mitchell not being started up. In light of all of the uncertainties surrounding today's energy marketplace, it is possible that NIPSCO's industrial customers served under Rate Schedule 845 and Rider 846 will see some increases in costs associated with their load. However, those increases will not be significantly related to Mitchell not being utilized. NIPSCO's current assumption is that NIPSCO will likely need to purchase adequate levels of intermediate dispatchable power with capabilities to meet NERC reliability requirements, as well as MISO's five minute balancing rule, because NIPSCO's existing fleet is not capable of meeting these requirements. This intermediate dispatchable power may be more costly than the current cost of forward purchased power, or power generated from the Mitchell station. Mr. Venhuizen provides more specific information on NIPSCO's need for alternative capacity. Of course, NIPSCO will continue to make every reasonable effort to seek the least cost purchased power possible, consistent with maintaining system reliability and consistent with NERC and MISO requirements. 7 Q: Does Mitchell's availability impact NIPSCO's reliability? A: No. As described in more detail by Mr. Venhuizen, NIPSCO does not need the base load generating capacity that Mitchell represents in order to reliably serve its firm electric retail customers' needs. Further, Mitchell's availability would not improve NIPSCO's compliance with NERC requirements, based upon the volatile load characteristics of certain of NIPSCO's industrial customers' applications and processes. Q: Could NIPSCO build new generating facilities with ramping capability sufficient to handle the interruptible load of its large industrial customers' applications and processes? A: In his Direct Testimony, Mr. Weeden states that this could be accomplished in four to eight years. Mr. Venhuizen argues that market forces may make such construction unnecessary. From my perspective, I do not believe new construction should be considered at the moment, because the primary purpose of that construction would be to serve the needs of NIPSCO's large industrial customers. A certain portion of NIPSCO's large industrial customers' load is interruptible, and under the terms of NIPSCO's interruptible tariffs, those customers generally have favorable pricing terms consistent with taking service under an interruptible rate schedule. That is, in return for paying reduced demand costs, interruptible customers have assumed more risk of interruption and are encouraged to avoid operating during the peak hours of the day. Thus, when considering that interruptible customers are paying reduced demand costs in return for accepting greater risk of interruption, it is fairly easy to conclude that the burden of building such a new facility would fall on either firm customers, who may not need it, or shareholders, who should not have to pay for new infrastructure without having an opportunity to earn a fair return on the investment. Q: Does NIPSCO need Mitchell? A: After considering the uncertainties of the current energy marketplace, along with its expected changes, Mitchell is not necessary to serve NIPSCO's firm electric customers with reliable power. Additionally, Mitchell does not fully satisfy the needs of NIPSCO's large industrial customers, who will likely be subject to different costs associated with new operating requirements, as described by Mr. Venhuizen. Q: Does this analysis differ from that in NIPSCO's latest Integrated Resource Plan ("IRP") filed on November 1, 2003? 8 A: Yes. Q: Please explain why. A: As discussed previously, since the temporary shutdown of Mitchell from service, NIPSCO has continually monitored Mitchell's efficacy under certain factors - e.g., economy, reliability, and environmental costs. Although NIPSCO has been a member of MISO, through its memberships in GridAmerica LLC (as approved by this Commission on September 24, 2003), sorting through the many complexities involved with the development of the evolving RTO- supported and - controlled marketplace is difficult. NIPSCO has continued to evaluate and assess Mitchell's role in NIPSCO's electric supply portfolio, and the value it may bring to serving our electric customers. Based upon new factors since the most recent IRP filed on November 1, 2003, NIPSCO now believes that it will likely require intermediate dispatchable power in order to adequately and reliably serve its electric customers. Q: Please explain these new factors and what impact they have had on any steps NIPSCO has taken towards utilizing Mitchell. A: As described in greater detail by Mr. Weeden, NIPSCO prepared for starting up Mitchell, including the development of cost estimates of activities associated with a start up, and a timeline for the start up. NIPSCO originally anticipated beginning the process of starting up Mitchell in late 2003; however, the City informed NIPSCO of its desire to acquire the Mitchell site in late 2003, which caused NIPSCO to reevaluate the risks of starting up Mitchell. At the same time, MISO's energy marketplace dynamics continued to evolve, including NIPSCO's understanding of its impacts. In light of the uncertainties of the evolving marketplace and the City's intended acquisition, NIPSCO has suspended its plans to start up Mitchell. Q: Please estimate the costs associated with a startup of Mitchell. A: The operation and maintenance expenses associated with the startup of Mitchell are estimated to be in the vicinity of $1.6 million. The capital costs associated with the start up of Mitchell are estimated to be in the vicinity of $3.9 million. These costs are discussed in further detail by Mr. Weeden. Q: Are there any other costs to consider? A: Yes. As described by Mr. Arthur E. Smith Jr., in his Direct Testimony, NIPSCO anticipates that there will be significant costs related to environmental permitting and compliance issues 9 associated with operating the Mitchell plant. As described by Mr. Smith, NIPSCO expects to begin incurring these costs in the next few years. As these costs are incurred, Mitchell's operation becomes more costly. Q: Given all of the issues you have identified thus far, including the uncertain energy marketplace that exists today and that NIPSCO anticipates will exist in the future, as well as economic and operational requirements you have noted, what is NIPSCO's position on selling Mitchell to the City of Gary? A: Although NIPSCO does not have a crystal ball, it is clear that the energy marketplace is evolving in ways that are not conducive to operating Mitchell. Adding to this consideration are the costs associated with starting up Mitchell, the costs associated with maintaining an old generating station, and the costs associated with environmental permitting that will be incurred prospectively. At this time, NIPSCO does not believe that starting up Mitchell makes sense for customers or shareholders from either an operating or economic viewpoint. As indicated earlier, the generating station operating environment and energy marketplace are much different now than they were even at the time of Mitchell's temporary shutdown. Faced with these moving and various factors, NIPSCO must endeavor to balance all of them in an effort to achieve its main priority as a public utility - providing safe, reliable service now and in the future. Mitchell does not serve a clear purpose that would cause NIPSCO to reject the City of Gary's attempt to purchase the plant. Simply stated, starting up and continuing to invest in Mitchell at this time does not make sense given all of the points discussed above, and discussed in further detail by other witnesses in this proceeding. Starting Mitchell will not enhance NIPSCO's ability to meet current or anticipated MISO and NERC requirements. Mitchell does not provide the type of responsive generating resources that NIPSCO needs today and into tomorrow - that is, intermediate dispatchable power. Starting and operating Mitchell will not change the fact that NIPSCO will likely be compelled to acquire intermediate dispatchable power resources in order to meet MISO and NERC requirements, and allow NIPSCO to continue to serve NIPSCO's unique industrial load profile. Additionally, there are greater policy issues involved that this proceeding has raised, issues that were not present before last fall. The City's intention to acquire the Mitchell site raises issues concerning the highest and best use of the land along the lakeshore, and whether those redevelopment plans constitute a greater economic benefit for the region - perhaps the entire state of Indiana - than the start up of Mitchell. 10 Even before, and definitely since, the City's announcement in early 2004 of its intention to acquire the Mitchell site, NIPSCO has been engaged in reviewing its options with regard to Mitchell, and trying to determine whether utilization of Mitchell makes operating and economic sense for our customers and shareholders. At this time, it appears that Mitchell is not necessary for and does not meet our customers' needs, and operating Mitchell does not make operating or economic sense. NIPSCO will continue to ensure that its customers have reliable and sustainable power supplies at competitive prices. NIPSCO will work with its customers in an attempt to find solutions for them, in an effort to serve them economically and efficiently, while protecting the interests of NIPSCO's firm customer base. In summary, one of NIPSCO's top criteria in reviewing its future supply needs is the impact on the safety, reliability and cost of electric service to our customers. As a public utility, NIPSCO must always endeavor to assure its customers that the electricity will be there when the customer flips on the switch, including residential, commercial and industrial customers. From lighting a home to supplying manufacturing with the necessary energy it needs to fuel our economy, NIPSCO takes very seriously its public charter and the provision of reliable electric service. The ability to supply our customers with reliable power is critical, and NIPSCO believes that Mitchell is not necessary for such provision of electric service. Q: Please introduce NIPSCO's witnesses and generally describe their Prepared Direct Testimony. A: In addition to my testimony, the following witnesses are offering Prepared Direct Testimony in support of NIPSCO in this proceeding: * Pierre R. H. Landrieu, Managing Consultant at PLP3, is providing Prepared Direct Testimony supporting his analysis and recommendations concerning the viability of Mitchell in light of MISO and NERC requirements, and the impending MISO energy market. Mr. Landrieu draws on his knowledge and experience regarding the PJM marketplace, which is operational today and has been for some time. * Jerome Weeden, Vice President, Generation for NIPSCO, is offering Prepared Direct Testimony concerning NIPSCO's generating resources, Mitchell and its operating characteristics in particular, and the steps and costs associated with a potential start up of Mitchell. * Arthur E. Smith, Jr., Senior Vice President and Environmental Counsel, NiSource, is providing Prepared Direct Testimony regarding the environmental requirements 11 and related costs associated with (i) a start up and (ii) the operation of Mitchell. * Frank A. Venhuizen, Director of Electric Transmission and Market Services for NIPSCO, is providing Prepared Direct Testimony regarding the evolving energy marketplace, MISO and NERC requirements, and NIPSCO's efforts to obtain electricity to support its customers' load requirements. Q: Does this complete your Prepared Direct Testimony? A: Yes, it does. 12 EX-99 4 xex99_3.txt 99.3 PREPARED DIRECT TESTIMONY OF ARTHUR E. SMITH, JR. EXHIBIT 99.3 ------------ RESPONDENT'S EXHIBIT AES-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 ARTHUR E. SMITH, JR. 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 ARTHUR E. SMITH, JR. ------------------------------------------------- Q. Please state your name, job title, and business address. A: My name is Arthur E. Smith, Jr. My title is Senior Vice President and Environmental Counsel, NiSource Inc. My business address is 801 East 86th Avenue, Merrillville, Indiana 46410. Q. Please provide a summary of your educational and professional background. A: I received a Bachelor of Arts in biology from Columbia College in New York. I also received from Columbia University a Master of Arts and a Master of Science in the environmental sciences. I received a J.D. degree from Seattle University School of Law. For fifteen years I served with the United States Environmental Protection Agency in Chicago, Illinois, primarily as a civil litigation specialist. During part of this period I was also an Assistant United States Attorney for the Northern District of Illinois. Thereafter, in 1991, I joined NIPSCO Industries, Inc., the predecessor of NiSource Inc. Q. What are your responsibilities as Senior Vice President and Environmental Counsel? A: I have direct responsibility for all corporate environmental and health and safety programs, including managing professional technical personnel and coordinating legal environmental services. In my capacity as Senior Vice President and Environmental Counsel, I provide environmental policy, strategy and legal advice to senior management and the NiSource Board of 1 Directors regarding the environmental matters for all of the NiSource companies, including Northern Indiana Public Service Company ( NIPSCO ). Q. For what purpose are you submitting Direct Testimony in this proceeding? A: I am submitting Direct Testimony regarding the environmental requirements and related costs associated with (i) a startup and (ii) the operation of the Dean H. Mitchell Generating Station ("Mitchell"). Q. Please review the current air emission regulations, with which Mitchell must comply. A: All NIPSCO generating stations have air emission requirements for particulates, sulfur dioxide ("SO2") and nitrogen oxides ("NOx"). These limitations can be specific for each unit within a station, or collectively for all units within the NIPSCO system. Generally the new SO2 and NOx requirements are for the NIPSCO system, including Mitchell. The 1990 Clean Air Act Amendments ("CAAA") required NIPSCO to reduce its SO2 emissions within a cap and trade program that allows NIPSCO to use various options to reduce SO2 emissions from its system, e.g., install pollution control devices, use low sulfur coal, and/ or buy allowances to meet a system limit. NIPSCO has used low sulfur coal to limit the SO2 emissions from Mitchell. NIPSCO is also subject to another cap and trade program, the Indiana NOx State Implementation Plan ("SIP") call rule that became effective on May 31, 2004. Since Mitchell will 2 not operate during the ozone season in 2004, NIPSCO will be able to bank all of the allowances allocated for 2004. Based upon the typical ozone season, the four Mitchell coal-fired units project to emit about 1,500 to 1,600 tons of NOx. Since the state allocation of NOx allowances to Mitchell station is about 841 tons, there is a shortfall of about 700 to 800 tons to be within the range of compliance. Were NIPSCO to re-start the Mitchell units for a full operation in 2005, the first year s allowance shortfall could be covered almost exactly by the allowances banked by Mitchell during the 2004 ozone season. Therefore, it is assumed that the cost of acquiring allowances will not be experienced until 2006. In order to operate in compliance with the rules, NOx allowances would be transferred from the NIPSCO NOx bank. NIPSCO planned to comply with the NOx SIP call at Mitchell by using the existing low NOx burners and by relying on the acquisition or transfer of allowances from within the NIPSCO system, but outside the Mitchell units. The cost for the Mitchell units compliance with the NOx SIP call program through the utilization of emission allowances is estimated to be about $2.4 million per year beginning in 2006 (based upon a price of an allowance of approximately $3,000 per ton of NOx). If Mitchell were to return to operation for a significant length of time, NIPSCO could consider another strategy- the addition of advanced combustion controls - i.e., Clean Coal Technology. The installation of intermediate level of pollution control is expected to be more cost effective than the installation of 3 selective catalytic reduction control technology. The rework of the current burner systems with addition of separated over-fire air could achieve between 30% to 40% reduction if Mitchell utilized Powder River Basin coal. The engineering and installation of the separated over-fire air on all four units at Mitchell is estimated to require a capital investment of about $9 million. The rework of the current burner system may ultimately require additional work or even replacement of the existing burners. Should this additional work be necessary, the capital expense could increase from the projected estimate. The remaining NOx allowances needed for compliance are estimated to cost about $400,000 per year. Q. If Mitchell were to return to full operating capacity, would that have an effect on NIPSCO s ability to operate any of its other coal-fired units? A: Yes. Since some of the air emission requirements are applied on a system basis, NIPSCO would need to consider the most cost effective compliance strategy. This would be most significant with the NOx requirements, because of the allowance shortfall described above. Q. Please describe any proposed environmental legislation being considered by Congress. A: Congress has before it several bills that would require substantial air emission reductions of SO2, NOx, CO2 and mercury. The most well known and most often referred to legislative proposal is the Clear Skies Act of 2003 ("Clear Skies") 4 introduced to Congress in February of 2003, at the request of the President in both the House and Senate. As proposed, Clear Skies would require a 70% reduction in NOx, a 66% reduction in SO2, and a 70% reduction in mercury. Like other bills, this is characterized as a multi-pollutant statute. For purposes of my testimony in this proceeding, I have based my estimates on the Clear Skies proposal. This legislative package has been put on hold, but the United States Environmental Protection Agency (EPA) has proposed similar reduction requirements and concepts in the Clean Air Interstate Rule and the Mercury Control Regulatory programs that were published in the Federal Register early in 2004. Q. Please describe the projected future environmental compliance costs associated with operating Mitchell. A: The projected compliance costs will be affected by the structure of future emission standards and whether an allowance trading program is included in the regulations. For purposes of this proceeding, NIPSCO is assuming that the future air regulatory reduction program requirements are generally structured with the flexibility allowed by cap and trade programs. These programs allocate a significantly reduced emissions budget to the individual units at each facility and the facility can decide the most cost effective means to meet the reduction requirements of the emissions budget. If the facility will emit more than the emission allocation from the environmental agency, the facility owners can decide if it is more cost effective to install 5 additional controls, acquire allowances and/or reduce production. The facility owner can choose to acquire additional allowances by over complying at other owned facilities to meet the emissions "cap" or by making market purchases for such allowances. The trading programs allow for the installation of controls at the most cost effective locations, while not requiring controls on every facility; thereby achieving the significant emission reductions with an overall cost saving that achieves the environmental goal. Q. Please describe the costs to operate the Mitchell units subsequent to implementation of the proposed Multi-pollutant rules concerning NOx emissions. A: During the first phase (beginning in approximately the 2008-2010 time period) of the proposed multi-pollutant control program, to meet the emission reduction requirements at Mitchell, the cost for the purchase of NOx allowances is estimated at $2.6 to $3.7 million per year. If the NOx combustion controls mentioned above were installed to help comply with the NOx SIP rules, then the cost for the purchase of allowances to supplement the controls would be about $400,000 to $600,000 per year. Q. Please describe the costs to operate the Mitchell units subsequent to implementation of the proposed Multi-pollutant rules concerning SO2 emissions. A: The capital cost for the installation of flue gas desulfurization ("FGD") for SO2 control at Mitchell is estimated to fall in the range of $100 to $150 million. Based upon analysis of the 6 proposed rules, the large capital cost combined with significantly increased operating expenses for the FGD would, in a market-based emission reduction system, not be considered cost effective. Due to the small size of the units and the low emissions, the cost of SO2 removal is expected to greatly exceed the market price of SO2 allowances. During the first phase of the assumed future multi-pollutant control program projected to begin in 2010, and assuming that banked Mitchell Acid Rain SO2 allowances are not used, Mitchell would need to purchase/transfer the SO2 allowances at an estimated cost between $4.3 and $5.9 million per year. Q. Please describe the legislative and regulatory programs that impact the operation of the Mitchell units with the intent of reducing mercury ("Hg") emissions. A: Clear Skies legislation would require a reduction in mercury emissions of approximately 69% and includes a cap and trade program designed to reduce mercury emissions. EPA has proposed rules and is currently considering two alternate pathways for reduction of Hg emissions from the electric generating sector. The first program is the mercury maximum achievable control technology ("MACT") standard, which was determined to apply through a regulatory determination based upon the Utility Hazardous Air Pollutant Study and the Mercury Report to Congress. The MACT regulatory approach is a command and control scheme implemented on a source specific basis. The alternative proposed in the regulatory arena also includes a cap and trade program. 7 Depending upon the pathway chosen for the control program, the Hg reduction requirements could have a major impact on the need to add controls at Mitchell. Q. Please describe the mercury MACT control requirements. A: The MACT pathway will require the installation of controls at Mitchell to meet the station specific emission reduction requirements, with only station-wide averaging allowed to provide flexibility. The mercury MACT requirements found in the proposed rule in early 2004 are projected to require that controls be installed within three years of the effective date of the rule. In order to meet the required reductions of mercury, sorbent (activated carbon) injection upstream of a compact hybrid particulate collector ("COHPAC") located downstream of the existing electrostatic precipitator is assumed. The COHPAC is a high airflow pulse jet fabric filter (baghouse) that acts as a polishing particulate control device. The capital cost for installing this system on all four of the Mitchell coal-fired units is estimated to be between $41 and $52 million with an increase in operation and maintenance expense of $2.5 to $3.5 million per year. Depending upon the final form of the MACT control requirements after completion of the rule in March of 2005 and any subsequent litigation, Mitchell would need to install from one to four COHPAC units to comply. Q. Please describe the Cap and Trade Mercury (Hg) control requirements. 8 A: A cap and trade program would allow Mitchell to purchase allowances from the external market or transfer allowances internally among the NIPSCO generating fleet for meeting emission reduction requirements. Under a cap and trade program, beginning in 2010 Mitchell would likely purchase/transfer allowances at an estimated cost of about $3.5 million per year. Depending upon the final form of the control requirements, Mitchell would need to install at least one of the four units described above to comply. Q. Do other bills include greenhouse gas/carbon dioxide ("CO2") control requirements. A: Yes. Although Clear Skies does not require reductions of CO2, the program implementation timing and cost estimate assumes that a moderate program to address CO2 emissions is enacted. The program provisions are based upon Senator Carper s Clean Air Planning Act of 2003. The proposed program calls for a reduction of CO2 emissions back to projected 2006 levels by 2009 and to 2001 levels by 2013. The Clean Air Planning Act would allocate allowances to individual units based upon the ratio of a unit s average annual net generation (in MWhrs) during the most recent three year period for which data was available (1999-2001) to the total average net generation of all affected units. For this estimate, the most recent three-year period was considered to be 1999 to 2001 and it is assumed that the 2006 levels could be met in 2009. Cost impacts for the reductions are estimated beginning in 2013 at a CO2 allowance price of $5 to $10 9 per ton of CO2. Based upon the allowance price, the purchase of CO2 allowances for compliance would cost between $5 million and $10 million per year and may be on the low end of the actual expense. Q. Please describe any potential water effluent control requirements. A: The National Pollutant Discharge Elimination System ("NPDES") permit for Mitchell will be reissued by the end of 2004 or sometime thereafter. The permit renewal will incorporate the added requirements found in the Great Lakes Water Quality Initiative ("GLI"), promulgated by IDEM since the last permit was issued. The new permit will contain additional metal discharge permit limits, including mercury, and requirements for toxicity testing from the new water quality standards. Q. How will Mitchell meet the expected mercury limits? A: It is widely understood that dischargers into Lake Michigan will not be able to meet the new mercury limits required by the GLI, even with the most advanced water pollution controls. NIPSCO will likely submit a mercury variance application to the Indiana Department of Environmental Management ("IDEM"). The GLI mercury water quality standard of 1.3 ng/L will be included in the renewed Mitchell NPDES permit. Background mercury testing of Lake Michigan has yielded test results of 1.5 to 2.0 ng/L. No available treatment methods exist to meet the GLI criteria. As a result, NIPSCO anticipates submitting a mercury variance application to IDEM requesting relief from the 10 mercury standard for Mitchell and other affected stations. This application must be submitted to IDEM within ninety (90) days of the NPDES permit issuance date. The estimated cost of the application preparation is $150,000. IDEM has indicated the Mitchell permit will be renewed during the second half of 2004. The mercury variance application will then need to be completed within 90 days. Based upon the above, we assume that IDEM will grant an exemption from permit limits for the non-contact cooling water discharge Outfall 001 at Mitchell and apply permit limits only to the station's ash pond discharge. Q. Please describe the treatment options for the ash pond discharge. A: IDEM will likely include limits for certain metals in the permit for this discharge. The two options to deal with these limits are deep well injection of the discharge or the installation and operation of a wastewater treatment plant. The estimated installation cost of the deep wells for Mitchell is $10 to $15 million. The annual operation cost of these wells will be approximately $0.5 million. If the EPA denies the deep well injection permits, the alternate option is the installation of a wastewater treatment plant to treat the metals in the ash pond discharge. The capital costs of the treatment plant is estimated to be about $135 million, with an annual operation cost estimate of $1 to $2 million. The NPDES permit will contain a compliance schedule of three (3) years to meet limits on the ash pond discharge. 11 Q. Are there any new water obligations under the Clean Water Act? A: Yes, EPA has proposed new requirements under Section 316 (a) and (b). The two available options to meet the expected 316(b) rule requirements are the biological studies/restoration measures or the installation of cooling towers. The final rule containing these options is scheduled to be published in the Federal Register during July 2004. The reissued NPDES permit will contain a reference to the rule. NIPSCO will then have to request that IDEM grant a three and one half year compliance schedule to meet the requirements of the rule. If the permit is reissued in the latter part of 2004, the alternate option/biological studies or the installation of the cooling towers will have to be completed in late 2008. Q. Please provide further detail concerning the biological studies and restoration measures identified above. A: The first 316(b) option would consist of a mixture of habitat restoration, fish restocking and station operational changes/modifications. This option would require the completion of the following: (1) Biological baseline studies of the station's intake to determine its effect on the aquatic community of the lake; (2) Develop compliance plan for facility to meet the 316(b) requirements. This plan must utilize the alternate options listed above and reduce the effects on the aquatic community of the lake commensurate to the installation of a cooling tower; 12 (3) Follow-up biological studies to determine effectiveness of facility compliance plan. The annual cost of these studies and compliance plan development are estimated to range from $100,000 to $350,000. Assuming the studies indicate the 316(b) rule requirements can be met with a restoration strategy, it is possible NIPSCO would be allowed to use a combination of facility modifications, restoration measures, fish restocking, and operational changes. The cost of these measures is difficult to estimate. Q. Please provide further detail concerning the installation of cooling towers identified above. A: The more traditional approach to meet the 316(b) requirements at Mitchell would be the installation of a cooling tower. Capital costs of the cooling tower for the station is estimated to be $50 to $100 million. This estimated cost is for a standard installation. Since the site conditions indicate a potentially difficult retrofit, the costs of the installation at Mitchell will likely be more than a standard installation. Again, if the permit is reissued by the latter part of 2004, the installation of the cooling tower will have to be completed in late 2008. The commitment to install the cooling tower will eliminate the need to conduct biological studies on the Mitchell intake. Q. Have you prepared an exhibit that represents the projected costs? A: Yes. I have attached Respondent's Exhibit AES-2 that was prepared by me or under my direction and supervision. 13 Q. If the Mitchell plant were shut down and decommissioned would there be environmental remediation costs? A: Yes. There would be costs associated with removing asbestos material, demolishing the plant, removing PCB containing equipment and soil and groundwater remediation. Depending on whether the existing fly ash is disposed offsite, and whether the above and below structures are disposed of in an off-site landfill, the cost would be approximately between $38 million and $53 million. Q. Please summarize your testimony. A: NIPSCO is continuing to assess its planning to achieve compliance with current and future environmental requirements. With the trend toward environmental control requirements based on a utility's system performance, the prompt resolution on the startup of Mitchell would help NIPSCO's environmental compliance strategy planning. Q. Does this conclude your Prepared Direct Testimony? A: Yes it does. 14 RESPONDENT'S EXHIBIT AES-2 CAUSE NO. 42643 FUTURE COST SUMMARY O & M CAPITAL TIME- COST COST FRAME ----------- ----------- ----------- Air Pollution Control Req Alternatives $2.5 - $3.3M 2006 - 2010 NOx controls - use trading program for compliance. NOx controls - add $0.4 - $0.6M $9M 2006- control technology to support compliance. NOx Multi-pollutant $2.6 - $3.7M 2010- controls Sulfur dioxide SO2 $5.9 - $7.4M 2010- Multi-pollutant Controls CO2 Allowances $5 - $10M 2012- Water Pollution Control Requirements $.5 - $1.0M $50 - $100M 2006-2009 Cooling Tower (or Natural Resource Mitigation) GLI Treatment Options $.5 - $2.0M $10 - $135M 2007-2010 Waste Ash Pond Lining $.9 - $1.2M 2004 - 2006 Other Coal pile Lining $.7 - $1.0M 2004 - 2006 Mercury MACT $2.5 - $3.5M $41 - $52M 2008- Bio Studies $100,000 - 2004-2009 $350,000 Mercury Variance $150,000 2004 15 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.
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 -------- ---- ----- -------- -------- --- ---- ---- ---- ---- ------- --------- --------- ---------- 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.
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 ---- ---- ------ ---- ---- ------ 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
Northern Indiana Public Service Company Cause No. 42643 Respondent's Exhibit FAV-6 MAIN ---- PROJECTED ----------------------------------------------------------- 2004 2005 2006 2007 2008 2009 2010 ---- ---- ---- ---- ---- ---- ---- 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
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 -----END PRIVACY-ENHANCED MESSAGE-----