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