### TDD (for hearing and speech impaired only): (651) 282-5332 Printed on recycled paper contai ning at least 10% fibers from paper recycled by consumers 

### AIR EMISSION PERMIT NO. 16300005-007

IS ISSUED TO

Northern States Power Co dba Xcel Energy

XCEL ENERGY – ALLEN S KING GENERATING Highway 95 & Point Road Oak Park Heights, Washington County, MN 55082

The emission units, control equipment and emission stack s at the stationary source authorized in this permit are as described in the following permit application(s):

Permit Type Application Date Issue Date Action # Reissuance January 17, 2003 March 28, 2005 005 Administrative Amendment January 13, 2006 March 2, 2006 006 Major Amendment August 21, 2006 See Below 007



### This permit authorizes the Permittee to operate and modi fy the stationary source at the address listed above unless otherwise noted in Table A. The Permittee must comply with all the conditions of the permit. Any changes or modifications to the stationary source must be performed in compliance with Minn. R. 7007.1150 to 7007.1500. Terms used in the permit are as defined in the state air pollution control rules unless the term is explicitly defined in the permit. Permit Type: Federal; Pt 70/Major for NSR Major Amendment

Issue Date: 03/28/2005 Issue Date: February 27, 2007 Expiration: 02/22/2010 Title I Conditions do not expire.

Richard J. Sandberg, Manager Air Quality Permits Section Industrial Division

for Brad Moore Commissioner Minnesota Pollution Control Agency

### TABLE OF CONTENTS

Notice to the Permittee

Permit Shield

Facility Description

Table A: Limits and Other Requirements

Table B: Submittals

Appendices: Attached and Referenced in Table A

### NOTICE TO THE PERMITTEE:

Your stationary source may be subject to the requi rements of the Minnesota Pollution Control Agency’s (MPCA) solid waste, hazardous waste, and water quality programs. If you wish to obtain information on these programs, including information on obtaining any required permits, please contact the MPCA general information number at:

Metro Area (651) 296-6300

Outside Metro Area 1-800-657-3864

TTY (651) 282-5332

The rules governing these programs are contained in Minn. R. chs. 7000-7105. Written questions may be sent to: Minnesota Pollution Control Agency, 520 Lafayette Road North, St. Paul, Minnesota 55155-4194.

Questions about this air emission permit or about ai r quality requirements can also be directed to the telephone numbers and address listed above.

PERMIT SHIELD:

Subject to the limitations in Minn. R. 7007.1800, complia nce with the conditions of this permit shall be deemed compliance with the specific provision of the applicable requirement identified in the permit as the basis of each condition. Subject to the limitations of Minn. R. 7007.1800 and 7017.0100, subp. 2, notwithstanding the conditions of this permit specifyi ng compliance practices for applicable requirements, any person (including the Permittee) may also use ot her credible evidence to establish compliance or noncompliance with applicable requirements.

### FACILITY DESCRIPTION:

The Allen S. King plant is a coal-fired electric utility located on Highway 95 in Oak Park Heights, Minnesota. The facility’s emission sources consist of boilers; fuel and ash storage and hand ling equipment; and emergency diesel engines. The facility’s main power boiler (Boiler No. 1) is a coal-fired cyclone boiler with a generating capacity of 550 megawatts (MW) of electricity. Pollution control equipm ent on the main boiler as of the date of issuance of Air Emission Permit No. 16300005-005 consists of an electrosta tic precipitator to control Particulate Matter (PM) emissions. Emissions from fuel and ash storage and ha ndling equipment, which are potential sources of PM emissions, are controlled using water and other dust suppressants, enclosures, and/or fabric filters. Permit action 005 authorized modification of the King Plan t. The Rehabilitation Project is currently underway and includes the installation of new pollution control e quipment, modification of the plant heat rejection system, and rehabilitation and life extension of the main (EU 001, coal-fired) boiler. The rehabilitation will allow the plant to operate at a capacity approaching its original design rating.

The boiler rehabilitation consisted of:

• Replacement of the furnace floor and support system.

• Installation of new cyclone burne rs and re-entrant throats.

• Replace furnace sidewalls and furnace floor tubes.

• Installation of induced draft fans to accommodate add itional draft requirements of new control equipment. The new (additional) control equipment will consist of:

• Selective Catalytic Reduction (SCR) reactor for control of NO X 

### emissions.

• Spray dryer absorber lime-based semi-dry Flue Gas Desulfurization (FGD) system for control of SO 2 

### emissions

• Pulse-Jet cleaned Fabric Filter (PJFF) for additional control of PM. The rehabilitation project authorized by permit ac tion 005 also involved decommissioning and removal of one existing auxiliary boiler, replacing it with a new auxiliary boiler. The rehabilitation of EU 001 is expected be completed and ready for startup in March of 2007.

### MAJOR AMENDMENT DESCRIPTION (PER 007) This major permit amendment grants the Permittee the following:

1. EU 001 – Clarified that first firing is intended to re fer to the first firing with permitted fuels other than natural gas. The definition of start up and shutdown for boiler EU001 was added since it affects the ability to operate the SCR and the SDA.

2. SCR (CE 015) and SDA (CE 016) – Because of the operating temperatures associated with the ability to operate the SCR and SDA, MPCA is adding a provision to the permit that clarifies that the SCR and SDA are not required to be operated during startup and shutdown of EU 001. What constitutes startup and shutdown of EU 001 is defined in the permit. All Title I emission limits remain applicable during periods of startup, shutdown, and malfunction.

3. Operation of Fabric Filter (CE 017) – The mandatory operation of the fabric filter (CE 017) associated with boiler EU 001 in lieu of operating th e existing electrostatic precipitators (ESP) (CE 001 and CE 002), is not required until the effective date of the total particulate emission limit (270 days after the first firing of the boiler EU 001 with fuels other than natural gas following rehabilitation). The permit still requires that either the ESPs, or the fabric filter, are operated after the first firing of the boiler with fuels other than natural gas following the rehabilitation project.

4. Removal of Hours of Operation Limit for GP 008 Emission Units

5. Removal of Emission Units – Design changes since the original permit issuance have resulted in the elimination of the duct burner (EU 030) and ammonia vaporizer (EU 031) as emission units. References to these emission units were removed from the draft permit.

6. Permit Language – The language for compliance with Boiler MACT for the auxiliary boiler (EU 028) was updated to incorporate changes in the regula tion since the issuance of the initial permit.

7. Changes to Ash Silo – The permit will be updated to acknowle dge that the fly-ash silo (EU 012) now has a dedicated fabric filter (CE 026) a nd its own stack (SV 036), as opposed to venting through the main boiler stack, as it was previously permitted.

8. Mercury Monitoring and Testing – Xcel Energy will be operating a continuous emission monitor (CEM) to measure the mercury emissions from EU 001 as a requirement of the Minnesota Mercury Reduction Act of 2006. Permit conditions for the opera tion of the CEM have been added to the draft permit. Because of the installation of the mercury CEM, it is no longer necessary to perform annual stack tests on mercury emissions after the initial performance test is completed.

9. Installation of SCR Ash Bin Vent – Installation of SCR ash bin and vent (EU 039/SV 037).

10. Removal of Redundancy – Language for Performance Test Notifications and Submittals in the original permit was located in the total facility requirements section as well as GP 004, EU 004, EU 006, EU 007, EU 011, and EU 028. The draft permit contains this language only in the total facility requirements in order to remove the redundant permit conditions.

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-1

Table A contains limits and other requirements with which your facility must comply. The limits are located in the first colum n of the table (What To do). The limits can be emission limits or operational limits. This column also contains the actions that y ou must take and the records you must keep to show that you are complying with the limits. The second column of Table A (Why to do it) lists the regulatory basis for these limits. Appendices included as conditions of your permit are listed in Table A under tota l facility requirements.

Subject Item: Total Facility

What to do Why to do it
A . OPERATIONAL LIMITS hdr
The Permittee shall comply with National Primary and Secondary Ambient Air Quality Standards, 40 CFR pt. 50, and the Minnesota Ambient Air Quality Standards, Minn. R. 7009.0010 to 7009.0080. Compliance shall be demonstrated upon written request by the MPCA. 40 CFR pt. 50; Minn. Stat. Section 116.07, subds. 4a & 9; Minn. R. 7007.0100, subps. 7A, 7L & 7M; Minn. R. 7007.0800, subps. 1, 2 & 4; Minn. R. 7009.0010 - 7009.0080 Truck and hauler unloading stations: Control fugitive particulate emissions from the unloading of coal and petroleum coke from trucks or haulers by dust suppression methods so that emissions from such sources are minimized. Minn. R. 7011.1105, subp. C

Operating practices: Clean up all coal spilled on roads or access areas as soon as practicable using methods that minimize the amount of dust suspended. Maintain air pollution control equipment in proper operating condition and utilize air pollution control systems as designed. Minn. R. 7011.1105, subp. I

Fugitive Emissions: Do not cause or permit the handling, use, transporting, or storage of any material in a manner which may allow avoidable amounts of particulate matter to become airborne. Comply with all other requirements listed in Minn. R. 7011.0150. Minn. R. 7011.0150

Comply with Fugitive Emissions Control Plan: Follow the actions and recordkeeping specified in the Fugitive Emissions Control Plan. The plan may be amended by the Permittee, but must include the minimum fugitive control requirements specified within this permit. Keep records of changes made to the fugitive control plan, including the date and nature of changes made. If the Commissioner determines the Permittee is out of compliance with Minn. R. 7011.0150 or the fugitive control plan, the Permittee may be required to amend the control plan and/or to install and operate particulate matter ambient monitors as requested by the Commissioner. Minn. Stat. Section 116.07, subd. 4a; Minn. R. 7007.0100; Minn. R. 7007.0800, subp. 2; Minn. R. 7009.0020; Minn. R. 7011.0150

A ny stationary internal combustion engines at the facility, including those which qualify as insignificant activities under Minn. R. 7007.1300, must meet the performance standards set out in Minn. R. 7011.2300. Minn. R. 7011.2300

Operation and Maintenance Plan: Retain at the stationary source an operation and maintenance plan for all air pollution control equipment. At a minimum, the O&M plan shall identify all air pollution control equipment and control practices and shall include a preventative maintenance program for the equipment and practices, a description of (the minimum but not necessarily the only) corrective actions to be taken to restore the equipment and practices to proper operation to meet applicable permit conditions, a description of the employee training program for proper operation and maintenance of the control equipment and practices, and the records kept to demonstrate plan implementation. Keep records of all changes made to the O&M Plan, including the date and nature of the change. Minn. R. 7007.0800, subps. 14 & 16(J)

Operation Changes: In any shutdown, breakdown, or deviation the Permittee shall immediately take all practical steps to modify operations to reduce the emission of any regulated air pollutant. The Commissioner may require feasible and practical modifications in the operation to reduce emissions of air pollutants. No emissions units that have an unreasonable shutdown or breakdown frequency of process or control equipment shall be permitted to operate. Minn. R. 7019.1000, subp. 4

Temporary boilers or engines may be brought on site for the purpose of providing steam, heat or electrical power in place of boilers or generators that are temporarily out of operation for less than one year. The temporary units may not be operated at the same time as the permanent units that they are meant to replace, except for up to 8 hours during start-up and shutdown transition periods. Temporary units must have potential emission rates in pounds/hour for all criteria pollutants that are less than permit emission limits and the potential emission rates of the permanent units that they are replacing.

Temporary engines may be used on site that do not replace existing equipment if the use qualifies as an insignificant activity under Minn. R. 7007.1300, subp. 2(B). Minn. R. 7007.0800, subp. 2

A ir Pollution Control Equipment: Operate all pollution control equipment whenever the corresponding process equipment and emission units are operated, unless otherwise noted in Table A. Minn. R. 7007.0800, subps. 2 & 16(J)

Inspections: The Permittee shall comply with the inspection procedures and requirements as found in Minn. R. 7007.0800, subp. 9(A). Minn. R. 7007.0800, subp. 9(A)

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-2

Circumvention: Do not install or use a device or means that conceals or dilutes emissions, which would otherwise violate a federal or state air pollution control rule, without reducing the total amount of pollutant emitted. Minn. R. 7011.0020

Noise: The Permittee shall comply with the noise standards set forth in Minn. R. 7030.0010 to 7030.0080 at all times during the operation of any emission units. This is a state only requirement and is not enforceable by the EPA Administrator or citizens under the Clean Air Act. Minn. R. 7030.0010 - 7030.0080

The permittee shall comply with the General Conditions listed in Minn. R. 7007.0800, subp. 16. Minn. R. 7007.0800, subp. 16

B. MONITORING REQUIREMENTS hdr
Operation of Monitoring Equipment: Unless otherwise noted in Tables A and/or B, monitoring a process or control equipment connected to that process is not required during periods when the process is shutdown, such as for system breakdowns, repairs, calibration checks, and zero and span adjustments (as applicable). Monitoring records should reflect any such periods of process shutdown. Minn. R. 7007.0800, subp. 4(D)

Monitoring Equipment Calibration: Annually calibrate all required monitoring equipment other than continuous emission and opacity monitors (requirements applying to continuous emission monitors are listed separately in this permit). Minn. R. 7007.0800, subp. 4(D)

Continuous Operation: CEMS must be operated and data recorded during all periods of emission unit operation including periods of emission unit start-up, shutdown, or malfunction except for periods of acceptable monitor downtime. This requirement applies whether or not a numerical emission limit applies during these periods. A CEMS must not be bypassed except in emergencies where failure to bypass would endanger human health, safety, or plant equipment. Minn. R. 7017.1090

Recordkeeping: The owner or operator must retain records of all CEMS monitoring data and support information for a period of five years from the date of the monitoring sample, measurement or report. Records shall be kept at the source. Minn. R. 7017.1130

C. TESTING REQUIREMENTS hdr
Performance Test: Conduct all performance tests in accordance with Minn. R. ch. 7017, unless otherwise noted in Tables A or B. Minn. R. ch. 7017

Performance Test Notifications and Submittals:

Performance Tests are due as outlined in Tables A and B of the permit. See Table B for additional testing requirements.

Performance Test Notification (written): due 30 days before each Performance Test Performance Test Plan: due 30 days before each Performance Test Performance Test Pre-test Meeting: due 7 days before each Performance Test Performance Test Report: due 45 days after each Performance Test Performance Test Report - Microfiche Copy or CD: due 105 days after each Performance Test

The Notification, Test Plan, and Test Report may be submitted in alternative format as allowed by Minn. R. 7017.2018. Minn. R. 7017.2018; Minn. R. 7017.2030, subps. 1-4; Minn. R. 7017.2035, subps. 1-2

CEMS Certification Test Notification and Submittals:

CEMS Certification Test Plan: due 30 days before CEMS Certification Test CEMS Certification Test Pretest Meeting: due 7 days before CEMS Certification Test CEMS Certification Test Report: due 45 days after CEMS Certification Test CEMS Certification Test Report - Microfiche Copy or CD: due 105 days after CEMS Certification Test

The Notification, Test Plan, and Test Report may be submitted in alternate format as allowed by Minn. R. 7017.1120, subp. 2 Minn. R. 7017.1060, subps. 1-3; Minn. R. 7017.1080, subps. 1-4

Limits set as a result of a performance test (conducted before or after permit issuance) apply until superseded as stated in the MPCA's Notice of Compliance letter granting preliminary approval. Preliminary approval is based on formal review of a subsequent performance test on the same unit as specified by Minn. R. 7017.2025, subp. 3. The limit is final upon issuance of a permit amendment incorporating the change. Minn. R. 7017.2025, subp. 3

D. DETERMINING IF A PROJECT/MODIFICATION IS SUBJECT TO NEW SOURCE REVIEW hdr

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-3

These requirements apply where there is a reasonable possibility that a proposed project, analyzed using the actual-to-projected-actual (ATPA) test and found to not be part of a major modification, may result in a significant emissions increase. If the ATPA test is not used for a particular project, or if there is not a reasonable possibility that the proposed project could result in a significant emissions increase, then these requirements do not apply to that project.

Even though a particular modification is not subject to New Source Review, a permit amendment, recordkeeping, or notification may still be required under Minn. R. 7007.1150 - 7007.1500. Title I Condition: 40 CFR Section 52.21(r)(6); Minn. R. 7007.3000

Preconstruction Documentation -- Before beginning actual construction on a project, the Permittee shall document the following information:

1. A description of the project 2. Identification of the emission unit(s) whose emissions of an NSR pollutant could be affected 3. A description of the applicability test used to determine that the project is not a major modification for any regulated NSR pollutant, including the baseline actual emissions, the potential emissions, the projected actual emissions, the amount of emissions excluded due to increases not associated with the modification and that the unit(s) could have accommodated during the baseline period, an explanation of why the amounts were excluded, and any creditable contemporaneous increases and decreases that were considered in the determination.

The Permittee shall maintain records of this documentation. Title I Condition: 40 CFR Section 52.21(r)(6); Minn. R. 7007.3000; Minn. R. 7007.0800, subps. 4 & 5

Before beginning actual construction of any project which includes any electric utility steam generating unit (EUSGU), the Permittee shall submit a copy of the preconstruction documentation (items 1-3 under Preconstruction Documentation, above) to the Agency. Title I Condition: 40 CFR Section 52.21(r)(6); Minn. R. 7007.3000; Minn. R. 7007.0800, subps. 4 & 5

The Permittee shall monitor the actual emissions of any regulated NSR pollutant that could increase as a result of the project and that were analyzed using the A TPA test, and the potential emissions of any regulated NSR pollutant that could increase as a result of the project and that were analyzed using potential emissions. The Permittee shall calculate and maintain a record of the sum of the actual and potential (if used in the analysis) emissions of the regulated pollutant, in tons per year on a calendar year basis, for a period of 5 years following resumption of regular operations after the change, or for a period of 10 years following resumption of regular operations after the change if the project increases the design capacity of or potential to emit of any unit associated with the project. Title I Condition: 40 CFR Section 52.21(r)(6); Minn. R. 7007.3000; Minn. R. 7007.0800, subps. 4 & 5

For any project which includes any EUSGU, the Permittee must submit an annual report to the Agency, within 60 days after the end of the calendar year. The report shall contain:

a. The name and ID number of the facility, and the name and telephone number of the facility contact person b. The quantified annual emissions analyzed using the ATPA test, plus the potential emissions associated with the same project and analyzed using potential emissions c. Any other information, such as an explanation as to why the summed emissions differ from the preconstruction projection, if that is the case Title I Condition: 40 CFR Section 52.21(r)(6); Minn. R. 7007.3000; Minn. R. 7007.0800, subps. 4 & 5

For any project which does not include any EUSGU, the Permittee must submit a report to the Agency if the annual summed (actual plus potential, if applicable) emissions differ from the preconstruction projection and exceed the baseline actual emissions by a significant amount as listed at 40 CFR Section 52.21(b)(23). Such report shall be submitted to the Agency within 60 days after the end of the year in which the exceedances occur. The report shall contain:

a. The name and ID number of the facility, and the name and telephone number of the facility contact person b. The annual emissions (actual plus potential, if any part of the project was analyzed using potential emissions) for each pollutant for which the preconstruction projection and significant emissions rate is exceeded. c. Any other information, such as an explanation as to why the summed emissions differ from the preconstruction projection. Title I Condition: 40 CFR Section 52.21(r)(6); Minn. R. 7007.3000; Minn. R. 7007.0800, subps. 4 & 5

E. OTHER RECORDKEEPING, NOTIFICATIONS, AND SUBMITTALS hdr

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-4

Recordkeeping and Reporting for Temporary Boilers and Engines: Keep the following records on-site: documentation of hours of operation of the temporary units, a statement for all periods of temporary unit operation that the replaced permanent unit is not also operating, and calculations demonstrating that emissions are less than or equal to emissions from the permanent units being replaced. Notify the Commissioner if temporary and permanent units are operated simultaneously, except as allowed by this permit. Make verbal notification within 2 days, and written notification with the semi-annual deviations report. Minn. R. 7007.0800, subp. 2

Shutdown Notifications: Notify the Commissioner at least 24 hours in advance of a planned shutdown of any control equipment or process equipment if the shutdown would cause any increase in the emissions of any regulated air pollutant. If the owner or operator does not have advance knowledge of the shutdown, notification shall be made to the Commissioner as soon as possible after the shutdown. However, notification is not required in the circumstances outlined in Items A, B and C of Minn. R. 7019.1000, subp. 3.

A t the time of notification, the owner or operator shall inform the Commissioner of the cause of the shutdown and the estimated duration. The owner or operator shall notify the Commissioner when the shutdown is over. Minn. R. 7019.1000, subp 3

Breakdown Notifications: Notify the Commissioner within 24 hours of a breakdown of more than one hour duration of any control equipment or process equipment if the breakdown causes any increase in the emissions of any regulated air pollutant. The 24-hour time period starts when the breakdown was discovered or reasonably should have been discovered by the owner or operator. However, notification is not required in the circumstances outlined in Items A, B and C of Minn. R. 7019.1000, subp. 2.

A t the time of notification or as soon as possible thereafter, the owner or operator shall inform the Commissioner of the cause of the breakdown and the estimated duration. The owner or operator shall notify the Commissioner when the breakdown is over. Minn. R. 7019.1000, subp 2

Notification of Deviations Endangering Human Health or the Environment: As soon as possible after discovery, notify the Commissioner or the state duty officer, either orally or by facsimile, of any deviation from permit conditions which could endanger human health or the environment. Minn. R. 7019.1000, subp. 1

Notification of Deviations Endangering Human Health or the Environment Report: Within 2 working days of discovery, notify the Commissioner in writing of any deviation from permit conditions which could endanger human health or the environment. Include the following information in this written description: 1. The cause of the deviation; 2. The exact dates of the period of the deviation, if the deviation has been corrected; 3. Whether or not the deviation has been corrected; 4. The anticipated time by which the deviation is expected to be corrected, if not yet corrected; and 5. Steps taken or planned to reduce, eliminate, and prevent reoccurrence of the deviation. Minn. R. 7019.1000, subp. 1

Emission Inventory Report: due on or before April 1 of each calendar year following permit issuance. To be submitted on a form approved by the Commissioner. Minn. R. 7019.3000 - 7019.3100

Emission Fees: due 60 days after receipt of an MPCA bill. Minn. R. ch. 7002

Recordkeeping: Retain all records at the stationary source or at another site where the records are readily accessible for a period of five (5) years from the date of monitoring, sample, measurement, or report. Records which must be retained at this location include all calibration and maintenance records, all original strip-chart recordings for continuous monitoring instrumentation, and copies of all reports required by the permit. Records must conform to the requirements listed in Minn. R. 7007.0800, subp. 5(A). Minn. R. 7007.0800, subp. 5(C)

Recordkeeping: Maintain records describing any insignificant modifications (as required by Minn. R. 7007.1250, subp. 3) or changes contravening permit terms (as required by Minn. R. 7007.1350, subp. 2), including records of the emissions resulting from those changes. Minn. R. 7007.0800, subp. 5(B)

Extension Requests: The permittee may apply for an Administrative Amendment to extend a deadline in a permit by no more than 120 days, provided the proposed deadline extension meets the requirements of Minn. R. 7007.1400, subp. 1(H). Minn. R. 7007.1400, subp. 1(H)

A pplication for Permit Amendment: If you need a permit amendment, submit application in accordance with the requirements of Minn. R. 7007.1150 through Minn. R. 7007.1500. Submittal dates vary, depending on the type of amendment needed. Minn. R. 7007.1150 - 7007.1500

F. CRITERIA POLLUTANT MODELING hdr

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-5

Parameters Used in Modeling: The parameters used in the PM10 modeling performed for determining emission and/or operational limits are listed in Appendix C of this permit. If the Permittee intends to change any of these parameters, the Permittee must submit the revised parameters to the Commissioner and receive written approval before making any changes. The revised parameter information submittal must include, but is not limited to: the locations, heights and diameters of the stacks; locations and dimensions of nearby buildings; velocity and temperatures of the gases emitted; and the emission rates. The plume dispersion characteristics due to the parameter revisions must equal or exceed the dispersion characteristics modeled for this permit, and the Permittee shall demonstrate this in the proposal. Minn. R. 7009.0020 (This is a state only requirement and is not enforceable by the EPA Administrator and citizens under the Clean A ir Act)

Parameters Used in Modeling (continued): If the information does not demonstrate equivalent or better dispersion characteristics, or if a conclusion cannot readily be made about the dispersion, the Permittee must remodel.

For changes that do not involve an increase in PM10 emission rates, and/or that do not require a permit amendment, the proposal must be submitted as soon as practicable, but no less than 60 days before making the change to any parameter.

For changes involving increases in PM10 emission rates and that require a minor permit amendment, the proposal must be submitted as soon as practicable, but no less than 60 days before making the change to any parameter.

For changes involving increases in PM10 emission rates and that require a permit amendment other than a minor amendment, the proposal must be submitted prior to or with the permit amendment application. Minn. R. 7009.0020 (This is a state only requirement and is not enforceable by the EPA Administrator and citizens under the Clean A ir Act)

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-6

Subject Item: GP 001 Boiler Nos. 11 & 12

Associated Items: EU 007 Boiler 11

EU 008 Boiler 12

What to do Why to do it Fuel Usage: less than or equal to 770 million cubic feet/year using 12-month Rolling Sum calculated monthly. This limit applies to EU 007 and EU 008 combined. Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.3000 By the last day of each month, record the total amount and type of each fuel combusted in the units listed in GP 001 for the previous month and calculate and record the total amount and type of each fuel combusted in GP 001 for the previous 12-month period. Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.0800, subp. 5

A llowable fuel use: limited to natural gas and propane. Minn. R. 7007.0800, subp. 2

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-7

Subject Item: GP 002 Emergency Generators

Associated Items: EU 013 Emergency Engine Generator 1EEG-GEN-0002
EU 014 Emergency Engine Generator 1EEG-GEN-0003

What to do Why to do it
A . EMISSION & OPERATING LIMITS hdr
Sulfur Dioxide: less than or equal to 0.5 lbs/million Btu heat input . This limit applies individually to each unit listed in GP 002. Minn. R. 7011.2300, subp. 2

Opacity: less than or equal to 20 percent opacity . Opacity shall not exceed 20% for more than 10 seconds once operating temperatures have been achieved. This limit applies individually to each unit listed in GP 002. Minn. R. 7011.2300, subp. 1

Operating Hours: less than or equal to 816 hours/year using 12-month Rolling Sum calculated monthly, for the GP 002 generators combined. Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.3000 Fuel type is limited to distillate oil with a maximum sulfur content of 0.5% by weight. Minn. R. 7007.0800, subp. 2

B. RECORDKEEPING REQUIREMENTS hdr
By the last day of each month, record the total hours of operation of GP 002 for the previous month and calculate and record the total hours of operation of GP 002 for the previous 12-month period. Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.0800, subp. 5 Maintain records showing the sulfur content of all fuel oil combusted in the GP 002 generators. Minn. R. 7007.0800, subps. 4 & 5

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-8

Subject Item: GP 003 Coal Handling and Coal Yard Traffic - Limited Operation

Associated Items: FS 002 Petroleum Coke Storage Pile (Inactive, reactivation will require new modeling demonstration)

FS 005 Coal Stacker
FS 006 Coal Silo Unloading
FS 007 Coal Reclaim Hoppers

FS 009 Coal Pile A

FS 010 Coal Pile B
FS 012 Coal Yard Traffic (Unpaved roads & driving on coal)

FS 013 Paved Road Traffic
FS 014 Petroleum Coke Unloading Station (Inactive, reactivation will require new modeling demonstration)

What to do Why to do it This requirement applies individually to each source in this group.

Stockpiles, stockpile construction and reclaiming: 1. Control fugitive particulate emissions by dust suppression methods on such operations so that fugitive particulate emission are minimized. 2. In the alternative, use an underground bottom feed (plow) of coal to an underground conveyor system provided the exhaust gases from the enclosed spaces do not contain particulate matter in excess of 0.020 grains per dry standard cubic foot (gr/dscf). Minn. R. 7011.1105, subps. (F)(1) & (2)

Coal/Coke Handling Operating Hours: Limited to 6:00 a.m. through 8:00 p.m. Minn. R. 7009.0020
Recordkeeping: The Permittee is required to keep a log of daily Coal/Coke Handling Operating Hours. Minn. R. 7007.0800, subp. 5

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-9

Subject Item: GP 004 Flite Conveyors (NSPS Subpart Y)

Associated Items: CE 014 Fabric Filter - Low Temperature, i.e., T<180 Degrees F
EU 016 East Flite Conveyor (AFC-2A)
EU 017 East Flite Conveyor (AFC-2B)
EU 018 West Flite Conveyor (AFC-1A)
EU 019 West Flite Conveyor (AFC-1B)
SV 018 Flite Conveyor Dust Collector

What to do Why to do it
A . EMISSION LIMITS hdr
Total Particulate Matter: less than or equal to 0.02 grains/dry standard cubic foot Minn. R. 7011.1105, subp. G(1)
Opacity: less than or equal to 20 percent opacity 40 CFR Section 60.252(c); Minn. R. 7011.1150; Minn. R. 7011.1105, subp. G(2) Particulate Matter < 10 micron: less than or equal to 0.008 grains/dry standard cubic foot Minn. R. 7009.0020

B. OPERATIONAL LIMITS hdr

A ir Flow Rate: less than or equal to 16,000 actual cubic feet/minute . The Permittee shall keep the baghouse system design specifications showing the calculated maximum airflow on site. Minn. R. 7005.0100, subp. 35a

Visible Emissions: The Permittee shall check the fabric filter stack (SV 018) for any visible emissions once each day of operation during daylight hours. During inclement weather, the Permittee shall read and record the pressure drop across the fabric filter, once each day of operation. Minn. R. 7007.0800, subp. 2

C. MONITORING AND RECORDKEEPING hdr
Pressure Drop: After the fabric filter has been in service for one week and before the end of first month, the Permittee shall observe the normal operating pressure drop and record it in the facility's O&M Plan. Minn. R. 7007.0800, subp. 4

Monitoring Equipment: The Permittee shall install and maintain necessary monitoring equipment for measuring and recording pressure drop as required by this permit. The monitoring equipment must be installed, in use, and properly maintained when the monitored fabric filter is in operation. Minn. R. 7007.0800, subp. 4

Recordkeeping of Visible Emissions and Pressure Drop (during inclement weather only): The Permittee shall record the time and date of each visible emission inspection/pressure drop reading, and whether or not any visible emissions were observed, and whether or not the observed pressure drop (during inclement weather only) was within the range specified in the facility's O&M Plan. Minn. R. 7007.0800, subp. 5

Operation and Maintenance: The Permittee shall maintain each piece of control equipment according to the manufacturer's specification, shall conduct inspections, and maintain documentation of those actions as required by Minn. R. 7011.0075, subp. 2(A) to 2(I). Minn. R. 7011.0075, subp. 2

Operation of Control Equipment: The control equipment is considered listed control equipment under Minn. R. 7011.0060 to 7011.0080.

Solid fuel handling equipment shall not be vented to the atmosphere when emissions are not controlled by pollution control equipment (CE 014). This emission unit is physically capable of operating without venting to the atmosphere, and therefore can operate when control equipment is not operational. Minn. R. 7007.0800, subp. 2

Corrective Actions: The Permittee shall follow the O&M Plan for the fabric filter and take corrective action as soon as possible (within 24 hours) if any of the following

occur:

- Visible emissions are observed; - The recorded pressure drop is outside the required operating range; or - The fabric filter or any of its components are found during the inspections to need repair.

The Permittee shall keep a record of the type and date of any corrective action taken for the fabric filter. Minn. R. 7007.0800, subps. 4, 5, & 14

D. PERFORMANCE TESTING REQUIREMENTS hdr

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-10

Initial Performance Test: due 180 days after Initial Startup of EU 017 to measure Opacity. (Note: testing was completed on SV 018 for EU 016 and EU 019 on A ugust 20, 2004.)

Performance Test Pre-test Meeting: due 7 days before each performance test. 40 CFR Section 60.8; Minn. R. 7017.2020, subp. 1; Minn. R. 7017.2030, subp. 4

Initial Performance Test: due 180 days after Initial Startup of EU 018 to measure Opacity. (Note: testing was completed on SV 018 for EU 016 and EU 019 on A ugust 20, 2004.)

Performance Test Pre-test Meeting: due 7 days before each performance test. 40 CFR Section 60.8; Minn. R. 7017.2020, subp. 1; Minn. R. 7017.2030, subp. 4

E. NSPS GENERAL PROVISIONS - APPLICABLE TO EU 016, EU 017, EU 018, and EU 019 ONLY hdr

Notification of any physical or operational change which increases emission rate: due 60 days (or as soon as practical) before the change is commenced within 180 days of completion of any physical or operational change subject to the control measures specified in 60.14(a), compliance with all applicable standards must be achieved. (Note: Notifications have been received for EU 016 and EU 019 and construction completed as described in the TSD for Air Emission Permit 16300005-004.) 40 CFR Section 60.7(a)(4); Minn. R. 7019.0100, subp. 1

Notification of Anticipated Date for Conducting Opacity Observations: due 30 days prior to observation date.

(Note: Testing notification for testing on SV 018 for EU 016 and EU 019 was completed on July 20, 2004. Testing was completed on SV 018 for EU 016 and EU 019 on August 20, 2004.) 40 CFR Section 60.7(a)(4); Minn. R. 7019.0100, subp. 1

Recordkeeping: Maintain records of the occurrence and duration of any startup, shutdown, or malfunction in the operation of the facility including; any malfunction of the air pollution control equipment; or any periods during which a continuous monitoring system or monitoring device is inoperative. 40 CFR Section 60.7(b); Minn. R. 7019.0100, subp. 1

Recordkeeping: Maintain a file of all measurements, maintenance, reports and records for at least five years. 40 CFR Section 60.7(f); Minn. R. 7019.0100, subp. 1 Opacity Compliance: Demonstrate compliance with Opacity standards using Reference Method 9. 40 CFR Section 60.11; Minn. R. 7017.2015 No owner or operator shall build, erect, install, or use any article, machine, equipment or process, the use of which conceals an emission which would otherwise constitute a violation of an applicable standard. 40 CFR Section 60.12; Minn. R. 7011.0050

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-11

Subject Item: GP 005 Synthetic Minor Fuel Usage Limits

Associated Items: EU 001 Boiler 1

EU 028 Auxiliary Boiler

What to do Why to do it
A . EMISSION & OPERATING LIMITS hdr
The Permittee shall comply with EITHER the Tier 1 limits (all of the limits listed under Tier 1) OR the Tier 2 limits (all of the limits listed under Tier 2). Compliance with either set of limits is adequate, it is not necessary to comply with both sets of limits simultaneously. Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.3000

A .1. Tier I Limits hdr
EU028 Natural Gas Fuel Usage: less than or equal to 380.95 million cubic feet/year using 12-month Rolling Sum Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.3000 EU028 Fuel Oil Fuel Usage: less than or equal to 500000 gallons/year using 12-month Rolling Sum Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.3000
A .2. Tier 2 Limits hdr
Volatile Organic Compounds: less than or equal to 132.7 tons/year using 12-month Rolling Sum for both units listed under GP 005, combined, calculated using Equation B.1 in Appendix B of this permit. Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.3000 Fuel Usage: less than or equal to 1750000 gallons/year using 12-month Rolling Sum of fuel oil used in EU 028, using the following calculation:

F(028) = 500,000 gal + [1,250,000 gal x ((8760-HMB)/2000)]

where: HMB = 12-month rolling sum of main boiler (EU 001) operating hours during which EU 003, EU 005, EU 010, and EU 016 are also presumed to be operating.

(Recordkeeping is not required if the 12-month Rolling Sum of fuel oil used in EU 028 is less than 500,000 gal.) Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.3000

B. RECORDKEEPING hdr
Maintain paper or electronic copies, for a period of 5 years, of the applicable records below Minn. R. 7007.0800, subp. 5

B.1 Tier I Recordkeeping Requirements hdr
Each day, record the quantity and heat content of each type of fuel combusted in EU 028.

Or

Be able to extract that information for each day of the previous month, based on operating records, by the 15th day of each month. Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.3000

By the 15th day of each month, calculate and record the 12-month rolling sum of fuel oil combusted in EU 028, for the previous 12 months. Minn. R. 7007.0800, subps. 4 & 5

By the 15th day of each month, calculate and record the 12-month rolling sum of natural gas combusted in EU 028, for the previous 12 months. Minn. R. 7007.0800, subps. 4 & 5

B.2 Tier 2 Recordkeeping Requirements hdr
Each day, record the operating hours for EU 001, and the number of those hours during which EU 003, EU 005, EU 010, and/or EU 016 were also operating (HMB). (Recordkeeping is not required if the 12-month Rolling Sum of fuel oil used in EU 028 is less than 500,000 gal.) Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.3000

Each day, record the quantity and heat content of each type of fuel combusted in each of the 2 units listed in GP 005.

OR

Be able to extract that information for each day of the previous month, based on operating records, by the 15th day of each month. Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.3000

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-12

By the 15th day of each month, calculate and record the following:

- The monthly and 12-month rolling sum of the main boiler (EU 001) operating hours during which EU 003, EU 005, EU 010, and/or EU 016 were also operating. (Recordkeeping is not required if the 12-month Rolling Sum of fuel oil used in EU 028 is less than 500,000 gal.)

- The monthly and 12-month rolling sum of the EU 028 fuel oil usage using the equation specified within the Tier 2 limit. Minn. R. 7007.0800, subps. 4 & 5

By the 15th day of each month, calculate and record the monthly and 12-month rolling sum of VOC emissions, using the calculation method described within the Tier 2 limit. Minn. R. 7007.0800, subps. 4 & 5

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-13

Subject Item: GP 007 Lime Handling & Storage

Associated Items: EU 032 Lime Silo Day Bin
EU 033 Lime Storage Silo

What to do Why to do it
A . EMISSION AND OPERATING LIMITS hdr
Total Particulate Matter: less than or equal to 0.01 grains/dry standard cubic foot . This limit applies individually to each unit listed in GP 007. Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.3000; Meets requirements of Minn. R. 7011.0735 Particulate Matter < 10 micron: less than or equal to 0.01 grains/dry standard cubic foot . This limit applies individually to each unit listed in GP 007. Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.3000 Opacity: less than or equal to 20 percent opacity Minn. R. 7011.0715
Operating Hours: less than or equal to 5096 hours/year using 12-month Rolling Sum for each unit listed in GP 007. Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.3000 B. CONTROL REQUIREMENTS - see GP 009 hdr

C. RECORDKEEPING REQUIREMENTS hdr
Daily Recordkeeping: Each day, record the total number of hours that each unit listed under GP 007 operated during the previous day. Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.3000 Monthly Recordkeeping: By the 15th day of each month, calculate and record the total number of hours each unit in GP 007 operated during the previous month, and during the previous 12 months. Minn. R. 7007.0800, subp. 4 & 5

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-14

Subject Item: GP 008 FGD Byproduct/Fly Ash Handling & Storage

Associated Items: EU 012 Ash Silo
EU 034 FGD Byproduct/Fly Ash Storage Silo
EU 035 Recycle Ash Storage Silo
EU 036 Recycle Ash Storage Silo
EU 037 Economizer Ash Surge Hopper
EU 039 SCR Inlet Ash Surge Hopper

What to do Why to do it
A . EMISSION AND OPERATING LIMITS hdr
Total Particulate Matter: less than or equal to 0.01 grains/dry standard cubic foot . This limit applies individually to each unit listed in GP 008. Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.3000; Meets requirements of Minn. R. 7011.0735 Particulate Matter < 10 micron: less than or equal to 0.01 grains/dry standard cubic foot . This limit applies individually to each unit listed in GP 008. Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.3000; Meets requirements of Minn. R. 7011.0735 Opacity: less than or equal to 20 percent opacity Minn. R. 7011.0715

B. CONTROL REQUIREMENTS - see GP 009 hdr

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-15

Subject Item: GP 009 Lime, FGD Byproduct/Fly Ash Fabric Filters

Associated Items: CE 018 Fabric Filter - Low Temperature, i.e., T<180 Degrees F
CE 019 Fabric Filter - Low Temperature, i.e., T<180 Degrees F
CE 020 Fabric Filter - Low Temperature, i.e., T<180 Degrees F
CE 021 Fabric Filter - Low Temperature, i.e., T<180 Degrees F
CE 022 Fabric Filter - Low Temperature, i.e., T<180 Degrees F
CE 023 Fabric Filter - Low Temperature, i.e., T<180 Degrees F
CE 026 Fabric Filter - Low Temperature, i.e., T<180 Degrees F
CE 027 Fabric Filter - Low Temperature, i.e., T<180 Degrees F

What to do Why to do it
A . OPERATING REQUIREMENTS hdr
The Permittee shall operate and maintain each fabric filter at all times that any emission unit controlled by the fabric filter is in operation. Title I Condition: To avoid classification as a major source and modification under 40 CFR Section 52.21; Minn. R. 7007.3000; Minn. R. 7007.0800, subps. 2 & 14 The Permittee shall operate and maintain each fabric filter in accordance with the Operation and Maintenance (O&M) Plan. The Permittee shall keep copies of the O&M Plan available onsite for use by staff and MPCA staff. Minn. R. 7007.0800, subp. 14

Pressure Drop: greater than or equal to 0.5 inches of water column and less than or equal to 10 inches of water column , unless a new range is required to be set pursuant to Minn. R. 7017.2025, subp. 3. If a new range is required to be set, it will be based on the values recorded during the most recent MPCA approved performance test where compliance was demonstrated. The Permittee shall record the pressure drop of each fabric filter once every 24 hours when in operation. Title I Condition: To avoid classification as a major source and modification under 40 CFR Section 52.21; Minn. R. 7007.3000; Minn. R. 7007.0800, subps. 2 & 14

B. RECORDKEEPING AND MONITORING REQUIREMENTS hdr
Recordkeeping of Pressure Drop: The Permittee shall record the time and date of each pressure drop reading and whether or not the recorded pressure drop was within the range specified in this permit. Title I Condition: To avoid classification as a major source and modification under 40 CFR Section 52.21; Minn. R. 7007.3000; Minn. R. 7007.0800, subps. 2 & 14 Monitoring Equipment: The Permittee shall install and maintain the necessary monitoring equipment for measuring and recording pressure drop as required by this permit. The monitoring equipment must be installed, in use, and properly maintained when the monitored fabric filter is in operation. Minn. R. 7007.0800, subp. 4

Periodic Inspections: At least semiannually, or more frequently as required by the manufacturing specifications, the Permittee shall inspect the control equipment components. The Permittee shall maintain a written record of these inspections. Minn. R. 7007.0800, subps. 4, 5 & 14

Corrective Actions: The Permittee shall take corrective action as soon as possible if any of the following occur:

- Visible emissions are observed; - The recorded pressure drop is outside the required operating range; or - The fabric filter or any of its components are found during the inspections to need repair.

Corrective actions shall return the pressure drop to within the permitted range, eliminate visible emissions, and/or include completion of necessary repairs identified during the inspection, as applicable. Corrective actions include, but are not limited to, those outlined in the O&M Plan for the fabric filter. The Permittee shall keep a record of the type and date of any corrective action taken for each filter

. Minn. R. 7007.0800, subps. 4, 5 & 14

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-16

Subject Item: GP 010 Areas Served by Watering Truck

Associated Items: CE 013 Water Application - truck
FS 002 Petroleum Coke Storage Pile (Inactive, reactivation will require new modeling demonstration)

FS 009 Coal Pile A

FS 010 Coal Pile B

FS 011 Coal/Coke Reclaim
FS 012 Coal Yard Traffic (Unpaved roads & driving on coal)

FS 013 Paved Road Traffic

What to do Why to do it
A ccess areas, roads, parking facilities (1) Install asphalt or concrete surfaces or chemical agents on all active truck haul roads of the coal handling facility when the coal throughput by truck is 200,000 tons or greater. All paved roads and areas shall be cleaned to minimize the discharge to the atmosphere of fugitive particulate emissions. Such cleaning shall be accomplished in a manner which minimizes resuspension of particulate matter. Access areas surrounding coal stockpiles and parking facilities which are located within a coal handling facility shall be treated with water, oils, or chemical agents. Minn. R. 7011.1105, subp. (A)

The Permittee shall water the unpaved roads (including all routes where vehicles are driven on coal) at the facility. Watering shall comply with the following conditions: a. The water application rate shall be at least 3 gallons for each 100 square feet every 24 hours. b. A rainfall of at least 0.1 inch during the previous 24 hours shall substitute for one water application, unless the storage pile moisture content is rated as "dry." c. If unpaved roads cannot be watered because the ambient air temperature (as measured at the facility during daylight operating hours) will be less than 35 degrees F (1.7C) or conditions due to weather, in combination with the application of water, could create hazardous driving conditions, then watering shall be postponed and accomplished as soon as the conditions preventing water application have abated. Minn. R. 7009.0020 (This is a state only requirement and is not enforceable by the EPA Administrator and citizens under the Clean A ir Act)

d. Water application is not required on days when there is no vehicle traffic. e. Water application is not required when the daily qualitative assessment of the moisture content of the coal piles is "wet." f. Following any day when water is not applied based on the absence of traffic, water shall be applied within 3 hours of commencement of vehicle traffic, unless another criterion for not watering is met. Minn. R. 7009.0020 (cont. from above) (This is a state only requirement and is not enforceable by the EPA Administrator and citizens under the Clean A ir Act)

Daily Recordkeeping: The Permittee shall keep records of the water applications, including the following: a. The daily qualitative assessment of the moisture content of coal piles where vehicles are driven. b. The roads watered, the amount of water applied, the time watered, and the method of application. If water was not applied because there was a 0.1 inch or greater rainfall within the previous 24 hours, or because of the temperature or other weather conditions that would result in unsafe driving conditions, it must be noted in the record along with the source of measurement (i.e. on-site rain gauge or thermometer). c. Records of watering equipment breakdowns and repairs, and records of contingency efforts undertaken. Minn. R. 7007.0800, subps. 4 & 5

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-17

Subject Item: SV 001 Main Boiler Stack

Associated Items: EU 001 Boiler 1

What to do Why to do it
A . MONITORING REQUIREMENTS hdr
Daily Calibration Error (CE) Test: Conduct daily CE testing on all CEMS required by the Acid Rain Program, in accordance with 40 CFR pt. 75, Appendix B. 40 CFR pt. 75, Appendix B, Section 2.1; Minn. R. 7017.1020 Linearity and Leak Check Test (Acid Rain Program): due before end of each calendar quarter starting 07/21/1998. Conduct a quarterly linearity test on CEMS required by the Acid Rain Program, in accordance with 40 CFR pt. 75, Appendix B. 40 CFR pt. 75, Appendix B, Section 2.2; Minn. R. 7017.1020

Linearity Test Results Summary: due 30 days after end of each calendar quarter following Linearity and Leak Check Test (Acid Rain Program) if performed. Minn. R. 7007.0800, subp. 2

CEMS Relative Accuracy Test Audit (RATA): due before end of each calendar half-year starting 07/21/1998. Conduct a RATA on all CEMS required by the Acid Rain Program, in accordance with 40 CFR pt. 75, Appendix B. If the RATA results indicate a relative accuracy of 7.5% or less, the next RATA is not required for twelve (12) months. 40 CFR pt. 75, Appendix B, Section 2.3; Minn. R. 7017.1020

Relative Accuracy Test Audit (RATA) Notification: due 30 days before CEMS Relative Accuracy Test Audit (RATA) Minn. R. 7007.0800, subp. 2

Relative Accuracy Test Audit (RATA) Results Summary: due 30 days after end of each calendar quarter following CEMS Relative Accuracy Test Audit (RATA) Minn. R. 7007.0800, subp. 2

CEMS QA/QC: The owner or operator of an affected facility shall operate, calibrate, and maintain each CEMS according to the QA/QC procedure in 40 CFR pt. 75, Appendix B as amended. 40 CFR Section 75.21; Minn. R. 7017.1020

Emissions Monitoring: The owner or operator shall measure SO2, NOx, CO2, and Hg emissions, and exhaust gas flow rate, for each affected unit in accordance with 40 CFR Section 75.10. 40 CFR pt. 75; Minn. R. 7017.1020

COMS Continuous Operation: Except for system breakdowns, repairs, calibration checks, and zero and span adjustments, all COMS shall be in continuous operation. Minn. R. 7007.0800, subp. 2

COMS Daily Calibration Drift (CD) Check: The CD shall be quantified and recorded at zero (low-level) and upscale (high-level) opacity at least once daily during periods of operation. The COMS must be adjusted whenever the calibration drift (CD) exceeds twice the specifications of PS-1 of 40 CFR pt. 60, Appendix B. Minn. R. 7017.1000

COMS Calibration Error Audit: due before end of each calendar half-year starting 06/23/2004. Conduct audits at least 3 months apart but no greater than 8 months apart. Minn. R. 7007.0800, subp. 2

The Report for COMS Calibration Error Audit: due 30 days after end of each calendar half-year following COMS Certification Test Minn. R. 7007.0800, subp. 2

COMS Monitoring Data: Calculate each six-minute average period as follows: total the opacity values of each individual data point collected by the COMS for each one-minute period and divide the total by the number of data points. (The sum of the individual one-minute averages in the applicable averaging period must be determined and divided by the number of one-minute averages taken.) Round the resulting averages to the nearest one percent opacity. This resulting average is the six-minute opacity that shall be recorded by the monitoring system. There are ten individual six-minute consecutive averaging periods in each hour beginning on the clock hour and ending six minutes later. Minn. R. 7017.1200, subp. 3

Recordkeeping: The owner or operator must retain records of all COMS monitoring data and support information for a period of five (5) years from the date of the monitoring sample, measurement or report. Records must be kept as required in Table A under the "Total Facility" subject item. Minn. R. 7007.0800, subp. 5

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-18

Subject Item: EU 001 Boiler 1

Associated Items: CE 001 Electrostatic Precipitator - High Efficiency
CE 002 Electrostatic Precipitator - High Efficiency
CE 015 SCR (Selective Catalytic Reduction)
CE 016 Spray Dryer
CE 017 Fabric Filter - High Temperature, i.e., T>250 Degrees F
GP 005 Synthetic Minor Fuel Usage Limits

MR 004 Flow Monitor
MR 006 SO2 Analyzer
MR 007 NOX Analyzer
MR 008 CO2 Analyzer
MR 009 Opacity Monitor
MR 010 Hg CEMS

SV 001 Main Boiler Stack

What to do Why to do it
A . EMISSION LIMITS hdr
Total Particulate Matter: less than or equal to 0.4 lbs/million Btu heat input using 3-hour Average . This limit applies prior to the boiler rehabilitation. Minn. R. 7011.0510, subp. 1

Total Particulate Matter: less than or equal to 0.015 lbs/million Btu heat input using 3-hour Average at the stack exit using Method 5, excluding condensable particulate matter as allowed under Minn. R. 7017.2060, subp. 3(c).

Heat Input is defined as the total input (fuel basis) of EU 001.

This limit becomes effective 270 days after the 1st firing of the boiler with fuels other than natural gas following the rehabilitation project. Title I Condition: To avoid classification as a major mod under 40 CFR Section 52.21; Minn. R. 7007.3000; Meets Minn. R. 7011.0510, subp. 1

Particulate Matter < 10 micron: less than or equal to 0.030 lbs/million Btu heat input using 3-hour Average at the stack exit, as measured using test methods 201A and 202 as amended and using any and all options allowed within the test methods, or other test method approved in advance by the Commissioner as allowed under Minn. R. 7017.2050.

Heat Input is defined as the total input (fuel basis) of EU 001.

This limit becomes effective 36 months after the 1st firing of the boiler with fuels other than natural gas following the rehabilitation project. Title I Condition: To avoid classification as a major mod under 40 CFR Section 52.21; Minn. R. 7007.3000

Sulfur Dioxide: less than or equal to 0.12 lbs/million Btu heat input using 30-day Rolling Average at the stack exit.

Heat Input is defined as the total heat input (CEMS basis) of EU 001.

This limit becomes effective 270 days after the 1st firing of the boiler with fuels other than natural gas following the rehabilitation project. Title I Condition: To avoid classification as a major mod under 40 CFR Section 52.21; Minn. R. 7007.0800, subp. 4 (PUC order approving MERP, March 8, 2004, Docket No. E-002/M-02-633); Minn. R. 7007.3000; Meets Minn. R. 7011.0510, subp. 1

Sulfur Dioxide: less than or equal to 1.6 lbs/million Btu heat input calculated as an annual average. By January 30th of each year, compute the annual average sulfur dioxide emission rate during the previous calendar year by averaging all hourly averages recorded over the previous calendar year. Determine hourly averages from data collected in accordance with 40 CFR pt. 75, subp. B, or using the missing data substitution procedures as set out in 40 CFR pt. 75, subp. D. Minn. R. 7021.0050, subp. 5

Sulfur Dioxide: less than or equal to 3.0 lbs/million Btu heat input using 1-Hour A verage Minn. R. 7009.0020 (This is a state only requirement and is not enforceable by the EPA Administrator and citizens under the Clean A ir Act)

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-19

Nitrogen Oxides: less than or equal to 0.10 lbs/million Btu heat input using 30-day Rolling Average at the stack exit.

Heat Input is defined as the total heat input (CEMS basis) of EU 001.

This becomes effective 270 days after the 1st firing of the boiler with fuels other than natural gas following the rehabilitation project. Title I Condition: To avoid classification as a major mod under 40 CFR Section 52.21; Minn. R. 7007.0800, subp. 4 (PUC order approving MERP, March 8, 2004, Docket No. E-002/M-02-633); Minn. R. 7007.3000;

Opacity: less than or equal to 20 percent opacity using 6-minute Average except for one six-minute period per hour of not more than 60 percent opacity. Minn. R. 7011.0510, subp. 2

B. OPERATIONAL & CONTROL REQUIREMENTS hdr

A llowed fuel types: bituminous and subbituminous coal, petroleum coke, wood, natural gas, used oil, non-hazardous petroleum-contaminated cleanup material, nonhazardous MGP waste, and cellulose-based, non-chlorinated, nonhazardous organic materials, including but not limited to paper and grain.

Manufactured Gas Plant (MGP) waste is defined as tar-contaminated materials and gas purification residuals associated with past operation of gas manufacturing plants. MGP waste includes non-hazardous materials such as contaminated soils, sediments, oxide box filler material, and wood chips. Minn. R. 7007.0800, subp. 2

Except as provided below, the Permittee shall operate and maintain the control devices listed above under "Associated Items" at all times that any emission unit controlled by the control equipment is in operation. See also Subject Items CE 015, CE 016, and CE 017 for further requirements. Title I Condition: To avoid classification as a major source and modification under 40 CFR Section 52.21; Minn. R. 7007.3000; Minn. R. 7007.0800, subps. 2 & 14 Operation of CE 015 and CE 016 is not required until 270 days after the first firing of the main boiler with fuels other than natural gas following the rehabilitation project. Minn. R. 7007.0800, subp. 2

Operation of CE 001 and CE 002 is required at all times that any source of emissions controlled by the ESPs is in operation, before and after first firing of the boiler with fuels other than natural gas following rehabilitation when CE 017 is not in operation, until required operation (i.e. 270 days after the first firing with fuel other than natural gas of the boiler following rehabilitation) of CE 017. After required operation of CE 017, operation of CE 001 and CE 002 is not required, and the permittee shall operate and maintain CE 017 at all times that any source of emissions controlled by the fabric filter is in operation. Minn. R. 7007.0800, subp. 2

C. BOILER OPERATING RATE REQUIREMENTS AND LIMITS hdr
Boiler Feed Water flow rate: less than or equal to 3828000 lbs/hour using 8-hour Block Average Minn. R. 7017.2025, subp. 3 (Notice of Compliance for 10/21/98 performance test) (this requirement expires upon 1st firing of the boiler following rehabilitation) Each calendar day, calculate the previous day's 8-hour block average boiler feed water flow rates by dividing the total boiler feed water flow during the 8 hours by the total operating time during the 8 hours. Downtime of 15 minutes or more is not to be included in the operating time.

The Boiler Feed Water Flow Rate may be exceeded for up to 40 hours per year under the STET limit, below. Minn. R. 7007.0800, subps. 2 & 5

Boiler Alternative Operating Conditions for Performance Testing: Alternative Operating Conditions during testing are defined as 90% to 100% of the boiler's normal dependable operating load or the short-term maximum permitted operating rate, whichever is lower. The basis for this number must be included in the test plan. If testing is conducted at the alternative operating condition established, an operating limit will not be established as a result of performance testing.

In no case will the new operating limit be higher than allowed by an existing permit condition. Minn. R. 7017.2025, subps. 2(A) & 3(B)

Boiler Operating Conditions Not Meeting the Defined Operating Conditions During Performance Testing:

If performance testing is not conducted at or above the established alternative operating condition, then the boiler operating rate will be limited on an 8-hour block average based on the following:

1. If the results of the performance test are greater than 80% of any applicable emission limit for which emissions are measured, then boiler operation will be limited to the tested operating rate. 2. If results are less than 80% of all applicable emission limits for which emissions are measured, boiler operation will be limited to 110% of the tested operating rate.

In no case will the new operating limit be higher than allowed by an existing permit condition. Minn. R. 7017.2025, subp. 3(B)

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-20

Short Term Emergency and Testing (STET) Operating Hours Limit: The boiler may operate up to 40 hours per year to demonstrate the Uniform Rating of Generating Equipment (URGE) capacity and to meet emergency energy supply needs. Documentation of all STET operation shall be maintained. The boiler must meet emission limits during STET operation. Minn. R. 7007.0800, subp. 2

STET Operation Definition that Applies to Boilers that Meet or do Not Meet the A lternative Operating Condition for Performance Testing:

If performance test results measure emissions at 80% or less of any applicable emission limits for any tested pollutant, STET operation is defined as operation beyond 110% of the average operating rate achieved during that performance test.

If performance test results measure emissions at greater than 80% any applicable emission limit for any tested pollutant, STET operation is defined as operation beyond 100% of the average operating rate achieved during that performance test.

In no case will STET operation be higher than allowed by an existing permit condition. Minn. R. 7007.0800, subp. 2

D. MONITORING REQUIREMENTS hdr

Use the SO2 CEM to measure SO2 emissions. 40 CFR Section 64.3; Minn. R. 7017.1000, subp. 1
Use the NOX CEM to measure NOX emissions. 40 CFR Section 64.3; Minn. R. 7017.1000, subp. 1 Use the COM to measure opacity emissions in 1-minute averages as required in Minn. R. 7017.1200, subp. 3. Minn. R. 7017.1200, subp. 3

Emissions Monitoring: Measure SO2, NOx, CO2, and Hg emissions, and exhaust gas flow rate, for each affected unit in accordance with 40 CFR Section 75.10. 40 CFR pt. 75; Minn. R. 7017.1020 Emissions Monitoring: The owner or operator shall use a Hg CEMS to measure Hg emissions from EU 001. Additional Hg monitoring requirements are located under subject item SV 001, MR 010, and Total Facility. Minn. Stat. 216B.681; Minn. R. 7017.1006

E. REQUIREMENTS FOR BURNING WASTE OR FUELS OTHER THAN COAL, WOOD, PETROLEUM COKE, OR NATURAL GAS hdr

The feed rate of MGP waste must not exceed 2 percent of total fuel mass (total fuel mass includes the mass of MGP waste used as fuel). The combined feed rate of MGP waste, used oil, petroleum-contaminated materials, and any fuels other than coal, wood, petroleum coke, and natural gas must not exceed 5 percent of total fuel mass (total fuel mass includes the mass of all other fuels in addition to coal, wood, petroleum coke, and natural gas), and a mercury analysis of the fuel must also be done. Minn. R. 7007.0800, subp. 2

Monitoring and Recordkeeping: When combusting MGP waste, used oil, petroleum-contaminated materials, or any other fuels other than coal, wood, petroleum coke and natural gas, monitor and record the following:

1. The daily quantity, by weight, of MGP waste, used oil, petroleum-contaminated materials, or any other fuels mixed with coal, once each day; and

2. Boiler operating load once each hour in pounds of steam per hour. Minn. R. 7007.0800, subp. 2

Minimum Operating Load: Operate EU 001 at 50% or greater capacity when combusting MGP waste, used oil, petroleum-contaminated materials, or any other fuels other than coal, wood, petroleum coke, and natural gas, except that up to 2,000 pounds of on-site generated petroleum-contaminated rags may be placed in the boiler prior to startup.

If EU 001 undergoes an emergency shutdown or emergency load reduction to below 50% capacity, immediately cease adding MGP waste, used oil, petroleum-contaminated materials, or any fuels other than petroleum coke, wood, or natural gas to the coal, until EU 001 again achieves 50% capacity. Fuels already mixed with coal and enroute to the boiler prior to the emergency may be burned after the emergency with EU 001 operating at less than 50% capacity. The permittee must take all feasible and prudent steps to minimize the amount of coal mixed with other fuels, except as allowed above, which are combusted when EU 001 operates at less than 50% capacity. Minn. R. 7007.0800, subp. 2

Manage MGP waste in accordance with a MGP Waste Management Plan which has been reviewed and approved by the Commissioner. The plan must specify how NSP will ensure that the waste is non-hazardous, how MGP waste will be delivered, stored, and transported on-site from storage to the boiler, the methods which will be used to track and ensure compliance with the maximum feed rate limit and minimum oxygen limit, and how the Permittee will ensure that optimum combustion conditions are maintained. Submit any proposed changes of the MGP Waste Management Plan to the Commissioner for review and approval prior to implementing the changes. Minn. R. 7007.0800, subp. 2

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-21

Do not combust waste from an MGP cleanup site unless treatment and disposal via combustion in a utility boiler is the chosen management alternative approved by the Commissioner for that site, after considering the recommendations from the MGP Remediation Advisory Committee. Notify the Commissioner at least 7 days prior to receiving MGP waste from a cleanup site from which waste has not been previously burned at the King Plant. Include in the notification the name and location of the MGP cleanup site and the name and date of the document or documents which identify the MGP waste management alternatives and the approved alternative for the site. Minn. R. 7007.0800, subp. 2

The concentration of the pollutants listed below in MGP waste, as measured in accordance with the approved MGP Waste Management Plan, must not exceed the following limits:

Pollutant Limit (ppm)

Arsenic 12 Cadmium 20 Chromium 100 Mercury 1 Lead 100 Selenium 20 Silver 100 Minn. R. 7007.0800, subp. 2

Comply with Minn. R. ch. 7045 for management of used oil. Maintain on-site records which demonstrate that used oil is managed as required by Minn. R. ch. 7045. Minn. R. 7007.0800, subp. 2

Combustion rate limit for petroleum-contaminated waste materials: Do not combust more than 1000 cubic yards per week of soils, sorbents, wood and other nonhazardous combustible materials contaminated with petroleum products. This does not include MGP waste. Minn. R. 7007.0800, subp. 2

F. ACID RAIN PROGRAM REQUIREMENTS hdr
Hold allowances as of the allowance transfer deadline, in the unit's compliance subaccount, not less than the total annual emissions of sulfur dioxide for the previous calendar year. Takes effect January 1, 2000. Allowances shall be held in, deducted from, or transferred among Allowance Tracking System accounts in accordance with the Acid Rain Program. 40 CFR Section 72.9(c)(1)(i); 40 CFR Section 72.9(g)(4)

Comply with the applicable Acid Rain emissions limitation for sulfur dioxide. Takes affect January 1, 2000. 40 CFR Section 72.9(c)(1)(ii); 40 CFR Section 72.9(g)(4) NOx Averaging Plan (2002-2006)

Beginning January 1, 2000 either: Maintain an annual average NOx emission rate of 1.05 lbs/MMBtu and limit the annual heat input to less than or equal to 34,000,000 MMBtu per year. OR Maintain a Btu-weighted annual average emission rate in lbs/MMBtu, averaged over the units specified in the NOx averaging plan, that is less than or equal to the Btu-weighted annual average emission rate averaged over the same units had they each been operated during the same period of time in compliance with the applicable emission limitations in 40 CFR Sections 76.5, 76.6, or 76.7. Units covered in the plan are:

Plant Boiler ID#

A llen S. King 1 Black Dog 3,4 High Bridge 3,4,5,6 Minnesota Valley 4 Riverside 6,7,8 Sherburne County 1,2,3 40 CFR Section 76.11; Minn. R. 7011.0553

Certify Acid Rain Program submittals. Each submission under the Acid Rain Program shall be submitted, signed, and certified by the designated representative or the alternative designated representative for all sources on behalf of which the submission is made in accordance with 40 CFR Section 72.21. 40 CFR Section 72.21; 40 CFR Section 72.22

A pply for Acid Rain Program Permit reissuance: The designated representative shall submit a complete Acid Rain permit application for each source with an affected unit at least 6 months prior to the expiration of an existing Acid Rain Permit in accordance with 40 CFR Section 72.30(c). 40 CFR Section 72.30(c)

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-22

Keep on site or readily accessible at another site each of the following documents for a period of 5 years from the date the document is created: - The certificate of representation, - All emission monitoring information, - Copies of all reports, compliance certifications, and other submissions or records made under the Acid Rain Program, and - Copies of all documents used to complete an acid rain permit application. 40 CFR Section 72.9(f)(1)

G. MERCURY hdr
Daily Sampling: Each day starting within 90 days of the first firing of the rehabilitated boiler with solid fuels, the Permittee shall collect a sample of the as-burned solid fuel blend and a sample of flyash, for the purpose of determining the mercury content of each and establishing baseline mercury emission levels.

This requirement expires on the earlier of: (1) Five years after initial startup of EU 001 after rehabilitation, or (2) The date a mercury CEMS is state certified.

This is a state only requirement and is not enforceable by the EPA administrator and citizens under the Clean Air Act. Minn. R. 7007.0800, subp. 4 (PUC order approving MERP, March 8, 2004, Docket No. E-002/M-02-633)

Quarterly Composite Samples: Once each calendar quarter, create a composite sample of as-burned fuel blend and of flyash, from the daily samples collected during the previous calendar quarter. The purpose of this is to determine the mercury content of each and establish baseline mercury emission levels.

This requirement expires on the earlier of: (1) Five years after initial startup of EU 001 after rehabilitation, or (2) The date a mercury CEMS is state certified.

This is a state only requirement and is not enforceable by the EPA administrator and citizens under the Clean Air Act. Minn. R. 7007.0800, subp. 4 (PUC order approving MERP, March 8, 2004, Docket No. E-002/M-02-633)

Establish Baseline Mercury Emission Rate: Use mercury contents of the as-burned fuel blend and flyash, in conjunction with results of mercury emission testing, to establish the baseline mercury emission rate.

This requirement expires on the earlier of: (1) Five years after initial startup of EU 001 after rehabilitation, or (2) The date a mercury CEMS is state certified.

This is a state only requirement and is not enforceable by the EPA administrator and citizens under the Clean Air Act. Minn. R. 7007.0800, subp. 4 (PUC order approving MERP, March 8, 2004, Docket No. E-002/M-02-633)

H. PERFORMANCE TESTING REQUIREMENTS hdr
Initial Performance Test: due 270 days after Initial Startup to measure total particulate matter emissions. Record and submit a summary of data collected simultaneously by the COM for each PM test run. ("Initial Startup" in this case refers to the first firing of the boiler with fuels other than natural gas following rehabilitation.) Minn. R. 7017.2020, subp. 1

Initial Performance Test: due 1,095 days after Initial Startup to measure PM10 emissions. Record and submit a summary of data collected simultaneously by the COM for each PM10 test run. ("Initial Startup" in this case refers to the first firing of the boiler with fuels other than natural gas following rehabilitation.) Minn. R. 7017.2020, subp. 1

Initial Performance Test: due 270 days after Initial Startup to measure ammonia slip. ("Initial Startup" in this case refers to the first firing of the boiler with fuels other than natural gas following rehabilitation.) Minn. R. 7017.2020, subp. 1

Initial Performance Test: due 270 days after Initial Startup to measure mercury emissions. ("Initial Startup" in this case refers to the first firing of the boiler with fuels other than natural gas following rehabilitation.) Minn. R. 7017.2020, subp. 1; Minn. R. 7007.0800, subp. 4 (PUC order approving MERP, March 8, 2004, Docket No. E-002/M-02-633) Start-up is defined as all EU operation at less than 250 MW. EU 001 startup ends no later than 15 minutes after EU 001 attains 250 MW.

Shutdown is defined as all EU 001 operation at less than 250 MW that is part of the process that terminates EU 001 fuel combustion until the next EU 001 startup. Shutdown does not include temporary operating loads below 250 MW for up to 15 consecutive minutes, due to external factors. Minn. R. 7007.0800, subp. 2

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-23

Subject Item: EU 003 Coal Gallery

Associated Items: CE 003 Fabric Filter - Low Temperature, i.e., T<180 Degrees F
SV 003 Coal Gallery Dust Collector Vent

What to do Why to do it
A . EMISSION & OPERATING LMITS hdr
Opacity: less than or equal to 20 percent opacity . If opacity exceeds 20 percent, then action must be taken to control exhaust gases so that either:

(1) particulate matter emissions do not exceed 0.020 gr/dscf, or (2) opacity does not exceed 20 percent. Minn. R. 7011.1105, subp. (G)

Particulate Matter < 10 micron: less than or equal to 0.008 grains/dry standard cubic foot .

This is a state only requirement and is not enforceable by the EPA Administrator or citizens under the Clean Air Act. Minn. R. 7009.0020

Solid fuel handling equipment shall not be vented to the atmosphere when emissions are not controlled by pollution control equipment (CE 003). This emission unit is physically capable of operating without venting to the atmosphere, and therefore can operate when control equipment is not operational. Minn. R. 7007.0800, subp. 2

B. CONTROL EQUIPMENT REQUIREMENTS hdr
Check for visible emissions (during daylight hours) from the control equipment (CE 003) once each calendar week while EU 003 is in operation. Minn. R. 7007.0800, subp. 4

Corrective Actions: If visible emissions (VEs) are observed, determine the cause and take corrective actions as soon as possible to eliminate the VEs. Corrective action may be in the form of discontinuing venting emissions to the atmosphere through CE 003. Minn. R. 7007.0800, subp. 2

Recordkeeping: Record the time and date of each VE inspection, and whether or not any VEs were observed. If VEs were observed, also record a brief description of the type of corrective actions taken, and the date the actions were taken. Minn. R. 7007.0800, subp. 5

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-24

Subject Item: EU 004 Transfer House 1

Associated Items: CE 004 Fabric Filter - Low Temperature, i.e., T<180 Degrees F
CE 005 Dust Suppression by Water Spray

SV 004 Transfer House 1 Dust Collector Stack

What to do Why to do it
A . EMISSION & OPERATING LIMITS hdr
Opacity: less than or equal to 20 percent opacity . If opacity exceeds 20 percent, then action must be taken to control exhaust gases so that either:

(1) particulate matter emissions do not exceed 0.020 gr/dscf, or (2) opacity does not exceed 20 percent. 40 CFR Section 60.252(c); Minn. R. 7011.1105, subp. (G)

Particulate Matter < 10 micron: less than or equal to 0.008 grains/dry standard cubic foot .

This is a state only requirement and is not enforceable by the EPA Administrator or citizens under the Clean Air Act. Minn. R. 7009.0020

Operating Hours: less than or equal to 5096 hours/year using 12-month Rolling Sum Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.3000 Do not build, erect, install, or use any article, machine, equipment, or process, the use of which conceals an emission which would otherwise constitute a violation of an applicable standard. 40 CFR Section 60.12; Minn. R. 7011.0050

B. CONTROL EQUIPMENT REQUIREMENTS hdr
Check for visible emissions (during daylight hours) from the control equipment (CE 004) once each calendar week, while EU 004 is in operation. Minn. R. 7007.0800, subp. 4

Corrective Actions: If visible emissions (VEs) are observed, determine the cause and take corrective actions as soon as possible to eliminate the VEs. Corrective action may be in the form of discontinuing venting emissions to the atmosphere through CE 004. Minn. R. 7007.0800, subp. 2

Recordkeeping: Record the time and date of each VE inspection, and whether or not any VEs were observed. If VEs were observed, also record a brief description of the type of corrective actions taken, and the date the actions were taken. Minn. R. 7007.0800, subp. 5

Solid fuel handling equipment shall not be vented to the atmosphere when emissions are not controlled by the pollution control equipment (CE 004). This emission unit is physically capable of operating without venting to the atmosphere, and therefore can operate when control equipment is not operational. Minn. R. 7007.0800, subp. 2

C. RECORDKEEPING REQUIREMENTS hdr
Daily Recordkeeping: Each day, record the hours of operation of the emissions unit. Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.3000 Monthly Recordkeeping: By the 15th day of each month, calculate and record the 12-month rolling sum of hours operated during the previous 12 months. Minn. R. 7007.0800, subps. 4 & 5

Maintain records of the occurrence and duration of any startup, shutdown, or malfunction in the operation of the facility including any malfunction of the air pollution control equipment, or any periods during which a continuous monitoring system or monitoring device is inoperable. 40 CFR Section 60.7(b); Minn. R. 7019.0100, subp. 1

D. TESTING REQUIREMENTS hdr
Initial Performance Test: due 180 days after Initial Startup of modified conveyors to measure opacity 40 CFR Section 60.8; Minn. R. 7017.2020, subp. 1; Minn. R. 7017.2030, subp. 4 Notification of any physical change or operational change which increases emissions rate: due 60 days (or as soon as practicable) before the change is commenced. Within 180 days of completion of any physical or operational change subject to the control measures specified in 40 CFR Section 60.14(a), compliance with all applicable standards must be achieved. 40 CFR Section 60.7(a)(4); Minn. R. 7019.0100, subp. 1

Notification of the Date Construction Began: due 60 days before start of construction (or as soon as practicable) of replacements. Submit the name and number of each unit and the date of construction of the replacement parts of each unit. 40 CFR Section 60.15(d); Minn. R. 7019.0100, subp. 1

Notification of Anticipated Date for Conducting Opacity Observations: due 30 days prior to observation date. 40 CFR Section 60.7(a)(4); Minn. R. 7019.0100, subp. 1

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-25

Subject Item: EU 005 Coal Crusher House

Associated Items: CE 006 Fabric Filter - Low Temperature, i.e., T<180 Degrees F

SV 005 Coal Crusher House Dust Collector Stack

What to do Why to do it
A . EMISSION & OPERATING LIMITS hdr
Opacity: less than or equal to 20 percent opacity . If opacity exceeds 20 percent, then action must be taken to control exhaust gases so that either:

(1) particulate matter emissions do not exceed 0.020 gr/dscf, or (2) opacity does not exceed 20 percent. Minn. R. 7011.1105, subp. (G)

Particulate Matter < 10 micron: less than or equal to 0.008 grains/dry standard cubic foot .

This is a state only requirement and is not enforceable by the EPA Administrator or citizens under the Clean Air Act. Minn. R. 7009.0020

Solid fuel handling equipment shall not be vented to the atmosphere when emissions are not controlled by pollution control equipment (CE 006). This emission unit is physically capable of operating without venting to the atmosphere, and therefore can operate when control equipment is not operational. Minn. R. 7007.0800, subp. 2

B. CONTROL EQUIPMENT REQUIREMENTS hdr
Check for visible emissions (during daylight hours) from the control equipment (CE 006) once each calendar week while EU 005 is in operation. Minn. R. 7007.0800, subp. 4

Corrective Actions: If visible emissions (VEs) are observed, determine the cause and take corrective actions as soon as possible to eliminate the VEs. Corrective action may be in the form of discontinuing venting emissions to the atmosphere through CE 006. Minn. R. 7007.0800, subp. 2

Recordkeeping: Record the time and date of each VE inspection, and whether or not any VEs were observed. If VEs were observed, also record a brief description of the type of corrective actions taken, and the date the actions were taken. Minn. R. 7007.0800, subp. 5

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-26

Subject Item: EU 006 Railcar Unloading

Associated Items: CE 007 Fabric Filter - Low Temperature, i.e., T<180 Degrees F
CE 008 Fabric Filter - Low Temperature, i.e., T<180 Degrees F
CE 009 Fabric Filter - Low Temperature, i.e., T<180 Degrees F
SV 006 Railcar Unloading Dust Collector Vent (West)
SV 007 Railcar Unloading Dust Collector Vent (East)

What to do Why to do it
A . EMISSION & OPERATING LIMITS hdr
Opacity: less than or equal to 20 percent opacity . If opacity exceeds 20 percent, then action must be taken to control exhaust gases so that either:

(1) particulate matter emissions do not exceed 0.020 gr/dscf, or (2) opacity does not exceed 20 percent. 40 CFR Section 60.252(c); Minn. R. 7011.1105, subp. (G)

Particulate Matter < 10 micron: less than or equal to 0.008 grains/dry standard cubic foot .

This is a state only requirement and is not enforceable by the EPA Administrator or citizens under the Clean Air Act. Minn. R. 7009.0020

Operating Hours: less than or equal to 5096 hours/year using 12-month Rolling Sum Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.3000 Do not build, erect, install, or use any article, machine, equipment, or process, the use of which conceals an emission which would otherwise constitute a violation of an applicable standard. 40 CFR Section 60.12; Minn. R. 7011.0050

B. CONTROL EQUIPMENT REQUIREMENTS hdr
Check for visible emissions (during daylight hours) from the control equipment (CE 007, CE 008, and CE 009) once each calendar week, while EU 006 is in operation. Minn. R. 7007.0800, subp. 4

Corrective Actions: If visible emissions (VEs) are observed, determine the cause and take corrective actions as soon as possible to eliminate the VEs. Corrective action may be in the form of discontinuing venting emissions to the atmosphere through CE 007, CE 008, or CE 009. Minn. R. 7007.0800, subp. 2

Recordkeeping: Record the time and date of each VE inspection, and whether or not any VEs were observed. If VEs were observed, also record a brief description of the type of corrective actions taken, and the date the actions were taken. Minn. R. 7007.0800, subp. 5

C. RECORDKEEPING REQUIREMENTS hdr
Daily Recordkeeping: Each day, record the hours of operation of the emissions unit. Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.3000 Monthly Recordkeeping: By the 15th day of each month, calculate and record the 12-month rolling sum of hours operated during the previous 12 months. Minn. R. 7007.0800, subps. 4 & 5

Maintain records of the occurrence and duration of any startup, shutdown, or malfunction in the operation of the facility including any malfunction of the air pollution control equipment, or any periods during which a continuous monitoring system or monitoring device is inoperable. 40 CFR Section 60.7(b); Minn. R. 7019.0100, subp. 1

D. TESTING REQUIREMENTS hdr
Initial Performance Test: due 180 days after Initial Startup of modified conveyors to measure opacity 40 CFR Section 60.8; Minn. R. 7017.2020, subp. 1; Minn. R. 7017.2030, subp. 4 Notification of any physical change or operational change which increases emissions rate: due 60 days (or as soon as practicable) before the change is commenced. Within 180 days of completion of any physical or operational change subject to the control measures specified in 40 CFR Section 60.14(a), compliance with all applicable standards must be achieved. 40 CFR Section 60.7(a)(4); Minn. R. 7019.0100, subp. 1

Notification of the Date Construction Began: due 60 days before start of construction (or as soon as practicable) of replacements. Submit the name and number of each unit and the date of construction of the replacement parts of each unit. 40 CFR Section 60.15(d); Minn. R. 7019.0100, subp. 1

Notification of Anticipated Date for Conducting Opacity Observations: due 30 days prior to observation date. 40 CFR Section 60.7(a)(4); Minn. R. 7019.0100, subp. 1

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-27

Subject Item: EU 007 Boiler 11

Associated Items: GP 001 Boiler Nos. 11 & 12

SV 008 Boiler 11 Stack

What to do Why to do it
A . EMISSION & OPERATING LIMITS hdr
Particulate Matter < 10 micron: less than or equal to 0.037 lbs/million Btu heat input Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.3000 Nitrogen Oxides: less than or equal to 0.1 lbs/million Btu heat input Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.3000 Opacity: less than or equal to 20 percent opacity Minn. R. 7007.0800, subp. 2 (negotiated limit)
A llowable fuel use: limited to natural gas and propane. Minn. R. 7007.0800, subp. 2
Steam Flow: less than or equal to 100800 lbs/hour using 24-hour Block Average Minn. R. 7017.2025, subp. 3 (Notice of Compliance for 01/15/2002 performance test) B. RECORDKEEPING REQUIREMENTS hdr

Each calendar day, calculate the previous day's average steam production by dividing the total steam produced during the 24 hours by the total operating time during the 24 hours. Downtime of 15 or more minutes is not to be included in the operating time. Minn. R. 7007.0800, subps. 2 & 5

C. TESTING REQUIREMENTS hdr
Performance Test: due before end of each 36 months starting 01/15/2003 to measure NOx emissions. The NOx emissions tests shall be conducted at an interval not to exceed 36 months between test dates.

If NOx emission test results are less than 90 percent of the NOx limit for two or more consecutive years, then the test frequency may be reduced to once every three years.

If a performance test measures NOx emissions at greater than 90 percent of the NOx limit, testing frequency shall revert back to the original yearly basis until the permittee is again able to meet the criteria for a three-year test frequency. Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7017.2020, subp. 1

Performance Test Notification Frequency:

If the NOx emissions test frequency is reduced from annual to once every three years, the permittee shall submit a notification in lieu of each annual test, 30 days before the date that testing was required to be conducted. The notification shall state the percentage of the NOx emission limit that emissions were measured at during each of the previous two performance tests. Minn. R. 7017.2030, subp. 1

The Performance Test requirement to be completed no later than January 14, 2006 has been extended 120 days to May 14, 2006. This is a one-time extension. The next subsequent test will be performed no later than 12 or 36 months after January 14, 2006 dependent on the test results from winter 2006. Minn. R. 7007.1400

Comply with 40 CFR 63, subpart DDDDD, by September 13, 2007. 40 CFR Section 63.7495(b)

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-28

Subject Item: EU 008 Boiler 12

Associated Items: GP 001 Boiler Nos. 11 & 12

SV 009 Boiler 12 Stack

What to do Why to do it
A . EMISSION & OPERATING LIMITS hdr
Particulate Matter < 10 micron: less than or equal to 0.037 lbs/million Btu heat input Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.3000 Nitrogen Oxides: less than or equal to 0.1 lbs/million Btu heat input Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.3000 Opacity: less than or equal to 20 percent opacity Minn. R. 7007.0800, subp. 2 (negotiated limit)
A llowable fuel use: limited to natural gas and propane. Minn. R. 7007.0800, subp. 2
Steam Flow: less than or equal to 35200 lbs/hour using 8-hour Block Average Minn. R. 7017.2025, subp. 3 (Notice of Compliance for 01/20/2000 performance test) B. RECORDKEEPING REQUIREMENTS hdr

Each calendar day, calculate the previous day's 8-hour Block Averages by dividing the total steam produced during the 8 hours by the total operating time during the 8 hours. Down time of 15 or more minutes is not to be included in the operating time. Minn. R. 7007.0800, subps. 2 & 5

C. TESTING REQUIREMENTS hdr
Performance Test: due before end of each 36 months starting 01/11/2005 to measure NOx emissions. The NOx emissions tests shall be conducted at an interval not to exceed 36 months between test dates. Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7017.2020, subp. 1 Comply with 40 CFR 63, subpart DDDDD, by September 13, 2007. 40 CFR Section 63.7495(b)

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-29

Subject Item: EU 010 Transfer House 2

Associated Items: CE 011 Fabric Filter - Low Temperature, i.e., T<180 Degrees F

SV 011 Transfer House 2 Dust Collector Vent

What to do Why to do it
A . EMISSION & OPERATING LIMITS hdr
Particulate Matter < 10 micron: less than or equal to 0.008 grains/dry standard cubic foot .

This is a state only requirement and is not enforceable by the EPA Administrator or citizens under the Clean Air Act. Minn. R. 7009.0020

Opacity: less than or equal to 20 percent opacity . If opacity exceeds 20 percent, then action must be taken to control exhaust gases so that either:

(1) particulate matter emissions do not exceed 0.020 gr/dscf, or (2) opacity does not exceed 20 percent. Minn. R. 7011.1105, subp. (G)

Solid fuel handling equipment shall not be vented to the atmosphere when emissions are not controlled by pollution control equipment (CE 011). This emission unit is physically capable of operating without venting to the atmosphere, and therefore can operate when control equipment is not operational. Minn. R. 7007.0800, subp. 2

B. CONTROL EQUIPMENT REQUIREMENTS hdr
Check for visible emissions (during daylight hours) from the control equipment (CE 011) once each calendar week, while EU 010 is in operation. Minn. R. 7007.0800, subp. 4

Corrective Actions: If visible emissions (VEs) are observed, determine the cause and take corrective actions as soon as possible to eliminate the VEs. Corrective action may be in the form of discontinuing venting emissions to the atmosphere through CE 011. Minn. R. 7007.0800, subp. 2

Recordkeeping: Record the time and date of each VE inspection, and whether or not any VEs were observed. If VEs were observed, also record a brief description of the type of corrective actions taken, and the date the actions were taken. Minn. R. 7007.0800, subp. 5

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-30

Subject Item: EU 011 Transfer House 5

Associated Items: CE 012 Fabric Filter - Low Temperature, i.e., T<180 Degrees F

SV 012 Transfer House 5 Dust Collector Vent

What to do Why to do it
A . EMISSION & OPERATING LIMITS hdr
Opacity: less than or equal to 20 percent opacity . If opacity exceeds 20 percent, then action must be taken to control exhaust gases so that either

(1) particulate matter emissions do not exceed 0.020 gr/dscf, or (2) opacity does not exceed 20 percent. 40 CFR Section 60.252(c); Minn. R. 7011.1105, subp. (G)

Particulate Matter < 10 micron: less than or equal to 0.008 grains/dry standard cubic foot .

This is a state only requirement and is not enforceable by the EPA Administrator or citizens under the Clean Air Act. Minn. R. 7009.0020

Operating Hours: less than or equal to 5096 hours/year using 12-month Rolling Sum Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.3000 Do not build, erect, install, or use any article, machine, equipment, or process, the use of which conceals an emission which would otherwise constitute a violation of an applicable standard. 40 CFR Section 60.12

B. CONTROL EQUIPMENT REQUIREMENTS hdr
Check for visible emissions (during daylight hours) from the control equipment (CE 012) once each calendar week, while EU 011 is in operation. Minn. R. 7007.0800, subp. 4

Corrective Actions: If visible emissions (VEs) are observed, determine the cause and take corrective actions as soon as possible to eliminate the VEs. Corrective action may be in the form of discontinuing venting emissions to the atmosphere through CE 012. Minn. R. 7007.0800, subp. 2

Recordkeeping: Record the time and date of each VE inspection, and whether or not any VEs were observed. If VEs were observed, also record a brief description of the type of corrective actions taken, and the date the actions were taken. Minn. R. 7007.0800, subp. 5

Solid fuel handling equipment shall not be vented to the atmosphere when emissions are not controlled by the pollution control equipment (CE 012). This emission unit is physically capable of operating without venting to the atmosphere, and therefore can operate when control equipment is not operational. Minn. R. 7007.0800, subp. 2

C. RECORDKEEPING REQUIREMENTS hdr
Daily Recordkeeping: Each day, record the hours of operation of the emissions unit. Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.3000 Monthly Recordkeeping: By the 15th day of each month, calculate and record the 12-month rolling sum of hours operated during the previous 12 months. Minn. R. 7007.0800, subps. 4 & 5

Maintain records of the occurrence and duration of any startup, shutdown, or malfunction in the operation of the facility including any malfunction of the air pollution control equipment, or any periods during which a continuous monitoring system or monitoring device is inoperable. 40 CFR Section 60.7(b); Minn. R. 7019.0100, subp. 1

D. TESTING REQUIREMENTS hdr
Initial Performance Test: due 180 days after Initial Startup of modified conveyors to measure opacity 40 CFR Section 60.8; Minn. R. 7017.2020, subp. 1; Minn. R. 7017.2030, subp. 4 Notification of any physical change or operational change which increases emissions rate: due 60 days (or as soon as practicable) before the change is commenced. Within 180 days of completion of any physical or operational change subject to the control measures specified in 40 CFR Section 60.14(a), compliance with all applicable standards must be achieved. 40 CFR Section 60.7(a)(4); Minn. R. 7019.0100, subp. 1

Notification of the Date Construction Began: due 60 days before start of construction (or as soon as practicable) of replacements. Submit the name and number of each unit and the date of construction of the replacement parts of each unit. 40 CFR Section 60.15(d); Minn. R. 7019.0100, subp. 1

Notification of Anticipated Date for Conducting Opacity Observations: due 30 days prior to observation date. 40 CFR Section 60.7(a)(4); Minn. R. 7019.0100, subp. 1

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-31

Subject Item: EU 015 Boiler 13

Associated Items: SV 017 Boiler 13 Stack

What to do Why to do it
A . EMISSION & OPERATING LIMITS hdr
Opacity: less than or equal to 20 percent opacity using 6-minute Average except for one six-minute period per hour of not more than 60 percent opacity. Minn. R. 7011.0515, subp. 2

Nitrogen Oxides: less than or equal to 0.13 lbs/million Btu heat input Minn. R. 7007.0800, subp. 2

Fuel Usage: limited to natural gas and propane Minn. R. 7007.0800, subp. 2
Steam Flow: less than or equal to 49800 lbs/hour using 24-hour Block Average Minn. R. 7017.2025, subp. 3 (Notice of Compliance for 10/12/2001 performance test) B. RECORDKEEPING REQUIREMENTS hdr
By the last day of each month, record the amount of natural gas and propane combusted during the previous month in EU 015. Records may be in the form of fuel bills or meter readings. 40 CFR Section 60.13(i) to comply with 40 CFR Section 60.48c(g) & (i); Minn. R. 7011.0570 Each calendar day, calculate the previous day's average steam production by dividing the total steam produced during the 24 hours by the total operating time during the 24 hours. Downtime of 15 or more minutes is not to be included in the operating time. Minn. R. 7007.0800, subps. 2 & 5

C. TESTING REQUIREMENTS hdr
Performance Test: due before end of each year starting 01/11/2005 to measure NOx emissions. The NOx emissions tests shall be conducted at an interval not to exceed 12 months between test dates. Minn. R. 7017.2020, subp. 1

Comply with 40 CFR 63, subpart DDDDD, by September 13, 2007. 40 CFR Section 63.7495(b)

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-32

Subject Item: EU 028 Auxiliary Boiler

Associated Items: GP 005 Synthetic Minor Fuel Usage Limits
SV 002 Auxiliary Boiler Stack

What to do Why to do it
A . EMISSION & OPERATING LIMITS (see also GP 005) hdr
Total Particulate Matter: less than or equal to 0.03 lbs/million Btu heat input . This limit applies at all times except during periods of startup, shutdown, and malfunction. (Potential emissions based on equipment design and allowed fuels are approximately 0.07 lb/million Btu heat input.) 40 CFR Section 63.7500(1); 40 CFR Section 63.7505(a); 40 CFR Section 63.7506(a); 40 CFR Section 63.3(f)(1) Hydrochloric acid: less than or equal to 0.0005 lbs/million Btu heat input . This limit applies at all times except during periods of startup, shutdown, and malfunction. 40 CFR Section 63.7500(1); 40 CFR Section 63.7505(a); 40 CFR Section 63.7506(a); 40 CFR Section 63.3(f)(1) Carbon Monoxide: less than or equal to 400 parts per million by volume on a dry basis corrected to 3 percent oxygen (3-run average). This limit applies at all times except during periods of startup, shutdown, and malfunction. (At standard conditions, this is approximately 18 lb/hour; potential emissions under design capacity and fuel limitations are approximately 8.4 lb/hr.) 40 CFR Section 63.7500(1); 40 CFR Section 63.7505(a); 40 CFR Section 63.7506(a); 40 CFR Section 63.3(f)(1)

Sulfur Dioxide: less than or equal to 0.5 lbs/million Btu heat input or, as an alternative, sulfur content of fuel shall not exceed 0.5 percent by weight. These limits apply at all times, including periods of startup, shutdown, or malfunction. 40 CFR Section 60.42c(d); 40 CFR Section 60.42c(i); Minn. R. 7011.0570 Opacity: less than or equal to 20 percent opacity using 6-minute Average , except for one 6-minute period per hour of not more than 27 percent opacity. This limit does not apply during periods of startup, shutdown, or malfunction. 40 CFR Section 60.43c(c); Minn. R. 7011.0570

A ny Permittee requesting permission to use an alternative non-opacity emission standard to achieve a reduction in HAP emissions shall, unless otherwise specified, submit a proposed test plan or the results of testing and monitoring in accordance with Sections 63.7 and 63.8, a description of the procedures followed in testing or monitoring, and a description of pertinent conditions during testing or monitoring. A ny testing or monitoring conducted to request permission to use an alternative nonopacity emission standard shall be appropriately quality assured and quality controlled, as specified in 63.7 and 63.8. 40 CFR Section 63.6(g)(2); Minn. R. 7011.7000

Fuel Usage: limited to natural gas and distillate fuel oil 40 CFR Section 63.7506(a)(2); Minn. R. 7007.0800, subp. 2
A t all times the Permittee shall operate and maintain the emission unit subject to the MACT standard and its associated air pollution control equipment in a manner consistent with good air pollution control practices for minimizing emissions at least to the levels required by all relevant standards, as described at 40 CFR Section 63.6(e)(1)(i). 40 CFR Section 63.6(e)(1)(i); 40 CFR Section 63.7505(b); Minn. R. 7011.7000

During periods of startup, shutdown, and malfunction, the owner or operator of an affected source must operate and maintain such source (including associated air pollution control and monitoring equipment) in accordance with the procedures specified in the startup, shutdown, and malfunction plan developed under 40 CFR Section 63.6(e)(3)(i). 40 CFR Section 63.6(e)(1)(ii); Minn. R. 7011.7000

EU 028 must comply with 40 CFR 63 Subpart DDDDD upon startup. 40 CFR Section 63.6(b); Minn. R. 7011.7000 Develop, implement, and maintain a written startup, shutdown, and malfunction plan (SSMP) according to all of the provisions in 40 CFR Section 63.6(e)(3). The plan must be available for inspection and copying by the Administrator upon request. 40 CFR Section 63.7505(d)(e); 40 CFR Sections 63.3(e)(3)(i), (v), (vi), (vii), & (viii)

During periods of startup, shutdown, and malfunction, the permittee must operate in accordance with the SSMP as required in Sec. 63.7505(e) and 63.3(e)(3)(i). 40 CFR Section 63.7540(c); 40 CFR Section 63.3(e)(3)(ii) When actions taken by the Permittee during a startup, shutdown, or malfunction (including actions taken to correct a malfunction) are consistent with the procedures specified in the affected source's SSMP, the Permittee must keep records for that event which demonstrate that the procedures specified in the plan were followed. These records may take the form of a "checklist," or other effective form of recordkeeping that confirms conformance with the startup, shutdown, and malfunction plan for that event. In addition, the Permittee must keep records of these events as specified in 63.10(b). Furthermore, the Permittee shall confirm that actions taken during the relevant reporting period during periods of startup, shutdown, and malfunction were consistent with the SSMP in the semiannual startup, shutdown, and malfunction report required in 63.10(d)(5). 40 CFR Section 63.3(e)(3)(iii); Minn. R. 7011.7000

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-33

If an action taken by the Permittee during a startup, shutdown, or malfunction (including an action taken to correct a malfunction) is not consistent with the procedures specified in the SSMP, and the source exceeds any applicable emission limitation in the relevant emission standard, then the Permittee must record the actions taken for that event and must report such actions within 2 working days after commencing actions inconsistent with the plan, followed by a letter within 7 working days after the end of the event, in accordance with 63.10(d)(5) (unless the owner or operator makes alternative reporting arrangements, in advance, with the Administrator). 40 CFR Section 63.3(e)(3)(iv); Minn. R. 7011.7000

B. MONITORING & RECORDKEEPING REQUIREMENTS (see also GP005) hdr
The Permittee shall obtain a supplier certification for each shipment of fuel oil received, showing the sulfur content of the shipment or showing less than 0.5% sulfur content. The certification shall include the name of the oil supplier and a statement that the oil complies with the definition of distillate oil. 40 CFR Section 60.44c(h); 40 CFR Section 60.48c(f); Minn. R. 7011.0570

Recordkeeping: By the last day of each month, record the amount of each fuel combusted during the previous month in EU 028. Records may be in the form of fuel bills or meter readings. 40 CFR Section 60.13(i) and February 20, 1992, EPA memorandum to meet the requirements of 40 CFR Section 60.48c(g) & (i); Minn. R. 7011.0570 For each 6-month period after actual startup, submit a report to the Administrator including the following information: - Calendar dates covered in the reporting period - Records of fuel supplier certification, including a statement signed by the owner or operator that the records of fuel supplier certifications represent all of the fuel oil combusted during the reporting period 40 CFR Section 60.48c(d); 40 CFR Section 60.48c(e)(11); 40 CFR Section 60.48c(j); Minn. R. 7011.0570

The Permittee shall maintain files of all information (including all reports and notifications) required by this part recorded in a form suitable and readily available for expeditious inspection and review. The files shall be retained for at least 5 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record. At a minimum, the most recent 2 years of data shall be retained on site. The remaining 3 years of data may be retained off site. Such files may be maintained on microfilm, on a computer, on computer floppy disks, on magnetic tape disks, or on microfiche. 40 CFR Section 63.10(b)(1)

The Permittee shall maintain relevant records of: (i) The occurrence and duration of each startup, shutdown, or malfunction of operation (i.e., process equipment); (ii) The occurrence and duration of each malfunction of the required air pollution control and monitoring equipment; (iii) All required maintenance performed on the air pollution control and monitoring equipment; (iv) Actions taken during periods of startup, shutdown, and malfunction (including corrective actions to restore malfunctioning process and air pollution control and monitoring equipment to its normal or usual manner of operation) when such actions are different from the procedures specified in the SSMP; 40 CFR Section 63.10(b)(2)

(v) All information necessary to demonstrate conformance with the SSMP when all actions taken during periods of startup, shutdown, and malfunction (including corrective actions to restore malfunctioning process and air pollution control and monitoring equipment to its normal or usual manner of operation) are consistent with the procedures specified in such plan. (The information needed to demonstrate conformance with the startup, shutdown, and malfunction plan may be recorded using a "checklist," or some other effective form of recordkeeping, in order to minimize the recordkeeping burden for conforming events); (vi) Each period during which a CMS is malfunctioning or inoperative (including out-of-control period); 40 CFR Section 63.10(b)(2) (continued from above)

(vii) All required measurements needed to demonstrate compliance with a relevant standard (including, but not limited to, 15-minute averages of CMS data, raw performance testing measurements, and raw performance evaluation measurements, that support data that the source is required to report); (viii) All results of performance tests, CMS performance evaluations, and opacity and visible emission observations; (ix) All measurements as may be necessary to determine the conditions of performance tests and performance evaluations; (x) All CMS calibration checks; (xii) Any information demonstrating whether a source is meeting the requirements for a waiver of recordkeeping or reporting requirements under this part, if the source has been granted a waiver under paragraph (f) of this section; (xiv) All documentation supporting initial notifications and notifications of compliance status under Section 63.9. 40 CFR Section 63.10(b)(2) (continued from above)

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-34

1. Notwithstanding the requirements in this paragraph or paragraph (e) of this section, and except as provided in Section 63.16, the Permittee shall submit reports to the Administrator in accordance with the reporting requirements in the relevant standard(s). 2. Reporting results of performance tests. The Permittee shall report the results of a required performance test to the appropriate permitting authority. The Permittee shall report the results of the performance test to the Administrator (or the State with an approved permit program) before the close of business on the 60th day following the completion of the performance test, unless specified otherwise in a relevant standard or as approved otherwise in writing by the Administrator. The results of the performance test shall be submitted as part of the notification of compliance status required under Section 63.9(h). 40 CFR Sections 63.10(d)(1) & (2)

Periodic Startup, Shutdown, and Malfunction Reports (SSMP Reports). The Permittee shall submit SSMP Reports only if there is an occurrence of startup, shutdown, or malfunction during the reporting period and shall be delivered or postmarked by the 30th day following the end of each calendar half year. The content of the report shall meet the requirements of 40 CFR 63.10(d)(5)(i). 40 CFR Section 63.10(d)(5)(i)

Immediate Startup, Shutdown, and Malfunction Report. Any time an action taken by the Permittee during a startup, shutdown, or malfunction (including actions taken to correct a malfunction) is not consistent with the procedures specified in the SSMP, and the source exceeds any applicable emission limitation in the relevant emission standard, the Permittee shall report the actions taken for that event within 2 working days after commencing actions inconsistent with the plan followed by a letter within 7 working days after the end of the event. Refer to 40 CFR Sections 63.10(d)(5)(ii) for additional information regarding the requirements of this report. 40 CFR Section 63.10(d)(5)(ii); 40 CFR Section 63.7550, Table 9

Keep records according to paragraphs (a)(1) through (3) of this section. (1) A copy of each notification and report that was submitted to comply with 40 CFR 63, Subpart DDDDD, including all documentation supporting any Initial Notification or Notification of Compliance Status or semiannual compliance report that was submitted, according to the requirements in Sec. 63.10(b)(2)(xiv). (2) The records in Sec. 63.6(e)(3)(iii) through (v) related to startup, shutdown, and malfunction. (3) Records of performance tests, fuel analyses, or other compliance demonstrations, performance evaluations, and opacity observations as required in Sec. 63.10(b)(2)(viii). 40 CFR Section 63.7555(a)

Keep the records required in Table 8 of 40 CFR 63, Subpart DDDDD including records of all monitoring data and calculated averages for applicable operating limits such as opacity, pressure drop, carbon monoxide, and pH to show continuous compliance with each emission limit, operating limit, and work practice standard that is applicable. 40 CFR Section 63.7555(c)

Records - Form and how long to keep: (a) The records must be in a form suitable and readily available for expeditious review, according to Sec. 63.10(b)(1). (b) As specified in Sec. 63.10(b)(1), the Permittee must keep each record for 5 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record. (c) Keep each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to Sec. 63.10(b)(1). The Permittee can keep the records off site for the remaining 3 years. 40 CFR Section 63.7560

Site-Specific Monitoring (SSM) Plan: The Permitee shall develop a SSM plan according to the requirements in section 63.6(e)(3) for CO emissions. 40 CFR Section 63.7505(e)

C.1. NSPS PERFORMANCE TESTING REQUIREMENTS hdr
Initial Performance Test: due 180 days after Initial Startup, to measure opacity 40 CFR Section 60.8(a); Minn. R. 7017.2020, subp. 1 Performance Test Notification (written): submit notification of the performance test to the EPA Administrator. 40 CFR Section 60.7(a)(6); Minn. R. 7019.0100, subp. 1 Performance Test Report: Submit performance test data from initial and subsequent tests to the EPA Administrator. 40 CFR Section 60.48c(b); Minn. R. 7011.0570
C.2 NESHAP TESTING & COMPLIANCE DEMONSTRATION hdr

Demonstrate initial compliance with the promulgated emission limits and work practice standards no later than 180 days after startup of the source. 40 CFR Section 63.7510(g)

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-35

The Permittee is not required to conduct a performance test to demonstrate compliance with the emission limits. The Permittee is not required to set and maintain operating limits to demonstrate continuous compliance with the emission limits. However, the Permittee must meet the requirements in paragraphs (a)(1) and (2) of this section and meet the CO work practice standard in Table 1 of 40 CFR 63, Subpart DDDDD. (1) To demonstrate initial compliance, include a signed statement in the Notification of Compliance Status report required in Sec. 63.7545(e) that indicates the boiler burns only liquid fossil fuels other than residual oils, either alone or in combination with gaseous fuels. 40 CFR Section 63.7506(a); 40 CFR Section 63.7520(c); 40 CFR Section 63.7530(b)

(2) To demonstrate continuous compliance with the applicable emission limits, keep records that demonstrate that the boiler burns only liquid fossil fuels other than residual oils, either alone or in combination with gaseous fuels. Also include a signed statement in each semiannual compliance report required in Sec. 63.7550 that indicates the boiler burned only liquid fossil fuels other than residual oils, either alone or in combination with gaseous fuels, during the reporting period. 40 CFR Section 63.7506(a); 40 CFR Section 63.7520(c); 40 CFR Section 63.7530(b) (continued from above)

For affected sources that have an applicable work practice standard, initial compliance requirements depend on the subcategory and rated capacity of the boiler or process heater. If the boiler or process heater is in any of the limited use subcategories or has a heat input capacity less than 100 MMBtu per hour, the initial compliance demonstration is conducting a performance test for carbon monoxide. 40 CFR Section 63.7510(c)

Initial Performance Test: due 180 days after 07/31/2006 to measure carbon monoxide emissions.

Testing shall measure CO emissions according to Table 5 in part 63, subpart DDDDD. Conduct annual performance tests for carbon monoxide according to Sec. 63.7520. Each annual performance test must be conducted between 10 and 12 months after the previous performance test. 40 CFR Section 63.7510(c); 40 CFR Section 63.7515(e); 40 CFR Section 63.7(a)(2); Minn. R. 7017.2020, subp. 1

Individual performance tests may be waived upon written application to the A dministrator if, in the Administrator's judgment, the source is meeting the relevant standard(s) on a continuous basis, or the source is being operated under an extension of compliance, or the owner or operator has requested an extension of compliance and the Administrator is still considering that request. Application for waiver of performance tests must meet all requirements in Section 63.7(h). 40 CFR Section 63.7(h); Minn. R. 7017.2015

Performance Tests and Procedures: (a) Conduct all performance tests according to Sec. 63.7(c), (d), (f), and (h). Develop a site-specific test plan according to the requirements in Sec. 63.7(c) if the Permittee elects to demonstrate compliance through performance testing. (b) Conduct each performance test according to the requirements in Table 5 of 40 CFR 63, Subpart DDDDD. (e) The Permittee may not conduct performance tests during periods of startup, shutdown, or malfunction. (f) Conduct three separate test runs for each performance test required in this section, as specified in Sec. 63.7(e)(3). Each test run must last at least 1 hour. 40 CFR Section 63.7520; 40 CFR Sections 63.7(c), (d), (e), (f), & (h); Minn. R. 7017.2015

To conduct a performance test for carbon monoxide, the Permittee must: 1. Select the sampling ports location and the number of traverse points using Method 1 in appendix A to part 60 of this chapter, 2. Determine oxygen and carbon dioxide concentrations of the stack gas using Method 3A or 3B in appendix A to part 60 of this chapter, or ASTM D6522-00 (IBR, see Sec. 3.14(b)), or ASME PTC 19, Part 10 (1981) (IBR, see Sec. 63.14(i)), 3. Measure the moisture content of the stack gas using Method 4 in appendix A to part 60 of this chapter, and 4. Measure the carbon monoxide emission concentration using Method 10, 10A, or 10B in appendix A to part 60 of this chapter, or ASTM D6522-00 (IBR, see Sec. 63.14(b)) when the fuel is natural gas. 40 CFR Section 63.7520

In the event the owner or operator is unable to conduct the performance test on the date specified in the notification requirement specified in Section 63.7545(d) due to unforeseeable circumstances beyond his or her control, the Permittee must notify the Administrator as soon as practicable and without delay prior to the scheduled performance test date and specify the date when the performance test is rescheduled. This notification of delay in conducting the performance test shall not relieve the Permittee of legal responsibility for compliance with any other applicable provisions of this part or with any other applicable Federal, State, or local requirement, nor will it prevent the Administrator from implementing or enforcing this part or taking any other action under the Act. 40 CFR Section 63.7(b)(2); Minn. R. 7017.2015

D. NOTIFICATION & REPORTING REQUIREMENTS hdr

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-36

Notification of Intent to Construct: Due as soon as practicable after promulgation of 40 CFR 63 Subpart DDDDD, and before construction begins. The application for approval of construction may be used to fulfill the initial notification requirements of 40 CFR Section 63.9(b)(5), the Notice of Initial Compliance The application must include: - The applicant's name and address - A notification of intention to construct a new major affected source - The address (physical location) or proposed address of the source - An identification of the relevant standard that is the basis of the application - The expected date of beginning of actual construction - The expected completion date of the construction 40 CFR Section 63.5(d); 40 CFR Section 63.9(b)(1)(iii); 40 CFR Section 63.7545; Minn. R. 7011.7000; Minn. R. 7019.0100

- The type and quantity of HAPs emitted by the source, reported in units and averaging times and in accordance with the test methods specified in the relevant standard, or if actual emissions data are not yet available, an estimate of the type and quantity of HAPs expected to be emitted by the source reported in units and averaging times specified in the relevant standard. The owner or operator may submit percent reduction information if a relevant standard is established in terms of percent reduction. However, operating parameters, such as flow rate, shall be included in the submission to the extent that they demonstrate performance and compliance. - Certification that the source will not burn residual fuels (to satisfy requirements of Initial Notification of Compliance Status) 40 CFR Section 63.5(d); 40 CFR Section 63.9(b)(1)(iii); 40 CFR Section 63.9(b)(4)(i); 40 CFR Section 63.7545; Minn. R. 7011.7000; Minn. R. 7019.0100 (continued from above)

Submit the Notification of Compliance Status containing the results of the initial compliance demonstration according to the requirements in 63.7545(e). Must include all performance test results and fuel analyses and/or other compliance demonstrations. The Notification of Compliance Status report must contain all the information specified in paragraphs (e)(1) through (9), as applicable, and meet all applicable requirements of Section 63.9(h). 40 CFR Section 63.7530(e); 40 CFR Section 63.7545(e); 40 CFR Section 63.9(h); Minn. R. 7019.0100

(1) A description of the affected source(s) including identification of which subcategory the source is in, the capacity of the source, a description of the add-on controls used on the source description of the fuel(s) burned, and justification for the fuel(s) burned during the performance test. (2) Summary of the results of all performance tests, fuel analyses, and calculations conducted to demonstrate initial compliance including all established operating limits. (3) Identification of compliance with the particulate matter emission limit or the alternative total selected metals emission limit. (4) Identification of whether the Permittee plans to demonstrate compliance with each applicable emission limit through performance testing or fuel analysis. (5) Identification of whether the Permittee plans to demonstrate compliance by emissions averaging. 40 CFR Section 63.7530(e); 40 CFR Section 63.7545(e); 40 CFR Section 63.9(h); Minn. R. 7019.0100 (continued from above)

(6) A signed certification that all applicable emission limits and work practice standards have been met. (7) A summary of the carbon monoxide emissions monitoring data and the maximum carbon monoxide emission levels recorded during the performance test to show that the Permittee has met any applicable work practice standard in Table 1 of 40 CFR 63, Subpart DDDDD. (8) If the new or reconstructed boiler or process heater is in one of the liquid fuel subcategories and burns only liquid fossil fuels other than residual oil either alone or in combination with gaseous fuels, submit a signed statement certifying this in the Notification of Compliance Status report. (9) If the Permittee had a deviation from any emission limit or work practice standard, submit a description of the deviation, the duration of the deviation, and the corrective action taken in the Notification of Compliance Status report. 40 CFR Section 63.7530(e); 40 CFR Section 63.7545(e); 40 CFR Section 63.9(h); Minn. R. 7019.0100 (continued from above)

Report each deviation from an applicable emission limit, operating limit, and work practice standard in Tables 1 through 4 of 40 CFR 63, Subpart DDDDD that apply. The Permittee must also report each instance during a startup, shutdown, or malfunction when each applicable emission limit, operating limit, and work practice standard was not met. These instances are deviations from the emission limits and work practice standards in this subpart. These deviations must be reported according to the requirements in Sec. 63.7550. 40 CFR Section 63.7540(b)

Consistent with Sec. 63.6(e) and 63.7(e)(1), deviations that occur during a period of startup, shutdown, or malfunction are not violations if you demonstrate to the EPA A dministrator's satisfaction that you were operating in accordance with your SSMP. The EPA Administrator will determine whether deviations that occur during a period of startup, shutdown, or malfunction are violations, according to the provisions in Sec. 63.6(e). 40 CFR Section 63.7540(d)

The Permittee must meet the notification requirements in Sec. 63.7545 according to the schedule in Sec. 63.7545 and in subpart A of this part. Some of the notifications must be submitted before compliance with the emission limits and work practice standards in this subpart is required. 40 CFR Section 63.7495(d)

Submit all of the notifications in Sec. 63.7(b) and (c), 63.8(e), (f)(4) and (6), and 63.9(b) through (h) that apply by the dates specified. 40 CFR Section 63.7545(a)

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-37

Semiannual Compliance Report: Unless the EPA Administrator has approved a different schedule for submission of reports under Sec. 63.10(a), submit a semiannual compliance report according to the dates required in paragraphs (b)(1) through (5) of 40 CFR 63.7550(b). The compliance report must contain the information required in paragraphs (c)(1) through (11) of 40 CFR 63.7550(c) . (1) Company name and address. (2) Statement by a responsible official with that official's name, title, and signature, certifying the truth, accuracy, and completeness of the content of the report. (3) Date of report and beginning and ending dates of the reporting period. (4) The total fuel use by each affected source subject to an emission limit, for each calendar month within the semiannual reporting period, including, but not limited to, a description of the fuel and the total fuel usage amount with units of measure. (5) Not Applicable 40 CFR Sections 63.7550(b) & (c); 40 CFR Section 63.7550, Table 9

(6) A signed statement indicating that the boiler burned no new types of fuel. (7) Not Applicable (8) Not Applicable (9) If the boiler had a startup, shutdown, or malfunction during the reporting period and the Permittee took actions consistent with the SSMP, the compliance report must include the information in Sec. 63.10(d)(5)(i). (10) If there are no deviations from any emission limits or operating limits in 40 CFR 63, Subpart DDDDD that apply, and there are no deviations from the requirements for work practice standards in this subpart, a statement that there were no deviations from the emission limits, operating limits, or work practice standards during the reporting period. (11) Not Applicable 40 CFR Sections 63.7550(b) & (c); 40 CFR Section 63.7550, Table 9 (continued from above)

For each deviation from an emission limit or operating limit in 40 CFR 63, Subpart DDDDD and for each deviation from the requirements for work practice standards in this subpart that occurs at an affected source where the Permittee is not using a CMSs to comply with that emission limit, operating limit, or work practice standard, the compliance report must contain the information in paragraphs (c)(1) through (10) of this section and the information required in paragraphs (d)(1) through (4) of this section. This includes periods of startup, shutdown, and malfunction. (1) The total operating time of each affected source during the reporting period. (2) A description of the deviation and which emission limit, operating limit, or work practice standard from which was deviated. (3) Information on the number, duration, and cause of deviations (including unknown cause), as applicable, and the corrective action taken. (4) Not Applicable 40 CFR Section 63.7550(d)

Each affected source that has obtained a title V operating permit pursuant to 40 CFR part 70 or 40 CFR part 71 must report all deviations as defined in 40 CFR 63, Subpart DDDDD in the semiannual monitoring report required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A). If an affected source submits a compliance report pursuant to Table 9 of 40 CFR 63, Subpart DDDDD along with, or as part of, the semiannual monitoring report required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A), and the compliance report includes all required information concerning deviations from any emission limit, operating limit, or work practice requirement in this subpart, submission of the compliance report satisfies any obligation to report the same deviations in the semiannual monitoring report. However, submission of a compliance report does not otherwise affect any obligation the affected source may have to report deviations from permit requirements to the permit authority. 40 CFR Section 63.7550(f)

Request for extension of compliance. If the owner or operator of an affected source cannot comply with a relevant standard by the applicable compliance date for that source, or if the owner or operator has installed BACT or technology to meet LAER consistent with 63.6(i)(5) of this subpart, he/she may submit to the A dministrator (or the State with an approved permit program) a request for an extension of compliance as specified in 63.6(i)(4) through 63.6(i)(6). 40 CFR Section 63.9(c); Minn. R. 7019.0100, subp. 2

Notification that source is subject to special compliance requirements. A n owner or operator of a new source that is subject to special compliance requirements as specified in 63.6(b)(3) and 63.6(b)(4) shall notify the Administrator of his/her compliance obligations not later than the notification dates established in Section 63.9(b). 40 CFR Section 63.9(d); Minn. R. 7019.0100, subp. 2

A ny change in the information already provided under Section 63.9 shall be provided to the Administrator in writing within 15 calendar days after the change 40 CFR Section 63.9(j); Minn. R. 7019.0100, subp. 2

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-38

Subject Item: CE 015 SCR (Selective Catalytic Reduction)

Associated Items: EU 001 Boiler 1
MR 007 NOX Analyzer

What to do Why to do it
A . OPERATING REQUIREMENTS hdr
Operate and maintain the SCR at all times that EU 001 is in operation except during times of start-up, shutdown, or malfunction (as defined in EU 001). This requirement is effective 270 days after the first firing of the boiler with fuels other than natural gas following the rehabilitation project. Minn. R. 7007.0800, subps. 2 & 14

A mmonia Injection Rate: Normal operating range to be determined based on the injection rate observed during the first 180 days of SCR operation. The rate or range may be expressed numerically, mathematically, or graphically, to account of the condition and age of the catalyst.

During times that MR 007 is not in operation, the Permittee shall read and record the ammonia injection rate at a minimum of once every 24 hours when the SCR is in operation. Title I Condition: To avoid classification as a major amendment under 40 CFR Section 52.21; Minn. R. 7007.3000

Monitoring Equipment: The Permittee shall install and maintain the necessary monitoring equipment for measuring and recording ammonia injection rate as required by this permit. The monitoring equipment must be installed, in use, and properly maintained when the SCR is in operation. Minn. R. 7007.0800, subp. 4

B. MONITORING AND RECORDKEEPING REQUIREMENTS hdr

During times when the Permittee is required to manually monitor ammonia injection rate, the Permittee shall record the time and date of each ammonia injection rate reading and whether or not the recorded value was within the Normal Operating Range determined in the above requirement. Minn. R. 7007.0800, subps. 4 & 5

Periodic Inspections: At least semiannually, or more frequently as required by the manufacturing specifications, the Permittee shall inspect the control equipment components. The Permittee shall maintain a written record of these inspections. Minn. R. 7007.0800, subps. 4, 5 & 14

Corrective Actions: The Permittee shall take corrective action as soon as possible if any of the following occur:

- The recorded ammonia injection rate is outside the required operating range; or - The SCR or any of its components are found during the inspections to need repair.

Corrective actions shall return the ammonia injection rate to within the permitted range, and/or include completion of necessary repairs identified during the inspection, as applicable. Corrective actions include, but are not limited to, those outlined in the O&M Plan for the fabric filter. The Permittee shall keep a record of the type and date of any corrective action taken for the SCR. Minn. R. 7007.0800, subps. 4, 5, & 14

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-39

Subject Item: CE 016 Spray Dryer

Associated Items: EU 001 Boiler 1
MR 006 SO2 Analyzer

What to do Why to do it
A . OPERATING REQUIREMENTS hdr
Operate and maintain the spray dryer at all times EU 001 is in operation except during times of start-up, shutdown, or malfunction (as defined in EU 001). This requirement is effective 270 days after the first firing of the boiler with fuels other than natural gas following the rehabilitation project. Minn. R. 7007.0800, subps. 2 & 14

Lime Injection Rate: Normal operating range to be determined, based on the injection rate observed during the first 180 days of spray dryer operation.

During times that MR 006 is not in operation, the Permittee shall read and record the lime injection rate at a minimum of once every 24 hours when the spray dryer is in operation. Title I Condition: To avoid classification as a major amendment under 40 CFR Section 52.21; Minn. R. 7007.3000

Monitoring Equipment: The Permittee shall install and maintain the necessary monitoring equipment for measuring and recording lime injection rate as required by this permit. The monitoring equipment must be installed, in use, and properly maintained when the spray dryer is in operation. Minn. R. 7007.0800, subp. 4

B. MONITORING AND RECORDKEEPING REQUIREMENTS hdr

During times when the Permittee is required to manually monitor lime injection rate, the Permittee shall record the time and date of each lime injection rate reading and whether or not the recorded value was within the Normal Operating Range determined in the above requirement. Minn. R. 7007.0800, subp. 4 & 5

Periodic Inspections: At least semiannually, or more frequently as required by the manufacturing specifications, the Permittee shall inspect the control equipment components. The Permittee shall maintain a written record of these inspections. Minn. R. 7007.0800, subp. 4, 5 & 14

Corrective Actions: The Permittee shall take corrective action as soon as possible if any of the following occur:

- The recorded lime injection rate is outside the required operating range; or - The spray dryer or any of its components are found during the inspections to need repair.

Corrective actions shall return the lime injection rate to within the permitted range, and/or include completion of necessary repairs identified during the inspection, as applicable. Corrective actions include, but are not limited to, those outlined in the O&M Plan for the fabric filter. The Permittee shall keep a record of the type and date of any corrective action taken for the spray dryer. Minn. R. 7007.0800, subp. 4, 5, & 14

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-40

Subject Item: CE 017 Fabric Filter - High Temperature, i.e., T>250 Degrees F

Associated Items: EU 001 Boiler 1
MR 009 Opacity Monitor

What to do Why to do it
A . OPERATING REQUIREMENTS hdr
Operate and maintain the fabric filter at all times that EU 001 is in operation. This requirement is effective 270 days after the first firing of the boiler with fuels other than natural gas following the rehabilitation project. Minn. R. 7007.0800, subps. 2 & 14

Monitoring Equipment: The Permittee shall install and maintain the necessary monitoring equipment for measuring and recording pressure drop as required by this permit. The monitoring equipment must be installed, in use, and properly maintained when the monitored fabric filter is in operation. Minn. R. 7007.0800, subp. 4

B. MONITORING AND RECORDKEEPING REQUIREMENTS hdr
Pressure Drop: greater than or equal to 0.5 inches of water column and less than or equal to 10 inches of water column unless a new range is set pursuant to Minn. R. 7017.2025 subp. 3, based on the values recorded during the most recent MPCA approved performance test where compliance was demonstrated. During times that MR009 is not in operation, the Permittee shall record the pressure drop once every 24 hours when in operation. Title I Condition: To avoid classification as a major modification under 40 CFR Section 52.21; Minn. R. 7007.3000; Minn. R. 7007.0800, subps. 2 & 14

During times when the Permittee is required to manually monitor the pressure drop, the Permittee shall record the time and date of each pressure drop reading and whether or not the recorded pressure drop was within the range specified in this permit. Minn. R. 7007.0800, subps. 4 & 5

Periodic Inspections: At least semiannually, or more frequently as required by the manufacturing specifications, the Permittee shall inspect the control equipment components. The Permittee shall maintain a written record of these inspections. Minn. R. 7007.0800, subps. 4, 5 & 14

Corrective Actions: The Permittee shall take corrective action as soon as possible if any of the following occur:

- Visible emissions are observed; - The recorded pressure drop is outside the required operating range; or - The fabric filter or any of its components are found during the inspections to need repair.

Corrective actions shall return the pressure drop to within the permitted range, eliminate visible emissions, and/or include completion of necessary repairs identified during the inspection, as applicable. Corrective actions include, but are not limited to, those outlined in the O&M Plan for the fabric filter. The Permittee shall keep a record of the type and date of any corrective action taken for each filter

. Minn. R. 7007.0800, subps. 4, 5 & 14

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-41

Subject Item: FS 003 North Live Coal Pile

What to do Why to do it (1) Control fugitive particulate emissions by dust suppression methods on such operations so that fugitive particulate emission are minimized. (2) In the alternative, use an underground bottom feed (plow) of coal to an underground conveyor system provided the exhaust gases from the enclosed spaces do not contain particulate matter in excess of 0.020 grains per dry standard cubic foot (gr/dscf). Minn. R. 7011.1105, subps. (F)(1) & (2)

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-42

Subject Item: FS 004 South Live Coal Pile

What to do Why to do it (1) Control fugitive particulate emissions by dust suppression methods on such operations so that fugitive particulate emission are minimized. (2) In the alternative, use an underground bottom feed (plow) of coal to an underground conveyor system provided the exhaust gases from the enclosed spaces do not contain particulate matter in excess of 0.020 grains per dry standard cubic foot (gr/dscf). Minn. R. 7011.1105, subps. (F)(1) & (2)

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-43

Subject Item: FS 008 Fly Ash Loadout

Associated Items: CE 025 Process Enclosed

What to do Why to do it
The Permittee shall install and maintain an enclosure to control emissions from the fly ash loadout operation. Minn. R. 7007.0800, subp. 2

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-44

Subject Item: FS 014 Petroleum Coke Unloading Station (Inactive, reactivation will require new modeling demonstration)

Associated Items: CE 025 Process Enclosed
GP 003 Coal Handling and Coal Yard Traffic - Limited Operation

What to do Why to do it Truck and hauler unloading stations: Control fugitive particulate emissions from the unloading of coal and petroleum coke from trucks or haulers by dust suppression methods so that emissions from such sources are minimized. Minn. R. 7011.1105, subp. C

A fter first firing of EU 001 following rehabilitation, in order to receive petroleum coke, the Permittee shall install and maintain an enclosure to control emissions from the petroleum coke unloading operation. Minn. R. 7007.0800, subp. 2

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-45

Subject Item: FS 016 Cooling towers 11-14

Associated Items: GP 011 22 cooling towers (used for PTE accounting only)

What to do Why to do it Total Particulate Matter: less than or equal to 0.3 grains/dry standard cubic foot of exhaust gas unless required to further reduce emissions to comply with the less stringent limit of either Minn. R. 7011.0730 or Minn. R. 7011. 0735. (The calculated limit at maximum operation is approximately 0.02 gr/dscf; calculated potential emissions are approximately 0.000044 gr/dscf) Minn. R. 7011.0715, subp. 1(A)

### TABLE A: LIMITS AND OTHER REQUIREMENTS 02/27/07 Xcel Energy - Allen S King Generating

16300005 - 007 Facility Name:

Permit Number: A-46

Subject Item: MR 010 Hg CEMS

Associated Items: EU 001 Boiler 1

What to do Why to do it Install: due before 07/01/2007, a mercury CEMS to monitor mercury emissions from EU 001. Minn. Stat. 216B.681

CEM Certification Test: due 30 days after Excess Emissions/Downtime Reports (EER's) are first required for the CEMS. The first EER is due 30 days after the end of the calendar quarter following 07/01/2007. Follow the Certification Procedures in 40 CFR Section 75.80(d). Minn. R. 7017.1050, subp. 1; Minn. R. 7017.1110

CEMS QA/QC: The owner or operator shall meet the applicable QA/QC requirements in 40 CFR Section 75.80(e). Minn. Stat. 216B.681

CEMS Relative Accuracy Test Audit (RATA): due before end of each year following CEM Certification Test. A RATA is not required in any calendar year if a RATA conducted in the previous year demonstrated a relative accuracy value of less than 15 percent or if the associated emissions unit operated less than 48 hours during the calendar year. If the exception is used, the next RATA shall be conducted during the first half of the following calendar year. RATAs may be conducted using an alternate test method as approved by the MPCA. 40 CFR Section 75.80(e); Minn. R. 7017.1170, subp. 5

Recordkeeping and Reporting: Follow the provisions listed under 40 CFR Section 75.84. This requirement is effective beginning January 1, 2009. Minn. Stat. 216B.681

### TABLE B: SUBMITTALS
Facility Name: Xcel Energy - Allen S King Generating

Permit Number: 16300005 - 007 02/27/07 B-1

Table B lists most of the submittals required by this permit. Please note that some submittal requirements may appear in Table A or, if applicable, within a compliance schedule located in Table C. Table B is divided into two sections in order to separatel y list one-time only and recurrent submittal requirements.

Each submittal must be postmarked or received by the date specified in the applicable Table. Those submittals required by part s 7007.0100 to 7007.1850 must be certified by a responsible official, defined in Minn. R. 7007.0100, subp. 21. Other submittals shall be certified as appropriate if certification is required by an applicable rule or permit condition.

Send any application for a permit or permit amendment to:

AQ Permit Technical Advisor Industrial Division Minnesota Pollution Control Agency 520 Lafayette Road North St. Paul, Minnesota 55155-4194

Also, where required by an applicable rule or permit condition, send to the Permit Technical Advisor notices of: - accumulated insignificant activities, - installation of control equipment, - replacement of an emissions unit, and - changes that contravene a permit term.

Unless another person is identified in the applicable Table, send all other submittals to:

AQ Compliance Tracking Coordinator Industrial Division Minnesota Pollution Control Agency 520 Lafayette Road North St. Paul, Minnesota 55155-4194

Send submittals that are required to be submitted to the U.S. EPA regional office to:

Mr. George Czerniak Air and Radiation Branch EPA Region V 77 West Jackson Boulevard Chicago, Illinois 60604

Send submittals that are required by the Acid Rain Program to:

U.S. Environmental Protection Agency Clean Air Markets Division 1200 Pennsylvania Avenue NW (6204N) Washington, D.C. 20460

### TABLE B: ONE TIME SUBMITTALS OR NOTIFICATIONS
Facility Name: Xcel Energy - Allen S King Generating

Permit Number: 16300005 - 007 02/27/07 B-2

What to send When to send Portion of Facility Affected
A pplication for Permit Reissuance due 180 days before expiration of Existing Permit Total Facility

Initial Compliance Status Report due 120 days after Start Of Construction. Notification must include certification that the boiler will not burn residual fuel oil. This notification can be satisfied with Application for Construction Approval. EU028

Notification of compliance status due 60 days after Initial Performance Test EU028 Notification of the Actual Date of Initial Startup due 15 days after Initial Startup EU004, EU006, EU011, EU017, EU018, EU028, FS017 Notification of the Actual Date of Initial Startup due 15 days after Initial Startup. For the purposes of this permit, "Initial Startup" means the first firing of the boiler following the rehabilitation project. EU001

Notification of the Date Construction Began due 30 days after 08/28/2006. Submit the name and number of each unit and the date construction of each unit began. EU011

Notification of the Date Construction Began due 30 days after Start Of Construction. Submit the name and number of each unit and the date construction of each unit began. EU004, EU006

Notification of the Date Construction Began due 30 days after Start Of Construction. Submit the name and number of the unit and the date construction began. EU018

Notification of the Date Construction Began due 30 days after Start Of Construction. Submit the name and number of the unit and the date construction began. EU017

Notification of the Date Construction Began due 30 days after Start Of Construction. Submit the name and number of each unit and the date construction of each unit began. EU028

Notification of the Date Construction Began due 60 days before Start Of Construction (or as soon as practicable) of Replacements. Submit the name and number of each unit and the date of construction of the replacement parts of each unit begun.

The Permittee submitted notifications for EU 016 and EU 019. GP004

Notification due 15 days after Startup. For the purposes of this requirement, "Startup" means the first firing of the boiler with fuels other than natural gas following the rehabilitation project. EU001

Notification due 30 days before Performance Test required under 40 CFR 63 Subpart DDDDD is scheduled to begin, submit Notification of Intent to conduct a performance test. EU028

Notification due 60 days before 07/01/2007 for the installation of the Hg CEMS. The notification shall include plans and drawings of the proposed system which show the configuration of the monitoring system including any monitor bypass routes. MR010

Performance Test Report due 60 days after Performance Test required by 40 CFR 63 Subpart DDDDD. This report should also verify that the operating limits for the affected source have not changed or provide documentation of revised operating parameters established according to Sec. 63.7530 and Table 7 of 40 CFR 63, Subpart DDDDD, as applicable. The reports for all subsequent performance tests and fuel analyses should include all applicable information required in Sec. 63.7550. Follow the data analysis, recordkeeping, and reporting requirements in Section 63.7(g). EU028

Relative Accuracy Test Audit (RATA) Notification due 30 days before CEMS Relative Accuracy Test Audit (RATA) MR010

### TABLE B: ONE TIME SUBMITTALS OR NOTIFICATIONS
Facility Name: Xcel Energy - Allen S King Generating

Permit Number: 16300005 - 007 02/27/07 B-3

Submittal due 120 days after 11/12/2004, Initial Notification for 40 CFR 63, Subpart DDDDD. Submittal must include applicable information from 40 CFR Section 63.7545(b)(1) and (2). EU007, EU008

Submittal due 120 days after 11/12/2004, Initial Notification for 40 CFR 63, Subpart DDDDD. Submittal must include applicable information from 40 CFR Sections 63.7545(b)(1) and (2). EU015

Submittal due 200 days after Initial Startup, submit information documenting the normal ammonia injection rate observed during the first 180 days of operation when the NOX monitor showed NOX emissions to be at or below the NOX limit prescribed under Subject Item EU 001. Information may be numerical, mathematical, or graphical, as necessary, to depict the predicted variation of required ammonia injection rate with the age and condition of the catalyst. CE015

Submittal due 200 days after Initial Startup, submit information documenting the normal lime injection rate observed during the first 180 days of operation when the SO2 monitor showed SO2 emissions to be at or below the SO2 limit prescribed under Subject Item EU 001. CE016

Testing Frequency Plan due 60 days after Initial Performance Test for opacity emissions. The plan shall specify a testing frequency based on the test data and MPCA guidance. Future performance tests based on one-year (12 month), 36 month, and 60 month intervals, or as applicable, shall be required upon written approval of the MPCA. EU028

Testing Frequency Plan due 60 days after Initial Performance Test for opacity. The plan shall specify a testing frequency based on the test data and MPCA guidance. Future performance tests based on one-year (12 month), 36 month, and 60 month intervals, or as applicable, shall be required upon written approval of the MPCA. EU004, EU006, EU011

Testing Frequency Plan due 60 days after Initial Performance Test to measure Opacity. GP004

Testing Frequency Plan due 60 days after Performance Test for PM and PM10 emissions. The plan shall specify a testing frequency based on the test data and MPCA guidance. Future performance tests based on 1-year (12 month), 36 month, and 60 month intervals, or as applicable, shall be required upon written approval of the MPCA. EU001

### TABLE B: RECURRENT SUBMITTALS
Facility Name: Xcel Energy - Allen S King Generating

Permit Number: 16300005 - 007 02/27/07 B-4

What to send When to send Portion of Facility Affected Compliance Certification due 30 days after end of each calendar quarter starting 01/01/2009 MR010

Excess Emissions/Downtime Reports (EER's) due 30 days after end of each calendar quarter starting 07/21/1998. Submit Deviations Reporting Form DRF-1 as amended. The EER shall indicate all periods of monitor bypass and all periods of exceedances of the limit including exceedances allowed by an applicable standard, i.e. during startup, shutdown, and malfunctions. The EER must be submitted even if there were no excess emissions, downtime or bypasses during the quarter.

The first EER for the Hg monitor is due 10/30/2007. SV001

Relative Accuracy Test Audit (RATA) Results Summary due 30 days after end of each calendar quarter following CEMS Relative Accuracy Test Audit (RATA) MR010

Submittal due 30 days after end of each calendar quarter starting 07/01/2007, the Hg reporting data specified in the MPCA approved Hg monitoring plan submitted by the facility.

This requirement will expire on 2-22-2010. SV001

Semiannual Continuous Compliance Report due 30 days after end of each calendar half-year following Initial Startup EU028

Semiannual Deviations Report due 30 days after end of each calendar half-year starting 07/21/1998. The first semiannual report submitted by the Permittee shall cover the calendar half-year in which the permit is issued. The first report of each calendar year covers January 1 - June 30. The second report of each calendar year covers July 1 - December 31. If no deviations have occured, the Permittee shall submit the report stating no deviations. Total Facility

Compliance Certification Report (Acid Rain Program) due 60 days after end of each calendar year starting 01/01/2000 an annual compliance certification report for the unit in accordance with 40 CFR Section 72.90(a). The report shall include all information required by 40 CFR Sections 72.90(b) and 72.90(c) EU001

Compliance Certification due 30 days after end of each calendar year starting 07/21/1998 . This is the annual compliance certification report, covering all deviations experienced during the calendar year. Total Facility

## APPENDIX MATERIAL Facility Name: Xcel Energy – Allen S King Generating Permit Number: 16300005-007

GP 005 Calculation

Equation B.1 

# [ ] 

# ∑

= = 

## × × =

oil fuel gas, natural coal, coke, j 028 EU 001, EU i j i, j i, 

## lb 2000

ton 1 HI EF (tpy) VOC

Where:
i = emission units (EU 001, EU 028) j = fuels used in the previous 12-month period, including coal, coke, natural gas, and/or fuel oil

EF = VOC emission factor obtained from the most recent version of AP- 42 or the most recent stack test approved by the MPCA, if any, for each emissi on unit and each fuel (lb VOC/mmBtu heat input) HI = 12-month rolling sum heat input for each fuel (mmBtu)APPENDIX C PM10Modeling ParametersFacility Name: Xcel Energy - Allen S. King Generating PlantPermit Number: 16300005-006PM10Modeling ParametersThe following stack and emission parameters were used in the modeling analysis submitted August 16,2004. Revision of any of these parametersmust result in plume dispersion characteristics equivalent to orbetter than the plume dispersion characteristics modeled and summarized in themodel submitted August 16, 2004. Revision of any ofthese parameters may require a major amendment.SVIDNo.Source Description ModeledHeight(feet)ModeledDiameter1(feet)Stack ExitVelocity(feet/sec)DirectionofFlowModeledTemperature(°F)24-HourModeledPM10(lb/hr)AnnualModeled PM10(lb/hr)001 Main Boiler 785.1 18.5 95.5 Vertical 169 300 300003 Coal Gallery 145 3.4 51.5 Vertical 70 1.92 1.92004 Transfer House 1 21.3 2.5 78.1 Vertical 70 1.58 1.58005 Coal Crusher House 76.4 3.28 45.3 Vertical 70 1.58 1.58006 Railcar Unloading 32.8 3 163.4 Vertical 70 4.66 4.66007 Railcar Unloading 32.8 3 163.4 Vertical 70 4.66 4.66008 Boiler 11 40.0 4 91.5 Vertical 525 5.33 1.63009 Boiler 12 27.9 3 41.0 Vertical 550 5.33 1.63011 Transfer House 2 26.6 2.7 47.9 Vertical 70 1.13 1.13012 Transfer House 5 15.7 2.7 54.5 Vertical 70 1.28 1.28013 Emergency Generator 40.0 1.3 169.3 Vertical 891 0.80 0.071014 Emergency Generator 40.0 1.3 169.3 Vertical 891 0.80 0.071017 Boiler 13 27.9 3 41.0 Vertical 550 0.46 0.46018 Flite Conveyors 104.0 3.3 31.5 Vertical 70 1.1 1.1020 Emergency Generator 14.1 0.3 0.003 Horizontal 1150 0.03 0.03023 Emergency Generator 11.10.3 377 Vertical 936 0.27 0.27024 Propane Vaporizer 1 6.9 1 11.5 Vertical 550 0.014 0.014025 Propane Vaporizer 2 6.9 1 11.5 Vertical 550 0.014 0.014026 Radio System EmergencyGenerator14.1 0.3 0 Horizontal 1150 0.029 0.029028 Fire Pump Engine 16.1 0.3 293.3 Vertical 855 0.044 0.044029 Lime Day Bin 68 3.3 0.003 Horizontal 70 0.21 0.21SVIDNo.Source Description ModeledHeight(feet)ModeledDiameter1(feet)Stack ExitVelocity(feet/sec)DirectionofFlowModeledTemperature(°F)24-HourModeledPM10(lb/hr)AnnualModeled PM10(lb/hr)030 Lime Storage Silo 118 3.3 0.003 Horizontal 70 0.15 0.15031 Byproduct/Fly Ash Storage 123.0 3 0.003 Horizontal 70 0.56 0.56032 Byproduct/Fly Ash Storage 115 3 0.003 Horizontal 70 0.42 0.42033 Byproduct/Fly Ash Transfer 50 1.6 0.003 Horizontal 70 0.33 0.33034 Byproduct/Fly Ash Transfer 50 1.6 0.003 Horizontal 70 0.33 0.33035 Byproduct/Fly Ash Transfer 50 1.6 53.8 Vertical 70 0.33 0.33036 Fly Ash Silo 105.8 1.46 0.003 Horizontal 283 0.27FS016Cooling Tower 11 60.3 35.8 20.3 Vertical700.021 0.010FS016Cooling Tower 1260.3 35.820.3 Vertical700.0210.010FS016Cooling Tower 1360.3 35.820.3 Vertical700.0210.010FS016Cooling Tower 1460.3 35.820.3 Vertical700.0210.010FS017Cooling Tower 1567.3 32.2 25.3 Vertical700.0210.010FS017Cooling Tower 1667.332.225.3 Vertical700.0210.010FS017Cooling Tower 1767.332.225.3 Vertical700.0210.010FS017Cooling Tower 1867.332.225.3 Vertical700.0210.010FS017Cooling Tower 1967.332.225.3 Vertical700.0210.010FS017Cooling Tower 2067.332.225.3 Vertical700.0210.010FS017Cooling Tower 2167.332.225.3 Vertical700.0210.010FS017Cooling Tower 2267.332.225.3 Vertical700.0210.010FS017Cooling Tower 2367.332.225.3 Vertical700.0210.010FS017Cooling Tower 2467.332.225.3 Vertical700.0210.010FS017Cooling Tower 2567.332.225.3 Vertical700.0210.010FS017Cooling Tower 2667.332.225.3 Vertical700.0210.010FS017Cooling Tower 2767.332.225.3 Vertical700.0210.010FS017Cooling Tower 2867.332.225.3 Vertical700.0210.010FS017Cooling Tower 2967.332.225.3 Vertical700.0210.010FS017Cooling Tower 3067.332.225.3 Vertical700.0210.010FS017Cooling Tower 3167.332.225.3 Vertical700.0210.010FS017Cooling Tower 3267.332.225.3 Vertical700.0210.0101If the stack is not round (i.e., it is rectangular), thisis the equivalent diameterused in the modeling analysis

## APPENDIX D Insignificant Activities Facility Name : Xcel Energy - Allen S. King Generating Plant Permit Number : 16300005-006

The tables below lists the insignificant activities that are currently at the facility and their associated general applicable requirements.



## Insignificant Activities and Applicable Requirements

Minn. R. 7007.1300,

subpart Rule Description of the Activity Applicable Requirement

3(B) Furnaces, boilers, and incinerators: 2. fuel burning equipment with a capacity less than 500,000 Btu/hour but only if the total combined capacity of all fuel burning equipment at the stationary source with a capacity less than 500,000 Btu per hour is less than or equal to 2,000,000 Btu/hour.

• Locomotive storage building

⇒ 3 heaters @ 75,000 Btu/hr each

⇒ 1 heater @ 130,000 Btu/hr Minn. R. 7011.0610

3(G) Emissions from a laboratory, as defined in the subpart

• Water lab activities Minn. R. 7011.0710/0715

3(H) Miscellaneous: 3. brazing, soldering or welding equipment

• Welding equipment Minn. R. 7011.0710/0715

3(I) Individual emissions units at a sta tionary source, each of which have a potential to emit the following pollutants in amounts less than: 1. 4,000 lbs/year of carbon monoxide; and 2. 2,000 lbs/year each of nitrogen oxide , sulfur dioxide, particulate matter, particulate matter less than ten microns, volatile organic compounds (including hazardous air polluta nt-containing VOC ), and ozone.

• Loadout of dewatered slag

• Magnetic separator chute

• Solvent use (> 200 gallons, < 1 tpy) Minn. R. 7011.0710/0715

### Minn. R. 7007.1300,

subpart Rule Description of the Activity Applicable Requirement

3(K) Infrequent use of spray paint equipment for routine housekeeping or plant upkeep activities not associated with primary production processes at the stationary source, such as spray painting of buildings, machinery, vehicles, and other supporting equipment.

• Spray paint system (>200 gal/yr) for facility upkeep Minn. R. 7011.0710/0715

4 Individual emissions units at a sta tionary source, each of which has: A. Potential emissions of 5.7 pounds per hour or actual emissions of two tons per year of carbon monoxide; B. Potential emissions of 2.28 pounds per hour or actual emissions of one ton per year for particulate matter, particulate matter less than ten microns, nitrogen oxide, sulfur dioxide, and VOCs; and C. For hazardous air pollutants, emissions units with: (1) potential emissions of 25 percent or less of the hazardous air pollutant thresholds listed in subp. 5; or (2) combined HAP actual emissions of one ton per year unless the emissions unit emits one or more of the HAPs listed in this subpart. Temporary emergency heating equipment Internal combustion engines VOC fugitives from pumps, valves, flanges on distillate forwarding system Distillate oil storage tanks Propane vaporizers 1 & 2 Plant propane emergency generator Plant diesel fire pump engine Substation diesel emergency generator Plant propane radio system generator Plant vacuum system Slag house vacuum system Minn. R. 7011.0710/0715 or Minn. R. 7011.2300



### Conditionally Insignificant Activities & Applicable Requirements
Rule Description of the Activity Applicable Requirement
Minn. R. 7008.4110 Emissions from equipment venting particulate matter (PM) or particulate matter less than 10 microns (PM 10 

### ) inside a building, provided that emissions from the equipment are: a). filtered through an air cleaning system; and b). vented inside of the building 100% of the time.

• Sandblasting Room

• Metal machining equipment Minn. R. 7011.0710/0715

## APPENDIX E – Acid Rain Forms Facility Name : Xcel Energy - Allen S. King Generating Plant Permit Number : 16300005-006United States Environmental Protection Agency OMB No. 2060-0258 Acid Rain Program 

# Phase II NO X 

# Compliance Plan Page 

### 1 of 

### 12

For more information, see instructions and refer to 40 CFR 76.9
This submission is: 

#  New 

#  Revised

STEP 1 Indicate plant name, State, and ORIS code from NADB, if applicable 

### Allen S. King

Plant Name 

### MN

State 

### 1915

ORIS Code

STEP 2 Identify each affected Group 1 and Group 2 bo iler using the boiler ID# from NADB, if applicable. Indicate boiler type: “CB” for cell burner, “CY” for cyclone, “DBW” for dry bottom wall-fired, “T” for tangentially fired, “V” for vert ically fired, and“WB” for wet bottom. Indicate the compliance option selected for each unit.

I D# 

### 1 I D# I D# I D# I D# I D#

T ype 

### CY T ype T ype T ype T ype T ype

(a) Standard annual average emission limitation of 0.50 lb/mmBtu (for Phase I dry bottom wall-fired boilers) 

#      

(b) Standard annual average emission limitation of 0.45 lb/mmBtu (for Phase I tangentially fired boilers) 

#      

(c) EPA-approved early election plan under 40 CFR 76.8 through 12/31/07 (also indicate above emission limit specified in plan) 

#      

(d) Standard annual average emission limitation of 0.46 lb/mmBtu (for Phase II dry bottom wall-fired boilers) 

#      

(e) Standard annual average emission limitation of 0.40 lb/mmBtu (for Phase II tangentially fired boilers) 

#      

(f) Standard annual average emission limitation of 0.68 lb/mmBtu (for cell burner boilers) 

#      

(g) Standard annual average emission limitation of 0.86 lb/mmBtu (for cyclone boilers) 

#      
(h) Standard annual average emission limitation of 0.80 lb/mmBtu (for vertically fired boilers) 

#      

(i) Standard annual average emission limitation of 0.84 lb/mmBtu (for wet bottom boilers) 

#      

(j) NO x Averaging Plan (include NO x Averaging form) 

#      

(k) Common stack pursuant to 40 CFR 75.17(a)(2)(i)(A) (check the standard emission limitation box above for most stringent limitation applicable to any unit utilizing stack) 

#      

(l) Common stack pursuant to 40 CFR 75.17(a)(2)(i)(B) with NO x Averaging (check the NO x Averaging Plan box and include NO x Averaging form) 

#      

### Allen S. King Plant Name (from Step 1) NO x Compliance - Page 2 Page 

### 2 of 

### 12

STEP 2, cont’d.

I D# I D# I D# I D# I D# I D#

T ype T ype T ype T ype T ype T ype

(m) EPA-approved common stack apportionment method pursuant to 40 CFR 75.17 (a)(2)(i)(C), (a)(2)(iii)(B), or (b)(2) 

#      

(n) AEL (include Phase II AEL Demonstration Period, Final AEL Petition, or AEL Renewal form as appropriate) 

#      

(o) Petition for AEL demonstration period or final AEL under review by U.S. EPA or demonstration period ongoing 

#      

(p) Repowering extension plan approved or under review 

#      

STEP 3 Read the standard requirements and certification, enter the name of the designated representative, sign & date. Standard Requirements

General . This source is subject to the standard requirements in 40 CFR 72.9 (consistent with 40 CFR 76.8(e)(1)(i)). These requirements are listed in th is source's Acid Rain Permit.

Special Provisions for Early Election Units

Nitrogen Oxides . A unit that is governed by an approved early election plan shall be s ubject to an emissions limitation for NO x as provided under 40 CFR 76.8(a)(2) except as provided under 40 CFR 76.8(e)(3)(iii). Liability . The owners and operators of a unit governed by an approved early election plan shall be liable for any violation of the plan or 40 CFR 76.8 at that unit. The owners and operators shall be liable, beginning January 1, 2000, for fulfilling the obligations specified in 40 CFR Part 77. Termination . An approved early election plan shall be in effect only until the earlier of January 1, 2008 or January 1 of the calendar year for which a termination of the plan ta kes effect. If the designated representative of the unit under an approved early election plan fails to demonstrate comp liance with the applicable emissions limitation under 40 CFR 76.5 for any year during the period beginning January 1 of the first year the early election takes effect and ending December 31, 2007, the permitting authority will terminat e the plan. The termination will take effect beginning January 1 of the year after the year for which there is a failure to demonstrate compliance, and the designated representative may not submit a new early election pl an. The designated representative of the unit under an approved early election plan may terminat e the plan any year prior to 2008 but may not submit a new early election plan. In order to terminate the plan, the designated r epresentative must submit a notice under 40 CFR 72.40(d) by January 1 of the year for which the termination is to take effect. If an early election plan is terminated any year prior to 2000, the unit shall meet, beginning January 1, 2000, the applicable emissions limitation for NO x for Phase II units with Group 1 boilers under 40 CFR 76.7. If an early election plan is terminated on or after 2000, the unit shall meet, beginning on the effective date of the terminati on, the applicable emissions limitation for NO x for Phase II units with Group 1 boilers under 40 CFR 76.7.

Certification

I am authorized to make this submission on behalf of the owners and operators of the affected source or affected units for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in th is document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtai ning the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for subm itting false statements and information or om itting required statements and information, including the possibility of fine or imprisonment.

N ame 

### Gary D. Hudson

S ignature D ate 

### 6/21/02United States Environmental Protection Agency OMB No. 2060-0258 Acid Rain Program 

# Phase II NO X 

# Averaging Plan

For more information, see instructions and refer to 40 CFR 76.11 Page 1

This submission is: 

#  New 

#  Revised Page 

### 1 of 

### 3

Plant Name State ID# (a) Emission Limitation (b)

ACEL (c) Annual Heat Input Limit

Allen S. King MN 1 0.86 1.05 34000000

Black Dog MN 3 0.46 0.81 5685000

Black Dog MN 4 0.46 0.81 11036000

High Bridge MN 3 0.50 0.60 1771500

High Bridge MN 4 0.50 0.60 1771500

High Bridge MN 5 0.50 0.60 5037000

High Bridge MN 6 0.50 0.60 10313000

Minnesota Valley MN 4 0.46 0.47 1189000 STEP 1

Identify the units participating in this averaging plan by plant name, State, and boiler ID# from NADB. In column (a), fill in each unit's applicable emission limitation from 40 CFR 76.5, 76.6, or 76.7. In column (b), assign an alternative contemporaneous annual emissions limitation (ACEL) in lb/mmBtu to each unit. In column (c), assign an annual heat input limitation in mmBtu to each unit. Continue to page 3 if necessary. Riverside MN 6 0.46 0.85 4324500

Btu-weighted annual emission rate averaged over the units if they are operated in accordance with the proposed averaging plan Btu-weighted annual average emission rate for same units operated in compliance with 40 CFR 76.5, 76.6 or 76.7

0.54

≤ 0.54



## HI ) HI x R (

i

n

=1 i i

Li n

=1 i 

# ∑ ∑

≤ 

## HI ] HI x R [

i

n

=1 i i li n

=1 i 

# ∑ ∑ STEP 2

Use the formula to enter the Btu-weighted annual emission rate averaged over the units if they are operated in accordance with the proposed averaging plan and the Btu-weighted annual average emission rate for the same units if they are operated in compliance with 40 CFR 76.5, 76.6, or 76.7. The former must be less than or equal to the latter. Where,

R L i = Alternative contemporaneous annual em ission limitation for unit i, in lb/mmBtu, as specified in column (b) of Step 1: R l i = Applicable emission limitation for uni t i, in lb/mmBtu, as specified in column (a) of Step 1; Hl i = Annual heat input for unit i, in mmB tu, as specified in column (c) of Step 1; n = Number of units in the averaging plan

P lant Name (from Step 1) Allen S. King NO x Averaging - Page 2STEP 3

Mark one of the two options and enter dates. 

#  This plan is effective for calendar year ___2002 ______through calendar year __2006

___ unless notificati on to terminate the plan is given. 

#  Treat this plan as 

#  identical plans, each effective for one calendar year for the following calendar years: ______, ______, ______, ______ and ______ unless notif ication to terminate one or more of these plans is given.

STEP 4
Read the special provisions and certification, enter the name of the designated representative, and sign and date. Special Provisions

Emission Limitations Each affected unit in an approved averaging plan is in compliance with the Acid Rain emission limitation for NO xunder the plan only if the fo llowing requirements are met: (i) For each unit, the unit's actual annual average emissi on rate for the calendar year, in lb/mmBtu, is less than or equal to its alternat ive contemporaneous annual emission lim itation in the averaging plan, and (a) For each unit with an alternative contempor aneous emission limitation less stringent than the applicable emission limitation in 40 CFR 76.5, 76.6, or 76.7, the actual annual heat input for the calendar year does not exceed the annual heat input limit in the averaging plan, (b) For each unit with an alternative contempor aneous emission limitation more stringent than the applicable emission limitation in 40 CFR 76.5, 76.6, or 76.7, the actual annual heat input for the calendar year is not less than the annual heat input limit in the averaging plan, or (ii) If one or more of the units does not meet the r equirements of (i), the des ignated represent ative shall demonstrate, in accordance with 40 CFR 76.11(d)(1)( ii)(A) and (B), that the actual Btu-weighted annual average emission rate for the units in the plan is less than or equal to t he Btu-weighted annual average rate for the same units had they each been operated, during the same period of time, in compliance with the applicable emission limitations in 40 CFR 76.5, 76.6, or 76.7. (iii) If there is a successful group showing of co mpliance under 40 CFR 76.11(d)(1)(ii)(A) and (B) for a calendar year, then all units in the averaging plan shall be deemed to be in compliance for that year with their alternative contem poraneous emission limitations and annual heat input limits under (i).

Liability The owners and operators of a unit governed by an approved averaging plan shall be liable for any violation of the plan or this secti on at that unit or any other unit in the plan, including liability for fulfilling the obligations specified in part 77 of th is chapter and sections 113 and 411 of the Act.

Termination

The designated representativ e may submit a notification to te rminate an approved averaging plan, in accordance with 40 CFR 72.40(d), no later than October 1 of the calendar year for which the plan is to be terminated.

Certification
I am authorized to make this submission on behalf of the owners and operators of the affected source or affected units for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, t he statements and information submitt ed in this document and all its attachments. Based on my inquiry of those indi viduals with primary responsibility for obtaining the information, I certify that the statements and information are to t he best of my knowledge and belief true, accurate, and complete. I am aware that t here are significant penalties for submitting false statements and information or omitti ng required statements and informati on, including the possibility of fine or imprisonment.

N ame Gary D. Hudson

S ignature D ate 6/21/02

P lant Name (from Step 1) Allen S. King NO xAveraging - Page 3

Plant Name State ID# (a)

Emission Limitation (b)

Alt. Contemp. Emission Limitation (c)

Annual Heat Input Limit STEP 1 Riverside MN 7 0.46 0.85 4324500Riverside MN 8 0.86 0.82 10821000

Sherburne County MN 1 0.45 0.28 42255000

Sherburne County MN 2 0.45 0.28 42255000

Sherburne County MN 3 0.46 0.35 34912000 Continue the identification of units from Step 1, page 1, here.

### STEP 1

Identify the source by plant name, State, and ORIS code. United States Environmental Protection Agency OMB No. 2060-0258 Acid Rain Program 

# Acid Rain Permit Application

For more information, see instructions and refer to 40 CFR 72.30 and 72.31

This submission is: 

#  New 

#  Revised 

### RENEWAL APPLICATION

a b c d

Unit ID# Unit Will Hold Allowances in Accordance with 40 CFR 72.9(c)(1) New Units Commence Operation Date New Units Monitor Certification Deadline



### 1 Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes 

### STEP 2

Enter the unit ID# for every affected unit at the affected source in column “a.” For new units, enter the requested information in columns “c” and “d.”

Yes

Yes

Yes

Yes 

### Allen S. King MN 1915 Plant Name State ORIS Code

### STEP 3

Read the standard requirements Allen S. King Plant Name (from Step 1 ) 

### Acid Rain - Page 2 Permit Requirements


### ( 1) The designated representative of each affected s ource and each affected unit at the source shall: (i) Submit a complete Acid Rain permit applicat ion (including a compliance plan) under 40 CFR part 72 in accordance with the deadlines specified in 40 CFR 72.30; and (ii) Submit in a timely manner any supplemental in formation that the permitting authority determines is necessary in order to review an Acid Rain permi t application and issue or deny an Acid Rain permit; (2) The owners and operators of each affected source and each affected unit at the source shall: (i) Operate the unit in compliance with a complete Acid Rain permit application or a superseding Acid Rain permit issued by the permitting authority; and (ii) Have an Acid Rain Permit.

Monitoring Requirements

(1) The owners and operators and, to the extent app licable, designated represent ative of each affected source and each affected unit at the source shall comp ly with the monitoring requirements as provided in 40 CFR part 75. (2) The emissions measurements recorded and reported in accordance with 40 CFR part 75 shall be used to determine compliance by the unit with the Acid Rain emissions limitations and emissions reduction requirements for sulfur dioxide and nitrogen oxides under the Acid Rain Program. (3) The requirements of 40 CFR part 75 shall not affe ct the responsibility of the owners and operators to monitor emissions of other pollutant s or other emissions characterist ics at the unit under other applicable requirements of the Act and other provisions of the operating permit for the source.

Sulfur Dioxide Requirements

(1) The owners and operators of each source and each affected unit at the source shall: (i) Hold allowances, as of the allowance transfe r deadline, in the unit's compliance subaccount (after deductions under 40 CFR 73.34(c)), or in the compli ance subaccount of another affected unit at the same source to the extent provided in 40 CFR 73. 35(b)(3), not less than the total annual emissions of sulfur dioxide for the previous calendar year from the unit; and (ii) Comply with the applicable Acid Rain emissions limitations for sulfur dioxide. (2) Each ton of sulfur dioxide emi tted in excess of the Acid Rain emi ssions limitations for sulfur dioxide shall constitute a separat e violation of the Act. (3) An affected unit shall be subject to the requi rements under paragraph (1) of the sulfur dioxide requirements as follows: (i) Starting January 1, 2000, an affected unit under 40 CFR 72.6(a)(2); or (ii) Starting on the later of January 1, 2000 or t he deadline for monitor certification under 40 CFR part 75, an affected unit under 40 CFR 72.6(a)(3). (4) Allowances shall be held in, deducted from, or transferred among Allowance Tracking System accounts in accordance with the Acid Rain Program. (5) An allowance shall not be deducted in order to comply with the requirements under paragraph (1) of the sulfur dioxide requirements prior to the cal endar year for which the allowance was allocated. (6) An allowance allocated by the Administrator under the Acid Rain Program is a limited authorization to emit sulfur dioxide in accordance with the Acid Rain Program. No provision of the Acid Rain Program, the Acid Rain permit application, the Acid Rain per mit, or an exemption under 40 CFR 72.7 or 72.8 and no provision of law shall be construed to limit the authorit y of the United States to terminate or limit such authorization. (7) An allowance allocated by the Administrator under the Acid Rain Program does not constitute a property right.

Allen S. King

### STEP 3, Cont’d. Plant Name (from Step 1) 

### Acid Rain - Page 3

Nitrogen Oxides Requirements The owners and operators of the source and each affected unit at the source shall comply with the applicable Acid Rain emissions limitation for nitrogen oxides.

Excess Emissions Requirements

(1) The designated representative of an affected unit that has excess emissions in any calendar year shall submit a proposed offset plan, as required under 40 CFR part 77. (2) The owners and operators of an affected unit that has excess emissions in any calendar year shall: (i) Pay without demand the penalty required, and pay upon demand the interest on that penalty, as required by 40 CFR part 77; and (ii) Comply with the terms of an approved o ffset plan, as required by 40 CFR part 77.

Recordkeeping and Reporting Requirements

(1) Unless otherwise provided, the owners and operat ors of the source and each affected unit at the source shall keep on site at the source each of t he following documents for a period of 5 years from the date the document is created. This period may be ext ended for cause, at any time prior to the end of 5 years, in writing by the Administrator or permitting authority: (i) The certificate of representat ion for the designated representativ e for the source and each affected unit at the source and all documents that demonstrate t he truth of the statements in the certificate of representation, in accordance with 40 CFR 72.24; provided that the certif icate and documents shall be retained on site at the source beyond such 5- year period until such documents are superseded because of the submission of a new certific ate of representation changing the designated representative; (ii) All emissions monitoring information, in a ccordance with 40 CFR part 75, provided that to the extent that 40 CFR part 75 provides for a 3-year period for recordkeeping, the 3-year period shall apply. (iii) Copies of all reports, compliance certificat ions, and other submissions and all records made or required under the Acid Rain Program; and, (iv) Copies of all documents used to complete an Acid Rain permit application and any other submission under the Acid Rain Program or to dem onstrate compliance with the requirements of the Acid Rain Program. (2) The designated representative of an affected source and each affected unit at the source shall submit the reports and compliance certifications required under the Acid Rain Program, including those under 40 CFR part 72 subpart I and 40 CFR part 75.

Liability

(1) Any person who knowingly violates any requirem ent or prohibition of the Acid Rain Program, a complete Acid Rain permit application, an Acid Ra in permit, or an exemption under 40 CFR 72.7 or 72.8, including any requirement for the pay ment of any penalty owed to the Un ited States, shall be subject to enforcement pursuant to section 113(c) of the Act. (2) Any person who knowingly makes a false, material statement in any record, submission, or report under the Acid Rain Program shall be subject to crim inal enforcement pursuant to section 113(c) of the Act and 18 U.S.C. 1001. (3) No permit revision shall excuse any violation of t he requirements of the Acid Rain Program that occurs prior to the date that the revision takes effect. (4) Each affected source and each affected unit shall meet the requirements of the Acid Rain Program.

Allen S. King

### Step 3, Cont’d.

STEP 4

Read the certification statement, sign, and date Plant Name (from Step 1) 

### Acid Rain - Page 4 Liability, Cont’d

. (5) Any provision of the Acid Rain Program that applies to an affected source (including a provision applicable to the designated representative of an a ffected source) shall also apply to the owners and operators of such source and of the affected units at the source. (6) Any provision of the Acid Rain Program that applies to an affected unit (including a provision applicable to the designated representative of an a ffected unit) shall also apply to the owners and operators of such unit. Except as provided under 40 CFR 72.44 (Phase II repowering extension plans) and 40 CFR 76.11 (NO x 

### averaging plans), and except with regard to the requirements applicable to units with a common stack under 40 CFR part 75 (incl uding 40 CFR 75.16, 75.17, and 75.18), the owners and operators and the designated representat ive of one affected unit shall not be liable for any violation by any other affected unit of which they are not ow ners or operators or the designated representative and that is located at a source of which they are not owners or operators or t he designated representative. (7) Each violation of a provision of 40 CFR parts 72, 73, 74, 75, 76, 77, and 78 by an affected source or affected unit, or by an owner or operator or designated representative of such source or unit, shall be a separate violation of the Act.

Effect on Other Authorities

No provision of the Acid Rain Program, an Acid Rain permit application, an Acid Rain permit, or an exemption under 40 CFR 72.7 or 72.8 shall be construed as: (1) Except as expressly provided in title IV of the Act, exempting or excl uding the owners and operators and, to the extent applicable, the designated representative of an affect ed source or affected unit from compliance with any other provision of the Act, includi ng the provisions of title I of the Act relating to applicable National Ambient Air Quality St andards or State Implementation Plans; (2) Limiting the number of allowances a unit can hold; provided, that the number of allowances held by the unit shall not affect the source's obligation to comply with any other provisions of the Act; (3) Requiring a change of any kind in any State law r egulating electric utility rates and charges, affecting any State law regarding such State regulation, or limiting such Stat e regulation, including any prudence review requirements under such State law; (4) Modifying the Federal Power Act or affecti ng the authority of the Federal Energy Regulatory Commission under the Federal Power Act; or, (5) Interfering with or impairing any program for com petitive bidding for power supply in a State in which such program is established.

Certification

I am authorized to make this submission on behalf of the owners and operators of the affected source or affected units for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and in formation submitted in this document and all its attachments. Based on my inquiry of those indi viduals with primary responsibility for obtaining the information, I certify that the st atements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and in formation, including the possibility of fine or imprisonment.



### Name Mark Fritsch

Signature Date 1-10-03

### Technical Support Document, Permit Action Number: 

## 16300005–007 Page 1 of 5 Date: 4/23/2007 

## TECHNICAL SUPPORT DOCUMENT For AIR EMISSION PERMIT NO. 16300005-007

This Technical Support Document (TSD) is intended for a ll parties interested in the permit and to meet the requirements that have been set forth by the federal and state regulations (40 CFR § 70.7(a)(5) and Minn. R. 7007.0850, subp.1). The purpose of this document is to pr ovide the legal and factual justification for each applicable requirement or policy decision consider ed in the determination to issue the permit.

1. General Information 1.1. Applicant and Stationary Source Location:

Applicant/Address Stationary Source/Address (SIC Code: 4911 ) Xcel Energy – Allen S King Generating 414 Nicollet Mall Minneapolis, MN 55401-1993 Highway 95 & Point Road Oak Park Heights Washington County Contact: Nancy Glass Phone: (612) 330-5520
1.2. Description of the Permit Action The Allen S. King plant is a coal-fired electric utility lo cated on Highway 95 & Point Rd. in Oak Park Heights, Minnesota. The facility’s emission sources consist of bo ilers; fuel and ash storage and handling equipment; and emergency diesel engines. The facility’s main power bo iler (Boiler No. 1) is a coal-fired cyclone boiler with a generating capacity of 550 megawatts (MW) of electricity. Pollution control equipment on the main boiler as of the date of issuance of Air Emission Permit No. 16300005-005 cons ists of an electrostatic precipitator to control Particulate Matter (PM) emissions. Emissions from fuel a nd ash storage and handling equipment, which are potential sources of PM emissions, are controlled using water and ot her dust suppressants, enclosur es, and/or fabric filters. Permit action 005 authorized modification of the King Plan t. The Rehabilitation Project is currently underway and includes the installation of new pollution control e quipment, modification of the plant heat rejection system, and rehabilitation and life extension of the main (EU 001, coal-fired) boiler. The rehabilitation will allow the plant to operate at a capacity approaching its original design rating.

The boiler rehabilitation consisted of:

• Replacement of the furnace floor and support system.

• Installation of new cyclone burne rs and re-entrant throats.

• Replace furnace sidewalls and furnace floor tubes.

• Installation of induced draft fans to accommodate add itional draft requirements of new control equipment. The new (additional) control equipment will consist of:

• Selective Catalytic Reduction (SCR) reactor for control of NO X 

### emissions.

• Spray dryer absorber lime-based semi-dry Flue Gas Desulfurization (FGD) system for control of SO 2 

### emissions

• Pulse-Jet cleaned Fabric Filter (PJFF) for additional control of PM. The rehabilitation project authorized by permit ac tion 005 also involved decommissioning and removal of one existing auxiliary boiler, replacing it with a new auxiliary boiler. The rehabilitation of EU 001 is expected be completed and ready for startup in March of 2007.

### Technical Support Document, Permit Action Number: 

## 16300005–007 Page 2 of 5 Date: 4/23/2007 

### 1.3 Description of the Activities Allowed by this Permit Action This major permit amendment grants the Permittee the following:

1. EU 001 – Clarified that first firing is intended to re fer to the first firing with permitted fuels other than natural gas. The definition of startup and shutdown for boiler EU 001 was added since it affects the ability to operate the SCR and the SDA.

2. SCR (CE 015) and SDA (CE 016) – Because of the operating temperatures associated with the ability to operate the SCR and SDA, MPCA is adding a provision to the permit that clarifies that the SCR and SDA are not required to be operated dur ing startup and shutdown of EU 001. What constitutes startup and shutdown of EU 001 is defined in the permit. All Title I emission limits remain applicable during periods of startup, shutdown, and malfunction.

3. Operation of Fabric Filter (CE 017) – The mandatory operation of the fabric filter (CE 017) associated with boiler EU 001 in lieu of operating th e existing electrostatic precipitators (ESP) (CE 001 and CE 002), is not required until the effective date of the total particulate emission limit (270 days after the first firing of the boiler EU 001 with fuels other than natural gas following rehabilitation). The permit requires that either the ESPs, or the fabric f ilter, are operated after the first firing of the boiler with fuels other than natural gas following the reha bilitation project until the date at which the fabric filter becomes mandatory.

4. Removal of Hours of Operation Limit for GP 008 – Required to provide adequate flexibility for post-Rehabilitation operations at the facility. The PSD applicability analysis demonstrates that this change will not cause any pollutant to cross any PSD thresholds.

5. Removal of Emission Units – Design changes since the original permit issuance have resulted in the elimination of the duct burner (EU 030) and ammonia vaporizer (EU 031) as emission units. The Byproduct/Fly Ash Transfer Station Mechan ical Exhauster was never and will not be installed. References to these emission units were removed from the draft permit.

6. Permit Language – The language for compliance with Boiler MACT for the auxiliary boiler (EU 028) was updated to incorporate changes in the regula tion since the issuance of the initial permit.

7. Changes to Ash Silo – The permit will be updated to acknowle dge that the fly-ash silo (EU 012) now has a dedicated fabric filter (CE 026) a nd its own stack (SV 036), as opposed to venting through the main boiler stack, as it was previously permitted.

8. Mercury Monitoring and Testing – Xcel Energy will be operating a continuous emission monitor (CEM) to measure the mercury emissions from EU 001 as a requirement of the Minnesota Mercury Reduction Act of 2006. Permit conditions for the opera tion of the CEM have been added to the draft permit. Because of the installation of the mercury CEM, it is no longer necessary to perform annual stack tests on mercury emissions after the initial performance test is completed.

9. Installation of SCR Ash Bin Vent – Installation of SCR ash bin and vent (EU 039/SV 037).

10. Removal of Redundancy – Language for Performance Test Notifications and Submittals in the original permit was located in the total facility requirements section as well as GP 004, EU 004, EU 006, EU 011, and EU 028. The draft permit c ontains this language only in the total facility requirements in order to remove the redundant permit conditions.

### Technical Support Document, Permit Action Number: 

## 16300005–007 Page 3 of 5 Date: 4/23/2007 

### 1.4 Facility Emissions The permit actions authorized by this amendment do not authorize an increase in emissions at the facility. The removal of the duct burner (EU 030) and ammonia vaporizer (EU 031) result in a decrease in PTE from the facility. In addition, the ash storage silo (EU 012) is no longer venting through Boiler 1 (EU 001) stack and is becoming a new emission point but with no increase in emissions. A summary of the Potential to Emit (PTE) in tons per year is as follows.

Table 1. Summary of Potential to Emit

Pollutant PM PM 10 

### SO 2 

### NO x 

### VOCs CO Lead Total Facility PTE 522.1 813.3 3027 2701 166.8 439.8 0.49 PTE after removal of emission units 522.1 813.3 3027.0 2693.0 165.4 418.6 0.49
Net change in PTE -0.02 -0.01 -0.01 -4.98 -1.39 -21.23 -1.26E-04



## PM = Particulate Matter PM 10 

## = PM smaller than 10 microns SO 2 

## = Sulfur Dioxide NO x 

## = Nitrogen Oxides VOCs = Volatile Organic Compounds CO = Carbon Monoxide

Table 2. Facility Classification
Classification Major/Affected Source Synthetic Minor Minor
PSD Source Modification Part 70 Permit Program X Part 63 NESHAP X

2. Regulatory and/or Statutory Basis

New Source Review The facility is an existing major source under New S ource Review regulations. None of the changes authorized by this permit action are subject to New Source review.

Part 70 Permit Program The facility is a major source under the Part 70 permit program.

New Source Performance Standards (NSPS) The existing flite conveyors and the modified EU 006, EU 011, and EU 004 are subject to Subpart Y. The auxiliary boiler (EU 028) is subject to Subpart Dc.

National Emission Standards for Hazardous Air Pollutants (NESHAP) The facility is a major source of HAPs. Auxiliary boiler EU 028 is subject to the Industrial/Commercial/Institutional Bo ilers and Process Heaters (Industrial Boiler) Maximum Achievable Control Technology (MACT) standard. The Industr ial Boiler MACT was promulgated on September 13, 2004, and is codified at 40 CFR pt. 63, Subpart DDDDD. This permit action revised the permit conditions to account for changes to the Boiler MACT regulation since the issuance of the initial permit authorizing installation of the EU 028.

### Technical Support Document, Permit Action Number: 

## 16300005–007 Page 4 of 5 Date: 4/23/2007 

### Acid Rain Program The Allen.S. King Generating Plant remains subject to the SO 2 

### and NO x 

### provisions of Title IV of the Clean Air Act. The King plant will continue to be allocated SO 2 

### allowances and will meet the requirements of Title IV with these allocations. The King Plant will also continue to meet these requirements by participating in Xcel Energy’s NO X 

### averaging plan for the state of Minnesota.

Minnesota State Rules Portions of the facility are subject to the following Minnesota Standards of Performance:

• Minn. R. 7011.1105 Minnesota Standards for Coal Handling Facilities

• Minn. R. 7011.0610 Minnesota Standards for Direct Heating Equipment

• Minn. R. 7011.0715 Standards of Performance for Post-1969 Industrial Process Equipment

• Minn. R. 7011.2300 Standards of Performance for Stationary Internal Combustion Engines

3. Technical Information 3.1 Operation of control equipment This permit action removes the permit condition that th e SCR, SDA and fabric filter are in service at all times that EU 001 is in operation. Since the perm it allows a 270 day period for commissioning, following the rehabilitation project, to meet the new emission limits for NO x 

### and SO 2 

### the permit has been amended to not require operation of the control equipment un til the effective date of the emission limits. This allows each component to be intermittently out of service during the commissioning period to allow for shakedown operation, resolution of equipment failures, process malfunctions, and equipment optimization. Commissioning several new components simultaneously increases the risk of malfunction, inadvertent unit trips, and damage to components. Operation of the SCR and SDA – Operation of the SCR and SDA are temperature dependent. The SCR requires the inlet flue gas temperature to be at least 625 °F prior to injection of the ammonia reagent. The SDA requires that the inlet flue gas temperature be at least 275 °F prior to injection of the lime slurry. In addition, the operating characteristics (pressure, temperat ure, slag ‘freezing’ temperature, etc) of the King Plant supercritical cyclone fire boiler are such th at EU 001 cannot sustain operation below approximately 250 MW.

CEMS for NO x 

### and SO 2 

### will continuously monitor emission rates so that on-going compliance with the limits can be demonstrated. CEMS will also mon itor the emission rates during startup and shutdown operation below 250 MW. Mercury Monitoring and Testing – Xcel Energy w ill be operating a continuous emissions monitor to measure mercury emissions from EU 001 as a requireme nt of the Minnesota Mercury Reduction Act of 2006. Permit conditions for the operation of the CEM ha ve been added to the draft permit. Because of the installation of the mercury CEM, it becomes unnecessary to perform annual stack tests on mercury emission after the initial performance test is completed.

3.2 Request Not Granted Xcel Energy requested that the Title I conditions which limit NO x 

### and SO 2 

### emission using a 30-day rolling average be amended to state that these limits do not apply during start-up, shutdown, or malfunction. However, MPCA has determined that Title I conditi ons do apply during startup, shutdown or malfunction.

### Technical Support Document, Permit Action Number: 

## 16300005–007 Page 5 of 5 Date: 4/23/2007 

### 3.3 Periodic Monitoring The only change in periodic monitoring authorized by this permit action is associated with the new SCR Inlet Ash Surge Hopper (EU 039). This emission unit is in GP 008 in the permit and subject to the same periodic inspections and pressure drop recordkeeping as the other units in GP 008.

3.4 Permit Organization In general, the permit meets the MPCA Delta Guid ance for ordering and grouping of requirements. One area where this permit deviates slightly from Delta guidance is in the use of appendices. While appendices are fully enforceable parts of the permit, in general, any requirement that the MPCA thinks should be tracked (e.g., limits, submittals, etc.), should be in Table A or B. The main reason is that the appendices are word processing sections and are not part of the tracking system. Violation of the appendices can be enforced, but the computer syst em will not automatically generate the necessary enforcement notices or documents. Staff must generate these.
In addition, the Industrial Boiler MACT standard dictat es a hydrogen chloride limit, which will be applicable to EU 028 upon startup. Delta does not offer “hydroge n chloride” as a drop-down option for pollutants, but instead offers “hydrochloric acid.” Since hydrogen ch loride and hydrochloric acid are the same chemical (CAS number 7647-01-0), hydrochloric acid is lis ted in the permit as the regulated pollutant.

3.5 Comments Received Public Notice Period: January 10, 2007 – February 8, 2007 One comment was received in regards to adding a requirement to require a permit amendment with public notice in the event that any changes needed to be made to th e ash loadout system as a result of the Environmental Impact Statement (EIS) for the Xcel Energy Ash Disposal Facility. Result: No action taken. EIS will dictate any ch anges required, permit amendment required will be dictated by state rules. Response letter is in Delta. EPA 45-day Review Period: Ja nuary 10, 2007 – February 23, 2007

No comments received from EPA

4. Conclusion Based on the information provided by Xcel Ener gy – Allen S. King Generating, the MPCA has reasonable assurance that the proposed operation of th e emission facility, as described in the Air Emission Permit No. 16300005-007 and this TSD, will not cause or cont ribute to a violation of applicable federal regulations and Minnesota Rules.

Staff Members on Permit Team: Trevor Shearen (permit writer/engineer) Ann Curnow (MPCA contractor/permit writer) Christian Norman (enforcement) Curtis Stock (stack testing) Toni Volkmeier (peer reviewer)

# Review of Xcel Energy’s Metropolitan Emission Reduction Proposal

December 30, 2002

## For More Information

Contact the following MPCA staff members for mo re information about the preparation of this report, as well as other ques tions related to environmental controls for energy production:

Deputy Commissioner Ann Seha (651) 296-7305 Policy J. David Thornton Manager, Major Facilities Policy and Planning Division (651) 296-7265
Technical, Regulatory and Cost Assessments Anne M. Jackson, P.E. Principal Engineer Policy and Planning Division (651) 296-7949 Best Available Control Technology Assessments Richard Cordes, P.E. Senior Engineer Majors and Remediation Division (651) 296-8157

Health Effects from Pollution Lisa Herschberger Research Scientist Environmental Outcomes Division (651) 296-7874 Environmental Justice John Seltz, Supervisor Air Unit Policy and Planning Division (651) 296-7801

Economic Analysis Robert McCarron Economist Policy and Planning Division (651) 296-7324 Editor Walker Smith Public Information Office (651) 297-7018

Printed on paper containing at least 30 percent fibers recycled by consumers. This document can be provided in other formats upon request.

## Table of Contents

1.0 Intr oduction .........................................................................................................1

2.0 Summary ..............................................................................................................3 2.1 Qualifying Projects................................................................................................. 3 2.2 Project Costs ......................................................................................................... 3 2.3 Projected Enviro nmental B enefit s.......................................................................... 4 2.4 Appropriateness of the Pr ojec t............................................................................... 5



## 3.0 Qualifying Projects ..............................................................................................6 3.1 Minn. Stat. § 216B.1692 Subd. 1. Qualif ying Proj ects.......................................... 6 3.1.1 New Source Review



### .................................................................................... 7 3.1.2 New Source Performance Standards .................................................................... 

### 8 3.2 Do the Projects Qua lify Under 216B. 1692 Subd. 1? ............................................. 9 3.2.1 A.S. King ................................................................................................................ 

### 9 3.2.2 High Bridge ............................................................................................................ 

### 11 3.2.3 Riverside ................................................................................................................ 

### 13



## 4.0 Other Questions the PUC Must Consider .........................................................16

5.0 Estimated Capital Cost of th e Proposal............................................................18 5.1 Method of Analysis ................................................................................................ 18 5.2 Assessment of A.S. King Costs ............................................................................. 18 5.3 Assessment of High Bridge Estima ted Costs......................................................... 21 5.4 Assessment of River side Estimated Costs............................................................. 23 5.5 Summary............................................................................................................... 24



## 6.0 Impacts of Power Plant Emissions.....................................................................25 6.1 Contribution of Power Plant s to Air Polluti on in Mi nnesot a.................................... 25 6.2 Environmental and Health Effects of Emissions from Power Plants ...................... 28 6.2.1 Particulate Matter............................................................................................... 

### 29 6.2.2 EPA Response................................................................................................... 

### 30 6.2.3 PM 2.5 

### in Minnesota ............................................................................................. 

### 31 6.2.4 Air Alerts for Particulate Matter in the Twin Cities ............................................. 

### 32 6.2.5 Ozone................................................................................................................. 

### 32 6.2.6 Air Alerts for Ozone in the Twin Cities ............................................................... 

### 32 6.2.7 Haze................................................................................................................... 

### 33 6.2.8 Global C limate Change...................................................................................... 

### 33 6.2.9 Mercury .............................................................................................................. 

### 33 6.2.10 Acid Rain............................................................................................................ 

### 34

## 7.0 Assessment of Benefits of the Proposed Project............................................35 7.1 Emission Estima tes of t he Propos al...................................................................... 35 7.2 Xcel Energy’s Estimates of the Environmental Benefits from MERP..................... 36 7.3 Avoi ded Cost s ...................................................................................................... 38 7.4 MPCA Estimate of Proj ected Environmen tal Benef its ........................................... 38 7.4.1 Time Period........................................................................................................ 

### 38 7.4.2 Discount Rates................................................................................................... 

### 39 7.4.3 Reconsideration of Benefits and Costs.............................................................. 

### 40 7.5 Alternative Means of Assessing Benefi ts of Controlling Power Plant Emissions ... 42 7.5.1 The Benefits Asse ssment Methodology............................................................. 

### 42 7.5.2 EPA’s Clear Skies Init iative................................................................................ 

### 43 7.5.3 Eight Util ities Study ............................................................................................ 

### 44 7.5.4 Two Massachusetts Power Plants..................................................................... 

### 44 7.5.5 Minnesota Power Plants .................................................................................... 

### 44 7.6 Conclusions on the Estima tion of Quanti fiable B enefit

........................................... 46



## 8.0 Other Benefits .....................................................................................................48 8.1 Environmental Justice............................................................................................ 49 8.2 Local Impacts ....................................................................................................... 49 8.2.1 Truck and Rail Traffic......................................................................................... 

### 49 8.2.2 Dust.................................................................................................................... 

### 51 8.2.3 Appearance........................................................................................................ 

### 51 8.2.4 Water Usage and Discharge.............................................................................. 

### 51 8.2.5 Noise .................................................................................................................. 

### 51 8.2.6 Land Use............................................................................................................ 

### 51



## 9.0 Appropriateness of the Proposed Projects ......................................................53 9.1 Costs and Benef its ................................................................................................ 53 9.2 Allen S. King.......................................................................................................... 55 9.3 High Bridge............................................................................................................ 55 9.4 Riverside ............................................................................................................... 55



## 10.0 References.........................................................................................................56

Attachment 1 — Minn. Stat. § 216.B1692

Attachment 2 — 2001 Energy Planning Report, Appendix A

Attachment 3 — Draft Environmental Section for the 2002 Energy Planning Report

### MPCA Review of MERP Proposal

page 1 

# MPCA Review of Xcel Energy’s

Metropolitan Emission Reduction Proposal

1.0 Introduction

On July 26, 2002, Northern States Power Comp any d/b/a Xcel Energy (Xcel) submitted an emission reduction proposal, th e Metropolitan Emission Reduc tion Proposal (MERP) and accompanying rate rider, pursuant to Minn. Stat. § 216B.1692. 1 

## The proposal identified emission reduction options at three plants located in the Twin Cities metropolitan area:

 Allen S. King, Bayport : Installation of new pollution control equipment, boiler rehabilitation and life extension, with a modest increas e in generation capacity of 12 percent.

 High Bridge, St. Paul : Replace existing coal-fired units with two natural gas combined-cycle units, eliminating air emissions from burning coal and with a substantial increase in generation capacity of 111 percent.

 Riverside, Minneapolis : Repower with two natural gas combined-cycle units, eliminating air emissions from burning coal and with a modest increase in generation capacity of 14 percent.

Table 1 shows that if implemented as proposed, these projects would result in huge reductions in key pollutant emissions. Emissions of sulfur dioxide (SO 2 

## ) and nitrogen oxides (NO x 

## ) would be reduced by more than 90 percent. Emissions of particulate matter and mercury would be reduced by 70 percent and 76 percent, respectively.

Table 1. Comparison of annual overall emissions for the three plants before and after proposed changes

SO 2 

### NO X 

### PM 10 

### CO 2 

### CO Lead Mercury

Current annual emissions from these three plants (in tons per year) 34,178 24,206 954 6,545,727 860 266 2 

### 232 2



### Emissions change (in tons per year) -31,880 -22,017 -667.1 -319,865 +80 -60 2 

### -178 2



### Percent change -93.3 -91.0 -69.9 -21.4 +9.3 -22.5 -76

1 

### The complete text of the statute is shown in Attachment 1.

2 

### Lead and mercury emissions are reported in pounds per year.

### MPCA Review of MERP Proposal

page 2 

## In this report, the Minnesota Pollution Control Agency (MPCA) provides the analysis of Xcel’s proposal that is required under the emission re duction rider statute, based on its expertise in evaluating pollution control projects as part of its long-standing air quality regulatory programs. Specifically, Minn. Stat. § 216B.1692, Subd. 4 asks th e MPCA to advise the Minnesota Public Utilities Commission (PUC) as to:

 Verification that the emission reductions project qualifies under Minn. Stat. § 216B.1692, Subd. 1;

 A description of the projected environmen tal benefits of the proposed project; and

 The MPCA’s assessment of the appropria teness of the proposed MERP project.

In addition to answering the above questions in th is report, the MPCA is also to provide the PUC with answers to two questions posed under Minn. Stat. § 216B.1692 Subd.5(c):

 Whether the project is needed to comply with new state or federal air quality standards; and

 Whether the emission reduction proj ect is required as a corrective action as part of any state or federal enforcement action.

### MPCA Review of MERP Proposal

page 3 

# 2.0 Summary

The MPCA has reviewed Xcel’s proposal to determine whether the proposal qualifies under Minn. Stat. §216B.1692. The MPCA has also project ed the environmental benefits from the implementation of this project, and has generally assessed the co sts versus benefits of the emissions reduction proposal.
2.1 Qualifying Projects The rates of air pollutants released by these plants at the end of their reconstruction/rehabilitation under MERP represent “best available control tec hnology” at each plant, thus meeting conditions required under federal new source review regulations in place at the time Xcel made its filing. In making this determination, the MP CA has met its statutory require ment to determine whether the emissions reductions proposed meet applicable new source review standards, emit air contaminants at levels substantially lower than allowed by new source performance standards or reduce air pollutants to their lowest-cost e ffective level [Minn. Stat. §216B.1692, Subd. 4 (1)].

The MPCA has determined that the projects at the A.S. King and Riverside electric generating stations meet all conditions of Minn. Stat. § 216B.1692, and thus fully qualify for consideration under the statute. The High Bridge propos al meets the conditions of Minn. Stat. §216B.1692, except that the capacity of the plant increases by more than allowed for under the statute. The MPCA concludes that the first 100 MW of th e 270 MW expanded generating capacity at High Bridge qualifies. The treatment of the cost of the remaining 170 MW of new generating capacity should be considered for “recovery above cost” if the PUC determines th at it is appropriate as described by Minn. Stat. §216B.1692, subd. 5(b)(4).

Further, the MPCA has reviewed the proposal for e ach plant, and has determined that the project is not needed to comply with new state or federa l air quality standards, nor is the project required as a corrective action as part of a state or federal enforcement action.
2.2 Project Costs Because project costs are compared to the benef its of this proposal, project costs were reviewed to determine if they were within a reasonable range. This project i nvolves essentially three different types of construction/re habilitation: A.S. King involves some rehabilitation of the coalfired boiler to extend its life along with the addition of highly efficient pollution control equipment. Riverside involves repowering the plan t to combust gas instead of coal, and requires replacing portions, but not all, of the power pr oducing equipment onsite. High Bridge is the construction of a new gas-fired generatin g station to retire a coal-fired station.

Construction costs for the A.S. King rehabilitation and the Riverside project fall within a reasonable range as defined by similar projects either nationally or within Minnesota.

The cost of reconstructing High Bridge appear s to be about 20 percent higher than national figures for new greenfield plants, probably due to some unique site characteristics that need to be addressed for reconstruc tion on the existing power plant site. Xcel has explained several reasons for the higher costs associated with its work on the High Bridge project. The MPCA suggests that the PUC further explore the appropriateness of the portion of the High Bridge project costs

### MPCA Review of MERP Proposal

page 4 

## that exceed the national average to assure that these costs are appropriate for the site’s conditions.
2.3 Projected Environmental Benefits The MPCA must describe the environmental benefits that result from the implementation of this project [Minn. Stat. §216B. 1692, Subd. 4 (2)].

The A.S. King, High Bridge and Riverside pl ants contribute significantly to total overall emissions of sulfur dioxide (SO 2 

## ) to Minnesota’s air — the three plants alone represent almost half of SO 2 

## released by electric utilities in the state, and nearly a quarter of SO 2 

## emissions overall. The plants also are emitting sizable amounts of NO x 

## and mercury in Minnesota. The proposed project reduces SO 2 

## emissions from these plants by 93 percent, NO x 

## by 91 percent, and mercury by 76 percent.

Reductions in SO 2 

## and mercury will aid in continued improvements to Minnesota and the nation’s water bodies. Evidence is showing that further SO 2 

## reductions are still needed to reverse ecological damage of acid rain. SO 2 

## converts to sulfates which when deposited as acid rain, appear to encourage bacteria in lakes to methylate mercury, that is, convert mercury into the form that is readily accumulated by fish. Th is proposal would reduce contributions of both SO 2 

## and mercury, thereby reducing factors that contribute to mercury contamination in the environment.

Fine particulates strongly correlate with incr eased health problems, including early death from cardiopulmonary disease and lung cancer. Rese archers have not yet identified a threshold concentration where these health impacts disappear. Fine particulate effects extend even down to background levels.

Knowing this, EPA established an ambi ent standard for fine particles, PM 2.5 

## , and requires state regulatory agencies to issue air alerts when monitoring shows actual ambient values approach levels that are still below the federal ambient standard. In 2001 and 2002, Minnesota experienced several air alerts for high levels of fine particles in Minne sota, and Minnesotans are suffering impaired health effects from fine particulates.

Because SO 2 

## and NO x 

## are contributing to widespread health concerns, the pollutants are subject to considerable regulation. Most notable is the Bush Administration’s Clear Skies proposal to reduce power plant emissions. This proposal, as we ll as several others, measured health benefits when power plants’ SO 2 

## and NO x 

## emissions are reduced. One such study evaluating emissions of coal-fired power plants in Minnesota finds th at with reductions of the magnitude offered by this proposal, the net present value of health be nefits in Minnesota coul d be at least $1.2 billion.

This is compared to a calculation of benefits also prepared by the MPCA using PUC externality values. The MPCA calculation extends benefits out to 2040, and uses a discount rate in keeping with public health benefits. This calculation s hows PUC externality-base d benefits of the MERP project to be $200 to $500 million (in 2001 dollars). Even this conservative treatment of the benefits of this emissi on reduction proposal shows benefits gr eater than that calculated by Xcel in its July filing ($58 – $127 million).

### MPCA Review of MERP Proposal

page 5 

## This benefit estimate does not attempt to fully address health issues associated with fine particulates. It also does not consider the reduction in mercury, regi onal haze, acid rain, ground level ozone and impacts felt by the communities around the three plants such as truck and rail traffic.

Xcel has presented the argument that the avoi ded costs related to the construction of an additional 385 MW over the original generating cap acity at the three plants has a net present value of about $700 million. The MP CA concurs that there is real value to this generating capacity that is not reflected in the construc tion costs, nor in the assessment of benefits.

In addition to adding generating capacity, this project refurbishes about 1,100 MW of existing capacity without the need to develop new sites or construct new transmission lines. There is substantial benefit (perhaps in the several hundred million dollar rang e) for not having to replace this power in some other manner.
2.4 Appropriateness of the Project There are many benefits to the project that ar e not directly quantifiable, many of which are described in this report. The proposal addresses multiple issues related to power plant emissions — reduction of PM 2.5 

## forming pollutants, reduction in merc ury emissions, improved efficiency in generating electricity that is necessary to addr ess global warming, and reduction in haze-forming pollutants. The MPCA notes that there could be substantial local improvements in the areas around the High Bridge and Riverside plants by eliminating coal burning at the plants.

The MPCA believes that this e mission proposal is an important project to achieve improvements in many of these environmental problems, and th at benefits of the proj ect approximate and most likely exceed the capital cost of this project.

### MPCA Review of MERP Proposal

page 6 

# 3.0 Qualifying Projects

Under Minn. Stat. § 216B.1692, Xcel has proposed emission reduction projects at three power plants located in the Minneapolis-St. Paul metropolitan area.

A. S. King

 A rehabilitation of the A.S. King plant in Bayport would add controls to significantly reduce emissions of SO 2 

## , NO X 

## and PM 10 

## while increasing the plant’s capacity from 504 MW to 564 MW (a 60 MW increase in capacity). The King plant would continue to burn coal. The repowered plant would be functional in 2007.

High Bridge

 At the High Bridge plant in St. Paul, locat ed near the Mississippi River in downtown, Xcel proposes to replace the existing coal-fired pl ant (with 243 MW of capacity) with a new natural gas-fired combined cycle plant with 515 MW of capacity (a 272 MW increase in capacity). Even with the proposed increase in capacity, the switch to a cleaner fuel and a more efficient combustion technol ogy decreases emissions of SO 2 

## , NO X 

## , PM 10 

## and CO 2 

## , while eliminating the emissions of mercury. The new plant would come online in 2008.

Riverside

 In northeast Minneapolis, Xcel proposes to c onvert its 387 MW Riverside plant from a coalburning unit to a 439 MW combined cycle plant that uses natural gas (a 52 MW increase in capacity). The conversion from coal to natura l gas drastically decreases emissions of SO 2 

## , NO X 

## , PM 10 

## and CO 2 

## , while eliminating emissions of mercury. Electricity from the modified plant would come online in 2009.

The MPCA is charged with determining whether these proposals “qualify” for the cost recovery that is allowed under Minn. Stat. § 216B.1692. Th is section first describes how the MPCA considered the statutory requireme nts, then evaluates each plant proposal to determine if it is a qualifying project.
3.1 Minn. Stat. § 216B.1692 Subd. 1. Qualifying Projects. Projects that may be approved for the emissions reduction rate rider under this section must:

1) be installed on existing large electric genera ting power plants as defined under Minn. Stat. § 216B.2421 subd. 2(1), that are located in the stat e and not subject to emission limitations for new power plants under the federal Clean Air Act;

The definition of a large power plant under Minn. Stat. § 216B. 2421 includes the following:

“Large energy facility” means any electric power generating plant or combination of plants at a single site with a combined capacity of 50,000 kilowatts (50 MW) or more and transmission lines directly associated with the plant that are necessary to interconnect the plant to the transmission system;

### MPCA Review of MERP Proposal

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## 2) not increase capacity by more than 10 pe rcent or 100 megawatts, whichever is greater;

This is a straightforward calculation of increased generating capacity over current facility generating capacity.

3) result in the existing power plant either:

i) complying with applicable new source revi ew standards under the federal Clean Air Act; ii) emitting air contaminants at levels substantially lower than allowed for new facilities by the applicable new source performance st andards under the federal Clean Air Act; or, iii) reducing emissions from current levels at a unit to the lowest cost-effective level when, due to the age or condition of the generating unit, the public utility demonstrates that it would not be cost effective to reduce emi ssions to the levels in item (i) or (ii).

3.1.1 New Source Review New Source Review (NSR) is a federally manda ted air quality program th at was established in the 1977 Clean Air Act Amendments. It is design ed to improve the quality of the air in areas that have poor quality air. These are called “non attainment” areas because they do not meet the National Ambient Air Quality Standards (NAAQS). In attainment areas that do meet the NAAQS, NSR protects the quality of the air from significant deterioration.

NSR requirements may be triggere d by the construction of new e quipment with air emissions or by the modification of existing equipment with air emissions. In nonattainment areas, NSR requires the application of technology with the Lowest Achievable Emission Rate (LAER). The determination of LAER is fairly straightforward. For a specific emission unit, all potentially applicable technologies are assesse d; the best performing technology is selected as LAER, since the review includes no assessment of the cost.

In attainment areas, NSR requi res the application of the Be st Available Control Technology (BACT). 3 

## A BACT review assesses technologies that can be potentially used to minimize the emissions from a new or modified unit. The BACT review includes an assessment of the economic, energy, and environmental factor s associated with the various options.

3 

### The official definition of BACT is found in 40 CFR 52.21(b)(12), which states that “[b]est available control

technology means an emissions limitation (including a visible emission standard) based on the maximum degree of reduction for each pollutant subject to regulation under Act which would be emitted from any proposed major stationary source or major modification which the Administrator, on a case-by-case basis, taking into account energy, environmental, and economic impacts and other costs, determines is achievable for such source or modification through application of production processes or available methods, systems, and techniques, including fuel cleaning or treatment or innovative fuel combustion techniques for control of such pollutant. In no event shall application of best available control technology result in emissions of any pollutant which would exceed the emissions allowed by any applicable standard under 40 CFR parts 60 and 61. If the Administrator determines that technological or economic limitations on the application of measurement methodology to a particular emissions unit would make the imposition of an emissions standard infeasible, a design, equipment, work practice, operational standard, or combination thereof, may be prescribed instead to satisfy the requirement for the application of best available control technology. Such standard shall, to the degree possible, set forth the emissions reduction achievable by implementation of such design, equipment, work practice or operation, and shall provide for compliance by means which achieve equivalent results.”

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## For the economic assessment, EPA guidance insi sts on a “top-down” review of the available emission-reducing technologies. The first (or “t op”) technology to be considered in a top-down BACT analysis would be the one selected as LAER if the review was performed for a nonattainment area. This results in the selec tion of BACT as the best-performing technology that is determined to be cost-effective. Technol ogies can be eliminated from selection if they are not technically feasible or if associated ener gy or environmental effects outweigh the emission reduction benefits.

The Twin Cities metropolitan area is currently classi fied as an attainment area, so the level of control proposed by Xcel for each of these plants will be compared to the MPCA’s evaluation of what might be expected from a BACT analysis.

The question of whether the proposed projects comp ly with NSR is somewhat difficult to answer directly. NSR requires a case-by-case analysis that the MPCA does not perform until a highly detailed permit application is received. However, the MPCA has reviewed recent BACT determinations from the RACT/BACT/LAER Cl earinghouse (RBLC) and from other sources. 4 

## The EPA operates the RBLC, a database that re cords emission rates achieved by technologies used to limit emissions that have been approved as BACT.

A review of the most recent submittals to the RBLC and to other associated databases provides an indication of the types of controls that have been placed on similar emission units and the emission limits that permitting au thorities placed on these units under the NSR rules. Xcel’s proposals can then be compared to a range of limits for the three pollutants of concern (SO 2 

## , NO X 

## , and PM 10 

## ) at similar emission units. 5



## 3.1.2 New Source Performance Standards The New Source Performance Standards (NSPS) program was established in the 1970 Clean Air Act. Under NSPS, generation facilities constr ucted after 1972 are required to meet certain minimum performance standards with regard to emissions of several pollutants. Generation facilities that were constructed before 1972 are exempt from NSPS.

NSPS have been revised several times, and different standards apply to plants depending on the year they were constructed. NSPS have become progressively more stringent, so control requirements at plants subject to newer NSPS tend to be much more stringent than older NSPS requirements.

Under Minn. Stat. § 216B.1692, subd. 1(3), a project qualifies if it meets NS R requirements or if it would make emissions “substantially lower” than the NSPS would require. As will be

4 

### RACT means Reasonably Available Control Technology

5 

### It is important to note that the NSR regulations do not apply to CO 2 

### , mercury or PM 2.5 

### .

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## explained in the next section, the proposed proj ect meets one or both of these requirements for all three plants. 6



## 3.2 Do the Projects Qualify Under 216B.1692 Subd 1? 3.2.1 A.S. King

Is it an existing large electric generating power plant as defined under Minn. Stat. § 216B.2421 subd. 2 that is located in the stat e and not subject to emission limitations for new power plants under the federal Clean Air Act?

The A.S. King plant is located in Bayport, Minnesota on the St. Croi x River and has a net generating capacity of 504 MW. It meets the defi nition of a large electric generating power plant because it is larger than 50 MW. The boiler is a cyclone boiler that burns subbitumious coal. The boiler was constructed in 1968, before the Clean Air Act was passed, and thus before EPA promulgated NSPS for boilers. It is therefore not subject to the NSPS standards for power boilers. The project meets this requirement.

Does it increase capacity by more than 10 percent or more than 100 MW?

Xcel’s proposal to modify this plant results in an increased electricity generating capacity of about 60 MW, less than the statute’s specified 10 percent of existing capacity or 100 MW, whichever is greater. The pr oject meets this requirement.

Does the project propose “bes t available control technology”?

Table 2 on the following page shows the curren t emission rates at the King plant and the emission rates that would result from Xcel’s pr oposed emission reduction project with NSPS and BACT determinations for similar plants.

6 

### Because the MPCA found this to be the case, there was no need to analyze the projects under the third ground for

qualification in section 216B.1692, subd. 1(3)(iii).

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## Table 2. Comparison of Emission Data, including New Source Performance Standards, recent New Source Review Limits, existing and proposed emission rates for Xcel A.S. King. 7



### Capacity NO x 

### SO 2 

### PM 10


### MW mmbtu/hr Lb/mmBtu Lb/mmBtu Lb/mmBtu Current King emissions 504 5,205 0.71 1.39 0.019

New Source Performance Standards 8 

### 0.60 9 

### 1.2 10 

### 0.03 11



### Recent Best Available Control Technology determinations for coal-fired facilities 12


### Range of recent BACT determinations 0.07-0.15 0.12-0.25 0.015-0.018

Median of BACT determinations 0.095 0.155 0.017

Emissions, King Rehabilitated (MERP) 13 

### 564 5,205 0.10 0.12 0.018



## The proposed emission rates for the rehabilitation of the A.S. King plant reflect BACT-like control levels. BACT is more stringent than the applicable NSPS. Because the proposal

7 

### Emissions data from RACT/BACT/LAER Clearinghouse and National Coal-Fired Utility Projects Spreadsheet. A

compilation of information supplied by all 10 EPA Regions about new utility projects occurring in their geographic area, provided the data on new coal-fired generation. This spreadsheet was found on the RBLC Web site (www.epa.gov/ttn/catca/projects.html#rblcdocs).

8 

### New Source Performance Standards in 40 CFR 60 Subpart Da (40 CFR 60.40b-60.49b).

9 

### These limits apply to units that are modified or reconstructed units burning subbituminous coal. A modified coalfired unit would need to reduce NO x 

### by 65 percent.

A new unit would be required to meet a 1.6 lb/MWh limit. (It is difficult to convert directly from this limit to lb/mmBtu because the unit’s conversion efficiency – energy output/ energy input – must be known.)

10 

### This NSPS also requires a reduction of 90% of potential SO 2 

### , or a minimum reduction of 70 percent if controlled

emissions are below 0.6 lb/mmBtu.

11 

### The NSPS restricts emissions of PM (not PM 10 

### ) from natural gas boilers. The NSPS requires a 99 percent reduction

of uncontrolled PM from coal-fired boilers.

12 

### These BACT determinations were made for units burning coal. Modifications recorded in the RACT/BACT/LAER

Clearinghouse from 1999 to 2002 were included in the analysis. Values for NO x 

### were based on coal-fired cyclone boilers, while the values for SO 2 

### and PM 10 

### were based on boilers using subbituminous coal.

13 

### Emissions rates identified in Xcel Response to MPCA Request No.1, dated August 23, 2002, and the Xcel Response

to MPCA Request No. 2, dated September 5, 2002.

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## achieves BACT-like control levels for coal-fire d cyclone boilers, the project qualifies under this requirement.
Summary The A.S. King proposal meets all three c onditions of Minn. Stat. § 216B.1692, subd. 1, and thus is a qualifying project under the statute.

3.2.2 High Bridge

Is it an existing large electric generating power plant as defined under Minn. Stat. § 216B.2421 subd. 2 that is located in the stat e and not subject to emission limitations for new power plants under the federal Clean Air Act?

The High Bridge plant is located between Shep ard Road and the Mississippi River in downtown St. Paul. It has four boiler un its, two dedicated to producing steam for a manufacturer and two for generating electricity.

The electricity generating units, units 5 and 6, were brought online in 1956 and 1959 respectively. Unit 5 has the electricity genera ting capacity of 85 MW and Unit 6 has a capacity of 158 MW, for a total generating capacity of 243 MW. Because the facility is greater than 50 MW, it is a large generating station. The facility was brought online before the Clean Air Act was passed and thus before EPA promulgated NSPS for boilers. It is therefore not subject to the NSPS standards for power boilers. The project meets this requirement.

Does it increase capacity by more than 10 percent or more than 100 MW?

The proposed project for this location is to retir e and demolish the current coal-fired plant, stack and related coal-handling equipment, and re place the generating station with a “2-on-1” combined cycle natural gas facility capable of generating 515 MW. The project increases generating capacity by about 270 MW, which is greater than the 100 MW increased generating capacity expressly allowed by the statute. The first 100 MW of this increase meets the requirement of the statute. The remaining 170 MW is discussed in the summary for this section.

Does the project propose “bes t available control technology”?

Table 3 shows the current emission rates at the High Bridge plant and the emission rates that would result from Xcel’s proposed emission reduction project with NSPS and BACT determinations for similar plants.

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## Table 3. Comparison of emission data, including New Source Performance Standards, recent New Source Review limits, existing and proposed emission rates for Xcel High Bridge.

Capacity NO x 

### SO 2 

### PM 10


### MW mmbtu/hr Lb/mmBtu Lb/mmBtu Lb/mmBtu High Bridge 5, coal 85.2 869 0.58 0.37 0.013 High Bridge 6, coal 158 1,611 0.58 0.37 0.013

New Source Performance Standards 14 

### 0.20 15 

### 0.20 0.03 16



### Recent Best Available Control Technology determinations for natural gas-fired facilities 17


### Range of Recent BACT determinations 0.009-0.055 0.0008-0.216 0.0076-0.048

Median of BACT determinations 0.013 0.006 0.013

Emissions, High Bridge Combined Cycle (MERP) 18, 

### 515 3,761 0.011 0 0



## Emission rates for the proposed new natural gas combined cycle plant are comparable to BACT control levels established for similar units. BACT is more stringent than the applicable NSPS. Because the proposal achieves BACT-like contro l levels, the project meets this requirement.

In addition, the emissions for this proposed pl ant are substantially lower than the emissions required by current state and federal standards for new power plants (NSPS).

14 

### New Source Performance Standards in 40 CFR 60 Subpart Da (40 CFR 60.40b-60.49b).

15 

### These limits apply to units that are modified or reconstructed units burning natural gas. A modified natural gas-fired

unit would need to reduce NOx by 25 percent.

A new unit would be required to meet a 1.6 lb/MWh limit. (It is difficult to convert directly from this limit to lb/mmBtu because the unit’s conversion efficiency — energy output/ energy input — must be known.)

16 

### The NSPS restricts emissions of PM (not PM 10 

### ) from natural gas boilers.

17 

### These BACT determinations were made for combined cycle units burning natural gas. Modifications recorded in the

RACT/BACT/LAER Clearinghouse in 2001 to 2002 were included in the analysis.

18 

### Emissions rates identified in Xcel Response to MPCA Request No.1, dated August 23, 2002, and the Xcel Response

to MPCA Request No. 2, dated September 5, 2002.

Xcel has represented emissions of SO 2 

### and PM 10 

### from gas-fired facilities as zero. It must be recognized that while not precisely zero, direct emissions of these pollutants will be extremely small.

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## Summary The High Bridge proposal meets all three conditions of Minn. Stat. § 216B.1692, subd. 1, except that the capacity of the plant would increase by approximately 270 MW, more than the 100 MW maximum allowed for projects to qualify under th e statute. The MPCA concludes that the proposed emission reduction project up to the fi rst 100 MW of the capacity increase fully qualifies.

The treatment of the cost of the remaining 170 MW of new capacity could be handled as an allowed “recovery above cost” if the PUC determines that it is appropriate to allow this recovery as “necessary to improve the overall econo mics of the qualifying project to ensure implementation under Minn. Stat. § 216B.1692, subd. 5(b)(4 ).” To the extent that the additional 170 MW of capacity is needed to improve the ove rall economics of the project, thus encouraging its voluntary implementation by Xcel, then costs of that additional capacity may also qualify for rate recovery.

3.2.3 Riverside

Is it an existing large electric generating power plant as defined under Minn. Stat. § 216B.2421 subd. 2 that is located in the stat e and not subject to emission limitations for new power plants under the federal Clean Air Act?

The Riverside Plant is located on the east ba nk of the Mississippi River north of downtown Minneapolis. It has three power boilers.

Boilers 6 and 7 were initially constructed in 1946 and 1948 respec tively. Together, these two boilers generate steam for one steam turbine. Boiler 8, first installed in 1961, has a separate steam turbine.

Due to the dates of construction, these units we re not initially subject to either NSPS or NSR regulations because they were built before the Clean Air Act was passed. A physical change was made to the facility in the 1980s, but EPA determined that the change did not trigger NSPS.

The plant’s capacity exceeds 50 MW so it is an existing large electricity generating plant.

Does it increase capacity by more than 10 percent or more than 100 MW?

The proposed project involves the repowering of th e Riverside plant. While the existing Unit 7 steam turbine and condenser will continue to be used, Xcel plans to install a natural gas-fired “2- on-1” combined cycle turbine arrangement. This will replace existing coal-fired boilers 6 and 7. Portions of the existing plant will be demolished.

The repowering of the plant will expand the generating capacity of the Riverside plant to 439 MW from its existing capacity of 386 MW. While the increase of 53 MW exceeds 10 percent of the facility’s existing capacity, it remains be low the limit of 100 MW (the maximum increase allowed under the statute), and thus meets this requirement.

### MPCA Review of MERP Proposal

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## Does the project propose “bes t available control technology”?

Table 4 shows the current emission rates at the Ri verside plant and the emission rates that would result from Xcel’s proposed emission reduction project with NSPS and BACT determinations for similar plants.

Table 4. Comparison of Emission Data, including New Source Performance Standards, recent New Source Review Limits, existing and proposed emission rates for Xcel Riverside.

Capacity NO x 

### SO 2 

### PM 10


### MW mmbtu/hr Lb/mmBtu Lb/mmBtu Lb/mmBtu

Riverside 6/7 134 1,371 0.83 0.38 0.013

Riverside 8 226 2,233 0.99 1.26 0.078

New Source Performance Standards 19 

### 0.20 20 

### 0.20 0.03 21



### Recent Best Available Control Technology determinations for natural gas-fired facilities 22


### Range of Recent BACT determinations 0.009-0.055 0.0008-0.216 0.0076-0.048

Median of BACT determinations 0.013 0.006 0.013

Emissions, Riverside Combined Cycle (MERP) 23 

### 439 3,538 0.015 0 0

19 

### New Source Performance Standards in 40 CFR 60 Subpart Da (40 CFR 60.40b-60.49b).

20 

### These limits apply to units that are modified or reconstructed units burning natural gas. A modified natural gas-fired

unit would need to reduce NO x 

### by 25 percent.

A new unit would be required to meet a 1.6 lb/MWh limit. (It is difficult to convert directly from this limit to lb/mmBtu because the unit’s conversion efficiency — energy output/ energy input — must be known.)

21 

### The NSPS restricts emissions of PM (not PM 10 

### ) from natural gas boilers.

22 

### These BACT determinations were made for combined cycle units burning natural gas. Modifications recorded in the

RACT/BACT/LAER Clearinghouse in 2001 to 2002 were included in the analysis.

23 

### Emissions rates identified in Xcel Response to MPCA Request No.1, dated August 23, 2002, and the Xcel Response

to MPCA Request No. 2, dated September 5, 2002.

As mentioned previously, Xcel has represented emissions of SO 2 

### and PM 10 

### from gas-fired facilities as zero. It must be recognized that while not precisely zero, direct emissions of these pollutants will be extremely small.

### MPCA Review of MERP Proposal

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## It is reasonable to expect a slightly higher emission rate at the Riverside plant than at High Bridge because the project involves integra ting new combustion and air pollution control equipment into an existing site with existing generation equipment. In particular, had this proposal been an entirely new plant (like the High Bridge plant), then the NO x 

## emissions rate might have been expected to be slightly lower.

However, the proposed NO x 

## emissions rate appears to be we ll within the range at which new combined cycle facilities that install BACT are ex pected to perform. T hus the proposal achieves a level of control reflecting th e application of BACT and exceed s the applicable NSPS. Because the proposal achieves BACT, the project meets this requirement.
Summary The Riverside proposal meets all the conditi ons of Minn. Stat. § 216B.1692, subd. 1, thus is a qualifying project under the statute.

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# 4.0 Other Questions the PUC Must Consider

Minn. Stat. § 216B.1692, Subd. 5 requires the PUC to evaluate whether:

1. the emission reduction project is needed to comply with new state or federal air quality standards; or

2. the emission reduction project is required as a corrective action as part of any state or federal enforcement action.

The MPCA has evaluated both of these que stions and has concluded the following:

1. None of the proposed projects are currently needed to meet any new state or federal air quality standards.

These three plants do not have to meet any performance standards for new sources because they were built before the Clean Air Act passed and EPA had developed specific performance standards. (Also see th e discussion regarding this in Section 6.) In addition, through ambient monitoring a nd/or dispersion modeling, the MPCA has determined that these projects are not required to meet any ambient air quality standards. Although there are several pot ential regulatory developments that may impose more limits on these plants, none are yet in effect. 24



## 2. None of the proposed projects are curren tly required as a corrective action as part of any state or federal enforcement action.

A potential enforcement action involves chan ges to the King plant’s coal handling equipment that the MPCA be lieves may have been made without first obtaining a required permit. EPA, at Xcel’s request, is deciding whether it agrees with the MPCA’s interpretation of the federal requirement at issue.

If EPA agrees that Xcel is subject to the federal standard, and thus should have obtained a permit before making changes, possible corrective actions would not involve the proposed projects. Xcel has already installed a dust collector as the pollution control equipment to reduce PM/PM 10 

## from coal handling, and has conducted a monitoring analysis of the am bient air. Any further corrective action requirements would not include the proposed projects because they would affect coal handling, not the operation of, or emissions from, the boiler.

On December 21, 2000 and May 6, 2002, EPA issu ed formal requests for information to Xcel regarding changes to several of its plants, including High Bridge, King and Riverside. Xcel completed their responses to these requests on May 4, 2001 and

24 

### For a description of these potential developments, see Appendix A of the 2001 Energy Planning Report, pp. 103-105

(Attachment 2). Also see p. 2 of the 2002 update to that report. (Attachment 3)

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## October 28, 2002, respectively. EPA is in the process of deciding what, if any, enforcement action may occur based on the information provided by Xcel.

There has not been a state or federal enforcement action concluded against Xcel that requires as its corrective action any of the proposed projects.

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# 5.0 Estimated Capital Cost of the Proposal

The MPCA analyzed the cost of the proposed pr oject to determine whether the estimated costs are reasonable because they will end up being compared with the estimated benefits of the project. The MPCA has reviewed the constructi on costs of the proposals to determine whether they are within an expected reasonable range of costs.

The MPCA’s experience in assessing the cost of projects has developed from its reviews of cost estimates of emission units and air pollution control equipment when assessing economic impacts of air pollution control policies and rules, and specifically from its experience reviewing and approving “best available control technology” (BACT) de terminations used for air permitting.

5.1 Method of analysis The MPCA compared Xcel’s estimates of construction cost to estimates provided for similar-size plants using similar electrical generating technol ogies. In general, comparisons between generating choices are expressed as the capital cost for each kilowatt of capacity.

In order to determine whether the budgetary costs presented in the filing were within an expected reasonable range of cost, the MPCA sought out estimating tools or costs of actual projects of similar size and scope. Thus, a variety of cost estimates are used, and their accuracy is discussed when they are presented.

The MPCA recognizes that Xcel has provided a budgetary estimate, which will likely be refined by Xcel as specific site-assessment, design and procurement activities occur. The MPCA’s understanding of budgetary estimates is that they are prepared to be within 30 percent of the final cost of the project, that is, fi nal project costs may be 30 percent higher or lower than the budgetary estimate.

Xcel proposes a cost-recovery process that a llows the PUC to review actual costs during construction, which is appropriate. The MPCA is at this point considering the budgetary estimates to compare them against expected environmental benefits of the project.

5.2 Assessment of A.S. King Cost Estimates This project is a rehabilitation of an existing facility. The rehabilitation will improve combustion and generating efficiencies. No additional coal will be burned yet an additional 60 MW of generating capacity will be regained. The air pollution control aspect of this project includes the removal of existing electrostatic precipitators to install selective catalytic reduction (SCR) for NO x 

## control, and spray drying and fabric filters for acid gas and particulate control (SD/FF). Emission reductions were quantified earlier.

Xcel’s cost estimates are based on their descripti on of project costs in their response to Sierra Club’s information request number 10. In that response, Xcel reports that the air quality portion is 55 percent of the total project cost.

### MPCA Review of MERP Proposal

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## The first set of cost information available to compare to Xcel’s estimates comes from actual retrofits of flue gas desu lfurization controls and NO x 

## controls at power plants. Retrofitting this equipment has been a common activity for power plants because of the acid rain control provisions required by the 1990 CAA amendments, as well as EPA’s NO x 

## State Implementation Plan call for NO x 

## emissions reductions in the eastern United States in 1998. 25 

## The MPCA identified separate sources for estimating the cost of retrofitting with SCR and SD/FF. Costs reflecting average national capital costs were de veloped by EPA and are included in several reports that the U.S. Department of Energy’s Energy Information Administration (EIA) prepared to assess the impacts of multi- pollutant control strategies (EPA 1998, EPA 1999a, EIA 2000).

EIA reports that the national average cost of a dding flue gas desulfurization is about $195/kW in 1997 dollars, or about $215/kW in 2001 dollars. NO x 

## controls, specifically SCR for high NO x 

## emitters has a capital cost of about $71/kW in 1997 dollars, or $78/kW in 2001 dollars. (EIA 2000) To estimate the cost of retrofitting a fa bric filter, the MPCA used cost estimating guidelines prepared by EPA, as this retrofit has not been commonly undertaken by power plants (EPA 1999a). The cost of retrofitting an FF for a 570 MW plant is currently estimated to be about $69/kW.

Another source of cost estimating information is EPA’s CUECost. CUECost is an electronic cost-calculating workbook that provides a means for air quality permitting authorities to estimate expected construction and operating costs of ai r pollution control equipment at power plants. The workbook has been used by permitting author ities and consultants in the preparation of BACT analyses, and allows the user to input site-specific design requirements of the proposed equipment.

The CUECost workbook was designed to produce “rough” cost estimates (+/-30 percent). In testing the model, the developers found that the model predicted estima ted SD/FF construction costs within +/- 15 percent of the published capita l costs of various power plant projects (Keeth). In order to ensure a conservative cost estimate, the MPCA selected input options that included burning Wyoming and Montana coals, difficult re construction (retrofit factors), with expected inflation of three percent per year.

CUECost estimates a total capital cost for an ai r pollution control retrofit on a 570 MW boiler to cost about $210 million dollars, or about $368/kW.

These estimated capital costs are compared in Table 5.

25 

### The EPA has issued a requirement for dozens of states east of the Mississippi to substantially reduce NO x 

### emissions. These emissions, when transported to cities long distances away, contribute to the formation of ozone at levels that would exceed health-based air quality standards. Many power plants subject to this requirement have needed to retrofit NO x 

### controls to make the reductions expected of them.

### MPCA Review of MERP Proposal

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## Table 5. Comparison of capital cost estimates for A.S. King

Size (MW) 2001 total project construction costs (in millions) Installed Cost per kW generating capacity ($/kW)
Xcel’s estimate — A.S. King, total capital cost 564 363 637

Rehabilitate boiler,

turbine/generator 163 287

Total Air Pollution control cost 200 350

NO x 

### control (SCR) 26 

### 92 161 Acid gas control (SD/PJFF) 26 

### 108 189
Energy Information Agency 2001/EPA 1999a/EPA 1998

Total Cost of Air Pollution Control Retrofit (sum of individual estimates below) 362

NO x 

### control (SCR) 78 Acid gas control (LSD) 215 Particulate control (FF) 69

EPA CUECost Workbook Adding SCR/PJFF/LSD

Total Cost of Air Pollution Control Retrofit 570 210 368

NO x 

### control (SCR) 85 Acid gas control (LSD) 185 Particulate Control (PJFF) 101



## Table 5 reports the estimated costs to retrofit the A.S. King plant with pollution control equipment as compared to retrofit cost estimates from EIA and EPA. The table reports both the total air pollution control costs and se parately reports costs to control NO x 

## and SO 2 

## (acid gas control/flue gas desulfurization).

Table 5 shows that the total air pollution control retrofit cost estimates for A.S. King is slightly lower than the total project costs estimated by CUECost and than national averages. The individual component costs are, however, significan tly different. Xcel reports that SCR vendors’ quotes have been much higher than is suggested by the national databases used to prepare the cost estimates in Table 5, due in part to the higher demand for SCR controls at utilities in the eastern United States. Unlike spray drying, S CR is not a “fully-matured” technology; it has not been installed and used over long periods of time where there are no real incremental

26 

### SCR = selective catalytic reduction; PJFF = pulse jet fabric filter; LSD = lime spray drying; SD = spray drying

### MPCA Review of MERP Proposal

page 21 

## improvements in design and operation being made. Each recent installation still offers some instruction to equipment designers and utility operators for future improvements, and now-higher vendor quotes may reflect this. Xcel indicates that installing SCR will require sophisticated foundation and structural work atthe King plant, which also may translate to a higher-thanaverage cost for this control device.

Spray drying and fabric filter estimates for A.S. King are lower than national estimates, due to it being a fully mature technology. Xcel re ports receiving vendors’ estimates that would manufacture and install both the spray drying and fabric filter components together, which leads to lower than average costs. Using a single equipment supplier to provide multiple units lowers the cost by eliminating the need for coordination and tie-in between two different manufacturers.

Xcel’s capital cost estimates for the air pollution control equipment retrofit at A.S. King are within an expected reasonable range of cost. The project’s expected cost is consistent with the capital costs experienced by the industry for this type of project.

5.3 Assessment of High Bridge Estimated Costs The scope of this project requi res the construction of combined cycle/steam generators and transmission capacity, and demolition of the existing four boilers.

Air pollution control benefits result from changi ng the fuel choice a nd combustion technology. Because changing combustion technology inherently results in pollution reductions, it is difficult to separate project costs between electricity ge neration and air pollution control, as was done at A.S. King.

To evaluate estimated construction costs, the MPCA sought out estimates for new advanced cycle combustion turbines, as this proposal is more in keeping with new plant construction.

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## Table 6. Comparison of capital cost estimates for High Bridge

Size (MW) 2001 total project construction costs (in millions) Installed cost per kW generating capacity ($/kW)
High Bridge, Xcel, advanced combustion combined cycle 515 $371 720

Energy Information Agency Outlook 2002, advanced combustion combined cycle 27 

### 607



## No advanced combined-cycle project has been installed in Minnesota that allows direct comparison. The MPCA identified two natura l gas-fired simple cycle turbine projects constructed in Minne sota of similar size to the High Bri dge proposal. The PUC gave approval in 1999 and 2000 to construct two ge nerating stations: Lakefield Junction and Pleasant Valley.

The Lakefield Junction project involved construc tion of a turbine/gene ration facility producing 515 MW. The project also included upgrading ex isting power lines, but no construction of new lines. The total cost of the project was $216 million.

The Pleasant Valley project included construction of a facility with a generating capacity of 434 MW. The project also involved constructin g six miles of 161 kV transmission lines, and rebuilding approximately 17 miles of existing 69kV lines to 161/69 kV. The total cost of the project was $195 million.

These two plants are simple cycle peaking plants with a planned utilization rate of about five percent. They are technologically more s imple and operate much less often than the intermediate-load plant proposed for High Bridge, and as such, are significantly less expensive to construct. As a result, they are not comparable to the High Bridge proposal.

The MPCA reviewed EIA’s project ed construction cost for the simple-cycle generating station to determine how accurate an appr oximation the EIA values are to costs experienced in Minnesota. Adjusting for inflation, the Lakefield Junction proj ect was within 12 percent of the installed cost estimated by EIA (EIA 2002). Because the Pl easant Valley constr uction cost includes transmission lines, it is not a direct comparison to EIA costs. However, its construction cost is about 30 percent higher than EIA’s estimates.

27 

### EIA cost estimates include contingencies as suggested by EIA. The cost estimate has also been inflated by 2.5

percent per year.

### MPCA Review of MERP Proposal

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## EIA predicts new “greenfield” advanced combus tion combined cycle generating stations to have an installed cost of about $607/kW. 28 

## This is down slightly from the EIA 1999 Energy Outlook where the installed cost of combined cycle stations averaged $641/kW. This decrease may suggest that as this type of electric generation is more widely deployed, its development costs may be falling 29



## . The High Bridge project budgetary estimate appears to be about 20 percent higher than the average national cost for installing advance combustion combined cycle generating stations as reported by EIA ($720/kW for High Bridge compared to $607/kW from EIA). Xcel suggests that the difference in its construction estimates and the EIA cost estimates is due to the difference between greenfield construction a nd reconstruction at an existing power plant site. Xcel has included a certain number of cost factors that relate to expectin g “unforeseen” site conditions.

Redevelopment of previously developed sites — “brownfield” construction — often requires some unique work to conform the s ite to its new use or to fit the new use on to the site. Some of the site-specific costs that may cause Xcel’s cost estimate to be higher than average national costs include: the need for an extra cooling tower to eliminate steam and icing problems; site remediation; connection to ga s infrastructure; and costs to tear down the existing plant.

5.4 Assessment of Riverside Estimated Costs This project converts the coal-fired plant to natural gas — the existing steam generating equipment in use on Unit 7 will be retained. Air pollution control benefits occur from the change in fuel type. It is difficult to compare this project cost to retrofitting air pollution control equipment, or the construction of a new greenfield plant. Cost estimating tools like CUECost are not able to estimate the cost of converting combustion systems from coal to gas. Therefore, the MPCA compares the cost of this project to that of a similar completed project here in Minnesota, the repowering of the NSP Black Dog Plant in Burnsville.

Table 7. Comparison of Estimated Capital Costs for Riverside

Size (MW) 2001 total project construction costs (in millions) Installed Cost per kW generating capacity ($/kW)

Xcel Riverside 439 212 483 Xcel Black Dog Repower 290 164 565



## The Riverside station has a current generating capacity of 387 MW; the proposed project results in the addition of about 52 MW of additional generating power, an increase of about 14 percent. The Black Dog repowering project added 114 MW, or a 63 percent increase in the generating capacity of the replaced units. The Black Dog repowering added consid erably more generating

28 

### “Greenfield” means construction at an undeveloped site (lit erally, building a plant in the middle of a “green field”).

29 

### We also note that while not a definitive cost study, a recent trade journal also reports installed costs of simple cycle

turbine/generators in the “neighborhood” of $375/kW, and combined cycle stations to be around $600/kW. Power, August 2002. “Top Plants Survey” available at www.platts.com/engineering/issues/Power/0208/index0208.shtml

### MPCA Review of MERP Proposal

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## capacity than the Riverside repowering (114 MW v. 53 MW). The PUC approved the Black Dog project’s Certificate of Need on July 21, 2000. Th e Riverside project cost appears to fall within the range of a similar project already approved by the PUC.

5.5 Summary Construction costs for the A.S. King rehabilitation and the Riverside project fall within a reasonable range as defined by similar projects either nationally or within Minnesota.

The cost of reconstructing High Bridge appear s to be about 20 percent higher than national figures for new greenfield plants, probably due to some unique site characteristics that need to be addressed for reconstruc tion on the existing power plant site. Xcel has explained several reasons for the higher costs associated with its work on the High Bridge project. The MPCA suggests that the PUC further explore the appropriateness of the portion of the High Bridge project costs that exceed the national average to assure that these costs are appropriate for the site’s conditions.

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# 6.0 Impacts of Power Plant Emissions

6.1 Contribution of Power Plants to Air Pollution in Minnesota Electrical utility power plants are a major source of air pollution. In Minnesota, power plants contribute about 50 percent of total sulfur dioxide (SO 2 

## ) emissions, 16 percent of total nitrogen oxides (NO X 

## ) emissions, 35 percent of carbon dioxide (CO 2 

## , a greenhouse gas), 43 percent of mercury emissions and betw een 10 and 60 percent of other metals emissions.

Power plants are also a large contribut or to fine particulate levels (PM 2.5 

## ) in Minnesota’s air. The emissions of SO 2 

## and NO x 

## are converted through atmospheric reactions to create fine particulate. Power plants also directly emit particles, regulated as “PM 10 

## ,” that is, particles with a diameter of 10 microns and less.

A detailed analysis of the emissions from Minne sota’s power plants can be found on pages 93 – 98 of Attachment 2 (the environmental anal ysis from the 2001 Energy Planning Report).

Table 8 and Figures 1 – 5 show the contribution of the three Xcel power plants that were selected for emission reduction projects to total statewide emissions of these pollutants.

Table 8. Quantity of emissions of selected pollutants from Minnesota sources, 2000 30



### SO 2 

### tpy NO X 

### tpy PM 10 

### tpy Mercury lb/yr CO 2 

### tpy
A.S. King 27,251 14,354 307 69 3,763,594 High Bridge 3,459 5,397 430 66 1,839,005

Riverside 12,794 13,102 535 98 2,750,201

Total MERP

Plants 43,504 32,853 1,272 233 8,352,800

Other point

sources 91,209 133,741 50,901 2817 36,596,606

Area and mobile

sources 54,922 366,259 841,920 593 64,160,115

Minnesota total 189,636 532,853 894,093 3,643 109,109,521



## From the table above and from Figure 1 on the next page, it can be seen that the SO 2 

## emissions from the three Xcel plants (A.S. King, High Br idge and Riverside) c ontribute almost half of

30 

### Emissions of sulfur dioxide, nitrogen oxides, and particulate matter taken from the MPCA’s Emission Inventory and the National Emission Inventory. Mercury emission data taken from Mercury Emissions in Minnesota – Draft: 2002 Update (MPCA). Carbon dioxide emission data we re provided in a personal communication with Peter Ciborowski, MPCA.

### MPCA Review of MERP Proposal

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## Minnesota’s estimated point source emissions or about one-fourth of the state’s estimated total SO 2 

## emissions. 31



## Figure 1. Minnesota sulfur dioxide emissions, 2000 (total =189,636 tons)

Figure 2 illustrates the relationship between the NO X 

## emissions from the three plants and those from other state sources. These power plants to tal about 20 percent of the point source emissions in the state or roughly six percent of NO X 

## generated in the state.

Figure 2. Minnesota nitrogen oxide emissions, 2000 (total = 532,853 tons)

31 

### “Point sources” are facilities, such as power plants and large factories, that emit air pollution from a smokestack from

a fixed location. 3 % 2 % 1 %

Area and mobile

sources

69% Other points

sources

25% A.S. King 3% Riverside 2% High Bridge 1% 48 % 14 % 2 %

Other point sources 48%

Area and mobile

sources

29% A.S. King 14% Riverside 7% Highbridge 2%

### MPCA Review of MERP Proposal

page 27 

## Figure 3 shows that these three metro area plants emit a very small portion of statewide PM 10 

## emissions. While these plants are not large direct contributors to PM 10 

## , Figures 1 and 2 show that they are significant contributors to SO2 and NOx emissions which once emitted, are the precursors of PM 2.5 

## formation.

Figure 3. Minnesota particulate matter emissions, 2000 (total = 894,093 tons)

Figures 4 and 5 demonstrate that these three metro area power plants emit small but significant portions of the statewide e missions of mercury and CO 2 

## . Point sources emit a very large portion of the state’s mercury emissions. As shown in Figure 4, more than four of every five pounds of mercury are emitted from point sources. Energy production overall contri butes about one-half of the mercury released in Minneso ta. About one in 16 pounds of me rcury released in the state comes from one of these three power plants. 32



## Figure 4. Minnesota mercury emissions, 2000 (total = 3,643 pounds)

32 

### For more information about mercury emissions in Minnesota and related impacts, see the MPCA’s 2002 Mercury

Reduction Program legislative report at www.pca.state.mn.us/hot/legislature/reports/2002/mercury-02.pdf. Other point sources 6%

Area and mobile

sources

94% 3 %

0 % A .S. King, Riverside, Highbridge combined

> 1%

77 %

Other point sources 77% Area and mobile

sources

16% Riverside 3% A.S. King 2% Highbridge 2%

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page 28 

## Table 8 and Figure 5 provide the picture for CO 2 

## , the primary greenhouse gas. Here, as with NO X 

## and SO 2 

## , power plants in general and, specifically, these three power plants produce a significant share of the total emissions.

Together, the three plants share about seven percent of the state’s total CO 2 

## emissions. Since point sources make up just under half of the st ate’s emissions, these pl ants contribute about 15 percent of the point source emissions.

Figure 5. Minnesota carbon dioxide emissions, 2000 (total = 109,109,521 tons)

6.2 Environmental and Health Effects of Emissions from Power Plants As described above, power plan ts contribute substantial amount s of pollutants to Minnesota’s atmosphere. A variety of health and environmen tal effects have been linked to these pollutants. This section briefly summarizes these impacts. 33



## The Department of Commerce’s 2001 Mi nnesota Energy Planning Report 34 

## contained a section on the health and environmental effects of electri city generation, which is Attachment 2 (pp. 98- 103) of this report. Attachment 3 to this report, pp. 1-2, contains the 2002 update on effects of these emissions. This following section will briefly describe the most significant effects of power plant emissions and not duplicate the material in Attachments 2 and 3.

33 

### Additional information about air pollution emissions can be found in the MPCA’s 2001 Legislative Report Air

Quality in Minnesota: Problems and Approaches, available on the MPCA Web site at www.pca.state.mn.us/hot/legislature/reports/2001/airquality.html.

34 

### The full report is available at www.commerce.state.mn.us/pages/EnergyPolicy/2002PlanningRpt.pdf. Riverside 3% A.S. King 2% Highbridge 2%

Other point sources 38%

Area and mobile

sources

55%

### MPCA Review of MERP Proposal

page 29 

## 6.2.1 Particulate matter Of particular concern today is the contribution of power plants to the amount of very small particles (or fine particulate matter, PM 2.5 

## ) found in the air. This concern has developed as a result of the increasing number of studies describi ng the adverse effects of very small particles on the respiratory and cardiovascular systems. Ambient air monitoring has shown that much of the fine particulate matter comes from nitrates and sulfates. This section describes what particulate matter is, how it is form ed and its effects on human health.

With the passage of the 1970 Clean Air Act, Cong ress directed EPA to review the evidence for health and environmental effect s of the well-known air pollutants, including particulate matter (PM). Congress instructed EPA to develop National Ambient Air Quality Standards (NAAQS) for their control. Through the establishmen t of NAAQS and efforts to achieve them, air pollutant levels decreased. Many people at that time believed the particulate matter air pollution problem was solved.

In the past 10 or 15 years, however, the availability of sophisticated statis tical software, medical records databases and more extensive air polluti on trend data has allowe d new and better health science (epidemiology) studies. A remarkable number of studies consistently find a range of serious and other health impacts associated with levels of particulate in the ambient air lower than previously thought to have these effects.

While total ambient PM concentration levels ha ve dropped, recent evidence shows that the size of the particle has health conse quences. To help characterize the health effects, particles are described as falling into two sizes. The larger group of particles is identified as “coarse,” which has a diameter ranging from 2.5 to 10 microns (PM 10 

## ). “Fine” particles are those smaller than 2.5 microns (PM 2.5 

## ). The characteristics, sources and health effects of these two sizes of particulate matter are different.

Coarse particles from unpaved road s may become airborne when “kicked up” by vehicle traffic. Rock crushing operations generate coarse partic les, as does the wind when it blows across the desert or agricultural fields. The particulate e missions from such sources can often be tracked by their plumes. These particles settle rapidly to the ground from the atmosphere, and so their impacts to health and environment occur fairly cl ose to the source. Coarse particles tend to be caught by some of the body’s defense mechanisms, including the nasal passages and mucus membranes, and are often remove d by regular body processes before embedding in the lungs.

In contrast, fine particles are invisible to the eye, deeply inhaled and not easily cleared by the lungs. Major sources are cars, trucks, constr uction equipment, coal-fired power plants, wood burning, vegetation and livestock. These particles can be directly released when coal, gasoline, diesel fuels and wood are burned.

Many fine particles are also formed in the atmosphere from chemical reactions of nitrogen oxides, sulfur oxides, organic compounds and a mmonia. The reaction process occurs over great distances as the gases released from power plant stacks and other sources disperse in the air. Once airborne, fine particles tend to remain in the atmosphere for long periods of time (days to

### MPCA Review of MERP Proposal

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## weeks) and travel hundreds to thousands of kilo meters. This results in air impacts on local and regional scales.

Exposure to coarse particles is associated primarily with aggravating respiratory conditions, such as asthma. Fine particles are associated with a range of adverse health effects such as coughing; shortness of breath; aggravation of existing respiratory conditions like asthma and chronic bronchitis; increased susceptibility to respiratory infections; and heightened risk of premature death from heart attacks and respiratory conditions . As an example, two landmark epidemiology studies provided strong evidence that long-term exposures to fine particles caused increased early deaths from cardiopulmonary causes in the United States (Dockery et al. 1993; Pope et al. 1995; Krewski, 2000; Pope et al. 2002).

Hundreds of epidemiology studies have assessed the health effects evident within a few days after spikes of particulate concentrations, that is, “acute” or short-term exposures. Commonly these studies link daily fine partic ulate levels not only to increases in death rates, but to increased hospital admissions for cardiovascular disease, pneumonia, and chronic obstructive pulmonary disease.

Further, with improved research methods, health scientists have studied areas with lower levels of air pollution and have been unable to iden tify a threshold (a level below which no effect occurs) for some of the more serious health effect s of particulate matter. So far, no threshold has been found at ambient leve ls (Schwartz et. al 2002).

6.2.2 EPA Response The Clean Air Act requires EPA to review the scientific evidence and revise ambient air standards “from time to time” to accurately re flect the latest scie ntific knowledge about identifiable health effects. EPA undertook rulema king in July 1997 to revise the ambient air quality standards in part to address the finding s of the serious health impacts of long-term exposure to PM 2.5 

## . Subsequently, EPA established an am bient air quality standard for these fine particles.

EPA retained the existing PM 10 

## standard to continue to addre ss the health effects from PM larger than 2.5 microns. EPA also issued new rules related to monitoring for PM 2.5 

## in the outdoor air.

Section 109 of the Clean Air Act di rected EPA to set the ambient air quality standard such that the

...level of air quality, in the judgment of the [EPA] Administrator, based on the criteria and allowing for an adequate margin of sa fety are requisite to protect public health. Clean Air Act, Sec. 109 (b)(1).

This language has been commonly assumed to imply that for these pollutants there are thresholds, levels below which there would not be adverse biological effects. Because of the inability to set a standard below which there would be no health effects, EPA chose to set a PM 2.5 

## NAAQS, and then required regulatory agencies to announce health advisories to the public when monitored PM 2.5 

## concentrations reach levels somewhat lower than the standard. EPA set

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## an annual PM 2.5 

## ambient standard of 15 g/m 3 

## and a 24-hour standard of 65 g/m 3



## . 35 

## EPA requires the MPCA to announce an unhealth y air pollution alert when the 24-hour PM 2.5 

## concentration exceeds 40.5 g/m 3



## .

6.2.3 PM 2.5 

## in Minnesota

PM 2.5 

## has been measured in Minnesota for about three years to determine whether Minnesota attains the NAAQS. The Twin Cities’ PM 2.5 

## concentration in 2001 was 13 g/m 3 

## . Rural areas are lower. The Twin Cities’ concentration is at the midrange of the U.S. metropolitan areas being monitored for compliance with the federal ambient air standard.

PM 2.5 

## is composed of many chemicals. When analyzing composition, the mass is classified as sulfates, nitrates, organic carbon, elemental carbon, ammonium ions, and other material, including metals and crustal ma terial. Minnesota has three urban monitors measuring the composition of PM 2.5 

## which have been operating for about a ye ar. Results of this monitoring are shown in Figure 6.

Figure 6. PM 2.5 

## composition in Minnesota (Sept. 2001 – Oct. 2002)

Power plants contribute significantly to several of the different fractions of PM 2.5 

## . Coal-fired power plants are significant contribut ors to the sulfate component of PM 2.5 

## due to the total amount of SO 2 

## released from power plant stacks. To a lesser extent, they contribute a smaller fraction to the nitrate component due to their NO x 

## emissions.

35 

### On Feb. 27, 2001, the U.S. Supreme Court unanimously upheld the constitutionality of the Clean Air Act as EPA had

interpreted it in setting these health-protective air quality standards. On March 26, 2002, the U.S. Circuit Court rejected the remaining claims that EPA's decision was arbitrary and capricious and not supported by the evidence. 0 2 4 6 8 10 12 14 16 18



### St. Paul (Harding) 

### Minneapolis (Phillips) 

### Rochester

Other

Ammonium ion

Elemental Carbon Organic Carbon

Total Nitrate

Sulfate Ion Annual PM 2.5 standard is 15 ug/m3concentration (ug/m3)

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## 6.2.4 Air Alerts for Particulate Matter in the Twin Cities EPA’s Clean Air Science Advisory Committee recogn ized there may not be a risk-free threshold of PM 2.5 

## and concluded there may be a continuum of effects potentially extending down to background levels (64 Federal Register 42530-42549, Aug. 4, 1999). As ambient concentrations increase, more individuals are likely to experience effects, and the seriousness of health effects increases. Minnesotans are likely suffering effects from current levels of PM 2.5


## . While this region meets the 24-hour PM 2.5 

## ambient standard of 65 g/m 3 

## and the annual standard of 15 g/m 3 

## , the MPCA has had to issue air alerts when PM 2.5 

## levels reach 40.5 g/m 3



## . EPA has specified 40.5 g/m 3 

## for these warnings because research has shown that serious health effects can occur at levels below the federal NAAQS. The PM 2.5 

## air alert level was required to be reported for the first time in 2002.

One alert for fine particles was issued in 2002 when smoke from the Canadian fires reached Minnesota. More recently, in December 2002, an air alert for PM 2.5 

## was issued due to a temperature inversion that trappe d fine particles near ground level.

In addition, a review of available PM 2.5 

## data indicates that concentrations in the Twin Cities reached levels considered “Unhealthy for Sens itive Groups” (children and the elderly) on seven days during calendar year 2000 and on four days during calendar year 2001, had PM 2.5 

## air alerts been required in those years. One PM 2.5 

## event considered “unhealthy” for all groups was monitored in October 2000 in Minneapolis. Mon itoring data shows that unhealthy levels of PM 2.5 

## can occur throughout the year in Minnesota.

6.2.5 Ozone Ground level ozone, also called “smog” forms in the atmosphere through chemical reactions involving NO X 

## , volatile organic chemicals and sunlight. In Minnesota, ozone pollution is primarily a summer problem because of the ne ed for sunlight in the formation process.

Ozone can adversely affect healthy adults, however children — because of their continuing physical development — and people with existin g respiratory problems are far more susceptible to its presence. Higher ozone levels can cau se eyes to itch, burn and water, trigger asthma attacks, and prompt coughing, chest pains and di fficult breathing. Because they generate large emissions of NO X 

## , power plants are a significant contributor to ozone.

6.2.6 Air Alerts for Ozone in the Twin Cities EPA promulgated a new, more restrictive ozone standard in 1997. Currently, that standard is being met in Minnesota. However in the last two years, the MPCA has had to issue air alerts for ozone four times in 2001 and twice in 2002. These represent the first air pollution alerts that have been issued for ozone since the 1970s.

A recent study has determined that ozone levels appear to be increasing the Twin Cities. (Chinkin et al. 2002) If this trend continues and the Twin Cities beco mes a nonattainment area for ozone, new federal regulations costin g between $189 and $266 million per year would be

### MPCA Review of MERP Proposal

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## required (Aulich and Neuson 1999). Requirements would include si gnificant new restrictions on allowable emissions from point sources and significant air quality requirements for transportation planning in the metropolitan area.

6.2.7 Haze High concentrations of fine particles reduces visibility. While haze may affect people at home and at work, impaired visibility is of greatest importance in places like national parks and wilderness areas, which people visit to enjo y recreational opportunities. However, they sometimes find scenic vistas obscured due to fine particles in the air. The difference in visibility between higher and lower pollution levels is shown in Figure A.14 in Attachment 2.

To address this, EPA promulgated a rule in 1999 that requires states to develop plans to return visibility in parks and wilderness areas to “n atural conditions” by mid-century. Controlling power plant emissions will be necessary to reduce the fine particles causing impaired visibility. In Minnesota, plans to reduce haze in Voyage urs National Park and th e Boundary Waters Canoe Area must be developed by 2008. The MPCA is wo rking with nine other states to prepare a regional plan to reduce haze.

6.2.8 Global Climate Change Global warming results from the accumulation of greenhouse gases in the atmosphere. These very long-lived gases act to absorb infrared radiation, trapping it in the lower atmosphere, leading to increasing temperatures of the earth’s surface and lower atmosphere. The result of global warming affects every aspect of what we know as weather.

Power plants are the second largest source of greenhouse gas emissions in Minnesota, just slightly behind transportation fuel use. While th ere is some debate about what to do about the problem of global warming in the short-term, there is general agreement that in the long-term, greenhouse gas emissions must be substantially reduced. 36



## 6.2.9 Mercury Minnesota’s fish are contaminated with mercury. Because contaminated fish are found in nearly every area of the state (as well as in commercial fish available to Minnesotans), the Minnesota Department of Health has issued safe-eating guidelines. MDH continues to provide lake- or stream-specific advice based on the results of fi sh sampling, but its current advice is expanded to include all fish caught while fishing in Minneso ta. The MPCA has liste d 784 lakes as “impaired waters” as a result of mercury contamination in fish. This means that humans must limit their fish consumption to avoid ingesting unsafe levels of mercury.

Most mercury entering lakes and streams in Minnesota comes from mercury deposited from the air. In northern Minnesota, rain and snow deposit about one gram of mercury to a 20 acre lake

36 

### The MPCA described in some detail the mechanisms, causes and effects of global warming in Department of

Commerce’s 2001 Energy Planning Report, Appendix A, pp. 101 to 103. (Attachment 2)

### MPCA Review of MERP Proposal

page 34 

## each year. One gram of mercury is the amount in a fever thermometer or 50 fluorescent lamps. Minnesota has been one of several states that ha ve led the nation in reducing releases of mercury to the air, particularly through eliminating the use of mercury in commercial products and their disposal.

However, energy production contributes about half of the mercury emitted in Minnesota. Energy production contributes to local deposition of mercur y, as well as to the global pool of mercury.

6.2.10 Acid Rain “Acid rain” refers to the deposition of acid that ha s formed in the atmosphere onto lakes, streams and forests. The acidification of a lake or stream can change its nature, sometimes substantially. The primary causes of acid rain are sulfur dioxide and nitrogen oxides released to the air. Coalfired power plants are significant contri butors to acid rain because of the SO 2 

## and NO x 

## they emit. Because of actions taken in the 1980’s by the Minnesota legislature and the MPCA, the acidity of rainfall in Minnesota has improved.

In Title IV of the 1990 Clean Air Act Amendmen ts, Congress created the Acid Rain program. Simply stated, Title IV required a fifty percent reduction in utility SO 2 

## emissions from 1985 levels by 2000. In addition, utilities n eeded to make some cuts in NO X 

## emissions.

To make the needed cuts in national SO 2 

## emissions, Congress approved a market-based approach. Existing utilities were given allowances based on their historical emissions. These allowances were less than the amount the power plants had previously emitted. This gave utilities the option of reducing their own SO 2 

## emissions or of buying SO 2 

## “reduction credits” from utilities that reduce their emissions below their allowances.

Congress used a different approach to reduce NO X 

## emissions. Utilities were required to meet a system-wide average NO X 

## emission rate. This allowed many utility companies to control emissions at one power plant without making changes at other facilities.

Minnesota’s utilities, including Xcel, found that the SO 2 

## emission targets could be met by switching from Eastern coals to Western coals, and implemented that strategy. To meet the NO X 

## requirements, Minnesota’s utilities cut emissions significantly at one plant and spread the emission reduction out over their entire system.

Unfortunately, rainfall acidity in the northeastern United States is still damaging the environment there, and it is generally acknowledged in the scientific and regulatory communities that further substantial reductions in these pollutants are needed.

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# 7.0 Assessment of Benefits of the Proposed Project

7.1 Emission Estimates of the Proposal The MPCA has independently calculated likely a nnual reductions in ai r emissions under Xcel’s proposal, presented in tables 9 through 11 belo w. Current emissions are shown in Table 9.

Table 9. MPCA’s estimated annual emissions for Xcel generating stations at current emission factors and typical operation.

Capacity factor 37 

### SO 2 

### (tpy) NO X 

### (tpy) PM 10 

### (tpy) CO 2 

### (tpy) CO (tpy) Lead (pounds) Mercury (pounds) A.S. King 0.70 22,182 11,331 303 3,271,501 432 207.5 68

High Bridge Unit 5 0.47 662 1,038 23 371,023 47 9.3 High Bridge Unit 6 0.53 1,384 2,169 49 775,255 93 19.4 High Bridge, Total 2,046 3,207 72 1,146,278 141 28.7 66

Riverside Unit 6/7 0.58 1,323 2,891 45 724,441 99 9.1

Riverside Unit 8 0.70 8,626 6,778 534 1,403,507 188 20.5
Riverside, Total 9,950 9,669 579 2,127,948 287 29.6 98

Three plants, Total 34,178 24,206 954 6,545,727 860 265.8 232



## Emissions estimates after retrofits or reconstruction are shown in Table 10.

Table 10. MPCA estimated emissions after proposed changes.

Capacity

factor SO 2 

### (tpy) NO X 

### (tpy) PM 10 

### (tpy) CO 2 

### (tpy) CO (tpy) Pb (pounds) Mercury (pounds) A.S. King 0.70 2,298 1,915 345 3,810,897 519 207.5 54 High Bridge 0.47 0 38 

### 107 0 1,087,230 198 0 0

Riverside 0.53 0 167 0 1,327,735 223 0 0

Three plants, Total 2,298 2,189 345 6,225,862 940 207.5 54

37 

### “Capacity factor” reflects how much the plant will be used to generate electricity during the year. A capacity factor of 1.0 would indicate operation 100 percent of the time. Most plants are operated at a capacity factor of 0.80 or lower. The factors used on Table 9 are from Xcel’s MERP proposal.

38 

### As noted before, Xcel has represented emissions of SO 2 

### and PM 10 

### from gas-fired facilities as zero. It must be recognized that while not precisely zero, direct emissions of these two pollutants will be extremely small.

### MPCA Review of MERP Proposal

page 36 

## Table 11. Comparison of annual overall emissions before and after the proposed changes.

SO 2 

### NO X 

### PM 10 

### CO 2 

### CO Lead Mercury Emissions change (tpy) -31,880 -22,017 -667.1 -319,865 +80 -60 39 

### -178 Percentage change -93.3 -91.0 -69.9 -21.4 +9.3 -22.5 -76



## The MPCA calculations strongly agree with Xcel’s estimates of emission reductions. Xcel reported emissions over a period of 10 years in its filing, and not annual emissions. 40 

## Xcel reports increased releases of CO 2 

## and CO at A.S. King due to increased generating capacity and facility utilization.

Mercury emissions should be virt ually eliminated at High Bridge and Riverside upon conversion to natural gas, removing the rel ease of 164 pounds of mercury per year 41 

## . With the implementation of MERP, mercury emissions are expected to be lowered by 20 percent at King, or about 14 pounds. Total mercur y reductions from MERP from current operation is about 178 pounds, or approximately 12 percen t of mercury emissions from co al-fired electricity generation in Minnesota.
7.2 Xcel Energy’s Estimates of the Environmental Benefits from MERP Xcel Energy uses the PUC’s high environmental externality values and estimates that the net present value of MERP’s environmental bene fits will be $127 million over 10 years. Table 12 shows what assumptions were used to produce this estimate.

A.S. King’s benefits were calculated using the PUC’s metro fringe environmental externality values, while the urban values were applied to reductions at High Bridge and Riverside.

Mercury is not figured into Xcel’s environmental benefits calculation because the PUC has not established an environm ental externality value. 42 

## Similarly, PM 2.5 

## was not a regulated pollutant at the time the externality values were developed, so no externality value was established for this pollutant.

39 

### Changes in lead and mercury emissions are reported in pounds per year.

40 

### See Attachment 4.A of Xcel’s petition.

41 

### www.xcelenergy.com/Environment/TRI2001MNWIbody.asp. Accessed October 3, 2002

42 

### The PUC established externality values for lead emissions, however the amount of lead released (and further reduced by MERP) is so small that it does not change the benefit calculations.

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## Table 12. Xcel’s Calculation of Environmental Benefits of Proposed Plan 43 

## (Net Present Value in 2001 dollars)

43 

### Xcel filing, Attachment 4.B. Calculated for the period beginning the first full year a plant is back in service through 2020. While an externality value is provided for lead emissions, its contribution to this calculation is so small that the MPCA has chosen not to include it in these discussions.King High Bridge Riverside Total ProposalHighExternalityValueAverageEmissions, tpyreducedPresent value,benefitsHighExternalityValueAverageEmissions, tpyreducedPresent value,benefitsHighExternalityValueAverageEmissions, tpyreducedPresent value,benefitsNet present value,benefitsSO20 23,700 0 0 3,100 0 0 12,000 0 0NOx298 16,700 $18,799,000 1,094 4,400 $19,367,000 1,094 13,100 $58,174,000 $96,340,000CO23.47 -482,000 ($17,998,000) 3.47 415,000 $2,636,000 3.47 1,570,000 $20,177,000 $4,815,000CO1.5 -100 ($1,000) 2,054 20 ($3,000) 2,054 140 $1,000 ($3,000)PM3,229 90 ($431,000) 7,187 100 $3,304,000 7,187 540 $22,669,000 $25,542,000TOTAL$369,000 $25,304,000 $101,021,000 $126,694,000

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## 7.3 Avoided Costs Xcel’s proposal results in an increase in generati on capacity of 385 MW. This is equivalent to a good-sized power plant. Xcel refers to some ME RP benefits as “avoided costs.” Xcel assumes that by including this additional generation cap acity in their MERP proposal, they would avoid significant costs associated with this additional capacity. The net present value costs minus the avoided costs result in a cost of about $900 million.

By making changes at existing power plant s ites, the proposal eliminates the need for new transmission lines needed to bring power to Minnesota’s load centers, and it eliminates the costs associated with developing a new plant. X cel has estimated that avoided costs for the 2006 to 2034 period are $712 million. 44



## It is important to note that this does not take into account the “avoided emissions” that would be associated with this generation capacity. Adding new generation capacity of 385 MW to the current Xcel system, or purchasing an equivale nt amount of power generated elsewhere, will result in greater overall emissions than proposed by this project.

In addition to the new generating capacity that will be added as a result of this project, Xcel also will be rebuilding or refurbishing more than 1,100 MW of power at existing plants. This will result in adding tens of years of additional useful life from th ese plants. This is important generating capacity located on existing transmission lines near load centers.

Xcel has not factored in the value of this bene fit in their proposal. Considering their estimates of $712 million as the value of avoided costs for 385 MW of new power, the value of extending the useful life of the current 1,100 MW at these thr ee existing plants must be in the several hundred million dollar range.
7.4 MPCA Estimate of Projected Environmental Benefits
The MPCA believes that Xcel’s calculation of the environmental benefits with current PUC externality factors does not take into consideration a number of important factors. The MPCA has calculated the benefits of this project using several alternative assump tions. In addition, it is important to note that the PUC externality f actors were developed for resource planning purposes, and evaluating resource planning deci sions among different types of generation technology options, not for evaluating the health and environmental bene fits of a particular project.

7.4.1 Time Period Xcel’s benefit estimates end in 2020. Since the MERP proposes physical changes that will last beyond 2020, environmental benefits will extend beyond 2020 as well.

A more appropriate statement of benefits and costs should have estimates that cover the likely duration of physical capital. Xcel estimates that MERP will extend the King plant’s useful life

44 

### Xcel Response to MPCA request for data Number 17. November 18, 2002.

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## by 20 years. 45 

## Since MERP will reconstruct the High Bridge and Riverside plants it seems appropriate to treat them as new plants, once ME RP is complete. They should last at least as long as the refurbished King Plant. More conventional assumptions set the useful life of a utility plant at 30 years or more (EIA 2000).

In reply to an MPCA request, Xcel estimated costs for a period that extends to 2034. Estimates end in 2034 because Xcel assumes the PUC will not approve “life extensions” that go beyond 2034. The new and refurbished plants will be fully depreciated by 2034, so there is no more cost to estimate.

At the same time, Xcel expects that the refurbis hed plants’ useful lives will extend beyond their book lives. Experience confirms this assumption. 46 

## This real world experience informs the assumptions many analysts make about the opera ting lives of electricity generating plants (EIA 1994, EIA 2002, DOE 1999, FERC 1980).

In the MERP case, it seems reasonable for pla nning purposes to think in terms of the project having a useful life that extends from co mpletion of the project to at least 2040.

If benefit estimates are ex tended to 2040, total environm ental benefits would double. 47



## 7.4.2 Discount Rates Xcel discounts its estimates — both benefits and costs — at a “co rporate discount rate.” The specific rate chosen is 7.9448 percent. It is a pr ivate rate of return that applies specifically to Xcel’s financial operations. The firm, its shar eholders and the PUC s hould take alternative investment choices into account when evaluating capital decisions. Xcel’s allowed discount rate is appropriate for future costs.

However, although a private discount rate is appr opriate for costs that Xcel will incur, different factors influence the discount rate for the value of environmental benefits. MERP’s environmental benefits will accr ue to a large community — one that extends well beyond Minnesota’s borders. Unlike private benefits that belong to individuals, pub lic benefits belong to everyone in an affected community. General price inflation will decrease the value of future

45 

### Xcel Energy reply to MPCA information request number 2, September 5, 2002, p. 3-6)

46 

### See data on the operating lives of retired and current plants in the Energy Information Administration's Form EIA860A Database, www.eia.doe.gov/cneaf/electricity/page/eia860a.html.

47 

### A rough estimate of the effect caused by extending the forecast period to 2040 shows a doubling of the net present

value of benefits. However, the net present value of revenue requirements (costs) does not increase as fast, increasing by about 50 percent.

Extending the time period for benefit and cost estimates requires some care. Rates of change for the two factors are different. We can expect benefit values to increase because the PUC has declared that they will increase at the same rate as the money value of gross domestic product. (Benefit values seem likely to increase for other reasons as well. For example, rising incomes will increase benefit estimates. But these sorts of changes are less predictable.) On the other hand, Xcel predicts that costs and revenue requirements will decline (see Attachments B.2. and DOC-12-A. of Xcel’s petition).

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## public benefits, so the same inflation-compensating rate should be used for both costs and benefits.

Financial risk is a different matter. Xcel’s shar eholders incur a risk that other investments may yield better rates of return. A significant por tion of the corporate discount rate compensates Xcel’s investors for the risk they accept with investment decisions. Risk does not affect public benefit values. Public benefits are spread so broadly that risk does not affect individuals. Everyone in a community affected by the MERP has the same chance, all other factors being equal, to enjoy the benefits of cleaner air. In this case, risk is moot because no one can choose, say, slightly dirtier air in exchange for some other public good they value more. Since public benefits accrue without risk, the discount rate for public benefits should be lower than the private discount rate.

EPA’s Science Advisory Board has accepted, w ith qualifications, a three percent discount rate for public benefits:

“Discounting future benefits and costs is conceptually appropriate and practically important... Unfortunately, there is substantial uncertainty about the appropriate disc ount rate to use. The rate of three percent proposed by the EPA seems reason able, and other values should be employed in a sensitivity analysis. The Council supports EPA’s proposed choice of discount rates, but re commends that EPA take pains to acknowledge conceptual and practical uncertainties inherent in the choice of discounting strategies.” (EPA 2001)

Therefore, for the purposes of evaluating the pr oject’s public benefit, the MPCA thinks a more appropriate discount rate to use is three percent. 48 

## By way of sensitivity analysis, benefits discounted by three percent are compared with benefits discounted at Xcel’s corporate discount rate. The lower discount rate nearly doubles the estimated value of e nvironmental benefits.

7.4.3 Reconsideration of Benefits and Costs MERP’s capital costs are spread out over four years:

2006 $500.2 million
2007 $332.1 million
2008 $177.4 million
2009 $34.0 million Total $1,043.7 million

48 

### MPCA adjustments take into account consideration of the Administrative Law Judge’s 1996 recommendation that the PUC adopt values for CO 2 

### that are discounted at three and five percent.

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## The present value of $1.04 billion (2002 valuati on, at a 7.9448 percent discount rate) is about $785 million. Xcel has also estimated a present value that combines both capital costs and returns on investment as allowe d under PUC orders. This “rev enue requirement” is $1.2 billion. It extends from 2006 to 2020. Because the MPCA believes the benefits will accrue well beyond 2020, it is appropriate to look at extending the cost estimate.

In reply to an MPCA request, Xcel estimated the net present value of revenue requirements for a period that extends from 2006 to 2034. Estimates end in 2034 because Xcel assumes the PUC will not approve “life extensions” that go be yond 2034. The new and refurbished plants will be fully depreciated by 2034, so there is no more cost to estimate.

The revised cost estimate is $1.6 billion. 49 

## Since this is the amount that Xcel’s customers are expected to pay for MERP over a longer period of time, it is a more appropriate value that should be compared to MERP’s benefits.

The net present value of the total project is approximately $1.6 billion, assuming the plant life beyond 2020 as described above. Taking avoided costs into account puts the net present value of the proposal closer to $900 million. Using a realis tic time frame and a mo re appropriate discount rate, the benefits are estimated at between $200 million and $500 million when using the PUC’s environmental externality factors. Figure 7 shows how the adjustments described earlier affect the estimate of benefits. This comparison does not take into ac count the substantial benefit of extending the useful life of the existing plants.

In addition, as described in the next section, the MPCA believes that this assessment of the MERP, even with the adjustments made so far, under-predicts the projects’ benefits, and that benefits are at least equal to the net present value of this project.

Figure 7. Estimate of MERP Benefits to year 2040

49 

### Xcel Response to MPCA request for data Number 16. October 25, 2002. 0 100 200 300 400 500 600

Xcel - original MERP benefit estimate Extended time period - 2040 end date 2040 end date discounted at 3%$ millions, net present value



### High Externality Value Low Externality Value

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## 7.5 Alternative Means of Assessing the Benefits of Controlling Power Plant Emissions Other studies have estimated the benefits of reducing coal-fired power plant emissions, many prepared to inform policy decision makers wh en imposing new emissi on reduction requirements. These studies provide estimates of the health effects avoided by reducing emissions of sulfur dioxide and nitrogen oxides.

The MPCA has identified four assessments that have been conducted in the United States estimating the benefits of reducing power plant emissions which are similar to Xcel’s emissions reduction proposal. Although there are similaritie s between these studies and the approach used to develop the externality values used in Xcel ’s emissions reduction pr oposal, these four studies were conducted using more curren t methods than were available when externality values were developed.

For example, these studies incorporate health effects information from studies showing serious health effects from long-term exposures to particulate air pollution that has been recognized since the externality proceeding was completed. The parameters of the assessments and the benefits they estimate are briefly described below. Each of these follows the same general approach outlined in the following discussion. They differ somewhat in the assumptions used in calculating the health impacts and costs.

7.5.1 The Benefits Assessment Methodology The following approach has typically been used to estimate the benefits of reduced air emissions; 50



## 1. Define the reduction in e missions to be assessed. 2. Estimate the change in pollutant air concentrations over a defined geographic region. Computer models predict the concentrations of air pollutants by modeling the dispersion of pollution and estimate the formation of particles from SO 2 

## and NO x 

## and other chemicals in the atmosphere. 3. Characterize the location of exposed human populations and their current death and disease rates. 4. Identify the potency of particulate matter to increased adverse health effects from the epidemiology literature. (These measures , known as concentration-response functions, estimate the percent increase in a health effe ct in a population for a specified increase in the particulate ma tter concentration.) 5. Estimate the number of deaths or cases of disease avoided by reducing emissions. These estimates assume that particles are causally associated with health effects, and that all particle components ha ve similar toxicity. 6. Some studies follow the estimate of the changes in disease or death incidence with an economic valuation, that is, calculating the ec onomic benefits associated with avoiding these health effects.

50 

### Besides the four studies described in this document, EPA has used this approach to assess the benefits of

implementing the Clean Air Act in its report to Congress, and to assess the benefits of two specific regulations: the Tier 2 Gasoline regulations and the Heavy Duty Engine/Diesel Fuel rule.

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## Table 13 summarizes the expected emission reductions, the estimated health benefits and cost savings included in the four assessments descri bed below. There are inherent uncertainties in this type of assessment. Complete studies recognize and describe the uncertainties associated with the estimated benefits. Th e table lists the estimated annual benefits from these studies with the estimated annual benefits from MERP, based on Xcel’s ca lculation using the PUC’s externality values.

A recent National Academy of Sciences report (NAS 2002) and EPA’s Science Advisory Board (SAB 2001) each reviewed EPA’s methods for estimating health benefits from reducing air pollution, with an emphasis on the method of assessing benef its from reducing PM 2.5 

## . Both generally supported these types of benefits anal yses to estimate the benefits of air pollution reductions, and recommended that fu ture studies more fully describe the uncertainties associated with the estimated benefits.

Some of the important uncertainties of the f our studies below include the uncertainty when modeling emission estimates for facilities in the future, the chemical formation and dispersion of particulates, and the concentra tion-response function of particle s from specific sources. Other uncertainties inherent in other similar scientific inquiries, a nd having differing importance, include variability of population de mographics and heterogeneity, intersubject variability, health and exposure baselines.

7.5.2 EPA’s Clear Skies Initiative In 2001, the Bush Administration proposed the “C lear Skies Initiative” to reduce emissions from electric power generating utilities. Nationwide, the Clear Skies Initiative is estimated to reduce emissions of sulfur dioxide by 73 percent, nitr ogen dioxides by 67 percent, and mercury by 69 percent.

The largest estimated benefits come from reducing the level of ambient particles. The estimated national annual mone tary benefits in 2020 are $89 billion for 12,000 avoided premature deaths and $3.2 billion for 7,400 fewer cases of chronic bronchitis, totaling $93 billion for all estimated health effects. The estimate of avoided early deaths is based on studies of the potential cumulative effect of long-term exposure to particles.

EPA separately estimated the impacts of pollutant reductions that occur over much shorter time periods. This short-term estima te concludes that on a national scale, 7,400 early deaths would be avoided by reducing power plant emissions.

In Minnesota, EPA projected that a Clear Skie s program would reduce pa rticulate matter levels across the state, and result in 100 fewer early d eaths due to their health effects. Because PM 2.5 

## is a regional pollutant, benefits estimated in Minnesota are a result of emission reductions in Minnesota and other states, and re ductions in Minnesota result in benefits in other states. All health improvements combined result in $1 billion in benefits in Minnesota from Clear Skies. 51

51 

### Details of the assessment of the human health benefits expected from the Clear Skies Initiative can be found at

www.epa.gov/clearskies/tech_adden.PDF.

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## 7.5.3 Eight Utilities Study Eight utility systems in the eastern half of the United States were the subject of a study to estimate the health impacts of emissions from th eir coal-fired power plants (Abt Assoc. 2002). This assessment estimated that roughly 5,900 prem ature deaths might be avoided if emissions ceased from these plants. The study did not attempt to translate these deaths and other respiratory effects into economic terms. The study estimates emissions from power plants in Illinois and Indiana contributing significantly to deaths in Missouri, Illinois, Indiana, Wisconsin and Minnesota.

7.5.4 Two Massachusetts Power Plants Harvard researchers Levy and Spengler estimated the health benefits of reducing SO 2 

## and NO x 

## emissions from the Brayton Point and Salem Har bor coal-fired power plants in Massachusetts (Levy and Spengler 2002). Their analysis comp ared current emissions with emission rates estimated under best available c ontrol technology (BACT), which results in emission reductions of 57,348 tons of SO 2 

## and 11,074 tons of NO x 

## per year from the two plants.

The predicted reductions of ambient annual PM 2.5 

## concentrations ranged from 0.006 ug/m3 to 0.2 ug/m 3 

## PM 2.5 

## covering a 600 km by 600 km area in th e Northeast U.S. This study estimates that this reduction in SO 2 

## and NO x 

## would reduce about 70 premature deaths each year over a total population of 33 million. Additi onal health effects were not considered. While suggesting caution when calculating the value of the avoide d early deaths, the authors used standard EPA valuation for a statistical lif e and determined these avoide d deaths represent a $400 million benefit per year.

7.5.5 Minnesota Power Plants Nelson estimated the public health impacts of particulate emi ssions from current coal-fired power plants in Minnesota, and the impacts if th ese plants switched from burning coal to burning natural gas (Nelson 2000). The study concluded th at by switching from coal to natural gas, about 25 early deaths would be avoided. Othe r health benefits include fewer new cases of bronchitis, emergency room visits, days of respiratory symptoms, and days of restricted activity. This study calculated that the economic benef it from switching to natu ral gas is $165 million per year (1996 dollars).

This study recognizes that using high stacks at power plants to disperse pollutants means that much of the damage from the emissions occur out side Minnesota. However, Xcel’s Riverside plant was estimated to have the highest incidence of early deaths (nine) due to its location within a heavily populated area.

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## Table 13. Comparison of benefits when power plant emissions are reduced.

Benefit Assessment Annual Benefits ($/yr) 52 

### Avoided Deaths NO x 

### reductions (tons per year) SO 2 

### reductions (tons per year)

Clear Skies (nationally) $93 billion 12,000 5,000,000 2,500,000

Clear Skies in Minnesota $1 billion 100 91,000 17,000

Eight Utilities Not calculated 5,900 Not presented Not presented

Two MA Power Plants $400 million 7 0 11,000 57,000

Minnesota Power Plants $165 million 2 5 53,700 57,000

Xcel Emissions Reduction Proposal 22,000 31,900



## Table 13 shows the estimated annual benefits calculated by each of the studies described above. Applying the Minnesota high environmental exte rnality factors to the average annual emissions avoided by implementing this pr oject would result in an annual benefits estimate of about $24 million (2001 dollars). This low value compared to the results of the recent studies above strongly suggests that the PUC’s externality factors are not in concert with other researchers and institutions’ assessment of the impacts of power plant emissions.

Since the PUC adopted its externality values, the weight of evidence for significant public health impacts from breathing fine particles is significantly stronger and more widely recognized. Peer reviewed methods for estimating h ealth benefits from reducing SO 2 

## and NO x 

## emissions and the associated long-term exposures to fine particle air pollution were used in the assessments above, and are being used to support developing fede ral regulatory programs like the Clear Skies Initiative, as well as national ambient air standards.

A comparison between Xcel’s estimated benefits from the MERP proposal and the results of the four studies above strongly suggest that extern ality values underestimate the health benefits of lowering emissions. There is compelling evidence that greater benefits accrue if the health impacts resulting from fine particulates were re-evaluated using methods similar to the Bush Administration’s Clear Skies Initia tive or these other assessments. Xcel’s proposal results in emission reductions about half that evaluated by Nelson, sugge sting that benefits could be at least $80 million per year (in 1996 dollars) — half of the benefits estimated in Nelson after the project is fully implemented. This translates to a net present value of more than $1.2 billion (in 2001 dollars) for the pollution reductions that are achieved with the MERP project.

52 

### Note that the annual benefits shown in this table represent calculations in different years and thus reflect different

dollar values. They are presented here to show the magnitude and range of benefits associated with reducing emissions from coal-fired power plants.

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## The four studies summarized above rely on models to simulate bene fits associated with emission reduction scenarios. The models are mathematical estimates of real world relationships. They rest on statistical foundations that are subject to bias and uncertainty. However, these models, and others like them, are tools th at environmental regulators use to evaluate potential regulations and decide on what emission reductions should be made.

The body of scientific evidence persuades the MPCA that Xcel Energy’s estimates significantly undervalue MERP’s environmental benefits, and that alternative assessmen t techniques would place benefits on par with the costs of the project.

7.6 Conclusions on the Estimation of Quantifiable Benefits

 The net present value of the project for th e period 2006 to 2034 minus the avoided costs for the 385 MW of new capacity ($712 million) is about $900 million.

 Xcel’s costs and benefits are calculated th rough 2020. Since these plants will last many years longer than that, using a larger timeframe to calculate costs and benefits is appropriate.

 Xcel used a corporate rate to discount costs and benefits. A lower discount rate is more appropriate to asse ss public benefits.

 Adjusting for longer plant life and lowering the discount rate, the benefits calculated from PUC externality values become $200 – $500 million.

 The calculation does not account for the value of extending the useful life of approximately 1,100 MW of existing power by decades.

 The calculation does not adequately account fo r the cost of impacts of fine particles on human health, as demonstrated in Section 7.5. In addition to the growing weight of evidence related to the damages from fine particles, there have been refinements in various assumptions. For example, the estimated value of a statistical life has increased since the PU C first conducted public hearings on the establishment of the externality values. A “statistical life” is th e amount people are willing to pay to reduce the risk of dying. When the PUC set environmental exte rnality values in 1995, the value of a statistical life was estimated to be approximately $3.5 million. Since then, new analyses have increased the estimated value of a statistical life.

EPA, in its regulatory impact analyses, now assumes a statistical life value in the $6 million range. EPA’s analyses have so far passed review and criticism by its Science Advisory Board. EPA continues to refine its estimates for review and comment by the Science Advisory Board. Increasing the value of a statistical life estimate to conform to EPA’s current practice doubles the portion of Xcel’s current present value benefits estimate related to death caused by air pollution.

Benefits are also under-predicted in the assign ment of zero as an externality value for SO 2 

## . This value was developed under the assumption that the co sts of all damages were internalized in the cost of allowances under the 1990 Clean Air Act regulations allowing SO 2 

## emissions trading. The damages focused primarily on the impacts of acid rain on the ecosystems.

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## Recent research suggests that the SO 2 

## reductions required in the 1990 amendments have been insufficient to reverse the ecological damages of acid rain, and further reductions of 50 to 80 percent in SO 2 

## releases from the electric power indus try are still necessary (Gbonda-Tugbawa, 2002). Additionally, epidemiological studies ha ve strengthened the links between fine and sulfate particles with early death from cardiopu lmonary disease and lung cancer (Pope et al. 2002, Krewski et al. 2000).

Evidence also suggests that sulfates encourage bacteria to methylate mercury, that is, convert mercury to a form that readily enters the food chain and bioaccumulates in fish. Researchers believe that reducing SO 2 

## emissions and the resulting sulfate deposition would likely reduce the amount of mercury that bioaccumulates (B ranfireun et al. 1999, Gilmour et al. 1992).

Despite this range of human health and environmental advantages to reducing SO 2 

## emissions, Xcel’s assessment of the benefits of th e MERP proposal assigns no benefits to SO 2 

## reductions. The PUC’s environmental externa lity values were designed and adopted for use in resource planning. The externality values are generalized estimates given for model power plants in rural, suburban and urban settings. These plants don’t r eally exist — they are idealized. While some of the underlying assumptions may be appropriate for this purpose, the externality values have limited applicability to specific projects such as those proposed for the MERP.

The MPCA is certain that the PUC’s externality values, when applied to a project such as the MERP, greatly underestimate the h ealth and environmental benef its of the proposal. The MPCA has demonstrated the degree to which the benef its are underestimated in this section by showing the benefit measured in similar analyses elsewhere.

There is compelling evidence that greater health benefits accrue if the health impacts resulting from fine particulates were to be evaluated using methods simila r to the Bush Administration’s Clear Skies Initiative or other assessments. For this analysis, the MPCA has attempted a very simple calculation which places benefits closer to the cost of this project

While it is simply not possible to quantify health and environmental benefits with accuracy, the MPCA finds that the benefits of the project roughly balances, if not exceeds, the costs of the project.

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# 8.0 Other Benefits

The previous analysis of benefits in reduci ng power plant emissions does not include any consideration of benefits related to the follo wing important environmen tal and health issues:

 Reduced emissions of mercury a nd other bioaccumulative metals.
The accumulation of mercury in fish tissue is a pervasive issue in Minnesota as well as many other states and countries. Power plants in Mi nnesota account for about half of the state’s mercury emissions. An extensive discussion about the mercury problem in Minnesota and what is being done about it can be found in the MPCA’s 2002 report to the Legislature, available at www.pca.state.mn.us/hot/legi slature/reports/2002/mercury-02.pdf. Metal emissions from power plants ar e discussed in Attachment 2.

Evidence suggests that sulfates encourage bacteria to methylate mercury, that is, convert mercury present in the environment to the form (methylmercury) that readily bioaccumulates in fish. A decrease in SO 2 

## emissions, and the resulting decrease in atmospheric sulfate deposition, would likely reduce the amount of methylmercury that accumulates in fish. (Branfireun, et al.1999, Gilmour et al. 1992) Th e MERP project thus offers improvements to the environment by first reducing me rcury emissions and by reducing SO 2 

## emissions that may be participating in causing fish contamination in lakes.

 Reduced contribution to gr ound level ozone (smog), regi onal haze and acid deposition. These three problems are all serious, but rising levels of ozone in the Twin Cities area is of particular, immediate concern. More discussion on these issues is available in Attachment 2.

 Reduced impacts from truck and ra il traffic, and ash disposal. More information about these impacts can be found in section 8.2.

 Reduced need for development of new energy generation sites and new transmission lines. If the existing generation capacity at these sites is not maintained, and if new generation needs are to be met elsewhere, then new generation sites and transmission lines will be needed. Development of energy generation site s and transmission lines requires a substantial amount of land, may require significant infr astructure upgrades, and is extremely controversial.

All of the items listed above ar e — or have a potential to — causing harm to human health and/or the environment. All of these impacts will be reduced as a result of implementing these projects. However, estimating a specific, or even a ballpark, associated benefit is not possible.

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## 8.1 Environmental Justice In recent years there has been growing con cern that minority populations and/or low-income populations bear a disproportionate share of advers e health and environmental effects. Many of our older and more polluting industries are locat ed near minority and lo w income residential

areas. 53 

## Higher traffic densities and hence mobile source emissions also exist in the core areas of Minneapolis and St. Paul, and lead to higher levels of various toxic air contaminants (MPCA 2001).

EPA defines Environmental Justice as the “fair treatment for people of all races, cultures, and incomes, regarding the development of envir onmental laws, regulations, and policies.” In September 1999, the MPCA adopted an environmenta l justice policy that, among other goals, is intended to ensure “that minority and economically disadvantaged communities in Minnesota do not bear a disproportionate share of the invol untary risks and consequences of environmental pollution.”

The Riverside and High Bridge plants are locat ed in areas of high minority population and high poverty rates relative to metropolitan averages. (See Figure 8 ) The project helps to minimize the local impact of these facilities on the health and well being of th e surrounding neighborhoods. This is largely the result of the proposed fuel switch from coal to gas. The project will also significantly reduce mercury emissions.

Health effects from mercury deposition and uptak e in fish are of most concern to pregnant women who eat fish caught from contaminated lakes. Fish eating habits of Native American and Southeast Asian communities in Minnesota likely pl ace them at higher risk than the population as a whole. Because the project reduces local impacts at Riverside and High Bridge, and because it reduces mercury emissions it is consistent with MPCA’s environmental justice goals.

8.2 Local Impacts Local benefits will accrue in the neighborhoods surrounding the High Bridge and Riverside plants when they are converted to natural gas. After conversion, all coal and ash hauling would cease and changes would occur in the appearance of the facilities. Tra ffic and appearance would remain roughly the same at the King plant.

8.2.1 Truck and rail traffic Coal is delivered to all three plants via rail. Three to four unit trains (115 cars) per week are currently delivered to both the High Bridge and Riverside plants. Ash from all three plants is trucked to a landfill. Approximately 1,700 trailer loads per year leave the High Bridge site. Approximately 2,800 trailer loads per year leave the Riverside site. In addition, in the summer, there is significant on-site use of a watering truck to minimize dust and fire danger. All of this traffic should be eliminated if th e plants convert to natural gas.

53 

### See, for example, Sheppard et al., “Examining Environmental Equity in Hennepin County and Minneapolis,” CURA Reporter, Sept 1999.

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## Figure 8

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## 8.2.2 Dust The handling and processing of coal inevitably results in the release of coal dust. Xcel minimizes the release of dust through many mitigation measures including watering. If the project proceeds, no coal will be used at Riverside and High Bridge. This will remove the source of any uncontrolled dust emissions from coal handling.

8.2.3 Appearance The reconstruction of the Riverside and High Bridge plants will result in changes to the appearance of these sites. The coal storag e areas (125,000 tons at High Bridge and 135,000 tons at Riverside) will be eliminated. The current exhaust gas stacks will be removed and replaced with lower stacks. These changes will make the sites on the Mississippi River look less “industrial.”

8.2.4 Water Usage and Discharge Conversion from coal to gas at the Riverside and High Bridge plants will result in cleaner wastewater at both plants. Rive r water usage at the High Bridge plant should remain at about current levels, whereas usage at the Riverside plant will be reduced.

8.2.5 Noise Noise is generated by activities related to transport of fuel and ash, and from activities related to plant operation. If the project is implemented, noi se related to transport will be reduced at the Riverside and High Bridge plants. It is difficult to determine specific impacts from new operations such as the new gas turbines be fore site specific designs are developed.

8.2.6 Land Use During the past three decades, the Twin Cities area has recognized the beauty and recreational benefits of the river corridors that are an integral part of the area. Numerous regional and local parks have been designated on the Mississippi, Mi nnesota, and St. Croix ri vers. (See Figure 9)

The National Park Service, in cooperation with Me tropolitan Council, the Minnesota Department of Natural Resources, and local authorities has designated two major river corridors for protection and improvement. Th e St. Croix National Scenic Ri verway was established in 1968 and the lower St. Croix was added in 1972. The A llen S. King plant borders the St. Croix River. The Mississippi National River a nd Recreation Area was established in 1988. It extends along both sides of the river from Dayton to Hastings. The High Bridge and Riverside plants are both located on the Mississippi River within this area.

Under the MERP, the High Bridge and Riverside pl ants would be converted to natural gas. As outlined above, gas fired facilitie s should have less local visual and environmental impact than coal facilities. The improvements at the High Br idge and Riverside sites should be more in line with city, state, regional and Park Service plan s for the Mississippi River corridor than continued operation as coal fired facilities.

Community concern for these plants is quite hi gh. For example, this year, the MPCA was planning to re-issue the air permit for the Riverside Plant with no significant changes. (Air

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## permits expire every five years.) During th e formal public comment period the MPCA received adverse comments from more people than have ever commented on a permit.

Figure 9

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# 9.0 Appropriateness of the Proposed Projects

When the Clean Air Act was passed in 1970, existin g power plants were grandfathered and thus exempt from having to upgrade pollution control e quipment. Expectations were that as these grandfathered plants aged, they would be either re placed with a new plant, or refurbished in such a way that pollution control upgrades would be required.

Thirty-two years later, these expectations have not been met. In Minnesota and across the country, older plants have been nursed along, w ith regular repairs, and have lasted long beyond their original expected useful life. They continue to emit at much higher levels than would be allowed any newer power plant.

Through the years, environmental and health experts have identified a number of serious problems linked to power plant emissions that ha ve required corrective actions. Two of the most significant are the acid rain controls required by the Clean Air Act Amendments of 1990, and the NO x 

## reductions needed to reduce regionally tran sported ozone pollution in the eastern United States. Even these actions have not been enough.

It is now recognized that further reductions are needed in SO 2 

## and NO x 

## to protect the environment from acid rain. The new federal ozone standard will require even greater power plant reductions to help cities reach compliance. And, there are new problems that have been linked to power plant emissions as well.

Regional haze regulations will likely require emission reductions in SO 2 

## and NO x 

## from power plants. Global climate change concerns may ultimately require CO 2 

## reductions from this industry. Coal burning power plants are one of the most significant sources of mercury emissions in Minnesota and the na tion. Finally, and perhaps the mo st serious, fine particulates, which have been scientifically linked to major h ealth problems, including death, are in part the result of power plant emissions.

Nationally, the need to reduce emissions from power plants has been recognized in all circles. The debate has moved from why, to what, how much and by when? Damage/cost studies are now emerging that demonstrate the huge environm ental and health benefits that may be gained from reducing power plant emissions. Perhaps the most interesting is the assessment associated with President Bush’s Clear Skies legislation th at projects benefits of $93 billion nationally and $1 billion in Minnesota.

9.1 Costs and Benefits Before summarizing the costs and benefits of th is MERP proposal, it is helpful to know that Xcel has already implemented Phase 1 of a significan t emission reduction project in Colorado. Xcel has now proposed a Phase 2 emission reducti on project in the Denver, Colorado area.

The magnitude of the costs and benefits estimates fo r projects like this can appear large. It has been many years since the PUC has been presented with a project of this size. The last major coal plant to be built in Minnesota was Xc el’s Sherburne County Unit 3, built in the 1980’s. That 871 MW plant was built at a cost of about $1 billion.

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## The pollution control equipment for Sherco III re presented about one-third of the plant’s total cost. The MERP proposal involves rebuilding or rehabilitating about 1,100 MW of generating capacity to like-new condition and adding 385 MW of new capacity, for a total of about 1,485 MW of capacity.

While it has not been possible to provide a detailed quantitative cost-benefit analysis of Xcel’s MERP, the MPCA has reviewed both the projecte d capital costs of the MERP proposal, and its estimated benefits. The MPCA ha s concluded that the project cost is approximately $1.6 billion net present value, when assuming a plant life beyond 2020.

After considering the avoided costs associated with the benefits of the additional generation capacity from the project, the costs are more in the range of $900 million. Remember that the avoided costs to not take into account the fact th at this project also extends the useful life of 1,100MW of existing capacity at these three plants for decades. There is a substantial benefit (perhaps in the several hundred million dollar range) for not having to replace this power in some other manner. Rebuilding or rehabilitating generating capacity at these sites takes advantage of existing transmission lines that are near load centers.

Using a more realistic timeframe for benefit accr ual and using a more a ppropriate discount rate, the benefits are estimated at between $200 million and $500 million when using the PUC’s externality values.

It is unfortunate that current science and economics makes it impossible to fully and quantitatively assess all the benefits associated with a project like this. Keep in mind what this benefit estimate does not quantitatively measure or consider.

 It does not quantify all health information asso ciated with fine particulates. Recent damage estimates link virtually all of the potential costs of power plant emissions to fine particulate. Xcel’s assessments do not include effects of long-term exposure to fine particulate matter.

 It does not account for the fact that SO 2 

## emissions play an important role in fine particulate formation and account for perhaps 20 percent or more of the mass of fine particulates in Minnesota’s atmosphere (Figur e 6) and one-third nationally.

 It does not account for benefits that occur more than 200 miles away. Recent benefit assessment estimates indicate that the majority of benefits will occur at significant distances from where the emissions occur.

 It does not account for mercury reductions. The reductions proposed in MERP are significant, reducing mercury emissions from power plants in the state by more than 10 percent. Mercury remains one of the most important environmenta l problems for Minnesota lakes and streams.

 It does not consider many spec ific local benefits, particularly those associated with the elimination of coal handling at two of the plants.

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##  It does not consider the fact that, with the a dditional generation capacity, one or more sites would not have to be developed for a power plant and the need for additional transmission lines would be reduced.

In weighing the projected costs for this three-pl ant proposal against the estimated benefits as well as the benefits that cannot be quantitatively es timated, the MPCA believes that the benefits, at the very least, approximate and most likely exceed the projected costs.

Finally, the MPCA will address the appropriateness of each individual plant project.

9.2 Allen S. King This plant is mostly operated as a base load plan t. Given the cost of coal vs. natural gas, it is reasonable to continue to burn coal at this plan t for base load generation capacity. The emission controls proposed by Xcel appr oximate state-of-the-art cont rols for a coal-fired facility.

It is possible that in the next few years, Xcel will need to begin major modifications at this plant in order to be able to conti nue operations into the future. Such modifications would likely trigger the need to install pollution control equi pment similar to what is proposed in the MERP. However, the environmental benefits will occur many years sooner under this voluntary emission reduction proposal.

The MPCA believes that it is appropriate to allow cost recovery for this project as specified by the statute.

9.3 High Bridge This plant is an intermediate load plant. It is reasonable to consider converting an intermediate load plant over to natural gas. Also, this plant is located near downtown St. Paul and is surrounded by a densely populated urban area where new housing is being developed. The emission controls proposed are appropriate for this type of generation technology.

The MPCA believes that it is appropriate to allow cost recovery for this project as specified by the statute. The generating capacity expans ion above the 100 MW limit in the statute should be considered for “recovery above costs,” if the PUC finds that the additional capacity is needed for the economic viability of the project and would ensure that Xcel implements the project as a whole

9.4 Riverside This plant is an intermediate load plant. It is reasonable to consider converting an intermediate load plant over to natural gas. Also, this pl ant is located near downtown Minneapolis and is surrounded by a densely populated urban area. Th e emission controls proposed are appropriate for this type of generation technology. This plan t, although quite old, s till has significant useful life. Clearly the conversion to natural gas is being proposed primarily for emission reduction benefits.

The MPCA believes it is appropriate to allow cost recovery for this project as specified by the
statute.

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# 10.0 References Abt Associates, Inc. (Abt Assoc) 2002. Particul ate-Related Health Impacts of Eight Electric Utility Systems. Prepared for Rockefeller Family Fund. April 2002. http://www.rrfund.org

Aulich and Neusen, (A ulich and Neusen) 1999. Estimated Economic Impact of Twin Cities Ozone Nonattainment , Report to the Minnesota Chamber of Commerce.

Branfireun, B. A., N. T. Roulet, C. A. Kelly, a nd J. W. M. Rudd. (Branfireun et al.) 1999. In Situ Sulphate Stimulation of Mercury Methylation in a Boreal Peatland: Toward a Link Between Acid Rain and Methylmercury Contamination in Remote Environments. Global Biogeochemical Cycles :1-16

. Chinkin L.R. et al. (Chinkin) 2002. Preliminary Assessment of Ozone Air Quality in the Minneapolis/St. Paul Region. Sonoma Technology, Inc. October 2002. http://www.pca.state.mn.us/publications/reports/ozonestudy2002.pdf

Dockery, D.W., C.A. Pope III, X. Xu, J.D. Ware, M.E.Fay, B.G. Ferris, Jr, and F.E. Speizer, 1993. An Association Between Air Pollution and Mortality in Six U.S. Cities. New England Journal of Medicine. 329:24;1753-1759.

Federal Energy Regulatory Commission (FERC), 45 F.R. 12214 (February 25, 1980); 45 F.R. 24126, (April 9, 1980), 18 CFR Part 292, Docket No. RM79-55, Order No. 69, Small Power Production and Co generation Facilities, Regula tions Implementing Section 210 of the Public Utility Regulatory Policies Act of 1978, Final Rule.

Gbondo-Tugbawa, S.S.; Driscoll, C.T.; Mitchell, M.J.: Aber, J. D.; Likens, G.E. (GbondaTugbawa) 2002. Ecological Applications. 2002, 12, 8-23.

Gilmour, C.C., E.A. Henry and R. Mitchell. 1992. Sulfate Stimula tion of Mercury Methylation in Freshwater Sediments. Environ. Sci. Technol . 26:2281-2287.

Keeth, R., R. Blagg, C. Burklin, B. Kosmicki, D ., Rhodes, and T. Waddell (Keeth). Coal Utility Environmental Cost (CUECost) Model Version 1.0 www.epa.gov/ttn/catc/products.html#software

Krewski, D., Burnett, R.T., Goldbert, M.S ., Hoover, K., Siemiatycki, J., Jerrett, M., Abrahamowicz, M., White, W.H., (Krewski et al.) 2000. Particle Epidemiology Reanalysis Project, Special Report: Reanalysis of the Harvard Six Cities Study and the American Cancer Society Study of Pa rticulate Air Pollution and Mortality. Health Effects Institute. www.healtheffects.org/pubs-special.htm

Levy, J.I. and J. D. Spengler (Levy and Spen gler) 2002. Modeling the Benefits of Power Plant Emission Controls in Massachusetts. Journal of Air and Waste Management Association 52:5-18.

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## Minnesota Department of Commerce (Commerce) 2002. 2001 Energy Planning Report. www.commerce.state.mn.us/pages/Energy/Policy/2002PlanningRpt.pdf

Minnesota Pollution Control Agency (MPCA), 2001. MPCA, Air Quality in Minnesota, Problems and Approaches. January 2001. www.pca.state.mn.us/hot/legisl ature/reports/2001/aq-report.pdf

Nelson, C.D (Nelson), 2000. The Public Health Impacts of Pa rticulate Emissions from Coalfired Power Plants in Minnesota. Thesis. Master of Scienc e. University of Minnesota. October 2000.

National Academy of Sciences (NAS) 2002. Estimating the Public Health Benefits of Proposed Air Pollution Regulations. Committee on Estimating the Health-Risk-Reduction Benefits of Proposed Air Pollution Regulati ons, Board on Environmental Studies and Toxicology, (The National Academie s Press, Washington, DC: 2002), www.nap.edu

Pope, C.A. III, M.J. Thun, M.M. Namboodiri, D.W. Dockery, J.S. Evans, F.E. Speizer, and C. W. Health, Jr. (Pope et al.) 1995. Particulat e Air Pollution as a Predictor of Mortality in a Prospective Study of U.S. Adults. American Journal of Respiratory Critical Care Medicine. 151:669-674.

Pope C.A. III, Burnett R.T., Thun M.J., Calle E. E., Krewski D., Ito K., Thurston G.D. (Pope et al.) 2002 Lung Cancer, Cardiopulmonary Morta lity, and Long-term Exposure to Fine Particulate Air Pollution . JAMA 287:1132-1141 (2002).

Public Utilities Commission (PUC) 1997. Order Es tablishing Environmental Cost Values, Docket No. E-999/CI-93/583. Minnesota Public Utilities Commission, January 3, 1997.

Schwartz, J., Laden, F., Zanobetti, A. (Schwa rtz et. al) 2002. The Concentration-Response Relation between PM2.5 and Daily Deaths. Environ. Health Perspectives , 110: 1025- 1029, (2002).

U.S. Department of Energy (DOE) 1999 . Report of the U.S. Department of Energy's Power Outage Study Team: Findings and Recommenda tions to Enhance Reliability from the Summer of 1999 . March 1999.

U.S. Energy Information Administration (EIA) 1994. Model Documentation: Electricity Capacity Planning Submodule of the Electricity Market Module Nuclear and Electricity Analysis Branch, March 1994, http://t onto.eia.doe.gov/FTPR OOT/modeldoc/m068b.pdf.

U.S. Energy Information Administration (EIA), 2000. Analysis of Strategies for Reducing Multiple Emissions from Power Plants: Su lfur Dioxide, Nitrogen Oxides and Carbon Dioxide , SR/OIAF/2000-05, December 2000. www.eia.doe.gov/oiaf/servicerp t/powerplants/appendixes.html

U.S. Energy Information Administration (EIA) 2002. Assumptions to the Annual Energy Outlook 2002: Electricity Market Module. www.eia.doe.gov/oiaf/aeo/a ssumption/electricity.html.

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## U.S. Environmental Protection Agency (EPA) 1999a. Analysis of Emissions Reduction Options for the Electric Power Industry. Office of Air and Radiation. March 1999. www.epa.gov/capi/multipol/mercury.htm

U.S. Environmental Protection Agency (EPA) 1999b. Regulatory Impact Analysis For The Final Section 126 Petition Rule , Office of Air Quality Planning and Standards, Office of Atmospheric Programs, December 1999.

U.S. Environmental Protection Agency (EPA) 1998. Analyzing Electric Power Generation Under the CAAA. Office of Air and Radiation, March 1998. www.epa.gov/capi/ipm/update.htm

U.S. Environmental Protection Agency Science Advisory Board (SAB) 2001. Review of the Draft Analytical Plan for EPA's Second Prosp ective Analysis - Benefits and Costs of the Clean Air Act 1990-2020, An Advisory by a Sp ecial Panel of the Advisory Council on Clean Air Compliance Analysis , EPA-SAB-COUNCIL-ADV-01-004, September 2001, p. 25. www/epa.gov.sab

### 216B.1692. Emissions reduction rider

Subdivision 1. Qualifying projects. Projects that may be approved for the emissions reduction-rate rider allowed in this section must:

(1) be installed on existing large electric generating power plants, as defined in section 216B.2421, subdivision 2, clause (1), that are located in the state and that are currently not subject to emissions limitations for new power plants under the federal Clean Air Act;

(2) not increase the capacity of the existing electric generating power plant more than ten percent or more than 100 megawatts, whichever is greater; and

(3) result in the existing plant either:

(i) complying with applicable new source review standards under the federal Clean Air Act; or

(ii) emitting air contaminants at levels substantially lower than allowed for new facilities by the applicable new source performance standards under the federal Clean Air Act; or

(iii) reducing emissions from current levels at a unit to the lowest cost-effective level when, due to the age or condition of the generating unit, the public utility demonstrates that it would not be cost effective to reduce emissions to the levels in item (i) or (ii).

Subd. 2. Proposal submission. A public utility that intends to submit a proposal for an emissions reduction rider under this section must submit to the commission, the department, the pollution control agency, and interested parties its plans for emissions reduction projects at its generating facilities. This submission must be made at least 60 days in advance of a petition for a rider and shall include:

(1) the priority order of emissions reduction projects the utility plans to pursue at its generating facilities;

(2) the planned schedule for implementation;

(3) the analysis and considerations relied on by the public utility to develop that priority ranking;

(4) the alternative emissions reduction projects considered, including but not limited to applications of the best available control technology and repowering with natural gas, and reasons for not pursuing them;

(5) the emissions reductions expected to be achieved by the projects and their relation to applicable standards for new facilities under the federal Clean Air Act; and

(6) the general rationale and conclusions of the public utility in determining the priority ranking.

Subd. 3. Filing petition to recover project costs. (a) A public utility may petition the commission for approval of an emissions reduction rider to recover the costs of a qualifying emissions reduction project outside of a general rate case proceeding under section 216B.16. In its filing, the public utility shall provide:

(1) a description of the planned emissions reduction

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### project;

(2) the activities involved in the project;

(3) a schedule for implementation;

(4) any analysis provided to the pollution control agency regarding the project;

(5) an assessment of alternatives to the project, including costs, environmental impact, and operational issues;

(6) the proposed method of cost recovery;

(7) any proposed recovery above cost; and

(8) the projected emissions reductions from the project.

(b) Nothing in this section precludes a public utility or interested party from seeking commission guidelines for emissions reduction rider filings; however, commission guidelines are not required as a prerequisite to a public utility-initiated filing.

Subd. 4. Environmental assessment. The pollution control agency shall evaluate the public utility's emissions reduction project filing and provide the commission with:

(1) verification that the emissions reduction project qualifies under subdivision 1;

(2) a description of the projected environmental benefits of the proposed project; and

(3) its assessment of the appropriateness of the proposed project.

Subd. 5. Proposal approval. (a) After receiving the pollution control agency's environmental assessment, the commission shall allow opportunity for written and oral comment on the proposed emissions reduction rate rider proposal. The commission must assess the costs of an emissions reduction project on a stand-alone basis and may approve, modify, or reject the proposed emissions reduction rider. In making its determination, the commission shall consider whether the project, proposed cost recovery, and any proposed recovery above cost appropriately achieves environmental benefits without unreasonable consumer costs.

(b) The commission may approve a rider that:

(1) allows the utility to recover costs of qualifying emissions reduction projects net of revenues attributable to the project;

(2) allows an appropriate return on investment associated with qualifying emissions reduction projects at the level established in the public utility's last general rate case;

(3) allocates project costs appropriately between wholesale and retail customers;

(4) provides a mechanism for recovery above cost, if necessary to improve the overall economics of the qualifying projects to ensure implementation;

(5) recovers costs from retail customer classes in proportion to class energy consumption; and

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### (6) terminates recovery once the costs of qualifying projects have been fully recovered.

(c) The commission must not approve an emissions reduction project and its associated rate rider if:

(1) the emissions reduction project is needed to comply with new state or federal air quality standards; or

(2) the emissions reduction project is required as a corrective action as part of any state or federal enforcement action.

(d) The commission may not include any costs of a proposed project in the emissions reduction rider that are not directly allocable to reduction of emissions.

Subd. 6. Implementation. Within 60 days of a final commission order, the public utility shall notify the commission and the pollution control agency whether it will proceed with the project. Nothing in this section commits a public utility to implementing a proposed emissions reduction project if the proposed project or terms of the emissions reduction rider have been either modified or rejected by the commission. A public utility implementing a project under this section will not be required for a period of eight years after installation to undertake additional investments to comply with a new state requirement regarding pollutants addressed by the project at the project generating facility. This section does not affect requirements of federal law. The term of the rider shall extend for the period approved by the commission regardless of any subsequent state or federal requirement affecting any pollutant addressed by the approved emissions reduction project and regardless of the sunset date in subdivision 8.

Subd. 7. Evaluation and report. By January 15, 2005, the commission, in consultation with the commissioner of commerce and commissioner of the pollution control agency, shall report to the legislature:

(1) the number of participating public utilities and qualifying projects proposed and approved under this section;

(2) the total cost of each project and any associated incentives;

(3) the reduction in air emissions achieved;

(4) rate impacts of the cost recovery mechanisms; and

(5) an assessment of the effectiveness of the cost recovery mechanism in accomplishing power plant emissions reductions in excess of those required by law.

Subd. 8. Sunset. This section is effective until June 30, 2006.

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# T he environmental impact of electricity is asignificant factor in energy policy and planning to meet Minnesota’s generating capacity deficit. Because different generating technologies range from significant air emissions (coal) to low airemissions (natural gas and biomass) to no air emissions (wind, solar and nuclear), energy policy and generation mix choices that will be made in the next few years may require other up-front policy choices to manage environmental impacts. The state should evaluate the benefits and cost-effectiveness of adding more pollution control to existing generating plants
based on the environmental effects described in thissection, and require installation of controls as appropriate. If generation technology choices in the future include significant new air emissions, this policy decision is even more necessary.

The first part of this section analyzes the environmental impacts of the current electric generating system in Minnesota, and explores alternatives toreduce or mitigate those impacts. This section focuses on air emissions, which are the single largestsource of environmental impact from electricity generation. This section will explain the air emissions that result from electricity generation in Minnesota, describe the health and environmental impacts of those emissions, describe the regulatory programs that have been in place to mitigate environmental impacts, and describe upcoming pollution controlprograms that will require further emission reductions from electricity generation, or require that current levels of emissions not grow any larger. Finally, this section will discuss options for further emissions control in Minnesota’s existing coal plants, most of which were not required to meet the most stringentClean Air Act requirements because they were constructed before those requirements took effect. 

# Current and Forecasted Emissions from Electric Generation in Minnesota
Air emissions from electricity generation in Minnesota are shown in Figure A-1 for 1999 in tons of emissions and as a percent of total statewide air emissions from all emitting sectors from Minnesota. Included are air emissions of nitrogen oxides (NOx), sulfur dioxide (SO 2 ), carbon monoxide (CO), fine particulate matter (PM 2.5 ), lead, mercury, other metals, and greenhouse gases. With the exception of CO emissions, electricity generation currently contributes a substantial fraction of total
statewide air emissions. One-fifth of NOx emissions and one-quarter of greenhouse gas emissions fromMinnesota sources derive from electricity generation, while electricity generation accounts for about 40 percent of all statewide mercury emissions and 58 percent of statewide SO 2 emissions. Sources of
PM 2.5 in the state are less certain, and are currently being studied in preparation for implementing the new federal air quality standards for PM 2.5
. However, it is thought that coal combustion during electricity generation could be a large source.

There are about 350 generating units located in Minnesota supplying power to the grid, some 9395 MW of installed capacity. Using 1999 plant utilization rates as a measure, about 6,900 MW of this would beclassified as baseload capacity, with 2,050 MW classi

### MINNESOTA DEPARTMENT OF COMMERCE Figure A.1: Electric Utility Contribution

to Current Minnesota Air Emissions
1999 Emission to the Air % of Estimated (thousand tons) Statewide Emissions Greenhouse Gases 35,982 26% Nitrogen Oxides 87 18% Sulfur Dioxide 95 58% Carbon Monoxide 8 <1% Fine Particulate Matter (2.5 microns) ? large Lead 0.03 62% Mercury 0.0008 40% Other Metals NA 10-60% (Chromium, Arsenic, Nickel) Source: PCA 

# 2001 ENERGY PLANNING REPORT
APPENDIX A: DEALING WITH ENVIRONMENTAL IMPACTS OF EXISTING ELECTRIC GENERATIONfied as peaking, and the remainder as intermediate load capacity. Baseload plants are plants that, over the course of a year, operate more than 50 percent of the time. Intermediate-cycling plants operate between 15and 49 percent of the time, while peaking plants operate 0 to 14 percent of the time.

Most air emissions in Minnesota derive from large baseload and intermediate cycling facilities. Baseload and intermediate cycling facilities located in Minnesota of more than 100 MW of capacity are listedin Figure A-2, along with summer capacity rating, facility start-up date, fuel type, and the status of each plant
under the New Source Performance Standards(NSPS) of the federal Clean Air Act. Under NSPS, generation facilities constructed after 1972 are required to meet certain minimum performance standards with regard to air emissions of SO 2 , NOx, CO, lead, andparticulate matter. Generation facilities that were constructed before 1972 are exempt from NSPS.

NSPS have been revised a number of times, leading to the application of different standards to different plants depending on the year of their construction. NSPS have become progressively more stringent, so control requirements at plants subject to newer NSPS tend to be much more stringent than older NSPS requirements. 134 Where NSPS applies, Figure A-2 indicates the vintage (year) of NSPS standard to which the facility is subject. While NSPS applies to five generating units, four are subject only to older, less stringent NSPS. Fifteen large baseload and intermediate load generating units are exempt from NSPS entirely, comprising 3,030 MW of the 5,559MW (55 percent) of installed baseload and intermediate-load capacity in the state.

Emissions at Minnesota ’ s large baseload and intermediate plants for 1999 are shown in Figure A-3 for
SO 2 , NOx, CO 2 and mercury. In 1999, 80,017 tons of NOx and 90,284 tons of SO 2 were emitted to the atmosphere from large baseload and intermediate load plants larger than 100 MW located in Minnesota. In 1999, mercury emissions from these facilities were an estimated 1,456 lbs., while some 34.1 million tons
of CO 2 was emitted from these plants. In 1999, net generation at these plants was some 29.5 million megawatt-hours. As might be expected, the greatest emissions occurred at the two largest generation facilities, Xcel Energy ’ s Sherburne County facility and
Minnesota Power ’ s Clay Boswell generating facility. 

### Page 94 2001 Energy Planning Report

MINNESOTA DEPARTMENT OF COMMERCE Figure A.2: Nonnuclear Baseload or Intermediate Load Electricity Generating Units at Large Plants Capacity Principal Load Type Start-up NSPS (summer) Fuel Date Status

(MW) Vintage (Year) Xcel Energy Sherburne County

unit 1 712.0 coal Baseload 1976 n/a unit 2 721.0 coal Baseload 1977 1976 unit 3 871.0 coal Baseload 1987 1986 Allen King 571.0 coal Baseload 1958 n/a Riverside

unit 7 150.0 coal Baseload 1987 1986 unit 8 221.5 coal Baseload 1964 n/a High Bridge

unit 5 97.0 coal Intermediate 1956 n/a unit 6 170.0 coal Intermediate 1959 n/a Black Dog

unit 3 113.2 coal Intermediate 1955 n/a unit 4 171.8 coal Intermediate 1960 n/a

XCEL total 3,959.6 LS Power 252.1 gas Intermediate 1998 1997 Rochester Publ. Util. Silver Lake

unit 4 60.3 coal Intermediate 1969 n/a Minnesota Power Clay Boswell

unit 1 69.0 coal Intermediate 1958 n/a unit 2 69.0 coal Baseload 1960 n/a unit 3 346.3 coal Baseload 1973 n/a unit 4 535.0 coal Baseload 1980 1979 Syl Laskin

unit 1 55.0 coal Baseload 1953 n/a unit 2 55.0 coal Baseload 1953 n/a subtotal 110.0

Minnesota Power total 1,129.3 OtterTail Power Hoot Lake

unit 2 64.9 coal Intermediate 1959 n/a unit 3 84.0 coal Intermediate 1964 n/a

Otter Tail Power total 156.9 Minnesota Total 5,355.7 *Does not include nuclear power reactors Monticello and Prairie Island 1 & 2.



### Figure A.3: Net Generation and Emissions During 1999 from Electric Generation Plants Located in Minnesota
1999 Net Emissions Generation NOx SO2 CO2 Hg

(MWH) (tons) (tons) (tons) (lb.) Xcel Energy

Sherburne County 13,289,695 22,285 20,667 15,864,259 809.57 Allen King 3,295,770 18,479 27,251 3,465,485 58.8 Riverside 2,164,668 12,176 13,441 2,279,736 88.92 High Bridge 1,185,039 3,946 2,942 1,457,755 60.73 Black Dog 1,382,947 7,080 3,005 1,795,939 44.81 Minnesota Power

Clay Boswell 6,172,773 12,382 17,305 7,230,445 315.93 Syl Laskin 570,635 1,570 1,008 646,863 38.50 Otter Tail Power

Hoot Lake 629,190 1,365 2,479 870,831 30.88 Rochester Publ. Util.

Silver Lake 206,166 683 2,184 183,044 8.33 LSP Cottage Grove 650,667 51 2 306,597 NA

TOTALS 29,547,550 80,017 90,284 34,100,954 1456.47
Source: PCAEmissions of SO 2 , NOx, CO 2 and mercury per kWh of net electricity generation is shown in Figure A-4 for 1999 for baseload and intermediate load plants of 100
MW or more located in Minnesota. Emissions of NOx vary from 0.0002 to 0.01 lb. per kWh, or by about 50- fold from the lowest emitting to the highest emitting facility. Emissions of SO 2 vary from 0.0001 lb. per kWh to 0.021 lb. per kWh, or by more than 100-fold from the lowest to the highest emitting facilities.
Emissions of CO 2 range from 0.94 lb. per kWh to 2.77 lb. per kWh, and those for mercury from 0.00002 to0.00007 lb. per MWH. The current performance standards for NOx for new or modified coal-fired facilities is equivalent to about 0.001 lb. per kWh, and that for
SO 2 to about 0.001 to 0.002 lb. per kWh. 135

The lowest emitting baseload or intermediate load facility per kWh-generated is the natural gas-fired LSP-Cottage Grove cogeneration facility. Xcel ’ s King and Riverside plants are the highest emitting plants presently in service for NOx, and the King plant and the Silver Lake facility owned by Rochester Public Utility are the highest emitting plants for SO 2
. Regarding CO 2 , the Hoot Lake and Black Dog facilities are the top-emitting plants, while for mercury,Sherburne County and Syl Laskin are the top-emitting facilities.

The wide range of emissions per kWh of net electricity generated results from, among other factors,differences in the type of fuels used, the use and vintage of any pollution control equipment, and the efficiency of conversion of thermal energy to electricity at the plant. While there exists no commercially available control technology for CO 2 and mercury, depending on type, pollution control equipment can
lower emissions of NOx and SO 2 by 30 to 85 percent. The efficiency of power generation in converting the energy content of fuel to electricity typically varies from about 32 percent for older existing coal-firedfacilities to 55 percent for new combined cycle natural gas units. Pollution control equipment installed at baseload and intermediate load generating facilities located in Minnesota is listed in Figure A-4.

On a per kilowatt hour basis, emissions of SO 2 and
NOx have declined on a statewide basis. Total emissions, however, continue to rise.

Emissions trends for all Minnesota electricity generating plants are shown in Figures A-5 to A-8 for



### 2001 Energy Planning Report Page 95

MINNESOTA DEPARTMENT OF COMMERCE Figure A.4: Emission Rates Per Unit of Electricity Generated at Minnesota Electric Generating Plants Primary

Emission Rate (lb./kWh generated) Emission Controls a,b NOx SO2 CO2 Hg SO2 NOx Xcel Energy

Sherburne County 0.003 0.003 2.39 0.00000006 scrubbers LNC, LNB Allen King 0.011 0.017 2.10 0.00000002 Riverside 0.011 0.012 2.11 0.00000003 High Bridge 0.007 0.005 2.46 0.00000005 Black Dog 0.010 0.004 2.60 0.00000003 Minnesota Power

Clay Boswell 0.004 0.006 2.34 0.00000005 scrubbers LNC Syl Laskin 0.006 0.004 2.27 0.00000007 Otter Tail Power

Hoot Lake 0.004 0.008 2.77 0.00000005 LNB Rochester Publ. Util.

Silver Lake 0.007 0.021 1.78 0.00000004 1 LSP Cottage Grove 0.0002 0.000 0.94 NA SCR

a LNC1 = low NO X coal and air nozzles with close coupled overfire air; LNC2 = low NO X coal and air nozzles with separated overfire air.

b low NOx controls 1 at Sherburne County unit 1 and low NO X controls 2 at Sherburne County unit 2. Wet scrubbers at Sherburne County units 1 and 2 and Clay Boswell unit 4, dry lime scrubbers at Sherburne County unit 3.

20,000 40,000 60,000 80,000 100,000 120,000Tons1985198619871988198919901991199219931994199519961997199819992000 Coal 

### Figure A.5: Sulfur Dioxide Emissions from Electricity Generation in Minnesota

20,000 40,000 60,000 80,000 100,000 120,000Tons1985198619871988198919901991199219931994199519961997199819992000 Internal Combustion

Natural Gas

Coal 

### Figure A.6: Nitrogen Oxides Emissions from Electricity Generation in Minnesota NOTE: SO 2 emissions from other electric generation sources are insignificant.sulfur dioxide, nitrogen oxides, carbon dioxide, and mercury. Figures A-5 and A-6 show SO 2 and NOx emissions, respectively, from electricity generation from 1985 to 2000. These figures show that most
emissions of SO 2 and NOx result from coal-fired
facilities. Emissions of SO 2 have increased from about 78,000 tons in 1986 to about 95,000 tons in2000, or at an overall average rate of about 1.3 percent per year.

SO 2 emissions prior to 1986 were higher, falling from the early 1980s to 1986 due to increased use of low sulfur western coal as a fuel. Since 1985, NOx emissions have increased from 58,000 tons per year to about 87,000 tons per year, or about 2.7 percent

per year.
The estimated long-term trend in emissions of greenhouse gases is shown in Figure A-7. About 99 percent of all greenhouse gases produced during electricity generation in Minnesota are in the form of carbon dioxide. Emissions of nitrous oxide (N 2 O) comprise most of the remainder. In terms of fuels, most emissions of greenhouse gases derive from coal combustion, with the combustion of solid waste, petroleum coke and natural gas contributing only a small part to total emissions. Since 1983, emissions of greenhouse gases from electricity generation in Minnesota have approximately doubled, increasing
from about 20 million CO 2 -equivalent tons to the
current 38.6 million CO 2 -equivalent tons. Emissions are increasing at a rate of 3.9 percent per year.

Finally, Figure A-8 shows the estimated 17-year trend in mercury emissions from electricity generation in Minnesota. Most mercury that is emitted during power production in Minnesota currently is derived from coal combustion. Due to enhanced mercury controls at solid waste incinerators, emissions of mercury from electricity generation have declined about 40 percent since 1990, falling from about 2,500 lb. of mercury in 1990 to the current 1,500 lb. in 2000.
With most emissions from solid waste incineration now eliminated, at present levels of emission control any increase in coal combustion at Minnesota ’ s electricity generation facilities will result in increased mercury emissions to the atmosphere.

With the exception of unit 3 at Xcel Energy ’ sSherburne County facility, relatively little new generation capacity has been built in Minnesota since 

### Page 96 2001 Energy Planning Report

MINNESOTA DEPARTMENT OF COMMERCECO2Equivalent Tons

5,000,000 10,000,000 15,000,000 20,000,000 25,000,000 30,000,000 35,000,000 40,000,000 45,000,000
MMSW
Gas
Oil
Coal198319841985198619871988198919901991199219931994199519961997199819992000 

### Figure A.7: Greenhouse Gas Emissions from Electric Generation in Minnesota198319841985198619871988198919901991199219931994199519961997199819992000lbs. 3,000

2,500

2,000

1,500

1,000

500

0 MMSW

Coal 

### Figure A.8: Mercury Emissions from Electric Generation in Minnesota

10 20 30 40 50 60 70 80198319841985198619871988198919901991199219931994199519961997199819992000Percentage 

### Figure A.9: Net Electric Generation in Minnesota Baseload Plants as a Percentage of Potential Generation 

### at 8760 Hours of Operations

and Reported Plant Net Summer Generation Capability Rating1983. Most of the increases in air emissions have derived from higher utilization rates of existing plants. Historical utilization rates for baseload and intermediate load plants larger than 100 MW in Minnesota are shown graphically in Figure A-9. This figure shows that utilization rates have steadilyincreased since 1983, rising statewide from 50 percent to the current estimated 70 percent. Much of this has occurred at coal-fired facilities, resulting in the upward movement of air emissions depicted in the Figures A-5 through A-8.

With regard to increased utilization of existing generating plants, the long-term trend favors at least
some increased utilization. A further increase in capacity factors at existing facilities of 5 percent ormore might be achievable. In their respective integrated resource plans filed with the PUC, Xcel Energy, Minnesota Power and Otter Tail Power in aggregate forecast an increase in coal throughput through existing facilities of about 2.5 million tons of
coal between 1999 to 2010.

In addition to increased utilization of existing facilities, new plants will be added. Figure 3-3 in Chapter 3 of the main report lists the generating plants under construction or planned in Minnesota. This list does not include conversion of the LTV Taconite Harborpower plant for use in supplying the grid with electricity. LTV is currently in a bankruptcy proceeding. The Hoyt Lakes and Taconite Harbor facilities are for sale in the bankruptcy proceeding. The conversion of the Taconite Harbor plant to a grid power plant will shift approximately 3,000 tons of SO 2 , 2,850 tons of NOx and 1.2 million tons of CO 2 from the industrial sector to the electricity generating sector.

Based on the emission and operating characteristics of similar types of newly constructed or operating plants, Figure A-10 estimates the contribution of thisexpansion in statewide generation capacity to annual statewide emissions of SO 2 , NOx and greenhouse

gases. 136 These additions can be expected to generate about 3.5 million MWh of additional electricity each year. Annually associated with this generation,however, would be an extra 1.6 million tons of carbon dioxide, 980 tons of SO 2 and 1,290 tons of NOx.
This translates to an increase in statewide emissions of about 4 percent for CO 2 , and 1 and 1.5 percent for
SO 2 and NOx, respectively.

Using the projected increase in coal throughput at existing facilities, current emission levels (seeFigure A-3) and emissions associated with new con

### 2001 Energy Planning Report Page 97

MINNESOTA DEPARTMENT OF COMMERCE Figure A.10: Estimated Extra Annual SO 2 , NOx and CO 2 Emissions Associated with Permitted or Planned Expansions to Service or Capacity Added Since 2000
Generation Emissions Capacity Capacity Net Efficiency in (Summer) Factor Generation Converting Fuel SO 2 NO X CO 2 Plant Name (MW) (%) (MWH/yr) to Electricity (tons) (tons) (Tons)
Pleasant Valley units #1-3 434 5 190,092 0.34 1 18 110,934 Lakefield Junction units #1-6 480 5 210,240 0.34 1 20 122,692 New Ulm unit #7 22 5 9,636 0.34 0 1 7,717 Cascade Creek units #3-4 50 5 21,900 0.34 0 2 12,780 Potlatch Cloquet unit #8 24 65 136,656 0.32 0 66 84,734 Navitas gas turbine 250 5 109,500 0.34 1 10 63,902 Otter Tail Power Solway unit #1 44 5 19,272 0.34 0 2 11,247 Prairie-Gen unit #1 49 5 21,462 0.34 0 2 12,525 St. James Diesel Plant units #1-7 12 5 5,256 0.25 9 117 5,725 Worthington Diesel Plant units #1-6 14 5 6,132 0.25 10 136 6,679 Black Dog units #2,5 143 a 45 c 1,144,757 0.5 -28 d -41 d 435,075 d District Energy unit #7 25 65 142,350 0.2 39 182 61,668 Heartland Energy and Recycling 4 65 22,776 0.2 7 14 36,824 Fibrominn Biomass Power Plant 50 65 284,700 0.22 155 353 - Northome Biomass Plant 15 65 85,410 0.26 14 56 - Perham Resource Recovery 2.5 65 14,235 0.2 2 36 11,746 Grand Rapids power plant 195 b 65 1,110,330 0.42 767 316 625,590 Total 1,813.5 3,534,704 978 1,288 1,609,838

a net increase in generation capacity after conversion of existing unit 2 to combined cycle gas turbine, retirement of existing u nit 1, and addition of unit 5. b net increase in generation capacity after subtraction of internal Blandin demand. c 45% capacity factor at 290.4 MW of capacity at repowered unit #2 and new unit #5. d estimated emissions at repowered unit #2 and new unit #5 less 1999 emissions from old units #1 and 2. NOTE: In addition, approximately 3,020 tons of existing SO 2 emissions, 2,849 tons of existing NO X emmissions and 1,215,921 tons of CO 2 would be shifted from the industrial sector to the electricity generation sector with the conversion of the 187.7MW LTV-Taconit e Harbor plant to a generating facility serving the grid.

### Page 98 2001 Energy Planning Report

MINNESOTA DEPARTMENT OF COMMERCE struction (see Figure A-10), aggregate statewide emission levels from electricity generation facilities located in Minnesota are forecasted in Figure A-11 through 2010. This forecast does not include any new generation needed to meet the capacity deficitforecast in Chapter Two, beyond the current projects listed in Figure A-10. Figure A-11 shows that
CO 2 emissions will increase 4.8 million tons by 2010, leading to a roughly 12 percent increase in emissions from current levels by 2010. In the case of NOx, emissions will increase 8,723 tons by 2010, or 10 percent. SO 2 emissions will increase 8,472 tons by 2010, or 9 percent.

Finally, it might be noted that the projections given in Figure A-11 assume that no new pollution control requirements are instituted in the state and that emissions will continue at current rates per MMBtu of energy input. The imposition of more stringent controls on existing plants could dramatically change this rate, thereby reducing levels of future
emissions. 

# Health and Environmental Impacts of Electric Generation
Sulfur dioxide and nitrogen oxides emitted from power plants interact with other compounds in the air to form fine particles and to cause acid rain.Nitrogen oxides react with volatile organic compounds to form ozone in hot, sunny weather. Mercury is a toxic pollutant that contaminates somefish, making them unsafe for human or wildlife consumption. Carbon dioxide is a greenhouse gas that contributes to global climate change. This section briefly describes the health and environmental impacts of these pollutants. 137



### Particulate matter Airborne particulate matter, especially very small particles from combustion sources such as power plants, diesel and gasoline powered engines andvehicles, and wood burning, are creating health concerns at current outdoor concentrations. Particlesare emitted directly, or can be formed when ammonia and combustion gases such as nitrogen oxidesand sulfur dioxide chemically transform into particles. Very small particles are inhaled deeply into the lungs where the body cannot easily remove them.

A substantial body of published scientific literature,such as the Harvard Six Cities Study findings dis

### Figure A.11: Historic and Forecasted Emissions of CO 2 , SO 2 and NOx from Electricity Generation in Minnesota
Year 2000 2005 2010 CO 2 Baseline 2000 Emissions 38,638,000 38,638,000 38,638,000 Emissions from Increased Use, Existing Plants a - 454,000 3,208,000 Emissions from New Generation Capacity - 1,610,000 1,610,000

total 38,638,000 40,702,000 43,456,000 SO 2 Baseline 2000 Emissions 94,915 94,915 94,915 Emissions from Increased Use, Existing Plants a - 1,065 7,494 Emissions from New Generation Capacity - 978 978

total 94,915 96,958 103,387 NO X Baseline 2000 Emissions 88,291 88,291 88,291 Emissions from Increased Use, Existing Plants a - 1,125 7,435 Emissions from New Generation Capacity - 1,288 1,288

total 88,291 90,704 97,014 Sources:Figures 3.3 and 3.13 above

a Calculated from projected increased coal use from 1999 levels at large baseload and intermediate load plants, as given in the integrated resource plan filings of Xcel Energy, Minnesota Power and Ottertail PowerNOTE: emissions from the Taconite Harbor plant are not included, since these would not represent new emissions but simply a shifting of emissions from the industrial sector to the electricity generation sector.

1.00 1.05 1.10 1.15 1.20 1.25 1.30

Annual Average PM 2.5 Concentration Steubenville, OH

Harriman, TN

Portage, WI Topeka, KS Watertown, MA St. Louis, MO

5 10 15 20 25 30 35Relative Risk of Death 

### Figure A.12: Relative Risk of Death vs. Fine Particle (PM 2.5 ) Concentrationplayed in Figure A-12, have shown an association between increased particles in the air and premature death from heart and respiratory disease. 138 Numerous studies also show the number of asthma attacks per day goes up as particles in the air increase. 139

In 1997, EPA added two new standards for fine particles (PM 2.5 ), set at 15 micrograms per cubic meter and 65 micrograms per cubic meter, respectively, for the annual and 24-hour standards. Beginning in 2002,based on three years of monitoring data, EPA will designate areas as nonattainment that do not meet the standards. Monitored yearly, average concentrations of fine particles in the Twin Cities typically range from11 to 14 micrograms per cubic meter. Scientists studying health effects have found health effects at levelsbelow the standards. In cities with lower particle concentrations, including some likely to meet current federal ambient air standards, both hospital admissionsand deaths from heart and lung disease rise when particles in the air increase. 140 EPA reviews air quality standards about every five years. EPA is currently revising the Criteria Document for Particulate Matterto reflect the recent evidence regarding ambient particulate matter air concentrations and health effects. EPA may use this information to propose a more restrictive particulate matter standard.

While the evidence for health effects from air pollution has strengthened over time, especially fine particles derived from fossil fuel combustion, scientists are actively researching how particles contribute tothese health effects: What are the biological mechanisms? Which physical and chemical properties of the particles are most relevant to their toxicity? Answering these questions will help determine which sources are most culpable.

Methods are unavailable to specifically apportion
health effects based on differences in emission sources. Given this uncertainty, human health risk estimates are simply based on particle mass. Using the assumption that fine particles from all sourceshave an equal ability to cause adverse effects, several researchers have developed ballpark estimates of the benefits from reducing power plant emissions.

One article referenced an estimate that reducing emissions from older coal-fired power plants in the U.S. could provide substantial benefits to public health, including the avoidance of 18,700 premature deaths, 3 million lost work days, and 16 million restricted activity days each year

—

primarily dueto reductions in particulate emissions. 141 Other studies, such as that by
the Environmental Law Institute shown in FigureA-13, have tried to quantify the public healthbased financial benefitsof reducing particle emissions from power plants.

In addition to health impacts, small particlesreflect light more efficiently than large particles and reduce visibility. Particles are not the only cause for visibility impairment but they are a major contributor. Figure A-14 shows how the Twin Cities skyline can look depending onthe degree of visibility. The concentration of particles in the air was 15 micrograms per cubic meter on the left and 35 on the right. 142



### Ozone Ozone can be good or bad depending on where it is
found. In the earth ’ s upper atmosphere, ozone occurs naturally and forms a protective layer that
blocks out harmful ultraviolet radiation. In the
earth ’ s lower atmosphere, ozone is formed whenpollutants (nitrogen oxides and volatile organic compounds) emitted from power plants, transportation, industrial plants and other sources react chemically in sunlight.

Ozone pollution is a concern in the summer when
weather conditions needed to form it

— hot, sunny days

— typically occur. Minnesota currently meets federal and state ozone standards. However, this past summer, for the first time since the mid-1970 ’ s, air advisories were issued on six days for the TwinCities due to ozone. Ozone effects can include respiratory irritation, coughing, throat irritation, chest 

### 2001 Energy Planning Report Page 99

MINNESOTA DEPARTMENT OF COMMERCE Figure A.13: Billions of Dollars Saved in Public Health 

### Costs as Result of Reduced Use of Coal in ElectricGeneration in Comparison to Business-as-usual Scenario for 2010 Morbidity Mortality Total SO2 1.2 23.2 24.5 NOx 0.4 1.6 2.0 Total 1.6 24.8 26.4*Data from Environmental Law Institute Report, May 2001. Health benefits calculated only as result of particulate reductions due to lowered SO 2 and NO X emissions under the scenario of 50 percent reduction in coal with replacement primarily by natural gas. The report notes that because of the uncertainties in the estimation of health benefits, the assumptionsmade for these calculations were conservative and therefore these estimates may provide lower benefit estimates compared to other studies. Inaddition, the health benefits modeled did not include co-benefits of lowered urban ozone levels, reduced acid deposition and eutrophication, and increased visibility. Nor does the estimate include the benefits of lowered mercury or carbon dioxide emissions. Values are calculated for the U.S.



### Figure A.14: Particulate Pollution Contributes to Visibility Impairment

8:00 AM on 9/14/00 12:30 PM on 6/28/01 Downtown St. Paul from Mounds Parktightness, lung injury, asthma aggravation, and increased susceptibility to respiratory infections. Those most susceptible to the effects of ozone
include children and adults who are active outdoors and people with respiratory disease.

Figure A-15 shows the number of days that the daily 8-hour average ozone concentration exceeded the standard for the past five years. Two more summerslike 2001 could cause parts of Minnesota to be designated as nonattainment. (The method for determining attainment states requires several years of data). Nonattainment results in a federally mandated plan typically including controls on large stationary
sources and mobile sources. 

### Mercury
Of Minnesota ’ s 85,000 square miles, 5,100 square miles are covered by lakes, rivers and streams, but a particularly toxic form of mercury, methyl mercury,
contaminates the fish in much of Minnesota ’ s waters. Surprisingly, the fish in some of Minnesota ’ smost remote, pristine lakes are among our most contaminated. Tourism is a major industry in these areas, due in part to the good sport fishing. In mostwaters in Minnesota, over 95 percent of the mercury falls from the atmosphere in rain or as dry fallout. It gets into the lakes when it is washed out of the atmosphere in rain or falls as fine particles, isconverted to methyl mercury in sediments and wetlands, and then accumulates up the aquatic food chain to reach high concentrations in fish.

Methyl mercury is a nerve poison, so eating too much contaminated fish can harm health. If a person does not eat a large amount of game fish, they areprobably not at risk. However, children and developing fetuses are susceptible to subtle, long-term nerve damage, even with small amounts of methyl mercury. Therefore, the Minnesota Department of
Health

— in its annual fish consumption advisory

— provides guidance on how many fish are safe to eat. In addition, mercury contamination could also be affecting the health of fish-eating wildlife, like loons. The long-term solution to this problem is not to limithow much fish people eat (which offers no protection to Minnesota ’ s wildlife), but to reduce the input of mercury to lakes.

Up to 90 percent of the airborne mercury landing on
northern Minnesota lakes blows in from outside thestate. Ten percent of the mercury comes from instate sources. Coal-fired power plants withinMinnesota contribute incrementally to the contamination of any particular lake or river within Minnesota. Other sources can have larger local impacts depending on the amount of mercury released, the species of mercury, and stack height.

Mercury in the environment undergoes many transformations before it is finally taken up into fish. Because the total pool of mercury is too large, the amount of mercury being emitted and the amount of mercury already in the environment needs to be reduced, regardless of emission source
or chemical form. 

### Page 100 2001 Energy Planning Report

MINNESOTA DEPARTMENT OF COMMERCE Figure A.15: Number of Days with Ozone Levels Greater than the 8-Hour Standard (ppb)

0 1 2 3 4 5

1996 1997 1998 1999 2000 2001# of days

Year

### Metals Power plants also emit metals such as cadmium, arsenic, vanadium, chromium, nickel and lead. Lead has historically been a concern in Minnesota ’ s urban areas.

Atmospheric lead is emitted from a variety of stationary sources. Nationwide, primary and secondary metals processing, waste incineration other than municipal waste, and aircraft are the most significant air emissions contributors of lead today. Coal burning in utility boilers contributes about 2 percent to the total releases of lead to the air today. According to EPA ’ s National Air Pollutant Emission Trends Report (1999), total lead emissions from all sources dropped from 220,860 short tons in 1970 to 4,199 short tons in 1999. Nationally, coal burning in utility boilers released 327 tons of lead in 1970, and 72 tons in 1999. 143

In Minnesota, lead in the air has dropped significantly. Between 1984 and 1994, average lead concentrations decreased 87 percent, from 0.53 μ g/m3
to 0.06 μ /m3 (compare to the national ambient air quality standard of 1.5 μ /m3). Minnesota ’ s emissions profile is similar to the national profile, suggesting that today, the most significant contributorsto atmospheric lead emissions are metals processing (lead and other metals smelters) and aircraft use
of leaded fuel. 144


### Global Climate Change Global warming results from the accumulation in the atmosphere of very long-lived gases that act to absorb infrared radiation, trapping it in the lower atmosphere and leading to globally rising surface and atmospheric temperatures. As a result of global warming, virtually every component of what we know as weather will change. Temperature will change. Rainfall will change, both in terms of its intensity, its distribution across seasons, and in its aggregate annual amount. Surface evaporation will change, as will seasonal soil moisture, run-off and stream flow. Some seasons will lengthen in duration, some dramatically shorten. The length of periods ofpeak heat and humidity will change, as will cloudiness, wind speed, patterns of storminess, and virtually every other component of weather.

These changes, should they occur, could dramatically effect the ecology of Minnesota. Ecological systems are tightly coupled to prevailing climate. As climate changes, ecological communities change. In Minnesota, ecological systems varywidely from a cold climate boreal forest in the
extreme north to a warm temperate oak parkland in the south,
woodland in the east and prairie in the west. Asclimate changes, particularly as it warms,
Minnesotans will see a progressive forced
northward march of
conditions favorable to warm temperature forests now dominant toour south, and the progressive shrinkage of
cool and cold climate vegetation types. Few ecological systems now
found in Minnesota are likely to survive this without significant disruption.

Gases that contribute to global warming are called greenhouse gases. The principal greenhouse gas is
carbon dioxide or CO 2 . Most human-produced CO 2 is emitted during the combustion of coal, oil and natural gas. Since the beginning of industrialization about 150 years ago, atmospheric concentrations of
CO 2 have risen about 30 percent, as shown in Figure A-16. Continued dependence on these fuels as the principal global source for energy will result in at least a doubling of preindustrial atmospheric
concentrations of CO 2 , and perhaps as much as a tripling. It has been widely accepted in the scientific community for three decades that a doubling of the preindustrial level of CO 2 will cause mean global surface temperature to rise between 1.5 and 4.5 degrees Celsius

— a view reaffirmed by the U.S. National Academy of Sciences earlier in 2001 in its latest scientific review of the question. 145

Since the beginning of industrialization, the mean surface temperature of the earth has risen about 0.7 degrees Celsius. For many hundreds of years prior 

### 2001 Energy Planning Report Page 101

MINNESOTA DEPARTMENT OF COMMERCE Figure A.16: Carbon Emissions, CO 2 Concentrations and Temperature Change, 1000-2000

Chart by Matt Kaniato industrialization, global surface temperature was very stable at levels much cooler than now. Beginning in 1900, global temperatures abruptly turned up in a warming without any parallel in the record of the prior 1,000 years. (see Figure A-16)

Most climatologists expect the warming trend to continue and even accelerate as emissions of greenhouse gases continue to accumulate in the atmosphere. It
has been common for several decades to find in the scientific literature estimates of future warming of 2 to 3 degrees Celsius over the next 50 to 100 years. Recently, the UN Intergovernmental Panel on Climate Change concluded that, accounting for uncertainties, mean global surface temperature will rise 1.4 to 5.8 degrees Celsius over the next 100 years. 146

In general, the degree of forecasted warming is roughly comparable to the amount of warming that the earth experienced at the end of the last ice age,when rising global temperatures changed a perennial winter-like climate throughout much of the northern half of the northern hemisphere into the presentwarm climate. This provides a measure of the intensity and geographic scale of the changes in ecological and other natural systems that are contemplated. As a rule of thumb, each 1 degree Celsius rise intemperature in the Northern Hemisphere is associated with a northward displacement of climatic and ecological regions of about 100 miles.

Once present in the atmosphere in elevated concentrations, CO 2 persists in the atmosphere at elevated concentrations for hundreds of years. This renders a
CO 2 -induced warming, once initiated, essentially irreversible by natural means over a time scale of
several lifetimes. In 2000, the U.S. Department of Commerce prepared a national assessment of impacts from global warming. Specific effects that are thought likely to
result in Minnesota include:

• retreat of the spruce-fir ‘ boreal ’ forest of the Boundary Waters Canoe Area and replacement by northern hardwood forest;

• progressive replacement of much of the aspenbirch forest for northern Minnesota by temperate deciduous forest and deciduous savanna, and associated decline in habitat for some wildlife currently inhabiting the state;

• loss of 50 to 100 percent of stream habitat for
cold water fishes like brook trout and decline
of habitat for cold water fishes in shallow Minnesota lakes;

• heightened influx of invasive species into Minnesota waterways and lakes;

• expansion of insect populations in Minnesota,requiring more intensive public health measures associated with the control of insect-borne diseases;

• reduced Great Lakes lake levels, requiring new
investments in harbor facilities in DuluthSuperior, and affecting the competitiveness ofthe Great Lakes shipping business and industries that depend on it; and

• reduced opportunities for winter recreation.

Agricultural production is thought likely to increase.However, due to higher summer surface temperatures, the number of days conducive to the formation of high levels of ozone may increase, leading to declining air quality. Large new public expendituresmay become necessary to account for climatic uncer

### Page 102 2001 Energy Planning Report

MINNESOTA DEPARTMENT OF COMMERCE Figure A.17: Principal Heath and Environmental Impacts of Air Pollutants Emitted From Coal-Fired Power Plants
Pollutant Effects Geographical Scope of Effect* Sulfur Dioxide Respiratory disease, acidification, crop losses, visibility impairment Local, regional Nitrogen Oxides Respiratory disease, acidification, crop losses, visibility impairment, eutrophication Local, regional Particulate Matter Respiratory and cardiac disease, premature death, visibility impairment Local, regional Mercury Central nervous system disease Local, regional, global Metals Various - depends on the metal Local, regional Secondarily formed pollutants Local, regional

•SO 4 from SO 2 Acidification •NO 3 from NO X Acidification, eutrophication
•PM 2.5 from SO 2 and NO X Respiratory disease, prematuredeath, visibility impairment •Ozone from NO X Respiratory disease, visibility impairment Carbon Dioxide Climate change Global

*Local: Within 100 miles; Regional: Within 1,000 milestainty in the design of sewage and wastewater treatment facilities, the in-land barge system and the flood
control infrastructure.

It is now generally recognized that some limit on atmospheric CO 2 levels will be necessary in the future to minimize the risks of global climate change to society. Current global policy is summarized in the provisions of the 1992 United Nations Framework Convention on Climate Change, of which the U.S. is a signatory. Under the terms of the Convention, the parties are required to implement policies to stabilizetheir emissions of greenhouse gases to the atmosphere at 1990 levels. The stated goal of the
Convention is the avoidance of ‘ dangerous ’ human interference in global climate. The level at which to cap CO 2 concentrations has yet to be determined.



### Acid Rain
Acid rain

— or acid deposition- causes acidification of lakes and streams and contributes to damage of trees and many sensitive forest soils. The primary causes of acid deposition are sulfur dioxide and nitrogen oxides. Thus, coal-fired power plants are significant contributors to acid rain. Acid depositionis a complex problem whose sources are often distant from its impacts and is highly variable acrosstime and geography. Prevailing winds blow the compounds that cause both wet and dry acid deposition across state and national borders, and sometimes
over hundreds of miles.

Acid rain causes a cascade of effects that harm or kill individual fish, reduce fish population numbers, completely eliminate fish species from a water body, and decrease biodiversity. Some types of plants and animals are able to tolerate acidic waters. Others, however, are acid-sensitive and will be lost as watersbecome more acidic. The impact of nitrogen on surface waters is also critical. Nitrogen plays a significant role in episodic acidification and new research recognizes the importance of nitrogen in long-term chronic acidification as well. Nitrogen is also an important factor in causing eutrophication (oxygen depletion) of water bodies.

In Minnesota, our lakes and soils are fairly wellbuffered and the effects of acid rain are not considered a problem here. However, in the northeastern
United States soils and lakes are much more sensitive to the effects of acid rain. Despite declining national emissions of sulfur dioxide, recent scientific study is showing that the capacity of lakes andsoils to recover from acid deposition is less than previously thought. 147 Many lakes in the northeast U.S.
are acidic and have few or no fish. Science reportsthe researchers are calling for an additional 80 percent cut in emissions beyond the current mandate and that may only bring partial recovery to fish and trees by 2050. 148



### Conclusion Power plants

— especially coal-fired power plants

— contribute significantly to the environmental andhealth impacts from air pollution. Figure A-17 summarizes the key air pollutants emitted from electricgeneration and their effects on health and the environment. 

# Current and Developing National Regulations Governing Utility Emissions

This section ’ s review of current and developing national programs will show that, due to thesehealth and environmental effects, utilities must continue to reduce emissions under programs already being implemented and further cuts are expected to be required under new programs. As a result, total
emissions from utilities in the future will have to be significantly lower than today, including emissions from whatever new generation capacity is needed.

In the past thirty years, numerous federal regulations and programs have affected air emissions from the electric power industry as shown in Figure A-18.Arguably the most successful and cost-effective program has been the Acid Rain Program

— an emissions “ cap and trade ” approach that has resulted in sulfur dioxide emissions dropping 4.5 million tons and nitrogen oxides emissions dropping 1.5 million tons from 1990 levels nationally. However, based upon the failure of lakes and streams to recover despite the drop in emissions, some scientists are calling for further reductions beyond the 1990 Clean
Air Act Amendments.

New Source Review is an older, more traditional regulatory program that is undergoing change. One intent of New Source Review is to require existing plants to improve their emissions control when they undergo a major modification. The New Source 

### 2001 Energy Planning Report Page 103

MINNESOTA DEPARTMENT OF COMMERCE National Air Standards/ 1970 State Implementation Plans

New Source Review/Visibility Programs PM 10 National Air Standard
1980

1990 UN Framework on Climate Change International Treaty (USA signatory)

Acid Rain SO 2 Phase 1 Acid Rain N0x Phase 1 N0x NSPS Revision

Acid Rain N0x Phase 2 2000

and SO 2 Phase 2

Assess Attainment of Revised PM 2.5 and Ozone Air Standards Interstate N0x Air Pollution Petitions/N0x State Plans US/Canada N0x Treaty Periodic Review of Ozone & PM 2.5 Air Standard Mercury Standards Implemented/Implement Regional Haze Rules Kyoto Protocol or alternative US Response
2010



### Figure A.18: Major National Air Quality Programs Affecting U.S. Electric UtilitiesReview process identifies the most appropriate (i.e.,lowest) level of emissions for a process on a case-bycase basis and applies the current best available control technology to the source. 149

In the near future, electric power plants will be the focus of a number of major initiatives to reduce air emissions, described in the next few paragraphs.


### Mercury National Emission Standard for Hazardous Air Pollutants EPA is developing a rule to limit mercury emissions from utilities. As required by the 1990 Clean Air Act Amendments, EPA studied emissions of hazardous air pollutants (or air toxics) from fossil-fuel-fired power plants and found in December 2000 that air toxics control (e.g. mercury control) is appropriate for coal-fired and oil-fired utility boilers. EPA is scheduled to propose a Maximum Achievable Control Technology standard by 2003 for these sources that is expected to focus on mercury control.


### Regional Haze Rules EPA recently finalized a regional haze rule designed to return visibility to natural conditions in national parks and wilderness areas. The rule will require power generators to reduce SO 2 and NOx emissions either through implementation of best available retrofit technology or a trading program yet to be developed.


### Implementation of New PM 2.5 and Ozone Standards
Since the PM 2.5 national ambient air quality standardfor fine particles was set in 1997, dozens of new published studies, taken together, collectively strengthen
the association between PM 2.5 and severe human health effects. In 1997, EPA also established a new
standard for ozone. If a state has areas that do not meet an air quality standard, then the Clean Air Actrequires the state to adopt emissions control requirements in the form of State Implementation Plans to bring nonattainment areas into compliance.

The MPCA will be able to determine its compliance
status with the PM 2.5 standard in 2002 (3 years of data is needed to determine compliance). TheMPCA expects Minnesota will be below the standards, but by a narrow margin. Recent exceedances
of the ozone standard in Minnesota and states to theeast suggest the possibility of future control requirements in Minnesota to address the ozone problem. Power plants are significant contributors to PM 2.5 and ozone precursor emissions.


### NOx Reduction Requirements In 1998, EPA finalized the NOx State Implementation Plan (SIP) call which requires the District of Columbia and 19 states (whose emissions contributesignificantly to downwind ozone nonattainment problems) to revise their SIPs to control summertime NOx emissions. In response, all of these states are choosing control strategies that focus on reducing power plant emissions. In a separate action, in January 2000, EPA finalized a rule which was issued in response to petitions from some northeastern
states under section 126 of the Clean Air Act. The rulerequires large electric generating units and large boilers and turbines in 12 states and D.C. to control summertime NOx emissions under the Federal NOx Budget trading program beginning May 1, 2003. Minnesota is currently not one of these states.


### Potential Multi-Pollutant Regulation Proposal by the Administration EPA and the White House are working to finalize the details of a legislative proposal that will set limits on the utility emissions of three major air pollutants

— nitrogen oxides, sulfur dioxide and mercury

— through the use of a “ cap and trade ” program. The strategy consists of establishing an emissions cap for existing sources. In return for the cap, NewSource Review would be relaxed and plants undergoing a modification would not necessarily need to install the best available control technology.


### Multi-Pollutant Regulation Proposals by Congress Legislation has been introduced in both the Houseand Senate that would require power plants to further reduce emissions. Representative Waxman ’ s bill (H.R. 1256) and Senator Jefford ’ s bill (S. 556) are very similar. Both bills would require:

• Plants 30 years old or more to comply with requirements for new sources within five years
after enactment.

• Aggregate emissions reductions

— not facility specific reductions.

• 75 percent reduction in NOx emissions from 1997 levels by 2007. 

### Page 104 2001 Energy Planning Report

MINNESOTA DEPARTMENT OF COMMERCE• 75 percent reduction in SO 2 emissions from Phase II acid rain levels by 2007.

• 90 percent reduction in mercury emissions from 1999 levels by 2007.

• Carbon dioxide emissions to 1990 levels by
2007.

• Regulations within 2 years. (S. 556 would require each plant to achieve reductions if EPA fails to meet timeline.)

Both bills may allow market-oriented mechanisms, except for mercury, to achieve these reductions.They also would allocate required emissions reductions equitably, taking into account reductions before enactment of the legislation. Jefford ’ s bill alsoincludes policies to reduce the rate of growth in natural gas consumption. 

# Reducing Emissions from Existing Power Plants
By applying proven pollution control technologies at
Minnesota ’ s existing coal-fired power plants, utility companies can reduce the emission rates of several pollutants. In particular, proven technologies can beinstalled that would significantly reduce the emissions of sulfur dioxide (SO 2 ) and nitrogen oxides (NOx) at Minnesota ’ s power plants.

Within the last ten years, Minnesota ’ s electric utilities
reduced SO 2 and NOx emission rates at some of their power plants, primarily to comply with the Acid Rain provision of the 1990 Clean Air Act Amendments. The Acid Rain program allows system-wide averaging; companies can reduce emissions significantly at oneplant while other plants continue to emit at higher levels. To comply with the SO 2 provisions of the Acid Rain program, many of Minnesota ’ s power plants switched from the higher sulfur coals they were usingto lower-sulfur coals. Few, if any, plants were significantly modified to meet the new standard. To meet the NOx requirements of the Acid Rain program, companies that needed to reduce their system-wide emissions may have modified one or two facilities,while the others are operated as before. With a significant reduction at a small number of units, the company ’ s average could meet the standard.

By using these methods to comply, the utilities have preserved opportunities for further improvement. For example, none of Minnesota ’ s large power plants meet both of the emission standards for SO 2 and NOx for new plants set in the federal New Source Performance Standard (NSPS) for electric utility generating units. 150 (The NSPS basically requires a 90 percent reduction in the amount of
SO 2 that the plant could emit without added controls. The NSPS sets a limit of 1.6 pounds of NOx per megawatt-hour of electricity generated.) Figure A-19
shows the characteristics of Minnesota ’ s baseload 

### 2001 Energy Planning Report Page 105

MINNESOTA DEPARTMENT OF COMMERCE Figure A.19: Characteristics of Selected Baseload and Intermediate Load Coal-Fired Utility Boilers in Minnesota
Name Approximate Boiler type Estimated SO 2 Estimated NOx Capacity Emission rate Emission rate MP

– Clay Boswell 1 70 MW Wall-fired 0.85 lb/mmBtu 0.4 lb/mmBtu MP

– Clay Boswell 2 70 MW Wall-fired 0.85 lb/mmBtu 0.8 lb/mmBtu MP

– Clay Boswell 3 350 MW Tangential 0.85 lb/mmBtu 0.3 lb/mmBtu MP

– Clay Boswell 4 535 MW Tangential 0.15 lb/mmBtu 0.3 lb/mmBtu MP

– Syl Laskin 1 55 MW Tangential 0.3 lb/mmBtu 0.5 lb/mmBtu MP

– Syl Laskin 2 55 MW Tangential 0.3 lb/mmBtu 0.5 lb/mmBtu OPC

– Hoot Lake 2 65 MW Tangential 0.6 lb/mmBtu 0.6 lb/mmBtu OPC

– Hoot Lake 3 85 MW Wall-fired 0.6 lb/mmBtu 0.3 lb/mmBtu RPU

– Silver Lake 60 MW Wall-fired 1.7 lb/mmBtu 0.4 lb/mmBtu Xcel

– A. S. King 570 MW Cyclone 1.6 lb/mmBtu 1.1 lb/mmBtu Xcel

– Black Dog 3 115 MW Wall-fired 0.35 lb/mmBtu 0.3 lb/mmBtu Xcel

– Black Dog 4 170 MW Wall-fired 0.35 lb/mmBtu 0.8 lb/mmBtu Xcel

– High Bridge 5 100 MW Wall-fired 0.4 lb/mmBtu 0.4 lb/mmBtu Xcel

– High Bridge 6 170 MW Wall-fired 0.4 lb/mmBtu 0.6 lb/mmBtu Xcel

– Riverside 6 80 MW Wall-fired 0.4 lb/mmBtu 0.9 lb/mmBtu Xcel

– Riverside 7 150 MW Wall-fired 0.35 lb/mmBtu 0.9 lb/mmBtu Xcel

– Riverside 8 220 MW Cyclone 1.4 lb/mmBtu 1.1 lb/mmBtu Xcel

– Sherco 1 710 MW Tangential 0.2 lb/mmBtu 0.3 lb/mmBtu Xcel

– Sherco 2 720 MW Tangential 0.2 lb/mmBtu 0.3 lb/mmBtu Xcel

– Sherco 3 870 MW Wall-fired 0.35 lb/mmBtu 0.3 lb/mmBtu

NOTES: Data as reported by US Department of Energy for 1999. Clay Boswell unit 4 and Sherco units 1, 2, and 3 are controlled for SO2. NOX controls are installed at Clay Boswell unit 4, A..S. King, and Sherco units 1, 2, and 3.and intermediate coal-fired utility boilers, and their
estimated emission rate.

The MPCA analyzed several control technologiesthat can be applied to the types of electricity generating units found in Minnesota. The SO 2 control efficiency and the cost of three types of scrubbers 151 were evaluated using five models. Characteristics of
these models and Minnesota facilities with similar characteristics are shown in Figure A-20. 152 Because the boiler design does not usually affect whether a scrubber can be installed, the three SO 2 control methods were applied to each of the five models.

The MPCA also assessed a larger number of NOx control technologies for the same five models. While some of the control technologies can be added on to almost any boiler (e.g., selective catalytic reduction, or SCR; and selective non-catalytic reduction, orSNCR; and natural gas reburn), some control methods must be matched with specific boilers. 153

Three boiler configurations were investigated. Wallfired units are the most common boiler types found in
Minnesota. The NOx emissions from wall-fired unitsmay be reduced by the installation of low-NOx burners (LNB) with or without overfire air (OFA). Minnesota also has a few tangentially-fired boilers and cyclone boilers. Coal-and-air nozzles may be installed to reduce NOx in tangentially fired boilers with either close-coupled overfire air or separated overfire air, or both. 154 To reduce emissions at cyclone boilers, coal reburning technology may be added. The MPCA looked at three SO 2 control technologies on five boiler models in Figure A-21. Minnesota has a number of coal-fired utility boilers that are used to generate electricity in Minnesota. These units vary by their size, the type of boiler, and by
their SO 2 emission rate. To assess the range of costs for controlling SO 2 emissions, the MPCA looked at
three SO 2 control technologies on the five boilermodels introduced earlier. The three flue-gas desulfurization options each achieved at least a 90 percent reduction in emissions (LFSO, which achieves an
SO 2 reduction of 95 percent; LSD, 90 percent; and MEL, 95 percent). Calculations were performed at two capacity factors (a baseload case of 65 percent and a intermediate load case of 40 percent).

Using an EPA analysis of SO 2 scrubbers 155 as the basis of the computation, the MPCA estimated that the cost of installing SO 2 controls on these boilers would range from about $40 million to nearly $190 million, with the cost increasing with the size of the
boiler. 156, 157 Estimates of annual operating costs (fixed plus variable) ranged from roughly $2 million to about $10 million. (Note that capital costs are the
same for both baseload and intermediate load facilities.) Operating costs increase with the size of theboiler and with increased use. Similarly, the estimated annualized costs range from roughly $5.5 million to over $25 million, rising as the size of the boiler
rises and also with increased use. 158

The cost-effectiveness of control is figured by dividing the annualized cost by the number of tons of SO 2removed from the flue gas (and therefore not emitted to the atmosphere). For the five modeled boilers, the estimated cost of the lowest-cost control at baseload conditions ranged from $1159 to $4861 per
ton of SO 2 removed. For intermediate loads, the estimated cost-effectiveness decreased; the cost per ton ranged from $1729 to $7316.

The cost-effectiveness of a control option usually
increases with the amount of SO 2 removed. (In 

### Page 106 2001 Energy Planning Report

MINNESOTA DEPARTMENT OF COMMERCE Figure A.21: Estimated Costs for Installing SO 2 Controls on Plants (low-cost technology to meet NSPS)
Baseload Annual Intermediate Load Model Capital Cost Operating Cost Annual Operating Costs Number (millions, 1997$) (millions, 1997$) (millions, 1997$) 1 38.4 2.8 2.3 2 38.4 2.8 2.3 3 56.4 4.1 3.4 4 134.1 10.0 8.2 5 134.1 10.0 8.2

*Values to be added 

### Figure A.20: Characteristics of Modeled Boilers

Model Boiler Uncontrolled SO 2 Uncontrolled NOx Facility with Number Capacity Type Emission Rate Emission Rate Similar Characteristics 1 100 MW Wall-fired 0.9 lb/mmBtu 0.6 lb/mmBtu MP: Clay Boswell 2 2 100 MW Tangential 0.4 lb/mmBtu 0.45 lb.mmBtu OTP: Hoot Lake 2 3 150 MW Wall-fired 0.35 lb/mmBtu 0.7 lb/mmBtu Xcel: High Bridge 6/ Riverside 4 400 MW Cyclone 1.5 lb/mmBtu 0.9 lb/mmBtu Xcel: A.S. King 5 400 MW Tangential 0.85 lb/mmBtu 0.35 lb/mmBtu MP: Clay Boswell 3other words, the cost to remove a ton of a pollutant decreases.) This amount of SO 2 removed is related
to the level of the uncontrolled emissions and the removal efficiency of the control technology. For a given capacity factor and control technology, the order of cost-effectiveness for the boilers (from highest to lowest) is likely to reflect the order ofmaximum annual emissions (from highest to lowest). Because emissions are tied to boiler use, controls installed at units with higher capacity factors(such as baseload plants) are likely to be more costeffective than those added at boilers with lowercapacity factors (intermediate load plants and peaking plants).

These trends are generally supported in the analysis. Figure A-22 shows that controlling Model 4 would be the most cost-effective choice. Controlling the other models, particularly Models 2 and 3,
would be less cost-effective. 159

To evaluate the effectiveness and cost of control technologies that reduce emissions of NOx, the MPCA again used the five boiler models presented
in the discussion of SO 2 control technologies. The number of control configurations analyzed varied with the different boiler models, as the applicablecontrol technologies varied by boiler type. In addition, some control technologies could be used together. An EPA model was used to determine theeffectiveness of the control technologies and to calculate their costs. 160, 161

The most effective single control technology was SCR (selective catalytic reduction). The analysis assumed that SCR reduced high concentrations of NOx by 80 percent and low concentrations of NOx by 70 percent. 162 Four of the five models were able to meet the NSPS standard for NOx (1.6 pounds of NOx per megawatt-hour) with only SCR. Alone,however, SCR was not usually the most cost-effective control technology. Frequently, a combination of technologies achieved the desired reductions for the
lowest cost.

As shown in Figure A-23, the cost of installing effective controls (i.e., those that would allow the controlled unit to meet the standard of 1.6 lb NOx/MWhr) ranged from about $9 million to roughly $27 million. Costs for a specific type of control rose as the size of the controlled unit increased. In addition, though, the type of unit played a role, with wall-fired units being the least expensive to control to this level, and cyclone units the most expensive units to control. Figure A-24 shows the most cost-effective control technology that achieved the desired emission level, and the associated cost per ton of NOx controlled.Again, the highest-polluting units (in this case, models 3 and 4) were the most cost-effective to control.

The analyses above indicate that, to meet the requirements that New Source Performance Standards place on new electricity generating units, utility companies must spend an estimated $1000 to $7000 per ton of SO 2 removed and an estimated$650 to $2300 per ton of NOx removed. This compares with values in the literature for similar changes of an estimated $322 per ton of SO 2 removed 163 and an estimated $975 to $2140 per ton of
NOx removed. 164

The MPCA did not investigate the efficiency or costof technologies to control mercury and carbon dioxide. Few control efficiencies or cost estimates havebeen firmly established for retrofits to reduce mer

### 2001 Energy Planning Report Page 107

MINNESOTA DEPARTMENT OF COMMERCE Figure A.22: Estimated Cost to Meet NSPS Standard for SO 2 Emissions
Lowest Cost Cost-effectiveness Cost-effectiveness Model Option to Meet for a for an Number NSPS for SO 2 Baseload Intermediate (selected technology) Plant Load Plant 1 Magnesium-enhanced lime $2,088/tpy $3,146/tpy 2 Magnesium-enhanced lime $4,697/tpy $7,079/tpy 3 Magnesium-enhanced lime $4,861/tpy $7,316/tpy 4 Magnesium-enhanced lime $1,159/tpy $1,729/tpy 5 Magnesium-enhanced lime $2,044/tpy $3,051/tpy



### Figure A.23: Estimated cost for installing NOx controls on plants(low-cost technology to meet NSPS) Model Capital cost Baseload annual Intermediate Load number (millions, 1995$) operating cost annual operating cost (millions, 1995$) (millions, 1995$)
1 8.8 .8 0.7 2 11.6 1.1 0.9 3 14.5 1.1 1.1 4 26.8 4.2 3.6 5 15.5 1.5 1.1



### Figure A.24: Estimated Costs to Meet NSPS 

### Standard for NOx Emissions a Model Lowest cost option Cost-effectiveness Cost-effectiveness Number to meet NSPS for a for an for NOx baseload imtermediate (selected technology) plant load plant 1 SCR $973/tpy $1499/tpy 2 Gas Reburn with SCR $1353/tpy 2290/tpy 3 LNB with SCR $694/tpy $1086/tpy 4 LNC3 with Gas Reburn $653/tpy $957/tpy 5 LNC2 with Gas Reburn $1034/tpy $1422/tpy

a cost in 1995 dollarscury emissions. However, the U.S. Environmental Protection Agency (EPA) and U.S. Department of Energy (DOE) continue to examine the injection of activated carbon and other control technologies thatreduce mercury emissions. Increasing the efficiency of existing plants or switching fuels from coal to natural gas also reduce mercury emissions.

At present, no economically feasible technologies exist for the capture and disposal of CO 2 from power plant flue gases. 165 Three opportunities exist for CO 2 emissions control by the electric utilities. To reduce CO 2 emissions during electricity generation, electricity generators could switch from coal to natural gas. On a per kilowatt-hour basis, the combustion of natural gas to produce electricity results in the production of about
one-third of the CO 2 produced when using coal as a fuel source. Second, electricity generators could offset emissions through carbon sequestration in standingbiomass and soils. During plant growth, carbon dioxide is removed from the atmosphere and stored in plant biomass or soils. The average acre of timberland
in Minnesota stores about 30 tons of carbon.

The Department of Commerce estimated the residential rate impact of installing central technology on theexisting Minnesota plants that most resemble the modeled units. Rate impacts range from $3.59/year to $27.42/year for SO 2 controls, as shown in Figure A-25. For NOx controls, rate impacts range from $1.02/year to $7.87/year, as shown in Figure A-26.
If controls are installed at more than one plant in one utility system and/or for both pollutants, totalrate impacts can be estimated by summing the individual rate impacts.

These estimates assumed that the addition of pollution controls would
not increase the useful life of the facility. While all of the representative
facilities are older plants, even among thefive facilities, the remaining life for depreciation purposes is more than twice as long as the oldest facility. 166 Rate impacts would decrease if the control equipment were depreciated over a longer period of expected plant operation. 

# Policy Recommendations
This section provided detailed information on thecurrent level of emissions from electricity generation in the state, the different environmental impactsassociated with those emissions, and a survey of relevant national environmental program initiatives.While electric generation is not the only source contributing to the environmental problems described in this section, it is a major source of these types of problematic emissions. Electric generation must notincrease and should, over time, decrease its contribution to harmful air emissions. As we add new power plants, we must take care not to compound existing problems. If new plants are constructed thatresult in significant new sources of emissions, emissions from existing plants should be subject to stricter controls or some of the existing plants
should close to ensure no net increase in overall emissions from the electric generation sector. 

### Page 108 2001 Energy Planning Report

MINNESOTA DEPARTMENT OF COMMERCE Figure A.25: Estimated Rate Impact of Installing SO 2 Controls on Plants (Low-Cost Technology to Meet NSPS) Facility Annual 2000 Baseload Cost Annual Baseload Intermediate Annual with Residential Per MWH $ Cost per Load Cost Intermediate Load Model Similar MWH Per MWH Residential Per MWH Residential Number Characteristics Usage 1 2000 $ 2 Customer 3 2000 $ Customer 4 to: (a) (b) (c) (d) (e) 1 Clay Boswell 2 8.32 1.2381 10.30 1.1924 9.92 2 Hoot Lake 2 10.23 2.3816 24.35 2.2743 23.25 3 High Bridge 6/Riverside 7.78 0.4802 3.74 0.4612 3.59 4 A.S. King 7.78 1.3804 10.74 1.3316 10.36 5 Clay Boswell 3 8.32 3.4615 28.79 3.2970 27.42

Assumes that these additions do not lengthen the life of the facility. Longer life would reduce the annual costs.

1 MN Jurisdictional Annual Report 2 Sheet 1 3 column (a) times column (b) 4 column (a) times column (d)



### Figure A.26: Estimated Rate Impact of Installing NOx Controls on Plants (Low-Cost Technology to Meet NSPS) Facility Annual 2000 Baseload Cost Annual Baseload Intermediate Annual with Residential Per MWH $ Cost per Load Cost Intermediate Load Model Similar MWH Residential Per MWH Residential Number Characteristics Usage 1 2000 $ 2 Customer 3 2000 $ Customer 4 to: (a) (b) (c) (d) (e) 1 Clay Boswell 2 8.32 0.3140 2.61 0.3044 2.53 2 Hoot Lake 2 10.23 0.8151 8.33 0.7699 7.87 3 High Bridge 6/Riverside 7.78 0.1313 1.02 0.1313 1.02 4 A.S. King 7.78 0.3543 2.75 0.3363 2.62 5 Clay Boswell 3 8.32 0.4545 3.78 0.4160 3.46

Assumes that these additions do not lengthen the life of the facility. Longer life would reduce the annual costs.

1 MN Jurisdictional Annual Report 2 Sheet 1 3 column (a) times column (b) 4 column (a) times column (d)In 2001, the legislature responded to growing publicconcern over air emissions from existing electric generating plants by enacting an emissions reductionrider that allows utilities to propose cost-effective pollution controls on existing plants, and receive rate recovery. Minnesota ’ s largest utility, Xcel Energy, has agreed to analyze possible emission control options at three of its plants by the summer of 2002. The study by Pollution Control Agency staff of possible control options presented in this section of the report will give policymakers a sense of the kinds of costs that would be incurred in installing pollution control equipment at selected existing facilities.

Policy considerations for the legislature include whether to require other utilities to prepare studies



### 2001 Energy Planning Report Page 109

MINNESOTA DEPARTMENT OF COMMERCE on cost effective pollution controls at some of their major existing uncontrolled generating plants. Another issue that may need to be addressed,depending on the response of utilities to the opportunity provided by the emission rider, would be to require certain projects to be implemented that the
Public Utilities Commission determines to be costeffective for ratepayers and to have significant positive impact on environmental emissions. The present emissions rider language makes implementation of a project entirely voluntary with the utility. Lastly, since it is likely that new electric generation plants constructed in Minnesota to meet growing demand for electricity will increase overall emissions of air pollutants, emissions at existing plants should be reduced by at least as much as new emissions.



# ENDNOTES
134. This is because NSPS are based on the best available technology at the time they are adopted, and control technologies of the 1990s are superior to those of the 1970s. 135. NSPS do not regulate mercury and CO 2 emissions. 136. Figure A-10 includes the two new gas peaking plants, Pleasant Valley and Lakefield Junction, because they were added in 2001 and their emissions thus occur after 1999. Figure A-10 also includes a handful of small capacity additions that were not listed in Figure 3-3 in Chapter 3 of the main report because their construction is below the thresholds for PUC approval.
137. Other sources of these pollutants also contribute to these pollution problems, but as shown in Figure A-1, electric generation is a significant or predominant source category for these pollutants. 138. Dockery, D.W., C.A. Pope III, X. Xu, J.O. Spergler, J.H. Ware, M.E. Fay, B.G. Ferris, Jr., and F.E. Speizer, 1993. An Association Between Air Pollution and Mortality in Six U.S. Cities, New England Journal of Medicine, pp. 281-287. 139. EPA. Air Quality Criteria for Particulate Matter, Office of Research and Development, EPA/600/p. 95/001, April 1996.140. Daniels, J.J., Dominici, F., Sanet, J.M., Zeger, S.L., 2000. Estimating Particulate MatterMortality Dose-Response Curves and Threshold Levels: An Analysis of Daily Time-Series for the 20 Largest US Cities, American Journal of Epidemiology, Vol. 152, No. 5, pp. 397-406. Schwartz, J. 1999. Air Pollution and Hospital Admissions for Heart Disease in Eight U.S. Counties. Epidemiology, Vol. 10, No. 1, pp. 17-22. Schwartz, J. and A. Zanobetti, 2000. Using Meta-Smoothing to Estimate Dose-Response Trends Across Multiple Studies, with Application to Air Pollution and Daily Death. Epidemiology, Vol. 11, No. 6, pp. 666-672. 141. Science, vol 293 17 August 2001, at 1257.
142. The left photo was taken on Sept. 14, 2000 at about 8:00 a.m. from Mounds Park in St. Paul. The right photo was taken on June 28, 2001 at 12:30 p.m.
143. U.S. EPA, 2001. National Air Emissions T r

ends. Website http://www.epa.gov/ttn/chief/trends/trends99/tier3_yrsemis.pdf accessed December 10, 2001.
144. MPCA. Minnesota Air: Air Quality and Emissions T r

ends. September 1997, p. 153.

### 145. The US National Academy of Sciences reviewed the underlying science of global climate change in 1979, 1981, 1983, 1987 and 1991, concluding in each instance that, with a doubling of atmospheric CO 2

, mean global surface temperature would rise 1.5 to 4.5 degrees Celsius. 146. While there is virtually no debate about the reality of the observed surface warming, scientistsdebate the degree to which mean global surface temperature will rise. However, even climate skeptics have concluded that at least some continuation of the observed 20th century warming is likely. To the degree that they have furnished estimates of future warming, these scientists have tended to support forecasts near the lower end of this range, 1 to 2 degrees Celsius, with one low value near 0.5 degrees Celsius.
147. BioScience, March 2001/ Vol 51 No. 3 pp. 180 –198.
148. Science Vol. 292, April 13, 2001 pp. 195-196.
149. New source review, because it is case-by-case, does not suffer from the control requirementfailing to be equal to stringent new technology. New source review was enacted to address this deficiency in the design of the NSPS program.
150. The New Source Performance Standards for utilities (40 CFR 60 Subparts D, Da, and Db) address emissions of SO 2

, NOx, and particulate matter. Emissions of other pollutants, including mercury and carbon dioxide, are not restricted by these regulations. A federal emission limit for mercury will probably be a part of a new National Emission Standard for Hazardous Air Pollutants (NESHAP) for utilities. The U.S. Environmental Protection Agency does not regulate carbon dioxide.

151. The three SO 2 control technologies are limestone forced oxidation (LFSO), limestone spraydrying (LSD), and magnesium-enhanced lime (MEL). Each of these flue-gas desulfurization technologies use scrubbing to reduce SO 2 emissions.
152. The “representative” facilities exhibit characteristics that most closely resemble the modeled units. However, the characteristics of the modeled units and the identified facilities are not identical.

153. While most SO 2 emissions are formed from the direct combustion of sulfur contained in thecoal, NOX emissions are formed in two ways. First, nitrogen in the coal can be oxidized (combusted). This creates a relatively small amount of NOx. The second way in which NOx is formed involves the heating of the air provided for combustion. When heated, the nitrogen in the air mayreact with nearby oxygen to form NOx. This reaction is more likely at higher temperatures. It generates most of the NOx created at a utility boiler. By redesigning the combustion chamber, the amount of NOx generated by the second method can be limited. However, this requires boiler-specific modifications. This is the reason that some of the control methods must be matched with specific boilers.
154. Coal-and-air nozzles with close-coupled overfire air is referred to as LNC1. When coal-andair nozzles are used with separated air, it is called LNC2. LNC3 refers to the case in which both types of air supply are used with the nozzles. 155. Srivastava, Ravi K., and Jozewicz, Wojciech. Controlling SO 2 Emissions: An Analysis of Technologies. EPA/600/SR-00/093, November 2000. Also: Srivastava, Ravi K. Controlling SO 2 Emissions: A Review of Technologies. EPA/600/R00/093, November 2000.
156. Costs for SO 2 controls are provided in 1997 dollars. 157. The actual costs of installing SO 2 controls at a particular plant must be determined on a case-by-case basis. This analysis relies on average costs from previous installations.158. Annualized costs are calculated by distributing the cost of the initial installation over the lifetime of the equipment, plus interest, and adding that cost to the annual operating costs. In this case, an interest rate of 6 percent and a twenty year life were used.
159. Model number 2 had a cost-effectiveness of $4697/ton, while model number 3 had a costeffectiveness of $4861/ton. Model number 4’s cost-effectiveness was $1159/ton. Page 110 2001 Energy Planning Report

MINNESOTA DEPARTMENT OF COMMERCE

### 160. EPA. Analyzing Electric Power Generation Under the CAAA. Office of Air and Radiation, July 1996. 161. The actual costs of installing NOx controls at a particular plant must be determined on a case-by-case basis. This analysis relies on costs from previous installations. 162. High NOx concentrations are those exceeding 0.5 lb/mmBtu. 163. Energy Information Administration. “ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update. ” (Costs in 1995 dollars.)
164. Butraw, Dallas; Palmer, Karen; Bharvirkar, Ranjit; and Paul, Anthony. “ Cost-effective Reduction of NOx Emissions from Electricity Generation. ” Discussion Paper 00-55, Resources for the Future, December 2000. (Costs in 1997 dollars.)
165. It is expected that systems for CO 2 capture could be commercially available within several decades at reasonable costs. 166. The remaining lives are: 6 years for Boswell 2, 11.3 years for Hoot Lake, 7.9 years for High Bridge 6, 5 years for King, and 12 years for Boswell 3.

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MINNESOTA DEPARTMENT OF COMMERCEAPPENDIX A: DEALING WITH ENVIRONMENTAL IMPACTS OF EXISTING ELECTRIC GENERATION 93 93 Current and Forecasted Emissions from Electric Generation in Minnesota 93 Health and Environmental Impacts of Electric Generation 98

Particulate matter 98 Ozone 99 Mercury 100 Metals 101 Global Climate Change 101 Acid Rain 103 Conclusion 103 Current and Developing National Regulations Governing Utility Emissions 103

Mercury National Emission Standard for Hazardous Air Pollutants 104 Regional Haze Rules 104 Implementation of New PM2.5 and Ozone Standards 104 NOx Reduction Requirements 104 Potential Multi-Pollutant Regulation Proposal by the Administration 104 Multi-Pollutant Regulation Proposals by Congress 104 Reducing Emissions from Existing Power Plants 105 Policy Recommendations 108 ENDNOTES 109

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# Environmental Section for the Energy Planning Report Update:

Recent Concerns about Air Pollution from Power Plants

A comprehensive discussion of the impacts of power plants on public health and the environment can be found in the 2001 Energy Planning Report. Since publication of that report, there has been increasing concern about two pollutants that are linked, in part, to power plant emissions – fine particulates and ozone.

Fine particulate matter is a complex mixture of very sm all liquid droplets or solid particles in the air. Major sources are cars, trucks, construction equipment, coal-fired power plants, wood burning, vegetation and livestock. These particles can be directly released when coal, gasoline, diesel fuels and wood are burned. Many fine particles are also formed in the atmosphere from chemical reactions of nitrogen oxides, sulfur oxides, organic compounds and ammonia. Fine particulates are associated with increased hospitalizations and deaths due to respiratory and heart disease and can worsen the symptoms of asthma. People with respiratory or heart disease, the elderly and children are the groups most at risk. Fine particles are also major contributors to reduced visibility (haze). Power plants are significant sources of fine particulates because of their emissions of SO 2 

### and NOx.

PM-2.5

In the past year since publication of the 2001 Energy Planning Report, the evidence that fine particles in the atmosphere are linked to health effects has strengthened. Scientists are finding serious health impacts at levels below the federal air quality standard. This evidence indicates that Minnesotans are likely impacted by breathing fine particulates. While this region meets the annual PM-2.5 ambient standard of 15  g/m3 and the 24 hour standard of 65  g/m3, the Minnesota Pollution Control Agency (MPCA) has had to issue air alerts when PM-2.5 levels reach 40.5  /m3. EPA has specified 40.5  /m3 for these warnings because research has shown that serious health effects can occur at levels below the standard. Air reached alert levels for fine particles twice in 2002. One event occurred when smoke from Canadian forest fires reached Minnesota. In addition, a review of available PM-2.5 data indicates that concentrations in the Twin Cities reached levels considered “Unhealthy for Sensitive Groups” on seven days during calendar year 2000 and on four days during calendar year 2001. One PM-2.5 event considered “Unhealthy” was monitored in October 2000 in Minneapolis. PM-2.5 events can happen throughout the year, although the causes of high PM levels may differ seasonally.

Ozone

Another pollutant that is receiving increased attention is ozone. Ground level ozone, also called “smog,” is formed in the atmosphere by chemical reactions involving NOx, volatile organic chemicals, and sunlight. Ozone pollution is primarily a summer problem because of the need for sunlight in the formation process. Ozone affects healthy adults, but children and pe ople with existing respiratory problems are most susceptible to its presence. Ozone causes eyes to itch, burn and water, triggers asthma attacks, and can cause coughing, chest pain and difficult breathing. Power plants are a significant contributor to ozone because of their emissions of NOx.

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EPA promulgated a new, more restrictive ozone standard in 1997. Currently, Minnesota is considered to be in compliance with that standard. However in the last 2 years, the MPCA has had to issue air alerts for ozone—4 times in 2001 and twice in 2002. These represent the first air pollution alerts issued for ozone since the 1970’s. A recent study commissioned by the MPCA has determined that ozone levels appear to be increasing the Twin Cities 1 

### . If this trend continues and the Twin Cities drops out of compliance for ozone, new federal regulations costing up to $250 plus million per years would be required 2



### . 

## Regulatory Activities on the Horizon

Several major regulatory initiatives will affect power plant emissions. These regulations would have significant impacts on the operations and emissions of power plants in Minnesota. They could also play a role in decisions about new generating capacity.

First, EPA recently finalized a rule to improve visibil ity in National Parks and Wilderness Areas (called the Regional Haze Rule.) This rule requires the development of plans to improve visibility by 2007-2008. Power plants play an important role in the formation of haze, but it is not yet known to what extent emissions will be reduced through this regulation. There is a multi-state regional planning effort underway to identify what emission reductions will be needed to reduce regional haze.

Second, EPA’s new ambient air standards for PM2.5 an d ozone are in effect. Plans to address these standards will likely also be due in the 2007-2008 timeframe. Even if these standards are being met in Minnesota, it is possible that emission reductions will be required from power plants in Minnesota to help meet the standards in other states, such as Wisconsin, Illinois and Michigan.

Third, EPA is currently developing a rule to limit mercury emissions from fossil-fuel-fired power plants. This rule is required by the 1990 Amendments to the Clean Air Act. The rule is expected to be proposed by 2003, finalized by 2004 and implemented by 2008. At this time it is not known to what degree emissions of mercury in Minnesota would be impacted.

Fourth, because these different regulations are pro ceeding on separate tracks and timeframes, there are congressional proposals to address all of these issues, including greenhouse gas emissions in some proposals, through multi-pollutant legislation. Th e two main proposals include a Senate bill and the White House proposal (Clear Skies.) Both require different but substantial reductions in emissions over widely different timeframes. Both would likely require substantial emission reductions, at older power plants.

Next Steps Towards Reductions: Xcel Metropolitan Emissions Reduction Proposal

In 2001, the legislature responded to growing public concern over air pollution from existing electric generating plants by enacting Minn. Stat. §2168.1692, an emissions reduction rider that allows utilities to propose cost-effective pollution controls on existing plan ts, and receive recovery of the costs in their rates. On July 26, 2002, Xcel Energy submitted a proposal that would substantially reduce emissions from the King, Riverside and High Bridge plants, and recover costs in a proposed rate rider.

The MPCA has reviewed the Xcel proposal and is required by the statute to provide its analysis to the Public Utilities Commission (PUC) on:

1. Whether the project qualifies for the rider;

1 

### L.R. Chikin et. al. Preliminary Assessment of Ozone Air Quality in the Minneapolis/St. Paul Region. Sonoma Technology, Inc. October 2002.

2 

### T. R. Aulich and K. N. Neusen. Estimated Economic Impact of Twin Cities Ozone Nonattainment. Minnesota Chamber of Commerce, February 1999.

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2. The projected environmental benefits from the project; and 3. Its assessment of the appropriateness of the project.

The MPCA’s filing will initiate the decision-making process before the PUC. The PUC will ultimately decide on the reasonableness of the proposed emissions reduction rider. After the PUC makes its decision, Xcel Energy will decide whether to proceed with the projects, which are voluntary.



## Benefits of Re ducing Power Plant Emissions

Several studies have been conducted to estimate the economic and health benefits of reducing the emissions from power plants. Four of those studies are summarized below and in Table X.

EPA’s Clear Skies Initiative

The Bush Administration proposed the “Clear Skies Initiative” to reduce emissions from electric power generating utilities. Nationwide, the Clear Skies Initiative is estimated to reduce emissions of sulfur dioxide, nitrogen dioxides and mercury by 73%, 67%, and 69%, respectively from 2000 baseline levels.

The largest estimated benefits were related to the reduction of fine particle pollution primarily through the reduction in emissions of SO2 and NOx. As of 2020, the estimated national annual monetary benefit was $93 billion for 12,000 avoided premature deaths, follo wed next by $3. 2 billion for 7,400 fewer cases of chronic bronchitis. This estimate includes the assessment of the potential cumulative effect of long-term exposure to particles. EPA separately estimated the impacts of these pollutant reductions presuming that PM effects are limited to those that accumulate over much shorter time periods. This separate estimate concludes that nationally 7,400 early deaths would be avoided by reducing power plant emissions.

In Minnesota, EPA projected that a Clear Skies prog ram would reduce particulate matter levels across the state, and result in 100 fewer early deaths due to particulate matter effects. EPA further estimated that all health improvements combined result in $1 billion in benefits in Minnesota from Clear Skies. Because PM2.5 is a regional pollutant, benefits estimated in MN would be a result of emission reductions in MN and other states. 3



### Eight Utilities Study

Eight utility systems in the eastern half of the United States were the subject of a study to estimate the health impacts of the projected 2007 emis sions from their coal-fired power plants 4 5 

### . This assessment estimated that roughly 5,900 premature deaths might be avoided if emissions ceased from these plants. The study did not attempt to translate these deaths and othe r respiratory effects into economic terms. The study shows emissions from power plants in Illinois and Indiana contributing significantly to deaths in Missouri, Illinois, Indiana, Wisconsin and Minnesota.

Two Massachusetts Power Plants

3 

### Details of this cost study for the Clear Skies initiative are on EPA’s webpage at www.epa.gov/clearskies

4 

### Rockefeller Family Fund. Particulate-related Health Impacts of Eight Electric Utility Systems. April 2002. http://www.rffund.org/abt%20report%20FINAL.pdf

5 

### The year 2007 was chosen to allow for full implementation of two federal air pollution control requirements expected to affect power producers: the Acid Rain program and the EPA 1999 NOx SIP for the eastern half of the United States.

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Harvard researchers Levy and Spengler estimated a portion of the health benefits of reducing SO2 and NOx emissions from the Brayton Point and Salem Harbor coal-fired power plants in Massachusetts 6 

### . Their analysis compared current emissions with emission rates estimated under best available control technology (BACT), which results in decreases of 57,348 tons of SO2 and 11,074 tons of NOx per year from the two plants. This study estimates that this reduction in SO2 and NOx would reduce 70 premature deaths each year over a total population of 33 million. Levy cautio ned that while it should be considered illustrative, using standard EPA valuation for premature death, these avoided deaths represents a $400 million benefit per year. This study only looked at death and did not address other health problems that these emissions cause or contribute to.

Minnesota Power Plants

Nelson estimated the public health impacts of particulate emissions from current coal-fired power plants in Minnesota, and the impacts if these plants switched from burning coal to burning natural gas. 7 

### The study concluded that by switching from coal to natural gas at Minnesota’s electric utility boilers, 25 early deaths would be avoided. Other health improvements were also estimated, and include fewer new cases of bronchitis, emergency room visits, days of respiratory symptoms, and days of restricted activity. This study calculated that the economic benefit from switching to natural gas to reduce emissions from these power plants is $187 millio n per year (1996 dollars).

This study recognizes that using high stacks at power plants to disperse pollutants means that much of the damages from the emissions occur outside Minnesota. However, Xcel’s Riverside plant was estimated to have the highest incident of early deaths (7) due to it being located within a heavily populated area.

Table X. Comparison of Benefits wh en power plant emissions are reduced.

Benefit Assessment Annual Benefits Avoided Deaths NOx reductions SO2 Reductions $/yr Tons/yr Tons/yr

Clear Skies (nationally) $93 billion 12,000 5,000,000 2,500,000

Clear Skies in Minnesota $1 billion 100 91,000 17,000

Eight Utilities Not calculated 5,900 Not provided Not provided Minnesota Utilities $187 million 25 53,700 57,000 Two MA Power Plants $400 million 70 11, 000 57,000



## Reducing Emissions from Small Electrical Generators

Background

Small stationary generators are used for emergency power and to an increasing extent, in distributed generation applications. Emergency generators are used to replace grid power when weather or some other action interrupts the distribution of power, and are typically used on situations where human life and public

6 

### Levy and Spengler. Modeling the Benefits of Power Plant Emission Controls in Massachusetts”. Journal of Air and Waste Management Association 52:5-18.

7 

### Nelson, C.D. 2000. The Public Health Impacts of Particulate Emissions from Coal-fired Power Plants in Minnesota. Thesis. Master of Science. University of Minnesota.

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safety are a concern. Distributed generation is gene rally grid connected and displaces energy that would otherwise be generated by large centralized power plants. Distributed generation can benefit a generation system through increased reliability, lower transm ission line losses and lower peak demand from centralized generators. The increased use of emergenc y and distributed generators (EDG) raises concerns for local health effects and exacerbation of the metr opolitan ozone problem, particularly since EDGs are most likely to be used in the summer on days when ozone levels may be high. In Minnesota there are easily more than a thousand small electric generators in place, ranging from emergency generators at hospitals, manufacturing facilities and commercial real estate, to peak shaving generators in a variety of locations with interruptible service contracts.

Small fossil-fueled generators typically have low exhaust stacks and can be located near sensitive populations. As can be seen from the following figures, diesel engines have much higher emission rates for nitrogen oxides (NOx) and particulate matter than othe r forms of electrical generation. Most concerns for the direct health impacts of EDG therefore center on diesel powered equipment. California has identified diesel particulate as a carcinogen, and has begun a program to clean up mobile and stationary diesel engines. EPA has established a health based standard for fine particles, and is in the process of reviewing the fine particle standard in light of new evidence of mortality effects at lower ambient levels than previously thought to have effects. NOx can ca use respiratory effects in high concentrations.

High levels of ozone occur in the Twin Cities area on hot sunny summer days. The demand for peak shaving generation also tends to be highest on hot summer days. The pollutants generated by diesel and other generators will contribute to ozone formation at downwind locations.

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Source: reference ____ SCR stands for selective catalytic reduction, a technology for reducing NOx emissions The last three bars in each chart refer to the emissions from the generation of electricity in the U.S. from burning coal, all fossil fuel combustion and from all forms of generation.

EPA has not established emission standards for NOx and particulate emissions from small stationary EDG. EPA is in the process of developing standards for air toxics emissions from reciprocating internal combustion engines. However, it is not anticipated that particulate and NOx emissions will be substantially reduced through the air toxics standard because partic ulate and NOx are regulated by a different section of the Clean Air Act.

Principles for Regulation

In anticipation of the growth of EDG, measures should be taken to insure that public health is protected. Emission standards should be developed to insure that new or even existing generators are cleaner. Several principles could guide development of these measures:

New generation should be at least as clean as current centralized power stations

Standards for similar engines in other uses (on and off- road mobile sources) should be a starting point

Minnesota should remove incentives for grid connection of high pollution technology (Commerce should have input here _________)

Regulatory Developmen ts in Other States

At least three models are available for regulation of EDG emissions. The Regulatory Assistance Project (RAP), a Vermont/Maine non-profit, coordinated the development of model rules for small generators. The workgroup that developed the rules consisted of utility and environmental regulators and industry representatives.

The Vermont/Maine model RAP rules:

Affect all types of small generators

Are more stringent for higher use generators

Tighten emission limits over time

Are based on EPA non-road emission standards

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The model rules were released in August of 2002. RAP staff anticipate that Connecticut and Massachusetts will be the first states to adopt the model rules.

California is developing toxic control measure rules for new stationary diesel engines and existing diesel engines over 50 horsepower. These rules include limits for NOx emissions.

California’s proposed rules:

Are more stringent for higher use engines

Are based on best available technology

Assume availability of very low sulfur fuel as will be required by EPA regulations

Apply to owners or operators

Exempt agricultural uses

Establish compliance dates for existing engines in 2005-2007

California Air Resources Board (CARB) staff anticipate that the rulemaking will be completed in the first half of 2003. Once completed, the rules could form the basis for nationwide regulation of emissions from stationary diesel engines. Manufacturers will build equipment and retrofits for the large California market. Due to economies of scale, other states could adopt similar restrictions at relatively low cost.

Finally, in 2001, Texas adopted permitting requirements regulating NOx from new small generating units. The standards vary by location and are phased in over four years.

Voluntary Approaches

The amount of particulate matter emitted by a diesel engine without a particulate trap is directly proportionate to the sulfur content of the fuel. According to EPA regulations, low sulfur (<15ppm) diesel fuel must be used in on-road diesel engines by 2006. It is also likely that low sulfur diesel fuel will be required for non-road mobile sources once concerns about adequate fuel supply have been resolved. A limited amount of low sulfur diesel fuel is available now in the Twin Cities. A voluntary effort could be mounted to expand this supply and channel some to stationary engines.

Retrofit devices are available for some diesel engines to remove particulate emissions. They work best when paired with low sulfur fuel. Retrofit campaigns for school buses and other mobile sources have been successfully completed in various locations across the country. The feasibility of a program to retrofit the larger diesel generators could be investigated. Retrofit costs should fall within the $2,000 to $8,000 range.

Finally, the use of biodiesel fuel can reduce emissions of particulates and organic compounds from generators. The higher the percentage of bio-to-die sel concentration, the greater the emissions benefit. Biodiesel fuel is becoming more available in Minnesot a and could be a part of a voluntary effort to reduce emissions. A new state law requires 2 percent biodiesel in diesel fuel beginning in June 30, 2005.