TDD (for hearing and speech impaired only): (651) 282-5332 

Printed on recycled paper containing 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 stacks 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 modify 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 requirements 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 air 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, compliance 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 specifying compliance practices for applicable requirements, 

any person (including the Permittee) may also use other 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 handling 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 equipment on the main boiler as of the date of issuance of 

Air Emission Permit No. 16300005-005 consists of an electrostatic precipitator to control Particulate Matter (PM) 

emissions. Emissions from fuel and ash storage and handling 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 Plant. The Rehabilitation Project is currently underway 

and includes the installation of new pollution control equipment, 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 burners and re-entrant throats. 

• Replace furnace sidewalls and furnace floor tubes. 

• Installation of induced draft fans to accommodate additional draft requirements of new control equipment. 

The new (additional) control equipment will consist of: 

• Selective Catalytic Reduction (SCR) reactor for control of NOX emissions. 

• Spray dryer absorber lime-based semi-dry Flue Gas Desulfurization (FGD) system for control of SO2

emissions 

• Pulse-Jet cleaned Fabric Filter (PJFF) for additional control of PM. 

The rehabilitation project authorized by permit action 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 refer to the first firing with permitted fuels other 

than natural gas. The definition of startup 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 the 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 regulation since the issuance of the initial permit. 

7. Changes to Ash Silo – The permit will be updated to acknowledge that the fly-ash silo (EU 012) 

now has a dedicated fabric filter (CE 026) and 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 operation 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 column of

the table (What To do). The limits can be emission limits or operational limits. This column also contains the actions that you 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 total 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

Any 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

Air 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

ATPA 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.

At 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.

At 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)

Application 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

Air 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

Air 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

Allowable 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

Air 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

August 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

August 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

Access 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

Air 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

Air 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

Average

Minn. R. 7009.0020

(This is a state only requirement and is not enforceable

by the EPA Administrator and citizens under the Clean

Air 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

Allowed 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

Alternative 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#

Allen 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

Apply 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)

Allowable 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)

Allowable 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

Any 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.

Any 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

At 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

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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

Administrator 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

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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

Administrator'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

Administrator (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.

An 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

Any 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

Ammonia 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

After 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

B-1 02/27/07

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 separately 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 parts

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

B-2 02/27/07

What to send When to send Portion of Facility Affected

Application 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

B-3 02/27/07

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

B-4 02/27/07

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 ∑ [ ]

=

=

= × ×

j coke, coal, natural gas,fuel oil

i EU 001, EU 028

i, j i, j

2000 lb

1 ton VOC(tpy) EF HI

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 emission unit and each fuel (lb VOC/mmBtu heat input) 

HI = 12-month rolling sum heat input for each fuel (mmBtu) 
APPENDIX C PM10 Modeling Parameters 

Facility Name: Xcel Energy - Allen S. King Generating Plant Permit Number: 16300005-006 

PM10 Modeling Parameters 

The following stack and emission parameters were used in the modeling analysis submitted August 16, 2004. Revision of 

must result in plume dispersion characteristics equivalent to or better than the plume dispersion characteristics modeled a

model submitted August 16, 2004. Revision of any of these parameters may require a major amendme

SV 

ID 

No. 

Source Description Modeled 

Height 

(feet) 

Modeled 

Diameter 1

(feet) 

Stack Exit 

Velocity 

(feet/sec) 

Direction 

of 

Flow 

Modeled 

Temperature 

(°F) 

24

M

PM

001 Main Boiler 785.1 18.5 95.5 Vertical 169 003 Coal Gallery 145 3.4 51.5 Vertical 70 004 Transfer House 1 21.3 2.5 78.1 Vertical 70 005 Coal Crusher House 76.4 3.28 45.3 Vertical 70 006 Railcar Unloading 32.8 3 163.4 Vertical 70 007 Railcar Unloading 32.8 3 163.4 Vertical 70 008 Boiler 11 40.0 4 91.5 Vertical 525 009 Boiler 12 27.9 3 41.0 Vertical 550 011 Transfer House 2 26.6 2.7 47.9 Vertical 70 012 Transfer House 5 15.7 2.7 54.5 Vertical 70 013 Emergency Generator 40.0 1.3 169.3 Vertical 891 014 Emergency Generator 40.0 1.3 169.3 Vertical 891 017 Boiler 13 27.9 3 41.0 Vertical 550 018 Flite Conveyors 104.0 3.3 31.5 Vertical 70 020 Emergency Generator 14.1 0.3 0.003 Horizontal 1150 023 Emergency Generator 11.1 0.3 377 Vertical 936 024 Propane Vaporizer 1 6.9 1 11.5 Vertical 550 025 Propane Vaporizer 2 6.9 1 11.5 Vertical 550 026 Radio System Emergency 

Generator 

14.1 0.3 0 Horizontal 1150 

028 Fire Pump Engine 16.1 0.3 293.3 Vertical 855 029 Lime Day Bin 68 3.3 0.003 Horizontal 70 
SV 

ID 

No. 

Source Description Modeled 

Height 

(feet) 

Modeled 

Diameter 1

(feet) 

Stack Exit 

Velocity 

(feet/sec) 

Direction 

of 

Flow 

Modeled 

Temperature 

(°F) 

24

M

PM

030 Lime Storage Silo 118 3.3 0.003 Horizontal 70 031 Byproduct/Fly Ash Storage 123.0 3 0.003 Horizontal 70 032 Byproduct/Fly Ash Storage 115 3 0.003 Horizontal 70 033 Byproduct/Fly Ash Transfer 50 1.6 0.003 Horizontal 70 034 Byproduct/Fly Ash Transfer 50 1.6 0.003 Horizontal 70 035 Byproduct/Fly Ash Transfer 50 1.6 53.8 Vertical 70 036 Fly Ash Silo 105.8 1.46 0.003 Horizontal 283 

FS016 Cooling Tower 11 60.3 35.8 20.3 Vertical 70 FS016 Cooling Tower 12 60.3 35.8 20.3 Vertical 70 FS016 Cooling Tower 13 60.3 35.8 20.3 Vertical 70 FS016 Cooling Tower 14 60.3 35.8 20.3 Vertical 70 FS017 Cooling Tower 15 67.3 32.2 25.3 Vertical 70 

FS017 Cooling Tower 16 67.3 32.2 25.3 Vertical 70 FS017 Cooling Tower 17 67.3 32.2 25.3 Vertical 70 FS017 Cooling Tower 18 67.3 32.2 25.3 Vertical 70 FS017 Cooling Tower 19 67.3 32.2 25.3 Vertical 70 FS017 Cooling Tower 20 67.3 32.2 25.3 Vertical 70 FS017 Cooling Tower 21 67.3 32.2 25.3 Vertical 70 FS017 Cooling Tower 22 67.3 32.2 25.3 Vertical 70 FS017 Cooling Tower 23 67.3 32.2 25.3 Vertical 70 FS017 Cooling Tower 24 67.3 32.2 25.3 Vertical 70 FS017 Cooling Tower 25 67.3 32.2 25.3 Vertical 70 FS017 Cooling Tower 26 67.3 32.2 25.3 Vertical 70 FS017 Cooling Tower 27 67.3 32.2 25.3 Vertical 70 FS017 Cooling Tower 28 67.3 32.2 25.3 Vertical 70 FS017 Cooling Tower 29 67.3 32.2 25.3 Vertical 70 FS017 Cooling Tower 30 67.3 32.2 25.3 Vertical 70 FS017 Cooling Tower 31 67.3 32.2 25.3 Vertical 70 FS017 Cooling Tower 32 67.3 32.2 25.3 Vertical 70 1 If the stack is not round (i.e., it is rectangular), this is the equivalent diameter used 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 stationary 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 pollutant-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 stationary 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 (PM10) 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: 16300005-006 
United States 

Environmental Protection Agency OMB No. 2060-0258

Acid Rain Program 

Phase II NOX 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 boiler 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 vertically fired, and“WB” for wet bottom. Indicate 

the compliance option selected for each unit.

ID# 1 ID# ID# ID# ID# ID# 

Type CY Type Type Type Type Type 

(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) NOx Averaging Plan (include NOx 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 NOx

Averaging (check the NOx

Averaging Plan box and include 

NOx Averaging form)

     
 Allen S. King 

Plant Name (from Step 1) 

NOx Compliance - Page 2

Page 2of 12

 STEP 2, cont’d. 

ID# ID# ID# ID# ID# ID# 

Type Type Type Type Type Type 

(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 this 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 subject to an emissions 

limitation for NOx 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 takes effect. If the designated representative of the unit under 

an approved early election plan fails to demonstrate compliance 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 terminate 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 plan. The designated representative of the unit under an 

approved early election plan may terminate the plan any year prior to 2008 but may not submit a new early election 

plan. In order to terminate the plan, the designated representative 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 NOx 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 termination, the applicable emissions limitation for NOx 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 this document and all its attachments. Based on my inquiry 

of those individuals with primary responsibility for obtaining 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 submitting false statements and information or omitting required statements and information, 

including the possibility of fine or imprisonment. 

Name Gary D. Hudson

Signature Date 6/21/02
 

United States 

Environmental Protection Agency OMB No. 2060-0258

Acid Rain Program 

Phase II NOX 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

( R x HI )

i

n

i=1

Li i

n

i=1

∑

∑

≤

HI

[ R x HI ]

i

n

i=1

li i

n

i=1

∑

∑

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, 

RL i = Alternative contemporaneous annual emission limitation for unit i, in lb/mmBtu, as specified in column (b) of Step 1: Rl i = Applicable emission limitation for unit i, in lb/mmBtu, as specified in column (a) of Step 1; Hl i

 = Annual heat input for unit i, in mmBtu, as specified in column (c) of Step 1; 

 n = Number of units in the averaging plan 

Plant Name (from Step 1) Allen S. King NOx Averaging - Page 2
STEP 3

Mark one of 

the two options 

and enter dates.

 This plan is effective for calendar year ___2002______through calendar year __2006___ 

 unless notification 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 notification 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 NOx under the plan only if the following requirements are met: 

(i) For each unit, the unit's actual annual average emission rate for the calendar year, in lb/mmBtu, is 

less than or equal to its alternative contemporaneous annual emission limitation in the averaging plan, 

and 

(a) For each unit with an alternative contemporaneous 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 contemporaneous 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 requirements of (i), the designated representative 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 the 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 compliance 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 contemporaneous 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 section at that unit or any other unit in the plan, including liability for fulfilling 

the obligations specified in part 77 of this chapter and sections 113 and 411 of the Act. 

Termination

The designated representative may submit a notification to terminate 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, the statements and information submitted in this document and all its 

attachments. Based on my inquiry of those individuals with primary responsibility for obtaining 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 submitting false 

statements and information or omitting required statements and information, including the possibility of 

fine or imprisonment. 

Name Gary D. Hudson 

Signature Date 6/21/02 

 

Plant Name (from Step 1) Allen S. King NOx Averaging - 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 4324500 
Riverside 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 source and each affected unit at the source shall: 

(i) Submit a complete Acid Rain permit application (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 information that the permitting authority determines is 

necessary in order to review an Acid Rain permit 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 applicable, designated representative of each affected 

source and each affected unit at the source shall comply 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 affect the responsibility of the owners and operators to 

monitor emissions of other pollutants or other emissions characteristics 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 transfer deadline, in the unit's compliance subaccount (after 

deductions under 40 CFR 73.34(c)), or in the compliance 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 emitted in excess of the Acid Rain emissions limitations for sulfur dioxide 

shall constitute a separate violation of the Act. 

(3) An affected unit shall be subject to the requirements 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 the 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 calendar 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 permit, or an exemption under 40 CFR 72.7 or 72.8 and no 

provision of law shall be construed to limit the authority 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 offset plan, as required by 40 CFR part 77. 

Recordkeeping and Reporting Requirements

(1) Unless otherwise provided, the owners and operators of the source and each affected unit at the 

source shall keep on site at the source each of the following documents for a period of 5 years from the 

date the document is created. This period may be extended for cause, at any time prior to the end of 5 

years, in writing by the Administrator or permitting 

authority: 

(i) The certificate of representation for the designated representative for the source and each affected 

unit at the source and all documents that demonstrate the truth of the statements in the certificate of 

representation, in accordance with 40 CFR 72.24; provided that the certificate 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 certificate of representation changing the designated 

representative; 

(ii) All emissions monitoring information, in accordance 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 certifications, 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 demonstrate 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 requirement or prohibition of the Acid Rain Program, a 

complete Acid Rain permit application, an Acid Rain permit, or an exemption under 40 CFR 72.7 or 72.8, 

including any requirement for the payment of any penalty owed to the United 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 criminal enforcement pursuant to section 113(c) of the 

Act and 18 U.S.C. 1001. 

(3) No permit revision shall excuse any violation of the 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 affected 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 affected 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 (NOx averaging plans), and except with regard to the requirements applicable to units 

with a common stack under 40 CFR part 75 (including 40 CFR 75.16, 75.17, and 75.18), the owners and 

operators and the designated representative of one affected unit shall not be liable for any violation by 

any other affected unit of which they are not owners or operators or the designated representative and 

that is located at a source of which they are not owners or operators or the 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 excluding the owners and operators 

and, to the extent applicable, the designated representative of an affected source or affected unit from 

compliance with any other provision of the Act, including the provisions of title I of the Act relating to 

applicable National Ambient Air Quality Standards 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 regulating electric utility rates and charges, affecting 

any State law regarding such State regulation, or limiting such State regulation, including any prudence 

review requirements under such State law; 

(4) Modifying the Federal Power Act or affecting the authority of the Federal Energy Regulatory 

Commission under the Federal Power Act; or, 

(5) Interfering with or impairing any program for competitive 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 information submitted in this document and all its 

attachments. Based on my inquiry of those individuals with primary responsibility for obtaining 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 submitting false statements 

and information or omitting required statements and information, 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 all 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 provide the legal and factual justification for each 

applicable requirement or policy decision considered 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 located on Highway 95 & Point Rd. in Oak Park Heights, 

Minnesota. The facility’s emission sources consist of boilers; fuel and ash storage and handling 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 equipment on the main boiler as of the 

date of issuance of Air Emission Permit No. 16300005-005 consists of an electrostatic precipitator to control 

Particulate Matter (PM) emissions. Emissions from fuel and ash storage and handling 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 Plant. The Rehabilitation Project is currently underway 

and includes the installation of new pollution control equipment, 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 burners and re-entrant throats. 

• Replace furnace sidewalls and furnace floor tubes. 

• Installation of induced draft fans to accommodate additional draft requirements of new control equipment. 

The new (additional) control equipment will consist of: 

• Selective Catalytic Reduction (SCR) reactor for control of NOX emissions. 

• Spray dryer absorber lime-based semi-dry Flue Gas Desulfurization (FGD) system for control of SO2

emissions 

• Pulse-Jet cleaned Fabric Filter (PJFF) for additional control of PM. 

The rehabilitation project authorized by permit action 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 refer 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 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 the 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 filter, are operated after the first firing of the boiler 

with fuels other than natural gas following the rehabilitation 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 Mechanical 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 regulation since the issuance of the initial permit. 

7. Changes to Ash Silo – The permit will be updated to acknowledge that the fly-ash silo (EU 012) 

now has a dedicated fabric filter (CE 026) and 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 operation 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 contains 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 PM10 SO2 NOx 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 PM10 = PM smaller than 10 microns 

 SO2 = Sulfur Dioxide NOx = 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 Source 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 Boilers and Process Heaters (Industrial Boiler) Maximum Achievable 

Control Technology (MACT) standard. The Industrial 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 SO2 and NOx provisions of Title IV of the 

Clean Air Act. The King plant will continue to be allocated SO2 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 NOX 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 the SCR, SDA and fabric filter are in service at all 

times that EU 001 is in operation. Since the permit allows a 270 day period for commissioning, following 

the rehabilitation project, to meet the new emission limits for NOx and SO2 the permit has been amended 

to not require operation of the control equipment until 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, temperature, slag ‘freezing’ temperature, etc) of the King 

Plant supercritical cyclone fire boiler are such that EU 001 cannot sustain operation below approximately 

250 MW. 

CEMS for NOx and SO2 will continuously monitor emission rates so that on-going compliance with the 

limits can be demonstrated. CEMS will also monitor the emission rates during startup and shutdown 

operation below 250 MW. 

Mercury Monitoring and Testing – Xcel Energy will be operating a continuous emissions monitor to 

measure mercury emissions from EU 001 as a requirement of the Minnesota Mercury Reduction Act of 

2006. Permit conditions for the operation of the CEM have 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 NOx and SO2 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 conditions 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 Guidance 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 system will not automatically generate the necessary 

enforcement notices or documents. Staff must generate these. 

In addition, the Industrial Boiler MACT standard dictates a hydrogen chloride limit, which will be applicable 

to EU 028 upon startup. Delta does not offer “hydrogen chloride” as a drop-down option for pollutants, but 

instead offers “hydrochloric acid.” Since hydrogen chloride and hydrochloric acid are the same chemical 

(CAS number 7647-01-0), hydrochloric acid is listed 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 the 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 changes required, permit amendment required will be 

dictated by state rules. Response letter is in Delta. 

EPA 45-day Review Period: January 10, 2007 – February 23, 2007 

No comments received from EPA 

4. Conclusion

Based on the information provided by Xcel Energy – Allen S. King Generating, the MPCA has 

reasonable assurance that the proposed operation of the emission facility, as described in the Air Emission 

Permit No. 16300005-007 and this TSD, will not cause or contribute 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 more information about the preparation of this

report, as well as other questions 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 Introduction.........................................................................................................1

2.0 Summary ..............................................................................................................3

2.1 Qualifying Projects.................................................................................................3

2.2 Project Costs .........................................................................................................3

2.3 Projected Environmental Benefits..........................................................................4

2.4 Appropriateness of the Project...............................................................................5

3.0 Qualifying Projects ..............................................................................................6

3.1 Minn. Stat. § 216B.1692 Subd. 1. Qualifying Projects..........................................6

3.1.1 New Source Review....................................................................................7

3.1.2 New Source Performance Standards ....................................................................8

3.2 Do the Projects Qualify 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 the Proposal............................................................18

5.1 Method of Analysis ................................................................................................18

5.2 Assessment of A.S. King Costs .............................................................................18

5.3 Assessment of High Bridge Estimated Costs.........................................................21

5.4 Assessment of Riverside Estimated Costs.............................................................23

5.5 Summary...............................................................................................................24

6.0 Impacts of Power Plant Emissions.....................................................................25

6.1 Contribution of Power Plants to Air Pollution in Minnesota....................................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 PM2.5 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 Climate 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 Estimates of the Proposal......................................................................35

7.2 Xcel Energy’s Estimates of the Environmental Benefits from MERP.....................36

7.3 Avoided Costs ......................................................................................................38

7.4 MPCA Estimate of Projected Environmental Benefits ...........................................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 Benefits of Controlling Power Plant Emissions ...42

7.5.1 The Benefits Assessment Methodology.............................................................42

7.5.2 EPA’s Clear Skies Initiative................................................................................43

7.5.3 Eight Utilities Study ............................................................................................44

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

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

7.6 Conclusions on the Estimation of Quantifiable Benefit...........................................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 Benefits ................................................................................................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 Company d/b/a Xcel Energy (Xcel) submitted an

emission reduction proposal, the Metropolitan Emission Reduction 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 increase 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 (SO2) and nitrogen oxides (NOx) 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

SO2 NOX PM10 CO2 CO Lead Mercury

Current annual

emissions from these

three plants (in tons

per year)

34,178 24,206 954 6,545,727 860 2662 2322

Emissions change

(in tons per year) -31,880 -22,017 -667.1 -319,865 +80 -602 -1782

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 reduction 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 the 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 environmental benefits of the proposed project; and

 The MPCA’s assessment of the appropriateness of the proposed MERP project.

In addition to answering the above questions in this 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 project 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 projected the environmental benefits from the

implementation of this project, and has generally assessed the costs 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 technology” 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 MPCA has met its statutory requirement 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 effective 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 proposal 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 the 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 that it is appropriate as

described by Minn. Stat. §216B.1692, subd. 5(b)(4).

Further, the MPCA has reviewed the proposal for each plant, and has determined that the project

is not needed to comply with new state or federal 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 benefits of this proposal, project costs were reviewed

to determine if they were within a reasonable range. This project involves essentially three

different types of construction/rehabilitation: 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 plant to combust gas instead of coal, and requires

replacing portions, but not all, of the power producing equipment onsite. High Bridge is the

construction of a new gas-fired generating 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 appears 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 reconstruction 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 plants contribute significantly to total overall

emissions of sulfur dioxide (SO2) to Minnesota’s air — the three plants alone represent almost

half of SO2 released by electric utilities in the state, and nearly a quarter of SO2 emissions

overall. The plants also are emitting sizable amounts of NOx and mercury in Minnesota. The

proposed project reduces SO2 emissions from these plants by 93 percent, NOx by 91 percent, and

mercury by 76 percent.

Reductions in SO2 and mercury will aid in continued improvements to Minnesota and the

nation’s water bodies. Evidence is showing that further SO2 reductions are still needed to

reverse ecological damage of acid rain. SO2 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. This proposal would reduce contributions of both SO2

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

environment.

Fine particulates strongly correlate with increased health problems, including early death from

cardiopulmonary disease and lung cancer. Researchers 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 ambient standard for fine particles, PM2.5, 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 Minnesota, and Minnesotans are

suffering impaired health effects from fine particulates.

Because SO2 and NOx 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 well as several others, measured health benefits

when power plants’ SO2 and NOx emissions are reduced. One such study evaluating emissions

of coal-fired power plants in Minnesota finds that with reductions of the magnitude offered by

this proposal, the net present value of health benefits in Minnesota could 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 shows PUC externality-based benefits of the MERP

project to be $200 to $500 million (in 2001 dollars). Even this conservative treatment of the

benefits of this emission reduction proposal shows benefits greater 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, regional 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 avoided costs related to the construction of an

additional 385 MW over the original generating capacity at the three plants has a net present

value of about $700 million. The MPCA concurs that there is real value to this generating

capacity that is not reflected in the construction 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 range) 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 are not directly quantifiable, many of which are

described in this report. The proposal addresses multiple issues related to power plant emissions

— reduction of PM2.5 forming pollutants, reduction in mercury emissions, improved efficiency in

generating electricity that is necessary to address 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 emission proposal is an important project to achieve improvements

in many of these environmental problems, and that benefits of the project 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 SO2, NOX and PM10 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, located near the Mississippi River in downtown, Xcel

proposes to replace the existing coal-fired plant (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 technology decreases emissions of SO2, NOX, PM10 and CO2,

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

Riverside

 In northeast Minneapolis, Xcel proposes to convert 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 natural gas drastically decreases emissions of SO2,

NOX, PM10 and CO2, 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. This section first describes how the MPCA

considered the statutory requirements, 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 generating power plants as defined under Minn. Stat. §

216B.2421 subd. 2(1), that are located in the state 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

page 7

2) not increase capacity by more than 10 percent 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 review 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 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).

3.1.1 New Source Review

New Source Review (NSR) is a federally mandated air quality program that was established in

the 1977 Clean Air Act Amendments. It is designed to improve the quality of the air in areas

that have poor quality air. These are called “nonattainment” 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 triggered by the construction of new equipment 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 assessed; the best performing technology is selected as LAER, since

the review includes no assessment of the cost.

In attainment areas, NSR requires the application of the Best 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 factors 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.”
MPCA Review of MERP Proposal

page 8

For the economic assessment, EPA guidance insists on a “top-down” review of the available

emission-reducing technologies. The first (or “top”) 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 selection of BACT as the best-performing technology

that is determined to be cost-effective. Technologies can be eliminated from selection if they are

not technically feasible or if associated energy or environmental effects outweigh the emission

reduction benefits.

The Twin Cities metropolitan area is currently classified 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 comply 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 Clearinghouse (RBLC) and from other sources.4

The EPA operates the RBLC, a database that records 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 authorities 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 (SO2,

NOX, and PM10) 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 constructed 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 NSR 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 CO2, mercury or PM2.5.
MPCA Review of MERP Proposal

page 9

explained in the next section, the proposed project 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 state 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. Croix River and has a net

generating capacity of 504 MW. It meets the definition 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 project meets this requirement.

Does the project propose “best available control technology”?

Table 2 on the following page shows the current emission rates at the King plant and the

emission rates that would result from Xcel’s proposed 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).
MPCA Review of MERP Proposal

page 10

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 NOx SO2 PM10

MW mmbtu/hr Lb/mmBtu Lb/mmBtu Lb/mmBtu

Current King emissions 504 5,205 0.71 1.39 0.019

New Source

Performance Standards8 0.60 9 1.210 0.0311

Recent Best Available Control Technology determinations for coal-fired facilities12

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 NOx 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 SO2, or a minimum reduction of 70 percent if controlled

emissions are below 0.6 lb/mmBtu.

11 The NSPS restricts emissions of PM (not PM10) 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 NOx were based on coal-fired cyclone

boilers, while the values for SO2 and PM10 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.
MPCA Review of MERP Proposal

page 11

achieves BACT-like control levels for coal-fired cyclone boilers, the project qualifies under this

requirement.

Summary

The A.S. King proposal meets all three conditions 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 state and not subject to emission limitations

for new power plants under the federal Clean Air Act?

The High Bridge plant is located between Shepard Road and the Mississippi River in downtown

St. Paul. It has four boiler units, 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 generating 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 retire and demolish the current coal-fired plant, stack

and related coal-handling equipment, and replace 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 “best 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.
MPCA Review of MERP Proposal

page 12

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 NOx SO2 PM10

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 Standards14 0.20 15 0.20 0.0316

Recent Best Available Control Technology determinations for natural gas-fired facilities17

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 control levels, the project meets this requirement.

In addition, the emissions for this proposed plant 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 PM10) 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 SO2 and PM10 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

page 13

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 the statute. The MPCA concludes that the

proposed emission reduction project up to the first 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 economics 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 overall 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 state and not subject to emission limitations

for new power plants under the federal Clean Air Act?

The Riverside Plant is located on the east bank of the Mississippi River north of downtown

Minneapolis. It has three power boilers.

Boilers 6 and 7 were initially constructed in 1946 and 1948 respectively. 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 were 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 the 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 below the limit of 100 MW (the maximum increase

allowed under the statute), and thus meets this requirement.
MPCA Review of MERP Proposal

page 14

Does the project propose “best available control technology”?

Table 4 shows the current emission rates at the Riverside 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 NOx SO2 PM10

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

Standards19 0.20 20 0.20 0.0321

Recent Best Available Control Technology determinations for natural gas-fired facilities22

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 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.)

21 The NSPS restricts emissions of PM (not PM10) 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 SO2 and PM10 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

page 15

It is reasonable to expect a slightly higher emission rate at the Riverside plant than at High

Bridge because the project involves integrating 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 NOx emissions rate

might have been expected to be slightly lower.

However, the proposed NOx emissions rate appears to be well within the range at which new

combined cycle facilities that install BACT are expected to perform. Thus the proposal achieves

a level of control reflecting the application of BACT and exceeds the applicable NSPS. Because

the proposal achieves BACT, the project meets this requirement.

Summary

The Riverside proposal meets all the conditions of Minn. Stat. § 216B.1692, subd. 1, thus is a

qualifying project under the statute.
MPCA Review of MERP Proposal

page 16

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 questions 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 the discussion regarding this in Section 6.)

In addition, through ambient monitoring and/or dispersion modeling, the MPCA has

determined that these projects are not required to meet any ambient air quality

standards. Although there are several potential regulatory developments that may

impose more limits on these plants, none are yet in effect.24

2. None of the proposed projects are currently required as a corrective action as part of

any state or federal enforcement action.

A potential enforcement action involves changes to the King plant’s coal handling

equipment that the MPCA believes 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/PM10 from coal handling, and has

conducted a monitoring analysis of the ambient 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 issued 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)
MPCA Review of MERP Proposal

page 17

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.
MPCA Review of MERP Proposal

page 18

5.0 Estimated Capital Cost of the Proposal

The MPCA analyzed the cost of the proposed project 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 construction 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) determinations 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 technologies. 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, final project costs may be 30 percent higher or lower than the

budgetary estimate.

Xcel proposes a cost-recovery process that allows 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

NOx 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 description 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

page 19

The first set of cost information available to compare to Xcel’s estimates comes from actual

retrofits of flue gas desulfurization controls and NOx 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 NOx State Implementation

Plan call for NOx 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 developed 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 adding flue gas desulfurization is about $195/kW in

1997 dollars, or about $215/kW in 2001 dollars. NOx controls, specifically SCR for high NOx

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 fabric 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 air pollution control equipment at power plants.

The workbook has been used by permitting authorities 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 estimated SD/FF construction

costs within +/- 15 percent of the published capital 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 reconstruction (retrofit factors), with expected

inflation of three percent per year.

CUECost estimates a total capital cost for an air 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 NOx 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 NOx controls to make the reductions expected of them.
MPCA Review of MERP Proposal

page 20

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

NOx 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

NOx 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

NOx 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 separately reports costs to control NOx and SO2 (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, significantly 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, SCR 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 at the 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 reports 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 requires the construction of combined cycle/steam generators and

transmission capacity, and demolition of the existing four boilers.

Air pollution control benefits result from changing the fuel choice and combustion technology.

Because changing combustion technology inherently results in pollution reductions, it is difficult

to separate project costs between electricity generation 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.
MPCA Review of MERP Proposal

page 22

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 cycle27

607

No advanced combined-cycle project has been installed in Minnesota that allows direct

comparison. The MPCA identified two natural gas-fired simple cycle turbine projects

constructed in Minnesota of similar size to the High Bridge proposal. The PUC gave approval in

1999 and 2000 to construct two generating stations: Lakefield Junction and Pleasant Valley.

The Lakefield Junction project involved construction of a turbine/generation facility producing

515 MW. The project also included upgrading existing 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 constructing 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 simple 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 projected construction cost for the simple-cycle generating station to

determine how accurate an approximation the EIA values are to costs experienced in Minnesota.

Adjusting for inflation, the Lakefield Junction project was within 12 percent of the installed cost

estimated by EIA (EIA 2002). Because the Pleasant Valley construction 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

page 23

EIA predicts new “greenfield” advanced combustion 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 falling29.

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 and reconstruction at an existing power plant site. Xcel has

included a certain number of cost factors that relate to expecting “unforeseen” site conditions.

Redevelopment of previously developed sites — “brownfield” construction — often requires

some unique work to conform the site 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 gas 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 considerably more generating

 

28 “Greenfield” means construction at an undeveloped site (literally, 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

page 24

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. The 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 appears 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 reconstruction 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.
MPCA Review of MERP Proposal

page 25

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 (SO2) emissions, 16 percent of total nitrogen

oxides (NOX) emissions, 35 percent of carbon dioxide (CO2, a greenhouse gas), 43 percent of

mercury emissions and between 10 and 60 percent of other metals emissions.

Power plants are also a large contributor to fine particulate levels (PM2.5) in Minnesota’s air.

The emissions of SO2 and NOx are converted through atmospheric reactions to create fine

particulate. Power plants also directly emit particles, regulated as “PM10,” that is, particles with

a diameter of 10 microns and less.

A detailed analysis of the emissions from Minnesota’s power plants can be found on pages 93 –

98 of Attachment 2 (the environmental analysis 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, 200030

SO2 tpy NOX tpy PM10 tpy Mercury lb/yr CO2 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 SO2 emissions

from the three Xcel plants (A.S. King, High Bridge and Riverside) contribute 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 were provided in a personal communication with Peter

Ciborowski, MPCA.
MPCA Review of MERP Proposal

page 26

Minnesota’s estimated point source emissions or about one-fourth of the state’s estimated total

SO2 emissions.31

Figure 1. Minnesota sulfur dioxide emissions, 2000 (total =189,636 tons)

Figure 2 illustrates the relationship between the NOX emissions from the three plants and those

from other state sources. These power plants total about 20 percent of the point source emissions

in the state or roughly six percent of NOX 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 PM10

emissions. While these plants are not large direct contributors to PM10, Figures 1 and 2 show

that they are significant contributors to SO2 and NOx emissions which once emitted, are the

precursors of PM2.5 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 emissions of mercury and CO2. 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 contributes about one-half of

the mercury released in Minnesota. About one in 16 pounds of mercury 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%
MPCA Review of MERP Proposal

page 28

Table 8 and Figure 5 provide the picture for CO2, the primary greenhouse gas. Here, as with

NOX and SO2, 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 CO2 emissions. Since

point sources make up just under half of the state’s emissions, these plants 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 plants contribute substantial amounts of pollutants to Minnesota’s

atmosphere. A variety of health and environmental effects have been linked to these pollutants.

This section briefly summarizes these impacts.33

The Department of Commerce’s 2001 Minnesota Energy Planning Report34 contained a section

on the health and environmental effects of electricity 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, PM2.5) found in the air. This concern has developed as a

result of the increasing number of studies describing 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 formed and its effects on human health.

With the passage of the 1970 Clean Air Act, Congress directed EPA to review the evidence for

health and environmental effects 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 establishment 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 statistical software, medical

records databases and more extensive air pollution trend data has allowed 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 have dropped, recent evidence shows that the size

of the particle has health consequences. 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 (PM10). “Fine” particles are those smaller than

2.5 microns (PM2.5). The characteristics, sources and health effects of these two sizes of

particulate matter are different.

Coarse particles from unpaved roads may become airborne when “kicked up” by vehicle traffic.

Rock crushing operations generate coarse particles, as does the wind when it blows across the

desert or agricultural fields. The particulate emissions 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 close 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 removed 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, 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. 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 kilometers. 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 particulate 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 identify a threshold (a level below which no effect

occurs) for some of the more serious health effects of particulate matter. So far, no threshold has

been found at ambient levels (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 reflect the latest scientific knowledge about

identifiable health effects. EPA undertook rulemaking in July 1997 to revise the ambient air

quality standards in part to address the findings of the serious health impacts of long-term

exposure to PM2.5. Subsequently, EPA established an ambient air quality standard for these fine

particles.

EPA retained the existing PM10 standard to continue to address the health effects from PM larger

than 2.5 microns. EPA also issued new rules related to monitoring for PM2.5 in the outdoor air.

Section 109 of the Clean Air Act directed 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 safety 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

PM2.5 NAAQS, and then required regulatory agencies to announce health advisories to the public

when monitored PM2.5 concentrations reach levels somewhat lower than the standard. EPA set
MPCA Review of MERP Proposal

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an annual PM2.5 ambient standard of 15 g/m3 and a 24-hour standard of 65 g/m3.

35 EPA

requires the MPCA to announce an unhealthy air pollution alert when the 24-hour PM2.5

concentration exceeds 40.5 g/m3.

6.2.3 PM2.5 in Minnesota

PM2.5 has been measured in Minnesota for about three years to determine whether Minnesota

attains the NAAQS. The Twin Cities’ PM2.5 concentration in 2001 was 13 g/m3. 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.

PM2.5 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 material. Minnesota has three urban monitors measuring the

composition of PM2.5 which have been operating for about a year. Results of this monitoring are

shown in Figure 6.

Figure 6. PM2.5 composition in Minnesota (Sept. 2001 – Oct. 2002)

Power plants contribute significantly to several of the different fractions of PM2.5. Coal-fired

power plants are significant contributors to the sulfate component of PM2.5 due to the total

amount of SO2 released from power plant stacks. To a lesser extent, they contribute a smaller

fraction to the nitrate component due to their NOx 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 PM2.5 standard is 15 ug/m3

concentration (ug/m3)
MPCA Review of MERP Proposal

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6.2.4 Air Alerts for Particulate Matter in the Twin Cities

EPA’s Clean Air Science Advisory Committee recognized there may not be a risk-free threshold

of PM2.5 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 PM2.5.

While this region meets the 24-hour PM2.5 ambient standard of 65 g/m3 and the annual

standard of 15 g/m3, the MPCA has had to issue air alerts when PM2.5 levels reach 40.5 g/m3.

EPA has specified 40.5 g/m3 for these warnings because research has shown that serious health

effects can occur at levels below the federal NAAQS. The PM2.5 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 PM2.5 was issued due to a

temperature inversion that trapped fine particles near ground level.

In addition, a review of available PM2.5 data indicates that concentrations in the Twin Cities

reached levels considered “Unhealthy for Sensitive Groups” (children and the elderly) on seven

days during calendar year 2000 and on four days during calendar year 2001, had PM2.5 air alerts

been required in those years. One PM2.5 event considered “unhealthy” for all groups was

monitored in October 2000 in Minneapolis. Monitoring data shows that unhealthy levels of

PM2.5 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 NOX, volatile organic chemicals and sunlight. In Minnesota, ozone pollution is

primarily a summer problem because of the need for sunlight in the formation process.

Ozone can adversely affect healthy adults, however children — because of their continuing

physical development — and people with existing respiratory problems are far more susceptible

to its presence. Higher ozone levels can cause eyes to itch, burn and water, trigger asthma

attacks, and prompt coughing, chest pains and difficult breathing. Because they generate large

emissions of NOX, 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 becomes a nonattainment area

for ozone, new federal regulations costing between $189 and $266 million per year would be
MPCA Review of MERP Proposal

page 33

required (Aulich and Neuson 1999). Requirements would include significant 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 enjoy 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 “natural 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 Voyageurs National Park and the Boundary Waters Canoe

Area must be developed by 2008. The MPCA is working 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 there 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 fish sampling, but its current advice is expanded to

include all fish caught while fishing in Minnesota. The MPCA has listed 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 have 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 mercury, as well as to the global pool of mercury.

6.2.10 Acid Rain

“Acid rain” refers to the deposition of acid that has 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 contributors to acid rain because of the SO2 and NOx 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 Amendments, Congress created the Acid Rain program.

Simply stated, Title IV required a fifty percent reduction in utility SO2 emissions from 1985

levels by 2000. In addition, utilities needed to make some cuts in NOX emissions.

To make the needed cuts in national SO2 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 SO2 emissions or of buying SO2 “reduction credits”

from utilities that reduce their emissions below their allowances.

Congress used a different approach to reduce NOX emissions. Utilities were required to meet a

system-wide average NOX 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 SO2 emission targets could be met by

switching from Eastern coals to Western coals, and implemented that strategy. To meet the NOX

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.
MPCA Review of MERP Proposal

page 35

7.0 Assessment of Benefits of the Proposed Project

7.1 Emission Estimates of the Proposal

The MPCA has independently calculated likely annual reductions in air emissions under Xcel’s

proposal, presented in tables 9 through 11 below. 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

factor37

SO2

(tpy)

NOX

(tpy)

PM10

(tpy)

CO2

(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

SO2

(tpy)

NOX

(tpy)

PM10

(tpy)

CO2

(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 0.47 038 107 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 SO2 and PM10 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.

SO2 NOX PM10 CO2 CO Lead Mercury

Emissions change (tpy) -31,880 -22,017 -667.1 -319,865 +80 -6039 -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 CO2 and CO at A.S. King due to increased generating capacity and

facility utilization.

Mercury emissions should be virtually eliminated at High Bridge and Riverside upon conversion

to natural gas, removing the release of 164 pounds of mercury per year41. With the

implementation of MERP, mercury emissions are expected to be lowered by 20 percent at King,

or about 14 pounds. Total mercury reductions from MERP from current operation is about 178

pounds, or approximately 12 percent of mercury emissions from coal-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 benefits 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 environmental externality value.42 Similarly, PM2.5 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.
MPCA Review of MERP Proposal

page 37

Table 12. Xcel’s Calculation of Environmental Benefits of Proposed Plan43

 (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 Proposal High Externality Value Average Emissions, tpy reduced Present value, benefits High Externality Value Average Emissions, tpy reduced Present value, benefits High Externality Value Average Emissions, tpy reduced Present value, benefits Net present value, benefits SO2 0 23,700 0 0 3,100 0 0 12,000 0 0 NOx 298 16,700 $18,799,000 1,094 4,400 $19,367,000 1,094 13,100 $58,174,000 $96,340,000 CO2 3.47 -482,000 ($17,998,000) 3.47 415,000 $2,636,000 3.47 1,570,000 $20,177,000 $4,815,000 CO 1.5 -100 ($1,000) 2,054 20 ($3,000) 2,054 140 $1,000 ($3,000) PM 3,229 90 ($431,000) 7,187 100 $3,304,000 7,187 540 $22,669,000 $25,542,000 TOTAL $369,000 $25,304,000 $101,021,000 $126,694,000
MPCA Review of MERP Proposal

page 38

7.3 Avoided Costs

Xcel’s proposal results in an increase in generation capacity of 385 MW. This is equivalent to a

good-sized power plant. Xcel refers to some MERP benefits as “avoided costs.” Xcel assumes

that by including this additional generation capacity 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 sites, 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. Xcel 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 equivalent 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 these plants. This is important

generating capacity located on existing transmission lines near load centers.

Xcel has not factored in the value of this benefit 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 three 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 assumptions. In addition, it is

important to note that the PUC externality factors were developed for resource planning

purposes, and evaluating resource planning decisions among different types of generation

technology options, not for evaluating the health and environmental benefits 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.
MPCA Review of MERP Proposal

page 39

by 20 years.45 Since MERP will reconstruct the High Bridge and Riverside plants it seems

appropriate to treat them as new plants, once MERP 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 refurbished 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 operating lives of electricity generating plants (EIA

1994, EIA 2002, DOE 1999, FERC 1980).

In the MERP case, it seems reasonable for planning purposes to think in terms of the project

having a useful life that extends from completion of the project to at least 2040.

If benefit estimates are extended to 2040, total environmental benefits would double.47

7.4.2 Discount Rates

Xcel discounts its estimates — both benefits and costs — at a “corporate discount rate.” The

specific rate chosen is 7.9448 percent. It is a private rate of return that applies specifically to

Xcel’s financial operations. The firm, its shareholders and the PUC should 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 appropriate for costs that Xcel will incur, different

factors influence the discount rate for the value of environmental benefits. MERP’s

environmental benefits will accrue to a large community — one that extends well beyond

Minnesota’s borders. Unlike private benefits that belong to individuals, public 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).
MPCA Review of MERP Proposal

page 40

public benefits, so the same inflation-compensating rate should be used for both costs and

benefits.

Financial risk is a different matter. Xcel’s shareholders incur a risk that other investments may

yield better rates of return. A significant portion 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, with 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 discount rate to use. The rate of three percent

proposed by the EPA seems reasonable, and other values should be

employed in a sensitivity analysis. The Council supports EPA’s proposed

choice of discount rates, but recommends 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 project’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 environmental 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 CO2 that are discounted at three and five percent.
MPCA Review of MERP Proposal

page 41

The present value of $1.04 billion (2002 valuation, 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 allowed under PUC orders. This “revenue 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 beyond 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 realistic time frame and a more 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 account 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
MPCA Review of MERP Proposal

page 42

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 when imposing new emission 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 similarities between these studies and the approach used

to develop the externality values used in Xcel’s emissions reduction proposal, these four studies

were conducted using more current 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 emissions 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 SO2 and NOx 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 effect in a population for a specified increase in

the particulate matter 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 have similar toxicity.

6. Some studies follow the estimate of the changes in disease or death incidence with an

economic valuation, that is, calculating the economic 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.
MPCA Review of MERP Proposal

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Table 13 summarizes the expected emission reductions, the estimated health benefits and cost

savings included in the four assessments described below. There are inherent uncertainties in

this type of assessment. Complete studies recognize and describe the uncertainties associated

with the estimated benefits. The table lists the estimated annual benefits from these studies with

the estimated annual benefits from MERP, based on Xcel’s calculation 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 benefits from reducing PM2.5. Both

generally supported these types of benefits analyses to estimate the benefits of air pollution

reductions, and recommended that future studies more fully describe the uncertainties associated

with the estimated benefits.

Some of the important uncertainties of the four studies below include the uncertainty when

modeling emission estimates for facilities in the future, the chemical formation and dispersion of

particulates, and the concentration-response function of particles from specific sources. Other

uncertainties inherent in other similar scientific inquiries, and having differing importance,

include variability of population demographics and heterogeneity, intersubject variability, health

and exposure baselines.

7.5.2 EPA’s Clear Skies Initiative

In 2001, 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 by 73 percent, nitrogen 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 monetary 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 estimate 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 Skies program would reduce particulate matter levels

across the state, and result in 100 fewer early deaths due to their health effects. Because PM2.5 is

a regional pollutant, benefits estimated in Minnesota are a result of emission reductions in

Minnesota and other states, and reductions 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 their coal-fired power plants (Abt Assoc. 2002).

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 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 SO2 and NOx

emissions from the Brayton Point and Salem Harbor coal-fired power plants in Massachusetts

(Levy and Spengler 2002). Their analysis compared current emissions with emission rates

estimated under best available control technology (BACT), which results in emission reductions

of 57,348 tons of SO2 and 11,074 tons of NOx per year from the two plants.

The predicted reductions of ambient annual PM2.5 concentrations ranged from 0.006 ug/m3 to

0.2 ug/m3 PM2.5 covering a 600 km by 600 km area in the Northeast U.S. This study estimates

that this reduction in SO2 and NOx would reduce about 70 premature deaths each year over a

total population of 33 million. Additional health effects were not considered. While suggesting

caution when calculating the value of the avoided early deaths, the authors used standard EPA

valuation for a statistical life and determined these avoided deaths represent a $400 million

benefit per year.

7.5.5 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 (Nelson 2000). The study concluded that by switching from coal to natural gas,

about 25 early deaths would be avoided. Other 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 benefit from switching to natural 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 outside 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

NOx reductions

(tons per year)

SO2 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 70 11,000 57,000

Minnesota Power

Plants $165 million 25 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 externality factors to the average annual emissions

avoided by implementing this project 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 health benefits from reducing SO2 and NOx 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 federal 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 externality 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 Initiative or these other assessments. Xcel’s proposal results in

emission reductions about half that evaluated by Nelson, suggesting 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 benefits 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 that 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 assessment 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 the 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 through 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 assess 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 for 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 PUC first conducted public hearings on the establishment of the

externality values. A “statistical life” is the amount people are willing to pay to reduce the risk

of dying. When the PUC set environmental externality 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 assignment of zero as an externality value for SO2. This

value was developed under the assumption that the costs of all damages were internalized in the

cost of allowances under the 1990 Clean Air Act regulations allowing SO2 emissions trading.

The damages focused primarily on the impacts of acid rain on the ecosystems.
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Recent research suggests that the SO2 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 SO2 releases from the electric power industry are still necessary (Gbonda-Tugbawa,

2002). Additionally, epidemiological studies have strengthened the links between fine and

sulfate particles with early death from cardiopulmonary 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 SO2 emissions and the resulting sulfate deposition would likely reduce the

amount of mercury that bioaccumulates (Branfireun et al. 1999, Gilmour et al. 1992).

Despite this range of human health and environmental advantages to reducing SO2 emissions,

Xcel’s assessment of the benefits of the MERP proposal assigns no benefits to SO2 reductions.

The PUC’s environmental externality 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 really 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 health and environmental benefits of the proposal. The MPCA

has demonstrated the degree to which the benefits 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 similar 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 reducing power plant emissions does not include any

consideration of benefits related to the following important environmental and health issues:

 Reduced emissions of mercury and 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 Minnesota 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/legislature/reports/2002/mercury-02.pdf. Metal

emissions from power plants are 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 SO2 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) The MERP project thus offers improvements to

the environment by first reducing mercury emissions and by reducing SO2 emissions that

may be participating in causing fish contamination in lakes.

 Reduced contribution to ground level ozone (smog), regional 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 rail 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 sites and transmission lines requires a substantial

amount of land, may require significant infrastructure upgrades, and is extremely

controversial.

All of the items listed above are — 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 concern that minority populations and/or low-income

populations bear a disproportionate share of adverse health and environmental effects. Many of

our older and more polluting industries are located near minority and low 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 environmental laws, regulations, and policies.” In

September 1999, the MPCA adopted an environmental 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 involuntary risks and consequences of environmental

pollution.”

The Riverside and High Bridge plants are located 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 the 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 uptake 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 place 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. Traffic 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 the 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 storage 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. River 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, noise 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 before 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, Minnesota, and St. Croix rivers. (See Figure 9)

The National Park Service, in cooperation with Metropolitan Council, the Minnesota Department

of Natural Resources, and local authorities has designated two major river corridors for

protection and improvement. The St. Croix National Scenic Riverway was established in 1968

and the lower St. Croix was added in 1972. The Allen S. King plant borders the St. Croix River.

The Mississippi National River and 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 plants would be converted to natural gas. As

outlined above, gas fired facilities should have less local visual and environmental impact than

coal facilities. The improvements at the High Bridge and Riverside sites should be more in line

with city, state, regional and Park Service plans for the Mississippi River corridor than continued

operation as coal fired facilities.

Community concern for these plants is quite high. For example, this year, the MPCA was

planning to re-issue the air permit for the Riverside Plant with no significant changes. (Air
MPCA Review of MERP Proposal

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permits expire every five years.) During the 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, existing power plants were grandfathered and thus

exempt from having to upgrade pollution control equipment. Expectations were that as these

grandfathered plants aged, they would be either replaced 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, with 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 have required corrective actions. Two of the most

significant are the acid rain controls required by the Clean Air Act Amendments of 1990, and the

NOx reductions needed to reduce regionally transported ozone pollution in the eastern United

States. Even these actions have not been enough.

It is now recognized that further reductions are needed in SO2 and NOx 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 SO2 and NOx from power

plants. Global climate change concerns may ultimately require CO2 reductions from this

industry. Coal burning power plants are one of the most significant sources of mercury

emissions in Minnesota and the nation. Finally, and perhaps the most serious, fine particulates,

which have been scientifically linked to major health 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 environmental 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 that projects benefits of $93 billion nationally and

$1 billion in Minnesota.

9.1 Costs and Benefits

Before summarizing the costs and benefits of this MERP proposal, it is helpful to know that Xcel

has already implemented Phase 1 of a significant emission reduction project in Colorado. Xcel

has now proposed a Phase 2 emission reduction project in the Denver, Colorado area.

The magnitude of the costs and benefits estimates for 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 Xcel’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 represented 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 projected capital costs of the MERP proposal, and its

estimated benefits. The MPCA has 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 that 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 accrual and using a more appropriate 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 associated 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 SO2 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 (Figure 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 environmental problems for Minnesota

lakes and streams.

 It does not consider many specific local benefits, particularly those associated with the

elimination of coal handling at two of the plants.
MPCA Review of MERP Proposal

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 It does not consider the fact that, with the additional 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-plant proposal against the estimated benefits as well

as the benefits that cannot be quantitatively estimated, 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 plant. Given the cost of coal vs. natural gas, it is

reasonable to continue to burn coal at this plant for base load generation capacity. The emission

controls proposed by Xcel approximate state-of-the-art controls 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 continue operations into the future. Such modifications would likely

trigger the need to install pollution control equipment 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 expansion 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 plant is located near downtown Minneapolis and is

surrounded by a densely populated urban area. The emission controls proposed are appropriate

for this type of generation technology. This plant, although quite old, still 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. Particulate-Related Health Impacts of Eight Electric

Utility Systems. Prepared for Rockefeller Family Fund. April 2002.

http://www.rrfund.org

Aulich and Neusen, (Aulich 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, and 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 Cogeneration Facilities, Regulations 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 Stimulation 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 Particulate Air Pollution and Mortality. Health Effects

Institute. www.healtheffects.org/pubs-special.htm

Levy, J.I. and J. D. Spengler (Levy and Spengler) 2002. Modeling the Benefits of Power Plant

Emission Controls in Massachusetts. Journal of Air and Waste Management Association

52:5-18.
MPCA Review of MERP Proposal

page 57

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/legislature/reports/2001/aq-report.pdf

Nelson, C.D (Nelson), 2000. The Public Health Impacts of Particulate Emissions from Coalfired Power Plants in Minnesota. Thesis. Master of Science. 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 Regulations, Board on Environmental Studies and

Toxicology, (The National Academies 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. Particulate 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 Mortality, and Long-term Exposure to Fine

Particulate Air Pollution. JAMA 287:1132-1141 (2002).

Public Utilities Commission (PUC) 1997. Order Establishing Environmental Cost Values,

Docket No. E-999/CI-93/583. Minnesota Public Utilities Commission, January 3, 1997.

Schwartz, J., Laden, F., Zanobetti, A. (Schwartz 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 Recommendations 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://tonto.eia.doe.gov/FTPROOT/modeldoc/m068b.pdf.

U.S. Energy Information Administration (EIA), 2000. Analysis of Strategies for Reducing

Multiple Emissions from Power Plants: Sulfur Dioxide, Nitrogen Oxides and Carbon

Dioxide, SR/OIAF/2000-05, December 2000.

www.eia.doe.gov/oiaf/servicerpt/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/assumption/electricity.html.
MPCA Review of MERP Proposal

page 58

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 Prospective Analysis - Benefits and Costs of the

Clean Air Act 1990-2020, An Advisory by a Special 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

1 of 3 12/10/02 3:12 PM
 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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http://www.revisor.leg.state.mn.us:8181/SE...S/mnstat/public/www/DDD/216B.1692/216B169
 (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.

 HIST: 1Sp2001 c 5 art 3 s 12</#FIELD>

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http://www.revisor.leg.state.mn.us:8181/SE...S/mnstat/public/www/DDD/216B.1692/216B169
The environmental impact of electricity is a

significant 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 air

emissions (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 this

section, 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 to

reduce or mitigate those impacts. This section focuses on air emissions, which are the single largest

source 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 control

programs 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 stringent

Clean 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 (SO2), carbon monoxide

(CO), fine particulate matter (PM2.5), 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 from

Minnesota sources derive from electricity generation, while electricity generation accounts for about

40 percent of all statewide mercury emissions and

58 percent of statewide SO2 emissions. Sources of

PM2.5 in the state are less certain, and are currently being studied in preparation for implementing the

new federal air quality standards for PM2.5.

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 be

classified as baseload capacity, with 2,050 MW classiMINNESOTA 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 GENERATION
fied 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 15

and 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 listed

in 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 SO2, NOx, CO, lead, and

particulate 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 5,559

MW (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

SO2, NOx, CO2 and mercury. In 1999, 80,017 tons of

NOx and 90,284 tons of SO2 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 CO2 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: PCA
Emissions of SO2, NOx, CO2 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 SO2 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 CO2 range from 0.94 lb. per kWh to 2.77

lb. per kWh, and those for mercury from 0.00002 to

0.00007 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

SO2 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 SO2.

Regarding CO2, 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 CO2 and mercury,

depending on type, pollution control equipment can

lower emissions of NOx and SO2 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-fired

facilities 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 SO2 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 Controlsa,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 NOX coal and air nozzles with close coupled overfire air; LNC2 = low NOX coal and air nozzles

with separated overfire air.

b low NOx controls 1 at Sherburne County unit 1 and low NOX 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

120,000

Tons

1985198619871988198919901991199219931994199519961997199819992000

 Coal

Figure A.5: Sulfur Dioxide Emissions from Electricity Generation in Minnesota

20,000

40,000

60,000

80,000

100,000

120,000

Tons

1985198619871988198919901991199219931994199519961997199819992000

 Internal Combustion

 Natural Gas

 Coal

Figure A.6: Nitrogen Oxides Emissions from Electricity Generation in Minnesota

NOTE: SO2 emissions from other electric generation sources are insignificant.
sulfur dioxide, nitrogen oxides, carbon dioxide, and

mercury. Figures A-5 and A-6 show SO2 and NOx

emissions, respectively, from electricity generation

from 1985 to 2000. These figures show that most

emissions of SO2 and NOx result from coal-fired

facilities. Emissions of SO2 have increased from

about 78,000 tons in 1986 to about 95,000 tons in

2000, or at an overall average rate of about 1.3 percent per year.

SO2 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 (N2O)

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 CO2-equivalent tons to the

current 38.6 million CO2-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’s

Sherburne County facility, relatively little new generation capacity has been built in Minnesota since

Page 96 2001 Energy Planning Report

MINNESOTA DEPARTMENT OF COMMERCE

CO2 Equivalent 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

Coal

198319841985198619871988198919901991199219931994199519961997199819992000

Figure A.7: Greenhouse Gas Emissions from Electric Generation in Minnesota 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 lbs.

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

80

198319841985198619871988198919901991199219931994199519961997199819992000

Percentage

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 Rating
1983. 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 steadily

increased 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 or

more 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 Harbor

power 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 SO2, 2,850 tons of

NOx and 1.2 million tons of CO2 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 this

expansion in statewide generation capacity to annual statewide emissions of SO2, 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 SO2 and 1,290 tons of NOx.

This translates to an increase in statewide emissions

of about 4 percent for CO2, and 1 and 1.5 percent for

SO2 and NOx, respectively.

Using the projected increase in coal throughput at

existing facilities, current emission levels (see

Figure A-3) and emissions associated with new con2001 Energy Planning Report Page 97

MINNESOTA DEPARTMENT OF COMMERCE

Figure A.10: Estimated Extra Annual SO2, NOx and CO2 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 SO2 NOX CO2

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 143a 45c 1,144,757 0.5 -28d -41d 435,075d

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 195b 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 unit 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 SO2 emissions, 2,849 tons of existing NOX emmissions and 1,215,921 tons of

CO2 would be shifted from the industrial sector to the electricity generation sector with the conversion of the 187.7MW LTV-Taconite

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 deficit

forecast in Chapter Two, beyond the current projects listed in Figure A-10. Figure A-11 shows that

CO2 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. SO2 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 some

fish, 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 and

vehicles, and wood burning, are creating health concerns at current outdoor concentrations. Particles

are emitted directly, or can be formed when ammonia and combustion gases such as nitrogen oxides

and 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 disFigure A.11: Historic and Forecasted Emissions of CO2, SO2 and NOx

from Electricity Generation in Minnesota

Year

2000 2005 2010

CO2

Baseline 2000 Emissions 38,638,000 38,638,000 38,638,000

Emissions from Increased Use, Existing Plantsa - 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

SO2

Baseline 2000 Emissions 94,915 94,915 94,915

Emissions from Increased Use, Existing Plantsa - 1,065 7,494

Emissions from New Generation Capacity - 978 978

total 94,915 96,958 103,387

NOX

Baseline 2000 Emissions 88,291 88,291 88,291

Emissions from Increased Use, Existing Plantsa - 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 Power 

NOTE: 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 PM2.5 Concentration

Steubenville, OH

Harriman, TN

Portage, WI Topeka, KS

Watertown, MA

St. Louis, MO

5 10 15 20 25 30 35

Relative Risk of Death

Figure A.12: Relative Risk of Death vs. Fine Particle (PM2.5) Concentration
played in Figure A-12, have shown an association

between increased particles in the air and premature

death from heart and respiratory disease.138Numerous

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 (PM2.5), 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 from

11 to 14 micrograms per cubic meter. Scientists studying health effects have found health effects at levels

below the standards. In cities with lower particle concentrations, including some likely to meet current federal ambient air standards, both hospital admissions

and 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 Matter

to 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 to

these 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 sources

have 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 due

to reductions in particulate emissions.141 Other

studies, such as that by

the Environmental Law

Institute shown in Figure

A-13, have tried to quantify the public healthbased financial benefits

of reducing particle emissions from power plants. 

In addition to health

impacts, small particles

reflect 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 on

the 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 when

pollutants (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 Twin

Cities 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 SO2

and NOX 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 assumptions

made for these calculations were conservative and therefore these estimates may provide lower benefit estimates compared to other studies. In

addition, 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 Park
tightness, 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 summers

like 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’s

most 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 most

waters 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, is

converted 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 are

probably 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 limit

how 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 the

state. Ten percent of the mercury comes from instate sources. Coal-fired power plants within

Minnesota 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 μg/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 contributors

to 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 of

peak 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 vary

widely 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. As

climate changes, particularly as it warms,

Minnesotans will see a

progressive forced

northward march of

conditions favorable to

warm temperature

forests now dominant to

our 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 CO2. Most human-produced CO2

is emitted during the combustion of coal, oil and

natural gas. Since the beginning of industrialization

about 150 years ago, atmospheric concentrations of

CO2 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 CO2, 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 CO2 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, CO2

Concentrations and Temperature Change, 

1000-2000

Chart by Matt Kania
to 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 present

warm 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 in

temperature 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, CO2 persists in the atmosphere at elevated

concentrations for hundreds of years. This renders a

CO2-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 of

the 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 expenditures

may become necessary to account for climatic uncerPage 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

•SO4 from SO2 Acidification

•NO3 from NOX Acidification, eutrophication

•PM2.5 from SO2 and NOX Respiratory disease, prematuredeath, visibility impairment

•Ozone from NOX Respiratory disease, visibility impairment

Carbon Dioxide Climate change Global

*Local: Within 100 miles; Regional: Within 1,000 miles
tainty 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 CO2 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 stabilize

their 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 CO2 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 deposition

is a complex problem whose sources are often distant from its impacts and is highly variable across

time 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 waters

become 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 and

soils 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 reports

the 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 and

health impacts from air pollution. Figure A-17 summarizes the key air pollutants emitted from electric

generation 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 these

health 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

PM10 National Air Standard

1980

1990

UN Framework on Climate

Change International Treaty

 (USA signatory)

Acid Rain SO2 Phase 1

Acid Rain N0x Phase 1

N0x NSPS Revision

Acid Rain N0x Phase 2 2000

 and SO2 Phase 2

Assess Attainment of

Revised PM2.5 and

 Ozone Air Standards

Interstate N0x Air Pollution

 Petitions/N0x State Plans

US/Canada N0x Treaty

Periodic Review of Ozone

 & PM2.5 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 Utilities
Review 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 SO2 and NOx emissions

either through implementation of best available

retrofit technology or a trading program yet to be

developed.

Implementation of New PM2.5 and Ozone

Standards

Since the PM2.5 national ambient air quality standard

for fine particles was set in 1997, dozens of new published studies, taken together, collectively strengthen

the association between PM2.5 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 Act

requires 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 PM2.5 standard in 2002 (3 years of

data is needed to determine compliance). The

MPCA expects Minnesota will be below the standards, but by a narrow margin. Recent exceedances

of the ozone standard in Minnesota and states to the

east suggest the possibility of future control requirements in Minnesota to address the ozone problem.

Power plants are significant contributors to PM2.5

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 contribute

significantly 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 rule

requires 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, New

Source 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 House

and 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 SO2 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 also

includes 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 be

installed that would significantly reduce the emissions of sulfur dioxide (SO2) and nitrogen oxides

(NOx) at Minnesota’s power plants. 

Within the last ten years, Minnesota’s electric utilities

reduced SO2 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 one

plant while other plants continue to emit at higher levels. To comply with the SO2 provisions of the Acid

Rain program, many of Minnesota’s power plants

switched from the higher sulfur coals they were using

to 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 SO2

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

SO2 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 SO2 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 technologies

that can be applied to the types of electricity generating units found in Minnesota. The SO2 control efficiency and the cost of three types of scrubbers151

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 SO2 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, or

SNCR; 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 units

may 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 SO2 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 SO2 emission rate. To assess the range of costs

for controlling SO2 emissions, the MPCA looked at

three SO2 control technologies on the five boiler

models introduced earlier. The three flue-gas desulfurization options each achieved at least a 90 percent

reduction in emissions (LFSO, which achieves an

SO2 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 SO2 scrubbers155as the

basis of the computation, the MPCA estimated that

the cost of installing SO2 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 the

boiler 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 SO2

removed 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 SO2 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 SO2 removed. (In

Page 106 2001 Energy Planning Report

MINNESOTA DEPARTMENT OF COMMERCE

Figure A.21: Estimated Costs for Installing SO2 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 SO2 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 3
other words, the cost to remove a ton of a pollutant

decreases.) This amount of SO2 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 of

maximum 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 lower

capacity 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 SO2 control technologies. The

number of control configurations analyzed varied

with the different boiler models, as the applicable

control technologies varied by boiler type. In addition, some control technologies could be used

together. An EPA model was used to determine the

effectiveness 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 SO2 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 SO2

removed163 and an estimated $975 to $2140 per ton of

NOx removed.164

The MPCA did not investigate the efficiency or cost

of technologies to control mercury and carbon dioxide. Few control efficiencies or cost estimates have

been firmly established for retrofits to reduce mer2001 Energy Planning Report Page 107

MINNESOTA DEPARTMENT OF COMMERCE

Figure A.22: Estimated Cost to Meet NSPS Standard for SO2 Emissions 

Lowest Cost Cost-effectiveness Cost-effectiveness

Model Option to Meet for a for an

Number NSPS for SO2 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 Emissionsa

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 dollars
cury 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 that

reduce 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 CO2 from power plant

flue gases.165 Three opportunities exist for CO2 emissions control by the electric utilities. To reduce CO2

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 CO2 produced when using coal as a

fuel source. Second, electricity generators could offset

emissions through carbon sequestration in standing

biomass 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 the

existing Minnesota plants that most resemble the modeled units. Rate impacts

range from $3.59/year to

$27.42/year for SO2 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, total

rate 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 the

five 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 the

current level of emissions from electricity generation in the state, the different environmental impacts

associated 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 not

increase 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 that

result 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 SO2 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 Usage1 2000 $2 Customer3 2000 $ Customer4

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 Usage1 2000 $2 Customer3 2000 $ Customer4

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 public

concern over air emissions from existing electric generating plants by enacting an emissions reduction

rider 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 CO2 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 Trends. Website

http://www.epa.gov/ttn/chief/trends/trends99/tier3_yrsemis.pdf accessed December 10, 2001.

144. MPCA. Minnesota Air: Air Quality and Emissions Trends. 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 CO2, 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, scientists

debate 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 requirement

failing 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 SO2, 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 SO2 control technologies are limestone forced oxidation (LFSO), limestone spray

drying (LSD), and magnesium-enhanced lime (MEL). Each of these flue-gas desulfurization technologies use scrubbing to reduce SO2 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 SO2 emissions are formed from the direct combustion of sulfur contained in the

coal, 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 may

react 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 SO2 Emissions: An Analysis of

Technologies. EPA/600/SR-00/093, November 2000. 

Also: Srivastava, Ravi K. Controlling SO2 Emissions: A Review of Technologies. EPA/600/R00/093, November 2000.

156. Costs for SO2 controls are provided in 1997 dollars.

157. The actual costs of installing SO2 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 CO2 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.

2001 Energy Planning Report Page 111

MINNESOTA DEPARTMENT OF COMMERCE
Page 112 2001 Energy Planning Report

MINNESOTA DEPARTMENT OF COMMERCE
2001 Energy Planning Report Page 113

MINNESOTA DEPARTMENT OF COMMERCE

APPENDIX 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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Attachment 3

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 small 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 SO2 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 people 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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Attachment 3

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 Cities1

. 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 required2

.

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 visibility 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 and 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 proceeding 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. The 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 plants, 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 Reducing 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, followed 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 program 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 emissions from their coal-fired power plants4 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 other 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 Massachusetts6

. 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 cautioned 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 million 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 when 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 generally 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 transmission line losses and lower peak demand from

centralized generators. The increased use of emergency and distributed generators (EDG) raises concerns

for local health effects and exacerbation of the metropolitan 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 other 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 cause 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 particulate 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 Developments 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-diesel concentration, the greater the emissions benefit.

Biodiesel fuel is becoming more available in Minnesota 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.