- Identify inspection finding that "rise to the top", or are most common to units across the fleet

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1 AEP BRO Conference 2009 AEP Core Boiler Inspection Group (ACBIG) In 2007 the (ACBIG) was conceived and implemented by AEP in an effort to improve boiler availability and consistency across the AEP fleet. The concept was to designate specific UDC inspection personnel to exclusively inspect in AEP plants. These inspectors were to utilize the UDC inspection ideology, become familiar with the specific requirements of each plant, and report only equipment condition and best practices for repair methods without influence from plant or system concerning budget or time constraints. In this way the AEP decision makers at the plant level would have a clear picture of their risk profile and could get the biggest bang for their buck with the least assumed risk. AEP System Analysis Findings and Priority 1 Identification: - Identify inspection finding that "rise to the top", or are most common to units across the fleet 1. Erosion: cause- Fly Ash and Soot Blower 2. Long Term overheat / High Temperature Creep

2 American Electric Power Repair Priority Totals Scheduled and Forced Outages June 2008 through May 2009 The following information was compiled by the UDC (AEP core group) from inspection databases. The data collected must be qualified as not all inspections in all plants were equal in areas accessed and inspectors provided. The data does however show general trends that are useful. Amos 2 as well as Northeastern unit 4 should benefit the most as they had the highest number of P1 issues discovered. If these were in fact repaired / replaced, the availability for those units should show the greatest improvement. It has been concluded that fuel adjustments have taken place at a number of facilities throughout the system increasing the percentage of Powder River Basin (PRB) utilized. The fuel changes will alter ash softening temperatures and may alter fly ash erosion patterns as well as change slagging and fouling rates. Areas affected by poor coal qualities

3 AEP Repair Priority Totals June 2008 through May 2009 Amos Gavin Kanawha River Unit 3 Sept Unit 2 Mar Unit 2 Oct Replacements 002 Replacements Replacements P1-009 P1 019 P1-038 P2-018 P2 030 P2-051 P3-000 P3 073 P3-012 Amos Gavin Kanawha River Unit 2 Apr Unit 1 May 2008 Unit 1 Oct Replacements 118 Replacements 022 Replacements P1 273 P1 043 P1-037 P2-022 P2 055 P2-018 P3-027 P3 046 P3-002 Amos Glen Lyn Kanawha River Unit 1 May 2009 Unit 51 Aug.2008 Unit 2 Feb Replacements 038 Replacements 009 Rep. 003 P1 038 P1 018 P1-022 P2 002 P2 004 P2-008 P3 013 P3 005 P3-051 Cardinal Glen Lyn Kanawha River Unit 2 Mar Unit 51 Sept Unit 1 Apr Replacements 029 Replacements 000 Replacements P1 072 P1 007 P1-026 P2 148 P2 024 P P3 005 P3 014 P3-030 Cardinal Glen Lyn Kyger Creek Unit 1 May 2009 Unit 52 Aug Unit 2 Nov Replacements 016 Replacements 016 Replacements P1 044 P1 016 P1-014 P2 054 P2 006 P2-042 P3-063 P3 001 P3-041 Conesville Glen Lyn Kyger Creek Unit 4 Feb Unit 52 Sept Unit 3 May 2009 Replacements 013 Replacements 011 Replacements P1 026 P1 037 P1-031 P2 624 P2 016 P2-118 P3-003 P3 045 P3-028

4 AEP Repair Priority Totals June 2008 through May 2009 Mitchell Oklaunion Unit 1 Oct Unit 1 Feb Replacements 013 Replacements P1 098 P1 021 P2-080 P2 311 P3-160 P3 026 Mitchell Tanners Creek Unit 2 Apr Unit 3 Nov Replacements 097 Replacements 106 P1 091 P1 149 P2 072 P2 262 P3 062 P3 188 Muskingum Welsh Unit 4 Sept Unit 3 Mar Replacements 028 Replacements 001 P1 047 P1 124 P2 076 P2 006 P3 158 P3 080 Muskingum Welsh Unit 2 Mar Unit 2 Apr Replacements 003 Replacements 028 P1 037 P1 047 P2 071 P2 071 P3 026 P3 131 Northeastern Welsh Unit 4 Nov Unit 1 May 2009 Replacements 012 Replacements- 004 P1 072 P1-005 P2 052 P2-034 P3-393 P3-028 Northeastern Unit 4 Mar Replacements 073 P1 167 P2 255 P3-269 END

5 Please note: Inspections that have been performed on units that have previous data may have included evaluations on different components; therefore, trending the number of repairs may be difficult by unit from year to year. Fly Ash Erosion Location: All tubes are vulnerable; however the following are the most common: Convection Pass Economizer Reheater Superheater External Appearance: Fly ash erosion produces polished flat spots from removal of the oxide and reduction in wall thickness. A longitudinal, thin edged fracture results when the erosion rate is high but the erosion occurs gradually over time, the fracture may be thick edged due to long term creep effects. Erosion damage is usually limited to a small area. Probable cause: Gas flow restrictions / slagging / fouling Fuel adjustments / Ash softening temperatures Ash content in flue gas Improper use of baffling Tube alignment The root causes of fly ash erosion can be verified by determining the reason for the non uniform or excessive gas flow at the location of erosion. Misalignment of tubing or flow guides and buildup of ash can be seen and corrected without any further testing requirements. Verification of excessive gas flow requires reviewing operating practices and conditions, and possibly conducting gas velocity tests. "Cold air" velocity tests have achieved good correlations between areas of high velocity and locations of failures. Corrective action: Corrective actions involved either reducing the amount and velocity of ash striking the tube or increasing the amount of wear resistance of the tube. Changing boiler operation conditions such as reducing load, lowering excess air levels, balancing air flows, modifying soot blowers, and preventing ash accumulations are possible actions to reduce the velocity of the ash. Structural

6 changes such as baffles, fences, shields, and plates may also be made, but care must be taken to prevent transfer of the erosion problem to another location. Cold air tests should be conducted after such changes. Pad welding and flame spray are short term actions which Increase the amount of wear resistance of the tube. Staggered tube arrangements replaced with inline tube geometry also helps. Comment: Fly ash erosion can occur at locations that: (1) Have gaps between the tube bank and the duct walls. (2) Have gas bypass channels where the velocity of the flue gas can be much higher than that of the main flow. (3) Have protrusions or misalignment of tubing rows. (4) Are adjacent to areas with large accumulations of ash. Fly ash erosion is caused by non uniform or excessive gas flow, which accelerates a large volume of fly ash particles and directs them onto the tube surface. Tube erosion is enhanced by distortion or misalignment of tubing rows; misalignment or loss of gas flow guides and baffles; operation above the maximum continuous design rating, above design excess air flow, or with non uniform flow of flue gas; and fouling or plugging of gas passages by ash buildups. Changing fuel to one with higher ash content can result in more erosion and failures. Visual examinations and ultrasonic (UT) tube wall thickness measurements are listed to detect and monitor fly ash erosion. UT surveys should be conducted after a change in fuel supply or after a failure occurrence to determine the extent of erosion and to prevent a subsequent failure within a short time. Periodic UT surveys can provide data for predicting remaining useful service life and planning corrective actions. An estimate of remaining service life should be made on un-failed tubes.

7 High Temperature Creep Location: Convection Pass Reheater Superheater Internal Appearance: Internal oxide scale External Appearance: High temperature creep produces a longitudinal fracture; the extent of the fracture and its appearance may vary, A small fracture will form a blister like opening, while a large fracture creates a wide fish mouth appearance. The fracture surface is thick edged with extensive secondary cracking adjacent to the main fracture. The tube surface may have a thick hard oxide scale which could have an alligator hide appearance. Probable cause: Flame patterns Improper use of materials Operating temperatures above the oxidation limits Flow reduction The root cause of high temperature creep can be verified by investigating the coolant circuitry, the gas passages, and the tube material properties. Tube sampling may be necessary to check for blockages and deposits that restrict the transfer of heat. Measurement of the tube metal and furnace gas temperatures can verify abnormal gas flow patterns. Tube material properties testing can verify the application of the material to the temperature experienced by the tubing. These ruptures occur primarily in high temperature locations such as superheat and reheat areas. Long term overheat is a result of operating problems, wrong material, incorrect flame patterns, and restricted coolant. Corrective action: Corrective actions involve the determination of the remaining life of the tubing based on the actual temperature, stress level, and material properties. Parametric analysis methods, such as the Larson Miller parameter method, can be applied to estimate the effects of various actions. High pressure

8 liquid flushing or chemical cleaning may be performed to remove internal scale, deposits, and blockages that reduce the tube metal temperature. Material upgrades may be necessary to provide higher creep resistant steel at the location of high temperatures. Corrective actions such as a tube shield log, pad welding, or thermal spray coating may be performed to reduce the rate of wall thinning caused by corrosion or erosion. Comment: High temperature creep can occur in steam-cooled tubes at locations that: (1) Have become partially blocked by debris, scale, or deposits restricting flow. (2) Have exposure to radiant heat (line of sight) or excessive gas temperature due to blockage of gas passages or are located before the final outlet header. (3) Are located before the change to a higher grade of steel or have incorrect or lesser grade of steel material. (4) Have higher stresses due to welded attachments and orientation. High temperature creep failures occur from a relatively continuous extended period of slight overheating above the design metal temperature, a slowly increasing level of temperature or stresses, or from the accumulation of periods of excessive overheating. The root cause of high temperature creep can be verified by investigating the coolant circuitry, the gas passages, and the tube material properties. Tube sampling may be necessary to check for blockages and deposits that restrict the transfer of heat. Measurement of the tube metal and furnace gas temperatures can verify abnormal gas flow patterns. Tube material properties testing can verify the application of that material to the temperature experienced by the tubing. Wall thickness measurements are necessary to verify that stress levels have not increased due to erosion or corrosion. Ultrasonic wall thickness measurements are taken to check for wall thinning from erosion, corrosion, or oxidation. Outside diameter tube measurements may indicate that swelling has occurred due to creep degradation. Thermocouples can be placed on the tubing to ascertain the actual metal temperature that is achieved at selected locations. Tubing locations just before the transition to a higher grade of alloy steel is of particular concern.

9 Thank You Jon S Cavote Chief Operating Officer United Dynamics AT Corp