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November 30, 2010 Ms. Kimberly Bose Secretary Federal Energy Regulatory Commission 888 First Street, N.E. Washington, DC 20426 Re: NERC Abbreviated Notice of Penalty regarding Indiana Municipal Power Agency,

FERC Docket No. NP11-__-000 Dear Ms. Bose: The North American Electric Reliability Corporation (NERC) hereby provides this Abbreviated Notice of Penalty (NOP) regarding Indiana Municipal Power Agency (IMPA), with information and details regarding the nature and resolution of the violation1 discussed in detail in the Settlement Agreement (Attachment c) and the Disposition Documents (Attachment d), in accordance with the Federal Energy Regulatory Commission’s (Commission or FERC) rules, regulations and orders, as well as NERC Rules of Procedure including Appendix 4C (NERC Compliance Monitoring and Enforcement Program (CMEP)).2

This NOP is being filed with the Commission because ReliabilityFirst Corporation (ReliabilityFirst) and IMPA have entered into a Settlement Agreement to resolve all outstanding issues arising from ReliabilityFirst’s determination and findings of the enforceable violations of VAR-002-1.1a R2, PRC-005-1 R1 and PRC-005-1 R2.1. According to the Settlement Agreement, IMPA neither admits nor denies the violation, but has agreed to the assessed penalty of twenty two thousand dollars ($22,000), in addition to other remedies and actions to mitigate the instant violations and facilitate future compliance under the terms and conditions of the Settlement Agreement. Accordingly, the violations identified as NERC Violation Tracking

1 For purposes of this document, each violation at issue is described as a “violation,” regardless of its procedural posture and whether it was a possible, alleged or confirmed violation. 2 Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the Establishment, Approval, and Enforcement of Electric Reliability Standards (Order No. 672), III FERC Stats. & Regs. ¶ 31,204 (2006); Notice of New Docket Prefix “NP” for Notices of Penalty Filed by the North American Electric Reliability Corporation, Docket No. RM05-30-000 (February 7, 2008). See also 18 C.F.R. Part 39 (2010). Mandatory Reliability Standards for the Bulk-Power System, FERC Stats. & Regs. ¶ 31,242 (2007) (Order No. 693), reh’g denied, 120 FERC ¶ 61,053 (2007) (Order No. 693-A). See 18 C.F.R § 39.7(c)(2).

NERC Notice of Penalty Indiana Municipal Power Agency November 30, 2010

Identification Numbers RFC200900157, RFC201000239 and RFC200900190 are being filed in accordance with the NERC Rules of Procedure and the CMEP. Statement of Findings Underlying the Violations This NOP incorporates the findings and justifications set forth in the Settlement Agreement executed on June 30, 2010, by and between ReliabilityFirst and IMPA. The details of the findings and the basis for the penalty are set forth in the Disposition Documents. This NOP filing contains the basis for approval of the Settlement Agreement by the NERC Board of Trustees Compliance Committee (NERC BOTCC). In accordance with Section 39.7 of the Commission’s regulations, 18 C.F.R. § 39.7, NERC provides the following summary table identifying each violation of a Reliability Standard resolved by the Settlement Agreement, as discussed in greater detail below.

NOC ID NERC

Violation ID

Reliability Std.

Req. (R) VRF Duration

Total Penalty

($)

NOC-602

RFC200900157 VAR-002-1.1a3 2 Medium 1/25/09-1/25/09

22,000 RFC201000239 PRC-005-1 1 High4 6/18/07- 11/30/09

RFC200900190 PRC-005-1 2.1 High5 6/18/07- 11/30/09

The text of the Reliability Standards at issue and further information on the subject violations are set forth in the Disposition Documents. VAR-002-1.1a R2 - OVERVIEW On June 24, 2009, IMPA self-reported a violation of VAR-002-1.1a R2. ReliabilityFirst determined that IMPA, as a Generator Operator, did not maintain its generator voltage output at its Anderson Station as directed by the Transmission Operator, American Electric Power (AEP),6

3VAR-002-1 was enforceable from August 2, 2007 through August 27, 2008. VAR-002-1a was approved by the Commission and was enforceable from August 28, 2008 through May 13, 2009. VAR-002-1.1a was approved by the Commission and was enforceable from May 13, 2009 through September 16, 2010. VAR-002-1.1b was approved by the Commission and became enforceable on September 16, 2010. The subsequent interpretations provide clarity regarding the responsibilities of a registered entity and do not change the meaning or language of the original NERC Reliability Standard and its requirements. For consistency in this filing, the version applicable when the violation was discovered, VAR-002-1.1a, is used throughout.

4 When NERC filed Violation Risk Factors (VRFs) it originally assigned PRC-005-1 R1 a “Medium” VRF. The Commission approved the VRF as filed; however, it directed NERC to submit modifications. NERC submitted the modified “High” VRF and on August 9, 2007, the Commission approved the modified “High” VRF. Therefore, the “Medium” VRF for PRC-005-1 R1 was in effect from June 18, 2007 until August 9, 2007 when the “High” VRF became effective. 5 PRC-005-1 R2 has a “Lower” VRF; R2.1 and R2.2 each have a “High” VRF. During a final review of the standards subsequent to the March 23, 2007 filing of the Version 1 VRFs, NERC identified that some standards requirements were missing VRFs; one of these include PRC-005-1 R2.1. On May 4, 2007, NERC assigned PRC-005 R2.1 a “High” VRF. In the Commission’s June 26, 2007 Order on Violation Risk Factors, the Commission approved the PRC-005-1 R2.1 “High” VRF as filed. Therefore, the “High” VRF was in effect from June 26, 2007. 6 PJM Interconnection, LLC (PJM) delegated its Transmission Operator responsibilities to AEP at IMPA’s station.


because the station voltage was not lowered to within the AEP voltage schedule on January 25, 2009 and there was no communication to AEP to allow for an exemption. PRC-005-1 R1 and R2.1 - OVERVIEW On September 29, 2009, IMPA self-reported7

a violation of PRC-005-1, R2.1 (September 29, 2009 Self Report). ReliabilityFirst determined that IMPA, as a Generator Owner, did not conduct maintenance and testing on six breaker failure relays on generator protection breakers in accordance with the defined intervals of its Protection System maintenance and testing program.

On January 7, 2010, ReliabilityFirst discovered a violation of PRC-005-1 R1 after requesting additional information related to the September 29, 2009 Self-Report discussed above. ReliabilityFirst determined that IMPA, as a Generator Owner, did not include maintenance and testing intervals and their basis and a summary of maintenance and testing procedures in its Protection System8

program for potential transformers (PTs), current transformers (CTs), station batteries and DC control circuitry.

Statement Describing the Assessed Penalty, Sanction or Enforcement Action Imposed9

Basis for Determination Taking into consideration the Commission’s direction in Order No. 693, the NERC Sanction Guidelines, the Commission’s July 3, 2008 and October 26, 2009 Guidance Orders,10

the NERC BOTCC reviewed the Settlement Agreement and supporting documentation on September 10, 2010. The NERC BOTCC approved the Settlement Agreement, including ReliabilityFirst’s assessment of a twenty two thousand dollar ($22,000) financial penalty against IMPA and other actions to facilitate future compliance required under the terms and conditions of the Settlement Agreement. In approving the Settlement Agreement, the NERC BOTCC reviewed the applicable requirements of the Commission-approved Reliability Standards and the underlying facts and circumstances of the violations at issue.

In reaching this determination, the NERC BOTCC considered the following factors:

1. the violations constituted IMPA’s first occurrence of violation of the subject NERC Reliability Standards;

7 In addition to the six breaker failure relays, IMPA indicated in its Self-Report that it had failed to test (1) the DC control circuitry for its Anderson Unit 3, (2) seven of the 21 PTs on its Anderson Unit 3, and (3) all of the 101 CTs on Anderson Units 1 through 3. ReliabilityFirst determined that IMPA’s failure to test these devices did not constitute a violation of PRC-005-1 R2.1 because IMPA’s program did not define any testing intervals for these devices. IMPA’s failure to include PTs, CTs, station batteries, and DC control circuitry in its program resulted in the aforementioned violation of PRC-005-1 R1. 8 The NERC Glossary of Terms Used in Reliability Standards defines Protection System as “Protective relays, associated communication systems, voltage and current sensing devices, station batteries and DC control circuitry.” 9 See 18 C.F.R. § 39.7(d)(4). 10 North American Electric Reliability Corporation, “Guidance Order on Reliability Notices of Penalty,” 124 FERC ¶ 61,015 (2008); North American Electric Reliability Corporation, “Further Guidance Order on Reliability Notices of Penalty,” 129 FERC ¶ 61,069 (2009). See also North American Electric Reliability Corporation, “Notice of No Further Review and Guidance Order,” 132 FERC ¶ 61,182 (2010).


2. IMPA self-reported two of the three violations covered by the Settlement Agreement;11

3. ReliabilityFirst reported that IMPA was cooperative throughout the compliance enforcement process;

4. IMPA had a compliance program at the time of the violation, as discussed in the Disposition Documents which ReliabilityFirst considered a mitigating factor in assessing the penalty;

5. there was no evidence of any attempt to conceal a violation nor evidence of intent to do so;

6. ReliabilityFirst determined that the violations did not pose a serious or substantial risk to the reliability of the bulk power system (BPS), as discussed in the Disposition Documents; and

7. ReliabilityFirst reported that there were no other mitigating or aggravating factors or extenuating circumstances that would affect the assessed penalty.

For the foregoing reasons, the NERC BOTCC approves the Settlement Agreement and believes that the assessed penalty of twenty two thousand dollars ($22,000) is appropriate for the violations and circumstances at issue, and is consistent with NERC’s goal to promote and ensure reliability of the BPS. Pursuant to 18 C.F.R. § 39.7(e), the penalty will be effective upon expiration of the 30 day period following the filing of this NOP with FERC, or, if FERC decides to review the penalty, upon final determination by FERC.

11 According to the Settlement Agreement at P 23, ReliabilityFirst determined that IMPA’s September 29, 2009 self-report of PRC-005-1, R2.1 and January 7, 2010 response to a ReliabilityFirst request for information indicated that an alleged violation of PRC-005-1, R1 also occurred, even though IMPA had not identified the facts as a violation of that requirement. No separate source document is being provided with respect to this violation.


Attachments to be included as Part of this Notice of Penalty The attachments to be included as part of this NOP are the following documents:

a) IMPA’s Self-Report for VAR-002-1.1a R2 dated June 24, 2009, included as Attachment a;

b) IMPA’s Self-Report for PRC-005-1 R2.1 dated September 29, 2009, included as Attachment b;

c) Settlement Agreement by and between ReliabilityFirst and IMPA executed June 30, 2010, included as Attachment c;

i. IMPA’s Mitigation Plan for VAR-002-1.1a R2 designated as MIT-09-2059 submitted September 18, 2009, included as Attachment A to the Settlement Agreement;

ii. IMPA’s Certification of Mitigation Plan Completion for VAR-002-1.1a R2 dated October 29, 2009, included as Attachment B to the Settlement Agreement;

iii. ReliabilityFirst’s Verification of Mitigation Plan Completion for VAR-002-1.1a R2 dated November 16, 2009, included as Attachment C to the Settlement Agreement;

iv. IMPA’s Mitigation Plan for PRC-005-1 R1 and R2.1 designated as MIT-07-2544 submitted May 6, 2010, included as Attachment D to the Settlement Agreement; and

v. IMPA’s Certification of Mitigation Plan Completion for PRC-005-1 R1 and R2.1 dated June 15, 2010, included as Attachment E to the Settlement Agreement.

d) ReliabilityFirst’s Verification of Mitigation Plan Completion for PRC-005-1 R1 and R2.1 dated August 13, 2010, included as Attachment d.

e) Disposition Document for Common Information, included as Attachment e:

i. Disposition Document for VAR-002-1.1a R2, as Attachment e-1; and

ii. Disposition Document for PRC-005-1, as Attachment e-2.

A Form of Notice Suitable for Publication12

A copy of a notice suitable for publication is included in Attachment f.

12 See 18 C.F.R. § 39.7(d)(6).


Notices and Communications Notices and communications with respect to this filing may be addressed to the following:

Gerald W. Cauley President and Chief Executive Officer David N. Cook* Sr. Vice President and General Counsel North American Electric Reliability Corporation 116-390 Village Boulevard Princeton, NJ 08540-5721 (609) 452-8060 (609) 452-9550 – facsimile [email protected] Kristina K. Wheeler* Vice President & Staff Counsel Indiana Municipal Power Agency 11610 N. College Ave. Carmel, Indiana 46032 (317) 575-3870 (317) 573-3372 – facsimile [email protected] Scott Berry* Generation/Compliance Engineer Indiana Municipal Power Agency 11610 North College Avenue Carmel, Indiana 46032 [email protected] Megan E. Gambrel* Associate Attorney ReliabilityFirst Corporation 320 Springside Drive, Suite 300 Akron, Ohio 44333 (330) 456-2488 (330) 456-5408 – facsimile [email protected] *Persons to be included on the Commission’s service list are indicated with an asterisk. NERC requests waiver of the Commission’s rules and regulations to permit the inclusion of more than two people on the service list.

Rebecca J. Michael* Assistant General Counsel North American Electric Reliability Corporation 1120 G Street, N.W. Suite 990 Washington, DC 20005-3801 (202) 393-3998 (202) 393-3955 – facsimile [email protected] Timothy R. Gallagher* President & CEO ReliabilityFirst Corporation 320 Springside Drive, Suite 300 Akron, Ohio 44333 (330) 456-2488 (330) 456-5390 – facsimile [email protected] Raymond J. Palmieri* Vice President and Director of Compliance ReliabilityFirst Corporation 320 Springside Drive, Suite 300 Akron, Ohio 44333 (330) 456-2488 (330) 456-5408 – facsimile [email protected] Robert K. Wargo* Manager of Compliance Enforcement ReliabilityFirst Corporation 320 Springside Drive, Suite 300 Akron, Ohio 44333 (330) 456-2488 (330) 456-5408 – facsimile [email protected]


Conclusion Accordingly, NERC respectfully requests that the Commission accept this Abbreviated NOP as compliant with its rules, regulations and orders.

Respectfully submitted, /s/ Rebecca J. Michael Gerald W. Cauley President and Chief Executive Officer David N. Cook Sr. Vice President and General Counsel North American Electric Reliability Corporation 116-390 Village Boulevard Princeton, NJ 08540-5721 (609) 452-8060 (609) 452-9550 – facsimile [email protected]

Rebecca J. Michael Assistant General Counsel North American Electric Reliability

Corporation 1120 G Street, N.W. Suite 990 Washington, DC 20005-3801 (202) 393-3998 (202) 393-3955 – facsimile [email protected]

cc: Indiana Municipal Power Agency ReliabilityFirst Corporation Attachments

Attachment a

IMPA’s Self-Report for VAR-002-1.1a R2 dated June 24, 2009

Self-Report Form – 6-18-09 – Revision I

COMPLIANCE MONITORING AND ENFORCEMENT PROGRAM

VIOLATION SELF-REPORTING FORM

This Violation Self-Reporting Form can be used for submittals via e-mail for violations of the Reliability Standards identified by a self- assessment.

1. Date: June 24, 2009

2. Registered Entity: Indiana Municipal Power Agency

3. NERC Registry ID: NCR00796 Joint Registration ID (JRO) (if applicable:)

4. Multiple Regional Registered Entity (MRRE) Regional Affiliates (if applicable:)

5. Reliability Standard VAR-002-1.1a Requirement a: R2.

6. Reporting for registered function(s): Generator Operator 7. Date Violation was Discovered: June 5, 2009

Beginning Date of Violation: January 25, 2009

End or Expected End Date of Violation: January 25, 2009 8. Has this violation been previously reported: Yes or No

If yes, Provide NERC Violation ID number: 9. Has this violation been reported to another region(s): Yes or No

If yes, Provide Region(s): 10. Is the violation still occurring: Yes or No 11. Detail description and cause of the violation: During an internal annual audit conducted June 2, 2009, IMPA discovered three dates on which its Anderson combustion turbine generating units were producing power and no station voltage reading was recorded in our operating logs. After acquiring historical voltage information from Duke Energy Indiana (Duke), IMPA found the station voltage on one of those three dates, January 25, 2009, to be higher than the station voltage schedule provided by American Electric Power (AEP). Before the generating units were brought online, the system voltage was already higher (at approx. 142.5 kV) than the voltage specified in the AEP voltage schedule (139 kV +/- 1%) given to IMPA. When the IMPA generating units were connected to the station, they brought the station voltage down to approximately 141.8 kV, but still were not within the AEP voltage schedule. While running the three units at the Anderson Station, the two operators had numerous and

X

X

X


continuing documented operational issues that required their attention, and were necessary to keep the generation online, which is also important to reliability of the Bulk Electric System. Once the operational issues were resolved, the operator was preparing to take voltage readings when he received a call from IMPA’s control center to shut down the units at PJM’s request. Since the station voltage was not lowered to within the AEP voltage schedule and there was no communication to AEP that day to allow for an exemption, IMPA believes a potential non-compliance issue may have occurred for R2 of VAR-002-1.1a. 12. Violation Risk Factor: Lower ( ) – Medium ( X ) – High ( ) – Not Specified ( ) Select One 13. Violation Severity Level: Lower ( X ) – Moderate ( ) – High ( ) – Severe ( ) Select One

Provide justification for this determination: The voltage schedule covers our Anderson Station which is made up of three peaking units (ACT 1, ACT 2, and ACT 3). ACT 1 and ACT 2 are rated at 48.7 MVA per unit, and ACT 3 is rated at 101 MVA. IMPA has maintained the voltage schedule for 100% of its generators for all but three hours in one day. On January 25, 2009, ACT 1 and ACT 2 were generating power for approximately 2 hours, and ACT 3 was generating power for approximately 3 hours. During the period when the units were online, they actually helped lower the station voltage to a level closer to the voltage schedule and did not make the station voltage higher. Therefore, IMPA believes the violation severity level to be lower.

14. Provide a determination of the Potential Impact to the Bulk Electric System: The units produced power for a very short period of time and actually lowered the system voltage to a level closer to the station voltage schedule provided by AEP. The units were dispatched by PJM for generation and not for VAR support. When considering these circumstances, IMPA considers the impact of this event on the Bulk Electric System to be minimal. 15. Mitigation Plan attached: Yes or No 16. Additional Comments: IMPA believes that the following additional information needs to be considered in making the determination if a potential non-compliant issue exists with R2 of VAR-002-1.1a. First, while the Anderson Station is in the AEP zone of the PJM footprint, it is physically interconnected with Duke Energy Indiana, which is in the Midwest ISO. Thus, the Anderson Station is located in PJM at its border with the Midwest ISO. In the development of IMPA’s standards compliance program, there was confusion between PJM, AEP and Duke regarding the appropriate party to provide a voltage schedule to IMPA for its Anderson Station. Ultimately, these parties agreed that AEP should provide the voltage schedule. Upon learning on June 2, 2009 that no station voltage was recorded at the Anderson Station on January 25, 2009, IMPA contacted Duke in an attempt to obtain historical voltage information at the Anderson Station from them. IMPA obtained this information from Duke on June 5, 2009. Secondly, since the Anderson Station transformers do not have automatic tap changers, the station voltage is completely controlled by Duke when IMPA has no generation online. IMPA can affect the station voltage when generation is online, but coordination is required with Duke to prevent either company’s generating units or other equipment from working against one another. Third, IMPA notes that the Anderson Station was still well within the PJM Default Generator Voltage Schedule for the 138kV voltage level (Manual 03, Section 3). When referencing the PJM Default Generator Voltage Schedules table, PJM requires a voltage range of 139.5 kV +/- 3.5 kV. During the event the station voltage was within these limits. Finally, the first voltage schedule given to IMPA by AEP had a 139 kV +/- 0.5% schedule (hours of operation 07:00 to 00:00). IMPA communicated to AEP that the variance of only +/- 0.5% in the first schedule was not attainable and negotiated a new schedule containing a variance of +/- 1.0%. While this was an improvement on

x


the original schedule, IMPA was still unsure if the AEP variance level was reasonable, but IMPA decided to wait and see how this new voltage schedule would work in real-time operations before considering a request to AEP for a wider voltage range. As a result of this event, IMPA has taken steps to ensure that station voltage readings are always recorded in our operating logs at the Anderson Station when generating units are online. In addition, IMPA has added station voltage readings to its SCADA database. Finally, IMPA will be contacting AEP to negotiate a more realistic voltage schedule for our Anderson Station, which is more consistent with actual operating circumstances at the site. IMPA will discuss with AEP why it is using a tighter voltage schedule for the Anderson Station, if other generating units located in the PJM area are on a more relaxed voltage schedule, to ensure that the required voltage schedule is, in fact, necessary and appropriate to ensuring the reliability of the Bulk Electric System. 17. Officer Verification: I understand that this information is being provided as required by the

ReliabilityFirst Compliance Monitoring and Enforcement Program. Any review of this violation will require all information certified on this form be supported by appropriate documentation.

Officer’s Name: Gayle Mayo

Title: Executive Vice President and Chief Operating Officer

E-mail address: [email protected] Phone: 317-573-9955

Primary Compliance Contact: Scott Berry


E-mail Submittals to [email protected] Subject Line: Violation Self-Report For any questions regarding compliance submittals, please e-mail [email protected]. a. Report on a requirement basis. If the violation is to a sub requirement, or multiple sub requirements, include all sub requirements relevant to this violation.

Attachment b

IMPA’s Self-Report for PRC-005-1 R2.1 dated September 29, 2009

Self-Report Form – 9-9-09 – Revision II

COMPLIANCE MONITORING AND ENFORCEMENT PROGRAM

VIOLATION SELF-REPORTING FORM

This Violation Self-Reporting Form can be used for submittals via e-mail for violations of the Reliability Standards identified by a self- assessment. 1. Date: September 29, 2009 2. Registered Entity: Indiana Municipal Power Agency

3. NERC Registry ID: NCR00796 Joint Registration ID (JRO) (if applicable:)

4. Multiple Regional Registered Entity (MRRE) Regional Affiliates (if applicable:) 5. Reliability Standard: PRC-005-1 Requirement a: R2.1 6. Reporting for registered function(s): Generator Owner 7. Date Violation was Discovered: September 28, 2009

Beginning Date of Violation: May 31, 2009 End or Expected End Date of Violation: November 20, 2009 8. Has this violation been previously reported: Yes or No

If yes, Provide NERC Violation ID number: 9. Has this violation been reported to another region(s): Yes or No

If yes, Provide Region(s): 10. Is the violation still occurring: Yes or No 11. Detail description and cause of the violation: During an internal review in preparation for submission of a self certification of compliance with PRC-005-1 on September 28, 2009, IMPA discovered that it had not performed testing for certain protection system components at its Anderson Combustion Turbine Station (Anderson Station) within the 24 month period specified in IMPA’s Generation Protection System Maintenance and Testing program. The protection system components that IMPA failed to test within the 24 month period include:

- Breaker failure relays on Generator Breakers 2, 3, 4, 5, 7, and 8 - Potential Transformers (PTs) on Anderson Unit 3 and 138 kV Bus 2 and 3 - Current Transformers (CTs) on Anderson Units 1, 2 and 3 - DC control circuitry on Anderson Unit 3

IMPA has determined the causes of these potential violations as follows:

x

x

x


- The breaker failure relays were scheduled to be tested in April 2008, but the contractor failed to perform the tests and the IMPA staff supervising the contractor did not discover the contractor’s error.

- The PTs were scheduled to be tested in the spring of 2009, but the tests were repeatedly delayed due to wet weather, and were finally delayed until the fall of 2009 because IMPA has a policy of not taking maintenance outages on generating units during the summer peak season.

- Until IMPA revised its Generation Protection System Maintenance and Testing program on September 29, 2009, IMPA’s policy has been to test CTs upon commissioning and then to limit tests of in-service CTs to situations where an operational problem with the CT was suspected. IMPA has recently learned that new test equipment makes the testing of in-service CTs more feasible and has revised its policy to require testing of CTs every five years.

- IMPA has determined that the failure to perform trip checks on the DC control circuitry for Anderson Unit 3 was caused by staff oversight, since DC trip checks were scheduled and performed for the control circuitry on Anderson Units 1 and 2 in December 2007 but were not scheduled or performed for Anderson Unit 3 until July 10, 2009 after the original oversight was discovered.

12. Violation Risk Factor: Lower ( ) – Medium ( ) – High ( x ) – Not Specified ( ) Select One 13. Violation Severity Level: Lower ( ) – Moderate ( X ) – High ( ) – Severe ( ) Select One

Provide justification for this determination: IMPA has 190 devices that are subject to R2.1 of PRC-005-1. Ninety-one of these devices, or 48% of the total number of devices, were not tested as required by R2.1 of PRC-005-1.

14. Provide a determination of the Potential Impact to the Bulk Electric System: The failure to perform timely tests of the generator protective system components noted above had the following potential impacts to the Bulk Electric System:

- Failure to perform timely tests of the breaker failure relays could have resulted in delayed detection of relay failures. Although relay failures in and of themselves would not have had any impact on the Bulk Electric System, a failure of Relay 2 or 8 in combination with a subsequent failure of Breaker 2 or 8 would have opened the breakers on Duke’s 138 kV Noblesville to Cadiz transmission line. For Relay 8, which is a digital relay, relay failure would have activated a warning light on an annunciator panel in the substation control house. That annunciator panel is checked monthly, and the warning light would have been reported for follow up action. Relay 2, which is an electro-mechanical relay, does not activate a warning light. Failure of relays 3, 4, 5, and 7 would not have opened the breakers on the Noblesville to Cadiz line and would have had a minimal impact on the Bulk Electric System.

- Failure to perform timely tests on the PTs would have minimal impact on the Bulk Power System. A failure of the PTs on Unit 3 would have activated an alarm on the Mark VI control system, which is checked at least weekly. Further, failure of the PTs on Bus 2 or 3 would prevent the affected generating unit from synchronizing with the grid. Since at least one these generating units was operated (and synchronized) on May 27, May 28, June 1, July 28 and September 24, 2009, the PTs have been effectively tested through the operation of these generating units.

- Failure to perform timely tests on the CTs would have minimal impact on the Bulk Power System. If the CTs were not working properly, they would cause the generating units to trip. Since the generating units have been operated on the dates noted above, this effective demonstrates that the CTs are operating properly.

- Although the DC control circuits on Anderson Unit 3 were not formally tested through the performance of trip checks, they were routinely exercised during the operation of plant and substation equipment and were demonstrated to operate properly as recently as June 1, 2009. This evidence indicates that the DC control circuits for Anderson Unit 3 were operating properly and did not pose a threat to the reliability of the Bulk Electric System even though they had not been formally tested within the 24 month period specified by IMPA’s testing policy.

x


15. Mitigation Plan attached: Yes or No 16. Additional Comments: In May 2007 IMPA developed its first written policy for Generation Protection System Maintenance and Testing Intervals. That policy required testing of all generation protection systems within 24 months of the date the policy was established, not the date of previous tests. At that time IMPA defined generation protection systems as protective relays, and scheduled such relays to be tested at the same time as other protective systems such as generator breakers, switches and transformers. IMPA’s initial policy did not contemplate testing of PTs, CTs, station batteries or DC control systems as a part of this policy or on the same schedule as the protective relays. All of these devices were actually tested between May 30, 2007, when IMPA established its initial policy and May 31, 2009 (the 24 month window allowed by the initial policy) except for the devices that are the subject of this self report. According to IMPA’s records, the devices that are the subject of this self report were last tested as follows:

- Breaker failure relays 2, 3, 4, and 5 were tested on December 6, 2004. Relays 7 and 8 were tested on March 11, 2005.

- PTs for Unit 3 were tested on February 4, 2004, during unit commissioning. PTs on Bus 2 and 3 were tested on November 15 and 9, 2004, respectively.

- CTs on Units 1 and 2 were tested on June 15, 1992, during unit commissioning. CTs on Unit 3 were tested on February 4, 2004, during unit commissioning.

- The DC control circuitry on Unit 3 was tested on July 10, 2009. Prior to that, it was tested on February 4, 2004.

After the implementation of its initial policy for Generation Protection System Maintenance and Testing Intervals, IMPA learned that the NERC definition of Protection Systems includes “protective relays, associated communication systems, voltage and current sensing devices, station batteries and DC control circuitry.” IMPA has now revised its policy for maintenance and testing of generator protection systems to include testing of these additional elements and has revised testing intervals based on industry practices, manufacturer’s recommendations and other information. 17. Officer Verification: I understand that this information is being provided as required by the

ReliabilityFirst Compliance Monitoring and Enforcement Program. Any review of this violation will require all information certified on this form be supported by appropriate documentation.

Officer’s Name: Gayle Mayo

Title: Executive Vice President and Chief Operating Officer


Primary Compliance Contact: Scott Berry


E-mail Submittals to [email protected] Subject Line: Violation Self-Report For any questions regarding compliance submittals, please e-mail [email protected]. a. Report on a requirement basis. If the violation is to a sub requirement, or multiple sub requirements, include all sub requirements relevant to this violation.

Attachment c

Settlement Agreement by and between ReliabilityFirst and IMPA executed June 30, 2010

Settlement Agreement Between IMPA and ReliabilityFirst Page 1 of 13

In re: INDIANA MUNICIPAL POWER ) Docket Nos. RFC200900157; AGENCY ) RFC200900190; and ) RFC201000239 ) NERC Registry ID No. NCR00796 ) NERC Reliability Standards: ) VAR-002-1.1a, R2; ) PRC-005-1, R2.1; and ) PRC-005-1, R1

SETTLEMENT AGREEMENT

BETWEEN RELIABILITYFIRST CORPORATION

AND INDIANA MUNICIPAL POWER AGENCY I. INTRODUCTION

1. ReliabilityFirst Corporation (“ReliabilityFirst”) and Indiana Municipal Power Agency (“IMPA”) enter into this Settlement Agreement (“Agreement”) to resolve alleged violations by IMPA of the NERC Reliability Standards VAR-002-1.1a, R2, PRC-005-1, R2.1, and PRC-005-1, R1.

II. STIPULATION OF FACTS

2. IMPA and ReliabilityFirst agree and stipulate to this Agreement in its entirety.

The facts stipulated herein are stipulated solely for the purpose of resolving between IMPA and ReliabilityFirst the subject matter of this Agreement and do not constitute admissions or stipulations for any other purpose. IMPA neither admits nor denies that the facts stipulated herein constitute violations of NERC Reliability Standards VAR-002-1.1a, R2, PRC-005-1, R2.1, and PRC-005-1, R1.

A. Background.

3. Indiana Municipal Power Agency (“IMPA”) is a not-for-profit, political subdivision of the State of Indiana created in 1980 by a group of municipally-owned electric utilities pursuant to Indiana Code Section 8-1-2.2 et seq. IMPA, called a joint action agency, was formed so these utilities could share generation and transmission resources, allowing member cities and towns to provide

electricity more economically to their customers. Currently, 52 Indiana cities and towns are members of IMPA. The Agency also has a long-term full requirements power contract with the Village of Blanchester, Ohio.

4. IMPA member utilities purchase their power requirements through IMPA and deliver that power to the residents and companies in their respective service territories. IMPA has annual revenues approaching $300 million. IMPA's assets total approximately $1 billion, which include generation sites and joint transmission system ownership.

5. IMPA has two jointly-owned generating units, Trimble County Unit 1 and Gibson Station Unit 5. Trimble County Unit 1 is a 514 MW coal-fired electric generating unit located in northern Kentucky, which IMPA jointly owns with Louisville Gas and Electric and Illinois Municipal Electric Agency. Gibson Station Unit 5 is a 625 MW coal-fired generating unit located in southwestern Indiana, which IMPA jointly owns with Duke Energy Indiana and Wabash Valley Power Association.

6. IMPA has seven wholly-owned generating units aggregating 419 MW. There are two 41 MW units and one 85 MW unit located in Anderson; two 41 MW units located near Richmond; and two 85 MW units located in Indianapolis. The Anderson and Richmond units operate primarily on natural gas and maintain an inventory of fuel oil as an alternative fuel. The Indianapolis units operate solely on natural gas. The generating facility involved in the alleged violations is the Anderson Combustion Turbine Station (“Anderson Station”).

7. ReliabilityFirst staff confirmed that IMPA is registered on the NERC Compliance Registry as a Generator Owner, Generator Operator, Purchasing-Selling Entity, Load Serving Entity, and Reliability Planner in the ReliabilityFirst region with the NERC Registry Identification Number of NCR00796 and is, therefore, subject to compliance with VAR-002-1.1a, R2, PRC-005-1, R2.1, and PRC-005-1, R1.

B. Alleged Violation of VAR-002-1.1a, R2. – RFC200900157.

8. In pertinent part, VAR-002-1.1a, R2 states: R2. Unless exempted by the Transmission Operator, each Generator Operator shall maintain the generator voltage or Reactive Power output (within applicable Facility Ratings) as directed by the Transmission Operator.

R2.1 When a generator’s automatic voltage regulator is out of service, the Generator Operator shall use an alternative method to control the generator voltage and reactive output to meet the voltage or Reactive Power schedule directed by the Transmission Operator.

Settlement Agreement Between IMPA and ReliabilityFirst

Page 2 of 13

R2.2 When directed to modify voltage, the Generator Operator shall comply or provide an explanation of why the schedule cannot be met.

9. On June 24, 2009, IMPA self-reported potential noncompliance with VAR-002-1.1a, R2. During an internal audit conducted on June 2, 2009, IMPA discovered three dates on which its Anderson Station combustion turbine generating units produced power but no station voltage reading was recorded in its operating logs. After acquiring historical voltage information from Duke Energy Indiana, IMPA found that the station voltage on one of those dates, January 25, 2009, was higher than the station voltage schedule provided by American Electric Power (AEP).1

10. Before IMPA brought the generating units online, the system voltage was

approximately 142.5 kV, already higher than the voltage specified in the AEP voltage schedule (139 kV +/- 1%). When IMPA connected the generating units to the station, the units brought the station voltage down to approximately 141.8 kV, still not within the AEP voltage schedule.

11. While running the three units at the Anderson Station, IMPA’s operators had numerous operational issues that they had to address in order to keep generation online. Once the operators resolved these issues and prepared to take voltage readings, they received a call from IMPA’s control center to shut down the units at PJM’s request.

12. IMPA did not receive an exemption from AEP for the circumstances that occurred

on January 25, 2009, when the station voltage was higher than the AEP voltage schedule.

13. ReliabilityFirst alleges that IMPA failed to maintain its generator voltage output as directed by the Transmission Operator, i.e., AEP, because the station voltage was not lowered to within the AEP voltage schedule on January 25, 2009 and there was no communication to AEP to allow for an exemption.

C. Alleged Violation of PRC-005-1, R2.1 – RFC200900190.

14. In pertinent part, PRC-005-1, R2 states:

R2. Each Transmission Owner and any Distribution Provider that owns a transmission Protection System and each Generator Owner that owns a generation Protection System shall provide documentation of its Protection System maintenance and testing program and the implementation of that program to its Regional Reliability Organization

1 PJM is the Transmission Operator, but delegated responsibility to AEP to provide a voltage schedule for the IMPA Anderson Station generating units.


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on request (within 30 calendar days). The documentation of the program implementation shall include:

R2.1. Evidence Protection System devices were maintained and tested within the defined intervals.

15. On September 29, 2009, IMPA self-reported potential noncompliance with PRC-

005-1, R2.1. IMPA failed to perform testing for certain protection system devices at its Anderson Station.

16. In May 2007, IMPA developed its first written protection system maintenance and testing program (“Program”). The Program required testing of all generation protection systems within 24 months of the date the Program was established. At that time IMPA defined generation protection systems as protective relays. IMPA’s Program did not contemplate testing of PTs, CTs, station batteries or DC control circuitry as a part of this Program or on the same testing schedule as the protective relays.2 However, all protective relays, PTs, CTs, station batteries, and DC control circuitry were actually tested between May 30, 2007, when IMPA established its Program, and May 31, 2009 (the 24-month window defined by the Program) except for the devices described below.

17. IMPA failed to test six breaker failure relays on generator protection breakers pursuant to its Program. IMPA scheduled the breaker failure relays to be tested in April 2008, but IMPA’s contractor failed to perform the tests and IMPA staff supervising the contractor did not discover the error.

18. IMPA failed to test one DC control circuitry on Anderson Unit 3. IMPA’s failure to perform trip checks on the DC control circuitry for Anderson Unit 3 was the result of staff oversight. IMPA had scheduled and performed DC trip checks for the DC control circuitry on Anderson Units 1 and 2 in December 2007 but failed to schedule or perform DC trip checks for the DC control circuitry for Anderson Unit 3 until July 10, 2009.

19. IMPA failed to test seven of 21 PTs on Anderson Unit 3 and failed to test all of its 101 CTs on Anderson Units 1, 2, and 3.

20. IMPA indicated to ReliabilityFirst that all protection system devices affected by the alleged violation had a condition of “Good” or “Pass” during the during the test interval immediately prior to the missed test interval, and upon completion of

2 Because the Program did not include PTs, CTs, station batteries or DC control circuitry, IMPA’s failure to test these devices cannot constitute a violation of PRC-005-1, R2.1 because the Program did not define any testing intervals for these devices to which IMPA failed to comply. However, the Program’s failure to include testing of PTs, CTs, station batteries or DC control circuitry in its Program is an alleged violation of PRC-005-1, R1, which is addressed in Section II (D) of this Settlement Agreement.


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the deficient testing. IMPA did not discover any problems with the condition of any of the affected devices.

21. ReliabilityFirst alleges that IMPA failed to test protection system devices within the defined intervals of its Program.

D. Alleged Violation of PRC-005-1, R1 – RFC201000239.

22. PRC-005-1, R1 states: R1. Each Transmission Owner and any Distribution Provider that owns a transmission Protection System and each Generator Owner that owns a generation Protection System shall have a Protection System maintenance and testing program for Protection Systems that affect the reliability of the BES. The program shall include: R1.1. Maintenance and testing intervals and their basis. R1.2. Summary of maintenance and testing procedures.

23. IMPA’s September 29, 2009 self-report of PRC-005-1, R2.1 and January 7, 2010 response to a ReliabilityFirst request for information indicated that an alleged violation of PRC-005-1, R1 also occurred.

24. In May 2007, IMPA developed its first written protection system maintenance and testing program (“Program”). The Program required testing of all generation protection systems within 24 months of the date the policy was established. At that time IMPA defined protection systems only to include protective relays. As such, IMPA failed to include PTs, CTs, station batteries, or DC control circuitry in its Program.

25. Although the devices were not included in IMPA’s Program, all PTs, CTs, station batteries, and DC control circuitry were actually tested between May 30, 2007, when IMPA established its Program, and May 31, 2009 (the 24 month window allowed by the Program), except for the devices described in the alleged violation of PRC-005-1, R2.1.

26. IMPA indicated to ReliabilityFirst that there have been no problems with operability of any of the PTs, CTs, station batteries, or DC control circuitry. IMPA’s revised Program includes PTs, CTs, station batteries, and DC control circuitry. The results of IMPA’s latest testing indicate that all protection system devices are working and are in good condition.

27. ReliabilityFirst alleges that IMPA failed to include maintenance and testing intervals and their basis and a summary of maintenance and testing procedures in its Program for PTs, CTs, station batteries, and DC Control circuitry.


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III. RISK CONSIDERATIONS AND COMPLIANCE CULTURE

A. Risk Considerations for VAR-002-1.1a, R2 – RFC200900157.

28. VAR-002-1.1a, R2 has a Violation Risk Factor (“VRF”) of “Medium,” consistent with the VRF Matrix promulgated by NERC. The duration of this alleged violation, for purposes of penalty determination, is January 25, 2009. The Mitigation Plan included preventive measures only and IMPA completed all milestones in the Mitigation Plan by September 11, 2009. Pursuant to Section 316A(b) of the Federal Power Act (16 U.S.C. § 825o-1),3 it is appropriate to apply this penalty on a daily basis for the duration of the violation.

tion.

29. ReliabilityFirst finds that this alleged violation did not pose a substantial risk to

the Bulk Electric System because the units produced power for a very short period of time and actually lowered the system voltage to a level closer to the station voltage schedule provided by AEP. The units were dispatched by PJM for generation and not for voltage support, and the Anderson Station was still within the PJM Default Generator Voltage Schedule for the 138kV voltage level (139.5 kV +/- 3.5 kV).

B. Risk Considerations for PRC-005-1, R2.1 – RFC200900190.

30. PRC-005-1, R2.1 has a VRF of “High,” consistent with the VRF Matrix promulgated by NERC. The duration of this alleged violation, for purposes of penalty determination, is from June 18, 2007 to November 30, 2009, when IMPA completed all milestone activities in its Mitigation Plan. Pursuant to Section 316A(b) of the Federal Power Act (16 U.S.C. § 825o-1),4 it is appropriate to apply this penalty on a daily basis for the duration of the viola

31. ReliabilityFirst finds that this alleged violation did not pose a substantial risk to the Bulk Electric System because all protection system devices affected by the alleged violation had a condition of “Good” or “Pass” during the during the test interval immediately prior to the missed test interval, and upon completion of the deficient testing. IMPA did not discover any problems with the condition of any of the affected devices.

32. Although the DC control circuitry on Anderson Unit 3 was not formally tested through the performance of trip checks, it was routinely exercised during the operation of plant and substation equipment and was demonstrated to operate properly as recently as June 1, 2009. This evidence indicates that the DC control circuitry for Anderson Unit 3 was operating properly and did not pose a threat to

3 See, also, NERC Sanction Guidelines, at § 3.20 (attached as Appendix 4(B) to the NERC Rules of Procedure).

4 Id.


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the reliability of the Bulk Electric System. IMPA indicated that failure to perform timely tests of the breaker failure relays could have resulted in delayed detection of relay failures.

33. IMPA tested PTs every other year when doing unit calibrations and generator control inspections at the site. IMPA tested CTs at the time of commissioning, and performed additional testing if an operational problem with a CT was suspected. A failure of the PTs on Unit 3 would have activated an alarm on the Mark VI control system, which is checked at least weekly. If the CTs were not operating properly, they would cause the generating units to trip. Since at least one of the generating units was operated on May 27, May 28, June 1, July 28, and September 24, 2009, this effectively demonstrates that the CTs were and continue to operate properly.

C. Risk Considerations for PRC-005-1, R1 – RFC201000239.

34. PRC-005-1, R1 has a VRF of “High,” consistent with the VRF Matrix

promulgated by NERC. The duration of this alleged violation, for purposes of penalty determination, is from June 18, 2007, to November 30, 2009, when IMPA completed all milestone activities in its Mitigation Plan. Pursuant to Section 316A(b) of the Federal Power Act (16 U.S.C. § 825o-1),5 it is appropriate to apply this penalty on a daily basis for the duration of the violation.

35. ReliabilityFirst finds that this alleged violation did not pose a substantial risk to

the Bulk Electric System because although the devices were not included in IMPA’s Program, all PTs, CTs, station batteries, and DC control circuitry were actually tested between May 30, 2007, when IMPA established its Program, and May 31, 2009 (the 24 month window allowed by the Program), except for the devices described above in the alleged violation of PRC-005-1, R2.1.

D. IMPAs Culture of Compliance.

36. ReliabilityFirst commends certain aspects of IMPA’s compliance program. For example, IMPA’s compliance program has the support and participation of senior management, and seven of the nine positions with the highest responsibility for implementing IMPA’s internal compliance program are Assistant Vice President rank or higher. IMPA also conducts annual internal self-audits of Reliability Standards.

5 Id.


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IV. MITIGATING ACTIONS AND PENALTY A. Mitigating Actions for VAR-002-1.1a, R2 – RFC200900157.

37. On September 18, 2009, IMPA submitted to ReliabilityFirst its mitigation plan

(“Mitigation Plan”) to address the alleged violation of VAR-002-1.1a, R2 set forth in this agreement. See, NERC Mitigation Plan ID # MIT-09-2059, (attached as Attachment A). ReliabilityFirst accepted the Mitigation Plan on October 23, 2009, and on this same date submitted the accepted Mitigation Plan to NERC for approval. NERC approved the Mitigation Plan on October 26, 2009 and, on this same date, submitted the Mitigation Plan to the Federal Energy Regulatory Commission (the “Commission”) as confidential, non-public information.

38. On October 29, 2009, IMPA submitted to ReliabilityFirst a certification of completion of the Mitigation Plan, which stated that the Mitigation Plan was completed as of September 11, 2009. See, Certification of Mitigation Plan Completion (attached as Attachment B). On October 29, 2009, IMPA submitted to ReliabilityFirst evidence of its completion of the Mitigation Plan.

39. In the Mitigation Plan, IMPA outlines actions necessary to mitigate the alleged

violation. a. IMPA re-trained the combustion turbine operators on the procedure for

documenting and maintaining the voltage schedule for system voltage.

b. IMPA entered an Anderson Substation system voltage data point into its SCADA system that will be recorded and used in case a system voltage point reading is not recorded for a time period in which the gas turbines are online.

c. IMPA revised its procedure for documenting and maintaining the voltage

schedule for system voltage to ensure the awareness is raised in its operations staff for documenting and/or maintaining a generator’s automatic voltage regulator and the voltage schedule for system voltage.

d. IMPA sent a letter to AEP to request a revised voltage schedule for its

Anderson Station, which is more consistent with the actual operating circumstances at the site and that references PJM’s Default Generator Voltage Schedule.

e. IMPA directed the power system coordinators and the combustion turbine

operators to review the revised procedure for documenting and maintaining the voltage schedule for system voltage, and to sign an IMPA staff review record sheet.


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f. IMPA received a revised voltage schedule from AEP that is more consistent with the actual operating circumstances at the site. The revised voltage schedule is 139.5 kV+- 2.5%.

40. ReliabilityFirst reviewed the evidence IMPA submitted in support of its

certification of completion of the Mitigation Plan. ReliabilityFirst verified that all actions specified in the Mitigation Plan were successfully completed. On November 16, 2009, ReliabilityFirst verified that the Mitigation Plan was completed in accordance with its terms. See, Summary and Review of Evidence of Mitigation Plan Completion (attached as Attachment C).

B. Mitigating Actions for PRC-005-1, R2.1 – RFC200900190 and PRC-005-1, R1 -

RFC201000239. 41. On May 6, 2010, IMPA submitted to ReliabilityFirst its mitigation plan

(“Mitigation Plan”) to address the alleged violations of PRC-005-1, R2.1 and PRC-005-1, R1 set forth in this agreement. See, NERC Mitigation Plan ID# MIT-07-2544, (attached as Attachment D). ReliabilityFirst accepted the Mitigation Plan on June 4, 2010, and on this same date submitted the accepted Mitigation Plan to NERC for approval. NERC approved the Mitigation Plan on June 14, 2010 and, on this same date, submitted the Mitigation Plan to the Commission as confidential, non-public information.

42. In the Mitigation Plan, IMPA outlines actions necessary to mitigate the alleged violation.

a. IMPA hired a different, fully qualified contractor to test the relays missed on generator protection breakers. These relays were satisfactorily tested.

b. IMPA satisfactorily tested the PTs.

c. IMPA satisfactorily tested the CTs.

d. IMPA revised its Program to include all the protection system devices (per NERC’s definition). The testing intervals were revised based on industry practices, manufacturer’s recommendations and other information.

e. IMPA developed and formally approved a guideline for tracking the testing of protection system devices.

f. Prior to formal training, IMPA briefed its field personnel on the revised Program and guideline for tracking the testing of protection system devices.


Page 9 of 13

g. IMPA conducted training on its revised Program and the new guideline for tracking the testing of protection system devices.

43. On June 15, 2010, pursuant to Section 6.6 of the ReliabilityFirst Compliance

Monitoring and Enforcement Program, IMPA submitted to ReliabilityFirst a certification of completion of the Mitigation Plan, which stated that the Mitigation Plan was completed as of November 30, 2009, and provided evidence of completion to ReliabilityFirst. See, Certification of Mitigation Plan Completion (attached as Attachment E). On June 15, 2010, IMPA submitted to ReliabilityFirst evidence of its completion of the Mitigation Plan. ReliabilityFirst will verify and promptly report to NERC IMPA’s completion of the Mitigation Plan.

C. Monetary Penalty.

44. Based upon the foregoing, IMPA shall pay a monetary penalty of $22,000 to

ReliabilityFirst. 45. ReliabilityFirst shall present a $22,000 invoice to IMPA within 20 days after the

Agreement is approved by the Commission or affirmed by operation of law. Upon receipt, IMPA shall have 30 days to remit payment. ReliabilityFirst will notify NERC if it does not timely receive the payment from IMPA.

46. If IMPA fails to timely remit the $22,000 monetary penalty payment to

ReliabilityFirst, interest will commence to accrue on the outstanding balance, pursuant to 18 C.F.R. § 35.19 (a)(2)(iii), on the earlier of (a) the 31st day after the date on the invoice issued by ReliabilityFirst to IMPA for the $22,000 monetary penalty payment or (b) the 51st day after the Agreement is approved by the Commission or operation of law.

47. ReliabilityFirst may deem IMPA’s failure to timely remit the $22,000 penalty

payment as either the same alleged violation identified in this Agreement or additional violation(s) or both, and, if so deemed, IMPA will be subject to new or additional enforcement, penalty, or sanction actions in accordance with the NERC Rules of Procedure. IMPA shall retain all rights to defend against such additional actions in accordance with the NERC Rules of Procedure.

V. ADDITIONAL TERMS

48. ReliabilityFirst and IMPA agree that this Agreement is in the best interest of Bulk Electric System reliability.

49. The terms and conditions of the Agreement are consistent with the regulations and orders of the Commission and the NERC Rules of Procedure.


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50. ReliabilityFirst shall report the terms of all settlements of compliance matters to NERC. NERC will review the Agreement for the purpose of evaluating its consistency with other settlements entered into for similar violations or under similar circumstances. Based on this review, NERC will either approve or reject this Agreement. If NERC rejects the Agreement, NERC will provide specific written reasons for such rejection and ReliabilityFirst will attempt to negotiate with IMPA a revised settlement agreement that addresses NERC’s concerns. If a settlement cannot be reached, the enforcement process shall continue to conclusion. If NERC approves the Agreement, NERC will (a) report the approved settlement to the Commission review and approval by order or operation of law and (b) publicly post the alleged violation and the terms provided for in this Agreement.

51. This Agreement shall become effective upon the Commission’s approval of the

Agreement by order or operation of law or as modified in a manner acceptable to the parties.

52. IMPA agrees that this Agreement, when approved by NERC and the Commission,

shall represent a final settlement of all matters set forth herein and binds IMPA to perform the actions enumerated herein. IMPA expressly waives its right to any hearing or appeal concerning any matter set forth herein, unless and only to the extent that IMPA contends that any NERC or Commission action constitutes a material modification to this Agreement.

53. ReliabilityFirst reserves all rights to initiate enforcement actions against IMPA in accordance with the NERC Rules of Procedure in the event that IMPA fails to comply with any of the terms or conditions of this Agreement. In the event IMPA fails to comply with any of the terms or conditions of this Agreement, ReliabilityFirst may initiate an action or actions against IMPA to the maximum extent allowed by the NERC Rules of Procedure, including, but not limited to, the imposition of the maximum statutorily allowed monetary penalty. IMPA will retain all rights to defend against such action or actions in accordance with the NERC Rules of Procedure.

54. IMPA consents to ReliabilityFirst’s future use of conclusions, determinations, and findings set forth in this Agreement for the purpose of assessing the factors within the NERC Sanction Guidelines and applicable Commission orders and policy statements, including, but not limited to, the factor evaluating IMPA’s history of violations. Such use may be in any enforcement action or compliance proceeding undertaken by NERC or any Regional Entity or both, provided however that IMPA does not consent to the use of the conclusions, determinations, and findings set forth in this Agreement as the sole basis for any other action or proceeding brought by NERC or any Regional Entity or both, nor does IMPA consent to the use of this Agreement by any other party in any other action or proceeding.


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55. IMPA affirms that all of the matters set forth in this Agreement are true and correct to the best of its knowledge, information, and belief, and that it understands that ReliabilityFirst enters into this Agreement in express reliance on the representations contained herein, as well as any other representations or information provided by IMPA to ReliabilityFirst during any IMPA interaction with ReliabilityFirst relating to the subject matter of this Agreement.

56. Each of the undersigned warrants that he or she is an authorized representative of

the entity designated below, is authorized to bind such entity, and accepts the Agreement on the entity's behalf.

57. The signatories to this Agreement agree that they enter into this Agreement

voluntarily and that, other than the recitations set forth herein, no tender, offer, or promise of any kind by any member, employee, officer, director, agent, or representative of ReliabilityFirst or IMPA has been made to induce the signatories or any other party to enter into this Agreement.

58. The Agreement may be signed in counterparts.

59. This Agreement is executed in duplicate, each of which so executed shall be

deemed to be an original.

[SIGNATURE PAGE TO FOLLOW]

[REMAINDER OF PAGE INTENTIONALLY LEFT BLANK]


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Attachment A

Mitigation Plan (MIT-09-2059)

Submitted September 18, 2009

MIT-09-2059 RFC200900157

Attachment A

Mitigation Plan Submittal Form

Date this Mitigation Plan is being submitted: September 18, 2009

Section A: Compliance Notices & Mitigation Plan RequirementsA.1 Notices and requirements applicable to Mitigati<)ll Plans and this Submittal

Form are set forth in "Attachment A - Compliance Notices & Mitigation PlanRequirements."

A.2 This form must be used to submit required Mitigation Plans for review andacceptance by ReliabilityFirst and approval by NERC.

A.3 ~ I have reviewed Attachment A and understand that this Mitigation PlanSubmittal Form will not be accepted unless this box is checked.

Section B: Registered Entity InformationB.1 Identify your organization.

Company Name:

Company Address:

NERC Compliance Registry ID:

Indiana Municipal Power Agency

11610 North College AvenueCarmel, IN 46032

NCR00796

B.2 Identify the individual in your organization who will be the Entity Contactregarding this Mitigation Plan.

Name:

Title:

Email:

Phone:

Version 2.0 - Released 7/11/08

Gayle Mayo

Executive Vice President and ChiefOperating Officer

[email protected]

(317) 573-9955

Page 1 of 10


Date this Mitigation Plan is being submitted: Septernber18,2009

Section A: Compliance Notices & Mitigation Plan Requirements

A.I Notices and requirements applicable to Mitigati()ll Plans and this SubmittalForm are set forth in "Attaclunent A - Compliance Notices & Mitigation PlanRequirements."

A.2 This fonn must be used to submit required Mitigation Plans for review andacceptance by ReliabilityFirst and approval by NERC.

A.3 [gJ I have reviewed Attachment A and understand that this Mitigation PlanSubmittal Form will not be accepted unless this box is checked.

Section B: Registered Entity Information

B.I Identify your organization.

Company Name: Indiana Municipal Power Agency

Company Address: _11610 North College AvenueCarmel, IN 46032

NERC Compliance Registry ID: NCR00796


Name:

Title:

Email:

Phone:


Gayle Mayo


[email protected]

(317) 573-9955

Page 1 oflO

FOR PUBLIC RELEASE - NOVEMBER 30, 2010

Attachment A

Section C: Identification of Alleged or Confirmed Violation(s)Associated with this Mitigation Plan

C.1 This Mitigation Plan is associated with the following Alleged or Confirmedviolation(s) ofthe reliability standard listed below.

NERC Reliability Requirement Violation Alleged or Method ofViolation II) Standard Number Risk Factor ConfIrmed Detection (e.g.,

# Violation Date'·) Audit, Self-report,Investigation)

RFC200900 VAR-002- R2 Medium January 25, 2009 Internal Audit,157 l.1a (see C.2) Self-renort

(*) Note: The Alleged or ConfInned VIolatIOn Date shall be expressly speCIfied by the RegIstered Entity,and subject to modification by ReliabilityFirst, as: (i) the date the Alleged or Confirmed violation occurred;(ii) the date that the Alleged or Confirmed violation was self-reported; or (iii) the date that the Alleged orContinued violation has been deemed to have occurred on by ReliabilityFirst. Questions regarding thedate to use should be directed to the ReliabilityFirst contact identified in Section G of this form.

C.2 Identify the cause of the Alleged or Confirmed violation(s) identified above.Additional detailed information may be provided as an attachment.

Requirement R2 states that each Generator Operator shall maintain the generatorvoltage or Reactive Power output as directed by the Transmission Operator. OnJanuary 25,2009, Indiana Municipal Power Agency ("IMPA") did not maintainthe generator voltage at IMPA's Anderson Combustion Turbine (CT) station asdirected by the Transmission Operator, American Electric Power ("AEP"). PJMdelegated the transmission operator responsibilities to AEP in this area. Asmore fully explained in IMPA's self-report, IMPA's CT operators wereoccupied with operational problems during the 3 hours the CT station wasonline, failed to take system voltage readings, and therefore failed to take actionto bring system voltage within the voltage schedule provided by theTransmission Operator or to contact the Transmission Operator, prior to PJMordering a shutdown of the units.

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C.I This Mitigation Plan is associated with the following Alleged or Confirmedviolation(s) of the reliability standard listed below.

NERC Reliability Requirement Violation Alleged or Method ofViolation If) Standard Number Risk Factor Confll"med Detection (e.g.,

# Violation Date(-) Audit, Self-report,Investigation)

RFC200900 VAR-002- R2 Medium January 25, 2009 Intemal Audit,157 1.1 a (see C.2) Self-report

(...) Note: The Alleged or Confirmed VIOlatIOn Date shall be expressly specified by the Reglstered Enhty,and subject to modification by ReliabilityFirst, as: (i) the date the Alleged or Confinned violation occurred;(ii) the date that the Alleged or Confirmed violation was self-reported; or (iii) the date that the Alleged orConfinned violation has been deemed 10 have occurred on by ReliabilityFirst. Questions regarding thedate to use should be directed to the ReliabilityFirst contact identified in Section G of this foml.


Requirement R2 'states that each Generator Operator shall maintain the generatorvoltage or Reactive Power output as directed by the Transmission Operator. OnJanuary 25,2009, Indiana Municipal Power Agency ("IMPA") did not maintainthe generator voltage at IMPA's Anderson Combustion Turbine (CT) station asdirected by the Transmission Operator, Amelican Electric Power ("AEP"). PJMdelegated the transmission operator responsibilities to AEP in this area. Asmore fully explained in IMPA's self-report, IMPA's CT operators wereoccupied with operational problems during the 3 hours the CT station wasonline, failed to take system voltage readings, and therefore failed to take actionto bring system voltage within the voltage schedule provided by theTransmission Operator or to contact the Transmission Operator, prior to PIMordering a shutdown ofthe units.

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Attachment A

Note: Ifa formal root cause analysis evaluation was performed, submit a copyof the summary report.

C.3 Provide any additional relevant information regarding the Alleged or Confirmedviolations associated with this Mitigation Plan. Additional detailed informationmay be provided as an attachment.

The Anderson Station is physically interconnected with Duke Indiana (amember of the Midwest ISO), but is located in the AEP zone of the PJMfootprint, at its border with the Midwest ISO. During its internal investigation,IMPA found that system voltage at the Station prior to IMPA's combustionturbine units coming online on January 25,2009 was already higher, at 142.5kV, than the permitted voltage range of 139 kV +/- 1%. The IMPA units acted tolower system voltage to 141.8 kV while they were online. During the event, thestation voltage was still well within the PJM Default Generator VoltageSchedule of 139.5 kV +/- 3.5 kV (Manual 03, Section 3). IMPA's position isthat the AEP provided voltage schedule of 139 kV +/- 1% is not reasonable, norreflective of actual operating circumstances at the site. Thus, the mitigationplan, in addition to other actions, includes IMPA's successful negotiation withAEP of a more realistic voltage schedule for the Anderson Station.

Section D: Details of Proposed Mitigation Plan

Mitigation Plan Contents

D.1 Identify and describe the action plan, including specific tasks and actions thatyour organization is proposing to undertake, or which it undertook if thisMitigation Plan has been completed, to correct the Alleged or Confirmedviolations identified above in Part C.I of this form. Additional detailedinfonnation may be provided as an attachment.

The following action plan was developed and is being implemented:

1. IMPA re-trained the Combustion Turbine ("CT") Operators on the procedurefor documenting and maintaining the voltage schedule for system voltage.

2. IMPA entered an Anderson Substation system voltage data point into itsSCADA system that will be recorded and used in case a system voltage pointreading is not recorded for a time period in which the gas turbines are online.

3. IMPA revised its procedure for documenting and maintaining the voltageschedule for system voltage to ensure the awareness is raised in its operationsstaff for documenting and/or maintaining a generator's automatic voltageregulator mode and the voltage schedule for system voltage.

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Note: If a formal root cause analysis evaluation was performed, submit a copyof the summary report.

C.3 Provide any additional relevant information regarding the Alleged or Confirmedviolations associated with this Mitigation Plan. Additional detailed informationmay be provided as an attaclunent.

The Anderson Station is physically interconnected with Duke Indiana (amember of the Midwest ISO), but is located in the AEP zone ofthe PJMfootprint, at its border with the Midwest ISO. During its internal investigation,IMPA found that system voltage at the Station prior to IMPA's combustionturbine units coming online on January 25, 2009 was already higher, at 142.5kV, than the pennitted voltage range of 139 kV +/- 1%. The IMPA units acted tolower system voltage to 141.8 kV while they were online. During the event, thestation voltage was still well within the PJM Default Generator VoltageSchedule ofl39.5 kV +/- 3.5 kV (Manual 03, Section 3). IMPA's position isthat the AEP provided voltage schedule of 139 kV +/- 1% is not reasonable, norreflective ofactual operating circumstances at the site. Thus, the mitigationplan, in addition to other actions, includes IMPA's successful negotiation withAEP of a more realistic voltage schedule for the Anderson Station.



D.l Identify and describe the action plan, including specific tasks and actions thatyour organization is proposing to undertake, or which it undertook if thisMitigation Plan has been completed, to correct the Alleged or Confirmed

. violations identified above in Part C.l of this form. Additional detailedinfonnation may be provided as an attachment.

The following action plan was developed and is being implemented:

1. Il\I1PA re-trained the Combustion Turbine C'CT") Operators on the procedurefor documenting and maintaining the voltage schedule for system voltage.

2. IMPA entered an Anderson Substation system voltage data point into itsSCADA system that will be recorded and used in case a system voltage pointreading is not recorded for a time period in which the gas turbines are online.

3. IMPA revised its procedure for documenting and maintaining the voltageschedule for system voltage to ensure the awareness is raised in its operationsstaff for documenting and/or maintaining a generator's automatic voltageregulator mode and the voltage schedule for system voltage.

Version 2.0 - Released 7111108 Page 3 of 10


Attachment A

4. IMPA sent a letter to the Transmission Operator, AEP, to request a revisedvoltage schedule for its Anderson Station, which is more consistent with theactual operating circumstances at the site and that references PJM's DefaultGenerator Voltage Schedule.

5. IMPA directed the Power System Coordinators ("PSCs") and the CToperators to review the revised procedure for documenting and maintaining thevoltage schedule for system voltage. The PSCs and CT operatorsacknowledged their understanding of the revised procedure by signing an IMPAstaff review record sheet.

6. IMPA received a revised voltage schedule from AEP that is more consistentwith the actual operating circumstances at the site. The revised voltageschedule is 139.5 kV ± 2.5%. The CT Operators and PSCs were provided withthe new schedule on the date it was received.

Mitigation Plan Timeline and Milestones

0.2 Provide the date by which full implementation of the Mitigation Plan will be, orhas been, completed with respect to the Alleged or Confirmed violationsidentified above. State whether the Mitigation Plan has been fully implemented,and/or whether the actions necessary to assure the entity has retumed to fullcompliance have been completed.

The mitigation plan was fully implemented by September 11, 2009.

0.3 Enter Key Milestone Activities (with due dates) that can be used to track andindicate progress towards timely and successful completion ofthis MitigationPlan.

Key Milestone Activity Proposed!Actual Completion Date*(shall not be more than 3 months apart)

1. IMPA re-trained the Combustion Completed on June 8,2009Turbine (CT) operators on the procedurefor documenting and maintaining thevoltage schedule for system voltage.2. IMPA entered an Anderson Substation Completed on June 2, 2009system voltage data point into its SCADAsystem that will be recorded and used in ..

case a system voltage point reading is notrecorded for a time period in which the gasturbines are online.

Version 2.0 - Released 7/11/08 Page 4 oflO

,RELI:.ABJlIT--- '.

4. IMPA sent a letter to the Transmission Operator, AEP, to request a revisedvoltage schedule for its Anderson Station, which is more consistent with theactual operating circumstances at the site and that references PJM's DefaultGenerator Voltage Schedule.

5. IMPA directed the Power System Coordinators ("PSCs") and the CToperators to review the revised procedure for ,documenting and maintaining thevoltage schedule for system voltage. The PSCs and CT operatorsacknowledged their understanding of the revised procedure by signing an IMPAstaff review record sheet.

6. IMPA received a revised voltage schedule from AEP that is more consistentwith the actual operating circumstances at the site. The revised voltageschedule is 139.5 kV ± 2.5%. The CT Operators and PSCs were provided withthe new schedule on the date it was received.


D.2 Provide the date by which full implementation of the Mitigation Plan will be, orhas been, completed with respect to the Alleged or Confirmed vi,olationsidentified above. State whether the Mitigation Plan has been fully implemented,andlor whether the actions necessary to assure the entity has retumed to fullcompliance have been completed.

The mitigation plan was fully implemented by September 11,2009.

D.3 Enter Key Milestone Activities (with due dates) that can be used to track andindicate progress towards timely and successful completion of this MitigationPlan.

Key Milestone Activity Proposed/Actual Completion Date*(shall not be more than 3 months apart)

1. IMPA re-trained the Combustion Completed on June 8,2009Turbine (CT) operators on the procedurefor documenting and maintaining thevoltage schedule for system voltage.2. IMPA entered an Anderson Substation Completed on June2-, 2009system voltage data point into its SCADAsystem that will be recorded and used incase a system v.oltage point reading is notrecorded for a time period in which the gasturbines are online.



Attachment A

3. IMPA revised its procedure for Completed on August 10, 2009documenting and maintaining the voltageschedule for system voltage to ensure theawareness is raised in its operations stafffor documenting and/or maintaining agenerator's automatic voltage regulatormode and the voltage schedule for systemvoltage.4. IMPA sent a letter to the Transmission Completed on July 22, 2009Operator, AEP, to request a revised voltageschedule for its Anderson Station, which ismore consistent with the actual operatingcircumstances at the site and that referencesPJM's Default Generator VoltageSchedule.5. IMPA directed the Power System Completed on September 11,2009Coordinators ("PSCs") and the CToperators to review the revised procedurefor documenting and maintaining thevoltage schedule for system voltage. ThePSCs and CT operators acknowledged theirunderstanding of the revised procedure bysigning an IMPA staff review record sheet.6. IMPA received a revised voltage Received on July 28, 2009schedule from AEP that is more consistentwith the actual operating circumstances atthe site. The revised voltage schedule is139.5 kV ± 2.5%. The CT Operators andPSCs were provided with the new scheduleon the date it was received.

(*) Note: Additional violations could be detennined for not completing work associated with acceptedmilestones.

Version 2.0 - Released 71ll/08 Page 5 of 10

-~"~' =~.._ , -::

3. IMPA revised its procedure for Completed on August 10,2009documenting and maintaining the voltageschedule for system voltage to ensure theawareness is raised in its operations stafffor documenting and/or maintaining agenerator's automatic voltage regulatormode and the voltage schedule for systemvolt'age.4. IMPA sent a letter to the Transmission Completed on July 22, 2009Operator, AEP, to request a revised voltageschedule for its Anderson Station, which ismore consistent with the actual operatingcircumstances at the site and that referencesPJM's Default Generator VoltageSchedule.5. IMPA directed the Power System Completed on September 11, 2009Coordinators ("PSCs") and the CToperators to review the revised procedurefor documenting and maintaining thevoltage schedule for system voltage. ThePSCs and CT operators acknowledged theirunderstanding ofthe revised procedure bysigning an IMPA staff review record sheet.6. IMPA received a revised voltage Received on July 28, 2009schedule from AEP that is more consistentwith the actual operating circumstances atthe site. The revised voltage schedule is139.5 kV ± 2.5%. The CT Operators andPSCs were provided with the new scheduleon the date it was received.


Version 2.0 - Released 7/11/08 Page 5 of10


Attachment A

Section E: Interim and Future Reliability Risk

Abatement of Interim BPS Reliability Risk

E.l While your organization is implementing this Mitigation Plan the reliability ofthe Bulk Power System (BPS) may remain at higher risk or be othelwisenegatively impacted until the plan is successfully completed. To the extent theyare, or may be, known or anticipated: (i) identify any such risks or impacts; and(ii) discuss any actions that your organization is planning to take to mitigate thisincreased risk to the reliability of the BPS. Additional detailed informationmay be provided as an attachment.

The violation was discovered on June 5, 2009 as a result of an internalcompliance audit. Within a few days of the discovery of the violation, IMPA'sCT operators received re-training and the Anderson Substation system voltagedata point was entered in the SCADA system. IMPA has revised its procedurefor documenting and maintaining the Anderson Substation system voltage.IMPA has also obtained and implemented a revised voltage schedule from AEPthat is more consistent with the actual operating circmnstances at the site. Bycompleting these tasks; IMPA greatly reduced any 11sks or negative impacts tothe Bulk Power System during the implementation period of this MitigationPlan.

Prevention of Future BPS Reliability Risk

E.2 Describe how successful completion of this Mitigation Plan by yourorganization will prevent or minimize the probability that the reliability of theBPS incurs Miher risk of similar violations in the future. Additional detailedinformation may be provided as an attachment.

Through the successful completion of this Mitigation Plan, IMPA gave retraining to CT operators and now records a system voltage data point in itsSCADA system. The procedure for maintaining and documenting the AndersonSubstation system voltage was revised to ensure the importance ofthis voltageschedule is raised among the IMPA operational staff employees. IMPArequested and received a revised voltage schedule from AEP that is very similarto PJM's Default Generator Voltage Schedule which allows for a wider range ofsystem voltage values in its scheduled range. Thus IMPA believes the risk offuture violations of the voltage schedule have been minimized, ifnot completelyprevented. Upon the full implementation of this mitigation plan on September11,2009, the PSCs and the CT operators have reviewed and understood therevised procedure for documenting and maintaining the voltage schedule andwhat actions would need to be taken if voltage could not be controlled to withinthe schedule's specifications.

Version 2.0 - Released 7/11/08 Page 6 ofl0



E.1 While your organization is implementing this Mitigation Plan the reliability ofthe Bulk Power System (BPS) may remain at higher risk or be otherwisenegatively impacted until the plan is successfully completed. To the extent theyare, or may be, known or anticipated: (i) identify any such risks or impacts; and(ii) discuss any actions that your organization is planning to take to mitigate thisincreased risk to the reliability of the BPS. Additional detailed informationmay be provided as an attachment.

The violation was discovered on June 5, 2009 as a result of an internalcompliance audit. Within a few days of the discovery of the violation, IMPA'sCT operators received re-training and the Anderson Substation system voltagedata point was entered in the SCADA system. IMPA has revised its procedurefor documenting and maintaining the Anderson Substation system voltage.IMPA has also obtained and implemented a revised voltage schedule from AEPthat is more consistent with the actual operating circumstances at the site. Bycompleting these tasks; IMPA greatly reduced any lisks or negative impacts tothe Bulk Power System duIing the implementation period of this MitigationPlan.

Prevention of Future BPS Reliability Risl<

E.2 Describe how successful completion of this Mitigation Plan by yourorganization will prevent or minimize the probability that the reliability of theBPS incurs fwiher risk of similar violations in the future. Additional detailedinformation may be provided as an attachment.

Through the successful completion of this Mitigation Plan, IMPA gave retraining to CT operators and now records a system voltage data point in itsSCADA system. The procedure for maintaining and documenting the AndersonSubstation system voltage was revised to ensure the importance ofthis voltageschedule is raised among the IMPA operational staffemployees. IMPArequested and received a revised voltage schedule from AEP that is very similarto PJM's Default Generator Voltage Schedule which allows for a wider range ofsystem voltage values in its scheduled range. Thus IMPA believes the risk offuture violations of the voltage schedule have been minimized, if not completelyprevented. Upon the full implementation of this mitigation plan on September11,2009, the PSCs and the CT operators have reviewed and understood therevised procedure for documenting and maintaining the voltage schedule andwhat .actions would need to be taken if voltage could not be controlled to withinthe schedule's specifications.



Attachment A

Section F: Authorization

An authorized individual must sign and date this Mitigation Plan Submittal Form. Bydoing so, this individual, on behalf of your organization:

a) Submits this Mitigation Plan for acceptance by ReliabilityFirst and approval byNERC, and

b) If applicable, certifies that this Mitigation Plan was completed on or before thedate provided as the 'Date of Completion of the Mitigation Plan' on this form,and

c) Acknowledges:

1. I am the President of Indiana Municipal Power Agency.

2. I am qualified to sign this Mitigation Plan on behalf of Indiana MunicipalPower Agency.

3. I have read and am familiar with the contents ofthi8 Mitigation Plan.

4. Indiana Municipal Power Agency agrees to comply with, this MitigationPlan, including the timetable completion date, as accepted byReliabilityFirst and approved by NERC.

Authorized Individual Signature

Name (Print):

Title:

Date:

Raj G. Rao

President

__l...!....JJIJ!l_(}-4-1 _

Section G: Regional Entity Contact

Please direct completed fonns or any questions regarding completion of this fom1to the ReliabilityFirst Compliance e-mail address [email protected] indicate the company name and reference the NERC Violation ID # (ifknown) in the subject line ofthe e-mail. Additionally, any ReliabilityFirstCompliance Staffmember is available for questions regarding the use of thisfonn. Please see the contact list posted on the ReliabilityFirst Compliance webpage.


Section F: AuthorizationAn authorized individual must sign and date this Mitigation Plan Submittal Fonn. Bydoing so, this individual, on behalf of your organization:


b) If a'pplicable, certifies that this Mitigation Plan was completed on or before thedate provided as the 'Date of Completion of the Mitigation Plan' on this form,and

c) Acknowledges:

1. I am the President of Indiana Municipal Power Agency.


3. I have read and am familiar with the contents of tIlis Mitigation Plan.

4. Indiana Municipal Power Agency agrees to comply with, this Mitigation.Plan" including the timetable completion date, as accepted by,ReliabilityFirst and approved by mRC.

Authorized Individual Signature ~ g, ~.r

arne (print): ""R,==a,,-iG=,,--,.R=ao"-- _

Title: President

Date: ti U!J_O-4-1 _

Section G: Regional Entity ContactPlease 'direct completed forms or any questions regarding completion of this formto the ReliabilityFirst Compliance e-mail address [email protected] the company name and reference the NERC Violation ill.# (ifknown) in the subject line of the e~mail. Additionally, any ReliabilityFirstComplil:!-llce Staff member is available for questions regarding the use of thisfonn. Please see the contact list posted on the ReliabilityFirst Compliance webpage.



Attachment A

Attachment A - Compliance Notices & Mitigation Plan Requirements

1. Section 6.2 of the CMEP1 sets forth the infonnation that must be included in aMitigation Plan. The Mitigation Plan must include:

(1) The Registered Entity's point of contact for the Mitigation Plan, who shall be aperson (i) responsible for filing the Mitigation Plan, (ii) technicallyknowledgeable regarding the Mitigation Plan, and (iii) authorized and competentto respond to questions regarding the status of the Mitigation Plan.

(2) The Alleged or Confinned Violation(s) ofReliability Standard(s) the MitigationPlan will correct.

(3) The cause of the Alleged or ConfIrmed Violation(s).

(4) The Registered Entity's action plan to correct the Alleged or ConfinnedViolation(s).

(5) The Registered Entity's action plan to prevent recurrence of the Alleged orConfrrmed violation(s).

(6) The anticipated impact of the Mitigation Plan on the bulk power systemreliability and an action plan to mitigate any increased risk to the reliability of thebulk power-system while the Mitigation Plan is being implemented.

(7) A timetable for completion of the Mitigation Plan including the completion dateby which the Mitigation Plan will be fully implemented and the Alleged orConfInned Violation(s) conected.

(8) Key implementation milestones no more than three (3) months apmt forMitigation Plans with expected completion dates more than three (3) monthsfrom the date of submission. Additional violations could be determined for notcompleting work associated with accepted milestones.

(9) Any other infonnation deemed necessary or appropriate.

(10) The Mitigation Plan shall be signed by an officer, employee, attomey or otherauthorized representative of the Registered Entity, which if applicable, shall bethe person that signed the Self-Certification or SelfReporting submittals.

II. This submittal fonn must be used to provide a required Mitigation Plan for reviewand acceptance by ReliabilityFirst and approval by NERC.

III. This Mitigation Plan is submitted to ReliabilityFirst and NERC as confidentialinfonnation in accordance with Section 1500 oftheNERC Rules ofProcedure.

IV. This Mitigation Plan Submittal Fonn may be used to address one or more relatedAlleged or Confinned violations of one Reliability Standard. A separate

I "Compliance Monitoring and Enforcement Program" ofthe ReliabilityFirst Corporation;" a copy of thecurrent version approved by the Federal Energy Regulatory Commission is posted on the ReliabilityFirstwebsite.



I. Section 6.2 of the GMEp l sets forth the information that must be included in aMitigation Plan. The Mitigation Plan must include:

(1) The Registered Entity's point ofcontact for the Mitigation Plan, who shall be aperson (i) responsible for filing the Mitigation Plan, (ii) teclmicallyknowledgeable regarding the Mitigation Plan, and (iii) authorized and competentto respond to questions regarding the status of the Mitigation Plan.

(2) The Alleged or Confirmed Violation(s) ofReliability Standard(s) the MitigationPlan will correct.

(3) The cause of the Alleged or Confmned Violation(s).

(4) The Registered Entity's action plan to correct the Alleged or ConfirmedViolation(s).

(5) The Registered Entity's action plan to prevent recurrence of the Alleged orConfrrmed violation(s).


(7) A timetable for completion of the Mitigation Plan including the completion dateby which the Mitigation Plan will be' fully implemented and the Alleged orConfirmed Violation(s) corrected.

(8) Key implementation milestones no more than three (3) months apa11 for .Mitigation Plans with expected' completion dates more than three (3) monthsfrom the date of submission. Additional violations could be determined for notcompleting work associated with accepted milestones.

(9) Any other information deemed necessary or appropriate.

(10) The Mitigation Plan shall be signed by an officer, employee, attomey or otherauthorized representative of the Registered Entity, which if applicable, shall bethe person that signed the Self-Certification or SelfReporting submittals.

II. This submittal form must be used to provide a required Mitigation Plan for reviewand accept~ceby ReliabilityFirst and approval by NERC.

III. This Mitigation Plan is submitted to ReliabilityFirst and NERC as confidentialinformation in accordance with Section 1500 ofthe.NERC Rules ofProcedure.

IV. This Mitigation Plan Submittal Form may be used to address one or more relatedAlleged or Confirmed violations of one Reliability Standard. A separate

I "Compliance Monitoring and Enforcement Program" ofthe ReliabilityFirst Corporation;" a copy of thecurrent version approved by the FederaL Energy Regulatory Commission is posted on the ReliabilityFirstwebsite.



Attachment A

mitigation plan is required to address Alleged or Confirmed violations withrespect to each additional Reliability Standard, as applicable.

V. If the Mitigation Plan is accepted by ReliabilityFirst and approved by NERC, acopy of this Mitigation Plan will be provided to the Federal Energy RegulatoryCommission in accordance with applicable Commission rules, regulations andorders.

VI. ReliabiIityFirst or NERC may reject Mitigation Plans that they determine to beincomplete or inadequate.

VII. Remedial action directives also may be issued as necessary to ensure reliability ofthe BPS.

Version 2.0 - Released 71ll/08 Page 9 of10



VI. ReliabilityFirst or ERC may reject Mitigation Plans that they determine to beincomplete or inadequate.


Version 2.0 - Released 71ll/08 Page 9 of10


Attachment A

DOCUlVIENT CONTROL

Title: Mitigation Plan Submittal Form

Issue: Version 2.0

Date: 11 July 2008

Distribution: Public

Filename: ReliabilityFirst Mitigation Plan Submittal Form - Vel' 2.DOC

Control: Reissue as complete document only

DOCUMENT APPROVALPrepared By Approved By Approval Signature Date

Robert K. Wargo Raymond J. Palmieri

Senior Consultant Vice President and~J'~ 1/2/08

Compliance Director

Compliance

DOCUMENT CHANGE/REVISION HISTORY

Version Prepared By Summary of Changes Date

1.0 Robeli K. WargoOriginal Issue - Replaces "Proposed

1/2/08Mitigation Plan" Form

Revised email address [email protected] to

2.0 Tony Purgar [email protected] 7/11/08


DOCUMENT CONTROL


Issue: Version 2.0

Date: 11 July 2008


Filename: ReliabilityFirst Mitigation Plan Submittal Form - Vel' 2.DOe


DOCUMENT APPROVAL

Prepared By Approved By Approval Signature Date- -


Senior Consultant V ice President and~rJ'~ 1/2/08

Compliance Director

Compliance



1.0 Robert K. WargoOriginal Issue - Replaces "Proposed



2.0 Tony Purgar mitigationplan@rf'il'st.org 7/11108

Version 2.0 - Released 71ll/08 Page JO oflO


Attachment B

Certification of

Mitigation Plan Completion

Submitted October 29, 2009

Attachment B

REU

Certification of Mitigation Plan Completion

Submittal of a Certification of Mitigation Plan Completion shall include data or information sufficient forReliabilityFirst Corporation to verify completion of the Mitigation Plan. ReliabilityFirst Corporationmay request additional data or information and conduct follow-up assessments, on-site or other SpotChecking, or Compliance Audits as it deems necessary to verify that all required actions in the MitigationPlan have been completed and the Registered Entity is in compliance with the subject ReliabilityStandard. (CMEP Section 6.6)

Registered Entity Name: Indiana Municipal Power Agency

NERC Registry ID:NCR00796

Date of Submittal of Certification:October 29,2009

NERC Violation ID No(s):RFC200900157

Reliability Standard and the Requirement(s) of which a violation was mitigated:VAR-002-1.1a R2

Date Mitigation Plan was scheduled to be completed per accepted Mitigation Plan: September II, 2009

Date Mitigation Plan was actually completed:September 11,2009

Additional Comments (or List ofDocuments Attached):

I certify that the Mitigation Plan for the above named violation has been completed on the date shownabove and that all submitted information is complete and correct to the best of my knowledge.

Name: Raj G. Rao

Title: President

Email: [email protected]

Phone: (317) 573-9955

Authorized Signature_----'~__e-,_"_'_S\--'--·_~____'=....!<v'____ _

Page I of3


Submittal of a Certification of Mitigation Plan Completion shall include data or infonnation sufficient forReliabilityFirst Corporation to verify completion of the Mitigation Plan. ReliabilityFirst Corporationmay request additional data or infonnation and conduct follow-up assessments, on-site or other SpotChecking, or Compliance Audits as it deems necessary to verify that all required actions in the MitigationPlan have been completed and the Registered Entity is in compliance with the subject ReliabilityStandard. (CMEP Section 6.6)



Date of Submittal of Certification:October 29,2009

NERC ViolationID No(s):RFC200900I57

Reliability Standard and the Requirement(s) of which a violation was mitigated:VAR-002-l.Ia R2

Date Mitigation Plan was scheduled to be completed per accepted Mitigation Plan: September 11, 2009

Date Mitigation Plan was actually completed:September 11,2009

Additional Comments (or List ofDocuments Attached):

I certify that the Mitigation Plan for the above named violation has been completed on the date shownabove and that all submitted infonnation is complete and correct to the best of my knowledge.

Name: Raj G. Rao

Title: President

Email: [email protected]

Phone: (317) 573-9955

Authorized Signature__P-:,__~-..:::..'_S\.L.·_~_--"';V::""'- _

Page 1 of3

Date IO,/;.q(~OO q

Attachment B

REUABIUT

Please direct completed forms or any questions regarding completion of this form to theReliabilityFirst Compliance e-mail address [email protected].

Please indicate the company name and reference the NERC Violation ill # (ifknown) in thesubject line of the e-mail. Additionally, any ReliabilityFirst Compliance Staff member isavailable for questions regarding the use of this form. Please see the contact list posted on theReliabilityFirst Compliance web page.

Page 2 of3

Please direct completed fonns or any questions regarding completion of this fonn to theReliabilityFirst Compliance e-mail address [email protected].

Please indicate the company name and reference the NERC Violation ill # (ifknown) in thesubject line of the e-mail. Additionally, any ReliabilityFirst Compliance Staff member isavailable for questions regarding the use of this fonn. Please see the contact list posted on theReliabilityFirst Compliance web page.

Page 2 of3

Attachment B

ReUABlUT

DOCUMENT CONTROL

Title:

Issue:

Date:

Distribution:

Filename:

Control:

Certification ofMitigation Plan Completion

Version I

5 January 2008

Public

Certification of a Completed Mitigation Plan_Verl.doc

Reissue as complete document only

DOCUMENT APPROVAL

Prepared By Approved By Approval Signature Date


Manager of Vice President and~l~ 1/5/2009

Compliance DirectorEnforcement Compliance



1.0 Robert K. Wargo Original Issue 1/5/2009

Page 3 of3

DOCUMENT CONTROL

Title:

Issue:

Date:

Distribution:

Filename:

Control:


Version I

5 January 2008

Public



DOCUMENT APPROVAL



Manager of Vice President and

~rJ'~ 1/5/2009Compliance DirectorEnforcement Compliance




Page 3 of3

Attachment C

Summary and Review of


Dated November 16, 2009

November 16, 2009

Summary and Review of Evidence of Mitigation Plan Completion

NERC Violation ID #: RFC200900157 NERC Plan ID: MIT-09-2059 Registered Entity; Indiana Municipal Power Agency NERC Registry ID: NCR00796 Standard: VAR-002-1.1a Requirement: 2 Status: Compliant

Indiana Municipal Power Agency (“IMPA”) submitted a Self Report of noncompliance with NERC Reliability Standard VAR-002-1.1a, Requirement 2, on June 24, 2009. IMPA submitted a Proposed Mitigation Plan to ReliabilityFirst on September 18, 2009, stating IMPA had completed all mitigating actions on or about September 11, 2009. This Mitigation Plan, designated MIT-09-2059, was accepted by ReliabilityFirst on October 23, 2009 and approved by NERC on October 26, 2009. Review Process: On October 29, 2009, IMPA certified that Mitigation Plan for VAR-002-1.1a, Requirement 2, was completed as of September 11, 2009. ReliabilityFirst requested and received evidence of completion for actions taken by IMPA as specified in the Mitigation Plan. ReliabilityFirst performed an in depth review of the information provided to verify that all actions specified in the Mitigation Plan were successfully completed. VAR-002-1.1a, Requirement 2 states: “Unless exempted by the Transmission Operator, each Generator Operator shall maintain the generator voltage or reactive Power output (within applicable Facility Ratings) as directed by the Transmission Operator.” Evidence Submitted for Milestone 1 completed on June 8, 20091: VAR-002-1.1a Generator Operation for Maintaining Network Voltage Schedules, IMPA Staff Review Record, signed and dated by Combustion Turbine CT Operators on June 8, 2009 certified that they have reviewed and understand the AEP voltage schedule and GOP Requirements: Reporting Automatic Voltage Regulator AVR & Power Systems Stabilizer PSS Status. Evidence Submitted for Milestone 2 completed on June 2, 20092:

1 Milestone 1 completed as scheduled on June 8, 2009 in the Mitigation Plan even though it succeded Milestone 2. 2 Milestone 2 completed as scheduled on June 2, 2009 in the mitigation Plan even though it preceded Milestone 1.

Attachment CRELlABILlT

Summary and Review of Mitigation Plan Completion Indiana Municipal Power Agency November 16, 2009 Page 2 of 3

Examples of Anderson Station 138 kV bus voltage data points for June 2, 2009 was provided that will be recorded and used in case a system voltage point reading is not recorded for a time period in which the gas turbines are online. Evidence Submitted for Milestone 3 completed on August 10, 20093: IMPA NERC Reliability Standards, Procedure for Documenting/Maintaining a Generator's Automatic Voltage Regulator Mode and the Voltage Schedule for System Voltage, dated July 31, 2009, approved August 10, 2009. Section I Voltage Schedule includes a procedure for the Combustion Turbine (CT) operator to monitor, document and maintain system voltage and the notification process to be utilized by the Power System Coordinator (PSC) when system voltage is outside to the voltage schedule specification or tolerance. This revision should ensure that awareness is raised in IMPA’s operations staff for documenting and/or maintaining a generator's automatic voltage regulator mode and the voltage schedule for system voltage. Evidence Submitted for Milestone 4 completed on July 22, 20094: Letter from IMPA to AEP dated July 22, 2009 requesting a revised voltage schedule that is more consistent with the actual operating circumstances at its Anderson combustion turbine site. Evidence Submitted for Milestone 5 completed on September 11, 20095: VAR-002-1.1a Generator Operation for Maintaining Network Voltage Schedules, IMPA Staff Review Record signed and dated by IMPA personnel during August and September which certifies that they have reviewed and understand the AEP voltage schedule and GOP Requirements: Reporting AVR & PSS Status. This covers revision up to and including revision 2 (approved August 10, 2009). Evidence Submitted for Milestone 6 completed on July 28, 20096: AEP letter dated July 27, 2009 to all generator owners and operators interconnected to the AEP-East Transmission System in the PJM-RTO footprint provides an AEP-East Transmission System (RFC/PJM), IMPA - South Anderson Generator Power Factor Schedule. The Voltage Schedule @AEP Interconnection Point indicates 1.011 p.u –

3 Milestone 3 completed as scheduled on August 10, 2009 in the Mitigation Plan even though it succeded Milestone 4. 4 Milestone 4 completed as scheduled on July 22, 2009 in the Mitigation Plan even though it preceded Milestone 3. 5 Milestone 5 completed as scheduled on September 11, 2009 in the Mitigation Plan even though it succeded Milestone 6. 6 AEP Letter dated July 27, 2009 was actually received by IMPA on July 28, 2009. Milestone 6 completes as referenced in the mitigation Plan even though it preceded Milestone 5.

Attachment C

Summary and Review of Mitigation Plan Completion Indiana Municipal Power Agency November 16, 2009 Page 3 of 3

139.5 kV with a a steady-state deviation between +/- 2.5% of the specified voltage schedule that is permissible per PJM default Generator Voltage Schedules highlighted in Manual 3: Transmission Operations, Section 3: Voltage & Stability Operating Guidelines, Page 30. The CT Operators and PSCs were provided with the new schedule on the date it was received. Review Results: ReliabilityFirst Corporation reviewed the evidence the IMPA submitted in support of its Certification of Completion. On November 16, 2009 ReliabilityFirst verified that the Mitigation Plan was completed in accordance with its terms and has therefore deemed IMPA compliant to the aforementioned NERC Reliability Standard.

Respectfully Submitted,

Robert K. Wargo Manager of Compliance Enforcement ReliabilityFirst Corporation

Attachment C

Attachment D

Mitigation Plan (MIT-07-2544)

Submitted May 6, 2010

REMitigation Plan Submittal Form

Date this Mitigation Plan is being submitted: May 6, 2010


A.l Notices and requirements applicable to Mitigation Plans and this SubmittalForm are set forth in "Attachment A - Compliance Notices & Mitigation PlanRequirements."

A.2 This form must be used to submit required Mitigation Plans for review andacceptance by ReliabilityFirst and approval by NERC.

A.3 ~ I have reviewed Attachment A and understand that this Mitigation PlanSubmittal Form will not be accepted unless this box is checked.

Section B: Registered Entity Information

B.l Identify your organization.

Company Narne:

Company Address:



11610 N. College AvenueCarmel, IN 46032

NCR00796


Name:

Title:

Email:

Phone:

Version 2.0 - Released 7/11108

Gayle Mayo


[email protected]

(317) 573-9955

Page 1 of 13

RFC200900190 RFC201000239

Attachment D




A.1 Notices and requirements applicable to Mitigation Plans and this SubmittalForm are set forth in "Attachment A - Compliance Notices & Mitigation PlanRequirements."

A2 This form must be used to submit required Mitigation Plans for review andacceptance by ReliabilityFirst and approval by NERC.

A.3 I:g] I have reviewed Attachment A and understand that this Mitigation PlanSubmittal Form will not be accepted unless this box is checked.

Section B: Registered Entity InformationB.l Identify your organization.

Company Name:

Company Address:




NCR00796


Name:

Title:

Email:

Phone:


Gayle Mayo


[email protected]

(317) 573-9955

Page 1 of 13

MIT-07-2544




A.1 Notices and requirements applicable to Mitigation Plans and this SubmittalForm are set forth in "Attachment A - Compliance Notices & Mitigation PlanRequirements."

A2 This form must be used to submit required Mitigation Plans for review andacceptance by ReliabilityFirst and approval by NERC.

A.3 I:g] I have reviewed Attachment A and understand that this Mitigation PlanSubmittal Form will not be accepted unless this box is checked.

Section B: Registered Entity InformationB.l Identify your organization.

Company Name:

Company Address:




NCR00796


Name:

Title:

Email:

Phone:


Gayle Mayo


[email protected]

(317) 573-9955

Page 1 of 13



C.1 This Mitigation Plan is associated with the following Alleged or Confirmedviolation(s) of the reliability standard listed below.

NERC Reliability Requirement Violation Alleged or Method ofViolation ill Standard Number Risk Factor Confmned Detection (e.g.,

# Violation Date{') Audit, Self-report,Investigation)

RFC200900 PRC-005-1 R2.1 High May 31, 2009 Internal review in190 preparation for

submission of a selfcertification

RFC201000 PRC-005-1 Rl. High May 31, 2009 Self-report239

(*) Note: The Alleged or Confinned VlOlatlOn Date shall be expressly speclfied by the RegIstered Entlty,and subject to modification by ReliabilityFirst, as: (i) the date the Alleged or Confinned violation occurred;(ii) the date that the Alleged or Confinned violation was self-reported; or (iii) the date that the Alleged orConfmned violation has been deemed to have occurred on by ReliabilityFirst. Questions regarding thedate to use should be directed to the ReliabilityFirst contact identified in Section G of this fonn.


Requirement 2.1. states the documentation of the program implementation shall includeevidence Protection System devices were maintained and tested within the definedintervals of the Generator Owner's Protection System maintenance and testing program.During an internal review in preparation for submission of a self certification with PRC005-1 on September 28, 2009, Indiana Municipal Power Agency ("IMPA") discoveredthat it had not performed testing for certain protection system components at one if itspower plants within the 24 month period specified in IMPA's Generation ProtectionSystem Maintenance and Testing program. That program required testing of allgeneration protection systems within 24 months ofthe date the program was established,

Version 2.0 - Released 71ll/08 Page 2 of 13

Attachment D


C.1 This Mitigation Plan is associated with the following Alleged or Continnedviolation(s) of the reliability standard listed below.


# Violation Date«) Audit, Self-report,Investigation)




(*) Note: The Alleged or Corrfmned VlOlatlOn Date shall be expressly speclf'ied by the RegIstered Entity,and subject to modification by ReliabilityFirst, as: (i) the date the Alleged or Confirmed violation occurred;(ii) the date that the Alleged or Confirmed violation was self-reported; or (iii) the date that the Alleged orConfmned violation has been deemed to have occurred on by ReliabilityFirst. Questions regarding thedate to use should be directed to the ReliabilityFirst contact identified in Section G of this form.

C.2 Identify the cause of the Alleged or Continned violation(s) identified above.Additional detailed infonnation may be provided as an attachment.

Requirement 2.1. states the documentation of the program implementation shall includeevidence Protection System devices were maintained and tested within the definedintervals of the Generator Owner's Protection System maintenance and testing program.During an internal review in preparation for submission of a self certification with PRC005-1 on September 28,2009, Indiana Municipal Power Agency ("IMPA") discoveredthat it had not perfonned testing for certain protection system components at one if itspower plants within the 24 month period specified in IMPA's Generation ProtectionSystem Maintenance and Testing program. That program required testing of allgeneration protection systems within 24 months of the date the program was established,

Version 2.0 - Released 7/11/08 Page 2 ofB


C.1 This Mitigation Plan is associated with the following Alleged or Continnedviolation(s) of the reliability standard listed below.


# Violation Date«) Audit, Self-report,Investigation)




(*) Note: The Alleged or Corrfmned VlOlatlOn Date shall be expressly speclf'ied by the RegIstered Entity,and subject to modification by ReliabilityFirst, as: (i) the date the Alleged or Confirmed violation occurred;(ii) the date that the Alleged or Confirmed violation was self-reported; or (iii) the date that the Alleged orConfmned violation has been deemed to have occurred on by ReliabilityFirst. Questions regarding thedate to use should be directed to the ReliabilityFirst contact identified in Section G of this form.

C.2 Identify the cause of the Alleged or Continned violation(s) identified above.Additional detailed infonnation may be provided as an attachment.

Requirement 2.1. states the documentation of the program implementation shall includeevidence Protection System devices were maintained and tested within the definedintervals of the Generator Owner's Protection System maintenance and testing program.During an internal review in preparation for submission of a self certification with PRC005-1 on September 28,2009, Indiana Municipal Power Agency ("IMPA") discoveredthat it had not perfonned testing for certain protection system components at one if itspower plants within the 24 month period specified in IMPA's Generation ProtectionSystem Maintenance and Testing program. That program required testing of allgeneration protection systems within 24 months of the date the program was established,

Version 2.0 - Released 7/11/08 Page 2 ofB


RELlAnot the date of previous tests. The protection system components that IMPA failed to testwithin the 24 month period include:

A total of six relays on the IMPA owned generator protection breakers.Seven Potential Transformers (PTs) on one of the three units.A total of one hundred and one Current Transformers (CTs) on the threegenerating units.DC control circuitry (one of three DC control circuitries was not tested).

IMPA has determined the causes of these potential violations as follows:The six relays were scheduled to be tested in April 2008, but the contractorfailed to perform the tests and the IMPA staff supervising the contractor didnot discover the contractor's error.The PTs were scheduled to be tested in the spring of2009, but the tests wererepeatedly delayed due to wet weather, and were finally delayed until the fallof 2009 because IMPA has a policy ofnot taking maintenance outages ongenerating units during the summer peak season.Until IMPA revised its Generation Protection System Maintenance andTesting Procedure on September 29,2009, IMPA's policy has been to testCTs upon commissioning and then to limit tests of in-service CTs to situationswhere an operational problem with the CT was suspected. IMPA has recentlylearned that new test equipment makes the testing of in-service CTs morefeasible and has revised its policy to require testing of CTs every five years.IMPA has determined that the failure to perform trip checks on the DCcontrol circuitry on one unit was caused by staff oversight, since DC tripchecks were scheduled and performed for the control circuitry on two otherunits at the station in December 2007 but were not scheduled or performedfor the unit that was overlooked until July IO, 2009 after the original oversightwas discovered.

Requirement R1. states that each Generator Owner that owns a generation ProtectionSystem shall have a Protection System maintenance and testing program for ProtectionSystems that affect the reliability of the BES. In May 2007, IMPA developed its firstwritten policy for Generation Protection System Maintenance and Testing Intervals. Atthat time IMPA defined generation protection systems as protective relays, and scheduledsuch relays to be tested at the same time as other protective systems such as generatorbreakers, switches and transformers. IMPA's initial policy did not contemplate testing ofPTs, CTs, station batteries or DC control systems as a part of this policy or on the sameschedule as the protective relays. However, all of these devices were actually testedbetween May 30,2007, when IMPA established its initial policy and May 31, 2009 (the24 month window allowed by the initial policy) except for the devices that are the subjectofIMPA's self report.

After the implementation of its initial policy for Generation Protection SystemMaintenance and Testing Intervals, IMPA learned that the NERC definition ofProtection


Attachment D

not the date of previous tests. The protection system components that IMPA failed to testwithin the 24 month period include:


IMPA has determined the causes of these potential violations as follows:The six relays were scheduled to be tested in April 2008, but the contractorfailed to perform the tests and the IMPA staff supervising the contractor didnot discover the contractor's error.The PTs were scheduled to be tested in the spring of2009, but the tests wererepeatedly delayed due to wet weather, and were finally delayed until the fallof2009 because IMPA has a policy ofnot taking maintenance outages ongenerating units during the summer peak season.Until IMPA revised its Generation Protection System Maintenance andTesting Procedure on September 29, 2009, IMPA's policy has been to testCTs upon commissioning and then to limit tests of in-service CTs to situationswhere an operational problem with the CT was suspected. IMPA has recentlylearned that new test equipment makes the testing of in-service CTs morefeasible and has revised its policy to require testing of CTs every five years.IMPA has determined that the failure to perform trip checks on the DCcontrol circuitry on one unit was caused by staff oversight, since DC tripchecks were scheduled and performed for the control circuitry on two otherunits at the station in December 2007 but were not scheduled or performedfor the unit that was overlooked until July 10, 2009 after the original oversightwas discovered.

Requirement R1. states that each Generator Owner that owns a generation ProtectionSystem shall have a Protection System maintenance and testing program for ProtectionSystems that affect the reliability of the BES. In May 2007, IMPA developed its firstwritten policy for Generation Protection System Maintenance and Testing Intervals. Atthat time IMPA defined generation protection systems as protective relays, and scheduledsuch relays to be tested at the same time as other protective systems such as generatorbreakers, switches and transformers. IMPA's initial policy did not contemplate testing ofPTs, CTs, station batteries or DC control systems as a part of this policy or on the sameschedule as the protective relays. However, all ofthese devices were actually testedbetween May 30, 2007, when IMPA established its initial policy and May 31, 2009 (the24 month window allowed by the initial policy) except for the devices that are the subjectofIMPA's self report.



not the date of previous tests. The protection system components that IMPA failed to testwithin the 24 month period include:


IMPA has determined the causes of these potential violations as follows:The six relays were scheduled to be tested in April 2008, but the contractorfailed to perform the tests and the IMPA staff supervising the contractor didnot discover the contractor's error.The PTs were scheduled to be tested in the spring of2009, but the tests wererepeatedly delayed due to wet weather, and were finally delayed until the fallof2009 because IMPA has a policy ofnot taking maintenance outages ongenerating units during the summer peak season.Until IMPA revised its Generation Protection System Maintenance andTesting Procedure on September 29, 2009, IMPA's policy has been to testCTs upon commissioning and then to limit tests of in-service CTs to situationswhere an operational problem with the CT was suspected. IMPA has recentlylearned that new test equipment makes the testing of in-service CTs morefeasible and has revised its policy to require testing of CTs every five years.IMPA has determined that the failure to perform trip checks on the DCcontrol circuitry on one unit was caused by staff oversight, since DC tripchecks were scheduled and performed for the control circuitry on two otherunits at the station in December 2007 but were not scheduled or performedfor the unit that was overlooked until July 10, 2009 after the original oversightwas discovered.

Requirement R1. states that each Generator Owner that owns a generation ProtectionSystem shall have a Protection System maintenance and testing program for ProtectionSystems that affect the reliability of the BES. In May 2007, IMPA developed its firstwritten policy for Generation Protection System Maintenance and Testing Intervals. Atthat time IMPA defined generation protection systems as protective relays, and scheduledsuch relays to be tested at the same time as other protective systems such as generatorbreakers, switches and transformers. IMPA's initial policy did not contemplate testing ofPTs, CTs, station batteries or DC control systems as a part of this policy or on the sameschedule as the protective relays. However, all ofthese devices were actually testedbetween May 30, 2007, when IMPA established its initial policy and May 31, 2009 (the24 month window allowed by the initial policy) except for the devices that are the subjectofIMPA's self report.




RELlASystems includes "protective relays, associated communication systems, voltage andcurrent sensing devices, station batteries and DC control circuitry." IMPA has nowrevised its policy for maintenance and testing of generator protection systems to includetesting of these additional elements and has revised testing intervals based on industrypractices, manufacturer's recommendations and other information.



None.



D.I Identify and describe the action plan, including specific tasks and actions thatyour organization is proposing to undertake, or which it undertook ifthisMitigation Plan has been completed, to correct the Alleged or Confirmedviolations identified above in Part C.1 of this form. Additional detailedinformation may be provided as an attachment.

The following action plan was developed and implemented (see D.3 for dates):

1. IMPA hired a different, fully qualified contractor to test the six missed relays ongenerator protection breakers. These relays were satisfactorily tested.

2. The PTs were satisfactorily tested.

3. The CTs were satisfactorily tested.

4. The DC control circuitry was satisfactorily tested.

5. IMPA revised its Generation Protection System Maintenance and Testing Procedureto include all the Protection System devices (per NERC's definition). The testingintervals were revised based on industry practices, manufacturer's recommendations andother information.

6. IMPA began to develop a guideline for checking and tracking certain ProtectionSystem device testing shortly after IMPA self-reported two possible violations ofPRC005-1. IMPA completed and formally approved this guideline on November 20, 2009.In accordance with this guideline, tests will be scheduled far enough in advance and


Attachment D

Systems includes "protective relays, associated communication systems, voltage andcurrent sensing devices, station batteries and DC control circuitry." IMPA has nowrevised its policy for maintenance and testing of generator protection systems to includetesting of these additional elements and has revised testing intervals based on industrypractices, manufacturer's recommendations and other information.



None.



D.1 Identify and describe the action plan, including specific tasks and actions thatyour organization is proposing to undertake, or which it undertook if thisMitigation Plan has been completed, to correct the Alleged or Confirmedviolations identified above in Part C.l of this form. Additional detailedinformation may be provided as an attachment.









Systems includes "protective relays, associated communication systems, voltage andcurrent sensing devices, station batteries and DC control circuitry." IMPA has nowrevised its policy for maintenance and testing of generator protection systems to includetesting of these additional elements and has revised testing intervals based on industrypractices, manufacturer's recommendations and other information.



None.



D.1 Identify and describe the action plan, including specific tasks and actions thatyour organization is proposing to undertake, or which it undertook if thisMitigation Plan has been completed, to correct the Alleged or Confirmedviolations identified above in Part C.l of this form. Additional detailedinformation may be provided as an attachment.










RElltracked on a daily basis to assure the tests will be completed within the time framespecified in the Generation Protection System and Testing Procedure and to help avoidthe necessity of testing during the summer to meet the schedule. The PlantSuperintendent is responsible for maintaining the scheduling function and arranging forthe upcoming Protection System device testing to be performed according to theschedule.

7. To help prevent future violations ofPRC-005, IMPA will not be using the testingcontractor who missed the six relays during the last testing period for any future relaytesting work.

8. Prior to conducting formal training, IMPA field personnel (Combustion TurbineOperators and Plant Superintendent) were briefed on the proposed procedure andguideline for tracking and testing Protection System equipment.

9. IMPA conducted training for the Combustion Turbine Operators, PlantSuperintendent, and Assistant Vice-President of Electrical Engineering on its revisedGeneration Protection System Maintenance and Testing Procedure and the new guidelinefor tracking the testing of Protection System devices.


D.2 Provide the date by which full implementation of the Mitigation Plan will be, orhas been, completed with respect to the Alleged or Confirmed violationsidentified above. State whether the Mitigation Plan has been fully implemented,and/or whether the actions necessary to assure the entity has returned to fullcompliance have been completed.

IMPA performed steps 1,2,3,4,6,7, 8, and 9 ofthe action plan in D.1 tocorrect the alleged violation for R2.I. IMPA was fully compliant with R2.I. onNovember 30, 2009.

IMPA performed steps 5 and 9 of the action plan in D.I to correct the allegedviolation for Rl. IMPA was fully compliant with RI. on November 30, 2009.



Attachment D

tracked on a daily basis to assure the tests will be completed within the time framespecified in the Generation Protection System and Testing Procedure and to help avoidthe necessity oftesting during the summer to meet the schedule. The PlantSuperintendent is responsible for maintaining the scheduling function and arranging forthe upcoming Protection System device testing to be performed according to theschedule.

7. To help prevent future violations of PRC-005, IMPA will not be using the testingcontractor who missed the six relays during the last testing period for any future relaytesting work.


9. IMPA conducted training for the Combustion Turbine Operators, PlantSuperintendent, and Assistant Vice-President of Electrical Engineering on its revisedGeneration Protection System Maintenance and Testing Procedure and the new guidelinefor tracking the testing ofProtection System devices.



IMPA performed steps 1, 2, 3, 4, 6, 7, 8, and 9 ofthe action plan in D.1 tocorrect the alleged violation for R2.I. IMPA was fully compliant with R2.I. onNovember 30, 2009.

IMPA performed steps 5 and 9 of the action plan in D.I to correct the allegedviolation for RI. IMPA was fully compliant with RI. on November 30,2009.



tracked on a daily basis to assure the tests will be completed within the time framespecified in the Generation Protection System and Testing Procedure and to help avoidthe necessity oftesting during the summer to meet the schedule. The PlantSuperintendent is responsible for maintaining the scheduling function and arranging forthe upcoming Protection System device testing to be performed according to theschedule.

7. To help prevent future violations of PRC-005, IMPA will not be using the testingcontractor who missed the six relays during the last testing period for any future relaytesting work.


9. IMPA conducted training for the Combustion Turbine Operators, PlantSuperintendent, and Assistant Vice-President of Electrical Engineering on its revisedGeneration Protection System Maintenance and Testing Procedure and the new guidelinefor tracking the testing ofProtection System devices.



IMPA performed steps 1, 2, 3, 4, 6, 7, 8, and 9 ofthe action plan in D.1 tocorrect the alleged violation for R2.I. IMPA was fully compliant with R2.I. onNovember 30, 2009.

IMPA performed steps 5 and 9 of the action plan in D.I to correct the allegedviolation for RI. IMPA was fully compliant with RI. on November 30,2009.





1. IMPA hired a different, fully qualified Testing on these relays was satisfactorilycontractor to test the relays missed on completed on October 29,2009.generator protection breakers, Theserelays were satisfactorily tested.2. The PTs were satisfactorily tested. Testing on these devices was satisfactorily

completed on October 14, 20093. The CTs were satisfactorily tested. Testing on these devices was satisfactorily

completed on October 28, 20094. The DC control circuitry was DC control circuitry testing wassatisfactorily tested. satisfactorily completed on July 10, 20095. IMPA revised its Generation Protection Completed on September 29, 2009System Maintenance and TestingProcedure to include all the ProtectionSystem devices (per NERC's definition).The testing intervals were revised based onindustry practices, manufacturer'srecommendations and other information.6. IMPA began to develop a guideline for The guideline for checking and tracking

,checking and tracking certain Protection the testing of relays, PTs, CTs, and DCSystem device testing shortly after it self- control circuitry was completed andreported two possible violations ofPRC- instituted on November 20, 2009005-1. IMPA completed and formallyapproved this guideline on November 20,2009. In accordance with this guideline,tests will be scheduled far enough inadvance and tracked on a daily basis toassure the tests will be completed withinthe time frame specified in the GenerationProtection System and Testing Procedureand to help avoid the necessity oftestingduring the summer to meet the schedule.The Plant Superintendent is responsible formaintaining the scheduling function andarranging for the upcoming ProtectionSystem device testing to be performedaccording to the schedule.7. To help prevent future violations of Notification was provided to the contractorPRC-005, IMPA will not be using the on October 20, 2009 via e-mail. Thistesting contractor who missed the six contractor was formally removed fromrelays during the last testing period for any IMPA's approved vendor list onfuture relay testing work. November 17, 2009.

Version 2.0 - Released 7111108 Page 6 of 13

Attachment D


1. IMPA hired a different, fully qualified Testing on these relays was satisfactorilycontractor to test the relays missed on completed on October 29,2009.generator protection breakers: Theserelays were satisfactorily tested.2. The PTs were satisfactorily tested. Testing on these devices was satisfactorily


completed on October 28,20094. The DC control circuitry was DC control circuitry testing wassatisfactorily tested. satisfactorily completed on July 10, 20095. IMPA revised its Generation Protection Completed on September 29, 2009System Maintenance and TestingProcedure to include all the ProtectionSystem devices (per NERC's definition).The testing intervals were revised based onindustry practices, manufacturer'srecommendations and other infonnation.6. IMPA began to develop a guideline for The guideline for checking and trackingchecking and tracking certain Protection the testing of relays, PTs, CTs, and DC i

System device testing shortly after it self- control circuitry was completed andreported two possible violations ofPRC- instituted on November 20, 2009005-1. IMPA completed and fonnallyapproved this guideline on November 20,2009. In accordance with this guideline,tests will be scheduled far enough inadvance and tracked on a daily basis toassure the tests will be completed withinthe time frame specified in the GenerationProtection System and Testing Procedureand to help avoid the necessity of testingduring the summer to meet the schedule.The Plant Superintendent is responsible formaintaining the scheduling function andarranging for the upcoming ProtectionSystem device testing to be perfonnedaccording to the schedule.7. To help prevent future violations of Notification was provided to the contractorPRe-005, IMPA will not be using the on October 20,2009 via e-mail. Thistesting contractor who missed the six contractor was fonnally removed fromrelays during the last testing period for any IMPA's approved vendor list onfuture relay testing work. November 17, 2009.



1. IMPA hired a different, fully qualified Testing on these relays was satisfactorilycontractor to test the relays missed on completed on October 29,2009.generator protection breakers: Theserelays were satisfactorily tested.2. The PTs were satisfactorily tested. Testing on these devices was satisfactorily


completed on October 28,20094. The DC control circuitry was DC control circuitry testing wassatisfactorily tested. satisfactorily completed on July 10, 20095. IMPA revised its Generation Protection Completed on September 29, 2009System Maintenance and TestingProcedure to include all the ProtectionSystem devices (per NERC's definition).The testing intervals were revised based onindustry practices, manufacturer'srecommendations and other infonnation.6. IMPA began to develop a guideline for The guideline for checking and trackingchecking and tracking certain Protection the testing of relays, PTs, CTs, and DC i

System device testing shortly after it self- control circuitry was completed andreported two possible violations ofPRC- instituted on November 20, 2009005-1. IMPA completed and fonnallyapproved this guideline on November 20,2009. In accordance with this guideline,tests will be scheduled far enough inadvance and tracked on a daily basis toassure the tests will be completed withinthe time frame specified in the GenerationProtection System and Testing Procedureand to help avoid the necessity of testingduring the summer to meet the schedule.The Plant Superintendent is responsible formaintaining the scheduling function andarranging for the upcoming ProtectionSystem device testing to be perfonnedaccording to the schedule.7. To help prevent future violations of Notification was provided to the contractorPRe-005, IMPA will not be using the on October 20,2009 via e-mail. Thistesting contractor who missed the six contractor was fonnally removed fromrelays during the last testing period for any IMPA's approved vendor list onfuture relay testing work. November 17, 2009.



RELlA

8. Prior to conducting formal training, IMPA field personnel were briefed onIMPA field personnel (Combustion October 20, 2009Turbine Operators and PlantSuperintendent) were briefed on theproposed procedure and guideline fortracking and testing Protection Systemequipment.9. IMPA conducted training for the Completed training on both items onCombustion Turbine Operators, Plant November 30, 2009Superintendent, and Assistant Vice-President of Electrical Engineering on itsrevised Generation Protection SystemMaintenance and Testing Procedure andthe new guideline for tracking the testingof Protection System devices.



Attachment D

8. Prior to conducting formal training, IMPA field personnel were briefed onIMPA field personnel (Combustion October 20, 2009Turbine Operators and PlantSuperintendent) were briefed on theproposed procedure and guideline fortracking and testing Protection Systemequipment.9. IMPA cop.ducted training for the Completed training on both items onCombustion Turbine Operators, Plant November 30, 2009Superintendent, and Assistant Vice-President ofElectrical Engineering on itsrevised Generation Protection SystemMaintenance and Testing Procedure andthe new guideline for tracking the testingofProtection System devices.

(*) Note: Additional violations could be determined for not completing work associated with acceptedmilestones.


8. Prior to conducting formal training, IMPA field personnel were briefed onIMPA field personnel (Combustion October 20, 2009Turbine Operators and PlantSuperintendent) were briefed on theproposed procedure and guideline fortracking and testing Protection Systemequipment.9. IMPA cop.ducted training for the Completed training on both items onCombustion Turbine Operators, Plant November 30, 2009Superintendent, and Assistant Vice-President ofElectrical Engineering on itsrevised Generation Protection SystemMaintenance and Testing Procedure andthe new guideline for tracking the testingofProtection System devices.

(*) Note: Additional violations could be determined for not completing work associated with acceptedmilestones.



RELlA



E.I While your organization is implementing this Mitigation Plan the reliability ofthe Bulk Power System (BPS) may remain at higher risk or be otherwisenegatively impacted until the plan is successfully completed. To the extent theyare, or may be, known or anticipated: (i) identify any such risks or impacts; and(ii) discuss any actions that your organization is planning to take to mitigate thisincreased risk to the reliability of the BPS. Additional detailed informationmay be provided as an attachment.

(i). It is the opinion of IMPA that risks or impact to the BPS are minimal. Withthe exception of Current Transformers, the Protection System equipment listedin Co2 above has been routinely tested in the past and, based on IMPA's pasthistory with these devices, equipment failures are extremely rare. Since thesedevices were installed, the only IMPA Protection System device that has failedwas a CT on a house power transformer that failed in the early 1990s. With thisone exception, IMPA has not had a relay, PT, CT, or DC control circuit fail topass a test, fail to operate or cause a misoperation to date.

(ii). IMPA has expedited testing on the Protection System equipment listed inC.2 above.


E.2 Describe how successful completion of this Mitigation Plan by yourorganization will prevent or minimize the probability that the reliability of theBPS incurs further risk of similar violations in the future. Additional detailedinformation may be provided as an attachment.

Through the successful completion ofthis Mitigation Plan, the ProtectionSystem components that IMPA previously failed to test have been satisfactorilytested. IMPA's Generator Protection System Maintenance and TestingProcedure has been revised to include specific assignments of responsibility andprocedures for the testing and maintenance of all System Protection devices.The new procedure also reflects a revised testing interval that is more consistentwith the industry practices, manufacturer's recommendations and otherinformation. IMPA has developed an internal guideline to use for thescheduling and testing of certain Protection System devices to ensure no devicesare missed during the testing period. IMPA staffhas been trained on the newprocedure and guideline. IMPA has also removed from its list of approved


Attachment D

R···.·········.).·····.E····.··.·.···

. . .. ~~, "

Section E: Interim and !future Reliability Risk


E.l While your organization is implementing this Mitigation Plan the reliability ofthe Bulk Power System (BPS) may remain at higher risk or be otherwisenegatively impacted until the plan is successfully completed. To the extent theyare, or may be, known or anticipated: (i) identify any such risks or impacts; and(ii) discuss any actions that your organization is planning to take to mitigate thisincreased risk to the reliability ofthe BPS. Additional detailed informationmay be provided as an attachment.

(i). It is the opinion of IMPA that risks or impact to the BPS are minimal. Withthe exception ofCurrent Transformers, the Protection System equipment listedin C.2 above has been routinely tested in the past and, based on IMPA's pasthistory with these devices, equipment failures are extremely rare. Since thesedevices were installed, the only IMPA Protection System device that has failedwas a CT on a house power transformer that failed in the early 1990s. With thisone exception, IMPA has not had a relay, PT, CT, or DC control circuit fail topass a test, fail to operate or cause a misoperation to date.

(ii). IMPA has expedited testing on the Protection System equipment listed inCo2 above.



Through the successful completion ofthis Mitigation Plan, the ProtectionSystem components that IMPA previously failed to test have been satisfactorilytested. IMPA's Generator Protection System Maintenance and TestingProcedure has been revised to include specific assignments of responsibility andprocedures for the testing and maintenance ofall System Protection devices.The new procedure also reflects a revised testing interval that is more consistentwith the industry practices, manufacturer's recommendations and otherinformation. IMPA has developed an internal guideline to use for thescheduling and testing of certain Protection System devices to ensure no devicesare missed during the testing period. IMPA staffhas been trained on the newprocedure and guideline. IMPA has also removed from its list ofapproved


R···.·········.).·····.E····.··.·.···

. . .. ~~, "

Section E: Interim and !future Reliability Risk


E.l While your organization is implementing this Mitigation Plan the reliability ofthe Bulk Power System (BPS) may remain at higher risk or be otherwisenegatively impacted until the plan is successfully completed. To the extent theyare, or may be, known or anticipated: (i) identify any such risks or impacts; and(ii) discuss any actions that your organization is planning to take to mitigate thisincreased risk to the reliability ofthe BPS. Additional detailed informationmay be provided as an attachment.

(i). It is the opinion of IMPA that risks or impact to the BPS are minimal. Withthe exception ofCurrent Transformers, the Protection System equipment listedin C.2 above has been routinely tested in the past and, based on IMPA's pasthistory with these devices, equipment failures are extremely rare. Since thesedevices were installed, the only IMPA Protection System device that has failedwas a CT on a house power transformer that failed in the early 1990s. With thisone exception, IMPA has not had a relay, PT, CT, or DC control circuit fail topass a test, fail to operate or cause a misoperation to date.

(ii). IMPA has expedited testing on the Protection System equipment listed inCo2 above.



Through the successful completion ofthis Mitigation Plan, the ProtectionSystem components that IMPA previously failed to test have been satisfactorilytested. IMPA's Generator Protection System Maintenance and TestingProcedure has been revised to include specific assignments of responsibility andprocedures for the testing and maintenance ofall System Protection devices.The new procedure also reflects a revised testing interval that is more consistentwith the industry practices, manufacturer's recommendations and otherinformation. IMPA has developed an internal guideline to use for thescheduling and testing of certain Protection System devices to ensure no devicesare missed during the testing period. IMPA staffhas been trained on the newprocedure and guideline. IMPA has also removed from its list ofapproved



RElcontractors the contractor that failed to perfonn all of the relay tests that were inits scope of work.


Attachment D

contractors the contractor that failed to perfonn all of the relay tests that were inits scope of work.


contractors the contractor that failed to perfonn all of the relay tests that were inits scope of work.



BILIT





c) Acknowledges:

I. I am Executive Vice President of Indiana Municipal Power Agency.


3. I have read and am familiar with the contents ofthis Mitigation Plan.


Authorized Individual Signature t~.~Name (Print):

Title:

Date:

L. Gayle Mayo

Executive Vice President


Please direct completed forms or any questions regarding completion ofthis formto the ReliabilityFirst Compliance e-mail address [email protected] indicate the company name and reference the NERC Violation ill # (if

known) in the subject line of the e-mail. Additionally, any ReliabilityFirstCompliance Staffmember is available for questions regarding the use of thisform. Please see the contact list posted on the ReliabilityFirst Compliance webpage.


Attachment D



a) Submits this Mitigation Plan for acceptance by ReliabilityFirst and approval byNERC,and


c) Acknowledges:

1. I am Executive Vice President of Indiana Municipal Power Agency.


3. I have read and am familiar with the contents oftms Mitigation Plan.


Authorized Iudividual Signature t ~~Name (Print):

Title:

Date:

L. Gayle Mayo



Please direct completed forms or any questions regarding completion of this formto the ReliabilityFirst Compliance e-mail address [email protected] indicate the company name and reference the NERC Violation ill # (if

known) in the subject line of the e-mail. Additionally, any ReliabilityFirstCompliance Staffmember is available for questions regarding the use of thisform. Please see the contact list posted on the Re1iabilityFirst Compliance webpage.




a) Submits this Mitigation Plan for acceptance by ReliabilityFirst and approval byNERC,and


c) Acknowledges:

1. I am Executive Vice President of Indiana Municipal Power Agency.


3. I have read and am familiar with the contents oftms Mitigation Plan.


Authorized Iudividual Signature t ~~Name (Print):

Title:

Date:

L. Gayle Mayo



Please direct completed forms or any questions regarding completion of this formto the ReliabilityFirst Compliance e-mail address [email protected] indicate the company name and reference the NERC Violation ill # (if

known) in the subject line of the e-mail. Additionally, any ReliabilityFirstCompliance Staffmember is available for questions regarding the use of thisform. Please see the contact list posted on the Re1iabilityFirst Compliance webpage.



REAttachment A - Compliance Notices & Mitigation Plan Requirements

I. Section 6.2 of the CMEp1 sets forth the infonnation that must be included in aMitigation Plan. The Mitigation Plan must include:

(I) The Registered Entity's point of contact for the Mitigation Plan, who shall be aperson (i) responsible for filing the Mitigation Plan, (ii) technicallyknowledgeable regarding the Mitigation Plan, and (iii) authorized and competentto respond to questions regarding the status of the Mitigation Plan.

(2) The Alleged or Confinned Violation(s) ofReliability Standard(s) the MitigationPlan will correct.

(3) The cause of the Alleged or ConfIrmed Violation(s).


(5) The Registered Entity's action plan to prevent recurrence of the Alleged orConfIrmed violation(s).


(7) A timetable for completion of the Mitigation Plan including the completion dateby which the Mitigation Plan will be fully implemented and the Alleged orConfirmed Violation(s) corrected.

(8) Key implementation milestones no more than three (3) months apart forMitigation Plans with expected completion dates more than three (3) monthsfrom the date of submission. Additional violations could be determined for notcompleting work associated with accepted milestones.


(10) The Mitigation Plan shall be signed by an officer, employee, attorney or otherauthorized representative of the Registered Entity, which if applicable, shall bethe person that signed the Self-Certification or Self Reporting submittals.

II. This submittal fonn must be used to provide a required Mitigation Plan for reviewand acceptance by ReliabilityFirst and approval by NERC.

III. This Mitigation Plan is submitted to ReliabilityFirst and NERC as confidentialinfonnation in accordance with Section 1500 of the NERC Rules of Procedure.


I "Compliance Monitoring and Enforcement Program" ofthe ReliabilityFirst Corporation;" a copy of thecurrent version approved by the Federal Energy Regulatory Commissiou is posted on the ReliabilityFirstwebsite.

Version 2.0 - Released 7111/08 Page 11 ofB

Attachment D


1. Section 6.2 of the CMEp1 sets forth the infonnation that must be included in aMitigation Plan. The Mitigation Plan must include:





(5) The Registered Entity's action plan to prevent recurrence of the Alleged orConfmned violation(s).






II. This submittal fonn must be used to provide a required Mitigation Plan for reviewand acceptance by ReliabilityFirst and approval by NERC,

III. This Mitigation Plan is submitted to ReliabilityFirst and NERC as confidentialinfonnation in accordance with Section 1500 of the NERC Rules ofProcedure.





1. Section 6.2 of the CMEp1 sets forth the infonnation that must be included in aMitigation Plan. The Mitigation Plan must include:





(5) The Registered Entity's action plan to prevent recurrence of the Alleged orConfmned violation(s).






II. This submittal fonn must be used to provide a required Mitigation Plan for reviewand acceptance by ReliabilityFirst and approval by NERC,

III. This Mitigation Plan is submitted to ReliabilityFirst and NERC as confidentialinfonnation in accordance with Section 1500 of the NERC Rules ofProcedure.







VI. ReliabilityFirst or NERC may reject Mitigation Plans that they determine to beincomplete or inadequate.



Attachment D












REllDOCUMENT CONTROL


Issue: Version 2.0

Date: II July 2008


Filename: ReliabilityFirst Mitigation Plan Submittal Form - Ver 2.DOe


DOCUMENT APPROVALPrepared By Approved By Approval Signature Date


Senior Consultant Vice President and~l~ 1/2/08

Compliance Director

Compliance






2.0 TonyPurgar [email protected] 7/11/08

Version 2.0 - Released 7/11108 Page l3 ofl3

Attachment D

DOCUMENT CONTROL


Issue: Version 2.0

Date: 11 July 2008


Filename: ReliabilityFirst Mitigation Plan Submittal Form - Ver 2.DGe


DOCUMENT APPROVAL



Senior Consultant Vice President and~/·~ 1/2/08

Compliance Director

Compliance








DOCUMENT CONTROL


Issue: Version 2.0

Date: 11 July 2008


Filename: ReliabilityFirst Mitigation Plan Submittal Form - Ver 2.DGe


DOCUMENT APPROVAL



Senior Consultant Vice President and~/·~ 1/2/08

Compliance Director

Compliance









Attachment E

Certification of


Submitted June 15, 2010

Attachment E


Submittal of a Certification of Mitigation Plan Completion shall include data or information sufficient forReliabilityFirst Corporation to verify completion of the Mitigation Plan. ReliabilityFirst Corporationmay request additional data or information and conduct follow-up assessments, on-site or other SpotChecking, or Compliance Audits as it deems necessary to verify that all required actions in the MitigationPlan have been completed and the Registered Entity is in compliance with the subject ReliabilityStandard. (CMEP Section 6.6)



Date of Submittal of Certification:June 15, 2010

NERC Violation ID No(s):RFC200900190 and RFC201000239

Reliability Standard and the Requirement(s) of which a violation was mitigated:PRC-005-1 R2.1 and Rl.

Date Mitigation Plan was scheduled to be completed per accepted Mitigation Plan:IMPA performed steps1,2,3,4,6,7,8, and 9 of the action plan in D.l (Mitigation Plan) to correct the alleged violation for R2.1.IMPA was fully complaint with R2.1. on November 30, 2009. IMPA submitted the Mitigation Plan onMay 6, 2010.

IMPA performed steps 5 and 9 of the action plan in D.l (Mitigation Plan) to correct the alleged violationfor Rl. IMPA was fully compliant with Rl. on November 30, 2009. IMPA submitted the MitigationPlan on May 6, 2010.

Date Mitigation Plan was actually completed:November 30, 2009.

Additional Comments (or List of Docnments Attached):Please reference the attached summary ofdocuments included for this Certification of Mitigation Plan Completion.

I certify that the Mitigation Plan for the above named violation has been completed on the date shownabove and that all submitted information is complete and correct to the best of my knowledge.

Name:L. Gayle Mayo

Title:Executive Vice President

Page I of 4

Attachment E

Email:[email protected]

Phone:(3l7) 573-9955 ,-.j)

Authorized Signature'__~,r6-~·~··+.._j;.;..;"-~~~-",'F=--~ Date-JJ;} f10

Please direct completed forms or any questions regarding completion of this form to theReliabilityFirst Compliance e-mail address [email protected].

Please indicate the company name and reference the NERC Violation ill # (if known) in the

suhject line ofthe e-mail. Additionally, any ReliahilityFirst Compliance Staff member isavailable for questions regarding the use of this form. Please see the contact list posted on theReliabilityFirst Compliance web page.

Page 2 of 4

Attachment E

DOCUMENT CONTROL

Title:

Issue:

Date:

Distribution:

Filename:

Control:


Version 1

5 January 2008

Public



DOCUMENT APPROVAL


RobertK. Wargo Raymond J. Palmieri

Manager of Vice President and

~l~ 1/5/2009Compliance Director

EnforcementCompliance

DOCUMENT CHANGEIREVISION HISTORY



Page 3 of 4

Attachment E

Page 4 of 4

Attachment d

ReliabilityFirst’s Verification of Mitigation Plan Completion for PRC-005-1 R1 and R2.1 dated

August 13, 2010

August 13, 2010

Summary and Review of Evidence of Mitigation Plan Completion

NERC Violation ID #: RFC200900190 RFC201000239 NERC Plan ID: MIT-07-2544 Registered Entity; Indiana Municipal Power Agency NERC Registry ID: NCR00796 Standard: PRC-005-1 Requirement: 2.1 & 1 Status: Compliant

Indiana Municipal Power Agency (“IMPA”) submitted a Self Report of noncompliance with NERC Reliability Standard PRC-005-1, Requirement 2.1, on September 29, 2009. Specifically, during an internal review in preparation for submission of a self certification of compliance with PRC-005-1 on September 28, 2009, IMPA discovered that it had not performed testing for certain protection system components at its Anderson Combustion Turbine Station (Anderson Station) within the 24 month period specified in IMPA’s Generation Protection System Maintenance and Testing program. Additional comments contained in the Self Report indicated that IMPA developed its first written policy for Generation Protection System Maintenance and Testing Intervals in May 2007. That policy required testing of all generation protection systems within 24 months of the date the policy was established, not the date of previous tests. At that time IMPA defined generation protection systems as protective relays, and scheduled such relays to be tested at the same time as other protective systems such as generator breakers, switches and transformers. IMPA’s initial policy did not contemplate testing of PTs, CTs, station batteries or DC control systems as a part of this policy or on the same schedule as the protective relays. All devices were tested between May 30, 2007, when IMPA established its initial policy, and May 31, 2009 (the 24 month window allowed by the initial policy) except for the devices that are the subject of the Self Report. This additional information indicated a Possible Violation of PRC-005-1, R 1. IMPA submitted a Proposed Mitigation Plan to ReliabilityFirst on May 6, 2010, whereby stating IMPA had completed all mitigating actions on November 30, 2009. This Mitigation Plan, designated MIT-07-2544, was accepted by ReliabilityFirst on June 4, 2010, and approved by NERC on June 14, 2010.

Summary and Review of Mitigation Plan Completion MIT-07-2544 Indiana Municipal Power Agency August 13, 2010 Page 2 of 5

Review Process: On June 15, 2010, IMPA certified that Mitigation Plan for PRC-005-1, Requirements 2.1 and 1, was completed as of November 30, 2009. ReliabilityFirst requested and received evidence of completion for actions taken by IMPA as specified in the Mitigation Plan. ReliabilityFirst performed an in-depth review of the information provided to verify that all actions specified in the Mitigation Plan were completed successfully. All evidence was received on June 15, 2010: PRC-005-1, Requirement 2.1 states: “Evidence Protection System devices were maintained and tested within the defined intervals.” Evidence Submitted: Requirement 2.1: Mitigation Plan Sections D.1.1–D1.4/Milestones #1-4 – Testing of Missed Protection System Devices ReliabilityFirst verified these actions as complete by reviewing the following: IMPA-Anderson CT - Units #1, #2, and #3 Generation Protection System Device Summary (Undated) This summary lists the 115 protection system devices identified in the Mitigation Plan showing the most recent and previous test dates. It assists in tracking the devices for which maintenance and testing evidence was provided to complete Mitigation Plan (MP) Milestones #1-4. ProTesT, Last Test Results sheets for 6 devices, dated October 29, 2009. These provide documentation that includes the dates on which the 6 relays were last tested/maintained, completing MP Milestone #1. Summary Reports of test results for 7 devices, dated October 14, 2009. These provide documentation that includes the dates on which the 7 voltage transformers were last tested/maintained, completing MP Milestone #2. Summary Reports of test results for 101 devices with various dates from October 13, 2009 through October 28, 2009. These provide documentation that includes the dates on which the 101 current transformers were last tested/maintained, completing MP Milestone #3.


Email from the IMPA Asst. VP, Electrical Engineering to the IMPA Generation/ Compliance Engineer regarding 1 device, dated July 22, 2009. This provides documentation that includes the date on which the 1 DC control circuit was last tested/maintained as part of the breaker trip test, completing MP Milestone #4. The combination of the above:

a. Provides evidence that the last test dates are within the defined testing interval (R2.1.), i.e., no subsequent tests have been required,

b. Provides evidence that the outstanding maintenance tasks were completed by the respective dates indicated in the mitigation plan (July 10, 2009 through October 29, 2009),

c. Addresses the stated violation, and d. Brings IMPA into Compliance with PRC-005-1 R2.1.

PRC-005-1, Requirement 1 states: “Each Transmission Owner and any Distribution Provider that owns a transmission Protection System and each Generator Owner that owns a generation Protection System shall have a Protection System maintenance and testing program for Protection Systems that affect the reliability of the BES. The program shall include:

R1.1. Maintenance and testing intervals and their basis. R1.2. Summary of maintenance and testing procedures.”

Evidence Submitted: Requirement 1: Mitigation Plan Section D.1.5/Milestone #5 – Revise Procedure IMPA revised its Protection System maintenance and testing program for all Protection System devices included in the NERC definition. It defines maintenance and testing intervals and their basis and provides a summary of maintenance and testing procedures. ReliabilityFirst verified this action as complete by reviewing IMPA’s Generation Protection System Maintenance and Testing Procedure, dated May 30, 2007, revised September 29, 2009. This brings IMPA into Compliance with PRC-005-1 R1. Mitigation Plan Completion The Mitigation Plan further stated that Indiana Municipal Power Agency would take a number of additional steps in order to prevent similar violations from arising in the future. Each of these steps and the evidence demonstrating completion of these steps is discussed below. Each step was completed on or before the respective completion date indicated in the Mitigation Plan.


Mitigation Plan Section D.1.6/Milestone #6 – Guideline for Checking/Tracking Device Testing IMPA completed and formally approved a guideline for checking and tracking certain Protection System device testing. In accordance with this guideline, tests will be scheduled far enough in advance to assure the tests will be completed within the time frame specified and to avoid the necessity of testing during the summer to meet the schedule. The Plant Superintendent is responsible for maintaining the scheduling function and arranging for the upcoming Protection System device testing to be performed according to the schedule. ReliabilityFirst verified this action as complete by reviewing Guideline for Tracking/Verifying Relay Testing, PT and CT Testing, and DC Control Circuit Testing, approved November 20, 2009. Mitigation Plan Section D.1.7/Milestone #7 – Change of Testing Contractor To help prevent future violations of PRC-005, IMPA will not be using the testing contractor who missed the six relays during the last testing period for any future relay testing work. ReliabilityFirst verified this action as complete by reviewing the October 20, 2009 email from IMPA Asst. VP, Electrical Engineering to referenced contractor indicating cancellation of relay testing purchase order and the November 17, 2009 Memo from IMPA Asst. VP, Electrical Engineering to Plant Superintendent and VP, Generation indicating that the referenced contractor has been removed from IMPA’s list of approved electrical testing contractors. Mitigation Plan Section D.1.8/Milestone #8 – Field Personnel Briefing Prior to conducting formal training, IMPA field personnel were briefed on the proposed procedure and guideline for tracking and testing Protection System equipment. ReliabilityFirst verified this action as complete by reviewing snapshots of the Calendar and Journal of the Plant Superintendent CT Facilities indicating a briefing on October 20, 2009 with the Asst. VP, Electrical Engineering and four power plant field personnel. Mitigation Plan Section D.1.9/Milestone #9 - Training IMPA conducted training for the Combustion Turbine Operators, Plant Superintendent, and Assistant Vice- President of Electrical Engineering on the revised Generation Protection System Maintenance and Testing Procedure and the new Guideline for Tracking/Verifying Relay Testing, PT and CT Testing, and DC Control Circuit Testing. ReliabilityFirst verified this action as complete by reviewing the Generation Protection System Maintenance and Testing, PT and CT Testing, Relay Testing, and DC Control Circuit Testing Verification IMPA Staff Review Record, dated November 30, 2009 which includes the signature and date of the personnel that received this training.


Review Results: ReliabilityFirst Corporation reviewed the evidence the IMPA submitted in support of its Certification of Completion. On August 13, 2010, ReliabilityFirst verified that the Mitigation Plan was completed in accordance with its terms and has therefore deemed IMPA compliant to the aforementioned NERC Reliability Standard. Respectfully Submitted,

Robert K. Wargo Manager of Compliance Enforcement ReliabilityFirst Corporation

Attachment e Disposition Document for Common Information

Attachment e

Indiana Municipal Power Agency Page 1 of 4

DISPOSITION OF VIOLATION1

INFORMATION COMMON TO INSTANT VIOLATIONS

Dated September 10, 2010

REGISTERED ENTITY NERC REGISTRY ID NOC# Indiana Municipal Power Agency (IMPA)

NCR00796 NOC-602

REGIONAL ENTITY ReliabilityFirst Corporation (ReliabilityFirst)

I. REGISTRATION INFORMATION

ENTITY IS REGISTERED FOR THE FOLLOWING FUNCTIONS: BA DP GO GOP IA LSE2 PA PSE RC RP RSG TO TOP TP TSP

X X X X X

5/30

/200

7

5/30

/200

7

5/30

/200

7

5/30

/200

7

5/30

/200

7

DESCRIPTION OF THE REGISTERED ENTITY IMPA was created in 1980 by a group of municipally-owned electric utilities. IMPA, called a joint action agency, was formed so these utilities could share power resources, allowing member cities and towns to provide electricity more economically to their customers. IMPA began operations in 1983 with 26 members and currently, 52 Indiana cities and towns are members. IMPA is a not-for-profit organization. IMPA member utilities purchase their power requirements through IMPA and deliver that power to the residents and companies in their service territories throughout Indiana. IMPA has annual revenues approaching $300 million and assets total approximately $1 billion, which include five generation sites and joint transmission system ownership. IMPA has two generating units which it owns in part. Trimble County Unit 1 is a 514 MW coal-fired electric generating unit located in northern Kentucky. IMPA has a 12.88 percent undivided ownership interest in the unit, which is jointly owned by Louisville Gas and Electric and the Illinois Municipal Electric Agency. Gibson Station Unit 5 is a 625 MW coal-fired generating unit located in southwestern Indiana. IMPA has a 24.95 percent undivided ownership interest in Unit 5, which it

1 For purposes of this document and attachments hereto, each violation at issue is described as a “violation,” regardless of its procedural posture and whether it was a possible, alleged or confirmed violation. 2 IMPA has a Coordinated Functional Registration for the LSE function – JRO00020.

Attachment e


jointly owns with Duke Energy Indiana and Wabash Valley Power Association. IMPA has seven wholly-owned combustion turbines and associated facilities aggregating 419 MW. They include two 41 MW units and one 85 MW unit located in Anderson; two 41 MW units located near Richmond; and two 85 MW units located in Indianapolis. The Anderson and Richmond units operate primarily on natural gas and maintain an inventory of fuel oil as an alternative fuel. The Indianapolis units operate solely on natural gas.

IS THERE A SETTLEMENT AGREEMENT YES NO WITH RESPECT TO THE VIOLATION(S), REGISTERED ENTITY

NEITHER ADMITS NOR DENIES IT (SETTLEMENT ONLY) YES ADMITS TO IT YES DOES NOT CONTEST IT (INCLUDING WITHIN 30 DAYS) YES WITH RESPECT TO THE ASSESSED PENALTY OR SANCTION, REGISTERED ENTITY ACCEPTS IT/ DOES NOT CONTEST IT YES

II. PENALTY INFORMATION TOTAL ASSESSED PENALTY OR SANCTION OF $22,000 FOR THREE VIOLATIONS OF RELIABILITY STANDARDS. (1) REGISTERED ENTITY’S COMPLIANCE HISTORY

PREVIOUSLY FILED VIOLATIONS OF ANY OF THE INSTANT RELIABILITY STANDARD(S) OR REQUIREMENT(S) THEREUNDER YES NO LIST VIOLATIONS AND STATUS

ADDITIONAL COMMENTS

PREVIOUSLY FILED VIOLATIONS OF OTHER RELIABILITY STANDARD(S) OR REQUIREMENTS THEREUNDER YES NO

LIST VIOLATIONS AND STATUS

Attachment e


ADDITIONAL COMMENTS

(2) THE DEGREE AND QUALITY OF COOPERATION BY THE REGISTERED ENTITY (IF THE RESPONSE TO FULL COOPERATION IS “NO,” THE ABBREVIATED NOP FORM MAY NOT BE USED.) FULL COOPERATION YES NO

IF NO, EXPLAIN (3) THE PRESENCE AND QUALITY OF THE REGISTERED ENTITY’S COMPLIANCE PROGRAM IS THERE A DOCUMENTED COMPLIANCE PROGRAM

YES NO UNDETERMINED EXPLAIN

At the time of the violation, IMPA had a documented internal compliance program, which RFC considered a mitigating factor in determining the penalty. IMPA’s compliance program has the support and participation of senior management and seven of the nine positions with the highest responsibility for implementing IMPA’s internal compliance program are Assistant Vice President rank or higher. IMPA also conducts annual internal self-audits of Reliability Standards.

EXPLAIN SENIOR MANAGEMENT’S ROLE AND INVOLVEMENT WITH RESPECT TO THE REGISTERED ENTITY’S COMPLIANCE PROGRAM, INCLUDING WHETHER SENIOR MANAGEMENT TAKES ACTIONS THAT SUPPORT THE COMPLIANCE PROGRAM, SUCH AS TRAINING, COMPLIANCE AS A FACTOR IN EMPLOYEE EVALUATIONS, OR OTHERWISE. See above.

(4) ANY ATTEMPT BY THE REGISTERED ENTITY TO CONCEAL THE VIOLATION(S) OR INFORMATION NEEDED TO REVIEW, EVALUATE OR INVESTIGATE THE VIOLATION.

YES NO IF YES, EXPLAIN (5) ANY EVIDENCE THE VIOLATION(S) WERE INTENTIONAL (IF THE RESPONSE IS “YES,” THE ABBREVIATED NOP FORM MAY NOT BE USED.)

YES NO

Attachment e


IF YES, EXPLAIN (6) ANY OTHER MITIGATING FACTORS FOR CONSIDERATION

YES NO IF YES, EXPLAIN (7) ANY OTHER AGGRAVATING FACTORS FOR CONSIDERATION

YES NO IF YES, EXPLAIN (8) ANY OTHER EXTENUATING CIRCUMSTANCES

YES NO IF YES, EXPLAIN OTHER RELEVANT INFORMATION:

NOTICE OF ALLEGED VIOLATION AND PROPOSED PENALTY OR SANCTION ISSUED DATE: OR N/A SETTLEMENT DISCUSSIONS COMMENCED DATE: 5/6/10OR N/A NOTICE OF CONFIRMED VIOLATION ISSUED DATE: OR N/A SUPPLEMENTAL RECORD INFORMATION DATE(S) OR N/A REGISTERED ENTITY RESPONSE CONTESTED FINDINGS PENALTY BOTH NO CONTEST HEARING REQUESTED YES NO DATE OUTCOME APPEAL REQUESTED

Disposition Document for VAR-002-1.1a R2

Attachment e-1


DISPOSITION OF VIOLATION Dated September 10, 2010

NERC TRACKING NO.

REGIONAL ENTITY TRACKING NO.

RFC200900157 RFC200900157

I. VIOLATION INFORMATION RELIABILITY STANDARD

REQUIREMENT(S) SUB-REQUIREMENT(S)

VRF(S) VSL(S)

VAR-002-1.1a1 2 Medium Moderate

VIOLATION APPLIES TO THE FOLLOWING FUNCTIONS: BA DP GO GOP IA LSE PA PSE RC RP RSG TO TOP TP TSP

X PURPOSE OF THE RELIABILITY STANDARD AND TEXT OF RELIABILITY STANDARD AND REQUIREMENT(S)/SUB-REQUIREMENT(S) The purpose statement of VAR-002-1.1a provides: “To ensure generators provide reactive and voltage control necessary to ensure voltage levels, reactive flows, and reactive resources are maintained within applicable Facility Ratings to protect equipment and the reliable operation of the Interconnection.” VAR-002-1.1a R2 provides:

R2. Unless exempted by the Transmission Operator, each Generator Operator shall maintain the generator voltage or Reactive Power output (within applicable Facility Ratings) as directed by the Transmission Operator.

R2.1. When a generator’s automatic voltage regulator is out of service, the Generator Operator shall use an alternative method to control the generator voltage and reactive output to meet the voltage or Reactive Power schedule directed by the Transmission Operator. R2.2. When directed to modify voltage, the Generator Operator shall comply or provide an explanation of why the schedule cannot be met.

1 VAR-002-1 was enforceable from August 2, 2007 through August 27, 2008. VAR-002-1a was approved by the Commission and was enforceable from August 28, 2008 through May 13, 2009. VAR-002-1.1a was approved by the Commission and was enforceable from May 13, 2009 through September 16, 2010. VAR-002-1.1b was approved by the Commission and became enforceable on September 16, 2010. The subsequent interpretations provide clarity regarding the responsibilities of a registered entity and do not change the meaning or language of the original NERC Reliability Standard and its requirements. For consistency in this filing, the version applicable when the violation was discovered, VAR-002-1.1a, is used throughout.

Attachment e-1


VIOLATION DESCRIPTION On June 24, 2009, IMPA self-reported a violation of VAR-002-1.1a R2 for its failure to maintain its generator voltage output as directed by its delegated Transmission Operator, American Electric Power (AEP).2 As a result of an internal review, IMPA discovered three dates on which its Anderson Station combustion turbine generating units produced power but the station’s voltage reading was not recorded in its operating logs.3

After acquiring historical voltage information from Duke Energy Indiana, IMPA reviewed the information for the three dates and determined that the station voltage on only one of the dates, January 25, 2009, was higher than the voltage schedule issued by the Transmission Operator. The system voltage was approximately 142.5 kV when IMPA brought the subject generating units online. The connection of the subject generating units reduced the station voltage to approximately 141.8 kV but IMPA’s station voltage remained higher than the specified voltage schedule (139 kV ± 1%). IMPA did not receive an exemption from its delegated Transmission Operator to maintain its station voltage higher than the voltage schedule and subsequently violated the subject Standard’s requirement.

RELIABILITY IMPACT STATEMENT- POTENTIAL AND ACTUAL ReliabilityFirst determined this violation did not pose a substantial risk to the BPS because the units produced power for a very short period of time (ACT 1 and ACT 2 were generating power for approximately 2 hours, and ACT 3 was generating power for approximately 3 hours) and actually lowered the system voltage to a level closer to the station voltage schedule provided by AEP. ReliabilityFirst determined the actual risk to the system was minimal which was confirmed when IMPA received a revised voltage schedule from AEP that is more consistent with the actual operating circumstances at the site. The revised voltage schedule is 139.5 kV± 2.5%.

II. DISCOVERY INFORMATION METHOD OF DISCOVERY

SELF-REPORT SELF-CERTIFICATION COMPLIANCE AUDIT COMPLIANCE VIOLATION INVESTIGATION SPOT CHECK COMPLAINT PERIODIC DATA SUBMITTAL EXCEPTION REPORTING

2 PJM Interconnection, LLC (PJM) delegated its Transmission Operator responsibilities to AEP at IMPA’s station. 3 The three dates where the Anderson Station’s voltage readings were note recorded in its operating logs are January 25, 2009, May 27, 2009, and May 28, 2009. IMPA used historical data to verify that on May 27, 2009 and May 28, 2009, the units were running for those two dates and that IMPA maintained the proper voltage according to its voltage schedule.

Attachment e-1


DURATION DATE(S) This violation was mitigated within one day on January 25, 2009. DATE DISCOVERED BY OR REPORTED TO REGIONAL ENTITY 6/24/2009 IS THE VIOLATION STILL OCCURRING YES NO IF YES, EXPLAIN

REMEDIAL ACTION DIRECTIVE ISSUED YES NO PRE TO POST JUNE 18, 2007 VIOLATION YES NO

III. MITIGATION INFORMATION FOR FINAL ACCEPTED MITIGATION PLAN:

MITIGATION PLAN NO. MIT-09-2059 DATE SUBMITTED TO REGIONAL ENTITY 9/18/2009 DATE ACCEPTED BY REGIONAL ENTITY 10/23/2009 DATE APPROVED BY NERC 10/26/2009 DATE PROVIDED TO FERC 10/26/2009

IDENTIFY AND EXPLAIN ALL PRIOR VERSIONS THAT WERE ACCEPTED OR REJECTED, IF APPLICABLE MITIGATION PLAN COMPLETED YES NO

EXPECTED COMPLETION DATE Submitted as complete EXTENSIONS GRANTED N/A

ACTUAL COMPLETION DATE 9/11/2009

DATE OF CERTIFICATION LETTER 10/29/2009 CERTIFIED COMPLETE BY REGISTERED ENTITY AS OF 9/11/2009

DATE OF VERIFICATION LETTER 11/16/2009

VERIFIED COMPLETE BY REGIONAL ENTITY AS OF 9/11/2009

ACTIONS TAKEN TO MITIGATE THE ISSUE AND PREVENT RECURRENCE

• IMPA re-trained the combustion turbine operators on the procedure for documenting and maintaining the voltage schedule for system voltage.

• IMPA entered an Anderson Substation system voltage data point into its Supervisory Control and Data Acquisition (SCADA) system that

Attachment e-1


will be recorded and used in case a system voltage point reading is not recorded for a time period in which the gas turbines are online.

• IMPA revised its procedure for documenting and maintaining the voltage schedule for system voltage to ensure the awareness is raised in its operations staff for documenting and/or maintaining a generator’s automatic voltage regulator and the voltage schedule for system voltage.

• IMPA sent a letter to AEP to request a revised voltage schedule for its Anderson Station, which is more consistent with the actual operating circumstances at the site and that references PJM’s Default Generator Voltage Schedule.

• IMPA directed the power system coordinators and the combustion turbine operators to review the revised procedure for documenting and maintaining the voltage schedule for system voltage, and to sign an IMPA staff review record sheet.

• IMPA received a revised voltage schedule from AEP that is more consistent with the actual operating circumstances at the site. The revised voltage schedule is 139.5 kV± 2.5%.

LIST OF EVIDENCE REVIEWED BY REGIONAL ENTITY TO EVALUATE COMPLETION OF MITIGATION PLAN OR MILESTONES (FOR CASES IN WHICH MITIGATION IS NOT YET COMPLETED, LIST EVIDENCE REVIEWED FOR COMPLETED MILESTONES)

1. VAR-002-1.1a Generator Operation for Maintaining Network Voltage Schedules, IMPA Staff Review Record signed and dated by Combustion Turbine CT Operators on June 8, 2009 certified that they have reviewed and understand the AEP voltage schedule and GOP Requirements: Reporting AVR & PSS Status;

2. Examples of Anderson Station 138 kV bus voltage data points for June 2, 009 was provided that will be recorded and used in case a system voltage point reading is not recorded for a time period in which the gas turbines are online;

3. IMPA NERC Reliability Standards, Procedure for Documenting/Maintaining a Generator's Automatic Voltage Regulator Mode and the Voltage Schedule for System Voltage, dated July 31, 2009 and approved August 10, 2009. Section I Voltage Schedule includes a procedure for the Combustion Turbine Operator to monitor, document and maintain system voltage and the notification process to be utilized by the Power System Coordinator (PSC) when system voltage is outside to the voltage schedule specification or tolerance. This revision should ensure that awareness is raised in IMPA’s operations staff for documenting and/or maintaining a generator's automatic voltage regulator mode and the voltage schedule for system voltage;

4. Letter from IMPA to AEP dated July 22, 2009 requesting a revised voltage schedule that is more consistent with the actual operating circumstances at its Anderson combustion turbine site;

Attachment e-1


5. VAR-002-1.1a Generator Operation for Maintaining Network Voltage Schedules, IMPA Staff Review Record signed and dated by IMPA personnel during August and September 2009 which certifies that employees have reviewed and understand the AEP voltage schedule and GOP Requirements: Reporting AVR & PSS Status. This covers revision up to and including revision 2 approved August 10, 2009; and

6. Letter from AEP to all generator owners and generator operators interconnected to the AEP-East Transmission System in the PJM regional transmission organization footprint dated July 27, 2009 provides an AEP-East Transmission System (RFC/PJM), IMPA - South Anderson Generator Power Factor Schedule. The Voltage Schedule @AEP Interconnection Point indicates 1.011 p.u – 139.5 kV with a a steady-state deviation between ± 2.5% of the specified voltage schedule that is permissible per PJM Default Generator Voltage Schedules highlighted in Manual 3: Transmission Operations, Section 3: Voltage & Stability Operating Guidelines, page 30. The Combustion Turbine Operators and PSCs were provided with the new schedule on the date it was received.

EXHIBITS:

SOURCE DOCUMENT IMPA’s Self-Report dated June 24, 2009 MITIGATION PLAN IMPA’s Mitigation Plan dated September 18, 2009 CERTIFICATION BY REGISTERED ENTITY

IMPA’s Certification of Mitigation Plan Completion dated October 29, 2009

VERIFICATION BY REGIONAL ENTITY ReliabilityFirst’s Verification of Mitigation Plan Completion dated November 16, 2009

Disposition Document for PRC-005-1

Attachment e-2


DISPOSITION OF VIOLATION Dated September 10, 2010

NERC TRACKING NO.

REGIONAL ENTITY TRACKING NO.

RFC201000239 RFC200900190

RFC201000239 RFC200900190

I. VIOLATION INFORMATION

RELIABILITY STANDARD

REQUIREMENT(S) SUB-REQUIREMENT(S)

VRF(S) VSL(S)

PRC-005-1 1 High1 High PRC-005-1 2 2.1 High2 Lower

VIOLATION APPLIES TO THE FOLLOWING FUNCTIONS: BA DP GO GOP IA LSE PA PSE RC RP RSG TO TOP TP TSP

X PURPOSE OF THE RELIABILITY STANDARD AND TEXT OF RELIABILITY STANDARD AND REQUIREMENT(S)/SUB-REQUIREMENT(S) The purpose statement of PRC-005-1 provides: “To ensure all transmission and generation Protection Systems[3

] affecting the reliability of the Bulk Electric System (BES) are maintained and tested.” (Footnote added)

PRC-005-1 R1 provides: R1. Each Transmission Owner and any Distribution Provider that owns a transmission Protection System and each Generator Owner that owns a generation Protection System shall have a Protection System maintenance and testing program for Protection Systems that affect the reliability of the BES.” The program shall include:

1 When NERC filed Violation Risk Factors (VRFs) it originally assigned PRC-005-1 R1 a “Medium” VRF. The Commission approved the VRF as filed; however, it directed NERC to submit modifications. NERC submitted the modified “High” VRF and on August 9, 2007, the Commission approved the modified “High” VRF. Therefore, the “Medium” VRF for PRC-005-1 R1 was in effect from June 18, 2007 until August 9, 2007 when the “High” VRF became effective. 2 PRC-005-1 R2 has a “Lower” VRF; R2.1 and R2.2 each have a “High” VRF. During a final review of the standards subsequent to the March 23, 2007 filing of the Version 1 VRFs, NERC identified that some standards requirements were missing VRFs; one of these include PRC-005-1 R2.1. On May 4, 2007, NERC assigned PRC-005 R2.1 a “High” VRF. In the Commission’s June 26, 2007 Order on Violation Risk Factors, the Commission approved the PRC-005-1 R2.1 “High” VRF as filed. Therefore, the “High” VRF was in effect from June 26, 2007. 3 The NERC Glossary of Terms Used in Reliability Standards defines Protection System as “Protective relays, associated communication systems, voltage and current sensing devices, station batteries and DC control circuitry.”

Attachment e-2


R1.1. Maintenance and testing intervals and their basis. R1.2. Summary of maintenance and testing procedures.

PRC-005-1 R2 provides in pertinent part: R2. Each Transmission Owner and any Distribution Provider that owns a transmission Protection System and each Generator Owner that owns a generation Protection System shall provide documentation of its Protection System maintenance and testing program and the implementation of that program to its Regional Reliability Organization[4

R2.1. Evidence Protection System devices were maintained and tested within the defined intervals. …

] on request (within 30 calendar days). The documentation of the program implementation shall include:

VIOLATION DESCRIPTION On September 29, 2009, IMPA self-reported a violation PRC-005-1 R2.1 because it failed to conduct maintenance and testing within defined intervals, on six breaker failure relays on generator protection breakers at its Anderson Station. Upon further review, after receiving IMPA’s response on January 7, 2010 to a request for information, ReliabilityFirst determined that IMPA’s self report also indicated a violation of PRC-005-1 R1 because its generation Protection System maintenance and testing program did not include potential transformers (PTs), current transformers (CTs), station batteries, or DC control circuitry, some of which were also not tested. IMPA’s initial generation Protection System maintenance and testing program, which went into effect in May 2007, defined an interval of 24 months for all generation Protection System relays. The program did not, however, include maintenance and testing intervals and their basis, or a summary of maintenance and testing procedures for PTs, CTs, station batteries and DC control circuitry. According to the Settlement, IMPA indicated in its Self-Report that it had failed to test the following devices:

(1) six breaker failure relays on generator protection breakers; (2) the DC control circuitry for its Anderson Unit 3; (3) seven of the 21 PTs on its Anderson Unit 3; and (4) all of the 101 CTs on Anderson Units 1 through 3.

4 Consistent with applicable FERC precedent, the term ‘Regional Reliability Organization’ in this context refers to ReliabilityFirst.

Attachment e-2


IMPA indicated in response to an information request that there are 197 protection system devices at its Anderson facility. IMPA owns and operates other protection system devices at other facilities that are not subject to the NERC standards. ReliabilityFirst determined that (1) IMPA’s failure to test the six breaker failure relays in accordance with its generation Protection System maintenance and testing program constituted a violation of PRC-005-1 R2.1, and (2) IMPA’s failure to test the DC control circuitry, the PTs and the CTs should not be treated as a separate violation of PRC-005-1 R2.1 because it arose out of a “common incidence” that also gave rise to the violation of PRC-005-1 R1. In other words, the program, at the time of the Self-Report, did not define any testing intervals for those devices. Testing on the six breaker failure relays was completed by October 29, 2009 approximately 18 months after the originally scheduled test period of April 2008. RELIABILITY IMPACT STATEMENT- POTENTIAL AND ACTUAL ReliabilityFirst determined that the violation of PRC-005-1 R1 did not pose a serious or substantial risk to the bulk power system (BPS) because, with the exception of the above listed devices, IMPA tested all of its PTs, CTs, station batteries, and DC control circuitry between May 30, 2007 and May 31, 2009 even though the devices were not included in the Protection System maintenance and testing program. IMPA provided this information in its Mitigation Plan to ReliabilityFirst and provided a spreadsheet listing the dates that each protection system device was last tested or maintained in response to a ReliabilityFirst information request. With regard to PRC-005-1 R2.1, ReliabilityFirst determined that the violation did not pose a serious or substantial risk to the BPS because all Protection System devices affected by the violation had a condition of “Good” or “Pass” during the test interval immediately prior to the missed test interval, and upon completion of the deficient testing. IMPA did not discover any problems with the condition of any of the affected devices. Although the DC control circuitry on Anderson Unit 3 was not formally tested through the performance of trip checks, it was routinely exercised during the operation of plant and substation equipment and was demonstrated to operate properly as recently as June 1, 2009. This evidence indicates that the DC control circuitry for Anderson Unit 3 was operating properly and did not pose a threat to the reliability of the BES. IMPA indicated that failure to perform timely tests of the breaker failure relays could have resulted in delayed detection of relay failures. IMPA tested PTs every other year when doing unit calibrations and generator control inspections at the site. IMPA tested CTs at the time of commissioning, and performed additional testing if an operational problem with a CT was suspected. A failure of the PTs on Unit 3 would have activated an alarm on the Mark VI control system, which is checked at least weekly. If the CTs were not operating properly, they would cause the generating units to trip. Since at least one of the generating units was operated on May 27, May 28, June 1, July 28, and

Attachment e-2


September 24, 2009, this effectively demonstrates that the CTs were and continue to operate properly.

II. DISCOVERY INFORMATION METHOD OF DISCOVERY

SELF-REPORT SELF-CERTIFICATION COMPLIANCE AUDIT COMPLIANCE VIOLATION INVESTIGATION SPOT CHECK COMPLAINT PERIODIC DATA SUBMITTAL EXCEPTION REPORTING

DURATION DATE(S) 6/18/07 (when the Standard became mandatory and enforceable) through 11/30/09 (Mitigation Plan completion) DATE DISCOVERED BY OR REPORTED TO REGIONAL ENTITY R1 - 1/7/2010 R2.1 - 9/29/2009 (confirmed via response to ReilabilityFirst’s Request for Information, although information alluding to PRC-005-1, R1 was included in the self-report). IS THE VIOLATION STILL OCCURRING YES NO IF YES, EXPLAIN

REMEDIAL ACTION DIRECTIVE ISSUED YES NO PRE TO POST JUNE 18, 2007 VIOLATION YES NO

III. MITIGATION INFORMATION FOR FINAL ACCEPTED MITIGATION PLAN:

MITIGATION PLAN NO. MIT-07-2544 DATE SUBMITTED TO REGIONAL ENTITY 5/6/2010 DATE ACCEPTED BY REGIONAL ENTITY 6/4/2010 DATE APPROVED BY NERC 6/14/2010 DATE PROVIDED TO FERC 6/14/2010

IDENTIFY AND EXPLAIN ALL PRIOR VERSIONS THAT WERE ACCEPTED OR REJECTED, IF APPLICABLE N/A MITIGATION PLAN COMPLETED YES NO

EXPECTED COMPLETION DATE Submitted as complete

Attachment e-2


EXTENSIONS GRANTED N/A ACTUAL COMPLETION DATE 11/30/2009

DATE OF CERTIFICATION LETTER 6/15/2010 CERTIFIED COMPLETE BY REGISTERED ENTITY AS OF 11/30/2009

DATE OF VERIFICATION LETTER 8/13/2010

VERIFIED COMPLETE BY REGIONAL ENTITY AS OF 11/30/2009

ACTIONS TAKEN TO MITIGATE THE ISSUE AND PREVENT RECURRENCE

1. IMPA replaced the contractor who missed testing the relays on generation protections breakers;

2. IMPA tested the relays missed on generator protection breakers; 3. IMPA satisfactorily tested the PTs, CTs and the DC control circuitry; 4. IMPA revised its Generation Protection System maintenance and

testing program to include all required Protection System devices (per NERC’s definition);

5. IMPA revised the testing intervals based on industry practices, manufacturer’s recommendations and other information;

6. IMPA developed and formally approved a guideline for tracking the testing of Protection System devices;

7. IMPA briefed its field personnel on the revised program and guideline for tracking the testing of Protection System devices; and

8. IMPA conducted training on its revised program and the new guideline for tracking the testing of Protection System devices.

LIST OF EVIDENCE REVIEWED BY REGIONAL ENTITY TO EVALUATE COMPLETION OF MITIGATION PLAN OR MILESTONES (FOR CASES IN WHICH MITIGATION IS NOT YET COMPLETED, LIST EVIDENCE REVIEWED FOR COMPLETED MILESTONES) In support of PRC-005-1 R1, ReliabilityFirst reviewed:

1. IMPA’s Generation Protection System Maintenance and Testing Procedure, dated May 30, 2007 and revised September 29, 2009.

2. Guideline for Tracking/Verifying Relay Testing, PT and CT Testing, and DC Control Circuit Testing, approved November 20, 2009.

3. E-mail from IMPA Asst. VP, Electrical Engineering to referenced contractor indicating cancellation of relay testing purchase order dated October 20, 2009.

4. Memo from IMPA Asst. VP, Electrical Engineering to Plant Superintendent and VP, Generation indicating that the referenced contractor has been removed from IMPA’s list of approved electrical testing contractor, dated November 17, 2009.

Attachment e-2


5. Snapshots of the Calendar and Journal of the Plant Superintendent CT Facilities indicating a briefing on October 20, 2009 with the Asst. VP, Electrical Engineering and four power plant field personnel.

6. Generation Protection System Maintenance and Testing, PT and CT Testing, Relay Testing, and DC Control Circuit Testing Verification IMPA Staff Review Record, dated November 30, 2009 including the signature and date of the personnel that received the training.

In support of PRC-005-1 R2.1, ReliabilityFirst reviewed:

1. IMPA-Anderson CT - Units #1, #2, and #3 Generation Protection System Device Summary, undated. This summary lists the 115 Protection System devices identified in the Mitigation Plan showing the most recent and previous test dates. It assists in tracking the devices for which maintenance and testing evidence was provided to complete the Mitigation Plan.

2. ProTesT, Last Test Results sheets for 6 devices, dated October 29, 2009. These provide documentation that includes the dates on which the 6 relays were last tested/maintained.

3. Summary Reports of test results for 7 devices, dated October 14, 2009. These provide documentation that includes the dates on which the 7 voltage transformers were last tested/maintained.

4. Summary Reports of test results for 101 devices with various dates from October 13, 2009 through October 28, 2009. These provide documentation that includes the dates on which the 101CTs were last tested/maintained.

5. E-mail from the IMPA Asst. VP, Electrical Engineering to the IMPA Generation/Compliance Engineer regarding 1 device, dated July 22, 2009. This provides documentation that includes the date on which the 1 DC control circuit was last tested/maintained as part of the breaker trip test.

EXHIBITS:

SOURCE DOCUMENT IMPA’s Self-Report dated September 29, 2009 MITIGATION PLAN IMPA’s Mitigation Plan dated May 6, 2010 CERTIFICATION BY REGISTERED ENTITY

IMPA’s Certification of Mitigation Plan Completion dated June 15, 2010

VERIFICATION BY REGIONAL ENTITY ReliabilityFirst’s Verification of Mitigation Plan Completion dated August 13, 2010

Attachment e

Notice of Filing

UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION

Indiana Municipal Power Agency Docket No. NP11-___-000

NOTICE OF FILING November 30, 2010

Take notice that on November 30, 2010, the North American Electric Reliability

Corporation (NERC) filed a Notice of Penalty regarding Indiana Municipal Power Agency in the ReliabilityFirst Corporation region.

Any person desiring to intervene or to protest this filing must file in accordance with Rules 211 and 214 of the Commission’s Rules of Practice and Procedure (18 CFR 385.211, 385.214). Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceeding. Any person wishing to become a party must file a notice of intervention or motion to intervene, as appropriate. Such notices, motions, or protests must be filed on or before the comment date. On or before the comment date, it is not necessary to serve motions to intervene or protests on persons other than the Applicant.

The Commission encourages electronic submission of protests and interventions

in lieu of paper using the “eFiling” link at http://www.ferc.gov. Persons unable to file electronically should submit an original and 14 copies of the protest or intervention to the Federal Energy Regulatory Commission, 888 First Street, N.E., Washington, D.C. 20426.

This filing is accessible on-line at http://www.ferc.gov, using the “eLibrary” link and is available for review in the Commission’s Public Reference Room in Washington, D.C. There is an “eSubscription” link on the web site that enables subscribers to receive email notification when a document is added to a subscribed docket(s). For assistance with any FERC Online service, please email [email protected], or call (866) 208-3676 (toll free). For TTY, call (202) 502-8659. Comment Date: [BLANK]

Kimberly D. Bose, Secretary