CHAPTER 4 ATTACHMENT 4.1 SCE Responses to Public …CHAPTER 4 ATTACHMENT 4.1 SCE Responses to Public Advocates Office Data Request 18, Question 1-57. DATA REQUEST SET A1803016 ORA-SCE-18

CHAPTER 4 ATTACHMENT 4.1

SCE Responses to Public Advocates Office Data Request 18, Question 1-57.

DATA REQUEST SET A1803016 ORA-SCE-18

To: ORA Prepared by: Timothy Condit

Title: Sr. Advisor Dated: 06/29/2018

Question 01:

1. Who are the owners of the Barre Peaker (Barre)? Please provide ownership breakdown by each owner, if any.

Response to Question 01:

SCE is the sole owner and operator of the Barre Peaker Plant.




Question 02:

2. What was the Application and Commission Decision which approved the purchase/construction of Barre?


SCE objects to the question as beyond the scope of the proceeding. Subject to and without waiving that objection, SCE responds as follows: On August 15, 2006, in Rulemakings 05-12-013 and 06-02-013 (see attached pdf), an Assigned Commissioners Ruling (ACR) “Addressing Electric Reliability Needs in Southern California For Summer 2007” directed Southern California Edison Company (SCE) to, among other things, pursue the development and installation of up to 250 MW of black-start, dispatchable generation capacity within its service territory for summer 2007 operation. These rulemakings were approved by the Commission in Resolution E-4031 (see attached pdf). The Barre Peaker is one of five peakers that SCE constructed in response to these Commission actions. PDF attachment available via email.




Question 03:

3. What was the Application and Commission Decision which approved the rate recovery of Barre? Response to Question 03:

SCE objects to the question as beyond the scope of the proceeding. Subject to and without waiving that objection, SCE responds as follows: Costs associated with acquiring and constructing the five Peakers was requested in Application 07-12-029 and approved in Decision 10-05-008. Peaker O&M cost recovery was requested in SCE’s 2009 GRC Application 07-11-011, and approved by the Commission in Decision 09-03-025 (see attached pdf). PDF attachment available via email.




Question 04:

4. What is the generating capacity of Barre?


The Barre Peaker has a nominal operating capacity of 49 MW.




Question 05:

5. What was the commissioning date of the Barre peaker?


August 2007.




Question 06:

Barre Peaker Forced Outage – May 11, 2017 (Reference: page 59 of SCE-01) 6. Please provide the exact date and time of the outage and the resumption of service. In the MDR response to

#Q.1.1.04b-c, the Attachment_Q1.1.4-Q1.1.13 Fossil-fueled Excel spreadsheet shows the outage as from 5/11/2017 10:49 to 6/19/2017 16:28 (39.24 days): is this information still correct?


SCE understands that this question refers to the Barre Peaker outage taken to address generator rotor electrical ground indication issues. SCE notes that the question contains a typographical error regarding the outage end date. As provided in the attachment to SCE’s response to MDR #Q.1.1.04b-c, and as also shown in the table below, 5/11/2017 10:49 is the start date/time and 5/19/2017 16.28 is the end date/time for this outage (i.e., the duration of this outage was approximately eight days).

1.1.13.1 1.1.13.2 1.1.13.3 1.1.13.4 1.1.13.5 1.1.13.6 1.1.13.7

Plant Units Start End NERC EventType

NERC Cause Code

NERC Cause Code Description

Mountainview 3 10/18/2017 4:28

12/31/2017 23:59 U1 4012 IP steam turbine damage and HRH 534 Vv seat

liberation issues

Mountainview 4 10/31/2017 0:00

12/31/2017 23:59 U1 4012 HP steam turbine damage and HRH 534 Vv seat

liberation issues

McGrath Peaker 1 2/19/2017 8:30

3/23/2017 11:02 U1 3642 13.8KV to 480V XFRMR bus bar arc damage

Barre Peaker 1 5/11/2017 10:49

5/19/2017 16:28 U1 4511 Generator Rotor Ground Issue OMS#4900815

Center Peaker 1 9/8/2017 21:48

9/12/2017 5:59 U1 4552 Generator Lube Oil Filters HI D/P after adding oil.


3/11/2017 12:43 U1 5530 Hydraulic Starter Failed

McGrath Peaker 1 4/25/2017 19:46

4/27/2017 10:31 U1 5441 Failed to fire, Gas Solenoid Issues.


5/18/2017 13:08 U1 8813 Water Injection Drain Valve SOV-6210 failed, unit

unable to control NOX




Question 07:

Barre Peaker Forced Outage – May 11, 2017 (Reference: page 59 of SCE-01) 7. SCE’s direct testimony (line 20 to 22) states that the generator rotor electrical ground detection instrument

experienced an intermittent fault-to-ground alarm condition between June 24, 2015 and May 10, 2017. In the following table, please provide more information of those alarm incidents during that three-year period:

# Date and time of alarm Forced Outage1 Corrective/ Remedial Action: What work was done2

Post Mortem Report:

Yes/No3

Start (a)

End (b)

Duration (c) = (b) - (a)

Yes /No (d)

Star t (e)

End (f)

Duratio n (g) = (f) - (e)

1 June 24, 2015 at xx hr

May 10, 2017 at xx hr


SCE provided an Apparent Cause Evaluation Report regarding this outage in SCE's direct testimony workpapers for this proceeding. As summarized on page 5 of that report, prior to the event which began on May 10, 2017, there were ten incidents of a generator rotor electrical ground fault alarm being triggered within the Barre Peaker control system. As noted, the first incident was on June 24, 2015, and the tenth was on May 4, 2017. All ten of these events were determined to be false alarms; i.e., there was no actual generator rotor electrical generator fault at any time. For each of these ten events, the trouble shooting and corrective actions taken did not require an outage. For each event, the trouble shooting found what was believed to be (at that time) the cause of the false alarm, and corrective action was taken. The dates and corrective actions for each of those ten events are summarized on page 5 of the

1 . Indicate the ERRA application where the forced outage was reported. 2 . Provide narrative below table or provide reference to any attached reports 3 . If “No”, please provide the explanation. If “Yes”, please provide copies of reports

Apparent Cause Evaluation Report. As no outages were required for any of these ten events, the exact start and end times involved in the diagnosis and corrective action implementation work, were not fully documented. The eleventh event occurred on May 10, 2017. It was determined that, given the prior history, further investigation would be conducted in response to this event including more extensive equipment disassembly. This work required an outage, which began on May 11 and lasted approximately eight days. Further details of this work are provided in the Apparent Cause Evaluation Report. Apparent Cause Evaluation Report PDF attachment available via email.




Question 08a-c:

NERC Classification 8. Per SCE-04C, NERC Event Type U1is defined as “an outage that requires immediate removal of a unit from

service, another outage state, or a reserve shutdown state. This type of outage usually results from immediate

mechanical/electrical/hydraulic control system trips and operator-initiated trips in response to unit alarms. ”

a. Please explain the purpose of the event type usage.

b. Was this outage resulted from what/which immediate mechanical/electrical/hydraulic control system trips? Please explain

c. Was this outage resulted from operator-initiated trips in response to what/which alarms? Please explain.

Response to Question 08a-c:

a. SCE participates in the collection and submittal of outage data for its gas-fired and hydroelectric generating units. This data is compiled and submitted to NERC in a manner which conforms to NERC GADS standards (i.e., separate from the operational data reported by SCE to and tracked by the California System Operator, using CAISO's protocols). Consistent use of these NERC GADS standards (including the coding of the outage event type) by SCE and the other NERC GADS participating generating facility owners and operators (including many that are outside of the CAISO area), facilitates analysis of outage causes and trends of generating units throughout North America. As provided in Testimony Exhibit No. SCE-04C, Appendix III-A NERC GADS Event Codes, U-1 Unplanned (Forced) Outage - Immediate is an outage that requires immediate removal of a unit from service, from another outage state, or from a reserve shutdown state. This type of outage usually results from immediate mechanical/ electrical/ hydraulic control system trips and operator initiated trips in response to unit alarms. b & c. See response to Questions 7 and 14.

Southern California Edison 2018 ERRA Review A.18-03-016




Question 09a:

NERC Classification

9. Please explain the purpose of the NERC cause code. Please cite source a. What do you mean that the NERC cause code for this outage is 4511. Please cite source.

Response to Question 09a:

The NERC Cause Code is used to classify the general cause of an outage. NERC Cause Code 4511 refers to an outage caused by issues involving the Generator Rotor. Refer to page B-GT-5 in the attached document A1803016 SCE-ORA 18 Q09.pdf for further information. Also see the response to Questions 7, 8 and 14. PDF attachment available via email.





Question 10:

Generator Rotor Electrical Ground Detection Instument 10. What is a ground detection instrument? Explain its use and purpose. Response to Question 10:

See response to Question 14.





Question 11:

Generator Rotor Electrical Ground Detection Instument 11. What is a generator rotor? Explain its use and purpose. Response to Question 11:

The generator rotor is the rotating component within an electric generator. Its purpose is to create a revolving magnetic field inside of the generator stator, which causes the stator to produce electricity.





Question 12:

Generator Rotor Electrical Ground Detection Instument 12. What is a generator rotor electrical ground detection instrument? Explain its use and purpose. Response to Question 12:






Question 13:

Generator Rotor Electrical Ground Detection Instument 13. Please provide a color picture or pictures, diagrams and cross-sectional views of the generator rotor electrical

ground detection instrument. Response to Question 13:






Question 14a-c:

Generator Rotor Electrical Ground Detection Instument 14. Does the generator rotor electrical ground detection instrument generate any readings?

a. Please explain the readings, and how they are being used.

b. Do these readings result in an automatic shutdown? Please explain

c. Do the control room operators see those readings, and how do the operators respond to those readings?

Response to Question 14a-c:

The generator rotor ground detection instrument (i.e., a PRISMIC R-10 Rotor Earth Fault Monitor) is a combination of electronic components that monitor for the presence or evidence of unintended and uncontrolled generator field current flow to ground. Above a certain level and under certain conditions, such current flow could damage the generator rotor or other components. Further details on the specific conditions that would need to be present whereby a ground fault could cause damage to the Barre Peaker, are provided in the Apparent Cause Evaluation Report for this outage. This report was provided in SCE's direct testimony workpapers; and for reference, a duplicate copy is attached in response to Question 7. The plant operators receive an alarm (via the Peaker control system) if such current flow is detected, or if the control system registers a loss of the detection instrument's signal. Upon receipt of an alarm, the operators enlist assistance from maintenance personnel or others who are more knowledgeable of the instrument and circuit, in verifying and validating the cause of the alarm and to determine the corrective actions needed. Operations personnel have the discretion to determine the appropriate response to the alarm which can include manually removing the generator unit from service (i.e., taking the unit off-line) for further testing/ evaluation, as was the case for the extensive diagnostic work that was initiated on May 11, 2017. A schematic of the Barre Peaker generator rotor ground detection system is attached.




Question 15:

Generator Rotor Electrical Ground Detection Instrument 15. What is a fault-to-ground?


An electric ground fault occurs when electricity travels through a device and into the earth's ground, in an unintended manner, instead of following its intended path.




Question 16:

Generator Rotor Electrical Ground Detection Instrument 16. What is a fault-to-ground alarm? Why is an alarm needed? Response to Question 16:

The alarm is a visual and audible indication that an unintended ground path exists. If above a certain level and under certain conditions, such unintended ground fault current flow can damage electrical components. Also see response to Questions 14 and 23.




Question 17:

Generator Rotor Electrical Ground Detection Instument 17. Does the alarm automatically trigger any particular action? Please explain. Response to Question 17:

No. The alarm notifies the plant operators of the situation, and then they determine the action to be taken. Also, see the response to Question 14.




Question 18:

Generator Rotor Electrical Ground Detection Instument 18. Is the alarm annunciated in the control room? How does the control room and the operators respond to the

alarm? Response to Question 18:

Yes. Also, see response to Questions 14, 16 and 17.




Question 19:

Generator Rotor Electrical Ground Detection Instument 19. Does the alarm result in an automatic shutdown? Please explain Response to Question 19:

No. Also, see response to Questions 14, 16 and 17.




Question 20:

Generator Rotor Electrical Ground Detection Instument 20. Do the control room operators see the alarm, and how do the operators respond to the alarm? Response to Question 20:

Yes. Also see response to Questions 14, 16 and 17.




Question 21:

Generator Rotor Electrical Ground Detection Instument 21. The Direct Testimony (line 20-22) states that the generator rotor electrical ground detection instrument

experienced an intermittent (at times continuous) fault-to-ground alarm condition between June 24, 2015 and May 10, 2017. Does SCE mean there is actually one alarm condition in that time period between June 24, 2015 and May 10, 2017, or does SCE mean that the generator rotor electrical ground detection instrument experienced several intermittent (at times continuous) fault-to-ground alarm conditions? Please list all alarm conditions in the table shown in question #7.


Operators indicate that for certain of the ten events described in SCE's response to Question 7, the alarm was intermittent (i.e., would trigger, then clear, and then trigger again). Operators indicate that for other events the alarm was continuous (i.e., it did not clear until corrective actions were taken). The specific number of alarms involved in each of the ten events, and the duration of time between the alarm triggering and its subsequent clearing, were not fully documented. As discussed in further detail in Apparent Cause Evaluation Report for this outage, in addition to other findings, the ground detection circuit power supply inhibit setting was found to be set higher than normal. This high setting, combined with normal thermal drift of this setting, apparently was such that the alarm would self-clear for periods of time. SCE believes that the corrections that were made to the ground detection instrument's factory wiring, during the May 2017 eight-day outage, along with the changes made to the power supply inhibit setting during this outage, have corrected the root cause of the series of recurring false alarms experienced from June 2015 through May 2017. The numerous other corrective actions that were taken during this approximate two-year time period (i.e., executed prior to the May 2017 outage) addressed issues that could have also been contributing to the series of false alarms. SCE believes that these same issues were also masking detection of the main root cause. However, with the benefit of hindsight, SCE personnel now understand that these earlier efforts were not successful in uncovering the main root cause of the problem. Also see the response to Question 34.


To: ORA Prepared by: Timtohy Condit


Question 22:

Generator Rotor Electrical Ground Detection Instrument 22. What is a dynamic ground?






Question 23:

Generator Rotor Electrical Ground Detection Instument 23. What do you mean by a dynamic ground within the rotor? What harm/benefit does the dynamic ground do? Response to Question 23:

A dynamic ground is an electrical grounding condition that occurs while the rotor is spinning (i.e., the generating unit is on-line). Grounds can also occur, and be detected, when the generating unit is off line (i.e., a static ground).




Question 24:

Generator Rotor Electrical Ground Detection Instument

24. What is a static ground? How does it differ from a dynamic ground? What harm/benefit does the static ground do?






Question 25:

Remedial Actions 25. What is a megger test? What information does the test provide? Please provide color pictures and diagrams. Response to Question 25:

A Megger or Ohmmeter is a portable instrument used to measure the insulation resistance of electrical machinery.

Megger tests performed at Barre Peaker on 3/7/2016 and 4/4/2017 measured the resistance between the rotor field winding electrical connection and the station ground bus. Both of the tests performed indicated that the rotor winding was within normal operating parameters which meant that the generator rotor ground fault alarms that were being received were false alarms.




Question 26:

Remedial Actions 26. Over the 3-year period (June 24, 2015 to May 10, 2017), for what actions and/or decisions do the megger test

results being used? Response to Question 26:

SCE believes this question contains a typographical error; the period of time referenced is an approximate two-year period. See response to Question 25.




Question 27:

Remedial Actions 27. Please identify, in the Table shown in question #7, the incident dates when SCE performed the megger test. Response to Question 27:

See response to Question 25. Note that these meggar tests were conducted as part of SCE's response to the fourth and ninth events discussed therein.




Question 28:

Transmitter 28. What is a transmitter? What information does it transmit? Response to Question 28:

A transmitter is an electronic component of the ground detection equipment that communicates a high frequency wireless signal which indicates the presence of a detected ground. The transmitter lens produces infrared pulses. Cleaning the lens is performed using a cotton ball and distilled white vinegar.




Question 29:

Transmitter 29. What parts of the transmitter were being cleaned? How do you clean the transmitter? Response to Question 29:





Question 30:

Transmitter 30. How do you know when to replace a transmitter? Response to Question 30:

Transmitters are replaced when they no longer function properly and repair is not practical.




Question 31:

Transmitter 31. Please identify, in the Table shown in question #7, the incident dates when SCE cleaned and/or replaced the

transmitter. Response to Question 31:

The transmitter was cleaned on 3/07/2016 and replaced on 5/04/2017.




Question 32:

Transmitter 32. Please provide color pictures and diagrams of a transmitter. Response to Question 32:





Question 33:

Transmitter 33. What is a power transmitter? What are the differences between a power transmitter and a non-power

transmitter? Response to Question 33:

SCE is unfamiliar with the term “non-power” transmitter and cannot find its usage in either direct testimony or workpapers. SCE believes that all transmitters require a source of power to operate. See response to Question 28.




Question 34:

Transmitter 34. What do you mean by a reversal of two electrical connections in the power transmitter? Please explain, and

provide photos and diagrams of the two electrical connections before and after the remedial action. Response to Question 34:

As explained on page 6 of the Apparent Cause Evaluation Report provided for this outage, the positive (F1) lead was connected to the rotor negative terminal and the negative (F2) lead was connected to the rotor positive terminal. As a result of the extensive disassembly and diagnosis conducted during the outage, it was determined that these lead wires were incorrectly installed (i.e., were reversed). SCE concluded that this error was likely present at the time of the original construction of the Barre Peaker. The attached photo shows the F1 & F2 connections, before correction. SCE does not have a photo showing the device after these connections were corrected (i.e., were reversed). It would require disassembly of the unit in order to take such a photo at this time. Also see the response to Questions 21, 38 and 39.




Question 35:

Transmitter 35. Are the connections installed correctly when the positive (F1) lead is connected to the rotor positive terminal and

when the negative (F2) lead is connected to the rotor negative terminal? Response to Question 35:

Yes.




Question 36:

Transmitter 36. What is the name of the contractor hired to search for a possible dynamic ground? Response to Question 36:

Baseload Power.




Question 37:

Transmitter 37. Did this contractor discover the reversal problem of the two electrical connection? Response to Question 37:

Yes




Question 38:

Transmitter 38. What is the name of the contractor hired at the time of commissioning in 2007 to install the power transmitter? Response to Question 38:

General Electric. Note that power transmitters are received pre-wired from the manufacturer. That is, SCE believes the wiring error at issue occurred in the factory where the transmitter was fabricated, and was not made in the field during the construction of the Barre Peaker.




Question 39:

Transmitter 39. What inspections did SCE perform at the time of commissioning in 2007 to prevent and identify the electrical

connection reversal mistake? Please provide all records of inspections and tests.


While extensive quality control was conducted during the Barre Peaker construction, SCE is not aware of any specific testing performed on the transmitter during the time of the Peaker's construction and commissioning in August 2007. Power plant construction involves thousands of individual components, and associated mechanical and electrical equipment connection points. It would be impractical to test every single connection point. Even with the benefit of hind-sight, SCE concludes that the first evidence of the transmitter's factory wiring error was the time of the first false alarm on June 24, 2015.




Question 40:

Aerial Receiver 40. What is an aerial receiver? Is it part of the transmitter. Response to Question 40:

No. The Aerial infrared receiver “sees” (i.e., reads) the infrared signal (from the transmitter) and relays this signal to the main signal detector in the control room. Also see response to Question 48.




Question 41:

Aerial Receiver 41. How do you know when to replace an aerial receiver? Response to Question 41:

It is replaced when it is no longer working properly and repair is not practical.




Question 42:

Aerial Receiver 42. Please identify, in the Table shown in question #7, the incident dates when SCE replaced the aerial receiver. Response to Question 42:

The Barre Peaker aerial receiver was last replaced on 04/01/2016. SCE is not aware of any replacements prior to that date.




Question 43:

Aerial Receiver 43. Please provide color pictures and diagrams of an aerial receiver. Response to Question 43:





Question 44:

Circuit 44. What is a circuit? Response to Question 44:

A circuit is an electrical path through which electric current can flow. Typically, a circuit includes a connection to a source of electrical power, and devices which start and stop (and sometimes modulate) the flow (and modulate the strength) of the current flow.




Question 45:

Circuit 45. What is the relationship between the circuit and the alarm? Response to Question 45:

When the rotor ground fault detector alarm contact (normally closed) opens, the electrical circuit is interrupted, which in turn activates the plant annunciator alarm.




Question 46:

Circuit 46. How do you adjust the circuit? Are there set points to which the circuit are to be calibrated? Please explain. Response to Question 46:

The circuit in question cannot be adjusted per se. However, the circuit contains detector set points that can be adjusted. The set points are tuned to detect the loss of the ground detector signal, but not respond to either low voltage or noise conditions.




Question 47:

Circuit 47. Please provide color pictures and diagrams of the circuit. Response to Question 47:

A simplified schematic is provided in response to Question 14, and photos of certain devices in the circuit are provided in response to Questions 28, 34 and 40. However, detailed diagrams and additional photos are not available. The devices, which are part of the circuit, contain numerous elements (i.e., circuit boards, etc.).




Question 48:

Circuit 48. Please provide photos and diagrams which show the layout of the transmitter, the aerial receiver, the circuit, the

electrical leads, generator rotor and the generator rotor electrical ground detection instrument. Also, please show, in the layout, where the megger tests were performed.


See response to Questions 14 (generator ground detection instrument), 28 (transmitter), 40 (receiver) and 25 (megger testing instrument). Pictures of the other requested items would require disassembly of the unit and are not available.




Question 49:

Shutdown

49. How were the operators alerted of the failure? Response to Question 49:





Question 50:

Shutdown

50. Was the facility shut down manually by the operators? Response to Question 50:

Yes. Also see response to Question 14.




Question 51:

Shutdown

51. Was the facility shut down automatically? Please explain. Response to Question 51:

No. Also see response to Question 14.




Question 52:

Shutdown

52. What is/are the interlocking device(s) which shut down the peaker? Are there any Instrumentation and Controls (I&C) devices which control the shutdown? Please explain.


The generating unit shut down was manually initiated by plant operators. This was needed so that disassembly and detailed diagnosis of the alarm circuitry could be undertaken. See response to Question 14.




Question 53:

Post Mortem

53. Please provide any other Root Cause Analysis Report (RCA) for the incident and any other post-mortem reports (such as, inspection reports) prepared by SCE and/or others (e.g. contractor and external technical consultant). If there are no other post-mortem documents, please explain why.


The Apparent Cause Evaluation Report for the 2017 Barre Ground Fault Alarm outage was provided in workpapers to SCE's direct testimony. No other analysis and/or reports have been performed as the fault-to-ground condition has not reappeared.




Question 54:

Post Mortem

54. Please furnish all post-mortem reports of this outage, including any inspection reports, root cause evaluation reports done by SCE and/or external consultant(s) and other Regulatory Reports (e.g. South Coast Air Quality Management District and/or Mojave Desert Air Quality Management District). If there are no reports for each of the afore-mentioned documents, please explain why.






Question 55:

Post Mortem 55. What were the findings on this outage, if any, from the Air Quality Management District (AQMD) and/or other

agencies? Please provide details, including any reports and/or documents. Response to Question 55:

This outage did not involve any SCAQMD (or other agencies) permit or rule violations, or require any specific regulatory reports.




Question 56:

Post Mortem 56. Did AQMD and/or other agencies issue any findings/failures on this incident in any of its inspection,

examination and assessment reports, or any other reports? Please explain, and submit those documents. Response to Question 56:

No. See response to Question 55.




Question 57:

Post Mortem 57. Did AQMD and/or other agencies cite SCE or any of the owners or other companies for this incident? Please

provide details, including any reports and/or documents. Response to Question 57:

No. See response to Question 55.


SCE Response to Public Advocates Office Data Request 18, Question 58.

(Confidential, partially available via email)



To: ORA

Prepared by: Adaora Okoro Title: Energy Marketing & Trading Financial Analysis, Advisor

Dated: 06/29/2018

Question 58: Replacement Power Cost (Please provide the response in an Excel spreadsheet, and show also the replacement power cost and revenue calculations. Provide sources of numbers, and show cell formulae if the numbers pertain to computation from different cell data.) 58. What is the replacement power cost during the outage? If the replacement power cost is zero or negative, please explain why. (Do not respond, “refer to spreadsheet.” State the cost in the answer sheet, and identify the Excel cell number where the cost may be found.) Response to Question 58: Marked Confidential in Accordance with California Law and Regulations – Basis for Confidentiality In Accompanying Confidentiality Declaration

Confidential Excel attachment available via email.


SCE Responses to Public Advocates Office Data Request 18, Question 59-77.



Title: Sr. Advisor

Dated: 06/29/2018 Question 59:

Equipment Warranty 59. For the failed/damaged components, how long have they been in service? State the original in-service dates for

each. Response to Question 59:

There were no failed or damaged parts, per se. Also see the response to Questions 34 and 38.



Title: Sr. Advisor


Equipment Warranty 60. What is the warranty period of the damaged parts in question? Response to Question 60:

There were no failed or damaged parts, per se. The ground fault detection system was manufactured by the Brush Group, under contract to GE, and the system components were delivered to the Barre Peaker construction site in 2007. While SCE believes the wiring error in question occurred in the Brush Group manufacturing plant, this cannot be proven. The Barre Peaker power plant's original equipment, installed at the time of the plant's construction, had warranty periods that varied from 1 to 2 years". Also, SCE believes that, if warranty coverage applied, the contractual remedy would be for Brush Group (or GE who supplied the Barre Peaker power block equipment) to simply correct the wiring. Correcting the wiring was a simple task, once the disassembly and the diagnosis was completed, and the problem was found. Also see the response to Questions 34 and 38.



Title: Sr. Advisor

Dated: 06/29/2018 Question 61a-b:

Equipment Warranty 61. Did SCE pursue compensation (equipment and replacement power cost) for the outage?

a. If so, please provide all documentations.

b. If not, please explain why not.

Response to Question 61a-b:

No. a. N/A

b. SCE is not aware of any instance in which the contractor who performed the work or other power plant component suppliers, or providers of power plant maintenance services, offer reimbursement of “replacement power costs” as part of their product offerings to their customers

.



Title: Sr. Advisor


Equipment Cost Recovery 62. What was the Commission-approved depreciation life and depreciation rate for the damaged parts in question? Response to Question 62:

SCE objects on the basis that the question relates to costs that are beyond the scope of this ERRA proceeding. Subject to and without waiving that objection, SCE responds as follows: SCE utilizes group depreciation methods and any parts replaced during troubleshooting do not have a separate depreciable life from the rest of the plant.



Title: Sr. Advisor


Equipment Cost Recovery 63. What was the Application and Decision number which dealt on the depreciation life and depreciation rate? Response to Question 63:

SCE objects on the basis that the question relates to costs that are beyond the scope of this ERRA proceeding. Subject to and without waiving that objection, SCE responds as follows: See response to Question 62.



Title: Sr. Advisor


Equipment Cost Recovery 64. How much did it cost SCE to replace the damaged parts; provide both the total cost and SCE’s share of this

cost.? Please provide the cost breakdown (labor, materials, etc.) and workpapers. If there are numerous cost items less than $100,000, please group them in the appropriate categories.


SCE objects to the question as outside the scope of this proceeding. Subject to and without waiving that objection, SCE responds as follows: The total O&M costs are provided in the following table:

Category Cost

Contract $

16,717

Labor $

4,879

Other $

703

Total $ 22,299



Title: Sr. Advisor


Equipment Cost Recovery 65. How does SCE intend to seek cost recovery of this repair? If SCE has already recovered the cost of the repair,

please provide the Application and Decision number. Response to Question 65:

SCE objects on the basis that the question relates to costs that are beyond the scope of this ERRA proceeding. Peaker maintenance costs are funded through SCE's approved GRC base rates.



Title: Sr. Advisor

Dated: 06/29/2018 Question 66a-e:

Corrective Action 66. Please enumerate what items were replaced during the shutdown to restore Barre Peaker back in service.

a. Please provide the color picture(s) and/or diagrams of the failed original items and the replaced/repaired items.

b. Please describe how each item failed, and why they need to be replaced/repaired.

c. Please describe the functions of each of the replaced/repaired parts.

d. Were any of the above listed replaced/repaired parts directly related to the outage?

e. Show where the parts are located in relation to one and the other, and to the generator rotor and the generator rotor detection instrument.

Response to Question 66a-e:

No items were replaced.



Title: Sr. Advisor Dated:

06/29/2018 Question 67:

Corrective Action 67. Was the repair or rework approved? If so, by whom? Response to Question 67:

Yes. SCE management approved the repairs.



Title: Sr., Advisor Dated: 06/29/2018

Question 68:

Corrective Action 68. If the approver(s) for the repair was not the same as the original designer, please explain who had the authority to

approve the work. Response to Question 68:




Title: Sr. Advisor


Corrective Action 69. Were the parts installed in the repair identical to the original design specifications? Please explain. Response to Question 69:

No new or replacement parts were installed.



Title: Sr. Advisor


Corrective Action 70. Please provide the documentation and/or inspection report when the replaced parts were installed and all

associated tests before the unit was returned to service. Response to Question 70:

No new or replacement parts were installed.



Title: Sr. Advisor


Corrective Action 71. What did SCE do to correct the problems which caused the outage? Response to Question 71:

See the Apparent Cause Evaluation Report that SCE prepared for this outage and included in the workpapers for SCE's direct testimony.



Title: Sr. Advisor


Corrective Action 72. Had SCE identified the conditions/factors which led or caused the problems which led to the outage? Please

explain. Response to Question 72:

Yes. See the Apparent Cause Evaluation Report that SCE prepared for this outage and included in the workpapers for SCE's direct testimony.



Title: Sr. Advisor


Corrective Action 73. Did SCE look at other units for similar problems? Please explain and provide documentations. Response to Question 73:

Yes. SCE performed evaluations and found that the other four Peaker plants were correctly wired, and had the proper device settings. However, SCE also concluded that similar wiring errors could be made in the future, if and when the equipment involved needed to be removed for repair or replacement, and then reinstalled. Therefore, SCE initiated and completed the following mitigation measures at all five Peakers:

1. Clearly stamp (+) on the lug of the F1 wire, and (-) on the lug of the F2 wire;

2. Ensure the R-10 receiver is tuned correctly; and

3. Install sight glass over LED’s in the receiver covers.



Title: Sr. Advisor


Corrective Action 74. Did SCE correct similar problems in the other units? Please explain and provide documentations. Response to Question 74:




Title: Sr. Advisor


Corrective Action 75. What has SCE done to preclude its recurrence? Please explain and list all actions, such as, scheduled inspections

and maintenance. Response to Question 75:




Title: Sr. Advisor

Dated: 06/29/2018 Question 76a-d:

Corrective Action 76. Why does it take SCE that amount of time (39.24 days) to repair the above damages?

a. Please provide the schedule/timeline chronologically of the various milestone activities, and identify the total amount of outage time.

b. Could something have been done better in the future to reduce the down time – please explain?

c. Please explain whether SCE did stock the parts in the warehouse to reduce the downtime for repair. If yes, explain why it took that amount of time for the repair.

d. Did SCE perform any benefit/cost study to determine whether it was cost effective to warehouse the above and/or other items which led to this outage? If yes, please provide the study. If not, please explain.

Response to Question 76a-d:

a. This question contains an error. As explained in response to Question 6 and as indicated elsewhere in this proceeding, the outage duration was approximately eight days. During these eight days SCE and Baseload Power (who was contracted by SCE to assist with this problem) performed the steps necessary to disassemble, test, diagnose, identify and correct the problem. A schedule/timeline was not developed for or tracked during the course of the work as the fault-to-ground alarm cause (and the work that would be needed to fix it) was unknown as work began.

b. No.

c. No new or replacement parts were needed or installed.

d. No new or replacement parts were needed or installed.



Title: Sr. Advisor


Corrective Action 77. Why did SCE wait for 10 years (from commissioning in 2007 to shutdown in 2017) before it decided to hire a

consultant to diagnose the problem? Response to Question 77:

The problem did not present itself until 6/24/2015, approximately eight years after the plant began commercial operations. See the Apparent Cause Evaluation Report that SCE prepared for this outage and included in the workpapers for SCE's direct testimony.

Documents

CHAPTER 4 ATTACHMENT 4.1 SCE Responses to Public …CHAPTER 4 ATTACHMENT 4.1 SCE Responses to Public Advocates Office Data Request 18, Question 1-57. DATA REQUEST SET A1803016 ORA-SCE-18