Peak Reliability Version 10.2 Reliability Coordinator Data Request and Specifications ... ·...

Peak Reliability

Reliability Coordinator Data Request and Specifications for Data Provision

Version 10.2

IRO-010-1a

Classification: Public of 37 Release Date: January 6, 2016

APPLICABILITY: Balancing Authorities, Generation Owners, Generation Operators, Load Serving Entities, Transmission Operators, Transmission Owners

I. Purpose

Pursuant to NERC Reliability Standard IRO-010-1a, the Reliability Coordinator (RC) requests data from your entity as detailed in Attachment 1. Specifically, IRO-010-1a R3 requires that each Balancing Authority, Generation Owner, Generation Operator, Load Serving Entity, Transmission Operator and Transmission Owner provide its RC with the operating data that the RC requires to perform operational reliability assessments and to coordinate reliable operations within the RC Area.

II. Introduction The data requested includes, but is not limited to, real-time facility data, schedule type data, facility outage information, and electrical equipment modeling data. This data is necessary for the RC to carry-out its functions, as defined by the NERC Reliability Standards, including:

• Real-Time Situational Awareness • System Alarms and Visualizations • Advanced Applications and other Network Analysis Tools • Future, Next Day and near Real-Time Engineering Study Analysis • Post Analysis, Event Analysis, Trends, Forecasts, etc.

III. Exchange of Information and Data Contact Information Each entity which is required to provide data directly to Peak RC should appoint a single contact person who is responsible for working with the RC in order to provide the requested data in the specified format. Please notify Peak Reliability of your entity’s contact name, email address and phone number at [email protected]. Data Format The formats for the data to be delivered to the RC are as follows: Inter Control Center Protocol Data (ICCP)

• Real time Analog and Status point data as detailed in Attachment 1. • The data provider must include data quality along with the data. This data quality shall

follow the ICCP Data Quality Standards as described in the IEC ICCP User’s Guide (870-6-505).

mailto:[email protected]

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• If real-time ICCP data transfer is unavailable for any reason, the responsible entity will provide critical real-time system data via phone to the RC real-time desk.

Electric Industry Data Exchange (EIDE)

• Schedule type data as identified in Attachment 1 to be delivered electronically on a daily basis as designated in Attachment 1, by EIDE protocol over https.

• If your entity is unable to perform EIDE over https, then the EIDE formatted files can be delivered to a Peak Reliability Secure File Transport Protocol (SFTP) site. Peak Reliability’s EMS technical staff will work with each entity’s technical staff on either implementation.

RC Coordinated Outage System (COS)

• This central outage system has a web front end for easy data entry. Submissions can be automated via a Web Services API by working directly with the system vendor.

• Planned Facility Outage information should include transmission equipment and generators. The details of the required planned outage submittals are in the COS User’s Manual supplied by the RC.

• If COS is unavailable, the responsible entity shall send planned outage information to the RC email address [email protected]

Topology Update Process for the West-wide System Model (WSM)

• The WSM topology updates will be provided through the RC Model Update Process. Model updates details are in Attachment 1 below and are required no less than 30 days prior to the actual change in the network (additions, deletions or changes in energized equipment).

Other data formats and submittal processes include the use of email, upload to Peak’s secure website Peakrc.org, and phone calls to Peak’s Reliability Coordinator System Operators.

Questions

Peak Reliability’s engineering and operations staff will work with each entity to answer questions, requests for clarification or to address issues related to the technical nature of the data. Please notify [email protected] with your questions about the RC data request.

Please send email to [email protected] with any questions of a legal nature.



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Attachment 1:

The table below contains the specific data Peak requires from each Responsible Party. Individual TOPs and GOPs are required to ensure their data is being provided either directly or through their associated BA.

1. Real-Time Network Measurement Data

Req #

Responsible Party

*See Note 1

Data Request Effective Date

Data Source Type

Data Item Data Transfer Method

Data Update Frequency

1.1 Transmission Operator*

January, 2009.

Transmission Real-time status points for all BES equipment and other non-BES equipment that impact the BES (see note 1).

ICCP By exception


January, 2009.

Transmission Real-time MW measurements or ampere if MW not available for all BES equipment and other non-BES equipment that impact the BES (see note 1).

ICCP 10 sec


January, 2009.

Transmission Real-time MVAR measurements for all BES equipment and other non-BES equipment that impact the BES (see note 1).

ICCP 10 sec


January, 2009.

Transmission Voltage measurements for all busses associated with BES equipment and other busses associated non-BES equipment that impact the BES (see note 1).

ICCP 10 sec

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Req #

Responsible Party

*See Note 1


Data Source Type



1.5

Transmission Operator*

January, 2009.

Transmission Designated WECC Transfer Path data and stability related interface data:

• SOL (including dynamic limits)

• actual MW

• scheduled MW as applicable

ICCP 10 sec

1.6


January, 2009.

Transmission LTC tap position measurements for LTCs with high side voltage > 100kV.

ICCP 10 sec


January, 2009.

Transmission Phase shifter phase tap position.

ICCP 10 sec

Note 1

Measurement data that should be provided to Peak includes 1) data associated with Facilities or equipment which are included in the Bulk Electric System (BES) definition, and 2) Measurement data for non-BES Facilities/equipment that impact the BES, including but not limited to parallel sub-100-kV systems, as determined by the TOP or by Peak as being necessary to support the accuracy of Real-time Assessments or to determine SOL exceedance on BES Facilities. This request is intended to provide adequate data for Peak to properly monitor all BES Facilities, and other Facilities that may have an impact to the BES. Peak’s state estimator accuracy is negatively impacted if the necessary sub-100-kV systems are not in the West-wide System Model with appropriate measurement availability.

Note that “Responsible Party” now includes the phrase “other NERC Registered Functional Entities”. This is intended to reinforce that the owners of the data, even if not explicitly listed, must supply the required data to Peak. Transmission Operators and Balancing Authorities may provide data to their Reliability Coordinator on behalf of Generation Owners, Generation Operators, Load Serving Entities and Transmission Owners to the extent they are authorized by those entities to do so. In the event Transmission Operators and Balancing Authorities are not authorized to provide Peak the necessary data on behalf of Generation Owners, Generation Operators, Load Serving Entities and Transmission Owners, it is the obligation of the Transmission Operator or Balancing Authority to notify Peak of the responsible party and it is the obligation of Generation Owners, Generation Operators, Load Serving Entities and Transmission Owners to provide the required data directly to Peak.

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Req #

Responsible Party

*See Note 1


Data Source Type



1.8


January, 2009.

Transmission MW/MVAR measurements for measured loads. These loads may be equivalent representations of your distribution system.

ICCP 10 sec

1.9


January, 2009.

Transmission RAS Arming Status for all schemes that have an impact to the BES. An armed RAS implies that it is 1) in service and 2) ready to perform an action (trip a unit for example) if a specific condition occurs on the power system.

ICCP 10 sec

1.10


March 31, 2015.

Transmission RAS in-service status for all schemes that have an impact to the BES.

ICCP is the desired communication method, if available. Phone call notifying that RAS is out of service (or returned to service) is required if ICCP not available.

ICCP or phone call to the RC upon change to RAS in-service status.

10 sec

1.11


March 31, 2015

Transmission RAS associated analog arming values (e.g. Amp, MW, MVAR). (See note 2 for example)

ICCP 10 sec

1.12


March 31, 2015

Transmission Status of Non-RAS devices that perform automatic post-contingency actions based on certain parameters such as under voltage or overloaded facilities. This may include, but is not limited to, certain generator run-back schemes or under voltage facility tripping schemes.

This is not a request for under-voltage or under-frequency load shedding information.

ICCP preferred. If none available, phone call to RC upon status change.

10 sec

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Req # Responsible Party

*See Note 1


Data Source Type



1.13


January, 2009.

Operations Data

Dynamic equipment ratings including all facilities with ratings that vary with real-time system or ambient conditions (temp driven Facility Ratings, Topology driven Facility Ratings).

ICCP (if available)

10 sec

Note 2:

Peak’s real-time measurement/ICCP data request requires data be made available which already exists within the TOP’s or BA’s SCADA system. This is not a request for the TOP or BA to install additional measurement devices in the field.

A RAS in-service status may or may not be available via ICCP. If there are real-time changes to the availability and an indication is available via a responsible entity’s EMS, that value should be provided to Peak. If ICCP data is not available for RAS in-service status, other documentation or other information must be provided to be sure that Peak understand how the RAS is operated.

An example of a RAS associated analog arming values is X MW of generation is armed to be dropped, or Y MW of load is armed to be dropped.

Note 3:

A note about dynamic equipment ratings: Peak has functionality in the Energy Management System (EMS) to either receive dynamic ratings in the following ways: 1) Provide Peak with the equipment rating as an analog point via real-time ICCP, 2) Provide Peak with ambient temperature tables and associated limits, along with actual temperature via real-time ICCP, and 3) Provide Peak with unique topology based limitations, such as when one breaker on a breaker and a half scheme is open, resulting in a limitation due to a lower rating on the remaining closed breaker.

Dynamic Facility Ratings help ensure that Peak has the most accurate Facility Ratings in our situational awareness tools, thus reducing incorrect application results and unnecessary phone calls to your operators.

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2. Real-Time Balancing Authority Data

Req #

Responsible Party

*See Note 1


Data Source Type



2.1 Balancing Authority

January, 2009.

BA Instantaneous BA Area Load

(See note 5 for definition of BA Area Load)

ICCP 10 sec


January, 2009.

BA BA Net Actual Interchange (as used in ACE calculation)

ICCP 10 sec


January, 2009.

BA BA Net Scheduled interchange (as used in ACE calculation)

ICCP 10 sec


January, 2009.

BA BA Instantaneous ACE that is used to satisfy CPS and DCS requirements.

ICCP 10 sec


July, 2011. BA BAAL high and low limits – one minute average values. This applies only to those entities that are participating in the Reliability Based Control (RBC) field trial.

ICCP 1 min


January, 2009.

BA System frequency at multiple locations within the BA as requested by the RC.

ICCP 10 sec


January, 2009.

BA BA Scheduled frequency ICCP 10 sec


January, 2009.

BA BA Area Operating Reserve (as defined by NERC)

• Required

• Actual available

ICCP 10 sec


January, 2009.

BA BA Area Operating Reserve -

Spinning (as defined by NERC)

• Required


ICCP 10 sec

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Req #

Responsible Party

*See Note 1


Data Source Type



2.9.1 Balancing Authority

TBD BA BA Area Contingency Reserve (as

defined in the NERC glossary and

WECC regional standards)

• Required


This item will replace 2.9 on the

effective date.

ICCP 10 sec


January, 2009.

BA BA Area Actual Generation Total ICCP 10 sec


January, 2009.

BA Actual most severe single contingency (MSSC) of your balancing authority. This value should not be a static Pmax of the largest generator, rather the actual MW output. This is NOT a request for the RSG MSSC.

ICCP 10 sec

2.12 Balancing Authority and Generator Operator

January, 2009.

Generator Real-time status points (UCON status point designating unit is or is not connected to the network) for units 10MW or greater, or those units with automatic voltage control or black start capability.

ICCP By exception

2.13 Balancing Authority*

January, 2009.

Generator All generators – real-time net MW output.

ICCP 10 sec


January, 2009.

Generator All generators – real-time net MVAR output.

ICCP 10 sec


June 1, 2015

Dynamic Transfer

Dynamic Schedule real-time dynamic signal used in ACE calculation for each dynamic schedule. This is not the anticipated energy on the tag, rather a real-time calculation of MWs associated with the dynamic schedule.

ICCP 10 sec

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Req #

Responsible Party

*See Note 1


Data Source Type




June 1, 2015

Dynamic Transfer

Pseudo Tie real-time dynamic signal. This is a real-time calculation of MWs associated with each pseudo tie used in ACE calculation.

Note: This is not an alternate method for inclusion in congestion management procedures pursuant to INT-004-3.

ICCP 10 sec


September 2010

Operations Data

Balancing Authority total wind MW output. This is a single value – summation of all wind generation currently online. This value should represent wind generation at the bulk electric system level.

ICCP 10 sec


March 31, 2015

Operations Data

Balancing Authority total solar MW output. This is a single value – summation of all solar generation currently online. This value should represent solar generation at the bulk electric system level, not roof top solar for example.

ICCP 10 sec

2.19 Generator Operator

January, 2009

BA Change in status of generating unit Automatic Voltage Regulators (AVR), Power System Stabilizers (PSS) or alternative voltage controlling device.

Phone call to RC Desk

Each occurrence lasting for 30 minutes or longer


March 31, 2015

BA ATEC component of ACE ICCP 10 sec


March 31, 2015

BA BA frequency bias if a dynamic bias is used

ICCP 10 sec


March 31, 2015

BA Meter Error component of ACE ICCP 10 sec

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3. Forecast Data

Req #

Responsible Party

*See Note 1


Data Source Type



3.1 Balancing Authority *

January, 2009.

BA Hourly BA Net Area Interchange forecast through the end of the next business day.

EIDE/

Secure FTP

Daily submission by 10AM Pacific Prevailing Time.


January, 2009.

BA Hourly Operating Reserve forecast of BA Area through the end of the next business day.

EIDE/

Secure FTP



January, 2009.

BA Hourly Spinning Reserve forecast of BA Area for each day up to and including the next business day.

EIDE/

Secure FTP


3.3.1 Balancing Authority *

TBD BA Hourly Contingency Reserve forecast of BA Area for each day up to and including the next business day.

This item will replace 3.3 after the effective date.

EIDE/

Secure FTP


Note 4:

Balancing Authority Real-Time Data

The MSSC value that is provided to Peak must be a real-time value to capture the actual output of the generator that is the MSSC at any given moment. If MSSC calculations are being done based on other application results, such as real-time contingency analysis, it is acceptable to provide the update at the frequency of the calculation.

Dynamic schedules and pseudo ties are important for RC implementation in the Enhanced Curtailment Calculator, as well as for general awareness of MW flows associated with the dynamic transfers. A list of dynamic schedules and pseudo ties for each BA must be provided along with appropriate descriptions and purposes for the dynamic transfers.

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Req #

Responsible Party

*See Note 1


Data Source Type




March 31, 2015

BA Hourly BA Area load forecast. Required each day for the current day through the next four business days.

(See note 5 for examples of load forecast submission)

EIDE/

Secure FTP



April 1, 2016

BA Hourly BA Area load forecast. Required each hour for the next 4 hours.

(See note 5 for examples of load forecast submission)

EIDE/

Secure FTP

Hourly submission received 10 min prior to the hour.


January, 2009.

BA Hourly unit commitment for all BA Area generation 50mw and above. Required for each day up to and including the next business day. Forecasts must be submitted by 10AM Pacific Prevailing Time.

EIDE/

Secure FTP



April 1, 2016

BA Hourly Unit Commitment for all BA Area generation that qualifies per the BES definition any non-BES generation (as determined by Peak) that are necessary to support the accuracy of Operational Planning Analyses and to determine SOL exceedance on BES Facilities. Required each day for the current day through the next four business days.

This item will replace item 3.5 after the effective date.

(See note 6 for definitions of generator forecast data submissions)

EIDE/

Secure FTP


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Req #

Responsible Party

*See Note 1


Data Source Type




April 1, 2016

BA Hourly Unit Commitment for all BA Area generation that qualifies per the BES definition any non-BES generation (as determined by Peak) that are necessary to support the accuracy of Operational Planning Analyses and to determine SOL exceedance on BES Facilities. Required each hour for the next four hours.


EIDE/

Secure FTP



April 1, 2016

BA Hourly Unit Dispatch MW for all BA Area generation that qualifies per the BES definition any non-BES generation (as determined Peak) that are necessary to support the accuracy of Operational Planning Analyses and to determine SOL exceedance on BES Facilities. Required each day for the current day through the next one business day.


EIDE/

Secure FTP



April 1, 2016

BA Hourly Unit Dispatch MW for all BA Area generation that qualifies per the BES definition any non-BES generation (as determined by Peak) that are necessary to support the accuracy of Operational Planning Analyses and to determine SOL exceedance on BES Facilities. Required each hour for the next four hours.


EIDE/

Secure FTP


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Req #

Responsible Party

*See Note 1


Data Source Type




April 1, 2016

BA Hourly Operational Maximum MW for all BA Area generation that qualifies per the BES definition any non-BES generation (as determined by Peak) that are necessary to support the accuracy of Operational Planning Analyses and to determine SOL exceedance on BES Facilities. Required each day for the current day through the next four business days.


EIDE/

Secure FTP



April 1, 2016

BA Hourly Operational Maximum MW for all BA Area generation that qualifies per the BES definition any non-BES generation (as determined by Peak) that are necessary to support the accuracy of Operational Planning Analyses and to determine SOL exceedance on BES Facilities. Required each hour for the next four hours.


EIDE/

Secure FTP



April 1, 2016

BA Hourly Operational Minimum MW for all BA Area generation that qualifies per the BES definition any non-BES generation (as determined by Peak) that are necessary to support the accuracy of Operational Planning Analyses and to determine SOL exceedance on BES Facilities. Required each day for the current day through the next four business days.


EIDE/

Secure FTP


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Req #

Responsible Party

*See Note 1


Data Source Type




April 1, 2016

BA Hourly Operational Minimum MW for all BA Area generation that qualifies per the BES definition any non-BES generation (as determined by Peak) that are necessary to support the accuracy of Operational Planning Analyses and to determine SOL exceedance on BES Facilities. Required each hour for the next four hours.


EIDE/

Secure FTP


Note 5:

Peak uses NERC’s definition for Net Energy for Load for BA Area Load: Net Balancing Authority Area generation, plus energy received from other Balancing Authority Areas, less energy delivered to Balancing Authority Areas through interchange. It includes Balancing Authority Area losses but excludes energy required for storage at energy storage facilities.

Examples of load forecast submission: On Monday, a BA shall submit the hourly load forecast for Monday, Tuesday, Wednesday, Thursday, and Friday. On Tuesday, a BA shall submit the hourly load forecast for Tuesday, Wednesday, Thursday, Friday, Saturday, Sunday, and Monday.

Peak validates forecasted load by comparing it to the actual load value provided via ICCP. BAs, please be proactive and perform the same validation to ensure that Peak is receiving consistent, and accurate, load forecast data.

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4. Documentation and Procedures

Req #

Responsible Party

*See Note 1


Data Source Type



4.1 Balancing Authority and Transmission Operator

July, 2011

Operations Emergency Operations Plans (limited to those affecting the BES)

Upload to secure folder in Peak website or Email

Annually and/or anytime the plan is updated.

Note 6:

NERC BES Definition of Generator inclusion: Generating resource(s) with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate nameplate rating greater than 75 MVA including the generator terminals through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.

Unit Commitment: Flag to indicate whether a generator is expected to be online or offline during the forecast interval specified by the start / stop times. Indicator of Unit Commitment (1=Committed/Online, and a 0=Offline). If the unit is in an outage the value shall be zero.

Unit Dispatch MW: The average MW value corresponding to the expected output of the generator during the forecast interval specified by the start / stop times. This value can represent a unit, a plant (set of units), a share of a jointly owned unit (JOU), or a set of plants aggregated (such as small units). Aggregations of units or plants should only be used when the fuel type is the same and when electrically connected in the same geographic region. Specific unit data is preferred over aggregations whenever possible. Positive values shall be submitted when units are generating, whereas negative values shall be submitted for consumption of power (such as motoring units, pumped storage, etc). Forecasts for jointly owned units (JOUs) shall be submitted for each owner's JOU share, and the total plant forecast output shall be submitted by the plant operator. If the unit is in an outage the forecast shall be zero.

Operational Maximum MW: The MW value corresponding to the maximum operating limit of the generator that is sustainable for the forecast interval, e.g. lowest of Generator, Turbine, Fuel, Temperature, or Environmental Limits. If the unit is in an outage the forecast shall be zero. Only non-negative numbers should be submitted for values. WMax numbers for JOUs shall be submitted by the GOP/BA. The JOU owner who does not operate the plant shall submit a value that reflects the JOU share of capacity that could be called on for the forecast interval. The JOU plant operator GOP/BA shall submit a value that reflects the operational capacity of the unit.

Operational Minimum MW: The MW value corresponding to the minimum operating limit of the generator, e.g. lowest limit to meet equipment or environmental constraints during the forecast interval specified by the start / stop times. Negative numbers can be submitted for values of generation that consumes power, but typically this value will be positive.

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Req #

Responsible Party

*See Note 1


Data Source Type




July, 2011

Operations Capacity and Energy Emergency Plans


Anytime the plan is updated.

4.3 Transmission Operator

July, 2011

Operations Restoration Plans Upload to secure folder in Peak website or Email

Annually and/or anytime the plan is updated


July, 2011

Operations Under voltage and under frequency load shed plans


Anytime the plan is updated


July, 2011

Operations Path procedures Upload to secure folder in Peak website or Email



March 1, 2015

Operations Geomagnetic Disturbance Operating Procedures



4.7 Balancing Authority and Transmission Operator

March 31, 2015

Operations Other procedures as appropriate or as requested by the RC, including documented mitigation plans, fire/weather protocols, regulatory protocols that could cause inability to follow directives, technical information concerning protective relays, voltage schedules.



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5. Scheduled and Forced Outage Information

Req #

Responsible Party

*See Note 1


Data Source Type




March 31, 2015

Planned Outage Data

Scheduled outages for BES transmission system elements or any non-BES transmission elements (as determined by either the TOP or by Peak) that are necessary to support the accuracy of Operational Planning Analyses and to determine SOL exceedance on BES Facilities. Planned transmission outages are to be submitted to COS by 10AM Pacific Prevailing Time four business days prior to the start of the scheduled outage.

Planned outages that are not submitted to COS by 10AM Pacific Prevailing Time four business days prior to the start of the scheduled outage will be considered late.

The start/end time/date of planned outages may be adjusted in COS after initial submission; however, planned outages beginning the next business day should be final (for operations planning purposes) according to the following:

• The start date of a planned outage should be final by 8AM Pacific Prevailing Time one business day prior to the start of the outage.

• The start time of a planned outage should be final by 5PM Pacific Prevailing Time one business day prior to the start of the outage.

COS Submitted daily, at a minimum each week day.

Adjustments to initial scheduled outage submitted as soon as practicable.

Note 7:

If email is used, please email all operational documents which do not require RC review or approval to [email protected]. TOP Restoration Plans and GMD Operating Procedures may be emailed to [email protected].



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Outage start/end dates/times should be updated in COS as soon as practicable to reasonably reflect the planned or actual start/end date/time of the outage.

Outages can be cancelled at any time as deemed necessary by the TOP or BA.

(See note 8 for acceptable examples of planned outage time adjustments)

Scheduled outages are encouraged to be submitted earlier than required.


March 31, 2015

Planned Outage Data

Scheduled generator outages and derates for units 50mw or greater. The RC considers a derate to be any reduction in MW output > 50MW. Scheduled generation outages are to be submitted by 10AM Pacific Prevailing Time at least four business days prior to the start of the scheduled outage.





Outage start/end dates/times should be updated in COS as soon as practicable to reasonably reflect the



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planned or actual start/end date/time of the outage.





April 1, 2016

Planned Outage Data

Scheduled generator outages and derates for all BA Area generation that qualifies per the BES definition any non-BES generation (as determined by Peak) that are necessary to support the accuracy of Operational Planning Analyses and to determine SOL exceedance on BES Facilities. The RC considers a derate to be any reduction in MW output > 50MW. Scheduled generation outages are to be submitted by 10AM Pacific Prevailing Time at least four business days prior to the start of the scheduled outage.







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February 10, 2015

Planned Outage Data

Any scheduled transmission or generation outage that impacts a WECC Transfer Path SOL or stability related interface SOL must be submitted as a path derate event in COS via the COS API or COS user interface. Path derates that are based on scheduled outages are to be submitted by 10AM Pacific Prevailing Time at least four business days prior to the start of the scheduled outage.

Planned outage based Path SOL derates that are not submitted to COS by 10AM Pacific Prevailing Time four business days prior to the start of the scheduled outage will be considered late.

The start/end time/dates of planned outage based Path SOL derates may be adjusted in COS after initial submission; however, those beginning the next business day should be final (for operations planning purposes) according to the following:

• The start date of a planned outage based Path SOL derate should be final by 8AM Pacific Prevailing Time one business day prior to the start of the outage.

• The start time of a planned outage based Path SOL derate should be final by 5PM



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Pacific Prevailing Time one business day prior to the start of the outage.

Planned outage based Path SOL derate start/end dates/times should be updated in COS as soon as practicable to reasonably reflect the planned or actual start/end date/time of the outage.





March 31, 2015

Planned Outage Data

Scheduled outages to remedial action schemes, relays and supporting communication systems (including channel outages when there remains a second, redundant channel operational) that may have an impact to the BES. Scheduled outages must be submitted by 10AM Pacific Prevailing Time at least four business days prior to the start of the scheduled outage. (See note 8 for examples of outage submission timing)


The start/end time/dates of planned outages may be adjusted in COS after initial submission; however, planned outages beginning the next business day should be final (for operations planning purposes) according to the following:


Outages/

COS

Submitted daily, at a minimum each week day.


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Note 8:

Examples of outage submission timing:

• A planned outage beginning anytime on Friday must be submitted to COS no later than 10AM the preceding Monday.

• A planned outage beginning anytime on Monday must be submitted to COS no later than 10AM the preceding Tuesday.

• A planned outage beginning the Monday after Thanksgiving must be submitted to COS no later than 10AM on the Friday prior to Thanksgiving. Note that Peak Thanksgiving Holiday includes Thanksgiving day (Thursday) and the day after Thanksgiving (Friday).

Examples of planned outage adjustments1:

Advanced Outages (outages adjusted to occur sooner in date/time)

• A planned outage beginning Thursday at 9:00AM is submitted to COS the preceding Friday as expected. The entity wants to advance the outage start date to Wednesday at 9:00AM due to early completion of other work. This planned outage date advancement should be made in COS as soon as practicable to improve the accuracy of Peak’s multi day ahead studies; however, the change must be made in COS no later than 8AM on Tuesday.

• A planned outage beginning Friday at 11:00AM is submitted to COS the preceding Monday as expected. The entity wants to advance the outage start time by three hours to 8:00AM due to availability of work crews. This planned outage time advancement should be made in COS as soon as practicable to improve the accuracy of Peak’s multi day ahead studies; however, the change must be made in COS no later than 5PM on Thursday.

Delayed outages (outages adjusted to occur later in date/time)

• A planned two-day outage beginning Monday at 9:00AM is submitted to COS the preceding Tuesday as expected. The entity wants to delay the outage to start on Wednesday at 9:00AM. This planned outage delay should be updated in COS as soon as practicable to improve the accuracy of Peak’s multi day ahead studies; however, the outage delay from Monday to Wednesday must be made in COS no later than 8AM on the preceding Friday.

• A planned outage beginning Friday at 9:00AM is submitted to COS the preceding Monday as expected. The entity wants to delay the outage start time by three hours to 12:00PM due to unavailability of work crews. This planned outage time delay should be updated in COS as soon as practicable to improve the accuracy of Peak’s morning peak hour study; however, the change must be made in COS no later than 5PM on Thursday.

1 In order for an outage to qualify for a date or time adjustment, it must have originally been submitted to COS by 10AM Pacific Prevailing Time four business days prior to the start of the originally scheduled outage date.

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Req #

Responsible Party

*See Note 1


Data Source Type



5.5 Transmission Operator *

January, 2009.

Forced Outage Data

Forced or unscheduled outages to BES elements must be called in to the RC without delay.

Phone notification to RC.

Without delay.


March 31, 2015

Forced Outage Data

Forced or unscheduled transmission outages to BES elements must be submitted to COS as soon as practicable if the transmission element is expected to remain out of service for one hour or longer.

COS As soon as practicable.


January, 2009.

Forced Outage Data

Forced or unscheduled outages or derates to generating units greater than 50 MW must be called in to the RC without delay.


Phone notification to RC without delay.


April 1, 2016

Forced Outage Data

Forced or unscheduled outages or derates for all BA Area generation that qualifies per the BES definition any non-BES generation (as determined by Peak) that are necessary to support the accuracy of Operational Planning Analyses and to determine SOL exceedance on BES Facilities must be called in to the RC without delay. The RC considers a derate to be any reduction in MW output > 50MW.



Phone notification to RC without delay.


March 31, 2015.

Forced Outage Data

Forced or unscheduled generation outages or derates greater than 50 MW must be submitted to COS as soon as practicable if the generating unit is expected to remain out of service for one hour or longer.

Outages/

COS,

Submitted to COS as soon as practicable.

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Data Source Type




April 1, 2016.

Forced Outage Data

Forced or unscheduled generation outages or derates for all BA Area generation that qualifies per the BES definition any non-BES generation (as determined by Peak) that are necessary to support the accuracy of Operational Planning Analyses and to determine SOL exceedance on BES Facilities must be submitted to COS as soon as practicable if the generating unit is expected to remain out of service for one hour or longer. The RC considers a derate to be any reduction in MW output > 50MW.

Outages/

COS,

Submitted to COS as soon as practicable.


February 10, 2015

Forced Outage Data

Any forced or unscheduled transmission or generation outage that impacts a WECC Transfer Path SOL or stability related interface SOL must be submitted as a path derate event in COS as soon as practicable. This requirement for forced outages is applicable to forced outages that are expected to remain out of service for one hour or longer.

COS Submitted to COS as soon as practicable.


July, 2011 Outage Data

Forced or unscheduled outages to RAS and supporting communication systems (including channel outages when there remains a second, redundant channel operational). Transmission Operator shall immediately inform the RC of the status of the RAS including any degradation or potential failure to operate as expected.

Phone call to RC as soon as practical and without intentional delay.

As soon as practicable.


January, 2009.

Outage Data

Planned and unplanned outages of communication systems and ICCP.

Phone notification to the RC

As soon as practicable.

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Data Source Type




May 2010 Outage Data

Notification prior to taking scheduled outages on equipment ≥ 200kV and/or any facilities affecting WECC Transfer Path SOLs or adversely impacting the BES.

Phone call to RC

As determined by the RC on the daily status call OR for all Data Item if entity does not participate on the daily status call 30 to 60 minutes before removing equipment from service.

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Data Source Type




May 2010 Outage Data

Transmission Line (all≥300kV) taken out for Voltage Control

Phone call to RC

Call prior to removal from and prior to return to service


December 31, 2011

Outage Data

Outage study reports shall be made available to the RC. Outage study reports will be uploaded to the PeakRC.org website.

Upload to secure folder in Peak RC web site.

When outage studies completed

6. Power System Modeling Information

Req #

Responsible Party

*See Note 1


Data Source Type




January, 2009.

Modeling Circuit breakers, disconnects, and switches: connectivity and normal status. Applicable for all equipment > 100kV and other lower kV BES equipment.

Secure FTP or email

30 days prior to actual network change


January, 2009.

Modeling Transformers: connectivity, high/low side tap ranges, and per-unit impedance. Applicable for all equipment > 100kV and other lower kV BES equipment.

Secure FTP or email



January, 2009.

Modeling Shunt devices: connectivity, nominal MVAR. Applicable for all equipment > 100kV and other lower kV BES equipment.

Secure FTP or email



January, 2009.

Modeling Lines: connectivity, per-unit impedance and charging susceptance. Applicable for all equipment > 100kV and other lower kV BES equipment.

Secure FTP or email


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Req #

Responsible Party

*See Note 1


Data Source Type




January, 2009.

Modeling Series Capacitor/Reactor: connectivity and per-unit impedance. Applicable for all equipment > 100kV and other lower kV BES equipment.

Secure FTP or email



January, 2009.

Modeling DC Line: connectivity, line parameters, rectifier data, and inverter data.

Secure FTP or email


Peak Reliability


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IRO-010-1a R3


Req #

Responsible Party

*See Note 1


Data Source Type



6.6.1 Transmission Operator*

January 15, 2016

Modeling HVDC Line: A one-line diagram that shows the entire configuration of the HVDC line including breakers/switches, converter transformers, DC poles, converters, DC lines (monopole or Bipolar, ground return or line return), as well as the following equipment parameters for both sides:

Converter Transformer:

• 2 winding or 3 winding • Nominal kV on each

winding • Tap changer: lowest,

highest, and nominal step number, step size, AVR status

• R and X

DC Pole:

• Regulation Schedule for Voltage, Current, and MW, including setpoint and deviation

• Regulation type (on Voltage, MW or MVar)

Converter:

• X0 (Constant term of valve group reactance)

• X1 (First-order term of valve group reactance)

• Amp rating • Min and max extinction

angel • Min and max firing angle • Nominal kV • Bridge number

DC Line:

• R (positive sequence series resistance)


Secure FTP or email


Peak Reliability


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IRO-010-1a R3


Req #

Responsible Party

*See Note 1


Data Source Type




January, 2009.

Modeling Phase shifter: connectivity, per-unit impedance, phase tap range, nominal tap, impedance tables, and step size in degrees. Applicable for all equipment > 100kV and other lower kV BES equipment.

Secure FTP or email



January, 2009.

Modeling Generators: connectivity, gross and net MW maximum and reactive capability curves (if no curve available, MVAR minimum and maximum required).

Secure FTP or email



January, 2009.

Modeling Loads: connectivity and conforming/non-conforming status.

Secure FTP or email


6.10 Transmission Owner*

January, 2009.

Modeling Facility Ratings: Notification of dates for seasonal change of rating set.

Secure FTP or email

Seasonally, 2 days prior to change


January, 2009.

Modeling Spreadsheet of all transmission and generation ICCP object ID data available for the entities Area. Also include SCADA definition relating to each object ID.

Secure FTP or email

Periodic update of ICCP points available (monthly updates when the point list has changed)


January, 2009.

Modeling / Situational awareness

Periodic update of station single line drawings.

Hard copy shipping or electronic transfer (Secure FTP or email)

Final version update as changes occur otherwise annual update

Peak Reliability


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Req #

Responsible Party

*See Note 1


Data Source Type




November 1, 2011


State, city, longitude, and latitude for each substation with voltage levels > 100kV or with total plant generation >= 50MW.

Secure FTP or email

One initial data set; updates to the data as new substations are built.


November 1, 2011


Line routing for all lines 100kV and above.

Data should be accurate to within ~½ mile.

Secure FTP or email

One initial data set; updates to the data as new substations and lines are built.


March 31, 2015


List of shunt devices normally on AVR. These shunts are those that can automatically connect/disconnect at a specified voltage setpoint without operator intervention. The list shall include the voltage setpoint(s) and any time delays prior to automatic switching.

Secure FTP or email

One initial data set; updates as necessary to reflect new devices or changes to existing devices.


June 1, 2015

Modeling List of all dynamic transfers (both pseudo-ties and dynamic schedules) operated by the BA. List should include:

1. Type of transfer (dynamic schedule or pseudo tie)

2. ICCP object ID for associated actual MW value

3. Description and purpose of dynamic transfer, including source and sink and any operational limitations

Secure FTP or email

One initial list; updates as necessary to reflect any changes to the list.

Peak Reliability


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Responsible Party

*See Note 1


Data Source Type




March 31, 2015

Modeling List of all normally open circuit breakers, disconnects and switches that control the connectivity of transmission branch elements and Facilities; list shall include unique status for all applicable seasons. The list is applicable to BES Facilities/elements and non-BES Facilities/elements that impact the BES (see note 1), and non-BES Facilities/elements specifically requested by Peak. Examples of applicable switching devices include those associated with:

• Transmission lines

• Transformers

• Series compensation

• Station bus switches including auxiliary buses and bus tie switches

Examples of non-applicable devices include:

• Shunt devices

Secure FTP or email

One initial list; updates as necessary to reflect any changes to the list.

Note 9:

At a minimum, Peak Reliability requires modeling data associated with Facilities or equipment which are included in the Bulk Electric System (BES) definition, and data for non-BES Facilities/equipment that impact the BES, including but not limited to parallel sub-100-kV systems, as determined by the TOP or by Peak as being necessary to support the accuracy of Real-time Assessments or to determine SOL exceedance on BES Facilities.

Not having this information in the West-wide System Model leads to potential inaccuracies in advanced real-time applications such as state estimation, contingency analysis, and voltage stability.

Modeling data and information shall be sent to Peak using the email address [email protected].


Peak Reliability


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IRO-010-1a R3


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Responsible Party

*See Note 1


Data Source Type




January, 2009.

Modeling RAS scheme information for all schemes. This requires logic diagrams and documentation on the function of each RAS.

Updated Documents, Secure FTP or email

Upon change to RAS schemes/logic.


March 31, 2015

Modeling Description and modeling information for all non-RAS automatic post-contingency actions based on certain parameters such as under voltage or overloaded facilities. This may include, but is not limited to, certain generator run-back schemes or under voltage facility tripping schemes.


Upon change to documents.


January, 2009.

Modeling 100kV and above facility and sub-100-kV BES facility MVA ratings; winter, summer, and fall/spring seasons if used. Continuous, long term and short term ratings are to be provided.


Upon change to ratings.


March 31, 2015

Modeling Time duration for long term and short term rating associated with each 100kV and above facility and sub-100-kV BES facility.




January, 2009.

Modeling 100kV and above and other lower voltage BES bus voltage limits. Pre- and Post-Contingency high and low voltage limits are to be submitted consistent with Peak’s SOL Methodology for the Operations Horizon document.




March 31, 2015

Modeling Overload relay trip settings (including time-delay) on those Facilities (transformers and transmission lines) that are part of Bulk Electric System and their overload trip settings are below 125% of the highest Facility rating


Upon change to relay trip settings.

Peak Reliability


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7. Other Operational Information

Req #

Responsible Party

*See Note 1


Data Source Type




May 2010 SOLs When an SOL is exceeded on all ≥ 100kV and other lower kV network elements that have an impact on the bulk electric system (BES).

Phone call to the RC as soon as practicable and without intentional delay.

As soon as practicable


February 28, 2013

Operations Notification of Real-Time Contingency Analysis (RTCA) failure.

This request is only applicable to those TOPs that run RTCA in support of real-time operations.

Phone call to the RC or WECCNet or successor

Any time RTCA is not available to TOP operations staff for more than 15 minutes


March 31, 2015

Operations Notification of inability to calculate ACE for greater than 30 minutes.

Phone call to the RC


Note 10:

A note about Facility Ratings: Peak Reliability monitors for pre-contingency (actual) exceedances of continuous, long term, and short term facility ratings. Using real-time and study contingency analysis, Peak monitors for post-contingency exceedances of the long term and short term Facility Ratings.

Peak recognizes that Facility Ratings are the responsibility of the TO. Practically, the TOP may provide those Facility Ratings to Peak if they are dynamically provided, or if they are verbally provided as part of real-time operations or operations planning activities.

It is advantageous for TOs and/or TOPs to provide Peak with the highest available short term Facility Rating for monitoring in contingency analysis. Any post-contingency facility rating exceedance beyond the highest available Facility Rating is considered an SOL exceedance.

In addition to providing Peak with the Facility Ratings, TOs and/or TOPs must provide the time duration that the facility can be operated within the long term and short term ratings. This information will help Peak RCSOs understand how much time is available before mitigation must address the exceedance.

Peak Reliability


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Req #

Responsible Party

*See Note 1


Data Source Type



7.4 Balancing Authority or Transmission Operator

March 31, 2015

Operations Any protective relay or equipment failure that reduces system reliability and corrective actions taking place.

Phone call to the RC


Peak Reliability


Version 10.2

IRO-010-1a R3


Version History

Rev. Date Action By Change Tracking 1.0 05/30/2008 Issued for Implementation Mark Maher Original WECC RC Data Request 2.0 02/04/2009 Revised and Reissued Eric Whitley Changed contact information.

Added additional real-time measurements, forecast data, clarified outage derates.

3.0 03/30/2009 Revised and Reissued Eric Whitley Fixed spelling, added effective date. Added additional real-time measurements, modeling data, outage data.

4.0 05/19/2009 Revised and Reissued Eric Whitley Added real-time RAS data and RAS documentation, other real-time data, path outages, modeling data.

5.0 09/15/2010 Revised and Reissued Brett Wangen Changed contact information. Added clarification documentation and real-time data. Added additional outage data, added path outages via EIDE, added SOL data.

6.0 8/20/2011 Revised and Reissued Brett Wangen Reformatted, new template. Added submission deadlines for forecast and outage data. Added modeling data.

7.0 12/31/2012 Revised and Reissued Brett Wangen Added requirement numbers, updated multiple standards, added notification of RTCA failure, updated contact information.

8.0 02/13/2014 Revised and Reissued Brett Wangen Rebranded document to Peak Reliability.

9.0 12/31/2014 Revised and Reissued Brett Wangen Divided data request into sections and renumbered accordingly. Added several clarifying/explanatory notes throughout the request. Updated planned outage requirements. Added multiple real-time data items, documentation items, modeling data items and other operational items.

10.0 10/02/2015 Revised and Reissued Jason Ausmus New document template, added versioning. Updated and expanded forecast data requirements, modeling requirements, real-time data requirements.

Peak Reliability


Version 10.2

IRO-010-1a R3


Rev. Date Action By Change Tracking 10.1 01/05/2016 Revised and Reissued Jason Ausmus Changed the Data Request

Effective Date for Req # 2.9.1 from Jan 15, 2016 to TBD.

10.2 01/06/2016 Revised and Reissued Jason Ausmus Changed the Data Request Effective Date for Req # 3.3.1 from Jan 15, 2016 to TBD.

Peak Reliability Version 10.2 Reliability Coordinator Data Request and Specifications ... ·...

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