Peak Reliability
/ Outage Coordination Process / DRAFT Version 1.0
NERC Reliability Standard IRO-017-1

Contents

I.Purpose

II.Applicability

III.Introduction

IV.Outage Coordination Process Scope

V.Outage Coordination Tool

VI.General Outage Submission Requirements and Responsibilities

VII.Outage Types

VIII.Outage States

IX.Study and Assessment Requirements

X.Operating Plan Requirements

XI.The Four Study Window Processes

XII.Planning Horizon to Operations Horizon Process

XIII.Long-Range Study Window Process

XIV.Short-Range Study Window Process

XV.Operational Planning Analysis (OPA) Window Process

XVI.Same-Day and Real-Time Outage Update Requirements

XVII.Revising and Rescheduling Outages

XVIII.Conflict Resolution Process

I.Purpose

The purpose of the Outage Coordination Process document is to:

  • Provide a process for coordination of transmission and generation outages within the Peak Reliability Coordinator (RC) area.
  • Describe the applicable functional entity roles and responsibilities.
  • Provide a mechanism to facilitate compliance with NERC Reliability Standard IRO-017-1 by ensuring outages are properly coordinated in the Operations Planning time horizon.

Adherence to this process is intended to help achieve Bulk Electric System (BES) reliability under outage conditions and to minimize late-term cancellation of scheduled outages.

II.Applicability

Peak Reliability’s Outage Coordination Process is applicable to the following entities within the Peak RC Area:

  • Peak Reliability as the RC
  • Balancing Authorities (BA)
  • Transmission Operators (TOP)
  • Planning Coordinators (PC)
  • Transmission Planners (TP)

Detailed responsibilities for each functional entity are described within the Outage Coordination Process.

BAs are expected to require Generator Owners (GO) and Generator Operators (GOP) to communicate outages to the BA as required to support the Outage Coordination Process.

TOPs are expected to require Transmission Owners (TO) and BAs to communicate outages to the TOP as required to support the Outage Coordination Process.

Per IRO-017-1, PCs and TPs within the Peak RC Area are expected to provide their Planning Assessment to Peak Reliability. Each PC and TP is expected to identify issues or conflicts with Planned outages in its Planning Assessment for the Near-Term Transmission Planning Horizon.

III.Introduction

During the development of this process, Peak collaborated with its stakeholders to ensure the Outage Coordination Process would dovetail with existing TOP/BAprocesses as much as possible.

Peak recognized that the process would mature over time, so efforts were made to ensure the process foundation was in place to allow for enhancements over time without requiring complete paradigm shifts.

The Outage Coordination Process answers the following questions:

  • What are my responsibilities and obligations as a TOP or BA with regard to submitting planned and unplanned transmission and generation Facility/equipment outages?
  • What is Peak Reliability’s responsibility and obligation to process my submitted planned and unplanned outages?

It is important to note that although this document does provide a process for coordinating outages, real-time system conditions will always take precedence over planned work. As such, Peak reminds its stakeholders that the RC, BA and TOP operators have the authority and responsibility granted to them by the NERC Reliability Standards to make real-time decisions based on system conditions and that those decisions may supersede the functions specified in this Outage Coordination Process.

Finally, Peak recommends that stakeholders refer to the following general guiding principles when implementing this Outage Coordination Process:

  • Coordination is more than checking boxes. In order to be successful, operating entities must work together effectively. There will be times when outages conflict with one another. Collaboration is key to ensuring the needs of the Interconnection as a whole are met, in order to ensure reliability.
  • Consideration should be given to seasonal concerns when planning outages.
  • Acceptable system performance must be maintained under outage conditions as per the Peak Reliability SOL Methodology for the Operations Horizon document.

IV.Outage Coordination Process Scope

Consideration shall be given to the in-scope and out-of-scope outage categories listed below when submitting outages.

In-Scope Outage Categories:

  • BES transmission/generation Facilities.
  • BES switching devices.
  • BES voltage control equipment (BES/non-BES necessary for BES voltage control).
  • BES Remedial Action Scheme (RAS) (including non-RAS automatic actions) and protection systems when functionality is affected or Contingency definitions are impacted.
  • Non-BES transmission or generation Facilities or equipment that are identified by the RC, TOP or BA as having an impact on the reliability of the BES.

Note that submitting entities may provide Informational outage submissions at their discretion to communicate information that might improve situational awareness for enhanced reliability. For example, an entity may choose to submit an Informational outage if they are performing work on a back-up system of a high-impact RAS.

Peak’s IRO-010-2 Data Specification contains a list of the data Peak requires for its operations and operations planning needs. For some of these data items, the Coordinated Outage System (COS) is the mechanism for providing that data to Peak. COS is also the primary tool used to support the Outage Coordination Process. Note that some of these data items where COS is the mechanism for providing that data may be out of scope for the Outage Coordination Process.

Out-of-Scope Outage Categories:

  • Non-BES transmission/generation Facility/equipment
  • Non-BES switching devices
  • Generator derates
  • Automatic Voltage Regulators (AVR)
  • Power System Stabilizers (PSS)
  • RAS (Including non-RAS automatic actions) and protection systems when functionality is not affected or Contingency definitions are not impacted
  • Telemetering equipment

Outage categories that are out of scope may be covered under Peak’s IRO-010-2 Data Specification.

V.Outage Coordination Tool

The Coordinated Outage System (COS) will be the primary tool used by Peak to collect and view data necessary to support the Outage Coordination Process. It is expected that all entities required to submit outages per the Outage Coordination Process submit those outages to COS either via the web user interface (WebUI) or the application programming interface (API).

If an entity currently has itsown mechanisms for managingand coordinating outages (i.e. through another software tool, spreadsheets, emails, etc.) those processes can continue. However, all outage data being requested as a part of the Outage Coordination Process must be submitted per the timing requirements and must ultimately end up in COS. Each submitting entity is responsible for determining how best to do that for itsrespective organization. The Outage Coordination Process is designed to facilitate an entity’s ability to use COS to obtain outage information from itsneighbors for coordination purposes if itchooses to do so.

Should COS become unavailable at any time during the Outage Coordination Process, Peak will communicate information regarding an alternate means of submitting outage data.

VI.General Outage Submission Requirements and Responsibilities

Outages must be scheduled and submitted consistent with the Outage Coordination Process. When the Outage Coordination Process refers to outage “submission,” it is understood that it is referring to outage submission to the RC Coordinated Outage System (COS) tool. Outages are to be submitted for in-scope items. The remainder of the Outage Coordination Process document assumes that submissions are applicable to in-scope items.

Outage Submission Responsibility

Outage submission is a TOP and BA responsibility. TOPs are responsible for submission of transmission outages, and BAs are responsible for submission of generation outages. Reference the Outage Types section of this document for submission requirements specific to each outage type. Reference the COS Manual for detailed information on how to submit outages to COS.

TOP General Outage Submission Responsibilities

  1. The TOP that operates a given Facility/equipment is responsible for submitting transmission outages for that Facility/equipment. Outage submission responsibility is not a function of Facility/equipment ownership.
  2. The Outage Coordination Process allows a TOP to delegate its responsibility of submitting transmission outages to another NERC-registered functional entity (for example, the equipment owner (the TO)), provided a written agreement is supplied to the RC. Such arrangements for the submission of outages do not absolve the TOP of other obligations related to the Outage Coordination Process.
  3. For jointly operated transmission Facilities/equipment, the TOP who requires the transmission outage is responsible for submitting the outage. Reference the Study and Assessment Requirements section for more information on TOP responsibilities for jointly operated Facilities.
  4. Example – TOP A needs an outage on a transmission line that ties TOP A’s area with TOP B’s area. TOP A is responsible for submitting the outage.
  5. When a Forced Automatic or Forced Emergency outage occurs on a jointly operated Facility, the associated TOPs are expected to coordinate and agree on who will submit the outage to COS. It is acceptable for this coordination and agreement to happen when the Forced Automatic or Forced Emergency outage occurs. The expectation is that one of the two TOPs submits the Forced Automatic or Forced Emergency outage to COS.
  6. If a transmission outage necessitates or results in a generator outage or reduction, the TOP is expected to coordinate with the BA to ensure the outage is acceptable and reliable. The BA is still responsible for submitting the resulting generation outage.

BA General Outage Submission Responsibilities

  1. The BA in whose BA Area the generator resides (i.e., that are within the metered boundaries of the BA Area) is responsible for submitting outages for that generator. Outage submission responsibility is not a function of generator ownership.
  2. If scenarios exist where it is not clear which BA is responsible for submitting a generator’s outage, the BAs that are associated with the generating unit or plant are expected to collaboratively determine which BA will assume responsibility for submitting outages for that generator, to document the decision, and to communicate that decision to the RC (via email or other method). Examples of such generators may include pseudo-tied units or jointly operated units or plants.
  3. The Outage Coordination Process allows a BA to delegate its responsibility of submitting generation outages to another NERC-registered functional entity (for examplethe equipment owner (the GO) or the Generator Operator (GOP)), provided a written agreement is supplied to the RC. Such arrangements for the submission of outages do not absolve the BA of other obligations related to the Outage Coordination Process.
  4. Unit outages need to be submitted to COS if the unit is unavailable and cannot be called upon for use. Examples include a unit that is down for maintenance work, repair work or nuclear refueling. Outages do not need to be submitted for units that are not committed. Peak’s data specification provides a mechanism to obtain necessary data for unit commitment, unit output limitations and projected unit dispatch.
  5. For example, if a unit is not committed or is not needed to serve load or facilitate schedules, the unit being “off” is not within scope of the Outage Coordination Process. If the BA takes this opportunity to perform maintenance on a unit while it is not needed, the BA is responsible for submitting an outage on that unit while it is out of service for the maintenance work.
  6. As another example, restrictions such as a hydro plant that isunable to generate for the next four hours due to water limitations or other restrictions do not need to be submitted to COS as outages.
  7. If a generation outage necessitates or results in a transmission outage or reconfiguration, the BA is expected to coordinate with the TOP to ensure the outage is acceptable and reliable. The TOP is still responsible for submitting the resulting transmission outage.

RC General Outage Submission Responsibilities

  1. The RC is responsible for ensuring that each Facility/equipment and generator modeled in the West-wide System Model (WSM) is associated with a TOP/BA that is responsible for submitting outages for that Facility/equipment or generator. This includes documenting any delegation agreements for the submission of transmission and generation outages. Ultimately, the RC needs to understand which TO, GO or GOP is actually submitting the outage per any submission delegation agreements.

General Requirements for Outage Submission

Outage Duration Submission Threshold

  1. Outages expected to have a duration of 30 minutes or more require submission to COS.
  2. Outages expected to have a duration of less than 30 minutes are not required to be submitted to COS unless the outage requires an Operating Plan to facilitate the outage, in which case, the Operating Plan needs to be submitted to COS at the time of TOP/BA confirmation. Reference the Operating Plan Requirements section for more information. Even though a less-than-30 minute outage does not require submission to COS, TOPs and BAs are expected to study/assess the outage.

One-at-a-Time (OAT) Outages

  1. For OAT outages where the individual Facility/equipment outages are expected to have a duration of less than 30 minutes, and no Operating Plan is required for any of the individual Facility/equipment outages, it is expected that the TOP/BA submit a single representative Informational outage to address all of the OAT outages.
  2. If, during the course of the OAT outage work, it is discovered that a Facility/equipment cannot be returned to service due to unexpected issues, the TOP/BA is expected to submit an individual outage for the Facility/equipment as soon as possible.
  3. If the individual Facility/equipment outages of an OAT outage are expected to last for 30 minutes or longer, the individual Facilities need to be entered into COS as separate outages with distinct start/end times. The start/end times of the individually entered outages should not overlap if they are not expected to overlap in the field.
  4. If the individual Facility or equipment outages within an OAT outage are expected to last for less than 30 minutes, the individual Facilities do not need to be entered into COS as separate outages (unless there is an Operating Plan associated with the OAT outage as stated above).
  5. BAs and TOPs are expected to perform studies/assessments to ensure that acceptable system performance will be achieved during all phases of an OAT outage sequence.
  6. The RC will not perform outage studies on all phases of an OAT outage as part of Planned outage assessments or Operational Planning Analysis (OPA).

Continuous Versus Non-Continuous Outages

  1. Continuous Outage – A Facility/equipment outage that will remain out of service for the duration of the specified start date/time and end date/time.
  2. Non-Continuous Outage – A Facility/equipment outage that will not be out of service for the duration of the specified start date/time and end date/time. An example of a non-continuous outage would be a multi-day outage where work is performed during the day and the equipment is returned to service at night.

VII.Outage Types

The seven unique outage types are described and listed below in their order of priority. Note that outage types are italicized in the Outage Coordination Process document.

  1. Forced Automatic Outage – Facility/equipment that is removed from service via automatic action.
  2. Forced Emergency Outage – Facility/equipment that is removed from service via operator action due to imminent equipment risks, safety concerns, environmental regulations or increased risk to grid reliability and/or security.
  3. Urgent Outage – Facility/equipment that is known to be operable, yet carries an increased risk of a Forced Emergency or Forced Automatic outage occurring. Facility/equipment remains in service until personnel, equipment and system conditions allow the outage to occur.
  4. Operational Transmission Outage – Transmission Facility/equipment that is removed from service in the normal course of maintaining optimal or reliable system conditions but remains available if needed upon short notice.
  5. Planned Outage – Non-automatic Facility/equipment outage with advance notice, for the purpose of maintenance, construction (including energizing and testing new Facilities), inspection, testing or other planned activities.
  6. Opportunity Outage – A short-duration Facility/equipment outage that can be taken due to a change in system conditions or availability of field personnel.
  7. Informational Outage – Facility/equipment outage that is entered into COS for informational reasons includingincreased situational awareness, for TOP/BA internal purposes or to satisfy the RC Data Specification where COS is the mechanism for communicating the information.

Reference Peak’s RC Data Request for same-day and real-time operations notification requirements. The next section provides details for each outage type listed above.

Forced Automatic Outage Type

Forced Automatic Outage – Facility/equipment that is removed from service via automatic action.

Submission requirements for Forced Automatic outages:

  1. Submit to COS as soon as possible, ideally no later than 30 minutes after the Forced Automatic outage has occurred; however, a System Operator’s first priority is to address the operating issue. Exceptions are allowed as deemed necessary by the submitter based on prevailing emergency conditions. Reference the Same-Day and Real-Time Outage Update Requirements section for more information.
  2. Forced Automatic outages that have (or are expected to have) a duration of less than 30 minutes do not require submission to COS. Forced Automatic outages that have a duration of 30 minutes or more are required to be submitted to COS even if they are submitted after the fact.
  3. Submissions are required to have a scheduled end time based on the best information available at the time. It is expected that submitters update the scheduled end time of a Forced Automatic outage as information becomes available.

Examples of Forced Automatic outages:

  1. A fault occurs on a transmission line, and the line trips offline in response to relay action.
  2. An event occurs and a generator is tripped offline due to RAS action.

Forced Emergency Outage Type