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Regulatory Update

NERC Protection System Compliance Studies Due This Year

Dylan Achey and Tim Farrar, PE | February 24, 2020

NERC’s PRC-027-1 standard addressing the Coordination of Protection Systems for Performance During Faults is designed to ensure that transmission owners and generators can detect and isolate faults on bulk electric system (BES) elements so that protection systems operate in the intended sequences during disturbances. The standard was approved by FERC in 2018 and is set to go into effect on October 1, 2020. Utilities should begin preparing now to meet compliance requirements which include significant system studies.  Additional information on the issues addressed in PRC-027-1 is available in the NERC System and Protection Controls Task Force 2006 Assessment of Standard PRC-001.

Standard Requirements

PRC-027-1 includes three mandatory requirements.

Requirement R1 mandates that an entity establish a process for developing new and revised protection system settings for BES elements to operate in the intended sequence during faults and stipulates certain attributes that must be included in the process.

Requirement R2 mandates that every six years utilities must implement one of the following:

  • Option 1: Perform a Protection System Coordination Study in a time interval not to exceed six-calendar years; or
  • Option 2: Compare present Fault current values to an established Fault current baseline and perform a Protection System Coordination Study when the comparison identifies a 15 percent or greater deviation in Fault current values (either three phase or phase to ground) at a bus to which the BES Element is connected, all in a time interval not to exceed six-calendar years;[1] or,
  • Option 3: Use a combination of the above.

The applicable protection system functions are identified in Attachment A of the PRC-027-1 standard. They include those protection system functions that require coordination with other protection systems such as:

21 – Distance relaying function if:

  • Infeed is used in determining reach (phase and ground distance), or
  • Zero-sequence mutual coupling is used in determining reach (ground distance).

50 – Instantaneous overcurrent relaying function

51 – AC inverse time overcurrent relaying function

67 – AC directional overcurrent relaying function if it is used in a non-communication-aided protection scheme

Requirement R3 mandates that a utility utilize the process established in accordance with Requirement 1 for the development of any new or revised protection system relay settings.

There is extensive supplemental material, with examples published with the standard to provide guidance on how to maintain compliance with the requirements.

Next Steps

TRC is supporting a number of utilities (generator owners and transmission owners) to meet the mandatory October 2020 study deadline. It is important to identify the applicable protection system functions of generators and transmission lines identified in Attachment A of the PRC-027-1 standard. Based on PRC-027-1 Requirement R2, utilities should analyze the relay protective settings whether they are set to operate in the intended sequence during faults.  TRC is currently working with multiple clients to develop PRC-027-1 studies for their facilities to either show compliance or develop relay protection settings to meet compliance. Our PRC-027-1 analysis report will provide the details of coordination results including plots and explanations in a comprehensive format for use by clients to provide evidence of compliance with the standard.


About TRC

TRC’s approach to power delivery design balances solutions that incorporate appropriate standards, regulatory requirements, best practices and operational goals and budgets. Our power system experts help you stay ahead of changing regulatory expectations because they stay engaged with the regulatory process and know how to plan, design and install programs that address your financial, technical and scheduling goals including compliance with changing NERC standards and guidelines as well as industry “best practices” and the latest technology developments.

This regulatory update is a service to TRC’s utility clients, helping keep you informed of issues that impact your company’s electric system security risks along with related topics regarding future regulatory developments to help you achieve your company’s business goals.

[1] The initial Fault current baseline(s) shall be established by the effective date of this Reliability Standard and updated each time a Protection System Coordination Study is performed. The Fault current baseline for BES generating resources may be established at the generator, the generator step-up (GSU) transformer(s), or at the common point of connection at 100 kV or above. For dispersed power producing resources, the Fault current baseline may also be established at the BES aggregation point (total capacity greater than 75 MVA). If an initial baseline was not established by the effective date of this Reliability Standard because of the previous use of an alternate option or the installation of a new BES Element, the entity may establish the baseline by performing a Protection System Coordination Study.

Dylan Achey

Dylan Achey is TRC’s Manager of Generation Engineering Services. He has been leading the effort with TRC generation clients on evaluating and providing updates/information so that clients can meet applicable NERC standards. His highly technical staff perform NERC compliance standard evaluations as well as studies for both generation and transmission clients that need assistance on technical issues concerning NERC compliance. Contact Dylan at

Tim Farrar, PE

Tim Farrar is a licensed professional engineer and works as the Protection & Controls Chief Engineer in TRC’s Augusta, Maine office. He is also a Certified Control System Technician (CCST) and Licensed Electrician with an Associate Degree from Eastern Maine Technical in Electrical Power Technology. Tim has 28 years of experience in protection and controls systems engineering for electric utilities and power generation industries including 10 years at Central Maine Power Company and 18 Years in the consulting engineering business. He has held several positions at TRC as an Engineer, Supervisor of Automation and Controls and Electrical Engineering Manager prior to his current position as Chief Engineer.

Contact Tim at

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