FERC-725G in Docket No. RM11-16-000 (Final Rule) Issued: 3/15/2012
OMB Control No.: 1902-0252. RIN: 1902-AE42
Supporting Statement for
FERC‑725G, Transmission Relay Loadability Mandatory Reliability Standards
For the Bulk-Power System
For the Final Rule in Docket No. RM11-16-000
(issued March 15, 2012)
The Federal Energy Regulatory Commission (Commission or FERC) is submitting a Final Rule that affects the requirements under the following information collection: FERC‑725G, Transmission Relay Loadability Mandatory Reliability Standards for the Bulk Power System (OMB Control No. 1902-0252). FERC-725G is an existing data collection (reporting and record retention requirements), as contained in 18 Code of Federal Regulations, Part 40, for which the Commission seeks OMB review.
Background
On August 8, 2005, The Electricity Modernization Act of 2005 (Title XII of the Energy Policy Act of 2005) (EPAct 2005), was enacted into law.1 EPAct 2005 added a new section 215 to the Federal Power Act (FPA) and requires a Commission-certified Electric Reliability Organization (ERO) to develop mandatory and enforceable Reliability Standards, which are subject to Commission review and approval. Once approved, the Reliability Standards may be enforced by the ERO, subject to Commission oversight.2
Final Rule, Order No. 693, Docket No. RM06-16-000
On March 16, 2007, the Commission issued Order No. 693, a Final Rule that added part 40 to the Commission’s regulations. The Final Rule stated that this part applies to all users, owners and operators of the Bulk-Power System within the United States (other than Alaska or Hawaii).3 It also requires that each Reliability Standard identify the subset of users, owners and operators to which that particular Reliability Standard applies. Order No. 693 also requires that each Reliability Standard that is approved by the Commission will be maintained on the ERO’s Internet website for public inspection.
The Commission approved 83 of 107 proposed Reliability Standards, six of the eight proposed regional differences, and the Glossary of Terms used in Reliability Standards as developed by the North American Electric Reliability Corporation (NERC). NERC was certified by the Commission as the ERO responsible for developing and enforcing mandatory Reliability Standards.
Relay Protection Systems
Protective relays are devices that detect and initiate the removal of faults on an electric system.4 They are designed to read electrical measurements, such as current, voltage, and frequency, and can be set to recognize certain measurements as indicating a fault. When a protective relay detects a fault on an element of the system under its protection, it sends a signal to an interrupting device(s) (such as a circuit breaker) to disconnect the element from the rest of the system.
Impedance relays are the most common type of relays used to protect transmission lines. Impedance relays continuously measure local voltage and current on the protected transmission line and operate when the measured magnitude and phase of the impedance (voltage/current) falls within the settings or reach of the relay.5 Impedance relays can also provide backup protection and protection against remote circuit breaker failure.
The sequence in which protective relays operate is important. For example, on a transmission line, coordination of protection through distance settings and time delays ensures that the relay closest to a fault can operate before a relay farther away from the fault.6 If the more distant relay operates first, it will disconnect both the transmission equipment necessary to remove the fault and “healthy” equipment that should remain in service.
On March 18, 2010, the Commission issued a Final Rule approving Reliability Standard PRC-023-1 (Transmission Relay Loadability), a Standard that requires transmission owners, generator owners, and distribution providers to set load-responsive phase protection relays according to specific criteria to ensure that the relays reliably detect and protect the electric network from all fault conditions, but do not operate during non-fault load conditions.7 In addition, under section 215(d)(5) of the FPA, the Commission directed the ERO to develop modifications to the Standard to address certain issues identified by the Commission. At issue in the immediate proceeding is a revised Reliability Standard that addresses Commission directives in that order and will replace the currently effective PRC-023-1.
NOPR in Docket No. RM11-16-000
In a March 18, 2011 filing (NERC Petition), NERC requested Commission approval of both its proposed Reliability Standard PRC-023-2 and its proposed NERC Rules of Procedure Section 1700 – Challenges to Determinations.
NERC stated that the proposed Reliability Standard requires transmission owners, generator owners, and distribution providers to verify relay loadability using methods that achieve “the reliability goal of this Standard in an effective and efficient manner familiar to the responsible entities.”8 The proposed Standard also applies to out-of-step blocking systems as well as to load-responsive phase protections systems. NERC specifically identified the benefits of proposed Reliability Standard PRC-023-2, as including (a) consistent identification of operationally critical circuits operated below 200 kV that must comply with the Requirements of the Standard, and (b) providing transmission operators, planning coordinators, reliability coordinators, and the ERO with more information regarding the criteria selected by entities for verifying relay loadability.9
Reliability Standard PRC-023-2 contains six requirements with the stated purpose of ensuring that protective relay settings do not limit transmission loadability; do not interfere with system operators’ ability to take remedial action to protect system reliability; and are set to reliably detect all fault conditions and protect the electrical network from these faults.10 The Reliability Standard also includes two attachments. Attachment A specifies the protection systems that are subject to and excluded from the Standard’s Requirements. Attachment B specifies the criteria for determining the circuits which must comply with Requirements R1 through R5.
Final Rule in Docket No. RM11-16-000
The final rule approves Reliability Standard PRC-023-2 which will replace currently effective Reliability Standard PRC-023-1 approved by the Commission in Order No. 733. Rather than creating entirely new requirements regarding the setting of protective relays, the Reliability Standard instead modifies and improves the existing Reliability Standard. Modified reporting and record retention requirements in the Reliability Standard have been accounted for and burden estimates are shown in item 12 and 13.
A. Justification
1. CIRCUMSTANCES THAT MAKE THE COLLECTION OF INFORMATION NECESSARY
With the passage of EPAct 2005 Congress entrusted FERC with the authority to approve and enforce rules to assure reliability of the Nation’s Bulk Power System. Section 1211 of EPAct 2005 created a new section 215 to the Federal Power Act (FPA) (16 U.S.C. 824o), which provides for a system of mandatory and enforceable Reliability Standards. Section 215(d)(1) of the FPA provides that the ERO must file each Reliability Standard or modification to a Reliability Standard that it proposes to be made effective, i.e., mandatory and enforceable, with the Commission. The law mandates that all users, owners, and operators of the Bulk-Power System in the United States will be subject to the Commission-approved Reliability Standards.
Section 215(d)(2) of the FPA provides that the Commission may approve, by rule or order, a proposed Reliability Standard or modification to a proposed Reliability Standard if it meets the statutory standard for approval, giving due weight to the technical expertise of the ERO. Alternatively, the Commission may remand a Reliability Standard pursuant to section 215(d)(4) of the FPA. Further, the Commission may order the ERO to submit to the Commission a proposed Reliability Standard or a modification to a Reliability Standard that addresses a specific matter if the Commission considers such a new or modified Reliability Standard appropriate to “carry out” section 215 of the FPA.11 The Commission’s action in this Final Rule is based on its authority in accordance with section 215 of the FPA.
On August 14, 2003, a blackout that began in Ohio affected significant portions of the Midwest and Northeast United States, and Ontario, Canada (2003 blackout). This blackout affected an area with an estimated 50 million people and 61,800 megawatts of electric load.12 The subsequent investigation and report completed by the U.S.-Canada Power System Outage Task Force (Task Force) concluded that a substantial number of lines disconnected when backup distance and phase relays operated under non-fault conditions. The Task Force determined that the unnecessary operation of these relays contributed to cascading outages at the start of the blackout and accelerated the geographic spread of the cascade.13 Seeking to prevent or minimize the scope of future blackouts, both the Task Force and NERC made recommendations to ensure that protective relays do not contribute to future blackouts.
The Task Force determined that one of the principal reasons why cascading outages spread beyond Ohio was the operation of zone 3/zone 2 relays in response to overloads rather than true faults.14 The Task Force identified fourteen 345 kV and 138 kV transmission lines that disconnected because of zone 3/zone 2 relays applied as remote circuit breaker failure and backup protection. Among these relays were several zone 2 relays in Michigan that were set to overreach their protected lines by more than 200 percent without any intentional time delay.15 The Task Force stated that although these and the other relays operated according to their settings, they operated so quickly that they impeded the natural ability of the electric system to hold together and did not allow time for operators to try to stop the cascade.16 The Task Force described the unnecessary operation of these relays as the “common mode of failure that accelerated the geographic spread of the cascade.”17 The Task Force also indicated that as the cascade progressed beyond Ohio it spread because of dynamic power swings and the resulting instability.18
2. HOW, BY WHOM, AND FOR WHAT PURPOSE THE INFORMATION IS TO BE USED AND THE CONSEQUENCES OF NOT COLLECTING THE INFORMATION
The final rule in FERC-725G approves a revised Reliability Standard that modifies an existing requirement regarding setting protective relays according to specific criteria in order to ensure that the relays reliably detect and protect the electric network from all fault conditions, but do not limit transmission loadability or interfere with system operators’ ability to protect system reliability. Reliability Standard PRC-023-2 requires entities to set transmission relays according to specified criteria and to retain evidence of compliance. It also requires planning coordinators to implement a test to determine which sub-200 kV facilities are critical to the reliability of the power system and subjects such facilities to the requirements of the Standard. The Reliability Standard requires entities to maintain records subject to review by the Commission and NERC to ensure compliance with the Reliability Standard.
Without this Reliability Standard in place (and its corresponding reporting and record retention requirements) the Bulk-Electric System would be at a greater risk of uncontrolled outages.
3. DESCRIBE ANY CONSIDERATION OF THE USE OF IMPROVED TECHNOLOGY TO REDUCE BURDEN AND TECHNICAL OR LEGAL OBSTACLES TO REDUCING BURDEN.
The Reliability Standard does not require any information to be submitted directly to the Commission. However, the Commission does support the use of improved technology in complying with the reporting and record keeping requirements of the Standard. The Commission has not considered any specific legal obstacles related to the burden that could be removed in order to reduce burden. However, FERC staff works with NERC staff and standards drafting teams in an effort to carry out directives effectively and efficiently and to produce standards that can be approved by the Commission in an efficient manner.
4. DESCRIBE EFFORTS TO IDENTIFY DUPLICATION AND SHOW SPECIFICALLY WHY ANY SIMILAR INFORMATION ALREADY AVAILABLE CANNOT BE USED OR MODIFIED FOR USE FOR THE PURPOSE(S) DESCRIBED IN INSTRUCTION NO. 2
Filing requirements are periodically reviewed as OMB review dates arise or as the Commission may deem necessary in carrying out its responsibilities under the FPA in order to eliminate duplication and ensure that filing burden is minimized. There are no similar sources of information available that can be used or modified for these reporting purposes.
5. METHODS USED TO MINIMIZE BURDEN IN COLLECTION OF INFORMATION INVOLVING SMALL ENTITIES
In Order No. 693, the Commission adopted policies to minimize the burden on small entities, including approving the ERO compliance registry process to identify those entities responsible for complying with mandatory and enforceable Reliability Standards. The ERO registers only those distribution providers or load serving entities that have a peak load of 25 MW or greater and are directly connected to the bulk electric system or are designated as a responsible entity as part of a required under-frequency load shedding program or a required under-voltage load shedding program. Similarly, for generators, the ERO registers only individual units of 20 MVA or greater that are directly connected to the bulk electric system, generating plants with an aggregate rating of 75 MVA or greater, any blackstart unit material to a restoration plan, or any generator that is material to the reliability of the Bulk-Power System. Further, the ERO will not register an entity that meets the above criteria if it has transferred responsibility for compliance with mandatory Reliability Standards to a joint action agency or other organization.19
In the subject Final Rule, the Commission asserts that while a significant number of small entities will be affected by the proposed Reliability Standard, the impact will be minimal and not significantly affect small entities.
6. CONSEQUENCE TO FEDERAL PROGRAM IF COLLECTION WERE CONDUCTED LESS FREQUENTLY
Protective relays are critical to ensuring the reliability of the Bulk-Electric System. The proposed information collection requirements are designed to monitor and ensure compliance with the proposed Reliability Standard. While less strict compliance requirements could be contemplated, the requirements proposed in PRC-023-2 have been debated, vetted, and approved by industry prior to coming to FERC for final approval and are designed to meet the purposes of the Reliability Standard. If anything less than these requirements were implemented it would increase the risk of outages on the grid and diminish the ability of FERC to meet its mandated reliability mission.
7. EXPLAIN ANY SPECIAL CIRCUMSTANCES RELATING TO THE INFORMATION COLLECTION
There are no special circumstances related to this information collection.
8. DESCRIBE EFFORTS TO CONSULT OUTSIDE THE AGENCY: SUMMARIZE PUBLIC COMMENTS AND THE AGENCY'S RESPONSE TO THESE COMMENTS
Each Commission rulemaking (both NOPRs and Final Rules) are published in the Federal Register, thereby affording all public utilities and licensees, state commissions, Federal agencies, and other interested parties an opportunity to submit data, views, comments or suggestions concerning the proposed collection of data. The notice procedures also allow for public conferences to be held as required.
On September 21, 2011, notice of the September 15 NOPR was published in the Federal Register with comments due on or before November 21, 2011.20 Timely comments were filed by the American Public Power Association (APPA), ISO New England Inc. (ISO-NE), the Midwest Independent System Operator, Inc. (MISO), and NERC.
The following sections under item 8 of this supporting statement are excerpted nearly verbatim from the text of the Final Rule. The Comments referenced below can be found on the Commission’s eLibrary system (http://www.ferc.gov/docs-filing/elibrary.asp) or attached to this submittal to OMB (at http://www.reginfo.gov/public/do/PRAMain).
On September 15, 2011, the Commission issued a Notice of Proposed Rulemaking (NOPR) proposing to approve Reliability Standard PRC-023-2.21 In the NOPR, the Commission proposed to approve Reliability Standard PRC-023-2. The Commission indicated that the Version 2 standard and new Rule of Procedure 1700 adequately address the directed modifications set forth in Order No. 733. The Commission also proposed to accept the Attachment B criteria for identifying sub-200 kV facilities to which the Reliability Standard applies.22 Finally, the Commission proposed to approve the implementation plan, Violation Risk Factors, and Violation Severity levels.
In addition, the NOPR set forth certain questions regarding the Attachment B criteria.23 Specifically, the Commission proposed the following questions to be addressed in the report regarding the application of Attachment B criteria NERC intends to file by February 17, 2013:
Whether the power system assessment proposed in criterion B4 includes the critical system conditions utilized under Reliability Standard TPL-003-0 Requirement R1.3.2;24
Whether applicable entities evaluate relay loadability under the B4 criterion consistent with Requirement R1 which requires, in part, that they “evaluate relay loadability at 0.85 per unit voltage and a power factor angle of 30 degrees” in addition to applicable current data;25
What “technical studies or assessments” will be used by planning coordinators to identify critical facilities under Criterion B5;26 and
Whether Attachment B is sufficiently comprehensive to capture all circuits in a planning coordinator’s area that could have an operational impact on the reliability of the bulk electric system.27
Pursuant to section 215(d)(2) of the FPA, the Commission approves Reliability Standard PRC-023-2, including the Violation Risk Factors and Violation Severity Levels, and implementation plan. The Reliability Standard meets the directives outlined in Order No. 733, and further contributes to the reliability of the Bulk-Power System by requiring load-responsive phase protection relay settings that will provide essential facility protection for faults while not limiting transmission loadability or interfering with system operators’ ability to protect system reliability. In addition, the Reliability Standard provides for the consistent identification of operationally critical circuits operated below 200 kV that must comply with the Requirements of the Standard. Accordingly, we find that the Reliability Standard is just, reasonable, not unduly discriminatory or preferential, and in the public interest.
Also, pursuant to section 215(f) of the FPA, the Commission approves NERC Rule of Procedure Section 1700 – Challenges to Determinations as just, reasonable, not unduly discriminatory or preferential, in the public interest, and satisfying the requirements of section 215(c) of the FPA.28 Rule of Procedure Section 1700 addresses the Order No. 733 directive for a mechanism by which a registered entity can challenge a determination by a planning coordinator made pursuant to Reliability Standard PRC-023-2.
NERC indicates in its comments that it is in the process of applying the test set forth in Attachment B of Reliability Standard PRC-023-2 to a representative sample of utilities from each of the three Interconnections and will file the results of these tests in a report on or before February 17, 2013. We adopt the NOPR proposal and direct NERC to address in the report several specific questions regarding the implementation of the applicability criteria set forth in Attachment B, as discussed below.
Further, commenters raise a number of concerns regarding the specific substantive Requirements of the Reliability Standard, the Standard’s Attachment B, and the violation risk factor designations. These commenter concerns are discussed below.
Requirement 1 of PRC-023-2 provides that applicable entities must use one of the identified criteria (Requirement R1, criteria 1 through 13) for any specific circuit terminal to prevent its phase protective relay settings from limiting transmission system loadability while maintaining reliable protection of the [bulk electric system] for all fault conditions. Requirement R1.13 provides that “[w]here other situations present practical limitations on circuit capability, set the phase protection relays so they do not operate at or below 115% of such limitations.”
MISO contends that over-reliance on criterion R1.13 would adversely impact operations, reliability, flexibility, and transmission congestion costs, and lead to unnecessary transmission expansion in the future to comply with transmission planning standards. To avoid this result, MISO requests that the Commission clarify the applicability of the standard by narrowing the scope of the protection systems covered by the Standard under Attachment A. In particular, MISO requests the Commission clarify that the following protection systems are excluded from the standard: (a) differential current relays and negative sequence relays; (b) supervisory elements with unanimous consent logic; (c) redundant voting protective relay schemes; and (d) switch-on-to-fault protective relay schemes. We address MISO’s request below.
MISO requests that we clarify that differential current relay elements and negative sequence relay elements should not be covered by the standard “as they would not trip with or without time delay on load current.”29 MISO argues that the exclusion of these specific relay elements from the proposed standard “would be consistent with the purpose and intent of the standard and would prevent an inappropriate and unnecessary expansion of the standard’s applicability.”30
We grant MISO’s request for clarification in part. As noted by MISO, differential current relay elements and negative sequence relay elements, by their nature, are not load responsive. As the Commission noted previously, the exclusion of a protection system from Reliability Standard PRC-023 appears to be unnecessary if the system is not load-responsive.31 Therefore, we grant MISO’s request for clarification to the extent that non-load responsive relays are not covered by Reliability Standard PRC-023-2, however we decline to direct NERC to include the assets in the exclusion list of Section 3 of Attachment A as the exclusion list should be limited to protection systems that would otherwise be subject to the Standard.
In Order No. 733, the Commission directed NERC to include supervisory relay elements on the list of relays and protection systems that are specifically subject to the PRC-023 Reliability Standard.32 In Order No. 733-B, the Commission clarified that its directive regarding the applicability of the Reliability Standard to supervisory relays does not foreclose the development of an approach tailored to eliminate application of the standard to some supervisory relays but not to others, where technically justified.33
In response to the directive, NERC modified Attachment A of Reliability Standard PRC-023-2, which identifies types of protection systems that are subject to, and others that are excluded from, the standard. In part, Attachment A provides that “this standard includes any protective functions which could trip with or without time delay, on load current, including but not limited to … 1.6. Phase overcurrent supervisory elements (i.e., phase fault detectors) associated with current-based, communication-assisted schemes … where the scheme is capable of tripping for loss of communications.” In the March 18 Petition, NERC explained that section 1.6, while addressing a subset of supervisory relays, is equally effective and efficient in addressing the Commission’s reliability concern. According to NERC, including all supervisory relays would have unintended negative impacts on system reliability by impacting the dependability and security of certain protection systems.34 NERC explains that supervisory overcurrent elements used as fault detectors “by themselves cannot trip on load current, with or without time delay. Since the trip logic requires assertion of the fault detector and the supervised protective function (which already is required to meet the loadability requirements), the overall protective function will meet the loadability requirement.”35
Comments
In its comments, MISO raises a concern that an interpretation of the term “phase overcurrent supervisory elements” in section 1.6 of Attachment A that includes elements in a unanimous consent scheme could lead to unnecessary facility limit reductions.36 MISO asks the Commission to clarify that it is acceptable to consider “unanimous consent” logic when evaluating transmission relay loadability. According to MISO, “[i]f a relay scheme contains multiple relay elements and requires ’unanimous consent’ among two or more of the relay elements in order to initiate a tripping action [of a circuit breaker], transmission relay loadability should be based solely on the relay element that is least sensitive to load so long as the relay elements could never initiate a tripping action without the operation of the relay element least sensitive to load.”37
Commission Determination
Giving due weight to NERC’s technical expertise on this issue, we approve NERC’s modification to Attachment A and find that NERC has developed an equally efficient and effective approach to addressing the Order No. 733 directive regarding supervisory relays. NERC’s proposal identifies a subset of supervisory relay elements, consistent with the Commission’s clarification in Order No. 733-B.
We deny MISO’s request for clarification. There are various types of protection schemes. MISO describes a specific protection scheme that uses unanimous consent logic and asks whether elements of the scheme are subject to Reliability Standard PRC-023-2. This is a fact intensive inquiry, and we will not rule on this matter based on the information provided in MISO’s comments. If MISO seeks further clarification of this issue, it should pursue the matter with NERC. The Commission will not make a determination on MISO’s specific scenario without a complete record and without it going through NERC’s Reliability Standards development process or interpretation process.
MISO requests that we clarify how entities should handle certain redundant voting protective relay schemes.38 MISO explains that, in a redundant voting protective relay scheme for a transmission facility, there are three protective relay schemes and only two of the three must operate to initiate tripping. MISO argues that the most load sensitive of these three relay schemes should be exempt from the standard, “so long as the most load sensitive of the three protective relay scheme can never initiate a tripping action on its own with[out] a tripping output from one of the other two protective relay schemes.”39
We decline to grant MISO’s request on this issue. MISO’s limited comments on this issue do not provide adequate information or technical support for its request. Without adequate support, the Commission cannot respond to MISO’s request.
MISO requests that the Commission clarify that a switch-on-to-fault protective relay scheme, which is specifically included in section 1.3 of Attachment A, may be excluded from the requirements of the Reliability Standard if it meets each of three stated conditions presented by MISO.40
Currently effective Reliability Standard PRC-023 explicitly addresses switch-on-to-fault protective relay schemes. Switch-on-to-fault schemes are protection systems designed to trip a transmission line breaker when the breaker is closed into a fault. Because the current fault detectors for these systems must be set low enough to detect “zero-voltage” faults, i.e., close-in, three-phase faults, these systems may be susceptible to operate on load.41 We note that the System Protection and Control Task Force acknowledged, with regard to switch-on-to-fault schemes “…a concern, based on actual events which have occurred in connection with blackouts, for the undesired operation of [switch-on-to-fault] schemes when a breaker is closed into a line.”42 Because the relays applied in switch-on-to-fault schemes are load-responsive, the Commission agreed with the ERO’s technical decision to make such relays subject to the requirements of PRC-023. As noted above, MISO proposed a set of conditions that would remove an otherwise load-responsive relay from the requirements of Reliability Standard PRC-023. MISO has not, however, provided any explanation or technical support for its proposed conditions. Therefore, we decline to grant the requested clarification.
Requirement R3 of PRC-023-2 requires a transmission owner, generator owner and/or distribution provider to obtain the agreement of the planning coordinator, transmission operator, and reliability coordinator for a calculated circuit capacity with the practical limitations described in Requirement R1, criteria 6, 7, 8, 9, 12, or 13.
MISO requests that the Commission clarify that Requirement R3 was not intended to create an obligation of the planning coordinator, transmission operator and reliability coordinator to independently verify or approve the calculated circuit capability provided by the transmission owner, generation owner or distribution provider.43 MISO argues that this obligation to obtain the agreement could impute an obligation on the planning coordinator, transmission operator and/or reliability coordinator to evaluate the calculated circuit capability without providing corresponding criteria that should be applied in the evaluation.44 MISO also requests that the Commission provide guidance on how such entities should resolve disputes over calculated circuit capabilities.
We deny MISO’s request for clarification. The Commission addressed MISO’s concern in Order No. 733.45 Specifically, in the Order No. 733 rulemaking, commenters argued that the use of the term “agreement” in PRC-023-1 simply meant that “the entity calculating the circuit capability is required to provide the circuit capability to the relevant functional entities” and that “planning coordinators, transmission operators, and reliability coordinators must simply agree that they will use the circuit capability provided by the transmission owner, generator owner, or distribution owner.”46 The concerns raised at that time mirror the concerns raised by MISO; commenters indicated that the applicable parties did not want to be “responsible for reviewing and approving the calculated circuit capabilities under Requirement R[3].”47
The Commission rejected the commenters’ arguments in Order No. 733, finding that the language “shall obtain the agreement” requires that “the entity calculating the circuit capability must reach an understanding with the relevant functional entity that the calculated circuit capability is capable of achieving the reliability goal of PRC-023-1.”48 In addition, the Commission clarified that since the Standard is “intended to ensure that protective relay settings do not limit transmission loadability or interfere with system operators’ ability to take remedial action to protect system reliability, and to ensure that relays reliably detect all fault conditions and protect the electrical network from these faults,” the agreement required under Requirement R3 should “center around achieving these purposes.”49 Having adequately addressed this matter in Order No. 733, it is unnecessary to elaborate further in response to MISO and, accordingly, we deny MISO’s request on this issue.
Further, to the extent that a dispute arises between responsible entities over the determination of a calculated circuit capability under Requirement R3, nothing precludes the responsible entities from raising the dispute with the applicable Regional Entity.
Requirement R6 of the Reliability Standard requires planning coordinators to conduct an assessment applying the criteria in Attachment B to determine a list of circuits subject to PRC-023-2 Requirements R1 through R5. Under Attachment B, the planning coordinator is required to evaluate “[t]ransmission lines operated below 100 kV and transformers with low voltage terminals connected below 100 kV that are part of the [bulk electric system].”
MISO requests clarification regarding the application of Requirement R6 to sub-100 kV facilities.50 Specifically, MISO requests clarification “with regard to what final and FERC-approved process is used by the Regional Entities to identify sub-100 kV facilities ‘critical to the reliability of the bulk electric system.’”51 MISO further requests clarification on how planning coordinators will be provided access to the list of such sub-100 kV facilities, and, finally, MISO requests clarification whether the use of such a list of sub-100 kV facilities is adequate to demonstrate compliance with Requirement R6.
With regard to MISO’s request concerning the identification of sub-100 kV facilities, we note that bulk electric system facilities are currently identified through the application of NERC’s definition of bulk electric system and NERC’s registration process, as applied by the Regional Entities.52 Regional Entities should inform planning coordinators of such sub-100kV facilities that already may have been identified so that the planning coordinator is able to fulfill its responsibilities pursuant to Requirement R6.
We deny MISO’s request for clarification “that the use of such a list as/if provided by the Regional Entities is adequate to demonstrate compliance with a requirement to evaluate ‘Transmission lines operated below 100 kV and transformers with low voltage terminals connected below 100 kV that are part of the [bulk electric system].’”53 The identification of facilities is only the first step in the process of determining whether the Standard applies. Once a planning coordinator has been provided with a list of sub-100 kV facilities that are part of the bulk electric system, if any, it must apply the criteria in Attachment B to determine whether Requirements R1 through R5 of Reliability Standard PRC-023-2 will apply to the individual facilities.
Attachment B specifies which circuits must comply with Requirements R1 through R5. Criterion B4 addresses circuits that are identified through a specified sequence of power flow analyses performed by the planning coordinator, which simulate double contingencies without manual adjustments between the contingencies.
IS0-NE requests that the Commission direct the ERO to remove criterion B4 of Attachment B from PRC-023-2.54 ISO-NE argues: (1) that such a criterion does not accurately recognize how the bulk electric system is operated; (2) that the system is neither planned nor operated to withstand two overlapping outages without intervening operator action; and (3) that such testing may result in unsolved cases, or voltages well below criteria.55 As an example, ISO-NE cites a system designed to bring on fast start generation before the second contingency. ISO-NE argues that testing under that scenario without the fast start generation removes transmission paths into an area, thus increasing current flows on the remaining circuits and increasing reactive losses, resulting in lower voltages. In addition, ISO-NE states that unsolved cases have no flows to evaluate and therefore cannot be analyzed as required under criterion B4, and that solved cases with below-criteria voltage and excessive currents are unrealistic. ISO-NE concludes that such simulations may misidentify system conditions as severe cases when in reality they are not, thwarting the purpose of the testing.
ISO-NE also asserts that criterion B4 provides no guidance on how the planning coordinator should dispatch the system in a model that tests overlapping contingencies, potentially resulting in different base assumptions used by the various planning coordinators.
The Commission recognizes that concerns exist regarding the application of Attachment B. As discussed below, NERC will be providing a summary of the base cases used in applying the Attachment B criteria and an assessment of how the base cases used for the analysis relate to TPL-003-0, Requirement R1.3.2 in response to our Order No. 733 directive. In the NOPR, the Commission expressed concern that criterion B4 of Attachment B is silent as to the rigor of the simulations other than requiring planning coordinators to use their engineering judgment.56 NERC’s additional information regarding the base cases used in applying the Attachment B criteria will allow the Commission and other interested parties to evaluate whether further modifications to Attachment B may be warranted. Accordingly, we deny ISO-NE’s request on this issue and will not direct the ERO to develop modifications to Attachment B at this time.
Therefore, we decline to direct NERC to remove criterion B4 from PRC-023-2 at this time.
As noted above, NERC has proposed a “high” violation risk factor for Requirement R6 of Reliability Standard PRC-023-2.
MISO requests that the Commission reject the assignment of a high violation risk factor to Requirement 6, arguing: (1) that a high violation risk factor implies there is a direct correlation between instability, uncontrolled separation and cascading outages and the maintenance of a list of sub-200 kV circuits to which the planning coordinator believes the requirements of the standard applies; (2) that there is no such direct correlation, as evidenced by the fact that NERC has created and the Commission is proposing to accept a process by which entities can dispute the inclusion of circuits on the planning coordinator’s list; and (3) that appearance on or absence from the list in itself will not cause or prevent instability, uncontrolled separation and cascading outages; some other event or Reliability Standards violation (i.e., operating above System Operating Limits) would have to occur to trigger any impact to reliability.57
In Order No. 733, we directed NERC to assign a “high” violation risk factor to Requirement R3 of Reliability Standard PRC-023-1.58 The Requirement at issue is renumbered Requirement R6 in Reliability Standard PRC-023-2. NERC’s assignment of a “high” violation risk factor to Requirement R6 is therefore consistent with our prior directive.
MISO’s request is an untimely argument against an explicit directive from Order No. 733. Therefore, we reject MISO’s request for a rejection of the assignment of a “high” violation risk factor to Requirement R6.
In Order No. 733, the Commission directed NERC to specify the test that planning coordinators will use to determine whether a sub-200 kV facility is critical to the reliability of the Bulk-Power System.59 In addition, the Commission directed NERC to file both the test and the results of applying the test to a representative sample of utilities from each of the three interconnections.60
Attachment B to Reliability Standard PRC-023-2 represents the test filed in response to the above described directive. The NOPR set forth questions intended to assist the Commission’s understanding regarding the implementation of the test. Specifically, the Commission proposed that NERC address the following questions regarding the application of Attachment B criteria in the report:
Whether the power system assessment proposed in criterion B4 includes the critical system conditions utilized under Reliability Standard TPL-003-0 Requirement R1.3.2;61
Whether applicable entities evaluate relay loadability under the B4 criterion consistent with Requirement R1 which requires, in part, that they “evaluate relay loadability at 0.85 per unit voltage and a power factor angle of 30 degrees” in addition to applicable current data;62
What “technical studies or assessments” will be used by planning coordinators to identify critical facilities under criterion B5;63 and
Whether Attachment B is sufficiently comprehensive to capture all circuits in a planning coordinator’s area that could have an operational impact on the reliability of the bulk electric system.64
In its November 21, 2011 Comments, NERC, with APPA concurring, responds to the questions proposed for inclusion in the report NERC intends to file by February 17, 2013.
With regard to the question whether the power system assessment proposed in criterion B4 includes the critical system conditions utilized under Reliability Standard TPL-003-0, Requirement R1.3.2, NERC states that the goal of the power flow analysis is to have planning coordinators utilize the base cases that are used for demonstrating compliance with the TPL Reliability Standards.65 NERC proposes to include in its report a summary of the base cases used in applying the Attachment B criteria and an assessment of how the base cases used for the analysis relate to TPL-003-0, Requirement R1.3.2.66
In response to the proposed question whether applicable entities evaluate relay loadability under the B4 criterion consistent with Requirement R1 which requires, in part, that they “evaluate relay loadability at 0.85 per unit voltage and a power factor angle of 30 degrees” in addition to applicable current data, NERC states that, although the measures in criterion B4 of Attachment B do not explicitly reference voltage and power factor, the measures were derived from Requirement R1 of PRC-023-2; specifically, 0.85 per unit voltage and 30 degree power factor angle.67 NERC states, therefore, that it is not necessary for it to include in the report a comparison of the results obtained using criterion B4 to the results that would be achieved based on assumptions consistent with Requirement R1.
Regarding the question proposed in the NOPR concerning what “technical studies or assessments” will be used by planning coordinators to identify facilities under criterion B5, NERC states that Attachment B does not identify a specific list to avoid unnecessarily limiting the technical studies or assessments a planning coordinator may use to identify circuits.68 NERC proposes to include a discussion in the report on the types of studies that planning coordinators may use.69
Finally, in response to the last proposed question of whether Attachment B is sufficiently comprehensive to capture all circuits in a planning coordinator’s area that could have an operational impact on the reliability of the bulk electric system, NERC proposes to include in the report an assessment that demonstrates whether Attachment B is comprehensive enough to capture all circuits that could have an operational impact on the reliability of the bulk electric system in the context of transmission relay loadabilty.70
As discussed above, NERC reports that it is in the process of applying the test set forth in Attachment B to a representative sample of utilities from each of the three Interconnections and will file the results of these tests in a report on or before February, 2013. In light of the discussion in NERC’s November 21 Comments,71 we accept NERC’s proposed plan to respond to the following three questions and direct NERC to include in the report:
A summary of the base cases used in applying the Attachment B criteria and an assessment of how the base cases used for the analysis relate to TPL-003-0, Requirement R1.3.2;
A discussion of the types of studies that planning coordinators may use to identify circuits under Attachment B; and
An assessment that demonstrates whether Attachment B is comprehensive enough to capture all circuits that could have an operational impact on the reliability of the bulk electric system in the context of transmission relay loadabilty.
However, we are not persuaded by NERC’s statement that it is not necessary for NERC to include in the report a comparison of the results obtained using criterion B4 to the results that would be achieved based on assumptions consistent with Requirement R1. The 0.85 per unit and 30 degrees power factor criteria in Requirement R1 is based on system conditions, voltage, current, and angle, observed prior to the cascading stage of the blackout. Although NERC states that criterion B4 was derived from these system criteria,72 the Commission is concerned that testing, which does not, at a minimum, compare whether criteria that do not consider voltage or angle affect the appropriate identification of applicable facilities, is not responsive to ensuring the reliability objective of the critical facilities test or the reliability objective of PRC-023. For these reasons, we direct NERC to evaluate, in the report, relay loadability under the B4 criterion consistent with Requirement R1, which requires, in part, that NERC “evaluate relay loadability at 0.85 per unit voltage and a power factor angle of 30 degrees” in addition to applicable current data.
In its petition, NERC submitted new Rules of Procedure Section 1700—Challenges to Determinations, which sets out the procedure for a registered entity to challenge a determination by a planning coordinator under Reliability Standard PRC-023-2.
In the NOPR, we proposed to approve NERC Rules of Procedure Section 1700, specifically proposed Rule 1702, finding that it addresses the Order No. 733 directives that NERC establish a mechanism for registered entities to challenge criticality determinations made by a planning coordinator.
No comments were filed concerning proposed Rules of Procedure Section 1700—Challenges to Determinations.
NERC’s proposal is responsive to the Commission’s directive in Order No. 733. Accordingly, we adopt our NOPR proposal and we approve, pursuant to section 215(f) of the FPA, NERC Rule of Procedure Section 1700 – Challenges to Determinations as just, reasonable, not unduly discriminatory or preferential, in the public interest, and satisfying the requirements of section 215(c) of the FPA.
9. EXPLAIN ANY PAYMENT OR GIFTS TO RESPONDENTS
No payments or gifts have been made to respondents.
10. DESCRIBE ANY ASSURANCE OF CONFIDENTIALITY PROVIDED TO RESPONDENTS
The Commission generally does not consider the data filed to be confidential.
11. PROVIDE ADDITIONAL JUSTIFICATION FOR ANY QUESTIONS OF A SENSITIVE NATURE THAT ARE CONSIDERED PRIVATE.
There are no questions of a sensitive nature that are considered private.
12. ESTIMATED BURDEN OF COLLECTION OF INFORMATION
In the final rule approving currently effective Reliability Standard PRC-023-1 (Order 733), the Commission aggregated the burden hours in terms of the number of hours per terminal that would have to be reviewed by an engineer for compliance with the requirements. The resulting hours were aggregated into the recordkeeping category, even though some of the requirements in the standard more closely fall under “reporting”.
The table below contains the burden estimate from this Final Rule, followed by a table showing how the current burden inventory for this collection is being changed. The Final Rule estimate below regarding the number of respondents is based on the NERC compliance registry as of January 26, 2012.
Changes in the burden due to the Final Rule:73
FERC-725G Data Collection |
Number of Respondents Annually (1) |
Number of Responses Per Respondent (2) |
Average Burden Hours Per Response (3) |
Total Annual Hours (1x2x3) |
|
R1 criterion 1.10: TOs, GOs, and DPs must analyze and document criterion 1.10 compliance |
660 |
1 |
Analysis for compliance documents |
8 |
5,280 |
Record Retention |
2 |
1,320 |
|||
R2: TOs, GOs, and DPs must perform analysis and retain evidence of compliance |
660 |
1 |
Analysis for compliance documents |
8 |
5,280 |
Record Retention |
2 |
1,320 |
|||
R4 and R5: TOs, GOs, and DPs must distribute updated lists and retain evidence that lists were distributed |
660 |
1 |
Reporting (dist. of list) |
10 |
6,600 |
Record Retention |
10 |
6,600 |
|||
R6: PC must perform assessment, distribute list of circuits and retain evidence of testing and distribution74 |
81 |
1 |
Reporting (assessment and dist. of list) |
20 |
1,620 |
Record Retention |
10 |
810 |
|||
Total |
741 |
|
28,830 |
||
Key: TO = Transmission owner; GO = Generation owner; DP = Distribution provider; and PC = Planning coordinator
FERC-725G |
Total Request |
Previously Approved |
Change due to Adjustment in Estimate |
Change Due to Agency Discretion |
Annual Number of Responses |
741 |
678 |
63 |
- |
Annual Time Burden (Hr) |
399,549 |
339,200 |
31,519 |
28,830 |
Annual Cost Burden ($) |
- |
- |
- |
- |
13. ESTIMATE OF THE TOTAL ANNUAL COST BURDEN TO RESPONDENTS
The Commission’s cost estimate for the current inventory is based on an estimated hourly rate for engineers of $120/hr. The estimated cost in the current inventory is as follows:
Number of line terminals to be reviewed: 53,000
Number of hours per terminal: 6.4
Hourly rate for review by engineers: $120
Total Cost for review = (terminals to be reviewed x hours per terminal) x hourly rate for review by engineers = (53,000 x 6.4) x ($120/hour) = $40,704,00075
In this Final Rule the Commission is updating the number of applicable entities based on a recent review of the NERC compliance registry. The number of entities added to the inventory is 63. Applying the current inventory hours per response (500.295 hours) to the 63 new entities yields a total of 31,519 hours (63 times 500.295 = 31,519 (rounded)). At $120/hour, the total additional cost of adding these entities (related to the agency adjustment) is $3,782,280.
The additional costs per entity (related to the program change) added by the final rule are as follows:
Reporting: 18,780 hours @ $120/hr = $2,253,600
Record Retention: 10,050 hours @ $28/hr = $281,400
Total cost = $2,535,000 ($2,253,600 + $281,000)
The proposed total cost for FERC-725G is $47,021,280 ($40,704,000 + $3,782,280 + $2,535,000).
14. ESTIMATED ANNUALIZED COST TO FEDERAL GOVERNMENT
Reliability Standard PRC-023-002 does not require any information to be filed with the Commission. Therefore, the only costs to the Federal Government are those associated with maintaining proper clearance from OMB to continue with the collection. The cost for this activity on an annual basis is estimated at $1,588.76
15. REASONS FOR CHANGES IN BURDEN INCLUDING THE NEED FOR ANY INCREASE
The modifications to the existing Reliability Standard PRC-023-1, and the corresponding burden increase, are a result of two things: one, FERC directives given to NERC when FERC approved the existing Reliability Standard; and two, an increase of 63 in the estimated number of entities that must comply with this collection. The estimated cost to comply with the information collection requirements is also increasing due to the increase in the burden hours (more fully discussed in question 13).
The FERC directives led NERC to propose version two of Reliability Standard PRC-023 which makes modifications and improvements to the existing standard. The revised standard includes new and modified requirements that are estimated to increase the burden on applicable entities by a total of 28,830 hours (program change), or approximately 39 hours per entity (for each of the 741 entities). NERC states that the proposed Reliability Standard requires transmission owners, generator owners, and distribution providers to verify relay loadability using methods that achieve “the reliability goal of this Standard in an effective and efficient manner familiar to the responsible entities.”77 The Standard also applies to out-of-step blocking systems as well as to load-responsive phase protections systems. NERC specifically identifies the benefits of the Reliability Standard PRC-023-2, as including (a) consistent identification of operationally critical circuits operated below 200 kV that must comply with the Requirements of the Standard, and (b) providing transmission operators, planning coordinators, reliability coordinators, and the ERO with more information regarding the criteria selected by entities for verifying relay loadability.78
The increase in the number of applicable entities is thought to be due to changes in the number of entities contained in the NERC Compliance Registry. The previous version of the Reliability was based on the NERC compliance Registry as of March 3, 2009. The current estimate is based on the NERC compliance registry as of January 26, 2011.
16. TIME SCHEDULE FOR THE PUBLICATION OF DATA
Data filed in response to the subject Reliability Standard is not published.
17. DISPLAY OF THE EXPIRATION DATE
It is not appropriate to display the expiration date for OMB approval of the information collected. The information will not be collected on a standard, preprinted form which would avail itself to that display.
18. EXCEPTIONS TO THE CERTIFICATION STATEMENT
The Commission does not use the data collected under the Reliability Standard for statistical purposes, as is described in the certification submitted with this collection to OMB for review.
1 The Energy Policy Act of 2005, Pub. L. No 109-58, Title XII, Subtitle A, 119 Stat. 594, 941 (2005), codified at 16 U.S.C. 824o (2000).
2 A reliability standard defines obligations or requirements of utilities and other entities that operate, plan and use the bulk power system in North America. Meeting these requirements helps to ensure the reliable planning and operation of the bulk power system. Each NERC Reliability Standard details the purpose of the standard, the entities that must comply, and the specific actions that constitute compliance and how the standard will be measured.
3 The bulk-power system consists of the power plants, transmission lines and substations, and related equipment and controls, that generate and move electricity in bulk to points from which local electric companies distribute the electricity to customers.
4 A ‘fault” is defined in the NERC Glossary of Terms used in Reliability Standards as “[a]n event occurring on an electric system such as a short circuit, broken wire, or an intermittent connection.”
5 The “reach” of the relay refers to the length of the transmission line for which the relay is set to protect and is generally used in reference to impedance relays.
6 “Coordination of protection” is defined by the Institute of Electrical and Electronics Engineers (IEEE) Std. C37.113-1999, “IEEE Guide for Protective Relay Applications to Transmission Lines” as “[t]he process of choosing settings or time delay characteristics of protective devices, such that operation of the devices will occur in a specified order to minimize customer service interruption and power system isolation due to a power system disturbance.”
7 Transmission Relay Loadability Reliability Standard, Order No. 733, 130 FERC ¶ 61,221 (2010), order on reh’g and clarification, Order No. 733-A, 134 FERC ¶ 61,127 (2011); clarified, Order No. 733-B, 136FERC61,185, (2011). Order No. 733-B issued concurrently with the Notice of Proposed Rulemaking.
8 NERC Petition at 42. The NERC petition is available on the Commission’s eLibrary document retrieval system at http://elibrary.ferc.gov/idmws/docket_search.asp, and searching on docket number RM11-16.
9 NERC Petition at 5.
10 Reliability Standard PRC-023-2, Section A.3 (Purpose).
11 See 16 U.S.C. 824o(d)(5) (2006).
12 U.S.-Canada Power System Outage Task Force, Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations, (April 2004) (Final Blackout Report), available at http://www.ferc.gov/industries/electric/indus-act/reliability/blackout.asp.
13 Id. at 80.
14 Id. at 73.
15 Id. at 80.
16 Id.
17 Id.
18 Id. at 81.
19 To be included in the compliance registry, the ERO determines whether a specific small entity has a material impact on the Bulk-Power System. If these small entities should have such an impact then their compliance is justifiable as necessary for Bulk-Power System reliability.
20 76 Fed. Reg. 58,424 (2011).
21 Transmission Relay Loadability Reliability Standard, 136 FERC ¶ 61,187 (September 15, 2011) (September 15 NOPR).
22 Id. P 38.
23 Id. PP 41-45.
24 Id. P. 43.
25 Id.
26 Id. P 44.
27 Id. P 45.
28 Section 215(f) of the FPA provides, inter alia, that “[a] proposed rule or proposed rule change shall take effect upon a finding by the Commission, after notice and opportunity for comment, that the change is just, reasonable, not unduly discriminatory or preferential, is in the public interest and satisfies the requirements of subsection (c).”
29 MISO Comments at 3.
30 Id.
31 Transmission Relay Loadability Reliability Standard, 127 FERC ¶ 61,175, at n. 98 (2009).
32 Order No. 733 at P 264.
33 Order No. 733-B at P 39.
34 March 18 Petition at 25-28.
35 Id. at 27.
36 MISO Comments at 4.
37 Id.
38 MISO Comments at 5.
39 Id.
40 Id. at 5-6.
41 Order No. 733 at n. 187.
42 NERC Planning Committee, System Protection and Control Task Force, “Switch-on-to-Fault Schemes in the Context of Line Relay Loadability,” at 2 (June 7, 2006).
43 Id. at 6-7.
44 Id.
45 Order No. 733 at P 229.
46 Id. P 228.
47 Id.
48 Id. P 229.
49 Id.
50 MISO Comments at 8.
51 Id.
52 Mandatory Reliability Standards for the Bulk-Power System, Order No. 693 FERC Stats. & Regs. ¶ 31,242, at P 77 (2007).
53 MISO Comments at 8.
54 ISO-NE Comments at 4.
55 Id. at 2-3.
56 September 15 NOPR at P 43.
57 MISO Comments at 7-8.
58 Order No. 733 at P 297.
59 Id. P 69.
60 Id.
61 Id. P 43.
62 Id.
63 Id. P 44.
64 Id. P 45.
65 NERC Comments at 3.
66 Id.
67 Id.
68 Id. at 4-5.
69 Id. at 5.
70 Id.
71 Id. at 12-19.
72 Id. at 3.
73 Some figures in this table have been rounded or truncated as necessary.
74 This applies to the portion of R6 that deals with testing for sub-100 kV facilities as described in the text. In addition it includes burden hours associated with adding Regional Entities to the list of entities to receive a list of circuits from the planning coordinator.
75 This cost was reported in ROCIS previously. In this submission FERC is removing this cost from ROCIS because it is associated with burden hour costs. The non-burden hour cost is $0 for this submission. The total cost, including burden hour wage costs, will continue to be estimated in FERC supporting statements.
76 This figure is based off of an estimate that it requires approximately 40 hours of FERC staff time to prepare, submit, and review the necessary documents related to obtaining OMB clearance to use this information collection.
77 NERC Petition at 42.
78 NERC Petition at 5.
| File Type | application/msword |
| Author | Michael Miller |
| Last Modified By | rnped32 |
| File Modified | 2012-03-26 |
| File Created | 2012-03-26 |