b_RM10-15_draft_for_final_rule_Supporting_Statement[1]

Docket No. RM10-15-000, Final Rule, FERC-725A Issued March 17, 2011 19

RIN 1902-AE17

Supporting Statement for

FERC‑725A, Mandatory Reliability Standards for the Bulk-Power System

Final Rule In Docket No. RM10-15-000; RIN 1902-AE17;

OMB Control No. 1902-0244

The Federal Energy Regulatory Commission (Commission) (FERC) requests Office of Management and Budget (OMB) review and approval of FERC‑725A, Mandatory Reliability Standards for the Bulk Power System as contained in the Final Rule in Docket No. RM10-15-000 “Revision to Electric Reliability Organization Definition of Bulk Electric System” (issued 3/17/2011).¹ FERC-725A (Control No. 1902-0244) is an existing Commission data collection, contained in 18 Code of Federal Regulations, Part 40 and is currently approved through February, 28, 2014.

In the final rule FERC approves three new Interconnection Reliability Operations and Coordination Reliability Standards and seven revised Reliability Standards related to Emergency Preparedness and Operations, Interconnection Reliability Operations and Coordination, and Transmission Operations. The Commission also approves the addition of two new terms to the NERC Glossary of Terms.

The three new Reliability Standards approved are designated as IRO-008-1 (Reliability Coordinator Operational Analyses and Real-time Assessments), IRO-009-1 (Reliability Coordinator Actions to Operate within IROLs), and IRO-010-1a² (Reliability Coordinator Data Specification and Collection). In preparing these new Reliability Standards, the standards drafting team determined that it was necessary to retire or modify certain requirements from several existing standards. Accordingly, FERC approves of revised Reliability Standards EOP-001-1,³ IRO-002-2, IRO-004-2, IRO-005-3, and TOP-006-2.

Background

On March 16, 2007, the Commission issued Order No. 693, approving 83 of the 107 initial Reliability Standards filed by NERC, including the existing IRO Reliability Standards.⁴ Under section 215(d)(5) of the FPA, the Commission directed NERC to develop modifications to the IRO Reliability Standards to address certain issues identified by the Commission.

With respect to IRO-001-1, the Commission directed the ERO to develop modifications to eliminate the regional reliability organization as an applicable entity.⁵ The Commission also directed the ERO to modify IRO-002-1 to require a minimum set of capabilities that must be made available to the reliability coordinator to ensure that a reliability coordinator has the capabilities it needs to perform its functions.⁶ With respect to IRO-003-2, the Commission directed the ERO to develop a modification to create criteria to define the term “critical facilities” in a reliability coordinator’s area and its adjacent systems.⁷ The Commission also directed the ERO to modify IRO-004-1 to require the next-day analysis to identify control actions that can be implemented and effective within 30 minutes after a contingency. In addition, the Commission directed the ERO to consider adding Measures and Levels of Non-Compliance to Reliability Standards IRO-004-1 and IRO-005-1 that are commensurate with the magnitude, duration, frequency and causes of the violations and whether these occur during normal or contingency conditions.⁸

The Commission also directed the ERO to conduct a survey on IROL practices and actual operating experiences by requiring reliability coordinators to report any violations of IROLs, their causes, the date and time, the durations and magnitudes in which actual operations exceed IROLs to the ERO on a monthly basis for one year beginning two months after the effective date of Order No. 693.⁹ On October 31, 2008, NERC filed the results of its year-long survey with the Commission.¹⁰ On February 8, 2009, NERC supplemented those results in a second filing.¹¹

1. Justification

1. CIRCUMSTANCES THAT MAKE THE COLLECTION OF INFORMATION NECESSARY

Since 1935, the Commission has regulated certain electric utility activities under the FPA. Under FPA Sections 205 and 206, the Commission oversees the rates, terms and conditions of sales for resale of electric energy and transmission service in interstate commerce by public utilities. The Commission must ensure that those rates, terms and conditions are just and reasonable and not unduly discriminatory or preferential. One of the Commission’s continuing priorities is to promote electricity grid reliability. The Commission’s ability to promote reliability was reinforced by the passage of the Energy Policy Act of 2005, which added section 215 to the Federal Power Act. In Section 215 a Commission-certified ERO is to develop mandatory and enforceable reliability standards, which are subject to Commission review and approval.

Blackouts can have major adverse effect on an economy. A common cause of the past three major regional blackouts was violation of NERC’s then Operating Policies and Planning Standards. Reliability standards are designed to promote an electric system that maintains reliability and minimizes the risk of outages. The approved Reliability Standards are designed to prevent instability, uncontrolled separation, or cascading outages that adversely impact the reliability of the interconnection by ensuring prompt action to prevent or mitigate instances of exceeding interconnection reliability operating limits (IROL). The information collection requirements are meant to assist in fulfilling the aims of the standards.

2. HOW, BY WHOM, AND FOR WHAT PURPOSE THE INFORMATION IS TO BE USED AND THE CONSEQUENCES OF NOT COLLECTING THE INFORMATION

The Commission approves three new Reliability Standards, IRO-008-1, IRO-009-1 and IRO-010-1a governing reliability coordinator analyses, operational actions and data collection, which standards will replace parts of the currently-effective Reliability Standards EOP-001-0, IRO-002-1, IRO-004-1, IRO-005-2, TOP-003-0, TOP-005-1 and TOP-006-1 approved by the Commission in Order No. 693. Many of the reporting requirements have been approved previously by OMB under Control No. 1902-0244. The exception is the new Reliability Standard IRO-10-1a which includes two related reporting requirements.

Requirement 2 of IRO-10-1a calls for the Reliability Coordinator to provide to applicable entities¹² “specification for data and information to build and maintain models to support Real-time monitoring, Operational Planning Analyses, and Real-time Assessments of its Reliability Coordinator Area to prevent instability, uncontrolled separation, and cascading outages”. ¹³ Requirement 3 of IRO-10-1a obligates the applicable entities to provide the data and information as specified by the Reliability Coordinator(s).

Without these requirements, the Reliability Coordinator would not have the data and information “it needs to monitor and assess the operation of its Reliability Coordinator Area”. If the Reliability Coordinator cannot fulfill this responsibility the Bulk-Electric System will be at a higher risk to “instability, uncontrolled separation, or cascading outages”.¹⁴

3. DESCRIBE ANY CONSIDERATION OF THE USE OF IMPROVED TECHNOLOGY TO REDUCE BURDEN AND TECHNICAL OR LEGAL OBSTACLES TO REDUCING BURDEN.

IRO-10-1a does not require any data or information to be filed with the Commission. However, the standard does require the data specification to include a format mutually agreeable to the Reliability Coordinator and the applicable entities. This format may be electronic.

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

The Commission believes that Reliability Standards in general may cause some small entities to experience economic impact. While the Commission is mindful of the possible impact on small entities, the Commission is also concerned that Bulk-Power-System reliability not be compromised based on an unwillingness of entities, large or small, to incur reasonable expenditures necessary to preserve such reliability. As the Commission explained in Order No. 672:

A proposed Reliability Standard may take into account the size of the entity that must comply with the Reliability Standard and the cost to those entities of implementing the proposed Reliability Standard. However, the ERO should not propose a “lowest common denominator” Reliability Standard that would achieve less than excellence in operating system reliability solely to protect against reasonable expenses for supporting this vital national infrastructure. For example, a small owner or operator of the Bulk Power-System must bear the cost of complying with each Reliability Standard that applies to it.¹⁵

While the Commission cannot rule on the merits until a specific proposal has been submitted, the Commission believes that reasonable limits on applicability based on size may be an acceptable alternative to lessen the economic impact on the proposed rule on small entities. The Commission emphasizes, however, that any such limits must not weaken Bulk-Power-System reliability.

The Commission does not foresee any undue impact, due to the revised reliability standards in Docket RM10-15, on the paperwork burden for small businesses.

6. CONSEQUENCE TO FEDERAL PROGRAM IF COLLECTION WERE CONDUCTED LESS FREQUENTLY

The new reliability standards approved in the final rule are designed to “prevent instability, uncontrolled separation, or cascading outages that adversely impact the reliability of the interconnection” by ensuring the bulk-electric system is properly assessed, that the reliability coordinators have all the necessary information, and that prompt action is taken in “instances of exceeding Interconnection Reliability Operating Limits”. Without prompt and accurate response to the paperwork requirements contained in these standards the risk of “instability, uncontrolled separation, or cascading outages” is increased.¹⁶

7. EXPLAIN ANY SPECIAL CIRCUMSTANCES RELATING TO THE INFORMATION COLLECTION

There are no special circumstances relating to the information collection.

8. DESCRIBE EFFORTS TO CONSULT OUTSIDE THE AGENCY: SUMMARIZE PUBLIC COMMENTS AND THE AGENCY'S RESPONSE TO THESE COMMENTS

The ERO process to establish Reliability Standards is a collaborative process with the ERO, Regional Entities and others developing and reviewing drafts, and providing comments.¹⁷ In addition, each FERC rulemaking (both proposed and final rules) is published in the Federal Register, thereby providing 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 of Proposed Rulemaking in Docket RM10-15 was published in the Federal Register on November 24, 2010 and requested public comments. No comments were received directly related to the burden estimates.

The following is excerpted from the final rule and contains industry comments and the Commission’s responses.¹⁸

Continued Analysis of SOLs by Reliability Coordinators

NERC states in its comments, that the proposed IRO Reliability Standards appropriately distinguish which entity has primary responsibility for SOLs. Further, Bulk-Power System reliability practices assign responsibilities for analyzing and resolving conditions to the entities closest to it, so that the entity with the closest eye to the condition can quickly assess and resolve it. NERC asserts that it is appropriate for transmission operators to maintain primary responsibility for SOLs, and for reliability coordinators to maintain primary responsibility for IROLs. NERC also explains that, while SOLs are typically associated with the prevention of facility damage or the accelerated degradation of equipment life, only a subset of SOLs are used to analyze and monitor local area reliability and, therefore, the proposed IRO standards are silent on the reliability coordinator’s responsibility with respect to SOLs.

NERC notes in its Petition, that the proposed Reliability Standards “should not imply that the Reliability Coordinator will not look at its future operations with respect to specific SOLs.”¹⁹ NERC also states that “[t]he Reliability Coordinator retains the overall visibility of all operations within its Wide-Area view, including some SOLs, although the transmission operator is primarily responsible for actions related to SOLs.”²⁰ NERC also notes that the reliability coordinator can monitor the transmission operator’s actions to resolve SOLs and provides, as an example, that the reliability coordinator can study real-time operating trends to help determine whether an asset is trending toward a “grid-impactive SOL.”²¹

In its comments, NERC provides the results of a survey conducted in response to the NOPR in which each of the nine reliability coordinators in the Eastern Interconnection responded that, for SOLs that it monitors, the SOLs were developed in a coordinated fashion with the transmission operators in its area. The survey responses did not suggest that any transmission operator withheld important SOL information from reliability coordinators, nor did any reliability coordinator indicate that transmission operators were not willing to work with the reliability coordinators in monitoring SOLs for Bulk-Power System reliability. NERC contends that this survey demonstrates that current operating practices are effective to ensure that reliability coordinators are able to obtain sufficient information from transmission operators in order to analyze and monitor certain SOLs other than IROLs.

NERC also notes that, since the completion of the proposed IRO standards, the industry has been working to improve the clarity of Reliability Standard requirements regarding the transmission operator’s primary responsibility for SOLs through the Real-time Operations Standard Drafting Team (Project 2007-03). For example, NERC explains that the Standard Drafting Team has proposed to add a requirement to TOP-001-2 that would require each transmission operator to inform its reliability coordinator of all SOLs which, while not IROLs, have been identified by the transmission operator as supporting its local area reliability based on its assessment of its Operational Planning Analysis. NERC states that, by using tools that properly model Wide-Area conditions, the reliability coordinators are able to identify and help resolve lower-level issues that may not explicitly be included in the reliability coordinator modeling capabilities. EEI supports NERC’s comments to the NOPR and believes that the Commission should encourage the NERC reliability coordinators working group to engage these issues with NERC stakeholders, especially the NERC Planning and Operating Committees.

The Joint Commenters support the proposed primary division of responsibilities for SOLs and IROLs between reliability coordinators and transmission operators. They contend, though, that the proposed division should not be interpreted as implying that a reliability coordinator should not monitor any SOLs. The Joint Commenters further contend that it was not intended that the proposed Reliability Standards would remove all responsibility for SOLs from the reliability coordinator, but to establish a clear distinction of responsibilities and authority. The Joint Commenters state that they would not support a formal requirement that would assign primary responsibility for analyzing and resolving SOLs to a reliability coordinator since the primary responsibility is correctly assigned to the transmission operator that is most familiar with their respective operating limits and local Bulk-Power System characteristics.

Midwest ISO states that it is necessary for reliability coordinators to analyze, monitor, and coordinate some SOLs other than IROLs and that the Reliability Standards should reflect this best practice. Midwest ISO believes the Commission should encourage the efforts currently underway at NERC towards the development of Reliability Standards addressing the role of reliability coordinators with regard to analyzing SOLs, other than IROLs, that are important to the reliable operation of the Bulk-Power System.

AEP states that it generally supports the proposed Reliability Standards but that it agrees with concerns raised by the Commission that if reliability coordinators are not monitoring other SOLs, there is a potential gap in monitoring for SOLs that have the potential to become IROLs. AEP argues that performing an annual IROL identification would be insufficient because it could miss some opportunities to identify these potentially new IROLs when they could be material. AEP asserts that, at a minimum, reliability coordinators should be required to be involved in SOLs that could border two different transmission operators’ areas to ensure the activities are appropriately coordinated. AEP states that reliability coordinators and transmission operators should develop this subset of SOLs through joint analysis, or agreement. AEP requests that the Commission direct NERC to develop a modification to proposed Reliability Standards EOP-001-1, IRO-002-2, IRO-004-2, IRO-005-3, TOP-003-1, TOP-005-2, and TOP-006-2, to require reliability coordinators to work together with transmission operators in developing and monitoring SOLs that border multiple transmission operators’ areas.

Documented Methodology to Identify System Operating Limit Information

NERC asserts that, because proposed Reliability Standard IRO-008-1 requires reliability coordinators to use tools to model transmission and generation assets based on ratings provided by asset owners, it is unnecessary to impose an additional requirement that the reliability coordinator have a documented methodology for identifying the SOL information it needs because the systems and controls in place already provide the information needed by the reliability coordinators. The Joint Commenters also believe that such a methodology is unnecessary because, in its defined role, a reliability coordinator already will have access to, and be provided with, the appropriate set of SOLs from the transmission operator.

Current Practices for the Prevention and Mitigation of SOLs and IROLs and the Monitoring Capability of the Reliability Coordinator

NERC states that current practices give the reliability coordinators the ability to provide assessments of the Bulk-Power System to their transmission operators on a Wide-Area basis. NERC believes it is unnecessary to require reliability coordinators to have additional responsibility to monitor SOLs other than IROLs. NERC also notes that there are checks in place that allow the reliability coordinator to monitor SOLs that could turn into IROLs. As an example, NERC points out that IRO-010-1a requires reliability coordinators to conduct Operational Planning Analyses and Real-Time Assessments to identify any IROLs that may be exceeded.

NERC states that the electric power industry is predicated on interdependencies. NERC describes the interdependency of transmission operators and reliability coordinators as enabling the reliability coordinator both to control IROLs and flows, and to be aware of local issues, giving the reliability coordinator the ability to monitor SOLs that may become IROLs within the reliability coordinators areas. NERC further explains that it is working on Project 2007-03 – Real-Time Operations to develop proposed revisions to the TOP standards that require a transmission operator to perform Operational Planning Analyses for its transmission operator area. NERC states that Project 2007-03 is considering revisions to the Reliability Standards that would require observation of SOL limits in adjoining areas.

The Joint Commenters state that the proposed IRO Reliability Standards hold reliability coordinators to the proper assessment of information required to provide accurate assessments on a Wide-Area basis. The Joint Commenters also caution that “accurate assessments” do not equate to precise results and the Commission should refrain from mandating that reliability coordinators provide accurate assessments.

Reliability Coordinator’s Procedures for Selecting the SOLs for Evaluation by the Interchange Distribution Calculator

NERC states that reliability coordinators in the Eastern Interconnection select which SOLs to evaluate in the interchange distribution calculator based on information received from the transmission operators indicating that the transmission operator has a facility that is approaching or exceeding its SOL and/or IROL. NERC states that the interchange distribution calculator is a congestion management tool that helps the reliability coordinators deal with transmission constraints. In the survey conducted by NERC of reliability coordinators, one reliability coordinator responded that it publishes most of its information for use by any entity that may wish to use the information in its reliability assessments. Another reliability coordinator responded that it does not enter SOLs in its area into the interchange distribution calculator, but flowgates are entered into the interchange distribution calculator that may have SOLs or IROLs associated with them. Entering the flowgates allows an entity to determine if external schedules are impacting the flowgate.

Current Functional Model

NERC argues that Version 5 of the NERC Functional Model makes a clear distinction between the duties of the reliability coordinator and transmission operator with respect to SOLs and IROLs in certain task descriptions.²² Similarly, the Joint Commenters state that the latest NERC Functional Model divides reliability components and allocates them to “unique” baskets of tasks which include a fundamental reliability task to do Wide-Area analysis and another task for local analysis.

Commission Determination

As we stated in the NOPR, we believe that it is appropriate for Reliability Standards requirements to offer a clear division of responsibilities among reliability coordinators and transmission operators. The preponderance of comments to the NOPR supports Commission approval of the Reliability Standards as proposed by NERC, including the proposed division of responsibilities. For the reasons described below, we approve the division of responsibility for SOLs and IROLs among transmission operators and reliability coordinators as expressed in the proposed Reliability Standards.

NERC and others suggest that these Reliability Standards are not intended to remove all responsibility for the analysis and monitoring SOLs from the reliability coordinator. We agree. These Reliability Standards generally establish a clear distinction of primary responsibility for SOLs and IROLs between the transmission operator and reliability coordinator respectively. As NERC notes, however, the reliability coordinator will continue to have the ability and the responsibility to analyze and monitor SOLs that could turn into IROLs. For example, Requirements R5 and R6 of Reliability Standard IRO-002-2 require the reliability coordinator to monitor the important elements that could be critical to SOLs and IROLs within the reliability coordinator’s area and surrounding reliability coordinator areas. In addition, the proposed IRO Reliability Standards require the reliability coordinator to conduct Operational Planning Analyses and Real-time Assessments of its reliability coordinator area. As NERC explained, the Operational Planning Analyses look at the expected system conditions and potential reliability impacts, with a focus on any impacts that affect the Wide-Area. Although a transmission operator lacks the tools to predict the impact on the surrounding transmission operator areas due to any changes in flow between inter-area facilities, a reliability coordinator addresses these facilities in its Wide-Area modeling capabilities.

As the Commission noted in its NOPR, Reliability Standard IRO-002-2 continues to require each reliability coordinator to monitor SOLs other than IROLs both within its reliability coordinator area and in surrounding reliability coordinator areas. Specifically, under Requirement R4 of IRO-002-2, each reliability coordinator must have detailed real-time monitoring capability of its reliability coordinator area and sufficient monitoring capability of its surrounding reliability coordinator areas to ensure that potential or actual SOL or IROL violations are identified and analyzed. In addition, under Requirement R5, each reliability coordinator must monitor bulk electric system elements such as generators, transmission lines, buses, transformers and breakers that could result in SOL or IROL violations within its reliability coordinator area. Further, as the Commission noted in the NOPR, the reliability coordinator must resolve potential or actual violations of SOL ratings by implementing a local or area-wide transmission loading relief procedure under Reliability Standard IRO-006-4.1.

Nevertheless, as noted by NERC and other commenters, there exists a subset of “grid-impactive” SOLs other than IROLs that the Commission believes may warrant closer analysis by the reliability coordinator, in addition to the analysis being conducted by the transmission operator, that focuses on whether these particular “grid-impactive” SOLs could become IROLs. The Commission believes that there can be considerable benefit derived from some overlap in the responsibility for analyzing and monitoring these “grid-impactive” SOLs since, by definition, every IROL emanated from an SOL. While the proposed Reliability Standards continue to commit the reliability coordinator to the analysis and monitoring of SOLs that may become IROLs, a subset of SOLs, such as these “grid-impactive” SOLs, may deserve a more defined analysis and monitoring role on the part of the reliability coordinator.

We acknowledge NERC’s and industry’s continuing efforts to improve the clarity of standard requirements regarding SOLs through the Real-time Operations Standard Drafting Team (Project 2007-03). We believe that the issues concerning the analysis and monitoring of “grid-impactive” SOLs that we note here can be raised and considered in this or other ongoing projects. NERC comments that it is working on Project 2007-03 to develop revisions to the TOP Reliability Standards that require transmission operators to perform operational planning analyses for their local areas. NERC also comments that this project is also considering revisions that would require that SOL limits in adjoining areas be observed. In addition, there are other open projects, such as Project 2006-06 — Reliability Coordination, which is analyzing appropriate reliability coordinator functions and responsibilities. In consideration of these ongoing efforts, we will not direct specific modifications to these Reliability Standards and, rather, accept NERC’s commitment to exercise its technical expertise to study these issues and develop appropriate revisions to applicable Standards as may be necessary.

Because the study and monitoring of SOLs and IROLs is an issue at the very core of Bulk-Power System reliability, the Commission agrees with EEI that the NERC Reliability Coordinators Working Group should engage the issues raised in this proceeding with NERC stakeholders, including the NERC Planning and Operating committees, to determine whether a need exists to further refine the delineation of responsibilities between the reliability coordinator and transmission operator for analyzing a class of “grid-impactive” SOLs. Depending on the results of that review, we further encourage NERC, working through its standard development process, to develop appropriate modifications to these and any other related Reliability Standards as necessary.

Operational Analyses and Real-time Assessments

In the NOPR, the Commission sought comment on the prudence of using an Operational Planning Analysis up to twelve months old. The Commission asked whether this timeframe is reasonable or whether the timeframe should be shorter to ensure that the analysis is not outdated. In addition, the Commission sought comment on whether the definition should include measurable criteria to determine whether it is appropriate to use an existing analysis.

Further, the Commission requested comments on the meaning of “immediately available data” within the proposed definition of the NERC Glossary definition of Real-Time Assessment. The Commission proposed to direct NERC to modify the definition of “Real-time Assessment” to specify that the type of data to be relied upon by a reliability coordinator in conducting a Real-time Assessment must be based on adequate analysis capabilities such as state estimation, pre- and post-contingency analysis capabilities (thermal, stability, and voltage), and wide-area overview displays referenced in Requirement R6 of IRO-002-2.

Comments

In response to the Commission’s questions regarding the use of an existing Operational Planning Analysis, NERC states that it is unlikely that a reliability coordinator would deliberately rely on an Operational Planning Analysis that does not reflect its expected system conditions. NERC asserts that a reliability coordinator will rely on a twelve-month old operational planning analysis only if system conditions have not changed over that time period. NERC states that the proposed definition of Operational Planning Analysis was developed, based on stakeholder comments, to apply not only to studies conducted for the day ahead, but also for future use in possibly developing requirements for seasonal studies. Thus, NERC explains, the definition includes the option of performing an Operational Planning Analysis up to twelve months ahead. NERC further explains that the definition includes key elements that provide measurable criteria in assessing an entity’s Operational Planning Analysis.

In response to the Commission’s questions regarding the proposed definition of Real-time Assessment, NERC and the Joint Commenters state that the industry is currently working towards consensus on the set of data and capabilities the reliability coordinators need to perform their tasks via the Real-time Reliability Monitoring and Analysis Capabilities Standards Development Team (Project 2009-02). Accordingly, NERC asks the Commission to refrain from directing modifications pending completion of the project.

Commission Determination

The Commission approves the definitions of “Operational Planning Analysis” and “Real-time Assessment” without modification.

The Commission agrees with NERC that the reliability coordinator should rely on a twelve-month old Operational Planning Analysis study only if system conditions have not changed from those originally studied. Consistent with the views of NERC, we expect that reliability coordinators will rely on Operational Planning Analysis that reflects expected system conditions. Accordingly, we accept the definition as proposed.

Similarly, we find it is unnecessary to direct NERC to modify the definition of “Real-time Assessment” to specify the type of data to be relied upon by a reliability coordinator in conducting a Real-time Assessment as proposed in the NOPR. Instead, the Commission will allow industry to complete Project 2009-02, which is working towards consensus on the set of data and capabilities the reliability coordinators need to perform their tasks. We expect NERC to use its technical expertise to develop any modifications to the definition of Real-time Assessment as may be necessary as a result of this ongoing project.

Reliability Coordinator Actions to Operate Within IROLs

In the NOPR, the Commission sought comment on whether reliability coordinators should have action plans developed and implemented with respect to other SOLs apart from IROLs and if so, which SOLs.

Comments

NERC states that transmission operators already are responsible for developing action plans for preventing and/or mitigating conditions that cause facility ratings to be exceeded. NERC therefore contends that it would add confusion to the process to require both the reliability coordinator and transmission operator to develop action plans for every SOL.

Similarly, WECC does not believe that reliability coordinators should be required to have action plans developed and implemented for SOLs apart from IROLs. WECC argues that requiring the reliability coordinator to second guess rather than defer to the more granular view and detailed view of the transmission operators or balancing authorities undermines and substantially changes the roles of each function without any foreseeable benefit to overall reliability.

Commission Determination

The Commission agrees with NERC that requiring both the reliability coordinator and transmission operator to develop action plans for every SOL may add confusion to the process. As a result, the Commission approves IRO-009-1, without modification. However, the Reliability Coordinator Working Group should further study this issue and determine if there is a need for reliability coordinators to have action plans developed and implemented with respect to certain grid-impactive SOLs.

IRO-010-1a

In the NOPR, the Commission expressed concern that Reliability Standard IRO-010-1a does not require reliability coordinators to specify a list of minimum data needed for reliable operation of the Bulk-Power System. The Commission, therefore, sought comment on whether a minimum list of data is necessary for the effective sharing of data between neighboring reliability coordinators and, if so, what data should be included. The Commission also sought comment on how compatibility of data between neighboring reliability coordinators can be assured without a list of minimum data in this proposed Reliability Standard.

In its discussion of Reliability Standard TOP-003-1, the Commission noted that Requirement R3 of proposed Reliability Standard IRO-010-1a requires entities to provide data and information to the reliability coordinator in accordance with the reliability coordinator’s specifications. The Commission expressed concern that this requirement does not specify outage coordination data and, therefore, the reliability coordinator may not receive adequate outage coordination data to support the Operational Planning Analysis. Accordingly, the Commission sought comment on whether IRO-010-1a should specify necessary outage coordination data.

Comments

NERC, the Joint Commenters and Midwest ISO contend that requiring a minimum list of data is not necessary for the effective sharing of data between neighboring reliability coordinators. NERC argues that requiring a list of minimum data not only could impair an entity’s ability to provide the data to the reliability coordinator quickly, but could prevent a reliability coordinator from obtaining needed data quickly. NERC also notes that, during the development of the proposed Reliability Standard, the reliability coordinators that were polled indicated they already were receiving the data they needed without any issues and that the data and information they received varied from one reliability coordinator to another. The Joint Commenters argue that it is unnecessary to develop such a requirement because two interconnected parties can agree upon the appropriate type and level of data it needs from the other, taking into consideration their respective tools and capabilities. Midwest ISO argues that many reliability coordinators already have developed coordination agreements with their neighbors that identify the information necessary for effective data sharing. Midwest ISO contends that a generic list of minimum data could be inadequate to meet regional needs and could create conflicts with existing coordination agreements. Midwest ISO further contends that a minimum list could curb creativity and innovation as capabilities develop new uses for data.

NERC and the Joint Commenters also urge the Commission to refrain from requiring NERC to modify IRO-010-1a to specify the necessary outage coordination data for all reliability coordinators. They contend that such an approach would not account for the significantly varying facilities located within the reliability coordinators’ area and allow for the flexibility to specify the data needed for its respective area.

Reiterating comments it raised during the standard development process, WECC opposes the requirement in R1.2 that the parties reach mutual agreement with respect to the format of the data and information that the reliability coordinator receives. WECC argues that, due to the large number of entities that must provide data to the reliability coordinator, the requirement for mutually agreeable formats may cause the reliability coordinator to receive data in a multitude of diverse formats. WECC also believes that requiring mutually agreeable data formats could delay the submission of data by a submitting entity until agreement can be reached via negotiation or dispute resolution. WECC argues that more than one party is involved in the formulation of an agreeable format yet only a reliability coordinator will be found non-compliant when the reliability coordinator and transmission operators or balancing authorities within the reliability coordinator area fail to reach an agreement over an acceptable format.

Commission Determination

The Commission agrees with commenters that it is unnecessary to direct NERC to develop a specific list of minimum data for the effective sharing of data between neighboring reliability coordinators under Reliability Standard IRO-010-1a. NERC and other entities confirm that reliability coordinators currently obtain necessary data without such a specific list. In addition, as commenters point out, a minimum list may conflict with coordination agreements currently in place which identify the information necessary for effective data sharing. With regard to the concern expressed in the NOPR regarding outage coordination data, we accept that reliability coordinators currently obtain necessary data. If, in the future, reliability coordinators are not able to obtain the necessary outage coordination data, we would ask NERC to consider whether a Reliability Standard should be developed for the reliability coordinators to obtain such data.

In response to WECC’s concerns about the submission of data in mutually agreeable formats under Requirement R1.2, we do not believe any modification is necessary. As NERC states in its Petition, by specifying that the format must be mutually agreeable, the standard supports efficiency by precluding the submission of data that is in a format that cannot be used. We agree. NERC states that current data exchange formats are acceptable. Therefore, entities can continue to utilize existing agreements regarding data exchange. While disputes may arise in the future, the Reliability Standard does not dictate a specific dispute resolution process in the interpretation leaving reliability coordinators and other entities options for informal resolution of a dispute on the format of data and flexibility in choosing a dispute resolution process to reach an agreement.

Accordingly, the Commission approves IRO-010-1a as submitted.

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 to be confidential. If necessary, information provided with a filing may be submitted with a specific request for confidential treatment to the extent permitted by law. The request is considered by FERC pursuant to 18 C.F.R. 388.112 and federal guidelines.

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

The Commission’s estimate below is based on the average annual reporting burden contained in the proposed standard IRO-10-1a. As indicated in item 2 above, the reporting burden contained in the other proposed and revised standards has been previously approved by OMB. The estimate is based on the NERC compliance registry as of September 28, 2010. According to the NERC compliance registry, there are 134 balancing authorities, 824 generator owners, 773 generator operators, 61 interchange authorities, 541 load-serving entities, 26 reliability coordinators, 178 transmission operators, and 332 transmission owners that would be involved in providing information. However, under NERC’s compliance registration program, entities may be registered for multiple functions, and as such there is some duplication of functions regarding the number of registered entities that would be required to provide information. Given these parameters, the Commission estimates that the Public Reporting burden for the requirements contained in the NOPR is as follows:

FERC-725A	No. of Respondents	No. of Annual Responses	Hours Per Respondent	Total Annual Hours
Reliability Coordinators distribution of data specification to entities	26	1	8	208
Applicable entities 23 reporting data to their Reliability Coordinator	1501	1	8	12,008
Total				12,216

*As needed

The following table shows how the currently approved inventory for FERC-725A will be affected if the new reporting requirements in this NOPR are put into effect.

FERC-725A	Responses	Reporting Hours per Response	Recordkeeping Hours per Response	Total Hours
Current Inventory	1,940	808.5198	82.5015	1,728,581
Program Change due to RM10-15 NOPR	0	+6.297#	0	+12,216
Requested Inventory (applying the program change from the NOPR)	1,940	814.8168	82.5015	1,740,797

#Rounded off

Due to rounding and/or truncation, the burden increase shows as 12,217 hours in ROCIS and 12,216 in the supporting statement and rulemaking.

12. ESTIMATE OF THE TOTAL ANNUAL COST BURDEN TO RESPONDENTS

For the reporting requirements in this NOPR, the Commission has set a rate that combines time for legal, technical and administrative support at $120/hour. Total annual cost estimate is $1,465,920 (12,216 hours @ $120/hour).

14. ESTIMATED ANNUALIZED COST TO FEDERAL GOVERNMENT

The estimate of the cost to the Federal Government is based on salaries for professional and clerical support, as well as direct and indirect overhead costs. Direct costs include all costs directly attributable to providing this information, such as administrative costs and the cost for information technology. Indirect or overhead costs are costs incurred by an organization in support of its mission. These costs apply to activities which benefit the whole organization rather than anyone particular function or activity.

IRO-10-1a requires Reliability Coordinators to provide data specifications to applicable entities and for these entities to provide the data to the Reliability Coordinators. Thus the Federal government incurs only the cost of processing this data collection as follows:

Annual Data Collection Cost as contained in this final rule: $1,575

15. REASONS FOR CHANGES IN BURDEN INCLUDING THE NEED FOR ANY INCREASE

The burden for the data collection FERC-725A (OMB Control No. 1902-0244) is increasing due to a new reporting requirement contained in Reliability Standard IRO-10-1a. As explained in item 2, the increase is necessary in order for Reliability Coordinators to better monitor the Bulk-Electric System and minimize the risk of system instability and outages.

16. TIME SCHEDULE FOR THE PUBLICATION OF DATA

The filed Reliability Standards are available on the Commission’s eLibrary document retrieval system in Docket No. RM10-15-000. The Commission requires that all Commission-approved Reliability Standards be available on the ERO’s website, with an effective date (http://www.nerc.com/page.php?cid=2|20).

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. Rather, the Reliability Coordinators and applicable entities must exchange information between themselves

18. EXCEPTIONS TO THE CERTIFICATION STATEMENT

The data collected for this reporting requirement is not used for statistical purposes. Therefore, the Commission does not use, as stated in item (i) of the agency certification, "effective and efficient statistical survey methodology." The information collected is case specific to each Reliability Standard.

B. COLLECTION OF INFORMATION EMPLOYING STATISTICAL METHODS.

This is not a collection of information employing statistical methods.

1 This submission was delayed due to other items under the same control number pending review at OMB.

2 NERC designates the version number of a Reliability Standard as the last digit of the Reliability Standard number. Therefore, original Reliability Standards end with “-0” and modified version one Reliability Standards end with “-1.” The NERC Board of Trustees approved the proposed IRO-010-1 Reliability Standard on October 17, 2008. Subsequently, on August 5, 2009, the NERC Board of Trustees approved an interpretation to the proposed IRO-010-1 standard. Accordingly, NERC is requesting approval of both the proposed standard and the appended interpretation, and NERC has designated the proposed standard and appended interpretation as IRO-010-1a.

3 Concurrent with its Petition in Docket RM10-15, NERC filed a petition in Docket No. RM10-16-000 seeking approval of certain Emergency Preparedness and Operations Reliability Standards. NERC, Petition for Approval of Three Emergency Preparedness and Operations Reliability Standards, Docket No. RM10-16-000 (filed Dec. 31, 2009). As part of its Petition in RM10-16-000, NERC proposed to retire Requirement R3.4 of EOP-001-0. Each petition proposes unique changes to EOP-001-0 reflecting the distinct issues addressed by the respective Reliability Standards drafting teams. In this Final Rule (RM10-15), the Commission is addressing Version 2 of EOP-001 contained in Exhibit B of the NERC Petition which reflects both the IRO and the EOP proposed changes.

4 Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, 72 FR 16416 (Apr. 4, 2007), FERC Stats. & Regs. ¶ 31,242, order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053 (2007).

5 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 896.

6 Id. P 908.

7 Id. P 914.

8 Id. P 935. NERC has subsequently replaced Levels of Non-Compliance with Violation Severity Levels. See Order on Violation Severity Levels Proposed by the Electric Reliability Organization, 123 FERC ¶ 61,284 (Violation Severity Level Order), order on reh’g, 125 FERC ¶ 61,212 (2008).

9 Id. P 951.

10 NERC, Compliance Filing, Docket No. RM06-16-006 (filed Oct. 31, 2008).

11 NERC, Compliance Filing, Docket No. RM06-16-006 (filed Feb. 8, 2009).

12 These entities include: Balancing Authorities, Generator Owners, Generator Operators, Interchange Authorities, Load-serving Entities, Reliability Coordinators, Transmission Operators, and Transmission Owners.

13 Reliability Standard IRO-010-1a, Requirement R2.

14 Reliability Standard IRO-10-1a, Purpose.

15 Order No. 672 at P 330.

16 See the “Purpose” section of reliability standards IRO-008-1, IRO-009-1, and IRO-010-1a at http://www.nerc.com/page.php?cid=2|20.

17 Details of the ERO standards development process are available on the NERC website at http://www.nerc.com/docs/standards/sc/Standard_Processes_Manual_Approved_May_2010.pdf.

18 The proposed and final rule documents, as well as submitted comments, can be found by searching on docket no. “RM10-15” on the Commission’s eLibrary site at: http://elibrary.ferc.gov/idmws/docket_search.asp.

19 NERC Petition at 9.

20 NERC Petition at 10.

21 NERC Comments at 7. NERC does not offer a definition of the term “grid-impactive SOL,” but we understand it to mean an SOL that the reliability coordinator monitors so that it does not develop into an IROL.

22 See NERC Functional Model at 31, 37.

23 These include Balancing Authorities, Generator Owners, Generator Operators, Interchange Authorities, Load-serving Entities, Reliability Coordinators, Transmission Operators, and Transmission Owners