Federal Energy Regulatory Commission 

Staff Preliminary Assessment of the 

North American Electric Reliability Council’s 

Proposed Mandatory Reliability Standards

May 11, 2006 

RM06-16-000 
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FERC Staff Preliminary Assessment of NERC Reliability Standards

Table of Contents 

I. EXECUTIVE SUMMARY.....................................................................................- 1 -

II. BACKGROUND/PURPOSE..............................................................................- 10 -

A. Background.................................................................................................................................................- 10 -

B. August 2003 Blackout ................................................................................................................................- 12 -

C. EPAct 2005 and Order No. 672.................................................................................................................- 13 -

D. Subject, Purpose and Commission Context for this Review...................................................................- 15 -

III. COMMON ISSUES............................................................................................- 17 -

A. Blackout Report Recommendations .........................................................................................................- 17 -

B. Ambiguities and Potential Multiple Interpretations ...............................................................................- 18 -

C. Technical Adequacy ...................................................................................................................................- 19 -

D. Measures and Levels of Non-Compliance ................................................................................................- 22 -

E. Fill-in-the-Blank Standards.......................................................................................................................- 23 -

F. Applicability of the NERC Standards ......................................................................................................- 24 -

G. Systems to Which the Standards Apply: Bulk Electric System v. Bulk-Power System ......................- 25 -

IV. BAL: RESOURCE AND DEMAND BALANCING........................................- 27 -

A. Description and General Issues.................................................................................................................- 27 -

B. Primary Issues in the Resource and Demand Balancing Standards......................................................- 27 -

1. Contingency Reserve Requirements .......................................................................................................- 27 -

2. Actual Frequency Response (Bias) .........................................................................................................- 28 -

C. Concerns Specific to Individual Standards..............................................................................................- 29 -

Real Power Balancing Control Performance (BAL-001-0)..........................................................................- 29 -

Disturbance Control Performance (BAL-002-0)..........................................................................................- 29 -

Frequency Response and Bias (BAL-003-0)................................................................................................- 30 -

Time Error Correction (BAL-004-0)............................................................................................................- 31 -

Automatic Generation Control (BAL-005-0)...............................................................................................- 31 -

Inadvertent Interchange (BAL-006-0)..........................................................................................................- 32 -
FERC Staff Preliminary Assessment of NERC Reliability Standards ii 

V. CIP: CRITICAL INFRASTRUCTURE PROTECTION ......................................- 34 -

A. Description and General Issues.................................................................................................................- 34 -

B. Primary Issues in the Critical Infrastructure Protection Cyber Security Standards ..........................- 35 -

C. Concerns Specific to Individual Standards..............................................................................................- 35 -

Sabotage Reporting (CIP-001-0)..................................................................................................................- 35 -

Urgent Action 1200 (UA 1200)....................................................................................................................- 36 -

Section 1201 – Cyber Security Policy..........................................................................................................- 37 -

Section 1202 – Critical Cyber Assets...........................................................................................................- 37 -

Section 1203 – Electronic Security Perimeter..............................................................................................- 37 -

Section 1204 – Electronic Access Controls..................................................................................................- 38 -

Section 1205 – Physical Security Perimeter.................................................................................................- 38 -

Section 1206 – Physical Access Controls.....................................................................................................- 39 -

Section 1207 – Personnel .............................................................................................................................- 39 -

Section 1208 – Monitoring Physical Access ................................................................................................- 39 -

Section 1209 – Monitoring Electronic Access .............................................................................................- 39 -

Section 1210 – Information Protection.........................................................................................................- 40 -

Section 1211 – Training ...............................................................................................................................- 40 -

Section 1212 – Systems Management..........................................................................................................- 40 -

Section 1213 – Test Procedures ...................................................................................................................- 40 -

Section 1214 – Electronic Incident Response Actions.................................................................................- 41 -

Section 1215 – Physical Incident Response Actions....................................................................................- 41 -

Section 1216 – Recovery Plans ....................................................................................................................- 41 -

VI. COM: COMMUNICATIONS .........................................................................- 42 -

A. Description and General Issues.................................................................................................................- 42 -

B. Primary Issues in the Communications Standards .................................................................................- 42 -

1. Unclear Requirements in Telecommunications Facilities.......................................................................- 42 -

2. Ineffective Communications and Inadequate Coordination Can Threaten Reliability............................- 43 -

C. Concerns Specific to Individual Standards..............................................................................................- 45 -

Telecommunications (COM-001-0) .............................................................................................................- 45 -

Communication and Coordination (COM-002-1) ........................................................................................- 45 -

VII. EOP: EMERGENCY PREPAREDNESS AND OPERATIONS.....................- 47 -

A. Description and General Issues.................................................................................................................- 47 -

B. Primary Issues in the Emergency Preparedness and Operations Standards........................................- 47 -

1. Definition of Emergency States: Normal, Alert and Emergency ...........................................................- 47 -

2. Load Shedding: Specific Amounts and Timing .....................................................................................- 48 -

3. Operator Protection for Load Shedding ..................................................................................................- 49 -

4. Back-Up Capability.................................................................................................................................- 49 -
FERC Staff Preliminary Assessment of NERC Reliability Standards iii 

C. Concerns Specific to Individual Standards..............................................................................................- 50 -

Emergency Operations Planning (EOP-001-0) ............................................................................................- 50 -

Capacity and Energy Emergencies (EOP-002-1) .........................................................................................- 51 -

Load Shedding Plans (EOP-003-0) ..............................................................................................................- 51 -

Disturbance Reporting (EOP-004-0)............................................................................................................- 52 -

System Restoration Plans (EOP-005-0) .......................................................................................................- 53 -

Reliability Coordination-System Restoration (EOP-006-0).........................................................................- 53 -

Establish, Maintain, and Document a Regional Blackstart Capability Plan (EOP-007-0) ..........................- 54 -

Plans for Loss of Control Center Functionality (EOP-008-0) ......................................................................- 54 -

Documentation of Blackstart Generating Unit Tests Results (EOP-009-0) .................................................- 54 -

VIII. FAC: FACILITIES DESIGN, CONNECTIONS, MAINTENANCE, AND 

TRANSFER CAPABILITIES.....................................................................................- 55 -

A. Description and General Issues.................................................................................................................- 55 -

B. Primary Issues in the Facility Standards .................................................................................................- 56 -

1. Consistency of Facility Standards with the Commission’s Generation Interconnection Orders.............- 56 -

2. Vegetation Management .........................................................................................................................- 56 -

3. Methodology to Determine Facility Ratings...........................................................................................- 58 -

C. Concerns Specific to Individual Standards..............................................................................................- 59 -

Facility Connection Requirements (FAC-001-0) .........................................................................................- 59 -

Coordination of Plans for New Generation, Transmission, and End-User facilities (FAC-002-0) ..............- 59 -

Transmission Vegetation Management Program (FAC-003-1)....................................................................- 59 -

Methodologies for Determining Electrical Facilities (FAC-004-0)..............................................................- 60 -

Electrical Facility Ratings for System Modeling (FAC-005-0)....................................................................- 60 -

Facility Ratings Methodology (FAC-008-1) ................................................................................................- 60 -

Establish and Communicate Facility Ratings (FAC-009-1).........................................................................- 60 -

Transfer Capability Methodology (FAC-012-1) ..........................................................................................- 61 -

Establish and Communicate Transfer Capability (FAC-013-1) ...................................................................- 61 -

IX. INT: INTERCHANGE SCHEDULING AND COORDINATION .....................- 62 -

A. Description and General Issues.................................................................................................................- 62 -

B. Primary Issues in the Interchange Scheduling and Coordination Standards.......................................- 63 -

1. Use of Interchange Transaction Modifications to Address Actual System Operating Limit or 

Interconnection Reliability Operating Limit Violations....................................................................................- 63 -

C. Issues Specific to Individual Standards....................................................................................................- 63 -

Interchange Transaction Tagging (INT-001-0) ............................................................................................- 63 -

Interchange Transaction Tag Communication and Reliability Assessment (INT-002-0) ...........................- 64 -

Interchange Transaction Implementation (INT-003-0) ................................................................................- 64 -

Interchange Transaction Modifications (INT-004-0) ...................................................................................- 64 -
FERC Staff Preliminary Assessment of NERC Reliability Standards iv 

X. IRO: INTERCONNECTION RELIABILITY OPERATIONS AND COORDINATION - 

66 -

A. Description and General Issues.................................................................................................................- 66 -

B. Primary Issues in Interconnection Reliability Operation and Coordination Standards .....................- 67 -

1. Unclear Responsibilities and Authorities of Reliability Coordinators ....................................................- 67 -

2. Operation Under Normal and Post-Contingency Conditions..................................................................- 67 -

3. Specificity on Wide Area View ..............................................................................................................- 68 -

4. Use of Transmission Loading Relief.......................................................................................................- 69 -

C. Concerns Specific to Individual Standards..............................................................................................- 69 -

Reliability Coordination – Responsibilities and Authorities (IRO-001-0)...................................................- 69 -

Reliability Coordination – Facilities (IRO-002-0) .......................................................................................- 70 -

Reliability Coordination – Wide Area View (IRO-003-0) ...........................................................................- 70 -

Reliability Coordination – Operations Planning (IRO-004-1) .....................................................................- 71 -

Reliability Coordination – Current Day Operations (IRO-005-1)................................................................- 71 -

Reliability Coordination – Transmission Loading Relief (IRO-006-1)........................................................- 72 -

Procedures, Processes, or Plans to Support Coordination Between Reliability Coordinators (IRO-014-1).- 73 -

Notifications and Information Exchange Between Reliability Coordinators (IRO-015-1) ..........................- 73 -

Coordination of Real-time Activities Between Reliability Coordinators (IRO-016-1)................................- 73 -

XI. MOD: MODELING, DATA, AND ANALYSIS...............................................- 74 -

A. Description and General Issues.................................................................................................................- 74 -

B. Primary Issues in the Modeling, Data, and Analysis Standards ............................................................- 75 -

1. Quality of System Modeling Data and Data Exchange Practices............................................................- 75 -

2. Different Approaches to TTC, ATC, CBM, and TRM Methodologies...................................................- 75 -

C. Concerns Specific to Individual Standards..............................................................................................- 76 -

1. Fill-in-the-Blank Standards.....................................................................................................................- 76 -

Review of TTC and ATC Calculations and Results (MOD-002-0) .............................................................- 76 -

Procedure for Input on TTC and ATC Methodologies and Values (MOD-003-0) ......................................- 77 -

Regional Steady-State Data Requirements and Reporting Procedures (MOD-011-0) .................................- 77 -

Regional Reliability Organization Dynamics Data Requirements and Reporting Procedures (MOD-013-0) - 77 

-

Development of Interconnection-Specific Steady State System Models (MOD-014-0).............................- 78 -

Development of Interconnection-Specific Dynamics System Models (MOD-015-0)..................................- 78 -

Actual and Forecast Demands, Net Energy for Load, Controllable DSM (MOD-016-0) ...........................- 79 -

Verification of Generator Gross and Net Real Power Capability (MOD-024-1) .........................................- 79 -

Verification of Generator Gross and Net Reactive Power Capability (MOD-025-1)...................................- 79 -

2. Absence of Consistent Methodology for Calculating ATC.....................................................................- 80 -

Documentation of TTC and ATC Calculation Methodologies (MOD-001-0) .............................................- 80 -

Documentation of Regional CBM Methodologies (MOD-004-0) ...............................................................- 80 -

Procedure for Verifying CBM Values (MOD-005-0) ..................................................................................- 81 -

Procedure for the Use of CBM Values (MOD-006-0) .................................................................................- 81 -

Documentation of the Use of CBM (MOD-007-0) ......................................................................................- 81 -

Documentation and Content of Each Regional TRM Methodology (MOD-008-0).....................................- 81 -

Procedure for Verifying TRM Values (MOD-009-0) ..................................................................................- 82 -
FERC Staff Preliminary Assessment of NERC Reliability Standards v 

3. Omission of the Planning Authority as an Applicable entity ..................................................................- 82 -

Steady-State Data for Transmission System Modeling and Simulation (MOD-010-0) ..............................- 82 -

Dynamics Data for Transmission System Modeling and Simulation (MOD-012-0) ...................................- 83 -

4. Accuracy and Bias of Load Forecasts .....................................................................................................- 83 -

Aggregated Actual and Forecast Demands and Net Energy for Load (MOD-017-0) ..................................- 83 -

Reports of Actual and Forecast Demand Data (MOD-018-0)......................................................................- 84 -

Forecasts of Interruptible Demands and DCLM Data (MOD-019-0) ..........................................................- 84 -

Providing Interruptible Demands and DCLM Data (MOD-020-0)..............................................................- 84 -

Accounting Methodology for Effects of Controllable DSM in Forecasts (MOD-021-0)............................- 85 -

XII. PER: PERSONNEL PERFORMANCE, TRAINING AND QUALIFICATIONS- 86 

-

A. Description and General Issues.................................................................................................................- 86 -

B. Primary Issues in the Personnel Performance, Training and Qualifications Reliability Standards...- 87 -

1. Scope of Applicability.............................................................................................................................- 87 -

2. Training Program Objectives ..................................................................................................................- 87 -

3. Operating Personnel Certification...........................................................................................................- 89 -

C. Concerns Specific to Individual Reliability Standards ...........................................................................- 90 -

Operating Personnel Responsibility and Authority (PER-001-0).................................................................- 90 -

Operating Personnel Training (PER-002-0).................................................................................................- 90 -

Operating Personnel Credentials (PER-003-0).............................................................................................- 90 -

Reliability Coordination – Staffing (PER-004-0).........................................................................................- 91 -

XIII. PRC: PROTECTION AND CONTROL.........................................................- 92 -

A. Description and General Issues.................................................................................................................- 92 -

B. Primary Issues in the Protection and Control Standards.......................................................................- 93 -

1. Ambiguous Requirements for Protection Failures ..................................................................................- 93 -

2. Integrated and Coordinated Approach to Bulk-Power System Protection ..............................................- 94 -

3. Criteria for Maintenance and Testing of Protection Systems..................................................................- 94 -

C. Concerns Specific to Individual Reliability Standards ...........................................................................- 95 -

1. Individually Identified Standards............................................................................................................- 95 -

System Protection Coordination (PRC-001-0).............................................................................................- 95 -

Development and Documentation of Regional UFLS Programs (PRC-006-0)............................................- 95 -

UFLS Performance Following an Underfrequency Event (PRC-009-0)......................................................- 96 -

Assessment of the Design and Effectiveness of UVLS Program (PRC-010-0) ...........................................- 96 -

Special Protection System Assessment (PRC-014-0)...................................................................................- 96 -

2. Specifications of Maintenance Intervals .................................................................................................- 97 -

Transmission Protection System Maintenance and Testing (PRC-005-0) ...................................................- 97 -

Underfrequency Load Shedding Equipment Maintenance Programs (PRC-008-0).....................................- 97 -

Undervoltage Load Shedding System Maintenance and Testing (PRC-011-0) ...........................................- 97 -

Special Protection System Maintenance and Testing (PRC-017-0).............................................................- 97 -

3. RROs Designated as the Sole Applicable Entity.....................................................................................- 97 -

Define and Document Disturbance Monitoring Equipment Requirements (PRC-002-0) ...........................- 98 -

Regional Procedure for Transmission Protection System Misoperations (PRC-003-1)..............................- 98 -

Special Protection System Review Procedure (PRC-012-0) ........................................................................- 98 -
FERC Staff Preliminary Assessment of NERC Reliability Standards vi 

Special Protection System Database (PRC-013-0).......................................................................................- 98 -

Under-Voltage Load Shedding Program Database (PRC-020-1).................................................................- 98 -

4. No Substantive Issues Identified.............................................................................................................- 99 -

Analysis and Reporting of Transmission Protection System Misoperations (PRC-004-0) .........................- 99 -

Assuring Consistency with Regional UFLS Program Requirements (PRC-007-0) .....................................- 99 -

Special Protection System Data and Documentation (PRC-015-0)..............................................................- 99 -

Special Protection System Misoperations (PRC-016-0)...............................................................................- 99 -

Under-Voltage Load Shedding Program Data (PRC-021-1)........................................................................- 99 -

Under-Voltage Load Shedding Program Performance (PRC-022-1) ......................................................... - 100 -

XIV. TOP: TRANSMISSION OPERATIONS......................................................- 101 -

A. Description and General Issues............................................................................................................... - 101 -

B. Primary Issues in the Transmission Operations Standards ................................................................. - 102 -

1. Ability to Readjust the System Following a Contingency .................................................................... - 102 -

2. Operation Under Normal Pre-Contingency Conditions ........................................................................ - 102 -

3. Minimum Acceptable Tools to Aid Situational Awareness .................................................................. - 103 -

C. Concerns Specific to Individual Standards............................................................................................ - 103 -

Reliability Responsibilities and Authorities (TOP-001-0) ......................................................................... - 103 -

Normal Operations Planning (TOP-002-0) ................................................................................................ - 103 -

Planned Outage Coordination (TOP-003-0)............................................................................................... - 104 -

Transmission Operations (TOP-004-0) ...................................................................................................... - 105 -

Operational Reliability Information (TOP-005-1)...................................................................................... - 106 -

Monitoring System Conditions (TOP-006-0)............................................................................................. - 106 -

Reporting SOL and IROL Violations (TOP-007-0) ................................................................................... - 106 -

Response to Transmission Limit Violations (TOP-008-0)......................................................................... - 107 -

XV. TPL: TRANSMISSION PLANNING CHAPTER .........................................- 108 -

A. Description and General Issues............................................................................................................... - 108 -

B. Primary Issues in the Transmission Planning Standards ..................................................................... - 109 -

1. Stressing the System during Simulations .............................................................................................. - 109 -

2. Element-Based vs. Event-Based Contingencies....................................................................................- 110 -

3. Interpretation of Performance Requirements ........................................................................................ - 111 -

4. Assessment of Extreme Events ............................................................................................................. - 111 -

5. Scope of Elements for which the Reliability Standards Apply ............................................................. - 112 -

C. Concerns Specific to Individual Standards............................................................................................ - 113 -

System Performance Under Normal (No Contingency) Conditions (Category A) (TPL-001-0) ............... - 113 -

System Performance Following Loss of a Single BES Element (TPL–002–0)......................................... - 114 -

System Performance Following Loss of Two or More BES Elements (TPL-003-0) ................................. - 114 -

System Performance Following Extreme BES Events (TPL-004-0).......................................................... - 115 -

Regional and Interregional Self-Assessment Reliability Reports (TPL-005-0) ......................................... - 115 -

Assessment Data from Regional Reliability Organizations (TPL-006-0) .................................................. - 116 -
FERC Staff Preliminary Assessment of NERC Reliability Standards vii 

XVI. VAR: VOLTAGE AND REACTIVE............................................................- 117 -

A. Description and General Issues............................................................................................................... - 117 -

B. Primary Issues with the Voltage and Reactive Control Standard ....................................................... - 118 -

1. Unclear and Incomplete Requirements ................................................................................................. - 118 -

2. Applicability.......................................................................................................................................... - 119 -

APPENDIX A: STANDARDS REVIEWED.............................................................- 121 -

APPENDIX B: STANDARDS WITH UNCLEAR ENFORCEABILITY UNDER EPACT 

2005 ........................................................................................................................- 124 -

APPENDIX C: STANDARDS LACKING MEASURABILITIY AND NON-COMPLIANCE 

SPECIFICATIONS ..................................................................................................- 125 -

APPENDIX D: ACRONYMS IN THIS DOCUMENT...............................................- 126 -
FERC Staff Preliminary Assessment of NERC Reliability Standards viii 

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FERC Staff Preliminary Assessment of NERC Reliability Standards - 1 - 

I. EXECUTIVE SUMMARY 

The Charge from Congress 

With the passage of the Energy Policy Act of 2005, the United States Congress entrusted 

the Federal Energy Regulatory Commission (Commission) with the authority to approve 

and enforce rules to assure reliability of the Nation’s Bulk-Power System. Section 1211 

of the Energy Policy Act of 20051

 (EPAct 2005) creates section 215 of the Federal Power 

Act (FPA), which requires the Commission to issue rules for the certification of an 

Electric Reliability Organization (ERO). The ERO will be responsible for developing 

and enforcing mandatory Reliability Standards, subject to Commission approval, that 

provide for an adequate level of reliability of the Bulk-Power System. 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, in contrast to the current 

system of voluntary compliance with industry-developed reliability standards managed 

by the North American Electric Reliability Council (NERC).2

 

In discharging its responsibility to review, approve and enforce mandatory Reliability 

Standards, the Commission is authorized to approve only those proposed standards that 

meet the criteria detailed by Congress: 

The Commission may approve, by rule or order, a proposed reliability 

standard or modification to a reliability standard if it determines that the 

standard is just, reasonable, not unduly discriminatory or preferential, and 

in the public interest.[3]

 

In considering whether a Reliability Standard meets the statutory criteria, the 

Commission must give "due weight" to "technical expertise" of the ERO or any Regional 

Entity organized on an interconnection-wide basis. 

This preliminary staff assessment is the first step in an open and inclusive process that 

will allow interested persons to submit comments on whether the proposed mandatory 

 

1

 Energy Policy Act of 2005, Pub. L. No. 109-58, Title XII, Subtitle A, 119 Stat. 594, 941 (2005) 

(to be codified at 16 U.S.C. § 824o). 

2

 This assessment capitalizes the words “Reliability Standard” only when referring to mandatory 

Reliability Standards approved by the Commission. This assessment capitalizes the words 

“Requirements,” “Measures,” “Compliance” and “Levels of Non-Compliance” when referring to those 

named sections in the NERC standards. 

3

 Section 215(d)(2) of the FPA, to be codified at 16 U.S.C. § 824o(d)(2) (2000). 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 2 - 

Executive Summary 

Reliability Standards found in NERC’s petition meet the statutory criteria and will allow 

the Commission to develop an adequate record on which to make the required statutory 

findings. Staff began the analysis by evaluating the current voluntary reliability 

standards listed on NERC’s website prior to its filed petition. Staff anticipated that the 

proposed mandatory Reliability Standards would have the same, or nearly the same, 

content as the current voluntary reliability standards but kept current on any revised or 

new standards that were developed. On April 4, NERC filed 102 reliability standards 

with the Commission requesting that they be approved and subsequently made 

mandatory. This assessment reviews these standards. 

As explained further below, staff has identified numerous deficiencies in the standards 

filed by NERC for approval and is seeking comment on them. In many instances, NERC 

has identified the same concerns in its April 4, 2006 standards petition and has proposed 

a workplan to address them. We commend NERC for taking this proactive role. In other 

instances, staff has identified potential deficiencies for which there is no proposed work 

plan in NERC's petition. We seek comment on these potential deficiencies, whether the 

proposed Reliability Standards containing such potential deficiencies meet the statutory 

criteria and, if not, the process by which the standards should be revised, including giving 

priority to those that are of the greatest importance to Bulk-Power System reliability. 

Initial Commission Activity – Order No. 672 

The Commission began implementation of section 215 of the FPA with Order No. 672, 

issued on February 3, 2006.4

 Among other things, Order No. 672 established criteria that 

an entity must satisfy to qualify to be the ERO and procedures under which the ERO may 

propose new or modified Reliability Standards for Commission review. In its final rule, 

the Commission provided guidance on the factors it would consider when determining 

whether proposed Reliability Standards meet the statutory criteria.5

 

For example, the guidance states that a proposed Reliability Standard must be designed to 

achieve a specified reliability goal and be clear and unambiguous regarding what is 

required and who is required to comply. In order to be approved, a proposed Reliability 

Standard does not have to reflect the “best practice,” but it similarly cannot be a 

compromise based on the “lowest common denominator,” if such a Standard would not 

 4 Rules Concerning Certification of the Electric Reliability Organization: and Procedures for the 

Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672, 71 FR 8,662 

(Feb. 17, 2006), FERC Stats. & Regs. Regulations Preambles ¶ 31, 204 (2006), order on reh’g, Order No. 

672-A, 114 FERC ¶ 61,328 (2006). 

5 See Order No. 672 at P 320-36. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 3 - 

Executive Summary 

efficiently and effectively achieve its reliability goal. A full discussion of the factors 

listed in Order No. 672 can be found in the Background/Purpose Chapter of this 

assessment. Ultimately, the Commission has the regulatory responsibility to approve 

Reliability Standards that protect Bulk-Power System reliability . 

Staff Activity 

In anticipation of NERC submitting an ERO certification application with a concurrent 

filing for Commission approval of NERC’s existing voluntary standards as mandatory 

and enforceable Reliability Standards pursuant to section 215 of the FPA, Chairman 

Kelliher, in the fall of 2005, directed the Commission’s Division of Reliability to initiate 

a thorough technical review of the existing voluntary standards. 

This preliminary assessment by Commission staff is the product of that months-long 

review. It is limited to a technical review as it makes no final determinations about 

whether the proposed Reliability Standards meet the Commission’s criteria. Its purpose 

is to solicit industry comment on the potential deficiencies in the current standards and 

the appropriate process and timeline for addressing them. Although staff has conducted a 

comprehensive internal review of the standards, we believe it is important that the 

industry and affected stakeholders have the opportunity to review our preliminary 

assessment before the Commission takes any actions with regard to the proposed 

standards. Such an open and inclusive process will ensure that all interested persons have 

an opportunity for comment on the proposed standards and that the Commission has an 

adequate record upon which to discharge its statutory responsibilities. 

NERC’s Application and Proposed Reliability Standards 

The current NERC voluntary standards are the product of industry’s dedication and 

persistence over decades to develop, enforce, and improve reliability standards. Based on 

information provided by NERC and industry, it appears that much of the existing BulkPower System is planned and operated in ways that may actually surpass the criteria 

specified in the existing standards.6

 However, at a minimum, it appears that all users, 

owners, and operators generally comply with the current voluntary standards and that 

good utility practice is the norm. During the transition period to mandatory Reliability 

 6

 Examples include practices cited in NERC’s “Examples of Excellence” found in its Readiness 

Audits, filings for jurisdictional utilities in Part 4 of FERC Form No. 715, Transmission Planning 

Reliability Criteria. Regional Reliability Organizations also specify requirements that exceed NERC 

Standards such as WECC’s Minimum Operating Requirement Criteria and the NPCC Document A-02 - 

Basic Criteria for Design and Operation of Interconnected Power Systems. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 4 - 

Executive Summary 

Standards, jurisdictional public utilities should continue to follow the existing standards 

as part of good utility practice under their existing open access transmission tariffs. 

On April 4, 2006, NERC filed with the Commission its application for certification as the 

ERO.7

 NERC simultaneously submitted a petition for Commission approval of 102 

proposed Reliability Standards.8

 The proposed Standards are identical to the current 

voluntary standards analyzed in this assessment. 

In undertaking a preliminary assessment of these standards, staff has identified a number 

of deficiencies. In making this assessment, however, staff concludes that NERC’s 

voluntary standards program represents a solid foundation on which to maintain and 

improve the reliability of the Nation’s Bulk-Power System. Staff favors NERC’s own 

interpretation as to the state of its standards: 

Although the Version 0 Reliability Standards signified an important 

milestone in NERC’s history, it was only a beginning point. An 

appropriate analogy is that the Version 0 standards represent the 

establishment of a base camp for standards at 7,000 feet. The revised and 

new standards recently approved by the board are the first few hundred feet 

of the climb above the base camp. Much more challenging work remains in 

the climb to achieve technically excellent reliability standards for the North 

American bulk-power system.[9]

 

Staff views the long-term Standards development process as one of continuous 

improvement and is pleased to note that NERC, in evaluating its own proposed standards, 

discussed a number of areas for improvement on some of the topics discussed in this 

assessment. The Commission will be looking for public input on these and other areas 

for improvement at a number of different points during the Standards approval process, 

particularly at the upcoming technical conference. For this assessment and beyond, of 

particular interest to staff are comments concerning the effectiveness of NERC’s 

proposed Reliability Standards, transitional issues, and any process changes that might be 

necessary to achieve “technical excellence.” 

Preliminary Staff Assessment 

 7

 Application for Certification as the Electric Reliability Organization, Docket No. RR06-1-000 

(April 4, 2006). 

8

 Petition for Approval of Reliability Standards, Docket No. RM06-16-000 (April 4, 2006) 

(petition). 

9 Id. at 69. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 5 - 

Executive Summary 

This preliminary staff assessment represents the first step in an open and inclusive 

process whereby the Commission will implement EPAct 2005's goal of establishing and 

enforcing mandatory reliability standards that meet the statutory criteria. The primary 

goals of the staff assessment are to: 

• Provide a basis for soliciting input regarding which of the proposed Reliability 

Standards should be approved, approved on an interim or conditional basis, or 

remanded to the ERO.10 

• Establish a platform from which to identify and prioritize potential problems with 

the proposed Standards that must be addressed as the industry transitions into the 

mandatory Reliability Standards paradigm. 

• Provide a comprehensive and objective assessment of NERC’s current 102 

reliability standards in view of the Blackout Report recommendations,11 system 

blackouts and other disturbances, the Commission’s Utility Vegetation 

Management and Bulk Electric Reliability Report to Congress, and the guidance 

provided by the Commission in Order No. 672. 

The preliminary staff assessment has identified a number of potential deficiencies in the 

proposed standards. We note, however, that many of these deficiencies, particularly 

those related to measures and fill-in-the-blank standards, have also been identified by 

NERC in its standards petition and NERC has proposed a workplan for addressing them. 

Our review has identified many additional deficiencies as well. We summarize the major 

areas of concern below, including those concerns identified by NERC in its petition: 

• Blackout Report Recommendations: Although the Blackout Report identified 

many of the primary causes of the August 2003 blackout and other major 

blackouts in the United States, many of its recommendations are not yet addressed 

in the reliability standards.12 NERC has activities in place to address the 

 10 It is staff’s view that the authority to approve standards on a conditional basis or to make some 

form of interim approval is within the scope of the Commission’s authority to remand or approve 

standards under FPA section 215. This conditional approval authority will enable some assurance of 

reliability while NERC has an opportunity to improve the standard in question. 

11 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, at 107 (Blackout Report). 

The Task Force investigated the causes of the 2003 blackout and recommended actions to be taken to 

prevent future widespread outages. 

12 The Blackout Report recommended changes that impact the following topical categories of 

standards, each examined in its respective chapter of this report: Communications, Emergency 

(continued) 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 6 - 

Executive Summary 

recommendations, but they have not yet resulted in full implementation in the 

reliability standards. 

• Ambiguity: Elements of numerous standards appear to be subject to multiple 

interpretations, especially with regard to the specificity of the standards’ 

requirements, measurability, and degrees of compliance.13 This ambiguity also 

extends to the differing definitions for the Bulk-Power System and the Bulk 

Electric System.14

• Technical Adequacy: The requirements specified in some standards may not be 

sufficient to ensure an adequate level of reliability. While Order No. 672 notes 

that “best practice” may be an inappropriately high standard, it also warns that a 

“lowest common denominator” approach will not be acceptable if it is not 

sufficient to ensure system reliability.15 NERC’s petition acknowledges that 

considerable effort is needed to bring the standards to the anticipated level of 

excellence and commits to working toward that goal. 

• Measures and Compliance: These two components are absent in many of the 

standards, which could lead to inconsistent interpretation and enforcement of the 

standards.16 NERC’s petition identifies 21 standards in this category and states 

that a project is underway to file the Measures and Compliance components by 

November 2006. 

 

Operations, Facility Design, Interchange Scheduling, Interconnection Reliability Operations, Modeling, 

Personnel Performance, Protection and Control, Transmission Operations, and Voltage and Reactive. 

13 Representative examples are contained in the chapters pertaining to Interconnected Reliability 

Operations and Coordination, Transmission Operations, and Transmission Planning. NERC’s 

Compliance Element Drafting Standards Team has independently identified 55 requirements in 14 

standards that need more definition or are vague. The drafting team, which is charged with providing 

compliance elements for the 21 standards identified by NERC that do not have compliance elements, 

posted their first draft at: 

ftp://www.nerc.com/pub/sys/all_updl/standards/sar/Missing_Compl_Measures_Set1_Clean_18Apr06.pdf. 

14 The Bulk-Power System is the term used to describe jurisdiction of the ERO in EPAct 2005 

and Order No. 672 whereas the Bulk Electric System is the term used by NERC to describe the 

jurisdiction of its standards. A more complete discussion of this issue can be found in section G of the 

Common Issues chapter of this assessment. 

15 Order No. 672 at P 328-29 (representative examples are contained in the chapters pertaining to 

Personnel Performance Training and Qualification; Modeling, Data, and Analysis; and Transmission 

Planning). 

16 See Appendix C which lists standards that lack either Measures or Levels of Non-Compliance. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 7 - 

Executive Summary 

• Undue Negative Impact on Competition: The primary purpose of this assessment 

was to provide a technical reliability analysis of the proposed standards, rather 

than to identify those that could have an undue negative impact on competition.17 

However, in certain instances staff identifies standards that could raise such 

concerns, such as the standards that govern the calculation of Available Transfer 

Capability (ATC). The Commission is considering the issues associated with 

ATC calculation in greater detail in Docket Nos. RM05-17-000 and RM05-25-

000. 

• Fill-in-the-Blank Standards: "Fill-in-the-Blank Standards" refer to those standards 

for which Version 0 does not contain a specific requirement that is enforceable 

against users, owners and operators of the grid, but rather provides only broad 

direction to the Regional Reliability Organizations (RROs) to adopt a particular 

standard. These standards raise concerns in two respects (i) they are not 

enforceable against users, owners and operators of the grid, but rather only provide 

broad direction to RROs, and (ii) the more specific implementing standards 

adopted by the RROs have not undergone an approval process under section 215 

and hence cannot themselves be enforced by the Commission or ERO. Beyond 

the near-term enforceability problems associated with these types of standards, 

there are concerns that the “blanks” be populated in ways that do not generate 

unnecessary regional differences.18 NERC’s petition acknowledges there are 

issues with fill-in-the-blank standards and proposes both short-term and long-term 

solutions. 

• Applicability: FPA section 215 requires that “all users, owners, and operators” 

comply with mandatory reliability standards approved by the Commission. The 

current standards do not define or list the “users, owners, and operators” that are 

required to follow the standard.19 The applicability of each standard needs to be 

clear. 

This assessment identifies staff’s preliminary observations and concerns regarding 

NERC’s current standards. It begins by reviewing the issues common to a number of the 

 17 Representative examples are contained in the chapters pertaining to Modeling, Data and 

Analysis and to Resource and Demand Balancing. 

18 Representative examples are contained in the chapters pertaining to Modeling, Data and 

Analysis, Resource and Demand Balancing, and Protection and Control. 

19 Representative examples are contained in the chapters pertaining to Data and Analysis, 

Transmission Planning, and Protection and Control. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 8 - 

Executive Summary 

standards. Following the discussion of these common issues, this assessment includes 

chapters devoted to each category of standards as defined in NERC’s petition. Each 

chapter examines the primary issues within the category in question as well as a specific 

analysis of each standard in that category. 

Next Steps and Challenges Ahead 

Staff recognizes the goal of the Commission to establish sound and enforceable 

Reliability Standards as soon as practicable, consistent with the statutory requirements of 

FPA section 215. Staff understands the limits of Commission authority, in particular, that 

it cannot directly modify the proposed Reliability Standards in the course of its approval 

review process. FPA section 215 authorizes the Commission to remand or approve the 

Reliability Standards. It is our view, however, that included within the Commission’s 

approval authority is the discretion to conditionally approve standards or to make some 

form of interim approval in order to provide some assurances of reliability while NERC 

has an opportunity to improve the standard in question. Staff also acknowledges that 

FPA section 215 requires the Commission to give “due weight” to the technical expertise 

of the ERO with respect to the content of a proposed Reliability Standard and therefore 

presents this document in the context of a technical review for public comment. In order 

to determine whether the proposed standards meet the statutory criteria, while giving due 

weight to the technical expertise of the ERO, we are soliciting comments on our 

preliminary assessment. Once the Commission has reviewed these comments, it will 

issue a Notice of Proposed Rulemaking that proposes to approve those standards that 

meet the statutory criteria and, as necessary, to remand or conditionally accept any 

standards that do not meet the statutory criteria. 

This preliminary assessment is the first step in an open process to establish technically 

sound and legally enforceable Reliability Standards that meet the statutory criteria in FPA 

section 215. The Commission initiated a rulemaking establishing the process for 

approving or remanding proposed Reliability Standards in part to assure the greatest 

possible degree of openness in the process. Undertaking the task by rulemaking allows 

us to have discussions with Canadian regulators, Mexican authorities, and State 

regulators; interested Federal Agencies; NERC; regional organizations; the industry; 

customers; and other stakeholders. 

The next step will be the technical conference, which will be announced at a future date. 

Following the conference, the Commission will propose a rule in which it will (1) 

approve those proposed Reliability Standards that meet statutory criteria, (2) approve for 

an interim period or conditionally approve proposed Reliability Standards, and (3) 

remand proposed Reliability Standards that are determined not to meet the statutory 

criteria. Opportunity for public comment will be available at each interval. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 9 - 

Executive Summary 

The Commission recognizes the difficulty of making the transition from a regime of 

voluntary standards to North American Reliability Standards that are both technically 

sound and legally enforceable. It also recognizes the practical limits on the ability of 

NERC, Regional Reliability Organizations (RROs), and industry to modify any reliability 

standards quickly. For that reason, our immediate focus is on those Reliability Standards 

that are most important to Bulk-Power System reliability. In particular, this will mean 

focusing on the proposed Reliability Standards that can be shown to affect the safety and 

security of the Nation through its Bulk-Power System. For example, staff is concerned 

that certain recommendations of the Blackout Report have not yet been fully 

implemented and we therefore seek comments on whether these recommendations should 

be given the highest priority by the Commission and the industry. To the extent proposed 

Reliability Standards may fall short of Commission criteria, our focus will be on 

identifying the flaws in such standards so that they can be improved to the point where 

they meet the criteria as soon as feasible and be approved by the Commission. 

Interested persons are invited to utilize this staff assessment of the current standards to 

inform their input to the Commission in its consideration of NERC’s petition for approval 

of proposed Reliability Standards. Staff agrees with NERC that a tremendous amount of 

work lies ahead “to achieve technically excellent reliability standards” for the BulkPower System in North America. In particular, staff is soliciting input from interested 

persons to help the Commission identify which standards deserve immediate industry 

attention and solutions, as well as suggestions for an appropriate plan for addressing the 

intermediate and longer term improvements which are necessary. With the shift to 

mandatory Reliability Standards, the Commission expects appropriate and timely 

improvements in the development and implementation of Reliability Standards necessary 

to protect the Bulk-Power System and has provided appropriate programs by which to 

evaluate this objective.20

 20 For example, the ERO must affirmatively demonstrate to the Commission at the end of the first 

three-year period, and every five years thereafter, that it can develop and enforce reliability standards and 

that it is improving the quality of its activities and those of the Regional Entities to which the ERO has 

delegated such activities. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 10 - 

II. BACKGROUND/PURPOSE 

A. Background 

Before NERC was formed, reliability of the interconnected electric grid was managed by 

the planning and operating criteria, guidelines, and policies of individual electric utilities 

and groups of interconnected utilities. Operating policies were then expanded to larger 

areas and international scale under the auspices of the North American Power Systems 

Interconnected Committee, which was formed in 1962, and ultimately merged with 

NERC in 1980. 

Shortly after the Northeast Blackout of 1965, Regional Reliability Organizations (RRO)21

started to form in the Northeastern United States and Ontario, Canada. In 1968, the 

electric utility industry established NERC to coordinate the RROs’ activities and to 

ensure reliability of the electricity supply in North America. By the mid-1990s, NERC 

began to develop planning standards through a committee system of industry 

representatives.22 During this transition, utilities continued to use and maintain their 

planning policies in conjunction with the development of standards by NERC.23 

In June 2002, the NERC Board of Trustees approved adoption of an open stakeholder 

process for the development of reliability standards and NERC was accredited by the 

American National Standards Institute (ANSI) in March of 2003. NERC planned to 

revise or develop each standard individually using the ANSI process. However, with the 

occurrence of the August 2003 blackout, NERC accelerated its efforts and developed as a 

group the Version 0 standards as a translation of many of NERC’s existing operating 

policies, planning standards and compliance templates.24 

NERC’s reliability standards currently consist of 102 separate standards and a glossary, 

which are organized by topic in 14 categories. Together the standards cover a wide range 

 21 A Regional Reliability Organization (RRO) is a regional entity of NERC that ensures that a 

defined area of the Bulk Electric System is reliable, adequate, and secure. There are currently eight 

NERC regions with eight corresponding RROs. 

22 North American Electric Reliability Council, NERC Planning Standards (1997). 

23 Jurisdictional utilities file their Transmission Planning Reliability Criteria (i.e., their planning 

policies), with the Commission as Part 4 of FERC Form No. 715. Staff notes that most utilities’ Criteria 

are more robust than NERC’s planning standards. 

24 See Blackout Report at 161 (NERC’s change in plans was based on Recommendation Number 

25, which suggested accelerating the adoption of enforceable standards). 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 11 - 

Chapter: Background 

of reliability issues – from transmission planning and operations to communications and 

emergency preparedness.25

Each NERC standard follows a consistent format: 

 A. Introduction 

1. Title: a phrase that describes the topic of the standard. 

2. Number: A unique identification number that starts with three letters to identify the group 

followed by a dash and then three digit number followed by a dash and the version number 

e.g., PRC-014-0. 

3. Purpose: One or more sentences that explicitly states the outcome to be achieved by the 

adoption of the standard. 

4. Applicability: 

4.1. Which entity, as defined by the Functional Model, must comply with the 

standard, such as Transmission Owner. 

5. Effective Date: The date that the standard becomes effective in terms of audits and 

compliance. 

 B. Requirements 

R1. A listing of explicitly stated technical, performance and preparedness requirements and 

who is responsible for achieving them. 

 C. Measures 

M1. A listing of the factors used to assess performance and outcomes in order to determine 

compliance, and who is responsible for achieving the measures. 

 D. Compliance 

1. Compliance Monitoring Process 

1.1. Compliance Monitoring Responsibility: Who is responsible for assessing 

performance or outcomes?

1.2. Compliance Monitoring Period and Reset Timeframe: What is the timeframe 

for each compliance monitoring period before it is reset for the next period? 

1.3. Data Retention: How long does the compliance documentation need to remain 

on file?

1.4. Additional Compliance Information: Any other information.

2. Levels of Non-Compliance: Usually four levels of non-compliance are identified with 

level 1 being used for the least severe non-compliance and level 4 for the most severe non-

 25 The categories are: Resource and Demand Balancing; Critical Infrastructure Protection; 

Communications; Emergency Preparedness and Operations; Facilities Design, Connections and 

Maintenance; Interchange Scheduling and Coordination; Modeling, Data, and Analysis; Organization 

Certification; Personnel Performance, Training, and Qualifications; Protection and Control; Transmission 

Operations; Transmission Planning; and Voltage and Reactive. The Organization Certification category 

does not contain any standards and was therefore not reviewed. Standards that have been adopted by 

NERC and those under development are available at www.nerc.com. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 12 - 

Chapter: Background 

compliance. 

 E. Regional Differences: Identification of any Regional differences that have been approved by 

the applicable NERC Committee (including Regions that are exempt). 

 Version History: The chronological history of changes to the standard.

B. August 2003 Blackout 

On August 14, 2003, an electrical outage in Ohio precipitated a cascading blackout across 

seven other states and as far north as Ontario, leaving more than 50 million people 

without power.26 The August 2003 blackout was the largest blackout in the history of the 

United States, leaving some parts of the nation without power for up to four days and 

costing between $4 billion and $10 billion.27 The 2003 blackout was the eighth major 

blackout experienced in North America since the 1965 Northeast Blackout. 

On August 15, 2003, President George W. Bush and then-Prime Minister Jean Chrétien 

directed the creation of a Joint U.S.-Canada Power System Outage Task Force to 

investigate the causes of the blackout and ways to reduce the possibility of future 

outages. The U.S.-Canada Task Force convened, investigated the causes of this blackout, 

and recommended actions to prevent future widespread outages. 

The Task Force issued a final Blackout Report in April 2004 with 46 specific 

recommendations to address the primary causes to help prevent or minimize the scale of 

future blackouts. These included a recommendation to “make reliability standards 

mandatory and enforceable, with penalties for noncompliance,”28 as well as specific 

recommendations to change some existing reliability standards. 

In addition, the Blackout Report identified eight factors that were common to some of the 

eight major outage occurrences from the 1965 Northeast Blackout through the 2003 

Blackout, as shown below: 

 26Blackout Report at 1. 

27 Id.

28 Id. at 140 (the Task Force made 46 recommendations urging improvements to: enhance the 

situational awareness of operators; establish training and certification requirements for operators, 

reliability coordinators, and operator support staff; upgrade the effectiveness of internal and external 

communications during alerts, emergencies and other critical situations; and improve vegetation 

management). 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 13 - 

Chapter: Background 

(1) conductor contact with trees; (2) overestimation of dynamic reactive 

output of system generators; (3) inability of system operators or 

coordinators to visualize events on the entire system; (4) failure to ensure 

that system operation was within safe limits; (5) lack of coordination on 

system protection; (6) ineffective communication; (7) lack of “safety nets;” 

and (8) inadequate training of operating personnel.[29]

The Blackout Report also listed recurring recommendations to address these common 

factors from these previous blackout investigations. 

C. EPAct 2005 and Order No. 672 

In EPAct 2005, Congress entrusted the Commission with the responsibility of reviewing 

and approving mandatory reliability standards that meet certain statutory criteria. EPAct 

2005 sets forth this charge in a new section 215 to the Federal Power Act (FPA) by 

requiring the Commission to issue a rule detailing the process for certifying an entity as 

the ERO and for establishing and maintaining mandatory Reliability Standards. Section 

215 of the FPA includes specific criteria that an entity must satisfy in order to be certified 

as the ERO by the Commission.30 In addition to outlining the certification process, 

section 215 provides that the ERO will develop mandatory, enforceable Reliability 

Standards, subject to Commission approval. 

To qualify as the ERO, an applicant must demonstrate, inter alia, that it has the ability to 

develop and enforce Reliability Standards that provide for “an adequate level of 

reliability of the bulk-power system.”31 According to the statute, the Commission may 

approve a proposed Reliability Standard that it determines to be just, reasonable, not 

unduly discriminatory or preferential, and in the public interest.32 The Commission may 

also remand a proposed Reliability Standard and may call for the ERO to develop a new 

standard, or for the revision of an existing Reliability Standard. If approved, a Reliability 

Standard is mandatory for the particular users, owners and operators of the Bulk-Power 

System identified in the Reliability Standard. An approved Reliability Standard is 

enforceable by the ERO, a Regional Entity that has been delegated enforcement 

authority, and/or the Commission. 

 29 Id. at 107. 

30 Section 215(c) of the FPA. 

31 Section 215(c)(1) of the FPA. 

32 Section 215(d)(2) of the FPA. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 14 - 

Chapter: Background 

On February 3, 2006, the Commission issued Order No. 672, which implements section 

215 of the FPA. Order No. 672, among other things, sets forth procedures under which 

the ERO may propose a new or modified Reliability Standard for Commission review. In 

addition, Order No. 672 provides guidance regarding certain factors the Commission will 

consider when determining whether a proposed Reliability Standard satisfies the statutory 

standard of review.33

According to this guidance, a proposed Reliability Standard must provide for the reliable 

operation of Bulk-Power System facilities. A proposed Reliability Standard may impose 

a requirement on any user, owner, or operator of such facilities. It must be designed to 

achieve a specified reliability goal and must contain a technically sound means to achieve 

this goal. The proposed Reliability Standard should be clear and unambiguous regarding 

what is required and who is required to comply. The possible consequences for violating 

a proposed Reliability Standard should be clear and understandable to those who must 

comply. There should be a clear criterion or measure of whether an entity is in 

compliance with a proposed Reliability Standard. While a proposed Reliability Standard 

does not necessarily have to reflect the optimal method for achieving its reliability goal, a 

proposed Standard should achieve its reliability goal effectively and efficiently. A 

proposed Reliability Standard must do more than simply reflect stakeholder agreement or 

consensus around the “lowest common denominator.” It is important that the Standards 

developed through any consensus process be sufficient to adequately protect Bulk-Power 

System reliability. 

A proposed Reliability Standard may take into account the size of the entity that must 

comply and the costs of implementation for a proposed Reliability Standard. However, 

the ERO should not propose standards that would achieve less than operational 

excellence or are otherwise inadequate to support the Bulk-Power System. A proposed 

Reliability Standard should be a single Standard that applies across the North American 

Bulk-Power System to the maximum extent this is achievable taking into account 

geographic variations in grid characteristics, terrain, weather, and other factors. It should 

also account for regional variations in the organizational and corporate structures of 

transmission owners and operators, variations in generation fuel type and ownership 

patterns, and regional variations in market design if these affect the proposed Reliability 

Standard. A proposed Reliability Standard should have no undue negative effect on 

competition. 

The timetable for implementation of a proposed Reliability Standard will also be 

considered, including how a proposal balances any urgency in the need for 

 33 See Order No. 672 at P 320-36. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 15 - 

Chapter: Background 

implementation against the reasonableness of the time allowed for those who must 

comply, along with the time needed for Canadian and Mexican authorities to act.34 The 

Commission will consider whether the ERO followed its Commission-approved 

Reliability Standards development process. Further, should the ERO balance a particular 

reliability goal against other public interests, the Commission will expect an explanation 

for such balancing to be a part of the Standard proposal. Finally, it is worth noting that 

section 1241 of EPAct 2005 specifically provides that the Commission shall establish by 

rule transmission rate recovery mechanisms which “allow recovery of all prudently 

incurred costs necessary to comply with mandatory reliability standards issued pursuant 

to section 215 . . . .”35 

D. Subject, Purpose and Commission Context for this Review 

The Commission recognizes the significance of Congress’ mandate that it oversee 

reliability of the Bulk-Power System. At the direction of Chairman Kelliher, in the fall of 

2005, the Division of Reliability initiated this preliminary technical assessment of the 

current NERC voluntary reliability standards. Staff anticipates that this review will assist 

in developing a more complete record concerning the Petition for Approval of Reliability 

Standards that NERC filed on April 4, 2006. This review reflects staff’s present 

understanding of the standards and does not reflect Commission policy. It does not make 

recommendations for Commission action regarding the standards, nor does it make 

recommendations to NERC. Rather, the review identifies issues raised by NERC’s 

existing voluntary standards in light of the statutory mandate to develop a comprehensive 

plan for mandatory Reliability Standards. This review will initiate an open and inclusive 

process by which all interested persons can comment on the adequacy of the existing 

standards and the process for improving them over time. 

This assessment examines NERC’s standards in chapters, grouping similar standards as 

NERC has done. Each NERC category has a corresponding chapter in this assessment. 

Each chapter examines general issues within that standards group and primary issues 

presented by the group. It then analyzes each standard within the group. 

The staff’s examination of NERC’s standards is comprehensive in the sense that all of 

NERC’s current standards were evaluated. However, this assessment is not exhaustive in 

that the issues highlighted by staff are only those deemed most significant and do not 

 34 Id. at P 409. 

35 Section 219(b)(4)(A) of the FPA. See also Order No. 672 at P 259. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 16 - 

Chapter: Background 

necessarily reflect every issue identified in every standard. Appendix A lists the specific 

standards reviewed in this assessment. 

This assessment identifies staff’s present observations and concerns regarding NERC’s 

current standards. Staff also anticipates that this assessment will generate input on the 

standards from industry, states, government agencies and the public. As stated in the 

title, this is a preliminary assessment of staff; we expect the analysis to evolve and that 

the Commission’s understanding of these issues will benefit from additional public 

comment in the proposed rulemaking proceeding. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 17 - 

III. COMMON ISSUES 

This chapter discusses the issues that recur across the topical categories of the NERC 

standards, as determined by this staff review of NERC’s Version 0 and Version 1 

standards, including the accompanying Glossary of Terms Used in Reliability Standards. 

This overview provides context for the further assessment of a given topical group or 

individual standard in subsequent chapters. 

A. Blackout Report Recommendations 

The August 2003 blackout was of a magnitude not previously experienced in North 

America. In total, over 50 million citizens lost power at a loss of 4 to 10 billion dollars. 

In its wake, the United States and Canada, and their respective utility industries, 

undertook an unprecedented coordinated investigation into the causes of the blackout. 

The President of the United States and the Prime Minister of Canada directed that a Joint 

U.S.-Canada Power System Outage Task Force be established. The Task Force 

undertook an analysis to identify the primary cause of the blackout and to develop 

recommendations to prevent or minimize the scope of future blackouts. 

The Blackout Report provided 46 specific recommendations to improve reliability based 

on the lessons learned from the August 14, 2003 blackout and seven previous major 

outages dating back to 1965. Thirteen of the Blackout Report recommendations address 

the NERC reliability standards that were in effect on a voluntary basis at the time of the 

Blackout Report. To implement these 13 recommendations, specific provisions in 22 

standards would be required in the areas of: emergency operations; vegetation 

management; operating personnel training; protection systems and their coordination; 

operating tools and backup facilities; reactive power and voltage control; system 

modeling and data exchanges; communications protocols and facilities; requirements to 

determination of equipment ratings; synchronized data recorders; clearer criteria for 

operationally critical facilities; and appropriate use of Transmission Loading Relief 

Process. 

Following issuance of the Blackout Report, NERC and the industry have been working to 

implement recommendations. Progress has been made and the process continues. NERC 

further explains the progress made to implement the Blackout Report recommendations 

in its standards petition. 

Despite this progress, however, the reliability standards (both Version 0 and Version 1) 

continue to reflect several of the deficiencies identified by the Blackout Report. For 

example, the Blackout Report found that “deficiency in training contributed to the lack of 

situational awareness and failure to declare an emergency on August 14 while operator 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 18 - 

Chapter: Common Issues 

intervention was still possible (before events began to occur at a speed beyond human 

control).”36 The Task Force therefore recommended that the standards contain 

requirements for formal training programs, including specified minimum training 

requirements (Recommendation Number 19). However, the reliability standards do not 

fully implement this recommendation. Although Personnel Performance standards PER002 to PER-004 set forth broad objectives that a training program must satisfy, they do 

not specify the minimum expectations of a training program or the minimum number of 

hours of training (other than a requirement of five days per year for realistic simulation 

training) consistent with the roles, responsibilities and authorities of operating and 

support personnel. Therefore, the nature, objective, and criteria of operator training 

programs and minimum hours of training are open to interpretation. This lack of 

specificity allows programs to vary widely with each Transmission Operator or 

Balancing Authority and still comply with the standards. 

There are other areas in which the reliability standards do not fully reflect the 

recommendations of the Blackout Report. For example, staff is concerned that, although 

the industry developed a vegetation management standard to implement Blackout Report 

Recommendation Number 16, the minimum electrical clearance portion of that standard 

is sufficiently low that it may not be adequate to maintain reliability or otherwise protect 

public safety. Staff also is concerned that, although the Blackout Report recommended 

the development of uniform and consistent methodologies for transmission line and 

equipment ratings (Recommendation Number 27), the reliability standards do not yet 

include such a requirement. The Blackout Report also recommended that transmission 

line loading relief (TLRs) not be used in situations involving an actual violation of a SOL 

or IROL (Recommendation Number 31), but the standards do not yet reflect this 

recommendation. We identify other areas as well in which the Blackout Report 

recommendations may not have been fully implemented in the current reliability 

standards. 

Staff seeks comment on whether and, if so, how the reliability standards should be 

reformed to fully address the recommendations of the Blackout Report. 

B. Ambiguities and Potential Multiple Interpretations 

Various elements of numerous standards appear to be subject to multiple interpretations, 

especially with regard to the lack of specificity in the standards’ requirements, 

measurability, and degrees of compliance. 

 36 Blackout Report at 157. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 19 - 

Chapter: Common Issues 

The Interconnection Reliability Operations and Coordination (IRO) standards are a good 

example of the potential for multiple interpretations and the resulting impact on the 

reliability of the interconnected grid. Standard IRO-005-0 states: 

If a potential or actual IROL violation cannot be avoided through proactive 

intervention, the Reliability Coordinator shall initiate actions or emergency 

procedures to relieve the violation without delay, and no longer than 30 

minutes.[37]

 

One interpretation of this Requirement allows an Interconnection Reliability Operating 

Limit (IROL) to be exceeded during normal operation (prior to a contingency) provided 

that corrective actions are taken within 30 minutes. Under this interpretation, if a single 

critical contingency38 occurs during this period – i.e., when IROL is exceeded but prior to 

completion of corrective actions – the interconnection could experience instability, 

uncontrolled separation or perhaps cascading outages. A more conservative 

interpretation of this Requirement would allow IROL to be exceeded only after a single 

critical contingency and with the expectation that the system must be returned to a secure 

condition as soon as possible, but no later than 30 minutes after the contingency occurs. 

This particular issue of variable interpretation in the IRO standards relating to IROL 

violations contributing to system instability also affects other standards such as TOP-004-

0 and TOP-007-0. 

C. Technical Adequacy 

At times, the Requirements (i.e., the technical performance and preparedness 

requirements for the various entities responsible for achieving them) specified in certain 

standards may not be sufficient to ensure an adequate level of reliability. While Order 

No. 672 notes that “best practice” may be an inappropriately high standard, it also warns 

that a “lowest common denominator” approach will be unacceptable if it is insufficient to 

ensure system reliability. Two examples of standards that may contain inadequate 

technical requirement elements follow below: 

Transmission Vegetation Management 

 37 North American Electric Reliability Council, Reliability Standards for the Bulk 

Electric Systems of North America, Standard IRO-005-0 (R3). 

38 The unexpected failure or outage of a system component, such as a generator, transmission 

line, circuit breaker, switch or other electrical element. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 20 - 

Chapter: Common Issues 

The Transmission Vegetation Management standard (FAC-003-1) requires a 

Transmission Owner to determine and document the minimum allowable clearance 

between energized conductors and vegetation before the next trimming. It specifically 

provides that “Transmission Owner-specific minimum clearance distances shall be no 

less than those set forth in the Institute of Electrical Engineers (IEEE) Standard 516-2003 

(Guide for Maintenance Methods on Energized Power Lines).39 However, IEEE 

Standard 516-2003 is intended for use as a guide by highly-trained maintenance 

personnel to carry out live-line work using specialized tools under controlled 

environments and operating conditions, not for those conditions necessary to safely carry 

out vegetation management practices.40 

The allowable clearances in the IEEE standard are significantly lower than those 

specified by the relevant U.S. safety codes. As such, use of IEEE clearance provision as 

a basis for minimum clearance prior to the next tree trimming as a Requirement in 

vegetation management may not be appropriate for safety and reliability reasons. For 

example, the IEEE Standard 516-2003 specifies a 2.45-foot clearance from a live 

conductor for the 120 kV voltage class,41 whereas the ANSI Z-133 standard specifies 12-

feet, 4-inches as the approach distance for the 115 kV voltage class.42 

Staff notes that some transmission owners currently use more stringent requirements and 

therefore, adopting the IEEE clearance provision for use with regular vegetation 

maintenance practices could be viewed as a “lowest common denominator” approach, 

about which the Commission expressed dissatisfaction in Order No. 672. Widespread 

implementation of this approach could inadvertently subject the public to safety hazards 

and the potential for multiple tree contacts under non-controlled conditions. In addition, 

use of the IEEE Standard 516-2003 could create unintended consequences that cause the 

transmission owners who currently maintain more stringent vegetation management 

programs based on standards such as the ANSI Z-133 to relax their practices to meet the 

less-stringent minimum requirement set forth in the NERC vegetation standard, exactly 

 39 North American Electric Reliability Council, Reliability Standards for the Bulk 

Electric Systems of North America, Standard FAC-003-1 (R1.2.2). 

40 Controlled environments and operating conditions include clear days without precipitation, 

high winds, or lightning. 

41 Institute of Electrical and Electronics Engineers, Inc. (IEEE) Standard 516-2003, IEEE Guide 

for Maintenance Methods at 20. 

42 ANSI Z133, American National Standards Institute Standard for Tree Care Operations – 

Pruning, Trimming, Repairing, Maintaining and Removing Trees, and Cutting Brush – Safety 

Requirements. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 21 - 

Chapter: Common Issues 

the opposite result intended by EPAct 2005 and FPA section 215. As a result, the danger 

could exist that increased amounts of vegetation will become vulnerable to tree contact, 

the initial trigger point of the August 2003 blackout. Staff is not necessarily 

recommending use of the ANSI Z-133 standard as the minimum standard; however, we 

seek comment on whether the IEEE standard is sufficient to maintain reliability and 

protect public safety and, if not, what modifications to that standard should be made or 

whether an alternative standard is required to satisfy Order No. 672. 

Transmission Planning 

The Transmission Planning standards also provide an illustration of standards that may be 

inadequate from a technical perspective. These standards contain technical deficiencies, 

vague language that could be subject to multiple interpretations. For example, Standard 

TPL-002-0 requires a Planning Authority and Transmission Planner to demonstrate that 

its portion of the interconnected transmission system can meet projected customer 

demands and projected firm transactions while capable of withstanding the Category B 

contingencies. 

The TPL Category B contingencies only include loss of a single element, defined as a 

generator, transmission circuit, transformer, or single DC pole with or without a fault. 

This definition does not cover all of the single element failures that are known to occur in 

actual operation. The unanticipated failure of some single elements in the Bulk-Power 

System can result in the loss of multiple elements. Because of the resulting impact on 

reliability of the loss of more elements than those defined in Category B, some Regions 

base their groupings according to the event, irrespective of the number of elements forced 

out of service.43 For such a Region, a single event that results in the loss of multiple 

elements (e.g., a relay failure that forces a DC bi-pole out of service or a lightning strike 

that simultaneously forces both circuits of a double circuit tower line out of service) are 

grouped alongside those events which would result in loss of single elements, such as a 

generator, transmission circuit or transformer, in essence providing a more stringent level 

of reliability. 

With such variation in criteria, what is acceptable in one Region is not acceptable in 

another Region for reasons related to historical adoption of reliability criteria and 

practices rather than geography or system topology. The result could be that some 

Regions have differentiated and higher standards than others.

 43 See, e.g., NPCC criteria A1 Document. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 22 - 

Chapter: Common Issues 

D. Measures and Levels of Non-Compliance 

The Measures in the standards specify the criteria that are used to determine if an entity is 

in compliance with the NERC standard. The Levels of Non-Compliance establish criteria 

for determining the severity of a violation of the standard. However, these sections are 

nonexistent or incomplete in many standards, either of which could contribute to varying 

interpretation of whether violations have occurred and the severity of the violation. 

Recognizing this, NERC has proposed to add Measures or Levels of Non-Compliance to 

21 of the standards in November 2006. We commend NERC for undertaking this effort. 

This report nonetheless identifies the standards that lack Measures or Levels of NonCompliance because these standards have been submitted for Commission approval 

without such specificity. 

Of the current NERC standards, staff found that 26 standards do not contain any 

Measures, or do not contain Levels of Non-Compliance, or lack provisions in both 

categories.44 Some standards have Measures but do not have Levels of Non-Compliance. 

For example, the Frequency and Response Bias standard (BAL-003-0) has a Measure 

requiring Balancing Authorities to perform Frequency Response surveys, but it does not 

have any Levels of Non-Compliance to identify the severity of a violation or to otherwise 

facilitate enforcement. 

Mandatory Reliability Standards should contain Measures that address each Requirement. 

The Standards should also contain Levels of Non-compliance that address all of the 

Measures. In addition, they would be more complete and less subject to variable 

implementation if they included use of performance metrics, where applicable. 

Performance metrics provide a vehicle to gauge the effectiveness of the standards. 

Performance metrics can be used to assess the overall reliability of the Bulk-Power 

System, monitor trends and to determine whether improvements are required in the 

standards. A few reliability standards already do include such performance metrics, but 

there is potential for many more to do so. 

The Levels of Non-Compliance sections are meant to facilitate enforcement and 

generally address the severity of violations of a standard and depend on factors such as 

the degree of impact on reliability and the frequency of instances of non-compliance. For 

example, in the recently approved standard on Transmission Vegetation Management 

Program, there are three Levels of Non-Compliance ranging from whether the 

Transmission Vegetation Management Program has all necessary documentation to meet 

 44 Appendix C identifies each standard’s retention of Measures or Levels of Non-Compliance. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 23 - 

Chapter: Common Issues 

the Requirements to the number of transmission outages due to tree contracts.45 This 

element is a good example of striving to improve reliability by setting the performance 

metric of the number of transmission outages due to tree contacts to near zero. However, 

as explained above, some standards do not provide any Levels of Non-Compliance, and 

not all standards identify such performance metrics even when they contain Levels of 

Non-Compliance. 

Measures and Levels of Non-Compliance are essential to the enforcement of the 

proposed mandatory Reliability Standards. Staff notes that if Measures and Levels of 

Non-Compliance are unclear in the standard, the standard may not be enforceable. Staff 

further notes that the NERC Compliance Penalties and Sanctions Task Force plans to 

address the lack of penalties and sanctions in the standards.46

E. Fill-in-the-Blank Standards 

In the context of the mandatory Reliability Standards required by section 215 of the FPA, 

fill-in-the-blank standards raise two principal concerns: (i) they are not enforceable 

against users, owners and operators of the grid, but rather only provide broad direction to 

RROs; and (ii) the specific implementing standards adopted by the RROs have not 

undergone an approval process under section 215 and hence cannot themselves be 

enforced by the Commission or ERO. 

In its petition, NERC identifies a total of 39 standards it refers to as “fill-in-the-blank” 

standards, according to any of the three sets of qualifying conditions it describes.47 In 

this assessment, staff identifies 28 standards48 as “fill-in-the-blank” standards which have 

the RRO’s as either the only entity or one of the entities identified in the Applicability 

section. Staff’s concern with these standards is their unclear enforceability under section 

215 of the FPA for those that apply only to an RRO. This issue is more fully discussed in 

section (F) Applicability of NERC Standards below. We are specifically soliciting 

comments on the applicability of standards to an RRO in the context of NERC defined 

“fill-in-the-blank” standards. 

 45 See North American Reliability Council, Reliability Standards for the Bulk Electric Systems of 

North America, Standard FAC-003-1. 

46 See NERC ERO Implementation Task Group Assignment, Compliance Penalties and Sanctions 

Task Force, available at http://www.nerc.com/~bot/cpstg.html. 

47 Petition at 87-89. 

48 Appendix B: Standards with Unclear Enforceability Under EPACT 2005. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 24 - 

Chapter: Common Issues 

In its petition, NERC describes a working plan to evaluate the fill-in-the-blanks standards 

and to modify, replace or withdraw them in an effort to allow the ERO Reliability 

Standards to become fully enforceable.49 NERC states: 

In the future, no standards will be developed that require entities to follow 

regional reliability organization criteria or procedures, unless such criteria 

or procedures are approved by the ERO and the Commission. Additionally, 

NERC will be working with the regions to achieve greater consistency of 

requirements across the regions.[50]

 

NERC acknowledges and staff agrees that fill-in-the-blank standards will require 

significant work by the ERO, Regional Entities, and others in the industry to satisfy the 

requirements of section 215 of the FPA. NERC has developed a proposed timetable to 

address these issues. 

F. Applicability of the NERC Standards 

Section 215(b) of the FPA requires all “users, owners and operators of the Bulk-Power 

System” to comply with Commission-approved Reliability Standards. Each current 

NERC standard identifies entities to which the standard applies based on the NERC 

Functional Model. This model omits the categories of users, owners and operators, and it 

includes other categories of entities that are not users, owners or operators. These 

differences must be reconciled for a given proposed Reliability Standard in order to make 

it technically sound and legally enforceable. 

In Order No. 672, the Commission stated: 

The proposed Reliability Standard should be clear and unambiguous 

regarding what is required and who is required to comply. Users, owners, 

and operators of the Bulk-Power System must know what they are required 

to do to maintain reliability.[51]

Accordingly, each Reliability Standard must be explicit as to which entity it applies. 

However, the Applicability sections of the standards are not always sufficiently specific 

to be clear and unambiguous about the applicability of the standard. One problem with 

 49 Petition at 89. 

50 Id. at 89-90. 

51 Order No. 672 at P 325. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 25 - 

Chapter: Common Issues 

this lack of clarity occurs when a given type of entity may perform more than one of the 

functions covered by the standard depending on the circumstances. 

G. Systems to Which the Standards Apply: Bulk Electric System v. BulkPower System 

The differences between the definition of Bulk-Power System in section 215 of the FPA 

and the definition of Bulk Electric System found in the NERC Glossary upon which the 

NERC standards rely, create a problematic discrepancy that could create reliability gaps. 

This discrepancy, if left unaddressed, will interfere with maintaining reliability 

consistently across the Regions and may be inconsistent with Order No. 672. This gap 

could allow for some interconnected electric energy transmission networks, and electric 

energy from generating facilities needed to maintain transmission system reliability to be 

outside of the mandatory Standards. 

The NERC Glossary defines the Bulk Electric System as follows: 

As defined by the Regional Reliability Organization, the electrical 

generation of resources, transmission lines, interconnections with 

neighboring systems, and associated equipment, generally operated at 

voltages 100 kV or higher. Radial transmission facilities serving only load 

with one transmission source are generally not included in this 

definition.[52]

 

When the task of defining the Bulk Electric System is delegated to each RRO, the result 

could be conflicting multiple definitions that subject different facilities to, or exclude 

different facilities from, the requirements of the standards. 

Further, section 215(a)(1) defines Bulk-Power System as: 

Facilities and control systems necessary for operating an interconnected 

electric energy transmission network (or any portion thereof), and electric 

energy from generating facilities needed to maintain transmission system 

reliability. The term does not include facilities used in the local distribution 

of electric energy.[53]

 

 52 NERC Glossary of Terms Used In Reliability Standards at 2 (effective April 1, 2005) 

(emphasis added). 

53 Section 215(a)(1) of the FPA.
FERC Staff Preliminary Assessment of NERC Reliability Standards - 26 - 

Chapter: Common Issues 

The FPA and NERC definitions obviously differ. The standards currently are applied 

only to the Bulk Electric System as defined by each Region. However, section 215(a)(3) 

of the FPA defines Reliability Standard as a requirement approved by the Commission to 

provide for reliable operation of the Bulk-Power System. The term Bulk Electric System 

does not appear to include all the system components from all non-distribution voltage 

levels, control systems, and electric energy from all generating facilities needed to 

maintain transmission system reliability included in the definition of Bulk-Power System. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 27 - 

IV. BAL: RESOURCE AND DEMAND BALANCING 

A. Description and General Issues 

NERC has six Resource and Demand Balancing (BAL) standards aimed at Balancing 

Authorities, Reliability Coordinators, RROs, Reserve Sharing Groups, Generator 

Operators, Transmission Operators, and Load Serving Entities.54 These standards state 

the requirements to balance generation and load in order to maintain frequency of the 

Bulk-Power System within limits. 

In general, the Measures, Compliance, and Requirements aspects of these standards may 

lead to different interpretations and inconsistent application. Of the six standards in this 

group, four do not list any criteria or factors to assess compliance with the Requirements 

or Levels of Non-Compliance that are required for the determination of enforcement 

penalties. In addition, one standard leaves the determination of actual Requirements to 

the RROs, leading to regional variations. 

Below is a discussion of the primary issues of concern to staff, followed by an evaluation 

of individual standards in the context of these observations. 

B. Primary Issues in the Resource and Demand Balancing Standards 

1. Contingency Reserve Requirements 

Contingency reserves are needed to compensate for the loss of generation resources so 

that the system frequency can be returned to 60 Hz. Specific Requirements concerning 

the composition of the reserves and the restoration time are left to Regions and subRegions to determine. For example, the following determinations are all left to 

individual Regions, sub-Regions, and Reserve Sharing Groups to make: the minimum 

reserve Requirement, the permissible mix of spinning and non-spinning operating reserve 

that may be included in Contingency Reserve, the procedure for applying Contingency 

Reserve in practice, any limitations on the amount of interruptible load, and what is 

counted toward spinning reserve. No specificity is provided concerning how these 

requirements are to be determined. Thus in some Regions large irrigation pumping and 

 54 The description of these entities, including their roles, tasks and relationships with other 

responsible entities are described in a document entitled “NERC Reliability Functional Model” that was 

approved by the Board of Trustees on February 10, 2004. There are three other relevant entities in 

addition to the entities identified above: Reliability Authority, Planning Authority and Resource Planner. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 28 - 

Chapter: BAL 

pumped hydro generation resources are permitted to be used as spinning reserve and in 

other Regions they are not. 

2. Actual Frequency Response (Bias) 

The frequency bias is a measure of the net power change for a 0.1 Hz change in 

frequency. The actual frequency bias is the net of the load frequency bias, which is 

mostly the result of the change in motor demand with changing frequency, and the 

generation frequency bias, which is a property of the type of generation and generator 

governor action. The actual bias will determine the post disturbance system frequency at 

which generation and load are again in balance. If the net bias is near zero, the postdisturbance frequency would settle to an unacceptably low and unstable level. 

Area Control Error (ACE)55 and the Control Performance Standards CPS1 and CPS256

are metrics that are used in gauging the performance of Balancing Authorities. Time 

Error Correction is a related metric but it is on an interconnection-wide basis. All of 

these metrics have Frequency Bias as one of their basic inputs. If the frequency bias 

used in the calculations is not the actual frequency bias, the metrics may not be 

measuring actual performance. 

Staff notes that the size of a disturbance resulting in a net power change that would 

produce a 0.1 Hz change in the frequency in both the Eastern and Western 

Interconnections has decreased over the last 10+ years.57 This is the opposite of what 

would be expected because each of the interconnections has grown in size. As the 

interconnections grow in size, it would be expected to take a larger disturbance and the 

resulting net power change to cause a 0.1 Hz frequency deviation. 

The use of an inappropriate frequency bias setting may have an adverse impact on 

reliability. While these standards contain a Requirement to recalculate the frequency bias 

setting for the Balancing Authority’s area annually, it also allows a default value of at 

 55 The instantaneous difference between a Balancing Authority’s net actual and scheduled 

interchange, taking into account the effects of Frequency Bias and correction for meter error. 

56 Control Performance Standard (CPS) is defined as the reliability standard that sets the limits of 

a Balancing Authority’s control error over a specified time period. The CPS1 has a time period of one 

minute and CPS2 has a time period of ten minutes. 

57 NERC Resources Subcommittee (Frequency Task Force), Frequency Response Standard 

Whitepaper (2004), at

http://www.nerc.com/pub/sys/all_updl/oc/rs/Frequency_Response_White_Paper.pdf. See also WECC 

Reserve Issues Task Force, Frequency Response Standard White Paper (2005), at

http://www.wecc.biz/documents/library/RITF/FRR_White_Paper_v12_1-27-06.pdf. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 29 - 

Chapter: BAL 

least 1% of the Balancing Authority’s estimated yearly peak demand per 0.1 Hz change.58

Use of a frequency bias setting that is different than the actual net physical bias of the 

Balancing Authority’s area could result in less control actions than are appropriate to 

preserve system reliability. 

Staff notes that the requirement to determine the minimum frequency bias required and 

how the frequency bias should vary with generation to assure the reliability of the BulkPower System is not covered in the standards. It is a topic of discussion in the NERC 

Resource Subcommittee and an issue in various white papers.59 

C. Concerns Specific to Individual Standards 

Real Power Balancing Control Performance (BAL-001-0) 

The purpose of this standard reads: “To maintain Interconnection steady-state frequency 

within defined limits by balancing real power demand and supply in real-time.” 

Staff notes that this standard provides metrics that are useful in determining the 

performance of individual Balancing Authorities and uses these metrics in determining 

the Levels of Non-Compliance. 

Disturbance Control Performance (BAL-002-0) 

The purpose of this standard reads: 

The purpose of the Disturbance Control Standard (DCS) is to ensure the 

Balancing Authority is able to utilize its Contingency Reserve to balance 

resources and demand and return Interconnection frequency within defined 

limits following a Reportable Disturbance. Because generator failures are 

far more common than significant losses of load and because Contingency 

Reserve activation does not typically apply to the loss of load, the 

application of the DCS is limited to the loss of supply and does not apply to 

the loss of load. 

 58 Frequency bias settings are available at 

ftp://www.nerc.com/pub/sys/all_updl/oc/opman/CPS2Bounds_2005.pdf 

59 NERC Resources Subcommittee (Frequency Task Force), Frequency Response Standard 

Whitepaper (2004), at

http://www.nerc.com/pub/sys/all_updl/oc/rs/Frequency_Response_White_Paper.pdf. See also WECC 

Reserve Issues Task Force, Frequency Response Standard White Paper (2005), at

http://www.wecc.biz/documents/library/RITF/FRR_White_Paper_v12_1-27-06.pdf. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 30 - 

Chapter: BAL 

Requirement R3.1 requires that a Balancing Authority or Reserve Sharing Group carry at 

least enough contingency reserves to cover the most severe single contingency.60 One 

interpretation of this requirement is that the most severe contingency is limited only to 

generation loss. However, a second, more stringent interpretation is that it can be applied 

to loss of supply which was the result of a transmission or generation contingency. 

Further, the minimum percentage of spinning reserve required as part of the contingency 

reserve is not defined in the standard but is at the discretion of each RRO. Not having a 

minimum requirement could result in an entity “leaning on the system,” which would 

result in an undue negative impact on competition. 

Various regions have different definitions as to which resources are eligible to be counted 

as spinning reserves. For example, in some regions large irrigation pumping and pumped 

hydro resources are permitted to be used as spinning reserves, and in other regions they 

are not. There should be a sound technical basis for any such difference. 

The standard states that a lower reporting threshold for the size of the minimum 

disturbance may be required by the RROs. To be enforceable, these lower reporting 

thresholds, along with their rationale, should be documented in the Regional Differences 

section. 

Frequency Response and Bias (BAL-003-0) 

The purpose of this standard reads: “To provide a consistent method for calculating the 

Frequency Bias component of ACE.” 

As discussed in section B2 above, the standard contains a Requirement to recalculate the 

frequency bias setting for the Balancing Authority’s area annually, it also allows a default 

value of at least 1% of the Balancing Authority’s estimated yearly peak demand per 0.1 

Hz change.61 Use of a frequency bias setting that is different than the actual net physical 

bias of the Balancing Authority’s area could result in less control actions than are 

appropriate to preserve system reliability. 

The Measure identified in the standard requires the Balancing Authority to conduct 

Frequency Response surveys, but only if specifically requested to do so by the NERC 

Operating Committee. Further, once the Frequency Response survey is completed, there 

 60 See Standard BAL-002-2 (R3.1). 

61 Frequency bias settings are available at 

ftp://www.nerc.com/pub/sys/all_updl/oc/opman/CPS2Bounds_2005.pdf 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 31 - 

Chapter: BAL 

is no requirement that the survey results be used to establish the Balancing Authority bias 

and there are no criteria or measures regarding how to apply the results of the survey. 

The standard does not contain any Levels of Non-Compliance. NERC has not identified 

this standard as one that would be modified and resubmitted for Commission approval in 

November, 2006. 

Time Error Correction (BAL-004-0) 

The purpose of this standard reads: “To ensure that Time Error Corrections are 

conducted in a manner that does not adversely affect the reliability of the 

Interconnection.” 

The standard does not contain Measures to assure that all Balancing Authorities and 

Reliability Coordinators participate in achieving Time Error Corrections. Data from the 

NERC time error web page indicates that the efficiency of the Time Error Correction has 

significantly decreased over the last ten years.62 Incomplete participation in time error 

correction can be measured by using this data. Participation in Time Error Correction 

requires change in generation output. 

The standard does not contain any Compliance Measures or any Levels of NonCompliance. NERC has not identified this standard as one that would be modified and 

resubmitted for Commission approval in November 2006. 

Automatic Generation Control (BAL-005-0) 

The purpose of this standard reads: 

To establish requirements for Balancing Authority Automatic Generation 

Control (AGC) necessary to calculate Area Control Error (ACE) and to 

routinely deploy the Regulating Reserve. The standard also ensures that all 

facilities and load electrically synchronized to the interconnection are 

included within the metered boundary of a Balancing Area so that 

balancing of resources and demand can be achieved. 

One reliability goal of this standard is to assure that all the load and the generation within 

the Balancing Authority’s boundary are balanced as measured by the ACE calculation. A 

 62 NERC, Time Error Reports, at http://www.nerc.com/~filez/timerror.html. Yearly data for total 

efficiency was 117 percent for 1996 and 65 percent for 2005. The calculation of efficiency by NERC in 

time error correction is the actual time change divided by the expected time change. If there is more 

participation than expected, the efficiency can be greater than 100 percent. The goal is to be near 100 

percent efficiency. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 32 - 

Chapter: BAL 

second reliability goal is to assure that all generation and load is under the control of a 

Balancing Authority. The technical solution to this goal is to have control over adequate 

amounts and types of generation reserves and controllable load management resources.63 

Staff notes that this standard does not require either Generation Operators or LoadServing Entities to provide AGC capabilities to the Balancing Authority. There is no 

requirement on how much AGC they must have at all times, or any subsequent 

verification process. This is a concern because there may not be adequate resources to 

maintain system frequency close to 60 Hz. Operation of the Bulk-Power System 

significantly different from the 60 Hz level can result in unintentional loss of firm load 

and generation resources. 

The standard does not contain any Compliance Measures or any Levels of NonCompliance. NERC has not identified this standard as one that would be modified and 

resubmitted for Commission approval in November 2006. 

Inadvertent Interchange (BAL-006-0) 

The purpose of this standard reads: 

To define a process for monitoring Balancing Authorities to ensure that, 

over the long term, Balancing Authority Areas do not excessively depend 

on other Balancing Authority Areas in the Interconnection for meeting their 

demand or Interchange obligations. 

The standard includes specifications for reporting requirements, but no requirements to 

prevent a Balancing Authority from depending excessively on other Balancing 

Authorities over time. Data available from the NERC website indicates that the 

magnitudes of inadvertent interchange for some RROs in the Eastern Interconnection are 

increasing.64 

The standard includes a single Level of Non-Compliance that is triggered if a Balancing 

Authority fails to report its inadvertent interchange by the 20th calendar day of the 

following month. There are no specific Measures in the standard concerning the 

reliability impact of large inadvertent interchange balances. NERC has not identified this 

 63 NERC Resources Subcommittee (Frequency Task Force), Frequency Response Standard 

Whitepaper (2004), at

http://www.nerc.com/pub/sys/all_updl/oc/rs/Frequency_Response_White_Paper.pdf. See also WECC 

Reserve Issues Task Force, Frequency Response Standard White Paper (2005), at

http://www.wecc.biz/documents/library/RITF/FRR_White_Paper_v12_1-27-06.pdf. 

64 NERC, Inadvertent Interchange, at http://www.nerc.com/~filez/inadv.html. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 33 - 

Chapter: BAL 

standard as one that would be modified and resubmitted for Commission approval in 

November 2006. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 34 - 

V. CIP: CRITICAL INFRASTRUCTURE PROTECTION 

A. Description and General Issues 

The Critical Infrastructure Protection group of reliability standards, as filed, consists of 

two standards aimed at establishing security for critical cyber assets and reporting 

occurrences of sabotage to the proper authorities. The first standard is CIP-001-0 

Sabotage Reporting. The second standard is Urgent Action 1200 (UA-1200), which 

addresses the cyber security of bulk electric system assets. This group of standards 

applies to Reliability Coordinators, Balancing Authorities, Interchange Authorities, 

Transmission Service Providers, Transmission Operators, Generation Operators and 

Load-Serving Entities. The UA standard also applies to Interchange Authorities where 

appropriate. 

In general, staff has concerns regarding measures, compliance, technical requirements 

and interpretation. CIP-001-0 does not include criteria or Measures to assess compliance 

with the Requirements of the standard or Levels of Non-Compliance that are required for 

enforcement. NERC has indicated that this standard will be modified to address this 

deficiency and resubmitted for Commission approval in November 2006. 

UA-1200, which relates to cyber security, provides some measures of compliance. 

However, these measures more often address the development or maintenance of 

documentation than the adequacy of the methods used or steps taken. A strong security 

standard should not only ensure that measures are in place, but also that those measures 

are effective. In the NERC petition, this Urgent Action standard was provided for 

information purposes only. The NERC Board of Trustees has since approved standards 

CIP 002-009 to replace this Urgent Action item. As approved by NERC, entities would 

be required to become compliant with the new CIP standards over the course of several 

years. However, the replacement standards have not yet been submitted to the 

Commission for approval. 

Staff’s examination indicates that the Requirements of both CIP standards may be 

incomplete and may be ambiguous regarding compliance requirements. 

Below is a discussion of primary issues identified by staff and an evaluation of each CIP 

standard. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 35 - 

Chapter: CIP 

B. Primary Issues in the Critical Infrastructure Protection Cyber Security 

Standards 

The cyber security standard, UA-1200, appears to establish requirements readily 

achievable by industry. However, the standard lacks detail and therefore creates for each 

applicable entity the discretion to set its own level of protection. As a result, security 

measures can vary widely from facility to facility. This lack of specificity makes it 

difficult to determine whether the standard reduces risks to the reliability of the BulkPower System from any compromise of cyber security assets. 

The cyber security standard requires entities to identify and catalog assets and 

procedures. However, except for provisions addressing the monitoring of physical and 

electronic access, the standard does not require entities to assess vulnerabilities of their 

assets and procedures, nor are applicable entities required to address identified 

vulnerabilities. 

C. Concerns Specific to Individual Standards 

Sabotage Reporting (CIP-001-0) 

The purpose of this standard reads: “Disturbances or unusual occurrences, suspected or 

determined to be caused by sabotage, shall be reported to the appropriate systems, 

governmental agencies, and regulatory bodies.” 

The standard requires that each Reliability Coordinator, Balancing Authority, 

Transmission Operator, Generation Operator and Load-Serving Entity: (1) have 

procedures for the recognition of and for making their operating personnel aware of 

sabotage events; (2) have procedures for the communication of information concerning 

sabotage events to appropriate “parties” in the interconnection; (3) provide operating 

personnel with guidelines for reporting disturbances due to sabotage events; and (4) 

establish communications contacts with applicable government officials and develop 

appropriate reporting procedures. While applicable entities must establish 

communication contacts, there is no requirement in the standard that an entity actually 

contact a governmental or regulatory body in the event of sabotage.65 Thus, the failure to 

follow the procedures developed by an entity would not result in a violation of this 

standard. 

 65 But see Standard EOP-004-0 (requiring entities to report actual or suspected physical or cyber 

attacks to the U.S. Department of Energy Operations Center). Reference to these related requirements in 

the CIP-001 standard could prove useful to regulated entities. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 36 - 

Chapter: CIP 

Further, the standard does not define “sabotage.” Thus, a cyber attack that gains access 

to a control room but does not cause damage may be reported by some entities but not be 

reported by others if it does not meet their understanding of the term “sabotage.”66 

Finally there are no Measures described that could be used to assist an entity in 

determining how to achieve the Requirements, nor are there any degrees of compliance 

described that could be used to measure compliance with the standards or enforce them in 

a meaningful way. NERC has indicated that this standard will be modified to address this 

deficiency and resubmitted for Commission approval in November 2006. 

Urgent Action 1200 (UA 1200) 

This cyber security standard is composed of 16 sections that discuss various aspects of 

cyber security. Even though NERC’s Board of Trustees has officially terminated UA 

1200 as of June 1, 2006, comments on this standard are included here to address the 

important area of cyber security. 

In general, the standard’s Requirements are imprecise, making it difficult to ascertain 

whether or not an entity was in compliance with the various provisions contained within 

each section. In addition, the Requirements in several sections rely on full compliance 

with other cyber security sections. Because success of the cyber security standard 

depends on full implementation of all the sections, enforcement and compliance 

assurance take on added importance. 

A related issue concerning the cyber security standard arises from NERC’s published 

implementation plan. This plan states that compliance with the cyber security standard 

will be conducted entirely through a self-certification process. Neither NERC nor the 

regions will conduct audits to verify self-certifications, and neither NERC nor the regions 

will issue letters of non-compliance or monetary penalties to those who indicate in their 

self-certification that they are not in compliance.67 These statements contradict 

provisions in each section of the standard which require certain documentation to be 

available for inspection and which state that sanctions will consist of letters for non-

 66 While UA-1200 defines “Cyber Security Incident” as “[a]ny event or failure (malicious or 

otherwise) that disrupts the proper operation of a critical cyber asset,” it is not clear whether this 

definition applies to CIP-001-0 as well. If applicable, this definition may actually lower the reporting 

requirements where a known penetration occurs but does not disrupt operations. 

67 NERC, Implementation Plan, Second Renewal of Urgent Action Cyber Security Standard 

(June 2005). 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 37 - 

Chapter: CIP 

compliance.68 As noted above, without strong enforcement and compliance provisions, 

assuring implementation of the cyber security standard will be difficult. The following 

discussion pertains to the individual sections that comprise UA 1200, as provided in 

NERC’s petition for information purposes. 

Section 1201 – Cyber Security Policy 

This section requires the creation and maintenance of a cyber security policy. It further 

requires designation of a senior manager to be responsible for this policy and to authorize 

any deviations. It also requires that the justifications for any deviations from the policy 

be documented. However, the Requirement to create a policy is vague; there is no detail 

regarding what issues or concerns the cyber security policy should address. The 

Measures for this section all address development and maintenance of documentation, 

e.g., the identification of the senior manager responsible, the annual review of the policy 

and the documentation for the deviations from the policy. There are no Measures that 

address the adequacy of the policy. In the NERC submission this Urgent Action standard 

was provided for information only. 

Section 1202 – Critical Cyber Assets 

This section requires that an entity identify its critical cyber assets, document these 

assets, and update this documentation at least annually or within 90 days of any changes 

to the critical cyber assets. The definition of “critical cyber assets” is imprecise, making 

it difficult for an entity to determine what cyber assets are “critical” and therefore 

governed by UA-1202.69 It is probable that two different entities could designate the 

same type of asset differently. The measures for this section all address development and 

maintenance of documentation, i.e., the development of the critical cyber asset document, 

and the annual review of the document. There are no compliance measures that address 

the adequacy of the selection of the assets themselves. 

Section 1203 – Electronic Security Perimeter 

This section requires that an entity identify an electronic perimeter around its critical 

cyber assets and maintain documentation of the perimeter, all interconnected cyber 

assets, and all electronic access points. This information must be updated at least 

 68 North American Electric Reliability Council, Reliability Standards for the Bulk 

Electric Systems of North America, Standard UA-1200 (Standard UA-1200). 

69 Id. (The Standard defines “Critical Cyber Assets” as “(t)hose computers, including installed 

software and electronic data, and communication networks that support, operate, or otherwise interact 

with the bulk electric system operations. This definition currently does not include process control 

systems, distributed control systems, or electronic relays installed in generating stations, switching 

stations and substations.”). 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 38 - 

Chapter: CIP 

annually or within 90 days of any changes to the network. The standard contains a 

definition of “Electronic Security Perimeter,” but there is little clarity on how an 

electronic perimeter is identified.70 Also, there is little specificity about how to determine 

what is an “electronic access point.” For example, an “access point” could mean an 

“interactive access point” where a user is prompted for a password, or it may include any 

electronic access, such as an application communications port. The Measures for this 

section all address development and maintenance of documentation, e.g., the 

development of the electronic security perimeter document and annual review. There are 

no Measures that address the adequacy of the method used to determine the electronic 

security perimeter. 

Section 1204 – Electronic Access Controls 

This section requires an entity to identify and implement electronic access controls for 

access to critical cyber assets within the electronic security perimeter. The entity is to 

maintain documentation of the electronic access controls and update it at least annually or 

within 90 days of any changes to the electronic security perimeter or the electronic access 

controls. However, there is no detail as to the functionality or any specific measures that 

the electronic access controls should address. Therefore, almost any electronic access 

control, good or bad, would satisfy this requirement. The Measures for this section all 

address development and maintenance of documentation, i.e., the documentation of the 

electronic access controls, and the annual review of this document. There are no 

Measures that address the adequacy of the methods used to provide the electronic access 

controls. 

Section 1205 – Physical Security Perimeter 

This section requires an entity to identify its physical security perimeter for the protection 

of critical cyber assets and document the perimeter and all access points. This 

information must be updated at least annually or within 90 days of any modification of 

the network. The section does not identify the level of rigor that a physical security 

perimeter should exhibit. The Measures for this section all address development and 

maintenance of documentation, i.e., the documentation of the physical security perimeter, 

and the annual review of this document. There are no Measures that address the 

adequacy of the perimeter itself. 

 70 Id. (The standard defines “Electronic Security Perimeter” as “(t)he border surrounding the 

network or group of sub-networks (the ‘secure’ network) to which the critical cyber assets are 

connected.”). 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 39 - 

Chapter: CIP 

Section 1206 – Physical Access Controls 

This section requires an entity to identify and implement physical access controls for 

access to critical cyber assets within the physical security perimeter. The entity must 

keep documentation identifying the physical access controls. This information must be 

updated at least annually or within 90 days of any changes to the physical security 

perimeter or physical access controls. There is no detail provided that would assist an 

entity in determining features or functionality of a good physical access control system. 

The Measures for this section all address development and maintenance of 

documentation, i.e., the documentation of the physical access control, and the annual 

review of this document. There are no Measures that address the adequacy of the 

physical access controls themselves. 

Section 1207 – Personnel 

This section requires the entity to maintain a list of all personnel who are authorized to 

have electronic or physical access to critical cyber assets. Entities are required to update 

the list at least quarterly or within 24 hours of any change. This section requires the 

entity to conduct background screening of all personnel in accordance with federal, state, 

provincial, and local laws. This section requires that the level of screening be consistent 

with the degree of access granted. The Measures for this section all address development 

and maintenance of documentation, i.e., the documentation of the personnel access list, 

and the quarterly review of this document. There are no Measures that address the 

adequacy of the personnel screening. 

Section 1208 – Monitoring Physical Access 

This section requires an entity to continuously monitor physical access to critical cyber 

assets. The entity is to document the tools and procedures used to monitor physical 

access and also verify in its documentation that these tools and procedures are 

functioning and being used as planned. The entity is also required to maintain for six 

months records (e.g., logs) of physical access to critical cyber assets and verify those 

records against the list of access control rights. While the verification requirement is a 

positive aspect of this section, there is limited specificity in the standard regarding what 

tools and procedures should be used to monitor physical access, suggesting that a 

minimum standard such as video surveillance or other physical monitoring can be used as 

a means to actually control access or to verify who received access. 

Section 1209 – Monitoring Electronic Access 

This section requires an entity to continuously monitor electronic access to critical cyber 

assets. The entity is to document the tools and procedures used to monitor electronic 

access and also verify in its documentation that these tools and procedures are 

functioning and being used as planned. The entity is also required to maintain for six 

months records (e.g., logs) of electronic access to critical cyber assets and verify those 

records against the list of access control rights. The section does not specify what tools 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 40 - 

Chapter: CIP 

and procedures are appropriate to monitor electronic access. The requirement to verify 

that tools and procedures are being used as planned is a positive aspect of this section. 

Section 1210 – Information Protection 

This section requires an entity to protect information associated with critical cyber assets 

as well as the policies and practices used to keep them secure. The entity is required to 

maintain a document identifying access limitations to sensitive information related to 

critical cyber assets. This document must address procedures, critical cyber asset 

inventories, maps, floor plans, equipment layouts, and configurations, and is to be 

reviewed and updated at least annually. There is some detail as to what an adequate 

information protection scheme should encompass. 

Section 1211 – Training 

This section requires an entity to develop and maintain a training program on cyber 

security policy, physical and electronic access controls to critical cyber assets, the release 

of cyber critical asset information, potential threat incident reporting, and action plans 

and procedures to recover or reestablish critical cyber assets following a cyber security 

incident. Training is to be conducted upon initial employment and reviewed annually. 

The Measures for this section all address development and maintenance of 

documentation, i.e., documenting successful completion of the training. There are no 

Measures that address the adequacy of the training itself. 

Section 1212 – Systems Management 

This section requires an entity to establish system management policies and procedures 

for configuring and securing critical cyber assets. The entity is required to document 

these policies and procedures and update them at least annually. According to this 

section, the policies and procedures at a minimum should address password management, 

computer account authorization, disabling unused accounts, disabling unused network 

ports and services, secure dial-up modems, firewall management, intrusion detection 

processes, security patch management, anti-virus software, retention of logs, and the 

identification of vulnerabilities and responses to same. The section is unclear about how 

entities ensure the adequacy of the efforts in any of these areas. The Measures for this 

section all address development and maintenance of documentation, i.e., the 

documentation of the policies and procedures. There are no Measures that address the 

adequacy of any of the policies or procedures themselves. 

Section 1213 – Test Procedures 

This section requires an entity to establish test procedures and acceptance criteria to 

assure that critical cyber assets installed or modified comply with the security 

requirements in this standard. The section requires that testing be conducted in an 

isolated test environment and that the test procedures and acceptance criteria must be 

documented. There is no detail on establishing proper test procedures or acceptance 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 41 - 

Chapter: CIP 

criteria. The Measures for this section all address development and maintenance of 

documentation, i.e., the documentation of the policies and procedures. There are no 

Compliance Measures that address the adequacy of any of the testing procedures 

themselves. 

Section 1214 – Electronic Incident Response Actions 

This section requires entities to define and document electronic incident response actions, 

including roles and responsibilities assigned by individual or job function. Aside from 

detailing reporting procedures to the Information Sharing and Analysis Center, there is 

little detail on establishing internal response actions. There is some information as to the 

types of incidents that should be reported based on the Indications, Analysis & Warning 

Program Standard Operating Procedure that is referenced in the section.71

Section 1215 – Physical Incident Response Actions 

This section requires entities to define and document physical incident response actions, 

including roles and responsibilities assigned by individual or job function. Aside from 

detailing reporting procedures to the Information Sharing and Analysis Center, there is 

little detail on establishing internal response actions. There is some information 

regarding the types of incidents that should be reported based on the Indications, Analysis 

& Warning Program Standard Operating Procedure that is referenced in the section.72 

Section 1216 – Recovery Plans 

This section requires entities to create action plans and procedures to recover or reestablish critical cyber assets following a cyber security incident and to maintain a 

document defining the plan and procedures. The entity should exercise these plans and 

procedures at least annually and document those exercises as well. There is no detail 

regarding what features and functionality should be incorporated in the recovery plan. 

The Measures for this section address development and maintenance of documentation, 

i.e., the documentation of the recovery plan. There are no Compliance Measures that 

address the adequacy of the recovery plans and procedures themselves. 

 71 National Infrastructure Protection Center, Indications, Analysis & Warning Program Standard 

Operating Procedure (2002). 

72 Id.
FERC Staff Preliminary Assessment of NERC Reliability Standards - 42 - 

VI. COM: COMMUNICATIONS 

A. Description and General Issues 

The two Communication (COM) standards apply to Reliability Coordinators, 

Transmission Operators, Generator Operators and Balancing Authorities. The first 

standard requires that these entities have adequate internal and external 

telecommunications facilities for the exchange of Interconnection and operating 

information necessary to maintain reliability. The second standard requires that these 

facilities be staffed and available for addressing real-time emergencies and that effective 

communications be carried out between operating personnel. 

Generally speaking, these standards raise issues from the standpoint of Measures, 

Compliance and Requirements. Further, these standards do not include recommendations 

from the Blackout Report and contain instances of ambiguity. 

These standards do not contain any specification of Measures and Compliance to assess 

an entity’s compliance with the Requirements. They also do not contain the Levels of 

Non-Compliance. NERC has indicated that these standards will be modified to address 

this deficiency and resubmitted for Commission approval in November 2006. 

Implementation of the Blackout Report recommendations regarding reliability involves 

these standards. 

Set forth below is a discussion of primary issues and an evaluation of individual 

standards in light of these observations. 

B. Primary Issues in the Communications Standards 

1. Unclear Requirements in Telecommunications Facilities 

Telecommunications facilities are an integral part of a complex set of operating tools 

necessary for all system operators to be continuously aware of emerging system 

conditions, to communicate with other operating entities, and to direct, coordinate and 

receive operating instructions to maintain system reliability. The first COM standard 

contains a general requirement to provide “adequate and reliable” telecommunications 

facilities for all applicable operating entities. It has a redundancy and diverse routing 

requirement, but it is effective only “where applicable,” and no specification is provided 

regarding the circumstances where the requirement would in fact be applicable. There 

are no specific or minimum requirements on adequacy, redundancy and diverse routing 

of the telecommunications facilities necessary to ensure the exchange of operating 

information, both internally and among the operating entities. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 43 - 

Chapter: COM 

To perform their real-time operational responsibilities properly, Reliability Coordinators 

need telecommunications facilities beyond those required by other operating entities. 

The particular needs of Reliability Coordinators are not addressed in the standards. In 

addition, leaving the specification of what constitutes adequate and reliable 

telecommunication facilities to operating entities without defining a minimum 

requirement based on their respective responsibilities may create ambiguities; operating 

entities could claim to be in compliance with the standard and still may not have adequate 

telecommunications facilities for use during real-time normal and emergency operations. 

2. Ineffective Communications and Inadequate Coordination Can 

Threaten Reliability 

Effective communications with proper communications protocols among the operating 

entities are essential for maintaining reliable system operations. The Blackout Report 

emphasized this principle using the following example: 

On August 14, 2003, reliability coordinator and control area 

communications regarding the conditions in northeastern Ohio were in 

some cases ineffective, unprofessional, and confusing. Ineffective 

communications contributed to a lack of situational awareness and 

precluded effective actions to prevent the cascade.[73]

 

The Blackout Report cited ineffective communications as a factor common to the August 

14 blackout and other previous major outages in North America.74 

Moreover, Recommendation Number 26 of the Report instructs NERC, working with 

Reliability Coordinators and Control Area Operators, to “[t]ighten communications 

protocols, especially for communications during alerts and emergencies. Upgrade 

communication system hardware where appropriate.”75 

Staff interprets this Blackout Report recommendation’s reference to “effective 

communications” with “tightened communications protocols” among operating entities to 

include two key components: (i) effective communications that are delivered in clear 

language via pre-established communications paths among pre-identified operating 

entities, and (ii) communications protocols which clearly identify that any operating 

 73 Blackout Report at 161 (Lack of situational awareness can result from the following: 

ineffective communications, inadequate reliability tools and inadequate operator training). 

74 Id. at 107. 

75 Id. at 141, 161. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 44 - 

Chapter: COM 

actions with reliability impact beyond a local area or beyond a Reliability Coordinator’s 

area must be communicated to the appropriate Reliability Coordinator for assessment and 

approval prior to their implementation to ensure reliability of the interconnected 

systems.76 

NERC’s second COM standard, titled “Communication and Coordination,” requires: 

Each Balancing Authority and Transmission Operator shall notify its 

Reliability Coordinator, and all other potentially affected Balancing 

Authorities and Transmission Operators through predetermined 

communication paths of any condition that could threaten the reliability of 

its area or when firm load shedding is anticipated. 

Each Reliability Coordinator, Transmission Operator, and Balancing 

Authority shall issue directives in a clear, concise, and definitive manner 

....[77]

 

Staff notes that these requirements fulfill the “effective communications” component of 

the Blackout Report recommendation, but do not meet the call for “tightened 

communications protocols”, as discussed above. These Requirement provisions do not 

contain a requirement that the appropriate operating actions in normal and emergency 

operating conditions that may have reliability impact beyond a local area or Reliability 

Coordinator’s area must be assessed and approved by the Reliability Coordinator, before 

being implemented by the operating entities. Some parties may suggest that the 

“assessment and approval” component is not considered as communications protocols 

and should instead be included as part of other relevant standards, such as the IRO or 

TOP standards. Staff agrees that this “assessment and approval” system of checks and 

balances to ensure reliability of the interconnected systems could be embedded as an 

important operating practice for the IRO and TOP protocols. Since this requirement is not 

explicitly included in the existing standards, Staff believes the most important need at this 

juncture is that it appears somewhere in the Reliability Standards. 

 76 See NERC Glossary at 13 (defining Reliability Coordinator as “the entity with the highest level 

of authority who is responsible for the reliable operation of the Bulk Electric System, has the Wide Area 

view of the Bulk Electric System, and has the operating tools, processes and procedures, including the 

authority to prevent or mitigate emergency operating situations in both next-day analysis and real-time 

operations...”). 

77 North American Electric Reliability Council, Reliability Standards for the Bulk 

Electric Systems of North America, Standard COM-002-1 Requirements R.1.1 and R.2. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 45 - 

Chapter: COM 

C. Concerns Specific to Individual Standards 

Telecommunications (COM-001-0) 

The purpose of this standard reads: 

Each Reliability Coordinator, Transmission Operator and Balancing 

Authority needs adequate and reliable telecommunications facilities 

internally and with others for the exchange of Interconnection and 

operating information necessary to maintain reliability. 

The standard does not contain specific or minimum adequacy, redundancy and diverse 

routing requirements for telecommunications facilities. Such specificity may vary 

depending upon whether the entity has a major impact on the system reliability. Such 

entities would have additional redundancy and diverse routing requirements. Staff notes 

that the Compliance Element Standards Drafting Team had similar comments concerning 

some of the requirements. 

The applicability section does not specify that Generation Operators are subject to 

telecommunications requirements set forth in the standard. This may have the effect of 

exempting Generation Operators from the standard or at least complicating the task of 

applying it to them. 

The standard contains no Compliance Measures or Levels of Non-Compliance. Without 

Compliance Measures and Levels of Noncompliance, the ERO will not have norms that 

are specific enough to implement consistent and effective enforcement. NERC has 

indicated that this standard will be modified to address this deficiency and resubmitted 

for Commission approval in November 2006. 

Communication and Coordination (COM-002-1) 

The purpose of this standard reads: 

To ensure Balancing Authorities, Transmission Operators, and Generator 

Operators have adequate communications and that these communications 

capabilities are staffed and available for addressing a real-time emergency 

condition. To ensure communications by operating personnel are effective. 

This standard does not contain a Requirement that appropriate operating actions be 

assessed and approved first and then implemented in normal and emergency operating 

conditions in which reliability could be impacted beyond a local area. This concern is 

discussed in section B.2 above. In situations where reliability impacts on one area could 

potentially affect the footprint of a Reliability Coordinator and its neighboring footprints, 

operating actions taken by a Balancing Authority or Transmission Operator should 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 46 - 

Chapter: COM 

require assessment and approval by their Reliability Coordinator and notification of the 

actions to the neighboring footprints to ensure reliability of the interconnected systems. 

The standard does not contain any Compliance Measures or Levels of Non-Compliance. 

Without Compliance Measures and Levels of Non-Compliance, the ERO will not have 

norms that are specific enough to implement consistent and effective enforcement. 

NERC has indicated that this standard will be modified to address this deficiency and 

resubmitted for Commission approval in November 2006. Standard COM-002-1 was 

recently approved by the NERC Board of Trustees with an effective date of November 1, 

2006. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 47 - 

VII. EOP: EMERGENCY PREPAREDNESS AND OPERATIONS 

A. Description and General Issues 

The Emergency Preparedness and Operations (EOP) group of reliability standards 

includes nine standards that are applicable to one or more of seven NERC-defined 

entities.78 These standards address preparation for emergencies, necessary actions during 

emergencies, system restoration and reporting after disturbances have occurred. 

In general, these standards raise issues in the Measures, Compliance, and Requirements 

sections. Further, these standards include instances of ambiguity. Five of the nine 

standards include some Measures to assess compliance, while four have no Compliance 

Measures. Six standards have some Levels of Non-Compliance that are required for 

enforcement and three standards have no compliance levels described. NERC has 

indicated that some these standards will be modified to address this deficiency and 

resubmitted for Commission approval in November 2006. 

An examination of the Requirements has identified six standards that have significant 

technical issues either because they may be incomplete or lack specificity or because they 

do not address knowledge gained from past experience. Implementation of the Blackout 

Report recommendations regarding reliability involves standards EOP-002, EOP-003, 

and EOP-008 in this group. 

Below follows a discussion of primary issues and an evaluation of individual standards in 

the context of these observations. 

B. Primary Issues in the Emergency Preparedness and Operations 

Standards 

1. Definition of Emergency States: Normal, Alert and Emergency 

System operators need common definitions for normal, alert, and emergency states to 

enable them to act appropriately and consistently as system conditions change. Alert and 

emergency states may result from either resource deficiencies and/or transmission 

contingencies. The Blackout Report states that 

 78 These entities are: Reliability Coordinators, Balancing Authorities, Transmission Operators, 

Generator Operators, Generator Owners, Load Serving Entities, and Regional Reliability Organizations. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 48 - 

Chapter: EOP 

On August 14, the principal entities involved in the Blackout did not have a 

shared understanding of whether the grid was in an emergency condition, 

nor did they have a common understanding of the functions, 

responsibilities, capabilities, and authorities of reliability coordinators and 

control areas under emergency or near-emergency conditions.[79] 

To address this concern, Recommendation Number 20 of the Blackout Report 

recommended establishing “clear definitions for normal, alert and emergency operational 

system conditions.”80 It also recommended clarifying “roles, responsibilities and 

authorities of reliability coordinators and control areas under each condition.”81 This 

group of standards does not clearly define transmission-related system states, entry 

conditions for alert and emergency states, or who has the authority to declare them.82 

2. Load Shedding: Specific Amounts and Timing 

Shedding of firm load is an operating measure of last resort to contain system 

emergencies and prevent cascading. The system operators must have the capability to 

manually or automatically shed load in a timely manner to return the system to a stable 

condition. The Blackout Report states that 

The investigation team concluded that since the Sammis-Star 345 kV 

outage was the critical event leading to widespread cascading in Ohio and 

beyond, if manual or automatic load-shedding of 1,500 MW had occurred 

within the Cleveland-Akron area before that outage, the blackout could 

have been averted.[83]

However, it should be noted that at that time there were no automatic or quick-acting 

manual load shedding capabilities in the area. While these standards require 

Transmission Operators and Balancing Authorities to have the capability to shed load in a 

timeframe adequate for responding to an emergency, they do not specify the minimum 

 79 Blackout Report at 158. 

80 Id. 

81 Id. 

82 See NYISO Emergency Operations Manual (July 2005) (For an example of transmissionrelated normal, alert and emergency states) at: 

http://www.nyiso.com/public/webdocs/documents/manuals/operations/em_op_mnl.pdf. 

83 Blackout Report at 70. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 49 - 

Chapter: EOP 

capability that must be provided and the maximum allowable delay before load shedding 

can be implemented.84 

3. Operator Protection for Load Shedding 

While the current standards provide operators with the authority to shed load to respond 

to an emergency and return the system to a stable state, the operators may hesitate to 

initiate such actions in appropriate circumstances without assurances that they will not be 

subject to liability or retaliation, even if their action is in accordance with previously 

approved guidelines. Recognizing the importance of this issue, the Blackout Report 

Recommendation Number 8 recommends that operators who initiate load shedding 

pursuant to approved guidelines should be shielded from liability or retaliation.85 The 

current standards do not require that these safeguards be provided to shield operators 

from retaliation when they declare an emergency or shed load. Staff notes that NERC 

readiness audits seek confirmation that such protection is provided to the operators by 

their employers. Staff believes this is a positive step, but not a substitute for addressing 

this issue in the standards. 

4. Back-Up Capability 

The primary control center may become inoperable either as a result of the need to 

evacuate the control center – for example, because of some environmental or security 

threat – or because of damage to the control center facilities due to natural or man-made 

disasters. In the former case, back-up capabilities may rely on the critical functionalities 

(data, tools, voice) of the primary control center. In the latter case, however, the back-up 

capabilities must be completely independent of the primary control center to ensure 

continued reliable operations. While evacuations may require back-up capability only for 

a few hours or days, damage to the primary control center may require operation from 

back-up capabilities for a prolonged period of time, possibly measured in months. 

Failure to provide adequate back-up capability and periodically test its effectiveness, and 

failure to periodically test the competency of operators to function from the back-up 

capability can have serious reliability impacts should the primary control center become 

inoperable for a prolonged period of time. These standards do not address the 

 84 This contrasts sharply with the criteria of the Northeast Power Coordinating Council (NPCC). 

NPCC Emergency Operation Criteria Document A-03 requires that “[e]ach Area must be capable of 

manually shedding at least fifty percent of its load in ten minutes or less. In so far as practical, the first 

half of the load shed manually should not include load which is part of any automatic load shedding 

plan.” 

85 Blackout Report at 147. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 50 - 

Chapter: EOP 

requirements for independence from the primary control center, provide for prolonged 

operation or provide the minimum tools and facilities consistent with the roles, 

responsibilities and tasks of the different entities. Staff recognizes, however, that when 

addressing back up capability for prolonged periods, the standards should reflect an 

appropriate balance between the probability of needing such back up capability and the 

consequences to reliability of not having back up capability. 

C. Concerns Specific to Individual Standards 

Emergency Operations Planning (EOP-001-0) 

The purpose of this standard reads: 

Each Transmission Operator and Balancing Authority needs to develop, 

maintain, and implement a set of plans to mitigate operating emergencies. 

These plans need to be coordinated with other Transmission Operators and 

Balancing Authorities, and the Reliability Coordinator. 

The standard requires Transmission Operators and Balancing Authorities to develop, 

maintain, and implement a set of plans to mitigate operating emergencies resulting from 

either insufficient generation or transmission. There is no similar requirement for 

Reliability Coordinators, who are the highest level of authority responsible for the BulkPower System. 

The standard requires “the [Transmission Operators] to implement load reduction in 

sufficient amount and time to mitigate IROL violations before system separation or 

collapse would occur. The load reduction plan must be capable of being implemented 

within 30 minutes.”86 One interpretation of this requirement is that power transfers must 

be adjusted within 30 minutes to relieve IROL overloads. Another interpretation is that 

load reduction - interpreted as load shedding - must be capable of being implemented 

within 30 minutes after an operating emergency is declared. The latter interpretation 

could lead to an inappropriate conclusion that load shedding capability with an 

implementation time of up to 30 minutes is acceptable to deal with system emergencies. 

This could expose the system to higher risk since load shedding is the option of last resort 

and must be capable of being implemented in a much shorter time period than 30 

minutes. 

 86 Standard EOP-001-0 (R2). 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 51 - 

Chapter: EOP 

The standard does not define transmission-related “normal,” “alert,” and “emergency” 

states, provide criteria for entering into these states, or identify authority for declaring 

these states as discussed in the Primary Issues section above. 

Capacity and Energy Emergencies (EOP-002-1) 

The purpose of this standard reads: “To ensure Reliability Coordinators and Balancing 

Authorities are prepared for capacity and energy emergencies.” 

The standard addresses responsibility, authority and actions to be taken to alleviate 

generation capacity and energy emergencies. It does not address emergencies resulting 

from insufficient transmission capability nor is this issue addressed elsewhere in other 

standards. Staff notes that TLRs are not appropriate for addressing actual transmission 

emergencies since they are “not fast and predictable enough for use in situations in which 

an operating security limit is close to or actually being violated” as stated in the Blackout 

Report87 and discussed further in section B.4 of the IRO Chapter , regarding IRO: 

Interconnected Reliability Operations and Coordination. 

Load Shedding Plans (EOP-003-0) 

The purpose of this standard reads: 

A Balancing Authority and Transmission Operator operating with 

insufficient generation or transmission capacity must have the capability 

and authority to shed load rather than risk an uncontrolled failure of the 

Interconnection. 

This standard requires that, after taking all other remedial steps, load be shed rather than 

risk an uncontrolled failure of components or cascading outages of the Interconnection. 

However, the standard does not specify the minimum load shedding capability that 

should be provided and the maximum amount of delay before load shedding can be 

implemented. This issue was explained in greater detail in the Primary Issues section 

above. 

Blackout Report Recommendation Number 8 recommends that operators who initiate 

load shedding pursuant to approved guidelines should be shielded from liability of 

retaliation.88 The standard does not require that safeguards be provided to shield 

operators from retaliation when they declare an emergency or shed load in accordance 

with previously approved guidelines. Staff notes that NERC readiness audits seek 

 87 Blackout Report at 163. 

88 Blackout Report at 147. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 52 - 

Chapter: EOP 

confirmation that such protection is provided to the operators by their employers. As 

indicated, this is a positive step but not one that is a substitute for a standard with full 

clarity on this issue.

The standard does not require periodic drills of simulated load shedding (not actual 

shedding of firm load). Periodic simulated drills are important to test the effectiveness of 

the processes, communications and protocols, and to familiarize operators from 

Reliability Coordinators, Transmission Operators and Load Serving Entities with their 

respective roles and responsibilities associated with the load shedding plans. 

The standard does not contain any Measures to assess compliance with any of the 

Requirements of the standard or any Levels of Non-Compliance required for 

enforcement. NERC has indicated that this standard will be modified to address this 

deficiency and resubmitted for Commission approval in November 2006. 

Disturbance Reporting (EOP-004-0) 

The purpose of this standard reads: 

Disturbances or unusual occurrences that jeopardize the operation of the 

Bulk Electric System, or result in system equipment damage or customer 

interruptions, need to be studied and understood to minimize the likelihood 

of similar events in the future. 

The standard does not address the Blackout Report’s Recommendation Number 14: 

“Establish a standing framework for the conduct of future blackout and disturbance 

investigations.”89 Staff notes that a presentation by the Department of Energy, Preparing 

For the Next Blackout,

90 was given to the NERC Board of Trustees in February 2005. 

Their presentation lays out steps to prepare for an investigation, priority actions to take 

immediately after a blackout and the process to follow during the investigation. Staff 

also notes that NERC has prepared a procedure for responding to major events that affect 

the Bulk Electric System entitled "NERC Blackout and Disturbance Response 

Procedures."91 The staff believes that the DOE presentation and the NERC 

procedure provide a reasonable basis for revising the standard. 

 89 Blackout Report at 149. 

90 Silverstein, Alison, Preparing for the Next Blackout, February 7-8, 2005 at 

http://www.nerc.com/~filez/botmin.html (Presentations at NERC Board of Trustees, Stakeholders 

Committee and Annual Meeting of Members). 

91 See NERC’s Application for Certification as the Electric Reliability Organization, Rules of 

Procedure of the Electric Reliability Organization, NERC Blackout and Disturbance Response 

(continued) 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 53 - 

Chapter: EOP 

The standard does not contain any Measures to assess compliance with any of the 

Requirements of the standard or any Levels of Non-Compliance required for 

enforcement. NERC has indicated that this standard will be modified to address this 

deficiency and resubmitted for Commission approval in November 2006. 

System Restoration Plans (EOP-005-0) 

The purpose of this standard reads: “To ensure plans, procedures, and resources are 

available to restore the electric system to a normal condition in the event of a partial or 

total shut down of the system.” 

The standard requires a restoration plan to reestablish the electrical system in a stable and 

orderly manner in the event of a partial or total shutdown. While the standard requires 

that operators be trained in the implementation of the restoration plan, it does not require 

this to be done periodically. 

The standard contains Levels of Non-Compliance but no Measures to assess compliance 

with any of the Requirements of the standard. NERC has not identified this standard as 

one that would be modified and resubmitted for Commission approval in November 

2006. 

Reliability Coordination-System Restoration (EOP-006-0) 

The purpose of this standard reads: “The Reliability Coordinator must have a 

coordinating role in system restoration to ensure reliability is maintained during 

restoration and priority is placed on restoring the Interconnection.” 

Staff notes that this standard requires only that Reliability Coordinators, the highest 

authority responsible for overall system restoration, be aware of the restoration plan of 

each Transmission Operator in its Reliability Coordination Area, but not that they be 

involved in its development or approval. 

The standard does not contain any Measures to assess compliance with the Requirements 

of the standard or any Levels of Non-Compliance required for enforcement. NERC has 

indicated that this standard will be modified to address this deficiency and resubmitted 

for Commission approval in November 2006. 

 

Procedures, Appendix 8 available at ftp://www.nerc.com/pub/sys/all_updl/ero/application/EROApplication-Complete.pdf. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 54 - 

Chapter: EOP 

Establish, Maintain, and Document a Regional Blackstart Capability Plan 

(EOP-007-0) 

The purpose of this standard reads: 

A system Blackstart Capability Plan (BCP) is necessary to ensure that the 

quantity and location of system blackstart generators are sufficient and that 

they can perform their expected functions as specified in overall 

coordinated Regional System Restoration Plans (SRP). 

RRO is listed as the Applicability entity in this standard and its appropriateness is a 

concern in the new mandatory standard structure. 

Plans for Loss of Control Center Functionality (EOP-008-0) 

The purpose of this standard reads: “Each reliability entity must have a plan to continue 

reliability operations in the event its control center becomes inoperable.” 

The standard requires a backup plan but does not specifically require that back-up 

capabilities be provided. As discussed in the Primary Issues section B4 above, this 

standard does not address the requirements for independence from the primary control 

center, provide for prolonged operation or provide the minimum tools and facilities 

consistent with the roles, responsibilities and tasks of the different entities. 

Documentation of Blackstart Generating Unit Tests Results (EOP-009-0) 

The purpose of this standard reads: 

A System Blackstart Capability Plan (BCP) is necessary to ensure that the 

quantity and location of system blackstart generators are sufficient and that 

they can perform their expected functions as specified in overall 

coordinated Regional System Restoration Plans. 

The standard requires that the start-up and operation of each generating Blackstart unit be 

tested and the results submitted to the RRO. However, it does not require the Blackstart 

units to be periodically tested to ensure that they will be available when required to 

restore the system. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 55 - 

VIII. FAC: FACILITIES DESIGN, CONNECTIONS, MAINTENANCE, 

AND TRANSFER CAPABILITIES 

A. Description and General Issues 

The nine Facility (FAC) standards apply to Generator Owners, Transmission Owners, 

Distribution Providers, Load-Serving Entities, Transmission Planners, Planning 

Authorities, Reliability Coordinators, and RROs. Of the nine standards in this group, two 

address facility connection and coordination requirements, one addresses vegetation 

management, and four address processes to determine facility ratings and use in system 

modeling. Two new standards address transfer capabilities methodology. 

In general, the FAC standards raise issues concerning the sufficiency of measures, the 

lack of compliance directives, and ambiguities in interpreting the technical Requirements. 

Two standards in this group may raise technical issues related to safety and reliability 

aspects of the Bulk-Power System. Two standards in this group may not contain 

sufficient criteria to assess Compliance. Several of these standards may not address the 

lessons learned from past operating incidents or may not contain technically sound means 

to achieve the specified reliability goal. 

Staff notes that several standards in this group address separate matters but have identical 

purpose statements. Generally, staff suggests such statements be augmented or tailored 

to reflect the specific aspect of the purpose the given standard is designed to achieve. 

Implementation of the Blackout Report recommendations regarding reliability involves 

standards FAC-003 and FAC-008 in this group. Below is a discussion of primary issues 

evident in the FAC standards as well as an evaluation of the individual standards in the 

context of these observations. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 56 - 

Chapter: FAC 

B. Primary Issues in the Facility Standards 

1. Consistency of Facility Standards with the Commission’s 

Generation Interconnection Orders92

System assessments are required to ensure that facilities can be interconnected to the 

system to supply load reliably under normal and contingency conditions. The FAC 

standards require system performance assessments in accordance with reliability standard 

TPL-001-0, which relates only to normal system conditions.93 Staff notes that Order No. 

200394 requires assessments of both normal and post-contingency conditions and 

therefore is more rigorous than TPL-001-0. 

2. Vegetation Management 

Improper vegetation management is a recurring causal factor in large-scale power 

outages, including the August 14, 2003 blackout.95 In response to the Blackout Report, 

NERC adopted a Version 1 vegetation management standard which became effective on 

April 7, 2006. Staff commends the industry for adopting a vegetation management 

standard that employs a performance metric, but has several significant concerns 

regarding the standard. These concerns reflect the recommendations that the 

 92 Standardization of Generator Interconnection Agreements and Procedures, Order No. 2003, 

FERC Stats. & Regs. ¶ 31,146 (2003), order on reh’g, Order No. 2003-A, FERC Stats. & Regs. ¶ 31,160 

(2004), order on reh’g, Order No. 2003-B, FERC Stats. & Regs. ¶ 31,171 (2004), order on reh’g, Order 

No. 2003-C, FERC Stats. & Regs. ¶ 31,190 (2005); see also Notice Clarifying Compliance Procedures, 

106 FERC ¶ 61,009 (2004); Standardization of Small Generator Interconnection Agreements and 

Procedures, Order No. 2006, FERC Stats. & Regs. ¶ 31,180 (2005), order on reh’g, Order No. 2006-A, 

113 FERC ¶ 61,195 (2005); see also Standardization of Small Generator Interconnection Agreements and 

Procedures, Notice of Proposed Rulemaking, FERC Stats. & Regs. ¶ 32,572 (2003); Interconnection for 

Wind Energy, Order No. 661, FERC Stats. & Regs. ¶ 31,186 (2005), order on reh’g, Order No. 661-A, 

FERC Stats. & Regs. ¶ 31,198 (2005). 

93 Standard TPL-001-0 (Requirement 1 states that “The Planning Authority and Transmission 

Planner shall each demonstrate through a valid assessment that its portion of the interconnected 

transmission system is planned such that, with all transmission facilities in service and with normal (precontingency) operating procedures in effect, the Network can be operated to supply projected customer 

demands ...”). 

94 Order No. 2003-A at P 89 and 145 (Transmission Owners have made compliance filings with 

the Commission for Large Generation Interconnection Procedures and Agreements, known as LGIP and 

LGIA respectively). 

95 Blackout Report at 107 (“The factors that were common to some of the major outages above 

and the August 14 blackout include: (1) conductor contact with trees ...”). 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 57 - 

Chapter: FAC 

Commission submitted to Congress in September 2004 in a report on Vegetation 

Management on how the electric industry could improve vegetation management 

practices.96 

First, the current standard does not designate maximum allowable inspection intervals. 

Rather, each Transmission Owner is responsible for maintaining a formal transmission 

vegetation management program that defines a schedule for and the type of right of way 

vegetation inspections (e.g., aerial, ground). Thus, a Transmission Owner cannot be 

faulted for the length of its inspection interval, provided that it has defined the schedule 

in its formal program.97 

Second, the current standard may use a minimum clearance based on an IEEE standard 

that is not sufficient.98 The Version 1 vegetation management standard requires a 

Transmission Owner to determine and document the minimum allowable clearance 

between energized conductors and vegetation before the next trimming, and it 

specifically provides that “Transmission-Owner-specific minimum clearance distances 

shall be no less than those set forth in the Institute of Electrical Engineers (IEEE) 

Standard 516-2003 (Guide for Maintenance Methods on Energized Power Lines).”99 

However, IEEE Standard 516-2003 is intended for use by highly-trained maintenance 

personnel to carry out live-line work using specialized tools under controlled 

environments and operating conditions. The allowable clearances in the IEEE standard 

are significantly lower than those specified by the relevant U.S. safety codes. For 

example, the IEEE’s standard specifies a 2.45-foot clearance from a live conductor for 

the 120 kV voltage class,100 whereas the ANSI Z-133 standard specifies 12-feet, 4-inches 

as the approach distance for the 115 kV voltage class.101 Therefore, use of the IEEE 

clearance provision as a basis for minimum clearance prior to the next tree trimming may 

 96 Utility Vegetation Management and Bulk Electric Reliability Report at 17 (September 7, 

2004). 

97 See North American Electric Reliability Council, Reliability Standards for the Bulk Electric 

Systems of North America, Standard FAC-003-1, Requirement R1.1 (Standard FAC-003-1). 

98Blackout Report at 154 (Recommendation Number 16 is to “(e)stablish enforceable standards 

for maintenance of electrical clearances in right-of-way areas.”). 

99 Standard FAC-003-1 (R1.2.2). 

100 Institute of Electrical and Electronics Engineers, Inc. (IEEE) Standard 516-2003, IEEE Guide 

for Maintenance Methods at 20. 

101 ANSI Z133, American National Standards Institute Standard For Tree Care Operations – 

Pruning, Trimming, Repairing, Maintaining and Removing Trees, and Cutting Brush – Safety 

Requirements. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 58 - 

Chapter: FAC 

not be appropriate, and adopting it for use with regular maintenance practices in 

vegetation management may be a “lowest common denominator” approach. Widespread 

implementation of this approach could inadvertently subject the public to more hazardous 

conditions. In addition, use of IEEE Standard 516-2003 could create the unintended 

consequence that some transmission owners who currently maintain more stringent 

vegetation management programs based on standards such as the ANSI Z-133 may relax 

their practices to meet the less-stringent minimum requirement set forth in the NERC 

vegetation management standard FAC-003-1.. 

Staff is not necessarily recommending use of the ANSI Z-133 standard as the minimum 

standard; however, we seek comment on whether the IEEE standard is sufficient to 

maintain reliability and protect public safety and, if not, what modifications to that 

standard should be made or whether an alternative standard is required to satisfy Order 

No. 672. 

3. Methodology to Determine Facility Ratings 

Under current utility practices, there is no uniform set of methodologies that are used by 

the reliability and operating entities to determine equipment ratings. This has frequently 

resulted in different ratings for the same equipment under the same ambient and 

operating conditions in the same region. It is possible that two transmission owners with 

joint ownership of an interconnection line using their respective methodologies could 

derive two different line ratings, even with both applying the same assumptions in 

ambient and operating conditions.102 

The standards for determining facility ratings do not establish a uniform or consistent set 

of methodologies; instead they only require Transmission Owners or Generation Owners 

to document its chosen methodology. The standards do not address Recommendation 

Number 27 of the Blackout Report that NERC “develop clear, unambiguous requirements 

for the calculation of transmission line ratings.”103

 102 This is true even when the different ratings are not due to the ratings of their respective 

terminal equipment. 

103 Blackout Report at 162 (Recommendation Number 27 states that “NERC should develop 

enforceable standards for transmission line ratings. NERC should develop clear, unambiguous 

requirements for the calculation of transmission line ratings (including dynamic ratings), and require that 

all lines of 115 kV or higher be rerated according to these requirements by June 30, 2005.”). 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 59 - 

Chapter: FAC 

C. Concerns Specific to Individual Standards 

Facility Connection Requirements (FAC-001-0) 

The purpose of this standard reads: “To avoid adverse impacts on reliability, 

Transmission Owners must establish facility connection and performance requirements.” 

No substantive issues were identified at this time. 

Coordination of Plans for New Generation, Transmission, and End-User facilities 

(FAC-002-0) 

The purpose of this standard reads: “To avoid adverse impacts on reliability, Generator 

Owners and Transmission Owners and electricity end-users must meet facility connection 

and performance requirements.” 

The FAC standards require system performance assessments in accordance with 

reliability standard TPL-001-0, which relates only to normal system conditions.104 Staff 

notes that Order No. 2003105 requires assessments of both normal and post-contingency 

conditions and is therefore more rigorous than FAC-002-0. 

Transmission Vegetation Management Program (FAC-003-1) 

The purpose of this standard reads: 

To improve the reliability of the electric transmission systems by 

preventing outages from vegetation located on transmission rights-of-way 

(ROW) and minimizing outages from vegetation located adjacent to ROW, 

maintaining clearances between transmission lines and vegetation on and 

along transmission ROW, and reporting vegetation-related outages of the 

transmission systems to the respective Regional Reliability Organizations 

(RRO) and the North American Electric Reliability Council (NERC). 

Staff’s technical concerns with this standard are discussed in section B.2 above. 

With regard to Measures and Requirements, both the Requirement on reporting 

transmission outages and the Levels of Non-Compliance in the standard -- which are 

based on the number of tree contact outages -- represent good performance metrics to 

improve reliability. 

 104 Standard TPL-001-0 

105 Order No. 2003 at P 89 and 145. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 60 - 

Chapter: FAC 

The Measures and Levels of Non-Compliance have been significantly improved 

compared to those in the Version 0 standard. They appear to be adequate at this time. 

Methodologies for Determining Electrical Facilities (FAC-004-0) 

The purpose of this standard reads: “To ensure that electrical facilities used in the 

transmission and storage of electricity are rated in compliance with applicable Regional 

Reliability Organization requirements.”106 

Staff’s concerns with this standard are discussed in section B.3 above. 

Electrical Facility Ratings for System Modeling (FAC-005-0) 

The purpose of this standard reads: “To ensure that electrical facilities used in the 

transmission and storage of electricity are rated in compliance with applicable Regional 

Reliability Organization requirements.” 

No substantive issues were identified at this time. 

Facility Ratings Methodology (FAC-008-1) 

The purpose of this standard reads: “To ensure that Facility Ratings used in the reliable 

planning and operation of the Bulk Electric System (BES) are determined based on an 

established methodology or methodologies.” 

This standard was recently approved by the NERC Board of Trustees and will become 

effective on August 7, 2006, replacing standard FAC-004-0, Methodologies for 

Determining Electrical Facilities. 

The concerns discussed in section B.3 above, regarding facility rating methodologies, are 

at issue in this standard. This standard does not provide a uniform or consistent set of 

methodologies; instead it only requires equipment owners to document the respective 

methodologies they use. Therefore, this standard does not appear to address 

Recommendation Number 27 of the Blackout Report to establish “clear, unambiguous 

requirements” for the calculation of transmission line ratings.107

Establish and Communicate Facility Ratings (FAC-009-1) 

The purpose of this standard reads: “To ensure that Facility Ratings used in the reliable 

planning and operation of the Bulk Electric System (BES) are determined based on an 

established methodology or methodologies.” 

 106 According to NERC, this standard will be retired on August 7, 2006 when Standard FAC-008-

1 comes into effect. 

107 Blackout Report at 162.
FERC Staff Preliminary Assessment of NERC Reliability Standards - 61 - 

Chapter: FAC 

This standard requires Transmission Owners and Generator Owners to establish and 

communicate their facility ratings to other reliability and operating entities. This is a new 

standard effective October 7, 2006. Staff notes that there is no substantive issue with the 

standard at this time. 

Transfer Capability Methodology (FAC-012-1) 

The purpose of this standard reads: “To ensure that Transfer Capabilities used in the 

reliable planning and operation of the Bulk Electric System (BES) are determined based 

on an established methodology or methodologies.” 

This standard requires the Reliability Coordinators and Planning Authority to document 

their methodologies in determining inter-regional and intra-regional transfer capabilities 

by stating that “Transfer Capabilities shall respect all applicable System Operating Limits 

(SOLs).” This is a new standard effective August 7, 2006. 

Staff notes that entities in different regions have historically calculated transfer 

capabilities using different assumptions or approaches.108 These approaches may be 

different between the Reliability Coordinators and Planning Authorities in a region, and 

may also vary from region to region. Therefore, the variable application of transfer 

capabilities is essentially a regional difference. A move toward standardization of the 

inter-regional and intra-regional transfer capability may be desirable to ensure an 

adequate level of reliability and minimize undue negative impact on competition. Staff 

notes that this issue is being considered in Docket Nos. RM05-17-000 and RM05-25-000. 

Establish and Communicate Transfer Capability (FAC-013-1) 

The purpose of this standard reads: “To ensure that Transfer Capabilities used in the 

reliable planning and operation of the Bulk Electric System (BES) are determined based 

on an established methodology or methodologies.” 

This standard requires Reliability Coordinators and Planning Authority to establish the 

transfer capabilities and provide them to the reliability entities. This is a new standard 

effective October 7, 2006. Staff notes that there is no substantive issue with the standard 

at this time. 

 108 See NERC Long-Term AFC/ATC Task Force Final Report, revised April 14, 2005. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 62 - 

IX. INT: INTERCHANGE SCHEDULING AND COORDINATION 

A. Description and General Issues 

The Interchange Scheduling and Coordination (INT) group of reliability standards 

consists of four standards applicable Balancing Authorities, Purchasing-Selling Entities, 

Transmission Service Providers, Reliability Coordinators and Transmission Operators, 

but potentially also applicable to Load Serving Entities and Generator Operators. 

This group of standards addresses the process of Interchange Transactions, which occur 

when electricity is purchased and transmitted from a seller to a buyer across the power 

grid.109 Specific information must be identified in electronic labels, known as Tags, and 

these must accompany the transactions to allow a reliability assessment by the affected 

reliability and operating entities. In addition, communication, submission, assessment 

and approval of these Tags, including modifications, must be completed for reliability 

consideration before implementation of the transaction. 

Generally, these standards raise issues in the areas of Applicability, Measures, 

Compliance, and Requirements. Further, these standards include instances of ambiguity. 

Set forth below is a discussion of primary issues and an evaluation of individual 

standards in light of these observations. 

Of the four standards in this group, one of them has partial Measures and Levels of NonCompliance provisions, one has partial Measures but no Levels of Non-Compliance 

provisions, and two have neither Measures nor Levels of Non-Compliance provisions. 

The two standards that contain Measures provisions do not provide specific compliance 

criteria to address all of the reliability goals identified in the purposes and all of the 

requirements contained in the INT group of standards. NERC has indicated that some of 

these standards will be modified to address this deficiency and resubmitted for 

Commission approval in November 2006. 

Implementation of the Blackout Report recommendations regarding reliability involves 

standard INT-004 in this group. Below follows a discussion of primary issues evident in 

the INT standards as well as an evaluation of the individual standards in the context of 

these observations. 

 109 NERC Glossary at 8 (defines “Interchange Transaction” at page 8 as “[a]n agreement to 

transfer energy from a seller to a buyer that crosses one or more Balancing Authority Area boundaries”). 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 63 - 

Chapter: INT 

B. Primary Issues in the Interchange Scheduling and Coordination 

Standards 

1. Use of Interchange Transaction Modifications to Address Actual 

System Operating Limit or Interconnection Reliability 

Operating Limit Violations 

The standards allow modifications to be made to Interchange Transactions in order to 

address actual System Operating Limit (SOL) or Interconnection Reliability Operating 

Limit (IROL) violations.110 Considering the specific requirements on Tag modification, 

submission, assessment, approvals and transaction implementation, the total time 

necessary to implement the Interchange Transactions modification is expected to exceed 

by a substantial amount the timeframe of 30 minutes that is established in other 

standards, i.e., the requirement that the system be returned to a secure operating state 

from a SOL/IROL violation as soon as possible, but no later than 30 minutes after the 

violation. The standards currently do not contain a clear warning of this potential 

limitation and therefore could lead to the inappropriate use of transaction modification by 

reliability entities to deal with actual SOL/IROL violations. In doing so, valuable time 

would be lost that is needed to re-adjust the system effectively using other operational 

corrective actions. 

C. Issues Specific to Individual Standards 

Interchange Transaction Tagging (INT-001-0) 

The purpose of this standard reads: 

To ensure that Interchange Transactions, certain Interchange Schedules, 

and intra-Balancing Authority Area transfers using Point-to-Point 

Transmission Service are Tagged in adequate time to allow the transactions 

to be assessed for reliability impacts by the affected Reliability 

Coordinators, Transmission Service Providers, and Balancing Authorities, 

and to allow adequate time for implementation. 

This standard has only one Measure. It requires documentation to demonstrate 

that all scheduled interchanges are tagged. This is not sufficient to ensure that all 

requirements in the standard are met. In addition, the standard does not contain 

 110 See NERC Glossary at 8 (defining IROL as “[t]he value (such as MW, MVar, Amperes, 

Frequency or Volts) derived from, or a subset of the System Operating Limits, which if exceeded, could 

expose a widespread area of the Bulk Electric System to instability, uncontrolled separation(s) or 

cascading outages”). 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 64 - 

Chapter: INT 

any Levels of Non-Compliance. Without Levels of Noncompliance, the ERO will 

not have norms that are specific enough to implement consistent and effective 

enforcement. NERC has indicated that this standard will be modified to address 

this deficiency and resubmitted for Commission approval in November 2006. 

Interchange Transaction Tag Communication and Reliability Assessment 

(INT-002-0) 

The purpose of this standard reads: 

To ensure that Interchange Transaction information is provided to all 

entities needing to make reliability assessments and to ensure all affected 

reliability entities access the reliability impacts of Interchange Transactions 

before approving or denying a Tag. To communicate the approvals and 

denials of the Tag and the final composite status of the Tag. 

Staff notes that Reliability Coordinators and Transmission Operators are not included in 

the applicability section of this standard. This is important because power flows for 

Interchange Transactions cross multiple Balancing Authority Areas and affect multiple 

transmission paths in an Interconnection, requiring the participation of Reliability 

Coordinators and Transmission Operators. 

The standard contains no Compliance Measures or Levels of Non-Compliance. Without 

Compliance Measures and Levels of Noncompliance, the ERO will not have norms that 

are specific enough to implement consistent and effective enforcement. NERC has 

indicated that this standard will be modified to address this deficiency and resubmitted 

for Commission approval in November 2006. 

Interchange Transaction Implementation (INT-003-0) 

The purpose of this standard reads: 

To ensure Balancing Authorities confirm Interchange Schedules with 

Adjacent Balancing Authorities prior to implementing the schedules in their 

Area Control Error (ACE) equations. To Ensure Balancing Authorities 

incorporate all confirmed Schedules into their ACE equations. 

The standard contains no Compliance Measures or Levels of Non-Compliance. Without 

Compliance Measures and Levels of Noncompliance, the ERO will not have norms that 

are specific enough to implement consistent and effective enforcement. NERC has 

indicated that this standard will be modified to address this deficiency and resubmitted 

for Commission approval in November 2006. 

Interchange Transaction Modifications (INT-004-0) 

The purpose of this standard reads: 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 65 - 

Chapter: INT 

To allow modifications to Interchange Transactions to address potential or 

actual System Operating Limit (SOL) or Interconnection Reliability 

Operating Limit (IROL) violations or other reliability conditions. To 

ensure Dynamic Transfers are adequately tagged to be able to determine 

their reliability impacts. 

The standard contains requirements concerning Generator Operators and Load-Serving 

Entities, but they are not listed in the applicability section, which may have the effect of 

exempting them from the standard or at least complicating the task of applying the 

standard to them. For example Requirement R2 specifically states “[a] Generator 

Operator or Load Serving Entity may request the Host Balancing Authority to modify...” 

If these entities are not listed in the applicability sections, the enforceability of this 

provision is undermined. 

The standard includes a provision to allow modifications to Interchange Transactions to 

address actual SOL/IROL violations. Staff’s concerns are discussed in more detail in 

section B1 above. 

The standard does not contain any Levels of Non-Compliance provisions. The one 

Measure contained in the standard is aimed at Requirement R5 which is applicable to 

Purchasing-Selling entities and Sink Balancing Authorities and not any of the other 

Requirements in the standard. Without Levels of Noncompliance and adequate 

Measures, the ERO will not have norms that are specific enough to implement consistent 

and effective enforcement. NERC has not identified this standard as one that would be 

modified and resubmitted for Commission approval in November 2006. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 66 - 

X. IRO: INTERCONNECTION RELIABILITY OPERATIONS AND 

COORDINATION 

A. Description and General Issues 

The Interconnection Reliability Operations and Coordination (IRO) standards focus on 

the responsibilities and authorities of Reliability Coordinators.111 These reliability 

standards establish requirements for data, tools, and wide area view, which are intended 

to facilitate a Reliability Coordinator’s ability to perform its responsibilities and ensure 

the reliable operation of the interconnected grid. 

Generally, these standards raise issues in the areas of Measures, Compliance and 

Requirements. Further, these standards are subject to varying interpretations. 

Three standards require entities to provide the data necessary to support reliability 

coordination tasks and implement operating instructions, as directed by Reliability 

Coordinators to preserve the reliability and integrity of the Bulk Electric System. 

However, the standards do not provide specific Requirements and Measures concerning 

wide area view and facilities. The second, third and fifth standards lack Measures and 

compliance Requirements. The sixth standard does not contain sufficient criteria or 

Measures to assess compliance with the Requirements. 

If the IRO standards provided clear and objective criteria or Measures concerning all of 

the Requirements identified, they could be enforced in a consistent and non-preferential 

manner. NERC has indicated that some of these standards will be modified to address 

this deficiency and resubmitted for Commission approval in November 2006. 

Implementation of the Blackout Report recommendations regarding reliability involves 

standards IRO-003 and IRO-006 in this group. Also, if left unresolved, the issue of 

conflicting definitions concerning the Bulk-Power System vs. the Bulk Electric System, 

discussed in the Common Issues chapter of this document, would add to interpretation 

and enforceability problems for the standards in this chapter. 

The following is a discussion of the primary issues and an evaluation of individual 

reliability standards in light of these observations. 

 111 See NERC Glossary at 13 (defining Reliability Coordinator as “the entity with the highest 

level of authority who is responsible for the reliable operation of the Bulk Electric System, has the Wide 

Area view of the Bulk Electric System, and has the operating tools, processes and procedures, including 

the authority to prevent or mitigate emergency operating situations in both next-day analysis and real-time 

operations...”). 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 67 - 

Chapter: IRO 

B. Primary Issues in Interconnection Reliability Operation and 

Coordination Standards 

1. Unclear Responsibilities and Authorities of Reliability 

Coordinators 

Some real-time operating actions that are carried out by operating entities, such as 

Transmission Operators and Balancing Authorities, may have a reliability impact on the 

footprint of their Reliability Coordinator and those of adjacent Reliability Coordinators. 

These operating entities must communicate their intended operating actions to their 

Reliability Coordinator who is responsible for assessing the overall interconnection 

reliability impact and authorizing the implementation of these operating actions. Unclear 

responsibilities and authorities of Reliability Coordinators may leave a gap in the 

communication, assessment and authorization process and may result in a significant 

adverse impact on the reliable operation of the interconnected grid. Currently, the 

standards do not explicitly assign responsibilities to Reliability Coordinators in the 

Purposes or Requirements. Assignment can only be inferred from the definition of 

Reliability Coordinator in the NERC Glossary.112 The Blackout Report recommended 

that NERC develop clear roles, responsibilities, and authorities for Reliability 

Coordinators to ensure effective and timely action in critical situations.113 

2. Operation Under Normal and Post-Contingency Conditions 

In real-time, system operating conditions constantly change from one operating state to 

another to accommodate changes in demand, generation dispatches, interchange 

schedules, planned element outages, and system contingencies. The Interconnection 

Reliability Operating Limit (IROL) is the level above which the system may cascade if a 

critical contingency occurs. The standards state 

If a potential or actual IROL violation cannot be avoided through proactive 

intervention, the Reliability Coordinator shall initiate actions or emergency 

procedures to relieve the violation without delay, and no longer than 30 

minutes. The Reliability Coordinator shall ensure all resources, including 

load shedding, are available to address a potential or actual IROL 

violation.[114]

 

 112 NERC Glossary at 13. 

113 Blackout Report at 158. 

114 Standard IRO-005-1 (R3) . 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 68 - 

Chapter: IRO 

One interpretation of this Requirement allows an IROL to be exceeded during normal 

operation (prior to a contingency), provided that corrective actions are taken within 30 

minutes. In this interpretation, if a single critical contingency115 were to occur, it would 

result in instability, uncontrolled separation or perhaps cascading outages. A more 

conservative interpretation of this Requirement is that an IROL should only be exceeded 

after a contingency and the system must subsequently be returned to a secure condition as 

soon as possible, but in no longer than 30 minutes. 

3. Specificity on Wide Area View 

The NERC Glossary defines Wide Area as “[t]he entire Reliability Coordinator Area as 

well as the critical flow and status information from adjacent Reliability Coordinator 

Areas as determined by detailed system studies to allow the calculation of Interconnected 

Reliability Operating Limits.”116 Wide Area visualization allows Reliability 

Coordinators to maintain situational awareness over neighboring areas.117 Thus, 

Reliability Coordinators must be continuously aware of the status and loading of critical 

facilities in neighboring systems that could have an adverse impact on their own system. 

Inadequate reliability tools and backup capabilities contributed to a lack of situational 

awareness and played an integral role in causing the August 14, 2003 blackout.118 The 

Blackout Report emphasizes that “[t]he need for improved visualization capabilities over 

a wide geographic area has been a recurrent theme in blackout investigations.”119 The 

Blackout Report recommends that NERC work with control areas and Reliability 

Coordinators to “[c]larify criteria for identification of operationally critical facilities, and 

improve dissemination of updated information on unplanned outages.”120 The IRO 

standards do not specify the criteria for identifying critical facilities whose operating 

status can affect the reliability of neighboring systems and, therefore, hampers effective 

Wide Area visualization. 

 115 The unexpected failure or outage of a system component, such as a generator, transmission 

line, circuit breaker, switch or other electrical element. 

116 NERC Glossary at 18. 

117 Id. 

118 See Blackout Report at 159. 

119 Id. 

120 Id. at 163. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 69 - 

Chapter: IRO 

4. Use of Transmission Loading Relief 

Transmission Loading Relief (TLR) procedures are used to relieve overloads on 

transmission facilities by curtailing and adjusting transactions. The existing TLR 

procedures, with the exception of the last step invoking load shedding, are likely 

incapable of being implemented quickly enough to achieve the desired goal of relieving 

IROL violations in less than 30 minutes. In reviewing the control area and Reliability 

Coordinator transcripts from August 14, 2003, the Task Force concluded that the TLR 

process is “cumbersome, perhaps unnecessarily so, and not fast and predictable enough 

for use in situations in which an Operating Security Limit [SOL] is close to or actually 

being violated.”121 The Task Force also recommended that NERC “[c]larify that the 

transmission loading relief (TLR) process should not be used in situations involving an 

actual violation of an Operating Security Limit [SOL].”122 The current IRO standards 

allow the utilization of the TLR procedure to mitigate potential and actual SOL or IROL 

violations on any transmission facility. The IRO standards could potentially lead system 

operators to inappropriately use transmission loading relief procedures to mitigate actual 

IROL violations. In doing so, valuable time that could be utilized to re-adjust the system 

by other, more effective, operating measures would be lost.123

C. Concerns Specific to Individual Standards 

Reliability Coordination – Responsibilities and Authorities (IRO-001-0) 

The purpose of this standard reads: 

Reliability Coordinators must have the authority, plans, and agreements in 

place to immediately direct reliability entities within their Reliability 

Coordinator Areas to re-dispatch generation, reconfigure transmission, or 

reduce load to mitigate critical conditions to return the system to a reliable 

state. If a Reliability Coordinator delegates tasks to others, the Reliability 

 121 Blackout Report at 163 (Note - the NERC Glossary defines System Operating Limit (SOL) as 

the “value (such as MW, MVar, Amperes, Frequency or Volts) that satisfies the most limiting of the 

prescribed operating criteria for a specified system configuration to ensure operation within acceptable 

reliability criteria.”). 

122 Blackout Report at 163. 

123 For example, consider the findings of the Blackout Report as to why the blackout began. The 

Report, when considering the utilities’ decision to use TLR to relieve overload, states “The only way that 

these high loadings could have been relieved would not have been from the redispatch that AEP requested 

[which is TLR], but rather from significant load-shedding by [First Energy] in the Cleveland area.” 

Blackout Report at 63. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 70 - 

Chapter: IRO 

Coordinator retains its responsibilities for complying with NERC and 

regional standards. Standards of conduct are necessary to ensure the 

Reliability Coordinator does not act in a manner that favors one market 

participant over another. 

This standard does not explicitly assign responsibilities to Reliability Coordinators in its 

Purpose or Requirements. Assignment can only be inferred from the definition of 

Reliability Coordinator in the NERC Glossary.124 This issue is discussed in more detail in 

the Primary Issues section under the heading “Unclear Responsibilities and Authorities of 

Reliability Coordinators.” 

Reliability Coordination – Facilities (IRO-002-0) 

The purpose of this standard reads: “Reliability Coordinators need information, tools and 

other capabilities to perform their responsibilities.” 

The standard does not have any Compliance Measures and Levels of Noncompliance and 

without such specificity, the ERO will not have norms that are specific enough to 

implement consistent and effective enforcement. NERC has indicated that this standard 

will be modified to address this deficiency and resubmitted for Commission approval in 

November 2006. 

Reliability Coordination – Wide Area View (IRO-003-0) 

The purpose of this standard reads: 

The Reliability Coordinator must have a wide area view of its own 

Reliability Coordinator Area and that of neighboring Reliability 

Coordinators. 

The standard states as a Requirement that 

When a Reliability Coordinator is aware of an operational concern, such as 

declining voltages, excessive reactive flows, or an IROL violation, in a 

neighboring Reliability Coordinator Area, it shall contact the Reliability 

Coordinator in whose area the operational concern was observed. The two 

Reliability Coordinators shall coordinate any actions, including emergency 

assistance, required to mitigate the operational concern.[125]

 

 124 NERC Glossary at 13. 

125 Standard IRO-003-0 R2. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 71 - 

Chapter: IRO 

This standard does not specify the criteria for defining critical facilities in adjacent 

systems whose status and loading conditions could affect the reliability of neighboring 

systems. An in-depth discussion of staff’s concerns regarding this standard appears in the 

Primary Issues section of this chapter under the heading “Specificity on Wide Area 

View.”

NERC’s Version 1 IRO-003-1 standard was recently approved by the NERC Board of 

Trustees with an effective date of August 1, 2006. However, the revised reliability 

standard does not address the concern raised above. 

Without Compliance Measures and Levels of Non-Compliance in either Version 0 or 

Version 1, the ERO will not have norms that are specific enough to implement consistent 

and effective enforcement. NERC has indicated that this standard will be modified to 

address this deficiency and resubmitted for Commission approval in November 2006. 

Reliability Coordination – Operations Planning (IRO-004-1) 

The purpose of this standard reads: 

Each Reliability Coordinator must conduct next-day reliability analyses for 

its Reliability Coordinator Area to ensure the Bulk Electric System can be 

operated reliably in anticipated normal and Contingency conditions. 

System studies must be conducted to highlight potential interface and other 

operating limits, including overloaded transmission lines and transformers, 

voltage and stability limits, etc. Plans must be developed to alleviate 

System Operating Limit (SOL) and Interconnection Reliability Operating 

Limit (IROL) violations. 

Other standards require the system to be operated in a manner that allows it to be returned 

to a stable state as soon as possible but no longer than 30 minutes after a contingency 

occurs and to be able to withstand another contingency without cascading. However, this 

standard does not require that the system be assessed in the next-day planning analysis to 

identify the control actions needed to bring the system back to a stable state, with an 

effective implementation time of within 30 minutes, so that the system will be able to 

withstand the next contingency without cascading. 

Reliability Coordination – Current Day Operations (IRO-005-1) 

The purpose of this standard reads: 

The Reliability Coordinator must be continuously aware of conditions 

within its Reliability Coordinator Area and include this information in its 

reliability assessments. The Reliability Coordinator must monitor Bulk 

Electric System parameters that may have significant impacts upon the 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 72 - 

Chapter: IRO 

Reliability Coordinator Area and neighboring Reliability Coordinator 

Areas. 

This standard is ambiguous in that it allows different interpretations in respecting IROL 

limits under normal and contingency conditions as discussed in section B.2 above. This 

version of the standard was recently approved by the NERC Board of Trustees with an 

effective date of November 1, 2006. 

Without Compliance Measures and Levels of Non-Compliance, the ERO will not have 

norms that are specific enough to implement consistent and effective enforcement. 

NERC has indicated that this standard will be modified to address this deficiency and 

resubmitted for Commission approval in November 2006. 

Reliability Coordination – Transmission Loading Relief (IRO-006-1) 

The purpose of this standard reads: 

Regardless of the process it uses, the Reliability Coordinator must direct its 

Balancing Authorities and Transmission Operators to return the 

transmission system to within its Interconnection Reliability Operating 

Limits as soon as possible, but no longer than 30 minutes. The Reliability 

Coordinator needs to direct Balancing Authorities and Transmission 

Operators to execute actions such as reconfiguration, re-dispatch, or load 

shedding until relief requested by the TLR process is achieved. 

Requirement R2 of this standard states that: 

A Reliability Coordinator experiencing a potential or actual SOL or IROL 

violation within its Reliability Coordinator Area shall, at its discretion, 

select from either a “local” (Regional, Interregional, or subregional) 

transmission loading relief procedure or an Interconnection-wide 

procedure.”[126]

 

This standard does not address the concerns expressed in the Blackout Report that call for 

“clarify[ing] that the transmission loading relief (TLR) process should not be used in 

situations involving an actual violation of an Operating Security Limit [SOL].”127 While 

the intent of the standard as expressed in the Purpose statement is appropriate, 

Requirement R2 could lead reliability entities to deploy inappropriate operating 

measures, such as TLR procedures, to mitigate actual IROL violations. Staff’s concerns 

 126 Standard IRO-006-1 (R2). 

127 Blackout Report, Recommendation Number 31 at 163. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 73 - 

Chapter: IRO 

regarding this standard are more fully addressed in the Primary Issues section of this 

chapter under the heading “Use of Transmission Loading Relief.”

Procedures, Processes, or Plans to Support Coordination Between Reliability 

Coordinators (IRO-014-1) 

The purpose of this standard reads: 

To ensure that each Reliability Coordinator’s operations are coordinated 

such that they will not have an Adverse Reliability Impact on other 

Reliability Coordinator Areas and to preserve the reliability benefits of 

interconnected operations.” 

No substantive issues were identified for this standard at this time. 

Notifications and Information Exchange Between Reliability Coordinators 

(IRO-015-1) 

The purpose of this standard reads: 

To ensure that each Reliability Coordinator’s operations are coordinated 

such that they will not have an Adverse Reliability Impact on other 

Reliability Coordinator Areas and to preserve the reliability benefits of 

interconnected operations. 

No substantive issues were identified for this standard at this time. 

Coordination of Real-time Activities Between Reliability Coordinators (IRO-016-1) 

The purpose of this standard reads: 

To ensure that each Reliability Coordinator’s operations are coordinated 

such that they will not have an Adverse Reliability Impact on other 

Reliability Coordinator Areas and to preserve the reliability benefits of 

interconnected operations. 

No substantive issues were identified for this standard at this time. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 74 - 

XI. MOD: MODELING, DATA, AND ANALYSIS 

A. Description and General Issues 

The Modeling, Data, and Analysis group of the current reliability standards consists of 23 

standards aimed at RROs, Transmission Service Providers, Transmission Owners, 

Transmission Planners, Generation Owners, Resource Planners, Planning Authorities, 

and Load-Serving Entities.128 The standards may be grouped into four distinct categories. 

The first category covers documentation, review, and validation of Total Transfer 

Capacity (TTC), Available Transfer Capacity (ATC), Capacity Benefit Margin (CBM), 

and Transmission Reliability Margin (TRM) calculations and is applicable to the 

RROs.129 The second category covers steady-state and dynamics data and models and is 

applicable to Transmission Owners, Transmission Planners, Generation Owners, 

Resource Planners, and the RROs.130 The third category covers actual and forecast 

demand data and is applicable to the RROs, Transmission Planners, Planning Authorities, 

Load-Serving Entities, and Resource Planners.131 The fourth category covers the 

verification of generator real and reactive power capability and is applicable to the RROs 

and Generation Owners. 132 

In general, these standards raise issues with regard to the applicability and Requirements 

sections of the standard. In addition, multiple standards have the same stated purpose 

rather than having purpose statements tailored to the particular goal of each standard. 

Of the 23 standards in this group, fourteen delegate responsibility to the RRO as the 

applicable entity for one or more Requirements to develop methodologies, procedures 

and grant variances. These standards have been referred to as “fill-in-the blank” 

standards. These regional methodologies and procedures have not been submitted to the 

Commission for approval or otherwise been subject to the requirements of section 215. 

The standards therefore pose problems of enforcement. In addition, the RRO is not 

currently defined as a user, owner, or operator of the Bulk-Power system. 

 128 Twenty-one of these Standards are Version 0 Standards, while two were recently approved by 

the NERC Board of Trustees as Version 1 Standards with an effective date of January 1, 2007.

129 North American Electric Reliability Council, Reliability Standards for the Bulk 

Electric Systems of North America, Standards MOD-001-0 to MOD-009-0. 

130 Standards MOD-010-0 to MOD-015-0. 

131 Standards MOD-016-0 to MOD-021-0. 

132 Standards MOD-024-1 to MOD-025-1. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 75 - 

Chapter: MOD 

Implementation of the Blackout Report recommendations regarding reliability involves 

standards MOD-014 and MOD-015 in this group. Below follows a discussion of primary 

issues and an evaluation of individual standards in the context of these observations. 

B. Primary Issues in the Modeling, Data, and Analysis Standards 

1. Quality of System Modeling Data and Data Exchange Practices 

Good data and system models are essential for accurately simulating the performance of 

the Bulk Electric System for use in planning, operations planning, real-time operations 

and after-the-fact analysis of disturbances. The Blackout Report states that “[t]he afterthe-fact models developed to simulate August 14 conditions and events found that the 

dynamic modeling assumptions for generator and load power factors in regional planning 

and operating models were frequently inaccurate. In particular, the assumptions of load 

power factor were overly optimistic – loads were absorbing much more reactive power 

than the pre-August 14 models indicated.”133 To address this deficiency, 

Recommendation Number 24 of the Blackout Report states the need to “[i]mprove 

quality of system modeling data and data exchange practices.”134 In describing the work 

required, the Blackout Report states that “[p]ower flow and transient stability simulations 

should be periodically benchmarked with actual system events to validate model data.”135 

While the standards require that steady state and dynamics data be submitted and that 

steady state and dynamic system models are prepared, there are no requirements to 

validate these models through periodic benchmarking and appropriately modify them 

against actual system events in accordance with Recommendation Number 24 of the 

Blackout Report. 

2. Different Approaches to TTC, ATC, CBM, and TRM 

Methodologies 

ATC is derived from TTC after allowing for existing transmission commitments 

including retail customer service and a Capacity Benefit Margin,136 less a Transmission 

 133 Blackout Report at 160. 

134 Id. 

135 Id.

136 Defined in NERC Glossary as “The amount of TTC preserved by the transmission provider 

for LSEs whose loads are located on that TSPs system, to enable access by the LSE to generation from 

the interconnected system to meet generation reliability requirements.” 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 76 - 

Chapter: MOD 

Reliability Margin.137 The TTC and ATC values must satisfy certain principles that 

balance both technical and commercial issues. The standards leave the development of 

methodologies and the procedures for periodic review of TTC, ATC, CBM and TRM 

calculations to RROs. This has resulted in different interpretations and applications of 

calculation methodologies resulting in different values for ATC when using the same data 

and assumptions. As such, the different approaches could have an undue negative impact 

on competition. The Commission is considering this issue in Docket Nos. RM05-17-000 

and RM05-25-000 and anticipates addressing it in any Notice of Proposed Rulemaking 

that may be issued in those dockets. 

C. Concerns Specific to Individual Standards 

1. Fill-in-the-Blank Standards 

This group of nine standards has one or more Requirements for a RRO to develop 

methodologies and procedures or grant variances for use by users, owners and operators 

within the region. These standards have been referred to as “fill-in-the blank” standards. 

These regional methodologies and procedures have not been submitted to the 

Commission for approval or otherwise subject to the requirements of section 215. The 

standards therefore pose problems of enforcement. In addition, they may result in 

regional differences which may not be necessitated by either a physical difference of the 

Bulk-Power System or the application of a more stringent Reliability Standard. The 

regional differences could have an undue negative impact on competition. In addition, 

the RRO is not currently defined as a user, owner, or operator of the Bulk-Power system. 

These standards are listed as follows: 

Review of TTC and ATC Calculations and Results (MOD-002-0) 

The purpose of this standard reads: 

To promote the consistent and uniform application of transfer capability 

calculations among Transmission System Providers, the Regional 

Reliability Organizations need to review adherence to Regional 

methodologies for calculating Total Transfer Capability (TTC) and 

Available Transfer Capability (ATC). 

This standard requires that each RRO, in conjunction with its members, develop and 

implement a procedure to periodically review (at least annually) and ensure that the TTC 

 137 Defined in NERC Glossary as “The amount of TTC necessary to provide reasonable assurance 

that the interconnected transmission network will be secure.” 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 77 - 

Chapter: MOD 

and ATC calculations and resulting values of member Transmission Service Providers 

comply with the Regional TTC and ATC methodology and applicable Regional criteria. 

Procedure for Input on TTC and ATC Methodologies and Values (MOD-003-0) 

The purpose of this standard reads: 

To promote the consistent and uniform application of Transfer Capability 

calculations among Transmission System Providers, the Regional 

Reliability Organizations need to review adherence to Regional 

methodologies for calculating Total Transfer Capability (TTC) and 

Available Transfer Capability (ATC). 

The standard requires that each RRO, in conjunction with its members, develop and 

document a procedure that transmission users can use to communicate their concerns or 

questions regarding the TTC and ATC methodology and values of the Transmission 

Service Provider(s), and how these concerns or questions will be addressed. 

Regional Steady-State Data Requirements and Reporting Procedures (MOD-011-0) 

The purpose of this standard reads: “To establish consistent data requirements, reporting 

procedures, and system models to be used in the analysis of the reliability of the 

interconnected transmission systems.” 

The standard requires RROs within an Interconnection, in conjunction with the 

Transmission Owners, Transmission Planners, Generator Owners, and Resource 

Planners, to develop comprehensive steady-state data requirements and reporting 

procedures needed to model and analyze the steady-state conditions for each of the 

NERC Interconnections. 

Planning Authorities are not included in the Requirements section of this standard. They 

are the entities responsible for coordination and integration of transmission facilities and 

Resource plans, as well as one of the entities responsible for the integrity and consistency 

of the data. 

Regional Reliability Organization Dynamics Data Requirements and Reporting 

Procedures (MOD-013-0) 

The purpose of this standard reads: “To establish consistent data requirements, reporting 

procedures, and system models to be used in the analysis of the reliability of the 

interconnected transmission systems.” 

The standard requires the RRO, in coordination with its Transmission Owners, 

Transmission Planners, Generator Owners, and Resource Planners, to develop 

comprehensive dynamics data requirements and reporting procedures needed to model 

and analyze the dynamic behavior or response of each of the NERC Interconnections. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 78 - 

Chapter: MOD 

Planning Authorities are not included in the Requirements section of this standard. They 

are the entities responsible for coordination and integration of transmission facilities and 

Resource plans, as well as one of the entities responsible for the integrity and consistency 

of the data. 

Development of Interconnection-Specific Steady State System Models 

(MOD-014-0) 

The purpose of this standard reads: “To establish consistent data requirements, reporting 

procedures, and system models to be used in the analysis of the reliability of the 

interconnected transmission systems.” 

The standard requires that RRO(s) within each Interconnection to coordinate and jointly 

develop and maintain a library of solved (converged) Interconnection specific steadystate system models. 

While the standard requires the development of steady state models, it does not require 

periodic verification or appropriate modification of models against field data in 

accordance with Recommendation Number 24 of the Blackout Report.138

Development of Interconnection-Specific Dynamics System Models (MOD-015-0) 

The purpose of this standard reads: “To establish consistent data requirements, reporting 

procedures, and system models to be used in the analysis of the reliability of the 

interconnected transmission systems.” 

The standard requires the RRO(s) within each Interconnection to coordinate and jointly 

develop and maintain a library of initialized (with no Faults or system Disturbances) 

Interconnection-specific dynamics system models linked to the steady-state system 

models, as appropriate in accordance with Standard MOD-014(R1). 

While the standard requires the development of dynamic models, it does not require 

periodic verification or appropriate modification of models against field data in 

accordance with Recommendation Number 24 of the Blackout Report.139

 138 Blackout Report at 160. 

139 Blackout Report at 160. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 79 - 

Chapter: MOD 

Actual and Forecast Demands, Net Energy for Load, Controllable DSM 

(MOD-016-0) 

The purpose of this standard reads: 

To ensure that assessments and validation of past events and databases can 

be performed, reporting of actual demand data is needed. Forecast demand 

data is needed to perform future system assessments to identify the need for 

system reinforcements for continued reliability. In addition, to assist in 

proper real-time operating, load information related to controllable 

Demand-Side Management (DSM) programs is needed. 

The standard requires that the Planning Authority and RRO have documentation 

identifying the scope and details of the actual and forecast (a) Demand data, (b) Net 

Energy for Load data, and (c) controllable DSM data to be reported for system modeling 

and reliability analyses. 

Staff notes that the Transmission Planner, which is one of the entities involved in 

assuring the integrity and consistency of the load, energy, and DSM data, is not included 

in the applicability. 

Verification of Generator Gross and Net Real Power Capability (MOD-024-1) 

The purpose of this standard reads: “To ensure accurate information on generator gross 

and net Real Power capability is available for steady state models used to assess Bulk 

Electric System reliability.” 

The standard requires the RRO to establish and maintain procedures to address 

verification of generator gross and net Real Power capability. 

Staff notes that the standard does not require definition of the test conditions, e.g., 

ambient temperature, river water temperature, etc., or methodologies for calculating derating factors for other conditions, such as higher ambient temperatures than the test 

temperature. 

Verification of Generator Gross and Net Reactive Power Capability (MOD-025-1) 

The purpose of this standard reads: “To ensure accurate information on generator gross 

and net Reactive Power capability is available for steady state models used to assess Bulk 

Electric System reliability.” 

The standard requires RROs to establish and maintain procedures to address verification 

of generator gross and net Reactive Power capability. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 80 - 

Chapter: MOD 

2. Absence of Consistent Methodology for Calculating ATC 

Five of this group of seven standards have requirements that delegate the development of 

methodologies and procedures for TTC/ATC/CBM/TRM to the RROs. These five 

standards have been referred to as “fill-in-the-blank” standards. The remaining two 

standards delegate the Transmission Service Providers to document their procedures for 

the use of CBM and report the use of CBM by Load Serving Entities. Such delegation 

from all seven standards may result in unnecessary regional variations not justified by 

technical differences and inconsistent application. 

Documentation of TTC and ATC Calculation Methodologies (MOD-001-0) 

The purpose of this standard reads: 

To promote the consistent and uniform application of Transfer Capability 

calculations among users, the Regional Reliability Organization shall 

develop methodologies for calculating Total Transfer Capacity (TTC) and 

Available Transfer Capacity (ATC) that comply with NERC definitions for 

TTC and ATC, NERC Reliability Standards, and applicable Regional 

criteria. 

The standard requires that each RRO, in conjunction with its members, develop and 

document a Regional TTC and ATC methodology. This standard has been referred to as a 

“fill-in-the-blank” standard. 

Staff notes that the RROs have historically calculated TTC/ATC using different 

approaches. 

Documentation of Regional CBM Methodologies (MOD-004-0) 

The purpose of this standard reads: “To promote the consistent and uniform application 

of transmission Transfer Capability margins calculations, Capacity Benefit Margin 

(CBM) must be calculated in a consistent manner.” 

The standard requires each RRO, in conjunction with its members, to develop and 

document a Regional CBM methodology. This standard has been referred to as a “fill-inthe-blank” standard. 

The standard does not specify how CBM is determined and allocated across transmission 

paths. Further, the standard does not address the effect of associated transmission service 

requirements and curtailment provisions on transmission customers. 

The standard does not specify the criteria to be used in determining the inclusion or 

exclusion of generation resources, reserves and loads described in four of its 

Requirements (R1.5, R1.6, R1.9 and R1.10). 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 81 - 

Chapter: MOD 

Procedure for Verifying CBM Values (MOD-005-0) 

The purpose of this standard reads: 

To promote the consistent and uniform application of Transfer Capability 

calculations among transmission system users, the Regional Reliability 

Organizations need to review adherence to Regional methodologies for 

calculating Capacity Benefit Margin (CBM). 

The standard requires each RRO, in conjunction with its members, to develop and 

implement a procedure to review (at least annually) the CBM calculations and the 

resulting values of member Transmission Service Providers to ensure that they comply 

with the RRO’s CBM methodology. It does not, however, actually require there to be a 

consistent and uniform calculation of CBM. This standard has been referred to as a “fillin-the-blank” standard. 

Procedure for the Use of CBM Values (MOD-006-0) 

The purpose of this standard reads: “To promote the consistent and uniform application 

of transmission Transfer Capability margins calculations among transmission system 

users.” 

The standard requires each Transmission Service Provider to document its procedure on 

the use of Capacity Benefit Margin values, but not to implement a consistent and uniform 

calculation of CBM. 

Documentation of the Use of CBM (MOD-007-0) 

The purpose of this standard reads: 

To promote the consistent and uniform application of Transfer Capability 

margin calculations among transmission system users by developing 

methodologies for calculating Capacity Benefit Margin (CBM). This 

methodology shall comply with NERC definitions for CBM, the NERC 

Reliability Standards, and applicable Regional criteria. 

The standard requires each Transmission Service Provider (TSP) to report the use of 

CBM by the Load-Serving Entities (LSEs) to the Region, NERC and the transmission 

users. 

The standard does not specify how CBM should be reserved to allow both Transmission 

Providers and Transmission Customers to meet their respective generation reliability 

criteria. 

Documentation and Content of Each Regional TRM Methodology (MOD-008-0) 

The purpose of this standard reads: 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 82 - 

Chapter: MOD 

To promote the consistent application of transmission Transfer Capability 

margin calculations among Transmission Service Providers and 

Transmission Owners, each Regional Organization shall develop a 

methodology for calculating Transmission Reliability Margin (TRM). This 

methodology shall comply with the NERC definition for TRM, the NERC 

Reliability Standards, and applicable Regional criteria. 

The standard requires each RRO, in conjunction with its members, to develop and 

document a Regional TRM methodology. This standard has been referred to as a “fill-inthe-blank” standard. The standard does not specify how TRM is determined and 

allocated across transmission paths. 

Requirement R1.5 requires the description of the formal process for the RRO to grant 

variances from the Regional TRM methodology. The standard does not specify the 

criteria for granting variances. 

Procedure for Verifying TRM Values (MOD-009-0) 

The purpose of this standard reads: “To promote the consistent application of 

transmission Transfer Capability margin calculations among Transmission System 

Providers and Transmission Owners.” 

The standard requires each RRO, in conjunction with its members, to develop and 

implement a procedure to review Transmission Reliability Margin (TRM) calculations 

and resulting values of member Transmission Service Providers. This provision is to 

ensure that the Transmission Service Providers comply with the Regional TRM 

methodology, and are periodically updated and available to transmission users. This 

standard has been referred to as a “fill-in-the-blank” standard. 

3. Omission of the Planning Authority as an Applicable entity 

This group of two standards, which covers data requirements for steady state and 

dynamic simulations, does not include the Planning Authority as an applicable entity. 

They are the entities responsible for coordination and integration of transmission 

facilities and Resource plans, as well as one of the entities responsible for the integrity 

and consistency of the data. 

These standards are listed as follows: 

Steady-State Data for Transmission System Modeling and Simulation 

(MOD-010-0) 

The purpose of this standard reads: “To establish consistent data requirements, reporting 

procedures, and system models to be used in the analysis of the reliability of the 

Interconnected Transmission Systems.” 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 83 - 

Chapter: MOD 

The standard requires the Transmission Owners, Transmission Planners, Generator 

Owners, and Resource Planners to provide appropriate equipment characteristics, system 

data, and existing and future Interchange Schedules in compliance with its respective 

Interconnection Regional steady-state modeling and simulation data requirements and 

reporting procedures as defined in Standard MOD-011-0(R1). 

Dynamics Data for Transmission System Modeling and Simulation (MOD-012-0) 

The purpose of this standard reads: “To establish consistent data requirements, reporting 

procedures, and system models to be used in the analysis of the reliability of the 

interconnected transmission systems.” 

The standard requires the Transmission Owners, Transmission Planners, Generator 

Owners, and Resource Planners to provide appropriate equipment characteristics and 

system data in compliance with the respective Interconnection-wide Regional dynamics 

system modeling and simulation data requirements and reporting procedures as defined 

by Standard MOD-013-0(R4). 

4. Accuracy and Bias of Load Forecasts 

This group of five standards addresses actual data, forecast data, and demand 

management. The standards do not require a consistent methodology in validating and 

forecasting demand Specifically, there are no requirements to report the accuracy, error 

and bias of load forecasts. Staff notes that several standards in this group address separate 

matters but have identical purpose statements. Generally, staff suggests such statements 

be augmented or tailored to reflect the specific aspect of the purpose the given standard is 

designed to achieve. These standards are listed as follows: 

Aggregated Actual and Forecast Demands and Net Energy for Load (MOD-017-0) 

The purpose of this standard reads: 

To ensure that assessments and validation of past events and databases can 

be performed, reporting of actual demand data is needed. Forecast demand 

data is needed to perform future system assessment to identify the need for 

system reinforcement for continued reliability. In addition, to assist in 

proper real-time operating, load information related to controllable 

Demand-Side Management programs is needed. 

The standard requires the Load-Serving Entity, Planning Authority and Resource Planner 

to each annually provide demand in MW and energy in GWh reported by hour, month 

and year. Each of these needs to be aggregated by Regional, sub-regional, Power Pool, 

and individual system or Load-Serving Entity bases to NERC, the RROs and others as 

specified in Standard MOD-016-0(R1). 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 84 - 

Chapter: MOD 

Reports of Actual and Forecast Demand Data (MOD-018-0) 

The purpose of this standard reads: 

To ensure that Assessments and validation of past events and databases can 

be performed, reporting of actual Demand data is needed. Forecast demand 

data is needed to perform future system assessments to identify the need for 

system reinforcements for continued reliability. In addition, to assist in 

proper real-time operating, load information related to controllable 

Demand-Side Management programs is needed. 

The standard requires Load-Serving Entities, Planning Authorities, Transmission 

Planners, and Resource Planners to indicate whether the demand data of nonmember 

entities within an area or Region are included and to address assumptions, methods, and 

the manner in which uncertainties are treated. 

Forecasts of Interruptible Demands and DCLM Data (MOD-019-0) 

The purpose of this standard reads: 

To ensure that assessments and validation of past events and databases can 

be performed, reporting of actual demand data is needed. Forecast demand 

data is needed to perform future system assessments to identify the need for 

system reinforcements for continued reliability. In addition, to assist in 

proper real-time operating, load information related to controllable 

Demand-Side Management programs is needed. 

The standard requires Load-Serving Entities, Planning Authorities, and Transmission 

Planners to annually provide forecasts of interruptible demand and Direct Control Load 

Management (DCLM) to NERC, the RROs and other entities as specified in Standard 

MOD-016(R1). 

Providing Interruptible Demands and DCLM Data (MOD-020-0) 

The purpose of this standard reads: 

To ensure that assessments and validation of past events and databases can 

be performed, reporting of actual demand data is needed. Forecast demand 

data is needed to perform future system assessments to identify the need for 

system reinforcement for continued reliability. In addition, to assist in 

proper real-time operating, load information related to controllable 

Demand-Side Management programs is needed. 

The standard requires Load-Serving Entities, Planning Authorities, Transmission 

Planners, and Resource Planners to each make known its amount of interruptible demand 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 85 - 

Chapter: MOD 

and Direct Control Load Management (DLCM) to Transmission Operators, Balancing 

Authorities, and Reliability Coordinators on request within 30 days. 

Accounting Methodology for Effects of Controllable DSM in Forecasts 

(MOD-021-0) 

The purpose of this standard reads: 

To ensure that assessments and validation of past events and databases can 

be performed, reporting of actual demand data is needed. Forecast demand 

data is needed to perform future system assessments to identify the need for 

system reinforcement for continued reliability. In addition, to assist in 

proper real-time operating, load information related to controllable 

Demand-Side Management (DSM) programs is needed. 

The standard requires Load Serving Entities, Planning Authorities, Transmission 

Planners, and Resource Planners to document how they address DSM impacts in their 

forecasts for peak demand and energy requirements. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 86 - 

XII. PER: PERSONNEL PERFORMANCE, TRAINING AND 

QUALIFICATIONS 

A. Description and General Issues 

The four Personnel Performance, Training and Qualifications (PER) standards apply to 

Transmission Operators, Reliability Coordinators, and Balancing Authorities. These 

reliability standards include such topics as operating personnel responsibility and 

authority, operating personnel training, operating personnel credentials, and reliability 

coordination staffing. 

Staff’s concerns about the PER standards generally relate to Measures, Compliance, 

Requirements, and susceptibility to multiple interpretations. 

Of the four reliability standards in this group, one does not contain criteria or measures to 

assess compliance with the Requirements or ascertain the Levels of Non-Compliance 

required for enforcement. NERC has indicated that this standard will be modified to 

address this deficiency and resubmitted for Commission approval in November 2006. 

In its review, staff identified three PER standards that contain technical issues either 

because they may be incomplete or lack specificity and therefore might not adequately 

protect the reliable operation of the Bulk-Power System. Some of the standards fail to 

address the knowledge gained from past operating incidents. Other reliability standards 

are ambiguous regarding the requirements for compliance. In addition, the applicability 

of two of the reliability standards appears to be too narrow in scope. 

Also, if left unresolved, the issue of conflicting definitions concerning the Bulk-Power 

System vs. the Bulk Electric System, discussed in the Common Issues Chapter of this 

document, would add to interpretation and enforceability problems for the standards in 

this chapter. 

Implementation of the Blackout Report recommendations regarding reliability involves 

standards PER-002 through PER-004 in this group. The following is a discussion of the 

primary issues and an evaluation of individual reliability standards in light of these 

observations.
FERC Staff Preliminary Assessment of NERC Reliability Standards - 87 - 

Chapter: PER 

B. Primary Issues in the Personnel Performance, Training and 

Qualifications Reliability Standards 

1. Scope of Applicability 

The Personnel Performance, Training and Qualifications reliability standards require each 

Transmission Operator and Balancing Authority to have training programs for all of their 

operating personnel who occupy positions that either have the primary responsibility, 

directly or through communication with others, for real-time operation of the 

interconnected Bulk Electric System or who are directly responsible for complying with 

the NERC reliability standards. However, Transmission Operators and Balancing 

Authorities are not the only entities that have operating personnel who, directly or 

indirectly, have the capacity to impact the reliable operation of the Bulk-Power System or 

who are directly responsible for complying with the reliability standards. Reliability 

Coordinators, Generator Operators, Operations Planning, and Operations Support staff 

also potentially impact the reliable operation of the Bulk-Power System yet these entities 

are not required by the existing standards to participate in a mandatory training program 

consistent with their roles, responsibilities, authorities and tasks. 

2. Training Program Objectives 

The Blackout Report reviewed several previous major North American outages and 

concluded that inadequate operator training was a contributory factor that the August 14, 

2003 Blackout had in common with earlier major outages.140 The Blackout Report 

identified training-related recommendations made in studies of major outages: 

• Thorough programs and schedules for operator training and retraining 

should be vigorously administered. 

• A full-scale simulator should be made available to provide operator training 

personnel with “hands-on” experience in dealing with possible emergency 

or other system conditions. 

• Procedures and training programs for system operators should include 

anticipation, recognition, and definition of emergency situations.[141]

 

Inadequate Operator training has contributed to several of the past major system 

disturbances.142 In the Blackout Report, the Task Force stated that some Reliability 

 140 Blackout Report at 107. 

141 Id. at 110 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 88 - 

Chapter: PER 

Coordinators and Control Area Operators did not receive adequate training in recognizing 

and responding to system emergencies.143 In fact, the “deficiency in training contributed 

to the lack of situational awareness and failure to declare an emergency on August 14 

while operator intervention was still possible (before events began to occur at a speed 

beyond human control).”144 According to the Blackout Report, the improvement of nearterm and long-term training and certification requirements for operators, reliability 

coordinators and operator support staff will aid in the proper recognition and adequate 

response to emergencies.145 The Task Force suggested that NERC require training for the 

planning staff at control areas and Reliability Coordinators concerning power system 

characteristics and load, VAr, and voltage limits to enable them to develop rules for 

operating staff to follow.146 In addition, the Task Force urged NERC to “require control 

areas and reliability coordinators to train grid operators, IT support personnel and their 

supervisors to recognize and respond to abnormal automation system activity.”147 

Further, NERC was advised by the Task Force to “commission an advisory report by an 

independent panel to address a wide range of issues concerning reliability training 

programs and certification requirements.”148 The existing NERC standards do not 

address these conclusions identified in the Blackout Report. 

The PER standards do not require training programs tailored to the needs of the 

respective functions with differing authorities, responsibilities, roles and tasks. The 

standards require that each Transmission Operator and Balancing Authority provide a 

training program for all specified operating personnel to ensure their operating 

proficiency.149 While this standard sets out broad objectives that a training program must 

satisfy, it does not specify the minimum expectations of a training program or the 

minimum number of hours of training (other than a requirement of five days per year for 

realistic simulation training) consistent with the roles, responsibilities and authorities of 

operating and support personnel. Therefore, the nature, objective, and criteria of operator 

 142 Id at 107. 

143 Id. at 157. 

144 Id. 

145 Id., Recommendation Number 19 at 156 (“The task force supports [these] near-term 

requirements strongly.”) (emphasis added). 

146 Id., Recommendation Number 19A at 156. 

147 Id., Recommendation Number 19B at 157. 

148 Id., Recommendation Number 19C at 157. 

149 See North American Reliability Council, Reliability Standards for the Bulk Electric Systems of 

North America, Operating Personnel Training, Standard PER-002-0 (R3.3) (effective Apr. 1, 2005).
FERC Staff Preliminary Assessment of NERC Reliability Standards - 89 - 

Chapter: PER 

training programs and minimum hours of training are open to interpretation. This lack of 

specificity allows programs to vary widely with each Transmission Operator or 

Balancing Authority and still comply with the PER standards. 

Staff notes that EPAct 2005 contains a provision for training guidelines for non-nuclear 

electric energy industry personnel.150 The training guidelines outlined in EPAct 2005 

apply to workers engaged in the construction, operation, inspection or maintenance of 

non-nuclear electric generation, transmission or distribution systems and include, among 

others, requirements for competency, initial certification, assessment, and recertification.151

Additionally, staff notes that there is a widely-accepted Systematic Approach to Training 

(SAT) methodology that has been successfully used in the electric industry as well as 

other industries.152 SAT is credited with ensuring that training is conducted efficiently, 

effectively and directly related to the needs of the position in question.153 Staff notes that 

the training program specifics in the standard might be greatly enhanced by considering 

some of the objectives and elements of the widely-accepted SAT concept. 

3. Operating Personnel Certification 

These standards require each Transmission Operator, Balancing Authority and Reliability 

Coordinator to staff all operating positions that have a primary responsibility for real-time 

operations or are directly responsible for complying with the reliability standards with 

NERC-certified staff. Generator Operators, who have responsibility for the real-time 

operation of the Bulk Electric System and are directly responsible for complying with 

NERC reliability standards, are not similarly required to be NERC-certified. Moreover, 

these standards do not specify the competencies operating personnel must demonstrate to 

 150 EPAct 2005, Pub. L. No. 109-58, § 1103(a), 119 Stat. 594 (providing for the development of 

personnel training guidelines by the Department of Labor in consultation with DOE, to support the 

reliability and safety of the electric system). 

151 Id. at § 1103(b)(1). 

152 10 C.F.R. 50.120(b) (2006) (For example, the SAT approach is required by the Nuclear 

Regulatory Commission for Nuclear Power Plant Operator training). 

153 SAT objectives include: Management and Administration of Training and Qualification 

Programs; Development and Qualification of Training Staff; Trainee Entry-level Requirements; 

Determination of Training Program Content; Design and Development of Training Programs; Conduct of 

Training; Trainee Examinations and Evaluations; Training Program Evaluation. U.S. Department of 

Energy, Guidelines for Evaluation of Nuclear Facility Training Programs. Department of Energy, 

Standard 1070-94 Appendix (effective June 1994). 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 90 - 

Chapter: PER 

meet the certification requirements. NERC’s System Operator Certification Program 

Manual outlines the requirements for certification, but the manual is not part of the 

standard and therefore is not enforceable.154

C. Concerns Specific to Individual Reliability Standards 

Operating Personnel Responsibility and Authority (PER-001-0) 

The purpose of this standard reads: “Transmission Operators and Balancing Authority 

operating personnel have the responsibility and authority to implement real-time actions 

to ensure the stable and reliable operation of the Bulk Electric System.” 

There are no substantive issues identified with this standard at this time.

Operating Personnel Training (PER-002-0) 

The purpose of this standard reads: “Each Transmission Operator and Balancing 

Authority must provide their personnel with a coordinated training program that will 

ensure reliable system operation.” 

Reliability Coordinators, Generator Operators, Operations Planning and Operations 

Support staff are not included in this training requirement. 

This standard does not specify minimum training programs, nor does it tailor training 

programs according to the needs of Reliability Coordinators, Balancing Authorities, 

Transmission Operators, Generator Operators, and Operation Planning and support 

personnel with differing authorities, responsibilities, roles and tasks. Further discussion 

is provided above in section B.2 entitled, “Training Program Objectives.” 

Operating Personnel Credentials (PER-003-0) 

The purpose of this standard reads: “Certification of operating personnel is necessary to 

ensure minimum competencies for operating a reliable Bulk Electric System.” 

While the reliability standards require positions that have primary responsibility for realtime operation of the interconnected Bulk Electric System or positions that are directly 

responsible for complying with the NERC reliability standards to be filled with NERCcertified staff, the standards do not specify minimum certification requirements. NERC’s 

System Operator Certification Program Manual outlines the requirements for 

 154 See NERC’s Application for Certification as the Electric Reliability Organization, Rules of 

Procedure of the Electric Reliability Organization, System Operator Certification Program Manual,

Appendix 6 available at ftp://www.nerc.com/pub/sys/all_updl/ero/application/ERO-ApplicationComplete.pdf. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 91 - 

Chapter: PER 

certification.155 However, the manual is not part of the standard and, thus the standard 

lacks an enforceable requirement in regard to system operator certification. Staff’s 

concerns regarding this standard are further addressed under the section of this chapter 

entitled “Operating Personnel Certification.” 

Reliability Coordination – Staffing (PER-004-0) 

The purpose of this standard reads: “Reliability Coordinators must have sufficient, 

competent staff to perform Reliability Coordinator functions.” 

Most of this standard addresses training issues, yet there is no requirement for a formal 

training program for Reliability Coordinators that is similar to the program required for 

Transmission Operators under standard PER-002-0. 

Without Compliance Measures and Levels of Non-compliance, the ERO will not have 

benchmarks to implement consistent and effective enforcement. NERC has indicated that 

this standard will be modified to address this deficiency and resubmitted for Commission 

approval in November 2006. 

 155 North American Electric Reliability Council’s Application for Certification as the Electric 

Reliability Organization, Rules of Procedure of the Electric Reliability Organization, System Operator 

Certification Program Manual, Appendix 6 available at

ftp://www.nerc.com/pub/sys/all_updl/ero/application/ERO-Application-Complete.pdf. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 92 - 

XIII. PRC: PROTECTION AND CONTROL 

A. Description and General Issues

Protection and Control systems (PRC) on Bulk-Power System elements are an integral 

part of reliable grid operations. Protection systems are designed to detect faults and 

isolate the faulted elements from the system, thereby limiting the severity and 

propagation of system disturbances and preventing possible damage to protected 

elements. System Operating Limits and Interconnection Reliability Operating Limits are 

only valid when they recognize the protection system functionalities, settings and 

limitations. From the blackout on November 9, 1965 to the August 14, 2003 Blackout, 

one of the common factors among the major outages was the lack of coordination of 

system protection.156 

Generally, these standards raise Measures, Compliance, and Requirements issues. The 

PRC standards consist of sixteen Version 0 standards and six Version 1 standards that 

apply to Transmission Operators, Transmission Owners, Generator Operators, 

Distribution Providers and RROs.157 They cover a wide range of topics related to the 

protection and control of power systems.158 However, NERC has recognized that these 

standards do not form a complete set of Protection and Control standards to meet the goal 

of reliability. The NERC Planning Standards state in relevant part: 

Certain planning standards that were a part of the Phase III- IV NERC 

compliance program were not included in the Version 0 reliability 

standards...[t]hese standards are important, nonetheless, as they contain 

critical reliability requirements in support of recommendations from the 

NERC and U.S./Canada Power System Outage Task Force reports on the 

August 14, 2003 Blackout...the NERC board resolved on October 15, 

2004, that: "A satisfactory resolution of the issues regarding Phases III and 

IV of the planning standards would be to: (1) develop reliability standards 

covering the Phase III and Phase IV issues separate from the Version 0 

 156 Blackout Report at 107. 

157 Three of the six Version 1 standards are intended to replace their Version 0 equivalents with 

effective dates of May 1, 2006 for PRC-003-1; August 1, 2006 for PRC-004-1; and May 1, 2006 for PRC005-1. 

158 Topics addressed under the PRC standards include: system protection coordination, 

disturbance monitoring, under-frequency load shedding (UFLS), special protection systems, undervoltage load shedding (UVLS) and their assessments, database, event and mis-operation analysis, 

maintenance and testing requirements, and performance evaluation. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 93 - 

Chapter: PRC 

effort, using the NERC standards development process; (2) have the 

Planning Committee expeditiously complete the drafting of the proposed 

standards needed to address the Phase III and Phase IV issues..." The SAR 

[Standards Authorization Request] propose[d] the development of 

reliability standards that address[ed] the disturbance monitoring and 

reporting requirements of those Phase III- IV planning standards.[159]

Implementation of the Blackout Report recommendations regarding reliability involves 

standards PRC-002, PRC-006, and PRC-020 through PRC-022 in this group. Also, if left 

unresolved, the issue of conflicting definitions concerning the Bulk-Power System vs. the 

Bulk Electric System, discussed in the Common Issues Chapter of this document, would 

add to interpretation and enforceability problems for the standards in this chapter. The 

following is a discussion of the primary issues and an evaluation of individual PRC 

standards in light of these observations. 

B. Primary Issues in the Protection and Control Standards 

1. Ambiguous Requirements for Protection Failures 

The failure of a protection system has the potential to result in major outages or 

cascading. If a non-redundant protection system for a critical element fails and no 

corrective action is taken, the system could be subject to the risk of cascading if a critical 

contingency subsequently occurred. The PRC standards require that where a protective 

relay or equipment failure reduces system reliability, Transmission Operators or 

Generator Operators shall take corrective action as soon as possible.

160 However, the 

PRC standards do not designate a limit to the time period for corrective actions. 161 This 

is inconsistent with the requirement that System Operators initiate actions or emergency 

procedures to re-adjust the system as soon as possible and no later than 30 minutes after a 

contingency to minimize reliability risks under the IRO and TOP standards. 

 159 See NERC Planning Standards Phase III-IV, available at

http://www.nerc.com/~filez/standards/Phase-III-IV.html. 

160 Standard PRC-001-0 (R2.1-2) (emphasis added). 

161 Corrective actions may include removing system elements, operating to a lower limit that 

does not impact reliability, etc. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 94 - 

Chapter: PRC 

2. Integrated and Coordinated Approach to Bulk-Power System 

Protection

Under-frequency load shedding (UFLS) and under-voltage load shedding (UVLS) are 

protection systems designed to detect abnormal conditions in the system and assist in 

preventing possible cascading by shedding load automatically at specific locations and 

for specified abnormal conditions. UFLS and UVLS act as a safety net for the grid. 

Generation protection systems disconnect the generator to prevent damage to the 

generator. Line protection systems are designed to sense faults in the lines and, where 

detected, take the faulty line out of service. An integrated and coordinated approach 

between UFLS, UVLS, line protection and generation protection is needed to “ensure that 

at the local and regional level these interactive components provide an appropriate 

balance of risks and benefits in terms of protecting specific assets and facilitating overall 

grid survival.”162 

In assessing protection measures, the Task Force recommended that NERC “[m]ake more 

effective and wider use of system protection measures.”163 In particular, the Task Force 

urged NERC to “determine the goals and principles needed to establish an integrated 

approach to relay protection for generators and transmission lines and the use of underfrequency and under-voltage load shedding (UFLS and UVLS) programs.”164 Currently, 

the PRC standards are not specific enough to be interpreted as requiring an integrated and 

coordinated approach to achieving the above goals and principles. 

3. Criteria for Maintenance and Testing of Protection Systems 

Protection systems must be maintained and tested at regular intervals to ensure that they 

will operate as intended when called upon. Maintenance intervals vary depending on the 

type and nature of the protection systems, as well as the reliability impact of a potential 

failure of those systems. These standards do not specify the criteria to determine the 

appropriate maintenance intervals, nor do the standards specify maximum allowable 

maintenance intervals for the protection systems. As the standards do not designate a 

maximum maintenance interval based on the protection systems, the lack of such a 

requirement could result in the potential ineffective operation of a protection system 

when called upon. This is in contrast with standard PRC-006-0, which requires periodic 

assessments of the effectiveness of regional UFLS programs at least once every five 

 162 Blackout Report at 159. 

163 Blackout Report, Recommendation Number 21 at 158. 

164 Blackout Report at 159. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 95 - 

Chapter: PRC 

years regardless of the circumstance - a good example of a maximum allowable interval 

without specific justification. 

C. Concerns Specific to Individual Reliability Standards 

1. Individually Identified Standards 

The following group of standards contains issues unique to each standard and are 

individually discussed below. 

System Protection Coordination (PRC-001-0) 

The purpose of this standard reads: “To ensure system protection is coordinated among 

operating entities.” 

This standard does not define the maximum time period for corrective actions if a 

protective relay or equipment failure reduces system reliability. This is inconsistent with 

the requirement that System Operators re-adjust the system within 30 minutes for 

contingencies as required under the IRO and TOP standards. These concerns are 

discussed in more detail in section B1 above. 

Without Compliance Measures and Levels of Noncompliance, the ERO will not have 

benchmarks to implement consistent and effective enforcement. NERC has indicated that 

this standard will be modified to address this deficiency and resubmitted for Commission 

approval in November 2006. 

Development and Documentation of Regional UFLS Programs (PRC-006-0) 

The purpose of this standard reads: “Provide last resort system preservation measures by 

implementing an Under Frequency Load Shedding (UFLS) program.” 

This standard applies to RROs. However, RROs have not been classified as a user, 

owner, or operator of the Bulk-Power System. The standard has been referred to as a 

“fill-in-the-blank” standard. 

This standard is not specific enough to address Blackout Report Recommendation 

Number 21 concerning an integrated and coordinated approach. The discussion of 

“Under-Frequency Load Shedding and Under-Voltage Load Shedding Coordination with 

Generation and Line Protection Systems” in section B.2 of this chapter details concerns 

regarding this standard. 

There is a Requirement to perform periodic assessments of the effectiveness of the 

regional UFLS programs and design details at least once every five years – a good 

example of a maximum allowable interval without specific justification. However, the 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 96 - 

Chapter: PRC 

standard does not contain a Requirement for an integrated and coordinated approach 

among UFLS, line protection, generation protection and generator under-frequency 

protection as suggested by Blackout Report Recommendation Number 21. 

UFLS Performance Following an Underfrequency Event (PRC-009-0) 

The purpose of this standard reads: “Provide last resort system preservation measures by 

implementing an Under Frequency Load Shedding (UFLS) program.” 

Standard PRC-009-0 also requires that the “Transmission Owner, Transmission Operator, 

Load-Serving entity and Distribution Provider that owns or operates a UFLS program ... 

shall analyze and document its UFLS program performance in accordance with its 

Regional Reliability Organization’s UFLS program.”165 In addition, the standard requires 

the same entities to “provide documentation of the analysis of the UFLS program to its 

Regional Reliability Organization and NERC on request 90 calendar days after the 

system event.”166 Staff notes that there is no similar reporting requirement for operation 

events of under-voltage load shedding. 

Assessment of the Design and Effectiveness of UVLS Program (PRC-010-0) 

The purpose of this standard reads: “Provide system preservation measures in an attempt 

to prevent system voltage collapse or voltage instability by implementing an Under 

Voltage Load Shedding (UVLS) program.” 

The discussion of "Integrated and Coordinated Approach to Bulk-Power System 

Protection" in section B.2 of this chapter highlights staff’s concerns regarding this 

standard in detail. 

Special Protection System Assessment (PRC-014-0) 

The purpose of this standard reads: “To ensure that all Special Protection Systems (SPS) 

are properly designed, meet performance requirements, and are coordinated with other 

protection systems. To ensure that maintenance and testing programs are developed and 

misoperations are analyzed and corrected.” 

The maximum allowable interval of at least once every five years as a Requirement for 

assessing the effectiveness of the special protection systems is a good example of a 

maximum allowable interval without specific justification. 

 165 Standard PRC-009-0 (R1). 

166 Id. at R2. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 97 - 

Chapter: PRC 

This standard applies to RROs. However, RROs have not been classified as a user, 

owner, or operator of the Bulk-Power System. The standard has been referred to as a 

“fill-in-the-blank” standard. 

2. Specifications of Maintenance Intervals 

This group of four standards does not specify the criteria to determine the appropriate 

maintenance intervals or maximum allowable intervals for protection systems to ensure 

effectiveness. Specific concerns are explained in the previous section, entitled, “Criteria 

for Maintenance and Testing of Protection Systems” of the primary issues identified in 

this chapter. Beyond this concern, there are no substantive issues identified at this time 

for the following standards. 

Transmission Protection System Maintenance and Testing (PRC-005-0) 

The purpose of this standard reads: “To ensure all transmission protection system 

misoperations are analyzed for cause and corrective action, and maintenance and testing 

programs are developed and implemented.” 

The revised standard PRC-005-1 was recently approved by the NERC Board of Trustees 

with an effective date of May 1, 2006. The title of the standard has been changed to 

include generation protection. Also, the purpose properly reflects the title and intent of 

the standard. However, standard PRC-005-1 does not address the concern regarding 

maintenance intervals discussed above. 

Underfrequency Load Shedding Equipment Maintenance Programs (PRC-008-0) 

The purpose of this standard reads: “Provide last resort system preservation measures by 

implementing an Under Frequency Load Shedding (UFLS) program.” 

Undervoltage Load Shedding System Maintenance and Testing (PRC-011-0) 

The purpose of this standard reads: “Provide system preservation measures in an attempt 

to prevent system voltage collapse or voltage instability by implementing an Under 

Voltage Load Shedding (UVLS) program.” 

Special Protection System Maintenance and Testing (PRC-017-0) 

The purpose of this standard reads: “To ensure that all Special Protection Systems (SPS) 

are properly designed, meet performance requirements, and are coordinated with other 

protection systems. To ensure that maintenance and testing programs are developed and 

misoperations are analyzed and corrected.” 

3. RROs Designated as the Sole Applicable Entity 

This group of five standards designates RROs as the applicable entity. Staff is 

concerned about the appropriateness of RROs serving as the applicable entity in the new 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 98 - 

Chapter: PRC 

mandatory Standards structure. These standards have been referred to as “fill-in-theblank” standards. This concern is discussed in the Common Issues chapter of this 

assessment. Beyond this concern, there are no substantive issues identified at this time 

for the following standards. 

Define and Document Disturbance Monitoring Equipment Requirements 

(PRC-002-0) 

The purpose of this standard reads: “To ensure that Disturbance monitoring equipment is 

installed in a uniform manner to facilitate development of models and analyses of 

events.” 

Regional Procedure for Transmission Protection System Misoperations 

(PRC-003-1) 

The purpose of this standard reads: “To ensure that all transmission protection system 

misoperations [must be] analyzed for cause and corrective action and maintenance and 

testing programs are developed and implemented.” 

Special Protection System Review Procedure (PRC-012-0) 

The purpose of this standard reads: “To ensure that all Special Protection Systems (SPS) 

are properly designed, meet performance requirements, and are coordinated with other 

protection systems. To ensure that maintenance and testing programs are developed and 

misoperations are analyzed and corrected.” 

Special Protection System Database (PRC-013-0) 

The purpose of this standard reads: “To ensure that all Special Protection Systems (SPS) 

are properly designed, meet performance requirements, and are coordinated with other 

protection systems.” 

Under-Voltage Load Shedding Program Database (PRC-020-1) 

The purpose of this standard reads: “To ensure that a regional database is maintained for 

Under-Voltage Load Shedding (UVLS) programs implemented by entities within the 

Region to mitigate the Risk of voltage collapse or voltage instability in the Bulk Electric 

System (BES). Ensure the UVLS database is available for Regional studies and for 

dynamic studies and simulations of the BES.” 

This Version 1 standard was recently approved by the NERC Board of Trustees with an 

effective date of August 1, 2006, though it understandably still does not address the 

applicability concerns. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 99 - 

Chapter: PRC 

4. No Substantive Issues Identified 

No substantive issues have been identified at this time for these six PRC standards. 

Analysis and Reporting of Transmission Protection System Misoperations 

(PRC-004-0) 

The purpose of this standard reads: “To ensure all transmission protection system 

misoperations are analyzed for cause and corrective action and maintenance and testing 

programs are developed and implemented.” 

PRC-004-1 was recently approved by the NERC Board of Trustees with an effective date 

of August 1, 2006. No substantive issues for the Version 0 or Version 1 standard were 

identified at this time. 

Assuring Consistency with Regional UFLS Program Requirements (PRC-007-0) 

The purpose of this standard reads: “Provide last resort System preservation measures by 

implementing an Under Frequency Load Shedding (UFLS) program.” 

Special Protection System Data and Documentation (PRC-015-0) 

The purpose of this standard reads: 

To ensure that all Special Protection Systems (SPS) are properly designed, 

meet performance requirements, and are coordinated with other protection 

systems. To ensure that maintenance and testing programs are developed 

and misoperations are analyzed and corrected. 

Special Protection System Misoperations (PRC-016-0) 

The purpose of this standard reads: 

To ensure that all Special Protection Systems (SPS) are properly designed, 

meet performance requirements, and are coordinated with other protection 

systems. To ensure that maintenance and testing programs are developed 

and misoperations are analyzed and corrected. 

Under-Voltage Load Shedding Program Data (PRC-021-1) 

The purpose of this standard reads: “Ensure that data is provided to support the Regional 

database maintained for Under-Voltage Load Shedding (UVLS) programs that were 

implemented to mitigate the risk of voltage collapse or voltage instability in the Bulk 

Electric System (BES).” 

This Version 1 standard was recently approved by the NERC Board of Trustees with an 

effective date of August 1, 2006. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 100 - 

Chapter: PRC 

Under-Voltage Load Shedding Program Performance (PRC-022-1) 

The purpose of this standard reads: “Ensure that Under-Voltage Load Shedding (UVLS) 

programs perform as intended to mitigate the risk of voltage collapse or voltage 

instability in the Bulk Electric System (BES).” 

This Version 1 standard was recently approved by the NERC Board of Trustees with an 

effective date of May 1, 2006. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 101 - 

XIV. TOP: TRANSMISSION OPERATIONS 

A. Description and General Issues 

The Transmission Operations (TOP) group of reliability standards consists of eight 

standards aimed at Transmission Operators, Generator Operators and Balancing 

Authorities. They cover responsibilities and decision-making authority for reliable 

operations, requirements for operations planning, planned outage coordination, real-time 

operations, provision of operating data, monitoring of system conditions, reporting of 

operating limit violations and actions to mitigate such violations. Complementary 

standards for Reliability Coordinators are covered under the Interconnection Reliability 

Operations and Coordination (IRO) group of standards in chapter X of this assessment. 

In general, these standards raise issues in the areas of Measures, Compliance, and 

Requirements. 

Of the eight standards in this group, five do not contain criteria or measures to assess 

compliance with the Requirements. These five standards lack Levels of Non-compliance 

that are needed for enforcement of penalties. The Levels of Non-compliance in one 

standard are based on procedural rather than substantive requirements regarding the 

quality, completeness and timeliness of the information submitted. NERC has indicated 

that these standards will be modified to address this deficiency and resubmitted for 

Commission approval in November 2006. 

An examination of the Requirements has identified five standards that have significant 

technical issues because they may be incomplete and therefore might not adequately 

protect the reliable operation of the Bulk-Power System. They do not address the lessons 

learned from past operating incidents; might not contain a technically sound means to 

achieve the specified reliability goal; or may not be clear and unambiguous regarding 

compliance requirements. In addition, the reliability goal of one of the standards may be 

too narrow in scope to adequately protect Bulk-Power System reliability. 

Implementation of the Blackout Report recommendations regarding reliability involves 

standard TOP-006 in this group. Also, if left unresolved, the issue of conflicting 

definitions concerning the Bulk-Power System, discussed in the Common Issues Chapter 

of this document, would add to interpretation and enforceability problems for the 

standards in this chapter. 

Below follows a discussion of primary issues and an evaluation of individual standards in 

the context of these observations. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 102 - 

Chapter: TOP 

B. Primary Issues in the Transmission Operations Standards 

1. Ability to Readjust the System Following a Contingency 

The standards require that plans be developed to meet dynamic changes to the system in 

the operations planning time frame, such as scheduled and unscheduled changes in 

system configuration, demand patterns, generation dispatch and interchange schedules. 

The unscheduled changes to system configuration and generation dispatch are referred to 

as a single contingency (defined as the loss a transmission circuit, generator, single DC 

pole, or transformer). However, following a single contingency, Standard IRO-005-1 

requires that the system be adjusted to compensate for the contingency as soon as 

possible but no later than 30 minutes after the contingency. This Requirement is to 

ensure that the system is returned to a secure operating state so it can withstand the next 

contingency without causing instability, uncontrolled separation or cascading outages.

This group of standards does not, however, require that the system be assessed to the 

same extent in the day ahead planning analysis, nor does it require identification of 

control actions, implementable within 30 minutes, that are needed to bring the system 

back to a stable state in order to withstand the next contingency without cascading. This 

may present a potential vulnerability as operators may not be aware of available control 

actions or worse may not have control actions, other than firm load shedding, available to 

them to adjust the system to a stable state after it incurs its first contingency. This can 

lead to poor execution and reliability risk after the first contingency has occurred in realtime operations. 

2. Operation Under Normal Pre-Contingency Conditions 

The primary reliability goal of the Transmission Operations standards is to ensure that 

instability, uncontrolled separation or cascading outages will not occur as a result of the 

most severe single contingency. However, these standards are worded ambiguously 

enough to be interpreted in two very different ways. A conservative interpretation is that 

under normal system conditions, i.e., before any contingency occurs, the system must be 

operated within Interconnection Reliability Operating Limits (IROL). A less strict 

interpretation of these standards is that operation above IROLs under normal precontingency conditions is permitted provided the system is returned to a secure operating 

state as soon as possible but not later than 30 minutes after the IROLs were exceeded. In 

the case of the latter interpretation, during the period when IROL is exceeded even a 

single system contingency (such as the loss of transmission circuit, transformer, 

generator, or single DC pole) could cause instability, uncontrolled separation, and even a 

cascading blackout. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 103 - 

Chapter: TOP 

3. Minimum Acceptable Tools to Aid Situational Awareness 

The Blackout Report states that “a principal cause of the blackout was a lack of 

situational awareness, which was in turn a result of inadequate reliability tools and 

backup capabilities.”167 To address this deficiency, Recommendation Number 22 of the 

Blackout Report requires that NERC evaluate and adopt better real-time tools for 

operators and Reliability Coordinators so they can recognize and respond to system 

emergencies in a timely manner.168 While the NERC standards identify the data 

requirements, they do not identify any minimum acceptable tools and capabilities to turn 

the data into information necessary to understand critical reliability functions, and 

therefore the standards lack an important Requirement in this area. 

C. Concerns Specific to Individual Standards 

Reliability Responsibilities and Authorities (TOP-001-0) 

The purpose of this standard reads: “To ensure reliability entities have clear decisionmaking authority and capabilities to take appropriate actions or direct the actions of 

others to return the transmission system to normal conditions during an emergency.” 

The standard does not contain any Measures to assess compliance with the Requirements 

or any Levels of Non-Compliance required for enforcement of penalties. NERC has 

indicated that this standard will be modified to address this deficiency and resubmitted 

for Commission approval in November 2006. 

Normal Operations Planning (TOP-002-0) 

The purpose of this standard reads: “Current operations plans and procedures are 

essential to being prepared for reliable operations, including response for unplanned 

events.” 

Staff notes that this standard specifies that capacity and energy reserves to local areas 

must be deliverable. Other standards require the system be operated in a manner that 

allows it to be returned to a stable state within 30 minutes after a contingency occurs and 

to be able to withstand another contingency without cascading. However, this standard 

does not require that the system be assessed in the next day planning analysis to identify 

control actions, which can be implemented in 30 minutes, that are needed to bring the 

system back to a stable state and can withstand the next contingency without cascading. 

Staff’s concerns in this area are discussed in more detail in section B1 above. 

 167 Blackout Report at 159. 

168 See id. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 104 - 

Chapter: TOP 

The reference to “single contingency” is defined as the loss of a transformer, transmission 

circuit, single DC pole, or generator, but does not include the assessment of outages of 

multiple elements as a result of a single component failure.169 This might leave a 

potential gap in the analysis of and planning for contingencies, as the loss of a single 

relay, breaker, control system component, transmission tower, etc., can affect multiple 

system elements. 

The standard recognizes the need to communicate changes in generator “real and reactive 

capability as well as the status of automatic voltage regulators.”170 However, the standard 

does not include a requirement to communicate a change in the status of equally 

important Power System Stabilizers. These stabilizers are critical components for 

stability performance. 

The standard does not contain any Measures to assess compliance with the Requirements 

or Levels of Non-Compliance required for enforcement. NERC has indicated that this 

standard will be modified to address this deficiency and resubmitted for Commission 

approval in November 2006. 

Planned Outage Coordination (TOP-003-0) 

The purpose of this standard reads: 

Scheduled generator and transmission outages that may affect the reliability 

of interconnected operations must be planned and coordinated among 

Balancing Authorities, Transmission Operators, and Reliability 

Coordinators. 

The standard requires outage information on transmission lines and transformers greater 

than 100 kV. These Requirements – which do not include a requirement for setting 

threshold levels – are inconsistent with the stated purpose, as they assume that only 

systems greater than 100 kV or generators above 50 MW will affect the reliability of 

interconnected operations. Although this may be true in most instances, either 

justification should be provided for the threshold of 100 kV for transmission and 50 MW 

for generation outages on a case-by-case basis, or else the standard could be expanded to 

cover all facilities that have an impact on reliability. The loss of less than 100 kV 

transmission lines or transformers and less than 50 MW generator units may affect 

 169 Failure of an electrical component includes relay and control system failures, which may 

remove more than one element. 

170 North American Electric Reliability Council, Reliability Standards for the Bulk Electric 

Systems of North America, Standard TOP-002-0(R14). 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 105 - 

Chapter: TOP 

system stability in load pockets or remote sections of the grid depending upon system 

conditions. 

While standard TOP-002-0 requires coordination of planned outages on a current-day, 

next day and seasonal basis for normal operations planning, this standard only requires 

next day reporting for planned outages and does not include longer range planning. This 

gap may affect the reliability of the system because proper assessment of the system and 

coordination between generation and transmission outages may not occur. This lack of 

information may also have an impact on TTC/ATC calculations. The Levels of NonCompliance are based on having a process in place for providing information, but they do 

not contain requirements for actually providing the information. 

Transmission Operations (TOP-004-0) 

The purpose of this standard reads: “To ensure that the transmission system is operated 

so that instability, uncontrolled separation or cascading outages will not occur as a result 

of the most severe single Contingency or specified multiple Contingencies.” 

Staff notes that an assessment on a regional basis of the potential impact of multiple 

outages in day-ahead operations planning is included in the Requirements. However, the 

conditions under which multiple outages can occur are undefined in the Regional 

Differences section. Only those Requirements that are included in the accepted standards 

are enforceable. 

The standard requires the operation of the system within IROL and SOL. When the 

system enters an unknown state (i.e., any state for which operating limits have not been 

determined), Requirement R4 of Standard TOP-004-0 requires the operator to “restore 

operations to respect proven reliable power system limits within 30 minutes.”171 The 

phrase “within 30 minutes” could be interpreted as a grace period. However, such an 

interpretation may not be consistent with the intent that while 30 minutes is deemed a 

reasonable time period, it is expected that actions will be taken as soon as possible and 

without delay. 

The standard does not contain any Measures to assess compliance with Requirements or 

Levels of Non-Compliance required for enforcement. NERC has indicated that this 

standard will be modified to address this deficiency and resubmitted for Commission 

approval in November 2006. 

 171 Standard TOP-004-0 (R4). 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 106 - 

Chapter: TOP 

Operational Reliability Information (TOP-005-1) 

The purpose of this standard reads: “To ensure reliability entities have the operating data 

needed to monitor system conditions within their areas.” 

Attachment 1 of TOP-005-1, entitled “Electric System Reliability Data,” specifies the 

data required but it does not include the operational status of Special Protection Systems 

and Power System Stabilizers. The absence of this information can lead to erroneous 

assessments of system capability that can in turn expose the system to unreliability risk. 

Monitoring System Conditions (TOP-006-0) 

The purpose of this standard reads: “To ensure critical reliability parameters are 

monitored in real-time.” 

However, while the requirements identify the data to be gathered, they fail to describe the 

tools necessary to turn that data into critical reliability parameters, e.g., system capability 

or contingency analysis, which are required to achieve situational awareness. Reliability 

Coordinators, Transmission Operators, and Balancing Authorities must be aware of the 

status of their respective systems, and such situational awareness can not be obtained by 

viewing massive amounts of raw data. 

The standard does not contain any Measures to assess compliance with Requirements or 

Levels of Non-Compliance required for enforcement. NERC has indicated that this 

standard will be modified to address this deficiency and resubmitted for Commission 

approval in November 2006. 

Reporting SOL and IROL Violations (TOP-007-0) 

The purpose of this standard reads: “This standard ensures that SOL and IROL violations 

are being reported to the Reliability Coordinator so that the Reliability Coordinator may 

evaluate actions being taken and direct additional corrective actions as needed.” 

Requirement R2 states “Following a Contingency or other event that results in an IROL 

violation, the Transmission Operator shall return its transmission system to within IROL 

as soon as possible, but not longer than 30 minutes.”172 However, the use of the words 

“other events” in Requirement R2 opens it up to interpretation. One interpretation is that 

it allows IROLs to be exceeded under normal pre-contingency conditions, provided the 

system can be returned to a secure state within 30 minutes. A more conservative 

interpretation is that the Requirement does not allow IROLs to be exceeded under normal 

pre-contingency conditions, and that after a contingency occurs the system must be 

returned to a secure condition as soon as possible and no later than 30 minutes. (This 

 172 Standard TOP-007-0. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 107 - 

Chapter: TOP 

issue was explained in more detail under the section entitled “Primary Issues in the 

Transmission Operations Standards” in item B.2 above.) 

Response to Transmission Limit Violations (TOP-008-0) 

The purpose of this standard reads: “To ensure Transmission Operators take action to 

mitigate SOL and IROL violations.” 

The standard does not contain any Measures to assess compliance with Requirements or 

any Levels of Non-Compliance required for enforcement of penalties. NERC has 

indicated that this standard will be modified to address this deficiency and resubmitted 

for Commission approval in November 2006. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 108 - 

XV. TPL: TRANSMISSION PLANNING CHAPTER 

A. Description and General Issues 

The Transmission Planning (TPL) group of reliability standards consists of six standards 

aimed at Transmission Planners, Planning Authorities and RROs. Four of the standards 

address the types of system simulations and assessments that must be performed to 

ensure that reliable systems are developed to meet present and future system needs.173

Two standards relate to information required to assess Regional compliance with 

planning criteria and for self-assessment of the reliability of the region.174 

In general, these standards raise issues of the following types: Requirements that are 

ambiguous, limited sets of contingencies, and Requirements or lack of Requirements that 

may have an undue negative impact on competition. 

All six TPL standards contain a list of Measures to assess compliance with the 

Transmission Planning standards and Levels of Non-Compliance required for 

enforcement. Two of the standards are solely applicable to the RROs -- entities that 

currently are not identified as a user, owner or operator of the Bulk-Power System. Four 

standards have technical issues because they may either be incomplete, vague or subject 

to different interpretations. 

In addition, if left unresolved, the issue of conflicting definitions concerning the BulkPower System vs. the Bulk Electric System, discussed in the Common Issues Chapter of 

this document, would add to interpretation and enforceability problems for the standards 

in this chapter. Staff notes that several standards in this group address separate matters 

but have identical purpose statements. Generally, staff suggests such statements be 

augmented or tailored to reflect the specific aspect of the purpose the given standard is 

designed to achieve. 

Set forth below is a discussion of primary issues and an evaluation of individual 

standards in light of these observations. 

 173 North American Electric Reliability Council, Reliability Standards for the Bulk 

Electric Systems of North America, Standards TPL-001-0, TPL-002-0, TPL-003-0, TPL-004-0. 

174 Standards TPL-005-0, TPL-006-0. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 109 - 

Chapter: TPL 

B. Primary Issues in the Transmission Planning Standards 

1. Stressing the System during Simulations 

In carrying out power systems simulations to determine the need for system upgrades or 

reinforcements with sufficient lead time to implement, it is important to ensure that the 

system under study is sufficiently stressed so that any underlying weaknesses or 

deficiencies can be identified. It is equally important to test the performance of the 

system under study for a wide variety of probable scenarios. Such scenarios would 

typically simulate a range of generation dispatches including generator outages, a range 

of demand levels and load power factors, a range of transactions and a range of 

transmission outages including reactive power devices.175 Such simulations would 

determine the most onerous set of system conditions, which might not be peak demand 

conditions. In addition, these tests would identify requirements for generators that must 

run to remove local transmission constraints,176 or alternatively identify the inability to 

deliver generation to load due to insufficient transmission capacity. These are especially 

important for the near term (one to five years), as the results would be instructive to 

seasonal, monthly, weekly and day-ahead operations planning studies and as both aspects 

are critical to reliable operations in real time. Adherence to applicable reliability criteria 

for the overall set of simulations provides a good indication of the ability of the system to 

remain reliable for a variety of operating conditions. 

The standards require entities to “cover critical system conditions and study years,”177 but 

they do not require that sensitivity studies be carried out, nor do they specify the rationale 

for determining critical system conditions and study years. System conditions are as 

important as contingencies in evaluating the performance of present and future 

systems.178 

 175 Some Regions use the term “deliverability” to describe part of this process. 

176 These are referred to as Reliability Must Run or RMR units. 

177 Requirement R1.3 of Standards TPL-001, TPL-002, TPL-003, TPL-004. Critical study years 

are those years determined by simulations to require transmission upgrades or reinforcement to meet 

reliability criteria. 

178 Expected changes in system conditions may be short-term predictive maintenance outages or 

longer-term corrective maintenance outages. The length of a corrective maintenance outage may be 

dependent upon the number and types of spare equipment that an entity has available. Widespread 

weather events may also impact system conditions. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 110 - 

Chapter: TPL 

2. Element-Based vs. Event-Based Contingencies 

The Planning Standards require demonstration through valid assessments that the system 

is planned so that it can be operated to supply projected customer demands and firm 

Transmission Services at all demand levels under a set of contingencies as defined in 

Table 1 (Transmission System Standards – Normal and Emergency Conditions) of the 

TPL Standards. Table 1 is a key part of the Planning Standards and lays out the system 

performance requirements for a range of contingencies grouped according to the number 

of elements forced out of service as a result of the contingency. For example: Category 

A applies to the normal system with no contingencies; Category B applies to 

contingencies resulting in the loss of a single element defined as a generator, transmission 

circuit, transformer, single DC pole with or without a fault; Category C applies to a 

contingency resulting in loss of two or more elements, such as any two circuits on a 

multiple tower line or both poles of a bi-polar DC line; while Category D applies to 

extreme contingencies resulting in loss of multiple elements, such as a substation or all 

lines on a right-of-way. The system performance expectations for Category C 

contingencies are lower than those for Category B contingencies, in that they allow 

unspecified amounts of planned or controlled loss of demand. 

 The term “Reliable Operation” as set forth in section 215(a)(4) of the FPA is defined as: 

Reliable Operation means operating the elements of the Bulk-Power 

System within equipment and electric system thermal, voltage, and stability 

limits so that instability, uncontrolled separation, or cascading failures of 

such system will not occur as a result of sudden disturbance, including a 

Cybersecurity Incident, or unanticipated failure of system elements. 

Staff interprets this to mean that any element in the actual Bulk-Power System may fail 

and contingencies used in simulations should be consistent with what can occur in realtime operations based on the actual details of the Bulk-Power System. 

The single unanticipated failure of some elements in the Bulk-Power System can result in 

the loss of multiple elements. Because of the resulting impact on reliability, some 

Regions179 base their groupings according to the event irrespective of the number of 

elements forced out of service instead of categorizing contingencies according to 

elements forced out of service. For such a region, a single event that results in the loss of 

multiple elements, e.g., a relay failure, that forces a DC bi-pole out of service or a 

lightening strike that simultaneously forces out of service both circuits of a double circuit 

 179 See, e.g., NPCC criteria A1 Document. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 111 - 

Chapter: TPL 

tower line, are grouped alongside those events which would result in loss of single 

elements such as a generator, transmission circuit or transformer. Through this variation 

in criteria, what is acceptable in one Region may not be acceptable in another Region 

because of historical adoption of reliability criteria and practices rather than physical 

differences in their systems. 

3. Interpretation of Performance Requirements 

As stated above, Table 1 of the Planning Standards lays out the system performance 

requirements for a range of contingencies. There are a number of footnotes associated 

with Table 1 meant to aid in the interpretation of the performance requirements. For 

example, the Requirements in Category B are no load loss or curtailment of firm transfers 

from contingencies resulting in the loss of a single element. But footnote (b) appended to 

these Requirements states in part “[p]lanned or controlled interruption of electrical supply 

to radial customers or some local Network customers, connected to or supplied by the 

faulted element or affected area, may occur in certain areas without impacting the overall 

reliability of the interconnected transmission systems.”180 This footnote is sufficiently 

ambiguous to allow differing interpretations. One interpretation of this statement is that 

load interruption for a single contingency is permitted, while another interpretation is that 

the practice is the exception rather than the rule, and for this reason load interruptions are 

not permitted for a single contingency except in very special circumstances where such 

interruption is limited to the firm load directly associated with the failure. In the case of 

the former interpretation, applicable entities may argue that they can deliberately 

interrupt firm load customers as a result of the loss of a single contingency without 

violating any reliability standards. 

Other footnotes are also ambiguous and as such detract from the intent of the 

performance requirements stated in Table 1. They should be clarified so that they are 

applied appropriately and consistently by all the entities to whom they apply. 

4. Assessment of Extreme Events 

Extreme events are low probability but high impact events. Examples provided by 

NERC in the standards include loss of a substation, loss of all generating units at a 

station, loss of all transmission lines on a right-of-way, etc. Extreme events must be 

assessed to evaluate their risks and consequences. While the standards require such 

assessments, documentation of the results and submission to the RRO, they do not 

require that consideration be given either to reducing the probability of the loss of 

 180 Standard TPL-002, Table 1 Category B Footnote (b). 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 112 - 

Chapter: TPL 

multiple elements or mitigating the impact. Furthermore, the standards do not explicitly 

require that the results of these assessments be shared with impacted entities or 

communicated to operations planning staff and control room operators. 

Staff notes that a number of high-risk weather events, such as the hurricanes that 

impacted the Southern United States and an ice storm that impacted Canada, resulted in a 

greater impact on the Bulk-Power System in terms of the number of elements lost than 

the scenarios identified in the standards. 

5. Scope of Elements for which the Reliability Standards Apply 

The differences between the definition of Bulk-Power System in section 215 of the FPA 

and the definition of Bulk Electric System found in the NERC Glossary upon which the 

NERC standards rely, create a problematic discrepancy that could create reliability gaps. 

These gaps could allow for some interconnected electric energy transmission networks, 

and electric energy from generating facilities needed to maintain transmission system 

reliability to be outside of the mandatory Standards. 

Clearly, this discrepancy in definitions, if left unaddressed, could interfere with 

maintaining reliability consistently across the Regions on an ongoing operations basis. 

The concern in this chapter is that the discrepancy is magnified when applied to 

contingencies that must be evaluated as part of the transmission planning process. 

The current Planning Standards apply to all elements that constitute the Bulk Electric 

System. The NERC Glossary defines the Bulk Electric System as follows: 

As defined by the Regional Reliability Organization, the electrical 

generation of resources, transmission lines, interconnections with 

neighboring systems, and associated equipment, generally operated at 

voltages 100 kV or higher. Radial transmission facilities serving only load 

with one transmission source are generally not included in this definition. 

According to this definition, each RRO may designate the scope of facilities to be 

included in, or excluded from, the system. Conflicting multiple definitions could result, 

which would in turn subject different facilities to the requirements of the standards or, 

alternatively, exclude various facilities from the standards. 

Further, section 215(a)(1) defines Bulk-Power System as: 

Facilities and control systems necessary for operating an interconnected 

electric energy transmission network (or any portion thereof), and electric 

energy from generating facilities needed to maintain transmission system 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 113 - 

Chapter: TPL 

reliability. The term does not include facilities used in the local distribution 

of electric energy.[181]

 

The FPA and NERC definitions obviously differ. The standards currently are applied 

only to the Bulk Electric System as defined by each Region. However, section 215(a)(3) 

of the FPA defines Reliability Standard as a requirement approved by the Commission to 

provide for reliable operation of the Bulk-Power System. The term Bulk Electric System 

does not appear to include all the system components from all non-distribution voltage 

levels, control systems, and electric energy from all generating facilities needed to 

maintain transmission system reliability included in the definition of Bulk-Power System. 

Therefore, the definitions of Bulk Electric System and Bulk-Power System are very 

different with respect to the facilities to which the TPL standards would apply. The Bulk 

Electric System definition may not include all the elements and all the voltage levels 

implied in the definition of Bulk-Power System. 

C. Concerns Specific to Individual Standards 

System Performance Under Normal (No Contingency) Conditions (Category A) 

(TPL-001-0) 

The purpose of this standard reads: 

System simulations and associated assessments are needed periodically to 

ensure that reliable systems are developed that meet specified performance 

requirements with sufficient lead time, and continue to be modified or 

upgraded as necessary to meet present and future system needs. 

The standard’s Requirements include a simulation and assessment of the ability of the 

Bulk Electric System to deliver firm demand and firm transactions with all elements in 

service for loads up to forecasted demand without violating performance requirements of 

Table 1 of the transmission planning standards. If an assessment indicates that a 

violation of the performance requirements has occurred, a plan to mitigate the violation is 

required. 

The standard does not require the consideration of planned outages. Further, footnote (a) 

-- which states in part that “Applicable Ratings may include Emergency Ratings 

applicable for short durations as required to permit operating steps necessary to maintain 

 181 18 C.F.R. § 39.1 (2005). 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 114 - 

Chapter: TPL 

system control”182 -- should be clarified that it is only applicable to Categories B, C, 

and D. 

Further details are provided in the Primary Issues section above. 

System Performance Following Loss of a Single BES Element (TPL–002–0) 

The purpose of this standard reads: 

System simulations and associated assessments are needed periodically to 

ensure that reliable systems are developed that meet specified performance 

requirements with sufficient lead time, and continue to be modified or 

upgraded as necessary to meet present and future system needs. 

The standard’s Requirements include a simulation and assessment of the ability of the 

Bulk Electric System to deliver firm demand and firm transactions after the loss of a 

single element identified in Category B in Table 1 or a reduced set of those contingencies 

if accepted by the applicable RRO. If the assessment indicates a violation of the criteria 

has occurred, a plan to mitigate the violation is required. 

Further details are provided in the Primary Issues section, items B.1, B.2 and B.3, above. 

The NERC Transmission Issues Subcommittee (TIS) reviewed regional practices used for 

system design, planning and analysis. The TIS set forth its recommendations in a 

report.183 Staff notes that the recommendations on clarifying the TPL standards 

contained in Appendix B of the NERC TIS Report have not been addressed. 

System Performance Following Loss of Two or More BES Elements (TPL-003-0) 

The purpose of this standard reads: 

System simulations and associated assessments are needed periodically to 

ensure that reliable systems are developed that meet specified performance 

requirements, with sufficient lead time and continue to be modified or 

upgraded as necessary to meet present and future System needs. 

The standard’s Requirements include a simulation and assessment of the ability of the 

Bulk Electric System to deliver firm demand and firm transactions after the loss of two or 

 182 Standard TPL-001-0 Table 1 Footnote (a). 

183 See NERC Transmission Issues Subcommittee, Evaluation of Criteria, Methods, and Practices 

Used for System Design, Planning and Analysis in Response to NERC Blackout Recommendation 13c 

(Nov. 28, 2005) (NERC TIS Report). 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 115 - 

Chapter: TPL 

more elements identified in Category C in Table 1. If the assessment indicates a violation 

of the criteria has occurred, a plan to mitigate the violation is required. 

Further details are provided in the discussion in the Primary Issues section, items B.1, B.2 

and B.3, above. 

Staff also notes that the recommendations on clarifying the TPL standards contained in 

Appendix B of the NERC TIS Report on regional practices referred to above have not 

been addressed. 

System Performance Following Extreme BES Events (TPL-004-0) 

The purpose of this standard reads: 

System simulations and associated assessments are needed periodically to 

ensure that reliable systems are developed that meet specified performance 

requirements, with sufficient lead time and continue to be modified or 

upgraded as necessary to meet present and future System needs. 

The standard’s Requirements include a simulation and assessment of the ability of the 

Bulk Electric System to deliver firm demand and firm transactions after the loss of 

multiple elements due to extreme events identified in Category D in Table 1. 

The standard does not require that consideration be given either to reducing the 

probability of the loss of multiple elements or mitigating the impact of such outages. It 

also does not require that the results of these assessments be shared with impacted entities 

or communicated to operations planning staff and control room operators. This standard 

does not address scenarios that are equal to or more severe than actual weather events 

such as the hurricanes that impacted the Southern United States and an ice storm that 

impacted Canada. 

Further details are provided in the Primary Issues section above. 

Staff also notes that the recommendations on clarifying the TPL standards contained in 

Appendix B of the NERC TIS Report on regional practices referred to above have not 

been addressed. 

Regional and Interregional Self-Assessment Reliability Reports (TPL-005-0) 

The purpose of this standard reads: 

To ensure that each Regional Reliability Organization complies with 

planning criteria, for assessing the overall reliability (Adequacy and 

Security) of the interconnected Bulk Electric Systems, both existing and as 

planned.
FERC Staff Preliminary Assessment of NERC Reliability Standards - 116 - 

Chapter: TPL 

The standard’s Requirements are intended to provide NERC with the authority to collect 

RRO reliability self-assessments on a seasonal and next ten year basis. NERC uses this 

data to publish seasonal and long-term reliability assessments of the Bulk Electric 

System. 

Staff finds no significant issues with this standard at this time and notes that these reports 

have been useful in understanding the performance of the present and future 

interconnected transmission system. It is expected that additional reports will be 

developed by the ERO in the future. 

Assessment Data from Regional Reliability Organizations (TPL-006-0) 

The purpose of this standard reads: 

To ensure that each Regional Reliability Organization complies with 

planning criteria, for assessing the overall reliability (Adequacy and 

Security) of the interconnected Bulk Electric Systems, both existing and as 

planned.

The standard’s Requirements are intended to provide NERC with authority to collect 

specific RRO data, reports and system performance information on a seasonal and next 

ten year basis. NERC uses this data to publish seasonal and long-term reliability data of 

the Bulk Electric System. 

Staff finds no significant issues with this standard at this time and notes that the data in 

these reports have been useful in understanding the trends in the performance of the 

interconnected transmission system. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 117 - 

XVI. VAR: VOLTAGE AND REACTIVE 

A. Description and General Issues 

The single Voltage and Reactive Control (VAR) reliability standard applies to 

Transmission Operators, Generator Operators and Purchasing-Selling Entities. The 

purpose of this standard reads: 

To ensure that voltage levels, reactive flows, and reactive resources are 

monitored, controlled, and maintained within limits in real time to protect 

equipment and the reliable operation of the Interconnection. 

Voltage control and reactive power supply are integral parts of reliable power system 

operations. A major imbalance between reactive power consumption and supply will 

lead to voltage collapse and cascading power outages. This has been a common causal 

factor in major power outages worldwide.184

In general, the VAR standard raises issues concerning the sufficiency of measures 

required, the lack of compliance directives, and ambiguities in interpreting the technical 

Requirements. Without Compliance Measures and Levels of Non-Compliance, the ERO 

will not have benchmarks to implement consistent and effective enforcement. This 

standard also does not contain sufficient Levels of Non-Compliance to assure the 

equitable enforcement of penalties. NERC has indicated that this standard will be 

modified to address this deficiency and resubmitted for Commission approval in 

November 2006. 

An examination of the standard’s Requirements has identified technical issues: the 

Requirements may be incomplete and therefore might not adequately protect the reliable 

operation of the Bulk-Power System, and they might not address the lessons learned from 

past operating incidents. Further, the Requirements are ambiguous regarding what is 

required to comply with the standard. In addition, implementation of the Blackout 

Report recommendations regarding reliability involves this standard. 

 184 Principles for Efficient and Reliable Reactive Power Supply and Consumption, Staff Report, 

Docket No. AD05-1-000 at p. 20 (February 4, 2005). See also Blackout Report at 18 (The August 14, 

2003 Blackout was due in part to inadequate voltage control and reactive power supply, as stated: 

“insufficient reactive power was an issue in the blackout, but it was not a cause in itself. Rather, 

deficiencies in corporate policies, lack of adherence to industry policies, and inadequate management of 

reactive power and voltage caused the blackout, rather than the lack of reactive power.”). 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 118 - 

Chapter: VAR 

B. Primary Issues with the Voltage and Reactive Control Standard 

1. Unclear and Incomplete Requirements 

The VAR standard requires a Transmission Owner to “acquire sufficient reactive 

resources within its area to protect the voltage levels under normal and Contingency 

conditions,”185 and “maintain system and Interconnection voltages within established 

limits.”186 These requirements may not assure reliable operation of power systems when 

operating under conditions that make them vulnerable to voltage collapse. Under heavy 

system loading conditions, and depending on system characteristics, operating voltages at 

levels that are traditionally considered normal (e.g., 95 percent nominal) may no longer 

be stable operating voltages. Voltage magnitudes alone are poor indicators of voltage 

stability.187 

The VAR standard does not address these pre- and post-contingency operating voltages, 

nor does it require Transmission Operators to maintain voltage levels above the voltage 

collapse points (i.e., voltage instability) with a sufficient margin in accordance with good 

utility practice. For example, the Western Electric Coordinating Council’s Reliability 

Criteria document, which contains a standard on voltage support and reactive power, 

states: 

For transfer paths, post-transient voltage stability is required with the path 

modeled at a minimum of 105% of the path rating (or Operational Transfer 

Capability) for system normal conditions (Category A) and for single 

contingencies (Category B). For multiple contingencies (Category C), 

post-transient voltage stability is required with the path modeled at a 

minimum of 102.5% of the path rating (or Operational Transfer 

Capability).[188]

 185 North American Electric Reliability Council, Reliability Standards for the Bulk 

Electric Systems of North America, Standard VAR-001-0 (Standard VAR-001-0) (R2). 

186 Id. at R6. 

187 Blackout Report at 36. See also Western Electric Coordinating Council, Reliability Criteria at 

35 (April 2005) (“Voltage magnitudes alone are poor indicators of voltage stability or security because 

the system may be near collapse even if voltages are near normal depending on the system characteristics. 

The system must be planned so that there is sufficient margin between normal operating point and the 

collapse point to allow for reliable system operation.”). 

188 WECC Reliability Criteria document at 32. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 119 - 

Chapter: VAR 

The above criteria state explicitly the voltage stability requirement and the margin 

requirements between the actual operating limits and the test levels in simulations for 

different contingencies. Staff notes that margins in Operational Transfer Capability are 

substitutable for voltage margins and either application is effective in ensuring reliability. 

The VAR standard does not contain a Requirement that operations planning studies be 

carried out to identify the minimum permissible pre-contingency voltage levels and 

reactive power reserves. Requiring such studies would assure stable post-contingency 

voltage levels to avoid voltage collapse. These studies would also identify feasible 

corrective operating actions, which may include load shedding in pre-contingency 

conditions to avoid voltage collapse that may occur either in the pre- or post-contingency 

conditions. The standard does not currently require that these corrective operating 

actions be communicated to system operators as part of the day-ahead operations plan. In 

addition, the standard does not require similar voltage stability assessments to be carried 

out periodically during real-time operations so that system operators can continuously 

respond to changing system conditions. 

The current standard does not address Recommendation Number 23 of the Blackout 

Report, which is to “[s]trengthen reactive power and voltage control practices in all 

NERC regions.”189 Staff notes that NERC, in response to this recommendation, 

established the Transmission Issues Subcommittee (TIS), which completed an evaluation 

of reactive power planning.190

2. Applicability 

Voltage and reactive control is an integral part of Interconnection Reliability Operating 

Limits (IROLs). Voltage collapse can result in a widespread cascading outage on an 

Interconnection. Therefore, reliable operations of the Bulk-Power System require that 

Reliability Coordinators be authorized to direct and coordinate voltage and reactive 

control among operating entities in an Interconnection and assure that they can fulfill 

their role as the entity with the “highest level of authority.”191

 189 Blackout Report at 160. 

190 NERC Transportation Issues Subcommittee, Evaluation of Reactive Power Planning and 

Voltage Control Practices in Response to NERC Blackout Recommendation 7a (May 3, 2005). 

191 NERC Glossary (A Reliability Coordinator is defined as “The entity that is the highest level 

of authority who is responsible for the reliable operation of the Bulk Electric System, has the Wide Area 

view of the Bulk Electric System, and has the operating tools, processes and procedures, including the 

authority to prevent or mitigate emergency operating situations in both next-day analysis and real-time 

operations. The Reliability Coordinator has the purview that is broad enough to enable the calculation of 

(continued) 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 120 - 

Chapter: VAR 

Staff notes that Requirement R3, which requires that “[e]ach Purchasing-Selling Entity 

shall arrange for (self-provide or purchase) reactive resources to satisfy its reactive 

requirements identified by its Transmission Service Provider,”192 is not currently 

applicable to Load-Serving Entities who are responsible for significantly more load on 

the system than the Purchasing-Selling Entities. The applicability of the standard is 

currently limited to Transmission Operators, Generator Operators and Purchasing-Selling 

Entities. This standard does not apply to Reliability Coordinators and Load-Serving 

Entities. 

 

Interconnection Reliability Operating Limits, which may be based on the operating parameters of 

transmission systems beyond any Transmission Operator’s vision.”). 

192 Standard VAR-001-0, Requirement R3. 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 121 - 

APPENDIX A: STANDARDS REVIEWED 

In this preliminary assessment, staff evaluated the same standards as those NERC 

submitted in its Petition for Approval of Reliability Standards dated April 4, 2006. 

Standard 

Number Title EffectiveDate

BAL-001-0 Real Power Balancing Control Performance 04/01/05

BAL-002-0 Disturbance Control Performance 04/01/05

BAL-003-0 Frequency Response and Bias 04/01/05

BAL-004-0 Time Error Correction 04/01/05

BAL-005-0 Automatic Generation Control 04/01/05

BAL-006-0 Inadvertent Interchange 04/01/05

UA-1200 Urgent Action Standard - Cyber Security 08/13/03

CIP-001-0 Sabotage Reporting 04/01/05

COM-001-0 Telecommunications 04/01/05

COM-002-1 Communications and Coordination 11/01/06

EOP-001-0 Emergency Operations Planning 04/01/05

EOP-002-1 Capacity and Energy Emergencies 11/01/06

EOP-003-0 Load Shedding Plans 04/01/05 

EOP-004-0 Disturbance Reporting 04/01/05

EOP-005-0 System Restoration Plans 04/01/05 

EOP-006-0 Reliability Coordination - System Restoration 04/01/05

EOP-007-0 Establish, Maintain, and Document a Regional Blackstart Capability Plan 04/01/05 

EOP-008-0 Plans for Loss of Control Center Functionality 04/01/05

EOP-009-0 Documentation of Blackstart Generating Unit Test Results 04/01/05

FAC-001-0 Facility Connection Requirements 04/01/05

FAC-002-0 Coordination of Plans for New Facilities 04/01/05

FAC-003-1 Vegetation Management Program 04/07/06

FAC-004-0 Methodologies for Determining Electrical Facility Ratings 04/01/05

FAC-005-0 Electrical Facility Ratings for System Modeling 04/01/05

FAC-008-1 Facility Ratings Methodology 08/07/06 

FAC-009-1 Establish and Communicate Facility Ratings 10/07/06

FAC-012-1 Transfer Capabilities Methodology 08/07/06 

FAC-013-1 Establish and Communicate Transfer Capabilities 10/07/06

INT-001-0 Interchange Transaction Tagging 04/01/05

INT-002-0 Interchange Transaction Tag Communication and Assessment 04/01/05

INT-003-0 Interchange Transaction Implementation 04/01/05

INT-004-0 Interchange Transaction Modifications 04/01/05
FERC Staff Preliminary Assessment of NERC Reliability Standards - 122 - 

Appendix A 

IRO-001-0 Reliability Coordination – Responsibilities and Authorities 04/01/05

IRO-002-0 Reliability Coordination – Facilities 04/01/05

IRO-003-1 Reliability Coordination – Wide Area View 08/01/06

IRO-004-1 Reliability Coordination - Operations Planning 11/01/06

IRO-005-1 Reliability Coordination – Current Day Operations 11/01/06

IRO-006-1 Reliability Coordination – Transmission Loading Relief 08/08/05

IRO-014-1 Procedures to Support Coordination Between Reliability Coordinators 11/01/06

IRO-015-1 Notifications and Information Exchange Between Reliability Coordinators 11/01/06

IRO-016-1 Coordination of Real-time Activities Between Reliability Coordinators 11/01/06

MOD-001-0 Documentation of TTC and ATC Calculation Methodologies 04/01/05

MOD-002-0 Review of TTC and ATC Calculations and Results 04/01/05

MOD-003-0 Procedure for Input on TTC and ATC Methodologies and Values 04/01/05

MOD-004-0 Documentation of Regional CBM Methodologies 04/01/05

MOD-005-0 Procedure for Verifying CBM Values 04/01/05

MOD-006-0 Procedures for Use of CBM Values 04/01/05

MOD-007-0 Documentation of the Use of CBM 04/01/05

MOD-008-0 Documentation and Content of Each Regional TRM Methodology 04/01/05

MOD-009-0 Procedure for Verifying TRM Values 04/01/05

MOD-010-0 Steady-State Data for Transmission System Modeling and Simulation 04/01/05

MOD-011-0 Regional Steady-State Data Requirements and Reporting Procedures 04/01/05

MOD-012-0 Dynamics Data for Transmission System Modeling and Simulation 04/01/05

MOD-013-0 RRO Dynamics Data Requirements and Reporting Procedures 04/01/05

MOD-014-0 Development of Interconnection-Specific Steady State System Models 04/01/05

MOD-015-0 Development of Interconnection-Specific Dynamics System Models 04/01/05

MOD-016-0 Actual and Forecast Demands, Net Energy for Load, Controllable DSM 04/01/05

MOD-017-0 Aggregated Actual and Forecast Demands and Net Energy for Load 04/01/05

MOD-018-0 Reports of Actual and Forecast Demand Data 04/01/05

MOD-019-0 Forecasts of Interruptible Demands and DCLM Data 04/01/05

MOD-020-0 Providing Interruptible Demands and DCLM Data 04/01/05

MOD-021-0 Accounting Methodology for Effects of Controllable DSM in Forecasts 04/01/05

MOD-024-1 Verification of Generator Gross and Net Real Power Capability 04/01/06

MOD-025-1 Verification of Reactive Power Capability 01/01/07

PER-001-0 Operating Personnel Responsibility and Authority 04/01/05

PER-002-0 Operating Personnel Training 04/01/05

PER-003-0 Operating Personnel Credentials 04/01/05

PER-004-0 Reliability Coordination – Staffing 04/01/05

PRC-001-0 System Protection Coordination 04/01/05

PRC-002-0 Define and Document Disturbance Monitoring Equipment Requirements 04/01/05
FERC Staff Preliminary Assessment of NERC Reliability Standards - 123 - 

Appendix A 

PRC-003-1 Regional Requirements for Transmission and Generation Protection System Misoperations 05/01/06

PRC-004-1 Analysis and Mitigation of Transmission and Generation Protection System Misoperations 08/01/06

PRC-005-1 Transmission and Generation Protection System Maintenance and Testing 05/01/06

PRC-006-0 Development and Documentation of Regional UFLS Programs 04/01/05

PRC-007-0 Assuring Consistency with Regional UFLS Programs 04/01/05

PRC-008-0 Underfrequency Load Shedding Equipment Maintenance Programs 04/01/05

PRC-009-0 UFLS Performance Following an Underfrequency Event 04/01/05

PRC-010-0 Assessment of the Design and Effectiveness of UVLS Program 04/01/05

PRC-011-0 UVLS System Maintenance and Testing 04/01/05

PRC-012-0 Special Protection System Review Procedure 04/01/05

PRC-013-0 Special Protection System Database 04/01/05

PRC-014-0 Special Protection System Assessment 04/01/05

PRC-015-0 Special Protection System Data and Documentation 04/01/05

PRC-016-0 Special Protection System Misoperations 04/01/05

PRC-017-0 Special Protection System Maintenance and Testing 04/01/05

PRC-020-1 Under-Voltage Load Shedding Program Database 05/01/06

PRC-021-1 Under-Voltage Load Shedding Program Data 08/01/06

PRC-022-1 Under-Voltage Load Shedding Program Performance 05/01/06

TOP-001-0 Reliability Responsibilities and Authorities 04/01/05

TOP-002-0 Normal Operations Planning 04/01/05

TOP-003-0 Planned Outage Coordination 04/01/05

TOP-004-0 Transmission Operations 04/01/05

TOP-005-1 Operational Reliability Information 11/01/06

TOP-006-0 Monitoring System Conditions 04/01/05

TOP-007-0 Reporting SOL and IROL Violations 04/01/05

TOP-008-0 Response to Transmission Limit Violations 04/01/05

TPL-001-0 System Performance Under Normal Conditions 04/01/05

TPL-002-0 System Performance Following Loss of a Single BES Element 04/01/05

TPL-003-0 System Performance Following Loss of Two or More BES Elements 04/01/05

TPL-004-0 System Performance Following Extreme BES Events 04/01/05

TPL-005-0 Regional and Interregional Self-Assessment Reliability Reports 04/01/05

TPL-006-0 Assessment Data from Regional Reliability Organizations 04/01/05

VAR-001-0 Voltage and Reactive Control 04/01/05

Glossary of Terms Used in Reliability Standards 02/08/05
FERC Staff Preliminary Assessment of NERC Reliability Standards - 124 - 

APPENDIX B: STANDARDS WITH UNCLEAR ENFORCEABILITY 

UNDER EPACT 2005 

NERC identifies 25 standards that are not enforceable with penalties. The following are 

the 28 standards identified by staff to have total or partial applicability to Regional 

Reliability Organizations. Such entities are not explicitly Owners, Operators, or Users of 

the Bulk-Power System, as defined by EPAct 2005, and therefore enforcement of these 

standards under EPAct 2005 is unclear. 

Standard Number Title 

BAL-002-0 Disturbance Control Performance (partial) 

EOP-004-0 Disturbance Reporting (partial) 

EOP-007-0 Establish, Maintain, and Document a Regional Black start Capability Plan 

FAC-003-1 Transmission Vegetation Management Program (partial) 

IRO-001-0 Reliability Coordination – Responsibilities and Authorities (partial) 

MOD-001-0 Documentation of TTC and ATC Calculation Methodologies 

MOD-002-0 Review of TTC and ATC Calculations and Results 

MOD-003-0 Procedure for Input on TTC and ATC Methodologies and Values 

MOD-004-0 Documentation of Regional CBM Methodologies 

MOD-005-0 Procedure for Verifying CBM Values 

MOD-008-0 Documentation and Content of Each Regional TRM Methodology 

MOD-009-0 Procedure for Verifying TRM Values 

MOD-011-0 Regional Steady-State Data Requirements and Reporting Procedures 

MOD-013-0 RRO Dynamics Data Requirements and Reporting Procedures 

MOD-014-0 Development of Interconnection-Specific Steady State System Models 

MOD-015-0 Development of Interconnection-Specific Dynamics System Models 

MOD-016-0 

Determination of Data Reporting Requirements for Actual and Forecast Demands, 

Net Energy for Load, Controllable DSM (partial) 

MOD-024-1 Verification of Generator Gross and Net Real Power Capability (partial) 

MOD-025-1 Verification of Generator Gross and Net Real Power Capability (partial) 

PRC--002-0 Define and Document Disturbance Monitoring Equipment Requirements 

PRC-003-1 

Regional Procedure for Analysis of Misoperations of Transmission and Generation 

Protection Systems 

PRC-006-0 Development and Documentation of Regional UFLS Program 

PRC-012-0 Special Protection System Review Procedure 

PRC-013-0 Special Protection System Database 

PRC-014-0 Special Protection System Assessment 

PRC-020-1 Under-Voltage Load Shedding Program Database 

TPL-005-0 Regional and Interregional Self-Assessment Reliability Reports 

TPL-006-0 Assessment Data from Regional Reliability Organizations 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 125 - 

APPENDIX C: STANDARDS LACKING MEASURABILITIY AND NONCOMPLIANCE SPECIFICATIONS 

In its Request for Approval of Reliability Standards, NERC identifies 21 standards 

without provisions in the Measures or Levels of Non-Compliance sections of the 

standard. The following is a list of 26 standards identified by staff without provisions for 

either Measures, or Levels of Non-Compliance, or both. 

Standard Number Title 

BAL-003-0 Frequency Response and Bias 

BAL-004-0 Time Error Correction 

BAL-005-0 Automatic Generation Control 

BAL-006-0 Inadvertent Interchange 

CIP-001-0 Sabotage Reporting 

COM-001-0 Telecommunications 

COM-002-0 or 

COM-002-1 Communications and Coordination 

EOP-003-0 Load Shedding Plans 

EOP-004-0 Disturbance Reporting 

EOP-005-0 System Restoration Plans 

EOP-006-0 Reliability Coordination – System Restoration 

INT-001-0 Interchange Transaction Tagging 

INT-002-0 Interchange Transaction Tag Communication and Assessment 

INT-003-0 Interchange Transaction Implementation 

INT-004-0 Interchange Transaction Modifications 

IRO-002-0 Reliability Coordination − Facilities 

IRO-003-0 or 

IRO-003-1 Reliability Coordination − Wide Area View 

IRO-005-0 or 

IRO-005-1 Reliability Coordination − Current Day Operations 

PER-004-0 Reliability Coordination – Staffing 

PRC-001-0 System Protection Coordination 

TOP-001-0 Reliability Responsibilities and Authorities 

TOP-002-0 Normal Operations Planning 

TOP-004-0 Transmission Operations 

TOP-006-0 Monitoring System Conditions 

TOP-008-0 Response to Transmission Limit Violations 

VAR-001-0 Voltage and Reactive Control 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 126 - 

APPENDIX D: ACRONYMS IN THIS DOCUMENT 

ACE Area Control Error 

AGC Automatic Generation Control 

ANSI American National Standards Institute 

ATC Available Transfer Capability 

BAL Resource and Demand Balancing category in the NERC Reliability 

Standards 

BCP Blackstart Capability Plan 

BES Bulk Electric System 

BPS Bulk-Power System 

CBM Capacity Benefit Margin 

CIP Critical Infrastructure Protection category in the NERC Reliability 

Standards 

COM Communications category in the NERC Reliability Standards 

CPS1/CPS2 Control Performance Standard 1 / Control Performance Standard 2 

DC Direct Current 

DCS Disturbance Control Standard 

EOP Emergency Preparedness and Operations category in the NERC 

Reliability Standards 

ERO Electric Reliability Organization 

FAC Facilities Design, Connections and Maintenance category in the NERC 

Reliability Standards 

FPA Federal Power Act 

GWh Gigawatt hour 

IEEE Institute of Electrical and Electronic Engineers 

INT Interchange Scheduling and Coordination category in the NERC 

Reliability Standards 

IRO Interconnection Reliability Operations and Coordination category in the 

NERC Reliability Standards 

IROL Interconnection Reliability Operating Limits 
FERC Staff Preliminary Assessment of NERC Reliability Standards - 127 - 

Appendix D 

MOD Modeling, Data, and Analysis category in the NERC Reliability Standards 

MW Mega Watt 

NERC The North American Electric Reliability Corporation and the North 

American Electric Reliability Council are separately or collectively 

referred to as NERC 

NPCC Northeast Power Coordinating Council 

PER Personnel Performance, Training, and Qualifications category in the 

NERC Reliability Standards 

PRC Protection and Control category in the NERC Reliability Standards 

RRO Regional Reliability Organization 

ROW Right of Way 

SOL System Operating Limit 

SPS Special Protection System 

TIS Transmission Issues Subcommittee 

TOP Transmission Operations category in the NERC Reliability Standards 

TLR Transmission Loading Relief 

TPL Transmission Planning category in the NERC Reliability Standards 

TRM Transmission Reliability Margin 

TTC Total Transfer Capability 

UA-1200 Urgent Action Standard - 1200 

UFLS Under Frequency Load Shedding 

UVLS Under Voltage Load Shedding 

VAR Voltage and Reactive category in the NERC Reliability Standards 

WECC Western Electricity Coordinating Council