123 FERC ¶ 61,064 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

18 CFR Part 40 

[Docket No. RM08-7-000] 

Modification of Interchange and Transmission Loading Relief Reliability Standards; and 

Electric Reliability Organization Interpretation of Specific Requirements of Four 

Reliability Standards 

(Issued April 21, 2008) 

AGENCY: Federal Energy Regulatory Commission. 

ACTION: Notice of Proposed Rulemaking. 

SUMMARY: Pursuant to section 215 of the Federal Power Act, the Federal Energy 

Regulatory Commission proposes to approve six modified Reliability Standards 

submitted to the Commission for approval by the North American Electric Reliability 

Corporation (NERC). Five modified Reliability Standards pertain to interchange 

scheduling and coordination and one pertains to transmission loading relief procedures. 

In addition, the Commission proposes to approve NERC’s proposed interpretations of 

five specific requirements of Commission-approved Reliability Standards. 

DATES: Comments are due 45 days after publication in the FEDERAL REGISTER.

ADDRESSES: You may submit comments, identified by docket number by any of the 

following methods: 

• Agency Web Site: http://www.ferc.gov. Documents created electronically using 

word processing software should be filed in native applications or print-to-PDF 

format and not in a scanned format. 
Docket No. RM08-7-000 - 2 - 

• Mail/Hand Delivery. Commenters unable to file comments electronically must 

mail or hand deliver an original and 14 copies of their comments to: Federal 

Energy Regulatory Commission, Secretary of the Commission, 888 First Street, 

N.E., Washington, D.C. 20426. 

FOR FURTHER INFORMATION CONTACT: 

Patrick Harwood (Technical Information) 

Office of Electric Reliability 

Federal Energy Regulatory Commission 

888 First Street, NE 

Washington, DC 20426 

Christopher Daignault (Legal Information) 

Office of the General Counsel 

Federal Energy Regulatory Commission 

888 First Street, NE 

Washington, DC 20426 

SUPPLEMENTARY INFORMATION:
UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Modification of Interchange and Transmission Loading 

Relief Reliability Standards; and Electric Reliability 

Organization Interpretation of Specific Requirements of 

Four Reliability Standards 

Docket No. RM08-7-000 

NOTICE OF PROPOSED RULEMAKING 

TABLE OF CONTENTS

 Paragraph Numbers

I. Background .................................................................................................................... 2.

A. EPAct 2005 and Mandatory Reliability Standards .................................................. 2.

B. NERC Filings ........................................................................................................... 6.

II. Discussion................................................................................................................... 11.

A. NERC’s December 19, 2007 Filing: Interpretations............................................. 12.

1. BAL-001-0 – Real Power Balancing Control Performance and BAL-003-0 

Frequency Response and Bias ................................................................................. 13.

a. Background..................................................................................................... 13.

i. Reliability Standard BAL-001-0 ................................................................ 13.

ii. Reliability Standard BAL-003-0 ............................................................... 15.

b. NERC’s Proposed Interpretations.................................................................. 16.

i. Reliability Standard BAL-001-0 ................................................................ 17.

ii. Reliability Standard BAL-003-0 ............................................................... 21.

c. Commission Proposal..................................................................................... 23.

2. BAL-005-0 – Automatic Generation Control..................................................... 26.

a. NERC’s Proposed Interpretation.................................................................... 26.

b. Commission Proposal..................................................................................... 28.

3. VAR-002-1 Generator Operation for Maintaining Network Voltage Schedules29.

a. NERC’s Proposed Interpretation.................................................................... 29.

b. Commission Proposal..................................................................................... 34.

B. NERC’s December 21, 2007 Filing: Modification of TLR Procedure ................. 35.

1. NERC’s Proposed Reliability Standard.............................................................. 35.

a. Background..................................................................................................... 36.

b. NERC Filing................................................................................................... 38.
Docket No. RM08-7-000 ii 

c. Commission Proposal..................................................................................... 47.

i. Requirements .............................................................................................. 48.

ii. Violation Risk Factors............................................................................... 50.

C. NERC’s December 26, 2007 Filing: Modification to Five “Interchange and 

Scheduling” Reliability Standards ............................................................................... 58.

1. INT-001-3 – Interchange Information and INT-004-2 – Dynamic Interchange 

Transaction Modifications....................................................................................... 59.

a. Background..................................................................................................... 59.

b. NERC’s Proposed Modifications................................................................... 61.

c. Commission Proposal..................................................................................... 63.

2. INT-005-2 – Interchange Authority Distributes Arranged Interchange,............ 64.

a. INT-006-2 – Response to Interchange Authority, and INT-008-2 – 

Interchange Authority Distributes Status............................................................ 64.

i. Background................................................................................................. 64.

ii. NERC’s Proposed Modifications .............................................................. 68.

b. Commission Proposal..................................................................................... 74.

III. Information Collection Statement ............................................................................. 75.

IV. Environmental Analysis ............................................................................................ 82.

V. Regulatory Flexibility Act Analysis........................................................................... 83.

VI. Comment Procedures ................................................................................................ 84.

VII. Document Availability............................................................................................. 88.
123 FERC ¶ 61,064 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Modification of Interchange and Transmission Loading 

Relief Reliability Standards; and Electric Reliability 

Organization Interpretation of Specific Requirements of 

Four Reliability Standards 

Docket No. RM08-7-000 

NOTICE OF PROPOSED RULEMAKING 

(Issued April 21, 2008) 

1. Pursuant to section 215 of the Federal Power Act (FPA),1

 the Federal Energy 

Regulatory Commission (Commission) proposes to approve six modified Reliability 

Standards submitted to the Commission for approval by the North American Electric 

Reliability Corporation (NERC). Five modified Reliability Standards pertain to 

interchange scheduling and coordination, and one pertains to transmission loading relief 

procedures.2

 In addition, the Commission proposes to approve NERC’s proposed 

interpretations of five specific requirements of Commission-approved Reliability 

Standards. 

 

1

 16 U.S.C. 824o (Supp. V 2005). 

2

 The Commission is not proposing any new or modified text to its regulations. 

Rather, as set forth in 18 CFR Part 40, a proposed Reliability Standard will not become 

effective until approved by the Commission, and the ERO must post on its website each 

effective Reliability Standard. 
Docket No. RM08-7-000 

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I. Background

A. EPAct 2005 and Mandatory Reliability Standards

2. Section 215 of the FPA requires a Commission-certified Electric Reliability 

Organization (ERO) to develop mandatory and enforceable Reliability Standards, which 

are subject to Commission review and approval. Once approved, the Reliability 

Standards may be enforced by the ERO, subject to Commission oversight, or by the 

Commission independently.3

3. Pursuant to section 215 of the FPA, the Commission established a process to select 

and certify an ERO4

 and, subsequently, certified NERC as the ERO.5 On April 4, 2006, 

as modified on August 28, 2006, NERC submitted to the Commission a petition seeking 

approval of 107 proposed Reliability Standards. On March 16, 2007, the Commission 

issued a final rule, Order No. 693, approving 83 of these 107 Reliability Standards and 

directing other action related to these Reliability Standards.6

 In addition, pursuant to 

 3

 See FPA 215(e)(3), 16 U.S.C. 824o(e)(3) (Supp. V 2005). 

4

 Rules Concerning Certification of the Electric Reliability Organization; and 

Procedures for the Establishment, Approval and Enforcement of Electric Reliability 

Standards, Order No. 672, FERC Stats. & Regs. ¶ 31,204, order on reh’g, Order 

No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006). 

5

 North American Electric Reliability Corp., 116 FERC ¶ 61,062 (ERO 

Certification Order), order on reh’g & compliance, 117 FERC ¶ 61,126 (ERO Rehearing 

Order) (2006), appeal docketed sub nom. Alcoa, Inc. v. FERC, No. 06-1426 (D.C. Cir. 

Dec. 29, 2006).

6

 Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, 

FERC Stats. & Regs. ¶ 31,242, order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053 

(2007). 
Docket No. RM08-7-000 

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section 215(d)(5) of the FPA, the Commission directed NERC to develop modifications 

to 56 of the 83 approved Reliability Standards.7

4. In April 2007, the Commission approved delegation agreements between NERC 

and each of the eight Regional Entities, including the Western Electricity Coordinating 

Council (WECC).8

 Pursuant to such agreements, the ERO delegated responsibility to the 

Regional Entities to carry out compliance monitoring and enforcement of the mandatory, 

Commission-approved Reliability Standards. In addition, the Commission approved as 

part of each delegation agreement a Regional Entity process for developing regional 

Reliability Standards. 

5. NERC’s Rules of Procedure provide that a person that is “directly and materially 

affected” by Bulk-Power System reliability may request an interpretation of a Reliability 

Standard.9

 The ERO’s “standards process manager” will assemble a team with relevant 

expertise to address the clarification and also form a ballot pool. NERC’s Rules provide 

that, within 45 days, the team will draft an interpretation of the Reliability Standard, with 

subsequent balloting. If approved by ballot, the interpretation is appended to the 

 7

 16 U.S.C. 824o(d)(5) (Supp. V 2005). Section 215(d)(5) provides, “The 

Commission . . . may order the Electric Reliability Organization to submit to the 

Commission a proposed reliability standard or a modification to a reliability standard that 

addresses a specific matter if the Commission considers such a new or modified 

reliability standard appropriate to carry out this section.” 

8

 See North American Electric Reliability Corp., 119 FERC ¶ 61,060, order on 

reh’g, 120 FERC ¶ 61,260 (2007). 

9

 NERC Rules of Procedure, Appendix 3A (Reliability Standards Development 

Procedure), at 26-27. 
Docket No. RM08-7-000 

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Reliability Standard and filed with the applicable regulatory authority for regulatory 

approval. 

B. NERC Filings

6. This rulemaking proceeding consolidates and addresses three NERC filings. 

7. On December 19, 2007, NERC submitted for Commission approval interpretations 

of requirements in four Commission-approved Reliability Standards: BAL-001-0 (Real 

Power Balancing Control Performance), Requirement R1; BAL-003-0 (Frequency 

Response and Bias), Requirement R3; BAL-005-0 (Automatic Generation Control), 

Requirement R17; and VAR-002-1 (Generator Operation for Maintaining Network 

Voltage Schedules), Requirements R1 and R2.10

8. On December 21, 2007, NERC submitted for Commission approval modifications 

to Reliability Standard IRO-006-4 (Reliability Coordination – Transmission Loading 

Relief) that applies to balancing authorities, reliability coordinators, and transmission 

operators. NERC states that the modifications “extract” from the Reliability Standard the 

business practices and commercial requirements from the current IRO-006-3 Reliability 

Standard. The business practices and commercial requirements have been transferred to 

a North American Energy Standards Board (NAESB) business practices document. 

The NAESB business practices and commercial requirements have been included in 

Version 001 of the NAESB Wholesale Electric Quadrant (WEQ) Standards which 

 10 In its filing, NERC identifies the Reliability Standards together with NERC’s 

proposed interpretations as BAL-001-0a, BAL-003-0a, BAL-005-0a, and VAR-002-1a. 
Docket No. RM08-7-000 

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NAESB filed with the Commission on the same day, December 21, 2007.11 Further, 

NERC states that the modified Reliability Standard includes changes directed by the 

Commission in Order No. 693 related to the appropriateness of using the transmission 

loading relief (TLR) procedure to mitigate violations of interconnection reliability 

operating limits (IROLs).12

9. On December 26, 2007, NERC submitted for Commission approval modifications 

to five Reliability Standards from the “Interchange Scheduling” group of Reliability 

Standards: INT-001-3 (Interchange Information); INT-004-2 (Dynamic Interchange 

Transaction Modifications); INT-005-2 (Interchange Authority Distributes Arranged 

Interchange); INT-006-2 (Response to Interchange Authority); and INT-008-2 

(Interchange Authority Distributes Status). NERC states that the modifications to 

INT-001-3 and INT-004-2 eliminate waivers requested in 2002 under the voluntary 

Reliability Standards regime for entities in the WECC region. According to NERC, 

modifications to INT-005-2, INT-006-2, and INT-008-2 adjust reliability assessment time 

frames for proposed transactions within WECC.13

10. Each Reliability Standard that the ERO proposes to interpret or modify in this 

proceeding was approved by the Commission in Order No. 693. 

 11 NAESB December 21, 2007 Filing, Docket No. RM05-5-005. 

12 An IROL is a system operating limit that, if violated, could lead to instability, 

uncontrolled separation, or cascading outages that adversely impact the reliability of the 

Bulk-Power System. 

13 The proposed, modified Reliability Standard addressed in this notice of 

proposed rulemaking is available on the Commission’s eLibrary document retrieval 

system in Docket No. RM08-7-000 and also on NERC’s website, http://www.nerc.com. 
Docket No. RM08-7-000 

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II. Discussion

11. The Commission discusses below the ERO’s proposed interpretations and 

proposed modifications, and the Commission’s proposed disposition of each. 

A. NERC’s December 19, 2007 Filing: Interpretations

12. As mentioned above, NERC submitted for Commission approval interpretations of 

four Commission-approved Reliability Standards. 

1. BAL-001-0-Real Power Balancing Control Performance and 

BAL-003-0- Frequency Response and Bias

a. Background

i. Reliability Standard BAL-001-0

13. The purpose of Reliability Standard BAL-001-0 is to maintain interconnection 

steady-state frequency within defined limits by balancing real power demand and supply 

in real-time.14 Requirement R1 of BAL-001-0 defines the limits on area control error 

(ACE), which essentially is the mismatch between generation and load (i.e., the mismatch 

between supply and demand) within the footprint of a balancing authority, measured by 

the difference between the balancing authority’s net actual interchange and scheduled 

interchange with neighboring balancing authorities, after taking into account effects of 

 14 See Reliability Standard BAL-001-0. Each Reliability Standard developed by 

the ERO includes a “Purpose” statement. 
Docket No. RM08-7-000 

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deviations in interconnection frequency.15 The ability to constantly match load and 

generation within a certain tolerance directly affects the electrical state and control of the 

Bulk-Power System.16 Each balancing authority thus monitors the extent of its ACE in 

real-time and takes appropriate action also in real-time to rebalance supply and demand.17 

Requirement R1 obliges each balancing authority, on a rolling twelve-month basis, to 

maintain its clock-minute averages of ACE within a specific limit. 

14. A supply/demand imbalance between the interconnection’s generation output 

(including net imports) and load on a real-time basis will result in a deviation from the 

desired 60 Hz optimum operating frequency of the interconnection. All of the balancing 

authorities within an interconnection must work together to correct a deviation.18 They 

do this by including a frequency bias component in their ACE calculation which indicates 

how many more or fewer megawatts a balancing authority would have interchanged with 

 15 Generally, a balancing authority within an interconnection has an obligation to 

do its part to maintain the desired 60 Hertz (Hz) frequency. To achieve this, each 

balancing authority must keep its generation output (including net imports from 

neighboring balancing authorities) and load in balance within its footprint. A deviation 

from the 60 Hz baseline system frequency signals an imbalance in supply and demand. 

To prevent this imbalance from propagating throughout the interconnection, steps are 

taken to adjust regulating reserves (generation output and demand-side management)in 

response to deviations from the 60 Hz optimum. See North American Electric Reliability 

Corp., 121 FERC ¶ 61,179, at P 17 (2007) (November 16, 2007 Order). 

16 If generation and load is not matched within a balancing authority’s area, the 

resulting imbalance could result in an undue burden on adjacent balancing authorities 

and, if additional contingencies from disturbances are experienced, may compromise the 

ability of the Bulk-Power System to recover from those disturbances. See November 16, 

2007 Order, 121 FERC ¶ 61,179 at P 28. 

17 See November 16, 2007 Order, 121 FERC ¶ 61,179 at P 20. 

18 See id. P 31. 
Docket No. RM08-7-000 

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neighboring balancing authorities if the actual frequency had been exactly maintained so 

as to equal to the scheduled frequency. Thus, balancing authorities calculate what their 

total interchange would have been if the actual frequency had been exactly maintained so 

as to equal to the scheduled frequency. With this information, the balancing authority 

can increase or decrease generation within the balancing authority’s area to maintain the 

correct scheduled interchange. The total supply and the demand within an 

interconnection is balanced by the collective effort of all the balancing authorities in that 

interconnection to maintain the correct scheduled interchange. In this manner, frequency 

deviations are minimized, thereby protecting reliability without causing undue burden on 

any balancing authorities. 

ii. Reliability Standard BAL-003-0

15. The purpose of Reliability Standard BAL-003-0 is to provide a consistent method 

for calculating the frequency bias component of ACE. To accomplish this purpose, it is 

necessary to rely on historic data from a balancing authority’s automatic generation 

control.19 Automatic generation control is the equipment that calculates ACE on an 

ongoing basis and serves as a “governor” that adjusts a balancing authority’s generation, 

and demand-side resources where available, from a central location to minimize 

unscheduled interchange with its neighboring balancing authorities in order to balance 

ACE. There are several ways that automatic generation control could be set to balance 

 19 Automatic generation control refers to an automatic process whereby a 

balancing authority’s mix and output of its generation and demand-side management is 

varied to offset the extent of supply and demand imbalances reflected in its ACE. 

November 16, 2007 Order, 121 FERC ¶ 61,179 at P 19 n.14. 
Docket No. RM08-7-000 

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the supply and demand within the balancing authority area. One method is called the 

“tie-line frequency bias” mode of operation. Collective operation in this mode allows 

balancing authorities’ automatic generation control to calculate ACE and adjust the 

generation in the balancing authority area in a manner that maintains the interconnection 

frequency and does not result in an undue burden for any balancing authority. In 

addition, operation in this mode allows a balancing authority to continuously collect its 

tie-line and frequency data that must be used when the balancing authority annually 

reviews the frequency bias component of its ACE calculation as specified by BAL-003-0. 

Requirement R3 of BAL-003-0 requires the use of the tie-line frequency bias mode of 

operation of automatic generation control, unless such operation is adverse to system 

interconnection reliability. 

b. NERC’s Proposed Interpretations

16. NERC further states that, on June 1, 2007, WECC requested that NERC provide a 

formal interpretation that addresses Requirement R1 of BAL-001-0 and Requirement R3 

of BAL-003-0. In particular, WECC asked whether the use of WECC’s existing 

automatic time error correction procedure, which is currently proposed as a regional 

Reliability Standard, violates Requirement R1 of BAL-001-0 or Requirement R3 of 

BAL-003-0. 

i. Reliability Standard BAL-001-0

17. Requirement R1 of BAL-001-0 provides: 

Each Balancing Authority shall operate such that, on a rolling 12-month 

basis, the average of the clock-minute averages of the Balancing 

Authority’s Area Control Error (ACE) divided by 10B (B is the clock-
Docket No. RM08-7-000 

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minute average of the Balancing Authority Area’s Frequency Bias) times 

the corresponding clock-minute averages of the Interconnection’s 

Frequency Error is less than a specific limit. This limit ε1

2 is a constant 

derived from a targeted frequency bound (separately calculated for each 

Interconnection) that is reviewed and set as necessary by the NERC 

Operating Committee. 

18. NERC’s proposed interpretation of BAL-001-0 Requirement R1 reads: 

 The [WECC automatic time error correction or WATEC] procedural 

documents ask Balancing Authorities to maintain raw ACE for 

[control performance standard or CPS] reporting and to control via 

WATEC-adjusted ACE. 

 As long as Balancing Authorities use raw (unadjusted for WATEC) 

ACE for CPS reporting purposes, the use of WATEC for control is 

not in violation of BAL-001 Requirement 1. 

(NERC December 19, 2007 Filing, Ex. A-2.) 

19. As context to its interpretation, NERC explains that BAL-001-0 uses a formula for 

the ACE calculation equal to the difference in actual and scheduled interchange, less a 

component based on the frequency bias to adjust for the difference in actual and 

scheduled frequency, less the meter error.20 NERC also explains that the WECC 

automatic time error correction procedure uses the same formula for ACE as defined in 

BAL-001-0 except with two additional components.21

20. NERC maintains that the use of the WECC automatic time error correction 

procedure for control does not result in a violation of BAL-001-0 Requirement 1, 

provided that (1) WECC’s balancing authorities use the raw and unadjusted ACE for 

 20 See NERC December 19, 2007 Filing at 8-9. 

21 See id. 
Docket No. RM08-7-000 

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control performance reporting purposes and (2) the raw, unadjusted ACE complies with 

Requirement R1. 

ii. Reliability Standard BAL-003-0

21. Requirement R3 of BAL-003-0 provides: 

Each Balancing Authority shall operate its Automatic Generation Control 

(AGC) on Tie Line Frequency Bias, unless such operation is adverse to 

system or Interconnection Reliability. 

NERC’s proposed interpretation of BAL-003-0 Requirement R3 reads: 

 Tie-Line Frequency Bias is one of the three foundational control 

modes available in a Balancing Authority’s energy management 

system. (The other two are flat-tie and flat-frequency.) Many 

Balancing Authorities layer other control objectives on top of their 

basic control mode, such as automatic inadvertent payback, [control 

performance standard] optimization, time control (in single 

[balancing authority] interconnections).[22] 

 As long as Tie-Line Frequency Bias is the underlying control mode 

and CPS1 is measured and reported on the associated ACE 

equation,[23] there is no violation of BAL-003-0 Requirement 3: 

ACE = (NIA− NIS) – 10B (FA − FS) − IME 

(NERC December 19, 2007 Filing, Ex. A-3.) 

22. NERC explains that there is no violation of BAL-003-0 Requirement R3, provided 

that a balancing authority uses the tie-line frequency bias mode as the underlying control 

 22 The “flat frequency” control mode would increase or decrease generation solely 

based on the interconnection frequency. The “flat tie” mode would increase or decrease 

generation within a balancing authority area depending solely on that balancing 

authority’s total interchange. The “tie-line frequency bias” mode combines the flat 

frequency and flat tie modes and adjusts generation based on the balancing authority’s 

net interchange and the interconnection frequency. 

23 “CPS1” refers to Requirement R1 of BAL-001-0. 
Docket No. RM08-7-000 

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mode and the control performance standard (CPS1), per BAL-001-0 Requirement R1, is 

measured and reported on the associated ACE equation. 

c. Commission Proposal

23. The Commission proposes to approve the ERO’s formal interpretation of 

Requirement R1 of BAL-001-0 and Requirement R3 of BAL-003-0. 

24. The ERO’s interpretation is reasonable because it clarifies that raw ACE must be 

used in NERC compliance reporting. Reporting of raw ACE is essential because a 

balancing authority could exceed ACE limits in BAL-001-0 if allowed to report an 

adjusted ACE that adds or subtracts amounts from the equation. This interpretation 

upholds the reliability goal of BAL-001-0, Requirement R1 to minimize the frequency 

deviation of the interconnection by constantly balancing supply and demand. The 

interpretation also clarifies that an entity may use automatic generation control modes 

layered on top of the tie-line frequency bias mode as long as the raw ACE is used in 

NERC compliance reporting. This would permit WECC to implement more stringent 

time error correction procedures that rely on additional control modes layered on top of 

the tie-line frequency bias mode of automatic generation control, provided they do not 

report adjusted ACE which, if reported, could produce ambiguous data used for 

frequency bias calculations. The interpretation maintains the goal of BAL-003-0, 

Requirement R3, by providing accurate historic data for frequency bias calculations and 

by using ACE calculations in automatic generation control that will adjust the generation, 

or demand-side resources where available, in the balancing authority area in a manner 

that maintains the interconnection frequency and does not result in an undue burden for 
Docket No. RM08-7-000 

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any balancing authority. The Commission proposes to approve the ERO’s interpretation 

based on the understanding that a balancing authority, in operating automatic generation 

control, must use tie-line frequency bias as its underlying control mode unless to do so is 

adverse to system or interconnection reliability. 

25. In Order No. 693, the Commission stated that, according to the available data, the 

WECC automatic time error correction procedure is more effective in minimizing time 

error corrections and inadvertent interchange than the Reliability Standard BAL-004-0.24 

Therefore, the ERO’s interpretation provides balancing authorities using the WECC 

automatic time error correction procedure with necessary clarification and certainty in 

accordance with the continent-wide Reliability Standards BAL-001-0 and BAL-003-0. 

Accordingly, this interpretation appears to be just, reasonable, not unduly discriminatory 

or preferential, and in the public interest. 

2. BAL-005-0 – Automatic Generation Control

a. NERC’s Proposed Interpretation

26. Requirement R17 of Reliability Standard BAL-005-0 (Automatic Generation 

Control) is intended to annually check and calibrate the time error and frequency devices 

under the control of the balancing authority that feed data into automatic generation 

control necessary to calculate ACE. Requirement R17 mandates that the balancing 

authority must adhere to an annual calibration program for time error and frequency 

devices. The Requirement states that a balancing authority must adhere to minimum 

accuracies in terms of ranges specified in Hertz, volts, amps, etc., for various listed 

 24 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 377. 
Docket No. RM08-7-000 

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devices, such as digital frequency transducers, voltage transducers, remote terminal unit, 

potential transformers, and current transformers. 

27. On December 21, 2006, NERC received a request to provide a formal 

interpretation of Requirement R17 asking whether the only devices that need to be 

annually calibrated under this requirement are time error and frequency devices, and 

whether the list of device accuracy is simply the design accuracy of the devices listed and 

that those devices do not need to be calibrated on an annual basis (except the digital 

frequency transducer which is covered as a “frequency device”). NERC provided an 

interpretation clarifying that the intent of BAL-005-0, Requirement R17 is to annually 

check and calibrate a balancing authority’s time error and frequency devices located in 

the control room against the common reference, and this requirement does not apply to 

any such devices located outside of the operations control center. 

b. Commission Proposal

28. On July 31, 2007, the ERO received a second request for an interpretation of 

Requirement R17 of BAL-005-0, which asked the ERO to further clarify the ambiguity of 

what devices are included in the requirement. On April 15, 2008, the ERO submitted 

another interpretation of Requirement R17 of BAL-005-0 and sought to withdraw its 

request for Commission approval of the interpretation of Requirement R17 filed in this 

proceeding on December 19, 2007. Accordingly, the Commission does not plan to act on 

the initial interpretation. The Commission will act on the April 15 interpretation in a 

future proceeding. 
Docket No. RM08-7-000 

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3. VAR-002-1 Generator Operation for Maintaining Network

Voltage Schedules

a. NERC’s Proposed Interpretation

29. The stated purpose of Reliability Standard VAR-002-1 is to ensure that generators 

provide reactive and voltage control necessary to ensure that voltage levels, reactive 

flows, and reactive resources are maintained within applicable facility ratings to protect 

equipment and the reliable operation of the interconnection.25 Specifically, Requirement 

R1 of Reliability Standard VAR-002-1 provides: 

The Generator Operator shall operate each generator connected to 

the interconnected transmission system in the automatic voltage 

control mode (automatic voltage regulator in service and controlling 

voltage) unless the Generator Operator has notified the Transmission 

Operator. 

Requirement R2 of this Reliability Standard provides: 

 

Unless exempted by the Transmission Operator, each Generator 

Operator shall maintain the generator voltage or Reactive Power 

output (within applicable Facility Ratings) as directed by the 

Transmission Operator. 

30. NERC states that it received a request to provide a formal interpretation of 

Requirements R1 and R2 on January 24, 2007. The request for interpretation first asked 

whether automatic voltage regulator (AVR) operation in the constant power factor or 

 25 Most bulk electric power is generated, transported, and consumed in alternating 

current (AC) networks. AC systems supply (or produce) and consume (or absorb or lose) 

two kinds of power: real power and reactive power. Real power accomplishes useful 

work (e.g., runs motors and lights lamps). Reactive power supports the voltages that 

must be controlled for system reliability. FERC, Principles for Efficient and Reliable 

Reactive Power Supply and Consumption, Docket No. AD05-1-000, at 17 (2005), 

available at http://www.ferc.gov/legal/staff-reports.asp (Reactive Power Principles). 
Docket No. RM08-7-000 

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constant Mvar modes complies with Requirement R1.26 Secondly, the request asked the 

ERO whether Requirement R2 gives the transmission operator the option of directing the 

generation owner to operate the AVR in the constant power factor or constant Mvar 

modes rather than the constant voltage mode. 

31. The AVR is designed to automatically adjust generator voltage and/or powerfactor to ensure proper grid operational characteristics. Constant voltage mode is the 

normal mode of operation for AVR and maintains the output voltage at a constant level. 

The constant power factor mode is a setting of the AVR that causes the generator to 

output a set ratio of real power to reactive power, whereas the constant Mvar mode is a 

setting that causes the generator to maintain an output with a constant amount of reactive 

power. 

32. NERC’s formal interpretation provides that AVR operation in the constant power 

factor or constant Mvar modes does not comply with Requirement R1.27 The 

 26 “Power factor” is a measure of real power in relation to reactive power. A high 

power factor means that relatively more useful power is being taken or produced relative 

to the amount of reactive power. A lower power factor means that there is relatively 

more reactive power taken than real power. “Mvar” is a measure of reactive power equal 

to one million reactive volt-amperes. Reactive Power Principles, supra note 16, at 7, 12, 

41, 119, 120. 

27 NERC’s proposed interpretation of VAR-002-1 Requirement R1 reads: 

1. First, does AVR operation in the constant PF or constant Mvar modes 

comply with R1? 

Interpretation: No, only operation in constant voltage mode meets this 

requirement. This answer is predicated on the assumption that the generator 

has the physical equipment that will allow such operation and that the 

Transmission Operator has not directed the generator to run in a mode other 

than constant voltage. 
Docket No. RM08-7-000 

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interpretation rests on the assumption that the generator has the physical equipment that 

will allow such operation and that the transmission operator has not directed the 

generator to run in a mode other than constant voltage. The interpretation also provides 

that Requirement R2 does give the transmission operator the option of directing the 

generation operator to operate the AVR in the constant power factor or constant Mvar 

modes rather than the constant voltage mode.28

33. In its transmittal letter, NERC explains that, with respect to the interpretation of 

Requirement R1, Reliability Standard VAR-002-1 clearly states that the generator 

operator shall operate with the automatic voltage regulator in service and controlling 

voltage. The interpretation specifies that this can only be accomplished by using the 

constant voltage control mode, and using the constant power factor or constant Mvar 

control is not a true method to control voltage even though it may have some effect on 

voltage. In addition, NERC explains that Requirement R2 provides for an exemption to 

this baseline mode of operation to allow the transmission operator the ability to direct the 

generator operator to use another mode of operation. 

 

2. Second, does R2 give the Transmission Operator the option of directing 

the Generation Owner (sic) to operate the AVR in the constant Pf or 

constant Mvar modes rather than the constant voltage mode? 

Interpretation: Yes, if the Transmission Operator specifically directs a 

Generator Operator to operate the AVR in a mode other than constant 

voltage mode, then that directed mode of AVR operation is allowed. 

NERC December 19, 2007 Filing, Ex. C-2. 

28 We note, as does NERC, the requesting party’s apparent error when it references 

“Generation Owner” instead of the generator operator. 
Docket No. RM08-7-000 

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b. Commission Proposal

34. The Commission proposes to approve the ERO’s interpretation of Requirement R1 

and Requirement R2 of VAR-002-1. These interpretations appear to be reasonable and 

do not appear to change or conflict with the stated responsibilities set forth in the two 

requirements as approved in Order No. 693. Therefore, this interpretation appears to be 

just, reasonable, not unduly discriminatory or preferential, and in the public interest. 

B. NERC’s December 21, 2007 Filing: Modification of TLR Procedure

1. NERC’s Proposed Reliability Standard

35. As mentioned above, on December 21, 2007, NERC submitted for Commission 

approval proposed Reliability Standard IRO-006-4, to modify the current Commissionapproved Reliability Standard, IRO-006-3. 

a. Background

36. In Order No. 693, the Commission approved the current version of this Reliability 

Standard, IRO-006-3. This Reliability Standard ensures that a reliability coordinator has 

a coordinated transmission service curtailment and reconfiguration method that can be 

used along with other alternatives, such as redispatch or demand-side management, to 

avoid transmission limit violations when the transmission system is congested. 

Reliability Standard IRO-006-3 establishes a detailed TLR process for use in the Eastern 
Docket No. RM08-7-000 

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Interconnection to alleviate loadings on the system by curtailing or changing transactions 

based on their priorities and the severity of the transmission congestion.29

37. In addition to approving IRO-006-3, the Commission in Order No. 693 directed 

the ERO to modify the Reliability Standard to: (1) include a clear warning that the TLR 

procedure is an inappropriate and ineffective tool to mitigate actual IROL violations;30

and (2) identify in a requirement the available alternatives to mitigate an IROL violation 

other than use of the TLR procedure.31 These directives reflect an observation from the 

U.S.-Canada Power System Outage Task Force in the August 14, 2003 Blackout Report, 

which identified that the TLR procedure is often too slow for use in situations where the 

system has already violated IROLs.32 In setting forth these directives, the Commission 

stated that it did not have concerns with the use of the TLR procedure to avoid potential

IROL violations.33 

b. NERC Filing

38. According to NERC, the modifications embodied in proposed Reliability Standard 

IRO-006-4 represent the first phase of a three-phase project intended to improve the 

 29 The equivalent interconnection-wide TLR procedures for use in WECC and 

Electric Reliability Council of Texas (ERCOT) are known as “WSCC Unscheduled Flow 

Mitigation Plan” and section 7 of the “ERCOT Protocols,” respectively. 

30 An IROL is a system operating limit that, if violated, could lead to instability, 

uncontrolled separation, or cascading outages that adversely impact the reliability of the 

Bulk-Power System. 

31 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 964. 

32 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, at 163 

(April 2004) (Final Blackout Report), available at https://reports.energy.gov/. 

33 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 962. 
Docket No. RM08-7-000 

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overall quality of IRO-006. In the first phase, NERC extracted the business practices and 

commercial requirements from the existing IRO-006-3 Reliability Standard and proposes 

to transfer them into the NAESB business practices.34 NERC’s filing does not seek to 

modify the remaining reliability requirements of IRO-006, with the exception that the 

Reliability Standard has been clarified to include the Commission’s Order No. 693 

directive that using the TLR procedure is not effective to mitigate an actual IROL 

violation. 

39. According to NERC, the second phase of the IRO-006 project will address 

possible changes to the regional differences associated with the congestion management 

process used by the PJM Interconnection, L.L.C., the Midwest Independent System 

Operator, Inc., and the Southwest Power Pool, Inc. In the third phase, NERC plans to 

completely redraft the Reliability Standard to incorporate further enhancements and 

changes beyond the separation of reliability and business practices. 

40. In its filing, NERC explains that the filed Reliability Standard IRO-006-4 meets 

the guidance outlined in Order No. 672, used to determine whether a Reliability Standard 

is just, reasonable, not unduly discriminatory or preferential, and in the public interest. 35 

In addition, IRO-006-4 includes violation risk factors and violation severity levels that 

were not provided with IRO-006-3. 

 34 The NAESB business practices and commercial requirements have been 

included in Version 001 of the NAESB Wholesale Electric Quadrant standards and filed 

with the Commission on December 21, 2007. The NAESB filing is the subject of a 

separate rulemaking in Docket No. RM05-5-005. A notice of proposed rulemaking 

addressing the NAESB filing is being issued concurrently with the immediate NOPR. 

35 Order No. 672, FERC Stats. & Regs. ¶ 31,204 at P 326. 
Docket No. RM08-7-000 

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41. NERC’s proposed IRO-006-4 Reliability Standard consists of five requirements. 

Proposed Requirement R1 obligates a reliability coordinator experiencing a potential or 

actual system operating limit (SOL) or IROL violation within its reliability coordinator 

area to select one or more procedures to provide transmission loading relief. The 

requirement also identifies the regional TLR procedures in WECC and Electric 

Reliability Council of Texas (ERCOT). The requirement includes a warning that the 

TLR procedure alone is an inappropriate and ineffective tool to mitigate an IROL 

violation and provides alternatives. 

42. Proposed Requirement 2 mandates that the reliability coordinator only use a 

congestion management procedure to which the transmission operator experiencing the 

SOL or IROL is a party. NERC explains that Requirement R1 and Requirement R2 are 

assigned a violation risk factor of “lower” because they are administrative in nature and 

are merely intended to describe how a reliability coordinator may choose a procedure to 

implement TLR.36 According to NERC, these Requirements are not intended to 

duplicate the requirements of other Reliability Standards that ensure the system is 

operated within SOL and IROL limits such as Requirements R3 and R5 of IRO-005-1, 

which have “high” violation risk factors.37 NERC adds that, provided the reliability 

coordinator is adhering to the requirements in IRO-005-1, there is no significant risk to 

 36 Exhibit A (Reliability Standard Proposed for Approval) of NERC’s 

December 21, 2007 filing, however, contains the violation risk factor of “medium” for 

these requirements, but NERC indicates elsewhere that it is “lower.” NERC December 

21, 2007 Filing at 12-13. 

37 Id. at 13. 
Docket No. RM08-7-000 

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the reliability of the Bulk-Power System as a result of a violation of Requirement R1 of 

IRO-006-4. 

43. Proposed Requirement R3 establishes that a reliability coordinator with a TLR 

obligation from an interconnection-wide procedure follow the curtailments as directed by 

the interconnection-wide procedure. The requirement includes that a reliability 

coordinator desiring to use a local procedure as a substitute for curtailments as directed 

by the interconnection-wide procedure shall obtain prior approval of the local procedure 

from the ERO. NERC states that a violation risk factor of “lower” for Requirement R3 is 

appropriate because it is intended that an entity could choose alternate actions for relief 

other than curtailments specified by this requirement to ensure reliability. 

44. Proposed Requirement R4 mandates that each reliability coordinator comply with 

interconnection-wide procedures, once they are implemented, to curtail transactions that 

cross interconnection boundaries. 

45. Proposed Requirement R5 directs balancing authorities and reliability coordinators 

to comply with applicable interchange-related Reliability Standards during the 

implementation of TLR procedures. NERC proposes “medium” violation risk factors for 

Requirement R4 and Requirement R5 explaining that, while failure to comply with these 

requirements could lead the system to an unbalanced scenario, such failure would not 

pose a “high” risk to the system. 

46. Finally, NERC explains that four violation severity levels have been assigned to 

Requirement R1 of IRO-006-4 based on the number of violations of interconnection-wide 

procedure requirements, and these levels are intended to base violation severity on the 
Docket No. RM08-7-000 

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degree of deviation from the requirements by the violator. NERC states that there is a 

single violation severity level for each of the remaining requirements (i.e., R2, R3, R4, 

and R5), because an entity simply either “passes” or “fails” each of these requirements. 

c. Commission Proposal

47. The Commission proposes to approve Reliability Standard IRO-006-4 as just, 

reasonable, not unduly discriminatory or preferential, and in the public interest. In 

addition, the Commission proposes to direct the ERO to modify certain violation risk 

factors that correspond to the Requirements of the Reliability Standard. 

i. Requirements

48. NERC’s proposal implements the Commission’s directives (1) to include a clear 

warning that the TLR procedure is an inappropriate and ineffective tool to mitigate actual 

IROL violations; and (2) to identify in a requirement the available alternatives to mitigate 

an IROL violation. Specifically, Requirement R1.1 of IRO-006-4 states, “The TLR 

procedure alone is an inappropriate and ineffective tool to mitigate an IROL violation due 

to the time required to implement the procedure. Other acceptable and more effective 

procedures to mitigate actual IROL violations include: reconfiguration, redispatch, or 

load shedding.” The Commission proposes to approve this standard based on the 

interpretation that using a TLR procedure alone to mitigate an IROL violation is a 

violation of the Reliability Standard. 

49. Further, the proposed division between NERC and NAESB business practices 

seems to be reasonable and appears to pose no harm to reliability. The Commission has 

long supported the coordination of business practices and Reliability Standards. As early 
Docket No. RM08-7-000 

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as May 2002, the Commission urged the industry expeditiously to establish the 

procedures for ensuring coordination between NAESB and NERC.38 The Commission 

asks for comments on whether any compromise in the reliability of the Bulk-Power 

System may result from the removal and transfer to NAESB of the business-related 

issues formerly contained in Reliability Standard IRO-006. 

ii. Violation Risk Factors

50. Violation risk factors delineate the relative risk to the Bulk-Power System 

associated with the violation of each Requirement and are used by NERC and the 

Regional Entities to determine financial penalties for violating a Reliability Standard. 

NERC assigns a lower, medium, or high violation risk factor for each mandatory 

Reliability Standard Requirement.39 The Commission also established guidelines for 

evaluating the validity of each Violation Risk Factor assignment.40 

51. The Commission is concerned regarding the violation risk factors submitted with 

IRO-006-4. While the approved violation risk factors for IRO-006-0 Requirement R2 

 38 Electricity Market Design and Structure, 99 FERC ¶ 61,171, at P 22 (2002); see 

also Standards for Business Practices and Communication Protocols for Public Utilities, 

Order No. 676, FERC Stats. & Regs. ¶ 31,216, at P 6 (2006). 

39 The definitions of “high,” “medium,” and “lower” are provided in North 

American Electric Reliability Corp., 119 FERC ¶ 61,145, at P 9 (Violation Risk Factor 

Order), order on reh’g, 120 FERC ¶ 61,145 (2007) (Violation Risk Factor Rehearing). 

40 The guidelines are: (1) consistency with the conclusions of the Blackout 

Report; (2) consistency within a Reliability Standard; (3) consistency among Reliability 

Standards; (4) consistency with NERC’s definition of the violation risk factor level; and 

(5) treatment of requirements that co-mingle more than one obligation. The Commission 

also explained that this list was not necessarily all-inclusive and that it retains the 

flexibility to consider additional guidelines in the future. A detailed explanation is 

provided in Violation Risk Factor Rehearing, 120 FERC ¶ 61,145 at P 8-13. 
Docket No. RM08-7-000 

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through Requirement R6 are all “high,”41 NERC proposes to revise violation risk factors 

for similarly-worded Requirements R1 through R5 of IRO-006-4 to “lower” or 

“medium.” Sub-requirements R1.1 through R1.3 are explanatory text; therefore, we 

propose that a violation risk factor need not be assigned to them. For consistency with 

the Commission’s five guidelines discussed above, the Commission proposes to direct the 

ERO to modify the violation risk factors assigned to Requirements R1 through R4 to 

“high.” We discuss our concerns below. 

52. The Commission disagrees with the ERO that Requirement R1 is administrative in 

nature in describing how a reliability coordinator may choose a procedure to provide 

transmission loading relief. Requirement R1, as well as Requirement R2 through R4, 

goes beyond merely providing procedural choices for transmission loading relief, as the 

ERO asserts. Requirements R1 through R4 require that a reliability coordinator choose 

and follow the appropriate procedure to provide relief. If the reliability coordinator 

chooses an unapproved and ineffective procedure for relief or fails to choose a procedure 

entirely, potential or actual IROLs will not be mitigated as intended by the reliability 

coordinator. Failure to implement the proper TLR procedure likely would lead to IROL 

violations, which could lead to cascading outages. The implementation of the TLR 

procedure shares a similar reliability goal as other Reliability Standard requirements that 

keep the transmission system within IROLs, thus presenting a similar reliability risk and 

violation risk factor, if violated. 

 41 The violation risk factors for these requirements were submitted by NERC on 

February 23, 2007, and they were approved in the Violation Risk Factor Order. 
Docket No. RM08-7-000 

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53. With respect to IRO-006-4, Requirement R1, the ERO states that, provided the 

reliability coordinator is adhering to the requirements in IRO-005-1, there is no 

significant risk to the reliability of the Bulk-Power System as a result of a violation of 

Requirement R1 of IRO-006-4. We disagree. The violation risk factor of a requirement 

represents the risk a violation of that requirement presents to the reliability of the BulkPower System. Violation risk factors should not be assigned differently for requirements 

in separate Reliability Standards based on compliance with another standard. Two 

requirements either achieve separate reliability goals and, therefore, violation of them 

represents independent risks, or two requirements share the same reliability goal. As 

stated in Guideline 3 of the Violation Risk Factor Order,42 the Commission expects that 

the assignment of violation risk factors corresponding to requirements that address 

similar reliability goals in different Reliability Standards would be treated comparably. 

54. Furthermore, a “high” violation risk factor assignment for Requirements R1 

through R4 is consistent with findings of the Final Blackout Report. The report 

highlights that, generally, “TLRs are intended as a tool to prevent the system from being 

operated in an unreliable state and are not applicable in real-time emergency 

situations.”43 As a result, Recommendation No. 31 in the Final Blackout Report was 

developed to clarify that the TLR procedure should not be used in situations involving an 

actual violation of an operating security limit. 

 42 119 FERC ¶ 61,145 at P 25. 

43 Final Blackout Report at 62. 
Docket No. RM08-7-000 

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55. A medium or lower violation risk factor has been approved for the Reliability 

Standards in the Interchange Scheduling and Coordination (INT) family of Reliability 

Standards. Requirement R5 of IRO-006-4 complements the INT group of Reliability 

Standards and, thus, appears to be appropriately assigned a medium violation risk factor. 

56. The added “Measures” and other revisions embedded in proposed Reliability 

Standard IRO-006-4 do not appear to substantively change the earlier, Commissionapproved version (i.e., IRO-006-3). 

57. In summary, proposed Reliability Standard IRO-006-4 appears to be just, 

reasonable, not unduly discriminatory or preferential, and in the public interest. 

Accordingly, the Commission proposes to approve Reliability Standard IRO-006-4 as 

mandatory and enforceable. In addition, the Commission proposes to direct the ERO to 

modify the violation risk factors, as described above.44 

C. NERC’s December 26, 2007 Filing: Modification to Five “Interchange 

and Scheduling” Reliability Standards

58. NERC submitted for Commission approval proposed modifications to five 

Reliability Standards from the INT group of Reliability Standards. 

 44 Although “time horizons,” which relate to the immediacy of the risk posed by a 

violation of a requirement, are included in this Reliability Standard, we do not propose to 

rule on the time horizons in this rulemaking. On March 3, 2008, in Docket No. RR08-4-

000, NERC submitted proposed violation severity levels corresponding to the 

Requirements of 83 Commission-approved Reliability Standards. The Commission will 

address the violation severity levels regarding IRO-006-4 in that proceeding. 
Docket No. RM08-7-000 

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1. INT-001-3 – Interchange Information and INT-004-2 – Dynamic 

Interchange Transaction Modifications

a. Background

59. The Interchange Scheduling and Coordination or “INT” group of Reliability 

Standards address interchange transactions, which occur when electricity is transmitted 

from a seller to a buyer across the power grid. Reliability Standard INT-001 applies to 

purchasing-selling entities and balancing authorities. The stated purpose of this 

Reliability Standard is to “ensure that Interchange Information is submitted to the NERCidentified reliability analysis service.” Reliability Standard INT-004 is intended to 

“ensure Dynamic Transfers are adequately tagged to be able to determine their reliability 

impacts.” 

60. In Order No. 693, the Commission approved the currently applicable version of 

these Reliability Standards, INT-001-2 and INT-004-1.45 Further, when NERC initially 

submitted these two Reliability Standards for Commission approval, NERC also asked 

the Commission to approve a “regional difference” that would exempt WECC from 

requirements related to tagging dynamic schedules and inadvertent payback provisions of 

INT-001-2 and INT-004-1. The Commission, in Order No. 693, stated that it did not 

have sufficient information to address the ERO’s proposed regional difference and 

directed the ERO to submit a filing either withdrawing the regional difference or 

providing additional information needed for the Commission to make a determination on 

 45 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 821, 843. In addition, the 

Commission directed that the ERO develop modifications to INT-001-2 and INT-004-1 

that address the Commission’s concerns. 
Docket No. RM08-7-000 

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the matter.46 The effect of NERC’s December 26, 2007 filing is to withdraw the regional 

difference with respect to WECC. 

b. NERC’s Proposed Modifications

61. In May 2007, WECC requested that NERC rescind the regional difference, 

referred to as e-tagging waivers,47 for Reliability Standards INT-001-2 and INT-004-1. 

According to NERC, WECC has developed business practices for dynamic schedules and 

has taken the steps needed to comply with the e-tagging of inadvertent payback 

interchange schedules. Thus, WECC determined that it no longer needs the e-tagging 

waivers. 

62. NERC processed WECC’s request through NERC’s Reliability Standard 

Development Procedure, using its urgent action process.48 NERC states that, by 

rescinding the e-tagging waivers, NERC maintains uniformity and makes no structural 

changes to the requirements in the current Commission-approved version of the 

Reliability Standards. 

c. Commission Proposal

63. NERC states that simply rescinding these waivers will not result in structural 

changes to the requirements in the current Commission-approved version of the 

 46 Id. P 825. 

47 An E-tag represents a transaction on the North American bulk electricity market 

scheduled to flow within, between, or across electric utility company territories 

electronically. This is done so that transmission system operators can ascertain all of the 

transactions impacting their local system and take any corrective actions to alleviate 

situations that could put the power grid at risk of damage or collapse.

48 NERC December 26, 2007 Filing at 5-6. 
Docket No. RM08-7-000 

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Reliability Standards and will maintain uniformity. Further, we note that WECC agrees 

that it no longer needs to retain the waivers.49 Accordingly, the Commission proposes to 

approve INT-001-3 and INT-004-2. 

2. INT-005-2 – Interchange Authority Distributes Arranged

Interchange,

a. INT-006-2 – Response to Interchange Authority, and INT008-2 – Interchange Authority Distributes Status

i. Background

64. In Order No. 693, the Commission approved the entire group of INT Reliability 

Standards.50 

65. Reliability Standard INT-005-1 applies to the interchange authority. The stated 

purpose of proposed Reliability Standard INT-005-1 is to “ensure that the 

implementation of Interchange between Source and Sink Balancing Authorities is 

distributed by an Interchange Authority such that Interchange information is available for 

reliability assessments.” 

66. Reliability Standard INT-006-1 applies to balancing authorities and transmission 

service providers. The stated purpose of the Reliability Standard is to “ensure that each 

Arranged Interchange is checked for reliability before it is implemented.” 

 49 Id.

50 In addition, the Commission directed the ERO to develop modifications to INT006-1. The Commission-directed modifications are not included in the immediate filing; 

rather, the ERO will develop such modifications pursuant to its Reliability Standards 

Development Plan 2008-2010. 
Docket No. RM08-7-000 

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67. Reliability Standard INT-008-1 applies to the interchange authority. The stated 

purpose of the Reliability Standard is to “ensure that the implementation of Interchange 

between Source and Sink Balancing Authorities is coordinated by an Interchange 

Authority.” This means that it is the interchange authorities’ responsibility to oversee 

and coordinate the interchange from one balancing authority to another. 

ii. NERC’s Proposed Modifications

68. In its December 26, 2007 filing, NERC addresses a specific reliability need 

identified by WECC in its urgent action request. 

69. Requirement R1.4 of INT-007-1 requires that each balancing authority and 

transmission service provider provide confirmation to the interchange authority that it has 

approved the transactions for implementation. NERC states that for WECC the 

timeframe allotted for this assessment is five minutes in the original version of the 

Commission-approved Reliability Standards. 

70. NERC explains that the proposed Reliability Standards for INT-005-2, INT-006-2, 

and INT-008-2 would increase the timeframe for applicable WECC entities to perform 

the reliability assessment from five to ten minutes for next hour interchange tags 

submitted in the first thirty minutes of the hour before. According to NERC, this 

modification is needed because the majority of next-hour tags in WECC are submitted 

between xx:00 and xx:30. NERC explains that the existing five minute assessment 

window makes it nearly impossible for balancing authorities and transmission service 

providers to review each tag before the five minute assessment time expires. NERC 

maintains that, when the time expires, the tags are denied and must be resubmitted. 
Docket No. RM08-7-000 

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71. NERC states that WECC has experienced numerous instances of transactions 

being denied because one or more applicable reliability entities did not actively approve 

the tag. In NERC’s view, the current structure causes frustration and inefficiencies for 

entities involved in this process, as requestors are required to re-create tags that are 

denied. Further, NERC states that there is no reliability basis for a five minute 

assessment period for tags submitted at least thirty minutes ahead of the ramp-in period. 

72. NERC notes that, prior to January 1, 2007, when the new INT group of Reliability 

Standards was implemented, WECC had a ten-minute reliability assessment period for 

next-hour tags. NERC states that the urgent action request restores assessment times 

back to ten minutes. 

73. Apart from the extension of the reliability assessment period from five to ten 

minutes for WECC entities, NERC avers that it makes no substantive changes to the 

requirements in the current Commission-approved version of the Reliability Standards. 

b. Commission Proposal

74. The Commission proposes to approve INT-005-2, INT-006-2, and INT-008-2. 

The only change proposed to these Reliability Standards is the reliability assessment 

period for WECC.51

III. Information Collection Statement

75. The Office of Management and Budget (OMB) regulations require that OMB 

approve certain reporting and recordkeeping (collections of information) imposed by an 

 51 The Commission notes that NERC’s compliance with Order No. 693, with 

respect to Reliability Standard INT-006-1, is ongoing. See Order No. 693, FERC Stats. 

& Regs. ¶ 31,242 at P 866. 
Docket No. RM08-7-000 

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agency.52 The information contained here is also subject to review under section 3507(d) 

of the Paperwork Reduction Act of 1995.53 As stated above, the Commission previously 

approved, in Order No. 693, each of the Reliability Standards that are the subject of the 

current rulemaking. The proposed modifications to the Reliability Standards are minor 

and the proffered interpretations relate to existing Reliability Standards; therefore, they 

do not add to or increase entities’ current reporting burden. Thus, the current proposal 

would not materially affect the burden estimates relating to the currently effective version 

of the Reliability Standards presented in Order No. 693.54

76. For example, the proposed interpretation of BAL-001-0 and BAL-003-0 does not 

modify or otherwise affect the collection of information already in place. With respect to 

BAL-001-0, the interpretation merely clarifies the rule that is already in place, that the 

time error correction component of the WECC automatic time error correction 

calculation of ACE is not to be used in NERC performance reporting. With respect to 

BAL-003-0, the interpretation clarifies that layering additional control modes on top of 

the tie-line frequency bias mode of automatic generation control is acceptable. Layering 

additional control modes on top of the tie-line frequency bias mode of automatic 

generation control does not change the information that a balancing authority reports 

because the same logs, data, or measurements would be maintained. 

 52 5 CFR 1320.11. 

53 44 U.S.C. 3507(d). 

54 See Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1905-07. 
Docket No. RM08-7-000 

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77. The proposed removal of business practice-related requirements from Reliability 

Standard IRO-006-4 will likely decrease, not increase, the reporting burden associated 

with the current, Commission-approved version of the Reliability Standard. Nor would 

the proposed revision to certain Reliability Standards to allow WECC an additional five 

minutes to perform a reliability assessment regarding interchange transactions impact 

the reporting burden. Further, the proposal to rescind the requested waivers from the 

e-tagging obligation under Reliability Standards INT-001-3 and INT-004-2 for entities 

in the WECC region does not change the reporting burden because NERC was never 

granted its requested waiver to exempt WECC from requirements related to tagging 

dynamic schedules and inadvertent payback.55 In addition, WECC already has business 

practice standards in place that fulfill the dynamic transfer e-tagging reporting and record 

keeping obligations set forth in these Reliability Standards.56

78. Thus, the proposed modifications to the current Reliability Standards and 

interpretations effected by this proposed rule will not increase the reporting burden nor 

impose any additional information collection requirements. 

79. The Commission does not foresee any additional impact on the reporting burden 

for small businesses, because the proposed modifications are minor and the 

interpretations do not increase the existing burden. However, we will submit this 

proposed rule to OMB for informational purposes. 

 55 See Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 822, 825 (directing ERO 

either to withdraw regional difference or provide additional information). 

56 See Business Practice Standard INT-BPS-008-1 (Dynamic Transfer E-Tagging 

Requirements), available at http://www.wecc.biz. 
Docket No. RM08-7-000 

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Title: Modification of Interchange and Transmission Loading Relief Reliability 

Standards; and Electric Reliability Organization Interpretation of Specific Requirements 

of Four Reliability Standards. 

Action: Proposed Collection 

OMB Control No.: 1902-0244 

Respondents: Businesses or other for-profit institutions; not-for-profit institutions 

Frequency of Responses: On Occasion 

Necessity of the Information: This proposed rule would approve six modified Reliability 

Standards, five of which pertain to interchange scheduling and coordination and one that 

pertains to transmission loading relief procedures. In addition, this proposed rule would 

approve interpretations of five specific requirements of Commission-approved Reliability 

Standards. The proposed rule would find the Reliability Standards and interpretations 

just, reasonable, not unduly discriminatory or preferential, and in the public interest. 

Internal Review: The Commission has reviewed the proposed Reliability Standards and 

interpretations and made a determination that these requirements are necessary to 

implement section 215 of the FPA. These requirements conform to the Commission’s 

plan for interchange scheduling and coordination as well as transmission loading relief 

procedures within the energy industry. 

80. Interested persons may obtain information on the reporting requirements by 

contacting the following: Federal Energy Regulatory Commission, 888 First Street, N.E. 

Washington, D.C. 20426 [Attention: Michael Miller, Office of the Executive Director, 

Phone: (202) 502-8415, fax: (202) 273-0873, e-mail: michael.miller@ferc.gov]. 

81. For submitting comments concerning the collection(s) of information and the 

associated burden estimate(s), please send your comments to the contact listed above and 

to the Office of Information and Regulatory Affairs, Office of Information and 

Regulatory Affairs, Washington, D.C. 20503 [Attention: Desk Officer for the Federal 

Energy Regulatory Commission, phone (202) 395-4650, fax: (202) 395-7285, e-mail: 

oira_submission@omb.eop.gov]. 
Docket No. RM08-7-000 

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IV. Environmental Analysis

82. The Commission is required to prepare an Environmental Assessment or an 

Environmental Impact Statement for any action that may have a significant adverse effect 

on the human environment.57 The Commission has categorically excluded certain actions 

from this requirement as not having a significant effect on the human environment. 

Included in the exclusion are rules that are clarifying, corrective, or procedural or that do 

not substantially change the effect of the regulations being amended.58 The actions 

proposed herein fall within this categorical exclusion in the Commission’s regulations.

V. Regulatory Flexibility Act Analysis

83. The Regulatory Flexibility Act of 1980 (RFA)59 generally requires a description 

and analysis of final rules that will have significant economic impact on a substantial 

number of small entities. The RFA mandates consideration of regulatory alternatives that 

accomplish the stated objectives of a proposed rule and that minimize any significant 

economic impact on a substantial number of small entities. The Small Business 

Administration’s Office of Size Standards develops the numerical definition of a small 

business. (See 13 CFR 121.201.) For electric utilities, a firm is small if, including its 

affiliates, it is primarily engaged in the transmission, generation and/or distribution of 

electric energy for sale and its total electric output for the preceding twelve months did 

not exceed four million megawatt hours. The RFA is not implicated by this proposed 

 57 Regulations Implementing the National Environmental Policy Act, Order 

No. 486, FERC Stats. & Regs. ¶ 30,783 (1987). 

58 18 CFR 380.4(a)(2)(ii). 

59 5 U.S.C. 601-12. 
Docket No. RM08-7-000 

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rule because the minor modifications and interpretations discussed herein will not have a 

significant economic impact on a substantial number of small entities. 

VI. Comment Procedures

84. The Commission invites interested persons to submit comments on the matters and 

issues proposed in this notice to be adopted, including any related matters or alternative 

proposals that commenters may wish to discuss. Comments are due 45 days from 

publication in the FEDERAL REGISTER. Comments must refer to Docket No. RM08-

7-000, and must include the commenter’s name, the organization they represent, if 

applicable, and their address in their comments. 

85. The Commission encourages comments to be filed electronically via the eFiling 

link on the Commission’s web site at http://www.ferc.gov. The Commission accepts 

most standard word processing formats. Documents created electronically using word 

processing software should be filed in native applications or print-to-PDF format and not 

in a scanned format. Commenters filing electronically do not need to make a paper 

filing. 

86. Commenters that are not able to file comments electronically must send an 

original and 14 copies of their comments to: Federal Energy Regulatory Commission, 

Secretary of the Commission, 888 First Street N.E., Washington, DC, 20426. 

87. All comments will be placed in the Commission’s public files and may be viewed, 

printed, or downloaded remotely as described in the Document Availability section 

below. Commenters on this proposal are not required to serve copies of their comments 

on other commenters. 
Docket No. RM08-7-000 

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VII. Document Availability

88. In addition to publishing the full text of this document in the Federal Register, the 

Commission provides all interested persons an opportunity to view and/or print the 

contents of this document via the Internet through FERC’s Home Page 

(http://www.ferc.gov) and in FERC’s Public Reference Room during normal business 

hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, N.E., Room 2A, 

Washington D.C. 20426. 

89. From FERC’s Home Page on the Internet, this information is available on 

eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft 

Word format for viewing, printing, and/or downloading. To access this document in 

eLibrary, type the docket number excluding the last three digits of this document in the 

docket number field. 

90. User assistance is available for eLibrary and the FERC’s website during normal 

business hours from FERC Online Support at (202) 502-6652 (toll free at 1-866-208-

3676) or e-mail at ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 

502-8371, TTY (202) 502-8659. E-mail the Public Reference Room at 

public.referenceroom@ferc.gov. 
Docket No. RM08-7-000 

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List of subjects in 18 CFR Part 40 

Electric power, Electric utilities, Reporting and recordkeeping requirements 

By direction of the Commission. Commissioners Wellinghoff and Kelly concurring 

 jointly with a separate statement. 

 

( S E A L ) 

 Kimberly D. Bose, 

 Secretary.
UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Modification of Interchange and Transmission Docket No. RM08-7-000 

Loading Relief Reliability Standards; and 

Electric Reliability Organization Interpretation of 

Specific Requirements of Four Reliability Standards 

 

 

(Issued April 21, 2008) 

WELLINGHOFF and KELLY, Commissioners, concurring: 

Today, the Commission issues a Notice of Proposed Rulemaking (NOPR) 

proposing to approve, among other matters, modified Reliability Standard IRO-006-4 

pertaining to transmission loading relief (TLR) procedures that can be used to prevent or 

manage potential or actual transmission line limit violations when the transmission 

system is congested. An earlier version of this Reliability Standard, IRO-006-3, was 

approved in Order No. 693 subject to modification.1

 This Reliability Standard 

establishes a detailed TLR process for use in the Eastern Interconnection to alleviate 

loadings on the system by curtailing or changing transmission transactions based on their 

priorities and the severity of the transmission congestion. However, the Commission 

directed the ERO2

 to modify the Reliability Standard to: (1) include a clear warning that 

the TLR procedure is an inappropriate and ineffective tool to mitigate actual IROL 

violations, and (2) identify in a requirement the available alternatives to mitigate an IROL 

violation other than use of the TLR procedure.3

 

 1 Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, 

FERC Stats. & Regs. ¶ 31,242, order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053 at 

P 964 (2007). 

2

 The Commission designated the North American Electric Reliability Corp. 

(NERC) as the nation’s electric reliability organization (ERO) in 2006.

3

 An IROL is a system operating limit that, if violated, could lead to instability, 

uncontrolled separation, or cascading outages that adversely impact the reliability of the 

Bulk-Power System. 
Docket No. RM08-7-000 

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Reliability Standard IRO-006-4 contains the required warning that the TLR 

procedure alone is an inappropriate and ineffective tool to mitigate an IROL violation due 

to the time required to implement the procedure. It furthers states that other acceptable 

and more effective procedures to mitigate actual IROL violations include reconfiguration, 

redispatch, or load shedding. Load shedding reduces customers’ demand involuntarily. 

We write separately to note that demand-side management (DSM), or voluntary 

demand reduction, is not explicitly included in IRO-006-4 among the acceptable 

alternatives to TLR procedures. Nothing in the proposed standard precludes the use of 

DSM that can respond quickly to emergencies as an alternative to TLR procedures. Nor 

is there any indication that NERC intended this to be an exhaustive list of alternatives. 

We understand that DSM technologies used currently to provide operating reserve (for 

instance, in the operating reserve markets of ISO and RTOs) would, in fact, be deployed 

as quick response to IROL violations and in most cases would be deployed prior to 

involuntary load shedding. Indeed, voluntary demand response could be a better 

alternative than involuntary load shedding, which, as we indicated above, IRO-006-4 

identifies as an acceptable alternative to TLR procedures. 

In Order No. 693, the Commission directed modifications to Reliability Standards 

BAL-002-0 (Disturbance Control Performance), EOP-002-2 (Capacity and Energy 

Emergencies), VAR-001-1 (Voltage and Reactive Control), and the sensitivity studies of 

the TPL (Transmission Planning) standards to explicitly provide that DSM may be used 

as a resource to meet the requirements of those Standards. The Commission clarified that 

DSM should be treated on a comparable basis and must meet similar technical 

requirements as other resources providing this service.4

 The Commission also addressed 

why explicit identification in the Reliability Standard is necessary, stating: 

The Commission disagrees with APPA that we should not explicitly 

identify any type of capacity as a resource for meeting reserve 

contingencies. The Commission believes that listing the types of 

resources that can be used to meet contingency reserves makes the 

Reliability Standard clearer, provides users, owners and operators of 

the Bulk-Power System a set of options to meet contingency reserves, 

and treats DSM on a comparable basis with other resources. 

 4

 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 335. 
Docket No. RM08-7-000 

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Many commenters argue that the Commission’s proposed directive 

that would explicitly allow DSM as a resource for contingency 

reserves is too prescriptive. Concerns in this area generally fall into 

three categories: (1) that DSM should be treated on a comparable 

basis as other resources; (2) that the Reliability Standard should be 

based on meeting an objective as opposed to stating how that 

objective is met and (3) that DSM may not be technically capable of 

providing this service. 

With regard to the first concern, the Commission clarifies that the 

purpose of the proposed directive is to ensure comparable treatment of 

DSM with conventional generation or any other technology and to 

allow DSM to be considered as a resource for contingency reserves on 

this basis without requiring the use of any particular contingency 

reserve option. The proposed directive as written achieves that goal. 

With regard to the second concern, we believe that this Reliability 

Standard is objective-based and we reiterate that we are simply 

attempting to make it inclusive of other technologies that may be able 

to provide contingency reserves, and are not directing the use of any 

particular type of resource. By specifying DSM as a potential 

resource for contingency reserves, the Commission is clarifying the 

substance of the Reliability Standard.5

Thus, in the interest of clarity and comparability, we would prefer to see DSM 

included among the list of alternatives to TLR procedures. Therefore, we would be 

interested in comments regarding the inclusion of DSM that is capable of responding 

quickly to emergencies among the alternatives to TLR procedures for mitigating 

transmission line limit violations to maintain system reliability. 

For these reasons, we concur with this NOPR. 

______________________________ __________________________ 

Jon Wellinghoff Suedeen G. Kelly 

Commissioner Commissioner 

 5 Id at P 331-33.