Federal Register / Vol. 74, No. 101 / Thursday, May 28, 2009 / Rules and Regulations 25413 

12Regulations Implementing National 

Environmental Policy Act, Order No. 486, 52 FR 

47897 (Dec. 17, 1987), FERC Stats. & Regs. ¶ 30,783 

(1987). 13 18 CFR 380.4(a)(5). 14 5 U.S.C. 601–12. 15 5 U.S.C. 601(3), citing to section 3 of the Small 

Business Act, 15 U.S.C. 632. Section 3 of the Small 

Business Act defines a ‘‘small business concern’’ as 

a business that is independently owned and 

operated and that is not dominant in its field of 

operation. The Small Business Size Standards 

component of the North American Industry 

Classification System (NAICS) defines a small 

electric utility as one that, including its affiliates, 

is primarily engaged in the generation, 

transmission, and/or distribution of electric energy 

for sale and whose total electric output for the 

preceding fiscal year did not exceed four million 

MWh. 13 CFR 121.201. 

prepared for any Commission action 

that may have a significant adverse 

effect on the human environment.12 No 

environmental consideration is 

necessary for Commission action that 

involves information gathering, 

analysis, and dissemination.13

Consequently, neither an environmental 

impact statement nor an environmental 

assessment is required. 

VI. Regulatory Flexibility Act 

17. The Regulatory Flexibility Act of 

1980 (RFA) 14 generally requires either a 

description and analysis of a rule that 

will have a significant economic impact 

on a substantial number of small entities 

or a certification that the rule will not 

have a significant economic impact on 

a substantial number of small entities. 

Most utilities to which this reporting 

requirement applies would not fall 

within the RFA’s definition of small 

entity.15 Consequently, the Commission 

certifies that this reporting requirement 

will not have a significant economic 

impact on a substantial number of small 

entities. 

VII. Document Availability 

18. 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 p.m. Eastern time) at 888 First 

Street, NE., Room 2A, Washington, DC 

20426. 

19. 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. 

20. User assistance is available for 

eLibrary and the FERC’s Web site 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. 

VIII. Effective Date and Congressional 

Notification 

21. These regulations are effective 

July 27, 2009. The Commission has 

determined, with the concurrence of the 

administrator of the Office of 

Information and Regulatory Affairs of 

OMB, that this rule is not a ‘‘major rule’’ 

as defined in section 351 of the Small 

Business Regulatory Enforcement 

Fairness Act of 1996. The Commission 

will submit this rule to both houses of 

Congress and the Government 

Accountability Office. 

List of Subjects in 18 CFR Part 33 

Electric utilities, Reporting and 

recordkeeping requirements. 

By the Commission. 

Kimberly D. Bose, 

Secretary. 

■ In consideration of the foregoing, the 

Commission amends part 33, Chapter I, 

Title 18 of the Code of Federal 

Regulations, as follows: 

PART 33—APPLICATIONS UNDER 

FEDERAL POWER ACT SECTION 203 

■ 1. The authority citation for part 33 

continues to read as follows: 

Authority: 16 U.S.C. 791a–825r, 2601– 

2645; 31 U.S.C. 9701; 42 U.S.C. 7101–7352; 

Pub. L. 209–58, 119 Stat. 594. 

■ 2. In § 33.1, paragraph (c)(12) is 

revised and paragraph (c)(17) is added 

to read as follows: 

§ 33.1 Applicability, definitions, and 

blanket authorizations. 

* * * * * 

(c) * * * 

(12) A public utility is granted a 

blanket authorization under section 

203(a)(1) of the Federal Power Act to 

transfer its outstanding voting securities 

to: 

(i) Any holding company granted 

blanket authorizations in paragraph 

(c)(2)(ii) of this section if, after the 

transfer, the holding company and any 

of its associate or affiliate companies in 

aggregate will own less than 10 percent 

of the outstanding voting interests of 

such public utility; or 

(ii) Any person other than a holding 

company if, after the transfer, such 

person and any of its associate or 

affiliate companies in aggregate will 

own less than 10 percent of the 

outstanding voting interests of such 

public utility, and within 30 days after 

the end of the calendar quarter in which 

such transfer has occurred the public 

utility notifies the Commission in 

accordance with paragraph (c)(17) of 

this section. 

* * * * * 

(17) A public utility granted blanket 

authorization under paragraph (c)(12)(ii) 

of this section to transfer its outstanding 

voting securities shall, within 30 days 

after the end of the calendar quarter in 

which such transfer has occurred, file 

with the Commission a report 

containing the following information: 

(i) The names of all parties to the 

transaction; 

(ii) Identification of the pre- and posttransaction voting security holdings 

(and percentage ownership) in the 

public utility held by the acquirer and 

its associate or affilate companies; 

(iii) The date the transaction was 

consummated; 

(iv) Identification of any public utility 

or holding company affiliates of the 

parties to the transaction; and 

(v) A statement indicating that the 

proposed transaction will not result in, 

at the time of the transaction or in the 

future, cross-subsidization of a nonutility associate company or pledge or 

encumbrance of utility assets for the 

benefit of an associate company as 

required in § 33.2(j)(1). 

[FR Doc. E9–12381 Filed 5–27–09; 8:45 am] 

BILLING CODE 6717–01–P 

DEPARTMENT OF ENERGY 

Federal Energy Regulatory 

Commission 

18 CFR Part 40 

[Docket No. RM08–16–000; Order No. 724] 

Electric Reliability Organization 

Interpretations of Specific 

Requirements of Frequency Response 

and Bias and Voltage and Reactive 

Control Reliability Standards 

Issued May 21, 2009. 

AGENCY: Federal Energy Regulatory 

Commission, DOE. 

ACTION: Final rule. 

SUMMARY: Pursuant to section 215 of the 

Federal Power Act, the Federal Energy 

Regulatory Commission hereby 

approves the North American Electric 

Reliability Corporation’s (NERC) 

interpretation of one CommissionVerDate Nov<24>2008 16:39 May 27, 2009 Jkt 217001 PO 00000 Frm 00027 Fmt 4700 Sfmt 4700 E:\FR\FM\28MYR1.SGM 28MYR1
25414 Federal Register / Vol. 74, No. 101 / Thursday, May 28, 2009 / Rules and Regulations 

1 16 U.S.C. 8240 (2006). The Commission is not 

adding any new or modified text to its regulations. 

2See 16 U.S.C. 824o(e)(3). 

3Rules 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). 

4North American Electric Reliability Corp., 116 

FERC ¶ 61,062, order on reh’g & compliance, 117 

FERC ¶ 61,126 (2006), appeal docketed sub nom. 

Alcoa, Inc. v. FERC, Case No. 06–1426 (DC Cir. Dec. 

29, 2006). 

5 Mandatory Reliability Standards for the BulkPower System, Order No. 693, FERC Stats. & Regs. 

¶ 31,242, order on reh’g, Order No. 693–A, 120 

FERC ¶ 61,053 (2007). 

6 16 U.S.C. 824o(d)(5). 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.’’ 

7NERC Rules of Procedure, Appendix 3A, 

Reliability Standards Development Procedure, 

Version 6.1, at 26–27 (2007). 

8The NERC board of trustees approves Reliability 

Standard interpretations once they are posted and 

presented for adoption. Id. at 23–24, 26–27. 

9See NERC’s Rules of Procedures, Appendix 3A. 

10NERC Petition at 3. 

11Electric Reliability Organization Interpretations 

of Specific Requirements of Frequency Response 

and Bias and Voltage and Reactive Control 

Reliability Standards, Notice of Proposed 

Rulemaking, 73 FR 71971 (Nov. 26, 2008), FERC 

Stats. & Regs. ¶ 32,639 (2008) (NOPR). 

12The IESO administers wholesale electricity 

markets and operates the integrated power system 

in Ontario, Canada and is subject to oversight by the 

Ontario Energy Board. 

approved Reliability Standard, BAL– 

003–0, Frequency Response and Bias; 

and remands NERC’s proposed 

interpretation of VAR–001–1, Voltage 

and Reactive Control, for 

reconsideration consistent with this 

Final Rule. 

DATES: Effective Date: The Final Rule 

will become effective June 29, 2009. 

FOR FURTHER INFORMATION CONTACT: 

Patrick Harwood (Technical 

Information), Office of Electric 

Reliability, Federal Energy Regulatory 

Commission, 888 First Street, NE., 

Washington, DC 20426, Telephone: 

(202) 502–6125, 

Patrick.harwood@ferc.gov. 

Richard M. Wartchow (Legal 

Information), Office of the General 

Counsel, Federal Energy Regulatory 

Commission, 888 First Street, NE., 

Washington, DC 20426, Telephone: 

(202) 502–8744. 

SUPPLEMENTARY INFORMATION: Before 

Commissioners: Jon Wellinghoff, 

Chairman; Suedeen G. Kelly, Marc 

Spitzer, and Philip D. Moeller. 

Final Rule 

Issued May 21, 2009 

1. Pursuant to section 215 of the 

Federal Power Act (FPA), the 

Commission hereby approves the 

interpretation proposed by the North 

American Electric Reliability 

Corporation (NERC) of Commissionapproved Reliability Standard BAL– 

003–0, Frequency Response and Bias, 

but remands NERC’s proposed 

interpretation of Reliability Standard 

VAR–001–1, Voltage and Reactive 

Control, for additional clarification.1

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.2

3. Pursuant to section 215 of the FPA, 

the Commission established a process to 

select and certify an ERO 3 and, 

subsequently, certified NERC as the 

ERO.4 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.5

In addition, pursuant to section 

215(d)(5) of the FPA, the Commission 

directed NERC to develop modifications 

to 56 of the 83 approved Reliability 

Standards.6

4. 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.7

In response to a request, the ERO’s 

standards process manager assembles a 

team with relevant expertise to address 

the requested interpretation and forms 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 Reliability Standard 

and filed with the applicable regulatory 

authority for approval.8

B. NERC Filing 

5. On July 28, 2008, NERC submitted 

a Petition for Approval of Formal 

Interpretations to Reliability Standards 

(Petition), seeking Commission approval 

of interpretations of BAL–003–0, 

Requirements R2 and R5; and VAR– 

001–1, Requirement R4. 

6. For BAL–003–0, the Electric 

Reliability Council of Texas (ERCOT) 

requested clarification that the 

provision in BAL–003–0, Requirement 

R2, permitting use of a variable bias 

setting, did not conflict with BAL–003– 

0, Requirement R5, which states that the 

frequency bias setting for Balancing 

Authorities serving native load should 

be at least one percent of yearly peak 

demand. For VAR–001–1, Dynegy, Inc. 

(Dynegy) requested clarification 

whether there are implicit requirements 

that the voltage schedule and associated 

tolerance band to be provided by the 

transmission operator under 

Requirement R4 be technically based, 

reasonable and practical for a generator 

to maintain. 

7. Consistent with the NERC Rules of 

Procedure, a NERC-assembled ballot 

body, consisting of industry 

stakeholders, developed the 

interpretations using the NERC 

Reliability Standards Development 

Procedure,9 and the NERC Board of 

Trustees approved the interpretations.10

The interpretations do not modify the 

language contained in the requirements 

under review. NERC requested the 

Commission to approve the 

interpretations, effective immediately 

after approval, consistent with the 

Commission’s procedures. 

C. NOPR 

8. In Response, the Commission 

issued a Notice of Proposed Rulemaking 

and proposed to approve the ERO’s 

formal interpretation of Requirements 

R2 and R5 of BAL–003–0 but remand 

the proposed interpretation of VAR– 

001–1, and requested comment on its 

proposals.11

II. Discussion 

A. Procedural Matters 

9. NERC, Ameren Services Co. 

(Ameren), Edison Electric Institute 

(EEI), FirstEnergy Service Co. 

(FirstEnergy) and The Independent 

Electricity System Operator of Ontario 

(IESO) 12 filed comments, largely 

addressing the Commission’s proposal 

to remand the proposed interpretation 

of VAR–001–1. 

B. BAL–003–0 

1. NOPR Proposal 

10. BAL–003–0, Requirement 2 states 

that a ‘‘Balancing Authority shall 

establish and maintain a Frequency Bias 

Setting that is as close as practical to, or 

greater than, the Balancing Authority’s 

Frequency Response.’’ BAL–003–0, 

Federal Register / Vol. 74, No. 101 / Thursday, May 28, 2009 / Rules and Regulations 25415 

13A frequency bias setting is a value expressed 

in MW per 0.1 Hz, set into a balancing authority’s 

ACE algorithm, which allows the balancing 

authority to contribute its frequency response to the 

Interconnection. NERC’s glossary, which provides 

definitions of the relevant terms, defines ACE as 

‘‘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.’’ 

14NOPR, FERC Stats. & Regs. ¶ 32,639 at P 17; 

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

370 (addressing the suggestion that Requirement R5 

should be required in lieu of Requirement R2 for 

certain balancing authorities and finding that 

Requirements R2 and R5 do not conflict); BAL– 

003–0, Requirement R5. 

15See id. P 362, 370. 

16NOPR, FERC Stats. & Regs. ¶ 32,639 at P 16, 18. 

17 Id. P 18 n.19. 

18Order No. 693, FERC Stats. & Regs. ¶ 31,242 at 

P 370 (emphasizing the need to follow both 

Requirements R2 and R5). 

19The voltage schedule is a target voltage to be 

maintained within a tolerance band during a 

specified period. [Footnote in original.] 

20When a Generator is operating in manual 

control, reactive power capability may change 

based on stability considerations and this will lead 

to a change in the associate Facility Ratings. 

[Footnote in original.] 

Requirement 5 states that ‘‘Balancing 

Authorities that serve native load [such 

as ERCOT] shall have a monthly average 

Frequency Bias Setting that is at least 

one percent of the Balancing Authority’s 

estimated yearly peak demand per 0.1 

Hz change.’’ ERCOT requested 

clarification whether there is a conflict 

between BAL–003–0, Requirement R2, 

and BAL–003–0, Requirement R5. In 

response, NERC proposed the following 

interpretation: 

Frequency Response and Bias Requirement 

2 requires a Balancing Authority to analyze 

its response to frequency excursions as a first 

step in determining its frequency bias setting. 

The Balancing Authority may then choose a 

fixed bias (constant through the year) per 

Requirement 2.1, or a variable bias (varies 

with load, specific generators, etc.) per 

Requirement 2.2. 

Frequency Response and Bias Requirement 

5 sets a minimum contribution for all 

Balancing Authorities toward stabilizing 

interconnection frequency. The 1% bias 

setting establishes a minimum level of 

automatic generation control action to help 

stabilize frequency following a disturbance. 

By setting a floor on bias, Requirement 5 also 

helps ensure a consistent measure of control 

performance among all Balancing Authorities 

within a multi-Balancing Authority 

interconnection. However, ERCOT is a single 

Balancing Authority interconnection. The 

bias settings ERCOT uses do produce, on 

average, the best level of automatic 

generation control action to meet control 

performance metrics. The bias value in a 

single Balancing Authority interconnection 

does not impact the measure of control 

performance. 

11. In the NOPR, the Commission 

proposed to find NERC’s interpretation 

of BAL–003–0, Requirements R2 and R5 

to be reasonable in providing 

consistency in frequency bias setting 

determinations, used in area control 

error (ACE) calculations.13 The 

Commission viewed the interpretation 

as consistent with an earlier, Order No. 

693 finding that the requirements of 

BAL–003–0 do not conflict with one 

another.14 In Order No. 693, the 

Commission found that Requirement R2 

provides the relationship between 

frequency response and frequency bias, 

with frequency bias to be as close as 

practical to, or greater than, the 

balancing authority’s frequency 

response. Requirements R5 and R5.1 

require balancing authorities to 

establish frequency bias settings based 

on one percent of peak demand or 

maximum generation level, based on 

individual circumstances.15

12. The Commission proposed to 

approve the interpretation, since the 

BAL–003–0, Requirement R5 minimum 

bias setting establishes a consistent 

methodology for an ACE determination 

input, and ensures that an adequate 

level of generation is set aside to 

provide frequency response.16 The 

Commission declined to address the 

issue whether the ERCOT methodology, 

reported to result in ‘‘the best level of 

automatic generation control action to 

meet control performance metrics,’’ may 

be a preferable methodology, noting that 

such an issue is better resolved through 

a proceeding to review a proposal to 

permit ERCOT to depart from the 

requirement. The Commission noted 

that while ERCOT is a single-balancingauthority Interconnection and, 

therefore, does not need to allocate 

automatic generation control 

responsibility among multiple balancing 

authorities within the Interconnection, 

the other justifications for Requirement 

R5, supporting a consistent ACE 

calculation methodology and providing 

a minimum standard for reliability, 

remain valid justifications for the 

minimum setting.17

2. Comments 

13. No participant filed comments 

opposing the BAL–003–0 interpretation. 

3. Commission Determination 

14. The ERO’s interpretation clarifies 

that the BAL–003–0 Requirements R2 

and R5 do not conflict with one another. 

In Order No. 693, the Commission made 

clear that a frequency bias setting based 

only on the value set forth in 

Requirement R5 is insufficient and that 

a balancing authority must also follow 

Requirement R2.18 ERCOT presents the 

reverse question, whether a balancing 

authority that follows the variable bias 

setting under Requirement R2 must also 

follow Requirement R5. In response, 

NERC’s interpretation affirms that a 

balancing authority that uses the 

variable bias option provided under 

Requirement R2 must also follow 

Requirement R5. In addition, no 

comments were filed opposing the 

Commission’s proposal to approve 

NERC’s BAL–003–0 interpretation. 

15. Accordingly, we approve NERC’s 

BAL–003–0 interpretation. The 

Commission finds that the ERO’s 

interpretation is just, reasonable, not 

unduly discriminatory or preferential, 

and in the public interest. 

C. VAR–001–1 

1. NOPR Proposal 

16. VAR–001–1, Requirement R4 

directs each transmission operator to 

provide each generator with a voltage 

and reactive power output schedule, 

within a tolerance band. A second 

Reliability Standard, VAR–002–1, 

Requirement R2, requires that each 

generator must meet the schedule 

(typically via automatic control) or 

provide an explanation why it cannot 

do so. The Requirements state: 

VAR–001–1—Voltage and Reactive 

Control. 

Requirement R4. Each Transmission 

Operator shall specify a voltage or Reactive 

Power schedule 19 at the interconnection 

between the generator facility and the 

Transmission Owner’s facilities to be 

maintained by each generator. The 

Transmission Operator shall provide the 

voltage or Reactive Power schedule to the 

associated Generator Operator and direct the 

Generator Operator to comply with the 

schedule in automatic voltage control mode 

(AVR [automatic voltage regulation] in 

service and controlling voltage). * * * 

VAR–002–1—Generator Operation for 

Maintaining Network Voltage Schedules. 

Requirement R2. Unless exempted by the 

Transmission Operator, each Generator 

Operator shall maintain the generator voltage 

or Reactive Power output (within applicable 

Facility Ratings) 20 as directed by the 

Transmission Operator. 

R2.1. When a generator’s automatic voltage 

regulator is out of service, the Generator 

Operator shall use an alternative method to 

control the generator voltage and reactive 

output to meet the voltage or Reactive Power 

schedule directed by the Transmission 

Operator. 

R2.2. When directed to modify voltage, the 

Generator Operator shall comply or provide 

an explanation of why the schedule cannot 

be met. 

17. Dynegy requested clarification 

whether there are implicit requirements 

that the voltage schedule and associated 

tolerance band to be provided by the 

transmission operator under VAR–001– 

1, Requirement R4 be technically based, 

25416 Federal Register / Vol. 74, No. 101 / Thursday, May 28, 2009 / Rules and Regulations 

21NERC Petition at 14. 

22Order No. 693, FERC Stats. & Regs. ¶ 31,242 at 

P 5 (‘‘[A] Reliability Standard must provide for the 

Reliable Operation of Bulk-Power System facilities 

and 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 Reliability Standard should be clear and 

unambiguous regarding what is required and who 

is required to comply. The possible consequences 

for violating a Reliability Standard should be clear 

and understandable to those who must comply. 

There should be clear criteria for whether an entity 

is in compliance with a Reliability Standard. While 

a Reliability Standard does not necessarily need to 

reflect the optimal method for achieving its 

reliability goal, a Reliability Standard should 

achieve its reliability goal effectively and 

efficiently.’’); see also Order No. 672, FERC Stats. 

& Regs. ¶ 31,204 at P 324. 

23NOPR, FERC Stats. & Regs. ¶ 32,639 at P 30 

(citing Order No. 693 at P 5). 

24See Order No. 693, FERC Stats. & Regs. 

¶ 31,242 at P 274. In reviewing specific Reliability 

Standards, the Commission identified for certain 

Reliability Standards implicit obligations that 

should be incorporated into those Reliability 

Standards and directed NERC to revise the 

standards to explicitly incorporate the obligations; 

see Mandatory Reliability Standards for Critical 

Infrastructure Protection, Order No. 706, 122 FERC 

¶ 61,040, at P 75 (2008) (directing the ERO to 

modify the CIP Reliability Standards to incorporate 

an obligation to implement plans, policies and 

procedures); Order No. 693 at P 1787 (‘‘In the 

NOPR, the Commission identified an implicit 

assumption in the TPL Reliability Standards that all 

generators are required to ride through the same 

types of voltage disturbances and remain in service 

after the fault is cleared. This implicit assumption 

should be made explicit.’’); Facilities Design, 

Connections and Maintenance Reliability 

Standards, Order No. 705, 121 FERC ¶ 61,296, at P 

54 (2007) (‘‘although the TPL Reliability Standards 

implicitly require the loss of a shunt device to be 

addressed, they do not do so explicitly’’). 

25Order No. 693, FERC Stats. & Regs. ¶ 31,242 at 

P 275. 

26As noted above, Reliability Standards should 

reflect sound engineering principles. See id. P 5; 

Order No. 672, FERC Stats. & Regs. ¶ 31,204 at P 

324; accord NERC Rules of Procedure, section 

302.5. 

27See, e.g., IESO comments at 5 (‘‘The IESO 

agrees with the Commission that standards should 

be technically sound’’). 

28See NERC comments at 5 (each requirement 

contributes to meeting a Reliability Standard 

objective; other Reliability Standards require the 

technical basis to be established for voltage 

schedules); Ameren comments at 5 (users, owners 

and operators must act in a technically sound 

manner in compliance with VAR–001–1, 

Requirement R4); EEI comments at 2 (however, EEI 

states that a transmission operator cannot be 

audited on the ‘‘subjective interpretation’’ that a 

voltage schedule be technically sound, because 

there are no associated compliance measures); 

reasonable and practical for a generator 

to maintain. In response, NERC 

proposed the following interpretation: 

NERC Reliability Standard VAR–001–1 is 

only comprised of stated requirements and 

associated compliance elements. The 

requirements have been developed in a fair 

and open process, balloted and accepted by 

FERC for compliance review. Any ‘‘implicit’’ 

requirement would be based on subjective 

interpretation and viewpoint and therefore 

cannot be objectively measured and enforced. 

Any attempt at ‘‘interpreting an implicit 

requirement’’ would effectively be adding a 

new requirement to the standard. 

This can only be done through the 

[Standards Authorization Request] process. 

Since there are no requirements in VAR– 

001–1 to issue a ‘‘technically based, 

reasonable and practical to maintain voltage 

or reactive power schedule and associated 

tolerance band,’’ there are no measures or 

associated compliance elements in the 

standard. 

The standard only requires that ‘‘Each 

Transmission Operator shall specify a voltage 

or Reactive Power schedule. * * *’’ and that 

‘‘The Transmission Operator shall provide 

the voltage or Reactive Power schedule to the 

associated Generator Operator and direct the 

Generator Operator to comply with the 

schedule. * * *’’ Also, Measure 1 and the 

associated compliance elements follow 

accordingly by stating that ‘‘The 

Transmission Operator shall have evidence it 

provided a voltage or Reactive Power 

schedule * * *’’ 

* * * * * 

Requirement 2 and Requirement 2.2 of 

VAR–002–1 relate somewhat to questions #2 

and 3. R2 states that ‘‘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.’’ R2.2 goes on to state 

‘‘When directed to modify voltage, the 

Generator Operator shall comply or provide 

an explanation of why the schedule cannot 

be met.’’ [footnotes omitted.] 

18. NERC provided additional 

information in its transmittal letter 

accompanying the interpretation, noting 

that VAR–001–1, Requirement R2 states, 

‘‘Each Transmission Operator shall 

acquire sufficient reactive resources 

within its area to protect the voltage 

levels under normal and Contingency 

conditions.’’ NERC explained that, in 

order to fulfill Requirement R2, the 

transmission operator must perform a 

valid analysis of the system, using 

models that accurately represent 

equipment capabilities. Therefore, while 

NERC supported its interpretation of 

Requirement R4, including the finding 

that a requirement cannot establish 

implicit obligations, it stated that the 

issue that Dynegy raised for clarification 

is better resolved through an 

examination of Requirement R2.21

19. In response, the Commission 

proposed to remand NERC’s 

interpretation of VAR–001–1, 

Requirement R4, because the 

interpretation suggested that there is no 

requirement that a voltage schedule 

have a sound technical basis. The 

Commission noted that Order No. 693 

stated that all Reliability Standards 

must be designed to achieve a specified 

reliability goal and must contain a 

technically sound means to achieve this 

goal.22 The Commission thus disagreed 

with NERC’s proposed interpretation 

because it suggested that a transmission 

operator could deliver a voltage 

schedule that lacked any technical 

basis. The Commission, citing the NERC 

Rules of Procedure, section 302.5, 

concluded that a voltage schedule 

should reflect technical analysis, i.e., 

sound engineering, as well as operating 

judgment and experience.23

20. The NOPR also highlighted the 

Commission’s review in Order No. 693 

of each Reliability Standard and 

approval of those containing 

Requirements that are sufficiently clear 

as to be enforceable and that do not 

create due process concerns.24 The 

Commission noted that its approval in 

Order No. 693 of VAR–001–1 meant that 

VAR–001–1 is sufficiently clear to 

inform transmission operators what is 

required of them.25 The Commission 

acknowledged that it has elsewhere 

declined to specify in detail how a 

registered entity should implement a 

Reliability Standard, but countered that 

such actions do not mean that an entity 

seeking to comply with a Reliability 

Standard may act in a manner that is not 

technically sound, i.e., in a manner that 

is not grounded in sound engineering, 

and thus, not reasonable and practical.26

The Commission objected to NERC’s 

proposed interpretation as implying that 

the voltage schedules provided under 

VAR–001–1, Requirement R4 need not 

have any technical basis, and thus need 

not be reasonable and practical. 

21. The Commission proposed in the 

NOPR to remand NERC’s proposed 

interpretation of VAR–001–1, 

Requirement R4 for reconsideration 

consistent with this rulemaking. In 

addition, the Commission rejected an 

additional proposal from Dynegy, 

asserting that NERC needs to develop 

evaluation measures to review the 

technical basis for voltage schedules, as 

beyond the scope of the interpretation 

process. The Commission proposed that 

such an effort would be better discussed 

pursuant to a Standards Authorization 

Request under the NERC Reliability 

Standards Development Procedures. 

2. Comments 

a. VAR–001–1, Requirement R4 

Technical Basis 

22. No participant contests the 

Commission’s determination that all 

Reliability Standards must be designed 

to achieve a specified reliability goal 

and must contain a technically sound 

means to achieve this goal.27 The 

parties, as discussed below, also largely 

agree or acknowledge that voltage 

schedules must have a technical basis.28

Federal Register / Vol. 74, No. 101 / Thursday, May 28, 2009 / Rules and Regulations 25417 

FirstEnergy comments at 6 (noting that VAR–001– 

1 avoids overly prescriptive language defining the 

correct technical basis). IESO argues that other 

Reliability Standards require sound engineering 

principals and technical expertise, in order to meet 

reliability objectives and obligations, and that these 

Reliability Standards ‘‘supplement’’ the VAR–001– 

1 Reliability Standard. IESO comments at 5–6. 

29FirstEnergy comments at 5. See also Ameren 

comments at 9 (comparing current proposal to 

directives in Order No. 693, FERC Stats. & Regs. 

¶ 31,242 at P 1880, to address clarifying changes 

through the Reliability Standards development 

process); IESO comments at 5 (perceived 

deficiencies in the Reliability Standard should be 

addressed in the Reliability Standards development 

process). 

30FirstEnergy comments at 6. 

31See NERC comments at 5, 9; Ameren comments 

at 6–9; IESO comments at 1–2, 3. 

32EEI comments at 3–4. 

33 Id. at 2. 

34 Id. at 3 (citing Order No. 693, FERC Stats. & 

Regs. ¶ 31,242 at P 1868). 

35Ameren comments at 10 (citing NOPR, FERC 

Stats. & Regs. ¶ 32,639 at P 32). 

36 Id. at 7, 10. 

37NERC comments at 5–6. 

38 Id. at 6–7. NERC lists Requirement R2 

(discussing reactive sufficiency), Requirement R8 

(requiring a transmission operator to operate 

reactive resources to maintain system voltage 

limits), Requirement R9 (requiring transmission 

operators to address reactive support under first 

contingency conditions), Requirement R10 

(addressing system operating limit (SOL) and 

interconnection reliability operating limit (IROL) 

violations), Requirement R11 (providing for 

transformer tap settings) and Requirement R12 

(directing a transmission operator to take 

preemptive action to prevent voltage collapse). 

39 Id. at 7. 

40 Id. at 7–8. 

41 Id. at 9–10. 

42 Id. at 9. 

23. FirstEnergy supports the 

Commission’s proposal to remand 

NERC’s interpretation for further 

consideration because NERC’s proposed 

interpretation suggests that voltage 

schedules could lack a technical basis. 

However, FirstEnergy interprets the 

Commission’s proposal in the NOPR as 

finding that there are ‘‘implicit’’ 

obligations in VAR–001–1, Requirement 

R4 that instead should be explicitly 

incorporated in the Reliability 

Standards. Therefore, FirstEnergy 

supports a remand, but states that the 

remand should incorporate a directive 

to consider evaluation measures and 

review the technical basis for voltage 

schedules pursuant to a Standards 

Authorization Request under the NERC 

Reliability Standards development 

process.29

24. According to FirstEnergy, 

Requirement R4 is correctly written to 

avoid overly prescriptive language as to 

what constitutes the correct technical 

basis, since the determination of voltage 

schedules is unique to individual 

transmission systems.30

25. Despite acknowledging that the 

voltage schedules must have a technical 

basis, some participants object to the 

Commission’s proposal to remand the 

interpretation in order that NERC may 

reflect that fact in the interpretation, 

solely because the requirement is not 

explicit, that is, not stated directly in 

the Reliability Standard and supported 

by compliance measures.31 EEI supports 

remand for the limited purpose to 

incorporate supporting material from 

NERC’s pleadings and a reference to the 

Order No. 693 discussion that prompted 

the Commission’s concern.32 However, 

EEI states that this material would not 

reflect an auditable requirement that 

voltage schedules be technically sound, 

due to the lack of measures and 

compliance elements.33 According to 

EEI, the issue raised in Dynegy’s 

interpretation request was resolved in 

Order No. 693 when the Commission 

addressed requests that the Commission 

direct NERC to modify VAR–001–1 to 

include detailed and definitive 

requirements on established limits and 

sufficient reactive resources and 

identify acceptable voltage margins.34

Therefore, EEI views Dynegy’s request 

as an attempt to circumvent the 

Reliability Standard development 

process. 

26. Ameren characterizes the 

Commission’s proposed remand as 

effectively creating a new requirement 

outside the approved procedures, and 

suggests that the appropriate procedure 

is to initiate a Standards Authorization 

Request. Ameren cites the Commission’s 

rejecting Dynegy’s proposed evaluation 

measures as supporting its position.35

Ameren characterizes the Commission’s 

proposal as resulting in an 

interpretation that would implement a 

requirement that is not understood to be 

part of the Reliability Standard, and 

cites the NERC balloting as evidence 

that the industry does not agree with the 

position that there is an implicit 

requirement.36

b. Technical Basis in Other Reliability 

Standard Requirements 

27. Several participants claim that, 

while the scope of VAR–001–1, 

Requirement R4 is limited, other 

requirements create obligations which 

lead to technically sound voltage 

schedules or compliance with VAR– 

001–1. According to NERC, each of the 

requirements in VAR–001–1 contributes 

to meeting the stated objective of the 

Reliability Standard, and it is the 

combination of requirements that 

provides a technically sound method to 

achieve the purpose of VAR–001–1. 

NERC states that, although Requirement 

R4 does not explicitly require a voltage 

schedule that is technically based, 

reasonable and practical, ‘‘other 

requirements in VAR–001–1 do require 

the technical basis to be established.’’37

NERC concludes that ‘‘as a whole’’ 

VAR–001–1 is technically sound. 

28. NERC cites Requirements R2 and 

R8 through R12 as requiring a 

transmission operator to have a 

defensible technical basis to achieve the 

purpose of VAR–001–1.38 NERC states 

that these requirements direct a 

transmission operator to understand 

system dynamics to maintain voltage 

sufficiency and stability under normal 

and contingency conditions. According 

to NERC, to maintain the system within 

limits in real-time and to avoid voltage 

collapse in the operating time horizon, 

a transmission operator must study the 

system on a first contingency basis and 

must ‘‘position the voltage and reactive 

profile of the system appropriately, 

including the voltage [schedules] 

provided to generator operators.’’ 39

NERC continues, indicating that a 

transmission operator possesses 

valuable insight into reactive ‘‘weak 

spots’’ where additional reactive 

support would be beneficial to help it 

achieve the performance expectations 

outlined in VAR–001–1.40

29. NERC also summarizes various 

planning actions that a transmission 

operator must take with respect to 

voltage support. NERC states that, to 

meet the planning obligations embodied 

in VAR–001–1, Requirements R2, R9.1 

and R11, a transmission operator must 

rely on long-range and seasonal studies 

provided by the transmission planner. 

According to NERC, a combination of 

planning and operations analysis and 

feedback provides the technical 

foundation for voltage schedules to be 

maintained at buses across the 

transmission system, including 

generator buses. NERC concludes that 

‘‘there must be a technical basis for’’ the 

voltage schedule provided for in 

Requirement R4.41

30. To remedy the perceived 

disconnect, NERC suggests that the 

interpretation could be improved by 

stating that it is VAR–001–1, 

Requirement R4 that lacks an explicit 

requirement for a technically-based, 

reasonable, and practical voltage 

schedule, and ‘‘not the entire VAR–001– 

1 standard.’’42

31. EEI also indicates that, even 

though not part of the interpretation, the 

additional information in NERC’s filing 

demonstrates that the requirements in 

VAR–001 are based on sound 

engineering principles, but because it is 

25418 Federal Register / Vol. 74, No. 101 / Thursday, May 28, 2009 / Rules and Regulations 

43EEI comments at 2. 

44Ameren comments at 6 (citing NERC Petition, 

Exhibit B–1 at 2; NOPR, FERC Stats. & Regs. 

¶ 32,639 at P 31 (proposing remand and rejecting 

Dynegy request for the development of compliance 

measures as beyond the scope of an interpretation 

proceeding)). 

45 Id. at 6 (citing NERC Petition, Transmittal 

Letter at 12–13 and VAR–001–1a as providing that 

‘‘each Generator Operator shall maintain the 

generator voltage or Reactive Power output (within 

applicable Facility Ratings[]) as directed by the 

Transmission Operator’’ and Requirement R2.2 as 

providing that ‘‘the Generator Operator shall 

comply or provide an explanation of why the 

schedule cannot be met’’). 

46 Id. at 7 (citing Order No. 693, FERC Stats. & 

Regs. ¶31,242 at P 5, as explaining that ‘‘a 

Reliability Standard does not necessarily need to 

reflect the optimal method for achieving its 

reliability goal, [but] a Reliability Standard should 

achieve its reliability goal effectively and 

efficiently,’’ and should be ‘‘sufficient to adequately 

protect Bulk-Power System reliability’’). 

47FirstEnergy comments at 8. 

48 IESO comments at 5. 

49 Id. at 6 (citing NOPR, FERC Stats. & Regs. 

¶ 32,639 at P 30). 

50EEI comments at 2. 

51Ameren comments at 5–6 (citing NERC 

Petition, Exhibit B–1 and Dynegy Oct. 11, 2007 

request for interpretation as stating: ‘‘Requirement 

4 does not impose any explicit obligations on the 

Transmission Operator other than to provide the 

Generator Operator with a voltage or reactive power 

output schedule and an associated tolerance 

band.’’). 

52Ameren comments at 8 (citing NERC Petition 

at 11; NERC proposed VAR–001–1 interpretation at 

1). 

53 Id. at 7 (citing Order No. 672, FERC Stats. & 

Regs. ¶ 31,204 at P 324, 327: 

The proposed Reliability Standard must be 

designed to achieve a specified reliability goal and 

must contain a technically sound means to achieve 

this goal. Although any person may propose a topic 

for a Reliability Standard to the ERO, in the ERO’s 

process, the specific proposed Reliability Standard 

should be developed initially by persons within the 

electric power industry and community with a high 

level of technical expertise and be based on sound 

technical and engineering criteria. It should be 

based on actual data and lessons learned from past 

operating incidents, where appropriate. The process 

for ERO approval of a proposed Reliability Standard 

should be fair and open to all interested persons. 

* * * 

There should be a clear criterion or measure of 

whether an entity is in compliance with a proposed 

Reliability Standard. It should contain or be 

accompanied by an objective measure of 

compliance so that it can be enforced and so that 

enforcement can be applied in a consistent and 

non-preferential manner. 

not in NERC’s official interpretation, a 

remand may be warranted.43

32. Ameren states that review of 

VAR–002–1a can answer Dynegy’s 

concerns regarding the ‘‘reasonable and 

practical’’ generator voltage schedule. 

According to Ameren, the interpretation 

would not permit unsound practices or 

practices that threaten system 

reliability, but instead points to VAR– 

002–1, Requirement R2 as establishing 

procedures that accommodate ‘‘actual 

generator capabilities’’ and ‘‘the 

transmission operator’s need to 

maintain voltage schedules.’’44 Ameren 

states that the interpretation addresses 

concerns whether a voltage schedule 

must accommodate ‘‘reasonable’’ and 

‘‘practical’’ generator capabilities by 

reference to VAR–002–1a, the 

Reliability Standard that addresses the 

generators’ obligations.45

33. Ameren states that Reliability 

Standards VAR–001 and VAR–002, 

taken together, support a technically 

sound purpose of providing for safe and 

reliable Reactive Power and voltage 

control, as required by Order No. 693. 

Ameren asserts that these Reliability 

Standards as written and interpreted are 

sufficient to protect electric reliability.46

34. According to FirstEnergy, both 

transmission operators and generator 

operators are responsible to confirm the 

technical basis for a voltage schedule. 

FirstEnergy continues, explaining that 

the stated purpose of VAR–001–1 

provides the basis for Requirement R4, 

which requires a transmission operator 

to provide a technically sound voltage 

schedule that provides sufficient 

reactive support and respects bulk 

electric system facility ratings. Failure 

to do so, FirstEnergy submits, could 

adversely affect generator equipment 

and bulk electric system reliability. 

FirstEnergy states that VAR–002–1 

requires generators to provide reactive 

support to meet this obligation; 

FirstEnergy suggests that a generator 

that cannot fulfill that purpose based on 

the voltage schedule received must 

coordinate an acceptable voltage 

schedule with the transmission operator 

in order to meet the explicit 

requirements of VAR–002–1. 

35. FirstEnergy agrees with the 

Commission’s proposal rejecting 

Dynegy’s request for more detailed 

specification of the technical 

requirements of the VAR–001–1 

Reliability Standard, as beyond the 

scope of an interpretation proceeding. 

FirstEnergy claims that Dynegy’s 

suggestions are already being 

considered in Project 2008–01, pursuant 

to NERC’s 2009–11.47 Finally, 

FirstEnergy suggests that the addition of 

reliability coordinators as applicable 

entities would aid in mediating disputes 

between transmission operators and 

generator operators. 

36. According to IESO, numerous 

Reliability Standards supplement VAR– 

001–1 and ensure that transmission 

operators develop plans and procedures 

that provide for reliability.48 IESO states 

that transmission operators would not 

be able to provide for system reliability, 

prevent system operating limit or 

interconnection reliability operating 

limit violations, or prevent cascading 

outages if they do not employ sound 

engineering principles and technical 

expertise during the development of 

plans and procedures. 

37. IESO lists several Reliability 

Standards as supplementing VAR–001– 

1, including TOP–002–2, Requirement 

R2 (requiring operations plans); TOP– 

004–2, Requirement R6 (requiring 

transmission operators to develop 

policies for transmission reliability, 

including controlling voltage levels); 

TOP–008–1, Requirement R2 (requiring 

transmission operator to limit potential 

for IROL or SOL violations). In addition, 

IESO objects to the Commission’s view 

that NERC’s interpretation fails to 

recognize that a voltage schedule issued 

under VAR–001–1 should reflect 

technical analysis, including sound 

engineering and operating judgment and 

experience, by noting that planners are 

required to include system operating 

personnel in the planning process under 

TOP–002–2, Requirement R2.49

c. Enforceability 

38. EEI agrees with NERC that VAR– 

001–1 lacks an explicit requirement to 

issue a technically based, reasonable 

and practical voltage and reactive 

schedule and also lacks measures or 

associate compliance elements in the 

standard. Therefore, EEI concludes that 

a transmission operator cannot be 

audited on what EEI terms the 

‘‘subjective interpretation’’ that a 

voltage schedule must have a sound 

technical basis.50

39. According to Ameren, NERC’s 

proposal correctly recognizes that a 

Reliability Standard cannot establish 

obligations implicitly, but instead must 

have stated obligations that can be 

objectively measured. Ameren states 

that nothing in VAR–001–1 specifies a 

technical basis for the transmission 

operator’s voltage schedule and 

tolerance band or requires a 

transmission operator to issue its 

supporting methodology, as Dynegy 

proposed.51 IESO agrees with NERC that 

an implied requirement is not a stated 

requirement that can be objectively 

measured. 

40. Ameren states that, since there are 

no implicit requirements, there are no 

measurements of compliance. 

According to Ameren, the Reliability 

Standard and interpretations drafting 

teams explained that any implicit 

requirement is subjective, and could not 

be objectively measured and enforced.52

41. Ameren cites the Order No. 672 

factors for approving a Reliability 

Standard as mandatory and enforceable 

under the FPA.53 According to Ameren, 

an implied requirement, not contained 

Federal Register / Vol. 74, No. 101 / Thursday, May 28, 2009 / Rules and Regulations 25419 

54Ameren comments at 8. 

55 Id. at 9. 

56Ameren comments at 10 (suggesting that 

remand may circumvent the Reliability Standards 

development procedure by adding new 

requirements to the standard violating the 

principles of due process and deference); 

FirstEnergy comments at 5. 

57EEI comments at 3. 

58Ameren comments at 2; EEI comments at 2; 

FirstEnergy comments at 5; IESO comments at 4. 

59Ameren comments at 10 (citing NERC Petition 

at Exhibit B–3 (results of the ballot body vote) and 

stating ‘‘Indeed, several members of the ballot pool 

for the VAR–001–1 interpretation indicated their 

belief that Dynegy’s request for an interpretation 

should have been filed as a Standards 

Authorization Request because the proposed change 

is so obviously beyond the scope of the current 

content of the Reliability Standard’’). 

60EEI comments at 4–5. 

61Order No. 693, FERC Stats. & Regs. ¶ 31,242 at 

P 5; see NOPR, FERC Stats. & Regs. ¶ 32,639 at P 

30. 

62See NERC comments at 5; Ameren comments 

at 5; EEI comments at 2; FirstEnergy comments at 

3–4; IESO comments at 2–3. 

63NOPR, FERC Stats. & Regs. ¶ 32,639 at P 30. 

64NERC comments at 5–6; EEI comments at 2 

(citing NERC petition at 12–14); FirstEnergy 

comments at 5–7; IESO comments at 5. See also 

Ameren comments at 6 (suggesting that procedures 

in VAR–002–1 would accommodate actual 

generator capabilities and not permit unsound 

practices under VAR–001–1, Requirement R4). 

in the language of the Reliability 

Standard itself, is ambiguous both as to 

what is required and what 

measurements will be used to determine 

compliance. Ameren concludes that 

such a requirement cannot be enforced 

fairly, and should not be made part of 

a mandatory Reliability Standard. 

42. Ameren states that disagreements 

may arise between transmission 

operators, NERC, generator operators 

and auditors over reasonableness of a 

technical basis or methodology or the 

practicality of a schedule.54 Ameren 

criticizes the proposed remand because 

it contains no instructions for how 

transmission operators could implement 

an implicit requirement.55 Ameren 

concludes that an implicit requirement 

is unacceptable and simply unworkable 

in the context of mandatory and 

enforceable electric Reliability 

Standards. 

d. Miscellaneous 

43. Some participants are concerned 

that this interpretation could 

circumvent NERC’s Standard 

development process or otherwise lacks 

due process.56 Ameren agrees with the 

Commission’s acknowledgement in the 

NOPR upholding NERC’s rejection of 

Dynegy’s proposed evaluation measures. 

Ameren states that NERC’s 

interpretation should be approved based 

on the results of the NERC ballot 

process. EEI states that the Commission 

provided an appropriate response in 

Order No. 693 by directing NERC to 

develop specific requirements for the 

issues addressed in the Final Rule 

through the NERC Reliability Standards 

development process, and questions 

whether Dynegy’s request concerning 

voltage schedules is an attempt to 

circumvent the Reliability Standards 

development process.57 These 

participants claim that interpretations 

that put new measures in place or 

would implement new requirements are 

beyond the scope of the interpretation 

process. 

44. Finally, participants reason that 

the Commission must rely on the 

judgment of the ERO in areas involving 

technical expertise relating to the 

content of the Reliability Standard and 

that, if Dynegy wishes to seek new 

material or measures to be added to the 

Reliability Standards, it must be 

handled through a Standards 

Authorization Request under the NERC 

Reliability Standards development 

process.58 Ameren states that the 

technical content of the interpretation is 

entitled to deference. Ameren claims 

that a remand of VAR–00l–l, 

Requirement R4 would add a new 

requirement to the Reliability Standard 

where the technical experts have 

acknowledged that one does not exist, 

without going through the required 

standards authorization process.59

Ameren states that such a revision 

would violate due process and 

demonstrate a lack of deference to the 

Reliability Standards development 

process. 

45. On a similar note, FirstEnergy and 

EEI both suggest that this interpretation 

request would add requirements to the 

VAR–001–1 Reliability Standard that 

are not otherwise required, and the 

proposed clarification would be more 

appropriately considered in the ongoing 

standards development proceedings. 

FirstEnergy states that changes to 

Reliability Standards to add more detail, 

such as the specific technical details 

sought by Dynegy, should be addressed 

in the ongoing Reliability Standards 

development process. 

46. EEI points out that Dynegy’s 

request raises several process issues. EEI 

claims that NERC’s narrow 

interpretation, that there are no implicit 

requirements with regard to the 

Reliability Standard’s technical validity, 

could suggest that the Reliability 

Standard itself is useless. On the other 

hand, EEI claims that if NERC indicated 

that there was an implicit requirement, 

such a requirement must be made 

explicit in this and every other 

Reliability Standard, potentially 

necessitating an overhaul of the entire 

collection of Reliability Standards.60 EEI 

also warns that the Commission and 

NERC should be careful not to allow a 

single entity to change a Reliability 

Standard via interpretations and that 

any such ‘‘backdoor’’ device should be 

avoided. 

3. Commission Determination 

47. The Commission remands to the 

ERO the proposed interpretation of 

VAR–001–1, Requirement R4 and 

directs the ERO to revise the 

interpretation consistent with the 

Commission’s discussion below. 

a. Voltage Schedules Provided Under 

VAR–001–1, Requirement R4 Must Have 

a Sound Technical Basis 

48. Order No. 693 held that all 

Reliability Standards must be designed 

to achieve a specified reliability goal 

and must contain a technically sound 

means to achieve the goal.61 No 

participant disagrees with this 

assessment.62 Furthermore, no 

participant challenges the Commission’s 

objection that the Reliability Standards 

should not permit delivery of a voltage 

schedule that lacks any technical 

basis.63 Instead, the participants suggest 

various ways in which other Reliability 

Standards requirements provide that 

technical basis or at least do not permit 

transmission operators to engage in 

unsound practices with respect to 

voltage schedules.64

49. VAR–001–1, Requirement R4 

requires each transmission operator to 

specify a voltage schedule to be 

maintained by each generator and 

explains that the voltage schedule is a 

target voltage to be maintained within a 

tolerance band during a specified 

period. Requirement R4 is part of the 

means by which a transmission operator 

achieves the goal of VAR–001–1, ‘‘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.’’ Because 

Requirement R4 requires transmission 

owners to specify target voltages at each 

generator’s interconnection with the 

system, while taking into account 

specific periods of use and facility 

tolerance bands, the Requirement is not 

merely a ministerial requirement, but, 

rather, presupposes the exercise of 

engineering judgment. These 

determinations are technical in nature, 

and, since they represent one of the 

means by which the VAR–001–1 

Reliability Standard achieves its goal, 

they must be technically sound, that is, 

based on sound engineering. Actions 

25420 Federal Register / Vol. 74, No. 101 / Thursday, May 28, 2009 / Rules and Regulations 

65NOPR, FERC Stats. & Regs. ¶ 32,639 at P 31. 

66Order No. 693, FERC Stats. & Regs. ¶ 31,242 at 

P 5 (‘‘a Reliability Standard must provide for the 

Reliable Operation of Bulk-Power System facilities 

and 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 Reliability Standard should be clear and 

unambiguous regarding what is required and who 

is required to comply. The possible consequences 

for violating a Reliability Standard should be clear 

and understandable to those who must comply. 

There should be clear criteria for whether an entity 

is in compliance with a Reliability Standard. While 

a Reliability Standard does not necessarily need to 

reflect the optimal method for achieving its 

reliability goal, a Reliability Standard should 

achieve its reliability goal effectively and 

efficiently’’); see also Order No. 672, FERC Stats. & 

Regs. ¶ 31,204 at P 324; accord NERC Rules of 

Procedure, section 302.5. 

67NERC comments at 8–9 (discussing VAR–001– 

1, Requirements R2, R9.1 and R11); Ameren 

comments at 6 (discussing VAR–002–1a, 

Requirement R2). See also EEI comments at 2 

(supporting NERC conclusion); IESO comments at 

6 (discussing transmission operations Reliability 

Standards, TOP–002–2, et al.). However, 

participants also suggest that a failure to meet that 

obligation would not constitute an enforceable 

violation of VAR–001–1, Requirement R4. See EEI 

comments at 2. 

68See Order No. 693, FERC Stats. & Regs. 

¶ 31,242 at P 274. 

69 Id. P 275. 

70 Id. P 1869. 

71NOPR, FERC Stats. & Regs. ¶ 32,639 at P 31; see 

also Order No. 672, FERC Stats. & Regs. ¶ 31,204 

at P 260 (stating that implementation procedures 

should be included when inextricably linked to the 

Reliability Standard or when leaving out 

implementation features could: (1) Sacrifice 

necessary uniformity in implementation of the 

Reliability Standard; (2) create uncertainty for the 

entity that has to follow the Reliability Standard; (3) 

make enforcement difficult; and (4) increase the 

complexity of the Commission’s oversight and 

review process). 

72Requirement R4 does not prescribe any one 

particular method of achieving compliance, but 

instead permits transmission operators to 

implement Reliability Standards through a variety 

of technically sound means. 

73Ameren comments at 8; EEI comments at 2; 

IESO comments at 3. 

74Order No. 693, FERC Stats. & Regs. ¶ 31,242 at 

P 253. 

75 Id. P 274–75 (‘‘the Commission finds that none 

of the Reliability Standards that we approve today 

that do not reflect sound engineering 

would not be technically sound.65

Therefore, the Commission adopts its 

NOPR proposal, and finds that a voltage 

schedule should reflect sound 

engineering, as well as operating 

judgment and experience.66 The 

Commission remands NERC’s proposed 

VAR–001–1, Requirement R4 

interpretation, in order that NERC may 

reconsider its interpretation consistent 

with this order. 

b. Whether Support for a Sound 

Technical Basis Is Found in Other 

Reliability Standards and Requirements 

50. Several participants, including 

NERC and Ameren, claim that, in the 

broader context of the Reliability 

Standards, there is already an obligation 

to use technically sound means to 

comply with VAR–001–1, Requirement 

R4.67 The Commission recognizes and 

appreciates, as part of the NERC filing, 

the additional information included to 

allay concerns that generator operators 

may receive a voltage schedule that is 

either unsafe or not technically feasible. 

However, if analysis of other Reliability 

Standard requirements provides the 

necessary clarification, such analysis 

should be made part of the formal 

interpretation. Thus, in this case, if the 

actions performed pursuant to other 

Reliability Standard requirements cited 

in the participants’ comments describe 

actions that form the basis for 

development of voltage schedules, then 

the interpretation should reflect that 

fact. 

51. Some petitioners suggest that 

other Reliability Standard requirements 

may mitigate any negative impact of a 

voltage schedule that lacks a sound 

technical basis, and thus imply that 

Requirement R4 need not reflect a 

sound technical basis, or they suggest 

that the clarification sought by the 

Commission is not necessary. The 

Commission does not agree. As 

discussed above, voltage schedules 

developed pursuant to VAR–001–1, 

Requirement R4 must have a sound 

technical basis, and failure to properly 

perform the task would constitute an 

independent violation of the Reliability 

Standard. 

c. The Commission Is Not Imposing 

Implicit Requirements 

52. The Commission disagrees with 

participants claiming that the 

Commission’s understanding of 

Requirement R4 would impermissibly 

create a new ‘‘implicit’’ requirement, or 

that such requirements would introduce 

an unworkable subjective analysis into 

Reliability Standard enforcement. As 

the NOPR stated, the Commission 

reviewed each Reliability Standard and, 

in Order No. 693, approved those 

containing Requirements that are 

sufficiently clear as to be enforceable 

and that do not create due process 

concerns.68 The Commission included 

VAR–001–1 as among the Reliability 

Standards that are sufficiently clear to 

inform transmission operators what is 

required of them.69 Order No. 693 

declined to order more specificity on 

the technical basis in the current 

version of VAR–001–1, but instead 

found that the development of more 

detailed requirements to address such 

concerns are best addressed by the ERO 

through the Reliability Standards 

development process.70 However, that 

finding does not suggest that existing 

requirements may be performed without 

any technical basis. 

53. FirstEnergy interprets the 

Commission’s proposal as finding that 

there are ‘‘implicit’’ obligations in 

Requirement R4 that should be 

explicitly incorporated into the 

Reliability Standard. To the contrary, as 

noted in the NOPR, the Commission has 

elsewhere declined to specify in detail 

how a registered entity should 

implement a Reliability Standard,71 and 

so we do not direct NERC to modify 

VAR–001–1, Requirement R4, at this 

time.72 The Commission affirms its 

approval in Order No. 693 of VAR–001– 

1, Requirement R4, and its finding that 

Requirement R4 is, as written, 

sufficiently clear to inform entities of 

what is required of them. 

d. Requirement R4 Is Mandatory and 

Enforceable 

54. Several participants claim that any 

requirement under VAR–001–1 to issue 

a technically based voltage schedule 

cannot be audited or enforced because 

VAR–001–1 lacks measures or 

compliance elements associated with 

such a requirement.73 We do not agree. 

In Order No. 693, the Commission 

approved Reliability Standards without 

associated measures, stating that it 

disagreed with comments that a 

Reliability Standard cannot reasonably 

be enforced, or is otherwise not just and 

reasonable, solely because it does not 

include enforcement measures and 

compliance elements. The Commission 

reasoned that while such compliance 

elements and enforcement measures 

provided useful guidance, ‘‘compliance 

will in all cases be measured by 

determining whether a party met or 

failed to meet the Requirement given the 

specific facts and circumstances of its 

use, ownership or operation of the BulkPower System.’’ 74

55. Ameren complains that a remand 

of the interpretation lacks specific 

instructions for transmission operators 

to implement an implicit Requirement. 

In addition, Ameren speculates that 

disagreements as to the sufficiency of a 

particular voltage schedule may arise 

between parties involved in 

implementation and enforcement. 

Again, the Commission affirms its 

finding in Order No. 693 that 

Requirement R4 is sufficiently clear; to 

be enforceable, Reliability Standards 

need not ‘‘spell out in minute detail all 

factual scenarios that might violate a 

Requirement and the precise 

consequences of that violation.’’ 75

Federal Register / Vol. 74, No. 101 / Thursday, May 28, 2009 / Rules and Regulations 25421 

contains an ambiguity that renders it unenforceable 

or otherwise unjust and unreasonable’’). 

76Order No. 672, FERC Stats. & Regs. ¶ 31,204 at 

P 324. 

77See Order No. 693, FERC Stats. & Regs. 

¶ 31,242 at P 165, 167 (‘‘NERC states that the 

requirement that a Reliability Standard be ‘‘in the 

public interest’’ provides the Commission with 

broad discretion to review and approve a Reliability 

Standard. According to NERC, implicit in the 

‘‘public interest’’ test is that a Reliability Standard 

is technically sound and ensures an adequate level 

of reliability, and that the Reliability Standards 

provides a comprehensive and complete set of 

technically sound requirements that establish an 

acceptable threshold of performance necessary to 

ensure reliability of the Bulk-Power System.’’). 

The Commission agrees with NERC that an open 

and transparent process is important in 

implementing section 215 of the FPA and 

developing proposed mandatory Reliability 

Standards. However, in Order No. 672, the 

Commission rejected the presumption that a 

proposed Reliability Standard developed through 

an ANSI-certified process automatically satisfies the 

statutory standard of review. Order No. 672, FERC 

Stats. & Regs. ¶ 31,204 at P 338. The Commission 

reiterates that simply because a proposed Reliability 

Standard has been developed through an adequate 

process does not mean that it is adequate as a 

substantive matter in protecting reliability. We, 

therefore, review each Reliability Standard to 

ensure that the Reliability Standard is just, 

reasonable, not unduly discriminatory or 

preferential, and in the public interest. 

78 5 CFR 1320.11. 

79 44 U.S.C. 3507(d). 

80See Order No. 693, FERC Stats. & Regs. 

¶ 31,242 at P 1901–07. 

e. Procedural Issues 

56. Several participants such as 

Ameren, FirstEnergy, and EEI are 

concerned that this interpretation could 

circumvent the Reliability Standards 

development process. In this remand, 

the Commission is not approving new 

Reliability Standards or Requirements. 

Such action would be better handled via 

the Reliability Standards development 

process. In remanding this 

interpretation, we are simply instructing 

NERC to provide a revised 

interpretation reflecting appropriate 

consideration of the Commission’s 

ruling that a Reliability Standard ‘‘must 

be designed to achieve a specified 

reliability goal and must contain a 

technically sound means to achieve this 

goal.’’ 76 Furthermore, the Commission, 

in considering the arguments and 

comments, has given due weight to the 

technical expertise of the ERO in 

deciding how to proceed; the ERO is 

directed to develop revisions to the 

Reliability Standard interpretation, 

consistent with this Final Rule, to 

address the Commission’s concerns.77

57. EEI warns the Commission that 

Dynegy’s request raises several process 

issues and cautions the Commission not 

to allow a single entity to change a 

Reliability Standard via an 

interpretation or any other ‘‘backdoor’’ 

device. The Commission is mindful of 

EEI’s concern, but we do not believe 

that we have decided the issues here in 

a way that allows an entity to change a 

standard through a ‘‘backdoor’’ effort. 

III. Information Collection Statement 

58. The Office of Management and 

Budget (OMB) regulations require that 

OMB approve certain reporting and 

recordkeeping (collections of 

information) requirements imposed by 

an agency.78 The information contained 

here is also subject to review under 

section 3507(d) of the Paperwork 

Reduction Act of 1995.79

59. As stated above, the Commission 

previously approved, in Order No. 693, 

each of the Reliability Standards that are 

the subject of the current rulemaking. 

This Final Rule approves one 

interpretation to a previously approved 

Reliability Standard developed by NERC 

as the ERO, and remands another 

interpretation. The proffered 

interpretations relate to existing 

Reliability Standards and do not change 

these standards; therefore, they do not 

add to or otherwise increase entities’ 

current reporting burden. Thus, the 

Final Rule does not materially and 

adversely affect the burden estimates 

relating to the currently effective 

version of the Reliability Standards 

presented in Order No. 693. 

60. The BAL–003–0 Reliability 

Standard that is the subject of the 

approved interpretation was approved 

in Order No. 693, and the related 

information collection requirements 

were reviewed and approved, 

accordingly.80 The approved 

interpretation of BAL–003–0 does not 

modify or otherwise affect the collection 

of information already in place. With 

respect to BAL–003–0, the 

interpretation clarifies that the 

minimum frequency bias setting applies 

to systems that employ a variable bias 

methodology. Incorporating a minimum 

frequency bias setting into the 

determination of frequency response 

under automatic generation control does 

not change the information that a 

balancing authority reports because the 

same logs, data, or measurements would 

be maintained. 

61. The Commission is remanding the 

interpretation of VAR–001–1. As a 

result, information collection 

requirements for that Reliability 

Standard will not change at this time. 

62. Thus, the interpretations of the 

current Reliability Standards at issue in 

this rulemaking will not increase the 

reporting burden nor impose any 

additional information collection 

requirements. 

63. However, we will submit this 

Final Rule to OMB for informational 

purposes. 

Title: Electric Reliability Organization 

Interpretations of Specific Requirements 

of Frequency Response and Bias and 

Voltage and Reactive Control Reliability 

Standards. 

Action: Final Rule. 

OMB Control No.: 1902–0244. 

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

institutions. 

Frequency of Responses: On 

Occasion. 

Necessity of the Information: This 

Final Rule approves an interpretation of 

the specific requirements of one 

Commission-approved Reliability 

Standard. The Final Rule finds the 

interpretation just, reasonable, not 

unduly discriminatory or preferential, 

and in the public interest. In addition, 

this rule remands an additional 

proposed interpretation for further 

consideration. 

Internal Review: The Commission has 

reviewed the proposed Reliability 

Standard interpretations and made a 

determination that the proposed BAL– 

003–1 interpretation is necessary to 

implement section 215 of the FPA. The 

interpretation conforms to the 

Commission’s policy for frequency 

response and bias within the energy 

industry as reflected in BAL–003–1. 

64. Interested persons may obtain 

information on the reporting 

requirements by contacting the 

following: Federal Energy Regulatory 

Commission, 888 First Street, NE. 

Washington, DC 20426 [Attention: 

Michael Miller, Office of the Executive 

Director, Phone: (202) 502–8415, fax: 

(202) 273–0873, e-mail: 

michael.miller@ferc.gov]. 

65. 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, DC 

20503 [Attention: Desk Officer for the 

Federal Energy Regulatory Commission, 

phone: (202) 395–4638, fax: (202) 395– 

7285, e-mail: 

oira_submission@omb.eop.gov]. 

IV. Environmental Analysis 

66. 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 

25422 Federal Register / Vol. 74, No. 101 / Thursday, May 28, 2009 / Rules and Regulations 

81Regulations Implementing the National 

Environmental Policy Act, Order No. 486, FERC 

Stats. & Regs. ¶ 30,783 (1987). 82 18 CFR 380.4(a)(2)(ii). 83 5 U.S.C. 601–12. 84See 13 CFR 121.201. 

85To be included in the compliance registry, the 

ERO determines whether a specific small entity has 

a material impact on the Bulk-Power System. If 

these small entities should have such an impact 

then their compliance is justifiable as necessary for 

Bulk-Power System reliability. 

86The Commission remands the interpretation of 

the VAR–001–1 Reliability Standard. 

environment.81 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.82 The 

actions proposed herein fall within this 

categorical exclusion in the 

Commission’s regulations. 

V. Regulatory Flexibility Act Analysis 

67. The Regulatory Flexibility Act of 

1980 (RFA) 83 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.84 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 Final Rule because 

the interpretations discussed herein will 

not have a significant economic impact 

on a substantial number of small 

entities. 

68. In Order No. 693, the Commission 

adopted policies to minimize the 

burden on small entities, including 

approving the ERO compliance registry 

process to identify those entities 

responsible for complying with 

mandatory and enforceable Reliability 

Standards. The ERO registers only those 

distribution providers or load serving 

entities that have a peak load of 25 MW 

or greater and are directly connected to 

the bulk electric system or are 

designated as a responsible entity as 

part of a required under-frequency load 

shedding program or a required undervoltage load shedding program. 

Similarly, for generators, the ERO 

registers only individual units of 20 

MVA or greater that are directly 

connected to the bulk electric system, 

generating plants with an aggregate 

rating of 75 MVA or greater, any 

blackstart unit material to a restoration 

plan, or any generator that is material to 

the reliability of the Bulk-Power System. 

Further, the ERO will not register an 

entity that meets the above criteria if it 

has transferred responsibility for 

compliance with mandatory Reliability 

Standards to a joint action agency or 

other organization. The Commission 

estimated that the Reliability Standards 

approved in Order No. 693 would apply 

to approximately 682 small entities 

(excluding entities in Alaska and 

Hawaii), but also pointed out that the 

ERO’s Compliance Registry Criteria 

allow for a joint action agency, 

generation and transmission (G&T) 

cooperative or similar organization to 

accept compliance responsibility on 

behalf of its members. Once these 

organizations register with the ERO, the 

number of small entities registered with 

the ERO will diminish and, thus, 

significantly reduce the impact on small 

entities.85

69. Finally, as noted above, this Final 

Rule addresses an interpretation of the 

BAL–003–0 Reliability Standard, which 

was already approved in Order No. 693, 

and, therefore, does not create an 

additional regulatory impact on small 

entities.86

VI. Document Availability 

70. 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 the 

Commission’s Home Page (http:// 

www.ferc.gov) and in the Commission’s 

Public Reference Room during normal 

business hours (8:30 a.m. to 5 p.m. 

Eastern time) at 888 First Street, NE., 

Room 2A, Washington, DC 20426. 

71. From the Commission’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. 

72. User assistance is available for 

eLibrary and the Commission’s Web site 

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. 

VII. Effective Date and Congressional 

Notification 

73. These regulations are effective 

June 29, 2009. The Commission has 

determined, with the concurrence of the 

Administrator of the Office of 

Information and Regulatory Affairs of 

OMB, that this rule is not a ‘‘major rule’’ 

as defined in section 351 of the Small 

Business Regulatory Enforcement 

Fairness Act of 1996. 

List of Subjects in 18 CFR Part 40 

Electric power, Electric utilities, 

Reporting and recordkeeping 

requirements. 

By the Commission. 

Nathaniel J. Davis, Sr., 

Deputy Secretary. 

[FR Doc. E9–12348 Filed 5–27–09; 8:45 am] 

BILLING CODE 6717–01–P 

DEPARTMENT OF ENERGY 

Federal Energy Regulatory 

Commission 

18 CFR Part 40 

[Docket No. RM08–12–000; Order No.723] 

Western Electricity Coordinating 

Council Regional Reliability Standard 

Regarding Automatic Time Error 

Correction 

Issued May 21, 2009. 

AGENCY: Federal Energy Regulatory 

Commission, DOE. 

ACTION: Final rule. 

SUMMARY: Pursuant to section 215 of the 

Federal Power Act (FPA), the Federal 

Energy Regulatory Commission 

(Commission) approves regional 

Reliability Standard BAL–004–WECC– 

01 (Automatic Time Error Correction), 

as submitted by the North American 

Electric Reliability Corporation. As a 

separate action, pursuant to section 

215(d)(5) of the FPA, the Commission 

directs the Western Electricity 

Coordinating Council to develop several 

modifications to the regional Reliability 

Standard. The regional Reliability 

Standard requires balancing authorities 

within the Western Interconnection to 

maintain interconnection frequency 

within a predefined frequency profile 

and ensure that time error corrections 

are effectively conducted in a manner 

that does not adversely affect the 

reliability of the Interconnection.