RM08-16-000 NOPR OMB Just.

RM08-16-000 NOPR, FERC-725A Issued November 20, 2008

Supporting Statement for

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

As Proposed in Docket No. RM08-16-000

(A Notice of Proposed Rulemaking Issued November 20, 2008)

The Federal Energy Regulatory Commission (Commission) (FERC) is submitting a Notice of Proposed Rulemaking Rule (NOPR) that affects the requirements under the following information collection: FERC‑725A, Mandatory Reliability Standards for the Bulk Power System. FERC-725A (Control No. 1902-0244) is a Commission data collection, (filing requirements), as contained in 18 Code of Federal Regulations, Part 40.

In 2007 the Commission created a new information collection FERC-725A, implementing mandatory reliability standards that were previously part of a voluntary program. The Commission is informing OMB that while there are changes due to interpretations of the Mandatory Reliability Standards, the proposed changes in this Notice of Proposed Rulemaking will not make substantive changes to the information collection requirements and therefore the last estimates reported remain unchanged in this submission. As the Commission has previously noted, it will revise these estimates as the mandatory standards are updated and enforced.

Background

On August 8, 2005, The Electricity Modernization Act of 2005, which is Title XII of the Energy Policy Act of 2005 (EPAct 2005), was enacted into law.¹ EPAct 2005 added a new section 215 to the FPA and requires a Commission-certified 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. (A reliability standard defines obligations or requirements of utilities and other entities that operate, plan and use the bulk power system in North America. Meeting these requirements helps to ensure the reliable planning and operation of the bulk power system. Each NERC Reliability Standard details the purpose of the standard, the entities that must comply, and the specific actions that constitute compliance and how the standard will be measured).

RM06-16-000 Final Rule, Order No. 693

On March 16, 2007, the Commission issued Order No. 693, a Final Rule that added part 40, a new part to the Commission’s regulations. The Final Rule stated that this part applies to all users, owners and operators of the Bulk-Power System within the United States (other than Alaska or Hawaii). It also requires that each Reliability Standard identify the subset of users, owners and operators to which that particular Reliability Standard applies. Order No. 693 also requires that each Reliability Standard that is approved by the Commission will be maintained on the ERO’s Internet website for public inspection. (The bulk power system consists of the power plants, transmission lines and substations, and related equipment and controls, that generate and move electricity in bulk to points from which local electric companies distribute the electricity to customers.)

The Commission approved 83 of 107 proposed Reliability Standards, six of the eight proposed regional differences, and the Glossary of Terms used in Reliability Standards as developed by the North American Electric Reliability Corporation (NERC). NERC was certified by the Commission as the Electric Reliability Organization (ERO) responsible for developing and enforcing mandatory Reliability Standards. Those Reliability Standards meet the requirements of section 215 of the FPA and Part 39 of the Commission’s regulations. However, although the Commission believed that it is in the public interest to make these Reliability Standards mandatory and enforceable, the Commission also found that much work remained to be done.  Specifically, the Commission believes that many of these Reliability Standards require significant improvement to address, among other things, the recommendations of the Blackout Report.  Therefore, pursuant to section 215(d)(5), the Commission required the ERO to submit significant improvements to 56 of the 83 Reliability Standards that are being approved as mandatory and enforceable.  The remaining 24 Reliability Standards remain pending at the Commission until further information is provided.

RM08-16-000 NOPR

On November 20, 2008 the Commission issued a NOPR proposing to approve the interpretation proposed by the North American Electric Reliability Corporation (NERC) of certain specific requirements of Commission-approved Reliability Standard BAL-003-0, Frequency Response and Bias, but remand NERC’s proposed interpretation of Reliability Standard VAR-001-1, Voltage and Reactive Control, for additional clarification.²

Order No. 693 explains that the purpose of BAL-003-0 is to ensure that a balancing authority’s³ frequency bias setting is accurately calculated to match its actual frequency response.⁴ A frequency bias setting is a value expressed in MW/0.1 Hz, set into a balancing authority area control error (ACE) algorithm, which allows the balancing authority to contribute its frequency response to the Interconnection.⁵ The actual frequency response is the change in output or consumption from generators and non-generation resources, respectively, after the loss of a generator and determines the frequency at which electric supply and demand return to balance.

Requirement R2.2 states that a Balancing Authority may use a variable frequency bias value, which is calculated by analyzing frequency response taking into account factors such as load, generation, governor characteristics, and frequency. Requirement R5 states that balancing authorities that serve native load shall have a monthly average frequency bias setting that is at least one percent of estimated yearly peak demand per 0.1 Hz change. The BAL-003-0 Requirements at issue state:

Requirement R2: Each 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. Frequency Bias may be calculated several ways:

R2.2. The Balancing Authority may use a variable (linear or non-linear) bias value, which is based on a variable function of Tie Line deviation to Frequency Deviation. The Balancing Authority shall determine the variable frequency bias value by analyzing Frequency Response as it varies with factors such as load, generation, governor characteristics, and frequency.

Requirement R5: Balancing Authorities that serve native load shall have a monthly average Frequency Bias Setting that is at least 1% of the Balancing Authority’s estimated yearly peak demand per 0.1 Hz change.

R5.1. Balancing Authorities that do not serve native load shall have a monthly average Frequency Bias Setting that is at least 1% of its estimated maximum generation level in the coming year per 0.1 Hz change.

For BAL-003-0, 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.

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.⁶ The ERO’s “standards process manager” will assemble a team with relevant expertise to address the requested interpretation 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 Reliability Standard and filed with the applicable regulatory authority for regulatory approval.

Each Reliability Standard that the ERO proposed to interpret or modify in the proposed rule was approved by the Commission in Order No. 693. In the NOPR, several standards were being updated but revisions to the standards and corresponding burden estimates are not applicable and the Commission is submitting the proposed rule to OMB with no changes to the reporting burden.

A. Justification

1. CIRCUMSTANCES THAT MAKE THE COLLECTION OF INFORMATION NECESSARY

With the passage of the Energy Policy Act of 2005 (EPAct 2005) Congress entrusted the Commission with the authority to approve and enforce rules to assure reliability of the Nation’s Bulk Power System. Section 1211 of EPAct 2005 created a new section 215 to the Federal Power Act (FPA), which provides for a system of mandatory and enforceable Reliability Standards. Section 215(d)(1) of the FPA provides that the Electric Reliability Organization (ERO) must file each Reliability Standard or modification to a Reliability Standard that it proposes to be made effective, i.e., mandatory and enforceable, with the Commission. The law mandates that all users, owners, and operators of the Bulk-Power System in the United States will be subject to the Commission-approved Reliability Standards. On April 4, 2006, and as later modified and supplemented, the ERO submitted 107 Reliability Standards for Commission approval pursuant to section 215(d) of the FPA.

Section 215(d)(2) of the FPA provides that the Commission may approve, by rule or order, a proposed Reliability Standard or modification to a proposed Reliability Standard if it meets the statutory standard for approval, giving due weight to the technical expertise of the ERO. Alternatively, the Commission may remand a Reliability Standard pursuant to section 215(d)(4) of the FPA. Further, the Commission may order the ERO to submit to the Commission a proposed Reliability Standard or a modification to a Reliability Standard that addresses a specific matter if the Commission considers such a new or modified Reliability Standard appropriate to “carry out” section 215 of the FPA.⁷ The Commission’s action in this NOPR is based on its authority pursuant to section 215 of the FPA.

Recent Events

A common cause of the past major regional blackouts was violation of NERC’s then Operating Policies and Planning Standards. During July and August 1996, the west coast of the United States experienced two cascading blackouts caused by violations of voluntary Operating Policies.⁸ In response to the outages, the Secretary of Energy convened a task force to advise the Department of Energy (DOE) on issues needed to be addressed to maintain the reliability of the bulk-power system. In a September 1998 report, the task force recommended, among other things, that federal legislation should grant more explicit authority for FERC to approve and oversee an organization having responsibility for bulk-power reliability standards.⁹ Further, the task force recommended that such legislation provide for Commission jurisdiction for reliability of the bulk-power system and FERC implementation of mandatory, enforceable reliability standards.

The Generation and Transmission components make up the “bulk power system”. 

Source of graph:  US-Canada Power System Outage Task Force

Electric reliability legislation was first proposed after issuance of the September 1998 task force report and was a common feature of comprehensive electricity bills since that time. A stand-alone electric reliability bill was passed by the Senate unanimously in 2000. In 2001, President Bush proposed making electric Reliability Standards mandatory and enforceable as part of the National Energy Policy.¹⁰

Under the new electric power reliability system enacted by the Congress, the United States will no longer rely on voluntary compliance by participants in the electric industry with industry reliability requirements for operating and planning the Bulk-Power System. Congress directed the development of mandatory, Commission-approved, enforceable electricity Reliability Standards. The Commission believes that, to achieve this goal, it is necessary to have a strong ERO that promotes excellence in the development and enforcement of Reliability Standards.

A mandatory Reliability Standard should not reflect the “lowest common denominator” in order to achieve a consensus among participants in the ERO’s Reliability Standard development process. Therefore, the Commission will carefully review each Reliability Standard submitted and, where appropriate, later remand if necessary, an inadequate Reliability Standard to ensure that it protects reliability, has no undue adverse effect on competition, and can be enforced in a clear and even-handed manner. Standards address aspects of the operation and planning of the bulk power system such as: real-time transmission operations, balancing load and generation, emergency operations, system restoration and blackstart, voltage control, cyber security, vegetation management, facility ratings, disturbance reporting, connecting facilities to the grid, certifying system operators, and personnel training. Standards detail how the system should perform, but not how the system should be designed. Individual owners, operators and users of the bulk power system determine if the system should be expanded or changed, and how, in order to achieve the standards.

Reliability Standard BAL-003-0

Order No. 693 explains that the purpose of BAL-003-0 is to ensure that a balancing authority’s frequency bias setting is accurately calculated to match its actual frequency response.¹¹ A frequency bias setting is a value expressed in MW/0.1 Hz, set into a balancing authority area control error (ACE) algorithm, which allows the balancing authority to contribute its frequency response to the Interconnection. The actual frequency response is the change in output or consumption from generators and non-generation resources, respectively, after the loss of a generator and determines the frequency at which electric supply and demand return to balance.

To accomplish this purpose, it is necessary to rely on historic data from a balancing authority’s automatic generation control.¹² 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 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.

VAR-001-1

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. Dynegy asked whether the voltage schedule and associated tolerance band, provided by the transmission operator must be technically based, and reasonable and practical. In addition, Dynegy asked how a transmission operator would demonstrate compliance with such requirements.

VAR-001-1, Requirement R4 and VAR-002-1, Requirement R2, which are at issue in this proceeding, state:

VAR-001-1 – Voltage and Reactive Control.

Requirement R4. Each Transmission Operator shall specify a voltage or Reactive Power schedule¹³ 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)¹⁴ 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.

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

Prior to enactment of section 215, FERC had acted primarily as an economic regulator of wholesale power markets and the interstate transmission grid. In this regard, the Commission acted to promote a more reliable electric system by promoting regional coordination and planning of the interstate grid through regional independent system operators (ISOs) and regional transmission organizations (RTOs), adopting transmission pricing policies that provide price signals for the most reliable and efficient operation and expansion of the grid, and providing pricing incentives at the wholesale level for investment in grid improvements and assuring recovery of costs in wholesale transmission rates.

The passage of the Electricity Modernization Act of 2005 added to the Commission’s efforts identified above, by giving it the authority to strengthen the reliability of the interstate grid through the grant of new authority pursuant to section 215 of the FPA which provides for a system of mandatory Reliability Standards developed by the ERO, established by FERC, and enforced by the ERO and Regional Entities.

As part of FERC’s efforts to promote grid reliability, the Commission created a new office, the Office of Electric Reliability. One task of this office has been to participate in North American Reliability Council’s (NERC’s) Reliability readiness reviews of balancing authorities, transmission operators and reliability coordinators in North America to determine their readiness to maintain safe and reliable operations. FERC’s Office of Reliability has also been engaged in studies and other activities to assess the longer-term and strategic needs and issues related to power grid reliability. Specifically, OER performs the following functions:

• Monitor and participate in the standards development process to help improve the quality of reliability standards proposed to the Commission. Review filed standards to make recommendations as to whether the Commission should approve or remand it, or whether the Commission should direct the Electric Reliability Organization (ERO) to create a new standard or revise an existing standard.

• Monitor the compliance of the users, owners, and operators of the bulk power system with the reliability standards.

• Lead or join in periodic and unscheduled reviews and audits of the ERO, Regional Entities, and users, owners, and operators to determine the effectiveness of their reliability programs and their compliance with reliability standards.

• Lead or join in analysis and investigations concerning complaints, blackouts, near-misses, etc., on the bulk power system to determine if reliability standards were violated, changes to the reliability standards are warranted, or if the reliability standards are adequate for their intended purpose.

• Oversee the ERO’s resource adequacy assessments to identify and investigate constraints on the bulk power system.

• Engage in the regional planning processes to determine if proposed and approved projects are sufficient to meet the reliability requirements.

• Work with other internal and external groups to evaluate elements that may impact the bulk power system (such as fuel constraints, generation and transmission siting and permitting, congestion, rate recovery for reliability expenditures, etc.) and cost recovery options for potential solutions.

The Commission assists in creating a more reliable electric system by:

• Fostering regional coordination and planning of the interstate grid through independent system operators and regional transmission organizations;

• Adopting transmission policies that provide price signals for the most reliable and efficient operation and expansion of the grid; and

• Providing pricing incentives at the wholesale level for investment in grid improvements and ensuring opportunities for cost recovery in wholesale transmission rates.

This NOPR proposes to approve one interpretation to a previously approved Reliability Standard developed by NERC as the ERO, and to remand 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 current proposal would not materially and adversely affect the burden estimates relating to the currently effective version of the Reliability Standards presented in Order No. 693. 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.¹⁵

For example, the proposed 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. The frequency bias is a measure of the power change for a 0.1 Hz change in frequency. The actual frequency bias is the net of the load frequency bias, which is mostly the result of the change in motor demand with changing frequency, and the generation frequency bias, which is a property of the type of generation and generator governor action. The actual bias will determine the post disturbance system frequency at which generation and load are again in balance. If the net bias is near zero, the post-disturbance frequency would settle to an unacceptably low and unstable level.

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. The use of an inappropriate frequency bias setting may have an adverse impact on reliability.

The Commission is proposing to remand the interpretation of VAR-001-1. As a result, information collection requirements for that Reliability Standard will not change at this time. Thus, the proposed interpretations of the current Reliability Standards at issue in this proposed rule will not increase the reporting burden nor impose any additional information collection requirements.

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

The Commission has developed the capability for electronic filing of all major submissions to the Commission. In Order No. 619, the Commission established an electronic filing initiative that permits over 40 qualified types of documents to be filed over the Internet to its website. This includes the ability to submit standard forms using software that is readily available and easy to use. Electronic filing, combined with electronic posting and service over the web site, permits staff and the public to obtain filings in a faster and more efficient manner. The Commission is working to expand the qualified types of documents that can be filed over the Internet.

In order that the Commission is able to perform its oversight function with regard to Reliability Standards that are proposed by the ERO and established by the Commission, it is essential that the Commission receive timely information regarding all or potential violations of Reliability Standards. While section 215 of the FPA contemplates the filing of the record of an ERO or Regional Entity enforcement action, FERC needs information regarding violations and potential violations at or near the time of occurrence. Therefore, it will work with the ERO and regional reliability organizations to be able to use the electronic filing of information so the Commission receives timely information.

The regulations established in Order No. 693 also require that each Reliability Standard that is approved by the Commission will be maintained on the ERO’s Internet website for public inspection. 

4. DESCRIBE EFFORTS TO IDENTIFY DUPLICATION AND SHOW SPECIFICALLY WHY ANY SIMILAR INFORMATION ALREADY AVAILABLE CANNOT BE USED OR MODIFIED FOR USE FOR THE PURPOSE(S) DESCRIBED IN INSTRUCTION NO. 2

Filing requirements are periodically reviewed as OMB review dates arise or as the Commission may deem necessary in carrying out its responsibilities under the FPA in order to eliminate duplication and ensure that filing burden is minimized. There are no similar sources of information available that can be used or modified for these reporting purposes. The filing requirements contained in FERC-725A will incorporate NERC’s requirements. However, all reliability requirements will be subject to FERC approval along with the requirements developed by Regional Entities and Regional Advisory Bodies and the ERO.

5. METHODS USED TO MINIMIZE BURDEN IN COLLECTION OF INFORMATION INVOLVING SMALL ENTITIES

FERC-725A is a filing requirement concerning the implementation of reliability standards by the Electric Reliability Organization and its responsibilities as well as those of Regional Entities and Regional Advisory Bodies in the development of Reliability Standards. The Electricity Modernization Act specifies that the ERO and Regional Entities are not departments, agencies or instrumentalities of the United States government and will not be like most other businesses, profit or not-for–profit. Congress created the concept of the ERO and Regional Entities as select, special purpose entities that will transition the oversight of the Bulk-Power System reliability from voluntary, industry organizations to independent organizations subject to Commission jurisdiction.

As noted above, Section 215(b) of the FPA requires all users, owners and operators of the Bulk-Power System to comply with Commission-approved Reliability Standards. Each proposed Reliability Standard submitted for approval by NERC applies to some subset of users, owners and operators. However, the Commission believes that in achieving compliance with the Reliability Standards, the burden could be minimized for smaller entities by having them join a joint action agency or a generation or transmission cooperative or similar organization that would assume responsibility for compliance on behalf of its members.  In addition, the Commission is relying on the registry established by NERC that spells out the criteria of who will be subject to the Reliability Standards. 

In Order No. 693, the Commission adopted policies to minimize the burden on small entities, including approving the ERO compliance registry process to identify those entities responsible for complying with mandatory and enforceable Reliability Standards. The ERO registers only those distribution providers or load serving entities that have a peak load of 25 MW or greater and are directly connected to the bulk electric system or are designated as a responsible entity as part of a required under-frequency load shedding program or a required under-voltage load shedding program. Similarly, for generators, the ERO registers only individual units of 20 MVA or greater that are directly connected to the bulk electric system, generating plants with an aggregate rating of 75 MVA or greater, any blackstart unit material to a restoration plan, or any generator that is material to the reliability of the Bulk-Power System. Further, the ERO will not register an entity that meets the above criteria if it has transferred responsibility for compliance with mandatory Reliability Standards to a joint action agency or other organization. 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.¹⁶

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

The Electric Reliability Organization (ERO) will conduct periodic assessments of the reliability and adequacy of the Bulk-Power System in North America and report its findings to the Commission, the Secretary of Energy, Regional Entities, and Regional Advisory Bodies annually or more frequently if so ordered by the Commission. The ERO and Regional Entities will report to FERC on their enforcement actions and associated penalties and to the Secretary of Energy, relevant Regional entities and relevant Regional Advisory Bodies annually or quarterly in a manner to be prescribed by the Commission. If the information were conducted less frequently or discontinued, the Commission would be placed at a disadvantage in not having the data necessary for monitoring its mandated obligations.

7. EXPLAIN ANY SPECIAL CIRCUMSTANCES RELATING TO THE INFORMATION COLLECTION

FERC-725A is a filing requirement necessary to comply with the applicable provisions of the Electricity Modernization Act of 2005 and section 215 of the Federal Power Act.

In accordance with section 39.5 of the Commission’s regulations, the ERO must file each Reliability Standard or a modification to a Reliability Standard with the Commission. The filing is to include a concise statement of the basis and purpose of the proposed Reliability Standard, either a summary of the Reliability development proceedings conducted by the ERO or a summary of the Reliability Standard development proceedings conducted by a Regional Entity together with a summary of the Reliability Standard review proceedings of the ERO and a demonstration that the proposed Reliability Standard is “just, reasonable, not unduly discriminatory or preferential, and in the public interest.

The ERO must make each effective Reliability Standard available on its Internet website. Copies of the effective Reliability Standards will be available from the Commission’s Public Reference Room.

The Commission requires an original and seven of the proposed Reliability Standard or to the modification to a proposed Reliability Standard to be filed. This exceeds the OMB guidelines in 5 CFR 1320.5(d) (2) (iii) because of the number of divisions within the Commission that must analyze the standard and corresponding reports in order to carry out the regulatory process. The original is docketed, imaged through e-Library and filed as a permanent record for the Commission. The remaining copies are distributed to the necessary offices of the Commission with one being placed immediately in the Commission’s Public Reference Room for public use. Since the time frame for responses to the request is very limited, the multiple hard copies are necessary for the various offices to review, analyze and prepare the final order at the same time. The electronic filing initiative at FERC, may in the near future, allow for relief of the number of copies, but at this time, the program turn around time for docketing, imaging and retrieval does not permit sufficient time to review the filings and to prepare the necessary documents for the processing of these filings.

In addition, individual reliability standards may have records retention schedules that exceed OMB guidelines in 5 CFR 1320.5(d)(2)(iv) of not retaining records for no longer than three years. The Commission is not prescribing a set data retention period to apply to all Reliability Standards.

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

Each Commission rulemaking (both NOPRs and Final Rules) are published in the Federal Register, thereby affording all public utilities and licensees, state commissions, Federal agencies, and other interested parties an opportunity to submit data, views, comments or suggestions concerning the proposed collection of data. The notice procedures also allow for public conferences to be held as required. The Commission has held several workshops and technical conferences to address reliability issues including transition to the NERC reliability standards, operator tools, and reactive power.

ERCOT Request

ERCOT requested clarification from NERC that a balancing authority may use a variable bias value as authorized under Requirement R2.2, despite the fact that doing so could, according to ERCOT, cause a violation of Requirement R5.¹⁷ According to ERCOT, if a balancing authority uses a variable bias in conformance with Requirement R2.2, it would violate Requirement R5 if its analysis resulted in a value less than one percent of its yearly peak demand (or maximum generation). ERCOT stated that Requirement R2.2 is only viable if Requirement R5 is interpreted to apply only to balancing authorities using a fixed bias setting. ERCOT proposed that an alternate method be used to calculate a floor setting for balancing authorities that utilize a variable bias setting. Under ERCOT’s proposal, the correct corresponding minimum setting for a balancing authority using a variable bias setting would be no less than one percent of estimated peak (or maximum generation) for the period in which the variable bias setting is active. ERCOT supported its interpretation as being consistent with a January 2003 NERC Resources Subcommittee analysis, which stated “for Control Areas utilizing variable bias, the Control Area’s average Bias Setting for a month must be at least one percent of the Control Area’s estimated peak load for that month (or one percent of peak generation for a generation only Control Area forecast for that month).”¹⁸ ERCOT suggested that the failure to provide for a variable-bias option in Requirement R5 appears to be an oversight. Furthermore, according to ERCOT, failure to adopt its interpretation would force ERCOT to abandon its longstanding practice of using a variable bias setting, without any corresponding improvement in reliability.

NERC rejected ERCOT’s proposal, finding that the variable bias setting under Requirement R2 does not conflict with the minimum setting required under Requirement R5. NERC found that its interpretation provides clarity and supports the reliability purpose of BAL-003-0, which it describes as providing a consistent methodology for calculating the frequency bias component of ACE. According to NERC, Requirement R2 requires a balancing authority to analyze its system as a first step in determining its frequency bias setting, which may be a fixed or variable bias setting. Requirement R5 establishes a minimum reliability threshold for an Interconnection and also a minimum contribution for all balancing authorities within an Interconnection. NERC states that the one percent minimum bias setting provides a minimum level of automatic generation control to stabilize frequency in response to a disturbance. As a second justification for the minimum setting, NERC states that the one percent minimum also helps ensure a consistent measure of control performance among balancing authorities within a multi-balancing authority Interconnection.

NERC pointed out that ERCOT is a single balancing authority Interconnection. NERC supports its proposed interpretation stating:

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.

NERC noted that ERCOT is subject to a Regional Difference exempting it from certain requirements of a related Reliability Standard. ERCOT’s Regional Difference addresses Requirement R2 of the related BAL-001-0 Reliability Standard, Real Power Balancing Control Performance, which adopts one of NERC’s historical balancing control performance standards, known CPS2.¹⁹ The purpose of Reliability Standard BAL-001-0 is to maintain interconnection steady-state frequency within defined limits by balancing power demand and supply in real-time. BAL-001-0 uses two averages as compliance measures: Requirement R1 covers the one-minute ACE performance (CPS1) and Requirement R2 covers the 10-minute ACE performance (CPS2). Requirement R1 obligates each balancing authority, on a rolling 12-month basis, to maintain its clock-minute averages of ACE, modified by its frequency bias and the interconnection frequency, within a specific limit based on historic performance. Requirement R2 obligates each balancing authority, on a monthly basis, to maintain an average ACE within a specific limit based on historical performance for at least 90 percent of 10-minute periods within an hour. NERC presents two reasons supporting ERCOT’s Regional Difference for BAL-001-0, namely (1) to accommodate ERCOT’s asynchronous connections with other Interconnections; and (2) to recognize the fact that ERCOT employs a more stringent methodology to identify the frequency controls necessary to maintain reliable operations.²⁰

During the ballot process, NERC responded to comments raising two issues. NERC indicated that it was sympathetic to comments that Requirement R5 is vague, finding that the requirement that each balancing authority have a monthly average bias greater than or equal to one percent of its projected annual peak load (or generation if it does not serve load), could be better drafted. However, NERC found that revising the requirement is beyond the scope of the interpretation process. Also, NERC stated that it addressed a second comment by indicating that a balancing authority that is the sole balancing authority for an Interconnection must comply with Requirement R5 and also that a balancing authority that uses a variable bias setting must comply with Requirement R5 in BAL-003-0.

The formal interpretation was approved by the ballot pool in September 2007 and by the NERC Board in February 2008.

Commission’s Response

The Commission proposes to approve the ERO’s formal interpretation of Requirements R2 and R5 of BAL-003-0 and requests comment on its proposal. The ERO’s interpretation is reasonable in that it provides for consistent determination of frequency bias settings, used in calculating ACE. In addition, the one percent minimum set aside established by Requirement R5 ensures that an adequate level of generation will be set aside to provide frequency response in the event of system disturbances due to imbalances.

Furthermore, the ERO’s interpretation is consistent with the Commission’s discussion in Order No. 693, which reviewed a similar objection, and found that the requirements of BAL-003-0 do not conflict with one another.²¹ Order No. 693 addressed the suggestion that Requirement R5 should be required in lieu of Requirement R2 for certain balancing authorities and found that Requirements R2 and R5 do not conflict. While, in this case, ERCOT is arguing the reverse, namely, that balancing authorities that meet the requirement of Requirement R2 should not have to meet Requirement R5, similar reasoning suggests no conflict in the two requirements. According to Order No. 693, Requirement R2 states that the frequency bias setting should be as close as practical to, or greater than, the balancing authority’s frequency response, while Requirement R5 and R5.1 provide minimum frequency bias values for specific types of balancing authorities.²²

As noted above, NERC’s interpretation states that ERCOT’s bias settings produce, on average, the best level of automatic generation control action to meet control performance metrics and the bias value in a single balancing authority interconnection does not impact the measure of control performance.  The Commission interprets this statement as providing that the second goal of the one percent minimum setting, to establish a consistent measure of control performance among balancing authorities, is not implicated by this interpretation. Nevertheless, the other justifications for the BAL-003-0, Requirement R5 minimum bias setting still apply namely, to establish a consistent methodology for one of the inputs into the ACE determination and to provide for a minimum threshold of reliability from frequency response.²³

Dynegy Request

Dynegy requested clarification whether there are implicit requirements for the voltage schedule, and associated tolerance band, provided by the transmission operator to be technically based, reasonable and practical for a generator to maintain.²⁴ According to Dynegy, the NERC Rules of Procedure require that each Reliability Standard be based on “sound engineering and operating judgment, analysis, or experience[.]”²⁵ Dynegy asserted that Reliability Standards must be implemented to meet such a standard and that transmission owners must have a technical basis for the specified voltage or reactive power schedule and associated tolerance band. Dynegy predicts that generator operator compliance with the schedule and tolerance band will be improved if the generator understands the technical basis for the instructions.

Dynegy argued that the lack of a technical basis could result in arbitrary target values or overly narrow or overly wide tolerance bands and those flaws could reduce system reliability. For instance, Dynegy hypothesized that overly narrow tolerance bands could cause a generator to make numerous short term responses to voltage fluctuations that do not improve system reliability; while overly broad tolerance bands could result in voltage fluctuations that jeopardize system reliability during system disturbances. Dynegy stated that voltage schedules must be reasonable and that a tolerance band that fails to account for measurement error is unreasonable. Dynegy states that, if the voltages or reactive power schedule and associated tolerance band are to have a technical basis and be reasonable, then NERC must develop measures to objectively evaluate compliance with the requirement.²⁶ According to Dynegy, such a measure should state that the voltage schedule and tolerance band should either be (1) consistent with the historical variation of system voltage, normalized to eliminate abnormal voltage fluctuations such as those caused by system disturbances; or (2) consistent with the historical variation of system voltage when the plant/unit is not operating, which variation would be normalized to eliminate abnormal voltage fluctuations such as those caused by system disturbances. According to Dynegy, if either of these conditions is not met, a transmission operator should be required to have a technical study or analysis that justifies a different voltage or reactive power schedule and associated tolerance band.

NERC’s proposed interpretation rejects the suggestion that there are implicit requirements within VAR-001-1, and finds, as well, that 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, and, consequently, the Reliability Standard needs no measures to implement such requirements. According to NERC:

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.²⁷

The interpretation concludes by citing VAR-002-1, Requirement 2, which provides that a generator must meet the voltage schedule or provide an explanation why it cannot do so.

The NERC Board requested additional information to address a concern whether a generator operator could be in violation of VAR-001-1 if it deviated from its schedule in order to protect its equipment. NERC provided supplemental information, which is not part of the formal interpretation, pointing out that VAR-002-1 requires a generator to maintain the voltage directed by the transmission operator “within applicable Facility Ratings” and permits a generator to deviate from the voltage schedule with an explanation.²⁸ NERC also cited VAR-002-1, section A(3), stating that the purpose of the Reliability Standard is “To ensure generators provide reactive and voltage control necessary to ensure voltage levels, reactive flows, and reactive resources are maintained within applicable Facility Ratings to protect equipment and the reliable operation of the Interconnection.”²⁹

Finally, NERC’s transmittal letter also provided additional instructive information, which is not part of 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 stated 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, according to NERC, while it supports the formal interpretation of Requirement R4 including the finding that a requirement cannot establish implicit obligations, the issue on which Dynegy seeks clarification is better resolved through an examination of Requirement R2.³⁰

According to NERC, the interpretation supports the intent of the requirement and the goal of VAR-001-1, because it reinforces that the transmission operator is responsible for identifying voltage schedules and associated bandwidth necessary to meet the objectives of the Reliability Standard.

In the ballot process, NERC responded to a negative comment arguing that the requirements of VAR-001-1 do imply that there will be a technical justification for a reactive power schedule. According to NERC, the drafting team responded that an implied requirement is not a stated requirement that can be objectively measured. The interpretation was approved by ballot in January 2008 and by the Board, upon receipt of the additional information, in March 2008.

Commission’s Response

The Commission proposes to remand NERC’s interpretation of VAR-001-1, Requirement R4. The Commission disagrees with the interpretation’s suggestion that there is no requirement that a voltage schedule have a sound technical basis. On the contrary, in Order No. 693, the Commission 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.³¹ Therefore, the Commission disagrees with NERC’s proposed interpretation insofar as it suggests that a transmission operator could deliver a voltage schedule that lacked any technical basis. A voltage schedule should reflect technical analysis, i.e., sound engineering, as well as operating judgment and experience.³²

In Order No. 693, moreover, the Commission reviewed each Reliability Standard and approved those containing Requirements that are sufficiently clear as to be enforceable and that do not create due process concerns.³³ In approving VAR-001-1 in Order No. 693, the Commission included VAR-001-1 as among the Reliability Standards that are sufficiently clear to inform transmission operators what is required of them.³⁴ While the Commission has elsewhere declined to specify in detail how a registered entity should implement a Reliability Standard, this does 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. NERC’s proposed interpretation, however, implies 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.

Based on this analysis, the Commission proposes to remand NERC’s proposed VAR-001-1, Requirement R4 interpretation, in order that NERC may reconsider its interpretation consistent with the NOPR. With regard to Dynegy’s assertion that NERC needs to develop evaluation measures to review the technical basis for voltage schedules, in the Commission’s view, this proposal is beyond the scope of the interpretation process and would be better discussed pursuant to a standards authorization request under the NERC Reliability Standards Development Procedures.

9. EXPLAIN ANY PAYMENT OR GIFTS TO RESPONDENTS

No payments or gifts have been made to respondents.

10. DESCRIBE ANY ASSURANCE OF CONFIDENTIALITY PROVIDED TO RESPONDENTS

The Commission generally does not consider the data filed to be confidential. However,

certain standards may have confidentiality provisions in the standard.

Section 215(e) of the FPA as well as section 39.7(d) of the Commission’s regulations regarding enforcement of Reliability Standards provides for public notice and opportunity for a hearing with respect to both the ERO (or Regional Entity) enforcement proceedings and proceedings before the Commission involving review of a proposed penalty for violation of a reliability standard. Section 39.7(b)(4) provides a limited exception to this notice requirement and allow non-public proceedings for enforcement actions that involve a Cybersecurity Incident,³⁵ unless FERC determines on a case-by-case basis that such protection is not necessary. The Commission has in place procedures to prevent the disclosure of sensitive information, such as the use of protective orders and rules establishing critical energy infrastructure information (CEII). However, the Commission believes that the specific, limited area of Cybersecurity Incidents requires additional protections because it is possible that system security and reliability would be further jeopardized by the public dissemination of information involving incidents that compromised the cybersecurity system of a specific user, owner or operator of the Bulk-Power System. In addition, additional information provided with a filing may be submitted with a specific request for confidential treatment to the extent permitted by law and considered pursuant to 18 C.F.R. 388.112 of FERC's regulations.

11. PROVIDE ADDITIONAL JUSTIFICATION FOR ANY QUESTIONS OF A SENSITIVE NATURE THAT ARE CONSIDERED PRIVATE.

There are no questions of a sensitive nature that are considered private.

12. ESTIMATED BURDEN OF COLLECTION OF INFORMATION

As stated above, the Commission previously approved, in Order No. 693, each of the Reliability Standards that are the subject of the current rulemaking. As noted in item no. 2 above, this NOPR proposes to approve one interpretation to a previously approved Reliability Standard and to remand another interpretation. These 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 current proposal would not materially and adversely affect the burden estimates relating to the currently effective version of the Reliability Standards presented in Order No. 693. Therefore the reporting burdens as reported in Order No. 693 (see estimates below) remain unchanged.

Total Annual Hours for Collection:

Data Collection	No. of Respondents	No. of Responses	Hours Per Response	Total Annual Hours
FERC-725A
Investor Owned Utilities	170	1	2,080	353,600
Municipals and Cooperatives (Large)	80	1	1,420	113,600
Municipals and Cooperatives (Small)	670	1	710	475,700
Generator Operators	360	1	500	180,000
Power Marketers	159	1	100	15,900
Recordkeeping	Investor Owned Utilities			35,360
	Munis/Coops (Large)			11,360
	Munis/Coops (Small)			47,570
	Generator Operators			18,000
	Power Marketers			1,590
Totals				1,252,680

(FTE=Full Time Equivalent or 2,080 hours)

Total Hours = 1,138,800 (reporting) + 113,880 (recordkeeping) = 1,252,680 hours. This estimated reporting burden will be significantly reduced once joint action agencies are established, which will reduce the number of small entities that will be responsible for compliance with Reliability Standards.

13. ESTIMATE OF THE TOTAL ANNUAL COST BURDEN TO RESPONDENTS

Information Collection Costs: As noted above, there are no modifications to the Reliability Standards and the proffered interpretations relate to existing Reliability Standards; therefore, they do not add to or increase entities’ current reporting burden. As a result, the Commission does not anticipate there will be associated costs to implement these revisions.

14. ESTIMATED ANNUALIZED COST TO FEDERAL GOVERNMENT

The estimate of the cost to the Federal Government is based on salaries for professional

and clerical support, as well as direct and indirect overhead costs. Direct costs include all costs directly attributable to providing this information, such as administrative costs and the cost for information technology. Indirect or overhead costs are costs incurred by an organization in support of its mission. These costs apply to activities which benefit the whole organization rather than anyone particular function or activity. As the Commission has already adopted many of the Reliability Standards instituted in Order No. 693 (many of which have already been in place on a voluntary basis), it is difficult to provide an assessment at this stage of what the costs will be to the Commission in its review and of Reliability Standards submitted to it. These requirements are at the preliminary stages and the Regional Entities and Regional Advisory bodies have only just been created. Both organizations will play a role in standards development prior to their submission to the Commission.

Initial Estimates anticipate that 2.5 FTE’s will review these revised Reliability standards at the Commission or a total cost of 2.5 x $126,384 = $315,960.³⁶

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

There are no changes to the reporting burden for the reasons stated above.

16. TIME SCHEDULE FOR THE PUBLICATION OF DATA

The filed proposed Reliability Standards are available on the Commission’s eLibrary document retrieval system in Docket No. RM06-16-000 and the Commission required that all Commission-approved Reliability Standards be available on the ERO’s website, with an effective date (http://www.nerc.com/~filez/nerc_filings_ferc.html).

Copies of the filings are made available to the public within two days of submission to FERC via the Commission's web site. There are no other publications or tabulations of the information.

17. DISPLAY OF THE EXPIRATION DATE

It is not appropriate to display the expiration date for OMB approval of the information collected. The information will not be collected on a standard, preprinted form which would avail itself to that display. Rather the Electric Reliability Organization must prepare and submit filings that reflect unique or specific circumstances related to the Reliability Standard. In addition, the information contains a mixture of narrative descriptions and empirical support that varies depending on the nature of the transaction.

18. EXCEPTIONS TO THE CERTIFICATION STATEMENT

Item No. 19(g) (vi) see Instruction No. 17 above for further elaboration. In addition, the data collected for this reporting requirement is not used for statistical purposes. Therefore, the Commission does not use as stated in item no. 19(i) "effective and efficient statistical survey methodology." The information collected is case specific to each Reliability Standard.

B. COLLECTION OF INFORMATION EMPLOYING STATISTICAL METHODS.

This is not a collection of information employing statistical methods.

1 The Energy Policy Act of 2005, Pub. L. No 109-58, Title XII, Subtitle A, 119 Stat. 594, 941 (2005), codified at 16 U.S.C. 824o (2000).

2 The Commission is not proposing any new or modified text to its regulations. As set forth in 18 CFR part 40, proposed Reliability Standards will not become effective until approved by the Commission, and the ERO must post on its website each effective Reliability Standard. The proposed interpretations would assist entities in complying with the Reliability Standards.

3 A Balancing Authority is defined as the responsible entity that integrates resource plans ahead of time, maintains load-interchange-generation balance within a Balancing Authority area, and supports interconnection frequency in real time. (see http://www.nerc.com/files/glossary.

4 Order No. 693 at P 357.

5 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.”

6 NERC Rules of Procedure, Appendix 3A, Reliability Standards Development Procedure, Version 6.1, at 26-27 (2007).

7 See 16 U.S.C. 824o(d)(5) (2006).

8 The Electric Power Outages in the Western United States, July 2-3, 1996, at 76 (ftp://www.nerc.com/pub/sys/all_updl/docs/pubs/doerept.pdf) and WSCC Disturbance Report, For the Power System outage that Occurred on the Western Interconnection August 10, 1996, at 4 (ftp://www.nerc.com/pub/sys/all_updl/docs/pubs/AUG10FIN.pdf).

9 Maintaining Reliability in a Competitive U.S. Electricity Industry, Final report of the Task Force on Electric System Reliability, Secretary of Energy Advisory Board, U.S. Department of Energy (September 1998), at 25-27, 65-67.

10 Report of the National Energy Policy Development Group, May 2001, at p. 7-6.

11 Order No. 693 at P 357.

12 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.

13 The voltage schedule is a target voltage to be maintained within a tolerance band during a specified period. [Footnote in original.]

14 When 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 associated Facility Ratings. [Footnote in original.]

15 See Order No. 693 at P 1901-07.

16 To be included in the compliance registry, the ERO determines whether a specific small entity has a material impact on the Bulk-Power System. If these small entities should have such an impact then their compliance is justifiable as necessary for Bulk-Power System reliability.

17 On July 21, 2008, the Commission approved a previous interpretation of BAL-003-0, Requirement R3, which requires each balancing authority to operate its automatic generation control on tie line frequency basis, unless such operation would diminish system interconnection reliability. See Modification of Interchange and Transmission Loading Relief Reliability Standards; and Electric Reliability Organization Interpretation of Specific Requirements of Four Reliability Standards, Order No. 713, 73 FR 43613 (July 28, 2008), 124 FERC ¶ 61,071 (2008).

18 NERC Petition at 6 (citing ERCOT request for interpretation at 1-2, available at http://www.nerc.com/docs/standards/sar/Request_Interpretation_BAL-003_ERCOT_27Jul07.pdf).

19 See NERC, Approval of ERCOT Waiver Request – Control Performance Standard 2 (Nov. 21, 2002), available at http://www.nerc.com/commondocs.php?cd=2 (under “Links to Regional Differences” tab), which was approved in Order No. 693 at P 314.

20 NERC Petition at 8.

21 Order No. 693 at P 370.

22 See id. at P 362, 370.

23 The Commission noted that NERC’s statement above could arguably be interpreted to suggest that the ERCOT methodology, by using a methodology that results in “the best level of automatic generation control action to meet control performance metrics,” may be a preferable methodology. That question is not before us, and thus we need not and do not address it. Should ERCOT wish to demonstrate that its alternate methodology under its Regional Difference is a superior alternate measure to that established under BAL-003-0, Requirement R5, ERCOT should pursue a Regional Difference supporting a departure from the requirement. While ERCOT is a single-balancing-authority Interconnection and does not need to allocate automatic generation control responsibility among balancing authorities, 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.

24 Dynegy’s request is provided in the NERC Petition, Exhibit B-3, along with the VAR-001-1 interpretation development record.

25 Dynegy request at 2 (citing NERC Rules of Procedure, section 302.5, “Each reliability standard shall be based upon sound engineering and operating judgment, analysis, or experience, as determined by expert practitioners in that particular field.”).

26 Id. at 4 (citing NERC Rules of Procedure, section 302.4).

27 NERC proposed Interpretation of NERC Standard VAR-001-1 at 1.

28 NERC Petition at 12-13.

29 Id. at 12 (emphasis in original).

30 Id. at 14.

31 Order No. 693 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 at P 324.

32 Id.; accord NERC Rules of Procedure, section 302.5.

33 See Order No. 693 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, 73 FR 7368 (Feb. 7, 2008), 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, 73 FR 1770 (Jan. 9, 2008), 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”).

34 Order No. 693 at P 275.

35 The term “Cybersecurity Incident” is defined as a malicious act or suspicious event that disrupts, or was an attempt to disrupt, the operation of those programmable electronic devices and communications networks including hardware, software and data that are essential to the Reliable Operation of the Bulk-Power System.

36 An FTE = Full Time Employee. The $126,384 “cost” consists of approximately $102,028 in salaries and benefits and $24,355 in overhead. The Cost estimate is based on the estimated annual allocated cost per Commission employee for Fiscal Year 2008.

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