The proposed “Version 4” CIP Standards provide a new framework for the identification and protection of Critical Cyber Assets that support the Bulk-Power System.  The new Version 4 CIP Standards would replace the currently-effective Version 3 CIP Standards. 

FERC stated that the proposed Version 4 CIP standards would provide three general changes: (1) Version 4 will result in the identification of certain types of Critical Assets that may not be identified under the current approach; (2) Version 4 eliminates Responsible Entities’ discretion in identifying Critical Assets by requiring the use of the 17 bright line criteria to identify Critical Assets; and (3) Version 4 provides a level of consistency and clarity regarding the identification of Critical Assets.

The NOPR proposes to modify CIP-002-4 to include 17 “bright line” criteria for the identification of Critical Assets, instead of using the current risk-based assessment methodology in CIP-002-3.  Specifically, proposed Reliability Standard CIP-002-4 contains three requirements:

1.  Requirement R1 provides that each Responsible Entity must annually develop a list of its identified Critical Assets using 17 specified criteria;
2. Requirement R2 provides that each Responsible Entities must develop a list of Critical Cyber Assets associated with the Critical Assets identified pursuant to R1.  The proposed R2 does not change the qualifications of a Critical Cyber Asset. However, in the context of generating units at a single plant location, R2 limits the designation of Critical Cyber Assets only to Cyber Assets shared by a combination of generating units whose compromise within 15 minutes result in the loss of generation capability equal to or higher than 1,500 MW; and
3. Requirement R3 provides that a senior manager or delegate for each responsible entity approve annually the list of Critical Assets and the list of Critical Cyber Assets, even if the lists contain no elements.

Proposed Reliability Standards CIP-003-4 through CIP-009-4 contain only changes to conform with CIP-002-4. 

The Commission also proposed to approve Violation Risk Factors (“VRF”) and Violation Severity Levels (“VSL”) with modifications. The Commission proposed to direct NERC to modify the proposed VSLs for CIP-002-4, Requirements R1 and R2, to address a failure of a Responsible Entity to identify either Critical Assets or Critical Cyber Assets.  This would include a failure to identify a Critical Asset, whether inadvertently or through misapplication of the bright line criteria.

The Commission proposed to adopt NERC’s implementation plan and effective date for full compliance with the Version 4 CIP Standards of the first day of the eighth calendar quarter after applicable regulatory approvals have been received. The Commission stated that the Version 4 CIP Standards are an interim step, and directed the electric industry and NERC to develop an approach to cybersecurity to ensure that the electric grid can withstand a cybersecurity incident. 

Comments on the NOPR are due 60 days after publication in the Federal Register.

A copy of the NOPR is available here.

Final Rule on TOP-001-1

In this Order, FERC adopted a final rule approving NERC’s interpretation of Transmission Operations Reliability Standard TOP-001-1 (Reliability Responsibilities and Authorities), Requirement R8, that the balancing authority is responsible for restoring real power balance and the transmission provider is responsible for restoring reactive balance during a system emergency.

On July 16, 2010, NERC submitted a petition requesting that FERC approve NERC’s interpretation of Requirement R8 of Reliability Standard TOP-001-1 in response to a request from Florida Municipal Power Pool.  On April 21, 2011, the Commission issued a NOPR proposing to approve NERC’s interpretation.  In this Order, the Commission adopts the NOPR proposal and approves NERC’s interpretation of TOP-001-1, R8, as follows:

Question: Balancing real power is not a function of a [Transmission Operator] and balancing reactive power is not a function of a [Balancing Authority]. For Requirement R8 is the Balancing Authority responsibility to immediately take corrective action to restore Real Power Balancing and is the [Transmission Operator] responsibility to immediately take corrective action to restore Reactive Power Balance?

Response: The answer to both questions is yes. According to the NERC Glossary of Terms Used in Reliability Standards, the Transmission Operator is responsible for the reliability of its “local” transmission system, and operates or directs the operations of the transmission facilities. Similarly, the Balancing Authority is responsible for maintaining load-interchange-generation balance, i.e., real power balance. In the context of this requirement, the Transmission Operator is the functional entity that balances reactive power. Reactive power balancing can be accomplished by issuing instructions to the  Balancing Authority or Generator Operators  to alter reactive power injection. Based on NERC Reliability Standard BAL-005-1b Requirement R6, the Transmission Operator has no requirement to compute an Area Control Error (ACE) signal or to balance real power. Based on NERC Reliability Standard VAR-001-1 Requirement R8, the Balancing Authority is not required to resolve reactive power balance issues. According to TOP-001-1 Requirement R3, the Balancing Authority is only required to comply with Transmission Operator or Reliability Coordinator instructions to change injections of reactive power.

A copy of the final rule is available here.

Final Rule on TPL-002-0

In this Order, FERC adopted a final rule approving NERC’s interpretation of Transmission Planning Reliability Standard TPL-002-0 addressing system performance following loss of a single bulk electric system element.

On November 17, 2009 NERC submitted a petition requesting that FERC approve NERC’s interpretation of Requirement R1.3.10 of Reliability Standard TPL-002-0 (System Performance Following Loss of a Single Bulk Electric System Element). In March 2010, FERC issued a NOPR proposing to reject NERC’s interpretation.  However, after evaluating comments received in response to the NOPR, FERC declined to adopt the NOPR and adopted NERC’s interpretations of TPL-002-0 in response to three questions from PacifiCorp, as follows:

Question 1:  Does TPL-002-0 R1.3.10 require that all elements that are expected to be removed from service through normal operation of the protection systems be removed in simulations?

Response 1:  TPL-002-0 requires that System studies or simulations be made to assess the impact of single Contingency operation with Normal Clearing. TPL-002-0, R1.3.10 does require that all elements expected to be removed from service through normal operations of the Protection System be removed in simulations.

Question 2: Is a Category B disturbance limited to faults with [N]ormal [C]learing where the protection system operates as designed in the time expected with proper functioning of the protection system(s) or do Category B disturbances extend to protection system misoperations and failures?

Response 2: This standard does not require an assessment of the Transmission System performance due to a Protection System failure of Protection System misoperation. Protection System failure of Protection System misoperation is addressed in TPL-003-0—System Performance following Loss of Two or More Bulk Electric System Elements (Category C) and TPL-004-0—System Performance Following Extreme Events Resulting in the Loss of Two or More Bulk Electric System (BES) Elements  (Category D).

Question 3: Does TPL-002-0, R1.3.10 require that planning for Category B [C]ontingencies assume a [C]ontinency that results in something other than a [N]ormal [C]learing event even though the TPL-002-0 Table I-Category B matrix uses the phrase “SLG or 3-Phase Fault, with Normal Clearing?”

Response 3: TPL-002-0, R1.3.10 does not require simulating anything other than Normal Clearing when assessing the impact of a Single Line Ground (SLG) or 3-Phase (3Ø) Fault on the performance of the Transmission System.

In addition, the Commission directed NERC and Commission Staff to initiate a process to identify any reliability issues. The Commission also directed NERC to make an informational filing within 6 months of the date of the issuance of the Final Rule on whether there is a further system protection issue, how it should be addressed, and what priority it should be accorded relative to other reliability initiatives planned by NERC.

A copy of the final rule is available here.

In 2009 and again in 2010, the U.S. Army Corps of Engineers questioned NERC’s ability to assess penalties against federal agencies.  In each of those cases, however, the reliability standard violation penalty was zero dollars.  In the instant case of SWPA, the penalty amount is $19,500.

In their application for review, SWPA and the DOE argued that the plain language of the Federal Power Act (“FPA”), and section 316A “expressly limits” application of civil penalties to “persons,” a term that excludes the federal government.  SWPA and DOE further argued that section 215(e) of the FPA does not create independent penalty authority, as NERC argued in its July 28, 2011 NOP.   SWPA and DOE went on to argue that even if the Commission finds that the FPA is ambiguous, the doctrine of sovereign immunity prevents the expansion of the FPA’s penalty authority beyond the plain language of the statute. 

Additionally, SWPA and DOE argued that the Commission should decline to impose monetary penalties against a federal agency as a matter of policy, even if it has the authority to do so.  NERC argued in its NOP that if federal entities are excluded from the enforcement regime and do not face the threat of monetary penalties, there is “increased risk to the reliability of the bulk power system and potential for an incident caused by an agency of the United States.”  NERC found this reliability risk to be inconsistent with the legislative history of section 215 of the FPA.

The Commission will review the NOP and the proposed penalty is stayed pending the conclusion of the Commission’s review.

A copy of the NOP is available here.

A copy of SWPA and DOE’s application for review is available here.

A copy of FERC’s order initiating review is available here.

Commissioner Moeller offered his thoughts on several trends in the power industry; both past trends and future developments.  First, Mr. Moeller suggested that over the past year the power industry, FERC, and NERC have begun to work together better than previously, and this is a trend he believes needs to continue to ensure reliability of the bulk power system.  Secondly, Commissioner Moeller stated that FERC and NERC need to find a way to deal with the thirty-two month backlog of violations that has piled up.  Next, he noted that state policies have created regional crises.  These crises could be mitigated if FERC had full backstop siting authority for electric transmission. 

Commissioner Moeller went on to briefly discuss an eighteen month Berkley Lab study that began in May 2009 on demand response that exposed how fragile the Eastern Interconnect is to real vulnerabilities.  The Commissioner also stated that cyber-security will need strong standards, and right now state renewable portfolio standards (“RPS”) are colliding with the public interest.  Specifically, Moeller mentioned the recently passed California RPS and how it will be implemented.  Finally, Commissioner Moeller spoke about the EPA’s eight rulemakings that will affect coal-burning power plants.  The major problem with the eight rules is that the quick timeline in which they are likely to be offered will create uncertainty in the industry.  Additionally, Mr. Moeller suggested that there need to be incentives in place in order to compensate older plants or reliability must-run plants in the face of compliance with EPA’s rules. 

Gerry Cauley discussed NERC’s focus on ensuring reliability as well as their commitment to holding entities accountable for ensuring the reliability of the bulk power system.  He believes that the industry, NERC, and FERC need to continue to share information and issues with each other as a community to ensure reliability.  Cauley also stated that currently the CEO risk priorities are: mix-operation of relay and control systems, human errors, incomplete voice communication and right of way maintenance and clearance.  He then stated that NERC needs to improve the process for passing better standards.  Finally, Cauley offered five critical success factors for NERC: (1) standards need to be approached from a risk management perspective, (2) compliance needs be prioritized and fully evaluated, (3) mitigation plans must be implemented and followed, (4) event analysis and investigation should be conducted, and (5) critical infrastructure in general needs to be improved with a focus on both resilience and protection.

On February 14, 2011, FERC issued an order to staff to initiate an inquiry into these outages and disruptions. (See February 18, 2011 edition of the WER).  

According to FERC’s May 9, 2011 news release, FERC and NERC have been sharing information, and will issue a joint report on their finds and recommendations. 

A copy of the Commission’s news release is available here.