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Federal Energy Regulatory Commission, NERC to hold Physical Security Conference in August

June 1, 2023

by Paul Ciampoli
APPA News Director
June 1, 2023

The Federal Energy Regulatory Commission and the North American Electric Reliability Corporation will convene a joint technical conference on August 10 to discuss physical security of the bulk power system, including the adequacy of existing physical security controls, challenges, and solutions.

The technical conference, which will be held at NERC’s headquarters in Atlanta, Ga., is being convened in response to a recommendation in NERC’​s recent report to FERC addressing the effectiveness of the existing NERC reliability standard on physical security – Critical Infrastructure Protection (CIP) reliability standard CIP-014. 

The American Public Power Association and several other trade groups recently voiced support for recommendations included in the NERC physical security reliability standards study.

Additional details related to the conference’s agenda and organization will be issued by FERC.

MMWEC, Public Power Entities Ask FERC to Force Disclosure on Charges

June 1, 2023

by Paul Ciampoli
APPA News Director
June 1, 2023

Massachusetts Municipal Wholesale Electric Company, leading a group of public power entities throughout New England, recently filed a motion at the Federal Energy Regulatory Commission asking that it force the disclosure of information “concerning the exorbitant charges being imposed on New England ratepayers under a fuel security cost-of-service agreement,” MMWEC said on May 22.

Joining MMWEC in the request are the Connecticut Municipal Electric Energy Cooperative, New Hampshire Electric Cooperative, Vermont Public Power Supply Authority, Energy New England, and a group of Massachusetts public power systems known collectively as the Eastern New England Consumer-Owned Systems.

In 2018, the region’s grid operator, ISO New England, executed a two-year agreement, which began June 1, 2022 and ends May 31, 2024, requiring the continued operation of Mystic Units 8 & 9, which are owned by Constellation Mystic Power, LLC. 

ISO-NE says that the units are needed to ensure regional “fuel security.” Mystic is paid under the agreement both its full cost of service and nearly all of the costs of Mystic’s affiliated liquefied natural gas fuel supplier, the Everett Marine Terminal.

MMWEC said the agreement protects customers against unreasonable fuel charges by requiring that ISO-NE audit Mystic’s fuel procurement practices. The audits are conducted to ensure that service under the agreement is being provided at the lowest possible cost.  

Over the first ten months of the two-year term of the Mystic agreement, consumers have been charged more than $436 million in fuel costs, most of which resulted from Constellation’s LNG purchases, and then selling at a loss, burning uneconomically, or otherwise disposing of fuel that it turns out Mystic did not need, MMWEC said in a news release.

“In the ten months since the Mystic agreement went into effect, the only document concerning the audits that ISO-NE has released is an uninformative, three-page summary of the conclusions of a consultant retained by the grid operator,” MMWEC said.

The consultant concludes that the charges are appropriate under the agreement, “but provides no insight into what MMWEC and the other public systems say is a key driver of the fuel-related charges: Mystic’s fuel purchasing decisions and the terms of its liquefied natural gas supply contracts.” 

The motion asks that FERC direct ISO-NE to release additional information concerning the variable charges passed through the agreement, including redacted copies of any reports, studies or other analyses produced by or for ISO-NE in connection with the audit.

In support of this request, the motion states that because of the paucity of data made public, neither FERC, the New England states, nor consumers have had the opportunity to assess what contributed to these charges and to determine if they are justified and reasonable. 

MMWEC and its supporters asked that FERC direct Mystic and ISO-NE to release data related to the excessive charges and continue to do so on a quarterly basis. 

The motion states that this information will help MMWEC and the public systems determine whether certain charges are warranted, whether there should be enhanced auditing, or if the agreement should be amended. 

MMWEC, joined by the New Hampshire Electric Cooperative, called FERC’s attention to the issue in a joint filing last December, in which they stated the charges had become much larger and more volatile than anticipated. 

Since that time, the charges have grown even larger, MMWEC said. In January and February 2023 alone, ISO-NE has passed on more than $220 million in charges under the agreement. The $120 million supplemental capacity payment to Mystic for January 2023 was more than a quarter of the value of the entire New England wholesale energy market for that month. 

The motion concludes by requesting that FERC direct Mystic and ISO-NE to release more robust and useful information about the basis “for the extraordinary charges and ISO-NE’s audit of them, as was promised during the 2018 proceeding in which Mystic and ISO persuaded FERC to approve the agreement.” 

MMWEC is a not-for-profit, public corporation and political subdivision of the Commonwealth of Massachusetts created by an Act of the General Court in 1975 and authorized to issue tax-exempt debt to finance a wide range of energy facilities. 

MMWEC provides a variety of power supply, financial, risk management and other services to the state’s consumer-owned, municipal utilities.

Senators Urge DOE to Reconsider Transformer Conservation Standards Proposal

June 1, 2023

by Paul Ciampoli
APPA News Director
June 1, 2023

The Department of Energy should reconsider its proposed rule to increase conservation standards for distribution transformers, 47 U.S. senators said in a June 1 letter to Secretary of Energy Jennifer Granholm. The bipartisan letter was led by Senator Bill Hagerty (R-TN).

On December 28, 2022, DOE announced it was proposing new energy efficiency standards for distribution transformers to improve the resiliency of the grid.

For over a year, the electric sector has been informing DOE about the severity of the supply chain challenges that have prolonged and complicated distribution transformer production and availability.

In announcing the proposed rule, DOE stated it “represents a strategic step to advance the diversification of transformer core technology, which will conserve energy and reduce costs. Almost all transformers produced under the new standard would feature amorphous steel cores, which are significantly more energy efficient than those made of traditional, grain-oriented electrical steel.”

“The availability of critical grid components remains a significant challenge for the electric power industry that could impact national security, grid reliability and resilience, as well as the ability to continue the important work of electrification and grid modernization,” the Senators wrote in their letter.

The proposed rule increases efficiency standards on distribution transformers, critical grid products, which currently are no less than 97.7% energy efficient, “at a time when the industry is struggling due to a significant increase in demand, supply chain issues, and skilled workforce shortage,” they said.

“These factors have made it hard for manufacturers to meet current demand for distribution transformers, creating challenging lead time conditions and concerns regarding grid reliability and resiliency,” the lawmakers noted.

“Further, the proposed rule has introduced uncertainty that prevents utilities from signing long-term contracts and manufacturers from making investment decisions,” the letter said.

The Senators noted that the proposed rule would require all distribution transformers to shift from the industry standard  grain-oriented electrical steel (GOES) cores to amorphous steel cores. GOES currently accounts for more than 95 percent of the domestic distribution transformer market and, therefore, manufacturers’ production lines are tooled for designs that use GOES.

“A final rule that adopts DOE’s current proposal could meaningfully worsen the current supply chain shortage by requiring manufacturers to change production lines to less readily available amorphous steel,” the Senators argued.

Currently, the United States only has one domestic producer of amorphous steel. “Moving to amorphous steel cores, as proposed by DOE, would require this sole domestic supplier to rapidly scale operations from its current market share of less than five percent to accommodate the entire distribution transformer market. Such a recalibration of the supply chain will further delay manufacturing production timelines – currently estimated to be a minimum of 18 months to two years,” the lawmakers said.

Between 2020 and 2022, average lead times to procure distribution transformers went from eight to 12 weeks to up to three years. “This multi-fold increase is directly impacting the electric power industry’s grid modernization and reliability efforts, as well as its ability to respond and recover from natural disasters, posing challenges for communities that need to rebuild as well as new development,” the Senators told Granholm.

Senators also expressed concern that requiring the use of amorphous steel for new distribution transformers could put the administration’s electrification goals at risk by exacerbating an existing grid vulnerability. “At the same time, we recognize the numerous and often underappreciated benefits of energy efficiency and support the overall goal of reducing wasteful electrical losses in our distribution grid.”

The lawmakers “believe the most prudent course of action is to let both GOES and amorphous steel cores coexist in the market, as they do today without government mandates, for new installations as we ramp up domestic production and reorient supply chains.”

They urged the DOE “to refrain from promulgating a final rule that will exacerbate transformer shortages at this strategically inopportune time. Such a standard could come at meaningful cost to grid reliability and national security, continuing the clean energy transition, and bolstering domestic supply chains and the workforce.”

Instead, they urged the Department to finalize a rule “that does not exacerbate the shortage in distribution transformers and convene stakeholders across the supply chain to develop consensus-based approach to setting new standards.”

Senators have also asked for a briefing “with your office on the path forward on DOE’s proposal, as well as how to best leverage existing DOE authority to bolster domestic supply chains and help alleviate the current and persisting supply chain challenges facing distribution transformers.”

Minnesota Agency, Public Power Utilities Get DOE Nod to Apply for Federal Energy Funds

June 1, 2023

by Paul Ciampoli
APPA News Director
June 1, 2023

A proposal by the Minnesota Department of Commerce, along with regional public power utility and electric cooperative partners, for over $240 million in federal energy funds has received the U.S. Department of Energy nod of approval to move forward with a full application. 

The funds would come from the Grid Resilience and Innovation Partnerships program if the DOE approves the final application, which was submitted May 19. The DOE is expected to announce awards later in 2023.  

The grid improvement proposal combines almost 300 projects involving small-scale utilities — rural cooperative, municipal owned, generation and transmission utilities — that would face significant challenges as individual projects to pursue federal funds, the Minnesota Commerce Department said on May 25.

The projects would serve communities with factors DOE defines as disadvantaged communities, such as being low income, rural, tribal, and geographically remote.

The Minnesota Department of Commerce Energy Resource Division staff has provided staff resources and time, as well as expertise in grant writing and technical assistance needed by the small utilities, to develop the consolidated proposal. 

Costs per project range between $360,000 to $54 million, with each project expected to ask for DOE federal funding to cover half the project costs. Combined, the projects would total more than $480 million. State funding may also be available to help some of the small utility projects through the State Competitiveness Fund, which passed the Minnesota Legislature in April 2023. 

The DOE joint proposal is a consortium, with the Minnesota Department of Commerce as lead state agency, along with multiple regional cooperatives (co-ops) and municipal utilities, and utility industry associations:

Projects proposed range from transmission system upgrades, infrastructure and tools to increase electricity generated by renewable energy, and innovative battery storage systems.

“The money allocated by GRIP would help consumer-owned electric utilities to implement innovative technologies to improve the grid in Minnesota and the region,” said Darrick Moe, CEO of MREA. Karleen Kos, CEO of MMUA, added, “We appreciate the collaboration of everyone on this proposal and the work of the Department of Commerce to get this done.” 

A key component of the joint proposal is to ensure disadvantaged communities in the region would benefit from the energy infrastructure investments.

The Justice40 Initiative, a stated federal government goal that at least 40% of the project benefits accrue to disadvantaged communities, is a component of GRIP funding. Justice40, and its foundation of equity in energy resources, is supported by the Minnesota Department of Commerce.

House Debt Limit Agreement Bill Includes Energy Permitting Reforms

May 30, 2023

by APPA News
May 30, 2023

A two-year budget deal released by House Republican leadership over the weekend that would lift the U.S. debt limit through 2024 includes energy permitting reforms.

The House is expected to take up the legislation on Wednesday, while the Senate is expected to  act later this week or over the weekend.

The Fiscal Responsibility Act includes the text of the BUILDER Act of 2023, which is sponsored by Congressman Garrett Graves (R-LA) and was included in the broader House-passed energy permitting reform bill, the Lower Energy Costs Act (H.R. 1).

APPA was generally supportive of the provisions in the BUILDER Act to modernize the National Environmental Policy Act.

The BUILDER Act section includes statutory reforms to the National Environmental Policy Act, including project threshold, interagency coordination and review deadlines to prevent project delay, limits on what qualifies as a major federal action, and limits to prevent agencies from missing statutory deadlines. These statutory changes are considered the first significant reforms to NEPA since 1982.

The  language would amend NEPA to clarify and narrow agency considerations to “reasonably foreseeable environmental impacts of the proposed agency action,” “reasonably foreseeable adverse environmental effects,” and “a reasonable range of alternatives to the proposed action that are technically and economically feasible and meet the purpose and need of the proposed action.”

The legislation would also codify key elements of the One Federal Decision Framework, including development by the lead agency of a joint schedule, procedures to elevate delays or disputes, and, to the extent practicable, preparation of a single environmental document. The legislation also sets reasonable page limits for environmental documents and reasonable time limits of one year for environmental assessments and 2 years for environmental impact statements. The bill provides a right of action to project applicants if statutory deadlines are not met.

With respect to NEPA thresholds and streamlining, the legislation includes threshold considerations for agencies assessing whether NEPA applies to a proposed activity. The bill also includes provisions facilitating agencies adopting categorical exclusions of other agencies through a streamlined process.

Also, a project sponsor would be allowed to assist agencies in conducting environmental reviews to help speed up the process and to resolve issues without taking control or authority away from the lead agency.

The legislation also:

Another section of the legislation would authorize the North American Electric Reliability Corporation to carry out, in consultation with regional operators, a study to examine total current transfer capabilities and provide recommendations to strengthen reliability and meet and maintain transfer capability between neighboring transmission regions.

The legislation also adds energy storage to this list of covered projects eligible for streamlining under the FAST Act and expedites the completion of the Mountain Valley Pipeline.

New Georgia Nuclear Unit Reaches 100 Percent Energy Output for First Time

May 30, 2023

by Paul Ciampoli
APPA News Director
May 30, 2023

Georgia Power announced on May 29 that Vogtle Unit 3 has safely reached 100 percent power, marking a major milestone towards commercial operation.

This milestone marks the maximum energy the unit is licensed to produce in the reactor core and is the first time the unit has reached its expected output of approximately 1,100 electric MW.

Southern Nuclear will operate Vogtle 3 and a second new unit, Vogtle 4, on behalf of the co-owners: Georgia Power, Oglethorpe Power and public power utilities MEAG Power and Dalton Utilities. MEAG Power is a 22.7% co-owner of Plant Vogtle, including the new units, while Dalton Utilities is a 1.6% co-owner of the plant.

Testing at the 100 percent power level is focused on the operation of the reactor, plant control systems for the reactor and support systems, and integrated plant operations. Plant performance is monitored at various conditions and data is gathered and evaluated by site engineers.

With the unit reaching full power for the first time, other tests must be performed at this power level before the unit is available for reliable dispatch in accordance with its combined operating license.

Once all startup testing is successfully completed and the unit is available for reliable dispatch, Vogtle Unit 3 will enter commercial operation.

Unit 3 is projected to be placed in service during June 2023.

Vogtle Unit 4 began receiving nuclear fuel this month. Since the first fuel delivery on May 3, 157 fuel assemblies necessary for the safe and reliable startup of Unit 4 have arrived by truck in shipping cannisters designed to transport non-irradiated uranium fuel assemblies. Hot functional testing for Unit 4 was completed on May 1.

Supreme Court Issues Major Decision Related to Clean Water Act

May 25, 2023

by Paul Ciampoli
APPA News Director
May 25, 2023

The U.S. Supreme Court on May 25 issued a decision that involves the scope of the Clean Water Act and, more specifically, whether an appeals court set forth the proper test for determining whether wetlands are “waters of the United States” under the CWA.

The ruling, in Sackett v. EPA, is based on an appeal by a family of the U.S. Court of Appeals for the Ninth Circuit’s ruling that they needed a Clean Water Act permit to build a home on their property. The court ruled in a 9-0 opinion that the wetlands on the property are not subject to CWA jurisdiction. 

The decision will have significant implications for the Biden Administration’s 2023 Water of the United States (WOTUS) Rule, the various cases challenging that rule, and CWA implementation going forward.    

In January 2022, the Supreme Court agreed to consider the case. The U.S. Court of Appeals for the Ninth Circuit had held that then-Justice Anthony Kennedy’s “significant nexus” test from Rapanos v. United States and not the Rapanos plurality’s “relatively permanent waters” standard, determined whether wetlands are subject to CWA regulation.

The court’s opinion essentially adopts the Rapanos et al. v. The United States, 547 U.S. 715 (2006) plurality’s “continuous surface connection” standard authored by Justice Antonin Scalia, rejects the “significant nexus” test described in Justice Kennedy’s concurring opinion in Rapanos, and reverses the Ninth Circuit holding that the wetlands on the Sacketts’ property are jurisdictional. 

The justices held that the CWA extends to only those wetlands that are “as a practical matter indistinguishable from waters of the United States.”

This requires the party asserting jurisdiction over adjacent wetlands to establish “first, that the adjacent [body of water constitutes] . . . ‘water[s] of the United States,’ (i.e., a relatively permanent body of water connected to traditional interstate navigable waters); and second, that the wetland has a continuous surface connection with that water, making it difficult to determine where the ‘water’ ends and the ‘wetland’ begins.”

More specifically, with respect to wetlands, the court held that the definition of WOTUS includes only those wetlands that have a continuous surface connection to other jurisdictional waters. Adjacent wetlands are included within WOTUS if they are indistinguishably part of a body of water that itself is a water under the CWA.  

As a result, the court found that the Environmental Protection Agency’s position — that adjacent wetlands are jurisdictional when they possess a significant nexus to traditional navigable waters and that wetlands are “adjacent” when they are “neighboring” — lacks merit. 

Public power utilities have had long-standing concerns over any expansion to the definition of WOTUS. The ruling offers some measure of clarity while still ensuring environmental protection.

Groups Ask EPA to Extend Comment Period for Greenhouse Gas Emissions Proposed Rule

May 25, 2023

by Paul Ciampoli
APPA News Director
May 25, 2023

The American Public Power Association and the National Rural Electric Cooperative Association are asking the Environmental Protection Agency to allow for an additional 60 days for parties to comment on an EPA proposed rule to limit greenhouse gas emissions from new and existing fossil fuel-fired electric generating units.

EPA published the proposed rule on May 23 and provided a 60-day public comment period that will end on July 24, 2023.

In seeking an extension of the comment period, APPA and NRECA noted that the proposal has significant economic and operational implications for the electric sector.

“There is a substantial amount of material to review to fully understand EPA’s proposal and provide meaningful comment. The proposal includes the 181-page proposed rule, a 359-page regulatory impact analysis, and references several technical supporting documents that have yet to be posted to the rulemaking docket,” they said.

EPA has also solicited comment on dozens of various topics in the proposed rule preamble. “The Associations and their members need additional time to evaluate EPA’s proposal, the supporting documents and analyses, and develop responses to EPA’s requests for comment.”

In addition to the proposed rule, there are currently open comment periods on other complex EPA proposed rules directly affecting cooperatives and public power utilities, the groups noted.

“These concurrent comment periods on five other extremely technical and significant proposed rules create challenges as cooperatives and public power utilities work to thoughtfully respond to each proposal.”

APPA and NRECA also said that when EPA first proposed New Source Performance Standards or fossil fuel-fired electric generating units in 2014, it provided a 120-day comment period following a 60-day extension.

“And when EPA proposed emissions guidelines for existing sources later that year, the agency’s initial 120-day comment period was later extended by an additional 45 days. Importantly, those comment periods were not concurrent – the NSPS comment period ended more than a month before the comment period for the proposed emissions guidelines opened.”

Providing half of that comment period “on this most recent power plant proposal would be woefully insufficient for the type of input EPA has requested, particularly because the package includes five actions in one.”

APPA and NRECA therefore requested a 60-day extension of the comment period. “Providing an extension of the comment period will allow all stakeholders additional time to analyze the proposal and provide more thoughtful comments.”

APPA Urges FERC to Keep Affordability in Mind as it Considers Interregional Transfer Capability

May 24, 2023

by Paul Ciampoli
APPA News Director
May 24, 2023

As the Federal Energy Regulatory Commission explores avenues for promoting interregional transfer capability development, it is essential that the Commission recognize the importance of maintaining affordability for load-serving entities and their customers, the American Public Power Association said in recent comments submitted to FERC.

APPA’s May 15 comments were submitted in response to a late 2022 FERC workshop on interregional transfer capability, or ITC.

APPA said it agrees that the nation needs additional bulk transmission facilities to accommodate new resources, to replace aging infrastructure, and to promote reliability and resilience. APPA further agrees that ITC is likely to be part of the solution for achieving these goals.

The workshop, as well as the lessons learned from Winter Storm Uri, document potentially significant benefits from interregional transfers, it said.

“Although regions are making progress in planning interregional capacity, APPA recognizes that the current Order No. 1000 rules have resulted in relatively few interregional projects,” it may be worthwhile to consider reforms to existing planning processes to help promote the development of beneficial interregional capacity, APPA said.

“At the same time, public power utilities are extremely concerned about additional transmission cost increases, and any consideration of policy changes to promote ITC must recognize the importance of maintaining affordability for LSEs and their customers,” the group told FERC.

“Part and parcel of maintaining affordability is ensuring that increases in ITC are evaluated in open and transparent planning processes to ensure cost-effectiveness, taking into account particular regional factors. Further, public power utilities should not be assigned costs of transmission facilities from which they derive little or no demonstrable reliability or economic benefits,” APPA said.

The Commission could best accommodate these various considerations by directing any ITC policy reforms toward existing regional planning processes rather than mandating a minimum level of ITC.

Much of the discussion at the workshop centered on the question of whether the Commission should specify a minimum level of ITC, or a metric for identifying a minimum ITC, that each region must maintain.

APPA said that the workshop record, while pointing to potential benefits of ITC, identified significant practical and legal challenges associated with establishing a reasonable generic minimum requirement. Given these substantial challenges, APPA urged the Commission not to pursue a generic minimum ITC requirement.

A one-size-fits-all minimum transfer capability requirement “that does not appropriately account for regional conditions and needs could also raise significant cost allocation objections, which in turn, could slow the interregional transmission development that any minimum requirement aims to encourage,” APPA said.

If the Commission pursues policy reforms to promote ITC development, APPA recommended that the Commission focus on a process for identifying beneficial interregional capacity, as opposed to mandating a minimum amount of capability (or adopting a formula to determine a minimum amount of ITC).

“Specifically, the Commission could consider modifying its existing regional planning process requirements to require transmission planners to identify ITC as a regional need that must be considered in the regional planning process,” APPA said.

Consistent with recommendations at the workshop, the Commission could facilitate this process by identifying a set of principles that each region should consider in evaluating how much ITC may be appropriate and reasonable for the region.

“APPA submits that such principles should focus primarily on potential reliability-related benefits of ITC, while allowing regions flexibility in the factors they will consider in evaluating an appropriate level of ITC.”

Any principles articulated by the Commission should not mandate any particular level of ITC and/or require the expansion of transmission facilities, APPA said.

Under the approach recommended by APPA, each region, as part of the regional transmission planning process, would identify the ITC needs the region will plan for as part of its regional transmission planning process, consistent with the principles established by the Commission.

Any required process to identify the need for ITC, and plan for it, would need to include transparent criteria for assessing its costs and benefits.

Leveraging existing Order No. 1000 regional planning processes, regions could identify transmission solutions (or non-transmission alternatives) to meet the identified levels of beneficial ITC.

“Consideration of ITC in the regional planning process could also inform the interregional planning process focused on identifying potential interregional projects, subject to existing Order No. 1000 interregional coordination principles, including the requirement that interregional projects must be evaluated jointly, and the prohibition on a region involuntarily imposing an interregional transmission project on another.”

Consistent with Order No. 1000, inclusion of a project in a regional or interregional plan would not require any entity to construct the facilities.

Under the approach outlined by APPA, regions would also have the option of developing cost allocation methodologies for Transfer Transmission Facilities or other investments to meet beneficial ITC objectives, or regions could rely on existing cost allocation approaches. Consistent with Order No. 1000, one region should not be able to involuntarily assign costs to a neighboring region, APPA told FERC.

Groups Voice Support for Recommendations in NERC Physical Security Reliability Standards Study

May 24, 2023

by Paul Ciampoli
APPA News Director
May 24, 2023

The American Public Power Association and several other trade groups recently voiced support for recommendations included in a North American Electric Reliability Corporation physical security reliability standards study.

The recommendations in the NERC report appropriately reflect a risk-based approach to physical security of the bulk power system, while offering reasonable suggestions for further action or analysis on certain specific issues, including a Commission technical conference, and clarification of the risk assessment requirement in Reliability Standard CIP-014, the groups said in their May 15 comments.

Joining APPA in the comments were the Edison Electric Institute, Large Public Power Council, the National Rural Electric Cooperative Association and the Transmission Access Policy Study Group.

The report was filed by NERC on April 14, 2023 in response to a December 2022 Commission order.

“With Trade Association members having been the target of recent attacks, all members are acutely aware of the physical threats posed to the grid,” the groups said. “Effective protective measures are indeed necessary, and the Trade Associations’ members are taking those measures.”

The groups noted, however, the particular challenge of developing and implementing a reliability standard that addresses the highly varied physical and electrical characteristics of the facilities that comprise the BPS.

“As currently conceived, CIP-014 appropriately reflects this reality. CIP-014 applies only to a well-defined set of transmission facilities and associated control centers that are likely to be critical to BPS reliability,” APPA and the other groups said.

They agree with NERC’s conclusion that the current CIP-014 framework remains appropriate. “Reasonably, CIP-014 does not cover all facilities nor seek to mitigate all threats and vulnerabilities to facilities in the BPS. Instead, the risk-based approach responds to reasonably assessed risks to the BPS, while weighing the cost of what otherwise might be an infinite number of measures that responsible entities might take to mitigate physical security risks.”

The groups specifically agree with NERC’s conclusion that CIP-014’s applicability criteria are adequate to identify the subset of “critical” transmission facilities that should be assessed, and with NERC’s recommendation that the CIP-014 applicability criteria not be changed at this time.

The groups also support NERC’s recommendation to establish a technical conference to examine:

The type of substation configurations that should be studied to determine whether any additional substations should be included in CIP-014’s applicability criteria in the future, and

Whether a particular combination of reliability, resiliency, and security measures could be effective in mitigating the impact of physical security attacks.

On the question whether a minimum level of physical security protection is needed, the groups said they agree with NERC that a uniform, bright-line minimum level of security protections would be counterproductive.

APPA and the other groups “also recognize that a technical conference enabling stakeholders to engage in discussions on this matter and to exchange ideas on how to address evolving threats and security risks would be quite valuable,” they told FERC.

The groups said they also understand the thinking behind NERC’s intent to initiate a standard authorization request to examine risk assessment methodologies under CIP-014, the cases employed in assessing risk and to clarify required documentation and the treatment of adjacent substations of differing ownership within line of sight of each other.