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November 17, 2024

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FERC Approves Cost Allocation for $5 Billion in PJM Transmission Expansion

FERC on April 8 approved PJM’s cost allocation for a $5 billion slate of transmission upgrades aimed at resolving reliability violations posed by growing data center load in Northern Virginia and generation retirements in Maryland (ER24-843). 

The commission dismissed as out-of-scope protests filed by the Maryland ratepayers and the state Office of People’s Counsel that Virginia should bear the full cost of transmission upgrades to serve data center load. The OPC argued the proliferation of data centers in Loudoun County and the surrounding area — known as Data Center Alley — has been fueled by incentives provided by Virginia and that the transmission needed should be classified as a public policy objective with the costs fully assigned to that state. 

Several Maryland residents urged the commission to initiate a proceeding under Section 206 of the Federal Power Act to consider whether the PJM cost allocation process remains just and reasonable, also arguing that the data centers are the result of Virginia’s policy objectives. They also argued that the stakeholder process is unfriendly to the participation of average consumers. 

The PJM Board of Managers approved the projects to become part of the RTO’s Regional Transmission Expansion Plan (RTEP) on Dec. 11, greenlighting new lines from the 502 Junction and Otter Creek substations in Pennsylvania, through Maryland and into Northern Virginia. Additional lines will supply power to the Alley from Dominion Energy’s Morrisville substation in Southern Virginia, and from the Peach Bottom substation in Pennsylvania to the Baltimore area to resolve violations related to the retirement of the 1,295-MW Brandon Shores coal generator. (See PJM Board Approves $5 Billion Transmission Expansion.) 

The commission said its review of the cost allocation for RTEP projects is limited to whether PJM correctly applied its tariff. The issues raised by the OPC and ratepayers around the mechanisms by which PJM determines cost allocation are beyond the scope of its review and more appropriately would be considered through a separate complaint that the RTO’s tariff is not just and reasonable. 

Even were a complaint to be filed, the commission expressed skepticism regarding the concept of assigning states the cost of building transmission to serve growing load, even that which may be the result of state incentives. It said the State Agreement Approach is the only structure for assigning transmission costs to an individual state and only if it voluntarily agrees to pay those costs to facilitate its public policy objectives. 

Commissioner Allison Clements wrote a concurrence going further, arguing that determining which transmission needs are the result of discrete state policies for the purpose of cost allocation would run contrary to the principles of regional transmission planning and would be “impractical and unworkable.” 

The OPC’s “argument also overlooks the reality that myriad state and local (and, for that matter, federal) public policies affect either the demand for or supply of electric power,” Clements wrote. “Virginia is certainly not the only state with economic development policies that are increasing the demand for power. Likewise, every state makes policy and/or regulatory decisions that affect which generating facilities provide supply to meet demand. Assigning transmission costs by attempting to parse countless public policies to determine whether and how each contributes to the need for transmission by affecting demand or supply in the power system is an impractical task that is not required by the Federal Power Act.” 

Commissioner Mark Christie also concurred, as PJM followed its tariff, but he argued there may be merit to deeper consideration of how state policies affect RTOs’ transmission planning. 

“I believe that the time has come for this commission to take the lead in its convening role to initiate a proceeding, such as a Notice of Inquiry, a series of technical conferences or by initiating an FPA Section 206 proceeding outside this docket, posing such important questions, among others, as: What is the proper definition of a public policy transmission project? Does the definition of public policy transmission project need to be changed for purposes of regional cost allocation? How should public policy transmission projects be cost allocated in a multistate RTO?” Christie wrote.  

“In my view the states themselves need to be at the forefront of deciding these questions, as it is their own state policies that are largely making these questions unavoidable, as these two recent PJM RTEP cases graphically illustrate,” he said. 

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NERC Tries Again with Revised INSM Standard

NERC is taking the pulse of industry again on its latest revisions to a proposed reliability standard requiring utilities to implement internal network security monitoring (INSM) after stakeholders rejected an attempt to pass the standard in March. 

The ballot period for CIP-015-1 (INSM) will run from April 12-17, according to the page for Project 2023-03, which is developing the standard. A formal comment period for the standard began April 5 and will also end April 17.  

In an email to stakeholders April 11, NERC said the project team had updated the redline version of CIP-015-1 after the comment period began because Requirement R1 of the redline used “security systems” instead of “cyber systems.” The updated redline is consistent with language in the clean version of the standard. 

Balloting and comments for the most recent update to CIP-015-1 closed March 18, with stakeholders delivering a 48.52% segment-weighted vote in favor. A two-thirds majority is needed for passage. (See Industry Sends Back NERC Cyber Monitoring Standards.)  

It was the first ballot for CIP-015-1 but the second for the entire project, because the original formal comment and ballot period that ended in January concerned a different standard conceived as a modification of CIP-007-6 (Cybersecurity — systems security management). The team decided to create a new standard after the ballot for CIP-007-6 was rejected overwhelmingly by industry with a segment-weighted vote in favor of just 15.42%. 

The quick turnaround to a new comment period is a reflection of the tight deadline NERC is working under; FERC ordered the ERO in 2023 to submit standards requiring INSM by July 9 of this year (RM22-3). (See FERC Orders Internal Cyber Monitoring in Response to SolarWinds Hack.) NERC’s Standards Committee voted at its February meeting to reduce comment and ballot periods for the project to as little as 10 days to meet FERC’s target, having already approved shortening to 20 days in August. 

In the comment form for the standard, the team for Project 2023-03 outlined some of the changes made to the latest version of the standard. These include relatively minor alterations, such as adding generator owners to the list of applicable entities after inadvertently excluding it from the previous posting, in addition to more substantial revisions. 

For example, requirement R1 and the associated metric both were revised, with language expanded and abbreviations removed “for consistency and clarity” regarding the methods by which entities should monitor network data activity for anomalous activity. Similarly, revisions to requirement R2 clarified the types of INSM data that entities should protect, and R3 was modified with a note that entities are “not required to retain detailed [INSM] data … that is not relevant to anomalous network activity” identified in other requirements. 

If the standard meets the threshold for approval in this ballot round, the next step will be a five-day final ballot (shortened from the usual 10 days), after which the standard will be submitted to NERC’s Board of Trustees for adoption. The next board meeting is scheduled for May 8. 

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Virtual Power Plants Could Save Calif. $750M a Year, Study Says

California could save more than $750 million a year in power costs through increased use of virtual power plants (VPPs), according to a new study by The Brattle Group and GridLab. 

The study found that more than 7,500 MW of VPP capacity could be deployed cost-effectively across California over the next decade, accounting for more capacity than the state’s largest power plant or the peak demand of Los Angeles.  

“By 2035, California’s VPP potential will exceed 15% of [statewide] peak demand. That’s five times the existing capability,” the study, which examines VPP deployment potential by 2035, reads. “By providing these services to the power system, VPPs can make significant contributions to grid reliability while directly compensating those consumers who participate.” 

Changing weather conditions, increasing loads, dependance on intermittent generation and growing demand for electrification are just some of the factors that have stressed California’s ability to meet its resource adequacy requirements in a timely and cost-effective manner, the report said.  

VPPs use an aggregated network of distributed energy technologies such as batteries and electric vehicle chargers to feed power back into the system and provide financial incentive to participating customers. The idea is that, in addition to increasing reliability, virtual systems reduce reliance on fossil fuels during times of peak demand.  

Almost all the state’s VPP capacity is traditional demand response, only a fraction of which is used to provide resource adequacy, the study says. But California is pushing for the increased adoption of VPPs with Senate Bill 1305, which would require the state’s Public Utility Commission to establish a VPP capacity procurement requirement by March 2026.  

And new technologies are emerging. Last year, Sunrun, a residential solar installer, partnered with Pacific Gas and Electric to enroll 8,500 residential battery owners in a VPP that provided nearly 30 MW of power during summer evenings. Also last year, the Sacramento Municipal Utilities District partnered with Ford, BMW and GM to develop a pilot that manages the charging of participating EVs to minimize costs to the power system.  

Study Scope

Researchers focused the study on five dispatchable consumer technologies: smart thermostat-based air-conditioning control, behind-the-meter batteries, residential EV charging, grid-interactive water heating, and automated demand response (auto-DR) for large commercial buildings and industrial facilities. 

The study employed a FLEX model, designed by The Brattle Group to assess load flexibility potential, to determine that all five technologies would contribute to peak demand reduction. Batteries, EVs and electric water heating could aid in load shifting, while smart thermostats and auto-DR could reduce energy consumption and save money.  

Roughly $550 million in system savings would be retained by customers, the study found. Broken down, VPPs would avoid $417 million in generating capacity, $194 million in transmission, $107 million in energy and $37 million in distribution. A household participating in all four residential VPP options considered could receive participation payments of $500 to $1,000 per year.  

While not quantified in the study, researchers also found that VPPs could help to reduce lengthy resource interconnection delays and “unprecedented uncertainty” in load forecasting.  

The Brattle Group also pointed to VPP options not considered in the study that could increase capacity potential, including vehicle-to-grid technologies, targeted energy efficiency, smart panels and thermal energy storage.  

The advancement of VPPs would rely on customer participation.  

“The share of customers that adopt flexible technologies such as EVs, batteries and smart thermostats over the next decade will establish the foundation for VPP program eligibility. The state will need a persistent focus on advancing policies that promote adoption in these areas for our potential estimates to materialize,” the report reads.  

Greater reliance on VPPs also would require more frequent use of said resources. Achieving 7,500 MW of net peak demand reduction would require 114 hours of VPP dispatch per year, six consecutive hours of dispatch on the peak day, and five months of the year, the study estimated.  

“By improving the utilization of distributed energy technologies, VPPs reduce the need for new grid resources that otherwise would sit unused for many hours of the year,” the study reads. “If this vision is achieved, the result will be a reliable and more affordable power grid for Californians.”  

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Cardinal-Hickory Creek Developers Appeal Injunction on Line’s Final Mile

Two of the developers behind the embattled Cardinal-Hickory Creek transmission line have appealed to lift an injunction on the last mile of the project that will intersect a wildlife refuge in Wisconsin and Iowa.  

ITC Midwest and Dairyland Power Cooperative filed last week with the 7th U.S. Circuit Court of Appeals to rescind a preliminary injunction on the 345-kV line issued in the U.S. District Court for Western Wisconsin.

The decision last month halted a land swap between the utilities and the U.S. Fish and Wildlife Service (FWS) to trade more than 35 acres in Wisconsin for almost 20 acres of the Upper Mississippi River National Wildlife and Fish Refuge in Iowa, which will be cleared for construction of the line’s final 1.1 miles. (See Judge Pauses Final Mile of Controversial Cardinal-Hickory Creek through Wildlife Refuge.)  

Line developers ITC Midwest and Dairyland are asking the court to expedite treatment of their request.  

The utilities said lifting the injunction and allowing construction on the last mile of the line “would replace existing lines now located in a much more environmentally sensitive area” of the Upper Mississippi River Wildlife and Fish Refuge. They also argued that the injunction lacked sound reasoning and relied on previously vacated findings and that the district court “erroneously presumed entitlement to injunctive relief.”  

The two also said plaintiffs Driftless Area Land Conservancy, Wisconsin Wildlife Federation and National Wildlife Refuge Association have overstated the impact of construction on the refuge. ITC and Dairyland said the area where the final swath of towers will be erected is “already fragmented by an existing road, maintains little to no wildlife or habitat value, is difficult to maintain and contains invasive reed canary grass.” 

ITC and Dairyland said that as a consequence of the preliminary injunction, Cardinal-Hickory Creek cannot meet its anticipated June 28 in-service date, and a revised date cannot be set until “further developments occur in the pending litigation, including a termination of the injunction, allowing for closing on the land exchange with the U.S. Fish and Wildlife Service.” The two said once the land swap occurs and a new construction schedule is established, the line could be in service within four to six months.  

“As long as the orders remain in place, the improved reliability and reduced electricity costs MISO envisioned will be foregone,” the two wrote, referring to Cardinal-Hickory Creek’s inclusion as part of MISO’s 2011 multivalue transmission portfolio.  

The utilities continue to assert that the parcel exchange will “provide significant net benefits” to the Upper Mississippi River National Wildlife and Fish Refuge. 

“We have a responsibility to get the Cardinal-Hickory Creek project in service as soon as possible so it can begin providing significant economic benefits for electricity consumers. The latest litigation and the preliminary injunction only serve to further increase costs for customers,” ITC Midwest President Dusky Terry said in a statement. “We strongly assert that the federal agencies that granted the land exchange and issued permits for the project acted within their legal authority under federal law and their environmental review complied with the National Environmental Policy Act (NEPA). Just as in prior litigation, we are confident that we will ultimately prevail in this case and move forward with project completion.” 

Dairyland COO Ben Porath emphasized that Cardinal-Hickory Creek’s completion will mean the utilities can remove an existing 161-kV transmission line in the refuge that crosses the Mississippi River. He said the “shifts in infrastructure will reduce the electric transmission footprint in the refuge and replace existing structures with low-profile structures using an avian-friendly design.” 

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MISO, SPP Preparing Joint Tx Study’s Scope

MISO and SPP staff have alerted their stakeholders that they have completed the annual issues review process and are developing the 2024 coordinated system plan’s study scope as they try once again to find a mutually suitable interregional joint project. 

In an email to stakeholders last week, the grid operators said their representatives had concluded two joint planning committee meetings reviewing feedback from stakeholders on “issues potentially benefiting” from interregional studies. The RTOs also gathered feedback from the Interregional Planning Stakeholder Advisory Committee (IPSAC) in February. (See MISO, SPP to Conduct Interregional Study in 2024.) 

MISO and SPP will review the 2024 CSP’s study scope with stakeholders during an upcoming IPSAC meeting yet to be scheduled. 

The grid operators’ joint operating agreement requires them to conduct a joint study every two years. Five previous studies have failed to produce any joint projects over differences in how to allocate costs. (See MISO, SPP Fall Short in 5th Try for Interregional Projects.) 

Ex-SPP Director Joins PUD Board

Former SPP Director Phyllis Bernard has been chosen to fill a commissioner’s unexpired term on a Washington county utility’s board. She will be sworn in May 1. 

Bernard will fill the remainder of Jim Waddell’s term on the Clallam County Public Utility District’s three-member Board of Commissioners. That term expires after Clallam County’s November general election is certified. The county is near Olympic National Park, northwest of Seattle. 

Waddell, the PUD’s commission chair since 2023, died in February. 

Bernard retired from SPP’s Board of Directors in 2019 after 16 years of service. (See “Last Meeting for Eckelberger, Skilton, Bernard,” SPP Board of Directors/MC Briefs: Oct. 29, 2019.) 

She has served as the Olympic Medical Center’s at-large representative to the PUD commission since July 2023. 

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IRA Driving New Clean Energy as Interconnection Queue Backlogs Persist

Interconnection requests across the U.S. shot up by 30% in 2023, with close to 2,600 GW of solar, wind and storage waiting to land a spot on the grid, according to the Lawrence Berkeley National Laboratory’s 2024 Queued Up report.  

This year’s edition of the lab’s annual tally of projects awaiting interconnection provides a granular look at the conflicting forces — regulatory, economic and logistical — affecting projects sitting in the queues of the nation’s seven RTOs and ISOs and 44 other balancing authorities in non-RTO/ISO regions. 

On the one hand, the report notes, renewable energy tax credits in the Inflation Reduction Act have had a significant impact on project development, providing tailwinds for over 1,200 GW of new projects that have applied for interconnection since the law was passed in August 2022. 

“Although not all of the post-IRA interconnection requests can be attributable to the IRA, these provisions increased developer interest in clean energy, and the queues are one indicator of this,” the report says. 

But even with FERC Order 2023, aimed at reforming interconnection processes, existing backlogs may take one to two years or more to clear. Several RTOs and ISOs have either paused applications or are considering doing so until they can implement the order. 

These backlogs’ impact — along with other permitting obstacles, supply chain delays and high interest rates — can be seen in the more than 70% of interconnection requests withdrawn between 2000 and 2018, the most recent figures available. During that time, only 20% of wind projects requesting interconnection went online, with solar scoring 13% and battery projects 11%. 

The Berkeley report also drills into the withdrawal stats to track when in the interconnection process they were withdrawn ― during initial feasibility or system impact studies, or later during the facility studies or interconnection agreement negotiations. Generally, most withdrawals occur in the early stages, but the report found an increasing trend toward late-stage withdrawals from 2016 to 2018. 

Such late-stage withdrawals can cause a snowball effect, the report says, causing sunk costs and lost deposits for developers while triggering restudies for other projects in the queue. 

Withdrawal rates for standalone solar, wind and battery projects were higher than for hybrid projects. While standalone projects each had a withdrawal rate of about 75%, the rate for hybrid projects was 49%. 

Projects online versus projects withdrawn: Interconnection queues continue to see high withdrawal rates. | Lawrence Berkeley National Laboratory

Size, Location Matter

The number of gigawatts now sitting in queues is more than twice the 1,279 GW currently online across the country, the report says, and almost all RTOs and ISOs could add more than enough new power to cover peak demands and expected demand growth. 

“Some people are saying, ‘We have so much more capacity in the queue that we really have a need for,’” said Joseph Rand, energy policy researcher at the Berkeley Lab. But with new data centers, electric vehicles and manufacturing coming online, “there’s a real need to bring online new electric generation,” he said. 

The slowdown in new interconnection requests in MISO and PJM has been more than offset by a boom of new capacity going into queues in CAISO and the non-ISO West, the report says. CAISO’s queue exploded in 2023, going from about 200 GW in 2022 to 523 GW of solar, storage and hybrid storage projects. 

The non-ISO West saw its queues add about 100 GW, also of solar, storage and hybrid resources; the region now leads the country with 706 GW awaiting interconnection. 

The size of projects is also increasing, with solar projects now averaging 193 MW, a 250% increase since 2015, while battery projects are averaging just over 200 MW, a 330% increase since 2015. 

But along with all that increased capacity and number of interconnection requests, the report also found longer timelines for projects to cycle through the process. For projects going online in 2023, the typical time from interconnection request to start of operation was close to five years, compared to three years in 2015 and less than two years in 2008. 

Timelines are also affected by project size, the report says. Projects under 5 MW can go from interconnection request to operation in about 20 months; for midsized projects of 5 to 20 MW, the time is 33 months, and for larger projects 100 to 200 MW and up, it’s four to 4.5 years. 

On average, CAISO takes the longest to get projects from interconnection request to operation — an average of seven years or more — followed by NYISO and SPP, at five to six years, the report says. The non-RTO Southeast and ISO-NE have the shortest timelines, three and two years, respectively. 

Rand cautioned that interconnection is one of a range of factors affecting project timelines, such as securing offtake agreements and local permitting, along with supply chain delays. 

New capacity entering interconnection queues has increased every year since 2014. | Lawrence Berkeley National Laboratory

‘Chipping Away’

With RTOs and ISOs still formulating their plans for implementing Order 2023, significant change in interconnection processes and timelines will likely be incremental, Rand said. 

He sees RTOs and ISOs facing “countervailing forces that are almost working against each other.” The “absolute splurge of developer interest in new clean energy … [and] an unprecedented volume of new requests [is] overwhelming the system” while the changes by FERC and the RTOs are only “chipping away” at the backlog, he said. 

“We’re hitting this point where we’re in need of more innovative reforms that are maybe a little bit more comprehensive, and they revamp things a little more deeply,” Rand said, pointing to more automation as an example. Most stakeholder sectors “seem to recognize that FERC Order 2023 is just a baseline, and more needs to be done.” 

Rand is hoping FERC’s forthcoming rule on transmission planning will make a bigger dent. “I really look forward to doing this report next year,” he said. 

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Western RTO Group Floats Independence Plan for EDAM, WEIM

Backers of an initiative to create an independent Western RTO that builds on CAISO’s markets have floated a plan to untangle the snag that’s hung up past efforts to “regionalize” the ISO: a lack of independent governance. 

The plan is set out in West-Wide Governance Pathways Initiative’s highly anticipated straw proposal, which the group’s Launch Committee released April 10 along with an accompanying stakeholder guidance document and legal analysis. The latter was performed by law firm Perkins Coie, which the committee retained to examine state and federal legal issues. 

It describes a “stepwise” approach for transitioning the oversight authority for CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM) from an ISO board appointed by California’s governor to an independent entity representing stakeholders from across the Western Interconnection.  

Effecting that transition has been the key objective of the Pathways Initiative, which utility commissioners from five Western states launched last July just as EDAM began to face mounting competition for participants from SPP’s Markets+ day-ahead offering. (See West Entered Pivotal Period for RTO Development in 2023.) 

“This package presents the Launch Committee’s evaluation of options to achieve the original goal of the Pathways Initiative: the creation of a new, independently governed entity capable of offering an expansive suite of West-wide wholesale electricity market functions across the largest possible footprint,” the committee said in a statement accompanying release of the documents. 

The proposal envisions three steps for progressively meeting that goal, but the plan released April 10 deals only with the first two steps, leaving the third for a future time once the effort has initial objectives. 

Option 0

Step 1 of the proposal calls for making the existing WEIM/EDAM Governing Body as independent as possible “within the current CAISO structure in a way that presents little or no” risk to inciting challenges to the change based on California law. 

The action represents “Option 0” among the governance options the Launch Committee laid out during its December stakeholder update call and is expected to be workable without making changes to the California statute governing the ISO. (See Western RTO Initiative Outlines Governance Options.) 

The step would entail giving the WEIM’s Governing Body “primary authority” over market-related matters in areas where it currently shares “joint authority” with the ISO’s Board of Governors, with disagreements being “channeled” into the existing dispute resolution process outlined in the WEIM charter, which falls under the CAISO tariff. 

Step 1 also would include modifying the current dispute resolution process to allow CAISO to make a “dual filing” of both bodies’ proposals with FERC — “with no stated preference” — in the instances of unresolved disagreements over market rules, similar to the “jump ball” process between ISO-NE and NEPOOL in New England.  

This step additionally would revise the WEIM charter to account for consumer and state interests in the market’s decision-making process. 

“This step also contemplates a continued advisory role for a Body of State Regulators (BOSR) in WEIM GB and CAISO BoG decision-making, and an active role in representing state interests, when necessary, in any ‘dual filing’ before FERC” the proposal says. 

Under the plan, Step 1 would be triggered once EDAM implementation agreements have been executed by a “set of geographically diverse” WEIM entities outside CAISO representing load “equal to or greater than 70% of the CAISO balancing authority area (BAA) annual load for 2022.” 

“Assuming all the entities who have expressed an intent to join EDAM as of April 10, 2024, execute implementation agreements, only one additional utility representing at least 10,000 GWh of load and located in the Southwest would be required to trigger the Step 1 governance transition” the proposal says. 

The proposal says: “Step 1 is just the first step toward the full realization of the regulators’ vision of energy markets with governance independent of any single state, participant or class of participants,” representing “a near-term incremental increase in independent governance that show commitment” to that vision. It also notes that Perkins Coie concluded the step could be completed within the scope to California law, but that FERC approval likely would be required. 

RO, Not RTO

Step 2 in the straw proposal seeks to achieve the Pathways Initiative’s “primary goal” by “creating a durable governance structure with a fully independent board that has sole authority to determine the market rules for EDAM and WEIM, building incrementally on the movement toward greater independence in Step 1.”  

The key action in the step is establishment of a new “regional organization” (RO) separate from CAISO that would become successor to the WEIM’s Governing Body.  

“The Launch Committee envisions that the RO would begin with a relatively modest size, consisting of a board of directors and a small initial dedicated staff and legal counsel (internal or external),” the proposal says. “The board itself would meet FERC’s standards for independent governance of an RTO, including the absence of any financial conflicts of interest related to the energy markets and market participants.”  

Step 2 would require winning passage of California legislation “to narrow the corporate scope of the CAISO and allow a complete transfer of some of its existing management responsibilities, while preserving the CAISO’s balancing authority responsibility” — the last being a key requirement for the support of California labor groups. (See Former Opponents Shift Position on CAISO ‘Regionalization’.) 

The step also would see a much-reduced role for the WEIM Governing Body, with the group’s “primary authority” over WEIM/EDAM decision-making (established in Step 1) being transitioned to the “sole authority” of the new RO, “while possibly continuing some form of shared authority for a limited number of tariff provisions,” the proposal says. The step also contains the potential for Western stakeholders to use the RO as the governing entity for new services beyond the WEIM and EDAM, such as reliability coordination, resource adequacy, transmission “functions” and consolidation of balancing authorities. 

The Launch Committee expects the WEIM’s BOSR, or “similar successor organization, would continue to have a significant role in reviewing and opining on policy proposals and actions of the RO to protect all affected consumers.” 

The committee also realizes the launch of the RO could be an appropriate time to “re-evaluate” how the WEIM and EDAM engage with participants, raising the potential for more stakeholder-driven processes. 

“The Launch Committee continues to evaluate how best to structure the stakeholder process for providing input into the RO’s consideration of market rules and any other matters under its authority. We expect the RO to be responsible for overseeing the stakeholder process associated with developing regional market rules,” the proposal says. 

“Some elements of creating the RO and the overall Step 2 proposal can be implemented sooner than others, and this may argue for beginning implementation prior to consideration of further legislation in California. And regardless of further legislative change in California, the creation of an RO with the attributes described here may prove attractive on its own merits as a locus for future regional market initiatives,” according to the proposal. 

‘Clear Line of Sight’

The straw proposal only briefly touches on Step 3, which would be the development of a full RTO, the design for which “goes beyond” the Launch Committee’s scope of work, although the proposal notes steps 1 and 2 were developed “with a clear line of sight” to the services of an RTO, for which membership would be voluntary. 

“One guiding principle for the Launch Committee was to ensure that a governance structure could evolve to allow market participants to voluntarily participate in a regional transmission organization (RTO), but not to mandate that any entity join an RTO,” the committee said. 

The Launch Committee expects to issue a final proposal for Step 1 and a revised proposal for the more complex Step 2 in early June, concluding Phase 1 of the committee’s work.  

Phase 2, expected to run through early fall, would include implementing Step 1 and further refining Step 2. That would be followed by Phase 3, which would “finalize” implementation of Step 1 and complete the design and proposed timeline for implementing Step 2. 

The Launch Committee will discuss the straw proposal during its next update call April 19. 

‘Pragmatic Effort’

The straw proposal earned support from several energy companies and groups in the West, including many participating in the Pathways Initiative effort. 

“The Pathways Initiative is a pragmatic effort to ensure any new market entrant will reap the benefits of joining a West-wide market,” Vijay Satyal, deputy director of regional markets and transmission at Western Resource Advocates, said in a statement. “The process has been inclusive and transparent, with a focus on identifying requirements for independent governance to facilitate the largest possible market footprint in order to maximize consumer and public interest benefits.” 

“This proposal marks a pivotal moment in our pursuit of a cleaner, more efficient energy future for the Western region,” said Kelsie Gomanie, Western markets advocate at the Natural Resources Defense Council. “As stakeholders rally behind a more expansive market, the vision of a grid with lower costs, lower emissions and stronger reliability becomes clearer and closer.” 

“Montana has already gained $74 million in benefits in less than three years of our utility’s participation in the EIM,” said Anne Hedges, co-director of the Montana Environmental Information Center. “The Pathways Initiative poses the best opportunity to grow those benefits, ensure reliability and help decrease the upward trend in customers’ rapidly rising electricity bills.” 

“The proposal will build on the success of EIM and EDAM, preserve state authority over energy policy goals and offer a path to additional market services, capitalizing on the reliability and cost savings benefits of sharing resources across the largest possible footprint,” Advanced Energy United Managing Director Leah Rubin Shen said in a statement. 

“We are very excited about the momentum happening in the West toward expanding CAISO’s successful EIM and building on top of that to have a day-ahead market,” said Mona Tierney-Lloyd, head of regulatory and policy at Enel North America. “Having a market structure in the West that covers the large footprint of the West is really important.”  

“The fewer seams there are across the West, the fewer barriers in the market,” said Varner Seaman, director of legislative and regulatory affairs at Pattern Energy Group. “Intuitively, a market that is inclusive of California makes the most economic sense, but ultimately, whatever market will get the best economic outcome for consumers is the right choice. Every state has an interest in how we can work better together.” 

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NERC Makes Case for Recertification in Performance Assessment

In its draft ERO Performance Assessment posted for comment April 9, NERC aimed to convince FERC to renew its certification as the Electric Reliability Organization on the strength of its record over the last five years demonstrating “notable successes … and [setting] the stage for continuing to advance reliability, resilience and security [for] nearly 400 million people in North America.” 

NERC will seek comments on the draft via email through April 30 and plans to file the completed assessment with the commission this summer, the ERO said in an email; the draft is dated July 19, 2024. It covers the five years from Jan. 1, 2019, through Dec. 31, 2023, reviewing what NERC views as its accomplishments during the assessment period under four focus areas: 

    • energy: addressing challenges arising from the changing resource mix, providing sufficient energy and essential reliability services, improving system performance during extreme weather and adding transfer capability; 
    • security: addressing cyber and physical security risks; 
    • agility: becoming nimbler in risk identification and standards development; and 
    • sustainability: investing in automation, eliminating single points of failure, and strengthening the ERO Enterprise’s long-term stability and success. 

FERC currently requires NERC to submit performance assessments every five years, but it has proposed shortening the assessment time frame to three years to identify performance issues in a timelier fashion, which the ERO opposed when the commission suggested it in 2021 (RM21-12). (See ERO Enterprise Resists FERC’s Assessment Proposal.) The draft suggests that FERC terminate that proceeding, given the ERO’s performance over the last five years. 

The draft depicts NERC as an active and dynamic organization, leading or participating in a wide range of efforts to promote electric reliability and “create value for stakeholders across [its] risk identification, mitigation and standards development process.” 

Internal Efforts Highlighted

NERC’s internal development is a significant focus of the document, with the ERO highlighting its ongoing efforts to modernize and streamline its committee structure. 

Among the accomplishments in this area is the creation of the Reliability and Security Technical Committee, which the ERO organized in 2020 through the combination of several existing technical committees to serve “as a proactive forum for aggregating ideas, leveraging industry expertise and prioritizing deliverables to target potential risks.” 

In addition, NERC pointed to the introduction of the Regulatory Oversight Committee. The ROC replaced the ERO’s Compliance Committee last year to give the Board of Trustees “committee-level oversight of standards development [and] enhanced oversight of NERC’s core regulatory processes along the entire continuum of activities.” 

Along with these internal modifications, NERC’s report held up its work on standards as a key pillar of its reliability work. While the standards introduced over the last five years are part of this (NERC observed that it has introduced multiple standards on cybersecurity, cold weather, and operations and planning since the last assessment), the organization’s efforts to improve the development process also received a lot of attention in the document. 

COVID Caused ‘Unprecedented Challenges’

The ERO “faced unprecedented challenges between 2019 and 2023” because of the COVID-19 pandemic, NERC said, most notably the sudden requirement to shift all its standards work to virtual meetings in 2020. 

This change meant NERC first had to slow its standards development work and ask FERC to defer implementation dates for standards coming into effect. 

Then, as the pandemic’s impacts subsided, the ERO “significantly increased the number, pace and intensity of standards development projects” in an effort both to get back on track and to address “increasing challenges to [grid] reliability,” including the changing resource mix, the increasing frequency of extreme weather and rapidly developing security threats. 

NERC acknowledged that the back-to-back slowdown and acceleration of standards work has caused “considerable pressure” for the ERO and its stakeholders. It pledged further efforts to enhance the development process over the next several years. 

The ERO also highlighted its efforts to advance the Electricity Information Sharing and Analysis Center (E-ISAC) as a forum for utilities, vendors, and other public- and private-sector partners to share updates on cyber and physical security threats. For example, the E-ISAC joined the Department of Energy’s Energy Threat Analysis Center pilot in 2022 to provide “industry context to U.S. government partners” and share information across the energy sector. The E-ISAC also provided regular security bulletins during the transition to remote work because of COVID-19. 

Finally, NERC mentioned its work on improving its own infrastructure “to ensure that it continues as a durable body of knowledge even during unprecedented external events.” These efforts include introducing new technologies to streamline enforcement activities, such as the Align tool and ERO Secure Evidence Locker. The ERO also established the Centralized Organization Registration ERO System project to “move all registration functions to a single, secure and consolidated system.” 

“NERC’s recent investments to enhance its sustainability support overall ERO Enterprise organizational sustainability even during unprecedented external events like the global pandemic,” NERC said. “That the ERO Enterprise achieved the enhancements to reliability and its processes described herein despite an intervening global pandemic demonstrates the resilience and coordination by the ERO Enterprise, commission, state and provincial governmental authorities, and stakeholders in support of reliability.” 

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Senate Energy Subcommittee Examines Cybersecurity Shortfalls at Dams

Most dams in the U.S. lack adequate cybersecurity protections, and FERC’s resources are too limited to develop them, senators heard in acommittee meeting April 10. 

Sen. Ron Wyden (D-Ore.), chair of the Senate Energy and Natural Resources Committee’s Water and Power Subcommittee, laid out the facts that FERC told his staff. 

“Today, the subcommittee is being told by the Federal Energy Regulatory Commission, which licenses 2,500 dams, that the dams responsible for well over half of the nonfederal power generation have not received a cybersecurity audit,” Wyden said. “And currently, there is no plan to complete these missing audits anytime soon.” 

The commission lacks the ability to complete those audits over the next decade because it has only four cybersecurity experts to oversee those thousands of dams, he added. Its rules have not been updated since 2016, and they are largely focused on “checking boxes,” Wyden said.

“FERC doesn’t have the resources it needs to be an effective regulator,” Wyden said. “This is a problem for the Congress to address. Now it’s time for Congress to step up. The seriousness of cyber threats to critical infrastructure has been clear for years.” 

Ideally, Congress would pass cybersecurity legislation universally covering the issue, but that is not within the ENR Committee’s purview, Wyden said. But it can address the shortfalls FERC has regarding hydroelectric dams. 

Hydropower dams are in nearly every state and on every major river system nationwide, with 100 GW overall and 57 GW owned by nonfederal parties including utilities, private companies, tribes and state governments, said Terry Turpin, director of FERC’s Office of Energy Projects. They are covered by NERC cybersecurity standards in effect since the end of 2018, and FERC staff audits dams when possible. 

“By the end of fiscal year 2024, staff of the security branch will have performed 271 physical security inspections and completed cybersecurity audits covering the owner-operators responsible for 37% of the installed nonfederal hydropower capacity,” Turpin said. “By the end of fiscal year ’25, we will have completed audits covering 70% of that installed generation capacity.” 

Fewer than 400 of the nation’s thousands of dams provide 90% of the country’s hydropower, but 87% of the fleet is over 30 years old with equipment that has exceeded its expected service life, said Virginia Wright, manager of Idaho National Laboratory’s Cyber-informed Engineering program. 

“Many of the remaining small- and medium-sized facilities are operated by entities with few resources to invest in vulnerability analysis and threat detection,” Wright said. “But they all face the same threat landscape.” 

Congress has allocated $753 million to improve existing hydroelectric facilities, but that means greater use of digital automation, which only will increase the digital risks the sector faces, she added. 

Wright agreed the federal government needs to step up its efforts but said that is not enough. Organizations also need to adopt cyber-informed engineering (CIE). 

“Cyber-informed engineering can be used to engineer out adversary opportunities and engineer in protections from sabotage in both existing and newly upgraded infrastructure,” Wright said. “While the federal government can provide financial resources and the expertise of the National Laboratories with their ready stockpile of capabilities, defending against ‘everything, everywhere, all at once’ will require everyone — both federal and nonfederal — to join forces.” 

CIE is a good concept that overlays with the Edison Electric Institute’s resilience goals, said Scott Aaronson, the organization’s senior vice president of security and preparedness. 

“There’s two ways you deter an adversary. The first is that the attack doesn’t have the intended impact,” Aaronson said. “So, an adversary attacks using cyber means, and we still maintain operations. The other way that you deter is that an attack has a consequence, which is the purview of our armed forces and intelligence community.” 

While the utility industry does not have any direct role in the latter deterrent, the military and intelligence rely on the grid like the rest of society, so ensuring the grid is resilient against cyberattacks is vital to preserving that capability, he added. 

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NEPOOL Markets Committee Briefs: April 9-10, 2024

ISO-NE continued work on resource capacity accreditation (RCA) changes at the Markets Committee on April 9 and 10, outlining how changes to the overall resource mix could affect the reliability value of different resource types.  

Dane Schiro of ISO-NE detailed additional results related to the RCA impact analysis. ISO-NE in February presented the analysis’ initial results, which showed how the RCA changes would affect the amount of accredited capacity for different resource types. (See NEPOOL Markets Committee Briefs: Feb. 6, 2024.) 

Building on the impact analysis, ISO-NE conducted sensitivity analyses looking at the effects of three scenarios changing the resource profile: the addition of renewables, the replacement of oil capacity with renewables and the replacement of coal capacity with renewables. 

The RTO in March presented the first phase of these analyses to the MC, focusing on how the scenarios would affect overall system reliability. (See NEPOOL Markets Committee Briefs: March 13, 2024.) At the April MC, Schiro outlined how the scenarios would affect the seasonal reliability benefits of different resource types.  

While the reliability contributions of resources including gas, oil and hydro remained consistent throughout the scenarios, wind, solar and energy storage varied significantly. 

For energy storage, reliability value increased in the summer in every scenario, with the greatest increase shown when renewables replaced oil resources, the scenario with the greatest reliance on renewables.  

Schiro noted that the value of energy storage is “closely related” to the duration of reliability risk events, increasing as the events get shorter. The addition of renewables in the summer reduced the length of risk periods by delaying the onset of the risks, Schiro said.  

In contrast, replacing coal and oil with renewables hurt the value of energy storage in winter because the duration of reliability risk events generally increased in these scenarios.  

The analysis also showed scenarios with greater renewable penetration hurt the value of wind resources. Wind resources typically all have high output at similar times, reducing the likelihood that periods of high wind generation face reliability risks, Schiro said. Therefore, the modeling found that adding wind capacity would produce diminishing reliability benefits.  

The modeling showed a similar reduction to the reliability benefits of solar resources as solar generation increased, Schiro added.  

Accreditation Calculation Updates

ISO-NE also provided additional details on its plans to calculate the accredited capacity of demand resources. For active demand capacity resources (ADCRs), the RTO will construct a “seasonal energy profile that represents their historical hourly availability over the last three years’ real-time offer data in the energy market.” 

ISO-NE then will use this profile to assess ADCRs’ performance during periods with reliability risks. Unlike passive demand resources (PDRs), ADCRs will have an annual opportunity to challenge their energy profile.  

The accreditation values of PDR resources will be based on “a single, common system-wide profile (different for each month) that represents the demand reduction associated with a given hour,” and will use reconstitution data from the previous five years, Christopher Parent of ISO-NE said.  

For energy storage resources, duration and round-trip efficiency will be the key factors in accreditation, Parent said. Market participants with energy storage resources will have one opportunity to challenge these values.  

Stakeholder Proposals

Tom Kaslow of FirstLight expressed concern that ISO-NE’s accreditation proposal may overvalue gas resources that lack firm fuel contracts.  

Kaslow said ISO-NE should consider increasing the daily operating hours requirement from 12 hours to 16 for gas resources. This would increase the amount of firm gas a resource would need to procure to receive its maximum possible accreditation value, and would reduce the value of nonfirm gas, Kaslow said.  

Meanwhile, Ben Griffiths of LS Power proposed changes to how ISO-NE is proposing to model resource outages. Griffiths argued that relying solely on historical data to estimate future outage rates could cause prolonged outages from abnormal equipment failures to have outsized impacts on individual resources’ accreditation values. 

“Resources can have equipment-related outages of extended duration that, once resolved, should not be expected to occur again,” Griffiths said. “In these instances, historic performance is a poor predictor of future performance. … Nevertheless, the ISO’s current proposal will include that outage for three to five years.” 

To prevent these distortions, Griffiths said a resource that deals with an extended, abnormal outage “should be able to challenge its default value and propose a substitute that better reflects expected output.”