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November 1, 2024

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FERC Proposes Further Cybersecurity Measures

FERC on Sept. 19 indicated its approval of NERC’s new reliability standard requiring utilities to implement internal network security monitoring (INSM) on some grid-connected cyber assets, while also floating the prospect of new standards aimed at securing the supply chain of critical electronic components. 

The commission issued two Notices of Proposed Rulemaking (NOPRs) at its monthly open meeting. The first indicated its plan to approve CIP-015-1 (Cybersecurity — INSM), which NERC submitted to FERC in June (RM24-7). It would require utilities to implement INSM at all high-impact grid-connected cyber systems, as well as medium-impact systems with external routable connectivity (ERC). (See NERC Submits INSM Standard for FERC Approval.) 

FERC ordered NERC to develop requirements for INSM last year, calling the proposal a necessary response to events like the SolarWinds hack of 2020. In that attack, malicious actors — later identified by U.S. law enforcement as belonging to Russia’s Foreign Intelligence Service — infiltrated the update channel for SolarWinds’ Orion network management software and pushed code to customers that the attackers could use to gain access to their systems. 

Commission staff said last year the compromise demonstrated a weakness of the kind of cybersecurity measures mandated in NERC’s Critical Infrastructure Protection (CIP) standards, which require a utility to monitor communications from the inside of its electronic security perimeter (ESP) — the electronic border around its internal network — to the outside. INSM could help security staff discover and respond to an attacker that already had infiltrated the system and did not need to communicate with external attackers, they said. 

CIP-015-1 would require registered entities to “implement one or more documented process(es) for [INSM] of networks … of high-impact [grid] cyber systems and medium-impact … systems with” ERC. Documented processes under the standard must include: 

    • network data feeds to monitor network activity, including connections, devices and network communications;
    • at least one method to detect anomalous network activity using the network data feeds; and
    • at least one method to evaluate anomalous activity to determine what additional action is needed. 

Entities also would have to implement documented processes to retain INSM data associated with anomalous network activity and to protect all data gathered or retained to prevent unauthorized deletion or modification. 

FERC’s NOPR proposed to accept CIP-015-1 but also described the standard in its current form as “not … fully responsive to the commission’s directive in Order 887 to implement INSM for the ‘CIP-networked environment.’” The commission specifically warned that the standard is not sufficient to “defend against attacks that circumvent network perimeter-based security controls.”

FERC said it’s concerned attackers may be able to compromise systems external to a utility’s ESP, such as electronic access control and monitoring systems (EACMS) or physical access control systems (PACS), and then use that control to establish access within the perimeter as a trusted communication. 

To address this potential shortcoming, the commission proposed approving CIP-015-1 while directing NERC to develop additional modifications to the standard “that would extend INSM to include EACMS and PACS outside the” ESP. The ERO would need to submit the revised standard to the commission within 12 months of the effective date of FERC’s final rule. Comment on “all aspects of this proposal” is due to FERC 60 days after the NOPR’s publication in the Federal Register. 

New Supply Chain Standards Proposed

FERC’s other NOPR proposed to direct NERC to address perceived gaps in the ERO’s standards concerning supply chain risk management (SCRM) (RM24-4). SCRM provisions are found in three existing standards: 

    • CIP-005-7 — Cybersecurity — electronic security perimeter(s); 
    • CIP-010-4 — Cybersecurity — configuration change management and vulnerability assessments; and 
    • CIP-013-2 — Cybersecurity — supply chain risk management. 

“Although the currently effective SCRM reliability standards provide a baseline of protection against supply chain threats, there are increasing opportunities for attacks posed by the global supply chain,” FERC said in its NOPR. “Using the global supply chain, adversaries have inserted counterfeit and malicious software, tampered with hardware and enabled remote access.” 

The gaps the commission identified in NERC’s standards relate to the sufficiency of entities’ SCRM plans as concern the identification, assessment and response to supply chain risks, as well as the applicability of the current standards to protected cyber assets. FERC said the current standards do not specify when and how entities should identify and assess supply chain risks; they also do not require entities to respond to supply chain risks through their SCRM plans. 

These gaps have led to “multiple gaps in SCRM” observed by FERC staff during their audits of responsible entities’ CIP compliance in fiscal 2023. (See FERC Report Identifies CIP Audit Lessons Learned.) Staff identified multiple SCRM-related security risks among the seven audited entities, most notably a “lack of consistency and effectiveness in SCRM plans for evaluating vendors and their supplied equipment and software.” Auditors also said many entities’ SCRM plans did not have procedures for responding to identified risks. 

FERC’s NOPR would have NERC submit new or modified standards establishing specific timing for entities to evaluate vendors and equipment to identify supply chain risks, along with periodic assessments of risks associated with vendors, products and services. The standards also would have to require entities to ensure their SCRM plans have steps to validate the accuracy and completeness of information received from vendors during the procurement process, and a process to document, track and respond to identified supply chain risks. 

As with the INSM proposal, the commission invited interested parties to submit comments on its intended actions. Comments are due 60 days after the NOPR’s publication in the Federal Register. 

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Markets+ ‘Equitable’ Solution to Seams Issues, Backers Say

Proponents of SPP’s Markets+ contend in their latest “issue alert” published Sept. 18 that the framework provides a much more equitable solution to tackling market seams than does CAISO’s Extended Day-Ahead Market (EDAM). 

In an email to RTO Insider, Jeff Spires, director of power at Powerex, said seams in the West have “resulted in inequitable outcomes, shifting value and reliability risk between subregions, and these outcomes are largely not captured in available studies to date.” (See SPP Briefs: Week of Nov. 7, 2022.) 

It’s a point that Powerex — the first and, so far, only entity to tentatively commit to joining Markets+ — has broached before. In March, the Canada-based energy trader issued a report criticizing CAISO’s operational practices in the Western Energy Imbalance Market (WEIM) during the January 2024 cold snap in the Northwest. The report argued CAISO’s processes unjustifiably limited energy transfers into the region during the weather event and squeezed wholesale electricity price spreads between the Northwest and Southwest through congestion charges at the ISO’s border with Oregon, benefiting California parties at the expense of those in the Northwest. (See Powerex Report Expands NW Cold Snap Debate.)  

Reiterating the points in the issue alert, Spires added that Markets+ “creates the opportunity for more equitable outcomes by leveraging its independent governance, its impartial operator and SPP’s demonstrated ability to negotiate seams agreements on a peer-to-peer basis with neighboring markets.”

The alert is the fourth published in a series of seven notices intended to highlight Markets+’s purported advantages over CAISO’s Extended Day-Ahead Market (EDAM) and WEIM. The first covered differences between how the two markets would be governed, the second focused on reliability, and the third compared pricing practices. 

The contributing parties include Arizona Public Service, Chelan County Public Utility District (PUD), Grant County PUD, Powerex, Public Service Co. of Colorado, Salt River Project, Snohomish PUD, Tacoma Power, Tri-State Generation and Transmission Association, and Tucson Electric Power. 

In the recent alert, the backers argue that Markets+ is a neutral market operator and can, therefore, resolve seams issues between adjacent balancing authority areas and adjacent transmission service providers (TSPs) more equitably than CAISO’s EDAM. 

“For entities outside California, joining EDAM would mean accepting that their BA-to-BA and TSP-to-TSP seams will be resolved by market rules developed by the CAISO under its governance framework, and implemented by a market operator that is also one of the participating BAs and one of the participating TSPs,” the alert said. 

Additionally, allowing CAISO to set the rules could lead to the California load receiving priority over other regions during heat waves, according to the alert. The parties also argued that CAISO’s market rules have led to concerns over inequitable distribution of congestion value, a point emphasized in Powerex’s March report. 

Instead of relying exclusively on CAISO to resolve seams issues, the entrance of Markets+ will lead to each market operator attempting to ensure “that its participants receive the fair value of trade at each applicable seam, including through seams agreements negotiated between these peer market operators, as is the practice today between adjacent organized markets in the Eastern Interconnection,” according to the alert. 

Trade across seams also is enhanced under Markets+ because it removes trade barriers and uses a flow-based dispatch, which will “facilitate greater reliability and economic benefits relative to today by enabling more transfers across the same transmission infrastructure, including across BA-to-BA and TSP-to-TSP seams,” according to the alert. 

‘Equitable and Efficient’

In response to the issue alert, CAISO spokesperson Anne Gonzales told RTO Insider the ISO remains focused on “implementing EDAM in a manner that best meets the needs of the region’s diverse interests.” 

“We continue to work with our partners to advance the Western energy markets, including the equitable and efficient management of seams with neighboring areas — whether in organized markets or not — and to grow its footprint to deliver maximum reliability, economic and environmental benefits to customers West-wide,” Gonzales said. 

In its own March report on the January cold snap, CAISO contested the negative characterization of how it managed flows across its seam with the Northwest during the deep freeze, contending that the event mostly demonstrated the value of the WEIM under stressed grid conditions, while the associated congestion charges reflected the functioning of mechanisms seen in any organized electricity market. (See NW Freeze Response Shows WEIM Value, CAISO Report Says.)  

The prospect of seams has been an especially fraught issue in the competition between Markets+ and EDAM.  

EDAM’s key supporters, who champion the cause of a single electricity market in the West that pointedly includes California, have warned that a divided West will prevent the region from realizing the full “diversity benefit” of resources across its broad footprint and could increase future reliability risks.  

On the other hand, Markets+ backers have played down any risks associated with seams. During a May workshop, Bonneville Power Administration officials noted the agency has deep experience dealing with market seams and made clear that seams concerns would not dictate its choice. (See Seams Concerns Won’t Drive Day-ahead Market Decision, BPA Says.) 

For its part, SPP has said it is prepared to take a leadership role in managing Western seams based on its own experience developing seams policies with markets neighboring its RTO in the Eastern Interconnection — a point reprised in the Sept. 18 alert. (See SPP’s Experience with Seams Could Help Markets+.) 

Robert Mullin contributed to this article. 

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8th Circuit Denies Review of FERC Orders on SPP Attachment Z2

The 8th U.S. Circuit Court of Appeals on Sept. 16 denied review petitions by several SPP members over FERC’s rejection of generators’ rehearing requests seeking compensation under tariff Attachment Z2.

The court said it found “no error” in FERC’s 2022 decisions and rejected the petitions filed by EDF Renewables, Enel Green Power, NextEra Energy Resources and Southern Power (23-1520, et al.).

At issue is Attachment Z2 of the SPP tariff, under which transmission upgrade sponsors receive credits from any upgrade users whose service could not be provided “but for” the upgrade. The attachment also requires the RTO to invoice the charges monthly and to make any adjustments within one year. Because of software problems, it took SPP eight years to implement the attachment before 2016, during which the RTO did not invoice for the upgrade charges.

FERC found in four separate orders that SPP had violated the filed-rate doctrine, its tariff and its contracts with three of the four generators. However, the commission declined to grant a remedy, citing the one-year limitation on adjusting bills for customers. It also noted that SPP is a nonprofit entity with no independent funds to cover requested remedies.

The 8th Circuit concluded that although Attachment Z2 — and its requirement for upgrade credits — is part of the filed rate, FERC did not violate the filed-rate doctrine by not granting credits to the generators. The court said Attachment Z2 does not conflict with the billing requirements of the tariff and found that it “sets out the arrangement for sharing upgrade costs” but is silent on the timing of billing for upgrade charges.

“The commission thus had only one choice regarding [SPP’s] customers: adhere to [the tariff] and the filed-rate doctrine,” the court wrote.

The generators also contended that FERC failed to adequately explain whether its decision was based on a lack of authority or an exercise of equitable discretion, but the 8th Circuit disagreed, saying the commission “articulated a satisfactory explanation for its orders.”

And “in any event, any error in failing to explain would be harmless here, because the agency was required by law to decline the requested remedies, and a remand would be unnecessary,” it concluded.

A similar request by other SPP members was denied in 2023 by the D.C. Circuit Court of Appeals, which said it lacked jurisdiction to consider the utilities’ filed-rate doctrine argument because they failed to exhaust it at the rehearing stage. (See Appeals Court Denies Review of SPP Z2 Charges.)

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DC Circuit Orders Could Lead FERC to Rethink its Natural Gas Policies

WASHINGTON — A pair of recent appeals court decisions signal a shift in how the courts view FERC’s approvals of natural gas infrastructure and has the commission considering its next steps, Chair Willie Phillips said at its open meeting Sept. 19.

The D.C. Circuit Court of Appeals issued a decision in late July vacating FERC’s approval of Transcontinental Gas Pipe Line Co.’s Regional Energy Access (REA) Expansion Project to bring gas from Pennsylvania to New Jersey. (See DC Circuit Vacates Pipeline Approval FERC Issued over NJ’s Objections.)

About a week later, the court vacated FERC’s approval of two LNG export facilities planned to be built near each other on Texas’ Gulf Coast. (See DC Circuit Vacates FERC Approval of Two LNG Facilities in Texas.)

Transco has asked for rehearing on its pipeline certificate and also has filed for a temporary, emergency certificate so it can keep operating the REA pipeline after the court’s mandate is issued, which could happen as early as Sept. 20.

“While I’m not going to prejudge what we will say in that particular proceeding, I want to make clear that I think the court erred in vacating our authorization,” Phillips said. “Transco took steps to build out its system and begin serving customers.”

Right after Phillips made that comment, a protester against FERC’s natural gas policies stood up and started interrupting the meeting, which happened several times during the proceedings.

The court did not consider how disruptive the vacatur of FERC’s approval would be on the pipeline’s customers, Phillips continued after the protester was escorted out of the hearing room. Old Dominion Electric Cooperative already has filed comments in support of Transco’s emergency petition, saying the firm service it uses to fuel the 980-MW Wildcat Point combined cycle plant could be interrupted.

The decision that vacated FERC’s approval of the Rio Grande and Texas LNG projects is up in the air as their developers consider appeals, so no mandate will be issued until that process plays out. FERC is conducting new environmental impact statements on the projects, it said in filings issued Sept. 13.

FERC has won some cases on pipeline issues since Phillips became chair, but he said at his post-meeting press conference that the two decisions represent a break from the past.

“This is clearly a shift in the legal landscape regarding these cases,” Phillips said. “What I focus on, though, is we have new commissioners who are here — who are voting … today for the first time — that I look forward to working with on bipartisan and legally durable ways forward to address these pressing issues.”

The new EISes from the two LNG facilities are going to be reviewed in the coming months, with Phillips saying they should be done by summer 2025, at which point FERC will be able to respond to remanded issues from the case.

The Transco case was approved because the firm found some customers willing to sign up for service on its expanded pipeline, but that was over the objections of the New Jersey Board of Public Utilities and other state agencies who argued the gas would not be needed. The BPU filed a study saying the state had ample gas for this decade and that in the long term, its climate policies will lead to reduced demand for the fuel. But those arguments ultimately lost out.

Phillips explained how such state policies impact FERC decisions at the press conference.

“It’s a matter of a balance test that we use when we consider the need, and we also consider the arguments for and against any proceeding, including our natural gas pipeline cases,” he said. “We consider what the states want; we give it due consideration, as we do with all arguments raised.”

The two court cases could lead FERC to again reconsider its 1999 policy statement on natural gas infrastructure approvals, which former Chair Richard Glick attempted before being rebuked by members of Congress on Capitol Hill. One of those, retiring Sen. Joe Manchin (I-W.Va.), refused to hold hearings on Glick’s renomination in the Energy and Natural Resources Committee, effectively ending his term.

“The shift that we’ve seen in the legal landscape regarding our certifications, on LNG in particular, I think does present an opportunity for us to revisit the 25-year-old policies that we have regarding those authorizations,” Phillips said. “To be clear, we have new colleagues. They’ve just gotten here. We certainly want to give them an opportunity to get up to speed on these matters.”

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New IBR Standard to Finally Go to Ballot

NERC’s proposed standard setting generator ride-through requirements for inverter-based resources will go out soon for a formal ballot round the ERO hopes finally will see it gain the required support from industry.

Committee Chair Todd Bennett, of Associated Electric Cooperative, told members of the Standards Committee the revised PRC-029-1 (Frequency and voltage ride-through requirements for IBRs) was out for public comment, having been posted after the technical conference hosted by NERC on Sept. 5. (See NERC, Industry Discuss IBR Issues in Technical Conference.) The formal ballot round will begin Sept. 24 and end Sept. 30.

Bennett said in a Sept. 18 committee meeting that the conference “was received rather well” by ERO stakeholders, complimenting NERC staff for their fast work setting up the event on short notice. NERC’s Board of Trustees in August ordered the committee to hold the conference, invoking its special authority to bypass the normal standards development process for the first time to meet FERC’s November deadline for submitting ride-through standards. (See “Board Invokes Standards Authority to Meet IBR Deadline,” NERC Board of Trustees/MRC Briefs: Aug. 15, 2024.) 

During the two-day conference, NERC staff presented on the background of the standard, while industry stakeholders took part in panels discussing their issues with the proposed standard and possible ways to address them. Amy Casuscelli of Xcel Energy said “it was really helpful to get to hear the technical experts in the room … weigh in on their different perspectives and different views.” 

Casuscelli also praised the inclusion of original equipment manufacturers (OEMs) who could address the manufacturing challenges that might be posed by some requirements of the proposed standard. Trustee Sue Kelly, the board’s liaison to the Standards Committee, agreed this community was a valuable addition to the conference. 

“I thought it was very powerful to have everybody all in the same room at the same time. The drafting team reps were able to say, ‘This is why we wrote what we wrote’; the OEMs … who are going to be crucially important to implementing anything were there to tell us what they thought they could and could not do; and we, in turn, were able to say to them, ‘Your equipment is becoming increasingly important, and you bear some responsibility in this as well,’” Kelly said. 

Standards Actions Approved

The committee approved a handful of standards actions at the meeting, starting with a proposal to appoint supplemental members to the standard drafting team (SDT) for Project 2020-06 (Verifications of models and data for generators). 

The project recently was assigned to satisfy Milestone 3 of FERC’s Order 901, which requires the ERO to submit standards addressing validation and verification of models for inverter-based resources by November 2025. 

NERC Manager of Standards Development Jamie Calderon told members the ERO seeks to supplement the SDT to provide “the requisite experience to tackle” the added responsibilities of Order 901. The ERO solicited nominations from the industry and received nine; seven were recommended to the committee for approval. As usual, the candidates were not identified during the meeting except by number. 

Calderon said one of the remaining nominees “did not respond to interview requests, and recommendations were not received” from their references; the other informed NERC they would prefer to join a different SDT. As a result, neither was recommended for approval. 

The seven nominees were approved unanimously, although Robert Blohm of Keen Resources moved to add the second of the unrecommended nominees to the slate. He argued that four of the seven recommended candidates had Canadian backgrounds and adding so much Canadian representation to the team could make it regionally unbalanced. However, Blohm’s motion did not receive a second and did not advance. 

Members also approved the addition of a single new candidate to the SDT for Project 2023-09 (Risk management for third-party cloud services). The committee approved the SDT’s current slate at its July meeting, but since that time, one of the members has stepped down because of workload concerns. They will be replaced by a candidate who was recommended by NERC staff at the July meeting but replaced with a different nominee by the committee. 

Margo Caley of ISO-NE explained that both nominees are from the same sector, meaning there will be no change in sector representation on the SDT. 

Finally, the committee authorized the posting of proposed reliability standard TOP-003-7 (Transmission operator and balancing authority data and information specification and collection) for a 45-day formal comment period, with ballot pools formed in the first 30 days and ballots conducted during the past 10 days. 

TOP-003-7 (on page 14 of the agenda) was developed by the SDT for Project 2022-03 (Energy assurance with energy-constrained resources). The revisions to the existing standard will add near-term energy reliability assessment to the list of functions for which balancing authorities must provide data to entities that request it. 

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Comments on Western RO Stakeholder Plan Show Complexity of Effort

Recent stakeholder comments filed with the West-Wide Governance Pathways Initiative illustrate — once again — the complexity of building the new kind of Western “regional organization” (RO) envisioned by backers of the effort.

The comments came in response to Pathways’ draft plan for the RO’s stakeholder process, an aspect of the organization likely to be as important as its governance structure in swaying some Western electricity sector participants to choose CAISO’s Extended Day-Ahead Market (EDAM) over SPP’s Markets+.

The Pathways Launch Committee floated the plan during an Aug. 28 workshop, the last of four such intensive workshops facilitated by consulting firm Gridworks to hash out ideas about how the RO would engage with its stakeholders and how the stakeholder process would tie into governance. (See No Clear Blueprint for Western ‘RO’ Stakeholder Process.)

At the heart of the proposal is the formation of a Stakeholder Representatives Committee (SRC), described as the “primary stakeholder body that works with RO staff to catalog and prioritize initiatives, as well as to define initiative problem statements and solutions.”

During the workshop to discuss the RO’s stakeholder process, Launch Committee Co-Chair Pam Sporborg, director of transmission and market services at Portland General Electric, described the SRC as an evolution of the Western Energy Imbalance Market’s (WEIM) Regional Issues Forum, which itself has evolved over time into a key stakeholder body for addressing issues related to that market.

The proposal calls for the SRC to be a sector-based body, with sectors to be “self-organized” and committee representatives selected by members of each sector.

“Sectors may elect to use selection criteria to establish diversity among SRC representatives that may be important to the sector,” a presentation accompanying the proposal states.

The proposal defines nine sectors to be represented on the SRC, including:

    • EDAM entities (one seat);
    • WEIM entities (two seats);
    • CAISO participating transmission owners (2);
    • transmission-dependent utilities (3), including one seat reserved for community choice aggregators;
    • public interest organizations (PIOs) (1);
    • consumer advocates (1);
    • large commercial and industrial consumers (1);
    • independent power producers, independent transmission developers and marketers (3), with assurance that IPPs and marketers each have an opportunity for a seat to represent different business models; and
    • distributed energy resources (1).

One seat would be reserved for federal power marketing administrations (PMAs) in either the EDAM or WEIM sectors — if any such agency participates in those markets.

According to the proposal, every organization registered to vote in the RO would have the chance to specify their support, opposition or neutrality when the SRC votes on an issue. To be eligible to vote, an organization must register in a specific sector and agree to a code of conduct.

“Once the organizational votes are tallied, the nine sectors of the SRC will also vote, with the threshold for support, opposition or neutrality determined by the organizations in the sector,” the proposal says. “The SRC representative will report on any specific splits that have been established by that sector, consistent with the self-organizing principle described above. The results of all votes will be provided in the materials related to the issue.”

The plan also puts stakeholder initiatives into three categories, including:

    • compliance/nondiscretionary, such as responses to FERC rulemakings or fixes to market design flaws that require tariff changes;
    • compliance with state and local public policy, which could require stakeholder discussion to determine whether a tariff change is needed; and
    • discretionary initiatives that can be advanced by any stakeholder, the states committee, market monitor, “independent market adviser” or RO staff.

Once initiatives are categorized, the stakeholder process would entail prioritizing them through a “roadmap” process. That would be followed by an “issue evaluation” to determine the nature of the problem to be solved (Stage 1) and an “identification of solutions” (Stage 2). The last step would be seeking approval by the RO board.

Dilution Concern

The Pathways Launch Committee received 22 comments on the proposal, including one combining responses from seven PIOs.

Other commenters included utilities (some jointly filing), large energy consumers, industry interest groups, an energy trader, the Bonneville Power Administration and Google.

In its comments, Black Hills Power expressed concern the SRC “does not provide sufficient representation to utilities, which play a critical role in ensuring grid reliability and managing market operations.”

The South Dakota-based utility is one of two Black Hills Energy subsidiaries that last month said it would pull out of SPP’s Western Energy Imbalance Service and join CAISO’s Western Energy Imbalance Market, although it made no commitment to EDAM. (See CAISO’s WEIM Plucks Black Hills Utilities from SPP’s WEIS.)

“We recognize that all registered utilities within a sector, including utilities, can vote and contribute to the sector’s overall vote,” Black Hills wrote. “However, we still have concerns that utilities’ votes will be diluted within sectors where there are diverse participants.”

Black Hills recommended that Pathways ensure utilities have “a formal mechanism for ensuring that their interests are not overshadowed by other entities within the sector.” It proposed a “more tailored sector designation for utilities” with “clear distinctions” among the types of utilities — such as investor-owned or publicly run — “to ensure that their unique perspectives are not lost within larger, more diverse sectors.”

NV Energy, which already has committed to joining the EDAM, said it supported the use of a sector-based process only for selection of the RO board and development of the annual roadmap to prioritize RO initiatives.

“While recognizing potential benefits of indicative votes, NV Energy does not believe the sector-based process proposed in the draft discussion paper is the best approach,” the utility wrote.

Instead, NV Energy “strongly supports” the indicative voting approach CAISO used in the recent stakeholder process for Pathways Step 1 — which granted the Western Energy Markets (WEM) Governing Body “primary” authority over matters related to the WEIM and EDAM. (See CAISO, WEM Boards Approve Pathways ‘Step 1’ Plan.)

In that situation, the utility noted, the ISO “simply added a voting request to the stakeholder comment template asking if the participant supports, opposes or was neutral to the proposal. The votes were then tabulated and presented to the WEM Governing Body and the CAISO Board of Governors to assist in their deliberations.”

NV Energy said that approach “provides far greater transparency” because it:

    • records and presents each specific vote, preventing intra-sector disagreements over an initiative from being concealed by the sector’s majority vote;
    • “better represents minority interests and reduces a feeling of disenfranchisement” among entities holding a minority position within a sector; and
    • “reduces the burdensome and time-consuming process for separate sector-led votes.”

The utility also recommended a second seat for EDAM entities and questioned the need for three seats for transmission-dependent utilities.

“Presumably, these are transmission-dependent utilities within the EIM/EDAM footprint,” the utility wrote. “If one seat is for a transmission-dependent utility within California and one for a transmission-dependent utility outside of California, it may be understandable but does seem to create a mismatch with the three seats being allotted to the total of EIM and EDAM entities.”

‘Ambiguities’ or ‘Right Balance’

Salt River Project (SRP) said it “generally supports” creation of a “parent committee,” such as the SRC, “through which issues flow both up to the regional organization board and down to working groups.”

“This structure ensures that topics are defined at a high level based on stakeholder input before being remanded down to the working groups/task forces,” it wrote.

But SRP also recommended changing the proposed composition of the SRC to match that of the Western Resource Adequacy Program’s Nominating Committee, which consists of representatives from investor-owned utilities (2), consumer-owned utilities (2), retail competition load-responsible entities (1), PMAs (1), independent power producers/marketers (1), PIOs (1), retail customer advocacy groups (1), industrial customer advocacy groups (1) and one “independent sector” representative for entities that don’t fit into any other category.

SRP also agreed with the proposal that RO staff should take on most of the “burden” of facilitating and administering the stakeholder process, saying the arrangement would allow stakeholders to participate “nimbly” regardless of their staffing levels.

Google offered no comment on the list of proposed SRC sectors but recommended each sector develop a manual of board-approved bylaws to define who could be a member of the sector, frequency of meetings, how it develops consensus and how it communicates its positions to the RO’s committees, staff and board.

“This structure would mirror MISO’s, where sectors are self-organizing but each sector’s bylaws are approved by the board,” the company wrote.

BPA requested one additional seat be reserved for PMAs in either the WEIM or EDAM sector, assuming a PMA is a member of either. In the case of no PMA participation in either market, the agency asked that an additional seat be reserved for PMAs in the transmission-dependent utilities sector given their transmission still would be used to deliver to load in the CAISO-run markets.

BPA said it supports the concept of a category for state and local public policy stakeholder initiatives, but it also wants federal obligations that may be statutory requirements for itself and the Western Area Power Administration to be added to the category.

“In implementing the process, it will be important to ensure that these initiatives only skip Stage 1 in situations where the problem statement has broad agreement or is so clearly defined by the state policy initiative that there is no room for discussion,” BPA wrote.

The California Large Energy Consumers Association (CLECA) commented on “the imbalance between buyers and sellers in SRC voting sector definitions and encourages efforts to establish commensurate supply and demand representation.” CLECA called for the Launch Committee to address the “imbalance” by providing each sector with two seats or, alternatively, just one seat or one seat with one backup.

“All sectors have heterogeneous membership worthy of adequate representation at the SRC. This revision partially restores the balance between supply and demand representation,” CLECA wrote.

The Portland-based Public Power Council (PPC), which represents consumer-owned utilities in the Northwest, raised concerns about “the ambiguities in the RO/CAISO relationship based on the current proposal,” saying the role of both the ISO staff and board is unclear.

“Also, it is unclear whether pursuing an RO stakeholder process as outlined in the discussion document would have any impacts on the existing CAISO stakeholder process and whether those processes would be kept distinctly separate, or whether there would be some combined discussions or efforts between the RO and CAISO. We would appreciate the Launch Committee addressing these issues in the Step 2 proposal,” the PPC wrote.

The seven PIOs — which include the Northwest Energy Coalition, Western Resource Advocates, Natural Resources Defense Council and Environmental Defense Fund, among others — said the SRC “strikes the right balance between clear roles for each sector representative while allowing all interested stakeholders to participate in the process.”

The PIOs expressed support for the lack of fees or other monetary requirements for participating in the RO’s stakeholder process.

“This is an important aspect to ensure equal access for all stakeholders; if the regional organization were to require a fee for participating in the stakeholder process, that fee can be a barrier to smaller organizations that, because of competing priorities, may be unable to spend scarce resources on participation fees, and thus will be unable to have a full and equal voice, via voting or committee membership, in the process,” they wrote.

Full comments on the Pathways stakeholder process proposal can be found here.

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Report Finds Mass. Storage Programs Falling Short on Equity

While Massachusetts has some of the strongest incentives for storage resources in the country, its programs are lagging in their focus on equity and environmental justice, according to a new report commissioned by the Clean Energy Group.  

The report analyzed the equity provisions in three Massachusetts programs that incentivize storage resources: the Clean Peak Energy Standard, the ConnectedSolutions program and the Solar Massachusetts Renewable Target (SMART) program. 

The report found that “the current energy storage-incentivizing programs in Massachusetts, while they are groundbreaking in many ways, do not live up to the commonwealth’s clean energy equity commitments.” 

It noted that the ConnectedSolutions program, which is part of the state’s utility-run energy efficiency program, and the Clean Peak Energy Standard lack incentives for deploying storage in low-income households or environmental justice neighborhoods and also do not include reporting requirements regarding equity.  

The SMART program, which focuses on boosting solar resources but also includes an incentive for co-located storage, does include additional incentives for low-income customers. However, data from the program indicate just 1.4% of SMART storage projects used this low-income adder. 

Todd Olinsky-Paul, senior project director at the Clean Energy Group, said he was surprised to find that not only is there no equity requirement, there’s no reporting requirement for two of the three programs. 

He emphasized the importance of including low-income households in the early stages of storage deployment and said low-income households often experience the most significant benefits of behind-the-meter storage resources.  

As climate change drives increased threats from extreme weather to the grid, the underserved communities are “getting hit the hardest,” Olinsky-Paul said.  

Because low-income households typically are the hardest to reach when deploying new technologies, it makes sense to prioritize these groups from the outset, Olinsky-Paul said. “Once you figure that out, then you’ll know how to get it to everybody else,” he added. 

The report is intended to influence the state’s ongoing work to update each of the programs, Olinsky-Paul noted. 

Commissioner Elizabeth Mahony of the Massachusetts Department of Energy Resources (DOER) told NetZero Insider the state plans to include an increased focus on equity in all three programs. 

“We’re in the infancy — or maybe toddler years — of the storage industry, and so our programs that work with storage deployment are in a similar phase,” Mahony said.  

The state issued a straw proposal in July for its update to the SMART program and proposed to increase the eligibility of low-income customers and require that community-shared solar programs enroll at least 40% low-income customers. 

The state also is working with the electric distribution companies (EDCs) to finalize their energy efficiency plans for the 2025/27 period, which will include updates to ConnectedSolutions. 

Regarding the Clean Peak standard, Mahony said the state is finishing updates focused on ratepayer protection and plans to address equity “in the next phase of that program.” 

Mahony noted that the state updated the Clean Peak standard in July to add “a near-term multiplier so that projects that are ready to go and can interconnect by 2027 … will get additional funding.” 

The DOER commissioner added that Gov. Maura Healey’s recently proposed closeout supplemental budget would direct a procurement of up to 5,000 MW. (See Mass. Gov. Healey Includes Permitting Reform in Budget Proposal.) The supplemental budget proposal also includes major reforms to the state’s permitting and siting processes, which Mahony called “our top topic.”

She said the state also is preparing a new $50 million storage grant program “that we hope to launch in some form later this year.” 

The legislature in 2018 established a goal for the state to deploy 1,000 MWh of energy storage by the end of 2025. In February, electric utilities reported the state has reached 569 MWh of installed storage, with 8,806 MWh in the development pipeline.  

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New Western Tx Could Bring Big CO2 Benefits, Study Shows

Carbon dioxide emissions from the Western U.S. power sector could drop by 73% from 2005 levels if 12 transmission projects in the development pipeline are finished by 2030, according to a new study from the U.S. Department of Energy.  

The report’s model incorporates 12 future transmission projects, which collectively span about 3,000 miles, and the likely wind and solar power projects and battery storage systems that would take advantage of the new capacity. The scenario “shows a reduction of CO2 emissions by 73% relative to 2005, reaching to 27% CO2 emissions in 2030,” according to the report published by the DOE’s Pacific Northwest National Laboratory on Sept. 13. 

“This work is important because it shows that significant progress can be made [toward] decarbonization policy objectives if we proceed with already-planned transmission projects to meet new capacity needs with new renewable resources,” Nader Samaan, report co-author and chief power systems research engineer at PNNL, told RTO Insider in an email. 

The report said more transmission could lead to renewable energy replacing some large thermal fossil generation, with the highest emissions reductions occurring in Utah, Nevada, Wyoming, Colorado, Arizona and New Mexico. 

“As of July 2024, the Western Interconnection hosts 30 gigawatts of wind power, 38 GW of solar power and 14 GW of energy storage,” the study said. “The report’s scenario would add an additional 35 GW of wind, 31 GW of solar and 12 GW of energy storage by 2030.” 

The 12 transmission projects behind the model include the 500-kV Boardman-to-Hemingway line, the Gateway West project and the Southwest Intertie Project-North, among others. (See DOE Awards $371M to Regulators, Communities Grappling with New Tx.) 

Aside from the purported environmental advantages, the transmission projects could also decrease generation costs by 32% compared with a reference case in which the projects were not built. However, “capital costs for generation and transmission are not considered as part of this analysis and would be needed for a complete economic evaluation,” according to the report. 

“Most of the infrastructure upgrades selected are either in interconnection queues or the transmission planning pipeline, increasing the likelihood that they will be realized,” the report stated. “In other words, the projects selected in this analysis rely implicitly on some economic analysis conducted by those proposing the projects.” 

The model also predicts a 26% reduction in California’s annual net energy imports from the Northwest. Under the scenario, the state could tap into “newly integrated wind resources from areas with abundant wind, such as Wyoming and New Mexico,” according to the report. This would also provide congestion relief for the Northwest, the report added. 

The report is part of the DOE-funded National Transmission Planning Study, slated to come out this year. 

“The upcoming National Transmission Planning study will expand on the possible transmission buildouts that could help the nation reach higher decarbonization goals,” Samaan said. 

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MIT Report Proposes Policies to Grow Use of Advanced Transmission Technologies

Advanced transmission technologies (ATTs) can help utilities meet the rising levels of demand that are stressing the grid, according to a report released Sept. 17 by the Massachusetts Institute of Technology’s Center for Energy and Environmental Policy Research (CEEPR).

ATTs are a suite of technologies that include grid-enhancing technologies (GETs). The most widely used ones are dynamic line ratings, advanced power flow control devices, topology optimization and high-performance conductors.

“Increased use of advanced transmission technologies can play a major role in meeting this demand growth quickly and cost-effectively,” the report says. “However, electricity market structures — which disincentivize investment in innovation — are impeding progress towards modernizing the electric grid.”

“A Roadmap for Advanced Transmission Technology Adoption” was written by Grid Strategies President Rob Gramlich, along with CEEPR Fellow Brian Deese and Research Associate Anna Pasnau, both of whom previously worked at the White House for President Joe Biden.

The technologies have been used for decades and are more widely deployed abroad. In the U.S., the lack of incentives for transmission providers, information provided to regulators and some features of electricity markets hold them back, according to the report. The profit structure of electricity markets does not offer the right incentives for transmission providers to adopt many forms of ATTs, despite their consumer benefits and the ability to quickly add transmission capacity to the grid, it says.

“Under the current electricity industry regulatory structure, utilities earn profits from capital expenditures, meaning that they are incentivized to make more costly capital investments (e.g., building a new power plant) over changing their operating expenses or lowering and smoothing demand for electricity — even when those capital expenditures ultimately increase costs for consumers,” the report says.

The “capex bias” is an accepted and well-known feature of cost-of-service regulation, according to the report. It disincentivizes utilities from deploying GETs because they would avoid the need to invest in new transmission — cutting their capital expenditures and thus their profits. Part of regulators’ job is to prevent utilities from taking advantage of that bias and ensure investments are in line with consumer interests, the report says.

“However, both transmission providers and regulators can struggle to identify the best way to expand capacity against a backdrop of multiple options, and for some technologies, they need new modeling practices to assess benefits,” the report says. “Transmission providers and their regulators have historically focused their cost-benefit analyses on a narrow set of risks and thus are slow to scale innovations, preferring the status quo.”

Some policies around ATTs already have improved, with states passing laws aimed at encouraging them, the report notes. Other policies have sought to align utility incentives with key performance metrics; FERC Order 1920 requires transmission providers to consider ATTs in the planning process.

Those steps are in the right direction, but the paper proposes five more to spread the use of ATTs across the grid:

    • Regulators should require the use of ATTs in certain contexts, with the paper suggesting FERC require DLRs on highly congested lines to increase their capacity at one-tenth the cost of reconductoring. The Department of Energy should adopt a national conductor efficiency standard, which would ensure utilities use more efficient lines that can cut line losses by 30%.
    • Transmission providers and regulators should have to conduct robust analyses of the value of ATTs for the electric grid. Order 1920 requires they be considered, but it lacks specificity on how robust of an analysis will be required. The paper suggests states adopt laws requiring more stringent analyses to complement the FERC rule.
    • FERC should create financial incentives for transmission providers to adopt ATTs where they provide high benefits. The commission should adopt a shared-savings incentive nationally, giving utilities a cut of ratepayer savings from GETs adoption, and where possible state legislators should authorize additional returns on equity for ATT investments.
    • The commission should require transmission providers to share additional information publicly so third parties can evaluate ATT adoption and hold utilities accountable when they fail to make sensible investments.
    • FERC should open up the planning process for a third party to work on deploying ATTs. The paper suggests the commission could require transmission providers to release relevant data to the National Renewable Energy Laboratory, or another qualified nonprofit entity, to come up with plans for each grid operator to adopt ATTs and update them on a regular basis.
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MISO, Monitor at Stalemate over Need for $21B Long-range Tx Plan

INDIANAPOLIS — MISO’s quarterly public meetup with its board of directors put on display the unrelenting rift between the RTO’s planners and the Independent Market Monitor over MISO’s $21 billion in upcoming long-range transmission planning.  

At a Sept. 17 Markets Committee meeting of the MISO Board of Directors, MISO IMM David Patton encouraged a recess on the proposed $21 billion second long-range transmission plan (LRTP) portfolio until MISO agrees to rework its 20-year view of its system and the benefit estimation of the transmission.  

Patton repeated concerns he raised earlier at a stakeholder workshop on MISO’s second LRTP portfolio, which MISO hopes to advance for board approval by the end of 2024. (See MISO Says 2nd Long-range Tx Plan to Cost $21B, Deliver Double in Benefits.) 

“We should pause this process and get to the bottom of this before we allow it to move on,” Patton told board members. “The problem is we don’t have a credible, ‘what-will-the-world-look-like’ scenario if we don’t build this transmission.”  

Senior Vice President of Planning and Operations Jennifer Curran said MISO believes it has devised a valuable portfolio and stands by its conservative, 1.9:1 benefit-to-cost estimate.  

“I think we have a different philosophy on benefits that leads to a fundamental disagreement,” she told the board.  

“We can’t perfectly predict the future. But through the use of scenarios, we can develop the most robust portfolio using the modeling we have available today,” Vice President of System Planning Aubrey Johnson said.  

Johnson said the LRTP can be interpreted as “skating to where the puck will be.” He said recent load growth shows MISO’s top-end, most radical planning scenario is likely, when some stakeholders thought it outlandish five years ago.  

Johnson said even scaling back MISO’s decarbonization benefit for areas of the footprint where the value of decarbonization isn’t openly acknowledged, the portfolio still would have 1.3:1 benefit-cost ratio.  

Multiple stakeholders urged MISO not to entertain the IMM’s request for an assumptions and benefits rework.  

ITC’s Brian Drumm said MISO leadership should reject the Monitor’s calls to “develop and test against an alternate reality” regarding LRTP transmission planning.  

Drumm said it’s “irresponsible and dangerous” for Patton to assume MISO won’t experience a major load shed event simply because it never has or assume members will make plans independently to dodge one.  

“Stakeholders have chosen to solve the reliability imperative through long-range planning and particularly” the second LRTP portfolio, Drumm argued. “The IMM’s request is inappropriate because MISO’s role is to plan regional transmission, not to serve as an integrated resource planner.”  

Drumm added that the industry is aware that significant loss of load events will occur again and become more pronounced by extreme weather. He said avoiding just one widespread load shedding event can more than cover the $21 billion price tag of LRTP II.  

The Union of Concerned Scientists’ Sam Gomberg said MISO isn’t going far enough in incorporating climate risk assessments in long-range transmission planning. He said the RTO should anticipate changing weather patterns to inform system planning so it doesn’t end up trying to solve the challenges of extreme weather on the fly in the control room.  

Gomberg also said MISO is correct to value decarbonization in transmission planning. He said Patton’s argument that federal production tax credits already fully value decarbonization and MISO’s benefit metric is redundant “borders on absurd” and gives too much credit to Congress to objectively put a price on the social cost of carbon.  

MISO Director Phyllis Currie asked if the RTO has a stance on planning for increased climate impacts on the system.   

“I think our primary objective is to reflect our members’ objectives. We really follow the lead of our members [rather] than taking an independent view of climate change,” Curran said. However, Curran added that from an operations standpoint, MISO uses analytics and machine learning to forecast weather events that historically haven’t occurred.   

“David Patton consistently misunderstands the benefits of regional backbone lines … [and] doesn’t like long-term scenario-based planning,” Sustainable FERC Project attorney Lauren Azar argued to board members. Azar said the IMM appears to want MISO to “go backwards” into the “balkanized system” that existed before the RTO’s creation.   

Azar rhetorically asked board members to place a monetary value on the 210 lives lost when the lights went out on Texas residents during Winter Storm Uri.  

Azar said the IMM should stick to its original purpose of “mainly markets” and advised MISO not to pay for the IMM’s opinions on transmission planning through its IMM budget.  

The MISO IMM has made some stakeholders uneasy with his interest in MISO’s long-range transmission planning and public criticism of the 20-year fleet and benefit estimates MISO uses. Since last year, some have said the IMM oversteps his role.  

MISO’s board of directors has included a $250,000 allowance in the Monitor’s $10 million budget next year to “monitor ratings and identify transmission withholding and compliance” associated with ambient adjusted line ratings requirements it will roll out under FERC Order 881. The line item and data collection of transmission data caused consternation among MISO transmission owners.  

MISO staff will be “actively discussing what data” transmission owners must provide, MISO Director Trip Doggett said.