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December 17, 2025

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CPUC Shifts More Attention to DR with New Rulemaking

The California Public Utilities Commission is preparing to overhaul its demand response programs, policies and data systems to ensure uniform DR standards statewide and better position the Golden State to meet its energy policy and emissions goals. 

During a Sept. 18 voting meeting, the CPUC approved an order instituting rulemaking intended to improve the “consistency, predictability, reliability and cost effectiveness of demand response resources in California,” the commission said in its decision approving the rulemaking. 

The rulemaking seeks to:  

    • Update demand response “guiding principles” designed to align statewide policies around DR programs. 
    • Update policies related to the state’s “dual participation” model, valuation methodologies and evaluation metrics. 
    • Standardize DR data system and process requirements.  
  • Standardized data processes will help the commission reduce data costs and errors, staff said in their proposed decision. 

The decision comes a few weeks after the commission approved guidelines for dynamic rate designs for the state’s investor-owned utilities. (See CPUC Approves Guidelines for Large IOUs’ Dynamic Rate Designs.) 

“This is a big moment for demand response in California,” Commissioner John Reynolds said during the voting meeting. “At our present moment, rates don’t yet provide a clear signal to manage electric usage as efficiently as possible or desirable.” 

“I wouldn’t be surprised if California one day reaches a point where most, if not all, demand response programs rely on economic signals that are integrated into existing retail and wholesale markets,” Reynolds added. 

In a presentation during the meeting, CPUC staff said demand response principles should be “predictable and reliable” so they can be incorporated into California’s forecasting and planning frameworks. 

Inconsistent or unpredictable demand response programs “jeopardize grid reliability, trigger emergency procurement of costly backup resources and erode confidence in the capability of demand response resources to play a significant role in achieving the state’s energy and environmental goals,” staff said in the presentation. 

“Without furthering our demand response policies, it is my belief that we’re not going to be able to meet our clean energy goals,” Commissioner Darcie Houck said at the voting meeting. “These [upcoming] policies are going to be absolutely critical.” 

CPUC staff plan to publish a full proposal for the new rules in the first quarter of 2026, followed by commission vote in the third quarter. 

SCE General Rate Case Revenue Approved

The commission also approved Southern California Edison’s (SCE) test year 2025 general rate case that includes a total revenue requirement of $41.8 billion for 2025-2028. 

The approved revenue requirement will increase average residential monthly bills by about $9.80 for California Alternate Rates for Energy (CARE) customers and $15.52 for non-CARE customers — a rise of about 9.1% for both groups. 

A significant portion of the money in the rate case — about $3.1 billion — will be used for work that reduces wildfire risk in SCE’s territory. SCE plans to spend about $554 million specifically on trimming and removing vegetation that is near electrical facilities to reduce the risk that those facilities start a fire. 

“A large part of utility expenditures today have to do with wildfire mitigation, and this decision recognizes the need to target undergrounding of powerlines and also authorizes covered conductor projects, all of which will dramatically cut wildfire risks,” CPUC President Alice Reynolds said at the meeting. 

“[This decision] recognizes the importance of all of [SCE’s] investments and costs, but [it] also [recognizes] the really urgent need to impose discipline on those costs, and that’s just as important given the challenges that Californians are facing for cost of living,” she added. “I think this decision does that. It’s not easy. We can’t find a perfect solution.” 

SCE Approved to Sell 7 Hydro Facilities

The commission also approved SCE’s request to sell seven of its small hydroelectric facilities to the San Bernardino Valley Municipal Water District for about $34 million. 

The facilities are Mill Creek 1, Mill Creek 3, Ontario 1, Ontario 2, Santa Ana River 1, Santa Ana River 3 and Sierra. Six of the seven facilities are operational and generate about 11.6 MW, or about 1% of SCE’s total hydroelectric facility capacity of 1,164 MW. 

SCE will incur a pre-tax loss of about $60 million due to the transaction, the decision says. 

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SPP Names Director to Lead Markets+ Monitoring

SPP has named Tim Vigil, chief member relations and strategy officer for the Pacific Northwest Generating Cooperative (PNGC), as director of the Market Monitoring Unit’s office dedicated to Markets+.

In the role, Vigil will lead the development of market monitoring reports and metrics for Markets+, manage processes for identifying and addressing market design flaws, monitor market operations functions and support a future surveillance team responsible for screening market participant behavior.

The new position within the MMU was created in advance of the RTO’s launch of its Western day-ahead and real-time market in 2027, SPP said in a press release.

Carrie Bivens, SPP’s vice president of market monitoring, said Vigil’s broad industry knowledge, strong market insight and long experience in the Western Interconnection “will be invaluable to our monitoring preparation efforts for the new market and future oversight responsibilities.”

SPP said Vigil was instrumental in forming and implementing SPP’s Western Energy Imbalance Service market. He chaired the stakeholder-led Western Markets Executive Committee from 2020-2021.

Vigil joins the SPP MMU from PNGC. He previously served as director of development-origination at NextEra Energy, COO at Delta-Montrose Electric Association and in various roles at the Western Area Power Administration. He holds a bachelor’s degree in economics from California State University Northridge.

The MMU is independent of the RTO and its contract services, including Markets+. It functions independently to avoid actual or apparent conflicts in its oversight role.

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FERC Requires Additional Z2 Filing from SPP

FERC has directed SPP to submit a compliance filing for its proposal to unwind credit payment obligations assessed under Attachment Z2 of its tariff for transmission service taken from 2008 to 2016.

In an order issued Sept. 18 at its monthly open meeting, the commission determined that SPP lacked specifics in its proposed five-year plan to process about $138.5 million in refunded transmission service revenue credits paid during the refund period (March 2008 through August 2015) and an additional $8.2 million to refund point-to-point rates that increased during that time (ER16-1341).

FERC directed the RTO to explain how the refunds from entities that elect the payment plan will be allocated to entities owed refunds and to lay out how the plan interacts with a separate short-payments plan. It ordered the grid operator to clarify the allocation of “necessary revenue reduction in proportion to the outstanding net amounts owed by each entity on an aggregate basis after netting together the individual amounts payable and receivable for that invoice date.”

“We acknowledge that an option for a five-year payment plan could provide needed flexibility to the parties that must make repayments, but details of the specifics of the payment plan, and what the impact on refunds of this plan will be, remain open questions,” the commission wrote. “Accordingly, we direct SPP to explain how it would proceed both for entities that owe and are owed refunds in a situation where an entity selected the five-year payment plan option but was unable to pay refund amounts during the five-year period.”

SPP’s response is due within 45 days of the order.

The Z2 issue has dogged SPP since 2016, when the grid operator owed $147 million plus interest to transmission customers for the historical period. Staff said in October 2024 that interest at that time stood at $33.4 million. (See “Grid Operator Waiting for FERC Order to Resettle Z2 Funds,” SPP Markets & Operations Policy Committee Briefs: Oct. 15-16, 2024.)

Under the attachment, 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.

However, software problems delayed the attachment’s final implementation for eight years before 2016, during which the RTO did not invoice for the upgrade charges. FERC approved a waiver request to settle more than 365 days in arrears, but in 2019, the commission reversed course and said SPP should have settled Z2 from only September 2015 forward. (See FERC Reverses Waiver on SPP’s Z2 Obligations.)

In January 2022, the grid operator updated its proposed refund plan and made an informational update to the commission in September 2024. If approved, SPP plans to send out refund invoices with interest for the refund period, accrued to the current invoice date.

Once a new settlement system is deployed in the coming months, invoices would be issued for the September 2015-January 2020 operating days. Additional resettlements from February 2020 would be run monthly in the current settlement system, along with normal current day Z2 settlements, until SPP catches up to the operating month.

SPP told FERC that the refunds and resettlement, before interest on refunds, total at least $657.8 million (as of June 2024). That amount grows by between $3 million and $4 million each month, it said.

The RTO has said it expects to resettle everything in about four years.

2nd Order 2222 Compliance Filing

Also at the open meeting, the commission accepted SPP’s second Order 2222 compliance filing, subject to another compliance filing to be submitted within 60 days (ER22-1697).

FERC found that in SPP’s December 2024 filing, the RTO complied with the first compliance order’s directives related to the commission’s decision to decline its jurisdiction over the interconnections of distributed energy resources to distribution facilities for the purpose of aggregation. The commission also found that SPP met Order 2222’s requirements of allowing distributed energy resource aggregators to register aggregations under one or more participation models to accommodate their physical and operational characteristics and proposing a maximum capacity requirement.

The commission rejected protests by Advanced Energy United, Sierra Club and virtual power plant operator Voltus that SPP’s proposed 2030 implementation timeline is “analogous” to MISO’s. (See FERC Permits 2030 Finish Date for MISO Order 2222 Compliance.)

The commission said it rejected MISO’s first timeline because the RTO proposed to defer Order 2222 implementation for several years. It said SPP’s proposal to implement the order in the second quarter of 2030 complies with the requirement for a “reasonable implementation date with adequate support to show that the proposal is appropriately tailored for its region and implements Order No. 2222 in a timely manner.”

“Here, SPP is not proposing to defer Order No. 2222 implementation. Rather, SPP has adequately explained why an effective date five years from the commission’s acceptance of its revised proposal is appropriate for its region due to its implementation needs,” FERC wrote.

Approved in September 2020, Order 2222 directed all FERC-jurisdictional regional grid operators to revise their tariffs to allow DERs to participate in their capacity, energy and ancillary service markets. (See FERC Opens RTO Markets to DER Aggregation.)

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NERC Cold Weather Standard Gains FERC Approval

At its monthly open meeting Sept. 18, FERC approved the latest version of NERC’s cold weather preparedness standard while ordering follow-up informational filings on progress with its adoption.

In a press conference after the meeting, Chair David Rosner said that grid reliability remains “job No. 1” for the commission and that he was “really pleased” that FERC was able to advance the cold weather standard and other reliability items on the agenda. (See FERC Tackles Cybersecurity in Multiple Orders.)

NERC submitted EOP-012-3 (Extreme cold weather preparedness and operations) on April 10 in response to the commission’s directive that it develop “targeted modifications” to its predecessor, EOP-012-2 (RD25-7). FERC had called for the ERO to clarify the term “generator cold weather constraint” (situations in which a generator owner may declare that a specific freeze protection measure would result in a net loss of reliability on the grid) and ensure that the ERO confirms the validity of each constraint, along with clarifying requirements around corrective action plans.

In the new standard, NERC proposed a new, clearer definition for generator cold weather constraints that removed ambiguous references to “cost,” “reasonable cost,” “unreasonable cost” and “good business practices.” An attachment to the standard provides examples of acceptable constraint declarations, such as a case in which “the cost of retrofitting a generating unit would be unduly burdensome such that it would retire prematurely or cancel plans to finish the development of a new generating unit.”

The standard also introduces the concept of a compliance abeyance period for the requirement that GOs calculate the extreme low temperature for their generating units, a move intended to allow some flexibility in the initial application of this requirement. During the abeyance period NERC will “monitor the implementation of this requirement and identify, as appropriate, any revisions to the extreme cold weather temperature formula,” FERC said.

The commission indicated it would approve the standard without any of the modifications called for by the Union of Concerned Scientists, which claimed the cold weather constraint language remained too subjective. (See NERC Replies to UCS’ Cold Weather Standard Criticism.) FERC said the standard was “consistent with commission guidance to provide a limited set of defined circumstances” in which constraints could be granted.

However, the commission did direct the ERO to collect and submit to FERC informational filings every two years, starting no later than October 2026 and ending in October 2034. The filings must include:

    • the number of cold weather constraint declarations submitted to each regional entity;
    • the number of declarations approved, and their aggregate megavolt-amperes; and
    • a summary of the rationales provided for approved declarations.

NERC must also submit a narrative analysis in the filing addressing:

    • whether reliability coordinators, transmission operators and balancing authorities are notified in a timely fashion of constraint declarations and extensions to corrective action plans (CAPs);
    • the reliability impact of allowing 36 months to correct freeze-related issues, rather than a shorter time frame;
    • whether compliance enforcement authorities interpret and apply the constraint declarations approval process;
    • whether constraint declaration criteria are adequately defined and understood by registered entities; and
    • the reliability impact of cold weather constraint declarations and CAP extensions.

The standard will take effect Oct. 1. This is a departure from NERC’s request that the standard take effect either that date or three months after regulatory approval, whichever is later. That plan would have resulted in an effective date in December, but FERC said that the earlier date would allow the standard to be in effect before the upcoming winter.

The commission also observed that “industry was involved in NERC’s standard development process and was made aware of pending changes,” meaning the new requirements should not be a surprise for registered entities.

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Texas Regional Standard for Frequency Response Headed to Ballot

The Texas Reliability Entity’s Member Representatives Committee agreed to send a proposed regional reliability standard before industry stakeholders for a 45-day comment and ballot period at its open meeting Sept. 17.

The comment period for BAL-001-TRE-3 (Primary frequency response in the ERCOT region) is expected to run from Sept. 22 to Nov. 6, with the ballot period occurring in the last 15 days. (See page 19 in the committee’s agenda.) The standard drafting team will meet to discuss comments within 30 days of the end of the comment period.

If the standard fails to receive enough votes from industry, a second comment and ballot period will be held in 2026. If the standard passes, a final ballot will be conducted, after which it will be presented to the Texas RE Board of Directors for approval. From there it would go to NERC, and then to FERC.

BAL-001-TRE was created in 2013 after NERC requested, and FERC granted, a waiver of BAL-001-0 (Real power balancing control performance) for ERCOT on the grounds that one of its requirements was not “feasible under ERCOT’s competitive balancing energy market” and that the grid operator could not create inadvertent flows or time errors in other control areas.

The new version of the standard adds language clarifying that it applies to battery energy storage systems (BESS) and performance requirements for BESS, along with generating facilities, and sets maximum governor deadband settings for generating units that are not qualified to provide operating reserves and have obtained approval from the balancing authority to widen settings. It also updates the compliance monitoring period and circumstances under which the compliance history for the standard may be reset by the compliance enforcement authority.

At the board meeting following the MRC’s, Texas RE Chief Engineer Mark Henry reviewed the region’s performance during the summer. While the hot and dry summer that was predicted did not develop “to the expected degree,” demand continued to increase, with renewable and storage resources setting records; battery discharge during the summer months so far has totaled 7 GW, while solar generation totaled 29 GW.

Henry also confirmed that demand from large loads, particularly data centers and artificial intelligence operations, continues to grow, with load expected to more than double from 18 GW to 37 GW between 2025 and 2026, and again to 83 GW in 2027. He referred to NERC’s Large Loads Action Plan, which envisions the Reliability and Security Technical Committee’s Large Loads Task Force developing recommendations through mid-2026 alongside NERC-led collaborative industry sessions and collaboration with large loads efforts in ERCOT and other areas.

Finally, Henry discussed NERC’s Level 3 alert on inverter-based resources, which the ERO sent to industry on May 20. The alert laid out essential actions for IBR performance and modeling with responses from registered entities required by Aug. 18. Answers were mixed; more than half of utilities said they lack internal processes to confirm the dynamic performance of IBRs following system events, but more than 75% said they do have internal processes to update transmission entities about changes to IBRs that can alter performance.

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FERC Tackles Cybersecurity in Multiple Orders

In two Notices of Proposed Rulemaking issued at its open meeting Sept. 18, FERC proposed to approve 11 new Critical Infrastructure Protection (CIP) standards intended to allow utilities to use virtualization technology, along with a further modification to one of those standards that would improve cybersecurity at low-impact grid-connected cyber systems.  

NERC submitted the virtualization updates in July 2024 (RM24-8). (See NERC Sends Virtualization Standards to FERC.) Along with four new and 18 revised definitions for the NERC Glossary of Terms, the filing touched almost every entry in the library of CIP standards: 

    • CIP-002-7 (Cybersecurity – BES cyber system categorization); 
    • CIP-003-10 (Cybersecurity – security management controls); 
    • CIP-004-8 (Cybersecurity – personnel and training); 
    • CIP-005-8 (Cybersecurity – electronic security perimeters); 
    • CIP-006-7 (Cybersecurity – physical security of BES cyber systems); 
    • CIP-007-7 (Cybersecurity – systems security management); 
    • CIP-008-7 (Cybersecurity – incident reporting and response planning); 
    • CIP-009-7​ (Cybersecurity – recovery plans for BES cyber systems); 
    • CIP-010-5 (Cybersecurity – configuration change management and vulnerability assessments); 
    • CIP-011-4 (Cybersecurity – information protection); and 
    • CIP-013-3 (Cybersecurity – supply chain risk management)​. 

Virtualization constitutes “the process of creating virtual, as opposed to physical, versions of computer hardware to minimize the amount of physical hardware resources required to perform various functions,” according to the National Institute of Standards and Technology. NERC said in its filing that the current versions of these standards are “designed around the concept that devices have a one-to-one relationship between software and hardware,” which prevents entities from taking advantage of security advances made possible by virtualization techniques.

In the NOPR, the commissioners wrote they “support NERC’s efforts to … accommodate virtualization and other nascent technologies” and that the new standards should “allow responsible entities to [adapt] to emerging risks with forward-looking security models.” They emphasized the revisions would allow, but not require, utilities to adopt these technologies. 

However, commissioners questioned NERC’s proposal to replace the phrase “where technically feasible” with “per system capability.” While the ERO said this change would ease the “administrative burdens” of reviewing technical feasibility exceptions, FERC expressed concern it “would eliminate transparency … by introducing a self-implementing exceptions process with no reporting obligations.” 

In light of these concerns, the commission asked for comments in three areas: first, whether there stillis a need to maintain a technical feasibility exception program and what administrative burdens are associated with the current program; second, if the proposed changes would result in entities seeking new exceptions using the “per system capability” language; and third, alternative approaches that would meet the streamlining goals while also allowing effective oversight. 

Low-impact Cyber System Concerns

In the other NOPR, FERC sought comments on its proposal to approve CIP-003-11 (Cybersecurity — security management controls), which NERC submitted Dec. 20, 2024 (RM25-8). 

The update to CIP-003-10 is intended to address the risk of a coordinated attack using low-impact cyber systems, which constitute most of the systems within the grid. They are considered to pose less of a risk to reliability than high- or medium-impact systems and thereforeare subject to fewer CIP requirements than other systems. However, after the SolarWinds Orion cyberattack of 2020, in which hackers infiltrated the update channel of a popular network management tool and sent malicious code to users around the world, NERC began an investigation into the potential threat posed by a coordinated attack against multiple low-impact systems. 

In the proposed standard, NERC staff said it would require utilities to add controls to authenticate remote users, protect authentication information in transit and detect malicious communications to or between low-impact cyber systems with external routable connectivity. These changes still would allow entities “the flexibility as to where the [authentication] control is implemented based on their architecture,” the authors said. 

FERC’s NOPR called for comments on developments in the cybersecurity environment since the SolarWinds attack, such as the China-linked Volt Typhoon group that has been accused of embedding itself in the information technology networks of U.S. critical organizations for at least five years. The commission asked whether such actors, who infiltrate a protected network and then move laterally into others, could pose a threat to grid reliability, and whether FERC should direct NERC to perform a study or develop a white paper on the issue. 

Comments on the NOPRs are due 60 days after they’re published in the Federal Register. 

Supply Chain Standards Due in 18 Months

FERC also directed NERC to develop standards addressing entities’ supply chain risk management (SCRM) plans (RM24-4).  

The order also ended a related inquiry regarding reliability risks posed by grid-connected cyber equipment originating overseas, particularly equipment manufactured by Huawei and ZTE (RM20-19). 

The final rule “largely adopts” a NOPR issued in 2024 in which FERC identified “multiple gaps” in NERC’s existing SCRM standards. Those standards did not specify when or how entities should identify and assess supply chain risks or require entities to respond to supply chain risks through their SCRM plans, the commission said. 

The new standards will have to address “the sufficiency of responsible entities’ SCRM plans related to the identification of and response to supply chain risks,” as well as whether the SCRM standards will apply to protected cyber assets (PCAs). PCAs are defined as “one or more cyber assets connected using a routable protocol within or on an electronic security perimeter [ESP] that is not part of the highest-impact [grid] cyber system within the same” ESP. 

One element not included from the NOPR was a directive to require utilities to validate data received from vendors. Instead, FERC encouraged entities to do so voluntarily “as appropriate.” 

The final rule directed NERC to submit the required standards within 18 months of the date of issuance. 

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MISO Board Set to Add Bonneville Power Exec, Keep 2 Existing Members

DETROIT — MISO is poised to retain two of its term-limited board members in 2026 while adding an executive from a federal power marketing agency.  

MISO announced its slate of candidates for three available board seats: board incumbents Todd Raba and Barbara Krumsiek; and Joel Cook, Bonneville Power Administration’s former chief operating officer and senior vice president of transmission services.  

Cook left Bonneville in February when he took up the federal Office of Personnel Management’s buyout offer.  

Longtime board members Raba, Krumsiek and H.B. “Trip” Doggett are wrapping their third and final three-year terms at the end of 2025. Though they’re term-limited, all expressed interest in serving a maximum fourth term that is allowable through a special waiver of MISO’s rules. (See MISO Could Replace Up to 3 Board Members by Year End.)  

Director Jeff Lemmer said MISO decided to use a waiver of normal board rules only after it weighed the need for fresh faces on the board while recognizing “the value of continuity,” as MISO has “several major initiatives in flight.”  

Board Chair Raba thanked Doggett, the board’s only departing member, for his nine-year service to the MISO board.  

Illinois Commerce Commissioner Michael Carrigan, who served as one of the two stakeholders on MISO’s Nominating Committee this year, said the committee had to consider that effectively, one-third of the independent board could have turned over. MISO’s board is composed of nine independent directors, along with MISO CEO John Bear.  

The Nominating Committee ultimately interviewed seven external candidates in addition to the existing three board members and made recommendations to MISO.  

The Nominating Committee is charged with vetting and advancing potential board members, who are put to a vote of membership. The committee’s members change annually, and they are composed of three MISO board members and two MISO stakeholders, one of whom typically is from a state public service commission. This year, directors Lemmer, Bob Lurie and Nancy Lange sat on the Nominating Committee alongside Carrigan and ITC’s Brian Drumm.  

MISO membership will vote in late September through the end of October on the candidates. In MISO, members vote electronically on whether they support a potential board member. MISO’s board elections require candidates to earn a majority of votes in support among membership. MISO members can vote for, against or abstain from selecting any of the candidates. Candidates typically earn enough favorable votes to be installed.  

To establish a quorum, 25% of MISO membership (39 members this year) must vote.   

MISO will announce election results sometime in November.  

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N.Y. Backs Utility Plan Relying on NESE Gas Pipeline

A controversial natural gas pipeline proposal got a boost as the New York Public Service Commission approved the long-term plan for the state’s largest gas delivery system. 

In reviewing the proposal by National Grid’s three New York gas utilities, the PSC found a reliability need for the Northeast Supply Enhancement (NESE) project proposed by The Williams Cos. and authorized National Grid to include NESE in its planning. 

On its face, the move runs contrary to the state’s statutory requirements to reduce greenhouse gas emissions — a significant component of which comes from combustion of natural gas in buildings and power plants. 

More than 3,800 comments were submitted to the PSC in Case 24-G-0248, almost all of them in opposition to the National Grid plan, many of those for environmental reasons. 

But New York’s decarbonization efforts are running far behind the schedule envisioned in its landmark Climate Leadership and Community Protection Act. With the Trump administration actively opposing renewable energy development, the state may need to rely on natural gas more heavily and much longer than its leaders and policymakers had hoped. 

One of the guideposts for the PSC has been the potentially disastrous nature of a natural gas outage. Restoring service requires utility technicians to visit every customer twice — with police and locksmiths in tow for locations where the customer is not present. National Grid has 2.5 million gas customers in the state, and a widespread outage could take weeks or months to resolve.  

“Widespread gas outages are a real possibility today given the narrow margin between available gas supply and demand,” PSC Chair Rory Christian said in a news release. “The gas planning activities we require National Grid to undertake today will ensure that National Grid continues to provide safe, adequate and reliable service while striving to meet the state’s greenhouse gas emissions reduction targets.” 

Surrounded by Controversy

Transco, a Williams company, made its initial NESE pre-filing to FERC in 2016, then in 2017 formally sought to extend its existing gas network to increase supply to the New York City/Long Island region (CP17-101-007). 

FERC authorized NESE in 2019. But state regulators denied key permits and Williams eventually shelved the concept. 

On April 16, 2025, the Department of the Interior slapped a stop-work order on Empire Wind, an important part of New York’s decarbonization strategy. The move now is seen widely as an attempt to coerce New York into approving NESE as well as the Constitution Pipeline, another pipeline extension proposal the state had stopped. 

When Interior lifted the stop-work order May 19, Interior Secretary Doug Burgum implied a quid-pro-quo for NESE and Constitution. Publicly, Gov. Kathy Hochul (D) said only that the state would give full consideration to energy proposals that complied with state law. 

Ten days later, Transco petitioned FERC to reissue its 2019 authorization of construction and operation of NESE. FERC granted the request Aug. 28. 

The PSC’s 6-1 approval Sept. 18 of National Grid’s long-term gas system plan sets a path for offtake from NESE, if it is built. Other New York and New Jersey regulatory agencies are continuing their review of the proposal. 

The Next Steps

Requirements in the PSC’s lengthy order include reporting on necessary improvements to demand forecasting, non-pipe alternatives, cost mitigation and electrification. 

The three utilities — The Brooklyn Union Gas Co., KeySpan Gas East Corp. and Niagara Mohawk Power Corp. — also must report on how they will optimize supply if NESE is built and how they will address reliability if it is not. 

The PSC’s order reflects the quandary that faces New York and Hochul. The state already has some of the most expensive electricity in the nation and must simultaneously harden, expand and decarbonize its aging energy systems. None of these were ever going to be easy or cheap, and by varying degrees they are getting harder and more expensive. 

National Grid said it expects NESE to increase natural gas costs and decrease electricity costs for ratepayers, due to construction costs and lower wholesale electricity prices. 

Democrats control all levels of state government, but not all Democrats are in lockstep on the energy transition and its costs. Hochul has been pushing back some of the decarbonization initiatives in an effort to keep electricity affordable, drawing criticism from some other Democrats and traditional allies. 

The PSC’s decision to let National Grid factor NESE into its planning was a hard truth for climate and clean power advocates who once hoped the concept was dead. 

Public Power NY referred to NESE as the “Hochul-Trump pipeline” and said: “The biggest step backward for New York’s climate in at least a decade is just the latest in Hochul’s multiyear assault on our air and lungs.” 

Food & Water Watch New York said: “This foolish plan would put everyday New Yorkers on the hook to pay for a filthy, climate-killing fracked gas pipeline that isn’t wanted or needed.” 

Leading up to the PSC vote, more than 3,700 opposing comments were submitted by individual New Yorkers and entities ranging from the Sierra Club to the City of New York to the Institute for Energy Economics and Financial Analysis to the Jewish Climate Action Network. 

But there also have been voices of support for NESE. 

The Plumbing Foundation City of New York called it a critical investment in the state’s energy infrastructure. 

IBEW Local Union 1049 pointed to the jobs that would be created by the project. 

The Independent Power Producers of New York said NESE is “critically needed to maintain the reliability of the natural gas system in New York to serve Grid’s downstate customers and to augment gas supply to enhance the reliability of the electric markets in the downstate region.” 

IPPNY also reminded the PSC of something it is very aware of: Recent federal policy changes complicate the state’s efforts to replace natural gas with renewables. 

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FERC: New England TOs Must Disclose More Info on Asset Upgrades

Eight New England transmission companies must provide the Maine Office of Public Advocate with more information on asset condition projects placed in service in 2022, FERC has ruled.  

The ruling partly granted a formal challenge by the OPA alleging the eight transmission companies, including subsidiaries of Eversource Energy, National Grid, Avangrid and PPL, along with Vermont Transco, “refused to answer questions regarding investment policies and practices related to prudence of these investments” (ER20-2054). 

Commissioner Judy Chang wrote in a concurrence that the Sept. 18 order “should serve as a call to action for transmission owners across the country to provide greater transparency regarding their transmission investments.” 

Asset condition spending has been a major focus for New England consumer advocates in recent years as costs associated with upgrades to existing transmission infrastructure have skyrocketed.  

Although there is broad consensus that significant investments are needed to maintain and upgrade the region’s aging grid, state representatives and consumer advocates have expressed concern about a lack of transparency and oversight over these investments. ISO-NE recently agreed to take on a non-regulatory role in reviewing asset condition project proposals. (See ISO-NE Open to Asset Condition Review Role amid Rising Costs.) 

The OPA’s formal challenge stems from a series of questions the office submitted to the companies in September 2023 seeking information on how the companies evaluated asset condition needs, considered solutions and alternatives, and determined when to proceed with projects.  

The OPA wrote in its challenge that the transmission companies violated the formula rate protocols by failing to adequately respond to the information request. 

Consumer advocates from Massachusetts, Connecticut, New Hampshire and Rhode Island supported the OPA’s challenge and emphasized the importance of information requests for providing consumers with the information needed to evaluate — and potentially challenge — the prudence of transmission investments.  

The consumer advocates encouraged FERC to “interpret the [formula rate protocols] liberally and to issue a decision in this matter that fosters open and transparent exchange of information that will allow interested parties to evaluate and determine whether formula rate costs are reasonable and were prudently incurred.” 

In a joint response to the OPA’s challenge, the transmission companies argued that the OPA filing does not meet the requirements for a formal challenge, that the OPA’s challenge is based on many “inaccurate or false” claims and that the companies “did provide responses and supporting documentation in response to Maine OPA’s information and document requests, in addition to objecting to certain questions.” 

The companies asked FERC to reject the challenge, writing that “failure to do so would invite needless litigation and divert resources away from the ongoing New England stakeholder process on transparency enhancements to the transmission regional planning process for asset condition projects.” 

In its ruling, FERC directed the companies to provide more information in response to several of the OPA’s requests, while finding some of the requests to be outside the scope of the companies’ requirements under the protocols.  

“We find that most of Maine OPA’s questions clearly set forth the request for information in a manner such that identified NETOs [New England transmission owners] could make a good faith effort to answer those questions as required by the protocols,” FERC wrote.  

The commission found the OPA’s requests for the identities of individuals involved in asset condition decisions and those seeking an undefined number of documents to be outside the scope of the companies’ requirements. 

FERC also found that, to varying degrees, the companies adequately responded to some of the questions, including the request that the companies describe their procedures for evaluating project alternatives. 

However, FERC ruled that the companies did not adequately explain how they ensure projects are not placed in service before they are needed.  

The commission also found that subsidiaries or Eversource, National Grid and Avangrid failed to make a “good faith effort” to document their procedures for evaluating asset condition needs or disclose whether any employee or consultant “recommended against proceeding with a particular asset condition project.” 

“This refusal to provide information that is reasonably necessary to determine the prudence of actual costs and expenditures included in the 2023 Annual Update could preclude Maine OPA from ever raising a prudence challenge by denying it the information required to raise serious doubt,” FERC wrote. 

It directed the transmission companies to provide more information correcting the deficient answers within 30 days. 

In her concurrence, Commissioner Chang emphasized the importance of transparency regarding transmission investments, along with stakeholders’ “fundamental right to transmission planning and investment information through existing formula rate protocols.” 

“At a time of sharply rising customer bills and increasing concern about the prudence of transmission planning decisions, transmission owners have an obligation to address those concerns and help customers, state regulators and stakeholders better understand how their money is being spent,” Chang said.  

She advocated for more standardization disclosures around transmission investments throughout the country and encouraged stakeholders to collaborate to develop these structures.  

“If further action by the commission is needed to ensure customers have access to information needed to assess the prudence of transmission owners’ investments, I encourage parties to bring the issue to the commission, as Maine OPA has done in this case,” Chang wrote.  

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Newsom Signs Calif. Pathways Bill into Law

California Gov. Gavin Newsom has signed into law the bill that will allow CAISO to transition the governance of its markets to an independent “regional organization,” along with five other bills related to energy and emissions. 

AB 825 implements the West-Wide Governance Pathways Initiative’s “Step 2” plan to create a regional organization to oversee CAISO’s Western Energy Imbalance Market and soon-to-be-launched Extended Day-Ahead Market — and authorize the ISO and California’s investor-owned utilities to participate in the RO. (See Pathways Bill Passes Calif. Legislature in Lopsided Votes.) 

Speaking during a Sept. 19 signing ceremony at the California Academy of Sciences in San Francisco, Newsom said the law will generate almost $1 billion in financial benefits, expand clean energy exports and address reliability. 

Referring to previous failed efforts to pass legislation to regionalize CAISO into a Western RTO, the governor said, “We’ve worked on that for over a decade.” 

“We’re getting it done here today,” Newsom said. “So, finding a balanced approach, setting forth strategies to achieve audacious goals that simply no other large-scale jurisdiction in the world can lay claim to, and do it in a way that reduces the burden on ratepayers and taxpayers at the same time.” 

Supporters of the bill were quick to thank Newsom and the California Legislature after the governor approved the measure. 

“Gov. Newsom’s signing of Assembly Bill 825 is a landmark achievement for the future of energy collaboration and innovation across the western United States,” CAISO said in a statement. “He, along with the California Legislature and the broad coalition of supporters, have recognized the importance of making this crucial next step toward independent governance of Western electricity markets. Now that AB 825 is signed into law, the ISO will work closely with partners across California and the rest of the region to ensure a more reliable and affordable bulk electric system for the benefit of consumers throughout the West.” 

Advanced Energy United highlighted the many stakeholders involved in drafting the legislation. 

“This legislation is the culmination of nearly a decade of work to create a more flexible, reliable and affordable energy future for the West,” said Leah Rubin Shen, managing director at Advanced Energy United. “AB 825 paves the way for an independently governed energy market that will deliver a more reliable grid, broader deployment of clean energy resources and more affordable energy for consumers across the region.”   

Speaking during the signing ceremony, Katelyn Roedner Sutter, California state director at the Environmental Defense Fund, said, “By expanding today’s energy markets, we expand access to clean electricity and lay a strong foundation for the growth of clean energy and jobs.” 

A broad coalition was responsible for getting AB 825 passed, Sen. Josh Becker, the bill’s chief sponsor, told RTO Insider at New York Climate Week.

“This was an unparalleled coalition that we built this year: Environmental Defense Fund, NRDC, Environmental Voter [Project],” Becker said. “This year the Sierra Club supported it — they always opposed it in the past; labor, who always opposed in the past, came on board because of some of the protections built in, and companies and the Chamber of Commerce. People who usually don’t agree on anything, agreed on this. There was still a lot of opposition, but that coalition helped us get it done.”

Becker said there are three positive outcomes of the bill: lower costs, improved reliability, and an expanded grid.

“The Brattle Group and California Energy Commission has projected it’ll be between $800 million and a billion dollars of savings a year to California directly.” Becker said being able to cite the economic benefits of the Western Energy Imbalance Market for 10 years supported the case for the bill: “That’s delivered over $7 billion of economic benefits, $2.2 billion directly to California.”

Second, he said the changes brought about by the bill should improve everyday reliability and decrease reliance on the most polluting peaker plants. The result: a 53% reduction in greenhouse gas emissions in California. “Right now, we spend billions of dollars keeping natural gas peaker plants available to run a few hours a year; literally, a few hours a year. We’re going to be able to use some of these highly polluting assets a little less frequently in California.”

Finally, the expanded grid provides reliability through major weather events: “Especially in the era of climate change, you need a grid bigger than any one weather event. As [California Energy] Commissioner Siva Gunda always says, if we have a massive heat wave, as we did on Sept. 6, 2022, being able to trade with our neighbors can increase reliability.”

In addition to AB 825, Newsom signed into law a measure aimed at extending California’s cap-and-trade program through 2045. The revenues of the program will go toward funding, among other things, California’s high-speed rail project. 

Other measures signed include efforts to stabilize gas prices, funding for air quality monitoring programs and the continuation of studies related to California’s greenhouse gas targets.  

The governor also approved SB 254, a law that will create a “transmission accelerator” to develop low-cost public financing programs for certain transmission projects. The legislation also establishes an $18 billion “continuation account” for the state’s wildfire fund to cover investor-owned utilities’ wildfire liabilities. Contributions to the fund will be split between ratepayers and shareholders. (See Calif. Lawmakers Pass Bill to Accelerate Transmission Development.) 

Dej Knuckey contributed to this article.