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November 16, 2024

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Calif. Lawmakers Consider $10B Climate Resilience Bond

California lawmakers are poised to place on the November ballot a $10 billion climate resilience bond measure that would provide $850 million for clean energy projects, including offshore wind. 

Senate Bill 867, which would send the bond measure to voters, must be passed by July 3 to meet the deadline for the November ballot. The legislature’s monthlong summer recess starts July 4. 

Lawmakers from the Senate and Assembly announced June 30 that they had reached agreement on the language of the bill, known as the Safe Drinking Water, Wildfire Prevention, Drought Preparedness and Clean Air Bond Act of 2024. 

On July 1, the bill was ordered to a third reading in the Assembly. It needs a two-thirds vote of each house and a majority vote at the ballot. 

An earlier version of the bill proposed a $15.5 billion bond measure. Even at the lower $10 billion amount, lawmakers are calling it “the single largest investment in public funding for climate resilience in California’s history.” 

The bond measure would provide: 

    • $3.8 billion for safe drinking water, drought, flood and water resilience. 
    • $1.5 billion for wildfire prevention and forest resilience.
    • $1.2 billion for sea level rise and coastal resilience. 
    • $1.2 billion for biodiversity and nature-based climate solutions. 
    • $850 million for clean energy. 
    • $700 million for park creation and outdoor access. 
    • $450 million for extreme heat mitigation. 
    • $300 million for climate-smart farms, ranches and working lands. 

At least 40% of the funds would go to projects that benefit vulnerable populations or disadvantaged communities. 

Clean Energy Projects

Of the $850 million earmarked for clean energy projects, $475 million would go to the California Energy Commission to support the development of offshore wind. That would include building or upgrading port facilities to accommodate the manufacturing, assembly and staging of offshore wind equipment. 

An additional $325 million would go toward clean energy transmission projects. And $50 million would be available for long-duration energy storage, zero-emission distributed energy backup assets, virtual power plants or demand-side grid support.

The $1.5 billion for wildfire prevention and forest resilience would include $35 million to reduce wildfire risk related to electricity transmission. 

The proposed bond measure comes as the state faces an increasing sense of urgency over the climate crisis. 

“We are already seeing the devastating effects of climate change — more extreme heat waves, catastrophic fires and floods, coastal erosion, and severe droughts,” Sen. Ben Allen (D), a lead author of SB 867, said in a statement June 30. “Unless we take action now, the cost to address these impacts will become increasingly overwhelming.” 

The California Natural Resources Agency’s Fourth Climate Change Assessment predicts that climate change will cost the state $113 billion a year by 2050 unless action is taken. 

Every dollar spent on resiliency saves $6 in disaster relief, according to Federal Emergency Management Agency estimates cited in the bill. 

Bond Fatigue?

The Assembly Natural Resources Committee held an informational hearing on the bill July 2. 

Assemblyman Josh Hoover (R) said that while there are “great things” in the bill, “I do remain concerned that there’s a bit of bond fatigue among the electorate.” 

Other lawmakers noted that budget cuts made for the new fiscal year in response to a $46.8 billion shortfall had hit climate programs. 

“We’ve got some pretty gloom-and-doom budget circumstances before us. There might not be other resources in front of us to be able to make these investments,” said Assemblyman Eduardo Garcia (D), one of the bill’s authors. 

Garcia said the bill would also provide an economic stimulus to parts of the state with high unemployment rates or where impacts of climate are felt disproportionately. 

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Federal Judge Stays Biden’s LNG Export Application Pause

The U.S. District Court for Western Louisiana on July 1 issued a stay on the Biden administration’s pause in considering new applications for LNG export facilities. 

The decision from Judge James Cain approved a motion from 16 Republican state attorneys general, led by Louisiana’s Liz Murrill. 

President Joe Biden announced the pause in processing new applications to export gas to non-free-trade-agreement (FTA) countries this January in order for the Department of Energy to update its approval process and study the impact of additional LNG export facilities. 

The pause did not impact applications that already were moving through the process, including Venture Global’s Calcasieu Pass 2 project being planned for Cameron Parish, La., that FERC approved last week at its monthly open meeting (CP22-21, CP22-22). The project, which still must be approved by DOE, would be able to export 20 million metric tons per year. Commissioner Allison Clements dissented from the approval because she said the commission failed to fully consider the project’s greenhouse gas emissions and its impact on the local fishing industry. 

Cain noted in his decision the pause in processing new applications was done without any publication in the Federal Register that explained or justified it and that DOE has not opened any rulemaking related to it. 

“The defendants’ choice to halt permits to export natural gas to foreign companies is quite complexing to this court,” Cain wrote. “Defendants remark that the purpose is to update its information as to how these exports to non-FTA countries might affect the economy and inherently consumers of natural gas here in the United States, and the effect on the environment. However, … DOE has made updates to its studies on several occasions without the president making an announcement of an unprecedented climate change action, and without … DOE declaring a wholesale ‘pause’ on pending current and future applications of exports to non-FTA countries.” 

Cain wrote that “it is undisputed that natural gas is cleaner than coal” and that gas being cheaper leads to reduced coal use around the world. Thus, “it appears that … DOE’s decision to halt the permit approval process for entities to export LNG to non-FTA countries is completely without reason or logic and is perhaps the epiphany of ideocracy,” he wrote. 

The court agreed with the AGs that their states would face irreparable harm from the pause because of lost revenue and market share. They also were deprived of a procedural right because the policy was not properly announced under the Administrative Procedure Act’s processes, it found. 

Murill welcomed the court’s ruling. 

“As Judge Cain mentioned in his ruling, there is roughly $61 billion of pending infrastructure at risk to our state from this illegal pause,” Murill said. “LNG has an enormous and positive impact on Louisiana, supplying clean energy for the entire world, and providing good jobs here at home.” 

The Sierra Club noted that the stay does not require authorization of new facilities, but DOE will have to continue its review of pending projects that were paused. DOE also can continue working on its review of what analysis the “public interest determination” requires for approval of LNG facilities. 

“Deciding whether or not to approve LNG export applications has serious consequences for how much Americans pay for energy and whether there is clean air and water to support healthy local communities and ensure thriving local industries, like fishing,” Sierra Club Staff Attorney Louisa Eberle said. “DOE has the authority — and obligation — to adequately review the true impacts of LNG exports, and we believe they will come to the same conclusion we have, which is that expanded LNG exports are not in the public interest and the pending applications should be denied.” 

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Portland General Electric Formalizes EDAM Commitment

Portland General Electric (PGE) on July 2 formalized its commitment to join CAISO’s Extended Day-Ahead Market (EDAM), making it the second entity in the Western U.S. after PacifiCorp to sign an implementation agreement.

CAISO CEO Elliot Mainzer commented on PGE’s move in an announcement.

“Portland General Electric has been an excellent partner in our real-time electricity market and has been very engaged in our work with stakeholders to design the Extended Day-Ahead Market,” Mainzer said. “PGE’s formal commitment to join EDAM provides more positive momentum for building a fully integrated Western day-ahead market that will benefit all market participants and their customers.”

PGE serves 1.9 million customers in Oregon with a peak load of nearly 5,000 MW. The utility announced its intent to join EDAM in March, which will “enable greater access to lower-cost renewable energy resources that are available from a more geographically diverse system,” CAISO’s announcement said.

The implementation agreement, which CAISO and PGE signed June 28, marks an important step in efforts to shift the “joint” authority that the Western Energy Imbalance Market’s (WEIM) Governing Body shares with the ISO’s Board of Governors over WEIM and EDAM matters to “primary authority,” which would require FERC approval but not a change to California law.

Tariff provisions to make that change won’t be triggered until EDAM obtains implementation agreements from a “set of geographically diverse” WEIM participants representing load equal to or greater than 70% of CAISO balancing authority area annual load in 2022. (See Pathways Initiative to Act Fast on ‘Stepwise’ Governance Plan.)

Tariff Waiver Sought

In a related move, CAISO on July 1 filed with FERC for a limited tariff waiver to facilitate PGE’s entry into the market.

The ISO’s tariff requires that an EDAM implementation date not be less than six months or more than 24 months after the date the EDAM entity implementation agreement becomes effective. Because PGE isn’t expected to begin participating in EDAM until fall 2026, CAISO requested a limited tariff waiver from FERC to support the utility’s participation more than 24 months after the effective date of the agreement.

“The complexity of enabling PGE’s transmission and technology to work in a compatible manner with the CAISO systems may require additional efforts over a period of slightly longer than 24 months, meaning it is not possible for PGE to implement its participation as an EDAM entity until the fall of 2026,” the ISO said. “Granting the waiver will provide additional time to allow the CAISO and PGE to effectively synchronize and coordinate their onboarding and readiness activities with PacifiCorp’s spring 2026 schedule and vendor engagement activities.”

The ISO and PGE agreed to perform parallel implementation work with PacifiCorp. (See PacifiCorp Fully Commits to CAISO’s EDAM.)

“Keeping PGE and PacifiCorp on the same EDAM implementation schedule is more efficient and creates the opportunity for joint implementation meetings and workshops and early vendor engagement that would otherwise not be available,” CAISO said. “Granting this petition will benefit all customers participating in the day-ahead market by facilitating PGE’s participation in EDAM.”

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Busy Summer Ahead for Pathways Initiative

Participants in the West-Wide Governance Pathways Initiative face a busy meeting schedule this summer as the group’s leaders look to advance on parallel fronts to develop a “regional organization” (RO) to assume governance of CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM). 

The Pathways Initiative hit a key milestone last month when CAISO began a stakeholder process to adopt the effort’s “Step 1” proposal for the ISO to elevate the “joint” authority the WEIM’s Governing Body shares with the ISO’s Board of Governors over WEIM matters to “primary” authority. (See CAISO Kicks off Stakeholder Process for Pathways Initiative.) 

“The CAISO board will be taking up the final recommendation with the EIM Governing Body sometime later this summer, or early fall, and then we’ll be working on the tariff language that will be required to actually make these changes,” Western Freedom Executive Director Kathleen Staks said during a June 28 meeting of the Pathways Initiative’s Launch Committee, of which she is a co-chair. 

Step 2 of the group’s efforts will be more complicated, said Launch Committee member Evie Kahl, general counsel at California Community Choice Association (CalCCA). That step, part of “Phase 2” of the committee’s work, deals with both the legislation needed to transfer WEIM/EDAM authority to the RO and the issues around forming the RO. 

Step 2 will consist of eight separate workstreams dealing with: the stakeholder process for an RO; CAISO-related issues such as the financial liability associated with governing an electricity market; analysis of the existing CAISO tariff; public interest issues; RO formation issues, such as form of incorporation; RO governance issues, such as board nominations and funding sources; California legislative issues; and other legal issues. 

Kahl emphasized that the CAISO tariff analysis is a “really important” workstream that will “cross over” into other streams. 

“The objective really is to define the portions of the tariff that will fall within the RO’s new scope of authority,” Kahl said. “And what it’s requiring is this foundational analysis that the team has started, looking at the existing CAISO tariff and looking at what sections are uniquely market functions, [and] which are uniquely [balancing authority] or transmission operator functions.” 

The “most challenging question” is how to handle sections of the tariff that touch on both the market and BA functions, she said. 

Kahl also said the public interest workstream will incorporate input from the state regulators who initiated Pathways a year ago, as well as work from consumer advocates and other “important voices.” 

“It’s going to be examining things like, ‘What are the public interest obligations that are going to be a part of the RO’s responsibility?’ For example, a responsibility to minimize consumer costs and, in undertaking market design, to respect state and local authority,” she said. “It’s also going to be looking at the role for state regulators and consumer advocates in the process of designing the market and tariff approval process.” 

Kahl set out the public workshop schedule for many of the workstreams, including: 

    • July 25 — RO formation and governance, which will discuss issues such as the RO’s state of incorporation, principal place of business and entity formation status. The workshop also will cover the nominating and selection process for the RO board and number of board seats; RO and CAISO board joint sessions for areas of shared authority; the potential for reserving board seats for particular sectors; and the transition from the WEIM Governing Body process to that of the RO.
    • July 31 — Public interest, to discuss the roles for a states committee and consumer advocates. 
    • Aug. 2 — Tariff analysis and CAISO issues, which will deal with what authority might be retained by CAISO; RO compliance, financial obligations and liability; and RO/CAISO staffing structure. The workstream also will cover RO authority matters. 

Special Process for Stakeholder Process

Staks said the Pathways Initiative is undertaking a different approach for the largest workstream, the stakeholder process, for which the Launch Committee has retained nonprofit group Gridworks to facilitate four meetings. This workgroup also will include some non-committee members, she said. 

Matthew Tisdale, executive director at Gridworks, said his company received funding from the Arthur M. Blank Family Foundation to support its work with Pathways. The workstream will focus on comparing how other RTOs/ISOs in the country, as well as the Western Power Pool’s Western Resource Adequacy Program (WRAP), engage with stakeholders. It will examine seven key elements: 

    • Among competing priorities, who selects the policy topics for stakeholder attention? 
    • Who among stakeholders frames and presents a policy problem and proposes a range of solutions? 
    • In stakeholder workshops, who is responsible for facilitating discussion and advancing an agenda? 
    • Will the stakeholder process include voting, and if so, how frequently should sector-based voting occur? 
    • How should sectors be defined and weighted for voting purposes? 
    • What kind of forums and committees use to organize themselves? 
    • How often and through what nomination process should topics be subject to a stakeholder process? 

Gridworks’ role in the workstream is to “organize” and “summarize,” not to “editorialize,” Tisdale said. It aims to provide stakeholders with a summary in early September. 

The stakeholder process work group will hold virtual workshops July 11, July 24, Aug. 2 and Aug. 28, all starting at 9 a.m. PT. 

Budget Update

The Pathways Initiative raised about $500,000 to complete its Phase 1 work (mostly committed to developing Step 1) but under-ran its budget by $150,000. That money will be carried over and applied to Phase 2, according to Jim Shetler, general manager of the Balancing Authority of Northern California and co-chair of the Launch Committee’s Administrative Work Group. 

The budget for Phase 2, which the committee expects will run from this month to the fourth quarter of this year and produce a Step 2 proposal, remains about $450,000, for which the committee is seeking funders, Shetler said. 

Phase 3, which is intended to implement Step 2 and likely will run from this fall to the first quarter of 2026, has a budget of $636,000.

Shetler said they will seek additional funding from the U.S. Department of Energy for Phase 3. 

DOE in April rejected the Pathways Initiative’s first attempt to secure $800,000 in agency grants. But later that month, Launch Committee Co-Chair Pam Sporborg, of Portland General Electric, said that, based on DOE feedback, the group likely would reapply with a “more detailed and specific proposal” on how it would spend the money. 

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BOEM Approves NJ’s Atlantic Shores OSW Project

The federal Bureau of Ocean Energy Management (BOEM) has given the go-ahead to New Jersey’s foremost offshore wind project, the 1,510-MW Atlantic Shores Offshore Wind. 

The approval of Atlantic Shores, which would serve 700,000 homes, boosts the state’s ambitious offshore wind plans nine months after Danish developer Ørsted abandoned two of the state’s first three projects off the New Jersey coast, Ocean Wind 1 and 2.  

The New Jersey Board of Public Utilities (BPU) approved Atlantic Shores and Ocean Wind 2 in 2021, following the agency’s backing of Ocean Wind 1 in 2019. Ørsted’s decision not to follow through on its two projects means Atlantic Shores likely will be the state’s first offshore wind project to come online, estimated between 2027 and 2029. 

BOEM’s approval also covers a second phase of the Atlantic Shores project, with capacity of about 1,300 MW and serving about 300,000 homes. However, that also would require approval from the BPU in a future solicitation. 

U.S. Department of Interior Secretary Deb Haaland called the BOEM approval a “milestone” and “yet another step toward our ambitious goal of deploying 30 gigawatts of offshore energy by 2030.”  

“Our clean energy future is now a reality. … We are addressing climate change, fostering job growth and promoting equitable economic opportunities for all communities.” 

BOEM granted the Record of Decision (RoD) to the two Phases of Atlantic Shores based upon the agency’s compilation of an environmental impact statement (EIS). The agency held four public hearings on the EIS, which the agency said resulted in several measures designed to “minimize or mitigate the potential impacts of the project, including visual impacts and potential impacts to marine life and to existing ocean uses such as fishing.” 

While the EIS concluded the project would have a “major” impact on commercial and for-hire recreational fishing, the view from the shore and on-ship traffic, it found the impact would be moderate or minor on most of the 19 categories studied. These included recreation and tourism, land use and coastal infrastructure. (See BOEM FEIS Cites ‘Major’ Impact from NJ OSW Project.) 

Atlantic Shores said in a statement the developer expects a decision on the project construction and operations plans (COPs) to be made in the fall and all reviews and permits to be completed by October. The project should be “shovel ready” by the end of 2024, the company said. 

“We recognize the significance of this milestone,” Joris Veldhoven, CEO of Atlantic Shores, said in a statement. “And we’re excited to work with our supply chain partners to continue making near-term investments and creating great-paying union jobs.” 

The Oceantic Network, which works to advance the offshore wind sector, noted that BOEM’s approval of Atlantic Shores follows the agency’s granting of COPs for Sunrise Wind and Empire Wind, both offshore New York, and New England Wind 1 and 2, off the coast of Massachusetts. Those projects, along with Atlantic Shores, will have a combined capacity of 8,200 MW, enough to power 3 million homes, the organization said. 

“BOEM’s consistent efforts to move projects through the regulatory process are pushing the offshore wind industry forward,” Sam Salustro, vice president of strategic communication at Oceantic Network, said in a statement. 

Clean Energy Future

New Jersey Gov. Phil Murphy (D), noting that Atlantic Shores ultimately could provide power for 1 million homes, said in a message on X, formerly known as Twitter, that the approval is “bringing us one step closer to a 100% clean energy future.” 

Murphy has set a state target of installing 11 GW of OSW capacity by 2040, and the state has aggressively pursued that goal. Since the termination of Ørsted’s projects, the BPU has concluded its third solicitation with the endorsement of two new projects — the 1,341-MW Attentive Energy Two project and the Leading Light project, with two phases of 1,200 MW each. The capacity of BPU approved projects now is 5,251 MW. 

In April, the BPU opened a fourth solicitation, which will close at 5 p.m. July 10. And in May, Murphy directed the BPU to advance the opening of the fifth solicitation by 15 months, to the second quarter of 2025.  

The state also has sought to position itself as a key hub for the growing industry, spending $600 million on the New Jersey Wind Port, in South Jersey, which has heavy-lift wharfs and space for manufacturing and marshaling. The first phase is expected to open this year. 

Paulina Banasiak O’Connor, executive director of the New Jersey Offshore Wind Alliance, which represents wind developers and other sector members, called BOEM’s announcement a “critical” development. 

“As the most mature project positioned to serve New Jersey, the Atlantic Shores South project is in many ways the vanguard of New Jersey’s offshore wind industry and all the benefits our industry will bring to the state,” she said. 

Diverging Responses

Environmental groups welcomed the project’s advance. 

“The momentum for offshore wind in New Jersey is only growing as we continue to lead the region in our transition to a cleaner, greener future for our communities,” said Sierra Club New Jersey Director Anjuli Ramos-Busot. 

Doug O’Malley, director of Environment New Jersey, called the decision a “clear win for offshore wind and another step forward to making offshore wind a reality off the Jersey Shore” after the “gut punch” of Ørsted’s withdrawal. 

“Offshore wind remains the best strategy for New Jersey to generate clean, renewable energy and reduce climate pollutants from fossil fuels,” he said. “This is the strongest sign that offshore wind is back.” 

With as many as 195 turbines planned and located 8.7 miles off the New Jersey coast, the project is the closest to the shore and faces local opposition. The project plans include 10 offshore substations with subsea transmission cables potentially making landfall in Atlantic City and Sea Girt. 

Commercial fishermen fear their catch will be sharply diminished by the wind projects, and local governments, the tourist sector and residents fear a loss in the quality of life and in tourist visits due to the visibility of wind turbines. 

Bob Stern, president of Save Long Beach Island, which opposes the project, said “the decision was not unexpected,” adding that “the agency has never seriously considered any alternative to it,” referring to BOEM.

“The shore experience from Long Beach Island and nearby shores will be destroyed, not only due to the visibility of the turbine structure, but due to the difficulty of watching blades rotating, the airborne noise at the shore from the pile driving construction and the operation of the turbines, and the reduced breeze due to the extraction of wind energy by the turbines,” he said. “It will force East Coast commercial, military, and fishing vessel traffic into a narrow 11-mile wide corridor creating safety concerns for both the vessels and the whales that migrate through that same corridor.”

Anticipating the decision, Stern said in a June 28 email that the non-profit citizens group has been preparing for the approval of Atlantic Shores, and included a request for donations.
“We have created a strong technical base and intend to file a number of lawsuits against the Atlantic Shores South project soon,” the email said. “So, this fight is far from over. It is, in fact, just beginning with intensity.”

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Avangrid Details Progress on NECEC Tx Line

Construction on Avangrid’s hotly contested New England Clean Energy Connect (NECEC) transmission project has made significant progress following a two-year pause, according to a filing submitted to the Maine Public Utilities Commission on July 1. 

NECEC is a 1,200-MW transmission line intended to send power from the Québec border to Lewiston, Maine, a city in the southern part of the state. The project is the result of a competitive Massachusetts clean energy solicitation and ultimately will be funded by ratepayers, as well as by Hydro-Québec. 

The project includes about 145 miles of new 320-kV HVDC transmission line, a new converter station, an upgrade to an existing substation and an AC line connecting the converter station to the substation. It also requires a series of upgrades to the local grid once it reaches the substation, including a new 26-mile 345-kV line and rebuilds of several other line segments. 

According to the July 1 filing (PUC docket 2017-00232), Avangrid said it has installed 504 pole bases, 441 poles, and wires on 178 poles for the HVDC line. The project’s website says the line will require 829 structures, with most structures being monopiles.  

This marks significant progress from the update filed at the beginning of this year, which indicated 187 pole bases had been set with 128 poles installed. 

Regarding the AC network upgrades needed to support the line, “since construction activities resumed in December 2023, access is approximately 81% complete, foundations are 41% complete (294 complete), pole setting is 31% complete (217 complete) and wire work is 34% complete (36 circuit miles),” Avangrid wrote.  

Work also is underway at the new converter station, where the foundations are in place, the company noted. 

The filing indicated the total taxable investments for the project as of April 1 have reached $904 million, an approximately $200 million increase compared to April 2023, after construction resumed in October 2023. These costs represent “actual construction work in progress and an applicable allocation of overall development costs as appropriate,” the filing noted.  

While the project initially was expected to cost about $1 billion, the delays have led to an approximately $500 million cost increase. In late 2023, Massachusetts passed a budget bill enabling its electric distribution companies to recover costs associated with the construction delays.  

When in service, the Maine PUC’s permitting approval indicates the line and its associated power contracts will help lower energy and capacity costs in New England, bolster grid reliability and fuel security, and help reduce carbon emissions by increasing hydropower imports.  

According to the project website, the line is tracking to be in-service “by 2025.” Avangrid declined to provide further comment on the status of the project. 

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FERC Denies Missouri River Complaint Against SPP

FERC has denied a complaint by Missouri River Energy Services (MERS) that SPP violated its tariff by failing to give the utility any firm transmission rights in every annual allocation since 2016, resulting in more than $25 million in overcharges.  

In its June 27 order, the commission said Missouri River did not meet its burden to prove that SPP’s implementation of the allocation process violated the tariff, filed rate doctrine or two FERC orders or that the allocation process is unjust and unreasonable (EL24-3). 

MRES, an SPP load-serving entity, filed a complaint with FERC under several sections of the Federal Power Act. It alleged SPP violated its tariff, filed rate doctrine and commission Orders 681 and 890 by not awarding any long-term congestion rights (LTCRs) to the utility. MRES also claimed the RTO’s lack of transparency into its LTCR allocations violated the Energy Policy Act of 2005 and Order 890. 

The utility asked FERC to order SPP to refund the overcharge and allocate LTCRs from the date of the complaint. 

The commission found MRES did not identify specific tariff language it believed the grid operator had violated and said SPP’s tariff does not support its argument that the utility is entitled to receive its nominated LTCR allocation. It said the RTO didn’t deviate from its filed rate because the tariff’s LTCR process does not require it to allocate nominated rights. 

FERC also said Order 681 gives flexibility to grid operators in how they design their long-term FTRs and allows them to limit the amount available to ensure feasibility. It noted LSEs would not necessarily be able to obtain all of the long-term FTRs they request. 

“As an initial matter, we note that the commission accepted SPP’s LTCR tariff process, including how it determines feasibility and the amount of LTCRs to allocate, as compliant with Order 681,” FERC wrote. “Thus, the commission has already determined that SPP’s tariff meets the requirements of Order 681.” 

The commission said MRES did not support its allegation that SPP violated Order 890’s transparency requirements by not supplying the utility with certain data and calculations used in the LTCR allocation process. Instead, FERC found that Order 890’s transparency requirements do not require SPP to provide MRES with either the shift factor data or SPP’s specific software implementation of the simultaneous feasibility test. 

FERC pointed out that there are several reasons the LTCR allocation process could result in MRES not being allocated the congestion rights.  

“Contrary to Missouri River’s contention, the fact that Missouri River was not allocated LTCRs is not in and of itself proof of an implementation error,” the commission said. 

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PJM MRC/MC Briefs: June 27, 2024

Markets and Reliability Committee

Stakeholders Endorse Revised Proposal to Align Energy, Gas Schedules

VALLEY FORGE, Pa. — PJM’s Markets and Reliability Committee last week endorsed a proposal to align the day-ahead energy market commitment cycle with the daily gas nomination deadlines in order to give gas generators more certainty on when they should procure fuel. (See “PJM Presents Electric Gas Coordination Proposal,” PJM MRC Briefs: May 22, 2024.)

The package would time three intraday commitment runs for gas generators, targeted to be commensurate with the three gas nomination deadlines under the North American Energy Standards Board. PJM would attempt to notify any generators picked up during those runs of their commitment before the corresponding NAESB deadline.

The committee initially rejected the proposal, which fell below the two-thirds threshold with 51% sector-weighted support, after stakeholders raised questions around language asking generators to notify PJM of whether they have or plan to procure the fuel necessary to meet their commitments.

After the proposal was rejected by the MRC, members suggested removing the notification provisions, and a second vote approved the package by acclamation.

Paul Sotkiewicz, president of E-Cubed Policy Associates, said the draft manual revisions did not reflect language in the proposal approved by the Electric Gas Coordination Senior Task Force (EGCSTF) stating that the notification process is voluntary, does not carry penalties and is not meant to be punitive if notification is not provided.

PJM’s Brian Fitzpatrick said the language was intended to appear in the manuals and would be added before a vote. He said the notification process was meant to give PJM dispatchers additional insight into the status of the gas fleet.

He also argued that regardless of PJM’s intent, the Independent Market Monitor had said it may view the notification as mandatory and that generators failing to provide their fuel status to PJM could face a referral to the FERC Office of Enforcement.

“We’re faced with this direct threat that it’s voluntary and if we don’t do it, we’re going to get a FERC referral,” Sotkiewicz said.

Monitor Joe Bowring said there had been no threats to market participants. He said that while it was his view at the EGCSTF that the notification should be mandatory, he recognized that the proposal would make it voluntary and stated the Monitor would enforce the rules as written and approved by stakeholders.

“The fact that stakeholders voted to remove any provisions about the notification that generators should provide to PJM about whether they have procured the gas to meet their commitments is surprising,” he said.

Bowring told RTO Insider that part of the misalignment between the electric and gas markets stems from the difference between the daily cycle the gas industry operates on, which starts at 10 a.m., and the midnight starting time for the daily electric market cycle. He argued that proposals drafted by the EGCSTF have sought to shift the risks created by that misalignment from gas generators to load.

While shifting market times to align with the gas cycle would resolve many of the issues, Bowring said generators could also reflect pipeline requirements in their parameters, which would mitigate their risk and provide PJM additional visibility on when resources can operate.

First Read on Expanded ‘Know Your Customer’ Rules

PJM presented a proposal to widen the scope of its “know your customer” (KYC) requirements to include a new “beneficial owners” definition, which would require due diligence checks on individuals who hold 10% of the voting power within a member entity.

The MRC is set to vote on the tariff revisions on July 24, with the Members Committee vote on Aug. 21.

Assistant General Counsel Eric Scherling said the proposal is intended to improve PJM’s understanding of which individuals contribute to the most risk profile of an entity and to align KYC definitions with corporate standards.

The beneficial owner definition is applicable to those who own, control or hold 10% or more voting power of an entity, either directly or together with family members. While the overall KYC design was based on the U.S. Treasury Department’s Financial Crimes Enforcement Network (FinCEN) rules, Scherling said PJM determined to use a lower 10% threshold for the beneficial owners definition.

The proposal also requires that PJM conduct background checks on beneficial owners, board of director members and principals of non-publicly traded members. Those entities would be responsible for providing a list of names for each of those categories and government-issued identifications, though the latter does not apply to boards unless requested by PJM.

For publicly traded entities, municipal power authorities and co-ops, only a list of principals, beneficial owners and board members would be required, though background checks could also be requested by PJM.

PJM Chief Risk Officer Carl Coscia said less information is requested for public entities because those data are already captured by Securities and Exchange Commission regulations, and the RTO’s aim is to have members validate that the information is timely and accurate.

Stakeholders questioned whether the proposed definitions could inadvertently capture shift supervisors or staff on real-time desks that have operational control over significant company assets but don’t necessarily make long-term strategic decisions.

Monitor, PJM Present Processes to Enable Multi-schedule Modeling

PJM and the Monitor presented two proposals to revise how the Market Clearing Engine (MCE) selects energy market offers to enable the implementation of multi-schedule modeling. (See “Stakeholders Discuss Path Forward on Multi-Schedule Modeling,” PJM MIC Briefs: June 5, 2024.)

Stakeholders considered both packages last year during a process to determine a methodology for winnowing generator schedules down to the most cost-effective offer forwarded to the MCE. Those discussions resulted in a PJM proposal using a formulaic approach being filed at FERC, which was rejected in March. (See “Stakeholders Endorse Multi-schedule Modeling Solution,” PJM MRC/MC Briefs: Dec. 20, 2023.)

The commission stated that PJM’s proposal would compromise market power mitigation by only considering the cost of market-based offers on the EcoMin parameter, even if that offer would be more expensive than a cost-based offer at higher outputs. The Monitor described the issue as the “crossing offer curves” scenario throughout the stakeholder process and in protests to the PJM proposal at FERC.

During the Market Implementation Committee meeting June 5, PJM’s Keyur Patel said the RTO planned to advance a proposal co-sponsored by it and GT Power Group, which received the second-highest degree of support during an October 2023 vote. The joint proposal retains PJM’s formulaic approach and seeks to address the crossing curves issue by selecting generators’ market-based offers only when they pass the three-pivotal-supplier (TPS) test under nonemergency conditions and select cost-based offers only when a resource fails the TPS test.

A joint proposal offered by the Monitor and GT would replace the formula with having market sellers choose the most economic cost-based offer to forward to the MCE.

Deputy Monitor Catherine Tyler said the formula in the PJM/GT proposal ignores market realities and retains some of the same problems that led FERC to reject the RTO’s original proposal. She argued that the formula would commit dual-fuel generators to operate on less economic fuels when the relative costs of fuels change during the operating day.

Bowring told RTO Insider that he considered a central flaw in PJM’s proposed formula to be that it only considers the highest-cost hours equal to the minimum run time and could therefore select the higher-cost fuel for the entire day rather than recognizing that, for example, gas was cheaper in the morning and oil was cheaper in the afternoon.

“That is not a logical, competitive or least-cost solution,” he said.

Bowring said that his goal is to try to reach a consensus before the next MRC meeting.

Responding to questions about why market sellers might prefer PJM’s formula over selecting from their own offers, GT’s Tom Hyzinski said some participants may prefer to have the RTO make that determination.

The “IMM wants the market participant to pick the schedule. PJM uses a formula to pick the schedule for the market participant. The market participant likely does not want to pick the schedule but would prefer PJM to pick the schedule. [The] IMM has not proposed an alternative formula that either PJM or the market participant can use to make the selection,” Hyzinski said.

Bowring said any market participant can use PJM’s formula, which has been provided in a spreadsheet, to make the choice.

“The generation owner ultimately and appropriately makes the decision about what fuel to burn. The Market Monitor’s proposal provides more flexibility to generation owners, including the option to use the PJM formula if they think that is preferable,” he said.

During the June 5 MIC meeting, Constellation Director of Wholesale Market Development Adrien Ford said her company was concerned about the precedent of PJM reviving past packages after a stakeholder-endorsed proposal was rejected by the commission. She said she may seek to waive the truncated voting rules to allow both proposals to be voted on alongside each other. She added that action would not presuppose Constellation’s position on the two proposals; rather, her concern was retaining options for stakeholders under the unusual situation.

Ford told RTO Insider on July 1 that the company plans to move the PJM/GT package at the MRC’s next meeting.

Consumer Advocates Seek Wider Scope for Deactivation Task Force

The Maryland Office of People’s Counsel and Illinois Citizens Utility Board proposed revisions to the issue charge framing the work of the Deactivation Enhancement Senior Task Force (DESTF) to includes several areas of concern around the future of resource retirements in PJM.

Phil Sussler, of the Maryland OPC, said there are stakeholder processes focused on allowing new generation to clear the interconnection queue faster, proactive transmission planning, responding to localized load growth and thermal generation retirements promoted by economics and government policies, but none of those deliberations are occurring in a coordinated manner.

Clara Summers, of the Illinois CUB, said the advocates’ proposal is not meant to slow any of those discussions, but rather to rework the scope of the DESTF to allow it to take on a wider slate of issues.

“Our effort is really meant to supplement, not supplant, that existing work,” she said.

Several consumer advocates have argued that PJM’s existing stakeholder processes around resource retirements have been scattershot and siloed into subcommittees in a way that prevents holistic solutions.

The expanded key work activities and scope section of the issue charge would include:

    • education on transmission technologies that can resolve transmission violations prompted by deactivations, including grid-enhancing technologies and energy storage;
    • education of the alternatives other RTOs have to reliability-must-run contracts that pay generators to continue operating past their deactivation date;
    • updates and follow-up on any revisions to PJM’s process for transferring capacity interconnection rights, which are being drafted through the Planning Committee; and
    • drafting proposals to establish cost-effective alternatives to RMR agreements.

The out-of-scope section of the issue charge would also be widened to exclude proposals focused on expanding the justifications for entering RMR agreements with generators, particularly for resource adequacy purposes.

First Read on 2 PJM Proposals to Revise Reserve Markets

PJM presented two proposals to enable the RTO to have the 30-minute reserve requirement dynamically change to reflect system conditions without affecting other reserve procurement categories and how deployment signals are conveyed to market participants.

The MRC is slated to vote on the proposals during its July 24 meeting; if endorsed, they will advance to the MC on Aug. 21.

The changes to the reserve requirement definition would shift the 3,000-MW procurement target to a formula selecting the greater of the peak load forecast times the average forecast error and forced outage rate, the primary reserve requirement or the largest active gas contingency.

PJM’s Emily Barrett said the static requirement doesn’t account for the varying risks PJM experiences day to day, which can often lead the reserves that the RTO actually requires to exceed 3,000 MW.

The proposal would allow PJM to increase specific extended reserve requirements without having to scale up all three requirements and over-procure reserves. Barrett said the primary use case would be extending the 30-minute reserve requirement without also having to procure a correspondingly higher amount of synchronized and primary reserves.

Allowing the three to be increased individually would align operational decisions with the markets to reduce out-of-market commitments, PJM’s Kevin Hatch said.

The second package would send reserve deployment instructions through resources’ basepoints as the primary notification that they are being called on to provide reserves. PJM would continue using the existing automatic notifications and all-call signal; however, the basepoint instructions would be considered the starting point for resources’ commitments and the 10-minute window in which they are expected to ramp up.

Members Committee

Stakeholders Elect Sector Representatives to Nominating Committee

The MC elected representatives to the Nominating Committee for each of the five sectors. The committee identifies candidates to serve on the PJM Board of Managers and advances them to be voted on by the MC. The 2025 sector representatives are:

    • Rory Sweeney, of the Northern Virginia Electric Cooperative, represents the Electric Distributor sector;
    • Jordan Nader, of the North Carolina Utilities Commission, represents the End Use Customer sector;
    • Marji Philips, of Rolling Hills Generating, represents the Generation Owner sector;
    • Sean Chang, of Shell Energy North America, represents the Other Supplier sector; and
    • Denise Foster Cronin, of the East Kentucky Power Cooperative, represents the Transmission Owner sector.

In addition to the five sector representatives, three members of the board serve on the committee: two voting members and one non-voting member who serves as the committee chair. The board selected Jeanine Johnson to serve as chair in May, while David Mills and Charles Robinson serve as voting members.

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Phillips, Christie Debate Loper Bright’s Impact on FERC Order 1920

The Supreme Court’s decision in Loper Bright Enterprises v. Raimondo is already making waves in the rehearing process on FERC Order 1920, with commissioners releasing dueling statements about what the end of Chevron deference will mean for the transmission rule. (See related story, Supreme Court Ends Chevron Deference to Administrative Agencies.) 

Commissioner Mark Christie released a statement after the court’s ruling June 28 arguing that the commission should reform the order on rehearing given the lack of Chevron deference, while Chair Willie Phillips released a statement July 1 arguing that 1920 is on firm legal footing even with the doctrine’s end. Ultimately, the issue will come down to a different commission than the one that approved the order, as three new members will have joined. 

Phillips argued that FERC’s authority to regulate regional transmission planning and cost allocation has long been recognized by bipartisan majorities of the commission and the D.C. Circuit Court of Appeals. 

“It could hardly be otherwise,” Phillips said. “Both regional transmission planning and cost allocation are practices that have exactly the type of ‘direct effect’ on commission-jurisdictional rates that the U.S. Supreme Court has held brings a matter within this commission’s jurisdiction. Indeed, our authority to regulate regional transmission planning and cost allocation is essential to the commission’s ability to ensure that customers have access to reliable, affordable supplies of electricity — our most fundamental statutory responsibility.” 

Order 1920 builds on Order 1000, which was upheld by the D.C. Circuit in South Carolina Public Service Authority v. FERC using Chevron deference. The Supreme Court held in Loper Bright that settled precedents would not be disturbed by its decision, so Order 1000 is safe. 

“Order 1000 is the sort of the foundation for this Order 1920,” Christie told RTO Insider on July 1. “But the Chevron deference is not available, and so my point is that lifeline is now not available on court challenges to Order 1920. So … we’re going to have the opportunity to do substantial amendments to 1920 when we get to the rehearing stage, and I hope that we’ll be able to do that.” 

Phillips argued that Order 1920 fits easily into the South Carolina precedent in that it does not promote particular public policies, dictate specific outcomes or include any selection mandate, and its cost allocation proposals rest on well-established principles. 

“As such, Commissioner Christie’s assertions about Loper Bright’s implications for Order No. 1920 cannot be squared with the court’s actual holding in that case,” Phillips said. “As always, I respect Commissioner Christie’s regulatory perspective on how we should exercise the regulatory ‘discretion’ that Congress vested in this commission. But his disagreement with how the commission exercised that discretion in Order No. 1920 does not provide a logical or reasonable basis for calling into question whether we have that authority in the first place.” 

Christie argued that it was clear when Order 1920 was issued that it would not work, and that was made more clear by the many petitions to strike it down, many of which came from states and their organizations, such as the National Association of Regulatory Utility Commissioners.  

But they were also joined by PJM, the National Rural Electric Cooperative Association and more. Given Loper Bright, FERC should fix its issues before it winds up before the courts, Christie said. 

“The commission still has an opportunity to amend Order No. 1920 into a true compromise that will promote sensible long-term transmission planning while protecting consumers and respecting and elevating the important role of states throughout the process,” Christie said. 

Two major issues Christie would like to see changed are the requirement that regional plans take into account the supply preferences of large customers, which he argued would spread the costs of their choices to every customer impacted by the cost allocation, and Order 1920’s language around state input in cost allocation. 

While the order requires developers to give states six months to hash out an agreement on cost allocation, FERC did not require the relevant transmission providers to file it. That was based on yet another court case, Atlantic City v. FERC, which said transmission owners have the right to file their own rates. In their requests for rehearing, parties argued FERC could get around that. 

Christie also noted that the order stops short of requiring transmission providers, which include the ISO/RTOs, from even reporting on their efforts to get states to agree to a cost allocation method. 

“It says that even if the states in a region agree, the transmission provider does not even have to file it,” Christie said. “I absolutely object to that, because that totally goes against what was promised in the [proposed rule]: that state agreements would be recognized.” 

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NERC Promises 1st ITCS Results by August

NERC last week published an overview of its work on the Interregional Transfer Capability Study (ITCS), laying out the overall strategy and technical approach for the project and outlining the documents to be released beginning this August.

The Overview of Study Need and Approach reviews the work done on the ITCS since Congress ordered the study in last year’s Fiscal Responsibility Act. The law requires NERC to deliver to FERC by December a study on the total transfer capability between neighboring regions, additions to transfer capability that could strengthen grid reliability, and recommendations to meet and maintain total transfer capability.

Work on the ITCS began after FERC approved the ERO’s plan for funding the study last August. (See FERC Approves NERC Transfer Study Funding Request.) NERC is in overall control of the study through the ERO Executive Leadership Group, which is led by NERC Chief Engineer Mark Lauby, with participation from leadership of the regional entities. The ERO also formed the ITCS Advisory Group in the early days of the project to give industry stakeholders input into the project’s direction. (See SERC to be ‘Well Represented’ in ITCS Group.)

In the overview document, the ERO emphasized the “unprecedented” nature of the task assigned by Congress, calling the ITCS “the first comprehensive study of transfer capabilities between adjacent transmission planning regions [that] will use 12 years of data, capturing a wide variety of operating conditions and historical weather events … to determine potentially deficient areas.”

Congress required that NERC base the ITCS on transmission planning regions identified in FERC Order 1000. The project team has further subdivided these regions in some cases “to provide more granular analysis of transfer capability limitations, especially under specific weather scenarios.” NERC said this approach was necessary because some of the planning regions, particularly in SPP, covered large geographic areas with significant internal transfer constraints.

According to the overview document, the ITCS report will consist of three documents. Part 1, to be issued in August, will present a transfer capability analysis for 2024 and 2033, covering both summer and winter for each year. Total transfer capability will be calculated “by determining the amount of additional transfers that can be added to base transfers already modeled while respecting contingency limits,” and will comprise two parts:

    • Base transfer level, indicating “scheduled power flows between areas in the starting case.”
    • First contingency incremental transfer capability, which simulates the amount of extra power that can be transferred during an unexpected event.

NERC will use the transfer capability limits between each neighboring region as a “critical input into Part 2,” which will be published in November. The goal for Part 2 is to identify conditions in areas that might experience energy deficiencies, such as extreme weather scenarios; determining areas where deficiencies are severe enough to justify additions to interregional transfer capability; and “prioritizing interfaces for transfer capability increases.”

The ERO will limit its recommendations to target megawatt ranges of transfer capability and will not recommend any actual transmission projects to meet its targets.

Under Part 3, which will be published in the same document as Part 2, NERC will provide recommendations to meet and maintain transfer capability based on the results of the transfer capability and energy deficiency analyses in parts 1 and 2 respectively. These may include further studies to measure progress addressing risks and ensure that recommended additions can be maintained reliably, technology that may address transfer capability limitations, and enhancements to regulatory mechanisms, policies or standards.

Congress mandated that the ERO study transfer capabilities only within the U.S.; the documents submitted to FERC this year will focus on the U.S. However, NERC said in the overview that it already concluded the study “would be incomplete without a thorough understanding of the Canadian limits and available resources.” Transfer capabilities between Canadian provinces and from the U.S. to Canada therefore will be the subject of a fourth report, to be released in the first quarter of 2025.