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November 4, 2024

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NW Senators Urge BPA to Delay Day-ahead Market Decision

All four U.S. senators representing Oregon and Washington have urged the Bonneville Power Administration (BPA) to delay its decision to join a Western day-ahead electricity market until developments play out further around SPP’s Markets+ and CAISO’s Extended Day-Ahead Market (EDAM).

In a July 25 letter addressed to BPA Administrator John Hairston, Democratic Sens. Jeff Merkley (Ore.), Ron Wyden (Ore.), Maria Cantwell (Wash.) and Patty Murray (Wash.) called on the federal power marketing administration to “act carefully and deliberately” before selecting a market.

The letter lays out the need for a “reliable, resilient and clean electrical grid” to achieve “the economic and environmental goals of the Pacific Northwest,” including electrifying transportation and buildings and “meeting the demands of our growing manufacturing and data center industries.”

It also points to the requirement for continued reliable service for residents and businesses in the face of “increasingly frequent extreme weather events.”

The senators’ letter additionally signals a preference shared by many state officials, environmental groups and large energy users across the West: that the region would benefit more from one organized electricity market than from two.

“In light of these major challenges, we share your view that ‘Bonneville’s customers and electricity consumers across the Pacific Northwest may achieve more benefits from participants coalescing around one regional market in the West,’” the senators wrote, quoting from a policy letter circulated by Hairston in January.

The letter comes about four months after BPA staff published a recommendation that the agency choose Markets+ over EDAM and just over a month before it is expected to issue a draft record of decision on its selection. A final decision is slated for November. (See BPA Staff Recommends Markets+ over EDAM.)

“Given ongoing uncertainties and the changing landscape with regard to both day-ahead electricity markets, we are concerned that BPA has expressed a preference for one market before complete and final information is available for clear decision making,” the senators wrote.

Among those uncertainties, according to the senators, is the fact that the Markets+ tariff, which SPP filed with FERC in April, is still under review by a largely new slate of commissioners and could face deficiency letters that take additional time to resolve.

Although not cited in the letter, PacifiCorp, the first utility to fully commit to EDAM, has asked FERC to reject the Markets+ tariff without prejudice, letting SPP refile it without a provision that would allow Markets+ participants to contribute their transmission rights in nonparticipating systems. (See SPP Markets+ Tariff Sparks Concerns for PacifiCorp, NV Energy.)

FERC issued a mostly clean approval of CAISO’s EDAM tariff last December.

The senators also raised a particularly heated topic in the West right now: the potential impact of seams between Markets+ and EDAM, which they said “may prove challenging to resolve, leaving ratepayers unable to realize economic and reliability benefits.”

In response to this concern from stakeholders, both BPA and SPP have said they have ample experience dealing with market seams and would be able to reliably manage the transfer of energy between the two markets. (See SPP’s Experience with Seams Could Help Markets+.)

14 Questions on ‘Leaning’

The senators acknowledged one of BPA’s primary reservations about committing to EDAM — CAISO’s state-run governance — and it credits the agency with spurring a regional effort to increase the ISO’s independence.

“The firm position taken by BPA that governance reforms were necessary helped inspire the West-Wide Governance Pathways Initiative last year. We see this effort has made real progress, culminating with NV Energy’s recent announcement that it intends to join EDAM,” the senators wrote.

For its part, BPA said July 18 that it has ramped up participation in the Pathways Initiative as the effort moves into its second phase, which is focused on changing California law related to CAISO’s governance and establishing an independent Western “regional organization” to assume oversight of the ISO’s EDAM and Western Energy Imbalance Market. But an agency official also noted that the move did not indicate BPA was pulling back from its “leaning” in favor of Markets+. (See BPA Stepping up Participation in Pathways Initiative.)

The senators asked BPA to clarify the reason for its leaning by responding to 14 questions with detailed analysis by Aug. 25. Among them are requests for BPA to explain which of the two day-ahead markets it expects would bring lower energy costs to the Northwest, provide the greatest improvement to grid reliability and reduce greenhouse gas emissions by the largest amount. The senators also asked if the agency’s concerns about CAISO’s governance would be assuaged by California’s adoption of the Pathways Initiative proposal and, if not, what outstanding issues remain.

“BPA’s decision to join a day-ahead market is monumental; BPA must be able to demonstrate that it is in the best interests of communities across the Northwest that are reliant on BPA for both power and transmission services,” they said.

The senators concluded by saying that their letter should not be taken as favoring one market over the other.

“We share a strong belief that any decision of this magnitude warrants thorough evaluation of all options, including joining neither market at this time,” they said. “BPA should refrain from making any draft or final decisions until there is less uncertainty and BPA can prove that any decision will provide the greatest benefit to the entire Northwest.”

In a statement emailed to RTO Insider, BPA said it “understands the magnitude of this decision and is committed to ensuring we do the right thing for our customers and the region through the deliberative process we have engaged in so far. BPA is committed to fully evaluating the benefits and mechanics of day-ahead markets to accomplish this objective.”

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FERC Open Meeting Showcases Order 1920 Rehearing Debate

WASHINGTON — The ongoing debate around Order 1920 and its pending rehearing requests continued at FERC’s monthly open meeting July 25, a day after it came up at a House oversight hearing. (See related story, Order 1920 Debated at House Hearing with All 5 FERC Commissioners.) 

Order 1920 came after Order 2023, which set new standards for interconnection queues, and Order 1977, which implemented FERC’s new backstop siting authority for lines in National Interest Electricity Transmission Corridors. 

“I believe this suite of transmission reforms is balanced,” Chair Willie Phillips said. “And I believe it will give us what we so desperately need to meet the demand that we know is going up in our country; to bring all of those resources that we know are waiting in the wings.” 

Phillips also noted that a group of state regulators from around the country supported Order 1920 in a letter to FERC this week (RM21-17). 

But legal challenges to the order kicked off July 15 when FERC issued a notice that it had not acted within its 30-day statutory deadline for responding to rehearing requests. A group of Republican state attorneys general have filed an appeal of the rule with the 5th U.S. Circuit Court of Appeals — as have many other parties, including those that generally support it, in appellate courts around the country. 

The commission did not say why it had not acted on the nearly 50 rehearing requests filed, but former Commissioner Allison Clements departed at the end of last month, and three new commissioners have joined since the order was issued in May. 

One area even some supporters of the rule would like to see changed on rehearing is whether transmission providers should be required to file any alternative cost allocation schemes proposed by state regulators. Commissioner Mark Christie dissented from the order over the issue. 

“We’ll respond to every single issue raised” in the rehearing requests, Phillips told reporters after the meeting. “To the extent that there are improvements that can be made to the rule, I look forward to working with my colleagues on what those might be. I think you hear me joke all the time that it’s a perfect rule, but I do believe that while it’s a great step forward, we’re just getting started. We can make improvements.” 

Christie said ensuring FERC gets to rule on any cost allocation proposal from states is a change that should be adopted on rehearing. 

“That ought to be one of the top priorities in amending because I think there’s going to have to be several major amendments to this rule to make it something that certainly would be acceptable to the states,” Christie said. “And I think that would just be one of the many issues that needs to be changed. And I would hope that there will be a majority on FERC amenable to making those major changes because, otherwise, this rule is not going to work.” 

Phillips and Clements did not require any resulting state plans be filed in part because of a precedent in Atlantic City Electric Co. v FERC, they argued. Christie argued in the dissent that the case did not tie FERC’s hands that much.  

An alternate interpretation is before the commission on rehearing, with the Harvard Electricity Law Initiative’s Ari Peskoe arguing that the precedent only stops FERC from forcing utilities to cede their rights to file rate changes under Federal Power Act Section 205. 

“Atlantic City does not prevent the commission from amending the pro forma [Open Access Transmission Tariff] to include a process for filing all regional cost allocation methods approved by relevant state entities, regardless of the transmission provider’s approval,” Peskoe wrote in his rehearing request. “Imposing a process for filing relevant state entities’ cost allocation methods would not ‘deny [utilities] their right to unilaterally file rate and term changes.’” 

Some state regulators have made similar arguments in their rehearing requests, noting that FERC has given their counterparts in SPP cost allocation filing rights. 

But Christie also argued that additional changes would be needed for his support, including giving states the chance to approve the parameters and benefits used in the planning process. As written, he argued, the order will spread the cost of public policy lines to unwilling states, contrary to Phillips’ continued insistence. 

Christie noted that MISO Independent Market Monitor David Patton has repeatedly criticized the RTO’s Long Range Transmission Planning process, which was cited as the model for Order 1920 by supporters. Patton argues that the LRTP consistently overstates benefits, which leads to too much transmission being built. (See MISO IMM Knocks LRTP Benefit Calculations, RTO Poised to Add More Projects.) 

While Phillips and Christie have been engaged in an often-public debate on the merits of Order 1920, the majority on rehearing will include at least some of FERC’s three new members who are still getting up to speed on its voluminous record. 

“The commission works best when we have five members,” Phillips said. “What that really means is that when you have five commissioners, they bring with them all of their history, all of their experience [and] all of their expertise to bear. And I believe you get a better result; you get better orders; you get better outcomes because of that diversity of opinion. And so, because we have five now, I think we will get an even better order on rehearing.” 

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FERC Ends Section 206 Proceeding for New Brunswick Energy Marketing

FERC ruled July 25 that New Brunswick Energy Marketing does not appear to have horizontal market power in the New Brunswick (NB) balancing authority area, concluding a Section 206 proceeding that came out of a failed market share screening test (ER14-225-008, et al.).

The NB balancing authority includes parts of Northern Maine and Eastern Canada. NB Energy Marketing is a subsidiary of the crown corporation NB Power and is directly interconnected to the transmission systems of ISO-NE and the Northern Maine Independent System Administrator.

ISO-NE initiated a Section 206 proceeding after NB Energy Marketing failed a “wholesale market share indicative screen” in three of the four seasons in the 2020/21 study period, suggesting the presence of horizontal market power.

The proceeding aimed “to determine whether NB Energy Marketing’s market-based rate authority in the New Brunswick balancing authority area remains just and reasonable.” (See FERC Orders Section 206 Proceeding for New Brunswick Energy Marketing.)

Responding to FERC’s show cause order on horizontal market power, NB Energy Marketing made the case that the results of a delivered price test (DPT) and a sensitivity analysis indicate the company is not a pivotal supplier.

When accounting for NB Power’s capacity factors and average load, the company “has a market share generally less than 20% and does not contribute significantly to market concentration,” NB Energy Marketing wrote in its filing.

Based on this evidence, FERC terminated the Section 206 proceeding, concluding that “on balance, NB Energy Marketing has successfully rebutted the presumption of horizontal market power in the New Brunswick balancing authority area.”

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FERC Accepts NYISO Capacity Accreditation Changes, with 1-Year Delay

FERC on July 23 approved NYISO’s proposed tariff revisions to more accurately accredit natural gas resources’ capacity, but the commission delayed their implementation until 2026 (ER24-2096).

NYISO pitched the changes as a way to help improve winter reliability by accounting for gas supply constraints and correlated derates in its capacity accreditation framework, which measures resources’ marginal contribution to resource adequacy.

Among the changes is a requirement that generators tell it by Aug. 1 prior to each capability year how much of their capacity was covered by firm fuel supply.

NYISO had proposed implementing this provision beginning with the next capability year, which begins May 1, 2025. That would mean generators would have just a week after the revisions went into effect to make their determinations. But the ISO also said it and the New York State Reliability Council had not finalized the modeling changes needed to differentiate firm versus non-firm fuel in its resource adequacy models, nor were they likely to be finished by Aug. 1.

Though they supported the new rules, the Independent Power Producers of New York and the Ravenswood Generating Station asked FERC to delay implementation until next year. NYISO did not oppose the request.

“The problem was that without firm or non-firm definitions on Aug. 1, our capacity suppliers would have to elect” as firm resources, said Richard Bratton, director of market policy and regulatory affairs for IPPNY. “We should be in a good place by next spring in terms of what firm and non-firm mean, so that our generators can understand whether it’s economical for them to elect firm or non-firm for the following capability year.”

Other changes include accounting for a generator’s ability to store on-site fuel and for the temperature of generators’ cooling water. The revisions also eliminate the category of “capacity-limited resource,” defined as a generator that is able to take extraordinary measures to increase its output above its normal upper operating limit. NYISO deemed this no longer necessary based on the other provisions in the proposal.

FERC agreed that the revisions would help NYISO more accurately align resources’ stated capacity with their actual output capability and therefore better reflect their ability to meet the ISO’s capacity requirements. The commission directed NYISO to submit a compliance filing within 30 days reflecting the delayed implementation date of the fuel supply rule. Commissioners Lindsay See and Judy Chang did not participate.

NYISO anticipates its system will flip to winter peaking in the 2030s. Some zones are already winter peaking, according to its 2024 Gold Book.

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Robb Reviews Challenges of Changing Grid at WIRES

NERC CEO Jim Robb told grid stakeholders July 25 that the rapid pace of change in the electric grid has left the ERO dealing with “frontier issues” that challenge its traditional ways of operating. 

“I always like to start off, when I talk with folks, that we are in a pretty amazing period of time for the electric grid because of the pace of change that we’re seeing, and the fact that it’s coming at the grid [from] a number of different directions at the same time,” Robb said in his keynote address to the WIRES 2024 Summer Meeting in Boston.  

“So we’re having to rethink a lot of things; we’re having to kind of, I don’t want to say invent new physics, but we’re having to understand physics in ways that we haven’t had to before, and that’s made our mission quite challenging.” 

In his talk, Robb said one of NERC’s roles in recent years is “to help catalyze a conversation around the reliability of the system, and how that plays against … all the environmentally policy-driven changes that we’ve seen to the sector.”  

He described energy policy as a balancing act between “three competing dimensions,” comprising access and affordability of energy, energy reliability and security, and the sector’s environmental footprint and sustainability.  

“Where the industry gets in … trouble is when we overweight one of those dimensions and [don’t] pay attention to the implications for the other two,” Robb said. “Because they all work at cross purposes, right? We could build a really cheap electric system, but it probably wouldn’t be reliable and it probably would have an environmental impact we don’t like. We could build a 100% reliable system, but we probably wouldn’t be able to afford it and we may not like its environmental impact.” 

Robb warned that with the large amount of renewable generation coming onto the grid, natural gas is becoming an increasingly essential source of reliable, dispatchable generation. With that reliance, the traditional construct of gas and electricity as “two parallel systems that happened to grow up together” no longer works. He said regulators “need to take a fresh look at the gas system as it relates to electricity, recognizing that gas has a number of other very important things it needs to be able to do, but we need to fix that interface and make that work for the benefit of customers.” 

ITCS Progress

During the Q&A period, WIRES Executive Director Larry Gasteiger asked Robb about the Interregional Transfer Capability Study that NERC has been working on since Congress ordered it last year in the Fiscal Responsibility Act. 

Last month, NERC published an overview of its work on the ITCS so far. It plans to release the report in three tranches, with the U.S.-relevant publications to be concluded by November of this year and a further report on Canadian transfer capacity in the first quarter of 2025. (See NERC Promises 1st ITCS Results by August.) 

Robb acknowledged that the “little homework assignment from Congress” has become “an even bigger beast than we thought it was when we started.” He said NERC spent nearly a year creating the framework for the study and identifying the tools and models for carrying it out. 

One of the challenges Robb identified was that the FRA required NERC to base the ITCS on the transmission planning regions identified in FERC Order 1000. This created problems because of the size of some of the regions; in MISO, for instance, “you obviously need to look at MISO North different than you look at MISO South,” he said. 

Although the first results from the ITCS will not be released until next month, Robb said some “early insights” from the study include that interregional transfer capacity differs greatly from summer to winter, and from one region to another. The interplay between weather, changing demand, and the physical assets on the grid have made the job “complicated to work our way through,” he added. 

“The challenge with interregional transfer assessments is that it really has a little bit to do with the wires, but it’s got a lot to do with the generating resources in the various planning areas and the loads, and the nature of the weather patterns that we’re dealing with,” Robb said. “So, we’re doing a lot of scenario analysis, using the big storms that we’ve seen as ways to pressure-test the system. We also have to kind of forecast where we think new generation will come in, what it will look like and how it would be impacted by those weather systems.” 

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CAISO Advances Pathways Initiative ‘Step 1’ Proposal to Board Vote

CAISO will recommend that its Board of Governors approve a proposal that eventually would give the Western Energy Markets (WEM) Governing Body increased authority over the ISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM). 

ISO staff discussed the recommendation July 23 during the second CAISO stakeholder meeting to discuss the West-Wide Governance Pathways Initiative’s “Step 1” straw proposal, which would elevate the “joint” authority the Governing Body shares with the ISO board over WEIM/EDAM issues to “primary” authority. 

The recommendation will advance that Step 1 proposal to a vote by the Board of Governors and the newly renamed WEM Governing Body on Aug. 13 — but some meeting participants expressed confusion over exactly what the two bodies will be voting on.  

CAISO staff provided a summary of the comments received on the proposal, which showed overall support from several stakeholders and members of the Pathways Initiative’s Launch Committee. Of the 31 entities that participated in indicative voting on the proposal, 22 offered support, six were neutral, one opposed and two had no position.  

“We got almost complete agreement on the issues here, and I think that stakeholder process and the highly collaborative nature of what everybody did led CAISO to be able to make the recommendation to move forward with the Step 1 proposal to the governing bodies,” Michael Colvin, director of regulatory and legislative affairs at the Environmental Defense Fund, said in the meeting.  

Adam Schultz, manager of regional coordination at CAISO, summarized the feedback received from stakeholders through submitted comments. A key point of concern centered around the trigger mechanism, which would require that the FERC tariff filing needed to establish the Governing Body’s primary authority wait until the EDAM obtains implementation agreements from a “set of geographically diverse” WEM participants representing load equal to or greater than 70% of CAISO’s balancing authority area annual load in 2022, according to the straw proposal.  

A few parties requested the trigger mechanism be eliminated and Step 1 be implemented immediately. Other stakeholders suggested the governance changes not take effect until one year after EDAM implementation.  

“The goal all along has been to achieve the greatest independence for the EIM and now EDAM governance within California’s existing law,” said Doug Marker, a specialist in intergovernmental affairs at Bonneville Power Administration. “So if we have found that there is the ability to achieve greater independence for the EIM and EDAM, then it should not wait for critical mass of participants signing implementation agreements.”  

“I recognize that’s a point that has been thoroughly discussed within the Launch Committee, but it is something that we flagged in our comments and would like to be brought before the boards when they consider this in August,” Marker added.

‘Extremely Frustrating’

Several stakeholders also took issue with the process used to develop the Step 1 proposal.  

Jessica Zahnow, of Puget Sound Energy, said WEM entities were not adequately engaged or represented in the process. 

“There’s some very material items that haven’t been addressed, and to just tell us that you think they are addressed and you’re going to continue forward is extremely frustrating. I don’t even know personally what the joint bodies are voting on,” Zahnow said. “The language needed to effectuate this proposal has not even been developed or put before us, and when told that the Launch Committee has already vetted these issues, they did so behind closed doors and this is the first time that most of us have seen this fully formed offering at CAISO.” 

Launch Committee Co-Chair Kathleen Staks, director of Western Freedom, noted that development of the Step 1 proposal was addressed in several of the initiative’s monthly public stakeholder calls and included input submitted from multiple public comment periods. Burton Gross, legal counsel at CAISO, provided further explanation.  

“What’s going to go to the board and the Governing Body for consideration is the proposal as written as a principle, and that is not going to be final,” Gross said. “As the trigger gets closer … we would then put in a set of governance documents that are designed to implement the proposal before the board and the Governing Body for approval.”  

An ISO spokesperson clarified to RTO Insider that the Step 1 proposal to be voted on Aug. 13 will set forth the proposed governance terms. If approved, the ISO will prepare revisions to the documents that implement the governance terms in a public process.  

Marker also reiterated prior concerns about the level of independence the Step 1 governance model achieves. (See CAISO Kicks Off Stakeholder Process for Pathways Initiative.)   

“While we appreciate the work of the Pathways Launch Committee and the proposal, we did indicate that our position is neutral, and that’s just because we want to be clear that we don’t think that this achieves the needed independence for EDAM governance, and that needed independence is going to take legislation,” Marker said.   

Despite opposition, ISO staff recommended moving forward with the proposal.  

“Our view at the staff level is that there is no need to make substantive changes to the Step 1 proposal as filed, and so for that reason, we are proposing to move forward with the joint meeting between the ISO Board and the Western Energy Markets Governing Body on Aug. 13 to consider and vote on the Step 1 proposal,” Schultz said.  

A memorandum outlining the ISO’s recommendations will be published in advance of the August meeting, though an exact date was not provided.  

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NV Energy Should Do More to Tap VPP Potential, Report Says

NV Energy’s virtual power plant market potential could grow from an estimated 134 MW this year to 1,230 MW in 2035, according to a new analysis.

But the utility isn’t taking full advantage of VPPs in its resource planning, Advanced Energy United said in the July 23 report, “Moving the Needle on DERs and VPPs in Nevada.”

And that means a missed chance to reduce the need for new gas-fueled generation in the state, said AEU, an association representing the alternative energy industry.

In March, Nevada regulators approved NV Energy’s proposal to convert its coal-fired North Valmy Generating Station to gas. And in its 2024 integrated resource plan (IRP) filed in May, the utility is seeking approval for a 411-MW gas-fired unit at North Valmy to start operating in mid-2028. The estimated cost is $573 million.

“Adding new gas instead of maximizing virtual power plant (VPP) capacity is a mistake Nevada cannot afford to make,” AEU staff said in a blog post accompanying the report’s release.

VPP Benefits

In a virtual power plant, customers allow a utility or third-party firm to control their distributed energy resources in a coordinated way to provide grid benefits, such as reducing peak-hour demand.

VPPs can help utilities address resource adequacy concerns and meet decarbonization goals, proponents say. They can keep costs down for a utility, and customers who participate in VPPs receive compensation that may help offset rising utility bills.

The AEU report is the latest analysis touting the potential of VPPs.

The Brattle Group released a report in April for GridLab that estimated California’s VPP market potential in 2035 at 7,671 MW — an amount roughly equal to 15% of peak demand. (See Virtual Power Plants Could Save Calif. $750M a Year, Study Says.)

A Brattle study for Google last year found that VPPs could provide resource adequacy at a net utility system cost that’s about 40% of the net cost of a gas peaker and 60% of the net cost of a battery. (See Brattle Group Finds VPPs Cheapest Alternative for Resource Adequacy.)

“If VPPs are left out of resource planning as load grows and fossil fuel assets retire, Nevada runs the risk of saddling ratepayers with unnecessarily expensive sources of capacity,” AEU said in its report.

‘Meaningful’ Compensation

NV Energy’s new IRP includes a distributed resource plan and a demand-side management plan. It features a proposed “grid value” portfolio, aimed at providing “flexible resources to manage operating conditions of the power grid,” the IRP states.

“It’s definitely going in the right direction, but we see areas for improvement,” AEU industry analyst Chloe Holden told RTO Insider.

AEU is concerned about the “vagueness” in NV Energy’s plan, Holden said, including a lack of detail about how different devices would be treated and how customers would be compensated.

“It is essential that customers are compensated in a predictable, meaningful fashion for VPP participation and that the level of compensation drives ongoing enrollment in the VPP,” AEU said in its report.

As another “best practice,” AEU recommends that NV Energy invite collaboration with third-party VPP companies and allow VPP participants to bring their own devices rather than being restricted to utility-owned equipment.

Holden said AEU took a conservative approach in its estimates of VPP market potential in Nevada. The potential increases from 134 MW in 2024 to 552 MW in 2029, 750 MW in 2031 and 1,230 MW in 2035.

The figures reflect the share of DER capacity that VPP participants are expected to provide at peak times, accounting for expected customer behavior.

DERs included in AEU’s analysis are smart thermostats, residential and commercial behind-the-meter battery storage, managed residential EV charging and managed commercial and public EV charging for both light- and heavy-duty vehicles.

The analysis doesn’t include traditional commercial demand response.

According to AEU, the 100 highest load hours for the NV Energy grid could be moderated with 721 MW of DER capacity, which is expected to be reached by 2031.

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Rhodium: US Accelerating Reductions in GHG Emissions

U.S. greenhouse gas emissions have decreased significantly over the past decade and are on track to decrease even more precipitously in the next decade, according to the Rhodium Group’s annual update of its “Taking Stock” report, issued July 23. 

The organization found the country’s GHG emissions were 18% lower in 2023 than in 2005, and it estimates they will be 32 to 43% lower in 2030. 

This is a marked acceleration just from 2022, the report’s authors write, but even a continuation of that would leave the U.S. short of the 50 to 52% reduction by 2030 that it committed to under the Paris Agreement in 2015. The country might not achieve a 50% reduction until the mid-2030s, the report indicates. 

Under a midrange scenario, the report projects a 65% reduction in emissions from power generation through 2035, as fossil-burning generators are replaced by renewables, and a 26% reduction from transportation, as the number of internal combustion engines decreases.

Past and projected future average annual growth in U.S. electricity demand | Rhodium Group, EIA

But industrial sector emissions are projected to decrease only 5% through 2035, at which point it would be the largest U.S. source of GHG emissions. And emissions from the agriculture sector actually could increase slightly, according to the analysis. 

Rhodium issued its first “Taking Stock” report in 2014 and has updated it annually. In announcing the 2024 update, it noted the historic confluence of factors in the past few years that has accelerated emissions reductions in the U.S., including the Inflation Reduction Act and the Infrastructure Investment and Jobs Act, which have helped spark a clean energy boom. 

It is a marked change from the conclusion of the 2014 report, which incorrectly predicted GHG emissions would increase through 2020. 

The report notes potential obstacles to continued progress, including the Supreme Court or the next president striking down or weakening the regulations that have been instrumental in bringing about the reductions to date. 

Ironically, attempts to build a domestic clean energy manufacturing base could result in an increase of emissions; meanwhile, interconnection delays, local opposition, transmission constraints and robust growth of GDP could slow the decrease of emissions. 

The report also flags supply chain constraints and data center demand as disruptors. Difficulty building renewables and the continued proliferation of data centers would result in 2035 power sector emissions that are substantially higher than in a scenario in which neither complicating factor existed. The report notes fossil generation retirements already are being reconsidered because of these two factors. 

Because of all these variables, the report gives a range of potential outcomes under three models: 

    • a high-emissions scenario where emissions-free energy deployment is slowed by high costs for renewable technologies, low costs for fossil fuels, interconnection queue delays and supply chain constraints; 
    • a low-emissions scenario where low-cost clean energy technologies and expensive fossil fuels drive a rush of investment in emissions-free power; and 
    • a mid-emissions scenario that splits the difference. 

The report anticipates a 38 to 56% reduction in U.S. GHG emissions by 2035 over 2005 levels, factoring a few trends into this projection: 

    • Zero-emissions sources such as wind, solar and nuclear could account for 62 to 88% of total generation by 2035, and coal could be nearing zero. This would yield a 42 to 83% drop from 2023 power sector emission levels. 
    • By 2035, 64 to 74% of light-duty vehicles sold could be electric, and 30 to 45% of medium- and heavy-duty vehicles sold could be zero-emitting, causing transportation sector emissions to drop 22 to 34% from 2023 levels. 
    • Emissions from oil and gas production could drop 12 to 28% below 2023 levels because of EPA regulations that limit release of methane. 
    • Regulatory changes phasing out hydrofluorocarbons could cut building emissions by 9 to 12%. 

Sources of electricity demand growth from 2023 through 2035, as modeled in a midrange emissions scenario | Rhodium Group

The report bases its projections for the next decade on state and federal policies in place in June 2024, which is an unstable foundation, the authors note. “The only thing that we can be certain of is that these policies will change by 2035 — probably many times over.” 

States can step up and take action if the federal government will not, they add. 

“What’s certain is that more policy action is needed for the U.S. to put itself on track for its 2030 commitment under the Paris Agreement and for deep decarbonization by midcentury.” 

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MISO Sets Sights on 50% Peak MW Cap in Annual Interconnection Queue Cycles

MISO said it plans to pursue a more straightforward, 50% peak load megawatt cap to limit the number of generator interconnection requests it would accept annually.

At MISO’s July 23 Interconnection Process Working Group teleconference, the grid operator revealed the cap would be based on 50% of peak load per study region. MISO divides its footprint into West, Central, East and South regions for queue study purposes.

MISO Manager of Generation Interconnection Ryan Westphal said using 2022 study modeling, a queue cap would have been about 68 GW. He said the simpler cap would take the RTO’s future resource adequacy need into account as FERC recommended, though he didn’t offer specifics.

MISO attempted last year to enforce an annual megawatt cap on its interconnection queue. FERC rejected the attempt on concerns over too many cap exemptions, the formula to establish the cap and potential resource adequacy deficits stemming from limiting new generation onto the grid. (See MISO: New Interconnection Queue Cycle to Wait on MW Cap Filing.)

MISO’s original cap formula was intended to be rooted in its ability to develop a reasonable dispatch for studying interconnection requests based on the existing system and considering regional and subregional peak loads. The complex calculation involved landing on load remaining to be served after existing generation and higher-queued generation proposals are dispatched at the lowest possible megawatt output while remaining online.

Westphal said MISO hopes to submit a fresh FERC filing for a more uncomplicated cap before the end of the year.

NextEra Energy’s Erin Murphy asked how MISO arrived at the 50% value. Westphal said the RTO assessed its rounds of potential generation submittals prior to the 2022 “explosion” of queue requests. He said before the exponential growth, MISO was processing about 60-GW entry classes. MISO is processing 123 GW of queue hopefuls that lined up in the 2023 cycle. If all projects proceed, MISO could have a more than 300-GW queue on its hands.

Westphal said MISO doesn’t have a “specific date” for when it will close the current queue cycle. Its application portal is open for interconnection customers to submit projects for MISO to review application completeness. However, MISO is holding off on processing the queue in earnest until it secures FERC permission to administer a cap.

Stakeholders asked whether projects that don’t make the cutoff would have priority access to MISO’s next queue cycle. Westphal said any projects shut out of a queue cycle would be “first in line” for the subsequent cycle.

MISO also said a few projects put forward after the cap is reached might be selected to proceed if other projects don’t successfully clear its validation process.

MISO staff said the grid operator would use the timestamps on project submittals to determine their place in line. Westphal said MISO wouldn’t refund study deposits to developers that don’t make the cap cutoff but hold on to them to prepare for processing them during the next queue cycle.

Derek Sunderman, of Shell subsidiary Savion, said MISO’s proposal doesn’t seem to address late-stage project withdrawals. He also said the cap won’t encourage developers to only put their most promising projects forward and not “hammer” the queue with several projects to secure a position.

Westphal said MISO is open to use of a volumetric price escalation in addition to the cap, where interconnection customers’ fees and penalties rise as they submit more projects to the queue for study. He said the RTO is considering starting at $8,000/MW for the first milestone fee.

Last month, Savion suggested MISO enact escalating financial commitments to prevent a handful of interconnection customers from submitting a disproportionate number of applications. MISO said raising fees based on a corporation’s project count would introduce several new requirements.

MISO once again proposes exemptions to the cap, though not as many as in its first filing with FERC. Westphal said MISO would exempt generators with provisional generator interconnection agreements; generators seeking to replace retiring counterparts and in need of extra interconnection service; and those generators wanting to convert their unguaranteed energy resource interconnection service with the higher-quality network resource interconnection service.

MISO again plans to exempt generation singled out as necessary by state commissions, though it would limit those exemptions from an unlimited number to three apiece annually per regulatory body.

Bill Booth, a consultant to the Mississippi Public Service Commission, questioned MISO’s three-project limit on regulator-backed projects. Booth said the restriction doesn’t make sense if the RTO’s goal is to cut down on speculative projects. He said a project backed by regulators usually is a sure thing.

Westphal said MISO needs some kind of limit in place, per FERC’s 2023 rejection of the first cap.

“FERC basically said without some kind of limit, we undermine the cap. We need to put some kind of limit on here based on what we heard from FERC,” he said.

Westphal said the cap is essential to make interconnection studies more manageable. He said as more projects vie for entry, more upgrades become necessary, and the more complex and insurmountable studies become.

“The point of the cap is to speed up the queue,” Westphal said.

Murphy asked what MISO is doing beyond proposing a future queue cap to address the backlog of projects now.

Westphal said MISO will build more automation into the 2023 modeling. The grid operator has solicited help from Pearl Street Technologies to determine whether their software can speed up interconnection studies.

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CenterPoint CEO Promises PUC Utility Will ‘Improve’

CenterPoint Energy executives appeared before Texas regulators July 25 to apologize for the company’s slow restoration following Hurricane Beryl’s landfall and promised to do better next time. 

The Houston utility had 2.6 million customers without electricity in the storm’s immediate aftermath, with some waiting more than a week to get their power back. CenterPoint was roundly criticized for the slow response and its poor communications with customers. 

“In times of emergency, our responsibility is to respond quickly, to communicate clearly, to provide accurate information and to restore power as rapidly and safely as we can,” CenterPoint CEO Jason Wells told the Public Utility Commission during its open meeting. 

“I take personal accountability on areas where we fell short of our customers’ expectations,” he continued. “Most importantly, I want to apologize. While we cannot erase the frustrations and difficulties so many of our customers endured, I, my entire leadership team, will not make excuses. We will improve and act with a sense of urgency.” 

Wells said CenterPoint will begin immediately to improve its communication with customers as part of an action plan with two other “pillars of action” focused on resiliency and greater collaboration with local partners and emergency responders. The intent is to address issues for the remainder of the hurricane season and beyond. 

Central to the plan is strengthening the utility’s vegetation management efforts. Wells said that as of July 16, CenterPoint had nearly doubled its vegetation-management workforce “to immediately address the higher risk areas … throughout the rest of this calendar year.” 

The utility plans to roll out a new cloud-based outage tracker Aug. 1, replacing the previous version that never was able to recover after being swamped following a derecho in May. It also will use composite poles to replace about 1,000 distribution poles currently planned for 2024. 

CenterPoint said its crews removed or trimmed more than 35,000 trees during the restoration effort, walked over 8,500 to repair damage and replaced more than 3,000 poles. 

Wells said CenterPoint will hire a new senior executive team member with expertise in emergency and storm response. More actions will be taken based on internal reviews, independent analysis and counsel from emergency response and communications experts, and feedback from the PUC, elected officials and community leaders, and its customers. 

“Going forward, our most important priority today and in the months ahead will be to improve our emergency response with a sense of urgency to re-earn your trust and the trust of the millions of people who depend on us,” Wells said. 

The PUC has opened a “rigorous” study of CenterPoint over repeated failures in its footprint. The utility also is being probed by state lawmakers, with hearings scheduled July 29 and July 31. (See CenterPoint Under Fire for Its Beryl Response.) 

The commission threatened to recall CenterPoint’s $2.3 billion resiliency plan — filed in April and currently in settlement negotiations — and preside over the hearings. However, it agreed to give the utility time to reach an agreement with the other parties (56548). 

“I want to ensure that we have the right, as in the law, to modify any plan that’s presented to us,” Commissioner Jimmy Glotfelty said. “Even if there’s a settlement, we must be willing to bring this back to the commission to get deeper into the specifics of how we will ensure resiliency on the CenterPoint system.” 

“You have an obligation to serve. You have an obligation to provide continuous and adequate service,” fellow Commissioner Lori Cobos said. “Getting a resiliency plan approved does not stop you from doing what you should be doing already to maintain continuous and adequate service for your customers and your service territory.” 

CenterPoint promised the PUC it would provide an update on the settlement negotiations within a week.