FERC has accepted a second compliance filing from SPP outlining its process for determining its planning reserve margin (PRM) with an Oct. 17 order that found the RTO’s response met the commission’s directives, effective April 10, 2024 (ER24-1221).
SPP was responding to FERC’s May order asking for more information on how it uses loss-of-load expectation (LOLE) studies to determine the PRM. (See FERC to SPP: Show More Work on PRM Determination.)
FERC directed SPP to revise its tariff to include more information related to a “non-exhaustive” list of the factors SPP staff, its board and its state regulators will consider when determining the recommended PRM value.
The commission disagreed with protests filed by several SPP members (American Electric Power, Golden Spread Electric Cooperative, Arkansas Electric Cooperative Corp., Xcel Energy, East Texas Electric Cooperative and Northeast Texas Electric Cooperative) that the grid operator did not explain how it will use the LOLE results to determine the PRM. FERC said the proposed tariff language “makes clear” that the PRM value will be determined based on the LOLE study results and that SPP set forth factors that its staff, board of directors and state regulators will consider when using the study results.
SPP’s Market Monitoring Unit also protested, arguing that the tariff shouldn’t reference available generating capacity and new generator development timelines as considerations for recommending or determining the PRM. FERC disagreed, noting that it already accepted a similar provision in the first compliance order.
“That’s a win, I guess, depending on who you ask,” SPP attorney Justin Hinton said to chuckles during a stakeholder meeting Oct. 18, referencing the stakeholder arguments that preceded the PRM’s revision in 2022.
The board approved changing the PRM to 15% from 12% over opposition from stakeholders advocating a three-year phase-in. Load-responsible entities unable to meet the requirement can incur financial penalties from the RTO. (See SPP Board, Regulators Side with Staff over Reserve Margin.)
Commission OKs LTCR Change
In an Oct. 11 letter order, FERC also accepted SPP tariff revisions to allow the nomination of candidate long-term congestion rights (LTCRs) for firm transmission capacity associated with the Federal Service Exemption (FSE) and for firm transmission service associated with grandfathered agreement (GFA) carve outs in the LTCR allocation process (ER24-2003).
FERC said the revisions, effective July 14, 2024, are likely to benefit load by further reducing uplift charges that load currently pays to compensate for the congestion and marginal loss charges that GFA carve outs and FSEs do not pay.
SPP said congestion charges associated with the carve outs and FSE transmission reservations have been offset by revenues that SPP receives from nominating auction revenue rights (ARRs) attributable to the carve outs and FSEs. The remaining amount is recovered from SPP-wide load as uplift.
The RTO said it will nominate LTCRs attributable to the carve outs and FSEs under the same criteria by which it currently nominates ARRs attributable to the same exemptions. It said the LTCRs’ revenue will be used to further offset the uplift charges that must be paid by load.
FERC rejected Missouri River Energy Services’ protests that the revisions shift costs to market participants with transmission reservations near the carve out and FSE reservations. It said the alleged cost shifts result from better aligning the tariff’s treatment of ARRs and LTCRs attributable to carve outs and FSEs with the tariff’s treatment of ARRs and LTCRs attributable to all other transmission reservations.
CARMEL, Ind. — MISO announced it will move forward on an annual interconnection queue cap based on 50% of peak load for the year in question, this time removing exemptions for projects regulators deem essential.
Stakeholders learned at an Oct. 16 Planning Advisory Committee meeting that MISO plans to scrap a regulator exemption from the annual megawatt cap it has designed for its generator interconnection queue. The deletion appeared unpopular among some stakeholders and state regulatory agencies.
MISO’s Ryan Westphal said removal of regulators’ ability to name exempted generation projects will prevent the cap from being diluted with exceptions to the rule. He also said MISO heard stakeholders’ concerns about how MISO would limit the number of regulators’ exemptions and how it would give those exemptions priority.
FERC last year rejected MISO’s first attempt to institute an annual megawatt cap on the queue based on concerns over too many cap exemptions, the formula to establish the cap and potential resource adequacy deficits from limiting new generation onto the grid. (See FERC Rejects MW Cap, Approves MISO’s Other Stricter Interconnection Queue Rules.)
Westphal said MISO needs a “reasonable number of resources and a reasonable dispatch” to be able to build sound study models.
“All of us can agree that in the 2022, 2023 modeling, there are a lot of resources in there that are creating a lot of difficulties, engineering problems,” Westphal said.
Westphal also said a 50% peak load cap should eliminate the need for “backbone” network upgrades, where interconnection customers are responsible for large transmission projects.
MISO previously said regulatory authorities would be allowed exemptions to the cap when generation additions are needed for resource adequacy or to serve documented load that regulators have authority over. MISO said it would allow one cap exemption per 3 GW of documented load that the regulatory authority serves. (See MISO: 50% Peak Load Cap, Software Help Key for Crowded, Delayed Queue.)
MISO has said that even with a cap in place, it could achieve a total 310-GW queue throughput through 2042. The RTO assumed a 68-GW annual cap based on its current annual peak and took its historic 21% completion rate into account to come up with 14.3 GW per year in completed projects. MISO has about 320 GW in active interconnection requests in its queue.
MISO staff have said controlling the cadence of project submissions is key to improving the quality of initial studies and potentially reducing network upgrade costs by being able to use a more true-to-life resource dispatch in models. MISO said once a cap is met for an interconnection cycle, projects will line up for the next year’s study cycle.
The RTO has also committed to a three-year review of the effectiveness of the queue cap.
MISO: 2nd Filing on the Way to Address Regulators’ Necessities
MISO’s Andy Witmeier said MISO dropped regulators’ exemption because planners didn’t see how a single exemption could address the multitude of imminent resource adequacy troubles.
Instead, Witmeier said MISO will develop a separate, “more holistic” proposal with stakeholders to find ways to speed up queue processing for projects that keep MISO in the black on resource needs.
Duke Energy’s Jay Rasmussen said he thought MISO is missing an opportunity to address resource adequacy issues within the cap.
Rasmussen pointed out that large load additions are on the horizon for load-serving entities. He said filing to implement a cap without acknowledging generation needs creates a “lag” for interconnection customers.
Illinois Commerce Commissioner Michael Carrigan said while the Organization of MISO States sympathizes with how difficult queue studies have become for MISO, “states very clearly value their respective authority.” Carrigan said he didn’t see a path to states supporting MISO’s queue cap proposal at FERC without some sort of exception for generation needed to preserve resource adequacy.
“This is a concern and could be very problematic,” Carrigan said.
“Our decision is that we need to address these in separate filings because they’re separate issues,” Witmeier said. He said MISO staff plan to discuss how to expedite generation projects necessary to resource adequacy in upcoming Planning Advisory Committee meetings through January. He said MISO could be ready for a separate filing by the first quarter of 2025.
At a Sept. 12 Organization of MISO States board meeting, OMS Director of Legal and Regulatory Affairs Brad Pope said MISO’s queue cap needs a “workable” exemption for regulatory agencies when they are reliant on a developer’s generation submittal.
While it’s jettisoning its regulator exemption, MISO said it would maintain cap exemptions for existing resources. Those resources may need to enter the queue to replace their output with an approved generation facility, receive provisional interconnection agreements or upgrade their current basic, unguaranteed energy resource interconnection service to the higher-quality, firm network resource interconnection service. Staff said those reasons don’t include proposing speculative generation projects and can earn exemptions.
Bill Booth, consultant to the Mississippi Public Service Commission, argued that projects regulators approve under utilities’ integrated resource plans are not speculative.
“The goal of this whole approach is to reduce speculative projects. Do you think projects approved under a state IRP process are speculative?” he asked rhetorically.
Witmeier said the past few times MISO discussed its proposed cap with stakeholders, the regulator exemption proved to be a sticking point.
“Folks are concerned about what it means and how it will be managed,” he said.
Some stakeholders asked MISO to delay its planned early November filing with FERC for a queue cap until it devises a way to address projects deemed necessary by states for resource adequacy.
NextEra Energy’s Erin Murphy said a “brief pause” makes sense considering MISO is working with tech startup Pearl Street to automate some study processes. She said perhaps MISO could wait to gauge the effectiveness of the new software’s ability to shrink wait times before it limits entrants.
Witmeier, however, said a queue cap has been in the works in MISO’s stakeholder process for two years. He said the need for a queue cap and creating a means to usher resource adequacy projects through faster are unrelated matters.
“I see no need to put it on the shelf just because we’re going to go after a separate process,” Witmeier said.
Booth said MISO required a little “intellectual integrity.” He said instead of MISO polishing and explaining a regulator exemption, MISO simply chopped its filing in half, with no guarantee of when it would address state-required generation projects.
Consumers Energy’s Dan Alfred said his utility’s support of the queue cap hinges on a companion resource adequacy exemption.
“I don’t understand why you’re not listening to the feedback here,” Alfred said.
Responding to an appellate court’s concerns about free ridership, FERC reversed a decision that allowed the WestConnect transmission planning region to include a category of participants not subject to binding cost allocation.
The order (ER13-75, et al.), issued Oct. 17, could mark the end of a yearslong dispute stemming from FERC Order 1000.
That order, issued in 2011, requires public utility transmission providers subject to FERC jurisdiction to participate in a regional transmission planning process that produces a regional transmission plan.
Nonpublic utility transmission providers may also choose to participate in regional transmission planning by “enrolling” in the effort. They are then required to pay a share of costs for future projects that benefit them.
And in what has become a contentious twist, a FERC-approved framework for WestConnect allows a third category of participants: coordinating transmission owners (CTOs). These nonpublic utility transmission providers participate in determining regional transmission needs and identifying projects that could meet those needs. But once costs of a proposed project are divided up, the CTOs choose whether they want to pay.
If a CTO decides not to pay, WestConnect reevaluates the costs and benefits of the project to determine if it should move forward.
In an August 2023 decision, the 5th Circuit Court of Appeals said FERC’s approval of the framework was “incompatible with the FPA’s [Federal Power Act’s] mandate for just and reasonable rates and with Order No. 1000’s application of the cost causation principle.”
A stated purpose of Order 1000 is to prevent subsidization by ensuring that costs correspond to benefits, the court decision stated, and the cost-causation principle combats “free ridership,” in which an entity is not required to pay for a benefit it receives.
FERC has now directed WestConnect public utility transmission providers to submit compliance filings to revise their Open Access Transmission Tariffs to remove the CTO framework and to update their OATTs to reflect the current list of enrolled members in the WestConnect region.
Long-running Case
After FERC issued Order 1000, the WestConnect public utility transmission providers submitted a series of filings beginning in 2012 to comply with the order’s requirements. WestConnect covers parts of Arizona, California, Colorado, Nebraska, Nevada, New Mexico, South Dakota, Texas and Wyoming.
FERC rejected several of the WestConnect public utility transmission providers’ cost allocation proposals, saying they weren’t consistent with the order’s principles. But FERC accepted the providers’ proposed participation framework in which nonpublic utility transmission providers could participate as either enrolled transmission owners or coordinating transmission owners.
The public utility transmission providers, led by El Paso Electric, took FERC’s rejection of their filings to court.
The 5th Circuit vacated FERC’s orders regarding the transmission providers’ compliance filings and remanded the case “for further explanation and fact finding.”
In 2017, FERC responded with an order on remand. Among the commission’s arguments in support of its decision was that nonpublic utility transmission providers are likely to submit to binding cost allocation so grid-improvement projects meet benefit-to-cost thresholds and can move forward.
FERC also said it could always revisit its approach if free ridership turns out to be more of an issue than expected.
The public utility transmission providers asked for a rehearing, which FERC denied. El Paso Electric then took the matter back to the 5th Circuit, petitioning for review of FERC’s order on remand and order denying rehearing.
The other WestConnect public utility transmission providers intervened in support of El Paso Electric, and the nonpublic utilities intervened in support of FERC.
The court stayed the petition in 2018 while the parties worked on a settlement agreement. But in 2022, FERC rejected the proposed agreement between the public and nonpublic utilities and the court continued with its review of the case. (See WestConnect Tx Cost Allocation Plan Rejected by FERC.)
CARMEL, Ind. — MISO is hesitant to grant a request from Michigan to give dispensations to distributed energy resources from its mandated affected studies that gauge transmission system impacts.
Michigan regulators and utilities’ recent bid to allow DERs to altogether skip out on MISO’s affected system-style studies might be shortsighted, said MISO Senior Manager of Resource Utilization Kyle Trotter.
“Generally, we are supportive of this particular issue; however, we’re not quite sold on an exemption from the whole process,” Trotter said during an Oct. 16 Planning Advisory Committee meeting.
Trotter emphasized the need for appropriate reliability assessments for DER additions. He said MISO cannot ignore DERs’ potential to affect local transmission systems and neighboring systems. Trotter said MISO needs some “touchpoint in place” to maintain visibility of DERs, continue to meet NERC reliability standards and have an idea of which interconnection points on the system are congested for its interconnection queue.
“We need to see what’s happening at those transmission-distribution interface. We need to keep visibility into what’s happening whether those DERs go through the MISO study process or not,” Trotter said.
Trotter also said MISO’s upcoming compliance with FERC Order 2222, which will allow aggregated DERs into the MISO markets, presents another reason to keep tabs on DERs.
“We would like to know about these before they show up and register for the market,” Trotter said.
Last year, MISO decided it would evaluate the need for a review of DERs when they can inject 5 MW of power at the substation level during system peak load and if they can force a 1% change in line loading. TOs screen for the 5 MW injection capability, while the RTO ascertains whether the DERs could influence a 1% line-loading change.
If the DER is shown to impact both reliability criteria, MISO issues a report that triggers its existing facilities study and could lead to network upgrades. TOs pay a $60,000 study deposit to MISO per substation that is required to be studied for DER impacts. MISO refunds any portion it doesn’t use for the studies. (See MISO Creating Means to Gauge Impacts of DER Interconnections.)
In July, Michigan utilities and the Michigan Public Service Commission asked MISO to rethink a study requirement for DERs that might influence the grid. They said MISO’s study process is burdensome, costly and limits efforts to integrate DERs on the grid. (See Michigan Utilities Call for Opt-Out on MISO DER Affected System Studies.)
Some stakeholders said MISO’s DER-affected system studies are redundant considering that MISO’s transmission owners already study DERs’ influence under transmission expansion planning and that MISO is devising a registration process for DERs that want to participate in markets.
ITC’s Ruth Kloecker agreed that MISO’s study process seems duplicative. She also said MISO’s 5 MW threshold seems too severe.
“5 MW of injection? I don’t know how that can seriously impact the transmission system,” Kloecker said.
Erik Hanser, a staffer with the Michigan Public Service Commission, asked if MISO sees a way to cut back study requirements on DERs.
Trotter said MISO would like to continue DER awareness and likely would maintain MISO’s policy of having TOs vet DER additions and notify MISO if an impact study is warranted. He said there’s a possibility DER additions could skip a “full MISO study and associated costs in some instances.”
With downed power lines and poles from hurricanes Helene and Milton still a painful memory for many, the U.S. Department of Energy on Oct. 18 announced almost $2 billion in new funding from the Infrastructure Investment and Jobs Act aimed at improving grid reliability and resilience.
The latest round of Grid Resilience and Innovation Partnerships (GRIP) awards will go to 38 projects across 42 states and the District of Columbia. The grants will be used to expand grid capacity and speed up interconnection to meet burgeoning power demand from new manufacturing and data centers, said Secretary Jennifer Granholm during an advance press call Oct. 17.
“The funding couldn’t come at a more critical time,” Granholm said. “Energy demand, as we know, is rising nationwide, and it is straining our outdated grid infrastructure, and as climate change worsens, we’re seeing more frequent and devastating storms like Helene and Milton.”
The projects selected for the GRIP awards will expand capacity on regional grids by 7.5 GW and add 300 miles of new lines and upgrade an additional 650 miles of lines with advanced conductors and other grid-enhancing technologies (GETs), according to a DOE press release.
President Joe Biden announced six of the projects ― all located in the Southeast ― during a visit to Florida on Oct. 13. The Tennessee Valley Authority (TVA) scored the largest award, $250 million, which will fund 84 “subprojects” in disadvantaged communities across eight states, adding more than 2,400 MW of capacity, according to a DOE fact sheet.
The federal dollars also will be used for the first interconnection tie — cables — allowing for power transfers between TVA and the Southwest Power Pool, providing TVA and its local utilities with an additional 800 MW of electricity.
In Florida, Gainesville Regional Utilities (GRU) is slated to receive $47.5 million for distribution grid upgrades including reconductoring, undergrounding and transformers. DOE’s project description notes that this “diverse portfolio of grid hardening and modernizing technologies and equipment will increase the grid’s intelligence and build system capacity for the adoption of clean energy, grid-edge technologies and electric vehicles.”
GRU CEO Ed Bielarski said he wants the utility to be a model “to further innovate and enhance [system] resilience and storm response, including in disadvantaged communities.”
The GRIP program includes three separate funding streams: the Grid Innovation grants, announced in August, and the just-announced GridResilience Utility and Industry grants and Smart Grid grants. Pending the election results, DOE is planning a third round of funding for 2025.
Speaking at the advance press call, John Podesta, Biden’s senior adviser on international climate policy, said the U.S. needs the grid to be “larger, stronger and more reliable. To effectively tackle the climate crisis and stay on course to reach 100% clean energy by 2035, we need to double our current transmission capacity in that time frame.”
Getting there will mean continued public and private investments, better interregional transmission planning and “cutting through red tape” to get projects sited, permitted and built, Podesta said.
Project Priorities
The IIJA provided $10.5 billion for the GRIP program, heralded as one of the largest public investments in the nation’s electric infrastructure. With the Oct. 18 announcement, $7.6 billion has been awarded.
In general, awardees must at least match the number of federal dollars, and with the current announcement, DOE said the almost $2 billion in GRIP awards would draw in an additional $2.2 billion in private investment.
Announced exactly one year ago, on Oct. 18, 2023, the first round of awards, totaling $3.46 billion, included 58 projects in 44 states. According to a senior administration official, 53 of those projects now have signed contracts with DOE. The projects announced in August are in contract negotiations, which also will begin for the latest round of awardees.
DOE officials have said repeatedly that once an awardee has a signed contract, the funds will be committed and safe from any claw-back, regardless of the outcome of the election.
Each round of GRIP awards has focused on different administration priorities. The first round leaned heavily toward projects that could improve resilience at the distribution level, had strong support from state and community officials and could move forward quickly.
Transmission projects were the top priority for the awards announced in August, with projects deploying GETs securing six of the eight awards. The largest award, $700 million, went to the North Plains Connector transmission project, a 420-mile, high-voltage direct current line running from Montana to North Dakota.
This round clearly prioritizes grid upgrades to improve resilience in areas especially vulnerable to extreme weather and to get more power online to meet rising demand. The projects are geographically diverse, with money going to red and blue states. Investor-owned utilities, municipals and electric cooperatives are on the list, as well as some technology companies.
In North Dakota, the Montana-Dakota Utilities Co. and Innovative Energy Alliance Cooperative were awarded close to $15.6 million for a project to upgrade a 54-mile segment of the state’s grid, adding new advanced conductors to expand capacity. Other upgrades include “installing software, sensors and interfaces for online weather data, allowing for dynamic line rating and quicker system response,” according to DOE.
Alabama’s Tombigbee Electric Cooperative, with about 45,000 members, is slated to receive $11.1 million for system upgrades including new storage to shave peak demand and distributed energy management and outage management systems. The project also will reconductor existing lines and install new lines.
In Florida, Chicago-based Switched Source will partner with Florida Power & Light to deploy its automated distribution power flow control technology on lines in disadvantaged communities especially vulnerable to extreme weather. The $47.7 million award could help cut outages by 10%, improve energy efficiency across the system and help integrate distributed resources, such as solar and electric vehicles.
LITTLE ROCK, Ark. — SPP stakeholders on Oct. 15 approved what one member called an “historic” transmission plan that will eclipse any previous portfolio by a factor of five.
The grid operator’s 2024 Integrated Transmission Plan’s portfolio includes 89 projects, including more than 1,900 miles of rebuilt or new EHV transmission, with a projected cost of $7.65 billion. That’s more than half the $12 billion of transmission facilities that SPP has directed, members have built or are building.
The ITP assessment cleared the Markets & Operations Policy Committee with 95% approval. It will go before SPP’s Board of Directors on Oct. 29 with passage almost guaranteed, considering stakeholders’ approval margin.
“This is a monumental day in SPP history,” Sunny Raheem, the RTO’s director of system planning, said at the MOPC. “That brings into question, is it affordable?”
Staff said their study of the plan’s two futures found benefit-to-cost ratios over 40 years of 8.9 and 8.2, about three points higher than any previous ITP assessment. They also expect the 2024 portfolio to be fully paid back within its first three years.
“We think [it’s] really needed to allow SPP to maintain a reliable system, be prepared for the changing resource mix, and, of course, load growth,” she said. “We were amazed and pleasantly surprised at the very strong levels of benefits relative to cost in this portfolio, and I think that that should make everyone feel fairly comfortable with supporting it.
“This is a large transmission portfolio for SPP, but it should not be a surprise,” McIntire added.
SPP COO Lanny Nickell said that during the MOPC’s discussion of the plan, he leaned over and asked the committee’s chair, Alan Myers, “When is the last time we had $7.6 billion of investment on the table with this kind on consensus behind it?”
“I don’t remember that. To me, that’s remarkable,” Nickell said. “It’s remarkable that the members all see value for the most part. Now, I know there are some that are concerned about certain projects, and you know the magnitude of cost associated with certain projects, but for the most part, the support for the projects that are in this portfolio is fantastic.”
The portfolio’s size is driven by rapidly increasing and electrified oil and gas load in the Southwest and the Dakotas, some population growth, and the usual wave of data centers and crypto miners. SPP said the ITP considered a “uniquely sharp increase” in load at multiple sites across the SPP footprint, compared to previous ITP assessments, and used the information to inform decisions made while crafting the portfolio.
The 2024 assessment’s Year 2 load is up 9.7% and 12.9% for the 2023 ITP’s Year 10 respective summer and winter projections. It projects a 25% increase in demand by 2030, a nearly 14 GW increase from its 2023 record peak of 55.89 GW. According to SPP’s report, “minimal load growth” has been accelerated by new customers asking to be connected to the grid as soon as possible.
“Uniquely sharp” load increases in New Mexico led to staff’s recommendation for SPP’s first 765-kV line, the Phantom-Crossroads-Potter project from the Texas Panhandle to southeastern New Mexico. Staff said the project has a $4.1 billion net adjusted production cost value beyond its $2.13 billion cost and a 3.1 benefit-to-cost ratio in Year 40.
Staff also incorporated extreme winter weather scenarios into its latest ITP after two recent storms stressed the grid with low temperatures from the Canadian border into the Texas Panhandle. The extended cold temperatures led to above-normal energy use, fuel availability issues and in 2021, the first directed load shed in SPP’s history.
SPP identified and recommended notifications-to-construct for projects to help support the system during extreme weather events.
“We’ve needed to address the resilience issue after Winter Storm Uri and Winter Storm Elliott for a couple of years,” Nickell told RTO Insider. “That has been something that needs to be addressed, and [members] recognize this does that. They not only appreciate the benefits of reducing congestion, but they also appreciate the fact that it solves the reliability and resilience needs that we needed to address.”
Stressing that he was not speaking for all members, Nickell said the $7.65 price tag was a “secondary component” because of the ITP’s huge value to the SPP grid.
Mike Wise, Golden Spread Electric Cooperative’s senior vice president of regulatory and market strategy, complimented SPP for using “decision quality” concepts and including it in the assessment’s analysis.
“I can’t stand in the way of what the analysis has shown here, but I do think SPP has done a good job,” he said.
Wise told RTO Insider that according to a back-of-the-envelope calculation and under certain conditions, the ITP could cost Golden Spread’s members more than $1 billion in additional transmission costs over the next 40 years. He attributed the lack of discussion over the costs to transmission users not understanding the ITP assessment’s assumptions.
“These are 40-year investments,” he said. “Who bears the risk if the load doesn’t come?”
SPP’s ITP still pales in comparison with MISO’s first two long-range transmission plan (LRTP) portfolios, which have a combined cost of nearly $32 billion. MISO is advancing the LRTP package for its board’s approval at the end of the year. (See MISO Affirms Commitment to $21.8B Long-range Tx Plan in Final Workshops.)
The commission also granted a request by NERC and WECC to fund the Western Transmission Expansion Coalition’s (WestTEC) transmission planning study over the next two years by releasing $2.2 million in total from the Peak Reliability Donation Reserve and approved the REs’ use of penalties to grow its financial reserves and reduce its 2025 assessments.
The ERO submitted the budgets to the commission following their acceptance by the ERO’s Board of Trustees at its August meeting in Vancouver. (See “Budgets Headed to FERC,” NERC Board of Trustees/MRC Briefs: Aug. 15, 2024.) NERC CFO Andy Sharp said at the meeting that the final budgets are “materially consistent” with NERC’s three-year projection.
NERC’s 2025 budget is set to rise 8.2% over the previous year to $123 million, according to the ERO’s August filing. Drivers of the increase include an expected need to hire 13 new employees in reliability standards development, enforcement, the Electricity Information Sharing and Analysis Center, and other areas; investments in the ERO’s technology strategy; and planned increases in meetings and travel costs. The E-ISAC’s budget is also set to grow from $41.1 million to $43.8 million.
The budgets for the REs and WIRAB are set to grow as follows:
Midwest Reliability Organization — from $24.9 million to $26.8 million
Northeast Power Coordinating Council — $22.1 million to $25.7 million
ReliabilityFirst — $31.3 million to $33.4 million
SERC Reliability — $32 million to $35.4 million
Texas Reliability Entity — $19.2 million to $20.3 million
Western Electricity Coordinating Council — $35.4 million to $39.3 million
WIRAB — $831,492 to $831,561
The ERO’s total assessment for 2025 is to rise to $270.9 million, up from $241.4 million in 2024. This includes $108.4 million for NERC and $128.3 million in combined assessments for the REs and WIRAB.
WECC and NERC’s requested funding for the WestTEC project will see progressive releases from the funds donated by Peak Reliability upon its dissolution in 2019, with $500,000 released in 2024, $1.5 million in 2025, and $200,000 in 2026. The WestTEC study is to take place over the next two years and is intended to produce transmission portfolios for 10- and 20-year planning horizons. (See WestTEC Seeks to Close $2.1M Funding Gap Despite DOE Boost.)
NERC said the withdrawals will leave a balance of just over $1 million in the Peak Reserve.
Commissioner Judy Chang spoke approvingly about the project at this week’s meeting, calling WestTEC “a collaborative, voluntary interregional planning initiative” that will help meet the long-term needs of the Western Interconnection.
“The Western markets [have been] evolving over the last few years and will continue to evolve in the future … [WestTEC] is very valuable, and I think it’s a good use of Peak Reliability funds to support reliability across the West,” Chang said. “I look forward to seeing the results of those efforts, which [are] also being supported by funds from the Department of Energy.”
First-quarter electricity prices in CAISO markets were down sharply from the same period in 2023, despite sharp spikes during the January cold snap in the Pacific Northwest, the ISO’s Department of Market Monitoring said Oct. 17.
January’s extreme weather events were the “major story for the wholesale electricity markets in the first quarter of 2024,” Ryan Kurlinski, a DMM senior manager, said during a market issues and performance meeting covering Q1.
The winter event saw Pacific Northwest and Intermountain West balancing authority areas hit an average of about $150/MWh in the Western Energy Imbalance Market (WEIM), compared with $65/MWh in other BAs in the market. As a result, transfer capacity in the WEIM was frequently constrained, preventing lower-priced marginal energy in southern areas from setting lower prices in the north, the DMM found.
Lower natural gas prices across the WEIM compared with Q1 2023 drove decreases in average electricity prices, despite the cold weather events. Prices at both California natural gas trading hubs decreased by more than 60% compared with 2023, helping undercut average power prices by 53%.
“In Q1 of 2024, after we get past the severe cold weather event up in the Pacific Northwest and into mid- and late January, prices significantly drop across the WEIM,” Kurlinski said. “Even with the severe cold weather event, high January prices in the Pacific Northwest and Intermountain West were about 20% lower in Q1 2024 on average compared to Q1 in 2023.”
Congestion and price separation between the Pacific Northwest and other BAAs continued into February and March, though prices were still lower than the previous year.
Congestion played a large role in market impacts during the January cold snap. Historically, congestion rent in the CAISO BA has been in the import direction over the interties, but Q1 saw a “huge spike” in export congestion rent over the ISO’s intertie constraints, symbolizing another one of the “most interesting and major stories of Q1 2024,” Kurlinski said.
“In Q1 2024, intertie congestion rent exploded to $133 million [from $13 million a year earlier]. $130 million of that was in the export direction,” most of which was on the Malin intertie in January, Kurlinski added.
Congestion rent on internal constraints in the CAISO BA in the day-ahead market decreased from $265 million in Q1 2023 to $125 million in 2024.
Additionally, transmission ratepayers lost around $53 million in congestion revenue rent auctions, up from $30 million in Q1 2023.
Kurlinski also noted that real-time balance offset costs in the CAISO area were $51 million in Q1 2024, down from $90 million in 2023. The primary driver of the uplift is load getting paid a different real-time price than generation.
Bid cost recovery (BCR) payments were also down to $41.5 million from $80.3 million in Q1 2023, largely due to a decrease in the residual unit commitment portion of BCR.
NEW SCOTLAND, N.Y. — Small-scale solar arrays in New York have surpassed 6 GW of capacity, meeting a milestone 2025 goal more than a year early.
It’s a bright spot in a state whose energy transition has been progressing more slowly than hoped.
Leaders of the transition and some of those helping to carry it out gathered at a new 5.7 MW solar farm Oct. 17 to celebrate the occasion and advocate for the addition of many more megawatts to follow.
The site itself is easy enough to reach, a smooth ride on main roads to the town of New Scotland, not far from the state offices where renewable energy policy is written, regulated and facilitated.
But the journey to reach the milestone achieved on this site was much longer: 235,803 distributed solar projects of every stripe had to be completed in every corner of the state before this one could push the combined nameplate capacity above 6 GW.
An uncounted additional number of projects dropped out of the pipeline along the way, just as utility-scale projects have seen high rates of contract cancellation in New York.
So why is distributed solar exceeding expectations by adding emissions-free capacity to the grid a few dozen kilowatts at a time? While multi-megawatt projects are lagging so badly the state is likely to miss a key 2030 renewables target codified in its climate law?
State support has allowed an ecosystem supporting distributed solar to grow to scale in New York, said Doreen Harris, president of the New York State Energy Research and Development Authority, one of the main architects and managers of the state’s energy transition.
These same policies send clear market signals that small solar is wanted and will be supported. In a telling indicator, New York — an expensive state with limited sunshine — is the nation’s leader in installed community solar capacity.
Smaller projects are nimbler, said Noah Ginsburg, executive director of the New York Solar Energy Industries Association. They face the same obstacles as large projects, with endless variations across hundreds of local permitting entities, but they can move and adjust quickly enough to not die on the vine.
“The timeline for getting a [distributed] project from idea to up and running, we’re talking three years,” he said. “You can navigate choppy waters and get projects over the finish line on that kind of timeline. And I just think New York has developed a really successful model.”
The 6 GW emerged with steady assistance from the state, including the $3.3 billion NY SUN initiative. The state estimates an additional $9.2 billion in private-sector investment has been a result.
The New Scotland project checks another box on the state’s list of priorities: It is one of the first community solar farms to participate in the Solar for All program. The savings achieved through its operation will be funneled to low-income ratepayers.
Moving Forward
Officials and guests at the ceremony spoke afterward to NetZero Insider about what went into reaching the 6 GW milestone and what comes next.
David Sandbank, NYSERDA’s vice president of distributed energy resources and transportation, said the state categorizes distributed solar as everything from residential rooftop arrays producing a few kilowatts on their best day to several-acre arrays rated at several megawatts, like the new one in New Scotland.
The cutoff is 5 MW for projects quantified in alternating current and a little more than 7 MW for those quantified in direct current.
“So if you talk in DC … I’d say the average home project is about 7 KW in this state. So 7 KW to 7 MW,” Sandbank said.
The next milepost is 10 GW of distributed solar by 2030. NYSEIA earlier this year called for kicking that up to 20 GW by 2035.
Distributed solar is a mainstay of NYSEIA’s 235 member companies, and obviously a priority for Ginsburg, but he says renewables are needed at every scale.
“My view on it is that for the state to hit its clean-energy goals, we need to accelerate utility-scale deployment,” he said.
The problem, Ginsburg said, is that some people overlook the contributions of small solar as they focus on major projects that would provide dozens or hundreds of megawatts.
“So, I try to remind people, 93% of the solar that’s up and running in New York is distributed scale; 6 GW is nothing to sneeze at,” he said.
Rory Christian, chair of the state Public Service Commission, said this fact is not lost on policymakers. It also is clear that 6 or 10 or 20 GW of solar does not by itself allow fossil-fuel generation to be retired — solar’s capacity factor is too low in New York, particularly during the short and often cloudy winter days.
There are simultaneous efforts to develop other forms of emissions-free generation and storage to backstop intermittent solar and wind; to anticipate transmission and distribution needs and address them proactively; and to begin managing the other side of the equation — demand.
So while 6 GW of distributed solar is an achievement to be celebrated, it is a mile marker rather than a finish line, a piece of a strategy that still is being planned out.
“We know there’s a gap. It’s documented in the [state climate law]. We are working to address that gap, and we recognize that we need to do more, and so we have the plans in place to do more, and we’re figuring that out as we go,” Christian said.
“What are those dispatchable emissions-free resources? What will those be? How will those function? Where do we put them? We’re looking at that right now.”
Electric utilities are working on their part of the equation.
The new solar farm sits near a National Grid substation and almost beneath some of its transmission lines.
That proximity helps with development, but there are many other factors that go into siting and system planning, said Brian Gemmell, National Grid’s chief operating officer for electric. “It’s all about making [sure] that the reliability is there, the resilience, the infrastructure is appropriately sized for the project.”
The utility is investing billions of dollars in dozens of projects to make its upstate New York network ready for more renewables expected to be built there.
Hurdles to Clear
Dan Berwick, CEO of New Leaf Energy, the New Scotland project developer, said solar development is not an easy proposition in New York. Permitting is hard, interconnection is harder, costs are higher than in other states and profits are lower. But New Leaf keeps at it, he added, and now has nearly 200 projects in development statewide.
State leadership is committed to making renewable development happen, and that makes it possible to clear those hurdles.
“We keep investing, even though it’s tough, because New York has a unique winning formula. New York’s political leadership sets big, clear, bold goals, and then NYSERDA and the Department of Public Service execute on those goals,” Berwick said.
“No other state has a NYSERDA, and that is why there’s no other state where we will develop projects and make substantial investments in projects based only on what a state government says it will do, as opposed to what it has already done. That’s unique, and it’s very powerful.”
The area is a blend of suburban and rural, light industrial sites and homes mixing with fields and woods. It is a quick drive from the state Capitol, yet far enough removed from the city that some people expect to see trees and distant hills rather than solar panels. A nearby apple orchard is a longstanding agritourism destination.
New Scotland Town Supervisor Douglas LaGrange spoke about the balance struck as the project moved through its yearslong development and review.
New Scotland is one of New York’s Climate Smart Communities, he said, and wants to do its part to advance climate protection goals.
“It started years ago when … we saw the opportunity to bring solar into the town and accommodate it, but we wanted to balance it with the beauty of the town,” LaGrange said. “It’s a beautiful area. And there are those that might suggest that solar arrays aren’t the prettiest things in the world, but we came to a point where we could balance both.”
He added: “This is a perfect example of that all coming together.”
Steven and Wendy Burke have owned the 27-acre site for more than 20 years but never developed it themselves. A local farmer cut hay from the portion that was not wooded.
The couple support renewable energy development; she drives an electric vehicle. When they decided to lease their land for solar development, they got some friction from a few neighbors, but it was less about the panels than the effect of the panels.
“There was a couple neighbors that had [objected] in the beginning, not knowing what it was going to look like,” he said.
“Or had questions and how things were going to be done,” she continued, “and wanted to make sure that it wasn’t going to be unsightly, that there was going to be proper screening, that it was going to be maintained properly, which were valid questions, and the town was able to answer those questions.”
One of the more frequent questions, the Burkes and LaGrange both said, was whether the array would be visible from the landmark Thacher Park overlook atop a 700-foot escarpment two miles away.
It is not, thanks to the contour of the hill. And the line of mature trees at the solar farm’s perimeter blocks passing motorists’ view of the panels, save for a gap the driveway runs through.
A line of saplings transplanted inside will close that gap in a few years.
Ginsburg said this is a winning approach.
“I think the reality is that as a species, we are resistant to change, but ultimately we need clean energy in our state,” he said. “Projects like this can be built in a way that’s aesthetic and that’s beneficial.”
ATLANTIC CITY, N.J. — States can reap long-term savings by upgrading their onshore grids and coordinating transmission development to serve multiple offshore wind projects, but they’ll also face higher upfront costs, supply chain challenges and ratepayer concerns, speakers at a New Jersey conference said Oct. 11.
Planned and coordinated transmission upgrades could save billions of dollars across the OSW sector, but the complexity and extensive planning needed to bring different stakeholders and states together to craft solutions could take more than a decade, speakers at the Time for Turbines 7 conference in Atlantic City said.
New Jersey’s use of the State Agreement Approach (SAA) to create $1.07 billion in transmission upgrades that can deliver 6,400 MW of OSW generation to the PJM grid is a prime example of the benefits of planning, speakers told conference attendees.
Yet time is of the essence for all states, according to Abraham Silverman, assistant research scholar with the Ralph O’Connor Sustainable Energy Institute at Johns Hopkins University. The global market for transmission equipment is competitive, and developers need to line up their supply chain now to ensure equipment is available years ahead of when it’s needed, Silverman told the 150 developers, government officials, environmentalists and other stakeholders at the conference.
Abe Silverman, Johns Hopkins University | Christian Fiore
“States are making procurement decisions today that are going to be delivered in the early 2030s,” he said. “2030 is today.
“So if you are going out and buying it, [and] thinking about offshore wind, you need to have all the major questions answered” around what’s being built, voltage levels and suppliers, Silverman said. “And I think, frankly, a lot of us see what happens when developers don’t have their supply arrangements totally locked up, and we end up in real problems, and you get delays.”
Projects in Germany and Scotland are “going ahead and procuring their HVDC equipment and stockpiling it for future use,” said Janice Fuller, former Mid-Atlantic president at Anbaric, which specializes in developing transmission for OSW projects.
“The projects aren’t awarded, but they’re buying [the equipment], and they will have it ready,” Fuller said. “So that also puts us a little bit further behind in that global supply chain.”
Planning Initiatives
Procurement is just one challenge conference speakers said is facing New Jersey and other states as they try to prepare their grids for the 60% increase in transmission capacity needed to bring about widespread electrification, according to Princeton University’s 2021 Net-Zero America report.
The New Jersey Board of Public Utilities (BPU) says ratepayers will save $900 million from its project to upgrade onshore transmission infrastructure to link OSW projects to the grid. The BPU and PJM created the project under the SAA, and the BPU in February sought FERC approval to use the SAA in a second solicitation but later put that plan on hold.
“Essentially, what we are trying to do is avoid a bunch of individual onshoring efforts and to minimize environmental impacts, minimize community impacts, minimize project risk and risks of delays that may come from a bunch of one-offs coming in,” said BPU Executive Director Robert Brabston.
The order requires RTOs and ISOs to undertake long-term transmission planning — with a 20-year time frame, taking into account anticipated load growth, state laws and generation retirements. The plans must be updated every five years.
Brabston said New Jersey can benefit from Order 1920’s planning requirements by addressing the “vastly different networks in the state.” These range from the well-developed infrastructure in the north to areas in the south that were “built to cobble together the agricultural part of the state and the population centers.” While southern areas have the space to house data centers and grid-scale solar projects, the grid there “wasn’t built for it, it’s not ready for it,” he said.
“So we need to be able to do things like pursue grid-enhancing technologies, because you can’t just build all new pipes and wires for infrastructure,” he said. “If you’re going to modernize utilities, you’ve got to modernize the utilities. It’s not just new wires. It’s reconductoring. It’s all kinds of other stuff.”
That means “getting this project selection criteria updated so it takes more factors into account and is more transparent,” he said.
Collaborative Strategy
Long-term planning was also central to New Jersey and nine other East Coast states in July establishing the Northeast States Collaborative on Interregional Transmission to explore mutually beneficial interregional transmission to increase the flow of electricity among ISO-NE, NYISO and PJM, as well as assessing offshore wind infrastructure needs. (See 10 Northeastern States Sign MOU on Interregional Transmission Planning.)
“The theory is, if it saves $900 million when New Jersey does it alone, how much is it going to save when we work with Maryland, New Jersey and Delaware, or New York and New England and all the other places?” asked Silverman, who helped put together the coalition. He noted New York had also studied the benefits of creating an “offshore wind backbone” similar to New Jersey’s and found it would save ratepayers $500 million.
Silverman said it’s not just about the savings, but also improved reliability, faster interconnection times and “derisking” of projects “so that when we ask developers to put billions of dollars of capital at risk, they really feel comfortable coming to that table.”
“We’ve seen success within individual states or even on a regional basis, like New England. But we also need to get states talking to each other and cross over some of these artificial barriers.”
Cost Allocation Straitjacket
However, that kind of collaboration raises questions about technology standardization, Fuller said.
As generators bid their projects and suppliers try to determine how to prepare for projects that won’t break ground —or water — for another decade, it’s crucial for both sides to agree on uniform standard for the technology being used, she said.
“That plays into your ability to have mesh-ready projects, projects that could be brought together in the future and connected together,” she said.
Janice Fuller, former president, Mid-Atlantic, Anbaric | Christian Fiore
Another ongoing issue is who pays for the projects, Brabston said.
“One of the key things from a New Jersey perspective is trying to get out of this straitjacket of: If it’s a state policy thing, the state has to pay 100% by itself,” he said, which fails to account for the fact that “all states stand to benefit from this to a greater or lesser extent. We should be talking about cost allocation, not an all-or-nothing kind of thing,” he said.
Fuller called the New Jersey initiative the “canary in the coal mine” for other states and stakeholders, particularly because it received 80 bids from 13 developers. (See NJ BPU OKs $1.07B OSW Transmission Expansion.)
“I think the industry stood up, and other states stood up, and said, ‘Oh, that’s real. They got a real robust response with really creative solutions, and it’s going to have a tremendous ratepayer impact,’” she said.
One challenge is communicating the benefits to the public, Fuller said. She said renewable development often prompts skeptics to say, “Why do we need to do this? It’s going to impact our electric bills, and the ratepayers aren’t going to be able to tolerate that.”
But infrastructure upgrades can produce multiple benefits, including realizing substantial savings for consumers and reducing the number of cables and beach crossings needed, she said.
Fuller suggested using the phrase “benefit allocation” to make projects more palatable to the public.
“We always talk about cost allocation,” she said, but changing the term could show “it’s not just fair sharing of the cost, it’s understanding where the benefit lies, and so you’re paying your share of the benefit.”
