ISO-NE’s work in 2025 will focus on capacity auction revisions, establishing a regional energy shortfall threshold (REST), complying with FERC orders 1920 and 2023, and implementing market and technology improvements, COO Vamsi Chadalavada told the NEPOOL Participants Committee (PC) Oct. 10.
The capacity auction changes are focused on improving how the capacity market assigns value to different resources and altering the timing of capacity auctions and capacity commitment periods (CCPs). The scope of work for the project is extensive, and ISO-NE expects the project to extend into 2027, in preparation for the 2028/2029 CCP. (See ISO-NE Responds to Feedback on Capacity Auction Reforms Scope.)
Regional Energy Shortfall Threshold
The REST is an effort to quantify how much shortfall risk from extreme weather events the region is willing to accept during a given season.
Chadalavada said the RTO will start working on the REST project in the fourth quarter of this year, continuing into the first or second quarter of 2025. ISO-NE is planning to conduct the first REST assessment for the winter of 2025/26.
“Results of the first assessment will provide more data on the risk trends to guide the timing and nature of the next phase, which is to evaluate whether the possibility of exceeding the REST requires development of specific regional solutions to mitigate risks,” Chadalavada said.
He emphasized the need for stakeholder input — especially from the states — to determine an acceptable threshold.
Transmission Planning
Chadalavada said ISO-NE is planning to initiate a request for proposals process in 2025 for its newly approved longer-term transmission planning framework, “in anticipation of a request from the states for a competitively selected transmission solution to address the future, clean energy needs in connection with the Transmission 2050 Study.” (See FERC Approves New Pathway for New England Transmission Projects.)
The RFP process will likely take about 18 months “from initiation through final recommendation,” Chadalavada said.
He noted that ISO-NE will continue to work with stakeholders on “the assimilation” of the LTTP process with FERC Order 1920, with compliance on the order due in summer 2025. (See With FERC Inaction, ISO-NE Delays Order 2023 Implementation.)
ISO-NE is also planning to work with the states in the coming year on an approach to “right-sizing” transmission upgrades “to support integration of renewables and higher load levels over the life of the transmission asset.”
The discussions will include a focus on “methods for distinguishing right-sizing costs from asset condition project costs so that they can be evaluated accordingly,” Chadalavada said, adding that the discussions will likely begin when the states and transmission owners have completed their work on improving the asset condition project review process.
In response to a request from the New England States Committee on Electricity (NESCOE), Chadalavada said ISO-NE will begin discussions at the Planning Advisory Committee about how advanced transmission technologies should be incorporated into transmission planning processes.
“To the extent that ISO-NE considers such technologies currently, bringing greater visibility to that would be informative,” NESCOE wrote in August. “An effective planning process should result in the deployment of these technologies when they provide a net benefit to consumers.”
Budget Increase
The PC also approved a 13.6% increase in its annual budget, driven by new investments in personnel and technology focused on clean energy, the impact of inflation on current operations, and a $7.8 million true up. The increases bring the projected 2025 ISO-NE budget up to about $314 million.
ISO-NE has emphasized that the budget increase is needed to meet the growing complexity of managing the grid during the clean energy transition. The increase follows a 21.5% budget increase in 2024. (See ISO-NE Proposes 21.5% Budget Increase for 2024.)
The budget is intended to support the addition of about 50 new full-time equivalent positions in 2025, along with improved cyber security and software capabilities.
One stakeholder stressed that increased resources should come with increased expectations regarding the workload ISO-NE is able to take on in the future and expressed hope that the RTO will be able to accommodate more stakeholder requests.
Operations Report
Overall energy market value was down nearly 8% in September compared to September 2023, Chadalavada told the PC, presenting his monthly operations report. Average locational marginal prices were down by about 18% from August of this year.
While ISO-NE hit its annual peak load of more than 24,000 MW in September 2023, the September peak for this year topped out at just 16,853 MW.
Annual power system carbon emissions continue to track higher in 2024 relative to 2023, driven by an increase in natural gas emissions.
CARMEL, Ind. — Demand response in MISO is poised to be subject to more rigorous standards as the Independent Market Monitor warns of more potential bad actors.
Carrie Milton, of the IMM staff, appeared before an Oct. 11 Market Subcommittee to put MISO and stakeholders on alert that MISO’s market likely contains more deceptive demand response players. It’s a warning IMM David Patton has delivered before. (See “IMM Demands Tougher Demand Response Requirements,” MISO: Hurricanes, Heat Wave Noteworthy Against Relatively Peaceful Summer.)
Milton said a review of Demand Response Resource Type I performance from 2023 to 2024 showed that those resources fall short of the amounts they promise. She said of 213 spinning reserve deployments across 22 event days in 2023-2024, more than 40% of the DRR Type I resources did not perform adequately. About 200 MW of DRR Type I participates regularly in energy and ancillary services.
FERC recently uncovered three companies manipulating MISO’s demand response market and collecting unwarranted payments. The commission found that an air separation facility in Indiana accepted payments for fabricated load reductions, an Arkansas steel mill for years made faux use reductions, and an obscure, Texas-based LLC formed to sell in-car ketchup holders fraudulently enrolled customers and made sham DR offers in three capacity auctions.
Milton said demand response that fails to respond to MISO’s calls for spinning reserve deployments faces only small penalties and, in some cases, still receives make-whole payments, “eliminating any incentive to curtail.”
“We have a lot of concerns about this. MISO’s rules, penalties and participant conduct all raise concerns for us,” Milton said.
She also said the Batch-Load Demand Response category, introduced by MISO in 2020, contains the worst performers.
“This class of DR is cycling load that agrees not to increase rather than to curtail,” Milton said.
Milton also said MISO’s practice of accepting mock tests instead of actual performance testing “presents serious opportunities” for misrepresenting a resource’s abilities. She said up to 25% of DR resources submit mock tests for accreditation.
“Since 2019, our demand response has received over $800 million in capacity payments. That’s a lot of money,” Milton said.
Milton repeated Patton’s asks that MISO eliminate mock testing and the batch-load demand response category, intensify penalties and automate validation of end-use registrations so end-use customers can’t contract with multiple market participants. She also asked MISO to require utility-grade meters and five-minute data for DR providing reserves.
Stakeholders warned that the IMM’s recommendations might make DR participation in the MISO markets unattractive.
Louisiana Public Service Commission staffer Robert Vosberg said he wanted the IMM to quantify the impacts of its recommendations on ratepayers’ bills.
Jim Dauphinais, an attorney representing multiple industrial customers in MISO, asked for a “less intrusive” list of recommendations.
“If we make this too difficult for customers, they will exit the program,” WEC Energy Group’s Chris Plante warned. He added that if “even half” of the 7 GW seasonal average of demand response that cleared the MISO capacity auction this year fails to participate, MISO will be in hot water.
“We just want it to be reliable,” Milton said of demand response. “It needs to be reliable, and MISO needs to be able to count on it. That’s the crux of this. … We need to make sure that these are legitimate resources that exist and are capable of curtailing load when called upon.”
MISO adviser Michael Robinson remarked that demand response has been getting more attention lately.
“It’s almost like we should have a joint Resource Adequacy Subcommittee and Market Subcommittee meeting on demand response,” he joked.
Robinson said while MISO already has rules to discourage demand response frauds, the recent instances mean it wouldn’t hurt to do more to discourage artificially inflated baselines, fraudulent registrations and artificial curtailments.
Robinson prefaced his comments by invoking a recent trip to a western Michigan orchard. He said when storing apples for the winter, one periodically should go through the bushels to look for bad apples.
“We are responding to essentially three bad apples that FERC has identified. And if you listened to the Market Monitor this morning, there are probably a few more,” Robinson said.
In August, Robinson jokingly invoked Dire Straits 1985 rock song “Money for Nothing” to describe the three recent schemes.
The rules will impel market participants to prove their legitimacy annually by sharing their contractual agreements with MISO. They also will require regularly updated meter data alongside attestation of baseline use. MISO will screen offer parameters and stop allowing whole event days to be precluded from the baseline calculation and instead use just the hours where LMRs responded.
MISO’s IMM also would assess demand response for withholding and create reference level calculations for demand response resources.
New LMR Accreditation Looks Certain
A more exacting accreditation remains on the way for MISO’s load-modifying resources over members’ objections.
MISO said staff will make a final presentation in November before filing the new LMR accreditation with FERC.
MISO’s LMR Type II category would have a maximum response time of 30 minutes and presumed availability for all of MISO’s maximum generation emergency step two events.
Conversely, an LMR Type I class would carry a maximum response time of six hours and be called up earlier, when MISO declares a maximum generation alert. MISO has long said it needs to be able to access LMRs outside of actual emergency declarations.
MISO plans to use a similar accreditation with its availability-based method for its more traditional generation resources. However, to measure demand response, MISO said it will use backward-looking meter data from hours when capacity advisory declarations are in place to accredit resources. The RTO plans to draw on data from a minimum of 65 historical hours per season over the past year and will give more weight in accreditation to performance during hours where capacity advisories escalated into maximum generation events, alerts or warnings.
MISO said it will cap accreditation at an LMR’s maximum stated capability during registration. The RTO also said it will reduce accreditation when LMR owners submit inaccurate availability information. Currently, MISO doesn’t tie the accuracy of LMR availability data to accreditation values.
The new accreditation model will put an end to demand resources being free to dual register as both LMRs that collect capacity payments and demand response resource types, which receive energy payments.
Joshua Schabla, a MISO market design economist, said MISO’s proposed accreditation design appropriately allows for “diversity of performance and diversity of characteristics.”
At an Oct. 9 Resource Adequacy Subcommittee meeting, Schabla said in addition to the usual large factories and mills, MISO’s LMRs also include about 250 resources that are 1 MW or smaller. He said the availability-based accreditation will keep smaller LMRs participating alongside the sites capable of significant load reductions.
“We do think that our overall design captures as much of this as reasonable,” Schabla said. He added that it’s difficult to keep the design simple because of the array of MISO’s LMR types.
Schabla said MISO remains convinced it needs to call on its longest-lead LMRs during maximum generation alerts rather than when actual emergencies arrive.
“We’re trying to incentivize more rapid response time. For longer lead resources to be effectively utilized, MISO needs the capability to deploy them earlier. … If you have a six-hour lead time, we need to deploy you earlier to effectively use you,” he said.
Plante said most of WEC Energy Group’s large industrial customers aren’t comfortable with a 30-minute lead time, citing safety concerns with powering down so quickly. On the other hand, Plante said WEC’s slower-moving LMRs are uneasy with the risk exposure of being called up six hours ahead of when they’re needed. Plante said a two- or even five-hour notification might be more suitable.
“What I’m hearing is neither option is really viable,” Plante said.
MISO and stakeholders sparred over the RTO’s goal to discontinue use of LMRs being able to use a firm service level option to participate. MISO’s firm service level option currently allows LMRs to select a prespecified baseline when registering, agreeing not to use more than that during emergencies. Unlike other LMRs, those using firm service level must curtail all nonfirm load from the system, rather than deducting a megawatt amount from a baseline demand.
Several stakeholders said MISO should preserve the firm service level option, calling it a cornerstone of LMR use in MISO. Dauphinais, the attorney representing multiple industrial customers in MISO, said it would be a “fatal flaw” to cut the participation option.
“We don’t see stated availability moving as fast as we see these loads moving,” Schabla explained. He said MISO needs a more accurate measurement of LMR capability.
Schabla said MISO expects there to be a “tolerance band” around the actual reductions LMRs can make, using the fluctuating draw of air conditioning programs as an example.
“By no means are we expecting you to know exactly what you can provide. We expect you to tell us, within a margin, of what you can give us,” Schabla said.
Multiple MISO stakeholders derided MISO’s reliance on its Demand Side Resource Interface tool for availability data. They complained that the DSRI, which recently replaced the MISO Communication System for communicating LMR availability, is not well understood and that members could use training sessions.
Schabla said he agreed MISO should provide member training on the system sooner rather than later.
CARMEL, Ind. — Midwestern power producers are asking for re-evaluation of MISO’s cost of new entry in light of recent clean energy goals.
The Coalition of Midwest Power Producers (COMPP) recently approached MISO’s Market Subcommittee to ask that MISO reconsider cost of new entry (CONE) being rooted in 20-year gas plants.
Currently, MISO’s CONE represents the cost of building an advanced combustion turbine and differs by zone to reflect regional differences in construction costs. The CONE calculation assumes a 20-year lifespan and loan term; considers debt-to-equity ratio and interest rates; and includes capital costs, property taxes, insurance costs, and operations and maintenance expenses. Values are used to set the limit for clearing prices in the RTO’s capacity auctions.
COMPP pointed out that Illinois in 2021 passed the Climate and Equitable Jobs Act (CEJA), which stipulates that most combustion turbines be retired by 2040. The group said it’s no longer appropriate to presume a 20-year project life and loan term for gas plants in Zone 4’s CONE calculation and asked MISO to “develop a process to adjust” Southern Illinois’ Zone 4 CONE “by reducing the assumed project life and loan term to capture CEJA’s retirement mandates.”
COMPP said MISO might expand its CONE investigation into other local clearing zones as they rev up and implement clean energy goals and 20-year gas plant waypoints go out of fashion.
FERC on Oct. 8 granted and denied in part challenges to Pacific Gas and Electric’s 2022 transmission rates, finding that PG&E must remove certain costs from its rate base while also denying a request to pause the utility’s ability to recover costs stemming from two massive fires in California.
The order concerns PG&E’s rate year 2022 information filing, which reflected increased costs in both retail and wholesale base transmission revenue requirements (TRRs) (ER19-13).
The utility reported that its retail base TRR would increase from approximately $2.214 billion to $2.812 billion, while its wholesale base TRR would rise from about $2.202 billion to $2.799 billion.
The California Public Utilities Commission and the California cities of Anaheim, Azusa, Banning, Colton, Pasadena and Riverside challenged the update. FERC handed wins to both sides in its decision while also scheduling some issues for hearing and settlement judge procedures, according to the order.
In siding with the challengers, FERC found that PG&E cannot claim that its vegetation management, such as tree removal, is similar to initial construction activities, which would have allowed PG&E to tack those costs onto its rate base. Instead, FERC ordered PG&E to reclassify such costs as operating and maintenance expenses and remove the costs from its rate base.
“PG&E has not demonstrated that tree removal associated with its [right of way] expansion qualifies as a substantial addition to plant nor a construction of a new asset, and accordingly, PG&E must record such costs in the appropriate O&M expense account,” the order stated.
However, FERC denied CPUC’s request for an order requiring PG&E to remove costs related to the 2019 Kincade Fire and the 2020 Zogg Fire. The devastating fires burned thousands of acres and destroyed hundreds of buildings in Northern California, and CPUC has hit PG&E with severe penalties over the utility’s alleged role in those fires and others. (See CPUC Fines PG&E $45M for 2021 Dixie Fire.)
In its 2022 challenge, CPUC asked FERC to avoid holding ratepayers responsible for the wildfire recovery costs until liability had been determined in various pending investigations and regulatory proceedings, according to the order.
FERC denied the challenge in the Oct. 8 order, finding that it rejected a similar challenge in San Diego Gas & Electric’s formula rate annual update in 2016.
“Consistent with this precedent, we are not persuaded to hold the allowance of costs at issue in this proceeding in abeyance pending resolution of the state criminal, investigatory and regulatory proceedings,” the order stated. “As in the SDG&E proceeding, the ongoing and potential state proceedings CPUC describes could take significant time to resolve, meaning that this proceeding would ‘be held in abeyance for an indefinite period of time.”’
FERC noted that its order “does not limit any party’s right to challenge the justness and reasonableness of the allowance of costs associated with the Kincade and Zogg fires in subsequent PG&E annual informational filings, including by pointing the commission to any relevant information that may emerge from state proceedings regarding the Kincade and Zogg fires.”
Additionally, FERC rejected challenges to PG&E’s accounting of costs related to upgrades to transmission towers, monitoring systems and a boardwalk replacement program.
CPUC also targeted insurance proceeds, wildfire-related costs and costs associated with removing the PG&E-operated Caribou-Palermo transmission line, which failed in 2018, resulting in the Camp Fire, one of the deadliest in California’s history. (See Ancient C Hook, Financial Manipulation Caused Camp Fire.)
Similarly, CPUC argued that ratepayers should not bear the burden of reconnecting the Grizzly Powerhouse, a hydropower project, to the transmission grid, saying that “would not be necessary but for the Camp Fire,” according to the order.
However, FERC declined to take a position on those challenges, finding that the matters “raise issues of material fact that cannot be resolved based on the record before us.” Instead, the commission sent the matters for a trial-type evidentiary hearing but encouraged the parties to reach a settlement before hearing procedures commence.
Representatives for the parties did not return requests for comment.
A Brattle Group study comparing key features of CAISO’s Extended Day-Ahead Market and SPP’s Markets+ contains “several material misstatements of facts” and overlooks evidence “directly contrary to its conclusions,” Powerex contends in an Oct. 7 brief criticizing the study.
The brief from the energy trading arm of Canada-based BC Hydro comes in response to a white paper Brattle published Oct. 1 that sets out a point-by-point comparison of seven design features of the EDAM and Markets+, including transmission optimization, fast-start pricing, real-time unit commitment (RTUC), procurement of imbalance and flexibility reserves, seams optimization, greenhouse gas pricing and congestion revenue allocation. (See Brattle Study Likely to Fuel Debate over EDAM, Markets+.)
All those features have figured prominently in the often-contentious debate between supporters of each market, which increasingly is playing out in various back-and-forth studies and presentations, as well as a series of “issue alerts” published by a core group of Markets+ funders — which includes Powerex.
Fast-start Conflict
In its brief, Powerex contends “the failure of the Brattle paper to provide a credible and fact-based examination of the market design differences is clearly evident in its discussion of fast-start pricing [FSP].”
While Markets+ supporters argue that FSP is an important benefit of the SPP market that’s conspicuously absent from CAISO’s markets, the Brattle paper played down the importance of the mechanism, saying evidence from several RTOs in the East — including SPP — shows FSP has minimal impact on market prices or revenues for fast-start resources.
Brattle questioned the viability of a 2022 study conducted by consulting firm Energy GPS for Powerex and the Portland, Ore.-based Public Power Council (PPC), which analyzed potential impacts on CAISO markets if the ISO were to implement FSP.
In his initial reaction to the Brattle study, Jeff Spires, director of power at Powerex, told RTO Insider that Brattle misrepresented the results of Energy GPS’ analysis and failed to include the most recent data from the Eastern RTOs showing the benefits of FSP.
The Powerex brief builds on Spires’ points, for example asking why Brattle chose to present MISO’s FSP analysis from 2015 and 2016 when more recent data are available online.
“This is a glaring omission, as later reports paint a very different picture,” Powerex wrote. “In 2021, the MISO Independent Market Monitor explained that while the initial effect of fast-start pricing was very small (when fast-start pricing was a new market design feature), MISO subsequently made important changes to how it applies fast-start pricing that ‘have significantly improved real-time price formation in MISO,’” according to the Monitor’s 2021 State of the Market report.
Powerex said MISO data show that, from 2020 to 2023, the overall price impact from FSP was 50 to 100 times the 1- to 3-cents/MWh estimates for 2015 and 2016 cited by Brattle.
The brief said Brattle’s study also omitted evidence that, in recent years, FSP in PJM added an average of $4/MWh to $8/MWh to the RTO’s prices during morning and evening demand peaks.
Powerex also said Brattle “briefly acknowledges” that New England system prices increased by 11% when ISO-NE implemented FSP, but at the same time cautions the analysis identifying that increase was “limited to the first eight months after FSP came into effect.”
“Brattle could easily have reviewed the annual reports for [ISO-NE] published since then,” Powerex wrote, citing the ISO-NE Internal Market Monitor’s conclusion in its 2023 Annual Markets Report that “fast-start pricing rules in the real-time energy market continue to have notable impacts on pricing and market costs.”
Powerex also castigates Brattle for saying Energy GPS’ 2022 analysis suggested FSP would have had an average price impact of $15/MWh to $23/MWh on CAISO’s market over 2017-2020 if the ISO had implemented the practice.
“In fact, the [Energy GPS] report clearly states that ‘for the evening peak hour from 6 p.m. and 7 p.m., this price impact averaged nearly $15/MWh in NP15, and nearly $23/MWh in SP15,’” Powerex wrote, referring to trading hubs on the CAISO system. “The Brattle paper takes the price impact of the single-highest hour and presents it as the price impact across all hours, which is simply false.”
John Tsoukalis, a principal at Brattle and the lead author of the study, said his group “will take a close look at and consider the additional evidence [Powerex] put forward on fast-start pricing, but we note that the fast-start pricing section of our white paper is based on the analyses conducted by market monitors in other regions.
“For example, SPP’s [Market Monitoring Unit] stated in May 2022 that ‘there was very little change in the revenues to fast-start units due to the new fast-start pricing. The fast-start pricing appeared to have created [a] 1.5% increase in day-ahead revenues to fast-start resources and a 0.5% increase in real-time revenues. All else equal, the increase in revenue would cause a negligible reduction in make-whole payments,’” Tsoukalis said in an email.
CAISO and FSP
The Powerex brief also calls out CAISO for being the only FERC-jurisdictional organized electricity market without fast-start pricing.
The company explains that in markets with FSP, “special pricing logic” is applied to ensure the cost of starting and operating fast-start units is allowed to set the market’s LMPs when those units are determined to be providing supply at the market’s margin. In markets without FSP, the LMP can remain “well below” the cost of running peakers and “artificially” depress wholesale prices, reducing the amount paid to local generators and imported electricity from neighboring balancing authority areas.
“Avoiding the adoption of fast-start pricing therefore largely benefits utilities (and their ratepayers) in jurisdictions like California that typically import electricity during the hours of the day that gas peaking units are frequently used, while harming suppliers (and their ratepayers) in jurisdictions that typically export electricity during those same hours,” Powerex wrote.
Powerex pointed out that CAISO opposed a 2016 FERC proposal that would have required all organized markets to adopt FSP and that the ISO’s Department of Market Monitoring intervened to oppose adoption of FSP in any market.
“Such opposition aligns with California’s own interests, since the state has historically been a large importer of electricity from both Northwest and Southwest utilities in those hours that gas peakers are running,” Powerex wrote.
Reached for comment on Powerex’s contentions, CAISO pointed out that its Price Formation Enhancements (PFE) Working Group is exploring the potential for implementing FSP in the ISO’s markets.
“We recognize this feature has been adopted in other markets, with each carefully considering integration into its existing design. Different design features of fast-start pricing have tradeoffs that need to be considered by the stakeholders, and in particular, compatibility with existing features of the ISO market design that were specifically developed to compensate flexible and responsive resources with much the same goal as fast-start pricing,” the ISO said in an email.
Still, CAISO said its own analysis, presented to the PFE in April, showed a “minimal $0/MWh impact of fast-start pricing in the Northwest with similar minimal impacts in the Southwest, the exception being very narrow stressed system conditions under which the price impact was small in the CAISO and some specific areas of the Southwest ranging from $2 to $8/MWh depending on the sensitivity.”
Other Features
While the brunt of Powerex’s response dealt with FSP, the company also briefly contested the Brattle paper’s assessment of other market features, including GHG pricing mechanisms, congestion revenue allocation and transmission optimization.
Regarding the last feature, Powerex says the Brattle paper incorrectly asserts that “some stakeholders” — that is, Markets+ supporters — have suggested the market would rely “solely” on flow-based optimization of transmission within its territory, while EDAM would rely on both flow-based and contract path-based optimization.
Powerex said it recognizes that both markets will need to apply contract path limits for rights on transmission located within the boundaries of one market but used in another market.
“But the actual distinction that has been pointed out is that in EDAM, the California ISO will also apply contract-path limits to EDAM transfers between balancing areas participating in the EDAM, just as it applies contract-path limits for [Western Energy Imbalance Market] transfers between entities in the EIM,” it said. “In contrast, Markets+ will limit transfers between balancing areas participating in Markets+ based on physical flow-based limits, enabling more efficient use of the transmission system.”
Cloud computing represents a potential boon for the operators of the North American electric grid, but adapting to the change while remaining compliant with NERC’s reliability standards could be a significant challenge for utilities, a speaker from ReliabilityFirst said at SERC Reliability’s Fall Reliability and Security Seminar.
Lew Folkerth, principal reliability consultant at RF, cast the transition to cloud computing as the latest in a long line of changes. He started his presentation by showing a picture of a slide rule, jokingly asking how many in the room recognized it, before juxtaposing it with a picture of a cloud data center. Both were intended to “help solve problems,” he said, but the data center would “help solve problems just a little bit faster.”
“We [deal with] this stuff all the time. We change daily. But if we don’t manage it, it bites us, right? So, what we’re doing now is all about managing the change in the computing paradigm that we’re seeing coming at us like a freight train,” Folkerth said.
Utilities in the electric industry are moving to adopt cloud services with growing speed, Folkerth said — but the choice sometimes can seem like it is out of operators’ hands. A major driving force is the migration of “essential services that we’re used to having on premise,” such as multifactor authentication and security applications like anomalous traffic detection and end-point detection and response. Folkerth said NERC’s recently approved requirements for internal network security monitoring are an example of a service “that’s probably best done in a cloud environment.”
The move to the cloud can create unforeseen problems regarding compliance with NERC’s Critical Infrastructure Protection (CIP) standards. For instance, Folkerth pointed out, cyber systems classified as “low impact” under NERC’s standards — meaning they pose a lower risk of disrupting grid operations if compromised — are not required to have physical control centers on-site. However, this requirement changes if a system is reclassified to “medium impact,” which may be as simple as expanding a solar farm to 1500 MW.
“The question is, from the ERO perspective, do we make them backtrack? Build a physical control center with on-site computers so that they can be fully compliant … at significant cost? And how much are we actually adding to the reliability of the [grid] by making them do that?” Folkerth said.
Another challenge with the cloud transition is ensuring compliance when the service providers themselves are not subject to the CIP standards. Cloud operators such as Microsoft and Amazon serve many clients, Folkerth pointed out, and store their data in multiple locations — which may not mesh well with NERC’s security expectations. Expecting them to “let each and every utility audit their systems” is not realistic.
Reliability is another concern. Folkerth said some major cloud providers advertise 99% availability, which sounds “pretty darn good” — except that “99% means 3.65 days per year you don’t have service.” One solution is to have multiple services so that if one fails a utility can switch to another. This approach still could introduce an unpredictable level of latency.
Folkerth encouraged seminar attendees to follow the work of NERC’s standard drafting teams developing the requirements related to cloud services and participate if possible.
Virtual power plants can help the power grid deal with some of its most pressing issues, such as meeting rising demand and helping to integrate more renewables affordably, according to a recent report from RMI and the Virtual Power Plant Partnership (VP3).
The report, “Power Shift: How Virtual Power Plants Unlock Cleaner, More Affordable Electricity Systems,” lays out a path to expand VPPs, in line with the Department of Energy’s VPP Liftoff report from last fall. (See DOE Report Lays out Commercialization Path for VPPs.)
About 500 VPP programs already are in operation, providing between 30 GW and 60 GW of peak-coincident capacity in the country. With hundreds of gigawatts of new distributed energy resources coming online, the report says VPPs could serve much of the emerging need for 160 GW by 2030.
While the technology is being used today, it’s important that it’s part of any planning processes, said the report’s co-author, RMI’s Tyler Fitch.
“The key is going to be changing our operations and planning processes such that VPPs are visible to them and making it such that VPPs can respond to signals in ways that make sense for the grid,” Fitch said.
Current planning practices can silo the distribution system, where VPPs are located, off from the bulk transmission system, so ensuring they can be procured and dispatched like any other is going to be important to fulfilling their potential, Fitch said.
Ben Brown, CEO of VP3 member Renew Home, said VPPs offer the kind of dispatchable, clean resource the grid needs.
“I think there tends to be a lot of focus on newer technology; technology that can go after solving some problems,” Brown said. “And I think for us, it was really important to highlight that, hey, there’s a lot of existing latent resources out there.”
Renew Home was created by the merger of Google Nest Renew and OhmConnect, and it now runs the largest residential VPP in the country. More than 80 million households have installed electric heating and cooling systems, and water heating increasingly is done with electricity, Brown said.
“Those represent … an existing growing resource that, if tapped into correctly, really can provide a meaningful, very low-cost way to support decarbonization and some of the load growth that we’re seeing on the grid,” Brown said.
VPPs offer benefits over the grid-scale resources they compete with in that they are rapidly deployable, meet load where it exists and offer local economic, reliability and resilience benefits, the report says.
“We believe we could bring together about 50 GW of VPP capacity online by 2030 just through kind of the current funnels,” Brown said.
VPPs do not require new technology, and there’s no need to build new infrastructure, with customers installing smart thermostats, distributed solar and storage, and electric vehicles into their existing homes, Brown said.
“Being able to engage directly with households around ways in which their home can add value to the grid and therefore actually them get paid for it, and then being able to reduce their energy costs, is such a huge component of this,” he added.
Getting residential customers signed up in VPPs will be increasingly important to help balance the grid, Brown said. ERCOT, where Renew Home is active as a retail electric provider, already sees its demand peak in the summer, and its winters are driven by residential demand. That will be more common across the country.
“Most of the rest of the country, over the next 10 to 15 years, will probably go through updates with using heat pumps, and that will actually drive more and more heating-related electric peaks versus what’s just happening in certain regions of the country where electric heating is already pretty high,” Brown said.
Heat pumps are efficient, but modeling in the Northeast shows their adoption could greatly increase the peak demands of residential and commercial customers in coming decades.
The adoption of EVs by consumers will add many new DERs to the grid, Fitch said.
“I think we’re sort of at an inflection point here, where a lot of the operational questions are being answered, and lots of the business models are being figured out,” Fitch said. “And … especially with the [Inflation Reduction Act], there’s a whole asset turnover, in terms of internal combustion vehicles to EVs, that will really facilitate a greater role for VPPs.”
Coordinated EV charging so the vehicles on a block are not all charging at once and overloading the local system is part of it, but utilities are realizing that more subtle, minute-by-minute shifts in that demand can help integrate those new loads cost effectively and reliably, Brown said.
“Otherwise, you’re dealing with a problem where you’re just overbuilding infrastructure and passing on that cost to consumers in a way that is not necessarily healthy for where we need to go,” he added.
DERs represent a growing base for VPP, just as the power grid’s need for additional supply as demand grows.
“In the context where interconnecting grid-scale resources is hard, there’s this unique window for VPPs to play this capacity role,” Fitch said.
Some VPPs already are, with Fitch pointing to SunRun’s aggregation of solar-plus-storage systems in California, which provided the grid with an average of 48 MW of dispatchable capacity during a heat wave this July, the company said.
FERC Order 2222, which required RTOs and ISOs to integrate DER aggregations into their markets, also helps integrate DERs into VPPs, Brown said. But some of the rules could be changed to encourage more participation from residential consumers, as the minimum thresholds to participate in some of the markets are too high.
The other big issue facing the industry is access to data, he said.
“It’s not easy for households to be able to get access to and share utility meter data very easily and everywhere, and so that’s an area that we believe there could be continued progress on,” Brown said.
That would help utilities engage with their customers in new ways, such as setting up smart home platforms, apps and other kinds of communications beyond the monthly bill or occasional email, he added.
Texas lawmakers charged with overseeing the state’s $5 billion fund for new gas-fired generation took aim this week at the consulting firm managing the program.
During a public hearing Oct. 8, the Texas Energy Fund (TEF) Advisory Committee roasted Deloitte representatives for missing an apparently fraudulent loan application that accounted for 13.2% and left a nearly 1.3-GW hole in the fund’s portfolio.
Deloitte principal Rod Kleinhammer, a senior partner overseeing the firm’s Texas business, defended his staff’s work. He said they could have been more intensive in performing due diligence of the 72 applicants for TEF funds. Deloitte conducted what amounted to cursory background checks of the applicants and found no negative results, Kleinhammer said, and added it intended a deeper dive after arriving at its shortlist of 17 projects deserving of loans.
“We should have accelerated some of the additional risk and reputational checks we had planned for due diligence to occur prior to the release of the 17 Texas energy fund loan applications being made public,” he told the committee, reading his short, prepared statement. “We’ve modified our processes and are confident the safeguards we have in place will continue to assure that no entities will be approved for funding before a rigorous and thorough review of the applicants and sponsors has been completed.”
That may not be enough.
Lt. Gov. Dan Patrick (R), one of the state’s most powerful political leaders, posted a statement after the hearing calling Deloitte’s failure to catch the sketchy application a “blunder.” He said the Public Utility Commission should follow through on its demand to claw back at least 10% of Deloitte’s contract and for the legislature to review the state’s other contracts with Deloitte, which average about $250 million annually, according to Kleinhammer.
“Our grid needs more dispatchable power as quickly as possible, and the Texas Energy Fund loan program is the most expeditious way to get more dispatchable megawatts online” he said. “Deloitte has only slowed down this important program. They need to correct their errors now or be gone.”
The application in question was proffered by Aegle Power, which said NextEra Energy was a party to the application, which the Florida company has denied. It also turned out that Aegle’s CEO, Kathleen Smith, had pleaded guilty in 2017 to embezzling a “significant” amount of money from a company that was trying to build a power plant in Corpus Christi, Texas. (See Texas PUC Rejects Possible ‘Fraudulent’ Loan Application.)
“The lack of just basic due diligence is astounding to me,” state Sen. Charles Schwertner (R), who co-chairs the advisory committee, told Kleinhammer. He noted Smith’s name was “all over the application” and received affirmation from the Deloitte rep.
Texas Sen. Charles Schwertner | Texas Senate
“And no one bothered to interview or Google her name?” he asked incredulously. “This is the second-largest, 1.2-GW, second-largest project in the Texas Energy Fund. Is it astounding that it wasn’t a baseline like, ‘Who am I dealing with?’”
Schwertner recalled an earlier conversation with Kleinhammer, in which they discussed Deloitte’s mantra of KYC (Know Your Client).
“You were like, all giddy about it, almost,” Schwertner said. “Do you know Aegle Power?”
“I do now,” Kleinhammer responded. “Now that I know what I’m looking for, it is very easy to find out, sir.”
“What do you mean, what you’re looking for?” Schwertner replied, not hiding his frustration. “’If they’re a convicted felon, I should probably not advance them.’ Is that what you’re looking for? Do we need to spell it out for you?”
Smith had agreed to attend the hearing, but Schwertner said she pulled out Oct. 7 because she said she couldn’t leave Florida because of Hurricane Milton’s approach.
Sitting next to her empty chair, Mitchell Ross, general counsel for NextEra Energy Resources, the competitive business for the giant Florida company with about a $160 billion market cap, said the subsidiary never committed to or applied for any project seeking Texas Energy Fund support.
He said discussions were held with Aegle, but that no equity commitment was ever made. Initial conversations began with Aegle’s investment banker in May, but by July, Ross said, NextEra’s deal team had decided to end the negotiations, partly because of Smith’s criminal history. He said a May letter submitted to the PUC and claiming a $252 million equity commitment from NextEra was fraudulent and has been reported to the U.S. Attorney’s Office.
“We do not support the application, and I agree that false statements and fraud have been committed against the state of Texas,” Ross said.
As if that weren’t enough, Coronado Power Ventures notified the PUC that the air permits Aegle said it had secured from the Texas Commission on Environmental Quality and the U.S. EPA actually were issued to its La Paloma Energy Center in South Texas. The project since has been canceled.
Coronado Power CEO John Upchurch said the application was made without his company’s “knowledge or consent.”
In a strange twist, Upchurch was CEO and Smith president at Chase Power from 2008 to 2012, when the embezzlement occurred. Federal authorities charged both with filing false invoices and using their company credit cards for personal travel, country club memberships and other expenses. Like Smith, Upchurch pleaded guilty to the charges.
“Deloitte’s failure to uncover the falsified application presented by Aegle Power, whose CEO was previously convicted of embezzlement, is outrageous, and the [PUC’s] advancement of this unvetted project is extremely troubling,” Patrick said in his statement.
PUC Chair Thomas Gleeson offered his apologies, saying the commission had “too much of an arm’s length relationship with our contractor.”
“I should have ensured we were more heavily involved in the review,” he told lawmakers. “Ultimately, it is my responsibility to make sure that Deloitte is doing what they need to do.”
The commission said it will strengthen the oversight process to address the issues that led to the Aegle Power application’s acceptance and denial. Executive Director Connie Corona said staff will meet with the 16 remaining applicants and conduct site visits to verify their legitimacy.
The PUC and Deloitte are negotiating over the 10% clawback of the latter’s contract, which is valued at $73 million over four years. An addendum could up the spending to $107 million.
Kleinhammer said the two sides are close, but Gleeson offered a different perspective. He said there will be no negotiation over the 10% number, which amounts to $7.3 million.
“That is $7.3 million, which is 10% of their base contract. That number is non-negotiable. It is not moving down,” Gleeson told the committee. “So, from my view, there is no ongoing negotiation. There is a number that needs to be met, and when it is, we will present you with an agreement of that number.”
Gleeson said the commission also has referred the matter to the Texas attorney general’s office, citing the “lies and false statements” in the application.
WASHINGTON — FERC Commissioner David Rosner told members of the American Clean Power Association that one of his main goals as a regulator is to successfully manage the energy industry’s transition.
“If you look back 20 years, the system is just completely different from what it was,” Rosner said. “And if you look 20 years out forward, it’s going to look different. And, so, one of the things I’m focused on is making sure in regions where there are markets … those markets are equipped to deal with that change.”
Another part of reliably managing the transition FERC oversees is deciding where and when infrastructure investments are needed, he added.
Rosner is not coming new to FERC like most commissioners; he’s moving up to the top floor after working as a staffer since 2017.
“Frankly, I have an unfair advantage, because there’s — you’ll be shocked to hear this — but there’s a lot of process at a regulatory agency,” Rosner said. “And that’s a really good thing, because we want a lot of eyes on these orders because they affect real people, real companies, real dollars. And, so, I already know to some extent that process, and that’s been a huge advantage.”
He already has seen the regulator go through changes since joining as a staffer. One of the reasons the commission has seemed more partisan in recent years, he said, is a court decision (NRG Power Marketing LLC v. FERC) that ended its flexibility in dealing with Federal Power Act Section 205 filings. (See PJM MOPR Order Reversed; FERC Overstepped, Court Says.)
While focused on long-running debates about PJM’s capacity market, the decision effectively tied FERC’s hands and limited its response to Section 205 filings to an up or down vote.
“Before you would see six, seven, eight — you know — rounds of conditional compliance,” Rosner said. “We can’t do that anymore. It’s yes or no, up or down. It’s always an emergency.”
Rosner also said he’s committed to getting orders out as soon as they are ready, which this summer involved approving new infrastructure. He also noted the commission is working on issuing a rehearing order for Order 1920, the transmission reforms passed this spring before Rosner took office.
PJM’s recent capacity auction and the price spikes caused by a narrowing supply and demand balance also are at the top of mind for the new commissioner, who said he’s been meeting with state regulators from the region concerned with the shift from “abundance to scarcity.” (See PJM Capacity Prices Spike 10-fold in 2025/2026 Auction.)
“The fundamental cure to this disease is adding capacity,” Rosner said. “And so, you know, last year, I think we saw a report just come out of PJM saying they added 2,000 MW of solar. I think they have somewhere between 20,000 and 30,000 MW of signed ISAs [interconnection service agreements], some of those for batteries. And you know, I think what we’re hoping to see is that we get more than 2,000 MW connected next year.”
FERC Order 2023 set a new baseline for interconnection queues around the country, and the commission recently held a two-day workshop looking into other ways, some of which do not require any rule changes, to speed up that process, Rosner said.
Industry Executives Discuss Maintaining Reliability as Grid Transitions
Rosner gave the keynote at an event that featured executives from around the industry describing how they responded to reliability challenges in their territories.
CAISO had to cut power briefly to some customers in 2020 as demand spiked around the West and it was unable to rely on imports, said Chief Operating Officer Mark Rothleder. The short version of what went wrong: California didn’t keep up with the pace of change, represented by higher peaks due to climate change and new types of resources.
At the time, CAISO had just 250 MW of batteries online. That has ramped up to 10,000 MW, which has helped.
“You’re starting to now see things stabilized,” Rothleder said. “We’re seeing these events happen. We’re forecasting the events in the operational time frame. We’re incorporating the changing conditions in the planning horizon, and we’re again developing and moving and building the resources that we need for the future.”
The bad times for SPP came in February 2021, when Winter Storm Uri led to blackouts, said General Counsel Paul Suskie.
Over its first two decades as an RTO, SPP approved $13 billion in transmission. That could grow by more than 50% after a vote set for the end of October, when its board will consider $7.5 billion more. Some $2 billion of that proposed transmission was planned when looking back to Uri and Winter Storm Elliott and determining what would have helped maintain reliability, Suskie said.
The new transmission lines would help connect the north to the south of SPP to better move power in emergencies. SPP also is considering proposals for eight high-voltage direct current lines to connect the Eastern and Western Interconnections as its RTO footprint expands across that seam, Suskie said.
One key policy goal of American Clean Power is getting the Energy Permitting Reform Act of 2024 to pass Congress this year, after clearing the Energy & Natural Resources Committee by a 15-4 vote.
“We are in a joyful position right now having a full consensus,” said ACP President Jason Grumet. “Not a single member of our organization is opposed to the EPRA proposal.”
ITC President Krista Tanner said the permitting bill is needed to avoid situations like the recently completed Cardinal-Hickory Creek Line, which took 13 years to build because it was under constant litigation. The law does not eliminate litigation under the National Environmental Policy Act, but it seeks to minimize “litigation abuse,” Tanner said.
“It puts time frames on statutes, limitations on how soon you have to file; it requires courts take these cases expeditiously, and then it requires the agencies to act within certain time frames,” Tanner said. “So, all of that helps a lot.”
NYISO expects it will be able to operate reliably, according to the Winter 2024 Operating Study presented to the Systems Operations Advisory Subcommittee on Oct. 9.
The ISO forecasts a 23,800 MW peak demand against 41,321 MW of total available capacity this winter, a 73.6% margin. This season’s load forecast is about 1.73% less than last winter’s expected 24,220 MW and about 7.53% lower than the all-time peak of 25,738 MW, set in January 2014.
Peak load was only 22,754 MW last winter, which was very mild. It was one of only three times during that January when load went above 22,000 MW. (See NYISO Recounts Mild Winter.)
The study notes that 935 MW of new generation have come online since last winter, spread across 13 projects. Most of these are solar farms, but they also include two wind farms over 100 MW in upstate New York and one battery facility outside of Buffalo.
Four gas turbine plants, totaling 60 MW, were modeled as deactivated since winter 2023.
