VALLEY FORGE, Pa. — PJMpresented to the Planning Committee on Oct. 8 an overview of a concept it is developing to allow high-capacity factor resources to be accelerated into the Phase 1 study period of Transmission Cycle 2 (TC2). If approved by the PJM Board of Managers and FERC, a new application window would be opened for generation developers to propose new projects.
The Dec. 17 application window for TC2 would not be changed with the goal of having little to no impact on the milestones for projects that already have been sorted into that cycle. A special session of the PC has been scheduled for Oct. 18 to discuss the proposal in more detail.
“We’ve been having a lot of internal discussions on what we can do and address the potential resource adequacy concern that we have,” PJM Vice President of Planning Paul McGlynn said, adding that the RTO sees the concept as a one-time opportunity to use TC2 to allow more resources to enter the study process to get interconnected more quickly.
Director of Interconnection Planning Donnie Bielak said staff have looked at every technical approach to getting significant quantities of capacity online soon enough, and this was the only one that met the reliability needs projected toward the end of the decade. (See “PJM Models Suggest Capacity Shortfall Possible in 2029/30 Delivery Year,” PJM PC/TEAC Briefs: Aug. 6, 2024.)
Bielak said there would be strict reliability criteria to determine which projects are eligible, with it likely that only a “very, very select few” would qualify. More specific details about eligibility will be presented Oct. 18.
Vitol’s Jason Barker said he’s concerned about the precedent this would set and the possibility PJM may seek similar modifications to the queue structure in the future.
Barker asked if developers who are offered accelerated queue positions will be required to post security to assure timely commercial operation or if an accelerated project fails to meet the promised commercial operation dates, it will be liable for damages to prior queue participants for cost shifts caused by the discriminatory acceleration of the so-called reliability projects.
Even with expediting, he said there are supply chain issues affecting the entire industry that could affect the preferred projects.
MISO wants FERC to reconsider its decision to let a jointly managed flowgate with SPP stand, with the RTO arguing the North Dakota cryptomining facility burdening the line is SPP’s responsibility alone.
FERC in September denied MISO and Montana-Dakota Utilities Co.’s separate complaints over the Charlie Creek flowgate. The two wanted market-to-market (M2M) coordination lifted after the Atlas Power Data Center opened and brought a 200-MW load to SPP’s transmission-constrained northwestern North Dakota load pocket. MISO and MDU maintain the congestion management the data center is instigating shouldn’t extend beyond SPP. (See FERC Refuses MISO, MDU Complaints Regarding Crypto-strained MISO-SPP Flowgate.)
In an Oct. 10 rehearing request, MISO continued to insist SPP is misapplying the two’s interregional coordination process in the joint operating agreement by insisting on interregional help for a provincial issue it is powerless to resolve (EL24-61).
“By summarily rejecting the complaints, and by refusing to properly examine the evidence submitted by MISO and MDU, the Sept. 10 order failed to engage in reasoned decision-making, thereby allowing SPP’s unjust and unreasonable rate practice to continue unabated in violation of the FPA,” MISO said.
MISO said its members have made more than $40 million in undue payments to SPP because of congestion on the flowgate. It pointed out the flowgate consists of two SPP transmission lines owned by the Western Area Power Administration in “a load pocket where the RTO has no regional flows and is unable to relieve congestion due to the lack of available generation.”
MISO said it offered “extensive evidence demonstrating the local nature of congestion” in its original complaint and said SPP’s insistence on using M2M coordination to manage it is counter to good utility practice.
MISO said FERC was wrong to read M2M coordination requirements as strictly those laid out in the joint operating agreement and not consider that the interregional coordination process dictates that M2M coordination should be reserved for issues that are regional, not local.
“It is well-established that tariff and contract provisions should not be interpreted in isolation from each other,” the RTO argued.
CARMEL, Ind. — Clean Grid Alliance is asking MISO to incorporate rules for HVDC into MISO’s energy and ancillary services markets.
“We think working out market participation rules for HVDC is timely and warranted,” Clean Grid Alliance Vice President of Transmission and Markets David Sapper told stakeholders at an Oct. 10 Market Subcommittee meeting.
Sapper said many expect that the companion portfolio to MISO’s second long-range transmission plan will include HVDC lines, necessitating MISO to think about market-dispatchable HVDC.
“The lack of rules is a hindrance to HVDC development, in particular MISO long-range transmission planning,” he said.
The Market Subcommittee adopted the issue through general consent at the meeting.
Sapper said HVDC lines can help quell system volatility, help deliver new resource types and improve efficiency across seams. He said HVDC-enabled resources shared between MISO zones versus from different grid operators could warrant unique rules.
“This could get complicated, but at least the HVDC technologies are well understood,” Sapper said, adding that MISO could create a task team or force to recommend participation plans in markets. He said the work might borrow from MISO’s existing participation plan on asynchronous resources.
Clean Grid Alliance’s ask continues a trend of MISO stakeholders asking the RTO to anticipate the contributions HVDC can make and how they could alter markets.
The Southern Renewable Energy Association approached MISO and stakeholders at the July Resource Adequacy Subcommittee, asking them to consider that HVDC lines can be a source of external capacity. The nonprofit said lines are capable of infusing faraway generation into MISO’s local resource zones and could alter auction clearing. (See Renewable Group Asks MISO Community to Consider HVDC Capacity.)
The subcommittee also ultimately took up the issue.
Although Texas recorded its sixth-hottest summer on record, ERCOT failed to set a new mark for peak demand despite loads similar to last year’s record. The grid operator came close when it registered a preliminary peak of 85.56 GW on Aug. 20, but it was later reduced to 85.12 GW.
Dan Woodfin, vice president of system operations, told the ERCOT board that wholesale energy storage charging was included in the initial figure. ERCOT treats the charging as negative generation from a settlements perspective, he said.
The ISO’s all-time demand mark remains 85.51 GW, set during August 2023. The ERCOT grid recorded 22 days of demand exceeding 80 GW through August, compared to 43 days of 80 GW last year.
Natural gas prices and renewable energy helped keep prices low during the summer. Wind (27.85 GW), solar (20.83GW) and energy storage (3.93 GW) resources all set highs through August, according to Grid Status.
More renewables are on the way. Solar and storage (155 GW each) and wind (34 GW) account for the bulk of capacity in ERCOT’s interconnection queue. The queue contains 25 GW of gas-fired capacity.
2025 AS Methodology OK’d
The board approved several measures previously endorsed by its Reliability & Markets (R&M) Committee and the Technical Advisory Committee (TAC).
A real-time market price correction resulting from an incorrect recall of ERCOT contingency reserve service. Affected counterparties will receive more than $3.5 million in settlements.
A real-time price correction after a resource was identified incorrectly as not being qualified for security-constrained economic dispatch. It will result in more than $323,000 in settlements to counterparties.
The Public Utility Commission must approve all three actions.
ERCOT CEO Pablo Vegas | ERCOT
The directors agreed with R&M and remanded back to TAC a protocol change (NPRR1190) that would recover demonstrable financial loss arising from a manual high dispatch limit override to reduce real power output, should the output be used to meet qualified scheduling entity load obligations.
The board asked TAC to gather more information on the initial market policy framework and reassess the need for the compensation mechanism introduced by NPRR649 in 2017 and whether it’s still needed in today’s market.
TAC’s consumer segment opposes the change in its current form, saying it would reward overscheduling power that cannot be delivered. That will force consumers to subsidize insufficient hedging by other market participants in the face of changing grid conditions.
New CFO; Board Vacancies
The directors ratified Richard Scheel as an officer following his promotion as ERCOT’s new CFO and chief risk officer. Formerly the ISO’s controller, Scheel has more than 20 years of finance experience. He replaces Sean Taylor, who announced his retirement in August.
The board also designated Scheel to join Chad Seely and Leslie Wiley as managers and officers of the two debt-financing mechanisms paying back $2.9 billion in market costs from the disastrous 2021 winter storm.
The meeting may have been the last for independent director Bob Flexon, who says he will step down from the board when his term expires Dec. 1. That will leave the board with three vacancies. A selection committee has yet to name a replacement for former Chair Paul Foster, who left the board this year, and the Office of Public Utility Counsel (OPUC) does not have a CEO to fill its seat.
The grid operator’s board consists of eight independent directors, two members from the Public Utility Commission, and single seats for the OPUC and ISO CEOs. Members are required by law to not have fiduciary duty or assets in the ERCOT market and to be Texas residents.
ERCOT Now on Instagram
ERCOT continues to expand its social media presence by joining Instagram, adding to its existence on X (formerly Twitter), Facebook and LinkedIn.
“Please come and follow us,” CEO Pablo Vegas said. “That’s how you know you’re cool, if you’ve got a lot of followers.”
Board Approves 11 Revisions
The board unanimously approved a consent agenda with seven NPRRs, two changes to the Nodal Operating Guide (NOGRR), an Other Binding Document Request (OBDRR) and a single revision to the Retail Market Guide (RMGRR) that will:
NPRR1188, OBDRR046: Modify the dispatch and pricing of controllable load resources (CLRs) in response to the PUC’s directive to increase the use of “load resources for grid reliability.” The NPRR revises the market-participation model of CLRs that are not aggregate load resources so they are dispatched at a nodal shift factor and settled for their energy consumption at a nodal price.
NPRR1215: Clarify that the day-ahead market’s energy-only offer credit exposure calculation zeroes out negative values, with any zeroed-out values being included in the calculation of the depth percentile difference.
NPRR1221, NOGRR262: Align manual and automatic firm load shed provisions; clarify the proper use and interplay of under-voltage load shed, under-frequency load shed and manual load shed; and address reliability concerns over the extent of transmission operators’ manual load-shed capabilities.
NPRR1227, RMGRR181: Align defined protocol terms and add five definitions (“acquisition transfer,” “decision,” “effective date,” “gaining competitive retailer” and “losing competitive retailer”) that previously were in the Retail Market Guide (Acquisition and Transfer of Customers from one Retail Electric Provider to Another). The NPRR replaces the broadly titled terms “decision” and “effective date” with the specific terms “mass transition decision,” “acquisition transfer decision,” “mass transition effective date” and “acquisition transfer effective date” to provide clarity. The change also expands the “gaining competitive retailer” and “losing competitive retailer” definitions to apply beyond the mass transition and acquisition transfer processes.
NPRR1236: Reflect Real-Time Co-optimization Plus Batteries (RTC+B) Task Force’s modifications to the reliability unit commitment capacity-short calculations and address limits in the current calculations by considering ancillary service sub-types. It changes the calculation process involving regulation down service and addresses changes required to align protocol language with recently approved NPRR1204 (Considerations of State of Charge with Real-Time Co-Optimization Implementation).
NPRR1237: Document the scenarios in which market participants are required to successfully complete retail qualification testing, regardless of whether the market participant previously received a qualification letter from ERCOT from prior retail flight testing.
NPRR1244: Align eligibility provisions for CLRs not providing primary frequency response (PFR) to provide ECRS. It also would include in physical responsive capability’s calculation only the capacity of CLRs when they are qualified to provide regulation service and/or regulation reserve service that requires the CLR to be capable of providing PFR.
NOGRR263: Clarify that a CLR is required only to provide PFR when it is providing an AS that requires that resource to be able to provide PFR.
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.
