Ohio regulators cleared American Electric Power (NASDAQ:AEP) of any wrongdoing in its response to severe storms that left more than 240,000 Ohio customers without power for up to two days in June, but said the company should develop a more aggressive vegetation management program on its transmission lines.
About 606,000 AEP Ohio customers lost service between June 13 and 19, including 283,000 who were cut off because of load sheds ordered by PJM.
PJM ordered load sheds to prevent overloads and cascading outages between June 14 and 16 after a storm identified as a derecho downed transmission and distribution circuits and sent dangerous volumes of power onto remaining lines.
Six lines failed on June 14 and 15, causing AEP to shed loads. | Public Utilities Commission of Ohio
Some customers accused the company of racism for cutting power to poor areas of Columbus while continuing service to richer suburbs. But the staff of the Ohio Public Utilities Commission said there was no evidence that the company acted improperly. (See Vegetation Eyed in AEP Ohio Outages Following Storms.)
AEP Ohio was required to take action within 30 minutes after PJM ordered the first of five load shed directives totaling 396 MW at 1:57 p.m. on June 14, PUCO staff said in its report Tuesday.
“After review of AEP Ohio’s actions during the load shed event, it is clear to staff that the company had very little time to communicate to its customers and to react to PJM’s directives in the selection of the circuits that needed a reduction in load,” it said. “The number of customers, the type of customers (residential, commercial or industrial), and the specific location of the customers are not readily available to the operations team and are not considered. The only criterion for selecting those feeds is the amount of load they are carrying.”
Staff said they believed the heat wave alone would not have caused any outages “and that it was only because of the damage caused by the storm that shedding load was necessary.” They noted that temperatures in the Columbus area reached highs of more than 95 degrees Fahrenheit days after the storm, but it resulted in no load shed orders.
Four transmission lines failed on the morning of June 15, including three that failed during the first event. | Public Utilities Commission of Ohio
But while staff said AEP Ohio had complied with state regulations, it said it was concerned about the utility’s transmission vegetation management program, particularly those outages attributed to “grow-in” vegetation — when vegetation comes into contact with lines but is still part of a growing plant.
“AEP Ohio has asserted that although the lines came into contact with trees and limbs that were still intact, it happened only because the storm itself impacted the vegetation in and around the [right of way] enough that the landscape changed,” the report said. “Staff understands this point and can accept that this may be the case. However, it believes that if the trees were in a position that allowed the storm to alter them to the point that they caused a grow-in outage, then perhaps they had not been trimmed enough.”
Although staff concluded that AEP complied with its commission-approved vegetation control plan, they said it “should re-evaluate its approach on its transmission vegetation management plan and move to a more cyclical trimming schedule, similar to its distribution plan.”
Staff also called for the utility to strengthen its community outreach plan for working with emergency responders and community organizations to supplement its own communications. “In both rural and urban centers, emergency responders and community organizations play a vital role in spreading valuable information and services to the communities that they serve,” staff said. “Efforts should be made to capitalize on this important community asset.”
Transparency Criticism
Merrilee Embs, spokesperson for Ohio Consumers’ Counsel Bruce Weston, criticized the report, saying the commission failed to involve the public and the Consumers’ Counsel, as the group and others had requested.
“That public process we called for has not happened despite the motion for an investigation that we, the Poverty Law Center and Pro Seniors filed at the PUCO in July,” she said. “Energy justice for hundreds of thousands of AEP consumers who lost their electricity should be served with a process that is transparent and inclusive of the public and their representatives. While we appreciate today’s PUCO report, it begs questions including why there would be outages from electric wires damaged by trees considering the money that AEP charges consumers for tree-trimming.”
The outages began after a line of storms moved through Ohio on June 13, damaging multiple electric lines throughout the state. Wind speeds reached as high as 90 mph and at least three tornadoes were reported.
Because the majority of the outages were caused by wind, trees or a combination of both, staff said it focused its investigation on circuit inspections and vegetation control for transmission lines.
After the first load shed directives beginning at about 2 p.m. on June 14, PJM issued a second set of load shed orders totaling 170 MW at about 7:30 p.m.
Staff noted that AEP’s system faced unusual strains as power was restored during the hot weather.
“While on hot days [air conditioners] are running throughout the area, they are not all running at the same time; it is staggered throughout the day, which serves to naturally levelize the overall load. But during the restoration period following a large storm outage, on a hot day, large numbers of customers are getting their power turned back on at the same moment. … So, all of their AC units turn on shortly after the power comes on and they run continuously for longer-than-usual periods because it takes time to reduce the temperature down to the level set on the thermostat.”
All customers affected by the two rounds of load sheds were restored by 9:48 a.m. June 15.
But the failure of four transmission lines that morning — including three that failed the day before — caused PJM to order additional load sheds totaling 479 MW.
The last of the affected customers had service restored by 4:51 a.m. on June 16, PUCO said.
PJM backtracked on posting “indicative” results of the 2024/25 capacity auction Tuesday in the face of stakeholder opposition.
During the Dec. 21 Members Committee meeting Senior Vice President of Market Services Stu Bresler said PJM intended to publish the results on Jan. 3, after filing a tariff change request with FERC to address a “mismatch” in the auction results. That submission was filed with FERC on Dec. 23 (EL23-19, ER23-729).
Bresler said the RTO would file the auction results under the existing rules and PJM’s proposed fix to allow stakeholders to evaluate the impact of the proposal before filing comments on it.
“Following consideration of the substantial stakeholder feedback received, PJM will not post indicative results at this time,” a PJM message to stakeholders said. PJM spokesman Jeff Shields said no decision has been made on whether the results will be posted in the future.
Among those options some stakeholders said they hope the commission may consider is permitting auction participants to change their sell offers based on the changes made to the market structure.
Paul Sotkiewicz, president of E-Cubed Policy Associates, said publishing the results could also create unnecessary polarization between groups because of price changes. He urged PJM to refrain from releasing any results until the issue has been settled with the commission.
Independent Market Monitor Joseph Bowring also pushed against releasing the results during the MC meeting, calling them incorrect and irrelevant.
PJM Seeks to Revise Auction Parameters in FERC Filings
Laying out the mismatch that led to the postponing of the auction closing, Bresler said generation included in the calculation reliability requirement for the DPL South locational deliverability area (LDA), which is centered on the Delmarva Peninsula, did not ultimately enter into the auction. Because of a quirk in the functioning of the reliability requirement in small LDAs, the inclusion of that generation elevated the capacity called for by the requirement. When that generation did not offer into the auction, it led to what PJM considers an unjust and unreasonable artificial inflation of clearing prices in that zone.
In its petition to FERC, PJM proposes revising the LDA’s reliability requirement to exclude the generation that did not offer into the auction. The changes would function as an additional factor in the optimization algorithm and be applied prior to the closing of the auction.
“Absent the ability to include this additional factor in the optimization algorithm, PJM would be forced to utilize a materially inaccurate locational deliverability area reliability requirement that does not reflect the actual capacity needs of the particular LDA in question and would result in an unjust and unreasonable outcome” the filing states.
PJM argued to FERC that none of the market fundamentals, such as the amount of supply or load, in the DPL-S LDA had changed since the previous auction and that the increase in clearing prices does not accurately reflect economic realities.
“To be clear, to the extent the LDA is tight on capacity, prices would be expected to separate and be higher than the rest of the RTO. However, in this case, as a result of this confluence of events … the prices become no longer linked to the actual reliability requirements of the LDA and the reliability needs of the LDA are not properly reflected in the auction results,” the filings say.
Should this set of circumstances affect future auctions before a long-term solution is found, PJM’s proposal is to use the same methodology in the filing whenever an LDA’s reliability requirement increases by more than 1% from the prior year due to the inclusion of resources that did not offer into auction.
Without adjustments, PJM said, the algorithm would result in clearing prices approximately four times higher than if those resources were removed from the calculation of the reliability requirement. The requirement increased by 373 MW, or 12%, over the 2023/24 Base Residual Auction (BRA) parameters, while no other LDA deviated by more than 1%.
The figure is calculated for each LDA by combining its internal generation and capacity emergency transfer objective (CETO), which is the amount of imports necessitated by the region’s expected load and anticipated outages. Bresler said the addition of large facilities or intermittent generation into a small LDA — particularly one with a higher winter load that does not align with solar output — can result in the reliability requirement increasing due to the capacity transfers needed for periods when those units are not available.
Even when resources that increase a region’s reliability requirement do not end up offering into the auction, they continue to result in an elevated requirement for imports and so an artificially high clearing price, PJM argues.
“This results in a fundamental mismatch between the actual load requirements and the resource supply stack, which ultimately yields an artificially inflated clearing price that is unjust and unreasonable. More particularly, based on preliminary auction data, PJM estimates that the clearing price for the DPL-S LDA would be more than four times what it otherwise should be if the locational deliverability area reliability requirement is updated to accurately reflect only those resources that actually participated in the BRA,” the RTO’s filings say.
Oregon’s Department of Energy has opened a second round of grants for community renewable and energy resilience projects focused on the state’s rural and disadvantaged communities.
The department said Tuesday it will once again solicit proposals for $12 million in grants of up to $100,000 for planning projects and $1 million for construction projects.
“The Oregon Department of Energy received dozens of applications for outstanding projects across the state in our grant program’s first round of funding,” Director Janine Benner said in a press release. “We’re thrilled to be able to award grants to more projects that will support clean energy and community energy resilience, bolster local jobs and economic development, and create energy cost savings for Oregonians.”
Established by Oregon lawmakers in 2021 to fund projects outside Portland, the Community Renewable Energy Grant Program has a total budget of $50 million to be spent through 2024.
Under the program, grants for planning projects can cover up to 100% of expenses. Construction grants for renewables can cover up to 50% of eligible costs, while those for resilience projects can cover 100%.
“Awards will be made on a competitive basis, and priority will be given to projects that support energy resilience and that serve qualifying communities, including communities of color, low-income communities, tribes, rural areas and other traditionally underserved groups,” ODOE said in Tuesday’s release.
The department in October announced grants totaling $12 million awarded to 21 recipients under the program, after receiving 68 applications representing about $27 million in projects. Among the grant recipients were tribes, local governments, school districts, colleges and a rural electric cooperative. Awardees included:
the Confederated Tribes of Coos, Lower Umpqua and Siuslaw Indians, which received $1 million to help construct two microgrid systems that pair renewable solar and battery storage to provide energy and resilience benefits to tribal buildings.
Wallowa County, which was granted $100,000 to develop a plan for “resilience hubs” in the cities of Joseph, Wallowa and Enterprise in Eastern Oregon. Each hub will pair renewable generation with battery storage and electric vehicle charging.
Jackson County School District, which received about $978,000 to construct a 107.8-kW solar facility with battery storage at an elementary school designated as a critical facility for emergency operations in the event of a natural disaster or other emergency.
High Desert Biomass Cooperative, which will partner with the U.S. Forest Service to use $627,585 for an energy resilience project to expand the capacity and customer base of the cooperative-owned biomass-powered district heating system.
Southern Oregon University, granted $1 million for a resilience project placing net-metered rooftop solar on two campus buildings with battery storage in one building to supply a critical load circuit.
Applications for the latest round of funding are due by Feb. 15 and will be checked for completeness before being advanced to “competitively scored” review, according to ODOE.
The ERCOT grid, tweaked since the disaster of 2021, twice proved its mettle during 2022, meeting record demand during the summer’s sizzling early months and then again during the pre-Christmas winter storm.
That gave Texans a chance to chortle when another state institution, Southwest Airlines, ran into difficulties over the holiday. It also gave Texas Gov. Greg Abbott an opportunity to pause his daily tweets about the southern border and praise ERCOT for not failing during two “extremely cold nights.”
“No Texan has lost any power because of the ERCOT grid,” Abbott tweeted.
Gov. Greg Abbott tweets during the winter storm. | Greg Abbott via Twitter
While there were localized outages at the distribution level, the grid held firm and set a new winter demand peak of 73.96 GW on Dec. 23 that was a 27.7% increase from the previous mark. Demand officially peaked at 69.8 GW during the February 2021 winter storm, but Texas A&M University’s Texas Center for Climate Studies has said demand would have reached 82 GW had not more than 50 GW of generation been unavailable.
ERCOT experienced many of the same issues that plagued it during the deadly 2021 storm, as chronicled by Stoic Energy principle Doug Lewin. The grid operator’s staff underestimated demand during the storm by 4 to 6 GW. Thermal plants again had problems staying on, with almost half the coal fleet offline Dec. 23 and gas plants again facing “fuel limitations” despite the lack of snow and ice.
At times, as much as 12 GW of generation was offline. ERCOT asked for, and received, the Department of Energy’s permission to ignore air quality and other permit limitations and run the grid’s power plants at their maximum output levels in the event of emergency conditions.
Fortunately for ERCOT, the storm, delivering single-digit temperatures but dry conditions, hit right before a holiday weekend, when demand tends to drop. Clear skies and wind gusts in the 40-mph range generated half of energy production at times.
Attention now turns to the Texas State Legislature, which opens its 88th session on Jan. 10 and where lawmakers are waiting to pass judgment on the Public Utility Commission’s proposed market redesign.
Following months of public work sessions, closed-door discussions and a consultant firm’s analysis of six different options, PUC staff urged the commission to adopt a performance credit mechanism (PCM). In public hearings, legislators joined some ERCOT stakeholders in criticizing the concept for being overly complicated, lacking a reliability standard and doing little to attract new baseload generation to Texas. (See Stakeholders Respond to ERCOT Market’s Proposed Redesign.)
The PCM would require load-serving entities to buy performance-based credits from generation resources in a voluntary forward market. The credits are awarded to resources through a retrospective settlement process based on availability during the 30 hours of highest risk, according to their load-ratio shares during those same periods. (See Proposed ERCOT Market Redesigns ‘Capacity-ish’ to Some.)
While generators largely support the PCM and its emphasis on dispatchability, the renewable sector and consumer groups argue it would harm further development of low-cost wind and solar energy.
ClearView Energy Partners, a D.C.-based independent research firm, said in a report that while the PCM is designed to be “resource agnostic,” it would “seem to financially benefit dispatchable conventional resources.” ClearView did allow that some renewables coupled with energy storage could also earn some performance credits.
New ERCOT CEO Pablo Vegas staked out staff’s support of the PCM during the December meeting of the grid operator’s Board of Directors. He said the concept will be critical to “incentivize and retain dispatchable generation” and to meet increased reliability goals.
“Based on our analysis, the performance credit mechanism option strikes a good middle ground that maintains the best parts of the energy-only market while providing new incentives to improve reliability and put steel in the ground,” Vegas said, noting several generators have told lawmakers that the PCM is one of the better options and will result in expected new generation investment.
The Texas Competitive Power Advocates (TCPA), a trade association representing generators, wholesale marketers and retail providers, has said it is prepared to add more than 4.5 GW of additional thermal generation to ERCOT if the PCM is adopted under the “right framework.”
The need to meet growing demand is obvious. ERCOT set an all-time demand peak of 80.04 GW in July, one of the summer’s more than three dozen demand records. Seven years ago, the grid almost peaked at 70 GW. Given ERCOT’s measure that 1 MW can power about 200 Texas homes during peak demand periods, that would mean about 2.1 million homes have been added to the grid during that time.
Vegas and PUC Chair Peter Lake have taken to using Corpus Christi — the eighth largest city in the state at 317,863 residents, according to the 2020 census — as an example of the state’s exploding growth. They say Texas is adding that many people every year, placing additional pressure on developing dispatchable generation resources.
“One of our clear goals this legislative session is to help members understand the resource adequacy challenges that Texas faces in the future,” Vegas said. “The dispatchable gap that is growing between ever increasing load and dispatchable generation is a real issue and is vital. Addressing this issue with clarity will give investors the certainty that they need to build dispatchable generation of Texas needs.”
“Ultimately, we think legislators and/or regulators could approve a new reliability mechanism next year that benefits gas-fired plants, potentially at the expense of renewable resources,” ClearView said. “This could slow deployment of solar and wind in the largest U.S. renewables market.”
Dispatchable generation such as this gas-fired facility are seen as key by some to ERCOT’s market redesign. | WattBridge
The PUC has scheduled a work session for Jan. 12 to discuss the design proposals and stakeholder feedback. A vote is not expected on the proposals during that meeting, but a plan is expected to be adopted later in the month and then passed on to the legislature. The commission also has open meetings scheduled for Jan. 19 and 26.
ERCOT has already made several changes as a result of laws passed during the 2021 session. Generation and transmission facilities have been required to weatherize, and the grid operator’s staff have been conducting compliance inspections, something that didn’t happen after rolling blackouts during a 2011 freeze.
Generators have been required to keep additional fuel sources on site in case of emergencies, and several ancillary services have been added to the energy-only market. At the same time, ERCOT’s price cap was nearly halved, from $9,000/MWh to $5,000/MWh.
During a summer of tight margins and several conservation calls, ERCOT’s conservative operations posture relied on reserves and reliability unit commitments to keep thousands of megawatts in reserve. The grid operator’s market monitor has said that has added hundreds of millions in costs as electricity costs rose more than 70% year-over-year in June.
In December, ERCOT announced a new voluntary curtailment program for crypto miners and other large flexible loads, effective with the new year. It later expanded the program’s scope, designed to reduce power use scare periods, to include loads qualified to provide ancillary services or emergency response service but that don’t have an active obligation to provide those services. (See ERCOT Opens Curtailment Program to Crypto Load.)
FERC and NERC will conduct yet another inquiry into cold weather grid failures after Duke Energy (NYSE:DUK) and the Tennessee Valley Authority cut power to consumers because of insufficient generation during December’s winter storm.
FERC announced Dec. 28 it would conduct the joint investigation with NERC and its regional entities after millions of customers were left without power following the storm’s snow, frigid temperatures and high winds.
Duke Energy’s outage map for North and South Carolina, shared by spokesperson Jeff Brooks on Twitter at 8:24 a.m. Dec. 24. | Duke Energy
“Although most of these outages were due to weather impacts on electric distribution facilities operated by local utilities, utilities in parts of the Southeast were forced to engage in rolling blackouts and the bulk power system in other regions was significantly stressed,” the agencies said.
FERC Chair Richard Glick said the behavior of the bulk power system during the storm shows that the BPS “is critical to public safety and health.”
NERC CEO Jim Robb noted that December’s storm was the fifth major winter event in the last 11 years.
“In addition to the load shedding in Tennessee and the Carolinas, multiple energy emergencies were declared and new demand records were set across the continent. And this was in the early weeks of a projected ‘mild’ winter,” Robb said. “This storm underscores the increasing frequency of significant extreme weather events … and underscores the need for the electric sector to change its planning scenarios and preparations for extreme events.”
Outside of the Southeast, the winter storm prompted conservation calls and emergency alerts in the Eastern Interconnection, while ERCOT and SPP joined TVA in setting new demand records. In PJM, where load hit 135.3 GW on the evening of Dec. 23, calls for conservation limited the peak to less than 129 GW on Dec. 24.
Some 500,000 customers who lost power during the storm across New York had their service restored as of Dec. 28, the New York Public Service Commission reported. The Buffalo area was pummeled by more than four feet of snow and winds as high as 70 miles per hour; more than three dozen deaths were attributed to the storm. Gov. Kathy Hochul called it the “most devastating storm in Buffalo’s long storied history.”
Southeast Struggles
Twitter users complained about being asked to conserve energy while corporate offices — including those of Duke Energy in Charlotte — remained fully lit. | Michael Konen via Twitter
Duke said in a release that it “was forced to interrupt service” to around half a million customers in North and South Carolina the evening of Friday, Dec. 23, and Christmas Eve morning, because of both increased demand from the below-freezing temperatures and “a shortage of available power in the Southeast.” Separately, a high-wind event Dec. 24 left about 40,000 customers without power.
Duke spokesperson Jeff Brooks told WRAL News in Raleigh that generator failures also played a part, along with challenges “in our ability to secure additional power from outside of our service area” because the extreme cold affected neighboring utilities as well.
While the utility reported it was back to normal operations in both states by Dec. 26, its customers — which Duke had thanked for helping reduce demand through voluntary conservation efforts — were less than pleased. Several Twitter users noted that major buildings in downtown Charlotte — including Duke’s own headquarters — appeared fully lit despite pleas for conservation. Others complained they had gotten no notice before Duke cut their power, even those relying on electricity for medical devices.
North Carolina Governor Roy Cooper tweeted that he was “grateful for those who conserved energy” but also “deeply concerned” about the alleged lack of notice for rolling blackouts. He said he had “asked Duke for a complete report on what went wrong and for changes to be made.” The utility is also scheduled to brief the North Carolina Utilities Commission on the outages at a meeting on Tuesday.
TVA Takes ‘Full Responsibility’ for Outages
Meanwhile, TVA said in a statement on Wednesday that it would “take full responsibility for the impact we had on our customers” and promised a “thorough review” of the holiday outages.
The utility acknowledged that it had ordered local power companies to reduce consumption by 5% on Dec. 23 and again on Dec. 24 by up to 10%. The Dec. 23 curtailment lasted two hours and 15 minutes, while the Christmas Eve cuts lasted more than five hours. TVA said that during the 24-hour period that began on Dec. 23, it “supplied more power than at any other time in its nearly 90-year history,” providing 740 GWh. The utility set its highest winter peak power demand, at 33.4 GW, at 7 p.m. the same day.
Electricity generation by energy source for Tennessee from Dec. 20-28, showing a significant drop in coal generation in the early morning of Dec. 23, along with smaller drops in gas and hydro resources. | EIA
Dec. 23 also marked “the first time in TVA’s 90-year history that we’ve had to direct targeted load curtailments due to extreme power demand.” While TVA did not mention generation outages in its statements, data from the Energy Information Administration showed that output from coal plants in Tennessee dropped significantly during the same period, from 4.5 GW the morning of Dec. 23 to a low of 1.4 GW Christmas afternoon.
As with the Duke outages, considerable criticism ensued in TVA’s service territory over the lack of warning. Nashville Mayor John Cooper said on Twitter that Nashville Electric Service “received only an eight-minute warning from TVA” on Dec. 23 about the coming blackouts. Fifty Nashville residents were without service at one point, according to local media, along with 226,000 in Memphis, where Mayor Jim Strickland said the utility was “not as reliable as they said they were.”
DOE Grants ERCOT’s Emergency Request
Battling some of the same problems that almost brought down its grid during February 2021 — thermal outages and derates, forecasts that underestimated load, gas supply issues — ERCOT went so far as to ask for help from the federal government as temperatures dipped into single digits in Texas’ northern regions.
New ERCOT CEO Pablo Vegas sent a letter to U.S Energy Secretary Jennifer Granholm on Dec. 23 requesting permission to ignore air quality or other permit limitations and run the grid’s power plants at their maximum output levels during Energy Emergency Alerts level 2 (load management procedures in effect) or EEA3 (firm load interruption is imminent or in progress) conditions. Vegas cited “natural gas delivery limitations” in saying the grid operator might not be able to avoid curtailing firm load.
He said about 11 GW of thermal generation were offline or derated, compared to 4 GW of wind and 1.7 GW of solar resources. Vegas said ERCOT “understands the importance of the environmental permit limits.”
“However, in ERCOT’s judgment, the loss of power to homes and local businesses in the areas that may be affected by curtailments presents a far greater risk to public health and safety than the temporary exceedances of those permit limits that would be allowed under the requested order,” Vegas wrote.
The Department of Energy agreed an emergency existed and quickly granted the grid operator’s request that same day (202-22-3).
“The DOE order was a tool to have at our ready should we need it, which we did not,” ERCOT spokesperson Trudi Webster said in an emailed statement. “ERCOT had sufficient generation to meet demand … and had additional tools left to deploy should additional generation been needed.”
Staff used all available import capacity on the DC ties, deployed additional capacity enrolled in emergency response service, suspended charging by energy storage resources, and directed load resources providing responsive reserve service to curtail demand. Online reserves exceeded 11 GW at times.
ERCOT’s average hourly demand peaked at 73.96 GW during the morning of Dec. 23, smashing a six-year-old December record of 57.9 GW.
The grid operator’s final seasonal resource adequacy assessment had projected demand to peak this winter at 67.4 GW, although models upped that to nearly 71 GW as the storm approached. (See ERCOT Says ‘Sufficient’ Capacity to Meet Winter Demand.)
Austin-based Stoic Energy consultant Doug Lewin said poorly insulated homes led to the “crazy high” demand. He pointed out that FERC and NERC identified energy-efficient homes as one of the fixes after the ERCOT grid came within minutes of collapsing during the 2021 February winter storm. “Lots more work to do,” he said.
Demand officially peaked at 69.8 GW during the 2021 storm, but Texas A&M University’s Texas Center for Climate Studies has said demand would have reached 82 GW had not more than 50 GW of generation been unavailable.
At one point on Dec. 23, more than 77,000 Texas customers were without power, according to PowerOutage.us. The cold front’s wind gusts reached 40 miles per hour at times and accounted for most of the localized outages. They also resulted in wind production that provided nearly half of ERCOT’s fuel mix.
Average prices that were still settling below -$1.00/MWh as late as 5 p.m. Dec. 22 went as high as $4,084.62/MWh during the interval ending at 7 a.m. Dec. 23. By 9:15 that night, prices dropped back into the triple-digit range, with a high of nearly $140/MWh on Dec. 24.
SPP Calls EEAs, Sets Demand Mark
SPP set a new mark for winter demand when load peaked at 47.1 GW on Dec. 22, smashing the previous record of 43.7 GW set during the February 2021 storm.
Forecast wind chills for the morning of Dec. 23. | National Weather Service
The persistent cold led to tightening reliability conditions in SPP’s 14-state Midwestern footprint and forced it to declare two EEA1s (all available generation resources in use) on Dec. 23 that lasted for more than four hours.
The grid operator called the first EEA1 at 8:27 a.m. CT and ended it at 10:00 a.m. SPP issued the second EEA1 at 5:20 p.m. as load exceeded staff’s forecast and generation dropped off heading into the evening peak. The RTO called off the alert at 8:20 p.m.
SPP also extended a previously issued conservative operations advisory for its Eastern Interconnection balancing authority footprint from 12 a.m. CT Dec. 25 to noon Dec. 25.
ISO-NE Handles Christmas Eve Capacity Deficiency
An unexpected generator outage and a reduction in imports from other regions led to a somewhat tense Christmas Eve for ISO-NE.
ISO-NE headquarters in Holyoke, Mass. | ISO-NE
The New England grid operator was forced into a series of actions to respond to the Dec. 24 capacity deficiency, going into its Operating Procedure 4 for the first time since Labor Day 2018.
The problems weren’t closely connected to the worst-case scenario that ISO-NE has laid out in recent years, where an extended cold snap challenges energy supply. The weather wasn’t especially cold on the Saturday, and demand was only very slightly above its predicted level at the peak hour.
Instead, it was unplanned outages and reductions at multiple generators, including an unidentified “large generating station” that pushed the grid operator into action. ISO-NE spokesperson Matt Kakley said the grid operator won’t release information on which specific units were knocked out or reduced.
In total for the day, New England unexpectedly lost 2,150 MW of generation and neighboring regions under-delivered energy by about 100 MW compared to the grid operator’s morning plans — and 1,100 MW less than what had cleared in the day-ahead market.
According to ISO-NE’s report on the deficiency, it first declared an abnormal conditions alert at 4 p.m. Dec. 24., with escalating actions coming subsequently until peak load had passed and the conditions eased by 6:30.
While the system was briefly strained, ISO-NE said, “only a small amount of day ahead cleared export transactions were curtailed and no emergency purchases were scheduled.”
Along with the warnings of an imminent energy shortage, the skyrocketing real-time wholesale prices (to over $2,000/MWh) at the peak hour raised eyebrows in New England, with one commenter noting that in the ISO-NE app, the whole region was colored a bright Christmas red.
MISO South Dodges Emergency
MISO managed to avoid an emergency in its South region despite issuing a maximum generation warning during the fierce cold blast Dec. 23.
MISO issued a maximum generation warning around 9 a.m. ET for the South as the storm intensified into a bomb cyclone and lifted the warning before 1 p.m. MISO said its South region was facing higher than forecasted load and significant generation outages.
MISO systemwide load and fuel mix on Dec. 23 | MISO
MISO South remained in conservative operations mode and under a cold weather alert until Dec. 26. The storm also forced MISO Midwest into conservative operations overnight into Dec. 24. MISO’s conservative operations instructions request members defer or cancel generation or transmission maintenance and return facilities to service as soon as possible.
The grid operator issued a cold weather alert for its South region ahead of the frigid weather on Dec. 20. On Dec. 22, central Mississippi and Arkansas recorded low temperatures around 10 degrees Fahrenheit.
Entergy Texas said its crews restored damage from “strong winds and gusts that swept across Southeast Texas” on Dec. 22.
2022 was a busy year for FERC, with a series of rulemaking proposals and technical conferences that covered practically everything over which the commission has jurisdiction.
But it was Congress that passed the most consequential changes to U.S. energy policy last year, in the form of the Inflation Reduction Act. Most of FERC’s work was preliminary, meant to set up final rulemakings this year.
Because of that, the most significant event for the commission in 2022 may end up being the refusal of Sen. Joe Manchin (D-W.Va.), chair of the Senate Energy and Natural Resources Committee, to hold a confirmation hearing for Chair Richard Glick. That will leave the commission evenly split between Republicans and Democrats for at least part of 2023, casting a cloud of uncertainty over the work Glick did in his two years as chair. (See Glick’s FERC Tenure in Peril as Manchin Balks at Renomination Hearing.)
President Biden named Glick chair upon taking office in 2021 and nominated him for a second term in May, but Manchin said in November that he would not consider him. Glick’s tenure on the commission will end at noon Tuesday, when the current Congress adjourns. (See Glick Bids Farewell to FERC.)
As a result, Biden will need to choose between Democratic Commissioners Allison Clements and Willie Phillips to be the new chair. Having joined in December 2020 and December 2021, respectively, Clements and Phillips have spent less time the commission combined than Glick, who joined in November 2017.
The president will also have to nominate Glick’s replacement — a pick that will have to go through Manchin, who will remain a wild card this year even after Democrats gained a Senate seat during the midterm elections.
And Biden will need to decide whether to nominate Commissioner James Danly for a second term or choose another Republican to succeed him. Danly’s term expires June 30. Senate Republicans — as well as Manchin, perhaps — will likely insist that the nominees for Glick’s and Danly’s seats be paired. That could leave the commission split for more than half of the year.
At his final post-open meeting press conference Dec. 15, Glick suggested this would likely be the case, but he expressed optimism that the commission would not deadlock frequently.
“I would also say there’s an opportunity here [when] Commissioner Danly’s position becomes open,” Glick said. “The Senate can confirm my replacement and Commissioner Danly’s replacement at the same time. … I very much hope that the president nominates our replacements and moves forward as quickly as possible.”
Pending Proposals
Manchin was angered by the commission’s plans to consider greenhouse gas emissions in natural gas infrastructure certificates.
The two proposals — to update its 1999 policy statement on natural gas infrastructure certificates (PL18-1) and guidance on how it will evaluate the impacts of projects’ greenhouse gas emissions in its environmental analyses (PL21-3) — were originally not proposals at all. Over the objections of the Republican minority, they were issued as final documents in February, but the commission rescinded and rereleased them as drafts the next month. The Democrats said they were persuaded by stakeholders who expressed confusion and their criticism that the policies would apply retroactively to projects already pending before the commission. (See FERC Backtracks on Gas Policy Updates.)
Those are just two of the proposals that the commission will continue to consider this year. Also pending are proposals to overhaul generator interconnection queue processes (RM22-14) and transmission cost allocation and planning rules (RM21-17).
Given the controversy surrounding each, and the split commission, FERC may approve those elements it can achieve consensus on rather than attempt to pass the proposals wholesale. For example, there seems to be wide support among both commissioners and stakeholders for a provision in the interconnection proposal to replace the serial “first-come, first-served” study procedure with “first-ready, first-served” cluster studies.
Both proposals are being watched closely not just by RTO/ISO stakeholders, but by environmentalists and climate hawks as well. Most of the resources in utilities and grid operators’ clogged queues are renewables, and there is increasing acknowledgement among state policymakers and environmentalists that large-scale transmission buildout is needed to accommodate those resources.
Even Danly — who always keeps FERC Secretary Kimberly Bose busy listing his many concurring and dissenting opinions at open meetings — said it was obvious that the queue processes needed fixing by FERC, rather than RTOs and utilities. He said he supported “a number of meritorious” provisions in the interconnection proposal. Danly’s support was also notable because of his frequent criticism of both federal and state policies that favor renewables over natural gas, which he argues is explicitly stated in U.S. law to be a necessary public good.
It was for that reason he opposed the transmission planning proposal, arguing that “it is designed to encourage buildout of transmission specifically for the purpose of encouraging the development of certain types of resources.”
Commissioner Mark Christie (R) may end up being the swing vote in many dockets, and key to what provisions make it into any final rules passed out of the interconnection and transmission proposals. Highly independent, Christie last year joined Danly in dissenting on high-profile cases perhaps as many times as he joined Democrats in support — though sometimes tepidly in the latter. The former chair of the Virginia State Corporation Commission, Christie often speaks up for states’ right to choose their resource mix and supports policies that protect that right.
President Biden entered the White House in 2021 with audacious goals for the U.S. transition to clean energy: first, to decarbonize the nation’s electric power system by 2035 and to cut greenhouse gas emissions to net zero economywide by 2050.
Biden remained firmly committed to these targets in 2022, even in the face of record-breaking inflation and calls for increased fossil fuel production and exports in response to Russia’s invasion of Ukraine. His moratorium on tariffs on solar cells and panels from Cambodia, Malaysia, Thailand and Vietnam was a clear boost to the solar industry.
He also used his executive powers to push the federal government to lead by example, for example, with this year’s agreement with Entergy that could provide 24/7 clean power for federal buildings in Arkansas and the release in December of federal building energy performance standards.
The impact of legislation passed by the outgoing Democrat-controlled Congress will be seen over the course of 2023, as the Biden administration ramps up implementation of the Infrastructure Investment and Jobs Act and Inflation Reduction Act. But the two people who have had the broadest and deepest impacts on federal energy policy in 2022 were undoubtedly Energy Secretary Jennifer Granholm and Sen. Joe Manchin (D-W.Va.).
Granholm and DOE
Government and business leaders from around the world flying into Pittsburgh International Airport for September’s Global Clean Energy Action Forum were greeted with a public service announcement by Granholm talking about the airport’s natural gas and solar microgrid, and the need for strong, urgent climate action.
The peripatetic former governor of Michigan has turned the Department of Energy into the vanguard of the U.S. clean energy transition, with a mission to “deploy, deploy, deploy” new and innovative zero-carbon technologies. Granholm is as ebullient about green hydrogen and carbon capture as she is about solar, storage and electric vehicles, and she has staffed up her department with an expanding team of corporate and academic energy leaders.
A few of 2022’s appointees included University of Illinois professor Kathryn Huff to head the Office of Nuclear Energy, former NRG CEO David Crane to direct the new Office of Clean Energy Demonstrations, and utility executive Gene Rodrigues to lead the Office of Electricity.
The passage of the IIJA and IRA allowed Granholm to reorganize DOE in 2022 from its longtime profile as a basic research organization to a catalyst for taking emerging technologies from the lab to commercialization. As part of that reorientation, two new offices were announced in August: the Office of Grid Deployment, and the Office of State and Community Energy Programs.
Granholm’s moves were frequent, if not a bit frenetic. Any of her many appearances at energy conferences or White House- or DOE-sponsored events have, almost invariably, included one or more new program and funding announcements. In Pittsburgh, they all targeted industrial decarbonization; for example, the opening of applications for the IIJA’s $7 billion funding opportunity for regional hydrogen hubs, and the rollout of a National Clean Hydrogen Roadmap. She also launched a new Industrial Heat Shot initiative, aimed at cutting carbon emissions from the heat processes used in heavy industry — like steel and chemical manufacturing — 85% by 2035. (See Decarbonizing Heavy Industry: Audacious, Ambitious, Achievable.)
Another $4.9 billion, also from the IIJA, was announced during the conference, this time to accelerate the commercialization of carbon capture.
Her final announcement of 2022, on Dec. 28, was a proposal for new energy efficiency standards for three categories of distribution transformers. DOE estimates the proposed standards would cut U.S. carbon emissions by 340 million metric tons over a 30-year period, while saving $15 billion.
The new year will present ongoing challenges for Granholm. She and other administration officials must ensure smooth and timely delivery of the $369 billion in clean energy funding in the IRA under close scrutiny from the Republican-controlled House of Representatives and its Energy and Commerce Committee. Expect to see her at a lot more events with a lot more announcements but also at a lot more oversight hearings on Capitol Hill, being grilled by GOP lawmakers.
One particular focus will be on DOE’s development of a nuclear fuel reserve, originally mandated in the Energy Act of 2020, to ensure an adequate supply of the high-assay, low-enriched uranium (HALEU) needed for the advanced nuclear reactor demonstration projects DOE is funding. Already one of the projects, TerraPower’s Natrium reactor to be located in Wyoming, could be delayed by two years because of a lack of a HALEU supply chain in the U.S.; the fuel can no longer be procured from Russia.
Manchin
Sen. Manchin also had an outsized impact on the U.S. energy transition in 2022. As chair of the Senate Energy and Natural Resources Committee and a must-have vote in the evenly divided Senate, he was a formidable gatekeeper on policy and appointments, at times frustrating and confounding his Democratic colleagues and the White House, and at times returning to the bargaining table for a last-minute compromise.
But Manchin’s ties and ongoing support for the coal industry — the source of his and his family’s wealth and political influence in West Virginia — have meant that finding those critical points of compromise usually comes with a price and tradeoffs.
Manchin killed earlier versions of what became the Inflation Reduction Act, walking away from its original incarnation as the Build Back Better Act in December 2021 and then again, closing down negotiations on a significantly downsized, renamed IRA in July, only to resurface two weeks later with a new, and still slimmer compromise.
Sen. Joe Manchin (D-W.Va.) | Senate ENR Committee
The tradeoffs made to win Manchin’s support can be seen in various provisions of the law; for example, its price- and income-linked rebates for electric vehicles and its generous tax credits for carbon capture.
EVs with a manufacturer’s suggested retail price of more than $80,000 for a van, SUV or pickup truck, or of $55,000 for other cars, are not eligible for rebates. Consumers earning more than $150,000 — or $225,000 for a single head of household or $300,000 for couples — are also not eligible.
On carbon capture, the IRA upped the basic tax credit for carbon capture and sequestration from $50/ton to $85 and from $50 to $180 for direct air capture and sequestration.
However, Manchin’s biggest power play of 2022 may have been his refusal to schedule a hearing to reconfirm former Chair Richard Glick for a second term, most likely due to Glick’s efforts to include the impact of potential greenhouse gas emissions as part of the commission’s pipeline permitting process. (See FERC’s Work in 2022 Left in Doubt by Manchin.)
The midterm election results, with the Democrats claiming a 51-seat majority in the Senate, looked to make Manchin a less decisive swing vote. But with Sen. Kyrsten Sinema (I-Ariz.) leaving the Democratic party to become an independent, both she and Manchin will continue to be critical votes for any efforts to pass major energy legislation, such as permitting reform.
Manchin’s efforts to push through a year-end permitting reform bill — which included approval of the controversial Mountain Valley natural gas pipeline — met with opposition from both Democrats and Republicans, exposing his vulnerability to critics on both sides of the aisle. A new, perhaps more carefully crafted reform effort can be expected in 2023.
A battle is also brewing over the guidelines from the Treasury Department and Internal Revenue Service on the implementation of the IRA tax credits for electric vehicles. While the incentives were supposed to go into effect Jan. 1, Manchin has already called for a hold on the tax credits because of the department’s failure to provide clear guidelines on requirements for domestic content in batteries and other vehicle components.
The close of 2022 finds PJM in a state of flux, with recent FERC orders and pending dockets carrying significant changes to the RTO’s expanding interconnection queue and the structure of its capacity markets, as well as ongoing stakeholder discussions on how to account for the capacity from intermittent resources. Many of those discussions that have culminated in solutions will begin their implementation in the new year, while others still in deliberations aim to wrap up in the first few months of 2023.
Here’s a review of some of the major stories of 2022 and ongoing discussions continuing into 2023.
Finalization of Capacity Auction Pushed into 2023
The first order of business in 2023 will be a review of the “indicative” 2024/25 capacity auction results on Tuesday, following a concern that the DPL South locational deliverability area (LDA), which is centered around the Delmarva Peninsula, could experience artificially inflated prices. (See Capacity Auction ‘Mismatch’ Roils PJM Stakeholders.)
During the Dec. 21 Members Committee meeting, Senior Vice President of Market Services Stu Bresler said the design of the reliability requirement for each LDA can create a situation where large facilities or intermittent generators cause the requirement to increase as more resources are brought online because of the need to account for when those resources are offline. When those resources are included in the resource modeling and lead to an elevated reliability requirement, but do not ultimately enter into the auction, it can create the appearance of a shortage that doesn’t exist.
PJM submitted concurrent Federal Power Act Section 205 and 206 filings with FERC on Dec. 23 seeking that the auction results in DPL South be found unjust and unreasonable and to allow the RTO to adjust the reliability requirement for the LDA “based on the actual supply of resources that submitted offers into the auction” (ER23-729, EL23-19).
The Section 206 filing argues that this would effectively function as an additional factor in the evaluation of offers into the market before the results are finalized.
“Absent the ability to include this additional factor in the optimization algorithm, PJM would be forced to utilize a materially inaccurate locational deliverability area reliability requirement that does not reflect the actual capacity needs of the particular LDA in question and would result in an unjust and unreasonable outcome,” the RTO said.
Several stakeholders raised concerns that the move would establish a precedent of market changes being implemented in the middle of auctions. Those reservations extended to PJM’s determination to publish the DPL South results Tuesday, which could hamstring the commission’s ability to allow market participants to alter their offers to reflect any rule changes.
Bresler said it is not a step being taken lightly, but the scale of the impact to DPL South warrants immediate measures while concrete long-term solutions are sought. In the filings before FERC, PJM said the clearing price for the LDA would be more than four times higher if the proposed changes are not made.
“More particularly, based on preliminary auction data, PJM estimates that as a result of this confluence of events in this small LDA, should PJM complete the auction and award capacity commitments, the clearing price for the DPL-S LDA (and the revenues received by capacity market sellers in this small LDA) would be more than four times what the clearing price should be if the planned generation capacity resources that did not offer in the auction are excluded from the locational deliverability area reliability requirement given that they did not offer into the BRA,” PJM told FERC.
The opening of the auction had already been delayed from August to November as part of a FERC-approved adjustment to the capacity auction timeline through the end of 2023 to allow PJM additional time to implement a revised forward-looking energy and ancillary services (E&AS) offset. The commission reversed its approval of the RTO’s forward-looking E&AS offset in December 2021 and granted the delayed timeline on Feb. 23, pushing the January 2022 auction to June. (See FERC Approves PJM Capacity Auction Date Changes.)
The 2023 auctions were postponed from February to June and from August to November. The schedule is set to return to normal with the 2027/28 BRA, in May 2024.
Capacity Prices Fall for 2023/24
The 2023/24 capacity auction, held in June, saw prices fall by nearly one-half relative to the previous auction, with 144,871 MW of capacity sold for $2.2 billion for the delivery year starting in June 2023. The 2022/23 delivery year saw a total capacity bill of around $4 billion. (See PJM Capacity Prices Crater.)
Several market changes likely impacted prices, including a decreased unit-specific market seller offer cap (MSOC), the use of a historical E&AS revenue offset, the introduction of the effective load-carrying capability (ELCC) methodology for measuring intermittent resource capacity and the near elimination of the minimum offer price rule.
The often contentious issue has been discussed in more than 25 meetings since a problem statement was adopted in early 2021, a referral to the FERC Enforcement hotline and a complaint to the commission filed by economist Roy Shanker on Nov. 30. At issue is whether PJM has been in violation of its tariff by improperly permitting energy above renewable resources’ capacity interconnection rights (CIRs) to be entered into the Reliability Pricing Model (RPM) auctions as capacity.
In his complaint, Shanker alleged that the practice results in diminished reliability; load overpaying for “phantom capacity” that does not meet reliability standards; artificial reduction of capacity prices for other resources; and inefficient economic decisions from market participants acting on potentially inaccurate information. Because the resources already have established interconnection service agreements (ISAs) and defined CIRs, the complaint states that an immediate solution can be implemented by capping capacity offers at the rates determined in those agreements with each resource (EL23-13).
The commission approved a PJM request for an extension from Dec. 20 to Jan. 10 to provide more time for its response to the complaint.
At the start of the year, the PJM Power Providers (P3) sent a letter to the PJM Board of Managers arguing that by allowing resources to acquire capacity obligations greater than their demonstrated deliverability, the RTO has “materially destabilized the market” and is not upholding its tariff. The board responded with a letter to stakeholders saying that it believes the accreditation of intermittent resources has been appropriate and compliant with the tariff.
The stakeholder discussions on a long-term solution has resulted in 11 packages of changes being offered as potential solutions, of which six remain under consideration by the Planning Committee. Though they agree on the ultimate methodology for accrediting intermittent resources, the packages vary widely on where to cap capacity offers for resources that already hold an ISA. The transitionary measures range from granting ELCC resources higher CIRs and having load pay for the transmission upgrades to capping their current CIR rating and requiring the resource to re-enter the interconnection queue to request a higher accreditation.
The PC is set to consider endorsement of a package on Jan. 10, while the Markets and Reliability Committee and MC are set to vote on Jan. 25. The proposals would also require approval from the board, which is set to take up the issue on Feb. 1. The solutions all look to be implemented for the 2025/26 BRA, but they differ in whether that is a target or mandatory.
Interconnection Queue Overhaul Approved
Following years of a growing backlog in its interconnection queue, FERC on Nov. 29 approved a proposal from PJM to overhaul how the RTO studies network upgrades for new projects. According to PJM, the number of new service requests it received tripled from 2019 through 2022 to more than 2,700 projects pending in the queue as of May 10 (ER22-2110).
The new system aims to reduce completion times by clustering projects together both for studying the upgrades required and allocating costs, as well as by discouraging speculative project submissions by requiring evidence of site control and progressively scaling readiness deposits throughout the process. (See FERC Approves PJM Plan to Speed Interconnection Queue.)
Once again the transitionary provisions were the source of much of the debate around the changes. Under the new system, projects submitted between April 2018 and September 2021 with a price tag above $5 million will be studied under two sequential transitionary cycles, while less expensive projects will be placed in an expedited “fast-track” queue.
Concerns raised by protesters questioned whether the measures would be enough to weed out proposals seeking to offload the work of testing a project’s viability onto PJM staff and whether site control requirements could allow viable projects to be forced out of the queue.
During the Organization of PJM States Inc.’s (OPSI) annual meeting on Oct. 18, PJM Vice President of Planning Kenneth Seiler said many of the smaller projects already in the interconnection queue could have their studies complete within six months and that the fast-track could be completed within two years after its approval.
Division over Design of Capacity Market
As FERC continues to weigh whether to approve PJM’s proposed changes to the RPM, generation owners are seizing upon comments made by PJM CEO Manu Asthana — in which he expressed concern about the pace of new generator installations — to argue that the capacity market should be structured to procure additional capacity. (See PJM MRC Briefs: Oct. 24, 2022.)
At the RTO’s annual meeting on Oct. 24, Asthana said about 40 MW of generation is expected to retire by 2030 as construction of new resources lags behind expectations and load continues to grow.
“We have time, but we don’t have time to waste,” he said. “We need to take action to ensure we retain an adequate supply of dispatchable generation through the [clean energy] transition.”
Protests against PJM’s proposed variable resource requirement (VRR) demand curve have pointed to Asthana’s statement as evidence that the RPM should be designed to incentivize the retention and development of all types of capacity (ER22-2984).
The Quadrennial Review filing proposed changing the reference resource to a combined cycle generator, revising the calculation of the gross cost of new entry (CONE) and changing how it is adjusted in years between reviews, steepening the VRR curve and shifting from a historical E&AS offset calculation to a forward-looking offset.
“To P3, this sounds like PJM is indeed on the cusp of a reliability crisis and the impact of the instant filing will coincide directly with the predicted reliability challenges in PJM,” the group said.
In response to previous P3 protests, several environmental and public advocacy groups — jointly filing as the Public Interest Entities — said the claims are unfounded and noted that PJM remains well above its “conservative” reliability standards.
“Rather than a market ‘on life support,’ PJM’s capacity market remains robust, procuring — indeed over-procuring — the resources necessary to maintain reliability,” they said.
MISO made several maneuvers in 2022 to position itself for a majority-renewable portfolio while attempting to take the sting out of an escalating capacity deficit in its entire Midwest territory.
After years of warnings from MISO leadership, the portfolio transition is in full swing in the footprint.
And MISO’s 2023 docket includes planning the next round of long-range transmission projects, navigating expected capacity shortfalls, attempting a sloped demand curve in a newly revamped seasonal capacity auction and managing an unprecedented number of new renewable resources queuing up for interconnection.
“There are going to be more things happening in the next five years than in the past 20 years,” CEO John Bear began a Nov. 28 executive update.
Bear thanked stakeholders for their assistance on MISO efforts. He said he understood the magnitude of work “takes a toll” on them, but that they and the RTO accomplished a lot over 2022 “in really trying times.”
“The urgency of course is always high,” Bear said, noting that decarbonization goals are always intensifying.
MISO’s most attention-grabbing headline of 2022 was the Midwest region’s 1.2-GW capacity shortage exposed in the RTO’s 2022/23 Planning Resource Auction. The shortfall triggered a $236.66/MW-day cost of new entry (CONE) clearing price for the Midwestern subregion. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.) MISO had said the capacity deficit might force it to order temporary, controlled load sheds, and it predicted insufficient firm resources to handle summer peak forecasts under typical demand.
“We have a resource adequacy problem. We have challenges to delivering energy when we need it,” Bear said simply during the Board of Directors’ meeting Dec. 8.
With a week left in 2022, MISO managed to avoid an emergency in its South region during a fierce cold blast Dec. 23. The late December winter storm also forced MISO Midwest into conservative operations overnight into Dec. 24.
At the time, MISO said its South region was facing higher-than-forecasted load and significant generation outages. MISO South remained in conservative operations mode and under a cold weather alert until Dec. 26.
Queue Bursting at the Seams
As it rounded out September, MISO received a record-setting 171 GW of proposed renewable generation and storage projects across 956 interconnection requests. Those requests could bring the total interconnection queue to the brink of 300 GW, triple that of just two years ago. Five years ago, a nearly 300-GW queue was unthinkable. In 2017, MISO planners said processing the then-60-GW queue was a tall ask.
MISO has said it’s up to the task and — what’s more — said it will stick to its pared-down 375-day study schedule for the queue’s definitive planning phase (DPP). The RTO got FERC permission in February to swap the new timeline for its previous 500-day DPP.
However, MISO has pushed back the DPP start of its record-setting 2022 cycle of entrants until Feb. 27 because of the multitude of requests.
At an October planning meeting, MISO’s Andy Witmeier said the RTO plans to study the current queue in a “timely manner” using the new deadlines.
“We do obviously have a backlog that needs to be worked through as well,” Witmeier said, predicting MISO will play catchup on the queue’s existing delays through 2023.
The queue is further evidence the footprint is marching toward more weather-dependent resources and fewer resources able to be called upon at a moment’s notice. MISO has said that while it expects an increase in installed capacity, accredited capacity values will plunge. Consulting firm McKinsey & Co. has said the MISO footprint could see a nearly 50% increase in overall capacity by 2030.
In September, Chief Digital Officer Todd Ramey said MISO will notice the loss of ramp-up capability the most acutely.
“We’re moving away from the worst hour of the year to the worst day of a season,” Ramey said of MISO peak demand planning in the years ahead. “In the future, it might be the worst week or the worst two weeks of a season.”
But during an October executive update, Ramey said MISO is “excited and honored to be working on so many reliability initiatives.”
As of late 2022, MISO had about 30 GW worth of registered wind capacity and 3.6 GW in registered solar capacity.
The grid operator also officially opened its wholesale markets to energy storage beginning in September. It’s the first time in years MISO has added a new resource type to its energy market portfolio. (See MISO Officially Opens Markets to Storage Resources.)
Seasonal is in
MISO is gearing up to simultaneously conduct four seasonal capacity auctions this spring, with accreditation values that vary by season. In late August, the grid operator got FERC’s approval to simultaneously clear four separate auctions once per year and use an availability-based resource accreditation that relies on the riskiest hours in a season. (See FERC OKs MISO Seasonal Auction, Accreditation.)
The new design is a reaction to MISO’s proliferating emergency declarations and a desire for more accuracy on when capacity is available.
However, MISO has yet to land on a separate, availability-based accreditation for its renewable generation. It plans to spend 2023 refining capacity values with stakeholders.
Without a new renewable capacity accreditation in place, MISO will use an 18.1% effective load carrying capability accreditation for wind generation in summer, a 23.1% accreditation in fall, 40.3% in winter and 23% in spring.
In a June presentation to the board, MISO said that it’s “on the front edge of insufficient supply, and coordinated action is needed to ensure sufficient resources with accredited attributes are available throughout the fleet transition.”
“The MISO region is experiencing continued resource transition acceleration and tight system conditions, which are expected to endanger reliability and market efficiency. Ongoing resource transition trends will likely lead to scarcity of certain essential resource attributes that require evaluation and collaboration with stakeholders,” MISO Director of Policy Studies Jordan Bakke said in August.
Since then, MISO has been trying to pin down what and exactly how much of certain system attributes it needs from its generating units.
The Attribute Debate
Against the resource turnover and capacity shortfalls, some environmental proponents have alleged that MISO employees are inappropriately appearing in front of state commissions to urge the construction of new natural gas-fired generation. (See “Unease over MISO Support for Gas Plant,” MISO Executives Spotlight Fleet Evolution Planning, Risks.)
At a Nov. 28 executive update, Sustainable FERC Project attorney Lauren Azar said MISO’s role is to be fuel-agnostic.
“MISO is of course using euphemisms for natural gas,” Azar said. “I’m just questioning how much you guys are looking into creative solutions.”
CEO Bear countered that MISO has been “very consistent” that it is in desperate need of “controllable, long-duration resources” quickly to cover the capacity shortfalls the grid operator foresees through 2027.
Planned retirements and additions by resource type, according to MISO members’ publicly announced plans | MISO
“Those comments always seem to get taken out of context,” Bear said, adding that MISO is angling for dependable resource attributes, not a certain fuel type.
MISO has defined six system reliability attributes as necessary, including availability, the ability to deliver long-duration energy at a high output, rapid start-up times, providing voltage stability, ramp-up capability and fuel assurance. (See MISO Considers Resource Attributes as Thermal Output Falls.)
MISO Independent Market Monitor David Patton said the RTO’s quantifying requirements for resource attributes isn’t helpful. He said MISO would be better served by a combination of a sloped demand curve in the capacity auction, a marginal capacity accreditation for non-thermal resources and improved shortage pricing so the quickest and most available resources are rewarded for their performance.
“There’s no answer to the question, ‘how many peakers do we need?’ or ‘how many long-duration resources do we need?’” Patton said during a Dec. 6 meeting of the board’s Markets Committee. “You’re positing a question that has no answer. There’s an infinite combination of attributes that would achieve the same reliability objective.”
But some stakeholders have said a discussion of resource attributes is overdue as portions of the Midwest fast approach levels of intermittent resources that will complicate grid operations.
LRTP Becomes Reality
Whether MISO’s grid will be able to support the influx of intermittent resources is an open question. The grid operator in July approved slightly more than $10 billion in long-range transmission planning (LRTP) and is embarking on a second portfolio to accommodate further resource turnover. (See MISO Board Approves $10B in Long-range Tx Projects.)
MISO said its second of four LRTP portfolios could run as much as $30 billion; stakeholders have voiced apprehension with the estimated price tag. (See ‘Conceptual’ Tx Planning Map Troubles MISO Members.)
The new transmission won’t arrive in time for MISO to avert a pair of system support resource (SSR) agreements to maintain system reliability.
During a Dec. 6 meeting of the board’s System Planning Committee, Witmeier said MISO believes that SSRs are the best route to “protecting the system” as thermal output falls and intermittent generation rises.
Stakeholders have asked how MISO can simultaneously juggle an unprecedented queue volume, long-range transmission planning, a shifting resource mix, the upcoming move to a seasonal-based capacity auction and testing use of a sloped demand curve in said auction.
“A shortage of work to be done has never been a challenge,” Ramey said in September. He said MISO plans to add manpower and devote more resources to projects where needed.
California lawmakers are planning a new effort in 2023 to allow CAISO to become a multi-state RTO under conditions that have changed greatly since the last attempt failed five years ago, while the ISO is hoping to win approval for a day-ahead extension of its real-time Western Energy Imbalance Market, increasing its role in the West.
The potentially big changes come as California is contending with regionalization efforts by SPP, which plans to launch a Western version of its Eastern RTO, and the Western Power Pool, which is seeking FERC approval for its Western Resource Adequacy Program, a possible launchpad for an RTO.
Developments in the past five years are fueling the efforts, including strained grid conditions in Western heat waves, the need for new transmission to carry renewable power, legal mandates for Colorado and Nevada transmission owners to join RTOs by 2030, and more states adopting clean energy and emissions reduction targets.
Collaborating to meet those needs in organized markets would be far less expensive than going it alone, a number of studies have shown.
“There’s a strengthened recognition of the need to work together in the West and the benefits of working together,” CAISO CEO Elliot Mainzer said in an interview with RTO Insider.
Last year’s California Assembly Concurrent Resolution 188, authored by Assemblyman Chris Holden, chair of the Assembly Appropriations Committee, asked CAISO to report on studies of the benefits of regional markets by the end of February. The measure passed the state Senate and Assembly by unanimous bipartisan votes.
“This is an important precursor to what’s likely to be a legislative push in California’s legislature next year for broader governance reform,” Mainzer said in a Dec 13 meeting of the WEIM Governing Body. “We look forward to following up with Chair Holden in the early new year to start thinking about the timing and the coordination and the choreography of that important initiative.”
Holden, the former chair of the Assembly Committee on Energy and Utilities, authored bills in 2017 and 2018 to pave the way for CAISO to become a multi-state RTO, but those bills failed. He asked CAISO for the ACR 188 report to show lawmakers the value of regional cooperation.
Since 2018 “states across the West and utilities have adopted their own policies to achieve a clean resource mix and reduce greenhouse gas emissions, which are generally consistent with the policy direction of California,” Holden said in a statement on the bill. “Two states [Nevada and Colorado] have mandated participation in a West-wide market.
“As tens of thousands of megawatts of renewable resources are slated for development in the West, and thousands of megawatts of coal-fired resources are retired and continue to be shut down, momentum is building for greater regional coordination to ensure that electricity is available at all hours of the day,” Holden said. “Consequently, I think it’s time for California to revisit a broader regional market.”
Restarting the Conversation
In the interview with RTO Insider, Mainzer said, “We don’t have any specific details and certainly haven’t seen any legislative language … but we certainly think that Chair Holden, having led the earlier efforts on this a number of years ago, believes that the time is right for another examination of this issue. So, I think the 188 [report] was his effort to start getting folks engaged and get good information and good facts … and to start reinitiating that conversation.”
CAISO commissioned the National Renewable Energy Laboratory to produce the study in partnership with the ISO and California’s eight other balancing authorities, including the Los Angeles Department of Water and Power, the Balancing Authority of Northern California and PacifiCorp. CAISO had planned to release a first draft of the report before the end of 2022 but postponed it until mid-January to give the drafting team more time.
A stakeholder process in the fall identified 41 relevant studies on legal, technical and market issues. They included a study by CAISO in 2016 that it conducted pursuant to Senate Bill 350, a measure that declared the legislature’s intent to “provide for the transformation of [CAISO] into a regional organization to promote the development of regional electricity transmission markets in the Western states.”
The five members of CAISO’s Board of Governors are all Californians appointed by the governor and confirmed by the state Senate. Changing that to allow governors from other states would require legislative action, SB 350 noted. The bill told CAISO to study the potential impacts of becoming a multistate, regional organization before any governance changes could occur.
The SB 350 study found that “a larger ISO-operated regional market [could] create significant value to California ratepayers, decrease overall [greenhouse gas] emissions inside and outside of California, reduce environmental impact in California and elsewhere, increase jobs and economic activities in California and improve the conditions of California’s disadvantaged communities.”
The benefits to the state and the West “increase significantly with the expansion of the market footprint, reducing emissions and the costs associated with the integration of larger amounts of renewable generation resources,” it said.
Holden characterized the ACR 188 report as an update of the SB 350 study.
Another study published last year found an RTO covering the entire U.S. portion of the Western Interconnection could save the region $2 billion in annual electricity costs by 2030 and cut carbon dioxide emissions by 191 million metric tons. A group of Western states led the study, which was financed by the U.S. Department of Energy. (See Study Shows RTO Could Save West $2B Yearly by 2030.)
Other studies identified for the ACR 188 report looked at the potential effects of regionalization on resource adequacy and transmission development.
Kellie Smith, a special consultant to Holden hired to work exclusively on Western regionalization in 2023, said the “critical question and the primary focus of ACR 188 is, ‘Is it good for California?’ Mr. Holden thinks the results are going to say, yes, it’s needed.”
“Since 2018, the perspectives and momentum are building,” Smith said in an interview. “I think it’s pretty obvious that the ISO has the best system around. It’s been working on integration and renewables and [greenhouse gas] tracking for years. The others just don’t have that. So, it makes a lot of sense for the ISO to be the lead” in Western market formation.
A bill to accomplish that, she said, would probably be similar to Assembly Bill 813, which Holden introduced in 2017 and advocated for until it languished in the Senate Rules Committee at the end of the 2017/18 legislative session. The measure passed by a vote of 74-0 in the Assembly and cleared three Senate committees. It never reached a Senate floor vote because some key lawmakers worried it could relinquish control of CAISO to out-of-state interests and jeopardize the state’s climate agenda. (See CAISO Expansion Bill Dies in Committee.)
AB 813 would have instructed CAISO to continue to develop a proposal, originally drafted in 2016, to establish a two-step process for selecting regional board members including a “stakeholder-based nominating committee that selects nominees with the assistance and support of a professional search firm and an approval committee, consisting of the voting members of [a] Western states committee, which would confirm each slate of nominees.”
The Western states committee would have included representatives from each state with transmission owners in CAISO.
The process for selecting members of the CAISO Board of Governors would have then been similar to the process for selecting members of the WEIM’s Governing Body, which includes members from California and other Western states.
The WEIM, which spans much of the Western Interconnection, has been popular with other states, in part, because of its inclusive governance and CAISO’s efforts to share power over WEIM matters with the market’s Governing Body. In contrast, energy leaders from across the West have said they would not join a CAISO-led RTO controlled by California politicians.
EDAM Moves Forward
The other major effort to broaden CAISO’s reach across the West in 2023 is its proposal for an extended day-ahead market (EDAM) for the WEIM. CAISO has promoted the EDAM this year as a way to bring greater cooperation to the balkanized Western Interconnection, which has 38 balancing authorities.
As a real-time-only market, the WEIM has produced more than $3 billion in benefits for its participants since 2014. The real-time market, however, represents only a fraction of the Western market. The day-ahead market is much larger.
The EDAM could generate $1.2 billion a year in benefits, or 60% of the savings of a West-wide RTO, if it encompassed the entire U.S. portion of the Western Interconnection, a new study commissioned by CAISO and performed by consultant firm Grid Strategies found. (See West Could Save $1.2B a Year in CAISO EDAM.)
CAISO fast-tracked the EDAM stakeholder initiative in 2022 amid competition for Western market share by SPP, which is pursuing its own day-ahead Markets+ program in addition to its RTO West. It published the final EDAM plan Dec. 7 and expects to seek approval from its Board of Governors and the WEIM Governing Body in February. The plan will also require FERC approval. (See PacifiCorp to Join EDAM, Final Plan Released.)
“An amazing amount of hard work and robust stakeholder engagement are coming to fruition with publication … of our final extended day-ahead market design,” Mainzer said in his year-end written report to the CAISO Board of Governors and WEIM Governing Body. “The strong stakeholder participation and engagement have helped shape the design through its various iterations, and we are committed to working with stakeholders in making any necessary adjustments that might be needed once the market is up and running.”
“We want to go and see some big things happen in 2023,” Mainzer said.
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