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November 14, 2024

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ERCOT Survives One Test, Faces Another

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.

Greg Abbott Weather (Greg Abbott via Twitter) Content.jpgGov. 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.”

Lawmakers are expected to be open to the message with the gas industry’s prominence in the state. (See PUC, ERCOT Face More Heat from Texas Lawmakers.)

“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.”

Topaz Plant (WattBridge) Content.jpgDispatchable 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.)

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FERC, NERC Set Probe on Xmas Storm Blackouts

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 outage map (Duke Energy) Content.jpgDuke 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.”

NERC’s 2022-2023 Winter Reliability Assessment, released in November, warned that while most areas were prepared for average winter temperatures, multiple regions — including North and South Carolina — were at risk of insufficient electric supplies during peak winter conditions. (See NERC Warns Winter Margins Tight in Multiple Regions.)

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

Michael Konen Duke Tweet (Michael Konen via Twitter) Content.jpgTwitter 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.

Tenn Electricity generation (EIA) Content.jpgElectricity 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.

Nationwide Forecast 2022-12-23 (National Weather Service) Content.jpgForecast 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-ISO-NE-Alt-FI-2.jpgISO-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.

Systemwide load and fuel mix (MISO) Content.jpgMISO 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.

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FERC’s Work in 2022 Left in Doubt by Manchin

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).

Each set of rule changes have elements that are supported by certain stakeholder sectors and those that are opposed by others. (See RTOs, Utilities Push Back on Interconnection Deadlines, Penalties and Battle Lines Drawn on FERC Tx Planning NOPR.)

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.

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Granholm and Manchin: The Yin and Yang of 2022 US Energy Policy

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.

Joe-Manchin-(Senate-ENR-Committee)-FI.jpegSen. 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.

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Major Changes in 2022 Continue to Shape PJM Outlook in 2023

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 Independent Market Monitor found that the auction results were competitive, largely because of the new MSOC. (See Monitor Finds PJM’s 2023/24 Base Residual Auction Competitive.)

Accreditation of Intermittent Resources Remains Divisive

Stakeholders are also pushing forward with an effort to have a new accreditation methodology for ELCC resources in place for the 2025/26 BRA in June. (See PJM Stakeholders Review Proposals on CIRs for ELCC Resources.)

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.

P3 protested that the changes are not transparent and would disincentivize the sort of generation Asthana said is needed over the coming decade. (See PJM Defends Quadrennial Review Parameters from Generator Protests.)

“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.

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MISO Concludes Turbulent 2022, Commences Busy 2023

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.

Todd Raba John Bear 2022-01-25 (RTO Insider LLC) Alt FI.jpgBoard Chair Todd Raba (left) and CEO John Bear at December Board Week | © RTO Insider LLC

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.

However, MISO cleared 2022 without dipping into its most serious maximum generation procedures, though it issued summertime and early fall alerts. (See Monitor Critiques MISO’s Commitment Usage During Summer.)

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 (MISO) Content.jpgPlanned 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.

Over 2022, MISO took steps to seek approval for two SSR agreements — a coal plant in Missouri and another in Wisconsin. (See MISO Proposing 2nd SSR Agreement for Retiring Coal Unit.)

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.

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Plans Revive to Make CAISO a Western RTO

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.

Elliot Mainzer 2022-11-09 (RTO Insider LLC) FI.jpg

CAISO CEO Elliot Mainzer

| © RTO Insider LLC

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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Winter Problems, Capacity Accreditation, New Faces on the Docket for ISO-NE in 2023

ISO-NE will start 2023 like it starts every year: worrying about the winter weather.

But from there, the New England grid operator will have to move on quickly to the longer-term concerns that will dominate the year, including imminent challenges with gas supply in the region and the complex project to update the way ISO-NE’s capacity market measures resource adequacy.

And the organization will be doing all that while facing tough questions and challenges, from new faces leading the states to a little closer to home, where an upstart group of climate activists has carved out a piece of the grid operator for its own.

Winter, Winter, Winter

In the first few months of 2023, grid officials will be closely watching the winter weather for extended cold spells that could spell danger for the region’s energy supply. So far, both weather and future forecasts have been mild, the only blip a brief shortage on Christmas Eve that was handled by reserve resources.

ISO-NE 2023 work plan (ISO-NE) Content.jpgISO-NE’s work plan for 2023 | ISO-NE

 

ISO-NE will be using a newly updated (and beautified) 21-day energy forecast, a tool that helps it and the public understand what risk lies in the coming weeks.

In the longer term though, the forecasts and solutions aren’t proving so neat.

Both outside experts and the RTO itself say that the Everett LNG facility north of Boston has to stay in operation in order to ensure that there’s enough gas to send out to generators in the region and keep the lights on in winter. (See ISO-NE: Reliability Still Depends on Mass. LNG Import Terminal.)

But the end of the reliability-must-run agreement keeping that facility’s “anchor tenant,” the Mystic Generating Station, alive has caused immense worry among energy policymakers.

“The clock that’s running is going to force us into another set of stopgap solutions,” ISO-NE CEO Gordon van Welie said at a recent conference put on by the New England Power Generators Association. “I don’t think we can design the elegant, long-term resource neutral solutions in a timely fashion to deal with the clock that’s running on Everett right now.”

With the Mystic contract ending in 2024, much of the New England energy world’s focus in 2023 will be on sorting out those solutions.

Capacity Accreditation, and Beyond

Meanwhile, in the NEPOOL stakeholder process undergirding ISO-NE’s policy decisions, there’s a debate underway about capacity accreditation that will burst into full bloom in 2023.

In the RTO’s own words, the project is designed to “identify and implement methodologies that will more accurately reflect resource contributions to resource adequacy in the Forward Capacity Market.”

More broadly, it’s a key part of the region’s energy transition: As more renewable resources come onto the grid, ISO-NE needs a better way to fairly measure the contributions of both them and the incumbent generators like natural gas plants.

But it’s also a highly complex process that has and will continue to strain the capabilities of even the most experienced energy policymakers in NEPOOL (let alone the journalists tasked with translating it to their readers).

In its early work on the concept, ISO-NE has pushed forward with using a metric that sets a resource’s accredited capacity based on the “marginal reliability impact of an incremental change in size.” (See ISO-NE Firms up its Support for Marginal Capacity Accreditation.)

Its preliminary proposals have already earned pushback from stakeholders including the Natural Resources Defense Council and LS Power, who are worried, respectively, that it undervalues the contributions of clean energy resources and doesn’t adequately account for the limitations of gas resources.

Much more of that debate is set to come in 2023, along with other key projects like developing a day-ahead ancillary services market and studies to examine 2050 transmission needs and the impacts of extreme weather.

Healey to the Fore

Maura-Healey-2019-07-25-(RTO-Insider-LLC)-FI.jpgNew Massachusetts Gov. Maura Healey could be a thorn in ISO-NE’s side. | © RTO Insider LLC

ISO-NE’s relationship with the New England states has been strained in recent years over disagreements about the speed and degree of the clean energy transition and responsibility for the region’s failings.

That’s not likely to change in 2023, but there is a new variable that could shake up the relationship further: Maura Healey.

The former Massachusetts attorney general was elected governor and is set to be sworn in as Charlie Baker’s replacement on Thursday. She’s likely to continue and build on what was, in the end, a fairly robust set of climate policies put forward by Baker. (See Healey Focuses on Climate in Mass. Gubernatorial Race.)

One area to watch where Baker took criticism was on environmental justice and project siting. But she also could take aim at ISO-NE. As AG, Healey and her office spent lots of time and energy navigating the NEPOOL process and helping to organize consumer advocacy responses to ISO-NE’s work.

And significantly, her chief energy aide as AG, Rebecca Tepper, is coming on to join her in the governor’s office as secretary of energy and environmental affairs.

Tepper has been a regular thorn in the side of ISO-NE and regularly pushed it to collaborate more with the states.

The Call is Coming from Inside the House

2023 will be a year when climate activists, for the first time ever, have control of a small piece of ISO-NE.

A group led by the group No Coal No Gas won election to several seats on the coordinating committee of the Consumer Liaison Group, a forum that ISO-NE is required to use for communicating with the public. (See Climate Activists Take Over Small Piece of ISO-NE.)

CLG holds no formal policymaking power, but the committee sets agendas for its four quarterly meetings, which have become increasingly high-profile and well attended.

In 2023, those meetings will look a bit different than they have in the past, with the group promising to focus on connecting the issues that ISO-NE works on more closely to ratepayers (and potentially even pushing for a name change for the group).

“It will now be much harder for ISO New England to keep the CLG from getting feisty,” said Donald Kreis, New Hampshire’s consumer advocate.

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Passage of the IRA Reshapes US Clean Energy Transition

The biggest clean energy story of 2022, hands down, was the passage of the Inflation Reduction Act, rising improbably and miraculously from the ashes of President Joe Biden’s Build Back Better Act of 2021.

The IRA and its $369 billion in clean energy funding, builds on the foundation laid by 2021’s Infrastructure Investment and Jobs Act, which included another $62 billion in funding for clean energy initiatives that began rolling out this past year.

The full impact of the two laws will likely be incremental, unfolding over the next five to 10 years, but 2023 will be pivotal as the Biden administration continues to push forward with its clean energy agenda, and private industry and finance make decisions about adding their own dollars to the billions in clean energy grants, tax credits and other incentives contained in the two laws.

The administration’s focus will be on delivery. In a series of appearances at recent energy conferences, National Climate Advisor Ali Zaidi has called on corporations and private investors to get off the sidelines and put steel in the ground. “For folks in the private sector, the time to make decisions is now. Boards can’t commission study committees; they’ve got to greenlight capital projects,” Zaidi said in a keynote address for a Resources for the Future conference in October.

But implementing the IIJA and IRA also raises complex issues as federal and state agencies hash out the details of legislative language and the intent of the lawmakers who crafted it. Other headwinds include inflation, Russia’s war on Ukraine and the lingering effects of the COVID-19 pandemic on clean energy supply chains.

The NEVI Example

While the IIJA and IRA are both trimmed-down, compromise versions of the original bills Biden and Democratic leaders hoped to pass, getting the laws through a deeply divided Congress was an extraordinary achievement. The often-tense negotiations, in particular for the IRA, required a fine balance between the Democrats’ progressive wing and the swing votes of conservative Democrats Sen. Joe Manchin and Sen. Krysten Sinema, now an independent.

What matters now, with the 2024 presidential election already on the horizon, is the impact the laws will have on the way the U.S. produces and consumes energy and how such changes are perceived by individual consumers. Will the IIJA and IRA deliver new, cleaner technologies, emission reductions and cost savings — as well as the sense of urgency and mission that is required to curb the mounting impacts of climate change?

The IIJA’s National Electric Vehicle Initiative (NEVI) provides an early look at the complexly layered issues that will likely surface as each new program is rolled out. With $7.5 billion from the IIJA, the goal of NEVI is to create a national network of 500,000 EV chargers over the next five years, with 150 kW DC fast chargers located along interstate highways, as well as in rural, tribal and disadvantaged urban communities.

The law provides millions in yearly allocations to individual states, which must submit plans to the Federal Highway Administration, showing how they will use the funds and identifying the specially designated routes and other locations where chargers will be installed. A joint effort of the Department of Transportation and the Department of Energy, the first guidelines for NEVI were announced in February, followed by more detailed technical standards in June.

As required, all 50 states, the District of Columbia and Puerto Rico submitted their plans by an Aug. 1 deadline, which were approved by the FHWA, also on deadline, by the end of September. (See US Completes Review of State EV Charging Plans.)

But many state plans raised a range of concerns about the program’s requirements, such as the mandate for the EV chargers to be located every 50 miles on key interstate and state highways, with charging stations installed no more than one mile off these roads. Highways running through remote or rural regions simply may not have the electric distribution system needed for the high-powered fast chargers or the traffic needed to make the installation of fast chargers pencil out.

Utilities have warned that building out the poles and wires in remote areas will need to occur in stages over several years. Making sure chargers are installed in areas where potential EV owners may live in multifamily apartment houses or other affordable housing is another area where many states are still developing policies and plans.

Installation of the first NEVI-funded charging stations should start this year, but Biden’s vision of a seamless, national network of chargers that will make topping up EV batteries as easy as stopping at a gas station, and banish drivers’ range anxiety, will likely encounter more than a few bumps and detours.

Implementing the IRA’s wide range of tax credits and other incentives could be even more complex, as states and industry stakeholders wait for the federal guidelines needed to put the cash incentives for electric vehicles, heat pumps and other energy efficiency technologies in consumers’ hands.

The Internal Revenue Service ran up against a year-end deadline for issuing guidelines for the IRA’s EV tax credits, without providing detailed guidance on domestic content requirements called for in the law. Manchin quickly called for a hold on the incentives and threatened additional legislation to ensure the IRS follows the letter of the law.

In other words, both sides of the aisle have major stakes in the IIJA and IRA, and the amount of money and scope of the programs involved almost ensure that mistakes will occur, and individuals and businesses will try to game the system.

Federal and state agencies face steep and slippery learning curves in the months ahead, and a small army of whistleblowers and gadflies will be watching their every step.

Inflation, COVID and the War in Ukraine

Even before the IRA was passed, congressional Republicans were talking up plans for whittling away at some of its provisions following November’s midterm elections, in which they had hoped to regain control of both the House and Senate. But, with the Democrats holding the Senate and the GOP winning only a slim majority in the House, efforts to slow or sideline implementation of the IRA will be limited to general political sniping and oversight hearings.

At the same time, the combined effects of inflation, Russia’s war in Ukraine, and the lingering impacts of the COVID-19 pandemic, could present additional obstacles to the implementation of the laws, and Biden’s clean energy agenda in general.

COVID-19 was an early trigger for inflation as factory closings and the resulting production slow-downs hit supply chains, not only in clean energy, but across the economy. After years of steady decreases, prices for solar panels and storage started to inch up, and installations slowed down. According to figures from Wood Mackenzie, solar installations in 2022, estimated at 18.6 GW, fell about 23% from 2021, with new utility-scale deployments falling 40%.

The war in Ukraine triggered a worldwide “dash to gas” as both European and Asian countries faced the immediate and potentially disastrous cutoff of their supplies of Russian natural gas, looking instead to the U.S. to keep their economies fueled and their consumers warm through cold winters. With mounting pressure from Republicans to “unleash” U.S. fossil fuels through increased leasing on public lands and approval of new or unfinished pipelines, the Biden administration and congressional Democrats have had to walk a fine line balancing the immediate needs of U.S. consumers and overseas allies with the impacts of climate change.

Biden and other energy leaders worldwide argued that the short-term need to boost natural gas production should not be used to slow or stop the global move to clean energy, which would provide the best defense against both inflation and Russia’s weaponization of vital energy supplies.

While inflation is nosing down, price increases and supply chain challenges could continue to slow critical clean energy projects. Biden’s goal of installing 30 GW of offshore wind by 2030 prompted a surge of activity last year with the Bureau of Ocean Energy Management holding a series of high-profile offshore lease auctions for sites on both the Atlantic and Pacific coasts.

The auction of six sites in the New York Bight, a curve in the New York-New Jersey coastline, produced record-breaking bids totaling $4.37 billion. At the same time, states up and down the Mid-Atlantic coast are expanding port facilities and drawing in new OSW manufacturers, all vying to become major hubs for offshore construction and operations.

For example, New Jersey’s ambitious plans for a purpose-built offshore wind port could cost between $500 million and $550 million and could create up to 1,500 manufacturing, assembly and operations jobs, according to figures from the state’s Economic Development Authority. (See NJ to Expand Wind Port with Land Purchase.)  

But the economics of developing and financing these offshore wind projects — and building the necessary transmission — remain uncertain. The West Coast sites will require floating turbines, which will present another level of technical and financial challenges.  

PPAs and Supply Chains

The Massachusetts Department of Public Utilities ended the year with Friday’s approval of contracts, called power purchase agreements, for the 1.2 GW Commonwealth offshore wind project and the 804 MW Mayflower project, despite petitions from both project developers to allow them to renegotiate due to rising costs, as reported in The New Bedford Light.

Following the DPU decision, Craig Gilvarg, a spokesperson for Commonwealth developer Avangrid, said, “The current Power Purchase Agreements do not allow the company to secure the significant financing needed to construct this critical project, and thus the project cannot proceed under these contracts.”

A joint project of Shell New Energies US and Ocean Wind, the Mayflower project will move forward, but the developers have signaled their current plans will focus on completing only an initial 400 MW.

Building out domestic supply chains for offshore wind, electric vehicles, batteries, solar panels and other technologies was yet another major flash point in 2022 — and an easy target for Republican criticism of the clean energy sector’s dependence on China and Russia for critical minerals, including lithium, cobalt and uranium.

Biden has promoted “Made in America” initiatives as a top priority in the IRA’s manufacturing and clean technology tax credits, and the auto industry, in particular, has responded with a series of announcements on plans for new factories and for the retooling and expansion of existing facilities for EV and battery production.

But building out an extensive U.S. clean energy supply chain, especially for critical minerals, will take years, billions in private investment and a willingness by all stakeholders to tackle the essential issue of permitting reform.

Both parties know reform is critical, but whether they will put politics aside and hammer out a deal could be one of the biggest stories of 2023.

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Climate Still on Washington Agenda After Landmark Legislative Sessions

Washington’s 2023 legislative session will seem less revolutionary on the climate front compared with the last two years, which saw the passage of landmark — and controversial — bills to reduce the state’s carbon emissions.

Still, a healthy number of environmental bills are in the works for 2023.

“Biggest thing is to focus on implementing the things we said we’re going to do,” Sen. Joe Nguyen (D) from Seattle, the new chair of the Senate Environment, Energy and Technology Committee, told NetZero Insider.

“There’s a lot of enthusiasm among House and Senate Democrats to keep momentum going,” said House Majority Leader Joe Fitzgibbon (D) of West Seattle.

One of the greatest challenges facing lawmakers will be deciding how to divvy up revenue generated by the state’s new cap-and-trade program, passed by the Democrat-controlled legislature in 2021 along party lines.  Lawmakers that year also enacted a low-carbon fuel standard and implemented a soft goal for the state to taper off sales of gasoline-powered cars by 2030. That was followed last year by Gov. Jay Inslee’s mandate that all cars sold in the state be emissions-free by 2035.

The cap-and-trade program’s first carbon allowance auction is scheduled for Feb. 28.  The auction — one of four to be held this year — will offer 6.185 million allowances at a minimum allowed bid of $22.20 per allowance. Entities will be able to bid on blocks of 1,000 allowances.

Under auction rules, the highest bidder would get first crack at the limited number of allowances, the second highest bidder would get second crack, and so on. The auction ends when the all the designated allowances are bid upon. Then, all the successful bidders will pay the same price per allowance as the lowest successful bid.

The number of auctioned allowances will decrease over time to meet the state’s decarbonization goals set for 2035 and 2050.  Companies will be allowed to trade allowances among themselves.

The auctions are expected to raise $500 million to $1 billion a year, depending on who is calculating. Democrats and Republicans expect to decide in the upcoming session how to spend that money, according to Gov. Jay Inslee, Nguyen, Fitzgibbon, and Rep. Mary Dye of Pomerory, ranking Republican on the House Environment and Energy Committee.

In the upcoming session, Senate Republicans want to introduce legislation to suspend the cap-and-trade program if gas prices get too high for too long. Democratic leaders say this bill won’t stand a chance of getting out of committee. Senate Republicans also plan to introduce a bill to track the effects of the state’s new low-carbon fuel standard on gasoline prices. Nguyen said such tracking is already in the existing low-carbon fuel standards law.

Land Use Bill Revived

Climate bills related to land use planning, salmon and tree planting will also come into play this year.

The 2023 session will likely see the revival — and passage — of House Bill 1099, which would add climate considerations to city and county land use planning.

The bill, introduced last year by Rep. Davina Duerr (D), would have made this change to Washington’s Growth Management Act, which regulates long-range land use planning for Washington’s city and county governments. It would have required local governments to review and, if needed, revise their comprehensive plans and development regulations every eight years.

Duerr’s bill would have required climate change to be considered in land use and shoreline planning for the 10 largest of Washington’s 39 counties and in cities of 6,000 residents or larger. The 10 largest counties cover Puget Sound, Spokane, the Yakima River Valley and the Washington-side suburbs of Portland.

Last March, Senate and House Republicans used parliamentary maneuvering to kill the bill on the final day of the session. (See Sponsor Plans to Revive Stalled Wash. Land Use Bill.)

Inslee and Dye want to introduce legislation to plant large numbers of trees along Washington’s rivers and streams to provide shade for migrating salmon. Water temperatures exceeding the lower 70s seriously threaten the health of the fish. “This is a major, major threat,” Inslee said in an interview.

The concept of cooling streams with extra shade has been around for decades, but Inslee and Dye said the measure needs to be tackled with much greater volume than before. Both speculated that cap-and-trade money could be used for the effort.

Duerr has introduced a bill (HB 1078) to establish “tree banks,” designated area where trees would be planted to replace those cut down to develop properties.

Republican Plans

While the ranks of Washington’s Republican lawmakers will be slightly thinner this year after last November’s election contests, they still plan to push bills that would deviate from the Democrats’ policy goals.

Sen. Curtis King of Yakima, ranking Republican on the Senate Transportation Committee, has introduced a bill (SB 5092) to provide tax breaks to residents buying hybrid vehicles. Hybrids provide an affordable steppingstone for lower-income people who cannot afford electric vehicles in the next few years, he said.

However, Inslee and Fitzgibbon believe boosting hybrids is an inadequate step in the state’s push to switch to a predominately EV market. “Hybrid vehicles were a great solution for lowering emissions 20 years ago, but we need to be moving faster in reducing emissions and focus limited incentive dollars on truly clean vehicles,” Fitzgibbon said.

Inslee said the cheapest all-electric car — the Chevrolet Bolt — costs about $25,000, making such vehicles more affordable.

Republicans also want to introduce a bill regulating the recycling of wind turbine blades and parts from solar farms. Fitzgibbon said Democrats are open to recycling power industry materials but wondered why the GOP’s plans don’t include recycling parts from natural gas plants and hydroelectric dams. Both sides speculate that the disposal and recycling of batteries will surface in this session.

In the 2022 session, House Republicans introduced a bill (HB 1822) to allocate some cap-and-trade revenue to create an Office of Puget Sound Water Quality to provide help and supervision to municipal sewage treatment plants on the sound to trim amount of nitrogen-laden nutrients, which decrease the oxygen needed by fish.  That bill never made it out of the House Environment and Energy Committee and Dye plans to revive it in 2023.