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November 20, 2024

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Biden: ‘I Will not Back Down’ on Climate Action

With Sen. Joe Manchin (D-W.Va.) once again shutting down negotiations over a budget reconciliation package that includes clean energy incentives, a range of voices and views have emerged to answer the crucial question of what comes next.

President Biden and Energy Secretary Jennifer Granholm both struck a note of defiance. In a statement released by the White House on Friday, the president said the need for climate action remained as urgent as ever, and he vowed not to back down.

“If the Senate will not move to tackle the climate crisis and strengthen our domestic clean energy industry, I will take strong executive action to meet this moment,” Biden said. “My actions will create jobs, improve our energy security, bolster domestic manufacturing and supply chains, protect us from oil and gas price hikes in the future, and address climate change.”

Granholm took to Twitter with a thread acknowledging her frustration while calling for broad action at all levels. “We will fight like hell with the tools we have to build a clean energy future and move forward on climate action,” she said. “This moment calls [for] every city, state, tribe, business, community and organization to get in the fight if you’re not already. We have to leave it all on the field.”

In an interview on West Virginia MetroNews radio on Friday, Manchin maintained that he wants action on climate, but in the wake of June’s 9.1% consumer price index — up 1.3% from May — fighting inflation and reducing the federal deficit have to come first.

Manchin in December gave similar reasons for pulling out of negotiations over the original Build Back Better Act. The bill was passed by the House of Representatives, but all 50 Republicans in the Senate are opposed. Democrats want to use the reconciliation process, which would only require a simple majority vote (with Vice President Kamala Harris breaking the tie) if Manchin joined in support, to bypass a filibuster.

“We’ve had good negotiations. … Our staffs have been working diligently for the last two to three months,” Manchin told Hoppy Kercheval, host of “MetroNews Talkline.” But he also said he had been clear with Senate Majority Leader Chuck Schumer (D-N.Y.) and other Senate staffers that his support would depend on the June inflation figures that were released on Wednesday.

“They knew exactly where I stood,” he said. “When we saw 9.1%, that was an alarming figure to me … so I said, ‘Oh my goodness, let’s wait; this is a whole new page.’”

With the war in Ukraine, and Europe looking to the U.S. to replace Russian fossil fuels, Manchin argued that the U.S. can decarbonize while continuing to “produce more fossil [fuel] cleaner than anyone in the world and replace that dirty fossil going into the atmosphere.”

“Also, what you can do is invest in the cleaner technologies that we know that will work,” he said. “We know hydrogen is going to work; we know we need storage for batteries, and battery storage takes care of wind and solar; we know that. New transmission — we know all these things. Geothermal and small nuclear reactors, I’m for all these things.”

Manchin said he is also consulting economic experts to ensure that any tax increases that would be used to fund clean energy incentives don’t cause further inflation or cause companies to cut back production or lay off employees. A budget reconciliation package, with or without energy incentives, could still be passed when Congress returns from its August recess in September, he said, “if it’s a good piece of legislation.”

Post-election Green Pivot?

Biden’s statement did not detail the specific executive actions he might take to provide momentum for his stalled vision for an aggressive climate agenda. Manchin’s latest defection comes two weeks after the U.S. Supreme Court’s decision in West Virginia v. EPA undercut EPA’s ability to cut emissions at existing power plants through generation shifting — changing out dirtier fossil fuels for cleaner low- or no-carbon generation. (See Supreme Court Rejects EPA Generation Shifting.)

Biden has already used executive orders to set the U.S. on a path to a 100% carbon-free electric system by 2035 and a net-zero economy by 2050. More recently, he invoked the Defense Production Act to ramp up clean energy manufacturing and ordered a two-year suspension of potential tariffs on solar cells and panels from Cambodia, Malaysia, Thailand and Vietnam in the face of a pending Commerce Department investigation. (See Biden Waives Tariffs on Key Solar Imports for 2 Years.)

Meanwhile, the Department of Energy is continuing to distribute new funding, much of it from the Infrastructure Investment and Jobs Act, for clean energy initiatives.

If fully funded, the law will continue to pump out funds for clean energy through 2026. For example, on Thursday, the DOE announced $29 million in funding, about a third from the IIJA, to increase the reuse and recycling of solar technologies and develop solar panel designs that reduce the cost of manufacturing.

In the wake of West Virginia v. EPA, California Gov. Gavin Newsom (D) and Washington Gov. Jay Inslee (D) both vowed to step up their efforts to cut carbon emissions. More recently, the D.C. Council passed legislation, pending before Mayor Muriel Bowser, that would ban natural gas hookups in new construction and require all new construction and major renovations in the district to be net-zero by 2026.

But, in its analysis of the post-Manchin state of play, industry analysts ClearView Energy Partners suggest that if the Republicans do gain majorities in the House and Senate in the midterms, Biden might “pursue muscular intervention into energy markets and capital formation … potentially including ‘a climate emergency’ declaration.”

“If the White House was also modulating its oil and gas policy in recent months to woo [Sen.] Manchin’s support for clean energy incentives, then Manchin’s latest defection could bring an even bigger post-election green pivot,” ClearView said.

In the absence of a “mini-BBB” budget reconciliation deal, ClearView also sees the potential for a congressional pivot toward passing a package of clean energy tax credit extenders in the lame-duck session between the midterm elections and the opening of the next Congress in January. Although the option of tax extenders has not been discussed thus far, “we would not be surprised to see extenders text proposed (or at least mooted) by the House Ways and Means and Senate Finance Committees before lawmakers leave for their August recess,” ClearView said.

Some Republicans might support extender legislation for two reasons, ClearView said. First, even if the GOP takes both houses of Congress, Biden will still have veto power, and second, a growing number of red states are now generating about half of the country’s onshore renewable and other clean forms of energy.

Underway and Unstoppable

Perhaps with such tax extender legislation in mind, clean energy advocates and business groups continued to call for congressional action on federal tax credits and other incentives, echoing administration arguments that they will help fight inflation, spur economic growth and protect energy security.

Clean energy tax credits “would deliver much needed relief, helping to cut energy prices and reduce U.S. dependence on price-volatile fossil fuels, by spurring the domestic manufacturing and deployment of clean, affordable and reliable advanced energy technologies,” said Heather O’Neill, president of Advanced Energy Economy. “Failing to use this opportunity to boost the domestic advanced energy manufacturing industry would mean American workers get less benefit from the world’s transition to clean energy, and would all but assure that our economic competitors, particularly China, reap the economic rewards instead.”

O’Neill and others also pushed hard on the business case for clean energy. The transition is “underway, and it is unstoppable,” O’Neill said. “We see it in corporate procurements driving clean energy investment across the country. We see it in consumer demand for electric vehicles as drivers seek to free themselves and their pocketbooks from the volatility of gasoline prices.”

“The private sector is making record-level investments in the clean energy transition, but a predictable and long-term national tax and policy framework is needed to support accelerated and expanded deployment,” said Lisa Jacobson, president of the Business Council for Sustainable Energy.

Any effort to find common ground on tax credits might begin with carbon-capture technologies and that industry’s 45Q tax credit, both of which have had strong support from Manchin, whose family still operates the coal company he started.

“While there is uncertainty about next steps with the reconciliation process, it remains clear that there is broad, bipartisan support for Congress to provide robust investments in carbon-management policies,” said Madelyn Morrison, external affairs manager for the Carbon Capture Coalition. “To achieve carbon capture and removal at climate scale, Congress must deliver the full portfolio of federal policy support for carbon management in any moving legislative vehicle, including a direct-pay option for the 45Q tax credit.” Manchin has recently opposed any direct-pay options for clean energy tax credits.

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MISO Promises Stakeholder Discussions on Capacity Auction Reform

MISO leadership last week committed to holding future talks with stakeholders on how to retool its capacity auction to stimulate more supply.

Scott Wright, the RTO’s executive director of market strategy, said the growing reliability risk will require staff and stakeholders to discuss modifications to price signals and how to value resources’ different attributes in the capacity market.

The discussions will be held in the Resource Adequacy (RASC) and Market subcommittees during the next few months, Wright said. He added that the conversations will likely include potentially adding a sloped demand curve in the capacity auction. (See MISO Warming to Patton’s Sloped Demand Curve.)

“MISO is committed to coordinated action and is developing plans for near-term evaluation and stakeholder engagement,” Wright told stakeholders during a Resource Adequacy Subcommittee meeting Wednesday. “We’re not deferring this to next year; we want to get going this year.”

The vow was repeated the next day during a Market Subcommittee meeting.

“We’re looking through what the plan is and will return to these forums,” MISO Senior Director of Transmission Planning Laura Rauch said.

Independent Market Monitor David Patton said after speaking with state regulators following the April planning resource auction (PRA), he’s “cautiously optimistic” that MISO will be on a path to applying a sloped demand curve within six months

“The best time to implement a sloped demand would have been when you’re not in shortage,” he said.

MISO Midwest is grappling with a 1.2-GW capacity shortage following the 2022-23 PRA. The shortfall triggered a $236.66/MW-day cost-of-new-generation-entry clearing-price for the Midwestern subregion. MISO has said the deficit might force it to order temporary, controlled load sheds this summer and next as it is not expecting sufficient firm resources to handle summer peak forecasts under typical demand. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.)

Though members approached this year’s auction with more capacity year-over-year, staff said the resource additions were mostly intermittent and generally less available than retiring thermal generators.

Stakeholders Ask for Data Improvements

Constellation Energy’s John Orr said staff’s posting of preliminary supply and demand data for the PRA could use some improvements and more regular updating.

Orr suggested MISO implement a standardized timeline for posting forecasted capacity positions by local resource zone, perhaps releasing the data in January and updating it on a weekly basis as market participants update capacity values. He said MISO should periodically update how much capacity has been converted to zonal resource credits. He said if a particular zone returns a zero value ahead of the auction, that could spur members into making arrangements to avoid another capacity shortfall.

Orr said a weakness of MISO’s 2022-23 preliminary data was that it was never updated beyond a singular release.

“We all knew those numbers are incomplete, but they gave us an idea of what to expect, especially in zones that are predicted to be tight,” Orr said. He, like other stakeholders, questioned why they failed to warn of a potential shortage.

Orr said he thinks “it’s time for stakeholders to ask MISO what they want to see” and asked stakeholders to work together to develop recommendations to MISO.

He said market participants need a better idea of what resources are expected to be unavailable, either due to retirements or auction exemptions and exclusions approved by the IMM.

“The exemptions and retirements that are protected by confidentially can really kind of can throw you off when you’re going to be very tight, as it appears we’re going to be for the next several PRA cycles. And the seasonal auctions could throw another wrinkle in that,” Orr said.

WEC Energy Group’s Chris Plante said his utility is having “a lot of difficulty” preparing quadrupled data for a yet-uncertain seasonal capacity auction. FERC has yet to approve MISO’s request to conduct four seasonal auctions per year.

In the meantime, MISO leadership continues to issue grim warnings over its forecasted capacity supplies.  

During a July 7 meeting with Kentucky lawmakers, Melissa Seymour, vice president of external affairs, said that part of the state might face controlled load shedding next year.  

Seymour delivered a similar message in front of the Illinois Commerce Commission in May. (See MISO Exec, IMM Debate Next Steps After Capacity Auction Shortfall.)

“Unless more capacity is built or bought, especially capacity able to reliably generate during tight system conditions, the shortfalls we experience this year will continue and get worse going forward,” she said.

MISO’s wholesale footprint affects just 14% of Kentucky’s retail power sales.

Seymour’s comments led Kentucky lawmakers to suggest ramping up coal production, delaying coal plant retirements, and even bringing some nonoperational coal plants out of retirement.

According to its pending 2021 integrated resource plan, Louisville Gas and Electric and Kentucky Utilities intend to retire a dozen aging coal and gas-fired units from 2024 to 2036.

“As a generation unit ages, the economics of retrofitting the unit to comply with new environmental regulations become less favorable,” LGE and KU explained in the filing. However, the utilities still plan to burn coal into 2066.

New Accreditation for Renewables in the Works

MISO continues to evaluate new capacity accreditation designs with stakeholders for the footprint’s renewable resources and load-modifying resources.

During the July RASC meeting, the RTO’s director of policy studies, Jordan Bakke, said staff and stakeholders are “learning together” about accreditation options for non-thermal generation. He said MISO is still in an evaluation stage and hasn’t internally settled on an option.

Patton said once MISO more accurately accredits intermittent resources, it should send economic signals to developers to pair their renewable energy with battery storage. He said co-located renewable and storage hybrid resources will likely have a much higher capacity credit.

MISO laid out three potential options this spring to accredit renewable resources: expand its effective load carrying capability (ELCC) calculation to include solar as well as wind; use the same performance-based accreditation design that it proposed for its thermal generation and currently pending before FERC; or use a blend of ELCC and performance-driven accreditation. 

Some stakeholders expressed confusion with how the blended option would be handled. Staff said they would use its projected loss-of-load risk hours and MISO’s new concept of “resource adequacy hours” — the historical tight margin and emergency periods defined for the performance-based accreditation design — as possible inputs for the new accreditation method. (See MISO Stakeholders Insist on Consistency in Capacity Accreditations.)

The RTO filed with FERC late last year to change its accreditation for conventional resources to a seasonal value based on a unit’s past performance during resource adequacy hours. The new accreditation is contained in a larger filing to create four seasonal capacity auctions. (See Deficiency Notices for MISO’s Seasonal Capacity Auctions Bid.)

The grid operator said the blended approach for renewables has the potential to encompass a “broader range of planning and operational considerations.” Staff said loss-of-load hours and resource adequacy hours don’t necessarily occur on the same days.

MISO plans to discuss a new accreditation method for its non-thermal resources in RASC meetings and special workshops through the end of the year.

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NV Energy Surpasses 2021 RPS Requirement

NV Energy exceeded Nevada’s renewable portfolio standard requirement of 24% in 2021, with nearly 31% of its retail energy sales coming from renewable resources and related credits, according to a report approved by state regulators last week.

NV Energy subsidiary Sierra Pacific Power, which serves northern Nevada, achieved 31.9% renewable energy last year. Southern Nevada subsidiary Nevada Power reached 30.1% renewable energy. The statewide weighted average was 30.7%, according to the report filed by the utility in April.

Last year’s adjusted retail sales were 8,728,248 MWh for Sierra Pacific and 20,712,404 MWh for Nevada Power.

The Public Utilities Commission of Nevada (PUCN) voted 3-0 on Tuesday to approve the report and confirm that NV Energy complied with the 2021 renewable portfolio standard.

50% by 2030

Nevada’s RPS was 24% last year, an increase from 22% in 2020. The RPS grows to 29% in 2022 and 2023; 34% in 2024 through 2026; 42% in 2027 through 2029; and 50% in 2030. NV Energy said it is “well on its way” to meeting the 50% renewable requirement by 2030.

“Our commitment to evolving our generation mix is one of many ways we are helping meet our state’s sustainability goals,” Dave Ulozas, NV Energy’s senior vice president of energy supply, renewables and origination, said in a release shortly after the utility filed its report with PUCN.

Last year was the 12th year in a row that the company surpassed the state’s renewable energy requirement, the release said.

DSM, Carryovers

Under Nevada statute, energy efficiency measures may count toward up to 10% of the annual RPS requirement, through 2024. After that, energy efficiency measures — included within demand side management (DSM) — can’t be used toward meeting the standard.

NV Energy used energy savings from DSM to satisfy 10% of its RPS requirements last year.

In addition, the utility used excess portfolio credits carried over from 2020 to help meet last year’s RPS requirement. And surplus credits from last year will be carried over to this year.

State law allows a utility to sell excess portfolio credits when the surplus is more than 10% of the required amount. If the surplus is more than 25% of the amount needed to meet the RPS, the utility is directed to “use reasonable efforts to sell” credits in excess of 25%.

Sierra Pacific went over the 25% threshold with its surplus portfolio credits and solicited offers to buy them. Although the utility received seven offers, it ultimately decided to keep the credits in case it needs them later, according to the report.

Nevada Power had surplus portfolio credits in the 10% to 25% range. NV Energy said it would consider selling the credits “if the circumstances are favorable and the sale benefits our customers.”

New Solar Projects

At the end of 2021, Nevada Power had about 1,570 MW of renewable generation capacity in service, according to NV Energy’s filing. Nevada Power added one utility-scale renewable project last year, Copper Mountain 5, a 250 MW solar facility in Boulder City.

In addition, Nevada Power had nine solar projects totaling 2,044 MW in development at the end of last year. Eight of those projects include battery storage.

Sierra Pacific finished the year with about 692 MW of renewable capacity in operation. During 2021, one new project was added: the 101 MW Battle Mountain solar facility, which includes 25 MW of storage.

The utility also had six solar projects with a combined total of 824 MW in development at the end of the year. All the projects include battery storage.

NV Energy’s filing described a “positive” outlook for both of its subsidiaries to comply with the RPS and other future credit commitments.

However, the utility noted some risks. In particular, delays in receiving solar panels and other project components are causing project completion dates to be pushed back and could result in project cancellations, the RPS report said.

“Delays and shortages can drive up costs to a point where a project that was previously economical becomes uneconomical,” NV Energy said.

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Residents Voice Opposition to Upstate NY Wind Project Before PSC

Residents opposed to the Heritage Wind project planned for western New York spoke before the Public Service Commission on Thursday, citing human health concerns, danger to migratory birds in nearby game refuges and a lack of transmission capacity (22-E-0204 and 16-F-0546).

The developers “maintain that there will be no change in property value in our area. We would have six of the wind turbines almost 600 feet tall within 1 mile of our home and the fact that they tried to maintain that there would be no effect on our property value or anyone else’s property value in this area I think is considerably a falsehood,” Iva McKenna — a resident of Barre, where the project is to be located — told the PSC.

While only five people spoke at the hearing, all against the project, the initial proceeding drew 452 written comments, which were overwhelmingly opposed to the project, though about two-thirds of the total was form letters.

Only three of the 17 written comments submitted for the public hearing were in support. Austin Kuntz, union representative for Rochester-based Laborers’ Local 435, said the project will bring hundreds of prevailing-wage jobs to local residents, provide them and their families with health care benefits and a suitable retirement, and fund schools, public services and infrastructure without the need to raise local taxes.

Heritage Wind southwest section (Heritage Wind) Content.jpgThe southwestern section of the Heritage Wind project lies within a mile or two of national and state wildlife areas. | Heritage Wind

The Office of Renewable Energy Siting (ORES) in January granted a construction permit for the project in Barre, between Rochester and Niagara Falls, contingent on securing a certificate of public convenience and necessity from the PSC. The project is owned by Virginia-based Apex Clean Energy, which manages 2 GW of renewable energy.

Barre resident Adrienne Daniels commented on July 1 that her seizure disorder “very likely will be further affected by the towers’ flicker effects. … The proposed heights of the towers are ludicrous. It has to cause problems with airspace for the small airport nearby, bird populations, migration routes, etc. An eagle has nested on my property; I strongly doubt we’ll have any other large birds establishing nests in this area.”

With 4,607 gravel truck trips projected, resident Georgette Stockman said that if “they plan to use Route 77, will the movement of equipment and components pass the new Western New York Veterans Cemetery, where two people have already lost their lives trying to negotiate their way onto Route 77? Will the equipment go through the Iroquois Wildlife Refuge and disturb the very nature of a refuge?”

Barre resident George McKenna reiterated his written concerns that the $198 million to be paid by NYSERDA for the project was “a wash” and that it would take at least 20 years to get that sum back in electrical energy value.

He also said Barre citizens have never had their opinions or concerns listened to.

“Surveys have shown approximately 70% of the population in opposition, and when the town board was in the process of changing the town’s wind ordinance to accommodate Heritage Wind, 87% of the population was opposed,” McKenna said.

Resident Kerri Richardson spoke of the inability of the transmission system to deliver increasing amounts of upstate renewables to downstate consumers and how that situation jeopardizes achieving the state’s public policy goals.

“The NYISO 2019 Power Trends report identifies that it is not actually in the public interest or public need to move forward with this project in particular,” Richardson said. Quoting from the report, she said, ‘Even with the Western New York and AC transmission projects already selected by the NYISO, congestion on the system will persist, complicating the state’s ability to meet its renewable energy goals.’”

In its January 2019 award of renewable energy credit (REC) contracts, the New York Energy Research and Development Authority (NYSERDA) noted that it was supporting 20 large-scale renewable projects, including Heritage, and that 93% of the awarded capacity would be located upstate (in zones A-E), where clean energy resources are already abundant and access to load centers in southeastern New York is heavily constrained, bottled in so-called generation pockets.

In its 2022 Power Trends report issued last month, NYISO projected that “transmission constraints in these pockets will likely result in curtailment of 11% of the total potential renewable energy production across New York, with curtailment levels in some individual pockets as high as 63%. As more renewables are added to the bulk electric system without additional transmission expansion, greater congestion and curtailment levels will occur.”

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MISO Predicts Easier Operations in Fall

As it navigates a tough summer, MISO is more optimistic about successfully managing operations this fall.

The grid operator on Thursday released a fall resource adequacy outlook, where it said it shouldn’t encounter trouble if demand and generation outages remain at normal levels throughout autumn.

Using a probable peak load forecast, MISO expects to have 114 GW of firm resources on hand to cover a projected 111-GW peak in September; 100 GW available to manage a 92-GW peak in October; and 104 GW by the time November’s expected peak demand of 91 GW rolls around.

Still, September’s skimpy surplus means the RTO is not ruling out the possibility of emergency actions. The National Oceanic and Atmospheric Administration has said almost the entire MISO footprint should see a warmer-than-normal fall.

The grid operator said a high-outage scenario in September could possibly completely exhaust the 10.3 GW cushion of emergency operating reserves and load reduction. MISO said a higher-than-expected load of 117.5 GW could outstrip its fleet if only 104.3-GW of firm resources are available.

The RTO also said it might declare an emergency to dip into load-modifying resources in a worst-case scenario in October, when high outage rates could make only 95.3 GW of non-emergency resources available and demand surges to 97.5 GW.

MISO typically experiences 34.5 GW worth of generation outages in the fall, with about 11 GW of that forced. The RTO’s all-time fall peak load of 115 GW occurred in September 2017.

Summer Woes Still Top of Mind 

Most of the MISO community’s attention remains on the summer heat and how much worse it could be this time next year.

During a Market Subcommittee meeting Thursday, Independent Market Monitor David Patton said there may be cause for “heightened concern” next summer. He said he anticipates about 1.4 GW of generation heading into retirement between now and next year.  

Patton continues to insist MISO isn’t communicating all risk in its pre-season summer assessments, failing to account for generation derates during heat waves.

“As temperatures get hotter and hotter, the generating capacity of our thermal generation tends to go down,” he said.

Stakeholders asked how MISO can avoid ERCOT’s fate of never-ending warnings of summertime energy conservation. (See ERCOT Dances with Danger Again.)

“You don’t want to be ERCOT,” Patton said before adding, “Not to put too fine a point on it, but I’ve been telling MISO for ten years now that you’re going to have a resource adequacy problem.”

Patton said MISO needs a sloped demand curve in its capacity auction to produce “reasonable” and not “close to zero” prices, allowing some resource owners to make enough money to stave off retirement.

“We haven’t done it, and we’ve needed it. And now I think we’ll do it,” he said of the demand curve changes. “It’s not rocket science.”

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DC Circuit Court Backs FERC over MISO Interregional Cost Allocation

The D.C. Circuit Court of Appeals on Friday sided with FERC over Entergy Arkansas in a disagreement concerning MISO’s cost allocation for interregional transmission projects with other RTOs.

The court rejected Entergy’s appeal and kept the current cost allocation in place for MISO’s share of interregional projects rated from 100 to 345 kV. The ruling supports FERC’s decisions to allow cost recovery of lower voltage transmission projects beyond the pricing zone in which they are located (20-1262).

MISO’s portion of its interregional market efficiency projects (MEPs) with PJM and SPP are divvied up based on an adjusted production cost savings calculation that finds benefits beyond a project’s own zonal borders. MISO and SPP have never approved an interregional MEP, but MISO and PJM have.

Entergy argued that power flows are different between lower and higher voltage projects, making the benefits of lower-voltage projects limited and locally concentrated.

Entergy also argued the commission was incorrect to refuse a 2019 MISO proposal that limited the cost recovery of projects under 230 kV to the transmission pricing zone they are located in. It said FERC’s substitute solution based on adjusted production costs savings was inadequate.

But the court, quoting a previous return-on-equity case, noted that “FERC is not required to choose the best solution, only a reasonable one.”

“It is not our job to determine that ‘FERC made the better call,’ rather, our ‘important but limited role is to ensure that the Commission engaged in reasoned decision-making — that it weighed competing views, selected a … formula with adequate support in the record and intelligibly explained the reasons for making that choice,’” the court wrote, citing 2016’s FERC v. Electric Power Supply Ass’n Supreme Court ruling.

The court also pointed out that MISO is still free to propose a different cost allocation for FERC’s review.

The commission twice rejected MISO’s cost-sharing design for interregional MEPs before directing the grid operator in 2019 to use a design based on adjusted production costs savings for economic interregional projects 100 kV and above. (See Another Rejection for MISO Cost Allocation Plan.)

The back-and-forth at the time was because of MISO and PJM approving their first major interregional transmission project. MISO said that because a $22 million reconstruction of the Michigan City-Trail Creek-Bosserman line in Indiana was only a 138-kV project, it could not allocate costs beyond the transmission pricing zone where the grid operator’s share of the project was located.

MISO currently has a FERC-sanctioned mismatch between the voltage thresholds it uses for its regional and interregional MEPs. The RTO uses a 230-kV threshold for MEPS in its footprint and relegates lower voltage projects to an “other” category, where they’re ineligible for cost recovery from multiple pricing zones. (See MISO Cost Allocation Plan Wins OK on 3rd Round.)

In 2016, FERC lowered MISO’s interregional economic project voltage threshold from 345 kV to 100 kV after a 2013 complaint before the commission by Northern Indiana Public Service Co. over the MISO-PJM interregional planning process.

The Circuit Court’s agreement that lower-voltage transmission projects can deliver benefits regionally might have implications for other past cost-allocation decisions on MISO MEPs.

The commission has repeatedly refused to entertain competitive developer LS Power’s argument for a lower voltage threshold on economic transmission projects in the MISO footprint (EL19-79; ER20-1723-001). (See FERC Spurns LS Power’s Voltage Threshold Argument.)

LS Power has tried for two years to persuade FERC that the RTO should use a 100-kV threshold for market efficiency projects instead of the 230-kV cutoff the RTO was cleared to use in mid-2020. The company has contended that MISO’s 230-kV threshold is arbitrary because projects with voltages down to 100 kV can deliver significant regional benefits.

FERC has held firm that small, regionally beneficial projects are the exception, not the rule, and do not justify opening more projects to competitive bidding.

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California PUC Opens ‘Critical’ Demand Flexibility Proceeding

The California Public Utilities Commission launched a proceeding Thursday aimed at shoring up grid reliability and soaking up more electricity from renewable resources by using real-time rates to influence customer demand.

The new order instituting rulemaking (OIR) is intended to “enable widespread demand flexibility through electric rates,” the commission said in a news release. “The concept of demand flexibility allows consumers to play a key role in the operation of the state’s electric grid by reducing or shifting their electricity use during peak-use periods in response to a price signal or other incentive.”

A major goal is reducing solar curtailment by increasing electricity use during the day, when solar power is abundant and demand low, including by charging electric vehicles during those times.

“I want to highlight the importance this rulemaking is going to be and the critical role it’s going to play in designing our future grid,” Commissioner Darcie Houck said. “It’s probably one of if not the most, important rulemakings we’re going to do during my term here as a commissioner.

“Our electric grid was originally designed with the assumption that customer demand for electricity was inflexible, and during the majority of the last 140 years, that was the correct assumption,” Houck said. “Customer demand was indeed inflexible. We did not have the tools or the technologies to manage demand, nor did we necessarily need to do so because we relied on energy supply being flexible.”

“As we move toward a very different energy landscape … we need to make adjustments,” she said.

California has experienced reliability crises in recent years as it attempts to reach its 100% clean energy goal by 2045 as extreme weather, prolonged drought and massive wildfires plague the West. The retirement of fossil fuel plants and their replacement with weather-dependent variable resources has exacerbated the problem.

Energy emergencies occurred the past two summers in California during heat waves, when solar ramped down in the evening and demand from air conditioning remained high. In one instance last July, a wildfire shut down major transmission lines from the Pacific Northwest, exacerbating tight supply.

In August 2020, CAISO was forced to order rolling blackouts during a severe heat wave, when imported electricity from the Desert Southwest dwindled and triple-digit temperatures continued after dusk.

In response, the CPUC issued expedited decisions last year to try to bolster reliability in the next three summers.

One of those decisions expanded existing demand-reduction efforts, and another created new ones, including two pilot programs to test the effects of dynamic rates that change rapidly based on grid conditions, including energy emergencies. (See CPUC Proposes Summer Reliability Measures.)

The new demand flexibility proceeding is connected with a June 22 white paper by the CPUC’s Energy Division that examines using advanced technologies and real-time price signals to encourage consumers to cut back on energy use when supply is tight and prices high, and to charge EVs or run their dishwashers when prices are lower, such as during the day when solar power is plentiful and cheap.

The white paper addresses the challenges the state faces while transitioning to clean energy and electrifying transportation and buildings. Scaling up demand response programs to cut energy consumption at key times is among its priorities.

The state’s current patchwork of DR programs, which pay customers to reduce consumption, is insufficient, it says. The white paper identifies strategies for broadening demand-side efforts, including by introducing dynamic energy prices based on real-time wholesale energy costs and localized marginal costs and making sure consumers have easy access to those prices online.

A workshop on the white paper is scheduled for this Thursday.

The demand flexibility rulemaking will address issues, outlined in the order, such as how the CPUC should “update its rate design principles to enable widespread demand flexibility to improve system reliability and advance the state’s climate goals in an affordable and equitable way.”

Two or more working groups will develop proposals for the proceeding. The CPUC expects to issue a scoping memo this fall followed by a proposed decision, with a commission vote in the first half of next year.

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PJM, AEP Address Ohio PUC on June Storms, Power Cuts

The powerful mid-June storms and demand surges in central Ohio forced American Electric Power (NASDAQ:AEP) to cut power to more than 150,000 customers to prevent further system damage, the company’s top executives told Ohio regulators Wednesday.

More than 21,000 of the customers who lost power were in Columbus, prompting angry residents at the time to allege that the company balanced its system on the backs of the poor.

“I believe [circuit trips] are attributable to the storm plus the load that came on after,” explained Toby Thomas, AEP senior vice president for energy delivery. “The reason I say that is the system load was [increasing the day after the storm]. We had fewer facilities left to serve the load, and the load was increasing significantly and very quickly.”

The high winds affected 34 69-kV lines, 29 138-kV lines, one 345-kV line and 81 transmission-connected substations, according to the information the company submitted to the Public Utilities Commission of Ohio.

There are no significant generation sources in Columbus or nearby suburban communities, leaving the company few options as PJM grid managers informed AEP it would lose more of its system if it did not reduce load, Thomas said.

“The storms impacted a number of bulk electric systems throughout this state, as well as many other states,” Mike Bryson, PJM’s senior vice president of operations, told the commission. “Ohio was probably hit the worst of all the states.

“As the day [June 13] proceeded, we were in what PJM calls a hot weather alert, which is temperatures exceeding 90 degrees [Fahrenheit] in the area. AEP and Ohio were in that condition.

“Several transmission lines tripped in and around Columbus. When one of these lines goes down, other lines in the system have to carry that electricity, and if enough lines go down, the surrounding lines begin to reach or exceed their operating limit,” Bryson explained.

The RTO’s system analysis, which is constantly refigured as data on the condition of transmission lines come in, showed the remaining power lines were in jeopardy.

PJM issued a load-shed directive to AEP because of three heavily overloaded lines, Bryson said. “AEP had five minutes to implement this directive from PJM.”

PUCO staff have been ordered to review the PJM analysis, as well as the scenarios that AEP Ohio said it faced, and issue a report.

The Ohio Consumers’ Counsel has asked for an independent analysis by an independent auditor.

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ERCOT Dances with Danger Again

Continued record electric demand driven by triple-digit temperatures, 13 GW of thermal outages and reduced renewable production forced ERCOT to issue its second conservation appeal of the week Wednesday to Texans and businesses.

The Texas grid operator was expecting demand to peak at nearly 78.5 GW on Wednesday. By late morning, its supply and demand curves indicated more than a 2-GW gap during the afternoon peak between the fast-starting resources on top of the committed capacity and projected demand.

Demand eventually averaged almost 78.3 GW during the hour ending at 5 p.m. CT, falling just short of the record set Tuesday at 78.4 GW. It was the eighth record for peak demand ERCOT has set since May.

The grid operator expects demand to again exceed 78 GW on Thursday. It has peaked above 78 GW all week.

ERCOT issued its conservation appeal at 11:52 a.m. CT, asking Texans to voluntarily conserve electricity between 2 and 9 p.m. It said no outages were expected at the time.

“We want to be respectful of Texans, so we will only call for conservation if we need it,” staff said in an email to RTO Insider.

Staff said Monday’s conservation appeal successfully reduced demand by about 500 MW.

The grid operator’s operations center issued a watch because of a projected reserve capacity shortage without a market solution that could lead to an energy emergency alert. The watch, like the conservation appeal, was the second of the week. (See ERCOT Flirts with Capacity Shortage.)

“Today, there is a lot of variability,” staff said.

Dallas Forecast (WFAA-TV) Content.jpgDallas Forecast | WFAA-TV

 

ERCOT said the forced thermal outages exceeded its forecasts. It was expecting only 67 of its 80 GW of installed thermal capacity to be available during the afternoon’s tightest hour (3-4 p.m.). Wind generation was again below its historical usage, but cloud cover in West Texas initially reduced the amount of available solar generation by almost 2 GW.

Operating reserves stayed below 3 GW during much of the afternoon.

Interim ERCOT CEO Brad Jones reminded the Houston Chronicle on Tuesday that the grid operator is now calling for conservation earlier to help the grid avoid emergency conditions.

ERCOT deployed 927 MW of non-spinning reserves at 12:39 p.m. and then called on emergency response service at 2:55 p.m. shortly before physical responsive capability fell below 3 GW. That forced dispatchers to issue another advisory.

There is little respite in the future. Texas has already suffered through its hottest May and June on record and meteorologists expect more of the same through July. Heat advisories remain in effect for much of the state.

ERCOT on Monday night issued the season’s sixth operating condition notice (OCN), its lowest-level market communication, in anticipation of possible emergency conditions through Sunday. Staff expect temperatures above 103 degrees Fahrenheit in its North Central and South Central weather zones.

Prices hit four figures by 1 p.m., reaching the $5,000/MWh offer cap by 3 p.m. and $5,500/MWh heading into the hour ending at 7 p.m.

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With California in Lead, Clean Truck Sales Accelerate Nationwide

California is leading a trend of growing zero-emission truck deployments across the U.S., a new report shows.

A total of 1,895 zero-emission medium- and heavy-duty trucks were purchased and deployed across the U.S. from January 2017 to March 2022, with 1,133 of the vehicles rolled out in California, according to the report released Thursday by CALSTART, a national nonprofit focused on clean transportation technologies.

New York had the second-largest zero-emission truck deployment in that period, with 134 ZETs purchased and placed into service, followed by New Jersey and Colorado, which had 65 and 57 ZETs deployed, respectively.

The report is an update to an earlier CALSTART ZET inventory report released in January. The new report covers vehicle classes 2b to 8, which range from larger pickup trucks to big rig trucks.

Broken down by vehicle type, 742 yard tractors were purchased and deployed over the study period, making them the largest category of ZETs. That was followed by step vans, with 521 ZETs purchased and deployed.

“Zero-emission yard tractors and other vehicles with low-range requirements are dominating MHD ZET deployed sales,” the report said.

Eighty-four heavy-duty ZETs, in vehicle classes 7 and 8, were rolled out during the study period. Although some other vehicle types had a bigger number of ZETs deployed, heavy-duty ZETs had the largest average annual growth rate from 2017 through 2021, at 1,400%, according to the report.

The trend for heavy-duty ZETs is expected to continue as more manufacturers enter the market and others expand their offerings.

‘Strong Growth’ for ZETs

Although the number of ZETs is small relative to the 26 million medium- and heavy-duty trucks registered in the U.S. in 2021, ZET sales are climbing. Looking at year-over-year figures, ZET sales grew by 78% in 2018, 26% in 2019, 65% in 2020 and 155% in 2021.

“The U.S. [medium- and heavy-duty] ZET market is experiencing strong growth,” the new report said.

In addition to zero-emission trucks that are already on the road, CALSTART said in its earlier report that there were more than 140,000 pending orders for commercial ZETs awaiting fulfillment.

Some companies have announced plans to expand their ZET fleets. For example, Amazon has pledged to buy 100,000 zero-emission delivery vehicles over the next eight years, the report noted.

In June, outside the timeframe of the new report, FedEx received its first 150 electric delivery vehicles from BrightDrop, a General Motors subsidiary. The Zevo 600 vehicles were provided to FedEx Express locations in Southern California, the company said in a release.

Under an agreement between FedEx and BrightDrop, FedEx will add 2,500 Zevo 600s to its operations over the next few years. FedEx plans to move to an entirely zero-emission parcel pickup and delivery fleet by 2040.

Policy Plays a Role

California has been able to take the lead in ZET deployments in large part due to its strong ZET policies, the CALSTART report said.

California runs the Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project (HVIP), a program that has provided $542 million to help fund the purchase of 5,337 ZETs, the report said.

In 2020, the California Air Resources Board adopted what it called a first-in-the-world rule that will require truck manufacturers to sell an increasing percentage of zero-emission trucks based on their total California sales starting in 2024.

States including Washington, Oregon, Massachusetts, New Jersey and New York have adopted California’s Advanced Clean Truck rule. And 15 states and the District of Columbia signed an agreement in 2020 to work together to accelerate truck electrification.