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November 14, 2024

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Report Details Challenges for Meeting Oregon ZEV Goals

Current trends suggest that Oregon will come up short of its zero-emission vehicle adoption goals over the next decade, but near-term policy developments, expanded buyer incentives and buildout of a reliable charging network could salvage the outcome for 2035, a new report said last week.

Oregon’s ZEV registrations reached 33,579 in 2020, up 20% from the previous year but well below the state’s target of 50,000, according to the Biennial Zero Emission Vehicle Report released by the state’s Department of Energy (ODOE).

As of June, 38,482 light-duty ZEVs were registered in the state, representing about 1% of all registrations, the report said.

“While ZEVs are increasingly popular, the state did not achieve its 50,000 registered ZEVs by 2020 goal, and it is not on track to achieve the 2025 or 2030 goals,” the report’s authors said. “However, Oregon is well positioned to increase ZEV adoption with policies and programs that support ZEV sales in Oregon, including incentives, to help reduce upfront vehicle costs.”

A 2019 Oregon law outlines the state’s clean vehicle targets, which include:

  • 250,000 registered ZEVs by 2025;
  • at least 25% of registered vehicles and 50% of new vehicles sales be ZEVs by 2030;
  • at least 90% of all vehicles sold annually be ZEVs by 2035.

The ODOE report found that the COVID-19 pandemic likely contributed to the 2020 shortfall but was not the sole factor.

“In early 2019, ZEV adoption was growing quickly, boosted by the first year in sales of the Tesla Model 3. By the end of the year, ZEV growth had slowed as Tesla completed backorders for the vehicle and resumed more normal vehicle production,” the report said.

With the onset of the pandemic last year, vehicle production and sales fell nationwide in April and May because of shutdowns at auto factories and dealerships. Overall new vehicle registrations in Oregon fell by about 23% to 165,770, while new ZEV registrations fell 8% to 6,532, bumping the ZEV market share for new cars from 3.3% to 3.9%.

Additionally, registration numbers for all vehicles last year likely did not reflect the total number of vehicles in the state because of delays in registration while the Department of Motor Vehicles allowed for a grace period during the pandemic.

Near-term Uncertainty

The ODOE report describes the heavy lift required to get the state back on track to meeting its next set of ZEV targets.

“In order to achieve the 2025 goal of 250,000 registered ZEVs, the market share of ZEVs would need to grow from 4% in 2020 to more than 47% in 2025 — more than a tenfold increase,” the report said.

Oregon would need to see a drastic uptick in ZEV market share over the next four years in order for the state to meet its 2025 goal to have 250,000 ZEVs on the road. | Oregon Department of Energy

Furthermore, to reach the target of 25% of registrations by 2030 (equating to about 1 million vehicles), ZEVs would need to comprise 50% of new car sales by 2026, ODOE found.

The required growth curve in Oregon’s ZEV market share “exceeds all recent EV market share forecasts by leading studies and is twice that of the most aggressive curve forecasted by the Electric Power Research Institute, which was included in a recent report from the University of Berkeley.”

Achieving such a steep trajectory of ZEV growth would require Oregon to outpace the country’s leading EV adopter, California, which currently last year had nearly 133,000 ZEVs on the road and an 8.1% ZEV market share. The California Air Resources Board (CARB) has estimated that ZEVs will make up 15.4% of that state’s market share in 2025, compared with the 47% market share Oregon would require to reach 250,000 ZEVs that year, ODOE pointed out.

In May, CARB proposed its Advanced Clean Cars II program, designed to boost California’s ZEV and plug-in hybrid electric vehicle (PHEV) market share to 26% by 2026, 60% by 2030 and 100% by 2035. But even if those growth estimates are applied to Oregon’s projected ZEV market share, the state will come up 100,000 vehicles short of its 2025 goal and 460,000 vehicles short of its 2030 goal, the ODOE report said.

Still, ODOE sees some hope that Oregon could meet its 2035 goal.

“Oregon is too early in the ZEV technology adoption curve to assess progress on the ZEV adoption goal of 90% ZEV market share by 2035. But because the goal is strictly based on market share and not total registrations, there is some qualitative evidence that the goal is achievable. Many vehicle manufacturers have indicated they will be ramping up production of ZEVs and, in some cases, phasing out production of internal combustion vehicles altogether,” the report said.

Furthermore, the report notes, ZEV production and adoption could get a boost after the International Energy Agency in May said that sales of cars with internal combustion engines must be phased out by 2035 for the world to meet net-zero CO2 emissions by 2050 and limit the increase in global temperatures to 1.5 degrees Celsius. (See IEA Paints Daunting Path to Net Zero by 2050.)

State Efforts

Oregon is taking its own steps to encourage the purchase of EVs. During its most recent session, the state legislature increased the amount of money the Department of Environmental Quality can make available through its Charge Ahead rebate program. Low- to moderate-income residents will now be eligible for up to $5,000 in rebates for the purchase of a new or used ZEV, on top of $2,500 in federal rebates.

“Higher upfront costs for EVs and a limited used vehicle market remain barriers to EV adoption for low-income families,” the ODOE report said.

In addition, the state’s Transportation Electrification Infrastructure Needs Assessment (TEINA) Advisory Group this year issued a study containing recommendations for state officials to consider in developing a network of EV charging stations that will encourage ZEV adoption. The wide-ranging report focuses on the needs of various vehicle classes, income levels, housing types and geographic locations. (See Oregon Study Charts Explosive Growth of EV Chargers.)

The ODOE report reiterated some of the findings of the TEINA study and additionally emphasized a set of key elements necessary for a successful public charging network, including open access, multiple payment options, pricing transparency and accessibility for people with disabilities.

“Widespread electric vehicle charging infrastructure is considered essential to the continued adoption of EVs,” ODOE said.

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California Earmarks $3.9B for ZEVs Through 2024

California lawmakers devoted a record $2.7 billion toward zero-emission vehicle programs in FY 2021-2022 and $1.2 billion over the next two fiscal years in their session that ended Sept. 10, accelerating the state toward its goals for decarbonizing the transportation sector.

The funding for zero-emission trucks, buses and passenger vehicles was far more than the $1.5 billion that Gov. Gavin Newsom proposed in January. (See Calif. Governor Proposes $1.5 Billion for ZEVs.)

“This is definitely a historic amount for California,” said Miles Muller, an attorney with the Natural Resources Defense Council. “It sets an example for other states and the federal government by saying that if we’re serious about the climate crisis and getting people into electric vehicles, California is dedicating the money to help realize that future.”

The budget plan passed this summer allocated $2 billion for medium- and heavy-duty ZEV incentives and infrastructure, including $1.3 billion over the next three years to deploy 1,000 zero-emission school buses, 1,000 zero-emission transit buses and 1,000 zero-emission drayage trucks.

The state budget includes funding for electric school buses. | Lion Electric

It also included $1.2 billion to promote consumer adoption of zero-emission passenger vehicles.

Programs that promote ZEV ownership among lower-income residents, including incentives under the state’s Clean Cars 4 All program, received $400 million over three years in the budget plan.

The state’s Clean Vehicle Rebate Project (CVRP), which offers rebates of up to $7,000 for the purchase or lease of new ZEVs, was awarded $525 million over three years. The program ran out of money earlier this year, resulting in a long waitlist for rebates.

CVRP funding wasn’t included in Newsom’s January budget proposal, which upset some lawmakers. (See Newsom’s $1.5B ZEV Plan Takes Flak from Democrats.)

Assembly Budget Committee Chairman Phil Ting said in a March hearing that CVRP had put hundreds of thousands of Californians into hybrid and EVs over the past decade and remains the best hope for wide-scale adoption. The 2021-2022 budget fixed the omission by providing $175 million in upfront funding for each of the next three years.

The plan approved in mid-July also put $407 million toward for zero-emission public-transit bus and rail equipment.

“These investments will prioritize projects that directly benefit priority populations and improve air quality in low-income and disadvantaged communities,” a summary of the climate-change portion of the budget said.

Newsom’s January plan proposed funding ZEV programs by securitizing revenues from vehicle registration fees. Lawmakers pushed back against that proposal as the state projected up to $75 billion in surplus revenues this year.

The vast sums in the budget could help the state fulfill former Gov. Jerry Brown’s 2018 target of putting 5 million ZEVs on the road by 2030 and Newsom’s executive order in September 2020 banning sales of new gas-powered passenger vehicles by 2035. The state remains far behind on both goals. (See Can California Meet Its EV Mandates?)

The investments are also being pitched as a spur to the economy. The state is home to 34 ZEV-related manufacturers, including Tesla, and ZEVs became the state’s No. 1 export in 2020, the budget summary said.

“California is committed to develop the zero-emission vehicle market equitably, not only as a foundation tool to protect public health and combat climate change, but as an engine of economic development and job creation,” it said.

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ERCOT Finds 345-kV Solution for Valley Constraints

ERCOT staff said Wednesday they are recommending one of two options for a 345-kV line in the Lower Rio Grande Valley, a region identified as in urgent need of more transmission capacity by the grid operator and state regulators.

The project would add 351 miles of transmission lines radiating from a new substation in the Valley and create a link from the border to San Miguel south of San Antonio. The projected cost of $1.28 billion is $60 million cheaper than the other short-listed option.

Staff told the Regional Planning Group that the preferred alternative would improve reliability in the region and address stability constraints. Seven of ERCOT’s 16 generic transmission constraints are in the Valley, which sits at the edge of the Texas Interconnection with limited and long-distance transmission circuits.

The project will meet future load growth and generation development with reliable long-term infrastructure, staff said, and minimize the construction’s effect on the existing system.

The region’s system can currently serve up to 3.2 GW of demand, according to a recent ERCOT assessment. However, there are only four conventional power plants in the Valley, generating a total of 1,461 MW, making it reliant on imports. If the wrong two plants go out of service, 77% of that capacity is lost.

The Valley’s renewable resources are taking off.  | ERCOT

Potential LNG and other industrial load additions in the Valley could trigger the need for system improvements before the proposal’s targeted implementation by 2027.

“Our focus is to address the part of the system needed to reliably serve the Rio Grande Valley load,” ERCOT’s Shun Hsien Huang said.

The proposal will be taken up by the Technical Advisory Committee and then the Board of Directors in the fourth quarter this year, Huang said.

Brad Jones, the grid operator’s interim CEO, included the need for new capacity because of the region’s transmission limitations in his 60-point roadmap to grid reliability. The Texas Public Utility Commission also discussed adding transmission in the Valley during its most recent open meeting. (See Texas PUC Considers Adding Grid Interconnections.)

Huang said the project is preferable to adding a second 345-kV circuit to an existing line as suggested by the PUC. That idea would require taking the line out of service for one or two years.

Renewable resources have ballooned along with the region’s population and offer some support. Wind and solar capacity in the region didn’t crack 1 GW until 2012 but is expected to reach 7 GW, when including planned projects, by the end of this year.

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FERC OKs CAISO Emergency Interconnection

FERC granted CAISO’s request for a tariff waiver Wednesday that allowed the ISO to immediately connect two temporary 30-MW generating units for grid reliability, though the commission cautioned it not to expect such waivers again (ER21-2753).

“Given the exigent circumstances currently faced by CAISO, we find that good cause exists to grant this limited waiver as another tool to help CAISO address [its] anticipated capacity shortfalls,” Chairman Richard Glick and Commissioners Allison Clements and Mark Christie wrote in their majority decision, to which Commissioner James Danly dissented. “But we emphasize that CAISO must make every effort to avoid these sorts of waiver requests in the future.”

California continues to face potential shortfalls this year during late-season heat waves and wildfires. State agencies and CAISO have been acting since July 30 under an emergency proclamation by Gov. Gavin Newsom to prevent blackouts or close calls like those the state experienced in August and September 2020 and again this July. (See CAISO Declares Emergency as Fire Derates Major Tx Lines.)

The governor ordered the state to license new emergency and temporary power generators of 10 MW or more that can be connected to the grid before Oct. 31. In response, the California Department of Water Resources (CDWR) procured trailer-mounted, 30-MW gas generating units that can be installed in days, start up in five minutes and ramp to full capacity within a half hour.

The U.S. Department of Energy granted CAISO an emergency order Sept. 10 allowing the units and other fossil fuel generators to potentially exceed federal pollution standards. (See DOE Orders CAISO Emergency Reliability Measures.)

FERC’s waiver applied to two of the CDWR units to be installed at the former Greenleaf 1 energy center in Yuba City, where a mothballed cogeneration plant remains connected to the CAISO grid with an interconnection service capacity of 49.2 MW. That means the new units required approval for only a 10.8-MW increase in interconnection capacity, FERC said.

The site is owned by Calpine and falls within Pacific Gas and Electric’s (NYSE:PCG) service territory. CAISO, PG&E and Calpine “intend to amend their existing generator interconnection agreement and market agreements to reflect these interconnections once the commission has ruled on this petition,” FERC said in its order.

Danly Dissents

“CAISO seeks this latest emergency relief because of the ongoing and persistent failure of its markets to attract and retain adequate resources to maintain reliability,” Danly wrote in a scathing dissent.

The waiver “only applies to two resources, but I have little doubt the majority would grant the same waiver the next time, and the next time, and indeed, every time there is an emergency,” he said.

Moreover, he said, the waiver allowed CAISO to connect the new resources on the same day the order was issued. Changes to its interconnection terms with Calpine and PG&E and “conditions of its filed rate” would follow.

That made the waiver “illegal” under the filed-rate doctrine and longstanding commission precedent, he said.

The majority said Danly’s argument “misunderstands CAISO’s request and the waiver granted here.”

“CAISO’s tariff expressly provides for a waiver of timelines to meet requirements imposed by regulators or by the governor of the state of California,” the majority said. “Indeed, CAISO has requested the waiver in order to satisfy a proclamation issued by the governor. This tariff provision provides sufficient notice to regulated parties, meaning there is no filed-rate doctrine problem here.”

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OSW, GHG Bills Go to California Governor

Measures tackling offshore wind, building decarbonization and other energy-related topics landed on the desk of Gov. Gavin Newsom this week after lawmakers completed their 2021 session and Newsom survived a recall effort.

One measure, Assembly Bill 525, by Assemblymember David Chiu, a San Francisco Democrat, would instruct the California Energy Commission to develop planning goals for offshore wind generation for 2030 and 2045 and to coordinate with state agencies to develop a strategic plan for OSW development, to be submitted to the legislature by June 2023.

Chiu’s bill passed the state Senate on Thursday, 38-0, followed Friday by an Assembly vote, 74-1, concurring in the Senate’s amendments.

“The signs of the climate crisis are all around us,” Chiu said earlier this year when the measure passed the Assembly Natural Resources Committee. “With offshore wind, we have an opportunity to counter the threat of climate change, meet our clean energy goals, and create thousands of new good-paying jobs in the process.”

The Biden administration announced in May it plans to offer leases for the state’s first offshore wind areas — a 399-square-mile block off Morro Bay in Central California that could support 3 GW of wind generation and the Humboldt Call Area off Northern California, large enough for an additional 1.6 GW. (See BOEM to Offer Leases for Calif. Offshore Wind.)

Another bill that reached the governor deals with greenhouse gas emissions from the production of cement, a key ingredient in making concrete, the world’s most common building material. California no longer has coal-burning power plants, but eight cement kilns continue to burn coal, releasing carbon dioxide.

Senate Bill 596, by Sen. Josh Becker (D) of San Mateo, would order the California Air Resources Board to develop a strategy for decarbonizing by July 2023 and set a goal of achieving net-zero greenhouse gas emissions no later than December 31, 2045. It cleared the Assembly on Thursday, 74-2, and the Senate on Friday, 29-9.

“This bill positions California to develop a model strategy to shrink cement’s huge carbon footprint, while continuing to grow our economy and protect public health. Governor Newsom should quickly sign it into law,” Alex Jackson, a senior attorney with the Natural Resources Defense Council, said in a statement after the bill’s passage.

The California Energy Commission recently began looking more seriously at decarbonizing building materials as part of the state’s GHG reduction strategy. Cement production accounted for 1.8% of GHG emissions in 2017, according to the California Air Resources Board. (See CEC Targets ‘Embodied Carbon’ in Buildings.)

Newsom has until Oct. 10 to sign or veto the measures.

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Lawsuit Questions Feasibility of Gas Turbine for Enbridge Compressor Station

A group of Massachusetts municipalities, together with climate and health activist groups, argued in the First Circuit U.S. Court of Appeals on Tuesday that Enbridge’s calculations in support of using a gas turbine to power the Weymouth Natural Gas Compressor Station are based on outdated and unreliable information.

The municipalities and community groups suing Enbridge and the Massachusetts Department of Environmental Protection (DEP) say the natural gas distribution company and government agency showed negligence in their use and approval of the gas turbine. 

The attorney representing the petitioners, Michael Hayden, said the cost effectiveness threshold from the DEP that Enbridge used to verify the economic feasibility of the gas turbine over an electric motor needs to be updated. 

For nitrogen oxide (NOx), guidance from DEP on best available control technology (BACT) — a pollution control method under the U.S. Clean Air Act — says technologies in or below the range of $11,000 to $13,000/ton of NOx removed per year are considered cost effective. That range, however, is from 1990.

An expert among the petitioners investigated the manufacturer specifications of an electric motor option, as well as worst case emissions scenarios under low temperatures, low load and start up and shutdown conditions, and recommended an updated cost effectiveness threshold of $20,350 to $24,050, Hayden said.

The DEP has acknowledged in the past that the range needs to be updated but has not yet updated it, making the range from the 1990s part of the rulemaking process for projects such as the Weymouth Compressor station.

In the final decision on remand, DEP hearing officer Jane Rothchild recommended updating the dollar amounts used for the cost effectiveness determinations to reflect a cost range that accounts for inflation since 1990.

Enbridge previously argued before the DEP that installing an electric motor drive would be too expensive, due to the cost of electricity.

And the department’s cost effectiveness calculation “excluded more than $12 million in capital infrastructure costs needed to run the electric motor at the site,” the attorney for the DEP, Seth Schofield, argued before the court. Yet the DEP still calculated the average cost effectiveness of an electric motor is $192,500/ton of NOx, exceeding by a “dramatic margin” the performance cost effectiveness range, Schofield said.

Residents near the compression station, however, say the infrastructure costs are a price Enbridge can afford to pay.

Gas-fired engines are often used to run compressors, but methane emissions can result from the engine, incomplete combustion or system interruptions, according to the U.S. Department of Environmental Protection (EPA). The agency also says that installing electric motors in the place of gas-fired turbines decreases gas losses, limiting pollution.

Electric motors also reduce the chance of methane leaking from a compressor station because they do not use fuel gas. They require less maintenance and are more efficient than gas turbines, according to the EPA.

The federal agency reported methane savings ranging from 40,000 to 16 million cubic feet/year with electric motors.

The Weymouth Compressor station has shut down four times since it began operating last year, resulting in the emergency release of at least 300,000 standard cubic feet of gas. In another incident on May 26, Enbridge vented 11,397 cubic feet of gas in a controlled release, according to the company’s reporting to DEP.

“Given that they went $82 million over budget to fight to place [the compressor station] in our neighborhood, and now they will be spending tens of millions to dig it back up because they ‘forgot’ to put in safety measures that could’ve been put in when they were constructing, we just don’t understand what a measly $13 million is [to Enbridge],” the grassroots organization Fore River Residents Against the Compressor Station wrote on its Facebook page.

The material used to build the pipeline corrodes in salt water, so the pipe — the length of 400 football fields — will need to be dug up again for reinforcement.

The petitioners argue it was an “abuse of discretion for the department not to revisit the cost effectiveness range between the June 2019 recommended final decision, when it was first put on notice that the range is outdated, and the remand procedure where the range remains outdated and unreliable,” Hayden argued.

Last year, DEP revised its decision on the BACT based on evidence presented by Enbridge. Towns around the project and several concerned residents challenged the decision in a remand adjudicatory hearing presided over by Rothchild, who found DEP properly conducted its analysis and approved the air permit.

A state air permit for a compressor station in Virginia was thrown out in federal court because regulators didn’t consider an alternative electric compressor that would reduce air pollution from the facility.

The court wrote in its decision that “environmental justice is not merely a box to be checked, and the board’s failure to consider the disproportionate impact on those closest to the compressor station resulted in a flawed analysis.”

Last year, the Massachusetts Attorney General’s office submitted a brief to the Department of Public Utilities stating that the Weymouth Compressor station is not in the public interest, so the department should deny the company’s petition for approval because the costs of the compressor station are passed off to ratepayers.

Quincy, Braintree and Hingham, Mass., along with 10 individual citizens, first filed the petition for review of the final decision after remand about the Weymouth Compressor motor in the First Circuit U.S. Court of Appeals in February (City of Quincy, et al. v. Massachusetts Department of Environmental Protection).

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NERC-ERCOT Report Reviews Texas Solar Issues

Recent issues with solar photovoltaic (PV) resources in Texas should serve as a warning sign that the power industry is not moving fast enough to implement the recommendations in NERC’s reliability guidelines, according to a new report released by NERC on Wednesday.

However, NERC’s report also identified shortcomings by NERC and FERC that should be addressed to prevent future issues.

Causes of reduced output from solar PV facilities following the BPS fault event. | NERCThe Odessa Disturbance report is a joint effort by NERC and the Texas Reliability Entity that mainly covers a bulk power system disturbance that occurred on May 9 near Odessa, Texas, though a smaller, similar event on June 26 is also covered in an appendix to the report. The Odessa Disturbance, as it has come to be called, resulted in a total reduction of output of 1,340 MW; the second event led to a reduction of about 697 MW.

The event began at a combined-cycle power plant near Odessa on the morning of May 9. Prior to the disturbance solar PV and wind facilities accounted for about 9% and 34% of ERCOT’s total internal net demand of 47,434 MW, with the rest covered by synchronous generation.

Issues Began at Combined-cycle Plant

Around 11:21 a.m., an A-phase-to-ground fault occurred on a generator step-up (GSU) transformer at the plant, caused by a failure in a surge arrester at the combustion turbine (CT), which was undergoing start-up for testing at the time. Protective relaying on the GSU cleared its fault within three cycles, and subsequently the faulted CT was tripped offline as well. Because of the GSU fault, as well as a steam turbine power reduction at a different unit at the same facility, the plant lost 192 MW of generation.

The fault and generation loss caused voltages in the area to be depressed on the 345-, 138- and 69-kV networks during the on-fault conditions. This “perturbation in system voltages and phase angles” in turn caused more than 15 solar PV and four wind facilities in the area to suffer reduced voltage as well; a map in the report shows that solar facilities reported “abnormally responding to the event” as far as 200 miles away from the combined-cycle plant.

NERC’s analysis mainly focused on the solar plants, including those with battery energy storage (BES) facilities and only covering the generators that experienced a reduction of more than 10 MW. The report identified seven causes of power reduction at the facilities:

  • Phase lock loop loss of synchronism (389 MW) — seen at two large BES facilities and attributed to the manufacturer of the inverters at the plants. NERC said it has seen this cause of tripping in previous similar events and considers it “a systemic concern” for facilities with the same equipment.
  • Inverter-level instantaneous AC overvoltage (269 MW) — because oscillography data is only collected at the point of interconnection, NERC was unable to discern the extent of this type of tripping. NERC said it has identified this condition in “nearly all large-scale solar PV tripping events” that it has analyzed.
  • Momentary cessation with plant-level ramp rate interactions (153 MW) — seen in one plant with legacy inverters that use momentary cessation when the voltage falls below 0.9 pu. In this case, rather than allowing the inverters to recover to predisturbance output quickly when voltage recovered, the plant-level controllers interfered to slow the recovery because of balancing authority ramping requirements. NERC identified this as an inappropriate application of BA limits.
  • Feeder-level instantaneous AC overvoltage (147 MW) — one facility had set its targets for feeder-level protection trip on instantaneous phase AC overvoltage to 1.2 pu. The plant’s inverters responded to the fault by reducing active current to zero, injecting reactive current, and then injecting active and reactive current after fault clearing. This increase in reactive power drove feeder voltages above the target and caused them to trip.
  • Inverter-level underfrequency (48 MW) — likely caused in error after a “poorly measured or calculated frequency signal,” as frequency never fell outside the boundaries established by reliability standard PRC-024-3 (Frequency and voltage protection settings for generating resources).
  • Feeder underfrequency (21 MW) — a feeder-level relay at one plant operated on underfrequency, tripping 21 MW of inverters. Subsequent analysis found the relay was set to trip immediately after underfrequency detection, rather than the 5-cycle delay recommended by the manufacturer.

Another 51 MW of reduction was attributed to unknown causes because of lack of sufficient data at the facility for useful analysis. Additionally, 34 MW of reduced output at various solar facilities fell below the threshold for detailed review.

Recommendations for Multiple Stakeholders

The review team concluded the report with several recommendations for registered entities, FERC, NERC and ERCOT.

Share of inverters involved in the disturbance by their manufacturers. The company with the smallest share is no longer manufacturing large-scale inverters, leaving the field donated by two companies. | NERCFor registered entities, NERC said the incident made it clear that “industry is not adopting the recommendations contained within NERC reliability guidelines” despite their wide dissemination among stakeholders. The report advised generator owners and operators, developers, and equipment manufacturers to adopt the guidelines’ performance recommendations and urged transmission owners to “establish (or improve) clear and consistent interconnection requirements” for the implementation of NERC’s reliability standards.

The report’s advice for FERC includes revising the commission’s Generator Interconnection Process and Generator Interconnection Agreement to add “comprehensive requirements that [are] clear, consistent and ensure reliable operation of [inverter-based] resources.”

The largest share of recommendations is for NERC itself: first, the authors urge the organization to make “significant enhancements to the NERC reliability standards” to address the performance gaps revealed by the events in May.

Examples of needed changes are a “performance validation standard” that would clearly require transmission operators, reliability coordinators, and balancing authorities to report performance abnormalities to NERC and their regional entity and correct them in a timely manner. Also recommended is a standard “focusing specifically on generator ride-through performance” to replace PRC-024-3, which has “caused significant confusion for inverter-based resource controls and protection within the individual inverters.”

In addition, NERC is urged to update its standards to “address modeling and studies gaps for inverter-based resources”: for instance, through requiring that accurate EMT models be created at the time of interconnection, and to establish a “feedback loop to ensure model accuracy,” conducted regularly by transmission planners and PCs.

Finally, the report recommends that ERCOT conduct a detailed model quality review for all inverter-based resources connected to its system to identify “any control or protection function that can trip the facility.” NERC also suggests that ERCOT perform a gap analysis of its interconnection study process to find areas of improvement and a system-wide model validation effort, while ensuring that the recommendations in NERC’s reliability guidelines are adopted to prevent future issues.

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New Yorkers Debate Clean Energy Policies at IPPNY Fall Conference

Experts from across New York’s energy industry on Wednesday discussed how to best deal with global climate change, foster new technologies and ensure that the state leads the nation in clean energy while maintaining economic competitiveness.

“My priority is how do we evolve our industry, maintain reliability, and reach the goals of the Climate Leadership and Community Protection Act [CLCPA] of 2019 through competitive markets and private investment, which are really the linchpin to helping consumers prosper in New York state,” Independent Power Producers of New York CEO Gavin Donohue said at IPPNY’s 36th Annual Fall Conference.

Donohue said IPPNY last month partnered with the AFL-CIO and the New York State Building and Construction Trades Council to submit a petition to the Public Service Commission requesting the development of a market for zero-emission technologies that will help meet the state’s goal of net-zero electricity by 2040.

The petition urged the PSC to establish a competitive program to secure investment in 1 GW of zero greenhouse gas emission resources by 2030, and to include prevailing wage clauses in project labor agreements (15-E-0302). (See NY Generators Seek State Incentives for New Clean Energy Resources.)

Today the dispatchable fuel in New York is natural gas, while in 2030 or 2035 it could be renewable natural gas, or hydrogen fuel cells, “not to mention the potential for carbon capture and sequestration,” Donohue said. “It could be a technology none of us have even thought of yet.”

New Leadership, Goals

New York has a new governor in Kathy Hochul, the first woman to serve as the state’s chief executive, and she has established new clean energy goals since taking office Aug. 24, said New York State Energy Research and Development Authority CEO Doreen Harris.

“The announcement to sign legislation requiring the transition to 100% sales of zero-emission passenger vehicles by 2035, that’s cementing our role as a leader in this space,” Harris said. “She’s been present when we’ve held events [and] it is clear to me and to others that she’s there to support not only the industry and the process, but also the outcomes as being hugely beneficial across New York.”

Harris said she’d been pleased to see the IPPNY petition filed with the PSC and looks forward to learning more about the topic, receiving comments, and ultimately developing an approach to realizing the technologies needed in support of the 2040 emissions-free power target.

The CLCPA also calls for the procurement of 6 GW of solar by 2025, 3 GW of storage by 2030, and 9 GW of offshore wind by 2035, and all targets are on track, she said.

Asked about responsible siting of large-scale renewable energy resources, Harris said that “from the perspective of host communities directly, we have an entire clean energy siting team, and their sole job is to bring information and resources to bear on those same host communities, because ultimately we need information to be flowing in both directions to get these projects right. And they do need to be permitted to begin paying on our contracts, so ultimately we need the projects to advance in a manner that can be successful in that process.”

Goodbye Gas?

NYISO has repeatedly emphasized the need for dispatchable generation to firm up variable resources in a way that ensures the grid remains stable 24/7, 365 days a year, Donohue said.

Achieving the CLCPA goals will require transitioning the existing natural gas infrastructure to providing lower carbon fuels in the future, said Donna DeCarolis, president of the National Fuel Gas Distribution Corporation.

“In New York state we have 49,000 miles of underground natural gas delivery systems — 10,000 miles in western New York, and it’s really storm-resistant in the coldest weather,” DeCarolis said.

She cited the 2006 “October surprise” ice storm in western New York, and a 7-foot snowfall in November 2014, during which “natural gas was being delivered to homes without interruption, so that’s just an important resource that we want to consider, and it also provides a great deal of storage as well.”

The New York Climate Action Council’s Power Generation Advisory Panel in May decided to recommend that the full council adopt a moratorium on building new gas-fired power plants and related infrastructure — with the caveat that it did not achieve consensus on the idea. (See NY Power Panel to Recommend Gas Infrastructure Moratorium.)

Many studies say that in 2040 New York will need between 17,000 and 25,000 MW of rapid-start, dispatchable units that can run for a long time, said John Reese, senior vice president at Eastern Generation.

“Currently, for those to be non-fossil fuels we require magic,” Reese said.

The studies assume there are renewable natural gas units of some type that supply that need, but those are proxies, he said. Other potential solutions such as green hydrogen or long-term batteries could materialize, but “technology development is not easy and infrastructure in New York is not easy and we have very little time. I believe we need a moonshot-like level effort to ensure that we have the kinds of technologies we need to keep the lights on.”

It’s “a heavy moment” and in many ways the urgency of climate change and the impacts that New York is already experiencing grow larger every day, and the hardest impacts hit disadvantaged communities of color, said Kit Kennedy, senior director of the Climate & Clean Energy Program at the Natural Resources Defense Council.

“The work that New York state and the Climate Action Council are engaged in is more important than ever, literally a matter of life and death for increasing numbers of people,” Kennedy said. “But there’s still room for optimism and hope. The CLCPA is such a historic, transformative piece of legislation, and it gives me hope that New York is going to be a great leader on climate as it has been for a long time.”

From the perspective of large energy consumers, it appears that all the major decarbonization efforts are being funded by electric and gas customers through their energy bills as opposed to being covered from all sectors of the economy, said Couch White partner Michael Mager, who represents Multiple Intervenors, a coalition of large electricity users in the state.

“Our concern is that, from an economic development perspective, continuously increasing the cost of energy in the state is the wrong way to go,” Mager said. “We understand that sometimes it’s the politically expedient way … but we think that continuously expecting that energy consumers will fund the entire order or a predominant share of the cost of the CLCPA” is not fair.

Release of the Council’s draft scoping plan “will change everything,” Mager said. “We hope to see an estimate of CLCPA costs as well as of benefits.”

Carbon Pricing 

Carbon pricing in the electricity sector “is a very elegant answer to a problem, and it allows regulatory bodies to ratchet down the available carbon tons that are out there as the price increases,” Reese said. A carbon price sends a very clear economic signal, “so I remain a very strong advocate of that as being the most cost-effective and transparent way to get there; however, I despair that it actually can happen given today’s panorama.”

Anything that puts a price on carbon emitters is an important tool in the toolbox but not at all a panacea, Kennedy said. “I would never trade carbon pricing for the CLCPA. At some point, in some form it could be an add-on, but not a standalone, silver-bullet solution.”

Regarding the carbon pricing proposal advanced by NYISO, Mager said some of his concerns are related to the impacts on the New York economy, if the state is the only one to do it. (See FERC OKs Carbon Pricing Policy Statement.)

“We also questioned whether it made sense to only apply it to the electric energy sector and to not have it be applied on a more general statewide basis,” Mager said.

It’s best to keep policies technology-neutral and technology-inclusive whenever and wherever possible, said Dr. Melissa Lott, director of research at the Columbia Center on Global Energy Policy.

“We can often fall into this trap of picking a single winner, and at the end of the day that really undermines our progress over all, if the goal is to get to zero emissions or 90% or anywhere really ambitious,” Lott said.

Policy makers and industry leaders have also debated whether it is better to adopt a carbon tax or a clean energy standard, which Lott called a false choice.

A modest carbon price can still produce a signal in conjunction with standards and it “can actually make a clean energy standard much more efficient to have that price working in the background,” Lott said. “Whether it’s 70% by 2030 or 100% by 2035 or 100% by 2050, if it’s the CLCPA or a federal standard, you know these studies about how we can actually make policies as efficient as possible are really important.”

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DOE Puts $16 Million into Community Clean Energy Plans

The Department of Energy launched its new Communities Local Energy Action Program (LEAP) on Wednesday with a roundtable focused on the kinds of community-led clean energy projects the $16 million initiative will seek to foster through a range of technical assistance options.

“Too often, low-income communities and communities of color don’t see the benefits of clean energy in their neighborhoods; too often, clean energy projects skip over the communities that need them the most,” Energy Secretary Jennifer Granholm said in her opening comments. She said the program will work with up to 36 communities, helping each “to develop a locally driven clean energy action plan; so, after 12 to 18 months, each community will then be prepared to work with DOE long term and to leverage more resources from the federal government and from philanthropy and from the private sector.”

The program is targeted at “communities that are experiencing environmental injustice or climate impacts or economic stress from the shift away from fossil fuels,” Granholm said. “Communities also have to be experiencing high energy costs and have 30% or more of residents that are low income to be eligible for this.”

Wednesday’s rollout begins a four-week comment period ending Oct. 12, according to a release from DOE. Applications are due Dec. 17, with the announcement of program participants expected in March 2022.

While not providing direct funding, Granholm described the program as a “down payment for the investments we will continue to make” in environmental justice, low-income and fossil-fuel communities.

As defined in the program announcement, technical assistance will include “expertise and resources” provided by DOE. For example, the department could provide a community “with an analysis of clean energy planning and development opportunities based on current infrastructure, workforce availability, energy resource potential [and] utility regulatory structure.”

Projects eligible for the program include renewable energy planning and development, microgrids for community resilience, building energy efficiency and electrification, clean transportation, and carbon capture and storage.

Communities ‘in the Driver’s Seat’

Community development and environmental experts and advocates speaking at the roundtable emphasized the importance of community-based project development.

“What’s exciting about the premise [of LEAP] is a realization that the people in these communities and the communities themselves are not the problem,” said Michael Tubbs, former mayor of Stockton, Calif., and now an adviser to Gov. Gavin Newsom. “They are actually the solution. When you speak about listening to and putting the community in the driver’s seat, it’s just a realization that there is the asset and solution.”

Roundtable participants said the program is a good first step, but some adjustments could be needed.

Stephanie Tyree, executive director of the West Virginia Community Development Hub, said drawing investment to coalfield communities in her state is difficult. But, she said in a phone interview with NetZero Insider, “no projects can be successfully implemented without a very well thought-out plan and without technical expertise to make the projects work.” LEAP will “give us access to technical expertise that we don’t normally have a direct pipeline to, or we don’t have the resources to pay for.”

She would like to see the program open to regional clusters of communities, rather than individual cities or towns, and the “anchor organizations” they work with, as described in the official announcement.

“I really hope that the DOE will consider allowing projects from anchor institutions that are bringing together multiple rural communities, working together with a regional strategy,” she said, noting that her organization often works with communities of 2,000 to 15,000 people.

“We find in rural places, regional strategies and partnerships work best for capacity building and for really driving the types of projects that are transformational for our communities,” Tyree said. “We think about it as not necessarily bounded by a census tract [or] geography; it’s really the sense of community that’s defined by the people.”

Tatewin Means, executive director of the Thunder Valley Community Development Corp., said her organization could use investment and policy support for its “regenerative community” of energy-efficient, solar-powered homes on the Pine Ridge Reservation in South Dakota.

“We face significant barriers here at the state level when it comes to incentivizing clean energy and moving more communities in that direction,” Means said. “There’s just no real incentive for energy distributors and producers to shift their practices. Having outside support and encouragement [for] a positive policy shift would be most helpful, especially to states like South Dakota that aren’t as progressive or as far along in our fight against climate change.”

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MISO Stakeholders Blame Entergy for Long-range Transmission Impasse

Some stakeholders directed blame this week at Entergy for obstructing grid planning in MISO South.

During a Tuesday meeting of MISO’s Board of Directors, former FERC Commissioner and Iowa Utilities Board Chair John Norris admonished the RTO for not directing meaningful planning and allowing Entergy to influence long-term planning decisions.

Norris said he had reservations when he sided with FERC’s order to approve Entergy’s MISO membership in 2013.

“I must say though, that I did not, nor did my colleagues, suspect that by 2021 no advancement in the regional transmission planning would have taken place,” he said.

Not having expanded the transfer constraint between MISO Midwest and MISO South for more than six years is unacceptable, Norris said. He said the restricted transfer between the regions “begs the question: ‘What’s the point?’”

The long-range transmission plan “is already five years too late,” Norris told MISO board members.

“MISO has to plan the grid that the future needs today,” he said.

Norris said MISO is being “held hostage” by “anti-competitive” MISO South members and has allowed them to grind the long-range transmission plan “to a halt.”

“MISO needs to lead, not be led by members with parochial interests,” he said.

New Orleans-based clean energy consultant Andy Kowalczyk also said MISO South would be better served by RTO-led effective and competitive transmission planning.

“The regional grid should not be built to accommodate the economic self-interest of investor-owned utilities and doing so will not just risk the larger market, it will risk the stability of the grid and public safety by blocking more competitive and/or efficient options,” he told MISO directors.

Kowalczyk said Entergy Louisiana’s grid is both unprepared for a transition to clean energy and extreme weather events. He said he was forced out of his home for several days after Hurricane Ida.

“We’ve been given two warnings about the transmission grid in eight months with extreme weather events in the footprint, three in nearly a year if you count [2020’s] Hurricane Laura,” Kowalczyk said, referencing Hurricane Ida and Winter Storm Uri this year. “If the RTO is not assertive in deploying regional reliability projects for the next 20 years of challenges on the grid, the system will become a symbol for decline.”   

This isn’t the first time Entergy has been accused of stalling major MISO transmission planning. Renewable advocates involved in a Mississippi Public Service Commission docket said recently that the state and Entergy Mississippi, the latter threatened by the prospect of competition inching into its territory, deliberately delay large-scale transmission expansion efforts. (See Mississippi PSC Audit Questions MISO Membership.)

Kowalczyk also asked MISO to lead the cost-allocation effort and develop a mechanism that results in “projects being built, not something that checks all the boxes for some utility members.”

Deadlock over Allocation

Members are at a stalemate over how MISO should divide up potentially billions of dollars in its long-range transmission planning construction costs.

Xcel Energy’s Carolyn Wetterlin, chair of MISO’s cost-allocation working group, said stakeholders have not reached consensus on an appropriate cost-sharing plan. She said some believe the grid operator can reuse cost allocation from its 2011 Multi-Value Project (MVP) portfolio while others favor an entirely new plan and want different cost-sharing plans for the Midwest and South regions. Still other stakeholders remain keen on assigning some costs to interconnecting generators hoping for grid treatment.

“[MISO] is in a tough spot, trying to find a balance between those conflicting positions,” Wetterlin told the MISO board Tuesday.

Stakeholders have cautioned the RTO against proposing cost allocations for projects in MISO Midwest that are different from those in MISO South, saying it would effectively create a seam within the footprint. (See MISO Dusts off MVP Cost Allocation for Long-range Tx Plan.)

The grid operator might finalize a cost-allocation proposal for long-range projects sometime in November, drawing on MVP cost-sharing principles.

“The cost allocation, no surprise, remains challenging,” MISO Vice President of System Planning Jennifer Curran said.

She said the stakeholder community is unlikely to be in lockstep on any allocation approach or the project candidates themselves, calling broad consensus “elusive.”

“We remain focused on getting to a least-regrets collection of projects as quickly as we can,” she said. “At some point, more time won’t get us to consensus no matter how much more discussion we have.”

Curran said should MISO decide on a $30 million portfolio, for instance, the projects would be brought forward for approval over the next three to five years.

Insufficient High-voltage 

Aubrey Johnson, MISO’s executive director of system planning, said the RTO will have more than 5,000 miles in new transmission lines come online over the next decade that were approved under its previous MISO Transmission Expansion Plan (MTEP) cycles. He said only 232 miles of those new lines will be rated at 345 kV and greater.

On the other hand, Johnson said, all projects in the long-range transmission plan will be 345 kV or higher. He said firm transmission service for resources is crucial to MISO members being able to reliably serve load.

Johnson warned that an Organization of MISO States survey predicting adequate resources in 2022 doesn’t account for extreme weather events. (See 2021 OMS-MISO Resource Adequacy Survey Shows Less Cause for Concern.) Should MISO encounter extreme weather, he said, some local resource zones could be at risk of insufficient resources to serve load.

None of MISO’s long-range transmission projects will make the December cut for MTEP 21. Those projects will come before the board for approval in March at the earliest. (See MISO Targets March Approval for Long-term Tx Projects.) MTEP 21 currently includes 367 projects totaling almost $3.25 billion.

MISO has opened a stakeholder suggestion window for additional long-range projects. Jarred Miland, the RTO’s manager of transmission planning coordination, said staff may face a lot of work in analyzing project proposals.

“Are we going to get five solutions or 572? We’ll see,” Miland said during a long-range transmission workshop last month.

The monthly workshops on the long-range plan have become heated lately. In August, Miland told Bill Booth, a consultant to the Mississippi PSC, that he wouldn’t rehash why staff is conducting a transfer analysis as part of the long-range study.

Miland directed Booth to staff’s underlying reasons for the long-range plan: to support a renewables-heavy fleet and additional electrification, to ward off reliability violations, and to adapt to shifting flow patterns as aging plants retire and members up carbon-reduction goals.

WPPI Energy’s Steve Leovy repeatedly asked why MISO edited a reliability analysis presentation the day before the Aug. 27 meeting.

Staff said the presentation was reposted to correct typos. When Leovy continued to question their reasoning, MISO planners said they would not address it further. Leovy said he was “disrespected” and expected better of the grid operator’s management.

“I think we have a common goal of a safe, reliable transmission system,” WEC Energy Group’s Chris Plante said. “I really want to stress the importance of working together.”

The Union of Concerned Scientists’ Sam Gomberg told Leovy that his and others’ concerns were part of the reason MISO has held the monthly workshops. Gomberg called the meeting frequency an “arbitrary milestone.”

“This sort of hard, last-Friday-of-the-month might be an imposition here,” Gomberg said, suggesting that MISO could sometimes forgo a teleconference and simply post the latest results of analyses for stakeholder review.

Clean Grid Alliance’s Natalie McIntire thanked MISO planners for their “behind-the-scenes” work.

“It’s clear to me that the scope of this study is the largest and most complex scope that MISO’s ever done, larger than the [MVP portfolio],” she said.