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November 8, 2024

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ERCOT Preps for 2nd Cold Snap of Year

ERCOT is bracing for the second major cold front of the year, issuing an operating condition notice (OCN) for Thursday and Friday ahead of expected “extreme cold weather.”

Interim CEO Brad Jones assured the Board of Directors on Tuesday during the second day of a two-day training session that the OCN is just an initial step in the grid operator’s emergency alert system and that he was confident the grid will manage the situation.

“It’s not a significant reliability challenge,” Jones said.

The grid operator issued the OCN at 9:30 a.m., signifying a need for additional resources because forecasted wind chills dropped to a level where they could affect power plant operations. An OCN is still three levels away from an energy emergency alert.

Operations alert levels (ERCOT) Content.jpgERCOT’s operations alert levels | ERCOT

 

Staff said they are expecting demand to peak about 61 GW Thursday night and Friday morning and that they have about 79 GW of operating capacity available. Dan Woodfin, vice president of system operations, said the latter number is “significant” and a “little more” than the grid operator had at its disposal during a Jan. 2-3 cold snap. (See ERCOT, PUC Say Grid is Ready for Winter Weather.)

That did little to comfort some of the directors, who heard much about the lack of transparency between Texas’ electric and natural gas systems. The lack of thermal fuel supplies, primarily natural gas, have been fingered as the primary reason for the widespread power outages during last February’s winter storm. (See FERC, NERC Release Final Texas Storm Report.)

The electric industry has added weatherization requirements with regulatory teeth for its power plants since then, but the gas industry, regulated by the Texas Railroad Commission (RRC), has lagged behind. The commission is not expected to mandate strict weatherization practices until next winter.

Asked if ERCOT would have enough gas supplies for the system’s plants, Jones said staff have already received one notice of a gas restriction that could affect up to 1.5 GW of capacity.

“One of the concerns we have is the great deal of information we don’t have,” Jones said of the gas side. He said he has plans to add a gas desk in the operations center that would monitor gas availability or restrictions, an idea that he said was first brought up in 2015 when he was ERCOT’s COO.

“We had concerns [in 2015 that] we wouldn’t get the information we needed,” he said. “We’re still in the same situation. There’s not a great deal of transparency around the operations of our natural gas system. That information doesn’t usually flow to us.”

Jones and Peter Lake, chair of the Public Utility Commission, both pointed to the Texas Energy Reliability Council (TERC) as where dialogue and coordination between the two industries takes place. Lake said the group was an informal group before the winter storm, but that legislation last year formalized TERC and “designed it specifically for that kind of information sharing.”

TERC meets as often as twice a month, Lake said. However, the meetings are not public.

Director John Swainson pressed Lake on the RRC’s regulatory responsibility. Lake declined to speak for that commission, saying, “They do oil and gas. They’re sitting across the table from us at TERC.”

“Doesn’t that look like sort of a weakness in the system here?” Swainson asked. “We’re trying to ensure our generators can provide power, but if no one’s providing gas to our power plants, that’s a weak link.”

“That’s why the legislature gave us TERC, and that’s why TERC is meeting more frequently,” Lake responded.

Temperatures are expected to dip to as low as 16 degrees Fahrenheit on Thursday in some parts of the state, according to The Weather Channel. ERCOT’s meteorologist says “wind chills will be an issue” most of Thursday and that temperatures likely won’t make it out of the 30s that afternoon in most of the state. Winter precipitation is not expected to be a factor.

Woodfin said that about 11.8 GW of thermal resources are currently on outages, a normal amount for ERCOT.

Staff also updated the board on their weatherization inspections at power plants and transmission facilities, saying they have inspected 324 generation resources and 22 transmission sites. This followed receipt of winter weather readiness reports from 850 generators and 54 transmission service providers. (See ERCOT Generators Near 100% Winter Readiness Compliance.)

David Kezell, ERCOT’s newly hired director of weatherization and inspection, said the inspections found 10 potential deficiencies at dispatchable generation sites, not at intermittent renewable resources, and six at transmission facilities. He said all of the deficiencies are being tracked and that most have been resolved and closed.

“I believe the system is in much better condition this year than it was last year,” Kezell said.

With Kezell’s organization still staffing up, ERCOT was forced to rely on contractors to handle most of the inspections. Staff that were pulled from other departments helped with the more than 3,600 hours of work during the fourth quarter.

ERCOT filed a report on its winter weather readiness inspections with the PUC on Tuesday (52786, 52787).

The board also agreed with staff’s recommendation to reschedule its Feb. 8 meeting to March 7-8. Its meeting schedule was set under its previous format, which was overhauled by the Texas legislature following last year’s storm. Several of the new directors had conflicts with the February date.

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Report Shows Nevada Lagging 2030 GHG Target

A new report from the state of Nevada projects that the state’s greenhouse gas emissions in 2030 will be 24% less than in 2005 — far short of the 45% reduction that the state has set as a goal.

And the 24% projected reduction in 2030 is only slightly more than the 23% reduction expected by 2025. Nevada’s goal for 2025 is a 28% reduction in GHG emissions compared to 2005.

The figures are included in the state’s 2021 GHG emissions inventory and projections report, which the Nevada Department of Conservation and Natural Resources (NDCNR) released last week. The 2021 report details the state’s GHG emissions through 2019 with projections through 2041.

State Senate Bill 254 requires NDCNR to issue the report each year.

The report finds that the state’s electricity sector is on track to meet the renewable portfolio standard (RPS), which requires half of energy sold to customers to come from renewable sources by 2030.

But increased emissions from the transportation, industrial, and residential and commercial sectors “cancel out” progress made under the RPS, NDCNR said.

“Additional climate action is necessary to stay on track with the goals and reign in climate pollution across all economic sectors,” NDCNR said in a release.

The report lists an array of policies Nevada could adopt to potentially bring the state closer to its GHG reduction goals. They include implementing net-zero building codes, adopting California’s upcoming Advanced Clean Cars II regulation or integrating the social cost of GHG emissions in planning.

The report noted that the listed policies aren’t recommendations at this stage; further analysis of costs and benefits is needed.

Decreased Emissions

In 2019, Nevada’s net GHG emissions totaled 40.6 million metric tons of CO2 equivalent (MMTCO2e), an 18% reduction from 49.3 million metric tons in 2005. Nevada contributed 0.71% of the U.S. total for gross GHG emissions in 2019, despite having 0.94% of the population, the report said.

Transportation overtook the electricity generation sector in 2015 to become the state’s largest source of GHG emissions. Emissions from the industrial sector are also on the rise.

In 2019, transportation contributed 34% of the state’s GHG emissions, the report said, followed by electricity generation at 29% and industry at 17%.

Given the trends for the transportation and industrial sectors, “addressing GHG emissions from these two sectors should be a priority for policymakers in both the near- and long-term,” according to the report.

“It is also important to note that continued decarbonization of the electricity generation sector is needed to realize greater carbon reduction benefits of transportation sector electrification,” the report said.

Transportation Sector

GHG emissions from Nevada’s transportation sector hit a low of 13.5 MMTCO2e in 2011, but by 2019 had increased by about 18%. Highway vehicles and aircraft were the main drivers of the increase, the report said.

The report predicts that 2020 data will show a drop in transportation sector emissions, followed by a gradual increase through 2041.

“Generally, gains in emission reductions due to new federal and state regulations will be offset by population and economic growth,” the report said.

But NDCNR noted the “high degree of uncertainty” in making GHG projections for the sector. In particular, it’s not yet known how long the increase in teleworking seen during the COVID-19 pandemic will continue.

In October, the state adopted the Clean Cars Nevada program, which takes effect starting with model year 2025 vehicles. (See Nev. Adopts Clean Cars Rule, Allows Early Credits.)

The report noted that it will take several years for the program to start making a dent in GHG emissions. By 2041, transportation sector emissions are expected to be about 6% lower than they would have been in the absence of the program.

Electricity Sector

GHG emissions from the electricity generation sector dropped from 26.2 MMTCO2e in 2005 to 13.6 million metric tons in 2019, a 48% reduction. The report estimates emissions for all fossil fuel-fired electricity generated in Nevada, even though some of that electricity may be used out of state.

The report attributes the sector’s decrease in GHG emissions largely to the retirement of the Mohave Generating Station in 2005 and the Reid Gardner Generating Station’s last unit in 2017. The two coal-fired power plants were partially replaced with natural gas-fired plants. The increased use of renewable energy is another factor in the sector’s GHG reductions, the report said.

Nevada has two remaining coal-fired power plants: the North Valmy Generating Station, which could potentially retire in 2025; and TS Power, which is expected to be converted to a dual coal and natural gas plant.

The report projects that those changes will contribute to a reduction in emissions from the electricity sector to 8 million metric tons in 2041.

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Ohio Report Offers Policy Roadmap to EV Adoption

Ohio residents who buy electric cars face an annual $200 charge in addition to basic registration fees to make up for not paying 38.5 cents per gallon in motor fuel taxes.

The charge is one of the highest among the 20 states imposing the fees to make up for lost gas taxes used for road maintenance.

But it makes little sense in a state dependent on automobile and auto parts manufacturing, especially as the industry moves into EV manufacturing, argues a policy report issued Tuesday by the Citizens Utility Board of Ohio.

The ABCs of Ohio EVs: A Policy Guide to Electrify Ohio argues that electrification of transportation is happening whether Ohio lawmakers want it or not and that it’s already past time to begin building policies to encourage the transition in an orderly and rational manner.

At its core, the report argues that encouraging auto electrification could lower consumer electric rates because regulated utilities will be able to sell more power over the infrastructure now in place, a debatable contention.

“I would emphasize that the central point of this 28-page report really is that if we do this right, then everybody will benefit from the increasing penetration of electric vehicles whether they drive one or not,” said Martin Cohen, a principal of Martin Roth Cohen and Associates, an energy economics consulting firm that assisted in researching the report.

“There will be downward pressure on electric rates because we’ll have new volumes of electricity sold to charge these EVs at the same time, as [well as] cleaner air and less pollution,” Cohen said in a news conference announcing the report.

“The key is that we need to do this by using the existing infrastructure — generation, transmission, distribution — which we can do with the right policies and programs in place to use electric vehicle charging, which is a flexible load to fill in the valleys in demand for electricity.”

EV adoption will not increase the cost of the system, he added, and it will produce new revenue for the utilities, helping to lower or steady future rates.

Accelerating Adoption

The report also argued that widespread EV use is just around the corner — and not coming in the distant future.

In the first six months of 2021, the number of EVs registered in Ohio jumped from 14,530 to 28,595, rising to 1.72% of new car registrations, but still representing only one of every 300 registered passenger cars, according to the report.

That growth will accelerate, Cohen said. “EVs are really going to be a choice of consumers, which is why they’re going to mushroom. It’s not primarily because of policy.

“It’s because people like them, and they are so much cheaper to drive and have such low maintenance and so many improved performance characteristics over a comparable internal combustion vehicle that we do expect they are going to be very popular,” he said.

The report notes that GM alone plans to produce 30 new EV models by 2025 and only electric cars by 2035.  “With the impending introduction of a new generation of EVs with higher ranges and lower costs, a tipping point toward mass market adoption appears to be on the horizon.”

GM assembles cars in Ohio and makes parts in the state, such as transmissions, an item not used in electric vehicles.

Thomas Bullock, executive director of CUB Ohio, said the anticipated growth of EV sales is set to accelerate.  “We have 4.5 million cars on [Ohio] roads.  When 20% are electric, we could see a 10% increase in overall electricity consumption. That can happen in as quickly as 10 years,” he said.

Bullock noted that AEP Ohio, a subsidiary of American Electric Power, took the first step toward direct utility involvement in EV charging last year in a rate case that included language authorizing EV rates for a limited number of charging stations.

However, the report appears to suggest that utilities should stick to selling power to EV charging companies rather than build the stations. In other words, it’s an issue that requires a comprehensive state policy and not one that can be addressed piecemeal in utility rate cases.

The report also opens a debate about whether state public utility commissions have the authority to develop EV charging policies without underlying rules crafted by state lawmakers.  The Ohio legislature knocked down proposed legislation last year that would have lowered the $200 EV registration fee.

Bullock said the report will be sent to the Ohio PUC, the Ohio Consumers’ Counsel and the legislature. None were asked to participate in drafting the report.

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Federal Judge: Tx Line Can’t Cross Wildlife Refuge

The Cardinal-Hickory Creek transmission project is “incompatible” with southwestern Wisconsin’s protected Driftless Area, a federal judge ruled last week in blocking construction in the region.

U.S. District Judge William Conley, with the Western District of Wisconsin, forbade the nearly $500 million, 101-mile 345-kV line from southwest Wisconsin to Iowa from making a beeline through the Upper Mississippi River National Fish and Wildlife Refuge (21-cv-096-wmc). A final judgement is pending.

Conley said project developers American Transmission Co. (ATC), ITC Midwest and Dairyland Power Cooperative violated federal environmental laws to secure permits for the line. He said clear-cutting and construction of transmission towers in the refuge would fragment habitat, adversely impact wildlife breeding, and permanently alter forest succession patterns — all “clear contradictions with the refuge’s purposes.”

ATC, ITC Midwest and Dairyland planned to begin opening up the project’s Wisconsin portion in early November. However, Conley agreed with several conservation groups and issued a preliminary injunction against the line. (See Conservation Groups Win Injunction vs. Cardinal-Hickory Creek.)

The utilities framed the line as a minor project in need of “a relocated right of way that results in a disturbance of some 30 or so acres … in the context of a 240,000-acre refuge.”

However, in a ruling last Friday, Conley said the route would cut through the heart of the refuge, disturbing 39 acres of land. He said the utilities had only secured permitting for nine of the acres.

Conley struck down the utilities’ arguments that one of the conservation groups didn’t have standing to sue and that the case was moot because they applied for a land transfer as an alternative to their right-of-way permit request.

The judge said that U.S. Fish and Wildlife Service, the agency responsible for right-of-way easement and special-use permits to cross the Upper Mississippi River National Wildlife and Fish Refuge, seemed to be “working hand-in-glove” with ATC, ITC and Dairyland. He said the only other line route alternative offered was a “nearly identical crossing” that indicated the service and the utilities were committed to carving a path through the refuge.

Conley pointed out that the utilities first sought a right of way in 2020, then an amended right of way, and later dropped the requests altogether. They recently proposed a land transfer with Fish and Wildlife instead of a permitting process.

“Suspiciously, all of these actions took place in the months after this case was filed,” Conley wrote, calling the sequence of events “thin porridge.”

“While the utilities have waffled between seeking another right of way or land transfers, at no point has Fish and Wildlife or the utilities suggested that the CHC would not cross the refuge,” Conley said. He said even if a new administrative record for a land exchange was opened, Fish and Wildlife would likely complete a nearly identical analysis to its right-of-way request.

Conley said the government agencies and utilities “appear to be playing a shell game, cavalierly revoking applications for and grants of permits.”

He also pointed out that Congress wrote the National Wildlife Refuge System Improvement Act of 1997 in order “to curb incompatible, secondary uses within refuges.”

“An incompatible use cannot become compatible simply by converting it to a land transfer,” he wrote.

Conley also ruled that the line’s environmental impact statement, prepared by the U.S. Department of Agriculture’s Rural Utilities Service, was inadequate and failed to comply with the National Environmental Policy Act (NEPA).

Conservation groups Wisconsin Wildlife Federation, Driftless Area Land Conservancy, National Wildlife Refuge Association, and Defenders of Wildlife argued in May that developers and government agencies ignored environmental harms when authorizing the line.

Conley said it didn’t appear that the utilities considered increasing the transfer capability of nearby existing lines or pursuing electric storage projects as alternatives to major new construction.

He said it appeared that the Rural Utilities Service simply parroted MISO’s reasoning for proposing the line instead of independently scrutinizing the line’s functions. A decade ago, the RTO said the line would relieve transmission congestion, boost reliability and facilitate more interconnections of renewable generation to the grid. MISO also said Cardinal-Hickory Creek would negate the need for more than a dozen smaller line upgrades in the vicinity.

“Because RUS adopted MISO’s convoluted purpose statement, which then drastically narrowed the alternatives reviewed in the [environmental impact statement], that purpose statement fails to comply with NEPA,” Conley said.

The Cardinal-Hickory Creek line is the last of MISO’s $6.7 billion, 17-project Multi-Value Project portfolio approved in 2011.

Developers Vow Line’s Completion 

In a statement, ATC, ITC Midwest and Dairyland said the judge’s ruling has “no immediate impact on the co-owners’ ability to continue construction activities” after the first injunction was issued. The companies pointed out that a final judgement has yet to be issued and that they are to provide briefs on remedies by Jan. 24.

“The utilities are committed to completing this project, which will reduce energy costs, improve electric grid reliability, relieve congestion on the transmission system, support decarbonization goals and help support the interconnection of renewable generation in the Upper Midwest,” the utilities said.

Environmental Law and Policy Center attorney Howard Learner, representing the conservation groups, said it was clear that Cardinal-Hickory Creek’s route would harm the refuge and said it’s time for the developers to consider alternatives.

“Running a huge high-voltage transmission line with 20-story high towers through the national wildlife refuge is illegal and is contrary to common sense and sound policy,” he said in an emailed statement.

Learner said the permanent injunction “makes clear that the agencies and the transmission companies essentially rigged the environmental impact statement process to preclude fairly evaluating alternatives to the huge, proposed transmission line.”

He said there exist “less expensive alternatives, that are less environmental damaging to the scenic Driftless Area’s vital natural resources, family farms and communities, and that create more local opportunities for clean energy progress in Wisconsin.”

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DC Circuit Rebuffs DOE on Boiler Efficiency Rule

The Department of Energy must provide better justification for its 2020 rule increasing the energy efficiency standards of boilers used in commercial buildings and multifamily housing, the D.C. Circuit Court of Appeals ruled Tuesday, giving the department 90 days to respond.

In issuing the remand, the court said DOE exaggerated the savings that would result from its rule on commercial-packaged boilers. The rule was more stringent than the standards of the American Society of Heating, Refrigerating and Air-Conditioning Engineers (ASHRAE).

The Energy Policy and Conservation Act prohibits DOE from establishing a standard more stringent than ASHRAE’s, barring “clear and convincing evidence” that it is economically justified, technically feasible and will lead to significant energy savings.

Commercial-packaged boilers are gas- or oil-fired and have rated inputs of at least 300 kBtu/h and are used for space conditioning and/or water heating. DOE said the rule, which was set to take effect in January 2023, would save consumers $36,832 for a large oil-fired boiler, a payback of 2.7 years out of an estimated 25-year lifespan.

The rule was challenged by the American Public Gas Association, which represents publicly owned gas distribution systems; the Air-Conditioning, Heating & Refrigeration Institute (AHRI), which represents manufacturers; and Spire Inc., an owner of gas utilities, including Spire Missouri. The American Gas Association, which represents local distribution utilities, intervened in support of the challengers.

The three-judge panel — Chief Judge Sri Srinivasan, Circuit Judge Ketanji Brown Jackson and Senior Circuit Judge Douglas H. Ginsburg, who wrote the opinion — noted that the “clear and convincing evidence” standard “is unusual,” saying, “We are aware of no other authorization for rulemaking subject to this heightened evidentiary standard.

“This unusual framework creates an unusually strong bias in favor of the status quo,” it added.

Bad Assumptions

The law requires DOE to consider the difference in the life-cycle cost (LCC) of equipment with and without a more stringent standard and the projected energy savings likely to result from the standard. The LCC is the sum of the purchase price (including installation) and lifetime operating cost (fuel, maintenance and repairs), discounted to present value.

The LCC analysis required DOE to describe the mix of boilers if it issued no new standards versus the mix with the new rules.

DOE said it had historical shipping data — the most accurate picture of the mix of boilers in a world without new standards — for only two of the eight relevant categories of boilers. Thus, it assumed the distribution of efficiency levels in shipped equipment was the same as that found in models listed in the database maintained by the AHRI.

In its “no-new-standards case,” DOE assumed the distribution of efficiencies among shipped boilers is the same as the distribution of efficiencies across the models listed in the AHRI database.

“As a result, when the DOE ran trials randomly assigning boilers to buildings in the no-new-standards case, the chance a boiler with a certain efficiency level would be assigned to a building in the sample was equal to the percentage of boilers in the AHRI database with that efficiency level, without regard to the characteristics of the building to which the boiler was assigned,” the court observed. In doing so, the court found, DOE failed to acknowledge that a rational building owner would consider the costs and benefits of its new boiler purchase to produce the best economic performance for its building.

“If a purchaser selects the most efficient unit for its building, then the DOE’s model will assign the benefits of that choice to its rule, rather than attributing it, correctly, to the purchaser’s rational decision-making,” the court said, inflating the economic value of the more stringent standard.

The court said DOE was “dismissive” in rejecting comments challenging its random assignment.

“DOE essentially said it did the best it could with the data it had. This is not enough to justify assuming a purchaser’s decisions will not align with its economic interests in purchasing a boiler,” the court said. “Indeed, the DOE’s lackadaisical response would have been inadequate even if the rulemaking were not governed by a heightened evidentiary standard, for the DOE’s failure to ‘engage the arguments raised before it.’”

The court also said DOE “significantly overstated” the fuel cost savings from the new standard.

“Because operators of commercial packaged boilers are among the largest purchasers of fuel from energy utilities, they receive volume discounts and enter into hedging contracts, and therefore pay significantly less” than predicted average energy prices, the court noted.

And it said the agency exaggerated in estimating that the median burner operating hours — a “crucial” variable in the LCC analysis — for most burners was more than 1,000 hours per year.

It cited an AHRI consultant who said “commercial buildings are generally cooling load dominated, so it would be highly unusual to have 1,000 system operating hours per year.”

“By no stretch was this an exemplar of reasoned decision-making,” the court said. “A commenter pointed to seeming anomalies in the DOE’s data, and the agency ignored them.”

Remedy

DOE told the court it expected to be able to provide “a full and sound” justification satisfying the clear and convincing evidence standard.

“Under these circumstances, we think it should be afforded a limited opportunity to do so,” the court said. “Therefore, we shall remand the final rule to the DOE for the agency to take appropriate remedial action within 90 days. If the DOE fails to do so, the final rule will automatically be vacated unless the agency demonstrates within 10 days of the issuance of this decision the need for additional time.”

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ERO Align Tool Final Release Now Planned for Q4

The ERO Enterprise has begun rolling out the third release of the Align software platform and the ERO Secure Evidence Locker (SEL), but some of the functionality planned for the release has been separated out and will be released later this year, SERC staff said Tuesday.

Speaking at SERC’s 2022 Open Forum, Todd Curl, the regional entity’s senior manager for risk awareness and oversight, said that Release 3 of Align — which adds audits, spot checks, compliance investigations and complaints to the functionality covered in previous releases — went online in December.

A spokesperson from NERC told ERO Insider that REs are currently working out plans for training and adoption. Curl said SERC intends to conduct training sessions in the second quarter of 2022, “consistent with what several other regions are doing.”

NERC originally planned for Release 3 to happen in the third quarter of 2021, and to be the final stage in Align’s deployment. (See Release 2 of ERO Align Tool Goes Live for All Regions.) As intended, Release 3 would have also included inherent risk assessments and compliance oversight plans. However, the ERO Enterprise’s experience implementing the first two releases in 2021 led NERC to set more modest goals for the release.

“As the ERO Enterprise subject matter experts worked together to identify the specific requirements needed around this very large Release 3 functionality, it became clear that these processes, which had never before been automated or harmonized, would be simply too complex for one single release,” Curl said. “So, given the importance of the smooth transition for these processes to the effectiveness of the CMEP [compliance monitoring and enforcement program], there were some adjustments to the original plan.”

These remaining functions have been separated into a separate Release 4, which will roll out in the third or fourth quarter of 2022, according to NERC. As with previous releases, the functionalities added in Release 3 and 4 only apply to new cases. Registered entities should continue to process and submit supporting evidence for existing self-reports using their current tools.

First Two Releases Already Online

Release 1 and 2 of Align, along with the SEL, went live last year. (See ERO Align Tool Goes Live for NERC, MRO, Texas RE.) The first release took effect starting in March and covered creating and submitting self-reports and self-logs, creating and managing mitigating activities and mitigation plans, and responding to requests for information. The second, which came online in July, added technical feasibility exceptions, periodic data submittals, attestations and self-certifications.

Align began in 2014 as the CMEP Technology Project, with the rollout date originally set for September 2019; this was delayed because of concerns about the software vendor’s sale to an Australia-based company whose investors include a private equity firm based in Hong Kong. (See NERC Investigating Chinese Tie to Software Vendor.)

This security issue prompted NERC to include the SEL in Release 1 rather than debut it later as originally planned. Because the SEL is intended to provide secure storage where potentially sensitive information can be kept separate from work papers managed through the Align tool, it is not part of the main software package, and REs are allowed to construct their own lockers for CMEP evidence if they meet NERC’s reliability and security specifications.

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MISO’s Seasonal Capacity Proposal Opposed at FERC

Stakeholders last week had mostly negative reactions at FERC to MISO’s bid to reconfigure its resource adequacy design into seasonal auctions with availability-based resource accreditations.

DTE Energy characterized MISO’s new accreditation as a “severe over-correction” that is “based on chance.” It predicted year-over-year capacity credit volatility and generation overbuilt at the expense of ratepayers, should the proposal go into effect.

“MISO’s proposal would inappropriately require a resource owner to do what MISO cannot or will not do, namely predict when system conditions will be tight in advance,” DTE wrote in its protest. “Even if forecasts based on weather predictions and historical patterns were accurate enough to indicate potential operating periods of concern, tight conditions are also driven by unpredictable events such as other resources’ forced outages or transmission outages.”

Louisiana utilities Entergy and Cleco also said the design would expose market participants to an “unreasonable level of volatility.”

The Coalition of Midwest Power Producers said MISO failed to show how the new auction and accreditation design would stem the RTO’s tide of reliability issues and asked FERC to order a technical conference to investigate problems with the plan.

MISO late last year sought the commission’s approval to perform four seasonal capacity auctions, with separate reserve margins, by 2024 and apply a seasonal accreditation based on a generating unit’s past performance during tight system conditions (ER22-495).

The grid operator also filed separately to establish a minimum capacity obligation. MISO load-serving entities would have to demonstrate that they have secured at least 50% of the capacity required to meet their peak load in advance of voluntary capacity auctions (ER22-496). (See FERC Grants Comment Extension for MISO Capacity Filing.)

MISO originally intended the minimum capacity requirement be included in the seasonal auction design. However, stakeholders said including it in the same filing could risk FERC’s rejection of the entire resource adequacy modification. Written opinions on the RTO’s plans were due Jan. 14.

Multiple market participants said MISO’s requested effective date was too soon, since preparations are already underway for the 2023-24 planning year capacity auction(s).

The Clean Energy Coalition, which includes the Sierra Club, Sustainable FERC Project, Natural Resources Defense Council and Clean Grid Alliance, said the seasonal design “is rigid and does not allow for a changing risk pattern that will continue into the future as the resource mix continues to evolve.” The groups criticized MISO for not considering fuel supply risks in accreditation and for using different risk hours to accredit thermal resources and wind resources. The latter will continue rely on the RTO’s existing effective load carrying capability calculation.

They also said the accreditation proposal is incomplete because it doesn’t offer a capacity accreditation approach for electric storage resources.   

Ameren said while it can get behind seasonal auctions, it disagreed with the proposed accreditation because of the disparate treatment of resource types when calculating capacity credits.

WEC Energy Group objected to MISO’s plan to plump up seasons with low or no loss-of-load risk with a resource’s annual availability values for accreditation purposes. It said a resource’s capacity credits in low-risk seasons would “inappropriately include resource availability from other seasons.”

MISO’s transmission owners said while they supported a transition to seasonal auctions and availability-based performance incentives, they wanted the grid operator to explain whether it will continue to limit capacity accreditation to summer interconnection rights. In MISO, a market participant’s annual unforced capacity value cannot exceed the resource’s summer interconnection rights.

“If the proposed seasonal construct is implemented, MISO effectively will be limiting non-summer capacity accreditation to summer interconnection rights,” the TOs said.

The Organization of MISO States (OMS) was one of few to lend support to the seasonal plan, saying it represents an “improvement over the status quo.”

“While MISO cannot control when a generator or transmission line goes down or when and how an extreme weather pattern will affect the system, it can control the signals generators receive to be available in the face of uncertainty,” OMS said. “This proposal more accurately identifies seasonal risk than MISO’s current resource adequacy construct and more accurately accredits resources’ ability to contribute to the system during tight conditions.”

OMS said it is “entirely reasonable for MISO to require resources that receive capacity credit and capacity payments be available to offer energy for a large part of a given season.”

Not all state regulators were in step with OMS. The Mississippi Public Service Commission said the accreditation proposal “interferes with state jurisdiction over generation resource decisions because existing and future generation that does meet MISO’s criteria will be devalued as sources of capacity.”

The PSC said the accreditation is “untested” in any other grid operator and is “a costly experiment.”

The Louisiana PSC also panned the accreditation design as placing “too much significance on too small a sample size” of risky hours. It added that MISO’s month-long limit on planned outages in any season will cause “discriminatory treatment of generation that requires outages greater than 31 days, particularly nuclear generation.”

Manitoba Hydro also said while the filing may not be perfect, it is necessary to confront escalating reliability risks in the footprint.

International Transmission Co. invoked climate change in addition to the resource fleet’s continued transition as evidence that seasonal auctions and accreditations will be necessary. It urged FERC to adopt the resource adequacy overhaul.

Minimum Capacity Rule Draws Ire

The possible introduction of a 50% minimum capacity obligation also proved unpopular. Several said it was a pointless mandate.

The Illinois Commerce Commission protested the possible requirement as unproven and discriminatory against retail choice areas in MISO, which rely on “a robust competitive wholesale market” instead of regulated, integrated resource planning.

The ICC said the rule will “likely result in higher rates that are unjust and unreasonable and is likely to result in the exercise of market power.”

Big Rivers Electric Corp., Hoosier Energy Rural Electric Cooperative, and Southern Illinois Power Cooperative said MISO didn’t describe what reliability problems the minimum obligation is tailored to address.  

Shell Energy North America similarly said MISO didn’t explain its reasoning for introducing the rule. It said the grid operator’s worries about load-serving entities’ (LSEs) increasing overreliance on its voluntary auction are overblown.

“In the last 2021-2022 Planning Resource Auction, MISO procured 96.4% of its capacity from self-scheduled and fixed resource adequacy plan resources, up from 94.5% in the 2020/2021 auction. This trend shows LSEs are acquiring more resources on a forward basis counter to MISO’s claims,” Shell Energy wrote.

Exelon called the minimum capacity obligation “a solution in search of an unsubstantiated problem, which will impose regulatory constraints that will inevitably increase costs to customers.”

However, the minimum capacity rule had its defenders. Entergy said the requirement is a “practical safeguard to ensure that LSEs engage in reasonable resource planning practices” and don’t develop a dependence on the Planning Resource Auction. DTE Energy also called it a “necessary first step in maintaining local and regional reliability.” Duke Energy characterized it as a “a much-needed backstop.”

Consumers Energy said the rule would level the playing field between the LSEs under state obligations to plan their capacity procurement years in advance and those that aren’t. It called the rule a “gentle mitigating measure.”

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Concerns Arise over EV Truck Impact on California Grid Reliability

As the California Air Resources Board moves toward requirements to electrify truck fleets, concerns are surfacing about the demands large electric vehicles will put on an already-strained grid.

A wide range of stakeholders commented on the issue during a medium- and heavy-duty infrastructure workgroup meeting that CARB hosted last week as part of its process for developing the Advanced Clean Fleets regulation.

“We obviously have power delivery problems today in California,” said Thomas Jelenic, vice president of the Pacific Merchant Shipping Association (PMSA). “And as we intensify electrification, we become more vulnerable. So what we have been doing in the past is not sufficient.”

Jelenic asked how electric resilience would be provided to ports, which he described as “a node of everything heavy-duty that’s going to be electrified in the future.” He said a PMSA analysis found that California ports would need about 600 MW for future transportation electrification — seemingly more than a microgrid would provide.

The goal of the Advanced Clean Fleets regulation is to accelerate the adoption of zero-emission trucks and buses by requiring fleets that are well-suited for electrification to transition to ZEVs where feasible. An informal discussion draft of the regulation was released in September.

Wastewater Worries

Eva Plajzer, assistant general manager for engineering and operations at the Rancho California Water District in Temecula, called the timing of the regulation unrealistic. The proposed rule would require half of new vehicles purchased for public fleets to be electric starting in 2024, increasing to 100% in 2027.

Plajzer asked whether grid reliability issues would be addressed by the time the fleet regulations take effect.

“This is a tremendous concern,” Plajzer said. “When do you see having enough capacity on the grid where this reliability issue is no longer significant?”

Plajzer said Rancho Water, which provides water and sewer service, doesn’t have the luxury of taking several days off because of a power outage, such as a public safety power shutoff.

She said the district has about 8 MW of solar power. But it doesn’t have space to add the “football field of batteries” it would take to provide backup power supply, she added.

In a written chat comment during the meeting, Kiel Pratt, vehicle-grid integration unit supervisor at the California Energy Commission, suggested that Plajzer look at the Laguna Wastewater Treatment Plant in Santa Rosa. The plant has engines fueled by biogas produced on-site, he said, as well as a photovoltaic system and battery storage.

Jason Dake, vice president of legal and regulatory affairs for Orange EV, a manufacturer of industrial EVs, pointed to the challenges of terminal tractors that may be used around-the-clock at distribution centers. The trucks are often “clumped together” geographically in warehouse districts, such as those in the Inland Empire, he said.

“Terminal tractors don’t have routes,” Dake said. “They are located on that site. They charge continuously during the day. That presents a very localized stress on the grid.”

Another issue raised during the meeting is that truck fleets are typically in use during the day and therefore can’t charge during off-peak times when solar power is plentiful. Charging overnight may rely on gas-fueled power that doesn’t have the same emissions-reduction benefits, a participant said in chat-section comments.

Leslie Goodbody from CARB’s Mobile Source Control Division said the agency is aware of the issue.

Planning Ahead

Utility representatives who participated in the meeting urged stakeholders to let them know in advance of plans to electrify fleets.

“The key thing is lead time — letting us know sooner than later that you’re planning to electrify,” said Vishal Patel, principal manager of integrated system analysis at Southern California Edison.

“Getting that discussion started is really important for the utility to be aware so we can put that into our processes.”

The Jan. 12 workgroup meeting was the third in a series of sessions related to Advanced Clean Fleets. The meeting’s focus was electricity and the grid. CARB is now planning a follow-up meeting on a date to be determined.

Another meeting, focused on costs and funding, was scheduled for this week but has been postponed to a date yet to be decided.

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PJM Operating Committee Briefs: Jan. 13, 2022

Illinois Energy Transition Act Update

PJM updated stakeholders at last week’s Operating Committee meeting regarding ongoing discussions with the Illinois Environmental Protection Agency over the impacts of the state’s sweeping energy legislation passed in September that has it on a 30-year path to 100% carbon-free electric generation.

Chris Pilong-2018-12-11-(RTO Insider LLC) FI.jpgChris Pilong, PJM | © RTO Insider LLC

Chris Pilong, director of PJM’s operations planning department, provided an update on the Illinois Energy Transition Act and the RTO’s response. Signed into law on Sept. 15 by Gov. J.B. Pritzker, the legislation requires all investor-owned baseload coal-fired power plants and remaining oil peaker turbines to shut down by 2030. (See Illinois Senate Passes Landmark Energy Transition Act.)

Gas turbine plants, including ones currently under construction, must also close by 2045 under the terms of the bill, although the state has an option to allow continued operation if they are critically needed.

Pilong said the broad scope and impact of the legislation has created a need for generation owners and Illinois state entities to have discussions and resolve issues.

“We’re well aware that there’s still a number of unanswered questions that generator owners have with respect to the legislation,” Pilong said.

PJM has been focusing on and working with the Illinois EPA and other state agencies on language within the legislation permitting generators “out of run hours” in the near term if there’s a reliability need for the resources. Pilong said there’s not much detail in the legislation about what out-of-run hours mean, resulting in a “source of confusion” and questions about how it will be implemented.

PJM wants the EPA to “provide clarity” on the guidance for generators and to post the language publicly. Pilong said the RTO hasn’t drafted language yet on the issue to present to the EPA, but it plans on having draft language ready by the end of the month. He said PJM is focusing on five areas of reliability needs in the language, including capacity, thermal constraint control, reactive support, system restoration through black start resources and testing of resources.

The RTO has also performed some initial analysis to see if there were any concerns this winter with thermal or voltage constraints resulting from the implementation of the legislation, Pilong said, but it didn’t find any concerns. PJM is also looking at analysis of the medium- and long-term impacts of the legislation on generation.

Paul Sotkiewicz of E-Cubed Policy Associates said he had concerns PJM was “abdicating its reliability responsibility” in favor of the language in the Illinois legislation. Sotkiewicz said the Illinois EPA is not subject to oversight by FERC and NERC like PJM.

Pilong said the language PJM is working on with the EPA is meant to give generation owners “more confidence” that the RTO isn’t taking unilateral actions that will put them in conflict with the state legislation.

“We’re not looking to get the blessing from the state about how reliability is maintained,” Pilong said. “Illinois is well aware that’s PJM’s responsibility.”

Sotkiewicz asked if PJM is pushing Illinois to conduct a rulemaking process on the legislation, calling it “absolutely critical” to provide guidelines. He said PJM in the past has met with state staffs to explain what needs to be included in rulemakings to guarantee reliability in the RTO.

“You’ve been given the reliability needs, and a state could turn around and say, ‘No thank you,’ and you’re stuck with it,” Sotkiewicz said.

Stephen Bennett, PJM manager of regulatory and legislative affairs, said Sotkiewicz misunderstood. He said the Illinois EPA told PJM that the “omission of explicit language” authorizing rulemaking on the issue in the legislation was a “conscious choice” made by the legislature and that the agency “does not have the authority” to conduct a rulemaking process.

“PJM has been explicitly clear that PJM and our members need as much clarity as possible to allow for us to move forward with our No. 1 priority of managing reliability,” Bennett said.

Philips-Marji-2017-10-5-at-OPSI-Annual-RTO-Insider-FI.jpgMarji Philips, LS Power | © RTO Insider LLC

Marji Philips, vice president of wholesale market policy at LS Power, said her company believes the Illinois legislation could result in a reversal of some of the “extraordinary gains” made on emission reductions in PJM. The company’s analysis shows more coal plants could end up operating in Illinois and in other states to make up for the loss of generation resources, she said.

She asked PJM to help identify some of the “environmental consequences” of the legislation on other states in the RTO through additional studies.

“When you turn off natural gas in Illinois, that might mean a whole lot more coal runs in Indiana or Ohio, actually defeating the whole purpose of the legislation,” Philips said.

Dynamic Line Rating Issue Delayed

PJM is delaying requirement language for several manuals related to the implementation of a dynamic line rating (DLR) system in the RTO after a FERC decision in December that ended static ratings.

Chris Callaghan, senior business solution engineer with PJM’s applied innovation department, had presented a first read of a problem statement and issue charge regarding DLR at last month’s OC meeting. (See “Dynamic Line Rating,” PJM Operating Committee Briefs: Dec. 2, 2021.) PJM is looking to install sensors on or near existing transmission lines to collect real-time data. The technologies include weather stations, electromagnetic field detectors and thermal cameras.

Later that month, FERC ordered transmission providers to employ ambient-adjusted ratings for short-term transmission requests and seasonal ratings for long-term service. (See FERC Orders End to Static Tx Line Ratings.)

Callaghan said PJM is now waiting until the committee’s February meeting to conduct a second first read of the proposed problem statement and issue charge as the RTO’s legal staff reviews the commission’s order.

“We want to make sure we have time to digest the order and make sure we fully understand it,” Callaghan said.

Renewable Dispatch Endorsed

Stakeholders unanimously endorsed an issue charge aimed at improving dispatch of renewable resources and increasing forward-looking visibility.

Darrell Frogg of PJM’s generation department reviewed the problem statement and issue charge that were first presented at last month’s OC meeting. (See “Renewable Dispatch First Read,” PJM Operating Committee Briefs: Dec. 2, 2021.)

Frogg said that as the number of renewable resources grows, manually managing dispatch becomes more difficult and leads to inconsistent performance.

“We’re in the middle of a significant transition in fuel mix with a large influx of new solar and wind projects,” Frogg said. “We want to get ahead of this now before the next significant wave of new renewable resources becomes commercial.”

Key work activities of the issue charge include reviewing education on existing renewable dispatch practices, with a goal of proposing solutions to enhance the overall renewable dispatch process.

Frogg said stakeholder suggestions led to PJM adding education on renewable dispatch performance statistics, and solutions and practices from other RTOs/ISOs.

PJM also added the tariff term “intermittent resources” to go along with the term “renewable dispatch” to better align with existing language in the RTO’s governing documents. Frogg said PJM wanted to keep the issue broad to include all renewable resources.

Work on the issue charge will take place in the OC beginning in February and is estimated to take six months.

Frogg said PJM was originally looking to pursue the CBIR (consensus-based issue resolution) Lite approach to develop a proposal, but the issue charge was changed to use the normal process after several stakeholders questioned the RTO at last month’s OC meeting.

Manual 38 Revisions Endorsed

Stakeholders unanimously endorsed minor revisions to Manual 38 as a part of a periodic review.

Liem Hoang of PJM reviewed the revisions after first presenting them at the December OC meeting. (See “Manual 38 Changes,” PJM Operating Committee Briefs: Dec. 2, 2021.)

Hoang said the minor changes include adding language stating that the Eastern Interconnection Reliability Assessment Group will conduct “assessments to identify key reliability issues and the risks and uncertainties affecting adequacy and security of the bulk power system in the Eastern Interconnection.”

Members will vote on final endorsement of the changes at the Markets and Reliability Committee meeting Jan. 26.

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Tx Fault Could Trip Thousands of MWs of DERs, ISO-NE Study Says

A new study from ISO-NE offers a warning that distributed energy resources equipped with outdated inverters could be a weak link in the region’s grid as it continues to rely more on renewable generators.

A fault on New England’s transmission lines could bring down thousands of megawatts of DERs under certain conditions, with ripple effects that could move into neighboring power grids, the study found.

The study, which commenced in September 2020 as a response to changing conditions and stress on the region’s transmission system and published this month, used a broader lens than many previous reports.

It took a range of four load and solar output conditions (the “four corners” of a scatter plot containing historical daily data) and turned them into six base cases, rather than the more typical consideration of just peak and minimum loads.

Most worryingly, the report found that “significant” amounts of DERs could trip or experience temporary power reduction after a transmission line or transformer fault in the spring weekend midday minimum load case, which involves high solar output and relatively low power consumption.

Those trips could lead to serious impacts on New England’s grid and beyond.

“As much as 1,850 MW of DERs (which is 25% of DERs assumed online) could trip for a fault in New England, which is greater than the current loss of source threshold of 1,200 MW where New England events could begin to impact the New York and PJM systems,” the study says.

Daytime Min Condition (ISO-NE) Content.jpgThe spring weekend conditions which could cause large amounts of DERs to trip | ISO-NE

 

Up to 5,300 MW of DERs could also go into temporary power reduction, potentially causing “huge power swings within neighboring systems,” even though they would come back to full power output within 10 seconds.

A large piece of the challenge presented in the study is that many of the DERs are what ISO-NE calls “legacy” systems that have older inverters that do not allow them to “ride through” faults.

The RTO tested several mitigation strategies, including replacing those legacy inverters with new inverters, enabling dynamic voltage control on new DERs, turning generators into condensers and reducing solar output. But none of those solutions offered enough improvement in the system conditions to alleviate worries.

“The exposure to this concern is not limited to a small number of hours per year, but is something that must be addressed to avoid reliability concerns under fairly frequent system conditions,” the study says.

The study concluded that there are a number of outstanding questions that need to be answered and additional data collected. Several of them focus on the interregional effects of DERs tripping and whether the current 1,200-MW threshold is low enough.

The RTO’s analysis for other conditions finds fewer reasons for concern. It projects a “number” of N-1-1 high-voltage violations during minimum load conditions, as well as thermal violations for one summer peak case. The study found that the high-voltage violations, caused by a lack of centrally located synchronous generators and lightly loaded transmission lines and transformers, could be addressed by installing five shunt reactors, costing approximately $25 million to $50 million in total.

The thermal violations could be managed by reducing generation by 30 MW in the relevant region (Massachusetts and Rhode Island), the study says.