Page 947 – RTO Insider

April 5, 2021

Conflict over Power Shutoffs Grows in California

The debate over using large-scale blackouts to prevent wildfires in California has become more urgent as the state heads into another fire season after a dry winter, with some urging restraint and others recommending more public safety power shutoffs (PSPS).

Federal Judge William Alsup, who oversees Pacific Gas and Electric’s criminal probation from the 2010 San Bruno gas explosion, is weighing new probation conditions that would require PG&E to expand its criteria for de-energizing lines when nearby trees pose a threat.

The state’s largest utility was blamed for catastrophic wildfires from 2017 to 2020 caused by its equipment contacting vegetation. The blazes include last year’s Zogg Fire, which began when a leaning gray pine tree struck a PG&E transmission line, the California Department of Forestry and Fire Protection concluded in March. (See PG&E Equipment Started Zogg Fire, Investigation Finds.) The fire killed four residents of Shasta County and burned 56,000 acres.

The Zogg Fire prompted Alsup’s proposed probation conditions, requiring the utility to consider hazard trees, like the gray pine, outside its usual clearance zone when determining which lines to shut down in high winds.

California PSPS — An analysis by wildfire firm Technosylva showed the spread of a potential fire if PG&E had not de-energized its lines in October 2019. | *Technosylva*

The California Public Utilities Commission has opposed Alsup’s proposal, arguing it could double the number of PSPS events and put residents and emergency responders in jeopardy.

“The potential doubling of public safety power shutoff events in PG&E’s service territory under these modified proposed conditions could translate into a corresponding or even greater increase in the public safety perils flowing directly from the use of PSPS,” the CPUC said in a March 19 letter to Alsup.

“PSPS is a vital wildfire prevention and mitigation tool that electric utilities can use, but PSPS itself raises serious public safety consequences by potentially impairing emergency services, water pumping capability and communications infrastructure,” the commission said in a subsequent court filing on March 29.

The CPUC urged Alsup to let it handle PSPS oversight, saying it is already “years into an ongoing and iterative public process — through several formal proceedings and informal processes — of improving PSPS as a tool of last resort, while mitigating the safety hazards that flow directly from the use of PSPS.”

Effectiveness Versus Harm

In a hearing last week, the CPUC focused on the harmful impacts of PSPS on disabled residents and those with medical needs. Shutting off power to customers who rely on electrical equipment is a major concern for commissioners, who have criticized the slowness of PG&E and Southern California Edison (SCE), the state’s second largest utility, to supply battery backup power to vulnerable residents. (See PG&E Working to Improve Safety Blackouts.)

A recent study commissioned by the CPUC, however, found that devastating fires could have occurred without PSPS.

The study by wildfire consulting firm Technosylva concluded that PG&E’s controversial power shutoffs in 2019 may have prevented the burning of more than 3.4 million acres and nearly 283,000 structures. High winds caused hundreds of damage incidents on the utility’s lines that may have sparked fires, including one massive conflagration of more than 3 million acres, Technosylva said. The analysis considered weather and fuel conditions, among other factors.

PG&E’s PSPS events in October 2019 left 2.4 million residents in the dark and led to public outrage and harsh criticism from lawmakers and the CPUC. (See California Officials Hammer PG&E over Power Shutoffs.)

Public anger over PSPS rose again last year when PG&E and SCE made unprecedented use of power shutoffs, blacking out residents through the holidays and into January. CPUC President Marybel Batjer said SCE’s failure to notify customers that a PSPS would be activated on Thanksgiving morning was especially egregious because it disrupted family gatherings.

“These missteps cannot be repeated,” Batjer told the utility during a January hearing. (See CPUC Slams SCE Over Power Shutoffs.)

During a hearing in early March, Assembly Utilities and Energy Committee Chair Chris Holden said PSPS was used 30 times between 2013 and 2019.

“It’s safe to say that we’re all frustrated by the use of public safety power shutoffs by our state’s electric utilities,” Holden said.

Anger over intentional blackouts is expected to play a role in the likely recall election of Gov. Gavin Newsom this fall, during the height of fire season. Proponents of the recall say they have gathered sufficient signatures, though the results have not been certified yet. Newsom’s handling of the COVID pandemic is at the heart of the recall effort.

April 5, 2021

Billing Key to NJ Community Solar Growth

The New Jersey Board of Public Utilities (BPU) is studying whether sending two separate bills or one “consolidated” bill to community solar subscribers is the most effective and user-friendly way to attract and keep customers signed on to projects in the fast-growing sector.

The state’s first community solar project began operating in January, and three more have since come online, for a combined capacity of 9 MW. With more than 40 projects in the pipeline, the BPU is midway through a public comment process to determine which billing system would work best for utilities, community solar program developers and consumers.

With a two-bill option, consumers receive their regular utility bill, plus a separate bill for their community solar subscription. The other option, a consolidated bill, provides a single accounting, compiled by the utility or energy supplier, that includes the cost of the community solar energy and all other electricity or power costs.

The March 25 hearing on the issue drew a range of stakeholders, including representatives of PSE&G, Atlantic City Electric, solar developers and advocacy groups. Most, but not all, favored a consolidated bill.

“A dual bill is really going to confuse retail customers,” said Jacob Sussman, COO of Evergreen Energy, a community solar project developer, adding that it would be harder to sign up consumers if they were going to receive two bills. “What potentially could happen is that people feel that community solar is a scam. They are going to lose faith in the system.”

Sussman and other speakers believe the BPU’s decision could determine whether community solar projects are successful in New Jersey. Potential subscribers receiving two separate bills would have to calculate the combined total and compare it to past bills to see if they have saved money, they said.

But Jake Springer, senior policy associate for Nexamp, a developer, owner and operator of solar projects, said the idea that consolidated billing is a “panacea” for marketing community solar is wrong. A well-designed consolidated billing system could be viable, but is not the only option, he said.

“Dual billing exists today in other markets that are farther along than New Jersey is right now,” he said.

The BPU is scheduled to release a report on the issue on May 28.

Growing Interest in Community Solar

New Jersey is one of about 20 states that have recognized the benefits of shared renewables by encouraging their growth through policy and programs, according to the Solar Energy Industries Association. Others include Massachusetts, Community Shared Solar Grows in NYC.)

Community solar projects are targeted at consumers — whether homeowners or small businesses — who either cannot or do not want to have solar on their roofs. In many instances, developers start enrolling subscribers before they begin building a project or look for a business to be an “anchor” subscriber by committing to buying a certain percentage of the power from the project.

In return for subscribing, the consumer receives a credit on their utility bill, reducing the electricity cost by a set percentage. The solar project operator then supplies the electricity generated in the project to a utility company, which provides power to the consumer in the same way the utility did before opting into community solar.

New Jersey Governor Phil Murphy is pushing community solar in the state’s effort to reach 100% clean energy by 2050. Murphy wants the state to have 32 GW of solar by then, about nine times the capacity online today.

Community solar also supports Murphy’s commitment to environmental justice and helping low- and moderate-income residents lower their electricity bills. Consumers generally pay little or no money upfront to subscribe to a project and, depending on the developer, can lock in savings of a certain percentage, typically 5% to 20%, on their monthly electric bills. Forty percent of the capacity in the BPU’s community solar program is reserved for low- and moderate-income residents.

Rising Consumer Interest

Shaun Keegan, CEO of Solar Landscape of Asbury Park, which developed the first two community solar projects in New Jersey, said that public interest in the projects is notable.

New Jersey Community Solar — Located in Perth Amboy, New Jersey’s first community solar project is now 75% subscribed, developer Solar Landscape says. | *Solar Landscape*

“It doesn’t cost anything to enroll. You can cancel at any time,” he said, adding that he believes the sector is growing steadily. “It checks all the boxes, triple bottom line: People. Planet. Profit.”

In 2019, the BPU approved 45 community solar projects totaling 78 MW. The Solar Landscape projects, on the rooftops of two Perth Amboy warehouses, began operating in January, and two smaller projects have since come online in Secaucus and Pennsauken. The BPU is considering proposals for a second phase of solar community projects, which together will generate 150 MW of electricity.

Lawrence Garb, executive vice president of Hartz Mountain Industries, which developed the Secaucus community solar project, said the company will have three more community solar projects online by the end of April, generating about 6.5 MW. Garb said the company, which mainly manages real estate, has been installing solar on company warehouses for more than a decade. But state regulations allowed the electricity from those projects to be used only in the buildings, while the community solar energy can be sold to the public.

Solar Landscape had about half the project target of 1,200 subscribers signed up when it launched the Perth Amboy projects, Keegan said. Now, the projects, which give participants a 10 to 20% savings on their bill, is about 75% subscribed, he said.

Solar Landscape uses a two-bill system but favors consolidated billing, as does Hartz Mountain, and several other developers.

“Having to explain to a customer that they will get two bills is definitely the biggest bottleneck,” said Nicholas Minekime, managing director of solar developer Altus Power America, “People already have enough difficulty understanding how community solar works in the first place.”

A Deeper Connection

Community solar subscribers in Massachusetts and Minnesota, states with established community solar markets, receive two bills, said Allan Telio, senior vice-president for Nexamp, a developer with projects in several states. The key to success in dual billing is to ensure transparency and understandability in both bills so that consumers can easily see what they are paying for and getting in return, he said.

A separate bill for the cost of the community solar can even make consumers feel more involved with the clean energy project, he said. “From a psychological perspective there’s a deeper connection,” he said.

If New Jersey were to opt for consolidated billing, many details would have to be worked out. The BPU is gathering information on topics including stakeholders’ experience of consolidated billing in other states and the potential challenges facing a consolidated billing system implemented in New Jersey.

In New York, the state Public Service Commission requires community solar projects that participate in its program to use a consolidated system, with subscribers given a credit on their utility bills, said Kristen Barone of Orange and Rockland Utilities. Subscribers are guaranteed at least 5 percent savings on their electricity bills, and the utility takes an administration fee for compiling the consolidated bill, she said.

Steve Sunderhauf from the Atlantic City Electric Company, said consolidated billing would provide consumers with a single electric bill that would include distribution, transmission and generation charges, all surcharges on taxes and all other items currently on utility bills. Its success could depend on acceptance by solar developers and consumers and a clear framework as to how the cost of developing the consolidated system would be recovered, he said.

Randi Orlow, solar program director for Neighborhood Sun Benefit Corp, a subscriber organization, said the group favors a consolidated bill; clarity and transparency are key.

“We want the subscriber to be able to easily identify who their community solar provider is, exactly what the charges are, what the discount is, and who they should reach out to if a concern needs resolution,” she said.

April 5, 2021February 2, 2024

How Geothermal Can Support 24-7 Carbon-free Targets

The U.S. Department of Energy last week advanced a group of technologies in a manufacturing competition that could help geothermal grow quickly as a ubiquitous, baseload power.

“If we crack the nut on being able to drill for geothermal anywhere, we’ll have a global clean energy source that can be located near population centers, is baseload and has a small footprint,” said Jamie Beard, executive director of the Geothermal Entrepreneurship Organization (GEO).

Three teams with a focus on drilling technologies were named semifinalists in DOE’s geothermal manufacturing competition during the NextGen Geo event Thursday. The Morgantown, W.Va.-based team behind project “Hot Hammer” designed an air hammer bit that could stay intact up to 600 degrees Celsius, which the team said in its submission would “drastically” speed up the drilling process. In addition, Ozark Integrated Circuits from Fayetteville, Ark., and Team AC from Cambridge, Mass., addressed vibration issues that affect sensors and generators during drilling.

Improving geothermal drilling techniques through innovation investment and collaboration with the oil and gas sector could rapidly expand geothermal to fulfill a growing interest in 24/7 carbon-free power. | Lindsey G, CC BY-SA 2.0, via Wikimedia Commons

GEO is also looking to the oil and gas industry to support rapid expansion of the geothermal industry. Doing so, Beard said during the event, will allow geothermal to help the clean energy sector fulfill an interest from corporations to truly decarbonize their energy purchases.

More than 100 private corporations have set 100% renewable energy targets over the last decade, but those targets are most often fulfilled through a balance of renewable purchases and fossil fuel energy use. A growing number of private industry climate goals are making 24/7, carbon-free energy the gold standard for power purchases, according to Tim Latimer, CEO of Fervo Energy.

“For the first time, organizations like Google and Los Angeles [Department of Water and Power] are contemplating having clean energy that matches their load profiles 24 hours a day, seven days a week, 365 days a year, which is an entirely different problem than the accounting exercise that’s done for 100% renewable energy,” Latimer said during the event.

Those 24/7, carbon-free energy targets are doable, according to Latimer.

“Study after study … have shown that wind and solar along with batteries are very important parts of this puzzle, and they’re going carry us a long way, but we need a resource to complement them that works 24/7,” he said.

Geothermal energy could be that resource if it can make a giant leap forward to being affordable and available where needed. Beard believes that bringing oil and gas together with geothermal can put the deep history of oil and gas drilling to work for clean power.

“The geothermal industry and the oil and gas industry are essentially the same business,” she said. “They both characterize and explore for an energy asset that’s in the subsurface, and they drill for an energy asset that’s in the subsurface.”

The two sectors have overlapping workforces and methodologies, and oil and gas has existing equipment that could be deployed immediately to start producing clean energy projects, she said. And the oil and gas industry has shown an interest in geothermal already.

“We’re finding a lot of willing partners in oil and gas companies that are trying to chart their new course in the energy transition,” he said. “Companies like Schlumberger, Shell and Chevron that have become experts in drilling over the last 150 years are now applying their expertise quite rigorously to the geothermal sector.”

Semifinalists

DOE named four geothermal manufacturing competition semifinalists, all based in Texas, focused on improving technologies that will keep fluids from mixing during drilling: Baker Hughes; Welltec; Downhole Emerging Technologies; and Huilin Tu, project manager and principal engineer at Schlumberger.

In addition, DOE named three semifinalists focused on logging and production:

PLUGS from Morgantown, W.Va.;
Ultra-High Temperature Logging Tool from Houston; and
Multiscale Systems from Worcester, Mass.

April 5, 2021December 14, 2023

Nevada Reveals ZEV Program Details

Small-volume car manufacturers wouldn’t be required to sell zero-emission vehicles in Nevada under the state’s proposed ZEV program, but if they did, they could earn credits to bank or transfer through the state market.

In contrast, large-volume automakers would be required to earn credits for the sale of ZEVs. Medium-volume manufacturers could meet their credit requirements by selling either ZEVs or transitional zero-emission vehicles, such as plug-in hybrids.

Those were some of the details discussed last week during a technical session on the Clean Cars Nevada program, hosted by the Nevada Division of Environmental Protection (NDEP).

Rulemaking is underway for the program, which NDEP hopes will go to the State Environmental Commission for approval in September. With all the necessary approvals, the program could take effect for model year 2025 cars.

Clean Cars Nevada has two parts. In addition to the ZEV program, it includes a low-emission vehicle (LEV) program. The programs are largely based on similar programs in California.

Last week’s technical session focused on the ZEV program.

Volume-based Requirements

The ZEV program would require vehicle manufacturers that sell cars in Nevada to produce a specified amount of ZEV credits by delivering zero-emission vehicles to the state.

The requirements vary depending on whether the automaker is considered to be small-, medium- or large-volume, said Danilo Dragoni, chief of NDEP’s Bureau of Air Quality Planning. Mitsubishi is an example of a small-volume automaker, according to NDEP, while Subaru and Mazda are intermediate-volume and Ford and General Motors are large-volume.

Starting in model year 2025, intermediate- and large-volume automakers would face a credit requirement equal to 22% of their passenger car and light-duty truck sales in the state averaged over three years. For example, a car maker that sold an average of 40,000 light-duty vehicles per year from model year 2021 to 2023 would need 8,800 ZEV credits for 2025

For a large-volume automaker, at least 16% of the average total sales — or 6,400 credits in the example — would need to come from ZEVs, defined as battery electric vehicles or fuel cell electric vehicles.

The remaining 6% — or 2,400 credits in the example — could come from transitional zero-emission vehicles (TZEVs). These include plug-in hybrid electric vehicles and hydrogen internal combustion engine vehicles.

Intermediate-volume automakers would not face a ZEV credit minimum. They could meet their credit requirement with any mix of ZEVs and TZEVs, Dragoni said.

Small-volume car makers wouldn’t have ZEV requirements under NDEP’s proposed rule. Still, they could generate credits to bank or trade on the Nevada credit market. One reason a small-volume automaker might want to bank credits is that it expects to grow into the intermediate-volume category, according to NDEP.

Dragoni also explained the formula for converting car sales to ZEV credits. The formula is based on how far an EV can travel on a single charge, under city driving conditions.

The vehicle’s range is multiplied by 0.01, and the result is added to 0.5 to determine the number of credits. NDEP cited as an example the Tesla Model 3. With a range of roughly 340 miles, it would earn 3.9 credits per vehicle.

The vehicle earns no credits if its range is less than 50 miles, and the maximum number of credits per vehicle is four.

A different formula applies to TZEVs. The range is multiplied by 0.01, and the result is added to 0.3. Using this formula, a Chevrolet Volt with a range of about 30 miles would earn 0.6 credits, NDEP said.

The maximum credits per vehicle is 1.1. No TZEV credits are earned if the vehicle’s range is less than 10 miles.

The program would keep ZEV and TZEV credits in separate accounts.

Steep Climb to 22%

Dragoni acknowledged that going from no ZEV credit requirements in Nevada to a 22% requirement for model year 2025 would be a steep climb for manufacturers.

To help with the transition, the Clean Cars program would allow automakers to accumulate credits from ZEVs sold before the program starts. The draft regulation includes early credits for model years 2023 and 2024.

NDEP has also proposed an “initial proportional credit” based on credits an automaker has in California. The California credits would be multiplied by a factor that accounts for different sales volumes in Nevada and California.

The division might also cap the amount of initial proportional credit.

The initial proportional credit would help reduce manufacturers’ “compliance uncertainty” during the early years of the program, according to NDEP’s presentation.

“NDEP is committed to finding an approach that maximizes air quality benefits but also provides the best strategy for compliance,” the agency said.

Is Sooner Better?

Some stakeholders would like to see early ZEV credits start even sooner.

Chris Nevers, director of environmental engineering and policy for Rivian, a company that makes electric “adventure vehicles,” argued for a model year 2022 start for early credits.

Waiting until model year 2023 to offer early credits would encourage car makers to delay delivery of EVs to Nevada, Nevers said in a letter to NDEP, and the proportional credit would also disincentivize ZEV sales before 2025.

“In addition to jump-starting Nevada’s public health and climate goals, model year 2022 early ZEV credits would drive infrastructure investment and utilization,” Nevers said.

Adam Mohabbat, market development manager for EVgo, said in a letter to NDEP that the ZEV program would give Nevadans more electric vehicle options. EVgo is the largest public fast-charging network for EVs in the U.S., Mohabbat said, and the company has 18 public charging locations in Nevada.

“EVgo is prepared to scale even further — and bring more investment to the state — to meet the increased demand for even more public charging infrastructure in the state if ZEV is implemented,” he said.

Additional Info

In addition to the March 30 technical session on ZEV credits, NDEP hosted a technical session on the LEV program on Feb. 23.

A third technical session, scheduled for April 27 at 9 a.m., will dive into details of the ZEV credit bank.

More information and recordings of past technical sessions are available on the Clean Cars Nevada website.

April 5, 2021November 29, 2023

Washington Jet Biofuel Plant Lands $600M Equity Commitment

A planned jet biofuel plant in Western Washington recently received a potential $600 million financial boost.

Northwest Advanced Bio-Fuels signed a memorandum of understanding on March 23 with New York City-based Stonepeak Infrastructure Partners for $600 million to finance initial construction of a proposed $1.5 billion biofuels plant in Grays Harbor County. Stonepeak has equity investments in roughly $31 billion worth of infrastructure projects, including green and traditional energy facilities.

The Grays Harbor County plant is preparing for an engineering study expected to take four to five months. That study will begin when the company raises $40 million to tackle it, NWABF President David Smoot told NetZero Insider. “We’re extremely excited,” he said.

Smoot declined to disclose exactly where the plant would be built, citing confidentiality agreements. He said the land is owned by the Port of Grays Harbor. The entire $1.5 billion for the project has been lined up, he added.

NWABF expects its plant to produce at least 60 million gallons of biofuel a year before considering expansion. The process would rely on using 3,000 dry tons of wood chips and forest slash a day. The plan is to mix the biofuel with petroleum-based fuel to produce a 90% biofuel blend. The Northwest has the potential to produce 7 million dry tons of wood chips annually, mostly in Western Washington and Oregon, according to a 2019 report issued by Washington State University and the Port of Seattle, the latter of which owns and operates SeaTac Airport.

About 8% of Washington’s carbon emissions comes from aviation fuel, the Port of Seattle said in a press release, citing state figures.

Fuel costs will be a big factor in the future ability of biofuels to compete economically with petroleum-based fuels. The 2019 report estimated that biofuels to be used for airlines would cost between $3.70 to $10.30/gallon. Meanwhile, jet fuel prices this month have so far fluctuated between $1.50 and $1.70/gallon, according to the Airlines for America fuel-cost tracking website.

“Price parity between petroleum jet fuel and (sustainable aviation fuels) from Northwest feedstocks will require financial support and will be sold to locations with the best incentives,” the WSU-Port of Seattle report said.

The report said: “Financial incentives will be necessary to bring sustainable aviation fuel to price parity with petroleum jet fuels. These incentives will likely be a combination of policies such as low-carbon fuel standards (LCFS), the federal Renewable Fuel Standard renewable identification numbers (RINs), blender tax credits and green bonds to help incentivize business investments.”

Delta Airlines has invested $2 million in feasibility studies for NWABF’s Washington project. The airline has a goal of reducing its carbon emissions by 50% by 2050. Smoot said the plant has a customer lined up but declined to say who it is, citing confidentiality.

Chris Whitworth, NWABF’s general manager for the Grays Harbor project, said the company has forest slash suppliers, but also cited confidentiality agreements in declining to say who they are. The WSU-Port of Seattle report said wood chips and forest slash from the Pacific Northwest has the potential to create 80 million to 130 million gallons of jet biofuels a year. When municipal solid wastes and oilseeds are added to wood chips as biofuel sources, the Northwest has to the potential to produce 220 million to 290 million gallons of biofuels a year.

Another jet biofuels plant that uses wood chips as a feedstock is in the works in the Pacific Northwest.

Red Rock Biofuels is building a facility for $320 million in Lakeview, Oregon. The WSU-Port of Seattle report said it will process 136,000 tons of forest slash to produce 15.1 million gallons per year of biofuels. The fuel from that facility is expected to be used by FedEx and Southwest Airlines planes flying out of Oakland International Airport in California, the report said.

April 4, 2021

Winter Wrath Not Enough to Break MISO Records

February’s cold snap set MISO’s winter peak this year but didn’t unseat the grid operator’s all-time winter demand record, stakeholders learned last week.

MISO set the winter peak of 103.1 GW Feb. 15, short of its 104-GW prediction and its all-time winter peak of 109 GW set in early January 2014. MISO South registered a 31.6-GW peak, nearly matching the region’s 32.7-GW all-time summer peak set in August 2015.

JT Smith, MISO’s director of operations planning, said while the wintertime peak didn’t reach worst-case projections of 109 GW, unprecedented weather patterns still necessitated emergency operations.

“It was a combination of cold weather over a longer stretch of time … and a band of snow and ice … over a number of days,” Smith said during a Reliability Subcommittee teleconference April 1.

Winter MISO — Ameren Illinois worker upgrading poles to better withstand wind and ice accumulations | *Ameren Illinois*

Despite the snow and ice dumped on the system, MISO was able to limit load sheds to two-hour rolling blackouts in MISO South and smaller outages caused by local transmission emergencies. (See MISO, Stakeholders Disagree on Post-storm Accreditation.)

MISO said it used load-shed orders and generator redispatch to manage an unusual east-to-west power flow bias on its system during the punishing weather. The grid operator said it directly exported power to SPP when it could while also experiencing intense flows from PJM to SPP that strained MISO’s system.

Smith said the MISO South load shed was called in part to manage the contractual limits on the RTO’s Midwest-to-South transfer limit.

Mississippi Public Service Commission staffer Bill Booth asked whether MISO considered violating the transfer limit to avoid MISO South load curtailment, though it would have later paid penalties to SPP and the joint parties later. The RTO has an obligation to not exceed the 3,000-MW Midwest-to-South directional transfer limit for more than 30 minutes at a time.

“I don’t think it’s a money situation here. It’s strictly a question of managing the grid reliably for us and our neighbors,” Smith said. “That there wasn’t an uncontrolled load shed, I think, is a testament not just to our control room operators but all our members’ control room operators.”

Customized Energy Solutions’ David Sapper said MISO should consider analyzing its most essential generating assets to make sure they’re replaced appropriately upon retirement.

MISO and its Independent Market Monitor both agreed that control room operators managed to avert a more dangerous situation.

Market Monitor David Patton emphasized that MISO employed numerous proactive measures that lessened the severity of the event.

“MISO operators performed admirably under extraordinary conditions, taking key actions in the face of simultaneous emergencies to protect the system,” he told the Board of Directors March 23.

But Patton said the event highlights the need for MISO to review its transmission loading relief procedures. He said the grid operator is often too slow to call relief procedures.

Patton also said RTO is opting not to test constraints that would be better defined as market-to-market (M2M) constraints with SPP. He said one constraint had previously been categorized as M2M “but had been disabled and not retested.” He said that during the event, that constraint accounted for $65 million in congestion costs, $10 million of which SPP would have been responsible for had the constraint been designated M2M.

April 4, 2021

Expansion Takes EIM into LA, New Mexico

CAISO’s Western Energy Imbalance Market notched another milestone last week as it welcomed the country’s largest municipal utility and extended its eastern border to include much of New Mexico.

The Los Angeles Department of Water and Power (LADWP) and Public Service Company of New Mexico (PNM) both commenced trading in the EIM on April 1, coming a week after four publicly owned utilities became participants, including Turlock Irrigation District (TID) and Balancing Area of Northern California members Modesto Irrigation District (MID), City of Redding and Western Area Power Administration-Sierra Nevada Region.

The EIM will grow to 15 members next month with the addition of Montana-based NorthWestern Energy. This spring’s expansion represents the largest ever for the market, which began operations in November 2014 with PacifiCorp as its first member.

“We are very pleased to welcome LADWP and PNM as new participants in the Western EIM,” CAISO CEO Elliot Mainzer said in a statement. “We look forward to working with both utilities to bring additional economic and environmental benefits to their customers as we further expand the geographical scope of the real-time energy market.”

LADWP brings significant and wide-ranging transmission assets into the EIM. The utility owns and operates more than 3,600 miles of transmission lines crossing five states, including half of the 3,100-MW Pacific DC Intertie linking the L.A. metro area with the Bonneville Power Administration territory in the Pacific Northwest.

EIM expansion — LADWP operates more than 3,600 MW of transmission across five states. | *LADWP*

Other transmission assets include 60% of the contract capacity rights on the Southern Transmission System line connecting Southern California with the Intermountain Power Plant (IPP) in Utah, a 36% ownership stake in the Mead-Adelanto Transmission Project connected to Nevada, and co-ownership of the Navajo-McCullough Transmission Line between the now-retired Navajo Generating Station in Arizona and the McCullough substation in Nevada.

LADWP also controls about 8,000 MW of generating capacity, including the 1,900 MW coal-fired IPP (slated for conversion to an 840-MW gas-fired plant in 2025), 15% of the output from the 2,080-MW Hoover Dam in Nevada, and 5.7% of output from the 3,300-MW Palo Verde nuclear generating station in Arizona.

The utility’s participation in the EIM will be “a win-win proposition for the City of Los Angeles and the Western Grid in terms of fostering the integration of renewable energy while maintaining power reliability, as the City of Los Angeles moves ahead with our goal of 100% renewables as well as assisting all California utilities in meeting the state target of 60% renewables by 2030,” said Reiko Kerr, LADWP senior assistant general manager of power system engineering, planning and technical services.

PNM, BANC, TID

PNM operates 3,189 miles of transmission, including a 500-kV segment from the Palo Verde plant (of which it controls 402 MW of output) and a 345-kV backbone spanning New Mexico and capable of delivering power from the wind-rich eastern reaches of the state to the Four Corners delivery point in the northwest. A portion of the 345-kV line extends into SPP.

The utility owns 2,865 MW of generating capacity, including the coal-fired San Juan Generating Station (847 MW) and Four Corners plant (200 MW). It also has more than 300 MW of wind assets and nearly 120 MW of solar.

PNM’s participation in the EIM will also include the loads of 11 members of wholesale power cooperative Tri-State Generation and Transmission Association, which in February transitioned a number of its Colorado, Nebraska and Wyoming members to join SPP’s newly launched Western Energy Imbalance Service. (See WEIS Market ‘First Step’ to Full RTO Membership.)

“PNM, CAISO and Tri-State’s close collaboration enabled us to have a smooth entry into the [EIM],” Tri-State CEO Duane Highley said in a statement. “We greatly appreciate the professionalism of the PNM and CAISO staff, who we worked with over many months to enter the market.”

The engagement of MID, Redding and WAPA-Sierra Nevada boosts the roster of BANC participants in the EIM. The group’s largest member, Sacramento Municipal Utility District, joined in April 2016. (See SMUD Goes Live in Western EIM.) BANC members Roseville Electric Utility, City of Shasta Lake and Trinity Public Utilities District have not yet committed.

Like BANC, TID owns a share of the California-Oregon Intertie (COI), the other major transmission line that allows California to tap the Northwest’s hydroelectric resources. TID’s transmission network also links to CAISO at two locations and to the SMUD and WAPA systems at the Tracy substation, the tie-in for the COI.

TID’s generation portfolio includes a 136-MW share of the output from the Don Pedro Dam, the 136-MW Tuolumne Wind Project, nearly 100 MW of gas-fired generation and a 6.8-MW geothermal plant.

“As participants in the EIM, we have the opportunity to further capitalize on the generation infrastructure TID has developed over the years,” TID General Manager Michelle Reimers said.

April 4, 2021

NYISO Management Committee Briefs: March 31, 2021

NYISO CEO Rich Dewey informed the Management Committee on Wednesday that the ISO in early March had completed its annual stakeholder sector meetings for this year with good input and participation, which was shared on a high level with the Board of Directors. He also announced that the joint board/MC meeting in June will again be a virtual event.

“The next iteration of our market participant survey will be going out soon, and I personally read verbatim every one of the comments,” Dewey added.

Responding to a stakeholder, Dewey said he has heard nothing about the timing of the NYISO-specific technical conference that PJM MOPR in the Crosshairs at FERC Tech Conference.)

Winter Operations Went Well

Vice President of Operations Wes Yeomans delivered the Winter 2020/21 Cold Weather Operations report, which showed a seasonal peak load of 22,542 MW on Dec. 16, compared with a seasonal 50/50 forecast of 24,130 MW. NYISO’s all-time winter peak load was 25,738 MW on Jan. 7, 2014.

NYISO Management Committee — Winter 2020–2021 daily peak loads in perspective | *NYISO*

“For the most part we did not have a single, brutal cold snap or a long sustained cold snap,” Yeomans said. “To explain the difference between the forecast and the peak, we simply did not have 50/50 weather, but if we had, I imagine the seasonal peak would have been very close to the forecast.”

The Dec. 16 snowfall exceeded that morning’s forecasts by 1 to 2 feet, and the storm proved to be the eighth largest in Albany history and the fourth largest December snowstorm.

The ISO ran the day-ahead forecast on Dec. 15, and as the day proceeded, transmission owners saw the possibility of exceeding the 50/50 forecast peak and thus issued a supplemental resource evaluation (SRE) request for Cricket Valley CC3 on Dec. 16. Transmission owners may request NYISO to issue an SRE to commit additional resources for reliability purposes in a local area.

Natural gas pipelines in New York and throughout the Northeast are running at high capacity factors, as was made evident in the second week of February when colder weather saw a flurry of operational flow orders (OFOs), both daily and hourly, Yeomans said.

On days when gas system reliability could be at risk, the local distribution company or a gas pipeline may invoke an OFO or issue other instructions restricting use of gas imbalance service. Under extreme circumstances, interruptible customers may also have their gas service interrupted to protect gas system reliability.

“The natural gas infrastructure in New York remained in service throughout the winter, yet a number of OFOs were reported on days not identified as particularly cold,” Yeomans said. “We hope to bring more information on that situation to an upcoming OC meeting.”

NYISO is following the FERC-NERC joint inquiry into the February winter storm in ERCOT and SPP, and it intends to review all findings and consider best practices and recommendations as appropriate, Yeomans said.

April 4, 2021

DOE Targets Geothermal Extraction for Lithium Supply

The U.S. Department of Energy’s Geothermal Technologies Office launched a new collegiate competition to find solutions for de-risking and increasing the market viability of direct lithium extraction from geothermal brines.

The $4 million Geothermal Lithium Extraction prize is designed to help the U.S. build out its lithium supply chain for electric vehicle batteries and grid-scale battery storage.

The U.S. lithium stock is almost entirely imported, with only 1% sourced domestically, Alex Prisjatschew, general engineer at the Geothermal Technologies Office, said Wednesday during a webinar announcing the competition.

“The combination of rapidly expanding global demand and lack of secure domestic supply has created an urgency to develop a safe, domestic and cost-competitive source of lithium,” she said. “Using geothermal lithium brines to extract lithium [can] become a more sustainable way to harness lithium resources.”

State of Play

Currently, no lithium chemicals are produced at commercial scale using geothermal extraction, but Alex Grant, principal at geothermal consulting firm Jade Cover Partners, expects the market for it to mature by 2030.

Geothermal lithium extraction takes advantage of existing geothermal power technologies in commercial operation today, Grant said during the webinar.

In a geothermal facility, power is produced with energy that is extracted from hot, pressurized water (brine) pumped from deep in the ground. That brine is reinjected into the ground, but some extracted brines contain minerals, such as lithium. Geothermal lithium could be removed from the brine on site before reinjection.

About half of the world’s lithium is made from the mineral spodumene that is mined in Australia and converted to lithium chemicals in China, Grant said. The other half is made from large brine ponds in South America through evaporative processing.

If lithium production from geothermal brines enters commercial scale, Grant said the resulting lithium chemicals would be highly competitive in terms of CO2 intensity.

“Geothermal extraction unlocks the ability to make lithium chemicals from very small physical footprints,” he said. “There are no evaporation ponds needed and no open pit, so it drastically reduces the number of square meters required to make a certain quantity of lithium chemicals per year.”

Competition Details

The geothermal lithium extraction competition will include three phases for participants to identify, develop and test their technology solutions. Participants will be eligible to earn cash prizes for their progress.

While competitors must be affiliated with a U.S.-based academic institution, Prisjatschew said DOE is encouraging participation from anyone with a background in oil and gas, mining, engineering or geosciences.

Submissions for the first phase are due July 2, and the competition will run through February 2023. DOE will hold an informational webinar on April 12.

April 4, 2021November 2, 2023

Maryland Panel Votes to Boost GHG Goal to 50%

A Maryland House of Delegates committee on Thursday approved legislation to increase the state’s 2030 greenhouse gas reduction target to 50% from 2006 levels, an increase from the current 40% goal (HB 583). But the vote disappointed some because the bill is less ambitious than the version the Senate approved March 12, which set the goal at 60% (SB 414).

House Environment and Transportation Committee Chair Kumar Barve (D) said he supported the 50% target because of concerns the Senate goal was unrealistic.

He said he was deferring to Economic Matters Committee Chair Dereck Davis’ (D) expertise on the electric grid and PJM. “He has said he thought 60% was a pretty tall order, and I have to take him at his word there,” Barve said during an Environment Subcommittee meeting Wednesday.

The committee also stripped from the Senate bill requirements that new commercial and residential buildings of 25,000 square feet or more make at least 40% of the roof “solar ready” and that they exceed the energy-use reductions in the 2018 International Energy Conservation Code (IECC). Beginning in 2033, such new buildings would have to achieve a net-zero energy balance under the Senate bill. Also eliminated was a requirement that all new schools be solar-ready or net zero beginning in 2022.

Sen. Paul Pinsky (D), lead sponsor of the Senate bill, told Maryland Matters he was “extremely disappointed” in the House’s amendments. “They almost gutted the bill,” he said.

Pinsky told Barve’s committee on Wednesday that the bill would prompt more aggressive climate actions from the administration of Gov. Larry Hogan (R), such as requiring purchase of zero-emission vehicles for the state’s 4,000-vehicle fleet beginning in 2027. The Maryland Transportation Administration would be required to purchase zero-emission buses beginning in fiscal 2023.

“Unfortunately, I don’t think there’s been much urgency in the administration,” Pinsky said. “I sat on the [Maryland Commission on Climate Change] for a number of years. They’ve rejected more aggressive actions.”

The bill would also require the Commission on Environmental Justice and Sustainable Communities to recommend a methodology for identifying communities disproportionately affected by climate change and develop recommendations for improving them.

“The environmental justice commission has been moribund for years,” Pinsky said. “So we include some really explicit charges to jump start them.”

The bill also would:

create a Just Transition Employment and Retraining Working Group to identify the skills and training required by jobs to counter climate change and strategies for workforce development and job creation for those whose jobs are threatened by the transition to a low-carbon economy;
set a goal of planting 5 million sustainable native trees in the state by the end of 2030, including at least 500,000 in “underserved” areas;
allocate Regional Greenhouse Gas Initiative auction proceeds exceeding $50 million annually to programs subsidizing zero-emission vehicles, providing loans for net-zero school construction and covering administrative costs for the departments of the Environment and Labor; and
create a Solar Land Use Commission to make recommendations on how the state can meet its solar goals in the face of restrictions on solar projects on agricultural land.

Barve said the land use commission is needed to address opposition to community solar. “We can’t move to a higher rate of carbon-neutral, carbon-free energy sources without actually producing electrons and doing so in the state of Maryland,” he said.

He said some environmental groups are “trying to have it both ways” in pushing for increased renewables but blocking siting of projects.

In an interview with NetZero Insider, Barve cited Montgomery County Council’s vote in February, which he said “functionally banned” community solar from the county’s 93,000-acre Agricultural Reserve.

“There is just a lot of actions like that around the state of Maryland that causes me to wonder if we’re even going to be able to achieve a 40% goal,” he said during a meeting of the Environment Subcommittee on Wednesday.

Barve also noted that while the amendments reduced the 2030 goal, it eliminated a requirement that the goal be reauthorized in 2025. It also kept the Senate bill’s ultimate target of net-zero statewide GHG emissions by 2045.

California’s 2030 GHG target is identical to Maryland’s current 40%. Massachusetts last month enacted legislation committing to a 50% emission reduction by 2030 but from a base of 1990. (See Mass. Governor Signs NextGen Climate Bill.)

Del. Dana Stein (D), vice chair of the Environment and Transportation Committee and lead sponsor of the House measure, defended the revisions to the building efficiency standards. “We listened to building engineers who said that requiring a net-zero energy standard … was not practical without advances in technology and that decoupling the state from national building codes (such as the IECC) would be challenging to implement,” he wrote in an email outlining ways he said the House improved the Senate bill. “We did not want to mandate building standards for which no modeling has been done.”

He noted that the House bill would require new state buildings (including those in which the state will lease more than 50% of the space) use a high efficiency HVAC system such as geothermal if the net present value over 15 years is less than a standard HVAC system. It also requires state agencies to give a price preference for concrete produced with lower GHG emissions.

Reaction

Del. Ann Healey (D) asked Pinsky about organized labor’s opposition to the bill.

Pinsky said it was impossible to estimate the impact of the clean energy transition on labor without the study by the transition work group.

“While I know labor doesn’t support it and they are concerned, I think they understand changes are coming and they want to be at the table. And that’s, at this point, what I can do,” Pinsky said.

Maryland Environment Secretary Ben Grumbles endorsed the House’s amendments, saying it “codifies into law the science-based, ambitious and broadly supported goals and recommendations of Maryland’s independent Commission on Climate Change and the administration’s Greenhouse Gas Reduction Plan released earlier this year. By elevating the plan to enforceable law with urgent requirements and visionary goals, we would demonstrate that Maryland continues to be a national leader with real and achievable commitments to dramatically reduce greenhouse gases and increase climate resiliency and environmental justice.”

Jamie DeMarco, federal and Maryland policy director for the Chesapeake Climate Action Network, told the Environment Subcommittee on Wednesday that his group supported the amendments to ensure speedy passage through the House. Sine Die, the last day of the General Assembly’s 90-day session, is April 12.

“We’re only just seeing the amendments today so we … haven’t had a chance to go through all of them,” he said. “I hope we can continue this conversation as we go forward and possibly in conference committee.”

Asked whether the two differing bills would be resolved in a conference committee, Barve responded: “There’s going to be discussions between us and the Senate before Sine Die, let’s put it that way.”

In the interim, he predicted, “there’s going to be much wailing and gnashing of teeth” over the bill.