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November 17, 2024

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Tesla Projects Take Lion’s Share of Nevada Development Incentives

Tesla has been gobbling up state-backed economic development incentives in Nevada, including the entire Northern Nevada allocation for an electric rate rider program.

Under the Economic Development Electric Rate Rider program, NV Energy had 50 MW to allocate, according to a report to the Nevada legislature from the Public Utilities Commission of Nevada. The 50 MW was split evenly between the utility’s northern and southern Nevada territories.

In northern Nevada, the entire 25 MW went to Tesla, whose 5.4 million square-foot gigafactory is near Reno. In southern Nevada, 1 MW was allocated through the program to Xtreme Manufacturing, which makes heavy equipment for construction.

A business accepted for the rate rider program receives a discount off the base tariff energy rate portion of its electric bill. Discounts provided through the program totaled $9.45 million as of the date of the PUCN report.

The PUCN voted 3-0 on Monday to approve the report.

Gigafactory Incentives

The rate rider is just one economic development incentive that the state of Nevada has granted to Tesla. Since 2015, Tesla (NASDAQ:TSLA) has received $410 million in tax abatements in Nevada related to the Nevada gigafactory, according to an October report from the Governor’s Office of Economic Development (GOED).

The tax breaks were for real and personal property tax, modified business tax, and sales tax on construction equipment and materials. The abatements last for 10 to 20 years.

In addition, Tesla received $195 million in transferable tax credits.

The tax abatements and credits were allowed through Senate Bill 1 from the legislature’s September 2014 special session. The bill authorized tax breaks for projects with a capital investment of at least $3.5 billion within 10 years.

Tesla is the only company that has qualified for tax abatements under the legislation, the Nevada Current reported.

Tesla said it has invested $6.2 billion in Nevada since 2014.

More tax incentives for Tesla may be on the way.

The electric vehicle manufacturer announced last month plans for a $3.6 billion investment in Gigafactory Nevada, including a new battery factory and its first high-volume manufacturing facility for electric semi-trucks. (See Tesla to Invest $3.6B in Nev. Truck, Battery Factories.)

The GOED is scheduled to discuss potential tax breaks for Tesla’s new investment on March 2; it will release details of the proposal later this month.

Rate Rider Revived

Nevada’s Economic Development Electric Rate Rider program expired in 2017. But the state legislature revived the program in 2021 through Senate Bill 448. It now runs through 2024.

A business accepted for the program receives an electric rate discount of up to 30% in the third and fourth year of the contract; up to 20% in years five through eight; and up to 10% in years nine and 10. There’s no discount in the first two years.

In addition to Tesla and Xtreme Manufacturing, GOED approved two other businesses for the electric rate rider. Those approvals hadn’t yet been filed with PUCN.

In March, the GOED board approved a 5 MW allocation for Haas Automation for its planned factory in Clark County. Another 5 MW allocation was approved in June for Ball Metal Beverage Container Corp. for a Clark County factory.

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NREL Report Sees Role for Electric Trucks at Port of NY-NJ

Electric trucks already on the market could replace 20% of the diesels taking cargo in and out of the Port of New York and New Jersey, but full electrification would require vehicles with larger batteries and greater range, according to a new report by the National Renewable Energy Laboratory (NREL).

The report tracked 46 trucks serving the port on trips totaling 121,000 miles over eight weeks and concluded that the routes executed by nine of the trucks could be done with an existing battery of about 375 kWh, with recharging taking place every time there is a two-hour break during the day.

The nine routes could be performed by existing electric trucks because they cover shorter distances. The average route across all the trucks was 140 miles, and the longest route was 573 miles. Those longer routes meant that a substantially larger battery — between 900 kWh and 1,600 kWh — would be needed for electric trucks to cover the remaining routes, the report states.

A battery at the lower end of that range could be used if there were more charging breaks during the day and faster chargers, the report said. But it added that “specific days of operation would require over 1,600 kWh of energy due to longer distances and more intense operation, which is not currently possibly without operational changes,” the report concluded. It added that full adoption of EV trucks would cut carbon emissions from the trucks by 75%.

Port fleet operators say there are relatively few electric truck models available. That is changing, however. Freightliner put its eCascadia (up to 438 kWh and up to 230 miles in range) into production last May. In December, Tesla began delivering its Tesla Semi (up to 500 miles on a single charge) to buyers. (See Tesla to Invest $3.6B in Nev. Truck, Battery Factories.) Both are Class 8 vehicles (over 33,000 pounds, including 18-wheelers).

NREL’s 47-page report also concluded that electric trucks “could be cost-competitive on an energy-cost-per-mile basis for all scenarios while diesel is above $3.00/gal.” The current price for diesel in the state is $4.90/gallon, according to Globalpetrolprices.com.

The report is one of two new studies that focus on the viability of electrifying different elements of the port activity and assessing the impact on emissions in the port, most of which is located in New Jersey and is the largest on the East Coast.

The reports offer a glimpse of what can be achieved through electrification, but also the extensive challenges standing in the way of widespread EV truck adoption, especially from the still limited truck technology available.

Trucks 25% of Transportation Emissions in NJ

New Jersey says electric trucks are key to reducing carbon emissions and pollution because trucks account for 25% of emissions from transportation, the state’s largest source of emissions. The state’s Energy Master Plan, released in 2019, assumes that 75% of medium-duty trucks and 50% of heavy-duty trucks will be electric by 2050. The Port Authority of New York and New Jersey, which runs the ports, has set a goal of reaching zero emissions by 2050.

The workload for drayage trucks — those that pick up and deliver goods to and from the port — varies a lot from truck to truck. Some do short trips to and from a warehouse or distribution center a few miles from the port while others do round trips of several hundred miles into Pennsylvania or the outer reaches of New York state.

So far, however, only a few electric trucks work in the port, and most of those are yard tractors that move containers short trips within the port’s perimeter. Truckers say electric vehicles are too expensive; the range is too limited; and there aren’t enough charging stations to rely on for recharging.

Red Hook Container Terminals in August 2021 introduced 10 electric yard tractors. (See Port of NY-NJ Unveils Fleet of 10 EV Trucks.) Earlier in the year, International Motor Freight outlined a plan to put 16 electric trucks, bought with $5.9 million from the state Volkswagen settlement, into service. (See NJ Looks to Boost Heavy-duty Charge Points.)

Many port trucking operations are run by small independent operators who have only a few trucks and lack resources to invest in EVs or charging stations, according to port officials. (See Port NY-NJ Cites ‘Hurdles’ to Employing EV Trucks.)

The second report, a working paper released on Feb. 6 by the International Council on Clean Transportation, documents case studies of the ports of New York and New Jersey and Seattle and concludes that electrification at both could lead to dramatic cuts in emissions.

The report found that drayage trucks generate about 23.5% of the carbon in the port of New York and New Jersey, and oceangoing vessels bringing the goods in and out of the port generate about 52%. The remaining 25% is generated by harbor craft, such as ferries and tugboats.

The ports could cut emissions from ocean vessels by half if they provided electricity to power them while they are sitting in the port, rather than them running their engines, the report says.

Subsidies

In New Jersey, state agencies have embarked on several initiatives to promote the purchase of EV trucks and stimulate the development of EV charging stations. The New Jersey Economic Development Authority expects to begin accepting applications within weeks for subsidies toward the purchase of the largest trucks, offering $135,000 for a Class 7 truck (ranging between 26,001 and 33,000 pounds, such as garbage collection vehicles or livestock transports) and $175,000 for a Class 8 truck. (See Electric MHD Truck Incentives Promoted in NJ.)  

The program has so far provided financial support for the purchase of 370 trucks, but that is a tiny sliver of the 500,000 trucks that the New Jersey Board of Public Utilities says drive in the state.

The NREL report demonstrates the interplay between battery size, the availability of chargers and the size and charging speed of the chargers. For example, one of the fleets studied would need a 1,600-kWh battery on each vehicle to cover all its routes if charging could take place at a 175-kWh charge rate when there was a break of at least two hours. But the battery could drop to 900 kWh if the charge rate was 300 kWh and charging could take place every time the truck stopped for 10 minutes.

If a truck could be charging every time it stopped for ten minutes, the number of routes that could be done with today’s battery size would increase from nine to 24 the report said, adding that such a scenario is not feasible today with current charging technology and infrastructure.

A key issue for drayage trucks is the location of where the truck takes a break, and whether there is a charging station there. For instance, some of the trucks’ stop time — known as dwell time — is in the terminals, where charging would not be possible, the report said.

The report added that ports are in some ways ripe for truck electrification because about 9% of the trucks’ energy is spent idling, either waiting to enter the terminal or to pick up or deliver a container or products, or other tasks, the report says.

EV trucks “use very little, if any, energy when they are stopped,” the report says. “In contrast, conventional internal combustion engine trucks may use a significant amount of fuel and generate emissions while the engine is idling.”

Moreover, “there may be potential for opportunity charging during times when the truck would traditionally be idling,” providing there is charging infrastructure available at the places where the trucks idle, the report added.

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MISO Data Show Steep Gas-fired Outages During Winter Storm

MISO told stakeholders Monday that as much as 23 GW of natural gas-fired generation was unavailable during the December winter storm, accounting for almost half of the grid operator’s forced outages.

Staff said during an Entergy Regional State Committee meeting that forced outages reached 50 GW during the last two days of the Dec. 22-24 storm, up from 30 GW during the first day. Natural gas generation outages comprised 23 GW on Dec. 23 and 22 GW on Dec. 24, up from the 9 GW on Dec. 22. Forced coal-resource outages varied between 13 and 16 GW during the storm.

The MISO footprint’s demand hit a likely winter peak of 107 GW on Dec. 23. Demand in MISO South peaked at 32 GW on Dec. 23, nearly matching the South’s record of 32.9 GW set last June.

Staff said gas supply availability issues ultimately tipped the system into emergency procedures on Dec. 23 as they tried to maintain exports to neighboring regions. The maximum-generation emergency lasted for three and a half hours, forcing MISO to call up 1.2 GW of load modifying resources.

MISO’s director of operations risk management, Jason Howard, told the ERSC that pipeline issues and fuel availability, not insufficient weatherization measures, contributed to the unplanned outages. He said staff are working to quantify operations data to better anticipate future winter storms.

In a blog post, Paul Arbaje, an energy analyst with the Union of Concerned Scientists, called the level of outages “troubling” and “equivalent to more than a third of the capacity that should have been available.”

MISO’s operations team drew parallels between this storm and the February 2021 severe-weather event. Howard said although the storm arrived earlier than staff predicted, the severe weather played out as expected. Staff said “abnormally high load forecasting errors” occurred because of a lack of historical data for “similar extreme conditions in December.”

Howard said the storm’s impact over most of the continental U.S. caused MISO and the industry to “really struggle” in gauging demand.

The grid operator’s exports pushed electricity served to 111 GW on Dec. 23. “MISO consistently exported power to southern neighbors with a maximum value of nearly 5 GW,” Howard said. (See MISO Actions During December Storm Spark Debate.)

The RTO said it honored a request to tamp down flows by 1,500 MW across its Midwest-to-South transfer constraint during the Dec. 23 morning peak, which produced emergency conditions in MISO South and a recall of non-firm exports. MISO can normally flow 3,000 MW south and 2,500 MW north across the transmission constraint, part of an agreement with its neighbors.

Scott Wright, executive director of resource adequacy, said because it’s becoming more unpredictable to respond to system operations, MISO has expanded Resource Adequacy Subcommittee meetings into two-day affairs. Staff will use that time to define essential resource attributes, create a new accreditation process for non-thermal generation and design a sloped demand curve for the capacity auction.

“We’re exploring with a conviction that we can do something,” Wright said.

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AEP, Liberty Utilities Try Again on Kentucky Territory Deal

American Electric Power and Algonquin Power & Utilities subsidiary Liberty Utilities have filed a fresh application with FERC seeking approval of AEP’s Kentucky operations’ sale to Liberty.

This time, the two utilities have added new commitments so the sale won’t raise customer rates (EC23-56).

FERC shot down the sale in December, indicating more consumer protections were needed before the commission could give its blessing.  

The utilities have since added more safeguards, including a five-year freeze on the current return on equity and 55% equity capital structure; a commitment from Liberty to maintain the same credit profile for five years; and a five-year cap on operations and maintenance and administrative costs at the 2022 rate.

AEP and Liberty also pledge to hold wholesale power and transmission customers harmless from any transaction costs for five years following the sale. The proposed transaction’s other aspects remain unchanged.

The utilities are requesting an expedited review of the application and hope to the close the transaction by April 26. If they fail again to gain commission approval by then, termination rights kick in for the parties.

“When taken in total, these commitments will ensure that the transaction has no adverse effect on both Kentucky Power or Kentucky TransCo’s individual rates and the rate for the AEP East zone,” AEP and Liberty said in the filing.

The new sale application continues AEP’s two-year effort to offload its Kentucky operations to Liberty. Late last year, the parties agreed to shave $200 million off the purchase price down to $2.646 billion. (See AEP Accepts Lower Price for Kentucky Operations Sale.)

AEP said the transaction’s approval should bring an economic boost to retail customers in an “economically disadvantaged part of eastern Kentucky.” It cited previously agreed-upon compromises at the Kentucky Public Service that include a $40 million fund to help offset volatile fuel rates for the remainder of the year; a $55 million, three-year rate holiday on collecting a Big Sandy nuclear plant decommissioning rider; a $43.6 million cut in regulatory charges collected from customers for storm costs; and a new Kentucky call center in the Kentucky territory.

“AEP and Liberty are committed to the sale and are requesting FERC’s accelerated review of the application so customers in eastern Kentucky can begin benefiting from the transaction,” AEP CEO Julie Sloat said in a statement.

Sloat said the sale is just one component of AEP’s strategic plan. She said utility leadership remains dedicated to selling AEP’s competitive renewables portfolio and conducting a review of its retail business as part of its equity financing plan and goal for a 6 to 7% long-term growth rate.

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NARUC Panel Tackles Gas-Electric Coordination

WASHINGTON — Despite making progress after repeated high-profile winter reliability events, the gas and electric industries still have more work to do to coordinate their operations enough to avoid such incidents in the future, experts said at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit Monday.

Winter Storm Uri in February 2021 and Winter Storm Elliot in December 2022 each presented the power and gas sectors with a different set of problems, according to MISO President and COO Clair Moeller.

But Moeller said the events shared a common thread: Those problems were rooted in a continued disconnect between the industries — one stemming from difference in how they operate.

“Electricity is ‘N minus one’ forever,” he said, referring to the power industry’s “N-1” reliability criterion, which holds that the grid must be equipped in a way that it can lose a major resource or transmission line without threatening electricity supply. “Gas is like, ‘You know, pipes don’t fail very often, so maybe it’s not worth those investments.’”

The gas industry has been more focused on the commodity itself rather than ensuring resilient operations because nobody has paid it to provide the latter, he said.

“Just to make it more fun in the planning horizon, we’re asking them to become intermittent resources, the reciprocal of renewables, to fill all those holes, and at the same time, we’re electrifying, taking their base load,” Moeller said. “So, the planning problem here is enormous.”

The differing business models makes it difficult to figure out whom to talk to in order to bridge the differences between the two industries, Moeller said. And even within the gas industry, the pipelines have their own issues, which are different from the local delivery companies and natural gas suppliers.

“There really isn’t a very good place to talk about it except here, which is why I bring it up,” Moeller said. “It’s time; the penetration of renewables is accelerating. We’re relying on gas to be that reciprocal intermittency. But we haven’t told them what that looks like, and we haven’t shown up with a checkbook to make sure that they can do it.”

After experiencing the polar vortex of 2014 and helping its neighbors get through Uri, PJM Senior Vice President of Operations Michael Bryson said he thought his RTO had achieved good coordination with the gas industry.

“I think we found out during Elliot that there were certainly gaps in what we were able to see in terms of availability,” Bryson said.

PJM’s load forecast was off by about 10% as it was not ready for the rapid temperature drop over the Christmas holiday weekend, but it also ran into plenty of outages of gas-fired plants that its operators were unaware of until they tried to dispatch the units, he added.

“We actually had, in fact, during Elliot, what I would consider the golden ticket of capacity performance gas: firm transportation, firm supply, no notice scheduling,” Bryson said. “We had units with that, that were curtailed.”

PJM does not have visibility into the operational issues natural gas suppliers might be running into during extreme weather, and that could be fixed by requiring similar information sharing between the gas and electric industries as the RTO does with its neighboring grid operators, he said.

Post-Uri Reforms in ERCOT

Texas has been working on reforms to its power market since Uri knocked out about 50,000 MW of its generation, plunging the state into blackouts that lasted for five days and causing hundreds of deaths and billions of dollars in damages. They include mandatory winterization standards that can be enforced with fines of $1 million per violation per day, said Public Utility Commission of Texas Commissioner Lori Cobos.

“We’ve also developed a first-in-class, first-in-the-country new firm fuel product to help ensure winter resiliency when fuel availability issues arise,” Cobos added.

The PUC authorized ERCOT to procure up to 3,000 MW for the new firm fuel product, and it signed up 19 power plants, 18 of which can burn fuel oil with storage onsite, while the other has a direct pipeline connection to its own natural gas storage facility. All the generators can provide power for up to 48 hours.

ERCOT used the firm fuel product for the first time during Winter Storm Elliot just before Christmas, calling up eight generators that supplied 950 MW, Cobos said.

While the product provided some guaranteed generation, the PUC still is looking into the 13,000 MW of generation that went offline during Elliot, specifically whether any had weatherization issues, she said.

Gas-fired generation has grown at the expense of coal because it is cleaner, but it cannot be stored. And now the electric industry is relying on the gas industry to meet needs the gas system was never designed for, said Chris Moser, head of competitive markets and policy at NRG Energy (NYSE:NRG).

“The gas system itself is well-built; the electric system itself is well-built. The combination of those two systems, frankly, is brittle,” Moser said. “And it’s the touchpoints in between the two of them, some of them just on a daily basis, where things start to break down.”

The issues are exacerbated during winter storms, when spot prices for natural gas spike to above $100/MMBtu, which leads to generator bids above the price cap in many markets. Uri saw prices reach $1,200/MMBtu on the border of Texas and Oklahoma despite the region’s vast supplies of natural gas, said Moser.

When gas is just $4 or even $10/MMBtu, generators can deal with it, but once prices get into the hundreds that can “sink an entire company,” Moser said.

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Eversource Still Eyeing Offshore Wind Sale

Eversource’s 2022 earnings were hit by continued uncertainty over its offshore wind portfolio despite record profits, the company said in a call with analysts on Tuesday.

The New England utility is performing a “strategic review” of its 50% stake in the South Fork Wind Farm, Revolution Wind and Sunrise Wind projects, which could lead to a sale of the assets, all of which are still under development.

“While our longer-term total shareholder return compares favorably with our peers, our 2022 return was disappointing,” CEO Joe Nolan said. “We understand that much of that is related to the uncertainty over our offshore wind investments. We expect to resolve that uncertainty in the coming months as our strategic review progresses.”

The company had originally planned to finish the review by the end of 2022 but now says it will be done by the second quarter of the year.

“I’d like to move at a good pace, but this is very complex and … folks need to understand that any buyer of these assets is going to want to do significant due diligence,” Nolan said.

But there is “significant interest in the lease here as well as the projects,” he said.

“We are going to get a fair price for these assets,” he added. In the meantime, work on the projects is moving ahead.

Despite earning a record $1.4 billion last year, an increase of 15% from 2021, the company missed Wall Street estimates, reporting adjusted earnings of $4.05/share for the full year and 92 cents/share for the fourth quarter.

Nolan said that Eversource’s customers should see reductions to their bills soon as mild winter weather has reduced consumption and eased gas prices.

“For most of our electric customers, lower power supply costs will start to be reflected in bills in July,” he said.

Unitil

Unitil, which serves customers in Massachusetts, Maine and New Hampshire, had a strong 2022, beating estimates and earning $41.4 million, up $5.3 million (24 cents/share) from the previous year.

“The earnings growth reflects higher distribution rates, including recoupment associated with the New Hampshire rate cases, partially offset by higher operating expenses,” CFO Robert Hevert said.

Unitil’s adjusted gross margin increased by more than $12 million thanks to higher rates, colder winter weather and customer growth; the company added 425 new customers on the electric side and 855 for gas.

“2022 certainly had its challenges. Ultimately, we were able to overcome these challenges and finish the year strong,” CEO Thomas Meissner said.

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How to Quicken Transmission Development Discussed at NARUC

The U.S. used to be able to build massive infrastructure projects such as the Empire State Building and the Pentagon in just a year, but nearly a century later that is far from the case with electric transmission, Maryland Public Service Commission Chairman Jason Stanek said at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit on Monday.

With billions in dollars in new federal incentives aimed at expanding clean energy, the pace of transmission development needs to speed up in order to take full advantage of those.

“As a state commissioner, I’m disappointed,” Stanek said. “I’m disappointed that over my five years at the commission, I haven’t been able to site and build 1 inch of interstate transmission.”

The Inflation Reduction Act and the Infrastructure Investment and Jobs Act (IIJA) are setting the country on course for the largest investment in infrastructure installation in 100 years, said Jeff Dennis, deputy director of the U.S. Department of Energy’s Grid Deployment Office.

“But we know that a significant portion of those benefits — as much as 80%, according to a Princeton study — of the emission reduction benefits that Congress expected from the IRA won’t happen if we don’t increase the pace at which we build transmission,” Dennis said.

The past decade has seen the grid expand at a clip of about 1% per year, but that needs to exceed 2% to meet those goals, he added.

Much of the funding DOE received for transmission in those recent laws is for “commercial support” rather than the loans it has used most often in the past, said Dennis. The money will help finance and speed up the development of transmission.

The IIJA included $2.5 billion the department can use to facilitate transmission by doing things like becoming the anchor-customer on a line to help it get financed and then sell off that space as the project is developed. The IRA has another $2 billion that DOE can use to help support transmission projects deemed in the national interest, Dennis said.

DOE also has new loan authorities, including some aimed at repowering existing corridors so that they can transmit more energy than they do now, Dennis said.

The IRA offers $100 million for addition regional and interregional transmission lines.

New England is expecting major changes to its grid, as it will have to greatly expand clean energy to meet future demand, which is on pace itself to grow from 25 GW today to 43 GW in the future because of electrification, said Digaunto Chatterjee, vice president of system planning for Eversource Energy.

“The best way to deploy IIJA funds is to surgically address specific transmission upgrades on your system and create new landing sites for offshore wind,” Chatterjee said.

While the industry has a daunting task of expanding its transmission grid and turning over to new sources of generation, it is a job that it has successfully performed in the past, said National Grid Clean Energy Development Director Terron Hill.

“When you think about the 1970s, we had a huge buildout of the transmission network in order to pick up electrification needs and new industries,” said Hill. “We saw the same type of buildout of the transmission network as we transitioned away from oil and coal to natural gas.”

New England has added about 300 MW of renewable energy per year, but to meet its carbon-mitigation goals, the pace of infrastructure development will need to be closer to 3,000 MW, Hill said.

“That is a huge challenge, but it’s a challenge that we can meet,” Hill said. “I was told very early in my career, that if you give engineers and planners a problem to solve, they will come up with the best solutions.”

Part of the solution is getting more efficiency out of the existing transmission grid through the adoption of dynamic line ratings, topology optimization and advanced power flow controls, said Hilary Pearson, vice president of policy for LineVision. The firm’s technology has helped New York wring more transfer capability out of its grid, which has historically been congested in power flowing from west to east and north to south, limiting the amount of load served by clean energy.

“By using dynamic line rating sensors in the western part of the state — very renewable-rich but has constraints and congestion on the system — we’re going to be able to eliminate 320 MW of existing wind energy curtailments, while creating another 190 MW in headroom for new renewable energy projects to be able to come onto the grid,” she said.

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DC Circuit Upholds FERC on Montana PURPA Project

The D.C. Circuit Court of Appeals on Tuesday upheld a FERC decision that allowed a solar-and-storage project in Montana to be certified as a qualifying facility under the Public Utility Regulatory Policies Act even though its total power production capacity exceeded the law’s 80-MW limit (21-1126).

FERC had justified its March 2021 decision under its longstanding “send-out” analysis, which determines a facility’s capacity based on the electricity it can actually deliver to an interconnecting electric utility.

Broad Reach Power’s Broadview Solar project included solar panels with a gross capacity of 160 MW DC and a 50-MW battery, but the project’s inverters allowed it to produce and deliver only 80 MW to its interconnection with NorthWestern Energy’s (NASDAQ:NWE) transmission system.d.

“The commission’s determination that Broadview is a qualifying facility with a ‘power production capacity … not greater than 80 MW’ because its component parts, working together, produce no more than 80 MW of grid-usable AC power was reasonable and well-supported by the statute’s text, structure, purpose and legislative history,” the D.C. Circuit said in its decision.

In upholding FERC’s order, the court rejected challenges by NorthWestern and the Edison Electric Institute, which argued that FERC exceeded its authority because the “power production capacity” of Broadview’s facility should be the total amount of DC power generated by the solar array and not the grid-usable AC power produced by the inverters working in conjunction with the solar array and battery.

PURPA was enacted in 1978 to encourage alternative energy generation by “qualifying small power production facilities” (QFs). It requires utilities such as NorthWestern to purchase a QF’s generation output, “providing those facilities with a guaranteed market,” the court noted.

Montana has been an especially contentious front for PURPA disputes in the West, where utilities contend the law requires them to integrate large volumes of QF renewable resources at contracted rates far above market rates.

Circuit Judge Justin Walker dissented in part from his colleagues on the three-judge panel, Circuit Judge Cornelia Pillard and Senior Circuit Judge David Sentelle, who drafted the majority opinion.  

PURPA “gives lucrative benefits to small facilities that produce solar power,” Walker wrote. “It defines them as facilities with a ‘power production capacity’ of no more than 80 MW. … Because Broadview can produce 80 MW for its inverters while it simultaneously produces 50 MW for its battery, Broadview’s facility is capable of producing more than 80 MW of power. So it is too large to be a ‘small facility.’ For that reason, I would grant the petitions, vacate the rehearing orders and remand to FERC for reconsideration.”

The case took an unusual twist at FERC before reaching the appeals court.   

In September 2020, FERC broke with its own precedent by deciding the Broadview project could not be certified as a QF because it exceeded the 80-MW cap despite its limited interconnection. Its decision aligned with the arguments of NorthWestern and EEI.

The commission’s lone Democrat at the time, Richard Glick, dissented. The commission’s decision, Glick wrote, “will make QF status turn on the capacity of any one component of the facility, rather than the actual power production capacity of the facility itself. That conclusion finds no support in the statute, our precedent or common sense.” (See Montana Hybrid Ruling Departs from PURPA Precedent.)

In March 2021, with Glick now chairman, FERC set aside its prior ruling, reinstated its send-out analysis, and determined Broadview could be a QF. (See FERC Reverses Ruling on Montana QF.)

“It is not fathomable to conclude that Congress would be more concerned about the electricity a project could theoretically generate on its own but not deliver to any customer,” Glick said at the time. “Instead, since the statute is all about the sale of a project’s output, the appropriate way to look at a facility is to assess how much can actually be sold to the purchasing utility.”

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NARUC Panelists: Rate Design Key for the Clean Energy Transition

Getting rate design right is important to the clean energy transition because it will help determine the best resource mix and ensure customers have opportunities to cut their bills with demand response and distributed resources, experts said at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit this week.

“The reason that I think there’s no more exciting topic than rate design is because it truly sits at that intersection of every other aspect of the energy system: affordability, reliability; all of the conversations we’re having around grid modernization, integration of different resources, customer choice,” said former Virginia State Corporation Commissioner Angela Navarro, now head of state regulatory affairs for Richmond-based climate technology company Arcadia. “All of those things are central to determinations on rates.”

Smart meters are on most homes in the country now, while rooftop solar and electric vehicles are becoming increasingly common; how those resources impact rates is very important, Navarro said. Storage has huge potential, but that can only be harnessed with the right rate design that informs its owners when to charge and discharge.

On the other side, the right rate design can help avoid negative impacts on the grid, such as by encouraging customers to charge their EVs during off-peak hours, she added.

Supply is going to be more variable in the future because of the growth of intermittent renewables and more common extreme weather, said Lon Huber, Duke Energy vice president of pricing and customer solutions.

“But fortunately, with technology, we have an increasing number of tools to use to start shaping load to match the more variable supply out there,” Huber said.

Sending those price signals far and wide requires approval from regulators and the right technology; it cannot happen overnight, he added. On top of smart meters, utilities need field area networks, data management systems and updated billing systems that can take years to put in place.

Smart meters have been rolled out to 75% of the nation’s customers and despite being in place for years in many jurisdictions, their use rarely matches their potential, said Travis Kavulla, NRG Energy vice president of regulatory affairs.

“We’re still talking about single-digit percentages of those smart meters that are used to do anything to actually interact with customers in terms of sending a price signal or any other incentive to flex demand,” Kavulla said.

Kavulla recently wrote a paper for an Energy Systems Integration Group effort looking into how retail pricing could be used to get customers to respond to grid needs, called “Why is the Smart Grid So Dumb? Missing Incentives in Regulatory Policy for an Active Demand Side in the Electricity Sector.” It has been a more than a decade since federal stimulus dollars gave most states the push to install advanced metering, and despite soaring rhetoric from that time, the investment has done little to make demand an active part of the electric industry, he argues.

“My basic proposition is this: that someone somewhere has to face the clear price incentives to accurately manage demand in order for it to happen,” Kavulla said. “And all too often in our regulatory schema that we set up for ourselves, regulated utilities themselves lack clear incentives to do so. And even for competitive retailers like NRG, we face an incomplete set of incentives to make these kinds of investments in demand flexibility.”

Getting the rate signals right could mean huge savings, with New York state estimating it could cut the cost of compliance with its climate mandates by a third, while PJM identified retail rate design as one of five key focus areas for successfully decarbonizing the grid, he added.

Kavulla would like to see more jurisdictions set up opt-out time-of-use pricing to tap the demand resources that advanced metering has made available. Customer adoption of complex rates under opt-in constructs are too low.

“As much as my inner libertarian would like to avoid this, regulators really cannot escape making solid decisions on behalf of customers in highly regulated industries like these,” Kavulla said.

Opt-in regimes usually produce better responses from customers who affirmatively decide to participate, said Huber. The system works too, with Huber noting Arizona has seen up to 60% participation in time-of-use rate programs.

“I think opt-in in the long run is better, but it takes time,” Huber said. “And it takes a lot of marketing [and] a lot of education to get it done.”

The Future of Solar

Getting rate design right is important for the solar industry as rooftop panels become increasingly common in many jurisdictions, leading to often thorny debates about how to pay for their excess output going forward, experts said an earlier panel on Sunday.

“Increasingly some of the issues that we’re beginning to tackle are how do we sort of evolve the industry from what has been a traditional approach to behind the meter resources,” Solar Energy Industries Association Senior Director of Utility Regulation and Policy Kevin Lucas said. “And how do we evolve that in a way that’s going to make sure that regulators, policymakers, customers and utilities are getting the most bang for the buck out of the resources that they’re putting onto the grid?”

SEIA is working in Arizona now to get a system in place that encourages more growth of solar-plus-storage than its current “net billing” structure, which does favor storage but incentivizes its use to shave the customer’s own peak rather than the system peak. Customers get paid less for exporting power to the grid than they do shaving their own demand.

SEIA would like to see batteries controlled by utilities in a program where they can be called on up to 30 times a year for up to three hours at a time and they get paid based on response to those signals.

“So, if a customer chooses to participate in a given event, they will export energy, that energy is going to be measured, and at the end of the year, they will get a credit based on how well they perform during these specific calls,” Lucas said.

Some 760,000 customers have solar installations on their homes, but just 47,000 customers around the country have adopted storage, said Sunrun Senior Manager for Public Policy Thad Culley. Most of the customers with storage have bought systems to improve their resilience because they live in areas that experience outages more often.

Expanding that market to a bigger number of customers and getting them to work with the grid is going to take some new rates, Culley said.

“You’re going to need to have some kind of predictable value stream going forward to motivate the customer to want to play nice with the grid and do the types of grid support services that are valuable,” Culley said.

With the right incentives, those customers could even provide more specific services that benefit the local grid, he added.

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FERC OKs WEIM Changes for Washington Cap-and-trade Costs

FERC on Friday approved Western Energy Imbalance Market (WEIM) tariff revisions to allow generators to include costs associated with the Washington cap-and-trade program in their default energy bids and commitment costs.

The commission approved the revisions over the objection of the Utah Division of Public Utilities (UDPU), which argued the rule changes run afoul of the U.S. Constitution because they impose an unlawful “border tax” on electricity imported into Washington (ER23-474).

WEIM operator CAISO filed the tariff changes late last year in anticipation of the Jan. 1 roll-out of Washington’s cap-and-trade regulations, which require any in-state emitters of more than 25,000 metric tons of carbon a year — including electricity generators — to acquire allowances to cover their emissions. The rules also apply to any electricity imported to serve Washington demand.

CAISO’s rule changes have to do with the reference levels the ISO uses to calculate a resource’s default energy bids and commitment costs for the WEIM. In its filing with FERC, the ISO proposed to alter the reference levels to allow generators selling into Washington to reflect GHG compliance costs in their market bids to ensure that those resources don’t appear be less expensive than their actual costs.

CAISO modeled the changes on tariff provisions already in place to accommodate California’s cap-and-trade program, which is administered by the state’s Air Resources Board (CARB). Under those provisions, the reference levels used in the default energy bid and commitment costs are based on a GHG allowance price derived from the average of two index prices published by separate vendors.

Washington’s cap-and-trade program is not tied to CARB’s, and the Washington-specific provisions approved by FERC on Friday differ in their details because the state’s Department of Ecology will not be holding an allowance auction until later this month, meaning there is not yet a published allowance price available to set the reference level. CAISO instead proposed a three-phase rate that will change in response to certain “triggers,” FERC noted.

In the first phase, before the first auction, CAISO will rely on a reference rate of $41/metric ton (MT), the halfway point between the Ecology Department’s floor and ceiling prices of $19.70/MT and $72.29/MT, respectively. For the second phase, CAISO will use the clearing price from the most recent quarterly auction until index prices become available. In the third phase, the ISO will rely on the average of two index prices from separate vendors, similar to its treatment of the CARB program.

The ISO contended that an index price would eventually provide a more accurate reflection of the price for Washington allowances.

“CAISO indicates that while the auction price is a starting point, as Washington’s cap-and-invest program evolves, CAISO expects market participants will engage in bilateral trading, which will cause deviations from the auction price.  According to CAISO, an index price, updated daily on weekdays, provides a timelier estimate of the allowance price,” FERC wrote.

Constitutional Questions

In approving the WEIM tariff provisions, FERC rebuffed the sole protest by the UDPU, a Utah agency charged with investigating consumer utility complaints and monitoring utility operations to ensure compliance with state Public Service Commission rules.

The UDPU contended that the tariff changes violate the Constitution’s Supremacy Clause because they subject out-of-state generators to Washington’s state-levied allowances, contravening FERC’s “exclusive authority to regulate the sale of electric energy at wholesale in interstate commerce.”

“UDPU states that the CAISO adders for compliance with state-specific cap-and-invest programs will affect the set of resources selected for generation in the WEIM, causing commission-jurisdictional markets to clear in significantly different ways than they would in the absence of those directly-imposed bid costs,” FERC noted.

The agency had also argued that Washington’s cap-and-trade program is unconstitutional under the dormant Commerce Clause because it imposes a “border tax” on energy imported into Washington. And it additionally contended that the program provides preferential treatment to in-state interests because Washington utilities are provided a free allocation of GHG allowances, buffering the state’s ratepayers from the burden of some compliance costs.

The commission said it was “not persuaded” by the UDPU’s arguments, noting that it could only consider whether the tariff provisions were just and reasonable under the Federal Power Act, and not the legality of the underlying law motivating the provisions.

FERC wrote that the revisions “simply allow generators to incorporate compliance costs associated with Washington’s cap-and-invest program in their default energy bids and commitment costs, which account for the variable costs of generation and provide generators a reasonable opportunity to recover their costs.” Those revisions are consistent with other commission-accepted tariff provisions that accommodate the compliance costs associated with state environmental requirements — including in the WEIM, the commission said.

The commission similarly found the UDPU’s “border tax” argument to be aimed at the constitutionality of the cap-and-trade program, saying a FERC proceeding was not the proper venue for addressing such a question.

“In any case, if the commission were to reject CAISO’s filing based on constitutional grounds, and if Washington’s cap-and-invest program were not ultimately enjoined by a federal court, generators would be deprived of the opportunity to recover costs that they are legally obligated to incur,” the commission said. “As long as the tariff revisions at issue apply to the mandatory compliance costs incurred by generators within the borders of Washington and which are subject to Washington’s jurisdiction, we are required to allow the opportunity for their recovery.”