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November 9, 2024

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FERC Rejects SPP Self-funding Proposal for TOs

FERC last week rejected SPP tariff revisions that would help transmission owners continue to self-fund network upgrades to interconnect generators (ER22-2968).

The commission found in a 3-1 decision on April 14 that SPP had not demonstrated that its proposed pro forma facilities service agreement and associated tariff revisions were just and reasonable and not unduly discriminatory or preferential (ER22-2968).

The grid operator sought approval of a proposal to allow TOs to self-fund the upgrades and recover their costs and a return on investment from an interconnection customer.

American Clean Power Association, Advanced Power Alliance, the Solar Energy Industries Association, the Natural Resources Defense Council and the Sustainable FERC Project all intervened against the revisions. They said the self-funding would heap costs on generation developers if they didn’t pay for the upgrades themselves.

FERC said SPP’s proposal ran counter to Order 2003, which established standard interconnection procedures to limit opportunities for transmission providers to favor their own generation and facilitate market entry for generation competitors by reducing interconnection costs and time.

The commission said the revisions could lead to “greater uncertainty” for interconnection customers that might not elect to a TO’s initial funding for upgrades, but then reverse course near the study process completion. It agreed with the clean energy advocates’ argument that such circumstances could lead to late-stage withdrawals and delays in administering the generator interconnection queue, further undermining Order 2003’s goals.

SPP and Xcel Energy subsidiary Southwestern Public Service contended that a non-binding indication provides an interconnection customer advance notice that a TO intends to self-fund prior to negotiation of generator interconnection. They also noted that FERC approved MISO’s request to require TOs to make binding self-funding decisions before GIA negotiations begin.

FERC disagreed, saying the non-binding self-funding election means a TO can make a choice when the study process begins and then do the opposite. The commissioners said they accepted MISO’s revisions to add deadlines by which TOs must make both non-binding and binding elections before the GIA negotiations. They said SPP’s proposal includes only the non-binding indication provision.

“Having more information earlier is beneficial not harmful,” the commission wrote. “By denying an earlier indication of the transmission owner’s potential election, interconnection customers will be denied access to information at an earlier stage under the tariff. That denial of information actually creates uncertainty; it does not protect against it.”

Commission Nixes PRM Waivers

The commission on Monday also rejected SPP tariff revisions that would allow load-responsible entities (LREs) to obtain two-year exemptions from deficiency payments assessed for not meeting the grid operator’s new resource adequacy requirement, finding the grid operator had not demonstrated the proposal was just and reasonable (ER23-636).

The commission found the RTO’s proposal would undermine the structure of deficiency payments, set out in a 2018 filing to establish the resource adequacy requirement. LREs unable to meet the requirement are subject to a deficiency payment equal to the payment amount multiplied by the cost of new entry and a multiplication factor of the footprint’s excess capacity relative to the planning reserve margin (PRM).

“The complete elimination of the deficiency payment, even under the criteria of the proposed exemption process, removes the incentive for LREs to procure the capacity needed to collectively ensure that the SPP footprint maintains resource adequacy,” the commission wrote.

FERC has said SPP’s proposed deficiency payment “provides a signal to LREs to plan ahead to satisfy the [resource adequacy requirement].”

The commission found that while the proposed exemption is limited to two hours each time the grid operator increases the PRM, LREs would be able to seek the exemption each time there is an increase. It said that, were SPP to make consecutive increases, deficient LREs with exemptions wouldn’t be required to meet their resource adequacy obligations for an extended time.

FERC also said the proposed tariff language is not clear as to how the proposed exemption process would work.

Denise-Buffington 2022-07-11-(RTO-Insider-LLC)-Content.jpgDenise Buffington, Evergy | © RTO Insider LLC

SPP last year increased the PRM to 15% from 12% for the 2023 season and filed the proposed exemption language. (See SPP Board Bypasses Stakeholders on PRM Obligation Exemptions.)

Evergy’s Denise Buffington, who warned last October that the proposal would fail at FERC, suggested SPP’s future tariff revisions should allow more time for compliance.

“It takes time to get steel in the ground, and if SPP continues to increase the performance or planning reserve margin on an annual basis, we’re never going to be able to meet it,” she said during a Resource and Energy Adequacy Leadership Team meeting Thursday. “When we think about setting out new requirements, we have to do them far enough in the future so that load-responsible entities can actually comply.”

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Vermont Gas Utility Explains its Effort to Electrify Customers

Electrify Now, an organization trying to speed the electrification of the U.S., took the counterintuitive step of inviting a natural gas utility to one of its monthly webinars this week, giving it a warm welcome.

Vermont Gas Systems (VGS) serves about 55,000 customers in and near Burlington, the largest city in the state and its only large region with a concentrated population. VGS is the state’s only gas utility but is attempting to reposition itself as a thermal solutions utility offering customers multiple strategies for heating their structures.

VGS is actively marketing electric heat pump water heaters to its customers and planning to offer centrally ducted heat pumps as well. The strategy is to profit from the sale, lease and service of that equipment, even as the revenue from powering them goes instead to the local electric utility.

Eventually, VGS plans to move into ductless heat-pump systems because many of the houses in Vermont currently use hydronic systems, and retrofitting them with ductwork would be a major undertaking.

VGS also is pursuing a renewable natural gas (RNG) strategy that will keep it in the gas-delivery business for some time to come, even if it is not selling as much gas to as many people. Its proposed RNG import contract drew extensive negative public comments to the state Public Utility Commission and led to charges that VGS is attempting to greenwash its image with the electrification effort.

As he opened the online session Wednesday, Brian Stewart of Electrify Now took a swipe at RNG, framing it as expensive non-solution to the imperative for gas utilities to “decarbonize their business without going out of business.”

“So imagine our surprise and delight when we came across this,” he continued. “Could it be that a gas utility is promoting electric heat pump water heaters? What’s going on here? Are they embracing electrification as a way to decarbonize their business, rather than actively resisting it?”

VGS New Product Development Manager Morgan Hood explained that decarbonization is part of the goal, along with maintaining a revenue stream and relevance in a changing marketplace. For multiple reasons, VGS is likely to see its gas customer base shrink rather than grow.

Though its governor is Republican, the Green Mountain State is firmly Democratic in its politics and consistently ranks among the most environmentally conscious states. Gov. Phil Scott vetoed a clean-heat bill last year and has said the version working through the legislature this year looks too similar and too expensive. But there is popular momentum behind it and smaller steps toward the same goal.

There are no bans now on new gas connections or gas-burning equipment in the VGS service area, but the utility views bans as inevitable, Hood said. VGS abandoned a previous attempt to expand geographically amid controversy and has no expansion plans now, she said.

And while natural gas has historically been pitched as cheaper and cleaner than the heating oil that many Vermonters use during their long, cold winters, new heat pump technology can be less expensive to operate than either.

Then there is the climate crisis, which Hood said VGS, and many of its customers, believe is real. Heat pumps generate no emissions of their own, and if the electricity powering them comes from clean sources, the carbon footprint is radically smaller than gas-burning equipment.

“More and more of our customers are looking to decarbonize,” she said. “If we want to continue to serve our customers, if we want to continue to be a thermal solution provider — which we do — significant changes are necessary.”

VGS is one of the few utilities that still installs and services gas-burning equipment in customers’ buildings with its own personnel, Hood said, so adding the new electric equipment to its offerings is not a major stretch.

But swapping out furnaces and water heaters is only part of the solution. VGS began its energy-efficiency program in the 1990s and has in-house engineers and energy auditors to help customers improve their homes.

“Houses in Vermont tend to be older, and many are in desperate need of weatherization,” Hood said. “If we intend for heat pumps to carry the full heating load in this very cold state and displace fossil fuels effectively, affordably and efficiently, we need to set these homes up for success with air sealing and insulation.”

VGS is offering its services to non-customers as well. Hood said the PUC is amenable to this because of the scarcity of private contractors to do the work. But VGS has limited itself geographically to within 5 miles of its gas lines to control transportation costs.

Shortage of skilled labor and supply chain constraints are two potential obstacles to VGS expanding this initiative, Hood said, and both have already cropped up.

Ultimately, Hood said, the possibilities move beyond single-building heat pumps to local ecosystems of shared geothermal energy and recycled waste heat from commercial users.

Stewart asked: “Does VGS imagine a future where they’re a heat provider and not a fossil gas provider?”

“Yes, and it’s daunting,” Hood replied.

It is also early in the process. VGS does not know how it will accomplish its goal of achieving net zero by 2050, Hood said, adding that probably no single strategy — RNG, hydrogen or electrification — will carry it there.

Joe Wachunas of Electrify Now asked if VGS is expecting its income to decrease as it converts customers to electric heating solutions.

“These solutions we’re proposing, although profitable, aren’t profitable in the same way delivering natural gas is profitable,” Hood said. “We are learning to look at that.”

There likely will be a gradual rollout and a bit of a balancing act, as VGS works to reach its goals while keeping investors happy, she added.

Wachunas asked whether other gas utilities perceive VGS as a trailblazer or a turncoat.

“I think the industry in general still regards us as quirky,” Hood replied. “If we can model the business case, the financial case for evolving a gas utility in this way, then I think people’s ears will perk up; maybe we’ll be leaders.”

Stewart and Wachunas raised what may be one of the hardest aspects of electrification: how to engineer a smooth transition at an acceptable cost.

Hood listed several factors at play. One priority is not sticking lower-income customers who cannot electrify with a rapidly increasing share of the gas system’s costs as wealthier customers electrify. Another is not harming large commercial customers.

There may be future efforts to press for electrification of areas where gas service becomes uneconomical because expensive work is needed, or because there are too few ratepayers left. There currently are not any plans for such a shrinkage of the distribution network, but that does not mean there never will be.

On the positive side, VGS was only founded in 1965. Its infrastructure is much younger than many other gas utilities’ and unlikely to need a lot of expensive work any time soon.

“I don’t have any easy answers,” Hood said. “It’s really, really nuanced.”

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NJ Backs Studies of OSW Impact on Marine Life

New Jersey’s Board of Public Utilities and Department of Environmental Protection on Wednesday approved $2 million in funding to study the impact of offshore wind development on marine life.

The funds, part of the $26 million Offshore Wind Research and Monitoring Initiative (RMI), will pay for projects that include deployment of a whale detection buoy, as well as studies to evaluate general species diversity in offshore wind development areas and better understand offshore movement of harbor seals, the agencies said in a release.

The funds will additionally pay for the state to join the Responsible Offshore Science Alliance, a nonprofit organization leading a collaborative effort to advance fish and fisheries research related to offshore wind.

The RMI program is jointly administered by the two agencies and is funded with contributions of $10,000 for each megawatt of capacity from the two projects approved by the BPU in the state’s second OSW solicitation. The $2 million in additional expenditures take the total spent from the fund to $8.5 million.

The addition of the new projects comes as the state undertakes a third solicitation for offshore wind projects, with the potential to increase OSW project approvals to substantially above the 3.758-GW capacity already approved. The latest solicitation, opened on March 6, could award between 1.2 and 4 GW, and perhaps more, according to the BPU’s solicitation guidance document. (See NJ Opens Third OSW Solicitation Seeking 4 GW+.)

The advance of the projects has stoked opposition from commercial fishers, coastal residents and the tourist and other industries, with opponents seizing on a series of whale deaths along the New Jersey shore to raise concerns about the impact of the growing wind sector on marine life. Opponents have held several protests, and two of the state’s Republican congressmen, Reps. Jeff Van Drew and Chris Smith, held a hearing on the issue, calling for a halt to the offshore wind projects.

Although little work has started on the OSW projects, environmentalists concerned about marine life say the studies and ocean floor analysis advance work could have impacted the whales by generating noise undersea.  

Responsible Development

Federal marine authorities have said they see no connection between OSW developments and whale deaths, and state officials have shown no signs of slowing the projects’ development.

The state, however, has paid increasing attention to efforts to gauge the impact on marine life, approving more than $3.4 million in March for three initiatives to research the impact on wildlife and fisheries. (See NJ Awards $3.4M to Study the Marine Impact of Turbines.)

Shawn M. LaTourette, the state’s commissioner of environmental protection, said the OSW projects are key to mitigating the effects of climate change, and the newly announced marine studies will work to mitigate any impact on marine wildlife.

“These projects will continue to advance the collection of baseline scientific information that will help ensure the responsible development and operation of offshore wind facilities that protect our coastline and its natural resources,” he said.

The whale detection buoy funded in the newly announced expenditure of RMI funds will listen for whales, and detections will be reviewed and used to mitigate risks associated with vessel strikes and future construction noise, according to the BPU and DEP.

Another study will look at environmental DNA (eDNA) to monitor species that “are protected or otherwise important to maintaining the ecological integrity of coastal waters and are important to New Jersey’s recreational and commercial fisheries,” the two agencies said.

A third study will collect data on the movement patterns and health of seals that spend the winter in the Great Bay area north of Atlantic City.  “This study will tag and collect baseline health data for harbor seals, such as stress hormones, that should help assess the impacts of future OSW-related activities, including construction and operation, on harbor seals,” the agencies said.

BPU President Joseph Fiordaliso said the projects would “assist us in protecting the environment as we move forward to reach Governor [Phil] Murphy’s goal of 11 GW of offshore wind capacity by 2040.”

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NERC Takes Step Toward New IBR Standard

NERC’s Standards Committee moved forward Wednesday with four standards development projects, including one that could lead to new rules for inverter-based resources (IBR).

Vice Chair Todd Bennett from Associated Electric Cooperative led the relatively brief meeting, filling in for chair Amy Casuscelli of Xcel Energy who was absent.

The new IBR standard arose from Project 2021-04 (Modifications to PRC-002 — Protection and Control), which was initiated to update PRC-002-3 to account for the expansion of IBRs such as solar and wind farms. NERC said the standard needed to be revised to ensure that system planners could access data on grid disturbances for post-mortem event analyses.

Phase 1 of the project was based on a standard authorization request (SAR) submitted by Glencoe Light and resulted in PRC-002-4 (Disturbance monitoring and reporting requirements), which was approved by FERC last week (RD23-4). The committee voted Wednesday to begin Phase II, inspired by a SAR from the Inverter-base Resources Performance Task Force (IRPTF).

Rather than further modify PRC-002, Phase II aims to create a new standard specifically designed around IBRs. Southwest Power Pool’s Charles Yeung, who is currently serving as the Project Management and Oversight Committee’s liaison to the standard drafting team (SDT), explained that the team felt that this approach was the best way to adapt NERC’s standards to the arrival of new technology.

“One of the charges to the team — that’s not in the SAR — was not to upset the current methodology [for determining the] location of DDR [dynamic disturbance recording] data. And of course, that methodology is based on a system with synchronous generation,” Yeung said. “The addition of IBRs is really … about the black box performance of IBRs. So even though it is about data location … it’s really a very separate purpose.”

Participants in the meeting were supportive of addressing IBRs in a new standard. Philip Winston, formerly of Southern Co., called the drafting team’s plan “a much better approach than trying to shoehorn new technology into old standards.” He added, “The times, they are a-changing.”

The SAR passed unanimously.

New Ride-through SAR Approved

Members also agreed April 19 to move forward development on Project 2020-02 (Modifications to PRC-024 —generator ride-through), accepting the SAR as revised by the project’s SAR drafting team and appointing the team as the SDT for the project.

Some members expressed confusion at the history of Project 2020-02, for which the committee approved a different SAR almost a year ago. (See NERC Standards Committee Moves Projects Forward.) This new SAR was submitted by NERC staff last May after an analysis of system disturbances found that PRC-024-3 (Frequency and voltage protection settings) did not account for many causes of tripping detected in the analysis. The Standards Committee assigned it to Project 2020-02 because of the similarity in subject matter.

Latrice Harkness, NERC’s manager of standards development, clarified that the previous SAR is not “being disposed of,” but that the SDT will need to examine both SARs to determine how it wants to incorporate them.

While the motion passed without objection, Marty Hostler of the Northern California Power Agency reminded members to be mindful of the burden that frequent changes to standards places on industry.

“I remember there being a big push for PRC-024. Everyone had to get all the studies done, and then it got changed, and then it got changed again. And now we’re saying it’s not suitable, or may not be suitable,” Hostler said. “Industry groups like us and our members devoted a lot of time to complying with the standards … and now we’re going to possibly have to do the work again. So, let’s just keep that in mind and not just push a project through just for the sake of getting it done in a certain time frame.”

IBR Event Reporting, PRC Successor

The committee turned to the SAR drafting team for Project 2023-01 (IBR event reporting), which is intended to revise the reporting thresholds for generation loss events to account for the performance of renewable resources. NERC’s Reliability and Security Technical Committee endorsed the SAR at its December meeting, and the Standards Committee authorized the solicitation of drafting team members in January. Twelve nominations were received, all of them recommended by NERC for appointment. The committee approved them all unanimously.

Finally, members voted to post the draft standard PRC-005-7 for a 45-day formal comment period, with an initial ballot to be conducted in the last 10 days of the comment period. The standard is intended as a successor to PRC-005-6 (Protection system, automatic reclosing, and sudden pressure relaying maintenance) to provide clarity on the grid elements to which its maintenance and testing requirements apply.

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Jersey City Unveils New EVs, Looks to Double Number of Charging Points

JERSEY CITY, N.J. — The state’s second largest city unveiled a new fleet of 20 Chevrolet Bolts and five electric garbage trucks Tuesday in an Earth Day celebration of the city’s aggressive effort to transition away from fossil-fueled vehicles.

In a press conference in front of the vehicles, Jersey City officials also said they expect to issue a request for proposals seeking partners to expand the number of available public charging sites and to help boost the number of private electric vehicles. Mayor Steven Fulop said the city currently has about 30 chargers, most of which are available to the public, and the goal of the RFP is to more than double that number, perhaps to 70.

The event came a day after the New Jersey Board of Public Utilities (BPU) announced that the third phase of the state’s popular Charge Up New Jersey program, which awards incentives of up to $4,000 for an EV purchase, would close because the allocated funds had been exhausted. The program awarded about $35 million for the purchase or lease of 10,000 vehicles, the BPU said.

The Bolts have just gone into service as messenger vehicles, replacing gasoline-powered vehicles in the task of ferrying documents and other items around the city and carrying city inspectors to inspection sites. With a range of about 220 miles, the Bolts are well suited for the task, doing on average 65 to 100 miles a day, Business Administrator John J. Metro said.

The garbage trucks, the first of which arrived last summer, pick up trash in the city’s parks and recharge every night after doing 40 to 90 miles a day — well within their range, employees said. The city purchased the trucks with $2.046 million awarded in 2019 by the state’s Volkswagen Environmental Mitigation Trust, and city officials say the vehicles were the first electric garbage trucks to go into service on the East Coast.

The trucks are charged by solar panels on the roof of the city’s Department of Public Works building, and the Bolts will be charged there when needed.

Fulop said the city’s growing EV fleet “speaks to the overall commitment we have about providing more access to electric vehicles here in Jersey City.”

“If we are going to be encouraging residents to move in this direction, the city should be setting an example by doing it ourselves,” he said.

Fulop said the city is still evaluating the economic benefits of using garbage trucks fueled by electricity rather than diesel.

“It’s surely not going to cost us more; that’s what we know for certain,” he said. “But how much we save is to be determined.”

Metro said the purchase of the Bolts, made with the help of funds from the U.S. Department of Energy, is part of an ongoing effort to replace the city’s entire car fleet. Fulop said the city has about 1,000 vehicles.

“We plan on doing this every year as long as the grant funding is available,” he said, adding that it could take up to 10 years.

The garbage trucks are among at least 52 trucks in 25 municipalities paid for by the New Jersey Department of Environmental Protection using funds either from the Volkswagen trust or the Regional Greenhouse Gas Initiative (RGGI). The RGGI fund especially has invested heavily in transportation, which is the city’s largest source of greenhouse gas emissions at 37%. (See NJ To Accelerate RGGI Fund Expenditures.)

Marking Earth Day a year ago, the DEP announced grants of $7.6 million to fund local government vehicle purchases, and the city of Paterson announced the purchase of 38 EVs for use by housing and health inspectors and its own Department of Public Works.

Jersey City in 2021 released its own Climate Change and Energy Action Plan, which called for an 80% reduction in GHG emissions by 2050 and the city vehicle fleet to be 100% electric by 2030.

Barkha Patel, director of the city’s Department of Infrastructure, said at the press conference that when her department started trying to electrify the city’s fleet six years ago, “we didn’t know how much we could expand the scope of this work.” But the city has steadily introduced a variety of programs to tackle the issue from different directions, she and other city officials said.

In one program, city workers can book a vehicle through an online ride-sharing scheduling system when they need it, so that individual employees are not assigned a specific vehicle all the time, allowing city vehicles to be used more efficiently. It now has 25 vehicles assigned to it, and the city is looking to replace them with EVs, Metro said.

The city also introduced a ride-sharing program operated by Via Transportation in 2020 to provide an option in areas of the city underserved by existing public transport, and now has 24 microvans and two SUVs. In 2022, the New Jersey DEP awarded the program $600,000 from RGGI for the purchase of four EVs and four Level 2 chargers. And the state in March awarded additional RGGI funds for the project to buy 15 to 20 Level 2 chargers and two to four DC fast chargers.

Incentive Support Halted

In announcing the closure of the Charge Up New Jersey program, the BPU said the state at the end of last year had more than 91,000 EVs, of which 25,000 were put on the streets with support from the three rounds of program funding. The board said applications already filed would consume the remainder of the $30 million set aside for the program by the legislature.

In the latest phase of the program, the BPU had shifted from a rebate system to one in which the incentive would be deducted from the vehicle cost at dealerships and showrooms. It reduced the maximum incentive available from $5,000 in the first two phases to $4,000 and continued a policy enacted in the second phase of awarding the maximum incentive only to vehicles priced less than $45,000. The changes were part of an effort to ensure that incentives would go only to “incentive essential” customers, those who would only buy an EV if there was an incentive available. (See NJ Cuts Incentives for New Phase of EV Promotion.)

“Due to the success of the point-of-sale incentive, available funds for this fiscal year are projected to be fully committed for eligible orders, purchases and leases by April 17, 2023,” the agency said in a letter to the state Department of the Treasury.

The program will continue offering $250 for the installation of home chargers, the BPU said.

ChargeEVC, a coalition of trade and environmental groups that advocates for greater adoption of EVs, said the closure of the program showed the level of public interest. The group said that 9.8% of all light-duty vehicles sales in New Jersey in 2022 were EVs, “ahead of the national average of 7%.”

“We can expect that the program will reopen in the new fiscal year under a new and approved state budget,” ChargeEVC said in a release, although the BPU’s release did not mention the future of the program.

The ChargeEVC release also quoted Jim Appleton, president of NJCAR, a car dealership trade group, saying that “the stop-again, start-again nature of the program over the last three years has not been conducive to an orderly business environment, and that ultimately hurts dealers and consumers.”

“Customers must be able to rely on incentives in the marketplace, or they will lose interest,” he said.

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RTO Wind, Solar PPA Offer Prices Continue Rise in 2023

Offer prices for renewable power purchase agreements continued to rise in early 2023, ending the quarter more than one-third higher than a year earlier, renewable energy procurement platform LevelTen Energy reported Tuesday.

On average, solar PPA offers increased 8.5% from the fourth quarter of 2022 and wind PPAs were up 4.9%, the company reported.

The numbers are derived from LevelTen’s P25 Price Index, which represents 25th percentile PPA price offers that developers uploaded to the LevelTen Energy Marketplace — not actual transacted prices. A total of 260 price offers came from 207 renewable projects in six U.S. grid operators: CAISO, ERCOT, MISO, NYISO, PJM and SPP.

LevelTen said multiple factors affected the U.S. market in early 2023, including the uncertainty over the Inflation Reduction Act, evolving polices at all levels of government, rising capital costs and supply chain challenges.

Other factors had an outsized impact within individual markets.

Wind up in SPP; Solar Rises in MISO, NYISO

Wind offer prices jumped almost 21% in SPP during the quarter, for example.

“Growing wind penetration in SPP is having a material impact on market dynamics in the region,” said Gia Clark, senior director of strategic developer accounts at LevelTen. “Wind facilities there are facing a more challenging financial picture as increasing wind generation drives down capture prices for wind assets operating there. Plans to expand transmission capacity between SPP and MISO are undoubtedly a step in the right direction, but approving, permitting and constructing such infrastructure will take years.”

The biggest quarterly jump in solar PPA offer prices was in MISO, at almost 14%.

“The MISO interconnection study process now requires more upfront capital from developers to remove speculative projects from an overcrowded queue — adding costs and financial risk,” Clark said. “Developers also have little certainty around the outcome of studies, which have increasingly included interconnection costs far higher than historical norms. Proposed projects in MISO factor these growing costs and risks into PPA prices.” 

By a wide margin, the highest offer prices cited in the report were in NYISO, where solar PPAs surpassed $80/ MWh.

“NYISO has long been at the high end of pricing within the PPA market,” Clark wrote.

Across the six regions indexed, the P25 offers were 36% higher for solar in the first quarter of 2023 than the first quarter of 2022 and 35% higher for wind, LevelTen said.

Developers’ struggles to understand the implications of the IRA played a significant role in the market fluctuations, Energy Marketplace Vice President Rob Collier said in the news release. He noted LevelTen’s wind index showed its first decrease in nearly two years in the fourth quarter of 2022 before rebounding in the first quarter of 2023.

“Rapidly evolving regulations at the federal, state and regional level are creating an unstable environment, making it difficult for developers to price PPAs and contributing to the price swings we’re seeing in the market,” he said.

Key details on IRA tax credits were released in early April.

“While this additional guidance on the IRA was very welcome, it does feel like we’re taking one step forward and two steps back when evaluating all the new pieces of legislation that are poised to hinder renewable buildout,” Collier said.

He singled out a proposal in the U.S. Senate to end the moratorium on solar panel import tariffs.

“While this proposal currently looks unlikely to succeed, solar developers now have to account for the possibility that tariffs may be reintroduced sooner than expected. That uncertainty is likely reflected in their pricing,” he said.

Collier also cited multiple legislative proposals in Texas that would boost the fossil fuel industry and, in some cases, actively attempt to hinder renewables. “We have heard from some developers that they will be pausing development in ERCOT until a clearer regulatory picture emerges,” he said. (See Texas Legislature Moves Bills Remaking the ERCOT Market.)

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Impact of Berkeley Gas Ruling Debated

A federal appellate court ruling voiding the city of Berkeley, Calif.’s effective ban on natural gas in new buildings could have national impact if it withstands further review, but it doesn’t prevent all local efforts to electrify buildings.

On Monday, the 9th U.S. Circuit Court of Appeals reversed a district court’s ruling and agreed with the California Restaurant Association that the city’s gas ban is pre-empted by the federal Energy Policy and Conservation Act (EPCA), which gives the Department of Energy authority to set energy conservation standards for appliances such as furnaces and water heaters.

But while the three-judge panel ruled unanimously against the law, one of the judges raised concerns in his concurring opinions that could undermine the ruling’s sweep. And most of the jurisdictions that have moved to electrify buildings have taken approaches not affected by the ruling.

“While the 9th Circuit decision does impact some aspects of local authority to electrify buildings, it is far from a knockout blow,” Amy Turner, senior fellow at the Sabin Center for Climate Change Law at Columbia Law School and head of the Cities Climate Law Initiative, wrote in a blog post. “The 9th Circuit decision has different implications for different building electrification requirements depending on location, legal landscape and policy approach.”

Closely Watched Case

Berkeley became the first U.S. jurisdiction to effectively ban new natural gas use in 2019, when it amended its building code to prohibit the installation of natural gas piping within newly constructed buildings. Since then, more than 70 jurisdictions have required or incentivized all-electric new buildings, according to the Building Decarbonization Coalition, with about 25 following Berkeley’s approach.

As evidence of the import of the Berkeley case, the states of California, Maryland, New Jersey, New Mexico, New York, Oregon, Washington and Massachusetts, as well as D.C. and New York City, filed amicus briefs with the court. About 20 Republican-controlled states, meanwhile, have enacted laws to pre-empt gas bans.

Berkeley argued that the EPCA’s pre-emption only covers regulations that impose standards on the design and manufacture of appliances, not regulations that impact the distribution and availability of gas.

DOE’s brief asserted that the EPCA only pre-empts “energy conservation standards” that operate directly on the covered products. It does not “prevent states and localities from adopting health and safety regulations that indirectly affect the quantity of energy or water used by” an EPCA-covered appliance, it said.

The EPCA’s pre-emption clause states that once a federal energy conservation standard becomes effective for a covered product, “no state regulation concerning the energy efficiency, energy use or water use of such covered product shall be effective with respect to such product.”

District Court Overruled

The U.S. District Court for Northern California dismissed the Restaurant Association’s challenge, saying EPCA’s pre-emption was limited to ordinances that facially or directly regulate covered appliances.

“But such limits do not appear in EPCA’s text,” the 9th Circuit wrote. “By its plain text and structure, EPCA’s pre-emption provision encompasses building codes that regulate natural gas use by covered products. And by preventing such appliances from using natural gas, the new Berkeley building code does exactly that.”

The court also rejected the city’s contention that — although a prohibition on natural gas infrastructure reduces the energy consumed by gas appliances in new buildings to “zero” — “zero” is not a “quantity.”

“It is well accepted in ordinary usage that ‘zero’ is a ‘quantity,’” the court ruled. “We doubt that Congress meant to hide an exemption to the plain text of EPCA’s pre-emption clause in a mathematical equation. …

“Put simply, by enacting EPCA, Congress ensured that states and localities could not prevent consumers from using covered products in their homes, kitchens and businesses. So, EPCA pre-emption extends to regulations that address the products themselves and the on-site infrastructure for their use of natural gas,” the court continued. “Congress thus indicated that EPCA pre-empts building codes, like Berkeley’s ordinance, that function as ‘energy use’ regulations. Put differently, EPCA does not permit states and localities to dodge pre-emption by hiding ‘energy use’ regulations in building codes.”

The judges also dismissed Berkeley’s claim that a pre-emption under the EPCA would conflict with the Natural Gas Act, which gives FERC jurisdiction over the transportation of natural gas in interstate commerce and the sale of gas for resale. They noted that the NGA “specifically exempted from” FERC regulation “the ‘local distribution of natural gas.’”

‘Troubling and Confused’

Judge M. Miller Baker (who sits on the U.S. Court of International Trade, but sat on the panel by designation) expressed reservations about the restaurant group’s standing to bring the challenge but joined the panel opinion in full.

In his own concurrence, Judge Diarmuid F. O’Scannlain said that he supported the association’s challenge only because of 9th Circuit precedent.

“I remain concerned that this area of law is troubling and confused, with tensions in the Supreme Court’s precedents, splits in the circuits and important practical questions unanswered,” he wrote. “Greater clarity and further guidance from the [Supreme] Court on how to navigate pre-emption doctrine … would be most welcome.”

The ruling does not apply outside the nine states and two territories of the 9th Circuit. If another circuit rules differently, the issue could make its way to the Supreme Court.

‘Consistent National Energy Policy’

Reichman Jorgensen Lehman & Feldberg, the law firm that represented the restaurant group, said the ruling “underscores the importance of a consistent national energy policy, which was Congress’ intent the whole time.”

“Cities and states should not be permitted to overrule energy decisions that affect the country as a whole,” partner Sarah O. Jorgensen said in a statement. “The panel’s unanimous decision that Berkeley’s ban on natural gas piping is pre-empted by EPCA sets an important precedent for future cases, especially with other cities considering similar bans or restrictions on the use of natural gas.”

The ruling “should invalidate the dozens of gas bans that have been enacted across the country over the past four years,” former Manhattan Institute senior fellow Robert Bryce wrote in a Substack column. “It may also mean that plans by federal authorities, including the Consumer Product Safety Commission, to ban or restrict the use of gas stoves, gas furnaces and other gas-fired appliances are kaput.”

Karen Harbert, CEO of the American Gas Association, which represents more than 200 gas distribution companies, called the ruling “a huge step … that will both safeguard energy choice for California consumers and help our nation continue on a path to achieving our energy and environmental goals. Natural gas has been one of the primary drivers to achieving environmental progress, and any ban on this foundation fuel will saddle consumers with significant costs for little environmental gain.”

“This is a win for consumers, and it’s not over yet,” former California State Sen. Melissa Melendez (R) tweeted. “The California Air Resources Board (CARB) wants to impose this ban on the entire state, so they issued rules that would require people to replace their broken gas water heater or gas furnace with an electric model. Now we wait to see if today’s Berkeley ruling negates the ban set by CARB for all of California.”

Different Approaches

But Columbia’s Turner noted that other jurisdictions chose different approaches than Berkeley, which used its authority to protect health and safety, citing natural gas’ contribution to asthma and climate change.

“In contrast, many other jurisdictions — in California and beyond — used their building code authority to require or incentivize all-electric construction. New York City took a third approach, enacting an air emissions standard for new buildings that was silent on the energy performance of any building or EPCA-covered appliance,” she said.

“Each of these approaches remains an option to at least some local governments looking to electrify new construction. In addition, local governments retain any authority over natural gas distribution they may be delegated by their states.”

She also noted that the EPCA includes a seven-factor statutory exemption to pre-emption for state and local building codes and that the 9th Circuit’s ruling does not automatically apply outside its territory.

“The key to moving forward: Don’t link legislation to specific appliances,” tweeted Claire Wayner, an associate with RMI’s Carbon-Free Electricity Program. “Focus on building-wide efficiency standards, or take the air quality route.”

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Wash. Lawmakers Pass Bill to Study Recycling of Wind Turbine Blades

Washington’s Senate on Monday unanimously approved a bill that directs Washington State University to study the feasibility of recycling wind turbine blades once they have reached the end of their useful lives.

The state’s House of Representatives had passed Senate Bill 5287 with some amendments, which the Senate reconciled on Monday. The bill calls for a study by the Washington State University Extension Energy Program to be turned in to the legislature by Dec. 1.

The legislation will go to Gov. Jay Inslee for signature.

“What we do with wind turbine blades has become an environmental concern,” said Sen. Jeff Wilson (R), who introduced the bill. “We’ve been putting up windmills on a large scale since the 1990s to make our energy green and clean. But those blades don’t last forever, and simply cutting them up and dumping them in landfills seems to defeat the spirit.”

SB 5287 calls for the study to cover:

  • the “cost, feasibility and environmental impact” of various methods of disposing of blades, including the potential for “reuse, repurposing and recycling;”
  • the availability of blade recycling facilities in Washington and other states;
  • possible incentives for creating recycling facilities in Washington;
  • “[v]arious mechanisms for establishing recycling requirements, or recycled content standards;”
  • options for “the design of a state-managed product stewardship program” for turbine blades.

The average lifespan of a wind turbine blade is 20 years, according to a Senate committee memo; the average length is 170 feet. Washington’s wind farms comprise about 3,400 MW of generating capacity. 

The study also would look at how a state-managed disposal program could be managed and examine the possibility of recycling blades made of steel, plastic and fiberglass.

Several weeks ago, the Senate Environment, Energy and Technology Committee heard testimony that the U.S. does not have a turbine blade recycling facility.

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New York Celebrates Completion of Renewable Projects

A spate of newly completed renewable energy projects in upstate New York — most recently, a wind farm on Friday — have brought the state 421 MW closer to its net-zero goal.

And downstate, after 22 years of buildout, the New York City area has surpassed 500 MW of installed solar capacity, most of it several kilowatts at a time on rooftops.

The progress upstate was announced Tuesday and keyed to Earth Week, as the eight recently completed projects are expected to reduce carbon emissions by nearly 600,000 tons a year.

The venue for the announcement was Grissom Solar, a 100-acre, 20-MW solar facility near Johnstown that was completed a month ago. Three other solar farms and three wind farms have been completed since last autumn and a small hydro facility was returned to service.

Dozens of additional projects are envisioned across the fields and hilltops of upstate New York as the state works to meet its statutory goals of 70% renewable energy by 2030 and 100% emissions-free energy by 2040.

The New York State Energy Research and Development Authority has a lead role in the process, not least by soliciting and contracting the projects.

 “Accelerating the development and completion of the dozens of wind and solar projects in our pipeline will continue to be a priority for NYSERDA,” NYSERDA President Doreen Harris said in a statement.

Progress has been steady if not blazingly fast. The eight recently completed projects celebrated Tuesday were awarded contracts in 2016 and 2017. New York has modified the process since then, creating the Office of Renewable Energy Siting to streamline the review of large renewable projects.

The 120 large-scale renewable energy and transmission projects now in New York’s pipeline total 14.2 GW, enough to bring the state to within a few percentage points of its 70% renewable goal if all were completed.

Many, of course, will not be built. Nevertheless, NYSERDA expects to announce contract awards in the summer for projects totaling at least 2 GW as a result of its sixth competitive solicitation.

Also on Tuesday, Con Edison (NYSE:ED) announced the solar generation owned by its customers in New York City and adjacent Westchester County has surpassed 500 MW of combined capacity.

Much of the densely built area is unsuitable for large-scale solar development. The 500 MW of capacity is spread among more than 55,000 individual solar systems.

New York City’s Queens borough, with its many low-rise neighborhoods, hosts 18,501 of those systems, while high-rise Manhattan has just 388. Suburban Westchester County, with its smaller population and lower density, has 44% fewer solar installations than Queens, but its total capacity is 5% higher, indicating larger installations are more common there.

“In spite of the obvious challenges for solar in the New York City region, with limited space and a dense population, the solar market continues to find ways to innovate and grow,” Con Edison distributed generation ombudsman Joe White said in a news release. “Solar energy saves customers money, creates local jobs and is a critical tool in New York’s fight against climate change.”

Progress to the 500-MW mark initially was slow but has been accelerating.

Con Edison said the first solar system was connected to its distribution grid in 2001, and it took 15 years to reach 100 MW combined capacity. In 2022, by contrast, a record 89 MW was installed.

The utility said it expects installations to continue at a similar or greater rate over at least the next decade.

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Has Dynamic Pricing’s Time Come?

Price-responsive demand has long been supported by economists, but despite the significant investment in advanced meters, it has yet to take off outside a few jurisdictions.

The Energy Systems Integration Group (ESIG) is releasing a series of papers this year, which Associate Director Debra Lew said are intended to raise awareness in the industry of how important it is to make the demand side a more active player going forward.

“We’re going to need that flexibility for high levels of renewables and high levels of electrification in the future,” Lew said in an interview.

In EPA’s recent rule, which it expects to greatly increase the number of electric vehicles purchased, it specifically pointed to time-varying rates as a way to charge all those cars without overloading the grid. (See EPA Releases Emissions Rules Aimed at Boosting EVs.)

Plenty of attention has been paid to programs such as demand response, or the aggregation of distributed energy resources under FERC Order 2222, but less focus has been paid to reducing demand through some kind of time-varying rate.

“Every time I bring up pricing, I always get told, ‘We don’t want to touch that with a 10-foot pole,’” Lew said. “So, I think it’s a really important, critical piece of the problem, and we’re hoping to shine a light on it, and to get industry to pay more attention to this, because it is a critical way of getting demand to provide that flexibility.”

Pricing should be part of the industry’s holistic planning process, where they can help avoid major spending on new resources, she said.

“If you’re thinking about adding storage to your system, maybe you should do time-of-use rates instead,” Lew said. “Think about some of these rates as replacements for resources that you might add to your system. If you’re thinking about adding a gas peaker, maybe instead you should do a peak-time rebate or critical-peak pricing.”

The idea of making the demand side more active is far from new, with the first DR programs going back decades and advanced metering infrastructure being rolled out to most customers in the country over the last decade-plus.

“As of 2021, I think there are approximately 115 million installed smart meters, and this is representing roughly 80% of all U.S. residential customers,” Brattle Group Principal Sanem Sergici said in an interview. “But when you go to [the U.S. Energy Information Administration] and look at their most recent data, only about 6% of the residential customers are on some sort of a time-varying rate.”

Time-varying pricing has not followed the rollout of smart meters because of inertia around how electricity has already been priced and some fear of the unknown, said Sergici, who contributed to ESIG’s reports and has tracked the issue for Brattle for years.

“Although, if you ask me, it’s not unknown anymore,” she added. “I mean, we have so much data. We have so much experience under our belts at this time when it comes to understanding customers response to these dynamic prices.”

Many industry veterans have bad memories about the first wave of DR programs 30 years ago that did not work as well as expected, but Lew noted much has changed since then. The industry has access to more advanced communications and control technology; the changing dynamics of the grid make the need more acute; and sophisticated customers such as data centers have shown that they can be very flexible if they get the right signals from the grid.

“I don’t think this is rocket science,” Lew said. “I think that it’s kind of ridiculous that it’s taken us this long to take this seriously.”

What to Charge?

Economists generally favor raising prices when demand is higher and having them lower when it is not, but former FERC Chair Jon Wellinghoff, who is now the chief regulatory officer at the aggregation firm Voltus, said that that would never fly politically. Dynamic pricing means customers must pay more when they use power the most, such as running their air conditioners on the hottest days of the year.

“That’s a penalty for consumers,” Wellinghoff said. “What they should be doing instead is rewarding consumers for not using energy during that time and paying them to not do that. And if they, in fact, gave them a reward, instead of a penalty, it would flip the whole thing on its head; it would make it much more palatable and much more acceptable for consumers.”

Voltus is working with Ameren Illinois to pay some of its mass-market customers who have smart thermostats to reduce usage during peak demand times. Wellinghoff argued that is much more attractive to customers than any kind of time-varying prices.

Price-responsive demand programs were sold as the key to advanced meters’ consumer benefits, but despite the meters being rolled out to most consumers, such programs have not been to nearly the same extent.

“I think it was oversold as to actually what it would be able to do and how it would be able to help consumers,” Wellinghoff said of advanced metering.

The meters rolled out to most residential customers are only collecting prices every five minutes, which makes them inadequate to really help with the sophisticated load management programs that Wellinghoff supports, he said.

FERC Order 2222, which requires RTOs to accept aggregations of distributed energy resources, is one way that the industry will be able to get the demand side into the market, but that transition needs to happen faster, said Wellinghoff. Getting Order 2222 fully implemented and demand more into the markets is going to require some changes from the distribution utilities.

“I think they’re sort of feeling afraid of being left out. And they’re not sure what their role should be. And they don’t want to accede their role to simply being a wires company. They want to do other things. But they’re not good at doing those other things, because they have never had experience in the competitive arena.”

Having the utilities focus on expanding the distribution system, while an independent distribution system operator (DSO) handles balancing various resources with flexible demand would lead to the kind of grid Wellinghoff sees in the future.

Utility Perspective

The concept of a DSO is just an idea at this point, so balancing all the activity on the distribution system is still firmly in utilities’ control. That has made implementing Order 2222 tricky, Portland General Electric Senior Vice President of Advanced Energy Delivery Larry Bekkedahl said in an interview.

“I don’t think that folks really thought through the full extent of the impacts on the distribution system, when we have traditionally been really good in the transmission generation space and bidding and markets in that space,” Bekkedahl said. “But to go to the distribution, you’ve got to be able to communicate with those that are operating the distribution system in the same way you do with the generators and transmission folks. We have not been set up for that.”

Without significant additional work bringing the utilities that run the distribution system into that picture, it will never be fully optimized, and it just has to deal with whatever extremes are placed on it, he said.

While Bekkedahl has some doubts about opening everything to third parties, virtual power plants and increased demand flexibility are a key part of the Oregon utility’s plans to keep the grid balanced. Going forward, Bekkedahl expects about a quarter of all supplies will come from distributed resources and that growing percentages of the rest will be from intermittent renewables.

“If we’re going to get to our decarbonization targets … we absolutely need as much flexibility in the load as possible because we’ve added all this variability in the generation side with wind, solar, etc.,” he added.

That flexibility will benefit from distributed batteries and direct load control (DLC) programs, in which customers can sign up for programs that allow utilities to turn up their thermostats a few degrees on the hottest days.

Most utilities in the country use their assets at about a 30 to 35% range, but PGE is starting to exceed its peaks on that usage, and it would like to be able to bring its asset usage up to 40 to 60% while meeting peak demand, Bekkedahl said. That is going to require significant flexibility.

In September 2022, the Western grid hit its all-time peak demand at 167 GW, and prices were up to $2,000/MWh, when normally they sit around $100/MWh at most. Those kinds of peaks make demand flexibility very cost effective.

“So being able to flex with customers and what used to be demand response programs now become these flexible programs that can keep the lights on for everybody,” said Bekkedahl. “And it also helps us to meet our greenhouse gas emission targets.”

How High Can Prices Go?

Reflecting the system conditions to mass market customers can be handled in a variety of ways, from standard time-of-use rates that go up over predetermined hours and are lower in others, to just passing the wholesale price signal directly to consumers.

The experience of the retailer Griddy in the winter storms that knocked out power to millions of Texans in February 2021 often came up in interviews with RTO Insider as an unfortunate, cautionary tale. The firm had grown its customer base by passing along normally cheap wholesale rates without any markup to cover the cost of hedging. But then the winter storm came through, pushing up natural gas prices, knocking power plants offline and eventually leading the Texas Public Utility Commission to set prices at $9,000/MWh for most of a work week. (See Texas Court Reverses PUC’s Uri Market Orders.)

Those wholesale prices led to some ridiculously high electric bills that customers ultimately did not have to pay; Griddy was forced out of the market, and its business model banned by subsequent legislation.

“ERCOT was living in this imaginary world were very infrequent, really high prices would automatically take care of all the issues that a capacity market takes care of in PJM,” PJM Independent Market Monitor Joe Bowring said in an interview. “It clearly didn’t work when push came to shove, and you had extreme weather. That’s the problem because then prices are extraordinarily high, and you can do a massive amount of damage in a very short period of time to companies as well as the customers.”

Some retailers ran into similar issues when PJM faced similar conditions during the polar vortex of 2014, though the RTO kept the lights on.

“In order for it to work, we have to have wholesale pricing that reflects shortages but does not reflect it to an extreme degree,” Bowring said. “I mean, some economists say that really high prices are essential. I don’t think that’s true.”

Prices can go up to $1,000/MWh, or maybe $2,000/MWh in extreme conditions, and still send the right signals to the market, including any customers on time-varying rates, he added. Prices also generally should not stay that high for long because they are only meant to go up to attract additional resources that tend to bring them back down.

Load-serving entities can design rates that would never expose their customers to such high prices, having a hedge kick in before prices shot up to their highest possible levels, Bowring said.

While the capabilities of smart meters were oversold, Bowring said, part of the reason dynamic pricing at retail has not taken off is that often third-party firms do not get access to the data that utilities have from those meters that would enable such programs. Bowring has long argued that DR should come from retail programs because he believes the wholesale DR programs PJM runs are far less efficient than that alternative.

Every time demand is triggered, it automatically leads to higher prices, which is the exact opposite effect demand is supposed to have, Bowring said.

“The place for demand side and where it can be most valuable to real customers is to have it on the demand side and to empower people to be able to reduce loads when they need to and to pay less for capacity and energy when that happens,” he added.

Some Skepticism from Consumer Advocates

California is one state that has defaulted to time-of-use rates for its residential customers, but that program needed a carveout for low-income customers in the hotter parts of the state, such as the Central Valley, Marcel Hawiger, staff attorney for TURN – The Utility Reform Network, said in an interview.

“Dynamic pricing has the potential to lower rates if, and only if, any actual reductions in demand flow through to real reductions in utility spending,” said Hawiger. “We hope that happens.”

But charging more money for power when customers need it the most can also harm them, especially low-income customers who lack the ability to pay for the automation and changes in lifestyle needed to maximize its benefits, he added. When it comes down it, dynamic pricing is “using prices to ration a needed commodity.”

“If you can afford it, you’ll just use as much as you want on a hot summer afternoon and cool your home,” Hawiger said. “And if you can’t afford it, you’ll cool less and have a warmer home because you can’t afford it.”

Many decry utility DLC programs, but they offer voluntary opportunities for customers to have their major appliances controlled by the utility in exchange for a rebate, which appeals to more customers and offers utilities more certainty over the resource, he added.

California only recently moved to default time of use rates for customers and TURN fought to exclude those who could not adequately respond. TURN looks forward to getting a look at the data on how the new rates in California have impacted customers, Hawiger said.

Where Else Has it Taken off?

Outside of California, some kind of time-varying rates have been fully deployed by Detroit Edison in Michigan, Xcel Energy in Colorado and the Long Island Power Authority in New York. Arizona Public Service and the Salt River Project in Arizona have high levels of participation in their programs, said Brattle Group’s Sergici.

Those programs show that dynamic pricing can work, Sergici said, and it is just a matter of willpower between the industry and regulators to get it in place in more jurisdictions. The transition the grid is going through, with the growth in renewables and more distributed resources, will only grow its benefits.

The shift to renewables means that instead of generation having to constantly track shifting demand, generation will be intermittent and would benefit from having the demand-side track its output at least somewhat, he said.

“Pricing actually is a very great tool to moderate the pace of that investment cycle that we’re going to go into because if you can manage some of the capacity growth through dynamic pricing, that means that you need to either defer that capacity build or you can even avoid some capacity build,” Sergici said. “And that will only help to make this transition more affordable and reliable.”

While dynamic pricing has been slow to take off, Sergici believes that is likely to change soon as the grid changes and more and more of the industry gets comfortable with it. The change will be like Ernest Hemingway’s description of how a character went bankrupt in “The Sun Also Rises”: “gradually then suddenly.”

“I think that it’s happened very slowly for a very long time,” Sergici said. “And I am now seeing this big momentum. And I think that it will happen suddenly, in the next five years, that more and more utilities will decide to have time-varying rates to be the default rates for their customers.”