California utility regulators voted Thursday to launch a proceeding to establish rules and requirements for the state’s resource adequacy program from 2025 to 2028.
“This rulemaking continues the California Public Utilities Commission’s oversight of the resource adequacy program, establishes forward RA procurement obligations applicable to load-serving entities beginning with the 2025 compliance year and considers structural reforms to the program,” the commission said in the order instituting rulemaking (OIR) approved last week.
“Reliability is a critical priority for California’s electric system. Resource adequacy ensures reliability in real time, and I look forward to building on the work we’ve done in recent years to refine the program and support the achievement of our ambitious climate goals,” CPUC President Alice Reynolds said in a statement after the commission approved the proposal.
The CPUC said the “preliminary scope” of the proceeding would include adoption of LSEs’ local capacity procurement requirements for 2025-2028 and flexible capacity procurement requirements for 2025 and 2026. Both sets of requirements will be rooted in CAISO’s annual local capacity area technical study, the commission said.
Other matters to be considered in the rulemaking include:
potential modification of the state’s new 24-hour “slice-of-day” planning framework, which requires LSEs to show they have enough resources on hand to meet load and planning reserve margin requirements for the day with the highest peak load in each month;
potential changes to the RA penalty structure and consideration of new ways to incentivize compliance;
increased coordination with utility integrated resource plan activities, including consideration of “appropriate” planning reserve margin requirements for short-term planning compared with the longer time frame for IRP proceedings;
exploration of changes to the methodology for counting qualifying capacity from resources, including demand response resources; and
the possible application of an unforced capacity methodology “for resource counting that would account for ambient derates and forced outages.”
The agency also will use the proceeding to seek additional suggestions from affected parties, it said.
Comments on the scope, schedule and administration of the proceeding are due no later than 20 days after approval of the OIR, and reply comments are due within 30 days after that. A prehearing conference for the rulemaking is scheduled for Nov. 17, and the commission seeks to issue a scoping memo in December. A proposed decision is slated for May 2024, with a vote on the final plan expected in June.
“California’s resource adequacy process is critical to ensuring sufficient resources are available to the California Independent System Operator for the safe and reliable operation of the grid, to advance our clean energy goals and to minimize costs to ratepayers,” Commissioner Darcie Houck said.
A one-year delay of Forward Capacity Auction 19 (FCA 19) would have cascading effects in the five subsequent auctions, ISO-NE told the NEPOOL Markets Committee on Thursday.
ISO-NE has recommended a one-year delay of the auction to implement resource capacity accreditation (RCA) changes and discuss moving to a prompt and/or seasonal market for FCA 19. The auction is scheduled for 2025 and would apply to the 2028-29 Capacity Commitment Period. (See ISO-NE Recommends Delaying FCA 19.)
Alan McBride of ISO-NE presented to the MC on a proposed schedule for FCA 19 through FCA 25. Following a one-year delay of FCA 19, subsequent auctions would be conducted on a 10-month timeline, instead of the typical 12-month timeline. This would return the FCM to the typical 3½-year forward auction process for FCA 26.
This would mean that along with the delay of FCA 19, five auctions in a row would be delayed to some extent, while the first annual reconfiguration auction for capacity commitment periods 19 through 24 would be eliminated. If ISO-NE moves to a prompt capacity market for FCA 19, these changes would become obsolete.
ISO-NE has emphasized the importance of implementing RCA for FCA 19 but would not be able to accomplish this under the current timeline. The RCA changes will alter how ISO-NE accredits resources like oil and gas generators and energy storage in the forward capacity market.
The RTO said it hopes to submit the filing as early as possible in anticipation of a potential government shutdown in November and has scheduled an extra MC meeting on the morning of Oct. 26 to vote on the proposal. It then would go to a general vote at the Nov. 2 Participants Committee meeting.
Some clean energy stakeholders have expressed concerns about the effects that delaying FCA 19 would have on new resources looking to secure capacity rights in the auction.
Mike Berlinski of BlueWave, a company that develops, owns and operates solar and storage projects, said it’s “disappointing that ISO-NE had not considered the impact of delaying FCA19 by a year on the ability of new resources to participate in the Capacity market in the 2025-2026 period.”
“Because new resources need to go through an FCA qualification process in order to be eligible for a reconfiguration Capacity auction, which unlocks capacity payments for near-term periods, pushing back the FCA19 process … would create a one-year gap where new resources could not enter the capacity market,” Berlinski told RTO Insider, adding that this could hurt projects in development and lead to decreased supply in reconfiguration auctions.
“If ISO-NE is determined to delay FCA19, we hope they will agree to implement some alternative process to enable capable projects to participate in the capacity market in the interim period,” Berlinski said.
Analysis Group Report on Prompt, Seasonal Construct
Chris Geissler of ISO-NE detailed scope of work for the Analysis Group report on the potential structural changes to the forward capacity market.
The intent of the Analysis Group study is to weigh the “pros, cons and key considerations associated with moving to a prompt and/or seasonal capacity market,” Geissler said, adding ISO-NE will use this study to inform its ultimate recommendation.
The report will focus on the effects on market efficiency, entry and exit decisions, price volatility, interactions with capacity accreditation, and supplier offers and risk. Geissler added the analysis will be quantitative and qualitative.
Geissler asked for feedback as soon as possible, as ISO-NE hopes to share the report with stakeholders in December.
“Due to the limited time to complete the assessment, AGI may not be able to complete analysis that addresses every stakeholder request,” Geissler said.
The Analysis Group is planning to present the methods of the report at the November MC meeting.
Upward Mitigation Prevention
The MC approved one aspect of ISO-NE’s proposed compliance to FERC’s show cause order (EL23-62) on Wednesday. The show cause order directed ISO-NE to change or justify parts of its tariff relating to “mitigation rules that can result in market power mitigation that increases the offers of a market participant.”
To prevent potential upward mitigation, ISO-NE proposes to “compare each financial parameter (e.g., block or component) of the Supply Offer and Reference Level and use the lesser of the two values when performing certain automated mitigation procedures,” Andrew Withers of ISO-NE told the MC in September. “This differs from current practice, where the entirety of the Supply Offer is replaced with the Reference Level.”
Withers also detailed the RTO’s proposal to allow two fuel price adjustments (FPAs) to the supply offer, compared to the single FPA currently allowed. The higher FPA of the two would be triggered at a designated MW threshold and is intended to better represent how fuel costs can increase as energy output increases.
Withers said ISO-NE still is evaluating the viability of this proposal and the tariff changes it would require.
FRM Market Power Concerns
Ash Bharatkumar of ISO-NE presented on proposed changes to the Forward Reserve Market (FRM) to address market power concerns raised by the Internal Market Monitor in the spring markets report.
ISO-NE proposes to reduce the Forward Reserve offer cap from $9,000/MW-month to $6,300/MW-month and move to a 12-month delay on the publication of auction offer data, compared to the current four-month delay.
Load flexibility is the fastest and cheapest way to prepare for rising electricity demand, and both the residential and commercial building sectors could be tapped as renewables supply an increasing portion of power, attendees at the Building Electrification Summit co-hosted by the California Energy Commission (CEC) and the Electric Power Research Institute (EPRI) heard last week.
Building electrification and the rise of EVs mean California needs to plan for using more electricity, not less, said CPUC President Alice Reynolds. When it comes to avoiding grid upgrades and coping with growing demand, moving the time at which electricity is consumed can be a massive lever. Load flexibility refers to the ability to change when electricity is consumed, and it can range from turning off an HVAC system for a short period during peak demand times to delaying EV charging until evening.
“Luckily these appliances that we’re all talking about growing, including electric vehicles and heat pumps, are the type of load that is flexible, so we have a lot of reasons for optimism,” especially as the grid moves to 100% clean energy, Reynolds said.
“Load flexibility is one of the cheapest and best approaches to improve grid reliability as far as greening our grid,” said Stefanie Wayland, load management standards lead at CEC. “We know that load flex works both at grid scale and at local scale, whether you’re doing it for sub-generation or for non-wire solutions where you’re avoiding distribution upgrades,” she said.
As buildings and transportation are electrified, the size and seasonality of peak demand will change, said Jessica Granderson, director of Lawrence Berkeley National Laboratory’s Building Technology and Urban Systems Division.
Granderson said that from 2025 to 2050, peak demand would increase from about 30 GW to 40 GW, while annual peak would shift to winter — when renewables generate less power — due to the load created by electric heating.
“As we successfully decarbonize the grid, we’re seeing this increase in the mismatch between that clean supply and the downstream demand from our buildings and increasingly our vehicles,” she said.
As buildings and transportation are electrified, the need for load flexibility will grow, along with the ability to control those loads through software.
Load flexibility is important during times of both excess and shortages of power, said Cisco DeVries, CEO of OhmConnect.
“So how do we adjust demand? We do that at home, in part through controlling devices and appliances directly in people’s homes. everything from EV chargers and battery storage systems all the way to hot water heaters’ spark plugs and thermostats,” DeVries said. “That allows us to very quickly and effectively reduce energy use in homes and help people get control of their energy bills, which is really critical.”
Labor Day in September 2022 proved the value of load flexibility in California. On a day when extreme heat produced high demand that was expected to lead to potential blackouts, OhmConnect’s customers were proactively reducing load. “They reduced 1.6 GWh of electricity over a few days, and we paid them over $2.7 million for the help that they gave. And that’s one of the reasons we didn’t have blackouts that day,” DeVries said.
The commercial building sector also offers significant opportunities to implement load flexibility strategies, Ammi Amarnath, principal technical executive at EPRI, said. For example, there are 12,000 convenience stores with significant refrigeration loads in California, most with present defrost cycles that can be reprogrammed. “A small change in the defrosting cycle in these small food stores can save up to 10 to 20 megawatts of electricity during those peak hours” in Los Angeles County alone, he said.
The 10,500 larger supermarkets, along with 112 refrigerated warehouses, each with peak demand of 250 kW to 4 MW, offer even larger load flexibility potential, Amarnath said, with a current EPRI project showing power can be modulated up to 25% while keeping the facilities within the carefully controlled temperature bands required.
Rhode Island Energy has issued a new Request for Proposals (RFP) for up to 1,200 MW of offshore wind capacity, the utility company announced on Friday, marking the largest solicitation of clean energy in the state’s history.
The announcement comes amid a period of setbacks for the industry due to escalating costs from supply chain constraints, high commodity prices and increased interest rates. Rhode Island’s most recent offshore wind solicitation received just one bid, which was rejected by Rhode Island Energy in July. (See Rhode Island Energy Rejects Revolution Wind 2 Proposal.)
“We know there’s a sense of urgency to get more renewables online and we believe this next RFP will give developers a new, unique opportunity to think creatively about how they can meet the state’s clean energy and economic development goals, while balancing our customers’ affordability needs,” Dave Bonenberger, president of Rhode Island Energy, said via press release.
Bids are due at the end of January, aligning the state’s timeline with the solicitations in Massachusetts and Connecticut. Earlier in October, Rhode Island, Connecticut and Massachusetts announced an agreement to coordinate their solicitations, hoping to bring down costs and leverage their collective buying power. The agreement will enable multistate bids to two or all three of the states. (See Mass., RI, Conn. Sign Coordination Agreement for OSW Procurement.)
“With a larger capacity available, a streamlined application process, additional flexibility on contract durations and the potential for multi-state coordination, we believe this solicitation could provide greater economies of scale for developers,” Bonenberger said. “We’re providing more tools to help drive affordable offshore wind opportunities to our state and we look forward to seeing how it spurs innovation and competitive pricing from offshore wind developers.”
Rhode Island Energy said that selected bids (if any) will be announced in the summer of 2024.
On Thursday, the New York Public Service Commission rejected requests for inflation adjustments on 90 clean energy projects, including four offshore wind projects totaling over 4 GW in capacity. (See NY Rejects Inflation Adjustment for Renewable Projects.)
The developers of these projects have expressed concern about the viability of their New York contracts without the extra money requested. The developers could look to New England as a place to bid their projects if they back out of their current contracts, albeit under a tight timeline to submit bids.
“It’s not easy to pivot all aspects of a project — especially interconnection and state-specific supply chain, workforce and economic development investments — to another market,” Bob Grace, president of Sustainable Energy Advantage, told NetZero Insider. “However, the developers of offshore wind projects with New York OREC contracts that are no longer financially viable have to consider offering bids into the upcoming synchronized Massachusetts, Rhode Island and Connecticut offshore wind procurements, particularly from lease areas off of New England.”
Meanwhile, the New York State Energy Research and Development Authority has yet to clarify what the rebidding process for projects in New York might look like, but the state has announced it’s pursuing an expedited procurement process to make up for any canceled contracts.
ERCOT’s senior leadership defended the grid operator’s 2024-25 budget and its planned 27.9% increase to its system administration fee during a public hearing Friday before the Public Utility Commission’s legal counsel.
CEO Pablo Vegas said the ERCOT board’s Human Resources and Governance Committee invited stakeholder feedback regarding strategic priorities and objectives for the next five years. He said that feedback informed the budget’s development.
The ISO is proposing the first increase to the administration fee since 2016, raising it from $0.555/MWh to $0.710/MWh. Much of that difference will be passed on by retailers to ratepayers. Consumer advocates didn’t oppose the increase, saying it was long overdue and will help pay for the real-time co-optimization project that is expected to save billions.
The biennial budget will provide ERCOT with $424.03 million and $426.99 million in 2024 and 2025, respectively. That will cover operating expenses, project spending and debt-service obligations.
“The board’s approval reflects that the budget complies with ERCOT’s financial corporate standard and associated financial metrics approved by the board,” Vegas said, reading from his tablet. “The board, along with ERCOT management, supported the reasonableness of the budget request to provide for ERCOT operations and meet our strategic objectives for 2024 and 2025, including the commission’s requests.”
Vegas told Kasey Feldman-Thomason, the commission’s general counsel and the hearing’s moderator, that ERCOT considered several alternatives to the administration fee’s increase. Management looked at an increase each year, every other year, or every four years.
The board, after “significant deliberation,” ultimately approved a rate increase that keeps the admin flat for four years, Vegas said. The next increase is projected to occur in 2028.
“This option was selected for three principal reasons” he said. “One, it addresses potential liquidity constraints in 2024 and 2025, resulting from deferring the expected increase from 2022 into 2024. Second, it provides great stability to Texas consumers. And three, it helps to minimize the potential intergenerational inequity issues among the ratepayers by appropriately charging ratepayers for the services they are receiving.”
ERCOT held off on increasing the fee in 2020. The deadly 2021 winter storm has increased the grid operator’s costs for legal support and IT projects, the latter a result of recent legislation.
“ERCOT maintains acute awareness that consumers of Texas fund ERCOT,” Vegas said.
The grid operator has asked that the budget be approved by Nov. 15. It will become effective Jan. 1.
Will McAdams | Texas PUC
During the PUC’s open meeting on Thursday, Commissioner Will McAdams encouraged stakeholders to participate in the budget hearing.
“The magnitude of the increase is significant, and I want to hear from stakeholders,” he said. “We so far have heard nothing about that within the ERCOT process … I’d like to know a little bit more detail about if there are questions or concerns and then how that affects the commission’s deliberations.”
The Texas Industrial Energy Consumers and Sierra Club were the only two groups to ask for more information from ERCOT during the hearing. They asked for more analysis of some of staff’s assumptions and questioned the need for additional legal and public affairs staff.
The hearing’s notice was not posted to the PUC’s online calendar until Thursday over what the commission’s executive director, Thomas Gleeson, called an “oversight.” He said a different meeting accidentally was posted first.
Nuclear Group Names Members
Commissioner Jimmy Glotfelty said he has a “well-rounded” members’ list for the PUC’s Texas Advanced Nuclear Reactor Working Group he is chairing (55421).
“We are going to be moving very [quickly], but we are excited to be moving forward,” he told the commission. “I’m just happy that we got over this hurdle.”
The 17-member list, released Oct. 10, includes ERCOT CEO Pablo Vegas; Entergy’s Dillon Allen, senior manager of advanced nuclear development; CPS Energy’s Bret Colby, nuclear oversight principal as part of the municipality’s ownership stake in the South Texas Project; and Clayton Scott, executive vice president of business development for NuScale, a developer of advanced nuclear reactor technology.
Glotfelty said those not selected shouldn’t feel they’re not part of the group. He said six or seven more teams will be formed to address specific issues such as supply chains and high technology interest in the Texas workforce, similar to the commission’s Aggregated Distributed Energy Resources (ADER) task force.
“We had two leaders and we had about 70 people participating,” Glotfelty said. “That’s what we want in this.”
Texas Gov. Greg Abbott (R) in August ordered the working group’s formation. It is to evaluate what steps need to be taken so advanced nuclear reactors can provide power for Texas. The group must report its findings and recommendations to Abbott by Dec. 1, 2024.
PUC Missing RRs’ Discussion
The PUC approved 29 ERCOT protocol changes and other revisions, but not before Glotfelty questioned the grid operator’s COO, Woody Rickerson, to better understand the revisions’ effect on the ERCOT market (54445).
“I don’t feel like we get the benefit of the discussion when these protocols are being approved,” Glotfelty said. “There are a lot of policy issues in here that I think rise to the commission level that we should take a position on … I also think that there has been some shyness to speak your mind during the ERCOT committee process as a result of feared backlash.”
Under legislation passed after the 2021 winter storm, the PUC now must approve revision requests after they emerge from the stakeholder process. ERCOT’s Board of Directors approved the last round of revision requests in June with minimal discussion.
The pre-Winter Storm Uri board would hold closed sessions before its meetings so the independent directors could ask clarifying questions about the changes.
“We’re supposed to all be working in one direction, but I do think the reason we’re asking these questions … is how do we stay out of this technical condition of potential system failure?” McAdams said. “The stakeholder votes on these policies are extremely important and we look to those. So, if they’re not 100% on board, we need to know that.”
The commission also approved publication of a rule that repeals and replaces the state’s renewable portfolio standard with a temporary solar-only renewable energy credit as required by 2023 legislation. The temporary program will expire Sept. 1, 2025 (55323).
The U.S. Department of Energy this morning announced designation of seven potential clean hydrogen hubs, the foundation of the Biden administration’s plan for a technology it views as central to the clean energy economy.
If selected, the H2Hubs will benefit from up to $7 billion in federal funding that recipients will match with more than $40 billion in additional funding.
The seven regional hubs are a central piece of the Biden Administration’s attempts to accelerate hydrogen’s development as an alternative to fossil fuel. They are intended to pave the way for a national hydrogen production, distribution, storage and end-use network.
The seven hubs are expected to produce 3 million metric tons of hydrogen annually, enabling end users to reduce their carbon dioxide emissions by up to 25 million metric tons per year. The administration has set a 2030 production target of 10 million metric tons to serve industrial sectors that represent 30% of total U.S. carbon emissions.
DOE Hydrogen Strategy Roadmap
DOE said its selection of the hubs does not commit it to provide funding. “Before funding is issued, DOE and the applicants will undergo a negotiation process, and DOE may cancel negotiations and rescind the selection for any reason during that time.”
The seven projects selected for negotiation are:
Appalachian Hydrogen Hub (West Virginia, Ohio, Pennsylvania)
Goal: Reduce cost of hydrogen distribution and storage; jobs for workers in coal communities
Power source: Natural gas with carbon capture
Jobs: 18,000 construction jobs; 3,000+ permanent jobs
Amount: up to $925 million
California Hydrogen Hub (California)
Goal: Decarbonizing public transportation, heavy duty trucking and port operations
Power source: Renewable energy and biomass
Jobs: 130,000 construction jobs, 90,000 permanent jobs
Amount: up to $1.2 billion
Gulf Coast Hydrogen Hub (Texas)
Goal: Drive down the cost of hydrogen
Power source: Natural gas with carbon capture and renewables
Jobs: 35,000 construction jobs, 10,000 permanent jobs.
Amount: up to $1.2 billion
Heartland Hydrogen Hub (Minnesota, North Dakota, South Dakota)
Goal: Decarbonize production of fertilizer; electric generation; cold climate space heating
Power source: Renewable energy, nuclear energy
Jobs: 3,067 construction jobs, 703 permanent jobs
Amount: up to $925 million
Mid-Atlantic Hydrogen Hub (Pennsylvania, Delaware, New Jersey)
Goal: Aid in decarbonizing Mid-Atlantic by repurposing oil infrastructure and using existing rights-of-way
Power source: Renewable and nuclear electricity
Jobs: 14,400 in construction jobs, 6,400 permanent jobs
DOE and the White House said the H2Hubs would create tens of thousands of jobs directly and tens of thousands more indirectly. Many would be temporary construction jobs but tens of thousands would be permanent.
The California, Mid-Atlantic and Pacific Northwest hubs have committed to negotiating project labor agreements with unions.
Hydrogen holds promise as a source of emissions-free energy for hard-to-decarbonize applications such as heavy-duty transportation and chemical, steel and cement manufacturing.
But most of the easily accessible hydrogen is locked in compounds with other elements and must be separated before it can become a fuel.
Further development is needed to produce clean hydrogen at high volume and low cost without generating excess emissions in the process. And exactly how to define “clean” remains a topic of debate. Friday’s announcement noted that hydrogen can be “produced with zero or near-zero carbon emissions.”
DOE Hydrogen Strategy Roadmap
DOE and the White House said Friday that two thirds of the total H2Hub investment is expected to focus on “green” hydrogen, which uses emissions-free renewable or nuclear energy to power the electrolysis process. But several of the hubs plan to use natural gas with carbon capture, so-called “blue” hydrogen.
Clean energy advocates assert that to make truly green hydrogen, the renewable power must be from a new generation source, not an existing source. If existing renewable electricity is diverted to hydrogen production, its place on the grid might be backfilled with fossil fuel.
In June 2021, DOE launched the Hydrogen Shot, the first of its Energy Earthshots, with the goal of reducing the cost of clean hydrogen by 80% to $1 per kilogram.
The Biden administration has targeted hydrogen as an economic development engine as well as a source of emissions-free energy. DOE said today’s announcement is “one of the largest investments in clean manufacturing and jobs in history.”
“With this historic investment, the Biden-Harris Administration is laying the foundation for a new, American-led industry that will propel the global clean energy transition while creating high quality jobs and delivering healthier communities in every pocket of the nation,” said Energy Secretary Jennifer Granholm.
WASHINGTON — Affordability and reliability can be maintained as the grid transitions to clean energy if the right decisions are made, FERC General Counsel Matthew Christiansen said Wednesday at the Energy Bar Association’s Mid-Year Energy Forum.
The technological trends are all moving toward new forms of energy including wind, solar and storage, with other possible technologies including advanced nuclear, long-duration storage and carbon capture just around the bend. That is coupled with strong policy certainty after the Inflation Reduction Act passed last year, and state laws that have been enacted in the previous decade, said Christiansen.
“I think we also — this is every bit as important — have a good sense of the challenges that come with that,” he added. “I think a lot of people are justifiably excited about the changes that are underway. But at the same time, I think it’s really important not to undersell the challenges that are going to go with those changes.”
FERC and Christiansen’s “clients” — its commissioners — have a chance to make decisions now that will ensure a reliable and affordable supply of power even as the grid undergoes significant changes. That window is not narrow, but it is also not open-ended.
While planning to meet the highest hour of demand on the hottest day of the year is not as easy as it sounds, it is easier than maintaining reliability on the changing grid, said Christiansen. The new resources bring some expected unavailability (solar will drop off as the sun sets) and some unexpected, such as the wind not blowing or cloudy conditions lasting for days, he said.
“As if that weren’t enough, they’re taking place against the backdrop of an increased incidence of extreme weather, which is due in large part to climate change,” he added. “So, we have as big a reliability challenge that I think we’re going to have to manage, at least at any point that I’m aware, in the history of the industry. I don’t think that challenge is even remotely close to insurmountable.”
Identifying the specific challenges that the industry faces and then figuring what is needed to ensure the grid can handle those reliably is the main job of FERC and others overseeing the transformation, said Christiansen.
“So, let’s be really specific,” Christiansen said. “Let’s go out and procure those things using our regulatory constructs — markets where we have them — so that we know that we have the specific tools that we need.”
Doing that will ensure reliability, but affordability is almost more impactful, he added.
“In my view, the best way to ensure that we have those services when we need them, and that we have them at a price that we can afford as customers, is to harness the benefits of competition to ensure that everyone is competing to provide those services,” Christiansen said.
Washington state is one of those that has moved to decarbonize its power industry, requiring net-zero emissions by midcentury, and that has turned the Utilities and Transportation Commission from a purely rate-setting board to one that also implements policy, said Commissioner Ann Rendahl.
The UTC only oversees the investor-owned utilities in the state, not the dozens of public utilities that are all preferred customers of Bonneville Power Administration and benefit from a higher share of its emissions-free hydroelectricity. The private utilities rely more on fossil fuel than those publicly owned firms.
“So, it’s a lot of rate pressure,” Rendahl said. “And we’re trying to mitigate that rate pressure at the same time as we’re implementing this new thing of energy justice for the customers, which is not something we have previously done. It’s very important.”
D.C. has similar goals, but with a very different backdrop of just one utility, Pepco, which must import almost all of its power from other jurisdictions in PJM as the dense city lacks any central-station generation, said Public Service Commission Chair Emile Thompson.
“We are, you know, for the most part at the mercy of our RTO, PJM,” Thompson said. “And PJM’s mix right now is about 4% renewable. And so, for us to get to 100% renewable in D.C., what that most likely is going to reflect is renewable energy credits, which is not really what the legislature wants.”
Thompson said another disconnect happens on the natural gas side when people ask why the PSC cannot just order Washington Gas to stop selling the fuel in the district. The issue there is the firm has a federal charter to sell natural gas in the district, and federal law outweighs any law that the D.C. Council might pass, he said.
Maryland is going through the same shifts, with a policy to electrify most of its natural gas demand, but that long-term goal has not filtered down to the planning at its local delivery companies, said People’s Counsel David Lapp.
The state has retail competition for natural gas, so utilities are indifferent to the amount of fuel flowing through their systems, but they are hyper-focused on that delivery infrastructure and have major investment plans in it in the coming decades, Lapp said. They spend $1 billion a year on their systems now, and that is expected to go up to $3 billion by 2050, he said.
“This is of great concern to customers, and we think it’s inconsistent with the state’s climate goals,” Lapp said.
With state and federal incentives for electrification, more of those customers will leave natural gas service as their bills rise, with fewer left behind to cover those costs. Those customers will tend to be the ones who can least afford it, he said.
“The people left on the gas system are going to be the people who can’t get off the gas system, and that’s lower-income customers,” Lapp said. “Eventually we think this will lead to stranded costs.”
The utilities would still be able to recover those stranded costs even if customers leave the natural gas system in droves, he added. In a competitive system, those investments would not be made, and regulation is supposed to stand in for the market in such cases, so the People’s Counsel has asked the PSC in a petition to engage in comprehensive planning of the gas system.
“Rates can’t be just and reasonable if they are based on an assumption that gas use is going to continue in five, 10, 20, 50 to 60 years, as it is occurring today. The state can’t meet its climate goals to accomplish that, and customers are at risk.”
An ambitious but pragmatic agreement among solar developers, conservation and agricultural groups, and environmental and environmental justice organizations could help accelerate a massive deployment of large-scale solar projects across the country by prioritizing climate action, land conservation and community involvement.
Those “3Cs” — climate, conservation and community — lie at the core of the 15-page agreement announced Thursday by Stanford University’s Woods Institute for the Environment, the Solar Energy Industries Association (SEIA) and The Nature Conservancy.
With 21 other organizations signing on, the agreement defines “large-scale” solar as projects of “megawatt or gigawatt scale” that are interconnected to the distribution or transmission grid. But, according to Stanford energy scholar Dan Reicher, “we have not defined a specific cutoff” for project size.
“The size of these projects has been growing a lot,” he said. “The bigger the project, the more rancor about it in the community.”
“Major U.S. solar projects are critical to fighting climate change but are increasingly opposed across the nation due to significant community and land concerns,” Reicher said.
“Every megawatt of large-scale solar capacity installed typically requires between five and ten acres of land and frequently necessitates additional development of new transmission capacity … requiring substantial additional land,” the agreement says.
Citing figures from the Department of Energy, the agreement notes that reaching the U.S. net zero goal by 2050 will require solar deployments to jump fivefold by 2033. Building out that much solar will “occupy about 0.5%-0.6% of the land surface of the contiguous United States, roughly 10 million acres,” the agreement says.
While that acreage is relatively small compared to the country’s 246 million acres of legally protected conservation land, the agreement says, “there is no such thing as an impact-free energy development. … it is anticipated that utility-scale solar and its potential impacts will not be uniformly distributed across the country.”
To balance the imperatives of the 3Cs, the agreement says, development of large-scale solar projects must be “transparent, equitable and efficient” and acknowledge that tradeoffs will be required.
The Working Groups
Negotiating those tradeoffs will be the task of the agreement’s six working groups, each focused on a vital industry issue: community and stakeholder engagement, siting, energy and agricultural technologies, information tools, tribal nations and policy.
Community and stakeholder engagement tops the list for a reason. The agreement notes the solar industry does not have a single approach to large-scale project development or business models, and some developers “may not prioritize or be compensated for robust community engagement.”
Charles Callaway, director of workforce development for WE ACT for Environmental Justice, a New York City nonprofit, said some solar contractors ensure local subcontractors get work, while others say they will make a “good faith” effort but bring in workers from outside.
Callaway’s top priority for signing WE ACT onto the agreement is to ensure developers have “a sustainable community benefit agreement that is tied to the solar project, and [provides] long-term benefits that can actually help the community that helped build the project,” he said. “Making sure the resources go to the community … monetarily and also energy wise.”
Any tradeoffs on community benefits will have to be made on a case-by-case basis, he said.
The agreement details a list of priorities for each working group to address. The community engagement group will draft best practices for identifying key community stakeholders and groups and track the timing and focus of developers’ community engagement efforts. Deliverables will include a checklist for community and stakeholder engagement, as well as a process for ensuring it is followed.
Abigail Ross Hopper, CEO of SEIA, said community engagement is critical for solar industry growth. “We’re confident that by thoughtfully addressing stakeholder concerns from the start, we’ll be able to deliver the equitable clean energy future we need to see.”
Nature Conservancy CEO Jen Morris said accelerating solar deployment means going smart to go fast. “Bringing environmental groups to the table ensures that we strike the right balance, delivering clean energy solutions while safeguarding our precious natural resources and communities.”
How It Happened
The agreement was hammered out in the course of six meetings held over 20 months under the sponsorship of the Woods Institute’s Uncommon Dialogues initiative, which seeks to address critical challenges to sustainability via invitation-only workshops with a cross-section of industry stakeholders and Stanford faculty experts.
Prior to the solar agreement, the Institute led an Uncommon Dialogue on hydropower and river conservation, which scored some major policy wins, including $2.4 billion in the Infrastructure Investment and Jobs Act to implement its October 2020 agreement.
The hydro agreement was focused on 3Rs: rehabilitating or retrofitting the nation’s 90,000 dams or removing ones that no longer provided benefits to society or had safety issues that could not be mitigated.
Hopper provided the original impetus for the solar dialogue, Reicher recalled. Seeing the impact of the hydropower dialogue, particularly the collaboration between the hydropower and river conservation groups, she asked if a similar effort might be made for solar.
The dialogue started its meetings as growing local opposition to solar began to delay or derail hundreds of projects, according to a recent study from Columbia Law School. The report found “at least 228 local restrictions across 35 states, in addition to 9 state-level restrictions, that are so severe that they could have the effect of blocking a renewable energy project.”
The solar dialogue had support from the Department of Energy, with Secretary Jennifer Granholm attending an early meeting, Reicher said. The Agriculture Department and DOE’s Office of Energy Efficiency and Renewable Energy also have been involved.
A major challenge for the solar dialogue was whether and how transmission should be included in the final agreement. The possibility of having a transmission working group was discussed, but ultimately a separate dialogue on transmission siting and cost allocation was launched in July, Reicher said.
According to the final agreement, plans for launching the working groups will be formed over the next four months and additional participants recruited. Reicher said implementation of the hydropower agreement was done in phases based on industry priorities, and he expects the solar working groups could follow the same pattern.
WASHINGTON — Despite years of talking past each other, some see a thaw in the most recent discussions around coordination between the electric and natural gas industries, panelists said at the Energy Bar Association’s Mid-Year Forum on Wednesday.
“We’ve made some substantial progress and [are] having an open and frank conversation about how each of the two sectors should interact with one another,” Gee Strategies Group President Robert Gee said.
Gee was one of three co-chairs on a recent effort from the North American Energy Standards Board on harmonizing the two industries. That effort at least got both industries to agree that it would be beneficial to better align the natural gas trading day with day-ahead power markets, he said. (See NAESB Forum Chairs Push for Gas Reliability Organization.)
Despite some progress, Gee noted that the 20 recommendations the process came up with saw differing levels of support between the two industries. And while he and the other two co-chairs — Hunt Energy Network CEO and former FERC Chair Pat Wood and the Analysis Group Senior Adviser Susan Tierney — endorsed a reliability organization for natural gas, the idea has not caught on with that industry.
PJM’s report on December 2022’s Winter Storm Elliott showed that most of the power plants unavailable because of a lack of natural gas were trying to secure their fuel after being dispatched in the real-time market, said Electric Power Supply Association Senior Vice President Nancy Bagot. (See PJM Recounts Emergency Conditions, Actions in Elliott Report.)
“If generators had day-ahead notification, they very often were able to make their fuel arrangements,” she said.
Dealing with issues around the few days a year when gas supplies are stressed from cold weather would be more effective than requiring generators to have long-term, firm supply contracts for natural gas, which do not guarantee they will get fuel during extreme cold snaps, Bagot added.
“Even though we’ve been working on gas-electric issues for what seems like decades, I sense a different kind of feeling or that we’re learning more this round, and for good reasons,” said Natural Gas Supply Association Executive Vice President Patricia Jagtiani.
FERC and NERC have come out with reports on multiple reliability incidents involving gas-electric coordination over the past decade, and each iteration has become more refined and detailed on what happened, she added. With Elliott, nearly 90% of the outages in PJM from fuel issues happened to plants dispatched in real time.
Trying to buy gas without a preexisting contract in the middle of a cold snap is difficult, and even if it can be secured, FERC requires that gas be delivered within three hours while power plants have to start up within one hour, Jagtiani said.
“I think a firm contract helps,” she added. “I think PJM’s report and FERC’s Uri report [on the February 2021 storm] showed that there was value in holding a firm contract: It improved your chance of getting confirmed.”
Gee questioned whether any kind of contracting regime would be enough to deal with the issue, noting that ultimately the fix might have to come from expanding infrastructure outside of the market. The task force asked FERC and the National Association of Regulatory Utility Commissioners to request a study from the Department of Energy on whether new natural gas storage might help, and whether that might need to be paid for in some way out of the markets, he added.
Redesigning the entire system from scratch, it would make sense to connect every gas-fired generator to a storage field, PJM Principal Fuel Supply Strategist Brian Fitzpatrick said.
“Quite frankly, I don’t see that existing in the future,” Fitzpatrick said. “But some of the major concerns I have going forward are just the headwinds, the negative headwinds, against the gas industry, whether it be state driven, whether it be federal driven, [such as] EPA regulations; they’re disincentivizing investment in natural gas infrastructure.”
Roughly half of PJM’s capacity is driven by natural gas, and it has 30 to 40 GW of coal-fired capacity that is going to retire in the coming decade that will largely be replaced by natural gas.
Gee agreed that the fuel was not going to disappear from the grid any time soon, even if it begins to be used more often to meet the ramping and balancing needs of a system dominated by renewables. But some states like Texas, where Gee said CenterPoint Energy is predicting that peak demand on its system will triple in the next 25 years, are going to continue needing the fuel for baseload generation.
“I think that we’ll have to figure out a way to weave together, in a coherent fashion, our climate goals along with our energy demand goals,” said Gee. “I think the road ahead could be quite rocky if we don’t proceed at a very careful pace and fully understand the impact of some of the decisions we’re making. And I say that as somebody who fully embraces that we need to address climate change and mitigate the amount of carbon in the atmosphere.”
ATLANTA — Speakers at the North American Generator Forum’s annual Compliance Conference this week acknowledged that “the volume of [standards development] projects has increased over the last two years” at NERC and that this heavier schedule has significantly burdened industry.
“I have been at NERC for nine years now, [and] I have never been this busy in my life,” Latrice Harkness, director of standards development, told attendees at the ERO’s headquarters Wednesday. “Even as a [standards] developer, I only had maybe two or three projects at a time. Right now, our developers sometimes are carrying about four development projects.”
Jay Cribb, cybersecurity program manager at Southern Co., concurred in a later presentation, sharing a screenshot of a list of reliability standards under development from NERC’s website and claiming he had never “seen it quite so lengthy.”
Of the ERO’s 26 active standard development projects, Harkness observed that 17 involve addressing security threats through NERC’s Critical Infrastructure Protection (CIP) standards or adapting to the transforming grid, including changes in the resource mix and the spread of inverter-based resources (IBRs). Additional high-priority projects include Project 2021-07 (Extreme cold weather grid operations, preparedness and coordination) and Project 2022-03 (Energy assurance with energy-constrained resources).
Noting industry feedback that “everything cannot be high” priority, Harkness said the ERO has worked to triage the standards projects and separate out as many low- and medium-priority efforts as possible. Two IBR-related projects are included in the medium-priority group, along with an effort to modify CIP reporting standards; low-priority projects include one dedicated to revising the definition of “reporting area control error” and another concerning modeling of electromagnetic transient events.
“Just because they fall into the low [priority] does not mean that they’re not going to get the attention they need to get some very good-quality standards,” Harkness said. “This just means that … we’ve been hearing from industry [that] we are too busy; we cannot keep up with the overlapping comment periods. And so we are trying internally [to] look at what subject matter experts those projects are going to be drawing on within industry and also trying to make sure that we post those projects based on the information we have so we don’t overload industry.”
Update on Cold Weather Standards
Venona Greaff, compliance manager at Occidental Energy Ventures, also gave attendees a progress update on Project 2021-07.
The project was begun in response to the February 2021 winter storms that led to the largest controlled firm load shed event in U.S. history. Currently it is in the second phase of development, which began after FERC approved the new reliability standards EOP-012-1 (Extreme cold weather preparedness and operations) and EOP-011-3 (Emergency operations) this year. (See FERC Orders New Reliability Standards in Response to Uri.)
Greaff, who serves on the standard drafting team for Project 2021-07, noted that EOP-011-4 (Emergency operations) and TOP-002-5 (Operations planning), produced in the project’s second phase, received industry approval last week after NERC’s Standards Committee approved both standards for a shortened public comment and ballot period. (See NERC Committee Agrees to Shortened Standard Comments.) EOP-011-4 passed with a 73.29% weighted segment value, while TOP-002-5 received 79.56%.
“Those latest revisions are going to be moved forward to the NERC Board of Trustees for their approval in the next few weeks, and it will move on to FERC from there,” Greaff said. The SDT will now move to the final phase, revisions to EOP-012-1, which FERC has directed to be submitted by February 2024.
