Key deadlines already have arrived for MISO’s spring capacity auction, while the RTO has hiked its planning reserve margin for the 2024/25 planning year.
So far for the upcoming summer, MISO has accounted for nearly 161 GW in installed capacity across the footprint that whittles down to almost 129 GW in total seasonal accredited capacity. The RTO must meet a 135.7-GW summer planning reserve margin requirement.
MISO will use a 9% summer 2024 planning reserve margin, higher than the 7.4% annual planning reserve margin used in last year’s Planning Resource Auction. MISO said its shifting resource mix and a move to seasonal modeling for its reserve margin contributed to the increase. This year, the RTO said it’s using seasonal values, rather than annual, in its generator verification testing data, reflecting different capabilities of generators in different temperatures. The upcoming spring auction marks the second time MISO has divided its capacity auction by season.
MISO stressed Jan. 17 that it’s “too early in the process to make quantifiable conclusions” on how much supply it expects beginning June 1.
The grid operator plans to update its supply information based on the data it receives from market participants every other week through late March. It said it expects information on energy supply to change “significantly.”
MISO resource owners have until Feb. 1 to confirm their seasonal accredited capacity values with the RTO. Load-modifying resource owners also have until Feb. 1 to register to participate in the auction. As of mid-January, MISO said approximately 12.8 GW of load-modifying resources from prior years had not started the registration process.
MISO confirmed Jan. 30 it likely will try again with FERC in the third quarter to apply an annual megawatt cap to its interconnection queue.
FERC in December denied MISO’s request to annually cap submittals to its interconnection queue on concerns over too many cap exemptions, the formula to establish the cap and potential resource adequacy deficits from limiting new generation onto the grid. (See FERC Rejects MW Cap, Approves MISO’s Other Stricter Interconnection Queue Rules.)
MISO said it will apply the rules FERC did approve to the 2023 cycle of project requests, which has been on pause since last year for FERC’s decision on the package of more stringent interconnection requirements. The new rules include increased entry fees, an automatic penalty schedule for withdrawing projects and added proof that developers have secured locations for projects.
MISO said it will belatedly open its 2023 queue cycle project window on March 18 and close it on April 18. That cluster of projects will not be subject to a megawatt cap. Currently, the RTO’s online generator interconnection portal remains closed to new applications.
MISO hasn’t abandoned the idea of a megawatt cap on future queue cycles. The grid operator plans to again propose a megawatt cap that first could apply to the 2024 class of projects.
Aneta Godbole of MISO’s resource utilization team said FERC “provided good guidance that MISO will use in its future refiling efforts.”
“MISO will come back to the stakeholders once it is ready for further discussion,” Godbole said of a second cap filing during a Jan. 30 teleconference of the Interconnection Process Working Group.
At this point, the RTO intends to begin processing both a 2023 and 2024 cycle of generation project requests this year. It said if all goes to plan, it could place the 2024 queue cycle deadline at the end of the year.
“MISO is anticipating two cycles in 2024, but it depends on our work to reduce the backlog, the size of the 2023 cycle, the cap filing and approval of the” long-range transmission plan (LRTP) and the MISO-SPP Joint Targeted Interconnection Queue (JTIQ) transmission portfolios, Godbole said. MISO previously said the regional LRTP and the interregional JTIQ will help support new generation interconnections.
Additionally, MISO said either its 2024 or 2025 class of project requests will be the first to proceed under FERC’s Order 2023 queue requirements, depending on the final effective date.
Some stakeholders were incredulous that MISO could handle the workload of two queue cycles in a single year given the uptick in project submittals.
“There are a lot of factors on when we hold the next queue cycle,” MISO’s Andy Witmeier added. He said the RTO wants to be transparent about which factors it foresees dictating when it can open a 2024 queue cycle.
At the Jan. 24 Planning Advisory Committee, Witmeier called a megawatt cap a “vital tool.” He also said MISO won’t file to apply a megawatt cap retroactively to projects in the queue.
A new coalition called Transmission Possible launched Jan. 25 to support local, state and federal efforts to expand transmission, while a recent paper from the National Bureau of Economic Research (NBER) put some numbers on an issue that has often complicated those efforts.
The new group is led by Advanced Energy United, and it includes the American Council on Renewable Energy, Americans for a Clean Energy Grid, the National Wildlife Federation, the Environmental League of Massachusetts and the Northeast Energy Council.
“Much of America’s transmission infrastructure was built in the 1950s and ’60s, and even though the technology has come a long way since then, we really haven’t made any significant improvements to the grid in 70 years,” said Verna Mandez, a director at Advanced Energy United who is overseeing Transmission Possible. “America and its energy needs are growing, and building interregional transmission lines is the way we ensure we have a reliable power grid that cost-effectively delivers energy from where it’s generated to where it’s needed.”
Transmission Possible’s campaign will encourage regional collaboration among states to plan lines across their transmission lines. It will endorse state policies that encourage the buildout of transmission lines.
The campaign will support deployment of immediate solutions to grid congestion, such as high-performance conductors and grid-enhancing technologies (GETs). It will also host a resource hub for decision-makers, stakeholders and the public about the role of transmission in ensuring grid reliability and accelerating the transition to clean energy.
Reaching the goal of 100% clean electricity by 2035 will require as many as 91,000 miles of new transmission lines over the next decade, while in the interim, the deployment of GETs could unlock as much as 40% more capacity from existing lines.
National Bureau of Economic Research Paper
A recent paper from the NBER put some firm numbers on a commonly cited barrier to transmission expansion: When lines open up isolated patches of the grid to greater competition, it cuts the prices for local generators.
“Power Flows: Transmission Lines and Corporate Profits” by Catherine Hausman, an associate professor at the University of Michigan’s Gerald R. Ford School of Public Policy, examined the issue using publicly available data on generators in MISO and SPP. While other papers have mentioned the issue of utilities trying to protect their generators’ income, Hausman estimated how fully expanding the two regions’ grids to fully tap their rich wind resources would impact generators’ profits.
The cost of transmission constraints has been on the rise, averaging $300 million to $400 million from 2016 to 2020, while spiking up to $2 billion in 2022 because of rising curtailments and higher natural gas prices.
“The transmission network until recently basically did what it needed to: connecting thermal power plants to load in population centers,” the paper said. “But in a world with increasing quantities of renewable generation, the existing network doesn’t match the spatial distribution of generation.”
Lower natural gas prices in the 2010s also flattened the marketwide marginal cost for electricity, which minimized the impact of constraints.
“But with natural gas prices surging up, the marginal cost curve has rotated, and dispatching the ‘wrong’ unit — because of something like a regional transmission constraint — has gotten much more expensive,” the paper said.
The $2 billion from 2022 could be justified if the cost of building new transmission is very high, but the paper noted that many grid observers have argued that the planning process does not lead to socially optimal investments, especially when it comes to long-distance lines crossing regions.
“The rise in wind energy in recent years has decreased profits for fossil incumbents — but crucially, by less than it would have had the market been fully integrated,” the paper said. “That is, fossil incumbents have been partially protected from new competitors by a lack of transmission.”
The overall impact masks important differences, with the paper finding that firms in MISO South (Entergy’s territory) would lose the most because it has poorer transmission connections to the rest of the market.
If the grid were fully expanded, just four firms would stand to lose $1.6 billion, or three-quarters of the total inefficiencies seen in 2022. In other years, the number would have been smaller, but those firms’ share would have been similar.
The firms that would have benefited the most are in Iowa, Illinois and Missouri, and they would have brought in about $1 billion in 2022, while wind farms would have earned an additional $800 million. The wind farms’ extra profit would have been spread wide across many facilities, though the paper noted that NextEra Energy owns many of them in the region.
Entergy Arkansas and Entergy Louisiana would lose the most from the expanded grid, at a combined $930 million in 2022. Renewable energy advocates and others have alleged that the firm has tried to delay or cancel transmission improvements, the paper said.
“The results in this section suggest that the current planning process is problematic given the fact that market integration is expected to bring very large losses to some incumbents,” the paper said.
American Transmission Co. will pay $75,000 to the Midwest Reliability Organization for violations of NERC’s facility rating standards, according to a settlement approved by FERC on Jan. 26.
NERC filed the settlement with the commission as part of its monthly spreadsheet notice of penalty at the end of December (NP24-4). FERC said in its filing Jan. 26 that it will not review the MRO settlement, along with an additional nonpublic spreadsheet NOP concerning infringements of NERC’s Critical Infrastructure Protection standards, leaving the penalty intact.
ATC owns and operates high-voltage transmission lines in Wisconsin, Minnesota, Michigan and Illinois. The settlement involves violations of FAC-009-1 (Establish and communicate facility ratings) and its successor FAC-008-3. According to MRO, the violations began in December 2009 and ended in August 2022, and involved facilities in both its footprint and that of ReliabilityFirst. However, NERC’s spreadsheet NOP did not indicate whether the regional entities would share the penalty.
The settlement says ATC submitted a self-report in October 2017 indicating that it was not compliant with FAC-008-3, followed by a second self-report involving two additional violations of the same standard in the first quarter of the following year. Because MRO determined that both violations began before FAC-008-3 became effective in 2013, the RE processed them under the earlier standard.
In the first self-report, ATC indicated that the rating for a winter season line segment was incorrect because the utility had not correctly recorded the segment’s temperature. The utility’s second submission reported a “bus section rating that did not reflect an equipment rating and a line conductor rating discrepancy that affected the transmission line facility rating.”
After discovering these issues, ATC ordered an independent evaluation of its data sets and found rating errors in 47 facilities — one substation and 46 transmission lines. MRO observed that this amounted to less than 5% of ATC’s total facilities.
Nineteen of the misratings were “lower than the actual rating of the most limiting element,” MRO said, which “and may have prevented system operators from utilizing the full capability of these facilities.” More serious were the 28 facility ratings that exceeded the most limiting element, which the RE said could have resulted in equipment overloads and damage to critical equipment.
Most of the equipment involved was never actually operated above the corrected rating; however, one 138-kV cranking path facility did exceed the corrected rating for five minutes at one point. MRO said this event posed a moderate risk to grid reliability because the involved line was part of the utility’s black-start restoration plan, although the RE also noted that the risk of damage to equipment was “highly unlikely” and that load on this segment would likely not reach its actual rating during a system restoration event.
ATC’s mitigation actions include updating its substation equipment and line database, correcting any incorrectly assigned relays, and updating procedure and process documents used in updating facility ratings. The utility also performed internal training, defined and documented its approach to quality checks, and completed evaluations and extent-of-condition reviews for its data sets and mitigation plans.
MRO gave ATC mitigating credit for self-reporting the issues and for cooperating in the enforcement process. The RE also considered the utility’s internal compliance program “as a mitigating factor in the penalty determination” because of its important role in the enforcement process. According to MRO the ICP empowers ATC’s employees to “go directly to the most senior leader and/or” the company’s Board of Directors, and “directs operational staff to be involved in the investigation of noncompliance and the creation of mitigation.”
WESTMINSTER, Colo. — The competing efforts by SPP and CAISO to build and deploy an RTO in the Western Interconnection have sometimes been painted as a race in which the winner will be first grid operator to reach the finish line.
Hold your horses, now (pun intended).
Some in the West have come to the conclusion there are likely to be two day-ahead markets in the West: CAISO’s Extended Day-ahead Market, and SPP’s Markets+ and/or RTO West. They’re also saying it is now time for CAISO and SPP to begin talking about seams issues.
“We are accepting the possibility of two day-ahead markets,” Vijay Satyal, deputy director of regional markets for Western Resource Advocates (WRA), said last week during SPP’s first Markets+ Participants Executive Committee (MPEC) meeting of the year. “For now, we will seek to ensure there’s little seams impact from possible bifurcated day-ahead markets in the West.”
Satyal raised the possibility of two markets several times during the meeting. WRA, a nonprofit environmental law and policy organization, has maintained for five years that the region’s economic, reliability and environmental benefits are maximized with one large Western RTO.
Now, Satyal says, “the sooner, the better” that CAISO and SPP start talking with each other.
SPP said its Markets+ staff and CAISO began regular informal monthly meetings in July to discuss the design and status of both markets. The RTO has much more regular communication over reliability issues with CAISO as a neighboring reliability coordinator in the West.
Carrie Simpson, SPP’s senior director of seams and Western services, said the conversations include “making our seams as seamless as possible” and present an opportunity for SPP to work with CAISO and stakeholders to find a better way to mitigate the risks on both sides.
“This could be one of those areas that we’ve worked for improvement. This [design item] is a good way to just recognize that [participants] might have to carry more [flexibility reserve] because this type of product is coming in,” she said, noting tariff language brought forward by the Markets+ Seams Working Group (MSWG). “The seams group felt it was appropriate to allocate the uncertainty costs to these types of transactions. It allocates the cost to those who are buying from CAISO to sell into SPP because of the uncertainties around those types of transactions.”
Chelan County Public Utility District’s Tuuli Hakala chairs the MSWG. She suspects most members of her team joined to work on those very issues.
“My expectation is that as we’re working through protocols, we’re identifying elements where this is an area where this policy could be improved through formal coordination,” she said.
Satyal said he didn’t think the discussions between the grid operators go far enough or give enough transparency to stakeholders that might be affected by both market footprints.
“It is going to be extremely important to build interoperability agreements (i.e., seams management) so that we have better coordination between the two markets,” he told RTO Insider. He called for agreement on issues “involving either reliability management or the economic impacts, transmission and greenhouse gas management that come with two adjoining markets at work together.”
“This is a proactive request that WRA feels is important and in the interest of the public, ratepayers and customers,” Satyal said. “The next year and a half are critical for both markets to come to the table and agree on a principle statement around the seams, to agree on what are the operational areas and then what are the specific practices that require coordination. [CAISO and SPP] have had initial discussions, but if there’s going to be a true transparent stakeholder process … the utilities and market participants that are going to sign participation agreements should be aware and be part of this.
“Doing so now would make future seams agreement work more flexible to update and propose to FERC for approval,” he added, calling for a seams evaluation or study scenarios that look at three different levels of power flows as the ideal next step. “It’s important that all parties come to the table and support the two market operators in the minimum elements of a seams framework.”
MMU, MSC to Collaborate
SPP’s Market Monitoring Unit and the Markets+ State Committee (MSC) agreed to collaborate on clearly defining an observed participant obligation gap in the tariff that was identified by state regulators.
At issue is a 2022 FERC Notice of Proposed Rulemaking related to “duty of candor.” It would require all entities communicating with the commission or other organizations — e.g., the MMU — about FERC matters to provide “accurate and factual information” (RM22-20). (See FERC NOPRs Would Require ‘Candor,’ Improved Accounting for Renewables.)
Oregon Public Utility Commissioner Letha Tawney called into the meeting and said the MMU’s “continued concern” of a weakness in the existing Markets+ tariff “concerns the MSC.” She said the committee is seeking rules that “explicitly apply” to all entities, with everyone held to the same expectations.
“We all know when there is trust, and that is built on transparency, and the rules apply to everyone who participates … and you are seeking those customer benefits that an efficient, well-functioning market can deliver. From that perspective, we are all very aligned,” Tawney said. “We all know from our shared experience in the West that there is a fragile trust that the West has begun to build in the concept of security-constrained economic dispatch.”
The MMU argued before the MPEC in November that “duty of candor” language was missing from the tariff. Asked for examples of duty-of-candor violations, Monitor Keith Collins said he could offer hypothetical examples, but he would be breaking FERC rules by giving specific examples of what counts as privileged information.
“There are times when we asked for more information, and we would expect that information to be accurate and factual,” Collins said. “Unfortunately, that has not always been the case, and that can create some problems for us.”
“It remains unclear to MSC members that all market participants will have the same obligations in how they respond to requests for information from the MMU outside of a specific market-manipulation situation,” Tawney said. “There have been challenges [in the Eastern Interconnection] to holding everybody to that obligation to respond.”
The Markets+ legal subgroup will assist the MMU and MSC in determining any changes that need to be made in addressing the issue and bring recommendations to MPEC’s Feb. 20 virtual meeting. If consensus is not reached, the MPEC will move forward with the existing tariff language.
The MPEC also asked the MSC to update the Interim Markets+ Independent Panel (IMIP) that is overseeing the first phase of the market’s development.
Independents Sector Changes
MPEC members unanimously endorsed a recommendation from the Independents sector to create a Markets+ Interim Governance Task Force that would review and process governance issues before they go to the committee. The group’s makeup is subject to MPEC’s determination.
Those issues include the weighting of votes within the sector, a sticking point since last year, and potential improvements of Markets+ sector definitions. (See IMIP Approves SPP Markets+ Governance Tariff Language.)
The Independents sector has also proposed that its votes be calculated on a single-vote-per-member basis, with at least half of the sector reserved for Markets+ participants, stakeholders with at least 1 MW in the market’s footprint or stakeholder organizations with at least five members, a majority of whom must be involved in wholesale markets.
The sector is a catch-all comprising public information groups, independent power producers, markets and other participants that aren’t investor-owned or public power utilities.
“It’s a very broad sector,” said Kylah McNabb, speaking for the National Resources Defense Council. “This helps the Independent sector manage itself, given our diversity.”
Draft Tariff Posted
Stakeholders endorsed several more pieces of tariff language during the meeting, with SPP posting the draft’s 592 pages Jan. 26. MPEC members have until Feb. 9 to submit their comments on the tariff and its 14 attachments detailing the market’s services, terms and conditions.
The IMIP will take up the tariff for approval in late February. The SPP Board of Directors will then consider it during a special meeting in late March, after which it will be filed at FERC.
SPP is hoping for the commission’s approval in about nine months, allowing it to begin Phase II of Markets+’s development.
HOUSTON — The Gulf Coast Power Association’s membership has elected Beth Garza, a senior adviser for R Street Institute and long-time presence in the ERCOT market, to a two-year term as president.
Garza joined R Street after 11 years with Potomac Economics. She served as the ERCOT Independent Market Monitor’s deputy director or director for Potomac until 2019.
Her 35 years in the electric industry also have included leadership roles at ERCOT, NextEra Energy and Austin Energy, where she gained expertise in generation and transmission planning, system operations, regulatory affairs and market design. She has an engineering degree from the University of Missouri and is a registered professional engineer in Texas.
GCPA’s Board of Directors filled out its officers by selecting Brian Lloyd, vice president with Oncor, as vice president; Mark Egan, Energy Evolution Advisors’ founder, as treasurer; and Donna Benefield, senior vice president with NRG Energy, as secretary.
Outgoing President Mark Dreyfus made the announcement during the GCPA’s annual meeting Jan. 18. He said 2023 was a “fantastic” year with corporate memberships up from 137 to 153, its largest corporate membership on record. Individual memberships increased from 301 to 337. Registrations for meetings and conferences were up 28% over 2022 as the organization set attendance records for its annual spring and fall conferences and its MISO–SPP forum.
The attendance numbers resulted in strong financials for the organization. Total revenues exceeded $1.9 million, an increase of just over $400,000 from the prior year “because of the economic recovery and strong attendance memberships revenues,” and added $651,000 to the GCPA’s coffers.
The profits will be used to fund the organization’s scholarship program, which was resumed after the COVID-19 pandemic. Under the revamped program, GCPA will award ERCOT, MISO and SPP $20,000 each to go to outstanding students in their summer internship programs.
Dreyfus said the hunt continues for a new executive director with the experience and contacts “to really keep the organization moving forward.” Kim Casey announced her retirement last year; she was the fourth ED in GCPA’s history.
Solar advocates have petitioned FERC to take enforcement action against Arizona’s Salt River Project for setting rates that allegedly discriminate against customers with rooftop solar.
The rooftop solar rates are in violation of the Public Utilities Regulatory Policies Act (PURPA), according to the petition. It was filed Jan. 12 by the nonprofit advocacy group Vote Solar and two SRP residential customers with rooftop solar.
“SRP’s current policies for residential customer solar violate the commission’s rules and have decimated what was previously a robust market for solar,” the petition said.
The petition asks FERC to compel SRP to offer nondiscriminatory electric rates for rooftop solar customers as well as fair rates for buying electricity from those customers.
As an alternative to an enforcement action, the petition asks the commission to make a finding that SRP’s rates for rooftop solar customers violate PURPA.
PURPA is intended to encourage development of small power producers and co-generators and to reduce fossil fuel demand.
SRP said in a statement that it is reviewing the FERC filing.
“Based on an initial review, we believe the claims are without support and the background provided regarding SRP’s programs and support of its solar customers is inaccurate,” the utility said.
SRP said it has a number of rate options for rooftop solar customers and, as of September, had more than 54,000 residential customers with rooftop solar systems.
Solar Rate Plans
Rate disputes are often resolved by a state’s public utility commission, according to David Bender, an Earthjustice attorney who’s working on the case on behalf of Vote Solar.
But because SRP is not regulated by the Arizona Corporation Commission, the petitioners took their issue to FERC, Bender told RTO Insider.
If FERC doesn’t initiate an enforcement action within 60 days, the petitioners may bring an action in federal court.
According to the petition, SRP has separate rate plans for rooftop solar customers and nonsolar customers.
The solar customers pay a fixed monthly charge that is up to $25.44 higher than that paid by nonsolar customers, the petition said, while the kilowatt-hour charge and demand charge are the same for both types of customers.
In addition, the petition said, only non-solar customers are offered the EZ-3 time-of-use plan, which includes a “more advantageous” three-hour peak period: 3 to 6 p.m. or 4 to 7 p.m.
In contrast, the time-of-use plan offered to solar customers has a longer peak period that varies by season — 2 to 8 p.m. in the summer and 5 to 9 a.m. plus 5 to 9 p.m. during the winter, according to the petition.
“All of the solar-customer tariffs impose higher fixed charges and preclude solar customers from benefits available under tariffs for nonsolar customers,” the petition alleged.
SRP’s rates to buy electricity from solar customers also violate PURPA, according to the petition, which said that the 2.8 cents/kWh reimbursement under several of SRP’s tariffs is lower than the utility’s full avoided costs.
New Mexico Case
Bender worked on a similar case involving solar rates charged by the Farmington Electric Utility System, owned by the city of Farmington, N.M.
In that case, FERC declined to act on a petition filed in April 2019 by Vote Solar and several Farmington residential electric customers who had rooftop solar. The parties contested a “monthly standby charge” that the Farmington utility charged its solar customers.
They took their case to federal court. The case was dismissed in U.S. District Court, but a Court of Appeals reversed the decision. Farmington rescinded its additional charges for solar customers and, under the terms of a settlement, agreed to credit or refund customers who had paid the standby charge.
While the deployment of utility-scale battery storage has accelerated in recent years, additional regulatory and policy support is needed to scale up the industry and fully realize its potential benefit to the grid, a panel of experts convened by the Clean Energy States Alliance said Jan. 29.
The panel’s discussion focused on the lack of revenue available to battery storage resources in restructured wholesale markets, despite studies showing overall cost savings associated with deploying large-scale solar on the grid.
“The revenue does not equal the costs, so we need state support, and we need policy,” said Julian Boggs, director of state policy for Key Capture Energy.
Boggs pointed to the large risks investors assume when developing battery storage projects that rely on wholesale market revenues. For the industry to reach the scale needed to support the clean energy transition, “it’s going to take a lot more certainty in those revenues,” Boggs said.
States should step up to help provide this stability, Boggs added. “You need long-term contracts at scale; that’s the name of the game. I think policy makers are increasingly getting that.”
Joan White, director of storage and interconnection for the Solar Energy Industries Association, said California and Texas have led the country in storage deployment because “the market fundamentals really are there.”
Panel clockwise from top right: Todd Olinsky-Paul, Clean Energy States Alliance; Julian Boggs, Key Capture Energy; Waylon Clark, Sandia National Labs; Ted Ko, Energy Policy Design Institute; Joan White, Solar Energy Industries Association (SEIA). Imre Gyuk, director of Energy Storage Research at the U.S. Department of Energy Office of Electricity, also spoke. | Clean Energy States Alliance
“When the value of storage truly is captured in a market design, you can see a market take off in this exponential curve,” White said. “We’ve seen that in California and Texas — they’ve got really big deltas between their off-peak energy and their on-peak energy costs.”
White added that the lack of carbon pricing in wholesale markets distorts the true value of battery storage.
“When we look at wholesale markets, there’s no reflection of the cost of climate change or the cost of carbon,” White said. “I think the biggest thing we can do in terms of market design is incorporate the cost of carbon into market prices.”
Ted Ko, executive director of the Energy Policy Design Institute, also advocated for a carbon price, while highlighting Massachusetts’ Clean Peak Energy Standard as an “interim solution.”
The Clean Peak Energy Standard mandates that electricity suppliers buy an increasing number of certificates from qualifying clean resources, including energy storage and demand response.
“You eventually want to get to carbon pricing in the wholesale markets,” Ko added.
Regarding ongoing issues with interconnection, White said FERC Order 2023 contains “a couple small wins for storage,” including improvements to how system operators and transmission owners model storage resources in interconnection studies.
At the same time, White stressed that structural changes at a federal level are needed to “clean up the dumpster fire that is interconnection at the RTO level.”
“In order to reach our decarbonization goals, we need a grid that is two to three times our current size, and FERC Order 2023 does not plan or finance that grid in any way,” White added.
White also expressed concern that FERC Order 2222, which requires ISOs and RTOs to allow distributed energy resource aggregations to participate in wholesale markets, will not address the underlying revenue deficiencies that serve as barriers to entry.
“If the underlying market fundamentals aren’t there … the resources aren’t going to show up,” White said. “The timeline is long, and the revenue isn’t there in most markets.”
Looking at the long-term outlook of the battery storage industry, the panelists also emphasized the need for strong regulations and standards around fire safety.
“Getting fire safety right is a must, must, must for the industry,” said Boggs, who expressed support for requirements for storage systems to follow the National Fire Protection Association’s 855 standard, submit emergency response plans, and provide emergency training for first responders.
“This is coming whether we ask for it or not,” Boggs said.
The webinar was a presentation of the Energy Storage Technology Advancement Partneship (ESTAP). ESTAP is funded by the U.S. Department of Energy Office of Electricity, managed by Sandia National Laboratories, and administered by the Clean Energy States Alliance.
The California Energy Commission on Jan. 19 released a draft plan for offshore wind development, adding to the rapidly growing body of work identifying wind power as crucial to achieving state and national clean energy goals.
The plan was developed in accordance with AB 525, the 2022 bill that directed the commission to develop the strategic plan in collaboration with several other state agencies and established a goal of deploying 2 to 5 GW of offshore wind by 2030 and 25 GW by 2045 in California — powering 25 million homes and providing about 13% of the state’s supply. The draft plan also says the U.S. is on the path to deploy 110 GW by 2050.
“On the floating offshore wind side, there is no plan in the country — maybe the world — as comprehensive as this one,” Adam Stern, executive director of Offshore Wind California, told NetZero Insider.
Development of offshore wind infrastructure will occur primarily in federal waters under the jurisdiction of the Department of the Interior’s Bureau of Ocean Energy Management (BOEM). The agency held its first auction for wind power commercial leases in December 2022, which resulted in lease awards to five developers for parcels off California’s North and Central coasts. The winning bids for the lease areas total more than $757 million and include a commitment of more than $50 million to support communities and ocean users through community benefit agreements. (See First West Coast Offshore Wind Auction Fetches $757M.)
Challenges
But amid the progress, challenges remain. Waters off the coast of California are deeper than those in the Atlantic, requiring the installation of floating wind turbines rather than the more common fixed structures, which are suitable for waters about 200 or fewer feet deep. Floating platforms require more infrastructure, including suspended electrical cables linking the turbines, mooring cables and anchors attaching the turbines to the sea floor, with an electrical cable to transport the energy to a substation.
California’s coast is also less populated than the East and will require development and upgrades to ports and waterfront facilities to support offshore wind power, the report says, including construction of floating platforms, manufacturing and storage of components, and long-term operations and maintenance.
“Existing California port infrastructure is unable to support an offshore wind industry in the state,” the plan says. “As it will take a decade to make the needed port improvements that can support the full offshore wind supply chain, the state may need to import components from other parts of the world to meet the state’s 2030 offshore wind planning goals.”
New transmission also will be needed.
“The electric system on the North Coast is relatively isolated from the larger California grid and serves primarily local communities, so additional transmission infrastructure will be needed in this region. Existing transmission on the South-Central Coast is robust; however, there is still a need for long-term planning,” the plan says.
Stacey Shepard, senior information officer at CEC, told NetZero Insider in an email that permitting among local, state and federal agencies is perhaps the largest challenge offshore wind deployment faces.
“Coordination will be critical, but California has successfully coordinated multiple local, state and federal agencies to deploy clean and renewable energy facilities on state lands,” Shepard said.
Benefits
The plan cites several studies that estimate high potential economic and workforce benefits from offshore wind. For example, a Catalyst Environmental Solutions study estimated that a $124 million investment at the Port of Humboldt, a $20 million training center and workforce development, would create 500 annual short-term jobs by 2030 and 14,000 annual long-term jobs by 2045. The study projects that offshore development would generate upward of $5 billion in state-level gross domestic product by 2045, in addition to $1.2 billion in labor income and $385 million in fiscal revenue.
Another study by the Natural Resources Defense Council and Environmental Entrepreneurs estimated that 10 GW of offshore wind development in the Morro Bay and Humboldt areas could create more than 169,000 jobs and more than $45 billion in short-term economic benefits to the state.
Impacts
To better understand the potential impacts associated with offshore wind, the CEC conducted outreach to neighboring communities and tribal nations.
“While permitting agencies and developers have extensive experience with development and operation of various types of onshore and nearshore facilities, including deep water oil and gas platforms, there is a great deal of uncertainty about the impacts from large-scale floating offshore wind facilities anchored more than 20 miles off California’s coast,” the report states.
The plan lays out a detailed analysis of potential impacts associated with the Morro Bay and Humboldt lease areas, which could include habitat displacement of marine animals and birds and entanglement of species in underwater gear. To address some of these challenges, the CEC suggests burying underwater cables, avoiding important habitat and conducting regular monitoring.
AB 525 also directed the CEC to create a strategic plan identifying impacts to Indigenous groups and offering potential solutions. Tribes consulted were concerned with several potential issues associated with offshore wind development, including the perpetuation of resource extraction in their traditional territories that lack benefits to their communities, potential violence associated with the influx of non-local workers, the impact on sacred and historical sites, and more. Suggested strategies included exploring public safety measures to reduce violent crime and sexual and gender-based violence against California tribes and other vulnerable populations, and collaborating on avoidance, mitigation and co-management opportunities.
A framework for identifying suitable sea space was also outlined in the plan, which involves spatial mapping in federal waters from about three miles offshore to the 200-mile federal boundary. So far, the CEC has identified six locations for further screening — five off the North coast and one off the South-Central coast.
The draft strategic plan will be presented at a future public workshop.
“The CEC and collaborating state agencies are proud of the progress to date but appreciates there is much more work to be done,” Shepard said.
The U.S. Department of Energy has finalized new efficiency standards for residential cooking appliances, ushering in modest increases that will take effect in January 2028.
In its announcement Jan. 29, DOE said the changes will save consumers $1.6 billion on their utility bills over 30 years.
But DOE also said the improvements it’s ordering are modest and will pertain to only a small percentage of cooktops and stoves manufactured. It said 97% of gas models and 77% of smooth-top electric stove models now on the market already meet the new standards.
The cooking equipment standards are part of a larger push by the Biden administration for energy efficiency standards it estimates will yield nearly $1 trillion in consumer savings over 30 years.
Partisan and corporate priorities would make any such package of changes contentious, but the proposed new rules on cooking equipment published by DOE in February 2023 became a cause celebre, with conservative firebrands pouncing on a supposed gas stove ban.
The blowback was such that DOE in May 2023 published a knockdown piece that read in part: “Claims that the federal government is banning gas stoves are absurd.”
The lingering effects of that kerfuffle can be seen in the wording of the announcement, in which DOE emphasizes that the new standards were mandated by Congress and drawn up in negotiations with stakeholders including utilities, states and advocates for consumers, appliance makers and the environment.
DOE also points out the new rules will not bar features desired by consumers such as continuous cast iron grates, high-input-rate burners and other specialty burners.
The efficiency standards for gas cooktops were watered down significantly during negotiations. DOE first proposed a limit of 1.2 million BTUs per year, but the final rule sets a limit of 1.77 million BTUs.
Spread over 30 years across the 143 million existing U.S. housing units, the $1.6 billion in projected savings works out to about 37 cents a year.
The Association of Home Appliance Manufacturers was one of the stakeholders that helped negotiate the new rule. It said Jan. 29: “This standard is a win for consumers and energy savings. Manufacturers will have the flexibility they need to continue offering the features and performance that consumers value in gas and electric cooking products.”
Another of the stakeholders, the Appliance Standards Awareness Project, said the value of the negotiated recommendations is not so much for cooking appliances but in the entire package of appliance standards that was negotiated, including washers, dryers, dishwashers, refrigerators, freezers and beverage coolers. Executive Director Andrew deLaski said the effect of the announcement will be seen primarily in electric cooking equipment.
“The main thing this does is ensure new smooth-top electric stoves don’t waste energy when they’re not even operating,” he said in a news release. “It’s a modest money saver for consumers, with changes that would be challenging to even notice. There was disagreement over this stoves rule last year, but then the stakeholders came together and resolved it.”
He added: “It’s the whole suite of dozens of updated product standards the department is working on that will deliver the big impact, reducing people’s costs and protecting the climate.”
DOE in late December adopted new residential refrigeration standards that will take effect in 2029 and 2030, with $36.4 billion in consumer savings over 30 years. Proposed commercial refrigeration standards would save businesses $56 billion over 30 years.
U.S. Secretary of Energy Jennifer Granholm said her agency is continuing the initiative: “DOE is dedicated to working together with our industry partners and stakeholders throughout 2024 to continue strengthening appliance standards, addressing a backlog of congressionally mandated energy efficiency actions that is delaying a projected $1 trillion in consumer savings from reaching the American people.”
