FERC on Tuesday rejected a pair of requests for exemptions from a resource availability cutoff under MISO’s new availability-based accreditation method.
The commission used near-identical language to deny Southern Minnesota Municipal Power Agency’s (SMMPA) and Cleco’s asks for exemptions from the new 24-hour lead time threshold for thermal resources’ capacity accreditation (ER23-837, ER23-1103).
Under the new construct, MISO treats offline resources that historically take more than 24 hours to start up as unavailable during predefined, risky hours that factor heavily in accreditation. In those cases, staff assigns a zero-capacity value and reduces accreditation accordingly.
Cleco (NYSE:CNL) had asked for waivers through 2026 for Units 1 and 3 at its 1,700-MW Big Cajun II Power Station in Louisiana. SMMPA asked for a waiver through 2026 for its 41% stake (359 MW) in Unit 3 of the Sherburne County Generating Station (Sherco) in Minnesota.
In both cases, FERC said the utilities did not prove that their waivers wouldn’t have “undesirable consequences, including harm to third parties.” It said while granting the waivers would increase Cleco’s and SMMPA’s seasonal accreditation values, it would also decrease the fleet-wide unforced capacity to intermediate seasonal capacity ratio. That would reduce other resources’ final seasonal capacity accreditation values, the commission said.
MISO took no position on the filings.
Commissioner Mark Christie penned a separate concurrence to express “surprise and disappointment in MISO’s failure to take a position on these waiver requests and to submit comments in these proceedings.” He emphasized that the grid operator characterized its capacity accreditation changes as too urgent to be delayed until the 2024-25 planning year.
“Yet now, when SMMPA and Cleco seek waiver of MISO’s new accreditation calculations — and, by extension, collaterally challenge the fairness of the implementation timeline expressed in MISO’s proposal — MISO remains strangely silent,” Christie wrote. “I would have expected MISO to defend its new [accreditation] or to explain why the waiver requests do not undermine the delicate balance it sought to achieve.”
The commission did not address other arguments from the utilities.
SMMPA pointed out that Sherco Unit 3 has a 26-hour startup time, and it now faces “significantly lower” accreditation values than it’s had for the “vast majority of its 30-year history.” It said the reduced accreditation values “do not reflect Sherco’s expected availability during times of need,” and that the unit “has the same capacity, availability, reliability and characteristics as it had in the past.”
Cleco said it lengthened startup times at the Big Cajun II plant in recent years to avoid violating MISO’s limits on uninstructed deviations from its dispatch orders. (See MISO Plans for New Uninstructed Deviation Rules.)
The utility said it wanted to maintain its eligibility for make-whole payments. It offered that its other units “with similar characteristics and design as the Big Cajun units” could change ramp rates, adjust offers in MISO’s real-time market or change startup times and make offers in the day-ahead market with an economic commitment status that would still require a startup period.
Cleco argued that without the waiver, it faced a “uniquely burdensome, … dramatic decrease in the Big Cajun units’ capacity accreditation value.” It said MISO’s accreditation will reduce Big Cajun II Unit 1’s average availability by 390 MW and cut Unit 3’s average availability by 202 MW for the 2023-24 planning year.
Entergy has a similar waiver request pending before FERC. The utility has warned that without waivers for three units in Mississippi and Arkansas, it risks a capacity shortfall this year in Mississippi. Entergy has pre-emptively adjusted the units’ startup times to less than 24 hours. (See Entergy Seeks Exemptions from MISO Accreditation Rules.)
Despite the disruptions of 2022 ― the war in Ukraine, inflation and ongoing supply chain issues ― the U.S. clean energy transition hit new highs in terms of renewable energy and storage deployed, new electric vehicles on the road and new investments, according to the Business Council for Sustainable Energy’s 2023 Sustainable Energy Factbook.
The transition is “now kind of hardwired into the U.S. economy and the way in which we’re evolving,” said Ethan Zindler, head of the Americas for BloombergNEF, which compiled the factbook released Wednesday.
Top line numbers from the annual compendium of energy facts and figures show that renewables, including hydro, accounted for about 23% of U.S. power generation in 2022, up 12.6% from 2021 and, together with nuclear, provided more than 40%, Zindler said during a media briefing Tuesday.
Clean energy drew about $140 billion worth of investment in the U.S., and close to 1 million EVs were sold, both new highs, he said.
Zindler also framed the passage of the Inflation Reduction Act as “absolutely a watershed in terms of policymaking in this sector at the federal level. We’ve really never seen any legislation passed by Congress as ambitious as the [IRA], in terms of what it’s trying to do to set us on the right course towards CO2 reduction and energy transition.”
With the exception of 2018, renewable energy has been the biggest source of new generation in the U.S. since 2015. | EIA/BloombergNEF
But the scope and speed of the transition must be accelerated if the U.S. is to meet its commitment under the Paris Agreement to reduce its greenhouse gas emissions 50 to 52% below 2005 levels by 2030. Even hitting the interim goal of a 26 to 28% reduction in GHG emissions by 2025 would require annual reductions of 4 to 5% per year, “which would be rather remarkable,” Zindler said.
With record growth in 2022, the U.S. continues to be the largest energy storage market in the world. | EIA/FERC/BloombergNEF
Thus far, the U.S. has cut its emissions 13.8% below 2005 levels, according to the factbook. But last year, emissions from the electric power sector dropped only 1.5%, and emissions from nonpower sectors of the U.S. economy increased 1.9%.
BCSE President Lisa Jacobson argued that it’s too early to predict whether the U.S. will be able to hit its emission-reduction goals, or President Biden’s 2035 target for decarbonizing the U.S. electricity grid. Time will be needed to assess the impacts of recent federal legislation — the IRA, the Infrastructure Investment and Jobs Act, and the CHIPS and Science Act — “not to mention what states and communities and the private sector are doing,” she said.
“We’re trying to lay out what we think would accelerate it even more, but I think we have some pretty strong market signals, and it may take two or three years to really know how much they push us,” Jacobsen said.
Other growth markers in the factbook include:
As of 2022, corporate procurements of clean energy totaled 19.9 GW. The number of power purchase agreements announced slipped from 118 in 2021 to 112 last year, but the average project size increased from 145 MW to 178 MW. Amazon leads the pack of corporate offtakers, with 8.4 GW of wind and solar.
Utilities and independent power producers are investing record amounts in transmission: an estimated $31.7 billion in 2022 and $33 billion in 2023, according to figures from the Edison Electric Institute cited in the factbook.
Energy storage deployments on the grid hit a new high in 2022 of 4.8 GW, which put total storage on the grid at 11.4 GW. Bolstered by tax credits in the IRA, the buildout of a domestic battery supply chain has already attracted $17 billion in investments, primarily focused on the EV sector.
Driven largely by the growing number of extreme weather events, the number of microgrids coming online has also increased to 101, with the main markets in California, Texas and Florida. Residential storage installations grew 25% year over year in California.
With funding from the IIJA and IRA, investment in green hydrogen technology is set for major increases. Federal support for green hydrogen could rise to $20 billion by 2030, and as prices fall, the IRA’s $3/kg production tax credit for green hydrogen could completely cover the cost of generation, the factbook says.
Natural Gas on the Rise
The factbook also contains some less optimistic numbers, such as the drop in solar installations last year because of supply chain delays and uncertainty over the Commerce Department investigation of solar imports from Cambodia, Laos, Thailand and Vietnam.
Biden’s two-year moratorium on any tariffs on solar cells or panels from those countries gave the industry some breathing room, but installations still fell from 24 GW in 2021 to 21 GW last year. Similarly, onshore wind deployments fell from 13 GW in 2021 to 11 GW. (See Biden Waives Tariffs on Key Solar Imports for 2 Years.)
At the same time, energy consumption in the U.S. continued its post-pandemic rebound, growing 3% over 2021. Natural gas accounted for 39.4% of U.S. power generation, and natural gas utilities poured more than $35 billion into infrastructure investments in 2021. Overall demand for U.S. natural gas, including exports, rose 5.4%, to a record 95.4 Bcfd.
U.S. levelized costs of electricity, unsubsidized for the second half of 2022. Solar and onshore wind remain cheaper than natural gas, but LCOEs for offshore wind and storage are still not competitive. | BloombergNEF
Energy efficiency spending by electric utilities fell during the pandemic, from $6.8 billion in 2019 to a flat $6 billion in 2020 and 2021. Another key factor affecting efficiency is state building codes. More than half of the states in the continental U.S. were using residential energy efficiency building codes from 2009 or earlier.
The International Energy Conservation Code, on which state codes are based, is updated every three years, which means the code has gone through four updates since 2009.
The factbook also looks at the ongoing challenge of interconnection queues, with solar and storage installations leading the projects applying for grid access. PJM and CAISO are called out as the grid operators with the longest wait times, averaging three or more years, versus the shorter two-year or less average for ISO-NE and MISO.
While not specifically called out in the factbook, questions about improving permitting policies and practices were also raised during the media briefing. Jacobson expects GOP bills on permitting to be voted out of the House of Representatives and is hopeful some compromise might be reached.
“We have a lot of proposals on the table, and they’re fairly comprehensive,” she said. “The question is, will the urgency of the need, at least in Congress and the Biden administration, get to the point where they are ready to make a deal. … I think the message is getting across that we will not meet our goals if we don’t take care of streamlining and making it faster and more efficient to build energy projects here in the United States.”
The Department of Energy conditionally committed to loan Li-Cycle Holdings (NYSE:LICY) $375 million to develop North America’s first recycling facility for battery-grade lithium, officials announced on Monday.
Li-Cycle’s 65-acre, 14-building facility in Rochester, N.Y. will form the center of the company’s “Spoke & Hub” business model, with the potential to achieve a 95% recycling efficiency rate and support the battery needs of hundreds of thousands of vehicles, according to a promotional video.
The company currently operates four “spoke” facilities in North America capable of processing more than 50,000 metric tons of lithium-ion battery material annually. The facilities produce an intermediate product containing critical minerals called “black mass,” which will be sent to the Rochester Hub for further processing into battery-grade materials.
Once operational, the Rochester Hub will become a domestic source of recycled and reusable battery materials, producing up to 8,500 metric tons of lithium carbonate, 48,000 tons of nickel sulphate and 7,500 tons of cobalt sulphate, according to Li-Cycle.
DOE’s loan is from the Advanced Technology Vehicles Manufacturing (ATVM) program, which was created to support critical infrastructure or technology projects deemed too risky by financial institutions and recently received a massive infusion of funding from the Inflation Reduction Act (IRA).
Li-Cycle’s loan, which has a term of 12 years and an interest rate equal to the U.S. Treasury’s 10-year rate (currently 3.92%), remains conditional until the company satisfies DOE financing procedures.
In a livestream of the announcement, Senate Majority Leader Chuck Schumer (D-N.Y.) told attendees that the DOE’s loan will not only bring jobs to New York and revitalize the Rochester industrial area, but “make America the center of electric car and electric battery production in the world.”
Doreen Harris, CEO of the New York State Energy Research and Development Authority, said that Li-Cycle’s facility is “representative of what we need to be doing at scale” and represents “the technologies of the future … that will be necessary to achieve the deep levels of decarbonization across all sectors of the economy.”
Li-Cycle said it received key environmental permits for the Rochester Hub last year and expects to commission the plant late this year. The project is expected to create about 270 permanent jobs and more than 1,000 jobs during construction.
Generation owners in PJM say that declining capacity prices and market participation in the Base Residual Auction, as shown by the results posted by the RTO on Monday, demonstrate underlying issues with the market.
“The auction results provide a long list of troubling indicators: supplier participation is down; more regions are in need of more capacity than they have; coal, wind, hydro and demand response are all leaving the market; and clearing prices are at near historic lows,” said Glen Thomas, president of the PJM Power Providers (P3).
Prices in the Rest of RTO region fell 18% to $28.92/MW-day from $34.13 in the previous auction, though the overall cost to procure the 140,416 MW in capacity cleared in the auction remained approximately the same at $2.2 billion because of higher prices in five constrained regions. (See PJM Capacity Prices Jump in 5 Regions.)
Pointing to a white paper released by PJM last week that raised reliability concerns with the pace of new generation construction and retirements, Thomas said declining prices show a disconnect in the market. (See PJM Board Initiates Fast-track Process to Address Reliability.)
Capacity prices declined in the auction results released by PJM on Feb. 27. | PJM
“The tragic irony in all of this is that these results were announced just days after PJM published a report warning of looming reliability risks at least partially caused by the accelerated retirement of dispatchable generation necessary to maintain reliability,” he said. “Clearly, there is a disconnect between the market’s rules and outcomes it needs to produce to maintain reliability, and that must be fixed if PJM is interested in retaining the resources it has and incenting construction of the resources it will require as the reliability threats begin to emerge in the coming years.”
Following the posting of auction results, the Electric Power Supply Association (EPSA) said that it is satisfied enough capacity was procured, but the clearing prices still show a need for market changes.
“Once again, the results of this BRA demonstrate the need for a clear price signal for capacity resources,” the organization said. “The market must be designed properly and avoid rule changes intended to accommodate specific preferred resources or technologies. EPSA has long called on PJM leadership, policymakers and regulators to address the serious foundational issues at hand, and we stand ready to continue to provide recommendations and work collaboratively to forge a solution.”
Some of those same concerns were raised by stakeholders in the Resource Adequacy Senior Task Force on Tuesday as they embarked on discussions of how to create market design proposals in response to a letter from the PJM Board of Managers. The board published the letter concurrent with PJM’s white paper announcing a fast-track process for addressing concerns raised by the report and stakeholders in recent months. (See PJM Board Initiates Fast-track Process to Address Reliability.)
Stakeholders said the capacity prices, some of the lowest the RTO has seen, underline the importance of their work and implementing new rules as soon as possible. Much of the discussion centered around balancing the urgency some see in putting those new rules in place with the disruption of potential auction delays that may be necessary to do so.
Constellation and Vistra Report Cleared Capacity
Constellation Energy (NASDAQ:CEG) reported to the U.S. Securities and Exchange Commission that it had cleared 18,725 MW in the auction, nearly the same as its 2023/24 auction figures. Its nuclear fleet cleared 25 MW lower than the previous auction, when its Byron, Dresden and Quad Cities facilities returned to the market.
Vistra (NYSE:VST) announced that it had cleared 6,905 MW at a $43.25/MW-day weighted average clearing price. The company projects it will receive approximately $109 million in capacity revenues for the 2024/25 delivery year, as well as an additional $11 million to $15 million in existing retail and bilateral sales. Total revenues for the year are estimated at $120 million to $124 million, down from 2023/24, which was projected at $164 million to $169 million following the June auction.
It should be “no surprise” that PRC-005-6 (Protection system, automatic reclosing, and sudden pressure relaying maintenance) and FAC-008-5 (Facility ratings) were the most violated operation and planning standards in SERC’s footprint last year, senior compliance engineer Miles Albritton told SERC Reliability’s Operation and Planning Spring Reliability Webinar Tuesday.
“With literally tens of thousands of devices in the field that require an inspection once a month, once a quarter, [or] annually … there are going to be some missing. However, with the right tools in place you can reduce the number of these misses,” Albritton said about the PRC-005-6 violations. Requirement R3 of the standard, which requires transmission owners, generator owners, and distribution providers to follow minimum maintenance schedules for certain equipment, accounted for 19 of the standard’s 20 violations in 2022.
“The same is true with FAC-008-5,” where the most violated requirement was R6, which directs transmission owners and generator owners to have facility ratings that are consistent with an established methodology, he said. “There are tens of thousands of elements in the field that have facility ratings, and these facility ratings can easily get altered, especially during restoration after a winter or summer storm. … As we all know, there are lots of opportunities for failure.”
Requirement R3 of PRC-005-6 accounted for all but one violation of the standard in 2022, with the last attributed to Requirement R1. | SERC
SERC holds the O&P webinar each spring to give staff at registered entities a chance to discuss recent changes in NERC’s reliability standards and trends the regional entity has seen in its audits in the past year. While the event included discussions on improving entities’ compliance with standards, presenters emphasized that the goal was to encourage entities to go beyond the bare minimum and develop a robust security culture.
“No one really gets up and says, ‘I’m going to be compliant today!’” said Tim Ponseti, SERC’s vice president of operations. “But you do get up and get excited about being safe, about being reliable, about being secure.”
Albritton acknowledged that SERC recorded violations of a “cornucopia” of standards last year but said PRC-005-6 and FAC-008-5 stood out. The first because it and its predecessors have been the most-violated standards over the last five years, and the second because it was the subject of an “influx of self-reports … across the entire ERO footprint” in 2022.
Violations of PRC-005-6 are frequently associated with failures of battery maintenance, with Albritton pointing to “simple [actions] like checking the electrolyte levels or checking for unintentional grounds” that are “easily fixed with a secondary peer review.” Albritton said the primary causes for FAC-008-5 violations are lack of internal controls, an “insufficient change management process, and training, not only for the field but for everybody in the change management process.”
“Change management internal controls are your friend. Many PRC-005, PRC-023, [and] FAC-008 noncompliances could be prevented with good … internal controls,” Albritton said. “Remember to test and audit the effectiveness of your internal controls; don’t just implement them and leave them on cruise control. You have to be able to test them on a periodic basis to make sure that they are still functioning.”
New England’s over-reliance on gas-fired power is the cause of big spikes in electricity prices this winter, the Sierra Club said in a paper published Tuesday.
The report “Fossil-Fueled Rates,” by the consulting firm Strategen, argues for increasing renewable generation and electrification to help customers save money, using this winter and its high prices as a case study.
“Far from being a reason to delay or avoid electrification, the recent electricity price spikes in New England ultimately demonstrate the risks of continuing to depend on an energy system reliant on volatile commodities like fossil gas,” the report says.
According to the Sierra Club’s Sarah Krame, the environmental group commissioned the paper to help educate policymakers and ratepayers about why electric bills have been so high this winter.
“We’ve all noticed the skyrocketing price of electricity in New England. It’s obviously an area of concern, and we’ve heard the concern expressed from policymakers: ‘How can we promote electrification if the price of electricity is so high?’” said Krame, a staff attorney for the Sierra Club’s environmental law program. “I think this paper is really helpful in highlighting that the cost of electricity is very high because we’re over-reliant on fossil gas.”
The paper also tries to explain why the impacts on gas rates have been muted compared to electricity prices, laying out the process through which gas utilities “true up” prices up to a year after incurring their costs.
Customers might feel the impact of volatility later in their gas bills, even though they’ve been relatively stable compared to electricity bills so far this winter, Krame said.
The Sierra Club and Strategen said the solution to the high prices is to build more renewables with lower marginal costs, and then electrify.
In the first three months of 2022, wholesale power prices in New England rose to an average of $137/MWh, an 83% increase over 2021, according to ISO-NE data. Eversource Energy doubled its residential electric supply rate from 12.1 cents/kWh to 24.2 cents/kWh for its customers in Massachusetts and Connecticut.
Rates were especially high in New England because of its reliance on gas, the report argues; the proportion of gas in New England’s fuel mix is roughly 20% higher than the percentage in the country’s fuel mix as a whole. The average settlement price at Henry Hub in January 2022 was up 62% from January 2021. In New England, the report says, the hike was even more pronounced: “Gas prices in New England in January 2022 were approximately 400% higher than they were in January 2021.”
Renewables have “lower marginal production costs” than gas, the report notes.
“As wholesale power prices become less heavily influenced by fossil gas costs, customers will have an opportunity to further reduce their exposure to gas cost spikes by electrifying appliances that currently run on fossil gas directly,” the paper says.
Electrification “can eliminate up to 100% of a customer’s direct gas demand, providing a pathway to completely remove New England residents’ dependence on the fuel,” it continued.
Strategen’s Brad Cebulko, one of the report’s authors, said in a statement that “transitioning New England’s electric supply to clean, abundant renewable energy sources and prioritizing the electrification of residential energy needs holds the promise to pay considerable and enduring dividends to residents for decades to come.”
CAISO sent a report to the California State Legislature on Monday that summarizes recent studies of Western regionalization, a document intended to inform this year’s renewed legislative discussion of the ISO becoming an RTO.
The 125-page report, “Impacts on California of Expanded Regional Cooperation to Operate the Western Grid,” was requested by lawmakers last year in Assembly Concurrent Resolution 188. It examines three dozen studies conducted over the last two decades that dealt with the benefits and drawbacks of greater cooperation among the West’s 39 balancing authorities.
“The studies reviewed, while varying in focus, are consistent and demonstrate that California’s goals for renewable energy and greenhouse gas reduction can be achieved more quickly and with less cost to Californians through expanded regional cooperation,” according to the report, prepared by the National Renewable Energy Laboratory.
It looked at different regional market constructs, including the formation of one or more Western RTOs and efforts such as CAISO’s planned day-ahead extension of its Western Energy Imbalance Market.
“The magnitude of the benefits to California will vary based on the mode of cooperation and on the states and utilities that elect to participate,” it says. “For example, the total benefits to California of a West-wide extended day-ahead energy market operated by CAISO … were less than the benefits estimated for the state under a West-wide RTO. For the rest of the West, an extended day-ahead market retained a slightly larger portion of the expected benefits of a full RTO.”
Some studies showed the distribution of benefits between California and other Western states to be uneven, the report noted.
A June 2021 “state-led” study found that an RTO covering the entire U.S. portion of the Western Interconnection could save the region $2 billion in annual electricity costs, providing 57% more savings in capacity value and 18% more production cost savings than two RTOs.
“However, this and other studies suggest the distribution of production cost savings and savings in resource adequacy costs could vary among individual states,” the NREL researchers wrote. “The type of technical modeling used in these studies accounts for detailed differences in generation cost between areas within the market being simulated. It also accounts for transmission congestion between areas; prices on the load side of a constraint tend to be higher, and prices on the generation side tend to be lower.
“As a result, shifting from several segregated markets to one integrated market could simultaneously exert downward pressure on market prices in high-cost areas [and] exert upward pressure on market prices in low-cost areas, and affect local imports, exports and the associated flow of revenue between areas,” it says. “These factors would drive local differences in benefits from regionalization even if the regionwide sum of benefits increased.”
A related issue is “how to allocate and recover the cost of new transmission that would increase power flows from low-cost areas to high-cost areas,” it says. “Consequently, it would be reasonable for California to anticipate a range of economic expectations from states with whom it might engage in discussions regarding an RTO.”
Governance remains a major hurdle. For CAISO to become an RTO, its Board of Governors would have to be opened to members from other states. Currently the California governor appoints all five members, and the State Senate confirms them.
“All other multistate RTOs in the country have an independent governing board and a special advisory committee that includes energy officials from all states in the RTO’s geographic footprint,” the report says. “Typically, the board is elected by RTO members from a slate prepared by a nominating committee, and members of the regional states committee are public utility commissioners, state energy officers or other officials from affected states.”
Holden, who also authored ACR 188, headed prior attempts in 2017 and 2018 to achieve the same goal, but the efforts failed because key lawmakers were unwilling to relinquish control of CAISO’s board or to jeopardize the state’s ambitious climate goals through increased cooperation with coal-burning states of the interior West.
Circumstances have changed since then, with strained supply in the West during extreme weather, especially in California. More states, cities and utilities have adopted 100% clean energy goals like California’s, requiring new transmission to move wind and solar power long distances. And two states, Nevada and Colorado, enacted requirements that major transmission owners join RTOs by 2030.
CAISO now faces competition from SPP, which plans to establish RTO West, and from the Western Power Pool, whose Western Resource Adequacy Program could be a springboard to an RTO.
The ISO released a draft version of the report in January, which left a section on the relative benefits of regionalization for California and the rest of the West unfinished, and asked for stakeholder feedback. (See CAISO Issues Report on Western Regionalization Studies.)
In a letter transmitting the final report to lawmakers, CAISO CEO Elliot Mainzer said, “NREL’s review of the literature makes clear [that] a broad geographic operational footprint that integrates California with the broader West tends to yield the most financial and reliability benefits due to greater resource and load diversity, while requiring resolution of governance issues.
“The report also illustrates how others in the West are creating alternative mechanisms for enhanced regional coordination outside of the footprint of the CAISO,” Mainzer said. “Utilities and regulators across the West are exploring their options with respect to regional coordination, further underscoring the timeliness and importance of this conversation.”
CAISO has revamped its policy initiative roadmap process by categorizing stakeholder initiatives under one of three “critical strategic and tactical objectives” as a way of providing more clarity on the ISO’s most significant policy goals for this year and beyond.
The reorganization of CAISO’s roadmap, which lays out the policy initiatives that the ISO plans to tackle in the next three years and their anticipated timelines in a diagram, was presented at a meeting last week that kicked off the 2023-25 planning process.
“Unlike previous years, we’ve gone ahead and organized the initiatives included in the roadmap … based on what strategic objectives we feel they most closely support,” said Gillian Biedler, CAISO policy integration and governance manager. “Some of them are quite clear. Some of them will support multiple strategic objectives. We’ve organized them that way so that you get a sense of the emphasis for those initiatives and a broader scheme of prioritization.”
The strategic goals mostly revolve around CAISO’s efforts to ensure it has sufficient capacity after three summers of strained grid conditions and to expand its regional presence through the Western Energy Imbalance Market, as well as advancing the state’s transition to 100% clean energy.
One objective is to “reliably and efficiently integrate new resources by proactively upgrading operational capabilities.” Initiatives that fall under that category focus on “improving the modeling of resources to better reflect their economic and physical characteristics,” Biedler said in her presentation.
Among them is CAISO’s Price Formation Enhancements initiative, which deals with issues such as scarcity pricing.
“Scarcity prices are important to attract supply and incent resources to be available and perform,” the ISO says on the initiative’s web page. “They are also important to provide appropriate price signals to reduce demand. Recent energy shortages and associated prices in the ISO real-time market have emphasized the need for the ISO to review and enhance its scarcity pricing provisions.”
Others deal with variable energy resources such as solar power and storage dispatch enhancements, both meant to optimize resource participation in the ISO.
A second objective is to strengthen resource adequacy and to meet the state’s climate goals through long-term transmission planning and effective coordination with state agencies such as the California Public Utilities Commission and the state Energy Commission, which share electricity planning duties with CAISO.
Initiatives dealing with changes to the ISO’s capacity procurement mechanism soft-offer cap and interconnection process enhancements fall into this category; so will processes expected to start next year on transmission planning and extreme weather events in response to FERC directives.
The third objective is to “build on the foundation of the Western Energy Imbalance Market to further expand Western market opportunities.”
The category includes initiatives to refine the rules governing the WEIM’s Extended Day Ahead Market (EDAM), which the CAISO Board of Governors and the WEIM Governing Body approved Feb. 1. (See CAISO Approves Day-ahead Market for Western EIM.)
The ISO’s Day Ahead Market Enhancements initiative and revisions to the EDAM resource sufficiency evaluation test and WEIM governance fall into this category.
The initiative and dozens of others are described in the ISO’s Policy Initiatives Catalog, which is updated twice a year. The 2023 draft catalog was last updated Feb. 16.
The Department of Energy and FERC already have enough authority to site necessary transmission lines under existing laws even without additional congressional action, the authors of a paper on the subject said in a webinar Monday.
Two of its authors, Isabel Carey, an associate at Marten Law, and Justin Gundlach, an attorney at the Building Decarbonization Coalition, spoke during the webinar hosted by ELI and the law school.
The article was published just as the national conversation around transmission was starting to shift, Gundlach said.
“Failing to develop more regional and interregional transmission capacity would mean leaving the power sector’s shoelaces tied together and constraining burgeoning efforts to build clean energy capacity,” he said. “This was true when we started writing our article years ago. But it is even more true now.”
The Inflation Reduction Act offers voluminous incentives to clean energy that are expected to accelerate the pace of renewable development, but ensuring that happens requires grid expansion, he said.
The Biden administration is aware of that, and the paper’s other two co-authors are now working at the U.S. Department of Energy: Sam Walsh is the agency’s general counsel and Avi Zevin is a deputy general counsel for energy policy.
The federal government has had backstop siting authority since the Energy Policy Act of 2005, but that tool had been collecting dust on the shelf for years until recently. The law allowed DOE to designate National Interest Electric Transmission Corridors (NIETCS), and FERC was given authority for backstop siting in the absence of state action.
The first attempt to implement the policy drew very wide corridors covering huge swaths of Southern California and the entire Mid-Atlantic, said Carey.
The U.S. 9th Circuit Court of Appeals found in California Wilderness Coalition v. U.S. Department of Energy that the agency had insufficiently coordinated with the states in determining the broad NIETCs. The court also said DOE failed to study the NIETCs’ environmental impacts as required by the National Environmental Policy Act, Carey said.
“Both of these were procedural errors that could have been fixed with additional time and resource devotion,” Carey said. “But DOE abandoned any attempt to re-designate the two quarters and has not attempted any designations since.”
The 4th Circuit limited FERC’s authority in a 2009 decision in Piedmont Environmental Council v. FERC, which found the commission could not overturn a state’s denial of a transmission line in an NIETC. That was fixed in the Infrastructure Investment and Jobs Act of 2021, which reversed the court’s finding and gave FERC the authority to approve national interest lines rejected by state regulators, said Carey.
FERC cannot act until states have a year to review transmission, but it is able to review proposals at the same time as states, which is a much more efficient process, she added.
“To address one of the problems that the failed corridor designations faced, our paper suggested that national corridors should be designated more narrowly, ideally with specific projects in mind,” Carey said. “By focusing the designated corridors, we could better tee up projects to apply for citing permits.”
AUSTIN, Texas — Infocast’s 11th ERCOT Market Summit last week attracted about 600 attendees, primarily financiers and developers, eager to gain insight into the Texas grid operator’s new products and services addressing reliability, the state’s increasing load, and emerging policy and market challenges.
Given the potential changes to how providing power is rewarded, much of the discussion centered on the performance credit mechanism (PCM), the Texas Public Utility Commission’s preferred market redesign for ERCOT.
The PCM would reward generators in ERCOT’s energy-only market with credits based on their performance during a determined number of scarcity hours. Those credits must either be bought by load-serving entities or exchanged between them and generators in a voluntary forward market. (See Texas PUC Submits Reliability Plan to Legislature.)
Most speakers expressed opposition to the construct. Others offered support.
Asked how he could be sure the untested PCM would incent gas-fired generation, as favored by the state’s lawmakers and regulators, ERCOT CEO Pablo Vegas said the market mechanism is really nothing new.
“The PCM is actually a fairly well understood set of tools that the ERCOT market and its participants have been using in different forms for many, many years,” he said, noting it can be broken down into three main components: a forward auction, a supply-and-demand curve and a backward settlement for performance during the performance period.
“We’re taking those three components and we’re putting that together. So, I think the argument that it’s too novel is really not well founded,” Vegas said. “Texas has created some of the most novel concepts in the history of energy markets. The energy-only market created back in 2000 was the first of its kind and continues to be one of the most innovative markets in the world. We have experience doing things that are completely new and different and seeing success from it.
“I think it will be well understood. I think it will incentivize generation because markets work. We have the history of knowing the markets work, when there are significant distortions that change the way those markets work, and you see issues on the market. And that’s what we’re dealing with today. Markets will work if they’re designed in a way that can be understandable.”
Campbell Faulkner, a senior vice president with over-the-counter energy commodity broker OTC Global Holdings, was asked whether the PCM market would turn into a capacity market, as some fear. He said the construct is unlikely to result in an optimum solution for everyone.
“You’re trying to marshal the quasi-governmental aspects of ERCOT with the state legislature and the end-use constituents. … It’s going to end up being filtered through the state representatives … to determine are you willing to pay more for a liability or a preference to paying less but having more frequent outages,” he said.
“Capacity markets, in general, are complicated. You’re essentially trying to ensure that you not only have fleet reliability, but you have dispatch reliability and often you have congestion reliability. The ERCOT system worked exceptionally well for most of its design life, largely because it did have a relatively high price cap. There are economic arguments that say there shouldn’t be a price cap at all to generate every single marginal megawatt. These things are all going to basically have to be relitigated.”
“If you look at other capacity market constructs … there are price mechanisms and price structures that help support debt financing for projects,” EIG Partners’ Shalin Parikh said. “When you look at the way the PCM has been proposed, I don’t foresee it being a structure that will support or that lenders will underwrite to.”
Parikh said capacity markets are “largely based on creating availability, covering your fixed costs and potentially servicing some of that financing that you have raised to build those projects.”
“From that standpoint, I would say ERCOT likely will not be viewed as a capacity market construct, even if that is the intention of the mechanism,” he said.
Katie Coleman, an attorney who represents industrial consumers, was asked what reliability problem the PCM is trying to solve as part of the PUC’s Phase II market redesign. Phase I included weatherization requirements, revisions to the operating reserve demand curve and additional ancillary services in the aftermath of the February 2021 winter storm.
“I view Phase II as an effort to try to exert more control over what investment decisions are made in a deregulated market,” she said. “This is at least the fourth time that we’ve been through this argument about whether we should impose a capacity construct on the market. I think when you are sitting in the seat as a regulator or a legislator who has responsibility for reliability, it is very attractive to try to impact market outcomes through administrative measures.
“We do believe that there are mounting operational issues in ERCOT that need to be addressed in a more tailored way,” Coleman added. “And my clients believe that it’s worth spending more money to do that, but they do believe that additional services and tools are needed to manage particularly renewable variability.”
Shell Energy North America’s Resmi Surendran said U.S. Energy Information Administration data on resource retirements and investment shows ERCOT’s energy-only market is sending the right signals to the financial community. She said the capacity markets in PJM and MISO have resulted in a combined 140 GW of investment against 77 GW of retirements, according to the EIA data.
“ERCOT has had 48 GW of investment in thermal resources in the last 20 years, but only 18 GW of retirement. That means ERCOT has load growth that is incentivizing generation,” she said. “The energy market is sending the signal that is needed for investment.”
Emily Jolly, associate general counsel for the Lower Colorado River Authority, listened to her fellow panelists and said she was noting the issues they raised and thinking about how to respond to them.
“I think the problems that we’re looking to solve in the market are, we don’t need payday loans. We don’t have a problem getting financing for the additional capital construction,” she said. “I think it’s important for us to look at the revenues that dispatchable generators are actually receiving in the ancillary services markets today. We’ve seen a lot of short-duration battery storage participating in those markets and getting increasing shares of those revenues. Those are not the kinds of resources that are going to get us through another multihour, multiday event, but I think that’s a tradeoff that we all need to be aware of.”
Study: PCM a ‘Major’ Market Overhaul
Aurora Energy Research’s Oliver Kerr shared his firm’s analysis of the PCM, saying it represents a “pretty major overhaul of the market” and that all its versions lead to a “pretty substantial shift away from scarcity value towards PCM credit.”
“I don’t think it’s an exaggeration to say that the PCM actually represents a pretty fundamental paradigm shift in how assets are remunerated in Texas,” he said. “You’re really seeing a pretty key shift away from revenues driven by energy scarcity value towards reliance on capacity payments.”
Aurora studied an illustrative PCM implemented in 2027, with credits paid for the 20 highest hours of peak net load. The firm modeled four scenarios based on renewables eligibility and the top 20 reliability hours determined seasonally versus annually. All the scenarios led to an increase in capacity, with more added when renewables were not eligible, Kerr said.
The researchers determined that excluding renewables leads to more new build capacity because fewer credits are generated. That increases the credits’ price and leads to the buildout of more peakers and batteries. Aurora found the PCM does benefit solar in all scenarios in that it sees increased capacity relative to the base case because of higher battery buildout; batteries increase solar gross margins by charging during solar production.
“All scenarios that we modeled led to an increase, a significant increase, actually, in dispatchable generation or capacity across the board,” Kerr said. “Fewer renewables means fewer credits are generated, which means that the price per credit is high as it grows to other technologies.”
Vegas Says ERCOT at Crossroads
Juliana Sersen, a 10-year veteran of ERCOT’s legal department and now a partner in the Baker Botts law firm, introduced CEO Vegas’ keynote speech by telling the audience, “I can tell you what ERCOT used to be like, but here’s someone who knows what it will be like in the future.”
“We find ourselves today at a crossroads. Facing us are a series of choices that could lead us into a prolonged season of stagnation and frustration, or continue ERCOT on a trajectory of innovation, competition and economic growth,” Vegas said in his opening comments. “As [Texas] legislators revisit the laws that they passed in 2021 and they debate the nature of their ongoing implementation going forward, I can’t think of a more important conversation or more significant way for us to spend our time today.”
Labeling ERCOT as “the nation’s only independent state grid,” he said the deregulated market’s track record is “unmatched” and its competitive edge and opportunity is “enormous.”
Vegas referred to the “false binary of renewables-only strategies” as he discussed the need for more dispatchable generation. ERCOT has seen more than 27 GW of thermal generation retire since 2000 and added more than 52 GW of renewable generation during that same time. The grid operator’s peak load exceeded 80 GW last year, more than a 5-GW jump in three years, he said.
“Are we doing what it takes to add the generation that we need before Mother Nature decides to test us again?” Vegas asked.
He assured his listeners that renewable energy remains a part of the mix as he answered a question about whether they should be excluded from the PCM.
“I think that we need to have performance criteria that creates a very dependable, responsive set of generating assets that can deliver earnings in that market,” Vegas said. PCM “is a separate market. … The energy-only market continues to operate the way it does today. All the benefits that renewables get today under the current energy on the market are going to continue to exist, so I think renewables will continue to have all the incentives that they have had historically to continue to develop.”
Political Influence Concerns Developers
A panel on ERCOT’s “new normal” in a future of volatile gas prices, increasing renewable penetration and exponential load growth debated the heavy hand of politicians following the February 2021 winter storm. The PUC commissioners at the time are all gone, replaced by Gov. Greg Abbott appointees, and the ERCOT board has replaced market representation with independent directors selected by a political committee.
The current market redesign work has only heightened fears of renewable developers that wind and solar will face stiff headwinds.
“I’ve been working in solar and ERCOT for a number of years now, and it definitely feels like it’s changing,” Lightsource BP’s Helen Brauner said. “The demand thankfully is greater than it’s ever been, so that’s a very positive trend and change. It’s a great market for solar, but it kind of feels like there’s additional pressures afoot.”
Brauner said that while ERCOT is on track to add 8 GW of solar-powered capacity this year and Texas is expected to overtake California as the No. 1 state for solar power, she is noticing political pushback against renewable energy. Referring to a recent bill filed at the legislature “with some really egregious time terms,” she said, “That just didn’t happen before, so I’m a little nervous about seeing things like that.”
Julia Harvey, vice president of government relations and regulatory affairs for Texas Electric Cooperatives, agreed with Brauner.
“I’m not the first to observe this, but maybe the trend towards politicization of the stakeholder process has always somewhat been the case because of the unique nature of electricity. You can’t just design a market purely based on economic ideals,” Harvey said. “There’s always other motivations, but since the [2021] winter storm, I think there’s been a more pronounced movement away from this kind of stakeholder-driven, more sort of technocratic policymaking to something that’s more top down, and I think that can create some sense of instability for market participants.”
“I feel like things are getting kind of political, and that concerns me,” Brauner added. “All these different generation resources have different pros and cons to them, and I just don’t want ERCOT or the politicians to pick and choose generation. Just lay out what we need, and let the resources figure out what they need to make money. That’s how it’s always been. … I just hope that continues.”
