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November 5, 2024

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Stakeholders Respond to ERCOT Market’s Proposed Redesign

Texas regulators have received almost 120 comments from ERCOT stakeholders and the public about their proposed market redesign, feedback they will review and discuss before turning over their final recommendation to lawmakers next year.

From global energy powerhouses like Shell Energy, to individual ratepayers, commentators have given the Public Utility Commission hundreds of pages for their holiday reading pleasure. Stakeholders had 35 days to file their comments before a Thursday deadline (54335).

The comments echo those made by lawmakers during recent public hearings: The PUC’s preferred market design is too complicated and an unknown among other grid operators. There is no reliability standard. It won’t attract new baseload generation to Texas.

A San Francisco-based energy consulting firm spent several months modeling and analyzing market designs proposed by the PUC following public work sessions after the deadly 2021 winter storm nearly collapsed the ERCOT grid. Energy + Environmental Economics (E3) recommended a forward reliability market construct that relies upon a centrally cleared auction procuring the “requisite” amount of reliability credits.

PUC staff instead urged the commissioners to pursue a performance credit mechanism (PCM) that requires load-serving entities to buy performance-based credits from generation resources in a voluntary forward market. The credits are awarded to resources through a retrospective settlement process based on availability during the 30 hours of highest risk, according to their load-ratio shares during those same periods. (See Proposed ERCOT Market Redesigns ‘Capacity-ish’ to Some.)

Potomac Economics, ERCOT’s Independent Market Monitor, said it found the PUC’s first phase of market changes to be “far more effective and more sound economically” than the proposals in E3’s report. The early modifications included a 44% reduction in the market’s price cap to $5,000/kWh and shifting the operating reserve demand curve (ORDC) so that the market’s shortage-pricing mechanism increased real-time energy revenues by $1.7 billion this year through November, according to Potomac.

“We continue to believe in the effectiveness of the energy-only market,” the Monitor wrote. “The energy-only market is an effective pay-for-performance mechanism and should be retained in full without adding an unnecessary separate availability payment structure that would be difficult to accurately hedge or predict due to its ex post procurement.”

Potomac recommended against the PUC moving forward with any of its designs, saying the PCM is “a less effective and efficient means to facilitate performance by ERCOT’s generation fleet” than the current construct. It did allow that the PCM would be “less disruptive” to the current market than the backstop reliability service (BRS) mechanism, an ancillary service meeting specific reliability needs during high uncertainty periods.

ERCOT Market Reorm Assessment (E3) Content.jpgERCOT market participants have plenty to say about a consultant’s report on the ERCOT market’s redesign. | E3

The Steering Committee of Cities Served by Oncor wrote that the PUC’s ultimate goals and principles in redesigning the market remain “unclear.” It called on the commission to direct E3 to revise and expand its analysis, saying the firm’s report is “inadequate as a basis for such a momentous redirection of the state’s and consumers’ energy resources.”

The Texas Public Policy Foundation, a nonprofit organization pushing the oil and gas industries’ interests, took aim at the “overinvestment” in renewable energy, saying any new market design needs to also address “underinvestment” in dispatchable generation.

“Any program that only addresses the underinvestment problem is simply countering the federal subsidies for wind and solar with state subsidies for dispatchable generation and will lead to skyrocketing costs for ratepayers,” the foundation said.

The PCM also has its supporters. Vistra and NRG Energy, the state’s two largest generation owners, favored the PUC’s recommendation.

The R Street Institute — a nonpartisan, public policy research organization that last year pushed its own version of the PCM — called the PUC’s preferred design a “workable framework” that will add “additional incentives for installed [reserve] capacity.”

The Texas Competitive Power Advocates (TCPA) — a trade association representing generators, wholesale marketers and retail providers — said it stands ready to bring more than 4.5 GW of additional generation to ERCOT if the PCM is adopted under the “right framework.”

“The E3 report demonstrates that the status quo energy-only market will not incentivize sufficient new generation or retain sufficient existing generation to ensure resource adequacy and reliability outcomes acceptable to Texans,” TCPA Executive Director Michele Richmond wrote. She said the PCM will meet the objectives of legislation passed year that requires a reliability standard for the grid and a market design ensuring reliability during extreme weather and periods of low non-dispatchable power.

“The [PCM] can achieve this; alternative and unstudied half-measures cannot,” Richmond said. “Nor can state-subsidized generation or loan programs, which may marginally reduce the cost of new generation but would also accelerate the retirement of the gas generation that kept the power on this summer.”

The PUC has scheduled a work session on Jan. 12 to discuss the design proposals and stakeholder feedback. A vote is not expected on the proposals during that meeting, but a plan is expected to be adopted later in the month, a commission spokesperson said.

“As [PUC Chair Peter Lake] has repeatedly assured, the commission will continue to work closely with the legislature on this important issue,” Rich Parsons said in an email to RTO Insider.

ERCOT’s Kenan Ögelman, vice president of commercial operations, said it will take at least 1.5 to 2.5 years and up to $4 million to implement the PCM, assuming the project can be done concurrently with the delayed real-time co-optimization (RTC) market tool’s development. He said that estimate is in addition to at least six months to write the necessary rules and protocols.

In comparison, delivering the BRS will take between 15 months and 2.5 years, Ögelman said. Again, this assumes the design’s work will be managed alongside that of the RTC tool. (See ERCOT Technical Advisory Committee Briefs: Dec. 5, 2022.)

“There is significant overlap in the systems that would be impacted by implementation of PCM and BRS, as well as the employees who would be needed to work on those projects,” Ögelman wrote. “As such, a decision to implement one program would significantly impact the timing of when the second program could be delivered.”

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CAISO, WEIM Boards Back Reliability Enhancements

The CAISO Board of Governors and the Western Energy Imbalance Market Governing Body on Wednesday adopted storage and resource-sufficiency upgrades intended to promote grid reliability.

Exercising joint authority on WEIM matters, both boards approved changes to the interstate market’s resource sufficiency evaluation (RSE). The test is meant to ensure that each WEIM participant enters a trading hour with enough capacity and ramping capability to supply its own needs and to prevent participants from “leaning” on the market to meet internal demand.

The two bodies adopted a first phase of changes to the RSE in February. Scheduled to take effect this summer, they include provisions to measure a participant’s available supply more accurately and allow demand response programs to count toward the RSE. (See CAISO, WEIM Adopt Resource Sufficiency Changes.)

The second phase of changes approved Wednesday will allow transfers into balancing authority areas that failed the RSE, subject to surcharges.

“These optional transfers, termed ‘WEIM assistance energy,’ will enable BAAs that are short supply to access the WEIM’s efficient dispatch while still providing incentives for BAAs to participate in the WEIM with sufficient resource to meet their own load,” Anna McKenna, CAISO’s vice president of market policy and performance, wrote in a Dec. 7 memo to the ISO and EIM boards.

Market participants helped develop the changes through CAISO’s RSE enhancements stakeholder initiative. NV Energy (NYSE:BRK.A), for example, raised concerns in February about the RSE being too restrictive and reducing the market’s ability to help in potential energy emergencies, which Nevada and California have faced in summer heat waves the past three years.

The utility asked CAISO to develop a mechanism to allow excess supply to “be available to the distressed EIM entity at an appropriate scarcity price,” Market Policy Manger Lindsey Schlekeway wrote in a Dec. 14 letter to the boards.

“NV Energy supports the CAISO’s final proposal for the resource sufficiency enhancements phase 2 because it creates a financial mechanism that EIM entities can opt in to,” Schlekeway wrote. “We recognize this is not a final solution for the resource sufficiency enhancements, but it is of critical importance not to delay the implementation of this reliability enhancement past the summer of 2023 for grid reliability.”

The ISO’s Market Surveillance Committee (MSC) said in a written opinion that the change will likely produce mixed results, “but we understand that the one or two BAAs that may utilize it believe it will be beneficial. However, it is our belief that these changes still leave the RSE almost certainly in need of further refinement.”

Another change exempted CAISO from counting low-priority exports in its RSE obligations.

“This change accounts for interactions between WEIM energy transfers and ISO exports that can occur in the real-time markets and can result in [CAISO] erroneously failing the RSE when it has sufficient internal supply resources to meet its load obligations,” McKenna wrote. “WEIM BAAs receiving these exports would still be permitted to count the supported supply towards meeting their RSE obligations.”

The MSC supported the change as “it clearly constitutes improvements in the RSE relative to current practice.”

Storage Enhancements

Additional reliability enhancements approved Wednesday are meant to better manage an increasing amount of battery storage in CAISO and the WEIM.

The ISO’s energy storage enhancements stakeholder initiative, begun in February 2021, generated the proposals. California and WEIM participants in the Southwest need battery backup power as solar ramps down late in the afternoon but demand remains high in heat waves from air conditioning use.

CAISO has been adding battery storage rapidly since the rolling blackouts of summer 2020, when it had only 200 MW, and it now has 4,700 MW online, with a goal to add 10 GW or more. Other WEIM entities are expected to add significant amounts of storage in coming years.

The ISO’s relatively recent experience with battery storage has led it to make corrections and adjustments, which it expects to continue as it moves forward.

“Most of the storage policy and the market tools that we’re using on the system today were implemented at a time before we had very much storage capacity actually operating and performing,” Gabriel Murtaugh, the ISO’s storage sector manager, said in Wednesday’s meeting. “So, this policy really is the ISO looking back on performance of these resources over the last few years and thinking about where we need to go and how we need to evolve.”

The grid reliability enhancements include software tools to better account for a storage resource’s state of charge when the resource is providing regulation service, requiring it to quickly charge or discharge to meet grid needs. In a September heat wave that brought CAISO close to ordering blackouts, some batteries discharged early and were not available when needed most.

A second component of the effort establishes new bidding requirements for storage resources that provide ancillary services. It requires “scheduling coordinators for storage resources to submit economic energy bids to charge when awarded upward ancillary services, or economic bids to discharge when providing regulation down,” McKenna wrote. “This, coupled with the first change, will ensure that a storage resource is available to provide awarded ancillary services.”

McKenna noted some stakeholders — particularly Vistra (NYSE:VST), a major operator of utility-scale battery storage in California — had expressed concern about the new bidding requirements “potentially reduc[ing] how much ancillary services storage resources may be awarded, which could impact resource profitability.”

“The ISO recognizes this limitation, [but it] has experienced operational issues during some periods in which storage resources that are scheduled to provide ancillary services may be unable to do so due to either too high or too low of state of charge,” she wrote. “This situation can threaten grid reliability if operating reserves from such resources are unable to be deployed during a contingency outage event. This typically occurs when storage resources are at very high or very low levels of state of charge and can be less responsive.”

The changes require FERC approval before they can take effect. Vistra indicated in a letter to CAISO that it might challenge the ancillary service proposals, which it said “would lead to inefficient [and] potentially harmful market outcomes in implementation if these proposals are approved by FERC.”

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Invenergy Files Suit Against Wash. Cap-and-trade Program

The owner of Washington’s only non-utility gas-fired plant has filed a suit over what it claims is discriminatory treatment in the state’s impending cap-and-trade program.

Chicago-based Invenergy on Tuesday filed the action against the program’s administrator, Washington’s Department of Ecology, in the U.S. District Court in Tacoma, Wash. 

Invenergy owns the 698-MW Grays Harbor Energy Center in Elma, Wash., the only gas-fired facility in Washington not owned by a utility. The plant did not receive an allocation of no-cost carbon allowances such as those granted to utility-owned power plants under the state’s new cap-and-trade program, which goes into effect Jan. 1.

The company’s petition contends that the state law underpinning the program, the Climate Commitment Act, is unconstitutional because it discriminates against independent owners of fossil fuel plants, violating the Equal Protection Clause of the U.S. Constitution. The lawsuit also alleges the Ecology Department denied the plant no-cost allowances under the program because it has an out-of-state owner, a violation of the Constitution’s Commerce Clause.

Invenergy complains that Grays Harbor will have to add the costs of buying cap-and-trade allowances to its power prices, a burden not faced by the 12 other utilities that own gas-fired plants. “The [Climate Commitment Act’s] allocations of no-cost allowance uniquely harm Invenergy. … Ecology brushed aside Invenergy’s concerns about unfair treatment,” the complaint said.

The lawsuit seeks no-cost allowances for the plant.

Under cap-and-trade, greenhouse gas emitters must acquire allowances for specific volumes of emissions, which they can buy, sell or trade with other businesses. The maximum volume of statewide emissions and allowances will decrease over time under the program.

The program’s plan calls for an undetermined number of emissions allowances to be auctioned four times a year to smokestack industries. The first auction is set to be held at a yet-to-be-scheduled date in February 2023. The state will set the number of allowances 60 days prior to the auctions.

Companies would bid on the allowances in clusters of 1,000 individual allowances. The number of allowances will be decreased over time to meet 2035 and 2050 decarbonization goals. If Washington chooses to join the Western Climate Initiative, which includes California and Quebec, participants would expand their purchase and trading territory to those two areas. Washington is the second state to adopt a cap-and-trade system following California.

For each auction, a specific number of allowances would be made available to bidders. All bids must be above a certain price level set in advance by the state. The highest bidder would get first crack at the limited number of allowances, while the second highest bidder would get the second crack, followed by additional iterations. The auction ends when the last of the designated number of allowances is bid upon. Then all the successful bidders pay the same clearing price set by the lowest successful bid.

Invenergy’s lawsuit alleges that the 12 in-state utilities have stronger local, political, donation and lobbying presences in Washington than that company, leaving the Illinois company out-gunned in efforts to lobby the state legislature and Ecology Department.

“We are reviewing the filing by Invenergy and Grays Harbor Energy,” Ecology said in a statement. “As we work to implement the Climate Commitment Act and reduce the largest sources of carbon pollution in Washington, we are committed to following the direction set by the Legislature. We believe courts will find that the law and Ecology’s work to implement it are fully constitutional.” 

Ecology rejected allocating no-cost allowances to Grays Harbor goes despite a recommendation by Washington’s Energy Facility Site Evaluation Council in September to extend the allowances to the plant.

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ERCOT Briefs: Week of Dec. 12, 2022

Texas Grid Prepared for Winter’s First Frigid Blast

ERCOT on Friday issued an operating condition notice to the system’s generators in advance of a polar blast that will drop temperatures below freezing next weekend.

The procedural notice alerts the grid operator’s market participants that temperatures will be 25 degrees Fahrenheit or lower in the Dallas and San Antonio metro areas from this Thursday through Dec. 26. It is the lowest of ERCOT’s four emergency-level communications.

ERCOT on Saturday projected demand to peak at 69.7 GW at 10 a.m. on Dec. 23, more than 2 GW more than its forecasted winter peak of 67.4 GW in its seasonal assessment released in November. (See ERCOT Says ‘Sufficient’ Capacity to Meet Winter Demand.)

“As we monitor weather conditions, we want to assure Texans that the grid is resilient and reliable,” ERCOT CEO Pablo Vegas said in a press release. “We will keep the public informed as weather conditions change throughout the coming week.”

Meteorologists have said the cold weather could threaten regional records that date back to 1983 but won’t be as bad as the deadly 2021 winter storm that almost brought down the ERCOT grid.

“The duration of this cold, the lack of snow and ice, and the intensity of the cold statewide will still lag February 2021, so at this point, we’ll take ERCOT at their word that grid conditions should be manageable,” Space City Weather meteorologist Matt Lanza said.

The Texas grid operator said it has sufficient generation to meet the forecasted demand and will continue to provide updates. The primary concern remains natural gas production, where wellheads can freeze and pipelines lose pressure. It was the lack of supplies from the gas fields that led to much of the generation problems during the 2021 storm.

ERCOT has increased weatherization requirements and improved coordination with the gas industry since the storm.

Fuel Mix Dashboard Added to Website

The grid operator has unveiled a new fuel mix dashboard on its website that provides a real-time view of energy generation by resource type.

ERCOT Fuel Mix (ERCOT) Content.jpgERCOT has added a real-time fuel mix dashboard to its website. | ERCOT

 

The dashboard offers several views of energy generation. The real-time view shows the current percentages of energy generated by resource type, with current and previous day options that can be displayed in a stack view or a line chart.

The fuel mix includes “power storage” as the output from energy storage resources when they are discharging power. Under current market rules, power consumed by storage resources when they charge is included in system load.

Dan Woodfin, vice president of system operations, said the dashboard is the “latest in a series of improvements to increase public visibility” into ERCOT.

The dashboard is accessible from the Grid and Market Conditions page on ERCOT’s website.

Brazos Repays Market $1.15B

ERCOT will begin distributing holiday gifts to market participants this Tuesday after an initial payment of $1.15 billion from Brazos Electric Power Cooperative last week. The cooperative declared Chapter 11 bankruptcy following 2021’s disastrous winter storm and only recently had a reorganization plan approved by a federal bankruptcy plan. (See Bankruptcy Judge Approves ERCOT-Brazos Settlement.)

Under the terms of a settlement agreement between ERCOT and Brazos, the cooperative will eventually pay the grid operator $1.4 billion to resolve its short pay to the market. The $1.15 billion Brazos sent to ERCOT on Thursday will be followed by 12 annual payments of $13.8 million.

In a market notice, staff told market participants the first payment will fully replenish $599.7 million for congestion revenue rights funds that they used to reduce the market shortfall, attributable to Brazos’ short-pay, immediately following the winter storm. The funds will also be used to pay eligible market participants for their allocable portion of the Brazos short-pay claim.

The timing and amount of payments to eligible market participants will be determined by the payment option they elected or were assigned.

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CARB Approves Plan to Reach Net Zero by 2045

The California Air Resources Board on Thursday approved a climate change scoping plan that charts a course for the state to achieve carbon neutrality by 2045.

The plan aims to slash greenhouse gas emissions to 85% below 1990 levels by 2045.

Its goal is to shift the state away from dependence on petroleum and natural gas to clean and renewable energy and zero-emission vehicles. It envisions an 86% drop in demand for all fossil fuels by 2045, with a 94% drop in demand for oil.

“Implementing this plan will achieve deep decarbonization of our entire economy, protect public health, provide a solid foundation for continued economic growth, and drastically reduce the state’s dependence on fossil fuel combustion,” CARB Chair Liane Randolph said in a statement.

The board’s vote was the final approval for the plan, which has been in the works for two years. State law requires a scoping plan update every five years. The previous scoping plan was adopted in 2017.

The 2022 scoping plan involves an “unprecedented deployment of clean technology,” CARB staff said.

By 2045, the plan envisions a 37-fold increase in the number of zero-emission vehicles on the road in California and a six-fold increase in residential electric appliances. Electricity generation would nearly double, with a four-fold increase in installed wind and solar capacity. The state’s hydrogen supply would grow to about 1,700 times the size of the current supply.

The plan incorporates Gov. Gavin Newsom’s goals of developing 20 GW of offshore wind by 2045 and meeting the increased demand for electricity without new gas-fired plants. (See Calif. Boosts Offshore Wind Goals.)

In addition to the 2045 carbon neutrality goal, the scoping plan includes a 2030 target of reducing GHG emissions to 48% below 1990 levels. That exceeds a statutory goal of a 40% emissions reduction by 2030.

CARB staff described the years leading up to 2030 as “the decade of action.” That will include speeding up construction of clean energy infrastructure and deployment of clean technology.

“Planning on a longer time frame for the new carbon neutrality target means California must accelerate near-term ambition for 2030 in order to be on track to achieve the longer-term AB 1279 target,” the board said in a resolution approving the plan.

AB 1279, which Newsom signed into law in September, sets a state policy to achieve net zero greenhouse gas emissions “as soon as possible, but no later than 2045.” The bill also sets an 85% emissions reduction target by 2045.

The 2022 scoping plan includes for the first time a detailed plan for natural and working lands, which play a role in storing carbon but also release emissions through wildfires. The plan calls for a 10-fold increase in fuel reduction and restoration of forests, shrublands and grasslands. Another goal is to establish defensible space — clearings that protect buildings from wildfires — on 46,000 properties per year. The plan aims for a 10% reduction in wildfire emissions by 2045.

Even with significant emission reductions from a broad range of sources, some GHG emissions will remain in 2045, CARB said. To address those remaining emissions, the scoping plan calls for using mechanical methods to remove CO2 from the atmosphere and storing it.

Implementation of the scoping plan will involve the adoption of new regulations and strengthening of existing rules. CARB plans to coordinate with other state agencies, as well as local governments, on meeting the plan’s goals.

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FERC OKs Sale of NY Power Plant to Crypto Miner

FERC last week granted a cryptocurrency mining company approval to buy a 60-MW gas-fired power plant near Buffalo, N.Y., where it has been running some of its operations (EC22-78).

FERC ruled that there was nothing within the parameters of its review that would block the sale. The New York state Public Service Commission reached the same conclusion in September.

Crypto mining has been under fire in New York for the carbon footprint of its huge electrical demand, and the state recently placed a two-year moratorium on permits for carbon-fueled operations. That first-in-the-nation move does not halt existing operations. (See: NY Slaps Moratorium on Certain Crypto Mining Permits)

The crypto operation at the Fortistar North Tonawanda (FNT) plant has been the target of noise and environmental complaints, although it also has supporters, as do other mining operations in the economically stagnant upstate region.

A subsidiary of Digihost Technology (Nasdaq:DGHI) seeks to buy FNT from its parent entities. In regulatory filings, it said there would be no change in the day-to-day operations after the purchase. The same company running it under contract since 2002 would continue to operate it, and it would sell to the wholesale power market whatever electrical output it does not use for on-site crypto operations.

The thermal output of the co-generation plant has, in the past, been shipped to a greenhouse complex via a 2.5-mile steam pipe but that had ceased at the time of application.

The 133 comments on the purchase submitted to the state PSC ranged from support because of economic benefits to opposition because of emissions.

In response to critical comments during the state review, Digihost said it intended to convert the plant to run on renewable natural gas and then hydrogen. It said this would make it entirely powered by zero-emissions sources by the 2025, and thereby compliant with New York state’s increasingly stringent climate protection laws.

In its Sept. 15 ruling, the PSC said environmental concerns were beyond the scope of its limited review. It could only look at whether the transaction would create an opportunity to exercise horizontal or vertical market power, or would create potential to harm ratepayers. It would not, six of the seven the commissioners said, and therefore the PSC would not undertake an expanded review.

FERC authorized the transaction, finding no impact on horizontal or vertical competition, no adverse impact on rates, no impairment of regulation and no cross-subsidization.

An attorney representing Digihost in the regulatory process declined to comment on the matter Friday.

An update issued by the company Dec. 2 indicated it expected the sale to close in the first quarter of 2023.

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California Energy Commission Approves $2.9B Clean Transportation Plan

The California Energy Commission on Wednesday approved a broad investment plan for $2.9 billion in state clean-transportation funding through 2026, with most of the money allocated to charging infrastructure for light-, medium- and heavy-duty electric vehicles.

“I just want to acknowledge how transformational this plan is,” said Commissioner Patty Monahan, who led the effort. “In terms of the level of investment, it’s 30 times what our [Clean Transportation Program] budget was in 2019, so that’s just an eye-popping number, but I would say that it is commensurate with the level of ambition in the state.

“We are seeking to zero-out emissions from all sources of transportation in the next 15 to 25 years,” she continued. “Historically, I would say lack of investment by the auto and vehicle industry largely was the biggest obstacle to zeroing out emissions from transportation. Now I wouldn’t say that. Now it’s infrastructure, and we need to build out infrastructure in a way that’s really attentive to the needs of communities and ensures that people are not left behind.”

The Energy Commission’s funding plan mainly adheres to requirements imposed by the State Legislature in the two most recent state budget cycles, which dedicated a total of $10 billion to accelerate the state’s transition to zero-emission vehicles.

The plan includes $1.7 billion for medium- and heavy-duty ZEV infrastructure and $900 million for light-duty EV charging infrastructure.

The remaining $300 million will go to promote in-state ZEV manufacturing, hydrogen fueling stations, low- and zero-carbon fuels, workforce development, vehicle-to-grid integration, and emerging technologies in zero-emission planes, trains and ships.

Funding for the current fiscal year of more than $1 billion is guaranteed, but future years will require legislative appropriations. The CEC intends to distribute the funds through competitive grant solicitations and direct-funding agreements.

“CEC staff estimates the plan will result in 90,000 new EV chargers across the state, more than double the 80,000 chargers installed today,” the commission said in a news release. “Combined with funding from utilities and other programs, these investments are expected to ensure the state achieves its goal to deploy 250,000 chargers by 2025.”

CARB Funding

The commission’s charging infrastructure investment plan complements $2.6 billion in incentives for clean cars and trucks that the California Air Resources Board approved Nov. 17.

CARB’s funding included $2.2 billion in incentives for clean trucks, buses and offroad equipment; $326 million for the purchase of zero-emission light-duty vehicles; and $55 million for clean mobility projects, such as community shuttles and bike-share programs. (See CARB Approves $2.6B in Clean Vehicle Incentives.)

Together, the $5.5 billion in ZEV funding is intended to help the state reach its decarbonization targets: All new passenger cars sold in-state must be emissions-free by 2035; all new medium- and heavy-duty vehicles sold must be ZEVs by 2045; and greenhouse gas emissions must be 40% below 1990 levels by 2030.

A series of bills, regulations and executive orders established the mandates, mostly in the past five years.

The CEC estimates the state will need to install 1.2 million light-duty EV chargers and 157,000 medium- and heavy-duty EV chargers over the next decade if it hopes to achieve its goals.

CPUC Actions

In support of EV charging needs, the California Public Utilities Commission has authorized the state’s three large investor-owned utilities to install thousands of EV chargers in recent years. In August 2020, for example, the CPUC approved Southern California Edison’s plan to install 38,000 charging ports at a cost of $437 million.

Last month it approved a $1 billion, five-year effort to provide charging infrastructure for EVs. Approximately 70% of the funds will be dedicated to charging medium- and heavy-duty vehicles; the rest will be for light-duty EV charging at or near multifamily housing complexes, with priority given to investments in low-income, underserved and tribal communities.

On Thursday, the CPUC authorized Pacific Gas and Electric to install 2,822 light-duty Level 2 chargers and direct-current fast chargers at multifamily housing complexes, workplaces and public-destination sites, “which typically face the biggest barriers to EV charging and transportation electrification,” the commission said in a news release.

The first phase of the program will run from 2023 to 2025 with $52 million in funding. PG&E must spend at least 65% of the funds in underserved communities, the CPUC said.

In a separate move Thursday meant to accelerate charger installations, the CPUC established a 125-day timeline for utilities to connect customers with EV infrastructure to the grid, “referred to as energizing new EV electric load,” the news release said. The timeline includes 25 days to obtain local permits.

The CPUC also required the utilities to make the energization process clearer to customers.

“Today’s energization decision takes big steps to speed up the process of connecting new EV chargers to the electric grid and to make sure utilities provide customers information about how that process works,” Commissioner Clifford Rechtschaffen said in a statement following the vote.

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APS Can Adopt Flowgate Methodology, FERC Rules

FERC on Thursday approved Arizona Public Service’s proposal to begin using the flowgate methodology to calculate available transfer capability (ATC) within its transmission system.

In approving the change, the commission rejected a protest by the Southwest Public Power Agency (SPPA), which complained that APS did not sufficiently explain the impact the move might have on transmission customers and other transmission facility owners in the region.

The commission also denied APS’s request to waive a requirement that the utility continue to post total transfer capability (TTC) on its Open Access Same Time Information System (OASIS) after transitioning to the new methodology (ER22-2476).

Provider Discretion

The APS proceeding has its roots in FERC Order 890, which sought to “increase nondiscriminatory access to the grid by eliminating the wide discretion that transmission providers currently have in calculating” ATC. The order required utilities to develop consistent methodologies for performing the calculation and to publish those methodologies for review.

Issued in 2007, Order 890 revised the pro forma Open Access Transmission Tariff (OATT) to require that transmission providers clearly identify the methodology and mathematical algorithms used “to calculate firm and non-firm ATC (and [available flowgate capability] AFC, if applicable) for its scheduling, operating and planning horizons.”

APS sought to revise its OATT by replacing the rated system path methodology with the flowgate methodology to calculate ATC across the three horizons.

According to NERC, the flowgate methodology identifies key transmission facilities as flowgates, a mathematical construct used to analyze the impact of power flows on the bulk electric system.

Under the method, NERC explains, “total flowgate capabilities (TFC) are determined based on facility ratings and voltage and stability limits. The impacts of existing transmission commitments (ETC) are determined by simulation. The impacts of ETC, capacity benefit margin (CBM) and transmission reliability margin (TRM) are subtracted from the total flowgate capability, and postbacks and counterflows are added, to determine the available flowgate capability (AFC) value for that flowgate.”

In Thursday’s order, the commission explained that “In order to have consistent posting of ATC, TTC, capacity benefit margin, and transmission reliability margin values on OASIS, the commission directed public utilities working through NERC to develop the available transmission system capability reliability standard, a rule to convert available flowgate capability values into ATC values.” The commission also affirmed that providers relying on the flowgate methodology are required to convert their AFC values to ATC and post the associated calculations on their OASIS and web sites.

The commission noted that, in response to a deficiency letter, APS had provided the required documentation for its various calculations, including those related to AFC and ATC — as well as its process for converting AFC to ATC.

But the proposed changes prompted a protest by SPPA. While claiming no objection to the use of the flowgate methodology, the power agency said it would be more “sensible” for all entities with component facilities on the APS system to adopt the methodology together.

SPPA also contended that APS’ filing with FERC lacked key details about the utility’s implementation of the methodology and that APS failed to inform the commission, transmission owners and customers how the methodology would affect transmission allocation and scheduling.

SPPA additionally argued that APS failed to explain how the new methodology would affect other transmission facility owners and transmission customers, particularly those in the Palo Verde area. It asked FERC to reject the changes or suspend APS’ filing for five months to either set the issue for settlement judge procedures or a technical conference.

The commission acknowledged SPPA’s concerns about transitioning to the flowgate methodology but agreed with APS that Order 890 gives transmission providers discretion in choosing their ATC calculation methodology.

The commission found that SPPA had “not identified any specific concerns with APS’ proposed OATT revisions,” and that APS had “appropriately revised its OATT to reflect the transition consistent with FERC requirements, finding the revisions to be just and reasonable.”

FERC also rejected SPPA’s requests to suspend the filing or convene settlement judge procedures or a technical conference, saying “there are no issues of material fact that would warrant a hearing.”

‘Industry-wide Consistency’

Thursday’s ruling also denied APS’s request for waiver of the requirement to post TTC values on its OASIS site. The utility had argued that while Order 890 references TTC as a component of ATC, TTC is not actually a component of ATC for providers relying on the flowgate methodology, who instead use TFC in their calculations. APS said the requirement to post TTC on OASIS would be a “burdensome, manual process” with little customer value.

In denying the waver, the commission said Order 890 “addressed the potential for undue discrimination by requiring industry-wide consistency and transparency of all components of the ATC calculation methodology and certain definitions, data and modeling assumptions. The commission [in Order 890] noted its concern that the lack of consistent, industry-wide ATC calculation standards poses a threat to the reliable operation of the bulk-power system, particularly because a transmission provider may not know its neighbors’ system conditions and how that might affect its own ATC values.”

The commission also found that APS erred in citing previous FERC cases, specifically 2009 rulings involving SPP (127 FERC ¶ 61,207) and Midwest ISO (126 FERC ¶ 61,107) to support its argument. It noted that the applicant in SPP requested only a temporary waiver of the requirement to post ATC, TTC, CBM and TRM values on its OASIS site. In Midwest ISO, the commission granted MISO a waiver of the requirement to post certain ATC components on its OASIS site for paths internal to the MISO system, but not for other transmission service requests, the commission added.

“APS has also failed to adequately explain how requiring APS to convert TFC to TTC would impose significant burdens on its staff,” the commission determined.

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FERC Again Prohibits MISO TOs from Financing Merchant Upgrades

FERC last week upheld its prior ruling blocking MISO transmission owners from self-funding network upgrades for merchant HVDC transmission lines.

The commission affirmed in its Friday order a decision issued in the spring that the self-funding option cannot be extended to merchant upgrades because their developers aren’t offered the same range of financing options as transmission owners under certain circumstances (ER22-477-002). (See FERC Blocks MISO Self-fund Rule for Merchant HVDC Line Upgrades.) 

FERC rejected arguments from MISO, its transmission owners and ITC Midwest that merchant HVDC developers and generation developers are interchangeable because they both require upgrades to the system for their projects.

The commission again emphasized that MISO doesn’t include an option to build or liquidate damage provisions in interconnection agreements for merchant HVDC developers without injection rights or a precertification from MISO that its system can handle the capacity and energy the line plans to deliver. The grid operator allows merchant HVDC lines to connect to the system without injection rights, but those lines are considered non-firm and the upgrades are classified as necessary upgrades instead of network upgrades.

MISO, TOs and ITC argued that necessary upgrades for HVDC lines are similar to the RTO’s other network upgrades, where the owners have the right to finance the upgrades before the interconnection customers are offered the chance.

“The thrust of MISO and MISO Transmission Owners’ and ITC Midwest’s argument on rehearing is that these two sets of customers are effectively indistinguishable, but neither grapples with how, then, MISO’s proposal to afford options to control risk and certainty during the design and construction process to only one set of customers is just and reasonable and not unduly discriminatory,” FERC wrote.

The commission said MISO’s case for applying initial funding to merchant HVDC lines “does not alter the fact that MHVDC connection customers with necessary upgrades are distinct because, unlike interconnection customers and MHVDC connection customers with network upgrades in MISO, they lack injection rights and are subject to different study requirements.”

Commissioner James Danly again protested the decision, as he did when it first came before FERC. He repeated a dissent that the decision denies “transmission owners’ right to receive a return on and of the capital costs of network upgrades, necessary upgrades and transmission owner system protection facilities.”

Commissioner Mark Christie separately concurred, contending that merchant developers are on equal footing with generation developers in RTOs. He said they should both pay the full “but for” costs of interconnection, including network upgrades.

“When … a generation developer or a merchant transmission line developer pays the full costs of its interconnection, it is the developer incurring a cost of capital, not the transmission owner,” he wrote. “Allowing the transmission owner a profit on someone else’s capital investment would be an unearned windfall. When the transmission owner incurs operations and maintenance costs associated with the upgrade, the transmission owner can seek cost recovery in compliance with applicable utility accounting rules or other acceptable procedures.”

The latest decision on HVDC self-funding is connected to a larger, still-unfolding saga over who has the right to finance line upgrades in MISO.

MISO reinstated TOs’ right to self-fund network upgrades necessary for new generation at the direction of a 2019 FERC order. The decision has been a hot-button issue, spawning three years’ worth of reopened contracts, refunds to interconnection customers, interconnection agreements left unexecuted in protest, and condemnation from FERC Chairman Richard Glick. (See FERC Upholds MISO Self-fund Order, Glick Dissents.)

The D.C. Circuit Court of Appeals in November ruled that FERC did not adequately explain why it recently reinstated transmission owners’ option to self-fund. It remanded the case back to the commission. (See FERC Must Clarify MISO Tx Funding Decision, DC Circuit Finds.)

MISO has revised various interconnection agreements for TOs who wanted to have first crack at network upgrades’ initial funding. (See FERC Accepts Documents in MISO TOs’ Self-fund Selection.)

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FERC Upholds MISO’s Cost Allocation for LRTPs

FERC continues to sanction MISO’s separate-but-equal postage stamp rate that is divided between its Midwest and South regions for major transmission buildout.

The commission rejected rehearing requests with an order Friday that keeps MISO’s subregional cost-allocation method for long-range transmission planning (LRTP) projects in place (ER22-995-001).

FERC said it continues to believe that it’s appropriate for the RTO to allocate project costs “broadly within a single subregion rather than solely on a systemwide basis.”

MISO is using a FERC-approved 100% postage stamp to load rate for the first two cycles of projects coming out of its LRTP studies. The costs are confined to the grid operator’s Midwest region, where the projects are physically located. (See FERC OKs MISO’s Bifurcated Cost-allocation Tx Design.)

When the RTO begins addressing needs in its South region during the final two LRTP portfolios’ work, it said it might use a new, more specific cost-allocation design that accounts for more beneficiaries. (See “Zeroing in on Cost Allocation,” ‘Conceptual’ Tx Planning Map Troubles MISO Members.)

MISO has already approved $10 billion in projects with its first LRTP portfolio. It may recommend up to $30 billion of work as part of its second portfolio.

Sequestering MISO Midwest from MISO South continues a transmission-planning tactic that staff has used since integrating the South in 2013. Through separate cost-allocation treatment and study deferrals, MISO shields its South region from footprint-wide system planning and allocation impacts.

American Municipal Power (AMP) and MISO’s industrial customers said FERC blindly accepted a “crude” cost allocation method that isn’t supported by analysis and will require transmission customers to foot steep bills, even when a project benefits a neighboring RTO. They argued that the commission neglected its duty to independently assess the rate proposal and said MISO failed to devise a more precise allocation when it had the means to do so.

The intervenors said FERC was wrong to characterize the new LRTP cost allocation as essentially the one used for 2011’s Multi-Value Project (MVP) portfolio with only “limited” changes. AMP argued there’s a “fundamental distinction between regional and subregional planning and cost allocation.” The MVP portfolio was allocated systemwide with a postage stamp rate in 2011, when the footprint didn’t extend beyond southern Missouri.   

The industrial customers said that FERC “cannot transfer its duties to the RTO stakeholder process or assume that state regulatory support or majority support in the RTO stakeholder process indicates widespread consumer satisfaction or provides evidentiary support for a just and reasonable rate outcome.”

They also said that the “promise of a more granular cost allocation for future LRTP projects does not justify acceptance of an allocation of over $10 billion in costs that are not sufficiently tied to roughly commensurate project benefits.”

MISO’s first LRTP portfolio alone could raise costs by as much as $2.80/MWh, the customers said.

They also contended that MISO relied on “stale” data to back up its allocation design. The RTO used a Brattle Group analysis that showed the 2011 MVP projects’ benefits were overwhelmingly confined to the Midwest region. The consulting firm said that benefits’ spread will likely continue unless MISO secures more transfer capability between the subregions. (See “Brattle: South Benefits Unlikely from Midwest,” MISO Finalizes Long-range Tx Cost Sharing Plan.)

FERC said that MISO was not required to “re-justify the MVP category from scratch,” nor was it required to “analyze the data from future LRTP portfolios.” The commission pointed out that courts have repeatedly found that a rate should be reasonable, not that it should be “the most reasonable or the best one out of possible alternatives.”

“It is not unduly discriminatory for the [c]ommission to accept a subregional option while MISO continues to discuss with stakeholders a different approach for future projects,” FERC said. “Therefore, arguments concerning future cost allocation method filings are premature.”

The commission said MISO’s LRTP allocation divvies costs on a “basis that is at least roughly commensurate with the estimated benefits” and was the product of “an extensive, multi-year stakeholder process.” It also defended the Brattle analysis, highlighting its “large data set of 16 actual — not just proposed ― projects.”

It said industrial customers’ request to allocate costs to customers outside of MISO is beyond the scope of the order.

In planning meetings, some MISO stakeholders have voiced concerns of disparate treatment between LRTP portfolios, saying a different cost allocation for projects in MISO South will violate FERC’s cost-allocation principle that differing allocations must not be applied to the same class of projects.

Commissioners James Danly and Mark Christie agreed with the order in short concurrences. Danly said although he had misgivings over the postage stamp method in general, he could not say definitively that its use is unfair.