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July 26, 2024

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FERC Orders $66.7M in Penalties and Disgorgement on Linde and NIPSCO

FERC on Jan. 4 ordered Linde Inc. and Northern Indiana Public Service Co. (NIPSCO) to pay a combined $66.7 million in disgorgement and penalties for violating rules related to MISO’s demand response program (IN24-3).

The order approves a consent agreement between Linde and NIPSCO, which requires Linde to pay $48.5 million in disgorgement and $10.5 million in civil penalties and NIPSCO to pay $7.7 million in disgorgement. The order also mandates that Linde complete compliance training to participate in MISO’s markets in the future and outlines steps NIPSCO must take to issue refunds to affected customers.

Linde’s Calumet Area Pipeline Operations Center (CAPOC), located in northwest Indiana and distilling gases such as oxygen and nitrogen for industrial or medical use, was found to have engaged in deceptive practices within MISO’s demand response resource Type 1 (DRR-1) asset program. This resulted in unfair advantages, market price distortions and adverse effects on other market participants and consumers.

MISO operates two demand response programs, including DRR-1, which allows participants to offer load reductions during peak demand periods and receive compensation for reducing their energy use in response to grid needs.

MISO requires DRR-1 participants selling energy to “respond to the transmission provider’s directives to start, shut down or change output levels of resources, in accordance with the terms specified in the offer,” and compensates DRR-1 assets at the LMP for the difference between a unit’s baseline and its actual load.

When MISO accepts DRR-1’s asset load reduction offer, it is called an event day, while other days are called nonevent days. Only on event days are participants expected to actively reduce their load.

Linde was found to have manipulated the DRR-1 program for about five years by artificially inflating its baseline load during nonevent days and then reducing operations during event days, thereby collecting payments based on this discrepancy without changing pre-planned operations when called upon by MISO.

This manipulation created a false impression of significant load reduction at Linde’s CAPOC. In reality, Linde did not reduce its energy or consumption levels. Consequently, Linde was awarded undue payments from MISO, while NIPSCO, which earned an administrative fee equal to 5% of Linde’s DRR-1 revenues because it sponsored Linde’s participation, also received inappropriate payments and was found to be in violation.

The Linde and NIPSCO case mirrors previous incidents in demand response markets.

In October, the Independent Market Monitor for MISO advocated for new rules in the demand response program after uncovering unfair gaming strategies by some market participants. (See IMM Presses MISO for New Rules After DR Market Gaming.)

Similarly, in August, FERC fined Big River Steel, an Arkansas steel mill operator, for its multiyear manipulation of MISO’s demand response programs to obtain undue payments without actual load reduction. (See FERC OKs $21M Settlement in Arkansas Steel Mill’s DR Scheme in MISO.)

FERC’s order not only mandates that Linde and NIPSCO pay their penalties and disgorgement within an unspecified time frame for past violations, but also imposes stringent conditions on Linde for future participation in MISO’s DRR-1 program. Conditions include providing advance notification to MISO of its intentions, demonstrating evidence of compliance training and submitting annual reports on its DRR-1 activities for the next three years.

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ERCOT Faces State’s Insatiable Demand for Energy

ERCOT’s grid survived another hellish summer in 2023, setting a record for peak demand that was 6.6% higher than the mark set the year before, and which itself was 7.1% higher than the previous record, set in 2019.

It didn’t come easy.

The Texas grid operator issued 17 weather watches, voluntary conservation notices or conservation appeals during a summer in which it recorded 193 demand peaks that exceeded the 2022 mark of 80.15 GW. In August, it set its 10th and final record peak of the year at 85.46 GW.

On Sept. 6, ERCOT entered emergency conditions for the first time since the disastrous and deadly February 2021 winter storm. It called a Level 2 EEA when a transmission limit restricting the flow of generation out of South Texas led to a voltage drop. (See ERCOT Voltage Drop Leads to EEA Level 2.)

The event occurred during the evening hours as the sun set, taking solar production with it. ERCOT’s growing reliance on solar power — it produces 12 to 13 GW on sunny days, with a high of 13.9 GW in December — to meet demand has shifted the tightest periods from the afternoon to the evening.

“The whole name of the game right now is how to manage that peak,” CPS Energy CEO Rudy Garza said during a November energy summit. “This was a tough summer, an unprecedented summer, and in spite of the however many events we had where things got tight, we never lost power. You’ve got to give ERCOT some credit.”

The grid operator has been operating under a conservative posture since the 2022 summer. It has been procuring huge quantities of ancillary services to ensure it has enough operating reserves to account for intermittent solar and wind resources.

That has increased costs in the energy-only market. The newest ancillary product, ERCOT contingency reserve service (ECRS), will likely cost between $675 million and $750 million for 2023, despite not being deployed until June. ERCOT’s Independent Market Monitor says ECRS has created artificial supply shortages that produced “massive” inefficient market costs totaling about $12.5 billion last year through Nov. 27.

The Monitor said it has had “encouraging” discussions with ERCOT over changes to its ancillary service methodology. The grid operator has also promised to re-evaluate ECRS and take it back to stakeholders in April or May. (See ERCOT Board of Directors Briefs: Dec. 19, 2023.)

In the meantime, demand for energy continues to increase, fueled by both economic growth and weather. Texas has the eighth-largest economy by GDP in the world ($2.36 trillion), and its lax regulatory environment and cheap labor have attracted much of that business.

That, in turn, has led to a staggering population increase. Texas led all 50 states in job creation over the past 12 months, adding more than 391,000 jobs to a workforce that now numbers a record 15.16 million. The 2.9% growth rate is better than the national average, 1.9%.

After a year that saw the world’s hottest single day on record (July 6); hottest-ever month (July); hottest June, August, September, October and November; and almost assuredly hottest year, scientists expect 2024 to be even warmer. State climatologist John Nielsen-Gammon said Texas experienced some of its warmest months last year, with average temperatures in December about 4 to 5 degrees Fahrenheit above the average temperatures from 1991 to 2020.

Repeating a refrain heard often from the grid operator and state lawmakers since Winter Storm Uri, Dan Woodfin, ERCOT vice president of system operations, said during a resource adequacy conference in September that the answer is more dispatchable generation.

“We need … to cover those timeframes where our tightest timeframe isn’t even in the peak demand time of the day anymore,” Woodfin said. “We’ve got roughly 13 GW of solar online every day. It’s when the sun goes down, and so every day, it becomes an issue of whether the load is going to go down enough, and the wind comes up enough to make up for the solar going down. And it goes down really fast.”

Texas voters in November approved a proposition that creates the Texas Energy Fund, a $7.2 billion low-interest loan program intended to develop up to 10 GW of natural gas plants. ERCOT’s regulatory overseer, the Texas Public Utility Commission, will manage the fund, a result of legislation passed last year. The PUC is staffing up and developing materials and processes before it begins accepting applications in June. (See 2023 Elections Bring Billions for Texas Gas, Dem Wins in Virginia, NJ.)

The pump may have been primed. ERCOT staff told directors in December that generator interconnection requests for about 7.7 GW of gas-fired resources have entered the interconnection queue.

“There’s promise to see that starting to provide an uptick,” said Kristi Hobbs, vice president of system planning and weatherization.

Entering the new year, GI requests received or under study for gas generation stood at 15.5 GW. The vast majority (14.8 GW) were for quick-starting combustion turbine or combined cycle units.

Still, those numbers are dwarfed by energy storage resources and renewables. The ERCOT queue has 127 GW of applications for battery interconnections, 145 GW of solar and 34 GW of wind. Construction costs have dropped for both wind and solar, according to the U.S. Energy Information Administration.

ERCOT CEO Pablo Vegas | © RTO Insider LLC

“Those are record numbers, and we are ready to help manage and facilitate those resources coming through the queue quickly,” ERCOT CEO Pablo Vegas said during the December board meeting. “We prioritize thermal dispatchable generation above intermittent resources. That is a directive that we have received, and we are able to process the dispatchable generators first as they come into the queue in order to prioritize their interconnection process.”

ERCOT also considers batteries a dispatchable resource; it expects to add about 25 GW of battery power in 2024 and more than 40 GW in each of the next two years. Energy storage set a high when it produced 2,172 MW of power during the Sept. 6 event.

The PUC will resume a discussion this year that began in late 2023 regarding requirements for batteries participating in ECRS and non-spinning reserve. Commissioner Jimmy Glotfelty says it is “discriminatory” to set a one-hour state of charge for batteries when coal and gas plants aren’t required to maintain real-time state-of-fuel availability. (See Texas Public Utility Commission Briefs: Nov. 30, 2023.)

At the same time, ERCOT is tracking nearly 40 GW of interconnection requests from large loads like bitcoin miners and data centers, both of which have popped up like mushrooms in recent years. These energy-intensive loads, like many industrial users in ERCOT, are compensated when they shut down during tight times. Riot Platforms raised eyebrows in August when it was awarded $31.7 million in energy credits — about $22 million more than the value of the bitcoin it “mined” that month.

Now, consumer advocates are asking why residential consumers can’t receive the same benefit for participating in demand response programs.

“I still believe, and the ERCOT market still believes, that there is a significant amount of demand response that potentially could be quantified and captured over time,” Vegas said in December. “I think that there’s an opportunity for us to work with the market and with the Public Utility Commission on defining those kinds of products that could be utilized throughout the year, not just during an extreme winter season, but to help with peak-shaving capabilities at any point throughout the year. And so that’s something that we’re going to commit to do in 2024.”

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Cap-and-invest to Loom Large in Wash. Legislative Session

OLYMPIA, Wash. — Washington’s one-year-old cap-and-invest program will be one of the dominant issues during the state’s 2024 legislative session, which begins Jan. 8.

From supporters of the program, which was created by the state’s 2021 Climate Commitment Act, there will be attempts to fine-tune it. Maybe make it more palatable to farmers. Maybe provide some money to the public. Maybe make Washington’s system compatible with that shared by California and Quebec in the hope of reducing gasoline prices.

In addition, Gov. Jay Inslee and Democratic legislative leaders want to copy a page from California and create a new state agency to monitor and regulate the oil industry within Washington to keep a check on prices at the pump.

“We’ve been whipsawed too long by the oil and gas industry, and we need a bill to find out what’s really going on,” Inslee said at a press conference. The Inslee administration has noted that the five biggest oil company made $200 billion in profits in 2022.

And all these efforts will occur against a backdrop of Republican moves to eliminate the entire cap-and-invest program — moves that could dominate the November 2024 election cycle.

Conservative organization Let’s Go Washington in November submitted a petition to the Washington Secretary of State’s Office to eliminate cap-and-invest, blaming it for high gas prices. If the Legislature declines to address it in the upcoming session, the petition will go to a public referendum next November. (See Wash. Cap-and-trade Opponents Advance Repeal Petition to Sec. of State.)

“It will be dead on arrival,” Sen. Joe Nguyen (D), chair of the Senate’s Environment, Energy and Technology Committee, told NetZero Insider. Democrats who support the cap-and-invest program constitute the majority in both the House and Senate.

“Maybe people would rather have a choice [with a November referendum]. The community at large, the people are upset about it,” Rep. Mary Dye (R), ranking minority member of the House Environment and Energy Committee, said in an interview. “[Cap-and-invest] is fundamentally transforming our energy industry with a hockey stick.”

Revoking the cap-and-invest program is one of the few policy planks that leading GOP gubernatorial candidate Dave Reichert has announced so far.

“On DAY ONE as governor, I will pause the taxes that are costing you 50 cents more a gallon for gas and are increasing your utility bill. The current policy is not affordable, and worse, it fails to live up to its promise to protect our environment,” Reichert posted on X (formerly Twitter).

Sen. Mark Mullet (D), a Democratic gubernatorial candidate, has introduced a bill to tweak the cap-and-invest program. “You have to make [the program] more affordable [at the gas pump]. You need to fix it, or voters will overturn it,” he told NetZero Insider.

The state is raising a huge amount of money from cap-and-invest — roughly $1.8 billion so far in its first year — which the Legislature is allocating toward clean energy development and programs that mitigate the impacts of climate change, particularly on disadvantaged communities. The Inslee administration predicts the program will raise an additional $941 million in the first six months of 2024, with most of the money going to climate change mitigation. Inslee wants to use some of that money to create a one-time $200 credit applied to the utility bills of roughly 750,000 low- and moderate-income households in Washington.

Changes Ahead?

Meanwhile, Rep. April Connors (R) has introduced a bill to send any cap-and-invest revenue the Legislature has not appropriated by July 1, 2024, back to state residents as a rebate.

At a Jan. 4 legislative press conference in Olympia, Reps. Timm Ormsby (D) and Chris Corry (R), respectively chair and ranking minority member of the House Appropriations Committee, said some type of rebate could be considered this session.

“There’s a high likelihood that all parts of the Climate Commitment Act will be considered for changes,” Ormsby said. Corry added that a rebate “is a start. It scratches the surface.”

Inslee and Democratic legislative leaders have been taking political flak from critics who blame the state’s high gasoline prices on the cap-and-invest program, due to oil companies passing their auction costs to the pump, which accounts for a 21- to 50-cent increase in gasoline prices depending on how calculations are made. Gas prices in the three West Coast states of Washington, Oregon and California are usually among the highest in the nation for economic and geographic reasons outside of the cap-and-invest program.

The most ambitious proposed legislation in the upcoming session would force oil companies to open their finances to state scrutiny. Inslee and Democratic leaders believe the oil industry has not been upfront about the reasons for Washington’s high gasoline price.

“We would like to see more transparency around oil prices,” Rep. Beth Doglio (D), chair of the House Environment and Energy Committee, said in an interview.

Modeled after a new California office, the bill would create a Division of Petroleum Market Oversight under the umbrella of the Washington Utilities and Transportation Commission.

The proposed office would require fuel suppliers, refinery operations and others in the fuel supply chain to provide the state with details on fuel pricing, profit margins and transaction data. The bill would likely explore establishing fines for collusion, shutting down fuel chain equipment and other forms of market manipulation, officials said in a press briefing on the proposed legislation.

“This is to simply unpack the black box of how oil companies set their prices. … Who’s selling to whom at what volume?” Becky Kelley, Inslee’s climate change policy adviser, said at the briefing.

Nguyen expects the proposed office to collect “thousands of data points” from the oil industry.

Meantime, Mullet has introduced Senate Bill 5783 to help tackle the criticism that high settlement prices for carbon allowances in the cap-and-invest auctions are driving up Washington’s gas prices.

The quarterly settlement prices in 2023 — $48.50 to $63.03 per metric ton of emissions — were much higher than what state experts predicted in 2021. By comparison, California’s settlement auction prices began in in 2012 at $10 per allowance, ending up slightly above $36 per allowance in 2023.

Inslee said a 2021 state forecast predicted lower gasoline price increases — the often-quoted “pennies a gallon” that critics are using against the governor — because analysts expected allowance auction prices to be similar to California’s when that sate began its program in 2012.

“They did their best job trying to predict what was going to happen,” Inslee said.

A reason for California’s lower auction prices is that Washington is trimming carbon emissions at roughly twice the rate as the Golden State over the next decade, before flattening out, according to observers. That translates into Washington having fewer allowances to auction off than California, driving up prices in the Evergreen State.

Mullet’s bill would address this issue by flattening out the 2021 law’s steep decline in carbon emissions over the next several years to mimic the smaller California emissions shrinkages. The bill would also shift some future allowance allocations to nearer years. Mullet said this would lead to lower auction prices because more allowances would become available.

Mullet said his bill would mean Washington would miss its 2030 goal of reduced CO2 emission to 50 million tons, but would still meet the 2050 goal of 5 million tons.

“We get to the same end goal, but do it more gradually,” Mullet said.

Mullet’s bill would also use some cap-and-invest revenue to trim Washington’s vehicle license plate prices.

At the Dec. 4 press conference, Inslee said he opposes Mullet’s bill because it would allow for more emissions in Washington in the near future. “We don’t need more Washingtonians losing their lives because of pollution,” Inslee said.

System Merger

In a move supported by Inslee, Washington Democrats plan to introduce a bill that will allow the state to mesh its cap-and-invest program with the one shared by California and Quebec.

State officials want to join the more established cap-and-trade system with the expectation that a bigger market will keep allowance — and gasoline — prices down. But to do that, the three jurisdictions must share cap-and-trade rules, which will require negotiations. (See Wash. Looks to Join California-Quebec Cap-and-Trade Market.)

A preliminary analysis by the Washington Department of Ecology in October concluded the proposed linkage would likely improve the cap-and-invest program’s economic durability, longevity and efficacy. “In a larger, more liquid market with a greater number of participants, allowance prices would likely be lower and change more predictably. Predictable prices can foster greater investments in decarbonization,” the report said.

However, Dye argues it would be premature for Washington to merge its system, saying the state needs to fix the bugs in its own program first. And she is leery about the state’s predictions of lower auction and gas prices. “These guys don’t have a good track record on being Nostradamus on the effects of their policies,” Dye said.

‘Complex Path’

Meanwhile, some legislators are worried that farmers are paying cap-and-invest costs from which they should be legally exempt. Dye said the Republicans are planning to introduce a bill to address those concerns.

Fuel suppliers fall under Washington’s laws to trim carbon emissions, and some are bidding on cap-and-invest allowances. They are not supposed to pass these costs on to farmers, but they have done so in some cases.

One basic problem is that gasoline and diesel move through a tangled web of middlemen before they reach farmers.

“We know fuel moves through a complex path from refinery to pump,” said Joel Creswell, climate pollution reduction program manager for the Washington Department of Ecology.

“Small operations just aren’t aware of how to navigate [the cap-and-invest system] to get exempt prices,” Ben Buchholz, a lobbyist for the Northwest Agricultural Cooperative Council, said during a Nov. 30 briefing of the Washington Senate Agriculture, Water, Natural Resources and Parks Committee.

Another problem is fuzziness on the definition of an agricultural product.

“If you dry a product, you qualify [for the cap-and-invest exemption]. If you dehydrate a product, you don’t,” Bre Elsey, a lobbyist for the Washington State Farm Bureau, told the committee. Buchholz added that fuel is exempt in a farm truck carrying cows to market, but that the same truck carrying wastes from French fry production for livestock feed is not exempt because that waste is a manufactured product.

Little Money for Ferries

Finally, with Washington’s ferry system suffering multiple breakdowns in its fleet of old diesel vessels, a budget proposal by Inslee and a bill (HB 1904) by Rep. Jim Walsh (R) both propose using cap-and-invest income to pay to build at least one new hybrid electric-diesel ferry.

Sen. Marko Liias (D), chair of the Senate Transportation Committee, said it is unlikely the excess cap-and-invest revenue will be used to speed up Washington’s transition to hybrid electric-diesel ferries beyond the one eyed by Inslee and Connors, which would be finished by 2027.

“I’d love to promise we’d get boats faster, but we have to be realistic,” Liias said.

At the press briefing Jan. 4, Liias and other legislative leaders said factors hampering the construction of hybrid ferries include the need for more shipyards, extra design work and difficulty hiring enough qualified new crew members — as well as other budget priorities.

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Sweeping Reset Underway for NY Renewable Development

Dozens of contracts for New York renewable energy projects totaling more than 8 GW of capacity have been canceled as developers scramble to exit unprofitable deals and rebid at higher cost to ratepayers.

The trade association representing renewable energy developers in New York, ACE NY, said Jan. 4 that 73 land-based projects with a combined 6,784 MW nameplate capacity had canceled or rejected contracts with the state in recent weeks.

A day later, the New York State Energy Research and Development Authority (NYSERDA) placed the total slightly higher: 79 projects.

Mass cancellations had been expected. The question was how many projects would pull out of New York’s pipeline and how many would attempt to bid back in at higher cost.

In June, developers of 86 land-based and four offshore projects totaling more than 12 GW told the state they could not begin construction without increased compensation because their costs had skyrocketed as they worked through the yearslong permitting and review processes.

The state Public Service Commission in October rejected their petition. (See NY Rejects Inflation Adjustment for Renewable Projects.)

Since then, NYSERDA — which had endorsed the projects’ request for more money — has been scrambling to perform damage control.

It has launched expedited onshore and offshore renewable solicitations and is allowing developers with existing contracts to rebid those projects into the new solicitations. (See New York Issues Expedited Renewable Energy Solicitations.) But they must cancel their existing contracts before rebidding.

A NYSERDA spokesperson said Jan. 5 that cancellation of contracts does not mean cancellation of projects: “While the developers of these projects may have terminated their contracts with NYSERDA, most continue to develop the projects and are expected to seek new agreements in current and future NYSERDA solicitations. NYSERDA remains optimistic that many projects with recently canceled awards and terminated contracts will bid into the open solicitation, ensuring New York consumers are getting the best deal and the state can continue apace towards reaching its nation-leading Climate Act goals.” Bid proposals are due Jan. 31, with awards expected in April.

Along with the onshore projects, plans for New York offshore wind farms totaling 4,230 MW are in danger.

The offshore wind sector has been particularly hard-hit by inflation and interest rate hikes, with contract or project cancellations in Connecticut, Massachusetts and New Jersey in 2023.

On Jan. 3, developers announced cancellation of the single largest renewable project under state contract — the 1,260 MW Empire Wind 2. They hinted but did not confirm they would seek to rebid the proposed wind farm into the expedited offshore solicitation now underway. (See Empire Wind 2 Cancels OSW Agreement with New York.)

Empire Wind and the 73 onshore projects cited by ACE NY total 8,044 MW. They are a critical portion of the portfolio the state is counting on to meet its legally mandated goal of 70% renewable energy by 2030.

For comparison’s sake, New York’s late-2023 contract announcement — which leaders called the largest-ever investment in renewable energy by a state — totaled 6,400 MW. (See NY Announces Renewable Energy Projects Totaling 6.4 GW.) And those were provisional contracts subject to negotiation, not final awards.

Specific details for the 252 large-scale renewable projects reported by NYSERDA from 2004 to Dec. 21, 2023, are listed on the state’s open-data portal: Fifty-six projects with a combined 4,250 MW capacity are listed as “canceled”; 51 rated at 4,376 MW are “canceled, subject to providing replacement contract security”; 65 rated at 1,817 MW are “completed”; 44 rated at 1,034 MW are “operational”; and 36 rated at 6,868 MW are “under development.”

The database does not reflect the most recent changes, however: Empire Wind 2 and its 1,260 MW still are listed as “under development.”

The developments tie in neatly with the timetable by which many policy and spending decisions are made in New York state.

Gov. Kathy Hochul (D) has begun to preview her priorities for the coming legislative season and will deliver more details Jan. 9 in her State of the State address. She and legislative leaders will bake these priorities into their budget proposals, and advocates and lobbyists of all stripes will fight for and against each one as a final budget is negotiated.

The Alliance for Clean Energy New York will be out front on energy issues. On Jan. 4, the trade and advocacy association presented its priorities for the legislative session as it reported the 73 contract cancellations.

“The clear priority for 2024 is for New York to award new contracts for wind and solar projects to replace those that were just canceled due to inflation,” ACE NY Executive Director Anne Reynolds said in a news release. “This market reset is critical for a re-start of renewable energy progress; to avoid the permanent cancellation of 73 projects; and to make progress towards our climate goals.”

The major legislative priority, she added, will be passage of the Omnibus Renewable Energy Progress Act.

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Stakeholders Propose Amendments to ISO-NE Order 2023 Compliance

Clean energy companies and trade groups proposed a series of amendments to ISO-NE’s proposed Order 2023 compliance at the NEPOOL Transmission Committee meeting Jan. 4, as the RTO and its stakeholders scramble to reach a consensus prior to the scheduled TC vote in February.

The compliance filing is set to bring sweeping interconnection changes as ISO-NE switches from a first-come, first-served queue to a process in which interconnection requests are studied simultaneously in large clusters.

ISO-NE discussed the initial details of its compliance over several TC meetings throughout the fall and presented the detailed tariff changes of its compliance proposal to the TC in December. (See ISO-NE Details Order 2023 Tariff Changes.)

The RTO has proposed several deviations from the specific approach detailed in FERC’s order, including a 270-day cluster study timeline, compared to FERC’s 150-day timeline. Advanced Energy United, a clean energy trade group, called for ISO-NE to stick to FERC’s timeline.

Alex Lawton of United said a significant extension of the study timeline could undermine the order’s goal of reducing interconnection delays and could cause future uncertainty if FERC ultimately rejects this request.

“Recognizing there are challenges and constraints in conducting cluster studies, we are concerned the filing will be rejected and interconnection study timelines will not be significantly improved without a 150 days requirement,” Lawton said. “Submitting the 270 days proposal therefore introduces significant regulatory risk.”

For the initial transitional cluster study process, the clean energy association RENEW Northeast proposed to add a customer engagement window within the existing time frame. While later clusters will have a customer engagement window at the beginning of the process for questions and feedback between interconnection customers and the RTO, ISO-NE’s current proposal does not include this opportunity in the initial cluster study.

“Without sufficient information about potential members of the transitional cluster or the ability to ask the ISO or interconnection transmission owners questions about a proposed interconnection, customers are asked to decide whether to enter the transitional cluster with incomplete information,” said Abby Krich on behalf of RENEW.

United, with the support of New Leaf Energy, also proposed to reduce the transitional cluster’s large generator commercial readiness deposits (CRDs) from $5 million to $2.25 million. CRDs are intended to prevent speculative projects from entering the cluster.

ISO-NE has smaller average project sizes compared to RTOs like PJM and MISO, Lawton said, adding that the $5 million deposit “disproportionately impacts commercially ready smaller projects that may be comparably mature.”

Lawton called the $5 million CRD “far less appropriate for ISO-NE, which has smaller projects and relatively less of a queue backlog.”

Meanwhile, Glenvale Solar advocated for reduced CRDs that are scaled to project size for the cluster studies that follow the initial transitional cluster.

“It is especially critical to manage costs for smaller generators (including smaller LGIRs) to ensure project development costs are as rational as possible” said Aidan Foley of Glenvale. “This will ensure the maximum number of generators reach the market.”

Foley said keeping deposits as low as possible “will maintain relative competitiveness with other RTOs where ICs parent companies are active. This will ensure that project sponsors find New England a compelling geography to direct investments to.”

Glenvale also proposed a reduction in deposits for projects that do not increase the generation capacity at a given site, such as repowering or adding batteries to a site.

Regarding withdrawal penalties in the transitional cluster, Glenvale is supporting New Leaf’s proposal to calculate the penalties based on costs incurred only during the transitional cluster, instead of based on a project’s total study costs since the project entered the queue.

Alex Chaplin of New Leaf said ISO-NE’s current proposal would unfairly increase withdrawal penalties for projects that already have included study costs associated with incomplete interconnection studies prior to the transitional cluster.

“This leads to similarly situated projects being subject to significantly different withdrawal penalties,” Chaplin said.

Meanwhile, RENEW proposed to exempt interconnection customers from withdrawal penalties if their decision to enter the cluster study was based on incorrect or misleading information provided at the beginning of the process.

“When this happens today, the interconnection customer must deal with the variety of consequences, but is not charged a withdrawal penalty,” RENEW wrote in a December memo. “With the introduction of a withdrawal penalty, it is appropriate to create an exception for this to protect everyone in the process.”

RENEW also proposed several amendments related to the distinctions between resources that request energy-only interconnection and resources that request both capacity and energy interconnection service. The trade group said interconnection customers should have the option to “downgrade” their request to energy-only interconnection based on study results.

Without this option, “the ISO proposal would prevent otherwise-viable energy-only projects from moving forward to commercial operation on a timely basis, result in additional withdrawals, reallocation of costs and further withdrawals,” Krich told the TC.

RENEW also proposed that ISO-NE differentiate between energy and capacity costs incurred in cluster studies. Grouping these costs together would burden energy-only interconnection customers with “a portion of the cost of identifying incremental upgrades required for the [capacity network resource interconnection service] requests, from which they do not benefit in any way,” RENEW wrote in the memo.

The TC will meet again Jan. 23 as it prepares for a vote on the compliance proposal in February.

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Federalist Society Examines the Changing Politics of Power Markets

Economic deregulation started out as a Republican policy, but GOP appointees to FERC have been questioning how it has been applied to the electric industry, a trend that was explored Jan. 5 at the 25th Annual Federalist Society Faculty Conference in D.C.

James Coleman, a professor at the Southern Methodist University Dedman School of Law, noted that former Commissioner Bernard McNamee has said marginal price auctions for energy are not ensuring reliability and that former Commissioner James Danly has said the markets are not a statutory requirement and that vertically integrated states have cheaper prices.

FERC Commissioner Mark Christie has not gone as far in his criticisms, but he has argued in the Energy Law Journal that it is time to examine whether the basic RTO market model is the best way forward, Coleman said. (See FERC’s Christie Calls for Reassessment of Single Clearing Price.)

“In some ways, it’s not so different from the traditional critique that we’ve seen from progressives of the use of electricity markets in providing electricity, which is they have been concerned that those electricity markets give short shrift to some of the important concerns other than price,” Coleman said.

Critiques from the left have focused on how the markets favor prices over environmental impacts, especially climate change, but the emerging criticism from the right is focused on how markets are impacted by a growing share of subsidized renewable power, Coleman said.

“In both the case of progressive critiques, and in the case of these increasing conservative critiques, the real concern is less about the use of markets, but more about what kinds of regulations we’re using to drive the kind of preferred energy sources,” he added.

One conservative critique is that the markets are focused on short-term costs and thus have no long-term vision, said Ari Peskoe, director of Harvard Law School’s Electricity Law Initiative. That led to the Trump administration trying to stem the shift from coal and nuclear to natural gas with a proposal that would have paid such baseload power plants outside of the ISO/RTO markets, effectively ending them.

“To maintain reliability, Scott Pruitt, who was then the head of EPA, went on TV and claimed that we needed to have 30% coal in our electricity mix, because, for the first time, coal was suddenly dropping below this marker,” Peskoe said. “And, so, he fabricated this number that was necessary to keep the system reliable.”

The so-called Grid Resiliency Pricing Rule, proposed by the Department of Energy, was rejected by FERC. Peskoe noted that the only utility to publicly support the rule was FirstEnergy, which was later found to be bribing Ohio officials for favorable treatment of its coal and nuclear plants in a massive corruption scandal.

Texas went further with restructuring than any other market, including on the retail side, and the devastating blackouts it experienced from Winter Storm Uri in February 2021 led to additional arguments against markets’ ability to maintain reliability.

“Texas is sort of vaunted as a purely competitive power market. It presents an interesting experiment, because there are actually a handful of remaining utility monopolies within the Texas ERCOT footprint that have no consumer choice, and which own their own fleet of power generation,” NRG Energy Vice President of Regulatory Affairs Travis Kavulla said. “And those power plants make their revenue by recourse to this captive base of ratepayers.”

Those traditionally regulated firms had poorer performance among their fossil fuel-fired power plants than did the competitive firms such as NRG, he added. The competitive market also was unable to pass along the huge costs from the storm, whereas Kavulla cited one gas utility in Oklahoma that is charging its customers $7/month for several decades to cover its costs from a week’s worth of natural gas.

The market felt major impacts from the storm, with Kavulla citing one NRG trader who had a retail deal exposed to wholesale prices and wound up spending $55 to boil a pot of water for tea that week. But instead of passing the costs along to customers for the next 20 years, NRG lost about $1 billion purchasing replacement power.

Uri also exposed issues with the side of the industry that has never seen any kind of deregulation — the distribution system — and how to implement rolling blackouts, Peskoe said. Utilities were not aware of vital natural gas infrastructure that needed power to keep operating, so when they cut off electricity to such sites, they only made the gas shortage worse, he added.

Winter Storm Elliott in late 2022 also showed that vertically integrated states can have some of the same issues, he said.

“It comes back to standards, sort of more traditional forms of regulation, because this is an essential good that people need,” Peskoe said. “And so, market or nonmarket is only sort of part of the debate; we have to have all this stuff happening to support the market or non-market and make sure that that all runs smoothly.”

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Citing California Law, FERC Rejects PG&E Request for RTO Adder

FERC on Dec. 29 rejected Pacific Gas and Electric’s request for an adder to its transmission rates based on its participation in CAISO, finding that California law precludes the utility from leaving the ISO without the state’s permission (ER24-96).

The rejection was part of a broader decision in which the commission partly accepted PG&E’s proposed revised formula rate and transmission recovery requirement (TRR), while also subjecting them to settlement judge procedures in light of protests from the utility’s transmission customers.

PG&E had proposed a base return on equity of 12.37%, which it said reflects its current financial situation and uncertainties and risks resulting from wildfires and California’s “inverse condemnation” law, which holds the state’s utilities responsible for damages caused by their equipment even in the absence of demonstrating negligence.

The utility said the base ROE fell within a “zone of reasonableness” ranging from 8.02 to 13.24% and contended that it deserved to be compensated at the higher end because of the risks it faces. On top of that, it also requested an adder of 50 basis points for participating in CAISO — for a total ROE of 12.87%.

Disputes around whether to allow California investor-owned utilities to recover an incentive for participating in the ISO have been ongoing. The commission in 2020 rejected the California Public Utilities Commission’s argument that PG&E was ineligible for the RTO adder — meant to incentivize utilities to join RTOs — because participation in CAISO was mandatory. FERC ruled that, based on California law, the utility’s participation in the ISO was voluntary and that it could unilaterally decide to leave. (See FERC Rejects RTO Incentive Adder Rehearing.)

But in September 2022, California amended its public utilities code to mandate that electric utilities join and remain members of CAISO, able to leave only with the CPUC’s approval.

The utility argued that because “California law expressly provides PG&E an opportunity to withdraw, subject to CPUC approval,” ISO participation is not strictly mandatory.

“We are not persuaded by PG&E’s arguments that there is a disputed factual issue about whether PG&E’s ongoing participation in CAISO is voluntary and that the commission should therefore set this matter for hearing and settlement judge procedures,” FERC said. “We find that, by virtue of the recently enacted California statute, PG&E is required to participate in CAISO and cannot unilaterally withdraw from CAISO. As such, PG&E’s participation in CAISO is no longer voluntary. Thus, we find that PG&E is no longer eligible for the RTO adder.”

FERC noted that the CPUC estimated the adder would have been worth $41.38 million annually.

Along with asking FERC to reject the RTO adder, several stakeholders also protested other aspects of PG&E’s proposed formula rate and TRR, contending the utility relied on an “inappropriately selected” proxy group for ROE comparatives, included an “expected earnings” analysis that is not part of FERC’s existing methodology and drew incorrect conclusions about its own risk position.

Among the complaints by protesters, two power agencies questioned PG&E’s accounting of its wildfire costs and the reasonableness of its proposed wildfire self-insurance program. Others contested the utility’s proposed 3.29% depreciation rate as being excessive, saying it was an unjustifiable increase from the presently authorized rate of 2.86%.

Having rejected the RTO adder, the commission said its preliminary analysis indicated that other aspects of PG&E’s requested formula rate and TRR might not meet FERC’s just-and-reasonable standard.

“We find that PG&E’s filing raises issues of material fact that, to the extent not summarily disposed of here, cannot be resolved based on the record before us and that are more appropriately addressed in the hearing and settlement judge procedures,” the commission wrote.

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Conditions Finally Reverted to (Somewhat) Normal for SPP in 2023

During SPP’s quarterly board meeting in October, CEO Barbara Sugg reflected on her tenure, which began shortly before the COVID-19 pandemic shut down the world in 2020.

“It is nice that after three and a half years as the CEO, we’re not talking about the pandemic anymore,” she told directors and stakeholders. “And we haven’t had a recent 100-year storm [in 2023].”

True. While the past year did not include a winter storm like those in February 2021 (Uri) and December 2022 (Elliott), it did include record-breaking heat during the summer that taxed the SPP system.

The grid operator broke the previous all-time peak several times before finally registering a record of 56.2 GW in August, a month during which it issued six conservative operations advisories for its footprint. Capacity dropped to ‑200 MW at one point during the summer, second only to the losses the RTO suffered during Winter Storm Uri. Imports from neighbors saved SPP both times.

“The summer was particularly challenging for us. It really tested our operators and your system operators as well,” Sugg told stakeholders. “The summer peak was 5% higher than the last summer, which was 5% higher than the summer before, which is incredible.”

Sugg said she is particularly concerned about the growth in demand and the variability of renewable resources. She pointed to a day in June when wind and solar resources produced only 111 MW at one point.

“That helps us really think about what we need to do to maintain reliability in the volatile climate,” she said. “The operating conditions certainly highlight the importance of maintaining the generation fleet and getting accreditation right for both conventional and renewable resources, and getting that to be as accurate as it can be.”

To that end, SPP created the Resource and Energy Adequacy Leadership (REAL) Team to mitigate resource adequacy risks and develop policies on fuel assurance, demand response and accreditation. The team — a cooperative effort between the Board of Directors, state regulators and stakeholders — has already signed off on performance-based accreditation for conventional resources and effective load-carrying capability accreditation for wind, solar and storage resources.

The REAL Team is waiting on the biennial loss-of-load expectation study to be finalized this spring. The study will fuel the effort to deliver winter and summer planning reserve margins to the team and to the July governance meetings.

FERC added to the REAL Team’s workload in November when it rejected SPP’s proposed winter resource adequacy requirement. However, the commission said the RTO can address FERC’s concerns and resubmit the proposal (ER23-2781). (See ‘Therapy Session’: SPP REAL Team Reviews Draft LOLE Study.)

Coming on the heels of Winter Storm Elliott, SPP set as its first goal improving grid resilience to prepare for extreme weather events. Staff have included winter scenarios in its 2024 and 2025 transmission plans and completed numerous recommendations from its review of the recent winter storms.

Another major priority for SPP has been improving a generator interconnection queue that contains more than 500 projects and more than 100 GW of capacity. Sugg said the RTO is still on track to meet its stated goal of clearing the original GI backlog and the 2022 cluster by the end of this year, having processed 93 GI agreements last year. Staff processed 37 agreements in 2022.

“I’m actually extremely optimistic about how far we will get with the ’22 and ’23 clusters … which is a far cry from where we were years ago when you were looking at four or five years to get answers on your generator interconnection requests,” Sugg said.

SPP also celebrated a $464 million grant from the Department of Energy to help fund its joint targeted interconnection queue projects with MISO. The portfolio and its five high-voltage transmission lines, recently revised to cost $1.86 billion, were one of several grid resilience and improvement projects to be awarded DOE funding from the Infrastructure Investment and Jobs Act. (See DOE Announces $3.46B for Grid Resilience, Improvement Projects.)

But that’s just SPP’s Eastern Interconnection footprint. Out West, where the grid operator is involved in several reliability and market initiatives, it received commitments from nine utilities that want to join its RTO West when it goes live in 2026. They are now obligated to reimburse the RTO for development expenses if membership agreements are not executed in March 2026.

In November, SPP began operating the Western Resource Adequacy Program (WRAP) on behalf of the Western Power Pool. The WRAP’s operations program produces seasonal forecasts to help determine whether participants have sufficient resources, and it enables anyone with a deficit to secure additional resources.

Western stakeholders and staff are well into the first developmental phase of Markets+, an RTO-light bundle of day-ahead and real-time market services. As 2023 wound down, stakeholders endorsed, and the Markets+ leadership approved, the market’s governance plan, helping clear much of the road to filing a tariff at FERC in February. (See IMIP Approves SPP Markets+ Governance Tariff Language.)

SPP’s Western Energy Imbalance Service added three Colorado utilities in April, expanding the reliability coordination market from 4.5 GW to 13.5 GW. The real-time balancing market, operational since 2019, provided an estimated $31.7 million in net benefits to its 12 participating utilities in 2022 at a benefit-to-cost ratio of 7-to-1, according to SPP analysis. The RTO said this resulted in reduced wholesale electricity costs by an average of $1.35/MWh over the year.

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Western Transmission Initiatives Differ on Dealing with Cost Allocation

The backers of two separate initiatives to spur development of new transmission in the West are taking different approaches on when to deal with the issue of who should pay for projects.

The Western Transmission Expansion Coalition (WTEC), launched by the Western Power Pool (WPP) and backed largely by the power sector, wants discussions about cost allocation to be put on the back burner while industry stakeholders first figure out what should be built.

But the Western States Transmission Initiative (WSTI), established by state regulators, thinks cost allocation must be addressed before serious planning can begin. (See In West, Proposals for Tx Planning Proliferate Faster than New Lines.)

WPP CEO Sarah Edmonds said WTEC efforts “aren’t touching cost allocation”; the subject is outside the intended scope of the effort, which is designed to expand the geographical scope of transmission planning to include all the West. “We aren’t part of a cost allocation federal tariff,” she noted during a Dec. 11 meeting of the CAISO Western Energy Imbalance Market’s Regional Issues Forum (RIF).

“Cost allocation is kind of one of those things that has really chilled conversation in the West around transmission planning. If we took that off the table for the WTEC effort, what might we find in terms of creative ideas?” Edmonds said.

While acknowledging the conundrum around the matter, Matthew Tisdale — executive director of decarbonization nonprofit Gridworks, which is partnering with the Committee on Regional Electric Power Cooperation on the WSTI — sees a problem with that approach.

“I think that planning and cost allocation are sort of a chicken and an egg here,” Tisdale said at the RIF meeting. “It’s hard to do the planning without understanding what is going to be the approach to cost allocation, and it’s difficult to do the cost allocation without knowing what you’re planning for.”

Both initiatives have set the stage for conversations about who will incur the costs and reap the benefits of much needed transmission projects in the West.

A key goal of WSTI is to form a Transmission Working Group that would, among several tasks, advance the discussion on transmission cost allocation. The states, Tisdale said, will be leading the conversation and coordination around how the cost of interregional transmission could be allocated across state lines.

‘Taking the Bull by the Horns’

While Tisdale, Edmonds and CAISO officials at the meeting agreed that states should be the entities to determine cost allocation for transmission projects, some stakeholders expressed concern about the challenges of that approach for allocating costs across state lines.

Matt Lecar, principal at Pacific Gas and Electric, highlighted complexities surrounding different regulatory requirements; for example, California could agree on a cost allocation framework not matched by entities elsewhere in the region.

“I get that having the states buy in on a cost allocation framework brings down the risk barrier, but what’s going to convince me that the billion dollars or more that I spend on constructing and bringing online a project is going to lead to a successful cost recovery via a mix of jurisdictions that may or may not see eye-to-eye on whether those costs were prudently incurred?” Lecar said.

“Discussions around ratepayer recovery of transmission facilities have been challenging under [FERC] Order 1000, and we need to have the cost allocation conversation,” said Danielle Osborn Mills, director of market policy development at CAISO. “In the meantime, we’re trying to think creatively around how we can have bilateral arrangements that lead to shared benefits across the region and also appropriately shared costs.”

Michele Beck, director of the Utah Office of Consumer Services, emphasized the need for greater coordination among consumer advocates, regulators and transmission planners. She expressed concern that while the WSTI interviewed more than 40 stakeholders, consumer advocates were not included.

Beck also noted that while the WSTI has signaled it will include public interest organizations in a Western transmission conference it intends to host, consumer advocates were again left out.

“We’re very cautious about an emphasis on cost allocation and moving forward on that, especially when we may or may not be at the table,” Beck said. “In our view, sometimes that can be a euphemism for finding a way to get more people to pay for projects … that might be desired only by a subset of the folks involved.”

While there was some disagreement on how costs should be allocated, energy officials seemed to agree upon the struggle to find a better option.

“The states leading on cost allocation is probably the worst forum for developing cost allocation — except for all the other ones, because all the other ones haven’t worked for 20 years either, and so we want to see some leadership in the region,” Tisdale said. “We want to see somebody taking the bull by the horns and raising hard questions.”

A public webinar regarding the WTEC project is scheduled for Jan. 29.

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DOE Lays out Plans for Designating Transmission Corridors

The Department of Energy plans to release a list of potential National Interest Electric Transmission Corridors (NIETCs) this spring.

DOE has already released a transmission needs study looking at where new projects could be beneficial around the country, and it released a related guidance document last month. (See DOE to Sign Up as Off-taker for 3 Transmission Projects.)

“This guidance improves upon previous NIETC designation processes in response to both court decisions and updates to our authority in recent legislation,” Grid Deployment Office (GDO) Director Maria Robinson said during a webinar Jan. 3. “Specifically, I’ll note that the proposed process would designate narrow geographic areas as NIETCs, rather than large swaths of land.”

The department is taking public comment on that guidance, which is due Feb. 2, and it plans to release a list of NIETCs that it will continue to study 60 days after that.

“This list will provide the preliminary geographic boundaries of potential NIETCs, which we expect to be sort of a rough approximation,” said Gretchen Kershaw, GDO senior adviser for transmission.

The lists will also include preliminary assessment of transmission needs within the relevant area and any harms to consumers, essentially explaining the threshold need determination made in phase 1, she added.

The transmission needs study identified a need for interregional transfer capacity around the country, but Kershaw said DOE’s process would favor lines with multiple benefits in addition to increasing the ability to ship power between regions.

The list will provide high-level explanations of why potential NIETCs moved to phase 2 of the designation process, and any that did not will continue to be eligible in future designations. Stakeholders will have an additional 45 days to provide comment on those in phase 2. DOE will look to refine the NIETCs’ geographic scope and start to consider environmental assessments.

DOE will further narrow down the list and then formally propose the NIETCs in phases 3 and 4. The department is unsure of the timeline for that because of how long environmental reviews can take, Kershaw said. A standard environmental impact statement takes the department about two years to produce, she added.

The department does not plan to propose massive corridors, as it did the last time it designated a pair of NIETCs in 2007, Kershaw said. In a process that was ultimately stymied by the courts, the department picked one route that covered Southern California and parts of Arizona and another that covered much of the mid-Atlantic into New York City — both designed to ship cheap power into the two biggest cities in the U.S.

“It concentrates stakeholder attention on where new transmission is most likely to be built within a NIETC by having that narrower scope,” Kershaw said. “The narrower geographic areas also lead to more efficient preparation by DOE of environmental documents again focused on a narrower area, and also more useful environmental documents for permitting agencies including FERC.”

The Infrastructure Investment and Jobs Act granted FERC the authority to approve new transmission in the corridors when states either lack authority to site a project (if they cannot consider regional benefits, for example), have not acted on an application after a year or have denied an application for a line.

FERC is reviewing its own authority under the NIETC process with a Notice of Proposed Rulemaking (RM22-7). (See FERC Backstop Siting Proposal Runs into Opposition from States.)

Some projects will use that authority from FERC under Federal Power Act Section 216b, but for those that do not, DOE can help coordinate all federal authorizations and environmental reviews under Section 216h of the law, Kershaw said.