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November 16, 2024

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DC Circuit Rejects Appeal of SPP Zonal Criteria

The D.C. Circuit Court of Appeals on Tuesday denied a petition to review FERC’s approval of SPP’s tariff revisions setting up a uniform planning criteria in each transmission zone to evaluate zonal reliability upgrades.

The court said Evergy Kansas Central, GridLiance High Plains and Oklahoma Gas & Electric “oversell” the risk that the proposal “will foist the costs of new projects on individual owners” (22-1252).

“In any case, FERC may balance the need to ensure that transmission owners bear perfectly proportional costs and benefits with other policy goals,” said Circuit Judge Justin Walker, writing for a three-judge panel. “It did that here by approving a regime that allows participants in regional transmission zones to collaborate on selecting and funding new projects.”

FERC last year approved SPP’s second attempt to establish an annual process allowing each pricing zone to develop uniform planning criteria. The commission affirmed its decision in October when it rejected rehearing requests from Evergy, OG&E, GridLiance and ITC Great Plains. (See FERC Affirms SPP’s Zonal Planning Criteria.)

Evergy, GridLiance and OG&E appealed to the D.C. Circuit, saying FERC approved an unjust and unreasonable change to SPP’s transmission-funding regime. They claimed the methodology would likely force TOs to pay for projects that benefit the entire RTO.

Under a two-step voting process, each zone’s customers vote on the criteria, with approval determined by a percentage of votes greater than or equal to the largest customer’s load plus half of the zone’s remaining load. In the second step, all the zone’s transmission customers and TOs vote, with a simple majority needed for approval.

The petitioners said a backup plan that allows any TO in the zone to create its own local planning criteria and build a project — though it would have to foot the bill — violated the cost-causation principle that generally prohibits FERC from “singl[ing] out a party for the full cost of a project, or even most of it, when the benefits of the project are diffuse.”

The court said that rule “is not rigid” and found that, according to Consolidated Edison Co. v. FERC, the commission “may permissibly approve a rate that does not perfectly track cost causation,” particularly if it is balancing competing goals.

“That is what FERC did here. [SPP]’s old funding regime let transmission owners unilaterally thrust the costs of new transmission facilities onto customers — whether it benefited them or not,” the court said. “When FERC approved [SPP’s] new proposal, it balanced the benefit of eliminating that unfairness against the risk that transmission owners might pay for some upgrades alone.”

It said balancing competing policy goals on a ratemaking matter is left to FERC’s “considered judgment.”

The court also denied five additional challenges to FERC’s order, saying, “None persuades.”

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BPA Keeps Rates Flat, Plans $2B in Grid Upgrades

The Bonneville Power Administration said Friday it would keep its power and transmission rates flat for the next two years, even as it pursues a $2 billion grid modernization effort.

“BPA will hold the average Tier 1 power rate and all transmission rates, including ancillary and control area service rates, flat for the next two-year period beginning Oct. 1, 2023,” it said in a news release. “This determination was part of the final record of decision for the BP-24 power and transmission rate case released today.”

The BP-24 rate case reflected a settlement between BPA and most of the rate case parties in a proceeding that began in November.

“The great collaboration with our customers and other rate case parties helped us to offer rates that are stable, predictable and low while preserving BPA’s strong financial health,” Administrator John Hairston said in Friday’s statement.

Tribal governments and environmental groups continued to object to the settlement agreement, saying it insufficiently funds efforts to increase salmon and steelhead runs and protect the tribes’ fishing rights in the Columbia River watershed.

“BPA’s BP-24 Rate Proposal takes steps to defund fish and wildlife protection, mitigation and enhancement, affording neither equitable treatment nor consistency,” to bolster fish populations, the Confederated Tribes and Bands of the Yakama Nation and the Confederated Tribes of the Umatilla Indian Reservation argued in their initial brief.

“The BPA Administrator should reject the BP-24 Rate Proposal and significantly increase fish and wildlife funding in the BP-24 rate calculation to ensure sufficient progress towards measurable increases in adult salmon and steelhead returns in the coming years,” the brief said.

But Hairston said in the news release that “BPA is well positioned to meet our customers’ needs across our service territory, including reinforcement of our existing grid and new infrastructure to meet anticipated load growth and the further proliferation of renewable resources coming into the region.”

On July 13, BPA said it was “moving forward with more than $2 billion in multiple transmission substation and line projects necessary to reinforce the grid. These projects are intended to increase capacity and accommodate regional growth, as well as an abundance of new, clean energy resources.”

Six of the projects will “reinforce existing major BPA transmission lines that run from east to west, allowing the flow of energy from the east side of the region to load centers such as the Puget Sound area and Portland,” it said. Projects in Central Oregon, “where utilities are experiencing significant growth and are attracting large commercial customers,” include a new transmission line and substations, with an estimated cost of $839 million.

BPA said grid modernization helps it participate in CAISO’s Western Energy Imbalance Market, which it joined last year. It is also participating in the development of CAISO’s proposed extended day-ahead market for the real-time WEIM and in SPP’s development of its planned Markets+ offering in the West, which includes a day-ahead market.

To pay for the infrastructure projects, BPA received a $10 billion boost in its borrowing authority with the U.S. Treasury under the Infrastructure Investment and Jobs Act of 2021, which raised BPA’s borrowing line from $7.7 billion to $17.7 billion.

BPA is self-funded; it must repay the Treasury with revenues from its power and transmission rate revenues.

“BPA sets its rates to ensure the probability of repaying its annual U.S. Treasury debt is at least 95%, which is the last payment it makes after all other obligations are paid,” it said in Friday’s news release. “BPA has made its Treasury payment on time and in full for the past 39 years. With the increased funds [$258 million] set aside for risk and its other sources of liquidity, the probability of making the Treasury payment over the BP-24 rate case period is more than 99%.”

The rate case takes effect Oct. 1 and runs through Sept. 30, 2025.

“BPA will file the case with the Federal Energy Regulatory Commission, requesting interim approval for the rates while awaiting final FERC approval,” it said.

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Eversource Takes Hit on Sale of Offshore Wind Assets

Eversource announced an after-tax impairment charge of $331 million related to the sale of its offshore wind assets in its quarterly earnings call Tuesday.

Eversource CFO John Moreira said the impairment “will not have any impact on our cash flows and operations” but noted that the impairment charge could be significantly larger if Eversource is unsuccessful in repricing the Sunrise Wind contract with the New York State Energy Research and Development Authority, or if the Revolution Wind and Sunrise Wind projects do not qualify for investment tax credit adders. (See OSW Developers Seeking More Money from New York.)

Moreira estimated these two issues could cost the company an extra $400 million each but said the company is confident it will avoid those costs.

“We have included both of those components in our impairment analysis, and obviously for us to be in a position to do that, there needs to be a certain level of conviction and probability, and on both of those we feel very good,” Moriera said.

The $331 million impairment charge amounted to $0.95 per share and contributed to reduced second-quarter earnings of $0.04 per share compared to $0.84 per share in the second quarter of 2022. It largely offset increased earnings in Eversource’s electric transmission and distribution businesses.

Eversource previously partnered with the world’s largest offshore wind developer, Denmark’s Ørsted, to pursue projects off the Northeast U.S. coast, but has decided to exit the partnership and the offshore wind business altogether.

The company completed the sale of its uncommitted lease area to Ørsted in May for $625 million and said it is “near the goal line” on the sale of its stake in the South Fork Wind, Revolution Wind and Sunrise Wind development projects. (See Eversource Begins Its Exit from OSW Development.)

The costs and in-service dates for these projects have not changed since May of this year, and about 93% of the costs of the three projects are locked in, Eversource said. The in-service dates range from late 2023 for South Fork Wind to late 2025 for Sunrise Wind.

Eversource CEO Joe Nolan said the company remains committed to clean energy and still sees offshore wind as a key resource for the region despite the recent setbacks.

“We feel very strongly that wind is going to play a major role as we transition to this clean energy environment,” Nolan said. “I don’t see anyone taking their foot off the gas. The policymakers are very excited about wind, so I really don’t see that waning.”

He added that Eversource is focused on making the necessary infrastructure improvements to enable the clean energy transition.

“We continue to emphasize the need for system investments to support increased electrification and distributed generation to help ease the current reliance on natural gas generation in the region,” Nolan said.

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Potential Military/NASA Conflict with OSW Seen in Wind Energy Area

Federal regulators are moving forward with three new wind energy areas off the Delaware, Maryland and Virginia coasts.

The WEAs total about 357,000 acres, 23 to 35 nautical miles off the DelMarVa peninsula, from the Delaware Bay to the Chesapeake Bay. If fully developed, they are believed to hold the potential for 4 GW to 8 GW of production capacity.

The Bureau of Ocean Energy Management’s announcement Monday of the three Central Atlantic WEA boundaries and publication Tuesday of a notice of intent to conduct an environmental analysis is a step forward, but only an early step.

BOEM is committed to holding a Central Atlantic lease auction by August 2024, but the process would continue for years before any construction can start.

And one of the three WEAs may never go to auction: BOEM is still doing an in-depth review with NASA and the Department of Defense to see if wind energy in the WEA designated B-1 could co-exist with the extensive space and military activities nearby.

BOEM said if WEA B-1 does go to auction, mitigation measures would be identified first, so bidders would be aware of steps they would need to take there.

Publication of the notice of intent (Docket BOEM-2023-0034) in the Federal Register on Tuesday launched a one-month public comment period.

BOEM said in a news release that extensive stakeholder and public input already has been incorporated into the planning process.

In April 2022, the Department of the Interior announced a call area of 3.9 million acres off the Central Atlantic Coast.

In November 2022, BOEM narrowed that down to eight draft WEAs covering 1.7 million acres from Delaware to North Carolina.

The three finalized this week are:

    • WEA A-2 — 102,000 acres, 26 nautical miles from Delaware Bay;
    • WEA B-1 — 78,000 acres, 23.5 nautical miles southeast of Ocean City, Md.;
    • WEA C-1 — 177,000 acres, 35 nautical miles from the mouth of Chesapeake Bay.

In its announcement, BOEM said these three WEAs encompass relatively shallow waters. It said it might identify additional WEAs for leasing in deepwater areas along the Central Atlantic Coast in the future, after further study.

BOEM told NetZero Insider on Tuesday the other five draft WEAs initially identified in November could be part of such a future lease auction.

Offshore wind development along the Central Atlantic Coast is in potential conflict with a constituency much more influential than the fishermen and beachfront property owners who oppose the wind turbines almost everywhere they are proposed.

The south end of the Chesapeake Bay is densely packed with military facilities, including the world’s largest naval base and airfields for multiple squadrons of supersonic fighter jets.

To the north, NASA has its Wallops Island launch facility. To the south, the Navy has its Dare County bombing and gunnery range.

Offshore wind skeptics and opponents pounced on a Bloomberg report in April that DoD had flagged large swaths of the Atlantic coast from Delaware to North Carolina as “highly problematic” for offshore wind development.

This friction between military planners and one of their commander-in-chief’s signature clean-energy initiatives developed outside of the public eye.

But a DoD spokesperson later confirmed in comments to Gizmodo the agency in fact had identified “compatibility challenges” between military training and offshore wind in this region.

In the environmental impact statements it has prepared for offshore wind farms farther north on the Atlantic Coast, BOEM has predicted a significant negative effect on U.S. Coast Guard search and rescue operations — the towering height of the turbines and the expansive sweep of their rotors would limit flight operations below 1,000 feet and complicate surface operations.

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PSEG Touts ‘Wins’ in Ocean Wind Sale, Energy Efficiency

Public Service Energy Group marked a number of “wins” that show how the company is aligned with New Jersey’s energy policies, including the sale of its portion of the state’s first offshore wind project, CEO Ralph LaRossa said during a second-quarter earnings call Tuesday.

LaRossa said the sale of its 25% share of Ocean Wind 1, which closed at the end of May, and other initiatives underway reflect what he sought to do in assembling his management team over the past six months and keeping the utility in line with the New Jersey’s aggressive clean energy initiatives. He became PSEG’s CEO in September.

LaRossa said he was “very proud” of how the company exited from the offshore wind business.

“We entered, we took a hard look at that opportunity, and we exited in a way that both we were able to keep our heads up financially, policy-wise and with the labor workforce in the state of New Jersey,” he said.

LaRossa said in February that the company would leave offshore generation due to its unpredictability but would be “keeping an eye on the market and [seeing] what makes sense.” (See PSEG CEO Says Need for ‘Predictability’ Drives OSW Sale.)

Ørsted and other OSW developers have in recent months expressed concern about the rising cost of completing projects due to general inflation, elevated costs for raw materials and transportation and rising interest rates. They also say they cannot execute projects under previously agreed financing deals. (See OSW Industry Group Sees Growth Beyond Turbulence.)

Reflecting NJ Policy

LaRossa said another big “win” was the New Jersey Board of Public Utilities’ (BPU) July 26 approval of the three-year Triennium 2 energy efficiency plan. (See NJ BPU Backs Building Decarbonization Plan Despite Opposition.)

Central to the BPU’s plan is a series of building decarbonization (BD) “startup” program plans designed to encourage customers of all kinds — but especially residential and multifamily-dwelling customers — to switch from fossil fuel water and space heaters to electric appliances. Another part of the plan details a package of demand response proposals under which customers would reduce their energy use in response to different circumstances. The proposal puts much of the responsibility for enacting the proposals on the state’s four utilities.

Parts of the BPU package are similar to existing PSEG energy efficiency measures, and other parts reflect the company’s own vision, LaRossa said.  He noted that the BPU in May approved a $280 million, nine-month extension for one of the utility’s energy efficiency programs that would put it in synch with the start of the Triennium plan in June 2024.

“We stayed aligned with public policy on our energy efficiency filing and [that] took us a good step forward,” he said. “As a result of that, we’ll really be able to take some advantage of some new orders that came out from the board.”

He described the BPU plan as “a good roadmap for all the utilities in New Jersey to follow” and said PSEG is “still studying” the proposals.

“That has a lot of upside for us,” he said. “We think [it] will really encourage additional energy efficiency investments from companies like ours,” he said.

Advocating for Electrification

LaRossa noted that Kim Hanemann, president of the company’s PSE&G New Jersey utility subsidiary, is “already actively involved” in the clean buildings working group assembled by Gov. Phil Murphy (D) to study how best to advance electrification in the state. The group “is considering various approaches to building electrification, including the development of a clean heat standard,” he said.

“Our overall approach to energy transition is to continue advocating for practical expansion of electrification in a manner which protects customer affordability, safety and reliability,” he said.

The approach also includes improving the efficiency of the utility’s gas operations, LaRossa said. The company in the first quarter submitted to the BPU a system modernization program that aims to improve the efficiency of its gas system. The plan aims to cut methane leaks by 22%, part of an effort to cut methane emissions by 60% between 2011 and 2030, he said.

He said the various initiatives contributed to a “relatively straightforward quarter” in which the company focused on executing its plans for growth, and “also increasing the predictability of our business.”

PSEG reported second-quarter net income of $591 million, ($1.18/share) compared to net income of $131 million, ($0.26/share) for the second quarter of 2022. Non-GAAP operating earnings for the second quarter were $351 million ($0.70/share) compared with non-GAAP earnings of $320 million ($0.64/share).

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Hydrogen Tax Credit Design is Key to Decarbonization

The Treasury Department must balance the need to grow the hydrogen industry with the need to ensure it is clean as it implements the 45v tax credit in the Inflation Reduction Act, experts said at a Resources for the Future event Monday.

While hydrogen production now is done with natural gas, which produces direct emissions, it can be done with electrolysis — using electricity to split the hydrogen atoms out of water. How clean that is depends on what is generating the electricity, said RFF Fellow Kevin Rennert.

Lawmakers were aware of the emissions issue and wrote in the statute that the 45v credit must take lifecycle emissions into account when it is being awarded, and how much credit projects get.

While the main strategy to cut emissions involves electrification, such as with motor vehicles and home heating, that does not work everywhere, said American Clean Power Association CEO Jason Grumet.

“There’s some big parts of our economy, both domestically and globally, that just don’t lend themselves to electrification: heavy industry, cement, steel, some heavy freight transport, aviation,” Grumet said. That’s been the missing piece, he added. “And so, here’s where green hydrogen kind of fits the bill.”

The industry doesn’t exist now. To ensure major commodities are produced cleanly, green hydrogen, or an alternative, needs to grow significantly in the coming decades. (See DOE Releases National Clean Hydrogen Strategy and Roadmap.)

Policymakers are worried that if they start putting a bunch of electrolyzers onto the grid without additional clean energy supplies, that would increase emissions overall, Grumet said.

To get around that, ACP supports requiring new electrolyzers to be supplied by new clean energy generation in their region. But the requirement to match hourly demand with renewable production would be phased in so any project that starts construction by the end of 2028 would only have to match annual demand, which is much more flexible and would allow the industry to grow, Grumet said.

To keep pace with the energy transition, about 10 million metric tons of clean hydrogen needs to be produced by 2030, and that would require 100 GW worth of electrolyzers, said Electric Hydrogen Vice President for Policy Paul Wilkins. That’s based on a utilization rate of about 60%, with hydrogen production ramping when renewable power is available and not running when it is not.

Without “temporal matching” with renewable production, the credits would go to simpler electrolyzers that can’t ramp production up and down easily and run as often as possible, helping to drive up peak demand and thus electric rates for other consumers.

“An electrolyzer that can’t ramp is more likely to be produced in China,” Wilkins said.

North America is expected to have 3 GW of hydrogen production running by next year. China will have 13 GW, dominated by less flexible production, which it can build at a third of the cost of what’s built in the West. Requiring temporal matching would ensure not only the molecules of hydrogen were clean, but also that the tax credits flowed to more technically advanced, American machinery.

“We need to make sure that we’re innovating incentivizing a flexible hydrogen production, storage and consumption system,” Wilkins said. “And the U.S. does innovation better than any other country in the world. If the U.S. incentivizes innovation, and if Treasury incentivizes innovation, we’re confident the U.S. industry is going to win. If Treasury incentivizes low tech, China does low tech at scale really well.”

The incentive in question is the IRA’s largest, totaling $450 per ton of CO2 abated when clean electricity production credits are included, and $300 per ton without them, said Rocky Mountain Institute Senior Associate Nathan Iyer. If designed well, it could help decarbonize major industries.

“It is all centered around one core question: How do you prove that the electricity that you are consuming is low carbon when you have a much dirtier grid?” Iyer said.

Using power with the grid’s average emissions would lead to hydrogen that produces about 20 kilograms of CO2 per ton, which is worse than producing with natural gas, and 30 to 60 times dirtier than electrolyzers would need to be to qualify for 45v, he added.

“As the largest credit, this will set a national precedent and could be a huge step forward if it’s durable and effective at reducing emissions in the real world,” Iyer said. “And while the structure of this credit forced this question for hydrogen first, this is not the last time that we will have this debate.”

The same subject of decarbonizing the grid while adding massive, new loads is going to be key to decarbonizing many parts of the economy, he added.

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ERCOT Technical Advisory Committee Briefs: July 25, 2023

ERCOT will ask its Board of Directors to approve a $329 million reliability project in the San Antonio area following an endorsement from stakeholders last week.

The Technical Advisory Committee approved the project as part of its combination ballot during its July 25 meeting, agreeing with staff’s recommendation that the project is critical to the ERCOT system’s reliability.

The project addresses thermal overloads in the San Antonio area and has been designated as a Tier 1 project because of its estimated capital costs of $100 million or more, thus requiring board approval. The board next meets Aug. 30-31.

CPS Energy, San Antonio’s municipal utility, submitted the project for the Regional Planning Group’s review in December. The staff-led RPG is the grid operator’s primary forum for discussion, input and comment on planning issues.

ERCOT staff studied five options for the project, shortlisting three. They determined the chosen option improves long-term load-serving capability and operational flexibility and provides an additional transfer path from South Texas into the San Antonio area.

The preferred option does lead to congestion on a line, but upgrading the line does not yield economic benefits, staff said, and it will not be included in the project.

The project involves building 50 miles of new double-circuit 345-kV lines and rebuilding an additional 25 miles of 345- and 138-kV lines. CPS expects to complete the project by June 2027.

RTC Stakeholder Group to Form

Now that work has resumed on real-time co-optimization (RTC), ERCOT wants to reconstitute the stakeholder group that produced seven nodal protocol revision requests (NPRRs) and two other changes to guide the ISO’s implementation of that market tool that procures energy and ancillary services every five minutes. (See ERCOT Technical Advisory Committee Briefs: Nov. 18, 2020.)

ERCOT’s Matt Mereness, who guided the RTC Task Force, will chair the proposed working group. A vice chair has not yet been identified. Work is to begin in September, with a targeted delivery of 2026.

The group will use the NPPRs to develop business requirements for RTC and single-model batteries. It also will review a state-of-charge concept for batteries. Staff are drafting a charter for the August TAC meeting.

The RTC Task Force was disbanded at the end of 2020 following completion of its work. The disastrous and deadly 2021 winter storm and the ensuring drain on staff postponed further work on RTC and batteries until recently.

Combo Ballot

TAC members approved a change to the Verifiable Cost Manual (VCMRR034) despite concerns from generators that it will create confusion over what can be included in the fuel adders. The revision provides that actual fuel purchases used to determine the reliability unit commitment guarantee will not be included when calculating fuel adders.

The measure passed 26-1, with Luminant casting an opposing vote and Calpine, ENGIE and Jupiter Power all abstaining.

The committee also considered a separate motion on NPRR1165, which would strengthen ERCOT’s market entry eligibility and continued participation requirements for qualified scheduling entities, congestion revenue right account holders and other counterparties. The measure passed 29-1, with only CPS Energy in opposition.

NPRR1165 would remove minimum capitalization requirements, require counterparties to post independent amounts, remove references to guarantors, clarify financial statement requirements and reference International Financial Reporting Standards rather than retired International Accounting Standards.

TAC’s combination ballot included three additional NPRRs, two revisions to the nodal operating guide (NOGRRs), another binding document request (OBDRR) and a change to the planning guide (PGRR). If approved by the board, these changes would:

    • NPRR1176, NOGRR252: revise the Energy Emergency Alert (EEA) procedures to require a declaration of EEA Level 3 when physical responsive capability (PRC) cannot be maintained above 1,500 MW and require ERCOT to shed firm load to recover 1,500 MW of reserves within 30 minutes. The NPRR also would modify the trigger levels for EEA Level 1 and EEA Level 2, change the trigger for ERCOT’s consideration of alternative transmission ratings or configurations from advisory to watch when PRC drops below 3,000 MW, and restore a frequency trigger for the EEA Level 3 declaration if the steady-state frequency drops below 59.8 Hz for any period of time.
    • NPRR1182: incorporate controllable load resources and energy storage resources (ESRs) into the constraint competitiveness test’s long-term and security-constrained economic dispatch (SCED) versions. Controllable load resources will not be mitigated but will be used to identify whether a market participant has market power in resolving a transmission constraint; other resources’ registration data will be used in the long-term CCT process, and real-time telemetry will be used in the SCED CCT process.
    • NPRR1183: revise rules for and make publicly available on ERCOT’s website general information documents that don’t include ERCOT critical energy infrastructure information (ECEII), remove a reference to the Freedom of Information Act from the ECEII’s definition and remove antiquated or duplicative language related to reliability must run.
    • NOGRR247: increase the under-frequency load shed (UFLS) program’s load-shed stages from three to five and change the transmission operator load-relief amounts to uniformly increment by 5% for each stage, add a UFLS minimum time delay of six cycles (0.1 seconds) and add 59.1 Hz to the list of UFLS stages, and revise the gray-box language from NOGRR226 to provide that the TO load value used to determine load at each frequency threshold will be the TO’s load at the time frequency reaches 59.5 Hz.
    • OBDRR047: clarify treatment of unused funds from previous emergency response service standard contract terms.
    • PGRR108: update language to reflect the current practice of posting regional transmission plan and geomagnetic disturbance (GMD) assessment plans and update data sets.
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MISO Wraps Incident-free June

MISO presided over routine operations in June, with an average 81-GW load and diminished wholesale prices.

Average load was down 3 GW compared to June 2022. MISO’s real-time locational marginal prices fell more dramatically, from about $75/MWh to $28/MWh year over year. Most of the drop was attributed to natural gas prices falling from about $8/MMBtu to $2/MMBtu within the year.

Average daily generation outages also were lower than last June, at about 38 GW instead of 41 GW. MISO operated with a fuel mix of 44% natural gas, 29% coal, 15% nuclear and 9% wind.

The grid operator realized a 3-GW solar peak June 20, when solar generation served 3% of total load at midday.

Heat arrived in the latter half of the month, forcing multiple rounds of conservative operations instructions and MISO’s 111-GW peak on the evening of June 29. The monthly peak was 10 GW short of last June’s peak.

MISO said it will internally review a more than 7% error in its load forecasting for June 29. The grid operator attributed the load estimate error to severe weather in the footprint’s central region that ultimately shaved 10-20 degrees from initial weather forecasts.

So far, summer hasn’t held any emergency procedures for the footprint. MISO managed to avoid a maximum generation emergency last week during a systemwide heatwave. (See MISO Preps for Heat Wave, Anticipates Annual Demand Peak.)

MISO ultimately issued two separate maximum generation alerts for its Midwest region two days before the expansive heatwave intensified July 27 and again July 28. Those followed MISO’s issuance of conservative operations instructions, a hot weather alert and a capacity advisory July 23.

The grid operator said July 25 that it was facing risks from above-normal temperatures and forced generation outages. It had warned that its forecasted high loads could have caused it to come within 500 MW of its operating obligations for July 27.

“With increased risk and uncertainty, it may be necessary for MISO to escalate further based on changing system conditions,” MISO said at the time.

MISO has a hot weather alert in effect for its South region through Aug. 4. Temperatures in the region are expected to be near 100 degrees.

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Whitmer EV Chargers Caught Up in Driveway Controversy

LANSING, Mich. – Gov. Gretchen Whitmer’s effort to install two electric vehicle chargers at the state’s Executive Residence have gotten caught up in a controversy over a driveway project at the house.

The state’s Administrative Board last week approved a slightly less than $1 million contract to build a new driveway and install the EV chargers at the residence in the Moore’s River Drive neighborhood — an upper-income neighborhood convenient to both the state Capitol and a large General Motors plant.

Ad Board actions generally are little noticed by the public, but once concrete started getting laid at the residence on July 28, the project gained controversy because it involves all taxpayer funds, and the contract was awarded with a no-bid contract.

Whitmer and her office have said adding the EV chargers is an effort at “leading by example,” as the state has taken major steps to be a leader in EV production and battery development.

But Rich Studley, the former chief executive of the Michigan Chamber of Commerce and a frequent critic of Whitmer, tweeted that the driveway and EV chargers are really an example of “greed.”

It isn’t the chargers themselves that are causing the controversy, but the whole nature of the project.

Michigan has two executive residences for the governor: the Lansing ranch-style house and a cottage on Mackinac Island. Michigan did not have a gubernatorial residence in Lansing until the 1963 Constitution required one, and the current residence was donated to the state. Then-Gov. George Romney was the first governor to live at the house.

While routine upkeep and maintenance of both residences is paid for by the state, major projects usually are financed through private donations. One of the most recent major renovations of the Lansing residence, done while U.S. Energy Secretary Jennifer Granholm was Michigan’s governor, was funded privately.

The new driveway must be commercial grade, twice as thick as most residential driveways, because the residence has a fair number of commercial and city vehicles — including garbage trucks to handle the building’s dumpsters — use the property. That accounts for much of the cost.

With the Legislature is on summer break, and controlled by Democrats, it’s unlikely there will be any attempt to block the project, which should be complete in August. Whether there will be an effort to refund the state for its cost through private donations has not yet been discussed, publicly at least.

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FERC Interconnection Rule Sets Penalties, Ends ‘Reasonable Efforts’ Standard

FERC’s long-awaited revamp of its generator interconnection procedures will make it more costly for developers to enter and leave queues and impose penalties on transmission providers that fail to complete studies on time.

Order 2023 (RM22-14) sets a 150-calendar day deadline for completing stability analyses, power flow analyses and short circuit analyses required to study complex clusters involving numerous interconnection requests.

FERC said the 150-day deadline gives transmission providers “sufficient time to perform these technical cluster studies while providing certainty about the timeline for the interconnection process.”

The commission cited reports filed by transmission providers that showed of the 2,179 interconnection studies completed in 2022, 68% were issued late and another 2,544 studies were still ongoing and past their deadlines as of the end of the year. All RTOs/ISOs except CAISO and 14 non-RTO/ISO transmission providers reported delayed studies for the year.

About 80% of transmission providers reported delayed studies in at least one of the past three years (2020-2022) and 57% had delayed studies in at least two, FERC said. The National Association of Regulatory Utility Commissioners complained to FERC that “nearly all transmission providers across the country, including many transmission providers that have implemented queue reforms, regularly fail to meet interconnection study deadlines.”

‘Reasonable Efforts’ Standard

Previously, the pro forma large generator interconnection procedures held transmission providers to a “reasonable efforts” standard for completing studies, defined as “actions that are timely and consistent with good utility practice and are substantially equivalent to those a party would use to protect its own interests.”

Transmission providers argued that many of the delays resulted from situations outside of their control, including large numbers of speculative interconnection requests, a shortage of qualified engineers, delayed data from interconnection customers and cascading restudies caused by withdrawals. MISO said most of its delays resulted from the need to wait for affected systems studies.

Some commenters warned that firm deadlines might lead transmission providers to prioritize speed over accuracy and the identification of the most efficient solutions. National Grid said it could result in later corrections to engineering requirements and cost estimates, causing more late-stage queue withdrawals.

The Edison Electric Institute and Eversource Energy complained that FERC’s Notice of Proposed Rulemaking (NOPR) failed to make the case for why reliance on good utility practice remains sufficient in other situations, but not for interconnection studies. New York’s Transmission Owners and Eversource said FERC should postpone penalties until it has allowed the other process changes to take effect.

But public interest and clean energy groups said the transmission providers were ignoring potential solutions, such as policy and process improvements and increasing spending on staff. Advanced Energy United (formerly Advanced Energy Economy) said accepting high interconnection queue volumes as a legitimate cause for delays would provide providers “a permanent free pass” to miss deadlines.

Losing Patience

FERC demonstrated little patience for the providers’ excuses.

“The reasonable efforts standard worsens current-day challenges, as it fails to ensure that transmission providers are keeping pace with the changing and complex dynamics of today’s interconnection queues,” the commission said. “Contrary to the assertions of some commenters, we believe that there are steps within transmission providers’ control, from deploying transmission providers’ resources to exploring administrative efficiencies and innovative study approaches, to better ensure timely processing of interconnection studies to remedy existing deficiencies.”

It noted that the order seeks to reduce speculative interconnection requests with stricter requirements for entering and remaining in the queue (site control requirements, commercial readiness deposits and withdrawal penalties) and also seeks to improve efficiency by switching to the first-ready, first-served cluster study process from the serial, first-come, first-served process.

The penalties, FERC said, “ensure that transmission providers are doing their part as well.”

Penalties

The NOPR proposed a penalty of $500 per business day that the study is late, but the commission said it was persuaded that was too low, noting that a study delayed by six months (126 business days) would result in a penalty of only $63,000. “We view such a penalty as insufficient considering that the purpose of the penalty is to incentivize timely study completion that may be achieved, for example, by hiring additional personnel or investing in new software,” FERC said.

Instead, it imposed per-day penalties of:

    • $1,000 for delays of cluster studies;
    • $2,000 for delays of cluster restudies;
    • $2,000 for delays of affected system studies, and
    • $2,500 for delays of facilities studies.

Penalties will be distributed to interconnection customers on a pro rata per interconnection request basis to offset their study costs.

As a concession to the transmission providers, FERC said it will not impose penalties until the third cluster study cycle (including any transitional cluster study cycle) after the effective date of the transmission provider’s compliance filing.

The commission also will waive penalties for studies submitted within a 10-business-day grace period and will allow a deadline extension of 30 business days by mutual agreement of the transmission provider and all affected interconnection customers. Penalties will be capped at 100% of the initial study deposits.

FERC rejected the NOPR’s proposed force majeure penalty exception, instead saying that transmission providers will be permitted to appeal penalties to the commission.

“Transmission providers may explain in any appeal to the commission any circumstances that caused the delay, including any events that qualify as force majeure, and the commission will consider such circumstances as part of its evaluation of whether good cause exists to grant relief,” FERC said.

RTOs and ISOs will be allowed to submit a Federal Power Act Section 205 filing to recover penalties from at-fault transmission providers.

“Non-RTO/ISO transmission providers and transmission-owning members of RTOs/ISOs may not recover study delay penalties through transmission rates,” FERC said. “… Because the at-fault transmission provider’s shareholders will pay the penalty, this prohibition addresses commenters’ concerns that study delay penalty costs will ultimately be borne by customers and ratepayers through increased transmission costs.”

Transmission providers will be required to make quarterly postings making public the penalties incurred from the previous quarter.

Other Studies Rejected

The commission rejected NOPR proposals for optional resource solicitation studies or optional informational interconnection studies and adopted a modified proposal to require evaluation of certain advanced transmission technologies. The commission said those changes “should reduce the burden on transmission providers as compared to that under the NOPR.”

The NOPR sought comment on whether state agencies required to develop a resource plan or conduct a resource solicitation process should be defined as a resource planning entity and be able to request initiation of an optional resource solicitation study.

But the commission concluded there was “insufficient evidence” to justify the optional resource solicitation study as a “generic solution” across all regions for coordinating state-level resource planning with the interconnection process, noting that many transmission providers do not have load-serving entities that conduct resource solicitations.

“We are also concerned that the particular ‘one size fits all’ approach proposed in the NOPR would create uncertainty regarding the cost and timing of interconnecting to the transmission system, because the proposed study would not result in useful network upgrade cost estimates.”

It said it agreed the proposal “would divert transmission provider resources and potentially lead to delays.”