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August 22, 2024

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California PUC Adopts Contested Net Metering Plan

The California Public Utilities Commission on Thursday adopted a controversial proposal to revise the state’s net-metering scheme for rooftop solar arrays, including by reducing bill credits for new solar owners and incentivizing battery installations.

“We are launching the solar and storage industry into the future so that it can support the modern grid,” CPUC President Alice Reynolds said in a statement issued after the vote. “The new tariff promotes solar systems and battery storage with a focus on equity and advances the new clean energy technologies we need to meet our climate goals and help ensure grid reliability.”

The vote came after months of wrangling over the plan, which was originally proposed a year ago, then postponed amid public outcry and rewritten to mollify homeowners angry about the possibility of losing their solar subsidies.

The modified proposal, approved by a unanimous vote Thursday, says it tries to balance the “multiple requirements of the Public Utilities Code and the needs of the electric grid, the environment, participating ratepayers, as well as all other ratepayers.”

It will not change the credits paid to current rooftop solar owners for excess electricity they export to the grid. The state’s investor-owned utilities compensate those homeowners at full retail electricity rates, which are much higher than the current costs of utility-scale solar.

The subsidies shift the costs of solar panels from ratepayers who can afford them to those who cannot, Pacific Gas and Electric (NYSE:PCG) and other IOUs argued. The “cost shift” amounts to $3 billion to $4 billion a year, the utilities estimated.

The generous payments to those who install PV panels are credited with making California the nation’s leader in rooftop solar over the past 25 years.

“Since 1997, California has supported the rooftop solar market through its NEM tariffs, which have enabled 1.5 million customers to install more than 12,000 MW of renewable generation,” the CPUC said in a news release last month.

The CPUC’s previous net energy metering proposal, issued in December 2021, would have slashed NEM bill credits by more than half and possibly up to 80%, including for homeowners who installed solar panels prior to the plan’s adoption. (See California PUC Proposes New Net Metering Plan.)

Under the revised plan, future rooftop solar owners will be compensated differently from existing customers through “an improved version of net billing, with a retail export compensation rate aligned with the value that behind-the-meter energy generation systems provide to the grid and retail import rates that encourage electrification and adoption of solar systems paired with storage,” the decision says.

“The successor tariff applies electrification retail import rates, with high differentials between winter off-peak and summer on-peak rates, to new residential solar and storage customers instead of the time-of-use rates in the current tariff,” it says. “The successor tariff also replaces retail rate compensation for exported energy with Avoided Cost Calculator values that vary according to grid needs.”

A fact sheet that accompanied the proposed decision when it was released in November said the new rate structure will encourage customers to install battery storage so they can store solar electricity generated in the daytime and sell it to the grid on hot summer evenings, when prices are higher and the state needs it most for reliability.

Strained grid conditions in the past three summers occurred during heat waves when solar ramped down in the evening but demand remained high from air conditioning use.

The state legislature approved $900 million in funding this year to spur adoption of rooftop solar and battery storage, including $630 million for lower-income households. Those who install solar or solar coupled with storage in the next five years will receive extra payments.

“Customers lock in these extra bill credits for nine years,” the CPUC said in the fact sheet.

The solar industry will benefit by selling more storage along with solar arrays, it said.

The adopted plan removed a controversial provision contained in the December proposal to impose an $8/kWh grid charge on solar customers’ bills, averaging about $48 per month for residential customers.

The CPUC estimated that under the new plan, residential customers installing solar will save an average of $100 a month on their electricity bills, and those installing solar panels and batteries will save $136 a month or more.

“With these savings … customers will fully pay off their solar systems in just nine years or less,” the CPUC said in the fact sheet.

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FERC Moves to Implement New Backstop Transmission Siting Authority

FERC on Thursday approved a Notice of Proposed Rulemaking that would pave the way for overriding state regulators’ rejections of certain transmission projects (RM22-7).

Congress originally gave FERC this backstop siting authority for transmission projects in Department of Energy-designated National Interest Transmission Corridors as part of the Energy Policy Act of 2005. But the 4th U.S. Circuit Court of Appeals ruled this only applied to those projects that state regulators did not act on, not to those that states denied (Piedmont Environmental Council v. FERC (2009)).

A provision in last year’s Infrastructure Investment and Jobs Act essentially overturned that ruling, expanding FERC’s backstop authority over state-rejected projects. The NOPR is intended to implement that provision.

“The NOPR clarifies the commission’s siting authority by expressly stating that the commission may issue a permit for the construction or modification of electric transmission facilities in DOE-designated national corridors if a state has denied an application to site transmission facilities,” Abigail Christoph, an attorney-adviser in the Office of General Counsel’s, said in a presentation at FERC’s open meeting Thursday.

E-1 panel (FERC) Content.jpgAbigail Christoph and Kim Smaczniak, of the FERC Office of General Counsel, and Enakpodia Agbedia, of FERC’s Office of Electric Reliability, brief FERC commissioners on the NOPR. | FERC

 

It would also allow developers to begin prefiling proceedings for their projects with FERC while its state applications are pending, instead of waiting for one year after they submit them.

“This change will allow applicants to simultaneously pursue approval before a state and the commission if they so choose,” Christoph said.

Transmission wonks generally consider federal backstop siting authority necessary for building large, interregional projects, as just one state can unilaterally kill a multistate project if it rejects its developer’s application. It is a deeply unpopular concept with state regulators, however.

FERC acknowledged this in the NOPR by proposing several rule changes aimed at ensuring a thorough process if a developer requests that it override a state’s rejection.

The commission would create a new applicant “code of conduct” for how potential permit holders engage with landowners. It would also require three “resource reports” be included in applications: on environmental justice, tribal resources, and air quality and environmental noise.

Republicans Tentatively Approve

All five FERC commissioners voted to approve the NOPR, but they didn’t agree on whether it will actually help build out any transmission projects.

“Infrastructure is extremely difficult to site in the United States,” Chair Richard Glick said. “It’s something that, as a country, we need to come to grasp with, especially in regards to transmission. … We have to get it done as a country, and I think this is a step in the right direction.”

Fellow Democratic Commissioner Allison Clements pointed to the provisions that add new requirements for engaging with landowners and other stakeholders as helpful to getting projects done and avoiding litigation.

“It’s really hard to build infrastructure because that impacts people. So let’s find ways to bring people into the conversation early on and get satisfactory outcomes,” she said.

But Republican Commissioner Mark Christie challenged both the premise of the new rules — that states are blocking transmission buildout in a meaningful way — and their function.

“This narrative that’s being pushed — that the states are standing in the way of critically needed infrastructure — is a false narrative,” Christie said.

He noted that the transmission rate base around the country has almost tripled in the last 10 years.

“The states are not standing in the way of critically needed transmission projects. The states are by and large approving them. If the states need anything, they need more authority to vet projects, not less,” he said.

Christie also said the rule changes would not be a “magic bullet” that results in more transmission. Instead, he said, they would create multiple lines of attack for litigation opposing new transmission lines.

“The first time FERC overturns a state after the state has said ‘no,’ once the state has held its own formal process and said ‘no’ either on the route or the need or the prudence of cost … that’s going to be litigated 16 ways from Sunday,” he said.

Still, Christie said he would approve the NOPR, though he said he wanted to hear from state regulators and consumer advocates.

“I question the purpose of fidelity to the IIJA in a NOPR that has what I think in many cases are unnecessarily burdensome requirements, but … I solicit comments on that,” Commissioner James Danly said.

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NERC Warns of Ongoing Extreme Weather Risks

The coming decade will be marked by “extraordinary reliability challenges and opportunities” amid rapid changes in the climate and the North American electric grid, NERC staff said while introducing the organization’s Long-Term Reliability Assessment (LTRA) on Thursday.

“Year after year, we’ve seen extreme weather leading to increased reliability events. … It’s clear that the bulk power system is impacted by extreme weather more than it ever has,” John Moura, NERC’s director of reliability assessment and performance analysis, said at a media event accompanying the report’s release. “So, as we transition our system so rapidly, it’s vitally important that we’re planning and operating a [BPS] that can be resilient to the extreme weather we’re seeing.”

NERC produces the LTRA every year in coordination with the regional entities to assess North American resource adequacy and identify trends, emerging, issues and potential risks during the coming 10 years. This year’s report found most of the continent as either high-risk — meaning energy shortfalls may occur at normal peak conditions in one or more years — or elevated, in which case reserves meet normal resource adequacy criteria but severe heat or cold could lead to shortfalls.

MISO, Ontario at High Risk

MISO and NPCC-Ontario led the high-risk areas, with projected shortfalls for each region exceeding 1,000 MW. Most urgent is the 1,300 MW in MISO, where NERC now expects the reserve margin to fall below the reference margin level beginning next year — a year earlier than the prediction from last year’s LTRA. Mark Olson, NERC’s manager of reliability assessments, explained in Thursday’s call that generation retirements in MISO are “outpacing the new resource additions, and not keeping up with resource adequacy criteria.”

Shortfalls are expected to begin in NPCC-Ontario as early as 2025, with the anticipated reserve margin (ARM) dropping below the reference margin level by 1,700 MW in that year and 2026, driven by “planned retirements and lengthy outages for nuclear units undergoing refurbishment.”

Five-year projected reserve (NERC) Content.jpgFive-year projected reserves for MISO (left) and NPCC. | NERC

 

Regarding the nuclear outages, NERC observed that Ontario Power Generation has proposed to extend the operation of Pickering Nuclear Generating Station, which is currently expected to retire in 2025, through September 2026. The LTRA’s ARM for NPCC-Ontario was calculated under the assumption this proposal would be approved by Canada’s Nuclear Safety Commission.

The last high-risk area is California. Although the state now seems set to avoid the shortfall that last year’s LTRA predicted would begin in 2026, thanks to added capacity, NERC noted it “remains dependent on electricity imports to manage periods of extreme electricity demand or low resource output.” A probability assessment for 2024 showed that while most months show a low risk of load loss and unserved energy in the state, August and September had high risks of more than two hours of load loss due to warm temperatures and “potentially volatile electricity demand.”

Olson said California’s Diablo Canyon nuclear plant was not included in the LTRA due to uncertainty around its continued operation, but that it “would certainly help alleviate risk.” The 2.2 GW plant was scheduled to close by 2025, but the state this year determined that its baseline contribution was essential for reliability, and the Department of Energy last month awarded PG&E $1.1 billion to help keep it in operation. (See DOE Grants PG&E $1B for Diablo Canyon Extension.)

Variable Generation a Continuing Concern

Areas at elevated risk include the U.S. Northwest and Southwest, SPP, Texas and New England. In those regions, capacity should be sufficient to meet normal peak demand; however, conditions under NERC’s 90/10 forecast — which has a 10% chance of being exceeded — could lead to outages.

Tier 1 and 2 planned resources (NERC) Content.jpgTier 1 and 2 planned resources projected through 2032. | NERC

For Texas, the report noted that “ERCOT’s winter peak load varies substantially … between the coldest temperatures of an average year and a more extreme year.” Although changes by state regulators, ERCOT and generator owners since the winter storm of February 2021 should reduce the risk of disruption, NERC said the state still has cause for concern.

The biggest risk for New England continues to be dependence on natural gas for electricity and the risk of gas supply bottlenecks due to increased heating demand in severe cold. The report reminded readers that stored backup fuels are “critical” to ensuring grid reliability.

WECC and SPP face risks due to high demand and variable output, highlighting an ongoing issue in the BPS. As in previous years, projections for planned resources for the next decade show that wind, solar and gas “are the overwhelmingly predominant generation types in the planning horizon.”

Michelle Bloodworth, CEO of coal industry advocate America’s Power, said in a press release that the increasing presence of weather-dependent resources in the electric grid is worrying. She called for utilities not to abandon conventional generation sources without a better understanding of how to maintain reliability.

“We remain deeply concerned that the grid is being forced to rely on less dependable electricity sources in the future because of coal retirements. We strongly urge the Federal Energy Regulatory Commission and grid operators to act as quickly as possible to value all reliability attributes,” Bloodworth said. “In addition, we urge utility commissioners to pause coal retirements until grid operators have identified and valued all reliability attributes.”

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FERC Restarts Hearing on La Paloma Interconnection Dispute

FERC on Thursday restarted a paper hearing in a dispute over a revised interconnection agreement that would reduce the transmission capacity provided to a 20-year-old gas-fired power plant located in California’s Central Valley.

The dispute involves CAISO, Pacific Gas and Electric (NYSE:PCG) and CXA La Paloma, owner of the La Paloma Generating Plant in Kern County, Calif. (ER21-2592).

La Paloma, which entered service in 2003, struggled financially over the last decade as low-priced renewable resources depressed wholesale electricity markets.

After failing to win an expanded reliability must-run designation from CAISO, the plant declared bankruptcy in 2016, citing rising debt, a difficult regulatory environment and mounting compliance obligations under California’s cap-and-trade program.

The ISO refused to authorize a partial closure of the plant, and a new owner acquired the facility in 2018.

La Paloma’s original large generator interconnection agreement (LGIA), which FERC approved in 2001, provided the plant with 1,160 MW of interconnection capacity in the CAISO system. When the LGIA expired in August 2021, PG&E proposed a replacement agreement that would reduce La Paloma’s interconnection capacity to 1,062 MW, which CAISO asserted had been the maximum net generating capacity demonstrated at the plant’s point of interconnection.

Negotiations between PG&E and La Paloma failed to produce a replacement, and in December 2021, FERC accepted the utility’s unexecuted agreement, then suspended it for a nominal period, saying it needed more information to determine the reasonableness of the agreement “regarding the amount of interconnection service that should be reflected in the replacement interconnection agreement.”

The December 2021 order established a paper hearing, which the commission held in abeyance to allow a settlement judge to help negotiate the dispute. In June, the chief administrative law judge overseeing the matter terminated settlement procedures, saying the parties had reached an impasse.

In its order Thursday, the commission asked the parties to address several points in preparation for the hearing. It:

  • directed CAISO to explain which tariffs or manuals, if any, govern the renegotiation of an expiring LGIA, as well as which documents govern “a decrease to the interconnection capacity provided under an expiring generator interconnection agreement, and explain under which conditions interconnection service capacity may be decreased from the amount specified in the expiring generator interconnection agreement.”
  • asked why 1,062 MW was selected for the proposed replacement interconnection agreement, given that La Paloma’s participating generator agreement states the plant has 1,022 MW of generating capacity; the CAISO master file for the plant shows it has a generating capacity of 1,066 MW; the project’s peak output in recent years has not exceeded 1,061.3 MWh in any given hour; and the plant’s average peak output since 2018 has been 988.95 MW.
  • asked La Paloma to provide evidence for its own claims about the capacity and output of the plant.
  • directed CAISO to explain whether it conducted PMax testing — which determines the maximum megawatt level that a resource is capable of sustaining — and site visits to the plant during the replacement interconnection agreement negotiations, in line with the ISO’s stated practice.

The commission also directed La Paloma to provide documentation supporting its request that the ISO and PG&E compensate the plant for the 98 MW of interconnection capacity the replacement agreement would return to the CAISO system.

Initial briefs from the three parties are due 60 days from Thursday’s order.

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FERC Orders NERC Review on Physical Security

Reacting to recent sabotage events, FERC ordered NERC Thursday to report within 120 days on the effectiveness of its existing physical security reliability standards and determine whether improvements are needed (RD23-2).

The commission acted in response to the Dec. 3 gunfire attack on two Duke Energy (NYSE:DUK) substations in North Carolina, which left 45,000 customers without power for as long as four days. Shots also were fired near Duke’s Wateree Hydro Station in Ridgeway, S.C., last week. (See Duke Completes Power Restoration After NC Substation Attack.)

“In light of the increasing number of recent reports of physical attacks on our nation’s infrastructure, it is important that we fully and clearly review the effectiveness of our existing physical security standard to determine whether additional improvements are necessary to safeguard the bulk power system,” FERC Chairman Richard Glick said.

FERC’s existing physical security reliability standard (CIP-014-3), approved in 2014, requires transmission owners to perform periodic risk assessments to identify transmission stations and substations whose loss or damage could result in instability, uncontrolled separation or cascading outages. The standard also applies to primary control centers overseeing such facilities.

Transmission owners and operators must evaluate potential vulnerabilities of a physical attack to each of those assets and develop and implement physical security plans to protect them. It requires TOs to have an unaffiliated third party verify the risk assessments and security plans.

The commission directed NERC to assess the effectiveness of the current standard in light of the recent attacks, including evaluations of the adequacy of the applicability criteria and required risk assessments. NERC also must determine whether a minimum level of physical security protections should be required for all BPS transmission stations, substations and primary control centers.

Glick said the North Carolina attacks, and news reports of incidents in the Northwest and elsewhere, “reminds us that we need to take physical security into account just like cybersecurity.”

“We don’t want to get out in front of the FBI [which is investigating the North Carolina incident] and we don’t know exactly what [the attackers’] motives were or what or what actually happened. … But in the meantime, I think it’s a good idea … to reassess our existing security standards, and whether changes need to be made.”

Glick also noted that some incidents occur at electric facilities below the bulk power system, which are subject to state regulation. “So we need to work with our state colleagues as well to make sure that we’re prepared; they’re prepared; and we all do as much as we can to make sure that the grid is as secure as possible.”

Commissioner Mark Christie said common distribution transformers are “vulnerable to a drunk with a gun and an attitude and … we have a lot of incidents of that. [The loss of a transformer] knocks out a block or two — a substation, several tens of thousands of people.”

Christie said he expects NERC to recommend upgrades to the standard, such as requiring high-definition cameras at substations. “That’s gonna be really costly,” he said, adding that he hoped the Department of Energy will provide support from the $15 billion in grid resilience funding from the Infrastructure Investment and Jobs Act.

“I hope this does not flow through to ratepayers,” he said.

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Northeastern States Plan OSW Compensation Fund for Fisheries

Nine Northeastern and Mid-Atlantic states are seeking input from fisheries and other stakeholders on a plan to create a compensation fund for commercial and for-hire recreational fishing businesses that suffer economic damage from the development of offshore wind projects.

The states — Maine, New Hampshire, Massachusetts, Rhode Island, Connecticut, New York, New Jersey, Maryland and Virginia — on Monday issued a request for information (RFI) seeking stakeholder input on the plan to “establish a regional fisheries compensatory mitigation fund administrator.” The RFI aims to secure input from “impacted members of the fishing industry” as well as offshore wind developers, corporate and financial management entities and interested members of the public.

The fund, if it goes ahead, would provide a source of assistance and compensation for fisheries that find their business and income damaged by the construction or operation of the wind projects, said Kris Ohleth, director of the Special Initiative on Offshore Wind, an independent non-profit organization that promotes wind energy and helped organize the interstate collaboration on the issue.

“So, if you are a fisherman who’s fishing, who is home porting in Virginia, and you fish for scallops off the coast of Massachusetts, you are eligible to apply if you can demonstrate that where you fish before is no longer available to you and it’s impacted your revenue,” she said. “That’s the way the states are envisioning it.”

The proposal addresses an issue that has stirred persistent opposition to offshore wind projects along the East Coast, and elsewhere, where commercial fishermen fear that project construction will damage marine wildlife and prevent them from fishing their regular locations. The fishing industry between Maine and South Carolina caught fish valued at $2.1 billion in 2019 and employed about 360,000 people, according to a scoping document put together by the nine states in preparation for the RFI.

In New Jersey, for example, clam industry representatives have expressed concern that the weight of clam dredges, which can weigh 5 to 7 tons when empty, and other nets, combined with unpredictable winds and currents through the turbines, will make it difficult and dangerous for fishing boats to maneuver around them once they are built. (See Fishermen Fear the Impact of NJ Wind Farms.)

In Massachusetts, lobstermen have expressed concern that their livelihood will be threatened by the construction of offshore wind turbines and embedding of power cables into the ocean floor to transmit the wind power. (See Massachusetts Fishermen Brace for Offshore Wind.)

A study by Rutgers University concluded in July that offshore wind projects on the East Coast could cut revenue in the $30 million surf clam industry by 3% to 15%. The study, which was funded by the U.S. Bureau of Ocean Energy Management (BOEM), said the presence of the turbines in the water could mean that some clamming vessels will make fewer trips, go to different — more distant — fishing areas and so harvest fewer clams, cutting their earnings. Those changes could also increase average costs by 1% to 5%, according to the study.

Trust Fund

The idea for a pool grew out of the framework released by BOEM in June, which set a goal of mitigating the impact of offshore wind projects on the fishing industry. The framework recommended that developers provide reimbursement for “for fisheries gear loss and damage resulting” from developer actions.

Seeing the benefits of collaborating and sharing experiences on issues such as permitting challenges, natural resource consideration and scheduling issues, the nine states had earlier written President Biden about the need for a coordinated offshore wind policy. In a June 2021 letter, they offered several recommendations for how the federal government could support states in the development of wind projects, including suggestions to plan from a longer- term perspective.

“The states are really motivated to get this work done,” said Ohleth. But they saw the “less than ideal” experience of the first two offshore wind projects in the U.S. — South Fork off the New York coast and Vineyard Wind off Martha’s Vineyard in Massachusetts — that handled the fisheries mitigation on a project-by-project level.

“In both cases, there was a lot of consternation,” she said. “There was a lot of issues with fishermen not trusting developers, developers not trusting fishermen, and the state is getting stuck in the middle as the arbiters of the deal.”

Ohleth said the question of compensation is always at the forefront of fishermen’s minds and providing an established fund to meet that concern would enable the states and the industry to address deeper questions.

“We’re attempting to take that question off the table,” she said. With that in place, “we can evolve to … higher order conversations about adaptability, about vessel diversification, about fishermen participating in the offshore wind space … It’s too scary for fishermen to think about that until they have their bottom line met.”

Beyond Compensation

The RFI poses a range of questions about the proposed fund and how it should be managed, seeking responses from the public, the commercial and for-hire recreational fishing industry, the renewable energy industry, corporate and financial managers, and others with knowledge of offshore wind energy siting and development. Questions include: What should be the purpose of the fund? How should the administrator handle claims? What kind of appeals process should be in place? And what role should states play in the fund?

The group will receive comments between Dec. 12 and Jan. 31 and expects to start seeking a regional fund administrator for the program in the spring.

The scoping document put together by the nine states says that “because coastal states are reliant on seafood as part of their complex economic portfolios, they are committed to ensuring sustainable seafood and domestic food security be maintained into the future.”

Yet “the junction of OSW and fishing is a complex intersection, where solutions are needed to advance the long-term sustainability of both industries,” the document says.

Compensation is the “last step” that states should consider in seeking to help the fishing industry, the document says. States and their developers should first focus on avoiding an impact on the industry or, if that is not possible, on minimizing or mitigating the effect, the document says. Still, a compensation plan is “vital to ensuring coexistence of robust and dynamic OSW energy and fishing industries,” the document says.

It adds that “experience to date with siting and development of OSW energy in the region indicates that a standardized framework is necessary to ensure compensation in addressing aggregated adverse economic effects on fisheries equitably and efficiently.”

The scoping document says the administrator would consider both revenue losses and the additional costs paid by fishing interests because of the wind projects. The revenue losses could include displacement of the interests from their fishing area; the transition from highly productive to less productive fishing grounds; reduced fish catch in lease areas; and the devaluation of fishing businesses.

Additional costs could include: the need to acquire new or modified gear, including navigational equipment; extended transit times to get to new fishing areas; increased insurance costs and higher dockage and offloading fees due to competition for “limited space in ports and harbors.”

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Entergy Strengthens its Emissions-Reduction Goals

Entergy has fleshed out its interim goal of emission reductions by adding interim benchmarks and a definitive goal for 2050.

According to the company’s latest climate report released last month, Entergy plans to reach net-zero greenhouse gas emissions from all electric and natural gas operations across its businesses by 2050. It aims to reduce owned and purchased emissions 50% from 2000 levels by 2030 and to have 50% carbon-free power generation capacity by 2030.

The utility’s 2030 goals did not previously include a carbon-free capacity component and power purchases in its 50% utility-only, carbon-reduction goal. Entergy said it added the provisos because its planning models showed that it was on track to outperform its current goal.

It said it now expects to reach the current 2030 interim goal of reducing its CO2 emission rate by 50% from its 2000 baseline several years early. “[We] are evolving this goal to include purchased power,” Entergy said in the report.

The New Orleans-based company had only said it would strive for net-zero emissions in an addendum to its first climate report in 2019.

Entergy’s goal is to reduce “emissions as low as possible and minimize our need to neutralize any residual emissions while still maintaining the reliability and affordability of our products, even as our customer base and demand for clean energy grows.”

Pathway to net-zero (Entergy) Content.jpgEntergy’s illustrative pathway to net-zero compared to other climate warming scenarios | Entergy

 

The utility said 2030’s carbon-free capacity will be supplied by nuclear, solar, wind, hydropower and energy storage. It did not specify a definitive supply plan for 2050, saying its assumptions and risks will change over time.

Entergy completed the report’s modeling before passage of the Infrastructure Investment and Jobs Act and the Inflation Reduction Act. It said the modeling doesn’t account for the laws’ potential acceleration of technological advancements and emissions goals.

However, Entergy noted that the laws are “expected to help us define our path to net-zero with more certainty, as well as enabling new and innovative solutions.”

Rick Johnson, the company’s director of sustainability, discussed the updated plan Monday during an Entergy Regional State Committee Working Group meeting.

He said while an uptick in demand might slow Entergy’s emissions reductions, the utility is poised under several scenarios to limit its greenhouse gases in line with either a 2-degree or 1.5-degree Celsius total warming.

“We’re going to continue to compare our path … to climate science to avoid the worst impacts,” Johnson said. Entergy foresees “substantial growth in demand from electrification” that could lead to up to 60% more energy production by 2050, Johnson said, noting load growth could “put upward pressure on our absolute emissions.”

“Some stakeholders might not be happy with individual company progress,” he said. But he added that Entergy’s subsidiaries are a linchpin in its region’s decarbonization efforts.

Johnson said Entergy is discussing whether to purchase carbon offsets but will likely only use them if it becomes necessary to counteract its remaining emissions.

“If we got to 2050, and we’re short, yes, we’ll look for high-quality, permanent instruments to neutralize those residuals,” he said.

Johnson said he doesn’t know when Entergy might next revise or update its climate goals, expressing hope that “this will go down to a lower number, but that’s difficult to guarantee 28 years out.”

Entergy needs clean, dispatchable generation including small modular nuclear reactors, advanced nuclear options, clean hydrogen, and long-duration storage to reach its overall emissions commitment, he said. Entergy believes some of those technologies may become commercially viable before 2035.

Going forward, any newly built Entergy gas facility will be hydrogen-capable and able to be retrofitted to exclusively burn hydrogen, Johnson said. He said Entergy’s two newest natural gas plants, the St. Charles and Montgomery power stations can co-fire up to 30% hydrogen.

Johnson added that Entergy Louisiana and Entergy New Orleans recently signed a memorandum of understanding with Diamond Offshore Wind to explore the feasibility of connecting offshore wind generation in the Gulf of Mexico to the grid. He also pointed to Entergy’s recent agreement with Holtec International to evaluate installing small modular reactors in the Entergy service area.

Entergy will need some long-term transmission projects to prop up a clean energy future, Johnson said. He said Entergy “supports MISO’s efforts to develop its initial proposal” for long-range transmission projects (LRTPs) and added that it will need to be confident that the projects have “demonstrable benefits that exceed the costs” and that costs are allocated in a fair manner.

MISO has mounted a series of four LRTP planning cycles but doesn’t anticipate assessing Entergy’s needs in MISO South until the third iteration. (See MISO Staff Preview New LRTP Projects with Board.)

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MISO, SPP Unable to Find Smaller Joint Tx Projects

MISO and SPP officially announced this week that they will not pursue any small, congestion-relieving interregional projects from their first Targeted Market Efficiency Project (TMEP) study.

The two grid operators have been hinting that they likely weren’t going to land on any beneficial projects. (See Search for Small SPP-MISO Interregional Projects May be Fruitless.)

SPP’s Neil Robertson said the constrained flowgates under study either already had a solution from SPP’s regional planning, resulted in projects with one-sided benefits, or the proposed projects were too costly for one RTO when compared to continued congestion payments.

Robertson said during an Interregional Planning Stakeholder Advisory Committee (IPSAC) teleconference Wednesday that the RTOs’ Joint Targeted Interconnection Queue (JTIQ) study stands to ease congestion on some of the TMEP candidate constraints. He said staffs assumed that the approximately $1 billion of JTIQ projects took precedence over potential TMEP projects. (See Stakeholders Not Sold on JTIQ Projects’ Cost-Sharing Plan.)

Robertson said the TMEP study contained multiple constraints where “other study processes got there first.”

“In this particular case, we’re a victim of timing and circumstance to some extent,” he said.

As an example, Robertson said a possible $37.7 million rebuild of a 50-mile ,161-kV line near the Oklahoma-Arkansas border would nearly double the TMEP cost cap of $20 million.

The grid operators screened for possible TMEPs when a market-to-market flowgate amassed $1 million or more in congestion costs over a two-year period. The two catalogued seven permanent flowgates that racked up between $10 million and $43 million worth of congestion. (See MISO, SPP Hunt for Small Interregional Tx Projects.)

This is the fifth straight time MISO and SPP have returned empty-handed after an interregional study.

Despite coming up empty, the RTOs are memorializing their TMEP process in their joint operating agreement and will launch another study in the future. They will also create separate regional cost-allocation methods to use when they find a beneficial project.

“I think [with] the fact that TMEPs will be a tool in the future, I think it’s inevitable that we will have multiple projects in the coming years,” Robertson predicted.

Advanced Power Alliance’s Steve Gaw said he was frustrated with the results. He said it seemed that MISO and SPP are hamstrung by siloed joint planning processes, perpetually promising projects “on the horizon” that never materialize.  

“We’re still missing the mark here in terms of our interregional planning processes,” Clean Grid Alliance’s Natalie McIntire said.

The RTOs have proposed that TMEPs must cost $20 million or less, must not be greenfield projects, be in service by the third summer peak from their approval, and completely cover their installed capital cost within four years of service through avoided congestion.

They borrowed many of their standards from MISO and PJM’s TMEP criteria. Stakeholders on both sides of the seam have said the cost threshold should be increased, given today’s high inflation environment and tight labor market.

They asked how the RTOs settled on the TMEPs’ cost threshold. Some said the $20 million limit established by PJM and MISO in 2017 amounts to $30 million in 2022 dollars. Their staffs responded that the $20 million cap ensures that projects are low-risk, relatively easy to complete and don’t impede on other more intensive interregional planning.

During a November common seams initiative meeting between the two grid operators, McIntire said it would be a “tragedy” if they emerged from another interregional study without a single project recommendation.

MISO and SPP are continuing to determine how a transmission owner in one footprint can finance and construct lines in the neighboring RTO without benefits to the region where the transmission would be located.

Currently, the MISO-SPP operating agreement doesn’t contemplate construction of a cross-border project unless at least 5% of the project investment stands to benefit the neighboring region. The RTOs are attempting to chart a path where a TO can construct a project that solely benefits the RTO across the border.  

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Will Glick’s Departure Mean More On-time FERC Meetings?

There’s a ritual most third Thursdays of the month among the FERC watchers on #energytwitter.

When 10 a.m. comes and goes without the commissioners taking their seats around their semicircular dais, the stakeholders who attend the monthly open meetings in person continue their schmoozing. But for those watching via the commission’s webcast, it provokes critiques of the hold music and sarcastic comments about how the commission is late — again.

FERC meetings have often started after the advertised 10 a.m., but they reached new tardiness levels during the two years of Richard Glick’s chairmanship, inspiring one civic-minded FERC watcher to launch a Twitter account earlier this year, FERCStartTime. (“Solely dedicated to announcing the ACTUAL start time of FERC’s monthly open meeting. I listen to the looped hold music so you don’t have to.”)

According to an RTO Insider analysis of FERC meetings since January 2010, FERC meetings began an average of almost 42 minutes late during the two years of Glick’s chairmanship — by far the longest of the seven FERC chairs during that period. Glick may be chairing his final meeting Thursday after failing to win a hearing on his renomination. (See Glick’s FERC Tenure in Peril as Manchin Balks at Renomination Hearing.)

Former Chairs Norman Bay, Cheryl LaFleur and Kevin McIntyre were relatively prompt, starting their meetings on average within six minutes or less of the scheduled start. Neil Chatterjee, Jon Wellinghoff and James Danly were on average 12 to 29 minutes late.

Glick and Danly also hold the top spots when ranked by median tardiness (33 and 30 minutes, respectively). Wellinghoff’s tardiness drops from an average of 18.9 minutes to a median of 5, while Bay’s drops from an average of 6.3 to a median of 1 and Chatterjee from an average of 11.8 to a median of 8.

RTO Insider’s analysis is based on transcripts of 133 meetings since January 2010. Seven meetings were canceled during that period, one because of the COVID-19 pandemic in March 2020 and six because of a lack of quorum in 2017. Transcripts were not posted for three meetings and could not be located. The analysis reflected rescheduled start times on a few occasions when meetings were delayed because of inclement weather and protester disruptions.

In interviews, former FERC staffers cited increased partisanship, the challenges of remote work during the pandemic, and the increasing public profile of the commission and the issues facing it for the increased delays.

Wellinghoff said “a chairman should make every reasonable effort to start meetings on time,” and lamented that one nearly three-hour delay had inflated his average. He said he could not recall the reason for the delay.

Glick, Bay and LaFleur declined to comment this week. Danly did not respond to requests for comment. McIntyre died in 2019.

Chatterjee, now a senior adviser at law firm Hogan Lovells, said the delays have increased in part because the meetings “have become really scripted affairs.”

“This is a conversation that I’ve actually had with a number of former chairs and commissioners that in the 80s, and 90s, in particular, and even in the early 2000s, the open meetings were kind of freewheeling debates,” Chatterjee said.

“What is happening now is — quite frankly, for strategic purposes — dissenting commissioners are withholding their separate opinions until the very last moment, and then … the chair and the majority has to then amend the order to account for some of the arguments being made in the dissenting opinions, and then amend their statements.”

Glick ‘Embarrassed’

At a press conference following the commission’s May 19 meeting, which started only 19 minutes late, Glick acknowledged he’s “sometimes … embarrassed when we don’t start on time.”

“I would love to sit here and tell you that [the May 19 start] means that we’re always going to be on time or at least close to on time,” said Glick. “But every commission meeting is different. Every set of orders that we have to consider are different. Sometimes there’s late negotiations between offices; [sometimes] we have difficult decisions we have to talk through with other offices. … The items that were on the agenda today [lent] themselves towards enabling us to start earlier.”

FERCStartTime, which began tracking the meetings in May, now has more than 150 followers, a who’s who of #energytwitter, including LaFleur; former Commissioner Phil Moeller; Glick’s chief of staff, Pamela Quinlan; analyst Christine Tezak, Harvard Law School’s Ari Peskoe; former Montana Public Service Commissioner Travis Kavulla; and Todd Snitchler, CEO of the Electric Power Supply Association.

It is “the most passive aggressive account on all of #energytwitter,” tweeted Joe Daniel, a manager in RMI’s Carbon-Free Electricity Practice.

What Goes On

So what’s happening on the 11th floor of FERC headquarters while we’re listening to “Man in the Mirror” for the third time?

Jeffrey Dennis, who recently left Advanced Energy Economy for the Department of Energy’s Grid Deployment Office, saw the process first-hand between 2010 and 2015, when he headed the Office of Policy Development and served as an aide to Commissioner John Norris.

“I think that what’s going on is that there are continued efforts to try to reach compromises [and] ensure that the language that the commission is voting on is ultimately what folks have agreed to — whatever compromises they’ve made — or that they’re giving the commissioners sufficient time to know what’s [included in] a vote … so that when they make their comments at the open meeting, they’re well informed, and they’re not making comments on something that perhaps was struck out of an order,” Dennis said.

“It did happen less often [in the past]. And I think that speaks to [the fact that] we certainly are seeing more separate statements, more orders that don’t have unanimity than we did … 15 years ago. That in some ways is a recognition of how much more difficult and controversial a lot of the issues the commission has before it are and the work it takes really to tackle these big issues,” Dennis continued. “The issues before FERC were always significant, but they are increasingly in the public eye. There does seem to be a bit more partisanship than there was before; I don’t want to [say on] every issue, but many.”

Grid Strategies President Rob Gramlich, who served as economic adviser to FERC Chair Pat Wood III from 2001 to 2005, said the remote work caused by the COVID-19 pandemic has contributed to the delays.

“It was always the case [that] we were negotiating orders right up to the last minute, so that’s not new,” he said. “You can get a lot more done when you’re physically there in person than when you’re all working off site. So I’m going to give the commission a pass for the last couple of years on that, because no previous commission ever had to negotiate final orders across five different offices and multiple staff offices from their homes all over the place.”

Larry Gasteiger, who worked 19 years at the commission (1997-2016) — including stints as legal adviser to Chair Joseph T. Kelliher and chief of staff to Chair Bay — said he sees a lack of discipline in the increasingly late starts.

“There was a lot of emphasis put on trying to resolve issues well in advance of the commission meeting so that we could essentially put it to bed … if not the evening before, certainly the morning of the commission meeting,” said Gasteiger, now executive director of the trade group WIRES. “And it’s a lot of work. I don’t want to suggest that it’s easy to accomplish that. It’s not. It’s really hard.

“Frankly, though, it does depend on the cooperation of all of the commissioners. I think we were lucky in the sense that the commissioners, at the time I was there, were really focused on trying to get the items ready so that the commission meeting could start on time,” he added. “It shows a level of respect for all of the … stakeholders who are interested in watching the meetings. … Once it starts to run into one or two hours later, that’s a lot of people sitting around waiting for commission meeting to start.”

Gasteiger acknowledged the commission’s tardiness has become a running joke on Twitter.

“But the joke’s getting kind of tired, frankly. And I just think the commission needs to get its act together. And I don’t point to the chairman only on this. All the commissioners need to be working on getting the meeting started promptly and on time. It can be done. It was done regularly for many, many years.”

It remains to be seen whether a new chairman will have any more success at on-time meetings. But one thing is certain: Since FERC moved its webcasts to YouTube, remote viewers can no longer hear playlists compiled by commissioners or commission offices while waiting for the meetings to start because of royalty issues.

“YouTube is very strict on that,” said FERC spokeswoman Mary O’Driscoll. “You have to be in the commission meeting room to hear the hold music.”

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Renewable Group Asks FERC for Interconnection Cost Changes in NE

RENEW Northeast is asking FERC to shift the burden of network upgrade operations and maintenance costs in ISO-NE off of interconnection customers.

In a complaint filed this week, the organization argued that the policy, contained in schedules 11 and 21 of Part II of ISO-NE’s tariff, is unjust and unreasonable.

“ISO-NE is the only region in the United States in which interconnection customers are directly assigned all capital cost and all ongoing O&M costs for network upgrades, regardless of who causes the network upgrades or who benefits from the network upgrades,” RENEW wrote in its complaint.

Since Order 2003 nearly 20 years ago, FERC’s policy has been to require interconnection customers to initially fund the cost of network upgrades that would not have been required without that specific interconnection, but not to let transmission owners assign customers ongoing O&M costs.

“There was never any rationale behind this exemption from the commission’s O&M policy other than it having been a transitional measure included in New England Power Pool’s transition to an ISO and its Order No. 2003 compliance filing,” RENEW wrote. “Continued direct assignment of O&M costs to interconnection customers is not just and reasonable and should be rejected.”

RENEW sees it as an issue especially for its members — renewable generators — because the process of interconnection can be especially unwieldy for new generation projects, and the direct assignment of O&M costs adds another burden and barrier to entry.

It’s one of the factors that could cause projects to withdraw late in the interconnection process, according to RENEW.

“Since network upgrades provide a systemwide benefit, expenses associated with owning, maintaining, repairing and replacing them should be recovered from all transmission customers rather than being directly assigned to the generator,” said Francis Pullaro, the group’s executive director.

RENEW tried to bring a change to address the problem through the NEPOOL process, but it missed the two-thirds vote required to advance through the Transmission Committee. In the complaint, it’s asking for FERC to issue an expedited order finding those portions of the tariff unjust and unreasonable.