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December 2, 2022March 6, 2024

California PUC Releases PG&E from Enhanced Oversight Process

The California Public Utilities Commission on Thursday allowed Pacific Gas & Electric to exit an enhanced oversight and enforcement process the CPUC created two years ago to prevent the utility from starting catastrophic wildfires, but commissioners warned they would use the process again if needed.

Before the unanimous vote on a resolution freeing the utility from enhanced oversight, commissioners emphasized that PG&E had entered the first step of the six-step process because of particular problems with its vegetation management practices, and that it was being released because it had met specific goals imposed by the CPUC.

“This is an illustration of how the enhanced oversight and enforcement process can be effectively used,” Commissioner Clifford Rechtschaffen said. “It worked here. It’s of course not a panacea. No one is suggesting it is, but it did work. It did address an important problem. So, we should not be bashful about using it again.”

“PG&E’s operational practices remain a serious concern for us, despite everything that’s been done, so we should continue to utilize this tool,” Rechtschaffen added.

Commissioner Genevieve Shiroma said she would vote for the resolution, but “I do want to be very clear about the limited scope of this resolution and my continued concerns with PG&E’s operations.”

Other speakers noted that a number of CPUC actions targeting PG&E remain in place. They include an independent safety monitor that reports every six months on the utility operations; specific metrics to evaluate PG&E’s safety performance and to implement the enhanced oversight and enforcement (EOE) process; and continuing investigations of PG&E intended to rein in unsafe practices.

The CPUC required PG&E to accept the EOE process as a condition of it approving PG&E’s bankruptcy organization plan in June 2020.

In September of that year, a leaning gray pine fell onto a PG&E line and started the Zogg Fire in rural Northern California, killing four people and leading to additional scrutiny of PG&E’s tree clearing efforts by the CPUC and the federal judge who oversaw PG&E’s criminal probation from the 2010 San Bruno gas explosion.

The CPUC used the process for the first and only time against PG&E in April 2021, passing a resolution that said the utility was not “sufficiently prioritizing its enhanced vegetation management based on risk.”

PG&E had ranked its power lines based on wildfire risk but failed to perform the majority of its enhanced vegetation management “or even a significant portion of work” on its highest risk lines, the CPUC said at the time. The commission ordered PG&E to submit a corrective action plan and to report every 90 days on its progress clearing high-risk lines of trees and overhanging branches.

Trees and branches falling onto PG&E power lines caused devastating fires over the past five years, including last year’s nearly 1 million-acre Dixie Fire, many of the Wine Country fires of 2017 and the Zogg Fire.

The Utility Reform Network and the CPUC’s Public Advocate’s (Cal Advocates) office argued in a joint filing that the Dixie Fire and other activities warranted placing PG&E into a higher step of the EOE process, with escalating oversight and penalties.

The Dixie Fire burned for more than three months in the northern Sierra Nevada and southern Cascade ranges of California. | U.S. Forest Service

“Of particular note was PG&E’s failure to identify and remove the damaged and decayed tree” that started the Dixie Fire,” TURN and Cal Advocates said.

“When the tree fell and contacted PG&E lines, the utility demonstrated no sense of urgency despite the history of extreme fire danger and poor access in the surrounding region,” they said, citing the findings of the California Department of Forestry and Fire Protection. “PG&E’s delayed response allowed the tree to remain in contact with energized lines for approximately 10 hours and was a direct and negligent factor in the ignition of the fire.”

The CPUC decided those concerns and others were outside the bounds of the current proceeding. They found that PG&E had met the requirements of its corrective action plan and shown that it had prioritized work on high-risk lines.

“PG&E’s goal was to perform more than 80% of its [enhanced vegetation management] work in the top 20% highest risk circuit protection zones in 2021,” Thursday’s resolution said. The utility exceeded that goal by completing 98% of its tree clearing in 2021 on its highest risk lines and met other CPUC criteria, allowing to leave the EOE process, it said.

December 2, 2022December 12, 2023

NERC Report Recommends No Change to DER Study Thresholds

A study recently published by NERC pours cold water on the idea that utilities can safely leave some distributed energy resources (DER) out of their interconnection studies without affecting the accuracy of their models.

The DER Modeling Study: Investigating Modeling Thresholds, released last month, was intended to respond to industry stakeholders’ comments on various documents on DER modeling produced by NERC’s System Planning Impacts from Distributed Energy Resources Working Group (SPIDERWG). While the group has consistently argued for a threshold of 0 MVA for gathering data to populate system models, some industry participants have pushed for non-zero thresholds to reduce the resources needed for data collection.

NERC defines DER as “any source of electric power located on the distribution system” — facilities located behind a transmission-distribution transformer that serve end-use customers, such as rooftop solar panels and energy storage in homes and businesses.

Because they sit behind the meter, DER have traditionally been viewed as a part of the distribution system only, with little or no impact on the broader bulk power system, SPIDERWG has previously noted. (See NERC’s SPIDER Group Warns of Modeling Difficulties for DERs.)

Total DER output during delayed clearing bus fault | NERC

But with the number of DER on the distribution system growing rapidly and potentially affecting customers’ energy usage patterns, the group said in November that transmission planners and planning coordinators can no longer ignore their impacts. (See NERC’s DER Strategy Focuses on Industry Education, Collaboration.)

The study used a base case provided by WECC, modified to simulate the effects of not modeling various amounts of DER depending on their size. NERC believed this approach would simulate the effect of using thresholds other than 0 in modeling data. The team chose a scenario representing a heavy load condition for spring 2023, which assumed 8.41% of load served by DER — the highest level in the Western Interconnection of all base cases considered.

NERC set thresholds for the study using various measures. Aside from the base case, which includes all 12.7 GW of DER that would normally be accounted for in the model, seven cases were considered:

The same as the base case but ignoring generators with a rating of less than 75 MVA under NERC’s DER_A model developed by SPIDERWG;
Similar to the above, with a threshold of 20 MVA;
Threshold of 5 MVA;
Similar to the above cases, but DER are ignored when they account for 10% or less of the “load record” (an aggregate representation of end-use load in the base case); DER modeling adds an offset or a separate generator record to the load record to represent DER generation;
Similar to previous, but with a 25% threshold;
50% threshold; and
Same as the base case, but only including DER that backfeed energy into the bulk electric system.

The study simulated the loss of two large conventional generation facilities, along with the loss of the major HVDC intertie between California and the Pacific Northwest to determine the impact on frequency stability. Report authors also used a transmission fault simulation to study the dynamic response of the system under a variety of conditions.

Results showed notable differences in behavior when the simulated faults were applied. In the cases other than the 10%, excluding DER led to an increase or decrease in the frequency nadir for the system under the resource loss scenarios. NERC noted that the 10% threshold performed most like the base case, perhaps because this change reduced the level of DER the least, with only 390 MW of generation excluded from the model. This left almost 97% of DER still modeled.

The team called this finding “a testament to having proper data collection and data verification procedures in place,” saying accurate study results can still be achieved, even if some generation data is excluded, because “the data verification can fine tune capacity and control parameters to ensure accurate study results over time.”

However, NERC concluded that changing the modeling threshold beyond the 10% case “did have a significant difference in simulated system level performance,” which contradicted stakeholders’ suggestion that they could plan the system safely with different thresholds. Authors recommended that grid planners gather the total DER capacity for their footprints, though they allowed that different modeling thresholds could be set if appropriate for local systems.

The report also called for future studies to “target different aspects of simulated DER output” that did not fall in this study’s purpose. Such studies could include investigations of the effect of modeling lower thresholds of DER, or using different assumptions for the faults studied.

December 2, 2022May 5, 2024

SPP Issues Final Markets+ Proposal

SPP on Wednesday released a final proposal detailing the proposed governance structure, basic market design and other key features for the RTO’s day-ahead market offering in the Western Interconnection.

The RTO will now spend the next few months engaging with parties that have already expressed interest in committing to Markets+, a conceptual bundle of services that centralizes day-ahead and real-time unit commitment and dispatch. SPP says the market and its “hurdle-free transmission service” will help integrate the region’s rapidly growing fleet of renewable generation.

SPP has held several in-person meetings and webinars over the past year to gather input and reach agreement with potential stakeholders on the service offering. CEO Barbara Sugg said in a press release that collaborating with Western stakeholders on the Markets+ design has been a “tremendous effort.” (See Governance, Resource Adequacy Key to SPP’s Markets+.)

“Thanks to the dedication and engagement of these entities over the past year, I’m confident we can design and deliver a market that addresses challenges unique to the region and provides value to western customers,” she said.

SPP Final Markets Service Offereing (SPP) Content.jpg

SPP’s final Markets+ service offering | SPP

The service offering anticipates a two-phase process for continued development of Markets+. Potential participants and stakeholders will financially commit to design the market protocols, tariff and governing documents in the first phase. A second phase begins after FERC’s approval of the tariff; SPP will acquire the necessary software and hardware while participating entities fully commit to fund and are integrated into the system.

Parties interested in committing to financing further development of the market must sign a funding agreement by April 1 that will cover SPP staff’s involvement.

Load and/or generation entities that sign the agreement would get a vote on the Markets+ Participants Executive Committee (MPEC) in the first phase, and their representatives would be eligible for appointment to working groups and task forces. Those without load or generation would sign a participation agreement and make a one-time $5,000 payment or obtain a waiver in order to vote on tariff and protocol recommendations.

The MPEC is akin to SPP’s Markets and Operations Policy Committee in the Eastern Interconnection. It will provide a forum for market participants, stakeholders and non-voting stakeholders to discuss issues and to review system or process-improvement proposals recommended by SPP, the Markets+ State Committee and members and stakeholders.

The committee will report to the Markets+ Independent Panel (MIP), the highest level of authority for decisions related to the market, but with the SPP Board of Directors providing independent oversight. SPP said the board will “give significant recognition and deference to the [MIP’s] decision-making role.”

Because the RTO does not expect the MIP to be established during phase one, a three-person subcommittee of the SPP board will perform the decision-making functions until the MIP can be formed.

December 1, 2022January 24, 2024

‘Conceptual’ Tx Planning Map Troubles MISO Members

CARMEL, Ind. — MISO sparked strong reactions from stakeholders Tuesday when it fired up the second phase of its long-range transmission plan (LRTP) by debuting a theoretical map of projects.

In a presentation to MISO’s Planning Advisory Committee, the RTO’s Senior Director of Transmission Planning Laura Rauch revealed a “conceptual map” of possible projects that may arise from a second attempt at a long-range analysis.

Some members were startled by the potential scope of the RTO’s ambitions.

The possibilities for MISO Midwest include a crisscrossing system of new 345-kV lines, a network of 765-kV lines, a handful of 138-kV lines and even one HVDC line across Lake Michigan and another spanning North Dakota and Minnesota.

MISO’s first $10 billion LRTP portfolio was also confined to MISO Midwest. The RTO doesn’t plan to address MISO South needs until the third leg of its long-range transmission planning. (See MISO Board Approves $10B in Long-range Tx Projects.)

Rauch cautioned that MISO’s conceptual map does not represent what a final portfolio would look like.

All line ideas considered under MISO’s 2nd LRTP portfolio | MISO

“This is a starting point, not an ending point,” she said, adding that the line routes are educated guesses because MISO doesn’t yet know how siting will play out.

“I’m sure there are things on this map that we will not want to analyze. I’m sure there are some substations that cannot handle … the magnitude of transmission,” she said.

Rauch said it’s still an open question whether the second LRTP cycle should include 765-kV and dispatchable HVDC lines.

Some stakeholders said they were taken aback by the scale of MISO’s envisioned second LRTP.

“When you throw this slide up, this is very expensive, what’s on here. Much more expensive than tranche one,” said Jim Dauphinais, an attorney for the Coalition of Midwest Transmission Customers.

Rauch said the map could potentially be the “size of the answer,” but added that the resulting portfolio could be smaller.

WEC Energy Group’s Chris Plante called the map “uncharted territory” and said it was premature for MISO to publish the map before it ran analyses. Plante also said that the map doesn’t include some lines utilities deemed necessary. He cautioned against sharing the map with MISO’s Board of Directors next week at its quarterly meeting in Orlando, Fla.

Other stakeholders said MISO’s release of the map might preclude consideration of other necessary transmission solutions that should be included in the second LRTP.

“I understand where you’re coming from. At the end of the day, the analysis will win out,” Rauch said. “This is going to be a long ride based on analysis. … Our intention was not to say we must do everything.”

While acknowledging that the release of the map may have been a “messy” way of broaching the issue, Rauch said it’s necessary to prepare stakeholders for MISO’s future system needs. She added that stakeholder LRTP workshops in 2023 will cover the RTO’s reasoning behind the hypothetical map of lines.

Rauch said MISO is building models to prepare for the second portfolio recommendation in 2023.

“We’re seeing member plans accelerating. We’ll continue to work through the futures and reflect that,” she told stakeholders.

The RTO is updating the data behind its three, 20-year transmission planning futures in time for more long-range transmission planning and work on the 2023 Transmission Expansion Plan (MTEP 23).

Changes will include revised state and member decarbonization goals, resource retirements, resource additions based on its interconnection queue, accredited capacity amounts, and capital, operating and fuel costs. MISO did not alter the 20-year load forecast behind the three planning futures.

So far, MISO has only shared preliminary information on its moderate, second future. The RTO said it foresees 270 GW of new resources and has 115 GW of resource retirements. It also anticipates a 90% reduction in emissions by 2042, faster than it previously projected.

The grid operator plans to share estimates from its conservative Future 1 and aggressive Future 3 next spring.

The second planning future will serve as the “focal point” for the lines MISO will plan under the second LRTP, Rauch said.

Zeroing in on Cost Allocation

A day before stakeholders got a glimpse of MISO’s controversial planning map, they heard how MISO continues to assess how to develop a more targeted cost sharing methodology for LRTP projects.

Milica Geissler, MISO | © RTO Insider LLC

Speaking at a stakeholder meeting on Nov. 28, cost allocation specialist Milica Geissler said the RTO will analyze whether it can allocate transmission costs by relying on more granular measures of identifying who benefits — and what the benefits are.

Geissler said MISO will examine the subregional benefits of preventing load shed, meeting NERC criteria, weathering extreme events, furthering state decarbonization goals and increasing transfer capability.

At the local zonal level, the RTO will test the benefits of avoided transmission investment, congestion and fuel savings, improved operating reserves and savings associated with resource adequacy. It will not test for any benefits on a footprint-wide basis because of its Midwest-South transfer constraint.

Some stakeholders argued that there’s too much overlap among the factors being considered to identify standalone benefits.

Plante said projecting some of the benefits into the future is akin “to throwing a dart in a blackened room” because benefits change over time and MISO lacks insight into future resource siting and expansion.

Clean Grid Alliance’s Natalie McIntire said MISO shouldn’t assume that the Midwest and South regions are unable to help each other during extreme events. The RTO’s Director of Cost Allocation and Competitive Transmission Jeremiah Doner said that while such benefits aren’t “zero,” they’re not enough to measure on a footprint-wide basis.

Mississippi Public Service Commission attorney David Carr encouraged MISO to consider that including decarbonization benefits might make it more difficult for some projects to get approval from certain utility commissions.

Geissler said MISO is at this point only pondering the benefits and hasn’t determined which ones will make the final cut. She added that the RTO isn’t willing to apply any proposed changes to projects already in progress, saying it “finds a lot of value” in current allocations.

MISO is using a 100% postage stamp to load rate for the first two cycles of projects coming out of its LRTP studies, with those costs confined to MISO Midwest. (See FERC OKs MISO’s Bifurcated Cost-allocation Tx Design.) But a new cost allocation approach that considers more beneficiaries could be applied to upcoming planning for the South region.

Carr said MISO should re-examine the assumption that load bear the “entirety” of long-range transmission costs. He made the argument in light of Montana-Dakota Utilities’ suggestion that new intermittent generation, in addition to load, should bear a portion of LRTP costs. (See MISO Gathering Stakeholder Input on LRTP Cost Allocation.)

“Transmission costs are a much larger share of customers’ bills. This situation is untenable,” Carr said.

Carr also pointed out that years ago, MISO South didn’t have any input in the postage stamp cost allocation.

Some stakeholders have voiced concerns about disparate treatment between LRTP portfolios, saying a different cost allocation for projects concerning MISO South will violate FERC’s requirement that the same class of projects should not be subject to different allocations.

In October, Geissler said planners were wrestling with how to assign an evolving cost allocation when beneficiaries of a line change over time. Some stakeholders have requested that MISO find a way to identify and mete out costs to new beneficiaries over time.

“I’m very thankful for the 2011 portfolio of projects,” Geissler said, referring to MISO’s Multi-Value Projects approved a decade ago. She said those projects show how benefit-to-cost ratios either increased or decreased over time depending on the transmission pricing zone.

“They change in a pattern that isn’t necessarily obvious,” Geissler said of benefits. She said those fluctuations mean that future beneficiaries might be difficult to predict over time.

However, stakeholders said the zones that over time realized the most benefits from the 2011 portfolio contained the most wind generation.

December 1, 2022

Sunflower’s New CEO Hillman Looks Back on MISO Tenure

Todd Hillman, currently MISO’s senior vice president and chief customer officer, is ending his nearly 20-year stretch with the grid operator and will become Sunflower Electric Power Corp.’s new CEO next year.

Sunflower’s board of directors on Nov. 21 named Hillman as its new CEO following a nationwide search. Hillman will succeed departing CEO Stuart Lowry.

Steve Epperson, CEO of Pioneer Electric Cooperative and Southern Pioneer Electric Co., two of Sunflower’s seven distribution member-owners, said Hillman is a “best fit” for Sunflower.

“I see great teamwork, collaboration and courageous decisions in our future and am confident that Mr. Hillman will deliver,” Epperson said in a press release.

At MISO, Hillman was responsible for customer relations, including member and regulatory relationships, and managing training, facilities and the RTO’s call center.

Hillman said it will be “bittersweet” leaving the organization. He joined MISO in 2004 as it prepared to launch its energy markets in April 2005.

“Imagine 100 employees, give or take. It was all-hands-on deck,” Hillman said in an interview with RTO Insider. “I just remember so much happening, and it was going so fast, and everyone was working on everything.”

MISO currently has about 950 employees.

Hillman said his first title with the grid operator was the generic “executive director.”

“We weren’t quite sure what the role meant yet,” he said.

Hillman joined the RTO after a stint at Reliant Energy’s offices in the Netherlands, where he managed various electricity, natural gas and transmission contracts. While there, he also established a European satellite office in Frankfurt, Germany. After Reliant’s sale of its Dutch operations, he returned stateside for Reliant before landing at MISO’s Carmel, Ind., headquarters.

“So naturally after working in Europe, Carmel, Indiana, is the next logical step,” he said.

“Todd’s contributions to MISO have been unbelievable,” MISO CEO John Bear said during an executive update Monday. He thanked Hillman for his dedication in integrating the MISO South region.

Hillman said MISO’s successful integration of Entergy as MISO South in 2013 ranks among its greatest achievements during his tenure. He described the work as “climbing Mt. Everest with one hand tied behind your back.”

“It took a village to do that,” he reflected.

Hillman said he considers the grid operator’s employee culture as his greatest personal accomplishment. He said he’s proud of the strides made on workplace diversity, equity and inclusion. He pointed to the creation of dedicated resource groups for employees who are also caregivers or veterans and employees’ annual $1 million in contributions to the Make-A-Wish Foundation.

“I look back, and I think about the culture,” Hillman said.

He said MISO today allows its employees to be creative and thrive in an industry that “isn’t smooth sailing.”

Hillman said MISO’s endeavor to attract and retain talent must continue. However, he said MISO is making progress and voiced confidence in Allegra Nottage, the RTO’s first chief diversity officer. (See MISO Installs First Diversity Officer; “High employee turnover concerns leadership,” MISO Board Week Briefs: Sept. 12-15, 2022.)

Hillman said MISO has a “huge opportunity to reset the turmoil” wrought by the Covid-19 pandemic and the Great Resignation.

“I feel like it’s a work in progress, but I know I leave it in great hands,” he said.

Hillman remembered challenging times during MISO’s early days, when Ohio and Kentucky members departed the footprint as former CEO James Torgerson also announced his exit in 2008.

“Imagine you’re having all this turmoil against a senior leadership change,” Hillman said.

Hillman said in all, MISO lost 7% to 10% of the footprint but gained roughly 30% in service territory with a spate of new memberships that began with MidAmerican Energy’s entry in 2009.

“So, we lost members, but then we had more members come on [within] a few years,” he said.

Hillman also said he has thought about his impending transition from MISO to SPP, where Kansas-based Sunflower is a member. The two RTOs attempted to merge last decade and remained rivals until recently.

“I promise I’m going to be a very good stakeholder,” he said. “I know how tough it is, so I want to be a help.”

Hillman said he’s encouraged by the RTOs’ collaboration in recent years and said he will place his Sunflower hat on and will advocate for his utility. “As it gets tougher in the business, the more those relationships can improve,” he said.

Hillman said he’s taking three important lessons learned from his time at MISO to Kansas.

“You always assume noble intent with anyone you’re working with,” he said. “Very few times are there issues that are black and white, and you can’t get the ball across the line. We have to figure out how to get that [assumption of] noble intent on both sides up across the industry.”

He said he plans on listening to all sides of an issue, something that’s served him well working with MISO’s 11 sectors and their differing viewpoints. He also said he will always remember that people are responsible for the electric industry’s operations and progress.

“This is very complex work at the end of the day. And I always remember that there are people behind it,” Hillman said.

He said he’s excited about Sunflower’s “main street” element and meeting customers. Hillman joked that he’s equally excited to “serve just one state,” instead of the 15 in MISO’s footprint.

Hillman said he’s “learned from the best” from MISO and its members and said he’s taking those leadership templates with him to Sunflower.

“People ask me, ‘Are you ready to be CEO?’ I don’t know, but I feel incredibly confident that if I can be anywhere near what they have done, I’ll be all right.”

December 1, 2022November 11, 2023

Red State AGs Challenge Vanguard Climate Activism

Attorneys general from 13 conservative states asked FERC this week to reject Vanguard’s request for a waiver allowing it to acquire large stakes in utilities, saying the investment giant’s climate activism violates its promise not to influence the companies’ management (EC19-57-001).

Attorneys general from Utah, Indiana, Alabama, Arkansas, Kentucky, Louisiana, Mississippi, Montana, Nebraska, Ohio, South Carolina, South Dakota and Texas cited Section 203 of the Federal Power Act, which prohibits holding companies like Vanguard from acquiring more than $10 million in securities of a utility without commission authorization.

In 2019, the commission granted Vanguard a blanket authorization to acquire up to 20% ownership in aggregate by Vanguard and its affiliates and subsidiaries or up to 10% ownership by any individual Vanguard fund. The commission said it was relying on Vanguard’s assurances that it would not invest “for the purpose of managing” utility companies or seek to “exercise any control over the day-to-day management” of them.

“Now, Vanguard’s own public commitments and other statements have at the very least created the appearance that Vanguard has breached its promises to the commission by engaging in environmental activism and using its financial influence to manipulate the activities of the utility companies in its portfolio,” the AGs said. They asked the commission to hold a hearing to determine whether Vanguard has violated the 2019 authorization and whether granting it an extension is in the public interest.

In February, Vanguard asked FERC to extend the initial three-year authorization for another three years.

Vanguard did not respond to a request for comment Wednesday.

The AGs cited Vanguard’s 2021 decision to join the Net Zero Asset Managers Alliance, nearly 300 asset managers who pledge to work together to “accelerate the transition towards global net zero emissions” and to prioritize “the achievement of real economy emissions reductions within the sectors and companies in which [it] invest[s].”

The states also pointed to Vanguard’s membership in the Ceres Investor Network, which works with “investors around the world to accelerate action on climate change.” Vanguard has told its portfolio companies that it will support shareholder proposals requiring the pursuit of climate risk mitigation targets, the states say.

They noted that Berkshire Hathaway’s PacifiCorp, which serves Utah, currently gets 20% of its energy from coal or natural gas. “Consumers in Utah would be harmed if their costs went up because of closure of these facilities or substitution of more expensive energy sources,” they said.

“We are concerned that Vanguard’s actions with respect to influencing environmental corporate policy — especially in combination with the stated motives of [money managers] BlackRock and State Street Global Advisors — will inflate the rates consumers and our states pay for electrical service.” (See BlackRock to Divest from Coal Companies.)

Extension Sought

Vanguard’s request to extend the 2019 waiver also asked FERC to exclude from the 10% and 20% limits securities of utilities in portfolios managed by unaffiliated external advisers.

On Aug. 8, the Office of Energy Market Regulation extended the 2019 authorization for nine months, prompting a critical joint statement from Republican commissioners James Danly and Mark Christie, who noted that Vanguard’s assets under management have increased from about $5 trillion to $8.5 trillion since the 2019 order.

“Vanguard’s application raises a number of issues that demand commission scrutiny because Vanguard could potentially exercise profound control over the utilities it owns,” they said. “The commission cannot merely rubber stamp requests for blanket authorizations if it is to carry out its statutory duty to ensure that the accumulation of such substantial equity in utilities is not contrary to the public interest. Should a company like Vanguard seek to influence the management and operation of utilities’ generation portfolio, for example, this could have a significant impact on the rates consumers pay for electrical service.”

‘Woke’ or Not?

In addition to the challenge by the AGs in conservative states, Vanguard’s climate policies have also attracted protests by climate activists such as the Earth Quaker Action Team, which says the fund manager is “the world’s largest investor in coal and #2 investor in major climate-harming projects across the globe.”

December 1, 2022November 9, 2023

SoCalGas System Still ‘Impaired’ but Winter Outlook Improves

Southern California Gas’ system remains “impaired,” but the risk of service reductions is lower than in previous years because a warm winter forecast could reduce demand for gas-fired electric generation, the California Energy Commission heard Wednesday.

During a joint workshop with the California Public Utilities Commission, Energy Commission staff said two key pipelines are operating at reduced capacity, including one pipeline that ruptured in 2017. An El Paso Natural Gas mainline that ruptured last year south of Phoenix is shut down, limiting supply from the Permian Basin. And storage at SoCalGas’ Aliso Canyon natural gas storage facility continues to be restricted after one of the worst methane leaks in U.S. history in 2015-16.

“Recognizing these restrictions, staff assesses that the risk of service interruptions is lower this winter than in recent winters,” CEC staff wrote in a briefing paper. “This lowered risk is largely due to forecast demand being lower than in prior years. Specifically, staff projects zero curtailment on a winter day cold enough to occur once in 10 years.”

In colder conditions, SoCalGas might have to curtail 280 million cubic feet per day, a tenth of its total pipeline flow of 2.8 million cubic feet per day, the CEC said. The curtailment would affect “noncore load,” mainly electric generators plus some industrial customers and other users.

“Any adverse event, such as a pipeline going out of service, could lead to a higher curtailment,” the CEC report said. “The key risk to reliability is multiday cold weather events with additional infrastructure outages.”

SoCalGas serves nearly 22 million customers, about the same as the population of Florida, in its 24,000 square mile territory.

The CEC’s review is part of its informational proceeding on decarbonization, which it launched with a workshop in June.

“The Energy Commission is making great strides towards enhancing our modeling and analytical capabilities in this winter assessment,” Chair David Hochschild said at Wednesday’s workshop. “We are using our own gas-demand forecast results for the first time, [and] we’ve been able to dig deeper into the winter demand scenarios. All this leads to more verifiable results that feed into the gas decarb.”

Aliso Canyon

Aliso Canyon, regarded as both a threat to public safety and essential for reliability, has been a sticking point in that effort.

Residents and public officials have repeatedly called for its shutdown after it spewed more than 100,000 tons of gas into the atmosphere. The leak was contained after four months and multiple failed attempts.

SoCalGas and parent Sempra Energy agreed to pay $1.8 billion last year to settle the claims of 35,000 residents who claimed they suffered physically and emotionally from the leak.

In November 2021, California’s two Democratic senators, Dianne Feinstein and Alex Padilla, issued a joint statement saying it is “critical that the California Public Utilities Commission outline concrete steps to close this facility while ensuring the reliability of our power grid.”

The storage facility serves more than 11 million customers and provides fuel to 17 gas-fired plants, according to SoCalGas.

“It is a critical part of the region’s energy infrastructure,” the utility says on its website. “More than 90% of Southern Californians depend on gas for heat and hot water, and approximately 60% of all the electricity generated in California is made by natural gas-fired power plants.”

Last November, the CPUC increased Aliso Canyon’s storage limits from 34 billion cubic feet to 41 billion cubic feet because of reliability concerns — still well below its pre-leak capacity of 86 Bcf. Climate change-induced extreme weather “unfortunately has created greater short-term dependency on natural gas generation,” former Commissioner Martha Guzman Aceves said at the time.

December 1, 2022

FERC Approves PJM Plan to Speed Interconnection Queue

FERC on Tuesday approved PJM‘s proposal to speed up its interconnection queue by handling requests through a new clustered approach that prioritizes projects that are ready to build (ER22-2110).

Under the new paradigm, PJM will shift away from its current first-come, first-served methodology to instead study new service requests with a first-ready, first-served approach that clusters proposed projects together to determine network impacts and allocate network upgrade costs. Much of the backlog of submitted projects will be grouped into transitional cycles, which are expected to be completed in the fourth quarter of 2026.

PJM Vice President of Planning Kenneth Seiler said the RTO sees FERC’s Nov. 29 order as a win for interconnection customers, stakeholders and electric users by allowing projects to more quickly move through the queue and begin development. He credited the transparency and dialogue with stakeholders through the process of drafting the proposal with creating a solution that was accepted by the commission nearly unaltered.

“We’re very happy with how FERC has come forward with this,” Seiler said.

An Aug. 30 deficiency notice from the commission seeking more information from PJM did not affect the anticipated timeline for implementing the new transitional process, Seiler said, and staff will be discussing the next steps at the Dec. 6 Planning Committee meeting. (See FERC Issues Deficiency Letter on PJM Queue Overhaul.)

“I believe we’re well on track to move forward,” he said.

Signing off on Tuesday’s order were commissioners James Danly, Mark Christie, Willie Philips and Allison Clements, who wrote a concurrence. Only Chair Richard Glick did not participate in the order; FERC’s Division of Media Relations could not supply a reason for his non-participation.

The order also requires two compliance filings from PJM. The first, due within 30 days, calls for new tariff language codifying that only new service requests with no network upgrade costs and that do not require further studies can receive acceleration to a final interconnection-related agreement.

The second filing is due 60 days before PJM begins to study interconnection requests under its new rules, after the completion of the transitional studies.

PJM is also required to submit informational reports alongside its Order 845 filings during the transitional period, detailing its progress toward reducing the backlog. The reports are to include the number of studies completed, average completion time, the number remaining in each cycle queue and updated timelines on when the RTO expects to begin and complete each phase.

Approval Paves Way for New Rules and Transitional Process

PJM has argued that the queue changes were needed as the number of new service requests tripled from 2019 through 2022, with more than 2,700 active projects as of May 10. In a letter accompanying filing, the RTO said the current interconnection process doesn’t provide incentives for speculative projects to leave the queue in timely fashion. When such projects exit the queue late in the process, they trigger restudies impacting the cost allocation for other submissions further down the queue.

Shifting from a process of studying and allocating costs for each project individually, the new approach groups projects into clusters and conducts studies in three phases, with an increasing share of a readiness deposit required at each step equal to a portion of the network upgrade costs.

Deposits vary with the size of a project, ranging between $75,000 and $400,000. There will be “off-ramps” — or decision points — between each phase for developers who wish to discontinue their projects and partial refunds of the deposits.

Developers also are required to show evidence of site control, with escalating degrees required the further a project has progressed through the three phases. Currently, developers are only required to demonstrate site control once when submitting a project and only for the generator site.

For two queue cycles, projects that entered the queue between April 2018 and September 2021 will be studied under transitional rules, while projects valued under $5 million will be subject to a “fast track” process. PJM will begin to conduct studies under the new rules after completion of both the transitional cycles and the fast-track process.

Many protestors raised concerns about the potential for the fast track to allow less mature — and possibly speculative — projects to jump the queue over more mature, higher-cost projects. Protestors also complained that the $5 million threshold was arbitrary and that the readiness deposits are insufficient to weed out speculative submissions. (See Renewable Devs Criticize PJM Response to FERC on Queue Proposal.)

But FERC found that the interconnection rule changes strike a balance of allowing PJM to expedite its ballooning interconnection backlog, helping developers progress their projects toward construction, and letting mature projects continue under the current rules.

“PJM’s proposed transition mechanism is a reasonable means of implementing PJM’s queue reform proposal and reasonably balances the interests of completing the interconnection study processes for mature New Service Requests under PJM’s current rules with the need to move expeditiously to a first-ready, first-served clustered cycle approach in order to clear the significant backlog and begin full implementation of the New Rules,” the commission wrote in its order.

“We recognize that PJM’s proposed queue cycle cutoffs for use of the current rules and the Transition Period Rules will inevitably exclude certain interconnection customers, but, as the commission has pointed out in multiple queue reform proceedings, ‘any cutoff date inevitably will have that effect.’”

Operational Penalties Eliminated for Late Tx Service Request Studies

The approved proposal also removes tariff language outlining penalties for transmission studies that are not completed on time, which PJM argued is now unnecessary given that FERC Order 845 requires that failures to meet study deadlines be publicly reported to the commission.

Protestors contended that removing the language would contradict the commission’s interconnection notice of proposed rulemaking and said the provision would lengthen delays for firm transmission service customers. But FERC determined that removal of the tariff language meets the requirements of Order 890, as the penalties “would not necessarily target delays due to studying firm transmission service requests.”

Clements Concurs Reluctantly

Clements issued a concurring opinion in which she expressed reluctant support for approving PJM’s proposal, which she described as an imperfect solution to an interconnection queue that has “spiraled out of control.”

Clements was most concerned about the requirement that developers demonstrate 100% site control for interconnection facilities at the decision point at the end of the third study phase. She noted that commenters’ protests raised the possibility that viable projects could be removed from the interconnection queue, particularly should a generation-owning transmission owner direct a late-stage route change to force a project out of the queue.

“They argue that the site control requirement may prove to be too onerous in practice because gen-tie line sites may involve numerous small land parcels for which minor issues could come up, and because last minute changes in line routes may occur. PJM’s untested approach appears to be unique among RTOs,” she said.

Clements’ also expressed concerns about the elimination of penalties for transmission service request studies that do not meet their deadlines, a revision she said only complies with the commission’s Order 890 due to the “unique circumstances of PJM’s interconnection process.”

To create an interconnection process that meets the needs of customers, she said the approved proposal should be viewed as “one step upon which several others could conceivably be layered.” She encouraged PJM and other RTOs to consider implementing forward-looking study processes that would provide those applying for interconnection with a more information that is less prone to unpredictable changes based on changes to the queue.

“Further changes that hold potential to accelerate PJM’s interconnection queue include modifying the threshold at which network upgrades are triggered by the interconnection process, and adjustments to cost allocation for interconnection upgrades such that network upgrade costs are less likely to spur queue withdrawal,” she wrote.

November 30, 2022

NECEC Scores Another Victory in Maine’s Highest Court

Maine’s high court on Tuesday issued another favorable ruling for the New England Clean Energy Connect (NECEC) transmission project, increasing the possibility that the contentious line will be resurrected.

The decision by the state’s Supreme Judicial Court marks the second in favor of the project since August, when it found that a referendum blocking the project may have been unconstitutional. (See Maine Court Ruling Gives New Life to Contentious Transmission Line).

In Tuesday’s order, the court reversed an August 2021 decision by the state’s Business and Consumer Court to vacate a lease agreement for public lands between the Maine Bureau of Parks and Land (BPL) and Central Maine Power, NECEC’s developer.

The court said that the BPL had followed the appropriate process in approving the lease, and found that Question 1, the referendum Maine voters approved in 2021 to oppose the project, had not vacated the lease.

“Because we conclude that the evidence contained in the record is sufficient, we see no reason to impose a further burden on the parties’ time and resources by remanding for the Bureau to take further evidence,” the five-judge panel wrote. “We conclude that the record establishes that the Bureau acted within its constitutional and statutory authority in granting the 2020 lease.”

Together, this week’s ruling and the August one mark significant victories that could put the project back on track.

“We think these two decisions have resuscitated the viability of the transmission project,” ClearView Energy Partners said in a note to clients.

A legal fight over Question 1 will continue, with the Business and Consumer Court set to hear more arguments in April as to “whether or not CMP had vested rights to complete construction of transmission line,” according to ClearView.

Depending on how that decision goes, CMP could restart construction as early as mid-2023, or face the prospect of having to make another appeal to the state’s highest court.

“Today’s ruling by the Law Court is yet another step in the right direction for Maine’s renewable energy future,” Scott Mahoney, senior vice president at CMP parent company Avangrid, said in a statement.

NECEC proponents have been arguing for years that the project is necessary to transmit electricity from hydro plants in Quebec down through Maine and into Massachusetts.

“The serious need for the NECEC project to reduce our reliance on fossil fuels, combat climate change, and lower regional energy prices remains unchanged,” Mahoney said.

November 30, 2022

Ohio Lawmakers Envision a State Nuclear Development Authority

Ohio lawmakers appear to be on track to create a nuclear development authority that would promote the state as a center for companies seeking to develop small modular and other advanced reactors and engage in related nuclear research.

The effort stems from House Bill 434, which was introduced in September 2021, approved by the Ohio House on a 75-to-18 vote in May and referred to the Senate. Backers of the bill testified Tuesday before the Senate Energy and Public Utilities Committee.

Proponents contended that the federal agencies that have dominated expensive nuclear research and development will in the future look to interact with state authorities that organize R&D efforts to attract entrepreneurial nuclear research companies such as TerraPower, which was founded by Microsoft co-founder Bill Gates.

The Washington-based company is focusing on the development of reactors cooled by molten chloride salt, a technology pioneered decades ago at Oak Ridge National Laboratory but abandoned when light-water reactors proved more practical to build given the technology of the day. Proponents of the new authority cited the reactor design as the kind of advanced technology that Ohio ought to be attracting.

William Thesling, an electrical engineer and lifelong Ohio resident, singled out molten salt reactors in his testimony.

“A goal of House Bill 434 is to make Ohio a leading state in advanced nuclear technology research, development and commercialization,” Thesling said.

“This has some enormous long-term benefits for Ohio as a manufacturing state,” he said. “There has been much advancement in materials technology, digital controls, sensors, instrumentation and computer modeling over the past several decades. These gains in technology have allowed us to revisit old technologies that were previously considered to be not viable. Nowhere is revisiting an old technology more compelling than molten salt reactor technology that was abandoned in the early 1970s largely for political reasons.”

Other proponents argued that U.S. Department of Energy and the Nuclear Regulatory Commission would, under a provision in the 1954 Atomic Energy Act, be obligated to work with a state authority such as what Ohio intends to create.

A spokesman for the NRC had no immediate comment other than that the agency does not normally comment on state issues. A DOE spokesperson could not be reached.

The next hearing by the Senate committee, which has not yet been announced, will focus on opposing testimony.

HB 434 is the work of Rep. Dick Stein (R), who argued that there has been a change in public sentiment about new nuclear technologies.

“In recent years, there has been a global shift in attitudes toward the development of new nuclear technologies to deploy scalable clean energy,” Stein said in a prepared statement. “This legislation will bring Ohio to the forefront of advanced nuclear innovation and strengthen our domestic supply chains.”