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November 18, 2024

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PG&E Ends Probation as a ‘Menace to California,’ Judge Says

Pacific Gas and Electric (NYSE:PCG) ended five years of probation Tuesday night with the judge in charge lamenting that California’s largest utility had caused more damage on probation than it had before it was sentenced.

PG&E was placed on probation in January 2017 after being convicted of six felonies related to the San Bruno gas explosion, which killed eight people and destroyed a suburban San Francisco neighborhood in September 2010.

“While on probation, PG&E has set at least 31 wildfires, burned nearly 1.5 million acres, burned 23,956 structures and killed 113 Californians,” Judge William Alsup, of the U.S. District Court for Northern California, wrote in his parting comments on the case.

The utility pleaded guilty to 84 manslaughter charges in the 2018 Camp Fire, which leveled the town of Paradise, Alsup said. It faces five felony counts in the 2019 Kincade Fire in Sonoma County and four manslaughter charges from the 2020 Zogg Fire in Shasta County. The Dixie Fire, ignited by PG&E equipment last summer, was the second largest in state history at nearly 1 million acres and will likely result in lawsuits and possibly criminal charges, he said.

“So, in these five years, PG&E has gone on a crime spree and will emerge from probation as a continuing menace to California,” Alsup said.

“Rehabilitation of a criminal offender remains the paramount goal of probation,” he said. “During these five years of criminal probation, we have tried hard to rehabilitate PG&E. As the supervising district judge, however, I must acknowledge failure.”

Alsup told federal prosecutors on Jan. 3 that he would give “serious consideration” to a request for more probation time based on the state criminal charges against PG&E, but the U.S. Attorney’s Office decided not to seek an extension. (See Judge Refrains from Adding Time to PG&E Probation.)

PG&E Responds 

In a November court filing, PG&E assessed its own progress on probation, often in contrast to the judge’s remarks.

“PG&E acknowledges, deeply regrets and owns the tragic consequences of the wildfires caused by its equipment,” it said. “The company has taken a stand that catastrophic wildfires shall stop.” But during the past four years, thanks in part to the court’s supervision, its “electric grid is fundamentally safer.”

“PG&E believes it is on the right path,” it said. With its 70,000-square-mile service territory and the speed at which climate change appears to be impacting Northern California, there are “no fast or fail-proof options,” but the utility insisted it has changed.

PG&E is now “led by a board and senior management team that is new compared to those in place at the time of the San Bruno tragedy, the North Bay fires [in October 2017] and the Camp Fire,” it said. “Recognizing the need for the best thinking on operations, safety and risk, the company has hired leaders from stable, safe and operationally excellent utilities around the country,” including new CEO Patti Poppe, former head of CMS Energy in Michigan.

PG&E cited its use of public safety power shutoffs to prevent ignitions, which it did not use in 2017 but now employs widely in fire season along with fast-trip sensors to shut down power lines when faults occur.

The utility contended it has greatly improved its vegetation management. Trees and limbs falling on power lines have caused many of the major fires in the past five years.

“Between 2017 and 2021, PG&E increased spending on vegetation management from approximately $440 million a year to approximately $1.4 billion, representing an over 200% increase,” it said. “The total number of employees and contractors dedicated to vegetation management rose from 4,446 in 2019 to 10,265 in 2021.

“These unprecedented monetary and workforce investments have resulted in a significant amount of additional work,” it said. “In 2021, PG&E has removed or trimmed over 1.63 million trees as of Oct. 31 and forecasts it will remove or trim 1.82 million trees in total by year-end, a 20% increase over the 1.52 million trees worked in 2019.”

Alsup, however, said tree trimming remains one of the utility’s biggest problems.

“We remain trapped in a tragic era of PG&E wildfires because for decades it neglected its duties concerning hazard-tree removal and vegetation clearance, even though such duties were required by California’s Public Resource Code,” Alsup said. “In time, this neglect led to hazard trees and limbs falling on its distribution lines and sparking wildfires or becoming ‘ground faults,’ wherein the tree remains against a live wire and conducts sufficient electrical power to the earth to overheat and explode in flames.

“PG&E’s backlog of unattended trees and vegetation was staggering at the outset of probation,” he said. “As probation ends, PG&E remains at least seven years, [in] my estimate, from coming close to being current. During its criminal probation, all or virtually all of the wildfires started by PG&E distribution lines have involved hazard trees.”

The Camp and Kincade fires were started by broken transmission lines that ignited dry vegetation, he noted.

Alsup said he believes a “systemic cause” of distribution-line fires has been PG&E’s outsourcing of tree trimming and line inspections.

“A large part of the wildfire problem, as the [court-appointed] monitor has pointed out, has been sloppy inspection and clearance work, almost exclusively outsourced to independent contractors,” he said. PG&E should hire and train “as many arborists as are needed to fully comply with California’s Public Resource Code,” and the state should outlaw or restrict outsourcing.

The utility’s size is another problem, Alsup continued. PG&E operates 107,000 circuit miles of distribution lines and 18,500 miles of transmission lines, with about half its territory in high fire-threat districts.

Alsup said he has “come to fear” that PG&E should be split into at least two entities, one to serve fire-prone areas and one or more to serve the rest of its 5.5 million electric customers.

“Less sprawling utilities would be easier to train and to instill practices and procedures that truly put safety first.”

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Dueling Bills Have Different Takes on Wash. Siting Council

Two Washington bills seek opposite outcomes for the state’s Energy Facility Site Evaluation Council (EFSEC).

The council, comprising representatives from several state agencies, makes recommendations to the governor for final decisions on the placement of solar farms, wind turbines and other energy resources.

If a wind or solar developer opts to seek state approval instead of obtaining county permits, it can bypass county governments by going through EFSEC. Or a developer can choose to have the appropriate county government handle the permitting, sidestepping EFSEC. 

Rep. Mark Klicker (R) has introduced one bill (HB 1871) to stop EFSEC from reviewing solar and wind projects until late 2023 after a task force studies the issue.

Klicker represents much of Benton County, where heavy opposition has surfaced to the Horse Heaven Hills wind turbine proposal — mostly because many residents of Washington’s Tri-Cities area don’t want to see windmills on their southern horizon. (See Wind Project Sows Controversy in Horse Heaven.) That bill showed up at a Tuesday public hearing before the House Environment and Energy Committee. 

Also on Tuesday, the same committee heard testimony that mostly supported a bill (HB 1812) by Rep. Joe Fitzgibbon (D) that would bolster the authority of EFSEC while also boosting tribal participation in reviews when needed. Fitzgibbon is the committee’s chairman, meaning his bill has the better chance of moving beyond the committee.

On Knicker’s bill, Tuesday’s testimony stressed that Eastern Washington residents believe that wind and solar farms chip away at their tax bases and that their region is being unfairly targeted to provide most of the state’s alternative energy sources. Critics of EFSEC argue the council is not receptive to local concerns. Habitat concerns did not pop up in the hearing.

“You guys are in too big of a hurry to meet climate change goals,” said Klickitat County Commissioner Dan Christopher. Josh Weiss, a lobbyist for Benton County said, “Local planning is capable of dealing with these projects.” 

“It does things to the people of rural Washington instead of doing things for them,” said Dave Barta, representing the Farm Bureau for Klickitat and Yakima counties. 

However, EFSEC Chair Kathleen Drew said the council has approved only three wind and solar projects so far with only a handful still under review. “The vast majority of wind and solar [projects] have gone before the county governments. I believe [EFSEC’s] siting process is the most thorough environmental review.”

Testimony on Fitzgibbon’s bill was overwhelmingly in favor of the legislation. There was very little overlap between the people testifying on the two bills. The bulk of the support came from labor and environmental organizations.

“We’re for any effort to bring speed and certainty to the process,” Matt Steuerwalt of NextEra Energy Resources said. Kelly Hall of Climate Solutions said, “We need to consolidate bringing new jobs to the state.”

The bill would take EFSEC out of the umbrella of the Washington Utilities and Transportation Commission and provide it with its own separate budget. It would also add pipelines to its jurisdiction, streamline some procedures and bolster tribal participation in matters affecting the Native American tribes.

The hearing also produced the only mention of concerns about solar and wind projects encroaching on sensitive wildlife habitat. The Washington Department of Fish and Wildlife said routing the process through EFSEC would provide stronger protections for habitat.

The Tulalip, Yakama and Puyallup nations warned against streamlining the review process too much, not wanting the state to rubber-stamp proposals.

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San Francisco Wins Against FERC, PG&E in DC Circuit

The D.C. Circuit Court of Appeals overturned FERC on Tuesday in two cases brought by the city and county of San Francisco against Pacific Gas and Electric (NYSE:PCG) for failing to deliver electricity to customers in violation of its wholesale distribution tariff (20-1084).

In one case, the city contested PG&E’s refusal to provide lower-voltage secondary service to many sites within the city. San Francisco filed a complaint with FERC in January 2019 alleging PG&E had consistently refused to make new interconnections at secondary voltage unless the total electricity demand was less than 75 kW.

PG&E instead offered to connect higher-voltage primary service, which requires the installation of transformers and carries higher fixed costs for ratepayers, San Francisco said. The city argued that the practice violated PG&E’s tariff because it requires the utility to offer secondary service when requested and to expand its infrastructure where necessary.

The company argued that it did not categorically deny secondary service in cases where demand exceeded 75 kW and said its denials in some cases were based on technical, safety and reliability concerns.

FERC denied San Francisco’s complaint, ruling that PG&E should decide what level of service is appropriate for customers.

“While the [wholesale distribution tariff] does not preclude a … customer from requesting the level of service that it wishes to take, PG&E, as the wholesale distribution service provider, is ultimately responsible for the safety and reliability of its distribution system,” FERC wrote in its April 2020 order (EL19-38). “Accordingly, we find that it is appropriate for PG&E, as that provider, to have discretion to determine what level of service is both appropriate and available based upon the status and configuration of its existing wholesale distribution system facilities and the nature and location of the interconnection request.”

The initial decision, as well as its order on rehearing that upheld it later in September, were unanimous among the commissioners at the time, which included current Chair Richard Glick (D) and Commissioner James Danly (R).

But in an opinion written by D.C. Circuit Judge Judith Rogers, a three-judge panel found that FERC failed to scrutinize the safety and reliability risks cited by PG&E. The judges also rejected PG&E’s contention that it decides appropriate voltages case by case.

“Evidence before the commission showed that since 2015, many of San Francisco’s new interconnection requests exceeding 75 kW have been denied secondary service by PG&E, and that the proportion of new interconnections above 75 kW receiving primary service has increased since 2015,” the court said. It cited a July 2019 letter written by PG&E to San Francisco saying it was no longer “willing to make additional accommodations” for secondary service.

“The July 1, 2019, letter hardly indicates that PG&E intends to evaluate San Francisco’s applications on a case-by-case basis,” the court wrote.

On rehearing FERC had said the “75-kW threshold is merely a ‘guidepost,’ while reaffirming its position that PG&E makes case-by-case determinations of which voltage to provide,” the court noted.

“Even if the 75-kW threshold is a guidepost, however, that kind of numerical threshold is the type of requirement that the ‘rule of reason’ requires be stated in the tariff,” the court said.

“Because the commission did not adequately explain any operational or engineering rationale justifying PG&E’s 75-kW ‘guidepost’ and did not explain why that guidepost did not need to be in the filed tariff, the court vacates the voltage orders and remands the case to the commission for further proceedings consistent with this opinion,” it said.

Grandfathering Service

In the second case, which was consolidated with the first, San Francisco argued that PG&E had denied service to delivery points that were eligible for it under a tariff grandfathering provision.

In interpreting the provision, PG&E cited the tariff’s reference to Federal Power Act Section 212(h), which prohibits mandatory retail wheeling with certain exceptions.

“No order issued under this chapter shall be conditioned upon or require the transmission of electric energy directly to an ultimate consumer … unless such entity was providing electric service to such ultimate consumer on Oct. 24, 1992,” the FPA says.

PG&E said that meant it had to serve end users it served in 1992 but not those that had moved. San Francisco argued the tariff requires PG&E to serve even those customers that had relocated since 1992.

A FERC administrative law judge interpreted the FPA, given prior FERC orders, as supporting San Francisco’s argument “that grandfathering applies to the class of customers that was eligible to receive wholesale distribution service on Oct. 24, 1992, regardless of where in the city those customers may be located now or in the future.”

FERC reversed the ALJ’s decision, agreeing with PG&E’s interpretation of the tariff’s grandfathering provision.

The court, however, said FERC’s interpretation of the tariff was too narrow and its “attempts to defend its interpretation [were] unpersuasive.”

“That the tariff references ‘points of delivery’ does not necessarily imply that only specific points of delivery may be grandfathered, and those references to ‘points of delivery’ do not change the fact that the tariff expressly references the criteria of Section 212(h)(2),” it said.

The court criticized FERC’s orders in the case as demonstrating a “troubling pattern of inattentiveness to potential anticompetitive effects of PG&E’s administration of its open-access tariff.” Faced with claims that PG&E was refusing service to San Francisco customers, FERC “fell short of meeting its duty to ensure that rules or practices affecting wholesale rates are just and reasonable,” it said.

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DOE Initiatives to Rev up $1B in Community Solar Savings

Energy Secretary Jennifer Granholm was at the National Community Solar Partnership’s Annual Summit on Tuesday to announce the Department of Energy’s latest initiatives aimed at deploying enough community solar in the next three years to provide $1 billion in savings for 5 million U.S. households.

According to the DOE, the U.S. currently has about 5.2 GW of community solar online across the country, but hitting the NCSP’s ambitious target will require getting to 20 GW by 2025.

The three initiatives announced Tuesday are intended to overcome key barriers to deployment: expanding state-level programs, improving access to finance and providing technical assistance to community organizations and other stakeholders to accelerate development of these projects.

“Not everybody can put solar panels on the roof,” Granholm said at the virtual summit. “And too many of those folks are in lower-income communities and communities of color. They don’t have to be left out, and we’re going to make sure that they won’t be. With community solar, we can give them access to clean and cheap solar energy, all at the same time.”

The DOE also wants to double household savings from community solar from the current average of 10% to 20%, which is about the same level of savings as residential solar owners get from their panels, said Kelly Speakes-Backman, principal deputy assistant secretary for energy efficiency and renewable energy.

The three initiatives announced at the summit include:

  • A States Collaborative, which will support the development and expansion of state-level community solar programs. State energy officials and program administrators from about half the states and the District of Columbia will be part of the group.
  • The Credit Ready Solar Initiative, which will enlist lenders, philanthropic organizations and community solar developers to improve projects’ access to financing, especially for projects serving low-to-moderate income communities.
  • The NCSP Technical Assistance program, which will provide $2 million in rolling grants to program partners to “help them accelerate implementation, improve the performance of their program or project, and build capacity for future community solar development,” according to a DOE press release.

A Concentrated Market

Community solar allows individuals or groups who cannot put solar on their roofs — such as commercial or residential renters — to subscribe to a project, often located in or near their community, and get a credit on their utility bills for a portion of the electricity produced. According to the DOE, 22 states and the District of Columbia have policies that allow community solar, but four states — Minnesota, Florida, Massachusetts and New York — account for nearly three-quarters of the existing market.

That concentration is why the DOE’s States Collaborative is so important, Illinois Gov. JB Pritzker (D) said at the summit.

“When states can access each other — share best ideas, work together — it will reduce barriers to expanding community solar,” Pritzker said. “Knowledge sharing is critical for us. … The more we can learn from each other across the states, the more quickly we can grow more effective programs.”

Projects being developed under Illinois’ Solar for All community solar program are specifically targeted at low-income households, nonprofits and public facilities, he said.

Victor Rojas, senior vice president at Sustainable Capital Advisors, said the Credit Ready initiative will address a long-standing gap in private investment in community solar.

Community solar developers need to ask not only whether projects are shovel-ready,” but are the projects … actually accessible to capital and developed and framed in such a way that capital finds attractive,” Rojas said. “We just haven’t done a good job doing that to date.”

In yet another announcement, Granholm said the Coalition for Community Solar Access (CCSA) has committed to meeting the DOE’s goal of 20 GW of projects online by 2025.

In the DOE press release, CCSA CEO Jeffrey Cramer said 80 community solar providers will be working with the organization to accelerate project deployments. “With the combination of the DOE’s … initiatives and the adoption of other critical actions by state and federal policymakers, industry can meet this goal and satisfy pent-up demand,” he said.

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FERC Directs More Clarity in Order 864 Filings

FERC last week approved NorthWestern Corp.’s (NASDAQ:NWE) compliance filing under a commission order that ensures transmission formula rates properly address excess and deficient accumulated deferred income taxes (ADIT) resulting from current and future tax-rate changes (ER20-1090).

The ruling was one of three FERC issued on Thursday related to Order 864. The 2019 directive required public transmission providers with formula rates under a tariff or rate schedule to make revisions accounting for changes caused by the Tax Cuts and Jobs Act of 2017. The order also directed entities to include a mechanism in their rates that deducts any excess ADIT or add any deficient ADIT to their rate base.

The commission found that NorthWestern partially complied with Order 864’s requirements and directed the company to make a further compliance filing within 60 days.

NorthWestern proposed incorporating two new worksheets addressing Order 864’s requirement for a rate base adjustment mechanism, a summary worksheet and a worksheet specific to each tax change. It also said it would add another worksheet calculating the excess and deficient ADIT.

FERC said NorthWestern’s adjustment mechanism did not fully apply to any future tax rate changes giving rise to excess or deficient ADIT and ordered it to include “deficient ADIT” in the summary worksheet. The commission also directed NorthWestern to include “deficient ADIT” in its tax allowance adjustment mechanism.

That latter mechanism allows a transmission company to decrease or increase its income tax component by any amortized excess or deficient ADIT, respectively. FERC found NorthWestern’s formula description did not accurately reflect the formula in a separate worksheet and ordered it to make revisions.

The commission also ordered the company to include “deficient ADIT” in the notes of its summary worksheets.

PacifiCorp Partially Rejected

FERC also rejected parts of an Order 864 compliance filing by PacifiCorp (NYSE:BRK.A) because of worksheet shortcomings and directed the utility to submit an additional compliance filing in 60 days (ER20-1828).

The commission found PacifiCorp’s ADIT filing did not comply with Order 864’s categories 1 and 2 worksheet requirements.

In category 1, “Order No. 864 required public utilities to include in their permanent ADIT worksheets ‘how any ADIT accounts were remeasured and the excess or deficient ADIT contained therein,’” FERC said.

PacifiCorp’s proposed ADIT worksheets did not demonstrate how any ADIT accounts were remeasured but only showed the “excess and deficient ADIT contained therein, and then allocated the ADIT amounts to transmission without providing additional illustration or explanation of their calculations,” FERC said.

To satisfy the category 1 requirements, PacifiCorp “must provide the pre-tax rate change and post-tax rate change ADIT account balances, in addition to the resulting excess and deficient ADIT already provided,” the commission said. “Further, such information must be provided at a level of detail such that interested parties can identify the source (i.e., the originating accounts) of excess or deficient ADIT in the proposed ADIT worksheet and verify excess and deficient ADIT resulting from the Tax Cuts and Jobs Act and future tax rate changes.”

In category 2, PacifiCorp identified end-of-year balances of excess and deficient ADIT but did not provide the full accounting for any unamortized excess or deficient amounts, FERC said.

“Specifically, the ADIT worksheets do not display the gross-up on unamortized excess and deficient ADIT included in these accounts,” it said. “As such, in the compliance filing ordered below, we direct PacifiCorp to display the gross-up on excess and deficient ADIT included” in two specified accounts.

Duke Partially Approved

Finally, the commission partially accepted Duke Energy Ohio/Kentucky’s (DEOK) (NYSE:DUK) proposed revisions to its transmission formula rate, directing a further compliance filing within 60 days (ER20-1832).

DEOK argued its existing formula rate included a rate base adjustment mechanism for several of its accounts “as adjusted by any amounts in contra accounts identified as regulatory assets or liabilities.” But DEOK proposed adding language to an existing account “to maintain rate-base neutrality in the event of a change to income tax rates” and that the account balance would be derived form the new ADIT worksheet it proposed to comply with Order 864.

The compliance filing proposed adding language to the formula rate “to incorporate the amortization of excess and deficient ADIT into the income tax calculation, in order to return or recover excess/deficient ADIT.” DEOK also proposed incorporating a new permanent ADIT worksheet into its formula rate that would annually track information related to its “protected and unprotected deficient deferred income tax” and to provide an “informational reconciliation of accounts remeasured as a result of federal and state income tax rate changes.”

American Municipal Power (AMP) made several protests of the filing, alleging that DEOK may be retaining a portion of excess ADIT because of the Kentucky corporate income tax rate changing from 6% to 5% in 2018. AMP said DEOK “improperly amortized certain excess ADIT related to that change,” requesting that the commission require DEOK to refund the amounts with interest and recalculate its 2019 annual update “because DEOK has not ensured rate-base neutrality.”

The commission found that the utility’s rate-base adjustment mechanism partially complied with Order 864, saying the mechanism “allows DEOK to deduct any excess ADIT calculated in the proposed ADIT worksheet from rate base, thus preserving rate-base neutrality for that component” and that it may be applied to “any future federal tax rate changes that give rise to excess or deficient ADIT.”

But it also said it agreed with AMP that the mechanism does not reflect the 2018 Kentucky excess ADIT as a “contra” in several accounts “instead of using its proposed rate-base adjustment mechanism.”

The commission said DEOK’s proposal “does not show how much of the 2018 Kentucky excess ADIT ultimately were included in other components” of the rate and how it meets the requirements of the ADIT worksheet.

It directed DEOK to show how its proposal for the state tax rate changes are consistent with the requirements of Order 864, including “how transmission customers will receive the full amount of both protected and unprotected excess ADIT balance to be returned to transmission.”

FERC also found that DEOK’s ADIT worksheet partially complied with Order 864, directing more changes. While the worksheet shows adjustments from the originating ADIT accounts to the regulatory asset and liability accounts, it does not include the beginning balance of the remeasured ADIT amounts, the commission said.

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FERC Weighs in as ISO-NE Prepares for Capacity Auction

FERC on Friday accepted ISO-NE‘s  informational filing for its upcoming capacity auction, turning down petitions by two companies to adjust their offers and taking the opportunity to once again call for elimination of the RTO’s Minimum Offer Price Rule (MOPR).

FERC’s order ahead of the Feb. 7 auction rejected a protest by Borrego for its Wendell Energy Storage Project (ER22-391). The solar and storage company argued that its offer floor price should be adjusted to account for a battery storage investment tax credit (ITC) that could be included in the Biden administration’s Build Back Better Act. FERC denied the request because the bill has not become law.

The commission also turned down a protest from Anbaric and Massachusetts Municipal Wholesale Electric Company (MMWEC) over their Westover Energy Storage Center. They argued that ISO-NE’s Internal Market Monitor inappropriately mitigated their proposed offer floor price to the offer review trigger price (ORTP) for storage.

Another Push on the MOPR

FERC Chairman Richard Glick and Commissioner Allison Clements wrote a separate concurrence to once again urge ISO-NE to remove its MOPR.

The two have been pushing both New England and PJM to get rid of the rules, which they say are uncompetitive and prop up incumbent generators.

The rule in New England, they wrote, makes the RTO’s existing tariff unjust and unreasonable. They argue that the MOPR is overly broad and goes beyond preventing market-side buyer power and into punishing legitimately low capacity offers.

The FERC commissioners deferred to ISO-NE’s process for replacing the MOPR.

“We think it prudent to give the ISO an opportunity to replace the existing MOPR with a solution of its choosing. After all, under the FPA, one size need not fit all and different regions of the country may choose different approaches to addressing the problem of actual buyer side market power,” they wrote.

But they urged ISO-NE to move “expeditiously.”

A proposal to eliminate the MOPR is moving through the NEPOOL stakeholder process and is up for a vote at the Participants Committee next week. (See NEPOOL MC Approves ISO-NE Plan to Eliminate MOPR.)

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Hydrogen Emerges as Crucial Component for Achieving Net Zero

An expansion of nuclear power, as well as more natural gas-fired power generation in developing nations, appear to be two technologies crucial to achieving global net-zero carbon emissions by 2050.

Oil, both as a fuel and chemical feed stock, isn’t going to disappear in the near or medium term, if only because so many of the world’s economies are tied to it.

And hydrogen, perceived as a long shot at the start of the Biden administration, is emerging as the one element thought to be capable of bridging multiple technologies, solving storage for renewable power, for example, while also replacing natural gas and gasoline as fuels.

These are some of the assertions that emerged during a four-day series of webinars produced last week by the Atlantic Council to coincide with the annual Abu Dhabi Sustainability Week. The four hours of rapidly paced discussions were also a prelude to the 27th U.N. Conference of Parties (COP27) scheduled for November in Egypt.

The 2022 Global Energy Agenda

Majid Hamid Jafar, CEO of Crescent Petroleum, based in the United Arab Emirates, said the long-term oil supply situation is the larger and more important question because the switch to renewables is going to take many years.

He said “climate activism” has damaged the infrastructure of the oil and gas industry.

“There are always short-term geopolitical impacts and volatility when it comes to energy markets. That’s always been the case and likely always will be the case.

“My bigger concern is the longer-term trends we’re seeing in the underinvestment: 25% lower investment in the upstream [exploration and production] than pre-COVID, but half the level of a decade ago.

“I think there needs to be this realization that oil and gas is still going to be needed,” he said. “It’s just how we produce it will be cleaner, and how we use it will be different.”

He said Crescent has gradually transitioned more from oil to gas. “We’re now at 85% gas. We reduced our flaring to near zero, and by offsetting the remainder we actually declared net zero not in 2050 but last October.

“The gas we actually produced in the region displaces diesel for electricity that actually avoids more emissions than all the Teslas on the planet,” he said.

“I think that impact is underappreciated. Yes, solar and wind power costs have come down, and they’re very promising. But the energy from them can’t be stored. So you need stable background sources like natural gas or nuclear as the U.S. energy policy has demonstrated.

“And on the oil side, even if cars become electric, they’re still made from products of oil, as are solar panels [and] wind turbines, and if we just look at the COVID pandemic, everything we’ve relied on, from smartphones, masks, sanitizers and vaccines, are all made from oil products,” he said.

In response, Francesco La Camera, director-general of the International Renewable Energy Agency, said the global oil industry lacks resilience. But he argued that the solution is moving more quickly toward renewables.

“What are the technologies that today are most competitive and cheapest way to produce energy? What are the technologies that ensure more resilience in the system?” he asked rhetorically.

“What are the technologies that can assure us to be in line with the Paris Agreement goals? What are the technologies that ensure that the energy transition will also … reduce the inequality existing today in the world?

“And as far as I can answer, the only way … is going faster and faster toward renewables.”

Hydrogen: Energy System Integrator?

The role hydrogen might play in decarbonizing transportation, stabilizing electric grids dependent upon increasing amounts of wind and solar generation, and eventually displacing natural gas in heavy industry was the focus of the Jan. 20 discussion.

“Our aim is to look at how hydrogen could become an energy system integrator,” Randolph Bell, director of the Global Energy Center at the Atlantic Council, said in opening remarks “tying together the worlds of electrons and molecules, leveraging the expertise of both the hydrocarbon and renewable energy sectors, and decarbonizing hard-to-abate sectors.”

That hydrogen has stirred global excitement was evident during the discussion.

Marco Alvera, CEO of SNAM, an infrastructure company headquartered in Milan, said the question of hydrogen’s future was “spot on.”

“We’ve had for too long a debate whether it was going to be molecules [or] electrons,” said Alvera, who wrote a book published last year, titled “The Hydrogen Revolution.”

“Because it’s a molecule, [and] you can make it with electrolyzers through electrons, you’re simply bridging the gap and that really helps the sector coupling. …

“Hydrogen allows us to produce great quantities of renewable energy, where there’s no grid, where there’s no market, and we can … produce hydrogen from the renewable energy. And we can easily transport that hydrogen — whether through liquid hydrogen, through [converting it to] ammonia, through methanol, or directly via pipes — we can move it to where the markets are.”

SNAM operates 30,000 miles of pipeline in half a dozen European nations and has already blended up to 10% hydrogen with natural gas. It has also done an engineering assessment of its system, determining that 99% of its pipeline system could run pure hydrogen, he said.

“The quality of the steel that was used in the ’70s, ’80s and ’90s to build our natural gas pipelines [is] exactly the same that we would use today to build a dedicated 100% hydrogen pipeline,” he explained.

The company has plans for enormous expansion.

“We have committed to our investors to have a hydrogen backbone to be able to move green hydrogen molecules from North Africa into Europe before 2030,” he said.

Pipeline companies in the U.S. will probably have to replace existing gas lines because the steel in the lines is harder than what was used in Europe in recent decades and could become brittle transporting hydrogen, Alvera said.

But that would not likely be as expensive as it sounds, he added, because the new lines could run in existing rights of way, side by side with the gas line, or even inside the old lines.

Wind to Hydrogen to Liquid Fuel

Houston-based Highly Innovative Fuels (HIF) is a company with big plans to make liquid fuels from hydrogen produced from water in electrolyzers using power produced by wind.

HIF has a project planned for Texas where site selection is underway, one planned for Australia and another in Chile where a plant is already under construction.

In Chile, the capacity factor of wind turbines is 75% (compared to 45% in Texas), said Meg Gentle, the company’s executive director. That means the wind farm will not have to be overbuilt to compensate for as much down time. And that means less expensive power to run the electrolyzers producing the hydrogen.

“We will be combining the hydrogen with CO2 that we will capture from the atmosphere,” Gentle said. “And when you do that recombination, you have methanol, which can easily be synthesized into gasoline, eventually into jet fuel or, in fact, used by the shipping industry simply as methanol. So, it creates a way to convert electricity into liquid fuels.”

Hydrogen Production in the Middle East

HIF will likely find itself competing with Middle Eastern companies, including one headquartered in Abu Dhabi that has similarly big plans.

“We have been a country that relied for decades on the rich hydrocarbon resources. This [hydrogen] gives us an opportunity to transition to a clean energy supply system,” said Alexander Ritschel, head of technology at Masdar Clean Energy.

He said his company will use the expertise and infrastructure it developed to move oil and refined products to instead transport hydrogen-based products, including aviation fuel.

He added that the company will make both green hydrogen with electrolysis and blue hydrogen, made from methane. And it has begun projects to make hydrogen from renewable methane made from municipal waste.

Moving the hydrogen out of the Middle East won’t be a problem, he said. “We have a lot of international sea routes, leaving from the UAE, going to all destinations in the world.

“But most importantly, the UAE is known as an aviation hub; we have one of the largest airlines in the world. We have launched a pilot project now … producing sustainable aviation fuel, purely made with solar electricity, [hydrogen] and recycled CO2,” Ritschel said.

Pathways to Net Zero

Friday’s webinar looked a little more closely at the range of strategies that nations, by resource necessity or for reasons of security, are expected to choose on the way to achieving net-zero carbon emissions.

“Our panelists will explore how different geographies, resource endowments, politics, financing and so on can impact a country’s net-zero strategies,” the Atlantic Council’s Bell explained in opening remarks.

Moderator Ryan Heath, a senior editor at POLITICO, noted that governments appear to be ahead of companies in figuring out exactly what net zero means and how they might reach it.

Quoting a recently released PricewaterhouseCoopers global CEO survey, Heath noted that when all business sectors are included, rather than just energy companies, only about a quarter of companies have actually created a net-zero target.

Melanie Nakagawa, special assistant to President Biden and senior director for climate and energy on the National Security Council, said governments are “trying to shape a policy landscape that can help enable other companies and entities to put forward their own net-zero targets.”

“We can create a demand pool for … innovative technologies, and we can be the enabling environment in many countries around the world for investment.”

One administration effort to create that “enabling environment” that garnered a lot of attention at last fall’s COP26 in Scotland was a commitment to immediately work to reduce “fugitive” methane emissions, the majority from oil and gas operations, by 30% by 2030. More than 100 nations formally agreed to the commitment.

Alain Ebobisse, CEO of Africa50, the infrastructure investment platform capitalized by the African Development Bank and more than 20 African nations and central banks, echoed Nakagawa and the Biden administration’s goals but stressed that solving energy shortfalls immediately is just as important as figuring out a future net-zero strategy.

Noting that Africa as a continent “contributes roughly 4% of global emissions” and that the majority of Africa50’s energy investments are already developing renewable technologies, Ebobisse stressed that many African nations are in the middle of an energy crisis, partly because of a global natural gas shortage.

Arguing that more natural gas infrastructure must be developed, Ebobisse said cooking gas prices in many African nations have nearly doubled, from $9 to $17, for a 12.5-kg canister and that people are switching to firewood and charcoal, which is adding carbon pollution.

“The main point that I would like to make is that we believe that natural gas should be part of the transition fuel solution, because of course it’s the cleanest burning fossil fuel, but also because it can … provide baseload power that works well with intermittent renewables,” he added, echoing an argument often made by the gas industry.

Brice Raisin, head of sales for GE Gas Power in Europe, the Middle East and Africa, built on Ebobisse’s assertion.

He said utilities and power generators face a “trilemma”: a growing demand for electricity; the obligation to provide reliable, affordable and sustainable power; and now net-zero targets.

Gas generation, he said, can provide the fastest solution to the problem while the buildout of solar and both on- and offshore wind continues and small modular nuclear reactors are deployed.

And, in a nod to the potential of hydrogen, Raisin added, “When you invest in a gas plant, you don’t invest in a plant that will always emit CO2. You invest in a plant that technologically is able to burn all the types of fuel.”

Tim Holt, a member of the executive board and labor director at Siemens Energy, agreed with Raisin, adding that the ability of the industry to quickly build new gas turbine power plants would give renewable technologies the time to continue efficiency improvements.

Adam Sieminski, a senior adviser to the King Abdullah Petroleum Studies and Research Center’s board of trustees, further buttressed the argument for continued use of fossil fuel.

“Hydrocarbons and net zero are not incompatible,” said Sieminski, a long-time energy analyst, former U.S. Energy Information Administration administrator and National Security Council member under President Barack Obama.

“Net zero does not mean no hydrocarbons. What it means is controlling the carbon from those hydrocarbons. I think at some point, we’re going to go to below zero. Right? We want to have negative emissions, but that still doesn’t mean [no] hydrocarbons.

“Alain mentioned that in Africa, natural gas is a good solution. Look, there’s more than a billion and a half people who don’t have clean cooking fuels. Propane might be [an] answer to that,” he said.

“Let’s figure out a way to deal with the carbon associated with the propane. Carbon is not the enemy. There’s living carbon … trees and breathing. There’s durable carbon that locks up the carbon, and it doesn’t create a climate problem. The problem is fugitive carbon. The problem is not the fuel,” he argued.

“Concentrate on the solutions: Direct air capture and nuclear and green initiatives are a way to accomplish that. We just have to push the cost down.”

Completing the circle of that argument, Sama Bilbao y Leon, director general of the World Nuclear Association, noted that energy technologies are rapidly changing.

“I think that the energy systems of the future are not really going to look very much like the energy systems that we are used to right now. We are trying to electrify a lot of things. We are going to see a lot of coupling between electrical grids and mobility. Hydrogen is going to play a role.

“I think there’s a real need for political leadership and pragmatic leadership. We really need to be very much technology-neutral. We need to put in place both policies and market structures. We need to look at what technology can support the system,” she said.

“Obviously, we are really going to need all proven low-carbon technologies, including of course, nuclear. There is not going to be not one size that fits all. Countries are going to pick the energy mix that fits best: their natural endowments; their socioeconomic situation; their cultural preferences. So obviously, there’s going to be a huge diversity,” she said.

“I think that advanced economies are going to have to focus on decarbonizing; however, when I look at emerging economies, I think their focus needs to be energizing.”

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Overheard at USEA State of the Energy Industry Forum

The U.S. has a broad and diverse range of energy resources, and all of them — from coal and gas to nuclear and renewables — are critical to the nation’s clean energy future.

That was the message coming out of the U.S. Energy Association’s 2022 State of the Energy Industry Forum on Thursday, where industry leaders said the sector also creates thousands of well-paying jobs that support families and communities.

Those leaders were mostly buoyed by passage of the bipartisan Infrastructure Investment and Jobs Act and individually supported various energy provisions in the stalled Build Back Better Act, which they say have broad, bipartisan support.

Another common theme during the day-long forum: the need to collaborate across industry sectors and with regulators and lawmakers.

Julia Hamm, CEO of the Smart Electric Power Alliance, said that almost 70% of U.S. consumers are now served by an electric utility that has committed to a 100% carbon reduction target. But the utilities making the most progress toward those goals are the ones partnering “outside the four walls” of their organizations and engaging with stakeholders “in a way in which it’s never happened before.”

“We really need to see utilities partnering together with technology companies, with their customers, with environmental groups and other stakeholders in order to get where we need to go,” Hamm said.

For Mike Sommers, CEO of the American Petroleum Institute, cooperation is necessary “to ensure the supply of U.S. energy, including solar, wind and nuclear and, yes, petroleum products.”

Sommers said that even if every Paris Agreement signatory meets their 2040 commitments, the International Energy Agency projects that natural gas and oil will still account for almost half of all energy used.

“The only real decision here is where natural gas and oil are produced,” he said.

The Case for Fossil Fuels

Fossil fuel associations made up more than a third of the speakers at the forum, reflecting the sector’s continued economic and political power. And like Sommers, each of their representatives offered up a range of statistics underlining the pragmatic and economic need for their products and services now and in the future.

“We’ve got 187 million Americans that are using natural gas in their homes as we speak,” said Karen Harbert, CEO of the American Gas Association. “So, we are a fuel of choice and a fuel in demand. Five-and-a-half million businesses are using natural gas right now in their industrial applications, making the things that life revolves around; so, we really see ourselves as foundational to the energy system and foundational to our way of life.”

“There are 200 million cars and trucks on the road, and they consumed more than 140 billion gallons of gasoline in 2019,” said Andrew Black, CEO of the Association of Oil Pipelines. “Together we Americans make 20 million visits to a gasoline station each day. There are other ways to deliver all this energy like trains and trucks, but none of them can handle this volume. Over 13 trains each a mile long with 100 rail cars are needed to equal the volume one large pipeline delivers on a single day.”

At the same time, Black and others also stressed their commitment to sustainability and cutting emissions.

“Pipelines deliver liquid energy using the least amount of greenhouse gas emissions with the lowest impact on the environment,” Black said. “Trains and trucks both emit more GHGs than pipelines, 42% more from rail, 467% more for trucks. … Liquid pipelines are the sustainable energy delivery choice.”

Amy Andryszak, CEO of the Interstate Natural Gas Association of America, cited research from the National Bureau of Economic Research showing “a correlation between the growth of natural gas for power generation and the increased deployment of renewables.”

“If we want to expand the use of renewable energy, natural gas is the answer,” Andryszak said. “The Biden administration has made a major commitment to expanding the use of renewable energy in the United States, particularly wind and solar. But we all must recognize that these technologies are complementary to natural gas, and they require a robust natural gas infrastructure to ensure affordability and reliability.”

Michelle Bloodworth, CEO of America’s Power, a coal industry trade organization, more aggressively argued that clean energy expansion poses significant challenges to an electric grid that “hangs in a fragile balance that requires not just close monitoring and care, but thoughtful and good energy policy.”

Energy markets need to put a value on the attributes of coal and send a signal to participants that those attributes are needed, she said.

“Rather than working to eliminate fossil fuels from the mix … [the Biden administration] should work hand-in-hand with the fossil fuel industry, including the coal sector, to make fossil fuels even more environmentally sustainable,” Bloodworth said.

Gas Experts: ‘Plenty of Supply’

At the same time, natural gas industry leaders countered current perceptions of a winter supply crunch, saying natural gas production has rebounded following a pandemic dip, and prices should return to pre-pandemic levels in the spring.

Natural Gas Supply Association CEO Dena Wiggins said domestic gas production is up 4 billion cubic feet per day compared to 2020, while Charlie Riedl, executive director for the Center for Liquified Natural Gas, said global demand hit a record high of 12.2 Bcf/d in December.

During the most restrictive phase of the pandemic in summer 2020, Wiggins said the U.S. had about 9,000 drilled but uncompleted wells, but in recent months, thousands of those wells have begun producing.

“We think there’s plenty of supply to meet demand, and we think that there will be plenty of supply to meet demand,” Wiggins said. “We get a lot of press when it’s a cold day in January and spot prices are high. … It gives people pause and makes people talk about high prices.”

Wiggins said not much gas typically sells at those prices in frigid weather; rather, those buying at those prices likely have not secured contracts.

“If you wait until the day before Christmas Eve to buy a plane ticket to go home and see mom, that is going to be an expensive plane ticket,” she said.

Wiggins reassured attendees that the U.S. has enough natural gas supply for the domestic market and exports. She said gas exports remain important for other countries to meet their own emissions reductions goals.

‘A Healthy, Growing Sector’

While fewer in number, renewable energy groups also sent a message of ongoing growth and sustainability that can weather the uncertainties of politics, supply chains and COVID-19.

Even during the administration of former President Donald Trump, the private sector pumped $56 billion into renewables in 2020, said Gregory Wetstone, CEO of the American Council on Renewable Energy (ACORE).

Noting that the U.S. added an estimated 46 GW of renewables in 2021, Wetstone said, “This is a healthy and growing sector.”

Utilities and corporate buyers are a major part of that growth, with 17 GW of clean energy contracts announced and “a record 110 GW of clean power under construction or in advanced development,” said Heather Zichal, CEO of the American Clean Power Association.

While 2021 was pivotal for solar, wind and storage, Zichal said 2022 will determine whether they “accelerate progress” or “plateau.” To be successful, she said, the industries need Congress to pass the Build Back Better Act, and everyone must be engaged in regulation and policy at the federal, state and local levels.

Erin Duncan, vice president of congressional affairs for the Solar Energy Industries Association (SEIA), focused on her industry’s priorities in the bill, including the 10-year extension of the solar investment tax credit and advanced manufacturing credits that would cover essential parts of the solar supply chain, such as inverters and racking.

A 10-year ITC will provide the “long runway” manufacturers say they need “so that they [know] there would be demand for solar,” Duncan said. A complementary manufacturing credit “would help offset some of the costs of bringing domestic production back to this country,” she said.

“You can’t just snap your fingers overnight and suddenly have a hotline to [solar] cell plants; those take time to build,” she said. “We’re going to need to continue to import materials from abroad, and so it’s a balance of how you continue to build out domestic supply chains … and [drive] demand.”

SEIA wants solar to grow from its current 4% of the U.S. energy mix to 30% by 2030, a target that will require the industry “to deploy more than we’ve ever deployed in prior years every year to reach the 850 GW of capacity we’re going to need,” Duncan said.

ACORE estimates that scaling the industry to that extent could mean an annual private sector investment of $93 billion through 2029 to keep the world on track for net-zero emissions by 2050, Wetstone said.

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FERC Accepts SEEM Revisions on Transparency

FERC on Friday approved changes to the Southeast Energy Exchange Market (SEEM) that will bring it in line with promises the market’s supporters made last year (ER22-476).

SEEM’s founding members — a group of utilities including Southern Co. (NYSE:SO), Dominion Energy South Carolina (NYSE:D), LG&E and KU (NYSE:PPL), the Tennessee Valley Authority and Duke Energy (NYSE:DUK) — first proposed the modifications in June before the commission approved the SEEM agreement. The utilities were responding to a deficiency letter from FERC that expressed concerns about market power and sought assurances about the transparency of the planned market.

SEEM supporters say the expansion of bilateral trading across 11 Southeastern states will reduce trading friction through the introduction of automation, eliminating transmission rate pancaking and allowing 15-minute energy transactions, while also promoting the integration of renewable resources. The market is expected to launch in the third quarter this year. (See FERC Rejects SEEM Opponents’ Rehearing Requests.)

FERC approved changes including:

  • weekly submissions of confidential market data to FERC and the market auditor, and periodically providing additional information publicly;
  • disclosure of regulators’ questions and answers, as well as market auditor reports, to participants, subject to restrictions on access to confidential information by marketing function employees;
  • clarification that available transfer capacity calculated by participating transmission providers must be provided to the SEEM administrator and must be used in the algorithm for each leg of any contract path to ensure transmission will not exceed available capacity;
  • updating market auditor functions to clarify that the auditor will verify compliance with market constraints;
  • use of randomization to resolve ties or ambiguities between multiple bids or offers;
  • prohibiting market-based rate holders from providing false or misleading information to the SEEM administrator or market auditor; and
  • implementing a posting requirement for complaints submitted to the market auditor.

The changes would also ensure that most SEEM rules would fall under the “just and reasonable standard” rather than the lower Mobile-Sierra public interest standard as proposed in the original agreement, an issue that became a sticking point for both FERC Chair Richard Glick and Commissioner Allison Clements.

Glick, Clements Unswayed on SEEM

Glick and Clements filed concurrences to Friday’s opinion asserting that they still had misgivings about SEEM.

In Glick’s filing, the chairman applauded SEEM members “for standing by their previous commitments on transparency.” However, he reiterated his stance that “applying [Mobile-Sierra] to any provisions of the Southeast EEM agreement is contrary to well-established commission precedent” that the standard can only apply to contracts that have “certain characteristics that justify the presumption.” Because the SEEM agreement contains “generally applicable” provisions that “bind not only the parties to the contract, but also any prospective future signatories,” Glick said Mobile-Sierra is inappropriate.

Clements’ concurrence asserted that SEEM members still had not dealt with “the underlying fundamental flaws with the [SEEM] agreement,” which remains “unduly discriminatory, unjust and unreasonable” in her eyes. But because “the scope of [FERC’s] review is limited to the amendments proposed in this proceeding,” she said she had no choice but to give her assent.

FERC ordered the revisions to take effect Nov. 25, 2021, one day after SEEM members filed the proposal, as requested by the utilities.

SEEM Moving Forward with Implementation 

Despite SEEM members’ pledge to update the agreement to address the commission’s concerns, the agreement that took effect in October did not include their proposed changes. This was because of the way the commission approved the agreement. At the time FERC had only four members, which split 2-2 on whether to accept the proposal; under Section 205 of the Federal Power Act, the agreement therefore became effective “by operation of law.”

Opponents of the market had warned that the lack of a FERC order could allow SEEM’s supporters to move forward without any of the promised transparency enhancements. However, in their November filing, the utilities claimed they “have always intended to fulfill the commitments” they made in June both because “it is the right thing to do and … to do otherwise might raise questions” about the market’s legitimacy.

Despite the divide among commissioners over approving SEEM, FERC has accepted the existence of the market as a fait accompli since the agreement took effect. Last month commissioners rejected requests for rehearing filed by several environmental and clean energy organizations on the grounds that they submitted their requests too late. FERC has also approved revisions to four of the participating utilities’ tariffs implementing the special transmission service used to deliver the market’s energy transactions. (See FERC Accepts Key Tariff Revisions to SEEM.)

SEEM has also continued to move forward since receiving FERC’s approval in October. Earlier this month, members announced that South Carolina-based Santee Cooper had agreed to join the market; the following week, the Municipal Electric Authority of Georgia announced that it would join as well. (See Santee Cooper Joins SEEM.)

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FERC Denies Co-ops’ $79M Complaint vs. SPP

[EDITOR’S NOTE: A previous version of this story incorrectly said the two cooperatives alleging SPP “misapplied” tariff provisions requested that the “grid operator be assessed $2.2 million in reliability unit commitment penalties.” The sentence now correctly reads, “The cooperatives also requested the grid operator assess them $2.2 million in reliability unit commitment penalties.”]

FERC last week denied a complaint by a pair of electricity cooperatives that SPP “misapplied” tariff provisions by de-committing their generation resources that went on outage during last February’s extreme weather event (EL21-90).

The commission ruled Thursday that Basin Electric Power Cooperative and North Iowa Municipal Electric Cooperative Association (NIMECA) had not met the Section 206 requirement proving that SPP violated its tariff.

Basin and NIMECA filed their complaint in July, asking the commission to direct SPP to refund them $79.3 million in revenue they claimed they would have received if the RTO had abided by its tariff terms. The cooperatives also requested the grid operator assess them $2.2 million in reliability unit commitment penalties.

The co-ops asserted SPP was in violation because it de-committed several of their resources that were committed through its multiday reliability assessment (MDRA) process for reasons other than addressing an emergency condition.

The commissioners pointed out that the outage resources were issued commitment instructions as part of the MDRA, but the cooperatives reported that the resources were on outage through SPP’s outage scheduler. The RTO reflected the outage status as an input to the day-ahead market.

“The fact that the outage resources were not awarded positions in the day-ahead market does not amount to SPP de-committing” them, FERC said. The commission said because SPP correctly included the resources’ status as a day-ahead input, the resources were unable to be awarded positions in the market, even if the RTO had previously sent commitment instructions for the resources resulting from the MDRA.

FERC also agreed with the grid operator that its tariff requirements to reflect resource outages as inputs to the day-ahead market, day-ahead RUC and intra-day RUC do not depend on whether the resources were previously committed as part of the MDRA as long lead-time resources or during conservative operations.

GI Backlog Plan Approved

The commission on Jan. 14 also accepted SPP’s tariff revisions modifying its generator interconnection procedures to mitigate the backlog in its GI study queue. It directed the RTO to make an informational filing within 30 days after a transitional open-season cluster’s window closes (ER22-253).

FERC said it expected SPP’s process changes “will help expedite the process and give SPP the opportunity to reduce its interconnection queue backlog.”

SPP's GI backlog in November (SPP) Content.jpgSPP’s GI backlog in November | SPP

The commission found that the RTO’s proposed deviations from FERC’s pro forma large generator interconnection procedures, permitted under the independent entity variation standard, met Order 2003’s intent to foster increased economic generation development by reducing interconnection costs and time “and encouraging needed investment in generator and transmission infrastructure.”

“We find that SPP’s proposals … will allow SPP to complete studies more efficiently than under the current process,” the commissioners wrote. “SPP’s proposed transition plan … allows SPP to manage the interconnection study queue while it addresses the backlog.”

The tariff revisions are the result of the Strategic and Creative Re-engineering of Integrated Planning Team’s work to resolve a five-year backlog of GI requests by 2024. SPP staff said the backlog dates back to 2017 and is comprised of 533 interconnection requests and almost 100 GW of capacity, most of it for wind and solar generation. (See “Renewable Developers Applaud SPP’s Plan to Reduce GI Queue’s Backlog,” SPP Markets and Operations Policy Committee Briefs: July 12-13, 2021.)

SPP staff are currently working on the oldest two study clusters.