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November 19, 2024

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Deflated New York OSW Portfolio Positioned to Start Regrowth

The few details released on New York’s potential next wave of offshore wind projects indicate continued efforts to expand the human and industrial infrastructure critical to offshore development. 

They also indicate a 28% shrinkage: Contracts for all four projects that previously were contracted by the state have been or will be cancelled. They had a combined 4,230 MW of capacity, but the three proposals submitted by the Jan. 25 deadline would be a maximum of 3,034 MW. 

Three gigawatts is a respectable figure, given the struggles the offshore wind industry experiences as it establishes itself in the United States. (Four other Northeast states have seen contract cancellations in the past year.) 

And New York is in advanced negotiations for three other projects it awarded provisional contracts in October 2023 — their total capacity is 4,032 MW. (See NY Announces Renewable Energy Projects Totaling 6.4 GW.) Final contract execution may come as soon as this quarter. 

If they all come to pass, these six projects would total 7 GW, and get the state most of the way to its 2035 goal of 9 GW.  

Beyond that, developers cancelled New York contracts for two other projects totaling 2,470 MW. But they did not cancel the projects themselves — they could be rebid into a future solicitation, though not necessarily New York’s. 

The three proposals submitted to the New York State Energy Research and Development Authority on Jan. 25 were Community Offshore Wind 2, Empire Wind 1 and Sunrise Wind.  

The names are familiar: Empire and Sunrise hold contracts that still officially are in effect but will be cancelled regardless of whether the projects win new contracts. And Community Offshore Wind 1 was one of the provisional contract awardees in October. 

Equinor and Ørsted both are moving to terminate their joint ventures and proceed solo on Empire and Sunrise, respectively. (See Offshore Wind Reset Complete in New York.) 

Both are mature plans with many regulatory and logistical hurdles already cleared, giving them a yearslong head start over newer proposals in a region of the state predicted to be at growing risk of capacity shortfalls as soon as 2025.  

The proposals submitted Jan. 25 illustrate the long timelines at play: Community’s projected commercial operations date is not until 2031. Sunrise projects commercial operations in 2030 if it is built to be ready for a meshed offshore transmission system, or 2026 if it is not meshed-ready. Empire also projects power generation starting in 2026. 

Most other details are redacted in the public versions of their supporting documentation. 

Equinor and Ørsted have continued actively moving the projects forward since declaring in June 2023 that the existing contracts were untenable without more money from the state, and since the state in October 2023 said no more money would be forthcoming. (See OSW Developers Seeking More Money from New York and New York Rejects Inflation Adjustment for Renewable Projects.) 

The latest update: On Feb. 1, Equinor announced New York City had approved its design for an offshore wind operations and maintenance building at the South Brooklyn Marine Terminal, a 73-acre facility the company envisions as an onshore hub for offshore construction and operations — both for itself and other developers. 

Ørsted, meanwhile, continues preparatory work for the onshore electrical infrastructure upgrades Sunrise would need. It plans to set up an operations and maintenance hub on the north shore of Long Island as part of the Sunrise project and open it in the third quarter of 2024. 

Community Offshore Wind is a collaboration by RWE and National Grid Ventures. In the summary of their proposal, they said they have made allowances for the economic risks and supply chain uncertainties that have bedeviled offshore wind developers since late 2022. The Community projects are designed with the flexibility needed to overcome these challenges, they added. 

Additionally, Community proposes nearly $50 million in workforce and supply chain investments; Equinor has been funding the Offshore Wind Innovation Hub; and Ørsted has funded the National Offshore Wind Training Center. 

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FERC Orders Change to MISO Order 2222 Compliance Plan

FERC ordered an after-the-fact addendum to MISO’s Order 2222 compliance plan this week after being alerted to an inconsistency by WPPI Energy.

The commission said MISO must revise its plan by May 10 to require aggregators of distributed energy resources to retain performance data of individual DERs and provide it to RTOs upon request for auditing purposes (ER22-1640).

FERC agreed with WPPI Energy that it overlooked MISO’s missing data requirement — which is required by Order 2222 — when it first issued an order on MISO’s plan in October. (See FERC: MISO’s 2030 Finish Date on Order 2222 Compliance not Soon Enough.)

The commission said while a section in MISO’s tariff states it has the right to audit data provided by the aggregator, including information related to the metering of individual DERs, MISO did not include a requirement that aggregators retain individual DER meter data.

WPPI Energy argued that FERC erred when accepting MISO’s compliance filing because it didn’t explicitly spell out the data preservation requirement.

MISO, meanwhile, continues to work with its stakeholders on other Order 2222 directives FERC ordered in October. Those include deciding whether the grid operator can handle aggregations that span multiple pricing nodes; coming up with a go-live date that’s sooner than 2030; setting up a dispute resolution process; and establishing cybersecurity and customer data privacy protections for meter data management. (See Stakeholders Ask MISO to Share New Order 2222 Go-live Date ASAP.)

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ICC Staff Demurs on Decision over Ameren’s MISO Membership

Illinois Commerce Commission staff have passed on recommending that Ameren and two smaller Zone 4 utilities depart MISO for PJM. 

ICC staff issued a final report Jan. 25 on the notice of inquiry they opened last year after the ICC directed Ameren to study the cost-benefits of leaving MISO and joining PJM. Ameren commissioned Charles River Associates, which found it would cost southern Illinois customers about $3.4 billion from 2025 to 2034 for Ameren to disentangle itself from MISO and join PJM. The study considered energy trade benefits, transmission expansion to tap into PJM, RTO costs and exit and entry fees to switch grid operators.

In comments on the study last year, ICC staff said PJM’s true capacity market style could be a better match for Ameren than MISO’s residual capacity auctions. They also said that a continued home in MISO could be fraught with resource adequacy risks when compared to PJM because MISO is poised to add more solar power and energy storage. (See ICC Staff: More to Consider in Possible Ameren Illinois Exit from MISO.) 

Ultimately, ICC staff said that although they combed through comments on how the study methodology and inputs could be tweaked to show greater future benefits of PJM membership, “it is not clear that implementing such changes would change the conclusion from the Ameren report that Zone 4 joining PJM would result in incremental net costs for [Ameren], ComEd and the State of Illinois overall.”

Staff said they weren’t recommending the commission “take any specific action” to change Ameren’s — and possibly by extension, City Water Light and Power and Southern Illinois Power Cooperative’s — RTO membership.

However, staff added it might be worthwhile for the commission to re-evaluate Ameren’s status as a MISO member in the future. 

“ICC staff notes that the information submitted in this proceeding suggests that assessing the net benefits of [Ameren’s] MISO membership is not a static assessment and will change over time. As a consequence, ICC staff further recommends the commission leave open the possibility of further analyses should future circumstances warrant them,” they wrote.

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FERC Approves 1st PJM Proposal out of CIFP

FERC on Jan. 30 approved a PJM proposal to rework several areas of its capacity market centered around aligning how resources’ capacity contributions match up to system risk analysis (ER24-99). 

The order greenlights PJM’s proposal to accredit all resources, except energy efficiency, using a marginal effective load-carrying capability (ELCC) framework and use the hourly probabilistic modeling at the heart of ELCC to calculate the RTO’s capacity needs through the Reserve Requirement Study (RRS). It also adds additional generation capability testing requirements to assess whether generators can meet their capacity performance obligations and whether resources that have not started for a month are able to properly synchronize to the grid and operate according to their parameters. (See PJM Files Capacity Market Revamp with FERC.) 

The proposal is one of two that the RTO filed following last year’s Critical Issue Fast Path (CIFP) process. The other (ER24-98) carries a Feb. 6 deadline for action on proposed changes to PJM’s market seller offer cap. (See “PJM Steams Ahead with CIFP Filing Timeline After FERC Deficiency Notices,” PJM MIC Briefs: Dec. 6, 2023.) 

FERC said that the new approach would allow PJM to capture how resources may perform during a wider range of system conditions, namely the sort of correlated outages experienced during extreme winter weather and the diminishing reliability benefit of “highly correlated resources such as solar and short-duration storage.” 

“PJM’s marginal ELCC capacity accreditation framework reasonably values resources’ capacity based on their expected incremental contribution to resource adequacy across reasonably anticipated load, weather and resource availability scenarios given the expected resource mix,” the commission said. “We find that PJM’s proposal will allow its markets to better value the ability of individual resources to address tight system conditions and emergencies, as well as resource adequacy challenges associated with correlated resource outages and an evolving resource mix.” 

While several protests took issue with the marginal ELCC approach, arguing that it relies on an assumed resource mix before generators have cleared the auction, the commission stated that such ex ante analysis has always been part of the Reliability Pricing Model, and the improvements to the accuracy of accreditation values under ELCC outweighs any disparities between the estimated and actual resource mix. 

Vistra, American Municipal Power and Ørsted argued that PJM’s explanation of how ELCC values would be calculated was vague and that additional information is needed in the tariff revisions, rather than future manual revisions.  

CIFP

PJM Board of Managers Chair Mark Takahashi | © RTO Insider LLC

The Independent Market Monitor and several generators protested PJM’s proposal to add a dual-fuel resource ELCC class, arguing that its qualification requirements are vague and unsupported, and that recognizing the reliability benefit of resources with backup fuel without also creating a new generation class for gas-fired generation with firm fuel contracts is discriminatory. 

Calpine commented that the changes were not overly complex, though it also argued that complexity should not be a reason to reject a market design. It compared the use of loss-of-load probability models to how market participants estimate future hourly energy prices. 

FERC determined that PJM’s proposal to remove generators that fail to provide dual-fuel capability after attesting that they meet the qualifications from the ELCC class, as well as the potential for referral to FERC enforcement, was adequate to address concerns that generators could claim capabilities that they could not deliver. The commission also stated that PJM had demonstrated that it could measure the reliability benefit of resources that maintain an on-site alternative fuel that can allow them to operate for two consecutive 16-hour periods, whereas the definition and benefit of a firm fuel contract remains ambiguous. 

The proposal also effectively lowers the maximum penalty generators can be assigned in a year for failing to meet their performance obligations during performance assessment intervals (PAIs). The current annual stop-loss limit is based on the net cost of new entry (CONE), which PJM stated current results in a $135,000/MW-year stop-loss limit it believes is disproportionate to the revenues a generator can receive through the capacity market. Based on the $18,250/MW-year clearing price, PJM said the stop-loss limit is 7.5 times higher than annual market revenues. 

The change to the stop-loss calculation swaps the 1.5 times net CONE component with 150% of the Base Residual Auction (BRA) clearing price. PJM said that the swap would continue to result in a maximum penalty larger than annual revenues without being overly punitive. 

The commission rejected arguments from Vistra and Constellation Energy that tying the stop-loss limit to future auction outcomes makes it difficult for market sellers to calculate the Capacity Performance quantified risk (CPQR) component of their market offers, as they would have to estimate the final clearing price in advance. It noted that market sellers already forecast several values ahead of the auction, including energy and ancillary service revenues, expected unit performance and the number of PAIs expected in the delivery year. 

PJM’s proposal also revised the deficiency charges that fixed resource requirement (FRR) entities are assessed if they fail to procure adequate capacity prior to the BRA. The RTO argued that low capacity prices have created an incentive for FRR entities to pay the deficiency charges, which are based on clearing prices, rather than meet their own reliability needs. It also implements a four-year transition period to provide additional time for FRR entities to adjust to the new ELCC accreditation and a longer lead time for capacity planning. 

Commissioner Allison Clements released a partial concurrence and dissent, stating the proposal would address growing reliability risk that does not correspond with meeting peak loads. But she argued that the commission erred in rejecting a protest from the Advanced Energy Management Alliance and clean energy associations that the changes to accreditation and the RRS render the demand response performance window unjust and unreasonable.  

Clements wrote that the commission should initiate a show-cause order to examine the “clear mismatch between PJM’s existing demand resource availability window and its new understanding of system risk. PJM should be required to either adjust the availability window to reflect its new understanding of risk, or else demonstrate why its proposed changes have not rendered the current availability window unjust and unreasonable or unduly discriminatory.” 

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China Preparing to ‘Wreak Havoc’ on US, Cyber Officials Warn

Jen Easterly, director of the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA), warned members of Congress on Jan. 31 that the electric grid remains a prime target for China’s cyber warfare forces intent on causing “societal panic” in a future conflict with the U.S.

Easterly spoke during a hearing on Capitol Hill before the House of Representatives’ Select Committee on the Chinese Communist Party. She was joined by Gen. Paul Nakasone, commander of U.S. Cyber Command; FBI Director Christopher Wray; and National Cyber Director Harry Coker Jr. The hearing focused on China’s ability and willingness to disrupt critical U.S. infrastructure in order to sap Americans’ will to respond to a Chinese invasion of Taiwan.

FBI Director Christopher Wray | U.S. House of Representatives

Chinese President Xi Jinping reportedly told President Joe Biden recently that his country is preparing to reunify with Taiwan and is willing to use force to do so. Easterly told the committee that in recent years, CISA has “seen Chinese cyber actors … burrowing deep into our critical infrastructure to enable destructive attacks in the event of a major crisis or conflict.”

As evidence that “the threat is not theoretical,” Easterly and her fellow panelists cited Volt Typhoon, a cyber actor connected to China by CISA and other security organizations that was accused last year of infiltrating U.S. critical infrastructure organizations disguised as legitimate users, a technique called “living off the land.” (See NERC Issues Cybersecurity Data Request.)

Wray noted to the committee that the FBI had “shut down” Volt Typhoon in an operation announced that day but warned that cyberattacks remain a potent part of the Chinese leadership’s “whole-of-government campaign” against the U.S. Echoing Easterly’s assessment of China’s cyber plans, he called the country’s cyber posture “the defining threat of our generation.”

“China’s hackers are positioning on American infrastructure in preparation to wreak havoc and cause real-world harm to American citizens and communities,” Wray said. “If or when China decides the time has come to strike, they’re not [going to be] focused just on political or military targets. … Low blows aren’t just a possibility in the event of a conflict. Low blows against civilians are part of China’s plan.”

Wray described the threat from China’s state-sponsored hackers as overwhelming, saying in his opening remarks that even if all of the FBI’s cybersecurity specialists focused on China, the country’s “hackers would still outnumber FBI cyber personnel by at least 50 to 1.” Under questioning from Chair Mike Gallagher (R-Wis.), Wray said China’s willingness to recruit cyber criminal gangs would likely make the disparity even greater in a crisis.

Rep. Mike Gallagher (R-Wis.) | U.S. House of Representatives

Following up on Wray’s remarks, Nakasone asserted that the U.S. cybersecurity agencies are not without their own “force multiplier” in the form of partnerships with the private sector, which he described as a source of justifiable concern for his Chinese counterparts.

“They may have 50 to 1, but when we have the private sector, we outnumber them,” Nakasone said.

Rep. Kathy Castor (D-Fla.) focused on the energy sector in her question time, asking Easterly for her impression of the response from “the fractured nature of public and private entities.” Easterly responded by praising energy utilities, particularly for the high degree of participation by company CEOs in CISA’s cybersecurity activities.

“You do not see that across every sector, and that really shows that CEOs in the energy sector understand this issue and understand the need to make significant investments in cybersecurity and cyber resilience,” Easterly said. She added that the connections established during CISA’s “very aggressive” outreach to industry before and during Russia’s invasion of Ukraine in 2022 have continued to pay off as concerns rise about China’s intentions.

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Texas Supremes Hear Arguments Over Uri’s Prices

The Texas Supreme Court heard oral arguments Jan. 30 over whether the state’s Public Utility Commission had the authority to order electric prices be set at $9,000/MWh during the 2021 winter storm or whether billions of dollars in market transactions need to be repriced (23-0231). 

Attorneys for the PUC and several market participants said state rules make it clear the commission’s top priority is the Texas grid’s reliability. Legal counsel for Luminant, the state’s largest generator, countered that the PUC exceeded its authority with the emergency pricing order. 

When the PUC issued its directive to ERCOT on Feb. 15, 2021, as generation was dropping off during the storm, the grid operator’s algorithm was setting prices as low as $1,200/MWh. Under ERCOT’s market construct, prices are designed to increase during scarce conditions to incentivize more generation to come online. 

The problem was, there wasn’t enough generation during the first two days of the storm because of frozen equipment or lack of fuel supplies. ERCOT kept prices at the $9,000 cap — since reduced to $5,000 — until Feb. 19, resorting to rolling blackouts to keep the grid stabilized. 

Allyson Ho of Gibson, Dunn & Crutcher | The Supreme Court of Texas

“Is it really your position that [the PUC’s commissioners] are tied to the mast of competition in a way that prevents them from taking that action, if we are in a world where it actually is the case that they just have to commandeer the market for a while to make sure we’re not in the Stone Ages for a few weeks?” Justice Jimmy Blacklock asked Gibson, Dunn & Crutcher partner Allyson Ho, who represented Luminant. 

Ho said the state’s Public Utility Regulatory Act prohibited the commission from setting prices by “regulatory fiat.” 

“The agency did the one thing that the [Texas] Legislature expressly said it could not do, and that is set prices,” Ho said. 

Earlier this year, Texas lawmakers attempted to fix the loophole with House Bill 1500. The legislation includes a section that requires the commission to issue a written order when directing ERCOT to take certain actions. 

Lanora Pettit, Texas Attorney General’s Office | The Supreme Court of Texas

Lanora Pettit, a lawyer with the Texas Attorney General’s office, said “the authority existed at the time” to order ERCOT to raise prices in trying to stabilize the grid. She said the PUC’s message to ERCOT was “that your algorithm’s not working the way it’s supposed to, so please go fix it and get in line with the rules we’ve already established.” 

“The understanding of everybody in the market was that [$9,000/MWh] was the price that when load was being lost, that would be charged,” Pettit said. “What happened here was not an amendment to that rule, but instead of direction to ERCOT.” 

Ho responded for Luminant, saying the order did little to bring more generation online because all plants that could run in the frigid conditions already were doing so. 

Luminant initiated the proceeding after it incurred $1.6 billion in losses when forced to buy backup power at the system cap and gas supplies at equally exorbitant prices. (See Vistra’s Winter Storm Loss Deepens to $1.6B.) 

The company won a surprise judgment from the 3rd Court of Appeals in March when it reversed the PUC’s emergency orders. The court found the commission’s actions “entirely” eliminated competition and were contrary to state law. (See Texas Court Reverses PUC’s Uri Market Orders.) 

The state Supreme Court in September agreed to review the appeals court’s ruling. (See Texas High Court to Review Decision on Uri Charges.) 

The emergency order resulted in $16 billion of market transactions that ERCOT’s Independent Market Monitor said were incorrectly priced during the 33 hours that followed the end of firm load shed. The PUC declined to reprice the transactions. (See “Monitor: $16B ERCOT Overcharge,” ERCOT Board Cuts Ties with Magness.) 

Some of the $16 billion balance has since been securitized, and some participants have been paying off debts they now might not even owe. Other transactions have been settled outside ERCOT and can’t be undone, according to legal experts. 

Two of the Supreme Court’s justices recused themselves from the proceeding. A third was absent. A decision is not expected to be rendered for several months, but the high court normally issues judgments on all proceedings it takes up. Its current term ends June 28. 

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NYISO Asks FERC for an Extension to Comply with Order 881

NYISO on Jan. 30 requested a three-year extension to comply with FERC Order 881, claiming it needs more time to implement the software and hardware updates necessary to support the required ambient-adjusted ratings (AARs) on its transmission lines (ER22-2350).

Order 881 mandates that providers assess transmission capacity based on real-time environmental conditions, such as temperature or wind, requiring the use of AARs for short-term transmission requests and seasonal ratings for long-term requests (RM20-16). NYISO says it needs more time to comply with the order because it also must undertake a multiyear effort to upgrade its Energy Management and Business Management Systems (EMS/BMS), which are critical to monitoring reliability and managing financial operations.

NYISO was slated to implement Order 881’s enhancements by the second quarter of 2025 but now is asking for an extension of no later than Dec. 31, 2028, arguing it is infeasible to both comply with the commission’s order and deploy the nine EMS/BMS software modifications necessary to support the order’s requirements. (See “Ambient-adjusted Ratings,” NYISO Management Committee Briefs: Nov. 29, 2023.)

The ISO had been upgrading its EMS/BMS software but now contends meeting the current deadline requires a substantial reallocation of resources and personnel, which, it states, “would jeopardize the timeline and quality assurance efforts required to successfully complete a critically important technology upgrade.” It added that it cannot use these operating systems past their June 2026 vendor support date “without risking significant software failures.”

Moreover, NYISO pointed out transmission owners (TOs) cannot fulfill their own Order 881 obligations until the ISO has the requisite software and protocols in place. But it assured FERC that if granted an extension, it would maintain certain dynamic line rating functions to still give TOs the ability to modify real-time transmission line ratings.

In an attached affidavit, Rana Mukerji, senior vice president of market structures at NYISO, wrote that a compliance extension was needed because certain modifications “were not anticipated in the initial scope for this technology upgrade project and the initial project schedule.”

He cautioned that, in his experience, without an extension, “coding two sets of major modifications in parallel within the same systems significantly increases the possibility that one or both software changes result in increased implementation times and errors.”

Mukerji added, however, that if given an extension, it still would take two-and-a-half to three years to complete and implement the EMS/BMS upgrades.

NYISO asks FERC to respond by March 29, because the ISO plans to begin its 2025 project prioritization process in April and wants to know if it can proceed with the EMS/BMS project in the coming year.

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FERC Releases Latest Version of ISO/RTO Metrics Report

FERC on Jan. 30 released the latest iteration of its Common Metrics Report on ISO/RTO markets, which evaluates the performance and benefits of organized markets. 

The commission has released these reports every few years since Congress’ Government Accountability Office suggested it do more to track the performance and benefits of ISO/RTOs back in 2008. The report shows the different fuel mixes from FERC’s six jurisdictional organized markets and how much they each rely on demand response. 

Some past reports have included similar data from utilities outside of ISO/RTO footprints, but none of them responded to FERC’s efforts this time. 

The highest share of DR is in CAISO at 10%, while MISO, NYISO and PJM each have 3-6%. ISO-NE and SPP both reported less than 2%. DR in SPP grew significantly in 2022, hitting about 2% after minimal levels in earlier years. 

ISO-NE and MISO added generation in each year from 2019 to 2022, while both PJM and NYISO lost capacity overall during that time. 

FERC staff collected information on 29 common metrics across the six ISO/RTOs split across three broader categories: administrative and descriptive metrics; energy market metrics; and capacity market metrics. 

CAISO, ISO-NE, MISO and NYISO all had actual reserve margins below their expected levels between 2019 and 2022, with MISO seeing the biggest gap. Only PJM had higher actual reserve margins than expected in all four years, while SPP flipped between both categories every year. 

Every organized market reported that natural gas was their single largest fuel type from 2019 to 2022 with NYISO seeing the biggest increase in the fuel — from 58% to 64% — while ISO-NE, MISO and PJM each reported a modest increase. CAISO saw natural gas share fall from 49% to 41% over the period, while SPP saw a more modest drop from 43% to 40%. 

“The decline in the share of natural gas-fired capacity in these regions is likely driven by the relatively large increases in wind and solar generating capacity, instead of natural gas retirements,” the report said. 

MISO, PJM and SPP all had a significant amount of coal in the fuel mixes, and all saw it drop. Coal in PJM fell from 30% in 2019 to 25% in 2022, MISO saw it fall from 41% to 37% and SPP from 25% to 22%. The other markets all reported less than 3% coal in their markets. 

SPP and CAISO had the highest shares of installed wind and solar generating capacity, with the two renewables representing 31% of capacity in SPP and 30% in the California ISO. 

“The largest relative increase in generating capacity of these resource types occurred in SPP, where the share of wind and solar capacity increased from 24% in 2019 to 31% in 2022,” FERC said. 

The report also included how often each market had to issue Energy Emergency Alerts across the four years studied, with CAISO seeing 16, MISO 10, PJM six, SPP five and ISO-NE one. 

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FERC to Return $13.6M to BP from 2008 Enforcement Case

FERC issued an order Jan. 31 approving the return of $13.6 million in penalties it had collected from BP over a case of alleged manipulation of Houston Ship Channel natural gas prices after Hurricane Ike in 2008.

The commission collected $24.36 million in fines, plus interest, from BP for allegedly keeping natural gas prices at the Houston Ship Channel lower than those at the Henry Hub in Louisiana and losing money in physical trades, which benefited its financial positions and led to overall profits. FERC first issued a show cause order in the case in 2013, and years of litigation followed until a decision from the Fifth Circuit Court of Appeals came down in October 2022.

The commission had argued it should have jurisdiction over any transaction that impacts the interstate natural gas markets it polices, but the court disagreed.

BP only shipped gas over intrastate pipelines regulated by the Texas Railroad Commission in the alleged scheme, but some of that natural gas previously had crossed state lines, meaning it fell under FERC’s jurisdiction. The court said only that interstate gas could be part of the federal regulator’s enforcement action.

BP and FERC’s Office of Enforcement entered into a settlement that trimmed the penalty to $10.75 million, following the court’s findings, which meant the firm had paid an extra $13.6 million.

The oil major agreed it would not seek recovery of $250,295 of disgorgement of unjust profits, which ultimately was paid to three Texas Low Income Home Energy Assistance Program (LIHEAP) programs.

BP made a filing in November arguing FERC itself should issue an order requiring it be repaid for the $13.6 million. The order Jan. 31 directed the director of the Financial Management Division in the Office of Executive Director to wire BP the money.

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Group Looks to Create ‘Actionable’ West-wide Transmission Plan

Backers of the recently formed Western Transmission Expansion Coalition want to fill a void in the Western Interconnection by producing an “actionable” interregional transmission study — one that starts with a holistic view of the region’s needs.

“The idea here is that we’re looking at that entire collective footprint, and not just the subregions,” Sarah Edmonds, CEO of the Western Power Pool (WPP), said during a Jan. 29 call to update stakeholders on the WestTEC effort, which was launched last October. (See Plan Seeks to Boost Prospects for New Transmission in the West.)

Edmonds explained the meaning of “actionable.”

“We want to provide high-confidence information to the industry so that if there are parties who are interested in advancing transmission build solutions, they can take the information out of our study, knowing that the study has a high-confidence factor built by all of the different participants,” including states and tribes, she said.

Edmonds reaffirmed that WestTEC won’t try to tackle the especially thorny subjects of transmission cost allocation, siting and permitting, despite the wishes of some stakeholders who provided comments on the effort’s concept paper. (See Western Transmission Initiatives Differ on Dealing with Cost Allocation.)

“We don’t deny that cost allocation, permitting and siting are complicated matters and that, in many ways, this study is the easiest part of a journey towards transmission solutions,” she said. “So when we say ‘high confidence,’ we’re really hoping that the study itself will really grease the skids for future conversations around all of those things.”

Former FERC Chair Richard Glick, now a principal at GQ New Energy Strategies and a consultant for WestTEC, spoke on the call, emphasizing the need to stay focused on the planning end of transmission development.

He pointed to the region’s growing concerns around resource adequacy, rising demand from electrification and increasing instances — and “ferocity” — of extreme weather events. Glick noted also that the Department of Energy’s most recent National Transmission Needs Study noted that the Northwest and Southwest could require an additional 30% of transmission capacity by 2035.

“As I think most people have seen, there’s been some frustration that the current approach to regional transmission planning in the West — particularly outside of the California ISO — has not been very effective,” he said.

Issues of cost allocation and siting are being picked up elsewhere, Glick said. Western state officials have started moving to address regional transmission cost allocation, as evidenced by the state-led Western States Transmission Initiative.

And given the scale of federal ownership of land in the West, siting and permitting are being addressed at the federal level.

“I know the Department of Energy now is taking the lead in terms of being the lead siting agency at the federal government,” Glick said. “There’s a number of bills pending in Congress right now that would attempt to facilitate and improve the transmission siting environment that currently exists.”

‘Biggest Tent Possible’

Inclusivity was a key theme during the call.

“WestTEC is about expanded engagement,” Edmonds said, noting the organization has sought to become West-wide and move beyond the participation of just transmission-owning utilities.

Ben Fitch-Fleischmann, director of markets and transmission at the Interwest Energy Alliance, lauded WestTEC for providing a seat at the table for trade associations such as his. He noted the group’s roster already includes utilities, independent power producers, the region’s three transmission planning entities, National Laboratories, state agencies, tribal representatives and the Western Interstate Energy Board.

“So aiming to pitch the biggest tent as possible,” Fitch-Fleischmann said.

WestTEC will seek to prioritize inclusivity through its proposed governance and committee structure, which would include the Steering Committee, Regional Engagement Committee (REC) and WestTEC Assessment Technical Team (WATT).

The Steering Committee, which will oversee the effort, will be “substantially West-wide in its representation,” Edmonds said. The committee will include representatives from transmission-owning utilities from across the West, the region’s three planning groups — CAISO, NorthernGrid and WestConnect — and WECC.

The REC would seek “a broad membership to make sure we’re aligned with state policy and consumer interests,” according to Fitch-Fleischmann. Its job will be to review the work of the WATT, gain insights from the region and provide feedback.

“We need to ensure we get timely input from a wide range of governmental agencies, public interest perspectives and the like to make sure we can engage with the broader public,” he said.

The WATT will be charged with getting into the weeds around the study.

“This is not a committee where we’re looking for another warm body,” said Chelsea Loomis, WPP manager of regional transmission planning services. “We need people who can really hit the road and contribute with data that will support the study scope. We need to make sure that we are developing the scenarios that support the execution of that study scope. This will be a very busy group.”

Members of the WATT also recently selected consultants to assist in modeling for the study: Energy Strategies, with support from Energy+Environmental Economics.

WestTEC is seeking funding to support its work, just like another big effort taking shape in the Western electricity sector: the West-Wide Governance Pathways Initiative. Edmonds said WestTEC recently completed an application for a DOE grant that seems “tailor made” for its work.

“But I really want to emphasize that it is not a condition for us moving forward,” she said. “We’re going to find a way to fund this amongst ourselves, and if DOE funding comes along, that will be very helpful. But we’re not waiting around for that determination.”