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November 2, 2024

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SEC Seeks Standard Disclosures for Climate-related Business Risks

The Securities and Exchange Commission voted Monday 3-1 in favor of a proposed rule that would expand and standardize how public companies disclose business risks related to the climate and greenhouse gas emissions.

“Investors representing literally tens of trillions of dollars support climate-related disclosures because they recognize that climate risks can pose significant financial risks to companies, and investors need reliable information about climate risks to make informed investment decisions,” SEC Chair Gary Gensler said in a statement.

Under the proposal, SEC registrants would have to provide information in filings about, among other things, oversight of climate risks, impact of those risks on business and financial statements, and any climate-related targets or goals. Climate-related risks, as defined in the proposal, are the negative effects of climate events on business operations or activities within the company’s value chain.

In addition, the SEC is seeking GHG emissions data related to direct business operations and energy use, and in some cases, value-chain operations. Standardizing how and when companies provide emissions data would remove uncertainty associated with voluntary reporting, according to the proposed rule.

GHG disclosures expressed as metric tons of carbon dioxide-equivalent per unit of revenue, for example, would give investors a basis for comparison across industries and companies, the commission said.

Jack Lienke, regulatory policy director at the Institute for Policy Integrity, supported the SEC’s proposed rule in a statement Monday, saying the commission “no longer has the luxury of ignoring climate change.” The SEC, he said, must protect investors by demanding the same transparency on climate risk as other financial risks.

The SEC based the proposed rule on the 2017 disclosure recommendations of the Task Force on Climate-related Financial Disclosures created in 2015 under the direction of the Group of 20 finance ministers.

Commissioner Hester Peirce, who was appointed by President Donald Trump to fill a Republican seat, voted against the proposal, saying that it “will undermine the existing regulatory framework that for many decades has undergirded consistent, comparable and reliable company disclosures.”

The existing filing rules, Peirce said, already require companies to disclose risks, such as those related to climate. In 2010, the commission issued guidance on how its rules at the time could require disclosure of climate issues for a business. Since then, investor interest has grown for more specific climate-related details in company filings, the SEC said in its proposal.

“It is appropriate for us to consider such investor demand in exercising our authority and responsibility to design an effective and efficient disclosure regime under the federal securities laws,” the commission said.

Peirce, however, said the proposal “exceeds the commission’s statutory limits.”

“Many calls for enhanced climate disclosure are motivated not by an interest in financial returns … but by deep concerns about the climate,” she said. The commission, she added, has a responsibility to limit disclosure requirements so they do not “bury the shareholders in an avalanche of trivial information.”

Compliance with the new rules would follow a phased approach, based on filing class. Assuming an effective date in December, filers would have to be in full compliance with everything but value-chain emissions disclosures for fiscal year 2025. Full compliance with value-chain emissions data reporting would begin in fiscal year 2026.

Sen. Edward Markey (D-Mass.) said the proposed rule is an “important step,” but he called for more aggressive action from the commission.

“I urge the SEC to expand the proposal to quickly require [value-chain] emission data, and to incorporate environmental justice considerations — such as assessment of the specific risks to [Black and Brown] communities — into the reporting requirements,” he said in a statement Monday.

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White House Issues Fresh Russian Cyber Warning

The Biden administration on Monday issued another warning that Russia’s government “is exploring options for potential cyberattacks” against the U.S. and called on critical infrastructure operators to “harden your cyber defenses immediately.”

In a statement, the White House cited “evolving intelligence” that links the growing cyber risk to the “unprecedented economic costs we’ve imposed on Russia” through sanctions launched since the country began its invasion of Ukraine in February. The administration did not specify what kind of intelligence officials have observed or what sectors may be most at risk, but it noted that cyberattacks against infrastructure are “part of Russia’s playbook,” referring to attacks against Ukraine, France, Georgia, South Korea and others that U.S. officials have blamed on Russian military intelligence. (See Six Russians Charged for Ukraine Cyberattacks.)

During a media briefing on Monday, Anne Neuberger, deputy national security adviser for cyber and emerging technology, declined to say whether intelligence agencies believe Russia has already attempted a cyber operation against the U.S., instead referring to “preparatory activity” that could include “scanning websites [or] hunting for vulnerabilities.”

However, Neuberger also reminded the audience that cyberattacks have been part of Russia’s ongoing operations against Ukraine, echoing warnings from the Cybersecurity and Infrastructure Security Agency (CISA) and other U.S. agencies early in the conflict about an outbreak of “destructive malware” affecting multiple countries the region.

These attacks have fallen short of the major cyberoffensive that many observers expected would accompany Russian military action against Ukraine, but experts have warned that President Vladimir Putin may be holding his strongest cyber capabilities in reserve as a hedge against a worsening military situation. (See Experts Warn Cyberwar Still Possible.)

Neuberger avoided saying which U.S. critical infrastructure sectors are most at risk, saying that the “steps that are needed … need to be done across every sector. … Even those sectors that we do not see any specific threat intelligence for, we truly want [them] to double down and do the work that’s needed.” But she did confirm that “key entities who need to know have been provided classified briefings” in the last several weeks.

While Neuberger provided few specifics, she did say that many entities still have not performed simple steps that would help mitigate against much of the risk.

“We continue to see known vulnerabilities, for which we have patches available, used by sophisticated cyber actors to compromise American companies [and] companies around the world … and that makes it far easier for attackers than it needs to be,” Neuberger said.

A fact sheet accompanying the White House’s statement listed a number of preparatory steps for private sector organizations to complete “with urgency.” Included in its recommendations are:

  • mandate the use of multifactor authentication and deploy “modern security tools” on computers and devices;
  • have cybersecurity professionals ensure that systems are patched against known vulnerabilities;
  • change passwords across networks and encrypt data so they cannot be used if stolen;
  • back up data to secure locations;
  • keep up-to-date emergency plans and run regular drills so employees can respond to attacks quickly;
  • train employees to avoid common hacking tactics; and
  • encourage employees to report unusual behavior from their computers or devices.

“What we’re asking for is: Lock your digital doors. Make it harder for attackers; make them do more work; [and that] will make it significantly harder, even for a sophisticated actor, to compromise a network,” Neuberger said.

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Court Backs FERC over ISO-NE’s Order 1000 Compliance

The D.C. Circuit Court of Appeals issued an opinion Tuesday siding with FERC over its finding that ISO-NE adequately complied with Order 1000’s provisions on competitive bidding for transmission projects.

The three-judge panel, led by A. Raymond Randolph, rejected a petition for judicial review from LSP Transmission Holdings (20-1422).

The petition centered around ISO-NE’s compliance with Order 1000’s requirement that RTOs remove “right of first refusal” provisions for transmission planning and move to a competitive selection process.

In 2013, while approving ISO-NE’s tariff revisions, FERC agreed that the RTO wouldn’t have to use a competitive process if it was dealing with “reliability-related” transmission projects, which are classified as those needed in three years or less to fix reliability violations on the system.

FERC later expressed concerns about the high number of projects with estimated “need-by dates” occurring within that three-year window but before the projects were in line to become operational.

In the docket where FERC asked ISO-NE to demonstrate compliance, LSP asked the commission to eliminate or limit the competition exception for reliability projects. But the commission ultimately found “insufficient evidence” that ISO-NE was noncompliant with Order 1000; the court declined to review that finding.

The judges wrote that because FERC had previously found that using need-by dates is preferable to in-service dates, it can again use that reasoning to dismiss LSP’s petition.

“We see nothing irrational in the commission’s response to LSP’s general criticism of ISO New England’s use of more conservative assumptions regarding its system capacity and future management,” they said.

And ultimately, the court found, it’s up to FERC to decide.

“The appropriate balance struck — between competitive procurement and quick redress of reliability needs — is the sort of policy judgment left to the commission,” the judges wrote.

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NYISO Files BSM Compliance, Extension Request

NYISO on Monday submitted a FERC compliance filing to establish a proposed effective date for the Part A test enhancements to its buyer-side market power mitigation rules (BSM) and requested an extension of time to submit all needed tariff changes no later than Aug. 1 (ER20-1718-003).

The commission in February reversed its September 2020 decision to reject the ISO’s proposal, voting 4-1 to accept NYISO’s revisions to the rules designed to prioritize evaluating state-subsidized resources. (See FERC Reverses Itself on NYISO BSM Exemptions.)

The Part A enhancements allow for evaluation of the new, policy-driven clean energy projects before evaluation of conventional energy projects and all projects under the Part B test, which is based on forecasts of unit-specific economics, the ISO said.

NYISO said that when it files the conforming tariff changes it will also address the effective date for the Part A enhancements “such that they will apply to the Class Year that begins immediately following Class Year 2021.”

Significant progress in Class Year 2021 has already been made over the past year, with several process milestones pertaining to the Part A enhancements having long since passed, and “trying to implement the Part A enhancements at this time to Class Year 2021 could be disruptive and cause confusion,” the ISO said.

NYISO originally filed the Part A enhancements in April 2020.

Initially, the ISO intended to implement the Part A enhancements for the Class Year 2019 study and included tariff language explaining that the revisions would apply to the Class Year 2019 and all subsequent BSM evaluations of examined facilities. Class Year 2019 was completed in January 2021, and Class Year 2021 began in March 2021.

Under the Part A test, NYISO will exempt a new entrant from the offer floor if the forecast of capacity prices in the first year of a new entrant’s operation is higher than the default offer floor, which is 75% of the net cost of new entry of the hypothetical unit modeled in the most recent demand curve reset.

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FERC Upholds CAISO Wheel-through Rules

FERC last week upheld its June 2021 finding that CAISO’s temporary wheel-through restrictions do not violate open-access transmission principles and approved a two-year extension of the provisions, but it urged the ISO to find a better long-term solution quickly.

In doing so, FERC rejected a rehearing request by the Arizona Corporation Commission and a coalition of Arizona utilities, including Arizona Public Service and Salt River Project, which continued to press their case that CAISO’s rules are discriminatory (ER21-1790).

The wheeling rules were part of a CAISO package of changes meant to promote summer reliability following the rolling blackouts and energy emergencies of summer 2020.

The rules reprioritized wheel-throughs so that transfers between the Northwest and Southwest could no longer take precedence over capacity needed to serve CAISO native load. Non-CAISO entities would have to apply at least 45 days in advance to designate high-priority wheel-throughs needed for reliability, giving the wheels equal standing with CAISO native load.

Utilities in the Southwest, dependent on Pacific Northwest electricity imported through CAISO’s grid each summer, were displeased. FERC, however, found the provisions acceptable. (See FERC OKs CAISO Wheel-through Restrictions.)

It reiterated that stance in its decision March 15.

“We continue to find that the scheduling priorities implemented in the interim tariff revisions result in a just and reasonable interim solution that is consistent with open-access policies, including the native load priority principles first articulated in Order No. 888 and reconfirmed in Order No. 890,” FERC wrote.

“These interim tariff revisions were designed to enable CAISO to maintain reliability in the summer of 2021 and strike a reasonable balance between ‘the transmission provider’s need to meet its native load obligations and the need of other entities to obtain service to meet their own obligations,’” it said.

Before the revisions, wheel-through transactions could receive scheduling priority higher than CAISO’s native load requirements, FERC noted.

The provisions “adjust scheduling priorities to protect native load by giving resource adequacy imports a scheduling priority equivalent to priority wheeling-through transactions and higher than non-priority wheeling-through transactions,” it said.

FERC acknowledged, however, that stakeholders remain “deeply divided” over the changes and said the challenging parties had reconveyed their “serious concerns with CAISO’s approach to implementing a native load priority.”

“The Federal Power Act does not require the commission to determine that a proposal is the best solution, only a reasonable one,” FERC said. “Therefore, we sustain the result in [our] June 2021 order as a just and reasonable interim solution for allocating transmission capacity fairly among users when the system is constrained.

“Nevertheless, in light of the interim tariff revisions’ potential impacts on neighboring balancing authority areas and parties’ ongoing concerns, we expect CAISO to work with stakeholders to design and file a just and reasonable and not unduly discretionary or preferential long-term solution as expeditiously as possible.”

In a related order (ER22-906), the commission accepted CAISO’s decision to extend the wheeling provisions for two more years through May 2024. The rules were originally scheduled to expire June 1 of this year. (See CAISO Extends Wheel-through Rules.)

“We find that extending the interim tariff revisions is just and reasonable and will provide certainty regarding the rules for wheeling-through transactions, while CAISO and stakeholders develop a long-term solution that will clearly delineate rights across CAISO’s transmission system,” FERC said.

The commission warned CAISO, however, that its findings were based on the rule changes being “interim,” not “indefinite,” and repeated its call for a quick resolution between the ISO and affected parties.

The commission also instructed CAISO to file quarterly reports updating it on its progress.

“In these filings, CAISO must describe any long-term alternative solutions being considered in the stakeholder process, explain any potential impediments to implementing any particular solution and provide an updated schedule for finalizing a proposal,” it said.

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FERC Rejects PG&E Bid to Raise Profits

FERC on Thursday shot down the latest attempt by Pacific Gas and Electric to significantly increase its return on equity based on the utility’s risks associated with wildfires and California’s transition to renewable energy (ER16-2320).

PG&E had asked FERC to retroactively increase its ROE from 9.13% to 13.29% in its transmission owner tariff for 2017-18. The utility said it needed larger profits to entice investors wary of the state’s inverse condemnation laws, which hold utilities strictly liable for wildfires ignited by their equipment.

It also contended the state’s ambitious environmental goals saddle it with cost-recovery risks associated with planning and operating a safe and reliable grid.

FERC, however, said the basis for PG&E’s ROE was a six-month test case in 2017 that ended prior to the utility’s equipment sparking the highly destructive wine country fires of October 2017. A series of catastrophic blazes ignited by PG&E equipment followed in each of the next four years, including the state’s deadliest wildfire, the Camp Fire, in November 2018, and its second largest wildfire, the nearly 1 million-acre Dixie Fire, last summer.

PG&E argued the wildfires put it in a high-risk category and justified an increased ROE. The California Public Utilities Commission and others opposed the move because of the potential cost impact on customers. They proposed a rate of less than 9%.

FERC concluded that PG&E was an average-risk utility during the 2017 test period and said its stock price and credit ratings declined dramatically only after the wine country fires and subsequent blazes.

“The October 2017 wildfires and resulting financial consequences and credit rating downgrades for PG&E occurred subsequent to the test period, such that we will not consider them in determining PG&E’s risk profile,” it said.

The commission applied its revised methodology for calculating ROE from Opinion 569-A issued in May 2020 and two related opinions. It ruled an “appropriate” ROE for PG&E was 9.26% based mainly on its risk profile prior to the wine country fires.

Dissents

Commissioner James Danly dissented from what he called the “common-sense defying outcome” in the case.

“In my view, it simply is not credible that PG&E faced the same risks as any other ‘average’ utility in light of rampant wildfires, California’s inverse condemnation laws (which require PG&E to compensate landowners for fire damage), and a host of other risks unique to a utility attempting to survive in California’s challenging legal and regulatory environment, in 2017 and since,” Danly wrote.

The inverse condemnation laws helped drive PG&E into bankruptcy in January 2019 after the Camp Fire, which killed 85 people and leveled the town of Paradise, he said.

FERC’s decision “underscores a fundamental concern I have with the commission’s convoluted ROE precedent and policy,” Danly said. “We have created a Rube Goldberg machine that ultimately can be manipulated into supporting any ROE a majority of commissioners favors at a given moment.”

Commissioner Allison Clements dissented in part but for different reasons. She agreed with the majority’s decision that PG&E was an average-risk utility during the test period, and said FERC had correctly applied the commission’s ROE policy established in Opinion 569-A.

“However, I dissent in part from today’s order because of my continuing concerns with the current ROE policy, which I believe applies a flawed methodology that does not adequately protect consumers and does not yield just and reasonable rates,” Clements said.

Not wanting to repeat herself, she referred readers to her May 2021 dissent in Opinion 575 (ER13-1508-001), in which FERC applied the methodology it had adopted for MISO transmission owners in Opinion 569-A a year before.

In that case Clements said the methodology, including the “risk premium model” applied by FERC to ROE calculations, failed to protect consumers. (See FERC Reduces Entergy’s Return on Equity.)

“The order of magnitude of transmission investment required to achieve [decarbonization, resilience and replacement of aged infrastructure] is unprecedented, which translates into a massive opportunity for utilities and transmission developers,” she wrote in Opinion 575. “But the value proposition for consumers is in no small part dependent on this commission’s rigorous scrutiny of the rates charged for transmission service, of which ROE is a central component.”

“Given this context, I believe the commission must revisit its existing ROE policy,” Clements said. “I appreciate that this policy has been unsettled for years, a state that increases investment uncertainty and extends litigation.

“To be sure, I share the goal of a stable ROE policy that will speed rate proceedings and allow for timely ROE updates as market conditions change,” she said. “But we should not double down on the desire for near-term stability to strong detriment of consumer protection, and I worry our current ROE policy does just that.”

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ERCOT: Sufficient Resources to Meet Spring Demand

ERCOT has sufficient installed generating capacity to serve peak demand under normal system conditions this spring, according to the seasonal assessment of resource adequacy (SARA) released last week.

The Texas grid operator is forecasting demand to top out at 64.7 GW, based on expected spring peak weather conditions. It expects to have 94.4 GW of resource capacity available for the spring season (March-May).

Staff has projected a 52.5% capacity planning reserve margin (PRM) for the spring that covers resource outages, lower-than-expected renewable output, and higher-than-expected customer demand. The PRM is not the same as operating reserve measures that focus on actual available capacity during real-time and hour-ahead operating periods.

The SARA report includes 14 reserve capacity risk scenarios developed according to varying load-forecast values and resource-availability parameters, divided into two separate periods: the March and April peak maintenance season and the May peak demand month. The scenarios are based on historical data, known changes expected in the near-term or reasonable assumptions regarding potential future events.

ERCOT has added 31 wind, solar and energy storage projects since November, with just over 1 GW of expected capacity contribution during peak demand. An additional 367 MW of planned gas-fired and wind resources are also expected to be available for spring’s peak demand.

The SARA report is intended to illustrate the range of resource adequacy outcomes that might occur and serves as a situational awareness tool for ERCOT’s operational planning purposes.

As has been the case since last summer, the SARA was issued in a market notice and without an accompanying media briefing.

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AEP Completes 1.5-GW Wind Energy Development

American Electric Power said Monday its Traverse Wind Energy Center, the last of three Oklahoma wind projects with a total capacity of 1.5 GW, is generating energy for customers in Arkansas, Louisiana and Oklahoma.

The 998-MW Traverse Center is the largest of the $2 billion North Central Energy Facilities’ three wind farms. The Sundance Wind Energy Center (199 MW) and the Maverick Wind Energy Center (287 MW) began commercial operation in April and September of last year, respectively.

Collectively, the wind farms are among the world’s largest wind facilities. AEP said they will save customers an estimated $3 billion in electricity costs over the next 30 years.

“The completion of the North Central Energy Facilities is a significant milestone in our efforts to provide clean, reliable power to our customers while saving them money,” AEP CEO Nick Akins said in a statement.

AEP subsidiaries Southwestern Electric Power Co. and Public Service Company of Oklahoma have taken ownership of the three wind farms after Invenergy completed their development. Invenergy Services will provide operations and maintenance services as part of a 10-year agreement.

AEP is investing $8.2 billion in regulated renewables and nearly $25 billion through 2026 to modernize grid systems, improve reliability and resilience, and provide more emissions-free energy. It plans to add about 14.5 GW of wind and solar in its regulated states by 2030 as part of a goal to achieve net-zero carbon emissions by 2050.

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Burke to Succeed Morgan as Vistra’s CEO

Vistra (NYSE:VST) said Monday that its board of directors has named 16-year company veteran Jim Burke as its next CEO effective Aug. 1, replacing Curt Morgan after a transition period.

The move is part of the company’s formal succession planning process, Vistra said.

“I am incredibly honored and humbled to assume the responsibility of leading Vistra,” said Burke, currently the Texas-based company’s CFO. Vistra hopes to name his replacement before Aug. 1.

Morgan-Curt-2017-Oct-RTO-Insider-FI.jpgCEO Curt Morgan is leaving Vistra after 37 years in the industry. | © RTO Insider LLC

Burke joined Vistra when it was TXU Corp., under new CEO C. John Wilder’s leadership, in 2005 following the company’s international financial difficulties. In 2007, the company was bought by private equity investors in a $45 billion leveraged buyout and went private as Energy Future Holdings. It declared bankruptcy in 2014, eventually emerging as Vistra Energy in 2016.

Burke was CEO of TXU Energy, Vistra’s retail company, until 2016, when he was named COO. He became CFO in December 2020. He was president and COO of Gexa Energy before joining TXU.

Morgan has served as Vistra’s CEO since 2016 and has a 37-year career in the power industry. He said in a statement that with the company having “created significant value for our shareholders, transformed our company … and firmly established Vistra as a leader in the country’s energy transition, now is the right time for this leadership transition.”

Vistra board Chair Scott Helm thanked Morgan for his leadership in helping grow the company into “one of the largest power producers and retailers in the United States.”

“While achieving this tremendous growth, Vistra has also significantly reduced its carbon footprint by retiring coal-fueled power plants and is rapidly growing its zero-carbon portfolio [Vistra Zero], all while returning a substantial amount of capital to its financial stakeholders,” Helm said.

Morgan will remain until next April as a special adviser to Burke and the board, a spokesperson said.

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NYISO Business Issues Committee Briefs: March 16, 2022

Monthly Energy Prices up 123% Y-o-Y 

NYISO locational-based marginal prices averaged $94.06/MWh in February, down from $134.79/MWh the previous month and higher than the $63.70/MWh average in February 2021, Rana Mukerji, senior vice president for market structures, said in delivering the monthly operations report to the Business Issues Committee on Wednesday.

Day-ahead and real-time load-weighted LBMPs came in lower compared to January.

Year-to-date monthly energy prices averaged $118.36/MWh, a 123% increase from $52.99/MWh a year ago, which Mukerji attributed to higher natural gas prices.

February’s average sendout was 429 GWh/day, down from 451 GWh/day in January and 434 GWh/day a year earlier.

Transco Z6 hub natural gas prices averaged $6.17/MMBtu for the month, down from $11.15/MMBtu in January and up 18.3% year-over-year.

Distillate prices were up 64.5% year-over-year. Jet Kerosene Gulf Coast averaged $19.79/MMBtu, up from $17.96/MMBtu in January. Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $20.46/MMBtu, up from $18.53/MMBtu in January.

February uplift decreased to -$1.73/MWh from -$1.50/MWh in January, and total uplift costs, including the ISO’s cost of operations, came in higher than those in January.

The ISO’s local reliability share dropped to 4 cents/MWh/MWh in February from 9 cents/MWh the previous month, while the statewide share dropped to -$1.77/MWh from -$1.59/MWh.

The Thunderstorm Alert cost in New York City was $2.98 because of some unusual thunderstorm activity in the month.

Real-time BPCG Eligibility Changes

The BIC recommended that the Management Committee approve tariff revisions that would change the provisions for real-time bid production cost guarantee (BPCG) payments.

BPCGs are paid as an incentive for resources directed to run by the ISO. In order to close a loophole whereby units may receive inappropriate real-time BPCG payments under certain circumstances, the new tariff language would add an exception to the eligibility criteria for units placed out-of-merit (OOM) for reliability, said Mark Buffaline, senior settlements analyst at the ISO.

As an example, the ISO hypothesized a unit scheduled for energy in the day-ahead market (DAM) at 100 MW bidding self-committed fixed/flex in the real-time market with a self-schedule at 200 MW. That unit operating in real time at 200 MW aggravates any transmission constraint and would be placed OOM for reliability with a 140-MW upper operating limit (UOL).

“The unit receives RT BPCG for 40 MW, and by self-scheduling at 200 MW in real time, they have indicated that they want to be a price-taker for all output up to 200 MW,” Buffaline said.

Units that bid self-committed fixed/flex at megawatt levels above the DAM energy schedule are generally ineligible for real-time BPCG, but by placing them out-of-merit for reliability, this makes them eligible for real-time BPCG, which supersedes the self-commitment ineligibility rule, he said.

“That is the discrepancy between the rules that we’re plugging here,” said Chris Brown, lead settlements analyst at NYISO. “So those costs representing that self-committed bid are no longer going to be eligible for a make-whole payment under this scenario with units out-of-merit for reliability.”