Search
`
November 7, 2024

Posted on

NYPSC OKs Exelon Spinoff of 4 Upstate Reactors

New York regulators on Thursday approved Exelon’s (NASDAQ:EXC) plan to split its regulated transmission and distribution business and merchant nuclear power generation into two separate publicly traded companies (Case No. 21-E-0130).

The Public Service Commission accepted a joint proposal by Exelon staff of the Department of Public Service, the state Attorney General, the Alliance for a Green Economy and the Long Island Power Authority for four upstate nuclear power plants to be spun off by Exelon.

The spinoff, Exelon Generation, will become part of a new, independent, publicly traded entity that owns the two-unit 1,918-MW Nine Mile Point nuclear power plants in Scriba, Oswego County; the 579-MW R.E. Ginna nuclear power plant in Ontario, Wayne County; and the 842-MW James A. FitzPatrick nuclear power plant, also in Scriba.

“Getting all the parties from disparate sides to sit at the table together to agree on this shows how significant their goals were of supporting the interests of New York,” PSC Chair Rory M. Christian said. “The simple fact that we’re going to be able to decommission these plants in 20 years, rather than the recommended 60, is a huge accomplishment. The financial protections you accomplished and achieved through these negotiations are just as significant.”

FERC in August approved the corporate transfer proposal, determining the transaction to be “consistent with the public interest” (EC21-57). (See FERC Sanctions Exelon’s Plan to Split Utility, Generation Businesses.)

The current operating licenses expire in 2029 for Ginna and Nine Mile Point 1, 2034 for FitzPatrick and 2046 for Nine Mile Point 2. The Nuclear Regulatory Commission (NRC) and the PSC required funds be set aside for the decommissioning of the facilities and the restoration of the sites.

Operational Details

Diane X Burman (NYPSC) Content.jpgNYPSC Commissioner Diane X. Burman | NYDPS

A lot of these issues were not as contentious as others for the parties, so working with the collaborative process seems to have worked here, Commissioner Diane X. Burman said.

Exelon has an “extraordinary obligation” to the state of New York, considering the more than $7 billion in ratepayer money that supports the four units and without which these plants would have ceased operation some time ago, Commissioner John B. Howard said.

“Second of all, the parent of this company, it should be pointed out, has had serious corruption allegations in the state of Illinois, and those are being pursued by various law enforcement and prosecutorial entities in that state and with the federal government. So that was the background by which we started this case,” Howard said.

Exelon also has proven itself devoted to focusing on safety and reliability, Howard said.

John B Howard (NYPSC) Content.jpgNYPSC Commissioner John B. Howard | NYDPS

In addition, the nuclear plants represent “a huge chunk of the overall central New York economy” and the people working at the facilities are “maybe the highest-paid and best-benefited workers in the region,” he said.

Under the approved proposal, Exelon and Exelon Generation agreed to the following:

  • Continuation of emergency operation facilities in New York;
  • Depositing an additional $15 million in the remedial trust fund for Nine Mile Point Unit 2 and maintaining a minimum trust fund balance of $144 million per unit — or $576 million in total across the four units;
  • Provide a 20-year projected backstop timeline for decommissioning following the end of licensed term rather than the 60 years allowed by the Nuclear Regulatory Commission;
  • Acknowledgment of New York State’s 10 millirem clean up guidance standard for residual radiation, rather than the NRC 25 millirem standard;
  • Annual decommissioning trust fund reporting rather than the 2-year summary level reporting to NRC, and twice-a-year reports during decommissioning; and
  • Provide an 18-month advance notice of shut down rather than the 12-month NYISO requirement.

Proposal supporters included the affected counties, the New York State Building and Construction Trades Council and the International Brotherhood of Electrical Workers, Local 97, representing approximately 4,700 electrical workers across upstate New York.

Posted on

FERC Sits Out One Grand Gulf Tax Dispute

FERC told the Louisiana Public Service Commission Thursday that it would not appoint a discovery master or settlement judge in an ongoing dispute over Entergy’s decommissioning deduction for its Grand Gulf Nuclear Station.

The PSC is attempting to compel Entergy subsidiary System Energy Resources, Inc. (SERI) to hand over accounting information and discussion notes with the IRS and understand the sudden decision to forgo a deduction it has enjoyed and renewed for 17 years (ER21-142).

However, the tax clash will continue to play out in another FERC docket.

The federal commission said in its order that state regulators were raising their arguments under an informal challenge as an interested party and that they needed a more formal channel for those measures.

The PSC filed the information request through a 2020 amendment to SERI’s formula rate protocols that allows interested parties to request information and submit informal challenges to unit power sales agreements. The commission claimed it needed to better understand Grand Gulf’s 2020 formula rate inputs.

SERI owns 90% of the 1,400-MW Grand Gulf plant in Port Gibson, Miss., and sells the plant’s output under a FERC-regulated wholesale rate to Entergy’s Arkansas, Mississippi, Louisiana and New Orleans subsidiaries. It’s taken a tax deduction since 2003 for future costs of shuttering the plant.

The Louisiana commission alleges SERI’s Grand Gulf power sales agreements contain “millions of dollars of unjust and unreasonable charges” because it didn’t reflect the decommissioning tax benefit in its rates. The PSC has accused Entergy of collecting money from ratepayers for taxes that were never paid.

The Louisiana commission and Entergy are involved in a separate docket before FERC over whether the utility violated filed rate doctrine by neglecting to include the decommissioning deduction as a rate base offset. The federal commission this year set that case for settlement hearings to determine customer refunds (ER21-748).

SERI relinquished its decommissioning deduction in 2020 following an IRS Notice of Proposed Adjustment that disallowed more than $1 billion of the deduction. The subsidiary quickly accepted the settlement, and Entergy said its net operating loss carryforwards would absorb the adjustment’s costs.

The Grand Gulf plant has been criticized in recent years for its persistent unplanned outages. Earlier this year, the PSC was joined by the Arkansas Public Service Commission and the New Orleans City Council in a FERC complaint over the plant’s malfunctions and performance issues. The trio argued that Entergy should refund customers the $800 million spent on upgrades to the plant in 2012. They also said Entergy should refund its customers the $361 million in power purchases it has had to make when the station was unavailable since the upgrade.

The Louisiana PSC has registered other grievances about Grand Gulf rates, arguing that SERI’s return on equity was overstated. (See FERC Rebuffs Challenges to Grand Gulf Ruling.)

Posted on

FERC Ups Hydro Dam Inspection and Safety Requirements

FERC on Thursday approved a rule to improve hydro dam safety by instituting a two-tier inspection program and requiring such inspections to be performed by teams with site-specific expertise, rather than a single independent consultant.

Additional provisions in the rule (RM20-9-000) will also codify a 2012 requirement that dam owners develop and file with FERC a Dam Safety Program, as well as report any public safety incidents, including rescues, related to project operations. The rule passed unanimously, with newly installed Commissioner Willie Phillips not voting. It will take effect 90 days after publication in the Federal Register.

The new requirements are based on recommendations from an analysis of the February 2017 incident in which California’s Oroville Dam, the tallest dam in the nation, saw major damage to its primary spillway and the first activation of its auxiliary spillway. About 180,000 people were forced to evacuate the surrounding area. Emergency response and repairs cost more than $1.1 billion, said a recent report from the Congressional Research Service.

Citing that report, FERC Chair Richard Glick said that the U.S. has 90,000 dams, 15% of which are classified as “high hazard potential,” meaning that any failure of the dam could result in loss of life. In addition, half the dams are more than 50 years old and could require upgrades costing an estimated $20 billion, Glick said.

FERC has jurisdiction over more than 2,500 hydro projects, said a Hydropower Primer the commission released in 2017. Following the Oroville incident, FERC convened its own review panel to suggest potential changes to its Dam Safety Program. A notice of proposed rulemaking (RM20-9) was issued in July 2020. (See FERC Proposes Tougher Hydro Safety Rules.)

David Capka, director of the Division of Dam Safety and Inspections in the Office of Energy Projects, said the final rule contains some “clarifying edits” made in response to comments received from stakeholders, including dam owners, other federal agencies and trade associations. But otherwise, it is essentially the same as the 2020 NOPR, he said.

Two-tier System

Prior to the vote, Tara DiJohn, attorney-advisor in FERC’s Office of General Counsel, provided more detail on the four “overarching objectives” of the rule.

All hydro projects under FERC’s jurisdiction will still be subject to the commission’s inspection rules, as spelled out in regulations known as Part 12D, which require inspections every five years. But, DiJohn said, under the two-tier system, “the required scope of the inspection will alternate between a periodic inspection and a comprehensive inspection.”

Ultimate damage at the service spillway (California Department of Water Resources) Alt FI.jpg
Ultimate damage at the Oroville service spillway | California Department of Water Resources

Periodic inspections will focus on “the performance of the project over the previous five years,” she said. “It includes a field inspection or review of project operations, an in-depth review of monitoring data trends and behavior, and an evaluation of whether any potential failure modes are occurring.”

Comprehensive assessments will build on the periodic reviews “with a deep dive into every aspect of a project, including a detailed review of the design basis, analysis of records and construction history, and evaluation of spillway adequacy [and] potential failure modes analysis and risk analysis,” she said.

Commissioner Allison Clements raised concerns about the cost of the new inspections. “If we’re going to strengthen safety, we have to balance the benefits of more stringent requirements with the cost burden to the regulated [projects], including the smaller entities that may have fewer resources,” she said.

The two-tier system is intended to help offset the cost of inspections, DiJohn said, with the periodic inspections being “less burdensome.” With smaller, less complex projects, licensees can also propose a single independent consultant to perform the inspection, she said.

First Line of Defense

The second major provision modifies who performs the Part 12D inspections. “Instead of focusing on the individual independent consultants, we will focus on the qualifications of the independent consultant teams,” DiJohn said.

“We have a lot of very large and very complex projects, and requiring one person to be responsible to review all the features of those projects is a lot to ask,” she said. “To have the right expertise, we want to ensure that licensees look at teams to do that.”

While first required in 2012, the Dam Safety Programs codified in the new rule will “formalize licensees’ policies and procedures related to organizational oversight and responsibilities, internal communication, resource allocation and continuous improvement,” DiJohn said. “A proactive, conscientious licensee is the first line of defense against potential dam safety issues.”

Finally, the rule expands requirements for reporting on public safety incidents at or near dams, DiJohn said, adding rescues to the list of incidents to be reported, along with serious injuries and deaths.

Calling dam safety “one of our most important jobs,” Glick said the new rule was “a step in the right direction … [but] not the end of our efforts to protect the public.” The commission is planning a staff-led technical conference, possibly in April, Glick said, examining financial assurance measures for hydropower projects to ensure than licensees have sufficient financial resources for dam maintenance and repair as needed for public safety.

Posted on

MISO-SPP M2M Settlements Exceed $200M

SPP’s market-to-market (M2M) settlements with MISO exceeded $20 million in October for the second time in 12 months, staff told the Seams Advisory Group Wednesday.

The $20.59 million in settlements, which accrued in SPP’s favor, pushed the M2M payments due to SPP to $203.87 million since the grid operators began the process in March 2015.

Permanent and temporary flowgates were binding for more than 1,875 hours in October. Outages and power swings from nearby wind increased shadow prices. The grid operators exchange settlements for redispatch based on the non-monitoring RTO’s market flow in relation to firm-flow entitlements.

M2M settlements hit a record $51.49 million, in MISO’s favor, in February, thanks to February’s winter storm. Settlements have accrued to SPP during the eight months since February and for 23 of the last 25 months.

New SAG Members

The group welcomed new members Luke Haner of Omaha Public Power District and Brenda Prokop of ITC Great Plains to their first meeting.

The SAG still has three open seats that it plans to fill next year. With a membership normally dominated by transmission owners, the group hopes to diversify by targeting larger retail customers and generation developers when it seeks applications after Jan. 1.

Rate Pancaking Issues

The Seams Liaison Committee’s (SLC) Pancaking Working Group met briefly Wednesday to review survey results of stakeholders’ pancaking issues and its information request of SPP and MISO.

Only five of 20 respondents to the stakeholder survey said their companies have experienced a failed cross-seam transaction, transmission project or interconnection project because of rate pancaking issues. Twelve said rate pancaking is a factor when seeking long-term generation commitments and half said the same for siting or accessing generation in a particular location.

Stakeholders said reservations timing is not consistent between the RTOs. SPP charges for all use of its transmission system, including unreserved use, while MISO only bills for network services taken, not reserved, at the time of the monthly system peak. MISO bills for transmission service each month based on actual usage at the zonal coincident peak, but SPP uses a 12-month rolling average.

Point-to-point reservations (Organization of MISO States) Content.jpgPoint-to-point reservations across the seam | Organization of MISO States

The RTOs told the working group that 59 load-serving entities have transactions across the seam. MISO has three active point-to-point (PTP) service requests across the seam and SPP had 75 network service and PTP requests.

Marcus Hawkins, the Organization of MISO States’ executive director, said he has not yet sifted through all the data, leading to group to plan another meeting in January to take a deeper dive. The working group plans to present its findings to the SLC in February.

Posted on

CAISO Proposes Paying Storage Differently

CAISO issued a straw proposal this week that seeks to address the state’s dependence on energy storage for meeting summer evening peaks by paying batteries to stay charged during the day in readiness for when they are needed most.

Avoiding energy emergencies like those in the past two summers requires batteries to be ready to discharge during heat waves in the hours after the sun sets and solar goes offline, CAISO said.  But requiring storage resources to maintain a state of charge means they cannot take advantage of other financial opportunities during the day, it said.

“A principal concern raised by the storage community is a lack of compensation during critical periods when the ISO must retain state of charge on limited energy storage devices, which may preclude their active participation in the real-time markets,” the proposal says. “The existing bid cost recovery rules, which are designed based on traditional energy generation resources, do not consider energy storage charging and discharging cycles.”

A main objective of CAISO’s energy storage enhancements stakeholder initiative is to develop a “set of solutions to enhance the optimization of storage resources and to allow additional flexibility for storage operators to manage state of charge in the real-time markets,” the straw proposal says. “The ISO proposes a new model, called the energy storage resource (ESR) model, which is unique from existing models because bids are predicated on state of charge values, rather than a dispatch instruction for power.”

The ESR model would require scheduling coordinators to “submit bids in terms of incremental state of charge instead of traditional bids submitted in terms of incremental energy,” in recognition that a resource’s costs to charge and discharge are different based on its state of charge, it says.

“Specifically, the energy storage resource model will allow storage resources to offer lower prices to provide energy when a battery has a nearly full state of charge and higher prices when it is nearly depleted,” it says. “This new model would be employed in the ISO’s market software for both the day-ahead and real-time markets and could be used by participants in the energy imbalance market.”

Before last summer, FERC approved a temporary two-year measure by CAISO to require batteries to maintain a minimum state of charge on days with insufficient supply to meet demand. The proposed changes are intended as long-term market rules.

Another part of the proposal involves paying storage resources for exceptional dispatch by compensating them “at the difference between the prevailing price during the exceptional dispatch and the reference interval discharge price. The reference interval discharge price will be the period when the storage resource actually discharges and sells energy.”

Batteries Proliferate

The proposed new rules reflect the state’s growing reliance on batteries to maintain reliability.

CAISO will have 2,500 MW of four-hour lithium-ion battery storage connected to its grid by the end of this year, CEO Elliot Mainzer told the Western Energy Imbalance Market’s Governing Body on Wednesday. He called 2021 the “advent of the bulk storage fleet on the California grid.”

“I believe that is the highest concentration of lithium-ion battery storage in the world and testament to years of policy support and procurement efforts by state officials,” he said.

Most of the battery resources were connected in response to the rolling blackouts of August 2020, when the state’s vulnerabilities to outages during severe Western heat waves became clear. The state’s increasing reliance on solar and wind power, without sufficient storage, was partly to blame for the energy emergencies. (See CAISO Sees ‘Explosive’ Growth in Storage in July.)

The energy storage enhancements stakeholder initiative, which began in May, focuses on market reforms to bring massive amounts of utility-scale storage into CAISO’s system to back up the solar and wind power needed for California’s transition to 100% clean energy by 2045, as well as to meet local capacity requirements. (See CAISO Readies for Storage Scale-up.)

The separate energy storage and distributed energy resources (ESDER) stakeholder initiative began five years ago and proposed numerous changes in four phases. FERC approved the fourth phase in October; it included market power mitigation measures for storage resources and biddable state-of-charge parameters. (See FERC Accepts Latest CAISO Storage, DER Rules.)

CAISO expects to add at least another 1,000 to 2,000 MW of storage in 2022-2024, most of it in lithium-ion batteries with four-hour discharging capacity.

Summer reliability issues will likely continue through 2024, as natural gas plants close and the state’s last nuclear generator, Pacific Gas and Electric’s Diablo Canyon power plant, begins shutting down, CAISO has said. State energy planners hope a large-scale buildout of solar, wind and batteries will compensate.

Posted on

SERC Urges Winter Preps Before Standard Enforced

NERC Trustee Roy Thilly urged members to adopt the agency’s new cold weather standards before they become enforceable in early 2023 during SERC Reliability’s year-end board meeting.

“The tolerance for outages is non-existent,” Thilly said Wednesday, referring to the general public’s attitude.

He also warned that regions can’t depend on neighboring supplies should a widespread weather event strike, saying it takes four years on average to implement a new standard after a major event.

“That simply is too long a period in some cases,” Thilly said. “We need to decide when we need to be more agile and nimble.”

SERC’s 2021 regional risk report listed supply chain issues, extreme weather, generation fleet transitions, cyber security threats, a dependence on rising natural gas prices and the challenge of integrating variable resources as major concerns this winter. (See Grid Faces Multiple Risks in Winter Months, NERC Warns.)

SERC CEO Jason Blake said the organization plans to tailor its operations more closely to its regional risk reports in 2022. He said it’s important for SERC to be able to point to the report’s sections as the reasons behind workshops and agenda items.

Blake also said SERC will focus more on severe weather preparations.

“We have a very hot footprint; we have parts of the footprint that get pretty cold,” he said. “We also have parts of the East Coast. … If you’re going to get hit by a hurricane, you’re probably in SERC.”

SERC board member Venona Greaff said the new freeze-protection rules should surprise no one.

“For many, it seemed like a freight train bearing down on us, but it’s been a long time coming,” she said, noting that parts of the country have been experiencing notable cold-weather strain on the grid since 2011.

Greaff said NERC left cold weather undefined, giving generation operators the responsibility of deciding which temperatures pose a risk. She said it’s not realistic for the Deep South to enclose entire plants in buildings like those in the North. Greaff said that during the summer, southern generation operators need heat to dissipate, but said operators could consider enclosing smaller segments of their facilities.

Melinda Montgomery, SERC’s senior director of engineering and advanced analytics, said about 86% of SERC entities in a recent survey intended to complete plant winterization before the end of November.

Montgomery said the organization plans to survey its members again on their performance following this winter.

Montgomery said while gas well-head freeze offs and frozen coal piles were an issue in SERC territory during February’s winter storm, frozen plant equipment, water supply issues and local transmission emergencies also contributed to the loss of load.

The February event culminated in the largest controlled firm load shed event in U.S. history at more than 23.4 GW. (See FERC, NERC Release Final Texas Storm Report.)

David Huff, an engineer with FERC’s Office of Electric Reliability, said the winter storm wrought the largest monthly decline of U.S. natural gas production on record. He said production in the continental U.S. dropped 28%; Texas’s production alone dipped more than 70% when compared to its January production.

Huff said 1,045 generating units experienced 4,124 “outages, derates or failures to start.” Of those failures, 58% came from natural gas-fired generation. He said frozen equipment accounted for more generation outages than fuel-supply issues. However, if there was an outage caused by fuel supply, it was overwhelmingly a natural gas generator.

Protecting transmitters, sensing lines and instrument against freezing, as well as protecting wind turbine blades against icing could have reduced offline megawatts caused by outages, Huff said.

Posted on

PUC Forges Ahead with ERCOT Market Redesign

Texas regulators on Thursday pushed ahead with commission staff’s proposal to re-design the ERCOT market, directing the grid operator to work with it in implementing the two-phase approach.

In a 35-minute discussion, the Public Utility Commission did not address the 54 stakeholder comments it received on staff’s Dec. 6 strawman proposal, sticking to language in staff’s original memo. (See PUC Narrows Options for ERCOT Market Redesign.)

In two orders, the commissioners agreed to adopt the strawman as its market redesign blueprint and ordered ERCOT to take the strawman’s Phase 1 blueprint and file a comprehensive implementation report on the plan by Jan. 10. The commissioners also directed the ISO to prepare nodal protocol revision requests for their approval, potentially sidelining ERCOT’s stakeholder process.

Phase 1’s order involves modifying the operating reserve demand curve (ORDC); allowing for “more targeted response” to increase the use of load resources; reforming emergency response service; and adding new ancillary service products.

The PUC ordered ERCOT to make the ORDC changes effective Jan. 1. The modifications include setting the curve’s minimum contingency level to 3,000 MW and eventually decoupling the systemwide offer cap and the value of lost load, now set at $5,000/MWh.

The commission earlier this month lowered the high systemwide offer cap to $5,000/MWh. (See Texas PUC Pushes 44% Reduction in ERCOT Offer Cap.)

Texas PUC Meeting 2021-12-16 (Texas Admin Monitor) Content.jpgPUC Chair Peter Lake (2nd from right) explains his thoughts on the ERCOT market redesign. | Texas Admin Monitor

 

PUC Chair Peter Lake also asked commission staff to work with ERCOT in “crystalizing” the major “abstract” concepts of Phase 2, which is described in the second order. He said staff should focus on Phase 2’s backstop reliability service proposal first and then the load-side reliability mechanism he has been promoting since October.

Neither order had been filed as of Thursday evening.

The PUC did not discuss the cost impact of its proposals.

ERCOT’s Kenan Ögelman, vice president of commercial operations, told the PUC that ERCOT staff would target a Feb. 15 deadline to provide the inputs, specifications, quantification and relevant metrics it would need to design and build each of the Phase 2 proposals.

Alison Silverstein, a former PUC and FERC staffer, said in a fiery response to RTO Insider that she was “deeply disappointed” by the commission’s actions. She said the commissioners should have called for “much more” analysis of both phases’ reliability, market and cost impacts and should include better stakeholder and public input going forward.

“Today the commission voted to implement many Phase 1 measures that will have interacting effects on resource and system operating capabilities and costs, without any clear analysis of whether and how it will all work together or what it could cost Texas electric customers,” Silverstein said. “We don’t know whether all these measures will collectively help or hurt day-to-day resource availability and reliability, and there has been zero calculation of how much additional money they will suck out of Texas electric customers’ wallets.

“I’m willing to pay more for better reliability, as are many Texans, but it’s the commission’s responsibility to make sure that we get what we pay for. Today, the PUC abdicated that responsibility,” Silverstein said.

Consultant Doug Lewin of Stoic Energy, who live-tweeted the open meeting, said although there will be a cost analysis on the load side reliability mechanism and the backstop reliability service, “it still seems to me like they’re missing an integrative look at system needs.”

“How big should the backstop reliability service be? What are we basing that on: a detailed, transparent analysis?” he said in an email to RTO Insider.

Both Lewin and Silverstein said the FERC-NERC investigation of Winter Storm Uri’s devasting power outages in Texas and elsewhere was largely ignored by the PUC. The report laid the blame for the nation’s largest controlled load shed at the foot of the natural gas industry and listed 28 recommendations to prevent a reoccurrence. (See FERC, NERC Release Final Texas Storm Report.)

“There was a lot of discussion at the legislature and in the press about how the 2011 recommendations were largely ignored,” Lewin said. “How seriously are we taking this more recent set of recommendations?”

ERCOT said in a statement that the PUC’s proposals “will require a lot of coordination among all the market participants and market experts,” calling them “the most significant and important changes … since [the market’s] migration to a competitive market almost a quarter-century ago.”

“ERCOT is glad to be able to assist the PUC in this effort and will continue to work closely with the agency to meet the aggressive timeline,” a spokesperson said.

“It is unprecedented to make so many substantive, market and cost changes with such minimal regulatory process and public and stakeholder input,” Silverstein said. “The pace and scope of the PUC’s decisions today may pass legal standards for Texas administrative law practice, but it violates sensible practices for sound public policy and public-interest decision-making.”

The open meeting was punctuated by almost 50 minutes of public comments, organized by the Sierra Club, Public Citizen and Texas Campaign for the Environment. The groups asked the PUC to prioritize public input in their decision-making and consider “people-first solutions.”

To make their point, the group’s members held up a symbolic power line, decorated with 350 icicles, each representing the names of 10 people asking the commission to weatherize the Texas grid to “protect and benefit the people of Texas, rather than the profits of Texas energy companies.”

The wide range of comments called for energy efficiency and demand response measures that decrease energy consumption. One speaker tearfully recounted her granddaughter being forced to go without power for 60 hours and then another 30 without water.

“You need to start being accountable to the people of Texas,” another person said.

Emma Pabst, a representative for the Sierra Club’s Beyond Coal Campaign, called for an energy grid “that works first and foremost for our communities.”

“The fossil fuel industry left us to die during the [February] freeze,” Pabst said. “Natural gas made $11 billion, while we were left to die in our homes.”

Posted on

FERC Accepts PJM Black Start Tariff Revisions

FERC on Thursday accepted PJM tariff changes covering non-rate provisions for black start service, including commitment and termination periods, as well as outage and substitution restrictions (ER21-1635-002).

The letter order directed a further compliance filing within 30 days to make agreed-upon revisions to an initial compliance filing that set forth details concerning the formulaic capital recovery factor (CRF) that the commission found essential to the rates, terms and conditions of black start service.

PJM Market Monitor Joe Bowring in April said the CRF table was originally created in 2007 and included incorrect assumptions. Black start unit owners and other stakeholders asserted that any changes to the CRF table should only be applied prospectively, and any rates currently in place should remain changed. (See PJM to File Black Start Proposal Without Members’ Endorsement.)

In October, PJM filed reply comments agreeing with the Market Monitor, explaining that the CRF formula used prior to June 6, assumed a 100-MW combustion turbine plant with a $1,000,000 capital investment. The RTO agreed that the formula no longer uses those assumptions and asked to remove the references to the assumed type of unit.

Posted on

FERC Questions Ratepayer Funding of Trade Association Dues

FERC opened a Notice of Inquiry on Thursday over the recovery of trade association dues in utility rates, with commissioners questioning whether customers should pay for groups that seek policies that may be contrary to consumers’ interests.

The NOI asks what portions of utilities’ dues paid to industry, civic and political associations are suitable for rate recovery (RM22-5).

The inquiry is a response to a petition filed by the Center for Biological Diversity, a conservation nonprofit that argued that association dues should be presumed to be non-recoverable through rates. Utilities should shoulder the burden of proving that such expenses should be recoverable, the group said. The group also sued the Tennessee Valley Authority over the issue in September. (See TVA Sued Over Contributions to Trade Groups.)

Under current FERC accounting rules, regulated utilities are allowed to recoup association dues, subtracting disclosed spending on IRS-defined lobbying activities.

FERC Chairman Richard Glick said the NOI will help FERC decide whether to modify its accounting and recording requirements.

“It appears that trade associations might not provide the utility company members with a sufficient level of detail as to which portion of a trade association’s dues should be recoverable and which should not, making it difficult for the commission to assess whether utilities are being excessively compensated by ratepayers or not,” Glick said at FERC’s open meeting.

Commissioner Allison Clements said the inquiry “in no way impinges on regulated utilities’ ability to advocate for any issue of interest.

“Regulated entities have every right to engage in outreach to influence public opinion on political issues; however, they do not have the right to pass through the cost of their outreach to the customer,” she said.

“At the minimum, it is a good housekeeping exercise to ensure that customers are not inappropriately left footing the bill for their electricity provider’s political aims, simply because they were taken on a by trade association instead of a regulated entity itself.”

Commissioner Mark Christie agreed that the NOI “is not a constitutional threat.”

“I don’t see it as threatening any corporations or trade associations’ speech rights,” he said. “The question here is not about the First Amendment; it’s about who pays for the expenses associated with speech.”

Christie pointed out that while state-regulated monopolies “may invest voluntarily,” their captive customers cannot buy voluntarily.

Christie said that FERC uses formula rates, a “very different system than in states where a utility comes in and has … the burden of proving that any expenditure is prudent.”

He added that he hadn’t prejudged any answer to whether FERC’s formula rate format is transparent enough. “It may be that the rules are fine. And maybe no changes are needed. But I don’t see a problem at all with putting this out for comment.”

Christie added that FERC should probably also consider whether its precedents on charitable and civic contributions should be codified. “I do not think that charitable and civic contributions by a state-granted monopoly should be recoverable from customers, period. That should not be allowed at all,” he said.

FERC Commissioner James Danly said he was dissenting on the NOI and would issue a later statement. He did not explain his opposition during the open meeting.

Posted on

California PUC Levies $550M on Edison for Wildfires

The California Public Utilities Commission on Thursday took steps to address two of the state’s major grid problems, resource adequacy and wildfires, by approving Southern California Edison’s request for a $1.2 billion storage project and slapping the utility with a half-billion dollars in penalties for blazes sparked by its equipment.

The decisions, reached in quick succession, came during the CPUC’s final meeting of 2021 and the last meeting for retiring President Marybel Batjer and Commissioner Martha Guzman Aceves, who is leaving for a top post at EPA.

The storage project, meant to improve summer reliability, would connect 535.7 MW of batteries at three SCE substations at an estimated cost of $1.226 billon. SCE said it will operate the storage resources as local distribution assets, not connected to CAISO, for five years. It will then transition the projects to “resources that participate in the wholesale market … [and] proceed through the interconnection process like any other customer.”

More than a dozen entities — including the CPUC’s Public Advocates Office, the Solar Energy Industries Association and the California Energy Storage Alliance — protested, challenging the cost of the project, its intended use and SCE’s interconnection plans.

The CPUC said it was not swayed by the objections and believed the project qualified under its prior procurement orders and Gov. Gavin Newsom’s emergency proclamation in July requiring the connection of additional resources to meet projected shortfalls by next summer. The five commissioners voted unanimously to approve it.

“We are facing a large gap in the amount of resources we have to ensure the reliability of our current grid in the face of the more extreme, climate-driven weather events that we saw earlier this summer and [that] we witnessed last summer,” Batjer said, referring to the derating in July of transmission lines linking the Pacific Northwest to California  caused by a massive wildfire and the rolling blackouts of August 2020 in a severe Western heat wave.

“In this case, Edison has been able to leverage its unique position as an IOU and distribution operator to move forward with a shovel-ready project that can respond to our emergency procurement needs,” she said.

The project is expected to come online by Aug. 1, 2022, in time to meet summer reliability needs.

Wildfire Penalties

The CPUC next voted 4-1 to approve a settlement with SCE over the major fires of 2017/18 ignited by its equipment. The Thomas, Woolsey, Liberty, Meyers and Rye fires collectively killed at least five people, destroyed more than 2,700 structures and burned more than 385,000 acres.

Of the five blazes, the Thomas and Woolsey fires were by far the largest and most destructive.

The Thomas fire, which began in December 2017, was the biggest wildfire in state history at the time at 282,000 acres. It was surpassed by much larger fires, including two of approximately 1 million acres, in recent years.

The fire in Santa Barbara and Ventura counties killed two people and destroyed more than 1,000 homes. Subsequent flooding and debris flows in the burn-scar area later killed 21 residents and destroyed more than 100 homes. Without admitting liability, SCE settled with insurers for nearly $1.2 billion last year.

The Woolsey fire started in November 2018, killed three people, destroyed more than 1,600 homes and led to the evacuation of almost 300,000 residents in Los Angeles and Ventura counties.

The CPUC used its new, controversial procedure called an administrative consent order (ACO) to settle with SCE. The expedited process reduces the time it takes the commission to hold utilities accountable for safety violations in an era of regular, catastrophic wildfires. Other enforcement proceedings, such as the commission’s order instituting investigation, can take years to complete.

It was the second time the CPUC has used an ACO to settle with a utility blamed for starting wildfires. Earlier this month it approved a $125 million settlement with Pacific Gas and Electric over the 2019 Kincade Fire in Northern California’s wine country.

Commissioners voted 3-2 to approve the agreement between PG&E and the CPUC’s Safety and Enforcement Division that levied $40 million in fines and denied the utility $85 million in cost recovery for removing abandoned transmission lines. (See CPUC Assesses PG&E $125M for Kincade Fire.)

They voted 4-1 to approve Thursday’s settlement with SCE. Commissioner Genevieve Shiroma, who voted “no” previously, said she was satisfied the process had led to a better result with SCE than with PG&E. Commissioner Darcie Houck, who also voted against the PG&E settlement said she believed the ACO process lacked transparency and the opportunity for public participation, especially involving fires of such magnitude.

“I agree that this can be a flexible and useful tool that allows us to resolve things in a streamlined and efficient way where we are dealing with only penalties and not the extreme catastrophic events at issue here,” Houck said.