A federal bankruptcy judge in Ohio on Tuesday approved of legal fees of more than $65 million and expenses totaling $2.7 million in the FirstEnergy Solutions bankruptcy case. The decision officially closes the case.
FES, a wholly owned generation subsidiary of FirstEnergy, emerged from bankruptcy as Energy Harbor in February 2020 after 23 months of litigation. It was represented by the international law firm Akin Gump Strauss Hauer & Feld, headquartered in D.C.
Akin Gump’s fees included about $2.8 million for lobbying work four members of the firm’s Public Law and Policy Group did to persuade Ohio lawmakers to approve H.B. 6 in June 2019. The legislation created a $1.1 billion public bailout of two FES nuclear reactors in northern Ohio. The firm’s lobbyists also worked closely with FES and FirstEnergy to defeat a referendum petition drive following the bill’s passage.
The court delayed approval of Akin Gump’s final fees and expenses invoice after learning of the existence of the lobbyists on the ground in Ohio and of the decision by FES to contribute $500,000 to Generation Now, a dark money group at the heart of the lobbying effort.
The court also took notice of the indictment of former Ohio House Speaker Larry Householder (R) and four associates on federal racketeering charges in July 2020, and the dismissal of FirstEnergy’s former chief executive and four others in October 2020 over the company’s contribution of $61 million in dark money to bankroll Householder’s multiyear campaign engineering passage of H.B. 6.
Judge Alan Koschik had delayed his decision for more than a year in the hope that federal prosecutors would let the court know, either in a docket filing or an appearance in court, whether his decision to authorize the final payments, officially closing the bankruptcy proceeding, would conflict with their investigation. He said Tuesday that the Justice Department, nor state authorities, never responded.
Two of the four Householder associates charged with racketeering have pleaded guilty but have not been sentenced. One killed himself in March, while a fourth along with Householder have pleaded not guilty and are awaiting trial. FirstEnergy has paid a $230 million fine in a deferred prosecution agreement.
Koschik last year ordered the four Akin Gump lobbyists to file affidavits explaining their work, but the firm repeatedly asked for delays until a hearing last month to avoid having to file the affidavits in the public docket and arrange for a court appearance of the four because of the ongoing federal investigation.
“The question before the court is what to do about the request for final approval of Akin Gump’s fees generally, and in particular, its fees for the Government Affairs [division] … [for] the approximate amount of $2.8 million, in light of the federal criminal investigation and indictments concerning alleged corruption and racketeering involving Ohio politicians and political operatives in connection with the passage of Ohio House Bill 6,” Koschik said Tuesday before announcing his ruling.
“This court observes that despite holding at least four substantive hearing on the application, and two more where the court granted motions to adjourn, very few substantive objections have been filed or raised in court. The court has done all it can to provide breathing space for persons to oppose or question some portion of the Akin Gump fees in light of the criminal investigations.”
FERC and NERC’s final report on February’s winter storms in Texas and the South Central U.S., issued on Tuesday, is a “sobering analysis that highlights the significant work that needs to be done” to prepare the electric grid for future cold weather events, according to FERC Chairman Richard Glick.
Incremental unplanned generating unit outages, derates, and failures to start for the total event area, by cause, fuel type, and MW of nameplate capacity | FERC
The report, released nine months to the day after the commission announced it in the middle of the 12-day crisis, detailed how the severe cold impacted bulk electric system reliability, leading to widespread generation outages, derates or failures to start and forcing more than 23,000 MW of manual firm load shed. (See “FERC, NERC Announce Joint Inquiry,” Slow Storm Restoration Sparks Anger in Texas, South.) Residents of several cities were ordered to boil drinking and cooking water because of lack of power for water treatment plants, and multiple deaths occurred from hypothermia, carbon monoxide poisoning and heating fires that grew out of control.
ERCOT, in whose territory the crisis was most severe, has not yet provided a response to the report. In an email to RTO Insider, SPP said it is “currently evaluating” the joint report while also plugging its Improved Resource Availability Task Force, which is working to “address recommendations found in” the commission’s preliminary report. (See FERC, NERC Share Findings on February Winter Storm.)
The preliminary report, issued at the commission’s open meeting in September, highlighted the role of natural gas supply disruptions in the outages and listed recommendations for preventing another disaster. Tuesday’s report provided the same overall conclusions but with more detailed data and recommendations.
Gas Accounted for Most Outages
The report showed that all types of generation experienced failures in the cold weather event, but the greatest share of outages by far occurred among natural gas facilities. Both in terms of the number of units that experienced unplanned outages, derates and failures to start, and in their total nameplate capacity, gas units accounted for more than 50%. Next in both categories was wind, accounting for 27% of generating unit outages and 22% of total capacity. Coal came third, with 6% of generating units and 18% of capacity.
Location and fuel type of unplanned generation outages and derates during the event (outaged capacity in MW) | FERC
Freezing issues caused 44% of the generating unit problems, which the report blamed on the facilities being unprepared for cold temperatures, wind and freezing precipitation. These conditions caused certain components and systems to freeze; for example, transmitters, sensing lines and instrumentation, valves and inlet air systems, and wind turbine blades. The report found many of the generator outages — 67% in ERCOT, 47% in SPP and 55% in MISO South — could have been avoided if these components had been properly prepared for the freezing weather.
Another major cause of generator outages was fuel issues, at 31%, of which natural gas alone accounted for 87%, with other fuels such as coal or fuel oil making up the rest. The issues with natural gas included drops in production and low pipeline pressure because of cold-related equipment failures, and the “terms and conditions of natural gas commodity and transportation contracts” that caused gas needed for electric generation to be prioritized for heating instead.
An additional 21% of generator outages were caused by mechanical and electrical issues. These were also from the cold, but they were not classed under “freezing issues” because the temperature did not reach freezing. The report’s authors once again laid the blame squarely at the feet of registered entities that failed to prepare their systems for the coming cold.
“Despite multiple prior recommendations by FERC and NERC, as well as annual reminders via regional entity workshops, that generating units take actions to prepare for the winter (and providing detailed suggestions for winterization), 49 generating units in SPP … 26 in ERCOT … and three units in MISO South still did not have any winterization plans,” the report said.
Report Urges Serious Cold Weather Prep
Recommendations provided in the report include significant changes to NERC’s reliability standards, requiring generator owners and/or operators to:
identify and protect cold weather-critical components;
build new or retrofit existing generating units to operate to specific ambient temperatures and weather based on extreme temperature and weather data, and account for effects of precipitation and wind;
perform annual training on winterization plans;
develop corrective action plans if freeze-related outages have been experienced in the past;
provide balancing authorities with the percentage of the total generating unit capacity that can be relied on during local forecasted cold weather; and
account for the effects of precipitation and wind when providing temperature data to balancing authorities.
NERC recently passed a set of cold weather standards, but that project began before February’s winter storm and was not intended to address any specific problems from that event. (See FERC Approves Cold Weather Standards.) The organization is attempting to initiate another cold weather standards project, but the Standards Committee last month decided to wait until the final report was issued before taking action. (See NERC Standards Committee Delays Action on Cold Weather SAR.)
Interdependency of electric and natural gas infrastructure in Texas and the South Central U.S. | DOE
The report also recommended that generator owners be compensated for the costs of retrofitting their existing units, or designing new units, to withstand specified ambient temperatures, and that FERC, NERC and the REs host a joint technical conference to “discuss how to improve the winter readiness of generating units before [NERC’s] reliability standard revisions become effective” in 2023.
In addition, in light of the interdependencies between the gas and electric sectors and the vulnerabilities in this area exposed by the storm, the team urged Congress, state legislatures and regulatory agencies to require natural gas facilities to implement and maintain cold weather preparedness plans. It also recommended that the facilities themselves “undertake voluntary measures to prepare for cold weather” and that generator owners and operators “identify the reliability risks related to their natural gas fuel contracts.”
A grand jury on Monday declined to return indictments over the Tennessee Valley Authority’s cleanup of the 2008 Kingston Fossil Plant coal ash spill, saying allegations the utility exposed workers to harm should instead be investigated by federal authorities.
The Roane County (Tenn.) grand jury heard presentations from the District Attorney General’s (DAG) Office, the Tennessee Bureau of Investigation and a former investigative reporter regarding allegations that dozens of cleanup workers were poisoned by exposure to coal ash after a dike at a TVA ash impoundment collapsed, sending a billion gallons of waste into the Clinch and Emory rivers.
The U.S. Coast Guard conducted the initial response to the spill, which covered 300 acres of farms and homes, along with local responders under the oversight of the Environmental Protection Agency. In 2009, EPA turned the site over to TVA, which hired Jacobs Engineering (NYSE:J) to oversee the cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA).
The aftermath of the Kingston spill. | TVA
TVA was found liable for the spill by a federal district court and had to compensate affected landowners. Cleanup costs have totaled about $1 billion.
Jamie Satterfield, a former reporter for the Knoxville News Sentinel, asked the grand jury to indict four mid-level supervisors for TVA, Jacobs, and subcontractor Shaw Industries under a state law that allows citizens to present information to grand juries.
The grand jury released a statement saying only two of the 12 jurors supported a state indictment and that “the evidence [was] better suited for federal authorities to investigate and prosecute.”
“We found much of the evidence about TVA & Jacobs’ handling of the cleanup, relative to worker safety, very concerning,” they said.
Covered in Ash
Jacobs employees said they were covered in ash during the work and were not provided adequate safety equipment.
More than 900 workers were involved in the cleanup, 258 of whom sued Jacobs Engineering. More than 50 workers have since died. In 2018, a federal civil jury found Jacobs liable for failing to inform workers and protect them from the dangers of coal ash.
The jury found exposure to coal ash could cause illnesses, including heart disease, lung and skin cancer, leukemia and emphysema. But the damages phase of the suit was delayed following a January 2019 order that the parties engage in mediation, which failed to resolve the matter. Jacobs is now seeking a ruling from the Tennessee Supreme Court on its claim for “derivative governmental immunity,” according to TVA’s latest 10-K filing.
Cleanup work in progress | WBIR
The TBI and DAG’s office began investigating the cleanup at the behest of a different Roane County grand jury in 2020. Among the allegations were alterations of air monitor results and other environmental tests and a failure to inform, protect and provide safety measures for cleanup workers.
In a statement, District Attorney General Russell Johnson said investigators couldn’t prove the ash exposure caused deaths without autopsies. He also cited the four-year statute of limitations on reckless homicide.
Johnson said that the cleanup was largely completed by 2014. “Therefore, anything that happened from December 2008 through December 2014 was now almost seven years old, making any state criminal charge problematic at best and, from a legal standpoint, impossible due to statutes of limitation.”
Johnson said the statement by the grand jury suggested “they were reluctant to hold four site supervisors criminally responsible for something that the grand jurors evidently perceived to possibly be ‘sins’ of the employers.”
“This is really a matter that the U.S. Attorney and the federal Office of Inspector General are better equipped to handle given that the initial cleanup from December 22, 2008 to May 2009 was conducted under the federal EPA, then from May 2009 to December 2014 the cleanup was conducted under a Presidential Order under CERCLA and EPA with TVA responsible for Jacobs Engineering as their selected contractor — all under federal jurisdiction.”
‘Best Available Science’
TVA said in a statement Tuesday that its cleanup plan “was created using the best available science on how to perform the work safely” in accordance with CERCLA.
“The state investigation has correctly concluded without any finding of wrongdoing,” Jacobs said Tuesday. “Jacobs stands by its work assisting TVA with the difficult job of cleaning up the Kingston coal ash spill. Jacobs did not cause the spill or cause any workers to be injured, and the allegations were baseless.”
Shaw did not respond to a request for comment.
Uranium, Radium
The Knoxville News Sentinel reported in stories by Satterfield that the coal ash had three times more uranium than documented in public reports. Satterfield also reported that TVA has known since at least 1981 that its coal ash contained radium 226 at levels that could cause cancer but did not inform the public.
The newspaper also reported that Tennessee regulators issued a public report on sampling of the coal ash that deleted a reading for radium and reduced readings for uranium by 98%.
A home is swallowed by the flood of coal ash. | TVA
Satterfield was fired in August, ending a 27-year career at the paper, after she spoke at a public meeting in Anderson County, when she gave officials an emotional warning that TVA had used coal ash waste as infill in its construction of a playing field.
Coal fly ash, a byproduct of coal burning, is used in Portland cement and sheetrock.
In 2015, EPA finalized regulations on coal ash — also known as coal combustion residuals (CCR) — noting it contains mercury, cadmium and arsenic, which are associated with cancer and other ailments. The agency’s rule addresses the risks from leaks into groundwater, exposure to coal ash dust and the failure of surface impoundments such as Kingston.
Satterfield, who said she shared evidence backing her allegations with the Office of Inspector General in September, called the grand jury’s action “not a win but not a loss.”
“This was as intentional an act as could be,” she told RTO Insider. “These workers … didn’t ask, ‘What am I running into?’ They said, ‘Where do you need us? There might be bodies under this stuff. Where do you need us?”
The federal judge overseeing the probation of Pacific Gas and Electric for convictions related to the San Bruno gas pipeline explosion in 2010 said the utility likely violated its probation by starting the Kincade Fire in 2019 and the Zogg Fire in 2020, which killed four people.
Judge William Alsup signed a petition on Nov. 10 submitted by a federal probation officer, who asked the judge for a summons for an “offender under supervision.” The officer cited charges by prosecutors in Sonoma and Shasta counties related to the Kincade and Zogg fires as evidence supporting the petition.
PG&E has not responded in court papers but said in a brief statement, “We’re aware of the court’s action and are currently reviewing.”
One of the conditions of PG&E’s probation is that it does not commit additional state or federal crimes.
Sonoma County prosecutors filed 33 criminal charges against PG&E on April 6 in connection with the Kincade Fire, a 78,000-acre blaze that injured six firefighters, destroyed 374 structures and led to mass evacuations. The California Department of Forestry and Fire Protection (Cal Fire) determined that a PG&E transmission line sparked the fire.
The complaint accused PG&E of committing five felonies and 28 misdemeanors, including “recklessly causing a fire with great bodily injury” and a felony charge of emitting harmful airborne contaminants, injuring children. (See Prosecutors Charge PG&E for 2019 Kincade Fire.)
PG&E acknowledged its line started the fire but has contested the criminal charges.
In September, the Shasta County District Attorney’s office charged PG&E with four counts of involuntary manslaughter in the Zogg Fire. The blaze killed an 8-year-old girl and her 46-year-old mother, as well as a 79-year-old woman and a 52-year-old man. It burned more than 56,388 acres and destroyed 204 structures.
Cal Fire concluded in March that the Zogg fire began on Sept. 27, 2020, when a leaning gray pine tree fell onto a PG&E power line near in rural Shasta County. (See PG&E Equipment Started Zogg Fire, Investigation Finds.)
PG&E CEO Patti Poppe said on Sept. 24 that the utility had accepted Cal Fire’s findings but denied criminal liability in the Zogg fire. “We did not commit a crime,” she said. The company is fighting the charges in court. (See PG&E Denies New Manslaughter Charges.)
Alsup, however, agreed with the federal probation officer that the charges for the Kincade and Zogg fires meant “there is probable cause to believe there has been a violation of the conditions of supervision” and said he would incorporate a charge of violating probation into future PG&E proceedings.
In such cases, federal law allows the court to extend a defendant’s probation, to add new terms, to revoke probation and resentence the defendant, or to do nothing. In prior instances when PG&E violated probation, Alsup has added new conditions related to vegetation management and equipment inspections, among other requirements, but has relented on more severe punishments.
PG&E’s five-year probation ends in January, and Alsup has vowed to do what he can to transform the utility’s safety culture before he loses authority.
Disasters caused by the utility’s equipment have killed at least 108 people since 2010, including 84 residents of Paradise, Calif., in the 2018 Camp Fire. The utility pleaded guilty to 84 counts of involuntary manslaughter in that case.
Opponents of the Southeast Energy Exchange Market (SEEM) filed rehearing requests with FERC on Friday in the hopes of persuading it to revisit its indecision over expanded bilateral trading in 11 Southeastern states, instituted last month automatically because commissioners were split (ER21-1111, et al.).
In two separate filings, the market’s opponents — an ad hoc group of environmental and clean energy organizations calling themselves the Public Interest Organizations (PIOs), along with a separate group billed as the Clean Energy Coalition — called the SEEM construct “unjust, unreasonable and unduly discriminatory.” The PIOs also called, once again, for a “broader technical conference on wholesale market development in the Southeast.”
FERC Chairman Richard Glick and Commissioner Allison Clements, both Democrats, were against the proposed SEEM agreement in October, while Republican Commissioners James Danly and Mark Christie approved of it. According to Section 205 of the Federal Power Act, the commissioners’ failure to take action by Oct. 11, 60 days after SEEM’s supporters responded to its latest deficiency letter, meant that the agreement took effect Oct. 12 “by operation of law.” (See SEEM to Move Ahead, Minus FERC Approval.)
FERC has since approved revisions to four of the participating utilities’ tariffs implementing the special transmission service used to deliver the market’s energy transactions. (See related story, FERC Accepts Key Tariff Revisions to SEEM.) That decision was made by majority vote, with Glick joining Danly and Christie in approval and Clements opposed. The PIOs — whose members include the Sierra Club, the Southern Alliance for Clean Energy, the Natural Resources Defense Council and others — indicated they will request rehearing on this decision as well.
SEEM Participants’ Power Seen as Unfair
Both the PIOs and the Clean Energy Coalition — which comprises Advanced Energy Economy, the Advanced Energy Buyers Group, Renewable Energy Buyers Alliance and Solar Energy Industries Association — prominently cited the arguments of Glick and Clements from their October statements explaining their opinions. (See FERC’s Christie Accuses Glick, Clements of Prejudice for RTOs.)
Glick indicated in October that he was prepared to approve SEEM despite his belief that an RTO would have served Southeastern consumers better; however, the proposed market’s use of the Mobile-Sierra doctrine, which presumes that any freely negotiated wholesale energy contract is just and reasonable, proved to be the sticking point. The chairman warned that FERC’s monitoring capabilities and enforcement authority would be “hamstrung” by the doctrine’s use.
The PIOs picked up this thread, arguing that the use of Mobile-Sierra “violates well established commission and federal court precedent” because the SEEM agreement deprives any potential signatories of the opportunity to negotiate — a fundamental assumption of the doctrine. Even market participants’ offer in their previous deficiency response to restrict the doctrine’s application to a more limited set of provisions would unacceptably limit market participants’ negotiating power, they said. (See SEEM Members Offer Rule Changes.)
In its filing, the Clean Energy Coalition concurred, saying that the application of Mobile-Sierra “in a manner contrary to commission precedent” made the approval of SEEM “arbitrary and capricious.” Quoting Glick, the coalition said SEEM members “have not shown ‘extraordinary’ or ‘compelling’ circumstances that … would merit application of Mobile-Sierra here as a matter of agency discretion.”
The groups also sided with Clements, who in her statement on the decision agreed with Glick’s concerns on Mobile-Sierra but went further, saying that the SEEM proposal “fails to abide by the bedrock principles of open access and non-discrimination that were crystallized in … Order No. 888.”
Expanding on Clements’ argument, the Clean Energy Coalition warned that accessing the non-firm energy exchange transmission service that is central to SEEM would require participants to get approval of an agent overseen by the market’s operating committee, which is controlled by current members, and to execute enabling agreements with at least three other participants. The coalition noted that FERC rejected a similar “two-class membership system” in the Mid-Continent Area Power Pool case and argued that approving it in this situation is unfair and inconsistent.
Danly, Christie Accused of Ignoring Precedent
The groups also criticized Danly and Christie, arguing that they dismissed commission precedent and the concerns of objectors.
“Neither Commissioner Danly nor Commissioner Christie acknowledged what SEEM is: a loose power pool,” the Clean Energy Coalition said. “The commission has been clear that a loose power pool is ‘any multilateral arrangement, other than a tight power pool or a holding company arrangement, that explicitly or implicitly contains discounted and/or special transmission arrangements.’ … The SEEM proposal is a multilateral arrangement and explicitly contains discounted and/or special transmission arrangements. … It was arbitrary and capricious for the commission to accept [it].”
The PIOs added that while Danly acknowledged the “cavalcade of existing commission precedent [that] supports protesters’ position” on Mobile-Sierra, he maintained that “both commission and judicial precedent are ‘in error.’” Although Danly justified his vote by stating that Mobile-Sierra is intended to “ensure that … contracts can be relied upon,” the PIOs called this a “fundamental misapprehension” of the doctrine.
“The Supreme Court, and numerous others, have explained that the justification for applying the heightened public interest standard is premised on the fact that the contract was negotiated at arm’s length between ‘sophisticated businesses enjoying presumptively equal bargaining power.’ … Those circumstances are why a contract with these exact characteristics — and only these exact characteristics — can be uniquely relied upon,” the PIOs said, concluding that it is Danly’s position that introduces “contractual uncertainty.”
30 Days to Act
FERC has 30 days to act on the merits of the rehearing request; if it fails to do so because it is still divided 2-2, the petitioners may appeal to the D.C. Circuit Court of Appeals. However, it may be possible to break the deadlock earlier if the Senate approves President Biden’s nomination of D.C. Public Service Commission Chair Willie Phillips to join FERC, which would give Democrats a 3-2 majority. The Senate Energy and Natural Resources Committee voted earlier this month to advance Phillips’ nomination to the full Senate. (See Senate Energy Committee Advances Phillips.)
President Joe Biden on Monday signed the $1.2 trillion, bipartisan Infrastructure Investment and Jobs Act (H.R. 3684) in a White House lawn ceremony.
“The bill will enable Americans to get off the sidelines and into the game of manufacturing — solar panels, wind turbines and batteries to store energy and power electric vehicles,” Biden said.
A Department of Energy factsheet listed the energy funding in the bill, which includes more than $7 billion in the supply chain for batteries; $1.5 billion to boost “clean” hydrogen manufacturing and a $750 million grant program supporting advanced energy technology manufacturing projects in coal communities.
It also expands the authority of the DOE’s Loan Program Office, allowing it to invest in projects that increase the domestic supply of critical minerals and expand programs that invest in manufacturing zero-carbon technologies for medium- and heavy-duty vehicles, trains, aircraft and marine transportation.
“Today’s infrastructure bill will also begin the necessary efforts to prevent the worst of climate change, putting thousands of Americans to work by investing in resilience in our buildings and crucially beginning our task to make America’s transportation system clean,” said Senate Majority Leader Chuck Schumer, (D-NY).
The bill drew praise from across the energy sector.
“Enactment today of the bipartisan Infrastructure Investment and Jobs Act puts in motion critical upgrades to our nation’s antiquated electric transmission infrastructure, an essential component of achieving a modern and decarbonized grid,” said Gregory Wetstone, CEO of the American Council on Renewable Energy.
Wetstone also urged Congress to pass the Democrats’ $1.75 trillion Build Back Better budget package to spur further investments in renewable energy, energy storage and advanced grid technologies. The infrastructure bill was approved Nov. 5, with some progressives supporting it in return for a procedural vote setting up the budget vote for action after an analysis by the Congressional Budget Office. (See Energy Groups Quick to Praise Infrastructure Bill Passage.)
“This historic law will help expedite some of the foundational infrastructure upgrades to our ports and electrical grid needed to spur the creation of a U.S. offshore wind industry,” David Hardy, CEO of Ørsted Offshore North America, said in a statement after attending the ceremony. Ørsted has six U.S. wind farms in development, totaling approximately 4 GW.
The infrastructure bill also invests in programs that will help the country continue to electrify its transportation systems, including charging infrastructure, electric school buses and transit fleets, Leah Rubin Shen, federal policy director at the national business association Advanced Energy Economy, said in a statement.
“This infrastructure bill [helps] ensure greater reliability and resilience, and drive essential R&D for hydrogen, nuclear, and other clean energy sources,” Electric Power Research Institute CEO Arshad Mansoor said in a statement.
Electrification of transportation, buildings and industry will play a crucial role in achieving the U.S. government’s climate goals, Mansoor said.
FERC on Monday continued to build the record for its Advance Notice of Proposed Rulemaking on potential changes to its rules on transmission planning processes, holding a technical conference that focused on long-term forecasts for transmission needs, based in part on the future generation mix (RM21-17).
FERC Chair Richard Glick said there is “a lot to be done” to build out the transmission grid to handle the clean energy transition. He noted that the vast majority of the comments on the ANOPR say that significant process changes and improvements are necessary to make transmission planning more proactive, based on future needs, and less reactive to projects in interconnection queues.
Zach Smith, NYISO | FERC
“We have this general sense of what kind of electric generation we’re going to have in the future,” Glick said. “It’s not entirely clear that our transmission planning process always adequately addresses that.”
Commissioner Allison Clements added that she does not see a way forward on cost-effectively facilitating a reliable grid without more intelligent planning that expressly considers a longer time horizon. She also said there is a critical need to factor in flexibility for regional differences.
The conference featured three panels, each with a mix of representatives from grid operators, utilities, consumer advocates, as well as experts from the Department of Energy and its National Laboratories.
Factors to Consider in Long-term Planning
On the opening panel, NYISO Vice President for System and Resource Planning Zachary Smith said that whether it is climate change or policies that affect the generation mix, RTOs and ISOs are all considering similar factors in their transmission planning processes.
Robert Ethier, ISO-NE | FERC
But NYISO’s processes do not necessarily take into consideration some future conditions, he said.
“I think it’s going to be critically important, especially for reliability, when we shift toward more scenario planning and shift away from this idea that we can somehow come up with a perfect base case … none of us are that good,” Smith said. “We need to look at scenarios to think about what the future could look like in various ways and be planning for that.”
Robert Ethier, vice president of system planning at ISO-NE, said that over the past two decades, about $12 billion has been invested in reliability-based transmission projects across the six New England states. But he said he recognizes the need “to move beyond this reliability-based transmission expansion.”
“That sort of approach is not going to meet the needs of the future and the dramatic goals that the states have set for themselves,” Ethier said.
The ISO-NE interconnection queue has more than 30,000 MW in projects, 20,000 MW of which are proposed wind resources that are primarily offshore.
“We have done some studies that look at the future grid and specifically about the interconnection of wind,” Ethier said. “They show that we can connect the first 6,000 to 8,000 MW of wind in a relatively low-cost way.”
David Patton, Potomac Economics | FERC
Interconnecting the rest of it will not be “zero cost,” he said. He noted that ISO-NE has already begun its 2050 Transmission Study, as requested by the states, which will take a high-level look at scenarios to reliably incorporate clean energy and distributed energy resources beyond the RTO’s current 10-year planning horizon.
David Patton, president of market monitor Potomac Economics, said the payoff of investments to upgrade the transmission system 30 years out will be far less than decisions based on congestion trends in closer time frames.
“I think it’s very difficult to do this well when you look in the very long term,” Patton said. “I would say taking a very measured approach in terms of how far out we look — how much uncertainty we’re willing to accept when spending [$5 billion to $20 billion] on new transmission assets — is very important.”
Grid Strategies President Rob Gramlich added that “everything in the power sector relies on well done transmission planning” from the start.
Future Scenarios
The second panel dealt with the development and study of long-term scenarios. FERC asked panelists on the assumptions in such futures, including how far into the future to look and both the advantages and disadvantages of different horizons.
Bryce Nielsen, Salt River Project | FERC
Bryce Nielsen, director of transmission planning, strategy and development for the Salt River Project, said a goal for planning would be to look out as far as the siting and permitting process takes, estimating that seven to eight years for a typical transmission project would be acceptable. If a planning horizon is double or tripled from a seven-year window, the extended windows should be more “informational” rather than “actionable,” he said.
Nielsen noted that if a 20-year planning horizon was used when new generation was being built in the Southwest in 2001, when “we couldn’t build combined cycles fast enough,” the transmission would have been built adjacent to natural gas pipelines. That “probably would have been the wrong answer.”
Natalie McIntire, American Clean Power Association | FERC
“Twenty years seems like a long time, and there’s a lot of uncertainty in a 20-year horizon,” he said.
Natalie McIntire, technical and policy consultant for the American Clean Power Association and Clean Grid Alliance, said she would look at a 20- to 25-year horizon because the entire process from planning, permitting and construction takes “an extended period” of time. Longer, regional lines provide more complications, so the need for additional advanced planning is even more important, she said.
There could be some instances where anticipated transmissions solutions end up not being needed, but those can be adjusted as scenario planning is re-evaluated if included in the process. “The challenge we have in looking only at the short term is that we may have a little bit more accuracy, but we don’t end up with the solutions when we need them,” she said.
Karen Onaran, Electricity Consumers Resource Council | FERC
Karen Onaran, vice president of the Electricity Consumers Resource Council, said consumers are “relatively risk averse” to transmission planning, but they recognize it must account for more transmission. A 20- to 25-year informational window that considers the length of permitting for projects but won’t produce a “piecemeal, Band-Aid approach” would be appropriate.
Having an actionable horizon into the future could bring less certainty and more risk, which can cause consumers to “get a little bit more nervous,” she said.
“We would need to continuously relook at those projections and adjust as needed,” Onaran said. “We do understand we need to do that long-term planning or else we’re not going to get to the big transmission we need for the future.”
Jay Caspary, Grid Strategies | FERC
Jay Caspary, vice president of Grid Strategies, also said there should be at least a 20-year outlook. Because of the length of the process, planners can’t just look out with actionable plans for five to 10 years. There’s also an opportunity to take advantage of the aging transmission assets and incorporate new technology into the planning process, he said.
“We can do things with advanced transmission technologies to greatly enhance the power density and capability in existing corridors to support these futures,” Caspary said.
Zonal Accord
Speakers on the final panel agreed that FERC should instruct planners to identify geographic zones with a strong potential for renewable resources, similar to Texas’ Competitive Renewable Energy Zone (CREZ) process.
Debra Lew, Energy Systems Integration Group | FERC
“We should forecast demand [and] generation. We should define geographic energy zones and proactively plan and build transmissions to these zones to save money,” Energy Systems Integration Group (ESIG) Associate Director Debra Lew said.
Transmission building is more effective on larger scales because it takes so much longer than generation.
“People worry that transmission costs are going to increase, but cost alone shouldn’t be the focus. Rather, look at systemwide electricity costs or customers’ bills as the metric,” she said. “The reason is you can pay a little more for transmission, and that can unlock much bigger savings through generation capacity and operations.”
Sunflower Electric Power Corp’s Al Tamimi | FERC
Al Tamimi, Sunflower Electric Power’s vice president of transmission planning, said his utility’s location in western Kansas means he’s in such a zone.
“We have about 350% wind penetration, so I have seen it live,” Tamimi said. He said it’s important to name geographic zones early enough and build optimal transmission so generation developers won’t miss out on opportunities and customers save money.
Tamimi said engagement with the National Labs is also need. There should be a “ranking methodology” of renewable energy zones to identify which ones have more demand and are thus more cost-effective and attractive to developers.
Bonneville Power Administration’s Jeffrey Cook said the labs should be included in the development of zones, alongside utilities, RTOs and transmission operators and developers.
David Hurlbut, NREL | FERC
David Hurlbut, senior analyst with the National Renewable Energy Laboratory, said Texas’ CREZ development is largely misunderstood.
“Many think it is drawing zones on the map and waiting for the magic to happen. To be clear, the idea was never ‘if you build it, they will come,’” Hurlbut said.
It’s crucial that any renewable zone identification first consider commercial interest and areas of high demand, he said. “Otherwise, they will have about as much weight as a letter to Santa Claus.”
Hurlbut also said naming zones should be “the easy part” because NREL and other National Labs already have resources for transmission providers and load-serving entities.
“The key is linking those zones to a source of demand that has some commercial weight to it,” he said.
Zones should also be large enough so that “no single developer or group of developers can clog up” the queue and restrict competition, Hurlbut added. “The development that we see in Texas today … is evidence that the competitive market can drive renewable energy expansion if the transmission system is built to support it.”
It’s important that zone identification “knock down those silos between regions in transmission planning.” He also said customer savings are amplified with larger transmission projects.
CAISO Vice President of Infrastructure and Operations Planning Neil Millar said renewable zone identification for transmission planning is already “a pretty common practice” within his ISO.
He said it’s CAISO’s 233-GW generation queue that is “overheated” to “distraction.” The ISO now finds itself in a “middle ground” where it needs “actionable transmission plans” based on which potential projects are the most promising.
Other panelists agreed that RTOs’ interconnection queues shouldn’t be the sole basis for the renewable zones. But Hurlbut said queues can provide “very valuable” information on pent-up demand.
“If you want to get the most productive resource investment, the transmission might need to go to areas it did not exist before,” he said.
New Jersey legislators backed bills Monday that would create a $45 million electric school bus pilot program, recommend that Gov. Phil Murphy place a moratorium on fossil fuel projects and enshrine the state’s 2019 Energy Master Plan into law, as the state’s fall legislative sessions surged ahead.
The five-member Senate Environment and Energy Committee voted unanimously in favor of spending $15 million a year for three years to enable 18 school districts to replace diesel vehicles with electric buses in a program designed to evaluate the performance and efficiency of the buses.
The hearing marked the start of the second week of legislative activity in the state after lawmakers took a five-month break for the summer and the election season. Legislation introduced in the current session has to be enacted by the time the next session begins in mid-January or be refiled and start the process again.
The bill (S5077) provides an alternative to less expansive legislation that would set up a $10 million pilot program in three school districts. That bill has advanced slowly, but state officials and environmentalists are increasingly focusing on how to jumpstart the use of electric buses to cut emissions and protect school children from diesel fumes. (See NJ Floats New Electric Bus Plan.)
Testifying in support of the school bus bill, Pam Frank, CEO of ChargEVC-NJ, an advocacy group that champions electric vehicle policies, recalled that about three years ago she attended a state government task force meeting at which the 70 or more people present agreed that the state should embrace electric school buses. Yet there are still none on state roads, and only 77 on order, she said.
“We’re way behind,” said Frank, who expressed concern that a three-year pilot would impede the advance of non-pilot ventures.
William Beren, transportation chairman for the Sierra Club’s New Jersey Chapter, said legislators should make sure the funds are available in June so that the buses can be ready for the next school year.
“We simply cannot afford to waste any more time,” he said.
Heavy Vehicle Focus
New Jersey’s focus on school buses is part of the state’s effort to cut carbon emissions by introducing more EVs into the transportation sector, which accounts for 42% of the state’s emissions. A key element of the state’s strategy is to promote the use of electric medium- and heavy-duty trucks and buses through incentives, grants and state rules that require truck manufacturers to meet EV sales goals. The state also has sought to reduce range anxiety by boosting the number of available electric chargers. (See Murphy Toughens NJ Emission-reduction Goals.)
The Environment and Energy Committee also advanced a bill that called on Murphy to “impose an immediate moratorium on fossil fuel infrastructure projects” to help cut emissions. The bill, which does no more than make a recommendation to Murphy, said the moratorium should stay in place until the state cuts its greenhouse gas emissions by 80% below 2006 levels.
Sen. Bob Smith (D), the committee chairman, told the hearing that he has drafted a bill for discussion in the next legislative session that, rather than making a recommendation, would require that when fossil fuel electricity plants are replaced the successor is a renewable facility.
Master Plan
In the Assembly, the Environment and Solid Waste Committee approved a bill (S3667) by a 3-2 vote that would put into law the state’s 2019 Energy Master Plan, rather than leaving it simply as an executive order. The senate passed the bill 25-13 in June, and approval by the Assembly would put it on the governor’s desk.
At the time of the Senate vote, the bill provided a way of ensuring that Murphy’s aggressive clean energy goals would stay in place even if he lost his re-election fight on Nov. 2. Murphy won re-election with a 2.9% margin against Republican Jack Ciattarelli, a far closer result than many observers anticipated.
The original bill would codify key planks of the Master Plan, including the goal of putting 330,000 light-duty vehicles on state roads by 2025. Other parts of the bill would require the state’s mass transit agency, New Jersey Transit, to operate at least one battery-powered train by 2025 and that New Jersey generate 7.5 GW of offshore wind by 2035. The committee amended some parts Monday, but no details were available.
Assemblyman John F. McKeon (D), speaking before he voted to support the bill, said the floods and devastation wreaked by Hurricane Ida in September demonstrated the need for the state to act on climate change.
“The proof is now in [front of] our eyes. I don’t know if this gets us [to a solution] quicker,” he said of the bill. “But I think that this sets a standard as to what we’re going to do and makes it more difficult in the future to move the ball backwards.”
Business Opposition
Yet one of the state’s biggest business advocacy groups was not convinced. Raymond Cantor, government affairs vice president for the New Jersey Business & Industry Association (NJBIA), said the state Master Plan is “problematic” and should not be codified into law, in part because the models used to compile it were unreliable. Cantor also said some goals in the plan are unattainable, such as getting 35% of the state’s energy from renewables by 2025.
He said NJBIA tried — so far unsuccessfully — to get the bill amended so it requires that the goals be affordable for taxpayers and that they would make the grid reliable. “If those two factors are not in this bill, then it says a lot about what the impact of this bill really is,” he said.
Debra Coyle McFadden, executive director of the New Jersey Work Environment Council Board, an alliance of labor, community and environmental organizations, told the committee that the bill is “moving too fast” and needs to be refined.
“One piece that’s really missing here is as we transition away from fossil fuel, what is going to happen to those workers and those communities?” she asked. “There has been no addressing what’s going to happen. No worker should be left behind. We need to have retraining; there are several things that we need to do for workers. And that’s just not in here.”
After a 14-month hiatus, CAISO on Friday restarted the stakeholder process to expand its real-time Western Energy Imbalance Market to include day-ahead trading.
CAISO CEO Elliot Mainzer spoke at an Oct. 13 EDAM forum. | CAISO
“There is real momentum towards further regional coordination in the West,” CAISO CEO Elliot Mainzer said in a statement. “By building on the foundation of the EIM and harnessing the knowledge and experience of stakeholders from across the region, our goal is to position EDAM [extended day-ahead market] as the next major step in West-wide market evolution.”
The EDAM initiative was put on hold following CAISO’s energy emergencies in August and September 2020, which raised concerns about resource adequacy in the West and California’s dependence on imports. (See Heat Waves, Blackouts Slow Western EIM Expansion.)
An EDAM straw proposal issued in July 2020 generated stakeholder pushback over transmission rights and concerns that the market would not be as voluntary as the WEIM. (See EDAM Design Could Undermine Tx Rights, Critics Say.)
A select working group of stakeholders met over the summer to produce a set of “common design principles” as the basis for ongoing discussions. The closed-door process met with some criticism, but Mainzer said he was optimistic that the EDAM process would eventually yield consensus from the WEIM’s diverse constituents.
“This is a group of people that have a track record of coming together around solutions,” Mainzer said as he opened Friday’s call-in session.
CAISO held a forum Oct. 13 to generate interest in EDAM as it faces a more crowded field of competitors trying to organize Western markets, especially SPP, which has been pitching a Western RTO and will operate the Northwest Power Pool’s Western Resource Adequacy Program (WRAP). (See CAISO Promotes EDAM Effort in Forum.)
CAISO formally recommenced the EDAM stakeholder process with a call Friday to review the initiative’s design principles, scope and timeline, and to begin forming stakeholder working groups to address key components including resource sufficiency, transmission commitments and greenhouse gas accounting.
Milos Bosanac is leading CAISO’s EDAM stakeholder process. | CAISO
“We envision that the first task of these working groups will be to identify the detailed market design issues that will need to be addressed … and a discussion of the common EDAM design principles that are relevant to [each] group,” Milos Bosanac, the ISO’s lead infrastructure and regulatory policy developer, said.
“Those [common design] principles potentially may be affirmed, edited or built upon throughout the discussion, and we encourage those working groups to dedicate time to this effort,” said Bosanac, who is heading the EDAM stakeholder process. “We recognize … [that] providing additional transparency and discussion on the common design principles” is important to stakeholders, he said.
The working groups’ recommendations will be incorporated into a comprehensive straw proposal due at the end of March, he said.
Resource Sufficiency
CAISO COO Mark Rothleder led a morning panel discussion.
The EDAM is meant to build on the WEIM’s success by optimizing dispatch of resources through the day-ahead market and maximizing efficient use of transmission to serve load across a larger footprint, Rothleder said. It is not meant to be an RTO substitute or to replace resource adequacy (RA) planning by its member entities or WRAP, he added.
But EDAM, like the real-time WEIM, will require members to show they have sufficient resources to meet their own demand and prevent “leaning” on the market for RA, Rothleder said.
“We do need a common resource sufficiency examination going into the day-ahead to make sure that everybody’s coming in sufficiently resourced to cover load and uncertainty, but we’re not using this as a mechanism to create a common resource adequacy regime across the entire footprint,” he said.
The resource sufficiency evaluation and potential consequences of failing to meet it “is definitely going to be a hot topic in the working groups,” he said.
Stakeholders have raised concerns about whether the EDAM would impose greater RA requirements than currently exist, panelists said.
“We can’t use EDAM to … be a super-restriction that, in effect, undermines activities that have already been satisfying agreed-to formalized [RA] processes,” Jeffrey Nelson, director of FERC Rates and Market Integration at Southern California Edison said. “If we have systems out there that are already showing reliability, we need to respect them. The EDAM shouldn’t eviscerate those or add on something that was not designed.”
Josh Walter, strategic adviser with WEIM member Seattle City Light, said “this is ultimately going to be a very difficult issue to work through … but I do think that this also highlights the need for constructive dialogue in the workgroups.”
The WEIM’s main draw has been its economic benefits, which have totaled $1.7 billion since the market started in 2014. CAISO is basing its hopes for EDAM on achieving similar or greater benefits for members. The WEIM now has 15 participants with seven more scheduled to join in 2022 and 2023. Together, those entities would represent 84% of load in the Western Interconnection, CAISO said.
Other thorny topics in EDAM are expected to include transmission commitment, congestion rent allocation and accounting for greenhouse gas emissions.
The workgroups were scheduled to start Dec. 6, though some stakeholders said Friday it would be better to start after the holidays to avoid added stress on participants. Rothleder said CAISO would take it under consideration.
EDAM policy design is expected to last through 2022, with implementation to continue in 2023 and participation scheduled to start in 2024.
SPP accrued $21.65 million in market-to-market (M2M) settlements with MISO during August and September, pushing the total payments due SPP to an all-time high of $183.39 million.
Permanent and temporary flowgates were binding for more than 1,500 hours in August, resulting in $4.72 million in settlements favoring SPP. Settlements jumped to $16.92 million in September when congestion led to more than 1,700 binding hours on 56 permanent and temporary flowgates, SPP staff told the Seams Advisory Group (SAG) on Friday.
M2M settlements hit a record $51.49 million, in MISO’s favor, in February, thanks to Winter Storm Uri. Congestion played a heavy role in limiting the amount of energy MISO could share with its seams neighbor.
The process’ settlements have accrued to SPP during the seven months since February and for 22 of the last 24 months, eclipsing the high-water mark of more than $168 million in January.
M2M settlements have eclipsed the previous high set in January. | SPP
The RTOs resettled 15 operating days between August 2020 and June 2021 that resulted in a $477,982 adjustment in MISO’s favor. Staff said that the appropriate transmission reliability margin (TRM) was not applied to a flowgate in North Dakota during the annual TRM update. The TRM affects the firm flow entitlements (FFEs) used for settlement purposes, but the difference would not and did not influence dispatch.
The M2M process began in March 2015. The grid operators exchange settlements for redispatch based on the non-monitoring RTO’s market flow in relation to FFEs.
Staff also told the SAG that language changes in the joint operating agreements with MISO and Missouri-based Associated Electric Cooperative Inc. (AECI) are undergoing legal review. SPP plans to file both JOA revisions with FERC at the same time.
The changes are related to interconnection queue priorities in the grid operators’ affected system studies.
