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November 7, 2024

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ERCOT’s Jones Looks Ahead, not Behind

HOUSTON — Introduced as “clearly a man of courage and conviction to take this job at this time,” interim ERCOT CEO Brad Jones stepped up to the speaker’s podium and briefly rehashed February’s events that led to his leadership position with the Texas grid operator.

“The media said we weren’t prepared [for the February winter storm]. That’s not true,” he told an in-person and virtual audience Thursday during the University of Texas School of Law’s Gas and Power Institute.

Referencing a similar winter event that led to suggested weatherization recommendations, Jones added, “The generators were prepared, but to 2011 standards.”

But rather than revisit history, Jones made it clear his focus is on what lies ahead.

“The future of ERCOT depends on more than our response to the winter storm. It depends on our response to an extraordinarily fast-changing market,” he said.

Brad-Jones-2021-10-15-(RTO-Insider-LLC)-Content.jpgBrad Jones explains ERCOT’s future concerns to UT Law’s Gas and Power Institute. | © RTO Insider LLC

Speaking without notes, Jones said his 60-point roadmap to grid reliability, given home-page prominence on ERCOT’s website, addresses the grid operator’s concerns “today and tomorrow.” Twenty-nine of the roadmap’s items have been completed, with all but one of the remaining 31 listed as being “on track.” (Placing senior-level representatives from each member organization on the Technical Advisory Committee has been delayed until the new Board of Directors is fully in place.)

“The seeds of what we want to fix are in the [February] problems,” he said. “Weatherization has to improve. We can’t rely on 2011 standards. The weather is not waiting for the PUC to get [its] rules in place. ‘Winter is coming,’ as we’ve all heard.”

Jones said he has been contacted by generation owners who told him they are investing “tens of millions of dollars” in weatherizing their facilities. “They’re investing because they see where the weather is going and they need to get ahead of it,” he said.

ERCOT staff this November will begin inspecting nearly 300 generating units’ weatherization, concentrating on those responsible for the 80% of lost megawatts from the February storm. The grid operator is staffing up for the effort, which includes filing a report with the Public Utility Commission.

“I hope gas suppliers are moving forward, just like the generators,” Jones said. The FERC-NERC joint inquiry on the storm and other reports have all placed most of the blame for generation outages on the lack of natural gas supplies. Texas politicians have found the gas industry’s response to be lacking. (See Texas Senators Call for New RRC Weatherization Rules.)

Noting ERCOT’s interconnection queue is heavily weighted in favor of renewable energy projects, Jones said their “extraordinarily valuable” low prices need to be balanced with more reliable generation. He brought up the RACE acronym he often uses with the public: reliable, affordable, clean electricity.

“For too long, it’s been CARE. We’ve got to put the R back in front,” Jones said. “One of the things the state has failed to do over the last 20 years is to put reliability first.”

Jones said ERCOT would like to see “stout” firm fuel contracts, dual-fuel capabilities and underground storage to ensure thermal plants have a reliable fuel supply. Citing rising gas prices, he also said he wants to separate generation from relying on natural gas, should the power equation’s gas side again fail during extreme weather.

“We want to ensure there’s language in the contracts to firm them up as much as possible and to give them some teeth to ensure reliable delivery,” Jones said.

Asked whether a capacity market would have resolved ERCOT’s problems during the winter storm, Jones said he is a fan of capacity markets and that they work “very well.”

“The problem is, it takes so much time to tune the rules and change things to drive certain outcomes,” he said. He used PJM’s capacity market as an example of a market that “drives the type of reliability we need” with its firm-fuel requirements.

“It’s also true that we can build those same tools outside of a capacity market,” Jones said. “It’s not necessarily true that a capacity market would have saved us. We had the capacity; it just didn’t operate.”

A capacity market would have helped in the billions of market charges assessed to participants in the two days after the storm subsided, Jones said. During that time, the PUC kept market prices at $9,000/kWh to encourage generation to stay online. He said capacity markets typically have $1,000 offer caps because capacity resources are paid on an annual basis.

“The financial storm would have been little more than 1/10 of what actually occurred,” Jones said.

The scars from February still remain. Jones said during a recent call with North Texas mayors, he was asked about the likelihood of another winter storm in 2022. Calling February’s a one-in-130 year event, he said one could assume a 1% chance of a similar destructive storm. However, weather forecasters have also said there’s a higher likelihood of another winter event the year after another one, Jones said.

“So not a 2021, but perhaps a 2011 storm,” he said, placing the chances in the 10-15% range. “We have to be prepared for something like that … and we are getting ready. I feel very confident we will be ready.”

Uncertainty for ERCOT Board, Market

Two energy lawyers both expressed uncertainty about changes to ERCOT’s governance structure and market design.

Meghan Elaine Griffiths, an attorney with Jackson Walker, said a questioner’s guess “is as good as mine” when queried about how the political appointees to the ERCOT board will affect the market and stakeholder process. Under new legislation passed earlier this year, the board’s structure of unaffiliated directors and market segment representatives has been replaced by a selection committee’s appointees, with the committee itself selected by the state’s political leadership. (See 2 New ERCOT Directors Named, Replacing Current Board.)

“One of the benefits of having market stakeholders on the board is they have a deep knowledge of the business and a deep knowledge of the protocols as they’re developed,” Griffiths said. “I think there’s a very steep learning curve for our new ERCOT board members. We’ll see how that plays out over time.”

Already, one media report has highlighted board Chair Paul Foster’s tie to Republicans. According to The Dallas Morning News, Foster has since June donated $1.775 million to Gov. Greg Abbott’s campaign committee.

Michael Nasi, a partner with Jackson Walker, shared a quote on market design from PUC Chair Peter Lake before the State Legislature: “‘I want to reassure you that we are not tweaking on the edges or making marginal changes. We are taking a blank-slate approach for a full overhaul and redesign of this market to drive reliability. Full stop.’”

“This market has been cited as the envy of many and potentially modeled in many places in this country and around the world,” Nasi said, referring to pre-February perspectives. “And then to have Chairman Lake say we’re going to fundamentally redesign this … I welcome the change, but how does it get done? It will be hard work, but it’s doable. ERCOT can still be a model for others.”

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OSW Grid Strategy Must Extend Beyond Current Proposals, Utility Says

BOSTON —
Offshore wind developers need to think on a larger scale than current projects in the pipeline when it comes to transmission planning, according to Nabil Hitti, director of U.S. business development for National Grid (NYSE: NGG).

“The existing plans and sizes are manageable, and the question is, ‘Can we go bigger?’” Hitti said at a panel for the American Clean Power Association’s Offshore WINDPOWER 2021 conference on Wednesday.

The U.S. Bureau of Ocean Energy Management this week set a goal to hold up to seven new offshore lease sales by 2025 to meet the Biden administration’s goal for 30 GW of OSW by 2030.

Coastal states are already facing the challenge of how to integrate existing OSW proposals into the transmission network, along with how to increase transmission capacity in general to “unlock the potential of renewables across the nation,” Hitti said.

BOEM is reviewing nine projects following its approval of the Vineyard Wind project off the coast of Massachusetts earlier this year.

Ocean Wind, the largest project under review with the agency, is expected to have a total capacity of 1,100 MW.

“PJM has been very helpful to us in trying to come up with the transmission that is going to provide the maximum rate of return for ratepayers,” Upendra Chivukula, New Jersey Board of Public Utilities commissioner, said during the panel discussion.

But New Jersey is at the forefront of issues with OSW interconnection, including establishing charges and costs, Chivukula said.

“Currently the planning system is fragmented, I think, due to transmission owners having incentives to construct and recover costs from transmission projects with little or no oversight,” he said. Those costs are then passed to ratepayers.

When developers approach state agencies for OSW renewable energy certificates, the “largest component of risk is associated with transmission costs,” said Tim Burdis, senior manager of policy solutions for PJM.

“You can quantify a lot of the other costs, but you don’t necessarily have specificity around what are going to be the upgrade costs that an ISO or RTO might be sticking with the bill,” Burdis said.

Transmission upgrade and replacement decisions in anticipation of a skyrocketing OSW industry need to be made now to save money and time on integrating the renewable resource, instead of “having to make a minimal upgrade and then come back later and make a bigger upgrade for OSW that wants to come on to the system,” Burdis said. “The state of public policy says it is going to be on in 10 years.”

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NAGF Speakers Highlight Resource Mix, Cyber Challenges

Speakers at the North American Generator Forum’s (NAGF) Virtual Compliance Conference this week repeatedly urged grid planners to take seriously the challenges of the changing resource mix and other threats to the reliability and security of the grid.

Ken-DeFontes-(NAGF)-Content.jpgNERC Board Chair Kenneth DeFontes | NAGFIn his keynote remarks on the first day of the meeting, NERC Board of Trustees Chair Kenneth DeFontes praised NAGF for its “longstanding partnership with NERC” and the “tremendous input and support” it has recently provided as the ERO sought to manage the myriad emerging threats to bulk power system reliability.

Citing the 2021 ERO Reliability Risk Priorities Report published in August, DeFontes emphasized that grid transformation remains one of the most pressing risks facing the ERO Enterprise. (See Grid Transformation, Cybersecurity Lead 2021 ERO Risk Report.) He warned utilities that they may not be taking the challenges of the transition to renewable resources seriously enough.

Two recent reports lent weight to DeFontes’ concerns. The first was NERC and FERC’s joint inquiry into February’s winter storm that led to unprecedented outages in the Midwest and left hundreds dead in Texas (AD21-28). The final report has not yet been released, but preliminary findings and recommendations were presented at the commission’s open meeting last month. (See FERC, NERC Share Findings on February Winter Storm.)

The second report was NERC and ERCOT’s review of an incident earlier this year in which multiple solar and wind facilities near Odessa, Texas, suffered voltage reductions. (See NERC-ERCOT Report Reviews Texas Solar Issues.) In both incidents, investigators found that entities had not implemented recommendations in NERC’s nonbinding reliability guidelines despite widespread knowledge of their existence and the reasons for them.

“As we learned in the February cold-weather report, there can be dire consequences when guidelines are not followed. I am concerned that we’re seeing a similar trend when I look at the Odessa disturbance report,” DeFontes said. “We see the industry is well aware of the guidelines; they have considered them and adopted some parts of them; but they are not widely and comprehensively being followed, which has left us with potential reliability gaps.”

Noting that FERC Chairman Richard Glick and NERC CEO Jim Robb have promised that the winter storm report “will not sit on the shelf,” DeFontes urged utilities to study the Odessa disturbance report and make a real effort to apply its lessons. He promised that if nonbinding guidelines prove to be insufficient, NERC will “move forward to improve [mandatory] standards.”

Gugel, Lauby Emphasize Changing Grid Conditions

Howard Gugel, NERC’s vice president of engineering and standards, continued the discussion of the changing grid in his presentation. Comparing predictions NERC made in 2008 of fuel mix changes over the next 10 years versus the actual conditions in 2017, Gugel observed that natural gas, wind, solar and nuclear all increased more than expected — gas and wind grew more than four- and threefold, respectively — while coal’s presence in the BPS actually declined, rather than rising as NERC had anticipated.

The growing presence of weather-dependent resources such as wind and solar — along with behind-the-meter resources like rooftop solar, home battery storage systems and grid-connected electric vehicles — poses a problem for system planners, who will “have to become very creative in understanding [the] differences” between these generators and traditional resources.

“Our system was not designed or planned with that in mind, but that reality is coming,” Gugel said. “The question is, how do you adapt for that? How do you become resilient?”

Gugel identified several problems that planners are going to have to solve, including a lack of transparency into current load and status of behind-the-meter resources; inability to quickly ramp up generation among wind and solar resources in the event of an emergency; voltage regulation; and underfrequency load shedding. All of these will require a level of communication that prior generations never anticipated.

Mark-Lauby-(NAGF)-Content.jpgMark Lauby, NERC | NAGF

NERC Chief Engineer Mark Lauby concurred with Gugel’s warning about the assumptions underlying traditional BPS planning, saying that “that world is slowly disappearing” and that establishing essential reliability services is becoming much more difficult in a world of distributed, smaller, asynchronous generation resources that require much more automation to manage remotely and programming to “ride through minor system disturbances so as not to make them worse.”

The increasing reliance on electronic grid management systems also means that the BPS must be hardened against cybersecurity threats, Lauby observed. Noting recent cybersecurity events like the SolarWinds and Microsoft Exchange Server attacks, he observed that hackers “are not dumb; they are persistent,” having learned how to target a wide range of industries.

“So far, fortunately, we haven’t really seen a breach from [information technology to operational technology], though we have had vulnerabilities we’ve identified and are working to address them,” Lauby said. “But as we start digitizing more … we’re going to have to keep in mind that we design a system that’s robust against those kinds of attacks … so that we’re not as much of a target.”

SERC Shares Self-report Tips

The meeting also featured presentations from other stakeholders, including Janice Carney, senior compliance engineer at SERC Reliability. Carney discussed the importance of self-reporting potential violations of NERC reliability standards, observing that bringing potential compliance issues to a regional entity’s attention voluntarily is “a much better position for an entity to be in compared with a noncompliance found during an audit.”

Information needed in self-reports includes the date of discovery; start and end dates of the noncompliance, with a basis for each; a description of how the infringement was identified; the number of people, devices or systems involved in the noncompliance; the cause of the violation; and prior instances of noncompliance with the same standard.

Carney also emphasized the importance of writing style in self-reports, urging utilities to be as clear as possible by using active voice rather than passive and defining all acronyms on first usage.

Cold Weather Plans Coming Soon

Finally, Venona Greaff, manager of compliance at Occidental Energy Ventures, updated attendees on the new reliability standard EOP-011-2 (Emergency preparedness and operations), approved by FERC in August, and its requirement that generator owners implement plans to protect their units from freezing. (See FERC Approves Cold Weather Standards.)

“As generators, when we think about these standards and how they fast-tracked them after the February [winter storms], it seems like it’s a steam engine barreling down on us at a great pace,” said Greaff, who served on the standard drafting team for EOP-011-2 and the other cold-weather standards.

“But in reality, this has been coming for a long time,” she continued, noting previous cold-weather events that occurred in 2011, 2013 and 2018 — the last of which was the impetus for the cold-weather standards project. (See FERC Orders Cold Weather Reliability Standard.)

While the new standard will not take effect until April 2023, Greaff’s presentation was aimed at providing utilities a basis for starting to develop their plans, including basic attributes such as a purpose statement explaining what the procedure is meant to do and the applicable entity or facility; the personnel who will be responsible for specific activities, as well as for oversight of the entire plan; and critical components and instrumentation that need priority protection.

“One thing I want to remind you [members] of the NAGF is, collaboration and assistance is always an option,” Greaff said. “We currently have a cold-weather preparedness group [that] has 82 members. … I think that we have a lot that we can share with each other, and we can learn from each other in this working group. So I’d encourage you to think about joining the working group. It doesn’t mean that you have to take a lead role; it just puts you in that small group and allows you to be a part of the conversation.”

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NRDC Report Predicts a Decline in NJ’s EV Truck Costs

The average medium- or heavy-duty electric truck purchased in New Jersey in 2040 will cost $25,000 less over its lifetime than a comparable diesel vehicle, according to a new report released by the Natural Resources Defense Council (NRDC).

Fuel and maintenance cost savings totaling about $36,000 over the lifetime of the average electric medium- to heavy-duty truck will make up for the purchase price premium over a diesel vehicle, according to the report, New Jersey Clean Trucks Program.

Seeking to rebut the perception that EV trucks are prohibitively more expensive than diesel and gas vehicles, the NRDC argues that EV trucks will yield health benefits quickly and significant savings after a few years. The report models the environmental and health benefits and cost impact of three different scenarios of state EV truck policies. Based on the report, the NRDC argues that “accelerating the deployment of zero emission trucks and buses would dramatically lower pollution.”

Modeled on California’s Advanced Clean Trucks regulation, New Jersey’s ACT — if approved by the Department of Environmental Protection (DEP) — would require manufacturers to meet an escalating series of electric truck sales targets, starting in 2025. Manufacturers would be required to increase their sales of zero- or near-zero emissions vehicles to 55% of class 2b and 3 truck sales by 2035, 75% of Class 4 to 8 trucks and 40% of truck tractor sales by 2035. (See: NJ Electric Truck Rules Face Many Questions).

Environmental groups embrace the ACT rules. Hayley Berliner, clean energy associate for Environment New Jersey, said the NRDC’s report “certainly shows the importance of the Advanced Clean Truck rule, and the remarkable public health and environmental benefits,” she said.

The NRDC, along with Environment New Jersey and other environmental groups, wants the DEP to approve the rules by the end of the year so that trucks made in 2025 are covered. Any delay to the enactment of the rules beyond the end of 2021 would mean the first trucks covered by the rules will be those made in 2026, says the NRDC and other environmental groups.

Cost vs. Environmental Impact

Opponents say that electric vehicles are too expensive and the number of models available is too small to be attractive without sizable government incentives. They say that substantial cuts in emissions can be achieved with cleaner, more modern diesel engines, which cost much less than EV trucks.

The NRDC report agrees that the expense of EV trucks will outweigh the savings over the next few years. The lifetime expenses for a truck bought in 2025 — including the cost of chargers, charger maintenance and the initial vehicle purchase — will be about $45,000 more for the average medium- to heavy-duty EV truck than a regular truck, the report concludes. That compares to $40,000 in savings the EV will provide on fuel and maintenance at that time, the report says.

But with EV costs expected to fall as volumes increase, the maintenance and fuel savings will outweigh the higher purchase price of an EV.

The report also endorses the Heavy-Duty Omnibus Rules adopted by California in 2020, which mandate the use of newer trucks that emit less nitrogen oxide (NOx), as part of the strategy to cut greenhouse emissions. Both the ACT and Heavy-Duty Omnibus Rule are “pretty integral key pieces to reducing greenhouse gas emissions from the transportation sector,” Kathy Harris, clean vehicles and fuels advocate for NRDC, said in an interview. She said New Jersey has yet to advance the Heavy-Duty Omnibus Rule, and electric vehicles are the priority for NRDC in cutting greenhouse gases.

“It’s pretty clear that that while, yes, we need to get old diesel (vehicles) off the road, moving to new diesel (trucks) is not the solution,” she said. Cleaner diesel trucks are “still going to perpetuate those issues that are associated with diesel currently, which is not good air quality and potential health impacts from those vehicles.”

The DEP appears close to deciding on ACT. “We are working on an adoption document” for ACT, Peg Hanna, the DEP’s assistant director for air monitoring and mobile source programs, told a conference Wednesday on electric school buses. She said that the department is also “closely monitoring” another California rule, the Advanced Clean Fleets rule, which would “impose requirements on fleet owners to actually purchase these electric trucks and buses that the manufacturers are being required to sell.”

At the May hearing, representatives of the New Jersey Business & Industry Association (NJBIA) and the Truck and Engine Manufacturers Association, a national trade group, said they opposed the rules because the cost of compliance would be too high for trucking companies.

“We agree that the future of trucking and heavy-duty vehicles needs to be much cleaner, if not carbon free,” said Ray Cantor, a vice president at NJBIA, in an interview with NetZero Insider Thursday. “However, at this point in time, the technology for heavy-duty vehicles is just not there [and the trucks] are just not affordable.”

Cantor said the organization would like to see more consideration of trucks powered by alternative fuels, such as liquified natural gas.

Tightening Government Measures for EV Trucks

Truckers have been slow to embrace EV trucks in New Jersey. Trucking advocates say that aside from the expense, the vehicle range (about 150 miles) is too small to make them a viable alternative, especially for the large Class 8 tractor trucks that haul containers — and the state has too few charging stations to alleviate that fear.

The Diesel Technology Forum, which advocates for the use of diesel engines, argues that adopting the ACT would limit the choices of truckers in how they respond to climate change. Allen Schaeffer, the organization’s executive director argued, in a recent op-ed that 55% of trucks on New Jersey roads have engines that are newer than 2011 and armed with technology that makes them “near zero emissions.” The state should transition the 52% of older trucks to near-zero technology, he argued, saying that with 55% of New Jersey’s electricity powered by natural gas, the power for most electric vehicles will come from gas-fueled electricity anyway.

“Let’s consider what we can do now rather than just hope what the future might be,” Schaeffer wrote. “Even if the most optimistic of all policy, funding, technology and infrastructure scenarios fall into place, the time frame for zero-emission heavy-duty vehicles to make up a majority percentage of the commercial trucks on New Jersey roads and streets is going to be measured in decades, not years.”

What Policy to Adopt

The NRDC’s report tries to evaluate what can be achieved and the impact on New Jersey’s emissions, resident health and economic situation under three scenarios with varying levels of aggressiveness in promoting electric medium- and heavy-duty trucks.

One way it does so is to look at the “societal benefits” of each. The calculation of societal benefits includes: the monetized value of climate and public health benefits resulting from fewer hospital visits and deaths from pollution; the net cost savings to fleets from operating zero-emission trucks; and savings to all residential and commercial electricity customers due to lower electric rates made possible by the additional electricity sales for electric vehicle charging.

The three scenarios are:

  • Adopting ACT only: by adopting the ACT, 34% of the state’s in-use medium- and heavy-duty-trucks would become EVs by 2040 and 59% would be EVs by 2050, the report says. That would yield annual net societal benefits totaling about $1.1 billion (in constant 2020 dollars) through 2050, and a 43% reduction in nitrogen oxide (NOx) emissions. The annual cost savings to New Jersey trucking fleets in 2050 would be $446 million, and annual savings in the bills of electric utility customers in the state could reach an estimated $70 million, the report says.
  • Adopting ACT and the Heavy-Duty Omnibus Rule: The omnibus rule requires a 75% reduction in NOx emissions from diesel trucks sold between model year 2025 and 2026, and a 90% reduction for trucks sold beginning in the 2027 model year. Under that scenario all gas and diesel trucks would become low-NOx vehicles by 2044. Annual societal benefits would be about $1.1 billion.
  • Adopting ACT, the omnibus rule and other state measures to accelerate an increase in EV sales and ensure that virtually all new trucks are EVs by 2040. That would yield societal benefits of about $2.1 billion. The annual fleet savings would be $843 million and electric customer annual bill savings increase to an estimated $81 million, the report says.

In the first scenario, 34% of the state’s trucking fleet would be EVs by 2040, and the same would happen under the second scenario, although in addition many vehicles would become low NOx vehicles. In the third scenario, 52% of the fleet would be EV by 2040 and 96% would be EVs by 2050, the report says.

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CEC Puts $24M Toward Electric Buses, Trucks

The California Energy Commission allocated a major round of funding Wednesday to support the development of electric transit buses, school buses and medium- and heavy-duty electric trucks as the state tries to decarbonize its transportation sector.

The nearly $24 million in funding included a $6 million grant to the Los Angeles Department of Transportation to continue electrifying its transit bus system. The grant will enable LADOT to add a solar-plus-storage microgrid to provide clean energy and keep its electric bus fleet running, even during power outages. It will also fund four 1.5-MW chargers, 104 charger dispensers and overhead transit bus charging with solar canopies.

“The project will deploy electric bus charging infrastructure to support up to 142 battery electric buses,” Energy Commission Specialist Esther Odufuwa said. “LADOT’s strategy is to convert its entire fleet of buses to battery-electric zero-emission vehicles.”

The microgrid project, in a city as immense as Los Angeles, can serve as a model for smaller cities, Odufuwa said. There are approximately 11,500 transit buses operating statewide, she added.

“This microgrid technology has the potential to be completely replicable for all transit agencies in California, regardless of their of their size,” Odufuwa said.

If the state were to convert all transit buses to electric vehicles and operate them as bidirectional resources, they could discharge up to 700 MW of flexible capacity to support the state’s grid reliability efforts — enough electricity to power 700,000 homes, she said.

Commissioner Patricia Monahan, the lead commissioner for CEC transportation programs, said “this project has it all in terms of … electrifying buses and doing it in a way that’s attentive to the grid. We are really looking for those twofer opportunities where we get a benefit to the grid and a benefit to the transit district.”

The item passed unanimously.

The CEC also approved a $13 million grant to the nonprofit Electric Power Research Institute to fund a research hub focused on electric heavy-duty drayage trucks. Cal Start, a research and development organization for clean transportation, will act as a major subcontractor on the project.

“The research hub will advance high-power charging technologies and engage a broad network of stakeholders and communities to deploy public-access charging infrastructure for [medium- and heavy-duty] vehicles in heavily trafficked freight corridors,” the project description said.

The CEC gave eIQ Mobility, which provides fleet electrification services, $2.2 million to fund a demonstration project for bidirectional electric charging of school buses in the San Francisco Bay area.

A $1.7 million grant will fund the deployment of 300-kW wireless charging infrastructure for the SolanoExpress intercity bus service in Solano County in Northern California.

Smaller grants will fund planning for medium- and heavy-duty vehicle electric charging and hydrogen refueling stations and to develop a zero-emission transportation program for the 2028 Olympic Games in Los Angeles.

The California Energy Commission granted nearly $24 million Wednesday to foster zero-emission transit buses, school buses and medium- and heavy-duty trucks.

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DOE: Atlantic Coast Needs Integrated Transmission Planning for OSW

While Interior Secretary Deb Haaland was in Boston on Wednesday announcing the Biden administration’s plans for deploying 30 GW of offshore wind, the Department of Energy released a new report on the gaps that will need filling to build enough transmission to get electricity from those turbines to the millions of homes they might power.

The report reviews more than 20 transmission studies for Atlantic Coast OSW projects to date and finds most were done on a project-by-project basis, “which may not necessarily be optimal for expanded development.” With a current pipeline of more than 35 GW of projects extending from Maine to Virginia, comprehensive, proactive transmission planning that incorporates “robust future scenarios across the broader interconnected system” will be needed, the report says.

Such an approach is essential, the report says, because of a frequent mismatch between the potential high output of offshore wind generation and daily variations in power demand, which can result in curtailment and transmission congestion.

For example, the report notes that ISO-NE will need minimal upgrades to interconnect the 5.8 GW total of offshore wind now being developed in Connecticut, Maine, Massachusetts and Rhode Island. Additional offshore projects could result in higher costs and curtailments, the report says.

NYISO, on the other hand, is facing cable routing limitations, substation space constraints and permitting challenges as it looks to expand and upgrade transmission on Long Island and in New York City to integrate the state’s planned 9 GW of OSW.

As an alternative to states going it alone, the report says transmission planning should look at co-optimizing systems with “generation and storage technologies to holistically compare completely integrated alternatives that capture generation and transmission trade-offs to adequately meet customer demand and federal and state policy objectives.”

Reaching such objectives will mean addressing research gaps in four key areas, the report says.

  • Studies by individual states, RTOs and ISOs — encompassing a range of study years and OSW deployment scenarios — generally assume the states involved each have a specific claim on offshore wind resources. But state and national goals may not be aligned, creating “a gap in understanding the Atlantic Coast and Eastern Interconnection implications of how offshore wind will be utilized by different states,” the report says.
  • Similarly, interconnection studies by RTOs and ISOs tend to be “deployment-specific,” focusing on single projects. While long-term planning efforts have begun, the report says traditional transmission planning misses the potential for collaborative solutions, such as shared transmission or shared rights-of-way that could minimize costs and impacts.
  • Technical and economic analyses of offshore wind have been widely conducted along the Atlantic Coast, but few states have yet to look at the details of routing and interconnecting transmission cables. Further, current analyses don’t account for technologies that need further development, such as high-voltage DC circuit breakers, which will be essential for developing offshore HVDC transmission, the report says. Without such in-depth analysis, technical solutions could be proposed that are either infeasible or overly costly.
  • With some technologies still in development, standards and practices for integrated offshore transmission networks are a critical gap in current analyses, the report says. As one example, many studies make future estimates of project reliability and resilience based on a year or less of weather data, the report says. This approach can leave out high-impact events like hurricanes and other “natural patterns of variability and uncertainty that occur over longer periods and for which the system should be designed.”

The FERC Connection

Stepping up research — and accelerating offshore wind development — will require collaborative efforts, and the report suggests that FERC step into the currently vacant role of coordinating local, state and national planning efforts, convening stakeholders and establishing frameworks for evaluating OSW transmission options. Referencing FERC’s Advanced Notice of Proposed Rulemaking (RM21-17) focused on transmission planning and cost allocation, the report envisions improved coordination that would promote more streamlined and consistent transmission planning.

Exactly how realistic that vision is remains uncertain. The report’s release also coincided with the end of a 75-day comment period on the ANOPR. The commission received 165 comments from stakeholders ranging from RTOs and ISOs to utilities, developers and industry associations. (See FERC Tx Inquiry: Consensus on Need for Change, Discord Over Solutions.)

A key theme across many comments was opposition to any “one-size-fits-all” solution, instead calling for engagement with state regulators and policy makers in the transmission planning process.

While recognizing the need for reform, the National Association of Regulatory Utility Commissioners (NARUC) said “the commission should not lose sight of the need to ensure that all potential transmission planning reforms explicitly recognize the essential role states, and state laws, play in this process.”

The National Conference of State Legislatures (NCSL) called for a “coordinated effort between FERC and states in the development and implementation of any regulatory change, including devising improved mechanisms to bring state legislatures into the energy decision-making process as full participants on an ongoing basis.”

Looking at potential models for future planning, the report points to New Jersey’s state agreement with PJM, under which the RTO will incorporate the state’s goal of 7,500 MW of offshore wind into its regional planning process.

It also cites onshore wind planning in Texas, where the Public Utilities Commission and ERCOT worked together on the development of renewable energy zones and the necessary transmission buildout.

Co-existing with Fisheries and Marine Life

Attacking the challenges of offshore wind development on all fronts, the DOE on Wednesday also announced $13.5 million in funding “to provide critical environmental and wildlife data to support offshore wind development.” The money will go to four projects, “that will inform offshore wind siting [and] permitting and help protect wildlife and fisheries as offshore wind deployment increases,” the announcement said.

“In order for Americans living in coastal areas to see the benefits of offshore wind, we must ensure that it’s done with care for the surrounding ecosystem by co-existing with fisheries and marine life — and that’s exactly what this investment will do,” Energy Secretary Jennifer Granholm said in the announcement.

Duke University received more than half of the funding — $7.5 million — for a project that will assess and monitor the impact of offshore wind development on birds, bats and other marine mammals.

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Akin Gump Public Policy Team Helped Win Ohio Nuke Bailout

In affidavits filed in a federal bankruptcy court Tuesday, four employees of the national law and lobbying firm Akin Gump Strauss Hauer & Feld denied wrongdoing but revealed the firm’s deep involvement in FirstEnergy’s (NYSE:FE) efforts to win passage of nuclear bailout legislation in the Ohio legislature.

That passage led to the indictment on federal racketeering bribery charges of the former speaker of the Ohio House of Representatives and four of his associates and the company paying a $230 million fine in a deferred prosecution deal. (See DOJ Orders $230 Million Fine for FirstEnergy.)

Akin has represented FirstEnergy since its incorporation in 1997, as well as its generation subsidiary FirstEnergy Solutions in its bankruptcy case, which began March 31, 2018.

After Akin last year revealed in a routine disclosure of charges and expenses — including those for assisting the company to win approval of Ohio House Bill 6 and fighting the resulting campaign against a ballot drive to rescind it — U.S. Bankruptcy Court for the Northern District of Ohio Judge Alan Koschik held up the final payment of the firm’s $67 million in legal fees while waiting for a Justice Department investigation into the passage of H.B. 6 to conclude.

But the judge demanded specific information from four employees, including their knowledge of FirstEnergy giving millions of dollars to Generation Now, a 501(c)4, the company used as a “dark money” organization to fund a legislative and public relations campaign. Classified as social welfare organizations by the IRS, 501(c)4 groups do not have to report donors.

After a second delay in July, the judge set a deadline for this week. The sworn disclosures of three Akin partners and a senior policy adviser give detailed accounts of their involvement with the company and top Ohio-based lobbyists in 2018 and 2019 to assist former Ohio House Speaker Larry Householder (R) engineer the passage of the bailout legislation.

H.B. 6, which has since been rescinded, created a six-year, $1.1 billion public bailout of two Ohio nuclear plants, formerly owned by the company. Its passage also immediately led to the Justice Department investigation and subsequent indictments.

Householder has pleaded not guilty to federal racketeering charges stemming from that multiyear campaign and is awaiting trial.

Two of his associates, including lobbyist Juan Cespedes and political strategist Jeffrey Longstreth, also pleaded guilty but have not been sentenced as the Justice Department investigation continues. Longstreth also pleaded guilty on behalf of Generation Now.

Affidavits Describe Company Activities

The affidavits of the Akin employees offer numerous details about their efforts, which included daily consultations to win passage of the bailout, beginning a year before the legislation won approval.

“I was first introduced to Juan Cespedes and his company, the Oxley Group, in or around March 2018,” wrote attorney Jamie Tucker, an Akin partner and member of the firm’s Law and Policy section. “At the time, we were looking for in-state legislative consultants to help with outreach to policymakers regarding the nuclear power plant deactivation process in Ohio and announcement of FES’ bankruptcy, as well as to assess the likelihood of possible legislative solutions.”

The affidavit continues that Cespedes “became the principal day-to-day point of contact” and that Akin and FES “relied upon Cespedes to report on the likelihood that particular members of the legislature would be supportive.”

A year later, leading up to the votes in the House and Senate, Tucker described his role and that of other members of the Akin team as one of analysis and strategizing.

The court also wanted to know specifically whether:

  • Akin’s staffers were aware of Generation Now before FES emerged from bankruptcy in February 2020;
  • they had advised FES “with respect to interaction with Generation Now”; and
  • they had advised FES regarding a “$1,879,457 electronic transfer to Generation Now on July 5, 2019 … or regarding any other transfer to or for the benefit of Generation Now.”

Tucker responded that in summer 2018, he learned that Generation Now “was a 501(c)(4) organization addressing energy independence and economic development, and that it was aligned with Larry Householder.”

“Over the course of the next two months, FES’ governmental affairs team and I, with input from outside consultants and others at Akin Gump, advised FES in connection with its decision to donate a total of $500,000 to Generation Now in October 2018 as part of its broader, bipartisan contribution strategy,” Tucker wrote.

He added that he had no “personal knowledge” of the $1.87 million transfer “or any other transfers” other than the $500,000 that had been discussed.

In a letter accompanying the affidavits, Akin attorney Abid Qureshi, who argued the FES case on several occasions during hearings in bankruptcy court, told the court that “the firm is not aware of any evidence that its attorneys and professionals knew of any illegal activity” and that “Akin Gump is not aware of anything that would lead the firm to revise its pending fee application.”

He said Akin’s restructuring lawyers routinely attended FES board meetings during the Chapter 11 proceedings, including a May 28, 2019, meeting.

“During that meeting, the board adopted a resolution, which Akin Gump corporate attorneys had drafted, authorizing expenditures of up to $15 million to Generation Now to fund Generation Now’s voter-education efforts,” Qureshi wrote.

He added that the “policy professionals,” such as Tucker, “were not specifically aware of the $15 million … and they did not advise on the authorization. Some of them were aware that FES’ media and voter-education efforts in support of House Bill 6 had been transitioned from another firm to Generation Now and that monies were being spent on those efforts.”

Qureshi’s letter went on to describe an August 2019 FES board meeting when the board adopted another resolution drawn up by the firm authorizing additional expenditures of up to $25 million in a drive to defeat a referendum petition that had been organized by opponents of H.B. 6. Again, he stressed that Akin’s team working with FES on the ground were not aware of those voted-upon decisions.

The court has set a final hearing on the issue of the final payments to Akin for Oct. 26.

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SEEM to Move Ahead, Minus FERC Approval

A divided FERC means the proposed Southeast Energy Exchange Market (SEEM) agreement took effect on Oct. 12, the commission announced Wednesday (ER21-1111, et al.), bringing relief for the proposal’s supporters and criticism from its opponents.

The agreement became effective “by operation of law” because FERC had failed to take action by Oct. 11, 60 days after SEEM’s supporters — a consortium of electric utilities including Southern Company (NYSE:SO), Dominion Energy South Carolina, Louisville Gas & Electric, the Tennessee Valley Authority, and Duke Energy (NYSE:DUK) — filed their response to the commission’s latest deficiency letter. (See SEEM Members Push for FERC’s Decision on Market Proposal.)

With commissioners “divided two against two as to the lawfulness of the change,” the measure automatically took effect in accordance with Section 205 of the Federal Power Act. It is the second time in two months that a deadlocked FERC allowed approval of a proposal, after the passage of PJM’s minimum offer price rule in September (ER21-2582). (See FERC Deadlock Allows Revised PJM MOPR.)

SEEM supporters issued a release Wednesday promising the platform would be operational by the middle of next year. The release listed a number of “founding members of SEEM” in addition to Duke, Southern, TVA and Dominion. Some utilities that have not yet made “firm decisions” are expected to do so as a result of the FERC ruling, and membership is open to any additional entities that meet the requirements.

A decision on SEEM was expected at the commission’s most recent open meeting, where the proposal was on the agenda, but the item was removed at the start of the meeting. FERC’s statement Wednesday did not reveal which commissioners supported the proposal. Commissioners are required by the FPA to provide written statements explaining their views, but the law does not specify when they must do so. So far, none of the commissioners have done so regarding the PJM MOPR decision.

Currently the commission has two Democratic members and two Republicans; President Joe Biden nominated D.C. Public Service Commission Chair Willie Phillips to fill the seat vacated by Republican Neil Chatterjee in August. (See Biden to Nominate Phillips to FERC.)

Critics Warn of Entrenching Current Winners

SEEM’s supporters submitted the proposed agreement to FERC in February, promising that the planned expansion of bilateral trading in 11 Southeastern states would reduce trading friction while promoting the integration of renewable resources. The proposal is intended to reduce trading friction by introducing automation, eliminating transmission rate pancaking, and allowing 15-minute energy transactions.

Criticism has dogged the project from the start, with opponents skeptical of the promises of its supporters. In multiple filings to FERC, a collection of environmental groups, including the Sierra Club, the Southern Alliance for Clean Energy, the North Carolina Sustainable Energy Association, and the Southern Environmental Law Center (SELC), warned that SEEM would allow transmission-owning utilities to “favor their own generated electricity and to exclude competitors from the market.” (See SEEM Critics Repeat Call for Technical Conference.)


Average-retail-prices-for-utilities-(SEEM)-Content.jpgAverage retail prices for utilities in SEEM versus the RTO markets. | SEEM

 

In addition, a September report by the American Council on Renewable Energy (ACORE) suggested that other models surpassed the supposed benefits of SEEM. The report simulated SEEM against three alternative energy market models in the same footprint and found that all three outperformed SEEM in terms of financial savings, integration of renewable energy resources, and reduction in carbon emissions over 20 years. (See Report: SEEM’s Benefits Beaten by Other Models.)

Following FERC’s announcement, SELC attorney Maia Hutt called SEEM’s supporters “some of the largest monopoly utilities in the country” and stressed that “SEEM … cannot be the last step towards wholesale market reform in the Southeast.”

Gizelle Wray, director of regulatory affairs and counsel at the Solar Energy Industries Association (SEIA), said in a statement that the proposal was “not a real market,” and would merely help “entrenched monopoly utilities” to consolidate their power.

“We need a true market that encourages new entrants and competitive bidding, all of which could help bring Southeast utilities into the 21st century. We are in a race against the clock on climate change, and structures like SEEM will only hinder our progress,” Wray said. “This decision is a clear sign of what can go wrong when there’s a 2-2 split on FERC and proposals go into effect by law. We urge the Senate to quickly confirm [Chairman Phillips] so we can have a fully functioning commission.”

Changes Promised After Deficiency Letter

Given the way the SEEM proposal was approved, it is not clear whether supporters will follow through on the changes they promised in a filing in June. FERC sent SEEM organizers a deficiency notice in May, submitting 12 detailed questions about how the plan to automate matching buyers and sellers would operate. In response, proponents suggested several modifications to the agreement, including:

  • confidential weekly submissions of market data to FERC and the market auditor.
  • disclosure of regulators’ questions and answers, as well as market auditor reports, to participants, subject to restrictions on access to confidential information by marketing function employees.
  • a clarification that available transfer capability calculated by participating transmission providers must be provided to the SEEM administrator and must be used in the algorithm for each leg of any contract path to ensure transmission will not exceed available capacity.
  • making the “just and reasonable standard” the default for most SEEM rules rather than the lower Mobile-Sierra public interest standard. (See SEEM Members Offer Rule Changes.)

SEEM’s release on Wednesday made no mention of these changes, only thanking FERC and its staff “for their thorough review” and pledging to follow “all FERC-approved rules and requirements for existing bilateral markets today, but with additional transparency.” Advanced Energy Economy, a national association of companies promoting clean energy and electrified transportation, warned that the lack of a FERC order “allows the sponsoring utilities to move forward without any commission direction” on implementation or transparency.

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NYISO Business Issues Committee Briefs: Oct. 13, 2021

Constraint Specific Tx Shortage Pricing

The NYISO Business Issues Committee on Wednesday recommended that the Management Committee approve tariff revisions related to implementing a revised approach to the current transmission constraint pricing logic.

The proposal includes establishing a revised six-step transmission shortage pricing mechanism for facilities currently assigned a non-zero constraint reliability margin (CRM) value, said Kanchan Upadhyay, energy market design specialist.

Each step corresponds to a specified percentage of the applicable CRM value, and the final step will price all shortages in excess of the applicable CRM value, thereby facilitating the ability to eliminate reliance on constraint relaxation for such facilities.

Given the expanded scope of graduated transmission demand curves envisioned by the Constraint Specific Transmission Shortage Pricing proposal, the ISO is working to implement the proposal in tandem with its Lines in Series effort, which seeks to develop enhancements to the measures used for addressing the limitations arising out of the operation of graduated transmission demand curve mechanisms.

NYISO-Tx-Demand-Curve-(NYISO)-Content.jpgNYISO proposes to apply a non-zero CRM value (e.g., 5 MW) to internal facilities currently assigned a zero value CRM and apply the following transmission demand curve. | NYISO

The proposal will also apply a non-zero CRM value (e.g., 5 MW) to internal facilities currently assigned a zero value CRM, with a separate two-step transmission demand curve mechanism for such facilities.

The first step is valued at $100/MWh and will price transmission shortages up to the proposed CRM value. The second step is valued at $250/MWh and will price all shortages in excess of the proposed CRM value, thereby facilitating the ability to eliminate reliance on constraint relaxation for such facilities, Upadhyay said.

The proposal will maintain the current single value $4,000/MWh shadow price capping method for external interface facilities (zero value CRM), permitting the continued use of constraint relaxation for external interfaces, she said.

One stakeholder wanted assurance that the Lines in Series initiative would in no way delay implementation of the transmission shortage pricing proposal.

“The constraint specific transmission pricing should be implemented as proposed today with Lines in Series,” said Michael DeSocio, NYISO director of market design. “Both will be implemented together in 2023, and we will be working with stakeholders to illuminate our thoughts on how to solve the Lines in Series effort later this year.”

CSR-related Tariff Revisions

The BIC also approved tariff revisions related to implementation of co-located energy storage resources (CSR) injection and withdrawal scheduling limit constraints and CSR-generator specific operating parameters.

FERC in March accepted NYISO rules allowing an energy storage resource to participate in the wholesale markets as a CSR with wind or solar, and the ISO has since been working on the market software. (See FERC Approves NYISO Co-located Storage Model.)

“In solving the market software, we found there were unique circumstances where these constraints were actually competing with other constraints in the model, specifically operating parameters of the generator specific to the CSR model,” said Zachary Stines, manager of energy market design.

In that situation the ISO had to prioritize which constraint was going to be respected and which was going to be relaxed to come up with an appropriate solution, “so this is really to prevent an issue where you could have these competing constraints on the individual units and then also this withdrawal or injection limit constraint,” Stines said.

Language will be added to the applicable manuals (likely the Day-Ahead Scheduling Manual and the Transmission and Dispatch Operations Manual) describing how the scheduling limits will interact with unit specific constraints, such as ramp, upper operating limit and lower operating limit.

If approved by the Management Committee this month and the Board of Directors in November, NYISO will make a filing with FERC and request a flexible effective date for the tariff changes that is prior to year-end.

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EBC Highlights Trends in Maine, Mass. Solar Markets

Maine and Massachusetts have vastly different installed solar generation capacities, but the two states are dealing with similar market issues as they work to meet their clean energy goals.

The Environmental Business Council of New England gathered industry experts on Thursday to discuss the status of solar in the Northeast, providing a look at key solar market trends playing out in Maine and Massachusetts.

Interconnection

Distributed generation interconnection and grid infrastructure investment, together, are “the single biggest impediment for continued [solar] success in Massachusetts and Maine,” Kelly Friend, vice president of policy and regulatory affairs at solar developer Nexamp, said during the webinar.

The two states, which are Nexamp’s primary New England markets, are not alone in their struggles to find a good pathway for how DG can quickly and affordably connect to the grid. While interconnection costs can be low in nascent DG markets, Friend said, the costs usually go up over time, depending on prior grid investments.

“We’re seeing that in Massachusetts, and particularly in Maine,” she said.

Some projects can trigger the need for a grid upgrade on a congested part of the system, which can increase the project’s interconnection cost by millions. And it can take a long time to get through an interconnection queue when grid studies hold up the process.

Massachusetts currently has 3,380 MW of installed solar capacity and Maine has 280 MW, according to the Solar Energy Industries Association.

Nexamp operated in Massachusetts for about five years before it began to see interconnection issues there in about 2018, according to Friend. In Maine, she said, it happened much faster. The state’s DG program opened in about 2019, and similar issues arose after about a year.

“That’s a result of the load profiles of both states and the investments in the grid that the utilities hosting those projects and interconnecting those projects have made,” she said.

Figuring out the interconnection conundrum is critical for achieving net-zero goals and signaling developers that they can move forward with business.

“Until we see signs of clear and consistent progress on interconnection, it’s very hard for us to think about Massachusetts growing at the rate we want to see it grow and need to see it grow from a climate perspective, because the cost and time to interconnect these projects is just so significant,” Friend said.

Nexamp is trying to take the lessons it has learned in Massachusetts and export them to Maine to ensure that projects there aren’t triggering huge interconnection costs and experiencing regulatory lag time in five years.

Regulatory Responses

In Massachusetts, some projects are seeing burdensome interconnection costs, and grid studies have left other projects in the queue for up to three years, according to Eric Steltzer, director of the Renewables and Alternative Energy Division at the Massachusetts Department of Energy Resources (DOER).

The Department of Public Utilities, in response, opened a docket (20-75) last fall to investigate the problems and present options for resolving them.

Regulators issued a straw proposal within the docket that incorporates DG planning into distribution system planning. The proposal also outlines a pathway for cost allocation of transmission upgrades that goes through the distribution system owner’s capital investments and becomes a fee to all interconnecting facilities that benefit from the upgrade.

DOER supports the straw proposal, and stakeholders are awaiting an order from the DPU in that docket, Steltzer said.

Maine is also trying to resolve its solar project interconnection problems through a Maine Public Utilities Commission investigation.

“Earlier this year, when CMP [Central Maine Power] issued some pretty shocking prices related to interconnecting solar projects, the governor sent a letter to the PUC asking them to look into what was going on with CMP’s interconnection process,” Celina Cunningham, deputy director of the Maine Governor’s Energy Office, said during the webinar.

The PUC issued a notice for the formal investigation (2021-00035) in April and held a series of hearings throughout the summer. The proceedings sought clarity on why CMP (NYSE:AGR) told some developers with signed interconnection agreements that they would incur significant, unanticipated grid upgrade costs.

PUC staff issued a bench memorandum on Sept. 21 that essentially found CMP did not properly anticipate the effect that a 2019 law (LD 1711) designed to encourage solar development would have the grid. Staff asked for comments on the basis for and potential calculation of penalties. Staff will issue additional recommendations in an examiner’s report after reviewing those comments.

In its comments on the memorandum Tuesday, CMP said that it has revised its estimated upgrade costs and there is no evidence of harm to any solar developers from its actions. The utility also said there is no basis for imposing a penalty.

Solar and Agriculture

Maine and Massachusetts are working on independent initiatives that will help them understand how to incentivize solar development in harmony with the agricultural sector.

Massachusetts proposed changes on Oct. 6 to its dual-use guidelines for projects under the Solar Massachusetts Renewable Target (SMART) program, according to Steltzer. Dual-use projects, which site solar on land designated for agricultural practices, receive a 6-cent/kWh adder under the SMART program.

The draft guidelines would, among other things, set a goal of 80 MW for dual-use projects, increase the eligible system size to 5 MW and require new farms to be operational for three years to qualify for the adder, Steltzer said.

DOER is accepting comments on the draft guidelines until Oct. 27.

In Maine, a stakeholder group has been studying solar and agricultural lands since June. The Governor’s Energy Office is co-chairing the group to look at “how to balance the use of Maine farmland … and development of solar and putting forward a number of recommendations,” Cunningham said.

The group wants to identify and prioritize different types of lands, identify farmland stressors and understand the lifecycle of solar projects on lands that could revert to agriculture.

A report is due in December, and the group’s next meeting is on Oct. 21.