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.
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.
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.
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.
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 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.
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 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.
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.
BOSTON — Environmental justice communities are already doing the work needed to make renewable energy industries like offshore wind equitable in their workforce and community benefits, according to Elizabeth Yeampierre, co-chair of the Climate Justice Alliance.
“We have questions; we have solutions; and we have concerns,” Yeampierre said during a panel on environmental justice in the development of the U.S. OSW industry. “Anyone who is coming into the sector needs to be able to support that and not manage our expectations or give us a voice — we have a voice, and we are leading this work nationally.”
The panel on Thursday was part of the American Clean Power Association’s Offshore WINDPOWER 2021 conference, held in Boston this week. It brought together officials from the federal and state level, as well as environmental justice advocates and a developer to discuss how to ensure frontline communities are equitably included in workforce development, training and education recruitment.
Developers should advise environmental justice communities on financing, costs and technical construction work, because “we’re leading this movement,” Yeampierre said, herself a leader from a community on the frontline of climate change in Brooklyn, N.Y. “We are not here to advise you.”
Conversations on how to equitably include environmental justice communities are not just about the disparate impacts of the energy industry on people of color and low-income workers, but a matter of allowing people in these communities to speak for themselves, she added.
“Really, the national initiatives and the state initiatives are being shaped by the work that is being done in vulnerable communities like ours,” Yeampierre said.
For example, New York City recently invested in the South Brooklyn Marine Terminal, a two-acre site on the Bay Ridge Channel, to make a national staging and assembly site for OSW. The terminal will be operated by Equinor, developer of the 1,260-MW Empire Wind project.
The company said it will establish a $5 million fund to ensure New Yorkers from low-income communities and communities of color benefit from the new investment, including the creation of at least 6,000 local jobs, because of advocacy from leaders like Yeampierre.
“Success for environmental justice communities equals having access to training, workforce development and education in all levels of employment,” she said. “Our communities can’t be boxed into bonuses or only have access to minimum wage or entry-level jobs.”
From a developer perspective, states have been leading the way with commitments to include underserved communities, said Nancy Sopko, head of external affairs at US Wind.
“There is a very strong commitment from the state to include local content in our OSW projects” to bring on more members of minority-owned businesses, women-owned businesses, veteran-owned businesses and disabled persons-owned businesses in the state, Sopko said,
But it is important that the jobs given to these businesses are good jobs, said Crystal Pruitt, deputy director of the Office of Clean Energy Equity for the New Jersey Board of Public Utilities.
People of color and women often receive “little cheap jobs and simple jobs that don’t mean anything and companies just mark it off,” Pruitt said. “Look at the jobs you’re giving these communities and these contractors and recognize that they need to be lifted up and become prime as well.”
MISO officials said Thursday that the RTO’s proposal to conduct its Multi-Value Project (MVP) cost allocation separately for its South and Midwest regions is likely to be in place for three to four years.
Chief Operating Officer Clair Moeller told the Regional Expansion Criteria and Benefits Working Group (RECBWG) that MISO will propose a bifurcated MVP cost allocation because of the limited transfer capability between the subregions and the RTO’s failure to capture what he called the “unicorn” of a more granular cost allocation.
MISO plans to file the proposal with FERC by the end of November. Officials promised to post tariff redline language by the end of next week and allow at least a week for stakeholder feedback.
Moeller said he hopes the separation of the zones will be temporary, saying it could change as a result of upgrades to relieve the transmission bottleneck or new rules resulting from FERC’s Advanced Notice of Proposed Rulemaking on transmission planning and cost allocation. (See related story, FERC Tx Inquiry: Consensus on Need for Change, Discord Over Solutions.) And he said officials would “continue hunting for the unicorn.”
The COO also said the bifurcated MVP recognizes the limited transfer capability between the subregions to ensure a “roughly commensurate, beneficiaries-pays cost allocation.”
Within five years after implementing the change, MISO will evaluate the transmission investments approved across the subregions and whether the cost allocation results in an equitable outcome for customers “across the entire footprint,” Moeller said.
He challenged the “myth” that previous MVPs built in the Midwest have provided “enormous benefits for the southern region.”
Since 2019, Moeller said, the flow through the Midwest-South interface has been “reciprocal.” For 2021, there has been slightly more flow from the South to the Midwest (52%) than vice versa. About 2% of the intervals found Midwest-South flow at the maximum capacity of 3,000 MW, while 8% of the intervals showed South-Midwest flows at the limit.
Wisconsin Public Service Commissioner Tyler Huebner asked why MISO couldn’t use a metric such as adjusted production costs (APC) for more granular allocations.
Moeller said the northern two-thirds of MISO has “pretty uniform” goals for fleet changes, driven by load. If Michigan benefits from a project in Northern Indiana, MISO must ensure “that costs from Northern Indiana get charged to Michigan.”
“Making sure that the drivers and the payers match is harder to do when you get more granular,” he said.
David Sapper, representing the MISO LSE Coalition, asked about the potential impact of the Southeast Energy Exchange Market (SEEM). The market’s members, including Southern Co. (NYSE:SO), Dominion Energy South Carolina (NYSE:D), the Tennessee Valley Authority and Duke Energy (NYSE:DUK), proposed improving bilateral trading in the region through automation and a move from hourly to 15-minute transactions. The SEEM agreement took effect Oct. 11 after FERC deadlocked 2-2 on the proposal. (See related story, SEEM to Move Ahead, Minus FERC Approval.)
“We’re not sure the Southeast [market] is going to have a big effect,” Moeller responded, saying MISO’s efforts to develop more transfer capacity with Southern and TVA failed to gain “traction.”
“They’re kind of busy doing their own thing right now,” he said. He predicted the SEEM members will see “seams friction” as they proceed. “We hope that that brings to the table” to discuss stronger interconnections, he said.
Steve Leovy of WPPI Energy expressed frustration with MISO’s approach, saying a unicorn “is not an appropriate metaphor” for the RTO’s challenges. “I’ve never seen a unicorn, but I have seen cost allocations that are more granular than 100% postage stamp,” he said.
He said improving transfer capability on the system could reduce required reserve margins in MISO zones. That “has a real economic value that we could measure if we try,” he said.
Lauren Azar, representing the Sustainable FERC Project, said she agreed with Leovy that stakeholders can develop a cost allocation that reflects the goals of the long-range transmission plan to ensure reliability and reduce congestion costs. “But that’s going to take time, creativity and a good-faith effort by all stakeholders,” she said.
Louisiana Hostile to Tx Expansion
The task force voted 32-29 last month against using a cost allocation proposed by Entergy (NYSE:ETR) and its state regulators that would set a higher bar for projects to be cost allocated and assign more specific beneficiaries. Multiple MISO stakeholders have accused Entergy of stalling transmission solutions that could bring outside supply into its territory. (See MISO Stakeholders Blame Entergy for Long-range Transmission Impasse.)
The Louisiana Public Service Commission, which has been clear that it doesn’t want to share in the costs of transmission projects built in the Midwest, will receive a presentation at its Oct. 20 meeting on a staff report looking at the pros and cons of MISO membership.
The PSC said it will pay “particular attention to the need for the state to remove itself from MISO membership prior to 2022 to avoid a negative offset of benefits to ratepayers.”
The Louisiana commission’s move follows an audit from the Mississippi Public Service Commission that questions the continued benefits of MISO membership in light of the long-range transmission plan, a move to a four-season capacity market and an increase of the RTO’s value of lost load. (See Mississippi PSC Audit Questions MISO Membership.)
Group Chair and Michigan Public Service Commissioner Dan Scripps said both he and Vice Chair Carolyn Wetterlin, of Xcel Energy, plan to seek re-election. If there are more than one candidate for either position, there will be an election by email ballot.
FERC’s inquiry into transmission planning and cost allocation prompted a flood of comments this week, most of them agreeing with the commission on the need for changes to aid the transition to a low-carbon grid.
But there was no consensus over whether the commission should eliminate participant funding or create independent transmission monitors. And transmission owners used the docket to call for a restoration of incumbents’ right of first refusal to construct upgrades in FERC-approved tariffs.
FERC received more than 165 comments from utilities, independent power producers, state regulators, RTOs and others in response to the Advance Notice of Proposed Rulemaking (RM21-17) the commission issued following a bipartisan 4-0 vote in July. In opening the inquiry, FERC acknowledged that Order 1000 has failed to provide interregional expansions to deliver increased renewables and meet the challenge of climate change. (See FERC Goes Back to the Drawing Board on Tx Planning, Cost Allocation.)
As is often the case in such dockets, the commission heard many entreaties against a “one-size-fits-all” rulemaking.
“Concerns with the transmission planning and generator interconnection processes are likely to be highly regional in nature,” said the American Public Power Association, opposing a “blanket move away from participant funding in regions where it is currently permitted.”
Dominion Energy (NYSE:D) said the commission should continue to acknowledge and respect the differences between RTO and non-RTO regions.
“FERC should refrain from establishing overly prescriptive rules, particularly around the inputs into planning studies and analyses, so that planning processes will be able to accommodate evolving technology, state laws, regulatory structures, and policy preferences,” said the National Association of Regulatory Utility Commissioners (NARUC).
States’ Roles
“The failure to conduct multi-value, scenario-based transmission planning on a regional and interregional portfolio basis is endemic to the grid,” the Natural Resources Defense Council, the Sierra Club and other public interest organizations told FERC in their comments on the transmission ANOPR. | The Brattle Group and Grid Strategies
Many comments dealt with what role the states — whose renewable portfolio standards and climate policies are helping drive the historic transition in the generation mix — should play in planning the transmission needed to connect renewables to load centers.
NARUC said it “shares the commission’s perspective on the need to reform existing planning processes.”
But it 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.”
NCSL said FERC should support the development of state-created regional mechanisms, such as interstate compacts and regional reliability boards, “to address transmission reliability, problems related to the interconnectedness of the energy grid, environmental impact of generating electricity, and other regional energy issues.”
But the National Rural Electric Cooperative Association (NRECA) said state commissions “should retain their role as stakeholders in Order No. 1000 regional transmission planning and cost allocation processes and not as overseers. Any expansion of that role, such as the SPP Regional State Committee authority noted in the ANOPR, should be the result of regional decision-making and not commission mandate.”
Participant Funding
One question FERC asked commenters to answer was whether it should eliminate rules that allow RTOs/ISOs to use participant funding for interconnection-related network upgrades or whether the costs should be “allocated more broadly among those that benefit” from increased transmission capacity.
EDP Renewables North America said it has “effectively abandoned” development plans in much of MISO West and SPP because of the high costs assigned to its proposed projects. It said it was forced to cancel a 100-MW wind project in Minnesota that was in the final stages of a power purchase agreement negotiation after learning it would be assessed more than $70 million in network upgrades.
Filing jointly, the American Clean Power Association and the U.S. Energy Storage Association, said the commission should eliminate participant funding for network upgrades and shift transmission planning and cost allocation to “a holistic and proactive process that simultaneously addresses key drivers, including — but not limited to — economic, reliability, public policy, and future generation needs.”
The groups proposed that generators, or clusters of generators, would have the sole responsibility for the costs of interconnection-related network upgrades up to and including the interconnection substation, with upgrades electrically “downstream” from the interconnection substation being the responsibility of the transmission provider.
But NRECA said existing policy, including allowing participant funding, “provides the appropriate price signal in nearly all cases.”
NRECA agreed that improvements are needed in generation interconnection processes in some regions. “NRECA members support generation-interconnection reforms that address these issues directly rather than simply shift most of the costs and risks to the customers of load-serving entities and thereby dampening if not eliminating appropriate economic incentives and price signals to interconnecting generators.”
NARUC also urged more incremental changes, saying FERC should “retain the core tenet of participant funding, while exploring the as yet untapped potential economies of scale that could result from increased coordination among participants,” including generators sharing costs in “clusters.”
“Contrary to the apparent presumption in the ANOPR, some state commissions’ experience is that the network upgrades needed to allow generation interconnection do not provide benefits to transmission customers as a whole,” NARUC said.
The Transmission Access Policy Study Group (TAPS), which represents transmission-dependent utilities, recommended allocating costs of proactively planned upgrades to beneficiaries. “If costs remain to be allocated, consideration of load zones expected to rely on the generation that the proactively planned transmission is designed to support could be appropriate. Consistent with fundamental cost allocation principles and given the tensions associated with broad cost allocation, it should be used sparingly.”
TAPS said eliminating RTOs’ ability to directly assign interconnection-related network upgrades costs would remove interconnection customers’ incentive to site wisely, “an inducement that will be essential as we move toward reliance on proactively planned facilities.”
Dominion said the commission should continue to ensure that those who receive the benefits of the investments are assigned the costs. “This means not generically socializing transmission costs, refraining from using transmission as a subsidy to speculative generation projects, and avoiding stranded costs for customers.”
“Wind and solar are important components to a clean energy future, but … new technologies, such as green hydrogen, small modular nuclear reactors, and new battery technology, could transform power generation in the future as well,” it continued. “Such technologies for the benefit of Dominion Energy’s customers should not be discounted by a transmission policy that favors certain types of resources over others.”
The Electric Power Supply Association (EPSA) also opposed broad socialization of transmission upgrade costs, saying the commission should instead “focus on reducing transaction costs, speeding up lagging processes, and adopt market-based approaches, like an open season” for transmission access.
“System planners could hold an open season competitive procurement to solicit bids from suppliers, developers, customers, or even states which could support the build of long-line transmission facilities or network upgrades,” EPSA said. “Rather than using a model like CREZ in Texas which socializes the costs to build transmission first to incent an influx of hopeful supply, an open season brings the interconnection customers to the table to demonstrate that transmission development would be prudently located and supported by sufficient commercial interest.”
EPSA said such a plan would not “rely on forecasting — which is rarely sufficiently accurate, if accurate at all — but could allow states or local entities to sign on to a project to signal a future need to fulfill state policies or goals.”
“While cost allocation may require consideration for revisions, a full reassessment or reversal of participant funding and cost causation principles in order to socialize costs may overstate identified benefits and warp the signals needed to support baseline transmission upgrades, even public policy projects,” EPSA said.
Planning Methodology
FERC also asked what metrics and time horizons transmission planners should use and whether they should consider potential generation not in their interconnection queues.
Several commenters said the transmission planners should use longer time horizons.
American Electric Power (NASDAQ:AEP) said need analyses should consider a 20-year horizon. “The commission’s focus is best directed at working with the North American Electric Reliability Corporation (NERC) and the RTOs to develop a set of planning standards, including benefits metrics and study scenarios, drawing on best practices found in existing planning processes, to create a baseline methodology for transmission planning that will apply to all RTOs and non-RTO regions,” AEP said.
NARUC said it supported “a long-term planning process to allow stakeholders to evaluate transmission system needs and conditions as the system integrates resources that states want to develop in the future. In some cases, states’ energy laws and policies look well beyond the ten-to-fifteen-year timeframe typical for transmission planning studies,” it noted.
MISO planners seek the least cost sweet spot, where transmission additions are lower and there is both a mix of local and remote generation. | MISO
But NRECA said a planning horizon of 10 years is “generally … appropriate” and consistent with NERC’s transmission planning (TPL) reliability standards and state integrated resource plans (IRPs).
Numerous commenters, including the Edison Electric Institute (EEI), which represents investor-owned utilities, agreed with the commission that one way to account for future uncertainty is with increased use of scenario planning that considers several plausible futures.
The Solar Energy Industries Association (SEIA) said planners should include carbon reduction and integrating renewable generation among the “benefits” considered in evaluating potential projects. “The commission, therefore, should require transmission providers, and ISO/RTOs in particular, to monetize the broader societal effects in transmission planning and cost allocation,” SEIA said.
It said FERC should require transmission providers to establish a fee, separate from any interconnection deposit, based on project size, to be charged for submitting an interconnection request. “For projects that require network upgrades, the fee would be applied towards the cost of the network upgrades. The remaining cost of the network upgrade would be allocated to the load zone served by the project.”
But the Southeastern Regional Transmission Planning Process (SERTP), which includes Duke Energy (NYSE:DUK), the Tennessee Valley Authority and Southern Co. (NYSE:SO), warned FERC against “unlawfully intruding into resource/IRP planning reserved to the states or inappropriately seeking to force ‘substantive outcomes’ rather than merely regulating the transmission planning process.”
It said FERC should “retain the prevailing quantitative, objective assessment of transmission benefits used for regional transmission cost allocation processes. The suggested consideration in the ANOPR of qualitative and ‘hard to quantify’ benefits would unnecessarily complicate cost allocation.”
NRECA opposed building transmission facilities to accommodate anticipated future generation not yet in the interconnection queue.
“The ANOPR cites no data to support a finding that ‘too much’ network transmission infrastructure (e.g., in dollars or transfer capacity or number of projects) is built through the existing generation interconnection process — much less any data on the lost efficiency in transmission investment that this might entail or the efficiency gains and losses to be expected by potential replacement processes.”
It said the commission lacks “the authority or expertise to require regional transmission planning processes to quantify the benefits of clean-air attributes of newly interconnected generation and identify the beneficiaries for purposes of regional transmission cost allocation.”
ROFR and Transmission Competition
EEI and Dominion were among those urging the commission to reinstate the federal right of first refusal for projects selected for regional cost allocation, which was eliminated in Order 1000, although the commission allowed states to enact their own ROFRs.
“This policy has resulted in a near standstill in transmission development for regional projects and a substantial increase in process-related costs,” EEI said.
“Allowing transmission owners to work with the state and outside of the constraints imposed by the current inflexible and inefficient RTO process can expedite transmission projects,” Dominion said.
EPSA disagreed, insisting “any reforms to transmission policies leverage the commission’s commitment to competition to ensure that cost-effective transmission investments are signaled and supported by planning, cost allocation, and/or interconnection processes, including the use of competitive procurement processes.”
TAPS also called for continuation of the current rules on competitive transmission development, which it said “has been effective in reducing costs where it has been used.”
Independent Transmission Monitors
There was no consensus on whether the commission should establish independent transmission monitors to evaluate plans to ensure that the projects are the most efficient or cost-effective.
Pine Gate Renewables, a utility-scale solar developer based in Asheville, N.C., said a monitor is essential, contending that transmission planning processes in non-RTO/ISO regions are “opaque with virtually no opportunity for meaningful input from independent power producers or other stakeholders.”
It said SERTP “provides very little information to stakeholders and essentially no opportunity for substantive engagement,” noting that it is comprised exclusively of load-serving entities. “Order Nos. 890 and 1000 have had no meaningful impact on the Southeast,” the group said.
NRECA, EEI and SERTP opposed the concept.
“There is sufficient oversight and transparency in the transmission planning and cost allocation process and another layer of review through an independent transmission monitor is not needed,” said EEI. “… There is no evidence that the existing processes, whether in or outside of a RTO/ISO region, are failing to implement tariffs appropriately or that the processes produce unjust and unreasonable outcomes.”
SERTP said a monitor “would unlawfully second-guess state-regulated IRP and bundled retail transmission service decisions, create friction points in the system expansion process, and cause resulting delays, litigation, and increased costs.”
It conceded SERTP could expand its transmission planning “to better inform decision makers and stakeholders by accommodating additional, proactive scenario-based planning processes that would not directly dictate construction.”
NARUC said such monitors “may be beneficial” but that the “concept and role that the commission envisions for transmission monitors is, at this time, unclear.”
It also questioned whether the commission has the authority to order independent monitors in areas outside of ISO/RTOs.
TAPS said a monitor “could play an important role in non-RTO regions and for local planning in RTOs.”
SEIA said a monitor that evaluates plans to ensure that the projects are the most efficient or cost-effective “could ensure that projects benefit the whole region, and not just a single utility.”
RTOs Weigh In
RTOs also called for the commission to allow regional flexibility in any new rules.
CAISO said it agrees that planning should include anticipated future generation but said FERC should “grant regions sufficient flexibility to implement this approach based on their specific circumstances.”
PJM said its current rules are balanced “in that interconnecting generators pay their ‘but for’ costs to interconnect to the existing transmission system, while load thereafter bears the costs of ensuring continued deliverability of those generators once interconnected.”
Any change to the policy “should account for a reasonable allocation of risk and reward to ensure that the change in policy choice does not result in an unreasonable shift of costs or risks to load,” it said.
The RTO also said resilience must be part of transmission planning and that FERC should create a “common working definition” of the concept and “resilience-based industry planning drivers.”
PJM said an independent monitor is not needed in RTOs and ISOs and “would be far more appropriate … in areas where there is no structural independence as between the transmission planner and its generation affiliates.”
“The oversight function over costs of transmission and the prudence of those investments not reviewed through the [Regional Transmission Expansion Plan] are best addressed by improving customers’ ability to make their voices heard through the commission’s regulatory process,” it said.
ISO-NE said FERC should “explore process enhancements to address any identified concerns before establishing another independent entity to monitor transmission planning, which could inadvertently weaken, and introduce delays and risks into a well-functioning, open and transparent process, at the expense of getting transmission built in time to meet identified needs.”
NYISO said “incremental, yet significant, reforms can meaningfully address many of the issues raised in the ANOPR.
“Adoption of targeted reforms can have a more immediate impact than a complete overhaul of the existing processes, which would take considerable time to develop, implement and, ultimately, to result in new transmission,” it said. “Moreover, attempting to address all transmission needs and issues simultaneously through a single, unified process may be overly complex, slow and inflexible.”
SPP said it already uses several of the commission’s proposed initiatives, noting that its Integrated Transmission Planning uses several future scenarios to evaluate a range of potential outcomes “under a variety of projected load, generation mix, and grid usage conditions.”
MISO said it has been conducting stakeholder processes “addressing nearly all of the topics raised in the ANOPR, and more, to address the evolving system.”
Grid-enhancing Technologies
One solution likely to get a boost from the rulemaking is grid-enhancing technologies (GETs).
“Going forward, GETs may play an important role in increasing efficient use of the system and providing a short-term solution until needed transmission is built,” EEI said. “However, additional experience is needed to determine how best to model and operate these technologies.”
