PJM MIC Briefs: Feb. 10, 2021

PJM delayed an endorsement vote on an issue charge regarding the allocation of capacity transfer rights (CTRs) for a month after stakeholders raised questions over the initiative’s scope and potential impact.

Kevin Zemanek, director of system operations for Buckeye Power, reviewed the problem statement and issue charge by the Ohio-based company during last week’s Market Implementation Committee meeting, saying current rules are exposing his cooperative to price separation.

Under the Reliability Pricing Model (RPM), CTRs return to load-serving entities (LSEs) capacity market congestion revenues that occur when there is a difference between capacity prices paid by load and market revenue received by cleared capacity resources. CTRs permit LSEs with load inside a constrained locational delivery area (LDA) to receive a credit for the import of capacity from a lower-priced region.

Zemanek said PJM does not have a way to allocate CTRs to an LSE that corresponds to the network load identified in its network integration transmission service agreement. Instead, PJM allocates CTRs pro-rata to each LSE serving load in the LDA or zone based on the LSE’s share of the zonal unforced capacity obligation.

Although an LSE may have resources that are deliverable to load inside the constrained LDA, current rules do not allocate an equivalent number of megawatts, Zemanek said.

Buckeye Power has been harmed because the existing RPM rules disregard the “historic structure” of Buckeye and Ohio TO’s, Zemanek said, leading to “millions of dollars” in excess charges.

He added that Buckeye seeks to explore market rule changes that would account for resources within PJM’s footprint that existed prior to the implementation of RPM.

“We’re asking the committee to consider a rule change that would account for historic resources internal to PJM’s footprint and have the deliverability to designated load,” Zemanek said.

He said he anticipates two months of education followed by discussions on potential rule changes.

Paul Sotkiewicz of E-Cubed Policy Associates said he’s inclined to support the problem statement to start the discussion, but one of his concerns would be adding to the key work activities on how incremental capacity transfer rights (ICTRs) would be impacted by any changes.

Zemanek said Buckeye didn’t intend to have ICTRs impacted by the issue charge and was not looking to impact any existing contractual rights.

Sotkiewicz asked if Buckeye would be open to a friendly amendment to look at the potential impact to ICTRs, but Zemanek said he wasn’t sure if the issue charge needs to be changed.

Sotkiewicz said he doesn’t see a way to address CTRs without also addressing ICTRs.

“Some of us have felt like we’ve gotten burned on issue charges where we think topics are in scope and then we’re being told they’re out of scope,” Sotkiewicz said.

Jeff Bastian, PJM senior consultant in market operations, said the CTRs that Buckeye is considering allocating are those remaining after ICTR megawatts are determined. Bastian said there would be no impact on the ICTR calculation from the issue charge.

PJM MIC — PJM Monitor Joe Bowring | © *RTO Insider*

One stakeholder questioned language in the issue charge, saying it seemed to find a way to allocate CTRs to entities like Buckeye while leaving other issues “undisturbed.” He said he’s not sure there’s a way to allocate the CTRs without disturbing the existing system.

Independent Market Monitor Joe Bowring said the Monitor is “skeptical” about introducing a contract path as the basis for the rights to CTRs.

Lisa Morelli of PJM suggested deferring the endorsement vote until the March MIC meeting to allow for refinements to the issue charge and problem statement from the stakeholder feedback about what is in scope and out of scope.

Capital Recovery Factors Discussion

Bastian provided a second first read of the problem statement and issue charge to regularly update the value of capital recovery factors (CRFs) based on current federal tax rates. CRFs are a component of the net avoidable cost rate (ACR) of a resource, which determines a resource’s market seller offer cap or minimum offer price rule (MOPR) floor price, depending on which is applicable.

The Monitor notified PJM in a letter Dec. 4 that the CRF values, which were set in 2007, do not reflect the 2017 reduction in federal corporate tax rates.

The RTO has proposed to address the CRF issue as part of a quick fix process in which the MIC would simultaneously approve the issue charge and the proposed tariff revisions at the March 10 meeting.

The Monitor said the tables should have been updated in 2018 and must be changed before the next capacity market auction, for the 2022/23 delivery year, takes place in May. The RTO said it was concerned that seeking an earlier effective date would further delay the auction, which was originally scheduled for 2019. (See PJM Sets BRA for May 2021.)

The RTO said it agrees with the Monitor that offers including the avoidable project investment rate in net ACR values are unlikely to impact the May auction results.

PJM proposed that after the upcoming auction, the table of CRF values be posted on the PJM website no later than 150 days before the beginning of the offer period of each auction. The values would reflect federal income tax laws in effect for the relevant delivery year at the time of the determination.

Bastian said PJM revised its initial proposal to reflect feedback at the January MIC meeting, when stakeholders requested more transparency in the key input assumptions. (See “Challenge on CRF Quick Fix,” PJM MIC Briefs: Jan. 12, 2021.)

Sotkiewicz thanked PJM for listening to the stakeholder feedback and said the changes reflected much of the discussions. He said the only potential concern he had was making the formulas used to calculate the CRFs accessible on PJM’s website rather than stated as a “generic financial model.”

Erik Heinle of the D.C. Office of the People’s Counsel said PJM was able to come up with a “reasonable solution” that addresses concerns of not falling behind in tax laws and constantly trying to catch up with changes.

Long-term Five-minute Dispatch

Aaron Baizman, senior engineer for PJM, reviewed the solution package matrix for the long-term five-minute dispatch and pricing issue worked on in the MIC special session meetings and said an endorsement vote on the PJM/IMM package would be delayed until the March MIC meeting.

Baizman said PJM wants to take a “measured approach” for the implementation of the long-term evaluation of five-minute dispatch and pricing, especially with the number of changes affecting dispatch.

Stakeholders approved the short-term proposal to resolve five-minute dispatch and pricing at the July MRC meeting. The RTO had said it expects to continue evaluating long-term solutions late into this year, with a quantitative analysis of the pros and cons of different approaches. (See PJM Stakeholders OK 5-Minute Dispatch Proposal.)

Baizman said highlights of the long-term package include real-time security-constrained economic dispatch utilizing previous generator dispatch instructions to create guidelines. PJM dispatchers will also be provided flexibility for exceptions for case approval caused by unanticipated conditions or application issues.

A first read of the proposed tariff language was also moved to the March 24 Markets and Reliability Committee meeting. Baizman said PJM and the Monitor are still reviewing the tariff changes, and a review of the draft tariff language will be held at the five-minute dispatch and pricing special session on Wednesday.

Baizman said the current long-term timeline calls for software development until April, testing of the software from May to June, parallel operations and evaluation from July to September and a pilot evaluation and implementation by Nov. 1.

February 16, 2021

PJM PC/TEAC Briefs: Feb. 9, 2021

Critical Tx Infrastructure Proposals Endorsed

Stakeholders last week endorsed PJM’s packages of proposals for mitigating and avoiding designating projects as critical infrastructure under NERC reliability standards after more than a year of work on the issues.

The Planning Committee endorsed the avoidance package, including associated manual language, with 77% support at its meeting last week. In a separate vote, the package won 61% support over maintaining the status quo.

The committee also endorsed PJM’s mitigation package with 61% support and 60% preferring it over the status quo.

Dave Souder of PJM thanked members for their work on the proposals and for the endorsements. He said PJM will take at least a month to finalize Operating Agreement language to be included with the mitigation portion, with a first read at the Markets and Reliability Committee’s meeting March 24.

“We’re not done yet, but we’re on the right path,” Souder said.

Mike Herman of PJM presented the proposals to the committee. The changes to Manual 14B include the addition of a new subsection describing the process related to maintaining reliability and added “avoidance” to the list of transmission planning activities.

PJM also added text to Manual 14F detailing the process by which it may modify a proposal submitted through the competitive planning process. Herman said PJM removed the term “resilience” from all the manual language edits in favor of the term “critical substation planning analysis” in response to stakeholder feedback at the January PC meeting. (See “CIP-014 Update,” PJM PC Briefs: Jan. 11, 2021.)

Other changes included new text detailing the process by which PJM may modify a proposal submitted through the competitive planning process and includes examples of proposal modifications that would and would not be deemed “limited in scope.”

Paul Sotkiewicz of E-Cubed Policy Associates pointed out that the term “resilience” was still included in at least one section in Manual 14F and should be corrected by PJM before endorsement.

PJM — Paul Sotkiewicz, E-Cubed Policy Associates | © *RTO Insider*

“I think consistency is really important in the language, especially when it comes to the transmission planning between the different manuals,” Sotkiewicz said.

PJM’s Aaron Berner said it appeared the existence of the “resilience” terms in the manual language was an oversight and would be corrected.

The RTO will hold a special PC meeting on Feb. 19 to go over the proposed OA language for the mitigation portion of the package. Herman said the major language change was the addition of a definition for substation contingency resilience planning criteria: “analyses performed to ensure system resilience based on a study of select substation contingencies, which are based upon TPL-001-4 Extreme Contingency Analysis. The analysis evaluates the loss of load and potential cascade events which may result from power flow analysis. Due to the sensitive nature of the analysis, identified substations and results require confidentiality consistent with established processes and good utility practice.”

Flow chart for “Substation Contingency Resilience Planning” within mitigation efforts for the PJM proposal on future CIP-014 facilities | *PJM*

Robert Taylor of Exelon said he appreciated the work that went into the packages and that it was “a long road to get here.”

“I personally believe we’ve landed in a good place that balances a lot of competing interests in how to address this,” Taylor said.

Capacity Interconnection Rights

Jonathan Kern of PJM provided a first read of the problem statement and issue charge to address the capacity interconnection rights (CIRs) of variable resources.

Kern said the recent adoption of effective load-carrying capability (ELCC) highlighted the need to investigate the topic. Stakeholders endorsed a revised joint stakeholder proposal at the September MRC and Members Committee meetings to use the ELCC method to calculate the capacity value of limited-duration, intermittent and combination (limited-duration plus intermittent) resources. (See ELCC Method Endorsed by PJM Stakeholders.)

ELCC, which is already used by MISO, NYISO and CAISO, evaluates reliability in each hour of a simulated year and compares a resource mix with limited resources against one with unlimited resources.

Kern said CIRs for new wind and solar resources are administratively set for several years at the average expected outputs for the summer period unless developers can supply weather data to support higher outputs. CIRs for new limited-duration resources such as storage are administratively set based on the amount of energy that can be supplied over a 10-hour period, he said.

CIRs are not included in ELCC calculations or in determining accredited unforced capacity (UCAP). Kern said sizing the grid for CIRs based on outputs below maximum summer values may result in curtailments because of insufficient transmission, and resource adequacy performance and accredited UCAP may be overstated unless CIRs are considered.

Kern said PJM’s goal is to hold a series of monthly discussions with the PC and to develop and propose changes to the applicable manuals and governing documents by the end of the year. He said PJM will hold educational sessions and discuss and develop proposals from April to October and ideally present a proposal to the MRC in November.

PJM — Gary Greiner, PSEG | © *RTO Insider*

Gary Greiner, director of market policy for Public Service Enterprise Group, said PJM’s presentation seemed “a little bit off” from what he expected to be discussed and that it’s not good to have stakeholder discussions “start on second base.” Greiner said there needed to be more foundational education pieces on the CIR issue, focusing on CIRs and what their rights and purposes are in traditional and intermittent resources, not diving into specifics from the beginning.

Greiner said the only point he’s comfortable with in the key work activities and scope on the issue charge is education on the status quo policies for CIRs.

Kern said PJM’s intention is to give a “good foundation” on the status quo policies of CIRs during the educational sessions.

Sharon Midgley of Exelon said she had additional questions on the issue charge. She pointed to subject areas deemed to be out of scope in the issue, including provisions for unlimited resources.

PJM — Sharon Midgley, Exelon | © *RTO Insider*

Midgley said Exelon realizes the CIR effort is to look at variable resources, but it wants to make sure there is “equity” in the rules between variable and unlimited resources. She asked PJM to strike the unlimited resources subject area from the out-of-scope section.

Kern said PJM wants to achieve the objectives in the allotted time, so a topic like unlimited resource CIRs would be considered out of scope. He said there may be other issues identified during the discussion that warrant a separate problem statement and issue charge.

“In the end, we want to find an equitable solution that works for all resources,” Kern said.

Midgley said she doesn’t want to have to bring forward another problem statement and issue charge “to fix something that might be inequitable” that emerges from the process. She said she would rather change the current problem statement and issue charge to leave the opportunity to examine unlimited resources if it’s needed.

Sotkiewicz said he agreed with the concerns raised by Greiner and Midgley. He said there are already issues he anticipates that will be brought up in the way CIRs and dispatch are done that will create inequitable outcomes among different resources.

He said there are too many issues that are “left to the imagination” that need to be spelled out more clearly in the problem statement and issue charge and that too many of the issues are “open ended.”

“I think the issue charge as it stands today is not ready for prime time,” Sotkiewicz said.

PJM encouraged stakeholders to provide redline language before the next PC meeting to address concerns in the problem statement and issue charge.

TO/TOP Matrix v15

Stakeholders unanimously endorsed a draft version 15 of the TO/TOP Matrix to be provided to the Transmission Owners Agreement-Administrative Committee (TOA-AC). Mark Kuras, chairman of the Transmission Owners/Transmission Operator (TO/TOP) Matrix Subcommittee, presented the proposed changes.

The matrix is an index between the PJM manuals and governing documents and NERC reliability standards that are applicable to the RTO as the TOP. It includes a column of “tasks” required by PJM under the documents. Kuras said version 15 of the matrix adds references for reliability standards, including TOP-001-5.

The endorsed changes will head back to the TOA-AC for final approval at its April 22 meeting.

Transmission Expansion Advisory Committee

Technological Pilot Project

PJM — Map of PEPCO region where Exelon is examining the installation of an experimental coated conductor | *Exelon*

Exelon is looking to test an experimental coating for overhead conductors to improve capacity. Koushy Nareshkumar of Exelon presented a need for supplemental projects in the Potomac Electric Power Co. (PEPCO) region.

Nareshkumar said Exelon is testing the “innovative technology” of E3X Technology, a coated conductor, to increase circuit rating. Conductors with the coating have shown to have increased emissivity and lower absorptivity. The technology allows for operation with a cooler conductor at higher ampacity, the maximum current a conductor can carry continuously without exceeding its temperature rating.

PJM — Erik Heinle, D.C. OPC | © *RTO Insider*

Erik Heinle of the D.C. Office of the People’s Counsel asked if Exelon’s project was being introduced through a state initiative or if it was just looking to test the technology. He also asked if the technology had been used anywhere else by Exelon.

Nareshkumar said Exelon was taking the initiative to test the technology themselves and that it was the first time E3X was being utilized. She said Exelon is still in the process of determining what line will be used for the project, but it will be on one of its 230-kV lines in PEPCO.

February 16, 2021

PJM Operating Committee Briefs: Feb. 11, 2021

PJM is looking to improve the deployment of synchronized reserves during a spin event, but some stakeholders are questioning whether the timing of the issue is appropriate given major changes in the reserve market next year.

Mike Zhang, PJM senior engineer of markets coordination, provided a first read of a problem statement and issue charge during last week’s Operating Committee meeting.

Synchronized reserve events are emergency procedures triggered by PJM to maintain grid reliability in accordance with NERC’s Resource and Demand Balancing (BAL) standards. Such procedures are caused by a variety of conditions, including loss of generation by multiple units going offline at the same time or a sudden influx of load.

Zhang said real-time security-constrained economic dispatch (RT SCED) cases are generally not used by PJM during an emergency event, which can lead to problems like unpredictable levels of unit response and a mixture of over- and under-response across various units.

Zhang said PJM dispatchers have been seeing a pattern of a slow initial recovery period followed by extended over response after the emergency event is over. Because tools like RT SCED are not utilized during an event, Zhang said, pricing and dispatch signals are still from a pre-event RT SCED case and often conflict with all-call instructions because the signals don’t go away immediately.

PJM is looking for controlled deployment of synchronized reserves throughout emergency events by utilizing tools like RT SCED to have consistent pricing and dispatch signals. The goal is to also ensure BAL compliance during recovery and a reliable transition in and out of emergency events.

Key work activities include review and education on existing actions and expectations for synchronized reserve events, and analysis of metrics and data on previous emergency events. PJM also wants to develop solutions and timelines for the overall synchronized reserve deployment process, including the deployment method, the expectations of resources and the evaluation of performance.

The existing performance penalty structure is not in scope for the issue, Zhang said, as PJM views it is adequate.

“We have a variety of metrics and historical data to draw from, and hopefully we can utilize that to get us started,” Zhang said.

PJM’s proposed approach to the issue calls for convening a task force within the OC to recommend potential changes to resource expectations during events. The estimated work schedule is between six to 12 months after endorsement.

One stakeholder said the timing of the work by the task force may be complicated by PJM’s revised operating reserve demand curve (ORDC), set to go into place by the middle of 2022. The stakeholder said he’s hoping the price signals from the ORDC will change whether the events PJM are worried about will even need to be called. (See FERC Approves PJM Reserve Market Overhaul.)

“I’m not sure that you need to still do all-calls, or at least the need would be different,” he said. “And I don’t see that anywhere in the issue charge.”

Zhang said PJM still believes the effort is beneficial even with the ORDC changes. He said those “hit at different areas” of the synchronized reserve market. This proposal revolves around the deployment of reserves, while the ORDC involves how those reserves are procured and priced, he said.

PJM — Adrien Ford, ODEC | © *RTO Insider*

The stakeholder said he believes PJM’s analysis of the ORDC only impacting procurement and pricing is “strongly incorrect” and that all the issues are intertwined more closely. He said the key work activities should at least include an educational piece on how all-calls would work in an environment of the ORDC coming into play next year.

Adrien Ford of Old Dominion Electric Cooperative said she understood the stakeholder’s concerns and thought having education on the impact of the ORDC was important. Ford said the reserve price formation changes set to go into effect next year are “pretty sweeping,” and education should be included in the issue charge.

“Issue charges are to explore what we need to do and not a foregone conclusion that the change would occur,” Ford said.

Stakeholders will vote on endorsement of the problem statement at the March 11 OC meeting.

Manual 40 Changes Endorsed

Stakeholders unanimously endorsed a minor change to Manual 40 as part of the periodic review.

Michael Hoke of PJM reviewed the update Manual 40: Training and Certification Requirements. In section 3.2.1: Transmission Owner Operators, a reference was added to the annual training requirements referenced in NERC standards. A second reference was added regarding using the PJM Learning Management System to track the annual task training requirement.

Hoke said the change was based on feedback from ReliabilityFirst, which expressed a desire to “see a more explicit connection” between Manual 40 and standard requirements in the matrix for transmission owners.

Resource Tracker Quick Fix

Chris Franks of PJM reviewed a “quick fix” problem statement and issue charge to update language in Manual 14D regarding the Resource Tracker application’s ownership confirmation requirement.

Franks said PJM members are responsible for maintaining complete and accurate records as stipulated in section 11.3.1(a) of the Operating Agreement. The Resource Tracker application was created in 2013 to provide a single-point location for generation owner information, Franks said, and stakeholders endorsed changes in 2018 to move the confirmation period to an annual basis with a four-week duration to enter correct information in the application. (See “Resource Tracker,” PJM Operating Committee Briefs: Nov. 6, 2018.)

The 2020 annual confirmation period opened on Oct. 1 and closed on Nov. 1, Franks said, with a total of 1,503 resources requested to confirm information. Of those resources, 60 did not confirm by Nov. 1. As of Feb. 1, four have yet to confirm information.

Franks said PJM is looking to refresh the user interface of the application to reflect similar tools used by the RTO and to add additional fields to provide contacts associated with the resources.

The proposed manual language includes changing “market participants are requested” to the “generation owner, or designated agent, is required” to confirm the resource ownership by Nov. 1.

The OC will be asked to approve the issue charge and endorse the proposed revisions as part of the “quick fix” process at the March meeting.

February 16, 2021

Overheard at NE Energy Vision Tx Planning Tech Forum

Energy officials in New England are concerned that ISO-NE’s transmission planning process cannot adapt to the evolving resource mix, the growing investments in clean energy and the decarbonization of the grid. Without more robust transmission planning, they said, ratepayers in the region likely face higher costs and lower reliability, plus potential curtailment of the renewable resources needed to meet state policy goals and mandates.

Here is some of what we heard during a public online technical forum on Feb. 2, organized by New England states, to discuss reforms to the RTO’s transmission planning process.

Long-term Tx Planning ‘Key’

New Hampshire Public Utility Commissioner Kate Bailey said the region’s clean-energy transition requires “significant new investments” in renewable resources that are unlikely located close to load centers.

Bailey said changes resulting from an expansion of distributed energy resources, energy efficiency, electrification of the transportation and heating sectors and, “retirement of a good portion of the fossil-fired fleet” would likely produce “very different power flows across the grid of the future compared to today’s grid.”

“Two-way flows of power are likely to be much more common than they are today, which will make the transition even more complicated,” Bailey said. “All of this will require substantial additional spending on new transmission lines and upgrades to existing lines to accommodate the new, remotely located clean resources.”

According to Bailey, the region must complete the transition within a relatively short time, and “our goal should be to accomplish the transition at least cost for ratepayers.”

New England states have decarbonization targets of 30 to 45% by 2030 and 80% or net-zero by 2050.

Bailey said that “long-term transmission planning, which factors in the state’s collective requirements, is key.” One way to limit higher costs for ratepayers, she said, is to require competitive solicitation for all transmission construction, not just those projects that address reliability, and she hopes that “changes made to the process will require that.”

Judy Chang, undersecretary of energy for the Massachusetts Executive Office of Energy and Environmental Affairs, said the region could not afford to continue the traditional way of developing transmission by reacting to interconnection requests or conducting reliability upgrades.

ISO-NE, Eversource Weigh in

Robert Ethier, ISO-NE’s vice president of system planning, said the grid is “undergoing as big a change as it’s experienced in the last several decades.”

Ethier said the RTO’s transmission planning process has been driven by addressing reliability needs and the interconnection of new resources. The integration of renewables and storage to meet state public policy initiatives “in a timely and efficient way” will require new planning, approval and funding approaches, he said, along with greater engagement with both states and NEPOOL stakeholders.

ISO-NE transmission planning — Breakdown of the new resource proposals in the ISO-NE interconnection queue | *ISO-NE*

Bill Quinlan, president of transmission for Eversource Energy, said that an effective long-term transmission planning process is essential — especially when examining the timeline to execute major upgrades — to achieve decarbonization goals.

“It’s clear to us that to deliver the clean energy future that we’re all seeking … we need to take a hard look at the long-term planning process,” Quinlan said. And “that planning process needs to begin now. We need to then look for alignment with key policies, whether it’s at the federal level … or the state level. With good involvement by the stakeholders, I think we will be able to deliver that grid of the future that will enable the clean energy future we are all seeking.”

‘The Benefit of Consumers’

Rebecca Tepper, chief of the Energy and Telecommunications Division in the Massachusetts Attorney General’s Office, said she “wanted to remind everyone” that the transmission system “was built for the benefit of consumers, and every penny of it was paid for by consumers, either directly or indirectly.”

“Over the last 10 years, New England ratepayers have spent $11 billion to develop and upgrade our transmission system,” Tepper said.

There are planned transmission upgrades “that will cost billions more,” so she said it is vital that the region makes “the best use of the transmission systems that customers have already paid for.”

“Right now, the overall utilization of our transmission system is actually low,” Tepper said. “Think about your car … you probably only use 10% capacity of your car, but it’s still really valuable when you want to drive it somewhere. …

“More efficient use of transmission lines can help save money by avoiding congestion, but it also can help integrate new kinds of uses like electric vehicles at lower costs,” she said.

Next Steps

Chang requested written comments on the forum’s topics and discussions. Those comments will be accepted through March 1 and posted publicly on the New England Energy Vision website. Additionally, she said the states would issue a joint summary of the issues identified and explain the potential solutions.

State officials have scheduled additional technical forums on governance reform (Feb. 25) and environmental justice (TBD).

February 16, 2021

Nev. Bill Would Spur Tx, Clean Energy Buildout

Nevada lawmakers are planning to introduce an array of clean energy bills during the 2021 legislative session, including a measure that could pave the way for a massive expansion of electric transmission in the state.

Nevada Clean energy Bill — Sen. Chris Brooks | *Nevada Legislative Counsel Bureau*

Sen. Chris Brooks (D) is crafting a bill that he says would incentivize and prioritize new electric transmission in the state, potentially creating about $10 billion worth of investment in clean energy.

“I’m really looking forward to being able to expand the clean energy opportunities in the state of Nevada through transmission investment,” Brooks said during a meeting this month hosted by the Nevada Conservation League. “I think it’s long overdue.”

Brooks told RTO Insider that he’s still working with stakeholders to hammer out details of the bill, which had not yet been introduced. While specifics of the proposal were not yet available, he said the incentives are not likely to be financial. Instead, the bill would provide ways to facilitate new transmission projects.

Transmission won’t be the only focus of Brooks’ omnibus legislation, which the senator informally called his “big energy bill.” Other components will include plans for electric vehicle charging infrastructure and measures that would create rooftop solar energy opportunities for renters and multifamily housing residents.

Another piece of the legislation aims to align electric utilities’ integrated resource planning process with the state’s carbon reduction goals.

“It won’t just be the renewable portfolio standard anymore that is guiding how we invest in clean energy in the state,” Brooks said. “We’re actually going to use the carbon reduction goals of the state to guide clean energy investments.”

The Nevada legislature, which meets every other year, convened on Feb. 1 for a session that will run through May 31. Brooks and other lawmakers outlined their clean energy plans during a Nevada Conservation League meeting on Feb. 1, held via Zoom.

Although lawmakers are grappling with the COVID-19 pandemic’s economic impacts, they said they are still determined to make progress toward climate objectives this session. Nevada has set a goal of net-zero greenhouse gas emissions by 2050.

“Even in the midst of a pandemic, even in the midst of a massive economic downturn, we can take advantage of this legislative session to move the ball forward on climate and also create jobs — good-paying jobs — and tax revenues,” Brooks said. “We can achieve all of the goals at the same time.”

‘Classic Car’ Loophole

In addition to Brooks’ energy bill, Assemblyman Howard Watts (D) is planning a bill to reduce vehicle emissions by closing what’s been called the state’s “classic car” loophole.

The state allows cars that are 20 years or older to be registered as classic vehicles, which exempts them from smog checks. Critics point to cars that many people wouldn’t consider a classic — such as a 2000 Honda Accord — which may qualify for the exemption and remain on the roads as gross polluters.

Watts said his bill would not only close the classic car loophole but also increase smog check fees to raise funds for a variety of programs. Those would include assistance to low-income residents to repair their cars to meet emission standards or even to buy a new electric vehicle.

Chispa Nevada, a Las Vegas-based environmental conservation organization, has championed the proposal.

“We like the idea of creating/identifying funds for programs that help low-income customers repair their polluting vehicles or replacing them with cleaner versions like … low- or zero-emission cars,” Program Director Rudy Zamora said. “Oftentimes when we talk about electric vehicles, we forget about our communities — low-income communities, communities of color.”

Natural Gas Under Scrutiny

The Natural Resources Defense Council (NRDC) is also crafting legislation for the 2021 session.

One proposed bill calls for increased scrutiny of investments in natural gas infrastructure.

“As Nevadans use less methane gas in homes and businesses … gas utilities are at risk of wasting ratepayer money on unnecessary construction projects,” said Dylan Sullivan, a senior scientist with the NRDC. Sullivan said Assemblywoman Lesley Cohen (D), had agreed to sponsor the bill.

NRDC’s second piece of proposed legislation would focus on energy efficiency programs. Although NV Energy runs a number of such programs, Sullivan said the utility is not doing enough. The bill would make some energy-savings targets mandatory and increase targets for programs geared toward low-income residents. The bill would also give regulators the option to designate a third party to run the programs.

Two bills are likely to come out of the Legislative Committee on Energy, a panel of six lawmakers that meets between legislative sessions to discuss energy matters. Assemblywoman Daniele Monroe-Moreno (D) chairs the committee, and Brooks is vice chair.

One of the committee’s proposals would amend the Nevada constitution to allow proceeds from gas taxes or vehicle license and registration fees to be used for transit projects. Currently, the use of those funds is restricted to the construction, maintenance, operation and repair of public highways.

The second proposal would establish a working group to develop preliminary plans for a sustainable system of transportation funding. The group would study topics including the needs of bicyclists, pedestrians and transit users, as well as ways to reduce transportation-related GHG emissions.

February 16, 2021

COVID Yields $1B of Unpaid Energy Bills in Calif.

The California Public Utilities Commission is seeking ways to help the millions of utility customers who collectively owe more than $1.15 billion in past-due energy bills, largely because of the COVID-19 pandemic and resulting economic downturn.

The commission continued a moratorium on customers disconnections through June. But without additional action, utility customers eventually will be on the hook for the arrearages, it said in issuing a new order instituting rulemaking (OIR).

California energy bills — CPUC commissioners and staff members opened a proceeding Thursday to deal with a huge backlog of unpaid energy bills. | *California Public Utilities Commission*

“We need to get started preparing our customers through what’s going to be a very, very difficult transition period,” Commissioner Clifford Rechtschaffen said. “Those numbers are extraordinarily frightening: the [amount and] extent of the debt owed — really, really jarring.”

Ed Randolph, head of the CPUC’s Energy Division, said he is fairly certain about the amount owed, but the exact number of customers in arrears is harder to determine because of the different ways utilities report them.

Pacific Gas and Electric, the state’s largest utility, said its customers owe it more than $531 million. Southern California Edison said its ratepayer debts total close to $332 million. San Diego Gas & Electric recorded more than $142 million in past-due bills, while Southern California Gas racked up nearly $149 million in customer debt.

Job losses contributed heavily to the debt. Unemployment for low-income households in California topped 30% during part of 2020, the commission noted.

The proposed decision adopted Thursday starts a process of trying to find “relief mechanisms” for customers and utilities alike.

“When the disconnection moratorium ends, some customers will be faced with outstanding utility bills,” the commission said. “When disconnections for nonpayment resume, some households will still be contending with loss of life and livelihood, and we do not intend for these customers to face their outstanding utility bill arrearages alone.”

Another concern is the financial stability of the investor-owned utilities, the CPUC said.

“The pandemic has persisted longer than could have been imagined,” it said. “Increases in unpaid customer bills may also impact the financial health of the very utilities that must continue to provide the essential services.”

The commission said it does not want to spread the backlogged debts among all IOU customers, as normally might be done. Instead, it is considering programs to provide payment assistance to vulnerable customers, including medical baseline customers, and to introduce longer and more flexible payment options for customers who cannot pay on time.

“Our new proceeding will put in place debt management programs tailored to these extremely challenging times, with special consideration for the most vulnerable in our communities who may be having trouble paying their energy bills,” Rechtschaffen said in a statement following the vote.

February 14, 2021

MISO TOs’ Self-funding Option Tested Again

Two FERC commissioners still have heartburn over a 2018 commission order reinstating MISO transmission owners’ rights to self-fund network upgrades.

Chairman Richard Glick and Commissioner Allison Clements expressed their concerns in a Feb. 8 order following MISO’s submittal of an unexecuted facilities service agreement (FSA) between itself, interconnection customer Walleye Wind and transmission owner Northern States Power Co. While FERC approved the unexecuted FSA for a 111-MW Minnesota wind farm, it opened old wounds over the appropriateness of TOs’ unilateral right to self-fund network upgrades (ER21-615).

Walleye Wind, a NextEra Energy Resources subsidiary, said it refused to execute the FSA and requested MISO file an unexecuted document because of “continued legal uncertainty regarding” TOs’ right to provide initial funding for the network upgrade that would accommodate the project.

MISO Transmission Owners — | *NextEra Energy*

Walleye said FERC could reverse its decision in the future, placing initial funding responsibility back on interconnection customers.

The company asked FERC to direct MISO to amend the FSA by including a provision for the possible reversal of TOs’ self-funding option. It asked that the FSA state that “changes will be undone if the legal premise for [transmission owner initial funding] is later eliminated.”

FERC declined to amend the FSA to incorporate such language, saying the document correctly reflects the state of MISO’s rules at the time.

Glick concurred with the FSA decision but wrote separately that giving TOs the option to “unilaterally choose whether to self-fund network upgrades constructed on behalf of affiliated and nonaffiliated interconnection customers” could be unfair. He said the commission “failed to meaningfully wrestle with these concerns in its orders allowing transmission owners the unilateral right to choose up-front funding.”

Clements said that while she concurred with the decision, she is worried that FERC didn’t “adequately address the justifiable concern that those rules create an opportunity for generation-owning transmission owners to unduly discriminate” between assets they have an ownership interest in and those they don’t have an interest in.

She said that when interconnection customers have control of initial funding, they can finance at more favorable rates instead of reimbursing TOs for construction and a predetermined rate of return. She also said TOs’ unilateral right to self-fund ignores that the “vast majority of transmission owners do in fact still own generation.”

The commission should conduct a “more searching inquiry” of the issue, she said.

“While this topic has been the subject of litigation before this commission and the courts for several years, I believe we have more work to do,” Clements wrote. “A foundational principle of the commission’s work to open up access to the nation’s transmission grid over the past 25 years has been that when monopoly utilities are permitted to discriminate among affiliated and nonaffiliated customers, competition suffers and customers pay.”

She said that while the reasonableness of MISO interconnection rules was not the item in question, “they may well merit additional scrutiny in the near future.”

MISO in 2018 acted on FERC’s direction and reinstated TOs’ right to self-fund network upgrades necessary for new generation. FERC originally issued a 2015 order barring TOs from electing to provide initial funding for network upgrades, but that decision was remanded by the D.C. Circuit Court of Appeals. (See MISO Gauging Aftershocks of TO Self-fund Order.)

The move was unpopular with some MISO generation developers, who said it could pave the way for discrimination by TOs of some interconnection customers and increase the cost of new generation. But TOs’ ability to self-fund network upgrades survived a challenge last year from the American Wind Energy Association. (See FERC Upholds MISO Self-fund Order, Glick Dissents.)

February 14, 2021

Long-term Tx Plan Edges Out MISO GI Coordination

MISO last week said it bit off more than it could chew by simultaneously mounting a long-term transmission package while trying to merge interconnection upgrades with annual transmission planning.

Staff announced Wednesday during a Planning Advisory Committee (PAC) teleconference that it will table the effort to analyze network upgrades stemming from interconnection requests for economic benefits and possible cost-sharing. They said MISO would wait until the end of the year and see how the long-term transmission plan develops.

“We received feedback from stakeholders last month that it’s probably better to wait until more information of the long-range transmission plan comes at the end of the year,” Senior Manager of Economic Planning Neil Shah said. “Let’s put this issue on hold, and we will continue to monitor the progress of the long-range plan.”

Stakeholders, particularly those belonging to the environmental sector, seemed fine with the breather.

“It did seem like it was appropriate to pause work on this since there are so many moving parts that could affect [it],” Clean Grid Alliance’s Natalie McIntire said. “I don’t want to lose this issue. It may be that it gets addressed somehow with long-range transmission and its allocation.”

Shah agreed that some long-term projects may ease network upgrade costs for interconnecting generators.

Stakeholders have warned MISO that system upgrade costs for interconnection hopefuls have been snowballing in recent years because of scant transmission planning, threatening a clean energy transition. (See “Coordinated Planning Effort Continues,” MISO Planning Advisory Comm. Briefs: Sept. 23, 2020.)

Before hitting pause on the network upgrade analysis, the RTO had proposed to conduct economic evaluations of interconnection upgrades with signed interconnection agreements rated at 230 kV or above and costing at least $50,000/MW. If the upgrades demonstrated the same 1.25:1 benefit-to-cost ratio required of market efficiency projects, they would have been included as economic projects in MISO’s annual Transmission Expansion Plan (MTEP).

The Long View

While interconnection upgrade coordination took a back seat, stakeholders at the PAC were left wondering how often they’ll be apprised of MISO’s long-term transmission planning.

They asked for monthly updates on the progress of MISO’s burgeoning long-term transmission plan, the first in a decade. (See MISO Begins Longterm Tx Modeling.) The February PAC meeting did not have an agenda item on the long-term plan.

Director of Planning Jeff Webb said MISO will begin delivering regular reports to stakeholders when it has “substantive materials.” He said so far, there is little to report.

“We can give updates, but they’ll probably be brief status updates,” Webb said, adding that the RTO plans to hold a discussion on long-term planning at the March PAC.

The grid operator is currently relying on the 20-year futures scenarios developed for MTEP 21.

Todd Hillman, MISO’s senior vice president and chief customer officer, said the RTO is first focusing on Future I, which most closely resembles member utilities’ collective plans. The future assumes an 85% likelihood that utilities meet their current decarbonization plans and full certainty that their stated generation retirements and additions come to pass. The scenario will likely translate into a 60% carbon reduction in MISO from 2005 levels.

“Future I was largely developed in talking with our members and stakeholders,” Hillman said during an informational forum in January.

MISO expects to have preliminary project solutions from its Future I modeling within the next few months. Staff is also beginning long-term modeling for the more aggressive Futures II and III. Webb said he thought that any transmission projects coming out of Future I would most likely be “baseline” and serve as a foundation for other needs found using the second and third futures.

WEC Energy Group’s Chris Plante said he wasn’t sure that MISO was predicting enough storage technology in its futures. He noted utilities are increasingly turning toward storage.

The Natural Resources Defense Council said late last month that the RTO has failed to prepare for a clean-energy future through sufficient transmission planning. The nonprofit said MISO’s recent transmission planning ignored the rapid pivot to clean resources and only anticipated “incremental clean energy development over the coming decade, rather than transformational clean energy development that is anticipated by 2035 and beyond.”

“In 2020, [MISO] ignored the demand for the regional transmission necessary to transition the Midwest into a clean energy hub. This year [it] can and should do better by building regional transmission,” the NRDC’s Toba Pearlman wrote in a blog post. She said the RTO’s inaction intensified its interconnection queue backlog.

NRDC reported that 278 storage, hybrid, wind and solar projects were withdrawn at “advanced stages” in the grid operator’s interconnection queue between 2016 and October 2020.

Senior Transmission Planning Engineer Andy Witmeier said the grid operator’s current transmission planning would be inefficient without a long-term package, and without it, “the resource shift contemplated by MISO stakeholders’ goals will be difficult to achieve.”

Speaking during a cost allocation working group teleconference on Thursday, Witmeier pointed to MISO’s newest instantaneous wind peak on Dec. 23, when 20.2 GW of wind generation served almost 27% of system load. He said even more wind power was available that day but was “trapped behind transmission congestion.”

“We have to make sure we enable the delivery of that extra generation,” he said. “With an additional 4,500 MW expected to come online in the next 12 months, it is increasingly important to see how the system is currently handling production of renewable resources and [preparing] for future growth.”

Cost Allocation Decisions Loom

MISO’s cost allocation group will eventually consider a benefit measurement and cost-sharing design for the long-range transmission plan.

Witmeier said the RTO’s current market efficiency project cost allocation won’t likely capture all long-term transmission benefits.

The Organization of MISO States convened a special cost-allocation committee late last year to draw up principles on how staff should approach long-term projects’ cost sharing. The resulting principles are broad, driving home that costs should be portioned out as precisely as possible to beneficiaries and cost-causers. OMS said generation and load — including regions with decarbonization goals — can be considered beneficiaries. It also suggested MISO use subregional allocations and bundle certain transmission projects’ costs when it makes sense.

MISO Executive Director of System Planning Aubrey Johnson acknowledged there’s not much appetite among stakeholders for a footprint-wide postage stamp rate for long-term transmission.

“That camp is very small. There’s not a high likelihood of success,” he said during an OMS meeting in January.

February 14, 2021January 15, 2025

Southeast Seeks FERC OK for Expanded Bilateral Market

Utilities and cooperatives in 11 Southeastern states on Friday proposed using automation and free transmission capacity to expand bilateral trading and allow 15-minute energy transactions.

Led by the Tennessee Valley Authority, Southern Co. and Duke Energy, the Southeast Energy Exchange Market (SEEM) seeks to reduce the “friction” in bilateral trading by using an algorithm to match buyers and sellers and eliminating transmission rate pancaking in the region’s 10 balancing authority areas.

Electric providers purchase cheaper power when they can back down more expensive generation in their own fleets; sellers earn profits to offset their operating costs.

To make a transaction currently “the parties must discover one another, negotiate the terms of the sale, arrange and pay for transmission service across all utilized transmission systems, and schedule the delivery of energy. All of this is done with ‘traditional’ methods of communication, by phone and electronically, thus creating transactional friction,” Southern Company Services said in a FERC filing on SEEM’s behalf (ER21-1111, et al.). “Trades generally occur on an hourly basis as the shortest increment, and most often occur only with entities in the same or directly interconnected balancing authorities.”

The SEEM proposal, which would allow participants to move power over unused transmission capacity at $0/MWh, “will enhance efficiencies and reduce opportunities to exercise market power by allowing more buyers to transact with more sellers over a much bigger region,” SEEM said.

Although the group’s name includes “market,” participants made clear that they do not see the proposal as a prelude to an RTO. “The Southeast EEM is not — and was never intended to be — a top-to-bottom reimagining of the Southeast energy market; rather, it reflects incremental improvement to the existing bilateral market,” the group said.

Among SEEM’s “core principles” are that each electric service provider and state will maintain control of generation and transmission investment decisions and that each transmission provider will remain independent, with its own transmission tariff. There will be no changes to reliability, state jurisdiction or responsibilities for resource adequacy, it said.

SEEM had provided some details of its proposal in an informational filing with the North Carolina Utilities Commission in December. (See Southeast Utilities Announce Regional Energy Market.) Friday’s filings provided many more details on its governance, cost allocation and measures to address potential market power.

Fourteen utilities and cooperatives have signed the SEEM agreement and five others are “contemplating or in the process of seeking” approvals to do so. Members opened 13 dockets detailing the agreement and changes to their transmission tariffs. (Some of the members are not FERC jurisdictional.)

Members and Participants

TVA; Southern’s Alabama Power (ER21-1111, ER21-1125), Georgia Power (ER21-1119) and Mississippi Power (ER21-1125, ER21-1121; and Duke Energy Carolinas (ER21-1116) and Duke Energy Progress (ER21-1115, ER21-1117) represent nearly three-quarters of SEEM’s net energy for load (NEL).

The other initial members are: Associated Electric Cooperative Inc.; Dalton Utilities; Dominion Energy South Carolina (ER21-1112, ER21-1128); Louisville Gas & Electric (ER21-1114, ER21-1118) and Kentucky Utilities (ER21-1120) (LG&E/KU); North Carolina Municipal Power Agency Number 1; PowerSouth Energy Cooperative; and North Carolina Electric Membership Corp.

Those planning to join are Georgia System Operations Corp. (GSOC); Georgia Transmission Corp. (GTC); Municipal Electric Authority of Georgia (MEAG); Oglethorpe Power Corp. (OPC); and South Carolina Public Service Authority (Santee Cooper).

The 19 expected members have 160 GW of summer generating capacity (180 GW winter) in parts of 11 states across the Eastern and Central time zones and serve more than 32 million retail customers.

New members — which must have a load-serving responsibility or serve an entity with that responsibility — will be allowed to join during an enrollment period from July 1 through Sept. 30 annually. Nonmembers that want to submit bids and offers into SEEM will be called participants.

Yes or No Decision for FERC

SEEM asked FERC to allow a comment period of 30 days, rather than the usual 21, and sought an effective date in 90 days — May 13. Members hope to select a vendor to build the system in the first quarter of this year with the buildout complete by the third quarter and trading beginning in the first quarter of 2022.

SEEM said FERC can only opine on whether the rates proposed in the group’s Federal Power Act Section 205 filing are just and reasonable, limiting any changes to “minor deviations.”

But FERC is likely to hear complaints from intervenors who contend SEEM does not go far enough to modernize the region’s electric industry.

When news of SEEM’s efforts became public in July, the Solar Energy Industries Association and the Southern Environmental Law Center said they would push regulators to demand more competition. The Southern Alliance for Clean Energy said SEEM appeared to be an effort to avoid legislative action to create an RTO in the Carolinas. “We remain concerned that SEEM is being constructed as a way for participating utilities to avoid being pushed to form or join a competitive energy market.” (See Southeast Utilities Talking Regional Market.)

Stakeholder Outreach

The proposal arose out of a year of discussions among the electric providers and other stakeholders, including “governmental entities and non-governmental entities such as environmental groups, trade associations and individual customers,” SEEM said.

“Comments have been overwhelmingly supportive, but a common request was that the members take the Southeast EEM construct further, to have more ambitious aims entailing far greater complexity. … The current proposal is the one that struck a delicate balance among the members, and thereby enables, for the first time, a regionwide market enhancement in the Southeast.”

“This is not the first effort to develop a regional market in the Southeast … but it is the first one to enjoy such broad support from the transmission owners and load-serving entities in the region,” Aaron Melda, TVA’s senior vice president for transmission and power supply, and Lonnie Bellar, chief operating officer of LG&E/KU, said in an affidavit submitted to FERC, referencing the collapse of a four-year effort following Order 2000 in 1999.

The group said it will post trading data on a public website and that it will hold annual meetings “open to all interested parties.”

Any changes to the market rules will be filed at FERC, providing an opportunity for public comments.

No Impact on Reliability

SEEM proposes a new zero-cost, non-firm energy exchange transmission service (NFEETS) provided on an as-available basis after all other uses have been considered. It would be available solely for 15-minute energy exchanges, have the lowest curtailment priority, and unable to be reassigned, sold or redirected.

It could only be provided by a transmission provider whose system — when added to the other participating transmission providers — creates a continuous contract path. Because it would be a non-firm, as-available product, no transmission studies would be required.

“The Southeast EEM will not have any negative impact on reliability, because it will not change any current reliability roles or responsibilities and will rely on unused transmission given the lowest curtailment priority,” the group said, adding that the market will not offer capacity transactions. “The reliability obligations that BAs and transmission providers have today are unchanged under the Southeast EEM.”

Split the Savings

SEEM said it will save customers money by allowing more efficient use of unused transmission capacity over a large footprint, increasing the opportunities for win-win trades. It will use a “split-the-savings” approach with the transaction price at the midpoint between the seller’s offer and the buyer’s bid, with an adjustment for transmission losses.

SEEM will be a “low-risk, high-reward venture,” members said, citing a 20-year benefits analysis by Guidehouse and Charles River Associates that projected a minimum of $40 million in benefits per year (2020$) in a scenario based on recent integrated resource plans and equivalent data.

Under a “carbon constrained” scenario, benefits will increase to more than $100 million annually by 2037, according to the analysis. The scenario was based on participants’ IRP carbon-reduction plans and “reasonable assumptions of what a high-renewable-and-storage, low-carbon future may look like in the Southeast.”

Start-up and ongoing costs are estimated at a total of $3.1 million annually (2020$) levelized over the 2021-2040 period.

SEEM acknowledged that the new free transmission service could result in a “slight decrease” in point-to-point revenues used to offset network service charges but said the revenues at stake are “minimal.”

Its benefits will result from bilateral trades unlikely to occur under current rules, the group said. “The automated system will have a substantial advantage in searching for transmission paths with available transmission to complete beneficial trades, overcoming transaction costs and information barriers. Further, the algorithm will exhaustively seek out all possible beneficial trades across the territory.”

In addition, it “will allow for better integration of diverse generation resources, including rapidly growing renewables, and will reduce renewable curtailments,” Melda and Bellar said in their affidavit.

Because of the lack of sub-hourly market liquidity, transmission providers currently must balance all variation in renewable output across the full hour.

“By creating greater liquidity in sub-hourly wholesale transactions, especially across a broad geographic area encompassing possibly different weather conditions and renewable policies, the Southeast EEM can provide additional opportunities for transmission service providers to either procure additional energy or to dispose of excess energy, rather than having to rely exclusively on increasing or decreasing the output from their own generation resources that provide imbalance service,” they said.

Governance, Cost Allocation

Each of the members would have a seat on a Membership Board, which “will be responsible for all significant decisions,” while a revolving subset of four members would run the Operating Committee, responsible for overseeing the day-to-day operations and working with an independent entity that would administer the system.

The Operating Committee would have two members from the investor-owned utility sector and one each from the cooperative sector and governmental utility sector, reflecting the sectors’ shares of load. To prevent any subset of members from dominating, votes by the Operating Committee would have to be unanimous, with any issues that cannot be resolved taken to the Membership Board. All members would be permitted to “attend, observe and participate” in Operating Committee meetings.

The group plans a hybrid cost allocation formula, with 25% of costs allocated equally among all members and 75% assigned based on NEL.

Market Power

The members said they would contract with an auditor to “review and analyze” market data to ensure that the system is functioning properly, but they have no plans to create a market monitor, contending that SEEM does not create new opportunities to exercise market power.

“Any additional market monitoring functions beyond the auditor’s responsibilities would be superfluous, creating additional administrative costs that are not justified. For these reasons, members are unwilling to fund the costs of a market monitor and believe the traditional means of commission oversight of [market-based rate] transactions will continue to provide adequate opportunities for review and regulatory protection,” SEEM said.

To avoiding potentially anticompetitive price discovery, all reported pricing information would be aggregated and its release delayed until at least the day after the trading day.

The group submitted an affidavit from Susan Pope, a managing director at FTI Consulting, who said no participant could exercise market power in SEEM “unless it already could exercise market power in today’s hourly bilateral market.”

Companies will be able to put constraints into the algorithm to ensure that they continue to obey current mitigation measures, Pope said. “Dominion Energy South Carolina, Duke and LG&E/KU anticipate complying with their mitigation requirements by toggling ‘off’ their home BAAs, thus ensuring that they are not matched with any bidder in their home BAAs and more than meeting the market power mitigation requirement.”

Pope said it would be problematic if a participant could unfairly obtain zero-cost NFEETS or profit from manipulating the average hourly energy exchange prices.

But she said the requirement that all participants have “toggled on” at least three unaffiliated potential counterparties would prevent collusion “to trick the algorithm into moving the schemers to the front of the line for zero-cost transmission.”

“The number of counterparties renders it difficult and risky for parties to coordinate to implement such a scheme, particularly in light of the small benefit to be obtained (i.e., a greater probability of obtaining zero-cost NFEETS),” she said.

TVA ‘Fence’

In crafting the SEEM agreement, members said they were careful to honor the so-called TVA “fence,” which Congress enacted to prevent the federal utility from selling power outside the areas it was selling to as of July 1, 1957.

Among the current SEEM participants, TVA can sell power to only Duke, LG&E/KU and Southern, although it can purchase from any SEEM participant.

“Given TVA’s central location in the Southeast, if TVA cannot participate in a redesigned market, then others (LG&E/KU and AECI) would not have a contiguous connection to the rest of the market,” Pope noted. “If they cannot connect through TVA, they must connect through one of the neighboring RTOs, thus adding another wheel, and the added transmission expense, to any transaction with a counterparty in the Southeast.”

February 14, 2021November 10, 2023

NYPSC OKs Clean Energy Programs, Local Transmission Planning

The New York Public Service Commission on Thursday approved several programs to speed up the state’s transition to renewable energy.

The measures include money for communities hosting solar or wind resources and those losing old power plants and their tax payments, new regulations on handling utility and customer data related to energy usage, and a mechanism for utilities to bypass rate case proceedings in local transmission planning.

The PSC also granted a certificate of environmental compatibility and public need to New York Transco to build a new, double-circuit 54-mile 345/115-kV transmission line, estimated at $530 million, along the Hudson River from near Albany down to Duchess County (Case No. 19-T-0684). The commission also approved the 20-mile, 345-kV Empire State Line project by NextEra Energy Transmission New York in the western part of the state (Case No. 18-E-0765).

New York state agencies last month released a study that urges faster permitting, planning and approval to build the transmission needed to integrate nearly 40 GW of new renewable energy into the grid over the coming decades. (See NY Grid Study Pushes Meshed OSW Tx, Coordination.)

The commission’s fast pace is being driven by New York’s Climate Leadership and Community Protection Act (CLCPA), which requires the state to consume 70% renewable electricity by 2030, switch to 100% zero-emission power by 2040 and reduce greenhouse gas emissions to 85% below 1990 levels by midcentury.

Utility Leverage

The PSC unanimously approved a “Phase One” local transmission planning mechanism that allows utilities to bypass the usual rate case process and acquire funding approval by petitioning the commission for such authority (Case No. 20-E-0197).

The state’s investor-owned utilities on Nov. 2 jointly filed a report in which they collectively proposed to undertake about $7 billion in transmission and distribution upgrades by 2025 (Phase One) and another $10 billion in projects for the following five years (Phase Two). (See Meshed OSW Tx Grid May Work Best, NY Officials Hear.)

The commission’s order said that relying strictly on rate case cycles to provide for cost recovery of proposed Phase One projects may delay achievement of CLCPA goals.

“However, we expect that this mechanism will be needed only in the short term … and once those [CLCPA] deadlines and requirements are incorporated into the utilities’ capital planning processes and rate plans, the commission does not anticipate a continuing need to rely on petitions for incremental funding of Phase One projects,” it wrote.

“In my eyes, this is a thoughtful and practical item founded on an open and thorough process founded on ample opportunity for input, and in fact ample and helpful uptake on that opportunity,” said PSC Chair John B. Rhodes. “It represents the next milestone to developing out the grid that we know we will need, in today’s case both on the distribution and local transmission side of the grid.”

“This really does mark the change in how transmission planning moves from serving native load, exclusively at lowest cost, to a more environmentally sensitive and environmentally driven system,” Commissioner John Howard said. “Most of the items here on Phase One were going to go forward regardless of the CLCPA, and we do get some tremendous environmental benefits by their construction.”

Most comments on the docket supported approval of the proposed Phase One projects, but the state’s Utility Intervention Unit, the City of New York and LS Power Grid New York filed comments opposing some or all of the projects on the basis that they either go beyond the scope of the PSC’s initial grid study order last May or that the utilities failed to provide adequate details or cost information.

In its comments, Multiple Intervenors, a coalition of about 60 large industrial, commercial and institutional energy customers, asked “that more robust cost-containment measures be applied to CLCPA-driven projects and especially those approved outside of the rate case process.” The group recommended NYISO’s public policy transmission planning process as a framework under which “developers submit highly detailed proposals” to allow the ISO to assess viability and sufficiency.

Relying on Property Taxes

The PSC unanimously approved a program that provides bill credits to residential electric customers in municipalities in which major renewable energy facilities are located, possibly dampening local opposition to such projects (Case No. 20-E-0249).

The type and size of the facility determine the amount of the credit. Any new solar or wind project greater than 25 MW that goes into service after April 2020 will be required to pay the utility serving the affected municipalities an annual fee of $500/MW and $1,000/MW of nameplate capacity, respectively.

Howard was not entirely pleased with the host community benefit program but said he was encouraged by the provisions to assess its effectiveness every two years.

“In the interim I would urge all municipalities that border host communities for large-scale renewable projects engage in the siting process to assure that any affected residences receive compensation under this program,” he said.

Two other energy-related items on the consent agenda had one or two votes in opposition, either from one or both of the Republican members on the five-member commission.

Commissioner Diane X. Burman provided the only dissenting vote on creating an integrated energy data resource that will provide a platform for collecting, integrating, managing and accessing customer and system data from the state’s energy utilities (Case No. 20-M-0082).

“While I think that the proposal for a statewide integrated energy data resource may have some merit, it is something we should not undertake as a commission right now,” Burman said, adding that the arrangement needs more discussion. “Frankly, I think we can and should wait until the new, permanent chair to decide if this is the direction … to have staff deeply invested in.”

Both Burman and Howard voted against authorizing the New York State Energy Research and Development Authority (NYSERDA) to provide approximately $12.5 million each year through 2029 to help local communities offset the loss of property taxes that typically occurs when a large power plant closes (Case No. 20-E-0473).

The plant closing mitigation program will not be backed by imposing incremental funding obligations on ratepayers. Instead, NYSERDA would transfer Regional Greenhouse Gas Initiative (RGGI) funding to Empire State Development for the program, with aid not to exceed $112.5 million in total through 2029.

“I must say I’m very troubled by this item for several reasons, first being the use of RGGI funds to compensate communities for loss of property tax revenues due to power plant closures,” Howard said.

The legislature has the power to compensate the loss of tax revenue in various ways, and the new program “takes off any veil” from RGGI and related fees on emitters or ratepayers being taxes, and in fact fungible, thus able to be used for purposes not foreseen when the environmental programs were created, he said.

“This is a perfect example of our state’s overreliance on property taxes to fund essential local services,” Howard said. “No state taxes energy infrastructure to the extent that we do in New York. … We also need to understand that massive capital investments to meet the carbon reduction goals of the CLCPA will only exacerbate this very flawed system.”

The PSC approved a resolution to petition Gov. Andrew Cuomo to increase the number of commissioners on the board from five to seven, given the increasing workload for commissioners and staff. The session closed with PSC Secretary Michelle Phillips reading a resolution from staff and commissioners thanking Rhodes, whose term ended Feb. 1, for his “faithful service to the residents of New York.”