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November 7, 2024

FERC Orders End to Static Transmission Line Ratings

FERC on Thursday ordered transmission providers to end the use of static line ratings in evaluating near-term transmission service, a move the commission said will improve accuracy and transparency and increase utilization of the grid (RM20-16, Order 881).

The order requires transmission providers to employ ambient-adjusted ratings (AARs) for short-term transmission requests — 10 days or less — for all lines that are impacted by air temperature. Seasonal ratings will be required for long-term service.

The commission said the current practice — in which line ratings are typically based on conservative assumptions about worst-case, long-term air temperature and other weather conditions — has caused underutilization of available transmission capacity.

“This is a pretty big deal,” Chairman Richard Glick said at the commission’s open meeting. “We’ve spent a lot of time over the last several months talking about the need for substantial investments in new transmission capacity, and there is a significant need for these investments. But at the same time, we need to squeeze more out of the existing grid.”

FERC opened the docket with a Notice of Proposed Rulemaking last year. (See FERC Proposes Requiring Variable Tx Line Ratings.)

The final rule did not mandate the use of dynamic line ratings (DLRs), which the commission said should be more accurate than AARs by incorporating not only forecasted temperatures, but also other weather conditions such as wind, cloud cover, solar irradiance intensity, precipitation, and line conditions such as tension or sag. DLRs also can provide situational awareness, alerting operators if a line is over its capacity.

But the order does require that organized market operators allow transmission owners that would like to use DLRs the ability to do so. FERC also ordered RTOs and ISOs to create systems and procedures to allow transmission owners to electronically update transmission line readings at least hourly.

The order also rejected the NOPR’s proposal to “stagger” implementation of AARs on historically congested lines first, followed by all lines. The order requires transmission providers to submit compliance filings within 120 days of the rule’s publication in the Federal Register and to implement the rules within three years after that.

Worst-case Assumption

In a presentation to the commission, Dillon Kolkmann of the Office of Energy Policy and Innovation, said that transmission line ratings are often based on worst-case assumptions, for example, a hot summer day. “Atmosphere and weather conditions vary day to day and hour to hour. But seasonal or static ratings are typically updated only when equipment is changed or weather assumptions are revised,” he said.

As a result, such ratings often result in less transfer capability than the system can actually provide, resulting in unnecessary congestion costs, curtailments and redispatch orders.

Kolkmann said seasonal and static ratings may also overstate near-term transfer capability, creating reliability risks.

Glick said the evidence gathered to date was insufficient to determine “the incremental benefits, costs and risks associated with dynamic line ratings.” The commission opened a new proceeding (AD22-5) to build the evidentiary record further.

Commissioner Allison Clements said she hoped that new rules also would result in more accurate signals about where investments in new transmission facilities are needed.

“I want to stress that this rule is not [the end of] efforts to improve existing system efficiency, but instead represents an important first step,” she said. “The record in this proceeding does demonstrate that dynamic line ratings may provide even more accurate line ratings than ambient adjusted ratings, and therefore even greater reliability and economic benefits to consumers. In my mind, these are benefits we can’t afford to leave on the table.”

How Much More?

LineVision Inc., which provides transmission technology for AARs and DLR, claims its solutions can “unlock up to 40% additional capacity.”

The Electric Power Research Institute said that DLR is more costly than AARs because it requires “placing sensors in remote locations, ensuring the cyber security of sensors, and various additional costs.”

AARs are widely used in PJM. The RTO told the commission that AARs provide “significant operational value [and] allows for the realization of additional incremental capability on the system.”

PJM is conducting DLR pilot programs with PPL and AEP. In a study of a hypothetical installation on one of its most congested lines, PJM said DLRs could provide a payback of the estimated $500,000 equipment installation cost in two months through reduced congestion payments.

In its comments, the Electric Power Supply Association was generally supportive of moving to DLR but warned it “could have some unintended impacts with respect to day-ahead and real-time price convergence.

“While such an impact ultimately may not be negative or significant, it is nonetheless important to ensure that the RTOs consider the issue,” EPSA said.

ITC Holdings told the commission in April that “AARs should not be seen as a panacea to the needs of the transmission system.”

The company said it agreed with the Organization of MISO States (OMS) that AARs “should not be implemented on facilities where it is not economic or reliable to do so.

“A collaborative approach among stakeholders will allow the identification of the facilities that will provide the most benefit to electric customers from the use of AARs,” ITC said. “This is of particular importance in MISO where the Transmission Owners have worked over more than the past 18 months to develop an AAR conceptual framework to evaluate candidate facilities and begin the process of program development.”

FERC Accepts MISO-SPP Congestion Charge Solution

FERC said Thursday that MISO and SPP can use a predictive flow factor process to offset overlapping congestion charges between the RTOs on pseudo-tied loads and resources (EL17-89, et al.).

However, the commission said the grid operators are not off the hook in refunding past excessive congestion charges.

FERC said the organizations can use the new process, which entails using forecasted rather than historical data, to determine the relief necessary on a market-to-market (M2M) flowgate. MISO and SPP said a predictive process will allow them to provide more precise redispatch relief on constraints.

The RTOs pledged to use the process in the first couple of intervals after an M2M event begins. The update to their joint operating agreement will become effective at the end of March 2022, when the RTOs will complete software design and testing.

FERC agreed that the solution would dramatically cut or reduce the duplicative charges.

The commission said in late 2019 that it would investigate overlapping congestion charges between the grid operators after complaints from American Electric Power (AEP) subsidiary Southwestern Electric Power Co. and the city of Prescott, Ark. FERC has since held a technical conference on the matter, ruling that MISO and SPP must correct the problem and rejecting challenges from the RTOs. (See FERC Upholds Decision on MISO-SPP Overlapping Charges.)

AEP and Prescott argued that it won’t be clear for months whether the new process is a sufficient solution and asked FERC that its acceptance be conditional. The commission responded that the predictive flow factor remedy should represent an improvement over the RTOs’ “uniquely excessive” congestion charges, reminding AEP and Prescott that “the RTOs cannot provide perfectly calibrated redispatch to match the exact congestion relief required.”

However, FERC ordered the grid operators to submit three annual joint informational reports through early 2025 to describe whether the solution works in practice and to list any post-implementation challenges.

FERC: Refunds in Order

FERC set hearing and settlement judge procedures to establish appropriate refunds due to AEP and Prescott.

The RTOs had said the refunds would be too onerous to calculate. They said the calculations would be tantamount to re-running the market and asked FERC to exercise its discretion in not ordering the refunds.

MISO and SPP said that “by only correcting the relief amount during any given interval, without taking into account the many variables that occur during real-time operations, the results of the calculations would be, at best, an unverifiable estimation.”

FERC countered, “We believe that providing recovery to AEP and Prescott for the unjust and unreasonable overlapping congestion charges they incurred during the refund period outweighs the RTOs’ concern that calculating refunds for AEP and Prescott would be burdensome and lead to unverifiable estimates.”

Before proposing their solution, MISO and SPP had argued that though duplicative congestion charges are possible for their pseudo-tie transactions, mechanisms such as virtual transactions, financial transmission rights and firm flow entitlements counteract double charging.

MISO maintained that congestion charges on the RTOs’ pseudo-tied generation don’t require special tariff remedies similar to the measures it took to correct double charging with PJM. MISO said it did not experience near the pricing impacts that it used to with PJM transactions.

NERC Standards Committee Briefs: Dec. 15, 2021

NERC’s Standards Committee approved a revised charter and standard authorization requests (SARs) for its MOD and PRC rules in its year-end meeting Wednesday.

Reactive Power Measurements

The committee accepted SARs for Project 2021-01, which is considering changes to MOD-025 (Modeling, Data, and Analysis) and PRC-019 (Protection and Control).

The Power Plant Modelling and Verification Task Force (PPMVTF) developed a SAR to revise MOD-025-2 to address problems with the verification and data reporting of generator active and reactive power capability. The task force said the existing standard has rarely produced data suitable for planning models although that is its purpose.

Most testing cases are undermined by limits within the plant or system operating conditions that prohibit the generating resource from reaching its “composite capability curve.” The standard drafting team hopes to correct these issues so that equipment owners can produce suitable and accurate data during verification activities.

PRC-019-2 seeks to addresses miscoordination among generator capability, control systems, and protection functions, but does not sufficiently outline the requirements for non-synchronous generation, a problem identified by the System Protection and Control Subcommittee (SPCS). The SAR seeks to revise the standard to apply to all generation types.

The Planning Committee endorsed a third SAR in December 2019 concerning the potential risk of increasing amounts of reactive power being supplied by nonsynchronous sources. But the SAR drafting team revised and consolidated the three SARs into two.

Marty Hostler of Northern California Power Agency questioned why the SAR wasn’t reposted after the drafting team made changes in response to industry comments. “I saw a lot of negative comments,” he said. “And I’m just curious why it hasn’t gone out again for additional commenting after all the adjustments were made?”

NERC Senior Standards Developer Latrice Harkness said NERC rules don’t require reposting the SAR after it has been reviewed by the SAR drafting team. “The comments for consideration … were posted back in November for review,” she said. “The team has worked to consider those comments.”

Transmission Relay Loadability

The committee also approved a SAR for Project 2021-05 that was submitted by the System Protection and Control Working Group to modify PRC-023 to address potential reliability issues resulting from confusion regarding the standard.

The standard is intended to ensure protective relays are set so they do not trip unnecessarily during heavy loading conditions while still being capable of detecting all fault conditions.

The SAR said some entities have disabled their power swing blocking (PSB) relays because of internal conflicts within the standard, which could lead to tripping during stable power swings. The SAR calls for removing or modifying Requirement R2 “because it has been interpreted to restrict the setting of PSB elements making determination of appropriate settings more difficult and making compliance with PRC-026 more difficult.”

Engineer Philip Winston questioned why the SAR continues to list the System Protection and Control Working Group as the sponsor even though it was changed after the working group submitted it.

“I’m a little concerned over the fact that this revision to the … SAR has never gone back to the [working group]. So to show it that they are sponsoring it, in my opinion, is incorrect,” he said. “And I have confirmed that with the chair of the [working group] that he has not been informed of the changes that have been made.”

“Once a SAR is submitted to the Standards Committee, it actually becomes part of the Standards Committee and the process there,” said Howard Gugel, NERC’s vice president of engineering and standards. “We do not typically go back to the original submitter and ask that submitter to review any changes that were done based on public comments.… That has been a common practice for us.

“In other words,” Gugel said, “the submitter doesn’t own the SAR anymore. It’s actually owned by the Standards Committee.”

The committee approved the SAR with the notation that it was “as revised by the SAR drafting team based on comments.”

Committee Charter Approved

The committee also approved a revised committee charter in response to a charge from the NERC board in November that it further amend the document — last updated in 2019 — to ensure clarity about its role and that it has the “agility” to respond to urgent reliability concerns.

Committee Chair Amy Casuscelli of Xcel Energy said the changes include additional language to clarify the committee’s role as a “process committee,” additional references and linkages to the Standard Processes Manual section of the Rules of Procedure, and a section on waivers to highlight the committee’s “ability to act with agility in the face of urgent need.”

The revised charter states that the committee “shall provide oversight of the reliability standards development process to ensure stakeholder interests are fairly represented” but that it “shall not under any circumstance change the substance of a draft or approved reliability standard.”

It also includes a new section allowing the committee to waive some steps in the Standard Processes Manual if needed to act quickly to meet “a time constrained regulatory directive” or meet “an urgent reliability issue.”

Call for Volunteers

NERC Board Member Jim Piro ended the meeting by thanking the committee for its work in 2021.

“It’s been a very busy year, and I’ve been really impressed with the attention to detail that the committee takes in doing their work,” he said. “And I will tell you that the work is not going to end … There’s a lot of important issues ahead of us in terms of looking at the changing grid as it decarbonizes.”

Piro acknowledged concerns about “industry fatigue” and the need to get resources from the industry to work on future SARs.

Charles Yeung, executive director of interregional affairs for SPP, and chair of the Project Management and Oversight Subcommittee, echoed Piro’s concern, saying the (PMOS) will be seeking new members in 2022.

“We had 11 members on PMOS. … Three of those 11 members did not re-up their membership for the next year, and we did not get any new nominations this year,” said Yeung. “… So, I invite anyone on the committee or folks that you know from your organizations to nominate.”

Casuscelli reappointed Michael Brytowski, of Great River Energy, as vice chair of the PMOS.

Oregon Effort Seeks to ‘Close the Gap’ on GHG Goals

Oregon is working on multiple fronts to help meet its goal of reducing greenhouse gas emissions 80% below 1990 levels by 2050.

But those measures won’t be enough to hit the target, Alan Zelenka, assistant director for planning and innovation at the Oregon Department of Energy (ODOE) said last week.

That’s where the Transformational Integrated Greenhouse Gas Emissions Reduction (TIGHGER) project comes in, Zelenka said during a Dec. 8 virtual public meeting to the explain the initiative, a collaboration with Oregon Global Warming Commission (OGWC).

Zelenka listed the major “planned actions” Oregon is putting in place to meet its 2050 objectives, including three efforts led by the Department of Environmental Quality:

  • implementation of the Climate Protection Program, intended to drive down emissions from stationary sources, transportation and natural gas by setting declining caps on GHGs;
  • an expansion of the Clean Fuels Program, which will decrease the carbon intensity of fuels sold in the state 25% by 2035; and
  • development of a program aimed at reducing GHG emissions from electricity generation 80% by 2030, 90% by 2035 and 100% by 2040.

Despite the immense scope of those efforts, a line graph shared by Zelenka illustrated the gulf between the reductions those “business-as-planned” measures are projected to provide and what Oregon actually needs to stay on its “decarbonization pathway.”

“So TIGHGER is in essence a gap analysis,” he said. “What actions do we need to close the gap between the two lines and meet our goals? With all of those actions identified through the TIGHGER project, we can then, with the Global Warming Commission, create the plan to meet our greenhouse gas emission reduction goals.”

TIGHGER’s focus will be medium-term — a “Roadmap to 2035” on the journey to achieving the 2050 goals.

Maya Buchanan, ODOE senior climate policy analyst, explained that the TIGHGER process will entail six steps:

  • identifying new actions to reduce GHGs or sequester carbon;
  • analyzing estimated GHG reductions and the cost of each action;
  • developing economic sector-based marginal abatement cost (MAC) curves, which illustrate the cost-effectiveness and emissions reduction potential of each action;
  • determining co-benefits for each action — that is, whether an action provides other social or economic benefits beyond reductions;
  • scoring and ranking the actions according to an accepted evaluation standard; and
  • creating the “Roadmap to 2035.”

“We are developing a broad list of potential actions that can be modeled and determining the greenhouse gas potential of those actions and their cost-effectiveness over a period of time. And these actions span a diverse array of sectors,” Buchanan said.

TIGHGER will look across the entire economy, examining potential measures related to electricity generation, natural gas, transportation, industry, agriculture, natural lands, landfills, residential and commercial buildings, and land use. ODOE will consult with other state agencies and stakeholders in the effort and rely on input from the OGWC.

The 2035 timeframe of the project requires ODOE to factor in only commercially available technology in calculating the MAC curves used to assess the cost-effectiveness of potential actions.

“But the analysis supporting the roadmap is going to go beyond MAC curves to help address two really important facts,” Buchanan said. “One, that many of the actions are interdependent on each other and two, that many actions will likely be needed simultaneously to help achieve our greenhouse gas reduction goals. To address this, the project also includes an analysis of how actions can be bundled together to achieve the targets.”

‘Things We Can Control’

Chris Strashok, senior consultant with Sustainability Solutions Group (SSG), said the “integrated systems dynamics” model his company is developing for TIGHGER will be capable of representing the impact of those bundled interactions.

“We are capturing those intricacies and those dynamics within the system,” Strashok said. “Things like population obviously drive energy use, so if population grows [then] the more energy we use [and] that will influence the system in overall land use. So, if we remove forest land to build houses, that would obviously influence the sequestration potential that those forests have.”

SSG’s model will also strive to be as geographically granular as possible to assess the effectiveness of GHG-reduction activities based on the specific characteristics of localities.

“We’re not just looking at one just big number for the overall state, but radiating down to the county level because we understand that the state is very diverse. The west and east and north and south are quite different climates, populations and demographics. Understanding those differences is important to having a plan that addresses the different areas of the [state] in different ways,” Strashok said.

Zelenka clarified that potential TIGHGER actions will be limited to activities within Oregon’s boundaries — “the things we can control,” excluding industrial production occurring elsewhere.

OGWC Chair Catherine Macdonald said that the TIGHGER project is following an “aggressive” timeline “in the hopes that we can get enough progress made so that we would be able to make good recommendations on important next steps in the 2023 [legislative] session.”

“People think that 2023 is way off. It’s not,” Zelenka said.

CARB Explores Benefits, Hurdles to Decarbonizing Homes

Strategies to decarbonize buildings should include speeding up deployment of electric appliances to bring down equipment costs, said a participant in a California Air Resources Board workshop this week.

“At current costs, we just cannot spend our way to retrofitting the entire building stock,” said Pierre Delforge, a senior scientist in the building decarbonization program at the Natural Resources Defense Council. “We have to bring the costs down to make it possible.”

New construction should be one priority area for electric appliances, since new buildings typically need new appliances for space heating, water heating, cooking and clothes drying, Delforge said. Replacement of propane appliances is another opportunity, he said, as the “economic case is very strong” for switching to electric equipment.

Replacement of air conditioning should also be a focus, Delforge said. For “a couple hundred dollars more” than standard air conditioning, someone could install an electric heat pump that provides both space heating and cooling. The same reasoning applies when a resident who has gone without air conditioning decides they now need it due to climate change.

At the same time, the first steps toward accelerating building decarbonization should include low-income communities where residents spend a large share of their income on energy bills and rent, Delforge said.

Delforge’s comments came on Monday during a CARB workshop focused on building electrification. CARB held the workshop as part of the process for developing the 2022 scoping plan, a roadmap for meeting greenhouse gas reduction goals.

Multi-Billion-Dollar Cost

According to a California Energy Commission report this year, the cost to reduce GHG emissions from residential and commercial buildings to 40% below 1990 levels by 2030 ranges from $2.9 billion to $40 billion. Those figures are likely an underestimate, Nick Janusch, an environmental and behavioral economist in CEC’s Demand Analysis Office, said during the CARB workshop.

The building decarbonization assessment, which CEC released in August, was required by Assembly Bill 3232 of 2018.

The assessment outlined seven strategies that could help achieve the 2030 goal. They include building end-use electrification, electricity generation decarbonization, energy efficiency, refrigerant leakage reduction, distributed energy resources, decarbonizing the gas system and demand flexibility.

Regarding the first strategy, the report said, “substituting energy-efficient electric appliances for gas appliances and equipment in buildings can offer efficiency savings and GHG reductions, as well as air quality co-benefits.”

The benefits are especially evident with the use of efficient electric heat pump technologies, the report said.

During the CARB workshop, Janusch said residents’ preference for gas cooking is one of the barriers to transitioning to all-electric buildings. And a neighborhood can’t be decommissioned from the natural gas distribution network unless all the homes go completely electric, he said.

But Janusch said educating residents on the health impacts of gas cooking might help change their minds. Children living in a house with natural gas cooking have a 42% increased risk of having asthma at the time, and a 24% increased risk of having asthma over their lifetime, said a study cited by CARB during the workshop.

Janusch said residents need to plan for electrifying their homes, rather than reacting to an unplanned emergency when an appliance breaks down.

Josh Greene, vice president of Government and Industry Affairs for A.O. Smith, a manufacturer of residential and commercial water heaters and boilers, suggested an assessment of existing homes to gauge whether they’re ready to switch to electric, or whether they need improvements such as panel upgrades.

Gathering the data would allow “viable opportunities” to be targeted now, Greene said.

Homeowner Weighs In

In letters submitted to CARB, some members of the public cautioned against requiring electrification of existing homes.

Resident Michael Brady described his income as “lower middle,” which he said is just high enough to disqualify him from many retrofit incentive programs. He recently spent much of his savings on a new heating and cooling system for his home and the installation of solar panels.

Replacing his gas cooking stove with an induction range would be an expensive project, with a new electrical panel and wiring costing more than the range itself. Incentives might be available for the appliance, but not for the electrical work, he said.

“Please consider the implications on existing building owners when talking about forced retrofits,” Brady said.

NEPOOL Reliability Committee Briefs: Dec. 14, 2021

Bay State Wind Project Wins OK for Larger Turbines

The NEPO Reliability Committee on Tuesday approved the Bay State Wind project’s request to increase its capacity by 40 MW, reflecting a move to larger turbines.

The committee found no negative reliability impacts resulting from Bay State’s proposed array of 80 11-MW turbines south of Martha’s Vineyard, Mass. The project, a joint venture of Ørsted and Eversource Energy (NYSE:ES), is scheduled to reach commercial service in May 2026.

The committee also signed off on transmission applications for the project including:

  • installation of two 140-MVAr synchronous condensers connected via 345/24-kV transformers;
  • construction of a 345/275-kV onshore substation;
  • installation and interconnection of two 275-kV submarine, landfall and land cable circuits;
  • installation of two 275/66-kV off-shore substations;
  • installation and interconnection of two 345-kV buried land cable circuits interconnecting at the Brayton Point 345-kV and Bay State Wind 345/275-kV onshore substations.

Order 2222 Compliance, Procedure Changes Approved

The committee also approved:

  • changes to Planning Procedure 10 (Planning Procedure to Support the Forward Capacity Market), including conforming changes for ER21-640, related to qualification of non-commercial resources in annual reconfiguration auctions, and ER19-343, related to the modeling of peaking generation in reliability reviews;
  • tariff revisions regarding auditing and installed capacity requirements as part of ISO-NE’s compliance with FERC Order 2222, which allows aggregations of distributed energy resources to participate in the RTO’s markets; the compliance filing is due Feb. 2, 2022;
  • changes to Operating Procedure 16K (Transmission System Data – Submission of Short Circuit Data), part of a biennial review with minor updates to process flow diagram; and
  • changes to Operating Procedure 3 (Transmission Outage Scheduling), part of biennial review with minor edits and grammatical revisions.

Other Projects

The committee also determined no negative reliability impacts from the following projects:

  • installation of a 200MW/400-MWh battery storage project in Milford, Conn., which will interconnect to a new 345-kV breaker position at the East Devon substation (Able Grid Infrastructure Holdings, Eversource Energy and United Illuminating);
  • installation of a 20-MW solar PV facility in Leeds, Maine, interconnecting to the Leeds Substation (Central Maine Power on behalf of Walden Solar Maine);
  • installation of a 4-MW solar PV facility in Putnam, Conn., interconnecting to the Tracy 14M Substation (Eversource Energy on behalf of Glenvale Solar); and
  • a generation group study for a 35.4-MW distributed energy resources project in the Winslow/County Road area and a 29.8-MW DER project in the Lakewood area of Maine. The generation clusters represent 20 DER facilities that would interconnect into Central Maine Power’s sub-transmission and distribution systems.

The committee approved the following cost allocations for pool transmission facilities:

  • $64.7 million of transmission upgrade costs for work associated with 115-kV and 230-kV wood structure replacement projects in Massachusetts, Connecticut and New Hampshire (Eversource);
  • $186.3 million for 345-kV structure replacement projects in Massachusetts, Connecticut and New Hampshire (Eversource);
  • $23.9 million for replacement of wood structures on the 1261/1598 115-kV line (Eversource).

Stein Re-elected Vice Chair

The committee re-elected Robert Stein, a consultant who represents H.Q. Energy Services, as vice chair for 2022. There were no other candidates.

PJM Energy Transition Study Released

PJM kicked off what it said will be a multiyear initiative on the increasing integration of renewables Wednesday with the release of a study on the transformation of generation.

The paper, Energy Transition in PJM: Frameworks for Analysis, includes the RTO’s preliminary five-year strategy built on three pillars: facilitating state and federal decarbonization policies, planning for the grid of the future and fostering innovation for the transition.

PJM told the Markets and Reliability Committee the study is designed to help the RTO identify gaps and opportunities in the current market construct and provide insights into the future of market design, transmission planning and system operations.

“As the generation mix continues to rapidly evolve in PJM, we must be ready to maintain the reliable, cost-effective delivery of electricity at all times,” said CEO Manu Asthana. “This study represents an important step in understanding how PJM can best work to facilitate the energy transition and make the grid of the future possible.”

Study Overview

Emanuel Bernabeu, director of PJM’s Applied Innovation and Analytics department, presented a high-level overview of the study, saying PJM believes it can “play a major role” in facilitating the decarbonization transition through reliability and cost-efficiency measures.

PJM is also working on defining what the grid of the future will be and how it will be operated, Bernabeu said, and fostering innovation both internally at the RTO and within the stakeholder community.

“These are pretty heavy pillars, so it does require a strong foundation,” Bernabeu said.

The first phase of the study was not meant for PJM to propose solutions, Bernabeu said, but to inform stakeholders on broad issues and initiate a discussion to “put some light” on areas that need focus.

Bernabeu called the paper a “living study” because the assumptions that went into the work will continue to be refined as PJM continues to look for opportunities to improve market designs, operations and planning.

The study considers three scenarios in which an increasing amount of energy is served by renewable generation. The “base” scenario included 10% of the annual energy in the PJM footprint coming from renewable generation, while the “policy” and “accelerated” scenarios had renewables representing 22% and 50% of the annual energy, respectively.

In the accelerated scenario, up to 70% of the dispatch was considered carbon-free when combined with nuclear generation. The accelerated scenario includes 29 GW of offshore wind, 36 GW of onshore wind and 55 GW of solar.

As of 2020, renewables represented 6% of PJM’s annual energy, a total of more than 40% carbon-free including nuclear.

Bernabeu acknowledged that annual energy is “not the most intuitive metric.” In the accelerated scenario, he said, there are periods of time when PJM is serving 130% of the load with renewables — with any generation over the 100% mark exported to other regions.

PJM studied the resource adequacy of the three scenarios and simulated an entire year of the energy market with an hourly resolution to see how the renewable resources will operate.

Bernabeu said the study’s initial findings suggested five key focus areas for PJM’s stakeholder community, including correctly calculating the capacity contribution of generators. He said transmission systems with increased variable resources will require “new approaches” to assess the reliability value of each resource and the overall system.

The study determined the need for “operational flexibility” to address the uncertainty of variable resources, Bernabeu said, including lower capacity factors for thermal resources and average locational marginal pricing (LMP) decreases of as much as 26%.

The report says thermal generators provide “essential reliability services,” and an adequate supply will be needed until a substitute is “deployed at scale.” Bernabeu said PJM and stakeholders should ensure market structures provide the necessary incentives to maintain the generation for reliability.

He said expected increases in congestion, renewable curtailments and interchange with other regions “suggest opportunities for strategic regional transmission expansion.”

Reliability standards also must evolve, PJM said. The development of PJM’s markets, operations and transmission planning must be accompanied by the “advancement of comparable reliability requirements across interdependent infrastructure,” Bernabeu said. “Reliability cannot be achieved in a vacuum.”

Work on the study is expected to continue through 2022 with an updated report coming around the end of the first quarter of next year. “This study is not meant to be done and collect dust in your desk,” Bernabeu said.

Stakeholder Questions

Bernabeu was asked about the modeling done in neighboring RTOs and ISOs and the assumptions that were used. Wind projects in MISO were highlighted as an example of potential impacts on generation in PJM.

Bernabeu said the export and interchange numbers in the first version of the study were based on modeling neighboring regions maintaining the status quo with transmission and generation.

“The models tend to be extremely detailed inside PJM, and then the accuracy tends to degrade the further you move away from the footprint,” Bernabeu said.

Another stakeholder asked what PJM believes is an adequate supply of thermal generation.

Bernabeu said the first round of the study stopped short of making definitive quantitative assessments. He said there’s not a definitive quantity of supply for adequacy, so sensitivity analysis is going to continue to seek answers.

The most important aspect of the thermal focus area is how to incentivize behavior to maintain “essential reliability services,” he said.

“What is adequate? We haven’t found an answer yet,” Bernabeu said.

NERC RSTC Revisits Rejected Standards Projects

NERC’s Reliability and Security Technical Committee (RSTC) this week agreed to endorse several proposed reliability standard projects that were previously rejected by it and NERC’s Standards Committee.

The committee’s endorsement of two separate standard authorization requests (SARs) to modify TPL-001-5 (Transmission system planning performance requirements) and one to revise MOD-032-1 (Data for power system modeling and analysis) means the SARs will now go to the Standards Committee for approval. If the Standards Committee grants its assent, work can officially begin on a standards drafting project.

Teams Submit Competing TPL-001 SARs

One of the TPL-001-5 SARs was proposed by NERC’s Inverter-based Resources Performance Working Group (IRPWG), while the other came from the System Planning Impacts from Distributed Energy Resources (SPIDER) Working Group. The first would clarify “terminology throughout the standard that is unclear with regards to inverter-based resources;” the second would revise the standard to better address distributed energy resources (DER).

It is not unusual for the Standards Committee to receive multiple SARs relating to the same standard. In such situations the committee often combines them into one project.

A previous SAR to modify TPL-001-5, supported by both IRPWG and SPIDER, failed to garner enough votes for endorsement at the RSTC’s meeting in March. (See “DER Standard Request Denied,” NERC RSTC Briefs: March 2-3, 2021.) Brian Evans-Mongeon of Utility Services Inc. was one of several members to raise concerns about the proposal, including that the SAR did not specify its applicability to non-bulk electric system devices.

SPIDER and IRPWG could still have proceeded to the Standards Committee for approval but elected to go back to the drawing board on separate proposals, working with the RSTC in hopes of identifying potential problems ahead of submitting them for endorsement. At this week’s meeting, SPIDER Chair Kun Zhu of MISO detailed the changes the working group made to its SAR, including:

  • clarifying that transmission planners with minimal DER impact do not have to study DER contingencies under a threshold established by the standard development team (SDT);
  • removing a statement that system peak net load is the most stressful condition;
  • recognizing that DER modeling and study requirements are based only on data made available and are not dependent on any SARs to modify MOD-032-1; and
  • removing recommendations related to inverter-based resources.

By contrast, the IRPWG’s SAR incorporated only one change based on feedback from the RSTC, removing a bullet from the section on the project’s scope that committee members considered overly broad. Otherwise, the working group’s leadership elected to leave the SAR intact despite members expressing concern on topics such as the lack of a section on applicable facilities, and the desire to include provisions for amending MOD-032 to better identify applicable entities.

Both of the SARs related to TPL-001-5 received endorsement, though Evans-Mongeon moved to delay a vote on the IRPWG SAR until no later than Jan. 15, stating that the agenda packets sent out before the meeting did not include all of the members’ comments. He and others had not had time to review all of the comments and IRPWG’s responses prior to the meeting, he said. However, his motion failed with 10 votes in favor, 14 opposed, and two abstentions; subsequently the IRPWG’s SAR passed with 24 votes in favor and two opposed, while the SPIDER SAR passed with 25 votes in favor and one abstention.

SPIDER Hopes for Standards Committee Reassessment

The MOD-032-1 SAR also revisits a previously rejected standards proposal, albeit one that got farther along in the development process. In this case the Standards Committee voted last year to end Project 2020-01, SPIDER’s previous attempt to update the standard, on the grounds that the project’s SDT had not done enough to respond to concerns raised by industry during the informal comment period. (See “SAR Rejected over Industry Concerns,” NERC Standards Committee Briefs: Dec. 9, 2020.)

The committee’s grounds for rejecting the project led SPIDER members to vent their frustration and confusion at a subsequent meeting, with many arguing that the negative comments didn’t truly represent industry sentiment. Some RSTC members also expressed concern over whether the negative comments had been fully addressed. However, others — including NERC Chief Engineer Mark Lauby — agreed with SPIDER that if “enough people don’t come back and say that [they] like it, it looks as if everybody’s against it.”

To avoid more wasted effort, the RSTC voted to endorse the SAR and send it to the Standards Committee along with several “technical justification documents,” including a letter from RSTC and SPIDER leadership explaining the decision to resubmit the project and the changes incorporated into the new proposal.

NYC to Ban Natural Gas in New Buildings Beginning 2024

The New York City Council voted Wednesday to ban the use of natural gas for heating or hot water in new construction or renovations beginning in 2024.

The statute prohibits the combustion of a substance that emits 25 kilograms or more of carbon dioxide per million British thermal units of energy, starting with buildings under seven stories permitted before Jan. 1, 2024, and in buildings seven stories and higher permitted on or after July 1, 2027. Mayor Bill de Blasio (D) negotiated changes to the bill this week and is expected to sign it.

“Buildings are responsible for nearly half of the greenhouse gas emissions that are destroying our Earth every day,” said the bill’s primary sponsor, Councilmember Alicka Ampry-Samuel (D).

Alicka Ampry (NYC Council) Content.jpgGas ban bill sponsor Alicka Ampry-Samuel (D. 41, Brooklyn) speaks to the Council on December 15, 2021. | NYC Council

The bill addresses both climate and racial justice and essentially codifies the city’s emission reduction goals, Ampry-Samuel said.

The law directs the commissioner of buildings to deny construction permits for buildings that would require the combustion of such emitting substances, with exceptions for emergency standby power, a hardship preventing compliance with the bill, and where the combustion of the substance is used on an intermittent basis in connection with a device that is not connected to the building’s gas supply line.

This statute also requires the Mayor’s Office of Long-Term Planning and Sustainability to conduct studies regarding the use of heat pump technology, and on the ban’s impact on the city’s electrical grid.

“This bill alone will yield a savings of 2.1 million tons of CO2 by 2040, which is equal to the carbon produced from 450,000 cars in a whole year,” said co-sponsor James F. Gennaro (D), chair of the council’s Environmental Protection Committee, which oversaw the legislation.

National Grid, which distributes gas in the city, opposed the ban, saying it could increase energy costs, with a disproportionate impact on low- and fixed-income families.

“National Grid shares New York’s goal for economy-wide decarbonization,” National Grid spokeswoman Karen Young told NetZero Insider. “We recently announced the progress we’re making with our own decarbonization plan to transform our networks to deliver smarter, cleaner and more resilient affordable energy solutions.”

State lawmakers have written a broader bill, the “all-electric building act,” currently in committee, that would require new buildings statewide to be all-electric beginning in 2024.

US Cities’ Progress on Clean Energy Rebounds in 2021

The American Council for an Energy-Efficient Economy (ACEEE) on Wednesday released its sixth City Clean Energy Scorecard, with San Francisco for the first time claiming the top spot, followed by Seattle, Washington, D.C., Minneapolis, and Boston and New York tied for fifth place.

Covering municipal clean energy policies from May 2, 2020 to July 1, 2021, the scorecard ranks 100 U.S. cities across 39 states, the District of Columbia and Puerto Rico. Based on a 100-point scale, ACEEE rates the cities on five key areas of clean energy policy and performance: community-wide initiatives (such as clean energy or emission reduction targets), building policies, transportation policies, efficiency and emission reduction programs of local energy and water utilities and of municipal operations.

New City Clean Energy Action Breakdown (ACEEE) Content.jpgThe COVID-19 pandemic led many cities to delay or modify planned 2020 work, but cities increased their clean energy efforts in late 2020 and early 2021. | ACEEE

Top-scoring San Francisco received 74 points (up 1.5 points from 2020), while at the bottom of the list, Baton Rouge had a total of only 3.5 points (down 2.5 points from 2020). However, ACEEE reported that it had revised some of its scoring criteria to reflect current energy policies and give added weight to equity policies and performance. As a result, 65 cities scored lower than in 2020, the report says.

The report underlines the significant impact city policies and programs can have on climate change. Citing figures from the International Energy Agency, the report says, “Cities around the globe are responsible for nearly three-quarters of the world’s energy consumption and more than 70% of energy-related carbon dioxide emissions.”

The COVID-19 pandemic put a damper on clean energy programs in many cities through 2020, caused by funding, staffing and operational challenges, the report said. However, the first half of 2021 saw renewed momentum on clean energy, with a particular focus on the buildings sector.

GHG Emission Reductions (ACEEE) Content.jpgWhile many cities have set targets for reducing GHG emissions from transportation, only eight are tracking data on emission reductions and of those, only three — Kansas City, San Diego and Providence — are meeting their goals. | ACEEE

“A lot of the activities were the creation of new incentive programs to encourage retrofits of homes and businesses,” said Stefen Samarripas, local policy manager for ACEEE, speaking at a Wednesday webinar launching the report. “There’s a lot of room to make further improvements in building energy efficiency by creating requirements that property owners make improvements to those properties.”

Data collection is another area for improvement, Samarripas said. Many cities “are not tracking consistently the data that would be needed to figure out if they’re on track to achieve [emission reduction goals],” he said, which is “particularly notable when it comes to transportation-specific goals.”

Only about one-quarter of the cities on the list have set emission-reduction goals for transportation, Samarripas said. Of those, only eight are tracking their data, and of those eight, only three — Kansas City, San Diego and Providence — are hitting their targets, he said.

The Total Buy-in Equation

The webinar also featured energy managers from three cities — San Francisco, Madison and Washington, D.C.

Debbie Raphael, director of San Francisco’s Department of the Environment, said her city has reduced its greenhouse gas emissions 41% since 1990, while its population has grown 22% and GDP 200%. The secret behind those numbers, she said is a “total buy-in equation.”

“It starts with the leadership of our mayor, our elected officials,” Raphael said. “We have business and educational institutions that are bought in — our community organizers, our residents and our voters. … So, this package of buy-in, this package of willingness to take risks and take bold action to prevent harm is what leads to those kinds of numbers.”

Raphael also noted that San Francisco had also recently released an updated climate action plan that is science-based, includes metrics and accountability, and is “centered on people, not just carbon,” she said. “It looks at the power unique within cities and that is land use, the power of land use to affect our greenhouse gas emission reductions. Our mayor [London Breed] loves to say, ‘Housing policy is climate policy.’”

Her advice to other cities is to approach climate and clean energy policy with “radical curiosity.”

“We’re going to have to challenge our assumptions about people’s behavior, about what people need, about what services are possible, what incentives are necessary,” Raphael said. “We really need to ask, with an open mind, what are the programs that will move the needle?”

The First Electric Fire Engine

Wisconsin’s capital is one of the most improved cities in ACEEE’s 2021 rankings, going from No. 64 in 2020 to No. 39 this year. At least part of that leap can be traced to the city’s progress toward running municipal operations 100% on clean energy by 2030. Madison is almost at 75%, said Jessica Price, the city’s sustainability and resilience manager, and “reaching this goal has really required us to take an innovative and multifaceted approach,” she said.

Madison has installed 1.3 MW of behind-the-meter solar at its city facilities, Price said, and the majority of those installations were completed through the city’s GreenPower workforce training program that prepares young people for jobs in renewable energy.

On the transportation side, she said, the city now has 60 electric vehicles and 100 hybrid EVs, and in June, it unveiled the nation’s first electric fire engine. Madison this year passed an ordinance requiring EV charging infrastructure in parking facilities.

Price also emphasized the need for regional collaboration, especially for mid-sized cities such as Madison. “Partnering with our local government neighbors can be a really powerful strategy for scaling up our work, creating regional change, sharing success stories, sharing failures and leveraging our resources,” she said. “Oftentimes we’re operating with limited budgets, limited resources, and the ability to collaborate with folks on shared priorities can be a great way to move things forward.”

Operationalizing Equity

Maribeth DeLorenzo, sustainability director for the nation’s capital, said ACEEE’s increased focus on equity reflected work now underway in her city. “Both at the mayoral level and on the council level, we have new offices of racial equity,” she said. “We’ve been working on racial equity impact assessments that are city-wide, so really moving from understanding how important racial equity is … to how do we operationalize that and what does it look like for us in D.C.”

One way, DeLorenzo said, is the city’s focus on affordable housing and the development of an affordable housing retrofit accelerator. The program helps affordable housing owners understand the city’s building energy performance standards and how to leverage opportunities for building efficiency, according to D.C.’s Sustainable Energy Utility.

D.C. also faces a complicated challenge in cutting its transportation emissions, a significant part of which are caused by commuters driving into the city from the Maryland and Virginia suburbs. To get people out of their cars, DeLorenzo said the city had rolled out three new car-free lanes for buses and bikes along key commuter routes, while also working on electrifying its own municipal fleet.

Echoing Raphael, she also emphasized the importance of buy-in. “In some places, it means focusing on adaptation. In some places, it means lining up partners who may have disparate interests with the same aim at the end,” she said. “And then in other places, it really means taking a hard look at our climate action through the lens of who has the ability to [have an] impact.

Room for Improvement

Funding in the bipartisan infrastructure bill — and in the Build Back Better Act, now stalled in the Senate — has cities excited and looking at how they will plug into the federal dollars.

One challenge, Raphael said, is that the money will come through the state in the form of grants or other funding opportunities before it gets to the cities. “How do we help cities communicate up to the state [and] states to the feds so that we at the implementation side, whether it’s affordable housing or transportation, get the money we need in the right ways that we need it so that we serve our communities?” she said.

The report also has recommendations for program development — with or without federal funds — stating that even the scorecard’s top-ranking cites have room for improvement. Key suggestions include:

  • A range of social equity policies, such as creating a formal clean energy decision-making body of historically marginalized community residents and helping minority-owned and women-owned businesses to secure local government clean energy contracts.
  • Mandatory policies designed to improve the energy performance of existing buildings, such as energy benchmarking and performance standards and policies to promote energy efficiency retrofits.
  • Higher targets for community-wide and transportation-specific clean energy goals. As noted, setting transportation goals and metrics are a major lapse in local clean energy policies.

“We know the actions that need to happen, on the building sector, on the transportation sector, on the social and environmental justice sector,” Raphael said. “It’s really a question of political will. And that political will gets built from a foundation of government power and expertise and support by our private sector and by our residents. That’s what we need. We need us all to lean in.”