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November 2, 2024

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FERC Accepts PJM Black Start Tariff Revisions

FERC on Thursday accepted PJM tariff changes covering non-rate provisions for black start service, including commitment and termination periods, as well as outage and substitution restrictions (ER21-1635-002).

The letter order directed a further compliance filing within 30 days to make agreed-upon revisions to an initial compliance filing that set forth details concerning the formulaic capital recovery factor (CRF) that the commission found essential to the rates, terms and conditions of black start service.

PJM Market Monitor Joe Bowring in April said the CRF table was originally created in 2007 and included incorrect assumptions. Black start unit owners and other stakeholders asserted that any changes to the CRF table should only be applied prospectively, and any rates currently in place should remain changed. (See PJM to File Black Start Proposal Without Members’ Endorsement.)

In October, PJM filed reply comments agreeing with the Market Monitor, explaining that the CRF formula used prior to June 6, assumed a 100-MW combustion turbine plant with a $1,000,000 capital investment. The RTO agreed that the formula no longer uses those assumptions and asked to remove the references to the assumed type of unit.

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FERC Questions Ratepayer Funding of Trade Association Dues

FERC opened a Notice of Inquiry on Thursday over the recovery of trade association dues in utility rates, with commissioners questioning whether customers should pay for groups that seek policies that may be contrary to consumers’ interests.

The NOI asks what portions of utilities’ dues paid to industry, civic and political associations are suitable for rate recovery (RM22-5).

The inquiry is a response to a petition filed by the Center for Biological Diversity, a conservation nonprofit that argued that association dues should be presumed to be non-recoverable through rates. Utilities should shoulder the burden of proving that such expenses should be recoverable, the group said. The group also sued the Tennessee Valley Authority over the issue in September. (See TVA Sued Over Contributions to Trade Groups.)

Under current FERC accounting rules, regulated utilities are allowed to recoup association dues, subtracting disclosed spending on IRS-defined lobbying activities.

FERC Chairman Richard Glick said the NOI will help FERC decide whether to modify its accounting and recording requirements.

“It appears that trade associations might not provide the utility company members with a sufficient level of detail as to which portion of a trade association’s dues should be recoverable and which should not, making it difficult for the commission to assess whether utilities are being excessively compensated by ratepayers or not,” Glick said at FERC’s open meeting.

Commissioner Allison Clements said the inquiry “in no way impinges on regulated utilities’ ability to advocate for any issue of interest.

“Regulated entities have every right to engage in outreach to influence public opinion on political issues; however, they do not have the right to pass through the cost of their outreach to the customer,” she said.

“At the minimum, it is a good housekeeping exercise to ensure that customers are not inappropriately left footing the bill for their electricity provider’s political aims, simply because they were taken on a by trade association instead of a regulated entity itself.”

Commissioner Mark Christie agreed that the NOI “is not a constitutional threat.”

“I don’t see it as threatening any corporations or trade associations’ speech rights,” he said. “The question here is not about the First Amendment; it’s about who pays for the expenses associated with speech.”

Christie pointed out that while state-regulated monopolies “may invest voluntarily,” their captive customers cannot buy voluntarily.

Christie said that FERC uses formula rates, a “very different system than in states where a utility comes in and has … the burden of proving that any expenditure is prudent.”

He added that he hadn’t prejudged any answer to whether FERC’s formula rate format is transparent enough. “It may be that the rules are fine. And maybe no changes are needed. But I don’t see a problem at all with putting this out for comment.”

Christie added that FERC should probably also consider whether its precedents on charitable and civic contributions should be codified. “I do not think that charitable and civic contributions by a state-granted monopoly should be recoverable from customers, period. That should not be allowed at all,” he said.

FERC Commissioner James Danly said he was dissenting on the NOI and would issue a later statement. He did not explain his opposition during the open meeting.

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California PUC Levies $550M on Edison for Wildfires

The California Public Utilities Commission on Thursday took steps to address two of the state’s major grid problems, resource adequacy and wildfires, by approving Southern California Edison’s request for a $1.2 billion storage project and slapping the utility with a half-billion dollars in penalties for blazes sparked by its equipment.

The decisions, reached in quick succession, came during the CPUC’s final meeting of 2021 and the last meeting for retiring President Marybel Batjer and Commissioner Martha Guzman Aceves, who is leaving for a top post at EPA.

The storage project, meant to improve summer reliability, would connect 535.7 MW of batteries at three SCE substations at an estimated cost of $1.226 billon. SCE said it will operate the storage resources as local distribution assets, not connected to CAISO, for five years. It will then transition the projects to “resources that participate in the wholesale market … [and] proceed through the interconnection process like any other customer.”

More than a dozen entities — including the CPUC’s Public Advocates Office, the Solar Energy Industries Association and the California Energy Storage Alliance — protested, challenging the cost of the project, its intended use and SCE’s interconnection plans.

The CPUC said it was not swayed by the objections and believed the project qualified under its prior procurement orders and Gov. Gavin Newsom’s emergency proclamation in July requiring the connection of additional resources to meet projected shortfalls by next summer. The five commissioners voted unanimously to approve it.

“We are facing a large gap in the amount of resources we have to ensure the reliability of our current grid in the face of the more extreme, climate-driven weather events that we saw earlier this summer and [that] we witnessed last summer,” Batjer said, referring to the derating in July of transmission lines linking the Pacific Northwest to California  caused by a massive wildfire and the rolling blackouts of August 2020 in a severe Western heat wave.

“In this case, Edison has been able to leverage its unique position as an IOU and distribution operator to move forward with a shovel-ready project that can respond to our emergency procurement needs,” she said.

The project is expected to come online by Aug. 1, 2022, in time to meet summer reliability needs.

Wildfire Penalties

The CPUC next voted 4-1 to approve a settlement with SCE over the major fires of 2017/18 ignited by its equipment. The Thomas, Woolsey, Liberty, Meyers and Rye fires collectively killed at least five people, destroyed more than 2,700 structures and burned more than 385,000 acres.

Of the five blazes, the Thomas and Woolsey fires were by far the largest and most destructive.

The Thomas fire, which began in December 2017, was the biggest wildfire in state history at the time at 282,000 acres. It was surpassed by much larger fires, including two of approximately 1 million acres, in recent years.

The fire in Santa Barbara and Ventura counties killed two people and destroyed more than 1,000 homes. Subsequent flooding and debris flows in the burn-scar area later killed 21 residents and destroyed more than 100 homes. Without admitting liability, SCE settled with insurers for nearly $1.2 billion last year.

The Woolsey fire started in November 2018, killed three people, destroyed more than 1,600 homes and led to the evacuation of almost 300,000 residents in Los Angeles and Ventura counties.

The CPUC used its new, controversial procedure called an administrative consent order (ACO) to settle with SCE. The expedited process reduces the time it takes the commission to hold utilities accountable for safety violations in an era of regular, catastrophic wildfires. Other enforcement proceedings, such as the commission’s order instituting investigation, can take years to complete.

It was the second time the CPUC has used an ACO to settle with a utility blamed for starting wildfires. Earlier this month it approved a $125 million settlement with Pacific Gas and Electric over the 2019 Kincade Fire in Northern California’s wine country.

Commissioners voted 3-2 to approve the agreement between PG&E and the CPUC’s Safety and Enforcement Division that levied $40 million in fines and denied the utility $85 million in cost recovery for removing abandoned transmission lines. (See CPUC Assesses PG&E $125M for Kincade Fire.)

They voted 4-1 to approve Thursday’s settlement with SCE. Commissioner Genevieve Shiroma, who voted “no” previously, said she was satisfied the process had led to a better result with SCE than with PG&E. Commissioner Darcie Houck, who also voted against the PG&E settlement said she believed the ACO process lacked transparency and the opportunity for public participation, especially involving fires of such magnitude.

“I agree that this can be a flexible and useful tool that allows us to resolve things in a streamlined and efficient way where we are dealing with only penalties and not the extreme catastrophic events at issue here,” Houck said.

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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.”

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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.

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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.

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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.

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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.

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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.

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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.