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November 5, 2024

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EJ Comm. Wants CARB GHG Plan to Cover Pesticides

Environmental groups have been urging the California Air Resources Board to include pesticide reduction strategies in its 2022 climate change scoping plan, and they now have the backing of CARB’s Environmental Justice Advisory Committee (EJAC).

The advisory committee voted on Nov. 9 to support a letter regarding pesticide use from Californians for Pesticide Reform and seven other groups.

As many as 59 organizations have signed onto letters to CARB or the governor this year asking that pesticide use be addressed in the 2022 scoping plan. The plan, which is updated every five years, is a roadmap for achieving the state’s greenhouse gas reduction goals.

And the groups made similar requests regarding pesticides during development of the 2017 scoping plan.

“Many of us have been calling for inclusion of pesticide reduction strategies in the state’s scoping plan since 2017, only to be told by CARB that there is insufficient research and/or that pesticides contribute only a negligible amount to GHG emissions when compared with other sources,” the groups said in their letter to EJAC.

The groups agreed that more research is needed on the subject of pesticides and greenhouse gases, and called for the state to fund studies on the topic.

But enough is known now to add pesticide reduction strategies to the scoping plan, they said. The groups have also asked CARB to add the Department of Pesticide Regulation to the list of 17 departments or agencies serving as collaborators on the scoping plan.

Pesticides’ Role Debated

EJAC was scheduled to hear an update from CARB staff on Nov. 16 regarding pesticides and the scoping plan, but the item was postponed. A CARB spokesperson did not respond to a request for comment on the letter the committee voted to support.

But CARB staff discussed pesticides during a July 20 scoping plan workshop focused on natural and working lands.

During the workshop, EJAC member Martha Dina Arguello asked how the impact of pesticides on greenhouse gas emissions would be addressed.

“I’m strongly concerned about excluding pesticides from the whole framing around the natural and working lands,” said Arguello, who is executive director of Physicians for Social Responsibility – Los Angeles.

Nicole Dolney, manager of CARB’s Emission Inventory and Economic Analysis Branch, said the agency is aware of two pesticides — methyl bromide and sulfuryl fluoride — that are greenhouse gases.

She said the use of methyl bromide is being phased out under the Montreal Protocol and emissions from the pesticide are “very small.” Sulfuryl fluoride is being tracked as part of the short-lived climate pollutants inventory, she added.

At least one study has found that use of sulfuryl fluoride is increasing as the pesticide replaces methyl bromide. The researchers, who describe sulfuryl fluoride as a potent greenhouse gas, found that the increase was mainly because of fumigation of buildings in North America. But postharvest treatment of crops also contributed, they said.

Matthew Botill, assistant chief of CARB’s Industrial Strategies Division, acknowledged the number of comments received on pesticides during the scoping plan process. Botill said pesticides weren’t directly included in modeling work discussed during the workshop.

“We are interested in looking at what those potential effects of pesticides are on greenhouse gas emissions,” Botill said.

GHG Contributions

In their letter to EJAC, the environmental groups outlined ways in which pesticides may contribute to greenhouse gas emissions.

The groups pointed to volatile organic compounds contained in pesticides, which react with sunlight and nitrogen oxides to form tropospheric ozone. Tropospheric, or ground-level ozone, is a greenhouse gas that is also harmful to health, according to the University Corporation for Atmospheric Research.

Soil fumigants, which account for about 20% of pesticides used in California, can increase nitrous oxide emissions, the groups said in their letter. In 2019, nitrous oxide accounted for about 7% of the nation’s greenhouse gas emissions from human activities, including agriculture, according to the U.S. Environmental Protection Agency.

In California, demographic data show “a pronounced racial disparity” in the amount of pesticide use in counties with the largest share of Latino residents, the letter said, with the greatest impact on the San Joaquin Valley.

In addition, the groups argue that organic farming naturally sequesters carbon and other GHGs to a greater extent than farming that uses chemicals.

“It is critical that the scoping plan include measures supporting rapid transition of chemical-reliant farming to organic farming that focuses on building soil and plant health,” the groups said.

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MISO Modifies Stakeholder Meeting Schedule

MISO has scrapped its plan for a meeting schedule that would have packed all major stakeholder meetings into a single week eight times per year.

Instead, the grid operator will stagger eight meetings of its main stakeholder committees across the year, alternating between in-person and virtual formats. The modified schedule still will have MISO holding fewer stakeholder meetings throughout the year.

The RTO said in September that it planned to squeeze all stakeholder meetings of its main parent entities into eight separate weeks over the year, creating “superweeks” consisting of all-day meetings. The new calendar was to take effect next year. (See MISO Wants Abridged Stakeholder Meeting Schedule.)

MISO defines its main parent entities as the Market Subcommittee (MSC), Resource Adequacy Subcommittee (RASC), Reliability Subcommittee, Planning Advisory Committee, and Regional Expansion Criteria and Benefits Working Group, which makes cost-allocation decisions. The committees currently meet monthly in separate weeks dubbed as planning week, markets week and reliability week.

The grid operator’s head of stakeholder relations, Bob Kuzman, said the new schedule will allow MISO to preserve its markets week and planning week.

“We heard your feedback, and we made a lot of changes to the proposal,” he told stakeholders during Wednesday’s RASC teleconference. “We heard that superweeks were going to provide too much information for stakeholders to digest.”

In response, the RASC and MSC only approved the first five months of their 2022 meeting dates. The committees usually set a full calendar year of meetings during their December meetings.

RASC Chair Chris Plante said committee chairs will still have to make sure their workplans and goals will be able to fit into the new calendar.

Speaking on behalf of his company, WEC Energy Group, Plante said he was willing to give the new meeting frequency a try.

MISO client relations staff had framed the new meeting schedule as a transition to in-person meetings after two years of pandemic-induced isolation.

Kuzman said MISO will review the schedule with stakeholders in May to gauge its effectiveness. “This allows the face-to-face meetings as we get back to an in-person schedule.”

He also said the new schedule will give staff subject matter experts respite between meetings to ready discussion points and meaningfully tweak proposals based on stakeholders’ suggestions.

“MISO can get a little bit better prepared for the meetings, with better material and better answers to stakeholders’ questions,” Kuzman said.

The RTO had said the meetings’ monthly pace was leaving staff in a cycle of preparing and delivering presentations, sometimes reciting information from identical slides across different committees.

The grid operator’s first vision for pared-down in-person meetings proved unpopular with stakeholders.

In November, Plante said MISO should have consulted with stakeholder committee chairs to determine whether the groups could cover 12 months of agenda items across just eight meetings a year.

Plante also said there was probably a better way of limiting COVID-19 exposure between stakeholders and MISO staff. MISO said fewer in-person meetings might lessen the chances that someone contracts the coronavirus.

“I would have much rather seen us maintain the monthly meetings with an in-person meeting every other month,” Plante said during a Nov. 4 MSC meeting.

“We were not approached about whether this would have been a good thing,” MSC Chair Megan Wisersky said. “I’m concerned there wasn’t enough stakeholder discussion outside of the Advisory Committee.”

Wisersky also questioned whether the schedule should be provisional, adding that, “sometimes when MISO suggests something is temporary, it often becomes permanent.”

Multiple stakeholders have also said change will relieve the pressure on staff to appear monthly and present market changes.

Wisersky, speaking as a representative of Madison Gas and Electric and not as a subcommittee chair, said she hoped MISO wasn’t using the COVID-19 pandemic as a “guise” to disrupt the stakeholder process.

“It’s not practical for us to block off an entire week for MISO meetings,” WPPI Energy economist Valy Goepfrich said.

Kuzman has asked stakeholders to be patient while the RTO navigates a return to in-person meetings.

“We’ve all been separate.” Kuzman said. “We miss the coffee talk; we miss the lunch talk.”

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MISO Market Subcommittee Briefs: Dec. 1, 2021

Stakeholders Surprised at Integrated Roadmap Changes

MISO plans to revise its Integrated Roadmap process, the ongoing five-year workplan that prioritizes and tracks progress on market improvements.

The grid operator is doing away with a stakeholder ranking of improvements. Additionally, it will now accept suggestions for improvements on RTO operations year-round instead of imposing an annual deadline. MISO usually closes a submission window late in the year and begins prioritizing issues early the following year.

Stakeholders attending Wednesday’s Market Subcommittee meeting said they weren’t notified that MISO would change the process so dramatically. They said staff should have approached them during earlier subcommittee meetings to discuss the change before their announcement.

MISO’s head of stakeholder relations, Bob Kuzman, said executives will deliver a more in-depth briefing on the changes during next week’s Board Week.

Low Numbers for New Member Interface

MISO customers are slowly migrating to the new market user interface. Only 24 of 294 customers have fully migrated to the new system, with another 86 in the process.

“We are making very slow progress towards the migration,” said Arijit Bhowmik, MISO director of real-time applications.

The RTO’s revamp of is market interface ― where participants submit bids and offers ― is part of its market platform replacement.

MISO will retire its legacy system on Jan. 18. It began a four-month parallel operations phase on Sept. 8.

MISO’s short-term reserve product, which is set to go live on Tuesday, relies on the new market user interface. Short-term reserves are meant to supply energy within 30 minutes.

MISO: Member Privacy Trumps Zonal Data Sharing

In responding to stakeholders’ requests for access to seven-day load forecasts in their local balancing authority or resource zones, staff said they could publish weekly load forecasting data, but only on a subregional basis.

MISO’s Congcong Wang said the RTO has a few local BAs that rely on just one or two suppliers. Divulging load data for those areas would display confidential information, she said.

Wang said staff can share its load data broken down to MISO South and the North and Central portions of MISO Midwest.

Some customers have asked for access to seven-day load forecasting data at the local BA or local resource-zone levels. (See “Tx Customers Ask for Additional Load-forecasting Data,” MISO Market Subcommittee Briefs: Oct. 7, 2021.)

Most RTOs make load forecasting data for the coming week available to their members, though the level of detail varies.

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FERC Accepts CAISO Hybrid Rules

FERC on Tuesday approved the second round of CAISO’s tariff changes for co-located and hybrid resources, the result of a two-year stakeholder initiative meant to accelerate the pairing of renewable generation with storage to ensure California has adequate resources during its clean energy transition. (ER21-2853).

The changes include a contested provision exempting hybrid resources from CAISO’s resource adequacy availability incentive mechanism (RAAIM), which CAISO said would reduce the risk of double penalizing the resources by assessing their performance based on historical output.

FERC agreed with the change, saying it had approved CAISO’s RAAIM exemption in October 2015 for variable energy resources under the same rationale.

“The use of a qualifying capacity methodology that discounts qualifying capacity by taking into account historical performance could lead to effectively penalizing a variable energy resource for a second time under the RAAIM framework,” FERC said. “We find that CAISO has adequately explained why hybrid resources, if subject to RAAIM, would face a similar risk of a double penalty here, and therefore that an exemption is also warranted for them.”

Middle River Power, a private equity firm that manages six natural gas plants and other generating assets in California, argued it was unreasonable to exempt hybrid resources from RAAIM. Hybrids combining solar or wind and battery storage represent “a significant portion of future resources that will be providing resource adequacy capacity to the CAISO” and should be subject to the same market rules as other RA resources, it said.

“Middle River argues that CAISO’s characterization that resource adequacy values for variable energy resources are determined by their historical performance is inapt,” FERC said. “Middle River explains that ELCC [effective load carrying capability] studies apply aggregate variable energy resource generation profiles, based on historical output (determined by historical weather), to a forecast of weather in future years. Middle River states that asserting that a variable energy resource’s qualifying capacity value is affected by its historical performance overstates the role an individual resource’s performance plays in setting its ELCC-based qualifying capacity value.”

FERC said it was unpersuaded by Middle River’s argument “that the Commission should re-examine the premise underlying the proposed exemption for hybrid resources given that variable energy resources’ qualifying capacity values are no longer based on the historical performance of an individual resource.”

‘Bleeding to Death’

Commissioner James Danly concurred with Chair Richard Glick and commissioners Allison Clements and Mark Christie in the decision.

“I agree that [CAISO] proposed a just and reasonable method by which hybrid and co-located resources can participate in the markets [it] administers,” Danly said. “Enhanced participation of these resources is critical because CAISO faces serious reliability and resource adequacy problems.”

The ISO has encountered strained grid conditions during the last two summers, including the rolling blackouts of August 2020, and expects another difficult summer in 2022. Extreme weather, wildfires and the switch from fossil fuels to clean energy without sufficient storage have been partly to blame.

Danly said he wondered whether exempting hybrid resources from RAAIM made sense in such circumstances.

“RAAIM is designed to improve resource performance, so exempting another entire class of resources from it appears to be problematic on its face, especially in a region suffering an ongoing reliability crisis,” he wrote. “But our Federal Power Act standard of review is whether a proposal is just and reasonable, not whether there is a better idea.”

He said he was persuaded that there was a risk of double penalties under RAAIM for hybrid resources if historical outage data was included in the capacity-factor calculation.

“So, while I agree with approving this proposal, I remain concerned that CAISO continues to use Band-Aids to address its ongoing reliability challenges rather than the emergency surgery that is actually required,” Danly said. “Each Band-Aid may mark a modest incremental improvement, but the patient is still bleeding to death.

“Today’s order is a perfect example,” he said. “CAISO almost certainly can find ways to incorporate hybrids and variable resources into its markets without RAAIM exemptions or other potentially discriminatory measures.”

Reporting Requirements

Danly said he supported FERC’s decision to require CAISO to provide an update next year on whether the RAIMM exemption is discriminatory.

Additional tariff changes accepted Tuesday included CAISO’s requirement that hybrid and co-located resources provide additional data on weather and state-of-charge, as well as a requirement that each hybrid resource and co-located intermittent resource provide its “high sustainable limit” via telemetry every 12 seconds.

“CAISO explains that this parameter is a real-time estimate of the instantaneous maximum output capability of a variable energy resource or the variable component of a hybrid resource, based on the resource’s physical properties and weather conditions,” FERC said.

FERC approved CAISO’s first set of tariff changes dealing primarily with co-located resources in November 2020. (See FERC Accepts CAISO Co-located Resources Plan.)

CAISO intends to begin a stakeholder initiative on the evolution of hybrid resources starting next year.

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Two More Directors Appointed to ERCOT Board

The Texas Public Utility Commission on Wednesday announced Bob Flexon and John Swainson as the two latest additions to ERCOT’s Board of Directors, leaving the body just two members short.

Flexon was Dynegy’s CEO before its 2018 merger with Vistra and was previously CFO for UGI Utilities and NRG Energy. (See Vistra-Dynegy Merger Closes After FERC Nod.) He currently chairs Pacific Gas and Electric’s board of directors and sits on several other governance groups. He gives the board just its second independent director with a background in the electric industry, alongside previous appointee Zin Smati.

John-Swainson-(Travelport)-Content.jpgJohn Swainson | Travelport

Swainson is executive chairman of Travelport, a business-to-business marketplace for travel information, and an executive partner at Siris Capital, a technology-focused private equity firm. He was president of the Dell Software Group until its sale in 2016.

Flexon and Swainson were chosen by the ERCOT Board Selection Committee, a three-person group appointed by Texas’ political leadership. The committee has been working with a search firm to fill the board’s eight independent director slots, as directed by legislation passed earlier this year.

Senate Bill 2 replaced the previous board’s five unaffiliated directors and eight market segment representatives with eight independent directors chosen by the selection committee. The ERCOT CEO, the PUC chair and the Texas Office of Public Utility Counsel’s CEO sit on the body as non-voting members.

One of the first five appointees, Elaine Mendoza, abruptly resigned Nov. 19 over an apparent conflict of interest. (See Twitter Blows up over ERCOT Communications.)

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Texas PUC Pushes 44% Reduction in ERCOT Offer Cap

Texas regulators are expected to consider an order Thursday that will lower
ERCOT’s high systemwide offer cap (HCAP) to $5,000/MWh from $9,000/MWh, a 44% reduction (52631).

The Public Utility Commission’s four members reached consensus during an open meeting Tuesday on $5,000 as the operating reserve demand curve’s (ORDC) top-line number. The ORDC is designed to accurately reflect shortage conditions by increasing power prices through an adder when operating reserves dip below 2 GW. It’s also seen as a price signal to investors that additional generation is needed in the market.

Commissioner Will McAdams offered up $5,000/MWh as an “appropriate level,” saying the ORDC should be designed to stabilize the existing fleet and ensure the real-time market operates effectively.

The ORDC “provides revenues with the right price incentives to behaving as they should … so they are online when the likelihood of scarcity is growing,” he said. “We should use it to stabilize current market conditions.”

Commissioner Lori Cobos agreed, saying the ORDC will help stabilize the existing generation but also “hopefully drive incremental generation.”

“I don’t want to minimize the importance of changes to the ORDC,” she said. “These have been highly contested, debated issues in the past. It is by no means low-hanging fruit.”

McAdams is also proposing to raise the ORDC’s minimum contingency level from 2 GW to 3 GW, saying it will give ERCOT “breathing room” before hitting emergency conditions.

“All of these changes we are considering are expensive, but expensive is relative to the problems,” Commissioner Jimmy Glotfelty said. “It’s warranted based on what all Texans have experienced. It’s the right policy to move forward.”

The HCAP was lowered to the low systemwide offer cap of $2,000/MWh after February’s winter storm, when it exceeded a threshold for too many hours at the limit as the ERCOT system struggled to meet soaring demand. By rule, the HCAP is set to revert to $9,000/MWh on Jan. 1.

“The overall objective is to reduce the HCAP before it resets in January to make sure people in Texas are not exposed to high prices when the calendar rolls over,” PUC Chair Peter Lake said.

PUC Increases Gas Coordination

Facing Wednesday’s statutory deadline to issue orders addressing the storm’s damaging aftereffects, the PUC approved a proposal to increase coordination between the electric and gas industries during an energy emergency (52345).

The rule requires critical natural gas facilities to share “critical customer” information to electric utilities, who then must incorporate the information into their load-shed and power-restoration plans by prioritizing natural gas. It applies statewide. ERCOT manages about 90% of the state’s grid, but staff have assured SPP and MISO that the rule will not conflict with their FERC jurisdiction.

“We want it to be clear they need to be collecting this information and implementing it to the extent they can, but it’s not going to impede their FERC obligations,” the commission’s David Smeltzer said.

The Texas Railroad Commission (RRC), which provides oversight of the state’s natural gas and oil industries, also passed a companion rule Tuesday that requires gas companies prepared to operate during an energy emergency to file necessary forms with regulators.

Those companies that tell the RRC they aren’t prepared to operate during an emergency will have to explain why they can’t and pay a $150 fee. The rule tightens the commission’s original proposal, which would have allowed facilities to opt-out of weatherization requirements by simply paying the $150.

“These requirements represent a fundamental change in the relationship between the natural gas industry and the electric generation industry,” Lake said. “For the first time ever, the electric transmission and distribution utilities will know the locations of the facilities which are critical to keeping natural gas flowing to the power plants that keep our lights on.”

Lake noted that more than 700 gas facilities have identified themselves as critical, up from the 10 or 15 before the storm.

During the RRC’s open meeting, Chair Wayne Christian took aim at the criticism the agency has faced in recent weeks. The Houston Chronicle has urged the RRC’s three commissioners to resign for “[misleading] Texans about the causes of the deadly blackouts” caused by the storm.

Despite FERC’s and NERC’s joint report that fingered the lack of natural gas and other fuel supplies as the main culprit behind the widespread outages, Christian said laying the blame on gas producers was “pure hyperbole.” (See FERC, NERC Release Final Texas Storm Report.)

The PUC also approved a rule requiring ERCOT market participants to update and file emergency operations plans with the commission and to participate in drills to test the plan once the State Operations Center is activated (51841).

The rule is a result of legislation passed by Texas lawmakers earlier this year. Stakeholders have a Jan. 4 deadline to file comments on the proposal.

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SEEM Members Seek to Quash Rehearing Requests

Members of the recently approved Southeast Energy Exchange Market (SEEM) on Monday called for FERC to reject the rehearing requested by the market’s critics earlier this month (ER21-1111, et al.).

The commission received two requests for rehearing on Nov. 12. One was filed by an ad hoc group of environmental and clean energy organizations calling themselves the Public Interest Organizations (PIOs), and the other by a separate group calling itself the Clean Energy Coalition. (See SEEM Opponents File Rehearing Requests.) Both groups urged FERC to reconsider its de facto approval of the SEEM agreement, which took effect Oct. 12 under Section 205 of the Federal Power Act after commissioners split 2-2 on approval. (See SEEM to Move Ahead, Minus FERC Approval.)

In their filing, SEEM members — a collection of utilities including Southern Co. (NYSE:SO), Dominion Energy South Carolina (NYSE:D), LG&E and KU (NYSE:PPL), the Tennessee Valley Authority, and Duke Energy (NYSE:DUK) — said the opponents’ request should be denied for several reasons.

The first issue the utilities raised was the timing of the rehearing requests, which they said by itself should be enough to quash the petitions. Under the FPA, any parties “aggrieved” by a FERC order may apply for rehearing within 30 days of its issuance. While the opponents filed their requests Nov. 12, which was 30 days after the commission’s announcement that the agreement had taken effect, the SEEM members asserted that this was actually two days after the deadline.

In their filing, the members argued that the “date of issuance” is not when the commission announced the decision, but when it failed to issue an order. Members cited FPA Section 205(g), which states that “the failure to issue an order accepting or denying [a] change … shall be considered to be an order issued by the commission accepting the change.” Under this wording, they said, the date that FERC failed to issue an order should be considered “no later than Oct. 11” — 60 days after the members filed their answer to FERC’s second deficiency letter. (See SEEM Members Push for FERC’s Decision on Market Proposal.)

SEEM members acknowledged some discrepancies between FERC’s announcement of the SEEM approval and the statements of commissioners: Commissioner Allison Clements suggested in a statement explaining her vote that the “statutory deadline” for FERC action in the proceeding was Oct. 8, while FERC’s notice said the deadline was Oct. 11. However, they emphasized that none of the previous filings in this case have stated any deadline after Oct. 11, which means that the 30-day deadline for rehearing requests expired Nov. 10, two days before the PIOs and CEC filed theirs.

Additional Claims Dismissed

Along with arguing to deny the rehearing requests on timing grounds, SEEM members dismissed the “substantive issues” raised in the requests as “largely moot” in light of last week’s filing in which they offered to implement a series of modifications intended to provide greater transparency. (See SEEM Members Embrace Market Changes.)

The issues dismissed by the utilities include concerns of the PIOs and CEC over the market’s use of the Mobile-Sierra doctrine, which presumes that any freely negotiated wholesale energy contract is just and reasonable. FERC Chairman Richard Glick also cited this as a reason for opposing the market. (See FERC’s Christie Accuses Glick, Clements of Prejudice for RTOs.) But SEEM members said this should no longer be a problem because they voluntarily offered in last week’s filing to make the “just and reasonable standard” the default for most SEEM rules.

Also dismissed by SEEM members were opponents’ fears about “the potential for exercise of market power” and monopolistic behavior by members. These concerns too should be negated by the “significant additional transparency measures” incorporated in last week’s filing, the utilities said.

The members did engage with the PIOs’ and CEC’s claim that the commission “has not engaged in reasoned decision-making” and that the commission’s approval of the SEEM agreement without an accompanying order or explanation “cannot be just and reasonable.” Calling this argument “odd,” the utilities asserted that the mechanism in the FPA by which SEEM took effect is intended by Congress for just such an occasion when commissioners are unable to agree on a course of action.

“In every such case there will not be a written opinion of the commission explaining the reasons the [decision] is just and reasonable,” members said. “Rather, it is just and reasonable because Congress said it is, subject to review on rehearing and by an appellate court, if pursued.”

FERC has 30 days to act on the merits of the rehearing request. If it fails to do so, the petitioners may appeal to the D.C. Circuit Court of Appeals.

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FERC Declines Rehearing of PJM MOPR; Ball now in 3rd Circuit Court

FERC on Monday declined rehearing requests of its inaction on PJM’s narrowed minimum offer price rule (MOPR) after a 2-2 tie vote, setting up further action in appellate court (ER21-2582).

The commissioner deadlock allowed PJM’s proposal to automatically take effect Sept. 29 “by operation of law.” The one-page notice from FERC on Monday said the rehearing requests “may be deemed to have been denied” in the absence of any action by the commission within 30 days of them being filed, indicating there has been no change in the stalemate.

Several PJM stakeholders, including the Electric Power Supply Association (EPSA) and the PJM Power Providers Group (P3), had filed requests. (See MOPR Rehearing Requests Set Stage for Appellate Review.)

The America’s Water Infrastructure Act, signed into law by President Donald Trump in October 2018, added a provision to FPA Section 205 to allow for judicial review if FERC fails to act on the merits of a rehearing request within 30 days because the commissioners are divided 2-2. Having filed its request Oct. 5, P3 petitioned the 3rd U.S. Circuit Court of Appeals earlier this month. (See P3 Seeks 3rd Circuit Review of PJM MOPR.)

Several parties have signed on to P3’s petition, including EPSA, Calpine, LS Power and Talen Energy. Vistra and Exelon also filed separate petitions for review, which have been consolidated with P3’s case. In a statement filed in the 3rd Circuit on Monday, the petitioners said they intend to raise the issue whether FERC’s order was “arbitrary, capricious or otherwise contrary to law.”

PJM’s narrowed MOPR is applied only to resources connected to the exercise of buyer-side market power or those receiving state subsidies conditioned on clearing the capacity auction.

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Duke and Solar Advocates Forge North Carolina Net Metering Agreement

A proposed agreement between Duke Energy (NYSE:DUK) and solar advocates that would significantly lower the net metering rate residential rooftop solar owners would receive for their excess power was hailed on Tuesday as a forward-looking compromise that would ensure ongoing growth for residential solar in North Carolina.

The agreement, filed with the North Carolina Utilities Commission on Monday, would change the compensation rate, beginning Jan. 1, 2023, from the full retail rate solar owners now receive to a lower “avoided cost” rate, according to Daniel Brookshire, regulatory and policy manager for the North Carolina Sustainable Energy Association (NCSEA).

“I don’t think there’s any getting around that it’s a small dip” in compensation for new solar customers, Brookshire said. But the agreement also includes new time-of-use rates and other incentives that could motivate customers to add storage or other smart energy management devices to their homes, he said. Thus, storage owners could charge their batteries during off-peak hours and use the power to avoid paying higher peak rates.

Over the long term, Brookshire said, customers on the old or new net metering rates would come out about even.

He and other stakeholders in the process, which included a series of meetings with Duke earlier this year, said they were all keenly aware of the need to avoid a long, adversarial process for reforming net metering, as is occurring now in California. The net metering agreement Duke reached with solar advocates in South Carolina in 2020 provided the framework for the nearly identical North Carolina agreement, said Lon Huber, the utility’s vice president of strategic solutions.

“We all recognize that really, the system is changing. There’s going to be a substantial amount of more renewables on the grid in the coming years,” Huber said in a phone interview with NetZero Insider. “We know that the resources at the grid edge have to help bring reliability and lower costs to the overall system. [They become] a pillar of that future system. And so, yes, at this point in time, we’re sort of right-sizing that compensation.”

The new net metering rates would apply to solar customers in both of Duke’s North Carolina utilities — Duke Energy Progress (DEP) and Duke Energy Carolinas (DEC). Duke is hoping to get an expedited approval from the NCUC to give it the time it needs to set up and educate customers on the new rates, Huber said.

Duke’s current residential retail rate, as listed on the company’s website, is $0.093/kWh; the avoided cost rate based on rates paid to larger, commercial projects would be about $0.03/kWh. According to the agreement, existing solar owners would be able to keep receiving the retail rate through 2027, after which they would be able to choose between retail or TOU rates for compensation.

The agreement also offers new solar owners generous upfront rebates — $0.39 per watt — provided they also install smart thermostats and enroll in Duke’s demand response program for 25 years. To qualify for the incentive, homeowners would also need to use electricity to power their home space and water heating, cooking and clothes drying.

Other components of the proposed rates include:

  • A minimum bill for solar owners of $28 for DEP customers and $22 for DEC customers.
  • Non-bypassable charges designed to recover all costs related to demand-side management and energy efficiency programs, as well as storm cost recovery and cyber security.
  • A grid access fee for systems of 15 kW or more, which would likely have little impact on residential customers. The average rooftop array in North Carolina is around 6-7 kW, according to Brookshire.

It’s Complicated

The concept behind net metering — that residential solar owners should be compensated for the excess power they put back on the grid — emerged in the early days of the rooftop solar industry. At the time, system costs were higher and the payback period on a system was longer. Net metering at retail rates was seen as an added incentive to help homeowners offset the costs of their systems.

But as solar prices dropped — and electric rates rose — utilities began to argue for revision of retail rate net metering, which they said resulted in system costs being shifted from solar customers to non-solar owners. Lower compensation and TOU rates, along with non-bypassable charges, have been framed as ways to ensure solar owners pay their fair share of system costs while receiving compensation that mirrors the rates paid for larger, commercial installations.

For solar advocates, on the other hand, retail rate net metering has been seen as critical for ensuring a competitive return on investment for retail customers.

The original impetus for the North Carolina agreement was HB 589, passed in 2017, which mandated that the NCUC revise net metering rates by 2027. If approved, the agreement will ensure a revision well before that date.

The agreement’s complicated solution combines net metering with the TOU rates. For example, the electricity produced by a rooftop installation during off-peak hours can only be applied to lower the customer’s off-peak rates, while on-peak generation can only be applied to on-peak consumption. And in North Carolina, on-peak hours — 6-9 p.m. in the summer and 6-9 a.m. in the winter — correspond to times of low solar production.

Duke’s TOU rates may range from an on-peak high of $0.19/kWh to a super-off-peak low of $0.06/kWh, according to the company website.

Huber acknowledges the complexity, but he said, “The grid is getting a lot more complicated, and so if you want to encourage new types of technologies to solve the grid challenges, you can’t mask the price signals for simplicity’s sake.”

Like Brookshire, he sees opportunities for customers to benefit through changing power consumption patterns and adding storage, smart thermostats and other energy management technology to their homes.

“If the customer engages in grid-beneficial behavior, there are also more rewards,” he said. “If they control that peak usage, now they can get some savings from responding to the TOU rates. If they charge their vehicle at the right times, they’re helping soak up excess [renewable] generation, getting a discount on that. So there are more opportunities to grab benefits.”

Huber also described the TOU rates as volumetric — based on how much power a customer uses — and easy to model for installers. As part of the agreement, Duke has committed to setting up an online calculator to help customers estimate savings under the new rates.

Brian Lips, senior project manager for the North Carolina Clean Energy Technology Center, which was not a stakeholder in the agreement, said that the result, while complicated, follows other net metering reform efforts across the country. The importance of the model is in the process, in which “all the relevant parties get together and actually reach an agreement and come to the [NCUC] with that agreement,” he said. “I think the commission certainly appreciates that. So, just in terms of coalition building and coming to an agreement, I think that’s a pretty welcome process.”

Other Reactions

NCSEA is one of several solar organizations signing off on the agreement, including the Southern Alliance for Clean Energy, the Southern Environmental Law Center (SELC) and Vote Solar. Under the agreement, all the organizations committed to publicly support the compromise, issuing a joint press release with statements of endorsement on Tuesday.

Bryan Jacob, solar program manager with the Southern Alliance, said the agreement balanced the need for customers to be fairly compensated for the services they provide to the grid with rates that are “designed to align customer behavior with controlling utility costs when possible.”

“This agreement recognizes the important role that solar can play in keeping the electric grid strong and resilient,” said David Neal, senior attorney at SELC, pointing to the upfront solar incentives as a spur for more residential solar deployment.

Lindsey Hallock, southeast regional director of Vote Solar, highlighted another provision in the agreement that commits Duke to exploring options for a low-income solar program. Bringing the voices of low-income customers to the table will “remove prohibitive cost barriers and unlock the benefits of solar for more North Carolinians,” Hallock said.

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OVEC Hit with $300K in NERC Penalties

FERC on Friday approved a $300,000 settlement between ReliabilityFirst and Ohio Valley Electric Corp. (OVEC) for violations of NERC reliability standards concerning vegetation management.

NERC submitted the settlement Oct. 28 (NP22-1). In its Friday filing, FERC indicated it would not review the settlement.

OVEC’s penalty stems from two violations of FAC-003-4 (Transmission vegetation management), specifically the following requirements:

      • R2: Transmission owners and generator owners (GOs) must manage vegetation to prevent encroachments into the minimum vegetation clearance distance of applicable lines.
      • R6: At least once a year, TOs and GOs must perform vegetation inspections of 100% of applicable transmission lines. No more than 18 calendar years may pass between inspections on the same transmission right of way (ROW).

The utility reported its violation of R2 in September 2018, after experiencing an outage on the 345-kV circuit between the Clifty Creek power plant in Indiana, operated by Indiana-Kentucky Electric Corp. (IKEC) — OVEC’s subsidiary — and the Pierce substation in Ohio.

At 2:12 p.m. on Sept. 4, 2018, a cedar tree contacted the line from inside the ROW, causing the circuit to trip and lock out of service. When the circuit failed to reclose automatically as designed, OVEC surveyed the line and found that a phase conductor had sagged into the tree, which was about 30 feet high. After the utility cut the tree, it re-energized the transmission line, and service was restored at 6:42 p.m.

OVEC had surveyed the span where the contact occurred in 2017 and concluded that vegetation clearing was needed, later including the span in a work scope created in February 2018. But the work had not been done at the time of the contact.

RF blamed the violation on ineffective prior inspections — both in 2017 and a partial survey in 2018 — that failed to identify the slow-growing cedar tree as a significant risk, and on ineffective vegetation management and clearing activities. The regional entity assessed the risk posed by OVEC’s violation as “serious” because the outage could have led to overloading of other transmission lines and cascading system failures; however, RF also acknowledged that because of the “operating characteristics and design of OVEC’s 345-kV transmission system,” no actual load loss occurred.

Helicopter Crashes, Hurricanes Hinder Inspections

The infringement of R6 came to light during a compliance audit begun by RF nearly a year after the R2 violation. RF found that OVEC had not completed vegetation inspections on 100% of its transmission lines as the requirement mandated.

A number of factors contributed to OVEC’s failure to complete the inspections. First, a helicopter crash in June 2019 prevented the utility from conducting the inspections — then around 90% completed — according to its schedule. OVEC rescheduled the remaining inspections to begin in October with another contractor (RF noted that it was during this delay that the tree encroached on the Clifty Creek-Pierce line, which had not yet been inspected.), but the new contractor was unable to complete the task in 2018 “because a hurricane damaged its helicopter hangar.”

RF acknowledged the difficulty of the situation for OVEC, which had to vet and hire a new helicopter operator in a relatively short time frame to complete the inspections by the end of 2018, and that new contractor was still unable to finish the task through no fault of the utility. But in its report, the RE stressed that the vegetation inspections are of paramount importance — again noting the Clifty Creek-Pierce outage — and said that the inability to complete them demonstrated “ineffective planning combined with ineffective contractor management.”

Mitigation measures for both violations were certified completed by the end of May 2020. OVEC’s efforts to address the infringements include detailed vegetation inspections via helicopter on all OVEC-IKEC circuits; a root cause analysis of the violation; formalizing documentation of vegetation management schedules and results to include versions, dates and signatures of personnel involved; and revising its transmission vegetation management plan to “address the latest version of the FAC-003 standard and to address the quality of inspections and documentation of said processes.”

RF noted the completion of the mitigation measures, and that there were no prior instances of noncompliance by OVEC that would affect the penalty. The RE concluded that the $300,000 penalty would bear a “reasonable relation to the seriousness and duration of the violations.”

The ERO also filed a separate, nonpublic NOP regarding an unnamed registered entity (NP22-2), in accordance with FERC and NERC’s policy on violations of Critical Infrastructure Protection standards.