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October 7, 2024

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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.

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Experts Talk Carbon Markets at Ontario Energy Conference

Canada has had a price on carbon pollution at the federal, provincial and territorial levels since 2019, but it’s not a perfect system, says Lisa DeMarco, senior partner and CEO of Canadian law firm Resilient.

Carbon pricing in Canada, which reflects the country’s constitutional, federalist structure, is “strange,” DeMarco said during the annual Association of Power Producers of Ontario (APPrO) energy and networking conference on Tuesday.

In what is supposed to be a flexible approach, a province or territory can design its pricing system or choose the federal pricing system. However, the federal government sets benchmark stringency standards that any carbon pricing scheme must meet to ensure it is comparable and effective in reducing emissions. If a province or territory decides not to price pollution or proposes a system that does not meet these standards, the federal system is implemented for consistency and fairness.

The federal price has two parts: a regulatory charge on fossil fuels such as gasoline and natural gas, known as the fuel charge, and a performance-based system for industries, known as the Output-Based Pricing System.

Provinces challenged the constitutionality of the federal system, but Canada’s Supreme Court upheld the government’s ability to set minimum national standards for carbon pricing.

Canada is covered entirely by various forms of carbon pricing. In New England, carbon pricing is a political hot potato. However, its high-profile advocates include ISO-NE CEO Gordon van Welie; U.S. Sen. Sheldon Whitehouse (D-R.I.); and New England Power Generators Association President Dan Dolan, who spoke at an APPrO panel on Monday.

With the looming elimination of the minimum offer price rule and a glut of state-sponsored resources entering the market, Dolan said the question is, “How does the market evolve?” New England has aggressive decarbonization and net-zero targets, driven by Massachusetts and Connecticut, which represent more than 80% of GDP and electricity load, Dolan said. Transportation represents the bulk of emissions in New England, twice the amount of any other sector in the economy and “the only one that has actually gone up,” Dolan said.

Power plant emissions, he added, have “fallen off a cliff” for New England, and now the region has “one of the cleanest fleets” in the country.

“Yet that is continuing to [be] where we see more focus put, in large part, because of political expediency,” Dolan said. “But how we then break that curve on the transportation side and bring in heating is going to be key to the overall foundation of where we can power this economy moving forward.”

Crossing the Border

In July, the Canadian government said its carbon price will increase by $15 per year after 2022 until it reaches $170/ton in 2030. However, that could lead to disparities with international trading partners, including the U.S. As a result, Canada is exploring Border Carbon Adjustments (BCAs), which account for differing carbon costs incurred in producing internationally traded goods.

BCAs could include import charges applied to goods from countries that do not have carbon pricing or use a lower carbon price to ensure that they face similar carbon costs. Export rebates can also be provided so that domestically produced goods compete on equal footing in foreign markets, alongside goods from countries with limited or no carbon pricing.

BCAs are not high on the policy docket at the moment, said Mitchell Davidson, executive director of Canada’s StrategyCorp Institute of Public Policy and Economy. The last thing that Canadian Prime Minister Justin Trudeau wants to do “is make things more expensive, even if it’s already doing that in some capacity with carbon pricing,” Davidson said.

Moreover, he said, the additional level of tariffs that would come with BCAs amid rising prices and supply chain issues make it “a low likelihood” for any immediate action.

“Although in the future it is certainly something that the government could seriously consider,” Davidson said of BCAs.

The better policy, said Scotty Greenwood, managing director of Crestview Strategy in Washington, is to have a “North American approach” for energy pricing and carbon transition.

“I think that is more productive to think about how we do that than trying to look at how we compete on something like carbon,” Greenwood said.

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Stark Choice for Va. Regulators on Shared-solar ‘Minimum Bill’

The Virginia State Corporation Commission faces a stark choice in setting the minimum charge for customers who subscribe to shared solar projects.

Dominion Energy (NYSE:D) has proposed a charge of more than $75/month, saying anything less than that would result in cost shifts to nonparticipating customers. But commission staff, legislators and the Virginia Department of Energy have joined solar advocates in expressing concern that Dominion’s proposed charge is so high it could smother the shared-solar concept in its cradle.

Expected to launch in July 2023, the shared-solar program would allow apartment dwellers and those in homes unsuitable for rooftop solar to offset part of their electric bills by purchasing a share of solar projects remote from their homes. Solar advocates said the “minimum bill” — after accounting for all bill credits — should be 1/10 of what Dominion proposed.

“The high amount proposed by Dominion … may have a significant inhibiting effect on customer acquisition,” the Department of Energy said in filed comments (PUR-2020-00125).

Dominion’s proposal also drew a backlash from the authors of the legislation establishing the shared-solar program, which was enacted last year (HB 1634/SB 629).  

“We believe Dominion’s proposed minimum bill is too high for the program to function as intended,” Sen. Scott Surovell (D) and Del. Jay Jones (D) wrote in an April 29 letter to the commission. “Prior to the passage of this legislation, Dominion Energy attempted to create a community solar pilot program with a minimum bill amount that we understand is similar to the current proposal. The pilot program did not work with a similar amount and we do not believe the program will work this time if the current proposal is enacted.”

Dominion’s April 1 proposal said that a residential customer who consumes 1,000 kWh of power should receive a minimum bill of $74.90 (distribution service charges: $29.45; transmission service charges: $20.29; generation balancing service charges: $25.16), not including administrative overhead costs, which it estimated at $10 to $20/month per customer.

Commission staff warned such administrative costs could push the bill to almost $95/month. It proposed an alternative fee of $10.95/month, which excludes transmission and distribution charges, or $55.10/month, which includes them.

“Staff believes that, ultimately, the determination of the appropriate minimum bill is a policy question for the commission’s determination,” David Dalton, principal utilities analyst with the commission’s Division of Public Utility Regulation, testified in a Nov. 18 hearing on the matter.

Staff said the commission must make a policy decision because the legislation creating the shared-solar program provided “wide statutory discretion.”

The legislation said the minimum bill “shall include the costs of all utility infrastructure and services used to provide electric service and administrative costs of the shared-solar program” and “minimize the costs shifted to customers not in a shared-solar program.” Low-income customers are exempt from the minimum bill.

Points of Disagreement

Dominion and solar advocates disagree over administrative charges, credit calculations for solar generation, and the impact of shared solar on the utility’s generation and transmission expenses.

In an April 30 filing, the Coalition for Community Solar Access (CCSA) and the Chesapeake Solar & Storage Association (CHESSA) recommended a minimum bill of $7.58/month for residential customers: the basic customer charge (currently $6.58/month) plus $1 for incremental administrative costs. The basic customer charge would be different for other rate classes, ranging from as low as $10 for small general service commercial customers to up to $120 for large general service customers.

Based on Dominion’s estimate that a typical 1,000/kWh residential customer would pay about $117/month for electricity service and supply, “this means that Dominion’s minimum bill proposal of about $75/month would be approximately 64% (nearly two-thirds) of the typical residential customer’s bill,” the solar groups said. “Individual customer savings would be reduced if not eliminated.”

CCSA/CHESSA said the additional $67 in Dominion’s proposal “seems to be entirely calculated by Dominion as the sum of the charges a hypothetical customer might have paid, net of avoided energy costs, if the customer had received no bill credit.”

“Dominion’s assertions about cost shifting … are incorrect and premised on a flawed view of its entitlement to effectively eliminate savings customers may realize by participating in the shared-solar program,” said former Texas regulator Karl Rabago, CCSA’s witness at the Nov. 18 hearing. “Dominion’s approach appears specifically designed to make shared-solar subscription unattractive to potential subscribers and, therefore, renders the shared-solar program unworkable.”

Dominion: Seeking to Prevent Cost Shifts

Dominion argued that its proposed charge is an effort “to mitigate cost shifting to nonparticipating customers.” That was a point attorney Jontille Ray, a partner at McGuireWoods, speaking on behalf of the utility, made repeatedly at the SCC hearing. “It is not meant to discourage participation” in the shared-solar program, she said.

Public comments during the hearing weighed heavily the other way. Jay Epstein, president at Health-E Community Enterprises of Virginia, a solar developer, said Dominion’s proposed minimum rate was much too high. Larry Bright, an Arlington resident who said he owns his own solar-powered home and pays $7/month for access to the grid, said $75/month would put shared solar out of reach “for almost everybody who would be interested.”

Likewise, Dr. Samantha Ahdoot, a pediatrician in Alexandria, speaking on behalf of the American Academy of Pediatrics, said Dominion’s proposal would discourage uptake of the shared-solar program. She talked of recently treating a young girl’s first asthma attack, a condition that is aggravated by air pollution of the kind the shared-solar program intended to alleviate.

There was no ruling at the end of the Nov. 18 hearing. Hearing Examiner Matt Roussy directed the parties to file post-hearing briefs by Jan. 13.

The solar groups said the commission should identify and minimize net program costs to nonparticipants by ordering a full benefit-cost analysis, “more transparent and forward-looking” integrated resource planning, including distribution planning, and more effective delivery of energy efficiency and demand response programs for shared-solar customers.

Threat to Shared Solar?

Dominion’s proposal and the two from staff would include a volumetric component that increases with the customer’s energy use. The solar groups said the charge should be a flat fee, arguing “a simple minimum bill will facilitate customer participation while minimizing potential confusion.”

“Higher costs and risks … would likely render projects nonviable,” they added. “Community solar projects are multimillion-dollar projects for which the return on investment takes many years of a project’s multidecade useful life.”

But Dominion said the impact of the minimum charge on the uptake of shared solar is irrelevant. “The appropriate question for this proceeding is not whether the framework of the minimum bill, established by statute, will be conducive to signing up subscriber organizations for the program, but what costs should be included in the minimum bill and how it should be administered to participating customers,” it said in a response to the solar groups’ comments. “The minimum bill as proposed does not interfere with the creation of shared-solar facilities, and the company believes it is too early in the program to reach this conclusion. Significantly more evidence would be needed to support a finding that the minimum bill proposal renders the program inoperable.”

Six Categories of Charges

Commission staff identified six categories of charges that could be included in the minimum bill: the basic customer charge; non-bypassable charges required by the Virginia Clean Economy Act (VCEA) for the renewable portfolio standard; transmission charges; distribution charges; generation balancing services charges; and administrative charges.

Dominion included all but administrative charges in its $75/month proposal.

“Since the shared-solar program is a couple of years away from implementation, it may be premature to set a specific administrative cost to the subscribers at this time, but the company does anticipate that could be in the $10 to $20/month range,” the company said in response to a question from commission staff. “This monthly rate would be independent of subscription size.”

“It is inconceivable that a prudent utility of Dominion’s size would incur incremental fixed costs, independent of subscription size, as large as $120 to $240 per customer per year for shared-solar billing,” Rabago responded.

“Because utility infrastructure and services costs associated with the operation of the shared-solar generator are recovered through upfront and ongoing interconnection costs assessed on shared-solar facilities, the only remaining administrative costs of the shared-solar program that must be reflected in the minimum bill are the costs incurred by Dominion for apportioning, crediting and billing-shared solar subscribers,” CCSA/CHESSA said.

Staff opposed Dominion’s proposal to set the administrative charges when the company files the tariff pages for the shared-solar program. “Staff believes that it is appropriate for the administrative charges to be subject to a formal petition, investigation, litigation and a finding of fact as to their reasonableness rather than proposed and reviewed informally after the commission’s issuance of an order in this case,” the SCC’s Dalton testified.

Dominion said CCSA and CHESSA “appear to use the basic customer charge as a proxy to account for all delivery charges and generation balancing service charges that must be recovered from customers to successfully support the shared-solar program, but the basic customer charge does not account for all costs of supporting the program.”

Commission staff said the CCSA/CHESSA proposal does not include any non-bypassable charges required by the VCEA.

Dalton said staff concluded Dominion’s proposal “appears to include some level of generation in excess of the non-bypassable charges” while leaving it to the commission to determine if recovery of such costs is appropriate.

Staff’s proposed $10.95 monthly fee incorporates the non-bypassable fees and also adopts the solar advocates’ proposed $1/month charge as a placeholder for administrative costs pending an evidentiary proceeding.

Staff’s $55.10/month option includes $49.74/month for transmission and distribution charges — a response to the company’s assertion that shared-solar subscribers will continue using the utility’s transmission and distribution infrastructure in the delivery of their electricity.

Different than Net-metered Solar

Dominion said shared-solar subscribers must be distinguished from net-metering customers who generate power behind their own meter.

“The [shared-solar] generation is not serving any of the customer’s load directly in real time … and, because of the nature of solar generation, does not cover the customer’s load whenever the solar facility is not generating (e.g., night, cloudy days, when the facility is down for repair or maintenance),” Dominion said. “Thus, at all times, the company is providing generation service to the participating customer.”

Rabago and the solar groups counter that Dominion failed to recognize the value of shared solar to Dominion’s system. “Fundamentally, shared-solar subscribers are supporting the construction and operation of clean, distributed solar generation. As such, they supplement and offset costs that the general body of customers would otherwise have to pay to support Virginia’s clean energy transition,” Rabago testified. “Shared-solar subscribers are frontline volunteers, mitigating costs that Dominion would otherwise incur to develop solar to meet the requirements of the Virginia Clean Economy Act and the renewable portfolio standard and which Dominion has not accounted for.”

The utility also ignored the locational value of solar sites, the groups said.

“Even in the near term, shared-solar generation can be injected into the grid at or near distribution load, providing transmission and distribution system savings that Dominion has not accounted for,” Rabago said. “Exported energy from shared-solar facilities does not physically travel to the homes of shared-solar subscribers. That energy will serve the nearest unserved load and will pass through a revenue meter when it does so. That service will generate full retail billings by Dominion, but without incurring the total system costs that drive Dominion’s cost of service.”

Rabago testified that the solar groups’ proposal would add about $25 million in costs to nonparticipants — adding about 35 cents/month for a 1,000-kWh/month user.

“Dominion has not performed and does not possess any research, analysis or other material on distributed generation that would be installed under the shared-solar program as [it] relates to the Virginia Clean Economy Act, the renewable portfolio standard or Virginia’s participation in the Regional Greenhouse Gas Initiative, and has conducted no evaluation of how the shared-solar program would impact its integrated resource planning process and plans,” Rabago said.

Crediting Calculation

Solar advocates also challenged Dominion’s proposal over how to calculate the bill credit that shared-solar subscribers should receive.

CCSA called for use of U.S. Energy Information Administration data, which it said justified a credit of 12.06 cents/kWh. Dominion proposed using data from FERC Form 1, which it said would amount to a credit of 11.765 cents/kWh.

Commission staff agreed, noting that Form 1 is already used by the commission in its multifamily shared-solar program.

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NECEC Halts Tx Line Construction, Regulators Suspend Env. Permit

In a fast-moving series of recent events surrounding the New England Clean Energy Connect (NECEC) transmission line, the project’s developer halted line construction and Maine regulators suspended its environmental permit.

The Maine Department of Environmental Protection issued a suspension order on Nov. 23 for the permit it granted last year authorizing construction of the line.

In the order, the DEP said that “all construction must stop.” NECEC Transmission, however, had announced on Nov. 19 that it is discontinuing construction while it challenges the legal authority of a referendum on transmission development passed by voters earlier in the month.

Gov. Janet Mills certified the referendum vote in a Nov. 19 proclamation and immediately sent a letter to NECEC Transmission CEO Thorn Dickenson asking that the company stop construction.

NECEC’s decision to continue work on the line without further legal clarity, she said, “is disrespectful to Maine people.”

The referendum authorizes a statutory change requiring legislators to approve high-voltage transmission lines greater than 50 miles that are not necessary for reliability purposes.

Suspension

While the DEP’s May 2020 permit allowed NECEC to start building the line, a Maine court in August reversed a Bureau of Parks and Lands decision to lease a 1-mile corridor to the company for the project.

The court’s ruling prompted DEP Commissioner Melanie Loyzim to launch a permit suspension proceeding, saying the ruling represented a “change in circumstance.”

In early November, the facts before the DEP for the suspension proceeding changed after voters approved the transmission-related referendum. The DEP then proceeded to seek additional input from parties to the proceeding regarding the referendum and scheduled a hearing for Nov. 22.

The referendum, NECEC argued during the hearing, does not represent a change in circumstance requiring permit suspension because there will be no environmental impact while work is stopped on the line.

Loyzim, however, determined that because of the statutory changes approved in the referendum, NECEC will not be able to construct the line as permitted, and it will need to find a new project route.

“The law would ban construction of any transmission line defined as a ‘high-impact transmission line’ in the Upper Kennebec Region,” where NECEC is sited now, the order said.

The DEP’s suspension order will remain in effect unless the court grants NECEC’s request to continue construction while it challenges both the referendum and the BPL corridor decision.

Despite DEP’s suspension order, Iberdrola remains committed to developing the line, Dickenson said in a Nov. 23 statement.

Mills reinforced her ongoing support for the project in her Nov. 19 letter to NECEC, saying the line “will usher in substantial environmental and economic benefits for Maine.”

“But more than any single policy or project, I support the rule of law that governs our society and the will of the people that informs it,” she said.

Legislators’ Plea

Members of the Maine State Senate and House of Representatives urged Massachusetts Gov. Charlie Baker in a Nov. 23 letter to terminate the NECEC project.

NECEC would supply hydropower from Hydro-Québec to the New England grid through a 20-year supply agreement with Massachusetts utilities.

“As a bipartisan group of lawmakers representing regions throughout Maine, we discourage Massachusetts from proceeding with this project after the people of Maine delivered a stunning rebuke of the NECEC,” the letter said.

The state’s utilities, the group said, received other bids as part of its clean energy generation request for proposals, and they should “move on” from NECEC.