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November 5, 2024

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PJM to Mandate COVID-19 Vaccines

PJM is mandating COVID-19 vaccines for its employees, contractors, vendors and stakeholders working at or attending meetings at the Valley Forge, Pa., campus or to attend RTO events on and off campus beginning Jan. 4.

CEO Manu Asthana made the announcement in a letter sent to stakeholders Nov. 19, laying out a path for the return to in-person meetings on the campus and working procedures for employees.

Stakeholders had argued for months at committee meetings that the RTO should mandate vaccinations for all its employees. They received further updates at the September Operating Committee meeting, with PJM staff saying they were reviewing Occupational Health and Safety Administration (OSHA) rules requiring vaccinations or a weekly negative COVID-19 test for any company with more than 100 employees by consulting the RTO’s legal counsel, its epidemiologist and the executive team. (See “COVID-19 Update,” PJM Operating Committee Briefs: Sept. 10, 2021.)

The 5th U.S. Circuit Court of Appeals, in New Orleans, earlier this month granted an emergency stay prohibiting enforcement of the OSHA rules, with the court saying they raised “grave statutory and constitutional issues.” The 6th Circuit, in Cincinnati, was selected on Nov. 17 to accept legal challenges to the mandate, and the Biden administration filed an emergency court motion on Nov. 23 seeking the reinstatement of the mandate.

Asthana thanked the membership for their cooperation and flexibility in the stakeholder process as the RTO has “navigated our way through the pandemic.”

“At PJM, the safety, security and reliability of the high-voltage electric system and the wellbeing of our employees and stakeholders are paramount,” Asthana said.

Stakeholder Meetings

PJM had said in August that it expected to resume holding in-person stakeholder meetings on the RTO’s campus in the first quarter of 2022, starting with the Members Committee’s and Markets and Reliability Committee’s meetings.

Asthana announced that PJM intends to extend an in-person meeting option in the second quarter of 2022 for the RTO’s standing committees, including the Planning, Market Implementation, Operating and Risk Management committees, as well as senior task force meetings.

Stakeholders will still have a virtual attendance option that has been available since PJM started emergency procedures for the pandemic in March 2020. Members wishing to attend in-person meetings will be required to be vaccinated.

Asthana said the RTO has been looking for locations for its Annual Meeting, but it has been unable to “secure an appropriate venue.” Instead, PJM will hold the meeting at its Conference and Training Center in Valley Forge to conduct necessary business in May, including the election of the Board of Managers, and then hold an event in the fall for “social and leisure activities.”

The Annual Meeting will start May 17 with the MC meeting, the board election and the general session. The following day will feature PJM board meetings with the Transmission Owners Agreement-Administrative Committee, the Public Interest and Environmental Organizations User Group, and the Organization of PJM States Inc. board of directors.

PJM Employees

Asthana also said PJM employees could resume business travel, which has been restricted since January 2020, in the first quarter, provided the employee is vaccinated.

In-person operator training will also resume next year with the spring PJM operator seminar running from March 7 to May 13. Asthana said details regarding the start of other in-person training seminars will be announced in the future.

When asked if there will there be any medical or religious exemptions provided to employees who do not take the vaccine, PJM spokeswoman Susan Buehler said the RTO is allowing for medical and “sincerely held religious exemptions” for employees. Buehler said the exemptions will be handled individually on a case-by-case basis.

A “majority” of PJM employees have already been vaccinated, Buehler said, and the RTO is working with unvaccinated employees to “provide flexibility and alternative jobs” if it is possible. She said the vaccine mandate does not apply to PJM employees working remotely 100% of the time.

Buehler said PJM has not been influenced by the federal court cases regarding the OSHA mandates and plans on holding to the Jan. 4 timeline.

“PJM is most concerned about the safety of the grid, the safety of employees and those who come on our campuses,” Buehler said.

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Conn. Environmental Advocates Urge Continued Commitment to TCI-P

Environmental advocates from across Connecticut have vowed to maintain pressure on Gov. Ned Lamont and the General Assembly to pass legislation that would enable state participation in the Transportation and Climate Initiative Program (TCI-P).

A dozen advocates co-signed a statement urging passage of the program, which would institute a declining cap on allowable carbon emissions from gasoline and diesel fuel sold and require suppliers to purchase carbon allowances at auction.

Those allowances would generate hundreds of millions of dollars during a 10-year period starting in 2023, which the state would reinvest in programs and infrastructure that reduce transportation emissions. The emissions cap would reduce carbon emissions from on-road transportation by at least 26% through 2032.

Lamont’s latest decision to pause the pursuit of TCI-P has affected the region as well. Massachusetts Gov. Charlie Baker and Rhode Island Gov. Dan McKee announced that their states would back away from the program, which all three states and DC signed a memorandum of understanding to join in December 2020. 

Advocates said walking away from TCI-P should not be an option.

“Pulling their support for TCI was a short-sighted move by the Lamont administration, which kicks the can even further down the road on addressing carbon pollution,” said Louis Rosado Burch, Connecticut program director at Citizens Campaign for the Environment. “Connecticut residents want bold leadership from their elected leaders. TCI is a necessity, not a luxury to be put on the shelf for another day.”

Acadia Center and its partners in Connecticut’s Transportation Future coalition maintain that businesses, mayors, community leaders and public health professionals support TCI-P and its economic, public health and climate benefits, said Amy McLean, Acadia Center’s Connecticut director and senior policy advocate. 

“Environmental justice leaders have worked closely with state agencies and the legislature to center equity and transportation justice in Connecticut’s implementation of the TCI,” McLean said. “While Gov. Lamont appears content to press pause on that important work, we are committed to moving it forward.”

Off Target

Another advocate added that Connecticut is at a crossroads. Charles Rothenberger, climate and energy attorney at Save the Sound, said it has been more than two months since the Department of Energy and Environmental Protection (DEEP) announced Connecticut is not on track to meet its statutory 2030 and 2050 economy-wide reduction targets.

The Connecticut Greenhouse Gas Emissions Inventory, which tracks progress on emissions targets, shows that the state emitted 42.2 million metric tons of carbon dioxide equivalent in 2018, the most recent year that data are available. That is 2.9% higher than the state’s 2020 emissions goal and a 2.7% increase from the 2017 inventory. Transportation emissions, at 15.8 million metric tons, exceeded the combined emissions of the electricity and residential sectors and have been rising since 1990 despite improvements in fuel economy. In addition, vehicle miles traveled have increased faster, further increasing emissions. (See Conn. Falls Behind on Mandated Emissions Targets, GHG Inventory Finds.)

The inventory makes two recommendations that would require action from lawmakers in the General Assembly: Adopting California emission standards for buses, light commercial trucks, single-unit short-haul trucks and similar vehicles; and implementing TCI-P. This spring, a bill to enable TCI-P made it out of the General Assembly’s Environment Committee but did not reach a full vote. Calls to include TCI-P in a special session never came to fruition.

“Our leaders need to step up to the plate and show the same urgency in their policies that they’ve shown in their rhetoric,” Rothenberger said. “The cost of inaction is too steep.”

‘Powerful’ Opposition

Last week, Lamont cited rising gas prices as an obstacle to enabling TCI-P legislation, saying the policy would be “a pretty tough rock to push” through the General Assembly. (See Lamont’s TCI-P Reversal Surprises Environmental Advocates, Lawmakers.)

“We are up against the richest and most powerful industries in the world in the fight against climate change,” said Megan Macomber, policy advocate for the Connecticut League of Conservation Voters. “The pushback on TCI shows us how loud these fossil fuel industries can be, but they do not represent the will of the majority.”

Republican lawmakers and gasoline trade associations labeled TCI-P as a “gas tax” in the form of potential pass-down costs from fuel suppliers to consumers.

DEEP analysis shows participation could boost gas prices by 5 cents/gallon beginning in 2023, assuming fuel suppliers will pass down 100% of allowance costs to consumers. Multiple consumer protection safeguards, including a cost-containment reserve, would kick in at 9 cents/gallon.

Opponents said the 5- to 9-cent increase applies to the first year of TCI-P alone, with prices potentially rising by as much as 26 cents.

Macomber added that a poll by Langer Research Associates showed that 78% of respondents ages 18-29 said climate change is a severe problem that needs to be addressed. 

“Major climate programs like TCI must not fall victim to in-party fighting or be used to leverage political agendas,” Macomber said. “With 2022 elections on the horizon, elected officials should double down on their efforts to reduce fossil fuel emissions, not shy away from the fight.” 

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Interior Greenlights South Fork Wind Project COP

The U.S. Department of the Interior on Wednesday approved the construction and operations plan for the 132-MW South Fork Wind Project being built for the Long Island Power Authority, the second major offshore wind project in the country to move forward following the July permitting of Vineyard Wind.

“We have no time to waste in cultivating and investing in a clean energy economy that can sustain us for generations,” Interior Secretary Deb Haaland said in a statement. “Just one year ago, there were no large-scale offshore wind projects approved in the federal waters of the United States. Today there are two, with several more on the horizon.”

A joint venture between Ørsted and Eversource Energy (NYSE:ES), South Fork will be located approximately 19 miles southeast of Block Island, R.I., and 35 miles east of Montauk Point, N.Y.

“New York state is facing the challenges of climate change head-on, and we thank the Biden-Harris administration for their steadfast support,” Gov. Kathy Hochul said in a statement. “With today’s permitting milestone, South Fork Wind is set to be New York’s historic first offshore wind farm providing clean energy where it is needed most. Our nation-leading climate and offshore wind goals demand bold action, and moving South Fork Wind forward brings us closer to a cleaner and greener future.”

Interior’s approval of South Fork’s plan to install 12 or fewer turbines is conditioned on several measures to avoid, minimize and mitigate potential impacts. Prior to construction, the developer must submit to Interior’s Bureau of Ocean Energy Management a facility design report and a fabrication and installation report.

The Environmental & Energy Law Program at Harvard University forecast that BOEM’s final approval might indicate how the agency “will address the concerns of the fishing industry when considering alternatives, mitigation measures and cumulative impacts under the National Environmental Policy Act.”

Fishermen, environmentalists, labor unions and local residents broadly support the project, but some opponents have filed suits in state courts to have its power purchase agreements nullified. (See BOEM Hears Public Support for South Fork OSW.)

Newsday reported Wednesday that the nonprofit Government Justice Center filed a lawsuit in New York State Supreme Court in Suffolk County on behalf of two Long Island ratepayers alleging that the Long Island Power Authority ignored its own criteria for power production resources in entering into a contract for the South Fork Wind Farm. The suit called the project’s power unreliable “because it depends on an intermittent resource to generate electricity.”

The main point in the September 2021 complaint signed by Wainscott resident Simon V. Kinsella, however, was price, not reliability. The PPA pays 22 cents/kWh versus the 8 cents being paid to the neighboring Sunrise Wind Project, the complaint said.

The request for proposals “was a manipulated, noncompetitive solicitation,” Kinsella argued, in which the company administering the procurement, PSEG Long Island, awarded a contract to its existing business partner, Deepwater Wind, at a rate that exceeded the market rate by 53% at the time. Deepwater Wind was the original developer of the South Fork project.

The complaint also alleges that then-Gov. Andrew Cuomo inappropriately interfered with the procurement process earlier this year by pressuring the LIPA Board of Trustees, the majority of whom were appointed by him, to approve a contract for $1.6 billion, which they did on Jan. 25.

The project’s “gross profit (excluding operations and maintenance) is $885 million, representing 120% of the cost ($740 million),” the complaint said.

LIPA determined that the totality of South Fork’s benefits outweighed the variable nature of wind power, spokesman Andrew Berger told RTO Insider.

“As part of the solicitation for resources, the South Fork Wind project was paired with transmission, battery storage and demand response. Thus, the awarded portfolio of projects produced more benefits to customers than the alternatives,” Berger said. “As with all LIPA contracts, the procurement was also independently reviewed and approved by the New York attorney general’s office and the state comptroller’s office.”

LIPA also pointed out that larger projects such as Sunrise Wind, able to spread fixed costs over greater energy production, have lower per-unit costs than smaller projects.

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FERC Establishes Paper Hearing on PJM Rate-base Network Upgrades

FERC on Friday ordered a paper hearing on the PJM transmission owners’ proposed tariff revisions to add network upgrades to their rate base, requesting more information be provided within 45 days (ER21-2282).

The commission accepted and suspended the TOs’ filing for five months, to become effective Feb. 1, subject to refund and to the outcome of the paper hearing procedures.

“We find that the proposed revisions have not been shown to be just and reasonable, and may be unjust, unreasonable, unduly discriminatory or preferential, or otherwise unlawful, and that the record would benefit from further information,” the commission said.

The commission in August had directed the TOs to provide evidence backing up claims that their ability to raise capital is being threatened because they must absorb the risks of increasing transmission upgrades without earning returns on the assets. The TOs responded in September, arguing that PJM’s tariff provides them with the “express authority” to make changes to any of its sections relating to transmission revenue requirements, cost allocation or cost recovery. (See PJM TOs Respond to FERC Questions on Rate-base Network Upgrades.)

The TOs had asked FERC on June 30 to allow them the option to fund network upgrades and add them to their rate bases. Under PJM’s “participant funding” model approved in 2004, generators provide the capital for network upgrades, while the additional infrastructure is added to rate bases at zero cost, allowing TOs to recover only their operations and maintenance expenses from network transmission customers.

According to the TOs, PJM’s 2020 Regional Transmission Expansion Plan (RTEP) showed that the total estimated costs of network upgrades to interconnect new generating resources was about $6.5 billion, which included $1.56 billion of upgrades already constructed and in service and $4.9 billion in active projects in the queue.

The TOs argued that even if a portion of the $4.9 billion of network upgrades in the queue were constructed, it would represent a “significant escalation” of the $1.56 billion of network upgrades they currently own or operate and for which they are currently not earning a return.

“They are concerned that this trend will continue as the number of new generation interconnection requests is expected to increase significantly, if not exponentially, in the coming years as the electric power industry continues to accelerate the development and construction of clean renewable energy resources,” FERC said.

But the commission said a preliminary analysis of the proposed revisions did not show them to be just and reasonable. FERC requested comments on a series of questions in the paper hearing.

The first question posits that the TOs’ proposed revisions are premised on their arguments that owning and operating network upgrades “entails significant risks for which PJM TOs do not earn a return or profit.” FERC asked if the risks TOs’ argue are associated with owning and operating network upgrades are “already incorporated into PJM TOs’ commission-approved ROEs, such that PJM TOs are already compensated for these alleged risks.”

FERC also asked what protections the proposed revisions provide against the “potential for undue discrimination” by the TOs in their choice of which network upgrades will be funded.

Another question asked if the proposed revisions could result in increased costs to interconnection customers “relative to the costs to initially fund network upgrades” if those same customers were able to obtain financing at lower or similar rates than the TOs.

Responses to the questions are due 45 days from the date of the order, and reply comments can be submitted 45 days after the due date of initial comments.

FERC Commissioner James Danly issued a concurring statement, saying that the “voluminous record” on the issue led him to the conclusion that the commission already has “sufficient” evidence to accept the tariff changes, but he recognized that his “colleagues still have questions.”

“While I have previously expressed concerns over improper delay tactics masquerading as requests for additional, unneeded information, the questions set for hearing are such that I do not oppose obtaining additional evidence here,” Danly said.

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Texas PUC Ponders Alternatives to LSE Obligations

Texas regulators continued to explore load-serving entity resource obligations (LSEROs) with an emphasis on dispatchable resources last week in their quest to modify ERCOT’s market design after its near collapse during the February winter storm.

“There’s no silver bullet, no readily apparent solution,” Public Utility Commission Chair Peter Lake said during Friday’s latest ERCOT market work session.

“The first crack we take won’t be the right answer,” he said. “We very much want to capture the good elements of all these proposals and continue to work going forward to the best solution. We’re in the business of vetting ideas and getting closer and closer to the right solution or the right set of solutions.”

One possible solution is the load-serving obligation that Lake has been championing and that still remains atop the list of potential answers. As proposed by NRG Energy (NYSE:NRG) and Exelon (NASDAQ:EXC), the LSERO would directly address resource adequacy concerns by introducing a formal reliability standard and a mechanism to ensure sufficient resources meet this standard. (See Study Suggests Texas LSEs Can Provide Reliability.)

At staff’s request, Brattle Group’s Sam Newell shared his analysis of the LSERO and another alternative to solving ERCOT’s resource-adequacy issues — targeted fuel and backup reserves — to help inform the commission’s decision-making.

He suggested an “LSERO plus” version that would require generators to bid in their capacity at cost to mitigate market power and allow LSEs to procure their obligation just before the season starts. Newell said this would be the most direct way to address resource adequacy, the PUC’s primary concern.

“If you want to look at the fleet and say, ‘Yup, we’re prepared’; if you think you’re able to look at the fleet and say, ‘That’s what we want — we’re prepared for any plausible event’ — this option is the most direct way to express that to the market,” Newell said. “This is the most direct way to export a resource adequacy objective to the market.”

He expressed concern about LSERO plus’s effect on forward bilateral contracts and the likelihood that LSEs wouldn’t know the prices ahead of the auctions and, thus, couldn’t hedge.

And then there’s the not-so-small matter of costs. Newell said Brattle has estimated the proposal would shift about a third of the ERCOT’s market value to LSEROs and cost “roughly” $300 million a year. The high costs stem primarily from staff managing an accreditation process for each resource and awarding reliability credits.

“A lot of administrative judgment goes into this, which will be the subject of ongoing argument,” Newell said. “The money subject to regulatory capture … [is] the biggest downside.”

“This is a major problem,” Stoic Energy consultant Doug Lewin said as he live tweeted the work session. It’s “a step toward an administered market where market participants spend more time working the refs for more money than providing innovation and lower-cost options.”

Alison-Silverstein-(ACEEE)-Content.jpgAlison Silverstein | ACEEE

Independent consultant Alison Silverstein told RTO Insider that large industrial customers might be tempted to opt out of another ERCOT charge and “dump reliability assurance costs onto small customers.”

As an alternative, Newell suggested a targeted fuel and backup reserves option that would require four days of on-site fuel. He said the gas-fired fleet would be the most likely candidate for that requirement, but it would necessitate the units being “satisfactorily winterized” and would only apply to about 25 GW of resources.

The proposal’s increased generation costs would be about half that of LSERO plus, Newell said.

“Holding out a few megawatts from the energy increased the price signals,” Newell told the PUC. “That can attract capital too. It does depend on people believing in [the proposal].”

Brattle’s alternative is similar to a strategic reliability service (SPS) proposed by Commissioner Lori Cobos that she called a “dynamic and flexible reliability tool” that would act as an insurance policy against reliability issues. She said the service would “prospectively target” and meet specific reliability needs not already addressed by ERCOT’s real-time and ancillary services markets.

Under Cobos’ plan, ERCOT would procure SPS through a competitive request-for-proposals process or auction to ensure the selection of the lowest-cost dispatchable resources. Eligible resources would have to meet weatherization requirements, fuel-supply arrangements and other accreditation requirements to ensure availability and firmness. They would also have to be capable of synchronizing to the grid within two hours and run for at least eight hours a day for multiple consecutive days.

Cobos said SPS would be deployed last in the bid stack to minimize its effect on real-time energy prices. Qualifying resources would be paid the market-clearing price, with those failing to perform assessed a “stringent” nonperformance penalty and its participation payment clawed back.

“We want to give ERCOT the flexibility to procure more than peakers. We need to send stronger price signals because we’re moving away from a crisis-based model,” Cobos said, referring to ERCOT’s current dependence on high prices during scarce times to incent new generation.

Newell pointed out that prices are only high during generation shortages.

“It’s not desired,” he said. “We want more supply and more cushion. The only two thematically ways to get that is to increase total demand, either through real-time reserves or through demand for capacity, as with an LSE obligation.”

The other theme?

“Make a side payment, but hold [the resource] out of the market,” he said. “There’s only so much room for supply and only so much demand. You don’t want to expand demand and pay everything that’s reliable. You want to hold some things out of the market.”

The discussion will continue in December, with the PUC committed to releasing a blueprint of its proposed market redesign before the year is up.

Silverstein, who sat in on the work session, questioned the rush for an LSE obligation when real-time co-optimization won’t be added to the market until 2025 at the earliest. The market tool clears energy and ancillary services every five minutes in the real-time market and would simplify a much more complex security-constrained economic dispatch problem when multiple resources and services are juggled over different interdependent time periods.

“I would prefer to see the commission do more, consistent analysis of every new option in the table … before they pick a single option like LSEO to move forward,” Silverstein said. She added that the PUC should analyze the major changes it’s already made to winterization requirements, the operating reserve demand curve and emergency response service, and determine their effect on reliability, market performance and costs.

“This should be the baseline against which they analyze the next set of potential market modifications,” Silverstein said.

Salty Public Comments

The PUC got more than it bargained for when it resumed in-person public comments during its open meeting Thursday. The commission took comments over the phone during the COVID-19 pandemic.

One speaker said she was upset over seats that some stakeholders reserved for others. “There are more suits in this room than the people who were affected” by the winter storm, she said.

A self-described organizer related a story of a person stuck in her home, battling 20-degree temperatures and ice in her sink.

That prompted a response from the woman who followed her: “We didn’t have ice in our sink, but we had ice on our asses.”

During the open meeting’s normal course of action, the commission also:

  • approved a $41.6 million rate-increase request from Southwestern Electric Power Co. (NASDAQ:AEP) but lowered its return on equity rate from 9.45% to 9.25%. SWEPCO had asked for a $90.2 million increase (51415).
  • agreed to a certificate of convenience and necessity for CenterPoint Energy’s (NYSE:CNP) 345-kV interconnection project southwest of Houston that will cost at least $22 million. Commissioner Jimmy Glotfelty dissented from the decision. An administrative law judge ruled that CenterPoint should work with a planned solar farm and existing landowners as it links another solar farm to the grid (51568).
  • learned from Cobos that she has been selected as vice president of Entergy’s Regional State Committee. The E-RSC comprises regulators from Arkansas, Louisiana, Mississippi, Texas and the city of New Orleans and provides input to Entergy about its operations and transmission upgrades.
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Maine Ag-Solar Group to Recommend Dual-use Pilot Program

The Maine Agricultural Solar Stakeholder Group is planning to recommend that the state establish a pilot program for dual-use solar projects as part of a report due to the legislature in January.

A pilot program is one of seven overall recommendations that are in a draft version of the report released by the group for public input.

“The pilot would provide opportunities to conduct necessary research on compatible crops and other dual-use systems to determine best practices for dual use within a defined time frame or capacity limit,” the draft says. In addition, the recommendation suggested that financial incentives or location-based waivers could support projects meeting a set of dual-use criteria.

The Department of Agriculture, Conservation and Forestry (DACF), in cooperation with the Governor’s Energy Office and other state agencies, would develop the pilot program with an eye toward innovation and data collection. Authorization for pilot funding would come from the legislature.

While details of pilot project parameters are not included in the draft recommendation, Nancy McBrady, director of the DACF’s Bureau of Agriculture, Food and Rural Resources, said Thursday that the final report should identify project size and scope.

“The term ‘pilot’ can sometimes infer something small and not particularly aggressive or audacious, and … a pilot specific to dual use needs to be robust enough to prove itself and to be successful,” she said during the group’s latest meeting.

To qualify as dual use, according to the report, a solar installation must enhance agricultural productivity, have a decommissioning plan and support the viability of a farming operation.

As part of its recommendation, the group pointed to New Jersey’s dual-use program as a possible model. The state has a three-year program to develop 200 MW of dual-use solar with projects not to exceed 50 acres, but the program is not “completely defined yet,” said Ellen Griswold, policy and research director at Maine Farmland Trust.

For the final report, McBrady said, the recommendation should convey the group’s interest in the development of a pilot program that would “lead to transformational change.”

Group Insights

The DACF and Energy Office convened the group this year to recommend ways to encourage solar development and protect Maine’s agricultural resources.

In their review of the draft, some group members felt it was cautious in terms of policy considerations.

“I would have liked to see some stronger language,” Griswold said.

The report’s overall tone could focus more on maximizing benefits to agriculture instead of minimizing damage, according to Fortunat Mueller, co-founder of ReVision Energy.

“I would be more inspired by the report if we work a little bit harder to frame it as an affirmatively positive vision for the mutually co-beneficial development of solar and rural economies in Maine,” he said.

Recommendations in the report could be “stronger,” or it should have a “vision statement conclusion about what the next steps should be,” according to Kaitlin Hollinger, policy manager at BlueWave Solar. “I think what’s missing [in the report] is kind of the sense of urgency around what we’re doing.”

In addition to the dual-use pilot program, the report’s other major recommendations include:

      • creation of a centralized clearinghouse of information related to approved and constructed solar projects, including information on the amount of agricultural land affected by deployed projects;
      • additional study on the treatment of land enrolled in the farmland current-use taxation program when the land houses a dual-use project;
      • inclusion of dual-use standards as permitting criteria in future development of processes for activities adjacent to protected natural resources;
      • development of detailed hosting capacity maps to include data on which areas of the grid have capacity for additional interconnections to minimize land-use stress in any one location;
      • increased technical assistance capacity and financial support for municipalities to encourage solar development; and
      • consideration of agricultural siting characteristics in state-sponsored programs that support solar development through long-term contracts or other financial mechanisms.

The group is seeking public input on the draft report through Friday.

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Renewable Advocates Troubled by Tradeoffs in N.C. Climate Bill

CHARLOTTE, N.C. — Renewable power advocates said last week they remain troubled by the concessions legislators made to utilities in return for the carbon-reduction goals of House Bill 951, saying the law fails to protect low-income residents, undermines competition and excludes renewable technologies other than solar.

The law, enacted in October, directs the North Carolina Utilities Commission to take the “least cost path” to cut electric-sector carbon emissions by 70% from 2005 levels by 2030 and reach carbon neutrality by 2050.  The law also requires the state’s utilities — including Duke Energy Progress, Duke Energy Carolinas (NYSE:DUK) and Dominion North Carolina Power (NYSE:D) — to add 2,660 MW of new solar generation, 45% through power purchase agreements and the remainder utility-owned. Utilities will be limited to securitizing only 50% of the remaining book value of coal generators retired early. But it also ensures any other new generation will be utility-owned and subject to cost-of-service rates. (See New Era for Grid Planning in North Carolina?)

The 11-page bill that emerged from the North Carolina Senate was less prescriptive than the initial 50-page House bill, leaving much of the policy decisions to the NCUC.

“But from my perspective, what happened is it got much more prescriptive about the renewable resources that have the opportunity to compete in a marketplace,” Adam Will Foodman, CEO of Solar Operations Solutions and chair of the Carolinas Clean Energy Business Association (CCEBA), said during a panel discussion last week at Infocast’s Southeast Renewable Energy conference. Aside from the 2,660-MW carve out for solar and solar plus storage, “everything else is considered regulatory assets of the utility,” he said.

“Innovation, competition, is the lifeblood of an economy,” he said. “And absent those items, I think it’s difficult to see us charting the most efficient path to an energy transition. … We want a broader opportunity for technologies to compete in the transition that is going to take place with the retirement of coal. There are some opportunities there opened up in the bill. I think it remains to be seen how they will be implemented by the utility commission.”

Consultant Diane Cherry, whose clients include renewable energy developers, the Sierra Club and Carolina Utility Customers Association, a group of manufacturers and other large consumers, said she was disappointed that the law lacked a carve out for stand-alone storage. She also expressed concern that the design of customer programs will be subject to commission rules, making the upcoming dockets — as many as seven of them may be needed to implement the law — a “full employment” guarantee for regulatory attorneys.

Stephen Kalland, executive director of the North Carolina Clean Energy Technology Center at North Carolina State University, said he was disappointed that the final bill did not address distributed generation, community solar, net metering or rooftop solar. But he said the compromises could not obscure the historic nature of the bill’s carbon-reduction goals.

“To see legislated carbon goals … in a bill sponsored by Republicans in both chambers and signed by Democratic governor [is] pretty much unprecedented nationally. I think it was something that was somewhat breathtaking as an example of what states could actually do if they really wanted to drive the train forward in the clean energy space.”

Kalland said the current commission is knowledgeable about the technical issues the law presents. “And so if I had to pick between the legislature writing detailed rules for the energy market, and that utility commission writing those rules, I think it was actually a pretty good outcome,” he said.

Betsy McCorkle, a partner in the lobbying group Kairos Government Affairs, which represented the North Carolina Sustainable Energy Association (NCSEA), said she fears the compromises made to win the carbon cuts may undermine renewable energy advocates in the future.

“In the decade that I’ve been advocating for clean energy, mostly in front of conservative audiences, we have built the case that clean energy is an economically competitive technology. … And I think having [the perception that] the carbon standard be the driver … for these new clean energy technologies in North Carolina, it kind of takes us back a little bit on advocacy perspective. It’s, ‘Democrats got a carbon standard and, Republicans got things that were good for the vertically integrated monopoly.’ … I think you all know it’s not that simple. But as someone who has to constantly advocate in front of people who don’t look at energy every day of their lives, and they get a sound bite here and there, I’m a little bit concerned.”

“There’s gonna be a lot of work to do at the commission,” she said. “… No doors have truly been closed. We’re just kind of moving the venue.”

Ivan Urlaub, chief of strategy and innovation for the NCSEA, said the NCUC will need to be innovative to overcome the Achilles’ heel of the law: the utility ownership provision.

“The evidence has shown that the utility is not least-cost; it’s just not,” he told the audience. “Your businesses are. … And when your businesses and the customer work together, that’s where we most often see the least-cost options.

“The law is basically inviting the regulator to come up with one integrated solution and innovate in how they do planning,” he continued. “The ball’s in the commission’s court. Are they going to pick it up and play a good hard game with it, and, and really be aggressive [or] are we going to get some status quo?”

Urlaub urged those participating in the upcoming dockets to be suspicious of short-term wins in settlement discussions.

In short term deals, “the carrot … gets dangled to slam the door on the next 12 carrots,” he said.

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CARB Approves $1.5B Clean Transportation Package

The California Air Resources Board on Friday approved a $1.5 billion clean transportation funding plan that includes $515 million for the Clean Vehicle Rebate Project, the state’s popular electric car incentive program.

The plan also includes $10 million for a new electric bike incentive program and $75 million for Clean Cars 4 All, a program that offers lower-income residents incentives to scrap their old cars and replace them with zero- or near-zero emission vehicles. The program is available in five of the state’s 35 air districts, but an expansion is planned.

On the heavy-duty side, the funding package contains $570 million for the Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project (HVIP). Within that amount, $70 million is set aside for zero-emission transit buses; $130 million for zero-emission school buses; and $75 million for zero-emission drayage trucks.

The spending plan allocates $195 million to the Clean Off-Road Equipment Voucher Incentive Project (CORE), which provides incentives for equipment such as zero-emission tractors and forklifts.

CARB staff said funding for the CORE program had been increased and that the range of eligible equipment was expanded. The program sets aside $30 million in incentives for small business and sole-proprietor landscaping companies.

Record-setting Funding

The CARB board on Friday approved a resolution adopting the fiscal year 2021/22 funding plan. The agency described the funding package as its largest for clean transportation, more than twice the amount of the previous largest investment.

“This unprecedented mix of incentives and funding will continue to support our equitable transition to zero-emission cars and accelerate the commercialization of zero-emission technologies for medium and heavy-duty trucks and buses,” CARB Chairwoman Liane Randolph said in a release.

The state general fund will contribute $838 million of the funding, and $595 million will come from the state’s cap-and-trade program. The Air Pollution Control Fund and the Air Quality Improvement Program account for the remainder.

Other pieces of the plan include $45 million for replacing diesel trucks with trucks that meet a low-nitrogen oxide standard through the state’s Carl Moyer program. There’s also $180 million in incentives for alternatives to agricultural burning in the San Joaquin Valley.

CVRP Changes

CARB announced in April that funding was rapidly running out for its Clean Vehicle Rebate Project (CVRP), as electric-vehicle purchases rebounded more quickly than expected during the COVID-19 pandemic. (See Shortfall Looms for Calif. EV Rebate Program.)

According to CARB, almost 65% of EV owners in the state have received a rebate through CVRP, a program that was launched in 2010 and had issued more than $926 million in rebates as of April.

The $515 million approved on Friday for CVRP is intended to last for three years, CARB staff said. During that time, CARB plans to “ramp down” the program and shift the focus to lower-income car buyers.

A first phase of changes will be implemented after 1 million EVs are sold in California, but not sooner than February 2022. At that point, CARB has proposed lowering the income cap for standard rebates and reducing the cap on manufacturer’s suggested retail price for smaller vehicles.

When EV sales in the state hit 1.25 million, but not sooner than February 2023, the income cap for standard rebates will be further lowered, rebate amounts will be reduced and plug-in hybrids will be dropped from the program.

Some members of the public who commented during Friday’s board meeting objected to the proposed changes to CVRP.

Anthony Bento, director of legal and regulatory affairs at the California New Car Dealers Association, said the incentive program is valuable but is “undermined by its complexity, particularly with respect to eligibility.”

Bento said the group is concerned that the proposed changes would make matters worse.

“In particular, that two-phase reduction in income caps and vehicle eligibility creates needless confusion,” he said.

Eileen Tutt, executive director of the California Electric Transportation Coalition, said in a letter to the CARB board that reducing the CVRP income cap “serves only to confuse and frustrate both middle-class consumers and auto dealers and reduce the market for EVs.”

Tutt described the proposed changes in income caps as arbitrary.

“The phases are proposed even though there is no data indicating these phases are related to consumer response or market viability of EVs,” she said.

CARB board member Daniel Sperling also urged the agency to be cautious in making changes to CVRP. He disagreed with the idea of dropping plug-in hybrids from the program as part of the second phase of changes.

While many people can switch to battery-electric vehicles without much trouble, especially if they own multiple cars, the change may be more difficult for others such as apartment dwellers, said Sperling, who is founding director of the Institute of Transportation Studies at the University of California, Davis.

In addition, Sperling called for using some of the money in the spending package to assess the effectiveness of programs being funded.

“Making sure we’re investing our money wisely and especially looking to the future,” Sperling said. “It can be built into every program, and I think we need to be thinking along those lines more.”

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Conservatives Tout RTOs over Regulations as Enviro Solution

A panel of conservative electricity market experts on Tuesday argued that markets work better than public policy at encouraging and developing clean energy resources.

“Private capital is foaming at the mouth to get in these markets, and the obstacle is outmoded regulation,” Devin Hartman, director of energy and environmental policy at conservative think tank R Street Institute, said at a webinar hosted by ConservAmerica, a conservative environmental advocacy group. Formerly known as Republicans for Environmental Protection, the group argues that “the most efficient way” of developing clean energy resources “is through policies that encourage competitive markets, private investment and expanded trade.”

The private sector wants to invest in building the infrastructure needed for a clean energy future, said Hartman, former CEO of the Electricity Consumers Resource Council (ELCON). He called for re-evaluating the regulatory structure.

Hartman was joined by current ELCON CEO Travis Fisher.

“A different way to view it is the difference between a state-level mandate versus a corporate goal,” said Fisher, previously economic adviser to former FERC Commissioner Bernard McNamee. A corporate goal can be dropped if things go poorly, there are reliability issues or the cost is too high, he said.

“It doesn’t take an act of state or Congress to drop that,” Fisher said. “The more rigid and the more top-down mandated it is, that’s where you get into problems. [Policy questions] can be borne out through voluntary transactions … instead of saying, ‘We know the answer has to be X, and we have to do it by year Y.’ I don’t think that’s the correct way to go about it.”

The discussion was framed the around a new report by the Energy Choice Coalition (ECC) on the environmental benefits of competition in electricity markets, which found that RTO/ISO regions have reduced their power sector CO2 emissions by about 35% from 2005 levels, while non-RTO regions have reduced theirs by about 27%.

Furthermore, the report found that RTO regions with more competitively owned generation, such as ISO-NE, NYISO and PJM, posted even deeper reductions: 61%, 56% and 41%, respectively, said Joshua Rhodes, research associate at the University of Texas at Austin and a founding partner of energy consultancy IdeaSmiths, which conducted the study.

ConservAmerica-Panel-(ConservAmerica)-Content.jpgClockwise from top left: Robert Dillon, Energy Choice Coalition; Landon Stevens, Conservative Energy Network; Joshua Rhodes, University of Texas Austin; Travis Fisher, ELCON; and Devin Hartman, R Street Institute | ConservAmerica

The study also found that RTO/ISO regions deployed almost 80% of all utility-scale renewable generation capacity, despite accounting for 67% of all existing power plant capacity. In addition, RTO/ISO regions have seen stronger growth in distributed solar PV, increasing by about 214% versus non-ISO regions at 199%.

“You’re never going to get a pure market in this area because there are a lot of different drivers,” said Robert Dillon, executive director of the ECC and a member of the leadership team at ConservAmerica.

The environmental and regulatory aspects of the wholesale level also apply to retail, whether for the large corporations like Google and Microsoft wanting a certain supply of clean energy, or private homeowners that want to install storage or solar, Dillon said.

“Their ability to choose is a market driver; [it’s] a great principle compared to government saying, ‘You’re going to build this traditional huge coal or gas or nuclear plant on the edge of town and running wires through the city,’” Dillon said.

The discussion of the clean energy transition tends to get stuck in a dichotomy of either the Texas model on one hand or vertically integrated markets on the other, said Landon Stevens, director of policy at Conservative Energy Network (CEN), a group of state-based clean energy advocacy organizations.

“There’s actually a lot of different policy decisions that can be made along the way,” said Stevens, who described himself as a “recovering regulator.” He previously served as policy adviser to former Arizona Corporation Commissioner Andy Tobin and his successor, current Commissioner Lea Marquez Peterson.

It’s a big opportunity when about half of the country is trying to consider what the next market designs look like, he said, referring to the West.

The West is considering “an RTO model that we designed in 1995, and I would say there’s probably a lot of changes you can make to that model that would be more tailored to today’s solutions,” Stevens said. “We need to look at those really long and hard, and that’s where we have a lot of research coming down the pipe. … What does an RTO 2.0 look like, or is there a whole new model paradigm that we need to consider to incorporate some of these new technologies and leave room for that innovation?”

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Governor Names Next California PUC President

California Gov. Gavin Newsom on Monday named his senior energy adviser, Alice Reynolds, as the next president of the California Public Utilities Commission, a body under intense pressure to ensure resource adequacy, prevent utilities from igniting wildfires and shepherd the state through its transition to 100% clean energy by 2045.

“As my lead energy policy expert, Alice has been indispensable in our work to move California toward a cleaner, affordable and reliable energy future, navigate the bankruptcy of the state’s largest investor-owned utility [Pacific Gas and Electric] and accelerate the state’s progress toward meeting our clean energy goals, among other critical issues,” Newsom said in a statement. “I look forward to her leadership as President of the California Public Utilities Commission.”

Reynolds will replace outgoing President Marybel Batjer on Dec. 31. Batjer announced in September that she planned to step down at the end of the year with five years left in her seven-year term. (See California PUC President to Step Down.)

“I have had the privilege of serving four California governors and have given my all to public service for many decades,” Batjer wrote in a letter to CPUC staff. “I am now ready for a new challenge and adventure.”

Newsom had named Batjer, then the state’s government operations secretary, to fill out the term of retiring President Michael Picker in July 2019. He reappointed her to a full term last year.

Under Batjer’s leadership, the CPUC oversaw PG&E’s Chapter 11 reorganization and obtained greater oversight of the troubled utility, which has been blamed for starting catastrophic wildfires since 2015. The commission worked to prevent more wildfires through vegetation management and grid-hardening and to rein in the overuse of public safety power shutoffs.

The CPUC came under fire for failing to anticipate the capacity shortfalls that have plagued the state in the past two years and are expected to continue next summer. Commissioners responded by ordering record amounts of procurement, including requiring the state’s three big investor-owned utilities — PG&E, Southern California Edison and San Diego Gas and Electric — to find 11.5 GW of new resources by mid-decade. (See CPUC Orders Additional 11.5 GW but No Gas.)

As adviser to Newsom since early 2019, Reynolds was instrumental in PG&E’s reorganization and in enacting a controversial measure, Assembly Bill 1054, that sought to shore up the IOUs against wildfire liability through a state insurance fund. (See Calif. Wildfire Relief Bill Signed After Quick Passage.)

Reynolds was former Gov. Jerry Brown’s senior adviser for climate, the environment and energy from 2017 to 2019 and served as deputy secretary for law enforcement and general counsel at the California Environmental Protection Agency (CalEPA) from 2011 to 2017.

A lawyer by training, she worked for two law firms from 1998 to 2001 and as a state prosecutor before taking the job with CalEPA.

Industry and environmental groups congratulated Reynolds or offered praise on her appointment after Newsom’s announcement.

“We have worked with Alice Reynolds during her years of service with Governors Brown and Newsom and believe that she is superbly qualified to lead the California PUC at a critical time,” Victoria Rome, director of California government affairs for the Natural Resources Defense Council said in a statement. “She has unmatched expertise on California energy issues. Over the next few years, the PUC will help ensure that California’s clean energy transition is built on a foundation of reliable electric service and equity.”

Others noted the difficult job ahead.

“California has a lot of work to do to make its energy more reliable, affordable, and cleaner, and we look forward to working with the CPUC to make that happen,” Advanced Energy Economy tweeted.

The state Senate must confirm Reynolds’ appointment as CPUC president, a position that pays $229,000 per year.