Maine Gov. Janet Mills last week released the first of a two-part seaport study and directed her administration to assess the state’s port infrastructure and the investments needed in them to enable offshore wind activity.
“The goal was to develop a viable offshore wind port concept that could proceed to the permitting and design phase,” said Matt Burns, director of ports and marine transportation at the Maine Department of Transportation (DOT).
For the study, the DOT evaluated four sites at the Port of Searsport and determined that two — Sears Island and Mack Point — were “clear leaders,” Burns told the Maine Offshore Wind Roadmap’s ports working group during its latest meeting Nov. 19.
A 330-acre, undeveloped transportation and marine development parcel at Sears Island owned by the DOT is the “preferred site,” he said. It has 9,000 linear feet of available water frontage and site access for vessels via Penobscot Bay, according to the study.
Development for the parcel would include construction of a marshalling and fabrication facility with a heavy-lift bulkhead and about 30 acres for a component laydown and staging area. Mack Point, which is across Penobscot Bay on the mainland, also could be available for an additional support facility, Burns said.
The study estimated that a two-phase, six-year development plan for Sears Island would cost $284 million.
“Cost is going to be a huge issue,” Burns said. “These facilities are not cheap, and we would certainly be pursuing federal funding to help assist us with constructing something of this scale.”
A second port study, which is underway now, will examine other sites that can provide a supporting role to a central port hub, such as Searsport, according to Burns.
The DOT is looking at the ports of Portland and Eastport as part of the second study.
“Once we actually have an array that’s being installed or is in play in the Gulf of Maine, we’re going to need a place for” manufacturing and operations and maintenance facilities, Burns said. “We really see this as a statewide effort.”
The study recommends that Sears Island site be evaluated for potential phased development through an environmental assessment, geotechnical study and preliminary design work.
“We look forward to realizing the economic benefits of putting more port into Searsport, while we preserve the ecological and recreational aspects of what makes us special,” Searsport Town Manager James Gillway said in a statement.
Part of Sears Island is protected under a conservation easement, and much of that property is used for recreation and nature conservancy, according to Burns.
“We thought it was appropriate for this study to also explore how a development on the transportation parcel could complement some improvements for education and maintenance on the conservation side of the island,” he said.
The study acknowledged that there will be “many differing viewpoints” on amendments to the conserved property, and it called for discussion between the DOT and concerned parties in developing a final plan.
In a filing with FERC on Wednesday, members of the Southeast Energy Exchange Market (SEEM) confirmed they would implement the “transparency enhancements” to the market that they previously promised, despite the lack of a commission order requiring them to do so (ER22-476).
The SEEM agreement went into effect Oct. 12 after FERC split 2-2 on approval. With the commission unable to form a majority for or against it, the agreement became effective under Section 205 of the Federal Power Act. (See SEEM to Move Ahead, Minus FERC Approval.) FERC has since approved revisions to four of the participating utilities’ tariffs implementing the special transmission service used to deliver the market’s energy transactions. (See FERC Accepts Key Tariff Revisions to SEEM.)
Earlier this year SEEM members — a group of utilities that includes 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) — proposed several modifications to the agreement in response to FERC’s deficiency letter and objections from the market’s detractors. (See SEEM Members Offer Rule Changes.)
Changes Offered in Previous Deficiency Response
Because the agreement entered operation by default rather than via a commission order, it did not include any of those modifications; however, according to the latest filing, SEEM members “have always intended to fulfill the commitments” they made both because “it is the right thing to do and … to do otherwise might raise questions” regarding the market’s legitimacy. The proposed changes include:
weekly submissions of confidential market data to FERC and the market auditor, and periodically providing additional information publicly;
disclosure of regulators’ questions and answers, as well as market auditor reports, to participants, subject to restrictions on access to confidential information by marketing function employees;
clarification that available transfer capacity calculated by participating transmission providers must be provided to the SEEM administrator and must be used in the algorithm for each leg of any contract path to ensure transmission will not exceed available capacity;
updating market auditor functions to clarify that the auditor will verify compliance with market constraints;
use of randomization to resolve ties or ambiguities between multiple bids or offers;
prohibiting market-based rate holders from providing false or misleading information to the SEEM administrator or market auditor; and
implementing a posting requirement for complaints submitted to the market auditor.
In addition, members promised to make the “just and reasonable standard” the default for most SEEM rules rather than the lower Mobile-Sierra public interest standard. The use of Mobile-Sierra was a sticking point for FERC Chair Richard Glick, who in a statement explaining his vote against SEEM said the commission’s monitoring capabilities and enforcement authorities would be “hamstrung” by the doctrine’s application. (See FERC’s Christie Accuses Glick, Clements of Prejudice for RTOs.)
Commissioner Allison Clements also cited the use of Mobile-Sierra in her statement against SEEM. Several of the market’s most vocal critics have criticized the doctrine as well, even going so far as to say that proponents’ offer to voluntarily restrict the application of Mobile-Sierra would still unacceptably limit market participants’ negotiating power. (See SEEM Opponents File Rehearing Requests.)
Nov. 25 Effective Date Requested
SEEM members asked that their proposed changes become effective Nov. 25, one day after their filing, and that the commission waive prior notice requirements in order to allow the new revisions to become effective before the incurrence of vendor costs, which could begin as early as next month. Members noted that if prior notice requirements are not waived, the commission is required to act on the filing within 60 days. They also reminded the commission that Section 205 mandates that FERC “not go ‘beyond approval or rejection’” of an amendment proposal.
“Rejection or acceptance of the amendments are the only permissible outcomes of this Section 205 proceeding,” the members said. “The commission cannot, in this proceeding, revisit the justness and reasonableness of the existing provisions of the [SEEM] agreement, except and only to the extent that the members propose … to change such provisions.”
FERC is also considering a rehearing request filed earlier this month by two ad hoc groups of SEEM’s opponents. The fate of both filings may be impacted by the U.S. Senate’s recent confirmation to FERC of D.C. Public Service Commission Chair Willie Phillips, who will join Glick and Clements as the third Democrat on the commission. (See Senate Confirms FERC Nominee Willie Phillips.)
The Vermont Climate Council is scrambling to update its draft action plan after Connecticut, Massachusetts and Rhode Island said they no longer back the Transportation and Climate Initiative Program (TCI-P).
“It’s unclear whether or not there will be a viable regional marketplace for this program to move forward,” Peter Walke, commissioner of the Department of Environmental Conservation, said Nov. 23.
The council is poised to consider adoption of the state’s first climate action plan Dec. 1, and joining TCI-P had been a keystone strategy to fund transportation emission-reduction programs in that plan.
Now, however, the council will amend the language around TCI-P as it appeared in the draft plan prior to the council’s latest meeting last week.
Connecticut Gov. Ned Lamont on Nov. 16 announced that he would not support TCI-P-enabling legislation next year. On the heels of Lamont’s announcement, Massachusetts Gov. Charlie Baker said he would remove his support for the program given the lack of broad participation among states. And Rhode Island Gov. Dan McKee said on Nov. 19 that his administration would no longer pursue the initiative.
Vermont has been a member of TCI for over a decade, but it never fully signed on as a program participant. Massachusetts, Connecticut, Rhode Island and D.C. agreed last year to launch TCI-P, which would cap regional transportation emissions and create a market for emissions allowances.
Members of the Vermont Public Interest Research Group said in a Nov. 22 statement that they are disappointed by the latest developments in the region, saying it “ignores our state, regional and national climate commitments.”
“It also ignores broad public support across the region for TCI-P, as confirmed by multiple independent polls and the groundswell of support expressed during the TCI public comment period,” they said.
Despite the latest setbacks, Vermont’s action plan will not abandon the potential for participation entirely, Walke, who is co-chair of the Cross-sector Mitigation Subcommittee, told the full council.
“The reality is that without TCI-P in the plan, it leaves a significant hole in the emissions reductions picture,” Walke said. “We are not proposing alternatives at this time because there’s work that needs to be done to validate those alternatives.”
While the council will monitor the fate of TCI-P and evaluate other options, there likely will not be any concrete actions ready for inclusion in the plan that’s set for adoption next week.
“There could be a lack of clarity and certainty around the future of TCI-P for a while, and at some point, we are going to need to have a plan B for one or more primary strategies that can meet the emissions reduction we were counting on TCI to have had by a date certain,” said council member Jared Duval, who is executive director of the Energy Action Network.
Council members will have one more opportunity on Monday to discuss the changes in the plan before they must vote on whether to adopt it.
As it stands, the updated draft plan language says that joining TCI-P is a “critical component” of the transportation sector strategy, and Vermont should “remain at the table” in finding a pathway for the program’s implementation. The update also allows for “additional parallel work” that is necessary to find a comparable cap-and-investment program for transportation fuel or other policies that will have similar outcomes to TCI-P.
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.
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.”
“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.”
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.)
Newsdayreported 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.
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.
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
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.
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.
Clockwise 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?”
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.
