The Northwest Power Pool began forming committees last week to nominate directors and shape program design for its resource adequacy effort designed to serve much of the Western Interconnection.
The new stakeholder committees will start to prepare the program’s governance for an initial nonbinding “beta test” of the Western Resource Adequacy Program (WRAP) starting next winter and should be in place before NWPP seeks FERC approval for binding phases of the program in late 2023, organizers said.
In standing up the WRAP, NWPP has determined that it must meet FERC requirements for the group’s governance and committee structures as well as for the program’s design, including the appointment of an independent board of directors to replace its existing board staffed by member representatives. (See RA Program will Require Restructuring of NWPP.)
“We see the need ahead of the nonbinding program [and] ahead of the FERC filing … of setting up committees,” Sarah Edmonds, director of transmission services at Portland General Electric, said Wednesday during an NWPP meeting. “We see the need to get those committees going ahead of official approval of the governance structure, [and] we expect … that what we’re doing will be very easily translatable into the future FERC jurisdictional governance program with little to no changes.”
The two new committees — the Program Review Committee and the Nominating Committee — will be composed of representatives from various sectors, including independent power producers, public interest organizations and advocates for retail customers.
The Program Review Committee “will be charged with receiving, considering and proposing design changes to the WRAP and will serve as the clearing house for most recommended design changes,” NWPP said in a statement.
The Nominating Committee will help establish an independent board by working with an executive search firm to identify candidates.
In Wednesday’s meeting, NWPP Director of Reliability Programs Rebecca Sexton-Kelly asked sector representatives if they wanted to organize among themselves or needed NWPP’s help finding committee members.
Spencer Gray, executive director of the Northwest & Intermountain Power Producers Coalition, volunteered NIPPC to lead committee selection on behalf of independent power producers and marketers.
Nicole Hughes, executive director of Renewable Northwest, offered to head the public interest sector’s selection process. And Josh Weber, an attorney representing the Alliance of Western Energy Consumers, said AWEC would lead industrial sector organizing.
NWPP is planning to help the retail advocacy sector and a sector representing certain types of load-serving entities to find potential committee members.
‘Unacceptable Loss of Load’
NWPP began examining the idea of a Western RA program in 2019, as shortfalls loomed because of the retirement of fossil fuel plants, especially coal-fired plants, and the spread of weather-dependent wind and solar resources.
“Soon, areas in the West may face a capacity deficit of thousands of megawatts,” NWPP CEO Frank Afranji said in an April 2020 meeting hosted by the Committee on Regional Electric Power Cooperation and the Western Interconnection Regional Advisory Body. “Deficits of that magnitude may result in both extraordinary price volatility and unacceptable loss of load.”
The WRAP is intended to increase visibility into existing RA conditions in the West, addressing concerns among industry stakeholders and state regulators that load-serving entities are unknowingly relying on the same capacity resources without realizing it, threatening system reliability during periods of scarcity.
The program is designed to provide participants a framework in which to access capacity resources when a participant is experiencing an extreme event.
In December, NWPP took its first steps in implementing WRAP by inviting participants to submit resource data for a nonbinding phase of the capacity market, which the organization says will serve as a “beta test” for a final program design. (See Implementation Underway for NWPP’s Western RA Market.)
NWPP noted that the move to implement the WRAP officially kicks off its working relationship with SPP, which has been retained to administer the program. (See SPP to Operate NWPP’s Resource Adequacy Program.)
Last week’s start to forming key committees was the next big step.
“The NWPP is looking forward to getting stakeholders engaged in governance and program design updates in this hands-on way,” COO Gregg Carrington said in a statement. “It’s an exciting evolution of the organization.”
Members Approve $1.04B 2021 ITP, Withhold $409M Project’s NTC
SPP stakeholders last week endorsed the grid operator’s latest transmission planning assessment, but not before withholding construction approval of a 345-kV, double-circuit project in West Texas.
The Markets and Operations Policy Committee on Jan. 10 agreed with a pair of working groups’ earlier recommendation to not issue notifications to construct (NTCs) to the 150-mile Crossroads-Phantom project.
The committee also withheld NTCs to a pair of transformer projects in New Mexico.
The 2021 Integrated Transmission Planning (ITP) report found the double-circuit project would provide twice the capacity of a single circuit, while “incrementally” increasing the engineering and construction (E&C) cost from $330.2 million to $409.9 million, a 23.9% increase. According to the 10-year assessment, the project would provide a low-resistance, parallel path for delivery of low-cost energy to Southwestern Public Service’s SPS South load pocket.
The 2021 ITP portfolio includes 28 projects costing more than $1 billion. | SPP
“For an additional cost increase, you’re getting two times the capacity and reserving some future options a little more effectively,” said ITC Holdings’ Alan Myers, chair of the Transmission Working Group (TWG).
The project is meant to address one of two targeted areas in the 2021 ITP where SPP found voltage-stability issues because of isolated load and above-average load projections, both related to oil and gas exploration: the Permian Basin in West Texas and eastern New Mexico, and the Bakken Formation oil fields in North Dakota.
However, load-projection errors, related to how load was allocated to individual substations, were discovered late in the process. Myers said the error was found in the 2022 ITP models, too late for staff to do a full impact analysis.
“So there was no time for staff to do like a full redo, if you will, of the analysis,” he said. “It was disproportionately, I believe, impactful to the loads down on that southern portion of the system.”
Myers said the TWG and Economic Studies Working Group spent a total of 7.5 hours in December discussing the NTCs for Crossroads-Phantom and the New Mexico transformers. Both groups endorsed the ITP in January but recommended the NTCs not be issued.
Staff, on the other hand, said they believe the Crossroads project is the best overall solution for the region. They requested the project still be considered for an NTC with conditions.
MOPC tabled and then un-tabled the proposal before finally approving the 2021 ITP by a vote of 56-5, with four abstentions. It recommended further evaluation of the Crossroads-Phantom project and that it be brought back to the committee during its July meeting.
The ITP portfolio includes 28 new projects and 380 miles of new 345-kV lines at an E&C cost of $1.04 billion. Staff said the projects would solve 185 system needs with a 5.3 to 5.7 benefit-to-cost ratio.
The committee also approved staff’s recommendation to re-baseline the delayed 2022 ITP by performing a reliability-only assessment, resuming full studies with the 2023 and 2024 ITPs.
SPP says its proposal to rebaseline the 2022 ITP will enable 2023 ITP work to begin early. | SPP
MOPC directed staff to work with the ESWG and TWG to review the tariff and scope documents to find further improvements to ensure timely completion of current and future ITP assessments. Staff are currently working on three ITPs, for 2021, 2022 and 2023. The 2022 plan is already behind schedule because of 2021 ITP constraints, and 2023 is at risk because of the previous two assessments’ delays.
SPP engineer Nick Parker said a task force that developed recommendations to improve the planning process “did a good job getting us close” and that staff were only a few months off, despite remote work during the COVID-19 pandemic and their other transmission-related requirements. (See SPP Strategic Planning Committee Briefs.)
“Certain stuff hit us all at once,” Parker said, adding that SPP has since added manpower to help manage the workload.
Casey Cathey, SPP’s system planning director, reminded members that ITP studies are on 27-month cycles so that a full assessment can be brought to MOPC every October.
“We did so in 2019 and 2020. The process is not broken,” Cathey said. “It’s really a 30-month process because of the contingencies that happen. Things happen. COVID happened, and that pushed things to where they’re at. Worst-case scenario, we do nothing and we have a 30-month process squeezed into a 27-month process, and you end up skipping an ITP once every four calendar years.”
MOPC also endorsed the 2021 ITP assessment report as having met the tariff’s requirement to complete the planning process.
Storage Accepted as Transmission
Stakeholders moved to accept storage resources as transmission assets in endorsing a recommendation (RR476) from the Electric Storage Resource Steering Committee (ESRSC).
The measure adds another acronym to SPP’s lexicon by defining the assets as “storage as transmission-only assets” (SATOAs). It requires SATOAs to register as market storage resources in the Integrated Marketplace to account for their injections and withdrawals. They will not be dispatched in the market and are only to receive charges and credits for the energy and over-collected losses; revenue or losses from the injections and withdrawals will be added back to the SATOA’s annual transmission revenue requirement.
EDP Renewables’ David Mindham said that while RR476 installs guardrails that prevent the assets from having an “overly burdensome” effect on the market, it “missed an opportunity.”
“By automatically assigning [SATOAs] to transmission owners, the developers could have provided a lot of experience in bringing these assets online,” Mindham said. “They could have provided this as a service and a competitive process probably more cheaply, especially for the limited uses that they’re intended for.”
He asked whether local issues outside the transmission-planning process would prevent the storage assets from coming online through the process.
“I don’t think that this process would prevent it from being put together,” SPP’s Joshua Pilgrim said. “The general consensus, since the device is only meant to run for post-contingency situations, is that their impact on local dispatch profiles would be minimal. They’re not designed to be run all the time. Most of the time, they’re waiting.”
MOPC Chair Denise Buffington, who also chaired the ESRSC, said storage devices’ multiple uses will demand a future conversation between staff and stakeholders.
“We need to get a baseline understanding out there for what the asset can do,” she said. “Once we get that baseline, we can start building on it. Part of the problem with some of the discussions we’ve had about the model is where do you start? Then, it starts to get circular.”
MOPC passed the measure by a 53-3 margin, with 10 abstentions. The Regional State Committee will have to weigh in on RR476’s rate sections.
The committee also endorsed an ESRSC policy paper that sets the methodology for accrediting hybrid generating facilities that qualify as capacity, SPP’s first such policy. The paper proposes that hybrid components (primarily wind, solar and storage) be studied and allocated separately, with four-, six- and eight-hour duration products. The proposal will consider a facility’s investment tax credit and its ability to charge from the grid, beginning with the 2023 summer season.
SPP defines a hybrid facility as two or more resources behind the same interconnection point, where at least one of the resources is not classified as storage.
Golden Spread Electric Cooperative’s Natasha Henderson, chair of the Supply Adequacy Working Group, said there are currently no hybrid facilities on the system, but they are expected to become more prevalent over the next five years. Given their multiple configuration possibilities, she said, the SAWG worked to ensure the facilities are not over or under accredited.
The stakeholder group will now work on criteria and develop tariff language. “That’s when we will debate the issue,” Henderson said.
“The policy’s basically been debated already,” American Electric Power’s Jim Jacoby said. “If people go out and make business decisions based on [the paper] and then you change the rules on them, they’re not going to be happy.”
Still, members approved the policy paper 49-7, with five abstentions.
Order 2222 Compliance Filing Endorsed
MOPC endorsed a revision request (RR468) that approves a compliance filing for FERC Order 2222 as SPP prepares to allow distributed energy resource aggregators to participate in its markets.
Members approved the measure by a 58-3 margin, with five abstentions, with some noting that did not mean they approved of FERC’s order itself.
“Our vote to approve is understanding that this is a compliance filing in response to a FERC order and not … endorsing the FERC order itself,” Oklahoma Gas & Electric’s Usha Turner said.
DeWayne Todd, with the Advanced Energy Management Alliance, said his organization remained concerned about the compliance proposal because “it does not really address some of the requirements of 2222 relative to reducing barriers [to DER participation].” He cited imposed telemetry requirements for every aggregation’s size, restrictions to single nodes and a registration process “that doesn’t provide a lot of value” because it’s duplicative to subsequent steps in the registration and participation process.
The compliance filing allows a DER aggregator to register its aggregation as a valid resource type if it meets technical and operational requirements, with the aggregator subject to the same service provision rules as other resources within that type. Aggregations must be at least 100 kW and can include a single DER. The aggregations must include real-time telemetry and settlement quality metering.
In what may be a nod to further pushback at FERC, SPP plans to keep alive the task force responsible for RR468’s tariff modifications until it receives the commission’s response. Assuming approval, staff plan to implement the tariff changes in early 2024.
The compliance filing was originally due last July, but FERC, noting the absence of opposing intervenors, granted SPP an extension until April 28 this year (RM18-9). (See FERC OKs Delay on Order 2222 Compliance.)
The committee also easily approved RR480, which gives the industry expert panel evaluating responses to SPP’s competitive transmission process the option to use incentive points in scoring the proposals. Members raised concerns that the expert panel could select a project other than the highest-scoring proposal, but they still gave the measure 93% approval.
JTIQ, Tx Value Staff Reports
David Kelley, SPP’s director of seams and tariff services, said the RTO’s collaborative work with MISO addressing their overflowing interconnection queues has identified a project portfolio that can relieve constraints on either side of the seam. Thirty-three of those constraints are in MISO’s footprint, and the other 17 are in SPP’s.
The grid operators began their joint targeted interconnection queue (JTIQ) study in September 2020, hoping to find interregional transmission projects to alleviate queues filled with renewable resource requests.
“The key theme was the development of generation along our seams and the difficulties many generation developers have found in accomplishing that,” Kelley said. “We happen to be very blessed in our part of the country with low-cost renewable generation; … the transmission system is at capacity along the seam.”
Kelley said the “optimized” portfolio has a preliminary combined load-adjusted-production-cost (APC)-to-cost ratio of 0.45. A report is being drafted for stakeholder review by the end of the month. The RTOs will schedule meetings with stakeholders to review the full results before seeking board approval for the plan.
A cost-allocation methodology is under development, Kelley said, and will reflect input from load-serving entities and generation developers. “We should reasonably assign those costs to those who will benefit,” he said.
Cathey told MOPC that an update to 2016’s value of transmission analysis determined that the $3.35 billion of installed transmission from 2015 to 2019 resulted in $27.2 billion in net present value of quantified benefits over 40 years and a 5.24 benefit-to-cost ratio.
The earlier study, dubbed by the Brattle Group as a “path-breaking effort,” found a net present value of $16.6 billion in benefits from projects installed from 2012 to 2014, a benefit-to-cost ratio of 3.5. (See SPP Begins Promotional Campaign to Tout Transmission Value.)
“I think that’s pretty reasonable if you think about what’s gone on in the last five years, especially with all the wind [resources] in our region,” Cathey said.
The new study simulated 57 days of production, compared to 38 in the earlier study, and captured benefits from line rebuilds and transformer additions in addition to the new infrastructure. Operations and engineering staff, “squeezing” in the analysis along with their other work, evaluated APC savings, reliability and resource adequacy benefits, increased wheeling revenues, reduced on-peak losses, and optimal wind generation development.
Cathey said the report is 95% complete. Staff will share the study and findings with other stakeholder groups before seeking endorsement from the Strategic Planning Committee in April. The report will then be shared with a wider audience.
Engineering Humor
A comedy routine (Or was it a comedy of errors?) broke out during MOPC’s final four-hour segment. Cathey, an engineer by trade, took advantage of a momentary pause before one of his presentations to try out his standup chops.
“Two investors were talking and one asked the other, ‘What do you think about this solar craze?’” Cathey said. “The other said, ‘Well, it’s not going to happen overnight.’”
Greeted by silence, he moved on. Cathey’s listeners, punch-drunk after hours of virtual conversation, didn’t.
“You just can’t hear all the laughter,” Lincoln Electric System’s Dennis Florom said in the virtual meeting app’s chat function.
Others chimed in with their own versions of “dad jokes.” Energy consultant Simon Mahan tweeted to SPP to “please let Casey know Energy Twitter loves him.”
MOPC’s New Faces
MOPC welcomed several new members, including two representing SPP’s newest members: Ray Bergmeier, with Sunflower Electric Cooperative’s competitive Konza Transmission, and Matt McCoy, with Southern Star Central Gas Pipeline. The pipeline company joined the RTO late last year as its 107th member. (See Southern Star Gas Pipeline Joins SPP.)
The committee’s other new members stepped in for their companies’ previous representatives. They are Western Area Power Administration’s Steve Sanders for Lloyd Linke; AEP-Southwestern Transmission Co.’s Brian Johnson for Chad Heitmeyer; Exelon’s Jason Barker for Chris Lyons; Walmart’s Jim Staggs for Holly Rachel Smith; Northeast Texas Electric Cooperative’s Ron Ray for Rick Tyler; and Mor-Gran-Sou Electric Cooperative’s Trisha Samuelson for Robert Kelly.
$73M Tab for 161-kV Rebuild
Members unanimously approved the consent agenda, which included the Project Cost Working Group’s recommendation to re-baseline the 31-mile, 161-kV Neosho-Riverton rebuild project’s costs from $48.3 million to $73.1 million. The line is historically SPP’s highest congested path, but rising steel costs and delivery issues threaten its in-service date of October 2023.
The agenda’s approval also resulted in MOPC’s endorsement of the Transmission Owner Selection Process (TOSP) Task Force’s suggestion to sunset next January. The TOSPTF has been evaluating improvements to SPP’s competitive transmission process, several of which were among the eight revision requests on the consent agenda:
RR450: provides guidance for using operating guides in the planning horizon.
RR469: corrects the Integrated Marketplace protocols’ settlements language defining the variables RtDesiredEn5minQty and RtOrigLmp5minPrc to clarify that the real-time desired energy five-minute quantity (RtDesiredEn5minQty) uses the dispatchable LMP and the real-time original locational five-minute price (RtOrigLmp5minPrc) uses the LMP.
RR470: corrects settlements language in the Marketplace protocols by removing an erroneous “minus” in section 4.5.9.35 (Real-Time Ramp Capability Non-Performance Amount) and correcting the variables in section 4.5.12 (Revenue Neutrality Uplift Distribution Amount).
RR471: automatically suspends the TOSP if a re-evaluation is approved equal to the days the re-evaluation requires.
RR472: requires that the TOSP’s industry expert panel Direction to Respondents document be created and published during a request for proposals response window.
RR473: cleans up the TOSP’s governing documents to more accurately capture their intent and execution.
RR478: adds flexibility to the resource planning process by allowing alternative methods outside of software, as required by the ITP manual.
RR479: clarifies staff’s steps when reviewing submitted detailed project proposal and determining if they qualify for incentive points under SPP’s competitive transmission process.
Just hours after taking office on Saturday, Virginia Gov. Glenn Youngkin (R) signed an executive order aimed at taking the state out of the Regional Greenhouse Gas Initiative, the 10-state cap-and-trade compact whose members have seen their carbon emissions decline by 50% since the program began in 2009.
The executive order sets up an expedited, 30-day process under which the departments of Environmental Quality (DEQ) and Natural Resources (DNR) will reanalyze the costs and benefits of RGGI and draft a proposed emergency regulation for the State Air Pollution Control Board to repeal its 2019 rules allowing the state to join the initiative.
Youngkin also ordered the departments to notify RGGI of the state’s intent to withdraw and “take all necessary steps so that any proposed regulation to the State Air Pollution Control Board can be immediately presented for consideration for approval for public comment.”
The order tacitly acknowledges what critics have argued since Youngkin first vowed to take Virginia out of the initiative during a speech in December: The governor does not have the authority to unilaterally order a withdrawal. (See Youngkin Vows to Pull Va. from RGGI.) He will have to work through a regulatory process that has some significant roadblocks built into it.
For example, Youngkin has based his argument against RGGI primarily on its cost to the state’s utilities and their customers. As part of its participation in RGGI, the Air Board has set a cap on carbon emissions in the state, which declines each year through 2030, and utilities must buy carbon allowances to cover emissions above the cap.
As noted in the executive order, Dominion Energy has estimated that it will have to pay $1 billion to $1.2 billion on allowances in the next four years, which has already raised residential rates $2.39/month. The utility had applied to the State Corporation Commission for an even higher add-on — $4.37/month beginning in September — to recover its costs for RGGI, but it pulled the application after Youngkin’s speech.
But how costs and benefits are calculated is sure to be a flashpoint for former EPA Administrator Andrew Wheeler and Michael Rolband, Youngkin’s picks to head the DNR and DEQ, respectively.
To date, Virginia has earned $227.6 million in proceeds from the auction of carbon allowances, as recorded on the RGGI website. That money is split between the state’s community flood preparedness program (45%) and energy efficiency measures for low-income households (50%). The remaining 5% covers administrative expenses.
In December, former Gov. Ralph Northam (D) announced that RGGI funds would provide $24.5 million to 22 local government organizations for flood preparedness projects. Another $15.2 million is filling a gap in state programs for weatherizing low-income housing, and $5.9 million is being used to preserve or build hundreds of affordable housing units, according to the Virginia Department of Housing and Community Development.
“Were Virginia to withdraw, we would lose hundreds of millions to help working-class families cut their electric bills,” said Harry Godfrey, executive director of Advanced Energy Economy Virginia.
Health benefits related to emission reductions produced by RGGI are also likely to be raised by environmental advocates. A 2020 study from Columbia University’s Mailman School of Public Health found that, in addition to carbon emissions, the initiative is cutting particulate matter, which is decreasing childhood asthma and premature birth rates. The study estimated the benefits at $191 million to $350 million across the RGGI states.
A Packed Board
Implementation of the executive order will also depend on leadership at the DNR and DEQ, which could be yet another hurdle.
Wheeler, who led EPA during the Trump administration, will first have to clear confirmation hearings in both houses of the Virginia General Assembly. Republicans now hold the House of Delegates, but Democrats have a slim majority in the Senate. (See Youngkin Taps Trump’s Former EPA Chief to Head Virginia DNR.) Similarly, because the Air Board is part of the DEQ, the less controversial Rolband might also face questions about RGGI at his confirmation hearings.
But the board itself could be the biggest obstacle to Youngkin’s effort to withdraw Virginia from RGGI, regardless of how fast he pushes for an emergency rollback. The original vote on the RGGI regulations was 5-2, and the seven-member board is now packed with Northam appointees. The new governor’s first opportunity to change the board’s composition will come in June, when Vice Chair Kajal B. Kapur’s and Gail Moore’s terms end. Youngkin might have to wait until 2024 to get a clear majority on the board.
Further, the DEQ successfully defended RGGI from a legal challenge from the Virginia Manufacturers Association. As reported in the Virginia Mercury, the Richmond Circuit Court in July rejected the association’s argument that RGGI is an illegal carbon tax on utility customers.
Virginia Democrats quickly voiced opposition to withdrawal. A statement on the state party’s Twitter feed declared that “Glenn Youngkin is already failing Virginia on climate change. His short-sighted decision to remove Virginia from the RGGI is purely partisan and it makes clear that he has no clear plan to combat climate change or invest in a clean energy future in Virginia.”
Nate Benforado, senior attorney at the Southern Environmental Law Center, called the executive order “a dead end.”
“For a new governor who has pledged to help Virginia communities struggling with climate change, this is a shocking and troubling first action out of step with what Virginia communities need,” Benforado said in an email statement.
Meanwhile, a tweet from the Richmond chapter of the Neoliberal Project noted that Del. James Morefield (R) recently introduced a bill (HB 5) that would cut the RGGI allocation for community flood preparedness from 45% to 40% and redirect that 5% to a flood relief fund that would compensate private property owners for flood damage.
LANSING, Mich. — Michigan would have at least 2 million electric vehicles and get 50% of its electricity from renewable energy by 2030 — while ending coal use by 2035 — under a draft climate proposal sent to Gov. Gretchen Whitmer (D) Friday.
The Department of Environment, Great Lakes, and Energy’s (EGLE) proposed Healthy Climate Plan, a roadmap for reaching carbon neutral status by 2050 required by a 2020 executive order by Whitmer, will be open to public comment through Feb. 13.
“Michigan communities and families are taking hit after hit from power outages, extreme heat events, flooding and sewer backups caused by intense rains,” the report said. “Our farmers are struggling to adjust and survive as temporary thaws result in frozen fruit blossoms thinking spring has come early, drenching storms inundate fields one day and then disappear into extended periods with no rain at all, and new insects migrate from warmer climates each year threatening our gardens, forests and crops. Disease-carrying ticks — in places we have never seen them and in previously unimaginable numbers for our state — add hassles and health risks to the outdoor [adventures] so many of us cherish.”
Input
In a letter accompanying the proposal, EGLE Director Liesl Eichler Clark said the plan was “first and foremost a Michigan plan.”
“We heard from environmental justice, public transit, and local food advocates; an array of business executives and labor leaders; academic experts and local government officials; and concerned residents of all political persuasions and walks of life,” she said.
The Council on Climate Solutions — 14 residents and representatives from the Departments of Agriculture and Rural Development, Labor and Economic Opportunity, Natural Resources, Transportation, Health and Human Services, Treasury and the Public Service Commission — provided detailed recommendations, along with the Climate Justice Brain Trust and others.
Clark, who chaired the climate council, called the proposal comprehensive, impactful and considerate of how residents’ pocketbooks will be affected.
But in reviewing the draft — which winnowed down dozens of proposals made by the council’s workgroups on issues like transportation, buildings, agriculture and equity — some council members urged the state to take bolder action.
“Can we make this more aspirational?” Jonathan Overpeck of the University of Michigan, one of the more outspoken council members, said at a meeting Tuesday. Proposals such as permitting coal use until 2035 allow “people to say we’re just kicking it down the road,” he said.
The council will review comments on the draft Feb. 22 before issuing the final proposal to Whitmer by March 14.
The draft plan’s main goal is to cut carbon emissions by 28% by 2025 and 52% by 2030 before reaching carbon neutrality by 2050.
Benchmarks
To reach that goal, the plan calls for a 50% renewable energy standard by 2030 and 100% renewable energy in state buildings by 2025, with a 40% reduction in their energy intensity by 2040. Although coal once generated most of Michigan’s electricity, the report noted, only one coal-fired power plant will operate beyond 2028, according to utility retirement schedules.
Michigan’s electric utilities have pledged to cut their carbon emissions by between 80 and 100% by 2050. | Michigan Public Service Commission
The plan also calls for putting solar generation facilities on state-owned land and for the state to help local governments in developing “best practices” for their own solar projects.
To meet the transportation goals, the proposal calls for establishing low-carbon fuel standards and incentives for EV purchasers. It also recommends the state move to more fuel-efficient vehicles and EVs — the Michigan State Police recently tested an electric Ford Mustang as a potential pursuit vehicle — along with aiding local governments and school districts toward climate friendly fleets.
The plan also calls for the state to electrify public transit and boost access to it. The Detroit area has struggled for decades to develop a public transit system that serves both the city and suburbs, and expanding public transit, especially in Metro Detroit, has long been a goal of environmentalists.
To address building emissions, the proposal recommends investing in the Michigan Saves Green Bank, a nonprofit bank set up to help finance home and commercial energy efficient projects.
The proposal says the state, which last updated its building code in 2015, should adopt the 2021 International Energy Conservation Code. It also calls for annual waste-reduction goals of 2% for electricity and 1% for natural gas.
However, the proposal does not call for an end to natural gas use, as some members of the council and environmentalists speaking at public comment sessions through 2021 had called for.
To ensure equity and justice, the plan says 40% of state funding for climate-related initiatives should benefit economically disadvantaged communities, echoing President Joe Biden’s “Justice40” initiative. The state proposal also calls for adjusting job training programs to assist students getting jobs in clean energy.
Economic Impact
The plan portrays its recommendations as essential to both continuing the state’s leadership in automobile production and attracting new businesses, citing research that lists clean energy and sustainability among the top factors in corporate location decisions. It noted Site Selection magazine’s 2021 Sustainability Rankings listed the state at No. 3 for sustainable development, with Grand Rapids and Lansing ranked the U.S.’s No. 2 and No. 6 metros.
The plan also said the changes will ensure that the state — “with the highest concentration of engineers in the nation and a skilled trades workforce ranked in the top ten” — remains a leader in auto production as GM, Ford and Chrysler transition from internal combustion engines to EVs.
Actions Across State Government
The report noted involvement in the climate council of numerous departments in addition to EGLE. “In order to meet the moment, every department must be a climate department,” it said.
EGLE has developed a the “Next Cycle Michigan” initiative to increase the state’s recycled materials supply chain. The Treasury Department has launched the Energy Transition Impact Project to help communities and workers affected by coal plant closures. The Department of Natural Resources is seeking strategies for responding to climate-based threats to natural resources. The Department of Labor and Economic Opportunity expanded job training and workforce development programs to include clean energy and mobility opportunities. The Department of Transportation developed Mobility 2045 to prepare transportation systems for climate challenges and new technologies.
Overall, council members were supportive of the EGLE proposal, but some wanted to see the state act more aggressively and take a leadership position among the states. Phil Roos, CEO of consulting firm Great Lakes GrowthWorks, said Tuesday it was clear the proposal was “really striving for leadership.” But he said the state could adopt greater specificity and earlier deadlines.
Clark called the plan a “living document,” acknowledging that the state will have to make course corrections on the way to 2050. “Some of the solutions to get to a 100% decarbonized economy that deliver good jobs and justice for Michiganders are still very much on the drawing board. But much of the path to carbon neutrality is already well known to us,” she said. “While there are complexities in every aspect of this plan, most can be overcome if we simply commit to getting the job done and equitably sharing the burdens and benefits.”
Massachusetts legislators are considering a bill that would remove the current price cap requirement for new offshore wind project bids.
“The price cap gets in the way of our competitiveness and discourages some developers from offering more creative, diverse and comprehensive proposals,” Gov. Charlie Baker said Tuesday. “Removing it would give bidders the flexibility to offer important added benefits to Massachusetts residents, including economic investment, job creation and reliability solutions, such as transmission and energy storage.”
While the price cap was important to the state’s early OSW procurement process, removing it responds to “signals” in the market, Baker said in hearing testimony before the Joint Committee on Telecommunications, Utilities and Energy.
But moving forward without the cap could risk driving up the comparatively low bids that Massachusetts received in its first three procurement rounds, Sen. Mike Barrett, co-chair of the committee, said during the hearing.
The costs for Sunrise Wind and Empire Wind in New York are 43% higher than Mayflower Wind’s winning $58/MWh bid in 2019 in Massachusetts, according to the U.S. Department of Energy. Revolution Wind’s bid in Connecticut is 68% higher than Mayflower’s bid, while Ocean Wind’s bid in New Jersey is twice that of Mayflower.
Under the current Massachusetts procurement process, regulators cannot approve a contract with a per-megawatt-hour bid, plus associated transmission costs, that exceeds the winning bid price from the previous procurement round.
Barrett urged Baker to consider alternatives to removing the cap, including removing the current requirement that project-related transmission costs be included in the bid price. The number of OSW developers, Barrett said, is too small right now to create market competitiveness. Only four developers have submitted their projects for Massachusetts’ three OSW procurements.
A provision in the procurement process protects the state from high bids by allowing utilities the right to reject a bid they do not like, according to Executive Office of Energy and Environmental Affairs Secretary Kathleen Theoharides.
In such a small market, Barrett said, Massachusetts does not have the luxury of rejecting bids. “It’s basically an oligopoly,” he said.
Lifting the cap may lead to somewhat higher per-megawatt-hour prices, Theoharides said in her testimony, but a price increase would come with more benefits that have been missing from previous bids.
“Getting additional benefits through a more flexible contract … that includes storage … hydrogen … and better interconnections means that ratepayers will save money not just from the one offshore wind contract but across the system with the additional benefits more creative contracts can provide,” she said.
Additional Changes
The bill (H.4204), which Baker filed in October, would transfer the authority for selecting winning bids from Massachusetts’ utilities to the Department of Energy Resources (DOER) to help speed up the contract negotiation process.
“Speed is important in future solicitations and especially important as we pursue somewhere on the order of 15 to 20 GW of offshore wind over the next 30 years,” Theoharides said.
While parties to the contract negotiations for Massachusetts projects “strive for consensus,” she said, disagreements still occur and have stalled the process in the past. If there’s no clear path to a consensus in future negotiations, DOER would be able to consult with an independent evaluator and make a final decision on the procurement.
“This ensures we can press forward swiftly and not allow an overly long process or disagreements to hinder our climate goals,” Theoharides said.
The bill also would codify new provisions to advance diversity and equity that were in the state’s most recent OSW request for proposals.
Bidders had to demonstrate how their projects would ensure the development of a diverse, equitable and inclusive workforce, as well as provide economic benefits for ratepayers, foster economic development and protect environmental justice communities.
“This legislation now captures these changes to the procurement criteria,” Theoharides said.
New Funding
Baker is seeking what he said would be a “game-changing investment” to advance clean energy innovation in the state.
The bill would authorize a $750 million transfer from the state’s COVID-19 response fund to the Clean Energy Investment Fund.
The fund, Baker said, would support emerging clean energy innovators, institutions and businesses; provide funding to colleges, universities and vocational technical institutions; and assist regional employment boards.
The U.S. House of Representatives Committee on Energy and Commerce last week put the Tennessee Valley Authority on notice that it’s concerned about the federal utility’s rates and clean energy goals.
The committee on Thursday sent TVA a letter posing 16 questions on electricity affordability and renewable energy investment. Representatives said they were troubled that TVA wasn’t making enough progress on emissions reduction and that its prices are no longer affordable.
“Specifically, we are concerned that Tennessee Valley residents pay too much for electricity, which particularly impacts low-income households in Tennessee,” the committee wrote. “The committee is also concerned that TVA is interfering with the adoption of renewable energy by its commercial and residential customers and, while it is making progress on decarbonization, it must do more this decade.”
TVA ratepayers’ bills exceed the national average, the committee said. It pointed out that Memphis’ low-income residents have among the highest energy burdens in the country while TVA has scaled back its energy efficiency programs in recent years.
The committee said its questioning serves to “understand the extent to which the disparity between TVA’s low rates and its high customer bills is driven by the organization’s decision to deprioritize energy efficiency and impose fixed fees that keep rates low but cost ratepayers money.”
The committee asked whether TVA would commit to more energy-efficiency measures and requested information on the utility’s current and future energy-efficiency savings and on its local power companies’ energy efficiency programs. It also asked TVA to explain its “underinvestment in solar and wind resources” and detail its wholesale contracts with qualifying facilities under the Public Utility Regulatory Policies Act.
TVA must also furnish information on its rate changes over the last five years and its reasoning behind its 2018 decision to introduce fixed charges to its local power companies.
The committee also said it wants to know “whether TVA plans to update its decarbonization goals and next integrated resource plan (IRP) to comply with President Biden’s executive order and to reflect TVA’s statutory role as a national leader in technology and environmental stewardship.”
It asked what TVA is doing to reduce its natural gas reliance and whether the utility would retire its entire coal fleet earlier than its stated goal of 2035. The committee requested the status of the environmental impact statements for the planned retirements of TVA’s Cumberland and Kingston coal plants.
The Biden administration has a goal of zero emissions in the electricity sector by 2035. TVA has a target to lower its carbon emissions 80% from 2005 levels by 2035; it plans to achieve net-zero carbon emissions by 2050. Clean-energy proponents have criticized TVA’s goals as sluggish. (See Green Groups Pressure TVA on Open Meetings, Decarbonization.)
Finally, the committee asked the utility to explain its participation in the defunct Utility Air Regulatory Group, a lobbying organization that opposed environmental standards. (See TVA Sued Over Contributions to Trade Groups.) The Center for Biological Diversity sued the TVA for passing on membership dues to ratepayers, leading to a FERC notice of inquiry over the appropriateness of recovering trade association dues in utility rates. (See FERC Questions Ratepayer Funding of Trade Association Dues.)
Reacting to the letter, TVA pointed that it has already reduced emissions 63% from 2005 levels and currently supplies almost 60% of its power from carbon-free resources.
TVA spokesperson Ashton Davies said the utility is “actively pursuing emerging technologies, from carbon capture to advanced nuclear, while supporting national clean energy initiatives, such as a robust electric vehicle charging infrastructure.”
Davies also said TVA’s rates are lower than 80% of the nation’s largest utilities.
“Even with TVA’s low energy costs, we recognize the challenge of high-energy burden in our region. TVA is in partnership with 153 local power companies and other organizations to help address the root-causes of this issue, including the need to weatherize and implement energy efficiency measures in buildings and housing,” Davies said in a statement to RTO Insider.
TVA has until Feb. 2 to respond in writing to the committee’s inquiry.
Southern Alliance for Clean Energy Executive Director Stephen A. Smith lauded the committee’s action. In a statement, he welcomed the “renewed Congressional oversight of this unregulated federal monopoly catering to the elite at the expense of the masses.”
“TVA has lost its way in serving the salt of the Earth people of the Tennessee Valley,” Smith said. “With a board of directors that condones the tasteless acts of cutting efficiency programs to help people lower their bills and blocking customer-owned clean energy, while simultaneously awarding excessive salaries and a jet-setting lifestyle to their executives, TVA has lost touch with its core service mission.”
Smith added that the “privileged rubberstamp of the TVA board structure is failing our people.”
Consolidated Edison (NYSE:ED) on Thursday reported its demand response programs increased only slightly in megawatt value last year but dramatically in enrollment, which climbed by approximately 250% compared to that of 2020 (Case No. 14-E-0423).
The company and five other investor-owned utilities in New York filed individual dynamic load management (DLM) performance reports for the state’s Public Service Commission to consider at a hearing Thursday.
Con Ed’s DR programs include its commercial system relief program (CSRP); distribution load relief program (DLRP); auto DLM; term DLM; and the residential Bring Your Own Thermostat (BYOT) program.
Under the DLRP, customers receive notification two hours before a DR event, which is called to address an isolated need. In contrast, the utility’s customers receive notification at least 21 hours before a CSRP event, which is called in response to systemwide peak demand.
Con Ed reported a slight decrease in enrollment in the CSRP and DLRP during 2021, which was the first year of the term and auto DLM programs. The term program is a day-ahead peak-shaving program that incentivizes customers to provide load relief with 21 hours of notice or more, while auto program participants agree to provide load relief on not less than 10 minutes advance notice.
The term and auto DLM programs offer fixed pricing for contract lengths of three to five years and longer-term price certainty compared to tariff-based programs, which can change pricing annually.
The PSC in September 2020 modified DLM implementation plans for the six utilities, all related to storage, saying the initial plans “resulted in a bias towards short-term, low-capital-investment solutions” because of their yearly performance structure (18-E-0130). (See “DLM Incentives Extension,” NYPSC Accepts CLCPA Environmental Review.)
Hearing facilitator Robert Cully, utility engineering specialist at the New York Department of State, asked whether the increase in term and auto DLM enrollments was related to the decrease in CSRP and DLRP enrollments, and whether there was a downward trend in overall enrollments.
A shift in program participation has definitely driven some of the decreases, said Marlon Argueta, energy efficiency program manager at Con Ed, “but when you look at the overall number of available megawatts for DR, it has definitely increased as a whole, and we expect to see that continue over the next few years.”
Aggregators drove the growth in participation by leveraging widespread deployment of advanced metering infrastructure to enroll residential and small business customers in their programs, which make up the majority of new customer enrollments, but each contributes much smaller megawatt reductions.
Shifting Load
David Ahrens, managing director at Energy Spectrum, asked why peaks were different within the four different call windows that Con Ed has in its CSRP program than in previous years.
In general the peaks are shifting more toward the day than the night, Argueta said.
“We are seeing a large movement in terms of how these call windows are aligned … and we have a sense that this is all being driven by some of the things that are happening right now in in the service territory, so COVID-19 brings a lot of folks into working from home and has driven a lot of the load towards residential areas,” Argueta said.
This shift is happening across the system, and of the more than 80 networks in the Con Ed system, the company’s analysis this year determined that 33 had shifted their peaks, meaning they changed call windows repeatedly, he said.
Summary of CSRP reservation payment option enrolled and achieved impact in 2021 | Con Edison
“This is not arbitrary; really the purpose of this program is to reduce network peaks, and we try to closely align those four hours the best we can to maximize the benefits that these programs bring to our system, and it seems that only one network now is peaking from 7 to 11 p.m., so that’s a significant change,” Argueta said.
Peter Dotson-Westphalen from CPower, an energy management company that manages some DLM programs for Con Ed and National Grid, asked for clarification on whether events called that may extend past midnight are still considered to be mandatory.
Under tariff revisions pending before FERC, participation will be mandatory before midnight, just as currently anything beyond midnight will only receive performance payments, Argueta said.
Ultimately, the DR programs are about allowing Con Ed to defer the need to build infrastructure, knowing that it has these resources to rely on, said Griffin Reilly, the company’s section manager of targeted demand management.
“We have some of these networks peaking for longer than eight hours in the day, and to really be able to defer infrastructure builds, we’re going to need resources that can respond for that long,” Reilly said. “How we do that is going to be a big part of the discussions we have this coming summer leading into potential changes that we’ll make for the program next year.”
A rent control plank prompted the greatest opposition to a Washington Senate bill to trim the carbon footprint of roughly 50,000 buildings in the state.
Senate Bill 5722 is being modified to include a cap on rent increases in order for building owners to receive state money to trim carbon emissions from their structures, Anna Lising, senior policy adviser to Gov. Jay Inslee, told the Senate Environment, Energy and Technology Committee Thursday at a public hearing. The bill is part of Inslee’s package of climate-related legislation unveiled in December. (See Flood of Climate Bills to Greet Wash. Lawmakers.)
While the size of the incentive fund is currently not in the bill, speculation emerged in Thursday’s hearing that it could be in the range of $150 million.
The bill by Sen. Joe Nguyen (D) calls for the state’s Department of Commerce to set draft standards to trim carbon by Dec. 1, 2023, for buildings ranging from 20,000 to 50,000 square feet. A 2019 law already addresses the carbon footprints of buildings that are greater than 50,000 square feet, which number about 10,000 in the state. The state must inform the affected building owners by July 1, 2025.
The Commerce Department would fine-tune the standards and submit a report to the legislature in 2029. It would have to adopt the standards in 2030, and the new rules would go into effect in 2031.
Twenty-seven percent of Washington’s carbon emissions come from buildings, the second largest emitter behind vehicles at 45%. In 2018, Washington’s carbon emissions totaled 99.57 million metric tons (MMT). A 2008 law set emission goals of 50 MMT by 2030, 27 MMT by 2040 and 5 MMT by 2050.
“We cannot meet our greenhouse gas limits without substantial action in the building sector,” said Emily Salzberg, an official with the Commerce Department.
The rent control cap prompted pushback from construction, real estate, utilities and business lobbyists. They argued that linking rent control — tentatively set for four years after the improvements are made — with receiving state aid for that work will lead building owners to stay away from applying for state financial help.
“We want the government to have more skin in the game with the incentives,” said Rod Kauffman, president of the Building Owners and Managers Association of Seattle King County.
Environmental groups, the cities of Shoreline and Olympia, and several private citizens supported the bill. Twelve people testified in favor of the bill and 13 against it. Three hundred twenty-eight people signed up to state their positions without testifying with 290 supporting the bill and 38 opposing it.
MISO on Thursday told stakeholders it had removed a 10-MW size limit on aggregations of distributed energy resources (DERs) from its FERC Order 2222 compliance proposal.
During a Distributed Energy Resources Task Force (DERTF) meeting, DER Program Manager Kristin Swenson said MISO removed the limit and will not propose a size limit on either aggregations or a single asset within an aggregation.
The RTO surprised stakeholders late last year by announcing the 10-MW limit. It has been on record multiple times saying it wouldn’t limit the size of aggregations in its markets under Order 2222.
Several stakeholders attending a late November DERTF meeting said it was the first they heard of a maximum threshold on DER aggregations. Staff cited market power concerns and simplified generation outage coordination for setting the size limit.
Swenson said MISO may have to revive discussions on size limits if unusually large aggregations seek wholesale market access. She said staff expects most aggregations to be relatively small but said it’s possible that an 80-MW wind farm on the distribution system could expect to participate in the markets without first entering the generator interconnection queue.
The grid operator plans to rely on its electric storage resource participation model to let DER aggregations participate in the wholesale market. It also said aggregations must be limited to a single pricing node and must self-commit. MISO has said it will not provide output forecasts for the aggregations. (See MISO Draws on Storage Model for DER Aggregations.)
The RTO is currently drafting the compliance filing.
“We’re in the crunch time here. There’s going to be a lot of tariff language,” Swenson warned stakeholders late last year.
Staff has said they don’t expect the Order 2222 compliance to cover all DER applications in the wholesale market.
“We have a lot to learn about DERs and how they will participate in the market,” Swenson said.
MISO is also contemplating whether it needs a forum to discuss DERs after it achieves FERC compliance.
The DERTF is slated to sunset July 31. Stakeholders are debating extending the sunset date by a year or transitioning it into a working group to address evolving and growing DER participation.
MISO says stakeholders can modify the group and reestablish a charter that doesn’t explicitly mention Order 2222 compliance once the RTO has a compliance ruling. It is accepting stakeholder input on whether to maintain a dedicated DER stakeholder group.
WEC Energy Group’s Chris Plante predicted more DER issues will need to be discussed once states have more assets on their distribution systems.
MISO legal counsel Michael Kessler said he doesn’t see a need for stakeholder work on Order 2222 or DER aggregation participation until FERC’s ruling.
“We’re going to be in a hold mode waiting on FERC,” Kessler said.
With the New Mexico legislature’s 2022 session scheduled to start Tuesday, the state has released a discussion draft of a bill that would set a statewide target of net-zero greenhouse emissions by 2050.
The bill, known as the Zero Emissions Economy Act, would also set an interim target for reducing GHG emissions by 50% below 2005 levels by 2030.
The New Mexico Environment Department (NMED) distributed the draft bill by email this week. Comments will be accepted through noon on Jan. 18 and may be sent to 2022act@state.nm.us.
The bill would allow the use of carbon offsets to help meet the 2050 net-zero goal. But even with offsets, GHG emissions would be capped at 10% of 2005 levels in 2050 and beyond.
This would “provide a check on absolute emissions to ensure they do not increase just because they are offset,” NMED said.
The bill would require the New Mexico Energy, Minerals and Natural Resources Department (EMNRD) and NMED to release an annual greenhouse gas inventory, showing progress toward reaching GHG reduction goals. Each year agencies would also assess the impacts of climate change on disadvantaged communities and whether new policies are needed to meet the GHG reduction targets.
NMED would have until June 30, 2025, to petition the Environmental Improvement Board to promulgate rules to lower GHG emissions from sources subject to the Air Quality Control Act.
Camilla Feibelman, director of the Sierra Club Rio Grande Chapter, said the group was still reviewing the draft bill. But she noted that the bill’s 2030 goal of reducing GHG emissions by 50% relative to 2005 levels was more ambitious than the 45% reduction that the governor set as a 2030 target in 2019.
Another positive is that the 50% reduction by 2030 would be actual emission reductions, without the use of offsets, she said.
“Taking real action to put greenhouse gas reductions in law … is essential,” she said.
In addition to the net-zero bill, Feibelman said she’s hoping to see a substantial “earth shot” investment in the state budget to drive a just transition on climate.
Steve Michel, deputy director of the Clean Energy Program at Western Resource Advocates, said WRA generally supports the bill.
“It’s moving us in the right direction, and it’s meaningful,” Michel told NetZero Insider.
Michel said he’d prefer a bill with more frequent benchmarks on the road to net zero, along with additional details on how to get there. And moving more quickly toward net zero would be preferable, he said, given the seeming acceleration of the climate crisis. Still, he called the bill an important step.
Governor’s Support
The state legislative session will run through Feb. 17. The focus of the 30-day session that takes place in even-numbered years is budgets, appropriations and revenue bills, as well as bills introduced at the behest of the governor — known as the “governor’s call.”
The bill is one of three that Democratic Gov. Michelle Lujan Grisham committed to including in her governor’s call during a two-day climate conference in October. The others are a bill that would establish a clean-fuel standard for transportation fuels and a hydrogen hub act. (See NM Draft Bill Would Encourage Hydrogen Buildout.)
In a January 2019 executive order, Lujan Grisham directed the state to join the U.S. Climate Alliance and set a goal for the state to reduce greenhouse gas emissions by 45% by 2030 compared to 2005 levels. The order also established an interagency climate change task force.
During the October conference, Lujan Grisham stressed the importance of codifying the GHG reduction targets into state law.
“If you don’t have that framework in statute, it’s too easy to not work as diligently or as quickly or as effectively,” she said.
The proposed legislation follows the failure of last year’s House Bill 9, the Climate Solutions Act. HB9 would have required “quantifiable and enforceable statewide greenhouse gas emissions reductions” of at least 50% percent below 2005 levels by 2030 and net-zero emissions by 2050. The bill stalled in committee.
Feibelman and Michel pointed to factors that might make this year’s Zero Emissions Economy Act more likely to succeed. The bill is much simpler than the Climate Solutions Act and has the direct backing of the governor, they said.
