NERC’s new cold weather standards give utilities considerable freedom in implementation, which is both an opportunity and a danger, attendees at a workshop hosted by the Texas Reliability Entity heard Thursday.
Speaking at the regional entity’s Spring Standards, Security and Reliability Workshop, Mario de la Garza, Texas RE’s manager of operations and planning compliance monitoring, pointed out that EOP-011-2, which took effect earlier this month after FERC approved it following the February 2021 winter storm, specifies only that registered entities prepare for “cold weather” rather than specific temperatures or conditions. (See FERC Approves Cold Weather Standards.)
This is deliberate, he said, observing that utilities in different areas will likely have very different ideas of what constitutes “cold weather.”
To illustrate this difference, he conducted a survey for participants to provide their definitions of “cold.” The seemingly simple question garnered a wide range of responses: The most popular answer was simply “below freezing,” but one said “not hot or warm,” while another believed only “20s [F] for [an] extended period of time” qualified, and one said “cold” meant a temperature “that impacts equipment.”
Attendees gave a wide variety of responses when asked for their definition of the word “cold.” | Texas RE
“My definition of cold is 40 degrees; that’s where I need to put my jacket on,” Garza said. “But that’s clearly not the same definition for [someone] who lives on the [Texas] Panhandle.”
If the definition of cold varied so much in just one room, Garza continued, the difference must be even greater between the service areas of different utilities — or even within the territory of a single large utility. This is why the standard drafting team that created the cold weather standards made the definition so broad, he said: to give individual utilities the flexibility to define cold weather, and their response to it, according to the circumstances they face rather than imposing definitions that may not make sense for everyone.
Garza acknowledged that this freedom also creates a responsibility for utilities to be proactive in setting parameters for the applicability of EOP-011-2 and its successor EOP-011-3, which is set to take effect in October next year. (See FERC Denies Rehearing of Cold Weather Standard.) The standards’ requirements include the creation of cold weather plans, and the freedom they provide means utilities must be thorough when setting the “trigger points” at which their plans take effect.
Garza recommended that once utilities have a plan in place, they make sure all relevant personnel are properly trained. He joked that auditors at Texas RE are “big fans [of] checklists” — especially ones that are completed.
“When we get a filled checklist for a specific project, that shows us that certain activities were performed [and] gives us some assurance that things were done … in respect to the matter,” Garza said. “So we highly encourage [you to], along with your plan, have a checklist to make sure that individuals who are a part of your plan are doing tasks in a specific order … that they are responsible for.”
The NEPOOL Markets Committee on Tuesday approved ISO-NE’s proposed compliance filing to FERC on distributed energy resource aggregation but rejected the RTO’s concerns in backing LS Power’s bid to save Ocean State Power’s (OSP) capacity supply obligation (CSO).
The committee overwhelmingly supported tariff changes to allow the gas-fired combined cycle plant to unwind a 64-MW capacity increase while maintaining its CSO for its existing 270 MW.
In Forward Capacity Auction 15, Ocean State Power cleared as a “repowering” to increase its output to 334 MW, a 24% increase, and was awarded a seven-year rate lock at $3.98/kW-month.
LS Power’s Dilemma
Since winning the award, however, LS Power has become concerned it may not be able to complete the upgrade economically — and by the RTO’s June 1, 2026 deadline for commercial operation — because of rising prices and supply chain challenges.
The company said it was surprised to learn that failing to add the incremental capacity as promised could cause it to lose its CSO for its existing capacity. “Under the ISO’s interpretation of the tariff, there is no way for a ‘repowered’ resource to unwind future [Forward Capacity Market] commitments, leading to an unexpected and nonsensical ‘bet-the-plant’ situation,” it said in a presentation by Ben Griffiths, director of New England market policy. “If OSP had cleared as greenfield new or as a minor uprate, we would not be here today: The tariff is unambiguous in the ability of these resources to shed incremental obligations.”
The company’s proposed tariff change would allow it to cancel the 64 MW of incremental capacity while ensuring the RTO retains 270 MW of capacity. The plant, in Burrillville, R.I., has connections to two interstate pipelines and 2 million gallons of on-site oil storage, enough for three days at full output.
The company said it would accept the same penalties that would apply if a minor uprate (less than 20%) or a greenfield project were terminated: forfeiture of the price lock and $2 million in financial assurance on the 64 MW that OSP cleared in FCAs 15 to 17.
Southeast New England customers would avoid having to pay $3.98/kW-month for 334 MW of capacity in FCAs 16 to 21, LS Power said. Because the two most recent auctions cleared around $2.60/kW-month, the savings would be about $15 million in FCAs 16 and 17, it said. Generators would benefit from the elimination of 64 MW of capacity from the supply stack in future auctions.
The company said the current repowering provisions were intended to allow existing capacity to obtain price locks, which are no longer permitted.
It said market power concerns in current rules were over the ability of only new resources to set the clearing price. Now that existing resources can set clearing prices, “concerns about toggling between new/existing do not matter in [the] same way,” it said.
The company said the 20% threshold for repowering is “largely arbitrary” for market mitigation. “Our 64-MW ‘repowering’ … would have been considered an uprate if OSP had a starting capacity of 320 MW instead of 270 MW,” it said.
ISO-NE’s Internal Market Monitor issued a memo saying it needs more time to vet the design changes and market power considerations.
“We do think taking a fresh look at the repowering rules in the tariff is a good idea, but we have a number of concerns with the proposed rule changes and the short evaluation time frame. In summary, the evaluation will need to assess incentives to limit the exercise of market power and gaming, and provide a clear and commensurate remedy if a participant is unable to perform on its repowering obligation,” the Monitor said.
The current rules were “intended to act as a strong deterrent to potentially setting a higher clearing price and securing a multiyear revenue stream, and subsequently toggling back to the original status,” the Monitor added. “This proposal does not factor in the potential market harm caused by the clearing of the repowering resource in the FCA, and may not adequately incentivize market participants to deliver on obligations obtained in the auction.”
Andrew Gillespie, the RTO’s director of market development, also weighed in with a separate memo.
Gillespie said the RTO’s primary concern is “the incentive and appropriate compensation problems created if existing capacity effectively participates in the FCA as new capacity and sets the FCA clearing price.” He noted that new capacity offers are subject only to buyer-side mitigation, with no downward mitigation.
Despite the RTO’s concerns, LS Power’s motion passed the committee with 83% of the vote, with unanimous support (excluding abstentions) from the Generation, Transmission, Supplier, Alternative Resources and End User sectors. The Publicly Owned Entity sector was unanimous in opposition.
The proposal will next be considered by the Participants Committee. But it’s far from certain that FERC would approve it, given the IMM’s concern that it would amount to retroactive ratemaking.
Compliance Filing on DER Aggregation
The committee also voted overwhelmingly in support of the RTO’s proposed response to FERC’s March 1 order requiring changes to its rules for DER aggregations under Order 2222 (ER22-983). (See FERC Gives ISO-NE Homework on Order 2222.)
Renewable energy groups had criticized ISO-NE for not going far enough to remove barriers for DERs to participate in wholesale markets, as required by Order 2222.
The commission agreed, saying the RTO failed to show that its proposed energy and ancillary services market participation models accommodate the physical and operational characteristics of behind-the-meter DERs. It flagged ISO-NE’s choice to require measurement of most behind-the-meter DERs at the retail delivery point, rather than allowing sub-metering.
Henry Yoshimura, director of demand resource strategy, presented the new filing, which the RTO plans to submit by May 9. The filing addresses six issues raised by FERC.
The RTO drafted tariff revisions for four items:
small utility opt-in requirement;
existing rules requiring market participants providing energy withdrawal service to register a load asset;
dispute resolution rules; and
applying nonperformance penalties to aggregations.
However, ISO-NE will provide additional explanation defending its proposed metering configuration rules. In addition the RTO and several of its utilities filed for rehearing on the sixth issue, rules governing the submission of metering data by DER aggregators.
FERC ordered ISO-NE to revise its tariff to designate the DER aggregator as the entity responsible for providing required metering information to the RTO.
Yoshimura said FERC’s requirement would run afoul of state policies that make host utilities responsible for providing metering services to all energy market loads and resources in the region. He said compliance would require modification of current agreements and costly changes to metering infrastructure and processes.
“Additional design elements would be needed to avoid costly delays in energy market settlement from potential data transmission errors and energy balance reporting, and to prevent double-counting of services,” the RTO added. “DER aggregators would need to install and operate costly and redundant metering and communications systems that no other energy market participant is required to install and operate.”
Any alternative metering requirements would depend on the commission’s final orders concerning acceptable metering configurations and the rehearing request on submission of metering data.
The RTO’s motion passed with 78.6% in favor, with unanimous support from the Generation, Transmission and Publicly Owned Entity sectors. The Supplier sector was mostly in favor, while Alternative Resources was split, and End Users were mostly opposed.
Nevada natural gas utilities would be required to file a plan every three years, similar to the integrated resource plans filed by electric utilities, under a bill intended to make natural gas planning more transparent.
Senate Bill 281, by state Sen. Rochelle Nguyen (D), would require natural gas utilities to detail the amount of greenhouse gas reductions they would achieve and how they would promote energy efficiency and conservation.
The plan would assess the reliability of gas pipelines and spell out any significant operational or capital requirements for the next three years.
The Public Utilities Commission of Nevada (PUCN) would hold a public hearing on the plan and vote on whether to accept it. The first plan would be due on Oct. 1, 2025.
Under current law, a natural gas utility must file an informational report with PUCN each year, discussing natural gas demand, costs related to providing gas service and planned gas acquisitions. The reports don’t go through a hearing process.
“Senate Bill 281 increases transparency around natural gas infrastructure investments and provides an appropriate venue for all stakeholders to participate in and provide feedback to utility regulators on the need for future natural gas investments,” Nguyen said during a hearing on the bill this month before the Senate Growth and Infrastructure Committee.
In 2021, the PUCN opened an investigatory docket on the future of natural gas in Nevada. Stakeholders made it clear during that process that they’d like natural gas utilities to face planning requirements similar to those for electric utilities, Nguyen said.
The committee passed SB281 on April 12. The bill is exempt from an April 25 deadline for bills to pass out of their house of origin.
Supporters include Southwest Gas, the largest distributor of natural gas in Nevada, serving about 792,000 customers.
“We think this is a good bill. We think it’s a fair process. We’ve done a lot of work on it,” Scott Leedom, director of public affairs for Southwest Gas, said during the committee hearing.
Union representatives said the bill would promote transparency and create jobs.
Representatives of Chispa Nevada, a program of the League of Conservation Voters, said the bill would help combat soaring gas rates.
“SB281 is an important step to hold Southwest Gas accountable for current and future rate increases as well as the impact of their investments on the environment,” Chispa National Director Estefany Carrasco-Gonzalez said in a letter to the committee.
Previous Bill Failed
Leedom of Southwest Gas also discussed SB281 this month during a joint meeting of the Committee on Regional Electric Power Cooperation and the Western Interconnection Regional Advisory Body in Incline Village, Nevada. Leedom was a panelist during a session on natural gas planning.
SB281 follows another natural gas planning bill in Nevada, Assembly Bill 380 by Assemblywoman Lesley Cohen (D), which died in its first committee during the 2021 legislative session. Southwest Gas lobbied against the bill, saying it “effectively bans natural gas.” (See Bill Would Tighten Oversight for Nevada Gas Providers.)
Leedom said AB380 went beyond implementing a planning process by including measures to promote a transition away from commercial and residential use of natural gas. It also would have blocked the utility’s expansion into new areas for economic development purposes.
“We are open to a planning process — just not one that plans to our ultimate demise,” Leedom said.
After AB380 failed, Southwest Gas began working with Sen. Chris Brooks (D) on a bill creating a natural gas planning process, similar to the integrated resource plans required for electric utilities.
But Brooks, whom Leedom described as a central figure in Nevada energy policy, resigned from the Senate last year to take a job in private industry. The Clark County Commission appointed Nguyen to fill the vacant seat. Nguyen agreed to keep working on the bill.
Gas Infrastructure Bill
In this year’s legislative session, another natural gas bill has died. SB116 by Sen. Skip Daly (D) would have allowed natural gas utilities to file a gas infrastructure modernization plan for approval with the PUCN. The plan would cover infrastructure projects proposed for the next five years.
The utility could then recover its infrastructure costs through a separate monthly rate charged to customers.
Daly said during a hearing before the Senate Growth and Infrastructure Committee that the bill was intended to address the potential degradation of certain types of pipe. The U.S. Department of Transportation issued an advisory about the degradation, which it said has been seen in certain pipelines installed between 1978 and 1999 in the southwestern U.S. and potentially could be more widespread.
Opponents of the bill included the Nevada Conservation League, which said utilities already have an effective process for replacing old or leaky pipes. The League called the bill “a step in the wrong direction for ratepayers and climate goals.”
“SB116 would lock in decades of continued reliance on fossil fuels, even as new, more efficient technologies become available, while guaranteeing Southwest Gas continues to collect a check,” the League said in a news release.
After holding a hearing on SB116, the Senate Growth and Infrastructure Committee took no action on it. The bill missed the April 14 deadline for committee approval in the house of origin and is now dead.
New Jersey’s Economic Development Authority (EDA) on Friday began accepting applications for a new $80 million fund designed to make matching loans of up to $10 million to small businesses seeking to make clean energy investments.
The project, called New Jersey Clean Energy Loans (NJ CELs), is designed to assist businesses that develop clean energy infrastructure, install or purchase clean energy improvements in an existing business, manufacture clean energy products, or offer clean energy services.
The program defines “clean energy” broadly, ranging from solar and wind power to carbon capture technologies, hydroelectric and wave power to fuel-cell based storage.
“NJEDA loans must be matched at least dollar for dollar with capital from a financial institution,” the EDA said in a release, adding that the program aims to “unlock capital for small businesses and start-ups, [and] catalyze the deployment of clean energy in New Jersey.”
The program is one of three climate change impact programs launched by or in development at the EDA, the main architect of the financial structures and programs underpinning Gov. Phil Murphy’s aggressive clean energy agenda. Together, the three programs could make available hundreds of millions of dollars in funding for climate change projects.
The agency is assessing public comments, with a May 15 deadline for submissions, and refining the rules for a program known as the Garden State Commercial Property Assessed Clean Energy (C-PACE) program. It will use a strategy similar to a property assessment to help property owners making renewable energy, energy efficiency, water conservation, and certain types of resiliency-related improvements access financing to fund their projects.
The EDA is also developing a $40 million “Green Fund,” which Murphy highlighted in his Feb. 28 budget speech but about which he has provided little detail. The governor’s budget proposal book released the same day says the fund will aim to leverage both private capital and private funds, and is designed to “attract up to $280 million in private capital to advance projects to advance the State’s new and bold environmental goals.”
“The Green Fund will support growth of clean energy technologies aimed at reduction or avoidance of greenhouse gases (GHG) and will help deliver on New Jersey’s environmental and economic development goals with a focus on overburdened communities,” EDA spokeswoman Rachel Goemaat said. “The Green Fund will be focused on sustainable infrastructure opportunities and represents a new approach in the clean energy marketplace in the state.”
Wide-ranging Scope
EDA officials say NJ CELs is looking to assist businesses of all kinds to initiate investments that work toward mitigating climate change.
“The program is designed to support small businesses and catalyze the deployment of clean energy in New Jersey,” Marta Cabral, senior project officer for clean energy at the EDA, told a pre-launch forum. “And we are using this program to support clean energy projects as well as the creation and expansion of clean energy businesses in the state.”
That expansive vision is reflected in the flexible criteria for defining which businesses are eligible for participation in the program.
“You could be seeking finance for a clean energy infrastructure project — let’s say solar plus energy storage distributed energy resource projects, for example,” Cabral said. “You could also be seeking financing to install or purchase clean energy improvements at an existing facility.
“So, if you’re upgrading to high efficiency boilers, for example, or you’re switching to electric vehicles, that could potentially qualify, even if … you’re not a clean energy business,” she added.
Eligible businesses can seek loans for between $250,000 and $10 million, with a matching loan from a financial institution. The EDA’s portion of the loan will be pegged at 3 percent points below the financial institution’s rate, with an additional 1 percentage point reduction each for minority-, women- and veteran-owned businesses — allowing for an additional cut of up to 3 percentage points for a business that fits into all three categories.
In addition, Cabral said, businesses “are also eligible for a 10% loan forgiveness if the project results in at least one job being created per $100,000 of the total loan amount.”
The list of 25 participating institutions ready to make loans under the program range from giants such as Bank of America and JP Morgan Chase, to smaller entities such as Cross River and Peapack-Gladstone banks.
Repayment Through Assessments
The C-PACE program aims to provide a new form of financing for climate change-related projects for the state, enabling property owners to leverage the value of the property by placing a special assessment lien on it.
The strategy will allow the owners of commercial, industrial, agricultural, and certain multi-family residential buildings to take out financing that would be repaid through an assessment to their municipality, in the same way that property tax and sewer or water bills are.
“Because the payment is secured by a senior lien, C-PACE projects are seen as less risky than typical loans, allowing capital providers to lend at lower interest rates than would otherwise be the case,” according to the agency’s explanation of the program. The repayment obligation is tied to the property and is transferred to any buyer.
“Due to the security arrangements for the loan, capital providers are willing to extend loans that are longer in duration,” the agency said, adding that “the longer loan terms result in lower periodic debt service payments, making it easier for energy efficiency, water conservation and renewable energy-related C-PACE projects to be cash flow-positive from the outset.”
A Colorado solar-and-battery project facing ongoing supply chain disruptions can postpone its operational start date by 21 months, FERC decided in a 3-1 vote Tuesday.
The ruling means that the 100-MW Front Range-Midway Solar project, which will interconnect into the Public Service Company of Colorado (PSCo) balancing area, might commence commercial operation nearly 10 years later than originally proposed (ER23-1108).
Xcel Energy subsidiary PSCo contested Front Range’s February request to waive relevant sections of the utility’s large generator interconnection procedures — and an amended large generator interconnection agreement (LGIA) — to allow the project to move its start date from March 31, 2024, to Dec. 31, 2025.
The Front Range project, which will pair a 100-MW solar photovoltaic facility with a 50-MW battery system, is being developed by Italy-based Enel and TradeWind Energy. The project was initially slated to begin commercial operation in July 2016 before Front Range and PSCo entered an amended LGIA that set a new deadline of Oct. 31, 2022.
In May 2022, FERC granted Front Range an 18-month extension to that deadline — to March 31, 2024 — “due to interruptions and delays in the project development process caused by the COVID-19 pandemic, port shutdowns within China and the prospect of new tariffs on modules.”
In its most recent request for an extension, Front Range argued that additional supply chain disruptions have arisen since last May’s order. They include power outages in China that have caused component capacity constraints, continued shipping delays for equipment and the U.S. government’s June 2022 implementation of the Uyghur Forced Labor Prevention Act (UFLPA), which presumes that all goods coming from China’s Xinjiang Uyghur Autonomous Region — the origin of many solar components — are the product of forced labor.
Front Range said it received a Notice of Detention from the U.S. Customs and Border Protection (CBP) in December for initial deliveries of PV modules that its supplier had manufactured in China and delivered to a U.S. port. The company said that it does not expect the equipment will be released soon because CBP has not provided clear guidance on the standard necessary to overcome the presumption for detention under the UFLPA.
“As a result, Front Range states that it will need additional time to procure an alternative supply of PV modules for the project,” FERC noted in Tuesday’s order.
In its filing with FERC, Front Range contended that the project continues to be viable, noting that the developers have secured all necessary property rights to begin construction; negotiated easement agreements with PSCo and the Western Area Power Administration to construct the interconnection tie-line; completed necessary environmental assessments; obtained a critical permit from El Paso County; and posted the required financial security under the interconnection agreements.
Front Range said that since the May 2022 order, it has “procured the battery energy storage system and transformer, executed the purchase order for the necessary PV modules, and funded and completed the network upgrades delineated in the LGIA and surplus LGIA.”
Waiver Requirements
Front Range also said its waiver request satisfies the commission’s criteria for granting a waiver, contending that:
the request was made in “good faith,” as demonstrated by the progress the company has made in developing the project, which would have been completed last December “but for” the CBP detention of its equipment.
the waiver is limited in scope, given that 21 months is a finite amount of time. Front Range also argued that the waiver would not relieve it of any financial obligations because it has already paid for the transmission upgrades needed to interconnect the project.
the request seeks to address the “concrete problem” of overcoming the supply chain disruption created by the UFLPA and finding a new supplier.
Front Range also contended that the waiver would not cause harm to any third parties, given that it has already fully funded the need transmission upgrades.
In contesting the waiver request, PSCo argued that Front Range had previously exhausted its suspension right under the LGIA and noted that an additional waiver would push the project’s commercial operation date to nearly a decade beyond the originally designated date.
The utility also contended that Front Range had not provided specific details about the impact of the UFLPA and the CBP’s Notice of Detention, a point that Front Range later contested by saying that it had worked diligently to assemble the “traceability documentation” regarding the origins of its PV modules in order to expedite their release but was still awaiting review by CBP.
PSCo’s protest also questioned the economic viability of the Front Range project, pointing out that the off-taker — the utility itself — had terminated its power purchase agreement for the project in January after Front Range failed to meet development milestones. The utility pointed to October and December 2022 letters from Front Range in which the company sought to renegotiate the PPA, say that current market conditions for solar development had rendered the original agreement “uneconomical and unfinanceable,” raising questions about Front Range’s assertion that completion hinged on the detention of the modules.
Front Range countered that the same letter stated that the project “has not failed” but was pointing to the fact that import restrictions had affected solar projects nationwide. The company said that PSCo had renegotiated PPAs for other solar projects and agreed to postpone their completion dates.
Commission Finding; Danly Dissent
In approving the extension, FERC determined that Front Range had satisfied its waiver criteria. The commission also found that, contrary to PSCo’s assertion, the record demonstrated that Front Range has made “continued efforts” to contact the CBP to resolve the UFLPA matter.
The commission also dismissed PSCo’s assertion that Front Range was seeking a waiver “merely to stay in an interconnection queue with the hope of securing an off-taker.”
“Instead, Front Range provides evidence of global supply chain disruptions and ongoing permitting and regulatory approval processes since the May 2022 order affecting the project,” the commission wrote.
FERC also said it was “not persuaded” by PSCo’s contention that Front Range’s 2022 letters to the utility suggested that the project was unlikely to be completed even before the UFLPA detention.
“While Front Range asserted that the project had become ‘uneconomical’ under the terms of the then-existing power purchase agreement while attempting to renegotiate those terms, we do not agree that this rendered the project unable to meet the March 31, 2024, commercial operation deadline, assuming that an agreement between the parties could have been reached,” the commission said.
In a dissent against the ruling, Commissioner James Danly said Front Range’s waiver “can hardly be” said to apply to a single deadline, given the project’s previous delays.
“While implementation of the Uyghur Forced Labor Prevention Act in June 2022 may present new circumstances not at issue when the commission granted Front Range a prior waiver request, application of the UFLPA is an industry-wide issue and does not support a finding that granting a waiver here is limited in scope,” Danly wrote.
He also argued that while Front Range had described its efforts to resolve the equipment detention issue, it did not explain any of its efforts to identify an alternative supplier for the PV modules.
“Front Range has also not addressed whether it has secured a new off-taker after termination of the power purchase agreement with PSCo due to Front Range’s failure to meet project development milestones,” he wrote. “Nor does Front Range state that it will construct the facility without an off-taker. For these reasons, Front Range fails to demonstrate that the waiver actually addresses a concrete problem.”
ALBANY, N.Y. — NYISO on Wednesday presented the Budget and Priorities Working Group (BPWG) with 48 market projects that it is proposing to be included in its 2024 budget.
The projects include 13 concerning the capacity market, 22 on the energy market and two for transmission congestion contracts. The total is 11 more than were proposed at this time last year in the project prioritization process. The ISO deemed six of the 48 as being mandatory for next year and 29 as priorities.
NYISO anticipates giving stakeholders a clearer indication about each of these projects’ potential resources, budgets, feasibility and constraints in either late May or early June. It will on May 22 both review proposed 2024 enterprise projects and discuss any updates made to the proposed market projects. Stakeholder advocacy and draft scoring surveys are scheduled for the BPWG on May 31.
The ISO asks stakeholders to send any additional feedback or questions to kpytel@nyiso.com by May 15.
Peak Hour Definition
The New York Department of Public Service also told Wednesday’s BPWG meeting that its definition of peak hour is being expanded to consider more than a single hour when determining transmission owners’ and load-serving entities’ obligations.
The department said the change is necessary because it will more accurately determine future peak loads, track customer usage on an hourly basis and more equitably allocate capacity costs among LSEs.
“This project isn’t changing the way that we forecast but is more about how that capacity obligation gets allocated to transmission owners and thus to those load-serving entities,” said Christopher Graves, DPS chief of utility programs.
Most projects remain on schedule, but two — upgrading the load forecasting data repository system, and securing better communication channels for market participants to exchange information — are at risk of not meeting their end-of-year milestones.
Meanwhile, the schedule for distributed energy resource participation modeling will most likely be delayed until July.
NYISO will return next quarter to update stakeholders about the status of these projects.
Comprehensive Reliability Plan
NYISO on Tuesday presented its proposed topics for the biennial 2023-2032 Comprehensive Reliability Plan (CRP) at the joint meeting of the Electric System Planning Working Group, Transmission Planning Advisory Subcommittee and Load Forecasting Task Force.
Flowchart of NYISO’s comprehensive system planning process | NYISO
The topics include winter gas constraints, extreme weather events, the integration of large load scenarios into transmission security and resource adequacy considerations, near-term reliability risks, and subjects identified within the “Road to 2040” section of the Reliability Needs Assessment (RNA), such as dispatchable emission-free resources (DEFRs).
Stakeholders attending Tuesday’s meeting pointed out that NYISO continues to discuss DEFRs as part of its proposed solutions to future resource adequacy needs but has yet to flesh out what those resources include or will look like.
NYISO responded that DEFRs represent technologies that either have not been discovered or have not evolved enough to be used at scale, but it stressed that it understood stakeholder concerns.
The ISO will spend the second and third quarters of this year presenting results from the draft CRP, then target the fourth quarter to obtain committee approval.
CARMEL, Ind. — As it prepares to address long-term transmission needs in its South region, MISO is proposing to replace total subregional cost allocation in favor of a half-regional, half-local zone cost-sharing plan.
The 50-50 split to subregion and cost-allocation zones may eventually supersede the RTO’s current postage stamp cost allocation in place for the first two long-range transmission plan (LRTP) portfolios. The new allocation methodology would take effect in regional transmission plans for MISO South, comprised mostly of Entergy operating companies.
MISO says assigning half the costs to a subregion “considers broadly spread benefits and accounts for changing beneficiaries over time.” Allocating the other half to cost-allocation zones is a more granular approach and “may account for differing policy given the mapping of zones.”
The grid operator’s zonal boundaries mostly follow state lines and divide the footprint into a dozen zones, which can contain multiple transmission-pricing zones.
During a cost allocation working group meeting Tuesday, MISO’s Milica Geissler said the RTO is aiming for an allocation that’s “reflective of the portfolio in front of us.”
MISO said it will refine and test its proposed design over the coming months. Geissler said staff are open to suggestions that would adjust the 50-50 split.
Geissler said her presentation should be construed as an “introductory first step.” She said she envisions staff and stakeholders building on the proposal through the summer so there’s a cost allocation direction by the end of the year.
“I think we’re going in with an open mind and seeing what ideas shape up,” Geissler said. “Our intent is not to prove out a 50-50 split. That’s the one thing I’m interested in learning about the most: what the split needs to be.”
The first round of stakeholders’ written feedback to the plan are due May 12.
Geissler said MISO always has the option to add a footprint-wide allocation construct in the future. She said the half-and-half approach is custom-built for the LRTP’s third cycle of projects.
MISO said its proposal won’t disturb the 100% postage stamp rate to load used for the first two LRTP portfolios in the Midwest region.
MISO has said it’s targeting a FERC filing in early 2024 to modify its current postage stamp cost-allocation methodology for the final two LRTP portfolios. Stakeholders have long expressed interest in an allocation that more precisely reflects how transmission benefits are dispersed.
Stakeholders Split Over Plan
Stakeholders didn’t appear quite sold on the allocation plan’s first draft.
Sustainable FERC Project attorney Lauren Azar said disparate allocations for the same class of LRTP projects doesn’t “jive” with FERC’s Order 1000, which requires identical project types be assigned identical allocations. She asked whether MISO would create a separate classification for projects in MISO South.
Staff said they haven’t considered creating a new project category.
Azar also said that a 50-50 regional-zonal split is not as accurate an allocation as a blanket postage stamp rate that better captures benefits over time. She offered to explain the advantages of postage stamp allocations during an upcoming cost-allocation meeting.
MISO’s environmental sector, one of 11 stakeholder divisions, is advocating the continued use of a postage stamp rate. Its members say that is the best way to share project costs as beneficiaries change and reliability benefits remain tricky to quantify into dollar values.
Bill Booth, a consultant to the Mississippi Public Service Commission, said he wants projects justified through measurable benefit metrics, not hypothetical ones. He also suggested allocations should be tailored to states’ differing decarbonization goals.
“I’m suggesting that some states might place different values on decarbonization,” Booth said. “I don’t think MISO can snap a cookie-cutter approach on this.”
He said FERC already has acknowledged in accepting the grid operator’s first LRTP cost-allocation design that MISO will propose a different methodology for MISO South projects. In its order, the commission said the postage stamp rate is an appropriate tool under Order 1000 and is considered in effect for MISO South. It also said it wouldn’t speculate on possible replacement allocations MISO may file in the future. (See FERC OKs MISO’s Bifurcated Cost-allocation Tx Design.)
In its filings to FERC, the Mississippi PSC said it would protest a postage stamp rate as not specific enough were it applied to Southern projects.
The Union of Concerned Scientists’ Sam Gomberg advised MISO against allowing states to back out of select LRTP benefit metrics, depending on their policies.
“I would caution MISO against wandering into that very dense forest,” he said.
Gomberg said the emissions-reduction component of decarbonization goals have “very, very real benefits that save lives, whether you want to admit that or not.”
Southern Renewable Energy Association Executive Director Simon Mahan asked whether a third cycle of LRTP projects will even occur, alluding to the $3.6 billion of reliability projects MISO South put forward as part of this year’s regular transmission planning effort. Those projects might negate the need for some LRTP projects. (See Initial MTEP 23 Ignites Familiar Arguments over MISO South’s Reliability Spending.)
Jeremiah Doner, director of cost allocation and competitive transmission, said MISO remains committed to proposing projects for its South region under the LRTP process.
Werner Roth, an economist with Texas’ Public Utility Commission, said he was disappointed that MISO revealed a first draft on the new cost allocation while the Organization of MISO States is still weighing other approaches.
OMS is in the middle of collecting and reviewing stakeholders’ suggestions on MISO’s proposal.
Roth also said he didn’t see a “generator-pays” component to the proposed allocation, something that multiple MISO states have conveyed interest in.
Xcel Energy (NASDAQ:XEL) executives told financial analysts Thursday that the recent radioactive water leak at a nuclear plant will not result in a material hit to earnings.
CEO Bob Frenzel said during the company’s quarterly conference call with analysts that the costs to repair two water leaks since last November “were not significant.” Xcel has estimated the costs to be about $2 million.
A pipe broke at Xcel’s Monticello Nuclear Generating Station last year, leading to a leak of more than 400,000 gallons of tritium-laced water. The company and state regulators did not disclose the leak until March.
Xcel patched the leak but discovered a second, smaller leak in March during a refueling outage. It has been pumping out the water and tritium from an aquifer under the plant, a process that is not expected to end until later this year or early next year.
“There was no risk to people or the plant,” Frenzel said. “It’s really about pumping water out. I expect they probably have two more weeks before they finish loading fuel and restarting the plant, but it is ready to go.”
Minneapolis-based Xcel reported first-quarter earnings Thursday of $418 million ($0.76/share), compared to $380 million ($0.70/share) over the same period last year. Earnings reflected the recovery of electric and natural gas infrastructure investments and other regulatory outcomes, partially offset by higher depreciation, operations and maintenance expenses, and interest charges.
Frenzel told analysts that Xcel continues to make progress on its clean energy transition plans. The company is reviewing proposals for 6 GW of new generation in its various jurisdictions and anticipates regulatory decisions on the proceedings in the latter half of the year.
Xcel has also submitted multiple projects to the U.S. Department of Energy for funding consideration, including hydrogen hubs in the Midwest and West, and grid resilience investments in Colorado.
The company’s share price closed at $70.26 on Thursday, a gain of 58 cents on the day.
During the same week President Joe Biden announced his re-election bid, congressional Republicans stepped up attacks on his energy agenda, with the House of Representatives passing legislation Wednesday trying to use the debt ceiling to force cuts on incentives.
Republicans from both the Senate Energy and Natural Resources Committee and the House Energy and Commerce Committee sent letters to FERC asking pointed questions about reliability, permitting and other issues as at least one of them gears up for oversight hearings. The Senate committee is holding its hearing on May 4, while the House committee has yet to schedule one.
The Limit, Save, Grow Act of 2023 cleared the House on Wednesday on a 217-215 vote, with four Republicans voting against it and no Democrats agreeing to the measure, which would raise the debt ceiling at the expense of key Biden administration priorities.
“The Limit, Save, Grow Act is a common-sense approach to return to fiscal sanity by putting an end to Democrats’ trillion-dollar spending sprees while ensuring veterans, Medicare and Social Security programs are strengthened and preserved,” House Speaker Kevin McCarthy (R-Calif.) and other members of leadership said in a statement. “It will save taxpayers trillions of dollars by reclaiming unused COVID funds, stopping Biden’s student loan giveaway to the wealthy and defunding his army of IRS agents.”
Democrats uniformly trashed the bill, with the White House releasing a statement saying that “the president has made clear this bill has no chance of becoming law” and calling on the House to raise the debt limit without strings attached. House Energy Committee Ranking Member Frank Pallone (D-N.J.) said the legislation puts polluters ahead of people.
“The bill repeals key climate provisions that Democrats delivered with the Inflation Reduction Act last year that are already making a huge difference in the clean energy transition,” Pallone said in a statement. “Since its passage, we’ve seen about $28 billion in new domestic manufacturing investments. Companies have announced $242 billion in new clean power capital investments, and more than 142,000 clean energy jobs have been created across the nation.”
FERC Oversight
Senate ENR Committee Ranking Member John Barrasso (R-Wyo.) sent a letter to FERC on Wednesday asking commissioners a number of questions about reliability and natural gas permitting. Committee Chair Joe Manchin’s (D-W.Va.) staff declined to comment on the hearing.
NERC, several ISO/RTOs and others have expressed serious concerns about the future of reliability on their grids, Barrasso said.
“You must do all that prudently may be done to enhance reliability and control electric costs for families and businesses,” he added.
Barrasso asked questions about what the impact of electrification efforts would have on reliability and affordability. He also focused on the recent report out of PJM saying about 40 GW is at risk of retirement largely because of state policies and the tight operations the RTO had near Christmas 2022. (See PJM Board Initiates Fast-Track Process to Address Reliability.)
“If electric grids suffer frequent reliability events or increasing reliability risks, doesn’t the underlying structure of the markets responsible for the grid become unjust and unreasonable under the” Federal Power Act? Barrasso asked.
The senator praised FERC’s recent approval of LNG export facilities in light of the ongoing invasion of Ukraine, but he also said the commission should get rid of the proposals pushed by former Chair Richard Glick to review the climate impacts of natural gas infrastructure.
“Both natural gas policy statements remain in draft form,” Barrasso said. “Under no circumstances should the commission attempt to finalize these policy statements in anything like their current form. They must be scrapped.”
In January the White House Council on Environmental Quality has issued an “interim GHG guidance” for federal agencies, and Barrasso asked whether and how FERC plans to apply that to its regulations.
House Energy Committee Chair Cathy McMorris Rodgers (R-Wash.) and Rep. Jeff Duncan (R-S.C.) — chair of the committee’s Energy, Climate and Grid Security Subcommittee — also wrote FERC a letter on Wednesday focusing on reliability in ISO/RTO regions. They want answers by May 10.
They pointed to rolling blackouts in CAISO, shortages in MISO and SPP, and PJM’s recent report about the 40 GW of potential retirements.
“The commission, as the federal agency responsible for the regulation of the nation’s organized wholesale electricity markets, must better understand how RTOs/ISOs have affected electric reliability,” the committee leaders said. “It is long past due for the commission to fulfill its statutory role by conducting a thorough, unbiased analysis on the reliability impacts of a policy for which it has advocated for more than 20 years.”
The letter has several questions drilling into that topic including asking for a comparison between RTOs and traditional regulation when it comes to reliability. The letter also notes that generators have not been able to secure firm gas in the markets and asks if FERC ensure that market designs allow for that.
Some Want Solar Tariffs Back
Sen. Manchin also announced this week that he was signing onto a joint resolution under the Congressional Review Act that would reimpose tariffs on solar cells from Asia, which President Biden had suspended as it led to shortages in supply. The main sponsor of S.J. Resolution 15 is Sen. Rick Scott (R-Fla.), and Manchin is the lone Democrat among nine co-sponsors.
“The United States relies on foreign nations, like China, for far too many of our energy needs, and failing to enforce our existing trade laws undermines the goals of the [Infrastructure Investment and Jobs Act] and Inflation Reduction Act to onshore our energy supply chains, including solar,” said Manchin. “I cannot fathom why the administration and Congress would consider extending that reliance any longer and am proud to join this CRA to rescind the rule.”
A similar bill cleared the House Ways and Means Committee on April 19; the Solar Energy Industries Association criticized the proposal in response.
“The United States currently lacks the capacity to produce solar panels and cells in adequate volumes to meet domestic demand,” SEIA CEO Abigail Ross Hopper said. “The two-year duty moratorium allows planned solar installations to move forward while we scale domestic manufacturing in the near term. This strategic approach protects existing jobs while new ones are added, but it also helps sustain the robust environmental, national security and job-creating benefits offered by U.S. solar deployment.”
Successful implementation of the Infrastructure Investment and Jobs Act and the Inflation Reduction Act may hinge on Congress’ ability to put politics aside and hammer out bipartisan legislation to streamline federal permitting, Martin Durbin, senior vice president for policy at the U.S. Chamber of Commerce, said Wednesday.
States and other recipients of federal funding from those laws “are struggling to use them since lengthy permitting processes can add years and uncertainty,” Durbin told the Senate Environment and Public Works Committee during a hearing on permitting.
Inflation combined with permitting challenges is a double whammy, he said. “The longer it takes for shovels to hit the dirt, the less we’re going to be able to build.”
Durbin was one of five speakers at the EPW hearing, kicking off the search for bipartisan solutions to the permitting logjam facing clean energy and transmission projects, as well as those related to natural gas.
Sen. Shelley Moore Capito (R-W.Va.) | Senate EPW Committee
Both Committee Chair Tom Carper (D-Del.) and Ranking Member Shelley Moore Capito (R-W. Va.) stressed that a bipartisan bill passed through a “regular order” process — with committee hearings and negotiations, and broad stakeholder input — is needed to forge the needed compromises.
Carper’s must-haves for “permitting reform,” as the issue is commonly referred to, include lowering greenhouse gas emissions, maintaining “the fundamental protections provided by our nation’s bedrock environmental statutes” and supporting “early and meaningful community engagement.”
Legislation must also “provide businesses, especially clean energy businesses, with certainty and predictability and help unlock economic growth,” he said.
Capito wants a technology- and project-neutral approach with firm, enforceable deadlines for permitting and an expedited process for deciding legal challenges so projects don’t “drown in litigation.” She called for amendments not only to the National Environmental Policy Act (NEPA) but also to the Clean Water and Clean Air acts.
Permitting challenges “don’t just impact [project] sponsors,” Capito said. “They harm American workers and consumers with lost jobs, higher energy prices, traffic congestion, more pollution and many other missed opportunities that result from the failure to modernize infrastructure and energy systems. …
“If all we do is window-dress the failed system, it’s not an option. We’re not getting anywhere,” she said. “At the end of an honest negotiation, neither side will get exactly what it wants, and we all know that.”
Common Ground
While Congress remains preoccupied with raising the debt limit, bipartisan efforts to find common ground on permitting reform are underway in both houses, driven in part by the billions for clean energy projects and other infrastructure in the IIJA and IRA. The U.S. Chamber has also launched its own lobbying campaign, called Permit America to Build. (See Congress Doubling Down on Bipartisan Push for ‘Permitting Reform.’)
The EPW hearing focused on identifying both common ground and the harder-to-resolve flashpoints.
On the plus side were calls for early and robust community engagement and a close look at how to streamline permitting processes across federal agencies.
Christy Goldfuss, NRDC | Senate EPW Committee
“The U.S. must shift the value proposition around clean energy deployment and transmission and move to a model that delivers more benefits directly to communities that host this clean energy infrastructure while providing the benefits of clean energy to everyone,” said Christy Goldfuss, chief policy impact officer of the Natural Resources Defense Council. “This shift will lead to less opposition and therefore faster timelines for getting clean energy projects and transmission deployed at scale.”
Dana Johnson, senior director of strategy and federal policy at WE ACT for Environmental Justice, agreed, “We really need to start community engagement much earlier in the process … Advocates in that space noticed that when industry comes to them, when they are able to negotiate, when we have community meetings before a permitting process even begins, we are able to work in partnership to solve the challenges of bringing a project to fruition.”
The U.S. Chamber of Commerce also “fully support[s] the idea of having early engagement of affected communities with the project developers and everyone else involved,” Durbin said. “We agree that that can help to offset problems later down the road.”
Christina Hayes, ACEG | Senate EPW Committee
Streamlining processes — without changing existing statutes — also got strong support. Christina Hayes, executive director of Americans for a Clean Energy Grid, said construction of new transmission must be doubled “to have a chance at hitting our [greenhouse gas] reduction goals. …
“Specifically, high-capacity, regionally significant transmission should go through a unified federal siting and permitting authority,” Hayes said. “Bright-line thresholds for unified federal siting and permitting authority should be clearly established, which when included [with] a single point of contact for environmental review will provide for a comprehensive and legally durable siting and permitting process. …
“Additionally, developers should consider support through community benefit agreements or revenue sharing. Mitigation beats litigation every time,” she said.
Jay Timmons, CEO of the National Association of Manufacturers (NAM), also spoke in favor of “consolidated processes with enforceable deadlines for the siting of new energy projects, including hydrogen, natural gas, nuclear and other emerging technologies, along with their infrastructure.”
Programmatic environmental impact statements (PEIS) could also promote more efficient permitting, Goldfuss said. A PEIS looks at environmental impacts across a specific region, for example, the Desert Renewable Energy Conservation Plan, which sets out areas for renewable energy development on more than 10 million acres of desert lands in seven counties in Southern California.
Such an approach could allow permitting to “move toward a ‘design one, build many’ model that decouples broad swaths of the environmental review process from individual project timelines,” Goldfuss said.
NRDC also supports “Smart from the Start” planning, which means “planning and siting development in ways that minimize potential impacts and conflict before project-by-project permitting even begins,” she said.
‘Permitting Myopia’
But any change to key environmental laws — like Capito’s call for amendments to NEPA and other environmental laws — are likely to be a point of contention.
Timmons of NAM cited figures from the White House Council on Environmental Quality (CEQ) that the environmental impact statements that NEPA may require for some projects take an average of 4.5 years to complete.
Jay Timmons, NAM | Senate EPW Committee
“More time is spent just projecting potential environmental impacts than it takes to actually construct and operate a clean hydrogen power generation facility,” Timmons said. “We can and we should still set high standards for ourselves. Let’s just modernize the process [so there are] fewer delays, fewer needless losses.”
But Johnson argued that the delays and long permitting timelines attributed to NEPA are overstated, citing decade-old estimates from the Government Accountability Office that less than 1% of federal projects require a full environmental impact statement. Only 5% require a less rigorous environmental assessment and 95% receive a categorical exclusion, meaning no environmental review is required, she said.
Johnson also pointed to interconnection bottlenecks, not NEPA, as a major factor in delays for renewable energy projects. Other reasons for delays of large-scale energy projects include “poor project management, poor contracting approaches, contractors’ financial issues, delayed approvals, delayed payments, clients’ financial issues [and] challenges with the actual design of a project,” she said.
Goldfuss agreed that “permitting myopia” has put too much attention on NEPA. “Broad claims that the permitting process … is broken and that NEPA is the problem are not borne out by the facts,” she said.
Dana Johnson, WE ACT for Environmental Justice | Senate EPW Committee
Instead, she called on FERC to use its “backstop authority,” established in the IIJA, to site lines within “corridors of national interest,” which the Department of Energy must designate.
Using this authority would mean FERC could overrule state regulators and local policy makers’ decisions on such projects, something it has yet to do.
FERC must also act broadly to allocate costs for large transmission projects crossing more than one state, Goldfuss said. If not, “Congress should pass legislation requiring FERC to adopt cost allocation rules that holistically reflect the multiple benefits of transmission.”
How effective such legislation might be is uncertain given FERC’s stalled efforts to approve new transmission planning and cost allocation rules with its current membership of two Democrats and two Republicans.
Both Carper and Sen. Ed Markey also pointed to the $1 billion in IRA funding to help federal agencies hire new staff and improve their permitting processes. That money represents “a new cure,” Markey said. “Now we’re applying the medicine, and we’re waiting for it to kick in.”
The House Debt Ceiling Bill
The narrowly passed Republican bill on the debt ceiling was a tangential concern in Wednesday’s hearing.
Markey noted that the spending cuts in the bill would include the $1 billion to fund permitting improvements across federal agencies. “They want to starve the agencies and then say, ‘Look how long it takes,’” he said.
Martin Durbin, U.S. Chamber of Commerce | Senate EPW Committee
He also defended NEPA as “a safeguard for communities. We need robust, upfront community engagement to power communities with clean energy while empowering them to be part of the [process].”
Sen. Sheldon Whitehouse (D-R.I.) grilled both Durbin and Timmons on whether they would support bipartisan permitting reform crafted by the EPW Committee versus GOP permitting changes in the debt ceiling law, which would primarily push for quicker permitting for fossil fuel projects.
Timmons sidestepped the question, saying NAM was not “going to engage in picking winners and losers between House versions and Senate versions. The interest is in working on a bipartisan … proposal that will actually get done, that everyone can feel good about.”
Durbin said the Chamber had supported H.R. 1, the GOP energy bill included in the debt ceiling package. “We think it does move the ball forward,” he said, but the organization also remains “fully committed to a bipartisan process.”
Attendees gave a wide variety of responses when asked for their definition of the word “cold.” | Texas RE
