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August 31, 2024

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Proposed NJ Solar REC Program Wins Initial Support

A New Jersey straw proposal to award solar renewable energy credits (SRECs) through annual procurements, with incentives for projects incorporating storage, won initial support from stakeholders in a Board of Public Utilities meeting May 26.

Representatives of the Division of Rate Counsel, the Solar Energy Industries Association (SEIA) and a solar developer expressed broad support for the Competitive Solar Incentive program (CSI), developed by BPU staff and Daymark Energy Advisors (Docket QO21101186).

The CSI program is one half of the Successor Solar Incentive program adopted by the BPU in July 2021 to implement the Clean Energy Act of 2018 and the Solar Act of 2021 and double the state’s solar footprint by adding 3,750 MW of new capacity by 2026. (See NJ Sees Solar Growth in Reduced Incentives.)

The other half of the BPU’s initiative is the Administratively Determined Incentive (ADI) program, which offers a fixed incentive for net-metered residential projects, net-metered nonresidential solar projects of 5 MW or less and community solar programs.

The 2018 law directed the BPU to redesign the state’s solar incentives and close the Legacy SREC program once it reached 5.1% of the power sold, a threshold attained on April 30, 2020. (See  Solar Subsidy Program Ending in New Jersey.)

As required by the 2021 law, the CSI program will use competitive procurements to target an average of 300 MW of new solar projects annually. All grid supply projects — front-of-the-meter projects that sell into the PJM wholesale market and net-metered non-residential projects greater than 5 MW — will be eligible to participate. (See NJ Solar Proposal Seeks More Market Competition.)

Five Tranches

The straw proposal recommends that the CSI program be structured as five separate procurement tranches to ensure that a range of types of competitive solar projects qualify to receive payments (called SREC-IIs) despite their different project cost profiles:

  1. Basic Grid Supply: All grid supply projects that do not qualify for one of the other tranches below (e.g., greenfield solar projects).
  2. Grid Supply on the Built Environment: Solar installed on rooftops, raised carports or similar installations.
  3. Grid Supply on Contaminated Sites and Landfills: Any currently contaminated portion of a property on which industrial or commercial operations were conducted and a discharge of contaminants occurred; or a properly closed sanitary landfill facility.
  4. Net-metered Nonresidential Projects above 5 MW:   Under the Solar Act of 2021, net metered solar projects of 5 MW or less qualify for inclusion in the ADI program.
  5. Storage Paired with Grid Supply Solar.

Projects eligible to compete in Tranche 2 or 3 would automatically also be eligible for Tranche 1. If some of the Tranche 1 awards go to projects that qualify in the specialized tranches, they would be removed from consideration in the subsequent tranches.

Year 1 Target Procurements (NJBPU) Content.jpgProposed year 1 target procurements by tranche | NJBPU

Price Premium to Reduce Open Space Development

The 2021 law requires that the “development of grid supply solar should be directed toward marginal land and the built environment and away from open space, flood zones and other areas especially vulnerable to climate change.”

The straw proposal said that considering the projects in separate tranches “recognizes that NJBPU may choose to select these projects even if they come at some premium over greenfield solar development, while establishing a competitive structure to set an appropriate market price for these projects.”

NJ Solar Projects (NJBPU) Alt FI.jpgAs of March 2022, there are 76 New Jersey solar projects totaling 1,583 MW active in the PJM queue. Of these, 37 (861 MW) have at least completed a system impact study. | NJBPU

Staff noted that solar on contaminated sites and landfills might face higher costs of mitigating contamination and securing permits but that encouraging projects on such sites would reduce development pressure on open space. The state had 230 MW of solar operating on landfills and brownfields as of the end of February.

Staff said it is uncertain how many qualifying large net-metered projects are likely to compete in the CSI program because of the “unpredictability of a competitive procurement” and limitations on the number of appropriate sites.

“However, the [Transition Incentive program that succeeded the Legacy program] received a robust response from large (> 5 MW) net-metered projects of approximately 120 MW, suggesting that there could be significant potential participation by large net-metered projects,” staff said. “In fact, net-metered projects may have some inherent advantages in a competition against wholesale projects, since they already receive some degree of subsidy, compared to wholesale projects, in the form of net metering credits higher than the wholesale cost of power.”

To ensure the continued diversification of resources as required by the 2021 law, “it would not be desirable to risk awarding all CSI program capacity to net-metered projects,” staff said. “By breaking these projects out into their own tranche, NJBPU will be able to award SREC-IIs to the most competitive net-metered projects, while ensuring that there is still room in the program for other types of projects.”

Storage Adder

Although the 2018 law requires New Jersey to achieve energy storage goals, the state currently lacks an independent energy storage program.

The straw proposal notes that solar projects with storage can obtain higher capacity ratings in PJM markets and are able to arbitrage by storing energy produced when wholesale prices are low and selling when they rise.

Staff said the dedicated storage tranche in the CSI program would provide a storage adder to solar projects that qualify for SREC-IIs in competition with other solar projects and also offer storage competitive within the storage tranche.

Solar-plus-storage projects would make two-part bids: a solar-only SREC-II price and a storage adder price. The project would first be considered as a solar-only project; if it receives an award, its proposed storage adder price would then be considered separately in the storage tranche.

The storage incentive would be limited to four times the total MW of the solar project (e.g., 4 MWh of storage per MW of solar capacity).

Bidding, Maturity Requirements

Staff recommended adopting project qualification and maturity requirements to ensure that selected projects are likely to reach commercial operation.

To prequalify, projects would need to demonstrate “a sufficiently advanced position in the PJM queue (taking into account the realities of the ongoing PJM interconnection reform process)” or a comparable interconnection position in a state-jurisdictional queue. Net-metered projects would be required to show conditional approval of their utility interconnection request.

Projects would be required to pay a $1,000/MW nonrefundable solicitation participation fee and achieve commercial operation three years after registration in the program.

“Using prequalification through queue position would avoid having to engage in a more complex, subjective process relating to permitting, securing right of ways or evidence of public support,” staff said.

Staff proposed resources be paid on a price as bid basis with confidential project cost caps. Among the 34 questions staff seeks input on is whether the SREC-IIs should be fixed or indexed to wholesale energy prices.

Staff recommended all tranches be included in a single procurement to be held once per year. “However, some adjustments to this schedule may be appropriate to coordinate with the implementation of PJM’s new queue procedures, should these be approved,” staff said.

Comments

During Thursday’s hearing, Sarah Steindel, of the state’s Division of Rate Counsel, expressed support for the tranches. “We think that the proposed five tranches are a sufficient number to recognize the legislature’s preferences for certain types of projects, but yet, each tranche is still broad enough to create robust competition.”

She said the Rate Counsel “strongly support[s] the proposal to utilize a confidential bid price cap for each tranche” but was still evaluating the proposal for solar-plus-storage. “We have some concern that … some of the tranche targets may be aggressive, and we recommend that the board consider what options it may have should some or all of the specialized tranches go unfilled.”

Speaking on behalf of SEIA, Nitzan Goldberger of Borrego Solar Systems, was also supportive.

“A pay as bid system, coupled with strong project maturity requirements for bidders, should avoid overpayment to bidders and avoid windfall [profits], minimize project attrition and ensures that the awarded projects reach completion,” she said.

Matt Tripoli, of solar developer CS Energy, echoed Steindel’s concerns that some of the tranches might go unfilled and suggested the BPU consider annual rather than monthly MW limits for the storage adder. We’re “glad to see that Daymark and the BPU are drawing lessons from some of those other states and how they’re constructing this program,” he said.

Fred DeSanti, the executive director of the New Jersey Solar Energy Coalition, said that by adopting a two-step process for storage-plus-solar, “we may be losing some economies because a lot of times when we’re pricing projects … if you do it on a joint basis, you can achieve some lower [costs] than you might by doing it independently.”

Feedback Sought

Staff will accept comments on the straw proposal until 5 p.m. June 20.

The BPU will hold two additional stakeholder meetings:

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Enviros Say It’s Too Soon for Liberty’s Long-term RNG Contract in Massachusetts

The outcome of Liberty Utilities’ petition for a long-term renewable natural gas (RNG) contract will have “a long-lasting impact” on Massachusetts and its climate landscape, Priya Gandbhir, staff attorney at the Conservation Law Foundation, told regulators Thursday.

“There remains significant doubt for many reasons about the viability of biomethane as a sustainable fuel source, as well as doubts around the accuracy of statements about the climate impacts and emissions potential of biomethane,” Gandbhir said during a Massachusetts Department of Public Utilities hearing on Liberty’s petition.

Without clarity on those issues, she added, the state should not approve long-term commitments to procure and combust RNG.

Liberty filed a petition on March 31 (Docket 22-32) seeking approval of a 20-year agreement for RNG supply from Fortistar Methane Group subsidiary Fall River RNG starting in November. The gas utility would blend Fall River’s product into the existing natural gas system.

Fortistar plans to build an RNG facility at the Fall River Landfill in southern Massachusetts to service the contract. As part of the petition, Liberty is seeking approval of a voluntary participation program to allow customers to purchase RNG as a percentage of their natural gas usage.

Utilities in Massachusetts, including Liberty, filed decarbonization plans in mid-March in the DPU’s ongoing “Future of Gas” investigation (Docket 20-80) into the role of gas distribution companies in reducing greenhouse gas emissions. The utilities asked the department to approve their plans, which are still under review. (See National Grid Proposes 100% Fossil-free Gas System in Mass.)

As part of its decarbonization plan in the 20-80 proceeding, Liberty said it would file an opt-in RNG proposal with the department to jumpstart supply by the end of next year and contribute to the state’s 2030 emission reduction target.

The Acadia Center’s senior policy advocate for Massachusetts, Kyle Murray, echoed Gandbhir’s concerns about the petition in his testimony.

“The 20-80 docket … is still ongoing, and a major portion of that is about the viability and safety of RNG and hydrogen,” he said. “We believe that, pending the outcome of that docket, we really should not be making long-term decisions in this instance.”

Approving a plan for blending RNG into the gas system would send a signal to the utilities to “proceed with business as usual,” said Cathy Kristofferson, secretary and treasurer of the Pipeline Awareness Network of the Northeast, in testimony.

“The department must not allow this gas contract petition to be a precedent-setting test case that allows components of the [gas companies’] unapproved net-zero enablement plans to be approved while they do not meet existing regulations or the department’s least-cost supply planning standards,” she said.

In a May 20 filing in its petition docket, Liberty said that litigating climate-related concerns already under review in the 20-80 docket would be “misplaced and inappropriate” in the “narrow” contract proceeding, and the department should not let intervenors, such as CLF and Acadia Center “invoke broader policy issues.”

“The issues that will be adjudicated in this proceeding fall within a narrow standard of review, which, while part of Liberty’s broader proposals in [the 20-80 docket], requires Liberty to make a particular showing to obtain the department’s approval of the proposed contract,” Liberty said.

However, Kristofferson argued during the hearing that Liberty’s May 20 comments demonstrate a duality of thinking by the utility.

“Liberty uses the need to comply with the Global Warming Solutions Act and their participation in the 20-80 proceeding … to justify this RNG contract, yet the company urges … that broader policy issues not be brought into this gas contract proceeding by NGO intervenors,” she said.

Gandbhir asked the department in her testimony to look beyond the narrow scope of the proceeding in reviewing Liberty’s petition.

“CLF requests that the department consider this docket not simply as a standalone petition for approval of this particular agreement, but look at it fully in the context of Massachusetts’ significant efforts to adequately and appropriately plan our climate future,” she said.

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NERC Plans Big Budget Hike for 2023

NERC’s draft 2023 business plan and budget shows the organization’s expenses are set to rise by more than 13% in 2023, fueled by increasing headcount, a return to in-person meetings and operating expenses that include the biannual GridEx security exercise and growing technology costs.

The ERO posted its draft budget Wednesday, along with those of the regional entities. The organization is accepting comments on the drafts through June 24, with the goal of submitting the final budgets to its Board of Trustees for approval at its next open meeting in August.

ERO Enterprise 2023 budgets and assessments (NERC) Content.jpgERO Enterprise 2023 budgets and assessments | NERC

 

All of the RE budgets are slated to grow next year as well, with the Midwest Reliability Organization increasing the most, at 15.2%, and the Texas Reliability Entity rising the least, at 3.3%. The overall ERO Enterprise budget is expected to be $248.9 million, about $22.7 million more than the budget for 2022. Assessments are also planned to rise across most of the enterprise, with the total for NERC and the REs growing by $14.2 million to $214.6 million; the sole exception is WECC, where the assessment is set to fall 17.2% to $20.7 million.

New Employees, GridEx Biggest Cost Drivers

NERC’s $100.8 million proposed budget, up from $88.8 million last year, represents the biggest increase since 2015, when the inception of the Cybersecurity Risk Information Sharing Program drove that year’s budget to grow from $56.4 million to $67.2 million, a rise of 18.3%. It is also more than double the average annual budget increase of 5.7% for the last 10 years.

The biggest line item in the 2023 budget is personnel, which is set to rise 11.6% to $58 million. In part this is because of NERC’s expectation of hiring 14 new full-time employees next year, part of its overall plan to add 37 employees by 2025. The new hires are expected to be concentrated in the information technology sector, reflecting NERC’s belief that cybersecurity is one of the top risks facing the North American bulk power system, as reflected in last year’s ERO Reliability Risk Priorities Report. (See Grid Transformation, Cybersecurity Lead 2021 ERO Risk Report.)

Another component of the increase in personnel costs is the planned merit-based pay increases that will average 5.5 to 6% over the next three years because of “inflationary pressures and increased demand for cybersecurity and IT talent.” The draft budget emphasized that this is only an estimate based on “market supply and demand,” but NERC is planning to conduct a market compensation study before the 2023 review cycle to help determine the appropriate amounts for raises.

The next biggest budget segment is operating expenses, which is set to rise 17.7% to $35.7 million. The biggest contributor to this increase is the Electricity Information Sharing and Analysis Center, which will see its budget rise from $32.8 million to $37.7 million. This is primarily because of GridEx, which is held every other year and thus will not see any expenses in 2022.

The budget for meetings and travel is increasing as well, as NERC continues to anticipate a limited return to in-person meetings that were sidelined for the last two years during the COVID-19 pandemic. The board was to have held its first face-to-face meeting since 2020 this month in Virginia, but it switched to virtual sessions after an attendee tested positive for the coronavirus at the meeting site; the August meeting is still expected to be held in person in Vancouver, Canada. (See NERC Board of Trustees/MRC Briefs: May 11-12, 2022.)

These increases are expected to be slightly offset by lower spending on rent for NERC’s Atlanta office, thanks to “lease concessions” that the organization negotiated after plans to relocate the headquarters this year fell through. (See NERC Shelves 2022 Atlanta Relocation Plans.) NERC said it expects to save about $300,000 on rent for the current office per year through 2025, when it may revisit the moving plans.

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California Energy Commission Postpones Vote on Offshore Wind Goals

The California Energy Commission postponed its expected vote this week to establish offshore wind targets after stakeholders argued in a May 18 workshop that the commission’s proposed goals of 3 GW by 2030 and 10 to 15 GW by 2045 are too conservative.

“In light of new information submitted during the workshop and public comment opportunity … [including] studies released after the draft report posted … Commissioner [Kourtney] Vaccaro will conduct a public workshop to further examine this new information to consider possible changes to the draft report recommendations for megawatt offshore wind planning goals for 2030 and 2045,” a CEC statement announcing the change said.

The CEC had not posted the date of the planned workshop as of Thursday.

The draft report proposing the targets stemmed from last year’s Assembly Bill 525, which required the CEC, by June 1, to “evaluate and quantify the maximum feasible capacity of offshore wind … [and to] establish megawatt offshore wind planning goals for 2030 and 2045.” The effort is intended to contribute to the state’s goal under Senate Bill 100 to supply all retail customers with 100% clean energy by 2045.

In written comments to the CEC, a group of University of California, Berkeley, scientists recommended the state set a goal of 50 GW by 2045, based on the National Renewable Energy Laboratory’s (NREL) estimate that California coastal waters have a “technical potential” for 200 GW or more of offshore wind.

Technical potential is the amount of offshore wind capacity that could be developed “while taking into account exclusion factors related to water depth, mean wind speed, industry uses and environmental conflicts,” NREL said in an October 2020 report. “By contrast, gross potential is the capacity without these exclusions.” NREL estimated the state’s gross potential at nearly 1,700 GW.

“Our view is that the maximum OSW capacity is significantly higher than the reference potential [of 21.8 GW] considered by the CEC, and that CEC should consider higher 2045 planning goals that reflect the updated technical-potential finding of 200 GW,” the scientists wrote. “We suggest a 50 GW planning goal for 2045 … [because it] would reflect full consideration of the immense benefits to the grid of offshore wind.”

Molly Croll with wind developer Avangrid Renewables said at the May 18 workshop that her company agreed with the CEC’s proposed 3-GW goal by 2030 but recommended setting the 2045 goal higher at 18 to 20 GW. (See OSW Advocates Urge California to Think Bigger.)

Kelly Boyd, business development lead with wind developer Equinor USA, said the state’s proposed target of 3 GW of offshore wind by 2030 “is a modest initial goal, especially if we want to get to 20 GW or higher at some point.”

Whether the CEC can meet AB 525’s requirements by June 1, a week away, is now in doubt, and the commission has not said how it expects to get around the legislature’s directive.

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BOEM Issues Proposed Sale Notice for California Offshore Wind Areas

The federal Bureau of Ocean Energy Management issued a proposed sale notice Thursday for five lease areas off the California coast, taking a major step toward anticipated auctions later this year and the development of the first offshore wind farms on the West Coast.

Two of the proposed lease areas in the proposed sale notice (PSN) are in the Humboldt Wind Energy Area off the coast of Northern California, near the city of Eureka. Three are in the Morro Bay Wind Energy Area off the Coast of Central California, about halfway between Los Angeles and San Francisco.

Together, the wind energy areas (WEAs) cover 583 square miles and have the potential to generate at least 4.5 GW of electricity, enough to power 1.5 million homes.

“The proposed lease areas include the entirety of the Humboldt and Morro Bay WEAs,” BOEM said on its California webpage. “The WEAs were subdivided so that each proposed lease area is of roughly equal power generation potential and geographical size [and] is delineated in a manner to maximize energy generation.”

The areas were also designed to facilitate a fair return to the federal government through competitive bidding, it said.

BOEM based the lease area boundaries on the findings of a study published in April by the National Renewable Energy Laboratory that assessed the Humboldt and Morro Bay WEAs.

PAC_California_WEAs (BOEM) Content.jpgBOEM plans to auction areas of the Humboldt Wind Energy Area off Northern California and the Morro Bay Wind Energy Area off Central California this fall. | BOEM

Trade groups reacted favorably Thursday to the news that BOEM has issued its PSN.

“By issuing today’s proposed sales notice and staying on track for an auction in the fall, BOEM is showing that it’s serious about advancing floating offshore,” Adam Stern, executive director of Offshore Wind California said in a statement.

The effort will “drive economies of scale and [help to] realize the very substantial clean power, climate and jobs benefits that offshore wind can deliver for our state and the nation,” Stern said.

The Business Network for Offshore Wind said the move represents a “step forward in the development of the next generation of offshore wind technology” because ocean depths off California require floating turbines, not the stationary units installed off the East Coast.

“Floating markets are advancing quickly in Asia and Europe, creating a race to develop our own capabilities and position the U.S. as a global leader in this cutting-edge market,” Business Network CEO Liz Burdock said in a statement.

“The Business Network congratulates President [Joe] Biden’s and [California] Governor [Gavin] Newsom’s administrations for this historic moment bringing offshore wind to the world’s fifth largest economy and taking necessary steps to set up a robust supply chain of domestic businesses that will elevate America as a frontrunner to an in-demand technology.”

Seeking Feedback

Planning efforts for port development, transmission and other key infrastructure are underway at the California Energy Commission and CAISO. (See California Port to Start OSW Upgrades and CAISO Sees $30B Need for Tx Development.) Experts, however, have expressed concerns that those efforts could lag development plans. (See West Coast Wind Faces Big Challenges.)

At the Pacific Offshore Wind Summit in San Francisco in late March, BOEM Director Amanda Lefton said the West Coast’s first offshore lease auctions would be held later this year for the Humboldt and Morro Bay WEAs. Her announcement prompted spontaneous applause from audience members, many of whom were wind developers.

“Let me be clear,” Lefton said. “We are going to hold a statewide offshore wind energy lease sale in California this year. The sale will offer up wind energy areas in the northern and central coasts, and these areas will enable the buildout of significant new domestic clean energy over the next decade or more. This will also help California reach its carbon-free energy goal by 2045.”

California Senate Bill 100 requires the state’s utilities to supply retail customers with 100% clean energy by 2045. The state’s offshore wind plans are part of the Biden administration’s national goal to develop 30 GW of offshore wind by 2030.

At the summit, Lefton also announced BOEM’s intent to issue a proposed sale notice, saying it would provide a “first look at the [proposed] lease terms and will ask for feedback on important initiatives for … labor agreements, credits for domestic supply chain investments, engagement with tribal nations and ocean users, and working with the commercial fishing industry.”

The PSN includes a request for feedback from stakeholders within 60 days. A final sale notice (FSN) must be issued at least 30 days prior to BOEM holding lease auctions.

“The designation of final lease areas in the FSN will be informed by comments received in this PSN and other relevant data,” BOEM said in its proposed sale notice.

In the meantime, BOEM is scheduled to hold the fifth meeting of its California Intergovernmental Renewable Energy Task Force on June 3. The “half-day virtual meeting will provide updates on offshore wind energy activities and discuss next steps in the BOEM authorization process,” BOEM said.

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Siting Is New England’s Biggest Tx Challenge, Say Region’s Energy Leaders

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BREWSTER, Mass. — “Transmission, transmission and transmission.”

Those are the top three near-term priorities of FERC Commissioner Willie Phillips, and his message was well received in New England last week, where energy regulators and officials were gathering for the New England Conference of Public Utilities Commissioners’ annual Symposium.

The region’s energy experts are well aware that the clean energy transition, and states’ goals to add thousands of megawatts of clean energy a year, will require new wires to carry that electricity to consumers.

Johannes Pfeifenberger 2022-05-23 (RTO Insider LLC) FI.jpgJohannes Pfeifenberger, Brattle Group | © RTO Insider LLC

FERC is hoping to send help as they work on a Notice of Proposed Rulemaking, issued in April, that would require longer-term regional transmission planning and new cost allocation procedures for projects (RM21-17).

“The NOPR proposal … can help us ensure reliability of our system, and I believe it can bring costs down for our consumers, if we do it right,” Phillips told the NECPUC audience.

Johannes Pfeifenberger, an economist and principal at the Brattle Group, said the NOPR is “an opportunity to … create a tariff structure that allows more proactive, multivalue planning to come to this region.”

To some of those tasked with putting up wires in New England, however, the broader planning issues aren’t the main barrier.

Bill Quinlan 2022-05-23 (RTO Insider LLC) FI.jpgBill Quinlan, Eversource | © RTO Insider LLC

“The planning of the system I think is well in hand between [ISO-NE] and transmission owners,” said Bill Quinlan, Eversource Energy’s president of transmission and offshore wind projects. “We can engineer these projects; we certainly know how to finance these projects. Where most large infrastructure projects get held up is either in siting or disputes about cost allocation.”

He said the rulemaking is a “very positive framework” to operate in, but that siting is the biggest hurdle.

The opposition to transmission projects has gotten both more political and more sophisticated, said Jared des Rosiers, a partner at Pierce Atwood who focuses on siting.

“These siting processes really are political campaigns. The messaging is messaging of the political process,” he said. “It’s not so much about the facts and the benefits of the project and what it does in terms of investments or jobs or taxes. It’s soundbites or messages that attract or support or oppose different groups.”

Jared des Rosiers 2022-05-23 (RTO Insider LLC) FI.jpgJared des Rosiers, Pierce Atwood | © RTO Insider LLC

Des Rosiers also said the fact that there are now competitive solicitations for transmission projects creates new, challenging dynamics. It’s no longer just “abutters or neighbors or NIMBYs” (not in my backyard) who are stepping up to challenge projects.

“We’ve gone to a competitive process for transmission. By its nature, that means there are winners and losers in the procurement for transmission,” des Rosiers said. “Once you lose the solicitation, you may now participate in the siting process in a way that is not necessarily constructive for getting the project sited.”

He called on political leaders in the region to step up their messaging efforts around building transmission and focus on the process in addition to the policy.

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Midwest Capacity Shortage Leads to Must-offer Talk

CARMEL, Ind. — MISO’s capacity auction shortfall has nearly doubled its probability of load shed in its Midwest region over last year, prompting stakeholder calls for an expansion of must-offer requirements and sounder supply predictions ahead of the auction.

The capacity shortage will lead to a one-day-in-5.6 years loss-of-load risk (or 0.179 days/year) in the Midwest beginning June 1, instead of the targeted one-day-in-10-years (0.1 days/year) MISO reported Wednesday.

Auction results indicate a 7.7% reserve margin in the Midwest, one percentage point below the planning reserve margin MISO prescribed heading into the auction.

MISO Independent Market Monitor David Patton said he doesn’t expect an increase in load shed during the 2022-23 planning year, but said next summer seems fraught. (See MISO Exec, IMM Debate Next Steps After Capacity Auction Shortfall.)

The April capacity auction cleared MISO Midwest at a $236.66/MW-day cost of new entry for generation, reflecting a 1.2-GW shortfall across the subregion. Staff have told stakeholders to prepare for the possibility of temporary, controlled load shedding over the summer months. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.)

MISO said its Zones 4, 5 and 6 “relied significantly on the auction” to meet resource adequacy requirements. Southern Illinois’ Zone 4 needed outside resources to cover 20% of its requirements before the auction, while Zones 5 and 6 in portions of Missouri, Indiana and Kentucky needed about 15% each.

Zakaria Joundi 2022-05-24 (RTO Insider LLC) FI.jpgMISO Director of Resource Adequacy Coordination Zakaria Joundi | © RTO Insider LLC

During Wednesday’s Resource Adequacy Subcommittee meeting, MISO Director of Resource Adequacy Coordination Zakaria Joundi pledged future discussions with stakeholders on how the RTO can improve its public-facing and preliminary supply data before auctions.

MISO said this year’s planning resource mix “shows the continuation of a multiyear trend toward less solid fuel and increased gas and nonconventional resources.” It said the capacity supplied by load-modifying resources increased 4.4% planning-year-over-planning-year.

The grid operator said 21 generation resources representing 3.4 GW in the Midwest footprint choose not to participate in the voluntary auction.

The RTO’s and the Organization of MISO States’ annual resource adequacy survey last year indicated 10 of the resources were deemed “high certainty” to be available for the 2022-23 planning year.

The other 11 resources were rated “low certainty.” The Monitor granted all 11 auction participation exclusions.

Minnesota Public Utilities Commission staffer Hwikwon Ham asked whether MISO tried to reach out to members to ask why they chose not to offer.

Eric Thoms, senior manager of resource adequacy operations, said MISO is still parsing through auction results data and has not communicated with those resource owners.

“I think now we’re trying to internalize some of the data,” he said.  

Ham said those energy resources that didn’t offer should be considered “speculative.” MISO resources that are not classified as capacity planning resources do not have a must-offer requirement.  

Monitor staffer Michael Chiasson recommended that the RTO extend a must-offer requirement to energy resources. He said the Monitor’s hands are tied by the MISO tariff to mitigate withholding resources that are not deemed planning resources and that it can’t recommend withholding sanctions on any resources other than capacity resources.

The IMM’s Taylor Martin also pointed out that MISO excludes resources with planned summers outages from auction participation.

WEC Energy Group’s Chris Plante asked whether staff has considered that some unit owners are using up to three-year suspension status to maintain MISO interconnection rights so they can retire and replace generation. Plante said such unit owners might be keeping a grip on their rights and never had the intention to participate in the auction.

Stakeholders have also asked MISO to evaluate how it calculates its capacity import and export limits between the 10 local resource zones in the auction given the changing generation fleet.  

The grid operator has said new intermittent resources and baseload generation retirements impact base transmission system line loadings and the ability to import and export power, in some cases reducing necessary counterflow or increasing constraints. The RTO said the “location and availability of generators to ramp up during transfer and to redispatch around identified constraints is shrinking.”

MISO and stakeholders will continue dissecting the auction’s results and tee up possible process changes stemming over the summer.

The RTO’s plan to alter its annual capacity market into four seasonal capacity auctions with an availability-based capacity accreditation is still pending before FERC. Joundi said MISO hopes to have a decision from the commission within the next few months.

Meanwhile, staff plans to register their first energy storage resources for participation in its wholesale markets, including the capacity auction, by Sept. 1. FERC in 2020 accepted MISO’s Order 841 compliance plan to fully incorporate electric storage resources (ER19-465).

The grid operator hopes to finalize its business practice manuals accompanying the compliance plan by July 29. Stakeholders have asked for a refresher on the RTO’s market storage participation plan.

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ERCOT Issues Another Operating Condition Notice

After a brief respite, the heat has returned to Texas and, with it, more stress on the ERCOT grid.

The state’s grid operator issued an operating condition notice (OCN), its second of the late-spring season, to market participants for Saturday through Monday. ERCOT said it is forecasting temperatures to be above 94 degrees Fahrenheit in its North Central and South Central weather zones.

ERCOT projects demand to peak at 67.2 GW on Saturday. About 16 GW of thermal generation was offline as of Thursday morning, a persistent problem with the grid operator’s conservative operations that has procured about 5 GW of operating reserves each day.

Weekend Forecast (Accuweather) Content.jpgThe weekend forecast for Texas | Accuweather

 

Demand was only expected to just top 60 GW on Thursday.

A cold front last weekend brought more seasonable temperatures and thunderstorms to much of Texas after weeks of May heat. However, a high-pressure system over the state is expected to pull in moisture from the Gulf of Mexico and increase humidity as temperatures escalate into the 90s. Far West Texas and the Panhandle are expected to break triple digits this weekend.

The grid operator issued an OCN on May 3 that was extended several times through May 20. OCNs are ERCOT’s lowest-level communication in anticipation of a possible emergency condition. Any emergency condition comes when staff determine the system’s safety or reliability is compromised or threatened.

ERCOT asked Texans to conserve electricity on May 13, which officials later termed a “request.” Interim CEO Brad Jones has said he is “confident” about the summer, while Public Utility Commission Chair Peter Lake continues to say the grid “is more reliable than it has ever been before.” (See ERCOT, PUC Say Texas Ready for Summer.)

During that period, demand eventually peaked at 71.2 GW on May 19, the fourth straight day demand exceeded 70 GW and the sixth time that month. The monthly record for May had been 67.3 GW, set in 2018. The June record is 70.3 GW, set last year.

ERCOT is expecting peak demand to hit a record 77.3 GW this summer, according to its latest seasonal assessment of resource adequacy Monday. That would shatter the current all-time mark of 74.8 GW set in August 2019.

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Solar Supply Chain Issues Dog PNM Coal Plant Replacement Plan

Public Service Company of New Mexico (PNM) exhausted every preferred alternative before postponing the retirement of the coal-fired San Juan Generating Station until the end of this summer, a company executive said Wednesday.

The two remaining units at the plant, located in San Juan County, N.M., had been scheduled to close June 30 before the state’s Public Regulation Commission (PRC) in February approved PNM’s request to extend its life by another three months to cover a projected 120-MW shortfall in summer generating capacity.

In 2019, PNM filed with the PRC to abandon its 497-MW stake in the San Juan plant, proposing to replace its output with 650 MW of solar paired with 300 MW of four-hour battery storage. With 45 MW in supplemental demand-side management, the replacement resources were expected to provide 432 MW of effective load-carrying capability. PNM contracted to have all the new resources become operational in time to meet the 2022 summer peak — before San Juan was shuttered.

“This is what we were expecting to have online by about today, and I’ll be frank … none of it is here. All four developers of those solar hybrid projects failed to meet their expected commercial online dates,” Nicholas Phillips, PNM director of resource planning, said Wednesday during a WECC summer readiness virtual workshop.

Phillips said developers have told PNM that supply chain disruptions are the key hurdle to advancing projects, a product of both the COVID-19 pandemic and the U.S. Department of Commerce’s ongoing investigation into whether Chinese companies have been thwarting trade restrictions by dumping solar equipment into the U.S. through firms based in other Asian countries. (See Solar Sector Braces for Tariff Probe Impact.)

Prices for solar have risen by 50 to 100% or more since the onset of the pandemic, while battery costs have jumped by about 30 to 100%, according to Philips. Even prices for simple cycle turbines have increased by 10 to 20%, he noted.

“The supply chain disruptions are hitting all parts of the market, making equipment tough to come by,” he said.

Supply issues extend to the transmission side as well, with generator interconnection timelines being pushed out because of difficulties in securing transformers and other protection-related equipment, in part because of labor shortages, Phillips said.

“We’re facing labor issues here in New Mexico as well, in terms of trying to get enough contractors to actually perform work to construct the interconnection facilities to get generators interconnected on time,” he said.

‘Not Just a Blip’

With the shutdown of San Juan looming in June and no new resources available to replace the facility, PNM — which operates a 2,000-MW peak system — forecasted that it would face a -5.5% reserve margin over the July-September summer peak period.

Phillips said the utility explored multiple options to address the capacity shortfall. It secured a deal to purchase 40 MW from a neighboring utility, won a bid for 150 MW for June and September (but not for the more critical months of July and August) and purchased 85-MW unit-contingent energy from the Four Corners coal plant in New Mexico.

But multiple requests for proposals that PNM issued turned up no viable projects to meet the summer 2022 peak, and a utility review of existing assets for possible capacity expansion determined that none of those upgrades could be completed in time. The utility also found little liquidity in the region’s forward market for electricity.

As a result, PNM decided to keep Unit 4 of San Juan operating through the summer, which will provide 327 MW of capacity and bump the utility’s forecast reserve margin to 17.4% for July-August and 25% for September. The unit will run at full load over the summer period to reduce cycling, Phillips said.

“Given those purchases that we were able to make and the additional capacity that we are getting now from our existing San Juan unit for continuing its operations … we are at a pretty comfortable level,” Phillips said. “You know, I’m a resource planner: I’m probably never comfortable. It’s not where I want it to be; it’s not where I would like to be in the future.”

Beyond this summer, the future looks less certain for PNM. While the utility expects two of its original projects — totaling 350 MW of solar and 170 MW of storage — to be online by early next year, the other two are currently subject to renegotiation. Phillips said PNM has talked with a “number of different developers” to find one that could complete the projects, which it hopes to bring online by summer 2024.

Because New Mexico’s clean energy rules make it impossible to further extend San Juan’s life, PNM will continue to “canvass the market” in search of new clean resources, Phillips said. He thinks the supply chain issues that have delayed the utility’s existing projects are “not just a blip.”

“They’re going to persist for a while.”

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Cold Weather Standards Team Seeks Industry Support

Members of the team working on NERC’s new cold weather standards project warned industry Tuesday that much work remains to be done to prevent grid damage from future extreme winter events.

In a webinar aimed at winning over industry stakeholders during the project’s first formal comment and balloting period, which began last Thursday, the standards development team (SDT) for Project 2021-07 (Extreme cold weather grid operations, preparedness and coordination) went over the changes that voters will find in the new standards: EOP-011-3 — Emergency operations, and EOP-012-1 — Extreme cold weather preparedness and operations.

NERC started the project last year in response to its joint inquiry with FERC into last February’s winter storms that knocked thousands of megawatts of capacity offline in Texas and left households across the state without power for days. (See FERC, NERC Release Final Texas Storm Report.) The goal of the standards project is to implement the report’s recommendations, which include requiring generator owners and operators to identify and protect cold weather-critical components, build or retrofit generating units to operate to specific ambient temperatures and weather, and perform annual training on winterization plans.

In a sign of the urgency with which FERC and the ERO Enterprise view the project, NERC’s Standards Committee voted last week to shorten the initial comment and ballot period from 45 days to 30, with voting to take place in the last 10 days. (See NERC Cold Weather Standards Set for Shortened Comment Period.)

Evergy’s Kenneth Luebbert, a member of the SDT, opened the webinar by reminding listeners that the industry already has many “tried and true methods” to prevent issues with winter weather, which the team expected would be part of their response to the standards; he also acknowledged that this may not be as easy in the case of newer technology.

“I don’t believe we [currently] have an industry-proven method to address icing on wind turbine blades,” Luebbert said, referring to one of the common causes of outages during last year’s storms. “So, when we go into the new standards … you’ll see that we have exceptions for where there [are] not commercially [or] technically available methods … and we have a way to address that. But where there is … our full expectation is that the industry would do those steps.”

Most of the new requirements developed by the SDT apply to EOP-012-1, the first planned standard to specifically address performance during cold weather. It includes minimum criteria for freeze protection measurements to be implemented by generator owners; for instance, generating units must be capable of continuous operation in the minimum hourly temperature experienced at their location since 1975 (or the earliest date for which reliable records are available). GOs are also expected to account for the effects of wind and precipitation.

For EOP-011-3, the SDT elected to expand requirement R1 to add additional criteria that transmission operators should consider when developing load-shedding procedures, and to revise R2 to clarify that TOPs are responsible for implementing the load-shedding provisions that balancing authorities create. The team also moved to EOP-012-1 several requirements that were added to EOP-011-2 as part of NERC’s last cold weather standards project, which FERC approved last year. (See FERC Approves Cold Weather Standards.)

Phase 2 Planned for Next Year

Team members also previewed future planned efforts to prepare the grid for extreme cold. The two standards discussed on Tuesday comprise Phase 1 of the overall cold weather strategy and are being developed under an accelerated schedule in hopes of submitting them to NERC’s Board of Trustees for approval by Sept. 30.

Phase 2 will address more recommendations from the FERC-NERC report, with the goal of sending more new standards to the board by Sept. 30, 2023. Issues to be tackled in this stage include specifying the role of GOs and GOPs, as well as BAs, in determining generator capacity, along with requirements protecting natural gas infrastructure from load shedding. Luebbert acknowledged that NERC had received requests to add these elements to the first phase but said the ERO decided to save them for next year so as not to overload the current project.

“To the extent Phase 1 was pretty meaty, and there was quite a bit we had to get done this year, we chose to go ahead and leave the phases as they were, and go ahead and address those requirements [in the] next phase,” Luebbert said. “So, to the extent industry would like to see more language around communication, that will be forthcoming.”