Following two years of remote meetings during the COVID-19 pandemic, the NYISO Board of Directors will resume in-person interactions with the Management Committee at their annual joint meeting scheduled for June 13, CEO Rich Dewey told the MC on Wednesday.
“This is really an important meeting for our Board of Directors to hear directly from market participants what the key concerns are; what their issues are,” Dewey said.
Discussion will focus on the ISO’s Grid in Transition initiative and what specific challenges market participants are encountering, Dewey said.
While many market participants have expressed intent to attend the event at the Sagamore Hotel on Lake George, COVID infection rates continue to be high in the capital region and New York state generally, so the ISO has procured a larger space than usual to allow for greater distance among participants and is planning most social activities for outdoors, he said.
“We’re going to send out some information encouraging people not to attend if they’re experiencing any symptoms and just be smart about taking care of themselves and each other as we get ready for an event like this,” Dewey said. “We do recognize that there are some individuals who might want to participate remotely, and we’re looking at how we might be able to accommodate that.”
Dewey closed his report with a reference to the March MC meeting, where he had briefed the participants on the ISO managing some atypically high staff vacancy rates. (See “Staffing Recruitment Improves,” NYISO Management Committee Briefs: March 30, 2022.)
“We’ve had two good recruiting months in a row, and we’ve been able to identify some really top talent that we brought into the organization, so the vacancy rate is down in the range of 9%, which is still a little bit higher than our budget, but we do have a healthy queue of individuals we plan to onboard in the next month,” Dewey said. “At least from a recruiting standpoint, things are trending in the right direction.”
Adequate Capacity for 2022 Summer
NYISO foresees having adequate generating capacity margins for normal weather conditions this summer, without emergency operating actions, but it would require emergency operating actions to varying degrees depending on the severity of extreme weather conditions, Vice President of Operations Aaron Markham reported.
“From a statewide perspective, we expect a surplus of about 2,000 MW for a baseline forecast without operating emergency operating actions, and that dwindles to an approximately 2,300-MW shortfall when we go all the way to the extreme 99-1 [once in 100 years] forecast conditions,” Markham said in presenting the Summer 2022 Capacity Assessment.
2021 and 2022 Summer Capacity Assessment and Comparison | NYISO
Last winter the ISO started including a 99-1 extreme forecast in its capacity assessment and plans to continue to do so to advise stakeholders of what that looks like, he said.
“We do have approximately 3,300 MW of emergency [resources], so when we take into account those, we do show positive margin for all of forecast conditions even up to 99-1 on a statewide basis,” Markham said.
Projected capacity margins for normal and extreme weather conditions without emergency operating actions:
1,918-MW capacity margin for 50-50 peak forecast conditions
-382-MW capacity margin for 90-10 peak forecast conditions
-2,287-MW capacity margin for 99-1 peak forecast conditions
Projected capacity margins for normal and extreme weather conditions with up to 3,294 MW of emergency operating actions:
5,212-MW capacity margin for 50-50 peak forecast conditions
2,912-MW capacity margin for 90-10 peak forecast conditions
1,007-MW capacity margin for 99-1 peak forecast conditions
The ISO is continuing to monitor energy supplies and prices based on global markets and events, and the weekly fuel survey process indicates that the prices for fuel will be higher this summer than in recent history, Markham said. Oil inventories for dual-fuel-capable units are lower than last year but still sufficient for starting the summer.
“We’ve done our normal coordination with the transmission and generator maintenance outages to ensure that, to the extent possible, any outages scheduled over the summer can be recalled on short notice to make sure that the resources are available to meet hot weather needs,” Markham said.
MISO transmission customers filed a complaint with FERC last week that the grid operator should allow its customers to reduce their load without penalty to lessen the possibility of summer blackouts.
The Coalition of MISO Transmission Customers (CMTC) said in a filing that the load reductions will help address a 1.2-GW capacity shortage following MISO’s 2022-23 Planning Resource Auction for its Midwest subregion. The shortfall triggered a $236.66/MW-day cost of new generation entry clearing price for MISO Midwest. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.)
The RTO has said the capacity deficit might force it to order temporary, controlled load sheds this summer and it predicts insufficient firm resources to handle summer peak forecasts under typical demand. The grid operator’s management has also said members must build new generation or risk future blackouts.
CMTC argued that when the capacity auction fails to procure enough supply, it should allow some load to exit the system, bolstering reliability by trimming demand while also avoiding the steep capacity prices.
The group said it has members “actively assessing the need to reduce operations” by more than 200 MW at least through May 31, 2023.
“A significant factor in the customer’s operational decisions is the ability of the customer to avoid the PRA charges that it would otherwise incur,” CMTC told FERC.
The group argued that MISO’s tariff shouldn’t regard PRA charges as “unavoidable and sunk” for load. The group said the tariff is unjust and unreasonable because it doesn’t contain any options for load to leave the system when it faces threats to resource adequacy.
“Because the exit of the customer’s load and possibly other loads would provide reliability benefits to MISO as MISO addresses looming resource adequacy issues in its footprint and the shortage of capacity procured in the 2022/2023 PRA, load should have an opportunity to exit the system without being charged,” CMTC wrote. “MISO’s tariff should be revised to enable MISO to create an orderly process in which load could nominate to exit the MISO system for the remainder of the planning year, in exchange for avoiding PRA charges, to help MISO address the insufficiency.”
The group suggested that MISO could allow load exits equivalent to the 1.2-GW auction shortage and stop accepting any further load reductions once it resolves the supply and demand imbalance.
CMTC asked FERC for expedited treatment of its complaint, requesting a response no later than early July. It also said it had been in touch with MISO about its proposal before it filed the complaint.
California Gov. Gavin Newsom and New Zealand Prime Minister Jacinda Ardern on Friday announced an agreement in which their governments will work together on climate issues such as transportation electrification and climate-smart agriculture.
The aim of the agreement is “to accelerate our efforts, to learn from each other,” Newsom said. “We need each other.”
Ardern said it was “common sense” to collaborate with likeminded partners to meet common goals.
“We both aim to achieve net-zero carbon emissions by the middle of the century,” Ardern said. “This agreement means we’ll work together to share expertise and experience and collaborate on projects that help meet each other’s targets.”
Newsom and Ardern made the announcement during an event in the New Zealand garden at Golden Gate Park in San Francisco.
The transportation sector is the largest source of greenhouse gas emissions for California, and the second largest GHG source for New Zealand, the document noted. And both jurisdictions are interested in reducing GHG emissions from the agricultural sector.
The agreement creates a “flexible framework” for the two parties to cooperate on issues of environmental protection, natural resources and climate change.
Some of the activities specified in the agreement are sharing best practices and possible solutions in zero-emission transportation market development and exchanging ideas on stimulating innovation in the renewable energy and clean tech sectors.
The California Environmental Protection Agency and the New Zealand Ministry of the Environment will coordinate implementation of the agreement, which is effective for five years but may be extended.
The agreement announced Friday isn’t the first collaboration between California and New Zealand.
During the 26th U.N. Climate Change Conference of the Parties in Glasgow, Scotland, in November, the governments of California, Quebec and New Zealand agreed to work together on carbon markets and other climate action. (See Calif., Quebec, NZ Pledge Cooperation on Climate, Carbon Markets.)
On Friday, Newsom said partnerships such as the one with New Zealand took on added importance during the Trump years when “you couldn’t rely on the federal government.”
“It became even more important that we sign memorandums like we’re signing here today with likeminded jurisdictions around the world,” the governor said.
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:
Basic Grid Supply: All grid supply projects that do not qualify for one of the other tranches below (e.g., greenfield solar projects).
Grid Supply on the Built Environment: Solar installed on rooftops, raised carports or similar installations.
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.
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.
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.
Proposed 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.”
As 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:
Wednesday, June 1, 1:00 p.m.: Project prequalification, bid participation fees, and commercial operation date requirements.
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.
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
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.
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.
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.
BOEM 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.”
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.
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.
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.
“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.”
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.
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.
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.
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.
2021 and 2022 Summer Capacity Assessment and Comparison | NYISO
