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November 5, 2024

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FERC OKs New Queue Priority for MISO, SPP Seams Studies

FERC on Friday approved MISO’s and SPP’s plan to assign a new prioritization of projects to study in their respective interconnection queues.

The new priority will employ a “first-ready, first-served” approach in which the RTOs study the projects that are primed for interconnection first, rather than based upon the order in which they entered the queue (ER22-1533).

FERC said the new arrangement will provide more certainty by establishing a rank when the projects pass the queues’ first decision points instead of when they submit an interconnection request (SPP) or when they pay study fees (MISO).

The commission said the queues’ first decision-point deadlines are an appropriate touchstone because they’re “a point in time after most delays in the interconnection study processes occur.” The new priority should “reduce the possibility that lower-queued cycles or clusters will not have affected systems information from higher-queued cycles or clusters when major commercial decisions are made,” FERC said.  

The priority will be used for the RTOs’ system impact studies, affected system studies, and cost assignments for network upgrades. The grid operators study each other’s nearby IC generation projects for potential effects that might require transmission upgrades in their footprints. MISO and SPP assign network upgrades costs identified in interconnection studies based on queue priority.

The grid operators said their ongoing joint targeted interconnection queue (JTIQ) transmission planning study compelled them to reexamine queue priority to ensure higher-queued generation projects aren’t holding up more prepared but lower-queued projects. (See Midwest Energy Policy Series Addresses JTIQ Projects.)

The new approach is effective with the 2020 cycle of MISO interconnection requests and the 2017 cluster of SPP requests.

The RTOs said their current practice “can lead to situations where interconnection customers are required to make significant commercial decisions about the viability of their projects without knowing what network upgrade costs they will be assigned after projects with higher queue priority have been studied.”

EDF Renewables supported the change, saying that it is “often faced with having to execute a generator interconnection agreement 12 to 18 months prior to receiving final affected system cost responsibility.”

Invenergy said the new prioritization will improve cost certainty for IC customers but said the effective date leaves out customers that entered the MISO queue in 2018 and 2019 and are still awaiting SPP study results. (See CGA Requests MISO Help for Late-stage Interconnection Projects.)

But FERC said the “proposed transition point appropriately respects the expectations of existing interconnection customers while improving the affected system study process for new interconnection customers.” It declined Invenergy’s request to include the 2018 and 2019 MISO queue cycles in the new ranking.  

The change comes as MISO and SPP are proposing to do away with their affected system study process and instead conduct more frequent interregional studies like the JTIQ to get more generation online near their seams. (See SPP, MISO Propose Scrapping Affected System Studies.)

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Western States Play Catch-up on Community Solar

As the Biden administration has set a goal of expanding nationwide community solar capacity to 20 GW by 2025, several Western states are pursuing initiatives that could encourage community solar development.

The New Mexico Public Regulation Commission (PRC) in March adopted rules to launch a community solar program.  A yet-to-be-appointed program administrator could start soliciting community solar projects as soon as this summer.

The Arizona Corporation Commission this month ordered Arizona Public Service (APS) to form a working group to help create a community solar program. The commission expects to vote on a proposed program in November.

And on Wednesday, the California Assembly passed AB 2316, which would require the CPUC to open a proceeding by March 2023 to create a community renewable energy program. The bill now heads to the Senate.

Despite its abundance of solar resources, much of the West has lagged when it comes to community solar programs, Matt Hargarten, vice president of campaigns at the Coalition for Community Solar Access (CCSA), told NetZero Insider. Even though Colorado was a pioneer in community solar, other states such as New York, Massachusetts and Florida are taking the lead in developing new solar capacity, according to data from the National Renewable Energy Laboratory.

New York and Massachusetts are attracting private capital to community solar by providing long-term certainty about the programs, Hargarten said.

But the recent actions in California, Arizona and New Mexico indicate the West might start catching up.

“We’re really optimistic about some of the progress the West has been making,” Hargarten said.

Solar Sharing

Community solar offers a way for people who are unable to install their own rooftop solar to subscribe to off-site renewable energy projects. Subscribers receive credits on their electric bills based on their share of the project’s generation.

According to CCSA, community solar projects are smaller-scale installations often built on private land, former industrial sites or landfills. CCSA said that, nationwide, community solar generates more than 5 GW of power.

The National Community Solar Partnership (NCSP), a U.S. Department of Energy program, defines community solar as projects to which multiple entities subscribe through voluntary action. NCSP doesn’t set a size limit on what constitutes community solar.

At the end of 2020, community solar projects across the U.S. had a combined capacity of about 3,253 MW. At that time, community solar encompassed 1,600 projects in 39 states and Washington, D.C., according to an NREL report last year.

About 72% of the community solar capacity was in four states: Minnesota, Florida, Massachusetts and New York.

State policy is one factor influencing community solar development. Twenty-two states and Washington, D.C. have passed laws to enable community solar, NREL said. Those states have typically allowed virtual metering that lets community solar subscribers receive benefits from their participation.

While enabling legislation can help pave the way for community solar, other state policies may slow deployment, DOE said in a summary of lessons learned. That includes limits to net metering and barriers to third-party development.

DOE set a nationwide goal in October of developing enough community solar to power 5 million homes by 2025, or about 20 GW of capacity. Meeting that target would save customers an estimated $1 billion on their energy bills, an average savings of about 20%.

California Bill Advances

California’s Assembly passed AB 2316 on a 47-22 vote.

The bill, by Assemblyman Christopher Ward (D), would instruct the CPUC to establish a community solar program in which at least 51% of subscribers are low-income. The bill asks the CPUC to minimize impacts of the program on non-subscribing ratepayers.

Although customers of the state’s investor-owned utilities have access to existing community solar programs, such as the Green Tariff Shared Renewables (GTSR) program, participation in the programs is low, according to an analysis of AB 2316.

Supporters of the bill say a new community renewable energy program is needed because GTSR is “crippled by outdated statutory constraints,” the bill analysis said. Those include financing difficulties and a lack of energy storage.

“Moreover, the coalition [of supporters] notes a properly structured community renewable energy program will drive further renewable energy development, potentially aiding in system reliability,” the analysis said.

Investor-owned utilities oppose the bill due to concerns that the customer bill credit will shift costs, the analysis said.

Arizona Program

The Arizona Corporation Commission (ACC) on May 18 directed APS to form a working group to help with the creation of a community solar program. The commission will consider the proposed program in November and, if approved, it would be implemented within six months.

The directive came as an amendment to an order approving APS’ renewable energy standard implementation plan for 2022 to 2026. The amendment, proposed by Commissioner Anna Tovar, was approved on a 4-1 vote with Commissioner Sandra Kennedy opposed.

The working group will meet at least every other week starting in June. In designing the APS community solar program, the working group will look at other successful programs, such as Xcel Energy’s program in Minnesota. ACC also wants the program to attract long-term private sector investment.

The program will set aside a percentage of capacity for low-income customers. The working group may also consider community wind projects or including battery storage with community solar projects.

“This is a really big first step in Arizona,” said Autumn Johnson, executive director of Arizona Solar Energy Industries Association (AriSEIA).

Johnson said AriSEIA plans to participate in the working group meetings. Others who are interested in participating are asked to contact Tovar’s office.

New Mexico Program

In New Mexico, state lawmakers last year passed Senate Bill 84, the Community Solar Act. The state’s PRC adopted rules in March to implement the law.

In an initial three-year phase of the program, community solar will be capped at 200 MW across the state’s three investor-owned utilities, with a 5 MW cap for individual projects.

Native American nations, tribes and pueblos are exempt from law, but may own or operate solar projects in New Mexico.

The law requires each community solar project to have at least 10 subscribers. Up to 40% of a project’s capacity may go to a so-called anchor tenant. At least 40% of capacity must be available in subscriptions of 25 kW or less, and at least 30% of capacity must be reserved for low-income subscribers and related service organizations.

The PRC is in the process of finding an administrator for the program. The commission issued a request for proposals in April, with a May 12 due date, and expects to award a contract for the administrator position by July 1.

The PRC will collect data on the program and submit a report to the Legislature by Nov. 1, 2024. More information on the program is here.

Federal Initiatives

DOE announced several of its own initiatives in January aimed at meeting the 2025 community solar goals.

A new collaborative among states will bring together state energy officials and program administrators to provide education and share best practices on community solar. Another initiative is aimed at giving community solar developers better access to project financing.

And a $2 million NCSP technical assistance program will help accelerate implementation of community solar while improving the performance of programs and projects. The technical assistance is free to NCSP partners.

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NYISO Management Committee Briefs: May 25, 2022

Joint Board/MC Resumes In-person

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.

Capacity Assessment (NYISO) Content.jpg2021 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.

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MISO Customers Ask for Penalty-free Load Reductions

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.  

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California, New Zealand Forge Climate Pact

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 agreement is contained in a memorandum of cooperation between the two governments.

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.

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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.