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November 9, 2024

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NJ Creates Green Bank to Support Clean Energy Goals

The New Jersey Economic Development Authority on April 15 approved the establishment of a green bank to help the state reach its clean energy goals by investing private and public money in financial instruments supporting clean energy projects. 

The New Jersey Green Bank (NJGB) will make investments through “debt, credit enhancements and other financial vehicles,” the EDA said in a statement. It “will be dedicated to investing in projects, technologies and companies that align with the state’s climate goals, including in areas such as zero-emission transportation, building decarbonization and resiliency, and clean energy generation and storage.” 

“The NJGB will also look to facilitate the development of climate and clean energy capital markets in the state through forms of financial support, such as warehousing and securitization, that address underdeveloped or nonexistent capital markets for these investments,” the agency said. 

EDA CEO Tim Sullivan called the bank a “pivotal step in the state’s continued push to meet the ongoing challenges of climate change.” New Jersey Gov. Phil Murphy (D) has set a goal for the state to reach 100% clean energy by 2035. 

“The NJGB will inject capital into New Jersey’s clean energy economy and support green businesses and good-paying jobs in the field,” Sullivan said. “Additionally, the investments made by the NJGB will pave the way for a cleaner and healthier environment for our residents and future generations.” 

Projects the bank supports will have to be new, rather than existing projects seeking refinancing, and must lead to reduced greenhouse gas emissions or other co-pollutants, according to the EDA. They could include solar power, onshore and offshore wind, all-electric heat pumps, geothermal and battery storage, the agency said. 

New Jersey follows several states that have created similar banks, among them Massachusetts, which created its Community Climate Bank in 2023. That bank started with $50 million in state funds and an initial focus on affordable housing, according to its website. Connecticut, Colorado and California also have green banks, according to the Coalition for Green Capital, which assists green banks in securing investments. The EDA’s proposal, issued last year, listed 28 other entities, mainly states, that have created green banks. 

New York’s Green Bank, a division of the New York State Energy Research and Development Authority, says it has committed more than $2 billion to finance clean energy and sustainable infrastructure projects over its 10-year history. The typical investment is $10 million to $15 million, according to the agency, which says it has an annual investment target of $225 million. 

Murphy allocated $40 million to the Green Fund in his 2024 budget, released last year. The fund “could attract up to $280 million in private capital to advance projects to advance the state’s new and bold environmental goals,” the budget book said. The bank is a subawardee in an application by the Coalition of Green Capital for funding from EPA’s National Clean Investment Fund (NCIF). 

In addition, the green bank could receive at least $100 million from the NCIF, $202 million from the Coalition for Green Capital and $350 million from Ecority, a clean energy financing nonprofit, according to a memorandum on the Green Bank proposal by Sullivan. 

New Jersey has for several years sought to launch such a bank. The state Energy Master Plan, released in 2019, outlined the concept and benefits of such a bank, saying it would help address an existing financing gap in customer segments: “those who lack access to the capital necessary to fund energy efficiency projects on their own but earn too much to qualify for low-income incentive programs.” 

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Industry Approves NERC’s Cyber Monitoring Standards

A proposed reliability standard to require utilities to implement internal network security monitoring (INSM) software on select grid cyber systems won industry approval this week, leaving a clear path for the ERO to submit the standard to FERC comfortably ahead of the commission’s deadline. 

The latest ballot period for CIP-015-1 (Cybersecurity — INSM) began April 11 and closed April 17, the same day as the formal comment period that began April 5. NERC’s Standards Committee authorized reducing comment and ballot periods for the project to as few as 10 days because FERC in 2023 ordered the ERO to submit standards requiring INSM by July 9 of this year. 

According to NERC’s ballot system, the standard received 175 votes for passage and 37 against. Applying the ERO’s weighting procedure (which proportionally reduces the impact of industry segments with fewer than 10 voters), the final result is a 76.78 weighted value in favor.  

The standard needed a two-thirds majority to pass. Now that the target has been reached, the normal move is to submit it for a five-day final ballot; a spokesperson for NERC told ERO Insider the team for Project 2023-03 (INSM) has not met to discuss the next step for the project.  

Under new rules approved by FERC in November, drafting teams may choose to conclude a standards action without a final ballot, but only if the previous ballot received approval from at least 85% of the registered ballot body, no further changes are proposed, and the team has made a good faith effort to resolve applicable objections and responded to industry comments in writing. (See FERC Approves NERC Standards Process Changes.) 

FERC ordered NERC to add INSM to its cybersecurity requirements in response to incidents like the SolarWinds hack of 2020, through which thousands of public- and private-sector organizations — including FERC itself — may have been infected with malicious code. (See FERC Orders Internal Cyber Monitoring in Response to SolarWinds Hack.) Commission staff said the SolarWinds attack demonstrated that an attacker “can bypass all perimeter-based security controls … and compromise” electronic networks believed to be secure. 

The standard this week would require registered entities to “implement one or more documented process(es) for [INSM] of networks … of high-impact [grid] cyber systems and medium-impact … systems with external routable connectivity [ERC].” 

Documented processes under the standard must include each of the following: 

    • network data feeds to monitor network activity, including connections, devices and network communications 
    • at least one method to detect anomalous network activity using the network data feeds 
    • at least one method to evaluate anomalous activity to determine what additional action is needed 

Entities would also have to implement documented processes to retain INSM data associated with anomalous network activity and to protect all data gathered or retained to prevent unauthorized deletion or modification. 

The limit of the standard’s applicability to medium-impact systems with ERC and all high-impact systems is in keeping with FERC’s original order. The commission also ordered NERC last year to examine the feasibility of implementing INSM in low-impact systems and medium-impact systems without ERC, but the ERO recommended against expanding the standard’s reach at this stage in a study submitted in January. (See NERC Recommends Phased Approach to INSM.) 

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Wash. Council OKs Reduced Version of Horse Heaven Hills Project

Washington’s Energy Facility Site Evaluation Council (EFSEC) on April 17 recommended approval for a slimmed-down version of a controversial wind project proposed for a site just south of the Tri-Cities in southeastern Washington.  

The EFSEC, a committee of representatives from several Washington state agencies, voted 5-2 to recommend that Gov. Jay Inslee approve the Horse Heaven Hills project. The governor now has 60 days to issue a final decision.  

Scout Clean Energy of Boulder, Colo., originally wanted to install up to 222 wind turbines that would be 500 feet tall, or up to 141 turbines that would go up to 657 feet along a 24-mile east-west stretch of the Horse Heaven Hills just south of Kennewick, Wash.  

However, EFSEC decided in February that two-mile buffer zones need to be implemented around 60 to 70 ferruginous hawk nests in that area. In 2021, the Washington Fish and Wildlife Commission downgraded ferruginous hawks’ status from threatened to endangered. 

The buffer zone roughly halves the number of turbines in the project. A precise new number won’t be available until Scout maps out a revised siting plan for the turbines. The company said the changes trim nameplate capacity of the project from 1,150 MW to 236 MW. 

Scout’s original proposal also included two 500-MW solar farms on the east and west sides of the 24-mile stretch. EFSEC ordered that the eastern solar farm be removed because it is near sensitive Tribal cultural sites. 

The wind farm has drawn strong opposition from numerous Tri-Cities residents because the turbines would show up in a currently pristine view of the hills from the urban area and because they’re near the ferruginous hawk nests. A February decision by EFSEC removed turbines along the north slopes of the hills, which would also eliminate much of the Tri-Citians’ concern about their view. (See Washington Renewable Developer Rankled by Siting Board Alterations.) 

“By partially approving the Horse Heaven wind and solar project, EFSEC is balancing the need for renewable, clean energy with potential impacts on tribal cultural resources, wildlife and surrounding communities,” EFSEC Chair Kathleen Drew said at the group’s April 17 meeting. 

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Northeast States Apply for Federal Money for 2 Tx Projects

The six New England states report they’ve submitted two applications for federal funding for transmission projects aimed at improving grid reliability and enabling interconnection of clean energy resources.  

The applications are for the second round of funding from the U.S. Department of Energy’s Grid Innovation Program, which offers up to $1.82 billion, capped at $1 billion for major individual transmission projects. 

The application for the “Clean Resilience Link” project was submitted in conjunction with New York state. The project, backed by National Grid, would upgrade a 230-kV line between New York and New England to 345 kV, “increasing transfer capacity between the two regions by up to 1,000 MW.” 

Analysis led by Energy and Environmental Economics (E3) and Hitachi Energy, and independently reviewed by the Brattle Group, found the project’s benefits would well exceed its costs.

“Even recognizing the large uncertainties, the ~$1.7b estimated system-wide benefits relative to the ~$600m net costs suggests that the project is highly favorable (with a ~$1b net benefit) from a systemwide perspective,” the Brattle Group wrote.  

The firm wrote that the project would address the need for increased transmission capacity between New England and New York, which has been documented in studies including the DOE National Transmission Needs Study and Massachusetts’ Energy Pathways to Deep Decarbonization report.  

The second project, titled “Power Up New England” is backed by developers including Eversource, National Grid and Elevate Renewables. The project is intended to upgrade and add points of interconnection in southern New England to unlock up to 4,800 MW of offshore wind and battery energy storage systems. 

“As we work to achieve our climate goals and increase the generation of renewable energy in the region, we need to invest in our transmission system and storage resources to deliver clean energy to our residents and businesses,” said Massachusetts Department of Energy Resources Commissioner Elizabeth Mahony in a press release. 

“This joint application to the Grid Innovation Program underscores the importance of continued collaboration with neighboring states and puts forth thoughtful proposals that will help strengthen and prepare our regional grid,” said Dan Burgess, director of the Maine Governor’s Energy Office. 

The states noted in an April 17 announcement that the applications contain “robust Community Benefits Plans” focused on “community engagement, workforce development, and diversity, equity, inclusion and accessibility.” 

The projects were selected by the states through a joint solicitation of proposals in 2023, and the states submitted concept papers to DOE for the projects in January, with help from ISO-NE. 

The first found of Grid Innovation Program awards ranged from $1.7 million for a synchronous condenser conversion project in Hawaii to $464 million for a new interconnection collaboration in the central U.S. 

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NY PSC Launches Grid of the Future Proceeding

New York has launched a process maximizing the use and effectiveness of flexible tools such as distributed energy resources and virtual power plants. 

The Public Service Commission on April 18 initiated the Grid of the Future proceeding (Case 24-E-0165) to control costs and maximize reliability amid the state’s clean energy transition. 

The order seeks to establish which capabilities will be needed, set targets for achieving those capabilities, identify the investments needed to reach those targets and identify the benefits that customers would realize when the targets are met. 

The Grid of the Future proceeding is the latest step in a process underway for over a decade, beginning with Reforming the Energy Vision (REV) in 2014 (Case 14-M-0101). 

PSC Chair Rory Christian said the process began before any current members joined the commission, and the challenges it was intended to address have come to pass. 

“They’re the type of challenges to be expected from any 100-plus-year-old system, built under a set of paradigms that are quickly being made obsolete through the progress of technology and evolving societal needs,” he said. “Challenges that are further amplified by severe weather events that are increasingly more severe.” 

The state’s landmark Climate Leadership and Community Protection Act of 2019 created a statutory requirement for 70% renewable energy by 2030 and 100% zero-emissions energy by 2040.  

The 70-by-30 goal seems increasingly out of reach amid slow regulatory processes and rising costs, but not for lack of effort — state regulators are simultaneously trying to change longstanding power generation and consumption patterns while ensuring the power grid can meet much higher demand with a much more intermittent generation portfolio. 

DERs and VPPs are expected to be an important part of a suite of dispatchable emissions-free resources to keep the lights on, and the Grid of the Future proceeding is designed to help move the state to a place where that is possible. 

Department of Public Service staff will convene at least one stakeholder conference to inform the process in the second half of this year.  

The order directs staff to conduct a Grid Flexibility Study on flexible resources’ status and potential by Nov. 15, 2024. 

The first iteration of the Grid of the Future Plan is due by Dec. 31, 2024; the second, a year later. 

The structure of the plan will evolve with stakeholder input, but initial required elements are: 

    • An inventory must be prepared of the resources expected to be needed, including how much of each is needed, how they will be obtained and what opportunities or barriers exist to securing them. 
    • Key elements of distributed system platforms must be identified; new or revised utility distributed system implementation plan requirements must be recommended. 
    • New or modified compensation plans for flexible resources must be considered, to encourage their best use by customers. 
    • Customer savings and benefits must be identified through better price signals on utility bills. 
    • The needs of market participants such as NYISO and utilities must be identified; the opportunity for changing roles and responsibilities for these participants also must be identified, along with improved interoperability among them. 
    • Changes in technology and information infrastructure must be accounted for. 
    • Rigid physical and cybersecurity protocols must be included. 
    • The plan must address variability and flexibility in the need for deployment and use. 
    • Allocation of costs and benefits among customers must be equitable.
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ISO-NE Analysis Shows Benefits of Shifting OSW Interconnection Points

Relocating two offshore wind points of interconnection (POIs) from Maine to Massachusetts could substantially reduce New England’s transmission upgrade cost requirements in the coming decades, ISO-NE told its Planning Advisory Committee on April 18. 

Shifting the points of interconnection would decrease the need for north-to-south transmission upgrades, cutting the overall cost range for transmission upgrades to $19 billion to $22 billion by 2050 compared to the original $22 billion to $26 billion estimate from ISO-NE’s 2050 Transmission Study. (See ISO-NE Prices Transmission Upgrades Needed by 2050: up to $26B.) 

“Location of offshore wind POIs are important, and results can vary significantly based on these locational choices,” said Liam Durkin of ISO-NE. “The offshore wind POI screening analysis will be one important step towards refining assumptions around offshore wind POIs.”  

The analysis used the same methodology as the 2050 Transmission study, shifting just two of the POIs in the study. One of the key findings of the original study was the need for increased transmission capacity from northern New England to the Boston area.  

Moving the two POIs south would reduce flows along the Maine-New Hampshire interface and the North-South interface in the winter, while the shifts would minimally impact summer flows, ISO-NE found. 

The lack of summer effects stemmed partly from ISO-NE’s expectation that offshore wind output would decline significantly during the summer. 

The 2050 Transmission Study considered four pathways to meet the transmission needs: an AC road map, a DC road map, an offshore grid road map and a plan focused on minimizing the need for new lines by upgrading existing infrastructure.  

The POI analysis showed that shifting the two offshore wind interconnections would benefit all four pathways, saving the AC road map an estimated $2.2 billion, the DC road map an estimated $4 billion and the offshore grid road map an estimated $2.6 billion. 

While ISO-NE initially found it could not meet its expected 2050 peak load of 57 GW through the “minimization of new lines road map,” the RTO found the POI shifts would make this road map possible, with an estimated cost of $19.8 billion. 

Although this pathway relies the least on new lines, it still would include a few, as well as substantial line rebuilds.  

“Rebuilds alone cannot successfully serve a 57-GW winter peak load along the North-South and Boston Import interfaces,” Durkin said.  

ISO-NE projects a 57-GW winter peak but also emphasized the potential benefits of lowering the peak through demand-reduction efforts. The original analysis from the 2050 Transmission Study found that limiting the peak to 51 GW would reduce transmission costs by about $8 billion. 

The updated analysis also found benefits of the POI shift with a 51-GW winter peak; taking the interconnection changes into account, the lower peak reduced the overall cost estimate to $13 billion to $16 billion.  

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Pathways Initiative Rejected for $800K in DOE Funding

The West-Wide Governance Pathways Initiative has potentially lost a key source of financial backing after the U.S. Department of Energy rejected the group’s application for $800,000 in grants to support its initial operations. 

“The Pathways Initiative did not receive DOE funding in the last round,” Western Freedom Executive Director Kathleen Staks, co-chair of the initiative’s Launch Committee, told RTO Insider in an email April 17. “We plan to share more information and potential next steps during our [April 19] stakeholder call and [will be] happy to answer additional questions at that point.” 

The group applied for the money in January in response to a DOE Funding Opportunity Announcement (FOA), seeking two tranches of $400,000 each to be disbursed over two years. The initiative was launched last July by energy officials from five Western states to develop the framework for an independent RTO that pointedly includes California and builds on CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM). (See Regulators Propose New Independent Western RTO.) 

“This funding is necessary for major Pathways support functions — development of informational materials; outreach to key stakeholders; regular convenings through virtual and in-person gatherings; and facilitation to ensure meaningful participation by those who wish to engage,” the group said in a concept paper included in the grant application. (See Western RTO Group Seeking $800K in DOE Funding.) 

The funding would be “essential to performing outreach to states and groups not yet aware of, or able to participate in, the new nonprofit independent governance entity envisioned by” the initiative’s backers and make it more accessible to a larger set of stakeholders, the paper said. 

Speaking at the Launch Committee’s last monthly update March 15, Jim Shetler, co-chair of the committee’s Priority Administrative Work Group, expressed confidence that Pathways would win the DOE funding. (See Pathways Initiative Discloses Funders, Reiterates Goals.) 

Shetler, general manager of the Balancing Authority of Northern California, said the federal money would likely arrive in June or July, possibly leaving a funding gap in late spring that would likely be covered by the group’s original budget of $570,000 needed to fund Phase 1 of the effort through the end of April. 

It’s now unclear how Phase 2 will be funded. During the March update, Shetler said the initiative had raised about $430,000 from 24 stakeholder donors to cover the initial budget, with more pledges on the way. 

As of April 17, a “pledge summary” spreadsheet maintained by the group showed the list of donors had expanded to 32. It now includes the Interwest Energy Alliance, Western Resource Advocates, Primergy Solar, Solariant Capital, Pattern Energy, Brookfield Renewable Partners, Engie North America and one “individual contributor.” But the spreadsheet shows only pledge ranges, not donors’ specific contributions. 

The denial of federal funding comes just a week after the initiative released its straw proposal for tackling a “stepwise” transition of CAISO’s WEIM and EDAM to independent governance and could represent a setback for the EDAM in its competition for participants with SPP’s Markets+. (See Western RTO Group Floats Independence Plan for EDAM, WEIM.) 

SPP officials, meeting in Denver, declined to comment on the development. 

CAISO spokesperson Anne Gonzales said the ISO would defer comment to the Launch Committee. 

Tom Kleckner contributed to this article from Denver.

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FERC OKs Pipeline Expansion Despite West Coast States’ Opposition

FERC on April 16 rejected rehearing requests on a certificate it granted to TC Energy to expand its Gas Transmission Northwest (GTN) pipeline’s capacity into the Northwest over three states’ objections and Commissioner Allison Clements’ dissent (CP22-2-001). 

The XPress project would provide 150,000 dekatherms per day of incremental firm transportation service from Idaho’s border with British Columbia to the Malin Meter Station in Klamath County, Ore., near the California state line. It has signed three deals with terms of 30-33 years for the pipeline’s entire capacity. 

While the pipeline has offtake deals with customers, California, Oregon and Washington argued that their climate policies, which require significant economywide natural gas cuts, will lower gas demand in coming decades and asked FERC to reject the proposed expansion. 

The commission mostly disagreed, finding the deals for 100% of its capacity significant evidence of need and that the project would cut costs to consumers while increasing supply diversity. 

The case covers similar arguments to a FERC-approved Transcontinental Gas Pipeline expansion, opposed by New Jersey regulators because of their state’s climate targets. That decision has been appealed to the D.C. Circuit Court of Appeals, which held oral arguments on it in March. (See FERC Approves Pipeline Expansion Despite New Jersey’s Worries.) 

The Western states argued the deals were not enough to show demand and cited another D.C. Circuit decision in Environmental Defense Fund v. FERC, in which the court rejected the commission’s approval because it had relied on a single-precedent agreement between the pipeline and an affiliate as evidence of need. 

But none of the buyers is an affiliate of GTN, nor is there evidence of self-dealing, so the EDF case does not apply, FERC said. 

“We continue to find that GTN presented sufficient evidence of project need — it executed precedent agreements for 100% of the project’s capacity with unaffiliated shippers, each for a duration of 30 or more years — notwithstanding the legislation and policies that the states argue will reduce demand,” FERC said. “These precedent agreements, as noted herein, are significant evidence of need.” 

The predictions that state climate laws will cut gas demand to make the expansion unneeded are speculative, FERC said. While the three West Coast states have climate laws, half the capacity is for Intermountain Gas, which serves customers in Idaho. 

Clements argued that GTN’s rate case offered different information on future gas demand; that FERC should have examined alternatives to the expansion in its environmental review; and that it should be able to assess the significance of greenhouse gas emissions. 

The three states submitted evidence in a supplemental filing from GTN’s rate case, which the majority held could not be considered due to late filing. Clements said the supplemental filing should have been accepted because it included information central to the case. 

The states had tried to get analysis from the firm that their laws would cut its demand, but GTN dismissed those concerns as speculative; then in the rate case, it claimed future demand was at serious risk because of their climate laws, Clements wrote. 

“Although GTN asserted in its data request response that the effect of state laws was too speculative to be considered for purposes of the certificate proceeding, its witnesses said the opposite for purposes of supporting an increase in GTN’s rates,” Clements said. 

Contracts for 40% of the pipeline’s existing capacity will expire in 2028, and local delivery companies subject to the three states’ laws hold 41% of that expiring capacity. 

“Thus, it is entirely possible (if not likely) that the three shippers who signed precedent agreements could access this existing capacity to meet their transportation needs as the current capacity holders reduce their reliance on natural gas pursuant to state legal mandates,” Clements said. 

FERC should have accepted the state’s filing of the rate case information because it undermines the foundation of the certificate order to the point where it cannot be rationally sustained on rehearing, Clements said. 

The expansion would increase the pipeline’s capacity by 5% and the region’s total pipeline capacity by 1.5%, and the three West Coast states represent 95% of the demand, with Idaho representing just 5%, she said. 

“Intermountain is unlikely to need any new capacity because, as GTN’s own rate case witnesses predict, the stringent decarbonization laws and renewable energy initiatives in Idaho’s neighboring states will drive down regional demand for gas and thereby demand for GTN’s existing gas transportation capacity,” Clements said. 

FERC considered updating its procedures for granting new pipelines certificates, but its proposal ran into steep opposition from the industry and on Capitol Hill, where it helped sink former Chair Richard Glick’s renomination. Clements argued in her dissent that this case shows why an updated policy statement on gas certificates is needed. 

“To avoid repeating these mistakes, the commission should finalize an updated certificate policy statement and implement enhanced procedures allowing us to fully evaluate all factors that actually do bear on the public interest in 2024, including the effect of state laws and renewable energy initiatives,” Clements said. 

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DOE Urges Utilities to Embrace ‘Holistic’ Reliability Solutions

With electricity demand expected to undergo rapid acceleration by 2028 while generation moves from fossil fuels to renewable resources, stakeholders must “pursue the full range of technology, planning and operation solutions” to meet resource adequacy needs, the U.S. Department of Energy said in a report released this week. 

DOE said “The Future of Resource Adequacy,” published April 17, was meant to highlight the challenges of maintaining resource adequacy in the face of the changing grid and spread awareness about potential solutions, as well as the “unprecedented funding” for grid infrastructure available through the Infrastructure Investment and Jobs Act and the Inflation Reduction Act. 

The report identified several growing threats to resource adequacy, which NERC defines as “the ability of the electric system to supply the aggregate electrical demand and energy requirements of the end-use customers at all times.” Growth in demand is chief among these, but the rising incidence of extreme weather events because of climate change is another factor; DOE noted that the U.S. experienced 28 weather and climate disasters in 2023 that each caused more than $1 billion in damages. 

There are no simple answers to these problems, DOE said, pointing out that the complexity of the grid makes electric reliability “intrinsically a systemwide property that cannot be ensured by any individual resource or technology.” The report recommends “holistic” thinking on reliability. 

Resource adequacy goals, for example, can be met using a variety of resource types to ensure that a shortage of one resource — such as sunlight or natural gas — does not imperil the entire system. Drawing on data from the National Renewable Energy Laboratory, DOE noted that synchronous generation facilities present a wide range of responses to extreme temperatures, with combustion turbine plants showing the highest rate of outages at temperatures of -15 degrees Celsius but steam turbines leading in outages at 35 C. 

Historical outage rates for fossil and nuclear power plans as a function of temperature | DOE

The report noted that new natural gas plants are often grid planners’ “first response … to meet resource needs” because of their “general flexibility, low cost and high-capacity credit, as well as familiarity with the technology.” But the temperature data suggest this approach could cause problems with reliability during extreme weather. 

Instead, DOE presented the example of Xcel Energy, which will replace an 1,879-MW coal facility in phases through 2030. Rather than replacing the plant with a natural gas combined cycle plant as originally proposed, the utility decided to build two smaller combustion turbines, 710 MW of new solar capacity, a long-duration storage facility and “transmission lines to facilitate interconnection of up to 1.2 GW of new wind resources.” The utility said this plan would reduce customer costs and its carbon footprint, “all while preserving reliability.” 

DOE also noted the accelerating deployment of energy storage systems, particularly paired with renewable generation to allow the energy from their most productive periods to be shifted to other times of day. Citing data from the Energy Information Administration, the report noted that battery capacity on the grid is expected to more than double by next year. 

Hybrid storage systems at existing generators, or attached to existing proposed projects, have the additional strength that they “generally [do] not have to re-enter the interconnection queue … cutting down on one of the biggest hurdles to greenfield deployment,” DOE noted. 

“The unprecedented availability of tax credits and other funding opportunities through the [IIJA] and IRA creates a compelling environment for exploring all of these opportunities,” DOE said. “Utilities have both the opportunity and the means to plan and deploy a variety of clean technologies to maintain and improve resource adequacy along the path toward the sustainable electric grid of the future.” 

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Calif. Senate Committee Passes Energy-related Bills

A California Senate committee passed a raft of energy-related bills April 16, including legislation focused on grid-enhancing technologies, hydrogen and data centers.  

The Senate Energy, Utilities and Communications Committee voted 18-0 on Sen. Steve Padilla’s Senate Bill 1006, which would require transmission-owning utilities to prepare a grid-enhancing technologies strategic plan to file with the California Public Utilities Commission (CPUC).  

Under SB1006,  the strategic plans would include an implementation timeline, and utilities would report their progress in their integrated resource plans. Starting in January 2026 and every four years thereafter, transmission utilities would be required to work with CAISO to evaluate which of their transmission and distribution lines could be cost-effectively fitted with advanced conductors.   

Padilla (D) pointed to CAISO estimates that the state will need more than 7,000 MW of new transmission capacity each year for the next decade to meet its energy demand and GHG reduction goals.  

Grid-enhancing technologies, such as dynamic line rating systems and advanced power flow control systems, typically are inexpensive hardware or software that can be deployed quickly, the bill states. Along with advanced conductors, the technologies could increase reliability while reducing transmission line congestion, renewable generation curtailment and wildfire risk.  

The U.S. lags behind other countries in use of the technologies, bill supporters said.   

Julia Selker, executive director of the Working for Advanced Transmission Technologies (WATT) Coalition, called the bill “a huge opportunity” for the state’s economy and decarbonization goals. “Grid constraints are blocking economic development in California, blocking renewable energy, and [this] will help us integrate new large loads,” Selker said, speaking in support of the bill.  

No one spoke in opposition to SB1006, now headed to the Senate Rules Committee.  

Hydrogen Bills

The committee also passed two bills by Sen. Josh Becker (D) that are aimed at accelerating the state’s progress on green hydrogen. The bills also seek to encourage the electrification of industrial processes that rely on fossil fuels. 

SB993 would direct the CPUC to set rates “as low as feasible” to encourage green hydrogen or industrial facilities to use electricity when clean energy is abundant and curtail their demand at other times.   

Customers would only be eligible for the tariff if they are new electrical customers or plan to increase their electrical load substantially after enrolling.   

“What both green hydrogen and electrified industrial heat have in common is that they’re economically competitive only if they have access to inexpensive electricity, and they’re only good climate solutions if they rely on clean electricity,” Becker told the committee.  

Proponents said the bill would support the Alliance for Renewable Clean Hydrogen Energy Systems (ARCHES), a private-public partnership in California. In October, the U.S. Department of Energy announced ARCHES will receive up to $1.2 billion in hydrogen hub funding. (See DOE Designates Seven Regional Hydrogen Hubs.)  

SB993’s opponents include Pacific Gas & Electric. A PG&E representative said the utility is worried about cost shifts that might occur under the bill.   

A second hydrogen bill passed by the committee, SB1018, would exempt certain solar or wind projects from being considered “electrical corporations” subject to CPUC regulation. The exemption would apply if the electricity were provided over private lines exclusively for electrolytic hydrogen production or electrifying industrial heat processes.   

SB 1018 would expand the state’s current “over the fence” exemption for electricity generated for consumption on-site or for one or two neighboring parcels.   

“That works fine for rooftop solar on a home,” Becker said. “But it’s not sufficient for the megawatts of solar, spread across many acres of land, that we’re going to need for a modest hydrogen facility or a factory.”   

The exemption would apply only to solar or wind generation serving new electrical loads.  

Opponents of the bill, including a San Diego Gas & Electric representative, expressed concerns about an exemption “undermining grid planning, safety and reliability.”   

Both hydrogen bills now head to the Senate Appropriations Committee.  

Data Centers

The committee also passed SB1298, by Sen. Dave Cortese (D), which applies to data centers’ emergency backup generating facilities.   

The California Energy Commission (CEC) has licensing authority for thermal power plants of 50 MW or larger but offers an exemption for power plants of 100 MW or less.   

SB1298 would raise the exemption’s cutoff to 150 MW. The bill originally set the cutoff at 200 MW, but Cortese agreed to lower that to 150 MW based on committee feedback. The exemption would be available to data centers’ backup power facilities that are not connected to the grid.   

Before granting the exemption, the CEC must find the proposed facility would not have a substantial adverse effect on the environment or energy resources. If an exemption is granted, the project developer still must obtain local, state and federal permits.  

Cortese noted the surging demand for digital services and said the data center vacancy rate in Silicon Valley is only 1.6%.   

Data centers support businesses of all sizes, he said, including 911 call centers, GPS navigation systems, hospitals and the tech industry.   

“This bill will create larger data center facilities that better meet the demands of California industries,” Cortese said.  

The Bay Area Air Quality Management District opposed the bill based on concerns about pollution from diesel generators that data centers use for backup power. 

The California Air Pollution Control Officers Association said lawmakers should re-examine the exemption’s 100-MW cap to see if it needs to be lowered to protect public health.   

Proponents noted the limited amount of time the backup generators are used.   

Following the committee’s 14-0 vote, SB1298 goes to the Senate Appropriations Committee.