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November 7, 2024

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DOE to Fund Enhanced Geothermal Demo on Oregon Volcano

The money may not be much by federal government standards, but the $60 million the U.S. Department of Energy may award to three pilot projects demonstrating enhanced geothermal drilling technologies could have a major impact on helping the U.S. decarbonize its grid by 2035. 

Traditional geothermal wells are located over existing underground sources of heated brine or other fluids, which produce steam to run turbines. Enhanced geothermal seeks to tap previously inaccessible geothermal heat even deeper underground by injecting fluids, in some cases using drilling techniques and equipment from the oil and gas industry. 

A recent DOE analysis estimates that if fully developed, enhanced geothermal systems (EGS) could provide up to 90 GW “of firm, flexible power to the U.S. grid by 2050,” according to the funding announcement released Feb. 13. 

The three projects will be located in Northern California, Utah and on a volcano in Oregon. 

“These projects will help us advance geothermal power … into regions of the country where this renewable resource has never before been used,” Energy Secretary Jennifer Granholm said in the announcement. Funded by the Infrastructure Investment and Jobs Act (IIJA), “these pilot demonstrations will help us realize the full potential of the heat beneath our feet to reduce carbon emissions, create domestic jobs and deliver clean, cost-effective, reliable energy to Americans nationwide.” 

The demonstration projects will also support DOE’s Enhanced Geothermal Earthshot, which is targeting a 90% cut in EGS drilling costs by 2035. 

The DOE announcement does not specify how the $60 million would be divided between the three projects, nor any requirements for projects to match the IIJA dollars with private investments. The three projects will now enter negotiations with the department to finalize the terms of the funding. 

The Projects

Chevron New Energies leads the list of awardees with a project that will “use innovative drilling and stimulation techniques” to access geothermal energy near an existing geothermal facility in Sonoma County in Northern California. 

While neither DOE nor Chevron have provided further details, an article in the North Bay Business Journal suggests that the demonstration project is being developed with Sonoma Clean Power, a community-choice aggregation utility. Located near the Geysers geothermal complex, which has been in operation since 1960, the project could produce up to 20 GW of power to start and expand to 200 GW, according to the report. 

Chevron’s goal is to “reduce well costs and increase well productivity,” the company said in an email to NetZero Insider. “This effort is essential to closing technology and cost gaps to achieve the DOE’s goals for enhanced geothermal systems. Project learnings will be used to improve the effectiveness of novel geothermal technologies, reduce the costs of implementation and advance widespread commercial deployment of EGS across the United States.” 

Headquartered in Houston, Fervo Energy will use its DOE grant to drill three wells at a site in Utah “with no existing commercial geothermal power production.” The goal is for each of the wells to produce 8 MW. 

According to information on the company’s website, Fervo also uses oil and gas technologies, such as “precision directional drilling technology to drill horizontally in geothermal reservoirs.” The company’s Cape Station well, one of the three receiving DOE funding, has already been able to cut drilling times 70% year-over-year and slash costs by about 50%, according to a press release issued Feb. 12. 

“These results substantiate the rapid learning underway in the geothermal industry and signal readiness for continued commercialization,” the company announcement said. 

The final project receiving IIJA funds is a first-of-its-kind pilot to be located at the Newberry Volcano in Oregon, demonstrating a technology for “super-hot” EGS, reaching temperatures of 375 degrees Celsius, or more than 700 degrees Fahrenheit. 

DOE identifies Mazama Energy as the project lead, but a website and online research papers indicate that the concept of developing a super-hot EGS project at the Newberry Volcano has been discussed since 2010. Located in the Newberry National Volcanic Monument in Central Oregon, the volcano last erupted more than 1,300 years ago, but is still considered active by the U.S. Geological Survey. 

A 2020 paper on the project notes that “super-hot dry rock (more than 375 C) is much more energy dense than conventional hot dry rock (less than 225 C), and production of supercritical EGS steam would represent an energy breakthrough. A super-hot EGS well would produce five to 10 times as much electricity as other well types.” 

The ‘Invisible’ Renewable

As increasing amounts of variable solar and wind energy come onto the grid, EGS could emerge as a potential source of zero-carbon, baseload power, and one with a broad geographic footprint, said Bryant Jones, executive director of Geothermal Rising, a North American industry trade association. 

“Geothermal is everywhere,” Jones said. “Some places you might use one type of geothermal technology versus another. You might use EGS in one place, geothermal heat pumps in another.” 

It also has a smaller carbon and environmental footprint than other renewable technologies. As “the invisible energy technology,” it is often overlooked by policymakers and the general public, Jones said. 

While EGS may borrow oil and gas drilling technologies, it is using them in different ways, he said. “Geothermal fracking does not use … chemicals in the way that oil and gas does.” Oil and gas use chemicals to extract materials out of the ground; EGS is only tapping “hot water to spin a turbine and create electricity or to use heat for an industrial purpose,” Jones said. 

“You’re using a geothermal aquifer that’s … often thousands of feet beneath any agriculture or drinking water aquifers,” he said. 

Looking ahead, Jones sees the DOE pilot projects demonstrating “that geothermal is cost competitive with all other energy power generating technologies … [with] a price point that will inspire or encourage private investment.” 

The current awards are the first round of the IIJA funding for EGS demonstration projects, according to DOE. A second round, yet to be announced, will provide support for East Coast projects. 

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Tug-of-war Developing over Ariz. Clean Energy Rules

As Arizona regulators begin a process to repeal renewable energy and energy efficiency standards for electric utilities, a group of state lawmakers want the regulators to reconsider clean energy rules they previously rejected.

State Sen. Priya Sundareshan (D) introduced Senate Concurrent Memorial 1002 last month, which would urge the Arizona Corporation Commission (ACC) to adopt as soon as possible energy rules the commission previously considered.

Those rules included a requirement for utilities to reduce carbon emissions by 50% by 2032 and 100% by 2050. Other components were an energy efficiency standard and energy storage requirements.

The introduction of SCM 1002 comes as the ACC voted Feb. 6 to start a rulemaking process to repeal its renewable energy and energy efficiency standards for electric utilities.

Commission Chair Jim O’Connor said the two standards combined have cost Arizona ratepayers almost $3.4 billion since 2006.

“We began the steps needed to repeal a rule that has cost ratepayers billions of dollars in out-of-market-priced contracts,” O’Connor said in a statement regarding the renewable energy standard. “Mandates distort market signals and are not protective of ratepayers.”

Under Arizona’s renewable energy standard, adopted in 2006, 15% of electric utilities’ retail sales must be from renewable resources by 2025. The state’s electric utilities have met or exceeded the standard.

Sundareshan told NetZero Insider she was “shocked and concerned” by the commission’s action.

“Weak as the current [renewable portfolio standard] is, what we need is action toward a stronger RPS,” she said in an email.

In addition to Sundareshan, SCM 1002 lists 11 other senators and five representatives, all Democrats, as co-sponsors. It is awaiting its first committee hearing. It’s not clear how far SCM 1002 will get in Arizona’s Republican-controlled legislature.

Sundareshan said she is asking the ACC to reconsider its prior energy rules decision via a Senate Concurrent Memorial because of uncertainty about what direction the legislature can give the commission under the state constitution.

If SCM 1002 fails, Sundareshan said, she might take a closer look at potential legislation to direct the ACC to update its renewable energy standards.

Repeal Process

The ACC voted 4-1 in separate votes Feb. 6 to start a process to repeal the renewable energy and energy efficiency standards. Commissioner Anna Tovar, the lone Democrat on the panel, cast the “no” votes.

The votes started a process that could take a year or longer. ACC staff will first create draft rules that will be brought to the commission. If approved, the formal rulemaking process will begin, with periods for public comment before a final vote by the commission.

In 2021, the commission rejected a set of clean energy rules that would have required electric utilities to eliminate their carbon emissions by 2050.

When the proposal was changed to give utilities until 2070 to meet the 100% carbon-free emissions target, the commission approved the rules — only to change course and reject them at a later meeting. (See Ariz. Regulators Reverse Clean Energy Rules.)

In rejecting the rules, commissioners voiced concerns about the impact to ratepayers.

But in SCM 1002, lawmakers blame natural gas price increases for rising costs to ratepayers.

“The commission’s failure to update this state’s renewable energy standards will continue to keep ratepayers captive to these rising fuel costs and at the mercy of the gas market,” it states.

Despite the commission’s rejection of the clean energy rules, Arizona utilities are making clean energy pledges.

Arizona Public Service (APS) has committed to being 100% clean and carbon free by 2050, with a 2030 target of 65% clean energy resources and 45% renewable energy.

Tucson Electric Power (TEP) was expecting 32% of its retail sales in 2023 to come from renewable resources, according to the company’s proposed integrated resource plan filed in November.

Energy Efficiency Rules

Under Arizona’s energy efficiency standard, electric utilities were required to achieve annual energy savings of at least 22% of the previous year’s retail sales by the end of 2020.

Commissioner Kevin Thompson said utilities’ efficiency measures “have done little to avoid the need for new generation and have benefited a select few.”

“Energy efficiency programs are routinely pushed by vocal special interest groups where the economic benefits favor a small group of customers, and the large majority of ratepayers foot the bill,” Thompson said in a statement.

Caryn Potter, Arizona representative for the Southwest Energy Efficiency Project (SWEEP), told the commission the energy efficiency standard requires programs to be cost effective, creating at least $1 in benefits for every dollar spent.

“No other utility investment today is held to that same bar,” Potter said.

Potter also noted the economic benefits of the standard to Arizona, which she said has more than 42,000 energy efficiency workers.

Ana Gorla, representing the Sierra Club Grand Canyon Chapter, said the commission should strengthen the energy efficiency and renewable energy standards rather than repeal them.

“Energy efficiency is the cleanest, cheapest energy resource,” Gorla said. “Investments in energy efficiency have helped people reduce their energy burden and help reduce the need for some generation.

“Keeping [the standard] in place sends a message to utilities to not backslide on energy efficiency.”

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DTE Highlights Improved Infrastructure in Year-end Earnings Call

DTE Energy touted its investment of more than $3.8 billion in Michigan’s electric and gas infrastructure last year for investors and analysts during its fourth-quarter earnings call Feb. 8. 

The company said it put $3.1 billion into improving electric reliability and increasing clean energy, with the rest going into upgrading its gas distribution lines. The electric work included trimming more than 5,200 miles of trees, installing more than 200 automated reclosers and replacing more than 3,500 utility poles. That led to 33% less outages in the second half of the year, the company said. 

DTE also “replaced more than 200 miles of cast iron pipes with more durable materials” and “moved more than 22,000 natural gas meters to the outside of homes and businesses” to improve safety, it said. 

“By making strategic investments in our infrastructure at levels significantly higher than our earnings, we accelerated our long-term plans for transforming our electric generation and distribution,” CEO Jerry Norcia said in a press release. “We will continue to increase our infrastructure investments in each of the next five years to keep getting better, faster.” 

Operating earnings for the year were down by just 1%, at $1.184 billion ($5.73/share). A loss of $170 million on the year in the company’s electric business was offset by profits in DTE Vantage — its direct-to-business energy solutions subsidiary that owns renewable natural gas and carbon-capture facilities — and in its energy trading subsidiary. It reported operating earnings of $406 million ($1.97/share) for the fourth quarter, a nearly 53% increase over the same period in 2022. 

The loss in electric earnings was mostly attributed to weather: a warmer winter, a cooler summer and higher storm-related expenses. 

“2023 was a challenging year for DTE as we faced significant headwinds from an unprecedented combination of weather and storm activity,” Norcia said during the earnings call. “The fact that we were able to offset most of the challenges we faced while maintaining service excellence is a clear indication of our highly engaged team and our commitment to operating excellence.” 

Norcia also said that clean energy legislation recently signed by Michigan Gov. Gretchen Whitmer (D) “creates a very clear roadmap for the development of additional solar, wind and storage assets” and aligns with DTE’s 20-year Integrated Resource Plan, which was approved by the PSC in July with the goal of reducing the company’s carbon emissions by 85% and ending coal usage by 2032. (See Whitmer Signs Climate Bills, Including 100% ‘Clean Energy’ Goal and DTE Earnings Focus on Faster Clean Energy Transition.) 

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Carbon Market Linkage Bill Passes Wash. Senate

The specter of a November referendum on the fate of Washington’s cap-and-invest program hovered over the state’s Senate Feb. 12 when it passed a bill to link the program to that shared by California and Quebec. 

The Senate approved  Senate Bill 6058  on a 29-20 vote along party lines after a brief discussion. The bill, which would start the process of integrating Washington into the larger and older system, will now advance to the state’s House of Representatives.  

Cap-and-trade supporters think that linking with California-Quebec would reduce and stabilize Washington’s carbon allowance prices and lower the state’s gasoline prices. But Sen. Drew MacEwen (R) argued the Legislature should wait to pursue a link-up until after the votes are counted on a November ballot initiative that seeks to disband the program, which opponents have blamed for the state’s high gas prices.  

“We have a tremendous amount of political uncertainty around the [cap-and-invest program],” MacEwen said.  

Rep. Jim Walsh (R), chair of the Washington Republican Party, is leading the efforts to rescind the cap-and-invest program. 

A November vote in favor of removing the cap-and-invest program would nullify the state’s attempts to link with California and Quebec.  

Sen. Kevin Van De Wege (D) said Monday that linkage “obviously provides a more stable marketplace.” 

Sen. Shelly Short (R) tried unsuccessfully to amend SB 6058 to require the state’s Ecology Department to provide relief from emissions caps to utilities affected by lower levels of electricity produced by hydropower, the largest source of Washington’s electricity. Bill sponsor Sen. Joe Nguyen (D) agreed that was a legitimate wrinkle to study but successfully argued putting off addressing the issue until a later date. 

Washington’s year-old cap-and-invest program has seen allowance prices rise steadily in its quarterly auctions last year, hitting $63.03 for one metric ton of emissions — much higher than state experts predicted in 2021. 

By comparison, California’s allowance prices started at $10 in 2012 and reached slightly above $36 in 2023. Washington’s program is designed to trim emissions at a higher rate than California’s, which is one reason observers believe Washington’s prices have been higher. 

Nguyen noted that the cap-and-invest program was created with the idea of eventually linking with the joint California-Quebec market to reduce and stabilize prices. He hoped that the larger market would encourage other states to join and further bring down prices. New York is currently designing its own cap-and-trade program. 

The earliest this linkage could take place is 2025.  

SB 6058’s biggest proposed change to the Washington program would be allowing a single bidder to obtain up to 25% of the allowances for sale in a quarterly auction. The current limit for a single auction is 10%. However, a single organization would still be limited to 10% of the allowances offered across all auctions in a calendar year. 

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Engineering Firm Finds Quality Problems in BESS Manufacturing

Quality-control problems affect a sizable number of new energy storage systems, creating potential safety and performance risks, a new report indicates.

Clean Energy Associates (CEA) based its conclusions on an extensive series of audits over six years.

CEA found 18% of inspected lithium-ion battery energy storage systems (BESS) had quality issues related to their thermal management system and 26% had issues related to their fire detection and suppression system.

CEA suggested the industry is focusing too closely on cell selection and said it should not overlook system integration as a potential source of problems. Nearly 50% of the defects CEA found were at the system level.

The report, “BESS Quality Risks,” comes amid an extensive buildout of BESS and a lingering public uneasiness about the safety of these systems. Fires are hard to extinguish and can emit toxic fumes.

The advisory and engineering services firm conducted more than 320 quality audits at over 52 BESS factories on systems that comprise more than 30 GWh of capacity. It found more than 1,300 problems.

CEA said the defects it found were split nearly equally between components — cells or modules — and systems. The integration of components into a system is subject to less stringent quality-control procedures, it said, even though it is a highly manual and labor-intensive process.

Meanwhile, the systems themselves are highly complex and vulnerable to component defects missed in earlier quality checks.

Other system-level findings in the report broke down as follows:

    • 8% were performance-related, due to manufacturing defects and/or integration errors. This led to problems such as diminished capacity and round-trip efficiency results due to large temperature and voltage variations among cells within a module, thanks to poorly welded wiring connections.
    • 34% were enclosure-related, due to manufacturing defects or damage sustained in transportation. These included poor rigidity, weakness, deformation, grounding defects, water ingress, cosmetic problems, and poor wiring or cabling.
    • 58% were related to the balance of system — various defects in components or errors in their integration. These included coolant leakage from a variety of causes; malfunctioning sensors and alarms due to miswiring; and exposure of a live conductor within the AC/DC distribution.
    • Common fire suppression system defects included nonfunctioning release actuators for the fire-extinguishing agent due to a faulty diode; nonfunctional fire alarm abort buttons due to miswiring; and nonresponsive smoke and temperature sensors, also due to miswiring. These defects pose a risk of fire and explosion, or of serious equipment damage due to unnecessary activation of the fire control system.
    • Common thermal management system defects included circulation system component failures due to fasteners being not tightened enough, leaving a loose connection, or over-tightened and deforming flange plates; and compressor mainboard short circuiting due to a burned metal oxide semiconductor tube. These defects pose a risk of thermal runaway or accelerated battery degradation.
    • Battery cell defects were attributed fairly evenly among electrode manufacturing, cell assembly and cell finishing.
    • Module defects were heavily attributed to sorting and installation (45%) and interconnection welding (41%); enclosing and end-of-line testing issues were less common.
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CISA Highlights China Threat in 2024 Priorities Report

Defending America’s critical infrastructure against threats from the People’s Republic of China will be a major focus of cybersecurity operations in 2024, the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) said Feb. 12.

CISA’s warning came in the 2024 Priorities document released by the agency’s Joint Cyber Defense Collaborative, which CISA established in 2021 to “drive unified efforts across public and private partners” to accomplish its security goals. The JCDC includes participants from state, local and international governments, along with infrastructure operators, cybersecurity companies, service providers and other stakeholders from various critical infrastructure sectors.

JCDC called the 2024 priorities “a critical step in [our] maturation [because] for the first time, we are aligning our priorities under three broad focus areas” that will help CISA and other participants create their strategies and direct their resources:

    • defend against advanced persistent threats (APT), particularly those backed by the PRC.
    • raise the cybersecurity baseline.
    • anticipate emerging technology and risks.

Discussing the first area, JCDC observed that many malicious cyber actors — notably those working for China — have pivoted from focusing on “espionage and data theft” to “destructive attacks designed to cause real-world harm.”

The document did not list any specific attacks or groups. However, in a blog post on the 2024 priorities, CISA Associate Director Clayton Romans noted that U.S. intelligence agencies saw a rise in APT activity targeting U.S. critical infrastructure.

Romans went on to call on JCDC to assist critical infrastructure organizations to prepare for malicious activity involving “living off the land techniques.” This is a clear reference to Volt Typhoon, a PRC-sponsored hacking group first identified last year but now believed to have been actively infiltrating U.S. infrastructure for “at least five years,” according to a recent CISA cybersecurity advisory.

Volt Typhoon’s malware has been discovered in the information technology environments of companies in the energy, communications, transportation, and water and wastewater sectors in the U.S. and its territories. The “living off the land” strategy refers to hiding inside a target’s system using only existing resources disguised as legitimate traffic, and CISA has expressed “high confidence” that the group hopes to move from IT networks to the utilities’ operational technology assets, potentially giving the PRC the ability to disrupt operations.

CISA Director Jen Easterly, along with FBI Director Christopher Wray and other cybersecurity officials, warned members of the House of Representatives’ Committee on the Chinese Communist Party last month that China’s strategy in a conflict with the U.S. or its ally Taiwan likely would include attempts to disable critical infrastructure and cause “societal panic” among the civilian population. (See China Preparing to ‘Wreak Havoc’ on US, Cyber Officials Warn.) At the same hearing Wray called Volt Typhoon “the defining threat of our generation.”

Ransomware, AI Also Key Topics

In addition to identifying and neutralizing APTs like Volt Typhoon, the JCDC’s priorities document emphasizes planning for major cyber incidents that could result when such actors are not intercepted in time. CISA’s goals for the year include updating the U.S. National Cyber Incident Response Plan, currently under development in coordination with the Office of the National Cyber Director and industry partners, to address “significant changes in policy and cyber operations” since the NCIRP originally was released.

Additional priorities include reducing the impact of ransomware on critical infrastructure. That topic reached new levels of urgency in 2021 with the hack of Colonial Pipeline, which caused the company to shut down a major source of petroleum products for the East Coast for several days.

Cybersecurity experts say ransomware attacks have become easier than ever because of the rise of the ransomware-as-a-service model, in which a core group develops and operates a ransomware package while recruiting affiliates to hack into networks and deploy the app. Users of this model include DarkSide, the group federal officials believe was behind the Colonial attack. (See Robb Says Collaboration Key to Maintaining Cyber Vigilance.)

The remaining priorities are to help state and local election officials secure their infrastructure against cyber threats, to encourage technology manufacturers to incorporate security into their designs and to reduce the risk of artificial intelligence to critical infrastructure. The last area includes the “Guidelines for secure AI system development” document, released by CISA and several of its international counterparts in November to provide guidance for AI developers on preventing security breaches in their technology.

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Constellation Reaches Agreements to Keep Everett LNG Terminal Open

Eversource and National Grid have reached agreements with Constellation to keep the Everett Marine Terminal (EMT) open for six more years, pending approval from the Massachusetts Department of Public Utilities (DPU). The gas utilities said the contracts would boost the reliability of their distribution systems and help meet winter gas demand.

Everett, a major LNG import facility located just outside of Boston, faces potential closure with its main customer, the Mystic Generating Station, set to retire this spring.

“These contracts, together with others that we hope to soon finalize, will help ensure the [EMT] continues to serve its vital role in supplying natural gas to the New England region, especially during the coldest winter conditions,” Constellation said via statement.

National Grid estimated its contract would increase customers’ gas bills approximately 1% year over year for the six years, while Eversource said its agreement would amount to “a 5 to 7% increase in the typical residential natural gas heating customer for next winter” (D.P.U. 24-26).

“This six-year agreement is critical in allowing the company to continue to provide gas supply in a safe and reliable manner to customers in the immediate term on peak days through the use of existing gas infrastructure,” National Grid wrote in its pre-filed testimony (D.P.U. 24-25).

The company noted Everett is located downstream of a bottleneck in the gas distribution system, making it “uniquely positioned to support the company’s gas system reliability during the demand seasons and demand days due to both its location and significant sendout capacity.”

Constellation declined to disclose the other companies that remain involved in contract negotiations related to Everett. ISO-NE confirmed with NetZero Insider that it is not involved in the negotiations to keep Everett open. The RTO facilitated a cost-of-service agreement to keep Mystic operating for the winters of 2023/23 and 2023/24, with the costs passed through to electric ratepayers.

The New England Power Generators Association applauded the agreement, writing in a statement that “the long-awaited contracts now being filed by [local distribution companies] ensure that the Mystic power plant shuts down, while a unique fuel resource remains in service to serve heating needs.”

In June, FERC convened a forum that focused on the future of Everett, and the heads of FERC and NERC issued a joint statement in November stressing the importance of the facility to the region’s gas network. (See NE Stakeholders Debate Future of Everett at FERC Winter Gas-Elec Forum and FERC, NERC Leaders Voice Concern About Loss of Everett Marine Terminal.)

Eversource and National Grid wrote that there were no alternatives to meet the reliability and peaking needs. Both companies project their gas demand to increase in the coming years. National Grid projects an 11% increase in gas demand between 2023/24 and 2029/30, while Eversource projects its gas load will increase by nearly 5% between 2023/24 and 2027/28.

The agreement with Constellation will help meet the growing demand, Eversource and National Grid said. The companies emphasized that the agreements would address near-term needs without requiring additional gas infrastructure.

“Incremental pipeline capacity requiring pipeline construction is not a realistic alternative to the company’s immediate reliability needs served by the proposed agreement, which are available to the company without construction of any new infrastructure,” Eversource wrote.

The DPU issued an order in December based on its three-plus-year investigation into the future of gas in the state. The order sets the stage for the state’s long-term transition away from natural gas and discourages additional investment in the gas system. (See Massachusetts Moves to Limit New Gas Infrastructure.)

Throughout the state, regulators and lawmakers hope a series of recently enacted and under-development laws and regulations will begin to turn the tide against growing gas demand. (See Mass. Lawmakers Aiming for an Omnibus Climate Bill in 2024 and Report Outlines Cost Savings of All-electric Buildings in Mass.)

However, both Eversource and National Grid left the door open to longer-term pipeline expansion to address regional gas constraints. In the fall of 2023, Enbridge announced a new project to significantly expand the capacity of its Algonquin gas system, dubbed “Project Maple.” (See Enbridge Announces Project to Increase Northeast Pipeline Capacity.)

Eversource wrote that Project Maple “could be an alternative to the proposed agreement in the long term, but the project would not be in-service until 2029 or later if it were to proceed.”

The company added that “a large-scale expansion to completely replace the EMT functionality does not seem feasible given the current policy initiatives in the state.”

Eversource confirmed to WBUR in January that it submitted a bid for firm service in the “open season” for Project Maple, a required process for Enbridge to assess the demand for the pipeline expansion. National Grid has not said whether it participated in the open season.

The DPU now faces a tight timeline to approve the agreements; the utilities requested that DPU rule by May 1. The Mystic agreement with ISO-NE is set to expire at the end of May, and the utilities’ agreements with Constellation would run from the beginning of June 2024 to the end of May 2030.

“In the event that the company does not receive timely approval of the proposed agreement, either party may terminate the proposed agreement,” Eversource wrote.

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BOEM Designates Wind Energy Areas off Oregon Coast

Federal regulators have finalized two Oregon wind energy areas they hope someday will host floating wind turbines with a combined capacity of up to 2.4 GW. 

The potential development has drawn the same criticisms leveled by opponents of East Coast proposals: It is ugly, expensive and potentially harmful to the ocean ecosystem and those who rely on it for their livelihood. 

But the U.S. Bureau of Ocean Energy Management said the Oregon WEAs incorporate adjustments made to reflect extensive feedback from the state, local residents, tribes and other stakeholders.  

BOEM said the WEA boundaries are drawn to avoid conflict with other ocean users, particularly commercial fishers. They exclude 98% of areas recommended for exclusion because of their importance as commercial fishing grounds. 

BOEM next will prepare an assessment of the potential environmental impact of placement of turbines and their electrical infrastructure within the WEAs. 

The Coos Bay WEA totals 61,204 acres and stands 32 miles offshore; the Brookings WEA is 133,308 acres and is about 18 miles from the coast. 

BOEM is following the framework it used in developing other WEAs, gradually refining the geography through multistep review and public comment. 

It identified two call areas totaling 1.15 million acres for initial consideration in April 2022, then narrowed them down to two draft WEAs totaling 219,568 acres in August 2023. The final WEAs total 195,012 acres. 

BOEM received roughly 1,150 comments on the draft WEAs, many of them form letters but 691 with unique content. They run the gamut from opposition to support, with impact on fishing raised as a frequent concern by opponents. 

The local opposition has been strong enough that Gov. Tina Kotek (D) and four members of Oregon’s congressional delegation in June 23 asked BOEM to pause its runup to the leasing process so that state officials could better identify, understand and respond to local concerns. 

In November, the Tribal Council of the Confederated Tribes of the Coos, Lower Umpqua and Siuslaw Indians unanimously declared opposition to wind energy development off the Oregon coast. 

BOEM notes that the wind off the Oregon coast is strong and consistent, offering a theoretical capacity of up to 62 GW.  

But the sea floor slopes off sharply on that portion of the outer continental shelf, limiting the siting options. BOEM considers 1,300 meters to be the limit for economically competitive offshore wind installations with existing technology.  

The water depth in the two WEAs ranges from 567 to 1,531 meters, too deep for the fixed-bottom foundations being used in the early stages of East Coast offshore wind energy development. But the technology and design of floating alternatives still are being developed. 

BOEM flags another hurdle facing development of the two WEAs: The Oregon Department of Energy indicated significant investment likely would be needed in the onshore grid to handle the output of any large-scale offshore projects — no single interconnection point on the Oregon’s coast grid can accommodate 2 GW. But such an investment would benefit development of onshore renewable energy, as well. 

After BOEM’s announcement Tuesday, Kotek responded with a prepared statement that was neutrally worded. 

But she said offshore wind likely is to be an important component of meeting the state’s 2040 goal of 100% renewable energy, and potentially also an economic boost for coastal communities.  

“As BOEM moves forward with establishing a federal offshore wind leasing process this year, Oregon is committed to developing a robust and transparent state roadmap to inform offshore wind opportunities,” Kotek said. “This state roadmap will also ensure that coastal communities and Tribal nations are consulted throughout the process

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Md. Lawmakers Load up on Clean Energy Bills

Depending on which bill you are looking at — Senate Bill 1065 or House Bill 913 — Maryland drivers of both electric and gasoline-powered vehicles could soon be paying an extra registration fee to top up the state’s Transportation Trust Fund, a main source of operating income for its Department of Transportation. 

But under SB 841, any extra fees based on how many miles vehicles actually drive on state roads would be prohibited. 

The competing bills are just three of more than 70 energy-related proposed laws introduced in the first month of the Maryland General Assembly’s 2024 session, as tracked by the Maryland Clean Energy Center. The state’s legislative session officially lasts from Jan. 10 to April 8. 

The pace of introductions reached semi-fast-and-furious in the past week — 43 bills in total — as lawmakers raced to meet the Feb. 5 deadline for new bills in the Senate and the Feb. 9 deadline in the House of Delegates. Bills can be introduced after these deadlines but will require approval from the Rules committees in their respective houses. 

The range of bills and issues covered ― from registration fees for EVs, to tough emission-reduction targets for data centers, cryptocurrency miners and cannabis growers ― reflect the challenges policymakers face as they seek to balance the state’s ambitious clean energy goals and potentially growing budget deficits. 

The bills on EV registration fees, both sponsored by Democrats, are a case in point. The Maryland Department of Transportation in December announced projected budget cuts of $3.4 billion because of falling revenues. 

SB 1065, sponsored by Sen. Guy Guzzone, would add a $100/year registration fee for zero-emission vehicles to fill at least part of that gap and make up for falling gas taxes. If passed, Maryland would join the growing number of states across the country — almost 30, according to POLITICO — that have extra registration fees for EVs. 

Del. David Fraser-Hidalgo’s HB 913 would keep the $100 fee for EVs but up the ante with a $75/year charge for other, non-electric vehicles. 

A vehicle-miles-traveled tax is an additional strategy for raising revenues for transportation infrastructure being tried by a small number of states, but Sen. Justin Ready’s (R) SB 841 would cut off that option. 

Other Republican bills similarly seek to slow or sidetrack action on the state’s transition to clean energy. 

SB 1063, sponsored by Sen. Steve Hershey, would push back the state’s adoption of California’s Advanced Clean Cars II (ACCII) until the 2030 model year. ACCII requires all new vehicles sold in a state to be zero-emission by 2035, and Maryland’s adoption of the rule in September would allow it to go into effect for the 2027 model year, when 43% of new cars sold would have to be zero-emission. (See Maryland Moves Ahead with Advanced Clean Car and Truck Rules.) 

HB 1240, sponsored by Del. April R. Rose, would ban the Department of the Environment (MDE) or the Department of Housing and Community Development from prohibiting natural gas or propane appliances in new construction or buildings undergoing renovations affecting 50% of their square footage. The bill also would ban any extra registration fees on gasoline-powered vehicles based on their use of gasoline. 

With Democrats in solid control of both houses of the General Assembly, it is unlikely such bills will pass. But with budget deficits and other economic priorities taking precedence, clean energy laws may have a rough road to passage. 

While Gov. Wes Moore (D) has committed the state to cut its emissions by 60% by 2031 and to provide residents with 100% clean power by 2035, only minor climate initiatives have been included in his fiscal year 2025 budget and the legislative agenda he brought to the General Assembly as part of his State of the State address. 

The only major energy-related line item mentioned in his budget message Jan. 17 was $90 million for implementing Maryland’s Climate Pollution Reduction Plan. Issued by the MDE on Dec. 28, the plan’s topline message is that reaching those goals will require $1 billion in new state funding every year through 2031. (See Md. Emission-reduction Plan: High Ambitions, No Funding.) 

Similarly, while the governor’s recently launched State Plan includes “making Maryland a leader in clean energy and the greenest state in the country,” the only energy-related bill (SB 474/HB 579) in his accompanying legislative agenda proposes to streamline the permitting of “critical infrastructure,” such as backup generators for data centers. 

“The Moore-Miller administration is continuing to work with the state legislature to meet Maryland’s energy goals while also protecting the state’s environment,” an administration spokesperson said in an email to NetZero Insider. “The governor looks forward to supporting legislation, and initiatives that will help Maryland secure its clean energy future.”

The General Assembly’s recent track record includes some major climate and clean energy wins, such as the Climate Solutions Now Act of 2022, which set the state’s 60% emissions reduction target. In 2023 the legislature passed laws making Maryland’s community solar pilot program permanent (HB 908) and adopting a Clean Trucks rule (HB 230) that, similar to ACCII, phases in sales of zero-emission medium- and heavy-duty trucks. 

Democrats Go Big

This year, Democrats have once again introduced ambitious bills now waiting for committee hearings. 

HB 1112, sponsored by Del. Lorig Charkoudian, would require the Maryland Public Service Commission to “determine whether the deployment of energy storage devices could help to avoid or limit a reliability-must-run agreement with an energy generating system or facility in the state under certain circumstances.” The PSC could require utilities to acquire storage, either as owner or through a third-party contract, as an alternative to keeping fossil fuel-fired generation online. 

The bill is clearly aimed at circumventing situations like PJM’s current efforts to keep the Brandon Shores coal-fired plant online past its planned 2025 closure. 

SB 861, sponsored by Sen. Karen Lewis Young, aims to cut emissions at “high-energy-use facilities,” such as data centers, cryptocurrency operations or cannabis growing farms. These facilities tend to have high energy demands that can put stress on local distribution systems. 

The bill would set a baseline emissions level of 0.428 metric tons of carbon dioxide per megawatt-hour of electricity used and require these facilities to cut emissions 60% by 2027, 80% by 2030, 90% by 2035 and 100% by 2040. 

HB 1272, sponsored by Del. Dana Stein, would take a first, small step toward funding the Climate Pollution Reduction Plan with its authorization for the MDE to establish an economywide cap-and-invest program. Maryland already receives millions of dollars from its participation in the Regional Greenhouse Gas Initiative, the regional cap-and-trade program that sets limits on greenhouse gas emissions from power plants in New England and the Mid-Atlantic. An economywide program could cover all major industrial emitters in the state. 

SB 959, cross-filed with HB 1256, is a complex package that combines the introduction of time-of-use rates as the default choice for electric utilities’ residential customers with demand-management strategies, such as the use of aggregated residential energy storage and managed charging of EVs or electric school buses. The goal, according to the bills’ sponsors, Fraser-Hidalgo and Sen. Brian Feldman (D), is to promote “beneficial electrification” by encouraging consumers to shift energy use to off-peak hours, thus cutting peak loads on distribution systems and their own energy bills. 

But not all bills sponsored by Democrats may be considered climate-friendly. A second bill sponsored by Stein, HB 990, would exempt manufacturing facilities in the state from complying with any emission-reduction rules, such as Maryland’s Building Energy Performance Standard, which requires buildings larger than 35,000 square feet to cut their emissions 20% below 2025 levels by 2030 and reach net zero by 2040. 

The bill would prohibit state agencies from establishing rules requiring manufacturers to cut emissions below 2023 levels, especially if doing so would cause significant cost increases above 2023 levels for the state’s manufacturing sector. However, the bill would not exempt manufacturers from complying with greenhouse gas reporting requirements or emission reductions related to RGGI. 

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DC Circuit Hears Arguments on FERC LNG Plant Approval

The D.C. Circuit Court of Appeals on Feb. 12 heard oral arguments on FERC’s approval of the Commonwealth LNG facility in Cameron, La. 

The case proceeds after the Biden administration paused new applications for liquified natural gas (LNG) export facilities in the U.S. (23-1069). 

FERC approved the Commonwealth project in late 2022. It would consist of 9.3 billion cubic feet per day of export capacity on 150 acres along the west bank of the Calcasieu Ship Channel, near three existing LNG export facilities and others being planned.  

In approving the project, FERC disregarded its potential to raise Louisiana’s greenhouse gas emissions by 1.7% on its own. The commission also ignored the environmental justice impact of the facility, which would be located on a heavily industrialized slice of the Gulf Coast, according to environmental groups Natural Resources Defense Council, Sierra Club, the Center for Biological Diversity and Healthy Gulf. 

FERC’s rules around approving projects that influence climate change are far from clear, but it has ruled on such impact before, Sierra Club attorney Nathan Matthews said during the hearing. In a case involving Northern Natural Gas Pipeline, it said 315 tons of GHG emissions per year was well below any threshold it would consider. 

“FERC could have done the same here where the 3.6 million tons per year of emissions are 36 times FERC’s draft threshold, which itself was equal to or higher than every other threshold any other agency proposed,” Matthews said. 

The commission has drafted rules amending how it processes natural gas projects, but they have not advanced since former Chair Richard Glick released them in 2022 and then had to withdraw them after criticism from the industry and Capitol Hill. 

The proposed facility would release 550 tons per year of nitrogen dioxide, which is harmful at any level and will cause the area around the terminal to exceed EPA’s limit for the gas in air quality standards, Matthews said. 

“FERC simply misunderstands cumulative effects,” Matthews said. “FERC concluded that there would be no cumulative impact problem here because the individual incremental impact of this project was individually insignificant. But the central thrust of the cumulative impact regulation and doctrine is to guard against the death of 1,000 cuts.” 

‘Incremental Impacts’

Judge Bradley Garcia asked whether the issue was FERC’s failure to label the nitrogen dioxide emissions as significant, which would have at least required it to explain why the facility should move forward regardless. 

“For every impact you identify as significant, you have to discuss mitigation of that impact,” Matthews said. “And here, we think that they could have redesigned the terminal to reduce these emissions, even if they were going to still approve the terminal.” 

A decision from the D.C. Circuit last year in a case the Center for Biological Diversity brought against FERC’s approval of an LNG facility in Alaska clearly laid out what the regulator had to do under the Natural Gas Act in its review of Commonwealth LNG, said FERC Attorney Susanna Chu. 

“Because, like this case, it’s a purely Section Three terminal case, there’s no Section Seven pipeline involved,” Chu said, referring to relevant sections of the Natural Gas Act. “So, the standard here is that the commission must approve the terminal proposal unless it makes a finding that the terminal is actually inconsistent with the public interest.” 

Chu was asked why FERC did not follow its finding in Northern Pass and determine that the 3.6 million tons of annual CO2 emissions from Commonwealth LNG are significant. The 100,000 tons per year threshold was only a draft proposal and FERC has not adopted it, Chu said.  

Judge Florence Pan asked whether there was any chance FERC would pick a threshold more than 36 times its proposal. 

Chu said that FERC has yet to make any final decisions on the question, but Pan pressed on — asking whether the project’s emissions would be significant if it increased the state of Louisiana’s emissions by 20%. 

“The issue with global climate change, as the commission explained in the environmental statement, is that there are incremental impacts,” Chu said. “And … you can’t attribute physical … global climate change impacts, such as sea level rise or other specific impacts, to a particular project. At least, the commission has not yet been able to identify a methodology that would allow it to do so.” 

FERC actually did more work than it had on previous projects in quantifying the emissions from Commonwealth. Garcia asked whether any of that influenced its decision-making when it came to mitigating pollution. 

The commission discussed climate change, but said it was unable to determine whether an individual project such as Commonwealth LNG would have a major impact on it, Chu said. Pan then said that it would seem easier to make an actual finding of significance and assess ways for the project to mitigate those impacts than to wind up in more litigation. 

“It’s been something that the agency has been grappling with,” Chu said. “I mean, this is a bipartisan, independent commission. And we see from the different, the evolution of the cases, the commission is moving [toward] more and more information in the environmental analysis.”