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December 24, 2024

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Ørsted Exits Offshore Wind Markets, Remains Committed to US

The world’s leading offshore wind developer announced it is pulling out of some smaller markets but reiterated its commitment to construction and operation in U.S. waters.

In its 2023 earnings report, issued Feb. 7, Ørsted also downgraded its growth projection, announced hundreds of job cuts and said its bottom line was a $2.91 billion net loss in 2023. More than $1 billion of the loss was because of offshore wind project cancellation costs.

Much of the fiscal distress stems from Ørsted’s troubles in the northeastern United States.

In late 2023, it became the first developer to cancel a major, mature U.S. project when it spiked Ocean Wind 1 and 2 and took billions in impairments.

In early 2024, it canceled the Maryland offtake contract for Skipjack Wind and moved to cancel the New York offtake contract for Sunrise Wind, resulting in additional costs and delays. But it continues to develop both projects and is seeking a new contract for Sunrise.

The developments prompted Ørsted to undertake a comprehensive offshore portfolio review, the results of which were reflected in Feb. 7’s announcements.

The board of directors set a goal of 35-38 GW of installed offshore capacity by 2030; it now has approximately 23 GW installed, and previously had aspired to reach 50 GW by 2030.

The challenges of 2023 also led Ørsted to suspended stock dividends for fiscal years 2023-25 and report a $2.91 billion loss in 2023, compared with a $2.17 billion profit in 2022.

It remains committed to the U.S. offshore wind sector, particularly off the Northeast coast, but will exit the market in Norway, Spain and Portugal; will deprioritize development in Japan; and is planning to trim development efforts in floating wind and P2X — the use of offshore wind energy to generate other forms of energy, such as green hydrogen.

As a result, the company expects to reduce its global workforce by 600 to 800 people.

Looking forward, Ørsted said it’s exploring options for divesting the federal leases off the New Jersey coast for the Ocean Wind projects.

The company said it is revising its project operating model to include better contingency planning, with more proactive planning for backup supply chain capacity; securing all critical local permits before making a final investment decision; ensuring greater flexibility on project timelines and commissioning dates; and conducting more reviews of projects as they progress, both by internal peers and external sources.

Other Financials

Other companies in the offshore wind space also have released financial results in the past week. The reports have provided additional insight into the problems the sector is facing.

For example, in its fourth-quarter/full-year earnings call Jan. 23, General Electric placed its 2023 offshore wind loss at roughly $1.1 billion.

In its 10-K filing Feb. 2, General Electric predicted global growth in the offshore wind industry in coming decades but near-term challenges due to companies trying to increase output and reduce cost.

For its own offshore business, GE said it continues to experience pressure related to product and project cost estimates. It’s attempting to counter this, but timeline changes and other adverse developments could result in further losses beyond what it currently estimates.

For the year ending Dec. 31, offshore project losses increased by $400 million, GE said, and launching or ramping up new platforms such as the Haliade-X offshore wind turbine will create additional operational risks.

In other reports:

    • Equinor said Feb. 7 its net income dropped 59% from $28.74 billion in 2022 to $11.9 billion in 2023. Its renewables sector recorded a $757 million net loss in 2023, compared with an $84 million net loss in 2022, which it attributed in part to the $300 million third-quarter impairment it took on its U.S. Northeast offshore wind projects, as well as higher development and operating costs elsewhere.
    • Bp took a $600 million pretax impairment charge in the fourth quarter of 2023 because of restructuring of its U.S. projects, raising the full-year cost to $1.14 billion. Bp and Equinor are dissolving their offshore partnership, which had four separate wind farms in development. They have terminated the New York offtake contracts for Empire Wind 2 and Beacon Wind 1 and effectively terminated the contract for Empire Wind 1.
    • Siemens Energy issued its first-quarter 2024 report Feb. 7, titling the release “Solid start to the year, turnaround of wind business remains focus.” But that referred to onshore wind, where Siemens has run into quality control problems. The company said orders were slightly higher but revenue lower in the offshore business in the first quarter of 2024 compared with 2023 amid rising product costs and ramp-up challenges.
    • Vestas said Feb. 7 that it returned to profitability in 2023 and recorded a record order intake — 18.4 GW — in both onshore and offshore equipment, especially in the U.S. 2023 offshore revenue was down from 2022 but that was more than offset by onshore increases. Looking forward, it expects the offshore market to show a compound annual growth rate of 20 to 25% in 2023-30, with growth accelerating after 2025. That is a downgrade from a year earlier, when Vestas predicted 35 to 40% growth from 2022-25.
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NY Fire Code Updates Recommended for BESS Facilities

A task force formed in the wake of significant fires at three grid-scale battery energy storage systems has recommended new safety protocols for the facilities in New York state. 

The 15 draft recommendations published Feb. 6 are open now for comment by the public and industry stakeholders. The final versions will be considered by the New York State Code Council for inclusion in the Fire Code of New York State and in other fire safety standards that apply to energy storage facilities. 

The three fires came in two months in mid-2023, each larger than the one before. Fires in lithium-ion battery energy storage systems (BESS) are hard to extinguish and can emit toxic smoke, but an extensive review found no sign of environmental damage or public health risks in the aftermath of these three. Nor were any injuries reported. (See Analysis Shows No Contamination from NY BESS Fires.) 

Public perception was perhaps the biggest casualty of the fires, becoming a friction point for New York’s clean energy ambitions, which will require many gigawatt-hours of installed storage to backstop intermittent renewables. (See Battery Storage Developers Bump Against Perception of Risk.) 

Numerous municipalities statewide proposed or enacted BESS moratoria as 2023 went on. 

After the third fire, Gov. Kathy Hochul (D) formed the Inter-Agency Fire Safety Working Group to examine the incidents and BESS safety standards. In late December, the group issued its initial analysis of the toxic effects of the fires. 

The fire code recommendations announced Feb. 6 were the next step. They’re intended to apply to lithium-ion grid-scale BESS exceeding 600 kWh of capacity. 

The working group’s continuing efforts include negotiations with the battery manufacturers and utilities to obtain root cause analysis reports for the three fires and perform inspections of all operational BESS above 300 kW in New York. 

BESS safety industry experts are part of the working group. The BESS industry itself is not. Its input will come now, during comment on the draft recommendations. 

The New York Battery and Energy Storage Technology Consortium told NetZero Insider via email: “NY-BEST is pleased that the State Inter-Agency Battery Safety Working Group has released its thoughtful draft recommendations and is soliciting feedback and additional input from industry subject matter experts. The energy storage industry appreciates the significant efforts of the state’s working group and we share the state’s interest in ensuring that battery energy storage is deployed safely throughout the state. We look forward to leveraging our expertise to assist the state in developing final recommendations that achieve our shared goal of making New York a leader in safe deployment of battery energy storage.” 

The Alliance for Clean Energy New York also was not ready to comment Feb, 6on the recommendations themselves. It said: “In the coming days, we plan to review closely the 15 draft recommendations proposed by the working group and look forward to submitting comments and working with the New York State Code Council to ensure that the installation and operation of BESS facilities continues in a safe manner.” 

The Recommendations

The Working Group noted in conclusion that the most critical issues it identified could be addressed by better enforcement and adherence to the existing code.  

It offered the 15 recommendations as ways to improve the regulatory framework for BESS in New York. They are:  

    • Require industry-funded independent peer reviews for all projects.  
    • Expand the requirement for explosion control to include BESS cabinets in addition to rooms, areas, and walk-in units; additionally, provide design requirements or language for what constitutes a “passable” system. 
    • Require that qualified personnel are available for dispatch within 15 minutes and able to arrive on scene within four hours to provide support to local emergency responders. 
    • Extend safety signage requirements beyond the BESS unit itself to include perimeter fences or security barriers and include a map of the site, BESS enclosures and associated equipment. 
    • Update the Fire Code to ensure that Battery Management System data is monitored by a 24/7 staffed Network Operations Center. Critical failure notifications should be immediately communicated to the site owner/operator to take corrective actions as necessary. 
    • Update the Fire Code to incorporate requirements for closed-circuit television systems, specifying their intended use as both a continuous monitoring tool and a post-event analysis resource. 
    • Remove the Fire Code exemption for BESS projects owned or operated by electrical utilities to ensure that all projects comply with the Fire Code. 
    • Include a requirement for an Emergency Response Plan and annual local first responder training for every BESS installation. 
    • Include a Fire Code requirement for monitoring of fire detection systems by a central station service alarm system to ensure timely, proper notification to the local fire department in the event of a fire alarm. 
    • Mandate the installation of fire stops for all BESS enclosure penetrations to prevent the propagation of fires from one BESS unit to another through these pathways. 
    • Introduce a new provision in the Fire Code mandating industry-funded special inspections for BESS installations to ensure thorough safety and compliance. 
    • Include “cabinets” in all Fire Code requirements that pertain to rooms, areas or walk-in units, except for fire suppression requirements, as they may be inappropriate for cabinets. 
    • The WG concluded that the Fire Code may not be the appropriate place to require a Root Cause Analysis. 
    • Establish guidance for water supply, including whether water is appropriate for different technologies, in an emergency response to a BESS fire and determining if more specific requirements are necessary. 
    • Recommend that the Code Council have further discussions around clearance distances of oil-insulated transformers from BESS. 
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9 States Agree to Accelerate Home Heat Pump Installations

Leaders of nine states have agreed to pursue greater adoption of heat pumps by their combined 93 million residents. 

A memorandum of understanding announced Feb. 7 sets a goal of heat pump technology comprising 65% of residential heating, cooling and water heating equipment sales by 2030 and 90% by 2040. That compares with a present-day market share of roughly 25% in the nine states. 

The Northeast States for Coordinated Air Use Management (NESCAUM) brokered the MOU, which reaches well beyond the borders of the air-quality advocacy organization. 

California, Colorado, Maine, Maryland, Massachusetts, New Jersey, New York, Oregon and Rhode Island signed onto the MOU. It builds on a September announcement by the U.S. Climate Alliance in which 25 governors set a 2030 goal of 20 million heat pumps operating in their states. (See Climate Alliance Seeks to Boost Heat Pump Sales.) 

The nine states agreed to lead by example and promote zero-emission technologies in state-owned buildings. They also will seek to direct at least 40% of efficiency and electrification investments toward low-income households that pay a large percentage of their income for energy costs, and to communities that historically have experienced high air pollution levels. 

NESCAUM noted that buildings are a leading source of greenhouse gas emissions. In the nine participating states, buildings emit 173 million metric tons of carbon dioxide per year, plus much smaller quantities of nitrogen oxides, fine particulate matter and other substances blamed for health problems. 

Multiple variables will bear on how these outputs change amid greater use of heat pumps, and there is not a ready estimate of what a 65% or 90% market share would accomplish by way of reduction, said Emily Levin, a NESCAUM senior policy adviser. 

She told NetZero Insider that small-scale residential installations are the subject of the MOU because controlling temperatures in larger residential and commercial structures with heat pumps is a more complicated proposition, and the technology is evolving. 

The MOU is not legally binding, and it is designed to sidestep the controversies that often attach to proposed fossil fuel bans or electrification mandates. 

Levin said there is not one single path to 65% market share; each state will develop its own strategy, and each strategy likely will have multiple tracks. 

“I think we see it being all of the above and looking a little different in every state,” she said. “There will likely be new policy measures in the mix.” 

Some of the first wave of electrification rules, such as the one New York passed in 2023, exempt retrofits of existing buildings. (See NY to Begin Banning Gas in New Construction in 2026.) 

But almost all of the residences that will exist in 2030 and 2040 already have been built. So any meaningful drive to building decarbonization will need to specifically target existing structures. A mix of incentives, tax credits and practical assistance is offered to make this happen. 

“We’re seeing a range of policies emerging to tackle existing buildings,” Levin said. 

There are potential sticking points on the path to 65% market share. 

A larger workforce skilled in heat pump technology needs to be trained, for example. Levin said these efforts are underway. The skillsets in the traditional HVAC industry are not entirely different, but there is a learning curve in the move to electrification. 

Grid capacity is also a consideration, she said, but there are strategies that could mitigate heat pumps’ demand for electric power in regions that previously relied on fossil fuels for heat. 

There also could be pushback from industries that rely on existing technology and see electrification as an existential threat. Some proposals have turned into battles. 

NESCAUM hopes this effort will be perceived more positively and has enlisted HVAC industry stakeholders in the push for the MOU. 

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NJ Opens 2nd State Agreement Approach to Connect OSW with PJM

The New Jersey Board of Public Utilities (BPU) has initiated a second state agreement approach (SAA) process with PJM to build the transmission needed to connect 3,500 MW of offshore wind with the RTO’s grid.

In a Feb. 5 announcement of the SAA, BPU President Christine Guhl-Sadovy said the first agreement in 2022 — also the first for PJM — made the state a national leader in developing offshore wind, putting it on track to construct 4,890 MW.

In addition to resources being developed through PJM’s traditional generation interconnection queue, the second SAA will allow the state to meet Gov. Phil Murphy’s goal of installing 11 GW of offshore wind by 2040. PJM and the BPU jointly filed the SAA with FERC on Feb. 2 (ER24-1187).

“We believe that a coordinated and planned approach could result in more efficient and cost-effective transmission solutions, significantly reducing the risks of permitting and construction delays and protecting ratepayers with cost containment options,” Guhl-Sadovy said in a statement. “This approach helps minimize environmental impacts associated with onshore and potentially offshore upgrades. We look forward to further evaluation and planning, as a result of SAA 2.0.”

PJM CEO Manu Asthana said New Jersey’s use of the SAA process shows the promise it holds for states with policy goals that required developing new generation.

“The continued collaboration between PJM and New Jersey through the State Agreement Approach underscores PJM’s commitment to reliably and cost-effectively facilitating states’ renewable energy policy goals,” Asthana said in the announcement. “PJM’s competitive planning process allows for creative solutions to complex infrastructure challenges. New Jersey has been a leader in this approach and can be a template for other states pursuing their individual energy policies.”

New Jersey has pushed ahead with solicitations for offshore wind infrastructure since approving the $1.1 billion in transmission projects PJM recommended through the first SAA round, but hit a snag when developer Ørsted canceled its two Ocean Wind projects in November. (See New Jersey Launches OSW Infrastructure Solicitation.)

Speaking at a Feb. 6 PJM Transmission Expansion Advisory Committee meeting, PJM’s Susan McGill said the RTO plans to run the SAA planning process parallel to the 2024 Regional Transmission Expansion Plan (RTEP), with the goal of opening competitive solicitation windows for both in July. Doing so would allow PJM to select project components that meet both future reliability needs and New Jersey’s interconnection request in the most cost-effective manner and on a timeline that allows the BPU to consider project approval in the second quarter of next year.

McGill encouraged developers to draft proposals that address needs identified in both windows and submit them to each window, which would allow PJM to ensure it is selecting the best match of components.

“We will look at it from every angle to make sure we are only building what’s needed,” she said.

McGill said PJM will also give further thought to a stakeholder question about whether this approach could result in transmission owners who submit projects having to pay twice the fees to have a proposal considered for both windows.

Several stakeholders raised concerns that having two competitive windows open at once could strain the resources of PJM and transmission owners. They suggested that better ideas might be submitted if the RTO conducted the processes on a staggered timeline.

PJM’s Sami Abdulsalam said the RTO considered delaying one of the windows but said there are time constraints on when each needs to be finished. Completing one without knowing what proposals will be made for the other could result in overlap and projects having to be canceled, he said.

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Hawaii PUC Approves HECO Grid Resilience Plan

The Hawaii Public Utilities Commission on Feb. 1 approved Hawaiian Electric Co.’s five-year resilience plan to harden the grid against future natural disasters like the wildfires that ravaged the state last year, particularly the island of Maui. 

The PUC’s approval of the Climate Adaptation Transmission and Distribution Resilience Program will allow HECO to receive $95 million offered by the Biden administration in August for investments in resilience. HECO’s ratepayers will fund the remainder of the plan’s $190 million overall cost. In a press release, the utility said the federal funds should reduce the program’s cost for consumers by half, with an estimated impact on the monthly bills of residential customers using 500 kWh to be 17 cents on Oahu, 47 cents on Hawaii Island and 39 cents in Maui County. 

The first phase of the plan will involve replacing or strengthening more than 2,000 transmission poles on critical circuits, HECO said. Additional steps include: 

    • increased situational awareness and control through cameras, sensors and reclosers in areas with higher wildfire risk; 
    • removal of trees that are weak, dead, diseased or otherwise in danger of falling on power lines; 
    • strengthening circuits serving hospitals, defense facilities and other critical customers; 
    • undergrounding selected distribution circuits; and 
    • hardening existing control centers, moving the Maui control center to avoid flooding and building a backup control center on Oahu. 

HECO faced widespread criticism in the immediate aftermath of the fires, which killed 100 people on Maui in August and burned more than 3,000 acres, including the historic town of Lahaina. As of October, more than 35 lawsuits had been filed against the utility, including by Maui County, which accused HECO of failing to power down electric equipment amid fire danger warnings from the National Weather Service. (See Hawaiian Electric Faces Multiple Lawsuits over Wildfires.) 

The county also said the utility and its sister company, Maui Electric, failed to properly maintain and repair utility poles and to keep vegetation trimmed and away from power lines. 

Testifying before the House Energy and Commerce Committee’s Oversight and Investigations Subcommittee in September, HECO CEO Shelee Kimura pushed back against the allegation that her company was responsible for the fires, noting that the lines in the area where the Lahaina fire began in the afternoon of Aug. 8 were not energized at the time. (See House E&C Members Grill HECO CEO About Maui Fires.)  

In later supplemental testimony, Kimura added that HECO had put its high-wind protocol in place Aug. 7, including a protocol to disable automatic reclosing on certain circuit breakers and reclosers to prevent lines that trip offline because of faults from re-energizing. She also acknowledged that HECO, “like most utilities,” did not have a pre-emptive public safety power shutoff program in place Aug. 8, but that it was working with stakeholders to design such a program. 

Last month HECO said it was continuing wildfire restoration efforts in West Maui, including by replacing destroyed transmission poles with more resilient steel infrastructure. While nearly all of the 12,000 customers in the area had restored power at the time, the utility warned that it will not have the ability to reroute power from other circuits until the work is completed later this year, meaning that outage restoration times may be longer than normal. 

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Cupparo Replaces Certoma as SPP Board Chair

SPP’s Board of Directors has elected independent director John Cupparo to be its chair, the RTO said Feb. 6.

Cupparo, who will assume the role Feb. 7, will fill out the remainder of Susan Certoma’s term, which expires at year’s end. Certoma told stakeholders Feb. 6 she is stepping down as chair but will remain a board member.

Susan Certoma | © RTO Insider LLC

“It’s an honor and a privilege to have the opportunity to follow in the footsteps of the SPP board chairs that have come before me,” Cupparo said during a Feb. 6 board meeting, which featured several discussions on resource adequacy and the grid’s transformation.

“As we saw in the conversation today, SPP is faced with a series of opportunities and challenges,” he said. “I believe SPP is well positioned to capture those opportunities and to meet those challenges, given the strength of this board, [SPP CEO] Barbara [Sugg] and her team, [and] the members in the broader SPP community.”

Cupparo was elected to the board in 2022. He will continue to chair the Strategic Planning Committee and serve on the Interim Markets+ Independent Panel and the Finance and Human Resources committees. He previously was an officer with PacifiCorp, a senior executive at Berkshire Hathaway Energy leading a transmission investment program in the West and a board member for WECC.

Certoma opened the board’s quarterly meeting Feb. 6 by announcing she was giving up her position as board chair, a position she has held since 2023. She will continue to serve on SPP’s Finance and HR committees.

“At this time, there are other matters that require my attention,” Certoma said.

Sugg lamented that the meeting’s virtual format prevented a standing ovation for Certoma. Still, members were able to use the webinar application to send virtual hand claps to Certoma.

“I don’t think that the membership realizes the load of work that the chair takes on, and it is significant,” Sugg said. “Susan has been with me at every step of the way over the last year.”

The three-year board terms for both Certoma and Cupparo expire at the end of the year, along with that of Ben Trowbridge. All three have expressed a desire to remain on the board. The Corporate Governance Committee will consider their interest when it meets next week.

Liz Moore will remain as the board’s vice chair.

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Mass. Gas Working Group Finalizes Recommendations to Legislature

The Massachusetts Gas System Enhancement Plan (GSEP) Working Group submitted its final report to the state Legislature at the end of January, providing a series of recommendations on aligning the state’s efforts to replace leak-prone pipes with its climate mandates. 

Intended to inform lawmakers as they attempt to craft an omnibus climate bill this spring, the recommendations also highlight key areas of contention between the gas utilities, climate advocates and state officials. (See Mass. Lawmakers Aiming for an Omnibus Climate Bill in 2024.)  

The working group consisted of representatives from a wide range of stakeholders, including state agencies (The Attorney General’s Office, Department of Environmental Protection, Department of Public Utilities and Department of Energy Resources), nonprofits (Conservation Law Foundation, HEET, Low-Income Energy Affordability Network, National Consumer Law Center and PowerOptions), and the state’s gas utilities (The Berkshire Gas Co., Eversource Energy, Liberty Utilities, National Grid and Unitil Corp). 

The existing GSEP program dates to a 2014 law directing utilities to replace or repair old gas pipes to reduce methane leaks, allowing the utilities to recover the costs on an accelerated timeframe. The program has faced criticism for encouraging investment in the gas system as the state simultaneously moves to phase out its reliance on gas. 

GSEP costs are expected to increase substantially in the coming years. An analysis by Dorie Seavey of Groundwork Data estimated capital expenditures from the program would cost ratepayers more than $34 billion between 2022 and 2039. The state Attorney General’s Office (AGO) estimated “if GSEP continues at its current pace, the total cost of this initiative will be approximately $40 billion over the next decade, an expense borne by ratepayers.” 

The working group was initiated by the state’s 2022 climate law and worked throughout the past year to produce a series of recommendations. 

Members of the working group voted on proposals to redefine the types of projects that are included and prioritized in the GSEP program, authorize the utilities to terminate gas service to existing customers within the scope of GSEP projects, and change the GSEP cost recovery timeline. 

Repair and Retirement

The majority of the working group, including the state agencies and advocacy groups, voted to add language shifting the program from a focus on pipe replacement toward the inclusion of pipe repair and retirement to help minimize costs and avoid stranded assets as the state moves away from gas. The gas utilities and the United Steelworkers Union (USW) opposed adding language promoting repair. 

Representatives for the state’s gas utilities argued that “it is more cost-effective and in the best interest of customers to replace pipe segments rather than undertaking extensive repairs that only serve to defer inevitable replacements.” The utilities voted in favor of adding language around pipe retirement.  

The working group also favored requiring the utilities to evaluate non-gas pipe alternatives (NPAs) prior to GSEP repairs or replacements. The AGO wrote that this would force the gas companies “to be proactive about the transition to renewable energy.” 

The gas utilities and USW opposed this requirement, arguing it undermines the purpose of the law. The gas utilities added they “do not believe it is practical or efficient to evaluate a NPA for all GSEP projects, and in fact, may result in delays to replacement of high-risk leak prone pipe, having a negative impact on safety.” 

Emissions Limits

The group also voted to add language to specify that GSEP projects must be consistent with the state’s decarbonization mandates, including the sector-based emissions sublimits. This proposal was supported by most stakeholders, with partial opposition coming from gas utilities. 

The utilities said the state should constrain the consideration of subsector emissions limits to the “Natural Gas Distribution and Service” sector, arguing that emissions limits that apply to natural gas consumption are beyond the scope of the GSEP program. 

Redefining the Obligation to Serve

Most of the stakeholders also voted to add language allowing gas utilities to “terminate natural gas service to a customer” to implement non-gas GSEP upgrades that would provide similar heating service to customers. This was supported by the state agencies and advocacy groups, with several of the nonprofits stressing the need to add language protecting low-income ratepayers. 

Redefining the obligation of local distribution companies to serve “can provide an opportunity for LDCs to identify opportunities for their participation in efforts to achieve net-zero greenhouse gas emissions,” commented the Conservation Law Foundation. “This is a potentially vital tool in Massachusetts’ transition to a clean energy future and should be considered as a viable change sooner rather than later.” 

The gas utilities and USW opposed this proposal, arguing that changing the statutory obligation to serve existing gas customers is beyond the scope of the working group. 

Cost Recovery Timelines

A plurality of members also supported a proposal by the AGO to phase out accelerated cost recovery for gas infrastructure investments, backed by the advocacy groups.  

“GSEP is, at its core, a funding mechanism that allows utility companies to recover the costs of natural gas infrastructure replacement on an accelerated timeline,” the AGO wrote, adding that accelerated cost recovery encourages the “further institutionalization of natural gas infrastructure that should be largely phased out by 2050.” 

The utilities and USW opposed this proposal. The utilities argued that repealing the accelerated cost recovery is beyond the working group’s scope, adding that the proposal “is tantamount to the repeal of the GSEP statute.” 

The fate of the proposals now sits with the Legislature. The working group included two members of the Legislature, Sen. Mike Barrett (D) and Rep. Jeff Roy (D), co-chairs of the Legislature’s Joint Committee on Telecommunications, Utilities and Energy. Barrett typically voted in alignment with the advocacy groups and state agencies, while Roy abstained in the votes. 

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DOE Opens 2nd Solicitation in Transmission Offtake Program

The U.S. Department of Energy opened the second solicitation in its program to prime the pump for new transmission needed to meet the Biden administration’s climate goals.

Initial proposals for the $1.2 billion to be offered in Round 2 of the Transmission Facilitation Program will be due March 11, DOE’s Grid Deployment Office said in its Feb. 6 announcement.

Authorized by the Infrastructure Investment and Jobs Act, the program allows DOE to borrow up to $2.5 billion to assist in the construction of high-capacity transmission lines that otherwise would not be built or to increase the capacity of already planned lines.

On Oct. 30, DOE announced it would spend $1.3 billion to purchase up to 50% of the capacity on three projects totaling 3.5 GW: the 500-kV Cross-Tie Transmission Line (Nevada and Utah), the Southline Transmission Project (Arizona and New Mexico) and the Twin States Clean Energy Link (New Hampshire and Vermont). (See DOE to Sign up as Off-taker for 3 Transmission Projects.)

The program offers capacity contracts to late-stage projects to increase investors’ and potential customers’ confidence and reduce the risk of developers undersizing projects. DOE will seek to recover its costs by selling its capacity rights, allowing it to make offers to additional projects.

DOE’s National Transmission Needs Study, also released in October, estimated the U.S. must more than double its regional transmission and expand interregional capacity more than fivefold by 2035 to ensure reliability, resilience to extreme weather and access to renewables.

Responding to industry feedback, DOE broke its second solicitation into two parts, with an initial submission of a  “project paper and virtual presentation” to be followed by a detailed application and in-person interview.

DOE will hold a public webinar to provide additional information on the solicitation Feb. 21 at 3 p.m. ET.

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Bill to Create Wash. Oil Market Oversight Agency Dies in Committee

OLYMPIA, Wash. — A Washington bill that would have created a new agency to monitor the state’s oil industry has died in committee.

Senate Bill 6052 was stopped in the state Senate’s Ways and Means Committee on Feb. 5 because of the costs stemming from the cybersecurity need to protect the data to be collected from oil companies, the bill’s sponsor, Sen. Joe Nguyen (D), told NetZero Insider. The bill will be revived in the legislature’s 2025 session, he said. (See Wash. Bill Seeks Increased Monitoring of Petroleum Sector.)

Washington’s Legislature is in the middle of a short 60-day session that will mainly tweak the 2023-2025 biennial budget adopted last year.

In a recent hearing on the bill, oil industry representatives voiced concerns about the cybersecurity of several dozen different types of information the proposed Division of Petroleum Market Oversight would collect and analyze to make sure the industry is not engaging in price gouging. The cybersecurity measures bumped up the initial costs of establishing the agency to $30 million, which is not available in the budget the Legislature is working on, Nguyen said.

But the money should be available in the 2025 session, which will deal with the main biennial budget, Nguyen said.

Creation of the agency has been a major plank in Gov. Jay Inslee’s push to fight climate change. Inslee and Democratic leaders are concerned the oil industry has been unjustifiably raising gas prices due to the cap-and-invest program the state launched last year.

“We knew a proposal like this would be a heavy lift for a short session, especially with the expense of setting up new state infrastructure for this,” Inslee spokesperson Mike Faulk said in an email. “Even as gas prices in Washington have dropped to almost their lowest in two years, consumers will continue experiencing dramatic price swings. … As we make the transition to clean fuels, transparency into oil pricing will only become more important for protecting consumers.”

“Until the close of this session, no proposal is truly dead,” said Jessica Spiegel, senior director for the Northwest region at the Western States Petroleum Association. “However, there are legitimate concerns about the structure, scope and costs of the new state agency SB 6052 would have created. Once we move beyond this issue, the focus can be on the important work of reforming Washington’s cap-and-trade program.”

The WSPA represents four of Washington’s five oil refineries.

Modeled after a new California office, the proposed agency would collect a massive amount of financial and industrial data from various branches of the oil industry in Washington, including five refineries and a complex supply chain.

The agency would have subpoena power and would confidentially refer suspected legal violations to the Washington Attorney General’s office. It also would report its observations and conclusions to the governor’s office, other state agencies and the Legislature.

Inslee called for the bill following the political and economic fallout from the state’s introduction of a cap-and-invest program that went into effect in January 2023. Critics have blamed the program for a gas price increase of 21 to 50 cents per gallon, depending on how calculations are done.

Inslee has pointed to the fact that the oil industry reported $200 billion profits in 2022, sparking suspicions that it is price gouging behind closed doors. Meanwhile, a public referendum is headed to the November ballot to repeal the cap-and-invest program against the wishes of the Democratic-controlled Washington Legislature.

Washington’s gas prices have been among the highest in the nation since last summer, including spending a week as the highest. However, citing AAA figures, Nguyen said Washington’s gas prices have been among the five highest in the nation since the 1970s for economic and geographic reasons.

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President Biden’s LNG Pause Fuels Partisan Debate at House Hearing

Republicans teed off on President Biden’s pause on processing new applications for LNG exports at a congressional hearing Feb. 6. (See Report: Biden Admin to Evaluate LNG Terminals’ Impact on Climate.)

“In addition to undercutting our domestic energy industry, President Biden’s decision is a gift to Vladimir Putin,” said Rep. Jeff Duncan (R-S.C.), chair of the House Energy, Climate & Grid Security Subcommittee. “Global demand for natural gas is expected to increase 46% by 2050. And our European and Asian allies who want to do business with the United States will now look to Qatar, Russia and Iran to meet their growing energy needs.”

Duncan said committee leaders had invited a speaker from the Department of Energy, but nobody from the administration came. Undersecretary of Energy David Turk is scheduled to testify on the subject at a Senate Energy & Natural Resources Committee hearing Feb. 8.

The pause comes after the industry already has built enough capacity to export 14 billion cubic feet per day, with enough under construction to double that capacity, said Subcommittee Ranking Member Diana DeGette (D-Colo.). Additional projects with full approvals from FERC and DOE, but yet to start construction, would triple that capacity, DeGette said.

None of those facilities under development will be affected by the pause in reviews, she added. The last time the review process for new export facilities was updated was 2018, when export capacity was just one-third of today’s level.

“The fact that our nation’s production has ramped up so quickly must be considered, especially since the U.S. currently has enough approved capacity to fulfill the world’s energy needs in the short and medium terms,” DeGette said. “Continuously increasing LNG exports, without updating guidelines to account for new information, is a fundamentally unserious proposal.”

EQT calls itself the largest producer of natural gas in the country, with its drilling focused around the Marcellus and Utica shales in Pennsylvania, Ohio and West Virginia. EQT CEO Toby Rice blasted the decision to pause approvals for new export facilities.

“The Biden administration’s decision was pure politics,” Rice said. “The moratorium was made under the guise of updated research and a claim that we needed updated studies on the environmental and economic impact of U.S. LNG. But we all know what it really is, and that’s an election-year stall designed to garner votes.”

Europe has had to rely on importing LNG from the U.S. since its countries were cut off from Russia following its invasion of Ukraine, said Brigham McCown, senior fellow at the Hudson Institute. Last month, spot prices there averaged $9.56/MMBtu (million British thermal units), while Henry Hub gas was at just $2.26/MMBtu this week, McCown said.

“Europe should not be allowed to recede into the background,” McCown said. “Energy security highlights the need for a comprehensive approach and a stable policy environment coupled with innovation, technology and international cooperation. Our allies would like to be able to have energy security as well.”

Gillian Giannetti is a former high school teacher along the part of Louisiana’s coast called “cancer alley” because of the concentration of industrial facilities and their pollution’s impact on locals. Now senior attorney for the Natural Resources Defense Council’s Sustainable FERC Project, Giannetti said she’s witnessed the effects on her former students, who had high rates of asthma and other respiratory conditions.

The pause impacts only LNG facilities being built to serve countries that do not have a free-trade agreement with the U.S., she noted. DOE must find that a facility shipping gas to non-free trade countries is in the “public interest” to approve it, and so far, it has yet to deny an application for any facility, Giannetti said.

“Put simply, DOE’s tools for assessing whether future gas exports are consistent with the public interest are both obsolete and inapplicable,” she added. “First, DOE has never published guidelines for evaluating the public interest for LNG exports. Never.”

The closest it came was a 1984 effort that sought to come up with rules for LNG imports, which do not work well for licensing export facilities four decades later, Giannetti said. DOE did do some studies on the economic impact of LNG exports in 2018, but they need to be updated too, she added.

The Industrial Energy Consumers of America (IECA) was not invited to testify, but it released comments saying LNG exports affect domestic prices, especially when storage is low. That coincides with demand peaks, which the IECA claims contributed to $84 billion and $53 billion in higher natural gas and electricity prices in 2022 compared to a year earlier.

“Accelerating volumes of LNG exports do have increasing impacts to reliability and prices of natural gas and electricity that are accentuated when inventories are low and during peak winter and summer demand,” said IECA President Paul Cicio. “The relationship is fundamental to the law of supply and demand. Low inventories result in high prices and high inventories result in low prices.”