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November 19, 2024

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Eversource Finds OSW Buyer, Takes $1.95B Hit for 2023

Eversource Energy has finalized its long-running attempt to sell off its offshore wind assets, but not soon enough to avoid a $1.95 billion impairment for 2023. 

If the moving pieces come together as planned, the New England utility will be done with the struggling offshore wind sector, though it will continue to lead onshore transmission infrastructure work for the projects underway in its joint venture with Ørsted. 

Eversource announced the sale to Global Infrastructure Partners (GIP) after the financial markets closed Feb. 13, along with its fourth-quarter and full-year financials. Its stock, which has been trading near a five-year low, closed 4.7% higher in heavier-than-average trading Feb. 14. 

Eversource also said it will begin to evaluate market interest for Aquarion Water, the sale of which would bring an infusion of cash without resorting to the equity market. 

The sale of the offshore wind interests and the water utility would refocus the company on natural gas and electric transmission and distribution, which now provide the vast majority of its earnings. 

The Ørsted-Eversource venture has not been a failure: The partners expect to finish the nation’s first utility-scale offshore wind farm — South Fork Wind — next month, have begun construction of Revolution Wind and are far along in planning for Sunrise Wind. But the effort has been much more costly than expected, causing billions in losses for both.  

Ørsted, the world’s leading offshore developer, is pushing forward with some cutbacks. (See Ørsted Exits Offshore Wind Markets, Remains Committed to US.) But Eversource, New England’s largest electric utility, decided over a year ago to jettison what was becoming an albatross around its neck. 

Piece by piece, it has made progress. Ørsted bought Eversource’s share of their as-yet-undeveloped seabed leases, and it agreed to buy Eversource’s share of Sunrise if New York state awards Sunrise a new, more lucrative offtake contract to replace the one initially awarded to the partners. 

In the latest development, GIP will buy Eversource’s share of South Fork and Revolution. Eversource expects to realize approximately $1.1 billion in cash proceeds from the deal but said that could be higher or lower because of factors including construction costs, tax credit eligibility and project delays. 

An 8-K filing by Eversource on Feb. 13 indicates that GIP is guaranteed a pretax equity internal rate of return of 13% for Revolution and South Fork upon the start of commercial operations; if it is less, Eversource will pay GIP the difference, and if it is more, GIP will pay Eversource. 

The transaction cannot close without federal and state approvals. 

In a call with financial analysts the morning of Feb. 14, Eversource CEO Joe Nolan immediately launched into discussion of the proposed sale. 

“When we started down this path in 2016, we were very excited for the opportunity to bring much needed renewable energy to our region,” he said. “Unfortunately, our offshore wind investment experienced difficulties as early-stage projects.” 

These problems — inflation, interest rates, shortage of material and dearth of specialized vessels — came to the fore in late 2022, after several projects off the Northeast coast already had locked in offtake contracts at fixed rates, thus rendering the projects financially untenable. 

Developers in Massachusetts, Connecticut, New York, New Jersey and Maryland canceled projects or put them on hiatus; canceled offtake contracts; and dissolved partnerships. Ørsted took over Public Service Enterprise Group’s share of a now defunct New Jersey project, while Equinor and BP have agreed to divvy up their proposed wind farms off New York and New England. 

If all the pieces come together for Eversource, it will be a chance to exit offshore wind and refocus on gas and electricity with its feet firmly on land. 

“Our core business is well positioned to deliver solid operational and financial results as we move forward in supporting the region’s transition to a cleaner energy environment,” Nolan said. “Moving forward, Eversource will focus on the delivery of clean, safe, reliable energy to our customers.” 

In another 8-K filing Wednesday, Eversource reported a net loss of $442 million for 2023, which compares with net income of $1.4 billion in 2022. That breaks down to a 2023 loss of $1.26/share and 2022 earnings of $4.05/share. 

As Nolan indicated, the onshore businesses performed well: Electric, gas and water distribution, and electric transmission generated earnings of $4.34/share, compared with $4.09 in 2022. 

But impairments totaled a loss of $5.60/share for 2023, all but 2 cents of it attributable to offshore wind. 

The pretax impairment for 2023 was $2.17 billion: $400 million for Sunrise and South Fork in the second quarter, $545 million for Revolution in the fourth quarter and $1.22 billion for Sunrise in the fourth quarter. 

A $215 million tax benefit brought the after-tax impairment down to $1.95 billion for 2023. 

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Entergy States Debut Long-range Tx Cost Allocation Proposal, MISO Members Unconvinced

Entergy regulatory staff have revealed their vision for cost allocation on future long-range transmission projects, with multiple clean energy groups deeming the proposal incompatible with building a grid that’s ready for the future.  

The Entergy Regional State Committee (ERSC) Working Group debuted a preferred cost allocation for the upcoming long-range transmission plan (LRTP) portfolio of projects that will focus on MISO South. At a Feb. 9 teleconference, the ERSC said it prefers a 90% allocation based largely on adjusted production cost savings and avoided reliability projects, with the other 10% assigned to new generation in MISO South using a flow-based methodology. 

The draft allocation proposal doesn’t include a postage stamp to load components. The ERSC said it wants costs allocated as specifically as possible based on cost causation and beneficiaries’ pay principles. It also said other benefit metrics should be “accurate, objective, measurable, quantifiable, nonduplicative, forward-looking and replicable.”  

The ERSC also said LRTP projects that are proposed “solely to meet” state or local clean energy policies should be paid for in full by those jurisdictions.  

Last year, MISO proposed using a blend of a 50% postage-stamp allocation to load and a 50% allocation to the local transmission zone for MISO South LRTP projects. The new allocation is meant for the third LRTP portfolio and will be used in place of the 100% postage stamp to load allocation MISO is using for the first two LRTP portfolios aimed at the Midwest.  

The ERSC has said it won’t support any postage-stamp aspect in MISO’s LRTP allocation and therefore opposes the 50/50 allocation split. (See Entergy Regulators Mount Challenge to MISO South Cost Allocation.)  

MISO Members Doubt Projects Under Allocation

Members of MISO’s environmental and consumer advocates sectors seemed skeptical the allocation would foster any meaningful transmission expansion in the South. 

Sustainable FERC Project attorney Lauren Azar said MISO’s LRTP is “decidedly not” a local planning exercise and that regional projects deserve a regional allocation. She urged the ERSC Working Group to get advice from experts and involve state commissioners in allocation design decisions.  

Azar said the MISO community should “beware of a wolf in sheep’s clothing,” referring to cost-allocation designs “under which no projects would actually qualify for funding” because they are too prescriptive and convoluted.  

Yvonne Cappel-Vickery, the clean energy organizer for the Alliance for Affordable Energy, said she was especially concerned about the South’s provision that transmission furthering decarbonization be billed to states or cities with targets. 

Cappel-Vickery said the ERSC’s draft allocation is hostile to known clean energy benefits. She cautioned the ERSC against pushing an allocation style that considers “too few benefits.”  

“There is an ever-growing body of evidence pointing to the need for new transmission,” Cappel-Vickery said.  

Attendees pointed to the U.S. Department of Energy’s National Transmission Needs Study, which found the Delta region requires more transfer capability, and a working paper released by the National Bureau of Economic Research that concluded that Entergy Arkansas and Entergy Louisiana brought in about $930 million in profit in 2022 because of transmission constraints in their territories. 

Multiple attendees questioned how the ERSC envisions realistically handling the 10% allocation to new MISO South generation. 

Southern Renewable Energy Association’s Andy Kowalczyk asked whether MISO South’s proposal will create a bifurcated generator interconnection queue, where MISO South generation projects receive different treatment to work in extra transmission costs.  

Organization of MISO States Executive Director Marcus Hawkins asked if there was the potential for allocation “leakage” among the queue, where generation projects that aren’t located in the South benefit from the lines and are assigned costs for South LRTP lines. 

Hawkins also asked how MISO South envisions handling “blended” transmission projects that further both reliability and decarbonization goals.  

Sustainable FERC Project’s Natalie McIntire asked how it’s possible for the South to tease out when exactly an LRTP line is intended only for clean energy targets when, by design, LRTP lines are designed to deliver multiple benefits simultaneously. 

The ERSC Working Group didn’t provide justifications for their proposal during the teleconference. ERSC Working Group representative and Public Utility Commission of Texas economist Werner Roth explained the proposal and said he collected stakeholders’ questions during the teleconference and will take them back to the Entergy Regional State Committee board so they can “make an informed decision on how to proceed.”  

Southern Renewable Energy Association’s Simon Mahan said MISO South should be proffering a cost-allocation method that not only works for the third LRTP portfolio, but also the fourth LRTP portfolio, which will zero in on how MISO can expand the transfer capability between its Midwest and South regions. He said working out an allocation that could serve both would save MISO South time, energy and money.  

Mahan said he didn’t think the ERSC’s proposed cost allocation would result in the projects that would best position the South to serve future energy needs. 

“We’ve been experiencing constraints in MISO South currently and for quite some time,” Mahan said. He added his fear is that South region members advance a futile cost allocation that deters transmission projects.   

Kowalczyk said there have been longstanding issues with energy delivery in MISO South that need to be addressed with regional transmission projects. 

“Load pockets are not making this any better. There have been load pockets that have been persistent for decades,” he said, adding that MISO South needs to proactively become the grid of the future and not rely on interconnection customers to build out the grid in a “piecemeal” fashion.   

Kowalczyk also questioned if it was fair to place more cost burdens on interconnection customers, pointing out that for the 2021 class of MISO South generation projects, developers already face network upgrade costs of about $100 million per project. 

Entergy’s Matt Brown said there are “serious data errors” in DOE’s Transmission Needs Study that seriously undercount Entergy’s transmission work in the Delta region. Brown said combined Entergy transmission investment represented in its FERC Form 1 is six to 12 times higher than what was represented in DOE’s investment data. He said DOE used project data from MAPSearch, which missed about $700 million worth of Entergy projects in the Delta region.  

Brown also said there will be “enormous complexity” in addressing MISO’s Midwest-South transfer constraint.  

“It’s important to underscore that it’s not a simple issue,” Brown said, emphasizing that the constraint isn’t physical, but contractual and agreed upon more than 10 years ago by SPP, Southern Co., TVA and other parties.  

Brown said MISO and the joint parties to the contract could renegotiate the contract to be able to flow more power because the system is capable of greater flows than currently allowed. The agreement with seven joint parties — including SPP — limits transfers between MISO Midwest and South to 3,000 MW southbound and 2,500 MW northbound. 

Brown didn’t address MISO members’ other concerns with the cost allocation proposal.  

MISO said it has reviewed ERSC’s draft proposal and listened to stakeholders’ opinions during the Feb. 9 teleconference. Spokesperson Brandon Morris said MISO could weigh in on the allocation plan during a Feb. 26 meeting of the ERSC board of directors.  

MISO did not address RTO Insider’s other questions on whether it might consider eliminating the postage-stamp piece of its own allocation proposal, where its allocation proposal stands today or whether it believes it can cleanly isolate clean energy policy projects for allocation purposes.  

Suspicion from Watchdog Organization

Daniel Tait, research and communications manager at the renewables watchdog organization Energy and Policy Institute, agreed the ERSC’s proposal won’t result in regional projects that can pass muster. 

In an interview with RTO Insider, Tait said the ERSC’s allocation proposal seems counterintuitive because Entergy’s own service territory includes New Orleans, which has an ambitious 100% clean energy standard by 2035 and a goal for complete carbon neutrality by 2050.  

Tait said there are “clear financial incentives” to Entergy continuing to advance “local, emergency projects that are basically exempt from any type of scrutiny except for state approval.”   

“The results speak for themselves,” he said, noting the lack of regional South projects to prevail in MISO’s planning process.  

Tait said Entergy sometimes can pull in “hundreds of millions of dollars” more in a gas plant’s return on equity than when compared to a new transmission line’s ROE.   

“Whether they want to admit it or not, shareholders are forcing the C-suite to make these kinds of decisions every time. This isn’t pennies we’re talking about,” Tait said. “Somebody has to check that. I understand why they’re doing that, but where are the other parties that are supposed to rein this in?”  

Tait said he would argue the existing system in MISO South was broken before the ERSC introduced the proposal. The MISO South grid is “severely debilitated” today, Tait said, and unable to host meaningful new generation, as evidenced by expensive network upgrade costs for developers wishing to interconnect in MISO South.  

“So, by definition, nothing is ever going to get built unless Entergy goes to its regulators and says, ‘We need this,’” Tait said. 

Tait likened the slim interconnection opportunity and sky-high network upgrade costs in the South to a neighborhood Walmart at full capacity with a line out the door. When a new shopper is allowed in, they’re charged something like $100 per tomato, he said.  

“That’s a crazy assertion that we would never see in any other marketplace. Now, that messiness coupled with this plan ensures [Entergy] can continue to do whatever they want,” Tait said.  

Tait said while the future MISO South grid is uncertain, if Entergy is allowed to have its way, MISO South won’t reach its full potential for solar installment. He predicted that when solar capacity is built, it will be owned and controlled by Entergy “because it, and only it, will have the ability to navigate all these roadblocks that it’s thrown up.”  

Tait also said DOE’s Transmission Needs Study represents a snapshot in time and that it’s not incumbent on DOE to track down every utility’s recently approved transmission. He said DOE is correct that transmission planning in the Delta has been paltry, even accounting for the additional $700 million in projects that Entergy has planned from its “white castle” and has claimed the department omitted from the study.  

Tait said the main takeaway from DOE’s study is that the Delta region’s transmission planning has been badly neglected in the past decade. 

“Entergy and Southern Co. cannot deny that number is awful,” he said. “MISO South is going to get left behind, and what I mean by that most directly is that as an Entergy customer in MISO South, you’re losing access to a whole host of affordable clean energy. … That should be a big deal to customers right now.”  

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SPP, MISO Clash over Crypto-strained M2M Flowgate

SPP, MISO and its Independent Market Monitor are at odds over how congestion should be managed on a market-to-market flowgate taxed by a cryptocurrency mining operation within SPP’s borders.

The three filed comments with FERC this week over whether the 230-kV Charlie Creek-Watford line in North Dakota should remain under M2M coordination, when congestion stemming from the 200-MW Atlas Power Data Center is costing MISO members millions. (See Crypto Load on MISO-SPP M2M Constraint Draws Complaint from Montana-Dakota Utilities.)

Montana-Dakota Utilities filed a complaint on the ongoing controversy in late January, arguing SPP should be found in breach of the grid operators’ joint operating agreement for unjustly taking M2M payments from MISO to manage local congestion. MISO and its IMM agreed the line’s M2M status should be lifted; SPP argued for the status quo (EL 24-61).

SPP contends there is no basis for Montana-Dakota Utilities’ complaint because the more than 3-year-old M2M flowgate is “clearly authorized” by the MISO-SPP joint operating agreement and other arrangements between it and MISO. It said an order for refunds would be illegal in this case, and it asked the commission to deny the complaint.

“Moreover, SPP and MISO are already discussing prospective enhancements to the removal provisions under the JOA’s dispute resolution process. SPP hopes that these discussions will successfully address the future operation of Flowgate 5717, while also avoiding near-term reliability risks and ensuring that similarly situated M2M-coordinated flowgates are treated comparably,” SPP said.

SPP said there’s no need for FERC to initiate hearing and settlement procedures or an alternative dispute resolution and that doing so could be “needlessly disruptive.”

SPP pushed back against Montana-Dakota’s claim that the flowgate is a local constraint, not a regional one. It said the constraint passed multiple eligibility studies before it was designated for M2M coordination.

“To the best of SPP’s knowledge, MISO has never objected to the results of the flowgate studies,” SPP said. The RTO also said it continues to believe M2M coordination on the flowgate is an “effective mechanism to manage congestion.”

SPP also said nothing in MISO and SPP’s agreements prohibits constraints from becoming M2M-coordinated flowgates just because they’re situated in a load pocket.

However, MISO Independent Market Monitor David Patton said the nature of the load addition means Charlie Creek shouldn’t be designated as an M2M flowgate.

Patton said while Charlie Creek technically passed the tests laid out in MISO and SPP’s congestion management process, the flowgate’s congestion now is local and is “not a regional issue that M2M coordination was intended to address.” He added that MISO, SPP and PJM in the past have agreed to remove flowgates from M2M procedures on a case-by-case basis when impacts are found to be local.

“[I]t is understood that this congestion is almost entirely managed by generation inside the [Williston load pocket (WLP)], almost none of which is operated by MISO. Likewise, MISO has no meaningful resources that can be used outside the WLP to provide relief on the Charlie Creek flowgate. These characteristics clearly indicate that the congestion on the Charlie Creek flowgate is local in nature and, as such, was never intended to be the type of flowgate that should be coordinated,” the Monitor argued.

MISO itself said negotiations with SPP over the flowgate effectively are at a stalemate. It said it is seeking immediate removal of Charlie Creek from joint congestion management and for SPP to return all associated M2M payments it made to SPP starting April 1, 2023. MISO said the “only practical result of the M2M coordination on that flowgate is an unjustified financial subsidy to SPP from MISO customers.”

MISO told FERC it objects to “SPP’s improper application of the M2M coordination protocol” on the Charlie Creek line. But it said it remains unable to remove Charlie Creek from M2M coordination, even after engaging in negotiations with SPP pursuant to their formal dispute resolution rules.

The MISO-SPP JOA allows the RTOs to cease M2M congestion management on flowgates when the process isn’t effective at curbing congestion. However, both MISO and SPP must consent to striking the flowgate from congestion coordination before it can be terminated.

MISO said it has repeatedly requested that SPP agree to eliminate the M2M designation on the line, but SPP “steadfastly refused, turning the consent requirement into a veto.”

MISO asked FERC to take swift action to “stop the unjustified flow of M2M payments” and direct it and SPP to draft revisions to their M2M coordination procedures to avoid similar situations in the future. It asked that FERC fast track Montana-Dakota Utilities’ complaint, given that its M2M payments to SPP are likely to rise when lower, summer ratings are applied to the line beginning in April.

MISO said it was well known that the Williston load pocket had longstanding congestion issues and said the recent load addition means its resources can offer near-zero relief.

“When SPP added a significant new load, the Atlas Power Data Center, to the WLP in early 2023, it exacerbated the existing constraints while neither SPP nor MISO have sufficient generation in the area to relieve those constraints. In other words, there is no economic M2M coordination solution that the RTOs may provide through redispatch to alleviate congestion,” MISO explained.

MISO argued that SPP acknowledged the load pocket’s issues in its 2021 Integrated Transmission Planning Report prior to the cryptocurrency mining facility’s operation. In the 2021 report, SPP said “the root of the issues in the [Williston load pocket] is the lack of transmission to accommodate the level of transfers required to serve the forecasted load in the future, contributing to a weak system unable to maintain acceptable voltage levels.”

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Consumer Collective Again Asks FERC to Strike ROFR Laws from MISO Planning

An alliance of consumer groups has asked FERC to address its 2022 joint complaint against MISO’s practice of deferring to state right of first refusal (ROFR) laws in its regional transmission planning.

The alliance — which includes the Industrial Energy Consumers of America, the Coalition of MISO Transmission Customers and others — said “despite the significant rate impact on consumers, the commission has not ruled on the complaint” (EL22-78).

In the summer of 2022, the consumer alliance asked FERC to block MISO and other RTOs from applying “anticompetitive” state ROFR laws to their regional transmission planning and cost allocation processes. The group said MISO shouldn’t hamstring itself by maintaining tariff provisions that prohibit it from holding a competitive solicitation for regionally cost allocated projects. It also argued that state-level ROFRs interfere with FERC’s “exclusive jurisdiction to set just and reasonable rates for transmission in interstate commerce.” (See Consumer Groups File FERC Complaint Against MISO.)

Now the alliance has said FERC’s inaction has allowed uncertainty to fester, as evidenced by MISO asking an Iowa court to lift an injunction against some of its long-range transmission plan (LRTP) after Iowa’s ROFR was deemed unconstitutional. (See MISO Asks Court for Injunction Reversal on Iowa LRTP Projects.) The group said MISO’s argument that FERC alone has the power to oversee any change in developers coincides with its complaint that FERC should be able to override state-level ROFRs in transmission planning.

The consumer alliance said the litigation and delay among the Iowa LRTP projects are a “concrete example” that it’s unreasonable for MISO to continue to yield to state ROFRs.

“The ROFR law exception in MISO’s tariff — as played out in the state of Iowa — has hampered MISO’s ability to select the more efficient or cost-effective developer in a timely manner or to effectively facilitate transmission development subject to the commission’s exclusive jurisdiction. And now MISO asserts that its determination to skip competition cannot be undone by a state court ruling that the law was unconstitutional from the inception,” the alliance argued.

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Duke Energy Projects Higher Earnings, Load Growth in 2024

Duke Energy has upped its forecast for growth across its territories, driven by migration, economic development and government funds, the company said during a Feb. 8 call to report its year-end earnings.

The company is entering the year with “significant momentum,” CEO Lynn Good said. For the first time in decades, Duke is beginning the year as a fully regulated utility following the July sale of its last renewables business. (See Duke Energy Sells Distributed Renewable Business to ArcLight.)

With this regulatory “transformation,” Good said, the company is “poised to deliver on [its] simplified, 100% regulated growth plan.”

Duke Energy’s Service Territory | Duke Energy

Duke’s long-term load growth projections increased to 1.5-2%, CFO Brian Savoy said. This growth is underpinned by economic development projects coming online, strong residential growth and a post-COVID trend of customers returning to their offices. “Those three factors give us confidence that 2% load growth in ’24 is definitely in our sights,” Savoy said.

Duke Energy’s third-quarter earnings call projected load growth of 0.5-1%. (See Duke Earnings Slip on Low Demand, but Long-term Growth Expected.)

To keep up, Good said a “record infrastructure build” is ongoing across Duke’s fastest-growing jurisdictions.

In Florida, where the number of customers grew 2% from 2022 to 2023, 300 MW of solar additions are under construction, with expectations of 1.5 GW of in-service solar in the state by 2025.

In the Carolinas, which grew by 2.1%, annual solar procurement targets of over 1 GW are in place. Duke plans to file Certificates of Public Convenience and Necessity for 2 GW of natural gas generation in North Carolina this year as well. Growth in the Carolinas is outpacing the forecast from August’s resource plan, Good said, leading the utility to file supplemental plans in January.

Duke added 195,000 customers in 2023 across all jurisdictions, Savoy said.

Nuclear PTCs

2024 marks the first year Duke can claim the nuclear production tax credits (PTCs) implemented under the Inflation Reduction Act. Savoy said the utility expects to claim several hundred million dollars of the credits.

These benefits will be amortized over four years, reducing customers’ electric bills during that time, Savoy added.

Financials

Adjusted earnings per share were $5.56, compared with $5.27 at the end of 2022, a growth rate of about 6%. This growth came primarily from rate case outcomes, multiyear rate plans and rider growth across the utility’s territory.

The utility projected yearly growth of another 6-7%, to a range of $5.85-$6.10. This is expected to be driven primarily by electric utilities and infrastructure, particularly North Carolina’s “historic” base case, Savoy said. Updated rates in Kentucky and expected updated rates in South Carolina also will drive this growth, he added.

This growth will be offset by the utility’s average tax rate, which sits at 10% but is expected to increase to 12-14%, as well as “depreciation and property taxes on a growing asset base,” Savoy said.

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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.