Noting “disruption often presents opportunity at NextEra Energy,” CEO John Ketchum said Jan. 25 the company relied on 25 years of experience with renewable energy to navigate “clear headwinds for renewables” over the past two years.
Ketchum told financial analysts during NextEra’s quarterly earnings call that its competitive, clean energy business, NextEra Resources, had its best year yet by adding about 9 GW of new renewable and storage origination to a backlog that now exceeds 20 GW. About 5.6 GW of renewables and storage were commissioned during the year, NextEra said.
“We successfully managed through the disruption,” Ketchum said. “We believe that the disruption over the last two years has made NextEra Energy an even stronger company. Our business model is more resilient. Our development platform is even more advanced, and our supply chain is more diversified than it has ever been.”
Ketchum noted inflation and inflation rates have declined from their peaks, solar suppliers have been provided with more certainty around rules for imports and new solar supply chains have led to lower panel costs that have declined by about 25% from their peak over the past 24 months.
“Ultimately, all these tailwinds are great for customers, and we believe that should drive greater renewables demand in 2024 and beyond,” he said.
NextEra reported year-end earnings of $7.31 billion ($3.60/share), up from $4.15 billion ($2.10/share) the year before. Fourth-quarter earnings were $1.21 billion ($0.59/share), compared to $1.52 billion ($0.76/share) for the same quarter in 2022.
Ketchum expressed frustration with NextEra’s stock performance this year. The company’s share price closed at $57.98 Jan. 25, down $4.94 from a Jan. 8 peak of $62.92.
“We recognize and are disappointed by the underperformance in the share price, and as we start 2024, we remain steadfast in our continued focus on execution and creating long term value,” Ketchum said. “Bottom line, we believe NextEra Energy is well positioned headed in the 2024.”
Xcel: Coal Closures to Continue
Xcel Energy also reported year-end and fourth-quarter earnings Jan. 25. Annual earnings were $1.77 billion ($3.21/share), compared with $1.74 billion ($3.17/share) for the same period a year ago.
For the quarter, earnings were $409 million ($0.74/share), compared with $379 million ($0.69/share) during the same quarter in 2022. Xcel reaffirmed its 2024 EPS guidance of $3.50-$3.60.
CEO Bob Franzel told financial analysts that the retirement in December of the first of three coal-fired units at the Sherburne County Generating Station (Sherco) sets the stage to retire all of its coal plants by 2030. Sherco’s other two units are targeted for closure in 2026 and 2030. (See Xcel Says Coal Retirements on Track Despite South Dakota PUC’s Plea for Extensions.)
“This is a milestone as we work to exit coal by 2030 and another sign that we’re leading the nation’s clean energy transition,” Franzel told financial analysts.
Xcel plans to replace the units with 2.1 GW of wind and 2.5 GW of solar with what it says will be the largest solar facility in the Midwest.
The company’s share price closed at $58.89, up 67 cents on the day. Xcel opened the year at $63.47.
CARMEL, Ind. — MISO’s Planning Subcommittee this year will tackle possible modifications to the RTO’s expedited project review process, which allows transmission developers to begin construction earlier than MISO’s annual approval process usually allows.
The RTO’s Planning Advisory Committee on Wednesday voted to allow the subcommittee to begin deliberations in March on a new schedule for the study process to better manage the increasing number of requests.
At a Jan. 24 PAC meeting, expansion planning engineer Amanda Schiro said expedited requests until recently have been few enough not to burden MISO resources.
“However, in the past three years, we have seen large load additions that increase the volume and complexity of expedited requests,” Schiro said, adding that requests often are driven by “spot load growth,” such as data centers.
Schiro said the expedited requests and their “isolated processes” are causing a “strain” on MISO’s planning staff to study all expedited requests alongside the RTO’s annual Transmission Expansion Plan (MTEP).
Schiro said MISO held 17 meetings over 2023 to review individual projects and the RTO needs to reduce the frequency of meetings. She said MISO might contain project submission times and introduce a timeline to accomplish a more streamlined process.
“We’d like to reduce that number both for us and our stakeholders,” she said.
Schiro said when conducting outreach on the issue, stakeholders urged MISO to keep the “valuable” expedited process. She said MISO has no plans to discontinue expedited reviews.
However, the Union of Concerned Scientists’ Sam Gomberg said he thought MISO’s plan to focus only on the expedited review timeline “misses an opportunity” for the RTO to plan for load additions more proactively.
Under the existing process, MISO conducts individual studies on expedited requests to confirm the projects won’t result in reliability violations before allowing them to proceed ahead of the usual MTEP cycle.
Stakeholders have suggested MISO enact voltage or cost thresholds so small projects don’t have to go through an expedited project review.
Generally, projects must rate at least 100 kV or cost at least $1 million to be considered candidates under MTEP and compelled to apply for expedited treatment when necessary.
This month, MISO analyzed an expedited need from Jonesboro City Water and Light, which proposed an $874,000 rebuild of a 69-kV line in northeastern Arkansas due to state Department of Transportation work. Some stakeholders at a Jan. 16 South Technical Study Task Force questioned whether MISO should have devoted time to examining such a small project.
NATIONAL HARBOR, Md. — The demand response business has changed so much in recent years that the term has fallen out of favor for “virtual power plants” (VPPs), and the trend is only going to continue as residential customers adopt more distributed energy resources.
The only thing aggregators like LS Power subsidiary CPower used to deal with was actual customer demand, CEO Michael Smith said in an interview on the sidelines of an event his company hosted on Jan. 23.
“Now we have on-site solar and storage,” Smith said. “Now we have a lot of backup generation fuel cells. We have interruptible computing loads, so we talked about data centers, or Bitcoin mining, that can change their load profile and actually change their operations. So, all of these things give us more tools in the toolbox. At the same time, the needs of the grid have become more complex.”
With residential customers getting more involved in the electric grid with the adoption of electric cars, distributed solar and batteries, and smart appliances, that shift is only going to accelerate.
“I think that the overall residential market just in terms of gigawatt-hours is going to be larger than the C&I [commercial and industrial] market, if you think about water, heaters, AC, that kind of thing,” Smith said. “But getting to it is a challenge; it’s a data challenge. But it’s also a controls challenge that has to be highly, highly automated.”
Many of the large C&I customers that CPower serves trim their demand at least in part by having an employee flip a switch, but residential customers need to have that process, Smith said.
That looming change has caught the attention of the U.S. Department of Energy, which is increasingly focused on helping VPPs roll out across the country, said Loan Programs Office Senior Adviser Jennifer Downing (no relation to reporter), who wrote the department’s “Pathways to Commercial Liftoff” report for the technology. (See DOE Report Lays out Commercialization Path for VPPs.)
“Well, a big reason why now is that we are about to experience a tsunami of DER adoption,” Downing said in public remarks. “And that’s true across three categories of DERs.”
Generation DERs like solar; flexible loads like smart thermostats and water heaters; and distributed batteries are all rolling out over the next decade with almost 25 GWh of capacity by 2030, she said, which pales in comparison to the amount of new load from electric vehicles over the same time period that will add hundreds of megawatts of batteries to be served by the grid. Not all the EVs will be plugged in at once, and often they will be unable to shift when they charge.
“But if even a fraction of this capacity is available to virtual power plants to help balance supply and demand of the grid, that’s an enormous potential,” Downing said.
The ability to orchestrate when some of those cars are charged will be key to supplying them with power reliably and affordably, and VPPs can make that happen, Smith said.
All the changes going on now are transforming the grid, which has generally operated the same way it has since the days of Thomas Edison and Nikola Tesla, she said.
“But now with increased distributed generation, we’re finally changing the physicality [of] the grid, which is what we’re experiencing right now,” she added. “So, it’s a balance: We’re always going to have central station generation, [but] we’re going to have less of it relative to the overall kind of load demand needs of the grid. More of that demand will be satisfied via on-site generation.”
Solar is the main agent of change, but storage and fuel cells and other technologies will also play a part. That change is going to impact how much transmission and distribution grids are operated, Smith said.
FERC Order 2222
FERC Order 2222 was meant to set the stage for that transition, and while it does represent a major step forward, Smith and other CPower executives at a media briefing said that its implementation has fallen short of what the VPP industry would have liked. The implementation was dogged by questions about cost and jurisdiction, said Kenneth Schisler, CPower senior vice president of regulatory and government affairs.
“But it was a very positive step in the right direction,” Schisler said. “So, let’s recognize that regulation gets to where it needs to be over a period of time. I think we have to acknowledge that even in the markets where we’re not as happy with the result of the implementation of Order 2222, it’s a positive step in the next direction.”
FERC left a lot of discretion on the details up to the ISO/RTOs and their utilities, which has led to uneven implementation and will likely require a follow-up “Order 2223,” he added.
No regulator or politician is going to be able to stop the tidal wave of DERs that Downing spoke of, and that transition would be better served by having them play well with the wholesale markets, Schisler said.
“The question is, do you want these resources operating in the underbrush?” Schisler said. “Or do you want them aggregated where you have visibility and a level of control, and you can begin to model and plan around their expected behaviors? And that’s, I think, where we have a very positive contribution to make.”
NYISO is the only organized market that has changed its participation model, with all the others using the old DR participation model that does not reflect the major changes the industry has seen in recent years, he added.
One common issue with ISO/RTOs is they still tend to plan around large, central-station power plants, said CPower Senior Director Aaron Breidenbaugh.
“If the only tool you have is a hammer, every problem looks like a nail, and to them every problem looks like a 500-MW power plant,” he added. “So, of course, you have to have six-second telemetry. So, of course, it has to be nodally located, or it’s going to completely screw up the price. Of course, it has to be individually metered.”
While FERC has some work left to do on VPPs and DER integration, the bulk of the activity is going to happen at the state level, where regulators have primary jurisdiction over the distribution system, Schisler said. State laws are helping to drive increased adoption of DERs, and even once skeptical states have started to embrace the role aggregators like CPower can play in coordinating those new resources.
FERC Order 719 required ISO/RTOs to remove barriers to DR, but it also let states opt out of letting their customers participate in wholesale markets as DR. That was included in the 2008 order because some states felt that DR could be a backdoor way into federally mandated retail competition, Schisler said.
The commission could end that opt-out now after some recent court findings; it has a pending complaint before it asking it to do so (EL21-12), while U.S. Rep Sean Casten (D-Ill.) has introduced legislation requiring that step. But Schisler argued that the issue should not be forced onto states.
“I think the opt-out is not constructive, and I would prefer it not be there; taking it away is a different proposition,” he added. “And our approach has been to work with states in the Midwest, and we’ve enjoyed a fair amount of success in the last year. We’re seeing great progress and in states like Michigan, Missouri and Indiana.”
Missouri especially was a landmark case in part because it never even considered endorsing retail competition, but now it has opened to third-party aggregators like CPower. It is also split between multiple wholesale markets.
“If a state like Missouri that has figured out a model to make it work, you know, I think other states will follow suit,” Schisler said.
The Biden administration is planning to delay its decision on approval of a major LNG export terminal in order to evaluate the project’s climate impacts, The New York Timesreported.
The delay could extend through the elections in November and could affect 16 other proposed export terminals, the Times reported, citing three unnamed sources. [Editor’s Note: The Department of Energy announced the delay on Jan. 26.]
The decision comes on the heels of an extended pressure campaign from climate activists to stop the projects, with focused opposition on the Calcasieu Pass 2 (CP2) project in Louisiana. If approved, CP2 would be the largest LNG export terminal in the country, with a capacity of about 20 million tons of natural gas per year.
CP2 needs to be first approved by FERC, which evaluates projects’ direct environmental impacts, before it moves to the Department of Energy, which decides whether the export of the fuel is in the public interest, which includes the consideration of upstream and downstream GHG emissions.
But those evaluations do not include any estimate of those emissions’ cumulative impact on climate change. The Times reported that the White House has asked DOE to analyze that, as well as the project’s impact on the economy and national security.
CP2 would essentially be an expansion of an existing export terminal in Cameron Parish, La. FERC approved the first terminal in May 2019, though not without debate among the commissioners over the climate issue. Former Commissioner Richard Glick (D) insisted that FERC had been directed by the D.C. Circuit Court of Appeals to evaluate proposed gas projects’ impacts on climate change, and he dissented on the approval. (See Glick Disputes FERC ‘Breakthrough’ on LNG Projects.) The commission had reached a compromise in which it quantified the upstream and downstream emissions but made no determination as to their impact on climate change.
FERC has continued to insist it cannot “determine credibly whether the reasonably foreseeable GHG emissions associated with a project are significant or not significant in terms of their impact on global climate change”; Commissioner Allison Clements (D) has continued to disagree. (See related story, FERC Approves Pipeline to Supply New TVA Cumberland Gas Plant.)
Climate activist and author Bill McKibben, one of the project’s leading opponents, called the delay “the biggest thing a U.S. president has ever done to stand up to the fossil fuel industry.”
A December letter to the Biden administration signed by 170 scientists said the current queue of LNG export terminals “could lead to 3.9 billion tons of greenhouse gas emissions annually, which is larger than the entire annual emissions of the European Union.”
The letter cited preliminary research from climate scientist Robert Howarth of Cornell University that found lifecycle carbon emissions of LNG are between 24 and 274% higher than coal.
While scientists and climate activists have applauded the decision, it has been met with outcry from the fossil fuel industry. The American Petroleum Institute reposted an opinion from The Wall Street Journal Editorial Board arguing that the delay “won’t reduce global emissions” but “would be a gift to America’s adversaries and show Europe that the U.S. isn’t a reliable ally.”
Senate Minority Leader Mitch McConnell (R-Ky.) called the delay “a functional ban on new LNG export permits,” adding that the administration’s “deference to climate extremists continues to sell out American consumers and U.S. allies.”
A report from ClearView Energy Partners noted that the climate review requirement seems likely to extend to all 17 proposed LNG export projects, although this has yet to be announced. ClearView added that the delay is unlikely to be well received by the U.S.’ European allies, who have relied on LNG exports amid Russia’s invasion of Ukraine.
“If a pause is in the offing, the issue would seem more a political matter than an economic or diplomatic one — that is, mobilizing young, climate-focused voters who could make a difference in closely contested ‘swing’ states,” ClearView said.
According to the Times’ report, the White House is unconcerned about CP2’s contribution specifically, as the U.S. is already exporting so much gas.
A new report from Friends of the Earth, Public Citizen and BailoutWatch pushed back on the narrative that increased LNG exports are needed to support European allies.
“Contracts with European customers represent the smallest share (18%) from pending LNG facilities,” the report found. “Contracts with Asia Pacific customers account for 30% of total volume, with the remaining 52% going to commodity firms and other portfolio buyers.”
The report also said Europe is on track to reduce gas consumption in half by 2030 compared to 2019 levels and concluded that “long-term infrastructure is a poor solution to short-term supply needs.”
Ultimately, the outcome of the pending projects may hinge on the results of the 2024 election. The two remaining Republican contenders, former President Donald Trump and former Ambassador to the U.N. Nikki Haley, have both expressed strong support for increasing domestic fossil fuel production.
“We will export as much liquefied natural gas as we can,” Haley told a New Hampshire crowd in the days leading up to the state’s primary Jan. 23. Shortly after, she was interrupted by several climate activists who criticized her for taking money from the fossil fuel industry.
The impasse over the ERO’s latest cold weather standard has ended, with EOP-012-2 (Extreme cold weather preparedness and operations) finally receiving enough votes from industry stakeholders this week to pass its third formal comment and ballot period.
The standard went before industry Jan. 16, with voting wrapping up Jan. 22. It received 205 votes in favor and 30 against, for a segment-weighted value of 81% for passage. Fifty-six respondents either abstained or cast no vote.
The commission ordered NERC to file the standard within a year when it approved the predecessor, EOP-012-1,last February, citing shortcomings in the standard including “undefined terms, broad limitations, exceptions and exemptions, and prolonged compliance periods.”
NERC’s Board of Trustees will now consider the standard for approval and submission to FERC. A spokesperson for NERC confirmed that the standard will be on the agenda for next month’s board meeting in Houston.
The positive result means the board will not have to exercise its authority under section 321 of NERC’s Rules of Procedure to approve a standard without a successful ballot. Board Chair Ken DeFontes warned at the board’s last meeting in December that such action might be necessary to meet FERC’s deadline. (See NERC Board May Force Action on Cold Weather Standard.)
Voters Focus on Clarity
The margin for EOP-012-2 marks a significant turnaround from the standard’s last ballot round, which closed Nov. 30 with a 58% weighted vote in favor of passage. An earlier vote fared even worse, with only a 44% segment-weighted vote for approval.
Comments from participants in the most recent ballot round indicated that most stakeholders had come around on the standard. Martin Sidor with NRG Energy said the standard drafting team’s most recent changes would “generally address the issues raised by industry” in previous rounds. Edison Electric Institute said the standard “provides sufficient clarity to allow EOP-012-2 to be auditable.”
However, ACES Power disagreed, casting one of the few votes against the standard. The energy management company’s comment, which was endorsed by several other participants, expressed “grave concerns” with the proposed standard’s definition of “generator cold weather constraint.”
The standard defined the term as “a limitation that would prohibit a generator owner from implementing freeze protection measures” in at least one generator component. ACES took issue with the standard’s use of the word “reasonable,” warning that such a vague word could “lead to inconsistent application throughout the … regions.” Other unclear words and phrases cited by ACES included “broadly implemented” and “areas that experience similar winter climate conditions.”
Donald Lock of Talen Generation cast another “no” vote, similarly fearing that the wording of the standard was not sufficiently clear. As an example, he noted that the expression “reasonable cost consistent with good business practices” could be interpreted to deem “all existing plants to be acceptable since they were winterized per the … business practices of the owner.”
Lock suggested that “rather than continue to adjust semantics,” NERC should make winterization criteria for new facilities “explicit” — with a list that is actively updated as technology progresses — while urging FERC to allow owners of existing plants to be reimbursed for upgrades. He said the ERO should limit mandatory actions for existing facilities, to include identifying conditions under which forced outages and derates may occur.
“Above all else, good business practices require that winterization capabilities … must be done right the first time, nor should the goalposts move about over the years,” Lock said.
The New Jersey Board of Public Utilities awarded contracts to a new set of offshore wind proposals Jan. 24 (Docket No. Q022080481).
The Leading Light Wind and Attentive Energy Two projects would total 3,742 MW of capacity. The contract awards are a shot in the arm for the Garden State’s highest-in-the-nation offshore wind goals after Ørsted canceled the Ocean Wind projects in late 2023.
However, the bounceback will not be immediate.
The new projects are not expected to come online until 2031 and 2032. Ocean Wind 1 had already begun onshore construction, planned to start offshore construction this year and had projected completion in 2025.
Also, Ocean Wind 1 was a mature project, with a stack of approvals in hand including the all-important green light from the U.S. Bureau of Ocean Energy Management.
Attentive Energy Two (1,342 MW) and Leading Light (two phases of 1,200 MW each) must now navigate extensive local, state and federal review processes before beginning construction.
They must also avoid the financial and supply chain pressures that doomed the Ocean Wind projects — but many analysts expect those constraints to ease significantly for the U.S. offshore wind industry in the next few years.
In fact, the Attentive and Leading Light projects themselves will help ease the supply chain crunch, as both development teams have committed to expand New Jersey’s new offshore wind manufacturing and operations facilities, including fabrication of towers and monopile foundations.
In one example, EEW is expected to produce more and larger monopiles in-state because of this commitment.
New Jersey officials said Jan. 24 that the projects will result in a guaranteed direct impact of 5,218 job-years and $2.5 billion in spending. Adding indirect and induced jobs and spending, the impact rises to an estimated 27,103 job-years and $6.8 billion.
Ambitious Goals
New Jersey Gov. Phil Murphy (D) set a goal of 3,500 MW of offshore wind in 2018, then bumped it up to 7,500 MW in 2019 and 11,000 MW in 2022.
The state’s first solicitation yielded Ocean Wind 1 (1,100 MW). The second yielded Atlantic Shores Offshore Wind (1,510 MW) and Ocean Wind 2 (1,148 MW).
The third solicitation drew interest from four developers: Atlantic Shores, Attentive, Community Offshore Wind and Leading Light; Community subsequently withdrew its bid.
An expedited fourth solicitation is underway, with contract awards expected to be announced in the first half of this year.
Cancellation of Ocean Wind 1 and 2 was announced on Halloween 2023 — a nasty trick for those who had expended political capital on behalf of the projects and a delightful treat for the many opponents of offshore wind in New Jersey.
Opposition to offshore wind has been particularly vocal along the Jersey Shore, due to cost, environmental impact and visibility from popular beaches. On this last point, Leading Light and Attentive would be more than 40 and 47 miles from land respectively at their nearest point, and all but impossible to see from shore.
Those opposed to offshore wind due to its cost will have the following numbers to work with:
Leading Light Wind offered a first-year price of $112.50/MWh for offshore renewable energy credits (OREC). That works out to a 20-year levelized OREC price of $139.53 and a 20-year levelized net cost of $70.05 once revenue credits and avoided costs are factored in. Average monthly cost to ratepayers (in 2023 dollars) is estimated at $3.71 residential, $31.86 commercial and $278.42 for industrial.
Attentive offered a first-year price OREC price of $131, a 20-year levelized OREC price of $165.14 and a levelized net cost of $96.75. Average monthly cost to ratepayers is estimated at $3.13 for residential, $26.87 for commercial and $234.80 for industrial.
For comparison, the Ocean Wind 1 contract award (Docket No. Q018121289) in 2019 specified a first-year OREC price of $98.10, a levelized 20-year price of $116.82 and a levelized net cost of $46.46. Estimated monthly ratepayer impacts (in 2019 dollars) were $1.46 residential, $13.05 commercial and $110.10 industrial.
A reporter asked BPU senior scientist Kira Lawrence on Jan. 24 why Attentive Energy Two’s ORECs would be noticeably more expensive than Leading Light’s.
“There is an economy of scale associated with the Leading Light Project,” she replied. “It’s a 2,400-MW project, so there are a number of economies of scale that can be achieved with a larger project size. Attentive is a 1,342-MW project.”
The reporter did not ask about the contract that Attentive is now negotiating with New York for the proposed Attentive Energy One in another portion of the same lease area off the New Jersey coast. Its capacity would be 1,400 MW, presumably creating some economies of scale.
Kate Klinger, a senior member of Murphy’s staff, added that bids were evaluated for not just cost but their holistic benefit to the community. “Some of what is included in that pricing is direct support for offshore wind supply chain facilities, for workforce development, benefits that will be felt directly in communities in New Jersey as well.”
Leading Light is a joint venture of Invenergy and energyRE. It said Jan. 24 it was reviewing the BPU order and looking forward to working with New Jersey to advance its clean energy transition.
Attentive Energy Two is a joint venture of TotalEnergies and Corio.
Mixed Reaction
The abrupt cancellation of Ocean Wind 1 and 2 — even after a financial concession by the state and even amid preparatory work by the developer — was a bitter setback for state leaders and offshore wind proponents. (See Ørsted Cancels Ocean Wind, Suspends Skipjack.)
New Jersey Board of Public Utilities President Christine Guhl-Sadovy | NJ BPU
BPU President Christine Guhl-Sadovy alluded to Jan. 24 before the board’s unanimous vote in favor of the two contracts.
“In spite of some setbacks,” she said, “we’re on track. If anything, this solicitation award shows that we’re moving full steam ahead. These two projects will help cement New Jersey’s position as an offshore wind leader and bring the clean energy and economic benefits to our state that have been such a critical part of Gov. Murphy’s agenda.”
Commissioner Zenon Christodoulou went a step further, warning the developers that the BPU would not let the state get skunked again, promising “fanatical, even tyrannical oversight” of progress, if necessary.
“The contracts we are awarding are tight and hold the awardees accountable to our production schedules and pricing schemes,” he said. “We will enforce those guarantees with relentless oversight and unwavering defense of our ratepayers. There will be no hat-in-hand requests, no unforeseen expenses, no nickel-and-diming.”
Clean energy groups greeted Jan 24’s’s action warmly.
New Jersey Board of Public Utilities Commissioner Zenon Christodoulou | NJ BPU
Oceantic Network CEO Liz Burdock said: “New Jersey reasserts its leadership in the U.S. offshore wind sector with today’s 3.7-GW commitment and securing new supply chain investments in towers, foundations, and secondary steel manufacturing. The U.S. offshore wind market is entering a new phase of development; today’s action capitalizes the state’s early investments in a coordinated transmission system, the New Jersey Wind Port, and the EEW monopile facility to accelerate development and position the state at the center of the nation’s supply chain.”
Anne Reynolds, vice president for offshore wind at American Clean Power, said: “Today is a key step towards achieving the state’s goal of a 100% clean energy economy by 2035. Offshore wind will bring huge economic benefits to the state and region, creating jobs and new investment opportunities for manufacturing companies and suppliers to support the necessary infrastructure needed for this new and growing industry. It is also a significant commitment to developing the New Jersey Wind Port which will generate up to $500 million in new economic activity annually for the Garden State.”
Advanced Energy United Managing Director Nathan Willcox said: “Today’s awards set the stage for a vibrant offshore wind future in New Jersey. Offshore wind is critical to growing New Jersey’s economy, hitting our clean energy goals and improving grid reliability, and we are eager to see these projects move forward.”
Support was far from universal, however.
SaveLBI, a Jersey Shore activist group that sued the federal government in an attempt to block Ocean Wind, picked apart the BPU decision in a series of social media posts.
“A bad day indeed,” it said.
U.S. Rep. Jeff Van Drew (R-N.J.) said on X: “Today, NJBPU unanimously approved two new offshore wind projects despite overwhelming disapproval from New Jerseyans. The Murphy admin has once again ignored the will of the people in order to line the pockets of offshore wind companies at the cost of NJ ratepayers.”
On the Facebook page of Protect Our Coast, commentary on the news ranged from snark to dismay to anger, and suggested strongly that placing the turbines out of sight beyond the horizon would not mollify most opponents. “WTF. THEY WANT WAR,” one said.
Texas regulators have remanded back to ERCOT a controversial protocol change attempting to regulate energy storage resources, but not before stripping out language related to state of charge (SOC) and enforcement processes.
The unanimous decision during the Public Utility Commission’s Jan. 18 open meeting is a victory, albeit temporary, for the energy storage sector, which has been battling the proposed change since last summer. As written, nodal protocol revision request (NPRR1186) sets a one-hour SOC for energy storage resources participating in two ancillary services (ERCOT contingency reserve service and non-spinning reserve). It also includes penalties of up to $25,000 per violation. (See “PUC Delays Approval of Rule Change that Penalizes Storage Resources,” Texas Public Utility Commission Briefs: Nov. 30, 2023.)
Storage developers say the new rules hold energy storage resources (ESRs) to higher standards than conventional thermal resources and could result in fines if batteries fall below SOC thresholds and still deliver the power promised.
ERCOT staff filed a report before the meeting trying to address questions raised by the PUC in November. It said with ESR capacity projected to grow from 4.4 GW to more than 20 GW by 2026, the rules are necessary to preserve reliability. The data presented showed similar failure rates for ESRs and for thermal resources involved in the ancillary service markets (54445).
Commissioner Jimmy Glotfelty, who has declared the rule change to be “discriminatory” to energy storage, was not swayed.
“They all fail. Singling out ancillary services providers of battery storage is discriminatory. Gas plants fail. Nuclear plants fail. Coal plants fail,” he said. “That’s why we over-procure ancillary services. I just cannot pass something that puts a compliance penalty on a type of service when the data from ERCOT shows that dispatchable resources fail in the same types of services.”
“It really is a big deal from a liability perspective to make sure that those ancillary services can provide the products that we need for the duration that we need them to,” Dan Woodfin, ERCOT’s vice president of system operations, told the PUC.
Commissioner Lori Cobos said ERCOT should withdraw or table NPRR1209, a directive from the Board of Directors as NPRR1186 ran into trouble. ERCOT staff said Jan. 24 the rule change was tabled in November within the stakeholder process to allow the commission to work out its issues with 1186, which also was a board priority item.
Both measures are seen as stopgaps until ERCOT deploys real-time co-optimization, currently targeted for the latter half of 2026.
The ERCOT board now will take up 1186 and the PUC’s changes for approval before they get sent back to the commission for a final review and vote.
The open meeting took place the day before Thomas Gleeson was appointed as the PUC’s chair. Gleeson was formally sworn in Jan. 23. (See Abbott Names PUC Executive Director as Chair.)
VoLL Study to Begin
The Brattle Group will open a value-of-lost load (VoLL) survey of ERCOT retail customers in March. The results will be reported back to the PUC in August as part of the grid operator’s effort to quantify VoLL (55837).
ERCOT is analyzing the frequency of load shed, but also its magnitude and duration, with an expected unserved energy metric. According to a staff filing, every 1% improvement in a plant’s weatherization reduces the needed for 175 MW of capacity.
The commission also requested comment on DC ties, such as the Southern Spirit line. Glotfelty asked PUC and ERCOT staffs to model the effect of that line had it existed Sept. 6, the last time ERCOT was in emergency operations (55984). (See ERCOT Voltage Drop Leads to EEA Level 2.)
The U.S. Department of Energy and Bureau of Ocean Energy Management on Jan. 17 kicked off a series of stakeholder workshops to address the specific challenges to siting transmission for the first generation of West Coast offshore wind projects.
The Biden administration set a goal of deploying 30 GW of offshore wind in U.S. waters by 2030 and an additional 15 GW of floating offshore wind — the type needed in the deeper waters off the Pacific Coast — by 2035.
Speaking during the Jan. 17 virtual meeting, Jocelyn Brown-Saracino, offshore wind energy lead at DOE, highlighted that the U.S. now has a combined potential capacity of approximately 52 GW of offshore wind, up nearly 50% from three years ago. And in the last year, she noted, the global floating offshore wind pipeline grew from around 60 GW to about 103 GW.
Planners are looking to the West to accelerate that progress: California has established a goal of deploying 25 GW of offshore wind by 2045, and Oregon set a target of 3 GW by 2030.
But the West Coast currently lacks the transmission infrastructure to meet those goals. And while the Atlantic Offshore Wind action plan serves as a road map for planning in the Pacific, development along the West’s more remote coastlines comes with its own unique obstacles.
“We know that bringing this energy to shore poses a host of challenges,” said BOEM Director Liz Klein. “On the West Coast, the lack of off- and onshore transmission pathways to access offshore wind development and the harsh ocean energy environment [are challenges]. We need to work together to understand these challenges and to identify potential solutions.”
Another challenge lies in the complications of developing transmission that extends beyond a federal lease area. BOEM’s authority over transmission siting starts at the outer continental shelf, allowing the agency to grant easements and rights-of-way for the production, transmission and transportation of energy sources. But BOEM does not have jurisdiction over landfall sites, so a project developer must work with regional and state entities and utilities to determine the appropriate points of interconnection.
In convening the workshops, the agencies hope that engaging states, transmission operators, tribal nations, ocean users and others will foster collaboration for the development of offshore wind. The series is part of a broader effort, and DOE is finalizing the scoping phase and beginning technical analysis.
Scoping in early 2023 identified gaps in planning, including the need for more interregional coordination and collaboration with tribal governments. DOE is working with the National Renewable Energy Laboratory (NREL) to engage tribes through the Tribal Nation Offshore Wind Transmission Technical Assistance Program, which will offer educational resources, training, technical assistance and funding for participation.
Technical Progress
The effort will also get significant technical support from U.S. national laboratories. Last May, the Pacific Northwest National Laboratory (PNNL) and NREL launched the West Coast Offshore Wind Transmission Study, which over the span of 20 months will explore transmission options to support offshore wind development through 2050. The labs reviewed 13 technical studies on offshore wind development, identified key themes in the region and determined that coastal interconnection points lack existing capacity for integrating offshore wind.
Mark Severy, a PNNL adviser to DOE, also identified gaps in the body of work reviewed, finding that most studies were focused on a single region or state and lacked consensus on the optimal technology or topology for offshore grid infrastructure.
According to Travis Douville, wind systems integration portfolio manager at PNNL, the study is the first of its kind to assess the entire West Coast. It considers a variety of guiding questions, including how much offshore wind should be developed through 2050 and where, and lays out nine tasks designed to help answer those questions.
To determine where transmission is needed, task two identified a series of zonal capacity expansion targets that span the Western Interconnection and provide information on how much offshore wind could be brought online. The targets will then be used to build nodal representations to simulate information on the economic dispatch of individual generators and model various sensitivities such as weather.
Tasks three and four involve the consideration of various siting conflicts, such as ocean co-use and topology. Douville said Pacific coastline is particularly challenging due to the depth of the water and the contour of the sea floor and canyons.
The team is constructing four topology sets to help consider where projects should be built. With those in place, the researchers will conduct weather-synchronized simulations of historical and future load, wind and solar patterns to provide insights into the types and location of needed generation.
After the modeling is complete, the labs will quantify the changes to capital and production cost, emissions, resource adequacy and resilience characteristics to the system, as well as the socioeconomic impacts and benefits to coastal and ocean co-use communities.
Lessons Learned
Alissa Baker, senior technical adviser for offshore transmission with DOE’s Grid Deployment Office, discussed lessons learned from developing the Atlantic action plan.
“We’re not inventing the wheel from scratch here,” Baker said. “We’re starting with a plan and hopefully refining and learning from the things that went well and the things that could go even better here.”
Key among the insights, Baker emphasized the importance of partnerships, particularly among state and regional entities and with tribes. She also highlighted the need for greater interregional offshore topology planning that spans ISO, RTO and state boundaries.
Baker’s presentation noted that FERC Order 1000 “sets forth the current generic federal requirements for considering potential interregional transmission” but requires only “coordination” between regions. “Fully integrated interregional planning is allowed but not required and, to date, has not been successfully implemented for any large-scale infrastructure,” it said.
Baker also suggested updating NERC standards for offshore wind generation to ensure they’re applicable to ocean transmission infrastructure and offshore wind generation tie-lines.
Another key recommendation was the support of local communities through community benefit agreements between project developers and those impacted.
“We want to make sure that the communities that are impacted by infrastructure are benefiting from that infrastructure and that the benefit is something that is greater than the impact they’re perceiving,” she said.
The Jan. 17 meeting closed with a lighthearted prerecorded discussion between DOE Deputy Secretary David Turk and Laura Daniel-Davis, acting deputy secretary at the Department of the Interior, which oversees BOEM.
“The Biden-Harris administration has an ambitious goal of deploying 30 GW of offshore wind by 2030,” Daniel-Davis said. “When we get there, that’s enough to power 10 million homes and we’re going to cut 78 million metric tons of carbon pollution … all while we build a domestic supply chain, creating these good-paying union jobs, and we’re lowering consumers’ energy prices.”
Turk reflected on the Atlantic convening series workshops and their benefit to transmission planning in the West.
“It was an incredibly good forum, and I think the West Coast can do an even better job of these kinds of discussions going forward,” he said.
LANSING, Mich. — Opponents of Michigan’s new laws governing siting for renewable wind and solar energy projects have until May 29 to present petition signatures from at least 356,958 registered voters to potentially put a repeal on the ballot.
The group backing the effort already is trying to collect signatures. Technically, as an initiated act, under Michigan’s constitution, the Legislature could enact the changes the proposal would make once enough signatures are gathered (and the constitution would forbid Gov. Gretchen Whitmer (D) from vetoing it). But no observer expects the Democratically controlled legislature to enact the proposal.
If the legislature does not approve the proposal, it would go to the voters at the next general election. Citizens for Local Choice is spearheading the petition effort.
Despite several attempts, officials with the Lenawee County-based group could not be reached for comment. Lenawee County is a mostly rural county on Michigan’s southern-most tier bordering Ohio.
Lenawee County Commissioner Kevon Martis has been quoted in newspaper articles saying the organization isn’t opposed to alternative energy, but the provisions in PA 233, 2023 give siting authority for solar and wind projects to the state’s Public Service Commission instead of local authorities.
The centralized siting provision was a main reason Republicans refused to support the bills in the legislative process.
Martis told the Michigan Board of State Canvassers the repeal effort, “has been about restoring local voices when it comes to wind and solar options being placed in their communities,”
Norm Stephens, a committee member for Citizens for Local Choice, told the Adrian Daily Telegram, the Lenawee County newspaper, “we refuse to sit on the sidelines as local control gets stripped from our communities.”
The new law is an important component of Michigan’s efforts to achieve net zero carbon emissions by 2040. It was enacted following a series of situations in which local governments, primarily in rural counties, enacted new zoning provisions blocking solar or wind projects. In some cases, residents objected to alternative energy projects over concerns about noise, attractiveness and the potential loss of farmland.
Supporters of the law argue it helps protect the property rights of farmers and others to sell and use their property for different purposes.
Nick Dodge, communications director for the Michigan League for Conservation Voters, said of the petition drive: “This reckless proposal hurts farmers looking to keep multigeneration land in their families and strips them of their property rights, all while harming workers that can benefit from clean energy tax revenue and jobs. Repealing this important law will only lead to an increase in utility rates for Michigan families and small businesses.”
The state canvassers reviewed the proposed language for the petition and the form of the petition before giving its approval to gather signatures. That step is not required in Michigan law but generally is sought by groups leading petition drives to minimize the chance the petition could be thrown out on legal technicalities.
Lawyers for supporters and opponents of the proposal worked on a compromise on the 100 words that would outline the proposed initiated act. It reads:
“Initiation of legislation to: amend the clean and renewable energy and energy waste reduction act by eliminating the requirement that applicants undergo state certification before construction of certain wind and solar energy facilities and energy storage facilities. Under current law, in addition to local approval, applicants for construction of these facilities must obtain state certification, which requires meeting state requirements, including: an application fee; public comment; assessment of environmental, natural resources and farmland impact; wages and benefits requirements for workers; setback distance; size and height of structures; and amount of light and sound emitted.”
The group needs to collect nearly 357,000 signatures, equivalent to 8% of the total votes for governor in the 2022 election, as required by the constitution. The group said on its website it plans to collect 550,000 signatures to ensure the proposal gets the minimum number. The organization is looking to raise between $7 million and $10 million for an anticipated campaign to win voter approval.
Montana-Dakota Utilities Co. has filed a complaint against MISO and SPP over a market-to-market flowgate chronically congested by a new cryptocurrency mining operation in SPP.
The utility said the RTOs are violating their joint operating agreement by conducting “unwarranted” and “unjust” M2M congestion coordination on the Western Area Power Administration 230-kV Charlie Creek-Watford line in North Dakota (EL 24-61).
Montana-Dakota Utilities — a MISO member — said its customers have been overcharged about $18 million for congestion on Charlie Creek-Watford. It said FERC should order a stop to MISO and SPP’s M2M coordination on the line, direct SPP to refund payments MISO made to it for M2M coordination and order refunds for “duplicative payments made by Montana-Dakota for M2M coordination.”
The company also said FERC should pronounce MISO and SPP’s interregional coordination process unreasonable because it allows MISO or SPP to “insist on continued coordination of a flowgate” even when the coordination is not shown to reduce congestion. MISO and SPP should be conducting M2M coordination only when it’s effective at cutting congestion, Montana-Dakota argued.
Montana-Dakota maintained the RTOs’ interregional coordination process never should have been enacted in the case of Charlie Creek-Watford because the constraint “was of local, not regional, concern.”
“SPP’s decision to enact and maintain M2M coordination for the local issue of congestion on the Charlie Creek-to-Watford City line violated and continues to violate [the JOA] and constitutes an unjust and unreasonable practice,” the utility told FERC. If SPP “continues to insist on use of M2M coordination for the Charlie Creek-to-Watford City line congestion issues, then Montana-Dakota and its customers will continue to be unfairly and unjustly assessed overlapping congestion charges.”
MISO IMM David Patton said MISO and SPP should revoke Charlie Creek-Watford’s status as an M2M constraint because MISO can offer little congestion relief for the line and it’s costing MISO millions in payments.
MISO staff said new load was allowed to be activated in an already-constrained SPP load pocket with planned transmission upgrades for the area not in service yet.
MISO itself hasn’t ruled out litigation with SPP over the overworked flowgate.
In mid-January, MISO deputy general counsel Kristina Tridico confirmed that MISO pursued alternative dispute resolution with SPP over the constraint and is at the “beginning stages” of negotiations.
