New Mexico regulators have launched a process to develop “guiding principles” regarding participation in a regional day-ahead market or RTO.
The Public Regulation Commission on Thursday voted 3-0 to approve an initial order opening a docket on the matter and scheduling a workshop at 2:30 p.m. Sept. 21.
The docket will be used to investigate factors that two investor-owned utilities in the state, Public Service Company of New Mexico (PNM) and El Paso Electric (EPE), should consider when deciding whether to enter an RTO or day-ahead market. Both utilities currently participate in CAISO’s Western Energy Imbalance Market.
Following one or more informal workshops, the PRC may opt to begin a formal rulemaking process.
Commissioner Patrick O’Connell called the order “a good step forward on a very important topic.”
“This is not a trivial thing,” O’Connell said. “I think there is a lot of potential value for our customers. Getting it right is where the work is.”
The commission also gave a homework assignment to PNM and EPE in the form of questions to answer in writing on RTO and day-ahead market issues. The utilities will present their answers during the workshop.
The questions are organized under 14 topics. On the topic of reliability, the commission wants to know whether system reliability is improved by regional market participation and how a utility’s responsibility for local reliability might change.
Two questions fall under the topic of transmission. The commission has asked if participation in a day-ahead market would improve the transmission system for New Mexicans and how that would compare to joining a full RTO. A second question asks whether the regional market should require participating transmission providers to make all their capacity available to the market and what exceptions should be made.
Under the topic of market transparency and performance, the utilities will discuss the types of data that would be provided to the commission and the public to assess market performance.
On another topic, the utilities were asked to describe the impact of joining either CAISO’s Extended Day-Ahead Market or SPP’s Markets+ on “seams.”
Another question is how rural electric cooperatives can participate in the market.
With dozens of questions for the utilities to answer, the commission could decide that a series of workshops is needed, rather than a single session.
The PRC also has asked Southwestern Public Service (SPS), which is a member of SPP, to submit written comments about benefits or impacts to ratepayers resulting from RTO participation.
Other stakeholders are encouraged to participate in the process.
“Stakeholders’ comments here about what they expect to get out of regional markets will be very valuable as we try to develop the guidance principles and expectations,” Commissioner Gabriel Aguilera said.
New Mexico’s effort comes just as competition is heating up between CAISO and SPP over their respective efforts to bring day-ahead markets to the West, which likely would be a precursor to a full RTO. (See In Contest for the West, Markets+ Gathers Momentum — and Skeptics.)
GRAND RAPIDS, Mich. — The annual Mid-America Regulatory Conference (MARC) Aug. 6-9 again centered on the clean energy conversion and transmission expansion, this time with an undercurrent of equity.
MARC’s 2023 conference, “Grand Vision: Past, Present, Future” originally was planned for late spring 2020 but was derailed by the pandemic until Aug. 6-9.
“It’s a conference more than four years in the making,” Michigan Public Service Commission Chair Dan Scripps said, welcoming regulators, utility representatives and “Barbies, Kens and even Allans” to the conference.
Equity Takes Center Stage
Multiple Indiana and Michigan-based grassroots equity and climate activist groups attended MARC this year, pressing regulators and utility representatives to decarbonize faster while addressing longstanding disparities in the grid’s design.
Wisconsin PSC Chair Rebecca Cameron Valcq said the energy transition affords the industry “a once-in-a-generation opportunity and responsibility” to include vulnerable communities in environmental justice. She said those communities have good reason to distrust the systems in place and have been neglected “for hundreds of years.”
Regulatory initiatives often are “dense and obtuse,” Cameron Valcq said, making an informed and participating public an uphill battle. She said “there’s more work to be done” in ensuring the public know where and when to comment.
Becca Jones-Albertus, director of the Solar Energy Technologies Office at the U.S. Department of Energy, said an “unevenly distributed” transition is underway, where some parts of the country already have rapidly transformed while other parts have little idea of what’s in store for them.
Jones-Albertus said over the next few years, she expects 5-10% of power consumed to originate on the distribution system.
“We’re at a fork in the road,” said Jeffrey Schlegelmilch, director of the National Center for Disaster Preparedness at Columbia Law School. He said the industry can either view the transition through the “lens of equity” and extend the benefits of innovation to all, or it can exclusively lavish investments on wealthier areas, forcing poorer Americans to pay more for power, be neglected from environmental redress and continue bearing the brunt of reliability breaches and dangerous weather.
Schlegelmilch said societal and economic costs will be much lower if the industry brings everyone along on the clean energy overhaul. He said he’s performed analyses where the medical costs of exacerbated health conditions and the “cascading impacts” of those costs alone make replacing a fossil fuel generator with a battery storage facility cost-effective in communities. But he also said that raises the question of who ultimately pays for action versus inaction.
Midwest Building Decarbonization Coalition’s Marnese Jackson said historic racism, capitalism and a single-minded drive for corporate profit is making a truly equitable decarbonization increasingly unattainable. She called for an emphasis on shifting away from “dirty” natural gas as soon as possible.
Consumers Energy CEO Garrick Rochow said equity and environmental justice can be baked into the energy transformation. He said he believes carbon capture will factor heavily into the clean conversion, and natural gas generation will “fill in the gaps” and then “diminish.” Rochow said once the grid is sufficiently greened, green hydrogen can enter the conversation.
Rochow also said Consumers has conducted unconscious bias analyses in its outage restorations and grid investments practices, something it “should have done 20 years ago.”
“What we’ve found is we’re investing more in our most vulnerable customers because the grid is in worse shape in those areas,” he said.
In a session on planning a just transition for power plant communities, Hilary Scott-Ogunrinde, deputy director of energy and utility at the Illinois Department of Commerce and Economic Activity, said the state is trying to “rectify the wrongs of the past” through the Climate and Equitable Jobs Act (CEJA).
She asked the audience to guess how many coal plants have closed in Illinois in the past decade. After speculations ranging from five to 20, she said the number is 11.
Scott-Ogunrinde said after the rash of closures, Illinois passed CEJA, which contains grants for coal-to-solar facility changeovers, both for underprivileged individuals seeking to invest in renewable development and for communities transitioning from coal, nuclear, natural gas or mining operations.
Larry Steckelberg, an administrator of community services at the Michigan Department of Treasury, said Windsor, Ontario’s twinkling lights across the Detroit River are in stark contrast to Detroit’s lack of recreational waterfront, brownfield sites, abandoned factories and shuttered coal plants. He said River Rouge, Mich., the former site of heavy industry and DTE Energy’s River Rouge coal plant, which closed in 2021, is one of the most polluted sites in Michigan and will take several years of remediation until people are enticed to move there.
Steckelberg said revitalizing a former coal plant city is a long-term project, often taking 15-20 years, with cities “swept up in global events” out of their control. He said he personally couldn’t predict how fast coal would fall out of fashion globally.
Steckelberg said the town of Covert, Mich., was unprepared for the closure of the Palisades nuclear plant, even though indications were clear. He urged communities to diversify energy sources and not “just become a site” for solar panels because it’s the trendy resource now. But he acknowledged that the list of federal resources and the requirements can be “bewildering” for some communities.
“Putting in layers of bureaucracy does not get the help that people need,” Scott-Ogunrinde agreed. “…If we’re going to have the money available, then have the money available. Because the people filling out the forms, they need it. Even if they don’t have 20 pages of documentation.”
EPA Senior Adviser Jon Grosshans said historically the U.S. has supported communities suffering manufacturing losses, but it hasn’t provided backing for communities that transition from coal plants.
Grosshans said the federal government is seeking to create a “front door” for financial resources for transitioning communities.
“Sitting around in 2019, it was pretty obvious to us that this was going to be a decade of closing more coal and bringing on more renewables,” said Emily Fisher, Edison Electric Institute executive vice president of clean energy.
Fisher said EEI quickly realized that net-zero plans would need to incorporate dispatchable technologies with the assistance of carbon capture, green hydrogen and long-duration storage.
“No company has released a plan that hasn’t carefully thought this through,” she said.
But Fisher said it became apparent over the past few years that “maybe this decade isn’t going to be as easy as we thought it was going to be,” referring to how difficult it remains for new generation to clear interconnection queues and receive grid treatment.
Fisher also said post-pandemic, utilities have become more acutely aware of affordability. She said when utilities raise concerns about customer affordability, it’s often perceived as utilities trying to stall the clean energy transition. But she said utilities are justified in their concern whether costs can be recovered from ratepayers.
“Solar seemed unreachable from an economics standpoint about 10 years ago. What seemed impossible a decade ago has become very, very possible,” Norcia said.
Norcia also said he’s optimistic about green hydrogen and predicted the technology will improve, and costs will plummet so that what seemed insurmountable will become achievable.
Norcia also said DTE’s service territory has begun to see “violent storms… and weather patterns that were reserved for states south of us,” upping the pressure to make infrastructure investments for the sake of reliability. He said the climate crisis and growing demand for electrification means utilities need to “build the grid out slightly ahead of time.” He also said worsening weather means utilities need to seriously consider “how to get stuff underground,” indicating burying lines.
“That’s something we’re going to start experimenting with and seeing how we can get the costs down,” he said.
Google Global Head of Energy Caroline Golin said Google is conscious it demands a lot of electricity and wants to accelerate the switch to carbon-free sources. She said Google is focused on how to partner with suppliers on pilot projects for green hydrogen, long-duration storage and carbon capture.
“I can tell you this [carbon-free] growth is coming, it’s coming now, it’s coming fast. We wanted it yesterday. …We will not grow somewhere where we don’t see a goal,” she said of renewable energy targets.
Golin also said Google doesn’t want to wait on a “six-year interconnection queue” before planned generation can link up to the grid. Google aims to achieve net-zero emissions across all operations by 2030.
“We make two-year, three-year business commitments,” she said.
Towering Transmission Investments
“What we do know is that the future is going to [be] significantly more complex than anything we’ve ever planned for before,” SPP Vice President of Engineering David Kelley said, noting that the U.S. has sustained about 360 weather and climate disasters since 1980 where overall damages and costs have reached at least $1 billion. “Planning for a loss of load event every 10 years is no longer going to cut it,” he said.
Advanced Power Alliance’s Steve Gaw said transmission system expansion is necessary to unlock clean, low-cost energy and shrink congestion.
Gaw said if grid operators aren’t proactively planning, “you’re risking being 10 years behind.”
“In the words of Dwight Eisenhower, I’d say plans are nothing — and basically worthless — but planning is everything,” he said.
Gaw also said transmission projects — even ones built to further a lone public policy goal — rarely fulfill a single purpose. He said transmission often offers a myriad of economic, reliability and decarbonization benefits. He said it’s nearly impossible to build transmission for a single goal.
“You’ve got to think about the consequences if you don’t make that investment,” ITC’s Charles Marshall said of transmission planning, pointing out that his friend’s electric bill will contain an up to $10 surcharge every bill for decades to fund the recovery efforts after Winter Storm Uri because the system wasn’t built to weather the storm.
FERC Commissioner Mark Christie said contrary to the perception of a crumbling and decrepit transmission system, there’s a surge in new transmission projects.
“We’ve heard a lot about how the grid is old, it’s creaky, it’s built for a World War II era,” he said.
But Christie said the national transmission rate base has tripled in the past decade and is set to double over the next eight years. He said grid planners need to be sensitive to regional costs. “You ain’t seen nothing yet” in terms of how high transmission price tags will ascend in the coming years, Christie warned.
Siting infrastructure isn’t going to get any easier, multiple panelists said.
“There’s so much development that communities are reacting. They’re being asked to solve global energy infrastructure problems, and they’re thinking ‘that’s not my problem,’” University of Michigan Director Sarah Mills said.
Mills said developers should sell their projects as solutions to lift farmers’ incomes and increase local tax bases.
Mills also said regulators should be upfront about collecting comments and if the contents stand to change the outcome in a decision.
Mills admitted even she didn’t fully understand how to comment in Michigan Public Service Commission proceedings. She said only the wealthy usually have the time and the means to register their opinions.
Grid United CEO Michael Skelly said infrastructure upgrades, renewable additions and carbon capture facilities stand to benefit disadvantaged communities by improving air quality.
Causes for Concern
America’s Power CEO Michelle Bloodworth said 80 GW of the nation’s 200-GW coal fleet will retire over the next seven years, “putting a lot of pressure” on natural gas infrastructure as a source of fuel-secure dispatchable generation. She said state regulators should slow down the pace of retirements for coal units and let them live their “natural, useful lives” until the grid can secure generation replacements with reliable attributes.
“I don’t want to be the angel of death and cast a pall on this discussion … but I think it’s important to speak very bluntly about the situation we’re in,” consultant Bob Gee said.
Gee said gas suppliers desperately need the creation of a gas reliability organization even though it’s a “hornet’s nest.” He said the grid risks outages in the winter and now in the summer as demand grows.
Grid Strategies’ Rob Gramlich agreed grid operators are leaning on natural gas more, and more needs to be done to make the supply dependable.
Gramlich credited MISO’s 2011 portfolio of Multi-Value transmission projects for keeping the lights on during severe winter weather. He said it’s possible to build the grid “bigger than the weather” and thanked MISO for its work on its first, $10 billion long-range transmission plan (LRTP) portfolio. Gramlich also said grid-enhancing technologies and plans for interregional transmission are necessary going forward to safeguard reliability.
MISO COO Clair Moeller said while about 80% of the first LRTP portfolio used existing rights of way or adjacent routes, the second, multibillion-dollar portfolio on greenfield locations will be more difficult to site and build.
“So, buckle up buttercup, this one’s going to be hard,” he said.
Moeller also said the greater transport capability between organized markets is the most significant change in recent years to avoid load shed events.
“In the old bilateral days, it would take days to move that kind of power,” he said.
Moeller said he continues to worry about what the Germans call “dunkelflaute,” or multiday periods of overcast skies and little wind. He said storage technology doesn’t yet have the capability to cover those prolonged conditions.
ISO-NEproposed a 21.5% increase in its revenue requirement for 2024 last week, citing the need to retain and expand its workforce to enable the clean energy transition. The RTO presented the $244.5 million operating budget and $35 million capital spending plan to the NEPOOL Budget and Finance Subcommittee on Friday.
In response to the proposed increase, some public advocacy groups have criticized the RTO for a lack of transparency and engagement with the public on its budget process, arguing that these issues indicate a lack of accountability to ratepayers.
“I don’t see it as reasonable that New England ratepayers are minting new millionaires every year at ISO-NE, and we don’t even have the ability to question those financial packages,” said Tyson Slocum, director of Public Citizen’s Energy Program. “Thousands of New Englanders who are really struggling to make ends meet with continued rate hikes across the region are shut out of the process. They can’t go and share their grievances; they’re literally locked out of the room.”
ISO-NE first proposed a preliminary version of the budget to the Participants Committee (PC) in June. (See ISO-NE Considers Major Capacity Market Changes.) The RTO said it needs $27 million for “catch-up” adjustments to current employee salaries and investments in information technology, cybersecurity and the transition to cloud-based infrastructure; $11.5 million for the revenue requirement true-up; and almost $10 million for 35 new employees to respond to the clean energy transition.
“Our executive compensation structure is designed to attract and retain top-tier talent essential to overseeing the complex energy landscape and ensuring the reliability of the regional power grid,” an ISO-NE spokesperson told RTO Insider. “We regularly review and benchmark our executive compensation against industry standards to ensure it remains competitive, fair and aligned with our performance goals.”
The draft budget also includes a placeholder headcount for a position focused on environmental policy and community engagement, following the request by five of the six New England states (all but New Hampshire) for an executive-level environmental justice position at the organization. (See States Call for an Executive-level EJ Position at ISO-NE).
Mireille Bejjani of environmental justice organization Slingshot applauded the inclusion of this position and the addition of staff and resources dedicated to the clean energy transition.
“I think the key distinction is, are we paying existing leadership — who are already making a lot of money — even more money, or are we paying for more staff to be able to accelerate the clean energy transition?” Bejjani asked.
According to ISO-NE’s 2021 IRS Form 990, ISO-NE CEO Gordon van Welie made about $2.4 million in 2021, while COO Vamsi Chadalavada made nearly $2 million. Meanwhile, salaries for members of the Board of Directors working about 10 hours per week ranged from $113,000 to $173,000.
The 2024 draft budget includes $5 million for the base salaries of the 11 officers, a roughly 6% increase over the $4.7 million requested in 2022. ISO-NE executives also make a significant portion of their total income outside of their base salary; van Welie and Chadalavada both made more in bonus and incentive compensation than in their base salaries in 2021.
“Especially this past winter, lower-income communities were hit really hard with rate increases and having to potentially choose between paying their electric bills and putting food on the table,” Bejjani said. “If those bills go up even a small percentage per month, that can make a huge impact on lower income communities, just to pad the pockets of people who are already making well over six figures a year for not very much work, in the case of the Board members, and for [van Welie] and the other top leadership, upwards of a million dollars.”
ISO-NE estimated that the budget increase would cost the average ratepayer 28 cents per month, bringing ISO-NE’s total charges to around $1.46 per consumer per month, or about $18 each year, assuming an average monthly electricity consumption of 750 kWh. The presentation said ISO-NE’s total operating expenses were on the lower end compared to NYISO, CAISO, IESO, PJM, MISO, SPP and ERCOT.
Slocum said since ratepayers pay ISO-NE’s cost regardless of performance, they must be given access to the RTO’s budgetary proceedings. He also argued that bonus compensation should be more transparently tied to performance.
“It doesn’t seem just and reasonable to pay such extravagant salaries and bonuses with no corresponding accountability,” Slocum said.
Beyond executive compensation, the proposed budget includes about $300,000 for state-level lobbying and $100,000 for federal lobbying, paid to external consultants. Over the first half of this year, ISO-NE spent $60,000 on federal lobbying, employing former Bush administration official Adam Ingols. ISO-NE also spent $45,000 on its Massachusetts lobbying operation.
ISO-NE plans on reviewing the proposed budget at the September PC meeting, followed by a PC vote in October.
With distributed energy resources (DER) playing a growing role in electric reliability, ensuring their protection from cybersecurity threats has become increasingly vital, the Texas Reliability Entity heard last week.
Rebekah Barber, a cyber and physical security analyst for Texas RE, says now is the time to look ahead at the threats this emergency technology will face. While she focused primarily on smart devices, Barber said DERs, whose deployments are expected to triple by 2025, will not be exceptions.
“These devices can pose a risk to the average network as these devices are typically not designed with security in mind,” she said during a Talk with Texas RE webinar Thursday. “Traffic is often not encrypted from these devices, default [administrative] passwords aren’t changed and sometimes, vendors don’t push out firmware updates or security patches.”
Barber said DERs may face “zero-day attacks,” when hackers exploit software flaws before developers are able to address them.
“While they are specifically targeted towards industrial systems, they prey on the vulnerabilities found in those newer technologies,” she said.
The threats don’t stop there, Barber said.
“As cybersecurity defenses have evolved, attackers have shifted their focus upstream to ‘contaminate the water,’ so to speak,” she said. “Attackers are now focusing more on trusted suppliers and vendors to add backdoors or weaken the overall security of products and services to gain access to an otherwise protected system.”
Barber cited the SolarWinds hack of 2020, in which the Texas software company sent an update to its customers that was infected with a malicious code. About 18,000 SolarWinds customers downloaded the update, unwittingly helping spread one of the largest cyberattacks against the U.S.
“Many companies, including some federal agencies, were affected by this attack, which gave attackers access to the victim’s network, and then from there allowed the attackers to compromise other systems,” Barber said.
She said protecting DERs should begin with a skilled and empowered security team and that “other best practices will naturally follow.”
They include: endpoint detection and response to understand what is being communicated with and to quickly respond to threats; a zero-trust model that verifies and authenticates every access attempt; encrypting communications between operators and resources to ensure confidentiality and prevent data tampering; and multi-factor authentication beyond passwords to strengthen user accounts and prevent unauthorized access.
Barber referred her audience to a report released last fall by the Department of Energy that gives a high-level overview of the expected cybersecurity challenges with DERs’ increased deployment in the coming years.
The report defines DERs as small-scale power generation, flexible load or storage technologies between 1 kW and 10,000 kW that can provide an alternative to or improve the traditional electric power system. They can be located on a utility’s distribution system, a subsystem or behind the customer’s meter. DERs may also include electric storage, variable generation, distributed generation, demand response, energy efficiency, thermal storage or electric vehicles and their charging equipment.
In 2020, NERC created the System Planning Impacts from DER Working Group (SPIDERWG) to address “key points of interest” related to system planning, modeling, and reliability impacts to the bulk power system .
GRAND RAPIDS, Mich. — This year’s Mid-America Regulatory Conference took notice of FERC’s recent set of interconnection rule changes.
Experts on an interconnection panel Aug. 7 were hopeful that the commission’s Order 2023 — meant to alleviate queue backlogs, give developers certainty and prevent discrimination against new technologies — will fix some of the problems plaguing queues (RM22-14). (See FERC Updates Interconnection Queue Process with Order 2023.)
“We know the symptom of the interconnection problem, but what’s the cure?” Iowa Utilities Board Commissioner and panel moderator Joshua Byrnes asked panelists in a room packed with attendees.
AEP Vice President of Transmission Planning Kamran Ali said he thought Order 2023 will result in “cleaner” interconnection queues, though the jury is still out on whether it will encourage more capacity to connect.
“We’re capacity-short in a lot of areas because load is pushing resource requirements up,” Ali said.
Clean Grid Alliance Executive Director Beth Soholt said FERC’s order is helpful to spur transmission providers to bring new generating capacity online and not simply be motivated to preserve the existing resources on the system.
“We’re talking about a lot of turnover. We have a lot of retirements; we must get a lot of megawatts through in a short amount of time. We have to look at both sides of the ledger. What can interconnection customers do, but what can MISO and transmission owners do? It’s not working well today,” Soholt said.
Enel North America’s Gina Mace said she was glad to see FERC placed emphasis on the commercial readiness of generation projects in Order 2023.
Mace also said queues “could see a lot of progress” if long-term transmission planning is co-optimized with interconnection planning. She said today’s transmission system is ill-suited to how scattered generation is becoming.
Soholt said in a perfect world, there would be that same comprehensive planning in MISO, in addition to many more engineers to study two cycles of entrants per year.
Soholt said transmission owners should communicate with interconnection customers earlier to signal whether proposed points of interconnection are feasible. She also said MISO is on the wrong track to propose to cap the number of megawatts annually that it will study. MISO has proposed to restrict queue submissions to a 60%-of-peak-annual-load (about 73 GW) annually, triple its entry fees and establish more rigorous land obligations and escalating penalty charges. (See MISO Aims for Manageable Interconnection Queue.)
“If you cap the megawatts, you’re going to have people lining up five years ahead just to enter the queue,” Soholt said, asking if that scenario is conducive to the rapid plans for a clean energy transition.
“The demand is there. We’ve got to get them through the process,” Soholt said.
Mace said MISO needs more realistic study assumptions, a clearer notifications process if withdrawing projects stand to affect other projects and a plan to somehow reduce the interdependency among projects in its studies.
Ali said interconnection customers want some certainty before they commit to securing land. However, he said the quicksilver nature of earlier queued projects and the potential for re-studies mean interconnection queues probably will continue to be synonymous with uncertainty.
MISO has said the majority of the requirements “appear to generally align” with existing MISO process. It said it likely must tweak timelines, requirements and nomenclature in its interconnection process to match FERC’s vision.
Ørsted last week provided an outlook and an update on its place in the U.S. offshore wind power market, where great business opportunities are balanced by significant near-term challenges.
The briefing came after the world’s largest offshore wind developer reported its second-quarter/first-half financials Thursday and published its investor presentation.
In the follow-up earnings call, CEO Mads Nipper was pressed by financial analysts on the situation off the Northeast coast, focus of the first phase of what is expected to be a massive U.S. buildout in decades to come.
Ørsted has achieved some significant positive milestones there in recent months:
Federal regulators gave Ørsted final approval for Ocean Wind 1 off the New Jersey coast. And the state allowed Ørsted to benefit from tax incentives previously reserved for ratepayers when it said it needed more money to proceed with the 1.1-GW project. Nipper said this will help the company progress to a final investment decision.
And off the Rhode Island coast, the turbine foundations and substation have been installed for South Fork Wind, which Nipper expects will be commissioned by the end of this year as the nation’s first utility-scale offshore wind farm.
But also in recent months, Ørsted has told New York it may not be able to go forward with Sunrise Wind 1 without more money.
Rhode Island shot down Ørsted’s proposal for Revolution Wind 2 as too expensive.
And New York invited Ørsted to resubmit lower bids for Sunrise Wind 2. (Other bidders in the state’s third solicitation were given the same option.)
Other developers and other states are having the same problems:
Avangrid has reached a deal to back out of power purchase agreements for Commonwealth Wind and is seeking a higher rate for Park City Wind.
Shell and Ocean Winds are trying to back out of their SouthCoast Wind PPAs.
Equinor and BP told New York they need more money to build Beacon Wind, Empire Wind 1 and Empire Wind 2.
Atlantic Shores wants the same help from New Jersey that Ocean Wind 1 received.
Developers cite surging material costs and rising interest rates. With the eventual income from these wind farms locked in place before costs started rising, the developers say they cannot obtain financing to build them.
Given this, and given that these projects each carry a price tag in the billions, the details are of particular interest to financial analysts.
Q & A
The following is a summary of some of the questions posed Thursday and Nipper’s responses.
Q: Do policymakers understand that they need to pay more to reach their offshore wind goals?
A: Generally, we are confident they will. But the challenges are not small, and it is good that the industry is showing financial discipline by pulling projects to make the point that prices need to increase and auction frameworks need to change.
Q: Is it time to rethink some of Ørsted’s final investment decisions on U.S. projects, given the stubbornness of regulators, and focus on new bids instead?
A: We are having good dialogues and see progress. So, we are still pursuing plans. We see no value in walking away from existing projects and pursuing new ones.
Q: What is your assessment of the U.S. offshore sector?
A: States’ ambitions are continually growing, and they are realistically considering what needs to happen to achieve those goals. President Biden’s target of 30 GW installed by 2030 is still within reach.
Q: What is your timeline for a final investment decision on the Northeast U.S. projects?
A: We are aiming for fourth quarter 2023 or very early 2024. We need clarity on investment tax credits for individual projects — final guidance has not been issued on domestic content. So, there is not a clear number on Revolution 1 or Sunrise 1. And we are still in discussion with New York on increasing offshore renewable energy credits for Sunrise 1, which is very important to that project moving forward.
Q: Why did New York invite developers to resubmit lower bids in the third solicitation?
A: The auction framework was quite complex, and we believe some of the other companies’ bids may not have been fully compliant. Ours was.
Q: So Ørsted is not going to rebid at a lower price?
A federal grand jury indicted an Idaho man last week after he allegedly damaged two hydroelectric dams in the state this year, interrupting their service and causing what prosecutors say was over $200,000 in damage.
On June 8, Randy Scott Vail of Meridian, Idaho, shot the Hells Canyon Dam with a firearm, the day before also shooting at the Brownlee Dam, according to the indictment, released Tuesday. Both dams are operated by Idaho Power and provide electricity to customers in Washington, Idaho and Oregon.
Vail was already facing multiple felony charges in state court, having been arrested by the Washington and Adams County sheriff’s offices June 9. A statement from the Adams County sheriff credited law enforcement from two additional counties with helping in the arrest.
Local media, citing the Idaho criminal complaint and probable cause filing, reported that deputies were called to Brownlee Dam around 12:30 a.m. June 9 in response to reports that a man on a white motorcycle had fired shots there and at the Hells Canyon Dam. The deputies spotted a white motorcycle leaving the scene and followed it, leading to a high-speed chase. At one point, the driver reached 80 mph in a 20-mph zone.
When Vail eventually stopped, the deputies found a case on the motorcycle holding two rifles; they also found bolt cutters and cans that appeared to contain gasoline. The state charges against him include attempting to elude an officer and malicious injury to property. Online court records indicate that Vail was committed to custody June 9, with bond set at $250,000.
In a press release, Josh Hurwit, the U.S. Attorney for Idaho, said the shooting caused “significant interruption and impairment of a function of” both dams, with damage to each in excess of $100,000. The Adams County sheriff’s statement said nobody was injured in the incident and no customer outages were reported. The federal charges carry a maximum penalty of 20 years in prison.
The shooting at the dams is the latest in a series of recent violent attacks against U.S. electric infrastructure. Previous incidents include the Dec. 3 gunfire attack on two substations in North Carolina that left 45,000 customers without power for days; no suspects have been identified in the attack. (See FERC Orders NERC Review on Physical Security.) Later in December, police in Washington state arrested two men after they allegedly damaged several electric substations; one of the men later claimed they were trying to disrupt power as part of a robbery plan.
Domestic extremists have become increasingly interested in damaging the grid as well. This year, the Justice Department charged neo-Nazi leader Brandon Russell and one of his followers with planning to disable substations around the Baltimore area in hopes of cutting off power to the city and provoking a race war. (Feds Charge Two in Alleged Conspiracy to Attack BGE Grid.) The Department of Energy released a report in February showing incidents of deliberate physical damage to bulk power system facilities rose by 77% in 2022.
FERC has responded to the growing threat of violence by ordering NERC to review its physical security standards, which the ERO did in a report issued in April. The report was followed by a joint technical conference at NERC’s headquarters in Atlanta on Thursday in which attendees discussed the needs and costs of implementing security at vulnerable facilities. (See FERC, NERC Conference Addresses Security Challenges.)
FERC last week granted one of three claims against Public Service Company of Colorado (PSCo) in response to cooperatives’ complaints that they were charged $17.5 million in excessive gas costs during Winter Storm Uri in 2021 (EL23-21).
The commission said four PSCo customers (CORE Electric Cooperative, Grand Valley Rural Power Lines, Holy Cross Electric Association and Yampa Valley Electric Association) were able to prove they are entitled to review a baseload contract under the utility’s fuel protocols. It directed PSCo to make the contract available to the complainants, subject to a protective order.
The cooperatives said they were charged $17.5 million for extra fuel costs during the storm.
The utility’s fuel protocols provide that PSCo will make available to any wholesale fuel adjustment clause customer “books and records” related to the clause’s provisions and protocols. The Xcel Energy subsidiary argued the term “books and records” does not include the baseload contracts because the contracts are not the actual inputs for the fuel costs that are calculated and charged to the cooperatives under the fuel adjustment clause.
PSCo contended that the invoiced amounts charged under the baseload contracts, which it had already turned over to the cooperatives, were relevant because the information is necessary to understand how the charges were calculated. FERC found the argument to be unpersuasive, saying the utility did not cite any fuel protocol language indicating that “books and records” is limited only to “fuel cost inputs.”
The commission denied two other complaints by the cooperatives: that PSCo “imprudently” planned for its natural gas reserves and passed on excess costs from spot market purchases in February 2021 and that it acted imprudently and in a preferential manner by selling excess gas to an affiliate during the storm. FERC said the complainants had not presented sufficient evidence to meet their initial burden for those claims.
The commission also denied without prejudice the complainants’ request for relief from a Dec. 31, 2022, tariff deadline to raise questions concerning the fuel adjustment clause charges. They alleged PSCo violated its filed rate by withholding information, negating a further challenge to the charges, but FERC found the request to be “premature at this time.”
Projects in Louisiana and Texas have been chosen as the first two direct air capture (DAC) hubs to receive up to $1.2 billion in funding from the Infrastructure Investment and Jobs Act, the Department of Energy announced Friday.
The South Texas DAC hub and the Project Cypress DAC hub in Louisiana “are going to build regional direct air capture hubs, and that means they’re going to link everything from capture to processing to deep underground storage, all in one seamless process,” Energy Secretary Jennifer Granholm said during a Thursday press call.
Granholm described the technology as “essentially giant vacuums that can suck decades of old carbon pollution straight out of the sky, and once you harness that pollution, we can trap it permanently underground, or we can turn it into building materials … agricultural products or even clean fuels.”
Combined, the Texas and Louisiana projects are expected to take more than 2 million metric tons of carbon dioxide out of the atmosphere per year, “like taking nearly half a billion gas-powered cars off the road,” she said. “These hubs are going to help us prove out the potential of this game-changing technology so that others can follow in their footsteps.”
Mitch Landrieu, White House senior advisor and infrastructure coordinator, said the projects are “the first direct air capture projects at this scale in the United States and will be the largest in the world.”
Occidental Petroleum and its carbon-capture subsidiary 1PointFive are developing the South Texas DAC hub on 106,000 acres at King Ranch, an agribusiness ranch and farm that is larger than the state of Rhode Island, according to its website.
The project will use technology developed by Carbon Engineering Ltd. of British Columbia that “draws air into a facility using a series of large fans” and separates out the carbon via a chain of chemical interactions, as described on the 1PointFive website. The carbon, in liquid form, can be compressed and stored underground or processed to be used as feedstock for other products.
Battelle, a technology developer that manages seven of DOE’s national labs, is leading the Project Cypress DAC hub to be located on the Gulf Coast in southwest Louisiana. The company is partnering with two carbon capture companies — Climeworks Corp. and Heirloom Carbon Technologies — with the intention of combining their different technologies. Climeworks uses fans, filters and heat to capture carbon, while Heirloom has developed a process to absorb CO2 using limestone.
The two projects are the first of four DAC hubs to get a slice of the $3.5 billion the IIJA provided to develop the technology at commercial scale. Noah Deich, deputy assistant secretary of DOE’s Office of Carbon Management, said the two projects were chosen based on a rigorous review of their technical readiness, financial viability, and community benefits plans.
DOE has provided early funding of $3 million to $12 million to 19 DAC projects still in development, with the goal of getting ready to compete for the other two hub awards, he said.
“It will be a bit before we open up the funding,” Deich said in an interview with NetZero Insider. “It’s intentional so that we can let this direct air capture field catch up, and we don’t want to lock in any one technology that happened to get a head start. We really wanted diversity of technology approaches, a diversity of business models [and] geographies.”
Getting to Scale
Direct air capture, like carbon capture, has raised concerns and skepticism among some environmental groups, which have pointed to its expense, high power requirements and its potential use for enhanced oil recovery. At the same time, it has garnered strong support from lawmakers from states with a long history of fossil fuel production, including Sen. Joe Manchin (D-W.Va.).
Kelly Cummins, deputy director of DOE’s Office of Clean Energy Demonstrations, said that neither of the DAC hubs will use captured carbon for enhanced oil recovery, a process in which carbon dioxide is injected into low-producing wells to increase their output.
Asked about the power source for the Louisiana project, Lewis Von Thaer, CEO of Battelle, said the company would be buying clean energy from the local power provider to start, but intended to build renewable energy for the project later.
Both Occidental and Battelle have to match the IIJA funds dollar for dollar, but they stand to benefit from the $180 per ton tax credits for DAC in the Inflation Reduction Act. Still, for first-of-a-kind projects, DOE is encouraging the hubs to develop additional revenue streams, if necessary, to ensure they are financially viable, Deich said.
He pointed to the “voluntary market” for carbon removal offtake agreements, such as 10-year agreement Climeworks signed with Microsoft in July 2022, to take 10,000 tons of CO2 out of the atmosphere on the software giant’s behalf.
“There’s greater demand than supply, and these projects will be really critical for helping to fill that gap once they do start to come online,” Deich said. Such agreements also will be vital to help the early demonstration hubs get to commercial scale, he said.
Echoing Deich, Madelyn Morrison, government affairs manager for the Carbon Capture Coalition, hailed the announcement of the two hubs as an important step “to help realize economies of scale and support the decarbonization of the American economy. As such, today’s announcement provides major headway to kickstart the deployment of large-scale DAC projects as well as to foster the development of promising earlier-stage efforts.”
ATLANTA — In his opening remarks at Thursday’s joint FERC–NERC technical conference on physical security, FERC Chair Willie Phillips reminded attendees that “it is not a matter of if, but when there is another attack” on North America’s electric infrastructure.
Phillips’ attendance at the conference, held in NERC’s headquarters in Atlanta, was intended to demonstrate the seriousness with which the commission takes the growing threat of violence against the grid. FERC and the ERO organized the technical conference following NERC’s April report on its physical security reliability standards and recent physical security incidents, including the Dec. 3 gunfire attack on two substations in North Carolina that left 45,000 customers without power for days. (See NERC Says Changes Coming to Physical Security Standards.)
“I thought that it was important that I be here to help kick things off, because I want to underscore a couple of things,” Phillips said to the audience. “One, how important this dialogue is; and [second], we can’t do this alone. NERC can’t do this alone. No one entity can do what we need to do to protect the integrity of the [grid] from physical security attacks. … That’s why we’re here today.”
The goal of the conference was to discuss potential improvements to NERC’s reliability standards — particularly CIP-014-3 (Physical security) — in addition to other actions that registered entities can take to improve grid security.
NERC CEO Jim Robb noted that more than 1,200 people were watching the meeting online, in addition to those in the room. He said the size of the audience showed “the breadth of interest, both in the topic and the importance of getting this right.” He emphasized that any grid security solution must take the reality of utilities’ limited resources into account.
“Nobody wants to have an entity have to construct Fort Knox around a bag of pennies,” Robb said. “At the same time, we also have to be cognizant about the difference between the money that we spend to protect versus the money we spend to be able to recover, and recover quickly. And I think, given the sprawling above-ground physical nature of the electric system, that’s a really important balance to keep in mind when we think about physical security of our infrastructure.”
In the first panel, speakers focused on CIP-014-3, which aims to “identify and protect transmission stations and transmission substations, and their associated primary control centers, that if rendered inoperable or damaged [by] a physical attack could result in instability, uncontrolled separation or cascading within an interconnection.”
Jamie Calderon, a manager of standards development at NERC and contributor to the ERO’s April report on grid security, briefly described its conclusions. The report found that the standard’s applicability criteria are effective to “focus limited industry resources” on the most critical facilities and did not need to be expanded; however, the ERO also found that utilities’ approaches to some studies required by the standard are inconsistent because its wording is unclear.
Lawrence Fitzgerald, director of security and emergency management at engineering consultancy TRC, said that CIP-014-3 has “done a good job” identifying sites critical to grid security. However, he said the standard could be improved, asserting that some of its requirements seem to require utilities to certify the compliance of facilities that haven’t even been built yet.
“We get put in an awkward position for facilities, substations and control centers that are only on the drawing board. They don’t exist yet. It can’t cause a cascading outage,” Fitzgerald said. “But we’re being asked to … certify that everything’s copacetic and working well. I can’t do that if I don’t know what the connectivity between the substation and the monitoring center is, [or] if I can’t see a camera view or know how a facility is actually going to look on the ground.”
Mark Rice, senior power engineer at Pacific Northwest National Lab, observed that there is a longstanding divide between operational staff, who “care about the next 24 hours,” and those involved in planning who think “five, 10, or 15 years out.” He said “there probably needs to be a better conversation” between those who are responsible for evaluating risk at these different scales.
“I know [from] talking to some utilities at the transmission level, they have no clue what the load is, and they don’t know that it’s identified as critical to someone downstream,” Rice said. “And so we have to get that information into our systems or into our evaluations before I can do the next step of evaluating risk.”
Cool on Mandatory Minimums
Participants in the second panel discussed whether NERC should mandate minimum resiliency or security protections against physical attacks at critical facilities.
Jackie Flowers, director of Tacoma Public Utilities — which suffered a coordinated attack last December as two men damaged several substations as part of a robbery plot — expressed skepticism about establishing mandatory minimum protections. (See Wash. Sabotage Suspect Pleads Guilty.) She said resiliency would be better served by allowing utilities the flexibility to address the myriad different challenges that could apply at each site.
“We believe that a uniform, bright-line set of physical security measures is unlikely to offer as effective of an approach, because of the very site-specific conditions and varied risks that we have from infrastructure to infrastructure,” Flowers said. “So it’s very important that utilities are at the table and part of identifying what those risks are.”
Flowers’ fellow panelists agreed. Mike Melvin, director of corporate security and corporate and information security services at Exelon, emphasized that “you’re never going to get that risk [of physical attack] down to zero.”
Melvin pointed to the arrests earlier this year of neo-Nazi leader Brandon Russell and one of his followers for plotting to attack substations operated by Baltimore Gas and Electric (an Exelon subsidiary) in hopes of starting a race war. (See Feds Charge Two in Alleged Conspiracy to Attack BGE Grid.) He suggested that Russell’s plot, which was based on publicly available information on the utility’s facilities, showed that “where there’s readily [available] information out there, you can never pull it back in.”
Rather than mandatory minimum standards, the panelists suggested that robust information sharing networks, both among utilities and with law enforcement, are key to foiling physical attacks and sabotage before they escalate into disaster. Flowers endorsed the Electricity Information Sharing and Analysis Center as a way for utilities to update their peers on the latest physical and cyber security threats.
Panelists in the afternoon session — the theme of which was “Solutions Beyond CIP-014-3” — agreed the standard should be considered a baseline for physical security rather than an end goal in itself.
Scott Aaronson, a senior vice president at Edison Electric Institute, warned against a one-size-fits-all approach to physical security, noting that threat actors are increasingly sophisticated.
“I’ve said it before — you protect diamonds like diamonds and pencils like pencils, and what [are] the crown jewels [is] going to continue to change,” Aaronson said. “So I think open dialogue about understanding where those truly critical nodes reside, and how best to protect them and/or ensure redundance and resiliency and opportunity to recover is going to be key.”
Aaronson echoed earlier panelists’ calls for information sharing, while warning against letting that crucial data spread outside the industry. He raised the chilling prospect of a map of critical substations appearing “on the front page of The Wall Street Journal.”
Vinit Gupta, vice president at ITC Holdings, recommended holding regular penetration tests in which a third party attempts to break into a facility and cause simulated damage. He said that in one case, testers found several vulnerabilities at his company using techniques found in videos on YouTube, or cheap devices purchased on Amazon.
“You’d be surprised to see that you can buy a $10 device and do some of those [threatening] activities,” Gupta said. “So when we looked at some of the recommendations … that actually prompted us to reevaluate our approach, with physical access control systems and video monitoring systems. And we’re right now in the middle of replacing that and looking at where we go from here, because the threat landscape continues to change.”
