Xcel Energy (NASDAQ:XEL) on Thursday announced plans to develop long-duration storage systems at two retiring coal plant sites, part of an accelerating timeline for transitioning away from coal as a fuel resource.
The Minneapolis-based company has entered into definitive agreements with clean energy developer Form Energy to deploy its iron-air battery systems in a pair of pilot projects. Xcel said the storage technology will allow it to integrate more renewable energy into its system and maintain reliability as it continues to retire coal plants in the coming years.
“We are starting to get on a treadmill of shutting down our coal plants,” CFO Brian Van Abel told financial analysts Thursday during the company’s year-end earnings conference call.
The 10-MW/1,000-MWh multiday systems — capable of providing 10 MW of instantaneous power for up to 100 hours — will be installed at the Sherburne County Generating Station in Becker, Minn., and the Comanche Generating Station in Pueblo, Colo. Both projects are expected to come online as early as 2025 and are subject to regulatory approvals.
“Our partnership with Form Energy opens the door to significantly improve how we deliver carbon-free energy,” CEO Bob Frenzel said in a statement.
The company remains on track to reduce carbon emissions 80% by 2030 and to deliver carbon-free electricity by 2050, Frenzel said. Pursuing advanced storage opportunities will “balance” Xcel’s system needs.
Xcel said in October it would quit burning coal by 2031 when it retires the final Comanche plant. It plans to shutter the 1.1-GW Tolk Generating Station in West Texas in 2028, more than four years earlier than planned. (See Xcel Energy to Quit Burning Coal in 2030.)
The company reported earnings for the year of $1.74 billion ($3.17/share), up from 2021’s performance of $1.6 billion ($2.96/share). Earnings for the fourth quarter came in at $379 million ($0.69/share), compared to $315 million ($0.58/share) for the same period a year ago.
The quarterly earnings were on par with Zacks Investment Research’s consensus estimate; the quarterly revenues of $4.05 billion exceeded the Zacks estimate of $3.54 billion.
Xcel’s share price closed the week at $68.43, off just 13 cents from its pre-earnings close of $68.56.
New York said Friday that its latest offshore wind solicitation drew a record level of response for an East Coast state: more than 100 proposals from six developers for eight new projects.
The New York State Energy Research and Development Authority, which is shepherding the state’s offshore wind buildout, said it would post summaries of the proposals after reviewing them. After the solicitation closed at 3 p.m. Thursday, five of the developers publicly announced their intentions.
“The high volume of quality proposals from leading global energy developers is a testament to the state’s ability to attract strong competition and significant investments in New York’s clean energy economy, ports and the development of long-term domestic supply chain,” NYSERDA said in an email. “Following a rigorous evaluation period, NYSERDA expects to announce the awards in spring 2023.”
Among the state’s priorities in this third solicitation was development of an in-state supply chain. One of the oldest names in the power industry, General Electric (NYSE:GE), will potentially help make that happen.
GE said Thursday that if there were enough orders for projects in New York waters, it would build two factories in Coeymans, 130 miles up the Hudson River from New York Harbor: one for nacelles, and one for blades for the next generation of GE’s Haliade-X offshore turbine.
Ørsted and Eversource Energy (NYSE:ES) already have contracted with Riggs Distler to build foundation components at the Port of Coeymans for their Sunrise Wind project.
At the nearby Port of Albany, a manufacturing plant for turbine towers is planned by a partnership that includes Equinor.
The move would be a reversal of sorts for GE, which was born in 1892 in Schenectady, not far from Coeymans. The conglomerate, which is now dissolving, long ago moved its headquarters out of Schenectady and has been shrinking its footprint there and elsewhere in upstate New York for decades through cutbacks, closures, spinoffs and business sales.
“As a leading manufacturer and innovator in developing renewable energy technology, GE is ideally positioned to help New York secure its vision of becoming a leading manufacturing hub for offshore wind technology,” Scott Strazik, CEO of the new GE Vernova, the company’s portfolio of energy businesses, said in a statement. “Our proposal leverages GE’s unique and unparalleled expertise, resources and track record — including a 130-year legacy of manufacturing in New York — to make this vision a reality in a durable and sustainable way.”
Notices of intent to submit proposals in this third solicitation were due Dec. 1. NYSERDA said it received notices from Attentive Energy, Bay State Wind, Beacon Wind, Community Offshore Wind, Invenergy Wind Offshore and Vineyard Offshore Wind.
Publicly announcing their intentions Thursday and Friday were:
Vineyard Offshore, which proposed two projects — Excelsior and Liberty Wind — with a combined capacity of 2.6 GW. They would entail the largest investment to date in the U.S. supply chain infrastructure for the young offshore wind industry and provide more than $15 billion in direct economic benefits, Vineyard said. The proposal is backed by Copenhagen Infrastructure Partners, with is building Vineyard Wind I off Massachusetts in a 50/50 venture with Avangrid.
Community Offshore Wind, a joint venture of RWE and National Grid Ventures, which said it would create more than 4,600 jobs, deliver more than $3 billion in economic benefits and collaborate with GE on the factories as it developed a 1.3-GW wind farm.
Leading Light Wind, a partnership between Invenergy and energyRE, which proposed a wind farm generating up to 2.1 GW of power and offering up to $13.3 billion in economic benefits to the state. Leading Light noted that it is the only American-led wind developer in the New York Bight, and that the two partner firms are developing the $11 billion Clean Path NY transmission project with the New York Power Authority.
Equinor and BP, already partners on Beacon Wind 1 and Empire Wind 1 and 2 off the New York coast, which submitted a proposal for a 1,360-MW installation in the Beacon Wind 2 lease area. In a news release Thursday, Equinor and BP said their plan would complement the 3.3-GW combined output of the three other wind farms and generate more than $11 billion in new economic activity statewide.
Ørsted and Eversource, already partners on South Fork Wind and Sunrise Wind off the New York coast, which submitted multiple bids with different configurations. The common factor, according to the companies, would be billions of dollars in economic activity, strides for economic justice, prioritization of disadvantaged communities and minority- and women-owned businesses, and furtherance of the state’s climate goals. Ørsted and Eversource are also partners in Bay State Wind.
FERC on Monday conditionally accepted the New York Power Authority’s (NYPA) proposal to revise its formula rate template in response to its need to bring on large amounts of clean generation.
In its filing with FERC, NYPA sought to “update the allocation methodology for administrative and general costs and expenses as well as depreciation and net plant costs for general plant (A&G), incorporate a transmission rate incentive and a cost containment mechanism for the Smart Path Connect Project, and make certain technical and clarifying improvements to the formula rate template,” the commission noted in the order (ER23-491).
A political subdivision of the state of New York, NYPA is classified as both a “municipality” and “state instrumentality” under the Federal Power Act. The agency has no specific service territory, but it generates, transmits and sells electricity at the wholesale and retail levels throughout New York. Since the creation of NYISO, NYPA has recovered the cost of its transmission facilities through the NYPA Transmission Access Charge (NTAC), which is assessed to most loads in NYISO on a load-ratio share basis.
In seeking the revisions, NYPA asserted that, because of New York’s aggressive climate change initiatives, the organization’s “business focus and investment profile has shifted such that transmission development and construction are the dominant activities,” meaning that the current “single factor ratio allocator is no longer the appropriate allocation.”
NYPA proposed using a “multifactor modified Massachusetts Method of allocation,” arguing that the method “uses an equally weighted average of direct labor, net plant, and net revenue ratios” and “has broad regulatory acceptance and aligns with utility practice.”
The Municipal Electric Utilities Association of New York (MEUA) disagreed, contending that NYPA “failed to demonstrate how the adoption of a multi-factor allocation of A&G costs is just and reasonable.” MEUA argued that using the Massachusetts Method “will likely assign a larger portion of A&G costs to the transmission function recovered in NTAC rates and less to its other profit centers.”
NYPA responded that the changes are simple “nomenclature changes” that would not “have material impacts” nor impose “A&G costs on NYPA’s transmission customers,” providing the commission no reason to rule against the proposals.
However, FERC said its preliminary analysis indicated that NYPA’s revisions might not meet its standard for justness and reasonableness and set the issue to a settlement judge hearing.
“We note that the proposed Formula Rate Template revisions to implement the proposed change in the A&G allocator go beyond NYPA’s assertion that the revisions are only changes in nomenclature or a non-ratemaking change,” the commission wrote. “Further, the incorporation of an allocation methodology is not an ‘accounting change,’ as NYPA asserts. Specifically, the proposed changes to the Formula Rate Template provide for a changed allocation of A&G costs to ratepayers and provide for changes to the Formula Rate Template that allow for the use of new inputs for those costs.”
The commission also pointed out that the Massachusetts Method is typically used by holding companies to allocate A&G costs between the non-revenue generating holding company and its subsidiaries.
“NYPA, however, is a corporate municipal instrumentality and a political subdivision of the State of New York. NYPA’s proposal includes no support for its claim that the Massachusetts Method is appropriate for its specific circumstances and structure,” the commission said.
FERC accepted NYPA’s filing for the proposed rate revisions, making them effective Jan. 23 but subject to refund pending the outcome of the hearing. The commission encouraged parties to the proceeding to reach a settlement before hearing procedures commence within 45 days of the order.
A trend of job changes and departures in California’s three major energy agencies has continued during the past two months, as officials opted to leave CAISO, the Public Utilities Commission and the Energy Commission, allowing Gov. Gavin Newsom to appoint replacements.
At CAISO, Governor Ashutosh Bhagwat opted not to seek another term after 12 years of service. Bhagwat chaired the Board of Governors last year; his most recent term ended Dec. 31.
“It has been a truly fantastic 12-year run, like nothing else I’ve had in my life,” Bhagwat said during the board’s last meeting of the year Dec 15. “I’ve enjoyed it thoroughly.”
The University of California, Davis, law professor plans to leave the board by the end of February or as soon as Newsom names his successor
At the CPUC, Commissioner Clifford Rechtschaffen chose to leave when his six-year term ended in December. Former Gov. Jerry Brown appointed Rechtschaffen, his senior adviser on climate and energy issues, to serve on the CPUC beginning in January 2017.
“My term at the CPUC was very rewarding, but I just turned 65, and I’m ready to move on to the next phase in my professional life, including doing some teaching again,” Rechtschaffen, a professor at Golden Gate University School of Law in San Francisco and graduate of Yale Law School, said in an email to RTO Insider.
On Dec. 22, Newsom said he was appointing Karen Douglas, his senior energy adviser and former member of the CEC, to fill the open CPUC seat left by Rechtschaffen.
A month later, Newsom’s office announced that CEC Commissioner Kourtney Vaccaro had been appointed technical adviser to Douglas at the CPUC. Vaccaro had served on the CEC since March 2022. She previously worked as Douglas’ top adviser at the CEC, where she had held multiple positions including chief counsel.
Newsom must next appoint a new CEC commissioner. The position requires confirmation by the State Senate, as do seats on the CAISO board and CPUC.
The series of personnel changes are similar to those that occurred in December 2021 and early 2022, when Newsom chose Douglas as his energy adviser, named Vaccaro to the CEC and appointed his senior energy adviser, Alice Reynolds, as the new CPUC president.
Earlier in 2021, Newsom appointed CEC Deputy Director Siva Gunda as a commissioner and chose then-CEC General Counsel Darcie Houck to fill an open spot on the CPUC, after he selected CPUC Commissioner Liane Randolph to head the influential California Air Resources Board.
Once the latest round of changes is complete, all five commissioners of the CPUC, four of five CAISO governors and the majority of CEC commissioners will be Newsom appointees. The governor has sought to exercise control over the state’s energy institutions with an aggressive climate agenda and efforts to keep the lights on following rolling blackouts ordered by CAISO in August 2020.
WASHINGTON — The United States Energy Association on Thursday gathered senior leaders of the major trade associations at the National Press Club, where they focused on implementing major energy legislation passed last year and many argued for reforms to permitting processes.
The passage of the Infrastructure Investment and Jobs Act and the Inflation Reduction Act gives the energy industry plenty to implement, but Edison Electric Institute President Thomas Kuhn said Congress still needs to pass more legislation to make the investments those laws promised a reality.
“One of the things on our priority list is siting and permitting,” Kuhn said. “If you want to have the benefits of the two major legislative initiatives over the past couple years, you’ve got to be able to do siting and permitting more efficiently.”
While changes to energy project permitting laws have some bipartisan support, different interest groups have their own ideas, and it will be challenging to bring them together and get something done, he said.
The electric industry has made significant cuts in its emissions over the last 10 years and many utilities have plans to clean up even more in the coming decades, but Kuhn warned against getting rid of all fossil fuels too quickly. With so much changing now, it does not make sense to take a major source of energy away all at once, he said.
“Some people want to take natural gas away,” Kuhn said. “You know, I’ve got to tell you, if you want to do this job and you want to do it reliably and mildly affordably, you’re going to need natural gas. It’s that simple.”
Generators switching from coal to natural gas have helped bring emissions down to 30-year lows, American Gas Association President CEO Karen Harbert said. The gas industry has been trying to clean up and working to cut its methane emissions, she said.
“If the conversation is about reducing emissions, we’re all in,” Harbert said. “If the conversation is about putting us out of business, not so much. Because there is no way to address energy security, environmental progress, economic security and national security without natural gas in our system.”
Interstate Natural Gas Association of America CEO Amy Andryszak argued that many states are enacting policies that favor renewable energy while discouraging new sources of natural gas that would help balance those resources.
“We know the Northeast is supply-constrained — not due to a lack of available natural gas in the United States,” Andryszak said. “Actually, we have the Marcellus right next door. But regulatory decisions and bad policies have contributed to this problem.”
INGAA supports “smart policies” aimed at reducing carbon emissions, but, echoing Harbert, Andryszak said if the conversation is really about eliminating natural gas, then the pipeline trade group is against it.
One major policy Congress has to deal with is the debt ceiling, said American Petroleum Institute CEO Mike Sommers, who was involved in such discussions as a senior staffer for Republican congressional leaders in the 2010s.
“There are big things that could get done, like permitting reform on a bipartisan basis, potentially as part of the way that we get the debt ceiling lifted as well,” Sommers said. “So, I’m optimistic that this is going to get done. I think we should all get used to some panic moments. But I’m confident that our leaders are going to get this addressed in a timely fashion.”
Germany now has five LNG terminals after it worked to replace the Russian-supplied natural gas that it embargoed after the invasion of Ukraine.
“And they built one of them in six months, when the typical receiving terminal is a two- to three-year time period,” Electric Power Research Institute CEO Arshad Mansoor said. “So, they figured out when there’s a necessity permitting can be streamlined.”
Germany has been a leader in moving to renewable energy, but it also has avoided completely retiring coal plants; that decision proved prescient this winter as they had to be used much more often than when the country was awash in cheaper Russian gas, he added.
“I think it’s a general belief that for all of us in the research community [and] in the technology community, that we must have optionality in our clean energy transition,” said Mansoor.
Natural gas plants are still relatively young when it comes to infrastructure, and Mansoor said that early studies have found that they could run blends of 20% or 40% clean hydrogen to minimize their emissions while maximizing their usefulness to the grid.
The industry has to prepare for more extreme weather and do so ahead of time, Mansoor said. While utilities have often done well upgrading their systems after a natural disaster, climate change means extreme weather will be more common.
“How do you proactively make that investment?” Mansoor said. “Don’t wait for the flood; anticipate weather in 2030, 2045, … and start building infrastructure for that weather.”
The Southern Renewable Energy Association (SREA) said Thursday that the Duke Energy Carolinas and the Tennessee Valley Authority Christmas Eve blackouts were likely avoidable had they built more robust transmission links and had better access to organized wholesale markets.
SREA Executive Director Simon Mahan | SREA
SREA Executive Director Simon Mahan said during a briefing focused on the Southeast region’s performance issues and rotating blackouts during the December winter storm that the region contains a “balkanized, separated grid” where each utility must balance their own system without a shared resource pool to fall back on. (See FERC, NERC Set Probe on Xmas Storm Blackouts.)
“With better connections with our neighbors, we can avoid blackouts,” he said.
The load shed was a first for both TVA and Duke.
Mahan drew parallels between the recent winter storm and the more severe storm in February 2021. He predicted the Southeast will receive much of the attention for its performance in December because it’s isolated from a regional grid, as was — and still is — ERCOT two years ago. TVA and Duke need to build better transmission to prevent future outages and grid-scale failures, Mahan said.
TVA and Duke Energy both had major power outages about the same time on Dec. 24, Mahan said. He added that both imported significant amounts of power from organized wholesale markets to avoid a more dire situation.
Duke reached its highest emergency level and initiated rolling outages that same day. Mahan noted North Carolina’s northeastern corner remained stable because it is in the PJM footprint.
“While much of the state was under rolling blackouts, that corner of the state was not experiencing blackouts,” he said.
TVA at times imported more than 5 GW from MISO on Dec. 23 and 24, Mahan said. Those exports helped trigger the RTO’s own maximum generation event, setting off stakeholder debate on how far it should stretch its system to assist neighbors. (See MISO Actions During December Storm Spark Debate.)
According to the North Carolina Utilities Commission (NCUC), Duke was negatively impacting the entire Eastern Interconnection’s frequency on Dec. 24. Mahan said Duke was close to setting off “significant and widespread” outages like the 2003 Northeastern blackouts.
“The situation was really quite dire before they decided to start causing the rolling blackouts,” Mahan said.
Duke Carolinas under-forecasted demand by as much as 1.5 GW on Dec. 24, while Duke Energy Progress East had an even larger forecast gap at 2.8 GW, Mahan said.
The bitter cold proved “really difficult for the company to come back from,” he said, noting that Duke was not able to resume normal operations until nearly midday Dec. 26. Had it not been for solar generation’s strong performance on Dec. 24, Mahan said, Duke would have been thrown further into “dire straits.”
He said after analyzing preliminary import and export data from the Energy Information Administration, the Southeast region’s system may have been “so taxed and so overburdened” that loop flows materialized.
Mahan said state regulators should investigate the event and make findings public. “We need to get a better sense of what actually happened,” he said.
Mahan said the region had indications that its grid and thermal generation would struggle during the storm. He said the wave of intense cold Dec. 23-24 fulfilled predictions meteorologists forecasted a week earlier.
“We should have been more prepared. We’ve seen it before. It’s happened before,” he said.
Mahan said the main difference between the two recent winter storms is that the December event had a “more direct bullseye” on the Southeast. He said he hoped more attention is paid this time to actionable changes.
Mahan said the Southeast needs more regional and interregional transmission connections; it’s imperative, he said, that Duke and TVA also diversify their generation mixes by adding more wind, solar and battery storage than natural gas plants.
Duke and TVA would have benefitted from larger solar fleets in this instance because sunshine was surprisingly plentiful during the event, Mahan said. He said as fossil plants struggled to be available on Christmas Eve, more solar generation would have shortened the length of the blackouts or made the outages less severe.
Chris Carmody, executive director of the Carolinas Clean Energy Business Association, said Duke would be better served if it “connects with a pack of states next door who don’t have blackouts.”
Duke Energy Carolinas CEO Julie Janson appeared before the NCUC Jan. 3 to apologize and vow the utility would learn from the experience.
“We own what happened,” she said. “We have set out on a path to ensure that if we are faced with similar challenges, we will see a different outcome and provide a better customer experience.”
Duke spokesperson Jeff Brooks told RTO Insider that the company “employed thousands of megawatts” during the storm. He said solar was added when it became available, but that it “was not generating at the time temporary outages were required as the sun was not up.”
Brooks said resources that Duke was counting on “included deliveries of generation from independent power producers and purchases through our out-of-state interconnections that were not fulfilled for use on Dec. 24 due to other utilities experiencing the same challenges.”
He said RTO membership “would present more risks than benefits to our customers and our state.”
TVA has launched an internal investigation of its actions and has also pulled together an independent, three-person panel to separately review how it can better prepare for severe weather. The panel includes American Public Power Association President Joy Ditto; Mike Howard, former CEO of the Electric Power Research Institute; and former U.S. Sen. Bob Corker (R-Tenn.).
“This is not the way we want to serve our communities and customers,” TVA said in a press release late last month.
TVA said it had nothing more to add when RTO Insider requested a reaction to SREA’s recommendations.
Mahan said the Southeastern Energy Exchange Market (SEEM) didn’t appear to assuage the situation like an RTO could have.
“There should have been more willing purchasers on Dec. 23, but the market showed that it had even less purchases from the day before,” he said.
In fact, Mahan said that SEEM’s records showed no voluntary trades of excess power Dec. 24-26. He said that was “highly unusual,” but that it’s difficult to get a sense of what happened because SEEM isn’t a transparent operation.
“It wasn’t helpful at all for many days, which was very unfortunate,” Mahan said.
“It’s designed to do so little in the first place. There’s just not much to it,” Carmody said of SEEM’s structure.
Gas-electric coordination is becoming the “Achille’s heel of the energy transition,” says ISO-NE CEO Gordon van Welie.
Van Welie gave his perspective at NERC’s Reliability Leadership Summit in Arlington, Virginia, Wednesday, where speakers also discussed challenges related to physical security, cybersecurity and energy security.
New England has faced issues with natural gas supplies going back decades, but van Welie said grid operators in other regions are starting to see similar issues crop up.
For now, natural gas is important to balancing renewables and ensuring the region can make it through the winter peak when its pipeline system is maxed out and natural gas utilities have priority because they pay for firm capacity.
“I think the primary vulnerability in this pillar is the premature retirement of resources that can provide this balancing energy,” said van Welie. “And in the longer-term, the risk that there will not be sufficient investment in balancing resources as electrification drives load growth.”
Natural gas is still the largest input of energy into the grid, but the two industries are not planned together at all, said van Welie.
“The fixed-costs of long-term firm gas transportation and storage infrastructure are largely not recoverable through the wholesale electricity markets,” he added. “So, merchant generators in these FERC-regulated markets can recover the commodity costs, but they have very poor incentives, or no regulatory requirement to ensure that there’s sufficient gas transportation capacity, or storage, to meet their peak demand, particularly under these extreme weather conditions. Conversely, pipeline developers will only build capacity for customers that are willing to sign long-term, firm transportation agreements.”
Generators’ demand for natural gas is going to become increasingly “peaky” as renewable resources grow and the gas industry’s current rules are not capable of planning around that, van Welie said, calling it the “Achille’s heel of the energy transition.”
In July, FERC and NERC asked the North American Energy Standards Board (NAESB) to look at whether any new standards could bridge the gulf between the different business models of the two increasingly interconnected businesses. (See NAESB Confirms Gas-electric Forum in the Works.)
“NAESB isn’t going to be able to solve [all of] these things,” said its Chairman Michael Desselle, who is also a vice president at SPP. “And what we’re learning … as the gas industry is working together with the electricity industry, is that there are potentially some things we can do.”
From left: Kamyar Ghaderi, ISMS Lead Auditor; Rob Lee, CEO of Dragos; Tabice Ward, Vice President Xcel Energy; Puesh Kumar, Director, CESER at Department of Energy; and Manny Cancel, NERC Senior Vice President and CEO, E-ISAC | NERC
The two industries could step up information sharing, especially during extreme weather, and they could make some small changes to their market structures to improve coordination.
“There’s a whole bunch of other things, quite frankly, that we are not going to be able to solve,” said Desselle. “They are going to be policy matters that we’re going to eventually — when we put our report together — tee up for policymakers to make decisions on.”
Ultimately it comes down to how much consumer money should be spent to ensure enough natural gas is available when needed, he said.
While NAESB might be able to make some small improvements around the margins, the two industries are coming into that debate wanting to protect their own economic interest, said van Welie.
“My one wish would be to see FERC step up and take a harder look at this to figure out how we solve this problem,” he added.
FERC could require the gas industry to build out pipelines to meet electric generators’ demand, but that leads to thorny cost allocation issues. The other way would be to require generators to procure firm transportation, but that could lead to even more costs as the pipelines would be overbuilt, said van Welie.
“The gas use is going to go down over time,” he said. “But when we have a polar vortex, a winter storm Uri [or] Elliot coming into town, then you’re going to have this massive demand on the system and you’re going to have to have to supply that demand.”
‘Job 1’
Acting FERC Chairman Willie Phillips opened the summit calling reliability “job No. 1” at his agency.
“When I think about why reliability is No. 1, I think back to August 2003,” Phillips said. “This is the 20th anniversary of the 2003 blackout. We had reports say in three minutes, 21 power plants went down because of computer error related to vegetation management and what could have been a local issue became a cascading outage on our system impacting over 50 million people.”
The blackout had a huge economic cost and inconvenienced a large chunk of the country, but what really drove the importance of reliability home is the fact that 100 people died, said Phillips.
Crossing the Rubicon
Ten years ago, it would have been much harder for hackers to cause physical damage on the grid. But increasing digitization and the changing resource mix have made that a reality in other countries and it could happen here, Dragos CEO Robert M. Lee said.
Previously, attacks would focus on one area of the electric system, which gave the industry plenty of time to react. But last year new hacking software called “Pipedream” was discovered that can be reused across different industrial control systems with the ability to scale and repeat.
“It feels very much that we’ve sort of crossed that Rubicon into how we’re going to have to deal with that,” said Lee.
The pace of vulnerabilities coming at the industry is “unbelievable,” said NERC Senior Vice President Manny Cancel, CEO of the Electricity Information Sharing and Analysis Center (E-ISAC).
“The number of vulnerabilities that [the National Institute of Standards and Technology] tracked last year was over 23,000 vulnerabilities,” Cancel said. “So, if you do the math, that’s 60 vulnerabilities a day.”
Attempting to deal with those alone would be an overwhelming task, but the industry must defend itself from more aggressive and active hackers from state adversaries, he added.
The Director of National Intelligence said that foreign governments have been hacking into the electric system and mapping the network, said Puesh Kumar, director of the Department of Energy’s Office of Cybersecurity, Energy Security and Emergency Response.
“And what that reminds me about is if they’re mapping our network, have we mapped our network well enough to know what’s out there?” he added. “And that’s something really critical that we have to be thinking about: If our adversaries are doing this, how well do we know our networks and our systems to prevent what they might be planning?”
Cyber-informed Engineering
The grid is becoming more connected, which can bring increased reliability and efficiency, but it also gives cyber attackers more endpoints that they could potentially leverage.
“It’s a very complex problem, because we need to do the reliability, we need to do the efficiency, but you got to do the security with it as well,” Kumar said. “And so, [what] we’re championing is cyber-informed engineering. So, as we engineer the grid of the future, we have to do that with cybersecurity in mind.”
No Longer a ‘Six Pack and a Shotgun’
Physical attacks have been on the rise as well, said Bonneville Power Administration CEO John Hairston. It is not just the “typical vandalism” where someone with a “six pack and shotgun” just wants to “see something arc.”
“They’re more targeted, they’re focusing in on, you know, the IT infrastructure, and they’re looking to take down a system for a long period of time, with a mass outage,” Hairston said.
It can take 18 months to two years to replace a damaged substation, and doing so relies on foreign manufacturing, said Mike Wise, senior vice president of regulatory and market strategy for Golden Spread Electric Cooperative.
“Years ago, we determined [that physical attacks were] one of the highest risks,” said Wise. “And so, we went out and purchased to make sure we had a backup step-up transformer for every type of step-up transformer in our generation fleet.”
CARMEL, Ind. — MISO and SPP said Thursday during their annual issues review that they plan to treat Joint Targeted Interconnection Queue (JTIQ) projects as large generator interconnection projects when allocating costs.
The RTOs have proposed allocating 90% of the portfolio’s costs to interconnecting generators and the remaining 10% to their load. SPP’s load will be responsible for 71% of costs, and MISO will shoulder the remaining 29%.
The JTIQ study completed early last year resulted in five projects on the RTOs’ seam that should help reduce congestion and allow additional resources, primarily wind farms, to interconnect with their systems. The portfolio has an estimated cost of $1.06 billion. (See MISO, SPP Propose 90-10 Cost Split for JTIQ Projects.)
Sumit Brar, reliability analysis lead for MISO long-range planning, said the grid operators will not begin additional JTIQ studies unless the first portfolio has secured enough generation to cover most or more of its costs. Future studies will be conducted on a five-year horizon.
MISO expects the first JTIQ portfolio to support up to 28 GW of interconnecting generation on both sides of the seam.
MISO stakeholders expressed worry that the necessary amount of generation may drop out of the two IC queues, leaving load to handle the bag of costs. Some have also said a 90% cost assignment to interconnecting generation might not be fair.
They asked whether the RTOs might consider adding a cost cap on the per-megawatt charge or enact protections when generation requests drop out of the queue.
“Now, there will be dropouts, so we expect that,” MISO Director of Resource Utilization Andy Witmeier said, adding that the RTO expects it will take “a few queue cycles” to get the lines nearly funded.
Witmeier said it’s “unrealistic” to assume that the grid operators won’t have enough willing generation developers to fully fund the projects.
“Eventually, enough generators will sign up, sign [generator interconnection agreements] in the region,” he said.
The RTOs are proposing that generation be on the hook for a JTIQ per-megawatt cost when a project has a greater than 5% distribution factor on one or more facilities in the affected system and a greater than 1-MW impact on “at least one” JTIQ line.
Steelhead Americas’ Adam Solomon said the threshold was “ridiculously low” when compared to the large interconnection projects in the MISO queue.
MISO and SPP said they don’t plan an interregional planning study this year, saying their plates are full memorializing the targeted market efficiency projects (TMEPs) work and preparing for an expected FERC notice of proposed rulemaking on interregional transfer capability. MISO said its planners are also working on the second tranche of its long-range transmission plan.
The grid operators are required to undertake a coordinated system plan every other year. Last year, the two performed a TMEPs study that failed to identify any small interregional projects. (See MISO, SPP Unable to Find Smaller Joint Tx Projects.)
Basin Electric Power Cooperative had asked the RTOs to study constraints in the Dakotas, and Ameren has requested an examination of chronically congested 161-kV lines and a transformer linked to a 345-kV line in Missouri.
DOE Funding for JTIQs Won’t Affect Cost Allocation
MISO said Tuesday that potential Department of Energy funds will not affect a planned cost-sharing plan for the JTIQ projects.
The program requires that states affected by a project make the application process. Great Plains is organizing stakeholders and coordinating the multistage GRIP application process.
Brar said states with a JTIQ project are all involved. Funding will be granted to states based on the percentage of projects located within their boundaries.
The organizations sent a concept letter to the DOE earlier in January. The DOE will inform applicants by Feb. 24 whether their projects are sufficient enough for a full application that would be due May 19. Approved GRIP projects could potentially be awarded a 50% project match. (See SPP MOPC Briefs: Jan. 17-18, 2023.)
Grid modernization (GM) investments encompass myriad technologies that digitize a utility’s distribution system. They have the potential to improve the reliability of the electrical grid, better integrate alternative energy, and enable pricing that reflects the marginal cost of generation.
The present grid was designed when power plants in central locations exclusively controlled a one-way flow of electricity to customers. A modern grid has the ability to accommodate greater consumer control and two-way flows of power.
Experience has shown that achieving public-policy goals at bearable cost to society frequently requires technological breakthroughs. Many experts assert that making the transition to a clean-energy future at an affordable or politically acceptable cost will demand new technologies, such as those rooted in GM.
It seems then that it is a slam dunk for state regulators to approve utilities’ plans to modernize their distribution systems, even if the cost is high. But, to no surprise, things are rarely as certain as they seem. Public utility commissions face a formidable challenge in ensuring that utility investments in GM advance the nebulous public interest or are cost-beneficial.
Pressure for GM comes from different quarters: electric utilities, Wall Street, clean air and climate advocates, GM technology vendors, consultants, labor unions, and state and federal politicians and bureaucrats. Utility managers themselves favor GM mainly because it will accommodate additional demands from electric vehicles and households for electric space and water heating (i.e., electrification).
Proponents of GM vastly outnumber both skeptics and opponents, making it challenging for regulators to reject GM plans proposed by utilities. We know that strong pressure from special interest groups with political clout can persuade policymakers to decide in their favor, even though it would be detrimental to society overall.
Since utility customers are the eventual payers of GM investments, the critical questions that PUCs need to ask themselves, are whether (1) the total benefits from GM to utility customers exceed the costs and (2) low-income households will overpay given that higher-income households will disproportionally benefit from purchases of electric vehicles and rooftop solar systems that GM tries to accommodate. Just because a Tesla is technologically superior to conventional vehicles does not mean that it is the right choice for everyone. It’s costly, and some car drivers might consider the technological benefits to be nominal.
I have seen too often where utility customers pay through their rates for utility investments directed at benefitting a special interest with political influence; that is, customers funding the advancement of political objectives through inflated rates without compensatory benefits. I ask whether we are seeing a repeat of this for GM investments. Or as one industry observer expressed to me, “Is grid modernization another way to line utility pockets and promote renewable energy and kill fossil fuels?” While this opinion seems extreme, it may not be so far-fetched.
There is great uncertainty over the benefits and costs of GM investments. Costs overruns are common, and benefits are difficult to quantify and require different methods of varying complexity.
A serious problem is a utility’s capital bias combined with laxed regulatory cost controls. Under traditional regulation, utilities collect capital costs only after the regulator considers them prudent or reasonable; utilities would be allowed to collect them only after a general rate case.
But for various reasons, regulators have accepted new cost-recovery approaches. Both utilities and climate activists have pushed for quicker and more certain capital-cost recovery when it comes to certain technologies like GM that advance their agenda. Wall Street has also supported these new approaches, fashioning an Iron Triangle that makes it difficult for PUCs to reject them.
Utilities should be held accountable for subpar performance from GM investments. These investments have often fallen short of achieving the benefits promised in utilities’ plans.
There is evidence that reliability has not improved in states that have so far invested the most in GM. Critics have also questioned whether it is too soon to replace the current infrastructure.
Advanced metering infrastructure (AMI) has in some jurisdictions failed to realize expected dispatch efficiencies and cost savings. Most utilities have also under-exploited the ability of AMI to enable granular time-of-use rates (e.g., real-time pricing, electric vehicle charging rates) that can produce large efficiency gains.
Another problem recognized by PUCs is utilities proposing to make large-scale, multitechnology investments, some of which have questionable, ill-defined benefits that are unlikely to transpire for several years.
PUCs should not outright reject a GM plan just because it would require an increase in electricity rates or be prejudiced against a plan in spite of the evidence; or accept a plan just because it will support a popular clean energy agenda, while ignoring the effect on utility customers. There is danger that either of these scenarios can happen and probably has already in some states.
The experiences across states have shown that the benefits from GM plans are often overstated and costs understated. The burden falls on PUCs to ensure that this does not happen. Unaccountability by utilities for their large investments can have a devastating effect on customers and society as a whole. Getting the incentives right is the key element for achieving socially desirable GM investments.
Kenneth W. Costello is a regulatory economist and independent consultant. He previously worked for the National Regulatory Research Institute, the Illinois Commerce Commission, Argonne National Laboratory and Commonwealth Edison Co.
The Inflation Reduction Act’s electric vehicle tax credits sparked a spirited debate on the Senate floor Thursday as Sen. Debbie Stabenow (D-Mich.) resisted Sen. Joe Manchin’s (D-W.Va.) call for swift passage of a bill that could put a hold on the credits for some EV buyers.
Manchin’s American Vehicle Security Act would force the Internal Revenue Service to put the IRA’s domestic content provisions into effect retroactively, as of Jan. 1. The IRA required the agency to issue guidelines for the tax credit by Dec. 31, but the IRS only issued partial guidelines, delaying action on the domestic content provisions until March and triggering Manchin’s efforts to force the agency’s hand. (See Treasury Delays Key Rules for IRA’s EV Tax Credits.)
In the interim, the IRS has said EV buyers can qualify for the full $7,500 tax credit offered in the IRA, without complying with domestic content rules. If Manchin’s bill were to become law, some of those cars might no longer qualify.
Sen. Debbie Stabenow (D-Mich.) | C-SPAN
“Why the IRS did not do their job, I can’t tell you, unless their intent was never trying to comply with what we passed,” Manchin said, moving for his bill to skip a hearing in the Senate Finance Committee and go straight to a floor vote.
Framing the IRA as an “energy security manufacturing” law, Manchin said the domestic content provisions are intended to spur the buildout of a U.S. supply chain for EVs, countering China’s dominance in the EV global market.
“We’re moving rapidly into the EV markets — and I think, recklessly — as we were going into that before we were able to supply [domestic production] and be held captive by China,” he said. The U.S.’s main economic competitor now controls 80% of the world’s battery materials processing and 75% of lithium-ion battery production, he said.
Stabenow had no argument with Manchin on building out a domestic EV supply chain and cutting U.S. dependence on China. But she said the EV tax credit in the IRA “is confusing. It was not well vetted. It is not supported by anyone in the auto industry.”
Objecting to Manchin’s motion for a quick vote on the bill, Stabenow said, “This does not create any path for success for American automobile workers, for American automobile companies, for suppliers, for consumers who are interested in being able to purchase electric vehicles and benefit from a credit.”
She also defended the IRS decision to delay rules on the domestic content provisions as “not unreasonable. … They have been given, I believe, an incredibly complicated task to try to figure out how this consumer credit will work for consumers and for companies and workers,” she said.
The domestic content requirements simply don’t work “on a practical level,” she said.
The Senate recessed without acting on Manchin’s motion.
GOP Support Uncertain
Facing opposition from his fellow Democrats, the bill’s prospects for passage are slim. But Manchin is seeking GOP support, enlisting Rep. Mike Braun (R-Ind.) as a co-sponsor.
Backing up Manchin on Thursday, Braun said he had not supported the IRA. But he said the new bill “is not just about promoting our own manufacturing, which we need to do better generally. It’s also about not funding the human rights abuses of the Chinese Communist Party.”
Sen. Mike Braun (R-Ind.) | C-SPAN
Indiana snagged a major EV battery manufacturing project in May, when Stellantis and Samsung announced plans to invest $2.5 billion in a plant in Kokomo. Delaying the domestic content provisions “sends a bad message to people in our own country about making the investments, and clearly in my own state, there’s a vested interest,” Braun said.
Whether other Republicans will sign on is less certain. Industry analysts ClearView Energy Partners said that even if some Republicans agree with Manchin’s focus on domestic manufacturing, they may be reluctant to sign on because the IRA also links some of its tax credits to “labor-friendly” provisions on prevailing wages and apprenticeships.
“Accordingly, we think Republicans may be leery of backing Manchin’s modification because it could be viewed as a tacit endorsement of the IRA,” ClearView said in an email note on Wednesday.
Opposition from the auto industry is almost certain, with many automakers already concerned about consumer and dealer confusion about the EV tax credit, according to John Bozzella, president of the Alliance for Automotive Innovation, an industry trade group.
“We want to make sure we don’t increase confusion for customers who might be confused already about what qualifies for a tax credit,” Bozzella said. “So I’m not quite sure what the value of the new legislation is.”
Placating Europe
The IRA’s $7,500 EV tax credit is broken down into two parts. Consumers purchasing a new EV may qualify for half the credit if the car’s battery components are at least 50% manufactured and assembled in the U.S. To qualify for the other half, 40% of the critical minerals in the battery, such as lithium or cobalt, must be sourced either in the U.S. or a country with which the U.S. has a free trade agreement.
The law also limits eligibility for the credit based on an EV manufacturer’s suggested retail price (MSRP) and a buyer’s annual income. The MSRP for EV sedans is capped at $55,000 and for SUVs, at $80,000. The income cap for individuals is $150,000 per year and for couples, $300,000 per year.
Beyond causing confusion at home, the EV tax credits and the IRS delayed guidelines on domestic content have also riled European automakers and their governments, who see the incentives as drawing vital investment dollars away from their countries. Despite being one of the U.S.’s major trading partners, the EU does not have a fair-trade agreement with the U.S., meaning its EVs would not quality for the tax credits.
Speaking at the Washington, D.C., Auto Show on Jan. 19, EU Ambassador Stavros Lambrinidis warned that the IRA could set off a “subsidy war” as both the U.S. and EU put billions into transportation decarbonization. (See Tracking the Contradictions of the US EV Market at the DC Auto Show.)
“That’s a danger because the IRA, the way it’s structured, in a sense is endangering investment in Europe. It is sucking away investment potential, especially at a time of very high energy prices,” Lambrinidis said. “Nothing could be worse for the strength of the U.S. economy and U.S. companies than a weak European economy.”
While still working on the domestic content guidelines, the IRS has an online list of EVs and plug-in hybrids it says are qualified for a $7,500 tax credit. Popular U.S. brands — including Ford’s F-150 Lightning, Chevy Bolt and Tesla’s Model 3 and Model Y — are on the list.
The IRS says many foreign automakers have “entered into a written agreement with us to become a ‘qualified manufacturer’ but [haven’t] yet submitted a list of specific makes and models that are eligible.”
The agency may have provided an opening for foreign models that are leased by individuals. In a recent fact sheet, the IRS identifies leased vehicles as eligible for the commercial EV tax credit, which is not subject to the domestic content requirements of the IRA.
The situation has been difficult for the White House, trying to move ahead with IRA implementation while also trying not to alienate the EU, where Manchin’s bill could be seen as adding more fuel to the fire.
But, in a now-divided Congress, Manchin does not have the leverage he had when Democrats controlled both houses and he was a key swing vote in the Senate.
“In the context of a divided Congress, however, the status quo puts [the IRS] in the driver’s seat,” ClearView said. “Not only does the administration have less to lose by overtly countering the Manchin bill, but the White House might be able to placate allies simply by staying silent and letting partisan divisions quash the measure.”
