A Nevada mining project that could produce enough lithium for 370,000 electric vehicles a year has received a conditional loan offer of $700 million from the Department of Energy.
The funds would go toward Ioneer’s Rhyolite Ridge lithium-boron project in Esmeralda County, Nev. If finalized, the loan would finance the on-site processing of lithium carbonate.
Ioneer said a term sheet for the DOE loan had been finalized, with a loan of up to $700 million and a term of 10 years. The conditional commitment indicates DOE expects to support the project, subject to conditions such as legal, contractual and financial requirements, Ioneer said.
Ioneer Managing Director Bernard Rowe called the proposed loan “the most significant milestone in the history of the company.”
“The term sheet and conditional commitment from DOE demonstrates its strong support for the Rhyolite Ridge project and, if finalized, the loan would be the first-ever by the DOE to provide financing for the processing component of a project where lithium is extracted and refined at site,” Ioneer said this month.
The loan would be made under DOE’s Advanced Technology Vehicles Manufacturing loan program. Lithium is a key component of EV batteries, and DOE estimates the loan could support lithium production for about 370,000 EVs each year.
Developing a U.S. supply chain for critical materials such as lithium is a national priority, according to DOE.
“Onshoring the critical materials supply chain is an important step toward energy independence, lower costs for American consumers and protection from global supply bottlenecks,” DOE said in announcing the loan.
Production in 2026
Demand for lithium is surging as EV adoption grows. The top lithium-producing countries are Australia, Chile and China. Interest in domestic lithium production is strong, but the U.S. has only one lithium mine in operation: Albemarle’s mine at Silver Peak in Nevada.
Ioneer described Rhyolite Ridge as the most advanced undeveloped lithium project in the U.S. Production at the facility is expected to start in 2026.
The project will be a drill-and-blast operation. Lithium and boron products will be made through a process with zero CO2 emissions from electricity generation, the company said.
Boron, in the form of boric acid, will account for about 30% of the project’s revenue. Boron has a wide range of industrial uses, and Ioneer said the co-production of boron will help the company keep its lithium costs down.
Ioneer is partnering with Sibanye-Stillwater, a global mining and metals processing company that has committed $490 million for a 50% stake in the Rhyolite Ridge project.
And Ioneer has offtake agreements with three entities so far. EcoPro Innovation plans to use lithium carbonate from Rhyolite Ridge at its South Korea battery plant. In July, Ioneer signed agreements with Ford Motor and Prime Planet Energy Solutions, which is a joint venture between Toyota and Panasonic.
Permitting Process
In December, the Bureau of Land Management published a notice of intent to prepare an environmental impact statement for the Rhyolite Ridge project. Ioneer called the notice a major milestone toward finishing the permitting process.
The Nevada Department of Environmental Protection issued a water pollution control permit for the project in 2021.
The company has also taken steps in response to the listing of Tiehm’s buckwheat as an endangered species. The plant is found at Rhyolite Ridge.
Ioneer has spent $1.2 million on research to preserve the buckwheat and revised its operations plan to avoid direct impacts to the plant. A Tiehm’s buckwheat greenhouse has been built and is now in operation.
DOE said the Rhyolite Ridge project is expected to be in operation for 26 years, although Ioneer said on its website that there is “significant potential for this to increase.” After operations are finished, the land will be reclaimed and revegetated, according to DOE.
Canadian long-duration energy storage company Zinc8 Energy Solutions plans to build its first factory in Kingston, N.Y., the company and Gov. Kathy Hochul announced Thursday.
The firm’s five-year, $68 million plan calls for it to be the anchor tenant in iPark87, a sprawling former IBM campus. The state will provide up to $9 million in tax credits through its Excelsior Jobs Program (EJP), contingent on Zinc8 creating up to 500 jobs there.
Zinc8 CEO Ron MacDonald announced in September that the company would set up manufacturing in the U.S. to take advantage of the recently approved Inflation Reduction Act’s tax credits for domestic production of its zinc-air energy storage system.
The Zinc8 ESS is a modular design, adaptable to numerous configurations with the same subsystems. Because its capacity is determined solely by the size of the zinc storage tank, it is readily scalable from 20 kW to 50 MW and can provide eight or more hours power, the company says.
Zinc8, a small operation in Vancouver, is in the pre-commercial/demonstration phase of the technology for which it holds 21 patents and has five more patents pending. It hopes to begin production in 2024 and start scaling up in 2025.
Zinc8 Energy Solutions’ zinc-air long-duration energy-storage battery system is shown. | Zinc8 Energy Solutions
The company has been on New York’s radar as the state moves to slash its carbon footprint and build a clean-energy economy.
The New York Power Authority selected it as a winner in an innovation challenge for its proposal to build a 100-kW/1-MWh demonstration project at the University at Buffalo, and the New York State Energy Research and Development Authority provided a grant to defray the cost of its 100-KW/1.5-MWh demonstration project at a New York City apartment complex.
The company joined Scale For ClimateTech, the New York City-based manufacturing accelerator supported by NYSERDA. And U.S. Senate Majority Leader Chuck Schumer (D-N.Y.) pitched the Kingston site to MacDonald in July 2022.
Hochul recently announced a goal of installing 6 GW of installed energy storage capacity in New York state. MacDonald said in a news release that New York’s push for green energy, and storage in particular, helped Zinc8 decide to locate its factory there.
“We’re excited by the level of support and interest we’ve received towards locating a manufacturing facility and creating jobs in the state of New York,” he said. “The EJP tax incentives offered to companies looking to create jobs and help build a green economy is an additional layer of funding that can be utilized concurrently with other financing, including state, municipal and federal funding packages, which help companies like Zinc8 access additional sources of capital and expand their business plans.”
“Creating good jobs that will lead to a greener, more sustainable New York for our children and grandchildren is not only beneficial to our economy; it’s the right thing to do for our planet,” Hochul said In her own news release. “Zinc8’s cutting edge, clean energy storage technology is another tool that will allow us to achieve our bold climate agenda and continue to make New York state a leader in advancing the green economy.”
SPP’s Markets and Operations Policy Committee on Friday approved two revision requests related to resource adequacy requirements that members had set aside during their regular quarterly meeting earlier this month.
The special conference call became necessary when MOPC deferred action on the RRs after several late changes were shared with members the night before the January meeting began. The committee directed SPP staff and the Market Monitoring Unit to re-engage with stakeholder groups to ensure members still agreed with the changes. (See “Members Defer on PRM Deficiency RRs,” SPP MOPC Briefs: Jan. 17-18, 2023.)
“We’ve kind of taken them on a roadshow,” the MMU’s John Luallen told MOPC during the call.
Taken together, RR536 and RR537 would provide load-responsible entities with a short-term, non-punitive alternative approach to deficiency payments for the summer resource adequacy requirement (RAR). Staff have been working on the mitigation strategy since July, when SPP increased the planning reserve margin (PRM) from 12% to 15%, effective this year. That left some members complaining they would not have enough time to meet the requirements. (See SPP Board of Directors Briefs: Dec. 6, 2022.)
The Supply Adequacy, Cost Allocation and Regional Tariff groups all approved the RRs last week by a combined vote of 75-1, with 28 abstentions, making only various non-substantive terminology edits.
MOPC then endorsed the tariff revisions in separate electronic ballots. Solar and storage developer Savion cast the only dissenting vote. The measures will now go before SPP’s Board of Directors and Regional State Committee this week for final approval. Staff hope to gain FERC’s approval in time to accredit resources for the summer season (June 1-Aug. 31).
Stakeholders modified RR536 to clarify that LREs can make a sufficiency payment only when the PRM is increased within the previous two years and the LRE demonstrates it had adequate capacity to meet the PRM before it was changed. A deficiency cannot result from selling accredited capacity to another region after the PRM’s increase is approved.
Under the change, capacity can only be claimed for accreditation by one asset owner in the SPP footprint. Capacity used to resolve deficiencies cannot be sold to another region for the applicable resource adequacy requirement season.
The measure includes the MMU’s proposed sufficiency valuation curve to value capacity in the market. The curve starts at twice the cost of new entry (CONE) at or below the sum of noncoincident peak loads, then slopes downward to a net CONE value when regional accreditation reaches the PRM. When the region has sufficient accredited capacity, the net CONE drops down to zero at 115% of the PRM.
RR537 emerged from the last-minute stakeholder process with revised language that removes a tariff violation when LREs fail to make a resource adequacy payment. As modified, LREs would be deemed sufficient for the adequacy requirement with a deficiency payment.
The change was also modified to clarify that only capacity resolving deficiency is obligated to stay in SPP; the obligation only applies to a specific RAR season; and that a deficiency payment is based on a kilowatt-year.
CRSP Faces Tx Rate Issues
The grid operator is working to address concerns by one of nine entities evaluating membership in its RTO West offering over its restrictions as a federal power marketer.
The Western Area Power Administration’s Colorado River Storage Project (CRSP) in November requested changes to the terms and conditions for RTO membership, approved last July. Those terms were to be effective March 1, but SPP’s Strategic Planning Committee endorsed a four-month extension to July 1 and additional terms and conditions during its Jan. 18-19 meeting.
The new terms include crediting CRSP’s point-to-point (PTP) transmission service and a federal service exemption (FSE) of replacement energy to satisfy its statutory load obligations.
The board will consider staff’s recommendation during its quarterly meeting Tuesday. The changes are contingent upon WAPA publishing its intent to join the RTO West in the Federal Register by Feb. 28.
Asked what SPP would do should other obstacles pop up before July, Bruce Rew, senior vice president of operations, said, “We would have to see what options we have that point to see if there’s some alternative that we can do to satisfy their situation.”
Rew said that about 88% of CRSP’s transmission obligations sink outside its zone, leaving the remaining 12% exposed to rate increases because of SPP’s treatment of PTP revenues. Low water levels in the Colorado River and the federal hydropower system also pose a risk, as the project’s transmission system was built to move federal hydro, he told stakeholders during the MOPC and SPC meetings.
Staff and other RTO West-interested parties, working together, agreed that CRSP would maintain PTP revenue from its reservations to pay for facilities in its transmission zone. This would apply to service delivered either inside or outside the SPP RTO footprint, with the contractual or statutory load obligations distributed solely to the project.
Because SPP’s tariff won’t allow CRSP’s replacement energy as an FSE, thus subjecting it to additional costs, staff and the other Western parties recommended the replacement energy be delivered to the CRSP zone and be subject to tariff provisions and charges. However, replacement energy delivered from CRSP’s zone will be eligible for an FSE; ineligible transmission purchases will receive auction revenue or transmission congestion rights.
CRSP sells about 5.3 GW of power to customers in Arizona, Utah, Colorado, New Mexico, Nevada, Wyoming and Texas over transmission facilities either owned or leased by WAPA.
SPP is also evaluating options to pull in the implementation schedule for its Markets+ offering in the Western Interconnection, an “RTO-light” market for those utilities not ready for full RTO membership. (See Governance, Resource Adequacy Key to SPP’s Markets+.)
The grid operator has projected an initial phase establishing market rules and tariff language will take about 21 months, followed by another three years to develop the day-ahead market.
The Western Resource Adequacy Program, a key part of the Markets+ offering, has attained funding commitments to move the program forward, and SPP has replied to a FERC deficiency letter over its tariff filing, the RTO’s Antoine Lucas told the SPC. Operations and forward-showing programs and systems will be implemented later this year, he said.
The SPC also approved a task force’s recommendation to add changes needed to include competitive upgrades to project monitoring processes as part of its business practice related to transmission projects.
The Transmission Owner Selection Process Task Force has reviewed 19 key areas to improve the competitive project selection process. It has reached consensus on 12 areas.
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.”
