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October 20, 2022December 2, 2023

NYSERDA Study: Ground Source Heat Reduces Peak, but Cost Impact Unclear

Wide deployment of ground source and district heat pumps (GS/DHP) could reduce New York’s peak electric loads by up to 12 GW, but it’s unclear whether the increased cost of the systems would produce net savings, according to an analysis shared with the state Climate Action Council (CAC) last week.

The New York State Energy Research and Development Authority (NYSERDA) conducted the analysis as a follow-up to a case study last year that found a higher adoption of GS/DHP would result in a net increased cost versus air source heat pumps, which have lower coefficient of performance. “But we recognized there were a lot of uncertainties in that work, so we committed to coming back to the council to further explore some of those uncertainties,” said Carl Mas, director of NYSERDA’s Energy and Environmental Analysis Department.

The new analysis found that boosting the share of buildings with GS/DHP from 25% to 65% would increase building sector costs by up to $19 billion because the technologies are more expensive than air source heat pumps. The more efficient heat pumps would save the electric system between $15 billion and $23 billion in reduced firm capacity, battery storage and renewables — meaning a net increase of up to $4 billion or a net decrease of $4 billion.

“On balance, we see that the savings that can accrue from heat pumps are on the same order as the net costs,” Mas said, meaning that there is not “clear winner [but] significant opportunity.”

As a result, Mas said the CAC’s scoping plan should include “an adaptive policy process” to monitor the relative costs of air versus ground heat pumps over time.

“As we see the evolution of the grid, and what the costs of those are, we can over time decide what the best tradeoffs are going to be,” he said.

Buildings cause one-third of the state’s greenhouse gas emissions, making them central to meeting the goals of the state’s Climate Leadership and Community Protection Act (CLCPA).

Managed vs. Unmanaged Electrification

In addition to comparing ground and air source heat pumps, the new analysis also considered the tradeoffs between a “managed” electrification — more energy efficiency and smart devices to manage peaks — versus an “unmanaged” electrification with less EE and smart devices. Managed building electrification would see building stock experience “significant levels of deep energy efficiency,” while unmanaged load growth would see “fewer deep shell retrofits,” Mas said.

NYSERDA projects peak load, currently 30 GW, will grow to 40 GW by 2050 under a managed scenario, as the state transitions from a summer- to a winter-peaking system. With unmanaged electrification, the peak would nearly double to 58 GW, but that would be cut by as much as 12 GW with higher GS/DHP penetration. The conclusion? More GS/DHP would have “a significant impact if we don’t realize the high levels of energy efficiency and peak load management” under a managed transition, Mas said.

A managed electrification would have a cost of around $80 billion, while an unmanaged system would see costs at least $27 billion higher because of a need for 14 GW of additional firm capacity and battery storage and 4 GW of incremental renewable generation. Uncertainty over distribution system impacts could add another $14 billion to the price tag, Mas said.

Mas said the analysis did affirm that improving building energy efficiency is critical for achieving CLCPA emissions reductions. But with the added costs of installing GS/DHP systems estimated at up to $19 billion, he said, there is not a clear case for recommending the more efficient systems now.

“We see the ground source heat pumps and district heat pumps have the potential [to reduce] the development risks that would come with having to build additional gigawatts of clean firm resources and the other distribution and transmission infrastructure that come from it,” he said. “And that’s what we’re recommending: that there be a continued effort to monitor and evaluate the relative … costs of ground source heat pumps and district heating, compared to how the electric system actually evolves over time.”

Comments

New York Public Service Commission Chair Rory Christian said the study “hit the nail on the head” when highlighting the significance of energy efficiency. “If you can be much more efficient in how our buildings are built and operate, then the need to build up bigger systems … is diminished significantly.”

Anne Reynolds, executive director for the Alliance of Clean Energy New York, asked whether there was significant difference in the costs of heating systems in urban versus suburban areas.

Mas responded that there were “different economics depending on the environment.” He noted that the analysis only used averages, saying there “certainly needs to be a specific utility-by-utility analysis for their specific service territories.”

Next Steps

The CAC will reconvene on Tuesday to give another integration analysis update and discuss any remaining feedback topics, including climate justice, before assembling a full draft scoping plan.

The council plans to spend November discussing redlines to the draft plan, then spend December making decisions on outstanding items, with a vote on a final scoping plan set for Dec. 19.

October 20, 2022

Ann Arbor Mayor Confident Voters Will Pass Climate Tax

ANN ARBOR, Mich. – Ann Arbor Mayor Christopher Taylor appears on his way to a third term after cruising to victory with 61% of the vote in the August Democratic primary; Republicans did not field a candidate.

Whether voters will also back his proposal for a 1 mill property tax increase to fund climate projects on Nov. 8 is less certain.

There is a “moral imperative to act on climate change,” Taylor said in an interview, repeating a phrase he has used since proposing the tax increase a year ago. While some suggest voters may be feeling “millage fatigue” after approving several city and school district tax increases in recent years, Taylor said he is confident residents and business owners will recognize the need to pay for actions to meet the city’s goal of reaching net zero emissions by 2030.

“I hope and believe Ann Arbor voters recognize we can’t get the benefits of climate restoration without resources,” Taylor said. “We’re all gonna pay for climate change,” he said, whether civilization takes steps to “counterbalance climate change,” or to protect itself from its impacts.

The tax, which would add $153 annually for an average property with a taxable value of $153,000 (half of the average fair market value of $306,000), would be in place for 20 years. In 2021, Ann Arbor property owners paid 50 mills.

The tax would raise an estimated $6.8 million in the first year. City Council passed a “shadow budget” saying it would spend

$1 million on compost programs and expanded recycling for “a zero waste, circular economy;”
$2 million on community solar, district geothermal and discount pricing of renewable energy;
$750,000 on services to help low-income residents save money and improve weatherization;
$500,000 on energy efficiency for residents and businesses;
$500,000 on neighborhood and community preparedness for climate change, including tree planting, rain garden installations and heat and flood mitigation;
$1 million to expand walking paths and bike lanes; and
$1 million to expand electric vehicle charging access — with an emphasis on renters and multi-family housing — and support electrification of appliances and heating and cooling.

The city currently spends about $2 million annually on climate measures, half from a Washtenaw County rebate and half from the city’s general fund.

Taylor said helping the city’s low-income Southeast Bryant neighborhood is a priority. Taylor said the city’s efforts to rebuild the tree canopy has been lacking in lower income areas. He also expressed a desire to help low-income households acquire more efficient appliances and access to renewable energy.

After winning his primary in August, Taylor’s only opponent in the liberal-leaning home of the University of Michigan is an independent. Taylor also appears poised to increase his 7-4 margin on council, as three candidates on his ticket defeated incumbents opposed to him.

City Council authorized a referendum on the tax last December. Ann Arbor would be one of the few communities in the nation to have a tax dedicated to climate action. Boulder, Colorado, voters enacted a similar tax in 2006 that raises about $1.8 million annually. No other localities in Michigan are considering such a proposal.

Tax increases have often proven contentious in Michigan, but the campaign on the tax proposal has been relatively quiet. There is an organization backing the proposal, A2 Climate Voters, which has gathered campaign donations. The city, which has a webpage backing the tax, spent nearly $20,000 to mail a postcard describing the proposal to some 56,000 city addresses.

There is no actively organized opposition to the tax proposal. One of the few, criticisms of the proposal came from a co-host of a podcast that deals with Ann Arbor issues and politics. The co-host said local residents may feel millage fatigue after voting in recent years on a sidewalk proposal and a large school improvement proposal. Even though she raised the criticism, the co-host also said she would probably vote for the proposal.

Missy Stults, Ann Arbor’s sustainability and innovations director, acknowledged that property owners don’t welcome tax increases, but said there are few other ways for local communities in Michigan to raise funds needed for projects. “We’ll see” if the city’s voters are tired of millages, she said.

Taylor expects the campaign will heat up with less than a month left to the election. More mailings are planned, and pro-proposal yard signs will be distributed, he said.

Taylor said businesses have a range of opinions on the proposal. But businesses also understand that all have to take action to combat climate change and want to be part of a community that meets its environmental responsibilities, Taylor said.

“On balance, everyone recognizes we need to do our part,” he said.

Taylor said he has heard nothing from other municipalities about the tax proposal. If the tax passes, Taylor said, he might get a phone call from another official considering similar action.

If the voters reject the tax, Taylor said, he expects the phone to stay quiet.

October 20, 2022June 14, 2023

NYISO Operating Committee Briefs: Oct. 13, 2022

ISO: Champlain Hudson Critical to NY Reliability in Future

The NYISO Operating Committee last week approved the ISO’s draft 2022 Reliability Needs Assessment (RNA), which did not identify any reliability needs for the 10-year study period but found that resource adequacy and transmission security margins are tightening over time.

But NYISO emphasized that the Champlain Hudson Power Express (CHPE) transmission project is critical to meeting future reliability needs, and delays could result in even thinner margins, creating significant risks to certain peakers who may be asked to continue operation when they otherwise would be unavailable because of non-compliance with new rules. An ISO representative said that “we’re putting all of our reliability eggs into the CHPE basket.”

The state also views the HVDC line, which would run from Quebec to New York City, as critical to its clean energy goals. (See NYSERDA Seeks 1-Year Delay for Tier 4 RECs.)

The report also noted that New York is likely to experience even smaller margins if additional power plants become unavailable or if future demand outpaces current forecasts. (See “RNA Draft Report Findings,” NYISO Transmission Planning Advisory Subcommittee Briefs: Oct. 3, 2022.)

The RNA also found that extreme weather events can result in transmission security deficiencies in the city, while gas supply shortages during winter peak conditions can eventually threaten reliability needs after 2032, when gas is predicted to become deficient in meeting statewide system needs.

The draft will be presented to the Management Committee on Wednesday for voting and to the NYISO Board of Directors for final approval in November.

NYISO-PJM Stability Analysis

NYISO recommended that its interconnection reliability operating limit (IROL) with PJM be removed after a study showed no stability issues even at transfer levels well in excess of the limit.

Robert Golan, NYISO manager of operations and engineering, presented the OC with the results of the study, which modeled three 115-kV tie lines with maximum transfers, winter ratings and optimized generation dispatch. NYISO-to-PJM flow achieved an emergency transfer limit of 2,440 MW, while PJM to NYISO achieved 3,175 MW.

NYCA transmission system interface | NYISO

The study also evaluated 61 NYISO and 68 PJM contingencies, finding that for NYISO to PJM, transfer levels were increased to 164% of the limit, giving the ISO a new proposed stability limit of 3,600 MW. From PJM to NYISO, the emergency transfer thermal limits increased to 150%, creating a new proposed limit of 4,250 MW.

The ISO “saw acceptable responses” in both the New York Control Area and PJM when examining “both angular and voltage response of each system,” Golan said.

Golan was quick to note, however, that both NYISO and PJM would reassess the need for the reinstatement of an IROL based on future system changes and five-year periodic reviews.

In response to questions around PJM’s status, Golan said NYISO has been “working hand-in-hand with PJM over the past year,” and that the RTO is currently waiting for the ISO to “go through the stakeholder process so that they can know when this report is approved.”

CESIL Updates

The committee approved manual updates implementing recently approved tariff revisions that preclude demand-side resources from curtailing critical electric system infrastructure load (CESIL) in response to ISO-called events and tests, beginning Nov. 1.

CESIL includes natural gas compressors and storage facilities; LNG storage, liquification and vaporization; refineries; electric system control centers; and natural gas system control centers, terminals, and metering and regulation stations. The revisions are intended to improve conditions for the upcoming winter, when gas supplies may short. (See “Critical Infrastructure Load,” NYISO Business Issues Committee Briefs: June 22, 2022.)

Ancillary Services

The committee also approved manual revisions regarding NYISO’s voltage support, operating reserves and black start capability services, such as preparing for the possibility of new technologies entering black start capability service and adding a 15-business-day window for ISO review of voltage support test data.

The ISO incorporated a “wish list of little things” that it had wanted to include in their manuals to confirm that market and review functions were in line with real-time situations.

Along with the new review period for voltage support reporting submissions, NYISO added a new allowance for out-of-period reactive capability testing and clarified language around data transmission requirements.

The 15-day review period was welcomed by stakeholders, with Brookfield Renewable’s Christopher LaRoe saying that the proposal for “the ISO to reply with a status besides ‘pending’ is helpful” because it will solve the current problem of “tight time constraints around the deadlines for suppliers to submit data for testing.”

The ISO also made terminology changes within its black start capability manual that would prevent innovative technologies from being excluded from these processes, with NYISO’s Harris Miller stating that the ISO is “trying not to exclude anyone.”

The changes become effective Nov. 1.

Interconnection Queue Streamlining

Zach Smith, NYISO’s vice president of system resource and planning, told the committee that the ISO has identified analyses that can be eliminated from the System Reliability Impact Study (SRIS) for 30 to 40 projects in the interconnection queue.

Smith noted that NYISO has been actively looking for ways to expedite SRIS processes to fix the backlog of projects currently waiting in the interconnection queue. (See NYISO Proposes Fixes for Interconnection Backlog.)

The categories identified are “immediate actions the ISO can take” to address these concerns without “sacrificing the quality of work or reliability of the grid” while remaining “in compliance with the relevant tariff and NERC standards,” according to Smith.

Stakeholders expressed support for these efforts, with Kaley Bangston from Invenergy stating that her team “thanks the ISO for putting the work and thoughts together to make this happen.”

NYISO plans to return to the Transmission Planning Advisory Subcommittee and the OC in November to share a more detailed list of projects that the ISO proposes to modify the study scope.

October 20, 2022

NYISO Class Year 2021 Cost Allocations Advance to OC Vote

NYISO stakeholders on Monday voted to recommend that the ISO’s Class Year 2021 (CY21) study results and cost allocations move to the Operating Committee for a vote next week.

Nearly 120 stakeholders attended Monday’s Transmission Planning Advisory Subcommittee meeting, where NYISO shared the list of upgrades required to reliably interconnect the 57 projects included in the CY21 study, at a cost of up to $900 million.

NYISO Manager of Facility Studies Wenjin Yan shared that 54 projects were requesting both energy resource interconnection service and capacity resource interconnection service (CRIS), while three members were CRIS only.

Decision Process and Timeline

With the upgrades and cost allocations for the CY21 projects identified, the ISO will now seek OC approval for the class year study reports, which include the allocations for CY21 system upgrade facilities (SUF) and system deliverability upgrades (SDU).

The OC’s approval of the CY21 study report will trigger the start of the initial decision period, during which class year developers will have 30 calendar days to accept or reject their cost allocations for SUFs and SDUs, and deliverable megawatts, if available, by providing NYISO either an acceptance or non-acceptance notice.

Developers who reject their cost allocations during this initial period will trigger additional decision rounds in which the ISO will issue within 14 calendar days a revised CY21 that removes projects that rejected their cost allocation, whereupon the remaining developers will have an additional seven calendar days to provide their acceptance or rejection to the revised CY21 cost allocations.

If additional rejections occur in subsequent rounds, the rejected projects are removed from the CY21 and the ISO will issue another revised CY21, and this iterative process will continue until all remaining CY21 members accept their respective cost allocations.

Once the remaining CY21 projects have accepted their cost allocations, developers will have five business days to pay cash or post security for the full cost allocation amount, and any developers who intend to post security are encouraged to reach out to applicable transmission owners to ensure the type of security that they intend to post meets the applicable transmission owners’ security arrangement requirements.

NYISO pointed out that developers who fail to notify the ISO by a stated deadline will be deemed as submitting a non-acceptance notice and removed from the class year.

Due to projects that reject their cost allocations in one round, the remainder of the CY21 members may see their CY21 cost allocations and any deliverable megawatts revised based on the updated study results.

NYISO also shared rules and procedural elements of this decision process, noting how developers that have additional SDU studies may accept their SUF project cost allocations, but separately accept or reject their SDU costs.

Developers with additional SDU studies not yet completed before the start of the CY21 initial decision period are given the ability to accept their SUF costs at this time and proceed with the additional SDU studies until they are completed or they can wait until the additional SDU studies are completed and, at that time, accept or reject the SUF and SDUs.

The ISO shared anticipated CY21 calendar breakdown, noting that the CY23 study could start as early as Jan. 3, 2023, with one decision round, or Feb. 13, 2023, should the CY21 study enter three decision rounds; however, CY21 can proceed with more than three decision rounds.

In response to questions about the timeline and whether the process could be sped up, Yan responded that “there is no reason we are going to hold up the results” if things could move faster than anticipated as the ISO “will use all their efforts to meet class year and tariff schedules.”

CY21 is considered complete once the class year report has been completed and all remaining developers have accepted and paid — or posted — security for their respective cost allocations.

Next Steps and Voting

Attending stakeholders recommended that the CY21 final results and cost allocations proceed to the OC for approval, though one objection was submitted by Empire Offshore Wind LLC, which represents two CY21 projects: Q958 (EI Oceanside 1) and Q959 (EI Oceanside 2)

The final report will be presented for approval at the next OC on Oct. 24. If approved, developers will have 30 calendar days to decide whether to accept their respective CY21 cost allocations.

If all 57 CY21 members accept their cost allocations, and no further decision rounds are required, then the ISO anticipates CY21 will end on Dec. 2, with the Class Year 2023 (CY23) study expected to start on Jan. 3, 2023.

October 20, 2022

MISO to File More Stringent Generator Retirement Study Process

MISO remains committed to beefing up and making information from its generation retirement studies more public as it outlined a number of study changes it plans to soon file with FERC.

The grid operator told stakeholders Wednesday it plans to impose a yearlong notice requirement on retiring generation before it begins retirement studies under Attachment Y of its tariff. It also plans to conduct the studies on a quarterly basis, share with stakeholders the megawatt value of retirement requests, and discourage reliance on load shed as a valid mitigation option when voltage and thermal violations are uncovered in its steady state analyses. (See MISO Bolstering Generation Retirement Studies Amid Capacity Shortage.)

“I know it’s a major change, but this will help us perform better studies. We believe there may be a ramp up in retirements, and this will help us study them,” Sydney Yeadon, with MISO’s resource utilization team, told stakeholders during a Planning Advisory Committee meeting.

Currently, generators intending to retire must notify the RTO six months ahead of time and studies are conducted as the notices are received. Staff says the changes are needed given the increase in retirement notices.

MISO says it will need four quarterly study periods worth of notice, rather than 52 weeks, from generation that is being retired or suspended.

MISO will define first-quarter retirement studies as beginning the first business day of March through the last business day of May; the second quarter as beginning the first business day of June through the last business day of August; the third quarter as beginning the first business day of September through the last business day of November; and the fourth quarter as beginning the first business day of December through the last business day of February.

The new study process will allow one quarterly study period after FERC approval for generator owners to prepare to use the new system.

Stakeholders asked whether the grid operator will study alternatives to keeping aging or uneconomic generation online under system support resource (SSR) agreements. Staff responded that it annually re-evaluates the need for SSRs after they are designated and said they view the agreements as a last resort for reliability.

DTE: Consider Old Generators for Reactive Power

DTE Energy is continuing its push to give old thermal generators new life as synchronous condensers that furnish the grid with reactive power.

During an Oct. 11 Planning Subcommittee, DTE’s Kenneth Gavin said that as dispatchable power retires and renewable integration gains traction, MISO will find a greater need for reactive power.

The utility says that existing generators can be cost-effectively converted to zero-emissions synchronous condensers after they suspend operations through MISO’s Attachment Y retirement process. It says that such conversions “can supply clean reactive power to the grid that maximizes performance and maintains customer affordability.”

Sustainable FERC Project’s Lauren Azar said the sooner MISO and members begin addressing grid technologies to support a majority renewable mix, “the better off we’ll all be.”

WPPI Energy’s Steve Leovy said it’s an opportune time for the RTO to signal a need for synchronous condensers because several thermal generators are announcing or weighing retirements.

Currently, retiring generators in the MISO footprint that are converted into synchronous condensers aren’t eligible for compensation under the tariffs Schedule 2, which outlines compensation for reactive supply and voltage control. The grid operator’s retirement process would take away a converting plant’s interconnection rights.

October 20, 2022

MISO: Diminished Emergency Possibilities this Winter

MISO says it will easily navigate normal winter conditions with its own firm supply but acknowledges that a worst-case winter storm in January could exhaust its emergency reserves.

During a winter readiness workshop Thursday, staff estimated they will have between 112 GW and 116 GW of capacity available to meet a projected 102 GW demand peak in January and 97-GW peaks in December and February. The forecast assumes average outage rates that have historically reached 29 GW.

The RTO’s all-time winter demand peak of 109 GW was set in January 2017.

Resource Adequacy engineer Eric Rodriguez said MISO “will be long as far as firm resources are concerned” if it experiences a normal number of outages and typical winter weather.

But the grid operator said “high-risk, low-probability events,” such as an artic blast, intense winter storms and fuel supply issues, “could impact available power” and challenge reliable operations.

According to Adam Simkowski, MISO’s principal meteorological risk analyst, MISO South should experience above normal temperatures while MISO Midwest should see near to slightly below normal temperatures. The grid operator noted that the National Oceanic and Atmospheric Administration is modeling a dynamic winter storm pattern for the Great Lakes states and said the area is at risk for blizzards and wind turbine icing.

“We could see a pretty active precipitation pattern this winter,” Simkowski said.

MISO is monitoring the small potential for a stratospheric warming event “which could destabilize the polar vortex” and unleash frigid weather that could dip into MISO South, he said.

“Overall, the ingredients for this to happen this winter don’t seem extremely likely,” Simkowski said, although he said the footprint could encounter “five- to 10-day shots” of cold weather.

Staff doesn’t foresee emergencies outside of a perfect storm of variables during the January peak. They said a scenario with unusually high demand of 109 GW and low available generation of only 95 GW could use up its 9.3 GW of expected emergency supply and force MISO to rely on imports from its neighbors to avert load shedding.

“Operating the power system is extremely complex, and adverse weather conditions can test the resiliency of the electric grid,” Jessica Lucas, executive director of system operations, said in a press release. “We have a responsibility to ensure 42 million customers have reliable power, which is why we need to work collaboratively with our partner utilities as we head into winter.”

“The system is evolving and will continue to evolve toward a more complex, less predictable future for the region,” added Anna Foglesong, director of strategy and policy coordination.

October 19, 2022

DOE Awards $2.8 Billion to ‘Supercharge’ Battery Production

The Department of Energy on Wednesday awarded 20 companies $2.8 billion to supply minerals critical to battery production and bolster domestic manufacture of batteries for electric vehicles and the grid.

The grants are the first round of $7 billion in DOE funding for batteries from last year’s $1.2 trillion Bipartisan Infrastructure Law, which included $62 billion for energy programs. The awardees will build or expand facilities in 12 states to manufacture battery components, including from recycled materials, and extract and process battery materials such as lithium and graphite, DOE said in a news release.

“This is truly a remarkable time for manufacturing in America, as President Biden’s agenda and historic investments supercharge the private sector to ensure our clean energy future is American-made,” Energy Secretary Jennifer Granholm said in the statement. “Producing advanced batteries and components here at home will accelerate the transition away from fossil fuels to meet the strong demand for electric vehicles.”

Sales of plug-in EVs have tripled since Biden took office, but the U.S. remains too dependent on other nations for critical minerals needed to produce EV batteries, mainly lithium, cobalt, nickel and graphite, DOE said.

“China controls the supply chains for many of these key inputs,” it said.

The grants are intended to alter that imbalance. All are matched or exceeded by company investments “to leverage a total of more than $9 billion,” according to DOE.

The largest award of $316 million went to Ascend Elements to establish industrial-scale separation of cathode materials from spent lithium-ion batteries and produce “precursor cathode active materials and metal salts to support domestic production of cathode active material (CAM),” DOE said in a fact sheet on the project. CAM can then be used in new lithium-ion batteries for EVs and energy storage systems, it said.

A new plant in Hopkinsville, Ky., will supply enough materials for 250,000 EVs annually, according to DOE. Ascend received another $164 million to design and construct the CAM plant.

With a $115 million DOE grant, Talon Nickel plans to construct a battery minerals processing facility in central North Dakota to process nickel ore for battery production. The company has an agreement with Tesla to supply 75,000 metric tons of nickel in concentrate along with copper, cobalt and iron in nickel and copper concentrates for “multiple battery chemistries,” DOE said.

“This process improves yield and metal byproduct utilization relative to legacy processing of nickel ores,” it said.

Talon CEO Henri van Rooyen said in a statement Wednesday that the “national urgency and the target date for nickel and iron production set within our Tesla-Talon supply agreement required an innovative approach to bring a new domestic source of battery minerals into production during a period of global battery-grade nickel deficits. Today’s announcement is a clear recognition that production of domestic nickel and other battery minerals is a national priority.”

In McMinn County, Tenn., Piedmont Lithium will use a $142 million grant to help build its $600 million Tennessee Lithium project, “which aims to expand the U.S. supply of lithium hydroxide by 30,000 metric tons per year,” the company said in a news release. “Lithium hydroxide is a key component of high energy density, long-range, EV batteries,” it said.

“We are pleased that the DOE has chosen to support our Tennessee Lithium project, and we are committed to being responsible stewards of these grant funds,” Piedmont COO Patrick Brindle said in the statement. “This funding will enable us to accelerate detailed engineering and place orders for long-lead items.”

Construction at the Tennessee Lithium project is expected to start next year, with production beginning in 2025, the company said.

‘Reliable’ and ‘Sustainable’ Supply Chain

Other projects funded include the first large-scale lithium electrolyte salt production facility in the U.S.; an “electrode binder facility capable of supplying 45% of the anticipated domestic demand for binders for EV batteries in 2030”; the nation’s first commercial-scale silicon oxide facilities, which will produce materials for an estimated 600,000 EV batteries annually; and the first lithium iron phosphate cathode facility in the U.S., DOE said.

In total, Wednesday’s first-phase funding will help supply enough battery-grade lithium for “2 million EVs per year, enough graphite for 1.2 million EVs annually and enough nickel for 400,000 EVs,” DOE said. The grants will promote creation of 8,000 jobs including 5,000 permanent jobs, many of them in or near disadvantage communities, it said.

The Biden administration wants electric vehicles to make up half of all new vehicle sales by 2030 and to transition to a net-zero emissions economy by 2050, the department noted.

Toward that end, the Biden administration announced Wednesday it was launching the American Battery Material Initiative, a “new whole-of-government effort to secure a reliable and sustainable supply of the critical minerals that power everything from electric vehicles to homes to defense systems,” the White House said in a fact sheet. “The American Battery Materials Initiative will be led by a White House steering committee and coordinated by the Department of Energy with support from the Department of the Interior.”

“The Initiative will work through the Partnership for Global Infrastructure and Investment, and leverage ongoing work by the Department of State, to work with partners and allies to strengthen critical mineral supply chains globally, and it will leverage and maximize ongoing efforts throughout the U.S. government to meet resource requirements and bolster energy security,” it said.

October 19, 2022June 14, 2023

Carbon Capture Projects Rise with Subsidy Boost

Carbon capture and storage is having a banner year, with 30 commercial CCS facilities now in operation worldwide capable of storing more than 42 million tons of carbon dioxide per year. Add in a pipeline of 164 projects in various stages of development, and the potential stored capacity jumps to almost 244 million tons per year — a 46% jump over 2021 — according to the 2022 Status Report from the Global CCS Institute.

“After so many challenges and so many false starts … the momentum is palpable,” said Brad Crabtree, assistant secretary of the Department of Energy’s Office of Fossil Energy and Carbon Management.

But speaking at a webinar on the report Monday, Jarad Daniels, the institute’s CEO, said optimism about new momentum in the industry must be tempered by the need for unprecedented growth. “Global efforts to reduce emissions, including investment in CCS, are still grossly inadequate overall,” he said. “Government policy must be met with private capital to unlock the full potential of CCS and limit global warming to 1.5 degrees.”

Hitting that target will mean increasing carbon storage capacity more than 100-fold by 2050, said Guloren Turan, GCCSI’s general manager for advocacy and communications.

“The science shows that reaching our sheer climate goals is practically impossible without [CCS],” Daniels said. “CCS is a mature, well-understood technology that is increasingly commercially competitive across the full value chain from capture to storage.”

The report highlights major industry developments, with the expansion of the 45Q tax credit in the Inflation Reduction Act at the top of the list. Daniels said the new law’s $85/ton credit for CCS and up to $180/ton for direct air capture (DAC) could increase deployment 13-fold in the U.S.

Denmark’s €5 billion investment in CCS has also signaled a growing market in Europe, with the Orca DAC plant in Iceland now sequestering about 4,000 tons of CO₂ per year. The plant uses a process called mineralization, which turns the injected gas into stone in about two years.

CCS projects in operation (GCCSI) Content.jpg

CCS plants worldwide now number 30, with 164 projects at various stages in the development pipeline. | GCCSI

Climeworks, the company behind the plant, recently broke ground on an even larger direct air capture facility in Iceland, which could sequester up to 36,000 tons per year, according to the company.

China has also opened its first CCS plant, with the capacity to capture 1 million tons per year, which is being used for enhanced oil recovery (EOR), according to the report. A second plant, which will capture carbon from coal-fired generation, is under construction.

Despite such progress, the industry faces a challenge in winning over the sizeable number of CCS skeptics, said U.K. and U.S. energy officials speaking at the event. In the U.S. and elsewhere, environmental and other community groups have criticized the technology as a too-expensive strategy for extending fossil fuel generation.

“Not everyone supports carbon capture as the route to net zero,” said Alex Milward, director of carbon capture utilization and storage at the U.K. Department for Business, Energy and Industrial Strategy. “It’s important for us all to work together to bring everyone along on this journey as well as we can.

“There’s more we all need to do together on international standards and modularization and product standards and transport standards, and then we [need] to get the optimal balance between where world CO₂ is emitted and where we can cost-effectively capture and store it,” Milward said.

“We need to get implementation right,” agreed DOE’s Crabtree. “There’s a lot of misunderstanding about what [CCS] technologies can and cannot do, but there are also real legitimate concerns about how these investments will benefit in real tangible ways communities, economically and environmentally. That’s something we really have to focus on going forward.”

Turning Point

A turning point for CCS, besides the IRA, was its recognition by organizations such as the U.N. Intergovernmental Panel on Climate Change and the International Energy Agency as critical to the 1.5-degree global climate goal.

In line with that institutional validation, a core driver for market growth is “the demand for greenhouse gas emission reductions in line with net-zero commitments from governments and businesses, together with rising expectations from civil society,” Turan said.

Other factors include the need to decarbonize “products that are critical to human economic development,” such as steel, cement and chemicals, she said.

Early development has been focused on EOR, the injection of CO₂ to produce more oil from low-producing wells, which accounts for 21 of the 30 facilities currently in operation. Turan expects the project pipeline will be more focused on other forms of sequestration.

The U.S. currently leads the world both in operating CCS facilities and in projects in development, according to the GCCSI report, with the IRA and $12 billion for direct air capture hubs in the Infrastructure Investment and Jobs Act, focusing on development and investment.

DOE issued a notice of intent for the funding in May, and according to the agency website, an application opening date is expected by year-end.

In addition, the report notes other key policy advances, with the Pipeline and Hazardous Materials Administration releasing new guidelines on CO₂ pipeline safety and the Bureau of Land Management issuing guidance on CO₂ storage on public lands.

“One of the exciting things for us, it’s not just the scale of these resources [in the IRA and IIJA], it’s also for the first time, we’ve really expanded research and development to include large-scale commercial demonstration, and that’s a major policy change in the United States. It’s long overdue and needed to really ramp up deployment of carbon management technologies across the economy.”

Other key funding in the IIJA includes $2.5 billion for “the development of dedicated regional geologic storage sites” and $2.1 billion for “carbon dioxide transportation infrastructure finance,” Crabtree said. The two projects will work in tandem, he said, so that “we can finally get beyond this historic chicken-and-egg challenge where you develop a carbon capture project, but how do you get the transport done, who develops the storage site?”

The goal, he said, is to build out a CCS “ecosystem in an integrated way on a regional basis, importantly to reduce costs and ultimately so we can bring carbon management to climate scale.”

October 19, 2022December 13, 2023

GridSecCon Panelists Tout GridEx Training Opportunities

Speakers at NERC’s annual GridSecCon security conference on Wednesday urged their colleagues to get involved in the Electricity Information Sharing and Analysis Center’s (E-ISAC) biennial GridEx security exercise, with one panelist calling the event a “perfect opportunity” to test emergency operations plans in a highly realistic setting.

Like last year’s event, GridSecCon 2022 was held online because of lingering concerns over the COVID-19 pandemic. (See GridSecCon Panelists Share Cyber Supply Chain Fears.) NERC, the E-ISAC and ReliabilityFirst hosted this year’s conference.

The ERO holds GridEx every two years. Each exercise consists of two parts: a two-day distributed play in which participants across the country work a core scenario developed by the E-ISAC and customized by each organization, and an executive tabletop hosted for leadership of various organizations, including investor- and publicly owned utilities, government entities, and grid operators, as well as representatives from other industries.

Last year’s GridEx VI saw participation in the distributed play portion of the exercise decline for the first time since the event was first held in 2011, which organizers attributed partly to the pandemic and partly to changes in how participants were counted. (See NERC: GridEx Lessons Already In Use.) NERC confirmed earlier this year that planning is already underway for next year’s GridEx VII, which is scheduled for Nov. 14-15, 2023.

Clockwise from top left: Jesse Sythe, E-ISAC; Blake Stave, Xcel Energy; Doug McCracken, Eversource Energy; Adrienne Lotto, APPA. | NERC

This year’s GridSecCon featured two separate panels focused on the security exercise. The first focused on recommendations from GridEx VI, while the second dealt with preparations for GridEx VII and the threats that it will need to consider.

“One of the neat things about GridEx is its amazing flexibility,” Peter Grandgeorge, state national security and resilience programs adviser at Berkshire Hathaway Energy, said in the first session. “And this is part of why I think it’s so successful across the board, and it’s why we’re here today talking about it, because this exercise keeps building … both in the sheer amount of folks involved, but also in depth.”

Grandgeorge and his fellow panelist Lance LaBreck, CAISO’s business continuity manager, noted how the exercise had grown since their organizations began to participate. Grandgeorge reminisced about “sitting around a table [with] about 50 folks” the first time BHE participated in the distributed play in 2013, a number that had grown to 600 by GridEx VI.

LaBreck said one of the most satisfying elements of the evolution of GridEx over the years is its expansion to include stakeholders beyond the electricity industry itself, with input now welcomed from government bodies and other infrastructure sectors like natural gas and telecommunications. He said exercises like this are an opportunity to build relationships with these players so that a utility’s emergency personnel are not meeting them for the first time during a crisis.

“The key part I try to bring up again and again, focused specifically to the electricity subsector, is [that] we are all interconnected … what’s upstream and what’s downstream of us,” LaBreck said. “And if we don’t leverage this training opportunity … at every level we can within the organization, it’s a missed opportunity. There is no other place where you have the ability to bring in your incident command, your cyber and physical security components, [and] your operators to work together internally [and also] to interface with your state emergency management agency [and] your local county … to leverage that relationship.”

In the second panel, Jesse Sythe, the E-ISAC’s GridEx program manager, said the organization’s intent with the exercise is to foster a “train-like-you-fight, fight-like-you-train mentality.” Adrienne Lotto, senior vice president of grid security at the American Public Power Association, said utilities should take advantage of the training opportunity and not be afraid of exposing weaknesses in their defenses.

“I guarantee … you will find gaps and lessons learned. But that’s OK,” Lotto said. “It’s all part of the continuous process to improve, and I think there’s always value to be driven from the exercise.”

October 19, 2022

Stakeholders Doubt MISO Study of Alternative Tx Projects

Clean energy and public consumer advocates questioned Wednesday whether MISO planners are sufficiently exploring alternatives to the projects transmission owners submit to staff.

Piqued by a batch of expedited substation projects in MISO South for the 2022 planning cycle, they asked for proof that the grid operator is identifying or studying alternative projects. They expressed hope during a Planning Advisory Committee that staff find larger regional projects that could satisfy several needs rather than blindly accepting TOs’ project plans. (See MISO’s 2022 Tx Planning Cycle Exceeds $4B.)

Several stakeholders said TOs don’t make enough project specifications public to allow meaningfully proposed project alternatives. “More detail needs to be given to stakeholders ahead of time,” Southern Renewable Energy Association Executive Director Simon Mahan said.

He suggested that MISO planners might also lack the capabilities to study project alternatives.

“As a stakeholder, I don’t know what to do,” Mahan said. “I think you all are doing the best you can … but $70 million is a lot to rush through. I don’t know if MISO has the tools to future-proof the system. I’m just worried how many more times this is going to happen in the future. I’m just really worried about this.”

This summer, Cleco applied to include a 230-kV and an 138-kV substation, each costing $15 million, for expedited treatment. Entergy requested approval to install two additional 230-kV breakers into an existing substation near the Louisiana-Texas border; to construct a 230-kV substation; and a $32.6 million, 115-kV substation in northern Mississippi. The utilities said the projects were necessary because of load growth in their territories.

MISO recommended all the projects for late inclusion in its 2022 Transmission Expansion Plan.

Clean Grid Alliance’s Natalie McIntire said her organization has raised the issue with MISO several times. She said she believes that Order 1000 obligates staff to offer and analyze project alternatives.

“Whenever we ask about this, MISO assures us it studies alternatives. But we don’t in the stakeholder process see alternatives. … This is an issue of costs for consumers,” McIntire said.

She said it seems that MISO “does a lot of hand waving” in only reassuring stakeholders that they study alternatives, but don’t back that up with evidence. The RTO is best positioned to examine alternatives with its “top-down” view of the system, McIntire said.

“We continue to make these comments, and I feel like it’s never quite resolved,” she said.

Jeanna Furnish, MISO’s director of expansion planning, said “there are situations in which” MISO comes up with alternative projects, with those alternatives sometimes presented in subregional planning meetings.

“So does every single project get an alternative? That’s probably not true,” she said.

Furnish said MISO will “think through” whether it has the tools to adequately study alternatives and how it might be more transparent in discussing the alternatives.

She also said grid operators stand to be affected by FERC’s notice of proposed rulemaking on more comprehensive transmission planning. Furnish appeared before the commission’s technical conference on transmission planning earlier in the month. She said then it isn’t feasible for grid operators to consider alternatives to every TO-proposed project. (See States Urge More Transparency on Tx Planning, Independent Monitors.)

Cleco Energy’s Chris Thibodeaux said the utility’s expedited projects will bring jobs to Louisiana and are requested by industrial customers who need transmission-level service.

“I’m not sure how the Environmental Sector really has a say in that,” he said.

Jeff Cook, with the Office of Consumer Advocate, said a public consideration of alternatives can help stakeholders more easily accept expensive projects.

LS Power’s Brenda Prokop added that an evaluation of alternatives could help determine whether the RTO could rely on larger projects to take care of various smaller needs.

Mahan agreed that MISO could help members figure out whether larger projects would save money and give stakeholders more confidence in the planning process.