FERC expanded its series of orders directing refunds for premiums earned in the Western heat wave of August 2020 by telling ConocoPhillips (NYSE:COP) and Direct Energy on Friday to return excess money they made on sales in scarcity conditions.
In Direct Energy’s case, FERC said the Houston-based energy retailer had failed to justify 25 MW in sales to Macquarie Energy for $1,500 MW/h, higher than the average index price of $1,333 MW/h at the Mead Hub in southern Nevada on Aug. 18, 2020 (ER21-64).
“We find that Direct Energy has not provided adequate justification for the amount charged above the index price, and, therefore, we direct Direct Energy to refund amounts charged above the average index price for the sale at issue within 30 days of the date of this order,” FERC wrote.
In ConocoPhillips’ case, the company had justified its August 2020 sales at its “cost of energy purchased, but it has not justified the amounts charged above [that cost],” FERC said (ER21-40).
ConocoPhillips contended two sales to Arizona’s Salt River Project on Aug. 17-18 were sleeve transactions it facilitated between a third-party seller and the utility. ConocoPhillips charged far more than it paid for the energy, which it said reflected operational costs and the heightened risks from record heat, wildfires, transmission outages and the potential for nonperformance by the parties at the time.
SRP argued the sales were not sleeve transactions under FERC’s definition, in which “an entity acts as an intermediary counterparty to accomplish a sale between two other counterparties who may not be set up to transact with each other using common enabling agreements (such as the Western Systems Power Pool (WSPP) or Edison Electric Institute agreements) or who may not meet credit requirements.”
The utility said the parties were members of WSPP that could use its common enabling agreement, and it pointed out that it had a credit rating of AA+ from S&P Global Ratings when the transactions occurred.
Even if the sales were sleeve transactions, the fees ConocoPhillips charged were far more than the “nominal” add-ons allowed by FERC in such cases, SRP said.
“According to Salt River, ConocoPhillips cannot credibly report to the commission that these transactions were sleeve transactions with nominal fees, nor attest reasonably to the commission that the amount it charged above cost, which is vastly higher than a nominal fee, should apply to its transactions during August of 2020 due to heightened risks,” FERC wrote.
The commission agreed.
“While the record in this proceeding indicates that ConocoPhillips acted as an intermediary in obtaining energy Salt River sought to purchase and then selling that energy to Salt River, [our previous guidance on sleeve transactions] was specific in its description of the circumstances in which a transaction involving an intermediary qualifies as a sleeve transaction, and ConocoPhillips has not demonstrated that those circumstances are present here,” FERC said.
“Specifically, ConocoPhillips has not demonstrated that it collected only a nominal fee in acting as an intermediary counterparty to accomplish a sale between two other counterparties,” it said.
So far, the commission has decided 10 of the cases, ordering refunds in all. It also has denied motions by some of the parties to raise WECC’s soft price cap to $2,000/MWh, the same as CAISO’s, saying the matter was beyond the scope of the proceedings.
Commissioner James Danly has dissented in each case, saying FERC lacks the legal authority to interfere in contracts between willing buyers and sellers that do not harm the public interest.
Parties to the United Nations Framework Convention on Climate Change began their annual subsidiary bodies conference in Bonn, Germany, Monday to prepare for the 27th Conference of the Parties (COP27) in Egypt this fall.
UN Climate Change Executive Secretary Patricia Espinosa | United Nations
“These are meetings where we can already start seeing the best way to address some of the contentious issues that will be coming up,” UN Climate Change Executive Secretary Patricia Espinosa said. The meeting has “special meaning” in the context of a world that is “nothing like what we saw [at COP26] in Glasgow … and is being impacted by significant progress on climate change, including the disruption of global energy markets and clean energy investments,” she said during an opening day press conference.
UNFCC subsidiary bodies, in charge of implementation and scientific and technological advice, will hold meetings through June 16, focusing on advancing the issues that will be before the full conference in Sharm El-Sheikh, Egypt. Top among the bodies’ concerns will be mitigation, adaptation, finance, and loss and damage.
The Bonn conference is the first time parties have met since COP26, where they agreed on the operational details of the 2015 Paris Agreement and the work necessary to mitigate, adapt to and compensate for climate change.
“This conference marks the start of a new phase in our intergovernmental climate change process; a phase of implementation,” Espinosa said. “We have a blueprint, and we have the rules to ensure that it is transpiring, so it’s time to get on with the job.”
Mitigation
Mitigating greenhouse gas emissions through national climate action plans is a cornerstone of the Paris Agreement, but Espinosa said parties in Glasgow agreed that the existing five-year cycle for updating those plans is not sufficient.
Parties need to make climate plan reviews a “permanent process” so they can watch for opportunities to reduce emissions and further the agreement’s goal of keeping global temperature rise below 1.5 degrees Celsius, she said.
“So far, we have received only a few updated [plans], and we need to get more,” she said.
The UNFCCC Secretariat is helping support more national plan updates by encouraging parties to report progress on implementation or potential future mitigation opportunities without walking through the entire plan development process, according to Espinosa.
Regular updates, she added, will help the Secretariat develop “the most credible picture” on mitigation and long-term climate strategies from countries.
“This is a big area where we know the world will be watching and will want to know exactly where we are,” she said.
During the Bonn conference, parties will also discuss preparations for the regular global stocktake required by the Paris Agreement to assess the collective progress on achieving the goals of the agreement.
“The technical dialogue [in Bonn] will allow parties to start identifying where the existing gaps are and hopefully how to address them,” Espinosa said.
Adaptation and Loss
Adapting to climate change was a main concern raised by vulnerable, developing countries during COP26, and Espinosa said that those countries were “eager” to see the issue on the Bonn conference agenda.
In Glasgow, “there was a decision to start the process of defining a new global goal on adaptation, and we start that conversation here in Bonn,” she said.
Espinosa also hopes parties will make progress in Bonn on developing the Santiago Network for countries that need advice on issues related to loss and damage from climate change. Last year, the parties outlined the functions of the network, which was formalized originally in 2019.
The network, Espinosa said, “needs to become fully operational.”
She also wants to see the parties advance a dialogue on how to finance loss and damage that started in Glasgow.
Retiring
Espinosa officially announced her retirement from the role of Executive Secretary during her opening speech at the conference.
“My time serving the process from the Secretariat is at an end, but this process will go on, and I will do all I can to contribute, as a private citizen, to improving our understanding, galvanizing action and, ultimately, improve our chances of success on climate,” she said.
Espinosa took over the role in 2016, having served previously as the Mexican Minister of Foreign Affairs and the President of COP16 in 2010.
Reflecting on her six-year tenure, Espinosa said: “If we all do what we can and we work together, we can get through any challenge. The key is to support each other.”
SACRAMENTO — Legislative leaders in California proposed a budget plan Wednesday that differs from Gov. Gavin Newsom’s proposal on how to spend $21 billion on climate and energy initiatives.
The legislature proposed appropriating $21 billion for climate and energy efforts to the state’s general fund, with spending details to be worked out later.
In contrast, the governor’s revised budget, released in May, proposed spending $32 billion on climate and energy — up $9.5 billion from his $22.5 billion January proposal — with almost all of it allocated to specific programs. (See Calif. Governor Proposes $5B ‘Reliability Reserve’.) The legislature’s full budget includes about $10 billion of that, including a $9.1 billion transportation infrastructure package, but allocates it separately from the climate and energy initiatives.
According to a summary of the legislature’s proposal, the $21 billion could fund projects related to drought and wildfire resilience, extreme heat and zero-emission vehicles, among other matters. But without specific allocations in place, each category’s funding level is uncertain.
California expects to have a record $97.5 billion revenue surplus in fiscal year 2022/23, and lawmakers want to return part of those funds to residents, including $8 billion to offset the rising costs of gas and consumer goods.
“The legislature has come together on a budget agreement that will truly put California’s wealth to work for all,” said State Sen. Nancy Skinner, chair of the Senate Budget and Fiscal Review Committee. Skinner is noted for her work on energy and climate change.
A 2010 state constitutional amendment requires lawmakers to pass a budget plan by June 15 or have their pay docked. That has resulted in placeholder budgets with contentious issues left for further negotiation between the governor and legislature.
Programs that would be put on hold for now under the legislative plan include the governor’s proposal to spend $250 million to support strategic clean energy projects such as building new transmission lines to connect CAISO’s grid to geothermal resources near the Salton Sea.
The legislature would also defer allocating $6.1 billion to accelerate the adoption of ZEVs, $5.2 billion for a 5-GW strategic reliability reserve and $1.2 billion for wildfire and forest resilience. (See Calif. Governor Proposes Spending $10B on EVs.)
Smaller items, such as $45 million to promote offshore wind, would also be postponed pending additional negotiations, which both sides hope to conclude before the start of the fiscal year on July 1.
ISO-NE is considering reusing its Winter Reliability Program or Inventoried Energy Program (IEP) to address uncertainty about the reliability of New England’s grid this winter.
Familiar fuel constraints, massive uncertainty from the war in Ukraine and the possibility of extreme weather have led to early and grim warnings from the grid operator about supply and reliability for the upcoming winter. (See Fears Already Mounting About Next Winter in New England.)
In a note sent to stakeholders Friday, Allison DiGrande, ISO-NE director of participants relations and services, said the RTO is working with a consultant to “refresh its analysis” and look at the costs and value of previously approved winter solutions, specifically naming both programs.
The Winter Reliability Program, in place between 2015 and 2018, incentivized generators that run on oil and gas to secure fuel before winter, by compensating them for a “portion of the costs related to any fuel inventory that is unused at the end of each winter.”
ISO-NE CEO Gordon van Welie, however, recently threw cold water on the prospect of revisiting that solution.
“Do we want to pay oil units more money to do what they have a massive incentive to do anyway?” he said at a recent conference. “What’s the likelihood of success of us trying to stand up a program like that, get it through the system and have it implemented in time?”
The IEP is a voluntary program in place for the 2023-2025 period that will compensate resources for the inventoried energy they hold on winter days that hit a certain low-temperature threshold.
It too would face uncertainty if ISO-NE decides to reuse it: It was approved by FERC in 2020, under a Republican majority; Commissioner Richard Glick, now chairing a Democratic majority, said in a dissent that the program was “an ill-conceived giveaway that acts as if throwing money at a problem is always just and reasonable.” (See ISO-NE Stopgap Fuel Security Program Gets OK.)
DiGrande said that by early July, ISO-NE will make a recommendation about whether it plans to “stay the course” with its current market structures or propose tariff changes for this winter. If the RTO does recommend changes, DiGrande wrote, “we would plan to meet the stakeholder process requirements with two Markets Committee meetings in July and the final vote at the Participants Committee on Aug. 4.” That schedule would allow for an August filing at FERC and a September order.
ISO-NE has also been requesting information from asset owners about their plans to meet operating requirements, and from some fuel providers about their inventories and delivery capabilities.
“When completed, these inquiries will allow the ISO to compile data on the anticipated fuel stock that will be available to suppliers to meet the demand for electricity this winter,” DiGrande said.
SACRAMENTO — Four bills intended to help speed the construction of transmission to deliver renewable energy to CAISO’s grid cleared the Senate and Assembly and are moving forward in the legislative process, including two measures that propose studying public ownership and financing of transmission projects in California.
The measures seek to bolster the state’s efforts to supply end-use customers with 60% renewable resources by 2030 and 100% carbon-free energy by 2045, as required by Senate Bill 100.
CAISO estimated in its first 20-year transmission outlook in February that meeting the state’s goals will require a $30.5 billion transmission buildout in California and across the West over the next two decades, mainly to carry wind and solar power from remote areas to urban load centers. (See CAISO Sees $30B Need for Tx Development.)
The assessment prompted lawmakers to introduce bills to accelerate the normally laborious process of transmission development. The measures include Senate Bill 1174, by Sen. Robert Hertzberg, a San Fernando Valley Democrat.
“California’s ambitious clean energy goals are nothing more than goals without the right infrastructure,” Hertzberg said in a statement following Senate passage of his bill, by a vote of 39-0, on May 25. “This bill connects the state’s bold plans for electrifying our economy with the modern infrastructure required to power a cleaner, greener California.”
SB 1174 is now before the Assembly Utilities and Energy Committee.
Transmission owners currently report annually to the California Public Utilities Commission on transmission upgrades needed to achieve their renewable portfolio standard procurement requirements, it notes.
Hertzberg’s bill would direct the CPUC to work with CAISO, the California Energy Commission (CEC) and the state Air Resources Board to “identify all interconnection or transmission projects necessary to achieve” the goals of SB 100 and to prioritize approval of the projects.
That includes the connection of offshore wind resources to CAISO’s grid.
The federal Bureau of Ocean Energy Management intends to hold the West Coast’s first wind auctions later this year for two areas off the California coast, one of which, the Humboldt Wind Energy Area in Northern California, lacks onshore transmission connections.
Completing the project and delivering its estimated 1.6 GW of capacity will require building transmission lines 100 miles across a mountainous landscape or laying an undersea cable more than 200 miles to the San Francisco Bay area, CAISO planners have said. (See West Coast Wind Faces Big Challenges.)
Such large-scale needs mean speeding transmission “may be one of the most important steps we can take to connect bold planning with common-sense policy,” Hertzberg said in his statement.
Faster, Cheaper and Possibly Public
Another bill, SB 887 by Sen. Josh Becker, a Democrat from the San Francisco Peninsula, says the state’s installed generating capacity could grow from 85 GW today to more than 300 GW by 2045 to meet SB 100’s targets. (CAISO’s estimates are less but still suggest the state may need to triple its in-state generating capacity in the next 23 years.)
“These build rates are not achievable without additional electrical transmission lines and facilities connecting new resources to consumers in the state’s load centers,” Becker’s measure says. “Given the scale of this challenge, there is an urgent need to prioritize and accelerate the substantial effort needed to build transmission projects with long development times.”
The measure would direct CAISO, the CPUC and the CEC to expand their generation and transmission planning horizons from the current 10-year process to “at least 15 years into the future to ensure adequate lead time for [CAISO] to analyze and approve transmission development, and for the permitting and construction of the approved facilities, to meet the projections.”
(CAISO’s 20-Year Transmission Outlook is “a long-term conceptual plan of the transmission grid in 20 years,” including out-of-state projects, that is intended to complement but not replace its normal 10-year transmission planning process, which concerns only projects in California.)
SB 887 would also require CAISO to identify “the highest priority transmission facilities that are needed to allow for reduced reliance on nonpreferred [fossil-fuel] resources in transmission-constrained urban areas by delivering renewable energy resources or zero-carbon resources that are expected to be developed by 2035 into those areas.”
A second Becker transmission bill, SB 1032, seeks “faster and cheaper transmission development,” the senator’s office said in a news release.
The bill would direct the CPUC to identify “proposals to accelerate the development of, and reduce the cost to ratepayers of expanding, the state’s electrical transmission grid as necessary to achieve the state’s goals [of reducing greenhouse gas emissions.]”
Measures to be studied would include public ownership of transmission facilities, public financing of transmission projects, and the use of non-ratepayer funds to cover part of the cost of transmission projects needed to achieve the state’s clean energy goals.
The bill also would direct the CPUC to examine state and private partnerships to support siting transmission projects and obtaining land-use rights, as well as “opportunities to reduce redundancy and streamline permitting processes related to transmission projects.”
Both Becker bills passed the Senate by large margins on May 23-24 and are now in the Assembly.
At about the same time, an Assembly measure dealing with transmission, AB 2696, crossed over to the Senate. It, too, seeks to lower the costs of transmission development, possibly through public ownership and financing.
The bill would instruct the CPUC — in consultation with CAISO, the California Infrastructure and Economic Development Bank and the Governor’s Office of Business and Economic Development — to study “potential lower cost ownership and alternative financing mechanisms for new transmission facilities needed to meet the state’s clean energy and climate targets” including public ownership, public financing and partnerships with federal agencies.
Under the measure, the CPUC would have to report its findings to the governor and legislature by September 2023.
Researchers at Michigan Technological University have wrapped a yearslong study that concludes many of the nation’s abandoned and flooded mines could become underground, long-term, pumped-storage facilities.
Studying a nearby closed mine shaft in Michigan’s Upper Peninsula, professors and graduate students determined that nearly 1,000 mines in the country could be repurposed into closed-loop hydroelectric storage facilities.
“We really can create a closed loop pumped hydro storage facility in an abandoned mine that is essentially invisible at the surface,” Michigan Tech associate professor of archaeology and anthropology Timothy Scarlett told RTO Insider in an interview. “We don’t really have to invent anything. It’s all of matter of using what has already been designed.”
Michigan Tech researchers concentrated on Mather B, a long-decommissioned iron-ore mine in Negaunee, Michigan, and extrapolated results to consider the applicability of such facilities on a national scale. They concluded proven and conventional pumped hydro equipment could be fitted into mineshafts. (See Mich. Energy Storage Idea Poses New Life for Old Mines.)
“What surprised me in the finding is how flexible this service can be in supplying grid services … We’ve concluded that this could do pretty much anything that MISO could ask it to do,” said Roman Sidortsov, associate professor of energy policy.
Research IDs 968 Mines as Storage Sites
Using data from the United States Geological Survey’s Mineral Resource Database System, the researchers identified 968 other abandoned mines across 15 states that could potentially host hydroelectric storage facilities.
Michigan Tech undergraduates worked with the university’s Alternative Energy Enterprise Team building a database of the country’s abandoned underground and combined underground and surface mines. They eliminated incompatible mines like open pits, mountaintop-removals and sites with weak structures.
“For example, we excluded coal mines because they’re usually more geologically unstable,” Scarlett said.
The team concluded that suitable mines could host up to 285 GW of daily power capabilities for partially underground storage facilities and 137 GW for fully underground facilities. The study pointed out that those values exceed the National Renewable Energy Laboratory’s (NREL) projections of storage needs to support an 80% renewable energy mix.
NREL’s recent Storage Futures Study projects from 100 to 650 GW of new storage capacity by 2050, all of which could support at least 80% of renewable generation penetration. The U.S. had about 23 GW worth of installed energy storage capacity in 2020.
Michigan Tech Researchers said a pumped hydro mine storage could become a seasonal asset, with four pumping and discharge cycles per year and a maximum cumulative power of 8.7 GW, or 8,010 GWh per season.
Mather B’s mine tunnels are now used as storage for nearby Negaunee High School | Mining History Association
The team analyzed Mather B’s dimensions, structural integrity, soil and water contamination, and property rights to come up with five pumped-storage designs that range from fully to partially subterranean and are capable of pumping different volumes of water. The designs use combinations of the shaft and surface pond, with equipment reaching to the mine’s mid- or deep levels.
“I joke with people that because there are so many ways to design this, it’s really a choose your own adventure book,” Scarlett said. “It is a question of what’s the most appropriate design, what are people most excited about? It doesn’t have to have a large visual footprint on the landscape.”
The team found the mine could support maximum power and energy capacities of 1,666 MWh under a daily energy storage model and 52,188 MWh for the seasonal energy storage model.
Scarlett said developers must refit a mine’s existing infrastructure with modern hydropower technology. But he said the turbine sizes and floodgates’ diameter are up to developers. He said designers could also use vertical boring mechanisms to add new shafts that take advantage of existing underground caverns.
“Nothing is prohibitively expensive; they’re all established mining practices,” Scarlett said, noting that developers can update old mine powerhouse and transmission systems for two-way power flows.
“Because these mines were big consumers of power in their operational lives, they either have already-active electricity hookups or legacy hookups,” he said.
Optimism for Concept
“I think we’ve made a really good case about why these facilities should be built,” Sidortsov said. “Based on the strides that companies in Europe are making, I think it will take off.”
Finland’s Pyhäsalmi Mine is set to host pumped-hydroelectric energy storage. Sweden boasts grid-scale energy storage company Mine Storage that develops and operates underground storage projects.
U.S.-based Rye Development has also filed an application with FERC for a 50-year permit to operate a 200-MW pumped-storage project in a former coal strip mine in Kentucky. Rye plans to complete the project by 2030.
Sidortsov predicted that underground pumped storage will be built on a “shift in the way we approach technology” that consists of “an alignment of not just the engineering bits, but the alignment of conviction of more people to engineer the facilities.” He said getting storage built in mineshafts requires “thoughtful government support” that holistically values resilience and takes a long view on energy assets.
Scarlett said an underground pumped-hydro storage facility could function like Michigan’s Ludington Pumped Storage Plant that’s been operating for 50 years.
“It’s been a profitable endeavor, not in a renewables environment, but in a coal- and nuclear-generation environment,” he said of the plant’s life span. “Once one of these is up and operating, there’s no reason to think that it couldn’t operate on a half to full-century timeframe.”
Scarlett said utilities “desperately” need to solve the problem of storing renewable output, calling it the “elephant in the room.” He said an array of storage options will be necessary and a mine storage operation can fill a need for otherwise limited grid-scale storage options. “I think people are going to be looking at this very, very seriously. It’s complicated and planning heavy, but it solves so many problems.”
A municipality could bank cheaper power at night, then sell it back to its own residents in a kind of “arbitrage driven by the community,” he said. Wholesale markets could also benefit from the facility’s ability to regulate load, shave peak and provide ancillary services and black start capability.
“It’s like a hydropower plant, where you can start it up quickly,” Scarlett said.
Michigan Tech researchers estimated the capital cost of draining the Mather B mine and installing a pumped storage facility at about $1.34 million/MW. Scarlett said Michigan Tech used “very cautious and reasonable” cost estimates.
“Mining companies dewater mines all the time and assess the mine integrity,” he said. “If one were really designing [pumped underground storage hydropower] in a mine, this would be a critical part of the work.”
Public-Private Partnerships
Scarlett said he envisions public-private partnerships producing the first mine storage facilities. He said states could invest in or provide subsidies for retrofitting.
“If you’re going to do it at scale and quickly, it’s going to be a big endeavor,” he said. “Convincing investors to do this is the risky part.”
The underground storage facilities would have variable profits depending on a multitude of factors, including design choices, but they “could be made to be profitable rather quickly,” Scarlett said.
“It will likely be expensive to build these facilities at first … but the advantages of building a large-scale pumped hydro facility underground and doing so quickly are tremendous. It makes it a very compelling case from a social perspective,” he said.
“Deployment of these facilities can be streamlined though public-private partnerships because many potential sites are located on public lands and can provide a wide range of benefits to the surrounding communities,” Sidortsov said. “What I’m not very optimistic about is the ability of our industry and governments to forge this kind of public-private partnerships. It doesn’t mean that the idea is doomed. It needs a positive and sustained momentum … If those things emerge, then we might be talking about kind of a revolution.”
He said a mine’s pumped storage facility will likely be on par financially with conventional pumped storage.
“So, we’re already at least in the vicinity, in the ballpark,” Sidortsov said. He said that though “virtually any energy technology has higher costs before it is deployed at scale, underground pumped storage can be an exception to this rule because of the reuse of the existing infrastructure, subterranean spaces and surface mine sites.”
“In the last three decades or so, the conventional wisdom about pumped storage hydro development has been that it was no longer feasible at scale in the U.S. because of the site availability,” he said. “Well, now we have at least 962 potential sites that pose lower environmental and community acceptance barriers. It would be a shame to not take advantage of them.”
Sidortsov added that the facility could create economic development “in areas that are really hard to develop economically.” He said pumped storage in mines could become firm, hybrid resources for rural areas where electricity rates tend to run high.
“If you do that, there’s an incidental benefit for other things, maintenance jobs, construction jobs [and] lower electricity rates,” he said. He said some of the ideal mine sites identified by Michigan Tech are in California, “where there’s a dire need for storage.”
A Hedge Against Severe Weather
A mine’s environment can provide a buffer against increasingly extreme weather and most natural disasters, Scarlett said.
“Of all those surface issues — save for earthquakes — the mine is the ideal storage facility,” he said. “You can’t drive a truck bomb into it, right? It’s underground. There are several non-monetized benefits to this.”
Sidortsov agreed that an underground pumped storage facility will be less vulnerable to floods and droughts.
“You would be fairly certain about what the total capacity would be. In the mine, there’s no evaporation. It’s only in-flow,” he explained.
If built at maximum capacity, a storage facility in the Mather B mine could furnish three-and-and-a-half months of uninterrupted power to its surrounding communities should they be islanded from the larger grid, Scarlett said.
He said the hydropower storage operations could tackle environmental improvements and pumping could be paired with a water-remediation system.
“Generally, whenever you talk about a mine, there are concerns about water quality,” Scarlett said. “You could attach water treatment to the facility, where the water gets treated during operations, and so the facility could actually improve the local ecosystem rather than continuing existing polluted discharges.”
He said some developers might be able to take advantage of water-remediation tax incentives. Older mines continue to leak contaminated water into communities “because no one is financially responsible” for them, Scarlett said.
An energy storage facility that also can mitigate environmental damage could be an “ideal solution” for communities experiencing cultural depression and economic contraction after mine closures, Scarlett said. The team’s next steps are to help those communities assemble their own analyses patterned on the Michigan Tech study.
“It’s what drives me in this work,” Scarlett said. “Communities can be involved in steering the direction of development.”
The research leads also said the team will examine pairing mine storage facilities with other energy operations, such as solar and wind generation or geothermal energy, that use the warm water already pumped up. Scarlett said new analyses may lead to developers selling minerals reclaimed from the filtering process.
“We’re at a point where we can think about combined systems and nesting them in different ways,” Scarlett said. “We wanted our … first study to show just how a facility would work on its own. Now, we want to show it in partnership with other uses.”
He said he’d like his team’s study to lead to more modeling in the U.S. on “how infrastructure can be reimagined to be multipurpose.” He said energy storage in abandoned mines can become a “sustainable economic engine … especially once industrial wealth commercialization leaves, and often leaves these communities hurting.”
Sidortsov said he foresees the Mather B mine becoming a good site for further studies or a pilot project.
“Frankly, there still has to be a lot of studying done before we can proclaim it as a commercially scalable technology,” he said.
Sidortsov said he views the concept as a “regulatory, economic, engineering and cultural Lego game” more than the creation of a new technology. “You’re not inventing anything new. You’re inventing a new way for those components to fit together, and the Lego figure that emerges at the end can be of a truly transformative kind.”
The Pacific Northwest stands out as an exception to the increasingly dire water supply situation gripping the wider West, boding well for the region’s hydroelectric potential heading into summer.
While regional officials in Southern California last week imposed “unprecedented” water-use restrictions on 6 million residents in the region and the state confronts declining reservoirs and dismal snowpack levels, Washington state faces the summer with dramatically improved water conditions compared with a year ago.
According to data released Thursday by the U.S. Drought Monitor, about 49% of Washington is not experiencing drought conditions, mostly areas from the Cascade Range to the coast. At this point last year, just under 9% of the state was designated as not being in drought after an exceptionally dry spring.
About 17% of the state is designated as being in “severe” drought, compared with nearly 30% a year ago, and no areas are currently in “extreme” drought, versus just under 4% last year.
A “drought” means that rainfall is less than 75% of normal and that hardships are expected because of a lack of water.
Some areas of Central and Eastern Washington still experiencing drought should eventually benefit from the runoff issuing from unusually high snowpack levels at upper elevations. Snow telemetry data from the U.S. Natural Resources Conservation Service show snow water equivalent (SWE) is currently at 215 to 221% of the average in the Upper, Central and Lower Columbia regions, 289% of the average in the Upper Yakima region, and 347% of the average in the Central Puget Sound region.
The improving conditions prompted Washington to dramatically cut back on its drought emergency late last month.
Last July, Gov. Jay Inslee declared a drought emergency for 96% of the state, citing the severe effects of climate change. Last year’s declaration sped up processing for emergency drought permits and allowed temporary transfers of water rights. The cities of Seattle, Tacoma and Everett were not included in the drought emergency because they have significant amounts of stored water.
As of May 26, all of Washington from the Cascade Mountains and to the west were removed from this designation. Most of Eastern Washington, except for four areas, was designated as a drought advisory area. A “drought advisory” means that rainfall is now above the 75% mark but could potentially drop below.
Five watersheds clumped in from areas spread across parts of eight northeastern Washington counties are still in states of “drought emergencies” because they have not received enough rainfall to recover. This land covers about 9% of the state. The drought emergency area covers parts of Spokane, Lincoln, Grant, Adams, Whitman, Stevens, Okanogan and Pend Oreille counties.
“2021 saw extreme temperatures and near record-low precipitation across much of the state,” Jeff Marti, the Washington Department of Ecology’s drought coordinator, said in a May 26 press release. “In 2022, conditions have been much more normal, but we’re still trying to make up a deficit in some places. Extending the drought declaration for these areas will give us more tools to manage water supplies and respond to changing conditions.”
Impacts from last year’s drought that are expected to continue through this summer include low soil moisture, dried-out ponds, earlier-than-normal curtailments for irrigators in Colville, the Little Spokane River and Hangman Creek, and low reservoir storage in Okanogan County, the press release said.
Mixed Conditions in Oregon
To the south, in Oregon, the picture is decidedly more mixed.
Northwest Oregon has emerged from drought after heavy rainfall this year, but conditions are worsening in other parts of the state. | U.S. Drought Monitor
A year ago, the entire state was experiencing drought, with nearly three-quarters designated as being in severe to “exceptional” drought conditions. After a spring of persistent and heavy rains, the northwest corner of Oregon — about 19% of the state, including the Portland metro area and lower Willamette Valley — has emerged from drought.
But the outlook has worsened farther inland, with the portion of Oregon classified as being in exceptional drought (the highest designation) expanding to 11.8%, from 3.5% a year ago, concentrated in the central part of the state east of the Cascades. An even larger portion of the state is in extreme drought, in an area stretching from Eastern Oregon to the south and west, along the California border.
As in Washington, Oregon SWE levels generally far exceed averages for this time of year, with the basin containing the Hood, Sandy and Lower Deschutes rivers at 349% of normal; the Umatilla, Walla Walla and Willow rivers region at 280% of normal; and the Willamette River basin at 219%. The only region with critically low snowpack is the drought-stricken Lake County region in Southern Oregon, currently at 15% of average.
‘A Bit of Good News’
The heavy snowpack in the Northwest should help recharge the region’s extensive network of hydroelectric dams this summer, although some industry observers are still cautious. The largest of those dams, mostly operated by the Bonneville Power Administration, sit in Central Washington or along the Oregon-Washington border on the Columbia River. Others dot smaller rivers in the region, many of them tributaries to the Columbia.
As in its U.S. neighbors to the south, snowpack in the British Columbia is above normal for this time of year. | British Columbia Ministry of Forests
Speaking at a WECC summer readiness workshop May 24, Amanda Sargent, senior resource adequacy analyst at the NERC regional entity, noted that Pacific Northwest hydroelectric output last year was 14% below the 10-year average, based on data from the U.S. Energy Information Administration. But conditions have changed drastically since the start of the current water year last September, when all of Oregon and Washington were in some level of drought.
“Is it going to be like it was last year? Are we going to see the same effects? It’s impossible to say,” Sue Smith, WECC resource adequacy analyst, said at the workshop. “But I did want to point out that compared to last year, our net generation is higher. It was higher in January, and it was higher in February,” the last months for which data were available.
Another encouraging sign for hydro production can be found in British Columbia — the source of the Columbia River — where government-owned utility BC Hydro operates a massive hydroelectric network on the Columbia and Peace rivers that typically produces ample electricity surpluses exported to the rest of the Western Interconnection.
In “a lot of our service territory right now, the snow levels — or the snow water index, as we refer to them — is quite high, quite healthy,” Brett Hallborg, senior system control manager at BC Hydro, said during the WECC workshop. “So that’s a good news story for BC Hydro and its resource adequacy. But it’s also probably a bit of good news for WECC and its resource adequacy [that] we do have quite a bit of water.”
The most recent data available show SWE at 118% of normal in the Peace River basin and 123% in the Upper Columbia basin.
Hallborg noted that cool weather this spring has delayed this year’s snowmelt, a condition that applies equally to Oregon and Washington.
“And, in fact, just recently in a kind of a new climate change-type storm, we got some fresh snow fall in each of those areas, which is a little unheard of even for us at this time of year,” Hallborg said.
ERCOT is expecting demand to peak at over 70 GW this week, as above-normal temperatures continue to bake the Lone Star State.
The Texas grid operator last week projected peak demand of 74.9 GW for Monday and more than 75 GW on Tuesday. Both would break its all-time record of 74.8 GW, set in August 2019.
Demand before noon Sunday had already hit 55.1 GW. During the same interval Saturday, demand peaked at 51.1 GW. In its last summer resource adequacy report, ERCOT forecasted a record peak demand of 77.3 GW this year.
Triple-digit temperatures are projected to swamp Austin this week. | Apple/The Weather Channel
Temperatures are expected to exceed 100 degrees Fahrenheit all week in Austin. Temperatures in the Houston region along the Gulf of Mexico are predicted to hit the mid-90s, compared to the normal high of 90 F.
ERCOT closed out May by setting another peak demand mark for the month on its last day at 71.7 GW. The monthly record had been 67.3 GW set in 2018, but that was exceeded several times before May 20.
The grid operator said it had more than 91 GW of resources to meet demand, but it has been bedeviled by forced and maintenance outages that have taken more than 20% of the thermal fleet offline. That outage number was down to 6% on Sunday.
Renewable resources have helped filled the gap by regularly providing 20 to 25% of ERCOT’s energy.
The grid operator has already issued two operating condition notices (OCNs), its lowest-level communication in anticipation of a possible emergency condition, before the summer months begin. Any emergency condition comes when staff determine the system’s safety or reliability is compromised or threatened.
The first OCN was issued on May 3 and extended several times through May 20. A second OCN was issued for May 28-30.
ERCOT asked Texans to conserve electricity on May 13, which officials later termed a “request.” Interim CEO Brad Jones has said he is “confident” about the summer, while Public Utility Commission Chair Peter Lake continues to say the grid “is more reliable than it has ever been before.” (See ERCOT, PUC Say Texas Ready for Summer.)
Three bills that passed the New York legislature last week in the final hours of its session seek to embed the state’s climate law into decision-making processes for certain cryptocurrency mining operations and heating and cooling for buildings.
Here’s a look at what the bills will achieve if Gov. Kathy Hochul chooses to sign them.
Building Codes
The Advanced Building Codes, Appliance and Equipment Efficiency Standards Act (A10439) would strengthen New York’s appliance efficiency standards and align the state’s building codes with the Climate Leadership and Community Protection Act (CLCPA). The bill would update the state’s energy law to go beyond merely encouraging the conservation of energy to promoting the “clean energy and climate agenda,” which includes reducing greenhouse gas emissions in new and rehabilitated buildings.
Application of the bill’s measures would save consumers $15 billion in utility costs by 2035, of which $6 billion is in low- to moderate-income households, according to the legislature’s bill analysis.
The Natural Resources Defense Council called passage of the bill a “big win for New Yorkers.”
“The legislation will result in a reduction of GHG emissions of 17 million tons, which is comparable to taking more than 3.5 million cars off the road for a year,” Samantha Wilt, senior policy analyst for NRDC’s climate and clean energy program, said in a statement.
A new definition of life-cycle cost in the bill would guide regulators’ consideration of the cost-effectiveness of potential amendments to the state energy conservation construction code. Regulators would be required to consider the estimated cost of acquisition, operation, maintenance and construction of an energy system over the life of a building, with specific attention to cost of fuel, among other things.
The bill also would ensure that efficiency standards and regulations do not increase emission of co-pollutants, such as sulfur dioxide and nitrogen oxides, or burden disadvantaged communities.
All provisions of the bill would take effect within six months of enactment.
Thermal Networks
The Utility Thermal Energy Network and Jobs Act (S9422) would change the definition of New York’s electric and gas utilities so they can own and operate thermal energy networks and supply thermal energy to consumers. It would also direct the Public Service Commission to initiate a proceeding within three months of the bill’s enactment to advance development of thermal networks to meet the GHG emissions and equity goals of the CLCPA.
Utilities would have three months from enactment to propose at least one, and up to five, thermal network pilot projects, ensuring at least one pilot per territory is within a disadvantaged community.
Thermal energy, as defined in the bill, refers to piped, noncombustible fluids that transfer heat in and out of a building to eliminate GHG emissions of heating and cooling processes. A thermal network would be defined as the infrastructure that supports a utility-scale project that supplies thermal energy.
Another provision of the bill seeks to support utility workers potentially affected by the downsizing of the gas system, with a priority placed on their transition for the operations and maintenance of thermal networks.
The Building Decarbonization Coalition, together with a group of union organizations and climate advocates, applauded passage of the act and called on Hochul to “act quickly” to sign the bill. The bill would take effect immediately.
Crypto Mining
A bill (A07389) that would amend New York’s environmental conservation law seeks to place a temporary moratorium on cryptocurrency mining operations that use an authentication method called proof-of-work (PoW) to validate blockchain transactions.
The PoW method uses substantial amounts of energy because of the high level of computations necessary for the process. Large cryptocurrency mining operations have sprung up around the PoW methodology, including some in New York, and the increase has prompted concerns about the associated energy use potentially preventing the state from meeting its GHG emission reduction targets.
Annual global energy use for PoW authentication is equivalent to that of Sweden, according to the legislature’s bill analysis.
For two years from the bill’s enactment, New York environmental regulators would not be able to issue an air permit to a fossil fuel-fired power plant that provides electricity for PoW cryptocurrency mining. They also would not be able to renew an air permit for a facility that plans to increase electricity supply for PoW mining.
To help the state understand the effects of PoW mining on energy use and the environment, the Department of Environmental Conservation would develop a generic environmental impact statement for the cryptocurrency operations in the state.
While environmental advocates applauded passage of the legislation, the Blockchain Association called it “misguided” in a tweet Friday. “We encourage all pro-tech New Yorkers to make their voices heard and ask the governor to veto” the bill, it said.
New York Gov. Kathy Hochul on Thursday announced awards for 22 solar and energy storage projects totaling 2,078 MW, the state’s largest land-based renewable energy procurement to date.
The New York State Energy Research and Development Authority estimates the projects will drive over $2.7 billion in private investment and create over 3,000 short- and long-term jobs while helping achieve the state’s environmental goals.
The Climate Leadership and Community Protection Act requires the state to obtain 70% of its electricity from renewable sources by 2030 and to make the grid net-zero by 2040.
“These projects will allow us to not just meet but exceed our goal of obtaining 70% of our electricity from renewable resources and will further cement New York as a national leader in the fight against climate change,” Hochul said.
“Today’s announcement of 22 exciting new clean energy project awards demonstrates that New York state continues its strong commitment to clean our electric grid, and the renewable energy industry is seriously stepping up to develop and invest in New York. We look forward to the construction jobs and pollution-free power these projects will deliver,” Anne Reynolds, executive director of the Alliance for Clean Energy NY, said.
The 22 large-scale projects feature several solar facilities combined with co-located storage, including the 350-MW Ridge View Solar Energy Center in Niagara County with 20 MW of storage; the identically sized Columbia Solar Energy Center in Herkimer County; the 240-MW Rich Road Solar Energy Center and 20-MW storage facility in St. Lawrence County; and the 250-MW Fort Covington Solar Farm with 77 MW of co-located storage in Franklin County.
