The Department of Energy on Nov. 27 said it would provide $275 million for seven projects around the country that are meant to bolster domestic clean energy supply chains.
The agency announced the funding at the inaugural meeting of the White House Council on Supply Chain Resilience, which includes Energy Secretary Jennifer Granholm and other administration officials.
DOE said the $275 million will leverage over $600 million in private-sector investments, which will help create 1,500 high-quality jobs. The projects are intended to address clean energy supply chain vulnerabilities by supporting key materials and components for batteries for grid and transportation uses, wind energy and energy-efficient buildings.
“President Biden’s Investing in America agenda is driving the manufacturing boom while preserving the communities and workforce that have powered our nation for generations,” Granholm said. “With these historic investments, DOE will bring new economic opportunities and ensure these communities continue their key role in strengthening America’s national and energy security.”
The projects aim to strengthen domestic clean energy supply chains by making them more resilient and cost competitive. The projects are with small and medium-sized manufacturers, and they address multiple needs in the domestic clean energy supply chain.
Alpine High-Performance Products will get $5.8 million to retrofit its existing facilities in Louisville, Colo., and Vandergrift, Pa., to produce ultra-thin, triple- and quad-pane insulated glass units for windows. The project will increase the firm’s production tenfold and create 100 good-paying jobs, DOE said.
Boston Metal is getting $50 million to build a new facility in Weirton, W.Va., to manufacture ultrapure chromium and high-temperature alloys used for clean power, fuel cell and green steel supply chains. The facility will be the only high-purity chromium and refractory metal alloy factory, and it will create 200 jobs.
Carter Wind Turbines is getting $20 million to build a new facility in Vernon, Texas, which will help scale production of hybrid wind turbine and energy storage systems that can be used to help power remote facilities. The firm expects to create 300 new jobs at the factory.
CorePower Magnetics is using its $20 million to help retrofit a retired coal plant in Pittsburgh for melting and casting of advanced magnetic amorphous alloys for grid components. The old plant is being used to leverage a significant network of utilities, transportation and facilities to create a factory that will install 10,000 tons of capacity for amorphous metals and magnetic component production. CorePower’s new facility is expected to increase domestic production by 20% and meet an estimated 10% of global demand for the materials.
FastCap Systems, doing business as Nanoramic Laboratories, is building a new facility in Bridgeport, Conn., to make new lithium iron phosphate battery electrodes for grid storage with help from $47.5 million in federal funds. The new manufacturing process at the plant is expected to cut costs, increase energy density and cut energy consumption.
LuxWall is getting $31.7 million to build a new facility in Detroit that will manufacture vacuum-insulated glass window units, which, when retrofitted onto buildings, provide one of the highest energy-efficient returns on investment. The facility is being built on the site of an old coal plant in the Delray neighborhood of Detroit and should create 277 jobs.
The biggest award from the announcements is the $100 million going to MP Assets Corp. to build a factory for lithium-ion battery separators that are important for electric vehicles, a sector dominated by China. The new facility will create 282 jobs on top of securing a domestic supply of the car components.
LA QUINTA, Calif. — Researchers are still in the early stages of determining the challenges, efficacy and cost of using hydrogen for both transportation fuel and blending with natural gas as part of the effort to transition to green energy.
Katie Jereza, vice president of corporate affairs at the Electric Power Research Institute (EPRI), discussed the viability of blending hydrogen into natural gas infrastructure during a Nov. 14 panel at the annual meeting of National Association of Regulatory Utility Commissioners.
“As we’re looking to decarbonize the economy, fuel blends with higher hydrogen content can result in lower carbon emissions per megawatt hour,” Jereza said.
According to the U.S. Department of Energy, hydrogen can play a role in decarbonizing up to 25% of global energy-related carbon emissions. But the details are still being worked out in tests and demonstrations done by EPRI and other research facilities.
EPRI recently completed a series of four tests blending different percentages of hydrogen into reciprocating internal combustion engine (RICE) natural gas units to see if hydrogen could lower emissions without compromising structural integrity. While each test yielded different results, overall takeaways concluded that hydrogen blending could be one key piece of a larger puzzle to reach a net zero economy.
One of the tests conducted by EPRI in May, in collaboration with WEC Energy Group and Wärtsilä Energy, found that blending 25% hydrogen into RICE units reduced carbon emissions by up to 10% with no significant impact to the efficiency of the system.
Jereza and other engineers say that making the most out of the infrastructure that’s already in place will save time and resources; EPRI made no modifications to the gas turbines used in their tests.
“Using hydrogen can enable natural gas assets and infrastructure to be leveraged as a resource for decarbonization in this integrated energy network,” Jereza said.
She added that while recent innovations in burner design and fuel staging enhanced the ability of gas turbines to accommodate fuels with high hydrogen content, more work is needed to develop turbine components suitable for 100% hydrogen combustion.
Uncertainties Remain
Argonne National Laboratory published findings in October on modeling that found blending 30% hydrogen into pipelines yielded only a 6% decrease in emissions. Its study also concluded that blending at that level significantly increased leakage and compromised the integrity of the pipeline.
Because hydrogen is a smaller molecule than methane and is substantially lower in density, it can easily crack solid metals. As a result, fuel supplies and other system components, such as the materials used in pipelines, may need to be re-sized to account for the increased volume of fuel and pressure needed to reach the same output, Jereza said.
Jeffery Preece, director of research and development at EPRI, told NetZero Insider that gas infrastructure materials start to become impacted when a blend exceeds about 20% hydrogen.
Critics also question hydrogen’s ability to decrease greenhouse gas emissions along the supply chain. The most commonly used hydrogen is “blue” hydrogen, which is produced by combining natural gas with high-temperature steam, a highly energy-intensive process that results in carbon emissions unless combined with a carbon capture system.
Engineers and power producers are looking to green hydrogen produced through electrolysis — and without GHG emissions — as an alternative.
Preece said the goal of most hydrogen blending tests, including EPRI’s, is to ensure that all emissions are accounted for in the value chain process associated with the production and use of the fuel. Using hydrogen produced with fossil fuels could divert from the goal.
“The focus is, of course, can hydrogen be produced from low-carbon pathways, so we use the ‘green’ moniker to demonstrate the hydrogen made from electricity and then that electricity comes from renewables,” Preece said. “So depending on the economics and use case, carbon capture and sequestration technologies can be used on the hydrogen facilities, and then it’s just a matter of the economics and the viability of how much CO2 is captured from that process.”
Preece pointed out there is little low-carbon hydrogen production occurring in the U.S. today, with most still being produced from natural gas.
More work is needed to understand the cost and efficacy of integrating hydrogen into the energy system, according to Preece and Jereza.
“When we look at the total energy economy, we’ll be able to find ways to reduce the total energy wallet,” Jereza said. “But I’d say that there’s a lot of uncertainties still around how affordable it will be.”
The New Jersey Senate Environment and Energy Committee took testimony last week on a bill that would put into law the state’s goal to reach 100% clean energy by 2035, sparking business concerns that the state is overreaching and union fears that it could create jobs outside of the state.
Gov. Phil Murphy (D) put the target into effect by executive order, committee Chair Bob Smith (D) said at the start of a hearing on S2978 on Nov. 20. Murphy’s successor could simply change it by enacting their own executive order, said Smith, the sole sponsor of the bill. Making it the state’s renewable portfolio standard (RPS) would make it more likely to remain in effect.
“There are no guarantees that the next governor will be as green as the current governor,” Smith said. “An executive order is only a rule. … When state government is making decisions about investments, what we should be doing or not doing, you need a guiding principle.”
But Ray Cantor, senior lobbyist for the New Jersey Business and Industry Association (NJBIA), said he received the latest version of the bill only four days before and had not had time to analyze the implications. He urged the committee to hold off voting until a later date.
“We have concerns generally with setting artificial deadlines to meet artificial goals in a period of time that may not be practical or implementable,” Cantor said. “When you do that, you end up making decisions that may not be the most cost effective, the most technologically feasible and the best public policy. You’re driving decisions based on deadlines put in law and not necessarily what’s realistic economically or on the ground.”
The committee did not vote on the bill at the end of the five-hour hearing, most of it focused on S2978. Smith said he would review the testimony and adjust the bill, and the committee would vote on it Dec. 18.
It was one of two Smith-sponsored bills considered, but not voted on by the committee, that could bring sweeping changes to the state’s clean energy efforts. The second, S3992, would require the New Jersey Board of Public Utilities (BPU) to create a plan to modernize the state’s electric transmission and distribution system and would allocate $300 million to do so. Smith said at the hearing that he does not expect the bill to be ready by the time the legislative session ends in January and that it will be introduced in the next session.
New Clean Energy Certificates
The RPS bill states that New Jersey is on track to satisfy 75% of its annual energy use with clean energy by 2025 and 84% by 2030. Smith said the bill would help the state reach 100%.
“Rapidly increasing clean electricity generation to achieve 100% of retail sales of electricity in New Jersey by 2035 will help displace fossil-fueled electricity generation and thereby reduce greenhouse gas and co-pollutant emissions,” the bill says.
It outlines a mechanism to reach that goal by creating Clean Electricity Attribute Certificates (CEACs), each of which represents “1 MWh of generation from a clean electricity production facility whose electricity is produced in New Jersey or acquired through the PJM Interconnection.”
Electricity generation providers and suppliers would be certified and “procure and retire” CEACs to meet a set of goals: at least 80% matched by June 1, 2027; 85% by June 1, 2030; and 100% by June 1, 2035. The bill would also allow CEACs to be replaced by clean energy certificates generated by existing state programs, including solar renewable energy certificates, Zero Emission Certificates from nuclear plants and offshore wind Renewable Energy Certificates.
The bill also sets a goal of in-state clean energy sources meeting 65% of New Jersey’s electricity demand, with the remainder supplied from out of state. If the state does not appear ready to reach the 65% target, the bill allows the BPU to “procure additional electricity” out of state.
Investment and Jobs
Jesse Jenkins, an assistant professor and energy systems engineer at Princeton University, said a team he heads had modeled New Jersey’s clean energy plans, including the impact of S2978, and believes it would “help meet our climate goals, and all while maintaining affordability and reliability of New Jersey’s electricity supply.”
“The law would ensure more clean electricity would be generated in-state in 2035 than is generated by all resources —both fossil power plants and clean sources — today,” he said. “That ensures a steadily expanding market for clean energy, investment and jobs in the state. … We estimate that under the proposed law, New Jersey electricity customers would pay less for their electricity supply and 2035 than we did in 2019.”
The law would support 24,000 jobs building, operating and maintaining electricity generators, including in the solar and offshore wind sectors, Jenkins said. More than 90% of the subsidies provided by state programs would go to generators within New Jersey, supporting investments and jobs in the state, he added.
Jenkins said the bill would also keep the state’s three nuclear plants open and would “not require natural gas plants to retire until clean, reliable replacements are available.” Gas plants could remain open until 2045, so they could be “called upon by the grid operator to meet reliability needs, while substantially reducing their generation overall and therefore their pollution,” he said.
Artificial Deadlines
But NJBIA’s Cantor said he believed gas-powered plants would be used for far more than just providing “reliability” services for when renewables could not cover demand. He argued that the grid is not ready for the amount of new clean electricity proposed in the bill. And he said NJBIA has concerns that the jobs created may actually be out of the state.
“If we don’t have the infrastructure to be able to hook up to solar developments, we’re really just driving those jobs, money, everything else out of state,” he said.
Jennifer Mancuso, director of government affairs for NJ LECET, a labor management cooperative that is part of the New Jersey Laborers Union (LIUNA), said the organization is also concerned about where the new jobs would go. She said LIUNA agrees with the state’s decarbonization goals but is concerned by the “considerable discretion” the legislation gives the BPU to seek energy out of state if New Jersey does not meet the 65% goal of in-state clean energy production.
Eric Miller, director of New Jersey energy policy for the Natural Resources Defense Council, said the committee should consider the impact of not adopting the legislation and where it would get its energy in that scenario. New Jersey is currently an energy importer and so already relies on out-of-state sources to meet demand, in large part, he argued, because fossil fuel-fired power is more expensive in the state.
“But for policies like this legislation that we’re considering, we would produce even less electricity in New Jersey,” he said. “[In] a purely competitive market, we buy it from PJM, almost every time. The only way to shift that needle back into New Jersey is through policies like this legislation.
“With this legislation, we could be a clean energy powerhouse.”
Hydrogen hasn’t gotten this much publicity since the Hindenburg. And never more U.S. taxpayer money, now estimated at $137 billion over the next 10 years.[1] And of course, federal policymakers waving wands over hydrogen, begging the question posed by The Lovin’ Spoonful, “Do You Believe in Magic?”[2]
Here we’ll cover some reality about hydrogen in the electricity sector.
Hydrogen does not exist on Earth as a standalone atom. You have to make it by separating it from a molecule it is part of, like water or a fossil fuel.
There are different ways of making hydrogen, and each way has been given its own color – nine and counting.[3] I’m not going to get into the debates about grey hydrogen (from fossil fuels), blue hydrogen (from fossil fuels with carbon capture), or myriad other colors. Here we’ll just talk about pure green hydrogen, from electrolysis of water using green electricity. Basically you use green electricity (from wind, solar, etc.) to separate the hydrogen and oxygen atoms that are in water molecules.
Green hydrogen electricity is very inefficient. You need a supply of electricity (and ultrapure water[4]) for the electrolysis, a way to store and transport the hydrogen (or an intermediary carrier like ammonia), and then a generator to turn the hydrogen back into electricity. Essentially two round trips.
The pure energy equivalence between electricity and hydrogen is 39.4 kWh to produce 1 kg of hydrogen,[5] and the most efficient electrolysis technology is around 80%,[6] so best case it takes 49.3 kWh to produce 1 kg of hydrogen. That creates the hydrogen. If the green source of electricity costs say $30/MWh,[7] then with the most efficient electrolysis the hydrogen costs $37.5/MWh equivalent.
Now we need to store and transport the hydrogen.[8] The most efficient storage and transportation method is probably converting hydrogen to ammonia, storing and transporting ammonia, and converting ammonia back to hydrogen.[9] The round-trip efficiency is 34%.[10] So that $37.50/MWh hydrogen equivalent from the prior paragraph becomes $110.30/MWh hydrogen equivalent from the ammonia round trip.
Now we’ll use this hydrogen to generate electricity. The most efficient turbine I can find for turning hydrogen back into electricity is the GE turbine 9F.04 in the 1×1 combined cycle configuration at 443 MW, which GE’s calculator says would require 22,307 kg/hour,[11] which converts on a pure energy basis to 879 MWh,[12] for a conversion loss of 50% (output of 443 MWh divided by input of 879 MWh). So if the cost of the hydrogen input is $110.30/MWh, the cost of the converted electricity output is $220.60/MWh. Thus, the initial $30/MWh electricity supply we started with has a delivered electricity cost of $220.60/MWh.
Just so we’re clear, $30/MWh green electricity becomes $220.60/MWh green electricity, a cost increase of 735%. Put another way, it would take 7 MWh of green electricity at the source to end up with 1 MWh of green electricity delivered to consumers.[13] So for every 1 MWh used, 6 MWh are wasted.
The foregoing is just about the energy conversion losses. The capital and non-fuel operating costs of the water purifier, electrolyzer, storage, transportation and generation facilities are extra. And those costs are, to use a technical term, ginormous.
Oh, if you’ve been following hydrogen news you may note that the analysis I provide here is in terms of end-to-end MWh costs, whereas hydrogen costs are talked about in terms of $/kg with a moonshot, aka “Hydrogen Shot,” objective of getting green hydrogen’s current cost of $4-6/kg down to $1/kg.[14] I doubt that’s realistic but in any event it’s largely irrelevant to green hydrogen electricity. The dollar per kg cost is cost at the outlet of the electrolyzer, before the losses and other costs of storage, transportation and generation. What really matters for green hydrogen electricity is the cost per MWh you start with and the cost per MWh you end with.
By the way, few gas turbine models can burn 100% hydrogen, and many turbine models are limited to hydrogen percentages like 5%, 15% and 30%.[15] Since thousands of gas turbines are supplied by dozens of major interstate gas pipelines, it begs the question of how various custom hydrogen-natural gas blends would be mixed, stored and transported across the country. And that still leaves the carbon emissions from the natural gas in the blended stream — if carbon capture were economic for that then it would be economic without using any of the incredibly expensive hydrogen.
By the way, blending hydrogen into existing natural gas systems for transportation is unrealistic (as are total conversions). Not only are there many physical incompatibility issues, such as those the National Renewable Energy Laboratory has described,[16] but hydrogen requires three times the volume for the same energy content as natural gas,[17] so blending hydrogen reduces the amount of energy transported (and stored via line pack).[18] And millions of end-use appliances served by a given pipeline are incompatible with a hydrogen blend above 20-30%[19] which means either: (1) the dominant natural gas supply would continue to create carbon emissions (or be wasted), or (2) there would need to be a one-time total conversion to hydrogen entailing modifications/replacements of all these appliances at the same time. Good luck with those options.
And one more thing. Notwithstanding the Department of Energy’s claim that its recently announced “hydrogen hubs” will “slash harmful emissions,”[20] green hydrogen electricity creates more NOx emissions than natural gas electricity. As much as twice for equivalent energy content.[21] This does not mesh with public health and environmental justice concerns.
[8] Storage and transportation are necessary because all green electricity that could be used as electricity as generated should not involve hydrogen at all. Projects that would involve diverting grid-connected green electricity generation into hydrogen production, rather than simply consuming the green electricity as generated, make no sense.
[13] There are unusual situations where this analysis may not apply, such as where the green electricity source would otherwise be curtailed and efficient storage like salt caverns is available.
[18]https://www.nrel.gov/docs/fy23osti/81704.pdf. NREL points out (page 14) that it may be possible to compensate for lower energy content with increased flow via higher pressure, however higher pressure would be inconsistent with the lower pressure likely needed for steel integrity.
The Bureau of Ocean Energy Management last week approved the Empire Wind project for construction, making it the sixth commercial-scale offshore wind farm to receive approval from the federal government.
The Department of the Interior said the joint venture between Equinor and BP supports the Biden administration’s aim to deploy 30 GW of OSW by 2030 and would assist New York and New Jersey in achieving their respective targets of developing 9,000 MW and 7,500 MW of OSW energy by 2035.
The project consists of two farms, the 816-MW Empire Wind 1 and the 1,260-MW Empire Wind 2, about 12 nautical miles south of Long Island and about 16.9 nautical miles east of Long Branch, N.J., respectively. EW1 is anticipated to be operational by 2027 and EW2 a year later, according to the New York State Energy Research and Development Authority.
BOEM’s Record of Decision documents environmental mitigation strategies, including compensating fishers impacted by construction in the lease area.
The approval is a positive development for an industry beset by problems recently, including regulatory setbacks, local opposition and financial constraints stemming from rising inflation that has led to project cancellations.
Danish company Ørsted canceled its two New Jersey OSW projects, Ocean Wind 1 and 2 this month after it said surging interest rates and supply chain disruptions made them unfeasible. (See Ørsted Cancels Ocean Wind, Suspends Skipjack.) A week later, Eversource Energy cited inflation as the reason for divesting its stake in the Revolution, South Fork and Sunrise projects. (See Eversource Closer to Exiting OSW Venture with Ørsted.)
Empire itself appeared to be in jeopardy after the New York Public Service Commission last month denied a request to amend power purchase agreements because of inflation pressures. (See NY Rejects Inflation Adjustment for Renewable Projects.)
New York on Nov. 30 will launch a new OSW solicitation open to all, including those with existing contracts, allowing developers to re-propose their projects at higher prices and offering an option to withdraw from previous agreements.
“A New York parade of positive developments has lifted the industry over the past month,” Oceantic Network CEO Liz Burdock said. BOEM’s approval of Empire maintains “the industry’s forward momentum while still ensuring environmentally responsible development.”
Empire “will stimulate the regional economy, revitalize ports and create many new job opportunities — including new manufacturing, installation, maintenance and operations jobs,” said JC Sandberg, chief advocacy officer at the American Clean Power Association.
Clean Ocean Action, an environmental organization based in Long Island, said it was concerned about the approval, writing on Facebook that the government was “fast-tracking” OSW projects.
“Too many questions remain unanswered about the impacts of offshore wind projects, such as Empire Wind 1 and 2, to move so quickly and recklessly forward with massive ocean industrialization,” the group said. “The ocean deserves more care, especially since it’s a prime buffer for climate change impacts.”
Green municipal aggregation (GMA) programs have cut costs for consumers in Massachusetts while lowering emissions, according to a new report by the Green Energy Consumers Alliance (GECA). However, the slow rate of approvals of new municipal aggregations at the state’s Department of Public Utilities (DPU) has limited the reach of these programs, researchers said.
GMAs are a type of community choice aggregation, which enables a municipality to buy electricity in bulk for ratepayers. GMAs include higher amounts of renewable energy certificates (RECs) than are required by the state’s Renewable Portfolio Standard (RPS). The RPS requires electricity suppliers to acquire a minimum number of RECs based on the amount of electricity they supply.
The researchers at GECA — a clean energy advocacy group that supports expanding municipal aggregation programs — compared the costs of 41 GMA programs to the basic service rates offered by the state’s investor-owned utilities from August 2017 to October 2023. The GMA programs included in the study had 5-11% more Class I RECs than the state’s RPS requirement.
The study estimated the active GMAs across the state are “adding approximately 1 million megawatt hours of renewable energy to the grid above and beyond RPS requirements per year,” equal to the power demand from 150,000 to 200,000 homes, largely displacing natural gas generation.
“That’s a pretty good number, and it’s gravy all on top of the state’s renewable portfolio standard,” said Larry Chretien, a co-author of the report and the executive director of GECA.
Regarding cost savings, the report found GMA customers saved an average of 3.3 cents per kWh compared to standard utility rates, equaling $200-$237 of annual savings for a household that averages 500-600 kWh per month.
These savings largely came from the ability of municipal aggregations to time their bids for energy supply when prices are lower, compared to the fixed schedule of supply procurements required for utility basic service, the study said.
Although GMA rates typically were lower than utility basic service, they were marginally higher than municipal aggregations that did not exceed the number of RECs required by the state’s RPS, Chretien told NetZero Insider.
“For every 5% of additional RECs that you include, it adds roughly 0.2 cents per kilowatt hour,” Chretien said. He noted that the increased cost of GMAs compared to typical municipal aggregations is small relative to the savings over utility rates and that customers can choose to opt out of the GMA to get the lowest price.
While GMAs have delivered significant benefits for Massachusetts residents, the report singled out the slow pace of municipal aggregation application approvals at the state DPU as a barrier to increased implementation.
Several municipalities have been waiting in the DPU’s queue for multiple years. There are 23 aggregation plans pending before the DPU, while only one new community has received an order of approval since the start of 2022.
In August, the DPU announced a proceeding to create guidelines for the municipal aggregation approval process and proposed an “expedited review process” for aggregation plans that comply with an established template (D.P.U. 23-67). The new guidelines are aimed at streamlining the approval process while making sure ratepayers are properly informed and protected.
“Municipal aggregation is an important tool for communities to utilize clean energy, provide ratepayers with more flexibility, and help cities and towns pursue our collective clean energy and climate goals,” DPU Chair Jamie Van Nostrand told NetZero Insider in a statement. “Addressing these delays is a top priority for the DPU, and we look forward to announcing finalized guidelines that will help facilitate a timely review of applications.”
The DPU’s proposal has received pushback from municipalities and other stakeholders (including the state’s Department of Energy Resources) for limiting the flexibility available to communities.
“Quite frankly, we’re disappointed in what they proposed,” Chretien said. GECA’s study concluded it’s debatable whether “the proposed guidelines and templates would adequately support the municipal aggregation model or further impinge the model’s ability to bring economic and environmental benefits to the Commonwealth.”
In response to a large number of comments, the DPU recently scheduled a technical session Dec. 20 to discuss the proposal with stakeholders.
Meanwhile, GECA is supporting legislation introduced in the Massachusetts House and Senate which would impose a 90-day timeline on the DPU to approve aggregation plans and amendments.
AUSTIN, Texas — The 20th Texas Energy Summit, organized by the Texas A&M University System’s Energy Systems Laboratory, again focused on the intersection of air quality and energy, with sessions on energy management, renewable energy, storage, zero-emission fleets, sustainability and resiliency during the Nov. 14-16 event.
Attendees explored policies and programs that improve the environment, advance new technologies, reduce costs and waste, and foster economic development.
Not that Texas needs to foster economic development. It already has the eighth largest economy by GDP in the world ($2.36 trillion), having passed Italy last year. The state’s economy is expected to overtake France’s within the decade, Texas Association of Business CEO Glenn Hamer said.
Texas’ lax regulatory environment and cheap labor have attracted much of that business. That, in turn, has led to a staggering population increase, putting a strain on the state’s infrastructure. Citing employment data from the state and national sources, Texas says it led all 50 states in job creation over the past 12 months, adding more than 391,000 jobs to a workforce that now numbers a record 15.16 million. The 2.9% growth rate is better than the national average of 1.9%.
“Not only do we have, depending on who you talk to, anywhere from 1,000 to 1,200 people moving to Texas every day, but nobody’s bringing water with them or more power,” said Kathleen Jackson, interim chair of the Texas Public Utility Commission.
“Customer demand is increasing very quickly. We’re seeing industrial growth, huge industrial growth,” said Warren Lasher, who opened an eponymous consulting firm when he left ERCOT two years ago.
He chose Samsung’s “monster” $17 billion semiconductor lab being built in Taylor, not far from ERCOT’s lead operations center, as an example of that growth. The 1,200-acre site is twice as large as Samsung’s flagship facility in South Korea.
“And then we’ve got the Tesla [Gigafactory in Austin]. We’ve got LNG facilities being built along the coast. We’ve got industrial growth in the Corpus and Houston ship channel, just between Austin and Dallas. There’s an enormous amount of increased industrial demand data centers. “And then if you look down the road, electric vehicles coming online, potentially hydrogen facilities, more LNG facilities.”
Lasher, who handled system planning for much of his 17 years at ERCOT, said the answer is more transmission.
Jackson chose a different direction, referring to energy efficiency as “the little black dress.”
“It goes with everything,” she said, including manufacturing, residential and small business. “So, as we move forward in Texas, I think we’re very, very well-positioned to be able to do things here that we can’t do anywhere else in the nation or maybe even the world. We’re growing, we have a competitive market that actually promotes innovation. I’m really excited about where we are today.”
An audience member asked Jackson whether Texas would accept federal funding for a rebate program that compensates Texans who retrofit their homes with energy efficient appliances. Florida, a state that, like Texas, is sometimes allergic to the federal government, recently rejected the grant and with it, access to $341 million the Inflation Reduction Act allotted to fund the program.
Jackson paused for a moment before responding to the question.
“I’m advocating for energy efficiency, for demand response and for using the resources that we have,” she said. “There are so many things involved in that particular decision as to whether you [think] that particular financing is appropriate for Texas. In my personal viewpoint, we have many resources here already that we can really pull together and we can use to move forward and make a difference.”
Texas politicians have been focused on dispatchable power from thermal resources since the disastrous and deadly February 2021 winter storm, despite the fact those very resources were unable to access fuel during the event and became part of the problem. This year’s legislative session responded with the Texas Energy Fund (TEF), a $7.2 billion low-interest loan program intended for the development of up to 10 GW of natural gas plants that voters approved Nov. 7. (See 2023 Elections Bring Billions for Texas Gas, Dem Wins in Virginia, NJ.)
“There’s a couple of different ways you can approach [dispatchable power]. One is from the demand side and the other is the consumption side,” Democratic State Sen. Nathan Johnson said. “On the demand side, we did what government often does well, sometimes poorly, and that is subsidize.
“The side that was neglected largely, but not completely, was the demand side. The fastest way to have extra power is to not use it, right? Don’t bake cookies at 5:30 when the grid is about to go down,” he said, alluding to the conservation notices that have become a part of ERCOT’s summer operations.
“We got notes and everybody got mad about it, because we’re so used to having a surplus of electricity,” Johnson said.
Asked why energy conservation isn’t one of the tools in the state’s toolkit, he said, “It’s not politically popular. But to think that the solution would be to spend money making systems more efficient or spend money to reward customers for not losing electricity just doesn’t have the same political punch as the other.”
Johnson did manage to add $1B to the TEF bill to set up microgrids at critical facilities, such as hospitals and fire states.
“If the grid goes down, you do not want nursing homes, water towers, water treatment facilities, law enforcement, hospitals, grocery stores, you don’t want those things to be without power,” he said. “We’ve created a plan where we’re going to subsidize the purchase by municipal entities and small private businesses that control vital systems to deploy these backup power systems that will give them power for a couple of days while we fix the grid.”
CPS Puts GRIP Grant to Good Use
CPS Energy CEO Rudy Garza celebrated his utility’s award of a $30 million grant from the U.S. Department of Energy’s Grid Resilience and Innovation Partnerships (GRIP) Program. He said he was proud CPS was the only Texas utility to receive a GRIP grant and one of the largest utility awards nationally. (See DOE Announces $3.46B for Grid Resilience, Improvement Projects.)
“Finding revenue that doesn’t have to come from our ratepayers is really, really important to us,” he said, noting the funds will be used to install batteries and solar panels at substations. Garza said CPS has chosen three substations on the east side of the city “where a lot of our low-moderate income customers are.”
“We’re thinking about underserved communities, we’re thinking about how [energy burdens] customers and how to continue to protect those folks,” Garza said. “We’re going to put this technology there so that in the event that we’re in a load-shed moment, that we’ll be able to keep those particular substations on and learn how to make our systems more resilient. I think we’re going to learn a lot from it and I think it’ll create opportunities for [DOE] going forward.”
He recalled sitting in the DOE offices with San Antonio Mayor Ron Nirenberg and CPS Board of Trustees Chair Janie Martinez Gonzalez. Garza said the trio told the department it was going to improve the substations anyway.
“Partnering with the DOE allows us to bring those costs down and make them more affordable for our customers,” he said. “I think that was a message, quite frankly, that resonated with the Department of Energy.”
One thing in Texas’ favor in addressing skyrocketing growth is ERCOT’s ability to quickly interconnect new resources. Whereas the process can take up to 10 years or more in some regions, it can take as little as five or six years in the Lone Star State.
“Unlike other markets, aside from the transmission planning challenges, the interconnection process is tremendously faster and it is also much more [transparent] about when we’re actually going to get online,” Cypress Creek Renewables’ Matthew Crosby said. “We take the risk with [generic transmission constraints] popping up in markets where we might not have anticipated other generation was going to locate, or where load was going to locate. But that’s the risk that we’re willing to take to be able to have more certainty, because that certainty is really valuable for our customers.”
David Treichler, director of strategy and technology for Oncor, said the utility had been spending about $1 billion a year hooking up new customers. Oncor now is adding between 60,000 and 70,000 new meters every year, with costs approaching $3.25 billion when 2023 is up.
“We try to get people connected as quickly as possible, but we’re also trying to identify places where we need to build new transmission that will serve the areas that [renewable developers] are looking at,” he said. “We work very collaboratively with the people who are developing generations to try to make sure that we have the lines in the right place.”
ISO-NE has provided additional information on the second phase of its Longer-Term Transmission Planning project, which is intended to facilitate transmission investments to meet the states’ policy goals.
The proposal would enable the New England States Committee on Electricity (NESCOE) to direct ISO-NE to issue a request for proposals (RFP) to address concerns identified in a longer-term transmission study (LTTS). After soliciting proposals, ISO-NE will consider stakeholder input and select a preferred solution to solve the identified issue.
Following ISO-NE’s selection of a solution, NESCOE will have 30 days to either accept the default regionalized cost allocation methodology, propose a new methodology or terminate the process.
“If a different cost allocation method is selected, the costs needed to address the reliability and/or market efficiency needs will be regionalized, while the additional costs to address the longer-term needs are subject to the alternative cost allocation methodology,” Brent Oberlin of ISO-NE said.
At the October TC meeting, ISO-NE said it’s considering assigning some projects to incumbent transmission owners, instead of going through the RFP process. However, following mixed feedback from stakeholders, ISO-NE proposes to abandon this aspect of the project.
“The ISO is concerned that further work on this concept will delay the Phase 2 effort and understands NESCOE’s interest in establishing this process without delay,” Oberlin said.
Oberlin also clarified that the LTTS process will be separate from the RTO’s public policy process, which exists to fulfill transmission needs associated with state, federal and local policy requirements.
ISO-NE will respond to feedback and introduce the initial proposed tariff redlines at the Dec. 21 TC.
The timeline for building the Nemadji Trail Energy Center (NTEC) in Wisconsin has been pushed into next year as clean energy groups continue to challenge the need for the planned gas-fired plant.
Minnesota Power, Dairyland Power Cooperative and Basin Electric Power Cooperative filed an update with the Public Service Commission of Wisconsin to report that onsite relocation work on the $700 million plant in Superior, Wis., won’t begin until April. Work was originally slated to begin in the third quarter of this year (9698-CE-100).
The utility and cooperatives now say the 625-MW NTEC won’t reach commercial operation until 2028 — not March 2027, as anticipated in the last update in July.
Dairyland said the holdup is a result of permitting, litigation and supply chain delays. In an email to RTO Insider, Dairyland spokesperson Katie Thomson said delays could drive up the cost of the project and risk grid reliability.
NTEC still needs a wetland permit from the U.S. Army Corps of Engineers and a stormwater permit from the Wisconsin Department of Natural Resources.
The slowdown comes as the Sierra Club and Clean Wisconsin continue to argue that the plant is harmful and unnecessary.
The two environmental groups this year asked the Wisconsin PSC to reopen the docket and rescind its 2020 approval of the plant. They also appealed a 2022 decision on their lawsuit alleging that the PSC failed to consider the full environmental impact of the plant (2020CV000585).
Last year, Dane County Circuit Judge Jacob Frost upheld the regulators’ approval of NTEC and said the PSC followed the law when issuing a certificate of public convenience and necessity, though he acknowledged the “massive impacts a major project of this nature holds for the state.”
In its 2020 decision, the Wisconsin PSC concluded that renewable energy combined with battery storage was “not yet capable of replacing a plant of this size.”
But the two groups argue that the planned construction of 489 MW in battery projects in Wisconsin will be complete a few years before NTEC is slated to begin running and is enough to negate the need for the plant.
They also continue to insist that the utility and cooperatives didn’t sufficiently analyze alternatives before settling on the gas plant. The groups maintain the cooperatives should instead pursue some of the $9.7 billion in federal funding available through the Inflation Reduction Act to help rural electric cooperatives transition from fossil fuels to renewable generation.
The groups say customers will be paying to recover the costs for NTEC at least into the 2050s, past the end date of most net-zero carbon pledges.
This year, Clean Wisconsin attorney Brett Korte said the PSC has a chance to reconsider the plant “to protect ratepayers and the environment by recognizing that the energy landscape has fundamentally changed since 2020.”
“This plant was always a bad investment, but it would be incredibly unwise to leave so much money on the table and stubbornly stick with fossil fuels that are going to harm communities and the environment in Wisconsin. The new federal funding really is a game changer, and Wisconsin should do everything it can to capitalize on the opportunities it presents,” Korte said.
Superior Mayor Jim Paine has changed his tune on the plant, saying it’s no longer needed. In a July letter commenting on a revised supplemental environmental assessment by the Department of Agriculture’s Rural Utilities Services, Paine said his “change of heart, mind and spirit” boils down to Dairyland’s acquisition of the 503-MW RockGen Energy Center gas plant in 2021, the ramp-up of renewable energy and energy storage, and a belief that the NTEC site is ill-suited for industrial development.
Construction will require the developers to fill in about 20 acres of wetlands on the banks of the Nemadji River. It would also be located near indigenous mass burial grounds.
Nemadji Trail Energy Center project map | Minnesota Power, Dairyland Power Cooperative and Basin Electric Power Cooperative
The Sierra Club said NTEC would be located “at the top of a steep slope with a historically high risk of erosion, potentially causing stormwater runoff.” The group pointed out that the utilities estimate they will have to pump almost three million gallons of water daily to operate the plant, close to the total daily water usage of the City of Superior itself.
Four of the Superior City Council’s 10 members — Nicholas Ledin, Jenny Van Sickle, Garner Moffat and Ruth Ludwig — also submitted letters of opposition. The council passed a resolution in favor of the plant in 2019.
Dairyland Says Plant is Crucial
Dairyland insists the plant is necessary to fill lulls in renewable energy output, delivering a bridge to a zero-carbon future. It also said the plant could be retrofitted to operate on up to 30% hydrogen.
“Today, there are not commercially available, utility-scale long-term battery storage technologies on the market to meet current and anticipated energy requirements,” Thomson said. “Currently, battery storage simply does not have the ability to replace the 24/7 power generated by power plants. A battery supplies energy measured in hours between charges, whereas a power plant supplies reliable energy for days, weeks or even months when wind and solar are unable to meet the demand for electricity.”
However, Thomson added that Dairyland is “enthusiastic” about batteries and other forms of energy storage and noted the co-op is exploring pumped hydro storage in abandoned mines and was recently awarded a battery storage grant from the Department of Energy.
She said NTEC’s ramping capability will help support Dairyland’s planned portfolio of 12 new wind and solar projects totaling 1.7 GW that could be funded under the IRA’s Empowering Rural America program, the same $9.7 billion program the Sierra Club and Clean Wisconsin urged the cooperatives to pursue.
Thomson said NTEC will dependably supply power at “60% less carbon, 100% less mercury and 97% less other emissions than coal.”
Clean Wisconsin has said rather than reducing emissions, the plant will annually release 3 million tons of carbon pollution into the environment.
The plant would operate as a merchant generator selling power in MISO markets. The RTO last year commented in support of the plant to the Rural Utilities Service, saying it would welcome new gas-fired capacity to bolster resource adequacy in its footprint. (See MISO Executives Spotlight Fleet Evolution Planning, Risks.)
Community groups are hailing the Kentucky Public Service Commission’s decision this month to reject a proposed gas plant from Louisville Gas & Electric and Kentucky Utilities (LG&E-KU) while greenlighting multiple planned solar installations and coal plant retirements.
The Kentucky PSC’s order authorized LG&E-KU to build only one of two 640-MW natural gas plants that it proposed in its $2.1 billion integrated resource plan and allowed the retirements of the coal-fired Mill Creek Units 1 and 2 and three smaller gas-fired units (2022-00402).
The coal retirements total about 600 MW, while the gas unit retirements will subtract about 47 MW from LG&E-KU’s portfolio. They will take place from 2024 to 2027.
The commission also denied approval of the companies’ requested retirement of KU’s coal-fired Ghent Unit 2 and Brown Unit 3, totaling almost 900 MW. It said the retirements should be deferred until it’s clearer what new environmental regulations will be enforced.
The new gas plant will be located at LG&E’s Mill Creek station. The PSC disallowed LG&E-KU’s proposal for a second new natural gas plant at KU’s E.W. Brown station.
The PSC also allowed all six of LG&E-KU’s proposed solar facilities at a combined 877 MW, a 125-MW battery storage plant and the utilities’ 2024-2030 demand-side management plan that includes more than a dozen new energy efficiency programs.
The storage project will be Kentucky’s largest utility-scale battery. The commission said the solar facilities will offer “significant savings” to customers and noted the critical role battery storage can play in the resource transition.
Intervenors in the case — Mountain Association, Metropolitan Housing Coalition, Kentucky Solar Energy Society and Kentuckians for the Commonwealth — say that the PSC’s ruling is a landmark decision that advances clean energy in a state whose legislature earlier this year enacted a law requiring the commission to review planned fossil-fueled power plant retirements using a presumption that they should remain in operation (SB4).
In a joint press release, the groups said they were disappointed with the approval of a new natural gas plant and the decision to keep two aging coal plants online. However, they said the order “offers major advances for clean energy in Kentucky and indicates that the PSC is weighing the risks of new and existing fossil fuel plants pose to ratepayers.”
“LGE-KU must not ignore this opportunity to ramp up efficiency programs, solar energy and battery storage to make any additional gas plants unnecessary,” they said.
“The denial of a $650 million, 40-year commitment to a risky natural gas plant is a major victory for ratepayers,” said Catherine Clement of Kentuckians for the Commonwealth. “And the closure of those old Mill Creek coal units will mean better air quality for the people of Louisville and the surrounding region.”
Josh Bills of the Mountain Association said LG&E-KU realizes that the plants are too costly to continue to operate because they require “massive investments to bring them into compliance with air and water quality regulations.” He said the Kentucky PSC’s order establishes a course for future coal plant retirements and “importantly” acknowledges that energy efficiency programs and distributed resources can reduce demand enough that the output from the Ghent and Brown units might not need to be replaced with an expensive new gas plant.
Chris Woolery, representing the Mountain Association, agreed that successful energy efficiency programs could shave enough demand to offset the need for a major power plant.
Tony Curtis of the Metropolitan Housing Coalition said his organization is looking forward to assisting LG&E-KU on implementing the new energy efficiency offerings, especially for those who “struggle to pay their bills each month and can really benefit from home energy improvements.”
After the PSC’s order, PPL — the parent of LG&E-KU — said in a U.S. Securities and Exchange Commission filing that the utilities’ planned capital investments in new and existing facilities in Kentucky are “materially consistent” with the utilities’ original $2.1 billion plan.
John Crockett, president of LG&E-KU, said the utilities are “pleased” that the PSC approved many aspects of the original plan.
