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September 4, 2024

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DC Circuit Strikes down Emissions Standards for ‘New’ Pre-2020 Boilers

A three-judge panel of the D.C. Circuit Court of Appeals on Sept. 3 set aside EPA emission rules on new large boilers as they applied to those built prior to August 2020, ruling that was a violation of the Clean Air Act (22-1271). 

The rules, issued in October 2022, set National Emission Standards for Hazardous Air Pollutants (NESHAP) for major sources focused on industrial, commercial and institutional boilers. A source is considered “new” under CAA Section 112 if it is built after EPA proposes an emission standard for that source, which the agency did for boilers in August 2020. The court found that EPA had improperly classified certain industrial boilers built before then as “new.” 

In doing so, the court agreed with industry petitioners, led by U.S. Sugar, which completed building a boiler to help power its facility in Clewiston, Fla., in 2019 at a cost of $65 million to replace three older and higher-polluting boilers to comply with standards issued by EPA in 2011. 

Boilers burn materials such as coal, paper and agricultural waste to create heat, electricity and other forms of energy. That comes with emissions of pollutants like mercury, carbon monoxide and particulate matter. 

U.S. Sugar’s boiler also “surpassed” EPA’s 2022 standards for existing sources, the court said. But under EPA’s rules, it was considered a new source. “Under this regime — whose logic suggests that boilers built after June 4, 2010, are forever ‘new’ — the U.S. Sugar Corp. must spend tens of millions of dollars retrofitting” the boiler, it said. 

EPA is supposed to base its standards around the maximum achievable control technology (MACT), which can vary between new and existing sources. New sources are supposed to meet a standard at least as strict as the emission control that is achieved in practice by the best controlled similar source, while existing sources have to meet one at least as stringent as the best performing 12% of operating sources for which EPA has emissions data. 

The agency argued that because it was using the same dataset as when it proposed the 2011 standards, the cutoff date for whether a source is “new” is June 4, 2010, when the proposal was first published.  

But the court found that “when Section 112 references the date ‘an emission standard’ is ‘first propose[d],’ it means the first proposal of each consecutive standard.” It noted that while existing sources are given three years to comply with new standards, new sources are expected to be in compliance upon their effective date. The court pointed to other cases challenging EPA rulemakings for other types of new sources under Section 112 in which the agency also noted this in its arguments. 

“EPA itself has explained that retrofitting older sources to comply with increasingly stringent modern standards may be ‘draconian’ if not ‘impossible,’” the court said. “And we should not lightly assume that a statute is ‘draconian’ or ‘demands the impossible.’” 

Environmentalists including Sierra Club also appealed the rules, but because they said EPA used old data, despite more recent data being available. But the court found that did not violate the CAA. 

In other cases, the court has generally acknowledged that EPA may exercise discretion and use its expertise to calculate standards. The environmentalists’ view would offer no discretion to EPA when choosing its data, which could force the agency to use faulty data if that was all it had, the court said. 

“Because that interpretation of Section 112(d) would substantially hamper EPA’s ability to effectively promulgate standards, we reject environmental petitioners’ interpretation and hold that EPA’s decision to rely on its original dataset was not unlawful,” the court said. 

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Heat Pump Tech Could Help Decarbonize Dairy Sector, CEC Says

The California Energy Commission (CEC) is exploring the use of heat pump technologies to accelerate decarbonization in the dairy sector, which accounts for 2.5% of the state’s energy consumption and 1.4% of greenhouse gas emissions.

Home to over 1,100 dairy farms and over 130 dairy product processing facilities, California leads the nation in milk production and is the second largest cheese producer. In 2020, the U.S. dairy industry announced a goal of net zero carbon emissions by 2050, and commissioners identified that transitioning from thermal resources to heat pump technologies for processes like pasteurization, evaporation and cleaning could lead to significant energy savings while reducing reliance on fossil fuels.

“Knowing how important the dairy sector is to California’s economy and knowing we could bring some innovation to the sector, [we can] really work together with industry to improve the carbon footprint,” CEC Commissioner Andrew McAllister said during an Aug. 29 meeting to discuss decreasing dairy emissions.

Through the Food Production Investment Program, the CEC has awarded up to $117.8 million in grants to help food producers reduce greenhouse gas emissions, including to six California dairy facilities.

“These projects have or will improve operation efficiency and lower production costs, and in general maintained or increased the quality and quantity of production,” said Matthew Stevens, a CEC staffer representing the Food Production Investment Program. “We have done a lot of waste heat capture and storage, general system overhauls, and recently, we’re tackling to replace very inefficient, aging, high global warming refrigeration systems.”

‘Where Everybody Wins’

Several experts who focus on the decarbonization of industrial facilities presented at the meeting, all highlighting the potential for heat pumps to improve energy efficiency in the dairy sector.

Dr. Ahmad Ganji, director of San Francisco State University’s Industrial Assessment Center (IAC), said there are “significant opportunities for energy efficiency in dairy processing plants,” with efficiency increases of at least 10-15%. The IAC analyzes and informs industrial facilities about how they can decarbonize, and Ganji said it plans to recommend heat pump technologies at dairy processing plants as the technology improves.

Most of the emissions from dairy processing facilities come from natural gas-powered steam boilers used for pasteurization and other processes requiring heat, according to Arun Gupta, CEO of Skyven Technologies.

“Twenty percent of global carbon emissions are caused by industrial heat, which, for context, is about as much carbon impact as all of transportation, all of the cars, trains, planes, boats, everything combined,” Gupta said. “Half of that is steam, so steam is enormous.”

Skyven developed a new steam-generating heat pump technology, designed for use in dairy processing plants, that can generate steam for heating and cooling at lower prices than boilers that run on natural gas.

“That allows us to achieve the deep decarbonization that the industry is looking for,” he said. “Decarbonization solutions must be cost competitive with existing boilers and, better than cost competitive, they actually need to save money … Where everybody wins is where decarbonization and cost savings go hand-in-hand.”

Skyven was recently awarded a $145 million grant from the U.S. Department of Energy to deploy steam-generated heat pumps across multiple manufacturing sectors, including California dairy facilities, with the goal to make the technology an industry standard. Gupta estimated the project will cut GHG emissions by around 400,000 metric tons, produce 1,000 jobs and benefit over 300,000 people through cleaner air.

Curtis Rager, product manager at Johnson Controls, provided additional background on how heat pumps could increase the efficiency of refrigeration systems at dairy facilities. Most dairy plants use ammonia as a refrigerant that is pumped throughout the system and absorbed at the point of use.

For example, refrigerant is sent to milk silos which absorb heat that then flows through the system and is discharged into the atmosphere via evaporative condensers. The process of heating milk up for pasteurization and then cooling it back down requires a lot of heat usage, and pumps could help offset discharged waste heat.

“[Heat pumps are] capturing that ammonia refrigeration gas steam that’s going to the evaporative condenser and it’s now taking that and it’s going through another stage of compression,” Rager said. “With a second stage of compression in the heat pump portion you can pump up that temperature … and now through the condenser, you can bring the cold water in and produce hot water all from the energy that was absorbed … from those evaporators.”

The system would allow for significant energy- and water-use savings, contributing to Gupta’s goal of simultaneous decarbonization and reduction of costs.

“We believe that steam decarbonization is crucial for the decarbonization of the industry, and this technology allows that to happen in a way that is profitable for manufacturers and allows them to achieve both the savings and the carbon reductions that they’re looking for,” Gupta said.

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NPCC, NYSEG Agree to Settle Control Center Violation

FERC accepted a settlement between New York State Electric and Gas (NYSEG) and the Northeast Power Coordinating Council in which the utility admitted to violating NERC’s requirements for maintaining backup control centers.

The settlement, which carries no monetary penalty, was filed by NERC in its monthly spreadsheet Notice of Penalty on July 31; it was the only settlement in the spreadsheet and the only NOP filed that month (NP24-10). In a filing issued Aug. 30, FERC said it would not further review the settlement. Commissioner Judy Chang did not participate in the decision.

The settlement stemmed from a violation of EOP-008-2 (Loss of control center functionality), approved by FERC in 2018 in order to “ensure continued reliable operations of the [electric grid] in the event that a control center becomes inoperable.” NPCC discovered the noncompliance during an audit in 2020.

According to the settlement, NPCC found that NYSEG’s backup and primary control centers used a shared communication path with a single point of failure. This contravened requirement R6 of the standard, which mandates that reliability coordinators, balancing authorities and transmission operators ensure their primary and backup control centers maintain separate functionalities.

NPCC reported that seven communications lines terminated in a single room common to both the primary and backup control centers. In the event of a “catastrophic event” at the primary control center, the utility would lose its connection with about 150 remote terminal units (RTUs), 62 of which provide data from its substations. This represents a loss of data from more than half of its 121 grid-connected RTUs.

Further investigation revealed that NYSEG had discovered the issue during a prior audit in 2017 and labeled it an area of concern. The utility first sought to address the problem with its telecommunications vendor, but the vendor delayed implementation of the proposed solution for more than a year before telling NYSEG in 2019 that it “could no longer support the solution as designed.”

NYSEG then pursued a permanent solution, which was “in the planning stages” when NPCC conducted its 2020 audit. But the regional entity said the utility did not assign the task the necessary priority or management oversight, and thus the violation lasted longer than it would have with proper prioritization. Along with EOP-008-2, NPCC also found that NYSEG had violated the standard’s predecessor, EOP-008-1, which was in effect when NYSEG registered as a transmission operator and was required to comply with it.

NPCC assessed the violation as a moderate risk to grid reliability. It pointed out that the shared point of failure would have reduced NYSEG’s visibility into its system and compromised its ability to work remotely if the primary control center became inoperable. The RE said a catastrophic event compromising the primary center “would likely be a long-duration event,” exacerbating the risk.

At the same time, the RE acknowledged that the risk of such a catastrophic event affecting the primary control center is low. It also pointed out that even if NYSEG lost its ability to monitor the system, NYISO and neighboring TOPs and BAs could still monitor their respective systems, ensuring some visibility into the grid’s health.

NPCC determined that no monetary penalty would be required in light of NYSEG’s cooperation in the enforcement process, lack of prior relevant noncompliance and agreement to settle the matter rather than calling for a hearing. However, the RE did feel it necessary to elevate the matter to the spreadsheet NOP because of the length of the noncompliance and the fact that it became aware of the issue through a compliance audit rather than the utility reporting the problem itself.

To mitigate the problem, NYSEG removed the single point of failure by migrating the communications lines. It also created a new NERC compliance tool to monitor compliance projects and make sure schedules are maintained properly, trained relevant personnel on the tool, and updated its project management procedures to specify that leadership must review the project management plan when changes to a project’s schedule are needed.

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Texas PUC Sets Reliability Standard for ERCOT

Texas’ regulatory commission has adopted a reliability standard for the ERCOT region, one of several policy parameters that will be used in upcoming analyses for the proposed performance credit mechanism (PCM) market design. 

As approved by the Public Utility Commission during its Aug. 29 open meeting, ERCOT must meet three criteria to comply with the reliability standard: frequency, duration and magnitude. To meet the standard, ERCOT outages should not occur more than once in 10 years on average, last more than 12 hours or lose more power than can be safely rotated (54584). 

“Our system must continue to evolve to meet the growing demand for power in our state … it’s critical we clearly define the standard at which we expect the market and system to operate,” PUC Chair Thomas Gleeson said in a statement. “By establishing a reliability standard for the ERCOT region today, we are setting a strong expectation for the market and charting a clear path to further secure electric reliability.” 

The new rule also establishes a process to regularly assess the ERCOT grid’s reliability. The commission directed ERCOT staff to conduct a probability-based assessment every three years, beginning Jan. 1, 2026, to determine whether the system is meeting the standard and is expected to continue to do so over the next three years.  

Should that assessment indicate the system fails to meet the reliability standard, the Independent Market Monitor (IMM) must conduct an independent review and commission staff must recommend their own potential market design changes. The PUC then would review ERCOT’s assessment, the IMM’s review, commission staff’s recommendations and public comments to determine whether any market design changes are necessary. 

ERCOT and IMM staff confirmed during the meeting that they have all they need to begin their respective analyses. Draft results are due to the PUC in early November; the commission will consider the final results in December. 

The ISO said it will use 19 GW as the amount of load it can safely rotate during an outage in its cost/benefit analysis, as it proposed in an April research paper. 

The reliability standard was just one of several actions the PUC took to establish regular assessments of the grid’s ability to meet demand and help determine any necessary future improvements. 

It adopted a value of lost load of $35,000/MWh, using information from a survey of ERCOT consumers and a Brattle study. Staff proposed a $30,000 VOLL, but Gleeson recommended Brattle’s suggested $35,685, saying it was “reasonable” after a “detailed and thorough” analysis (55837). 

“We don’t need the extra numbers in there,” Gleeson said. 

ERCOT will use VOLL for cost/benefit analyses in its planning models. The PUC said it will not be used to update the operating reserve demand curve or any current market-design elements. 

The commission also accepted staff’s final recommendations for each of the PCM’s 37 base case parameters, including a firm $1 billion gross cost cap to comply with state law (55000). ERCOT had proposed a counterfactual of energy-only market equilibrium reserve margin instead of the cost cap, a “purely theoretical number,” according to Stoic Energy principal Doug Lewin. 

PUC staff and ERCOT also differed on four other parameters: the metric to determine performance credit (PC) hours; a duration-based cap for consecutive PC hours; the net-cost cap compliance framework; and non-performance penalties for PCs offered but not cleared in the forward market. 

The PUC selected the PCM from among five other suggested market reforms as its design of choice and approved it in 2023. That same year, the Texas Legislature passed a bill setting a $1 billion annual cap for the PCM. (See Texas PUC Submits Reliability Plan to Legislature.) 

The PCM will use the reliability standard and a corresponding quantity of PCs that must be produced during the highest reliability risk hours to meet the standard. Load-serving entities can purchase PCs, awarded to resources through a retrospective settlement process based on availability during hours of highest risk, and trade them with other LSEs and generators in a forward market; generators must participate in the forward market to qualify for the settlement process. 

CPS Energy MRA, RMR Update

ERCOT told the PUC it has changed course on must-run alternatives for three retiring CPS Energy coal units, postponing an inspection of the largest unit until after the winter season (55999). 

The San Antonio municipality told the commission this year it planned to retire the three coal units, which date back to the 1960s, in March 2025. However, ERCOT said the Braunig Power Station units, with a combined summer seasonal net maximum sustainable rating of 859 MW, were needed for reliability reasons and issued a request for reliability-must-run proposals in July. (See ERCOT Evaluating RMR, MRA Options for CPS Plant.) 

The grid operator said in an update to the commission that while it continues to negotiate a potential agreement with CPS Energy to inspect the 412-MW Unit 3, it would be “more prudent” to allow the resource to operate through the winter’s peak demand period. ERCOT staff said the inspection could be held in mid-February or early March. 

“If we waited until after winter peak load, we believe we’d still have plenty of time, barring unforeseen circumstances, to have the unit inspected and repaired during another shoulder season for outages and before the summer peak load season,” ERCOT’s Davida Dwyer said. 

The ISO extended the deadline for RFP responses to Oct. 7 after receiving fewer than 10 proposals to its initial request. (See “ERCOT Extends MRA Timeline,” ERCOT Board of Directors Briefs: Aug. 19-20, 2024.) 

Chad Seely, the ISO’s general counsel, told the commission the deadline would provide an “important data point” in seeing whether the industry has responded with enough MW to provide relief for a constrained area south of San Antonio. 

“The additional time affords us a more deliberative process on these critical policy issues to see if the industry is going to respond to the must-run alternative,” Seely said, “and then continue to move forward [on] a path where we still think it’s appropriate and prudent for reliability to start to open up the unit in advance of any April 1 RMR agreement.” 

“Is it looking bleak on the MRA?” Commissioner Lori Cobos asked Seely.  

Noting that ERCOT has amended the RFP after stakeholder feedback, he said, “We’re hopeful, with the amendments that we put forward and allowing almost another month of time for people to go do their due diligence, and talk to their shops about options, that we will see a higher [number] of offers come in in October.” 

“Ultimately, I don’t want RMR to be the norm, right?” Cobos responded. 

Seely said the three units are in a “prime” location to relieve the constraint’s interconnection reliability operating limits (IROLs), which makes the pre-RMR inspection work such an “extraordinary situation.” 

“[Braunig] is one of the best assets right now in the system, until we see other solutions to help relieve the overloads of the IROL for the next couple of years,” he said. “That’s why it’s critically important to be deliberative and these critical policy issues on how we approach this.” 

CPS has said it will cost about $22 million to inspect, repair and prepare Braunig Unit 3 to remain in service past March and an additional $35 million for the other two units. 

Utility and energy storage company Eolian announced Aug. 28 an agreement for two storage facilities south of San Antonio totaling 350 MW of capacity. The projects are not expected to come online until 2026, but work to upgrade the transmission infrastructure and relieve the South Texas constraint isn’t expected to be completed until the middle of 2027. 

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Counterflow: Back to the Future

It seems like yesterday I started scribbling about all manner of industry subjects — against the flow, the prevailing wisdom, the latest hype, etc. 

But it’s actually been 10 years. With that passage of time, spanning 90 columns and articles all available here, I thought I’d look back at what I might have gotten right, gotten wrong or whatever. And what such might portend for the next 10 years. 

Let’s start with — who else — Elon Musk and his claims for his new home battery, the Powerwall. Including pairing with his cousins’ SolarCity’s solar panels. Powerwall and SolarCity didn’t live up to Musk’s early hype, as I discussed in follow-up columns (one more), but they finally became a profitable part of Tesla. Maybe I should get partial credit.  

Steve Huntoon |

Next subject was Big Transmission (not to be confused with economic interregional ties). Back then, I summarized the prior 10 years: “It was heady stuff: Big lines and arrows sweeping across the country, depicting massive new transmission projects. But after 10 years of dramatic announcements and proposals, the reality today is that Big Transmission has fallen and it won’t be getting up. And a second reality is this: The fall of Big Transmission is not a public policy failure. Rather, Big Transmission never did make sense. Instead, the experience so far points to a continuation of what we’re doing now — to more of the incremental transmission expansions that have characterized the past 10 years — and not to count on Big Transmission as a solution to any future industry challenge.” Another 10 years and the song remains the same.✔️  

On to microgrids! I showed that microgrids are the irrational antithesis of everything we know about electric system planning and operation. A couple years later, I discussed the threat microgrids posed to national security, did a recap a couple years later, and then this year covered the microgrid boondoggle in Chicago. ✔️  

Next up were utility-scale batteries. I showed that the two claimed value propositions, capacity backup and energy arbitrage, didn’t pencil out. Battery costs have since come down significantly, but batteries remain a niche product absent subsidies and/or mandates. Hmm, maybe another partial credit. 

On to New York’s REV (“Reforming the Energy Vision”). As I said back then, it was the most hyped regulatory initiative since the California restructuring some 20 years prior. REV was mostly word salad, but one of the few specifics was subsidizing utilities to install rooftop solar. I couldn’t imagine a worse idea. ✔️  

Well, except maybe California’s artificial creation of the Duck Curve by layering one bad policy on top of another. Free storage and distribution in the form of net metering, uneconomic time-of-use rates discouraging afternoon usage, subsidies of battery storage reducing afternoon usage. Yikes. Many years later, the Duck is finally getting targeted, but not before helping drive California’s electric rates to astronomical levels. ✔️ 

Another close contender from California was the planned closure of the Diablo Canyon nuclear plant. Perhaps my hair-on-fire column helped save the plant … and perhaps helped the planet. ✔️  

Oh, and lest we forget Bernie Sanders’ promise to ban fracking during his 2016 campaign. Not only to cost consumers some $100 billion annually, but to increase carbon emissions by increasing coal-fired generation. Yikes! ✔️  

Enough reminiscing for one day! 

P.S. Except to add to prior columns’ postscripts about Peace, Love and Understanding. Here’s an audio version by the guy who wrote it, Nick Lowe. Oh, and this cover by Elvis Costello 20 years ago is epic. 

As Spinal Tap said: Turn it up to 11. 

Columnist Steve Huntoon, principal of Energy Counsel LLP and a former president of the Energy Bar Association, has been practicing energy law for more than 30 years. 

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DOE Approves 1st LNG Exports Since Biden Administration’s Pause

The Department of Energy on Aug. 31 approved a five-year term for New Fortress Energy’s Fast LNG 1 project to export gas produced in the U.S. to countries without free trade agreements (FTAs).

The LNG facility recently started operations in Altamira, Mexico, and will receive U.S.-produced gas via pipeline to export. It announced its first exports in August, having already won approval to ship gas to countries with FTAs.

The authorization comes after a court stayed the Biden administration’s pause on such approvals, announced earlier this year, and while DOE works on a related study on the environmental impacts of LNG exports. (See Federal Judge Stays Biden’s LNG Export Application Pause.)

“This important authorization cements NFE’s position as a leading global vertically integrated gas to power company and enhances the marketability of our FLNG 1 asset,” CEO Wes Edens said in a statement Sept. 3. “NFE is now able to freely supply cheaper and cleaner natural gas to underserved markets across the world and further our goal of accelerating the world’s energy transition.”

DOE approved the facility to ship 145 Bcf/year of U.S.-produced LNG. The gas will flow into Mexico over the Valley Crossing Pipeline, which runs south from Texas, and potentially other cross-border pipelines that have yet to be completed.

The exports to non-FTA countries give NFE more flexibility with the facility, DOE said.

“These re-exports can diversify global LNG supplies and improve energy security for U.S. allies and trading partners,” the department said. “Based on this administrative record, DOE has determined that it has not been shown that NFE Altamira-proposed re-exports of LNG to non-FTA countries will be inconsistent with the public interest over the authorization period.”

DOE’s approval is in effect for five years, until Aug. 30, 2029, but NFE wants to keep exporting gas until 2050. The department will reevaluate its approval once the company formally asks for a new end date.

So far, DOE has approved 46.45 Bcfd of natural gas exports, which includes 6.71 Bcfd of gas shipped to Canada and Mexico before being exported overseas.

North America’s export capacity is on pace to double by 2028, from 11.4 Bcfd to 24.4 Bcfd, the Energy Information Administration said Sept. 3.

The U.S. is home to 9.7 Bcfd of projects under construction, with Canada building 2.5 Bcfd and Mexico 0.8 Bcfd. The Canadian facilities would export gas produced there, but the Mexican facilities are seeking to export gas initially produced in the U.S.

In approving NFE’s application, DOE said it would monitor market developments closely as the impact of successive authorizations of LNG exports continues to unfold.

“DOE also acknowledges that proposals to re-export U.S.-sourced natural gas in the form of LNG from Mexico or Canada to non-FTA countries raise public interest considerations that are not present for domestic exports of LNG,” DOE said. “In the case of re-exports, the U.S. economy does not receive a significant portion of the benefits DOE has recognized for LNG exported directly from the United States, particularly with respect to the jobs and infrastructure investment associated with construction and operation of liquefaction facilities.”

Foreign LNG export facilities are also not subject to U.S. environmental laws, which could lead to long-term issues if local laws are laxer, DOE added.

The export application was opposed by environmentalists, with Sierra Club protesting and Food & Water Watch releasing a statement blasting the approval.

“It’s ridiculous that the Department of Energy would issue this license despite the administration’s ongoing, incomplete public interest review of such exports,” said Mitch Jones, managing director of advocacy and policy. “The department is under no obligation to approve these ill-advised proposals, now or ever. As the disastrous impacts of increased fossil fuel development become more and more obvious here and around the globe, the notion of expanded LNG exports should be dismissed out of hand.”

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Federal Briefs

Researchers: Clean Energy Transition Will Cost $1T in Federal Spending

For the U.S. to meet its clean energy goals, the federal government would need to invest around $1 trillion into local economies by 2031 via tax incentives, according to a new report from RMI. 

So far, through June 2024, the government has distributed $66 billion — or around 6% of the full spending that climate commitments demand. 

The RMI report looked specifically at how well each state has captured federal tax incentives, compared to estimates of their full funding potential. On average, states have received 7% of the total funding they would need to reach their full potential by 2031. 

More: Grist 

USDA Invests $140 Million to Lower Energy Costs in Kentucky, Nevada

The U.S. Department of Agriculture last week announced $140 million for clean energy projects in Nevada and Kentucky to lower bills for households, expand reliable access to clean energy and create jobs for families, small businesses and agricultural producers. 

The Valley Electric Association in Nevada plans to use an $80.3 million investment to install a 37-MW solar and storage system to serve Pahrump and the Fish Lake Valley region. In Kentucky, some of the money will go toward building three hydro plants on the Kentucky River. 

More: USDA 

Former Union Director Indicted on Warrior Met Coal Gas Pipeline Damage

The United States District Court for the Northern District of Alabama Western Division last week indicted James Gale Kerns in relation to Warrior Met Coal gas pipeline damage caused in 2022. 

Kerns has been indicted on one count of destruction of property with an explosive device after allegedly destroying parts of a facility on or around March 23, 2022. 

In April 2021, approximately 900 members of the UMWA began striking against the Warrior Met Coal Mine after failed contract negotiations and an expired labor contract. 

More: WBMA 

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State Briefs

IOWA 

Hancock County Approves Resolution Objecting to Eminent Domain Use for CO2 Pipeline

Hancock County last week became the state’s 14th county to approve a resolution objecting to the Utilities Commission’s authority to enact eminent domain for privately owned and operated CO2 pipelines. 

The county board’s action comes less than a week after the South Dakota Supreme Court handed down a unanimous decision that included the finding Summit Carbon Solutions did not prove its common carrier status, which prevents Summit from using eminent domain in that state for its proposed pipeline. The pipeline will also cross Hancock County.

More: Globe Gazette 

Utilities Commission Issues Pipeline Permit for Summit Carbon Solutions

The Iowa Utilities Commission last week issued a construction permit for Summit Carbon Solutions’ proposed liquid pipeline. 

The commission issued the permit without modifying the previously imposed conditions Summit Carbon must meet to begin construction – the most significant of which is that the project must be approved by regulators in North Dakota and South Dakota. The commission also required the company to secure and maintain a $100 million insurance policy and agree to compensate landowners for any damages that result from the pipeline’s construction. 

The company hopes to begin construction next year. 

More: Iowa Capital Dispatch 

KENTUCKY 

Gov. Beshear Makes Appointments to Energy Planning and Inventory Commission

Gov. Andy Beshear last week filled several seats on the new Energy Planning and Inventory Commission created to slow the retirement of power plants fueled by coal and natural gas. 

Among Beshear’s first eight appointees to the 18-member board were Louisville Gas and Electric and Kentucky Utilities CEO and President John Crockett and Duke Energy Senior Vice President Brian Weisker. The law requires one of the governor’s appointees represent an investor-owned utility. 

Under the new law, most of EPIC’s decision-making power will be vested in a five-person executive committee. The law also requires EPIC to submit a study of the state’s electricity supply and the impact of federal policies on it by Dec. 1.  

More: Kentucky Lantern 

MASSACHUSETTS 

Holtec Appeals DEP’s Denial to Discharge Pilgrim Wastewater into Cape Cod Bay

Holtec Decommissioning International last week announced it is appealing a Department of Environmental Protection ruling denying the company permission to release treated wastewater from the Pilgrim Nuclear Power Station into Cape Cod Bay. 

Holtec wants to discharge up to 1.1 million gallons of industrial wastewater — treated beforehand, but still containing some radionuclides — from the shuttered plant. However, the DEP has identified the bay as “a protected ocean sanctuary” as defined under the state’s Ocean Sanctuaries Act. 

Holtec filed its appeal Aug. 16 with the Office of Appeals and Dispute Resolution and argues the NRC has the sole responsibility of deciding on discharge of “radiological liquid effluent” under the Atomic Energy Act. 

More: Cape Cod Times 

MISSOURI 

Evergy Seeks Rate Increase

Evergy last week applied to the Public Service Commission for a 13.99% increase in electric rates, giving the company up to $104.5 million more in revenue a year. 

Evergy said the higher rates are needed to recoup money it spent on two natural-gas plants and for upgrades to withstand severe weather. 

The commission figures to decide in December. 

More: Missouri Independent 

NEVADA 

BLM Approves Solar, Battery Storage Project

The Bureau of Land Management last week issued a right-of-way for the Dry Lake East Energy Center Solar Project in Clark County, Nev. 

The battery energy storage system will generate 200 MW of solar energy with 600 MW of storage. 

More: Power Technology 

NEW YORK

Senate Republicans Outline Legislation to Delay Renewable Transition

Senate Republicans last week unveiled a legislative package to delay the state’s statutory mandates to transition to renewable energy. 

The legislation would push back deadlines in the state’s climate law, which passed in 2019 and requires a 40% reduction in greenhouse gas emissions by 2030, by 10 years and require a study of its costs. 

Other parts of the package would prevent the state from closing any power plants before new facilities come online and require it to invest in “alternative energy” options. 

More: WSKG 

OHIO 

PUC Proposes $1.45M Fine Against Duke for Billing Errors

The Public Utilities Commission last week proposed a $1.45 million fine against Duke Energy for repeatedly violating state administrative code while making more than 100,000 billing mistakes since 2022. 

The fine is part of a revised settlement proposal, filed by PUC staff on Aug. 12, to address ongoing problems with Duke’s “Customer Connect” software system. The revised settlement would triple an earlier penalty. 

By April 2023, one year after installation, PUC staff said Duke had reported 106,453 billing errors. 

More: WCPO 

PENNSYLVANIA 

PECO Looking for Rate Increase in Philadelphia Area

PECO recently filed for a 12.3% rate increase with the Public Utility Commission. 

The increase would add $16.67 a month more to the typical residential customer bill starting in January. That would be followed by additional increase of $2.07 per month in 2026. 

PECO argues it’s investing billions in infrastructure upgrades and needs the earnings increase to ensure its continued financial health. Without a higher revenue stream, it’ll lose opportunities to attract capital investments. 

More: BillyPenn 

VIRGINIA 

Charlotte County Approves Permits for Dominion Solar Project

The Charlotte County board last week unanimously approved a permit and a siting agreement for Dominion Energy’s Quarter Horse Solar project. 

Dominion has shaved down the project since purchasing it from Apex Clean Energy Holdings. The 125-MW project will sit on 1,678 acres and consist of 291,384 solar panels. 

More: The Charlotte Gazette 

NRC Grants North Anna Extensions

The NRC approved 20-year extensions for North Anna Power Station’s two nuclear reactors, allowing them to operate through 2058 and 2060, Dominion Energy announced last week. 

The two reactors were originally licensed to operate for 40 years beginning in 1978 and 1980. In 2003, the licenses were renewed for an additional 20 years, permitting them to operate through 2038 and 2040.   

More: Virginia Business 

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Company Briefs

Exxon to Sell Non-core Oil Assets in Permian Basin

Oil giant Exxon Mobil last week said it is looking to sell oil assets in the Permian Basin that could fetch $1 billion. 

The company wants to sell a collection of conventional oil and gas properties in the Permian across west Texas and New Mexico to focus on higher-growth assets. 

More: Reuters 

Microsoft Signs 20-Year Solar PPA with EDP Renewables in Singapore

Renewable energy producer EDP Renewables (EDPR) last week announced a 20-year agreement with Microsoft through which the tech giant will purchase 100% of the renewable energy via EDPR’s SolarNova 8, the largest solar project in Singapore. 

EDPR announced earlier this year that it had been awarded Phase 8 of the SolarNova program, to install up to 200 MW of capacity across 1,075 Singapore public housing buildings and 101 government-owned buildings. 

It is the second agreement between the companies in Singapore. 

More: ESGtoday 

Ice Industries to Invest in Production Facility to Supply First Solar

Ice Industries last week announced it will invest $6 million to build in the Lacassine Industrial Park, La., that will focus on roll forming steel back rails for solar panels for First Solar. 

First Solar is expected to begin operations in the second half of 2025. 

More: The Acadiana Advocate 

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NYISO Presents Final 2025 Project Budget Recommendation

NYISO last week presented the Budget and Priorities Working Group with its final recommended 2025 budget for in-house initiatives, showing that it responded to stakeholder feedback by reincluding several projects that had been cut.

The ISO’s initial recommendations last month cut several stakeholder favorites, including implementing storage as transmission and market purchase hub transactions. (See NYISO Presents Initial 2025 Project Budget Recommendation.)

“We took the feedback that we got from the initial recommendation, went back, and looked at the projects,” said Kevin Pytel, senior manager of product and project management for NYISO. “We have modified some of our estimates when we further scrutinized those estimates, trying to bring them down as much as possible for the resourcing.” This freed up some resources for other projects, he said.

Most of the projects that had been excised were reincluded by modifying their deliverables, which may change when they come fully online. Pytel explained that some of the changes were possible because NYISO produced new estimates of how many labor hours they would take.

“What you found in the past is that you’ve made conservative estimates, as in protecting yourselves: estimates of how much time projects would take and that they don’t take as much time as you estimate?” said Mark Younger of Hudson Energy Economics.

“That’s what the data suggests, Mark,” said Pytel.

Based on the recommended projects, NYISO estimates the total budget for 2025 to be $42.73 million — up from 2024’s $41.62 million — with $22.56 million for labor, $8.31 million for capital and $11.86 million for professional services.

In response to a stakeholder question, NYISO staff said the total cost is slightly higher than what it initially recommended, mostly because of a $500,000 increase in labor costs.

The Integrating Champlain Hudson Power Express project “could not fit into budget due to resource constraints,” NYISO said. The project aims to develop an operating protocol between Hydro-Quebec and the CHPE line, including identifying tariff revisions, software enhancements and integrating the facility to the system reliability tools. This would not impact the expected deployment in 2026, the ISO said. The line is expected to go into service that year.

The proposed budget is expected to be presented to the Management Committee at the end of this month, with a committee vote a month later and a Board of Directors vote in November.