The Department of Energy has released finalized energy efficiency standards for “general service lamps, which include the most common types of commercial and residential light bulbs.”
The congressionally mandated standards go into effect in July 2028 for newly produced bulbs and are expected to save $1.6 billion annually on energy costs, cut waste and avoid carbon emissions. Over 30 years, DOE projects the standards will save more than $27 billion on utility bills and cut 70 million metric tons of carbon emissions.
“Making common household appliances more efficient is one of the most effective ways to slash energy costs and cut harmful carbon emissions,” Energy Secretary Jennifer Granholm said in a statement April 12.
DOE continues to implement the law on efficiency standards, and so far under the Biden administration, it has promulgated standards that cumulatively save $1 trillion in energy costs over 30 years and could save the average family $100 a year through lower utility bills. The standards cumulatively will cut 2.5 billion metric tons of greenhouse gas emissions, which is equivalent to 22 coal plants, over 30 years.
The standards increase the efficiency level from 45 lumens per watt to more than 120 lumens per watt for the most common light bulbs, which DOE said is in line with industry trends shifting toward more efficient and longer-lasting LED bulbs. The new standards will save 4 quadrillion BTUs, or 17%.
The department already has implemented efficiency standards that cannot be met by old, inefficient incandescent bulbs and were specifically directed by the Energy Independence and Security Act of 2007. The standards issued April 12 are part of a congressional requirement that DOE regularly review efficiency standards to ensure consumers benefit from technological improvements.
The new standards can be met with a broad variety of LED bulbs, but not compact fluorescent bulbs (CFLs), which the market is transitioning away from. LEDs last longer, use less energy and do not contain mercury like CFLs.
The American Council for an Energy Efficient Economy (ACEEE) welcomed the standard and noted that most light bulbs on the market are LED. A common bulb equivalent to old 60-watt models will use no more than 6.5 watts under the new standards once they go into effect. Many LED models today use 8 to 10 watts, while the harder-to-find compact fluorescents use about 13 watts, ACEEE said.
“LED technology has gotten even better in recent years, and these standards will ensure that all products on the market catch up with the latest efficiency advances,” said Andrew deLaski, executive director of ACEEE’s Appliance Standards Awareness Project.
MISO hopes it can use a two-step approach to Order 2222 compliance, first using a demand response category in 2026, with full market participation of aggregations of distributed resources still on the RTO’s original 2030 timeline that FERC refused last year.
MISO revealed at an April 11 DER Task Force teleconference the near-final revised Order 2222 compliance plan it intends to file with FERC.
The RTO has divided its plan to allow DER aggregations in its markets into two parts. First, it plans to use an existing demand response resource participation category to get aggregations of distributed resources participating sooner, albeit on a limited basis. MISO said it can begin registering DER aggregations under its demand response resource participation model by Sept. 1, 2026, and begin participation by June 1, 2027.
For demand response participation, DER aggregations must be at least 1 MW and MISO would commit them for either energy or contingency reserves.
A few years later, MISO would roll out its comprehensive Distributed Energy Aggregated Resource model at the beginning of 2030. It plans to register aggregations beginning June 1, 2029, allow DER aggregations to participate in its energy and ancillary services by Jan. 1, 2030, and finally open capacity market participation to aggregations by June 1, 2030.
However, MISO would not adopt a wide-ranging, multinodal approach for aggregation. Aggregations would be limited to multiple nodes within a single load-balancing authority and a single load-serving entity, as they are today under its demand response resource model.
“Adding more locations adds complexity,” MISO’s Kim Sperry said. She said the complexity is not limited to the RTO, but seeps into aggregators and distribution utilities’ processes.
Sperry said MISO keeping its DER aggregation locational limits in line with its demand response resource rules allows it to not take on “too much too fast.”
“We’re not trying to bring something brand new to the stakeholder community,” she said.
Some stakeholders questioned why MISO needs three years of prep work to employ an existing resource model for DER aggregations.
MISO DER Program Manager Paul Kasper said MISO needs time to complete a new, “foundational” settlement system tool to accept DER aggregations.
Other stakeholders said the 1-MW size minimum seemed restrictive and pointed out that some states in MISO’s footprint prohibit aggregators from providing demand response and effectively would be shut out of the markets until 2030.
MISO no longer accepts stakeholders’ written opinions on its revised Order 2222 implementation plan and has until May 10 to file its new compliance. It will present its final compliance plan to stakeholders at the April 18 Market Subcommittee.
FERC on April 11 accepted ISO-NE’s fifth Order 2222 compliance filing while requiring the RTO to make additional changes detailing deadlines for distributed energy resource aggregators to submit metering data (ER22-983-007).
Order 2222 aims to enable DER aggregations to participate in regional wholesale markets. FERC wrote that ISO-NE’s proposal met the requirements to make DER aggregators responsible for providing required metering information to the RTO, and to create standards for aggregators that work with host utilities to share these data.
However, the commission concluded that ISO-NE did not meet the requirement to change its tariff to specify data submission responsibilities and deadlines, disagreeing with its contention that these instead should be included in the RTO’s manuals.
“ISO-NE fails to address adequately the commission’s finding in the Nov. 2 order [the RTO’s third compliance filing] that the meter data submission deadline is a key component of metering practices for DER aggregators that should be included in the basic description of metering practices in the tariff,” FERC wrote.
ISO-NE in February 2022 submitted its first compliance filing to Order 2222, issued in November 2021. FERC directed additional changes, which the RTO submitted in three batches last year. The commission accepted the second and fourth filings without requiring any changes, but it ordered another round in response to the third. (See FERC Accepts ISO-NE Order 2222 Compliance Filing.)
The topline figures from EPA’s new inventory of U.S. greenhouse gas emissions from 1990 to 2022 ― released April 11 ― show the country’s slow and uneven progress toward President Joe Biden’s goal of cutting emissions by 50 to 52% below 2005 levels by 2030.
The U.S. has cut its greenhouse gas emissions by a modest 16.7% since 2005, and in 2022, total GHG emissions edged up 1.3% over 2021 levels as the economy continued to rebound from the COVID-19 pandemic, the report says.
Carbon dioxide accounted for 80% of the country’s 5,489 million metric tons (MMT) of GHG emissions in 2022, with 93% of that coming from the burning of fossil fuels.
In second place, methane emissions accounted for 11%, with 27% of that produced by farm animals ― cows, sheep and goats ― and 25% from natural gas infrastructure. Methane has 28 times the global warming potential of CO2.
The remaining 9% came from a mix of lesser GHGs, all with high global warming potential. Nitrous oxide, which makes up 6% of total emissions, has a global warming potential 265 times higher than CO2.
EPA compiles the report annually to be submitted to the U.N. Framework Convention on Climate Change by April 15, the deadline for developed countries to send in their inventories, according to a press release announcing the report. Biden’s 2030 goal is part of the U.S.’ commitment to reducing its greenhouse gases made under the 2015 Paris Agreement.
Signed by 194 countries and the EU, the agreement commits the countries to limiting global temperature increases to 2 degrees Celsius over preindustrial levels at a minimum, with a preferred target of 1.5 C.
The report was produced “in collaboration with numerous experts from other federal agencies, state government authorities, research and academic institutions, and industry associations,” according to Joseph Goffman, assistant administrator for the Office of Air and Radiation.
Breakdown by Sector
The report’s analysis of emissions by economic sector provides some insights into the drivers for emission increases and decreases.
Emissions from the transportation sector, the top source of U.S. GHGs at 28%, fell 0.2% from 2021 to 2022. Light-duty vehicles — passenger cars, SUVs and light pickup trucks — accounted for 37% of transportation emissions, and medium- and heavy-duty vehicles contributed 23%, with the remainder coming from off-road sources, which can include heavy-duty construction vehicles.
U.S. GHG emissions by economic sector, 1990-2022 | EPA
The electric power sector, now the country’s second-largest source of GHGs at 25%, also saw a small drop, 0.4%, even as electricity generation grew by 3%, as coal-fired plants retired and renewable capacity increased, the report says.
At the same time, electricity produced from natural gas and petroleum increased by 7% and 19%, respectively.
The commercial and residential sectors’ emissions increased the most from 2021, at 10.4%. The report notes that building energy use — and GHG emissions — will vary seasonally, but part of the increase in 2022 can be traced to an increase in heating and cooling “degree days,” or days when colder or hotter weather may trigger increased demand for heating or cooling, respectively.
Heating degree days increased by 7.9% from 2021 to 2022, while cooling degree days rose by 4.3%. According to the Energy Information Administration, the Mountain West states had the most heating degree days in 2022, while the West South Central states — Texas, Oklahoma, Arkansas and Louisiana — had the highest number of cooling degree days.
Industrial emissions — 23% of total U.S. GHGs — also dropped 0.2%, while electricity use increased 3% over 2021 levels. Accounting for 10% of emissions, the agricultural sector scored a 1.8% drop in GHGs, the report says.
The inventory’s preliminary figures for 2023 show decreases, with U.S. energy use falling 1% and GHG emissions dropping 3%, a step in the right direction but still not fast or steep enough to reach the nation’s 2030 targets.
The planned 625-MW gas-fired Nemadji Trail Energy Center in Wisconsin encountered another hitch after the Superior City Council refused to move ahead on zoning changes necessary to break ground on the plant.
At its April 3 meeting, the council voted 5-4 on a roll-call vote to set public hearings required by state law to make land use changes from suburban to heavy industry and vacate streets to allow for the nearly $1 billion gas plant. But the motion, which required six votes to pass per city code, failed, stalling the plant’s development.
Plant co-developer Minnesota Power had requested the land use changes, which would have altered the city’s comprehensive plan.
Construction on the Nemadji Trail plant and associated transmission line has yet to begin, according to a quarterly filing with the Wisconsin Public Service Commission by project partners Minnesota Power, Dairyland Power Cooperative and Basin Electric Power Cooperative.
The vote against the plant appeared to be motivated by a groundswell of opposition from Superior residents. Several people attending the city council meeting spoke out against the plant before the vote, expressing worries over wetland habitat loss, air quality, greenhouse gases that would worsen climate change and stranded asset costs.
Multiple residents expressed disbelief at the U.S. Department of Agriculture Rural Utilities Service’s final supplemental environmental assessment, which found the plant “would not cumulatively contribute to significant adverse air quality impacts.” They also contended that the plant fundamentally contradicts the city’s 2040 comprehensive plan, which calls for waterfront cleanup, preservation and tourism opportunities, among other goals.
Jadine Sonoda, of the Sierra Club’s Wisconsin chapter, said the plant would be “expensive and dangerous decades down the line.”
“Gas has no place in our transition to clean energy, and I really want to underscore that,” Sonoda said.
Milo Peterson, a 15-year-old Superior resident, said, “To put it simply, this project goes against my values … and doesn’t seem like a very considerate thing to do for the environment.”
“I’m asking you to think of my future,” he asked council members.
Superior Mayor Jim Paine said it’s “extraordinary risky” to develop the plant on undeveloped wetland near the banks of the Nemadji River, as the potential for erosion is high.
However, Superior Councilor Brent Fennessey said the city council shouldn’t have used residents’ opposition to the plant to deny an opportunity for a public hearing on land use changes. He said he didn’t think Superior was giving Minnesota Power a fair process.
Paine said allowing hearings would have signaled that Superior was open to rezoning changes to host the plant.
Councilor Jenny Van Sickle said she took exception to Minnesota Power insinuating the plant could be used for hydrogen when the plant’s partners haven’t made any design changes to accommodate the fuel. She also said the design remains out of step with EPA’s suggestion for a form of carbon capture.
Artist rendering of the Nemadji Trail Energy Center | Nemadji Trail Energy Center
‘Disappointed’
Last year, Nemadji Trail’s developers said pushback from environmental groups was partly responsible for delaying the plant’s expected commercial operation date from 2027 to 2028. Construction was set to begin this month — but that was before the city council refused to begin zoning procedures. (See Wisconsin Gas Plant Delayed as Enviros Still Try to Block Project.)
Environmentalists maintain the plant is unnecessary and would increase emissions at a time when utilities need to scale back on polluting resources. They’ve also raised concerns about the plant’s location near wetlands.
In 2022, Wisconsin’s Dane County Circuit Court rejected arguments from the Sierra Club and Clean Wisconsin that the Wisconsin PSC didn’t sufficiently consider the full environmental impact of the plant when it granted it a certificate of public convenience and necessity. The plant has yet to secure permitting approvals from the U.S. Army Corps of Engineers.
Minnesota Power, which would build and operate the plant, has pledged to close its two remaining coal-fired power plants by 2035, generate more than 70% of its energy from renewables by 2030, achieve an 80% reduction in carbon emissions by 2035 and produce only carbon-free energy by 2050. (See Minnesota Power IRP Pledges End to Coal by 2035.)
Minnesota Power has framed Nemadji Trail as a vital supply of backstop power when renewables aren’t available during the clean energy transition.
The utility did not respond to RTO Insider’s request for comment about its plans following the council’s vote. Spokesperson Amy Rutledge previously told local news outlets in a statement that Minnesota Power is “disappointed by the lack of transparency and communication surrounding the hearing, and with the city’s disregard for conducting a fair process involving all interested parties.”
Rutledge said Minnesota Power is evaluating next steps with partners Dairyland and Basin Electric “to ensure we meet our commitment to safe, reliable and affordable power in this clean energy transformation.”
In 2022, MISO wrote a letter to the Rural Utilities Service in support of a loan for Nemadji Trail. The grid operator asked the federal agency to consider its looming generation shortfalls, grid reliability and the plant’s potential role in the RTO’s resource adequacy.
FERC on April 8 approved PJM’s cost allocation for a $5 billion slate of transmission upgrades aimed at resolving reliability violations posed by growing data center load in Northern Virginia and generation retirements in Maryland (ER24-843).
The commission dismissed as out-of-scope protests filed by the Maryland ratepayers and the state Office of People’s Counsel that Virginia should bear the full cost of transmission upgrades to serve data center load. The OPC argued the proliferation of data centers in Loudoun County and the surrounding area — known as Data Center Alley — has been fueled by incentives provided by Virginia and that the transmission needed should be classified as a public policy objective with the costs fully assigned to that state.
Several Maryland residents urged the commission to initiate a proceeding under Section 206 of the Federal Power Act to consider whether the PJM cost allocation process remains just and reasonable, also arguing that the data centers are the result of Virginia’s policy objectives. They also argued that the stakeholder process is unfriendly to the participation of average consumers.
The PJM Board of Managers approved the projects to become part of the RTO’s Regional Transmission Expansion Plan (RTEP) on Dec. 11, greenlighting new lines from the 502 Junction and Otter Creek substations in Pennsylvania, through Maryland and into Northern Virginia. Additional lines will supply power to the Alley from Dominion Energy’s Morrisville substation in Southern Virginia, and from the Peach Bottom substation in Pennsylvania to the Baltimore area to resolve violations related to the retirement of the 1,295-MW Brandon Shores coal generator. (See PJM Board Approves $5 Billion Transmission Expansion.)
The commission said its review of the cost allocation for RTEP projects is limited to whether PJM correctly applied its tariff. The issues raised by the OPC and ratepayers around the mechanisms by which PJM determines cost allocation are beyond the scope of its review and more appropriately would be considered through a separate complaint that the RTO’s tariff is not just and reasonable.
Even were a complaint to be filed, the commission expressed skepticism regarding the concept of assigning states the cost of building transmission to serve growing load, even that which may be the result of state incentives. It said the State Agreement Approach is the only structure for assigning transmission costs to an individual state and only if it voluntarily agrees to pay those costs to facilitate its public policy objectives.
Commissioner Allison Clements wrote a concurrence going further, arguing that determining which transmission needs are the result of discrete state policies for the purpose of cost allocation would run contrary to the principles of regional transmission planning and would be “impractical and unworkable.”
The OPC’s “argument also overlooks the reality that myriad state and local (and, for that matter, federal) public policies affect either the demand for or supply of electric power,” Clements wrote. “Virginia is certainly not the only state with economic development policies that are increasing the demand for power. Likewise, every state makes policy and/or regulatory decisions that affect which generating facilities provide supply to meet demand. Assigning transmission costs by attempting to parse countless public policies to determine whether and how each contributes to the need for transmission by affecting demand or supply in the power system is an impractical task that is not required by the Federal Power Act.”
Commissioner Mark Christie also concurred, as PJM followed its tariff, but he argued there may be merit to deeper consideration of how state policies affect RTOs’ transmission planning.
“I believe that the time has come for this commission to take the lead in its convening role to initiate a proceeding, such as a Notice of Inquiry, a series of technical conferences or by initiating an FPA Section 206 proceeding outside this docket, posing such important questions, among others, as: What is the proper definition of a public policy transmission project? Does the definition of public policy transmission project need to be changed for purposes of regional cost allocation? How should public policy transmission projects be cost allocated in a multistate RTO?” Christie wrote.
“In my view the states themselves need to be at the forefront of deciding these questions, as it is their own state policies that are largely making these questions unavoidable, as these two recent PJM RTEP cases graphically illustrate,” he said.
NERC is taking the pulse of industry again on its latest revisions to a proposed reliability standard requiring utilities to implement internal network security monitoring (INSM) after stakeholders rejected an attempt to pass the standard in March.
The ballot period for CIP-015-1 (INSM) will run from April 12-17, according to the page for Project 2023-03, which is developing the standard. A formal comment period for the standard began April 5 and will also end April 17.
In an email to stakeholders April 11, NERC said the project team had updated the redline version of CIP-015-1 after the comment period began because Requirement R1 of the redline used “security systems” instead of “cyber systems.” The updated redline is consistent with language in the clean version of the standard.
Balloting and comments for the most recent update to CIP-015-1 closed March 18, with stakeholders delivering a 48.52% segment-weighted vote in favor. A two-thirds majority is needed for passage. (See Industry Sends Back NERC Cyber Monitoring Standards.)
It was the first ballot for CIP-015-1 but the second for the entire project, because the original formal comment and ballot period that ended in January concerned a different standard conceived as a modification of CIP-007-6 (Cybersecurity — systems security management). The team decided to create a new standard after the ballot for CIP-007-6 was rejected overwhelmingly by industry with a segment-weighted vote in favor of just 15.42%.
The quick turnaround to a new comment period is a reflection of the tight deadline NERC is working under; FERC ordered the ERO in 2023 to submit standards requiring INSM by July 9 of this year (RM22-3). (See FERC Orders Internal Cyber Monitoring in Response to SolarWinds Hack.) NERC’s Standards Committee voted at its February meeting to reduce comment and ballot periods for the project to as little as 10 days to meet FERC’s target, having already approved shortening to 20 days in August.
In the comment form for the standard, the team for Project 2023-03 outlined some of the changes made to the latest version of the standard. These include relatively minor alterations, such as adding generator owners to the list of applicable entities after inadvertently excluding it from the previous posting, in addition to more substantial revisions.
For example, requirement R1 and the associated metric both were revised, with language expanded and abbreviations removed “for consistency and clarity” regarding the methods by which entities should monitor network data activity for anomalous activity. Similarly, revisions to requirement R2 clarified the types of INSM data that entities should protect, and R3 was modified with a note that entities are “not required to retain detailed [INSM] data … that is not relevant to anomalous network activity” identified in other requirements.
If the standard meets the threshold for approval in this ballot round, the next step will be a five-day final ballot (shortened from the usual 10 days), after which the standard will be submitted to NERC’s Board of Trustees for adoption. The next board meeting is scheduled for May 8.
California could save more than $750 million a year in power costs through increased use of virtual power plants (VPPs), according to a new study by The Brattle Group and GridLab.
The study found that more than 7,500 MW of VPP capacity could be deployed cost-effectively across California over the next decade, accounting for more capacity than the state’s largest power plant or the peak demand of Los Angeles.
“By 2035, California’s VPP potential will exceed 15% of [statewide] peak demand. That’s five times the existing capability,” the study, which examines VPP deployment potential by 2035, reads. “By providing these services to the power system, VPPs can make significant contributions to grid reliability while directly compensating those consumers who participate.”
Changing weather conditions, increasing loads, dependance on intermittent generation and growing demand for electrification are just some of the factors that have stressed California’s ability to meet its resource adequacy requirements in a timely and cost-effective manner, the report said.
VPPs use an aggregated network of distributed energy technologies such as batteries and electric vehicle chargers to feed power back into the system and provide financial incentive to participating customers. The idea is that, in addition to increasing reliability, virtual systems reduce reliance on fossil fuels during times of peak demand.
Almost all the state’s VPP capacity is traditional demand response, only a fraction of which is used to provide resource adequacy, the study says. But California is pushing for the increased adoption of VPPs with Senate Bill 1305, which would require the state’s Public Utility Commission to establish a VPP capacity procurement requirement by March 2026.
And new technologies are emerging. Last year, Sunrun, a residential solar installer, partnered with Pacific Gas and Electric to enroll 8,500 residential battery owners in a VPP that provided nearly 30 MW of power during summer evenings. Also last year, the Sacramento Municipal Utilities District partnered with Ford, BMW and GM to develop a pilot that manages the charging of participating EVs to minimize costs to the power system.
Study Scope
Researchers focused the study on five dispatchable consumer technologies: smart thermostat-based air-conditioning control, behind-the-meter batteries, residential EV charging, grid-interactive water heating, and automated demand response (auto-DR) for large commercial buildings and industrial facilities.
The study employed a FLEX model, designed by The Brattle Group to assess load flexibility potential, to determine that all five technologies would contribute to peak demand reduction. Batteries, EVs and electric water heating could aid in load shifting, while smart thermostats and auto-DR could reduce energy consumption and save money.
Roughly $550 million in system savings would be retained by customers, the study found. Broken down, VPPs would avoid $417 million in generating capacity, $194 million in transmission, $107 million in energy and $37 million in distribution. A household participating in all four residential VPP options considered could receive participation payments of $500 to $1,000 per year.
While not quantified in the study, researchers also found that VPPs could help to reduce lengthy resource interconnection delays and “unprecedented uncertainty” in load forecasting.
The Brattle Group also pointed to VPP options not considered in the study that could increase capacity potential, including vehicle-to-grid technologies, targeted energy efficiency, smart panels and thermal energy storage.
The advancement of VPPs would rely on customer participation.
“The share of customers that adopt flexible technologies such as EVs, batteries and smart thermostats over the next decade will establish the foundation for VPP program eligibility. The state will need a persistent focus on advancing policies that promote adoption in these areas for our potential estimates to materialize,” the report reads.
Greater reliance on VPPs also would require more frequent use of said resources. Achieving 7,500 MW of net peak demand reduction would require 114 hours of VPP dispatch per year, six consecutive hours of dispatch on the peak day, and five months of the year, the study estimated.
“By improving the utilization of distributed energy technologies, VPPs reduce the need for new grid resources that otherwise would sit unused for many hours of the year,” the study reads. “If this vision is achieved, the result will be a reliable and more affordable power grid for Californians.”
Two of the developers behind the embattled Cardinal-Hickory Creek transmission line have appealed to lift an injunction on the last mile of the project that will intersect a wildlife refuge in Wisconsin and Iowa.
ITC Midwest and Dairyland Power Cooperative filed last week with the 7th U.S. Circuit Court of Appeals to rescind a preliminary injunction on the 345-kV line issued in the U.S. District Court for Western Wisconsin.
The decision last month halted a land swap between the utilities and the U.S. Fish and Wildlife Service (FWS) to trade more than 35 acres in Wisconsin for almost 20 acres of the Upper Mississippi River National Wildlife and Fish Refuge in Iowa, which will be cleared for construction of the line’s final 1.1 miles. (See Judge Pauses Final Mile of Controversial Cardinal-Hickory Creek through Wildlife Refuge.)
Line developers ITC Midwest and Dairyland are asking the court to expedite treatment of their request.
The utilities said lifting the injunction and allowing construction on the last mile of the line “would replace existing lines now located in a much more environmentally sensitive area” of the Upper Mississippi River Wildlife and Fish Refuge. They also argued that the injunction lacked sound reasoning and relied on previously vacated findings and that the district court “erroneously presumed entitlement to injunctive relief.”
The two also said plaintiffs Driftless Area Land Conservancy, Wisconsin Wildlife Federation and National Wildlife Refuge Association have overstated the impact of construction on the refuge. ITC and Dairyland said the area where the final swath of towers will be erected is “already fragmented by an existing road, maintains little to no wildlife or habitat value, is difficult to maintain and contains invasive reed canary grass.”
ITC and Dairyland said that as a consequence of the preliminary injunction, Cardinal-Hickory Creek cannot meet its anticipated June 28 in-service date, and a revised date cannot be set until “further developments occur in the pending litigation, including a termination of the injunction, allowing for closing on the land exchange with the U.S. Fish and Wildlife Service.” The two said once the land swap occurs and a new construction schedule is established, the line could be in service within four to six months.
“As long as the orders remain in place, the improved reliability and reduced electricity costs MISO envisioned will be foregone,” the two wrote, referring to Cardinal-Hickory Creek’s inclusion as part of MISO’s 2011 multivalue transmission portfolio.
The utilities continue to assert that the parcel exchange will “provide significant net benefits” to the Upper Mississippi River National Wildlife and Fish Refuge.
“We have a responsibility to get the Cardinal-Hickory Creek project in service as soon as possible so it can begin providing significant economic benefits for electricity consumers. The latest litigation and the preliminary injunction only serve to further increase costs for customers,” ITC Midwest President Dusky Terry said in a statement. “We strongly assert that the federal agencies that granted the land exchange and issued permits for the project acted within their legal authority under federal law and their environmental review complied with the National Environmental Policy Act (NEPA). Just as in prior litigation, we are confident that we will ultimately prevail in this case and move forward with project completion.”
Dairyland COO Ben Porath emphasized that Cardinal-Hickory Creek’s completion will mean the utilities can remove an existing 161-kV transmission line in the refuge that crosses the Mississippi River. He said the “shifts in infrastructure will reduce the electric transmission footprint in the refuge and replace existing structures with low-profile structures using an avian-friendly design.”
MISO and SPP staff have alerted their stakeholders that they have completed the annual issues review process and are developing the 2024 coordinated system plan’s study scope as they try once again to find a mutually suitable interregional joint project.
In an email to stakeholders last week, the grid operators said their representatives had concluded two joint planning committee meetings reviewing feedback from stakeholders on “issues potentially benefiting” from interregional studies. The RTOs also gathered feedback from the Interregional Planning Stakeholder Advisory Committee (IPSAC) in February. (See MISO, SPP to Conduct Interregional Study in 2024.)
MISO and SPP will review the 2024 CSP’s study scope with stakeholders during an upcoming IPSAC meeting yet to be scheduled.
The grid operators’ joint operating agreement requires them to conduct a joint study every two years. Five previous studies have failed to produce any joint projects over differences in how to allocate costs. (See MISO, SPP Fall Short in 5th Try for Interregional Projects.)
Ex-SPP Director Joins PUD Board
Former SPP Director Phyllis Bernard has been chosen to fill a commissioner’s unexpired term on a Washington county utility’s board. She will be sworn in May 1.
Bernard will fill the remainder of Jim Waddell’s term on the Clallam County Public Utility District’s three-member Board of Commissioners. That term expires after Clallam County’s November general election is certified. The county is near Olympic National Park, northwest of Seattle.
Waddell, the PUD’s commission chair since 2023, died in February.
