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Public Power Would Gain Access to Direct Payment of Tax Credits under Energy, Climate Deal

August 1, 2022

by Paul Ciampoli
APPA News Director
August 1, 2022

Public power utilities, rural electric cooperatives, the Tennessee Valley Authority, state and local governments, and other tax-exempt entities would have access to refundable direct payment tax credits under an energy and climate agreement announced on July 27.

The agreement was unveiled by Senate Committee on Energy and Natural Resources Committee Chairman Joe Manchin (D-WV) and Senate Majority Leader Charles Schumer (D-NY).

The climate and energy provisions will be included in budget reconciliation legislation. Senate Majority Leader Chuck Schumer (D-NY) hopes to begin debate of the measure on the Senate floor as early as this Wednesday, but key details remain to be ironed out. It is also unclear whether the measure will have the support of all 50 Democrats that will be needed to pass the bill and send it to the House for consideration.

Provisions of particular interest to public power include:

Tax Provisions

Internal Revenue Code (IRC) Section 45 – Electricity Produced from Certain Renewable Resources

Base credit of 0.5 cents per kWh, for wind, solar and geothermal construction of which begins after 2021 and through 2024. Credit is increased to 2.5 cents per kWh for facilities:

IRC Section 48 – Energy Credit (ITC)

Base credit of 6% for projects after 2021 and through 2024. The credit is expanded to include energy storage, qualified biogas, microgrid controllers.

Credit is increased to 30 percent for facilities:

The credit is increased for:

Clean Electric Production Credit and IRC Section 48D – Clean Energy Investment Credit

IRC Section 6417 – Elective Payment of Applicable Credits

Other tax provisions include the creation of a production tax credit for existing nuclear power facilities equal to up to 1.5 cents per kWh. The credit is reduced as the sale price of such electricity increases.

The agreement also calls for the creation of a new production and investment tax credits for clean hydrogen and will allow corporate taxpayers to transfer energy tax credits to another taxpayer in exchange for cash.

The agreement also imposes a tax equal to 15 percent of a corporation’s adjusted financial statement income. Financial statement income generally includes all interest and, so, this minimum tax would apply to other tax-exempt bond interest.

Funding

On the funding side, the deal calls for $1 billion in additional funding to the Rural Electrification and Telephone Fund for electric storage project loans. Up to 50 percent of such loans can be forgiven for projects meeting terms and conditions set by the Department of Agriculture.

It also includes $1 billion for loans and grants to promote underutilized renewable technologies in rural areas.

The agreement also includes $3.6 billion to authorize an additional $40 billion under the Department of Energy (DOE) loan office to support projects that support technology innovations to avoid, reduce, utilize, or sequester air pollutants or anthropogenic emissions of greenhouse gases.

Other funding elements in the agreement include:

The text of the bill and a variety of summaries can be found here.

Nuclear Regulatory Commission Directs Staff To Issue Final Rule Certifying NuScale SMR Design

July 31, 2022

by Paul Ciampoli
APPA News Director
July 31, 2022

The U.S. Nuclear Regulatory Commission has directed its staff to issue a final rule that certifies NuScale’s small modular reactor (SMR) design for use in the U.S., the NRC said on July 29.

The certification’s effective date is 30 days after the NRC publishes the rule in the Federal Register.

NRC certification means the design meets the agency’s applicable safety requirements.

An application for a nuclear power plant combined license that references a certified design will not need to address any of the issues resolved by the design certification rule. Instead, the combined license application and the NRC’s safety review would address any remaining safety and environmental issues for the proposed nuclear power plant, the NRC said.

The design certification approves the NuScale reactor’s “design control document,” which is incorporated by reference in the final rule.

NuScale submitted an application to the NRC on Dec. 31, 2016, to certify the company’s SMR design for use in the United States. The NRC staff met its schedule goals for completing its technical review.

The design uses natural, “passive” processes such as convection and gravity in its operating systems and safety features, while producing up to approximately 600 megawatts (MW) of electricity.

The SMR’s 12 modules, each producing 50 MW, are all submerged in a safety-related pool built below ground level.

Carbon Free Power Project, LLC (CFPP), a wholly owned subsidiary of Utah Associated Municipal Power Systems, continues to advance the development and deployment of its first-of-a-kind SMR nuclear plant at the U.S. Department of Energy’s Idaho National Laboratory near Idaho Falls, Idaho. 

CFPP successfully and safely completed field investigation activities at the site in January 2022, a major milestone for the project.  

The CFPP will deploy a NuScale power plant that is based on NuScale’s SMR technology.  

In May 2021, NuScale Power and Washington State’s Grant County Public Utility District announced the signing of a memorandum of understanding to evaluate the deployment of NuScale’s SMR technology in Central Washington State.

Canada’s Ontario Power Generation (OPG) and the Tennessee Valley Authority (TVA) will jointly work to help develop small modular reactors (SMRs), TVA announced earlier this year.

The agreement allows TVA and OPG to coordinate their explorations into the design, licensing, construction and operation of small modular reactors.

The Heart of Public Power

July 30, 2022

by Joy Ditto
APPA President and CEO
July 30, 2022

I just came back from visiting the heartland, literally and figuratively.  I made my way to Madison, South Dakota, for the Heartland Consumers Power District meeting.  Heartland was established in 1969 and is a joint action agency serving 29 cities in South Dakota, Minnesota, Iowa, and Nebraska. I had been to South Dakota previously, including last year during a family trip to Mount Rushmore and the Crazy Horse monument. Note that my kids asked me if I was going back to those monuments when I mentioned the location of my trip – they loved them so much! But I had never been to Madison, which is about 45 minutes from Sioux Falls.  What a cute town! It has a quaint, historic downtown and a beautiful lake community. 

Upon arriving at the meeting on a crisp Tuesday morning — a nice change from the humid summer temps I had been experiencing in the former swampland of Northern Virginia/Washington, D.C. — I noticed that there was some great signage touting “Heartland Energy.”  My sleuthing skills took over and I quickly verified that a new brand was going to be unveiled for the group. As was described by Ann Hyland, chief communications officer, and Russ Olson, president and CEO, after doing a thorough job vetting the look and feel of the brand and the direction of the organization, the Board of Directors chose a name that included the term “energy” to convey action and forward movement while also depicting the literal delivery of energy the group provides to its member communities and keeping the term “Heartland.”

Heartland Energy has an incredible reputation among policymakers in South Dakota, as evidenced by participation in/attendance at their event by Governor Kristi Noem, staff members from the offices of both the state’s U.S. senators, state representatives, and commissioners from the Public Utility Commission (even though public power utilities are not directly regulated by the PUC), and the state economic development office. This is no fluke. Russ and his team focus on these relationships. These policymakers also recognize the tremendous value Heartland has provided South Dakota and the other states it serves through affordable and reliable electric rates and a major focus on economic development.

Heartland is one of about 60 joint action agencies across the country that aim to do the same thing for their member communities. The joint action model, which was pushed by many public power leaders, first in the 1950s and ‘60s and continuing into today, is so powerful because it pools the resources of small and medium communities to enable solutions they likely would not be able to achieve on their own. It marries the on-the-ground, specific community attributes that public power utilities embody with the economies of scale that can enable these communities to optimize their power supply, transmission access, and economic development priorities. The joint action model also allows communities to address other, more recent, challenges like managing supply chains, cybersecurity, and sharing line workers. 

In short, what Heartland Energy and other joint action agencies do is expand and strengthen the heart of public power so that it can beat in places it might not have otherwise: in state legislatures and governors’ offices, in regional transmission organizations’ planning committees, on the member representative committees of reliability groups, and in state economic development discussions. That public power heart beats strongly and loudly to the benefit of the customers they serve – families, the elderly, students, small-, medium-, and large businesses, and non-profit groups.

Heartland Energy CEO Russ Olson and APPA CEO Joy Ditto in Madison, South Dakota
Joy Ditto and Heartland Energy CEO Russ Olson in Madison, SD.

NERC Report Sees Weather, Cyber, Inverter Based Resource Threats To Reliability

July 29, 2022

by Peter Maloney
APPA News
July 29, 2022

Grid operators were able to maintain electric system reliability in 2021 with one notable exception, the February extreme cold weather event that affected Texas and parts of south-central United States, according to a new report from the North American Electric Reliability Corp. (NERC).

The cold weather event resulted in the largest controlled load shed event in U.S. history and the nation’s third largest load loss event, according to NERC’s 2022 State of Reliability report.

The February cold weather event, among other things, confirmed that interdependencies between the electricity and natural gas industries are a major new reliability risk that must be explicitly managed, NERC said in its report.

Last year also saw the rise of reliability threats from cyber attacks from nation-state adversaries and organized cyber criminals, who demonstrated they have “the ability and willingness to disrupt critical infrastructure,” NERC said.

Cyber-attacks “routinely targeted the digital supply chain and reports of suspicious cyber incidents (including vulnerability exposure, phishing, malware, denial of service, and other cyber-related reports) increased significantly in 2021,” the report found.

The NERC report also noted that there were several widespread solar photovoltaic loss events in 2021, two in Texas and four in California. Although reliability was maintained, those events highlighted the importance and urgency of expanding and accelerating ERO Enterprise and industry efforts to address them, the report said.

ERO Enterprise comprises NERC and the six North American regional electric reliability entities.

Conversely there are diminished levels of flexible generation, such as fuel-assured, weatherized, and dispatchable resources, in many parts of the nation, increasing the risk of energy shortfalls. “No longer is the peak demand period the only clear risk period; instead, risks can emerge when weather-dependent generation is impacted by abnormal atmospheric conditions or when extreme conditions disrupt fuel supplies,” the NERC report said.

Overall, the events of the past year have led the ERO Enterprise to begin reassessing how best to measure the overall reliability performance objectives for the industry, NERC said.

The report noted that NERC also has begun to address several of the growing threats. The ERO Enterprise, for instance, is implementing the recommendations in a report on the February cold weather event done by staff at NERC, the ERO Enterprise and the Federal Energy Regulatory Commission.

When implemented, those actions will provide bulk electric system (BES) “planners and operators with additional tools to avoid a recurrence of BES reliability threats arising from extreme cold weather events and address energy availability standards development for long-term planning and operational planning/operations time frames,” NERC said.

Regarding electric-gas interdependency, NERC said its “forward-looking Reliability Assessment Program continues to emphasize the risk of increased reliance on natural gas generation,” and the ERO Enterprise is “actively encouraging registered entities to conduct studies to model plausible and extreme natural gas disruptions” set forth in its March 2020 reliability guideline.

NERC also said it is drafting supply chain requirements and guidance to reduce vulnerabilities and better protect industry systems and infrastructure.

And to address the intermittency of inverter based resources, NERC said the ERO Enterprise and industry are implementing recommendations set forth in reports on the solar power loss events in Texas and California.

In a recent episode of the American Public Power Association’s Public Power Now podcast, Jim Robb, President and CEO of NERC, detailed NERC’s 2022 summer reliability assessment and discussed supply chain challenges facing the power sector.

WAPA Approves Interconnection Of 504-MW Wyoming Wind Project

July 29, 2022

by Peter Maloney
APPA News
July 29, 2022

The Western Area Power Administration (WAPA) recently approved interconnection requests for a proposed 504-megawatt (MW) wind power project in eastern Wyoming.

The proposed Rail Tie Wind Project is being developed by ConnectGen, based in Houston, and calls for up to 149 wind turbines sited on approximately 26,000-acre site that includes both private and state land roughly centered on the town of Tie Siding close to the Colorado border. The project would also include access roads, collection lines, substations, control buildings, meteorological towers and other related infrastructure.

The Rail Tie project was approved by the Albany County Board of County Commissioners in July 2021, the Wyoming State Board of Land Commissioners in January 2021, and the Wyoming Industrial Siting Council in November 2021.

Over the past three years, WAPA has been evaluating two interconnection requests submitted by ConnectGen Albany County to connect the Rail Tie Wind Project to the existing Ault-Craig 345-kilovolt line in Albany County, Wyoming, owned by WAPA, Tri-State Generation and Transmission Association, and Platte River Power Authority.

When ConnectGen completes all other local, state and federal permitting requirements, it would finance and build and WAPA would own, operate and maintain a switchyard to control power flow onto the existing transmission line.

ConnectGen filed two interconnection requests with WAPA, each 252 MW, to accommodate build-out of its proposed project in two stages, if necessary. However, there would be only one interconnection point on the Ault-Craig transmission line.

Under federal regulations, interconnection requests are generally approved if there is sufficient capacity is available, operation of the power system would not be negatively affected, the applicant funds any necessary system upgrades, and existing power customers are not affected.

In the case of Rail Tie project, WAPA determined that while its federal action to approve or deny ConnectGen’s interconnection requests was a minor action environmentally, the proposed project had the potential for significant environmental impacts and should be analyzed as a “connected action.” WAPA, therefore, determined that the proposed project constituted a major federal action requiring the preparation of an environment impact statement (EIS). Preparing the EIS helped ensure that WAPA could make an informed decision on the interconnection requests, the agency said.

WAPA determined that interconnecting the ConnectGen project would not negatively affect the reliability of the transmission system or degrade service to existing customers and that no system upgrades would be required to support the interconnection.

WAPA also found that ConnectGen “adopted all practicable means to avoid or minimize environmental harm from its proposed Project, which includes WAPA’s interconnection switchyard.”

At the same time, WAPA noted that it is “cognizant that ConnectGen’s Project will have significant impacts on visual resources in the Project viewshed, potentially significant impacts on eagles through collisions with operating turbines, and significant adverse effects on certain” National Register of Historic Places cultural resources, such as the Ames Monument.

WAPA noted that ConnectGen has taken steps to alleviate those concerns but also noted that final assessment of those concerns lies with other agencies, such as the U.S. Fish and Wildlife Service, which will be analyzing the impact of the wind project on eagles and other raptors.

“Connecting more renewable energy projects to the grid is a critical step in modernizing America’s energy infrastructure and meeting our nation’s growing energy needs,” Tracey LeBeau, WAPA administrator and CEO, said in a statement. “Our technical analyses found available capacity on WAPA’s system and the comprehensive analysis in the EIS provided environmental impact information, both of which informed the interconnection record of decision.”

MMWEC Uses DEED Grant To Develop Model To Undergrounding Cost-Benefits

July 28, 2022

by APPA News
July 28, 2022

The Massachusetts Municipal Wholesale Electric Company (MMWEC) has completed an in-depth study of the costs and benefits of the combined undergrounding electric and broadband internet lines in metropolitan areas with a grant from American Public Power Association’s Demonstration of Energy & Efficiency Developments (DEED) program.

MMWEC’s research team used the grant to build a model that optimizes construction of new utility corridors based on estimated cost and projected benefits, including enhanced reliability of electric service and access to broadband.

MMWEC’s researchers conducted a literature review to collect background information on electricity and broadband cost elements. They also collected data on undergrounding from public and commercial sources, including member utilities such as Shrewsbury Electric and Cable Operations and Concord’s public power utility, as well as the 2020 Underground Distribution Systems Reference Book (Bronze Book) from the Electric Power Research Institute and real estate data from Zillow that was used to assess aesthetic benefits from undergrounding in the form of increased property values.

The researchers analyzed the co-deployment of electric and broadband lines to develop data-driven cost and benefit models. “Our synthetic and disaggregated approach is readily deployable to other similar study areas and provides effective decision-making capabilities with limited amounts of data,” the MMWEC researchers said in their report.

MMWEC also took into consideration costs beyond the plainly financial, such as environmental damage caused by undergrounding from soil erosion and the disruption of ecologically sensitive habitats, as well as safety hazard for crews attempting to locate and repair failed equipment that has been undergrounded.

In their preliminary analysis, the MMWEC researchers found that the per-mile cost of underground installation is a major cost driver. The lifespan expected from underground cable is also a key cost factor, and they found that commonly assumed lifespan values may be significantly underestimated.

“Undergrounding electric and broadband cables is a viable approach for improving resilience,” MMWEC said in its final DEED report, noting, however, that there are many variables that have to be taken into consideration. “The massive investment costs [of undergrounding] require frameworks to analyze costs and benefits of competing strategies. Prior efforts have been too generalized and not accounted for broadband.

Thus, we present a framework that demonstrates a localized approach, using Shrewsbury, MA, as a case study.”

The researchers also found that aggressive conversion strategies, that is, those that convert to underground from overheard well before the lifespan of the overhead cable is reached, lead to greater aesthetic benefits, yield higher avoided economic losses, and, in the Shrewsbury case study, netted benefits totaling over half $500 million.

On the other hand, the researchers said, moderate conversion strategies exhibited benefits toward the end of the simulation. Optimal potential benefits can be achieved by undergrounding after the complete lifespan of the overhead lines has been reached, they said.

Looking forward, MMWEC said it plans to publish a paper with the detailed models and results of its research and another paper that will use a Monte Carlo simulation to analyze competing strategies. “This will also allow us to improve the generalizability of the model by incorporating additional factors critical to the estimation process,” such as segment length and type and the effect of a variety of conditions on the network’s sustainability and resilience, MMWEC said.

Lawmakers Ask EPA, DOE To Require Cryptocurrency Miners To Report Emissions, Energy Use

July 28, 2022

by Paul Ciampoli
APPA News Director
July 28, 2022

The Department of Energy (DOE) and the Environmental Agency (EPA) should require cryptocurrency miners to report their emissions and energy use, a group of U.S. Senators and Representatives said in a recent letter to the two federal agencies.

The July 15 letter, which was sent by Sens. Elizabeth Warren (D-Mass), Sheldon Whitehouse (D-R.I.), Edward J. Markey (D-Mass.) and Jeff Merkley (D-Ore.) and Representatives Jared Huffman (D-Calif.) and Rashida Tlaib (D-Mich.), also highlighted findings from an investigation into the environmental impacts of cryptocurrency mining.

They noted that the cryptocurrency market has grown exponentially since first introduced over a decade ago. “Mining operations for Bitcoin, the largest cryptocurrency by market cap, are increasingly moving onshore, with the United States’ share of global mining increasing from 4 percent in August 2019 to nearly 38 percent in January 2022,” the letter said.

The lawmakers  wrote to seven of the largest cryptomining operations in the U.S. seeking information about the locations of their facilities, their energy sources and consumption, and the climate impacts associated with this production.

“The results of our investigation, which gathered data from just seven companies, are disturbing, with this limited data alone revealing that cryptominers are large energy users that account for a significant – and rapidly growing – amount of carbon emissions,” the lawmakers said in their letter.

“Our investigation suggests that the overall U.S. cryptomining industry is likely to be problematic for energy and emissions,” they asserted. “But little is known about the full scope of cryptomining activity.”

The lawmakers said that “it is imperative that your agencies work together to address the lack of information about cryptomining’s energy use and environmental impacts, and use all available authorities at your disposal” to require reporting of energy use and emissions from cryptominers.

APPA Grant Helps Rock Hill, S.C., Integrate SCADA Fault Data

July 28, 2022

by Peter Maloney
APPA News
July 28, 2022

The City of Rock Hill in South Carolina has used a grant from American Public Power Association’s Demonstration of Energy & Efficiency Developments (DEED) program to help make fault detection more visible to repair crews and thereby improve reliability and reduce the duration of electrical outages for customers.

The project aimed to improve outage restoration times using smart overhead and underground fault indicators to communicate and integrate with the utility’s Supervisory Control and Data Acquisition (SCADA) and Outage Management (OMS) systems.

Fault data was already being sent to the SCADA system, but Rock Hill’s dispatchers and field technicians did not have a visual representation of the faults. The City applied for and was awarded a DEED grant to develop an OMS integration module.

The module allows the SCADA integration of the fault indicators to be displayed on the OMS map viewer whenever the server has indicated a fault has been detected by a device in the power network.

The project was designed to address two problems. First, service personnel would spend the first part of a call trying to pinpoint the location of a fault, draining financial resources and dragging out restoration times.

The second problem was a lack of real-time mapping of system strengths and weaknesses that could be used to identify areas where there are repeated outages and faults. That information can be used to target resources for improvement. Without real-time data, the utility said it is not able to make as many preventative decisions that benefit the long-term success of its electrical system.

Under the Fault & Load Indicator Technology Integration Project, Rock Hill was able to develop a software module through dataVoice, its OMS vendor, to integrate the information provided from smart fault indicators on the V3 outage map.

System status indicators was delivered from the SCADA to the OMS system with location and unique identifiers imported via GIS Publisher and is made available in the dataVoice’s mobile application.

The original termination date of the grant award was July 1, 2021, but the original fault indicators failed to perform to expectations, delaying progress for one year.

New technologies were explored, tested, and one was selected for implementation during the last two quarters of 2021. The equipment was installed during the first quarter of 2022.

A contract was signed with dataVoice in January 2022 and a kick-off meeting was held in March 2022 to initiate the software integration. During software testing, Rock Hill discovered malfunctions that dataVoice corrected, and the project was implemented and completed in June.

The completed project enables data from field sensors to communicate with a SCADA system which relays the information to an OMS system in a way that provides users with a visual representation of faults and outages.

The completed application reduces the complexity of information from the OMS by giving a direct visual representation of what kind of fault is occurring and the approximate location on the line based on the locations of the sensors. Rock Hill said.

The overall cost of the project was $154,401 of which the City of Rock Hill contributed about $129,066 and the DEED grant provided $25,335.

The project is applicable to all utilities as we share the same goal, to improve customer satisfaction by reducing the duration of outages by adapting the latest technology, Rock Hill said in its final DEED report.

As a next step, the City of Rock Hill said it plans to train its dispatchers and field technicians to use of the software. The utility also intends to budget a reoccurring $40,000 each year for the purchase of additional sets of smart overhead and underground smart fault sensors.

The City of Rock Hill offers electric, water, and wastewater utilities to its customers. It distributes electric power to approximately 32,000 residential and 8,000 commercial and industrial customers in the greater Rock Hill area.

CPUC Seeks Comment On Study About Adding Hydrogen To Natural Gas Stream

July 28, 2022

by Paul Ciampoli
APPA News Director
July 28, 2022

The California Public Utilities Commission (CPUC) is seeking comment on a study about the feasibility and safety of injecting hydrogen into the natural gas system as a means of helping the state meet its decarbonization goals.

The CPUC commissioned the Hydrogen Blending Impacts Study in compliance with Senate Bill 1369 and as part of its ongoing Renewable Gas Rulemaking.

The Rulemaking examines expanding renewable hydrogen by establishing standards and interconnection protocols for injecting renewable hydrogen into natural gas pipelines.

The study was done by the University of California at Riverside.

The study found that hydrogen blends of up to 5 percent in the natural gas stream are generally safe but going beyond 5 percent results in a greater chance of pipeline leaks and the embrittlement of steel pipelines. In addition, hydrogen blended into the natural gas stream at levels above 5 percent could require modifications of appliances such as stoves and water heaters to avoid leaks and equipment malfunction.

Hydrogen blended at levels above 20 percent present a higher likelihood of permeating plastic pipes, which can increase the risk of gas ignition outside the pipeline. And because hydrogen has a lower energy content than natural gas, more hydrogen-blended gas would be needed to deliver the same amount of energy to users.

The researchers concluded that more study on the effects of blending hydrogen into the gas system is needed to ensure the safety of the practice. The researchers also said it is critical to conduct real world demonstrations of hydrogen blending under safe and controlled conditions to determine “the appropriate blend percentage suitable to mitigate operational risks such as ignition.”

In March 2020, the Northern California Power Agency said it was preparing to install equipment at a 304-megawatt (MW) power plant so it could burn hydrogen mixed with natural gas.

In December 2019, the Los Angeles Department of Water and Power said it planned to phase out the 1,800-MW, coal-fired Intermountain Power Project (IPP), which it participates in with electric power cooperatives and other public power utilities in California, Nevada and Utah, and replace it with natural gas-fueled generation that would eventually be fueled entirely by hydrogen.

“This Study provides additional insight into the possibilities and limits of California’s pipeline infrastructure as we explore options for supplying zero-carbon energy to hard to decarbonize applications,” Clifford Rechtschaffen, the CPUC commissioner assigned to the Renewable Gas Rulemaking, said in a statement. “I look forward to party comments on hydrogen-methane blending and its role in decarbonization strategies.”

The ruling seeking comments is available on the CPUC website, and members of the public can comment on the study and access related documents here.

Midwest Grid Operator’s Board Approves $10.3 Billion In Transmission Projects

July 27, 2022

by Paul Ciampoli
APPA News Director
July 27, 2022

The Midcontinent Independent System Operator’s (MISO) Board of Directors on July 25 unanimously approved a portfolio of long-range transmission projects, which represent a $10.3 billion investment.

This Tranche 1 portfolio is the first of four planned tranches in MISO’s Long-Range Transmission Planning (LRTP) process. The projects are needed to begin to integrate new generation resources outlined in MISO member and states plans and increase resiliency in the face of severe weather events, MISO said.

Analyses conducted as part of the LRTP initiative indicate the Tranche 1 benefits are conservatively well in excess of costs, with a benefit-to-cost ratio of at least 2.2 for all resource zones in the MISO Midwest Subregion, MISO said.

Benefit metrics include congestion and fuel savings, avoided capital costs of local resource investment, avoided transmission investment, resource adequacy savings, avoided risk of load shed and decarbonization.

The cost allocation approach for this portfolio has been approved by the Federal Energy Regulatory Commission.

“While Tranche 1 represents an important start, further work is needed to ensure reliability,” said Aubrey Johnson, MISO’s vice president of system planning. “Tranche 2 will focus on the MISO Midwest Subregion, Tranche 3 in MISO South, and Tranche 4 will address the limitations on power exchange between the MISO Midwest and South Subregions.”