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PJM Begins Expedited Process for Reform of Capacity Auction

March 8, 2023

by Peter Maloney
APPA News
March 8, 2023

PJM Interconnection and its stakeholders have begun an expedited process to address capacity market design issues related to maintaining resource adequacy.

The PJM Board implemented the Critical Issue Fast Path process by letter on Feb. 24, citing a PJM report, Energy Transition in PJM: Resource Retirements, Replacements and Risks.

The letter noted that while PJM “currently has a healthy reserve margin, Winter Storm Elliott demonstrated that PJM is not immune to reliability challenges as the system was stressed, even with a reserve margin in excess of the target and a lower level of renewable penetration than other regions.”

Although PJM maintained grid reliability throughout Winter Storm Elliott, “we believe this event demonstrates a need to focus on PJM’s rules and processes to ensure reliability is maintained both now and throughout the transition,” the letter said.

PJM has “healthy reserve margins,” but that “cannot be taken for granted into the future,” PJM said in the letter, noting that up to 40 gigawatts of capacity in the regional transmission organization, whose territory includes a large swath of Mid-Atlantic and Midwestern states, is at risk of retirement by 2030.

The PJM report also highlighted “significant uncertainty around the pace of resource additions, which at current completion rates would be inadequate to maintain resource adequacy.” In addition, the potential also exists for “significant load growth in the future, driven by data center additions and electrification of transportation, heating and industry,” PJM said.

In initiating the Critical Issue Fast Path process for resource adequacy, PJM’s board of directors identified four areas for stakeholders to focus on in the CIFP process:

These areas are considered as “must haves,” Adam Keech, PJM vice president of market design and economics, said during a Feb. 28 meeting of PJM’s Resource Adequacy Senior Task Force. “These will be the centerpiece of the PJM proposal,” Keech said, adding, “the board is open to solutions across the spectrum that align with their objectives.”

This fast-track process will inform a decision by PJM’s board by late summer, and the organization aims to file its proposal with the Federal Energy Regulatory Commission on Oct. 1.

Capacity auctions normally occur three years before the capacity delivery date, but the reforms under way in PJM have caused delays for several capacity auctions. PJM hopes to have its capacity auction schedule back on track for the 2027/2028 auction, which is now scheduled for May 2024, but PJM’s board is seeking stakeholder feedback on whether prior year auctions that have not been run, the 2025/2026 and 2026/2027 auctions, should be adjusted or pushed back.

DOE Urged to Provide More Flexibility, Fund Eligible Hydro Projects Under Incentive Programs

March 7, 2023

by Paul Ciampoli
APPA News Director
March 7, 2023

The Department of Energy should provide for more flexibility for permits and authorizations and fund all eligible projects under hydroelectric incentive programs that will be implemented under the Infrastructure Investment and Jobs Act, the American Public Power Association and two other associations recently said in comments filed with DOE.

Section 40333 of the infrastructure law amended the Energy Policy Act of 2005 to establish section 247, which offers a new hydroelectric incentive payment to the owners and operators of qualified hydroelectric facilities for capital improvement projects directly related to supporting grid resiliency, improving dam safety, and environmental enhancements.

Incentive payments are limited to 30 percent of the cost of capital improvements, and only one incentive payment of no more than $5 million can be made to a single project per year. $553.6 million was appropriated for the provision.

In February, DOE issued draft guidance to inform its implementation of hydroelectric incentives in the Infrastructure Investment and Jobs Act.

APPA was joined by the National Hydropower Association and the Edison Electric Institute in Feb. 23 comments filed in response to the draft guidance.

The Associations asked that DOE provide funds to all eligible projects on an equitable basis. “Congress did not authorize DOE to create a prioritization structure between categories or within categories. It is impossible for DOE to create a system that could score the vast array of potential projects that could be eligible for Section 247 grants,” they said. “DOE should review each project to see if it is eligible for funding and, in the event of oversubscription, prorate such that eligible projects receive at least some funding.”

The groups noted that the draft guidance requires applicants to have received any and all permits and authorizations as a condition on eligibility. “This strict requirement significantly limits the population of potential investments to only those that are shovel ready. This was not Congress’ intent,” APPA and the other groups said. 

Projects that are still ongoing the permitting process should be eligible to apply for funding, they argued, noting that DOE has other programs that “obligate” funds pending the permitting process. “Actual outlay should remain conditioned on the project receiving all applicable permits.”

The groups also argued that the application period should be long enough to give applicants the opportunity to put together robust and complete applications, noting that the Section 247 program is new for both DOE and the industry. 

“The Associations have heard great interest in this program from member companies; however there are significant questions on what constitutes an eligible project and uncertainty as to what is required in the application package.”

APPA, EEI and NHA said that potential applicants will require varying degrees of resources to put together a complete application. “The Associations recommend at least a 90-day open window which gives potential applicants enough time to put together comprehensive applications.“

The Associations said they agree that projects where capital was spent (i.e., placed in service) after the IIJA was signed by President Biden, but before guidance was finalized are eligible.

However, due to the timing of the development of these projects, they were planned and undertaken without guidance from DOE, they pointed out.

“Therefore, they had no way to know what was required to apply for Section 247 funds. DOE should create a process such that these projects have a path to apply for these funds and cure any deficiencies so they can meet the spirit and intent of the guidance.” 

The Associations recommended that that DOE require only expenditures made after the final guidance is issued need to adhere to the Community Benefits Plan requirements in Section VIII and relevant requirements in Section XIII.  Alternatively, DOE could grant waivers in these cases.

NREL Report Sums Up Benefits of a Broader RTO for California And The West

March 7, 2023

by Peter Maloney
APPA News
March 7, 2023

California could benefit from a widespread electric power grid in the West, according to a new report from the National Renewable Energy Laboratory.

The study, The Impacts on California of Expanded Regional Cooperation to Operate the Western Grid, is the final report in a series of studies authorized by California’s legislature.

The studies reviewed for the report “demonstrate that California’s goals for renewable energy and greenhouse gas reduction can be achieved more quickly and with less cost to Californians through expanded regional cooperation,” the authors wrote. “The magnitude of those benefits will vary based on the mode of cooperation and on the states and utilities that elect to participate,” they added.

As an example, the authors noted that the total benefits to California of a West-wide extended day-ahead energy market operated by the California Independent System Operator were less than the estimated benefits of a West-wide regional transmission organization, an option that was identified by the California legislature.

RTOs tend to yield “greater cost savings and grid flexibility than more limited forms of cooperation,” the report’s authors said. In addition, the RTO option would not remove the jurisdiction of California, or any other state, over its retail rates, resource planning, resource siting, transmission siting, renewable energy policies, or emissions reduction policies, the report noted, but it would very likely require changes to CAISO’s governance.

For the rest of the western United States, however, an extended day-ahead market retained a slightly larger portion of expected benefits of a full RTO, according to the report. Some of the technical studies reviewed in the report suggest the benefits of more comprehensive forms of regional cooperation such as a West-wide RTO might not be spread evenly across participating states and utilities, the authors noted.

Transmission planning across a region, rather than by individual utilities, can reduce transmission congestion costs and the cost of operating reserves required to maintain reliability, leading to more efficient use of the transmission system and greater reliability for customers, the report found.

Other benefits include less curtailment of solar and wind resources because of congested transmission paths and the ability to move excess wind and solar power elsewhere in the region when local production is high and demand is low, the authors said, adding that regional cooperation also can yield more operational flexibility to manage the variation in solar and wind output and better grid resilience. In addition to reducing production costs, regional cooperation can also offer “significant savings in the cost of resource adequacy,” the authors noted.

However, regional cooperation can take many other forms, some of which have been or are being implemented, “demonstrating a general momentum towards greater regional cooperation,” the authors said.

Policymakers must weigh the benefits of various regional cooperation solutions, but experiences in other parts of the country suggest regional cooperation is not one single decision but an evolutionary progression, the authors said. They noted that CAISO has operated a voluntary real-time Western Energy Imbalance Market since 2014 that has saved participants more than $3 billion and formed the foundation for CAISO’s approval in February 2023 of the Extended Day-Ahead Market that utilities may join without becoming full CAISO members.

Besides CAISO, other balancing authorities involved in preparing the report included the Balancing Authority of Northern California, the Turlock Irrigation District, the Western Area Power Administration, the Los Angeles Department of Water and Power, NV Energy, PacifiCorp, and the Imperial Irrigation District.

Florida Lawmakers Introduce Bills That Would Place Public Power Utilities Under PSC Regulation

March 7, 2023

by Paul Ciampoli
APPA News Director
March 7, 2023

Legislation has been introduced in the Florida Legislature that would give state utility regulators the ability to regulate public power utilities with customers outside city boundaries.

The bills are HB 1331 and SB 1380. The Florida Legislature’s current session began on March 7. Both bills would take effect July 1, 2023, if signed into law by Florida’s governor.

In essence, both bills seek to place municipal utilities selling retail electric or natural gas service to customers outside their city limits under the full regulation of the Florida Public Service Commission (PSC), among imposing other significant limitations.

“Municipal electric utilities were created to ensure communities had access to affordable, reliable power through an entity that was locally owned, locally controlled and locally operated. Florida’s 33 municipal utilities do that and more,” said Amy Zubaly, FMEA Executive Director in response to the legislation. “Everything Florida’s municipal utilities do is centered on making their communities stronger and the quality of life better for their family, friends and neighbors.”

SB 1380 would revise the definition of the term “public utility,” traditionally inclusive in Florida of investor-owned utilities subject to PSC regulation, to include a municipality supplying electricity to any electric retail customer receiving service at a physical address located outside its corporate boundaries. Under the proposed legislation, full PSC regulation over municipal electric and gas utilities that serve outside-the-city customers would continue for at least five years.

Going substantially further in its restrictions on municipal electric and gas utilities, HB 1331 mirrors the provisions of SB 1380 and also creates a new statutory provision authorizing outside-the-city surcharges on utility customers of up to 10 percent, with the surcharge based on the percentage of customers located outside municipal boundaries.

Additionally restricting are the provisions in the proposed legislation that authorize, but limit, transfer to the city general fund from municipal electric or gas utilities. The legislation imposes limitations on percentages of transfer to the general fund for both inside- and outside-city customers. Of great concern is a provision specifying that the use of general fund transfer is limited to only public utility purposes, or perhaps, a total ban on earning a reasonable return on utility expenses.

“We have grave concerns regarding the proposed legislation that would add additional state regulation to municipal utilities and its impact on our communities and the affordability of customers’ rates,” Zubaly continued. “We look forward to working with the bill sponsors to address any outstanding issues.”

The 2023 Florida Legislative Session runs through May 5.

Santee Cooper Issues RFP for Capacity and Energy

March 7, 2023

by Paul Ciampoli
APPA News Director
March 7, 2023

Santee Cooper has issued a request for proposals to assist in meeting specific load growth expectations in their service territory starting January 1, 2024.

Santee Cooper, the state-owned public power utility in South Carolina, is requesting proposals for firm capacity and energy from all dispatchable resources for delivery to its load in the Santee Cooper balancing authority.

Santee Cooper may be required to bundle multiple offers to meet load growth forecasts as a result of this RFP.

Examples of eligible dispatchable resources include, but not limited to: 

Proposals are due March 24, 2023.

The RFP is available here.

APPA Weighs In On EPA’s Proposed Clean Air Act State Plan Implementing Regulations

March 7, 2023

by Paul Ciampoli
APPA News Director
March 7, 2023

The American Public Power Association recently weighed in on the Environmental Protection Agency’s proposed Clean Air Act Section 111(d) implementing regulations, with APPA recommending a federal plan timeline no shorter than 18 months and voicing concerns with the timeframe to submit state plans.

APPA, which submitted comments on the proposed EPA regulations on Feb. 27, said that EPA’s state and federal implementation timelines are impracticable.

“States must have a fair opportunity to perform their role. Otherwise, states are essentially written out of the cooperative process, contrary to statute,” APPA said. “If states are not afforded enough time  to fulfill their roles, Congress’s intent is thwarted. The rulemaking framework effectively collapses into an EPA-only standard setting and federal plan implementing approach.”

The current proposal of only 15 months does not provide states adequate time, APPA said.

APPA highlighted a number of reasons to explain why states need a longer time frame.

Among other things, APPA noted that the proposed rule requires that states conduct “meaningful engagement” of pertinent stakeholders.

State plan submissions must include a list of these stakeholders, a summary of engagement, and a summary of stakeholder input received. EPA’s definition of “meaningful engagement” requires “early outreach” and solicitation of input on the state plan.

“The effort entailed to engage meaningfully should not be taken lightly. States must define the relevant stakeholders first. These parties may be numerous, depending on the section 111(d) rule at issue and the number of affected sources and geographic areas. Then states must undertake ‘meaningful engagement,’” APPA noted.

States also need time to determine the reliability impacts of state plans. CAA Section 111(d) emissions guidelines may have impacts on grid reliability.

For instance, the Supreme Court observed that there were no controls that a coal plant operator could install and operate to attain compliance with Clean Power Plan limits. Rather, compliance was achieved by forcing a shift throughout the power grid from one energy source to another, APPA said.

“This approach would have impacted reliability by forcing certain assets offline, had the Clean Power Plan taken effect. Likewise, if EPA imposes a section 111(d) rule that effectively achieves compliance via reduced generation, reliability impacts must be thoroughly evaluated.”

APPA also argued that Remaining Useful Life and Other Factors (RULOF) requirements are substantial and will require significant time to satisfy.

In the proposed rule, EPA fundamentally changes and enhances RULOF requirements for state plans, according to APPA.

“States must embark on a comprehensive analysis of any source to be considered for a less stringent standard of performance,” APPA pointed out. “EPA squarely places the responsibility of making this demonstration on states.”

The analysis must identify all control technologies or other systems of emissions reductions available for the source. This evaluation would involve an emissions analysis for each source. There is also a feasibility component of the RULOF analysis to prove that the source cannot meet the best system of emission reduction identified by EPA.

The state plan “must present details, such as monitoring, reporting, and recordkeeping, in addition to the proposed emission standard. Further, states must undertake an environmental justice analysis of the less stringent standard on vulnerable communities.”

APPA also noted that:

“Given these considerations, APPA supports a time frame of 36 months but certainly no shorter than 24 months for state plan development.”

The federal plan promulgation deadline should be at least eighteen months, APPA said.

“EPA must provide itself adequate time to develop federal plans. EPA proposes that federal plan promulgation occur within 12-months from failure to submit or disapproval of a state plan. This aspirational deadline is likely to fail based on APPA’s members’ experiences with federal plan promulgation in other CAA programs,”

EPA “contends with a multitude of litigation cases enforcing missed actions on state implementation plans and promulgation of federal plans when states miss deadlines. An aggressive deadline for section 111(d) federal plan development will place unnecessary pressure on EPA and will result in uncertainty for states, sources, and stakeholders if deadlines are missed.”

In addition, federal plans should not be rushed, APPA argued. “As EPA highlights in the rule, federal plan development has many layers. EPA contemplates collaboration through an interagency workgroup and meaningful public engagement. Careful consideration of stringency of the emissions guidelines and translating them to numerical standards will require work.”

Nuclear Regulatory Commission Grants Exemption For Calif. Nuclear Plant’s Continued Operation

March 6, 2023

by Paul Ciampoli
APPA News Director
March 6, 2023

The Nuclear Regulatory Commission has granted an exemption to Pacific Gas & Electric Co. that would allow the Diablo Canyon nuclear power plant to continue operating while the agency considers its license renewal application.

After evaluating the company’s exemption request, NRC staff determined that the
exemption is authorized by law, will not present undue risk to the public health and safety, and is
consistent with the common defense and security.

In addition, the staff determined Diablo Canyon’s continued operation is in the public interest because of serious challenges to the reliability of California’s electricity grid.

The current operating licenses for the Diablo Canyon Nuclear Power Plant, Units 1 and 2, expire on Nov. 2, 2024, and Aug. 26, 2025, respectively. The exemption will allow those licenses to remain in effect provided PG&E submits a sufficient license renewal application for the reactors by Dec. 31, 2023.

The NRC will continue its normal inspection and oversight of the facility throughout the review to ensure continued safe operation. If granted, the license renewal would authorize continued operation for up to 20 years.

NRC regulations allow a reactor’s operating license to remain in effect beyond its expiration date contingent upon the licensee submitting a sufficient license renewal application at least five years prior to expiration – a status called “timely renewal.” PG&E requires the exemption because it has not met that five-year requirement.

PG&E applied to renew the licenses in November 2009 but withdrew the application in
2018 and announced plans to cease operations and decommission the reactors when the licenses
expire.

After California enacted legislation last September to support continued operation, PG&E
asked the NRC to resume its review of the previous application. In January, the staff informed
the company that it would need to submit a new, up-to-date renewal application. That made the
current exemption necessary to allow continued operation while the application is under review.
PG&E has said it will submit an application by the end of this calendar year.

The NRC’s review of a license renewal application typically lasts 22 months.

The California Energy Commission on Feb. 28 approved a staff analysis recommending the state pursue extending operation of Diablo Canyon nuclear power plant through 2030 to ensure electricity reliability.

The determination is based on data showing California risks energy supply shortfalls during extreme weather events driven by climate change, the CEC said.

APPA Voices Concerns About Redundant Cyber Incident Reporting Bill

March 6, 2023

by Paul Ciampoli
APPA News Director
March 6, 2023

The House Energy and Commerce Committee’s Subcommittee on Energy, Climate, and Grid Security in late February approved a bill that would set up redundant cyber incident reporting mandates.

The American Public Power Association believes the bill, H.R. 1160, the Critical Electric Infrastructure Cybersecurity Incident Reporting Act, would create significant confusion, as well as impose a significant burden on public power utilities with little, if any, security benefits. The bill is sponsored by Representatives Tim Walberg (R-MI) and Kim Schrier (D-WA).

H.R. 1160 would define the Department of Energy as the designated agency within the federal government to receive notifications regarding cybersecurity incidents and potential cybersecurity incidents with respect to critical electric infrastructure from other federal agencies and owners, operators, and users of critical electric infrastructure.

Owners, operators, and users of critical electric infrastructure (including federal agencies, such as the Power Marketing Administrations) would be required to report cybersecurity incidents and potential cybersecurity incidents to DOE within 24 hours of discovery. DOE would be directed to, within 240 days of enactment, promulgate regulations to facilitate the submission of notifications regarding cybersecurity incidents and potential cybersecurity incidents. 

In a Feb. 26 letter to lawmakers, Desmarie Waterhouse, Senior Vice President of Advocacy and Communications & General Counsel at APPA, detailed APPA’s concerns with H.R. 1160.

She said it is not clear how this legislation would work with existing cybersecurity incident reporting requirements, such as what is required through the North American Electric Reliability Corporation, or with pending cybersecurity incident reporting requirements, such as the Cyber Incident Reporting for Critical Infrastructure Act of 2022 (CIRCIA).  

CIRCIA directs the Cybersecurity and Infrastructure Security Agency to work with sector risk management agencies (DOE, in the electric utility industry’s space) to harmonize implementation of the law with existing reporting requirements.

“APPA believes that task will be a significant undertaking and enactment of this legislation would create great confusion,” wrote Waterhouse.

CIRCIA says that covered entities that report “substantially similar information” within a “substantially similar timeframe” to another federal agency can be exempted from reporting directly to CISA provided that the federal agency has an “agency agreement and sharing mechanism in place” with CISA.

APPA believes that DOE should prioritize getting the legal agreements and technology in place that would allow electric utilities to report incidents directly to DOE (or NERC/FERC) and have that reporting count as fulfilling our reporting obligations under CIRCIA. This would benefit DOE without setting up a separate process as this bill envisions, Waterhouse said.

 Defining what constitutes a “potential cybersecurity incident” is “deceptively difficult – it is subjective and highly dependent on the situation and assets involved,” wrote Waterhouse.

Such mandated reporting of “potential incidents,” especially with a 24-hour reporting window, would likely result in utilities overreporting, making it difficult if not to impossible to get a meaningful signal through the noise.

“For example, one large APPA member says that it blocks roughly one million attempts to connect to internal networks on any given day. Each of these one million attempts could fall into the ‘potential cybersecurity incident’ definition. But none of these attempts were successful, nor were they targeted, which negates the usefulness of reporting,” the letter notes.

In addition, critical electric infrastructure is defined in the 2015 FAST Act as “a system or asset of the bulk power system, whether physical or virtual, the incapacity or destruction of which would negatively affect national security, economic security, public health or safety, or any combination of such matters.”

“This is a broad definition. No list exists of CEI and this legislation does not offer any guidance as to who would determine what constitutes CEI — would DOE have to create one to figure out who is covered by this law or would utilities have to self-designate? Each of these possibilities comes with a host of issues,” wrote Waterhouse.

APPA is urging member utilities that have members of Congress who sit on the full Energy & Commerce Committee to reach out to those lawmakers immediately to flag concerns with this legislation and to share APPA’s letter.

Western Electricity Coordinating Council Releases Long-Duration Storage Assessment

March 3, 2023

by Paul Ciampoli
APPA News Director
March 3, 2023

The Western Electricity Coordinating Council recently released a long-duration energy storage assessment that examines how, with 12-hour duration energy storage, an 80–90% clean energy future with high electrification load can be achieved and what effect this might have on the reliability of the bulk power system.

The purpose of the assessment was to determine whether long-duration energy storage systems mitigate challenges in reaching higher clean energy percentages, as identified in a 2040 clean energy scenarios assessment completed by WECC.

The clean energy scenarios assessment examined increasing clean energy and energy needs percentages provided by non-carbon-emitting resources in 2040 to 80, 90, and 100 percent.

The long-duration energy storage assessment initially sought to examine the impacts on the clean energy percentage of increasing energy storage duration — to 24, 48, 168, and 336 hours.

In WECC’s initial simulations, energy storage charging and discharging cycles for longer
than 24 hours were not used due to modeling options requiring use of static annual user defined
energy prices, thus resulting in lower than anticipated use of storage devices. Therefore, the study,
focused on if an 80-90% clean energy scenario, with load and generation balanced, can be achieved
with 12-hour duration energy storage, the report said.

The study explored the following reliability impacts on the Western Interconnection of these high clean energy scenarios:

The long-duration energy storage assessment produced a number of takeaways.

One takeaway is that energy storage systems with a 12-hour storage duration modeled over a 24-hour charging and discharging cycle can mitigate daily fluctuations in loads and resource availability.

Also, different modeling tools are needed to model charging and discharging cycles longer than 24
hours.

Another takeaway is that to achieve a 90% clean energy scenario, significant capacity addition was needed for both renewable and energy storage resources. Careful balance between renewables and storage is needed to achieve the desired clean energy targets.

Also, increasing storage and renewable energy capacity also increases the “spillage” of renewable
resources.

Other takeaways include:

Building on the current 2022 long-duration energy storage assessment, the report said that the following opportunities will increase the understanding of potential energy storage system benefits in 2023:

Click here for the full report.

WECC is a non-profit corporation that exists to assure a reliable bulk electric system in the geographic area known as the Western Interconnection.

WECC has been approved by the Federal Energy Regulatory Commission as the Regional Entity for the Western Interconnection. The North American Electric Reliability Corporation delegated some of its authority to create, monitor, and enforce reliability standards to WECC through a delegation agreement.

Moves to Expand Public Power in Michigan Grow in Wake of Recent Outages

March 3, 2023

by Paul Ciampoli
APPA News Director
March 3, 2023

In the wake of recent power outages affecting parts of Michigan, communities in the state recently took steps to explore the option of municipalization.

The steps were spurred by power outages in the service territories of investor-owned utilities DTE Energy and Consumers Energy.

On March 1, Washtenaw County residents gave public comments asking the County Commission to investigate the creation of a public power utility, arguing that public power utilities provide better reliability, lower rates, and the ability to reduce fossil fuel use.

Washtenaw County Commissioners unanimously approved a resolution directing the County Administrator to investigate alternative options to DTE and Consumers Energy within Washtenaw County.

County Commissioner Yousef Rabhi cited the Michigan Revenue Bond Act of 1933, stating that it gives public corporations like Washtenaw County the right to acquire infrastructure necessary to distribute power and establish its own publicly owned electric utility. 

Meanwhile, in late February, the Pontiac, Mich., City Council approved a resolution that, among other things, calls for the Michigan Legislature to start a committee that would research the feasibility of creating a state-run utility.

In early 2022, Ann Arbor, Michigan’s City Council unanimously adopted a resolution initiating a feasibility study for a public power utility.

Ann Arbor for Public Power, a nonprofit grassroots citizen group, has been leading the municipalization effort. DTE Energy currently serves Ann Arbor.

Ann Arbor for Public Power last summer said that a request for proposals for a municipalization feasibility study fell short on several fronts.

Ann Arbor for Public Power noted that it supports a thorough and unbiased municipalization feasibility study. “However, this RFP is flawed, and could lead to a study that does not provide the information to accurately determine the technical and economic feasibility of an Ann Arbor municipal electric utility,” the group said.

The American Public Power Association offers resources related to municipalization. Click here for additional details.