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Groups Urge DOE to Prioritize Funding Toward Production of Distribution Transformers

October 21, 2022

by Paul Ciampoli
APPA News Director
October 21, 2022

The American Public Power Association (APPA) and the National Rural Electric Cooperative Association (NRECA) recently sent a letter to Department of Energy (DOE) Secretary Jennifer Granholm urging the prioritization of funding toward the production of distribution transformers.

“Throughout 2022 we have been calling attention to the unprecedented challenges our members, representing the nation’s not-for-profit, community-owned and rural electric utilities, are facing in procuring basic equipment needed to provide reliable electric service to Americans, as well as in restoring power following storms and natural disasters, particularly with regard to distribution transformers,” wrote Joy Ditto, President and CEO of APPA, and Jim Matheson, CEO of NRECA in their Oct. 19 letter.

They noted that under Granholm’s leadership, the Electricity Subsector Coordinating Council stood up a Tiger Team to work with the federal government to address the supply chain crisis and identify solutions that will resolve current and long-term constraints.

“We’ve surveyed our members to provide the latest information to the Tiger Team and they report waiting on average a year or more for distribution transformers. Projects are now being deferred or canceled, and utilities are concerned about their ability to respond to more than one major storm in a season due to their depleted stockpiles,” noted Ditto and Matheson.

The Department of Energy (DOE) was allocated at least $250 million from the Inflation Reduction Act (IRA) to execute on Defense Production Act (DPA) authorities.

“To our knowledge, the IRA gives DOE discretion to use the funds on any technology invoked under DPA. We respectfully urge you to reconsider your plan to use the entirety of the funds for heat pumps and instead put at least some of the funds to immediately increase distribution transformer production,” the trade group leaders said.

Issues around labor have been identified as the most immediate challenge for manufacturers. “We urge DOE to establish a $220 million wage subsidy program that would assist manufacturers in attracting and retaining more workers, thus enabling them to move to 24/7 operations. We believe such a program could result in increased output of approximately 30 percent of distribution transformers in 2023 and support the workforce keeping the lights on in our country.”

While the trade groups support long-term investment in domestic manufacturing capacity for heat pumps, “we believe the current shortage of distribution transformers available to electric utilities poses an unacceptable risk to the electric reliability of our nation and urge you to alleviate this unprecedented situation by prioritizing available IRA funding for transformers,” Ditto and Matheson said.

“If we don’t act today, we risk being unable to recover from a storm tomorrow. In the longer term, it could mean being unable to meet the electrification goals envisioned by the Biden administration. In the meantime, the backlog for distribution transformers continues to grow.”

Household Energy Prices Expected to Increase Sharply This Winter: EIA

October 20, 2022

by Peter Maloney
APPA News
October 20, 2022

Household energy prices will increase broadly this winter on expectations of higher retail energy prices and a slightly colder winter, according to the latest short-term forecast from the Department of Energy’s Energy Information Administration (EIA).

Retail heating oil prices will be 19 percent higher than last winter, reflecting price pressures in the distillate fuel oil market: low inventories, low imports, and limited refining capacity, the EIA said in its Winter Fuels Outlook, which is part of its Short-Term Energy Outlook (STEO). Natural gas prices are expected to be 21 percent higher than last winter, but propane prices are forecast to fall by 2 percent this winter, according to the EIA. The Winter Fuels Outlook reflects consumption across all residential energy uses, not just home heating.

Changes in wholesale heating oil and propane prices pass through to retail prices much more quickly than changes in wholesale natural gas or electricity prices, the EIA said.

With almost 90 percent of U.S. homes heated primarily by natural gas or electricity and with higher expected wholesale prices for natural gas this winter, the EIA forecasts higher retail prices for both natural gas and electricity this winter.

The EIA is forecasting Henry Hub natural gas spot price to average about $7.40 per million British thermal units (MMBtu) in the fourth quarter and then fall below $6.00/MMBtu in 2023 as gas production rises.

Natural gas consumption, on the other hand, will average 87.9 billion cubic feet per day (Bcf/d) in 2022, up 3.9 Bcf/d from 2021, reflecting more consumption across almost all sectors, the EIA said. The agency sees natural gas consumption falling by 2.6 Bcf/d in the 2023 because of lower consumption in the electric power and industrial sectors.

The EIA also forecasts a rise in electricity sales of 2.7 percent in 2022, mostly as a result of higher economic activity but also because of slightly hotter summer weather than last year. The agency sees electricity sales falling by 0.9 percent in 2023.

Meanwhile, wholesale electricity prices will be about 20 to 60 percent higher on average this winter with the largest increases likely in New England because of possible natural gas pipeline constraints, reduced fuel inventories for power generation, and uncertainty regarding liquefied natural gas shipments given the tight global supply conditions, the EIA said.

On the residential side, the EIA expects electricity will average 14.9 cents per kilowatt hour in 2022, up 8 percent from 2021, reflecting the expected increase in wholesale power prices driven by higher natural gas prices.

Natural gas will fuel 38 percent of electricity generation in 2022, up from 37 percent in 2021, but will fall to 36 percent in 2023, the EIA forecasts.

Electric generation fired by coal is expected to continue to fall, from 23 percent last year to 20 percent in 2022 and 19 percent in 2023 because of the expected retirement of some coal-fired capacity, the EIA forecasts.

Renewable generation sources, meanwhile, continue to gain ground, providing 22 percent of generation in 2022 and 24 percent in 2023, up from 20 percent in 2021, the EIA said.

Ultimate Public Climate Spending Spurred by Inflation Reduction Act Could be Over $800 Billion: Credit Suisse

October 19, 2022

by Paul Ciampoli
APPA News Director
October 19, 2022

Citing the uncapped nature of tax credits and attractiveness of economics, investment firm Credit Suisse is estimating that the ultimate public climate spending enabled by the Inflation Reduction Act (IRA) could be over $800 billion.

“We see most of the upside coming from solar, wind, battery deployment and manufacturing, clean hydrogen, and carbon capture,” Credit Suisse analysts wrote in a recent report on the IRA. “With subsidized green financing and the multiplier effect on federal grants/loans, the total public plus private financing could reach ~$1.7 trillion over ten years,” it said.

President Biden on Aug. 16 signed into law the IRA, which will extend and expand various energy tax incentives and give public power utilities direct access to such credits through a refundable direct payment tax credit.

The report said that roughly two-thirds of the baseline IRA spending is “allocated to provisions where the potential federal incentive is uncapped, meaning the ultimate outlay is either based on units of production or upfront capital spent.”

Therefore, Credit Suisse believes the Congressional Budget Office “is significantly underestimating costs of certain provisions as the attractiveness of credits could propel much higher activity levels, particularly in green manufacturing, carbon capture and clean hydrogen.”

Using its own forecasts, “we see federal climate spending at over $800 billion, doubling the baseline of >$400 billion. Combined with the multiplier effect on private investments and green financing programs, total spending could reach nearly $1.7 trillion over the next ten years.”

Credit Suisse said that the new credits in the IRA provide long-term certainty, flexibility on the choice of credits and are technology-agnostic.

“Combined with the manufacturing tax credits, the US should benefit from the lowest levelized cost of clean electricity in the world,” the report said.

Permitting uncertainty remains the single biggest execution risk in Credit Suisse’s view in reaching the full potential of the IRA, particularly around transmission, carbon dioxide Class VI permits, and future green infrastructure buildouts.

In a recent article in the Atlantic, Robinson Meyer breaks down the Credit Suisse report’s key conclusions and offers his own predictions about the impact of the IRA on the energy sector.

APPA’s Joy Ditto Details How Public Power Will Benefit From Inflation Reduction Act

Joy Ditto, President and CEO of the American Public Power Association, recently detailed how public power utilities are poised to benefit from the IRA.

“We’ve been working on this for over twenty years,” said Ditto on a recent episode of White House Chronicle, which is hosted by Llewellyn King.

Since the 1992 Energy Policy Act, “we’ve been looking at this idea of parity or comparability in the tax code for publicly-owned utilities, for other not-for-profit utilities like rural co-ops so that we can really be unleashed in the marketplace as we continue to drive toward a cleaner energy future,” she said.

The mechanism in the IRA, a refundable direct pay credit, “allows us to take advantage of these tax credits that have been available to our for-profit brethren for many years both in the form of an investment tax credit and a production tax credit.”

Interconnection Costs Have Risen Steeply in MISO: Berkeley Lab Report

October 18, 2022

by Peter Maloney
APPA News
October 18, 2022

The costs to interconnect wind, solar and storage projects in the Midcontinent Independent System Operator (MISO) region have nearly doubled and, in some cases, nearly tripled over the last 18 years, according to a study by the Lawrence Berkeley National Laboratory.

For projects that have completed all required interconnection studies, average costs for more recent projects have nearly doubled relative to historical costs from 2000 through 2018, and for projects still moving through MISO’s interconnection queue costs have more than tripled over the last four years, the report, Generator Interconnection Cost Analysis in the Midcontinent Independent System Operator (MISO) territory, found.

Specifically, costs averaged $102 per kilowatt (kW) for projects that have completed interconnection studies between 2019 and 2021. Active projects had even higher interconnection costs of $156/kW on average. Withdrawn projects had the highest costs, $452/kW, on average, which was “likely a key driver for those withdrawals,” the report’s authors said.

Irrespective of request status, wind projects had the highest interconnection costs at $399/kW, followed by energy storage at $248/kW, and solar at $209/kW. Natural gas projects were at the lowest end of cost scale at $108/kW.

Wind projects that completed the interconnection study process in 2021 had even higher costs, $252/kW on average, nearly four times the historical average, the report found. And wind projects that ultimately withdrew from the queue had average interconnection costs of $631/kW, equivalent to 40 percent of total project costs.

Even though larger generators have greater interconnection costs in absolute terms, the study found that economies of scale exist on a per kilowatt basis with medium wind and solar projects facing twice the potential interconnection costs of very large wind and solar projects.

Interconnection costs also vary by location, the authors noted. Projects in eastern MISO reported overall lower costs, irrespective of request status – on average $50-$70/kW – than requests in northern MISO and parts of Texas with average costs of $508-$915/kW.  

Projects requiring network upgrades beyond the interconnecting substation explain most of the sharp rise in cost differences, the report found. For instance, among withdrawn projects broader upgrades accounted for an average of $388/kW for recent projects, or 85 percent of total interconnection costs, the authors said.

Berkeley Lab gathered estimated interconnection costs from project-specific MISO interconnection studies, representing nearly 50 percent of all projects requesting interconnection between 2010 to 2020, or 30 percent when going back to 2000.

While the data is “sufficiently robust for detailed analysis,” the authors noted that much data remains unavailable to the public, which “poses a significant information barrier for prospective developers, resulting in a less efficient interconnection process.”

At year-end 2021, MISO had over 160 gigawatts (GW) of generation and storage capacity actively seeking grid interconnection. Most of the projects are solar, 112 GW, followed by wind, 22 GW. MISO’s interconnection queue also has data for 366 GW of withdrawn projects and 62 GW of in-service projects.

MISO’s 2022 generator interconnection queue is set to break those past levels, increasing by 220 percent over 2021 levels, if all project submissions are accepted as valid. If that is the case, MISO’s queue would balloon to 289 GW, with more than 95 percent of the submissions either renewable or energy storage projects, the report said.

The capacity associated with those requests is more than twice as large as MISO’s peak load in recent years of about 120 GW, the report’s authors noted. And, if substantial amounts of those projects are built, they “will likely exert competitive pressure on existing generation,” the authors said, noting, however, that “most projects have historically withdrawn their applications, often in response to high interconnection costs.” Only 24 percent of all projects requesting interconnection between 2000 and 2016 have ultimately achieved commercial operation at the end of 2021, they noted.

APPA Responds to FERC’s Generator Interconnection Reform Proposal

October 17, 2022

by Paul Ciampoli
APPA News Director
October 17, 2022

The Federal Energy Regulatory Commission (FERC) should consider a number of modifications and/or clarifications to a generator interconnection Notice of Proposed Rulemaking (NOPR) to help ensure that any final rule improves interconnection queue processing while not inadvertently creating problems that could impose unnecessary costs and inefficiencies on transmission providers, interconnecting generators, and existing transmission customers, the American Public Power Association (APPA) and the Large Public Power Council (LPPC) said.

The Oct. 13 comments filed by APPA and LPPC came in response to a NOPR issued by FERC in June 2022. In the NOPR, FERC proposed to reform its generator interconnection procedures and pro forma interconnection agreements to address interconnection queue backlogs.

Although the proposals in the NOPR are not directly applicable to public power transmission owners, public power utilities in regional transmission organization (RTO)/independent system operator (ISO) regions may be subject to the proposed requirements under RTO/ISO tariffs or other governing agreements. 

Also, as FERC specifically states in the NOPR, transmission providers that are not utilities subject to FERC’s general transmission jurisdiction (such as public power utilities) would be required to adopt the requirements of the NOPR as a condition of maintaining the status of any safe harbor tariff to satisfy the reciprocity requirements of FERC Order No. 888. 

In their comments, APPA and LPPC note that they generally support the initiatives in the proposed rule, “and we are gratified in particular by the NOPR’s focus on improving the incentives generation developers have to stand behind bona fide interconnection applications, which should have a substantial stabilizing effect.”

A common refrain in their comments is the need for flexibility in implementing certain of the NOPR’s proposals, particularly to accommodate existing generator interconnection processes that have made progress in addressing the types of challenges cited in the NOPR.

APPA and LPPC said that FERC should not adopt the NOPR’s proposal to require transmission providers to undertake informational interconnection studies. 

“Substantial information is already made available to prospective interconnecting customers, and the informational study requirement would transfer the current burdens associated with processing speculative interconnection requests to an extra-LGIP process.”

APPA and LPPC endorsed the proposed requirement to post certain interactive information for use by prospective generator interconnection customers, though they argued that the Commission should clarify that transmission providers would not be required to conduct any individualized analyses in response to use of these interactive tools.

While APPA and LPPC support the NOPR’s proposed requirement to use a cluster study approach in studying generator interconnection requests, they said the Commission should allow for an exception where there are too few interconnection applications to justify a cluster study approach. 

In addition, the groups said that FERC should allow for flexibility in the cost allocation methods used to allocate cluster study costs and to allocate costs of required transmission system network upgrades identified in the cluster study.

APPA and LPPC said they strongly support the Commission’s proposal to adopt financial commitment and readiness reforms for prospective generator interconnection customers. They said the Commission should not dilute these reforms by allowing an interconnection customer to provide a deposit in lieu of making a showing of commercial readiness. “It may be appropriate to permit deposits in lieu of demonstrating full site control in circumstances where an interconnection customer is genuinely prohibited by regulatory limitations from obtaining site control, or where particular regions have specific reasons to adopt a deposit-in-lieu-of-site-control framework,” they said.

The NOPR’s proposal to impose stricter study processing requirements on transmission providers, backed by penalties, is generally a reasonable complement to the application of stricter financial commitment and readiness requirements on interconnection customers, APPA and LPPC said. 

“The Commission, however, should allow for flexibility in transmission provider deadlines, particularly in Regional Transmission Organization and Independent System Operator regions, particularly where the transmission provider has been permitted to utilize a cluster study approach that differs from the pro forma LGIP requirements.”

FERC should not adopt a penalty framework under which RTOs and ISOs might be obligated to pass penalties through to RTO/ISO members that bear no responsibility for interconnection study delays, they said. “The Commission should adopt a reporting requirement for RTOs and ISOs as a substitute for imposing interconnection study delay penalties on these not-for-profit entities.”

The groups also said that:

APPA and LPPC also specifically responded to the NOPR’s statement that public power utilities would be obligated “to adopt the requirements of this Proposed Rule as a condition of maintaining the status of their safe harbor tariff or otherwise satisfying the reciprocity requirement of Order No. 888.”

While acknowledging that safe harbor tariff requirements will be modified pursuant to any final rule in this case, APPA and LPPC expressed concern that the Commission’s statement failed to acknowledge that the reciprocity requirements of Order No. 888 can also be satisfied through bilateral arrangements or by waiver.  APPA and LPPC asked FERC to make clear in any final rule that public power utilities would still be able to satisfy the reciprocity requirements under Order No. 888 through bilateral arrangements and/or waiver.

JEA, Other Florida Utilities Sign Agreements to Join the Southeast Energy Exchange Market

October 16, 2022

by Paul Ciampoli
APPA News Director
October 16, 2022

Florida public power utility JEA and three other Florida utilities have signed agreements to join as members of the Southeast Energy Exchange Market (SEEM), effective Jan. 1, 2023.

Duke Energy Florida, JEA, Seminole Electric Cooperative and TECO Energy recently expressed their intent to join the expanded platform and expect active energy trading in mid-2023.

The new SEEM platform will facilitate sub-hourly, bilateral trading, allowing participants to buy and sell power close to the time the energy is consumed, utilizing available unreserved transmission. Participation in SEEM is open to other entities that meet the appropriate requirements.

Other founding members of SEEM include Associated Electric Cooperative, Dalton Utilities, Dominion Energy South Carolina, Duke Energy Carolinas, Duke Energy Progress, Georgia System Operations Corporation, Georgia Transmission Corporation, LG&E and KU Energy, MEAG, N.C. Municipal Power Agency No. 1, NCEMC, Oglethorpe Power Corp., PowerSouth, Santee Cooper, Southern Company and TVA.

With the addition of these Florida companies, the SEEM footprint would include 23 entities in parts of 12 states with more than 180,000 MW (summer capacity; winter capacity is nearly 200,000 MWs) across two time zones.

APPA Survey of Members Shows Distribution Transformer Production Not Meeting Demand

October 12, 2022

by Paul Ciampoli
APPA News Director
October 12, 2022

An American Public Power Association (APPA) survey of its members shows that production of distribution transformers is not meeting current demand, “as evident in the significantly growing lead times, lack of stock in yards and the high number of project deferrals,” APPA said.

In August 2022, APPA surveyed its members about distribution transformer supply and demand. The survey “highlights the expanded nature of this problem subsequent to the results of two previous surveys we have done on this matter, beginning in November 2021,” APPA said.

The data from the survey informed the Department of Energy and the Electric Subsector Coordinating Council (ESCC) of the severity of the supply chain distribution transformer shortage across the entire electric sector.

Ninety-five public power utilities serving a total of 6,719,596 meters responded to the survey.

Along with its finding that production is not meeting current demand, another key takeaway from the survey is that demand has grown consistently in the past and will continue to rise in the future.

 Because demand is out pacing supply, many public power utilities are at a high risk of stocking out on transformers in 2022 or following one storm.

Between 2019 and 2020, demand across all voltage classes for distribution transformers rose 3.6% for public power survey respondents. During this period, the lead time to procure distribution transformers averaged two to three months. Economic forecasts anticipate that the calculated annual growth rate for distribution transformers in North America will continue to increase and  be 9.1% for 2022-2030.

Between 2020 and 2022, the number of distribution transformers purchased remained largely steady. However, beginning in 2021 and continuing into 2022, the number of distribution transformers available for purchase no longer meets the demand. Evidence for this imbalance can be seen in the significantly increasing lead times and the deferral of projects, APPA stated.

Meanwhile, between 2020 and 2022, average lead times to procure distribution transformers for all voltage classes rose 429% for public power respondents — from about two to three months pre-2021 to about 12 months in 2022. Some utilities reported being quoted lead times of more than three years.

APPA reported that many utilities are deferring or canceling infrastructure projects because they are unable to procure the additional distribution transformers required for these projects. Among public power utilities, one in five projects were deferred or canceled.

Most responding utilities reported low or near zero emergency stock, which is often used to recover post-disaster or to do infrastructure maintenance. Some public power utilities reported being within weeks of hitting the bottom of their distribution transformer stocks. In the event of a catastrophic hurricane or other natural disaster, the industry risks stocking out much sooner, APPA pointed out.

APPA continues to work through the ESCC and other forums to discuss the problems and identify solutions that the federal government can act upon to alleviate the supply chain shortages, specifically with regards to distribution transformers.

APPA has taken a number of actions to address ongoing supply chain challenges. APPA recently rolled out an additional feature to its eReliability Tracker that is available to all public power utilities and allows for voluntary equipment sharing by matching systems with the same distribution voltages. APPA also recently finalized a new supply chain issue brief. APPA members can download the issue brief here.

In May, APPA sent a letter to Secretary Granholm at the Department of Energy asking that they consider a temporary waiver of efficiency standards in distribution transformers that may lead to an increase in supply.  That request was declined in August.  In a speech in June at APPA’s National Conference in Nashville, Tenn., APPA President and CEO Joy Ditto urged member utilities to share their supply chain challenges with APPA so that the trade group can relay details on these challenges to federal partners and discuss how critical burdens on the sector can be alleviated.

In May, APPA convened a supply chain summit that included participation from public power utility officials who discussed their supply chain challenges and mitigation strategies.

Hannibal Board of Public Works Seeks Solar Plus Battery Storage Proposals

October 7, 2022

by Paul Ciampoli
APPA News Director
October 7, 2022

Missouri public power utility Hannibal Board of Public Works (HBPW) is seeking proposals for a 7 megawatt (MW) solar project paired with a 3 MW, 12 MWh battery energy storage system located behind their wholesale meter with the primary use case of meeting Midcontinent Independent System Operator capacity requirements. 

HBPW will accept proposals from any electric utility, independent power producer, solar/storage developer, or electric power marketer that can deliver the project described in the request for proposals, which was issued on Oct. 4.

HBPW seeks proposals from respondents to enter into a mutually agreeable 20-to-25-year third party power purchase agreements.

HBPW will allow flexibility in the term length on the storage part of the project, requesting a term length of at least 15 years. HBPW is not seeking turnkey EPC ownership and is only requesting PPA options.

Bids are due December 15, 2022, and the contacts for the RFP at GDS Associations are: Kyle Haemig, kyle.haemig@gdsassociates.com and Justin Hey, justin.hey@gdsassociates.com.

SPP RTO Expansion Into Western Interconnection Details Projected Savings

October 3, 2022

by Paul Ciampoli
APPA News Director
October 3, 2022

Expanding the Southwest Power Pool (SPP) Regional Transmission Organization into the Western Interconnection could produce a net total of $55 million to $73 million per year in savings depending on hydrologic conditions, according to a new study commissioned by prospective SPP RTO participants in the Western Interconnection.

The Brattle study evaluated adjusted production cost savings and reported potential market benefits for expanded SPP RTO participation. The study estimates adjusted production cost savings of $71 million per year under average hydrology conditions. The savings increase to $89 million per year under severe drought conditions.

There are also potential operational and reliability benefits provided by RTO participation that are not quantified in the adjusted production cost study.

 “This study, including the specific impacts across WAPA customers, will help inform our next steps and potential future as we adapt to the changing climate and generation mix. We greatly appreciate the effort dedicated to this study from Brattle and other study participants,” said Western Area Power Administration Administrator and CEO Tracey LeBeau. “As always, we are committed to collaborating with our customers and stakeholders as we assess this opportunity. Any decision to move forward with final negotiations for SPP RTO membership will be consistent with our statutory requirements and involve the appropriate public processes.”

Prospective SPP RTO participants included in the study are Basin Electric Power Cooperative, Colorado Springs Utilities, Deseret Power Electric Cooperative, Tri-State Generation and Transmission Association and the Municipal Energy Agency of Nebraska along with the WAPA Upper Great Plains region, Rocky Mountain region and Colorado River Storage Project.

Each of these entities is currently participating in the SPP Western Energy Imbalance Service and receives Reliability Coordinator services from SPP. Tri-State, WAPA UGP region, Basin Electric and MEAN are already members of SPP in the Eastern Interconnection.

Although not included in the study, Platte River Power Authority announced in August its intention to join the SPP RTO.

As potential benefits, the SPP RTO expansion could increase the portfolio of tools available to support reliability in the Western Interconnection. This includes consolidated balancing authority operations, coordinated resource adequacy and a fully integrated wholesale market that would optimize real-time, day-ahead and ancillary services.

Additionally, the established SPP RTO transmission processes could improve transmission planning and development needed to support growing electricity demand and addition of more generation resources, including renewables.

“We’re pleased that the study reinforces the promise of an organized power market and our partnership with the Southwest Power Pool,” said Colorado Springs Utilities CEO Aram Benyamin. “For our customers, the benefits are clear – millions of dollars in annual savings by having access to regional energy producers and the reliable and cost-effective integration of additional carbon-free energy resources into our system.”

This study builds on previous evaluations of the benefits of SPP RTO expansion into the Western Interconnection, including a 2020 study commissioned by SPP. The new 2022 study uses updated modeling assumptions about the participant footprint, generation portfolios, natural gas prices and projected hydrology conditions.

The study is not a decision by participants to join the SPP RTO. Each of the participating organizations will continue their internal review and approval processes to determine if they will proceed to the next steps for SPP RTO membership. The 2022 Brattle study results, along with other factors, will help inform those processes.

Nominations for APPA’s Policy Makers Council Now Being Accepted

October 1, 2022

by Paul Ciampoli
APPA News Director
October 1, 2022

Nominations for the American Public Power Association’s Policy Makers Council (PMC) are being accepted through November 18.

Leaders of public power utilities can nominate members, who are either elected or appointed officials, on the governing authorities of public power distribution utilities, including mayors, city council members, and elected or appointed board members.

The PMC meets twice a year in Washington, D.C. during the APPA Legislative Rally in February and at a separate PMC-only meeting in July to participate in meetings with elected representatives and congressional staff to advance APPA’s legislative and regulatory agendas. 

To nominate a member of a utility’s governing body to the PMC or learn more about the process, contact Steve Medved, APPA’s Government Relations Manager, at: smedved@publicpower.org.