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DOE Study Sees 1,400 GW Of Economic Wind Power Potential

May 14, 2022

by Peter Maloney
APPA News
May 14, 2022

There are nearly 1,400 gigawatts (GW) of economic wind power capacity in the United States, an amount equal to more than half of the nation’s current annual electricity consumption, according to a Department of Energy’s (DOE) study.

The results of the Distributed Wind Energy Futures Study, which was conducted by the National Renewable Energy Laboratory (NREL), were detailed in two snapshots in time, 2022 and 2035, and done within the context of the Biden administration’s established targets of 100 percent carbon dioxide free electricity supply by 2035 and net-zero greenhouse gas emissions economywide by 2050.

In the 2022 scenario, the economic potential for behind-the-meter wind installations is 919 GW, compared with 474 GW for front-of-the-meter installations.

However, “the economics of distributed wind are highly sensitive to policies, especially those that impact project-level costs,” the study said. As an example, the authors said,

“If current tax credits and net-metering policies expire as scheduled, economic potential is estimated to drop between 2022 and 2035. However, if current tax credits and policies are extended and strategically expanded, economic potential increases by more than 80% for behind-the-meter applications and by a factor of nearly nine for front-of-the-meter application.”

With future policy support and “more relaxed siting conditions,” the economic potential of front-of-the-meter installations could increase to more than 4,000 GW and 1,700 GW for behind-the-meter installations in an “optimistic 2035 scenario,” NREL said.

There are currently about 1.1 GW of distributed wind capacity in the United States.

The study identified the Midwest and the Heartland regions as having the largest potential for behind-the-meter wind power because of a combination of high wind speeds and sufficiently high retail electricity rates. Six states in those regions – Texas, Minnesota, Montana, Colorado, Oklahoma, and Indiana – have a combined wind power potential of 500 GW, the study said.

The Midwest and Heartland regions also have strong potential for front-of-the-meter wind power, estimated at over 300 GW in the top six states: Oklahoma, Nebraska, Illinois, Kansas, Iowa, and South Dakota.

Agricultural lands make up 70 percent of the total 2022 economic potential for behind-the-meter wind power and 97 percent of the total 2022 economic potential for front-of-the-meter wind power potential.

In addition, Kansas, Colorado, Texas, South Dakota, New Mexico, and Kentucky each have more than 900 megawatts (MW) of behind-the-meter economic wind power potential in 2022 on commercial and industrial lands, the study said.

Behind-the-meter economic wind power potential in 2022 on residential lands is greatest in New York, Minnesota, Kentucky, Texas, Oklahoma, and South Dakota, the study found.

In general, California and states in the Northeast have less profitable distributed wind power potential, except in certain locations where there are significant wind resources and higher retail electricity rates, NREL said.

Fitch Affirms AA- Rating On Bonds Issued To Finance First Phase Of MMWEC-Operated Wind Farm

May 14, 2022

by Paul Ciampoli
APPA News Director
May 14, 2022

Fitch Ratings has affirmed the AA- rating on bonds issued by the Berkshire Wind Power Cooperative Corporation (BWPCC) to finance the 15-megawatt Phase 1 portion of the Berkshire Wind Power Project. 

The 19.6-megawatt project is located atop Brodie Mountain in the towns of Hancock and Lanesborough, Mass.

The AA- rating applies to $34.4 million in wind project revenue Green Bonds, series 2.  Green bonds are earmarked to be used exclusively for climate and environmental projects. 

Fitch has also issued a rating outlook of stable.  Fitch originally upgraded the rating and rating outlook to their current levels in 2019. 

The AA- rating largely reflects the credit quality of the utilities participating in Phase 1 of the project.  Phase 1 participating Massachusetts municipal light plants (MLPs) include Ashburnham, Boylston, Groton, Holden, Hull, Ipswich, Marblehead, Paxton, Peabody, Shrewsbury, Sterling, Templeton, Wakefield and West Boylston. 

Payments from the project participants are made pursuant to identical take-or-pay power purchase agreements with the Massachusetts Municipal Wholesale Electric Company (MMWEC), the state’s designated joint action agency for municipal utilities. 

MMWEC is a member of the BWPCC and operates the wind farm. 

In its rating report, Fitch identified several key drivers, including a strong contractual framework.  The assessment also factors in the terms of the contract that provide for unconditional payments from the 14 project participants. 

The power purchase agreements require MMWEC to sell, and each participant to purchase, the project capacity and energy based on their allocated share of the project. 

Payments are imposed on a take-or-pay basis, whether or not the wind project is operating.  Each of the participants is required to maintain rates sufficient to repay their obligations under the respective agreements. 

Fitch cited very strong rate flexibility in its rating report, as rates charged by each of the project participants are determined by each utility’s governing board.  Autonomous ratemaking authority and retail rates that are highly affordable and well below the state average all led to this positive rating. 

MMWEC is a non-profit, public corporation and political subdivision of the Commonwealth of Massachusetts, created by an Act of the General Assembly in 1975 and authorized to issue debt to finance a wide range of energy facilities. 

MMWEC provides a variety of power supply, financial, risk management and other services to the state’s consumer-owned municipal utilities.

Southwest Power Pool Anticipates Sufficient Energy Resources For This Summer

May 14, 2022

by Paul Ciampoli
APPA News Director
May 14, 2022

Southwest Power Pool (SPP) expects to have enough generating capacity to meet the regional demand for electricity through the summer season, the grid operator said on May 12.

For the season lasting June-September 2022, SPP anticipates that the demand for electricity will peak at 51.1 gigawatts (GW) and also studied scenarios with higher-than-expected demand.

Its fleet of member utilities’ conventional and renewable generating resources will be prepared to serve at least 55.5 GW, taking both planned and a margin of unplanned outages into consideration. SPP’s all-time peak demand for electricity was 51 GW, which occurred July 28, 2021.

SPP’s studies consider factors including:

SPP assesses electricity supply and demand from a high-level, regional perspective and bases its studies on data provided by generator and transmission owners and member utilities who directly serve residential, commercial and industrial customers.

While SPP anticipates sufficient resources to meet the demand across its 14-state balancing authority area, the summer seasonal assessment did identify potential local issues that it will address with the entities responsible for serving load in those areas. SPP will likewise address potential fuel-supply constraints with generator owners and operators on a case-by-case basis.

On May 12, 2022, SPP declared a Resource Advisory effective May 13-14 in response to higher-than-normal temperatures and other factors.

The advisory required no action on behalf of the general public but was meant to raise awareness among generation and transmission operators regarding circumstances that could require action on their part to prevent impacts to regional reliability.

New England Experienced Historically Low Demand For Grid Electricity In Early May

May 14, 2022

by Paul Ciampoli
APPA News Director
May 14, 2022

Mild temperatures, sunny skies, and typically low Sunday demand for electricity combined on May 1, 2022 to result in the lowest demand for grid electricity on record in New England, ISO New England reported on May 5.

Consumer demand for electricity from the bulk power grid dropped to 7,580 megawatts (MW) during the afternoon hours, the lowest mark observed by system operators since ISO New England began operating the system in 1997.

Sundays typically see lower electricity demand than other days of the week, and afternoon temperatures on May 1 were in the 50s and 60s across New England, lowering overall demand for electricity in the region. Production from behind-the-meter solar resources was estimated at more than 4,000 MW of electricity during this period, further tempering demand on the bulk power grid, ISO New England said.

While May 1 represents a record, it was the continuation of a trend seen across New England as rooftop solar installations have become more popular, it said.

The region has already seen nearly as many so-called “duck curve” days, during which demand from the bulk power system is at its lowest in the afternoon hours and not overnight, in 2022 as in all previous years combined.

These trends are expected to accelerate over the coming years as behind-the-meter solar continues to grow in New England, according to the ISO’s recently-released 10-year solar forecast.

Public Power Credit Unaffected by Glen Canyon Dam Drought Measures: Fitch

May 14, 2022

by Paul Ciampoli
APPA News Director
May 14, 2022

Against the backdrop of recent urgent drought response actions at Lake Powell, which are intended to preserve water levels and power generation at the Glen Canyon Dam, the credit effect of generation shortages is limited because the dam constitutes only one of multiple generation sources for public power utilities rated by Fitch Ratings, the rating agency said on May.

Fitch noted that the U.S. Bureau of Reclamation (BOR) recently announced urgent drought response actions at Lake Powell, which are designed to preserve water levels and power generation at the Glen Canyon Dam, the second-largest hydroelectric power source in the Southwest.

“The announced actions will preserve minimum levels of power supply from this low-cost, carbon-free hydroelectric resource for regional public power utilities in the short term. Still, consensus is needed among the entities that rely on Lake Powell for water and power to address declining hydrology in the Colorado River Basin if power generation is to be sustained longer term,” said Fitch.

Reduced hydroelectric output, as a result of the Colorado River Basin drought, is driving replacement power supply of purchasing utilities higher, but the increases are manageable, the rating agency said.

The BOR increased project energy and capacity rates charged to purchasing utilities by 8% and reduced available allocations in December 2021, given the region’s increasingly severe drought conditions.

The BOR indicated it would no longer purchase power in order to firm deliveries to purchasing utilities, given increasing market energy prices in the western U.S., Fitch said.

Utilities rated by Fitch “are absorbing the incremental cost caused by reduced supply in 2022 by replacing the lower generation with additional purchased power costs, increased output from other owned generation, or reduced off-system (optional, non-customer) sales. To the extent the project’s power supply remains curtailed, the replacement costs in relation to overall power supply costs for Fitch-rated public power issuers are expected to be recovered through rate adjustments.”

The Colorado River Storage Project (CRSP), which includes the 1,320-megawattt Glen Canyon Dam power plant, provides cost-based energy supply at typically below market prices to 130 public entity customers: 53 native American tribes, 60 municipalities, cooperatives and irrigation districts, and 17 other entit

Four Fitch-rated utilities receive between 5% and 18% of their total power supply from the project: Colorado Springs, Colorado; Platte River Power Authority, Colorado; Tri-State Generation and Transmission Association, Inc., Colorado; and the Utah Municipal Power Agency, Utah. Two additional rated systems, Fort Collins, Colorado and Provo, Utah, purchase power from these utilities.

“The Glen Canyon Dam constitutes only one of multiple generation sources for the Fitch-rated utilities, limiting the credit effect of generation shortages, even in the event of full cessation of power from the facility,” Fitch said.

But the rating agency said that the reduction of low-cost power supply from Glen Canyon “is just one example of the sector’s broader operating cost pressures. “Additionally, lower generation from Glen Canyon reduces carbon-free electricity as the sector is pursuing cleaner, non-emitting electric sources.”

Glen Canyon Dam, Lake Powell, and the Glen Canyon Dam power plant together form the largest project of the CRSP and are collectively owned and managed by the BOR. The project controls water releases from the Upper Colorado River Basin to the Lower Basin and generates hydroelectric power, accounting for approximately 75% of CRSP’s generating capacity.

Fitch noted that the entire Colorado River Basin is experiencing progressively worse drought conditions since 2000.

The BOR in early May announced drought response actions that it said would help prop up Lake Powell by nearly 1 million acre-feet of water over the next 12 months (May 2022 through April 2023).

On May 3, Lake Powell’s water surface elevation was at 3,522 feet, its lowest level since originally being filled in the 1960s.

A critical elevation at Lake Powell is 3,490 feet, the lowest point at which Glen Canyon Dam can generate hydropower. “This elevation introduces new uncertainties for reservoir operations and water deliveries because the facility has never operated under such conditions for an extended period. These two actions equate to approximately 16 feet of elevation increase,” BOR said.

BOR invoked its authority to change annual operations at Glen Canyon Dam for the first time. The measure protects hydropower generation and the water supply for the city of Page, Arizona, and the LeChee Chapter of the Navajo Nation, it said.

OPPD Employees Organize Collection To Assist Ukrainian Refugees

May 12, 2022

by Paul Ciampoli
APPA News Director
May 12, 2022

Omaha Public Power District’s (OPPD) employee resource group, OPPD Global Connections, recently organized a collection to assist local Ukrainian refugees in need.

OPPD Global Connections is committed to promoting, supporting and advancing a workforce that embraces inclusive diversity through respectful interactions.

The group works to build a greater OPPD workforce by welcoming all immigrants, refugees, and interested employees to connect with and educate one another through diverse skills, expertise and cultural values resulting in opportunities for better career pathways and professional growth.

Collection boxes were setup at seven different OPPD locations and OPPD employees were encouraged to purchase LED light bulbs since they are more energy-efficient and longer lasting, but any light bulbs were acceptable.

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Oleg Lys, OPPD Global Connections president, and Lili Solsky, president-elect, pose with donated bulbs. Lys is originally from Ukraine.

A total of 326 light bulbs were collected and on May 10, the light bulbs were dropped off to Lutheran Family Services to be given to local Ukrainian refugees.

Public Power Groups Weigh In On Bond Private Use Rules

May 11, 2022

by Paul Ciampoli
APPA News Director
May 11, 2022

The American Public Power Association (APPA) and the Large Public Power Council (LPPC) recently sent a letter to Tom West, Deputy Assistant Secretary for Tax Policy at the U.S. Treasury Department, related to bond private use rules.

The May 3 letter follows a meeting in April with West, his staff, and personnel from the Internal Revenue Service to discuss the issue. The letter was signed by LPPC President John Di Stasio and APPA President and CEO Joy Ditto.

It has been over 30 years since the enactment of private use rules for public power in the Tax Reform Act of 1986 and nearly 20 years since the related regulations in Section 141 for output facilities were updated, the letter noted.

“The changes to the regulations that were made in 2002 were, in part, made in response to significant changes that had occurred in the electric industry. Given the changes that have occurred in the electric industry since 2002, the private use rules need to be modified again,” wrote Ditto and Di Stasio.

APPA and LPPC are focused on the two most significant issues affecting public power: the impact of output contracts with large retail customers and the issues created by the section 141(d) “Rostenkowski Rule” on the ability of the members of the groups to use tax-exempt bonds to acquire existing electric resources needed to serve their customers.    

Contracts With Retail Customers

A growing trend in the industry is that large retail electric customers — both existing customers and new customers — are seeking to negotiate customized contracts for electric service with public power and other utilities. Private use rules limit the ability of public power utilities to enter into customized contracts and put them at the risk of losing these important customers.

“These customers can be extremely important to their communities and the inability provide them with satisfactory electric service arrangements could be devastating for both the utility and the local community. At the same time, if these customers are not obligated to remain as customers for a significant enough period, the utility and its other customers are at risk that they will bear the cost of the improvements required to serve these customers if they go out of business or relocate,” the letter said.

Under current regulations, the only approach that can be used by public power utilities with large, retail customers is to enter into contracts with terms of not more than three years, which is not sufficient for the public power utility to ensure that its other customers will end up bearing the cost of any necessary improvements and often does not provide a long enough contract term for the customer.

“Oddly, the regulations contain a more generous rule for contracts with wholesale customers that permits contracts, subject to certain conditions, with terms of up to five years,” Ditto and Di Stasio said.

APPA and LPPC proposed the adoption of an exception to the private use rules for contracts with retail customers that tracks the requirements for short-term contracts in section 1.141-7(f)(3) and that would apply if:      

“We believe that an expansion of the short-term use rule as described above as not giving rise to private use is consistent with both the underlying regulatory framework of the output regulations (i.e., such a contract does not shift the ‘benefits and burdens of ownership’ to the taker), and Treasury’s economic policy of accommodating certain industry changes to foster competition,” Ditto and Di Stasio said.

Acquiring Existing Output Facilities

The letter notes that Section 141(d) (the “Rostenkowski Rule”) was enacted in 1987 and regulatory guidance on this provision has yet to be provided.

Although designed to prevent tax-exempt bonds from being used to “municipalize” privately owned facilities, the rule contains an exception designed to permit the acquisition of existing facilities by a public power utility to serve its existing customers — the “Existing Service Area Exception.”

“This exception is very difficult and burdensome for utilities to apply: it requires that the utility use virtually all of the electricity from the acquired facility to serve customers in its historic service area throughout the term of the bond issue and monitor compliance with this rule,” wrote Ditto and Di Stasio.

The Existing Service Area Exception was meant to permit public power utilities to use tax-exempt bonds to acquire electric facilities that were to be used to serve the existing customers of the acquiring utility.

The requirement that 95 percent of the electricity from the acquired facility be used to serve those existing customers subject only to the ability to make non-service area sales with terms of up to 30 days has significantly limited the use of this exception and prevented public power utilities from using tax-exempt bonds to acquire facilities despite the underlying rationale for the Existing Service Area Exception.

The Existing Service Area Exception presents practical and economic issues that make it difficult and costly to comply with, the letter said.

The public power groups said that many public power utilities that have short-term excess energy to sell make those sales on a “system” basis, meaning that the electricity being sold does not come from any particular generating unit. 

As a result, even with on-going monitoring, it is difficult to prevent the electricity from a facility that is subject to 141(d) from being sold outside the utility’s service area without restricting the entire system. 

A second, related difficulty is that in making system sales, all of a utility’s electricity derived from other bond-financed generating facilities can be sold for up to three years, but the facility that is subject to section 141(d) prevents the utility from making system sales of more than 30 days because of the need to comply with section 141(d).  

The existing three-year short-term sale exception that applies for other output sales for purposes of section 141 was included in the regulations so that private use rules did not impact the typical, day-to-day functioning of public power utilities. 

This private use exception is consistent with the “benefits and burdens” framework of the output regulations.  

As an example of the problem with a 30-day exception under Section 141(d), short-term sales of electricity are often made on a seasonal basis to reflect situations, such as a utility that has its peak load during warm months may have excess electricity in the winter.

Ditto and Di Stasio suggested two possible approaches that can be used to address these issues. The first is to simply provide that the existing short-term sale exception to private use of output facilities applies to section 141(d).

Alternatively, a safe harbor could be adopted that permits public power utilities to base compliance on either reasonable expectations or based on historical use of electric generation to satisfy customers in their historic service areas, the groups said.

This approach would be modeled after section 148(b)(4)(B), related to bonds issued to finance natural gas prepayments.

“The rule based on historical use has proven to be very workable. Under this approach, a new safe harbor would permit public power utilities to use their historic sales of electricity in their service areas to determine compliance with the existing service area exception of the Rostenkowski Rule,” the letter said.

APPA Regional Exercise On Mutual Aid Yields High-Level Lessons Learned

May 11, 2022

by Paul Ciampoli
APPA News Director
May 11, 2022

A recent regional mutual aid held by the American Public Power Association (APPA) that was hosted by Ohio-based American Municipal Power (AMP) resulted in a series of high-level lessons learned.

The exercise took place on April 27 in Columbus, Ohio, and involved over 50 in-person public utility participants from four states and over 27 communities, including local county emergency managers and DOE regional emergency support function (ESF) #12.  

The ESF #12 Annex is a construct established within the National Response Framework. ESF #12 helps manage the resources required to support energy infrastructure systems, and public and private services and resources.

The exercise was kicked off by introductory remarks from Brandi Martin, Program Manager at DOE’s Office of Cybersecurity, Energy Security, & Emergency Response.

The full day exercise featured in-depth discussion of emergency response issues including mutual aid and coordination with state, local and federal government.  The scenario for the exercise was a major tornado event causing widespread grid disruptions. This exercise began after the tornado made impact and did not deal with preparatory actions.  

Notable discussions during exercise or captured in a post-exercise review included the following:

In terms of high-level lessons learned, the exercise was very well received. Participants commented on the importance of addressing emergencies during “blue sky” days.  

Participants also commented that they appreciated the chance to participate and that DOE and APPA efforts made this possible.

Another lesson learned is the Importance of knowing peers at adjacent utilities and communities and sharing information with likely mutual aid participants.

The importance of having connections with local government decision-makers before the emergency response was another lesson learned.

Another lesson learned is the importance of having local experts as part of the facilitation teams. Each small group breakout session was led by a local power utility expert and an emergency management/exercise expert. The small groups and the local utility expertise helped draw participants into the discussions.

AMP is the nonprofit wholesale power supplier and services provider for 134 members in Ohio, Pennsylvania, Michigan, Kentucky, Virginia, West Virginia, Indiana, Maryland and Delaware.

The exercise was held under DOE CESER Cooperative Agreement DE-CR0000012.

APPA Urges FERC To Ensure Reliable And Affordable Supply Of Natural Gas

May 11, 2022

by Paul Ciampoli
APPA News Director
May 11, 2022

The Federal Energy Regulatory Commission (FERC) should clarify or revise aspects of draft gas policy statements issued in March by FERC that could interfere with FERC’s pursuit of policies that help ensure a reliable and affordable supply of natural gas in order to support a reliable and resilient power grid and reasonable electric rates for consumers, the American Public Power Association (APPA) said.

FERC on March 24, 2022, voted to seek additional comments on two policy statements it issued in February that provide guidance regarding the certification of interstate natural gas pipelines and consideration of greenhouse gas emissions (GHG) in natural gas project reviews. 

“Public power utilities across the country continue to reduce their GHG emissions through a variety of means, such as fuel switching to lower-emitting resources, investments in renewable and other non-emitting resources, the integration of distributed energy resources, and a host of energy efficiency measures,” APPA said in comments submitted to FERC on April 25 (Docket Nos. PL18-1, PL21-3).

Public power utilities “also have been reducing GHG emissions by facilitating the electrification of the transportation sector in their communities, and by promoting the electrification of water and space heating, as well as appliances. As new technologies become commercially available and additional investments are made in clean energy technologies, public power utilities will further reduce their GHG emissions,” APPA said.

Meanwhile, natural gas-fired generation continues to play — and is expected to continue to play — an important role in the nation’s resource mix.  In its most recent Annual Energy Outlook, the Energy Information Administration projects that natural gas resources will remain relatively constant as approximately one-third of the generation mix at least through 2050. “These resources, moreover, are expected to be critical to the overall reliability of the bulk electric system as the resource mix transitions to more intermittent renewable energy, a point that has been emphasized by the North American Electric Reliability Corporation,” APPA noted.

Public Power Utilities Rely On Gas-Fired Generation

Many public power utilities rely on natural gas-fired generation, either owned or contracted through bilateral or organized wholesale markets, and these utilities continue to have a critical interest in access to reliable and affordable supplies of natural gas. 

“Even leaving aside the importance of natural gas to electric reliability, the price of natural gas often directly impacts the wholesale price of electricity, both within and outside the organized wholesale markets, and higher natural gas prices are likely to mean higher electricity bills for public power customers,” the trade group noted.

It said that a reliable and affordable supply of natural gas depends on adequate transportation infrastructure. APPA supports Commission policies that streamline the permitting process for needed interstate natural gas pipeline infrastructure, consistent with the Congress’ principal aim in enacting the Natural Gas Act to “encourage the orderly development of plentiful supplies of . . . natural gas at reasonable prices” and “protect consumers against exploitation at the hands of natural gas companies.”

“It is axiomatic that regulatory predictability and certainty help promote investment in necessary infrastructure; indeed, that is one of the stated purposes of the Commission’s revisitation of its gas pipeline certificate policies. APPA is concerned, therefore, by the degree of uncertainty and opposition that the Draft Gas Policy Statements have engendered among natural gas companies and other key stakeholders,” APPA said.

APPA agrees that it may be appropriate to reassess the Commission’s existing policies for evaluating the need for new pipeline infrastructure, particularly with respect to cases involving precedent agreements with pipeline affiliates, to ensure that costs are not being unfairly shifted to captive customers for unnecessary expansions.

But the Commission’s “proposed shift in focus from the economics of proposed pipelines to a more open-ended public interest balancing, however, could create significant uncertainty for the gas industry in trying to gauge the standards for pipeline approval. Such uncertainty could, in turn, constrain natural gas supply availability, potentially increasing electric prices and degrading grid reliability.”

APPA also said that uncertainty regarding how the Commission’s certificate policy will be applied may also perversely undermine decarbonization efforts by influencing electric utilities to retain older, less efficient generating units that might otherwise be displaced due to concerns about inadequate natural gas infrastructure, “notwithstanding the suggestion that the Commission will consider evidence that a proposed project ‘will displace more pollution-heavy generation sources’ in assessing project benefits.”

In this respect, a policy under which the Commission broadly examines the entirety of a proposal and balances all its benefits against all of its adverse impacts “is likely to leave a great deal of uncertainty in the minds of pipeline developers and their potential electric generation customers.”

APPA also urged the Commission to further consider and clarify the suggestion that the Commission will encourage applicants to mitigate indirect GHG emissions “given the substantial uncertainty that the proposed policy has created for natural gas pipeline companies, and the potential deleterious effects that such uncertainty could have on developing needed pipeline infrastructure.”

Voters in Barton Village, Vt., Decide Not To Sell Public Power Utility To Cooperative

May 11, 2022

by Paul Ciampoli
APPA News Director
May 11, 2022

Voters in Barton Village, Vt., elected not to sell Barton Electric to Vermont Electric Cooperative (VEC) in a ballot vote on May 10.

The decision allows Barton Village to continue owning and operating the public power utility that serves more than 2,000 customers in Barton, Brownington, Charleston, Irasburg, and Westmore. 

“I’d like to thank the Barton Village residents for the commitment they’ve shown to their municipal electric utility,” said Ken Nolan, Vermont Public Power Supply Authority (VPPSA) General Manager.

“Over the past several weeks, voters dedicated themselves to learning as much as possible about the electric utility industry so they could make an informed decision,” he said. “Please know that VPPSA stands ready to assist the community as you move forward and explore the options for serving residents and customers of Barton Electric.”  

Barton Village Trustees first announced their recommendation to sell the electric utility to VEC in March. Two informational meetings were held prior to the vote on May 10. 

For more than 40 years, VPPSA has assisted Barton Electric with services and solutions to ensure safe, reliable, and affordable electric service, VPPSA noted. 

VPPSA is a joint action agency. Its membership includes 12 consumer-owned municipals in Vermont and the Authority has broad statutory powers that enable it to provide such services as may be required in support of the activities of its member municipal utilities and to market its services to non-member utilities as it deems appropriate.