Skip Navigation

APPA’s Ursula Schryver Highlights Local Control As Key Benefit Of Public Power

May 15, 2022

by Paul Ciampoli
APPA News Director
May 15, 2022

Local control over decision making in areas such as renewable energy or reliability offers a key advantage for public power communities, Ursula Schryver, Vice-President of Strategic Member Engagement & Education at the American Public Power Association (APPA), said during a recent event related to public power.

Schryver was joined in the discussion by Maine State Rep. Seth Berry and Darren Springer, General Manager for Vermont’s Burlington Electric Department.

The three participated in a virtual event on public power around the country and lessons learned for Ann Arbor, Mich., whose City Council earlier this year unanimously adopted a resolution initiating a feasibility study for a public power utility.

Schryver said that local decision making “is the overarching tenet of public power.” She noted that communities with public power have local control over “the decisions that they make, how the utility is run, the utility’s priorities, and so that allows the city and the community to set its own priorities,” whether that’s keeping rates low, investing in system upgrades or adding renewable energy to their portfolio.

“More and more, we’re seeing communities that are pursuing the public power option” because of an interest in renewable energy, she said.

At other times, communities have pursued the public power option for other reasons, such as reliability or rates, Schryver noted.

While renewable energy may be the driving force now for communities to pursue public power, “twenty years down the road it may be some other issue that your community is interested in but having the local utility with local governance allows you to” make changes and address the issues that are important to the community, she said.

Schryver also said that public power utilities are in a solid position to address the needs and challenges of the 21st Century.

She said that there a number of public power utilities across the U.S. that are “great examples of utilities that are doing innovative things.”

Public power utilities address the issues that are of importance to their communities and “they have the ability to adapt and change,” she said.

Berry, who has been a key advocate for bringing public power to Maine, said that public power is “a superior business model” if a community wants to achieve 100 percent renewable energy supplies.

He pointed out that two California public power utilities – SMUD and the Los Angeles Department of Water and Power – are “leading in the race to one hundred percent renewables.”

In Maine, a group called Our Power is working to create a statewide, consumer-owned utility.

Meanwhile, Springer provided an overview of Burlington Electric Department and detailed the utility’s key initiatives that it is pursuing.

Among other things, Springer discussed the City of Burlington’s net zero energy by 2030 goal and provided details on a $20 million net zero energy revenue bond. The bond will allow Burlington Electric Department to continue and expand green stimulus incentives that have helped Burlington residents switch to electric vehicles (EVs) and cold-climate heat pumps.

Online Tool Allows Users To Estimate Economic Impact Of EV Charging Stations

May 14, 2022

by Paul Ciampoli
APPA News Director
May 14, 2022

Scientists at the U.S. Department of Energy’s (DOE) Argonne National Laboratory recently launched an online tool that allows users to quickly estimate the economic impacts associated with the development, construction, and operation of electric vehicle charging stations, also called electric vehicle supply equipment (EVSE).

The impacts range from job creation to ripple-effect economic activity, such as local spending.

The tool, referred to as JOBS EVSE 1.0, permits users to estimate economic impacts for individual states, regions, or the United States as a whole.

The tool contains default input values, but users can override default data with their own data for more project-specific results.

Although it focuses on charging stations and the infrastructure immediately upstream from them, it also considers the entire energy supply chain in calculating impacts.

Impacts also include recurring expenditures for electricity, network and data fees, revenues, operating and maintenance and administration, as well as potential revenues and access fees.

JOBS EVSE 1.0 was developed with funding from DOE’s Vehicle Technologies Office.

To view a webinar about the tool, go to https://​cleanci​ties​.ener​gy​.gov/​w​e​b​i​n​a​r​s​/​#​28469.

Public Power Utilities Make Progress In Connecting Navajo Nation Families To Grid

May 14, 2022

by Paul Ciampoli
APPA News Director
May 14, 2022

Public power utility crews are making significant progress in their efforts to extend electricity to Navajo homes through Light Up Navajo III (LUN III), a joint effort between the American Public Power Association (APPA) and the Navajo Tribal Utility Authority (NTUA).

The LUN III initiative began on April 3, 2022 and will last for 11 weeks.

NTUA will be welcoming workers from public power utilities and organizations from 11 states, including Arkansas, Arizona, Delaware, California, Connecticut, North Carolina, New Mexico, Ohio, Washington, Texas, and Utah.

One of the public power utilities participating in LUN III is Arizona public power utility Salt River Project (SRP).

SRP on May 11 reported that its linemen have successfully connected more than 50 Navajo families to electric service despite rough terrain, high winds, snow and mud in unfamiliar land. In all, 56 families on Arizona’s Navajo Nation now have electricity powering their homes for the very first time, SRP reported.

The SRP linemen took four weeks of up to 16-hour workdays during their phase of the project.

“The first home we connected was the most touching for me. It was a mom who was living in a trailer with her children, and they had no power or running water. They had gotten sick with COVID-19 and had to quarantine at home. They were excited (to get power) and telling us how tough it had been the last few months,” said Art Peralta, SRP construction crew foreman, who resides in Mesa. “It’s very rewarding. I’ve never done anything like this, and it means a lot. It’s life changing and brings more meaning to our job.”

The SRP line crews returned home on May 8 after working on the Navajo Nation in northeastern Arizona since April 2.

During SRP’s participation in the month-long humanitarian effort, line crews constructed about 12 miles of distribution lines. SRP crews also set 193 poles, strung 13 miles of overhead wire and worked 4,500 hours of donated man-hours. It marks the second time SRP line workers, based out of the Tempe Service Center, volunteered to participate in Light Up Navajo.

A total of 17 SRP employees participated in the project and SRP donated employee time, line trucks, digging equipment and a mechanic service truck.

“Light Up Navajo III is an initiative to bring power to all the residents on Navajo Nation. There are about 14,000 homes on the Navajo Nation that currently do not have electric service. The vision back in 2019 was to solicit neighboring utility support primarily from public power utilities like SRP to help build the infrastructure to serve the community,” said Wayne Wisdom, the senior director of Distribution Grid Services at SRP. “For generations, these families have been living on their own with the use of generators, kerosene lamps, or whatever they have.”

“There was a mother, daughter and her two kids in Tuba City and they were really excited to have power. The kids were excited to be able to entertain themselves without having to turn on a generator and to watch TV. It was nice to get to see that and use our skills to help out,” said Austin D’addabo, SRP trades helper.

“It’s given me a different outlook on the work we do,” added Peralta. “Sometimes we take it for granted because we do it every single day. But (on the Navajo Nation) it’s not normal for them. They get really excited and are very grateful to get power.”

Along with SRP, the following public power utilities participating in LUN III are:

Two investor-owned utilities are also participating in LUN III: Arizona Public Service and New Mexico’s PNM Resources.

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.

TBA
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.