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AccuWeather experts predict 2021 Atlantic hurricane season will result in 16-20 named storms

April 7, 2021

by Paul Ciampoli
APPA News Director
April 7, 2021

AccuWeather’s team of tropical weather experts is predicting that the 2021 Atlantic hurricane season will result in 16-20 named storms, including seven to 10 hurricanes.

Of the storms projected to reach hurricane strength, three to five are predicted to become major hurricanes (Category 3 or higher storms that have maximum sustained winds of 111 mph or greater), according to a report written by Kevin Byrne, AccuWeather staff writer.

“AccuWeather’s forecast, when compared to that 30-year average, indicates that 2021 is expected to be an above-normal season for tropical activity in the Atlantic. A normal season is considered to have 14 storms, seven hurricanes and three major hurricanes,” wrote Byrne.

In 2020, 13 hurricanes formed, and six of those reached the major hurricane threshold, he noted.

After six years of Atlantic Tropical Cyclones forming prior to the official start of the season, the National Hurricane Center will now issue routine Tropical Weather Outlooks starting May 15, the center said in an early March tweet, adding there would be no changes to the official start of the Atlantic hurricane season in 2021.

“Public power utilities last year proved their mettle in successfully responding to an above-average hurricane season, all while adhering to safety protocols in the midst of the COVID-19 pandemic,” said Sam Rozenberg, Senior Director of Security and Resilience at the American Public Power Association.

“It’s never too early to start planning for tropical storms and hurricanes,” Rozenberg said, noting that APPA offers a wide range of resources to its members.

Those resources include an all-hazards guidebook and a Restoration Best Practices Guidebook.

APPA members can access disaster planning and response resources — including the public power Mutual Aid Network.

CDE Lightband digs into pros and cons of solar penetration with DEED grant

April 7, 2021

by Peter Maloney
APPA News
April 7, 2021

CDE LIghtband has used a Demonstration of Energy & Efficiency Developments (DEED) grant from the American Public Power Association to conduct and refine an analysis of the effects of solar power penetration on the Tennessee public power utility’s operations.

The DEED project had three goals: develop simple models for forecasting solar adoptions at the local level, compare the modeled solar output with actual solar power output, and evaluate the forecasts of those models on utility revenues and load curves.

The first step in the process was to simulate solar generation. The majority of that work was done by using the National Renewable Energy Laboratory’s System Advisor Model (SAM), modeling software that NREL makes available for free as an aid to decision-makers in the renewable energy industry.

NREL’s software enables planners to model how much power a particular solar array can produce while factoring in variables, such as latitude, seasonal weather, cloud cover, and even the effects of shade from trees at different times of day.

The second step asked the “big question, ‘how accurate is the model for Clarksville?’” Jared Combs, business intelligence analyst at CDE Lightband and author of the DEED report, said.

To do that the CDE Lightband team modeled the output of a 6-kilowatt (kW) photovoltaic solar array in Clarksville using the NREL software. The 6-kW size was chosen because it is the average size of a residential solar array, according to the Lawrence Berkeley National Laboratory.

CDE Lightband also built an actual 6-kW solar array and collected the data on its output and compared those results of the simulated and actual data. “The biggest finding,” Combs said, was that using average weather data as opposed to actual weather data yielded “potentially wildly inaccurate” results. “The simulated results do not align with the actual results unless you use specific year weather data,” he said.

The comparisons show “the importance of using hourly data, modeled on a specific year weather file when conducting a utility solar economic analysis,” Combs wrote in the DEED report. “This means that to analyze demand charge and time-of-use effects specific weather files must be used in the SAM model.”

One of the driving factors behind the analysis made possible by the DEED grant was to come up with a more accurate assessment of the effect of solar penetration and solar output on utility revenues.

Even if a customer is getting most of their power from solar panels on their roof, the utility is still bearing a fixed cost in personnel and equipment such as transformers. “To be fair to customers, we need to find out how much our customers with solar arrays affect our revenues,” Combs said.

Combs ran the modeled solar output data against CDE’s 2018 rates and demand intervals to determine revenue effects. A positive revenue effect is the result of solar output reducing utility wholesale demand charges by more than the amount lost on utility energy revenues less power costs.

Taking reductions in demand charges paid to wholesale power suppliers into account, total utility revenue effects from solar generation were 42 percent lower than when demand charges were not factored in, the analysis showed.

“One of the key findings,” Combs said, was that the revenue affect of a solar array is affected by its orientation. A Southwest facing array, because it catches solar energy in the evening as utility demand is rising, can pay for itself because it can reduce demand charges at a time when the utility is often selling power to customers at a loss, Combs said.

“Understanding of hourly economic interactions between utility wholesale costs and solar array generation might inform strategic planning and various models for distributed energy resource (DER) market participation,” Combs wrote in the DEED report, adding that utilities developing community solar programs “might consider the effect of solar arrays on their wholesale demand charges when calculating investment metrics and pricing models.”

Combs also recommended that “rate adjustments intended to ensure that solar array owners cover their portion of the fixed costs of electric distribution might more accurately consider the value of customer generated solar power.”

Combs cautioned, however, that conditions such as solar irradiance and the relationships between retail and wholesale rate structures often vary hourly and are different from one utility to the next.

One of the benefits of understanding the revenue effects of a single solar array is that that data can be applied as a multiplier against anticipated solar arrays to estimate future net revenue effects of solar adoption on a utility system, Combs said.

As part of the DEED grant, CDE Lightband also analyzed census data to gauge where rooftop solar arrays would be installed. CDE looked at several census traits, such as house size, education levels, and house ages. CDE was aided in its analysis by analytics firm DNV GL. The analysis found that in Tennessee the most predictive characteristic was income. Higher income correlated with higher solar penetration.

Combs cautioned, however, that those results might not hold true for utilities in other areas. It also said it is “advisable that utilities consult expert analysts before taking business action on the results of any PV adoption models or the models intended for economic analysis.”

The cost of building the solar array was about $25,000. CDE Lightband submitted and received a DEED grant for about $10,000. Expenses for data collection, analysis and reporting were assumed by CDE Lightband and Tennessee Valley Authority, which provided the Clarksville utility with assistance, and were not included in the budget.

The DEED grant gave CDE the freedom to collect and thoroughly analyze the solar data in a way that would have been hard to justify otherwise, Combs said. “It was good, not just because it was good for us, but because of the exponential benefit of being able to share the results with other utilities,” he said.

A webinar related to the project was held on April 6. A replay of the webinar is available for purchase at APPA’s product store and will also be shared in the DEED project library.

Colorado Springs Utilities enters pilot program to source responsibly sourced natural gas

April 6, 2021

by Peter Maloney
APPA News
April 6, 2021

Colorado Springs Utilities has entered into a pilot project to provide responsibly sourced gas (RSG) to its customers.

Responsibly sourced gas is natural gas produced from sites that have undergone third-party certification to verify that the operator has used the highest standards and practices in all phases of operations, according to Project Canary, a subsidiary of International Environmental Standards Co.

RSG certification is similar to a Leadership in Energy and Environmental Design (LEED) rating for buildings and is designed to certify that harmful environmental effects of natural gas, such as methane leaks in production and transportation, are mitigated.

International Environmental Standards says its Project Canary’s TrustWell certification process reviews, verifies and scores over 300 engineering and operational aspects of natural gas production and delivery categories including air, water, land and community, in awarding its RSG certification.

In the pilot program, Colorado Springs Utilities will purchase certified RSG produced by Bayswater Exploration & Production, a Colorado oil and natural gas development company. The certified RSG will be gathered and processed by Rimrock Energy Partners and then delivered to Colorado Interstate Gas Co., a Kinder Morgan subsidiary, which will transport the RSG to Colorado Springs Utilities.

“This partnership will allow us to further diversify our energy portfolio and expand our commitment to environmental stewardship,” Aram Benyamin, CEO of Colorado Springs Utilities, said in a statement.

The pilot program calls for continuous emissions monitoring across the energy value chain, from wellhead to burner-tip, which includes the production, transportation and marketing of the gas.

“This is the first of its kind pilot project in the nation and I’m proud to say we are at the forefront of exploring this newly-evolving Responsibly Sourced Gas market,” Benyamin said.

UP Energy recently said it would use Project Canary to certify that gas from some of its natural gas wells in Wyoming would be RSG certified. UP Energy said it is seeking to produce RSG on 68% of its production in its initial efforts and eventually certify 100 percent of its production by year-end 2022.

In January, natural gas producer EQT Corp., which has operations in Pennsylvania, West Virginia and Ohio, committed to a pilot project to demonstrate the production of RSG for use in domestic and international energy markets.

Under the pilot project calls for EQT to produce RSG through certification by Project Canary of two of its well pads, accompanied by continuous methane emissions monitoring of the pads.

SMUD releases a plan to eliminate greenhouse gas emissions from power supply by 2030

April 6, 2021

by Paul Ciampoli
APPA News Director
April 6, 2021

California’s Sacramento Municipal Utility District (SMUD) has released a plan to eliminate greenhouse gas emissions from its power supply by 2030.

“Our 2030 zero carbon plan is a road map with the flexibility needed to adjust to changing technology and customer preferences to completely eliminate the use of fossil fuels in our electricity production by 2030,” SMUD said in an executive summary of the plan.

“With the clean energy technology in our power supply today, we expect to be able to reduce our carbon emissions by 90%, without compromising reliability or our low rates. Eliminating the last 10% will be more challenging and will require SMUD to take bold actions and pioneer new game-changing technologies,” the utility said.

To achieve zero carbon, SMUD is focused on four main areas.

One area is natural gas generation repurposing. Eliminating greenhouse gas emissions from SMUD’s power plants is essential to reach the goal of zero carbon, SMUD said. “We’re focused on reimagining our existing generation portfolio to eliminate greenhouse gas emissions through retirement, re-tooling and using renewable fuels,” SMUD said.

“We believe our gas power plants can continue to play a vital role to support reliability without emitting greenhouse gases. By retooling two of our plants from constant operations to become more flexible peaking units, we can drastically reduce their use and carbon emissions while maintaining most of their capacity. We’re targeting operating them on biofuels such as renewable gas from landfills, biodiesel or other renewable sources when they’ll need to operate for reliability,” SMUD said.

The utility said its Campbell and McClellan gas plants are located in areas already affected by air pollution.

SMUD said modifying or retiring those plants will bring air quality benefits to these historically under-resourced communities because they’re located in areas of SMUD’s territory with some of the highest environmental sensitivity scores. “Based on our studies to date, we believe we can retire McClellan in 2024 and Campbell in 2025 and replace them with proven clean technologies.” Final decisions about the retirement of these plants will be based on additional reliability studies and discussions and engagement with the community.

A second area is proven clean technologies, which are carbon-free technologies available today, including solar, wind and geothermal energy and battery storage. “We’ll significantly expand our investments in these technologies and adjust our plan as we progress in the other three areas,” SMUD said.

Along with reimagining its natural gas power plants, SMUD said proven clean technologies are the foundation of the plan “and we expect they’ll help reduce our carbon emissions by about 90% by 2030, far exceeding the regulatory and legislative mandates in place today.”

The zero carbon plan “includes a significant increase in investments proven clean technology over the next nine years, by SMUD and our customers.”

SMUD listed the following utility-scale investments (2021-2030):

These utility-scale investment ranges are based on current and expected market conditions and costs for new technologies, “recognizing market conditions can change quickly, impacting resource availability and costs,” SMUD said.

“External market factors such as changes in California and western U.S. electricity market rules also play an important role in resource adoption, as do legislative and regulatory changes.”

If emerging technologies develop faster than expected, “we will adjust our proven clean technology strategy accordingly. Similarly, if costs for new technologies decline slower than expected or if promising research areas don’t yield the expected results, we may need to scale up our investments in other areas.”

SMUD listed the following for customer-owned adoption of solar and storage (2021-2030):

SMUD said it recognizes its customers’ investment in rooftop solar and battery technologies depend to a large extent on costs as well as overall customer sentiment about zero-carbon technologies.

“Investment estimates are based on today’s forecast of probable adoption rates and the ranges reflect the uncertainty of costs associated with these systems over the next decade,” the utility said.

“To safeguard reliability, it’s also important that SMUD maintains a diverse resource portfolio that reflects different generation technologies and geographic diversity. So, our plan includes intermittent renewable energy such as wind and solar as well as energy storage and geothermal resources that support reliability.”

A third area is new technologies and business models, which are technologies that are either currently unknown or are not ready for large-scale adoption due to price, reliability or other factors. SMUD said it will launch pilot projects and programs to test and prove new and emerging technologies and develop paths for prioritizing technology adoption and scaling.

Emerging technologies play a critical role in the plan, specifically to eliminate the remaining 10% of carbon emissions.

SMUD said it will look to emerging distributed energy resource options and large-scale new technology innovations. This includes focusing on new applications for customer-owned distributed energy resources by assessing the attractiveness, costs and reliability of emerging technologies and business models.

After launching and evaluating pilot programs and projects SMUD will evaluate, prioritize and scale the technologies and programs it expects will have the largest impact reducing carbon in its 2030 resource mix, especially in terms of short duration generation capacity.

To that end, SMUD is focused on four main areas of technology: (1) electrification; (2) education and demand flexibility; (3) virtual power plants and vehicle-to-grid technology and (4) new grid-scale technologies.

“Taken together, we expect customer-owned resources and SMUD customer-focused programs will contribute between 360 and 1,300 MW of capacity to our grid by 2030, depending on the rate of customer adoption and the success of the programs and technologies we develop.”

The fourth area is financial impact and options. “We’re focused on making sure achieving our zero carbon goal is possible at a reasonable cost that minimizes rate increases for our customers. We’ll do that by identifying savings and pursuing partnerships and grants that support the plan.”

Paul Lau, SMUD’s CEO and General Manager, discussed the plan in a recent episode of the American Public Power Association’s Public Power Now podcast.

SMUD is seeking comments on the plan by April 16 and additional details are available here.

President Biden proposal includes $100 billion for power infrastructure

April 6, 2021

by Paul Ciampoli
APPA News Director
April 6, 2021

The Biden Administration on March 31 outlined infrastructure legislation that includes $100 billion for power infrastructure.

According to a summary of the plan released by the White House, the president is proposing a “targeted investment tax credit that incentivizes the buildout of at least 20 gigawatts of high-voltage capacity power lines.”

In addition, President Biden plans to establish a new Grid Deployment Authority at the Department of Energy that “allows for better leverage of existing rights-of-way – along roads and railways – and supports creative financing tools to spur additional high priority, high-voltage transmission lines.”

He also proposed a ten-year extension and phase down of an expanded “direct-pay” investment tax credit and production tax credit for clean energy generation and storage. These credits will be paired with strong labor standards.

It is unclear whether these direct-payment credits would be available to state and local entities, in part because the summary goes on to explain that the President’s plan will “support state, local, and tribal governments choosing to accelerate this modernization through complementary policies – like clean energy block grants that can be used to support clean energy, worker empowerment, and environmental justice.”

To accelerate responsible carbon capture deployment and ensure permanent storage, President Biden’s plan reforms and expands the Tax Code’s Section 45Q tax credit, making it direct pay and easier to use for hard-to-decarbonize industrial applications, direct air capture, and retrofits of existing power plants.

President Biden is also proposing to spend $174 billion on the electric vehicle market. The plan would enable automakers to spur domestic supply chains from raw materials to parts, retool factories to compete globally, and support American workers to make batteries and EVs. It will give consumers point-of-sale rebates and tax incentives to buy American-made EVs.

It will also establish grant and incentive programs for state and local governments and the private sector to build a national network of 500,000 EV chargers by 2030, while promoting strong labor, training, and installation standards.

President Biden is also proposing electrify the entire federal fleet, including the United States Postal Service.

Other proposals include requiring federal buildings to be powered “24/7” with clean power, establishing an Energy Efficiency and Clean Electricity Standard aimed at cutting electricity bills and electricity pollution, increasing competition in the market, incentivizing more efficient use of existing infrastructure, and continuing to leverage the carbon pollution-free energy provided by existing sources like nuclear and hydropower.

Grant County PUD, Energy Northwest sign MOU for advanced nuclear project

April 5, 2021

by Peter Maloney
APPA News
April 5, 2021

The Grant County Public Utility District in Washington State with Energy Northwest and X-energy have signed a memorandum of understanding for the development of an advanced nuclear reactor demonstration project.

The partners agreed to collaborate and share resources to evaluate the goal of siting, building, and operating an X-energy Xe-100 advanced nuclear power plant at an existing Energy Northwest site north of Richland, Wash. The plant would have four 80-megawatt (MW) units and is scheduled to begin construction in 2024 and come online in 2027.

Under the TRi Energy Partnership, the parties agreed to evaluate each step of the project and identify the best approach to licensing, permitting, construction, operation, and ownership.

“This partnership signifies our strong interest in advanced nuclear energy as one of the best, lowest-cost options to reliably serve Grant County’s growing communities and support their continued economic growth,” Kevin Nordt, CEO of Grant County PUD, said in a statement. “The electricity generated by a Xe-100, and other advanced nuclear energy technologies, will be invaluable to our future carbon-free grid.”

Energy Northwest, a public power joint operating agency, is providing the project site and would operate the completed plant. Energy Northwest is also considering an ownership option down the road, Jason Herbert, director of government affairs at Energy Northwest, said.

Under the state’s Clean Energy Transformation Act, utilities in Washington have to serve retail load with 100 percent carbon dioxide free resources by 2045, so many are phasing out natural gas generation and looking for resources to fill in gaps when solar wind or hydro resources are not available. “That is what got us going down this path,” Herbert said.

Grant County PUD could also take an ownership stake in the project. “We haven’t gotten to that point yet, but it is a possibility,” Chuck Allen, public affairs supervisor at the PUD, said. “There are a lot of ways this could end up.”

Grant County PUD could also be the offtaker for the electrical output of the nuclear plant. Emphasizing that the project is still in the early stages of development and that the PUD is just at the “starting line” in the development process, Allen said the utility sees X-energy’s technology as “promising technology and a promising way to generate carbon free energy to meet firm load.” The advanced nuclear plant would be able to provide both baseload and load following power.

The PUD anticipates it will have retail load in excess of its peak capacity by 2026, “so we will have to do something,” Allen said, noting that the utility is in a “unique position” because its demand is growing so rapidly. Grant County PUD’s integrated resource plan is predicting 4.9 percent load growth through 2030.

“As we move forward with our partners, we need to be sure this project makes sense for our customers and for our county,” Allen said. “Right now, we think it could,” he said, though he noted that the utility still has more due diligence to do.

X-energy is providing the technology design concept for the small nuclear reactor, as well as the fuel design. Unlike most operating nuclear reactors, which use some form of water cooling system, the Xe-100 design uses helium as a coolant. The design also uses X-energy’s proprietary tri-structural isotropic (TRISO) fuel design that mixes and encases the uranium fuel with graphite and ceramic. X-energy claims that its fuel cannot melt down and that the fuel itself is the containment vessel, replacing the need for what has typically been one of the most expensive components of a traditional nuclear plant.

X-energy’s next step in its development process is building a fuel manufacturing facility.

The company has a pilot plant in Oak Ridge, Tenn., but is looking for a new commercial site. X-energy filed an application for a new site with the Nuclear Regulatory Commission in August and is “beginning to work with regulatory agencies on environmental applications,” Carol Lane, head of governmental relations at X-energy, said.

In October 2020, the Department of Energy, through its Advanced Reactor Demonstration Program, awarded X-energy $80 million in initial funding for the Washington project.

On March 1, X-energy signed an approximately $2.5 billion cooperative agreement with the Advanced Reactor Demonstration Program under which the DOE will invest about $1.23 billion and X-energy will have to raise a similar amount through private sources.

The Northwest public power utilities are not the first to pursue an advanced small modular reactor.

In January, Utah Associated Municipal Power Systems (UAMPS) and NuScale Power signed agreements to facilitate the development of the Carbon Free Power Project that would deploy NuScale’s small modular reactors design at the Idaho National Laboratory. Energy Northwest has the option to operate the SMR plant.

TVA, University of Tennessee sign MOU on advance nuclear reactor demonstration

In April 2020, it was disclosed that the University of Tennessee and the Tennessee Valley Authority had signed a memorandum of understanding to evaluate the development of a new generation of cost-effective, advanced nuclear reactors, such as small modular reactors, at TVA’s 935-acre Clinch River Nuclear Site in Roane County.

Nucor signs 10-year virtual PPA for 100 MW from wind farm in North Texas

April 2, 2021

by Paul Ciampoli
APPA News Director
April 2, 2021

Nucor Corporation has signed a 10-year virtual power purchase agreement (VPPA) with Orsted Onshore North America, LLC for 100 megawatts from Orsted’s Western Trail wind farm in North Texas.

This is Nucor’s second VPPA. Last year, Nucor signed a VPPA with EDFR Renewables North America to be the sole off-taker for EDFR’s 250-megawatt Brazos Fork solar project, which is also located in Texas.

Orsted’s wind farm project is already under construction and is expected to be in service later this year. The project incorporates Nucor steel and steel products and is designed to continue generating power even during particularly severe weather.

A virtual PPA is a financial deal under which the buyer pays a set price but doesn’t directly buy electricity from the project. Power from the project is sold into the wholesale market. If the wholesale price is higher than the price in the virtual PPA, the offtaker receives the difference. If the price is lower, the offtaker pays the facility owner to make up the difference.

Nucor and its affiliates are manufacturers of steel and steel products, with operating facilities in the United States, Canada and Mexico.

Enel enters virtual power purchase agreement with Kellogg tied to Texas wind project

Through a VPPA, Enel will sell a portion of the electricity delivered to the grid from a Texas wind energy project to Kellogg Company, Enel said on March 3.

Italy-based Enel, through its U.S. renewable subsidiary Enel Green Power North America, has started construction of the Azure Sky wind plus storage project, its first large-scale hybrid project globally to integrate wind and battery storage at one site.

Through a 100-megawatt VPPA, Enel will sell to Kellogg a 360 GWh portion of the electricity delivered to the grid annually from the Azure Sky wind project, which is equal to 50% of the volume of electricity used across Kellogg’s North American manufacturing facilities.

Starbucks enters VPPAs

Starbucks Corp. in December said it was entering into solar and solar-plus-storage VPPAs to support its corporate sustainability goals.

House bill would reinstate ability to issue tax-exempt advance refunding bonds

April 1, 2021

by Paul Ciampoli
APPA News Director
April 1, 2021

House Municipal Finance Caucus Chairmen Dutch Ruppersberger, D-Md., and Steve Stiver, R-Ohio, recently reintroduced the Investing in Our Communities Act (H.R. 2288), which would reinstate the ability to issue tax-exempt advance refunding bonds.

This is one of the American Public Power Association’s top tax legislative priorities and APPA supports the House bill, which has 22 additional original Democratic and Republican cosponsors.

A related bill was introduced on February 25 by Senators Roger Wicker (R-MS) and Debbie Stabenow (D-MI). 

The Lifting Our Communities through Advance Liquidity for Infrastructure (LOCAL Infrastructure) Act of 2021 (S. 479) has 18 additional Democratic and Republican cosponsors.

Wilson Energy seeks proposals for 100-MW battery energy storage systems

April 1, 2021

by Paul Ciampoli
APPA News Director
April 1, 2021

Wilson Energy, the City of Wilson, N.C.’s municipally-owned electric and natural gas utility, is now accepting proposals for 100-megawatt battery energy storage systems that can reduce wholesale power costs.

Wilson Energy’s purchased power demand costs are based on a monthly coincident peak hour. Wilson Energy targets its demand side management efforts to reduce the electric load during this period.

Wilson Energy is seeking bids for several systems of varying sizes for different locations within their electric service territory.

Systems with a total of 100 MW battery storage with the potential for an additional 21 MW will be considered.

Wilson Energy will use these systems in conjunction with the existing distributed generation program and residential load management switch program.

Wilson is located in eastern North Carolina, approximately 45 miles east of Raleigh. Wilson Energy operates the city’s electric distribution system serving 35,000 customers, and gas distribution system serving 13,000 customers.

Fully operational systems are expected to be in place by fourth quarter of 2022.

Proposals are due by 2:00 pm on Thursday, April 29.

Additional details are available here.

Department of Agriculture approves $235 mil loan package for the Navajo Tribal Utility Authority

April 1, 2021

by Paul Ciampoli
APPA News Director
April 1, 2021

The U.S. Department of Agriculture (USDA) recently approved a $235 million loan package to the Navajo Tribal Utility Authority (NTUA) for electric infrastructure improvements and system expansion.

The news was unveiled by U.S. Agriculture Secretary Tom Vilsack on March 16, announcing that NTUA is part of the $598 million rural electric loan package.

The program is part of the Biden-Harris administration’s commitment to bring affordable electric power to rural residents, Tribal communities, community facilities, schools and medical institutions that perform critical services each day.

“NTUA continues to work together with its partners to expand and complete power line connections and other critical infrastructure projects. With the CARES Act funds received last year, NTUA expedited projects and their work crews worked seven days a week to connect 737 families to the electric grid,” said Navajo Nation President Jonathan Nez. “With support from the Biden-Harris Administration, we look to build Back better and provide long-term benefits for our Navajo people through the USDA loan package,” he said in a statement.

The Navajo Nation is among communities in 11 states that were selected to be a part of the program, which will allow NTUA to connect 1,340 families, including building and improving 636 miles of electric powerline throughout the region.

The loan will also provide funding for electric transmission expansions and upgrades, and the construction of three district offices and a safety and training facility.

“This funding source will help NTUA to improve, expand, and modernize its electric transmission and distribution systems,” said NTUA General Manager Walter Haase. “At the same time, it will allow us to meet the Navajo people’s needs while keeping electric utility rates affordable.”

Since NTUA completed the work under the 2020 CARES Act, more than 500 families have requested to be served by our electric utility. Every day NTUA receives new requests, NTUA noted.

The funding source will also be used to build 144 miles of transmission line and 221 miles of distribution line. USDA also noted that $29.4 million of this loan will go to smart grid technologies including 304 miles of backbone fiber.

“The pandemic has placed focus on what is lacking and what needs to be improved,” Haase said. “As an essential service, we know that we have to provide electric, water, wastewater, and broadband services to our unserved citizens as they shelter at home which will help prevent the spread of COVID-19.”

Light Up Navajo III

Navajo Nation families can now submit applications for Light Up Navajo III, which will begin electric connections in the spring of 2022.

The Navajo Nation is the largest Native American territory in the U.S., with an estimated population of 300,000. Its unelectrified homes make up 75 percent of all unelectrified households in the United States.

To expedite electrification projects in the Navajo Nation, the American Public Power Association partnered with the NTUA to create Light Up Navajo.

Light Up Navajo, which was supported by a $125,000 grant from APPA’s Demonstration of Energy and Efficiency Developments (DEED) program, began in Spring 2019, bringing together volunteer crews from public power utilities across the country to connect Navajo homes to the grid.

In six weeks, the volunteer crews connected more than 230 homes to electricity. More than a dozen members of APPA’s staff and more than 130 individuals from 27 utilities (representing 12 states) joined in the effort.

The COVID-19 pandemic delayed plans for Light Up Navajo II, but “APPA continues to work and partner with NTUA and the rest of the public power community to help bring power to those who have been unable to access this essential modern convenience,” Said Alex Hofmann, Vice President, Technical and Operations Services.