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hydroelectric power

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• National Geographic - Hydroelectric Energy: The Power of Running Water
• Energy Education - Hydropower
• Energy.gov - Hydropower Basics
• U.S. Energy Information Administration - Hydropower explained

hydroelectric power , electricity produced from generators driven by turbines that convert the potential energy of falling or fast-flowing water into mechanical energy . In the early 21st century, hydroelectric power was the most widely utilized form of renewable energy ; in 2019 it accounted for more than 18 percent of the world’s total power generation capacity.

• Geothermal power
• Hydroelectric power
• Solar power
• Tidal power

In the generation of hydroelectric power, water is collected or stored at a higher elevation and led downward through large pipes or tunnels (penstocks) to a lower elevation; the difference in these two elevations is known as the head . At the end of its passage down the pipes, the falling water causes turbines to rotate. The turbines in turn drive generators , which convert the turbines’ mechanical energy into electricity. Transformers are then used to convert the alternating voltage suitable for the generators to a higher voltage suitable for long-distance transmission. The structure that houses the turbines and generators, and into which the pipes or penstocks feed, is called the powerhouse.

Hydroelectric power plants are usually located in dams that impound rivers , thereby raising the level of the water behind the dam and creating as high a head as is feasible . The potential power that can be derived from a volume of water is directly proportional to the working head, so that a high-head installation requires a smaller volume of water than a low-head installation to produce an equal amount of power. In some dams, the powerhouse is constructed on one flank of the dam, part of the dam being used as a spillway over which excess water is discharged in times of flood. Where the river flows in a narrow steep gorge, the powerhouse may be located within the dam itself.

In most communities the demand for electric power varies considerably at different times of the day. To even the load on the generators, pumped-storage hydroelectric stations are occasionally built. During off-peak periods, some of the extra power available is supplied to the generator operating as a motor, driving the turbine to pump water into an elevated reservoir . Then, during periods of peak demand, the water is allowed to flow down again through the turbine to generate electrical energy . Pumped-storage systems are efficient and provide an economical way to meet peak loads.

In certain coastal areas, such as the Rance River estuary in Brittany , France , hydroelectric power plants have been constructed to take advantage of the rise and fall of tides . When the tide comes in, water is impounded in one or more reservoirs . At low tide, the water in these reservoirs is released to drive hydraulic turbines and their coupled electric generators ( see tidal power ).

Falling water is one of the three principal sources of energy used to generate electric power, the other two being fossil fuels and nuclear fuels . Hydroelectric power has certain advantages over these other sources. It is continually renewable owing to the recurring nature of the hydrologic cycle . It does not produce thermal pollution . (However, some dams can produce methane from the decomposition of vegetation under water.) Hydroelectric power is a preferred energy source in areas with heavy rainfall and with hilly or mountainous regions that are in reasonably close proximity to the main load centers. Some large hydro sites that are remote from load centers may be sufficiently attractive to justify the long high-voltage transmission lines. Small local hydro sites may also be economical, particularly if they combine storage of water during light loads with electricity production during peaks. Many of the negative environmental impacts of hydroelectric power come from the associated dams, which can interrupt the migrations of spawning fish , such as salmon , and permanently submerge or displace ecological and human communities as the reservoirs fill. In addition, hydroelectric dams are vulnerable to water scarcity . In August 2021 Oroville Dam , one of the largest hydroelectric power plants in California, was forced to shut down due to historic drought conditions in the region.

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Lecture 9 Hydroelectric Power Plants

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Hydro Electric Power Plant.

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Presentation on theme: "Hydro Electric Power Plant."— Presentation transcript:

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Hydroelectric Power

Hydroelectric power worldwide, hydropower plants produce about 24 percent of the world's electricity and supply more than 1 billion people with power. – powerpoint ppt presentation.

• Worldwide, hydropower plants produce about 24 percent of the world's electricity and supply more than 1 billion people with power.
• The world's hydropower plants generate a combined total of 675,000 megawatts, the energy equivalent of 3.6 billion barrels of oil, according to the National Renewable Energy Laboratory.
• There are more than 2,000 hydropower plants operating in the United States, making hydropower the country's largest renewable energy source.
• Hydropower plants harness water's energy (of motion) and use simple mechanics to convert that energy into electricity.
• Hydropower plants are actually based on a rather simple concept -- water flowing through a dam turns a turbine, which turns a generator.
• Intake and Penstock-pull water into the area where turbine is located
• Turbine-spins as water passes through
• Generator-generates electricity using mechanical energy of the spinning turbine
• Transformer-transforms electrical energy for passage through the power lines
• Reservoir-holds the water
• The Hoover Dam weighs 6.6 million tons
• There is enough concrete in the dam to build a 3 inch
• thick, 4 foot wide sidewalk around the earth at the equator
• Standing 726 feet tall, the Hoover Dam is tallest solid
• concrete dam in the western hemisphere
• Clean, very little pollution
• Renewable resource
• Inexpensive
• Diverts natural flow of water-changes the environment
• Not suitable for all areas-need high and low elevations for gravity to cause water to move
• Solar power
• Geothermal power
• Tidal Power
• With your group discuss how are these other power production methods are similar/different?
• Brain POP Nuclear Power-as you watch the BP consider the following
• What are pros and cons for using nuclear power?
• How does nuclear power create electricity?
• What is a chain reaction?
• Nuclear Fission Chain Reaction Video
• The City of Tallahassee uses 4 power plants to generate electricity for its residents
• C.H. Corn Facility
• Arvah B. Hopkins Generating Station
• Sam O. Purdom Generating Station
• Tallahassee requires approximately 425 megawatts of electricity daily!
• Hydroelectric powered
• 1 of only 2 hydroelectric plants in Florida (why only 2?)
• Has 3 generators
• Capacity of 12 megawatts
• City plans to shut this plant down as it is not cost effective
• burns fossil fuels (either natural gas or oil) to convert water to steam in two huge boilers.
• The steam is used to drive two turbines which are in turn connected to power generators.
• In addition, power can be produced when needed by two gas turbine generators located at the plant.
• Capacity of 368 megawatts
• Purdom Unit 8 uses a system called Combined Cycle Technology, which effectively uses the energy from the burned fuel twice.
• It then uses mechanical energy produced by steam to move the turbines.
• Capacity of 320 megawatts
• Source www.talgov.com
• Tallahassee broke ground on 5/30/17 on a 120-acre solar project at the international airport capable of powering 2,400 homes and businesses. Customers can opt in to use solar energy with a fuel rate of 5 cents per kilowatt hour for 20 years (compared to 3.5 cents for fossil fuels). Capacity is 20 megawatts
• Tallahassee Solar Farm Building Video
• http//www.brainpop.com/technology/scienceandindus try/dams/zoom.weml
• Click the link to see how it works
• http//www.solar-is-future.com/index.php?id316
• https//www.eeremultimedia.energy.gov/solar/videos /solar_power_basics
• Energy is collected and stored in batteries
• Once the batteries are full, power is used to offset the electrical needs of the school
• Some systems will actually feed back to the local power company if it generates extra power that is not used
• Our solar panel generates enough power to operate our emergency lights and two outlets
• Energy Whiz website-data is uploaded to the internet from the panel
• http//energywhiz.com/
• Watch the video
• http//flix.quickrewards.net/watch/4309757/
• Air pollutants are not released, just water
• Natural gas is much cheaper than diesel
• Natural gas is found in the United States
• Leon County is currently adding CNG buses to its fleet, reducing the diesel buses
• Which energy source do you think would be suitable for the most populations in the world? Explain using at least 2 reasons
• Which energy source do you think would be best for Tallahassee? Explain using at least 2 reasons
• Why cant we use just one of the power production methods globally?

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Hydropower Remains Renewable Leader Despite Climate Challenges

As the oldest renewable energy resource, hydropower is well-established as a reliable source of dispatchable energy. Yet, it is often overlooked and taken for granted. It’s commonly believed that hydro’s potential is tapped out in the U.S., but many opportunities exist to add capacity at non-powered dams and on repowering projects.

Hydropower installations worldwide have been increasingly impacted by drought conditions. The World Economic Forum in a recent report noted that while hydro for many years has provided most of the globe’s renewable energy, its output has slowed due to the effects of climate change, including what the International Energy Agency (IEA) calls “erratic” rainfall. The IEA has said global investment in hydropower generation capacity has fallen in the past few years, and the group expects that trend will continue.

Despite that, new projects—including large installations—are being built. China and the U.S. in recent years have experienced drops in the percentage of hydro as part of those countries’ generation mix, but China for its part continues to invest in hydroelectricity as part of that country’s strategy to increase all forms of power generation. China is home to most of the largest hydropower dams in the world, led by Three Gorges Dam, a 22.5-GW behemoth that has produced power since 2003. Next is the Baihetan hydropower station (Figure 1), a 16-GW facility that became fully operational in 2021.

Climate Change Impacts Hydro

Chinese officials, though, earlier this year said the country’s hydro generation has been essentially flat for the past three years despite several new large power stations coming online, including the Lijiaxia Hydropower Station No. 5, one of the world’s biggest hydropower plants in a dual-row turbine layout. That facility entered operation in October of last year. Officials in China have acknowledged the need to continue to support hydropower, even as prolonged drought has markedly reduced river flows in the southwestern part of the country.

“Hydropower generation critically depends on how much water runs in rivers and hence hydro climatological conditions. In the decades to come, there are likely more frequent and severe droughts globally, threatening sustainable hydropower operations and installations,” said Dr. Hong-Yi Li, associate professor of civil and environmental engineering at the University of Houston. Li told POWER , “To tackle this challenge, other forms of renewable energy such as solar are worthy of more consideration than ever, particularly for those places that already often experience water shortages.” China has certainly recognized this; the country added 226 GW of new power extra generating capacity last year, with 129 GW from solar, 39 GW from thermal, 33 GW from wind, and 8 GW from hydro, according to the National Energy Administration.

Dimitrios Kalliontzis, assistant professor of civil and environmental engineering at the University of Houston, told POWER : “Hydropower accounts for more than 25% of the renewable electricity generation in the United States. The risk hydropower is facing underlines the need to rethink, adapt, and transform. While drought is a threat to hydropower facilities, climate change and the associated sea level rise may create opportunities to adapt existing technologies to the offshore marine environment, harvesting tidal streams, currents, or even waves. While offshore harvesting is still in the early stages, it can potentially compensate or exceed the current hydropower supply.”

Ember, an energy think-tank based in the UK, last year reported that global output of hydropower had a historic drop in the first half of 2023. The group said drought conditions led to an 8.5% decrease in global hydro output during that period; China accounted for about 75% of the worldwide decline. The IEA has said hydropower eventually will be overtaken by solar and wind energy output, though the agency doesn’t expect that to happen for at least another decade. The group said a slowing of the industry’s growth puts global net-zero targets in jeopardy. The International Renewable Energy Agency reported that hydropower generation capacity must double by 2050 for the world to remain on track to limit global warming to 1.5C by mid-century.

John Stranne, research associate, Nordic and Baltic Power Markets at Aurora Energy Research, told POWER : “Increased variation in weather due to climate change, with more frequent droughts and floods, will increase the level of uncertainties for hydropower operations. Mainly, the weekly, monthly, and seasonably valuation of water—which leads to tougher optimization and reduced system efficiency. Storage plants plan their behavior several months or even years in advance, estimating when they should contribute how much to the electricity market and at which hours of the day and periods of the year, where the system benefits the most. If weather patterns, and correspondingly hydro inflows, become harder to predict, it could lead to changed bidding behavior on the market, potentially increasing weekly spreads, or price volatility.”

Investments Flowing to Hydropower Projects

The U.S. Department of Energy (DOE) in a 2023 market report said that incentives authorized in the Bipartisan Infrastructure Law and the Inflation Reduction Act (IRA), including tax credits, “are expected to stimulate investment in upgrades to the existing [U.S.] fleet and construction of new hydropower and PSH [pumped storage hydro] projects in the coming years. However, they may have contributed to the decline in activity in 2021–2022 because of plant owners waiting for full guidance on the implementation of these incentives (e.g., which types of projects would qualify, details on wage, apprenticeship, and domestic content requirements) to make any new capital investment decisions.”

Don Erpenbeck, vice president and global sector leader of Hydropower & Dams at Stantec, an engineering services firm, told POWER : “The U.S. hydropower market continues to be very robust for engineering and for capital projects’ work. However, it is slightly different than people think it is… 90% of the capital spend in the U.S. is around hydropower refurbishment, dam refurbishment, and environmental projects that are the result of ongoing Federal Energy Regulatory Commission license compliance or other environmental improvements.”

Erpenbeck said Stantec is currently working on more than 20 GW of repowering in the U.S. alone. “That is mostly in the powerhouses and the powertrain equipment, but also includes the upgrades to dams, spillways, and other major civil infrastructure elements. It’s a large, multibillion-dollar construction market overall. The U.S. fleet, in general, is being modernized to increase their flexibility of operations with all the different renewables coming onto the power grid. The hydropower fleet has generally gone from operating at a constant power—maybe starting/stopping twice a week—to starting and stopping sometimes eight to 10 times per day on each unit. And within those starts and stops, plants are running from maximum to minimum power swings to regulate the grid. A hydropower plant’s capability to regulate the grid through flexible operations is totally taken for granted. But talk to any operator in a balancing authority control center and they will tell you how valuable the hydro units are. But it is accelerating the aging process of the existing older fleet.”

Lizzie Bonahoom, research associate at Aurora Energy Research, said hydropower still should be considered important to the buildout of renewable energy resources. “Hydro technologies account for just 28% of installed renewables capacity today in the U.S., down from 54% a decade ago,” said Bonahoom, who referenced U.S. totals of 99 GW of hydropower and 184 GW of total renewable energy generation capacity in 2014, levels that are now at 101 GW and 360 GW, respectively.

“These [hydro] projects tend to be older, with only 3% of capacity coming online since 2000. The three different types of large-scale hydropower across the U.S. are conventional hydropower [impoundment] at 79 GW, pumped storage at 22 GW, and run of river [hydrokinetic or diversion] at just under 1 GW. Over half [50 GW out of 79 GW] of existing conventional hydro is located in the West, particularly Washington, California, and Oregon, whereas, most pumped storage is located in the South [10 GW],” she said.

Bonahoom further noted, “Different revenue streams and subsidy structures are available to new build hydropower projects across the U.S. All are supported by federal investment tax credits, which under IRA provisions could reach up to a 50% discount on total project CAPEX [capital expenditure]. Conventional hydropower and run of river are also eligible for the production tax credit, a variable subsidy based on electricity generation. Additional support is available for hydro in the Bipartisan Infrastructure Law, which aims to improve environmental standards and operation of existing facilities, without extending support to new facilities.”

Markets and Competing Technologies Vary by Location

Bonahoom said there are regional differences when it comes to U.S. hydropower. “On a more granular level, all markets in the U.S. have different designs and are influenced by local and state policies in addition to federal policy. For example, hydro would tend to benefit from capacity market payments in markets with capacity payments, such as CAISO’s [California Independent System Operator’s] Resource Adequacy or PJM’s Reliability Pricing Model. In Texas’ market, ERCOT [Electric Reliability Council of Texas], where there is no capacity market, hydro is eligible to participate in smaller ancillary services, such as spinning reserve.”

Bonahoom noted the impact of drought on the hydropower market, and how that can limit investment. “Despite availability of federal tax credits and various other revenue streams, there has only been 3.3 GW of hydro made operational since the year 2010 [all of it conventional], which is small compared to onshore wind [116 GW], solar PV [97 GW], and battery [17 GW] additions in the same time frame,” said Bonahoom.

“Aside from high costs, drought risk presents a significant barrier to development of more hydropower on the system: California’s power market for example is particularly susceptible to drought and a poor water year can reduce hydro output by approximately 10 TWh, approximately 5% of the ISO’s demand in 2023,” she said. “High upfront costs of developing hydro have helped to hamper development. This is reflected in investor interest across competitive ISOs; only 3.1 GW of new pumped storage and 1.7 GW of conventional hydro is currently under development, as opposed to 586 GW of battery storage, 584 GW of solar PV, and 213 GW of onshore wind.”

Bonahoom said that despite lacking investor interest, there is a growing need for dispatchable clean generation in the U.S. to complement rising intermittent renewables generation. “Pumped hydro especially is in a good position to provide value, ‘charging’ when power prices are low and there is sufficient generation on the system, and discharging when the grid is tighter, which will more often coincide with the sun setting,” she noted.

David Pretyman, senior partner of Energy and Utilities at West Monroe, a consultancy group, said, “It’s true that hydropower outputs in the American West have been below average this year and last. However, the variability of a changing climate may also imply that the wet seasons could become wetter, and the dry seasons could become drier. This could potentially destabilize power prices and the overall system makeup in the long term. Dueling proposals and divided allegiances among market participants on the future of a West-wide regional transmission organization could further complicate matters,” he said.

Pretyman continued: “For instance, Bonneville Power Administration, which markets wholesale electrical power from many of the large federal hydro facilities in the Northwest [including the Grand Coulee Dam, the largest hydro dam in the U.S. with more than 6.8 GW of generation capacity, Figure 2], supports a day-ahead market proposal from Southwest Power Pool. Meanwhile, California and several surrounding utilities have signed on in support of a proposal to extend California’s market arrangements more broadly to the West. The ultimate framework will have significant implications for how hydropower is valued on the grid.”

Adding New Hydropower Capacity Can Be Difficult

Pretyman also referenced the market dynamics of the U.S. Northeast, telling POWER , “The reality is that the U.S. has largely exhausted its available hydropower resources, with new dam proposals often facing opposition from environmental groups. This opposition is partly driving investor dollars toward transmission solutions. For instance, in the Northeast, the Champlain Hudson Power Express HVDC [high-voltage direct-current] transmission line is set to deliver hydropower from Quebec to serve the New York City load center with substantial amounts of clean energy. This project has been in development for over 20 years. However, another proposed line, intended to bring hydropower to the New England area, was recently canceled despite receiving federal backing. The challenge lies in finding a way to access clean, firm power where solar and wind alone are insufficient.”

The largest hydro project currently planned in the U.S. is the Leslie D. Thatcher pumped storage facility, according to Global Data. The Thatcher PSH project, which would be located in Michigan, is being designed with a total capacity of almost 3.5 GW. Hydropower Highway is the project developer.

Erpenbeck told POWER , “In the U.S., the new hydropower market is going to be focused on pumped storage hydropower. In the energy transition, the value of electricity storage, and particularly long-duration storage, is dominated by pumped storage, where over 90% of the U.S. electricity storage capacity is currently in the existing pumped storage fleet. But it will need to increase and potentially even double to support all the new solar and wind projects. Pumped storage is very dispatchable, but unlike batteries, which are DC power with inverters, these are large synchronous machines that have large amounts of inertia and add stability and reliability to the grid when compared to inverter-based resources. Pumped storage can also run as a synchronous condenser as required by the grid.”

The DOE in a March report wrote: “Hydropower’s longstanding reputation as a reliable source of energy and storage may ironically be one of the reasons people often assume it is ‘tapped out’ of investment opportunities, but this is not the case. Far from being tapped out, hydropower, including pumped storage hydropower, still has enormous potential for growth, particularly for small- and medium-sized projects [or those that produce up to 30 MW of power].”

The DOE noted that less than 3% of the more than 90,000 dams in the U.S. produce power, and said that there are “thousands of non-powered dams offering excellent opportunities for investment. In addition, dams that do currently produce power can often be updated to increase capacity. There are also millions of miles of waterways, including both rivers and canals, that can be utilized for in-stream hydropower.”

“The U.S. should definitely be investing more into new, renewable hydropower development, as well as the existing fleet,” said Erpenbeck. “On the existing plants, the larger plants have been getting investment because they’re so valuable. But the smaller projects have been struggling. Many of these are very old projects—more than 80 years old—that were part of an industrial complex, like a pulp and paper mill, where the megawatts aren’t all that large out of the facility. However, the facility itself and the dams provide recreational lakes and flood control, and the power basically pays for all those public benefits. These are the projects that have been sorely neglected and struggling to find the proper funds to put back into the projects. In terms of new projects, the fact is that many of the best conventional hydro project sites have been built. However, there are many dams in the U.S. that still do not have hydropower on them, over 80,000, and some of these could be developed if we can find sites where there are minimal impacts to powering the dams,” he said.

“I’ve worked in the hydropower industry my entire career and one of the things that I tell people is that every hydropower project is a local tourist attraction, a recreational area, a boating and fishing haven, as well as a tool for flood control, navigation, or water supply—all of that in addition to being a renewable power project,” said Erpenbeck. “Many of the projects have visitors’ centers and museums. I can’t name any other power project that has these things, and they are common on many hydropower projects. We used to say these projects are designed for 100 years, but the reality is that these projects are ‘forever assets’ as one of my clients refers to them.”

Erpenbeck continued: “In addition to long life and local tourist benefits, many of these projects are over 90% efficient. And when designed correctly they can be an environmentally positive force in the community. Yes, hydropower is an older proven technology—but was also the first renewable resource developed in the U.S. The technology has been upgraded over the years, so much so that the new projects are very different than the old historic projects. But, yet, they are taken for granted because they are a legacy asset. We need to look at the future and include what works. We as a power industry need to get back to thinking about multiple bottom-line decision-making and have a longer-term vision than the next five years. Instead, think about the next 50 years, and in the case of hydropower, the next 100-plus years.”

— Darrell Proctor is a senior associate editor for POWER.

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Major contract signed for revitalization of Vidraru hydropower plant in Romania

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As part of a consortium, KONČAR has signed a significant contract with Romanian company Elektromontaj S.A. to revitalize the Vidraru hydropower plant in Romania. This project includes comprehensive design, production, delivery, dismantling of outdated equipment, installation of new equipment, testing, and commissioning. The contract, awarded through an international tender, is valued at over €188 million, with KONČAR’s contribution nearly €80 million.

The Vidraru hydropower plant, located on the Argeș River, is a crucial part of Romania’s energy infrastructure. Built in 1961 and operational since 1966, the facility is set for a major overhaul to improve efficiency, extend its operational life, and strengthen Romania’s energy capabilities.

The customer for this project is S.P.E.E.H. HIDROELECTRICA, Romania’s largest electricity producer, based in Bucharest. HIDROELECTRICA has an installed hydropower capacity of 6.3GW, generating 15.6 TWh annually.

KONČAR’s entry into this market with the Vidraru project enhances its global market presence. Multiple companies within the KONČAR Group will collaborate to execute this project.

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Price tag for overhauling big hydro plant could pass $7 billion

The overhaul of New Brunswick’s most important hydroelectric power plant could cost as much as $7.2 billion – a huge amount tied to the unprecedented electrical rate hikes NB Power is seeking.

The startling figure was released reluctantly by NB Power’s chief financial officer and senior vice president Darren Murphy during a rate hearing in Fredericton last week.

NB Power has not provided an updated estimate since it embarked on the Mactaquac Life Achievement project in 2016, when it said it would cost between $2.9 billion and $3.6 billion to extend the life of the generation station and dam near Fredericton another 50 years.

Murphy at first told the three members of the New Brunswick Energy and Utilities Board he’d rather not give an estimate, citing the fact that tenders have not come in yet for pieces of the work. He said he didn’t have confidence in providing a reliable figure.

But under persistent questioning from Glenn Zacher, a lawyer working for J.D. Irving, Limited, Murphy acknowledged that with inflation and additional scoping work on the project, it would be one and half times to double the original estimate.

That would amount to between $4.4 billion and $7.2 billion.

The board, an independent, quasi-judicial regulator, will ultimately decide whether NB Power has proven its case that it should get its requested rate hikes.

Although most proceedings over the first two days of the hearings at the Fredericton Delta Hotel were dry, polite and formal, at times the atmosphere was tense, including an argument over whether NB Power’s customers would feel rate shock.

NB Power’s three most senior executives – Murphy, CEO Lori Clark and Vice President Brad Coady – appeared as the first panel at the hearing to decide whether the utility should be allowed to raise the average electrical rate by 9.25 per cent this year and the same amount next year.

That’s an average hike only. For instance, households are facing a higher increase of 9.8 per cent, plus a catch-up amount for unexpected costs last year of three per cent, for a total increase of 12.8 per cent as of April this year. Add that to next year’s potential hike, and households could be forced to pay 22.6 per cent more.

Randy Hatfield, executive director of the Human Development Council in Saint John, warned the board that New Brunswick has one of the highest energy poverty rates in the country.

Someone who is energy poor spends six per cent or more of their after-tax income on electricity. In New Brunswick’s case, that’s one in every third person in the province, he said.

Raising electricity rates steeply would be hugely difficult for most of these people, he said, given that most of them already have low incomes and use baseboard electrical heat.

NB Power has some programs to help low-income households, but he said they weren’t nearly enough.

“The glaring hole, the missing piece in a comprehensive energy poverty strategy, is a low-income rebate program,” he told reporters afterward. “That’s available in Ontario, in many of the States in the U.S. and throughout Western Europe. And in the absence of a low-income energy rebate, we’re going to find more and more, low-income households falling back onto whether they spend money on heat or eat.”

Big industrial customers face the highest hikes, this year amounting to slightly more than 15 per cent. JDI, which runs paper and sawmills throughout the province, is a huge consumer of electricity.

Clark said NB Power needs the increases to prepare for future load growth, meet climate change goals, deal with intense weather and worse storms, replace badly aging infrastructure, handle inflation, address supply chain problems and fulfill its financial obligations.

As part of NB Power’s efforts to shore up its finances and prepare for the spending at Mactaquac, among other big projects, it is under pressure from the Progressive Conservative government to wipe $1 billion of debt off its books by 2029.

Zacher pointed out that NB Power had failed to reduce any of its debt since formulating a plan in 2013 to reduce it by $1 billion, despite having $426 million in net earnings since that period.

“So ratepayers, for the next five years, are expected to pay the entire freight,” Zacher said.

But Clark said it was unfair to portray the situation that way. The chief executive argued that breakdowns at the Point Lepreau nuclear plant in Saint John were one of the main reasons her organization couldn’t pay down debt, a situation it hopes to address by investing more in annual maintenance and repairs.

Every time the plant has an unscheduled outage, the utility is forced to pay for expensive power from out of province or run other generators, otherwise people would experience brown-outs or rolling blackouts, she said.

And during the pandemic, NB Power decided to freeze electrical rates to help its customers cope.

“In hindsight, I don’t think it was the right thing to do,” Clark said. “But at the time, it was the right thing to do.”

NB Power lawyer John Fury asked the panel of NB Power executives whether the JDI lawyer was right to say ratepayers would shoulder the entire $1-billion debt repayment burden over the next five years. Coady said no, and estimated that about half the amount, $500 million or so, would likely come from revenues made from export sales of electricity to markets outside of New Brunswick.

Besides, Clark said the utility could not wait any longer to pay down debt because the upgrades were so badly needed at Lepreau and Mactaquac.

The Mactaquac project alone is expected to take 15 years. It’s already behind schedule, with Murphy explaining that experts had advised the utility to take its time and get the project started right, rather than rushing in.

NB Power asked for tenders on replacing the turbines and other work and expects to make a recommendation on how to proceed to its board of directors at the beginning of next year, with a final cabinet decision six to nine months later. That means work could start in the fall of 2025.

Alain Chiasson, the public intervener who the provincial government hired to represent the public interest, said the Mactaquac project concerned him. He wonders if NB Power will be able to keep rates at an annual average increase of 4.75 per cent for the three years following the latest hikes.

“The cost for Mactaquac has exploded since 2016,” he told reporters. “It will probably be at least $7 billion or if not more. So, yes, I’m concerned about that.”

At one point in the hearing, JDI’s lawyer recited sworn testimony from Clark at last year’s rate hearing, when NB Power unsuccessfully asked for an 8.9 per cent increase (the board only gave it a little over half the amount, 4.8 per cent).

He recounted that Clark had described rate shock as an increase of 10 per cent or more, what many customers are threatened with this year.

“Any amount when you’re already struggling to pay for groceries and gas will feel like rate shock,” Clark argued, adding that NB Power has a guiding principle of trying to avoid double-digit increases.

Zacher asked if she wouldn’t agree that the proposed increases were extraordinary.

“They are higher than what you’d normally see,” Clark said. “But these are not normal times.”

John Chilibeck, Local Journalism Initiative Reporter, The Daily Gleaner

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164 MW power generated from Karnaphuli Hydroelectric Power Station due to rise in water level of Kaptai Lake

• Jul 3, 2024 Jul 3, 2024 1:48 am GMT

Rangamati, July 2 -- Karnaphuli Hydroelectric Power Station is generating 164 MW of power per day due to the rise in Kaptai Lake water level, the highest power generated at the plant this year.

All four units of Kaptai station were kept open and the authorities concerned were able to generate 164 MW of power from 9 am , said ATM Abuzzaher, manager of the Karnaphuli Hydroelectric Power Station .

Among these, 42MW power generated from no 1 and no 2 units each while 80 MW from no 4 and 5 units, he said.

If the flow of the water level of Kaptai Lake remains so, the power generation will be increased, he said.

According to the control room sources the rule curve of Kaptai Lake was initially expected to reach 88.16 feet Mean Sea Level (MSL) but the current water level has reached 83.69 feet MSL, indicating the significant impact of the ongoing rains.

The capacity of the rule curve of Kaptai Lake is 109 feet MSL.

A total of 230 MW of power could be generated from Karnaphuli Hydroelectric Power Station if all five units are operative, said Abduzzaher.

He also urged the government not to reduce the water level of the lake for the continuation of the power generation.

However, the local people demanded dredging of the lake for the normal flow of the lake. Published by HT Digital Content Services with permission from United News of Bangladesh . For any query with respect to this article or any other content requirement, please contact Editor at [email protected]

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On June 26, the Office of Indian Energy hosted the third webinar of the 2024 Tribal Energy Webinar Series.

View the webinar recording to hear Tribal energy success stories from the Seneca Nation of Indians and Northwest Arctic Borough and learn about tax credits available through the Low-Income Communities Bonus Credit Program 48(e) .  

The webinar also provides an overview of the Office of Indian Energy technical assistance process and considerations for Tribal utility pre-feasibility studies.

Presentation Slides

Introduction and Contact Slides (includes funding opportunities)

Low-Income Communities Bonus Credit Program 48(e)

Tribal IPP Development in Alaska

Northwest Arctic Borough

Technical Assistance Support

Seneca Nation of Indians

Webinar Recording and Transcript

Jump to each section: (links open in YouTube, or you can manually skip to the timecode in the webinar player on this page)

19:35 Low-Income Communities Bonus Credit Program 48(e) 50:04 Tribal IPP Development in Alaska 1:23:36 Northwest Arctic Borough 1:45:30 Technical Assistance Support 1:59:56 Seneca Nation of Indians

BRANDON KIGER: Welcome, everyone. I'm Brandon Kiger, today's webinars host. I'm a contractor supporting the Office of Indian Energy Policy and Programs Tribal Energy Webinar series. Today's webinar, titled Leveraging Opportunities to Bring Tribal Clean Energy Projects Online, is a third webinar of the 2024 DOE Tribal Energy Webinar series. Let's go over some of the details. 

Today's webinar is being recorded and will be made available on DOE's Office of Indian Energy Policy and Programs website in about one week. Copies of today's presentation and slides will be posted to the Office of Indian Energy's website shortly after this webinar. Everyone will receive a post-webinar email with the link to the page where the slides and recording will be located. 

Because we are recording this webinar, all phones have been muted. We will answer your written questions at the end of today's final presentation. However, you may submit a question at any time by clicking on the Question button located in the webinar control panel on your screen. 

Let's get started with opening remarks and a presentation from Lizana Pierce. Ms. Pierce is a senior engineer and the deployment supervisor for the Office of Indian Energy Policy and Programs duty stationed in Golden Colorado. She is responsible for the execution of the deployment program, which is national in scope. Specifically, the deployment program includes financial assistance and technical assistance and education and outreach. 

She also implements national funding opportunities and administers some of the resultant tribal energy project grants and agreements. She has nearly 30 years of experience in project development and has been assisting tribes in developing their energy resources for 25 years. Ms. Pierce holds a Bachelor of Science degree in mechanical engineering from Colorado State University. Lizana, the virtual floor is now yours. 

LIZANA PIERCE: Thank you, Brandon. And hello, everyone. I join Brandon in welcoming you to today's webinar. This webinar series is sponsored by the Office of Indian Energy Policy and Programs, otherwise referred to as the Office of Indian Energy. 

This year's webinar series is entitled Tribes Leading the Way to Clean Energy Transition. Great strides have been made in recent years to help provide greater financial support and foster relationships between federal agencies and tribal governments. The most recent examples are the Bipartisan Infrastructure Law or bill, the Inflation Reduction Act, otherwise known as IRA, and the recent presidential executive order on reforming federal funding and support for tribal nations, as well as the US DOE secretary reaffirming our commitment to buy tribal energy. 

Last year's tribal energy webinar focused on the unprecedented amount of funding going towards climate change solutions and landmark legislation. that's built in IRA and how tribes can participate in the clean energy transition. 

This year's webinar series will continue providing information on funding and financing while also providing case studies on how tribes are leading the way. Additionally, the 2024 series will include information on tools, resources, and funding and financing opportunities to help you participate in that clean energy transition. 

We do hope the webinar and the series as a whole is useful to you, but we also welcome your feedback. So please let us know if there's a way to make this series better. You can send that feedback to our main email at [email protected]. Or add your comments to the question box in the webinar control panel. 

Before we move on to the other presenters, I want to provide some information on the Office of Indian Energy and highlight new funding opportunities and resources. But before we jump into it, I want to introduce you to the DOE Office of Indian Energy team. And my dog is not cooperating. So bear with me here. 

Waleah Johns is the director of the Office. She's a member of the Navajo tribe and comes from Northeastern Arizona. Stop. Stop. Go on. And our deputy assistant-- pardon me. Under her tenure, the Office of Indian Energy budget has more than tripled from 22 million in fiscal year 2021 to 75 million in 2023. This growth provides additional funding to support tribal communities in pursuing their energy sovereignty and their energy goals, and it includes 30 staff positions for the office. So we're growing as well to, hopefully, provide you with more support. 

David Conrad, he's a citizen of the Osage Nation. He serves as our deputy director, and he had recently served as director of the Office of Public Affairs for the assistant secretary of Indian Affairs in the Department of Interior. And prior to that, he did serve within DOE congressional affairs as well as acting director for the office at one point. He has 20 years of intergovernmental experience and energy, environmental, economic development and natural and cultural resources. Next slide, please. 

This is a picture taken at the end of August of 2023. It includes our leadership in the middle and the front and our federal staff and contractor support. We've since grown as well. The office is currently comprised of 20 federal employees. And we have individuals in DC, Colorado, Florida, Oregon, Oklahoma, Wyoming, Nevada, and North Carolina and probably missed a few. But we're all over the place. Next slide, please. 

So the federal deployment team consist of myself. Tommy Jones is a deputy, and he's a enrolled citizen of the Cherokee Nation of Oklahoma and Naknek Native Village. And he's a Native shareholder of Bristol Bay Native Corp. 

Jamie Alley, senior engineer, she has worked with me for 15 years or thereabouts as a contractor and has recently joined our federal team, and we're so pleased to have her. Josh Gregory is the lead engineer and our DOE project officer. He joined us a few years ago. And some of you may have worked with him when he was with the Division of Energy Mineral Development at the Department of Interior. 

Mike Stevenson is the lead engineer. He manages our technical assistance. And some of you may have also worked with through the Division of Energy and Minerals. Mike Vehar, another engineer, DOE project officer, he oversees grants and assists tribes from their tribal entities with their project. He had worked with us a number of years ago-- well, now quite a few during the [INAUDIBLE]-- 2009, '10, '11, '12 era-- and has come back to his forever home. 

Lastly, we have two federal staff on the deployment team-- James Jensen, general engineer; and Joe Owle, a physical scientist-- both serving as technical assistance specialists, serving the tribe for the last couple of years at tribal and intertribal organizations through the Technical Assistance Program. In addition, we have eight contractors who support us in the execution of financial assistance and technical assistance and outreach. Next slide, please. 

I think seeing the faces of the people and some of you have worked with is important. So bear with me as I take the time to introduce you here. So we have a fantastic contractor staff from [INAUDIBLE] in Boston Government Services. 

On the contractor side, we have Jen Luna. She's the team lead for the contractor team. She's worked with us for quite a few years and I think-- and before that with other DOE offices. Also shown is Sam Baker and Nathan Ballenger and Pat Gwin. Next slide, please. 

On this slide, we have Kris Venema and Roberta "Bobbie" Wells. Both of them will act as project monitors and in concert with the DOE project officers to help the tribes and tribal entities with their clean energy projects. And on the left, we have Kara Wilcox and Brandon Kiger, who you heard from earlier, are program analysts who work more closely on the competitive processes, metrics, research, special projects. Next slide, please. 

So as advocated for and by the tribes and incorporated in the Energy Act of 2005, the office is chartered by Congress to promote Indian Energy development, efficiency and use, reduce or stabilize energy costs, enhance and strengthen Indian tribal energy and economic infrastructure, and bring electric power and services to Indian lands and homes. Next slide, please. 

To achieve our mission and address the barriers, the Office of Indian Energy offers financial assistance, typically through competitive grants; technical assistance offered at no charge to Indian tribes and tribal entities; and education and capacity building, of which this webinar series is one. Through these three prongs are intended to assist tribes and tribal entities overcome those unique regulatory, technical, and economic challenges in developing their vast energy resources if and how they so choose. Next slide, please. 

So last year, the office committed $75 million to 21 tribal energy projects across the nation. And prior to that, between 2010 and 2022 invested over 120 million in more than 200 tribal energy projects in the contiguous 48 states and Alaska. Through these grants, the Office of Indian Energy continues this efforts in partnership with Native communities to maximize the deployment of clean energy solutions for the benefit of those communities. 

Specifically, those projects have resulted in tangible benefits to over 100 American, Indian, and Alaska Native communities, which include nearly 46 megawatts of new generation, over $14.4 million collectively saved every year, and an estimated $350 million saved over the life of those systems. This results in a $3.38 savings for every dollar DOE invested and [INAUDIBLE] over 8,800 tribal buildings in the country. Next slide, please. 

And you can access energy-related opportunities offered through DOE, other agencies on our current funding opportunity page and download a funding flyer shown here, which is updated weekly. Next slide, please. 

So here's a sample of the opportunities that are open now. And you can see there's a lot of money through USDA, EPA, and others. I won't go into this, but you will have the slides. Or you can go to our Funding Opportunities page and download this yourself. Next slide, please. 

Again, more examples of wonderful opportunities for tribes to tribal entities, including the Tribal Energy Financing program, which has $20 billion available for loans and loan guarantees. Next slide, please. 

So in addition to the Office of Indian Energy funding opportunities, I wanted to bring your attention to a few resources. We do have, as I said, the Funding Opportunities page. It includes tribal energy-specific opportunities, not only through the Office of Indian Energy, throughout DOE and other federal agencies. You can also receive information on funding opportunities by subscribing to our email newsletter or access to the Weekly Funding Flyer, either online or through the email newsletter. 

There's also a Clean Energy Infrastructure program and Funding Opportunities page, and this identifies opportunities for the $97 billion through DOE, through the Bipartisan Infrastructure Law and Inflation Reduction Act and a more general website, which I think is wonderful, is the clearinghouse of all government opportunities, not only energy but for a variety of different areas is shown here on the energy communities website at that link. Next slide, please. 

So thank you all for your time and attention. Thank you for joining us today. You can reach the Office of Indian Energy through our help desk phone number and email at [email protected]. And submit your questions, and we'll have a Q&A at the end. You can also join us on social on Twitter and Facebook or at, I guess now, at DOE and Indian Energy. 

And before I turn it back to Brandon, I did want to personally thank all of the presenters for giving up their time and preparing for and presenting today's webinar. Thank you all. And with that, the virtual floor is yours. Brandon. 

BRANDON KIGER: Thanks, Lizana. Before we get started with the remaining presentations, I first want to introduce the other presenters on today's webinar. We just heard from Lizana. Our next speaker is Gabriela Rodriguez, who is a policy analyst at the US Department of Energy, Office of Energy Justice and Equity. 

In this role, she is assisting with the administration of the Low-Income Communities Bonus Credit Program by supporting the program stakeholder engagement efforts. Prior to this role, Gabriela assisted the Office of Energy Justice and Equity with the rollout of the Department of Justice40 programs through the creation of public-facing materials and development of the stakeholder engagement strategy. Gabriela received her masters of environmental management from the Yale School of Environment. 

Following Gabriela's presentation, we will hear from Brian Hirsch. Dr. Brian Hirsch is the president and founder of DeerStone Consulting, LLC, a renewable energy consulting firm focused on microgrid utility and community development in remote locations, especially in the arctic and the tropics. Recent and ongoing projects include developing solar photovoltaic, wind battery, diesel, hybrid systems across Alaska and providing technical support to Alaska Native regional organizations and other groups, covering over 120 communities across Alaska. 

DeerStone has helped clients secure over 260 million in clean energy funding in the last three years. From 2009 and 2015, he was a senior project leader for the National Renewable Energy Lab Alaska initiative and projects globally. 

Following Brian, we will hear from Ingemar Mathiasson. Originally from Sweden. Ingemar has lived in Alaska since 1987. Since 2009, Ingemar has continued his work with renewable energy as an energy manager for the Northwest Arctic Borough, managing multiple renewable energy projects in 11 communities, including a wind diesel project in Buckland and Deering since 2010, a 1.7 million solar PV project for all regional water plants in 2013, a biomass project in Ambler 2019, a heat pump pilot project and energy efficiency for all households in Ambler in 2020, Chinook's and Kobuk solar battery IPP 2021, and the Noatak solar battery IPP in 2023. 

He is the coordinator for the Northwest Arctic Energy Steering Committee. And that encompasses the communities of Kotzebue. Buckland, Deering, Noatak, Kivalina-- you're really testing me here, Ingemar-- Noorvik, Selawik, Kiana, Ambler, Chignik, and Kobuk. He acts as one board director on the Renewable Energy Alaska Project otherwise known as REAP. 

Following Ingemar, we will hear from Margie Schaff. Margie is a partner at Native Energy Resources Counsel, LLC, where she represents tribes and tribal organizations with tribal legal codes, tribal utility negotiations, electric power and transmission contracting, oil and gas, tribal energy resource development, business matters, and energy strategies. 

Margie has also been an energy attorney for over 30 years. She also assisted DOE with technical assistance requests related to tribal utility pre-feasibility studies. She also has published law review articles including the "Regulation of Electric Utilities on Indian Reservations" and "Indian Allotee Water Rights-- A Case Study of Allotments on the Former Malheur Indian Reservation." 

Finally, we will hear from Anthony Giacobbe, who is with the Seneca Energy. Anthony has over 20 years of experience in corporate strategic planning, project management, sales and marketing, and policymaking with national corporations. Over the last 10-plus years, Anthony has served as the director of Seneca Energy and Telecom at the Seneca Nation. In his role as a director, Anthony has managed distributed generation projects, developed a broadband network and related infrastructure, supply natural gas and electricity deliveries, negotiated interstate pipeline rights away, and conducted rate analysis, and implemented energy efficiency initiatives. 

Anthony serves as a member of the Department of Energy's Indian Country Energy and Infrastructure Working Group also known as ICEIWG, the Tribal Advisory Board, and the New York State Climate Impacts Assessment Team and the Climate Change Task Force of Seneca Nation. Anthony received his Bachelor of Science degree from Clarkson University in Potsdam, New York, and graduated with his masters degree from Canisius College in Buffalo, New York. 

Thank you to each of our presenters for making the time to join us today. As a reminder, please feel free to submit a question at any time by clicking on the Question button located at the webinar control panel on your screen and typing your question. We will answer your written questions at the end of today's final presentation. With that, let's get started with our next presentation. Gabby, you may proceed once your slides are up. 

GABRIELA RODRIGUEZ: Hi everyone, and welcome to this presentation on the Low-Income Communities Bonus Credit Program. We're so glad that you can join us today. Before I get started, I'd like to quickly thank the Office of Indian Energy for inviting us to talk to you all about this opportunity. 

Throughout this presentation, I will be referencing various documents and resources, including the 2024 revenue procedure for the program. You can also find these resources and the revenue procedure on the DOE program home page, which will also specify in this presentation. In addition, we will not be addressing any questions during this session. Towards the end of this presentation, I will be providing the email address of the DOE support desk, where your questions about this program may be submitted. Next slide. 

I'd like to quickly introduce myself. My name is Gabriela Rodriguez, and I'm a policy analyst with the Office of Energy Justice and Equity at the Department of Energy. I am here in DOE's capacity supporting the IRS in the administration of the program to provide you an overview of the Low-Income Communities Bonus Credit Program. Next slide. 

Before we dive in, we do want to provide the following disclaimer. Today's presentation provides an overview of the implementation of the Low-Income Communities Bonus Credit Program. This presentation will not cover all aspects of the program. Please refer to the official IRS guidance, the 2024 revenue procedure, and the Treasury regulations for complete information on eligibility requirements and the application process. 

The information provided in this presentation should not be considered tax advice or tax filing support. Please consult a tax professional, accountant, or attorney if you need tax-related assistance. Next slide. 

So here's for our-- here's our agenda for today. We'll first provide an overview of the program and then describe the application selection process. We'll then provide a short overview of the documentation and attestations needed to apply. 

And then we'll talk about the steps of the application process itself, which includes registration, submitting an application for allocation, and the steps to take once the facility is placed in service. And then we'll end by sharing some important dates and time frames to be aware of and some helpful program resources. Next slide. We will now walk through the program's overview. Next slide. 

So what is the Low-Income Community Bonus Credit Program? The Low-Income Communities Bonus Credit Program under Section 48(e) of the internal revenue code provides a process for owners of qualified solar or wind facilities to apply for an allocation of environmental justice, solar and wind capacity limitation. 

Section 48(e) generally provides for an increase to the investment tax credit under Section 48 of 10 or 20 percentage points for qualified solar and wind facilities that receive an allocation of capacity limitation. The Treasury regulations and the revenue procedure found on the IRS website and the DOE program homepage details the rules and process for owners of qualified solar or wind facilities to apply for an allocation of environmental justice solar and wind capacity limitation. 

DOE will review applications and make recommendations for eligible applications to the IRS. The IRS will annually allocate capacity limitation up to 1.8 gigawatts plus any carried over an allocated capacity limitation from the previous program year. Treasury and the IRS recently announced the distribution of that capacity limitation, which I will go over later in this presentation. Next slide. 

Treasury included three implementation goals for this program. They are to first increase the adoption of and access to renewable energy facilities in underserved and environmental justice communities. The second goal is to encourage new market participants. And the third is to provide substantial benefits to underserved communities and individuals who have been historically marginalized from economic opportunities and overburdened by environmental impacts. Next slide. 

The Inflation Reduction Act is the most significant legislation to combat climate change in American history. It is also one of the largest investments in the American economy in a generation, because the majority of these investments are delivered through tax incentives. The Treasury Department is honored to be at the forefront of implementing this landmark legislation. 

There are two pieces of guidance to best understand this program-- first, the final regulations; and secondly, the revenue procedure. These documents contain all of the information to determine program eligibility. The final regulations we released in 2023 remain the same regulations for 2024. The revenue procedure, though, is updated every program year as it describes the application process, all the documents and attestations that you will need to submit an application, and changes between program years. 

On August 10 of 2023, Treasury and the IRS released the final regulations and the 2023 revenue procedure. Then on March 29 of 2024, Treasury and the IRS released the revenue procedure for the 2024 program year with updates to the program. On May 13, 2024, Treasury announced that the 2024 program year would open and begin accepting applications on May 28. And then on May 28 of 2024, the 2024 program year opened, and the DOE began accepting applications. Next slide. 

So to be eligible for the program, an energy facility must be in one of four categories that qualify for either a 10% or 20% tax credit bonus. The 1.8 gigawatts of annual capacity is divided for the 2024 program year among the four categories in the following manner plus any carried over unallocated capacity limitation from the 2023 program year, which, as mentioned earlier, was announced recently. 

So first, 800 megawatts will be reserved for category 1, facilities located in low-income communities. Low-income communities is defined in the Treasury regulations and includes census tracts with a poverty rate of at least 20% or areas with a median family income no more than 80% of the state's median family income. 

Second, 200 megawatts will be reserved for category 2, facilities located on Indian land. Indian land is defined in the Energy Policy Act of 1992, which is linked to in the final regulations. Third, 224.8 megawatts will be reserved for category 3, facilities that are part of federally subsidized residential buildings. A list of eligible housing programs for this category is available in the final guidance and also separately on the DOE home page. 

And lastly, 900 megawatts is available for category 4, facilities where at least 50% of the financial benefits of the electricity produced go to households with incomes below 200% of the poverty line or below 80% of the area's median gross income. On the rightmost column, you will see the tax credit percentage boost that successful applicants would claim on top of the energy investment credit. This is 10% for category 1 and 2. And this is 20% for category 3 and 4. I'm sorry, next slide. Thank you. 

So to further our impact, we focus on the people and places disproportionately impacted by energy insecurity. We know that some parts of the country and some facility owners may need additional time to reach commercial readiness and put together competitive applications. Because of this, at least 50% of the program's capacity limitation in each facility category will be set aside for qualified solar or wind facilities that meet additional selection criteria. 

Using these set asides for additional selection criteria helps us meet the goals we outlined for the program. The additional selection criteria fall into two buckets. First is ownership criteria, and second is geographic criteria. Next slide. 

The first additional selection criteria is based on facility ownership. And it includes facilities owned by tribal enterprises, Alaska Native corporations, renewable energy cooperatives, qualified renewable energy companies, and qualified tax exempt entities. Please refer to the guidance for the exact definitions of each of these if you feel like you could qualify for it. Next slide. 

The second additional selection criteria is based on geography, and it includes facilities located in areas with the highest energy burden and the least investment. This is indicated by facilities that are located in persistent poverty counties or in areas that have high energy costs as determined by the energy category of the Climate and Economic Justice Screening Tool. A mapping tool is available on the DOE program homepage that helps the public identify whether a potential facility meets this additional selection criteria. Next slide. 

As mentioned, at least 50% of the program's capacity is set aside for facilities that meet additional selection criteria. In addition, the category 1 capacity limitation of 800 megawatts is subdivided. Category 1 facilities are subdivided with 500 megawatts of capacity reserved specifically for eligible residential behind the meter facilities, including rooftop solar. The remaining 300 megawatts of capacity distributed to category 1 is available for applicants with front of the meter facilities and non-residential behind the meter facilities that meet the requirements. 

When we refer to subreservations-- apologies. One second. When we refer to subreservations in this presentation and materials, we are referring to these category 1 subreservations. As demonstrated on this table, when submitting an application for the program, an applicant will choose which category and/or subreservation of the four categories their facility is eligible for and indicate if they are purporting to meet additional selection criteria in their applications. Next slide. 

Now we'll explain the application selection process. Next slide. So the 2024 program year began on Tuesday, May 28 at 9:00 AM Eastern Time. This is when it became available for registered applicants to submit applications for all four facility categories in the DOE's applicant portal. The applicant portal web address is https://eco.energy.gov/ejbonus. 

Once the application period opened for the 2024 program year, the initial 30-day period began, during which all applications would be treated as submitted on the same date and at the same time. In other words, there is no advantage to submitting an application on the first day or on the 30th day or any time in between. We want to encourage applicants to take their time filling out their applications to ensure they are complete and correct. 

The closing date of the initial 30-day period will be Thursday, June 27, 2024, at 11:59 PM Eastern Time. All applications submitted by 11:59 PM Eastern Time on the closing date will be considered submitted during this initial 30-day period. Next slide. 

After the 30-day period, applications submitted during these 30 days in oversubscribed facility categories and subreservations will enter a lottery. Next slide. 

Following the 30-day period, the rolling application period will begin. If there is remaining capacity in a facility category or subreservation after applications submitted in the first 30 days have been reviewed, DOE will review applications submitted in those facility categories or subreservations after the 30-day period. This will be reviewed in the order in which applications are received in a particular category or subreservation. 

The IRS will award capacity limitation allocations in the order that it receives recommendations from the DOE. DOE will continue to accept applications until the rolling application period closes. There is not yet a set date for when the rolling application period closes. This will be announced in the future. Importantly, the end of the program year does not coincide with the end of the calendar year. Next slide. 

As mentioned, at least 50% of the program's capacity in each category will be reserved for qualified facilities, meaning Additional Selection Criteria referred to as ASC for short. We recognize that in the first 30 days, we may receive more applications than capacity available, which is what we would call an oversubscription. If a category or subreservation is oversubscribed, a lottery will take place to determine the order of application review. 

Within the same category or sub reservation, applications That qualify for ASC will be given priority over applications that do not purport to meet ASC. So to better understand how we operationalize this, we have provided a category for example with three scenarios that could take place depending on the capacity received at the end of the 30-day period between ASC and non-ASC applications. You can find these slides on our website, which I will share at the end of this presentation. And we encourage you to take a look at these examples and these possible scenarios. Next slide. 

How is the review order for ASC applications determined in a lottery scenario? DOE will use lottery scores to determine which qualified facilities are eligible for a recommendation for an allocation of capacity if a facility category or subreservation is oversubscribed. If the eligible applications for capacity limitation for facilities that meet at least one or two additional selection criteria exceed the capacity limitation for a facility category or subreservation, applications purporting to meet both ASC receive a higher score so that they are given priority over other applications within each facility category or subreservation. 

If upon DOE review, it is determined that an application does not meet one or both ASC purported in their application, then the application score may be reduced, resulting in a change to the application's priority status. Remember, this ordering takes place for all ASC applications. However, the lottery only takes place if there is an oversubscription within the first 30 days and is only done within those oversubscribed categories and subreservations. All applications that are received after the initial 30-day window are ordered based on their submission timestamp. Next slide. 

Before we dive into the application process, we will now provide a short overview of the documentation and attestation requirements. Slide. There are certain documentation and attestation requirements that applicants must prepare for their applications. The application option chosen partly determines what documentation and attestation is needed from the applicant. 

Applicants submitting applications in the 2024 program year must submit the documentation specified in the 2024 revenue procedure. Documentation requirements are based on facility type, facility category, and additional selection criteria. An application is not complete and may be rejected if any documentation is not included. 

In addition to documentation, each applicant must complete the required attestations as specified in the 2024 revenue procedure. Similarly, attestations are also based on facility type, facility category, and additional selection criteria. An applicant will be unable to submit it there-- to submit their application if any required attestations are not completed. You can find these attestations in the 2024 revenue procedure. 

Additional documentation and attestations are also required for placed-in-service requirements, which occurs after an applicant has received an allocation for capacity limitation. Details can be found in the 2024 revenue procedure. Slide. Thank you. 

In addition to the documentation and attestations related to facility type and category, any applicant purporting to meet the additional selection criteria must submit additional required documentation and complete additional attestations. For ownership criteria with respect to all four categories, applicants must submit certain documentation to demonstrate that they meet the ownership criteria. For geographic criteria with respect to categories 1, 3, and 4, applicants must provide an attestation that the qualifying facility will be located in a persistent poverty county or in a census tract designated as disadvantaged in the Climate and Economic Justice Screening Tool. Next slide. 

We will now provide an overview of the application process. As a reminder, you can find much more detailed slides that explain the application process step by step on the program home page. Next slide. 

Here are the basic steps of the application process. The very first requirement for anyone who wishes to submit an application on behalf of their organization is to create an account with login.gov. This will grant you access to login to the DOE applicant portal to register and submit applications. Next slide. 

The registration process includes providing certain details about your organization. Slide. And at that point, you're able to apply for an allocation of capacity limitation by submitting applications for single qualifying solar and wind facilities. Next slide. 

The DOE review team will conduct an initial review of the application and provide a recommendation to the IRS to approve or deny the application based on whether it satisfies the required criteria. Additional documentation may be requested by the DOE review team. Once a recommendation is made, the IRS will review and issue an approval or denial letter for the facility. Slide. Thank you. And again, DOE we will make a recommendation to the IRS, who will then make a final eligibility determination. Next slide. 

The owner of the solar or wind facility is the applicant who must apply for an allocation of capacity. Provided the facility is determined to be eligible for an allocation and there is capacity available to allocate, the owner of the facility is the recipient of the allocation of capacity. Each application must be for a single facility. 

The individuals who apply for an allocation of capacity on behalf of their organization must have personal knowledge of the facts related to the application and be a person who is legally authorized to, one, bind the applicant entity for federal income tax purposes; two, communicate with about the application prior to and after submission; and three, receive notifications, letters, and other communications from DOE and the IRS. Please make sure that you understand the ownership structure of the project and comply with these requirements before moving forward with an application. Next slide. 

So after you successfully register your organization, you're then ready to submit an application for allocation. Once registered, applicants will select the applicable category and application option link for their facility. This will then generate the appropriate application for you, and applicants may view descriptions of each category. 

Each category has application options based on additional selection criteria and the appropriate subreservation. Please make sure you review the additional selection criteria requirements to ensure you have selected the appropriate application option. Next slide. 

Once an applicant's facility is placed in service, but prior to filing tax forms to claim the credit, applicants are required to submit additional information and complete the placed-in-service requirements. Next slide. 

Applicants will then be instructed to review their original application. Applicants will upload additional documentation, check attestations, and submit the information for review. The details of these documents and attestations can be found in the 2024 revenue procedure. 

Projects that are allocated capacity must follow the revenue procedure of the program year in which they received an allocation. So projects that are allocated capacity from the 2024 program year must follow the 2024 revenue procedure for all placed-in-service requirements. Next slide. 

So once the IRS has completed its review, applicants will receive a notification that the IRS has issued an eligibility or disqualification letter. That can be found within the applicant portal. If the IRS issues an eligibility letter, the applicant may claim the energy percentage increase on their applicable tax filing form. Please consult with the tax advisor to determine eligibility under the investment tax credit. 

Applicants may also make a transfer election or, if eligible, make an elective pay election. To make an elective pay election, additional steps are required outside of the 48(e) application process. Please see irs.gov//electivepay for more information. Next slide. 

We will end this section of the presentation by discussing the final steps in claiming the energy percentage increase. The applicant may claim the energy percentage increase on Form 3468, Investment Credit; or Form 3800, General Business. Secondly, the applicant may make a transfer election under Section 6418. 

And third, if eligible, the applicant may make an elective payment election under Section 6417. If an applicant will be making an elective pay election, again, additional steps are required outside of the 48(e) application process that can be found at the link on the slide. Next slide. 

We will now wrap up by discussing the program timeline and helpful program resources. Next slide. So here are some important key dates and frames. As stated earlier, on May 28, the applicant portal opened and the 30-day application window began. And on June 27, the initial 30-day application window will close at 11:59 PM Eastern. 

DOE will continue to accept applications on a rolling basis. Afterwards, lotteries will be conducted, and applicable subreservations and the program capacity dashboard will be published. It is not determined yet when, but then the 2024 program year will close. And DOE will no longer accept applications. Finally, IRS allocation letters will begin to be issued as soon as possible this program year. Next slide. 

The DOE has established a program home page, which I have mentioned throughout this presentation. On this program home page, you will find program information, the revenue procedure and Treasury regulations, program updates, access to the applicant portal, program resources, and the support desk contact information. The link to the program homepage is www.energy.gov/justice/low income communities bonus credit program. Next slide.

DOE's program home page also hosts a variety of very helpful program resources that are including, but not limited to these on this slide. I will highlight just a few of these. The first one is the Applicant Checklist. This is a handy, digestible checklist of information and materials to prepare to submit an application. 

Secondly, there is the Applicant User Guide. This has very detailed instructions and screenshots of each step of the application process. And third, there is the Frequently Asked Questions document. This document holds many, many common questions about the program and the application with detailed answers to those questions. Next slide. 

In addition, a public mapping tool has been created showing census tracts that meet the definition of category 1 low-income community eligibility and census tracts that meet the geographic additional selection criteria. As covered earlier in this presentation, the geographic additional selection criteria includes persistent poverty counties and census tracts that have been specifically identified as having a high energy burden by the Climate and Economic Justice Screening Tool's Energy Category. This mapping tool was created by our partners at NREL and is hosted, again, on the DOE's program home page. Next slide. 

I want to quickly take this opportunity to review some helpful reminders about the public mapping tool. First, the category 1 maps are identical to the new market tax credit maps. Secondly, the CEJST map includes eight categories of burden. Only the Energy Category is eligible for additional selection criteria. 

In addition, program-provided mapping resources are not available to identify Indian land. So you will need to reference the statutory definition of Indian land for category 2 eligibility. And lastly, we want to clarify that it is possible for facilities to qualify for geographic additional selection criteria, but not qualify for the category 1 definition of low-income community and vice versa. Next slide. 

Wrapping up here. I just also want to share the DOE support desk. For program-related questions and application assistance, applicants may contact the DOE support desk for the program. This email address is [email protected]. 

There is no dispute process for capacity allocation denial decisions or for determinations of an eligibility at the place-in-service stage. The DOE support desk is unable to provide tax advice, clarification, or interpretation of the regulations for Section 48(e) or any other IRS tax incentives or tax-related policies. Any questions requesting tax-related guidance or tax filing support should be directed to the applicant's tax professional accountant or attorney. And lastly, please don't contact the support desk for questions related to the status of an application or to submit program feedback. Next slide. 

So this concludes the content of my presentation. Thank you for your attention and interest. I want to emphasize that all questions about the program and what you heard about today should be forwarded to the email address listed. That is [email protected]. 

In addition, please, please visit the program home page for more information. That is where you can find the larger version of this entire slide deck on that link there on the slide. Thanks, again, so much. And looking forward to your participation in the program. 

BRANDON KIGER: Thanks, Gabriela, for sharing this opportunity with us. And just to let the audience know, I am dropping some of these links over in the chat box. So if you do have a question, you can copy the text there and then send your question to the help desk there. So thanks, again, Gabriela. 

GABRIELA RODRIGUEZ: Thank you. 

BRANDON KIGER: Yeah. Next, we will move on to Brian Hirsch with DeerStone consulting. And he's going to be-- yeah, you may go ahead and proceed once your slides are up there, Brian. 

BRIAN HIRSCH: Great. Thank you, Brandon. And good morning, at least from Alaska here. Good afternoon to you folks that are further East. Thank you all for your time and attendance today. I was asked to speak in particular about some unique situations in Alaska associated with some of the Department of Energy, Office of Indian Energy support that has been provided to many of the communities up here. 

And DeerStone Consulting works with really tribal communities across the entire state. And for folks not from Alaska, typically, the state is broken out into 12 different regions. And each of them has some unique aspects from Indigenous perspectives, both geographically as well as institutionally and things along those lines that we'll get into a little bit more in detail. 

This picture is of Ernie Tickett, the power plant operator in the village of Shungnak. Typically, a power plant operator is paid for somewhere between two and four hours a day, and that's it. And yet, they're expected to do a whole lot of things to keep the power running. 

And what we've been trying to do is get the power plant operators trained up, not just on diesel power plants, but also on some of the renewables. And here he's, obviously, inspecting and maintaining some of the solar array that is in the community of Shungnak and is receiving additional pay and training on the renewables' side of the power-producing effort. So we can maybe go to the next slide here. 

Again, a unique aspect of Alaska's power cost equalization-- and I apologize for all the words here, but there wasn't-- I couldn't figure out a better way to do this. Typically, in rural Alaska, electricity is much more expensive than in the urban areas. And the urban areas are the big cities-- Anchorage, Fairbanks, and Juneau. And most of rural Alaska is majority Indigenous tribal communities. 

And so there are some unique differences in the rural communities. They're typically dependent on diesel power and complex logistics for supply chain delivery of diesel fuel. And so that results in higher costs. 

There was widespread recognition within Alaska many years ago that that diesel dependence results in higher costs. And at the same time, urban Alaska had some energy needs around things like, for example, drilling for natural gas in Cook Inlet, near Anchorage. And the political deal that was cut was that the rural legislators would support natural gas drilling and other activities that reduced costs for energy in urban Alaska. And then the urban legislators would support power cost equalization for rural Alaska. 

It was kind of a very classic compromise, and everybody benefited from it. And so now the situation is that there has been established an endowment fund that currently is about a billion dollars for the Power Cost Equalization program. And that endowment fund does not get drawn from directly, but it generates revenue, kind of like a savings account. 

And that interest that is generated goes toward the subsidy of diesel fuel. And so historically, there's a relatively complex formula that is used to determine how the earnings from the endowment fund are allocated to. There's about 150 villages that are dependent on this PCE program. 

And so there's a relatively complex formula that allocates this earnings interest. And it's based, first and foremost, on the cost and the consumption in terms of the amount of diesel fuel. But there are also some non-fuel expenses around if you were to purchase power and/or how much you pay your local labor for operating and maintaining the power plant. 

So in general, though, historically, the way the formula worked in, say, the 1980s, when it was initially established, there weren't really many other options other than diesel fuel to produce power. Nowadays with renewable energy, the formula is sort of outdated in a way. Because what happens is it creates a perverse incentive. So if you save diesel fuel-- and hence, as a utility, you're saving money-- the result is that you get less of a payment back from the state. Because less diesel fuel equals less PCE funding. 

So the utilities were not really incentivized to save diesel fuel. And it was a penalty if you did so. And so what we've been trying to do is change that incentive structure so that there are incentives to save fuel and that everybody benefits from doing so. 

And what you see here in this picture is actually a site visit that was sponsored by Department of Energy, Office of Indian Energy many years ago here in 2012. And we see these things nowadays in terms of $10 per gallon, which sounds expensive now. In many places, gasoline is much more than that currently. 

And in this situation, people had to limit the amount that they were able to purchase to just 6 gallons a day. And you see here, that's in March of 2012. And typically, what happens is communities get a single delivery of diesel fuel for the entire year. And they do that when the ice-- when it's ice free, which is either on the river, if it's a barge, or on the ocean. 

And this is the community of Quinhagak, which is on the coast. And so they are dependent on a fuel barge coming there. And by March, it's almost a year since the last fuel delivery. And at that point, they have basically run out of fuel from their large fuel delivery on a barge. And what's happening, typically, in the spring time is communities are dependent on air delivery from airplanes for just a very small amount of fuel on a daily basis. So they have to start rationing gas. 

So that's what's going on here. So there are other incentives to saving fuel, not just the financial side here. It's just simply absolute limit of how much they have. So there are incentives to save fuel. But the financial incentive was not really aligned with that kind of structure. So we can move to the next slide. 

And so what's happened in the recent past is the evolution of independent power producers writ large. And then in many of the rural remote communities, in particular, the tribes have become the independent power producers, in part because of support from the Department of Energy's Office of Indian energy, where they have provided financial support for the tribe to install solar panels or put up wind turbines or even energy efficiency and weatherization so that there's just less fuel being consumed and the amount that's delivered in the ice free months is able to last for the entire year. 

So the tribal independent power producer develops and owns a renewable energy assets. And typically, without something like grant support from Office of Indian Energy, tribes aren't able to get this process started. And then what happens is the local utility signs a power purchase agreement that says, we're willing to buy power from the IPP. And then that purchased electricity that the utility is now buying is essentially the equivalent of buying diesel fuel, according to the power cost equalization formula. 

So the utility can count the power purchase the same way they count the diesel fuel purchase that they were previously burning. And they receive their full allocation of PCE. But now you have an independent power producer under the tribe that has received money because they have generated power and sold that power to the utility. 

So now the tribe has essentially a savings account or some amount of money that they can devote to maintaining and operating the renewable energy system, having a sinking fund so they can replace it over time. They can create a job associated with that. And they can do other things, perhaps distributing the funding in ways that result in reducing economic burdens on the tribal community and really the community writ large. So we can go to the next slide here. 

And so this is-- the numbers came from a particular community. And so we just looked at-- on the left side here, you have what the utilities annual expenses were in fuel and non-fuel costs. So 1.8 million in fuel, which is all the diesel fuel that's delivered; and 1.154 million in non-fuel costs-- paying their labor and collecting their bills and maintaining their equipment. 

If they put in a solar project in this case, it would result in a reduction of their fuel burn cost wise of $367,000. But because not all of the kilowatt hours that are sold are PCE eligible, some of them-- the way the Power Cost Equalization program works is it's a subsidy for residential ratepayers and for community facilities like, say, the tribal council building or the health clinic and things like that. But commercial facilities like a store as well as government facilities like, say, the post office are not eligible for PCE. 

So there's a split between how this whole thing works. And again, it gets kind of complicated. We won't get too far into the details. But the upshot is that the utility would have burned $367,000 less in diesel fuel, but they lose 110,000 in PCE reimbursement if there's no independent power producer in the mix. So if you're the utility, you look at that. And you say, well, great, we saved some fuel, but we're losing money on that, basically. 

So if you go to the next slide, what we have here is if you structure the process correctly and the IPP is involved, the electric utility would buy that $367,000 that was saved in fuel. They would now purchase that from the IPP. And they would receive that reimbursement back from the state in the form of power cost equalization payments. 

So we can go to the next slide here. And so this is just a roll-up of how that works. And so PCE reimbursement to the utility, the first case on the left here is just 100% diesel. In the second case, the fuel costs with no IPP, that's what the utility would spend on their diesel fuel, but they wouldn't get any other reimbursement. So they're essentially losing money, even though they're burning less fuel. 

And then on the right-hand column, the IPP would be taking care of that whole power need, but it would not be generated from diesel. It would be generated from solar. And then the utility is still made whole from their original expenses and revenues from both selling power and receiving PCE allocation from the state. 

So we can move to the next slide, please. And so again, this is just another view of how that works. And so this analysis was performed prior to the community thinking through-- prior to the community developing the solar project. And so this analysis was used actually in both grant applications as well as city and tribal council meetings and utility management meetings to help understand both the size of a potential solar project, as well as the kind of economic implications of who would benefit and who would not benefit from this sort of a process. 

So it was-- we've developed an analytical tool kit to plug in what your existing-- what your fuel costs are, what your power generation portfolio looks like, what your solar potential would be based on the size of your solar system, how much fuel you would save, and when you need a battery. 

Because the other thing is that when your utility system is all diesel generation and you start putting other inputs into the system like solar, as soon as you get to a relatively large portion, like plus 20 or-- yeah, 20% or 30% or more of the entire generation at any moment in time, if that's solar, your system can start to be unstable. And so the diesel generator is always chasing the amount of solar because it's not a steady state production. 

So as that varies, and the larger the solar system, the more it will vary relative to the diesel, you need batteries to stabilize the whole system. And the goal at some point is for parts of the day, in the summertime, in particular, you just completely shut the diesel generators off. And the whole system is run by solar and batteries. 

And so under those circumstances, well, A, you need a battery. And B, the solar, you can start to plan for a relatively large solar system. Whereas without batteries, you're limited to a much smaller overall size because you're always trying to maintain stability from the diesel generation. 

So we can move to the next slide. And so this talks a little bit about that. And again, this was developed for a particular community to really think through what the options are in terms of a utility ownership versus an IPP ownership of the renewable asset. 

And so typically, what we find is initially, the utility is hesitant to jump into this mix. But if you're a utility and you're looking at somebody eating into your revenue stream and then you're dependent on this other entity to generate power that's going to your customers, et cetera, initially, you'll have some real understandable reservations about doing so. 

And what we've been able to do is, A, alleviate some of the utility's concerns from the economic standpoint by showing this kind of analysis; and, B, having some long-term partnerships and some technical credibility so that the utility feels comfortable with the tribe and the technical support that's involved between engineering and administration and things along those lines that they're willing to enter into a long-term power purchase agreement. 

So I'm not going to get into the details here, but these are the kinds of issues that would be addressed and ideally build confidence on both parties to establish a power purchase agreement. So we can move to the next slide. 

And these are just some pictures from the Northwest arctic region, which I think we're going to hear a lot more about that from the next presenter, my colleague Ingemar Mathiasson, who we work very closely with. But here are some of the solar installations, battery installations. And in the lower left-hand corner, you see the community of Shungnak with the solar array oriented in a few different directions to take advantage of the sun moving very widely across the sky in the arctic and having less impact on the electric utility because of the stability issue that I mentioned earlier. 

This is a relatively large solar array compared to the diesel generation. And if all the solar panels were oriented in one direction and the sun went behind a cloud, for example, the diesel generator would have to instantly turn on. Or there'd be a lot more of an impact on the battery than with the orientation that the way the solar panels are there. 

So there's a lot more detail to that. And that's been an evolution of other projects and lessons learned. But it's another unique feature of far Northern solar projects. So we can move on to the next slide. 

And this is an animated slide. So you can just start hitting return for a while, and we're going to see some growth of the different activities. And again, this is focused on the Northwest Arctic. And yeah, there's one or two more of these, I think, that you can hit. 

And so yeah, maybe stop right there for a moment. And what we see is from 2013, this was a glimmer primarily in Ingemar Mathiasson's eye and some of the tribal communities. And they were able to put solar PV on the water facilities in all of the communities in the Northwest Arctic. 

And as we learned lessons and got better at writing grants and dealing with the financial side of things, recently, the Department of Energy, Office of Clean Energy Demonstrations awarded a quite large grant to the Northwest Arctic-- to the Northwest Arctic Borough, in particular, and all of the villages within it. And we're now looking at over 7 megawatts of solar that will be implemented in the region. 

And I think you can hit return a few more times. And we'll see just a couple projects, some pictures of the projects going across the top of the screen there. So you see some of the different projects that we were talking about earlier. OK, next slide, please. 

Yeah, so what I want to share here is an entirely other region and a different approach to the same concept. And so this is focused on the Bristol Bay region, where we're also doing a lot of work with really all the communities in the regional entities. And in this case, what we have is a very, I guess, diverse situation where you see at the top there, Naknek and Nushagak. 

Those are the two largest utilities and communities in the region. And the rest of the communities are much, much, much smaller. And so the bigger utilities have some advantages and some challenges. But in this case, what we found for the most part is some advantages compared to the much smaller communities. And this is a justification for communities to work together and to try to create an economy of scale so that some of the efforts, for example, that have been successful in the Northwest Arctic can be reproduced here. 

And so the two largest communities have-- Bristol Bay, many people probably know is the home to the largest commercial salmon runs in the country and some of the largest in the world. And so there is a lot of commercial fish processing in the villages of Naknek and Nushagak, which is also Dillingham is the other name for it. And so those two communities on an annual basis have a much larger, 30 times larger load than many of the other communities, 70 kilowatts versus 2.4mw kilowatts. 

So if we move to the next slide, what you'll see is that that distribution of power, however, is very uneven. And because of fish processing, the month of July, which is coming right up here, is when the majority of the commercial fish processing occurs. And so in the two communities of Naknek and Nushagak, they have a substantially larger demand for just literally one month a year. 

So to some degree, arguably, the obvious solution or a potential solution is a lot of solar power. In the month of July in Alaska, we have almost 24 hours a day of solar, which in many other parts of Alaska, the electricity demand is much higher in the winter time than the summertime. So solar doesn't do you a whole lot in the time when you have high demand. 

But in these communities where there is commercial fishing-- and you can see right at the bottom there, Naknek Electric, Nushagak Electric, and the other kind of large bars up above that line there are Chignik and Egegik. And those four communities all have commercial fish processing. And so that's really what we see. 

And that's, on one hand, a real challenge. If you have a 450% increase for one month of the year, you need lots of diesel generators for that one month of year. And the rest of the time, they're sitting idle. And at the same time, it's an opportunity, as just mentioned, because you can maybe meet a lot of that demand with solar. 

So we can move on to the next slide here. And so what you see here, the black in particular is the percentage, not the dollar amount, but the percentage of individual utility's expenses that are related to the fuel cost. And so for example, you see there maybe a third of the way down, Koliganek. Over probably 2/3 of their entire cost for electricity is because of diesel fuel. 

And communities have different percentages here for all sorts of reasons. Some of the diesel generators are more or less efficient than other places. Fuel delivery is much more complex than some places where they have to fly in all of their fuel, whereas other communities can get ocean and river barges fueled in-- of fuel shipped in. 

So there's some real variation here. But again, if you start thinking about that target for power cost equalization, communities that are spending a lot of their percentage costs on fuel are good targets for trying to help maybe establish an independent power producer with renewables and really knocking down that fuel cost and still getting that funding coming into the community through the PCE allocation. 

So we can move to the next slide here. And what we see here now is not just the percentage, but the actual rates. The dark blue is what people are paying after PCE. And the entire bar, both the dark blue and the light blue, is what it actually costs the utility. 

So what you're seeing is some of the communities have a much higher rate than others on both the effective rate, which is with PCE subsidy; or the other one is without the PCE subsidy. But what we're seeing in many situations, for example, Nushagak and Naknek there, if you see near the bottom, their average effective residential rate is $0.26 a kilowatt hour. 

Now this is several years ago. So that's probably gone up a little bit. Because fuel costs have gone up, et cetera. And the PCE floor has gone up as well. Because power has increased in Anchorage, Juneau, and Fairbanks. And PCE is based in part on what those three urban areas are spending. 

So anyway, that's a nuance. But the other communities, the effective rate is $0.36. And when you look at the full cost, it's 44 versus 71. So clearly, larger utilities there have a lower fuel price-- or a lower overall electricity price for a whole host of reasons. 

So we can move on to the next slide. And so what we've done is really dig into why and how that happens and where the opportunities from the utility side as well as the IPP side. But really, right now, we're just primarily looking at the utilities. Because frankly, a lot of them are really struggling with very high fuel costs and some, well, high electricity costs as well as deferred maintenance and just basic reliability of the systems. 

Communities are really struggling. They maybe have three or four diesel generators in their power plant. And all of them, except one of them, are not working as they often go into the winter. And so then they'll have extended outages when it's 10 or 20 below 0 outside. And there's some real emergencies that occur under those circumstances. 

So we tried to identify the challenges here and the opportunities, So for example, in the larger utilities, they have more trained personnel. And they can afford to pay higher rates for people. And they have real need in the summertime because of those commercial fishing situations. Whereas in the smaller communities, they still have winter peaking demand. And they have a lot of need in the wintertime for trained personnel. 

So we've looked at maybe we could trade off where the larger utilities have personnel for diesel mechanics or people working on the power lines and things like, that they're hired through the larger utilities. But in the wintertime, the smaller utilities could essentially lease them out. And that's cheaper than flying people in from Anchorage. There's more ready response, things along those lines. 

Also for things like, say, filing your PCE report-- because if you don't file it every month with the state, then you don't get the money, even if you deserve it, essentially, if you have all of your other ducks lined up. If you don't file the reports and what-- somebody who's looking at this-- and they said, jeez, this is like filing our taxes every month of the year. 

And so it's a real challenge. It's an administrative burden to do so. And yet, some people get really good at it. So you could have-- for example, you could imagine a situation where there's one or two or three people that file everybody's PCE reports every month. And that's just what they do, and they get good at it. And we develop computer programs into it and just streamline that process. 

So we can move to the next slide. And I guess what I should say is that these activities were funded in large part through the Bureau of Indian Affairs, Tribal Energy Development Capacity Grant. And the Bristol Bay Native Corporation was the entity that received the grants, and that's also supported a lot of this work. 

And so we've prioritized these activities to say, this is where you can really save money and fuel and reduce emergencies. And we've lined out actual dollars and cents and some real activities that could really reduce the stress of people trying to provide these services for the communities. So we can move on to the next slide. 

And so what we've come up with is this shared services approach to managing rural power utilities. And so we've now turned this into a pilot project with five individual communities, and now we're looking at spreading it around at least part of the entire Bristol Bay region. And it's being facilitated in part also by Department of Energy's Office of Grid Resilience. 

So some of the tribal formula funding that some people call 40101(d) funding is helping to aggregate and create a consortium of tribes to aggregate their utility services while they all still maintain their ownership. We're trying to create a situation where you have shared resources and outsourcing the defined roles and responsibilities to people who do this all the time. And so we can move on to the next slide here. 

And so it's really just getting started. But here's all the kinds of activities that we've identified that this utility collaborative could assist the individual villages with performing. And so there's classic governance and management issues. 

There's nuts and bolts on PCE so that all the communities can get all of the-- right now we've identified millions of dollars at communities are leaving on the table with PCE, that if they filed all their reports and really got into the nitty-gritty of all of it, they'd be able to maximize that PCE subsidy. And there'd be a lot more funding coming into the communities for improving their energy systems and paying people and reducing emergencies, things along those lines. 

And really, down the road here to the right in terms of power supply, the long-term goal is to help communities transition to renewables. And without having your diesel power plants running properly, it's essentially impossible to fully optimize renewables. So moving on to the next slide here. 

What we've done so far is create a pilot project with five villages. And we've started to really implement these activities. And we are now expanding this to 17 communities in essentially half of the Bristol Bay region under what's called the Lake and Peninsula Borough. That's similar to the Northwest Arctic Borough in the Northwest Arctic. And this is just another local government in the Bristol Bay region. And then the hope is to really expand this to all of communities that want to participate. 

So we can move on to maybe the last slide, I think. Yeah, so that's what I got. Thank you, everybody. 

BRANDON KIGER: Thanks, Brian. It's really exciting to see the progress being made there and how you're expanding that. And to complete all the completed projects, that's an exciting, positive arc, that one graph you showed, so. Next to carry on to this conversation, we have Ingemar Mathiasson. He is going to be discussing a case study on how communities using the IPPs have allowed Northwest Arctic Borough to build out several clean energy projects. Ingemar, you may perceive once your slides are up. 

INGEMAR MATHIASSON: Thank you very much in allowing me to present at this webinar-- appreciate it-- and all the support we have from DOE. I'll be following in the excellent report from Brian Hirsch, my partner in the energy business. And the PCE that he presented looked really, really good. So you can go to the next slide. 

So of course, I just want to put this one in. Because we have our energy steering committee. And it's very important to remember that it's not the most adaptable-- it is the most adaptable to change that lives within means available and works cooperatively against common threats that survives. 

And another thing, we don't necessarily need to cling to old resources if you know they're endangering you. And I'm, of course, referring to oil in this case. Next one. 

Some background and what we're looking at and what we have looked at for 16 years now since 2008. I have this star here for 2008, and then there's the next star for 2024. This is the outside oil representation of the world, basically. Brent fuel, Brent oil, and the cost that has been up and down over time. I want to compare that to what's happening in the Northwest Arctic. Next one. 

And in our case, it doesn't go up and down necessarily. It just keeps going up. And the picture for 2024, '25 is higher than that. It's the average prices per gallon now in the Northwest Arctic, and it's getting critical for survival. We can do the next one. 

We had a vision in the beginning, in 2008, that we were going to try to be 50% reliant on regionally available energy sources, both renewable and non-renewable, for heating and generation purposes by 2050. And then we added in 2016 to a combat rapid climate change due to greenhouse gas emissions like CO2, methane, and other harmful effects of fossil fuel usage. 

It is interesting to note here that in 2008, we did not look at the climate issues. They started to pop up between 2012 and 2016. The progression is as follows-- 10% decrease by imported diesel fuel by next year, 2025, and we're on track for that; 25% decrease for imported diesel fuels by 2030; and hopefully 50% decrease by 2050. The next one. 

Fuel prices currently as they stand. Even five or six years ago, I was looking at these prices. And I was telling myself, if the villages was going over $15 a gallon, survival is just not going to be possible. We have Ambler at 18 right now and Kobuk at 15 and Noatak at 14. And it keeps increasing. It is not a good situation. We're trying to do everything we can to bring down the cost of fuel. Fuel is, of course, the base for the electrification also. So we can go to the next page. 

And here we see the prices that are according to that. Kobuk, Shungnak at the dollar, if you look at the middle column, at 0 to 750 kilowatt hours. Without tax, you'll see the actual cost of electricity in the villages. And in Kobuk, Shungnak is just around $1. And Noatak at 1.20 at this point. The red marks in there is increases since the previous year. And these things just keeps increasing slowly but surely. 

I should also note that the end, at the far end there, you'll see utility non-firm power purchase rates, referring to the IPP buyback rate in the case of the communities for what the utility is willing to buy the renewable electricity for. And if you look at Shungnak, for example, that I will show here, you'll see the actual cost is over $1. But the buyback is $0.65, 0.6479. And that's the avoided diesel cost right there. That's referred to that. 

I should note one thing here. In Brian's presentation, it showed a little bit the differences between utilities operation with alternate energy versus the IPPs. And one thing that I wanted to add there is that if you look at the electric rates for households with PCE at 1 to 750 kilowatt hours first column, that rate never did change over the 16 years. It's slowly, slowly increased instead. And no matter what any utility did to bring down cost of electricity by renewables, it just kept increasing. 

Because of the PCE formula sitting in the way, it always balances out to what it should be across all the villages of Alaska. And what did go down is instead the full base rate that then impacted, of course, commercial operations and schools. They benefited from having the utility, having the renewable energy, but the households did not up until what we are doing with the IPPs at this point. The next one. 

In 1997, Kotzebue was leading the way with the first wind farm-- this is just some background-- to reduce the need for the fuel. Next one. And in 2008 to 2015, we built some diesel project in Buckland and Deering. If we had looked closely at the grant in small print at the bottom, it said, "As a condition of the grant, independent power producer can agree to sell the energy resources for electricity and heat at a cost base straight for the economic life of the project." 

But we were not even thinking about IPPs back then. All these projects were made for utilities. And this little note here, even though in 2008 it was there, there were no IPPs in Alaska at that time. The first one actually happened with Fire Island later on in 2012. Next one. 

In 2012, up in the borough, we put together the solar project that proved to Washington and everybody else around the nation that Alaska was not dark, that we actually could have good solar power up in Alaska. And that project has been going well through all the years. Most of the arrays are still functional. We're going to have an update on that this year to go through them and make sure everything is working fine. 

But the different variations of how we put together those arrays showed us the way to what we needed to do. The semicircular one in the middle, you can see there is a Deering on a water tank. It has a wonderful power curve, perfect for the innovation, and takes the sun in 180 degrees as it goes around up in the arctic. Next one. 

So village independent power producers. We started to think about it as the Buckland and Deering project started to happening. The next one. 

And in 2021, we put together this Shungnak-Kobuk project. And this will be the update on it. You had some seen some pictures of this, of course, before. Next one. 

In 2021, a grant opportunity from USA High Energy Cost Grants was secured by the two tribes by allowing the borough, NAB, to apply on behalf of the communities. The communities are interconnected with power lines. So the proposed solar project benefits both of them. 

Through an MOA of a working agreement was executed between the two tribes to become an IPP, an Independent Power Producer. And a power purchase agreement was then executed with AVEC, the Alaska Village Electric Cooperative. And AVEC pays for the solar power and recover the cost then partly from the PCE fund. 

Another MOA was then executed with the borough for help with administration and investment of funds. And investment in energy fund was established for the communities. And then funds are dispersed as needed for insurance, maintenance, and eventual build out of the solar array. Next one. 

Here's a snapshot. As of the end of April 2024, since commissioning in '21, in September, 457 megawatt hours of electricity has been generated, equal to 32,643 gallons not needed. 319 tons of CO2 offset, together with a total of 1,473 hours of diesel off operation equal to just about two months of alternate energy. That is then you continuously. You can see about 11 hours diesel off picture of what the data controller shows on Shungnak there in that picture. Next one. 

This was fiscal year '22, first for the Shungnak operation. Estimated gross input from the revenue at 120,000 sold to AVEC, insurance 3,700, electric 1,900, Ageto service fee of 3,242, tribal employee 8,600, fuel to heat the battery building $3,000, total estimated expenses 20,805, net income at 100,000, estimated admin fee at 9,000, annual income less admin fee $89,000. Current status on the saving account is about 152,000 for Shungnak at this point as they continue operation in 2024. Next one. 

And we got awards for it. The most equitable community solar array in 2020, I think; and 2021, the best built award of the year. It was great to be recognized for that when we went down to San Diego. Excellent. 

So why develop independent power producers? Well, energy sovereignty. The community is taking control of their own energy future, creates buy-in and a good relationship with the utility; being able to sustain PCE support to the communities and stabilize the energy cost; better economics.

Funding collected pays for further development and local workforce expertise. The money stays in the community instead of sending the money to far off countries. It becomes a circular economy. Use it right there. And it really ties together the community, where before, utility, in particular, if it was operated like AVEC from Anchorage, it was disconnected from the community in a way where people weren't involved as much as they are now. 

It also connects the two tribal and city governments in our villages better where they share in the proceeds from the IPP as it sits usually on city land. And then there is lease agreements between the tribe and the city. So everybody is working together for our energy future. And this creates the energy sovereignty we're looking for. Next one. 

So a reason for regional approach, energy unity. Regional support apply and manage energy grants, including access to Department of Energy and other funding, economy of scale and increasing efficiency. Small single project are too expensive. Develop regional energy infrastructure with wind, solar, hydro, interties, bulk fuel storage, and direct household investments. Next one. 

Energy security, administration help for Independent Power Producers, IPPs, for PC calculations and utility rates and billing. Brian referred to what he was doing in the other communities down in the Southwest there. And job creation, workforce development and training, capacity building-- and the region speaking with one voice can advocate on behalf of the PCE going forward. And statewide energy policy-- and this is all needed to stop the increasing cost of energy and hedge against the fuel increases and supply disruptions. Next one. 

So this is our outlay of how we operate now, the Northwest Arctic Independent Power Producer organization. You have the ones that are up and running. Noatak and Shungnak and Deering in red. Buckland just signed their IPP contracts and is now becoming an IPP also. And Ambler and Selawik will follow. They are the beginners of what will become eventually 11 communities in the IPP controlled. 

And the steering committee will morph into basically an organ of creating your own energy for the future, little more powerful than it was in the beginning when it was just starting to speak with one voice. We're getting stronger that way all the time. 

And you can see how the energy flows. The power purchase agreement-- IPP revenues from utilities goes to the investment fund and then back. And all of it overseen by the borough and the steering committee itself. 

We also have the REPOP program started under USDA. We started a program for service training, repair, maintenance equipment, local job creation, and grant writing and administration. And we now have one person fully employed in that particular position to hold together the IPPs, be the go-to person if any issue shows up, and connect the network. The next one. 

The Noatak Solar IPP Project followed Shungnak and is now up and running since last year. Basically, 650-watt panels of a total of 300-- sorry, about 280.6 DC, 250 kilowatt AC power, together with Kronus Pylontech KFO battery at 442 kilowatt hours capable to hold the communities for two hours without generators or solar power and with room for expansion to capacity of 500 kilowatt hours at 500 kilowatt, 352 kilowatt hours. 

Starting construction was in September '22 and completed in August of '23. Total cost, 2.946 million, of multiple grant sources and in-kinds have funded that grant. Next one. 

Here's a blessing picture by the elders, where they bless the array and the battery. Next one. And here a power outage avoidance that nobody even noticed. It's just a shot from the yellow controller in Noatak, where there was a momentary half-hour off on the generators. And the battery kicked in and took care of the problem, and power was flowing. Next one. 

So in the Northwest Arctic, how much is clean, renewable electric energy now? Well, 11% renewable in 2023. You can see Kotzebue itself, which is KEA, Kotzebue Electric Association. And then there's some slivers next to it and then spread out by community on the left. 

Shungnak and Kobuk actually are producing 11% of their electricity from the sun. Kotzebue does 19% to 30%, depending on wind and solar. Noorvik has 0.6%, Deering at 17%, and Buckland at 10%. So Buckland, Deering, and Kotzebue has wind turbines also and varies a little bit year by year, depending on wind conditions. The sun is more consistent, of course. And we'll look at it what it's going to look like into the future here. So the next picture. 

OCED request that we is now working to finalize. Total project budget of 68 and 1/2 million or 54.8 is coming from the DOE OCED. There is cost shares, 5 millions from the NANA Regional Corporation and 5 million from the borough, that we set aside for this project. AVEC has a cost share of 1.887 and Kotzebue Electric 1.8. And a total of 13.7 million in cost shares, 20% of the project. Next one. 

Preliminary timeline for this. 2024, upgrade Noatak and with some heat pumps is actually delayed to 2025. 2025, we're looking at Selawik and Ambler and heat pumps. 2026, construction of Noorvik, upgrade Deering, and heat pumps. And '27, Kiana, upgrade Buckland, and heat pumps. '28, construction of Kivalina and upgrade Shungnak. And in 2029 to 2030, close out approximately. And the next one. 

From that, we would end up with something like this. Estimated IPP production per year at full build-out of all communities. You can see the gallon offset at about 328,214 gallons at full build-out, with a total estimated IPP annual revenue between all of them at about 1.8 million that we then would save coming in from the PCE front that would be lost if this project was built under the utility only. Then that 1.8 million would stay in the PCE fund and would not go to the communities. 

So basically, by doing the IPP build-out, it makes sure that that money from the PCE fund stays with the community so that it can be used for service maintenance and upkeep of it and, at the same time, give some local jobs. Well, the next one. 

So this is what it would look like after. In 2028, we would go to 21% for all the whole region, for all 11 villages, including Kotzebue. 21% renewables for electricity by 2028. And you can see that most of the villages will stay between 20% and 27%, I think, is the highest one at Ambler. Percent of their power for electricity would come from the sun or wind combination. 

So that's the outcome of this project. Once we're completing it four or five years from now, that will get a quarter of our electricity from renewables. And that is a pretty good deal. The next one. 

The Energy Steering Committee keeps going, 16 years and going and continue to work with all the regions communities to hold it all together. It's the vision for the future. Make sure the documents get updated. And it's a dynamic living document. This is the energy plan. And needs to be able to adapt to the changes. 

We continue to make a sustained effort and realize that change comes slowly with understanding of new ways of operation. We constantly looking at new technology all the time. We thought in the beginning, well, maybe we could make sure that everybody, all communities, has the same kind of equipment for sharing. 

But the fact is, actually, that it takes a long time to put in these project and that the technology is advancing so fast that just isn't going to happen. It will be different equipment in the communities. And we have to live with that dynamic change like everything else. 

We also have to realize that the energy plan is dynamic and needs to be revised itself as new energy sources and thinking comes along. Hopefully, it will be never completed. And as you get project up and running, used them for education and community participation, so what's the policy? 

We need a clear vision for the future from the people, for the people. And this is the IPP operations. Do we develop energy resources for short-term profits? Or do we develop energy resources that can sustain the region for the foreseeable future and create that cleaner environment for our children? 

And the next one is probably the last one. And thank you. 

BRANDON KIGER: Thanks, Ingemar, for sharing us those case studies and great examples. You guys are going to be busy for a while, it looks like. So next, we're going to move to the Lower 48. We have Margie Schaff, who will be talking about technical assistance that is available and some other great stuff. So, Margie, you may proceed once your slides are up. 

MARGIE SCHAFF: All right. Well, happy Wednesday, everyone. My name is Margie Schaff. And I'm an attorney with the Native Energy Resources Counsel. My partner, Evan DeWitt, and I represent a number of tribes in the Lower 48 doing energy projects in tribal utilities. I also do some work with NREL in assisting with the technical assistance programs, which is what they asked me to talk about today. So please, next slide. 

So a little bit about the TA program. It's approximately 40 hours of free technical assistance. The work that we do results generally in a pre-feasibility study for a tribal utility or sometimes for other energy projects. There's the link to signing up. It's a very simple email to send in your request. And as I said, they will do technical assistance for tribal utility formation, a pre-feasibility study. But there's also technical assistance in all kinds of other things that are done by other subcontractors and other folks throughout the DOE. 

I do mostly the tribal utility pre-feasibility studies. And these studies have been changing over the last number of years simply because the tribal utility is evolving. What is a tribal utility? It's really any entity that administers a tribal energy project. Next slide, please. 

So here are some example topics in the technical assistance reports. And I've tried to do just a little overview for those of you listening in on the webinar. Next slide. 

So the first thing that we always tackle are the regulatory questions. Because when you're starting a utility, you're doing some kind of an energy project, it's really good to know what regulations apply to you. So the first question is, what is federally regulated, and what is locally regulated? 

Anything that's interstate or wholesale is federal. And anything that is intrastate, inside the state or retail, is local. That's a general rule, of course. And if it's locally regulated, the question then becomes, is it state regulated, or is it tribally regulated? 

Generally, on-reservation services can be regulated under a tribe's jurisdiction. And states have commonly exercised jurisdiction over all the utility companies, including the utility rates and services. And so as most tribes have not had similar regulations, the state regulations have been applied, whether or not that's exactly what the tribe wants to have happen. Tribes may develop, however, a legal framework through tribal law to a certain implement their jurisdiction. Next slide, please. 

So a little bit more about the federal matters. This is just a list. Because these slides will be up on the website, I won't go through them really carefully. But anyway, it's just anything that's more utility scale or on the transmission side. Next slide, please. 

Here are some of the local matters. One of the main issues that we always find in these kinds of reports are questions about state taxes. What of your utility products should be paying taxes? And generally, tribe should not be paying any state taxes on products and services delivered to them. That's of course, for energy products and for other things. 

And so what we found that is in a lot of the state-approved utility tariffs, there are a lot of state programs that are included. And to what extent these are state taxes that should not be applied to tribes is a question for your lawyers to work with. 

Some of the other local matters are anything that's behind the meter like a customer meter, that kind of generation like small projects on rooftop solars, any kind of distribution lines and substations that are within the utility boundary that don't cross state lines. The rates in the tariffs are also local, unless, of course, it's a federal utility. Service territories are either tribal or state and then other state programs. Next slide. 

So some tribal authorities over energy matters include the tribal laws, the codes and ordinances the tribe can pass that govern your utility activities. Some tribes have regulatory commissions. Some tribes have franchise agreements with their utilities. And then, of course, you can negotiate with your utilities. 

The taxation, I've already talked about a little bit. The tribe's ability to change their utility company, including to change to their own utility company, is a tribal authority. And then, of course, leveraging things like right of ways and other activities that a utility may have on the reservation can be leveraged to make sure that the utilities do what the tribes like. Of course, tribes also, as sovereigns, have an eminent domain opportunity and authority. Next slide. 

Sometimes we get asked technical assistance questions about these common regulatory problems. And I've made a list here of things that we've heard a number of times-- how utilities are not comfortable with tribal sovereignty or regulation. And they really have to be convinced that the tribe has regulatory authority. So we try to give people background information that will help their attorneys negotiate these things or their other folks. 

State direction to their regulated utilities regarding the tribes is often not clear. Utility tariffs sometimes undermine tribal goals and projects. So we try to help tribes understand what those utility tariffs are and how they have been created and ways to potentially remove that barrier. 

Wholesale distribution is another issue. And that's using a distribution system, the small poles and wires to deliver wholesale power. That then becomes federal because it is a wholesale service, even though it's on smaller facilities owned by a smaller utility. Sometimes state-created service territories create a problem for tribes. State tariffs contain those taxes, which I mentioned. 

And then the other issue can be departing load charges, which is when a tribal utility or other service takes over an existing IOU service territory. Sometimes the state allows those utilities to charge a departing load charge, which is essentially a way for them to recover some of their profit and so forth from losing those customers. So there are certainly jurisdictional questions about that. And many tribal utilities are facing those questions. Next slide, please. 

So here are just some traditional elements of a tribal utility. We always talk about these different things in these pre-feasibility studies, because it's important to understand the difference between your regulatory piece and the different functions of your utility and compartmentalize them for things like rates and even in understanding your utility bills. 

So the first element is your customer and your load. You have to know how much load you're going that you're using now, how much electricity you're using now, plus what your loads will be if you create a utility or if you create an energy project that's going to serve a group of folks. You really need to understand what your loads are. 

The next element of a traditional utility is a power source. These can be federally or locally regulated, depending on the size or configuration. Next is transmission, getting that power source if it is a distance away to your customer base or to your meter. 

And again, transmission is federally regulated. It's deemed to be interstate. And so even though it may be a small transmission line, that just goes for a short ways, it is still part of the grid. So it is considered to be transmission and federally regulated. Then from the transmission system down to your customers is the distribution system. And that part is locally regulated. 

The last piece of a tribal utility is its administration. And so what we found is that the administration piece is becoming more and more part of the questions for tribal utilities, because not all of these elements anymore are required to form a utility. For example, you can just have a power source and a few customers, but you still have to administer it. Or you can have just a power source that uses transmission to go out into the market. Again, you have to administer that. All of those ways of doing it can be considered a tribal utility. 

So the other issue is that tribes with traditional utilities are expanding and growing their services. So if they at one point only had a few customers served by a solar system, now they're going to expand by acquiring some distribution. So all of these different aspects of things and ways of mixing and matching all of these different elements still equal what I would call a tribal utility. Next slide, please. 

So all of the energy projects that everybody's considering will need administration. And so the administration includes things like just customer service, your maintenance, your operations, your reporting to leadership, your grant tasks and grant reporting, making sure your safety provisions are in order, all of your employment and TERO issues, your environmental questions, rates and billing, budgeting and planning. 

And then over there on the light bulb, you see things like GIS. It's really important to make sure all your facilities are included in GIS systems, making sure your meters are done right, making sure your planning is done right, doing rate setting, all of your HR issues, your finance matters. 

And then I have an et cetera in there because it can go on and on. Running any kind of a utility project is way more than just getting a grant and putting up a solar panel or putting up a wind project. Because what happens down the road when it needs maintenance, what happens if nobody's watching it or paying attention to it, all of these things need some kind of administration. Next slide, please. 

So just a little bit more about the administration and rates and billing. So tribal energy projects, even if the capital costs are virtually free using grant funds aren't really sustainable without long-term maintenance and customer service. So successful projects often have a planned source of funds for long-term operations. 

Customers, we all know, will take for granted and have an expectation if services are just provided to them for free. If that project then has maintenance issues and goes away, customers have gotten used to it. And they want that, and they don't want to go back to paying higher utility rates. 

So for all of these projects, you can create a rate and a billing to customers that pays for all their out-of-pocket costs your needed personnel to administer the project and a rate that creates a reasonable fund to pay for project maintenance and expenses. The rates can be shown to be significantly less than your existing rates. 

So for example, we have one customer whose existing rates are about $0.15 per kilowatt. But when they installed a solar system and improved the ability for the homes in the area to accept just their solar power, their utility bills went down. But they were then charged a small rate, a couple cents per kilowatt hour for the solars to assure that those solar systems were properly managed. 

Billing may be able to be done through your existing utilities, net metering and other agreements with existing utilities. And then just a suggestion-- include the cost for your electronic metering for your customers, which allows for rates and billings in your grant application so that you are always setting your project up for future success. Next slide. 

That's all I have. I think we were running a little late on our time, so I wanted to go through this quickly. But give me a call or send me an email if you have questions. Thanks. 

BRANDON KIGER: Thanks, Margie. Yeah, you got us caught up. So we are on to our last speaker here with Seneca Energy. Anthony, you may proceed once your slides are up. 

ANTHONY GIACOBBE: All right. Thank you. Hello, my name is Anthony Giacobbe. I'm the director of Seneca Energy and Telecom for the Seneca Nation and have been in this role for about 10-plus years now. Brought on back in 2014. And we now have a team of eight that work with myself and the organization. Next slide, please. 

So the Seneca Nation is located in the Western New York area. You can see we have five non-contiguous territories. The two that are primarily highlighted are our residential territories, Cattaraugus and Allegany. 

One of the challenges, they're separated by about 45 minutes. So we have to duplicate a lot of our services and buildings and things like that. We basically have two administration buildings, two clinics, and so on and so forth. 

Our president currently sits on the Allegheny territory. Our treasurer is on the Cattaraugus territory. In November, every two years, we have an election. And that actually flips. So the president in the next term will be on the Cattaraugus territory, and the treasurer will be on the Allegheny territory. 

We have 16 councilors, eight from each of those residential territories, and eight are elected every two years. So they are staggered a bit. They do four-year terms. Next slide, please. 

Seneca Energy's mission is really to ensure the security, prosperity, and independence of the Seneca Nation by building a sustainable energy platform and lowering energy costs for the nation and its residents. And you'll see as we talk today, all of our decisions really, it's all going towards this direction. And we really do look to the mission statement that ultimately created our vision and some of the things we'll talk about in some of the next slides. Next slide, please. 

So I mentioned I was brought on in 2014. This has been a long undertaking, predates myself. Seneca Nation really started back in 2003. Applied and received the DOE First Steps Towards Energy Efficiency and Renewable Energy Grant. This really started a lot of strategic planning. 

They looked at current analysis and did an analysis of current and projected energy use, natural gas resource, renewable resources. And really the output was to come up with some goals and objectives on how we could move forward and the best options to move forward, whether it's renewable energy or with our natural gas resource. 

One of the things that came out of the 2003 grant was really the creation of Seneca Energy, the development of our utilities commission. And again, then you can see the years that passed. We didn't actually staff Seneca Energy till 2014. So 10, 11 years later. And then now we're 10 years into that progression where we've accomplished quite a bit. And we'll talk about some of those projects that we've done. 

So it's a 20-year journey. And once the foundation is built, then you can really start to really move things forward a lot quicker. I think building that foundation is really important, setting up that strategic plan. And then again, you'll see in some of the things we've accomplished over the last decade, it really helps bring those things to fruition. Next slide, please. 

Then in 2009, again, applied for another DOE grant. And this really was the one that catapulted us to creating sonic energy. We had bylaws. A charter was developed. And again, then staff finally in 2014. And we really created this utility commission, saying that we wanted to own infrastructure to start. And that's what we've done. 

We own broadband infrastructure, natural gas infrastructure. We've put up a wind turbine, a solar array that we'll talk about. And really wanting to own that to have more control. And you'll learn that we contract. We have a lot of partnerships that we do help with-- they help with O&M and maintaining everything that we have. 

But we found that those relationships are a lot more beneficial. They're basically our contractor. In one case for our natural gas, we've actually contracted with the utility. But that contractor relationship is much more of a partnership than before, where we were really just at the mercy of the utility, if you will. It wasn't necessarily a partnership. And so again, owning that infrastructure has helped us move into that array. Next slide, please. 

So our energy vision, these are the pillars that we really came out of the strategic planning, came out of those different grants. What do we want to accomplish? What are those pillars that we're going to really push towards or use as our beacons and guiding us? 

So energy sustainability, reducing stabilizing costs, improving or enhancing infrastructure, economic development, environmental benefits, utilizing the natural resources that we do have, workforce development, and energy information hub. Back in 2014, there was energy information in a number of different departments-- in our EPP, our environmental department. Our planning department took a big role, even transportation. And other departments had different energy Information. 

And we've really in the last decade become that information hub, where most things are coming through Seneca Energy. And we're at least aware of what's going on. And that helps make sure that we're all pulling in the same direction. Next slide, please. 

So framework for success. Strategic vision, we did put a five-year strategic plan together. We update that pretty much annually. We're always looking at it, making sure that we're moving in that direction that we've set for ourselves. 

Leadership is huge. Having champions within council and our executives have really-- it's the reason that we've accomplished what we've accomplished to date, and they've really just helped in every two years that we do have elections, having those champions, making those projects get to that next administration, and keeping them going. We've had many projects that administration changes. And we're able to keep that project and really bringing the implementation or deployment and getting it up and running. 

Team development, I have a great team, seven others that are foreign or natural gas, one on our telecom, and basically two under arsenic energy, doing our energy. Our different energy applications-- so they are all learning and wear a lot of different hats. But they help on the solar array. They'll change out panels, reset inverters, wind turbine. We do some of the maintenance or help with our events. 

Our manufacturer does a lot of maintenance as well, but we can help with some of the things and restarting the turbine. On our fiber project, we'll assign fibers and install ports and things like that and just really having a lot of support, which has been great. And we've really seen the organization grow over the last 10 years. 

Capital investment, the nation has invested. We've received grants. We've received grants through DOE for our wind turbine. We've received grants actually through NYSERDA, which is a state organization. But basically, if you pay into-- when you pay your utility bill, there's a renewable portfolio charge that they charge you. That goes into a fund that we can then access for different projects. 

And finally, project evaluation and selection-- we've developed a few tools that really help us evaluate the projects that we're looking at, prioritize them, and then finally select them for which ones we want to deploy on territory. Next slide, please. 

Again, strategic planning. Identifying those stakeholders-- so we started a steering committee back in 2014. It has disbanded in the not-- since then, but we met for a couple of years while we really did the strategic planning. And they helped set those goals. We had everybody from GIS to environmental planning right down the line, [INAUDIBLE] involved, and really tried to identify what was important to all of the different departments at the nation. 

We developed the energy vision; again, assessed our needs and resources; tried to develop specific goals on really where we wanted to go and what we wanted to accomplish; again, evaluating and prioritizing projects. We developed a decision matrix that helped-- we gave things weights and give them different scores based on a 1 to 5. And you can weight it, how important it might be to you. And we actually spit out like a number result, but you can essentially rank projects against each other and come up-- and again, it clearly shows you which would be the top priorities for us. 

Identified financing options. We are constantly doing that through looking at different grants or loans. And we've looked at the DOE loan program and actually put in a few of the first step 1 applications. We haven't moved to the phase 2 yet and anything, but actively pursuing that. And then finally, strategic energy plan-- so the outcome is this five-year plan that really details what it is we're trying to do when we come to work every day. Next slide, please. 

So these are some projects, the highlights. So on our Cattaraugus territory, we built a 50-mile fiber broadband network. We do have some Wi-Fi in some areas that we couldn't bring fiber to. But ultimately, we pass 1,200 homes. We have 750 residents and businesses that are currently on our network, and we've been operational for two years. 

We leveraged a partnership with a local ISP. So we own all the wires, all the electronics, everything. Even inside the home, everything's kind of owned by the nation. But we partnered with a internet service provider. We tapped into them right off territory into one of their cabinets. They actually do the billing for us and for fiber. They do service calls and things like that. 

So they're a great resource for us. They're a medium-sized company. They're not a Spectrum or a Verizon. We found that that's really beneficial for us, to try to partner with companies that are like sized to us. The nation's pretty large. And we have a lot of economic development going on and casinos and things like that. But we're a medium-sized company. When you get into the Verizon's, again, it's can be a challenge from time to time to work with. 

So we found that finding those partners is really important. We went through three potential partners for our internet. And we landed on DFT, who has been great to work with. And I think we got really lucky with that. And then the hope is that we'll take on more of the O&M as we go forward and really getting into splicing, things like that. We do want to move in that direction. 

I mentioned the wind turbine and the solar array. We have installed about 4 megawatts on territory. We have a few smaller solar arrays that you see the microgrid in our Allegheny territory. Our Oak Tree Housing, which is an elder facility, we've done. 10, 13 kW. The microgrid, obviously, batteries are included. There's no electric to that building. Or there's actually three buildings that make up our Allegheny fish hatchery. 

Energy efficiency measures-- we've put LEDs in every building on both territories. We've plugged natural gas wells. There was 141 wells that were drilled on our Cattaraugus territory at one point in time. Another 120 wells in the Allegheny territory. 

And Allegheny, they were drilled by corporations that then left and left us with the burden to plug and abandon and deal with the environmental ramifications. So we're slowly but surely doing that. We've actually applied for a DOI grant recently to plug a number of those wells on the Allegheny territory. We did plug 30 on our Cattaraugus territory a number of years ago. 

We've done some microgrid feasibility studies, still trying to see if and where that would make sense for us. And then finally, the residential solar program, we've partnered with our EPC now for basically 10 years. They put up the wind turbine 10 years ago. Then we did the solar array and then residential solar program. Was really trying to roll it out to the community. We did 21 homes with over 200 kW last year. And we are-- I think we have seven or eight now signed up for our second phase that we're going to be doing. 

So moving towards just the residential level, again, one of our goals being reducing those costs for the residents. So trying to help them do that. Next slide. 

Our wind turbine, I've presented this in the future, so I'm going to do it pretty quickly. But ultimately, you see there's capital investment. We did receive 1.5 million through DOE, the implementation and deployment grant through Lizana's program, which was awesome and really catapulted this project into bringing it to fruition. 

I mentioned NYSERDA. This was commissioned back in 2017, so a couple of years. You can see it took three years after even I was brought on to get that fully commissioned. But we did it. And now it's virtually net metered. We've produced over 21 million kilowatt hours. That's a little old. Probably 22 million kilowatt hours. 

We provide a benefit to the community. So we give a $25 month credit to over 450 community members that have signed up for that program on both territories that are under our national grid. So not everybody on the Allegheny territory is under national grid utility service area. 

We do have a Salamanca BPU, which is like a public utility on our Allegheny territory. They do receive a hydro allocation. So there's a discrepancy in the power prices paid between the two territories. And what we've tried to do is with that $25 monthly credit, bringing the people who pay national grid, trying to create rate parity, where they're paying a similar rate to what people are paying under the public utility. 

Our project payback was estimated about eight years, so getting pretty close. And we are on schedule to have our projects paid off in time. And you can see the environmental benefits equivalent of powering almost 3,000 homes at the New York State average of use. Next slide, please. 

Some pictures of the wind turbine. We're in Buffalo, so we decided to put that up in the winter. You can see we started, it wasn't snowing. But then the wind storm is when we had the snowstorm. Put the tower together. And when you put the tower up, you have to get them to sell basically the head of the turbine on it. 

So got that up. I believe it was February when we were putting that up, but we had to wait for the lower part of the tower came in three pieces. And the lowest part, basically, we couldn't get it through Canada to us. And they almost had to cut it in half. And they were going to do that and, basically, solder the thing back together when they got here. But we were able to get permits and get it through and get it to the Seneca Nation. 

You can see our foundation is in the middle there. We dug down about 20 feet deep. And we have hundreds of yards of concrete pillars that are in there as well, stabilizing the foundation. Next slide, please. 

The rotor flies, this was the fun part, really. You get the blades on the ground and pick it up and put it on in the cell. So you can see that we had Seneca members, ironworkers put up this project. I think it was about nine Seneca Nation members between operators and ironworkers. 

And you can't really see them in that picture, but they're hanging out of the nacelle. And they basically guide it right in up in that third picture on the right. So that was really cool to have Seneca members working on this project. That's always important to us. Next slide, please. 

Our solar array is 2 megawatts. Same thing, virtually net metered. So we basically put all of the two big projects go into the grid. We have there the host account. We allocate satellite accounts that basically get credited back. 

So that's the virtually net metered, meaning it's not directly used. I guess it's going into the utility. We've generated about 10 million kilowatt hours and funded the majority of this construction with some NYSERDA grant. But this one, we commissioned in about six months versus three years or so that took on wind. 

Because again, I think setting that foundation was huge. We had the experience. We had an EPC that we had worked with. So contracting, things like that, whereas a little bit smoother. And we had some experience with both renewable energy and the company that we were working with that really helped us bring this project much quicker to deployment and implementation phase. Next slide, please. 

Just a picture of the kind of a drone picture of the array. Next slide. Our inverters, we have 49 inverters. They're string inverters. So it used to be central inverters. You'd have one or two inverters for an array this size. But if an inverter went down, you'd lose half or the entire array. In our case, you just lose a string. 

So most of the array would stay up if one inverter went down. We've replaced one inverter, I believe. We've had to reset them once in a while. But so far, we've been very happy with the brands and the equipment that we have. Next slide, please. 

Our fiber broadband project, I mentioned it. This was a huge project for us. We received a reconnect grant, so we received about $8.5 million for this. It was about $10.5 million project. We had to-- so mostly aerial, 5 miles underground, across thruways, railroads. 

Some of the challenges that we had-- we had to replace about 20% of our national grid utility poles on territory. And we spent about 3 million. I think ultimately was about $3.5 million just on our pole replacement alone. We really had to work with the utility on that. Connected, like I said. Now it's actually 750 residents and businesses. 

We're generating revenue share. So one of the nice things with that agreement with our ISP is we are generating revenue. Day 1, we started generating revenue. And the revenue we're generating is pretty significant, a couple hundred thousand dollars a year that we can use for reinvestment into the system when we have to rebuy electronics, when we're doing more installs. 

We're not charging the customer for installs. The nation covers that, but we're using those funds that we're generating the revenue. It's about a 60% split. We get 60. They get 40. They can make some money on some other services that we don't share. 

So it works out. They didn't have to pay to build the lines. They didn't have to invest to get to these customers. So that's the reason they can basically take half the revenue. And we've been up and running for two years now. Next slide, please. 

That's just a map of the network. You can see all the different lines. That's just by-- the different colors are different fiber counts. We go from 288 in our trunk line and then all the way down to 12 in some areas. Really not a lot of 12. I think 24 was our mostly our lowest that we ended up going to. Next slide, please. 

I mentioned the residential solar. We also did a generator program. We put some grants towards these programs. The nation invested $3 million. That was all through grants. We've contracted about 200. I think we almost have 200 installed at this point, generators, some natural gas, some propane, not necessarily clean energy. But reliability, I mean, being very important to us. 

So a lot of elders have gotten these. And the nation's covering the majority of the costs. Basically, residents are putting in a percentage, a small percentage. And the nation's covering the majority of it. Same with the solar arrays. Nation's covering the majority of those, where residents are putting in a certain percentage. 

And our goal is just really trying to create reliability for all of our residents. We have power outages. We have people that have medications that have to keep cool. Might have oxygen or whatever it might be, but a reason that they have to keep the power on. And that's why we rolled out that program. 

Our solar project did win Solar Project of the Year under Residential Solar Project of the Year for Solar Builder Magazine. So we're really proud of that. And next slide, please. 

Think that's it. So I just have my team there and my information, my email. But I appreciate the time. And thank you for your attention. 

BRANDON KIGER: Thanks, Anthony, for sharing all those projects and highlighting the 2003 First Steps Grant. That's great. We had a question about the amount of penetration that-- so we are going to move into questions right now for the panelists. 

But a question came up about what penetration of broadband is in the community now. I think I saw 650 residents. And are there future plans to do more work like that? Or maybe just briefly discuss some of the advantages of maybe leveraging being able to do energy projects and broadband projects at the same time. Are there some advantages to doing stuff like that? 

ANTHONY GIACOBBE: Well, definitely. I mean, we need-- so it's about 750 now, businesses and customers, that are connected. We did pass 1,200 homes. So we built out to every edge of the territory, except one spot where we have eight homes and one business. We received an NTIA grant that we're actually putting up some Wi-Fi equipment for those customers. And then we'll have 100% covered. 

So it's about 50%, a little more, I guess of penetration rate, if you will, people who've taken the service. We do installs every week. So I mean, I think it's out there. But just for one reason or another, some people haven't signed up. 

And again, I mean, we have-- it's a rolling applications coming in. And I think it is important to go to hand in hand as far as I can really say, you tell. Because we need SCADA systems. I mean, for example-- so we actually have a Wi-Fi system in Allegheny. And we're converting to fiber. We were able to convert our wind turbine to fiber. 

So for our monitoring systems, when looking at microgrids, fiber is going to be really important in connectivity. So yeah, I think they do go hand in hand. And I think they're both, obviously, essential. Broadband now-- I mean, we only had satellite prior. So people were paying really high prices for really low speeds, getting real high latency, maybe 15 megabits per second, where now they can get up to 500 megabits per second. So [INAUDIBLE] connection. 

BRANDON KIGER: Yeah, thanks, Anthony. So we don't have a lot of time for questions, but I did want to just do a quick round robin. Margie, I have a question for you. 

You emphasize how tribal utilities really do need a sustainable model. And when you talk about the technical assistance and you start to emphasize the rates and billing, is that something-- when you meet with technical assistance, is that something that the pre-feasibility that you can start helping work with the tribe on how to figure out? It seems very complex to figure out the whole rates and billing and what that might look like. 

MARGIE SCHAFF: Yeah, I mean, I-- 

BRANDON KIGER: Would it be covered under technical assistance? Yeah, yeah. 

MARGIE SCHAFF: Yeah, I don't think that technical assistance would cover a whole rate study, because sometimes these can be quite complicated. But certainly, it can give a lot of general information as to how you can set a rate and what the components should be. And then, of course, there's just a lot of work that your accountants have to do to make sure that all your numbers are correct. 

BRANDON KIGER: Yeah, OK. Thanks. Ingemar, it seems like the energy steering committee was pretty crucial to really getting the buy-in and getting these projects online and moving. Can you comment on that and just briefly say how critical that's been and any other nuanced information you can provide about that? 

INGEMAR MATHIASSON: Yeah, I mean, the steering committee from the very beginning has been instrumental in bringing the whole region together and highlighting the different projects starting in 2008 with the wind projects over in Buckland and Deering. And then two times a year, connecting with all the communities in these meetings has made the sustainable forward motion to accept the transition and understanding the transition and everybody slowly getting on the same page of what needs to happen. 

Very good discussions. We have usually a day and a half scheduled for those meetings, one in the spring and one in the fall. And then just keep it up. 

BRANDON KIGER: Yeah, yeah. It seems like the more projects you get online, maybe the easier it is to really-- not sell, but just the idea of using the IPPs to leverage bringing on clean energy. 

INGEMAR MATHIASSON: Oh, yeah, for sure. For sure. I mean, it's trying to-- once people understand how it works and then the other villages, they want to do the same thing, you know? So. 

BRANDON KIGER: Yeah, yeah. And, Brian, for us non-engineers out there, can you clarify-- you're talking about how it is difficult when you have diesel generators and you have solar and when you start getting into the higher penetration of solar. Can you just in layman's terms help me understand why you have to start shutting the diesel down and what happens if you don't do that? 

BRIAN HIRSCH: Yeah, so actually, you only shut the diesels down if you have everything else established. So typically, what would happen if you didn't have a battery and you had a lot of solar on the system, the diesel generator is ramping down. It's slowing down. It's not putting as much power out. 

And then all of a sudden, say a cloud comes over the sun. And the diesel generators have to ramp back up very quickly. It's kind of like the hybrid engines in your cars for folks who have seen that, where the engine and the battery are always sort of doing a dance. 

And so the goal, however, is to shut the engines down so that you have an electric vehicle where you don't have to have the diesels chasing the variability of the sun. And you're just taking advantage not just of saving fuel, but of saving wear and tear on the diesel generators. So the more you can completely shut them down, you get more benefits beyond just fuel savings, but operation and maintenance of the diesel generator itself, which is a fair bit of cost. 

So that's the goal. But you can really only achieve that if you have enough batteries to cover your need without the diesel engines on. 

BRANDON KIGER: All right. Thanks for breaking that down. So I just want to move to concluding today's webinar. Again, I just want to thank all of our panelists and attendees for hanging in there. This was definitely an extended webinar, but a really good informational webinar. 

So please stay tuned for future announcements on webinars through our Office of Indian Energy website, our email newsletter, and social media. Thank you, again, for your interest and attendance. We look forward to you joining us in future webinars. And have a great day. This concludes today's webinar. Thank you. 

LIZANA PIERCE: Thank you, Brandon. Thank you to presenters. Take care. 

Furey says firefighting efforts at Churchill Falls 'finally getting some help from Mother Nature'

All power restored in labrador city and most power in wabush, social sharing.

Newfoundland and Labrador Premier Andrew Furey said Wednesday he is cautiously optimistic about the efforts to keep the massive forest fire threatening Churchill Falls at bay.

During an update Wednesday afternoon, Furey said the fire remains on the perimeter of the town, which Newfoundland and Labrador Hydro operates to run one of North America's largest power plants. 

He said favourable weather conditions should continue to keep the forest fire — which prompted a mass exodus a week ago, and a full evacuation on Tuesday — away from the town's residential areas. The fire is currently about three kilometres from the town.

"We are finally getting some help from Mother Nature," Furey said.

The fire, which has been fluctuating continuously, was downgraded from as high as a Level 6 classification to as low as Level 2. Under higher categorizations, water bombers are unable to fly. Level 2 and Level 3 categorizations indicate there are some open flames and hot spots.

Furey says 'favourable' weather conditions helping with Churchill Falls wildfire

"These are much better days to fight fires than the two or three we've seen preceding today. And once we get a clear visual once the ceiling is clear we can get choppers, we'll look at what the suppression plan is," said Jamie Chippett, the deputy minister of the Department of Fisheries, Forestry, and Agriculture.

Parts of Labrador West have been without power since Tuesday as flames and dropped water tripped power lines at Churchill Falls, but power had been restored to all customers in Labrador City and most of Wabush as of early Wednesday evening, according to an update from N.L. Hydro. The utility says crews are working to restore power to its remaining customers without electricity.

The Iron Ore Company of Canada mine has also restarted operations in Labrador City.

As wildfires continue in Labrador and Quebec, there is a risk of additional power outages for all customers in Labrador.

Hydro is monitoring the situation and encourages customers to stay updated and prepared. 

Wildfire jumps river, approaches Churchill Falls, N.L.

Hydro is looking at contingency plans to help Wabush such as moving a generator into place to provide power but neighbouring stations in Quebec have different systems.

Backup supply from Hydro-Québec's Fermont station was a good match for the Labrador City station but not Wabush, according to Williams.

Extreme caution

Hydro is working to allow Fermont power to share supply in the two areas, but the updates must be done with extreme caution.

"If you rush it, you could have power quality issues and you fry everyone's microwave," Williams said.

She is asking the residents of Labrador West for patience and kindness, as N.L. Hydro's primary focus is on the residents of Churchill Falls.

"There are people that are incredibly affected that are removed from their homes and that we have to do our best to prioritize how we are handling things for them," Williams said.

The out-of-control fire jumped the nearby Churchill River on Tuesday afternoon and kept moving, providing a formidable challenge to fire crews.

Earlier Wednesday, Furey said up-to-date intelligence from aircraft was unavailable because of smoke produced by the fire hitting bodies of water like the Smallwood reservoir. 

Provincial forest fire duty officer Mark Lawlor said the fire was so powerful on Tuesday that water bombers stopped having an effect. For safety, the pilots pulled out. 

"There was no suppression efforts we could have put in that yesterday to stop it," Lawlor told CBC News on Wednesday morning.

Eight water bombers are available to attack the eastern edge of the blaze when it's safe to do so, said Furey on Wednesday afternoon.

How long can the Churchill Falls power plant operate with staff off-site?

After a broad evacuation June 19, a full evacuation order was issued Tuesday afternoon, forcing the remaining skeleton staff to leave for safety. 

Between 80 and 100 people had been operating the plant and handling operations and site services, fire services and clearing work for a fire break that has been under construction. All personnel were evacuated by suppertime, and 90 people registered at the YMCA in Happy Valley-Goose Bay on Tuesday evening, according to Furey earlier Wednesday.

• After Churchill Falls fire jumps river, officials hope for rain to help firefighting efforts
• Evacuee returns to 'eerie' Churchill Falls as an essential worker keeping town running

Download our free CBC News app to sign up for push alerts for CBC Newfoundland and Labrador. Click here to visit our landing page .

Related Stories

• With help from favourable weather, Churchill Falls fire drops to Level 1, says Furey
• Fire suppression efforts working against Churchill Falls wildfires
• More essential workers return to Churchill Falls, with fires holding steady
• Some Hydro workers back but evacuation order still in effect for Churchill Falls

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HYDROELECTRIC POWER PLANT

Mar 24, 2012

840 likes | 2.08k Views

HYDROELECTRIC POWER PLANT. HYDROELECTRIC POWER PLANT. PREPARED BY: PROF.DEEPTI G.PATNE. SYLLABUS. Site selection Hydrology Estimation electric power to be developed Classification of Hydropower plants. Types of Turbines for hydroelectric power plant. pumped storage plants.

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Presentation Transcript

HYDROELECTRIC POWER PLANT PREPARED BY: PROF.DEEPTI G.PATNE

SYLLABUS • Site selection • Hydrology • Estimation electric power to be developed • Classification of Hydropower plants. • Types of Turbines for hydroelectric power plant. • pumped storage plants. • storage reservoir plants.

World Hydro Production

SITE SELECTION FOR HYDRO ELECTRIC POWER PLANT. • Preliminary investigation: • The purpose of preliminary investigation is to provide sufficient information to find out the practicability of the proposed scheme and choose between alternative schemes. • The preliminary designs and estimations can be prepared and recommendations are made with reasonable confidence.

INTRODUCTION

kW(Power)=(mgH/1000)*ἠh * ἠm * ἠg • Where: • m= Rate of water flow in kg/sec. • H=Height of fall in meters • ἠh =hydraulic efficiency of prime mover • ἠm & ἠg are mechanical and generating efficiencies • kW=(mgH/1000)*ἠoverall

HYDROLOGY • The science which deals with rainfall and run-off is known as hydrology. • Hydrological cycle:

Rainfall and its measurement • Rainfall: it is a natural process of converting atmospheric vapour into water. • Or • Total condensation of moisture from the atmosphere that reaches the earth, including all forms of rains, ice and snow.

One Centimeter Rainfall • When the quantity of water collected on a certain plain area due to rainfall becomes one centimeter in height, one centimeter of rainfall is said to occur.

Intensity of rainfall • I(intensity in cm/hr)=R/T+C • T=duration of rainstorm in hours • R&C= constant

Non Recording Gauge

Non recording type

Recording Type

Average or mean depth of rainfall • Arithmetic mean method: • ha =h1 + h…………+hn /n • ∑h/n

Thiesson method

Iso-hyetol method

Final Investigation • The final investigations include the detailed exploration of the recommended site so as to establish the complete suitability and to enable the final design. • The preliminary and final investigations include: • Hydrological • Topographical • Geological

Once the location of is chosen,the exact position of different components will be fixed after careful consideration of the following factors: • Requirement of head, flow availability and storage capacity. • The character of the foundation ,particularly for dams. • The topography of the surface at proposed location

Arrangement and type of dam,intakes,counduits ,surge tank, power house and many others. • Availability of materials for construction. • Transportation facilities. • The cost of the project and period required for completion.

HYDROLOGICAL INVESTIGATION • It includes following investigation: • Water availability • Water storage • Water head • Ground water data

Water availability • All other designed based on this. • Estimate should be made on average quantity of water throughout the year and also about maximum and minimum quantity of water available during the year. • The details are necessarily to decide the capacity of hydropower plant • It also provide spillway

Water storage • Since there is wide variation in rainfall during the year,therfore it is necessary to store the water for continuous operation of power. • The storage capacity can be calculated with the help of mass amount.

Water head • In order to operate a requisite quantity of power it is necessary that a large quantity of water at sufficient head should be available. • An every increase in head for the given output reduces quantity of water to be stored and therefore the capital cost

Accessibility of site • The site where hydroelectric plant is to be constructed should be easy accessible. • This is important if the electrical power generated is to be utilized at or near the plant side. • The site selected should have transportation facilities of rail and road.

DISTANCE FROM THE LOAD CENTER. • Power plant should be set up near the load center, it reduces the cost of maintainace of transmission lines.

Type of land of site • The land to be selected for the site should be cheap and rockey • The ideal site is one where dam will have largest catchment area to store water at high head and will be economical in construction. • The rock should be strong enough to withstand stresses transmitted from dam structure • Rock should remain stable at all condition.

HYDROLOGY • It is a science which deals with depletion and replenishment of water resources. • It deals with the surface water as well as ground water. • It also concerned of with the transportation of water from one place to another. • It helps to determine the occurrence and availabity of water

HYDROLOGICAL CYCLE

HYDROLOGICAL CYCLE • Most of earth water sources, such as river, lake ocean and underground sources get their supply from rain • The evaporation and precipitation continuous forever and process is known as hydrological cycle. • P=R+E • P= PRECIPITATION • R=RUNOFF • E=EVAPORATION

MEASUREMENT OF RUNOFF • Runoff can be measured daily monthly ,seasonally or yearly. • It can be measured by following method. • From rainfall records • Empirical formule • Runoff curves and tables • Discharge observation method.

Rainfall records • Runoff=rainfall*coefficient • Coefficeint of catchment area • Eg: • Garden apartment=0.50 • Commercial and industrial=0.90 • Concrete pavement=0.85

Runoff curves and table • Each region has its own catchment area and rainfall characteristics and for same region the characteristics mostly remain unchanged. • The graph is plotted in which one axis represents rainfall and other runoff • The curve obtained called run-off curve. rainfall runoff

Discharge observation method • By actual measurement of an outlet of a drainage basin runoff over a catchment can be computed. • The complication in this method is that the discharge of the stream outlet comprises surface run off as well as sub surface flow. • To find out subsurface runoff is essential to separate substances from the total flow. • The separation can be in approximate basis but with correct analysis.

HYDROGRAPH • It is defined as graph showing discharge of flowing water with respect to time for specific time. • Hydrograph of steam of river will depend on the characteristics of catchment and precipitation over catchment • It indicate power available from stream at different times of day, week, month and year

The unit hydrograph (discharge Vs time) • The unit hydrograph represents the unit runoff resulted from intense rainfall of unit duration and specific area distribution. • It is possible to predict a runoff hydrograph corresponding to hypothetical storm. • The basic concept of unit hydrograph is that the hydrograph or runoff from two identical storm would be same

How hydroelectric power plant works? • Flowing water is directed at a turbine. • The flowing water causes the turbine rotate, converting the water’s kinetic energy into mechanical energy • The mechanical energy produced by turbine is converted into electric energy using turbine generator. • Inside, the generator the shaft of turbine spins a magnet inside coil. Producing electric current

How much electricity can be generated by hydro power plant • The amount of electricity that can be generated is depends on two factors. • Flow rate: • Quantity of water flowing in a given time. • Flow head: • The height from which water falls • Greater the flow and head more electricity is produced • Flow rate=the quantity of water flowing. • Power production is directly proportional to river flow • The flow rate depends on size of the river and amount of water flowing in it. • Head-height from which water falls. • Power production is directly proportional to head. • When determining head, hydrologist take into account the pressure behind the water. Water behind the dam put pressure on falling water

A standard equation for calculating energy production • Power= head*flow*efficiency • 11.8 • Where • Power=electric power in KW • Head=distance of water falls (feet) • Flow=amount of water flowing (cubic feet per second)or CFS • Efficiency=turbine & generator convert the power falling water into electric power • these can range from 60%(0.60)older poorly maintained from 90% (.90) newer • 11.8=constant in KW

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