Delaware to begin training new 'green workers'

By The News Journal


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When Dale Davis began installing solar-panel systems 10 years ago, his primary customers were "fervent environmentalists."

"It didn't matter that it cost four times as much and that it took 25 years to recoup their investment," said Davis, president of CMI Electric, a Wilmington solar contractor. "They did it because it was the right thing to do."

Now though, interest in home weatherization, solar, wind and geothermal power isn't just about altruism anymore. In Delaware and beyond, government leaders see it as the key to lifting the state — and the country — out of economic turmoil.

In October, Delaware Technical & Community College will launch the first of what educators intend to be a slate of programs to train energy auditors, facilities managers, green power technicians and green builders.

At the same time, the Department of Energy has set aside $54 million for Delaware in stimulus funding for weatherization, efficiency and conservation and the state's energy program. State officials are planning to launch public awareness campaigns and augment existing financial incentives for consumers who go green.

"To be successful, the programs kind of have to advance simultaneously," said Collin O'Mara, secretary of natural resources and environmental control. "We believe energy efficiency is the biggest market and also where we have a lot of stimulus dollars."

The training efforts are starting small, with a new 52-hour certificate program that DelTech will offer in October to train certified energy auditors, which are consultants that work with consumers to identify ways to make their homes more efficient. The program begins this month.

Within the next several years, however, DelTech hopes to launch programs to train technicians to install, operate and maintain solar- and wind-energy systems.

"It's kind of a chicken-and-egg dilemma," Smith said. "We want to be ready when the jobs are ready but we don't want to be too far ahead because we don't want the students to be trained and not have the jobs here."

Jason Wardrup, a certified energy auditor for Brightfields Inc., a Wilmington environmental consulting company, took part in an earlier auditor training program.

"There's not that many auditors in the state right now, not too many people at all that do this, but we're trying to get the work force trained up now to meet the demand as it rises."

Davis, president of CMI Electric, currently has to send new employees as far away as Colorado, Florida and California to be trained to work with solar-panel systems. Finding a worker locally who already has the specialized training is "very unusual," he said, but many different types of workers can be retrained to do the job.

To train someone to design a solar-panel system or to be a windsmith will require millions of dollars of investment in specialized labs and equipment. For example, Smith said, DelTech needs to buy a nacelle, or the operations unit that holds a wind turbine's generator, gearbox and control system.

Any day now, Owens campus director Ileana Smith will hear whether the federal Economic Development Administration is awarding the school $800,000 to build "Energy House," a 3,052-square-foot green technology lab and classroom building, in Georgetown.

Intended to look like a home, the structure will be designed to LEED standards and include a geothermal heat pump, a "green" roof and wind and solar equipment for use by students. The house design was chosen so the structure can also be used for public tours to give homeowners an idea of what a renewable-energy system might look like and how they work.

Delaware ranked last in the nation in renewable-energy production in 2006; less than 0.05 percent of energy in that year came from renewable sources, according to a report from Gov. Jack Markell's Energy Advisory Council. But the state has passed a law mandating that by 2019, 20 percent of Delmarva Power's electricity supply must come from renewable sources.

Delaware needs to move fast, because other states also are trying to establish themselves as leaders in green technology.

"It's early on, but we're all sort of preparing for this crush," Bowman said. But when stimulus money "starts to flow, we need to get busy in a hurry, because there's an 18-month burn rate and it's gone. Everybody is cautious in overinvesting in any kind of development before it flows, but at the same time, we want to be ready when it does."

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Uzbekistan Looks To Export Electricity To Afghanistan

Surkhan-Pul-e-Khumri Power Line links Uzbekistan and Afghanistan via a 260-kilometer transmission line, boosting electricity exports, grid reliability, and regional trade; ADB-backed financing could open Pakistan's energy market with 24 million kWh daily.

 

Key Points

A 260-km line to expand Uzbekistan power exports to Afghanistan, ADB-funded, with possible future links to Pakistan.

✅ 260 km Surkhan-Pul-e-Khumri transmission link

✅ +70% electricity exports; up to 24M kWh daily

✅ ADB $70M co-financing; $32M from Uzbekistan

 

Senior officials with Uzbekistan’s state-run power company have said work has begun on building power cables to Afghanistan that will enable them to increase exports by 70 per cent, echoing regional trends like Ukraine resuming electricity exports after grid repairs.

Uzbekenergo chief executive Ulugbek Mustafayev said in a press conference on March 24 that construction of the Afghan section of the 260-kilometer Surkhan-Pul-e-Khumri line will start in June.

The Asian Development Bank has pledged $70 million toward the final expected $150 million bill of the project. Another $32 million will come from Uzbekistan.

Mustafayev said the transmission line would give Uzbekistan the option of exporting up to 24 million kilowatt hours to Afghanistan daily, similar to Ukraine's electricity export resumption amid shifting regional demand.

“We could potentially even reach Pakistan’s energy market,” he said, noting broader regional ambitions like Iran's bid to be a power hub linking regional grids.

#google#

This project was given fresh impetus by Afghan President Ashraf Ghani’s visit to Tashkent in December, mirroring cross-border energy cooperation such as Iran-Iraq energy talks in the region. His Uzbek counterpart, Shavkat Mirziyoyev, had announced at the time that work was set to begin imminently on the line, which will run from the village of Surkhan in Uzbekistan’s Surkhandarya region to Pul-e-Khumri, a town in Afghanistan just south of Kunduz.

In January, Mirziyoyev issued a decree ordering that the rate for electricity deliveries to Afghanistan be dropped from $0.076 to $0.05 per kilowatt.

Mustafayev said up to 6 billion kilowatt hours of electricity could eventually be sent through the power lines. More than 60 billion kilowatt hours of electricity was produced in Uzbekistan in 2017.

According to Tulabai Kurbonov, an Uzbek journalist specializing in energy issues, the power line will enable the electrification of the the Hairatan-Mazar-i-Sharif railroad joining the two countries. Trains currently run on diesel. Switching over to electricity will help reduce the cost of transporting cargo.

There is some unhappiness, however, over the fact that Uzbekistan plans to sell power to Afghanistan when it suffers from significant shortages domestically and wider Central Asia electricity shortages persist.

"In the villages of the Ferghana Valley, especially in winter, people are suffering from a shortage of electricity,” said Munavvar Ibragimova, a reporter based in the Ferghana Valley. “You should not be selling electricity abroad before you can provide for your own population. What we clearly see here is the favoring of the state’s interests over those of the people.”

 

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The CIB and private sector partners to invest $1.7 billion in Lake Erie Connector

Lake Erie Connector Investment advances a 1,000 MW HVDC transmission link connecting Ontario to the PJM Interconnection, enhancing grid reliability, clean power trade, and GHG reductions through a public-private partnership led by CIB and ITC.

 

Key Points

A $1.7B public-private HVDC project linking Ontario and PJM to boost reliability, cut GHGs, and enable clean power trade.

✅ 1,000 MW, 117 km HVDC link between Ontario and PJM

✅ $655M CIB and $1.05B private financing, ITC to own-operate

✅ Cuts system costs, boosts reliability, reduces GHG emissions

 

The Canada Infrastructure Bank (CIB) and ITC Investment Holdings (ITC) have signed an agreement in principle to invest $1.7 billion in the Lake Erie Connector project.

Under the terms of the agreement, the CIB will invest up to $655 million or up to 40% of the project cost. ITC, a subsidiary of Fortis Inc., and private sector lenders will invest up to $1.05 billion, the balance of the project's capital cost.

The CIB and ITC Investment Holdings signed an agreement in principle to invest $1.7B in the Lake Erie Connector project.

The Lake Erie Connector is a proposed 117 kilometre underwater transmission line connecting Ontario with the PJM Interconnection, the largest electricity market in North America, and aligns with broader regional efforts such as the Maine transmission line to import Quebec hydro to strengthen cross-border interconnections.

The 1,000 megawatt, high-voltage direct current connection will help lower electricity costs for customers in Ontario and improve the reliability and security of Ontario's energy grid, complementing emerging solutions like battery storage across the province. The Lake Erie Connector will reduce greenhouse gas emissions and be a source of low-carbon electricity in the Ontario and U.S. electricity markets.

During construction, the Lake Erie Connector is expected to create 383 jobs per year and drive more than $300 million in economic activity, and complements major clean manufacturing investments like a $1.6 billion battery plant in the Niagara Region that supports the EV supply chain. Over its life, the project will provide 845 permanent jobs and economic benefits by boosting Ontario's GDP by $8.8 billion.

The project will also help Ontario to optimize its current infrastructure, avoid costs associated with existing production curtailments or shutdowns. It can leverage existing generation capacity and transmission lines to support electricity demand, alongside new resources such as the largest battery storage project planned for southwestern Ontario.

ITC continues its discussions with First Nations communities and is working towards meaningful participation in the near term and as the project moves forward to financial close.

The CIB anticipates financial close late in 2021, pending final project transmission agreements, with construction commencing soon after. ITC will own the transmission line and be responsible for all aspects of design, engineering, construction, operations and maintenance.

ITC acquired the Lake Erie Connector project in August 2014 and it has received all necessary regulatory and permitting approvals, including a U.S. Presidential Permit and approval from the Canada Energy Regulator.

This is the CIB's first investment commitment in a transmission project and another example of the CIB's momentum to quickly implement its $10B Growth Plan, amid broader investments in green energy solutions in British Columbia that support clean growth.

 

Endorsements

This project will allow Ontario to export its clean, non-emitting power to one of the largest power markets in the world and, as a result, benefit Canadians economically while also significantly contributing to greenhouse gas emissions reductions in the PJM market. The project allows Ontario to better manage peak capacity and meet future reliability needs in a more sustainable way. This is a true win-win for both Canada and the U.S., both economically and environmentally.
Ehren Cory, CEO, Canada Infrastructure Bank

The Lake Erie Connector has tremendous potential to generate customer savings, help achieve shared carbon reduction goals, and increase electricity system reliability and flexibility. We look forward to working with the CIB, provincial and federal governments to support a more affordable, customer-focused system for Ontarians. 
Jon Jipping, EVP & COO, ITC Investment Holdings Inc., a subsidiary of Canadian-based Fortis Inc. 

We are encouraged by this recent announcement by the Canada Infrastructure Bank. Mississaugas of the Credit First Nation has an interest in projects within our historic treaty lands that have environmental benefits and that offer economic participation for our community.
Chief Stacey Laforme, Mississaugas of the Credit First Nation

While our evaluation of the project continues, we recognize this project can contribute to the economic resilience of our Shareholder, the Mississaugas of the Credit First Nation. Subject to the successful conclusion of our collaborative efforts with ITC, we look forward to our involvement in building the necessary infrastructure that enable Ontario's economic engine.
Leonard Rickard, CEO, Mississaugas of the Credit Business Corporation

The Lake Erie Connector demonstrates the advantages of public-private partnerships to develop critical infrastructure that delivers greater value to Ontarians. Connecting Ontario's electricity grid to the PJM electricity market will bring significant, tangible benefits to our province. This new connection will create high-quality jobs, improve system flexibility, and allow Ontario to export more excess electricity to promote cost-savings for Ontario's electricity consumers.
Greg Rickford, Minister of Energy, Northern Development and Mines, Minister of Indigenous Affairs

With the US pledging to achieve a carbon-free electrical grid by 2035, Canada has an opportunity to export clean power, helping to reduce emissions, maximizing clean power use and making electricity more affordable for Canadians. The Lake Erie Connector is a perfect example of that. The Canada Infrastructure Bank's investment will give Ontario direct access to North America's largest electricity market - 13 states and D.C. This is part of our infrastructure plan to create jobs across the country, tackle climate change, and increase Canada's competitiveness in the clean economy, alongside innovation programs like the Hydrogen Innovation Fund that foster clean technology.


Quick Facts

  • The Lake Erie Connector is a 1,000 megawatt, 117 kilometre long underwater transmission line connecting Ontario and Pennsylvania.
  • The PJM Interconnection is a regional transmission organization coordinating the movement of wholesale electricity in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.
  • The project will help to reduce electricity system costs for customers in Ontario, and aligns with ongoing consultations on industrial electricity pricing and programs, while helping to support future capacity needs.
  • The CIB is mandated to invest CAD $35 billion and attract private sector investment into new revenue-generating infrastructure projects that are in the public interest and support Canadian economic growth.
  • The investment commitment is subject to final due diligence and approval by the CIB's Board.

 

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Spent fuel removal at Fukushima nuclear plant delayed up to 5 years

Fukushima Daiichi decommissioning delay highlights TEPCO's revised timeline, spent fuel removal at Units 1 and 2, safety enclosures, decontamination, fuel debris extraction by robot arm, and contaminated water management under stricter radiation control.

 

Key Points

A government revised schedule pushing back spent fuel removal and decommissioning milestones at Fukushima Daiichi.

✅ TEPCO delays spent fuel removal at Units 1 and 2 for safety.

✅ Enclosures, decontamination, and robotics mitigate radioactive risk.

✅ Contaminated water cut target: 170 tons/day to 100 by 2025.

 

The Japanese government decided Friday to delay the removal of spent fuel from the Fukushima Daiichi nuclear power plant's Nos. 1 and 2 reactors by as much as five years, casting doubt on whether it can stick to its timeframe for dismantling the crippled complex.

The process of removing the spent fuel from the units' pools had previously been scheduled to begin in the year through March 2024.

In its latest decommissioning plan, the government said the plant's operator, Tokyo Electric Power Company Holdings Inc., will not begin the roughly two-year process (a timeline comparable to major reactor refurbishment programs seen worldwide) at the No. 1 unit at least until the year through March 2028 and may wait until the year through March 2029.

Work at the No. 2 unit is now slated to start between the year through March 2025 and the year through March 2027, it said.

The delay is necessary to take further safety precautions such as the construction of an enclosure around the No. 1 unit to prevent the spread of radioactive dust, and decontamination of the No. 2 unit, even as authorities have begun reopening previously off-limits towns nearby, the government said. It is the fourth time it has revised its schedule for removing the spent fuel rods.

"It's a very difficult process and it's hard to know what to expect. The most important thing is the safety of the workers and the surrounding area," industry minister Hiroshi Kajiyama told a press conference.

The government set a new goal of finishing the removal of the 4,741 spent fuel rods across all six of the plant's reactors by the year through March 2032, amid ongoing debates about the consequences of early nuclear plant closures elsewhere.

Plant operator TEPCO has started the process at the No. 3 unit and already finished at the No. 4 unit, which was off-line for regular maintenance at the time of the disaster. A schedule has yet to be set for the Nos. 5 and 6 reactors.

While the government maintained its overarching timeframe of finishing the decommissioning of the plant 30 to 40 years from the 2011 crisis triggered by a magnitude 9.0 earthquake and tsunami, there may be further delays, even as milestones at other nuclear projects are being reached worldwide.

The government said it will begin removing fuel debris from the three reactors that experienced core meltdowns in the year through March 2022, starting with the No. 2 unit as part of broader reactor decommissioning efforts.

The process, considered the most difficult part of the decommissioning plan, will involve using a robot arm, reflecting progress in advanced reactors technologies, to initially remove small amounts of debris, moving up to larger amounts.

The government also said it will aim to reduce the pace at which contaminated water at the plant increases. Water for cooling the melted cores, mixed with underground water, amounts to around 170 tons a day. That number will be brought down to 100 tons by 2025, it said.

The water is being treated to remove the most radioactive materials and stored in tanks on the plant's grounds, but already more than 1 million tons has been collected and space is expected to run out by the summer of 2022.

 

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Marine Renewables Canada shifts focus towards offshore wind

Marine Renewables Canada Offshore Wind integrates marine renewables, tidal and wave energy, advancing clean electricity, low-carbon power, supply chain development, and regulatory alignment to scale offshore wind energy projects across Canada's coasts and global markets.

 

Key Points

An initiative to grow offshore wind using Canada's marine strengths, shared supply chains, and regulatory synergies.

✅ Leverages tidal and wave energy expertise for offshore wind

✅ Aligns supply chain, safety, and regulatory frameworks

✅ Supports low-carbon power and clean electricity goals

 

With a growing global effort to develop climate change solutions and increase renewable electricity production, including the UK offshore wind growth in recent years, along with Canada’s strengths in offshore and ocean sectors, Marine Renewables Canada has made a strategic decision to grow its focus by officially including offshore wind energy in its mandate.

Marine Renewables Canada plans to focus on similarities and synergies of the resources in order to advance the sector as a whole and ensure that clean electricity from waves, tides, rivers, and offshore wind plays a significant role in Canada’s low-carbon future.

“Many of our members working on tidal energy and wave energy projects also have expertise that can service offshore wind projects both domestically and internationally,” says Tim Brownlow, Chair of Marine Renewables Canada. “For us, offshore wind is a natural fit and our involvement will help ensure that Canadian companies and researchers are gaining knowledge and opportunities in the offshore wind sector as it grows.”

Canada has the longest coastlines in the world, giving it huge potential for offshore wind energy development. In addition to the resource, Canada has significant capabilities from offshore and marine industries that can contribute to offshore wind energy projects. The global offshore wind market is estimated to grow by over 650% by 2030 and presents new opportunities for Canadian business.

“The federal government’s recent inclusion of offshore renewables in legislation, including a plan for regulating offshore wind developed by the government, and support for emerging renewable energy technologies are important steps toward building this industry,” says Elisa Obermann, executive director of Marine Renewables Canada. “There are still challenges to address before we’ll see offshore wind energy development in Canada, but we see a great opportunity to get more involved now, increase our experience, and help inform future development.”

Like wave and tidal energy, offshore wind projects operate in harsh marine environments and development presents many of the same challenges and benefits as it does for other marine renewable energy resources. Marine Renewables Canada has recognized that there is significant overlap between offshore wind and wave and tidal energy when it comes to the supply chain, regulatory issues, and the operating environment. The association plans to focus on similarities and synergies of the resources in order to advance the sector as a whole, leveraging Canada’s opportunity in the global electricity market to ensure that clean electricity from waves, tides, rivers, and offshore wind plays a significant role in Canada’s low-carbon future.

 

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Utilities see benefits in energy storage, even without mandates

Utility Battery Storage Rankings measure grid-connected capacity, not ownership, highlighting MW, MWh, and watts per customer across PJM, MISO, and California IOUs, featuring Duke Energy, IPL, ancillary services, and frequency regulation benefits.

 

Key Points

Rankings that track energy storage connected to utility grids, comparing MW, MWh, and W/customer rather than ownership.

✅ Ranks by MW, MWh, and watts per customer, not asset ownership

✅ Highlights PJM, MISO cases and California IOUs' deployments

✅ Examples: Duke Energy, IPL, IID; ancillary services, frequency response

 

The rankings do not tally how much energy storage a utility built or owns, but how much was connected to their system. So while IPL built and owns the storage facility in its territory, Duke does not own the 16 MW of storage that connected to its system in 2016. Similarly, while California’s utilities are permitted to own some energy storage assets, they do not necessarily own all the storage facilities connected to their systems.

Measured by energy (MWh), IPL ranked fourth with 20 MWh, and Duke Energy Ohio ranked eighth with 6.1 MWh.

Ranked by energy storage watts per customer, IPL and Duke actually beat the California utilities, ranking fifth and sixth with 42 W/customer and 23 W/customer, respectively.

Duke ready for next step

Given Duke’s plans, including projects in Florida that are moving ahead, the utility is likely to stay high in the rankings and be more of a driving force in development. “Battery technology has matured, and we are ready to take the next step,” Duke spokesman Randy Wheeless told Utility Dive. “We can go to regulators and say this makes economic sense.”

Duke began exploring energy storage in 2012, and until now most of its energy storage efforts were focused on commercial projects in competitive markets where it was possible to earn revenues. Those included its 36 MW Notrees battery storage project developed in partnership with the Department of Energy in 2012 that provides frequency regulation for the Electric Reliability Council of Texas market and two 2 MW storage projects at its retired W.C. Beckjord plant in New Richmond, Ohio, that sells ancillary services into the PJM Interconnection market.

On the regulated side, most of Duke’s storage projects have had “an R&D slant to them,” Wheeless said, but “we are moving beyond the R&D concept in our regulated territory and are looking at storage more as a regulated asset.”

“We have done the demos, and they have proved out,” Wheeless said. Storage may not be ready for prime time everywhere, he said, but in certain locations, especially where it can it can be used to do more than one thing, it can make sense.

Wheeless said Duke would be making “a number of energy storage announcements in the next few months in our regulated states.” He could not provide details on those projects.

More flexible resources
Location can be a determining factor when building a storage facility. For IPL, serving the wholesale market was a driving factor in the rationale to build its 20 MW, 20 MWh storage facility in Indianapolis.

IPL built the project to address a need for more flexible resources in light of “recent changes in our resource mix,” including decreasing coal-fired generation and increasing renewables and natural gas-fired generation, as other regions plan to rely on battery storage to meet rising demand, Joan Soller, IPL’s director of resource planning, told Utility Dive in an email. The storage facility is used to provide primary frequency response necessary for grid stability.

The Harding Street storage facility in May. It was the first energy storage project in the Midcontinent ISO. But the regulatory path in MISO is not as clear as it is in PJM, whereas initiatives such as Ontario storage framework are clarifying participation. In November, IPL with the Federal Energy Regulatory Commission, asking the regulator to find that MISO’s rules for energy storage are deficient and should be revised.

Soller said IPL has “no imminent plans to install energy storage in the future but will continue to monitor battery costs and capabilities as potential resources in future Integrated Resource Plans.”

California legislative and regulatory push

In California, energy storage did not have to wait for regulations to catch up with technology. With legislative and regulatory mandates, including CEC long-duration storage funding announced recently, as a push, California’s IOUs took high places in SEPA’s rankings.

Southern California Edison and San Diego Gas & Electric were first and fourth (63.2 MW and 17.2 MW), respectively, in terms of capacity. SoCal Ed and SDG&E were first and second (104 MWh and 28.4 MWh), respectively, and Pacific Gas and Electric was fifth (17 MWh) in terms of energy.

But a public power utility, the Imperial Irrigation District (IID), ended up high in the rankings – second in capacity (30 MW) and third  in energy (20 MWh) – even though as a public power entity it is not subject to the state’s energy storage mandates.

But while IID was not under state mandate, it had a compelling regulatory reason to build the storage project. It was part of a settlement reached with FERC over a September 2011 outage, IID spokeswoman Marion Champion said.

IID agreed to a $12 million fine as part of the settlement, of which $9 million was applied to physical improvements of IID’s system.

IID ended up building a 30 MW, 20 MWh lithium-ion battery storage system at its El Centro generating station. The system went into service in October 2016 and in May, IID used the system’s 44 MW combined-cycle natural gas turbine at the generating station.

Passing savings to customers
The cost of the storage system was about $31 million, and based on its experience with the El Centro project, Champion said IID plans to add to the existing batteries. “We are continuing to see real savings and are passing those savings on to our customers,” she said.

Champion said the battery system gives IID the ability to provide ancillary services without having to run its larger generation units, such as El Centro Unit 4, at its minimum output. With gas prices at $3.59 per million British thermal units, it costs about $26,880 a day to run Unit 4, she said.

IID’s territory is in southeastern California, an area with a lot of renewable resources. IID is also not part of the California ISO and acts as its own balancing authority. The battery system gives the utility greater operational flexibility, in addition to the ability to use more of the surrounding renewable resources, Champion said.

In May, IID’s board gave the utility’s staff approval to enter into contract negotiations for a 7 MW, 4 MWh expansion of its El Centro storage facility. The negotiations are ongoing, but approval could come in the next couple months, Champion said.

The heart of the issue, though, is “the ability of the battery system to lower costs for our ratepayers,” Champion said. “Our planning section will continue to utilize the battery, and we are looking forward to its expansion,” she said.” I expect it will play an even more important role as we continue to increase our percentage of renewables.”

 

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Basin Electric and Clenera Renewable Energy Announce Power Purchase Agreement for Montana Solar Project

Cabin Creek Solar Project Montana delivers 150 MW of utility-scale solar under a Power Purchase Agreement, with Basin Electric and Clenera supplying renewable energy, enhancing grid reliability, and reducing carbon emissions for 30,000 homes.

 

Key Points

A 150 MW solar PPA near Baker by Basin Electric and Clenera, delivering reliable renewable power and carbon reduction.

✅ 150 MW across two 75 MW sites near Baker, Montana

✅ PPA supports Basin Electric's diverse, cost-effective portfolio

✅ Cuts 265,000 tons CO2 and powers 30,000 homes

 

A new solar project in Montana will provide another 150 megawatts (MW) of affordable, renewable power to Basin Electric customers and co-op members across the region.

Basin Electric Power Cooperative (Basin Electric) and Clenera Renewable Energy, announced today the execution of a Power Purchase Agreement (PPA) for the Cabin Creek Solar Project. Cabin Creek is Basin Electric's second solar PPA, and the result of the cooperative's continuing goal of providing a diverse mix of energy sources that are cost-effective for its members.

When completed, Cabin Creek will consist of two, 75-MW projects in southeastern Montana, five miles west of Baker. According to Clenera, the project will eliminate 265,000 tons of carbon dioxide per year and power 30,000 homes, while communities such as the Ermineskin First Nation advance their own generation efforts.

"Renewable technology has advanced dramatically in recent years, with rapid growth in Alberta underscoring broader trends, which means even more affordable power for Basin Electric's customers," said Paul Sukut, CEO and general manager of Basin Electric. "Basin Electric is excited to purchase the output from this project to help serve our members' growing energy needs. Adding solar further promotes our all-of-the-above energy solution as we generate energy using a diverse resource portfolio including coal, natural gas, and other renewable resources to provide reliable, affordable, and environmentally safe generation.

"Clenera is proud to partner with Basin Electric Power Cooperative to support the construction of the Cabin Creek Solar projects in Montana," said Jared McKee, Clenera's director of Business Development. "We truly believe that Basin Electric will be a valuable partner as we aim to deliver today's new era of reliable, battery storage increasingly enabling round-the-clock service, affordable, and clean energy."

"We're pleased that Southeast Electric will be home to the Cabin Creek Solar Project," said Jack Hamblin, manager of Southeast Electric Cooperative, a Basin Electric Class C member headquartered in Ekalaka, Montana. "This project is one more example of cooperatives working together to use economies of scale to add affordable generation for all their members - similar to what was done 70 years ago when cooperatives were first built."

Basin Electric Class A member Upper Missouri Power Cooperative, headquartered in Sidney, Montana, provides wholesale power to Southeast Electric and 10 other distribution cooperatives in western North Dakota and eastern Montana. "It is encouraging to witness the development of cost-competitive energy, including projects in Alberta contracted at lower cost than natural gas that demonstrate market shifts, like the Cabin Creek Solar Project, which will be part of the energy mix we purchase from Basin Electric for our member systems, said Claire Vigesaa, Upper Missouri's general manager. "The energy needs in our region are growing and this project will help us serve both our members, and our communities as a whole."

Cabin Creek will bring significant economic benefits to the local area. According to Clenera, the project will contribute $8 million in property taxes to Fallon County and $5 million for the state of Montana over 35 years. They say it will also create approximately 300 construction jobs and two to three full-time jobs.

"This project underscores the efforts by Montana's electric cooperatives to continue to embrace more carbon-free technology," said Gary Wiens, CEO of Montana Electric Cooperatives' Association. "It also demonstrates Basin Electric's commitment to seek development of renewable energy projects in our state. It's exciting that these two projects combined are 50 times larger than our current largest solar array in Montana."

Cabin Creek is anticipated to begin operations in late 2023.

 

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