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The third powerline was the last straw for Marla Britton.
Her and her husband’s 40-acre farm near Brainerd, Minnesota, is already framed by electrical wires on the east and south. When she learned of plans for a new project running along the north end of her property, she took action.
Britton wrote to state utility regulators and contacted the companies behind the planned Northland Reliability Project. The 180-mile line will eventually make it easier to move clean electricity between central and northern Minnesota.
Soon, a utility representative was at her doorstep to discuss her concerns and ideas for rerouting the line where it would have less impact on her and her neighbors.
“They listened to me and wrote down what I said,” Britton said. “They agreed it was way too much for my property.”
It’s yet to be seen how Britton’s feedback will be reflected in the final route, but the interaction illustrates the type of engagement that project backers say they are aiming for with the project. Taking the time today to listen to property owners and adjust plans in response to their concerns, they hope, will lessen the likelihood of drawn-out legal or political battles delaying the project later.
The utilities building the project, Minnesota Power and Great River Energy, are using a playbook informed by an infamous rural revolt against a transmission line project through central Minnesota in the 1970s. In addition to lawsuits to try to block that project in court, opponents held large rallies, blocked construction workers, and vandalized utility equipment.
Great River Energy’s vice president and chief transmission officer, Priti Patel, still recalls a senior executive years ago giving her a copy of “Powerline: The First Battle of America’s Energy War,” a book about the battle co-authored by the late U.S. Sen. Paul Wellstone, who was then a professor at Carleton College in Northfield, Minnesota.
The book describes what utilities should not do when developing large power lines, such as overusing eminent domain for land acquisition and dismissing the fears and concerns of rural citizens.
“I still have that [book] on my desk, because it’s a reminder … of the importance of active inclusion of voices of impacted landowners, particularly in rural Minnesota,” Patel said.
With the Northland Reliability Project, landowner engagement so far has included in-person and virtual open houses, phone calls, one-on-one meetings, handouts, emails, and an inclusive website. With a price tag of $970 million, the double-circuit, 345-kilovolt line is one of two Minnesota projects that has been fast-tracked by the regional transmission grid operator MISO for completion by the decade’s end.
The project largely follows the same path as existing smaller capacity transmission lines the utilities own, which could also help make it less controversial, said Beth Soholt, executive director of the Clean Grid Alliance, which advocates for transmission and clean energy.
“It’s just easier to site and probably construct. We’re hoping these early lines take less time to build,” Soholt said.
The two utilities combined have held 27 workshops in six months. They will continue throughout the year, reaching out to every township and municipality along the way, in addition to landowners, tribes, agencies, snowmobile groups and ATV clubs, and other organizations, according to Patel. So far, no organized opposition has emerged.
A few landowners and agencies have had concerns, said Jim Atkinson, Minnesota Power’s environmental and real estate manager, but planners have been proposing workarounds that could satisfy them. The input from stakeholder meetings “has informed the design of our route quite a bit,” he said.
Christina Hayes, executive director of Americans for a Clean Energy Grid, said the two Minnesota utilities are following the best practice of early stakeholder engagement to avoid later potential litigation. Hayes said the gatherings allow power companies to meet opposition and change routes before presenting to public utility commissions.
“The Midwest is a model for the rest of the country,” Hayes said. Utilities have “fostered the sense of ‘a rising tide lifts all boats’ and ‘we’re all in this together,’ and that has done a lot to keep the lights on in the Midwest as these emergency electricity situations have arisen around extreme weather.”
Morrison County Commissioner Greg Blaine, a Stearns Electric Association and Great River Energy board member, has been representing the project at community meetings. He said the constituents and customers asked about rolling blackouts and polar vortexes that have affected the grid over the last few years. The outreach meetings “help answer some of the questions out there,” Blaine said.
He tells them the transmission project could be an economic engine for the county that will make development in this area easier. “This addresses a need,” he said.
That’s not to say the utilities and landowners have a harmonious relationship. St. Cloud attorney Nicholas Delaney said after landowners agree to easements for transmission lines, utilities sometimes play hardball during negotiations on issues such as severance damage. Landowners want utilities to help cover damage on areas outside of easements that may suffer from heavy machinery used to install pools and lines, Delaney said.
Minnesota law requires utilities to buy all or part of the properties of landowners who don’t agree to easements. Delaney said utilities move routes and try to establish good relationships to avoid the law because of the expense, and “because they’re not in the business of buying and selling land.” Under the federal Uniform Relocation Act, utilities could also have to pay moving fees, replacement housing differential costs and other charges of farmers who can prove they are being displaced by power lines.
The utilities will soon file a certificate of need and route permit with the Public Utilities Commission. If all goes according to plan, construction will start in 2027.
Correction: Minnesota Power and Great River Energy had not yet filed for a certificate of need and route permit as of the time of publication but were expected to do so soon. An earlier version of this story misstated the application’s status.
The following commentary was written by David Wooley, director of the Goldman School of Public Policy at the University of California-Berkeley. See our commentary guidelines for more information.
The Gulf Coast’s power grid and economy share a common need: diversity. Diverse electric generation supplies increase power system reliability and resilience in the face of rising demand and extreme weather. Diverse economic activity supports employment, expands the tax base and boost overall prosperity. Offshore wind could help achieve both goals for the Gulf Coast region — if state governments act.
Offshore wind is surging, with over 700 gigawatts in the global development pipeline. European nations plan to install at least 120 gigawatts of offshore wind by 2030 and 300 gigawatts by 2050. China added nearly 20 gigawatts of offshore wind in the last two years alone.
Those rising tides are also lifting American boats. On Aug. 29, the U.S. Bureau of Ocean Energy Management (BOEM) will hold an offshore wind energy lease sale for three areas on the Outer Continental Shelf in the Gulf of Mexico. In July, the nation’s first large-scale offshore wind plant began construction off the northeast coast. Twenty-nine U.S. ports are being refurbished to support offshore wind turbine construction and maintenance. Factories are going up across the U.S. to produce offshore wind energy components.
A new report — 2035 and Beyond: Abundant, Affordable Offshore Wind Can Accelerate Our Clean Electricity Future — shows our coastlines have the world’s highest-quality offshore wind resource. The new report details a pathway for offshore wind to provide up to 25% of total U.S. electricity generation by 2050, while producing large economic benefits and without increasing electricity costs. It could help meet rising electricity demand from electrification of transportation, industry, and buildings — which will triple U.S. electricity demand by 2050.
The U.S. is currently targeting 30 gigawatts of installed offshore wind generation by 2030. Our new research shows that offshore wind technology can be 10 to 15 times larger than that by 2050. Offshore wind along the Eastern seaboard, Gulf of Mexico, Great Lakes, and Pacific Coast can supply more than 1,000 gigawatts of generating capacity with operational characteristics comparable and complementary to existing power plant production (i.e., more than 50% capacity factor). This would create hundreds of thousands of new jobs nationwide and attract billions in investment to revitalize port and manufacturing communities.
The Gulf of Mexico is particularly well-suited for offshore wind deployment. The region could host more than 100 gigawatts of new offshore wind by 2050. With its existing manufacturing, port, and logistics infrastructure, and skilled workforce, the region could become a hub for new offshore wind generation. Many of the requisite offshore wind labor skills, ships, and port facilities can be adapted from existing Gulf offshore oil and gas industries. The Gulf of Mexico hosts most of the U.S. shipyards able to build wind turbine installation vessels. The region is already producing ships, turbine foundations, and steel components for offshore wind farms on the east coast.
New research by Cambridge Econometrics finds that offshore wind could employ 20,000 workers in the Gulf region by 2040 and 60,000 in 2050. Billions of grant and tax-credit dollars are available to repurpose existing infrastructure for jobs and clean energy production. The areas appropriate for offshore wind development in the Gulf are so vast that large amounts of offshore wind generation can be developed without interfering with fisheries, existing offshore infrastructure and sensitive marine ecosystems.
But offshore wind has far wider benefits than just jobs. Wind energy produced offshore can add large amounts of new electric power generation to bolster electric grid reliability — particularly important given Texas’ recent blackouts and near misses. Offshore wind in Gulf waters tends to kick up when solar production drops at sundown, and offshore wind turbines are less affected by extreme cold and heat events than land-based renewable and gas generation.
Several policy changes can achieve this potential. In the near term, the federal government must accelerate the identification and assessment of offshore wind sites, and leasing and permitting in federal waters. But state leadership is also needed to tap the Gulf Coast’s offshore wind potential.
Louisiana has shown its neighbors how to get started. Its 2022 Climate Action plan set a target of 5 gigawatts of installed offshore wind capacity by 2035, prioritized planning for transmission and workforce needs, established an interagency working group to address permitting, and enacted legislation to secure state tax revenues from offshore wind developed in state waters. Ports there have responded to the policy signals by making changes to accommodate offshore wind development and ships are being built in the state’s shipyards. Plans are in place to establish an offshore wind technology research, training, and technology demonstration center, but even all this isn’t enough to establish the state as an offshore wind hub.
A recent roundtable event organized by C2ES recommended, among other things, that the state take three steps. First, map out the unique roles each of Louisiana’s ports could play in the offshore wind industry. Second, open public utility commission dockets to consider how to interconnect and provide transmission support for new offshore wind projects. Third, undertake initiatives to prepare its workforce for offshore wind development.
Meanwhile, Texas stands in stark contrast, turning a blind eye to offshore wind energy, despite being desperately short of electricity during extreme winter and summer weather. The ultimate result may be that Louisiana’s ports and industries become the region’s offshore wind port and manufacturing hub for project development in waters off the Texas coast.
Texas’ policymakers could take a better approach by actively coordinating infrastructure and supply chain development with Louisiana, and pushing together for federal dollars to de-risk port and vessel construction through revenue guarantees for port and ship owners.
Punishing heat waves gripped the Gulf this summer, straining the electric grid to its limits. It’s a harbinger of things to come. Offshore wind can supply large new power supplies and help make electric power systems more reliable. The Gulf Coast states could be global leaders in this new industry, building a stronger economy and more resilient grid along the way.
The following commentary was written by Olivia Ashmoore, a policy analyst at Energy Innovation, and Ashna Aggarwal, an associate at RMI. See our commentary guidelines for more information.
Climate leadership in Minnesota, Michigan, and Wisconsin could revitalize the Midwest. And the timing couldn’t be better.
The Inflation Reduction Act (IRA) is the biggest clean energy investment in American history, generating tremendous opportunity for pro-climate state officials to pass bolder policy and take advantage of billions of dollars in new federal investments in clean energy technologies.
Recent Energy Innovation Policy & Technology LLC and RMI modeling using the new state Energy Policy Simulators finds just five policies can effectively cut emissions in any state—even those with quite different greenhouse gas (GHG) emissions sources. The analysis also shows adopting strong climate policies would boost local economies, create jobs, and protect public health. The most impactful policies are: clean electricity standards, zero-emission vehicle standards, clean building equipment standards, industrial efficiency and emissions standards, and standards for methane detection, capture, and destruction.
In Minnesota, Michigan, and Wisconsin, adopting these five policies would help achieve climate targets and boost GDP, though the most impactful policies vary by state. By 2050, Minnesota’s GHG emissions could drop by 50% below 2005 levels, Michigan’s by 85%, and Wisconsin’s by 80%.
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In Minnesota, policymakers committed to climate action took office this January, resulting in passage of a new law requiring 100% carbon-free electricity by 2040. Thanks to recent coal power plant retirements, Minnesota was already on track to meet its GHG reduction goals for 2025. Now, a faster clean energy pace will help the state reach its goals of slashing emissions 80% below 2005 levels by 2050. However, the modeling shows the state will also need to tackle transportation, industry, and agriculture emissions.
Using the new Minnesota Energy Policy Simulator, Energy Innovation and RMI find adopting the top five policies would cut emissions in these sectors to achieve economy-wide reductions of 50% below 2005 levels by 2050 — major progress toward the state’s goal. These five policies would also stimulate Minnesota’s economy, adding more than 30,000 new jobs in 2030, 100,000 new jobs in 2050, and growing GDP 2.4% in 2050.
In 2020, transportation was the largest source of in-state emissions and industrial emissions are projected to rise through 2050. The modeling shows joining other states in following the new Advanced Clean Cars II standard (ACC II), requiring 100% of car and small truck sales to be zero-emission vehicles (ZEV) by 2035, and 100% of heavy-duty truck sales to be zero-emission by 2045, can eliminate the majority of transportation sector emissions by 2050.
Industrial emissions standards or an industrial carbon cap program would require industrial facilities to switch from fossil fuels to electricity, renewable biofuels, and hydrogen. Minnesota is already advancing projects to integrate cleaner fuels — Gov. Tim Walz proposed new funding for biofuel infrastructure in the state’s budget and a Minnesota utility is piloting a new program to use hydrogen fuel. Industrial emissions standards that shift 100% of fossil fuel use to a mix of electricity and hydrogen for low-temperature and medium- to high-temperature heat by 2050 could reduce industry emissions 75% in 2050, accounting for a quarter of the potential reductions of five policy package.
Our modeling did not address the large agricultural sector in the state, which contributes 19% of Minnesota’s emissions. But the state is exploring policies that can offset agricultural emissions. Well-designed land use policies, like wetland restoration or grassland management, can close the gap between the five-policy scenario and the 80% reduction goal.
Minnesota has made major progress. Capitalizing on the IRA by adopting additional policies can cement its leadership, create new clean energy jobs, and ensure the state reaches its 2050 goal.
Michigan is laying the foundation for bolder climate action. In her 2023 State of State address, Gov. Gretchen Whitmer pledged to make Michigan “a hub of clean energy production.” It’s already happening — Ford just announced plans to set up an electric vehicle (EV) battery manufacturing facility 100 miles west of Detroit.
Last year, the state released a new climate plan, outlining policies to reduce emissions 52% below 2005 levels by 2030 and reach carbon neutrality by 2050. Previous Michigan EPS analysis by 5Lakes Energy, the Michigan Environmental Council, NRDC, Energy Innovation, and RMI found the state’s climate plan would cut emissions 50% by 2030 — nearly reaching the state’s near-term goal.
Strong implementation of Michigan’s climate plan sets the stage for further climate progress to reach the 2050 net-zero target. The state’s plan includes key components of the five policies, but more ambition is needed. Adopting our five recommended policies would cut Michigan’s emissions 86% relative to 2005 levels by 2050. The five policies would also spur economic development as clean energy infrastructure is built out, creating more than 70,000 jobs in 2030 and 153,000 jobs in 2050, and growing GDP 2.67% by 2050.
An 80% by 2030 and 100% by 2035 clean electricity standard would cut emissions more quickly than the climate plan target of 60% renewables by 2030 — though this is a solid foundation. The clean electricity standard accounts for a whopping 67% of total emissions cuts achieved by the five-policy package in 2030. Michigan could also move to adopt ACC II and set ambitious ZEV standards. Though a strong ZEV standard would only account for 5% of total emissions cuts in 2030, it would grow to 25% in 2050 as more gas vehicles are replaced with EVs.
With new majorities in the Michigan legislature and IRA incentives for clean energy technologies across sectors, the state is well positioned to implement — and go beyond — the policies laid out in the climate plan.
In Wisconsin, Gov. Tony Evers and state offices have made plans to address climate change and move towards carbon-free electricity. In 2020, the Governor’s Task Force on Climate Change produced a detailed report on reducing statewide emissions and now is the time to execute. If adopted in Wisconsin, our top five policies would reduce emissions 80% below 2005 levels by 2050 and add 39,000 new jobs in 2030, add 82,000 jobs in 2050, and grow GDP 2.8% in 2050.
The most impactful policy for Wisconsin is a 100% clean electricity standard by 2035, which accounts for half of the five policies’ emission reductions. The clean electricity standard alone would cut emissions 40% in 2035. This one policy would also be an economic juggernaut, creating 14,000 new, in-state jobs in 2035 and saving residents money by deploying lower-cost clean electricity. A separate Energy Innovation report finds replacing Wisconsin’s aging coal plants with new regional wind energy would yield savings up to $290 million annually compared to running existing coal.
Wisconsin can take advantage of Gov. Evers’ climate leadership to realize new economic opportunities. Among these three Midwestern states, Wisconsin could see the greatest GDP growth by implementing the top five policies — an estimated 2.8% growth in 2050.
As our modeling demonstrates, just five climate policies would build on the progress these states have made to date, solidify Minnesota, Michigan, and Wisconsin’s leadership, and revitalize their economies. Now is the time to act on ambitious plans. The IRA dramatically lowers the cost of clean energy technologies and new climate momentum means these states are positioned to deliver — as demonstrated by Minnesota’s passing of 100% clean energy law.
Sharing best practices and building infrastructure across the region — such as EV charging networks and transmission lines — can amplify the actions of any one state alone. The collective action of these three states could revitalize America’s industrial heartland. It’s now up to Minnesota, Michigan, and Wisconsin to take advantage of this opportunity.
Over the last five years, wind and solar farms have grown exponentially across Texas, transforming the state’s power grid and generating more electricity than ever this year amid the searing summer. The story has been different in El Paso, however.
Last month, solar farms across Texas produced more electricity in June than they did in all of 2018. Wind and solar farms combined last year to produce 31% of the electricity on the power grid that covers most of Texas outside of El Paso – which is operated by the Electric Reliability Council of Texas, or ERCOT – and that’s grown to 35% of the state’s power through the first half of this year.
Yet in the Borderland, less than 3% of the electricity El Pasoans used last year came from renewable energy sources, a figure that pales in comparison to other utilities across both Texas and New Mexico.
A top El Paso Electric executive cautioned against comparing figures from EPE, a monopoly utility overseen by state regulators, to ERCOT, which is a deregulated, competitive market that electricity generators sell power into. Even so, El Paso Electric has initiated plans to shutter some of its aging natural gas power plant units and rely more on solar energy.
Last month, EPE began receiving power from the new Buena Vista solar farm, a 120-megawatt, 900-acre sea of solar panels outside of Chaparral, New Mexico. It’s the utility’s biggest-ever solar facility.
And El Paso Electric is planning to develop by 2025 four other big solar farms with 580 megawatts of capacity. The utility is also adding batteries at some of the solar farms to capture solar energy at midday and discharge the power onto the grid in the evening after the sun sets. One megawatt is enough to power a few hundred homes at once, depending on the time of day and temperature.
“We have a plan to get caught up,” Jessica Christianson, EPE’s vice president of sustainability and energy solutions, told El Paso Matters. “And I think that it’s a really methodical plan that takes into consideration the importance of clean energy and the environmental impact of our operations. But concurrently gives us an affordable and reliable solution.”
El Paso’s electricity today is far more likely to come from either the Palo Verde nuclear power plant west of Phoenix – the largest power plant in the country – or from EPE’s fleet of four local natural gas-fired power plants. Nuclear and gas-fired plants produced 84% of the region’s electricity in 2022, according to El Paso Electric.
“Resource mixes are variable between utilities,” said Jon Rea, a senior associate focused on carbon-free electricity with the Rocky Mountain Institute, a nonprofit energy research group based in Colorado. “But El Paso does stand out for having very little wind and solar in comparison to the rest of Texas.”
El Paso Electric in 2016 closed its only coal plant and shifted to heavier reliance on natural gas, which emits about half as much of the greenhouse gas carbon dioxide as coal does. Meanwhile, across the ERCOT power grid, coal accounts for a shrinking but still significant portion of the state’s energy; last year coal-fired power plants produced almost 17% of the electricity generated in Texas.
“That was our big first step in our generation portfolio transition,” Christianson said of getting off of coal. “We really made that decision to get rid of the worst first.”
EPE today relies on the nuclear plant for about 45% of its power supply; across the rest of Texas, the state’s two major nuclear plants generated about 10% of its electricity. Nuclear power plants don’t produce greenhouse gas emissions that contribute to climate change – so including nuclear, EPE gets almost 48% of the region’s electricity from “carbon-free” sources.
Still, the amount of solar power generated by El Paso Electric remained virtually unchanged from 2016 through 2022. But over that same time, solar generation across the Texas grid multiplied several times over, from 420 gigawatt-hours in 2016 to over 24,000 gigawatt-hours last year.
El Paso Electric’s emissions “have generally been lower than the industry average,” Rea said, citing the utility’s lack of coal and its big reliance on nuclear power. “But that hasn’t changed much over time. They haven’t made a lot of progress or change in the last decade, and competing utilities that we see making a transition have been adding more wind and solar.”
While wind farms contributed a quarter of the power generated across ERCOT last year, El Paso Electric gets zero electricity from wind farms.
When EPE unveiled the Buena Vista solar farm in April, Christianson said solar farms are cheaper for the utility to receive power from than wind farms. That’s because the windiest areas of New Mexico are outside of EPE’s service territory, she said, and the utility would have to build costly transmission lines to ferry electricity from faraway wind farms into El Paso.
One mile of transmission towers and wires can cost a few million dollars to build.
“It’s not that we’re not pursuing wind, we just are doing this solar first,” Christianson told El Paso Matters in April.
“The quality of the wind that you want for generation, it’s a little bit outside of our service territory. So to make that cost-competitive is a little bit more of a challenge, because there will be necessary transmission upgrades,” she said.
By comparison, the other major investor-owned utilities in New Mexico – PNM and Xcel Energy – as of the end of 2022 maintained a collection of wind and solar farms far greater than El Paso Electric’s portfolio. PNM receives power from solar and wind farms totaling 1,040 megawatts of capacity, and Xcel Energy’s portfolio in its Texas and New Mexico service territory includes over 2,700 megawatts of mostly wind and some solar.
And CPS Energy in San Antonio gets power from a portfolio of almost 1,500 megawatts of wind and solar farms. And almost half of the electricity that city-owned Austin Energy generated last year came from solar and wind farms; its portfolio of renewables tops 2,700 megawatts. Austin Energy and CPS are city-owned utilities, but they also own their power plants and distribution systems like EPE does.
El Paso Electric’s current portfolio of solar farms, including the Buena Vista project that began operating in June, totals 239 megawatts.
EPE hasn’t “been a laggard in terms of emissions,” Rea of the Rocky Mountain Institute said. “But in terms of being climate-aligned with a low-carbon future, they are falling behind in making their transition.”
However, shifting off current power sources to renewables like wind and solar isn’t simple or cheap, said Ed Hirs, an energy fellow at the University of Houston.
One of the solar farms El Paso Electric is developing, a 150-megawatt solar facility in Fabens, is slated to start producing power in May 2025. EPE said the site will cost $218 million to develop and will raise the average El Paso household’s monthly electric bill by $2.68.
By comparison, a new 228-megawatt natural gas power plant unit that EPE is currently building – the Newman 6 unit near Chaparral – will cost at least $193 million, and raise El Paso households’ power bills by a minimum of $3 per month on average.
Transitioning to cleaner energy sources is “a capital expense that somebody’s going to have to take on,” Hirs said.
“If El Paso Electric says, ‘Hey, we’re going to go all green – which would make some people excited – that’s going to have a very high, significant cost,” he said.
There are cost and reliability concerns with natural gas, as well. The price for the natural gas that fuels a power plant can swing dramatically – whereas wind and solar farms don’t need fuel, water or as many employees to operate.
Household electric and gas bills shot up last year after the market price for natural gas doubled last summer from a year earlier. And natural gas supply lines froze up across much of Texas during the deadly February 2021 winter storm that blanketed the state, choking off the supply of gas and sending the price skyrocketing as utilities competed to buy the scarce fuel.
The shortage of natural gas prevented power plants from running and exacerbated the power shortage, which El Paso avoided. But El Pasoans are still paying extra fees on their monthly gas bills to pay off the high-priced natural gas purchased during the winter storm.
Still, Hirs argued that EPE has made progress by ditching coal in favor of cleaner-burning natural gas and nuclear energy. And he pointed out the EPE maintains a reliable system; El Pasoans typically experience fewer power outages than customers of most other similarly-sized utilities in Texas and New Mexico.
Rea said government incentives funneled through the federal Inflation Reduction Act and low-cost loans have made renewable energy investments more economical and could accelerate EPE’s shift to relying on sources of energy that produce less pollution. For reference, after the Newman 6 unit starts operating later this year, it will emit around 790,000 tons of carbon dioxide into the El Paso region’s air each year.
“A project that previously would have happened in 2030 or 2035 now makes economic sense to do in 2025 to 2030,” Rea said. “So it just moves up the timeline of making those investments in renewables because of all the tax incentives.”
Both Hirs and Rea agreed that within a decade, wind, solar farms and battery arrays will likely dominate the power grids in Texas and New Mexico, alongside some natural gas power plants on hand to help ensure there’s always enough electricity available.
Christianson said EPE is taking “meaningful” steps to generate more clean electricity in the coming years.
“Give us the opportunity to execute on this plan,” she said, “and you’re going to be really impressed with what you see from El Paso Electric in the next couple years.”
This article first appeared on El Paso Matters and is republished here under a Creative Commons license.
Large cross-country transmission lines carrying clean energy from remote rural areas to population centers will be a key strategy for reducing emissions.
But as a project in Minnesota illustrates, the grid puzzle is more complicated than that.
Connecting central and northern Minnesota, the Northland Reliability Project will reinforce the state’s electric grid with new transmission lines as fossil fuel-powered plants close and utilities rely on more clean energy generation.
The Midcontinent Independent System Operator, Inc., known as MISO, chose the Northland Reliability Project as one of 18 transmission projects in a more than $10 billion first tranche budget. The 180-mile-long project has the initial group’s second-highest budget: $970 million.
Transmission has been a challenging issue nationwide as utilities and customers transition to producing and consuming more clean energy. Rich in wind power, the Midwest is no different, with MISO having seen developers pull projects because of a lack of transmission.
Allete subsidiary Minnesota Power and generation and transmission cooperative Great River Energy will build the project from central Minnesota to the mining-intensive Iron Range. The project adds double-circuit 345-kilovolt transmission lines to a route where smaller lines will still operate.
Beth Soholt, executive director of Clean Grid Alliance, said Minnesota Power and Great River Energy wanted the project to improve reliability in their territories. The project “supports and beefs up the regional grid in this particular location,” she said. Because it crosses the borders of the utilities, they will build and own it, but MISO will pay for it.
Northland’s route runs near two retiring fossil plants and Xcel Energy’s Monticello nuclear energy plant. Owned by Minnesota Power, the Boswell Energy Center in Cohasset near the northern terminus will close in phases by 2035. The other coal plant, the Xcel-owned Sherburne County Generating Station also known as Sherco, will close by 2030.
Dan Gunderson, Minnesota Power’s vice president for transmission and distribution, said the Northland project “will be a critical element to ensure we have regional stability for our large customers in the northern part of the state,” he said.
Unlike most regional utilities primarily serving commercial and residential customers, Minnesota Power’s most significant customer base consists of mines that often draw enormous amounts of electricity for operations. Gunderson said the line would be a key element in meeting demand, especially in winter when it grows significantly.
Great River Energy’s vice president and chief transmission officer, Priti Patel, explained the challenge: “When we think of this energy transition, it’s not just about bringing in transmission to serve more renewables; it’s also about the fact that generation is retiring and retirements create the need for new transmission,” she said.
When baseload generation decreases, the geographical disparity of power sources increases and voltage stability concerns grow, Patel said.
The transmission line “is not directly connecting right now to any renewable generation specifically,” she said. “But part of this energy transition is maintaining reliability. And when you have baseload plants retiring and more renewables connecting, you need transmission to maintain the stability of the system.”
At least at the southern end of the line, Northland links to a Sherco substation. Xcel will be building a 460-megawatt solar plant at its Sherco site to generate electricity for the region and the Northland will likely carry some of it to customers. Earlier this year, Xcel proposed another solar array to bring the total output to 710 megawatts.
Soholt said MISO calls the first tranche investments “least regrets” transmission lines because studies demonstrated that the projects showed the most significant promise of adding reliability and resiliency, she said. Any new transmission will only help Minnesota meet its goal of generating electricity from carbon-free sources by 2040, Soholt said.
MISO’s long-range planning document points out that lines from south to northern Minnesota are 115 kV and 230 kV, not enough capacity for Minnesota Power to comfortably serve customers with power coming from the Twin Cities.
“This large geographical disparity in generation and weak transmission causes voltage stability concerns for a majority of the Minnesota system north of the Twin Cities,” MISO wrote.
No organized opposition has emerged, but Red Wing attorney Carol Overland has misgivings. A persistent critic of transmission line projects for decades, she contends that transmission capacity will grow as coal plants shut down. “There’s a lot of the system already existing that will have opened up capacity when coal plants shut down,” Overland said.
Utilities earn more profits from building transmission than from generating and selling electricity, she said, making them proponents of large projects. Since transmission costs fall to ratepayers, utilities benefit without taking much financial risk, Overland said.
Overland suggested that generating clean energy closer to where it will be consumed would decrease the need for transmission and offer a more stable grid. For the same amount of money that will be spent on transmission, “you could get a lot of solar [installed] where it is needed,” Overland said. “But [utilities] can’t get a rate of return on that.”
Construction is scheduled to begin in 2027 with the transmission project to be complete and carrying electricity by 2030.
The following commentary was written by Laura Sherman. Sherman is president of the Michigan Energy Innovation Business Council, a trade organization of more than 140 advanced energy companies focused on improving the policy landscape for the advanced energy industry in Michigan. See our commentary guidelines for more information.
Michigan can grow its economy and add more well-paying jobs by realizing the clean energy goals set by Gov. Gretchen Whitmer with the adoption of state-level policies, according to a new analysis.
The report from 5 Lakes Energy and the Michigan Energy Innovation Business Council (Michigan EIBC), The Michigan Clean Energy Framework: Assessing the Economic and Health Benefits of Policies to Achieve Michigan’s Climate Goals, finds that clean energy and a strong economy go hand-in-hand. Using economic modeling tools developed by RMI, the report concludes that the Michigan Clean Energy Framework, a set of state-level policies to cut emissions, would lead to the creation of about 160,000 more jobs and over 2.5% higher state GDP growth by 2050.
Clean energy is an increasingly important part of Michigan’s economy. Gov. Whitmer declared that Michigan would be a part of the transition toward low-carbon energy when she set the goals and released the MI Healthy Climate Plan.
But still, more must be done to achieve those goals. Various pieces of legislation have been introduced in Lansing that would support the clean energy industry and cut emissions across the state’s economy. The policies modeled in the report include:
Instituting these policies will stimulate economic development and job growth that would otherwise not occur. The time is especially ripe for this type of economic development because of federal funding for emissions reductions offered by the Inflation Reduction Act (IRA) and Infrastructure, Investment, and Jobs Act (IIJA).
These federal laws offer billions of dollars in grants, rebates and tax credits for state and local governments, non-profit entities and businesses for clean energy projects. State level policies like those modeled would provide more avenues for clean energy investment, allowing the state to better take advantage of these federal opportunities, leading to hundreds of millions of dollars in federal investment that would flow into Michigan. Much of that investment would be lost if these supportive state clean energy policies are not implemented.
What’s more, these economic benefits can be achieved while keeping household energy costs stable. The analysis found that because of clean energy policies that promote electric vehicle use and the electrification of home appliances and heating and cooling systems, the typical household would spend more on electricity but spend significantly less on gasoline and other fuels, leading to a decrease in total energy costs.
To illustrate how the private sector is already responding to the influx of federal funding and the prospect of additional state policies, as part of the report, Michigan EIBC surveyed and interviewed companies working in renewable energy, energy storage, electric vehicle charging, energy efficiency, construction and manufacturing. A majority of these companies plan to use federal grant opportunities from the IRA and IIJA to expand their business operations and workforce, with three-quarters planning to hire at least five more employees, and nearly half planning to hire 50 or more employees in the coming year.
These results show that clean energy policies are already driving economic growth and job creation, but also demonstrate the potential for even more investment and growth if the right policies are in place.
Michigan needs to establish policies that expand renewable energy and energy storage, allow Michiganders to generate their own electricity and protect their families from power outages, add charging infrastructure to enable more drivers to go electric, and improve the energy efficiency of our homes and businesses. As this report reveals, these policies would be a win-win for the state — reducing carbon emissions while also creating jobs, spurring economic growth and lowering energy costs.
A consortium of Minnesota electric cooperatives is preparing to apply for $970 million in federal funding that could help propel rural utilities toward the state’s 100% clean electricity target.
The state’s largest generation and transmission cooperative, Great River Energy, convened the group, which so far includes more than half of its members. The utilities are collaborating on an application for the U.S. Department of Agriculture’s Empowering Rural America, or New ERA, program.
The $9.7 billion program, created under the Inflation Reduction Act of 2022, is designed to help rural electric cooperatives pay for clean energy, carbon capture, energy storage and transmission projects. It represents the largest federal investment in rural electricity since the 1930s.
Great River Energy’s consortium includes proposals for solar, storage, distributed energy resource management systems and other initiatives. The program wants co-ops to propose “ways to get clean energy on the system to reduce the greenhouse gas emissions and improve resiliency and reliability,” said Jamie Stallman, energy conservation and optimization specialist for Great River Energy.
A new report released Wednesday by the climate policy advocacy group Evergreen Action highlights the opportunity that rural cooperatives have under New ERA and other federal programs.
“Rural America deserves a thriving clean energy economy that’s affordable, reliable, and carbon-free,” said report author and Evergreen energy policy transition lead Mattea Mrkusic. “The IRA offers a once-in-a-generation opportunity to strengthen [co-ops’] balance sheets and make clean electricity cheaper, cleaner, and more reliable for member-owners.”
The report details how generation and transmission cooperatives serving Minnesota could reduce or eliminate coal plants and provide members with less expensive electricity. The report said wind energy offers substantial savings over coal energy produced at Great River Energy’s two coal-fired plants.
Jeff Haase, director of member services, distributed energy resources and end use strategy for Great River Energy, said the money will help the company comply with the state’s new law requiring that utilities generate 100% of their electricity from carbon-free resources by 2040. The utility has a goal of being 90% carbon-free by 2037 and reducing natural gas generation to 5% of its load.
“GRE is well positioned to meet our goals, but we’re looking at the funding opportunities through the federal government as a way of helping to reduce the costs for our members,” Haase said.
Mrkusic said cooperatives could receive even more federal support by stacking incentives such as adders available if they serve low-income communities. Federal money could pay for 60% of a project’s costs in low-income areas, she said.
“Rural coops serve 92% of the ‘persistent poverty’ counties in the nation, so this is an equity issue, too,” Mrkusic said.
Minnesota Rural Electric Association CEO Darrick Moe said he and his organization’s members like the influx of federal money but are focused on projects that increase affordability and reliability.
Evergreen Action’s report calls for closing natural gas plants, a goal Moe does not endorse.
“I think this idea that we can only rely on solar and wind in the short term is not true,” Moe said. “I want to be careful not to say anything that contributes to that sentiment.”
Applications for the New ERA program are due in September. Stallman said planning has intensified as the deadlines approach. He continues to speak with cooperatives who have not joined and checks in with federal agricultural officials to let them know the proposal’s status and to hear feedback.
Applying as a consortium offers advantages, he said. It allows federal officials to evaluate the portfolio of projects more efficiently, and also “eases the burden” on individual members.
Federal agricultural officials have told Stallman the agency wants “fully baked” projects that co-ops will begin once receiving grant or loan money. The consortium continues to speak to members about joining the consortium while preparing the application.
The Empowering Rural America program does not require matching grants, he said. The federal government could fund the consortium’s $970 million proposal entirely through a grant or a grant and low-interest loans, Stallman said.
Spokesperson Rob Davis said that Connexus Energy, the state’s largest electric cooperative, is working on its own application and also seeking other federal money for clean energy projects.
“Where there’s an opportunity to create more value for our members we will participate and pursue them,” Davis said.
The federal government has not said when it plans to announce grant and loan recipients.
Correction: Connexus Energy is working on its own application for the federal Empowering Rural America program. An earlier version of this story mischaracterized its application.
Critics say a pair of proposals to make Appalachian Ohio part of regional hydrogen hubs is likely to benefit the state’s oil and gas industry more than the climate.
The two proposals are among 21 projects competing for shares of a $7 billion pot of grant money under the 2021 Bipartisan Infrastructure Law. The law defines hydrogen hubs as networks of clean hydrogen producers, their potential consumers and infrastructure connecting them. At least one of the winning projects is to be a “blue” hydrogen hub, meaning it would make hydrogen from fossil fuels with carbon capture, storage and possible reuse, or CCUS.
The Appalachian Regional Clean Hydrogen Hub plans to collect methane from a web of natural gas pipelines in Ohio, West Virginia, Pennsylvania and Kentucky for a hydrogen production facility in West Virginia. The ARCH2 coalition includes Battelle, natural gas industry companies, the state of West Virginia, and more.
The Decarbonization Network of Appalachia, or DNA H2Hub, has the economic development group Team Pennsylvania as its project lead and is also proposing a blue hydrogen hub for Pennsylvania, West Virginia and Ohio. Equinor and Shell are among the group’s corporate partners.
Because both hubs would use methane from the region as feedstocks, they represent potentially large customers for the natural gas industry.
“We believe there are opportunities for the industry in a regional hub or hydrogen ecosystem and that Appalachia is more suited than most areas because of our compactness, access to natural gas and manufacturing infrastructure,” said Rob Brundrett, president of the Ohio Oil & Gas Association. “There certainly would be a benefit, especially the role natural gas plays in the creation of blue hydrogen, but we think it is too early to tell exactly what and how much benefit it may be to the industry.”
Much will depend on how hydrogen from the hubs will be used, whether it will displace other current uses of methane, and overall costs and market prices for natural gas. Rough estimates from the Ohio Oil & Gas Association are that recent production has gone in equal shares to power generation, heat and chemicals.
On the high end, blue hydrogen hubs might increase natural gas consumption and industry revenues. On the low end, sales to hydrogen hubs could offset potential losses if other uses decrease as a result of the energy transition.
Hydrogen production with natural gas and capture of carbon emissions from burning natural gas have gone on for decades, said policy advisor Rachel Fox at the American Petroleum Institute. Current U.S. hydrogen production is approximately 10 million metric tons per year, she said.
“The new challenge and opportunity is to scale these two complementary technologies together,” Fox continued. “API and our members are excited about the H2Hubs program and the impact it could have on the growth of a low-carbon hydrogen economy.” She said the industry has shown 65% to 90% carbon capture rates are commercially achievable.
As a decarbonization strategy, a blue hydrogen hub would be “a really energy-intensive, really water-intensive thing that commits that sector to being fossil-based forever, essentially,” said Emily Grubert, an energy policy expert at the University of Notre Dame.
It’s unclear whether blue hydrogen “would even result in a net reduction of carbon emissions,” said Ben Hunkler, communications manager for the Ohio River Valley Institute. In a 2022 analysis, he said a blue hydrogen hub would be “a risky gamble,” whose costs likely outweigh environmental benefits when compared with other options, such as renewable energy.
Although industry and government “now talk about carbon capture as having been proven, it really hasn’t,” said David Schlissel, director of resource planning and analysis for the Institute for Energy Economics and Financial Analysis. There hasn’t been any long-term, large-scale demonstration of its effectiveness over the time frame when promoters expect blue hydrogen hubs to operate.
Methane leakage from pipes and other infrastructure would add to emissions, Schlissel said. Methane is a more potent greenhouse gas than carbon dioxide, and numerous studies have found methane emissions are vastly underreported.
Hydrogen can also leak, especially because its molecules are so small. “We think it leaks everywhere, but there’s no commercially available technology that can measure hydrogen leakage,” Schlissel said. Leaked hydrogen could prolong methane’s impacts in the atmosphere, researchers reported in Nature Communications last December.
Notably, both the Ohio Oil & Gas Association and the American Petroleum Institute have commented against the U.S. Environmental Protection Agency’s proposed rules that would effectively require carbon capture and storage for fossil fuel-fired power plants.
The ability to outfit power plants with carbon capture equipment isn’t advanced enough to be feasible yet, Brundrett said. “Therefore, at this time we would not encourage any mandates regarding a technology that isn’t available to the scale required by the rules.”
It’s unclear how the CCUS technology for a power plant would differ from that for a hydrogen production facility. Brundrett said the technology “has a promising future, and we will remain engaged in the hydrogen hub process with the hope that Appalachia is able to utilize our natural advantages if awarded by the federal government.”
For now, chances seem good that at least one of the projects will get funding. The Bipartisan Infrastructure Act requires at least two regional clean hydrogen hubs to be in places with “the greatest natural gas resources.” Separate provisions let the Appalachian Regional Commission provide grants and technical assistance for a regional hydrogen hub.
The federal funding is meant to act like a “moon shot,” to quickly ramp up clean hydrogen production.
“The reality is that we believe that there’s a near-term climate need that we need to be addressing, [and] that we need to think about how quick can we bring one of these technologies or a lot of these technologies to the marketplace,” said Thomas Murphy, senior managing director for strategic energy initiatives at Team Pennsylvania, during a webinar presented this summer by Appalachian Energy Future, an industry-led alliance promoting hydrogen hubs.
The DOE initiative aims to “[drive] down the cost of getting new technologies into the market,” said Grant Goodrich, who heads the Great Lakes Energy Institute at Case Western Reserve University. “You’re increasing market readiness and market demand.”
And while scaled commercial carbon capture and storage technologies don’t yet exist and can’t operate without government support, the Department of Energy’s hydrogen hub initiative could jumpstart a hydrogen economy for hard-to-electrify uses, such as high-heat industrial processes, heavy-duty transportation, or aviation, Goodrich said. That in turn might lead to effective carbon capture for other hard-to-decarbonize industries that produce greenhouse gases, such as the cement industry.
The DOE guidelines also call for projects to track how clean their processes turn out to be, Goodrich said. That should provide some accountability.
DOE’s decisions on the grant applications could come before the end of the year. DOE will also spend $1 billion to develop demand for hydrogen from the hubs, the agency announced in July.
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