Indiana ratepayers spend hundreds of millions of dollars per year for power from coal plants that are operating despite the availability of cheaper sources, including wind and solar.  

The state is emblematic of a larger problem, as electricity market rules typically allow utility-owned power plants to essentially cut in line even when they are not the most economical option for customers.  

A recent report commissioned by the Natural Resources Defense Council examined how this phenomenon plays out in the Midcontinent Independent System Operator (MISO) regional transmission organization specifically, building on previous research by RMI, the Union of Concerned Scientists and others — all of which show that uneconomic coal plant dispatch takes a huge toll on ratepayer wallets and public health. 

The problem happens primarily with vertically integrated utilities or municipal utilities and cooperatives, which can recoup costs of fuel and operations from ratepayers even if they are operating at a loss. In most of MISO territory, energy markets have not been restructured as open markets, making such cost recapture the norm. 

The NRDC study showed that Indiana ratepayers bore the second-highest burden in MISO, paying $338 million for uneconomic coal power from 2021-2023, just behind Louisiana’s $341 million. North Dakota ratepayers spent an extra $120 million, Wisconsin $69 million, and Minnesota $54 million, the study found. 

Indiana’s R.M. Schahfer plant, run by utility NIPSCO, cost ratepayers more than $100 million in such uneconomical dispatch from 2021-2023, the NRDC study found. 

In an ongoing rate case, Duke Energy is seeking to increase reliance on its Gibson and Cayuga plants in Indiana. These plants were responsible for $29 million and $7.6 million in uneconomic dispatch costs to consumers in 2023, according to RMI’s economic dispatch dashboard. 

“This has been a problem plaguing Indiana coal plants for many years, it’s costing our consumers in Indiana millions of dollars and it’s one of the factors driving rates higher and driving clean energy off the grid,” said Ben Inskeep, program director for Citizens Action Coalition in Indiana. “It’s a tale of utilities making bad decisions as part of their profit motive and then utility regulators failing to hold them accountable as they’re supposed to. Certainly utilities should be operating their plants efficiently and economically, and when they fail to do so, they shouldn’t be getting cost recovery.” 

Duke spokesperson Angeline Protogere said the study misses important context. 

“There are a lot of considerations that go into plant dispatch decisions, and the priority is always reliability of service and economics,” Protogere said. “We weren’t able to replicate the NRDC data, but it appears it’s based on incomplete information. For example, there are times when MISO calls on a unit because of grid reliability needs. There’s a bigger picture that’s not reflected here.”

Skewed markets

The NRDC study found that over three years across MISO, about 400 MW of wind power was curtailed in favor of power from coal plants generating at higher-than-market costs. 

Power producers bid into regional energy reverse-auctions for real-time and next-day power, offering the price for which they can produce their electricity. Grid operators like MISO and PJM are supposed to dispatch the power starting with the most affordable option, until demand is met. 

Even if vertically integrated utilities are not selling their power on the open market but rather serving their own customers, they still need to be dispatched by the grid operator to send their energy onto the grid. 

But under the rules for MISO and other grid operators, coal plants can “self-commit” to run for a given time period even if they cannot produce power below the market rate. The idea is that coal plants can’t ramp up or down quickly, so they may need to keep running at a certain level to be ready to provide more power when needed.  

If this relatively expensive coal power weren’t on the grid, more wind power would be purchased and demand for new renewables would likely be created. 

“That increment of power would be filled through the market selecting the next highest bidder,” providing “an accurate picture of what electricity should cost that gives a signal that incentivizes newer generation,” explained James Gignac, Union of Concerned Scientists Midwest senior policy manager. 

The lower the energy prices at a given time and the lower the demand, the worse the coal plant dispatch problem gets. Data from RMI and a 2020 report by the Union of Concerned Scientists shows that ratepayer losses due to uneconomic coal dispatch were lower in 2022, because Russia’s invasion of Ukraine caused natural gas prices to spike, making coal more competitive by comparison. Conversely, when energy demand plummeted in 2020 because of the pandemic, uneconomic dispatch of coal plants soared. 

Since 2015, the uneconomic dispatch of coal plants has cost Indiana ratepayers $1.9 billion and ratepayers nationwide $20 billion, according to RMI’s dashboard. 

The issue has real impacts on the growth of renewables, experts note. If the practice was prevented, market prices would be higher and there would be more incentive for renewable developers to build projects to sell their power on the open market. Meanwhile if vertically-integrated utilities were not allowed to recoup their costs for uneconomic dispatch, they would be motivated not to run coal plants and might decide to invest in building renewables instead, or at least buy wind power on the open market.    

“I’ve talked with [wind] developers who say they look at where coal plants self-commit uneconomically, and they avoid those transmission lines because they know they will be curtailed,” said Joseph Daniel, principal in RMI’s Carbon Free Electricity team and lead author of the Union of Concerned Scientists report. 

That report shows that if uneconomic coal dispatch was avoided, Indiana customers would save money — but not as much money as ratepayers in other states, because there is less wind power available around Indiana. Over time, a market unfettered by uneconomic coal plants might correct this situation. 

“The greatest immediate savings for customers from stopping uneconomic coal plant operations are in areas where there are existing low-cost resources such as wind power being curtailed by that behavior,” said Gignac. “If the replacement for the uneconomic coal generation is something like a relatively higher-cost gas plant, then the market clearing price is higher and customer savings are not as significant. However, that higher clearing price is a signal and an incentive for low-cost renewables to locate projects in that area and deliver further cost savings. 

“Removing the market distortion of uneconomic coal operations helps move us toward the cleaner, lower-cost energy system we need.” 

Solutions   

Studies show that coal plants that sell their power on the open market – known as “merchant” plants – rarely decide to operate when they are not getting market prices at least equal to their cost of operating – the way vertically-integrated or publicly-owned coal plants do when they know they can recoup their costs from ratepayers, without compensation from the market. In other words, merchant plants do not ask grid operators to be uneconomically dispatched. 

These merchant plants nonetheless seem to ramp up in time to operate when their power is needed, experts note, indicating that vertically-integrated plant operators in MISO are understating their ability to ramp up and down quickly, as noted by NRDC policy analyst Dana Ammann and other experts.  

“There’s so little incentive to ramp up quickly, because the market really accommodates their inflexibility,” said Ammann, lead author of the recent NRDC study. The vertically-integrated coal plants in MISO are “much less flexible than coal plants in other markets. In PJM you see coal plants turning on much more quickly, since the merchant plant operators are reliant on the price signals to turn a profit. They don’t have the guaranteed rate recovery, so they’re very responsive to price signals.” 

State utility commissions can prevent regulated utilities from recouping costs when coal plants are dispatched uneconomically. Michigan regulators did exactly this last year in a rate case for Indiana Michigan (I&M) Power, preventing the utility from passing on such costs for its share of the Rockport coal plant, located in Indiana.  

Daniel said Indiana regulators should likewise protect Indiana customers from paying for uneconomic power from the Rockport plant. The RMI dashboard shows that plant dispatched $142 million worth of such power last year. Meanwhile the Michigan ruling could be considered precedent for Michigan utilities like DTE and Consumers Energy in future rate cases. 

Ammann noted that states can also use the Integrated Resource Plan process to curb uneconomic dispatch, as Minnesota’s utility commission did when it recently decided that Otter Tail Power’s Coyote coal plant can only recoup costs during a designated power emergency.

“It’s an interesting approach for getting ratepayers basically off the hook for coal plants that aren’t retiring, that might still be economic to run for a small number of hours,” Ammann said. 

Grid operators like MISO may have the most important role to play in better managing markets, refusing to dispatch coal plants that aren’t necessary and doing deeper analysis to figure out exactly how much power is needed. Experts say multi-day markets – rather than just real-time and day-ahead ones – could better match supply with demand and avoid unnecessary coal plant dispatch. 

MISO’s Independent Market Monitor has recommended such measures, including de-committing coal power producers who sold into the day-ahead market if it turns out that others – including renewables – could sell power more efficiently in the real-time market once the time comes. 

“MISO works closely with our members, state regulators and our independent market monitor to ensure our markets are efficient,” said MISO spokesperson Brandon Morris. MISO’s June 2024 monthly operations report shows that in June, 18% of coal-fired power dispatched in the region was uneconomic self-committed dispatch. 

Experts note that fuel delivery contracts often include a minimum purchase, so utilities committed to buying a certain amount of fuel might as well burn the fuel even if they are not making a profit on the power. This might not have been an issue in years past when coal plants operated at high capacity most of the time, but as coal plants have become increasingly uncompetitive, the NRDC study notes, they are more likely to be committed to buy fuel they actually don’t need. Fuel contracts are usually of short duration, with 88% of those reviewed by the federal Energy Information Administration expiring by 2025, meaning there is ample opportunity for fuel delivery contracts to be revised, the NRDC study said. 

Such fuel contracts have meant massive stocks of unneeded coal piling up at Duke plants in Indiana, Inskeep said, forcing the company to burn it even if the power isn’t needed.

Protogere said the coal supplies are necessary, as “the goal is to ensure a reliable supply in an increasingly uncertain market. The aim is to manage volatility as well as maintain long-term supply reliability and security, so that we don’t have to resort to higher cost options in the market.”

Inskeep hopes state regulators deny requests by Duke and other utilities to increase coal-fired generation and the recouping of the costs from ratepayers. 

“The bottom line with this uneconomic dispatch situation is it means utilities are keeping their old expensive coal plants open longer than they should,” Inskeep said. “Utilities should be rapidly transitioning to a renewable energy-based portfolio of resources. Instead, utilities are feeling pressure to justify a lot of the bad economic decisions they’ve made in the past, foolish decisions to invest millions or even billions of dollars to keep these plants open.”

Indiana’s dependence on coal is costing ratepayers millions and holding back clean energy growth is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

The Midwest’s regional transmission grid operator this week announced another multi-billion dollar phase of transmission line projects as part of a four-part push to improve reliability and reduce curtailments.

The Midcontinent Independent System Operator (MISO) unveiled plans Monday for what’s known as its “Tranche 2” portfolio, which includes plans for several 765 kilovolt transmission “highways” spanning sections of Minnesota, Iowa, Wisconsin, Illinois, Indiana, Michigan, North Dakota and Missouri.

Many of the new lines would connect to projects being built as part of the $10.4 billion Tranche 1 portfolio, which MISO approved last year. Tranche 2 is projected to cost even more, at between $17 billion and $23 billion. A third batch of projects will focus on the grid operator’s southern territory, and the fourth will address north-south connections.

In its presentation to stakeholders, MISO officials said the investment will help manage challenges in three regions. In MISO West, which includes Minnesota, Iowa, North Dakota, Wisconsin and Michigan’s Upper Peninsula, 20% of its facilities are overloaded and annual curtailments exceed 15%.

In its Central region, composed of parts of Illinois, Indiana, and Missouri, facilities are 10% overloaded, and there’s a need for transmission to move power from west to east.

MISO’s East Region, defined as Michigan’s lower peninsula, suffers annual curtailment of over 15% and 10% of facilities are overloaded. MISO said in a presentation that transmission would help mitigate “import and export power swings between day and night.”

Beth Soholt, executive director of the nonprofit Clean Grid Alliance, said the Tranche 2 plan is  “bold” and “the direction we need to go.” The question is: does it go far enough?

The regional grid is expected to see significant growth from industries, electrification, data centers and other sources, Soholt said. 

“If load growth ramps up faster than the grid can handle, then we’re behind the eight ball again,” she said. “Now is the time to ask: Have we right-sized this portfolio?”

Mike Schowalter, senior manager of wholesale electric grid transition for Fresh Energy, said he was surprised by the lack of a High Voltage Direct Current (HVDC) line.

“If we’re looking at the long-term, we’re going to need the attributes that HVDC brings,” Schowalter said.

The Energy News Network is an independent journalism program of Fresh Energy.

A 765 kV transmission line needs taller towers and a much wider corridor than HVDC or other alternatives, Schowalter said. 

“I’m a little concerned about some of the siting issues that the different states will have to deal with,” he said, noting that the map shows a 765 kV Minnesota River crossing.

Utilities have told Schowalter that the plan misses future pockets of generation that may need additional transmission. He said the reason may be because the draft report centers on reliability, not interconnection constraints.

The plan also does not venture much into North Dakota, which has plenty of wind generation, Schowalter said. The draft plan “will help with some congestion, but will it help enough?” he said. “Probably not. In terms of relative to what we need, we need a lot more than this.”

Some utilities also think deploying HVDC lines would better solve grid instability issues, especially between wind-rich Southwest Minnesota and the more populated regions to the east, Soholt said. HVDC transmits electricity more efficiently than alternate current lines, which have higher rates of power loss. 

Utilities have often had to curtail wind power from southwest Minnesota because of transmission capacity issues. Clean energy advocates and others will be closely listening to the business case MISO will make later for the choice of the transmission locations and the size of the lines, she said.

Soholt said comments are being taken now on the plan and some stakeholders will offer modifications and alternatives. Some clean energy developers and members of the Clean Grid Alliance plan to suggest alternatives. Some organizations are expected to argue that MISO does not need this much transmission and others will tender a different vision, she said.

So far, MISO has released only a rough map of where the lines would run, without much detail. A stakeholder process will refine precisely where the lines will operate, Soholt said. 

Stakeholder input and alternatives to the Tranche 2 plan will be accepted through April 5. MISO will make a final decision later this year.

Fresh Energy staff, board members and funders do not have access to or oversight of the Energy News Network’s editorial process. More about our relationship with Fresh Energy can be found in our code of ethics.

The Midwest’s grid operator is planning a massive new transmission buildout. Will it be enough? is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

The final report from a Republican-led state task force cautions against shifting to renewables too quickly and contradicts a previous, more-detailed analysis. 

A new report from an Indiana legislative task force appears to lay the groundwork for justifying power-plant bailouts similar to those in Ohio and Illinois, despite assurances from state regulators and the region’s grid operator that coal plant closures do not pose a threat to grid reliability.

The Indiana Legislature’s Energy Policy Development Task Force issued a long-awaited report on Thursday, after two years of studies, meetings and testimony from about 100 experts. The report was meant to examine how the shift in energy sources will affect power reliability, resiliency and other factors. 

“It really landed exactly where myself and others predicted,” said Kerwin Olson, executive director of Citizens Action Coalition, “that it would be vague and leave the door open for more evil coal activity in the next legislative session. That’s precisely what happened.”

The report’s findings and recommendations cover only three pages and raise concerns about electric grid reliability if the state shifts to renewable energy too quickly, with vague references to recent grid problems in California. 

During the Republican-led task force’s final meeting, when members voted to adopt the report and pass it on to the full legislature, chair State Rep. Ed Soliday said legislation has already been drafted related to reliability.

“Reliability is the new code word for ‘how do we support coal?’” said Ben Inskeep, an Indianapolis resident and energy policy analyst with EQ Research who has closely followed the proceedings. 

Stakeholders are particularly concerned about the task force’s third recommendation, which asks the legislature to “create a mechanism … to assure generation and transmission resource adequacy throughout Indiana.” 

“It sounds a lot like what was done in Illinois and Ohio, in bailing out their uneconomic fleets,” Olson said, referring to supports for those states’ nuclear plants and Ohio’s coal plants. 

“Illinois and Ohio aren’t the same, nevertheless it reads eerily similar to creating a mechanism under the guise of reliability. In Indiana when we use the word reliability, we’re really talking about baseload, and when you’re talking about baseload in Indiana, you’re talking about coal. It leaves the door wide open for further efforts to extend the life of Indiana’s coal fleet.” 

Undermining regulators?

Olson and other stakeholders noted that extensive input from regional transmission operator MISO and the Indiana Utility Regulatory Commission indicated that there are no major pending concerns about reliability, and that the existing regulatory process is effective in ensuring that utilities are able to provide energy to their customers. 

The task force report says there is “apparent ambiguity” — an earlier draft said “confusion” — about which entities are responsible for ensuring reliability. In Olson’s view, expert testimony from MISO, the regulatory commission and the North American Electric Reliability Corporation (NERC) provided evidence of a “robust and rigorous” process to ensure reliability. 

The Hoosier Environmental Council in its testimony asked legislators to put more faith in the regulatory commission and the utility planning process that it oversees. He lamented that the legislature has passed bills ending net metering and getting rid of the state’s energy efficiency standard, without adequately considering input from the regulatory commission.

“We didn’t want Indiana [legislators] to keep repeating its mistakes of enacting public policy that really is a much less effective approach than the [commission-driven] process,” said Hoosier Environmental Council Executive Director Jesse Kharbanda, adding that the commission is “driven by highly experienced, highly trained professionals who have the expertise to track reasonable data-driven policy that ultimately has the oversight of the legislature.”

“We came away from this Energy Task Force process believing the current structure is actually good — that MISO and NERC and the commission do a careful job of making sure Indiana remains reliable, rather than the bandwidth of the legislature being devoted to policies that we worry would slow the transition of coal to renewables,” he said. 

Skepticism of renewables 

The task force report found that renewable energy “is significantly less reliable and stable” than energy from other sources, and that “to compensate for the unreliability and instability of electricity generated from renewables, backup sources of generation are required, such as generation from fossil fuels, nuclear resources,” biomass, energy storage and more.

Stakeholders lamented this attitude toward renewables. One of the task force findings says that states such as California that “have simultaneously invested heavily in renewable resources before sufficient system redundancies were in place, and while neglecting to invest in transmission and distribution infrastructure, have experienced rolling brownouts and some of the highest electricity prices in the nation.”

Inskeep noted that there was no testimony from California regulators and little context provided for the finding. 

“Particularly when the first draft came out, there was language blatantly anti-renewables,” Inskeep said. “The final report had some of those removed, but the tenor is still a skeptical view of the transition to renewable energy, specifically calling out California as a punching bag without actually any robust findings and discussions.”

The task force did call for standardizing regulations related to renewable energy siting, ordinances and tax structures — measures that could aid renewable development. And it said, “To keep Indiana competitive in attracting and retaining certain businesses, the state must encourage the deployment of renewable energy resources, while not compromising the reliability and affordability of electric utility service.”

The task force recommended that its process continue for another two years, with energy efficiency and storage, electric vehicles, demand response, and distributed energy resources (like rooftop solar) on the agenda. 

Olson, Inskeep and others said these topics should have been studied by the task force in its first round, especially since net metering will essentially end in July 2022 under current policy, so the residential and commercial solar economy will suffer great harm even if the task force were to prioritize distributed solar in recommendations it would make in December 2022. 

“Not only will net metering be prohibited, utilities will already have their successor tariffs in place by the time Task Force 2.0 has finished its work,” Olson said. 

Ignoring expertise? 

The legislature requested that the Indiana Utility Regulatory Commission examine fuel shifts and emerging technologies, which it did in conjunction with the State Utility Forecasting Group, Lawrence Berkeley National Laboratory, and Indiana University Public Policy Institute.

The resulting 338-page report was released in August and the task force held a meeting about it on Nov. 12. Stakeholders say the task force doesn’t appear to have taken the information in the report to heart. 

A detailed analysis by Lawrence Berkeley National Laboratory, for example, shows resilience and reliability benefits from increased distributed energy sources — namely electric vehicle charging, battery storage and solar panels. The task force did not take note of such advantages, framing solar instead as a risk to reliability. 

The Indiana Utility Regulatory Commission report details energy shifts in the region, noting that in MISO territory, coal generation dropped from 54% in 2006 to 32% in 2019, gas increased from 28% to 33% and wind last year represented 10% of generation. 

“While the speed of change depends on the specific circumstances of a given company, the evolution is clear: greater diversification of generation portfolios, including greater incorporation of renewables and gas-fired generation facilities, and reduced reliance on coal-fired generation,” the report found.

The report also stressed that Indiana’s decisions will impact neighboring states: “Ultimately, Indiana is not an island. Electric resource decisions by Indiana utilities will affect the performance of the electric system throughout a multi-state region.” 

The Hoosier Environmental Council also advised the task force to hold informational hearings on issues including energy storage, coal ash and best practices in other states, noting how Indiana compares to its neighbors on clean energy measures. 

Indiana gets only 6% of its energy from renewables, compared to 37% in Iowa and Kansas, the council told the task force, and its energy efficiency investments represented only 0.65% of retail sales in 2018, about half the rate in Michigan and Minnesota. Unlike most other states, Indiana has no property assessed (also known as PACE) financing available for clean energy investments; net metering is ending and it has no mechanism for third-party ownership of distributed solar. 

Kharbanda said that rather than trying to slow renewable deployment and support coal, the task force should be focusing on “how Indiana can be a national leader in energy efficiency, because we have such a strong manufacturing sector.”

“Jobs are needed especially in the context of this COVID recession — we’re getting hit hard economically,” he said. “We need to find new paths for creating jobs in the state, and clean energy is one of them.”

Indiana task force report could slow state’s transition from coal, critics fear is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

A recent analysis found 245 clean energy projects that were withdrawn during the advanced stages of development, with many blaming a lack of transmission capacity.

Grid congestion — and the exorbitant cost of relieving it — has caused developers to cancel scores of wind and solar projects planned in grid operator MISO’s territory, renewable industry advocates say. 

The Natural Resources Defense Council’s Sustainable FERC Project recently released an analysis showing high numbers of renewable projects withdrawn from the Midcontinent Independent System Operator’s queue in the same areas where the grid operator’s maps show that congestion is extreme, and expensive upgrades are needed. 

In all, 245 clean energy projects that had reached advanced stages of development were withdrawn between January 2016 and July 2020, the study found. While there are various reasons a project may be withdrawn, experts and developers say that especially in the western region of MISO, congestion and related grid upgrade costs are the main factors. 

EDP Renewables recently withdrew a planned 100-megawatt wind farm in southwestern Minnesota from MISO’s queue for interconnection to the grid, because MISO said it would have to pay $80 million for grid upgrades. The company, which was in the midst of negotiating a power purchase agreement with a telecommunications company, had estimated the work would cost about $10 million and has since called the project off, said director of government affairs Vanessa Tutos. 

It’s one of several that have faced a similar fate.

“What we’ve seen in the data and reports from developers is that the number of projects dropping out as a result of high network upgrade charges has significantly increased over time,” said John Moore, director of NRDC’s Sustainable FERC Project. “The network is reaching its limit.”

Power generators typically pay for the interconnection lines needed to get their power to the grid, and EDP regulatory and market affairs director David Mindham said there are few concerns about this arrangement. But as the long-distance, high-voltage interstate power lines are too congested to serve new projects, developers are required to pay for upgrades on these lines if they want to build. 

The developers and clean energy advocates say that as these upgrades benefit many parties across multiple states, the needs and costs should instead be predicted farther in advance by MISO and passed on to a wider range of stakeholders, including ratepayers. MISO declined to comment for this story.

“Generators absorb those costs up front,” which is not feasible in many cases, Mindham said. “We need a better cost-sharing mechanism between generators and other beneficiaries of the system.”

Developer Invenergy has also withdrawn projects because of congestion on the MISO grid, after spending many millions on the earlier stages of the process. 

“The current process ignores the reality of the way the grid is heading — it used to be that you’d build your generating facility close to load, but renewable resources need to be sited where the resource is best … and often in far-flung locations, the transmission system is not robust,” said Nicole Luckey, vice president of regulatory affairs for Invenergy. “Customers are seeing the benefits but they’re not funding those upgrade costs.”

Invenergy Senior Vice President Kris Zadlo noted that there were 27 projects submitted into MISO’s February 2017 west interconnection cluster representing 3,421 megawatts. MISO studies initially showed the need for about $3.4 billion in transmission upgrades for those projects, coming out to about $1 million per megawatt to interconnect. “To put this value in context, you are almost paying as much to interconnect as you are to build a renewable resource,” Zadlo said, and all but two of the projects were ultimately canceled.

“There’s a breakpoint where bearing those costs makes the renewable project unprofitable and you just have to drop out of the queue,” Zadlo said. “Transmission is essentially highways or roads in the sky — if you wanted an Amazon distribution center in your community, you wouldn’t make Amazon pay for the highway — you would build a highway to attract Amazon and all the other industries that would come with it.” 

Surprises and risks 

Typically the cost of needed upgrades for long-distance lines is divided among multiple companies seeking to connect new projects. The upgrade needed for EDP’s Minnesota project cost hundreds of millions of dollars in all, Tutos noted. That means developers who move forward could be shouldering additional risk that another developer will bow out, and the remaining ones will have to pick up their portion of the cost. Developers can also be billed for costs of upgrades in affiliated systems that are not in MISO territory. 

A March 2020 study by MISO showed that 60 proposed projects representing 9 gigawatts of wind would require total upgrades costing more than $1 billion. A report by wind and solar energy trade associations and the nonprofit Clean Grid Alliance notes that prior to 2009, upgrade costs were split 50-50 between generators and load (essentially, customers). Today, generators pay 100% of the costs, unless the upgrades are above 345 kilovolts, in which case generators pay 90%.

Mindham said that regional transmission organizations like MISO aren’t doing enough to predict where renewable projects could be built and the grid upgrades needed, including to meet specific renewable energy goals in neighboring states. Many developers say more new transmission lines should be built — with the cost spread across large regions — to get renewable energy from where it’s best generated to where it’s needed. Investments have been made in these so-called multi-value projects in the past decade, but that new transmission capacity is in many places already being used up. 

“If you do that study and understand your transmission needs, you can build transmission in anticipation of renewable energy and come up with a more fair cost allocation that assigns costs to everyone,” Mindham said. 

Developers also say that they suffer from a lack of certainty, and are forced to go through the costly early stages of the interconnection process before learning that the upgrade costs they’d need to pay are too high to proceed. 

“You have to demonstrate site control and other aspects of projects — before we even come to the queue, we’ve invested significant money, millions and millions of dollars,” Mindham said. “What’s hurting developers is a lack of certainty. Everything has to line up perfectly in multi-year cycles, you have to get site control, local permits, every other aspect of developing the project and then at the end if you’re hit with an $80 million bill you hadn’t anticipated, it just kills the project.” 

Such concerns are part of MISO’s ongoing stakeholder process, but developers say it is moving too slowly and wind and solar projects crucial to helping states meet their renewable energy goals are being needlessly sacrificed. They want to see MISO and the Federal Energy Regulatory Commission make changes more quickly, and they are calling on state legislators and governors to weigh in on the issue.

“As we see more and more carbon reduction goals, we’re seeing a greater appetite for clean energy growth,” Tutos said. “But it can’t actually come to fruition. There’s a move afoot to educate lawmakers and regulators so they can put some pressure on MISO, but there’s only so much they can do without everyone being on board. There are so many diverse stakeholders, it’s hard to move things forward.” 

On Sept. 8, the Midwest Governors Association sent a letter to regional transmission organizations MISO, PJM and Southern Power Pool about the issue, asking them to come up with a “long-term transmission ‘blueprint,’” otherwise “the grid could continue to act as a barrier to industry evolution for decades to come.”

A Midwestern crisis 

The Natural Resources Defense Council’s study says the 245 advanced projects withdrawn represented 40% of the total in MISO’s queue at the time. High numbers of projects withdrawn were concentrated in Minnesota, southern Wisconsin, and southern Michigan plus a swath of Michigan’s Upper Peninsula. Michigan and Minnesota saw the most withdrawals, representing about 5,000 MW in each state. 

A map from MISO shows the amount of energy that can be added to power lines in different areas. In the same parts of Minnesota and Michigan where high numbers of projects were withdrawn, there are already 10,000 MW or more of power on the lines above what MISO considers ideal. The map shows most of Iowa, Michigan and Wisconsin and central Illinois and Indiana also above the threshold. 

Congestion is also bad in MISO’s southern reaches including Missouri, Arkansas, Louisiana, Mississippi and part of Texas. Only MISO’s eastern flank — including Virginia, West Virginia and the Carolinas — can add thousands of megawatts before becoming congested. 

MISO’s project queue is currently made up predominantly of clean energy projects — a total of 50,000 MW of solar, wind, storage and hybrid projects and just 4,452 MW of natural gas projects, as of July, according to NRDC’s analysis. 

A spreadsheet provided by NRDC showed that when projects in all stages of development were considered, more than 20,000 MW of wind and more than 21,000 MW of solar were withdrawn, along with battery storage projects. The companies owning the transmission lines in question include Entergy, Otter Tail Power Company, American Transmission Company, Xcel Energy, Ameren Illinois, Duke Energy, ITC Transmission, and others.

Tutos noted that in addition to withdrawals, many proposed projects are canceled before ever being submitted to the MISO queue because of concerns about grid constraints. “We go through fatal flaw analysis and decide just not to proceed because of this,” she said. 

Mindham added that the congestion in areas with prime wind mean projects are instead being shifted to areas with weaker wind but more grid capacity. That makes investments less cost-effective and limits carbon emission reductions. 

“Not only are renewables not being built that otherwise would be built — there’s no question of that,” Moore said, “but also it stands to reason that higher quality renewables may not be being built because there’s not enough space on the system where solar or wind resources are the best.”

Mindham added: “In my opinion, this is the single largest thing holding back renewable development.”

Grid congestion a growing barrier for wind, solar developers in MISO territory is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

“The idea would be to make Michigan less of an electrical peninsula,” a state utility regulator said.

Michigan officials are seeking more information about the potential to import more electricity to the Lower Peninsula to help maintain reliability as coal plants close and more distributed energy resources come online.

In February, the Midcontinent Independent System Operator, or MISO — which operates the grid in central U.S. states from the Gulf of Mexico to Canada — launched a study following a request from Michigan Gov. Gretchen Whitmer and the state Public Service Commission.

The study’s primary focus will be the potential costs and benefits of increasing the import limits into the Lower Peninsula, which is known as MISO’s Zone 7.

“With the move to coal plant retirements and increased renewable energy in our state and elsewhere, the transmission ties can provide a level of resilience,” said Public Service Commission Chair Sally Talberg. “The idea would be to make Michigan less of an electrical peninsula.”

The Lower Peninsula is unique among MISO local resource zones and is restricted in the amount of power that can flow through from other states. Some advocates in recent years have said importing more power could also reduce the need to build new power plants here.

Capacity import and export limits are the maximum amounts of generation that can be reliably moved through grid systems under peak demand conditions. MISO has resource adequacy requirements that a certain amount of generation must be produced within a particular zone, known as the local clearing requirement. Import and export limits can change based on transmission topology changes, generation additions or retirements, and changes in demand, according to MISO. The amount of power allowed to be imported in Michigan has declined in recent years amid coal plant closures.

“With power plants retiring in the state, this became more of an issue to meet reliability requirements in an effective manner,” Talberg said. “One way to do that is to boost the transmission capability so you can meet the requirements but don’t have to rely so much within the zone.”

The issue was identified by the commission last year in a Statewide Energy Assessment following the polar vortex of January 2019. The study is expected to be completed in November. Meanwhile, previous studies found that bolstering transmission connections between Michigan’s two peninsulas and with Ontario in the Upper Peninsula would be uneconomic.

The latest MISO study will cover a range of scenarios that gradually increase the Lower Peninsula’s import capabilities, which are currently capped at 3,200 megawatts. One scenario would look at nearly doubling that with an additional 3,000 MW.

Transmission struggles

Increasing the state’s importing capacity could potentially mean new transmission lines, a contentious process seen elsewhere in the country as developers seek to move renewable energy from resource-rich regions like Iowa to population centers.

MISO has a transmission approval process that also allocates costs across its region. (This is why Michigan ratepayers could pay some of the costs of a proposed transmission project in southwestern Wisconsin.) Costs are borne by transmission companies’ customers — in Michigan’s case, utilities. Those costs are then passed on to ratepayers.

There’s also a sense of urgency about finding transmission solutions, which could include a combination of new projects or upgrading equipment on existing power lines.

“In the transmission business, it takes years to study and build projects,” said Simon Whitelocke, president of ITC Michigan, the company that owns transmission lines in the Lower Peninsula. “We need to look at this today because solutions are years away. We can’t really wait until the 11th hour to start looking at it.”

A January study by consultant ScottMadden for Wires Group, a transmission industry trade association, emphasized the urgency needed for new transmission projects across the U.S. to meet increasing renewable energy demand. More extreme weather events driven by climate change are also driving the need for more grid resiliency.

“Clearly transmission is needed to facilitate [renewables integration] across the country and across regions,” said Cristin Lyons, partner and head of the energy practice at ScottMadden. “The game-changer today is the way companies and states are committing to clean and renewable energy standards. That puts the spotlight right back on the need to build big lines across broader balancing areas.”

Larry Gasteiger, executive director of Wires, said the Michigan study “is a bit of a microcosm of what you’re seeing in many parts of the country. There’s going to be a significant need for more transmission investment and for coordinated and collaborative planning amongst various regions.”

Plant closure impacts

Though composed of two peninsulas, Michigan is still tied to the regional grid that serves states across the Midwestern region, Talberg said. Those connections with other states will increase in importance as large, centralized power plants close down, experts say.

ITC has also been looking at ways to reinforce the transmission network, and company officials also plan to participate in the MISO study.

Whitelocke said previous and planned coal plant retirements are “going to keep putting more pressure on the system.” 

“On top of that, the generation is being replaced with solar and wind, which is intermittent,” he continued. “This trend is happening not just here in Michigan, but across the country.” 

MISO spokesperson Allison Bermudez said the Lower Peninsula’s transmission system is limited by insufficient voltage near Detroit.

“It is likely that fixing this constraint will shift the issues down the line to the next element and so forth,” Bermudez said. “To determine the most cost-effective solution, analysis must be iterative in nature to consider both incremental [or] piecemeal solutions as well as holistic solutions.”

Given the connected nature of the power grid, Bermudez added, “any transmission upgrades will need to be coordinated and complement other transmission upgrades across the MISO system.”

For transmission line owners, the interconnected nature of the grid will likely increase as more renewables displace centralized fossil fuel plants.

“Over the longer term, we’re going to rely on each other much more than we have in the past,” Whitelocke said, adding that increasing renewable demand is forcing changes in the transmission sector. “The whole landscape is shifting. As an industry, we are all trying to make sense of all the moving parts.”

Michigan explores importing more electricity as coal plants close is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.