Transmission lines near Canton, Michigan. (Photo by Fred Locklear via Creative Commons)
Transmission lines near Canton, Michigan. (Photo by Fred Locklear via Creative Commons)
Transmission lines near Canton, Michigan. (Photo by Fred Locklear via Creative Commons)

Michigan’s Lower Peninsula faces a 3 GW electric capacity shortfall next year. But energy experts say that doesn’t mean the state needs to rush into building 3 GW worth of new generation.

Doing so, some argue, could actually put Michigan in an even worse position in the future.

The capacity shortfall — which is projected by the Midcontinent Independent System Operator (MISO) to grow as coal plants are retired to meet federal emission rules — may also present opportunities for the state to restructure its energy system to encourage demand-side solutions, driving down the need for new generation.

While details about energy supply and demand may sound esoteric to average ratepayers, the issue is on the radar of lawmakers in Lansing this year. State officials say that reliability concerns in the Upper Peninsula due to uncertainty over an aging coal plant serve as a warning to the rest of the state about how average ratepayers could be impacted without proper planning for the future.

Energy experts say the issue downstate will require a balancing act of carefully planning new generation while also pursuing policies and incentives that decrease demand, such as crediting customers who conserve energy during peak hours.

“Going out and overbuilding new fossil fuel plants could ultimately end up with stranded assets,” said Dan Scripps, president of the Michigan Energy Innovation Business Council. “Demand response, behavioral energy efficiency and distributed generation can have a pretty dramatic effect on peak loads.

“It’s something ratepayers and policymakers should be concerned about: How do you get that balance right?”

What is the capacity shortfall?

The Lower Peninsula’s 3 GW projected capacity shortage is often referred to as a contractual shortfall rather than a physical one. It’s not as if the state will leave 3 GW worth of customers in the dark in 2016 unless there is generation to replace it, but rather what MISO requires for a reserve margin, or the capacity available beyond normal peak demand.

The Lower Peninsula’s is the largest shortfall among the nine zones in MISO’s footprint, which stretches from North Dakota and Minnesota south to Louisiana. The shortfall is largely due to the state’s geographic nature as a peninsula away from energy hubs elsewhere in the Midwest. Additionally, Scripps said, Michigan’s coal fleet is “ancient,” which is causing a relatively high rate of coal retirements in the next couple years.

“Those three things stacked on top of each other are creating a perfect storm that’s leading MISO to say both in the short-term and long-term there may be capacity issues we need to resolve,” said Scripps, a former state representative from West Michigan.

The shortfall is comprised of about 1.8 GW of contractual shortages between DTE Energy and Consumers Energy, Michigan’s two largest investor-owned utilities. The projection increased last year when Tenaska Capital Management chose to connect a power plant within MISO’s territory near South Haven, Michigan with the PJM grid operator instead of MISO.

The capacity shortfall throughout MISO’s footprint increases steadily over the next 10 years, largely due to pending federal emission regulations.

Ken Rose, a senior fellow at Michigan State University’s Institute for Public Utilities, said it’s important to remember that these shortfalls are projected numbers “based on the probability of what future demand will be and how much capacity will be retired and what new stuff will be built. There’s a lot of moving parts in that.”

For regulated states, “There’s quite a bit of work in going into what’s needed and, if new capacity is needed, what ought to be built. In a deregulated environment, we kind of ceded that to the market on the wholesale side.”

Ultimately, the projections become “moving targets,” Rose added, which can be influenced by a variety of factors, including the health of the overall economy. The 2008 recession, for example, led to a decrease in demand and “more than enough capacity. If the economy takes off, we may need a lot more capacity than we’re thinking.”

Demand-side solutions

When energy systems are constrained, traditional solutions have involved turning to next-in-line generators.

“Or you can reduce demand by asking or paying people to not run energy-intensive systems,” Scripps said. “It’s often about balance.”

David Kolata, executive director of the Illinois-based Citizens Utility Board, said, “In general, the best thing for consumers and the environment is really to invest heavily in demand-side energy efficiency and enable distributed generation. That’s a low-cost solution and something we’re just starting to tap the potential of.”

Some have alleged that MISO lags behind PJM in encouraging demand response within its footprint.

“Certainly a piece of this puzzle is working with MISO to see how they’re going to restructure those markets so that there is the right incentives in the right place for using demand response,” said Liesl Eichler Clark, a principal at the Michigan-based consulting firm 5 Lakes Energy. “PJM is better set up for that than we are right now.”

Some utilities have pushed MISO to reform its capacity payment system to be more like PJM, which pays generators for the promise to have available supplies later. Opponents, including consumer and clean-energy advocacy groups, shot back that the changes would disrupt states’ ability to make their own decisions about capacity planning and don’t properly account for demand-side solutions.

Rose said the two grid operators are “very different in a couple aspects.” PJM has restructured at the state level as well as the wholesale market. Additionally, more states within PJM are deregulated; the opposite is true within MISO, he said. That makes planning for capacity inherently different and also accounts for why suppliers in MISO don’t get the kinds of capacity payments as those in PJM.

“You can’t really compare them in that sense by saying one is better than the other” in planning for capacity, Rose said.

Beyond demand-side solutions, the state can also rely on nearby regions within MISO’s footprint, contracting for new capacity on the open market. For example, nuclear power from the Chicago area.

In the longer term, however, there’s no question that Michigan (like other states) will have to replace old coal plants with new generation from natural gas and renewables.

“It seems no matter how you slice it, we need some new generation,” said John Quackenbush, chairman of the Michigan Public Service Commission.

Tim Sparks, vice president of energy supply operations for Consumers Energy, said the utility is adding about 540 MW of new capacity after buying a natural gas plant in mid-Michigan.

“From there, we have various new programs coming into place from our smart energy roll-out, putting in smart meters across our footprint, offering customers different demand-response offerings,” he said. “That will get us several hundred megawatts of load reduction during those times.”

Along with its energy efficiency program and refurbishing smaller combustion turbines, Sparks said the utility is prepared to meet capacity obligations “at least for the next five years.”

Whichever route energy suppliers take between demand-side solutions, importing from other states (of which there is a limit) or building new generation, MISO would “work with either solution,” said Melissa Seymour, executive director of MISO’s central region. “If the state decides it’s in its best interest to build generation in the state, that’s an option we support. Transmission is also an alternative.”

Are we planning well enough?

This week, utilities turned in to the Michigan Public Service Commission five-year projections on how they plan to meet capacity needs. It is the longest-term view utilities have had to take and an effort for state regulators to paint a statewide portrait of where needs may be.

Quackenbush said that since the 1990s, the MPSC required utilities to file reports showing how they would meet peak demand in the following summer. Last year, the MPSC asked utilities to plan three years ahead. With coal retirements and new EPA rules coming, it has been extended to five years. The same is being asked of alternative energy suppliers, he said.

“We’re really looking forward to getting this information and to get a (statewide) assessment,” Quackenbush said.

Still, Michigan is one of 12 states that does not require utilities to file an Integrated Resource Plan, or a comprehensive plan that factors in the entire state’s needs, said Clark of 5 Lakes Energy. Until now, they have done what’s required of them for their own service territory and filing certificates of need when considering new plants.

“An IRP instead would do comprehensive planning for the whole state,” she said. “Both of the [investor-owned] utilities are for sure planning for their future loads, but neither of them are looking at the state in concert. They don’t need to.”

IRPs, she added, would “draw in other stakeholders in the planning process instead of, with certificates of need, the utilities doing what they think they need to do and then interveners get involved when they file the actual case” before the MPSC. “It’d be great to actually have people at the table before it gets to that intervener step.”

Electric choice and capacity

Michigan’s major investor-owned utilities, DTE and Consumers, often use the capacity shortfall issue to say that Michigan’s retail access law, a partial-deregulation policy that caps electric choice participation at 10 percent of a utility’s load, creates even more uncertainty of what capacity needs will be going forward. DTE and Consumers are supporting an advertising campaign to convince legislators to end the 10 percent cap and go back to a regulated market.

The two utilities plan to meet most of their combined 1.8 GW shortfall by purchasing existing natural gas plants. DTE is issuing an RFP for more simple-cycle facilities. How alternative suppliers meet the goal is less certain, according to Quackenbush.

In the past, alternative suppliers have told the MPSC that they rely on MISO’s annual auction to meet capacity.

While the capacity issues are expected to increase prices on the wholesale market, that may drive some customers from the alternative suppliers back to regulated utilities here in Michigan.

Laura Chappelle, of the pro-deregulation group Energy Michigan, Inc., said alternative suppliers should not be solely blamed for any uncertainty.

“Some who are discussing this topic are conveniently ignoring the realities of the energy market in terms of MISO’s role and what their role has been since 2005,” said Chappelle, a former MPSC commissioner. “It’s important to note that Michigan is not an island unto itself anymore.

“While the soundbite lately is that AES’s may be short on capacity, DTE and Consumers have been short on capacity and buying capacity on the wholesale market for a very long time.”

Sparks said when Consumers Energy does pursue resources from the open market, “It will be for a minimal amount — 100 to 150 MW or less in any given year.”

DTE reports that capacity prices on the open market in Michigan will increase as reserves shrink — from $31,000 per MW-year to $60,000 per MW-year in 2019. Sparks said prices at the MISO auction could reach $90,000 per MW-year.

“That could be very expensive,” Sparks said, predicting that either way, wholesale electricity prices are likely to go up. “Those costs will ultimately be passed on to ratepayers.”

Chappelle counters that any uncertainty related to customers exercising choice should not ultimately influence whether the utility builds a new plant.

“The idea that they are not able to build new capacity unless 100 percent of choice customers return to service is just a fallacy,” she said.

The governor’s official position on deregulated markets is ambiguous. At a state House Energy Committee meeting last week, Valerie Brader, Gov. Rick Snyder’s deputy legal counsel and senior policy advisor, said there are no definitive reports showing one model is better. It varies by state and the price of energy on the wholesale market within those states, she said.

Rose, of the Institute for Public Utilities, said planning responsibility in Michigan is “a little more ambiguous” because of its partially deregulated market.

“If Michigan was fully regulated, it would be clear utilities are responsible. If it was deregulated, we’d be arguing who is responsible,” he said. “There’s a real concern in deregulated states that there’s not enough incentive to build new capacity or keep open plants. In Ohio, utilities are asking for additional money from ratepayers to keep units open. That flies in the face of the idea of having the market decide.”

But generally, Rose said Michigan is no different than states in the rest of the country facing this capacity question as aging coal-fired power plants head to retirement.

“What’s on our side is flat demand and decreasing demand. If that continues, the need isn’t quite so acute,” he said.

And that’s what people like Scripps, of the Michigan Energy Innovation Business Council, are advocating for. Demand-side solutions can address the near-term shortfall before Michigan replaces its dying coal fleet with new generation.

“The short-term conversation is different from the long-term conversation,” he said.

The Citizens Utility Board is a member of RE-AMP, which publishes Midwest Energy News.

Andy compiles the Midwest Energy News digest and was a journalism fellow for Midwest Energy News from 2014-2020. He is managing editor of MiBiz in Grand Rapids, Michigan, and was formerly a reporter and editor at City Pulse, Lansing’s alternative newsweekly.

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