In Michigan, we’re lucky to have one of the largest pumped storage facilities in the world. At the Ludington Pumped Storage facility, water is transported uphill when cheap excess electricity is available and allowed to flow back downhill through a turbine when electricity is needed. Despite its clear value to the grid and to the increased integration of renewables, the 1,872-megawatt facility took four years to build and is unlikely to be replicated.

Instead, the greatest expansion in energy storage over the last decade has been in batteries. Utility-scale battery storage capacity has soared over the past 10 or so years, from almost nothing before 2010 to nearly 1,000 megawatts today, driven in large part by lithium-ion battery storage, the price of which has fallen 85 percent since 2010. There has also been growth in the number of energy storage projects outside of lithium-ion batteries, such as compressed air energy storage and flywheel storage.

But despite the value of pumped storage in the state’s energy mix, Michigan has been slow to adopt these booming new energy storage technologies relative to the growth seen on the coasts.

This is unfortunate, because, as revealed by the Michigan Public Service Commission’s (MPSC) recent State Energy Assessment, Michigan's energy system is not as resilient as it could be. Storage could help.

Michigan ranks near the bottom of all U.S. states in terms of electric reliability due in part to harsh summer thunderstorms and bouts of extreme winter freeze, but also due to aging infrastructure and outdated systems. Energy storage allows the grid to tap power at will and store power in times of excess and so represents a massive opportunity to shore up reliability and resiliency.

By shifting electric demand to off-peak times and keeping the grid stable, storage can serve as an alternative to old ways of upgrading the grid. Utilities may not need to charge ratepayers for as many distribution-level projects like new power lines or transformers because many of those projects may not be needed if energy storage is deployed appropriately. Several states have required utilities to analyze these “non-wires alternatives” before spending ratepayer dollars on large distribution grid upgrades.

The disparity between Michigan and other regions when it comes to energy storage can be explained in part by policy hurdles. The problem is multifaceted, involving state regulations and utilities as well as the wholesale market.

Realizing energy storage's full potential

The MPSC requires Michigan's investor-owned utilities to submit distribution investment and maintenance plans every five years. The commission is hosting stakeholder workshops to develop guidance on making non-wires alternatives an area of emphasis in these plans.

Utilities are also required to think about the long term with the integrated resource plans (IRPs) they must file with the MPSC every five years, which lay out how utilities plan to provide or purchase enough electricity generation to meet customer needs.

But these plans treat distribution and generation like separate buckets, and the value of storage is intrinsically tied to both. If one looks at the distribution system separate from generation, then only a subset of the benefits of storage are considered, such as the ability to serve as non-wires alternatives, while benefits related to generation — like dispatching stored power at times of peak demand — are not.

The reverse is true if one focuses on generation and not distribution. Again, only one part of the puzzle gets considered. As a result, storage has not received the attention in long-term utility planning in Michigan that it deserves. That could change with the recent announcement by Michigan Gov. Gretchen Whitmer and the MPSC of the MI Power Grid initiative.

One of the initiative’s primary objectives is “integrating transmission, distribution and resource planning to increase transparency and optimize solutions.” This new, holistic approach to treat energy as a complete system, if properly implemented, can allow utilities to fully realize storage’s potential.

Given the advancements the storage industry has achieved recently, it is strange that the IRP most recently proposed by DTE Energy, Michigan’s largest electric utility by number of customers, seems not to acknowledge that energy storage today is leaps and bounds over where it was in the recent past.

In testimony supporting the IRP, a DTE witness described battery storage as “not currently cost-effective relative to other resource options." The only storage resources suggested by the IRP are 11 megawatts of solar-plus-storage pilot projects — a tiny amount in the context of the 1.2 gigawatts to 1.4 gigawatts of new generation proposed by the IRP over the next five years.

DTE certainly has not ignored storage. This past summer the utility won regulatory approval for a customer demand response pilot with solar and battery storage at the Ford Motor Co. Research and Engineering Center in Dearborn, as recently reported by Crain’s Detroit Business.

But while pilot programs are a good first step, many other utilities have gone beyond pilots to full-on deployment of battery and other types of storage. Several of DTE’s peers have found that storage is indeed cost-effective at much larger scales than DTE contemplates in the IRP.

The Northern Indiana Public Service Company recently opened a bidding process for developers to build 2,300 megawatts of solar and solar-plus storage projects, as well as 300 megawatts of wind and wind-plus-storage, as replacements for retiring coal plants.

In another example, NextEra Energy’s Lee DeKalb 20-megawatt battery storage facility in Illinois has been in commercial service since 2014. It sells its ability to balance the grid on a second-by-second basis into PJM’s regulation market, in which PJM dispatchers take bids in real time from resource operators (such as storage projects) that can regulate grid frequency.

Why MISO lags PJM in energy storage

The market rules for the transmission system are not the same throughout the Midwest, and those policies make a big difference for storage. The Illinois battery storage project mentioned above is within the territory of the PJM regional transmission organization, the largest wholesale electricity market operator in the country. Most of the Midwest, however, is part of the territory of the Midcontinent Independent System Operator.

As this map from the U.S. Energy Information Administration demonstrates, battery storage deployment has been significantly higher in PJM than other markets, while MISO has one of the lowest levels of deployment.

Why? Maybe the biggest reason is that MISO has been somewhat behind PJM in developing market rules for storage that allow it to provide its full range of capabilities. As mentioned, battery storage projects in PJM like NextEra’s Lee DeKalb facility have been selling ancillary services for several years. But only in December 2018 did MISO file its plan for allowing what it calls electric storage resources — a technology-neutral term including but not limited to batteries, flywheels, compressed air and pumped hydro.

MISO’s market for electric storage resources was previously going to come into effect in December of this year, but procedural delays involving the Federal Energy Regulatory Commission have pushed the effective date to June 2022.

So most of the Midwest, which falls under the MISO market, is only at the beginning of unlocking the full potential of storage. But despite these regional market challenges, utilities in Michigan still can — and in fact need to — increase investment in energy storage solutions.

Even before the MISO reforms have come into effect, there are promising opportunities for Michigan utilities to use storage projects to make energy more reliable and affordable for their customers.


Laura Sherman is president of the Michigan Energy Innovation Business Council.