Energy storage in the MISO region

As prices for lithium-ion batteries drop, and installed capacity increases in the United States, deployment in the MISO Midwestern states has lagged behind. We examine some of the factors limiting storage deployment in the MISO region, and how those barriers are breaking down. Public Utilities Commissions play an important role in opening up integrated resource planning and procurement processes, so that energy storage can compete with conventional resources and that evolution is often slower in Midwest states, which have primarily traditionally regulated vertically integrated utilities. Most Midwestern states do not allow third parties to aggregate and sell DERs. Electricity prices tend to be low to moderate in many parts of the Midwest, so it is often more difficult for projects to garner a significant return on investment in a relatively short time period.

The role of the Midwest regional transmission operator, MISO, is also very important. Generally, energy storage does not fit neatly into the categories that grid operators traditionally use—generation, load, transmission—so it has taken proactive change at ISOs/RTOs to enable energy storage to play a more active and productive role. Market rules in many regions do not allow storage projects to capture multiple value streams or to otherwise monetize their many capabilities. This has been the case in MISO in recent years, but it is changing significantly in real time. While market restructuring is important to allow fair compensation of energy storage services, “frequent refinements create market uncertainty.”^{Reference Forrester23} In Minnesota, we have worked to understand the opportunities and barriers to storage. At the University of Minnesota’s Energy Transition Lab’s Energy Storage Summit in 2015, stakeholders from many perspectives—utilities, MISO, renewable energy industry, state regulators, and researchers—heard about the many policy and market barriers storage faces in Minnesota and the Midwest. The Energy Transition Lab then began to convene stakeholders to continue the conversation on how to enable beneficial deployment of energy storage in Minnesota. This coalesced into the Minnesota Energy Storage Collaborative (MESC), which then became the Minnesota Energy Storage Alliance (MESA). The collaborative identified key regulatory barriers, including the difficulties of participating in RTO markets, the inability to compete with conventional resources in utility and Public Utilities Commission integrated resource planning and procurement, and the barriers to monetizing multiple values of energy storage.

In 2016, MISO hosted an Energy Storage Workshop and then requested comments. MESC filed comments on January 22, 2016, which outlined some of the major obstacles in MISO to storage participation.²⁴ Key points were:

1. (i) MISO should allow aggregation of energy storage assets. This would allow small energy storage resources, located behind a customer’s meter, to gain maximum access to MISO’s market in the early stage of market development. The inability to aggregate was identified as a barrier to demand response resources, which could include energy storage.

2. (ii) MISO should reduce the minimum megawatt limit for MISO market participation. PJM’s threshold of 100 kW would enable more participation, especially of DERs.

3. (iii) MISO should enable energy storage resources to provide multiple, stacked services in its markets. No market product existed in MISO to take advantage of the full suite of energy storage’s operational capabilities and services for the grid. In 2010, MISO introduced the stored energy resource product, which was limited primarily to flywheels, providing regulating reserve services. This did not allow advanced energy storage technologies to provide multiple services, including energy, capacity, and ramping. MESC also suggested that all types of storage technology be recognized, including thermal energy storage.

4. (iv) MISO should develop a fast ramping market product in its ancillary services, allowing more efficient options to maintain grid stability, especially important as more conventional generators retire and wind and solar become larger parts of the energy mix.

5. (v) MISO should develop simple, specific interconnection rules for energy storage.

6. (vi) Energy storage technologies should be able to participate in MISO markets as generation and/or transmission assets.

FERC Order 841

These comments illustrate the barriers energy storage has faced at MISO. However, MISO is correcting many of these, driven in part by the significant federal policy direction on energy storage set by the Federal Energy Regulatory Commission (FERC) in Order 841 in February 2018.²⁵ The FERC addressed market barriers to energy storage participation in all the organized wholesale markets with the following requirements:

1. (i) Ensure participating resources are eligible to provide all capacity, energy, and ancillary services the resource is technically capable to provide.

2. (ii) Execute all storage wholesale transactions at locational marginal price.

3. (iii) Ensure resource can be dispatched and set the wholesale price.

4. (iv) Recognize physical and operational characteristics of storage.

5. (v) Establish a minimum size requirement that does not exceed 100 kW.

6. (vi) Allow storage to derate capacity to meet minimum run-time requirements.

The Order is intended to unlock electrical energy storage’s ability to compete with conventional resources and offer services into wholesale markets. Under Order 841, MISO is required to accommodate energy storage into existing market products—energy, ancillary services, and capacity—but not to create new market products. For example, a complaint from Indianapolis Power and Light (IPL) to the FERC requested a market for primary frequency response and frequency control, which the FERC is not mandating MISO to do.

One point of contention in Order 841 is its direction to RTOs/ISOs to allow energy storage in both the wholesale and distribution system to participate in wholesale markets. The order says that energy storage resources can participate from anywhere on the grid, including those interconnected to the distribution system.

Some stakeholders, including the Transmission Access Policy Study Group (TAPS) and Xcel Energy, have argued that FERC lacks jurisdiction to mandate distribution-connected storage resources to participate. In its filing, Xcel argued that it “oversteps the limits on the Commission’s jurisdiction under the Federal Power Act by interfering in state jurisdiction over retail sales and affecting the ability to preserve distribution system reliability.”²⁶ States have raised jurisdictional concerns about participation of distribution scale resources in wholesale markets, a traditional area of state oversight. The FERC is considering its approach to DERs in a separate docket, and the MISO approach to this will not be clear until that is resolved.

Another key aspect of Order 841 is the changes to smaller scale, DERs participation in the wholesale market. The threshold for participation in each RTO/ISO must be reduced to 100 kW, which is a dramatic change in MISO with a much higher threshold.

Proponents would argue that access to wholesale markets by distributed resources at the lower threshold of 100 kW is essential for behind the meter storage projects to fully monetize their value. The FERC requirements would enable a future where homes or businesses with energy storage batteries and electric vehicles can be aggregated and sell their excess power into the regional market.

RTOs/ISOs were required to submit FERC 841 compliance filings by December 2018. Each proposed a participation model for storage, but requirements vary. MISO’s proposal is intended to enable electric storage resource participation in MISO’s capacity, energy and ancillary services markets. MISO’s proposal is technology neutral, designed to integrate any storage technology “and/or storage mediums, including but not limited to batteries, flywheels, compressed air, and pumped-hydro.”^{Reference Brown27} The storage resource may be located on either the transmission system or a local distribution system.^{Reference Brown27} MISO proposes to integrate the technology by “providing unique modeling, offer parameters, operating limitations and settlement provisions that recognize the physical and operational characteristics of storage resources.”^{Reference Brown27}

Storage resources will be able to participate in MISO reserve markets as supply and demand, set market clearing prices as either supply or demand, and provide energy and ancillary service products.^{Reference Brown27}

MISO would allow for eight “commitment statuses”: discharge, emergency discharge, charge, emergency charge, continuous, available, not participating, and outage.^{Reference Brooks28}

MISO is currently modernizing its market platform. Ms. Paslawski said “there are limits to what [the RTO] can do” to implement the FERC order with the existing outdated system. For example, MISO established a 100-kW minimum size requirement for resources—the maximum allowed by the order—“because MISO’s existing market systems do not support offer or bid quantities less than this amount.”^{Reference Brooks28} In an effort to manage a quickly evolving set of grid issues, MISO has undertaken a major $135 million modernization of its software systems, which should help the market platform be more nimble and modular.

MISO has been working on many changes to accommodate the directives of Order 841. MISO has also begun to clarify how it will allow resources, including energy storage, to be qualified to provide non-market products, such as black start, voltage, and reactive power services, as needed for the grid on a cost-based basis.²⁹ If the storage meets technical capabilities and submits an FERC filing documenting the revenue requirement, MISO could call on them as needed for reliability and recover the costs from utilities.

There is growing interest in the MISO region for “hybrid” energy systems, which incorporate generation resources of two or more different fuel types. This is being discussed by MISO’s Interconnection Process Task Force, which may lead to new processes in the future. Current rules would require each aspect of the project to be independently studied and modeled. However, the ISO’s new Net Zero Interconnection Service will allow a storage project to share the interconnection capacity of an existing resource that already has an interconnection agreement. The advantage of the Net Zero is that it provides for an expedited process outside of the interconnection process.³⁰

Also extraneous to the FERC order, MISO has begun integrating energy storage as a transmission asset through its MISO Transmission Expansion Planning (MTEP) process. In January 2017, the FERC announced that it was open to considering electric storage resources receiving both cost-based rate recovery and market services revenues.³¹ However, questions need to be resolved for storage to serve that role. The issues were grouped into five higher level categories: project proposal submission details, interconnection requirements and processes, planning evaluation considerations/modeling, functional control/state of charge, and facility retirement. MISO controls the transmission operations, so would they control the storage assets when they are acting as transmission assets? If not, will the storage asset be in the proper state of charge when required? How will the storage’s expected availability (forced outage rates) compare to alternatives? How long would the storage resource last and replacement costs, should there be a formal retirement process for storage resources? Should the storage project go through the interconnection queue if it will be used exclusively as a transmission asset? MISO’s goal is to implement this during the MTEP 2019 cycle.

An insightful take on the FERC order suggests that energy storage should be adopted as the “universal participation model.”^{Reference Ahlstrom32} Author Mark Ahlstrom of NextERA and Windlogics points out that demand response, storage, renewables, and DG all look differently from conventional generators in their properties and capabilities. The RTOs must therefore create new participation models and modify market software, so that each of these technologies can fully participate and contribute their unique and valuable capabilities to the existing grid system. This can be a slow and cumbersome process to add new resources on one by one, and so Ahlstrom suggests we use storage as the most general model, which encompasses the capabilities of other resources. Battery storage can act as a generator, a load resource, and a flexibility enabler. The storage participation model would then “with slight ‘idealization’ in its design, become[s] the universal model that can be used, simply by changing appropriate parameters, for all other resources.”^{Reference Ahlstrom32}

Illinois

The Shedd Aquarium installed a 1 MW/277 kWh lithium-ion battery on May 26, 2016, the largest battery installation in Illinois.^{Reference Garcia33} The battery, the first installed at any zoo or aquarium in the United States, is part of a microgrid system that includes a 265 kW solar system on the roof of the Aquarium. Funded by a grant from the Illinois Department of Commerce & Economic Opportunity, the 60,000 lb, $2 million battery provides backup power, peak load demand, and frequency regulation. The energy storage systems, which are connected to Shedd’s electrical distribution system, are located on Shedd Aquarium’s loading dock and can be seen by aquarium visitors from inside the South Abbott Oceanarium window. The battery installation and solar system are part of the aquarium’s Master Energy Roadmap, which has set a goal to reduce its energy consumption by 50% by 2020.

In February 2018, the Illinois Commerce Commission approved ComEd’s $25 million plan to create a microgrid in Chicago’s Bronzeville neighborhood.^{Reference Palivos, Brumit and Merza34} The project involves solar panels and a battery storage system. ComEd’s pilot program is the first microgrid operated by a utility in the country.³⁵ The final project will be completed in 2 phases and will ultimately serve 1060 residential, commercial, and small industrial customers. The goal of the project is to meet peak electricity demand of customers and maintain service to customers when the microgrid is “islanded” (able to operate independently) from ComEd’s grid. Phase I of the project, which began installation on June 26, 2018, includes 2.5 MW of load and installation of battery storage (0.5 MW/2 MWh) and solar PV and serves approximately 490 customers. Phase II of the project will add approximately 570 customers and an additional 4.5 MW of load and 7 MW of DERs.

Another ComEd project, the Community Energy Storage pilot in Beecher, Illinois, launched in March 2017 and uses a 25 kW/25 kWh lithium-ion battery to reduce the number and length of outages. The battery can supply power to three houses in the event of a power outage. The Beecher project was the first community energy storage program in Illinois.

Iowa

The Maharishi University of Management (MUM) solar and storage project launched in December 2018 in Fairfield, Iowa.³⁶ The project uses a 1.1 MW solar array plus a 350 kW/1.05 MWh battery energy storage system. MUM already has two smaller solar arrays and a small wind turbine, and these previously installed projects in combination with the new solar and storage project will supply MUM with 43% renewable energy. The new solar and storage project will supply 33% of MUM’s electricity usage. “By combining active tracking technology with battery energy storage MUM forecasts it will cut its electric utility costs by a projected 30%.” In addition, in early 2019, the five acres of soil under the solar array will be planted with pollinator friendly plants. Ideal Energy, Iowa State University, and MUM will conduct studies on solar production and battery storage at the site with research grant funding provided by the Iowa Economic Development Authority.

Michigan

Consumers Energy has two energy storage programs. The first program, at Western Michigan University in Kalamazoo, Michigan, was installed in September 2018.^{Reference Lillian37} A 1 MW/1 MWh battery was installed at the Parkview battery site. The second program involves two 280 kW/340 kWh energy storage systems installed by Consumers Energy in Grand Rapids, Michigan, at the end of January 2019.^{Reference Walton38} The pilot project is located within and named Circuit West, a 13-block district on the west side of Grand Rapids, where new building construction is increasing.

Missouri

City Utilities of Springfield, Missouri, and NorthStar launched a pilot energy storage project in September 2017.^{Reference Uhlenhuth39} The 1.1 MW/1 MWh project utilizes thin plate lead carbon batteries, not the more commonly used lithium-ion batteries. The pilot project studies whether energy storage can extend utility equipment life, in this case, a substation, by providing demand and “grid smoothing” during peaks.

Ohio

The Village of Minster, Ohio, demonstrates the first U.S. municipal utility-owned solar plus storage project.^{Reference Trabish40} Minster installed a 3 MW solar array with a 7 MW/3 MWh lithium ion energy storage system in 2016.

South Dakota

BP Wind Energy installed a 212 kW/840 kWh battery storage system at its Titan 1 Wind Energy site in South Dakota in 2018.^{Reference Froese41} The project is the first combined wind and battery project in the Southwest Power Pool (SPP).

Minnesota and energy storage

The University of Minnesota’s Energy Transition Lab, which has been studying and educating stakeholders on energy storage since 2015, hosted the Midwest Energy Storage Summit in Minneapolis in 2017. The objective of the event, which attracted more than 300 attendees, was to explore opportunities and barriers to energy storage in the Midwest from the perspective of research, implementation, and policy and regulatory issues. Some key insights from the expert speakers are summarized below.

The biggest takeaways from the Midwest Energy Storage Summit were two contradictory assertions: many regional energy players are convinced that advanced energy storage, primarily batteries, are too expensive to deploy cost effectively in Minnesota and the Midwest, while many other experts presented examples of cost-saving energy storage scenarios available today. So many concluded that the price is closer than we think to where it needs to be to allow broad deployment in ways that benefit the energy system and its participants. The survey on pricing was taken before the Summit and then tested by a range of opinions and information presented by many experts.⁴²

The Summit made it clear that many leaders are driving innovation, including utilities, renewable energy companies, state regulators, grid operators and RTOs, policymakers, individuals, and large and small customers.

The President of Xcel Energy (Minnesota & the Dakotas), Chris Clark said that they are “driving toward the future” where there will be “a lot more wind, a lot more solar, and a lot more need to figure out how storage and other things fit in.”⁴³

Mary Powell, CEO and President of Green Mountain Power (GMP) in Vermont, asserted that the “debate about storage is over.” Her company has “leaned in hard to storage” for the benefit of ratepayers, and the results have surpassed any of their penciled pro forma estimates envisioned. GMP is “customer-obsessed,” which drives everything they do. Certified as a B Corporation,⁴⁴ their incentives are driven not just by shareholder return. All value streams go back to other customers, which avoids cost shifting among customer groups. This helps them meet their customers’ desires to move “very fast to clean local renewable energy options” at low cost. Powell compared their model with the 130-year-old model that drives decisions at most electric utilities. The company is now 60% renewable energy powered and 90% carbon free.

Powell believes the energy industry is going through radical transformation. It is a “customer-led revolution away from the bulk grid system.” She sees the bulk grid as the backup system, not the main energy system. Powell asserts that it will save ratepayers money. She cited an NREL study predicting that 40% of American homes and businesses will be at least in part self-supplying their own energy by approximately 2025. She said GMP is the first utility to offer customers off-grid options. She critiqued the unprecedented spending on the bulk grid system which called for $10 billion of new infrastructure spending in 2016, for a system that has a flat to declining load and is only 40% efficient.

GMP’s residential battery storage program, rolled out in 2017, has saved $500,000 by reducing peak demand during the July 2018 heat wave.^{Reference Walton45} When the temperatures spiked, about 500 residential Tesla Powerwall batteries sent power to the grid. The program offered Powerwall 2 batteries to 2000 customers, who pay $1500 or $15 per month. The battery systems should be able to supply all of a home’s needs for up to 12 h. This “virtual power plant” can provide in aggregate up to 10 MW to reduce peak load.

This article’s author led a Summit interview with Mary Powell and Xcel Energy President Chris Clark, discussing the similarities and differences between their states’ approaches. Like most of the Midwest, Vermont and Minnesota are both traditionally regulated utility states, and electricity prices are slightly higher, on average, in Vermont than in Minnesota.⁴⁶

Sarah Van Cleve, who leads analyzes energy policy for Tesla, said “we are past pilot projects. I understand that some companies want to pilot [battery storage] on their systems [but the] technology is fully commercially available.” She emphasized several cost-effective use cases, including reducing system peak demand, deferring distribution infrastructure projects, hedging against overly grandiose load forecasts that may not materialize, and demand charge reduction for commercial/industrial customers. Van Cleve emphasized that cost-effectiveness variability depends more on updating grid tariffs and processes than on pure technology economics.

Lin Franks, formerly Senior Strategist at IPL in Indiana, was originally a skeptic on the value of energy storage investment for her utility. She used the analogy of preferring to use a traditional manual screwdriver for home improvement projects—until she built a deck. Then, she realized a power screwdriver was essential for both higher efficiency and quality outcomes. She compared manual screwdrivers to utility’s conventional synchronous generators. Franks’ analysis convinced her company to install the largest battery storage system in the Midwest. That battery storage system, known as Advancion Energy Storage Array, is a 20 MW lithium-ion battery array. The array is capable of “both injecting and withdrawing up to 20 MWs in less than one second for a flexible range of 40 MWs in the performance of frequency control.”⁴⁷

For MISO, the array was the first grid-scale lithium-ion battery to apply for interconnection. It was also “the first grid scale battery in the United States to be classified as a transmission asset.”⁴⁸ Once installed, however, IPL found that MISO did not have a market product that sufficiently valued the instantaneous capabilities of the battery storage system. In particular, its transmission asset designation was a challenge. Existing Federal Energy Regulatory Commission (FERC) policy “dictated that no transmission asset could participate in a market mechanism.”⁴⁹ In other words, the array was unable “to recover its costs through both cost-based and market-based rates concurrently.”⁵⁰ To resolve this inefficiency, IPL challenged MISO, and, on January 19, 2017, the final complaint was resolved by the FERC. The FERC’s amended policy now allows transmission assets, like the array, to participate in markets if three conditions are addressed: “(i) the potential for combined cost-based and market-based rate recovery to result in double recovery of costs by the electric storage resource owner or operator to the detriment of cost-based ratepayers; (ii) the potential for cost recovery through cost-based rates to inappropriately suppress competitive prices in the wholesale electric markets to the detriment of other competitors who do not receive such cost-based rate recovery; and (iii) the level of control in the operation of an electric storage resource by an RTO/ISO that could jeopardize its independence from market participants.”⁵⁰ Franks’ Summit presentation concluded with this anecdote: When IPL’s corporate counsel complained about the high cost of the legal action, she replied to him “we spent $600,000 and then we won, and saved customers $22 million” (Tables 1 and 2).

Table 1.

Existing Midwest battery storage projects.

^a Only includes projects 1 Megawatt or greater. Data from Global Energy Storage Database. U.S. Department of Energy, Office of Electricity Delivery & Energy Reliability, retrieved from energystorageexchange.org; and Generator Interconnection Queue. Midcontinent Independent System Operator, Inc., retrieved from misoenergy.org/planning/generator-interconnection/GI_Queue.

Table 2.

Midwest battery storage projects in the MISO queue.^a

^a Only includes projects 1 Megawatt or greater. Data from Generator Interconnection Queue. Midcontinent Independent System Operator, Inc., retrieved from misoenergy.oreplanning/generator-interconnection/GI_Queue.

Storage and peak demand

Traditionally, utilities handle peaks in energy demand with fossil fuel plants built expressly for meeting that demand, sometimes combined with a limited amount of demand response or interruptible power. Utilities’ primary concern is maintaining reliable power that constantly matches energy supply with energy loads. Meeting peak demand is costly and represents millions of dollars of carbon-emitting infrastructure that is only used a small percent of the time. Energy storage has opened up a range of innovative alternatives to reduce or manage peaks.

The news on energy storage in the United States is dominated by developments on the east and west coasts, while the profitability of storage in the Midwest is limited by generally lower electricity prices. However, a recent report from the University of Minnesota, “Modernizing Minnesota’s Grid: An Economic Analysis of Energy Storage Opportunities,” found that solar arrays combined with energy storage can be a more cost-effective option for Minnesota than the alternative of using natural gas peaking plants, once the additional environmental benefits are taken into account.⁵¹

This combination of renewable energy and energy storage can provide the state with a lower cost and quicker pathway toward meeting its statutory goal of 80% carbon reduction by 2050.⁵²

Lessons learned from the report, which was led by the University of Minnesota’s Energy Transition Lab, could be usefully applied to other Midwest states within the jurisdiction of MISO.⁵³ The findings are based on input from more than 60 stakeholders, including representatives from utilities, energy technology providers, nonprofit organizations, and government, provided over two Energy Storage Strategy Workshops. Participants explored how energy storage could be used to help Minnesota achieve its energy policy objectives, while enabling improvements to system efficiency, resiliency, and affordability. The need to reduce peak demand was identified as a key challenge for energy systems, which would benefit from further analysis. The use case and system-wide modeling for this analysis was conducted by Strategen Consulting.

Use-case analysis of energy storage and storage + solar as peaker alternative

The storage use-case analysis compared the costs and benefits of a 100 MW 4-h battery storage system with a conventional new natural gas 100 MW peaking combustion turbine (CT) and found that the alternative with storage alone would be a cost-effective way to meet Minnesota’s capacity needs in 2023. When solar was added to the storage system, it became cost-effective in 2018, with environmental costs and the federal Investment Tax Credit (ITC) included. This analysis assumed a 100 MW 3-h storage plus a 50 MW solar PV system. Income for the combined system is derived from capacity payments, energy sales revenue, and sub-hourly ancillary services revenue. As solar PV generation does not coincide with times of peak demand in Minnesota, it can instead be supplemented with stored energy during these hours, resulting in a capacity resource that satisfies peak demand using less capacity than a stand-alone storage project (Fig. 4).

Figure 4.

Cost-benefit projection for storage or solar + storage versus gas peaker.

These findings are potential game changers for Minnesota and the Midwest region for several reasons. First, while electricity usage growth is relatively flat, peak demand is increasing and managing it is costly. The Massachusetts 2017 study, State of Charge, found that “on average from 2013 to 2015, Massachusetts electricity customers annually spent over $3 billion, 40% of the total annual electricity spending by consumers in Massachusetts, on the top 10% most expensive hours.” Minnesota plans forecast 1800 Megawatts of new gas peaking capacity by 2028, so there is a meaningful opportunity to find cost-effective and lower carbon solutions without locking in new fossil fuel infrastructure for decades to come. Energy storage systems paired with solar can level off peak demand, save customers money, and reduce carbon emissions (Fig. 5).

Figure 5.

Projected peaking plants capacity additions in Minnesota.

Demand response and peak shaving

The Energy Transition Lab’s work illuminated projected and actual energy storage opportunities in Minnesota. Connexus Energy, Minnesota’s largest distribution cooperative, was a participant in the workshops. Connexus built and commissioned its 15 MW, 30 MWh energy storage system paired with 10 MW of solar in late 2018. It became the largest storage project of its kind in the state, saving money for cooperative customer/members and facilitating renewable energy growth to reduce greenhouse gas emissions. Responses to Connexus’ Request for Proposals demonstrated the market’s fast evolution, with bids coming in at half the cost projected just one year earlier. The project is “pay as you go,” using a solar 25-year power purchase agreement, in which Connexus only pays for the energy received, and a 25-year storage service agreement, only paying for the service received. The project is designed to time-shift solar energy production to reduce peak demand (Fig. 6).⁵⁶

Figure 6.

Representation of energy time shifting with battery storage in the Connexus solar and storage installation.

During the polar vortex period of cold weather, the solar plus storage installation performed beyond expectations. The solar array produced 147% compared with its average for the month of January 2019. The system enabled Connexus to meet peak demand on their system, helping to reduce stress on the grid during the same day that MISO experienced a “maximum generation” event.⁵⁷ This is a MISO procedure to ensure system reliability by preparing all available generation to be dispatched in case of an emergency (Fig. 7).

Figure 7:

Slides from Brian Burandt, Vice President, Power Supply & Business Development, Connexus Energy, used with permission.^{Reference Burandt58}

Distribution infrastructure upgrades

A 2014 study by Strategen and EPRI on energy storage in Minnesota analyzed different use cases for storage to determine which, if any, were likely to have a positive return on investment. The resulting White Paper identified distribution infrastructure upgrade deferral as the most promising use case, with a positive benefit–cost ratio.⁵⁹ Efforts to actualize this concept met with regulatory barriers, however.

Xcel Energy proposed a project of this type to the Minnesota Public Utilities Commission in 2015 as part of its Distribution Grid Modernization Report.⁶⁰ The “Belle Plaine” project would have added “a large [6 MWh, 2 MW] battery to reduce the load on the Belle Plaine feeder and transformer, combined with a 1 MW…solar array.”⁶¹ Xcel Energy’s goals for the Belle Plaine project were twofold: (i) deferring distribution upgrades at its Belle Plaine substation, which was nearing capacity; and (ii) “exploring the benefits of battery storage combined with solar generation…”⁶² Construction on the project would have taken approximately a year and a half and would have cost about $12.5 million to put the project into service in 2017.⁶³

The Commission denied the project without prejudice on June 28, 2016, finding that “Xcel simply [did] not provide enough information to establish that the Belle Plaine project [was] consistent with the requirements of Minn. Stat. § 216B.2425, subd. 2(e).⁶⁴ The regulators did not think Xcel showed how deferring substation upgrades was necessary to modernize the transmission or distribution system, nor did they find that the project would meet the benefits listed in the statute.⁶⁵ The order went on to say that “[t]his is particularly true since the Company is already operating a solar-plus-storage project in its Colorado service territory.”

In 2018, legislation advanced during the Minnesota Legislative session that would have required utilities to include energy storage in their Integrated Resource Planning (IRP) process at the Public Utilities Commission, incent investor-owned utilities to invest in energy storage and funded a study on energy storage. An earlier version of the legislation included direction to the Public Utilities Commission (PUC) to approve cost recovery for utilities for energy storage pilot projects that met certain criteria for system and ratepayer benefit. Although none of the bills were signed into law, they have been reintroduced in the 2019 session.^{Reference Osmek, Marty, Dibble and Senjem66}

Resiliency

Most of the weather disasters in the national news have been on the East or West Coast or in Texas and Puerto Rico. Minnesota and the Midwest do not have hurricanes or coastal storm surges but do face extreme weather disasters every year. The northeastern Minnesota city of Duluth has been hard hit by extreme weather causing power outages. The city, which is built on a steep hill overlooking Lake Superior, has twice come within 2 h of its drinking water pumping system shutting down, cutting off access to drinking water for a city of nearly 100,000. Duluth’s Hartley Nature Center was hit by the same storms and has since built a small-scale solar plus storage project designed for resiliency.⁶⁷ During the 2012 outage, the small nature center was forced to cancel a week of its summer camp program, losing $14,000, a significant portion of their annual revenue. The project, which combines 12 kW of solar and 6 kW/14.2 kWh battery, serves multiple functions. It reduces electricity demand charge costs by shaving peak demand and can island and become a community shelter, while protecting critical loads like lighting, computers, and charging stations.⁶⁸ It even has the capability to act as a base of operations for the city’s emergency response efforts.

Hartley, while a small-scale project, was unique for northern Minnesota and has served as an educational model for the region. Other projects are being planned, including an innovative community resiliency microgrid project in North Minneapolis that will be built around community solar, storage, job training, resiliency, and access for disadvantaged communities to innovative energy solutions.^{Reference Bade69}

Carbon emissions reduction

Storage plays an important role in supporting decarbonization of the electricity grid by enabling high penetrations of renewable energy, by displacing fossil fuel plants and by increasing the flexibility of the grid. Energy storage reflects the generation resource on the electric grid. Some regions such as MISO are still coal dependent, so storing that energy includes its emissions. Understanding marginal emissions factors can help storage owners and grid operators minimize greenhouse gas reductions when charging from the grid.^{Reference Li, Smith, Yang and Wilson70} As renewable energy generation increases and the grid becomes cleaner, this problem will diminish.