Microgrids are a hot topic in the power sector, but for years utilities have struggled to devise business models that allow deployment at a larger scale.

Now, new research is targeting how microgrids, typically designed for individual customers, can be standardized for wider adoption and provide benefits to the larger utility grid.

A new paper from the Smart Electric Power Alliance (SEPA) and the Electric Power Research Institute (EPRI) details three evolving business models for microgrids, describing a new project led by Xcel Energy will test the most cutting edge of those new strategies.

“There is an inherent interest in microgrids for their own sake, but the more interesting conversation is about the services microgrids provide,” Peter Bronski, marketing strategy lead for Panasonic, told Utility Dive. Panasonic is partnering with Xcel along with IT provider Younicos in a microgrid project in Denver, Colo.

“It’s not that we like microgrids, it’s that we like what they can do,” Bronski said. “This project defies the traditional definition because, although it can island, we are really looking at how it interacts more broadly with the PV systems, the battery storage, and the load on the distribution feeder.”

Microgrids have been used for decades, but they have typically been built by independent developers using fossil fuel generators to protect end users from grid outages, said Ryan Edge, SEPA Program Manager and co-author of the white paper, “Microgrids: Expanding Applications, Implementations, and Business Structures”

“It made sense for big power users, like college campuses or military bases that had their own generation, to add a couple of switches and make it a microgrid with the ability to island, or disconnect from the grid and operate when the grid was down,” he said. “That was the traditional microgrid business model.”

“Then,” he said, “Superstorm Sandy happened.”

Many in the power sector point to the storm, which cut power to much of the Eastern Seaboard in 2012, as the catalyst to pathbreaking grid modernization proceedings taking place today, like New York’s Reforming the Energy Vision (REV). But the storm also sparked a broader discussion of how microgrids could enhance power reliability, especially for critical infrastructure.

“The disruptions caused by Superstorm Sandy on the East Coast amplified the need for greater grid resiliency,” said Nadav Enbar, EPRI’s principal project manager and co-author to the white paper.

But despite the growing interest, utilities have found it difficult to build replicable business models around microgrids that allow both they and end users to benefit.

As models evolve, microgrids will likely become more cost-effective, said Robyn Beavers, vice president at Lennar Technology and Investments. But, she noted at a recent conference, even the newest business models have produced only “one-off projects.”

There is not yet “a truly scalable platform where a microgrid is a cost-effective energy infrastructure alternative,” she said. “There is a technology and it works, but there is not a front-end business model or the back-end financing. There is no customer pull. The next disaster will likely help push it along.”

As utility microgrid deployments continue to grow across the U.S., projects like the Xcel-led initiative could provide early models for scalable microgrid solutions that can harden the grid and deliver savings to utilities and customers alike.

Utilities and microgrids

Utilities’ market share of microgrid ownership was expected to reach 18% in 2016, according to a GTM Research report, up from 2% in 2014.

Customer rate impacts of increased utility capital expenditures (CapEx) are a main driver, experts said. Instead of shelling out CapEx dollars for traditional grid hardening, microgrids could potentially provide resiliency benefits at a lower overall cost.

Microgrids can “improve reliability, lower costs, and diversify energy sources,” the SEPA/EPRI paper reports. The islanding capability also enhances resiliency “via backup or emergency operation.” This produces a “combined value” for resiliency that can make microgrid investments more appealing than traditional wires and substations.

This combined value “may justify microgrid development for electric utilities, producers, and end users,” the SEPA paper argues, and it could lead to “a future grid that is more transactive.”

But utility-led microgrids face challenges “because of the way utilities are regulated,” Edge said. “You see a lot of proposals but not many are built."

A utility-led project will likely have several customers but, without a single customer to clearly bear the costs, regulatory approval will be a challenge, Edge said. The question is whether the microgrid’s costs should go to the entire rate base or just interconnected customers. And the answer might change if the microgrid never islands, he added.

“It doesn’t fit neatly in the traditional utility business model.”

But even given those difficulties, the utility still faces costs for system infrastructure, Edge noted. If regulators understand the resiliency potential, they might approve limited utility CapEx in return for control of the microgrid during outages, he suggested. The private sector could in turn retain control and monetize their DER investment “the other 99% of the time.”

Additionally, while resiliency remains the main driver for microgrids, their ability to island also makes them DER aggregators, Edge noted.

“A utility is not going to dispatch small DER, but it might dispatch a microgrid that can run on DER like solar and battery storage,” he said. “If the utility has control of the microgrid and wants to shave its peak, it could island the microgrid. It could also use the microgrid’s resources for ancillary services.”

The paper describes projects involving San Diego Gas & Electric, Southern California Edison, Commonwealth Edison, and Green Mountain Power that are working with these use cases. Much depends on the control software and who operates it, Edge said. But the key insight is that a microgrid controller added to a DER installation offers utilities a new level of “combined value.”

Matt Wartian, a global practice manager at Burns McDonnell, which oversees microgrid construction, sees utilities “in an internal tug of war” over microgrids as they move from central to distributed generation.

“Utility leaders in the regulated business may be concerned but other utility leaders are starting to think like developers and can be partners in microgrid innovation,” hesaid.

But Alex Spature, president of the ADEPT Group, a microgrid consultant, sees utilities as “the 400 pound gorilla on the block.” They tend resist change, and they control the interconnection approval process, he said. To grow the sector, microgrid developers therefore need to find remote territories, islands, or military bases where utilities are not in control.

“The only way to get movement from utilities, which is essential, is to work through regulators to demonstrate the advantages and disadvantages of microgrids,” he said.

Key to addressing these issues, stakeholders say, is finding the answer to a key question — how to make money off microgrids. New business models could offer a way forward.

Microgrid business models

In the original “third-party” business model, the microgrid was primarily for islanding from the grid during emergency outages to protect the end user’s load and operations. Generation might be sold into markets if the system was stable and prices were advantageous prices.

In a more “integrated” business model, the utility owned and controlled the microgrid and contracted with end users at a regulated tariff with a premium for the microgrid services. Operations put system stability and efficiency first.

The newest hybrid model, not as established as the others, allows for a wide “unbundled” set of possible ownership and operating arrangements.

“One entity—the utility, end user, or third party—owns or finances the microgrid, while another entity operates the microgrid,” the paper reports. “Both grid-tied and islanding operations can have single or multiple objectives.”

In the “third-party” and “integrated” business models, microgrids offered limited returns beyond the primary resiliency benefits. The wider ownership and operating arrangements in the “hybrid” or "unbundled" model offer new potential to monetize the “flexibility and diverse capabilities” of DER, though the cost-benefit balance remains uncertain, the SEPA/EPRI paper notes.

Monetizing the many potential value streams “is complicated by the tangle of economic and industry factors involved,” the paper reports. Scaling the sector will require greater “clarity on price signals, rate structures, and regulations” and “a more detailed and nuanced set of standards.”

In the hybrid model, which GTM Research predicted will make up 38% of the market by the end of 2016, third party providers can make money by selling energy, capacity, or ancillary services from the PV, other generation, and battery storage into wholesale markets, Edge said. Monetizing resilience is more difficult.

“Evaluating avoided costs for maintaining critical services (e.g., hospital care, national security, and public safety) is a more challenging undertaking,” the paper reports. “Avoided cost calculations, regardless of their context, require a range of assumptions about the expected frequency and magnitude of grid disturbances over the life of a microgrid’s operation.”

Estimates have put lost economic value from an outage at “hundreds of dollars per kilowatt hour,” Edge said. “If that is the cost, something will happen in microgrids. I just don’t know that anybody has verified those numbers.”

In a third-party business model, resiliency may be sold to a customer as a premium service, but it would necessarily be unique in each microgrid arrangement, Edge said. Monetizing other DER services is likely to be dependent on natural gas prices and other market factors.

Standardizing the microgrid concept might help shape “a basic model,” he said. “But it will have to be customized once you talk to the community.”

The business model of ADEPT is based on locating microgrids where they can offer specific marketable services, Spataru said.

“A specific market may need a microgrid to supply rushing current for a black start,” he said. “But the first challenge is financing. Though microgrids have a proposed payback of six years to 10 years, nobody has actually gotten their money back so only an investor with vision will take the risk.”

Dan Cohee, vice president of PDE Total Energy Solutions, a microgrid contractor, said a project can achieve a reasonable payback if the fully installed system price is under $500/kWh.

PDE, he said, builds cost effective projects by customizing them to the need. It uses control algorithms to maximize value from the range of services obtainable with DER.

“One of our island projects is running at a seven-year payback with a 20-year system life,” Cohee said. Another does peak shaving with a battery storage system that has been precisely sized “to carry the load through the night and as the sun comes up the next day it will start recharging."

The limitation is that optimized calculations are inconsistent, Cohee said. “We sent complete details for a system to three different sources and got back three completely different assessments of the best solar plus battery system, payback, and savings.”

Beavers said the lack of standardization is a hurdle that will be difficult to overcome.

“A microgrid integrates a lot of different technologies and serves a lot of different kinds of customers,” she said. “No builder is going to be a microgrid store right now.”

But “as costs for solar and batteries come down and microgrid use cases expand, a market can emerge,” Beavers added. “Right now, microgrids are edging out of the valley of death and entering the early phase of commercialization but there are the usual barriers that will take a lot of work.”

Xcel’s hybrid microgrid experiment

Xcel Energy and its microgrid partners are attempting to tackle many of those issues in Colorado.  

Their Peña Station NEXT “hybrid” business model microgrid project in Denver, Colo., is a public-private, multi-stakeholder partnership.

Panasonic is the primary equity shareholder, the engineering, procurement, and construction contractor, the solar module supplier, and the operator for the microgrid’s two solar installations. A 1.6 MW solar PV array is on a Denver International Airport (DIA) carport while another 259 kW rooftop solar array is on top of Panasonic’s network operations center (NOC).

The 1 MW/2 MWh lithium-ion battery system with inverter and controls was designed and supplied by Younicos, a project partner. Panasonic owns the net metered smaller solar array that supplies its NOC building. DIA is the primary contracted off-taker for the larger array, which is owned by Xcel, who also manages the microgrid controller.

Panasonic’s priority, beyond the solar generation, is ensuring round-the-clock resilience for its NOC, Bronski told Utility Dive.

“We monitor and manage a nationwide network of hundreds of megawatts of utility-scale solar from the Carolinas to California around the clock,” he said, “but we also want to take advantage of the other services the microgrid assets can provide for the system.”

The Colorado Public Utilities Commission approved expenditures for the demonstration project, including the rate based solar generation, under Xcel’s Innovative Clean Technology program. The utility intends to explore five use cases, Beth Chacon, director of grid storage & emerging technologies, told Utility Dive.

Beyond the backup power for Panasonic, Xcel will use the resources to learn how to more efficiently integrate a high feeder penetration of PV into its distribution system. The Pena Station feeder is forecast to have a 20% penetration of distributed solar by the time the project is online in midsummer.

Using the battery and the solar generation, Xcel will “firm the feeder load” by smoothing ramps or shifting output, Chacon said. The time shifting of the solar generation will help with peak demand reduction and also allow electricity market arbitrage or frequency regulation with solar over-generation.

"The findings from the Pena NEXT demonstration will tell us more about microgrid costs and capabilities and how these use cases can be optimized," she added. "They could inform our future plans."