Multi-Customer Microgrids: Rare, Difficult and the Future

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When the switch is flipped on the Redwood Coast Airport Renewable Energy Microgrid, it will become the first multi-customer microgrid in Northern California and one of only a handful active in the US. 

airport microgrid

The Redwood Coast Airport Renewable Energy Microgrid is located in remote Humboldt County, California. By Vladimir Sviracevic/Shutterstock.com

This inventive project aims to be a model for creating resilient communities, but should it be successful some of its more innovative features, as well as numerous roadblocks and archaic regulations, may make replicating this microgrid in the future unnecessarily difficult.

Traditional microgrids — typically a single building or contained campus — are becoming more commonplace. But the gradual rise of multi-customer microgrid projects further blurs the line of where electricity customers end and the utility begins, challenging traditional roles and regulatory responsibilities.

More than the sum

Implemented as a technology demonstration project, the ratepayer-funded microgrid in Humboldt County is part of California’s EPIC program to “accelerate the transformation of the electricity sector to meet the state’s energy and climate goals.”

The Redwood Coast renewable microgrid stretches over seven acres, connects multiple non-adjacent customers, and has both utility-side and behind-the-meter components, making it a unique endeavor even among microgrids. The anchor tenants are the regional airport and a US Coast Guard air station. A handful of surrounding commercial customers are also connected into the system.

The microgrid includes a solar farm with 2 MW of grid-tied capacity that can participate in competitive markets and 250 kW of net-metered capacity that will power the airport. Redwood Coast Energy Authority (RCEA) will own and operate the solar facility and maintain a 2 MW/8 MWh battery energy storage system and dynamic EV charging infrastructure that can participate in demand response programs.

The local utility, Pacific Gas & Electric (PG&E), will own and operate the microgrid circuitry and equipment, and oversee operations of the microgrid in island mode when the regional grid is inoperable or the utility implements a public safety power shutoff. This is one of a few EPIC-funded microgrids by PG&E and the state’s other investor-owned utilities that will come online in the coming months.

Unlike other microgrid systems, the front-of-the-meter design enables the output from the grid-tied solar capacity to be redirected to the microgrid in island mode, meaning that along with backup batteries the airport and coast guard facilities can effectively operate indefinitely as critical lifelines for the community.

Interfacing on the utility side of the meter enables the multi-faceted solar system to bid into the wholesale market, net-meter the airport, and supply the microgrid and batteries in times of need. This means that RCEA will generate new revenue, reduce operational costs for a major customer, and ensure resilience in wildfire and mudslide prone California, all from one solar farm.

One of the most important elements of the system’s design is the shared ownership model with the utility, without which this microgrid would be impossible.

This capability — to be directly grid-tied and still behind the microgrid meter — is possible because of PG&E’s participation. But that’s also what may make this project difficult to replicate in the future without the same conditions and partners in place.

Multi-customer microgrid projects can provide a number of communal benefits and help apportion the cost burden of resilient infrastructure investments, but the ability to build them is constrained by the rules and regulations that govern the electric grid.

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Good for the goose

One of the most important elements of the system’s design is the shared ownership model with the utility, without which this microgrid would be impossible.

By splitting ownership with PG&E, the system adheres to a notable roadblock to wider adoption of multi-customer microgrids — utility franchise rights, known in California as the ‘over-the-fence’ rule.

California’s over-the-fence rule prevents non-utility entities from owning infrastructure that crosses public rights of way, like a public road. It also restricts customers from, in turn, serving as an electricity supplier to other customers. In effect, the rule is designed to ban anyone from stringing up their own wires and running their own shadow utility, which could endanger public safety and generally wreak havoc.

In practice, though, the rule can be limiting and circumspect in certain scenarios, preventing a multi-customer microgrid like Redwood Coast Airport from being built any other way. Without utility involvement as the owner and operator of the circuitry and equipment (particularly where it crosses public streets), the resilience and cost-savings benefits could not be shared by these otherwise independent customers.

Communal ownership of the microgrid assets between the utility, the public and customers prevents running afoul of the over-the-fence rule, but it also helps address the challenge of monetizing certain system capabilities.

As just one example, a storage-enabled microgrid could also support the distribution grid, and allow the utility to defer the cost of upgrading an area substation (augmenting the grid so that upgrade investments can be put off). This will save the utility money, making funds available for other infrastructure improvements.

There is no market mechanism or payment to compensate an independent microgrid developer or the microgrid customer for providing this cost deferral. When a utility participates in a multi-customer microgrid system design, implementation and operation, then these otherwise inaccessible value streams can be captured and factored into project planning.

Peña Station NEXT

Rendering of Peña Station NEXT. Credit: SevenG

At the Peña Station NEXT microgrid, there is a collaboration between local utility Xcel, project integrator Younicos, and anchor customer (and battery manufacturer) Panasonic, where each shares a portion of the microgrid’s costs and benefits. Xcel plans to use the microgrid to aid in renewable integration, augment other distribution infrastructure, and provide cost-effective  reliability for customers in the area.

If Xcel was not involved in that project, those capabilities would be left on the table in the absence of new market structures; the microgrid would not even be allowed to be built due to utility franchise rights. With a utility as a project partner, these new revenue streams become accessible, further improving overall project viability and justifying their costs and engagement in part by reaping these additional systemic benefits.

Utility involvement is a regulatory requirement for almost all multi-customer microgrid projects, and utility involvement can make economics more favorable and enable additional capabilities.

Good for the gander

Having a utility partner for a microgrid project is great — but requiring one is inherently limiting. Without utility involvement and partial asset ownership, most plans for multi-customer microgrids will quickly unravel as technically infeasible and cost prohibitive.

As clarification, current rules dictate that a non-utility entity is allowed to distribute power to two adjacent customers, meaning that not all multi-customer microgrid designs are restricted. But if two buildings are across the street from each other, distributed in a neighborhood, or multiple non-adjacent buildings on a campus, regulations currently prevent a microgrid without the utility.

The city of Berkley learned this when they sought to create a fully-connected, multi-building, clean energy microgrid community with non-adjacent government buildings. The solar and storage microgrid project was ultimately abandoned due to regulatory restrictions, and they opted for a less cost-effective variation with independent solar and storage systems installed at some of the targeted buildings.

Franchise rights are foundational to monopoly regulation, so it would be counterproductive to open up a Wild West where anyone can be a utility.

Under California law, and in many other states, utilities also can levy a cost of ownership charge on customers, ostensibly to recover infrastructure costs related to a customer’s service. This presents another financial hurdle to a multi-customer microgrid that lacks a utility partner.

Additionally, the interests of the utility and the customer are not always aligned. The financial and systemic benefits necessary to justify utility involvement may not be present in a project that otherwise would pencil out through customer benefits alone, deterring utility engagement in an otherwise viable microgrid. 

For a project where monetizing resilience and reliability is difficult, sharing the costs and benefits through a multi-customer microgrid can greatly improve the economics.

Franchise rights are foundational to monopoly regulation, so it would be counterproductive to open up a Wild West where anyone can be a utility. But striking a balance between necessitating utility involvement and empowering customers to deploy innovative microgrid strategies could open new opportunities for multi-customer microgrid development in the future.

The future of the multi-customer microgrid
multi-customer microgrid

Courtesy of By Dream Master/Shutterstock.com

Utility partnerships make multi-customer microgrid projects possible today, but also may limit future deployment of these communal systems. 

Limited access to revenue streams and a very competitive marketplace for distributed energy solutions mean that microgrids often operate on thin margins, and multi-customer microgrids could help project viability and increase access to this novel resilient energy solution.

The Redwood Coast Airport Renewable Energy Microgrid will create a resilient rural community in a state plagued by natural disasters and blackouts. It is poised to demonstrate the multiple benefits of collaboration between a utility and its customers to implement creative solutions. 

But this unique project may remain one of a kind if other utilities don’t embrace this reimagining of the utility-customer relationship, or unless interconnection and ownership rules are modified to allow for more innovative system designs. 

In the meantime, utility partners are essential to developing effective multi-customer microgrid projects and reaping benefits that transcend the traditional boundaries of the utility meter.

Matt Roberts is director of strategic growth & government affairs at Microgrid Knowledge

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Comments

  1. This article raises an important, and often overlooked, aspect of microgrid development. While single facility or campus distributed generation is commonplace, multiple facilities, on distant parcels and with different ownership, reflect an evolving and more accurate definition of a microgrid. Currently, much emphasis is spent on the technical aspects of microgrid development but design tasks have evolved to the point of being fungible. The real challenge in developing a multi-customer, economically viable microgrid is securing participation from multiple end-users. This is further complicated when one of the users may be making a more significant contribution to the microgrid’s economic viability such as where a factory, apartment complex or hospital provide a host site for siting a generator designed as a cogeneration plant. Often more attractive electric loads and the benefit of offering a home for cogenerated thermal energy, can be sticking point when pricing output to the thermal host or other customers on the microgrid. Another challenge is securing multiple consent from numerous smaller users on the microgrid which can be a door-to-door endeavor, particularly in city locations. While overcoming legacy regulatory treatment of utility franchise rights is a challenge, with a moderate level of compromise such as that exhibited by Xcel here, they should be able to be resolved by reasonable parties, particularly when a utility has a record of resiliency issues and can use the microgrid to mitigate those challenges.. Resolving commercial issues such as equitable distribution of microgrid benefits reflected in pricing, and developing microgrid customers, rather than design, is, and will remain, the largest challenge to microgrid development.

  2. In my opinion the greatest obstacle to microgrid development are the IOU’s and regulatory environment which allows them to maintain monopolies and “call the shots”. Once consumers/prosumers realize the benefits of energy security and equity provided by multi-user community micogrids, they will happily switch to the new systems. This will initially and especially be the case in California and the East Coast, where the extreme vulnerabilities of the existing grid during certain weather events is causing major disruptions with an ongoing and increasing frequency and urgency that is exacerbated by the effects of climate change. There are very few if any places on earth where this will not eventually be the case if it is not so already, so the time for the transition to a more resilient energy system is truly upon us. We are LATE to this task already, so to protect the people of their service areas the utilities and PUC’s alike need to help facilitate this important transition.

    • You are not even close on the greatest obstacle. Safety and reliability are the problems. It is extremely unsafe for linemen, troublemen and electricians (the touchers) for the utility to give up temporary operating jurisdiction to an island or operate someone elses island without preparation. Especially during partial outages within the island where the line crew needs certainty and guidance. Plus, over-stressing the utilities equipment during an island becomes the utilities maintenance (expense or capital) and an inspection problem. Control room operators use SCADA to view and manipulate field devices. A third party can be given Read-Only rights to view and archive data, but they can’t be given Control rights over devices of the utility. Conversely, if a microgrid or say even a municipality like City of Palo Alto wants PG&E to temporarily give operating jurisdiction to PG&E the firewalls and permissions have to be altered. There would be acceptance testing to prove controls previously, but doubts would occur if any database has changed. Then in transmission, there are NERC CIP requirements to prevent hacking, intrusion and criminal behavior of SCADA and substations.
      So, Humboldt is the perfect guinea pig because it’s on the end of a long radial of 115kV lines and it has actually become an island in the past. The 10 diesel generators either balance load before the separation into an island or God forbid have to Black-Start and sequencially add load. Since there are emission thresholds, the governor gives a waiver so all 10 diesell generators can run at the same time.
      As for separating into islands, there is huge equipment risk when trying to re-parallel an island back to the grid. The old days an operator would watch the sync-scope and close the breaker at 12 o’clock. Today Schweitzer, GE or ABB relays have sync check relays that delay breaker closing until permissions are met. In any case, if an island wants to parallel back to the grid there is the risk of a bad parallel and the utility’s breaker could be damaged. If any line work was done on the island during its stand alone, then a phase location/rotation might be off and phasing testing with hotsticks must occur across and open breaker.
      Most utilities will require a small island to drop all load before the utility picks up the island (drop and pickup) with a breaker with sufficient fault duty and ground grid within the substation for the relays to work properly. The utility doesn’t want to subject their breaker to a bad parallel, have it smoke or do the Wahtusi dance on its pad making it useless to continue picking up the island’s load.
      The 800lb gorilla in the room is Black-Starting any island. Many if not all areas should easily survive if they separate into island mode. But, if while in island mode the generation trips off-line, then few areas have the means to Black-Start. In fact, unless the utility is a partner with the generator in that island they probably won’t let you attempt a Black-Start on your own because you would be affecting and operating their equipment which you probably have limited viewing and no control until IT guys make the provisions. Plus, the utility’s operator is blind to switching alignments unless it is tracked in their chronological log that shows position changes in DMS.
      More important the operator is going to know how to respond to the Ferranti Effect of unloaded energized line where voltage goes sky- high and will flashover mildly dirty insulators in a heartbeat. If landlines and cell phone service goes down during an attempted black-start it’s not going to happen. Black-Starting coastal loads from Sierra foothill hydros or east bay natural gas is a major ordeal. A solar plant (without monster batteries) is not capable of consistent power over a 12 hour period necessary for black-starting a large natural gas plant due to nil ductility temperature warmup requirements on boilers (usually 50 degrees per hour, sometime 100 degrees per hour).

  3. “But the gradual rise of multi-customer microgrid projects further blurs the line of where electricity customers end and the utility begins, challenging traditional roles and regulatory responsibilities.”

    Aggregate distributed power providers in partnership with utilities or CCAs in partnership with utilities.

  4. Scott M: You make islanding a problem, by mentioning things like sync check relays and sync check and closing the breaker at 12 O’ clock. GE has its own inverter solution to all you have pundited. The GE PV LV5 or just a stand alone energy storage system with the LV5 inverter has been used for a black start and was successful. As far as syncing a grid to an island, something like the GE LV5 inverter could ‘ping’ the grid and sync up to go online in milliseconds. The up side to energy storage facilities, they can be used for several grid services, capturing more revenue streams from one asset than having fueled generator sets for black starts, emergency backup. I’ve come across a couple of incidences where a power outage at a remote canal gate structure, ended up a gate raise makes for a gate lower, a gate lower makes for a gate raise. Switch two leads on the motor magnetic and see if this corrects the problem. You talk of safety and reliability of field personnel. Lock out, tag out is something EVERY utility should have a program for the safety of their employees. This is also why many utilities are training their, electricians, technicians and field service personnel in NFPA 70-E. As for “flash over” from the what you call Ferranti Effect, the SCADA system I worked on had it’s own battery backed power supply and didn’t depend on the grid to be up. I’ve had callouts to domestic well sites where a 350H.P. motor faulted out, due to a cross phase on the grid, then the back up generator didn’t pick up the site when the automatic transfer switch tripped to break before make and caught on fire. The site was dead, but telemetry knew exactly what ‘didn’t’ happen. Power fail, no ATS switch over, no well run. I’d rather be outside the site on the radio with (operations) and have them use SCADA to transfer over, than have to go into an area, look at a GE or ABB sync relay close. Arc Flash is not our friend.

    • I’ve written thousands of pages of switching for test program for commissioning of GE, Schweitzer and ABB multifunction relays. I’ve seen so many cross jurisdictional clearance (lockout tagout) screw-ups even though both parties have had procedures and training. Every task done at a utility is negotiated risk with the Union leadership. When contractors come in for construction and especially storm support it’s really challenging for them to research their clearance points and even recite them back correctly. Toward the end of my career, I investigated human failures for 7 years using DOE handbooks Vol 1 & 2 with HFACS and NERC certifications and years before that we did MORT, TapRoot, Fishbone…. Granted my Ferranti effect is primarily a transmission black start problem on 40 mile+ large conductor lines. You are use to small installations, where I operated then supervised both the transmission and distribution grids responsible for millions of customers 24/7. Analog radios are fine for mom and pop. Utilities changed over to digital radio for intrusion security. A utility’s SCADA uses dedicated phone line system, some leaselines with heavy protocols and digital radios in my world. I will concede a small island with an analog radio should be able to black-start if they have the resources and stand-alone comm lines from a purely local SCADA system. But, I’ll hold firm on the “drop and pickup” to be re-paralleled with the utility.

  5. Sorry, a 2MW nameplate solar + 2MW/8MWh BESS are woefully undersized for a regional airport, town, or anything besides a rural feeder. Operate indefinitely during a bulk system outage? Out of touch with reality. Maybe good enough for a few hours. How long are those wildfire outages?

    Even the market service is useless. CA has an oversupply of energy during “solar” hours. 2 MW can’t be relied on for peak capacity in any meaningful way. “But what about the battery, which firms up capacity?” If the battery is busy doing market service, it isn’t available for unplanned outage support, is it?

    Scott covered most of the practical liability issues perfectly. No need to repeat. 100% agree.

  6. Scott M: The salesman’s hype of “digital radio” is a misnomer. The IF, intermediate frequency and finals are all analog, with digital “blips” added for data transfer. So, bandwidth determines capacity of a “radio internet connection”. The FCC determines where the radio bands and their bandwidths are located. Lately the shift to 6 GHZ spectrum has created the wide band microwave hop to allow an internet protocol backbone along a radio link. Older technology can create an internet protocol at lower frequencies and narrow bandwidths, but is limited to 19,200 baud and probably 9,200 baud for long transmission paths.

    This is why I say, placing the “overhead” in the local site controller with appropriate site feed back and programming to control the site locally if the communications link is no response or denial of service. I don’t ‘write’ compliance papers, I just remove the fried animal, bug nest, burnt wiring and damaged transducers and get the site back up ASAP.

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