From Superstorm Sandy, to Lloyd’s recent report on the potential for major system damage due to geomagnetic storms, to cyber-attacks on utilities and the grid (such as the one that hit San Jose earlier this year), the last twelve months have brought a redoubled focus to the fragility of the U.S. electric grid. That demonstrated fragility has provided a stark reminder that while the U.S. pioneered the advance into the electrical age, our systems are therefore among the oldest on the planet. Our performance is indicative of a failing network — a Galvin Electricity Initiative report found the U.S. grid experienced triple the frequency and ten times the duration of system interruptions compared to places such as Germany and Denmark.
Whether through physical decline, natural catastrophe, or misguided malice, our grid is subject to increasing threats that can and will lead to more frequent failure. Meanwhile, our centralized architecture, which is largely based on hub-and-spoke generation and transmission, only adds to the brittleness of the system.
One solution to these emerging infrastructure challenges that have been receiving increased attention is the use of microgrids: small, self-balancing networks that have the ability to fractally break apart from the larger grid for autonomous operation and then seamlessly recombine to function as part of the whole on demand. Such networks have a single point of common coupling to the grid, and include sources of generation (such as diesel and/or gas generators, distributed solar, and distributed wind resources), as well as electrical loads that can be managed in a coordinated manner. Demand response and energy efficiency — and increasingly, storage and EVs — often figure prominently in design and operation to flexibly manage supply and demand requirements on the microgrid.
Today, the United States has nearly 1,500 megawatts of generation operating in microgrids, but because such systems help to resolve reliability issues and enhance the performance of the larger grid, they also — like distributed energy resources such as rooftop solar PV — potentially threaten the traditional utility business model.
There’s value there
We see several compelling ways that microgrids provide value over and above the status quo.
Microgrids can aggregate complementary distributed energy resources. Through the matching of supply and demand resources within a given microgrid, it is possible to tailor the performance of that network to provide specific operating or environmental performance characteristics. For instance, individual microgrids can be designed for interruptibility, or efficiency of generating sources and loads, or a specific level of reliability and power quality, or an environmental emissions profile, or even to maximize economic value by selling services to the macrogrid. In this way, microgrids make a fairly commoditized electricity system customizable to the quality needs of an individual customer.
Market-linked microgrids provide customers options that can help drive down costs and risks. The traditional electric customer is often a price-taker at the mercy of the utility’s pricing structure. Customer investment in efficiency and distributed resources like solar PV provide the customer with some power, but the microgrid represents the ability to completely flip the script. The microgrid puts power in the hands of the customer and opens up choices for how to manage energy risks and optimize costs. Places like White Oak, the campus of the U.S. Food and Drug Administration, are already showing what is possible. Today, White Oak optimizes on-site power production based on grid costs and fuel costs of on-site generators. As White Oak expands fuel sources on its campus by adding the ability to use biofuels, it continues to diversify away risks associated with sole dependence on utility power and reduces security risks associated with on-site reliance on one or two fuel types.
Microgrids promote infusion of additional private capital to supplement existing sources. The global microgrid sector is expected to grow from $10 billion in 2013 to $40 billion by the end of the decade. Much of the investment in microgrids will come from customers, since the microgrid market in the U.S., which represents 64 percent of the global market according to Navigant, is customer-driven. As electric utilities face the burden of raising huge sums to replace aging infrastructure, comply with environmental and renewables standards, and deploy smart grid technologies — estimated to add to $2 trillion by 2030 — growing customer investment in microgrids can ease the pressure on utilities and rates while simultaneously modernizing the grid.
Microgrids improve the efficiency of the electric system. A microgrid relies on generating equipment that is located close to the demands it must serve. The more a microgrid relies on its generating equipment to meet demand, the fewer units of energy are shipped from central power stations to customers. This reduces the 7 percent to 10 percent rate of loss that is typical in the transmission and distribution system, potentially saving energy costs by reducing total generation requirements.
Of course, this is just a starter list. There are certainly other values that will vary by size depending on the specific application. Today, the cost-benefit is not compelling, with the exception of a select group of customers, such as universities and military installations that place a high value on reliability and energy security, but as microgrid costs fall and new opportunities open to monetize benefits, microgrid economics should improve for a wider swath of customers.
The challenge of "micro-municipalization"
In the past year, the long-term repercussions of the growing momentum behind distributed generation, energy efficiency, and demand response have received considerable attention (see, for instance, EEI’s summary of the challenge by Peter Kind or RMI’s own discussion from our eLab initiative). These business-model issues are probably most visible in solar development due to the challenges around managing net energy metering.
However, adjusting utility rates and debating the right to sell self-generation back onto the grid pale in comparison to the consequences for utilities of the complete defection of customers made possible by microgrids. In traditionally structured markets, this defection would knock utility cost recovery practices out of tilt. Within restructured markets, it introduces new wholesale market participants and shifts operating dynamics. The process of activating microgrids is akin to the impacts of the municipalization of grid assets — only at a much smaller scale — that, once aggregated, could spell big change.
The municipalization of parts of the electricity system is a theme that has often been met with opposition by centralized utilities for a number of reasons, not least of which is the loss of valuable customers. Between 1980 and 1997, at least 40 proposals for the municipalization of electricity assets were made in seventeen states. While these have slowed in more recent years, Boulder, Colorado’s ongoing high-profile municipalization effort continues to progress and is a reminder of the challenges associated with breaking off assets in a highly interconnected operational and financial system.
But take the complexity of this challenge and now reduce it down to that of an individual customer on the grid: a campus, a hospital, or even an individual residence. Sprinkle in currently low gas prices, declining renewable generation costs, a preference for cleaner energy than the grid can provide, a desire for resiliency and performance assurance beyond what the utility can muster, or any number of other wishes, and you have the potential for “micro-municipalization” to occur — the creation of microgrids that give customers the option to secede from the larger grid at will, in some respects the functional equivalent of municipalizing those grid assets and taking them out of the hands of utilities.*
To be clear, these customers do not necessarily want to “defect” per se (neither do municipal utilities, which often retain wholesale contracts with providers outside their service territory), but the option for self-sufficiency that a microgrid provides and the prospect for value optimization in the center of a host of other supply options is extremely alluring for some customers. To find potential interest, talk to customers in the Northeast and mid-Atlantic, where ice storms and hurricanes have left individual feeders and in some cases whole communities without power for days multiple times over the last decade, or others on the Gulf Coast, where every hurricane incident threatens a long and slow path to recovery for devastated communities. In light of such threats, microgrid access can appear a reasonable insurance policy.
The size of this customer demand could be quite substantial. If Navigant’s forecasts for microgrid development cited above prove correct, the United States could be creating the equivalent of one major utility with approximately $25 billion in assets annually. Of course, this capital would be distributed broadly across the country. And with recent announcements by NRG and SolarCity looking to market fused self-generation and storage solutions, the prospect of a simple, microgrid-able package being available to force the discussion in the near term is an inevitability.
It is this prospect that will force the discussion of business models faster than has happened to date. The challenge is not one where the proliferation of microgrids is going to “eat the lunch” of a utility anytime soon. However, key customer defection and/or curtailment of revenues may very well start “nibbling at dessert,” which can make serving the bulk of the remaining customers a little less financially appetizing.
Principles to help microgrids flourish
Historically, utilities have resisted municipalization, and by extension, microgrids. Standby, ratchet, and departure charges, while reasoned with intent, often become punitive in practice. But if we believe that there is real value to be gained for both grid and customer through the deployment of microgrids, shouldn’t it be in everyone’s interest to create business models that encourage their development (such as business models highlighted in an NRRI paper by Tom Stanton)? We think so, and offer a set of principles for consideration by all that can help navigate the regulatory juggernaut and speed the advance of rational microgrid development.
There are multiple considerations that shape the opportunity for all players and determine whether and how new business models will emerge. These include rate design (e.g., how microgrid costs and benefits are assigned, where the capital comes from, what types of performance incentives exist, how to manage legacy grid costs); provider participation rules (e.g., who is allowed to own the microgrid, what products and services are allowed, how are they governed in the market); customer eligibility (e.g., which customers are allowed to microgrid in the first place and what rights do they have in secondary markets); how to plan around microgrids (e.g., optimizing parallel investments, their role in delivering the “smart grid of the future”); and interoperability rules that define the technical aspects of islanding. While this is quite an array of considerations, our guiding principles can help minimize unnecessary friction in the alignment process between stakeholders on all sides of the issue.
1. Define microgrids and clarify how existing policies apply to them. Job number one for regulators is to determine a clear definition (or definitions, plural, if a one-size-fits-all approach proves insufficient) for a microgrid. Should a microgrid be categorized as a distributed energy resource, an independent power producer, or something completely different? How big or small can a microgrid get before it ceases to be a microgrid? Only after such questions are answered can the regulator, utility, customer, and private developers make sense of how existing rules and regulations inhibit or incent microgrids in places where sound business cases exist. In addition to clarifying how existing rules apply, the regulator must clearly articulate the type of treatment legacy utility assets will receive.
2. Adopt and enforce a grid-wide interoperability standard. Safe and beneficial linking of microgrids to macrogrids requires adoption of standard protocols that ensure physical integrity of the system and allow for joint optimization of the independent and combined system’s economic, environmental, or operational performance. IEEE 1547.4 is one promising option for standardization, though there may be additional requirements to be codified in this or other protocols over time.
3. Strive to reasonably value microgrid costs and benefits, and price accordingly. The foundation for microgrid business models is premised in part on the costs and benefits this technology offers to the grid. These include services like black-start capability, frequency regulation, and an ability to shift from energy sink to energy source at a moment’s notice. But these services should be weighed against any additional infrastructure or operational costs associated with integrating many semi-autonomous microgrids into the macrogrid. An initial effort at evaluating the size of these costs and benefits and finding ways to monetize them through existing or new pricing approaches is critical to encouraging microgrid development in situations that make the most sense for the grid, while also providing fair compensation for customers investing their own capital in microgrids.
4. Remove the delivery utility’s disincentive and consider performance-based incentives to stimulate development. As another technology that stands to reduce demand serviced by the distribution utility, there is a potential disincentive for the utility to pursue or support investment in microgrids. However, microgrids present real opportunities to deliver system benefits to customers in the form of cost savings and improved reliability and power quality. Where evaluation and planning reveal these opportunities, the utility should be permitted to pursue and invest in them. Beyond freeing the utility up to invest in microgrids, establishing and strengthening performance-based incentives for cost, reliability, and power quality can provide the carrot that some utilities may need to explore microgrid opportunities. And just as the utility is incentivized to make targeted microgrid investments through performance-based incentives, more highly differentiated pricing can signal to customers and developers where microgrid investments will minimize distribution system costs.
5. Allow broad-based microgrid participation in wholesale markets. In some cases it will make the most sense for microgrids to participate and provide services in the wholesale markets. To facilitate customer participation, clear operational and market-based standards need to exist without limiting customer access to develop a microgrid. In markets like California, the path to participation for a microgrid connected at the transmission level is clear enough, but the situation grows more complex and nuanced when a microgrid is connected to the distribution system and wants to participate in wholesale markets. In this instance, the customer must navigate between the ISO and the distribution utility. Simplifying and reducing barriers to wholesale market participation for microgrids, both big and small, that are connected at the distribution level increases competition in the markets, improves the economic case for microgrids, and provides the grid operator with new resources to balance the system. In Denmark, on the island of Bornholm, the municipal utility is testing a market that encourages participation from many small customers. In this market, prices change every five minutes, there is no limit on the size of demand or supply resources that can participate, and participants do not need to bid into markets to participate, vastly simplifying the task for small residential and commercial customers.
6. Incorporate microgrids into broader grid-planning processes. Both distribution and transmission system planning represent important opportunities for evaluating microgrid options and incorporating them into system design. These resource-planning processes can provide the foundation for targeted deployment of microgrids in ways that minimize system costs, manage load shapes, and provide valuable ancillary services to the grid. Transmission planning processes typically include non-transmission alternatives (NTAs), a category in which microgrids should be included. Although the consideration of NTAs is far from perfect, it represents a clear entry point for the consideration of microgrids. Incorporating microgrids as potential assets for optimization in other integrated grid planning exercises (either traditional Integrated Resource Plans done by electric utilities in 34 states, or alongside the emerging discipline of integrated distribution planning) presents an opportunity to evaluate and implement least-cost distribution alternatives, such as energy efficiency, distributed energy resources, and microgrids.
Can you “micro-municipalize” a municipal utility or co-op?
So with all this talk about “micro-municipalization,” we have to ask ourselves if microgrids pose a similar challenge to publicly owned power as well. Our view is that any publicly funded infrastructure program requires a careful rethink in the face of a powerful dislocative force such as what microgrids embody. However, we see a clear opportunity for municipal electric providers and cooperatives to lead in showing how to practically integrate and promote these projects.
This is, in fact, what is happening in Fort Collins, Colorado. In this city of 150,000 people, the municipal utility is part of a multi-stakeholder effort to develop a 2.5 square mile net-zero energy district. The district, called FortZED, will produce or procure as much electricity from renewable sources as it consumes. One of the first projects in FortZED demonstrated the coordination of distributed energy resources like solar PV and demand response to reduce peak load by 20 percent. Up next for the team is to build on this effort and test the use of these assets as an islanded microgrid. And as the team pushes forward with microgrids, the municipal utility is also working with RMI and its Electricity Innovation Laboratory (e-Lab) on new approaches to scale investment in distributed renewable resources throughout the city. Rather than run from or ignore the challenges that microgrids create for the utility, Fort Collins is tackling them head-on, looking for the opportunities they create for the utility and its customers.
To be clear, we are in the very early stages of working to integrate microgrids into our electricity network. At RMI, we see early evidence of new and additive value that these resources can provide, adding flexibility to operations and stimulating dynamic power markets that result in more resilient and cheaper power. With the right business models, these outcomes can be achieved faster and with greater benefits for all.
This article was originally published at the Rocky Mountain Institute and was reprinted with permission.
Jon Creyts is a program director at RMI, where he helps lead industrial and electric power activities; Eric Maurer is a senior consultant with RMI’s electricity program, where he specializes in the financial and strategic analysis that underpins carbon strategy development.
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