At its White Oak headquarters in Silver Spring, Md., the U.S. Food and Drug Administration doesn’t worry about power outages. That’s because the FDA’s sprawling campus near Washington, D.C., is home to one of the most sophisticated microgrids on the East Coast.
The system is connected to PEPCO’s grid. But with 21 MW of onsite generating capacity, and with solar arrays, thermal storage, and load management systems installed by Honeywell, the White Oak microgrid is capable of isolating itself from PEPCO and running in island mode almost indefinitely—depending on a steady supply of fuel and sunshine, of course. And White Oak has done exactly that several times in recent years, including during and after Superstorm Sandy last fall. While neighboring buildings were in the dark, White Oak kept the lights on.
The U.S. General Services Administration financed the $71 million microgrid project—a tidy sum for a 21-MW system. But Honeywell says it will save the FDA about $11 million a year in energy and O&M costs. That means in less than 10 years, the federal government should start seeing payback from its investment—or sooner if the region gets hit by more storms like Sandy.
Meanwhile, further south along the Atlantic basin, electricity is reaching people in some Haitian villages for the first time ever. A not-for-profit company, EarthSpark International, is setting up tiny utility systems to serve residential and commercial customers. EarthSpark installs microgrids—which tap existing diesel generating capacity, and add solar PV, battery storage, SCADA, and prepaid metering systems—to provide power for nearby homes and businesses. Local service reps set up energy sales contracts for customers, and sell LED lighting and other efficient electric appliances through EarthSpark’s retail subsidiary, Enèji Pwòp (“clean energy”).
Compared to the White Oak system, the EarthSpark microgrids are miniscule; in the village of Les Anglais, for example, EarthSpark is on track to install 150 kW of solar capacity, augmented by about 15 kW from a diesel generator at a Digicel cell phone tower, to provide service for 400 customers. But the potential effect of microgrids in Haiti is anything but miniscule. The availability of microgrid electricity allows customers to cut their monthly energy budgets by as much as 80 percent by reducing or eliminating the need to burn kerosene and candles—and vastly improving their indoor air quality in the bargain. And now Enèji Pwòp micro-power systems are sprouting up across northern Haiti through a partnership with Organisation des Jeunes Visionnaires Haïtiens, a group that provides job training and supports entrepreneurship for Haitian youths. The idea is to spread microgrids as profitable enterprises.
“We’re looking to replicate microgrids in Haiti with a commercial financial model,” says Richenda van Leeuwen, executive director of the UN Foundation’s Energy Access Initiative (See sidebar, “Microgrids for the World”). “The ideal approach would involve a known, stable revenue stream that allows the sponsor to calculate a return profile.”
That’s the key phrase that has transformed the microgrid concept from an unlikely curiosity into a bona-fide development opportunity. Microgrids already are cost-effective in some locations, and seem destined to become more so in the future. Several major trends are pointing in that direction—from growing supplies of natural gas to fuel onsite generation, to rapidly improving energy management technologies and practices. And of course photovoltaics (PV) technology is advancing at an exponential rate, bringing costs down to grid parity in many places, and providing almost immediate payback in locations where expensive diesel fuel provides most of the electricity.
When these and other factors come together in a microgrid package, the potential benefits are promising enough that they’ve given rise to a whole new industry, with a community of developers focused on financing, building, and operating microgrids around the world, across the full range of sizes. And just like the independent power industry did for generation, microgrids could break the seal on the utility compact, introducing competition into the energy industry’s last great monopoly—the electric distribution business.
“It could, in fact, be the final game changer,” says Michael Zimmer, senior counsel at the Thompson Hine law firm. “It’s much like cell phones were a game changer for the centralized landline telephone system, starting the transformation in the mid-’80s that led to the vibrant competitive mobile telecom system that we see today. The microgrid is a logical outgrowth of IT development in the energy sector, and it’s a solution to the inadequacies of the status-quo regulated utility system.”
“Microgrid” has emerged as the hottest buzzword in the utility industry. But the fact is, depending on how you define the term, the microgrid really isn’t new. For decades, hospitals and government facilities have used backup power systems to keep the lights on during outages, and manufacturing and processing industries have operated their own inside-the-fence cogeneration systems in a variety of configurations—grid-tied, utility dispatchable, and entirely off-grid. But a better definition of a microgrid involves more than just distributed generation (DG)—which is a disruptive trend in its own right, but is incomplete without the other components that make a microgrid work. Specifically, a microgrid combines various types of distributed energy resources (DER)—generation, storage, and demand management—in a discrete, smart package. In an integrated utility network, like ours in the United States, the optimal microgrid also is a grid-friendly package that can be isolated on the fly, or conversely, dispatched as a controllable resource.
It’s an elegant idea that heretofore hasn’t gained much traction, because it requires complex and expensive technology to accomplish—not to mention a supportive electric utility. But a few factors are making microgrids easier and more cost-effective to build than their simpler ancestors.
First, the core resource in a microgrid—distributed generation—has gotten cheaper. Or rather, it’s cheaper for gas-fired systems in markets that are enjoying the fruits of the shale-gas boom; diesel fuel remains stubbornly expensive. But other supply technologies definitely have dropped in price—i.e., the aforementioned PV, and also wind turbines, fuel cells, and batteries. PV in particular is dramatically changing the economic calculus in remote locations that lack a supply of cheap gas, and those that offer government incentives for solar energy. And batteries and other forms of integrated storage are increasingly cost-effective and useful for stabilizing the frequency and voltage of small-scale grids.
“Storage is the great leveler,” says Steve Pullins, president of design and development company Horizon Energy. “Every microgrid we install has energy storage. It allows us to actively manage the system.”
That’s where the second factor comes in—energy management systems. Increasingly sophisticated automation and controls allow microgrids to operate with a much tighter reserve margin than macro-scale utilities historically have dared to attempt.
In a regular grid, electric energy, capacity, voltage support, and reactive power supplies are provided by a large pool of hydro, nuclear, and fossil generation. A microgrid operating in island mode can’t tap into such deep resources, so its automated systems must dynamically ramp loads up and down in real time, while synchronizing multiple energy supplies with different power factors and characteristics. These are tricky tasks, and the technology is still maturing. But the evolutionary path leads to increasingly affordable microgrids—because the more efficiently you can manage the system, the less capacity you’ll need to build, and the less fuel you’ll burn.
Fortunately for microgrids, energy management technology is advancing rapidly, along with the utility industry’s growing reliance on less-firm, distributed resources, like demand response (DR), conservation, and variable renewables. “The fundamental technologies are there, but they haven’t been integrated for this application yet,” says Peter Lilienthal, president of HOMER Energy, which provides software for modeling microgrid systems. “Technical standards aren’t yet in place, so the first few projects must use custom solutions. But there’s enormous opportunity for costs to come way down.”
And third, the trend toward integrating DERs in wholesale energy markets is changing the way some utilities and resource planners view the whole energy services business, creating new opportunities for alternative approaches. In organized markets, a next-generation microgrid could be treated like a big dispatchable load—and perhaps even a power plant that can relieve congestion on the grid.
The prospect of microgrid-as-power-plant raises interesting possibilities vis-à-vis revenues from net metering and grid services. But it also raises technical and regulatory issues, and not everyone agrees that microgrids should export power to the grid. Pareto Energy, for example, uses inverters that keep its microgrids effectively isolated, even when they’re drawing power from the grid. But whether it’s designed to export power or not, a microgrid could qualify as a non-transmission alternative (NTA)1 for system planning purposes—a category of grid asset the Federal Energy Regulatory Commission in 2011 established in its landmark Order 1000.
At this stage of development, the optimal microgrid is still evolving; going from grid-tied to island mode isn’t always a seamless or glitch-free process. But microgrids equipped with next-generation energy management systems and controls will be highly valuable assets in an integrated utility network.
“Cracking the code on optimization should drive down our costs, and allow us to utilize huge untapped benefits in distributed resources,” says David Mohler, Duke Energy’s chief technology officer. He points out that of all the DG systems now installed, about 80 percent sit idle almost all of the time. “They aren’t being economically dispatched. Integrated into a larger system, they can be used more effectively. That’s something we can figure out.”
Toward that end, Duke installed a microgrid test project in its home town of Charlotte, at the McAlpine Creek substation. The project involves a 50-kW PV array and a 500-kW zinc-bromide battery, serving a fire station and about 100 homes equipped with energy management systems—all managed with a commercial software package called IDROP (Integrated Dispatchable Resource Optimization Portfolio). Duke reports remarkable results from the project—estimating significant returns on investment when the system is economically dispatched, based on locational pricing and real-time cost of service.2
“There’s huge potential for microgrids to provide very-much-enhanced DR and peak avoidance,” Mohler says. “It’s about cost savings. If you have 50 MW in microgrids, and you can take those customers off and put them back on when the peak is gone, that would be pretty amazing.”
In the future, optimized microgrids like Duke’s will be part of a transactional energy market, in which resources are valued and operated on the basis of system constraints. “As we move toward nodal markets, microgrids will provide targeted DR that can help utilities manage costs and manage the grid,” says Pullins of Horizon Energy. “Those are economic drivers for utilities and their customers.”
For every potential benefit, the microgrid poses half a dozen technical challenges. But perhaps more important than technical issues are financial and regulatory barriers.
On the regulatory front, microgrids defy the standard approach to retail utility services, leapfrogging the rate-regulated framework and providing a full scope of services directly to host customers, at their sites. Different jurisdictions present different regulatory challenges, but as a general matter, when a microgrid owner in the United States seeks to serve more than one customer—or sometimes even the same customer with locations on two sides of a public street—that’s when legal battles tend to begin.3 As a result, most developers in the United States expect each microgrid to serve just one narrowly defined customer—following the same legal paths as a company that develops inside-the-fence cogeneration systems.
But restricting microgrids to single-customer facilities or campuses imposes an artificial limit on the market, and arguably prevents microgrids from providing the full measure of their value in locations where multiple adjacent customers can be effectively served as a unit. The trick to escaping this single-customer ghetto, developers say, would be to use ownership and sales structures that tiptoe around utility franchise laws4 —or, alternatively, to forge arrangements that secure the active support of franchised utilities.
“We have a microgrid at a university with all kinds of adjacent privately owned properties, including a data center and a hotel,” says Guy Warner, founder and CEO of Pareto Energy. “They’d like to pool their resources and join the microgrid. How do you organize them? To what extent can they self-determine their energy infrastructure?”
If the local utility won’t support multi-customer microgrid development, some possible approaches involve forming electric cooperatives; municipalizing certain grid assets; or establishing mutual company structures that perhaps could behave as a single customer. Warner suggests another approach, based on the “business improvement district” model that’s sometimes used to foster economic growth in specific areas. These districts sometimes get the blessing of a city or other government agency, but they’re developed and managed by the residents of the district. “An energy improvement district makes sense where there’s a spot in the grid with a bunch of energy users that can pull together to negotiate,” Warner says.
In each situation, the key would be for customers to present a united front that utilities and regulators can’t easily dismiss. Arrangements resulting from such an approach might resemble the aggregation structures that are proliferating in some states with deregulated retail electricity markets. Like an energy service company aggregating demand, a cluster of customers could aggregate their full scope of energy supply requirements, and contract them out to a microgrid service provider. Exactly what services the third party might provide, and how the assets would be owned, would depend on various factors—including regulatory structures, customers’ needs, and financing arrangements.
Such approaches, however, remain somewhat academic, as companies are focusing first on developing the potential market for single-customer microgrids. These projects present more than enough complexities for developers, without picking fights over the utility franchise.
Microgrid developers seem to be going through the same gauntlet that IPP developers traversed back in the 1980s and 1990s—convincing banks and investors to provide debt and equity financing for a new type of energy enterprise. Microgrids pose technology risks, cash-flow questions, and regulatory uncertainties—just like early IPPs did. And as a result, most microgrids in the industrialized world today are being financed by their host institutions, frequently with government assistance.
U.S. taxpayers paid for the FDA’s microgrid at White Oak, and also will pay for dozens of military microgrids being pursued by the Defense Department at its various bases around the world. New York University financed the microgrid at its Washington Square campus with tax-exempt revenue bonds.5 The University of California paid for its famous microgrid at UC San Diego, with help from the California Energy Commission. And Alameda County financed the $6.4 million microgrid at the Santa Rita Jail, with help from the State of California and the U.S. DoD’s fuel cell program. In each case, the money was relatively cheap and easy to raise, on the strength of the host institution’s credit and tax-exempt status.
Project financing for independently owned commercial microgrids, however, is another story.
“In the long run our plan is to be an owner,” says Terry Mohn, CEO of General Microgrids. “But we have to attract capital for projects. Banks aren’t familiar with microgrids, so the way to attract capital is to have a power purchase agreement (PPA). That’s unfortunate, but it’s what the banks understand.”
It’s unfortunate because a microgrid is much more than just a power plant, and thus the capital costs will be much higher per kilowatt of microgrid capacity—and per kWh of sales—than they would be for a traditional IPP. A microgrid likely will have revenue streams beyond just energy sales, but those streams might seem less tangible to a banker. “The model we’re looking at is very similar to a PPA, with infrastructure costs added in,” Mohn says. “The generation pays for the other elements of the microgrid—the reliability, demand management, and integrated smart grid components.”
This approach, Mohn says, works best for projects 10 MW or larger in size, because those projects have enough energy sales revenue to cover non-generating capital costs. Pullins at Horizon, on the other hand, says PPAs can work for microgrids as small as 2 MW. “That’s where both the customer and the third-party developer can financially benefit,” he says.
“You have to remember that C&I customers in the United States have been investing in 5.5 GW of new behind-the-meter generation capacity and energy efficiency programs every year for the last 15 years,” Pullins says. “That’s up to $6 billion a year they’re spending on self-generation and load control. With a microgrid, you can do it more efficiently and effectively. You can offer a lower rate and a lower cost-escalator than they currently bear, and still have a fair rate of return on the project. And at the same time, you make them a more successful grid partner, a good citizen on the grid.”
Ultimately, the goal is to develop a financial model in which the energy customer pays a premium—say, 10 or 15 percent—for a more resilient and reliable energy supply, and that amount, combined with energy savings and perhaps revenues for things like DR bidding and renewable energy credits, adds up to healthy debt-service coverage for banks.
“The microgrid project finance model is absolutely a work in progress,” says Mark Lopata, president of Microgrid Solar, which sells distributed rooftop solar systems and also develops microgrids on islands. “There are lots of banks and investors that understand the renewable energy business—the technology risk and cash flows—and they’re willing to finance projects as leases or PPAs. It’s just a matter of presenting it to them in a way that makes sense. They’re looking for projects that come to the table fully fleshed out.”
Beyond pure commercial financing, options can open up where projects serve policy goals at various government levels. The state of Connecticut provides grants and loans to support microgrid development.6 New York and California both have provided funding for microgrids, and so have the U.S. DOE and DoD. Some microgrids can qualify for special funding to support things like EV charging; distributed generation; conservation and efficiency; renewables; and greenhouse gas abatement. Microgrids also could benefit from federal and state tax incentives, to the degree equity owners have tax liabilities to offset.
Projects also might fit into tax-efficient financing vehicles, like master limited partnerships or real estate investment trusts.7 “If you can define microgrid projects as MLPs or REITs, that would be very useful to bridge the gap for capital formation,” says Zimmer of Thompson Hine. “PACE [Property Assessed Clean Energy] financing also offers potential.”
In some cases, developers might finance microgrids by leaning on a host customer’s balance sheet at some phase—through a lease or build-own-operate-transfer (BOT) arrangement. Many IPPs used such structures during that industry’s maturation phase, particularly in jurisdictions that restricted ownership of energy assets. And also like early IPPs, microgrid developers could team up with more established players that have larger balance sheets—in this case energy service companies and perhaps system vendors and engineering companies. SAIC and DNV KEMA, for example, have teams focused on developing microgrids.8 “I wouldn’t be surprised if Siemens, Johnson Controls, and Honeywell got into this market, because there’s an opportunity here,” Mohn says. “It’s a big opportunity.”
The most logical partners, of course, are utilities themselves. Investment-grade utilities can access some of the lowest-cost capital in the market. They have real-world operating know-how about smart grid systems, and clear reasons for gaining more knowledge about them. And if the local utility were an investor, it might be more inclined to facilitate interconnection and dispatch, and optimize assets for everyone’s benefit. The local utility is in the best position to know where microgrids make the most sense—i.e., to relieve congestion and reduce the cost of serving customers in load pockets, for example, or in places where distribution systems are stressed.
“We’d like to know where the weak substations are,” says Warner of Pareto Energy. “We have no idea. Utilities have all the information, and they’re not going to tell us where to get the most bang for the buck.”
But properly motivated, a utility might tell—and it might even support multi-customer microgrids, if it means resolving persistent problems in a cost-effective way, and raising customer satisfaction in the process.
“The model I prefer is to let utilities do this,” Warner says. “They should forge a new business model, like Bell Atlantic became Verizon. There must be win-win ways for them to get into the microgrid business.” He acknowledges that in some states, regulations prevent distribution utilities from investing in generation. “But they can do financing,” he says. “They can do T&D, dispatch, forecasting, metering, controls … they should be doing all of that, or at least the controls, if nothing else.”
Microgrids’ ability to achieve their potential—to truly deliver benefits to the grid, rather than just provide some benefits to host customers—likely depends on utilities’ willingness to facilitate rather than fight the phenomenon. “The utility could offer microgrids as a service, but as far as I know no utility does,” Warner says. “I don’t understand why.”
The likely reasons are complex. One issue is the aforementioned constraint on unbundled utilities investing in generation. Another involves prohibitions against self-dealing and cross-subsidy; investing in a microgrid that sells power back to the utility could be perceived as diverting capital into a speculative venture to benefit certain customers and utility shareholders, to the detriment of non-microgrid customers. On that point, utilities increasingly are concerned about stranded investments and rising burdens to provide service for self-generating customers.9 Investing in a microgrid might be seen as exacerbating the problem, while also diminishing the utility’s standing in regulatory proceedings addressing the issue.
And some utilities might feel constrained by state laws that require them to provide equivalent service to all customers within a class; regulators frown upon utilities offering higher service levels to some customers and not others. Of course states establish special tariffs for various programs, and utilities could find a way to do so for microgrids if they had a good reason.
But given this array of challenges, the question isn’t why utilities don’t offer microgrids as a service, but why in the world they’d want to do so. One reason might be that if they don’t do it, someone else will.
“Disintermediation is happening,” says Mohler of Duke Energy. “We’re seeing more players getting into the space—the EnerNOCs and Googles of the world. Some of it is destroying value, but a lot of it is creating value.” And just as any disruptive transition is most problematic for incumbent, legacy businesses, microgrids and other DER upstarts pose a challenge for utilities—try to beat them, or try to join them?
“If I were the CEO of a large utility, I would jump on this opportunity,” says Mohn of General Microgrids. “If I can build 80 microgrids in 80 different communities, wouldn’t that be just like building a utility, but without all the implications of owning a large service territory? I would think a utility would be a great candidate to make that investment. But on the flip side, maybe communities and customers will say ‘Utilities haven’t serviced us properly, so why would we want them to do it now?’ It’s a great opportunity for an independent developer to come in and serve those customers.”
Utilities understandably oppose competition in the distribution business, and their first instinct likely will be to block it or marginalize it.10 But doing so poses its own risks—including the real possibility of a backlash, if utilities become hostile toward microgrids and other DERs. After all, if microgrids soon will become cost-effective for some customers in grid-tied mode, how much longer can it be before they pay off as fully isolated systems?
By some accounts, this is a small risk, given that most microgrids won’t be designed with off-grid operations in mind. They won’t be able to generate a full 100 percent of the host’s energy needs, and islanding during a utility outage will require emergency load shedding. But as time goes on, and as developers gain experience with isolated systems elsewhere in the world, the economics will change. Depending on whom you ask, viable off-grid systems might not be far off.
“When we propose a microgrid, we consider four business case scenarios,” says Pullins of Horizon Energy. “We consider maximum savings, maximum renewables, grid independence, and maximum diversity. The difference in cost between the maximum savings and grid independence scenarios isn’t very large.”
Pullins suggests that if utilities move to discourage microgrids—for example, by forcing self-generation customers to carry the full freight of non-energy network charges, even when they’re not buying electricity—they might just be making the off-grid option more attractive, and creating ill will that serves no one.
“That’s not a good model for utilities,” Pullins says. “After all, this isn’t microgrids challenging the regulatory model; it’s customers challenging that model. Utilities shouldn’t have misplaced aggression against microgrids.” The strategy of marginalizing DERs by heaping costs on fixed charges is a “death spiral,” he says.
Moreover, strategies that contravene the wishes of customers seem likely to elicit a vigorous public reaction that could complicate life for utilities in policy forums. “I don’t suspect a utility would be successful arguing with their customer base,” Pullins says. “Certainly they wouldn’t be successful in the public forum. One thing you never do in a customer-facing industry is sue your customers.”
That leaves two key questions for utilities: How many customers might move toward microgrids, and how should we deal with them? Depending on how the future unfolds, the numbers could be substantial. Just as aggregation arrangements are proliferating in states where they’re allowed, microgrids could become attractive to many commercial, industrial, and institutional customers that want service levels and options that utilities aren’t providing. How many of those customers would actually take the leap is an open question; Pullins puts the total number of prospects at 24,000 sites in the United States, with as many as 300 getting microgrids by the end of 2015. But whatever the exact number, a large share are likely to be exactly the kinds of customers that utilities are most loath to lose.
“The subset of customers who passionately want to get away from the big-bad utility, and who are prepared to make the required investment and to manage the technical issues it entails—that subset of customers is small,” says Mohler of Duke Energy. “For those customers, they should be able to do it. It’s their prerogative. To me the key question isn’t how do you prevent it, but how do you capture the full value of distributed energy? I don’t believe it would be possible for an individual customer to create as much value with a microgrid as it would as a fully integrated, dispatched part of the broader system.”
Microgrids and DERs raise difficult questions for utilities, but they also accelerate a paradigm shift that some utilities have been anticipating—and might actively support.
“The root issue,” Mohler says, “is that the existing utility business model simply has to change.”
The utility industry’s traditional volumetric business model, he says, with standard rate tariffs and least-cost planning, is obsolete in a world where customers require a wider range of differentiated services than simply taking electrons off a wire. “The business model is left over from when the industry was electrifying the country,” he says. “That’s done now, electricity demand has flattened out, and utility service today is about life convenience.”
Accordingly, the utility industry should refocus its mission on serving the customer’s need for value, rather than the bare necessity for energy. Indeed, that need is the whole reason microgrids are cropping up—to deliver a level of value that traditional utility services simply don’t, even though they certainly could. Arguably microgrids—and distributed energy resources in general—are the proverbial camel’s nose under the tent; they’re a small factor today, but they could become much larger and very disruptive, very quickly.
“As more of this activity goes forward and costs improve, we’ll face a real issue,” Mohler says. “How does society finance the reliability of the system as load starts coming off? There has to be a mechanism. It’s not free.”
This growing concern about demand destruction reflects a realization by utilities that they’re no longer the only game in town, when it comes to energy services. That’s a fact that executives and policymakers are still trying to reconcile with service obligations and rate structures established by the utility regulatory compact. Ultimately the problem—and the solution—might be found in the emerging transactional approach to valuing energy services.
“Utilities tend to look at things in the average, not the margin,” Warner says. Microgrids will be most cost effective on the margin, he explains, where costs of service substantially exceed the average. “Those are the places where it makes sense to do distributed generation. The utility is in a jam in certain places where the marginal cost of power is a lot higher than [what it can charge for] its duty to serve. Those places are win-win opportunities, where without microgrids, the utility is just losing money.”
Zimmer of Thompson Hine adds, “Smart utilities might see microgrids as a new service model. Using distributed energy and digital infrastructure creates a new way to address growing concerns. It’s a way to better manage power stability, in terms of voltage levels, frequency, and signal phasing. And it might be a way to test dynamic pricing and other rate approaches.”
But such opportunities are only as compelling as the regulatory structures that allow utilities to profit from them, whether through rate-based capital or unregulated investments.
“We have to begin pursuing regulatory policies and strategies that allow the business model to evolve,” Mohler says. “Maybe the place to start is just to allow different types of customers to be treated differently, if they want different kinds of service.”
1. See “Looking Beyond Transmission: FERC Order 1000 and the case for alternative solutions,” by Elizabeth Watson and Kenneth Colburn, Public Utilities Fortnightly, April 2013.
2. “[D]ispatching the battery and customers based on LMP and COS [locational marginal pricing and cost of service] has profound changes on the net value to the utility. [W]ithout any dispatching of the distributed resources, the microgrid would result in a net loss of over a dollar [over the test period], while managing all these resources as a system results in a net income of over four dollars… This is a proven solution that is easily extensible to deliver short-and long-term return on investment.” See Michael Ozog, Integral Analytics, and Anuja Ratnayake, Duke Energy, “Orchestrating Duke’s ‘Virtual Power Plant,’” presented at Association for Energy Services Professionals National Meeting, 2010.
4. Not all utility franchise laws in the United States forbid independent sales to multiple retail customers, and some franchise agreements allow for certain exceptions and exemptions; op cit., Bronin and McCary.
5. Microgrids: An Assessment of the Value, Opportunities and Barriers to Deployment in New York State, New York State Energy Research and Development Authority, September 2010.
6. Connecticut Department of Energy and Environmental Protection, Microgrid Grand and Loan Pilot Program.
7. See “Green REITs, MLPs, and Up-Cs: Tax-efficient capital vehicles for unregulated utility investments,” by David F. Levy, et al., Fortnightly’s Spark, April 2013.
8. See “March of the Microgrids: Technology is changing the game. Is your utility ready?” http://www.fortnightly.com/fortnightly/2013/01/march-microgrids by Stephen F. Schneider, SAIC; and “Smart Grid at a Crossroads: Refining the business case for advanced distribution investments,” by Michael T. Burr, Public Utilities Fortnightly, January 2013.
9. See “The Law of Unintended Consequences: The transition to distributed generation calls for a new regulatory model,” by Robert E. Curry Jr., Public Utilities Fortnightly, March 2013.
10. In one recent case, the Public Service Commission rejected a petition by NV Energy to block the Department of Energy from transferring its electric business at the Nevada National Security Site (the nuclear weapons testing site) to the Valley Electric Association cooperative. DOE gave VEA a $62 million contract to provide services over five years. Although not a microgrid as such, the VEA contract includes almost doubling onsite generation from 40 MW to 70 MW, and upgrading systems to improve reliability and “eliminate long-standing low-voltage concerns.” (Nevada PSC Dkt. 13-01021)