Part II of IV: Short and Long-term Solutions for Struggling Commercial Nuclear Energy Generators in Restructured Wholesale Markets

Background on the History of Commercial Nuclear Power Generation in the U.S. and How Restructured Electricity Markets Developed

To understand how market forces currently threaten the viability of nuclear power generators, it is important to know how the electricity sector itself has evolved over the years. Part II of this blog series briefly summarizes the development of the electricity sector, from the early advent of public utility law and cost-of-service regulation, to the expansive restructured wholesale markets through which most Americans receive their power. With that background, subsequent subsections discuss the particularities of nuclear power generation and how it fits into, and is struggling because of, these wholesale market structures. Continue reading


Part I of IV: Short and Long-term Solutions for Struggling Commercial Nuclear Energy Generators in Restructured Wholesale Markets

Although the U.S. nuclear power industry has struggled to regain footing in the aftermath of Three Mile Island and Fukushima, nuclear power nonetheless plays a critical role in the nation’s electricity sector and will be a necessary resource to utilize in the struggle to reduce carbon emissions and combat climate change. Aside from concerns over finding a permanent waste storage solution, an increasing worry for industry members is how high-cost – but emissions-free – nuclear power is being undercut by low-cost natural gas in restructured wholesale power markets. Without a long-term market-based mechanism to account for the environmental and grid-stabilizing benefits provided by nuclear power generation, America risks losing this important, carbon-free, source of base load generation. Over the course of the next few months, I will upload a series of posts discussing some potential long-term market-based solutions to put nuclear energy on a level playing field, and furthermore argues for a nuclear feed-in tariff as a short-term solution for states with the most financially vulnerable nuclear energy generators.

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Going it Alone: Potential Interstate Problems of Intrastate Clean Power Plan Compliance

As evidenced by the 27 states that are suing the EPA, the agency’s recently-finalized Clean Power Plan(CPP) is controversial to say the least. In addition to the legal challenges facing the rule, there are also concerns over grid reliability posed by the large number of coal-fired generator retirements anticipated in the near term. Although much ink has been spilled on analyzing the Clean Power Plan, aside from discussions over grid reliability, little attention has been paid to other potential interstate effects posed by intra-state CPP compliance efforts, and vice versa. Despite the pitfalls posed by discordant state implementation plans within a region, the CPP nonetheless does not require regional collaboration. As argued in this essay, however, by failing to collaborate, states may not only put their own and neighboring states’ CPP compliance plans at risk, but also jeopardize existing and future regional electric system planning efforts.
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“So What’s the Horror Here of Concurrent Jurisdiction?”

As readers are likely well aware of, this month the Supreme Court heard oral argument in FERC v. Electric Power Supply Association. The ultimate result could decide the fate of the nascent wholesale demand response sector, but at a deeper level, the case raises important questions about how well equipped the Federal Power Act is to facilitate innovation, integrate new technologies, and allow for cross-jurisdictional electric system planning.

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“What Is The True Nature Of A Sale That Was Never Made?”

An Existential Dilemma Arrives at the Supreme Court 

On Wednesday, October 14, the Supremes will hear oral argument in Electricity Power Supply Association v. Federal Energy Regulatory Commission. The ultimate result could decide the fate of a nascent cleantech industry aimed at promoting efficiency, lowering prices, and reducing greenhouse gas emissions. More fundamentally, though, this case raises important questions about the federalism underpinnings of the U.S. electricity sector, and how well they can adapt to the new energy evolution underway today.

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Protecting Low-Income Ratepayers as the Electricity Industry Evolves

A common understanding among all electric utility reform efforts is that significant investment in our energy infrastructure is needed. In today’s age of flattening electricity demand, expanding DER integration, carbon constraints, cybersecurity and physical threats, and cheap natural gas, electric utilities can no longer rely on building new central generating plants and selling more and more kilowatt-hours to generate profits and support the cost of maintaining and improving the system.

These realities are fundamentally changing the way that electric utilities will be operated and regulated, and several states, like New York, Minnesota, Massachusetts, and Hawaii, have begun investigating how to prepare for and guide this evolution. At the forefront of this discussion are important issues like how to change utility business models and pricing structures, both of which are being actively examined in New York’s REV proceeding and the stakeholder-led e21 Initiative in Minnesota. Every reform effort around the country also includes a recognition that the system of the future must continue to deliver universal, reliable and affordable service. One under-examined issue, however, is just how radically these changes will affect the most vulnerable in our communities — specifically, low-income ratepayers — and how we will protect them.

This article is an excerpt from a larger on-going research project from GW Law’s Sustainable Energy Initiative. Although we are only introducing the project in this article, the ultimate goal of our research is to highlight what policies both protect low-income ratepayers and complement the larger Utility 2.0 reform process taking place across the country.

Scope of the Low-Income Problem

According to the U.S. Census Bureau, 46.7 million people were in poverty in the United States in 2014 — nearly 14.8 percent of the population. But those numbers tell only part of the story. Generally, although each state- and utility-run low-income assistance program defines “low-income” differently, most peg eligibility to certain thresholds at or up to 200 percent of the federal poverty level (FPL) — which expands the total number of eligible enrollees for low-income assistance programs by some 10.6 million people.

In the context of energy assistance, many programs look to not only a person’s income in relation to the FPL but also his or her total “energy burden” — that is, the percentage of a customer’s income spent on energy. According to various resources, like the federal Energy Information Administration middle-income and high-income ratepayers have a one to five percent energy burden, whereas low-income customers face burdens from 10 to 30 percent or more depending on the state.

Sample State Comparison of Energy Burden and Number of Households in 2014 in Relation to the Federal Poverty Level

Although the above table highlights only four states, it is clear that millions of Americans struggle to pay their energy bills. And the closer a household is to the federal poverty level, the more onerous that monthly energy bill is. This problem manifests itself in millions of service terminations every year, as well as hundreds of millions of dollars in unpaid bills owed to utilities. So what policies are in place to assist low-income ratepayers, and how well are they working?

Programs and Policies to Assist Low-Income Ratepayers

States and the federal government have various tools available to help low-income households with their energy burdens. At the federal level, two important initiatives are the Low Income Home Energy Assistance Program (LIHEAP, discussed further below) and the Weatherization Assistance Program — both of which are federally-funded grant programs administered in every state, the District of Columbia, as well as most tribal reservations and U.S. territories. State governments also have a broad selection of programs, but the primary mechanism for helping low-income individuals is through the utility rate structure itself.

1. Low Income Home Energy Assistance Program (LIHEAP)

Since funding began in 1981, LIHEAP has become a critical lifeline for some of the country’s most vulnerable members. However, due to budgetary constraints, LIHEAP funding has been cut considerably, from $4.7 billion in 2011 to $3.4 billion in 2014 — which directly impacts the number of funding recipients. In concrete terms, here are those same states again, when factoring in LIHEAP eligibility cap of 150% of FPL.

Sample State Comparison of Total Poor and Low-Income Households
and LIHEAP Coverage

For each of the above states, there is a wide gap between how many households qualify for LIHEAP and how many receive coverage in the form of heating or cooling assistance. Indeed, of the roughly 28,780,463 households that met the LIHEAP eligibility requirement in 2014, only 2,985,747, or 10.3%, received assistance. So, if only a small percentage of low-income ratepayers receive LIHEAP assistance, how are the others getting by and how can we both ensure their protection in the future, and potentially broaden coverage to others in need?

2. Ratemaking

Aside from programs like LIHEAP, the other policy tool for assisting low-income ratepayers is through the utility rate structure itself. Although there are about ten different categories of rate structures used by the states, they essentially all boil down to a subsidy paid for by industrial and other residential ratepayers. In essence, by imposing slightly higher rates on industrial, commercial and non low-income residential customers, utilities are able to deliver electricity to low-income customers at rates that are oftentimes below the actual cost of the electricity service.

For example, in the typical increasing block rate, higher rates are imposed on high-usage customers (read: industrial ratepayers), and rates for other customer classes also rise with consumption.

Standard Inclining Block Rate

One of the criticisms of the conventional block rate utility rate structure is that it does not so much target low-income customers as low-usage customers — many of whom may not necessarily be low-income. As such, usage-based rates may be over-inclusive, thereby diverting resources away from low-income customers who, because of poor home weatherization or large household size, are not low energy users, and applying them to low-usage customers who do not require subsidization; and potentially sending false price signals that fail to incentivize energy efficiency that would be societally beneficial.

As reported in a recent Electricity Journal article, a helpful illustration of this can be found in the results of a recent study conducted by a medium-sized utility in Oregon. The utility sought to answer the question of how well low-usage corresponds with low-income, and the results were surprising. When the utility analyzed its entire residential load according to various usage categories, it found that its low-income customers were spread out among various usage levels, just like the larger residential class. With only ten percent of the utility’s total residential class being low-income that meant that the utility’s block rate structure “was helping about nine times as many customers as intended.”

To the extent that conventional utility rates worked well at subsidizing low-income customers — a disputed point, as noted above — it was primarily because such rates were implemented in an era of increasing electricity demand and grid-dependence. However, as mentioned at the outset of this piece, today’s electricity sector faces just the opposite set of challenges: demand is falling and more residential and industrial customers want to self-generate, which puts more pressure to subsidize low-income customers and maintain the entire system on a dwindling group of ratepayers.

In the coming months, GW Law’s Sustainable Energy Initiative will be exploring this issue more thoroughly and preparing a set of policy solutions. As utilities and regulators endeavor to adapt to these new realities, they will have big problems to solve: How will utilities earn revenue despite falling demand and customer-side distributed generation? What regulatory policies will be required to ensure sustainable, equitable, forward-thinking development? As new policies and regulatory models emerge from these discussions, it is also important to remember that this evolution will especially affect those in our community who are the most vulnerable to the changing status quo.

Millennial Consumers and Energy Users

America’s “Millennial” — or “Gen Y” — generation has been a popular topic of discussion, and it’s not hard to see why. Encompassing those born roughly between 1980 and 2000, Millennials are the country’s largest generation by population size (nearly 80 million people, or one quarter of the U.S. population), and are just now coming into their own as trend-setters, political mobilizers, and — as explored here — energy consumers.

As a generation, Millennials have been identified by their digital connectivity, affinity for #selfies and social media, and tireless optimism in the face of bleak economic prospects. According to the Pew Research Center, one-third of Millennials have a four-year college degree or more and about 43% identify as non-white — making this generation the most educated and racially diverse group in U.S. history. On the one hand, researchers have described Millennials as noncynical, civic-minded, and politically active, while on the other, additional studies have shown them to be inwardly-focused, apathetic toward politics and social issues, and, perhaps surprisingly, the least environmentally-minded of any previous generation.

Whether this cohort will ultimately be known as “Generation We” or “Generation Me” remains a driving question behind the ever-expanding body of research into the Millennial psyche. Meanwhile, data on the group’s consumer habits is much more straight-forward — providing useful insights for businesses interested in this multi-billion-dollar market, and giving electricity utilities a glimpse at what their future ratepayers value.

Millennials as Consumers and Energy Users:

Of the multiple drivers behind Millennial consumer spending, two stand out the most for this generation: cost-savings and connectivity. While product quality matters to a certain degree, Millennials tend to care most about price — not surprising, considering that they are saddled with staggering student debt in the face of lackluster job prospects. Furthermore, as the first “digital natives”, Millennials embrace technology and expect high-performance and usability from their products and websites.

Being cost-conscious and digitally-connected have led Millennials to develop a unique value-set. Traditional “adult” markers prized by previous generations — homeownership, marriage,  retirement savings, etc. — are being delayed or forgone entirely due to changed values and limited economic opportunities. Instead, as shown by the rise of Uber, Airbnb and other “sharing economy” companies, many Millennials value flexibility and experiences — especially when they can be arranged on the go from their smartphones. As summed up by one market strategist, in addition to cost-savings, Millennial consumers value “happiness, passion, diversity, sharing and discovery.”

This new “Millennial value-set” could have profound implications for the electric utility industry. “Consumer energy markets are really posed to be totally upended,” said NRG CEO Steve McBee in a recent interview. He likened the energy sector to other consumer categories like transportation or tourism or retail or entertainment or publishing or media, which have all been disrupted over the past couple decades “in part by the new products and services and technologies that mostly insurgent competitors have brought to market.”

In addition to utilities like NRG, the software-as-service company, Opower, has also taken an interest in Millennial consumers. Those familiar with the “disruptive” forces at work in the utility sector (increasing integration of electric vehicles, rising demand for rooftop solar fueled by reduced solar PV costs, etc.) will agree with Opower that “the traditional utility experience is pretty much over.” Perhaps taking a cue from Millennials, more and more customers want a wider range of energy products and services from their utilities, including personalized information on their energy usage and smart metering capabilities.

Why This Should Matter to Electric Utilities and Regulators:

As utilities begin to adopt more customer-centric business models, they would be wise to reexamine just who their customers are — or soon will be. By 2025, Millennials will make up 75% of the workforce in the U.S., and as a result, they will be calling a lot of the shots as consumers and energy users. Although some consumers may not share a desire for “granular-level” energy data (indeed, the average consumer annually spends only 6-9 minutes interacting with their utility), Millennial consumers as a whole do want to be more engaged with the product and services they buy. The sooner utilities shift to a more customer-centered, interactive, business model, the greater their advantage will be in the new energy economy.

What Lies Ahead for Utilities?

What Lies Ahead for Utilities?

For decades, U.S. electric utilities have enjoyed monopolies over their service areas and customer bases. In the coming years, however, a host of destabilizing realities will prompt the utility industry and policymakers to reconsider the utility’s role in the 21st century energy economy. As these challenges mount, currently-captive ratepayers will soon be able to drastically reduce their consumption, and perhaps one day disconnect from the utility entirely — precipitating what some have christened, the “utility death spiral.” How utilities will remain operational, and solvent, in this brave new world, is the topic of this and the next few series of posts.

The current Investor-owned utility business and regulatory structure

Although often colloquially and collectively referred to as “utilities,” investor-owned utilities (IOUs) are actually much different than their municipal utility and rural cooperative counterparts. First, IOUs currently claim a larger market-share of electricity customers: about 68%, as compared to 14.6% for municipal utilities, and 12% for rural cooperatives. Second, while municipal utilities and rural electric cooperatives are largely allowed to self-regulate (except for federal regulatory oversight in the wholesale marketplace), IOUs are principally regulated by their respective state’s public utility commission (PUC). IOU revenue is determined by a PUC-approved calculation that amortizes the cost of utility assets and a reasonable rate of return across all the utility’s ratepayers over a period of years. Under this ratemaking model, IOUs are incentivized to build large generation units and keep the meters turning.

Current policy and market trends are shaking this model to its core. On a macro level, political and societal concerns over climate change are forcing all utilities to invest in more renewable energy sources, energy efficiency programs, and prompting stricter emissions regulations that are shuttering many fossil burning generators. On a micro level, customers are calling for more integration of distributed energy resources (DERs) and demand-side management (DSM)—disruptive challenges that will effectively reduce IOU “market share” and lower their revenues under the current regulatory model. The following paragraphs will look at some of these factors, and future posts will discuss how utilities are responding — and should respond — to remain relevant in the future energy economy.

Destabilizing forces affecting the IOU business model

A. Energy Demand

Population growth, slow-but-steady economic growth, and PV implementation are three positive factors that will drive up electricity demand. However, this rise will be counterbalanced by higher electricity prices (owing in part to tighter environmental regulations), efficiency policies, and smart meter (or even, microgrid) policies.[1] In the end, the EIA projects that electricity demand will decline 6 percent from now through 2040, and coal’s market share of electricity generation will decline to 35 percent.The EIA report does not take into account anticipated or pending policies (only fully implemented legislation), so these may be conservative estimates.

B. Energy Efficiency

Energy efficiency (EE) programs and investments will continue to impact utility load and cut into their sales. One DOE study estimates that with current electricity price trends, customer objectives, and various other policy incentives, EE program spending could rise 300 percent by 2025—from today’s $6 billion per year to $16 billion. Under the current rate structure, utilities will have to raise their rates to make up for this lost revenue, which in turn could prompt customers to either reduce their consumption further, or off-set it through DER.

C. Distributed Energy Resources (DER), Demand-Side Management (DSM), and Smart meters

The renewable distributed energy resource (DER) with the most near-term potential is solar photovoltaic (PV) panels. Solar PV installments totaled 3,313 MW in 2012, a 76% increase from the year prior. The utility sector grew the most (54%, or 1,782MW), followed by non-residential installments (more than 1000MW, or about 30%), and the residential sector, which installed about 524MW, or roughly 16% of the total. For next year, the Solar Energy Industries Association forecasts an additional 4,300MW of new PV (a 29% increase from 2012), and 946MW of concentrating solar power. The top ten states contributing toward the 2012 solar PV deployment were: California (1032.7 MW of installed generation), Arizona (710.3MW), New Jersey (414.9MW), Nevada (198 MW), North Carolina (131.9 MW), Massachusetts (128.9MW), Hawaii (108.7 MW), Maryland (74.3MW), Colorado (69.9MW), Texas (64.1MW). Bloomberg New Energy Finance anticipates a 22% compound annual growth rate in PV installations through 2020, which will result in 30 GW of total PV capacity, 4.5GW of which from distributed PV. Solar PV is expected to reach grid parity with little-to-no government subsidy assistance by 2017. Wind energy technology is also decreasing in price. Demand-side generation has become more popular thanks to net-metering statutes (implemented by over 40 states) and state and federal incentive programs.

The implementation of smart grid technology—especially smart meters—is on the rise. Thanks in large part to federal stimulus funding, to date, nearly 35 million meters have already been deployed across the United States, and 15 million more are projected to be installed by the end of 2013. However, utilities are just now starting to implement some of the key features enabled by smart meters, such as: outage management, voltage optimization, load planning and revenue protection.

In the absence of innovative policymaking and ratemaking restructuring, increased DER and DSM will negatively affect utilities’ bottom-line. Although current nationwide electricity load that is lost to DER is only at one percent,[ii] as more smart technology is deployed, and as other DER become more cost competitive this market share will increase and utilities will have to raise their rates to compensate.[iii] In addition, as smart grids begin to realize their full functionality potential, this will also allow customers to tailor and reduce their consumption, further cutting into IOU revenue streams.

D. Net Metering

Net metering programs allow electricity customers to offset their electricity bills through supplying their consumption via small on-site distributed sources and selling excess electricity back to their utility. Clean energy advocates champion netmetering policies for their promotion of distributed generation technologies, contributions toward state renewable portfolio standards (RPS), reductions of greenhouse gas emissions, and facilitation of in-state job creation and economic development.

Currently, 44 states and the District of Columbia have net metering laws. The following states do not have official net metering laws (although some individual utilities have their own net metering policies): Alabama, Idaho, Mississippi, South Dakota, Tennessee, and Texas. These laws are praised by renewable energy advocates (especially solar PV proponents) for increasing distributed generation (DG) deployment and empowering consumers. Although DG only currently displaces about one percent of total U.S. electricity load, this market share is increasing quickly. Indeed, 99% of U.S. solar PV installations in 2012 were net metered, representing 1.5 GW of capacity added to the grid.

Net Metering laws pose an impediment to the traditional utility revenue stream. Under this model, every kilowatt that a customer generates and consumes, is one less kilowatt that the utility sells—and profits from. In an effort to preserve their business model, many utilities have been pushing back on net metering laws by encouraging state legislatures to restrict the capacity of net-metered facilities or allow for increased “convenience” charges on net metering customers.

E. The Microgrid

The term “Microgrid” has been defined differently over the years. One of the most cited definitions comes from the DOE’s Microgrid Exchange Group (MEG). According to the MEG, a microgrid consists of “[i]nterconnected loads and distributed energy resources within clearly defined electrical boundaries that act as a single controllable entity… A microgrid can connect and disconnect from the grid to enable it to operate in both grid-connected or island mode.”[i] Microgrids present tremendous opportunities for DER and DSM integration, and they also pose a competitive threat to the utility business model. Microgrids are already commonplace in many developing countries such as in Haiti, Africa, and Brazil, where some communities are isolated from larger transmission systems. In addition, islands have made use of microgrid technology, for instance, El Hierro, a Spanish Canary Island off the coast of Africa, runs completely on a microgrid connected to various wind, solar, and pumped hydro storage resources. The Portuguese island of Graciosa is expected to generate 65% of its load through a renewables-power microgrid by the end of 2013. One research and consulting firm, Navigant Research, has identified over four hundred projects in development worldwide, and projects that microgrid investments will increase from $10 billion annually in 2013 to $40 billion by 2020.

1. Microgrids in the United States

Microgrid development is taking off in the United States as well. The CEO of Horizon Energy, a micogrid development company, recently told Fortnightly magazine that the company sees nearly 24,000 potential microgrid sites across the U.S., 300 of which could be completed by 2015. Several microgrids are complete or under development in the United States. Among some of the first and consistent microgrid developers were universities like: University of California-San Diego (42 MW generation capacity), New York University at Washington Square (13.4 MW), Utica College (3.6 MW), and Cornell University, which spent $60 million to construct a 37 MW system.  The Illinois Institute of Technology is currently considering a $12 million microgrid system (i.e. a series of microgrids looped together for greater reliability).

Some federal agencies have also entered the microgrid market. The Food and Drug Administration’s White Oak research facility in Maryland recently finished a $71 million microgrid project.[vi] Just this year, the Department of Defense (DOD) completed a substantial grid-interconnected microgrid in its Fort Bliss army post in Texas, one in a series of microgrid development projects that started with its flagship 17 MW project at the National Interagency Biodefense Campus at Fort Detrick in Maryland. The DOD is fully embracing microgrid technology and recently joined forces with the Departments of Energy and Homeland Security to ensure that other military bases can function independently from the grid. The goal of the project, called SPIDERS (Smart Power Infrastructure Demonstration for Energy Reliability and Security), is to gradually implement microgrid technology through three, progressively complex, installations: first, Hickam Air Force Base, which was completed earlier this year, then Fort Carson in Colorado, then finally Camp Smith back in Hawaii.[viii]

As recently discussed here, Connecticut is the first state to promote microgrid policies. In June 2012 the Connecticut General Assembly created the microgrid pilot program in which $20 million was allocated to the state Department of Energy and Environmental Protection in order to develop and test dozens of small microgids, and bring some of them operational by the end of 2013. On Wednesday, July 24, 2013, state officials announced that nine microgrid projects were approved to receive a cumulative $18 million in funding. The projects chosen include certain universities, hospitals, a submarine base, as well as various discrete residential and commercial mixed-use communities. The microgrids will be designed to independently provide power to these critical facilities and town centers on a 24-7 basis, without needing to connect to the larger grid. Governor Malloy has allocated an additional $30 million over the course of the next two years to continue funding other microgrid projects throughout the state. Any additional costs for the microgrids will be borne by all ratepayers, and utilities will be allowed to recover any costs incurred for overall grid maintenance.[xi] Future funding solutions will likely be fettered out in the pilot process.

The only other states to have explored microgrid policies have been New York (which published a report on the current regulatory obstacles facing microgrid deployment in 2010), and California. Aside from the DOD project, Hawaii is also transitioning to microgrids and local generation in order to cut down on oil imports. In April 2013, a water-pumping and wind energy generating turbine finished construction on North Kohala. The developer, Gen-X Energy Development LLC, announced that it plans to replicate the project in other Hawaiian communities.

2. Challenges for Microgrid Implementation going forward

Microgrid developers are watching Connecticut’s experiment closely. Once technological hurdles are overcome, then regulators will have to grapple with some of the nitty-gritty regulatory issues involved with microgrid implementation, such as:

  • Funding: as utility customers reduce grid usage or leave entirely, how to ensure that remaining utility customers are not left paying for increased stranded operation and maintenance costs, which could drive more consumers away.
  • Ownership: whether efficiency and reliability require that microgrid resources be owned by the utility or by independent third parties.[iv]
  • Utility franchise laws: how independent third parties can access and/or operate the microgrid without intruding on state-granted utility franchises.[v]

For additional information on the current state of the IOU business and regulatory model, and the challenges facing these utilities, check out this GreenTechMedia podcast, as well as this report from the Center for American Progress. The second part of this two-part post will discuss how utilities are responding, and should respond, to remain solvent despite these growing market and technological changes.

Other (non-hyperlinked) resources:

[i] See, e.g., Peter Fox-Penner, Smart Power (2010), Chapter 6.

[ii] Edison Electric Institute, Disruptive Challenges: Financial Implications and Strategic Responses to a Changing Retail Electric Business 1 (Jan. 2013), available at

[iii] Id. at 17.

[iv] See, e.g., Margarett Jolly, et al., Capturing Distributed Benefits, Fortnightly Magazine (August 2012) (arguing that Utilities should be able to own DG infrastructure because it “would allow for efficient and timely deployment of strategically-sited DG that operates at high levels of reliability during system peaks.”).

[v] See Sara C. Bronin & Paul R. McCary, Peaceful Coexistence, Pub. Util. Fortnightly 39, 41 (March 2013),

All Eyes on Connecticut: Microgrid Pilot Program Gets Underway

UPDATE: a version of this article appeared on the WorldWatch Institute’s ReVolt Blog, and can be accessed here:

One of the more interesting and underreported stories in the energy industry today is Connecticut’s ambitious electricity system pilot project—one that could have a widespread ripple effect across the country. On Wednesday, July 24, government officials announced plans for nine microgrid projects, as part of the state’s Micgrogrid Pilot Program aimed at ensuring electricity grid resilience and reliability during severe weather events.

“Microgrids” are essentially small-scale electricity generation and distribution systems integrating various distributed energy resources (DER) that can be managed locally and completely independently from the main grid. Fossil-fuel generator microgrids are common in many developing countries such as Haiti, India, and Brazil, and some U.S. universities and military bases have also implemented their own systems in order to insulate their operations from main grid outages. However, the concept of connecting already-electrified communities with microgrids is being touted as a means to encourage more renewable distributed generation (DG), relieve congestion from the main grid, and increase reliability in the process. (not to mention, a way to ensure humanity’s survival during the zombie apocalypse).

Prompted by the protracted blackouts that crippled Connecticut and much of the east coast during hurricane Irene and other storms, state lawmakers charged the Department of Energy and Environmental Protection (DEEP) with implementing a microgrid pilot program. The momentum behind this endeavor only strengthened after hurricane Sandy swept across the region. Late last year, DEEP opened up the application process and nearly three dozen Connecticut cities, towns, universities, hospitals, and companies applied to participate in the $18 million Microgrid Pilot Program. Once complete, renewable, fuel-cell, and fossil-fuel power will be delivered to the project areas on a 24/7 basis, without being integrated into the larger grid.

The nine applications that were ultimately selected represent a cross-section of the important resources that the state wants to safeguard during severe weather storms: police stations, supermarkets, university dormitories, city halls, senior centers, fire departments, gas stations, cell towers and shelters. Construction of the projects will be underway soon, with several coming to completion by the end of 2013. Governor Malloy has appropriated another $30 million for additional microgrid projects over the next two years.

A micro idea with macro potential for developers

The energy industry will be watching Connecticut’s progress closely because this pilot program could outline the path forward for the many potential microgrid sites around the country — nearly 24,000 in the estimation of one microgrid development company. Ideally, these grids would not all just operate small cogeneration plants (CHP), but would instead harness the best in renewable energy technology, advanced metering infrastructure, and electricity storage to form an independent and self-healing system. They could be grid-connected to provide more generation capacity and stability, and also “islandable” at a moment’s notice if severe weather or some other emergency require transmission operators to shed load from the main grid.

Waiting in the wings are big developers like General Electric, ABB, Siemens, SAIC, Schneider Electric, Boeing, Honeywell and Lockheed, along with boutique technology firms such as Spirae, Integral Analytics and Power Analytics (formerly EDSA). Many of these companies have already gotten a big boost from the Department of Defense’s massive multi-state investment in microgrid projects, as well as from several university microgrid endeavors. If the Connecticut project proves successful and lawmakers look for other microgrid opportunities, these companies stand to profit handsomely. Indeed, some analysts already forecast that the global microgrid market could be valued as high as $40 billion by 2020.

A micro idea presenting macro challenges for utilities

Despite all the buzz and momentum behind microgrids, one major industry group—investor-owned utilities (IOUs)—has not yet decided whether to embrace or shun this new technology. Microgrids present a dual challenge to these utilities. First, IOUs prefer to invest in tried-and-true technology because they are tasked with keeping the lights on and the system reliable. Second, IOUs stand to lose “market share” with every kilowatt generated by a customer or saved through an energy efficiency program. Under the traditional regulatory model, IOU revenue is determined by a PUC-approved calculation that amortizes the cost of utility assets and a reasonable rate of return across all the utility’s ratepayers over a period of years—a regulatory model that rewards large capital investments and increasing energy consumption.

Microgrids strike to the heart of this business model by presenting customers with the real option of one day being able to exit the utility’s service area entirely. If IOUs compensate for this lost revenue by raising rates on remaining customers, that could perpetuate yet more departures and eventually trigger a “cascading natural deregulation” of the whole utility industry.

Perhaps seeing the writing on the wall, some utilities have begun engaging with microgrid and smart grid technology. Thanks to a $10 million grant from the Department of Energy and the California Energy Commission, San Diego Gas & Electric (SDG&E) recently completed a complex project in Borrego Springs, California that integrates many microgrid elements including smart meters, distributed generation, and storage. A few other utilities, including some municipal utilities like Austin Energy and SMUD, are also moving forward with smart grid and microgrid-like projects. Although a step in the right direction, it remains to be seen how these projects will surmount the traditional IOU “business as usual” regulatory model.

It is difficult to say what the role of utilities will be as microgrids advance, especially after Connecticut’s pilot program. Many commentators have argued that the rise of distributed generation and demand-side management is driving the old utility model into extinction. In order to survive, utilities will have to make room for a more active and dynamic customer, one that expects advanced pricing and demand-response mechanisms along with other consumer-oriented services. Nonetheless, IOUs are arguing that—as the owners of nearly 66% of the country’s transmission and distribution system—the low-carbon economy of the future will have to make room for them too.