Big Money Is Getting Into Microgrids

The Carlyle Group will put hundreds of millions of dollars toward owning and operating microgrids, tackling the industry’s financing challenges.

Can big money help standardize microgrid development?






Can big money help standardize microgrid development?

Most companies have a hard time coming up with the upfront cash to build a microgrid, and financing one can be a major headache.

Theoretically, that headache would go away if an entity with functionally unlimited capital bought the project and operated it on behalf of the customer in exchange for service payments.

The Carlyle Group, the Washington, D.C.-based private equity behemoth, set up a business unit last fall to do just that. Dynamic Energy Networks (DEN) will deploy Carlyle capital to create microgrids, then operate them in an energy-as-a-service model for long-term contracts.

This model has been deployed in a few instances already; it eliminates upfront capital requirements and caters to customers that want cleaner or more reliable power but don’t want to be in the energy asset management business.

But up until now, nobody has funded the model at this scale. Carlyle has set aside an initial pot of $500 million, but DEN President and CEO Karen Morgan said at DistribuTech Wednesday, “There is no cap on that.”

This entrance is a big deal in the hardscrabble world of microgrid development. Large corporate and municipal customers want the resilience and environmental benefits that microgrids can provide, but nobody’s cracked the code on how to make it cost-effective at scale.

No one with this much money has given it a serious try. Carlyle’s interest may prompt other private equity firms to consider microgrids as an investment vehicle.

DEN approaches its work more like an equity investor than an energy services company. That gives it a high degree of flexibility in shaping its deals compared to, say, a utility. DEN plans to focus on new builds, primarily behind the meter, but it can buy existing assets or renovate them if a good opportunity arises.

A key hurdle to the fledgling microgrid industry has been lack of repeatability, which drives up costs. The scale of funding here opens up the possibility of enterprise-wide microgrid contracts and other forms of big thinking. Indeed, the leadership won’t be interested in small one-offs, a category that describes nearly every microgrid built so far.

“A lot of assets have been sold at the facility level; this is really a C-suite solution,” said Morgan, who previously led Renewable Energy Trust Capital, which owned utility-scale wind and solar.

C-suites might be easier to access when the firms involved share the same parent company. Carlyle owns some 270 portfolio companies and manages $40 billion of real assets including energy, infrastructure and real estate. DEN could easily keep itself busy catering to that market.

“It is a clear differentiated advantage, and it’s something that we’re leveraging significantly,” Morgan said of the relationship with Carlyle.

The group hasn’t announced any projects yet, but several are in the works.

Once they get finalized, DEN won’t be the developer, but it will have input, Morgan said. DEN will work with a handful of best-in-class EPCs to build projects, and has a partnership with Schneider Electric for microgrid controls. That firm was an early pioneer of the microgrid-as-service model in its work with Duke Energy.

If all goes according to plan, DEN would resemble an independent power producer, getting paid for electrons flowing from its fleet of generators, which happen to be located inside microgrids.

That platform will be worth $3 billion to $5 billion in the next three to five years, Morgan said.

“The complexity around microgrids and energy infrastructure, particularly behind the meter, is what is very compelling to us, because there’s a lot of value that’s created in delivering those integrated solutions,” she said. “That’s where we can capture more value: We’re efficient in how we execute, from a capital perspective as well as technology and partnering perspective.”

Extracting profit from microgrids has proven notoriously difficult so far. Perhaps the early entrants just weren’t thinking big enough. It’s a lot easier to play the long game when you have a few hundred million dollars to spend.

Originally Published on Greentech Media

Energy As A Service: An interview with CEO Karen Morgan

Energy As A Service: An interview with Karen Morgan from Dynamic Energy Networks

Dynamic Energy Networks (DEN) launched in order to provide customers and investors with an opportunity to tap into the hyper growth “Energy-as- a-Service” market. It is an energy infrastructure platform that owns and operates microgrids to provide energy to the commercial and industrial, municipality, healthcare, university campuses and the military sectors. 

Energy As A Service: An interview with Karen Morgan from Dynamic Energy Networks

The company formed a strategic alliance with Schneider Electric and The Carlyle Group and has a top executive team which formerly worked with Hitachi and RET Capital. It develops holistic and flexible solutions to deliver predictable, reliable, secure and resilient energy solutions which can run in parallel or completely independent of the utility grid.

REM spoke to Karen Morgan, DEN President & CEO to find out more about the company and its plans for transformation of the energy market.

Can you tell me about DEN and what it does?

Dynamic Energy Networks is a global energy infrastructure platform. We own, operate and manage energy infrastructure in key market sectors, such as the commercial and industrial, municipality, healthcare, university campus and military sectors.

What is the Energy as a Service market?

Energy as a Service redefines the relationship between users and sources of energy. It shifts the cost and the risk to DEN, as a third-party owner, and enables optionality or choice of energy source.

For example, let’s say a hospital has a combined heat and power (CHP) plant and would benefit from adding solar and storage. DEN could acquire the existing CHP plant and integrate solar and storage to create a microgrid solution at no cost and no risk to the hospital. This allows the hospital to redirect their capital and resources internally, and shifts a capital expenditure to an operational expenditure. These bespoke solutions could be in the form of a long-term power purchase or concession agreement.

Can you tell me more about the microgrids you intend to provide?

We provide something much broader than microgrids; we provide energy infrastructure. Energy infrastructure is the integration of critical technology components and, in the case of microgrids, it might include a base load, such as combined heat and power (CHP) plus solar and storage. It could also include other energy resources, such as energy efficiency and smart technology solutions that interact with the microgrid. We design and optimize our microgrids and infrastructure using best-in-class partners and solutions that are most appropriate for the facility, geography and needs of the customer.

Our microgrid designs ensure resilience of a facility in cases where the traditional utility grid fails. For example, we design solutions to ensure business continuity and lifesaving critical infrastructure for hospitals and disaster relief centers. DEN’s infrastructure can operate completely independent of the utility, that is, in ‘island mode’ or in parallel with the grid.

I notice that you quite often work with the military, what extent is the military trying to decarbonise now?

Both Carlyle and Schneider Electric have a long history with the military. We see a very strong commitment from the military to decarbonize and be good citizens in their own geography. One of the major offerings to the military, though, is resilience. Microgrids and distributed energy resources enable independent power on site to the military base and to the local community in the event of a utility outage. Resilience, secure and reliable energy is paramount to military operations and microgrids are the solution.

What advantages does your solutions have over what other companies are doing?

I think what we’re really trying to do is play a major role in the transformation of the energy market. Our Energy-as- a-Service model is a differentiated value proposition today, where we take the risk out of the equation and deliver predictable, efficient, secure and resilient energy to our customers. We’re moving from a static utility market to a very dynamic and interoperable marketplace where this integration of flexible capital and critical infrastructure will drive the transformation of the electricity markets. We refer to it as ‘Utility 2.0’.essential, for this market to mature, that we get these cornerstone players investing in the transformation.

How do you expect to grow over the next few years or so?

Our growth will be based on our ability to deliver bespoke and modular solutions to the markets we identified in a programmatic and repeatable fashion. The ability to scale will be predicated on working with best-in-class engineering firms, developers and others, in addition to our anchor partners, Carlyle and Schneider Electric.

Originally Published on Renewable Energy Magazine


Solving the Right Problem

Steve Pullins, Vice President, Energy Solutions

This not a short read because real problems are not understood and fixed in an elevator speech or executive summary. So, if you want some reality, please read on. If you’re looking for the elevator speech, no need to read beyond the first two sentences.

Solving the Right Problem

Engineers learn early to first understand what the problem is before setting out to solve it. In the grid industry, the majority of effort spent on reliability is focused on the wrong problem.

A Spring 2016 EnergyBiz article, “Spare Transformers: The Answer to Extreme Weather Risks?,” quoting a 2015 study by Lawrence Berkeley National Laboratory and Stanford University, said there is a 260% increase in storm outage duration to 370 minutes per customer over the last decade. The report provided several examples of greatly extended outages in distribution, as well as efforts in states for grid modernization. But, the industry is still focused on transmission lines, reserve capacity at the central generation level, and spare power transformers through FERC rules.

Okay – the wrong problem. The transmission and generation (bulk power) system only contributes 10% of the events that lead to customer outages, so massive investment in improving reliability at the bulk power system can only have minimal effect on the reliability felt by customers. It would seem more helpful to attack the 90% problem – distribution system reliability.

There is a difference between how reliability is viewed, and how metrics are structured, at the bulk power system level and the distribution level.

The bulk power system uses grid architecture-based metrics to judge reliability, such as redundancy, reserve margins, N-1 contingencies. However, these architectural metrics do not demonstrate reliable performance, from the customer’s perspective.

At the distribution level, reliability is measured as a performance-based metric. Okay, better. However, the industry uses a reliability metric standard (IEEE 1366) that specifically excludes the largest (and most rapidly growing) cause of customer outages; storms and other Acts of God. Figure 1 suggests the industry pay more attention to the impact of major storms on customers.

For more than 15 years, the industry has said that storms are not the utility’s fault, and that is true. However, the source of the cause of the grid outage is far less important to the customer than the fact that the customer is without power, losing business, damaging product, or failing to deliver important life functions.

The point is, that from the customer perspective, at the time the grid is most needed, in the face of storms, it is not required to operate. This is not reliability, nor is it resilience. The industry metrics do not even measure this most critical element of reliability and resilience.

Storms are nasty. Just ask Mississippi Power about Hurricane Katrina, which damaged all but 3 of their transmission lines and 65% of their distribution infrastructure. All of this damage greatly affected the customers of Mississippi Power, but none of this damage counted as a reliability performance metric.

That same LBNL and Stanford study mentioned above puts the business loss price tag of storm outages in the US at $18B to $33B/year felt by commercial and industrial businesses. Studies at LBNL and EPRI for the last 17 years show the business loss price tag for commercial and industrial businesses for grid reliability (non-storm) at $79B+.

This says that storm-related grid outage impacts on business is significant enough, and growing, to become part of the grid reliability discussion. So, would changing the basis of how reliability is measured help the customer see improved reliability? Yes, but is the cost too great for customers to shoulder the burden?

What Performance We Track Today

The following Figures 2 and 3 from a Heidemarie C. Caswell article in T&D World Magazine, November 2012, show trends in distribution system reliability from the IEEE Distribution Reliability Working Group. The trend in non-storm outage durations is up slightly, and this would suggest that customers are being delivered a reliable grid service at 99.97% uptime.

A 99.97% uptime means grid services available for 99.97% of the hours in a year.) A SAIDI of 170 min/yr/customer is an uptime of 99.97%.

This is an A+ in school. This is fine for most residential applications, but today’s commercial and industrial customers have a growing digital footprint in their processes, point of sales, and overall operations. They require more reliability for business continuity.

However, reviewing where the Quartiles reside in the nation (Figure 3), shows that the Northeast and Mid-Atlantic states constitute nearly all of the 4th Quartile performance on reliability, and this does not include storms, which also affect the Northeast and Mid-Atlantic states heavily.

As utilities and regulators move to decouple the relationship between how much energy a utility produces and delivers, from the rates and fees it charges to customers, the belief is that utility distribution system investments can be maintained or increased in the face of flat or declining customer energy consumption. On the surface this sounds prudent. But the reality does not seem to bare this out.

It seems that the unintended consequence is (1) deterring innovative solutions, and (2) higher rates for customers, even those who conserve more energy. Left unchecked, the results can be unfathomable. One industrial customer in Connecticut, with flat consumption, saw their energy bill increase over the last 14 years from $450,000/month to $1,100,000/month, but their energy consumption portion of that bill only grew from $300,000/month to $350,000/month over the same 14-year period. The non-consumption portion of their bill grew from $150,000/month to $750,000/month, unchecked. At the same time, this customer saw a decrease in reliability and resilience of their electric service.

The industry needs to change two assumptions; (1) the only solution is more of the same, and (2) the customer will pay for all of it.

To reinforce the point about customer impact from storms, one utility in the Northeast reported to their regulator that their 2012 non-storm SAIDI was typical for the Northeast. They also stated that it represented 26% percent of the total (storm related and non-storm related) outage numbers. This means that 74% of all outages were storm-related outages, three times the non-storm outage numbers. Granted this included Superstorm Sandy; but it makes the point that storm-related outages are important for the industry to incorporate into its thinking and metrics about reliability and resilience. More of the same will not change this. Neither will making the customer pay for it (all).

A Proper Solution Will Take Time

Even if you believe that utilities and regulators are starting to understand the problem and taking actions to address it, which many are; based on historical evidence of significant change in the electric industry, it will take 10 to 15 years to see a broad measurable improvement.

Commercial and industrial customers then must determine if they can wait for this improvement, or seek another course. All too often, one of the options chosen is to move the business to lower energy cost regions or countries.

Is there another way to achieve significantly better reliability performance for the customer?

There is an answer. Not in all cases, but in many communities and campuses (commercial, industrial, university, hospital, etc.) a Microgrid solution can deliver concurrent reliability, resilience, and cost savings (and/or containment) improvements.

There are more options today for the energy service for customers. It would seem prudent that distribution utilities see Microgrids and distributed energy resource (DER) solutions as additional tools in its toolbox to better serve customers.

Microgrid Vision

Steve Pullins, Vice President, Energy Solutions

With the waning performance of the electric grid from a reliability and economics perspective, many consumers have become prosumers, taking more control of their own energy environment. This trend will continue, and possibly accelerate, as the millennials take more and more leadership in companies and agencies in the coming years. As we consider the robust trends in the energy industry, microgrids show promise as an effective tool for consumers and utilities to address many of the reliability, resiliency, environmental, and economic needs on campuses and in communities.

Like many industries, electric and gas industries will become more and more dis-intermediated by distributed solutions and market forces. The shift from landlines to mobile phones, the democratization of travel, and growth of required social options all suggest similar long-term trends will persist in energy. New rules, driven by consumers, are chipping away at the 75-year history of major utility monopolies, and recent efforts in New York, Connecticut, California, Hawaii, and Massachusetts are putting the power of choice in the hands of energy consumers. These drivers are changing the energy market.

The expansive enablement of new technologies are opening doors to these changes in the industry, but it is clear that we have only a glimpse of how technology will enable future changes in the energy industry. Change begets change.

Thus, with waning performance, changes in rules growing out of consumer influence, and new technology enablement, the industry trends are demonstrating a radically different future in energy. The trends suggest that the average distance between generation of electricity and consumption of electricity is moving from tens of miles to tens of feet. The trends are showing the consumers will no longer rely on utilities for reliability and resiliency of service. The trends are showing that younger consumers, as they take on more leadership in society, will drive a much greater emphasis on sustainability and clean energy, even at greater cost. The trends are showing the importance of local energy markets at the city / community level (transactive distribution networks). These trends are suggesting that by 2050 90% of the energy will be produced at the consumer and distribution level and consumed within a mile. The remaining 10% role of the bulk power system will return to its original role (1930’s) of getting geographically constrained renewables to urban / suburban areas.

Microgrids present a new breed of complex solution in this changing space. They offer an optimized portfolio of resources (self-determination) that support cleaner energy supply. They offer a data-rich environment (local big data) where trend and signature analysis are important attributes in driving economics, reliability, and emissions reduction. They offer the flexibility to share energy across neighborhoods (markets) opening the door to shared savings. Microgrids also offer local solutions that “close the loops” on clean water, improved healthcare, retention of local culture, and fostering small businesses in developing nations, who are all challenged by access to affordable, reliable energy.

So, to meet the needs of consumers as the industry progresses to a vastly distributed 2050, much technical, policy, market, and educational change is required to facilitate, even follow, the change driven by new consumer realities. Microgrids are changing the vision of what is possible.

Originally published on LinkedIn

The Curious Thing About a Community Microgrid…

Steve Pullins, Vice President, Energy Solutions

Communities have a lot of stakeholders, but often with common goals. Communities want to be safe, stable, prosperous, and neighborly. In recent years, we have added “sustainable” to those common goals for many communities. Now, that may mean different things to different stakeholders, but generally it means that the community wants to exist 100 years from now with many or all of those same common goals.

If one were to “create” a community with many stakeholders and common goals from scratch, the process would probably be messy. The complexity of gaining consensus on community goals requires diligence and patience.

The same is true for building an energy microgrid for community resilience. Here, I am using resilience as a first cousin to sustainable. Resilience in a community can mean different stakeholder objectives. Some may want life-sustaining services (pharmacy, oxygen, food) to be resilient for vulnerable neighbors in the face of major storms. Some may want critical public safety and health services to be resilient for the entire community in the face of downed power lines and debris-filled streets. Some may want important job-centered businesses to be resilient in the face of emergencies so that income in the community is minimally impacted.

To incorporate a diverse set of important community goals (i.e., “messy”), the microgrid will likely be messy as well. Messy means multiple distributed energy resources vice a single energy resource because a single resource can leave a community vulnerable to loss. Messy means distributing the energy resources across critical facilities because the community needs those services even on loss of the local neighborhood distribution grid. Messy means burying critical sections of the local neighborhood distribution grid because overhead lines are vulnerable to storms. Messy means actively managing all distributed energy resources and load interfaces with real-time controls, load forecasting, and resource dispatch scheduling.

So, for communities with multiple goals around resiliency and sustainability, we probably need to serve them with complex microgrids. Messy.

This is complex, but doable.

Originally published on LinkedIn

Is Your Microgrid Flexible?

Steve Pullins, Vice President, Energy Solutions

There are a lot of definitions of a microgrid floating in the industry, but we’re not too worried about a definition. We are more interested in its characteristics.

Is your microgrid flexible?

Does it handle multiple modes of operation? Does it operate under a variety of use cases? Does it provide multiple functions to the customer? Can your microgrid serve the host customer with electricity as well as heating and cooling? Can your microgrid serve not only the customer, but also work with the local distribution grid when needed to benefit the greater community? Can your microgrid adjust operations to improve economics, reliability, resiliency, or emissions?

If the character of your onsite generation is singular in function, then it doesn’t follow that it is a microgrid, because it doesn’t demonstrate the character of a microgrid.

If the character of your onsite generation is that it shuts down when the local distribution grid is lost, then it doesn’t meet the character test of a microgrid.

If the character of your onsite generation is that it operates solely (whether continuous or in emergency) for reliable operations, then it doesn’t meet the character test of a microgrid.

It could be that your onsite generation is just that…onsite generation. And, there is nothing wrong with that. But, if it doesn’t have the character trait of flexibility, then it is probably not a microgrid.

We often link the flexible character of a microgrid with the use cases it serves for the customer. There is a huge difference between serving one use case and two. Now consider that most microgrids (the flexible ones) are serving upwards of 7 or 8 use cases.

Instead of debating definition for a couple years, it might be a good idea to determine the key characteristics of a microgrid, like we did with the Principal Characteristics of a Smart Grid 10 years ago. That helped shape the direction of the Smart Grid movement, investments, and deployments. Plus, we didn’t take three years debating the definition of a Smart Grid before we set a course of action for the future.

I’m just sayin’…

Originally published on LinkedIn