Navigant Research Blog

Data Centers and Military Microgrids: The Diesel Dilemma

— October 20, 2017

If something isn’t broken, why try to fix it? This kind of thinking sums up the perspective of many owners and operators of data centers. If they feel comfortable with the technology or solution that has been in place for quite some time, the incentive to enact something new and different is small. As a result, to maintain power for mission-critical loads, data centers have historically relied upon diesel generators linked to lead-acid batteries and (perhaps) dual feeds from two different utilities.

The Uptime Institute has created de facto data center industry standards that range from Tier I to Tier IV, with the latter representing the highest possible resilience. “Human beings have an almost emotional attachment to their diesel generators, as they give data center owners and operators both comfort and a form of insurance,” observed Chris Brown, CTO for the Uptime Institute. He does not see a decline in reliance upon diesel generators. According to Brown, “Engine generator usage will likely hang on, as the emotional tie and the form of insurance will still be present.”

Despite these insights, new data highlights how existing power infrastructure does carry risks for data centers. The average power outage cost for a data center in 2015 was $740,357—a 38% increase in the cost of downtime compared to 2010. Perhaps the most disturbing statistic found in Eaton’s Blackout Tracker Annual Report for 2016 is that the increase in maximum downtime costs rose to $2.4 million.

Military Base Parallels

One analogy to the challenge facing data centers is military bases in the United States. A typical large-scale military base may feature from 100 to 350 backup diesel generators, each hardwired to a single building. In many instances, they are sized at more than 200% of each building’s peak load as a contingency for energy security. Just a simple networking of existing diesel generators into a microgrid can offer cost savings for military microgrids and data centers alike.

A study by Pew Charitable Trusts found, for example, that creating a microgrid instead of relying upon standalone backup diesel generators reduces the cost of resilience by $1 billion or more. Note that the savings vary by region, with the greatest savings for those military microgrids deployed in the PJM Interconnection transmission control area. Yet, when displacing diesel backup generators with 50% diesel/natural gas fuel hybrid microgrid, California military bases boast the largest net savings. With a 50/50 portfolio of diesel/natural gas, microgrids in the PJM territory and the Southeast ironically show an increase in cost on a dollar-per-kilowatt basis if compared to the current reliance upon diesel backup generators. This is largely a result of low diesel fuel prices in those parts of the country, and it arguably points to the need to diversify power generation sources with a microgrid beyond fossil fuels.

Annual Net Cost of Protection ($/kW of Critical Load)

(Sources: Noblis, The Pew Charitable Trusts)

A new report by Navigant Research, Military Microgrids, notes that a key to innovation lies in new business models. The same could also be said for data centers. Data centers like to control their own destiny, which often means they want to own infrastructure. Yet, just like solar leases and third-party power purchase agreements accelerated the solar PV industry at a critical point in time in its development path, similar models could also bring microgrids into the mainstream.

Does such an approach hold promise for state-of-the-art data center microgrids? Schneider Electric would like to find out. Learn more at the upcoming webinar on October 24.


Plug-and-Play Microgrids, Here and Now

— September 22, 2016

Power Line Test EquipmentOne of the primary challenges facing the microgrid market today is the perception that each project is unique and therefore requires significant customized engineering. In fact, dozens of microgrids never seem to make it past the feasibility analysis phase due in part to this predicament.

While it is true that very few microgrids are exactly alike and therefore the idea of cookie-cutter configurations seems next to impossible, there are vendors now offering products and services that are moving the market much closer to a plug-and-play paradigm.

Case in point: Tecogen. The company manufactures the InVerde, a small natural gas engine often deployed as a modular 100 kW combined heat and power (CHP) unit that comes embedded with the Consortium for Electric Reliability Technology Solutions (CERTS) islanding software. String a few of these CHP units together (as the Sacramento Municipal Utility District has done) and presto—you now have a simple microgrid. The inverter that comes with the InVerde technology enables islanding and can support multiple generators on the same microgrid, each one acting autonomously to maintain power quality by responding to load changes, managing voltage sag, and regulating current.

Energy Ecosystem

Navigant Research does not consider a single InVerde unit a microgrid, since it is powering up a single building and is only 100 kW in size. We would instead categorize such systems as nanogrids. However, even multiple InVerde units are not considered microgrids by some entities, among them the New York State Smart Grid Consortium. Regardless of what one calls such systems, nanogrid, microgrid, or whatever else, they do represent part of a new Energy Cloud 2.0 distributed energy resources (DER) ecosystem.

The argument that Tecogen is not a microgrid market maker is being challenged by a new product offering, the InVerde e+, which allows for the integration of both energy storage and solar PV (or small wind) into a single controllable entity by virtue of direct current (DC) bus. With this recent upgrade, Tecogen’s claim to enabling truly plug-and-play microgrids seems quite valid—and even more compelling.

In the United States, CHP (and the ability to create thermal energy) is key to the economic value proposition for microgrids. In fact, the ideal resource mix for a microgrid in the United States today is CHP, solar PV, and a lithium ion battery. If sized strategically, this microgrid configuration can be cheaper than utility costs in California and much of the East Coast today.

Tecogen’s InVerde units boast an impressive list of features, among them emissions equivalent to that of a fuel cell, 33% electrical efficiency (and 81% total energy efficiency), and the lowest installation costs of any comparable technology in its class. The biggest surprise? The cost of microgrid controls—embedded in each CHP unit—is zero.

Marketplace Gains

Even before the recent new offering, Tecogen had made impressive gains in the marketplace. It ranked fourth in terms of total installed microgrid projects globally in the latest version of Navigant Research’s Microgrid Deployment Tracker. In last year’s Leaderboard report ranking microgrid developers/integrators that offered their own controls platform, the company ranked fifth.

Tecogen is not the only vendor moving the market toward plug-and-play and interoperability. Spirae and Blue Pillar have made important strides in this direction from an independent controls perspective. In addition, Duke Energy’s Coalition of the Willing is also moving forward to develop a common interoperability framework for microgrids, focused on so-called Open Field Message Bus (Open FMB) communication standards.


Nevada’s Net Metering Change May Present Opportunities for Storage

— April 15, 2016

GeneratorNevada’s public utilities commission (PUC) has changed the net metering rules for solar PV, effective January 1, 2016. Not only will this development erode the business case for new systems, but will also affect approximately 17,000 existing customers. SolarCity and Vivint have eliminated jobs in Nevada, and Sunrun has exited the solar PV market in the state. Two customers have filed a class-action lawsuit against utility NV Energy in protest of the decision. Although this rule change has been characterized as a bait-and-switch for solar PV customers, this is also an opportunity for residential energy storage under two scenarios.

The first scenario would be if residential energy storage with PV can be aggregated to deliver services to NV Energy. The aggregator—which could either be the utility itself or a third party—would share the payment with residential customers. In order to make the storage option appealing to customers that have invested heavily in solar PV, it would need to be offered using a low capital expenditures (CAPEX) business model. The value of the services delivered through the virtual power plant would need to at least cover the monthly grid connection charge and would also need to help the customer minimize the amount of solar PV energy exported to the grid and maximize self-consumption. The Nevada PUC could also opt to waive the grid connection fee for solar PV plus storage plants because distribution system issues would be mitigated by using a storage system.

Customer Disconnects

A second scenario that may present an opportunity for storage is if the storage can help customers disconnect completely from the grid. This would be a much more radical move for customers, but would help them avoid the grid connection charge. This charge starts at $12.75 to $17.90 per month in 2016 and is slated to increase to $38.51 per month by 2021. Although the yearly grid connection fee is relatively modest in 2016 at between $153 and $214, it is set to double to $462 within 5 years. Customers could spend over $1,500 over a 5-year period in grid connection charges alone. This solution’s business case would take many years to pay for both the battery and the solar PV. Therefore, this solution would also require some financing mechanism to ease the CAPEX burden on the homeowner in order to gain market traction. This scenario would be appealing to customers dissatisfied with the local utility, or who are looking to move off-grid for ideological reasons.

The chart below forecasts the power capacity and revenue of residential solar PV and energy storage systems—referred to by Navigant Research as nanogrids—as 40.8 GW and $79.5 billion from 2015 to 2024. North America is slated to account for 16.8% of the global market over the 10-year period. One of the key issues to tapping into this market will be creative customer offerings and go-to-market strategies on the part of vendors in this space.

Solar PV plus Energy Storage Residential Nanogrid Capacity and Revenue by Region,
World Markets: 2015-2024

Anissa Blog Chart

 (Source: Navigant Research)


Arctic Circle Is Hot Spot for Renewables Innovation

— March 2, 2016

GeneratorThe market opportunity for remote, off-grid power is immense, as verified in a report released late last year sizing this market (including projects that meet Navigant Research’s definitions of both nanogrids and microgrids). According to this analysis, the total value of the assets and services that could flow into this huge global market over the next 10 years could reach more than $200 billion.

As was reported in a previous blog, one could make the argument that Alaska, sitting within the Arctic Circle, is a global leader on remote microgrids, with almost 140 such systems representing over 900 MW of capacity identified in the most recent version of Navigant Research’s Microgrid Deployment Tracker. The vast majority of these remote microgrids incorporate some level of renewable energy. In fact, Kodiak Island reached nearly 100% renewable energy generation during 2014. Several local utilities have set goals ranging from 70%-80% renewable penetration within the next 5-7 years.

It turns out innovation on renewables and remote microgrids is not limited to Alaska. The Alaska Center for Energy and Power (ACEP) is co-leading a new program to be launched this summer for countries whose borders venture into the Arctic Circle. Dubbed the Arctic Remote Energy Network Academy (ARENA) program, this program is a formal project under the U.S. Chairmanship of the Arctic Council, with four of the eight council countries co-leading so far, including Canada, Finland, and Iceland, along with the United States (Alaska). This program is designed to bring together practitioners from throughout the Arctic to learn from one another with the goal of increasing the number of hybrid-renewable energy systems installed across the region. “ARENA is focused on the Arctic now, but we are hoping to expand it to other regions in the future, if we are able to find some partners,” said Gwen Holdmann, ACEP director.

Forefront of Climate Change

As a region, the eight countries representing the circumpolar Arctic are at the forefront of climate change, as measured and expected temperature increases are significantly higher than the national average. Impacts like diminishing sea ice and coastal erosion are becoming common challenges for these frigid and remote communities. However, the Arctic region is also leading the way when it comes to renewable energy development. ACEP estimates that 60% of grid-connected communities across the Arctic produce power from renewable resources (compared to a global average of 22%), including:

  • Finland (39%, biomass)
  • Sweden (48%, hydropower, biomass)
  • Norway (99%, hydropower)
  • Iceland (100%, geothermal, hydropower)

However, approximately half of the populations residing within the Arctic are not connected to a traditional power grid. Instead, they rely on remote microgrids to provide electric power services. This increases the complexity of integrating renewables, particularly at high penetration levels. These systems are among the most sophisticated engineering marvels in the world, providing energy services that are often a matter of life and death.

Countries throughout the Arctic are actively investing in renewable resource development. Perhaps the most fascinating data points come from Russia, a country not often linked with a focus on sustainability. The project pipeline in the country totals over 800 MW of remote microgrid capacity designed to displace pure diesel capacity with some renewables. Last year, a modest 15 MW of wind and solar capacity was brought online by RAO Energy Systems of the East, the state-owned utility that serves parts of Russia within the Arctic Circle. Those numbers are expected to scale up dramatically in the near future, with some 178 distinct projects in the works. At present, Russia also has the largest solar PV array located within the Arctic, a 1 MW system at Bagaday.


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