Wind energy in China has been expanding at an incredible rate, and the Chinese government hopes to speed up this deployment in the future.  Currently, China has approximately 62.4 gigawatts (GW) of wind energy installed, mostly in the remote northern and western regions of the country.  Transmission infrastructure, however, has not kept pace; up to 20% of the power generated is wasted because the wind farms are not connected to the grid.

Microgrids could be the solution, or at least an interim step, to integrating this burgeoning generation capacity.  By definition, microgrids incorporate distributed generation resources and have the ability to isolate, or “island,” themselves from the greater electric grid.  Deploying microgrids near the sites of non-grid connected wind power would have three main benefits:

First, microgrids utilizing the wind generation would provide the surrounding communities with a more reliable source of electricity.

Second, since microgrids have their own generation resources, they draw less power from the electric grid than regular loads.  This means that capital investments in transmission infrastructure would be reduced, since less power would need to flow into the microgrid, and already strained utility budgets would be eased.  For example, a significant amount of wind capacity exists in Inner Mongolia, but the region has a relatively small load compared to the more urbanized parts of China.  The regional utility, Inner Mongolia Grid, lacks the funds to build sufficient transmission capacity to the rest of the country.  Using that power to create local microgrids would benefit both the region and the power producers.

The third benefit is more subtle.  Microgrids enabled with storage components (e.g., batteries, flywheels, and so on) can be used to smooth out the intermittent nature of wind power.  When wind power is greater than load in the microgrid, the electricity can be delivered to the national grid.  With storage components installed, electricity could be delivered in a smoother and more predictable pattern.  Not only would this cause less strain on the physical grid, but the stored power could also be used for peak shifting and load-leveling applications, if the storage capacity is large enough.

Along with the entire Asia Pacific region, China currently has a relatively small share of microgrid installations, only about 118 megawatts (MW), according to Pike Research’s Microgrid Deployment Tracker 4Q 2012.  Microgrid deployments are accelerating in Asia, though, and significant increases in wind power should reinforce that trend.

Microgrid Capacity by Region, World Markets: 4Q 2012

July 5 was another scorching hot day in the midwestern United States.  Although I can empathize with our central states – Washington, D.C. has been experiencing temperatures over 100 degrees for several weeks, typical for this time of year – I suspect it’s more difficult to cope with weather that’s unseasonably warm.  Hot days like these provide insight into the resilience (or fragility) of a grid system.  Midwest ISO (MISO, the grid operator for several  Midwest states) provides a map of the Locational Marginal Pricing in its service territory.  In the afternoon of July 5, the map changed a great deal from hour to hour.

Around mid-day on Thursday, the map went red.  This indicates that the marginal price for a megawatt-hour (MWh) of energy is above $1,000.  Only an hour later, prices dropped significantly.  Some areas actually experienced a negative marginal price. The fact that the LMP was negative is not in itself remarkable; this happens whenever there is congestion on a node and MISO uses negative pricing to rein in a bottleneck.  Typical LMP prices range from $50 to $75 for 1 MWh during peak hours in the summer.  In this case, not only was the sharp increase in the marginal price alarming, but so was the volatilty on the system.  Grid operators work hard to avoid volatility in order to provide secure, reliable, and cost-effective energy via transparent markets.  In this case, the market came as close to failing as we are likely to see.

In order to cope with the tremendous imbalance on the system, MISO issued a maximum generation warning, instructing that from 2 p.m. to 8 p.m. Central time any extra generation capacity that had been withheld should be released.  This includes generation from nearby ISOs like PJM Interconnection and NY Independent System Operator, in addition to any additional generation on the MISO footprint.  Essentially, the grid operator was required to call on very expensive resources to meet the grid demands—at wildly inefficient prices.

Locational Marginal Pricing Map, July 5, 2012, 2:05 pm

Locational Marginal Pricing Map, July 5, 2012, 3:05 pm

There are obvious lessons here for energy storage providers.  For the right price, energy storage systems or energy storage services (in the vein of what AES Energy Storage provides) could serve very well as insurance policies against this sort of event.  It’s important to keep in mind, however, that these events are exceptional, not typical, and that MISO rescinded the maximum generation warning early.   MISO has not released any details on what caused the incident.

Alex Lauderbaugh contributed to this report.

Frequently, Europe is cited as one of the best markets for energy storage, especially bulk energy storage.  The key drivers for energy storage in Europe center on the region’s rapidly changing energy mix and its ambitious renewables targets.  It’s certainly true that Europe is integrating an impressive amount of renewables, especially intermittent renewables such as wind and solar PV.  Not only will this cause instability on the grid locally, but there will also be congestion issues to deal with as electricity travels along energy corridors in Europe.  This will tax infrastructure, creating significant opportunities for energy storage in Europe to help maximize transmission and distribution infrastructure.

However, the fact is that European officials have seen the writing on the wall, and companies and the EU are investing heavily in infrastructure that can cope with the intermittency and volatility of increased renewables on the grid.  Most of this funding will come via the European Network of Transmission System Operators for Electricity (ENTSO-E), an association of transmission and distribution operators that was formed in 2008.  As shown in the table below, some €104 billion ($130 billion) will be spent on pan-European transmission and interconnection projects over the next 10 years.  That investment in transmission and distribution will reduce the need for extensive storage installations, making Europe a less attractive market for energy storage than it might seem.

Investment Cost Breakdown for Pan-European Transmission Projects 2010-2020

(Source: ENTSO-E)

As a part of its unique cooperative approach to energy policy, the European Union has recognized that increases in demand, decommissioning nuclear power plants, and sharp increases in intermittent renewables will require additional investment in transmission infrastructure and greater interconnection throughout the continent.  Approximately 100 projects have been identified and nearly 52,000 kilometers of transmission will be built or refurbished.  The figures above do not include projects of national or regional importance, only projects that will affect greater Europe.  Significant national-level spending and upgrades are expected, for example, within Germany.  Spending levels by nation reflect population size and the need for renewables integration, although Ireland will be investing a great deal to shore up interconnections and will spend a disproportionately high amount over the next decade.

A Microsoft/OSIsoft survey released in early 2012 ranked renewables integration (43%) as the second most important reason for implementing a smart grid, behind smart metering (71%).

A forthcoming report for Pike Research will show how microgrids are leading the world today in terms of revenues derived from smart grid renewables integration, but recent market activity has intensified in regards to the concept of a Virtual Power Plant, a smart grid optimization platform that still faces skepticism.

The company that first introduced the term to the world, Siemens, is taking the concept of a VPP to the next level in terms of actual market commercialization.

Given that Germany is phasing out nuclear power, the 23 megawatt (MW) “Regenerative Combined Power Plant” (RCPP) experiment carried enormous implications.  A total of 36 wind, solar, biogas, CHP, and hydropower generators were operated as if a single power plant was supplying 24/7 power to the equivalent of 12,000 households.  Project leader Dr. Kurt Rohrig of Kassel University was awarded the German Climate Protection Prize 2009 for his work on this cutting-edge renewable supply management experiment.  While it generated the equivalent of only 1/10,000 of Germany’s total supply, this successful R&D venture has convinced academics and a partnership featuring Enercon GmbH (whose wind turbine provides a unique suite of grid services), SolarWorld AG (a major manufacturer), and Schmack Biogas AG that the entire country of Germany could be completely powered with a diverse blend of complementary renewable energy resources.

Doubters have pointed out that the RCPP project failed to account for grid congestion challenges that might frustrate this sort of VPP under real market conditions.  That’s why Siemens’ recent announcement to work with German utility RWE Deutschland AG (RWE) to fully commercialize this VPP model is so important.

Siemens’ VPP commercial offering is based on is its Decentralized Energy Management System (DEMS), which is designed to enhance both wholesale and distributed generation operations according to pre-defined economic, environmental, or energy-related priorities.  A variety of combinations of supply- and demand-side resources can be optimized, whether the generator is a large wind farm or an on-site biogas unit.  DEMS was first deployed at a small Austrian paper and pulp mill in 2003.

Siemens was one of the first private companies to explore the concept of VPPs, playing a key role in providing the management system for another pioneering effort in Germany.  Since October 2008, this project has aggregated the capacity of nine different hydroelectric plants ranging in size from 150 kW up to 1.1 MW, with a total VPP capacity of 8.6 MW.  The VPP framework opened up new power marketing channels for these facilities that would not have been viable if these distributed energy resources (DER) were still operating as standalone systems.

Operated by RWE from a centralized control room based in Dortmund, the Siemens/RWE project will grow to 20 MW this year by adding combined heat & power (CHP) units and emergency back-up power systems to the existing hydro portfolio.  It will be expanded to 200 MW by 2015 by further integrating biomass, biogas and wind resources into the network, making this an official commercial offering in Germany, where recent market changes have created fertile ground for VPPs.

Since February of this year, power from this VPP has been sold at the Energy Exchange (EEX) in Leipzig, Germany under new amendment terms of the Renewable Energy Sources Act. This is the first direct marketing of renewable power under this new program. Given the proposed reductions in Feed-In Tariff (FIT) rates, the EEX is being viewed as a key new innovation to help optimize growing renewable energy resources in Germany.