Navigant Research Blog

Solving Renewable Energy’s Integration Challenge

— February 2, 2012

Judging from industry hype, it might seem that the smart grid will solve virtually all of our problems relating to energy, transportation, and the economy moving forward.  Smart meters, distribution management automation, and other smart grid technologies will not only reduce both customer and utility costs and optimize the power grid akin to an Internet of Energy, but also is portrayed as vital to efforts to increase renewable energy production.

Last month, I attended the “Wind and Solar Integration Summit” in Scottsdale, Arizona, as a starting point for my research on a forthcoming Pike Research report.  There was plenty of discussion about wind and solar forecasting, different types of energy storage, and the different challenges that face regional grid operations across the United States.  Interestingly, I rarely heard the term “smart grid.”

Part of that, no doubt, is because the focus of efforts to date on integrating variable wind and solar power has been at the wholesale, transmission level of grid service, instead of at the distribution level, where smart grids, microgrids and virtual power plants are absolutely vital for integration.  It’s at the wholesale level where the money is right now, integrating bulk renewable energy into so-called organized markets managed by entities known as independent system operators (ISOs).

The summit did provide some good data points, among them the fact that wind integration costs generally run from $3 to $12 per megawatt hour (MWh), which at today’s wind penetration levels adds up to $270 million to $1 billion in just the United States. Less data is available about solar integration costs since utility scale solar PV is a rather recent phenomenon, but one can assume roughly the same order of magnitude.

Iberdrola, the Spanish operator, has more than 3 gigawatts (GW) of wind power capacity in current operation in the Pacific Northwest.  The company is among the leaders in investigating how better forecasting can reduce integration costs.  According to the company, so-called “day ahead” forecasts are already about as accurate as they can get, with error rates ranging from zero to as high as 18% for Iberdrola in the Bonneville Power Administration’s (BPA) grid control area spanning Washington, Oregon, Idaho and Montana.  (The equivalent forecasting error rate for day ahead forecasts in Europe is closer to just 5%, reflecting, perhaps, a more mature technology/policy integration.)

Better Forecasts

The real challenge for wind and solar forecasting is in the “hour ahead” and “intra-hour” data.  Within this forecasting envelope, error rates can exceed 30% for wind power.  The shorter the scheduling interval – e.g., every five minutes, as is the case in Texas – the more accurate the forecast.  (This is one reason why BPA has struggled in the past is that it used to only schedule wind hourly, and even today schedules wind power every 30 to 60 minutes).

Which variable renewable energy technology offers the greatest integration challenge?  While wind power is less predictable than solar power, the output from the utility scale solar PV project can ramp down instantaneously with cloud cover.  In contrast, wind turbine ramps tend to be more gradual due to spinning machinery.

Beyond forecasting, the most heated discussions at the Summit pertained to energy storage.  It became clear that the perception that energy storage was too expensive may not always be true.  Energy storage is not a monolithic resource, but rather an emerging grouping of technologies that can offer long-term and short-term solutions for variable renewable resources.  The cost of a flywheel providing frequency regulation is a completely different animal than a compressed air storage unit offering long-term energy storage.  The storage firm A123, working with AES Storage, has bragging rights to a 32MW storage project offering frequency regulation services in the Pennsylvania-New Jersey-Maryland (PJM) grid control area today, as well as a 12MW spinning reserve service project in Chile, South America.

The most provocative take away from the Scottsdale conference was a recently released study by Alstom Grid that surveys the world about solutions to the challenges of wind integration.  This report actually does reference the smart grid, highlighting the role of demand response, dynamic line ratings and transformer load management as keys to moving forward with planned wind project integration throughout the globe.

The truth of the matter is that the integration of renewables is not a reliability issue, as these resources are being integrated around the world without a smart grid.  It’s really all a matter of costs to ratepayers.  The far larger challenge is at the distribution level, which is where microgrids and virtual power plants come in.  I’ll have more on that topic in a future blog post.


Wind Power Industry Faces Solar-Like Challenges in 2012

— January 27, 2012

The recent announcement by Vestas, the largest manufacturer of utility-scale wind turbines in the world, about a major shake-up at the management level and the loss of 2,300 jobs in Denmark, raises the question of whether wind – like solar photovoltaics (PV) in 2011 – may be entering a major shakeout and downsizing period.

While the growth of wind power is still an astounding success story, there are clouds on the horizon, particularly in the United States. Among the major challenges facing the industry today are record low natural gas prices, which have lowered the price of electricity, making it more difficult for wind to compete in wholesale power markets.

A rush to develop new supplies from shale deposits through the controversial practice of so-called “fracking” raises interesting questions about how we regulate future energy supplies.  In Texas, it is possible to get a permit to drill for natural gas wells in a residential neighborhood within a week, without an environmental permit, and at a total cost of around $3,000. Contrast that streamlined approach – for a technology that has been implicated with polluting drinking water supplies and contributing to air quality concerns, as well as leading to possible lethal explosions – with wind (and solar) technologies.

Where I live, in Marin County just north of San Francisco, the county is imposing a height restriction of 40 feet for any wind turbine located in the western, rural part of the county, which, in effect, is an outright ban, even on small on-site wind turbines.  Why?  There’s just not enough wind at that height to generate power.  Furthermore, local activists successfully filed a suit against NextEra Energy to block the erection of a meteorological tower to measure wind resources for a possible wind project near the town of Tomales, in the northwestern corner of the county.  Since Marin County has set a goal of becoming completely powered by renewable energy over the long term through a community choice aggregation program, this reluctance may seem a tad ironic.

The good news (at least for the wind industry) is that the growing backlash against fracking, and the familiar boom and bust cycle in fossil fuel exploitation, may send prices for natural gas upward again within the next few years.  Innovations and global competition appear to be driving prices for wind and solar down, and that trend will likely continue. How much would natural gas cost if it had to undergo the same kind of environmental scrutiny as wind and solar projects?

Wind power will always face greater opposition than solar PV, though trends toward utility-scale solar PV projects have engendered intense debates over land use.  In this case, wind power may actually have fewer impacts, since turbines have small footprints and allow farmers and ranchers to continue their traditional way of life, whether grazing livestock or growing crops.  Solar arrays, on the other hand, blanket the entire landscape.

The other major challenge facing the wind industry is continued uncertainty around the extension of the production tax credit (PTC), the federal government’s prime vehicle for making wind more cost-competitive with traditional fossil fuel resources.  Vestas has announced it may trim another 1,600 employees here in the U.S. (mainly in Colorado) if the PTC is not passed. At a time of great economic uncertainty, it seems unwise to send mixed signals to the private sector about the U.S. commitment to clean energy.

Given the fracking/natural gas dynamic – and the poisoned political environment in Washington, DC in regards to government support for renewables, the “austerity and delays” scenario in the graph above may be the best current forecast for the future of wind power worldwide.


The Case for Net Metering

— January 23, 2012

It may not be as sexy as the oft-celebrated feed-in tariff (FIT), but net metering is the policy that’s driven U.S.  solar photovoltaics (PV) growth to date.  A simple billing arrangement that lets a customer’s electric meter spin backwards, net metering ensures that participating customers receive credit for electricity their systems generate during daytime hours, when they might not be home.  And now, in the largest of those markets – California – this workhorse of the solar policy world is under attack by the state’s investor-owned utilities (IOUs).   

While growing numbers of clean energy advocates   trot out some impressive statistics about the virtues of FITs, the fact of the matter is that net metering has been the prime driver behind solar PV and small wind installations in the U.S., with 43 states currently offering this policy to help consumers extract the greatest value from on-site power in which they have often invested their own hard earned capital.  In essence, net metering allows a customer to barter with their host utility with solar PV installed behind the customer retail meter.  To utilities, however, net metering is perceived as a threat, and they have been relying upon an outdated cost analysis as the reason-du-jour to lobby against continued customer access to net metering. 

A new study by the consulting firm Crossborder Energy of the alleged “cost shift” impacts of net metering on those customers in California who enjoy net metering with solar PV (and the vast majority of customers that do not have solar PV) sheds some important light on this topic.  Interestingly enough, the study focuses on the Pacific Gas & Electric (PG&E) service territory, since that is the region where past studies have indicated that 87% of the net cost shifts occurred.  Nevertheless, a recent radical restructuring of PG&E’s rates, which lowers the rates for highest demand customers, radically shrinks the perceived negative impacts of net metering on overall customers.  The end result?  The study shows a cost shift of $.00064 cents/kWh; in other words, virtually nothing.  Furthermore, the study confirms no significant cost shifts in other IOU service territories or for commercial customers.

The Three Solar States

To better understand the dynamics of net metering, the Crossborder Energy study breaks down three scenarios (or “states”) that a customer with on-site renewables enjoying net metering are in during different times of the day:

  • The “Retail Customer State.”  The sun is down and there is no PV production and all energy flows into the house from the utility grid.  The customer is a regular utility customer just like everybody else.
  • The “Energy Efficiency State.”  The sun is up and there is some PV production, but not enough to serve all instantaneous loads.  Here the customer is served both with power from the solar system as well as with power flowing in from the grid.  In this state, the renewable distributed energy generation (RDEG) serves as a means to reduce the customer’s load on the grid, in the same fashion as a more efficient air conditioner.
  • The “Power Export State.”  The sun is high overhead and PV production exceeds the customer’s instantaneous use.  In this state, the solar power flows into the house to serve the entire load, with the excess power flowing back out to the neighborhood grid.  These exports run the meter backward, providing the solar customer with compensation from the utility for these power exports in the form of bill credits that can be netted against the customer’s imports.  In essence, this is a bartering deal. 

It is this last “power export” state that is what makes customers smile, but utilities frown. 

Another overlooked benefit of net metering is that the output from RDEG reduces the IOU’s retail sales, because the solar customer serves its own load.  Since California utilities operate in a market where revenue is decoupled from sales, this drop can be viewed as a benefit to the utility since it reduces the utility’s own obligations under the state’s aggressive Renewable Portfolio Standard (RPS).  Given the challenges with siting and building transmission to large scale wind, geothermal and Concentrated Solar Power facilities for utilities such as San Diego Gas & Electric, this is an important point that many microgrid advocates such as General Microgrids have been making. 

Multiplier Effect

California boasts the most accommodating net metering policies in the United States for consumers, offering this bartering value proposition to virtually all forms of renewable energy.   Along with a new policy of paying behind-the-meter solar PV generators for excess generation beyond annual consumption, the state has also adopted virtual net metering for low-income multi-family residential buildings and complexes.  This program allows customers that might not otherwise be able to receive the benefits of on-site generation to join together to install a larger solar PV or other renewable energy system that can serve the group.   

To accommodate locations with multiple generation sources — but served through a single point of common coupling — California also allows net metering for what it calls “multiple tariff facilities.”  Under multiple facility net metering, billing credits are based on the proportional contribution of the energy production (in terms of kWh) of each net metering-eligible generator over the applicable billing period.  This is an important policy for facilitating RDEG aggregation platforms such as microgrids, in the sense that it allows for such aggregation platforms to utilize multiple forms of generation and/or fuel sources in the most cost-effective manner.

As reported previously, 2011 was a banner year for solar PV in California.  And the state ended the year on a high note, with a record amount of installations and reservations for behind-the-meter, rooftop systems – RDEG that has been stimulated, in part, by net metering.  To pull the plug on this option now would seem foolish, given the updated economics.


New Opportunities for Microgrids in 2012

— January 3, 2012

The global market for microgrids, and other forms of aggregation and optimization for distributed energy resources, made some major leaps forward during 2011. While not the commercial opportunity being hyped by some organizations such as the Galvin Electricity Initiative, this smart grid network platform is coming of age, especially in the U.S., due to two major developments.

The first was the adoption of standards for safe islanding by the Institute of Electrical Energy Engineers (IEEE) in July 2011, which should accelerate the shift from pilot validation projects to fully commercial microgrid ventures. Since 2009, a handful of large projects have come on line, especially in California – as platforms for aggregation of distributed renewable resources – and in New York, with combined heat and power (CHP) units as anchor technologies.

Second, a series of Federal Energy Regulatory Commission (FERC) orders – 719, 745, and 1000 – takes steps toward harmonizing innovation occurring independently at the wholesale and retail market levels. Demand response (DR) is seen as a stop-gap resource whose role will expand in markets characterized by volatility, high demand peaks, and lack of new transmission level generation capacity. Microgrids are now being viewed as the ultimately reliable DR resource, since islanding securely takes load off of the utility grid.

The recently updated Pike Research Microgrid Deployment Tracker 4Q 2011 identified over 100 more microgrids than previously highlighted, representing more than 300 megawatts of planned or operating additional capacity, primarily in the remote microgrid segment.

Pike Research’s new report, Remote Microgrids, highlights the fact that this remote sector represents the largest potential investment and revenue, a market currently valued at $3 billion and projected to grow to over $10 billion in the average scenario forecast by 2017. These figures reflect the fact that remote microgrids require the build-out of new renewable distributed energy generation facilities, whereas many of the grid-tied microgrids previously profiled by Pike Research only derive revenues from networking and optimization of existing generation assets.
Pike Research has also identified four sub-segments of the remote microgrid market, which is further commercialized than other segments, but heretofore sorely lacking in available data:

  • Village Power Systems: Perhaps the largest number of remote microgrids operating today would fall into this category, though data is extremely scarce due to the small scale of such projects and to the fact that most installations are located in Asia. According to leading purveyors of this remote microgrid sub-segment, the average village power system has a capacity of 10 kW. It typically provides power to a medical clinic, school, and/or community center in the center of the village.
  • Weak Grid Island Systems: To a purist, microgrids that have any linkage to a larger grid would not be considered “remote.” From the Pike Research perspective, these systems belong in the remote microgrid camp since the underlying assumption is to design and operate a power system as if the larger grid is not there. Weak grid island systems could represent an even bigger opportunity than the campus environment and military microgrid sectors that have been featured by Pike Research in previous microgrid segment reports.
  • Industrial Remote Mine Systems: This sub-segment of the remote microgrid market is the least mature, but also boasts the highest growth rates due to a groundswell of interest in shifting to more sustainable energy strategies for sites controlled by large multinationals. Globally, nearly 75% of existing mines are remote operations, though very few deploy renewable energy generation.
  • U.S. Mobile Military Microgrids: This last category of remote microgrids is the least developed, but has the most policy and financial support from the U.S. Department of Defense. At present, these systems are being deployed in pilot projects in combat missions at FOBs in Afghanistan and other remote DOD sites. They are included in this report because many mobile systems will likely become village power systems to serve humanitarian services once U.S. troops pull back from combat zones such as Afghanistan.

And while Africa and the rest of the developing world are ideal markets for remote microgrids, Comverge, the struggling demand response provider, ended 2011 with a bang when it announced a major deal with South African provider Eskom, one of the largest utilities on the continent. With DR technology now spreading more rapidly throughout the world, new synergies between microgrids, DR and virtual power plants will certainly emerge.


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