On June 25, we joined 500 executives at Stanford University for the 2010 Silicon Valley Energy Summit. The CEO of a large California utility company, Chris Johns of Pacific Gas and Electric (PG&E), was the first keynote speaker. His topic was PG&E’s effort to roll out 10 million smart meters. At an average rate of 15,000 installations each day, the devices are the first and most important pieces of PG&E’s smart grid infrastructure. All PG&E customers will have electric and gas smart meters by the end of 2012.
Johns noted near-term benefits familiar to most of us: no physical meter reading, faster identification of grid faults, and most importantly, lower peak power as residential customers are given the double-edged sword of time-of-use rates and “near-time” energy pricing data for the purpose of managing their power use more cost effectively.
But to those of us who are thinking about the future through the lens of solar power and other distributed generation (DG), PG&E’s venture into the emerging smart grid space could mean much more. Smart meters could become the communications and control gateway to two major areas of progress for the solar power industry:
1) An increase in solar power yield through better system monitoring and remote inverter repair.
2) The deployment of much higher photovoltaic (PV) penetrations than are currently allowed in power distribution networks.
Demand for accurate solar power system monitoring and remote repair has been increasing since the commercial solar market shifted to a Power Purchase Agreement (PPA) model in which PV system operators are paid for energy delivered. There is clear incentive to maximize generation and minimize downtime. Solar monitoring companies such as FST, Draker Labs, Energy Recommerce (now National Semiconductor), and Deck stepped up to serve this market, and PPA company SunEdison even introduced its own monitoring system.
This demand has also encouraged module and inverter companies to make customer relationships more “sticky” by bundling monitoring systems that work with portfolios of systems made for their products. Module companies such as SunPower and Suntech offer complete system packages with bundled monitoring systems. Inverter companies, including Satcon, PV Powered (now owned by Advanced Energy), and SMA, are dedicating more development cycles to monitoring, communications, and control features. We also expect utility supervisory control and data acquisition (SCADA) companies will start to support big new utility projects such as Southern California Edison’s and PG&E’s massively distributed 250 megawatt (MW) PV implementations.
The second initiative—high-penetration PV—has even higher stakes for the solar industry.
Today, grid operators get nervous when as much as a few percent of peak load is met by renewable energy (RE) within a distribution area served by a substation. As a result, we see rules across the country that directly limit the size of solar power systems and the amount of peak load that can be met by RE. Hawaii’s most populous island, Oahu, is a good example. The following rule is taken from the North Carolina Solar Center’s DSIRE Database:
For customers of Hawaiian Electric Company (HECO), the maximum individual system capacity is 100 kW. The aggregate capacity of net-metered systems is limited to 1% of HECO’s peak demand. Of this 1% limit, 40% is reserved for systems 10 kW or smaller.
Rules like this hinder the growth of the solar power industry. Oahu has an estimated 1.2 gigawatts (GW) of peak load. The above rule reduces that 1.2 GW to 7.2 MW of commercial solar power systems allowed on the island. At 40 cents per kilowatt hour (kWh), a common revenue target after incentives, the maximum number of commercial solar power systems on Oahu would generate $4.3 million per year. Unfortunately, that’s about what a single supermarket makes each year.
So, what’s the problem? Hawaii’s electricity comes mostly from foreign oil, they’re ranked among the highest in greenhouse gas (GHG) emitting states, and they pay the highest price for electricity. Meanwhile, they have a lot of sun. It seems they would want PV everywhere. The explanation: they don’t think their grid can handle that much solar power.
And they may be right. PV systems produce power at variable rates based on available sunlight. They also automatically disconnect from the grid when they sense poor power quality or no grid power. There is no reason for concern when solar power fluctuation is a small percent of total power on a distribution grid. However, if it becomes too large, grid operators are responsible for compensating for dips and spikes. The problem is they can’t. Conventional power plants don’t ramp quickly enough, and operators don’t control customer demand.
Also, when distributed generation (DG) exceeds load in a substation area, it flows through transformers onto transmission lines—a prospect that makes grid operators shudder. Unless they’ve been upgraded to bidirectional relay equipment, substations are not equipped to handle “reverse flow,” meaning operators cannot measure or throttle power flowing onto transmission lines. And, if a transmission line fails, blackouts can occur.
This happened in Europe in 2006 when one of two redundant German transnational high-voltage lines was “idled” to allow a newly built cruise liner to pass underneath. The ship was late, night came, and two factors arose that resulted in the automatic curtailment of 10 million customers: an unusual rise in demand due to a cold snap in the south, and a common upsurge in wind power from the north. Despite debate over the root cause, the failure spawned Germany’s Medium Voltage Directive, which appears to be the first large-scale mandate of grid operator communications and control over third-party DG.
The directive gives grid operators the ability to remotely disable RE systems connected at 10-110 kilovolts (kV), requires power ramping to prevent harmful surges and dips, enables RE systems to ride through grid faults when linemen are clearly not at risk, and may require that inverters provide reactive power to correct voltage problems. The directive seems chiefly intended to manage wind power. It’s yet to be seen if it will be necessary for solar power management, because PV conveniently generates during times when solar power is most likely to be consumed by adjacent loads.
In the U.S., a similar communications and control requirement is under development by the California Independent System Operator (CAISO), which proposed its version several months ago for RE systems connected to California’s transmission system. Some industry prognosticators believe the CAISO requirements will also be adopted by utility grid operators to manage single systems and system portfolios in the MW range. Considering the concern among operators, this seems like a reasonable prediction, especially as California approaches its limit for net-metered DG, currently set at 5% of peak demand.
The race is on for communications and control within the RE industry. At AltaTerra, we’ve coined the phrase Distributed Generation Communications and Control (DGC2) to describe this burgeoning area of information technology. With the addition of automated control intelligence to system monitoring, we believe DGC2 will be essential for the coordination of all forms of DG with RE-supply and conventional demand forecasting, dynamic pricing, smart grid transmission and distribution components, SCADA systems, and a wide range of load-shedding smart grid devices yet to come. DGC2 will be the brains that direct these new and not-so-new technologies to work together to reduce peak load, dampen RE variability, and safeguard grid operations as we blow past the current limits to RE DG.
Jon Guice is the co-founder and Managing Director of Research at AltaTerra Research.
Jon Previtali has 13 years experience in product management, specializing in renewable energy and related fields such as energy efficiency, smart grid devices and energy storage. Prior to AltaTerra, at SunEdison, the largest generator of solar power in North America, Mr. Previtali managed the operations service for third-party systems, assisted in the development of the solar power fleet monitoring system and developed a high-penetration PV-grid integration strategy. Jon Previtali also launched SunEdison’s channel partner program, which has resulted in over 100 MW of solar power projects and is today responsible for the majority of SunEdison’s system construction. Earlier, Mr. Previtali was the Director of Product Management for Monitoring and Reporting Services at Digital Island, a leading Internet infrastructure firm. He holds a B.S. in Civil Engineering from Stanford (1993) and an M.S. in Civil, Environmental and Architectural Engineering from the University of Colorado, Boulder (2007).