Navigant Research Blog

GridPoint Takes Aim at Enterprise Energy Management

— November 6, 2012

GridPoint, the Washington, D.C.-based software company, has been a bit of an enigma over the last few years.  It started in 2003 as a provider of an energy and solar system management solution for upper-end homes, but, realizing the constraints of that market, repackaged its software into a customer engagement platform for utility customers as well as several other smart grid applications like load management.  GridPoint landed a number of high-profile utilities as customers, including Xcel Energy through its $100 million SmartGridCity project in Boulder, Colorado.

It still offers each of these, but has recently taken yet another turn.  The firm has begun developing enterprise energy management systems for large commercial and industrial enterprises.  It acquired energy management software firm ADMMicro in 2009 and has made significant inroads already.  Its enterprise business is actually considerably larger than its utility business today.  It has extended its non-software offerings in the process, with a platform that includes hardware (such as controllers, thermostats, submeters, and other sensors) and services (including network operations center-style energy advisory services).

It’s one of the best-financed cleantech startups, having raised over $240 million to date.  GridPoint was even considering an IPO in 2010, but didn’t follow through, and shortly thereafter replaced its then-CEO with software and communications industry maven John Spirtos.  GridPoint went dark for a period of time, but has started to reappear in the media as Spirtos has led the company deeper into the enterprise energy management space.

In a certain sense, GridPoint’s approach and solution are starting to come full-circle, as its utility customers are now asking GridPoint to go beyond customer engagement and deeper into device-level energy monitoring and management of their ratepayers’ facilities.  This corresponds with the broader trend we’ve been tracking on this blog, in which energy management software companies are looking to market their enterprise platforms to utilities for deployment to their customers.

That field is getting increasingly crowded, with other software companies like C3, Pulse Energy, and BuildingIQ making similar early moves.  GridPoint may have an added strength in its existing relationships and knowledge of what works (and what doesn’t) in deploying next-generation software to the slow-moving utility sector.  And although GridPoint has reimagined itself a number of times over the last few years, the success it has had in serving enterprise customers recently shows how readily same data and analytics engines can be used to tell different stories, be they smart grid- or smart building-related.  If GridPoint maintains this light-footedness, it will serve it well in the evolving smart grid industry.

 

Hard Winter Will Test Europe’s Grid

— November 2, 2012

According to the European Network of Transmission System Operators for Electricity (ENTSO-E), the body responsible for managing cross-border energy exchanges in Europe, the 2011-2012 winter was very mild.  Temperatures were warmer than average, and snowfall was lower than average, keeping energy demand for heating far below normal. The ultimate effect was to reduce total electricity exchanged between the European Union (EU) countries, as well as the energy settlement prices.

The main exception was a serious cold front and weather system which hit in early February of 2012, and sent a significant shock through the electric grid.  Record snowfalls and low temperatures across most of Europe, as well as northern Africa, caused a significant increase in energy demand. Electricity import prices spiked above the ENTSO-E average of approximately €70 per megawatt-hour (MWh), in some cases to more than €1000/MWh (about $1300/MWh). With an unusually cold winter predicted for 2012-2013, the European grid may be in for more volatility this year.

The European grid is becoming increasingly interconnected, which should be a boon for managing extreme weather events. Further, the flexibility of the grid increases as intermittent renewable generation comes online.  While a more robust transmission grid can deliver electricity where it is most needed, it does not address the total generation/load ratio.  Much ado has been made about potentially insufficient generation capabilities in the United Kingdom in the near future.  However, with gas and coal prices forecast to increase, simply increasing traditional generation capacities may not be enough, or may prove to be economically unfeasible.  Furthermore, tightening EU-wide environmental regulations will continue to reduce the viability of coal and petroleum plants for electricity generation.

ENTSO-E, meanwhile, suggests that developing enhanced demand response (DR) services could be the most economically efficient way to address large surges in demand.  Such programs encourage electricity consumers to reduce electricity usages during times of high demand.  However, there are few DR systems currently in place; Germany’s four transmission system operators have no specific DR programs, while the United Kingdom and the Netherlands have only limited DR capabilities.

The other relatively cheap option to address potential generation shortcomings is virtual power plants (VPPs).  Essentially, VPPs can aggregate unused generation capacity in certain parts of the grid and deliver it to the parts with excess load.  VPPs are gaining traction in Europe through companies like Spirae, which set up a 76MW VPP in Denmark in 2010.  The system is operated by Energinet.dk and consists mostly of combined heat and power plants.  Since wind power represents a large portion of Denmark’s power base, the Spirae VPP has helped to firm that generation.

Employing similar networks to address energy shortfalls on other parts of the larger European grid is a plausible extension of this technology.  While the dearth of governmental standards may inhibit VPPs from sending power directly to other countries to meet demand, individual countries may be able to maximize their electricity production and capitalize on increased power exports through VPP adoption within their own borders.  If the coming winter turns out to be a hard one, these technologies could prove critical.

 

Hurricane Highlights Nuclear Plants’ Vulnerabilities

— November 1, 2012

As Hurricane Sandy reached the height of its fury on Monday night, October 29, the Oyster creek nuclear plant in southern New Jersey went on “alert” – the third-highest of four levels of emergency action for nuclear generating stations in the United States.

The oldest operating nuclear plant in the country, Oyster Creek is about 40 miles north of Atlantic City, just a mile from Barnegat Bay, an inlet off the Atlantic Ocean.  It has been plagued for years by environmental protests and lawsuits, mostly relating to the hot water it discharges into the bay.  It’s the same design as the ill-fated reactors at Fukushima-Daiichi in Japan that were inundated in the March 2011 earthquake and tsunami.  Oyster Creek is scheduled to be shut down in 2019.

In anticipation of the storm, emergency crews from the Nuclear Regulatory Commission were dispatched to Oyster Creek, along with eight other nuclear plants on the Eastern Seaboard.  Officials with the federal government and with Exelon, the nation’s largest producer of nuclear power and operator of Oyster Creek, were less concerned about damage to the reactor itself than about keeping the spent fuel rods, stored in a large pool onsite, from overheating.  Intake structures and pumps take water from the creek and pump it through the plant to cool off both the reactor core and the spent fuel.  While there is backup power for the reactor cooling system, there’s none for the spent-fuel pool.

“Exelon … was concerned that if the water rose over 7 feet it could submerge the service water pump motor that is used to cool the water in the spent fuel pool,” reported Reuters.  In fact, the flood peaked at nearly 7-and-a-half feet, above the threshold, but the pump motors continued operating.

Vulnerable systems like this are in place at nuclear plants across the country, where fuel rods are often stored in large pools that must be supplied with a constant source of fresh water.  Without that supply, the pool could boil in a day thanks to the residual heat of the radioactive fuel rods.  That almost happened at Fukushima-Daiichi, and the spent-fuel pool at that plant remains at risk today.  Nuclear industry spokespersons were full of assurances in the last few days that such a thing could never happen in this country.  An Exelon spokesman said the company’s nuclear facilities have “multiple and redundant” cooling systems.  U.S. nuclear power is “a whole different ballgame” than the Japanese industry, maintained Tom Kauffman of the Nuclear Energy Institute.

It could in fact happen here, and judging from the high levels of water at Oyster Creek it nearly did.  A disaster of this magnitude highlights the central flaw of conventional nuclear reactors, which are largely based on technology nearly a half-century old (Oyster Creek went critical in December 1969).  As I explain in SuperFuel: Thorium, the Green Energy Source for the Future, nuclear plants are controlled by elaborate engineering systems, with backup diesel generators and supposedly fail-proof systems, to keep the reactor and the spent fuel pools cool in emergencies.  The nature of Sandy-caliber disasters, though, is that such systems often fail.  Our nuclear fleet is one major flood away from a full-on disaster, and major floods are getting more common yearly.  Meanwhile, inherently safe reactor technology, like the liquid-fuel thorium reactor, cannot melt down or overheat due to the design and the physics of the machine.

We’ve been hearing reassurances like the ones this week from the nuclear power industry for decades, but the machines themselves just keep getting older.

 

Biomethane Shows Market Promise, at Least in Europe

— November 1, 2012

Europe is leading the world in production of biomethane vehicles, which run on methane generated from digesters of waste products.  Germany has jumped into the market in a big way, with Hamburg Wasser shifting its fleet of vehicles to run on biomethane and the opening of the 100th all-biomethane refueling station.  Biomethane (also called biogas or renewable methane) is often mentioned as a way to move to CO2-neutral driving.  The German energy agency, DENA, found that mixing 20% biomethane has the possibility of reducing GHG emissions by up to 39% over gasoline and 36% over new clean diesels, and that using 100% biomethane would be as clean as driving an electric car using 100% wind electricity generation.

Well-to-Wheel Greenhouse Gas Emissions for Various Fuel

(Source: DENA German Energy Agency GmbH)

A new study from Dr. Frank Rijnsoever of Utrecht University in the Netherlands shows that Netherland government fleet managers will value biomethane-fueled vehicles as much as electric vehicles.  The research shows that fleet managers are willing to pay a premium for both biomethane and electric vehicles over traditional gasoline vehicles.  However, similar to what we see here in the the United States, the lack of refueling infrastructure for biomethane limits interest.

Interest in biomethane is particularly strong in Northern Europe (the Nordic countries, the Netherlands, and Germany).  However, the overall market for natural gas vehicles in these countries remains small in comparison to Western Europe’s largest market, Italy, with 159,578 NGV sales anticipated this year, compared to 29,849 in Sweden, the second largest market in Western Europe.  While Italy is in the throes of sorting out the biomethane industy, Sweden has a strong market for biomethane, with about 58% of NG used for transportation coming from biomethane in 2008 (latest data available).

In the United States, biomethane remains a very small part of the overall gas market.  As a transportation fuel it’s almost entirely relegated to fueling garbage trucks and a few other demonstration fleets.  That may change in time, as the California Air Resources Board has published a proposal for a new Low Carbon Fuel Standard (LCFS), which includes a “pathway” to biomethane production.  This was followed by the announcement that three companies have been selected by the California Energy Commission to receive grants for biomethane production.  Whether these grants will ultimately be awarded is still very much up in the air, but the momentum is growing.

If emissions were the deciding factor then biomethane would be the clear, hands-down, winner.  However, production costs of biomethane range from $5.90 to $9.00 per million British thermal units (MMBtu), according to Calstart, for midsize to small production facilities.  Non-renewable natural gas is very cheap at the moment ($3.43/MMBtu), so the economic motivation is not there.  This will relegate the biomethane market to small projects targeted at specific fleets or geographic areas.  This, combined with the small size of the NGV market in the United States (20,381 vehicles in 2012), makes it hard to see biomethane having a significant impact on the U.S. transportation market.  For the foreseeable future, most biomethane investment will remain focused in Europe.

 

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