Tag Archives: DER

Fighting the last war: Study finds solar + storage uneconomic now  | from Utility Dive

“A Rochester Institute of Technology study says a customer must face high electricity bills and unfavorable net metering or feed-in policies for grid defection to work.”

Yet…this study used current battery costs (at $350/KW-Hr), ignoring probably cost decreases, and then made more restrictive assumptions about how such a system might work. It’s not clear if “defection” meant complete self sufficiency, or reducing the generation portion (which in California about half of electricity bill.) Regardless, the study shows that grid defection is cost-effective in Hawaii, confirm the RMI findings. Even so, RMI said it would take at least 10 years before such defection was cost-effective in even the high-cost states like New York and California.

A more interesting study would be to look at the “break-even” cost thresholds for solar panels and batteries to make these competitive with utility service. Then planners and decision makers could assess the likelihood of reaching those levels within a range of time periods.

Source: A study throws cold water on residential solar-plus-storage economics | Utility Dive

And then this…Trump’s energy plan doesn’t mention solar – The Washington Post

After the release of a study showing solar now employs more than oil, gas and coal combined.

Source: Trump’s energy plan doesn’t mention solar, an industry that just added 51,000 jobs – The Washington Post

How Should Distributed Generation be Distributed?

Bruce Mountain observes in the Comments that Australia already is experiencing deep solar penetration, but is not find extensive disruptions in the distribution networks.

Energy Institute Blog

Growth in the residential solar market continues apace. In the United States, residential solar PV installations last quarter were up 11 percent over the previous quarter:

q1-2015-install

Source: http://www.greentechmedia.com/research/ussmi

The figure  illustrates this impressive growth rate (in dark blue). However, this is growth on a very small base. By my crude calculations, less than half a percent of American households currently have solar panels on their roof.[1]

In those states where residential solar is starting to take hold, there are mounting concerns that rate structures currently in place to support residential PV will result in adopters bearing less than their fair share of system costs. If increasing levels of distributed solar generation puts additional pressure on grid equipment and aging infrastructure, these concerns loom even larger.

A new EI working paper takes a close look at how increasing levels of distributed solar generation can impact power system costs. For me, this…

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Cheap energy storage may be parked in your garage

One of the key questions about how to bring in more renewables is how do we provide low-cost storage? Batteries can cost $350 per kilowatt (kW) and pumped storage somewhat lower. Maybe we should think about another potential storage source that will be very low cost: automobiles.

California has about 24 million autos. The average horsepower is about 190 HP which converts to about 140 kW. Let’s assume that an EV will have on average a 100 kW engine. Generally cars are parked about 90% of the time, which of course varies diurnally. A rough calculation shows that about 2,000 GW of EV capacity is available with EVs at 100% of the fleet. To get to 22 GW of storage, about 1% of the state’s automobile fleet would need to be connected as storage devices. That seems to be an attainable goal. Of course, it may not be possible for the local grid to accommodate 100 kW of charging and discharging and current charging technologies are limited to 3 to 19 kW. So assuming an average of a 5 kW capability, having 20% of the auto fleet connected would still provide the 22 GW of storage that we might expect will be required to fully integrate renewables.

The onboard storage largely would be free–there probably are some opportunity costs in lower charging periods that would have to be compensated. The only substantial costs would be in installing charging stations and incorporating smart charging/storage software. I suspect those are the order of tens of dollars per kW.

What are the missing questions in California’s distribution planning OIR?

The CPUC has opened a long awaited rulemaking to revisit (or maybe visit for the first time!) how utilities should plan their distribution investments to better integrate with distributed energy resources (DER). State law now requires the utilities to file distribution plans by next July. But the CPUC may want to consider some deeper questions while formulating its policies.

To date the utilities have pretty much been able to make such investments with little oversight. For one client, AECA, we submitted testimony pointing out that PG&E had consistently overforecasted demand and used that demand to justify new distribution investment that probably is unneeded. Based on a corrected forecast that recognizes that that PG&E’s (and the state’s) demand has turned downward since 2007, PG&E’s loads don’t return to 2007 levels until at least 2014. (We found a similar pattern in SCE’s 2012 GRC filings.)

 

AECA - PG&E 2014 GRC Testimony: Comparing Demand Forecasts

AECA – PG&E 2014 GRC Testimony: Comparing Demand Forecasts

Both PG&E and SCE justified new investment based on phantom load growth, but they would have been better served to show what investment might be required for the evolving electricity market. SCE has responded with the Living Pilot that tests out how to best integrate preferred resources.

The CPUC is relying on Paul De Martini’s More than Smart paper as a roadmap for the rulemaking. The CPUC has asked a number of questions to be addressed by September 4 with replies September 17. A workshop is to be held September 18.Beyond these questions, two more questions come to mind.

First, who will be allowed to play in the DER world? The OIR asks about non-IOU ownership of distribution lines, particularly related to microgrids, but it doesn’t consider the flip side–can utilities or affiliates participate in the DER market? Setting market rules in the face of rapid evolution and uncertainty, current participants will look to protect their current interests unless they are shown a clear opportunity to gain the benefits of a new market. The CPUC ignores the political economy of rulemaking at our risk.

The second is how is this proceeding to be integrated with the multitude of other proceedings at the CPUC that set various resource targets? The LTPP, energy efficiency, demand response and solar initiatives, along with others, all seem to run on parallel tracks with little in the way of interactive feedback. Megawatt targets seem to be set arbitrarily with little evaluation of comparative resource costs and effectiveness, and more importantly, how these resources might best integrate with each other. How are the utilities to adapt to the spread of DER if the CPUC hasn’t considered how much DER might be installed?

Both of these questions are about market functionality. Who are the likely participants? What are their incentives to act in different situations? How would the CPUC prefer that then act? How are price signals to be coordinated to create the preferred incentives? The system investment and operation rules are a necessary component of anticipating the market evolution, but they are not sufficient. California ignored the incentives of market participants in the previous restructuring experiment, at the cost of $20 to $40 billion. We should take heed of what we’ve learned from the past about the paradigm we should use to approach this impending change.