by Julian Spector
April 06, 2018

After a week of personal leave to quantify the solar potential on the beaches of Maui, I’m back. Before we dive into the news of the week, I wanted to flag an opportunity for you — yes you, Squared Reader!

We’re launching our very first live discussion for Squared members, in which myself and fellow reporters Julia Pyper and Stephen Lacey will debate and dissect the cutting-edge news of the day. Listeners can join the conversation by submitting questions in advance when you register or during the live broadcast.

I’m taking point on the program, which means it’ll strike the fancy of any regular Storage Plus reader. We’ll scrutinize what future is left for gas peaker plants, whether all the recent talk around resilience has any tangible effect on the market, and whether residential storage will finally shine this year.

It’s free to you as a Squared subscriber, but tell your non-Square friends so they’ll feel jealous and want to join. Click here to register, and I'll see you there.

And now for the latest updates. We’ve had another gas plant crossed off the to-do list in California and a potentially groundbreaking new paradigm for the solar-plus-storage marketplace. Then I’ll highlight new findings from a fresh GTM Research report on the operational potential for storage in a peaking role, which hasn’t been quantified before.

If it seems like I'm putting a lot of focus on the storage versus gas peakers storyline, that’s just because the most exciting storage developments lately have pushed in that direction. But if you’d rather look for cool new trends in ancillary services, let me know if you find any.

Abort Mission Rock

California’s docket of new gas peakers got a little thinner.

Power producer Calpine asked to suspend its application to put a redundant gas plant on a river bank sacred to the Chumash Nation of Southern California.

Lawyers for the community asked regulators to terminate the proceeding altogether, so the possibility isn’t hanging over their heads for the next three years. The plan was a curious one for Calpine, which is already losing money on merchant plants elsewhere in California. Mission Rock purported to serve a local grid need that Southern California Edison already awarded a contract to resolve, so it’s not clear how Calpine would have made money there.

If regulators quash the application rather than suspending it, it will offer another data point in their recent turn away from gas plants. SCE requested bids for storage and other preferred alternatives to a gas plant that regulators planned to reject in Oxnard, just down the road from the proposed Mission Rock site.

A proper market signal for distributed storage

I recently learned about an idea with the kind of clean, intuitive logic that makes you wonder why you didn't consider it sooner: net metering for batteries.

States with net metering pay solar customers for the power they export to the grid. This policy has crucially advanced the deployment of distributed solar. But if that solar generation first went to a battery and later exported to the grid, then all bets are off.

Utilities don’t want to pay battery owners net metering rates if they’re charging from the grid, which has a dirtier mix of power than pure solar. But the lack of compensation for time-shifted exports limits the value of a rooftop solar installation. Now that California’s utilities are shifting to time-of-use rates, the value of midday solar exports will drop while the value of evening exports rises.

Battery net metering proposes a better pathway. If customers prove their batteries only charge from solar, they can get net metering credits for battery exports just like direct solar exports. Instead of flushing unwanted power onto the grid at noon, rational economic actors will store it to get the premium rates in the evening peak, exactly when the electric system needs it most.

This reorients solar customer incentives in the right direction for the grid. Instead of an imperative to oversize one’s system and dump it all on the grid for a check, this encourages delivery during the hours that drive the most capital investment and greenhouse gas emissions.

The proposal is pending before the California Public Utilities Commission, but it is drawing vocal support from both the solar industry and the three investor-owned utilities. Other states would do well to take a closer look.

Under the hood of the gas plant

The argument for storage to replace gas peakers makes sense in the abstract: Instead of a carbon-emitting, expensive investment that operates a tiny fraction of the year, get a zero-emission battery and do other things with it when peak demand isn’t an issue.

For that to work in practice, batteries must physically meet the needs that gas plants serve. Gas plants can chug along as long as the gas keeps flowing, but batteries run out of juice, and long-duration technologies have eluded commercialization.

GTM Research storage maestro Ravi Manghani sought to quantify the market opportunity in a new report, in which he compares storage capabilities with the historical operations of representative natural gas peakers.

The U.S. has 120 gigawatts of operating gas peaker capacity. In recent years, their capacity factors — a measure of how often the plants run —have jumped from 3 percent to 6 percent. Wood Mackenzie expects them to stay flat in the vicinity of 6 percent over the next two decades.

Manghani dialed into the population of combustion turbines which, at 109 gigawatts, forms the bulk of U.S. peak capacity.

It would be hard for today’s storage industry, with its 4- and 6-hour systems, to replace a peaker that ran infrequently but for, say, 12 or 18 hours at a time.

Luckily for storage developers, a veritable supermajority of combustion turbines — 73 gigawatts, 67 percent — runs at an average capacity factor of 10 percent or less, and fires up for an average of 8 hours or less. That means that storage could be in striking distance of taking over the peak power role, most of the time. But the exceptions matter.

Take the 199 megawatt Elk Station GT2 plant in Texas. It fired up 47 times in 2017, with an average length per start of 6.6 hours. That said, it ran for more than 8 hours in 11 of those starts, and more than 10 hours in one of them.

Manghani tested hypothetical storage systems against the real-world operations of the power plants to see how the newfangled technology stacks up.

In July, Elk Station’s busiest month, a 4-hour battery with the same power capacity as the plant would fail to match most of the peak capacity starts. That alternative would not suffice.

A 6-hour battery, though, would have met 74 percent of Elk Station’s July peaks. An 8-hour system would have met every single July peak, and only missed one of the 47 for the whole year of 2017.

Manghani flags that Elk Station has a higher-than-median number of operating hours per start, meaning roughly half of U.S. peaker capacity runs for shorter average durations than this plant. This is a crucial point: Not all peakers are created equal, and it would behoove the storage industry to start picking off the ones that operate least and for the shortest bursts.

This example also illustrates two challenges for storage in this role.

Replacing Elk Station, based on this analysis, would require a behemoth 199-megawatt/1,592-megawatt-hour battery system. That dwarfs anything the industry has built so far, and it’ll be some years before that kind of scale becomes economical.

However, Manghani projects that such systems will become feasible by the early 2020s. In a levelized cost of energy comparison, 8-hour storage starts competing with combustion turbines within six years, and almost always wins in 10 years. And that’s not even the aggressive case.

The second challenge is that the comparison operated with perfect knowledge, because it looked back in time. Let’s say a battery replaces Elk Station, and the next July there are two 11-hour peak events. Even that behemoth battery won’t suffice.

This is the deeper grid planning challenge: How do you balance the grid with finite battery resources taking over for gas plants? And is it still economical at the system level when you do?

One could imagine a new paradigm where batteries take over typical peaker duties, but utilities keep a smaller number of combustion turbines in reserve for the most extreme demand spikes, when the batteries can’t handle it all.

Then again, demand-side management may progress to a point where those kinds of spikes no longer exist, and backup gas will lose its urgency. I anticipate this kind of systems planning will stimulate a new cottage industry of white papers, so get in quick before the masses realize it.