Well I'm not sure how much longer the term baseload will be relevant. But in the traditional sense, batteries are not a good fit for baseload. Too expensive and too short a cycle life. Batteries are more valuable for their flexibility. So I think they would function better in the role of things like ancillary services, peak shaving, complementing intermittent renewables, etc.ROCKMAN wrote:Ignoring the insignificant numbers of systems currently in operation wouldn't grid scale battery storage represent the ideal "baseload". The UK utility is currently investing $125+ million in 8 such systems that can respond in less then one second to supply shortages. Rather difficult for a coal/NG plant to respond that quickly. Of course the magnitude of the shortage is critical. But if that need is relatively small a fossil fuel plant can't shut down in less then a second either.
But if the ultimate shortage is too large for the battery system they can potentially cover the need until the fossil fuel plants can kick in. And while the battery systems could be beneficial to alt intermittent problems they can also be charged by fossil fuel plants as they cycle down due to sudden demand decreases.
But such possibilities will require a lot of grid battery build out.
Deployment of Grid-Scale Batteries in the United StatesLooking forward, however, limits to this trajectory are apparent. The PJM frequency regulation market may soon be saturated, and in other wholesale markets, technologies other than batteries may be more cost-effective for providing ancillary services. FERC recently opened a proceeding to explore barriers to greater participation of energy storage in wholesale markets. But the slow pace with which its 2011 orders have been implemented suggests that its leverage may be limited.
Most of these other applications are not yet cost-effective, although specific projects in specific locations, such as at the distribution level in dense urban areas, may be. Stacking multiple services on a single storage system may also bring more projects within reach at today’s battery prices. But the “levelized cost of storage,” to use the terms of Lazard’s recent analysis, is generally higher than the alternative in every use case. Similarly, Hittinger and Lueken argue that falling natural gas prices have adversely affected the revenues of U.S. energy storage projects since 2009, because they must compete with gas turbines for peak shifting purposes.
The biggest drivers of the next phase of grid-scale battery deployment are likely to be state mandates, rather than markets. Most notably, California utilities are required to procure 1.3 GW of storage by 2020 (none of which is yet recorded in the DOE Global Storage Database), provide incentives for customer-sited storage resources, and include storage among preferred resources for distributed generation and demand management. Arizona, Hawaii, Massachusetts, New Jersey, New York, and Washington are among the other states that are mandating or subsidizing electricity storage on a reasonably large scale.51 (See Figure 21.) Given the difficulties of siting pumped hydro and CAES as well as the growing experience with batteries, it seems highly likely that such mandates will led to growth in the grid-scale battery market.
Is the bloom off the RegD rose for battery storage in PJM?Changes in PJM's frequency regulation have soured the market for battery storage there. After an initial boom that began to overwhelm PJM’s frequency regulation market, the RTO put the brakes on battery storage installations. PJM quickly followed up by changing the parameters of its frequency regulation signal and then proposed further changes in how it calibrates the relationship between fast response resources, such as batteries, and conventional resources, such as gas turbines. Those changes were met with howls of protest by energy storage developers, some of who are contesting the changes at the Federal Energy Regulatory Commission.
By mid-year 2016, PJM had about 265 MW of grid-connected storage projects, of which about 160 MW were installed in 2015, and with about 700 MW more under construction or in development. The rush of projects also exposed some flaws in the design of PJM’s frequency regulation market. Sometimes a battery providing fast ramping frequency regulation service would be depleted and go from discharge to charging mode, burdening the grid instead of supporting it. “The RegD signal would sometimes move in the opposite direction of the area control error [ACE], exacerbating the frequency regulation problem.” When that would happen, PJM would in effect be paying for RegA in order to cancel out the draw of RegD resources on the system. RegD resources respond quickly to ACE signals, but are time limited. RegA resources respond to signals more slowly but do not have duration limits, so the technical trick is to find the optimal mix of RegD and RegA on the system. RegD has more value for quick response needs, but too much RegD and that benefit would be reversed and could even harm the grid.
Project margins reduced 75%
In a July letter to PJM, AES Energy Storage said it designed its 20 MW Tait storage facility in Ohio and its 32 MW Laurel Mountain facility in West Virginia with PJM’s 15 minute design specifications in mind. AES says PJM’s December and January changes to the RegD market have reduced the 2016 margins for those projects by 75% compared with 2015 margins. In addition, AES says operating under the new rules “has greatly reduced the expected useful equipment life and seriously threatens the continued viability of these batteries.” Those batteries are now “doing twice the work for half the revenues while shortening their remaining life,” AES said in the filing. In the ESA complaint filed with FERC, Damien Buie, with EDF Renewable Energy, said the company’s 20 MW McHenry storage project in Illinois “has been significantly and detrimentally impacted by PJM’s January 9, 2017, decision.”
Storage projects dropping out
The result, said Finn-Foley, is that storage projects are dropping out of the interconnection queue. “We are seeing a handful drop off every quarter.”
ROCKMAN wrote:jaw - "If the goal is to lower CO2 emissions, this is a massive failure given the amount of money and effort spent over the past 20 years since the Kyoto Accord." As I've repeatedly pointed out Texas didn't develop world class wind power with the goal of reducing CO2 emissions. It wasn't even a secondary consideration. After all:
"Texas emitted more carbon dioxide from burning energy in 2013 than it did at any point since 2004. And, for at least the 24th year in a row, the Lone Star State tops the list of the nation’s biggest carbon polluters, according to U.S. Energy Information Administration."
Check the chart: http://www.climatecentral.org/news/carb ... ates-19615
What our wind power build out did accomplish was preventing an equivalent expansion of our fossil fuel fired generation: we were going to expand one way or the other to meet our growing demand.
Folks can f*ck around with the economic numbers all they want but it doesn't change the fact: every wind farm built in Texas was done because of a profit motive. And given they continued to be built profits must have been realized. And while the fed tax credits are a benefit the value is there only if the investment is producing a taxable profit. IOW losing money means no profit to apply the credit to.
The two wind and solar companies that will supply Georgetown, Texas, with 100% alt electricity are doing so to make a profit. And thanks to a contracted rate structure with the utility company the profit IS NOT theoretical: it's locked in from Day 1. And now E.ON is building grid scale battery story to be fed by two wind farms it owns in Texas. And this isn't the first such effort by those Germans. Having done it before they should have a good handle on the profitability: they aren't subsidizing Texas alt out of the goodness of their hearts. LOL.
Texas does have have some geographic advantages over other states. But that's not the primary reason why we've expanded alts so quickly: OK has the same strong winds just across the state line. We have ERCOT: it is composed of electricity generators, transmission companies, consumers via the utility commission and the state's politicians. Essentially it's forces cooperation amongst all parties to provide not just the lowest possible rates but also accetable profit margins for the investors. Membership isn't really voluntary: you either cooperate with the ERCOT regulations or you don't participate in the state's power generation system as a provider or consumer. And given that Texas is by far the biggest electricity consumer in the country that's a very big pie to grab a slice of.
ERCOT comes as close to a "benevolent overlord" as we'll ever see in this country. LOL.
coffeeguyzz wrote:Good time, perhaps, for folks to do a little checking up on exactly what the ITCs and PTCs actually are. (Investment Tax Credits/Production Tax Credits).
I will repeat a statement previously made, whirleys would shut down tomorrow sans subsidies. Check out the statement by the US' largest owner of whirley farms, made in 2014, Warren Buffet claiming they made no economic sense without credits.
North Dakota just looked into taxing the income on whirley farms in the state and discovered income was zero.
These credits are also transferable.
coffeeguyzz wrote:Ghung
Suggest you do a quick check on the Scot wind farm situation where the production is both large and increasing.
As was stated above, not only can whirley producers crank out the juice without worrying about profit making, their advantages destroy legacy producers as juice price drops (see South Australia for advanced state of this situation) , which is why the nuke boys are heading out the door toot sweet.
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