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Published on April 27th, 2016 | by Susan Kraemer


How Ivanpah Raised Its Performance In Its Second Year

April 27th, 2016 by  

In 2015, PG&E customers received about 97% of Ivanpah’s contracted electrons, which is a massive improvement over its first year.

But this raises a question:
Ivanpah PG&E PPA solar required versus generated in year 1 and year 2
Source: SEC/EIA data Unit 1, Unit 3

What exactly were the engineering challenges at Ivanpah – and why did they take a year to solve? 

To find out, I spoke with engineering experts at NRG, which is the operating partner as one of the three Solar Partners which developed the project, along with BrightSource and Google.

“We encountered the kinds of engineering problems that can really only be seen and solved in a first full-scale deployment,” NRG spokesman David Knox told me.

“And in that first year, an inordinate number of partly cloudy days impacted not only the energy output, but also the plant’s ability to commission and actually fine tune all of its control systems.”

At 377 MW net, Ivanpah is the first-ever utility-scale direct steam solar tower: any similarly novel technology relying on solar would also need a succession of sunny days to diagnose and try out solutions to engineering problems. 

“But now that we have learned the lessons that we have learned, and the industry has learned the lessons that we have learned; others don’t have to,” he added.

“But the first large-scale installation needed to go through those steps.”

Correcting a too-easily-tripped steam sensor

Adjusting the settings for the sensor on a steam drum to prevent tripping too easily was one of the biggest contributions to the increase in generation in the second year, according to Mitchell Samuelian, NRG’s vice president of operation for utility-scale renewable generation.

“If even a wispy little cloud came over in the morning, the plant would trip. We would actually have four or five drum level trips on start-up every morning,” he told me.

Samuelian has an engineering background and worked in traditional thermal and hydropower electricity before coming to NRG, which itself is well-versed in operating traditional thermal plants that use a power block in the same way as a CSP plant does, but they are fueled by gas or coal, not solar.

In both the newer “tower” types of CSP, whether they operate on direct steam like Ivanpah, or on molten salt with energy storage, like Crescent Dunes, the transfer medium is heated by the moving path of sunlight continually reflected off mirrors (heliostats) onto a receiver in a central tower.

The steam drum has to be downsized in a solar tower.

At Ivanpah, sunlight concentrated onto the tower receiver heats water to steam in the steam drum.

At 500 feet up in the tower, the drum had to be smaller than a typical steam drum in a conventional power plant. A steam drum has water in the bottom, and heating the water creates steam in the top. In the Ivanpah plant, that gets piped down the tower to operate the steam turbine below.

“In a gas or coal plant the steam drum is much bigger, so they don’t have the same issues with the level going up and down,” he told me. “Small changes in level don’t cause problems. So it was just the fact that it was up in the tower and it’s hard to put a big huge steam drum up there.”


A sensor reset helped reduce morning startup time down to 25 minutes.

Initially the water level sensors in the steam drum were set like those for a fossil fuel plant, which trips off if the water level raises too much, indicating inadequate steam production to run the turbine.

But in a solar configuration, every passing cloud was tripping it off, turning off the plant unnecessarily, and especially during morning startup.

“So we went through with the engineering and redesign so we could go to a higher level and a lower level when we are operating,” said Samuelian. “The operating range was plus or minus I think three inches. And now I think we’re in the range of plus or minus 11 or 12 inches.”

“And now we get a trip on start-up only every couple of weeks”

Simply resetting the steam drum water level sensors to be a little less sensitive to water levels (we’re talking a few inches here) while not endangering turbine operation was a big part of how the morning startup time was cut from four hours to under 25 minutes:

“In the first couple of months, it was taking us right around three to four hours to startup, and now on a normal sunny day from the time that the sun comes up over the horizon to the time that we actually synchronize the unit is in the 25 minute range,” he said.

Many other small engineering fixes included ongoing improvements in integrating the control system that operates the movement of the mirrors in the solar field with the one operating the power plant itself.

Ivanpah was the world’s first attempt at utility-scale direct steam solar tower CSP. Abengoa built the first direct steam tower CSP in Spain at just 11 MW in 2011, which is pilot sized. Abengoa’s direct steam Khi Solar One came online in South Africa in 2016, but at only 50 MW, compared to Ivanpah’s three towers totaling 377 MW two years ago.

New technology takes time to refine. I asked NRG whether traditional power plants had similar start-up troubles:

“Oh yeah,” said Samuelian. “You see that in all new technology. In fact if you look at early on; I remember in the first number of years they will tell you that the forced outage rate was in the 30 or 40 percent range for that new technology, when they were first using gas turbines to drive generators. and nowadays those things are at between 97 percent to 98 percent availability.”

“It is just like any other technology. It just takes a while to get all the bugs out of it.”

For engineers behind the scenes, improving technical problems is just routine.

But CSP is not like any other technology. Our previous first-of-its-kind energy technologies didn’t start up in the glare of a hostile spotlight from today’s highly politicized media:  

Nobody cared that engineers took years to fix the start-up problems of coal or gas turbines. Solar PV could take care of any start-up buggy-ness in the privacy of space.

The Wall Street Journal, now owned by Rupert Murdoch, is widely quoted with its factually wrong statements about Ivanpah’s generation requirement for PG&E, making it appear that the first direct steam solar tower has failed spectacularly to meet the target.

When I asked the journalist responsible why she ignored the facts in the SEC filing, she said because BrightSource wouldn’t also “go on the record.”

When PPAs are confidential, the parties are liable if they reveal PPAs that are not in the public domain: However, another journalist outed the SEC filing last year so it is in the public domain.

SEC filings are reliable sources; in covering most businesses, the WSJ cites them, because investors need facts.

The SEC filing states the mature year contract quantity of generation required after a four year ramp up is 640,000 MWh for PG&E’s two units.

“The “contract quantity” for each year is expected to be 304,000 MWH for Solar Partners II (Unit 1) and 335,600 MWH for Solar Partners VIII (Unit 3) throughout the delivery term, and the seller must deliver a guaranteed amount of energy in two-year measuring periods.”

Now here is the math for the first two-year measuring period: 2014-15:

“The production guarantee generally is 140% of the contract quantity during the first measuring period after the commercial operation date.”

So to get PG&E’s two-year requirement, multiply 640,000 by 140% = 896,000 MWh.
EIA shows two-year generation from PG&E’s  Unit 1 and Unit 3 as = 723,153 MWh.

Over both years that’s 81% of the contracted quantity.
Ivanpah PG&E PPA solar required versus generated in year 1 and year 2

But most of the shortfall was in the first year: The reason that PG&E petitioned the California Public Utility Commission to allow it to keep the contract was the improvement after these engineering challenges were resolved.

In 2015, PG&E customers received about 97% of Ivanpah’s contracted electrons. 


About the Author

writes at CleanTechnica, CSP-Today and Renewable Energy World.  She has also been published at Wind Energy Update, Solar Plaza, Earthtechling PV-Insider , and GreenProphet, Ecoseed, NRDC OnEarth, MatterNetwork, Celsius, EnergyNow, and Scientific American. As a former serial entrepreneur in product design, Susan brings an innovator's perspective on inventing a carbon-constrained civilization: If necessity is the mother of invention, solving climate change is the mother of all necessities! As a lover of history and sci-fi, she enjoys chronicling the strange future we are creating in these interesting times.    Follow Susan on Twitter @dotcommodity.

  • CU

    Thanks for the informative article!

  • JvonRuhl

    Reading that Ivanpah is a first in its field, and there have been no plants like it make me wonder how it’s different from the old Solar 1 at Daggett California, owned by southern Cal Edison. It ran along side the Coolwater Coal fired 3 unit (if I remember rightly) for about 10 years. It too, had a mirror field that heated a steam drum at the top of a tower. I would have thought that plant would have taught the industry a lot about Solar Collection, unless they refused to share. It sounds like a similar process.

  • Paul

    Hopefully El Nino was the cause of the extra cloudy days and will not be a factor again for a while.

  • Bob_Wallace

    Susan, another question which probably belongs on a different solar thermal article you wrote, however…

    You expressed concern about storing a large amount of molten salt in an underground chamber. How do thermal plants now store ‘heat’? Do they build insulated tanks above ground?

    • They do. They are pretty big, almost like those big refineries in Pinole in the East Bay (and obviously many other places too). And they are insulated, and lined with corrosion-proof material.

  • Bob_Wallace

    Susan, a few years back someone proposed a thermal solar plant where a concave mirror was suspended above the mirrors, the mirrors aligned so that light reflected off the higher mirror, and heated a collector on the ground.

    In fact, the collector/storage system was located in a subsurface chamber which could be covered at night with an insulated cover.

    Wonder if your thermal solar contact people see any validity in that idea. It would get the weight out of the sky, reduce the amount of plumbing, and get stuff down on the ground where it’s easier to work on.

    A potential problem I can see is the possible light blocking by the 3 or 4 legs it would take to hold the top mirror rigidly in place.

    • Yes, I spoke with Nicolas Calvet at Masdar in the UAE where he runs that research thingie that tries that. (He’s the one who had the funny response when I asked if Spain’s Gemasolar had had any trouble with birds, that I quoted here a while back.)

  • JamesWimberley

    It really is moving the goalposts to describe Abengoa’s 50MW plant in South Africa as not utility sized. That is a common size for utility PV farms.

    It is an uncomfortable truth that Ivanpah has had a lot more technical problems than typical in the CSP industry, following the decision to go for a leap in steam temperature rather than incremental improvement like Abengoa.

    • Maybe, yes. For you in the UK, it may seem so. 50 MW was the limit set by Spain’s govt for CSP, and by South Africa for that first round under REIPPPP. But utility-scale PV and wind in the US does tend to be 100 MW – 500 MW.

      (But look at your offshore wind – latest offshore wind farms being built at over 1 GW!)

  • eveee

    Fantastic Susan. Been waiting for someone to point out that these are the first ever full scale units of this type of CSP tech. They must be given consideration for this, not rushed to production, or judged harshly by critics, using the yardstick of BAU FF power plants.

  • Pete Danko

    As always, lots of good information here. The only correction I’d make is where you say “Over both years that’s 81% of the contracted quantity.” It’s actually 81 percent of the “guaranteed energy production” (GEP) — the amount the plant needed to produce in the first two years (the first measuring period) in order to avoid being in default of the contract. It’s also worth noting that under the PPAs, after the first measuring period the GEP rises to 160 percent of the “contracted quantity” in any two-year period looking back. The forbearance agreement gives Solar Partners six months and more likely up to a year — until Feb. 1, 2017 — to reach this higher GEP that is now in effect. It will require continued, significant improvement. Unit 1 generated 213,126 MWh in the 12 months ended January 31 this year, and will need to generate 273,274 MWh over the following 12 months – an increase of 28 percent, to hits its GEP. Unit 3 will need to increase production from 220,595 MWh to 316,365 MWh to reach a GEP of 536,960 MWh. That’s a 43 percent increase,

    • Dragon

      If that’s true it seems like it’s going to be very difficult to increase production by that much at this point since they’ve already done the most obvious efficiency improvements. They also seem to be fighting climate change effects that are increasing the likelihood of cloud cover vs historical norms, meaning they’re at a fundamental disadvantage in hitting their original targets over the long term. Still, I certainly wish them luck.

    • You are right, Pete. I try to be so careful. But yes, my whole point is to explain the percentage idea: the percentage required for the startup two-year measuring period amounted to 70%. Yes, for the next two-year measuring period, it next ramps up from 140% to 160% divided between those two years = 75% requirement. (2015-2016)

      • But by the end of 2016, that will be looking not at the bad numbers of 2014, but 2015’s much closer generation, with 2016’s. So I think they can do it.

        • Pete Danko

          80%, you mean, not 75% – and yes, as a rolling 24-month period, small early totals will fall away, although the numbers in my comment above use Year 2 data to figure out what they will need in Year 3 to meet the new GEP that will come into play once the forbearance agreements expire. One other small point: I use “Year 1” and “Year 2” etc because measuring of performance against the contract’s requirements does not conform with the calendar years. For GEP purposes, counting began on Feb. 1, 2014. So “Year 1” is Feb. 1, 2014-Jan. 31, 2015, inclusive, and so forth. This changes the totals a bit, putting the initial 24-month measuring period generation total at 730,204 MWh for the two PG&E units, not 723,153.

          • No, the next measuring period must be 75% of mature year. Pretty sure. 80% is the third measuring period; 2016-2017, not the second one.

          • Pete Danko

            Nah, that’s not what the SEC docs say about the PPA. They say 140% for the first measuring period and 160% for “subsequent measuring periods.” And the advice letter on the forbearance agreement makes clear that subsequent measuring periods begin after Feb. 1, 2016 on a “24-month rolling” basis. Rolling being the key term.

          • Well, I agree that 2016 has to be 80%, as the first year of the second look-back measuring period. As I read it the next actual two-year measuring period is the look-back at 2016-2017 and that must be 160%.

            However, a new interim look-back as a result of the PG&E petition will be to see if it is at 80% (2016)/70% for (2015). And that averages 75% (though, practically speaking, it has to be just like 83% to make up for 2015 being 3% under 70%.

          • Pete Danko

            There’s nothing in the contracts (at least what we know about them as revealed in SEC filings) about 70 percent or 80 percent, those are just our constructs to help convey the minimum generation requirement on an annualized basis in the first two years. It’s all about 24-month periods — rolling 24 month periods. “Because the Projects started deliveries in mid to late January 2014, the two-year GEP requirement will be calculated effective February 1, 2016 and will be based on a 24-month rolling requirement after that date.”

          • I agree they are our constructs (half of a two year target). Pete, see my email.

          • Found my notes: the 80% target is for years 3 and 4 – they have to achieve 160% by the end of year 4. But at the end of 2016, it is one year (2015) at 70% and one year at 80% (2016) but totalled, averages 75%.

            By the end of year 3 (2016), they split the difference and will need to have averaged 75% on a two-year basis (year 2 at 70%, and year 3 at 80%)

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