The Ivanpah solar project is deadlier to birds than previously thought, but the plant still presents a low risk to any species or group of species, according to a new report.
In April 2015, the annual monitoring report prepared for the California Energy Commission estimated 3,504 birds died at the solar power tower plant in the Mojave Desert in its initial year of operation, ending in October 2014. The Year 2 report (PDF), filed late last month, revises that first-year number up to 5,128, while estimating that 5,181 birds died at the plant in the most recent operating year.
The report’s preparer, Western EcoSystems Technology, said the revision to the first-year number reflects improved understanding of bird migration timing and better information about how many of the birds that die at the plant are being found by searchers.
After coming up with a Year 2 estimate using the same methodology as in Year 1 – 6,186 – the company went through and applied the improved methodology to both years and arrived at the revised numbers.
“Overall, the estimates calculated using biologically informed seasons are greater for the first year, lower for the second year, and greater overall for both years combined. The changes are driven by two main factors: re-categorizing a number of detections from winter seasons to fall seasons because a monitoring year ends in fall, and the effect of additional bias trial data from the period between 21 October 2015 and 15 December 2015,” the report said.
In the end, “the new analysis does not change any conclusion of the impacts of the Project” on birds, the report said, categorizing that risk as “low.”
The big story at Ivanpah these days is last week’s fire. That was at Unit 3, also known as Solar Partners VIII, one of the two units contracted to sell power to PG&E, which means there could be implications for the tenuous power purchase agreement Solar Partners (NRG Energy et al) has with the Northern California utility.
But for Ivanpah geeks there’s interesting non-fire news as well, involving the plant’s use of natural gas.
You might recall that a couple of months ago, just after the Wall Street Journal click-baited you all with that “Ivanpah Solar Plant May Be Forced to Shut Down” headline, NRG fed a story to Bloomberg touting the plant’s vastly improved electricity generation in February (67,254 MWh vs. 30,273 MWh the previous February). I asked at the time how much gas the plant used on its way to that improved performance, and later found it was about double the previous February.
So now we have March data. It shows generation up just slightly over March 2015 – 58,409 MWh vs 56,343 MWh. Meanwhile, gas use again increased dramatically. In fact, sound the trumpets, in March Ivanpah burned more gas than in any month since it began operating: 149,445 mcf. The old record was 144,472 mcf in June 2015. In March 2015 the figure was 87,367 mcf.
Add up the three first-quarter months and you see gas consumption at the plant was up 93 percent this year over 2015 (while energy generation was up 39 percent). That’s a crazy pace that would seemingly have put the plant, which used 1,195,123 mcf last year, on the way to busting through its regulatory limit of 1,575,000 mcf/year (525,000 mcf per unit, to be precise). Remember, too, that originally Ivanpah was certified to use 984,000 mcf/year. Then it started up, realized it would need more, and successfully petitioned to boost the limit.
Early production at Crescent Dunes, the new solar power tower plant with integrated energy storage, has been meager, but developer SolarReserve says not to worry, things are going according to plan.
Crescent Dunes began selling energy to the Nevada electric utility NV Energy last October, sporadically until the end of 2015, then a bit more regularly in 2016. Still, through March the highest monthly output was February’s 9,095 megawatt hours, according to Federal Energy Regulatory Commission reports. That’s a capacity factor of 11.9 percent for the month, a long way from the 52 percent overall capacity factor expected at Crescent Dunes in the long run.
Via email, I asked SolarReserve’s vice president of communications, Mary Grikas, what was up. She said the plant, in The Middle of Nowhere, Nevada, is purposefully pursuing a “deliberate ramp-up.”
“We’re not required under our PPA with NV Energy to be fully ramped up until January 2017 so we’re taking things slowly,” Grikas said. “This was also accounted for in our financial modeling, so we’re meeting our commitments both to NV Energy, as well as meeting our revenue requirements.”
A fully ramped up Crescent Dunes is promising 500,000 MWh a year from its single 110-megawatt tower surrounded by more than 10,000 heliostats. Pound for pound, that would make it a heavier hitter than the three-unit, 377-MW, direct-steam Ivanpah plant, whose backers once talked of producing around 975,000 MWh annually but now would be happy to reach 780,00 MWh, the sum of the plant’s long-term minimum contractual obligations. (Energy storage also means Crescent Dunes doesn’t require the substantial natural gas that Ivanpah gobbles up to prime the system in the morning and keep it from locking up overnight.)
But that’s assuming it all works. Crescent Dunes isn’t the first plant of its type — the 20-MW Gemasolar tower in Spain has been in operation since April 2011, seemingly without issue, although I’ve been unable to determine if it has reached its annual generation target of 110,000 MWh/year — but it does represent a big scale-up of the basic technology.
Crescent Dunes took longer to build and commission than expected, so it will be interesting to see if it can indeed hit full stride next year. Lots of interested parties will presumably be watching closely. SolarReserve’s technology is proving to be attractive around the world, with a 100-MW project under construction in South Africa and another, a tower/PV combo totaling 260 MW, planned for Chile. And just last week, SolarReserve signed a memorandum of understanding with the state-owned Shenhua Group “to build 1,000 megawatts of solar thermal projects in China.”
Crescent Dunes cost about $1 billion to build. In March, CEO Kevin Smith told SoCal Tech “we’re looking to cut costs 30 to 40 percent with the next group” of projects. For that kind of money — $650 million, say — you could build 350 MW of PV, and in a sunny Southwest U.S. location generate around 900,000 MWh annually.
That’s more than what Crescent Dunes hopes to deliver, true, but PV electricity has value challenges. There’s lots of it at the same time, it peaks around noon, and is largely a nonfactor come dinnertime, when demand remains high during summer in the West. Crescent Dunes, with its molten salt storage, plans to hum into the evening, giving the utility power when it wants it (not forcing it to take the power whenever it arrives).
If it succeeds as efficiently as planned, with costs coming down, Crescent Dunes might even be enough to give power towers a chance again in the United States, where planned projects have fallen by the wayside.
First, though, there’s this shakeout period, in which production seems to be an afterthought to testing, learning and fixing.
Grikas said the sophisticated software at the plant is working fine and “the core technology continues to perform quite well, with the molten salt receiver performing above the expected efficiency curve.” The work, she said, is in “getting the balance of system components in a first-of-its-kind facility up to full speed.”
She went on to say: “On a day-to-day basis, we have a punch list of items that we’re going through — similar to any type of new construction. We’re also running through various operational scenarios to ensure that the plant operators thoroughly know all the procedures and are comfortable with operating the facility under various conditions, which will in the long run help to maximize output.”
I finally caught up this morning with David Roberts’ excellent post on Vox about big solar, and noticed that in his discussion of capacity factor he mentions inverter load, saying “inverter load is important, though I won’t bore you by explaining it.”
But I will!
A good place to explore inverter load is the Solar Star Projects, a sprawl of ground-mounted solar panels straddling the LA-Kern County line in the Antelope Valley, on the edge of the Mojave, and which Dave mentions.
Technically speaking, it’s called the “Solar Star Projects” because there’s Solar Star 1 and Solar Star 2. But it’s correctly treated as one plant because 1 and 2 are conjoined, had the same builder, use the same SunPower systems, have the same power buyer (Southern California Edison) and charge the same price for their energy.
Dave labeled it the world’s largest solar plant at 579 megawatts. There is a plant in India that is said to come in around 600 MW, but I’ve never been able to get firm data on it and I’m not sure how much is actually operational, so I’m comfortable giving Solar Star the crown.
Turns out, too, that Solar Star is a little bigger than even the company that owns it says. According to the Western Renewable Energy Generation Information System database and filings by the builder, the plant is actually 586 MW. This is confirmed in a recent Fitch’s Ratings release on the plant, which noted: “The completed project’s capacity totals 586 MW of capacity, providing an additional 7 MW of capacity compared to design specifications.”
But enough of that – you came here to read about inverter load.
So as you probably know, inverters are the electronics that convert direct current (DC) output into alternating current (AC) before it goes onto the grid. This results in some loss in power, but systems are built with more DC (photovoltaics) power capacity than AC (inverter) power capacity. The ratio of PV to inverter is called the inverter load ratio, or ILR.
In its most recent report on utility solar trends [PDF], the Lawrence Berkeley Laboratory last fall noted that ILRs were climbing. That is, developers were installing more PV capacity per inverter capacity than they used to. Why? Well, one big reason is that, as Dave noted, PV has fallen in price so dramatically. A few more panels come cheap. Why not?
This doesn’t help the plant produce more peak power – the plant can’t produce more than its inverter capacity – but it does help it produce full power for more of the day. Instead of a production curve that peaks at somewhere between 11 a.m. and 1 p.m., you can get steady peak or near-peak production for several hours. This boosts capacity factor and can pay off for the electricity seller, as LBNL explains:
… with some utilities (particularly in California) offering time-varying PPA prices that favor generation during certain daylight hours, including late afternoon, many developers have found it economically advantageous to oversize the DC array relative to the AC capacity rating of the inverters. As this happens, the inverters operate closer to (or at) full capacity for a greater percentage of the day, which – like tracking – boosts the capacity factor, at least in AC terms…. (T)he resulting boost in generation (and revenue) during the shoulder periods of each day outweighs the occasional loss of revenue from peak-period clipping (which may be largely limited to just the high-insolation summer months).
LBNL says that back in 2010, ILRs were around 1.2, on average, and were often much lower than that. Now they’re just shy of 1.3 on average, and never under 1.2. Here’s a chart from the lab:
And, indeed, we can see this at Solar Star, where the PV panels add up to 747.29 MW of installed capacity. Divide this by the 586 MW of AC capacity, and you get a ratio of 1.28.
With this arrangement, Solar Star was able to operate at a remarkably high capacity factor in 2015: 35.2 percent.
The plant generated 1,663,593 megawatt-hours of electricity, as reported by the Energy Information Administration with – this is an important point here – a plant capacity of 540 MW. Why 540 MW and not 586 MW (or even 579)? Because the entire plant wasn’t online for the whole year – construction began in 2013 and big blocks gradually came online until the whole thing was done in late June 2015. Taking into account exactly how much capacity was online ever day of the year in 2015, the average daily capacity was 540 MW.
You might be curious how much Southern California Edison paid for this energy. Well, the PPAs aren’t public, but FERC records show the total for the year to be $157,180,118, or $94.48/MWh or, to put it in the units you see on your electricity bill, about nine and a half cents per kilowatt-hour.
This, however, masks the extreme variability in pricing. As LBNL noted, when the electricity flows to the utility can make a big difference in how much it pays. At Solar Star, Southern California Edison paid as little as $49.99/MWh during offpeak hours in the first quarter of the year. But in the third quarter – July, August and September, when California energy use often peaks – it paid $251.40 for “onpeak” electricity.
I don’t know exactly how these periods are defined in the Solar Star contracts (there’s one for each “unit” of the plant), but if you read the footnotes to my Crescent Dunes post a few weeks ago (and who didn’t), you know that one California solar PPA I did see defined the peakiest peak as weekdays from 1 p.m. to 8 p.m. during July, August and September.
So you can see why solar power developers will take readily add more cheap PV – leading to a higher ILR – in order to boost generation as the afternoon wears on.
One last thought. The overall average price of nearly 10 cents/kWh paid in 2015 emphasizes again how quickly solar prices have fallen. The Solar Star contracts are about five years old. That means that the price of solar has fallen by half or more in five years, with no change in the regulatory structure. Pretty impressive.
So after seeing the capacity chart, a commenter thought a chart based on generation would be interesting. Here it is. A couple of things to note: EIA reports generation in thousands of megawatt-hours, nothing smaller, and they round to the nearest whole number. So at the very low end the per capita figures are probably skewed a bit. Also, while differences between per capita capacity and generation rankings can probably be attributed to one state having better-producing solar (better resource, higher proportion of utility-scale, etc.), when the capacity was installed in 2015 will also influence rankings. For instance, if a state saw a relatively large amount of solar get installed late in 2015, that would boost its capacity ranking without providing much generation for the year.And one other thing: Remember. this is per capita, not per household as electricity use is often described.
NOTE: See the short update at the end of the post.
The nation’s largest solar industry group is objecting to an attempt by Pacific Gas & Electric to eliminate a hefty batch of solar power solicitations set for this year and 2017, in part, the group said, because the utility could be mistaken if it thinks the price tag will go down in the future.
In a January petition to the California Public Utilities Commission, PG&E said it doesn’t need additional solar power plants to meet its near- and medium-term obligations under the state’s Renewable Portfolio Standard, which requires the utility to get a third of its power from renewables by 2020, rising to 50 percent by 2030. PG&E added that contracting for more solar now could hurt ratepayers, given that the cost of renewable energy is trending down and that new “more efficient and cost-effective” technologies could become available if it waits.
The precise amount at issue isn’t explicitly spelled out in the petition, but it looks to be 136.5 megawatts, which on an annual basis could produce electricity equal to the amount used by about 50,000 California households.
Originally, the power was part of a special “PV program” intended to develop 500 megawatts of solar within PG&E’s territory at plants ranging in size from 1 to 20 megawatts, on the smaller side for utility-scale power in California. Half the power was to be owned by PG&E, the other half was to be obtained through power purchase agreements.
But in 2014, PG&E sought to cut short the program two years and around 210 MW shy of completion, transferring the remaining portion half to a scheduled 2015 auction and half to the 2016 and 2017 solicitations it now wants to eliminate. In December, the utility executed four power purchase agreements totaling 73.5 MW rolled over from the PV program.
Responding this week to PG&E’s petition, the state’s Office of Ratepayer Advocates gave a thumbs up. “Given PG&E’s current RPS portfolio and compliance position, it is unnecessary to lock ratepayers into long term contracts at the current market price,” the ORA said.
But the Solar Energy Industries Association, the voice of U.S. solar, asked the CPUC to deny PG&E’s petition. The group argued, for one thing, that the assessment that PG&E is in good shape vis-à-vis the RPS was based in part on the assumption that the 2016 and 2017 solicitations would happen. The group noted that when PG&E asked to end the PV program and move the unused megawatts over to the other auction mechanism, the utility said doing so would “result in procurement that better matches PG&E’s demonstrated RPS need, which is later in the decade and beyond.”
Plus, the group said, PG&E won’t necessarily be able to get cheaper renewables by kicking the solar can down the road:
“Undergoing solicitations in 2016 and 2017 will allow developers to take advantage of the recently extended 30% Investment Tax Credit and thereby lower their bid price – a benefit which will pass through to PG&E’s customers in the form of lower cost renewable energy. Forestalling additional procurement for several years will preclude PG&E from capturing the ITC benefit for its customers.”
The ITC was set to fall to 10 percent for utility-scale projects at the end of this year, but in December Congress passed an extension and gradual phase-out. The credit remains at 30 percent through 2019, falls to 26 percent in 2020, 22 percent in 2021 and then 10 percent thereafter.
As for the “new technologies” argument by PG&E, the SEIA said such developments are spurred by procurement, not by sitting back and waiting for them to happen.
“In order for there to be market innovation and the creation of new and more cost efficient technology, there has to be procurement,” SEIA wrote. “Indeed, that was the very purpose behind the Commissions approval of PG&E’s PV program – i.e., promoting the development of a certain technology, smaller scale PV. Forgoing all renewable solicitation for the next few years undermines rather than enhances PG&E’s future opportunities to procure RPS resources using better technologies at lower prices.”
UPDATE: The Sierra Club has joined in opposing PG&E on this. Like the solar folks, the Sierra Club says these solicitations are baked into all the decision-making that’s already gone down on PG&E’s RPS requirements. The club notes, as well, that “many potential bidders will have already begun the resource-intensive process of preparing the system impact and interconnection studies PG&E requires.”
UPDATE: Footnotes have been added to elaborate on a few of these items, most notably the comparative price of energy between Ivanpah and Crescent Dunes.
It uses mirrors and a giant tower, like the Ivanpah Solar Electric Generating System in California, and molten salt like Solana Generating Station in Arizona. But SolarReserve’s Crescent Dunes, now in “full commercial operation” [PDF], is different from any large-scale power plant that came before it in several important ways.
1. Unlike Ivanpah, Crescent Dunes, in Nevada, was built with the ability to store energy and dispatch power when needed.
At Crescent Dunes, giant mirrors focus the sun’s energy at the top of a tower, heating a mixture of sodium and potassium nitrate. This molten salt can be used immediately to superheat water and produce electricity in the manner of any other thermal power plant. Or it can be stored in insulated tanks to drive the thermal-power process during periods of cloudy weather or at night.
At Ivanpah, the “heliostats” focus the sun’s energy atop towers to heat water, which won’t hold the heat for long. That means the vast bulk of Ivanpah’s production comes at the same time the California grid is being fed large and rapidly increasing amounts of power from solar PV plants. Ivanpah can provide a smoother flow of electricity than a PV plant, but its value is still limited by immediate reliance on the sun.
2. Solana can store energy, too, but Crescent Dunes claims an advantage over the Arizona plant.
As SolarReserve CEO Kevin Smith told me last year: “We’re using molten salt directly,” giving Crescent Dunes the ability to drive the temperature of the heat-holding salts 300 degrees higher than at Solana, where long rows of parabolic mirrors are used to first heat a transfer fluid. “They need two or three times the salt we have to get the same amount of heat storage,” Smith said. That leads to a bigger, more expensive footprint – “a whole lot more tanks, pumps and salt.” In sum, Smith said, the multistep nature of the Solana process results in less efficient operation.
3. Unlike Ivanpah, Crescent Dunes doesn’t burn fossil fuels.
In 2014, Ivanpah used 867 million cubic feet (mmcf) of natural gas. It helps jump start the system in the morning, mostly, and to get through some cloudy periods. At a typical gas-fired power plant, that would produce around 85 gigawatt-hours of electricity. Ivanpah produced 420 GWh in 2014 – so you could say natural gas use was equal to about 20 percent of the plant’s output. This is way over the 5 percent allowed by California regulations, but a California Energy Commission spokesman said much of the natural gas Ivanpah uses isn’t held against it.
“(N)atural gas used between the end of daily generation and the start of generation the next day is not considered as contributing to electricity generation and therefore, not included in calculating the percent of non-renewable fuel used at the facility,” the CEC’s Michael Ward said in an email earlier this month.
Ivanpah’s output jumped up to 652 GWh in 2015, so if natural gas use held steady, the plant’s generation-to-gas-use ratio would have improved substantially. But while we won’t know exactly how much gas Ivanpah used in 2015 for a few months, some hints are available: Between August and November in 2015, gas consumption at one of its three units was double what it was in 2014.
4. Crescent Dunes should break out of the gate faster than Ivanpah.
Ivanpah went into full commercial operation in February 2014, not even three and a half years after construction began. Despite being one-third the size of Ivanpah, Crescent Dunes took at least four years to achieve that status.NOTE A One reason Crescent Dunes was slower to start up: SolarReserve saw what happened when Ivanpah’s early production fell dramatically short of ultimate expectations.
“We certainly recognized that Ivanpah got hammered,” Smith told me. “From a management perspective, that led us to want to be more cautious.” That was a year ago, when Crescent Dunes seemed on the precipice of startup, but it wasn’t until today that SolarReserve heralded the plant’s opening.
After the fact, Ivanpah’s operators said they expected all along that it would take up to five years to hit long-term performance targets. But they didn’t make that clear at the plant’s grand opening.NOTE B And, as my reporting has revealed, performance has even fallen short of contractual obligations that anticipated a slow start.
After taking extra time to dial in performance, SolarReserve was confident enough to say today that “Consistent with the rollout plan, the facility will ramp up to its full annual output over the coming year.” The target number: 500 GWh/year beginning in Year 2. Yes, we will be watching.
5. Crescent Dunes electricity is less expensive than Ivanpah electricity.
Crescent Dunes is selling its output to NV Energy for 13.5 cents per kilowatt-hour, rising 1 percent a year during the life of the 25-year power purchase agreement. Ivanpah’s contracts with PG&E and Southern California Edison are confidential, but filings with the Federal Energy Regulatory Commission show that during the high-demand July-September period last year, the utilities paid between 20 and 22 cents per kWh for Ivanpah electricity.NOTE C During the same period, Solana sold electricity to Arizona Public Service at 12.8 cents/kWh.
Oregon’s solar power industry revved up in 2015, with employment growing by 42.8 percent to 2,999 workers as of November, according to a new report from the research group The Solar Foundation.
The gain of 899 workers put Oregon 16th in the nation in solar jobs, 13th on a per capita basis. The Solar Foundation said growth is unlikely to be as robust in the current year, but the solar workforce should still increase by 14.9 percent, or nearly 450 jobs, in line with a national forecast of 14.7 percent growth.
One reason for Oregon’s strong growth, as highlighted in the report: “Oregon added more than 19 megawatts (MW) of solar photovoltaic (PV) capacity in 2015 through Q3, which is twice the capacity installed in the state in the previous year (8.2 MW).”
But the solar industry in Oregon looks a little different than the national picture, which shows 57.4 percent of jobs in installation and 14.5 percent in manufacturing (those are the top two subsectors). In Oregon, the breakdown is a somewhat lower 50 percent in installation and a vastly higher 38.3 percent in manufacturing. That’s largely thanks to SolarWorld, the German company that has its U.S. headquarters and a big plant in Hillsboro, in Washington County. Big as it is, so goes SolarWorld, so goes Oregon solar, to an extent.
Employment at the plant reached 1,000 in late 2010, but then rapidly reversed course, heading below 700 as the company contracted in the face of an onslaught of cheap, heavily state-subsidized solar panels from China. SolarWorld fought back, winning trade sanctions for unfair practices by those Chinese competitors, which brought some relief, and the company announced in October 2014 that it would begin adding jobs again.
Spokesman Ben Santarris said 150 new workers have come aboard since then, and that when ongoing expansions are completed in the third quarter this year “we should reach employment of 900.”
Nationally, the Solar Foundation reported 208,859 workers as of November 2015, a 20.2 increase from November 2014. California leads the nation in solar jobs with 75,598.