UPDATE (August 9, 2016) — In a filing today, NRG Energy confirms that Units 1 and 3 met their production requirements under the forbearance agreements, extending those agreements through January 2017. From the filing: “Subsequent to the close of the second quarter of 2016, each of Ivanpah’s unit 1 and unit 3 satisfied their respective production requirements for the initial six-month measurement period under the forbearance agreements.” H/T to NRG’s David Knox for the notification.
Energy production was up at Units 1 and 3 at Ivanpah in the first half of 2016, despite a highly publicized fire in May, suggesting the solar power plant is likely to get additional time as it works to make good on its contracts with Pacific Gas & Electric.
Ivanpah failed to meet guaranteed production minimums for the PG&E-contracted units in the plant’s first two years of operation, 2014 and 2015, and faced default. But PG&E and California regulators granted the plant, led by majority owner and operator NRG Energy, a reprieve – “forbearance agreements” that put the original power purchase agreements, with their escalating production requirements, on hold while Ivanpah tries to step up its game.
The forbearance agreements run for an initial period of six months – February 1 through today – and call for a six-month extension “if the Projects meet certain production requirements during the initial six-month period,” according to California regulators (PDF).
Those “certain production requirements” are confidential, but reports to federal energy agencies* indicate the two units that sell power to PG&E have performed well, with generation from February 1 through June 30 of 221,271 megawatt hours, a 16 percent increase compared to the same period in 2015. It’s an increase of 87 percent over 2014, as well.
Assuming July proceeded without incident and that the six-month thresholds weren’t onerous, that would seem to set the plant up for another six months of forbearance. That would then give Ivanpah the opportunity to face the next year of its PG&E contracts, which measure performance on a two-year rolling basis, without the burden of its dismal first year.
“While the fire obviously impacted our operations, we are pleased with our generation on all units since coming back online,” NRG spokesman David Knox said in an email. “We will be reporting the six month forbearance results to PG&E in August.”
NRG has described a number of engineering fixes that have helped improve performance – see this piece by Susan Kraemer for details. It’s also true that Ivanpah is using significantly more natural gas this year than in its first two years of operation.
The plant uses “night preservation” boilers to keep seals intact overnight and “auxiliary” boilers to get it jumpstarted in the morning. The auxiliary boilers are also used in “supplementing solar generation during periods of transient clouds or at the end of the day,” according to technology provider BrightSource.
From January through May, the two PG&E-contracted units together used 381.2 mmcf of natural gas – 188.5 mmcf for Unit 1 and 192.7 mmcf for Unit 3. That’s an increase of 42 percent over the same period in 2015.
Still, each unit is allowed to use 525 mmcf annually (up from the original cap of 384 mmcf), so it doesn’t look like staying under the limits will be a big problem.
*Reports to the Federal Energy Regulatory Commission provided quarterly data for January through June. Reports to the Energy Information Administration provided monthly data for January through May. The reports are generally 99.5 percent consistent with each other, and were blended to determine output for the February 1-June 30 period.
If you’ve heard of Ivanpah, you’ve heard of “streamers” – birds set aflame in flight, raining fire from the sky with regularity, at the Ivanpah Solar Electric Generating Station in California..
Well, a newly published peer-reviewed study indirectly suggests the plant might have gotten a bum rap with all that talk.
The widely accepted view of Ivanpah as a massive bird incinerator has its origins at the National Fish and Wildlife Forensics Laboratory. Staff from the lab, as well as U.S. Fish and Wildlife Office of Law Enforcement personnel, visited Ivanpah for a few days in October 2013 and wrote of seeing “streams of smoke rise when an object crosses the solar flux fields aimed at the tower.”
Fried birds, they presumed.
When told by Ivanpah employees that many of the streamers weren’t birds but were instead insects or debris, the feds weren’t completely dismissive, but they sounded skeptical. After all, they wrote, “there were instances in which the amount of smoke produced by the ignition could only be explained by a larger flammable biomass such as a bird.” Plus, they has “observed birds entering the solar flux and igniting, consequently becoming a streamer.”
Eventually, their observation of seeing “a streamer event every minute or two,” became the incendiary lead to an Associated Press story about Ivanpah and birds.
But it turns out more streamers than they thought might not be birds.
In May and September of 2014, a team from the U.S. Geological Survey conducted research at Ivanpah into ways of “detecting animals flying around solar power towers.” To do so, among other things they set up sophisticated video cameras and radar equipment and conducted hundreds of hours of surveillance.
Their equipment captured a lot things flying around the towers, and after looking at all the images and videos they made some observations:
Now, this doesn’t prove that Ivanpah isn’t a threat to birds (and it says nothing about the plant’s impact on desert tortoises, or the worthiness of its technology). Birds are killed at the plant, although not in nearly the numbers some had projected. But it is a reminder of the power of provocative language and images to overwhelm a complex risk-benefit question.
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.”
That’s the claim from a Forbes contributor, but I don’t see it. In the last four years (ending with 2014), imports have made up 32, 34, 33 and 33 percent of electricity in the state.
UPDATE: About 10 days after original publication, NRG got back to me with corrected and previously missing data, necessitating minor changes throughout this piece. The upshot: Gas usage was up 62 percent, not 59 percent, in Year 2, and emissions were 229 pounds CO2-equivalent per MWh in Year 2, not 225.
Natural gas consumption at Ivanpah, the controversial power plant in the California desert, increased 62 percent in its second full year of operation, and the plant emitted the equivalent of about 229 pounds of carbon dioxide for each megawatt hour of electricity it generated.
How’s that compare?
It’s about one-fifth the emissions of the average U.S. power plant and a bit over one-quarter the emissions of a recently built combined cycle natural gas-fired power plant in California.
But of course Ivanpah is considered a renewable energy source by the state, like utility-scale solar PV, which according to the National Renewable Energy Laboratory puts out 18 to 22 pounds of CO2 per megawatt hour of energy produced. In other words, CO2 emissions at Ivanpah are at least 10 times those of solar PV.*
Ivanpah used 1,251 million cubic feet (mmcf) of gas in the 12 months ended January 31, a figure based on preliminary data obtained from the U.S. Energy Information Administration.
The $2.2 billion Ivanpah Solar Electric Generating System, with tens of thousands of reflecting mirrors and giant “power towers” that heat water to generate thermal power, was fully online by February 1, 2014. It generated 430,488 MWh of electricity in its first 12 months of operation, according to the EIA, while consuming 773 mmcf of natural gas. That slow start left the plant in danger of defaulting on its PPAs with the utility PG&E (see: “Ivanpah Not Out of the Woods Yet“). In Year 2, the plant produced 655,926 MWh of electricity, a 52 percent increase.
Under its original licensing, Ivanpah’s three units were permitted to burn a total of 984 mmcf of natural gas annually. But a few months after the plant began commercial operations, Solar Partners – consisting of majority owner NRG, along with Google and technology developer BrightSource Energy – asked and then received approval from the California Energy Commission to use as much as 1,575 mmcf in a year.
So in Year 2, Ivanpah ended up using about 25 percent more gas than originally planned, but about 22 percent less than the revised limit.
The overall limit isn’t the plant’s only consideration when it comes to natural gas, however, not with PG&E and Southern California Edison counting Ivanpah electrical output toward their obligations under California’s renewable portfolio standard. To qualify as a renewable energy source, state law limits the amount of “non-renewable energy that may be included with renewable energy at no more than two percent of total fuel use.” But the law allows wiggle room up to 5 percent in special circumstances, an allowance granted to Ivanpah.
Is Ivanpah using less than 5 percent natural gas?
Depends on how you look at it.
Ivanpah relies on gas in “night preservation” and “auxiliary” boilers. As BrightSource has explained, “night preservation boilers are very small boilers used overnight to maintain seals and preserve heat.” As for the auxiliary boilers, again quoting BrightSource, they are used for:
BrightSource says “this type of natural gas does not produce electricity. In fact, it increases the amount of electricity produced through the sun.”
The gas used at Ivanpah in Year 2 would have produced 180,000 MWh at a modern natural gas-fired power plant like the Lodi Energy Center, opened in late 2012. Although that’s equivalent to 27 percent of Ivanpah’s total Year 2 electricity generation, regulators say Ivanpah has not been using more than 5 percent non-renewable fuel.
That’s because the regulators don’t count most of the fuel used for the purposes listed by BrightSource. If the gas wasn’t burned between the start of generation and the end of generation each day, it’s like it didn’t happen.
This allows NRG to say that less than 5 percent of the electricity generated at Ivanpah resulted from burning natural gas. (Under this calculation, in Year 2, 4.3 percent of electricity generated at Unit 1 came from burning gas; 4.1 percent at Unit 2; and 4 percent at Unit 3. Overall, the figure was 4.1 percent.)
But of course, the gas used for all the other purposes at Ivanpah was still burned, and presumably because it had to be in order for the plant to function. And the emissions were still emitted.
As Dan Danelski revealed last year in the Riverside Press-Enterprise, Ivanpah’s emissions are hefty enough to qualify it as a polluter under California’s cap-and-trade program.** Based on its natural gas consumption, emissions in Year 2 of the plant’s operation were about 68,097 metric tons. That’s 150,128,000 pounds – thus the 229 pounds per megawatt hour figure.
The Lodi gas-fired power plant pumps out about 837 lb/MWh.
It’ll be interesting to see what happens to Ivanpah’s gas consumption in Year 3. The most notable trend evident in Year 2 was a big increase in use at the end of the year – in the three month period from November 2015 through this January, consumption was up 142 percent.
*NREL estimates full life-cycle emissions for solar PV at 88 lb/MWh, with 21 to 26 percent attributed to operational processes, including power generation and system operations and maintenance. See this PDF.
**Danelski reported on 2014 calendar year emissions. But the three Ivanpah units began delivering electricity at various points in January that year, and NRG and PG&E are using February 1, 2014, as a starting point in measuring performance of the two units under contract to PG&E. This analysis follows suit for the entire plant.
In “forbearance agreements” recently approved by California regulators, Pacific Gas & Electric has given the owners of the Ivanpah solar power tower plant up to an extra year to reach energy production levels called for in contracts for two of the plant’s three units. Based on how those units have done so far and what will be required down the road, achieving those minimums won’t be easy.
New data from the U.S. Energy Information Administration indicate that for the first 24-month measuring period called for under the PG&E power purchase agreements, Unit 1 fell 61,692 megawatt hours shy of the 425,600 MWh production guarantee apparently set out in the PPAs. The slightly more powerful Unit 3’s production gap was even greater, 103,544 MWh, toward a goal of 469,840 MWh.
That said, in their second full year of operation, which officially ended at the close of January this year, both units performed much better than in their first year, with Unit 1 production up 29 percent and Unit 3 up 34 percent.
Here’s the issue, though: Under the PPAs, the bar rises. This snippet, from a BrightSource Energy filing several years ago, is what we know about the confidential PPAs (Solar Partners II is Unit 1 and Solar Partners VIII is Unit 3):
So instead of hitting 140 percent of “contract quantity” in a 24-month period (or 70 percent per year on average), Solar Partners now apparently needs to ratchet production up to 160 percent (or 80 percent per year on average). California Public Utility Commission documents related to the recently approved forbearance agreements note that this is a rolling 24-month measurement period, so every month from now on, for the life of the 25-year contracts, the units must hit 160 percent of the annual contract quantity for the preceding 24 months.
Those forbearance agreements push that requirement out six months, at least, and more likely for a year — so it’ll be starting next February, then going forward, when this new target will have to be met.
It will require major increases in production.
Take Unit 1. Its 24-month target — that is, the minimum it needs to produce to avoid being in default — come February 2017 will be 486,400 MWh. With 213,126 MWh in the 12 months ended January 31 this year, that means the unit will need to generate 273,274 MWh over the following 12 months – an increase of 28 percent. That’s as big an increase as it had this past year, but off a larger base.
The challenge for Unit 3 is even steeper. It will need to increase production from 220,595 MWh to 316,365 MWh to reach a target of 536,960 MWh. That’s a 43 percent increase, a significant step up from the 34 percent increase the unit managed from Year 1 to Year 2, and again it’s coming off a larger base.
Four big developments reflected in this chart: the closure of the San Onofre Nuclear Generating Station, the impact of the drought, and the rise of both solar and wind.
Output at San Onofre bounced around in the ten years before it shut down in 2012 – it hit a high of 18,399,596 megawatt hours in 2005 and then sunk to a low the next year, at 13,567,626 MWh. The average over the period was 16,332,433 MWh, about 8 percent of California’s in-state energy generation. So you can see what an emissions-free energy loss the plant’s closure was for the state. But it’s gone, gone, gone, and nothing’s gonna bring it back.
Hydroelectric is a different story, its decline a product purely of the drought. In the decade before the drought began, the state on average got nearly 17 percent of its in-state generation from hydro. In 2015, hydro’s share was 7 percent, so you could say the drought cost California 10 percent of its clean energy generation.
Solar and wind have made up for some of these losses. Wind grew substantially up to 2013 and has been stable at around 6 percent of generation since then (despite the “wind drought” of the first half of 2015), while solar, still on the move, climbed to about 10 percent of generation in 2015, from just 0.2 percent a decade before.
This year, 2016, should see a pretty hefty jump in clean-energy generation in California as wind ticks up slightly, solar continues to surge and, with a decent Sierra snowpack in place, hydropower recovers at least somewhat.
Many climate-change activists are uncomfortable with the idea of swapping an end to the oil export ban for an extension (and eventual phaseout) of tax credits for solar and wind. But how does the deal pencil out on carbon emissions? I took a whack at the math.
GTM Research says the proposed extension of the solar investment tax credit will result in an additional 25 gigawatts of solar power capacity in the United States by 2021, around 62% of that utility-scale solar. Assuming capacity factors of 25% for utility and 18% for non-utility solar, this would produce about 27,000 GWh of electricity per year beginning in 2021.
If all that electricity displaces average grid electricity, it would result in an annual cut in carbon emissions of 13.5 million tons beginning in 2021 (27,000 x 500). Accounting for those 25 GW of additional solar arriving incrementally from 2016 through 2020, the total carbon emissions reduction brought about by the extension of the solar investment tax credit would be 108 million tons for the 10-year period 2016 through 2025.
Bloomberg New Energy Finance sees the five-year gain in solar being less robust that GTM, at 14.8 GW, which would shrink the cut in carbon emissions to about 64 million tons over the next 10 years.
On the wind side, BNEF estimates the PTC deal resulting in 19.3 GW of additional wind capacity through 2020. Assuming a capacity factor of 32% and using the same basic formula as with solar, this translates to decreased carbon emissions of 162 million tons from 2016 through 2025 thanks to the wind PTC component of the omnibus deal.
So with solar providing 64 million to 108 million tons in decreased carbon emissions over the next ten years and wind contributing a cut of 162 million tons, the proposed PTC/ITC extensions will bring total carbon emissions reductions of between 226 million and 270 million tons.
Meanwhile, Michael Levi estimates that on the higher side, lifting the oil export ban will result in “10 million tons a year of additional carbon dioxide emissions on average over the next decade,” or 100 million tons in ten years.
So in this very simplified analysis, the PTC/ITC extensions result in a net decrease in total carbon emissions of between 126 million and 170 million tons for the period 2016 through 2025.
UPDATE: A more sophisticated analysis has now arrived from Levi and Varun Sivaram! They show an even bigger win in carbon reductions with the deal:
The net impact of the exports-for-renewables-credits trade, then, is to reduce carbon dioxide emissions by at least 20-40 million metric tons annual over the 2016-2020 period. The most likely emissions reduction in our estimate is around 35 million metric tons. The climate benefit of the tax credit extension is over a factor of ten larger than the climate cost of removing the oil export ban over this period.
Levi and Sivaram get to their bigger number in part by assuming higher capacity factors for utility-scale solar (30%) and for wind (37%). (Thirty percent capacity factors are common for big utility-scale solar in the Southwest (see this story of mine from March), although elsewhere solar doesn’t do as well. Where the new solar comes will be a big factor in determining actual capacity factors. For wind, LBNL sees capacity factors in the 32-35 percent range. Again, where the new wind power comes will be a big factor in determining how productive it is.)
An even bigger factor in their outcome is the assumed carbon intensity for the generation displaced by solar and wind, between 640 and 800 tons/GWh vs. my 500. My number was based on EIA data showing total generation in 2013 of 4,065,964 GWh and emissions of 2,172 million tons for the electric power sector.