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.
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.
Two Oregon teams are among the finalists selected today in the Wave Energy Prize, a U.S. Department of Energy competition to double the energy captured from ocean waves. One is the familiar Salem-based M3 and the other is a new name in the wave game, Portland-based AquaHarmonics.
The teams, both with Oregon State ties, were selected along with seven other teams to construct 1/20th-scale models of their wave energy converters. As finalists, they’ll receive up to $125,000 to ready their devices for testing this summer at the Navy’s giant Carderock MASK Basin wave tank in Maryland. Assuming they meet a cost-efficiency threshold set for the competition, the first-place winner could receive $1.5 million, second place $500,000 and third place $250,000.
The competition began with 92 entries, then was trimmed to 66 teams that submitted technical documents. Twenty teams were next selected as semifinalists and required to perform wave-tank tests of 1/50th-scale models.
Although Oregon State has a wave tank, in order not to confer a “home-field” advantage, AquaHarmonics and M3 were sent off to the University of Michigan to test their devices.
AquaHarmonics consists of Alex Hagmuller and Max Ginsburg, both engineering graduates from Oregon State, according to their Facebook page. Their device is described as a “point absorber with latching/de-clutching control.” Point absorbers bob at the surface to absorb the vertical motion of passing waves.
M3’s design is an adaptation of the APEX device that was tested off Camp Rilea in September 2014 – submerged but not on the ocean floor like APEX. Called NEXUS, it uses the change in pressure caused by passing waves to send air back and forth through a column, spinning a turbine.
The Pacific Northwest, home to much of the wave energy development in the United States, also has a third team among the finalists, Oscilla Power of Seattle. Their floating device is completely different from anything else, taking advantage of an effect called magnetostriction, caused by the constantly changing tension in the device’s tethers, to produce an electrical current.
Yes, China is using less coal, thanks in part to rapid expansion of renewables, as news reports today trumpeted, and Greenpeace reckons that led to a decline in CO2 emissions of 1 to 2 percent in 2015. But the country could be doing even better if it put its world-leading wind capacity to better use.
This fact was highlighted today when the American Wind Energy Association noted that in 2015, the U.S. remained the world’s top producer of wind energy.
This is startling given that China installed a staggering 23 gigawatts of wind power in 2014, then outdid itself last year by adding another 30 GW, driving total installed wind capacity to 145 GW, according to the Global Wind Energy Council. That’s nearly double the 74 GW that the U.S. had at the end of 2015.
Yet the U.S. wind fleet beat China’s in energy generation, 191 terawatt-hours to 185 TWh.
AWEA highlighted this gap two years ago, when the U.S. was at 61 GW of capacity and 168 TWh of generation and China was at 91 GW/136 TWh. China’s Achilles’ heel then was curtailment, the term for shutting down tubines because there’s no way to get the power to users on a congested transmission system. The situation apparently hasn’t improved. Earlier this month, the China Electricity Council talked (as translated by Google) about how “abandoning the wind” and “discarding light” – a reference to solar power – continue to be problems in particular provinces.
AWEA credited the U.S. edge to “strong wind resources and production-based U.S. policy (that) have helped build some of the most productive wind farms in the world.” It also noted that “upgraded transmission infrastructure in the U.S. also helps relieve congestion and bring more low-cost wind energy to the most densely populated parts of the country.”
Meanwhile, in China, curtailment knocked 15 percent off China’s wind generation in the first half of 2015, and the rate was 20 percent in western Inner Mongolia and 31 percent in Gansu, according to an October Reuters article. In those regions particularly, the transmission lines are inadequate and there’s not enough demand for the energy locally. Reuters said national authorities were trying to encourage those regions “to attract more energy-intensive industries from China’s east, helping to better absorb the supply of renewable energy locally.”
Sounds like a long-term project.
China has also been reducing the guaranteed payments or “feed-in tariff” for new wind projects, especially in the impacted regions. Wind Power Monthly reported in January that “the change is aimed at directing the onshore wind sector towards healthy and orderly development, for balancing the growth of new energies in various regions, and for enhancing the efficiency of renewable power subsidy payout.”
Curtailment is sometimes an issue in the United States, but a declining one. Although there hasn’t really been a big national commitment to build new and better transmission, regional efforts have paid off. A federal report last fall noted that ERCOT, which oversees the wind-heavy Texas grid, saw wind curtailment fall from 17 percent in 2009 to 1.2 percent in 2013. “Primary causes for the decrease were the Competitive Renewable Energy Zone transmission line upgrades, most of which were completed by the end of 2013, and a move to more-efficient wholesale electric market designs,” the report said.
Bruce Hamilton, an analyst at Navigant, said the fact that “the U.S. has such a great wind resource” could also be a factor in getting more bang for its buck out of wind. Plus, “the technology in the U.S. is the latest and greatest, and I’m not sure that’s the case in China, where they could be a generation behind.”
The U.S. lead over China might have been even greater in 2015 were in not for a strange U.S. wind drought, particularly in the West, in the first half of the year. From January through June, generation was down 5.6 TWh from the year before, despite increased capacity. The pattern changed in the second half of the year, and from July through December generation was up 14.8 TWh over that same period in 2014.
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.
The state legislature is poised to give Oregon wave energy backers what they hope will be an edge on any competitors — namely a California hopeful — in a quest to land a U.S.-supported wave energy test center….
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.”