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Wind Ramps Up, Solar Emerges

2005-15 Renewables

China Has Way More Turbines, but US Is Still Tops in Wind Energy

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.

china-us wind cap-gen

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.

Top Solar States: Per Capita PV Generation

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.

state per capita solar generation

Top Solar States: Per Capita PV Capacity

state per capita solar-b

With Newport facility in sight, wave energy prepares for $1M win in Salem

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….

See my story on the Portland Business Journal website.

PG&E Wants to Ditch Big Batch of Planned Utility-Scale Solar

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.

A 15-megawatt Five Points solar plant near Fresno,, built under PG&E's truncated "PV program."

The 15-megawatt Five Points solar plant, built under PG&E’s truncated “PV program.”

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.”

5 Ways Crescent Dunes Solar Isn’t Ivanpah (or Solana)

Crescent Dunes, near Tonopah, Nevada (photo from SolarReserve)

Crescent Dunes, near Tonopah, Nevada (photo from SolarReserve)

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.


A. I used the “Break Ground” and “Start Production” information from NREL’s website to determine how long it took to build each project. Another way to measure is from close of financing to the beginning of delivery of electricity under contract. That stretches the difference between Ivanpah and Crescent Dunes. Ivanpah took from April 2011 to February 2014 – about two years and 10 months. Crescent Dunes took from September 2011 to sometime in November 2015 – a period of four years and two months.

B. In all their communications around the plant’s opening as it was happening, Ivanpah’s developers didn’t talk about a long ramp-up. However, as first reported last June, in SEC filings in 2011 BrightSource Energy noted that “initial performance will be less than full design,” then would rise due to “realization of the operator’s learning curve, procedural optimization, and fine-turning of equipment and systems for increased plant performance.” The company went on to say “this ramp-up process may last up to four years.”

C. Did I overstate the Ivanpah-Crescent Dunes energy price gap? It’s worth a closer look, starting at Crescent Dunes. The price NV Energy pays, to be precise, is $134.95 per megawatt-hour in the first year of the contract and, as mentioned, it rises 1 percent each year of the 25 year contract. My math says that takes the price on an escalator to around $173/MWh by 2040.
Because they’re still confidential, the Ivanpah contracts (“contracts” because electricity from two units goes to Pacific Gas & Electric, and from another unit to Southern California Edison) are more difficult to pin down. But we do know from SEC filings that “the Ivanpah PPAs include time-of-day (TOD) pricing.” And a closer look at FERC reports reveals how dramatically that can impact what the utilities actually pay.
In the post, I gave a price range for the third quarter. Here are the average weighted prices to the penny, broken down by unit:
Unit 1: $197.33/MWh
Unit 2: $220.51/MWh
Unit 3: $201.99/MWh
But check out the figures for the fourth quarter, the most recent reporting period.
Unit 1: $134.84/MWh
Unit 2: $117.44/MWh
Unit 3: $137.91/MWh
Huge difference. Clearly when Ivanpah delivers energy has a huge impact on the price of that energy. To get a better sense of how this might work, I dug up a power purchase agreement that PG&E did to buy 48 MW of PV power from the Copper Mountain Solar Facility, a sprawling 458-MW plant in southern Nevada. Because the plant has now been delivering power for more than three years, the contract details are no longer confidential.
That contract, signed way back in 2008 when solar PV was a lot more expensive, sets a delivery price of $139/MWh – but then multiplies that price by a factor depending on the month, day and hour of delivery. For instance, if the energy is delivered from June through September on a weekday between 1 p.m. and 8 p.m., the $139/MWh figure is multiplied by 2.01, jacking the actual price up to $279.39/MWh. But if the energy is delivered on a weekday from March through May between 7 a.m. and noon, or pretty much any time on a weekend or holiday, the price is multiplied by 0.86, yielding an actual price of $119.54/MWh.
We don’t know the base price at Ivanpah, and we don’t know to what degree the Ivanpah deals mirror this one. But clearly the third-quarter prices I used were at the very high end of what Ivanpah electricity costs the utilities that purchase it. When you look at the FERC reports and add up all the numbers and average out all the mysterious up and downs in the price for Ivanpah’s electricity throughout the year, you end up with:
$162.49/MWh, or 16.2 cents/kWh.
Last thought to this ridiculously long footnote: This price comparison is a pretty crude measure of the “value” of these groundbreaking technologies. It doesn’t factor in the presumably higher cost of permitting and building in California, nor does it look at the solar resource each site offers, which can have a significant impact.

Oregon’s Solar Workforce Grew 42.8% in Past Year

Baldock Solar Station, south of Wilsonville off I-5, opened in January 2012. Photo by Pete Danko.

Baldock Solar Station, south of Wilsonville off I-5, opened in January 2012. Photo by Pete Danko.

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.

Washington County is home to the big SolarWorld manufacturing plant. Chart from http://solarstates.org/

Washington County is home to the big SolarWorld manufacturing plant. Chart from http://solarstates.org/

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.