Oregon has pulled back on its investment in ocean energy, but for now, at least, funding from the U.S. Department of Energy continues to flow to the Pacific Northwest.
The DOE on Monday announced contract awards totaling “up to $10.5 million” for projects by six ocean energy players, three of which are headquartered in or have significant operations in the region: Columbia Power Technologies, Oscilla Power and M3 Wave.
The individual award amounts weren’t disclosed and the companies will need to negotiate project terms with the DOE in the coming weeks. However, based on the earlier DOE funding opportunity announcement, it looks like Columbia Power Technologies is in line to receive $400,000 in the first phase of its project, with an additional $3.75 million possible in a second phase, while Oscilla and M3 are due to get $600,000 apiece for their projects.
Columbia Power is headquartered in Charlottesville, Virginia, but its product development team — a half-dozen engineers with deep Oregon State University connections — is in Corvallis. The company tested a small-scale prototype in Puget Sound in 2011 and 2012, and with $3 million from the Naval Facilities and Engineering Command, is due to try out a grid-connected, utility-scale version of its StingRAY device at a Navy test site in Hawaii in 2016.
From 2008 through the 2014 fiscal year, Columbia Power received project funding from the DOE’s Wind and Water Power Technologies Office totaling $7.5 million, and got $800,000 in grants through the federal government’s Small Business Innovation Research (SBIR) program.
The new project backed by the DOE is aimed at making it easier and less expensive to install and recover the StingRAY device, which bobs at the ocean’s surface and uses forward and aft floats to absorb the energy of waves.
Seattle-based Oscilla uses a device that resides atop the swells in deep water, as well. But it generates power in a very different way, taking advantage of an effect called magnetostriction, caused by the constantly changing tension in the device’s tethers, to produce an electrical current. The company has received four SBIR awards totaling nearly $1.8 million, and in August said it had been awarded a £500,000 contract by Scotland’s wave energy development agency to improve its power takeoff system.
The DOE said Oscilla will use the new award to “optimize the device’s storm-survival configurations, which will decrease the loads the device experiences during extreme conditions, thus lowering the resulting cost of energy.”
For M3, the new award would represent a big infusion for what has been a minimally funded effort — until now, it had received about $400,000 from the state of Oregon and $240,000 from the DOE, and founders Mike Morrow and Mike Delos-Reyes have retained their day jobs as engineers at Hewlett-Packard.
In an interview, Morrow wasn’t sure how the new backing might change that situation, and said ocean energy continues to be underfunded in the United States. Still, he said the award was a big boost that would “definitely help us do a lot of important work” in refining M3’s technology, which is based on a concept Morrow and Delos-Reyes came up with in 1991 while students at Oregon State University.
Unlike the other devices, the M3 wave energy converter is submerged in the water. Pressure changes from passing waves deflate an air bladder at one end of the device, pushing air through a column to a bladder at the other end. The flowing air, back and forth, turns a bidirectional turbine at the center of the column.
A one-fifth scale version of the device was tested for a few weeks off Camp Rilea in September 2014. Though successful, the test revealed potential issues with shifting sediment on the ocean floor. The new project “will explore ways to minimize effects of sediment transport,” the DOE said.
M3 is also a competitor for the DOE-sponsored Wave Energy Prize, which is searching for “game-changing performance enhancements” and offering $1.5 million to the grand prize winner. A field of 92 was narrowed to 20 in August and finalists are to be announced in March. But first, early next month, the Salem-based M3 will take a 1/50th-scale version of its new NEXUS model to Michigan for wave-tank testing as part of the contest. Oscilla Power is also in the competition, and will test its small-scale model in Maine next month.
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.
NOTE: This post has been updated and expanded for KQED News.
Ivanpah, the biggest power-tower solar plant in the world, is doing better after woeful energy production in its first year of operation in 2014. But not better enough.
In its quarterly report filed in November, majority owner NRG Energy says it faces a default on its contracts with Pacific Gas & Electric, which has power purchase agreements for production from two of the plant’s three units:
Ivanpah Energy Production Guarantee — The Company’s PPAs with PG&E with respect to the Ivanpah project contain provisions for contract quantity and guaranteed energy production, which require that Ivanpah units 1 and 3 deliver to PG&E no less than the guaranteed energy production amount specified in the PPAs in any period of twenty-four consecutive months, or performance measurement period, during the term of the PPAs. If either of Ivanpah units 1 and 3 deliver less than the guaranteed energy production amount in any performance measurement period, PG&E may, at its option, declare an event of default. Based on the energy production amount since January 2014, the Company expects that the units will not meet their guaranteed energy production amount for the initial performance measurement period. The Company is exploring options to mitigate this risk or its consequences.
Electricity production at Ivanpah was up 71 percent in the first nine months of 2015 compared to the same period in 2014. But 2014 was so dismal, the plant still won’t be able to meet the production guarantee outlined in SEC filings:
The “contract quantity” for each year is expected to be 304,000 MWH for Solar Partners II (Unit 1) and 335,600 MWH for Solar Partners VIII (Unit 3) throughout the delivery term, and the seller must deliver a guaranteed amount of energy in two-year measuring periods. The production guarantee generally is 140% of the contract quantity during the first measuring period after the commercial operation date and 160% in subsequent measuring periods, subject to reduction if the project company is unable to deliver power due to a force majeure or curtailment.
Unit 1 declared commercial operations on January 10, 2014, and Unit 3 on January 15, 2014. Through September 2015, Unit 1 had produced 319,994 megawatt-hours, according to the Energy Information Administration. Its production guarantee during the first measuring period works out to 425,600 MWh. Based on past performance and trend, the unit will probably fall at least 50,000 MWh short of that threshold. Unit 3 was at 311,057 MWh through September toward a goal of 469,840, so its shortfall will likely be even greater.
You have to wonder how PG&E might proceed here. Would it be interested in getting out of its Ivanpah contracts, if it could? The utility needs renewable energy, like that produced at Ivanpah, to meet California’s aggressive renewable portfolio standard. That said, the Ivanpah contracts date back several years (last amended in 2010, it appears), and renewable energy prices have plunged recently. Consider: In the third quarter of this year, PG&E paid $201.99/MWh for electricity from Ivanpah’s Unit 3. Meanwhile, PPAs for utility-scale PV in the Southwest in the past year have fallen to around—and in some cases below—$50/MWh.
Update: What about Unit 2, you ask? Electricity from Ivanpah Unit 2 (Solar Partners I) is sold under a power purchase agreement to Southern California Edison. The production standard for Unit 2 is essentially the same as for Units 1 and 3 and it, too, will fall well short two years after going into operation on January 31, 2014. So why did it escape mention in NRG’s filing? The apparent answer: The PPA with Edison doesn’t leave NRG (and minority owners BrightSource and Google) similarly vulnerable to a default declaration. According to a BrightSource filing, the contract stipulates only that “If these production levels are not met, the project company will have to pay SCE for replacement power.” (12/9/2015)