There was a lot of fanfare in February 2014 when the Obama administration announced Principle Power could submit a plan to build a 30-megawatt offshore wind farm in deep Pacific Ocean waters off the coast at Coos Bay, Oregon. U.S. Secretary of the Interior Sally Jewell came to Portland to publicize the decision, and joined then-Gov. John Kitzhaber in front of a gaggle of media. “Floating Wind Turbines Coming to Oregon Coast,” ClimateWire reported a day later. (Others were less exuberant.)
No such ceremony this past week, as the project’s demise was made official in a U.S. Department of Energy update to its Advanced Technology Demonstrations Program for Wind.
Media in Virginia first reported the feds’ decision after Dominion Virginia Power put out a press release that the DOE was jettisoning support for an offshore wind project that the company was planning to do off the coast at Virginia Beach.
That project and the Oregon one (plus a third off New Jersey, called Fishermen’s Energy) had been funded to the tune of $10.7 million apiece, with about $40 million more due once they convinced the DOE they were actually on course to be built.
Neither was. Dominion seemed weirdly lukewarm on its own VOWTAP project right from the start, and turned icy after cost estimates came in on the high side. In Oregon, Principle Power was unable to get an above-market power purchase agreement for Windfloat Pacific from the state’s two major investor-owned utilities, Portland General Electric and Pacific Power, and there was no political appetite to force it. Gov. Kate Brown, who replaced the scandal-ruined Kitzhaber as governor in early 2015, appeared unwilling to spend any political capital to make it happen (she was busy backing a clean fuels bills in 2015, and 2016’s legislative session was dominated by the Clean Electricity and Coal Transition bill). She did set up a “WindFloat Pacific Offshore Wind Advisory Committee” last summer, but critics said the composition of the committee made it unlikely it would find a solution. And it didn’t.
In its funding update, the DOE didn’t say they’d pulled the plug on Dominion and Principle Power, but instead said an evaluation had led them to select two alternate projects:
In May 2016, the Energy Department evaluated the full portfolio against established milestones to determine whether any of the three demonstration projects—Dominion, Fishermen’s Energy, or Principle Power—should continue as part of the Offshore Wind Advanced Technology Demonstration program, and whether either or both of the alternates—the University of Maine or LEEDCo—should be onboarded into the Demonstration program.
Through this evaluation, the Department decided that the Atlantic City Windfarm developed by Fishermen’s Energy, Lake Erie Energy Development Corporation’s (LEEDCo’s) Icebreaker project, and the University of Maine’s New England Aqua Ventus I project have demonstrated significant progress toward being successfully completed and producing power.
None of this is too surprising. Last June, I wrote a piece for Breaking Energy about the original three projects’ struggles. Check it out for more background, but the basic point was that the DOE’s funding for advanced offshore wind simply wasn’t enough to make such projects happen. Will the two newly tapped projects and the still-standing Jersey project now be able to find the strong state and/or utility support they will need?
The Jersey project looks stuck as long as Chris Christie is governor; earlier this month he vetoed another bill that would have paved the way for a power purchase agreement. Prospects for the Maine project appear better—regulators long ago approved a term sheet to sell the power from the University of Maine-run project at 23 cents per kilowatt-hour. Of course, a planned Statoil project in the state had a similar term sheet, but it ultimately fell through under pressure from Gov. Paul LePage.
Finally, in Ohio, the developer says it “has a Memorandum of Understanding with Cleveland Public Power for 25% of the power” and agreements with two counties to buy 10 percent apiece. That doesn’t sound totally solid, but is better than nothing. What of the remaining power? The plan is that it “will be purchased by a retail electricity supplier who will create an Icebreaker power option for residential and commercial customers.” It all sounds reasonable, but far from certain.
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.”