Thursday, February 23, 2012

Patent accepted

There is good news to report.  Today I received notification from my patent attorney that my patent application 2007240126 has been accepted.

My attorney writes:

“The acceptance will be advertised in the Australian Patent Office’s Official Journal of Patents on 1 March 2012.  The deadline for any third party opposition is three months from that date.  If no opposition is filed in that period then the patent will be granted shortly thereafter.”

This patent application refers to my concepts for an evaporation heat engine and condensation heat pump, both in piston-cylinder and continuous-flow forms.  It’s a high-level application, which covers the thermodynamic cycles and their uses, rather than actual details of the devices (although examples are given).

As the patent number suggests, the provisional application was filed in 2007, then converted into a Patent Collaboration Treaty (PCT) application thus giving me international protection for 18 months, and then applied for in the national phase in Australia.

What have I learned from this long process?

My dominant realisation is that inventors have to exercise fine judgement in patenting.  There are familiar arguments for patenting an invention:  protection is obtained and the concept can be promoted to potential investors.  But on the other hand, patenting is certainly not cheap and is time-constrained.  If an inventor hasn’t secured funding to take the invention further, then patent bills still have to be paid and perhaps the number of national jurisdictions pruned back when the PCT application reaches the national phase.  So it’s a fine judgement – to patent, or to protect your work through other means (such as good old-fashioned secrecy).

To complete this post, I’ll just mention that I’m currently working on computer simulations of thermal storage in a bed of loosely packed rock.  This storage mechanism is very well suited to my evaporation engine, as powered by passive solar heat collection (see www.sunoba.com.au).  I expect to be able to report on the storage simulations within several months.

Wednesday, February 15, 2012

Cost of solar power (18)

Today I shall analyse the cost of power from a utility-scale solar thermal power station.  It’s the Crescent Dunes project, located just northwest of Tonopah, Nevada in the USA.

From my vantage point in Sydney, Australia, it seems there is a thundering herd of utility-scale solar projects under construction in the USA, helped along by a loan guarantee program from the US Department of Energy.  A recent article in greentechsolar makes the case – almost USD 5 billion was guaranteed on the last day of the program alone (in September 2011), including to the Desert Sunlight (partial guarantee for USD 1.88 billion, 550 MW PV) and Antelope Valley (USD 680 million, 230 MW PV) projects.  In the last week of the program, loans were also guaranteed to Mesquite Solar 1 (USD 337 million, part of a 700 MW PV project) and Crescent Dunes (USD 737 million, 110 MW, solar thermal).

This blitzkrieg of financial and construction activity makes a mockery of negative articles about solar energy that appear frequently in our local mainstream media.

The Crescent Dunes project is being developed by Tonopah Solar Energy LLC, a wholly owned subsidiary of SolarReserve LLC.  The peak and annual power outputs are 110 MW and 504 GWhr.  The project is being built on a 640 Ha site and will have a 195 m central tower and 17,500 heliostats each of 62.4 m^2.  Energy will be stored in molten salt so that the project can deliver power for up to ten hours after dark.  The project is due for completion in 2013.

SolarReserve raised USD 140 million in venture capital in 2008 and the DOE loan guarantee is for USD 737 billion.  That’s a total of USD 877 million, whereas this site reports that the project will cost USD 900 million.  Let’s stick with the latter figure.

I now evaluate the Levelised Electricity Cost (LEC) using my customary assumptions
          there is no inflation,
          taxation implications are neglected,
          projects are funded entirely by debt,
          all projects have the same interest rate (8%) and payback period (25 years), which means that the required rate of capital return is 9.4%,
          all projects have the same annual maintenance and operating costs (2% of the total project cost), and
          government subsidies are neglected.

For further commentary on my LEC methodology, see posts on Real cost of coal-fired power, LEC – the accountant’s view and Cost of solar power (10).  Note that I am now using annual maintenance costs of 2% rather than 3% as previously.

The results are:

Cost per peak Watt             USD 8.18/Wp
LEC                                        USD 204/MWhr

The components of the LEC are:
Capital           {0.094 × USD 900 × 10^6}/{504,000 MWhr} = USD 168/MWhr
O&M              {0.020 × USD 900 × 10^6}/{504,000 MWhr} = USD 36/MWhr

By way of comparison, LEC figures (in appropriate currency per MWhr) for all projects I’ve investigated are given below.  The number in brackets is the reference to the blog post, all of which appear with the title “Cost of solar power ([number])”:

(2)        AUD 183 (Nyngan, Australia, PV)
(3)        EUR 503 (Olmedilla, Spain, PV, 2008)
(3)        EUR 188 (Andasol I, Spain, trough, 2009)
(4)        AUD 236 (Greenough, Australia, PV)
(5)        AUD 397 (Solar Oasis, Australia, dish, 2014?)
(6)        USD 163 (Lazio, Italy, PV)
(7)        AUD 271 (Kogan Creek, Australia, CLFR pre-heat, 2012?)
(8)        USD 228 (New Mexico, CdTe thin film PV, 2011)
(9)        EUR 200 (Ibersol, Spain, trough, 2011)
(10)      USD 231 (Ivanpah, California, tower, 2013?)
(11)      CAD 409 (Stardale, Canada, PV, 2012)
(12)      USD 290 (Blythe, California, trough, 2012?)
(13)      AUD 285 (Solar Dawn, Australia, CLFR, 2013?)
(14)      AUD 263 (Moree Solar Farm, Australia, single-axis PV, 2013?)
(15)      EUR 350 (Lieberose, Germany, thin-film PV, 2009)
(16)      EUR 300 (Gemasolar, Spain, tower, 2011)
(17)      EUR 228 (Meuro, Germany, crystalline PV, 2012)
(18)      USD 204 (Crescent Dunes, USA, tower, 2013)

[Note: all estimates made using 2% annual maintenance cost.]

The Capacity Factor for Crescent Dunes is 504,000 / (110 × 24 × 365) = 0.52, somewhat less than the 63% CF that I calculated for Gemasolar in Spain, which is a natural project for comparison.  At the current exchange rate USD 1 = EUR 0.76, the Crescent Dunes LEC is much less (almost half!) than that for Gemasolar.

It’s also of interest to compare Crescent Dunes with Ivanpah.  Both are under construction; both are heliostat-tower systems; Crescent Dunes has thermal storage whereas Ivanpah does not; both are Rankine cycle steam plants:  Ivanpah has air-cooled condensers whereas Crescent Dunes has a hybrid cooling system (mainly dry cooling, with some wet cooling in summer); and the LECs are USD 231/MWhr (Ivanpah) versus USD 204/MWhr (Crescent Dunes).

For my next Cost of Solar Power analysis, I’ll try to get some figures on Asian projects.

Monday, February 6, 2012

Cost of solar power (17)

It has been six months since I last blogged on the cost of solar power, during which time the press has been full of reports that the cost of PV modules has fallen sharply.  Does that translate into a falling cost of solar power at utility scale?  Let’s find out by analysing the Meuro Solar Park in Brandenburg, Germany.

To start, however, let’s remind ourselves about the concept of “learning rate” for PV, see figure below.
Figure 1:  PV module price [USD2011/W] against cumulative PV installations [MW], from Breyer & Gerlach, “Global Overview of Grid Parity Dynamics”, Proc 2011 Solar World Congress, Kassel.

The learning rate is the reduction in module cost per doubling of installed capacity, and, as Breyer & Gerlach show, this was 22.8% over the period 1976-2003 and 19.3% over 1976-2010.  In 2011, feed-in tariffs were wound back in various countries and production capacity increased, particularly in China.  The outcome, as reported in Renewable Energy Focus (Dec 2011), was a 40% fall in PV panel prices in 2011.  So it can be assumed we are still tracking at or better than the blue curve in Figure 1.

The Meuro PV Park is located in the German state of Brandenburg.  The 152 Ha project consists of four fields on the site of a former brown coal mine, not far from the Lieberose project described in Cost of solar power (15).  The 306,000 crystalline PV panels are from Canadian Solar, with installation complete in September 2011.  According to this blog, installation was completed in three months, an outstanding performance.  The peak output is 70 MW and the annual output is 70 GWhr.  According to most reports I read, the cost of the project is EUR 140 million.

I now evaluate the Levelised Electricity Cost (LEC) using my customary assumptions
          there is no inflation,
          taxation implications are neglected,
          projects are funded entirely by debt,
          all projects have the same interest rate (8%) and payback period (25 years), which means that the required rate of capital return is 9.4%,
          all projects have the same annual maintenance and operating costs (2% of the total project cost), and
          government subsidies are neglected.

For further commentary on my LEC methodology, see posts on Real cost of coal-fired power, LEC – the accountant’s view and Cost of solar power (10).  Note that I am now using annual maintenance costs of 2% rather than 3% as previously.

The results are:

Cost per peak Watt             EUR 2.00/Wp
LEC                                        EUR 228/MWhr

The components of the LEC are:
Capital           {0.094× EUR 140 ×10^6}/{70,000 MWhr} = EUR 188/MWhr
O&M              {0.020× EUR 140 ×10^6}/{70,000 MWhr} = EUR 40/MWhr

By way of comparison, LEC figures (in appropriate currency per MWhr) for all projects I’ve investigated are given below.  The number in brackets is the reference to the blog post, all of which appear with the title “Cost of solar power ([number])”:

(2)        AUD 183 (Nyngan, Australia, PV)
(3)        EUR 503 (Olmedilla, Spain, PV, 2008)
(3)        EUR 188 (Andasol I, Spain, trough, 2009)
(4)        AUD 236 (Greenough, Australia, PV)
(5)        AUD 397 (Solar Oasis, Australia, dish, 2014?)
(6)        USD 163 (Lazio, Italy, PV)
(7)        AUD 271 (Kogan Creek, Australia, CLFR pre-heat, 2012?)
(8)        USD 228 (New Mexico, CdTe thin film PV, 2011)
(9)        EUR 200 (Ibersol, Spain, trough, 2011)
(10)      USD 231 (Ivanpah, California, tower, 2013?)
(11)      CAD 409 (Stardale, Canada, PV, 2012)
(12)      USD 290 (Blythe, California, trough, 2012?)
(13)      AUD 285 (Solar Dawn, Australia, CLFR, 2013?)
(14)      AUD 263 (Moree Solar Farm, Australia, single-axis PV, 2013?)
(15)      EUR 350 (Lieberose, Germany, thin-film PV, 2009)
(16)      EUR 300 (Gemasolar, Spain, tower, 2011)
(17)      EUR 228 (Meuro, Germany, crystalline PV, 2012)

[Note: all estimates made using 2% annual maintenance cost.]

The Capacity Factor for the Meuro PV park is 70,000 / (70 × 24 × 365) = 0.114, identical to that for the nearby Lieberose project, which is not a surprise.  Note however the big drop in LEC between Lieberose and Meuro over a three-year period.  The Meuro LEC is 21% more than for the Andasol solar thermal trough project, which admittedly is in a far sunnier location.

Details on other recent projects soon …