Wednesday, May 21, 2014

Cost of solar power (44)


RenewEconomy has a story today about a PV installation at Rio Tinto’s bauxite mine at Weipa at the northern tip of Queensland, Australia.  At present, the mine’s electricity is provided by diesel generators, which require the fuel to be shipped in, clearly an expensive process.
 
Replacement of diesel power generation at remote mine-sites is reckoned to be ‘low hanging fruit’ for the solar industry and a number of big players are active in the market.
 
Here are some facts about the Weipa installation, including data kindly made public by ARENA, the Australian Renewable Energy Agency.  Overall the two-stage project will cost AUD 23.4 million, of which ARENA will provide AUD 11.3 million.  In the first stage, 18,000 thin film PV panels from First Solar will generate 1.7 MW peak and 2,620 MWh per year.  ARENA will provide AUD 3.5 million for the first stage, which is due for completion in January 2015.
 
ARENA’s CEO, Ivor Frischknecht, says
 
“This is the first time a mining company has adopted renewable energy for its Australian operations and is the first project to be funded through the Industry arm of ARENA’s Regional Australia’s Renewables Program.”
 
Clearly today’s announcement is a pivotal event for renewable energy in Australia.
 
In the second stage, another 5 MW of capacity will be added, together with an unspecified amount of battery storage.  ARENA will provide an additional AUD 7.8 million for the second stage.
 
I’d really like to make an analysis of both stages, but I don’t have the data on the amount of battery storage.  However I can analyse the LCOE for the first stage once I’ve made one (thoroughly reasonable) assumption about costs, namely that Rio Tinto will provide 50% of the Stage 1 costs.  That gives the Stage 1 cost as AUD 7.0 million for an output of 2,620 MWh per year.
 
We can now proceed to analyse the LCOE using my standard 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 LCOE methodology, see posts on Real cost of coal-fired power, LEC – the accountant’s view, Cost of solar power (10) and (especially) Yet more on LEC.  Note that I am now using annual maintenance costs of 2% rather than 3% as in posts during 2011.

The results for the Weipa project are as follows:

Cost per peak Watt              AUD 4.1/Wp
LCOE                                     AUD 304/MWh

The components of the LCOE are:

Capital           {0.094 × AUD 7×10^6}/{2,620 MWhr} = AUD 251/MWhr
O&M              {0.020 × AUD 7×10^6}/{2,620 MWhr} = AUD 53/MWhr

By way of comparison, LCOE figures (in appropriate currency per MWh) for all projects I’ve investigated are given below.  The number in brackets is the reference to the blog post, all of which appear in my index of posts 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)
(19)      AUD 316 (University of Queensland, fixed PV, 2011)
(20)      EUR 241 (Ait Baha, Morocco, 1-axis solar thermal, 2012)
(21)      EUR 227 (Shivajinagar Sakri, India, PV, 2012)
(22)      JPY 36,076 (Kagoshima, Kyushu, Japan, PV, start July 2012)
(23)      AUD 249 (NEXTDC, Port Melbourne, PV, Q2 2012)
(24)      USD 319 (Maryland Solar Farm, thin-film PV, Q4 2012)
(25)      EUR 207 (GERO Solarpark, Germany, PV, May 2012)
(26)      AUD 259 (Kamberra Winery, Australia, PV, June 2012)
(27)      EUR 105 (Calera y Chozas, PV, Q4 2012)
(28)      AUD 205 (Nyngan and Broken Hill, thin film PV, end 2014?)
(29)      AUD 342 (City of Sydney, multiple sites, PV, 2012)
(30)      AUD 281 (Uterne, PV, single-axis tracking, 2011)
(31)      JPY 31,448 (Oita, PV?, Japan, to open March 2014)
(32)      USD 342 (Shams, Abu Dhabi, trough, to open early 2013)
(34)      USD 272 (Daggett, California, designed 2010)
(35)      GBP 148 (Wymeswold, UK, PV, March 2013)
(36)      USD 139 (South Georgia, PV, June 2014)
(37)      USD 169 (Antelope Valley, CdTe Pv, end 2015)
(38)      AUD 137 (Mugga Lane, PV, mid 2014)
(39)      AUD 163 (Coree, fixed PV, Feb 2015)
(40)      AUD 298 (Ferngrove Winery, July 2013)
(41)      USD 125 (Cerro Dominador, mid 2017)
(42)      USD 190 (La Paz, PV, September 2013)
(43)      USD 152 (Austin Energy, PV, 2016)
(44)      AUD 304 (Weipa, PV, January 2015)

Conclusion

You can compare results with my LCOE graphic.

The Capacity Factor for Stage 1 of this installation is 2620/(365 × 24 × 1.7) = 0.176.  That’s not brilliant for a tropical location with a daily solar exposure of 21 MJ/m^2, although cloudy days and storms would be expected frequently in summer.  I can only presume the panels are fixed.

I’m underwhelmed with the LCOE of AUD 304 per MWh.  Even allowing for the remote location and high costs to transport workers and material, the LCOE figure seems off the pace compared to recent installations in the list above.

Sunday, May 18, 2014

Cost of solar power (43)


A few days ago, Recurrent Energy issued a press release with some brief details of a 150 MW installation in Austin, Texas.  When I say “brief details”, that’s what I mean.  The only two items of hard information in the document are “completion in 2016”, and the “power to be delivered to Austin Energy pursuant to a 20-year Power Purchase Agreement”.

Elsewhere, greentechmedia reports that the PPA is for less than 5 cents per kWhr.  and several sources including Fuel Fix say that the value of the contract is USD 525 million and the project will occupy 1,000 acres = 405 Ha.  Fuel Fix also says that 1 MW provides enough power for 500 Texas residences under normal conditions.  Meanwhile, this reference says the average electricity consumption in Texas is approximately 14,000 kWh per year.

So we know the cost of the deal, but what about the annual output?  In my analysis of the Antelope Valley installation, I used a figure of 0.30 for the Capacity Factor of a PV system with one-axis tracking.  Let’s use that CF here.  The annual output would then be 150 × 365 × 24 × 0.3 = 394,200 MWh.

Or, if I say that the system will provide power to 150 × 500 Texas residences with an average annual consumption of 14 MWh per year, the annual output would be 150 × 500 × 14 = 1,050,000.

Those two estimates for the annual output are widely disparate.  I think the first estimate is ambitiously high and the second estimate is ridiculously high.  Let’s stick with the first estimate.

We can now proceed to analyse the LCOE using my standard 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 LCOE methodology, see posts on Real cost of coal-fired power, LEC – the accountant’s view, Cost of solar power (10) and (especially) Yet more on LEC.  Note that I am now using annual maintenance costs of 2% rather than 3% as in posts during 2011.

The results for the Austin Energy project are as follows:

Cost per peak Watt              USD 3.5/Wp
LCOE                                     USD 152/MWh

The components of the LCOE are:
Capital           {0.094 × USD 525×10^6}/{394,200 MWhr} = USD 125/MWhr
O&M              {0.020 × USD 525×10^6}/{394,200 MWhr} = USD 27/MWhr

By way of comparison, LCOE figures (in appropriate currency per MWh) for all projects I’ve investigated are given below.  The number in brackets is the reference to the blog post, all of which appear in my index of posts 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)
(19)      AUD 316 (University of Queensland, fixed PV, 2011)
(20)      EUR 241 (Ait Baha, Morocco, 1-axis solar thermal, 2012)
(21)      EUR 227 (Shivajinagar Sakri, India, PV, 2012)
(22)      JPY 36,076 (Kagoshima, Kyushu, Japan, PV, start July 2012)
(23)      AUD 249 (NEXTDC, Port Melbourne, PV, Q2 2012)
(24)      USD 319 (Maryland Solar Farm, thin-film PV, Q4 2012)
(25)      EUR 207 (GERO Solarpark, Germany, PV, May 2012)
(26)      AUD 259 (Kamberra Winery, Australia, PV, June 2012)
(27)      EUR 105 (Calera y Chozas, PV, Q4 2012)
(28)      AUD 205 (Nyngan and Broken Hill, thin film PV, end 2014?)
(29)      AUD 342 (City of Sydney, multiple sites, PV, 2012)
(30)      AUD 281 (Uterne, PV, single-axis tracking, 2011)
(31)      JPY 31,448 (Oita, PV?, Japan, to open March 2014)
(32)      USD 342 (Shams, Abu Dhabi, trough, to open early 2013)
(34)      USD 272 (Daggett, California, designed 2010)
(35)      GBP 148 (Wymeswold, UK, PV, March 2013)
(36)      USD 139 (South Georgia, PV, June 2014)
(37)      USD 169 (Antelope Valley, CdTe Pv, end 2015)
(38)      AUD 137 (Mugga Lane, PV, mid 2014)
(39)      AUD 163 (Coree, fixed PV, Feb 2015)
(40)      AUD 298 (Ferngrove Winery, July 2013)
(41)      USD 125 (Cerro Dominador, mid 2017)
(42)      USD 190 (La Paz, PV, September 2013)
(43)      USD 152 (Austin Energy, PV, 2016)

Conclusion

You can compare results with my LCOE graphic.

My analysis for the Austin Energy project has uncertainties in annual output, but I think it’s reasonable to conclude that project is in the same LCOE range as the best of the PV projects I have analysed.  Based on my LCOE methodology, which I use uniformly across all projects, the LCOE is definitely more than 5 US cents per kWh, in fact about three times as much.  The effects of government subsidies are not included in my analysis.

The capital cost for the project is not cheap at USD 3.5/Wp.  That indicates to me they must be using one-axis tracking, although I couldn’t find any confirmation of that on the internet.