Tuesday, July 9, 2013

Cost of solar power (37)

The Antelope Valley Solar Projects are two co-located PV installations in Kern and Los Angeles Counties, near Rosamond Ca in a desert location. 

These are a big deal!  The peak output is 579 MW and the annual output is said to be enough to supply 400,000 households.  In today’s post, I’ll make an estimate of the Levelised Cost Of Electricity (LCOE) for the projects.  But first let me give a few details. 

Construction on the projects began in April 2013 and will continue for nearly three years.  Let’s assume completion by December 2015.  SunPower (majority owned by Total of France) did the initial development work using the company’s own CdTe panels and solar trackers.  Then earlier this year the project was on-sold to Berkshire Hathaway subsidiary, MidAmerican Energy Holdings.  We can assume that Warren Buffett, a notoriously canny investor, is happy with the deal.

The site occupies 3,230 acres (13.07 km^2).   MidAmerican expects to employ 650 workers on the construction site, which will generate more than USD 500 million in regional economic impact.

What was the cost of the deal?  As usual, that’s hard to establish.  Various reports on the internet give a figure of between USD 2.0 and 2.5 billion, whereas this report gives a remarkably precise figure of USD 2.742 billion, which I find hard to believe since it gives an LCOE that’s too high.  I’m inclined to use a figure of USD 2.25 billion, the midway point of the figures most commonly cited.

And what is the annual output in MWh?  Let me estimate that in two ways.

As is often the case, the press reports aren’t specific, merely saying that the output is enough to power approximately 400,000 average California homes when fully operational.  Now the Energy Information Agency gives the average site consumption in California homes as 6,888 kWh per year.  Therefore the annual output would be 400,000 × 6,888 /1,000 = 2,755,200 MWh per year.  According to those figures, the Capacity Factor would be 2,755,200 / 579 × 365 × 24 = 0.54, an estimate that is much too high.

Let’s estimate the CF in another way.  In a technical paper [1], Matt Campbell of SunPower helpfully provides information about Capacity Factors.  For plants in Nevada, typical CF values for one-axis tracking are around 0.30.  Let’s use that for Antelope Valley.  The annual output would thus be 0.30 × 579 × 365 × 24 = 1,521,612 MWh per year.  That figure is acceptable.

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 Antelope Valley project are as follows:

Cost per peak Watt              USD 3.9/Wp
LCOE                                     USD 169/MWh

The components of the LCOE are:

Capital           {0.094 × USD 2.25×10^9}/{1.521×10^6 MWhr} = USD 139/MWhr
O&M              {0.020 × USD 2.25×10^9}/{1.521×10^6 MWhr} = USD 30/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)


You can compare results in the graphic below (click for a larger image), which expresses costs in USD/MWh at the exchange rates of 13 June 2013.  Antelope Valley is not shown on the chart since it will not be finished until the end of 2015. (Currencies deflated at 1.75% per annum, baseline date is end 2014.  Red is for solar thermal, blue for PV.  Filled-in circles denote completed projects, non filled-in circles denote announced projects.)

My estimate for Antelope Valley has uncertainties in both price and output.  That’s normal in this business.   However, it’s reasonable to conclude that the project is in the same LCOE range as the best of the PV projects I have analysed, and definitely superior to current LCOE results for solar thermal projects.

Note also that the Antelope Valley project is not cheap at USD 3.9/Wp.  One-axis tracking adds to the costs, but also adds to the output; the ultimate LCOE figure is good.

[1]  Matt Campbell, “Minimizing utility-scale PV power plant levelized cost of energy using high capacity factor configurations”, available at www.pv-tech.org.

Monday, July 8, 2013

World Renewable Energy Congress

Next week, I’ll attend the World Renewable Energy Congress in Perth, where I’ll present a paper entitled “Life-Cycle Assessment for BRRIMS Solar Power”.  I’ll take this opportunity to mention key findings of the paper and also provide a brief progress report on my research.

The abstract for the paper is as follows:

This paper presents a life-cycle analysis for a new concept in solar thermal power generation.  BRRIMS denotes Brayton-cycle, Re-heated, Recuperated, Integrated, Modular and Storage-equipped.  This concept envisages collection temperatures of around 250°C, thermal storage in pebble beds, thermal-electric conversion in a piston-cylinder engine and air as the heat transfer fluid and working gas of the engine.  The analysis applies to the manufacturing phase of the overall power plant and separately to the pebble bed thermal storage component.  Three sustainability metrics are included – life-cycle greenhouse gas emissions, cumulative energy demand and energy payback time.  On these metrics, the BRRIMS concept has broadly similar results to a conventional parabolic trough plant with molten salt thermal storage.

The last sentence says it all – for the manufacturing phase, my findings are that the BRRIMS concept will have similar life-cycle metrics to conventional parabolic trough solar plants.  My life-cycle investigation didn’t extend to the construction, operation, decommissioning and disposal phases, but my expectation is that life-cycle contributions are not large for these phases with the BRRIMS concept.  That was generally the case in a detailed study of a parabolic trough plant by Burkhardt et al. [1].

In the paper, I also used Barnhart & Benson’s concept of “Energy Stored On Invested” (ESOI, [2]) to investigate thermal storage in pebble beds.  ESOI for a storage device measures the (equivalent) electrical energy stored in whole of life relative to the energy embodied during manufacture.  On this metric, solar thermal concepts have a good rating.  Their ESOI score is much better than for chemical storage in batteries, but not as good as geologic storage such as pumped hydro and compressed air energy storage. 

Here are the ESOI scores (my calculations for the solar thermal concepts, other data from [2]):

Geologic storage
Solar thermal
Trough, molten salt
Flow batteries

In other work, I continue to establish the technological case for investment in solar thermal concepts such as BRRIMS.  These concepts are easy enough to understand (see e.g. explanations at www.sunoba.com.au), but many engineering questions need to be resolved prior to any decision to design and build power plants. 

Much of this work has to remain confidential for the moment.  I’ll post details here when I am able to do so.


[1]  J.J. Burkhardt III, G.A. Heath and C.S. Turchi, “Life cycle assessment of a parabolic trough concentrating solar power plant and the impacts of key design alternatives”, Environ. Sci. Technol. 45 (2011), 24572464.

[2]  C.J. Barnhart and S.M. Benson, “On the importance of reducing the energetic and material demands of electrical energy storage”, Energy Environ. Sci., 6 (2013), 1083-1092.