Wednesday, December 30, 2015

PV versus CST

2015 was a watershed year.

The Paris climate change talks revealed a positive change in attitude amongst many countries (even if the signed agreement is rather toothless), steaming coal consumption has entered a structural decline, China is getting serious about air pollution, renewable electricity generation is cheaper than from fossil fuels if conditions are favourable, and battery storage is much talked about for numerous applications.

And it’s batteries that I want to blog about today.

Many studies on this blog and elsewhere show that PV is cheaper than Concentrated Solar Thermal (CST) power generation in the absence of storage.  But has battery technology advanced so much that PV plus batteries can compete with CST plus thermal storage at utility scale?  That’s the question I’ll answer.

In 2015 I analysed two installations in the Atacama desert where the solar conditions are superb.  The first was a PV installation at Amanecer, the second was the Atacama 1 CST project.  These are big projects delivered at world’s best practice. 

The Amanecer project had peak power 100 MW, no storage, Capacity Factor 0.308, annual output of 270 GWh, total cost USD 260.5 million, and my LCOE estimate was USD 110/MWh.  The Atacama 1 CST project was a conventional heliostat-tower design with twin tank molten salt energy storage for 17.5 hours, peak power 110 MW, estimated annual output 840 GWh, total cost USD 1.1 billion, and my LCOE estimate was USD 149/MWh.

What would happen if we tried to replicate the output of Atacama 1 with PV plus batteries?  Let me use the following assumptions:

  • PV costs and output are as per my Amanecer blog post,
  • batteries have a round-trip efficiency of 95% for a charge/discharge cycle,
  • batteries last 12.5 years under a regime with a complete charge/discharge cycle each day to a depth of 70%, and
  • the capital cost of batteries lies in the range USD 100 to USD 400 per kWh.
Suppose we want to replicate the peak power of Atacama 1 with PV, namely 110 MW.  Such a PV system would produce (110/100) × 270 = 297 GWh per year.  To match the annual output of Atacama 1, namely 840 GWh, requires that 840 - 297 = 543 GWh be delivered via batteries, or that 543 / 0.95 = 571.6 GWh be delivered by PV panels after accounting for the round-trip efficiency of storage.  Since the Capacity Factor for the site is 0.308, the peak power of the panels would be 571.6 / (0.308 × 24 × 365) = 0.212 GW or 212 MW.  The cost of those panels would be (212/100) × 260.5 = USD 552 million.

What about the cost of the batteries?

Well, we need to deliver 543 GWh annually, or 1,487,671 kWh per day.  But the batteries are assumed good for 70% discharge on a daily basis, so we need storage of 1,487,671/0.7 = 2,125,244 kWh.

And there’s more … We know the PV panels will last for 25 years, whereas the batteries are assumed to last for only 12.5 years.  So we need two sets of batteries during the assumed 25 year life of the project.  That makes 2 × 2,125,244 = 4,250,489 kWh battery storage required.

Exploring the sensitivity, the total cost of the batteries will be:
  • USD 425 million at battery cost USD 100 per kWh
  • USD 850 million at battery cost USD 200 per kWh
  • USD 1,275 million at battery cost USD 300 per kWh
  • USD 1,700 million at battery cost USD 400 per kWh
All up, to replicate the Atacama 1 CST project with PV plus batteries we need to add USD 260.5 million plus USD 552 million plus the cost of the batteries given above.  That makes:
  • USD 1.238 billion at battery cost USD 100 per kWh
  • USD 1.622 billion at battery cost USD 200 per kWh
  • USD 2.088 billion at battery cost USD 300 per kWh
  • USD 2.512 billion at battery cost USD 400 per kWh
Those figures need to be compared with the USD 1.1 billion cost of the Atacama 1 CST plant. 

Note that the capital price in 2015 for batteries is around USD 350 per kWh, so I think the result is clear.  Batteries are already cost efficient for portable electronic devices, maybe break even with flywheel costs for short-term frequency control, and in a few years will be cost-efficient for behind-the-meter applications and automobiles.  However the above estimates show that battery storage is nowhere near competitive with CST plus thermal storage for utility-scale applications.  In my view, proponents of utility-scale CST with storage can proceed with confidence.

With that (and as an enthusiastic inventor and developer of CST concepts), I wish all readers of this blog a successful and happy year ahead.  Thank you for reading this blog.

Acknowledgement: Thanks to Anthony Kitchener for suggesting that I perform this analysis.

Monday, December 28, 2015

Cost of solar power (59)

In January this year, I blogged about the 100 MW Amanecer PV project in the Atacama desert, Chile.  That project had an excellent Levelised Cost of Electricity (LCOE), even though cost per peak Watt wasn’t anything special.  The reason for the excellent LCOE is that the Atacama solar resource is the best in the world, as confirmed here.

Today I’ll run the numbers on another solar project in the Atacama desert, namely the Atacama 1 Concentrated Solar Thermal (CST) plant due to open in 2018.  An interesting story about the project recently appeared in The Guardian, whilst key project details are given here.

The 110 MW solar plant is at 1,100 m altitude and has a conventional heliostat/tower design with 17.5 hours of two-tank molten salt energy storage.  It’s a big project by experienced developers (Abengoa); the central tower is 243 m high, there are 10,600 heliostats each of 140 m^2, and the overall heliostat field occupies 1.484 km^2.  The receiver itself is a cylinder 32 m high and 19 m in diameter.  Molten salt is fed to the receiver from the cold tank at 300°C and returned at 550°C.

The cost of the project is reported by The Guardian as USD 1.1 billion.  The annual output was not given in any report I read, although it was reported that the project will abate 840,000 t of CO2 emissions per year.  At an emissions intensity of 1 t CO2 per MWh, that corresponds to an annual output of 840,000 MWh at a Capacity Factor of 840,000/(110×24×365) = 0.87.  That seems high but achievable since the plant provides baseload power to regional industries, there is a lot of storage and the solar resource is superb.

Let me now estimate 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% of capital cost rather than 3% as in posts during 2011.  

The results for the Atacama 1 CST installation are as follows:

Cost per peak Watt              USD 10.00/Wp
LCOE                                     USD 149/MWh

The components of the LCOE are:

Capital           {0.094 × 1.1×109}/{840,000 MWhr} = USD 123/MWhr
O&M              {0.020 × 1.1×109}/{840,000 MWhr} = USD 26/MWhr


My LCOE estimate of USD 149/MWh compares to Abengoa’s estimate of USD 120/MWh.  It is also of interest to compare to other CST projects such as the proposed Port Augusta plant (USD 153/MWh), Cerro Dominador USD 125/MWh, Ashalim USD 284/MWh and Xina Solar One USD 256/MWh.  These solar plants have a higher LCOE than the best of recent PV plants without storage, such as Nyngan & Broken Hill AUD 139/MWh = USD 99/MWh. 

A historical comparison might also be interesting.  Probably the most famous CST plant of all is Gemasolar, which opened in September 2011.  For that I estimated the LCOE to be AUD 447 per MWh in 2011 Australian dollars.  The current exchange rate is about 1 AUD = USD 0.72, so AUD 447 is about USD 322.  A strong improvement, and I suspect there will be further improvement as more CST plants are built.

Acknowledgement: Thanks to Anthony Kitchener for providing web links for the Atacama 1 CST installation.

Friday, December 18, 2015

Levelised cost of pumped hydro

RenewEconomy had an interesting story yesterday about plans to develop a pumped hydro storage facility at an abandoned gold mine in central Queensland.  Further details are available in this media release from the Australian Renewable Energy Agency, ARENA, which has given a grant of AUD 4 million to help with a feasibility study for the project.

In brief, the facility is to be located at the abandoned Kidman gold mine, 270 km north-west of Townsville.  The mine site has two deep pits 400 m apart, there is plenty of water available, there is an existing 132 kV transmission line connecting the site to a substation near Townsville, and there is plenty of infrastructure already on site.  This project will use existing features of the landscape for pumped hydro generation without need for extensive earthworks.

The best details that I could find about the project are at this web page for the proposers, Genex Power.  From that we read the estimated cost is AUD 282 million, the peak power output will be 330 MW and the project will deliver 1,650 MWh of energy in a single cycle.  To do this, water is pumped from one pit to the other with an average head of 190 m; in so doing, water level in the lower pit will change by 44 m and in the upper pit by 8 m. 

From the point of view of capital costs, this project will deliver 1,650 MWh for AUD 282 million; that is AUD 170,909 per MWh installed capacity, or AUD 171 per kWh installed capacity.  That’s deliverable now, without need for R&D or assumptions about the likely decrease in cost of battery storage.  One could expect the project would have a long lifetime, far longer than the life of batteries.

As an aside, 1,650 MWh divided by 330 MW gives 5 hours, a convenient round number for the recharge/discharge time of the system.

What then is the value of this storage?  At present, the main opportunity is to use off-peak power (coal generated) at night to recharge the upper dam, and then to provide power during periods of peak demand in the rest of the day.  There would also be some value in ancillary services to the grid such as reserve generation capacity and frequency control.

In future, as the fraction of intermittent generation increases in the grid, especially from PV, the value proposition will switch around.  The upper pit will be charged during the day and discharged at night.  I imagine hefty simulations will be required to understand and quantify this likely transition in usage, hence the need for a substantial feasibility study.

In November 2015, I blogged about the Levelised Cost of Electricity storage.  In that post, I presented a standard methodology to calculate the value of energy stored in an operational sense.  That methodology is used in the cases below.

For a best-case scenario, let’s assume the cost of capital is 6%, the project delivers the full 1,650 MWh on a daily basis for 40 years, and that the round-trip efficiency is 100%.  Also assume that the cost of maintenance is 1% of the capital cost.  Then the Levelised Cost of Electricity Stored is AUD 36 per MWh.

For a less favourable scenario, let’s assume the cost of capital is 8%, only half of the full capacity is used each day for 25 years, the round-trip efficiency is 90% and the cost of maintenance is 2% of the capital cost.  In this case, the Levelised Cost of Electricity Stored is AUD 118 per MWh.

The feasibility of this project – or not – will rest on a raft of assumptions about present and future demand, cost of capital, cost of O&M, competition in the market place, etc.  Nevertheless, if existing features of the landscape can be used, it seems to me that pumped hydro storage is much cheaper than battery storage today, and will continue to be cheaper for many years in the future.

Thursday, December 10, 2015

Back to Barcaldine

In this post of 11 May 2015, I analysed the Levelised Cost of Electricity (LCOE) for a proposed large PV installation at Barcaldine in central Queensland.  The project has now reached financial closure and the specifications of costs and output have drifted somewhat.  Here’s a quick revision of the LCOE based on details in this press release.

The peak output is now 20 MW AC at grid voltage (25 MW DC from panels to the inverters).  Previously the output was stated as 23.6 MW, without reference to AC or DC.  The annual output is unchanged at 53,000 MWh.  The panels will have single axis tracking and the Capacity Factor will be 0.301.  The project is due for completion in April 2017.

The cost is now estimated to be AUD 69 million (previously “between AUD 55 million and AUD 65 million”; I used AUD 60 million in my LCOE estimate).  Financing for the project is helped by a grant of AUD 22.8 million from the Australian Renewable Energy Agency (ARENA) and AUD 20 million in debt finance from the Clean Energy Finance Corporation (CEFC).

Using my standard methodology (see almost any post in this blog, especially my original post for 11 May 2015 on Barcaldine), my revised estimate for the LCOE is AUD 148 per MWh (previously AUD 129 per MWh).  My LCOE graphic gives comparisons.

Monday, November 16, 2015

Levelised Cost of Electricity Storage

RenewEconomy had an interesting story recently by Ramez Naam about the likely decrease in costs of battery storage.  This relates particularly to the learning curve, or how quickly costs fall for every doubling of installed capacity.  Naam cites Bloomberg, the Electric Power Research Institute and a private enterprise (Applied Materials) and suggests that the learning rate for battery storage is in the range 15-21%.

I too have written about the learning curve for battery storage – see my post of April 2015 that relies on the work of two academics, Nykvist & Nilsson.  Their estimate of the learning curve is slower, about 14% for general battery storage and 8% for automotive applications.  Whatever, everyone agrees that the cost of battery storage will continue to fall for several years at least.

Note that the above discussion refers to the capital cost of installation, measured in units like $ per kWh installed capacity.

But that begs the question of the cost of battery storage in an operational sense when capital costs and operating costs need to be included.  Let me call that the Levelised Cost of Electricity Stored, LCOES.   I should note that Naam gives figures for LCOES, but does not give the methodology, and that’s the purpose for my post today.

Here’s the notation I’ll use:

P          cost of the installed system [$]
C         capacity of the installed system [kWh]
d          depth of discharge on a sustainable basis [-]
N         lifetime of battery at daily discharge d [years]
i           weighted cost of capital [-]
m         maintenance cost per year as fraction of installed cost [-]

The first thing to calculate is the capital recovery factor, R.  This is the rate at which the capital cost must be repaid over N years, given that the weighted cost of capital is i, and so that no further payments are required after N years.

The answer (see e.g. Wikipedia) is

R = i * (1+i)^N / { (1+i)^N – 1}.

Here’s an example:  suppose we wish to pay back $1,000 over 20 years given that the weighted average cost of capital is 6%.  Then the capital recovery factor is

R = 0.06 * 1.06^20 / { 1.06^20 – 1} = 0.08719 approximately.

So to pay back $1,000 over 20 years when the weighted cost of capital is 6%, the required annual payment is $1,000 * 0.08719 = $87.19, each year for 20 years.  Inflation is not included in this simplified calculation.

Let me now give the basis for estimation of Levelised Cost of Electricity Stored, LCOES.  My standard assumptions are:
  • there is no inflation,
  • taxation implications are neglected,
  • all projects have the same annual maintenance and operating costs (say 1% of the total project cost), and
  • government subsidies are neglected.

Variables will be capacity (C), price (P), weighted cost of capital (i), depth of discharge (d) and lifetime of battery (N).

Annual costs ($) are as follows:

Capital cost:              P * R
Maintenance cost:    P * m
Total cost:                  P * (R + m)

The annual output (kWh) will be

C * d * 365

Hence the Levelised Cost of Electricity Storage is

LCOES = P * (R + m) / {C * d * 365}  in $/kWh

Examples of systems at 10 kWh capacity

Pessimistic assumptions (for Australia in 2015):

P = $5,000, i = 0.10, d = 0.6, N = 10 years.
Result: $0.394 per kWh

Neutral assumptions:

P = $3,500, i = 0.08, d = 0.7, N = 12 years.
Result: $0.195 per kWh

Optimistic assumptions:

P = $2,500, i = 0.06, d = 0.8, N = 14 years.
Result: $0.101 per kWh


To install your home battery system under the neutral assumptions, your actual costs will be $0.195 per kWh.  If you are coupling your battery system with a rooftop PV system, then you would have additional costs of say $0.15 - $0.20 per kWh (and that’s taking into account the government small-scale technology certificates).  At this stage, in 2015, home battery storage is for enthusiastic early adopters, not canny investors.  I expect the results will be more favourable in a few years.

Note added (18 November 2015)

Let me make a link to a related report by Lazard on the Levelised Cost of Storage.  I should also note that I’ve assumed that charging is 100% efficient, which is not the case.  It would be simple to subtract from the annual output C*d*365 so as to account for charging inefficiency.

Sunday, September 27, 2015

Cost of solar power (58)

For some time now, residents of South Australia have been agitating for construction of a Concentrating Solar Thermal (CST) power station at Port Augusta to replace two old coal-fired power stations.  The owner of the coal-fired stations, Alinta Energy, has now released reports describing the financial viability of the project.  These reports were prepared by Alinta with support from the Australian Renewable Energy Agency and the Government of South Australia.

What do the reports say about the Levelised Cost of Electricity (LCOE) for this project?  And why is Alinta walking away from this project that could be built within two years?

As a starting observation, let me say that the Alinta reports are very instructive.  They have been carefully prepared with input from numerous serious players in the industry.  The base case is for a Rankine-cycle 50 MW CST power station at nearly 40% thermal-electrical efficiency and based on heliostat/tower technology with molten salt storage for 15 hours.  Port Augusta has good solar resources and Alinta’s estimate for the annual output is 301 GWh, which corresponds to a Capacity Factor of 301,000 /(50 × 365 × 24) = 0.687.

The problems, however, come in two ways.  First, the Port Augusta CST plant would be expensive.  Alinta’s base estimate, which I will use here, is for a cost of AUD 577 million.  In part, that reflects the recent collapse in the Aussie dollar, thereby making components such as the power block and molten salt storage more expensive.  Another contributing factor is that the Alinta price estimate includes a hefty AUD 68 million contingency, in addition to Balance of Plant costs of AUD 118 million and EPC/owner costs of AUD 53 million.  The estimated cost for the heliostat field is AUD 138 million (AUD 150 per square metre), for the receiver AUD 86 million, for the tower AUD 21.5 million and for the molten salt storage AUD 83 million.  The steam turbine package was estimated at AUD 29 million.

The second big problem for Alinta is that there is currently an oversupply of generating capacity in South Australia.  So, the price achieved for the output would be the electricity wholesale pool price in South Australia, which is not particularly high, even allowing for variations between peak and off-peak prices, as Alinta did.  The study made no allowance for a price on carbon, nor for any other government support.

Let me now estimate 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.  It should be noted that the Alinta financial model is more detailed than mine.

Note that I am now using annual maintenance costs of 2% of capital cost rather than 3% as in posts during 2011.  As an aside, the Alinta study includes a sophisticated estimate for the annual maintenance costs, namely AUD 8 million, or 1.4% of the capital.  That’s less than my 2% of capital, but I won’t change my methodology at this stage.

The results for the proposed Port Augusta CST installation are as follows:

Cost per peak Watt              AUD 11.54/Wp
LCOE                                     AUD 218/MWh

The components of the LCOE are:
Capital           {0.094 × 577×106}/{301,000 MWhr} = AUD 180/MWhr
O&M              {0.020 × 577×106}/{301,000 MWhr} = AUD 38/MWhr


The LCOE for the proposed Port Augusta CST plant is AUD 218 per MWh.  As can be seen from my post summarising all projects I have examined, the Port Augusta LCOE is significantly more than my estimates for recent PV projects.  Perhaps the best comparisons are with other recent CST projects.  In USD at today’s exchange rate, the LCOE for Port Augusta would be USD 153 per MWh, whereas Cerro Dominador is USD 125/MWh, Ashalim is USD 284/MWh and Xina Solar One is USD 256/MWh.

I should also give the LCOE resulting from Alinta’s sophisticated financial model based on a 12% internal rate of return (IRR); that’s AUD 201/MWh.  The chosen value for the IRR explains why Alinta is walking away from this project – on their 12% IRR, the project has a negative net present value.  Simple really; at the present time and without a lot of government support, this project would not get board approval.

Tuesday, September 15, 2015

LCOE results and graphic

This post summarises my results for the Levelised Cost of Electricity (LCOE) for 57 solar projects in various parts of the world.

In the graphic below, red denotes solar thermal, blue denotes PV.  Open circles denotes projects that have been announced but not completed (to my knowledge).  Filled-in circles denote completed projects.  The LCOE is expressed in US dollars at today’s exchange rates (16 September 2015).  Currencies are depreciated/appreciated by 1.0175 (1.75%) per annum using today's date as the baseline.

The current exchange rates are (in USD):
EUR 1.1300
AUD 0.7125
JPY 0.00833
GBP 1.54005
CAN 075441
INR 0.01505

(please click graphic to see a bigger image)

I need to sound a note of caution in interpreting this graphic.  When projects are announced, the project price is also announced, and that’s the information I’ve used.  If the project is a small one, then it doesn’t matter much that the opening date for the project is different to the date at which the price is announced.  In some cases, however, the project will take a long time to complete, so it’s inconsistent to use the announced price for the project.  An example is Cerro Dominador, announced in February 2014 and not due to open until mid-2017.  The announced price is in 2014 dollars, whereas the datum on the graphic has been plotted as if the price is in deflated 2017 dollars.  So the results for Cerro Dominador look a bit better than they actually are.

Don’t allow these subtleties to obscure the overall trend, however, which is that solar power is obviously getting cheaper, both for solar thermal and for PV.

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])”.  The date given in this list is the completion date of the project (or estimate thereof).

(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 & 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, PV, July 2013)
(41)      USD 125 (Cerro Dominador, CST, mid 2017)
(42)      USD 190 (La Paz, PV, September 2013)
(43)      USD 152 (Austin Energy, PV, 2016)
(44)      AUD 304 (Weipa, PV, January 2015)
(45)      AUD 256 (Kalgoorlie-Boulder, PV, August 2014)
(46)      AUD 141 (new Moree Solar Farm, PV, one-axis tracking, December 2015)
(47)      AUD 184 (Brookfarm, PV, December 2015)
(48)      USD 110 (Amanecer, PV, June 2014
(49)      USD 113 (DEWA, PV, April 2016)
(50)      USD 284 (Ashalim, solar thermal, 2017)
(51)      USD 256 (Xina Solar One, solar thermal, 2017)
(52)      AUD 129 (Barcaldine, PV, one-axis, March 2017)
(53)      AUD 139 (Nyngan & Broken Hill, fixed PV, late 2015)
(54)      AUD 240 (DeGrussa, PV/batteries, early 2016)
(55)      AUD 364 (Uterne Stage 1, PV, one-axis tracking, July 2011
            AUD 230 (Uterne Stage 2, PV, one-axis tracking, August 2015)
(56)      INR 4,034 (Cochin Airport, PV, August 2015)
(57)      AUD 136 (Lilydale, PV, one-axis tracking, September 2017)