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

Conclusion

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.