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“Strike a balance between coal and renewables,” was the message Department of Energy Secretary Alfonso Cusi recently gave Environment Secretary Gina Lopez. But that’s not quite the true picture he’s trying to paint. He was only giving her a general perspective.
On the other hand, she said clean energy is the way to go, proposing to even use strictly renewables in certain regions. What she had in mind is Palawan and claimed that Cusi is also going in that direction.
Lopez also said, “It needs patience, needs time. We’re getting there.”
She must be well aware of the implications of solely on renewables such as hydro, solar and wind. Unless it’s geothermal or biomass, the intermittent renewables are unreliable because it’s under Mother Earth’s control. The most we can do is extend the services with the use of energy storage technology that has yet to fully-mature and still very expensive for utility-scale applications. The added costs of storage makes large intermittent renewables unattractive to utilities. So she’s absolutely right about exercising patience but we could be in for quite a long wait.
Plant utilization and utility-scale energy storage
Lopez must have envisioned energy storage in the near future for intermittent renewables in the form of heat storage or advanced batteries. This is probably more achievable for small areas such as Palawan but nevertheless, it could still be in some distant future.
A utility-size example is the Solana Solar Power Generating Plant in Arizona in the US which is a 250 net MW concentrating solar power (CSP) plant utilizing parabolic trough mirrors for solar heat collection and molten salt system for heat storage in a 140-ft diameter tank, to extend the services for up to 6 hours each day. Since some of the heat collected during daytime is stored, the net capacity to the consumers is reduced and depending on the weather and insolation (solar radiation), the extended service hours could be shorter.
The station sits on 777 hectares with a total installed cost of around $2 billion, of which $1.45 billion were on DOE loan guarantees. So based on a 250 MW net output, it’s an astounding $8,000/kW, roughly twice that for advanced coal and more than 5 times that for combined-cycle gas turbine (CCGT) plants such as the San Gabriel, San Lorenzo, Santa Rita and Ilijan plants in Batangas. The large land footprint would also be a concern. The extremely high initial cost is just part of the big problem because where the rubber meets the road is the levelized cost of electricity (LCOE) in $/kWh or the break-even cost for the power producer.
LCOE is a comparative measure of the cost in today’s money, of the total money that will be invested and spent throughout the service life of the plant, to produce one kilowatt-hour of energy. It’s essentially using a net present value calculation, to come up with the levelized cost. In other words, if a plant is not producing enough of the expected kilowatt-hours, the price of electricity from that plant will increase.
The worst case would be if a plant is down or idle with zero kilowatt-hours to show for. This is exactly what happens with solar and wind. With their naturally low utilization based on the season and available solar and wind energy, their LCOEs go up.
The LCOE is greatly affected by capacity factor which is ratio of the net generated over a period of time to what could have been generated running continuously at maximum rated power over the same period of time, or in lay terms, the utilization of the plant. Idle investments cost money.
So Solana saddled with a very high initial cost has to capitalize on the free-cost of solar energy whenever available. However even with up to 6 hours of heat storage, the Solana could only claim around a 38% capacity factor which is exceptionally high for intermittent renewables that generally hover at around 15-25% for the solar PVs (photovoltaic) and wind turbines.
The advanced battery storage technology is also in its infancy and not ready for “prime time” as they say. Solar PV plants and wind farms on the grid without energy storage, need emergency backup power such as diesels. That will effectively increase their LCOEs.
With some energy storage plant utilization or capacity factor goes up which in turn lowers the LCOE for intermittent renewables. However, based on the current and not too distant future, it will not be able to match the LCOEs from the baseload fossil fuels.
I know that it becomes too technical for many, but I believe that the consumers and the public in general, should be appraised of the importance of capacity factors which are in the 80% to greater than 90% for baseload fossil plants, making their LCOEs much lower than the intermittent renewables, resulting in lower electric bills.
Rebalancing energy mix
Going back to the energy mix, both chiefs should understand that specifically, it’s about optimizing the energy mix in terms of the composite levelized cost of electricity (LCOE), reliability, source diversity and environmental impact.
Cusi said they’ve met with USAID for a discussion on formulating the ideal fuel mix and reserve requirements. Unfortunately the USAID is not an organization suitably staffed to handle other country’s energy mix problems. They help the poorest countries installing roof-mounted solar PVs for schools and homes with battery storage for extended services during nighttime or daytime with inadequate solar radiation.
Our energy mix problem is national and regional (Luzon, the Visayas and Mindanao), and not in small specific or remote areas. It involves years of constantly rebalancing by retiring some and adding new sources. It calls for technical competence devoid of political taint. With lack of technical capability at the DOE, Cusi has to engage the services of U.S.-based power plant consultants.
A balanced mix has to be the attainable optimum and not only based on sources abundantly available in each region. For instance, Mindanao, too dependent on hydros and land-based oil with barge diesels to bailout the hydros during the dry season, has recently been adding a lot of coal capacities. In anticipation of the depletion of the Malampaya gas fields, an imported liquefied natural gas (LNG) terminal is being built by First Gen in Batangas to feed their CCGTs.
So why is the DOE not looking into more CCGTs, especially in the Visayas and Mindanao, now that the price of imported LNG is competitively priced as Cheniere Energy is getting set to export LNG to Europe and Asia.
An LNG terminal is a business on its own, just like the coal mines are, in supplying the coal plants. Installing LNG terminals in Mindanao and the Visayas with captive CCGT plants are low-risk investments that the DOE should provide loan guarantees for.
DOE Secretary Cusi said based on a study performed in 2015 by IHS, a U.S.-based think tank, 42.59% in coal, 24.9% in gas,13.3% in hydro, 12.7% in geothermal and 6.3% in oil, is a balanced mix for the total installed capacity of 18,765 MW. Without knowing the evaluation criteria and details used by the IHS, it’s difficult to understand with that balance why the Philippines has the highest electricity rate in the Southeast Asian region and has been suffering from persistent blackouts and brownouts for decades?
For a lower composite cost, more natural gas should be added. It’s the most efficient of the fossil fuel sources with lower LCOE and half the GHG emissions from coal. For instance, an advanced combined-cycle gas turbine (CCGT) plant in Europe similar to First Gen’s San Gabriel Unit 1, ran a record efficiency of greater than 60% compared to around 40% for the advanced or clean-coal technology plants being built in Mindanao.
Coal should be limited, if possible, to the already committed new units and the existing coal capacity gradually reduced through retirement of aging and inefficient units.
Oil is no longer considered as one of the new electricity generating technologies and depending on the size and age, should be kept for emergency situations and possibly as baseload backups for some intermittent renewables on the grid.
Except for geothermal and biomass, intermittent renewables such as hydro, solar and wind connected to the grid, will incur the additional cost of baseload backup power in the event the energy sources become unavailable. With the DOE’s original goal of 30% in intermittent renewables, the composite cost will rise due to their low capacity factors.
Of the non-intermittent renewables, geothermal would be the best choice but limited by the available heat source underneath the ground. Biomass fuels are more expensive than the other fossil fuels, due to the additional costs of raw material gathering, transport and processing.
Although renewables use free-cost energy sources, equipment to harness the energy and the facility that converts it into usable form, have to be built and maintained over the service life of the plant. Those expenditures have to be factored in. Due to the high initial costs, government subsidies often come into play, never cost-free but rather on the backs of the taxpayers, so this must be considered in optimizing the mix.
Availability and source diversity go hand in hand in providing a 24/7 reliable power to support the optimum mix. The existing coal, gas, oil, geothermal, hydro and other renewable sources available in each region will play significant roles in the rebalancing process.
Without the benefit of nuclear power plants that other countries have, the DOE should aggressively pursue a mix starting with 45% gas, 25% coal, 15% geothermal, 7% hydro, 7% non-hydro (solar and wind) and 1% oil (mainly for emergency backups).
In the event of loss of intermittent renewables, the nominal 15% reserve margins should be able to stabilize the entire power system on the grid. A continuous rebalancing process based on new commercially available plant capacities and retirement of aging and ailing plants, must take place until an optimum mix is reached.
It’s high time for Cusi to roll up the sleeves and get serious in finding that right energy mix. – Rappler.com
Rolly Calalang holds a BSME from UP Diliman and a BSEE from FEU Manila. He has extensive experience in the power industry in the U.S. and China.