When we have committed to reducing total greenhouse gas emissions by 26 percent over a business-as-usual (BAU), 10-year window, two questions arise: What emission baseline do we use and what mitigation plan do we have?
The world baseline for emission reduction changes over time. Discussions and negotiations in preparation of a new agreement between nations have become more complicated, due to the fact that a number of Annex-1 (developed) countries are trying to get advantages by playing with different numbers, baselines, and definitions.
The baseline was first based on the reduction of emission levels of 1990, but it shifted to a reduction of the emission levels of 2005. During the Kyoto negotiations, the central focus was CO2 emission, but now the focus is on not allowing the climate to change more than two degrees Celsius in temperature.
Similarly, we in Indonesia are subject to confusing definitions, and changing targets. Different ministries are using different baselines expressed in different units for the same commodity.
In the energy sector we have various terms like TJ (liquid fuels consumption), MMBOE (million barrels of oil equivalent) GWh (global specific mix) and so on, which make data comparison extremely difficult.
Our first communication to the United Nations Framework Convention on Climate Change (UNFCCC), said the energy sector in 2010 would emit less than 450 million tons of CO2 (MtCO2) and in 2020 close to 700 MtCO2. PLN, a monopoly responsible for all power generation, has generation data on the basis of which CO2 emission have been estimated.
Then, of course the Energy and Mineral Resources Ministry has developed a number of scenarios, as part of their continued effort to monitor and manage emissions. Data provided by the ministry, i.e., the National Energy Conservation Master Plan (RIKEN), both stated in the blueprint of the National Energy Management (PEN) 2005 and Energy Outlook 2006-2030, show yet a different set of figures.
Thus, in the process leading to Copenhagen, we must be consolidating these data sets. While it may take a while, we have to soon agree on and decide which data sets should be used as a baseline for emission reduction. Moreover, we have to make sure that in presenting the country’s proposed mitigation action plan, the units used are following the IFCC 2006 guidelines.
With the objective of moving away from oil due to declining domestic reserves and energy efficiency, the target for the energy supply mix has been set for 2025 — in the 2006 presidential decree. With this policy, as projected by RIKEN, energy consumption would reduce to about 5.5 million GWh from the business-as-usual consumption, which is roughly 8.6 million GWh, in 2025.
If this estimate is true and RIKEN — not the first communication to UNFCCC — is considered to be a baseline, using the average weighted data for Indonesia of 0.741 kg/CO2/kWh, this energy mix policy would reduce annual emissions from roughly 650 to 400 MtCO2, or a reduction of 36 percent , in 2025. If the energy sector is responsible for emitting 30 percent of the total greenhouse gases, then this reduction constitutes roughly 10 percent of the commitment.
With support from Annex-1 countries, we expect to have a higher share of renewable energy in the energy mix, and reduce the coal and oil share. An increase of 5,000 to 7,000 megawatt (MW) of geothermal power would reduces emissions by more than 40-50 MtCO2 annually, or over the period 2010 to 2025 would mitigate close to 500 MtCO2, more than the whole Clean Development Mechanism has achieved in its nine years of existence on a worldwide scale.
This mitigation scheme would bring the geothermal share from the BAU case of 4 percent to 12 percent of generating capacity and thus bring total energy sector emission reduction from roughly 36 percent to 43 percent over the BAU scenario in the energy sector.
However, the cost of this additional mitigation is considerable, due to the fact that at current price levels, the capital cost for investment in geothermal, as compared to oil and coal, generation is about three times more expensive.
If this 5,000 to 7,000 MW investment was made in coal-fired plants, it would cost approximately US$5-7 billion, now for geothermal $15-20 billion would be required in direct investment and an additional $2 billion in transmission, capacity building etc – an incremental cost
of more than $10 billion over coal investment.
A high cost would, of course, be compensated for by significantly lower operational costs, as a geothermal plant does not need to buy any other fuel.
Yet, to attract the required level of investment to realize this additional mitigation potential, we will need to assist the electricity offtaker, i.e., state-owned electricity company PLN, in paying a feed-in tariff.
This is to close the gap between the cost of coal-generated electricity and the perceived higher cost of geothermal generation.
While a feed-in tariff can be repaid with the income from the sale of Certified Emission Reductions (CER), there are risks preventing it happening. No one knows whether the price of coal will increase significantly in the coming five to 10 years.
A coal price increase is good news as the feed-in tariff will automatically be eliminated but, on the other hand, this would eliminate CERs for geothermal. Thus the additionality required under the CDM would fall away.
The other is the price of carbon credits — none knows whether or not the price will stay at $20/tCO2 for the next five to ten years, which of course relates to the demand.
These risks make it difficult to get the private sector, i.e., geothermal IPP, to commit — uncertainty with respect to the price of coal and uncertainty with respect to the price of carbon. However, under the
assumption that the price of coal will go up, the feed-in tariff is financially viable.
The decision on a baseline for emission reduction is a fundamental step as it determines the level of our mitigation efforts.
Any wrong decision would end up having either excessive resources spent, if the baseline was biased
toward overestimation, or insufficient mitigation if the baseline was underestimated.
Finally, if geothermal is chosen to be the core of our additional mitigation potential in the energy sector, support to the offtaker in paying a feed-in tariff is needed to close the gap between the cost of a coal-based power plant and the perceived higher cost of a geothermal-based power plant.
The writer is the director for energy, mineral resources and mining at the National Development Planning Agency (BAPPENAS). This is a personal opinion.
