Coal in the 2020–2040 Least Cost Power Development Plan

Coal sections of the official updated report released in January 2021

For reference and comparison, previous LCPDP 2017–2037 here.

Least Cost Power Development Plan, study period 2020–2040

• In accordance with the Energy Act of 2019, the Cabinet Secretary is mandated to develop an Integrated National Energy Plan in respect of coal, renewable energy and electricity so as to ensure delivery of reliable energy services at least cost.

Generation Expansion Planning:

• The LCPDP recommends adoption of the optimised case. In this model, coal is added into the mix in the year 2040. Coal would generate 981 mW, or 12% of total electricity, as listed in the Optimised Reference Expansion Plan-Generation Capacity Summary Table.
• “The expansion plan adopted as the least cost plan forms the basis for preparation of a power transmission plan.” (section 6)
• “The level of vented steam remains high at an average of 18% of the possible maximum geothermal generation over the planning period.”
• “The LEC [levelised cost of electricity] rises from US Cents 8.31/KWh in 2020 to peak at US Cents 10.23/KWh in 2033, before decreasing to an average of US Cents 9.82 /KWh in the period 2034–2040.”
• LCPDP recommendations: Create demand, incentivize electricity use. Improve system management, supply reliability, efficiency; reduce system losses.
• Conclusion on coal as an energy source: “Due to its widespread deposits, production experience as well as relatively low costs, coal is an important fuel option for expansion planning but the negative environmental impacts has to be factored in.”

Demand Forecast (2020–2040)

• Reference scenario: average of 5.28%, peak 5.38% (1,972 to 5,526MW) (based on historical data trends)
• Vision scenario: average of 8.20%, peak 8.35% (1,972 to 9,635MW) (“highly driven by Vision2030” and flagship projects)
• Low scenario: average rate of 4.89%, peak demand increases to 5,028MW (where most of the government plans are not implemented as planned)

Vision 2030 Flagship projects listed include electrified mass rapid transit system in Nairobi; Standard Gauge Railway between Mombasa and Nairobi; and six Special Economic Zones across the country, including in Lamu.

“It has been noted that flagship projects are not being implemented within the timelines as envisaged, therefore slowing down both the economic and demand growth. It has also been noted that specific consumption has declined due to low consumption by newly connected customers.”

2.5. Electricity supply

• “The installed generation capacity has increased considerably over the past five years, an annual average growth rate of 4.52%.”
• “The effective capacity mix comprises of 30.2% of hydro, 24.7% thermal (medium speed diesel: MSD), 2.1% Thermal (gas turbine: GT), 28.8% geothermal, 12.2% from wind and 1.96% from solar.”
• “Current effective installed (grid & off-grid) electricity capacity is 2,668 MW.”

2.6 Energy Sources in Kenya

“The power generation mix comprises of 45.6% of geothermal, 36.2% hydro, 6.7% fossil fuels, 9.6% wind and 0.8% from solar for the financial year ending June 2020.”

There has been a “continous decline in energy purchased from Thermal generation.”

3. ELECTRICITY DEMAND FORECAST

3.4. Performance of the Power Sector

“Energy consumption increased from 9,280GWh in 2014/15 to 11,462GWh in 2019/20 representing an average growth of 4.5% over the last six years as shown in figure 7.”

4. ASSESSMENT OF NATURAL ENERGY RESOURCES IN KENYA

Current national primary energy consumption:

• biomass (charcoal and wood fuel) 69%
• petroleum products 22% and demand increasing 10% annually
• electricity 9%, with about a third based on the fossil fuels heavy fuel oil (HFO) and gasoil products, the remaining based on renewable energy sources (does this make sense?)
• coal 1%

CURRENT AND FUTURE ENERGY SOURCES: COAL SECTION

4.4. Solid fuels

4.4.1. Coal

Coal is a solid fossil fuel consisting mostly of carbon with variable amounts of other elements mainly hydrogen, sulphur, oxygen, and nitrogen. Coal is formed when dead plant matter decays into peat and is converted into coal by the heat and pressure of deep burial over millions of years. It is found in and extracted from geological formations beneath the earth’s surface. For utilization in power plants, coal can be distinguished by the heating value and its composition ranging from lignite with a relatively low heating value to sub-bituminous coal. Coal has been the second most important fossil energy source in the world measured by energy content behind crude oil5. It is the most important fuel for power generation worldwide due to its abundant reserves, which are relatively distributed among many countries. However, the use of coal is accompanied by strong environmental impacts, such as high emissions of sulphur dioxide, heavy metals and harmful greenhouse gases.

In Kenya local coal reserves can be found in the Mui Basin which runs across the Kitui county 200 km east of Nairobi. The coal basin stretches across an area of 500 square kilometers and is divided into four blocks: A (Zombe — Kabati), B (Itiku — Mutitu), C (Yoonye — Kateiko) and D (Isekele — Karunga). Coal of substantial depth of up to 27 meters was discovered in the said basin. 400 million tons of coal reserves were confirmed in Block C109. The Government of Kenya has awarded the contract for mining of coal in Blocks C and D. Coal mining, in particular open pit as planned for Mui basin, has strong environmental and social impacts. The mining will require large scale resettlement plans. Further, mining will produce considerable pollution.

Due to its widespread deposits, production experience as well as relatively low costs, coal is an important fuel option for expansion planning but the negative environmental impacts has to be factored in. The planned coal power plant in Lamu would be the first in Kenya. More coal power plants in future, utilizing domestic coal, could be developed directly near the Mui Basin in Kitui County.”

5.EVALUATION OF POWER GENERATION EXPANSION PROJECTS

5.1. Objective

The objective of this chapter is to assess candidate power generation projects to be considered in the expansion planning process designed to meet projected demand over the planning period.

The projects evaluated included several committed projects expected to be commissioned in the short to medium term. Analyzing these approved projects was necessary, considering that it may be prudent to reschedule some depending on the system load growth.

Section on coal in its entirety:

5.3.1. Coal

According to International Energy Agency, Coal remains a major fuel in global energy systems, accounting for almost 40% of electricity generation and more than 40% of energy-related carbon dioxide emissions. This is despite the growing prominence of renewable energy sources. Global coal demand increased by approximately 1.1% in 2019, continuing the rebound that began in 2017 after three years of decline. The main driver was coal power generation, which rose almost 2% in 2019 to reach an all-time high. It is however expected that demand for coal will remain under pressure due to strong uptake of renewables-based capacity and, in the United States, the availability of inexpensive natural gas.

One of the most important coal markets is China, due to its large share in both global coal demand and production. Any significant shifts in Chinese coal usage or output has an immediate effect on other world’s markets. Although China’s coal demand increased marginally since the rebound in 2017, the country is increasing its efforts to reduce coal’s share in its energy mix. A large amount of coal-fired capacity was taken offline in 2017 in order to reduce local pollution. Many of those plants were smaller, old and inefficient coal-fired units, using mostly low-quality coal, thus, contributing significantly to local air pollution. This is part of a broader plan to cap coal-fired capacity at 1,100 gigawatts (GW) by 2020. Furthermore, the Chinese government has decided to stop or delay more than 100 GW of previously planned and under construction coal power projects by 2020. This is in line with the series of medium to long-term actions that the government is taking to achieve its 13th Five Year Plan (FYP) climate related goals.

5.6. Fuel Forecast Results

Coal sold for electric power generation is sold through long term contracts and supplemented with spot purchases. The spot prices are more vulnerable to short term market conditions.

In addition to electricity generation, coal is also used to produce coke which is used in smelting iron ore to make steel. Coal prices have been changing at an average rate of -3.57%. This change is attributable to the fact that coal is mainly used for power generation and there is a global shift from coal power generation to renewable and cleaner sources of electricity generation like wind, solar, geothermal, nuclear etc.

5.7. Screening curve analysis

• Screening curves were constructed for selected Thermals, Nuclear, Coal, Geothermal, Imports and Hydro Candidate plants. The screening curve technique is an approximate method that captures major tradeoffs between capital costs, operating costs and utilization levels for various types of generating capacity in the system. This approach is especially useful for quick comparative analyses of relative costs of different electricity generation technologies.
• List of screened candidates includes Lamu Coal (981 MW) and Kitui coal (960 MW)
• Lamu coal fixed cost USD $2,504,000,000 ($2.5 billion) and annual fixed cost $498,000,000 ($498 million)
• Kitui coal fixed cost USD $2.331,000,000 ($2.3 billion) and annual fixed cost $519,000,000 ($519 million)

6.2.2. Committed Generation Projects

Table 24: Committed projects are defined as those with PPAs and for KenGen as approved by EPRA. Total of 53 projects listed: 31 hydro, four biomass, one biogas, six wind, eleven solar, fourteen geothermal, two imported hydro (Ethiopia), and one coal: “Amu Coal 981.5 MW, PPA dated December 2016, optimised case COD 2037, fixed case COD 2027”

Table 24: No coal projects listed under Candidate projects

Table 27: Optimised Case Reference scenario generation expansion overview

• End of 2036 Lamu Unit 1–327 MW “firm”
• End of 2038 Lamu Unit 2–327 MW “firm”
• End of 2040 Lamu Unit 3–327 MW “firm”

(No other coal projects.)

6.5.2. Fixed System Case

The modelled case consists of the existing plants, committed KenGen and GDC projects and IPP projects with PPAs over the planning period. This case was simulated under the three demand forecast scenarios developed -Reference, Vision and Low.

6.5.2.1. Fixed System Case- reference demand scenario

From 2024 to 3031, the excess capacity in the system ranged between 300–800 MW largely due to the Lamu coal plant, and the average annual excess energy as share of generation in the period 2020–2030 at 6%. The level of vented steam was 1,200 GWh from 2021 to the end of the planning period. The average vented steam was 18% of the possible maximum geothermal generation, with a high of 23% in 2024- 2026. The excess energy and vented steam was mainly due to the high amounts of solar, wind and geothermal baseload capacity in the system, as well as imports from Ethiopia.

Capacity factors for the coal plant was significantly low at an average of 7% over the planning period. Geothermal plants’ capacity factors declined beginning 2021 to an average of 77.5% over the planning period.

6.5.2.2. Fixed System case — low demand Scenario

The capacity requirement for this scenario is lower due to the low demand forecast, growing from 2,654 MW in 2020 to 7,421 MW in 2040. However, excess capacity was higher, ranging from 400 MW to 900MW, due to the large number of committed plants. The steam vented over the planning period averaged 19% or 2,100 GWh of the possible maximum geothermal annual generation. The annual generation mix over the period is shown in Figure 29.

6.5.2.3. Fixed System Case — vision demand scenario

With the higher demand in this scenario, the interconnected system capacity was higher growing from 2,654 MW in 2020 to 17,175 MW in 2040. This accommodated all the committed projects and the excess capacity decreased compared to the other scenarios, to an average of 96MW over the planning period. The excess energy was also lower averaging 3% over the period. The Vented steam was also lower with an average of 18%, and dispatch of plants more optimal with capacity factors of 83.6% for Geothermal and 28.2% for coal. The annual generation is illustrated in figure 25.

6.6. Conclusions and Recommendations

i) Renegotiate CODs and tariffs for projects that have PPAs but are yet to commence construction, to be integrated according to the dates given in the optimal plan. Respective contingent liabilities for the committed projects should be determined to inform proposals and negotiations.

7. INVESTMENT COSTS OF THE INTERCONNECTED SYSTEM AND THE EVOLUTION OF TARIFFS IN THE MEDIUM TERM.

This chapter covers generation costs for the period 2020–2040 as simulated in the chapter 6, and the evolution of tariffs for the medium term period 2020–2025 where the projects are committed and fixed.

7.2. Optimized Case — Reference Demand Scenario

The implementation of an additional capacity of 8,186.5MW will require a capital cost of USD 2.4725 billion.

The generation cost in the rises from Kshs.9.82/kWh in 2020 to KSh. 11.68/kWh in 2025.

7.3. Fixed system case — Reference Scenario

The implementation of the additional capacity of 8,371.5MW will require a capital cost of USD 10,055.1 billion.

Geothermal shall require a larger share of the Capital requirement.

“[In] the levelised costs for the planned fixed system case, the cost ranges from 8.31 USDCents/kWh in 2020, to 11.12 USDCents/kWh in 2040. The highest Levelised cost of 12.68USDCent/kWh, is realized in 2027. The spike is attributable to commissioning of the Lamu Coal power plant.”

8.4.1 Planning assumptions

In preparation of the transmission development plan the following basic assumptions were made:

• Future thermal generation (coal and gas turbines) will be developed mainly in Coast area to reduce the cost of fuel transportation and consequent environmental impact.

8.19.4. Investment Sequence

8.19.4.1. Transmission lines and substations

Ongoing projects:

• Mwingi-Kitui 132kV, 46 km, substation 6, Kitui 132/33 1x23MVA, 23 MVA, March 2021 projected commissioning date
• Kitui-Wote 132kV, 66km, March 2021 projected commissioning date
• Cost together with Lessos-Kabarnet 132/33 1x23MVA and Olkaria-Narok 132/33 1x23MVA, estimated cost USD $105.38 million

Planned projects: Year 2037

• Lamu –Lamu Coal 220KV, 20 KM, year 2037, estimated cost USD $20.37m, KETRACO+Generation
• Malaa-Lamu 400KV, 520 KM, Lamu 400/220 2x200MVA, MVA 400, estimated cost USD $487.65m, KETRACO+Generation
• Garsen-Lamu 220kV ( line II ), 96, estimated cost USD $27.3m, KETRACO+Generation

9. CONCLUSIONS AND RECOMMENDATIONS

9.1.2. Generation Expansion planning

Simulations were done on the cases assembled based on various assumptions as discussed in chapter 6. Simulations were run based on three demand growth scenarios namely; Reference, Vision and Low. The “Fixed Case Reference Scenario and optimized case reference scenario” encapsulated the most likely development path hence it was used in deriving the long term expansion plan.

Annual generation analysis indicates progressive addition of intermittent capacity (solar and wind) in the planning period necessitates the selection of High Grand falls hydro plant, Dongo Kundu CCGT and Back up diesel generation for system support.

Addition of 981MW Lamu coal generation in year 2027 to the system results in huge surpluses over and above peak and reserve requirements.