This part gives the results of the research in the form of varying recommendations. The recommendations are presented in the following order: (1) priorities for the near term (2025–2030), (2) strategies for the mid-term (2030–2040), (3) planning for the long-term (2040–2050), (4) cross-cutting institutional reforms.
Near-Term Priorities (2025–2030): Foundation Building
1. We will quickly speed up solar deployment in Southeast and Mediterranean regions (Target: 28.7 GW by 2030 (+16.3 GW from 2025))
- Southeast Anatolia has the highest potential in the world for Solar Energy. Currently, about 15% of the available 118 GW is utilized for Solar Power Plant. The region also experiences maximum irradiance of over 1800 kWh/m²/year. Furthermore, the estimated Lowest Cost of Energy (LCOE) is expected to be just $19.80/MWh (USD, 2023) by the year 2030. The Mediterranean basin has the potential to generate 67 GW of solar energy, 28% of which has been utilized. The close proximity to the Marmara Sea enables the export to the Marmara Sea region, whose national demand accounts for 32% and whose capacity-demand ratio is 0.87. - **Policy instruments:**
- A feed-in-tariff where the price is set based on auction is$0.072 (USD 2023) per kWh in 2025 declining to $0.050 (USD 2023) per kWh in 2030 with 15-year contracts. - Land allocation: Designate 2,500 km² solar zones in Şanlıurfa, Gaziantep, Adıyaman provinces (Environmental Impact Assessments expedited). - The priority of interfacing to the grid will be guaranteed within 12 months (as opposed to the existing 24-36 months). - The anticipated outputs include 16.3 GW of solar additions between 2025 and 2030, an investment of$15.18 billion in USD 2023, and 31,000 construction jobs. Further, the share of renewables is expected to rise 71.2% in 2030 (from 53.8% in 2025).
2. Expansion of wind power capacity in Aegean and Marmara aiming at 24.5 GW by 2030 and 12.7 GW increase.
- **Rationale:** Aegean boasts premier wind resource (avg 7.5 m/s @ 100m), 48 GW potential (38% developed). Marmara requires closeness (transmission losses <5% vs. Southeast >15%), offshore potential (Sea of Marmara 12 GW). - **Policy instruments:**
- Offshore wind tenders: 2 GW annual (2026-2030), $0.088 (USD 2023)/kWh (15% premium over onshore reflecting higher CAPEX$1,320/kW vs. $1,045/kW, USD 2023). - Approval from the Ministry of Energy, Environment, and Defence through the Single-window post submission of application within six months. - By 2028, 40% of turbines are to be manufactured domestically. This will help in creating industries. - The anticipated end result is a 12.7 GW addition of wind power and$13.31 billion (USD 2023) in investments. Aegean region will become a net exporter with a generation/consumption equilibrium of 1.21.
3. The implementation of coal phase-out which has a target of 8.3 GW remaining by 2030 is likely to lead to reduction of -11.1 GW from 2025.
- Under the 2021 Climate Law, a ban on lignite by the year 2030 has been legislated. Furthermore, a reduction of coal from 19.4 GW in 2025 will produce 8.3 GW for 2030 (hard coal only) and finally a decrease to 0 GW by 2035. If there are early retirements there will be stranded assets of $2.31B (USD 2023) (Section 4.2.2). - **Policy instruments:**
- The Just Transition Fund helps communities (Zonguldak, Manisa, Kütahya) that depend on coal. Its budget for 2023 is$3.85 billion or $3,850,000,000. 8,000 coal workers are going to transfer to renewable O&M through retraining. Also, there will be regional development projects. - The retirement compensation stands at$198.00 (USD 2023) per kW, encouraging early closure to put the asset in stranded condition (fair market value). - Each retired coal plant must include an equivalent of solar or wind + storage based on capacity and flexibility in the new capacity mandates. - The expected outcomes are 11.1 GW of coal retirement from 2025–2030, a 65 MtCO₂ emissions reduction equivalent to 38% of the 2025 baseline of 172 Mt and air-quality improvements with around -20 μg/m³ PM2.5 in coal-producing regions.
4. Strengthening the Accumulation of Akkuyu Nuclear Plant.
- The construction of Akkuyu (4.8 GW, 4× VVER-1200, commissioning from 2025-2028) would provide baseload (CF 85%, 35.8 TWh/year, generation share in 2030 8%). Scheduled with certainty, no policy discretion. - **Policy actions:**
- The budget for the Turkish Atomic Energy Authority (TAEK) increased 40% with semi-annual IAEA inspections. - Spent fuel management involves the establishment of an interim storage facility in Sinop province having a capacity of 500 tonnes by 2028 and site selection for permanent repository has already been initiated. - We issue safety reports once every 3 months in both Turkish and English. Besides, citizen monitoring panels are also being hosted in 50 km radius provinces (3 in total). - The expected outcomes of the Akkuyu project online 2025-2028 is more than 4.8 GW, no incident (target), over 60% public acceptance with transparency.
Mid-Term Strategies (2030–2040): Acceleration Phase
5. Solar Dominance Phase The target of 68.9 GW (40.2 GW beyond 2030) by 2040.
- The price of solar power will become cheaper than fossil energy. This is expected to cause an exponential growth of solar energy in future. 4.1 GW per Year Peak Deployment Rate (2035-2040 Section 4.2.2). - **Policy evolution:**
- End feed-in tariffs (FIT) by 2032, transition to capacity markets and power purchase agreements. - Rooftop solar incentives: Net metering for residential (<10 kW), $0.110 (USD 2023)/kWh export tariff (vs.$0.154 (USD 2023)/kWh retail), target 5 GW distributed. - Promotion of Agrivoltaics: This involves two usages of land: agriculture plus solar; a $55.00/kW (USD 2023) bonus for agrivoltaic systems (crops are grown under elevated panels). - Anticipated outcomes include 40.2 GW solar additions,$28.27B (USD 2023) investment, share of solar 32% (68.9 GW / 218 GW cumulative capacity).
6. Target to achieve battery storage scale up of 14.1 GWh by 2040 - up 9.3 GWh from 2030.
- The 2040 strategy targets a high reliance on renewables (92.8%). This article discusses duck curve mitigation monitoring, among others, to make this happen. Cost of storage estimated to fall from $495/kWh in 2025 to$165/kWh (in present terms) in 2040. This represents a 67% reduction. - **Policy instruments:**
- A new Solar Plant above 50 MW capacity should have co-located storage of at most 20% capacity and of 4-hour duration. For instance, a 100 MW solar plant must have co-located storage of 20 MW / 80 MWh. - The standalone storage will receive a rebate of 30 percent of Capital Expenditure (CAPEX). This will decline to 15 percent by 2040. It has a sunset provision which encourages early adoption. - Reforming the market can enable storage revenue stacking. They include frequency regulation and voltage support for auxiliary services markets. - The anticipated benefits of the storage expansion are 9.3 GWh, investment of $2.31B (USD 2023) and curtailment decrease from 12% to 3% (avoided waste is 8 TWh/year).
7. Gas will transition to peaking role. (Target: 6.8 GW by 2040, -15.3 GW from 2030)
- Gas is becoming less competitive compared to renewables and storage. Maintain 6.8 GW (3% capacity) for reliability: winter peaks and renewable lulls (long cloudy/calm periods). Total generation per year 6.1 TWh (1.4% of total), capacity factor 10% (peaking-only). - **Policy actions:**
- Gas plants placed into service after 2030 would qualify for a 10-year depreciation schedule as opposed to a 20-year standard, as these facilities have a shorter life. - Ban on new gas investments: No new gas plant investments except for peaking units (less than 50 MW) replacing retired capacity. - All the gas plants being kept are hydrogen-ready, allowing them to switch fuel for decarbonization purposes. 30 per cent blend by 2035 and 100 per cent by 2045. - The results we expect are the retirement of gas of 15.3 GW (2030 to 2040), the reduction of emissions by 42 MtCO₂ (the residual will be 3.2 Mt from 6.8 GW of peaking), and the fossil fuel imports avoided are$9.02B (USD 2023) (natural gas).