Renewable energy procurement mechanisms

Renewable power generation has different characteristics than fossil-based or nuclear generation, one of them being its more limited dispatchability in overall terms. Renewable-based generation technologies can be divided between variable renewables (VRE) with limited dispatchability, such as wind and solar PV, and fully dispatchable renewables, such as concentrated solar power (CSP), biomass, hydropower with reservoirs, and geothermal.

VRE technologies dominate current and forecasted generation mixes for the energy transition because of their lower costs in generating electricity. Declining VRE costs entail important consequences for products and services needed, as well as for procurement structures.

The cost structure for renewables is dominated by capital expenditure (CAPEX), whereas fossil-based generation entails higher operating expenditure (OPEX). This radically different cost structure, combined with the limited dispatchability of renewable power, makes procurement structures based on short-term marginal pricing a poor fit for renewable-based power systems.⁸

Long-term procurement mechanisms acknowledge and honour the cost characteristics of renewable energy and specifically VRE technologies, including lower ability to properly respond to short-term price signals. Successful renewable power procurement has always, without exception, been linked to the existence of a long-term procurement mechanism, often by-passing existing electricity procurement structures unsuited to renewable sources and the associated technologies.⁹

Long-term procurement mechanisms for renewable power generation no longer function as traditional subsidies. Still, characterising them as such can prompt political and social resistance that hinders the transition. These mechanisms can form part of either a competitive market-based or a direct regulation process and can operate within both liberalised market systems and publicly managed frameworks.

Long-term procurement of renewables can take different forms, requiring different policies, namely: PPAs, feed-in tariffs (FiTs), feed-in premiums (FiPs), contracts for difference (CfDs), and direct public investment.

⁸ Garcia-Casals, X., and E. Bianco, Potential limitations of marginal pricing for a power system based on renewables (IRENA Technical Paper 3/2022): www.irena.org/Technical-Papers/Potential-Limitations-of-Marginal-Pricing-for-a-Power-System-Based-on-Renewables.
⁹ When the costs of renewable power technologies were higher than those of fossil-fuel technologies, such procurement mechanisms were described as subsidies. Historically, this subsidy aspect helped advance renewable power technologies along an initial learning curve. Even as life-cycle costs for renewable power technologies have fallen below those of fossil-fuel technologies, the crucial need for long-term procurement mechanisms remains.

Power purchase agreements

A PPA is a long-term contract in which a renewable power producer and an off-taker – such as a utility, government, corporation or energy community – agree on a price for generated electricity, which may be fed into the grid or self-consumed. While the PPA is a contractual arrangement rather than a policy instrument, it depends on an enabling policy framework.

For producers, PPAs provide revenue certainty just as FiTs do, but prices are typically determined through competitive auctions rather than administratively set rates. The resulting market-based price discovery can reduce the risk of overcompensation, though it may also result in prices that challenge project viability or disadvantage smaller market participants.

Aspects to consider in the design of a PPA procurement process include:

Delivery structure: The choice between physical PPAs (direct delivery or utility-sleeved arrangements) and virtual or financial PPAs determines how electricity and price risks are allocated between parties. A well-suited structure enhances revenue stability for generators while aligning with market design and grid access conditions.
PPA contract duration and volume: Clearly defined contract terms – often 10 to 20 years – and agreed supply volumes provide predictable revenue streams that underpin project bankability. Longer tenors and well-calibrated volumes reduce refinancing risk and support access to lower-cost capital.
Volume of electricity: Specifying contracted energy output or capacity clarifies performance obligations and revenue expectations. Clear volume commitments reduce uncertainty for lenders and investors, strengthening the financial viability of renewable energy projects.
Standardisation and risk mitigation: Standardised PPA templates streamline negotiations, lower transaction costs and enhance transparency. Clearly defined provisions on curtailment, force majeure, changes in laws, and termination rights improve risk allocation between parties, increase legal certainty and strengthen overall investor confidence.

Case study: Contract standardisation in South African renewable energy procurement

South Africa’s Renewable Energy Independent Power Producer Procurement Programme (REIPPPP) is underpinned by a highly standardised, largely non-negotiable contractual framework. This approach was designed to reduce transaction costs, accelerate project development, and improve bankability by providing clear and consistent risk allocation across projects.

Successful bidders under the REIPPPP enter a standard PPA with Eskom, the state-owned electrical utility, as the single buyer. The PPA is complemented by the standard Implementation Agreement with the government and Direct Agreement involving lenders, together forming a comprehensive contract package that allocates commercial, regulatory, and political risks. PPAs are typically concluded for a 20-year term, denominated in South African rand (ZAR). Tariffs are indexed to inflation, providing long-term revenue stability and protecting investors against currency and inflation risks.

Contracts contain detailed provisions governing the scheduled Commercial Operation Date (COD), a final “Last COD,” and the consequences of delays. These include liquidated damages and, in cases of prolonged delay, termination rights, ensuring discipline in project delivery while maintaining clarity for lenders. Standardised clauses allocate the risks associated with regulatory changes and unforeseen events.

Change-in-law provisions define compensation mechanisms, while force majeure clauses allow schedule relief and, where applicable, term extensions, with clear rules for interaction with insurance coverage. Where power generation is curtailed due to defined system events or decisions, the framework allows for “deemed energy” payments as compensation, shielding project revenues against certain system-level risks beyond the control of the producer.

The Direct Agreement establishes clear default and termination procedures and includes step-in rights for lenders, strengthening project bankability and facilitating access to long-term finance. South Africa’s use of standardised contracts demonstrates how consistent risk allocation and legal certainty can support large-scale renewable energy deployment in emerging markets.

Legislation and policy documents

Eskom Holdings SOC Ltd. Power Purchase Agreement – Photovoltaic Projects. Renewable Energy Independent Power Producer Procurement Programme (Appendix K2). Parliamentary Monitoring Group (South Africa):

Secondary literature

Eberhard, Anton, and Raine Naude. The South African Renewable Energy IPP Procurement Programme: Review, Lessons Learned & Proposals to Reduce Transaction Costs. University of Cape Town, Graduate School of Business. 2017.

Direct power purchase agreements

Direct PPAs enable major electricity consumers, such as corporations, public institutions or large industrial users, to contract directly with renewable energy producers. By providing long-term revenue certainty independent of public support schemes, direct PPAs reduce reliance on government-backed procurement and help diversify the sources of demand for clean electricity. By unlocking private-sector purchasing, they can stimulate additional renewable generation capacity, support corporate decarbonisation and improve project bankability.

Direct PPAs allow for:

Moving beyond single-buyer arrangements: Enabling commercial and industrial consumers to contract directly with power producers reduces reliance on a single utility, diversifies demand and supports additional renewable deployment. Greater buyer choice can enhance competition and strengthen corporate decarbonisation efforts.
Wheeling frameworks: Transparent rules for transporting electricity across the grid, or "wheeling," provide certainty on access rights, charges, losses, and settlement. Clear wheeling frameworks reduce transaction risk, ensure fair cost recovery and improve the bankability of direct PPAs.
Direct power lines: Allowing direct connections between generators and large consumers can reduce grid dependency and congestion risks. Such arrangements can enhance project viability, particularly amid network constraints or regulatory uncertainty.

Case study: Opening the power system to third-party access in South Africa

South Africa's framework for non-discriminatory grid access is anchored in the establishment of the National Energy Regulator of South Africa (NERSA) in 2004 and the Electricity Regulation Act (ERA) of 2006. The ERA explicitly prohibits unfair discrimination in grid access and tariffs while requiring transmission and distribution licensees to provide third-party access on objective and transparent terms. These provisions encourage competition, facilitate private investment in generation, and support the integration of renewable energy by allowing electricity to be transported (“wheeled”) across the grid from generators to third-party consumers.

Electricity Regulation Amendment Act 38 of 2024 represents a significant step in operationalising these principles. The act accelerates the transition away from a single-buyer model toward more open and competitive electricity trading arrangements and formally defines institutional roles related to a transmission system operator and future market structures.

A major implementation milestone was reached in May 2025 with the publication of the Regulatory Rules on Network Charges for Third-Party Wheeling of Energy (Version 1) in Government Gazette No. 52781. These rules establish national principles for cost-reflective, transparent, and non-discriminatory use-of-system charges, as well as standardised wheeling credit rates.

Together, these reforms provide greater regulatory certainty for generators, large consumers, and intermediaries engaging in wheeling arrangements. By clarifying access rights and pricing principles, the framework lowers barriers to market entry, supports corporate power purchase agreements, and facilitates higher shares of renewable energy in the power system. South Africa's experience highlights the importance of combining legal access rights with detailed regulatory rules on network charges and institutional roles, thereby translating non-discrimination principles into workable market practice.

Legislation and policy documents

Department of Mineral Resources and Energy (South Africa). Regulatory Rules on Network Charges for Third-Party Wheeling of Energy (Version 01, approved 02 March 2025). Government Gazette (No. 52781, pp. 52-77). Government Printing Works. 2025.

Secondary literature

RES4Africa. Grid access queueing mechanisms for RE projects in South Africa. Renewable Energy Solutions for Africa (RES4Africa) Foundation. 2024.

Feed-in tariffs

A FiT policy guarantees renewable energy producers a pre-agreed payment for each unit of electricity generated over an agreed long period of time. It is a market-independent mechanism that provides high degree of revenue certainty to the producer. It is one of the oldest and most successful policies available to support renewable electricity uptake.

Several aspects to consider in the design of a FiT policy are:

Duration of tariff payment: Long-term tariff guarantees – typically 15-20 years – provide revenue certainty and reduce financing costs. Stable payment periods improve project bankability and support sustained renewable energy deployment.
Differentiated tariff levels: Differentiation by technology, plant size, location or other characteristics allows tariffs to better reflect generation costs and system value. Tailored rates can prevent overcompensation while supporting a diverse portfolio of renewable energy technologies and project types.
Adjustment mechanisms for new plants: Gradual tariff digression for newly commissioned plants reflects cost reductions over time and limits excess rents. Clear, pre-defined rules and avoidance of retroactive changes preserve investor confidence and maintain the credibility of the framework.
Cost recovery and communication: Transparent mechanisms for recovering FiT costs – often through electricity tariffs or alternative public funding sources – reduce fiscal uncertainty and distributional concerns. Clear communication around cost recovery and long-term benefits can help support social and political acceptance.
Tariff-setting methodology: Well-defined approaches to determining tariff levels – whether set administratively or informed by competitive processes – help balance adequate investment incentives with cost control. Robust calibration may be necessary to limit windfall profits while ensuring continued deployment.
Alignment with system planning: FiTs are most effective when deployment incentives are aligned with grid expansion, connection procedures, and broader power-system planning.

Case study: Feed-in tariffs and renewable energy in Viet Nam

Viet Nam has used feed-in tariffs as a central policy instrument to accelerate renewable energy deployment and reduce reliance on fossil fuels. FiTs played a catalytic role in initiating market development and rapidly scaling up renewable generation capacity.

The first FiT for onshore wind was introduced in 2011 (Decision 37/2011/QD-TTg), but deployment only picked up after tariffs were increased in 2018 (Decision 39/2018/QD-TTg), underscoring the importance of appropriate tariff calibration. A FiT for solar PV was introduced in 2017 (Decision 11/2017/QD-TTg). Subsequent tariff adjustments, combined with falling technology costs, drove an unprecedented solar boom: capacity rose from around 0.1 GW in 2018 to roughly 16.5–16.7 GW by 2020, far exceeding the original 2020 target of 0.85 GW.

Despite their effectiveness in driving capacity growth, Viet Nam's FiTs have faced challenges. Short application windows and uncertainty about postFiT support initially created pronounced boom-bust investment cycles, constraining the emergence of a stable domestic renewable energy industry. Limited geographic differentiation of tariffs and insufficient coordination with grid expansion and flexibility investments led to grid congestion, curtailment and system stability issues in highpenetration regions.

Viet Nam's experience highlights the need for wellcalibrated tariff levels, policy predictability, and close alignment between deployment incentives, grid planning, and flexibility measures to ensure a sustainable and resilient renewable energy transition.

Legislation and policy documents

Prime Minister of Vietnam. Quyết định số 37/2011/QD-TTg về cơ chế hỗ trợ phát triển các dủ án điện gió tại Việt Nam [Decision No. 37/2011/QD-TTg on the Mechanism Supporting the Development of Wind Power Projects in Vietnam]. 29 June 2011.

Government of Vietnam. Decree No. 57/2025/ND-CP dated March 3, 2025 on mechanisms for direct electricity trading between renewable energy generation units and large electricity consumers (No. 57/2025/ND-CP). 2025.

Secondary literature

Huld, Arendse. “Vietnam's Solar Feed-in Tariffs in 2025: Incentivizing Energy Storage.” Vietnam Briefing. 2025.

Le, Hang Thi-Thuy, Eleonora Riva Sanseverino, Dinh-Quang Nguyen, Maria Luisa Di Silvestre, Salvatore Favuzza, and Manh-Hai Pham. Critical Assessment of Feed-In Tariffs and Solar Photovoltaic Development in Vietnam. 2022.

Do, Thang Nam, Paul J. Burke, Hoang Nam Nguyen, Indra Overland, Beni Suryadi, Akbar Swandaru, and Zulfikar Yurnaidi. “Vietnam's solar and wind power success: Policy implications for the other ASEAN countries.” Energy for Sustainable Development (Vol. 65). 2021.

Feed-in premiums

FiPs help align renewable energy support with liberalised wholesale markets, specifically by requiring generators to sell electricity at market prices while receiving an additional premium. Compared to FiTs, the FiP approach strengthens market orientation through greater exposure to wholesale price signals and revenue variability.

For VRE projects, price responsiveness remains constrained by weather-dependent generation profiles. Nevertheless, FiPs can still strengthen market participation incentives, forecasting, and system integration.

Revenue stability varies with FiP design: while fixed premiums expose producers fully to market fluctuations, sliding or two-sided premiums can (similarly to FiTs) preserve a degree of long-term certainty. In both FIT and FiP systems, overall support costs are ultimately borne by electricity consumers, although the allocation between regulated payments and market revenues differs – as can associated public perceptions.

In addition to FiT-related aspects, the following design considerations apply to specifically to FiPs:

Fixed vs. sliding premium: The choice between a fixed or sliding premium shapes the balance between market exposure and revenue stability. Fixed premiums fully expose generators to wholesale price volatility, increasing downside risk when prices are low but potentially resulting in windfall gains during price spikes. Sliding premiums, by contrast, reduce uncertainty by stabilising total remuneration, preventing revenues from falling below a minimum while limiting excessive returns. As sliding mechanisms expand, revenue profiles increasingly resemble those under FiTs, although the premium approach maintains a link to market prices.
Design options for sliding premiums: Sliding premiums can include floors and caps, either on the premium or on total remuneration, to reduce downside risk and limit excessive upside gains. In the spot-market gap model, for instance, a minimum remuneration is guaranteed by topping up wholesale prices to a predefined level, with the premium falling to zero when market prices exceed it. These design choices influence revenue predictability, fiscal exposure, and the extent of market integration.
Market participation requirements: FiP schemes are often accompanied by requirements for direct market participation, generation forecasting, and balancing responsibility (making renewable power generators financially and operationally responsible for any difference between their scheduled and actual output to the system), further strengthening the integration of renewable power generators into wholesale electricity markets.
Rules for negative price periods: FiP schemes may also include rules for periods of negative prices, aiming to preserve incentives for efficient market participation and system integration.

Case study: Feed-in premiums in Spain

Spain was an early adopter of FiPs, implementing them between 1998 and 2013 to support renewable energy deployment while encouraging closer integration into wholesale electricity markets. During this period, producers could choose between a FiT and a FiP, subject to limits based on technology and plant size.

In practice, FiPs were often more attractive than FiTs. However, only dispatchable technologies – meaning hydropower with reservoirs, geothermal, bioenergy and CSP – could respond meaningfully to wholesale price signals. To address revenue volatility, Spain introduced caps and floors on total remuneration in 2007, reducing uncertainty for investors while limiting windfall profits during high-price periods.

Rapid renewable power deployment contributed to a growing tariff deficit, reflecting a mismatch between regulated system costs (including renewable energy support payments) and electricity revenues. These pressures were exacerbated by excess capacity in combined-cycle gas turbines (CCGTs) and declining wholesale prices, which reduced revenues for conventional generators and intensified political opposition.

In response to mounting fiscal and political pressure, Spain suspended the FiT/FiP framework in 2008 and introduced retroactive regulatory changes, triggering legal disputes and international arbitration cases, undermining investor confidence. The subsequent “reasonable return” framework substantially reduced project revenues and linked remuneration largely to installed capacity rather than actual generation, weakening operational incentives. Renewable power deployment stalled until new auction-based support schemes were introduced from 2016 onwards.

Spain's experience highlights both the potential and the risks of FiPs, underscoring the importance of fiscal sustainability, policy stability, and careful management of distributional impacts in renewable energy support schemes.

Legislation and policy documents

Ministry of Industry and Energy (Spain). Real Decreto 2818/1998, de 23 de diciembre, sobre producción de energía eléctrica por instalaciones abastecidas por recursos o fuentes de energía renovables, residuos y cogeneración [Royal Decree 2818/1998 of 23 December on the Production of Electricity by Installations Supplied by Renewable Energy Sources, Waste, and Cogeneration]. Boletín Oficial del Estado (BOE-A-1998-30041). 1998.

Ministry of Economy (Spain). Real Decreto 436/2004, de 12 de marzo, por el que se establece la metodología para la actualización y sistematización del régimen jurídico y económico de la actividad de producción de energía eléctrica en régimen especial [Royal Decree 436/2004 of 12 March Establishing the Methodology for the Updating and Systematization of the Legal and Economic Regime of Electricity Production under the Special Regime]. Boletín Oficial del Estado (BOE-A-2004-5562). 2004.

Ministry of Industry, Tourism and Trade (Spain). Real Decreto 661/2007, de 25 de mayo, por el que se regula la actividad de producción de energía eléctrica en régimen especial [Royal Decree 661/2007 of 25 May Regulating the Activity of Electricity Production under the Special Regime]. Boletín Oficial del Estado (BOE-A-2007-10556). 2007. www.boe.es/buscar/act.php?id=BOE-A-2007-10556

Secondary literature

Duffield, John S. “The politics of renewable power in Spain.” European Journal of Government and Economics. ISSN 2254-7088, Universidade da Coruña, A Coruña (Vol. 9, Iss. 1, pp. 5-25). 2020. www.econstor.eu/bitstream/10419/298613/1/1726723593.pdf

Contracts for difference

CfDs aim to combine the long-term revenue stability needed for renewable energy investment with exposure to wholesale market prices. Under a CfD, a generator receives or pays the difference between a fixed strike price and a reference market price per unit of electricity. In two-way CfDs, the state compensates the generator when market prices fall below the strike price and receives payments back when prices exceed it.

This mechanism – along with stabilising revenues while limiting windfall gains – can help cushion consumer bills if clawback revenues are redistributed. Although like FiTs in providing predictable remuneration, CfDs remain formally linked to market prices, with overall costs ultimately borne by electricity users.

Key considerations in applying CfDs include:

Allocation and strike price determination: Awarding CfDs through competitive bidding can enhance price discovery and cost efficiency, while administratively set strike prices may provide greater policy control. Hybrid approaches – such as price caps in auctions – can balance competition with budgetary discipline.
Contract design parameters: Contract duration (often 15-20 years), technology neutrality or differentiation, locational requirements, and eligibility criteria can all influence investment certainty, as well as system value and alignment with broader socio-economic objectives. Careful calibration helps avoid excessive price suppression while supporting diverse and timely deployment.
One-sided vs. two-way contracts: One-sided CfDs, like sliding premiums, protect against low prices but allow windfall gains during high-price periods. Two-way CfDs stabilise revenues while clawing back excess returns, reducing volatility for both producers and consumers.
Treatment of negative prices: Limiting top-up payments during periods of negative wholesale prices reduces incentives to generate when electricity has a low or negative system value, encouraging more efficient market behaviour.
Reference price design: The choice between hourly spot prices and average reference prices affects exposure to short-term volatility and the incentives needed to align production with system needs. Alternative reference structures can influence both revenue stability and system integration.

Volume definition: Settling CfDs on actual output provides strong revenue certainty, while applying them to partial volumes or predefined profiles increases market exposure. The further settlements deviate from actual power generation, the greater the residual risk borne by producers.
Use of clawback revenues: Revenues collected when market prices exceed the strike price can offset consumer costs or support broader public spending priorities. Transparent allocation enhances public trust and policy legitimacy.
Degree of market exposure: Mechanisms such as partial volume coverage or price corridors increase responsiveness to market signals but reduce long-term revenue certainty. The balance between stability and exposure shapes financing conditions and overall policy effectiveness.

Case study

A CfD scheme has been the UK’s central mechanism for supporting low-carbon electricity generation since 2014, when it replaced the earlier Renewables Obligation system. CfDs aim for long-term revenue certainty through competitively determined strike prices while exposing generators to market signals. Low-carbon electricity generators compete for CfD contracts in the UK through auctions. Successful projects receive payments based on the difference between a fixed strike price and a reference wholesale market price, conditional on meeting milestones for financial closure and delivery.

To date, seven CfD allocation rounds have been completed. Early support focused on offshore wind and biomass, including bilateral investment contracts awarded in 2014 with a combined capacity of 4.6 GW. The first competitive auction (Allocation Round 1, or AR1) followed in 2015. Over time, eligibility expanded to additional technologies, including solar PV (from AR4 onwards) and floating offshore wind (with dedicated arrangements established in AR4). From 2019, auctions became annual, increasing deployment certainty and pipeline continuity.

AR5, in 2023, resulted in no new offshore wind awards, largely due to an administrative strike price cap – GBP 44 per megawatt-hour (MWh) – that proved commercially unviable amid rising costs. This prompted recalibration in AR6 (2024), which awarded nearly 10 GW of offshore wind. AR7 (2025) shows UK energy-transition ambitions increasing further, with the auction reserving a dedicated offshore wind stream, raising strike price caps, extending contract durations to 20 years, and introducing the Clean Industry Bonus to incentivise sustainable supply chains.

Despite the UK’s clear success in scaling up offshore wind, the CfD scheme faces challenges, including negative wholesale price bidding by CfD-backed generators and delayed consumer savings due to higher strike prices and substantial grid investment needs. The UK experience highlights the importance of adaptive auction design, cost realism, and alignment between support schemes, grid development, and industrial policy.

Legislation and policy documents

GOV.UK. Contracts for Difference. Update: 16 December 2025.

Secondary literature

UK Department for Business, Energy & Industrial Strategy. Evaluation of the Contracts for Difference Scheme (Phase 1: Allocation Rounds 1 & 2): Final Report. 2019.

Public investment

Direct public ownership of power generation or grid assets and other forms of public investment, such as grants, concessional loans, tax incentives, research funding, and support for standards and skills development, can significantly accelerate renewable energy deployment. While private sector participation is often key to achieve scale, government- or state-run institutions continue to influence system development through planning, financing and risk-sharing mechanisms.

When supported by sound governance, public investment can align infrastructure development with long-term social, economic and environmental objectives. However, its effectiveness depends on fiscal capacity, institutional quality, and the design of complementary market frameworks.

Key considerations in planning public investment in renewables include:

Scope of public ownership: Defining the boundaries of public ownership clarifies where state involvement can address market gaps or strategic needs for grids, system flexibility or other capital-intensive assets that may face underinvestment under purely private models. Targeted ownership can enhance system reliability and long-term planning while limiting fiscal exposure.
Financing and cost recovery: Public investment can be supported through budgetary resources, public development banks, bond issuance, commercial debt, or international and regional funding. Recovering costs through electricity tariffs or broader fiscal revenues influences affordability, distributional impacts and public acceptance. Sound financing and cost-recovery arrangements are essential to keep projects financially viable.
Human and institutional capacity: Public ownership entails operational, financial and technical responsibilities that require adequate expertise. Strong institutional capacity reduces inefficiencies and operational risks, whereas limited capacity may constrain the appropriate scope of public involvement.
Supply-chain boundaries: Public participation rarely extends across the full supply chain. Clearly delineating responsibilities – such as by leaving plant construction and operation to competitive engineering, procurement and construction (EPC) contractors or independent power producers (IPPs) can support an effective combination of public strategic control with private-sector efficiency and technical know-how.
Governance arrangements: Transparent power-system governance structures and clear allocation of responsibilities across national and sub-national levels are vital to enhance accountability and reduce corruption risks. Strong oversight mechanisms reinforce public legitimacy and strengthen project performance.

Case study: Uruguay’s state-led electricity transition

Uruguay’s electricity system is organised around its vertically integrated, state-owned utility UTE (Administración Nacional de Usinas y Transmisiones Eléctricas), which has operated for more than a century. Electricity supply is treated as a regulated service that must be guaranteed in terms of quality and provided on a non-discriminatory basis.

Today, the power system is almost fully based on renewable sources, which account for 97–99% of annual generation under average hydrological conditions. The mix is dominated by hydropower and wind, with biomass and solar PV playing a secondary role. Fossil fuels account for the remaining 1–3% of electricity generation under such conditions.

Historically, Uruguay relied on state-owned hydropower complemented by fossil fuel-based thermal generation. By the end of the first decade of the 21st century, rising demand and system adequacy concerns required generation capacity expansion. A series of severe droughts, culminating in 2008, sharply increased reliance on costly imported fossil fuels, exposing the system to climate variability and fuel price volatility.

In 2008, Uruguay adopted a long-term energy policy, which was ratified in 2010 through a multiparty political agreement that laid the groundwork for a genuine national energy transition. The policy established strategic objectives, targets, and action plans to promote the expansion of renewable energy, with a strong emphasis on wind power to complement hydropower and reduce fossil fuel imports. By that time, UTE, in coordination with the Secretary of Energy, had already developed in-house technical expertise in wind power generation.

To limit fiscal risk, wind capacity was largely deployed through competitive auctions for independent power producers, with UTE acting as the sole buyer under long-term PPAs. The system is operated through centralised economic dispatch by the Electricity Market Administrator (ADME) and planned by the Ministry of Industry, Energy and Mining (MIEM) in coordination with UTE, maintaining public control over planning and operations. UTE also owns approximately 20% of non-hydro renewable capacity.

Within a few years, wind power reached 35–45% of annual electricity generation, while biomass and solar PV expanded in parallel. Uruguay consequently shifted from being a net electricity importer to an exporter, supported by regional interconnections.

While the transition reduced expected cost variability due to power generation, some stakeholders question whether greater state ownership through EPC-based investment could have delivered lower long-term costs and simpler governance. The case highlights trade-offs between fiscal constraints, ownership models, and long-term value capture, often key considerations for developing countries.

Legislation and policy documents

República Oriental del Uruguay. Decreto N.º 354/009: Promoción de energías renovables y diversificación de la matriz energética [Decree No. 354/009: Promotion of renewable energy and diversification of the energy matrix]. 2009. Instituto de Prensa Oficial (IMPO).

Secondary literature

SOAS Development Leadership Dialogue. From crisis to energy security: How Uruguay built national backing for its renewable energy revolution. SOAS: University of London. 2025.

Robbins, Patrick, Johanna Bozuwa, Alex Lenfena, Daniel Chavez, Chris Hayes, Melanie Brusseler, and Anne Debregelas.Who Owns Power in the Energy Transition? Evaluating deregulation and public-private partnerships of public energy utilities internationally. Climate & Community Institute. 2024.

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4. Grid planning and access

Power purchase agreements

Case study: Contract standardisation in South African renewable energy procurement

Legislation and policy documents

Secondary literature

Further reading

Direct power purchase agreements

Case study: Opening the power system to third-party access in South Africa

Legislation and policy documents

Secondary literature

Further reading

Feed-in tariffs

Case study: Feed-in tariffs and renewable energy in Viet Nam

Legislation and policy documents

Secondary literature

Further reading

Feed-in premiums

Case study: Feed-in premiums in Spain

Legislation and policy documents

Secondary literature

Further reading

Contracts for difference

Case study

Legislation and policy documents

Secondary literature

Further reading

Public investment

Case study: Uruguay’s state-led electricity transition

Legislation and policy documents

Secondary literature

Further reading

Keep reading