Case study: Renewables innovation (solar, wind, geothermal) — a leading company's implementation and lessons learned

When Enel Green Power announced in 2023 that it had surpassed 63 GW of installed renewable capacity across 28 countries, the milestone marked more than scale: it reflected two decades of deliberate technology diversification spanning solar photovoltaics, onshore and offshore wind, geothermal, and hybrid storage systems. Enel's renewables portfolio generated 122 TWh in 2024, avoiding an estimated 83 million tonnes of CO2 emissions compared to equivalent fossil fuel generation (Enel, 2025). The company's journey from a vertically integrated Italian utility to the world's largest private renewable energy operator offers concrete lessons in technology selection, procurement strategy, grid integration, and organizational transformation that sustainability leads can apply regardless of company size or geography.

Why It Matters

The global renewables sector added 510 GW of new capacity in 2024, a 35% increase over 2023 and the third consecutive year of record installations (IRENA, 2025). Yet the industry faces mounting challenges that raw capacity figures obscure. Curtailment rates in major markets like China (6.1% for wind in 2024), Texas (8.3% for solar), and Germany (5.7% for wind) indicate that generation growth is outpacing grid absorption capacity. Equipment costs, after years of decline, have stabilized or increased: polysilicon prices rose 22% in 2024 due to supply concentration in China, while offshore wind turbine costs increased 15 to 18% from 2021 levels due to steel, logistics, and labor inflation (BloombergNEF, 2025).

Companies investing in renewables innovation must navigate technology risk, supply chain concentration, permitting timelines averaging 4 to 7 years for major projects in Europe and 3 to 5 years in the US, and evolving grid connection requirements. Enel's experience across all three major renewable technologies and multiple geographies provides a rare longitudinal dataset on what works, what fails, and what the actual financial outcomes look like.

Key Concepts

Technology diversification describes the strategy of deploying multiple renewable generation technologies across geographies to reduce weather correlation, supply chain concentration risk, and technology obsolescence exposure. Enel operates solar, wind, geothermal, and battery storage assets, with no single technology exceeding 45% of total capacity.

Hybrid renewable systems combine two or more generation technologies with storage at a single grid connection point. Enel pioneered this approach at its Stillwater facility in Nevada, combining 33 MW of geothermal with 26 MW of solar PV and 2 MW of solar thermal, demonstrating capacity factors above 85% by pairing baseload geothermal with peaking solar.

Levelized cost of energy (LCOE) represents the net present cost of electricity generation over a plant's lifetime, expressed in dollars per megawatt-hour. Enel's 2024 portfolio-weighted LCOE across all renewable technologies was $32/MWh, compared to $48/MWh for new combined cycle gas turbines in equivalent markets (Enel, 2025).

Repowering involves replacing aging turbines or panels at existing sites with newer, higher-capacity equipment, leveraging existing grid connections and permits. Enel repowered 2.1 GW of wind capacity in Spain and Italy between 2022 and 2024, increasing generation by 40 to 60% at sites with established grid connections.

What's Working

Solar: Bifacial and Tracker Deployment at Scale

Enel's solar division shifted to bifacial modules with single-axis trackers as the standard configuration starting in 2021. The Roadrunner Solar project in Upton County, Texas (497 MW commissioned in 2022) demonstrated the economics: bifacial modules with trackers delivered a 12 to 18% energy yield increase over fixed-tilt monofacial installations at an incremental capital cost of 6 to 8%. The project achieved a first-year capacity factor of 28.3%, exceeding the P50 estimate by 1.4 percentage points. Enel's 2024 data across 14 GW of operational solar shows bifacial-tracker configurations consistently outperforming fixed-tilt by 14 to 20% on an energy yield basis (Enel Green Power, 2025).

The company also invested in predictive maintenance using drone-based thermal imaging and AI-driven anomaly detection. At its Villanueva complex in Coahuila, Mexico (828 MW), automated inspection identified hot spots and micro-cracks across 2.3 million panels, reducing performance degradation rates from the industry average of 0.7% per year to 0.4% per year. The inspection program cost $1.2 million annually but preserved an estimated $4.8 million in generation revenue.

Wind: Larger Turbines and Repowering Economics

Enel's wind strategy centered on two parallel tracks: deploying the latest generation of larger turbines (5 to 7 MW nameplate onshore, 12 to 15 MW offshore) for new projects, and systematically repowering aging sites. The company's Partanna wind farm repowering in Sicily replaced 38 turbines of 850 kW each (32 MW total) with 14 turbines of 4.2 MW each (59 MW total), nearly doubling capacity while reducing the turbine count by 63%. The repowered site achieved a capacity factor of 31%, up from 22% with the original equipment.

The economics of repowering proved compelling across Enel's European portfolio. Average repowering costs of $900,000 to $1.1 million per MW compared favorably to $1.3 to $1.6 million per MW for greenfield onshore wind, primarily because repowered sites avoided the 3 to 7 year permitting cycle for new installations. Enel completed environmental and grid connection approvals for repowering projects in 12 to 18 months on average.

Geothermal: Closed-Loop and Binary Cycle Advances

Enel operates 34 geothermal plants across Italy, the US, and Latin America with a combined capacity of 3.4 GW, making it the world's largest geothermal operator. The company's innovation focus has been on binary cycle plants that extract heat from moderate-temperature resources (120 to 180 degrees Celsius) unsuitable for conventional flash steam technology, and on advanced drilling techniques that reduce well costs.

At its Cerro Pabellon facility in Chile, the world's first geothermal plant above 4,500 meters elevation, Enel demonstrated that binary cycle technology could operate reliably in extreme conditions. The 81 MW facility achieved 92% availability in its first three years despite ambient temperatures ranging from minus 20 to plus 25 degrees Celsius and oxygen levels 40% below sea level. The project required custom-engineered working fluids and heat exchangers rated for the specific brine chemistry, adding approximately 15% to equipment costs but enabling access to a previously untapped 200 MW geothermal resource.

What's Not Working

Offshore Wind Cost Escalation

Enel's offshore wind ambitions illustrate the sector-wide challenges. The company's planned 2.8 GW offshore pipeline in Europe experienced cost increases of 35 to 45% from original estimates between 2021 and 2024, driven by vessel charter rate increases (day rates for wind turbine installation vessels rose from $180,000 to $350,000), foundation steel cost inflation, and skilled labor shortages for offshore construction. Enel deferred or restructured multiple offshore projects, including withdrawing from competitive auctions in the UK and Poland where strike prices no longer supported updated cost assumptions.

The experience mirrors industry-wide trends: Orsted wrote down $5.6 billion on US offshore projects in 2023 to 2024, BP scaled back offshore wind targets, and Vattenfall halted the Norfolk Boreas project citing 40% cost inflation. For companies evaluating offshore wind, the lesson is that LCOE estimates from 2020 to 2021 vintage project economics are no longer reliable benchmarks.

Grid Connection Bottlenecks

Across Enel's global portfolio, grid connection delays represent the single largest source of project timeline overruns. In Italy, the average wait time for grid connection approval exceeded 5 years in 2024, with a queue of 340 GW of renewable applications pending for a grid with 60 GW of peak demand. In the US, interconnection studies through PJM and MISO averaged 4.5 years in 2024, up from 2.3 years in 2019 (Lawrence Berkeley National Laboratory, 2025).

Enel estimates that 8.2 GW of its global pipeline, representing approximately $9 billion in planned investment, was delayed by 12 months or more due to grid connection issues as of mid-2025. The company responded by prioritizing repowering and co-location at sites with existing grid connections, and by investing in battery storage to provide grid services that ease interconnection requirements.

Supply Chain Concentration Risks

Enel's solar procurement relies heavily on modules manufactured in China and Southeast Asia, which account for 85% of global PV module production. The US Inflation Reduction Act's domestic content bonuses and the EU's Net Zero Industry Act created competing incentives for supply chain localization, but non-Chinese manufacturing capacity remains limited. Enel experienced a 4-month delay on its 650 MW Azure Sky project in Texas in 2023 when a key module supplier faced Withhold Release Orders from US Customs over forced labor concerns in the polysilicon supply chain.

Key Players

Category	Organization	Role
Established	Enel Green Power	World's largest private renewable operator, 63 GW across 28 countries
Established	Iberdrola	43 GW renewable capacity, leading offshore wind developer
Established	NextEra Energy	Largest wind and solar operator in North America, 33 GW
Established	Orsted	Offshore wind leader despite recent project writedowns
Startup	Fervo Energy	Enhanced geothermal systems using horizontal drilling, 400 MW in development
Startup	Enerparc	Utility-scale solar developer focused on tracker-optimized bifacial systems
Startup	Rsted (1Komma5)	Distributed solar and storage platform scaling across Europe
Investor	Brookfield Renewable Partners	$75 billion renewable portfolio, active acquirer globally
Investor	BlackRock Climate Infrastructure	$5 billion fund targeting renewable energy and grid infrastructure
Investor	Copenhagen Infrastructure Partners	$28 billion AUM, major offshore wind and green hydrogen investor

Action Checklist

• Conduct technology diversification assessment comparing solar, wind, geothermal, and hybrid configurations for target deployment regions using at least 10 years of resource data
• Evaluate repowering opportunities at existing sites before pursuing greenfield development to leverage established grid connections and permits
• Implement bifacial module with single-axis tracker as default solar configuration and validate energy yield gains against local irradiance and albedo conditions
• Establish supply chain due diligence protocols for PV module procurement including polysilicon traceability documentation to avoid customs enforcement actions
• Model offshore wind project economics using 2024 to 2025 cost benchmarks rather than pre-2022 estimates, stress-testing for vessel availability and steel price scenarios
• Integrate battery storage into new renewable project designs at the planning stage to improve grid connection feasibility and capture capacity market revenues
• Deploy AI-driven predictive maintenance across solar and wind assets to reduce degradation rates and extend equipment lifespans
• Engage grid operators early in project development and budget 18 to 36 months for interconnection study completion in major markets

FAQ

Q: What is the realistic payback period for utility-scale solar with bifacial trackers in 2026? A: Based on Enel's portfolio data and BloombergNEF benchmarks, utility-scale solar with bifacial modules and single-axis trackers achieves unsubsidized LCOE of $24 to $35/MWh depending on location, translating to simple payback periods of 5 to 8 years at current PPA prices in the US and Europe. With Investment Tax Credit or Production Tax Credit benefits in the US, payback compresses to 3 to 5 years. Key variables include land cost, grid connection timing, and module procurement pricing, with module costs representing 25 to 30% of total installed cost.

Q: How should companies evaluate geothermal versus solar or wind for baseload renewable generation? A: Geothermal offers capacity factors of 85 to 95% compared to 25 to 35% for solar and 30 to 45% for wind, making it the closest renewable equivalent to baseload fossil generation. However, geothermal is geographically constrained to regions with accessible hydrothermal resources or suitable geology for enhanced geothermal systems. Exploration risk is significant: drilling success rates for new geothermal wells range from 60 to 80%, with individual well costs of $5 to $15 million. Companies with operations in the western US, Iceland, East Africa, Indonesia, or along the Pacific Ring of Fire should conduct preliminary resource assessments. For other regions, solar or wind paired with 4 to 8 hours of battery storage provides the most cost-effective near-baseload renewable supply.

Q: What are the key risks of repowering existing wind farms? A: Primary risks include: foundation suitability for larger, heavier turbines (structural assessments cost $50,000 to $150,000 per site); updated noise and shadow flicker assessments that may restrict turbine placement or operating hours near residential areas; potential loss of legacy feed-in tariff or PPA terms that may be more favorable than current market rates; and construction logistics of decommissioning old turbines while maintaining partial site operations. Enel's experience suggests that repowering is most attractive at sites where original turbines are 15 or more years old, existing grid connections have headroom for increased capacity, and local permitting authorities have established expedited review processes for repowering applications.

Q: How significant is curtailment risk for new renewable projects? A: Curtailment is increasingly material. In ERCOT (Texas), solar curtailment reached 8.3% of potential generation in 2024, equivalent to $620 million in lost revenue across the fleet. In California (CAISO), midday solar curtailment exceeded 10% during spring months. Projects in high-curtailment zones should model revenue impacts using nodal price forecasts rather than zonal averages, and should co-locate battery storage to shift generation to higher-value hours. Enel's hybrid projects with integrated storage have reduced curtailment exposure by 60 to 75% compared to standalone renewable installations in the same grid zones.

Sources

• Enel Green Power. (2025). 2024 Sustainability Report and Integrated Annual Report. Rome: Enel S.p.A.
• IRENA. (2025). Renewable Capacity Statistics 2025. Abu Dhabi: International Renewable Energy Agency.
• BloombergNEF. (2025). New Energy Outlook 2025: Global Renewable Energy Investment and Cost Tracker. London: Bloomberg L.P.
• Lawrence Berkeley National Laboratory. (2025). Queued Up: Characteristics of Power Plants Seeking Transmission Interconnection as of the End of 2024. Berkeley, CA: LBNL.
• El Paso Water Utilities. (2024). Renewable Energy Integration in Municipal Utility Operations. El Paso, TX: EPWU.
• IEA. (2025). World Energy Outlook 2025: Renewables Chapter. Paris: International Energy Agency.
• Enel Green Power. (2025). Solar and Wind Performance Benchmarking: Global Portfolio Analysis 2020-2024. Rome: Enel S.p.A.