2026 will feel less like “more renewables” and more like “more system engineering.” The winners won’t just be the cheapest generators — they’ll be the developers, utilities, and financiers who can deliver firm, flexible, and financeable electrons at scale. From a financial modelling lens, the biggest shift is that value is moving from MWh produced to services delivered (capacity, flexibility, congestion relief, resilience). 🌍📈⚙️
1) Electricity demand is rising faster — and it’s spikier ⚡📊🌍
The power sector is absorbing growth from EVs, heat pumps, and (increasingly) data centers and AI workloads. That demand is not smooth: it creates new peaks, new locational constraints, and a higher penalty for outages. Ember’s recent global reviews show renewables’ share rising strongly (30% in 2023; record levels again in 2024), but demand growth is also accelerating — which means the grid must expand and become more flexible at the same time. 📈⚡🌍
Modelling implication: Your load profile matters again. I’m seeing more investment committees ask for hourly (or sub-hourly) revenue simulations rather than monthly averages — especially where merchant exposure exists. 📊🧮⚙️
2) Grids become the binding constraint (and a capital market) in their own right 🧩⚡🏗️
For years, we underwrote renewables like the grid was infinite. In 2026, interconnection queues, transformer lead times, and local congestion are core risks. The IEA is explicit: as we enter the “Age of Electricity,” demand for grid expansion is rising rapidly, and efficiency can reduce the investment gap. Separately, IEA work on transmission supply chains highlights how component bottlenecks (transformers, cables) are now project-critical. 🧩📉⚡
Modelling implication: In diligence, I now treat grid connection like a mini-project: milestone-based probability weighting, schedule risk (COD slip), and capex escalation scenarios for key equipment. 📊🏗️⏱️
3) Storage moves from “nice-to-have” to “revenue stack” 🔋📈⚙️
By 2026, batteries are less about “renewables smoothing” and more about capturing price spreads, providing ancillary services, deferring network upgrades, and firming corporate PPAs. This is also where investors get tripped up: a BESS is not a single cashflow line; it’s a stack. 🔋📊⚡
Modelling implication: I typically model at least three layers: (1) energy arbitrage, (2) frequency/ancillary services, and (3) capacity or reliability payments (where applicable). The risk is correlation: stress-test what happens when multiple revenue streams compress at the same time. 📉🧮📊
If you want a starting point for BESS underwriting (10-year structure, sensitivity framework, debt sizing logic), this template is a solid baseline: https://www.eloquens.com/tool/wyv8teXq/finance/renewable-energy-excel-financial-models-methods/battery-energy-storage-system-bess-10-year-financial-model?ref=finteam ⚡🔋📊
4) Wind’s “reset” and auction redesigns change the pipeline 🌬️📉⚖️
Several markets are revisiting auction design, indexation, and risk allocation after tougher development economics (rates, supply chain inflation, permitting). Reuters has pointed to expectations of a wind sector uplift in 2026 after a difficult period, supported by policy adjustments and improving market conditions in some regions. 🌬️📈🌍
Modelling implication: Don’t assume a fixed WACC and a stable EPC price environment. I’m increasingly using inflation-linked capex, rate-lock scenarios, and contract structures that pass-through specific inputs (e.g., steel, turbines) — then testing DSCR headroom. 📊💶🧮
5) Capex discipline + higher rates force better project structuring 💶📉📊
Global energy transition investment has been setting records — BloombergNEF reported $1.8T in 2023, and later reporting indicates totals exceeding $2T in 2024 — but capital is more selective. Investors want clear offtake, credible grid access, and resilient downside cases. 📊💶⚖️
Modelling implication: You’ll see more focus on minimum DSCR, sculpted debt, cash sweep mechanics, and conservative degradation assumptions. For merchant or quasi-merchant projects, the “bank case” is increasingly based on a percentile pricing deck, not a single curve. 📉📈🧮
6) The transition becomes more regional (and more geopolitical) 🌐⚖️📍
Supply chains are localizing (or at least diversifying), and policy risk is back as a first-order variable. That doesn’t stop the transition — it changes where manufacturing and deployment happen and how contracts are written. The lesson for 2026 is that energy security and decarbonization are now intertwined — and that affects everything from tariff exposure to local content requirements. 🌐⚡🌍
Modelling implication: I’m adding explicit lines for tariffs, FX mismatch, and local content cost uplifts, then mapping mitigants (indexed PPAs, hedging, blended finance, political risk insurance). 📊💱🧮
7) ESG becomes operational: permitting, community value, and resilience 🌱🏗️⚖️
In 2026, ESG is less about glossy reporting and more about execution risk: land use, biodiversity, grid reliability, and community benefits. Projects that can quantify local value (jobs, reliability, reduced diesel reliance) tend to move faster through stakeholder processes and financing committees. 🌱📊🤝
Modelling implication: I often include a “social value” appendix in investment memos (not to inflate returns, but to de-risk approvals). For emerging markets, I also separate affordability from bankability and show how guarantees or blended structures bridge the gap. 📉🌍📊
What I’m watching (and building into models) for 2026 👀📊⚙️
- Hourly capture price erosion for high-penetration solar/wind nodes
- Curtailment as a base-case line item, not a tail risk
- Transformer/cable lead times as a critical path constraint
- Revenue stacking for storage and hybrid projects
- Policy sensitivity (auction redesign, permitting, trade measures)
If you’re preparing an investment case for 2026, a simple question helps: Is your project selling energy — or selling reliability? The more your model can demonstrate the second, the easier the financing conversation becomes. ⚡📈💡
Finteam 