The business case for day-ahead optimization at renewables

With real-time prices falling, day-ahead participation rates for solar assets have reached 30%, with an average $1.50 per MWh improvement in returns.

For owners and operators of renewable assets, the ability to predict long-term trends is integral to the profitability of their assets. How will load growth affect revenues for solar farms against a backdrop of likely-to-disappear tax credits? How will nodal prices change in several years based on the current state of the interconnection queue?  In ERCOT, against the backdrop of impending trends like OBBBA, load growth, solar growth and increasing penetration of battery storage, the facts remain: real-time prices have dropped considerably in the last few years.

The average trailing-twelve months (TTM) real-time price in ERCOT has declined considerably since 2023.

For solar and wind developers, sustained weakness in real-time prices erodes merchant margins and complicates the investment case—especially as federal subsidies diminish. This poses a challenge for the largest U.S. power market by load, particularly in contrast to the tripling of renewable capacity in China over the past five years.

Most utility-scale renewable projects in ERCOT are financed through long-term financial hedges or PPAs that settle at liquid hub prices, often indexed to real-time settlement. While these contracts provide revenue stability, they also leave projects exposed to several merchant risks—most notably basis risk between the hub and project node, shape risk from deviations between contracted and actual generation, and residual exposure to real-time market volatility. Without a capacity market in ERCOT, there is no supplemental forward revenue stream, so merchant upside typically comes from selling excess generation into spot markets. As real-time prices have declined, that incremental merchant opportunity has narrowed, pressuring returns for projects with material merchant exposure.

Key Takeaways

• Real-time power prices in ERCOT have fallen sharply in recent years, reducing the merchant revenue opportunity for wind and solar developers.

• Even with long-term hedges or PPAs, projects face residual merchant risk from basis, shape, and real-time market exposure, and without a capacity market, the shrinking real-time opportunity directly impacts returns.

Short-Term Levers for Protecting ROI

There is good news in the short term for renewables developers worried about their ROI. Load growth in Texas may inflate prices, and collocated storage can support solar developers shifting production from solar weighted to evening hours.  

Prices during solar hours have now inverted to be cheaper than the average in ERCOT - a sign of increased solar capacity.

A few trends are beginning to emerge from the past few years.  The rise of solar in ERCOT has caused solar-weighted hours (which remain the highest load hours of the day) to be less than the average; a change since 2023. Day-ahead prices remain higher than real-time prices, reflecting the risk premium of committing resources.  Solar developers with merchant exposure can take advantage of the day-ahead premium with targeted trading strategies to improve ROI of operating assets.

Day-Ahead Optimization Matters

The arbitrage opportunity to lock in a higher DA price because of a suspected depression in RT price is not new – risk-tolerant liquidity traders have reaped profits on the strategy since deregulation in the early 2000s.  In ERCOT, where the data is particularly transparent, solar developers are joining the game.

Solar asset participation in day-ahead market volumes as a percentage of real-time generation over time.

Anecdotally, the trend makes sense: when solar-weighted average RT prices were above $50, the resources required to capture the day-ahead premium may have been better spent elsewhere. With prices trending around $25 and several heatwaves behind us this summer, the opportunity in day-ahead optimization remains.

For many generators that don’t participate in the day-ahead market, their generator profit is equal to a real-time only strategy: they make exactly what they generate multiplied by the real time price. But for those willing to take make partial commitments into the day-ahead market, generator profit is higher by 7.7%.

Solar and wind assets can both increase generator revenues by participating in the day-ahead market.

For generators that participate in the day-ahead, they can make more or less than the real-time only strategy depending on the day-ahead premium at their price node. In practice, outperforming real-time only strategies requires accurate forecasts to reduce production and decision risks.

Production risk is the financial exposure caused by uncertainty in actual solar output at delivery time. Solar developers that too aggressively try to capture the day-ahead premium may expose themselves to covering a shortfall in production (forecast error, operational downtime) during a real-time price spike.

Decision risk is the opportunity cost of committing a volume of generation to the day-ahead price when the real-time price is higher – there’s a day-ahead premium on average but forecasting the right hours is important for day-ahead optimization to be profitable.

From January 1, 2025, to June 1, 2025 over 100 of a sample of roughly 500 mapped wind and solar resources have sold generation in the day-ahead market according to ERCOT SCED data.

• Of the 23% of mapped resources that participated in the day-ahead market, 88% have made more money than a RT only strategy, with the remaining 12% losing money (mostly due to the opportunity cost of being in the wrong market)

• Resources that participated in the day-ahead market outperformed a real-time only strategy by 7.7%, or an improvement of $1.50 per MWh

Other ISOs

Other ISOs were omitted from this analysis, but are likely to have higher DA participation rates as a downstream effect of capacity supply obligations or resource adequacy contracts. The same risks exist: the opportunity cost of being in the wrong market and the production risk of failing to meet day-ahead commitments, though often there are competing risks for a trader including basis risk with a forward contract or other existing financial obligations.

The Road Ahead for Renewable Bidding 

Day-ahead optimization is quickly becoming a core strategy for renewables in ERCOT, as falling real-time prices squeeze merchant revenues. Load growth may help support prices, but continued solar buildout will keep pressure on daylight hours. Renewable operators that can accurately forecast next-day prices are likely to experience better returns on merchant revenue than those that are price takers in the real time.

Enertel AI provides short-term energy price forecasts and bidding benchmarks for utilities, independent power producers (IPPs), and asset developers. If you're interested in a free benchmarking assessment of your asset, book a demo or reach out to learn more.

The data in this report can be found in the 60-day delayed reports from ERCOT, or is commercially available with Yes Energy or Grid Status.