Most infrastructure models, including those for gas plants, focus on project IRR, debt service coverage ratios (DSCR), Project Life Coverage Ratio (PLCR), and EBITDA. However, gas plants are operationally intensive and market-exposed. This means weekly and monthly cash flows can swing dramatically. Even plants that are profitable on a full-year basis face severe cash flow stress during certain weeks, often because of timing mismatches between fuel purchases and market payments. This has implications not just for plant operators, but for lenders, investors, and infrastructure funds betting on gas as the backbone of grid reliability.

There are three key sources of volatility for grid-scale gas-fired generation plants. First, upfront fuel costs: piped gas, the feedstock fuel, is often purchased day-ahead or intraday, with minimal credit terms, especially during periods of high demand or price volatility. Second, ISO payment lags: energy payments from ISOs like ERCOT or PJM can be delayed by up to 30 days, creating working capital gaps. Third, lumpy ancillary and capacity revenues: these can account for 10–30% of revenue, but they are often seasonal, monthly, or even quarterly.

Take, for example, a prolonged period (1-2 weeks) of unusually hot weather. During high dispatch weeks, merchant plants see a sharp spike in fuel costs and volume while revenues from grid operators lag. This creates a working capital crunch. Unless the operator has strong liquidity planning (cash reserves, revolving credit) in place, this mismatch can force financial collapse or reliance on costly credit facilities, even when the plant is profitable over the quarter. Cash is king.

The liquidity problem is especially relevant today because of gas price volatility, peak load season, and rising interest rates. Spikes in global gas prices, with ripple effects even in the U.S. The easing of permitting in the U.S. will hopefully temper this on the supply side. As we enter summer, ERCOT has already issued grid stress warnings. Peaker plants (largely idle plants that are put to work during periods of high demand) are ramping up, and with that, their cash needs are rising. As it relates to power plant cash flow management in today's high-rate environment, maintaining large liquidity buffers or reserve accounts imposes a higher opportunity cost, both in terms of cash drag and the increased cost of debt or credit lines used to support them.

Investors looking at these plants through an annualized EBITDA lens are missing critical intra-year stress points that can trigger covenant breaches or even force early refinancing.

In early 2024, NRG Energy announced its $1.1 billion acquisition of LS Power's 4.9 GW portfolio of peaker and fast-start generation assets, including sites in key merchant markets like ERCOT, CAISO, and NYISO. For the most part, these aren't flashy baseload assets, they're often older, gas-fired peakers that run only during grid stress or price spikes. So why would NRG pay up for them? Because when peakers run, they print cash, but only if you can manage the cash cycle.

I like to think of peakers as the ice cream truck: you make real money when it's scorching out, but only if you can stand the heat and stay out long enough. During summer peaks or extreme weather events, these plants can generate 30–50% of their annual revenue in just a few weeks. But the fuel must be purchased upfront. The ISO payments often come later. Maintenance risk spikes. Credit requirements increase.

What NRG is buying isn't just power capacity, it's a portfolio of optionality, contingent on their ability to manage liquidity during crunch weeks. This underscores a key theme: these assets are highly valuable if you can handle the short-term liquidity volatility. A weak sponsor could easily lose that value due to poor cash planning. A strong operator with smart 13-week forecasting and access to liquidity facilities turns a volatile asset into a strategic cash flow engine.

A sophisticated power plant CFO or infrastructure fund analyst should treat liquidity risk with the same seriousness as fuel supply or maintenance risk.

Here's what that looks like in practice:

Weekly Cash Stress Testing: Use 13-week rolling cash flow forecasts to model worst-case volatility in fuel costs, ISO payment delays, and unplanned outages.

Tie Capacity Payments to Working Capital: Don't treat capacity payments as free upside. Use them to backstop peak working capital needs.

Structure Flexible Credit Lines: Even a modest revolver or delayed draw term loan can bridge funding gaps, preserving operational optionality. It's always better to arrange this before it's needed.

Build Liquidity Covenants into Operating Agreements: Investors should demand minimum cash or working capital buffers, not just DSCR compliance.

Natural gas-fired generation isn't going away. In fact, with the grid becoming more weather-dependent and renewables gaining momentum, flexible dispatchable generation is becoming more valuable. But that premium value is lost if the asset can't operate when it's needed most, simply because it doesn't have cash on hand.

If you're underwriting gas projects, or backing sponsors who are, ask this: What does the cash position look like in Week 7 of a 13-week model? If the answer is "we don't know," you may be sitting on a hidden risk.

The failure of a plant rarely comes from lack of profitability, it comes from a failure to convert earnings into cash in time. In this market, liquidity isn't just a financial metric. It's an operational weapon.