Why utilities must rethink natural gas procurement for a high-demand future

Electric utilities are grappling with the reality that the past is not prologue when it comes to electricity demand. Just a few years ago, many utilities assumed that flat load growth and decarbonization policies aimed at increasing electrification meant they didn’t have to worry much about securing sufficient volumes of affordable natural gas.

Those days are over, at least for now. Utilities face real concerns about managing the price and volume risk tied to obtaining enough gas. A major risk driver is the electricity demand of data centers. Data center load growth tripled from 2014 to 2024 and may double or triple again by 2028, according to an analysis by the U.S. Department of Energy’s Lawrence Berkeley National Laboratory.

“Across the industry, we’re seeing a resurgence in the need for new natural gas generation,” said Brian Despard, senior project manager at 1898 & Co., the consulting arm of Burns & McDonnell. “Load forecasts are increasing, especially with the demands from 24/7 operations like data centers and large industrial loads. That naturally leads utilities back to gas, and it’s increasing the pressure to manage procurement risk more strategically.”

Growing need and complexity

Planning for natural gas is difficult because gas-fired units are often dispatched based on market prices or short-term needs, making daily volume requirements unpredictable. Waiting until the last minute is risky—prices fluctuate with weather, power demand, LNG demand, and pipeline congestion.

“The complexity is growing,” said Matthew Lind, director of resource planning and market assessments at 1898 & Co. “We’re seeing cost pressure, delivery constraints, and increased reliance on a system that hasn’t added major pipeline infrastructure in years. That creates planning challenges that utilities need to factor into every major investment.”

This risk is especially acute in Northeastern states, where fracking bans and pipeline permitting limitations restrict access to reliable gas delivery. Limited gas supply during high demand periods has forced utilities to burn more expensive fuels or even curtail load—threatening both reliability and affordability.

“You can’t assume fuel will show up just because you built a gas plant,” Lind said. “That delivery network has to be planned for, and it’s increasingly important to recognize regional pinch points and infrastructure limits.”

Why utilities need a strategic, future-focused procurement strategy

Reactive natural gas procurement strategies cannot prevent price spikes or ensure reliability. Instead of relying on spot market purchases dictated by daily events, utilities must embrace a structured and long-term procurement strategy that accounts for uncertainty.

This will vary by utility, depending on risk tolerance and available planning tools and expertise. “We recommend defining clear procurement and hedging objectives and using probabilistic modeling to quantify price and volume risks,” Despard said. “From there, you can build a structured program that tests different hedge strategies and adapts to market conditions.”

Hedging strategies can significantly lower risk while still allowing utilities to take advantage of short-term market opportunities. For example, programmatic hedging locks in gas prices over fixed intervals, regardless of market conditions. Other strategies adjust volumes when prices drop or trigger hedges if prices spike. These approaches allow utilities to match gas positions with expected power needs and adjust as needed.

A phased hedging strategy over a three-to-five-year timeframe can also be effective, Despard said. “Early on, you want to lock in the most certain volumes further out. As you get closer to the month you need the gas, the hedging becomes more dynamic, reacting to updated load forecasts and price signals.”

Co-optimized planning is mandatory

As the energy system becomes more integrated and complex, utilities can’t plan gas and power in silos. In constrained regions like New England, for example, limited land for new renewable generation and natural gas pipeline limitations have forced planners to model energy systems holistically, balancing seasonal gas storage, renewable intermittency, and electrification all at once.

This need is expanding nationwide. “You have to look at the whole system,” Lind said. “If you’re planning power and gas separately, you can miss how deeply they depend on each other. That interdependence becomes even more critical when you’re retiring coal and expecting renewables and gas to fill the gap.”

Co-optimization helps answer critical questions: Do current pipelines support new generation? Can you afford the price and volume risk of interruptible gas? Are long-term procurement plans aligned with decarbonization timelines?

While integrated resource planning is already complex, adding co-optimization and probabilistic gas modeling is too vital to delay.

“This isn’t about getting paralyzed by complexity,” Lind said. “It’s about recognizing that ignoring it means risking unfavorable decisions on infrastructure.