Don't Get Me Wrong - Are Government Forecasts Underestimating Gas Burn for Power?

Last summer, a tight coal market in the Eastern U.S. made an already tight natural gas market even tighter. Low coal stocks, dwindling production and transportation constraints led to exorbitant premiums for Appalachian coal and limited coal consumption in the East, leading to record gas demand for power generation — even as gas prices soared to 14-year highs. Now, gas markets are considerably looser, storage inventories are high, and gas prices are signaling the need for more demand (or lower supply) to balance the market and avoid storage constraints this injection season. But the coal market has eased as well. Coal production is up, coal stocks are too, and Appalachian coal prices have plunged in recent months. What will that mean for power burn and balancing the gas market this summer? In today’s RBN blog, we look at the latest developments in the coal and gas markets, the potential for coal-to-gas switching, and how those dynamics could impact gas balances.

Gas-fired power generation in the U.S. has been making impressive gains lately and that trend looks likely to continue. Power demand is growing quickly and generation fueled by cheap natural gas is taking an ever-increasing market share of the new and existing load from more expensive generators like coal and nuclear, which is leading significant numbers of those plants to shut down. The Energy Information Administration (EIA) earlier this year forecast that combined-cycle, gas-fired generation capacity could rise by 6.1 GW between now and 2020, which ­— if fully called upon — would equate to roughly 1 Bcf/d of gas demand. That growth would displace some older gas-fired generation but also fill the void left by retiring coal-fired and nuclear power generators — two sectors EIA expects to decline over the next couple of years by 14.1 GW and 1.7 GW, respectively. What’s more, surging gas production and rapidly filling pipeline expansions in recent months suggest that gas-fired generation demand may be growing even faster than expected. Today, we take a look at how gas generation has been besting coal-fired plants on fuel costs in recent years, and at the string of nuclear and coal-fired generators that are being permanently retired.

The CME/NYMEX Henry Hub prompt natural gas futures prices have been relatively rangebound this injection season and have averaged around $2.60/MMBtu since June — a third or less of where prices stood during the same period last year, in the $7-$9/MMBtu range, and at or below most natural gas producers’ breakeven costs. Yet, this is a much rosier scenario than it could have been considering that the first quarter of 2023 was one of the most bearish in over a decade and led to a massive storage surplus vs. last year that persisted through much of the summer. Since setting the year-to-date monthly average low of $2.19/MMBtu in April, prompt futures rose to an average of nearly $2.50/MMBtu in June, ~$2.65/MMBtu in July and August, and have mostly stayed in the $2.50-$2.75 range in September to date. In today’s RBN blog, we break down the factors that kept prices from unraveling this injection season to date and the implications for the rest of the shoulder season.