As natural gas goes, so goes power.
The U.S. gas and power markets continue to be transformed by a combination of increasing regulation and shifting supply. (See "The Need for ETRM Software in US Energy Markets.") EPA regulations designed to reduce CO2 emissions are forcing the early retirement of dozens of otherwise viable coal-fired facilities, forcing power producers to turn to natural gas or renewable resources to fill the capacity void. Renewables, chiefly wind and solar, are comparatively expensive and, by their nature, unreliable sources of energy as they are dependent on favorable weather. Without economically feasible energy storage, these renewable sources cannot, on their own, meet the prerequisites of the U.S. power grid for reliability and economy. With few new coal facilities being built, an increasing portion of the base load and the burden of meeting peak power demand is falling on natural gas.
While natural gas is currently less than 30% of the generation mix in the U.S., the operational flexibility of gas generation has made it the logical choice for meeting peak requirements and maintaining grid stability. With rapid start and ramp capabilities, natural gas turbines can be called on in minutes to meet grid load requirements. Given this flexibility, and a relatively low carbon impact, it's little wonder that most forecasts indicate natural gas will continue to increase its share of our future generation mix – to as much as 40% by 2040.
The U.S. Energy Information Administration (EIA) estimates that
the percentage of the U.S. generation mix supplied by natural gas
will increase from 30% today to as much as 40% by 2040.
Even in regions with lower than average gas-fired generation, such as the eastern interconnection grid PJM (the world's largest competitive wholesale electricity market) where natural gas makes up only 17% of the generation capacity, natural gas has become the primary fuel in peaking facilities. This reliance on natural gas during times of peak needs has led to highly correlated prices between power and natural gas. In fact, at the PJM West Hub, prices for power have been averaging a 95% correlation to prices at the natural gas Henry Hub since 2008. Even in non-peak times, gas-fired generation continues to be the marginal source for power, ramping as necessary to ensure grid stability. Given this important role as swing producer, it’s clear that as gas prices go, so go wholesale power prices.
With natural gas fully entrenched in the U.S. power market, gas supply disruptions during peak loads can, and have had, devastating impacts on power delivery in all regions of the country. Unfortunately, as most of the new and most prolific sources of natural gas, such as the Marcellus Shale, are underserved by gathering and long-haul pipeline and treating infrastructure, getting gas to generators during periods of highest demand (such as during cold snaps in the Northeast) has been difficult due to pipeline capacity constraints. That difficulty is fully reflected in the price of both power and natural gas during peak load, when prices for both commodities can shoot up more than a thousand percent over their non-peak prices.
In this market, the real money for traders is won or lost during these peak times. Having real-time visibility into commodity positions and transportation/transmission options is key to ensuring traders are properly positioned to address market needs and meet obligations, and that they can take advantage of sudden unexpected opportunities. Unfortunately without a fully capable ETRM software solution, one that can manage both natural gas and power in a single view, that visibility just isn’t available to traders at the most critical times — when the opportunities, and the risks, are the greatest.