Natural Gas Wins Big in Power Plant Rules

Much has already been said about the Environmental Protection Agency (EPA)’s recently proposed plans to lower greenhouse gas emissions over the next three decades. Under the EPA’s proposed mandate, power plants must achieve a 25 percent reduction in carbon emissions by 2030, and 30 percent by 2040. The EPA’s new rule targets the electric power sector, which produced one-third (32 percent) of U.S. carbon emissions in 2012. Much of that was generated by coal-fired plants that fueled 37 percent of the nation’s electricity. States may improve energy efficiency standards, switch to renewable power sources, or create markets for carbon emissions. The rule doesn’t mean much for oil, which only contributes 0.4 percent of carbon emissions from power generation. Is the rule a blanket win for renewables? Wind and solar will benefit, but most of these emissions reductions will come from a transition from coal to natural gas. Compared to coal, natural gas emits far less carbon dioxide per megawatt hour. It is also in growing abundance thanks to the domestic shale gas bonanza, and this increase in supply is fueling surging demand in its own right: long before EPA’s rule was released, The Dow Chemical Company projected a 75 percent increase in total natural gas demand from current levels over the next 20 years given the new demand for the “Prince of Hydrocarbons” from LNG exports and natural gas vehicle, as well as what it describes as a “manufacturing renaissance.” The EPA anticipates that its emissions reductions plan will add five percent to U.S. natural gas demand, and increase prices by 12 percent. Implications for Future Natural Gas Demand Although the United States is currently a net importer of natural gas, this is estimated to change in 2017 as U.S. gas production surpasses consumption. The EIA, in its reference case  forecast, estimates that the United States will export 18 percent of its natural gas supply in 2040. That estimate was made prior to the EPA’s announcement. The American Natural Gas Association (ANGA) estimates that the EPA’s proposal could increase natural gas demand for power generation by as much as ten billion cubic feet per day, an almost 50 percent increase from current levels of 22 bcfd. ANGA’s projected growth rate equates to 365 trillion cubic feet per year. As many analysts and experts have noted, everybody wants a bite at the natural gas boom apple, and while prices remain (relatively) low at the moment, supply and demand fundamentals mean that the days of $4 per mBtu gas are limited. Higher prices enable producers to invest in a broader range of more challenging geologies. In addition to increased demand from power plants and manufacturing, LNG exports will also draw on supplies—9.27 bcfd of exports have already been approved. If all approved export facilities are operating at full capacity in 2025, and ANGA’s projections are met in 2030, those two added sources alone will push domestic natural gas demand toward EPA’s high production supply scenario. It’s worth noting that all of the forecasts are, of course, uncertain.  In addition to the inherent difficulty in forecasting energy market dynamics 25 years into the future, ANGA’s calculations are admittedly “back of the napkin.” Meanwhile, the full story on LNG exports remains to be told. It’s unclear when many of the approved export facilities will be completed, if they will all operate at full capacity, which additional facilities will be approved, production conditions, and other unforeseen changes in global natural gas markets. Still, the data below provide a rough demonstration of the emerging market dynamics.

It is also important to emphasize the inherent volatility of natural gas markets, which could easily shake many of these assumptions. With the exception of one price spike in 1996, natural gas prices were steady in the 1990s before becoming more volatile in the 2000s (Figure 2). Price spikes in 2000-2001 were, in part, precipitated by uncharacteristically cold temperatures in the Northeastern United States. Price spikes in 2003 and 2005 were again brought about by major weather events, including Hurricanes Katrina and Rita. Between 2008 and 2012, prices came down as the United States invested in unconventional shale drilling techniques. Even just this year, Henry Hub spot prices climbed to $6.22/mBtu—a five year high—due to unanticipated winter demand.

Natural gas proponents will point out that global natural gas markets are still less volatile than global oil markets. When compared with Brent crude oil prices ($/million Btu), Henry Hub natural gas prices fluctuate significantly less than crude. Between 2010 and 2012, for instance, natural gas at the Henry Hub fluctuated around $5/million Btu. Global crude, meanwhile, rose the equivalent of $13 to $19, before falling to around $17 per million Btu. However, even if price volatility between oil and natural gas differs, the negative consequences for businesses and the economy remain true in both cases. Natural gas only displaces oil in one sector—natural gas vehicles—and in such cases will serve as a preferable alternative since natural gas prices are lower and less volatile than oil or gasoline prices. Furthermore, the rapid increases in supply and demand—not to mention the various regulatory uncertainties—are likely to drive greater natural gas price volatility in the future, which could impact residential and commercial consumers.

This is not to say that the natural gas bonanza isn’t an unambiguously good thing for the economy and our energy security. However, as we move forward, various stakeholders must be cognizant of volatility and supply/demand fundamentals to mitigate the risks associated with price spikes and other adverse impacts.