The Gas Sector Implications of a Crude Oil Price Trough

Oil prices have collapsed dramatically since June. As our colleagues noted earlier this week, Brent prices in the low $80s translate to Bakken prices in the low $70s (or below), putting pressure on unconventional producers. At current price levels, operators with high cost structures may be prone to slow or stall their investment in new wells. Even lower-cost operators (many of whom spend more than they take in) will have diminished cash flows available to invest in future production.

U.S. producers tend not to shut in their wells during periods of low prices, but tight oil wells decline quickly (in some cases by as much as 60% within the first year of production). Should prices remain low for several months, the market may learn whether U.S. tight oil truly functions as a sort of “synthetic spare capacity” that balances global supply. Much of the current discussion has focused on oil production impacts and, to some degree, the de facto economic stimulus that lower gasoline and diesel prices provide, but the current price trough has potential to impact U.S. natural gas prices and – to some degree – the global competitiveness of U.S. liquefied natural gas (LNG) exports and petrochemical investments in the United States.

According to International Energy Agency (IEA) estimates, more than half of U.S. natural gas output comes from “associated” volumes that are a byproduct of oil production. As a result, any slowdown in oil drilling could correspond to a slowdown in the growth of the gas supply, too. If this happens, the nation won’t run short of natural gas. Vast, untapped shale gas resources remain, especially within the Haynesville and the gas-prone regions of the Marcellus. That said, production could shift to a modestly higher point on the supply curve.

Meanwhile, domestic demand for natural gas is poised to grow briskly, and recent and pending environmental policy could put a floor beneath it. In 2015, approximately 1.0 billion cubic feet per day (Bcf/d) of power sector demand could come from coal-to-gas switching due to the Environmental Protection Agency’s (EPA) Mercury and Air Toxics Standards, rising to slightly less than 3.0 Bcf/d of incremental demand by the end of the decade. Should EPA finalize its Clean Power Plan as proposed, the agency projects anywhere between 2.3 and 4.9 Bcf/d of additional power sector gas demand in 2020.

New and reinvigorated manufacturing activity could drive anywhere between 2.5 and 6.0 Bcf/d of industrial demand within the same timeframe. These price-sensitive industrial consumers might slow their own investment plans in the event of a dramatic price spike, but likely production of abundant reserves in gas-prone formations suggests a modestly higher acquisition cost, rather than a spike. Higher feedstock costs are only part of the story for U.S. petrochemical manufacturers, however. Overseas competitors largely rely on crude oil-derived feedstock, meaning that lower crude prices and higher gas prices add up to diminished competitive advantage for U.S. petrochemical companies.

The same is likely to be true for LNG. U.S. projects price their deliveries in proportion to the price of gas at Louisiana’s Henry Hub. At present, the vast majority of competing global suppliers price LNG in proportion to crude prices using oil-indexed “S-curve” contracts (prices proportional to crude within a bounded range). Most U.S. projects are structured as “tolling facilities” where buyers commit to a “reservation charge” that provides a significant share of project financing. A sustained period of lower global crude prices – especially when combined with higher Henry Hub prices – could make it harder for would-be U.S. project developers raise capital for their prospective projects.

All of this is subject to the nature of the oil market adjustment underway.  How low will prices go? How long will it last? It is also subject to other difficult to predict factors as well – natural gas still occupies a market position that is relativistic.  For example, gas’s future role in power generation in the United States is partially determined by environmental regulation that is far from concluded and definitely contentious. Moreover, power generation fuel switching and dispatch choices are often determined by the relative cost of natural gas compared to coal. The push to include natural gas in more and more parts of the transportation fuel mix was predicated on an oil and gas price differential that investors had to have enough confidence in to make long-term infrastructure investments. Indeed, even international buyers of natural gas were aggressively pursuing hub based gas pricing contracts with view towards hub-based pricing being preferable to oil-based contracts. However, according to the Energy Intelligence Group, with current Henry Hub prices, a Brent price of $80 per barrel for oil (and a slope of .145), the arbitrage opportunity to Asia drops to about $1 per one million British Thermal Units.  If oil prices recover quickly this oil price decline may be little more than a shock to the system. If it’s sustained, however, these new gas opportunistic strategies may start to be tested by newly emerging market realities.

Kevin Book is a senior associate in the Energy and National Security Program at the Center for Strategic and International Studies (CSIS) in Washington D.C. Sarah O. Ladislaw is a senior fellow and director of the Energy and National Security Program at CSIS.

Commentary is produced by the Center for Strategic and International Studies (CSIS), a private, tax-exempt institution focusing on international public policy issues. Its research is nonpartisan and nonproprietary. CSIS does not take specific policy positions. Accordingly, all views, positions, and conclusions expressed in this publication should be understood to be solely those of the author(s).

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