The Looming Gap in Natural Gas Supply
Demand for US natural gas has been growing since before the advent of the shale boom, and has only accelerated in recent years. Prices have been low enough, for long enough, to encourage investment in industrial projects that consume large amounts of gas, such as fertilizer and petrochemical plants. Not only that, but new regulations on emissions combined with low gas prices have encouraged the shuttering of coal-fired power plants and the building of new natural gas plants, as well as switching existing dual-fuel plants to natural gas. This summer has seen record levels of natural gas demand for power generation, reaching a peak on August 11th of 41.9 Bcf out of that day’s total 71 Bcf of total US gas production. (Source: Platt's)
Demand from these sources is expected to continue to rise, as well as exports to Mexico via pipeline and the rest of the world via LNG. The EIA shows these increases in their full-year 2016 forecasts, as well as their 2017 projection.
The agency also forecasts, neatly, that production will rise to meet this demand. In fact, they go on to predict that the US will become a net exporter of natural gas in the second quarter of 2017. In August’s Short Term Energy Outlook, they state “EIA expects production to increase in late 2016 and through 2017 in response to forecast price increases and increases in LNG exports.” They forecast prices at the Henry Hub to average $2.95/MMBtu in 2017. This is slightly lower than the current strip price, which is hovering a few cents over the $3.00 mark.
This expectation of production growth at a 2017 price near $3.00 per MMBtu at the Henry Hub fails the smell test, for a couple of reasons.
First, production has been falling. With the exception of an anomaly in February, US gas production has been declining since last fall, and the gas rig count has flat-lined since early this year, with no sign of life at all, despite a return to gas prices approaching $3 over the last couple of months.
Basically, a rise in gas price of a full $1 at Henry Hub from March of this year until now has failed to spur additional rigs, let alone more production. The reason becomes clear if we break things down geographically and take a closer look.
We know that the prime mover in the shale gas boom has been the Appalachian basin, specifically the Marcellus shale. The EIA also breaks down production by shale play, and their own forecasts don’t show production growth over the next couple of months in the area.
The reason is clear if we consider that prices in the region have been extremely depressed, with little relief in sight in the upcoming months. Cash prices have been well under $1.50 in the area, with averages recently in the $1.25 range. Forward prices are likewise depressed compared to the rest of the country:
Even at the peak of the winter, prices at Dominion South (one of the Appalachian benchmarks) are a full $1 behind the Henry Hub benchmark price, for a netback currently around the $2.20 level. This is even before gathering and processing fees, which would push the wellhead price, even deep in the winter, below the $2 mark. Pipeline additions and expansions will alleviate the situation and help prices, but the forward curve suggests that constraints remain for getting more Marcellus gas to market until at least early 2018.
So it’s clear right now that Henry Hub prices at current levels are not high enough to spur production growth in the nation’s most productive area. How will the gap be filled? There are a few possible ways:
1. Canadian imports rise. In the past, this is exactly how the US has balanced supply with demand, and imports from the Great White North are still a factor, though they have been falling. This is a potential solution, but the market price (typically in the US Midwest) must be high enough to cover the cost of Canadian gas, plus mainline tolls. There have been whispers of TCPL negotiating rate reductions in exchange for long-term agreements, but no deals have been announced.
2. Power generation demand falls. If prices stay high enough, most analysts predict that many plants will switch back to burning coal, which will reduce gas demand. However, prices above $2.50 in the last couple of months have still produced record gas burn for power generation this summer.
3. Henry Hub prices rise further, enabling producers to add rigs in less-productive basins. While costs are higher in the Haynesville, Niobrara, and Permian, these areas don’t share the constraints that the Marcellus producers face in getting their gas to market.
The total size of the supply gap that the US natural gas market faces in 2017 will depend on how cold the winter is, and how far down storage inventory will be drawn by the end of the season. Mid-winter spikes will most likely be filled by Canadian imports, but the ongoing shortfall must be met by higher production from areas other than the northeast. For this to happen, overall prices must rise.