What a difference some mild winter weather makes. Now, after around seven weeks of predominantly milder weather, the market balance is looking much more relaxed. While the demand side is still going to boast higher exports over the year, as gas markets in other areas of the world have experienced a much colder winter, storage injections are going to be less onerous—stocks are unlikely to end the winter below 2.0 tcf given prevailing weather forecasts.
The 2017 production outlook remains clouded at the moment, as despite the underlying fundamental indicators all pointing to a better environment for producers, output has been staying stubbornly below 71 bcf/d.
One of the key reasons for this, particularly in the Northeast, is that the time lag between drilling and completion is long, with wells tending to stay drilled but uncompleted (DUC) for five or six months. The implication is that the increase in drilling activity across Q4 16 will only really show up in production from Q2 17 onwards. As such, a sluggish start to the production numbers this year is largely to be expected.
However, that production response might be smaller than previously expected. Drilling in the predominant gas plays improved markedly in Q4 16 but has largely stalled since. Northeastern rigs rose from a low of 36 in August 2016 to around 60 by December, where they have stayed since. Rig efficiencies, however, are much higher after the strong improvements seen in 2016.
Northeast production will also benefit from more take-away capacity, both that added in 2016 and that scheduled in 2017. Not all of the 16.4 bcf/d of capacity scheduled for completion this year will materialise—some will be pushed into 2018—but at least 2.25 bcf/d, at the low end, should be added. Issues at FERC, which are leading to an effective freeze on approval of new projects, appear to be a serious headwind for Northeast infrastructure this year. However, even given this, we expect the Northeast to add around 2.3 bcf/d to supply in 2017. Given some good growth from the Permian, but accounting for some falls in conventional production, we expect total US gas production to rise, but by no more than 0.9 bcf/d over the year.
For the Permian, the swift increase in drilling activity and the addition of lots of new gas transportation in the region, particularly for exports to Mexico, means that we expect the Permian to add some 1.5 bcf/d to gas supply. As such, the upward pull on Henry Hub prices could be muted by more gas coming into the southern regions.
In terms of our balances, the key change is a 4 bcf/d write-down on the outlook for Q1 17 res-com demand. With that, our forecast for end-March storage is now 2.1 tcf. This means more gas for power over the summer quarters and lower gas prices as a consequence.
For Q1 17, we now expect prices to average 3.0 $/mmbtu, down from our previous forecast of 3.45 $/mmbtu on the impact of mild weather against the curve. Our 2017 price forecasts have dropped from an annual average of 3.2 $/mmbtu to 3.0 $/mmbtu on the weaker first three quarters of the year. Against the prevailing curve, we are bearish. What is clear is that the summer balances now look much more relaxed than they did four weeks ago, taking away some of the pressure for summer gas prices to go back up.