Despite a warm April, when residential and commercial demand ebbed, Henry Hub prices remained supported as US dry gas production continued to underwhelm. Production readings largely came in around 70-71 bcf/d with a bias to the bottom of that range—only in the first half of May has there been a movement back up towards 71 bcf/d.
Despite prices staying well above 3 $/mmbtu across all the 2017 contracts, drilling activity focused on dry gas plays has stalled since the start of the year. While gas activity is comfortably higher y/y, the continued growth in drilling being seen in the oil plays over the last few months has not extended to the gas plays, with Marcellus rigs stubbornly staying in the low 40s.
For the remainder of the summer, the key to unlocking higher gas production is likely to be new pipeline infrastructure. In this regard, a key project is the first phase of Energy Transfer Partners’ 3.25 bcf/d Rover pipeline which will take Northeast gas to Midwest, Southern and Canadian markets, and which has an expected in-service date of July. That said, the pipe has been plagued by a number of issues and still has several hurdles that it must clear in order to maintain its project timeline. While there are a lot of potential projects in development and in construction, issues of potential delay are acute this year, given FERC delays to pipeline permissioning.
While we assume that some of the 2017 pipeline capacity additions will be subject to delay, our Northeast production forecast is for y/y growth of 2.6 bcf/d. Furthermore, based on the regional rig count, which has not seen significant upward movement so far in 2017, we assume producers will struggle to fill all the pipeline capacity coming onstream, even with a continued focus on well completions.
We still expect oil plays to be quite strong this year, particularly the Permian, which will add 1.56 bcf/d of incremental gas production into the market. All in all, we are now forecasting that lower-48 dry gas production will grow by 1.0 bcf/d in 2017—up from last month’s 0.11 bcf/d forecast largely on the revisions to rig productivity levels and a larger uptick in Q4 17 output. That said, the latter depends on pipeline infrastructure, so any delays could temper the growth. Nonetheless, with net imports expected to drop by 2.1 bcf/d this year (a combination of LNG exports and pipeline exports to Mexico), gas available for power will remain constrained.
For the quarters out to Q1 18, the global arbitrage windows for LNG exports remain open. With the 2017 summer-month contracts at the Henry Hub below 3.4 $/mmbtu, the arb with Asia will stay open so long as delivered LNG prices in Asia stay above 5 $/mmbtu. For Europe, that arb stays open longer but will close if European delivered prices fall to around 4.6 $/mmbtu.
For 2018, the global price arbs with Henry Hub are still open, based on the prevailing forward curves. We remain unconvinced that there will be sufficient global demand to keep the arb open when the market gets nearer to delivery. While the closing of that arb will be sensitive to when new liquefaction trains come online, if they generally start-up as scheduled, the global gas market will go into surplus in Q2 18. The US export arbs should stay open until that time, but we expect them to be shut for the remainder of that year. As a result, the US market balance looks loose for 2018, with a chunky increase in output pencilled in and a probable reduction in net exports pushing Henry Hub down beneath 3 $/mmbtu, dragging global gas down with it.