Please note that we will not publish an August edition of North America Outlook. The monthly schedule will resume as normal in September.
The last month has seen Henry prices largely stuck in range (around 3 $/mmbtu). Adding to the sense of stability, EIA production numbers saw little change, which all might suggest better clarity on where the gas market is heading. To tell the truth, the growth starting to manifest itself in dry gas production and has becalmed the market needs to continue over the next few months. If not, a stringent upward repricing of gas may be hard to avoid.
There has been plenty of focus on delays to the 3.25 bcf/d Rover pipeline, which will add some much-needed take-away capacity for Northeast gas. The developer, ETP, now expects the first section, from Cadiz (OH/WV border) to Defiance (OH) to be online in late summer with the 22 September having been cited as a potential date. This pipeline is important, as some 2.2 bcf/d of capacity can be used through interconnections with existing pipes for distribution to markets across the US. This delay, having been pushed back from a July start, certainly lowers our expectations of the level of production growth to be realised this summer.
As such, the Q3 17 balances feel tight. Industrial sector demand is ticking up as new world-scale ethane crackers are starting up. Over H1 17, some 2 Mtpa of ethane cracking capacity came online and another 4.5 Mtpa is expected in H2 17. Those additions are helping industrial demand to grow, with Q2 17 demand up y/y by around 0.42 bcf/d.
Exports are also high, with LNG exports at Sabine Pass keeping a steady pull on some 2.1 bcf/d of gas, while exports to Mexico have remained around 4.1 bcf/d. With limited to no y/y incremental production, the market has to reduce either storage injections or the amount of gas going into power.
Power demand hinges on how hot it gets, and seasonal forecasts for the July-September period are largely for warmer-than-normal temperatures in the Eastern and Southwestern parts of the US. As these are the key gas to power regions, underlying base levels of power sector gas demand look set to be well supported. However, last summer’s peak months were very warm across July–September, particularly August (CDDs 17% above the five-year average) and September (CDDs 20% higher), so that base power demand may well still be lower in y/y terms. The flipside is more gas plants are now on the system, with over 6 GW of new gas-fired power online this year, predominantly in the more eastern markets.
In terms of storage, there will need to be a 3.5 bcf/d y/y reduction in power sector gas demand for end-October storage levels to reach our forecast of 3.85 tcf. While some cooler weather might help deliver a bit of that, the figure still feels as though it would require gas to be priced relatively higher compared to coal than last summer. Even if production outperforms our somewhat modest growth forecasts by 1 bcf/d, that would still require gas into power to fall y/y by 2.5 bcf/d. Given where the gas price fuel switch triggers are, this all suggests prices will need to move, at least, back above 3.1 $/mmbtu.
Meanwhile, the US market balance looks a bit tighter for 2018 than our previous forecasts. We still have a chunky y/y production increase of 4 bcf/d pencilled in, although net exports now look unlikely to decline due to changes in our global gas balances. As such, the demand side will be strong, with another 0.4 bcf/d of demand growth from industry, some 12 GW of new gas-fired capacity, and an increased call on exports (Mexico and LNG) all keeping the market ticking over.