Oil price volatility is primarily driven by supply factors (ie. OPEC compliance), whereas Henry Hub (HH) price volatility is primarily driven by demand factors (ie. winter weather). There are fundamental changes to non-weather natural gas demand that are happening and do not require future changes to have a material demand impact relative to swings in winter weather demand. Under construction LNG export projects alone are expected to add >2 tcf of demand per year by the end of 2019 (relative to 2016), and this is before increasing pipeline exports to Mexico. There are no “what if’s” required to keep these non-weather natural gas demand factors on track, which means there should be an outlook of better downside HH price protection in the winter, and better HH prices in 2018 and 2019 compared to the current HH strip of ~$3. The primary risk to better HH prices is a return of strong US natural gas production from natural gas drilling and from associated natural gas from oil drilling.
Q4 earnings calls provided fresh updates on most of the US LNG export projects. The just finished Q4 earnings calls provided updates on the full range of US LNG export projects that are under construction/development. These projects are not the potential projects awaiting FID, rather these are projects that are under development and, for the most part, are well underway actual construction. Our weekly Energy Tidbits memos include regular updates on the US LNG export projects, and the updates from the Q4 earnings calls were in line with expectations.
US LNG projects expected to add 2.119 tcf of annual demand by the end of 2019. Below is our table that shows the impact of increased natural gas demand by year for all of the US LNG export projects that are in operation and under construction/development LNG export projects. The list of projects is as per the Federal Energy Regulatory Commission listing of existing in operation LNG projects [LINK] and of approved under construction LNG projects [LINK]. The incremental YoY demand is 430 bcf in 2017 vs 2016, a further 650 bcf incremental YoY demand in 2018 vs 2017, and a further incremental 1,038 bcf incremental YoY demand in 2019 vs 2018. In total, the incremental demand by year end 2019 vs 2016 is 2,119 bcf.
The risk seems low as these LNG export projects are under construction and almost all are adding onto existing LNG import projects. The incremental 2,119 bcf demand is from projects that are under construction with planned start dates. The other important aspect is that almost all of these projects (Sabine Pass, Cove Point, Cameron, Freeport and Elba Island) are add ons to existing import terminals. Cheniere’s Corpus Christi LNG project is under construction and located on an existing Cheniere site that was previously permitted for a regasification terminal. The primary risk to the projects is delays, but the slippage risk is likely only a few months as they are under construction. However, Sempra, in its Feb 28 Q4 earnings call, confirmed that that the 3 phases of its Cameron LNG project were delayed by 6 months, but this delay is exactly in line with their warning in the Q3/16 earnings call on Nov 2, 2017.
Adding 2.1 tcf of non-weather demand is a very big factor relative to the annual demand swings from winter weather. An added 2.1 tcf of natural gas demand is only ~7.5% of total US natural gas consumption of ~75 bcf/d or ~27.4 tcf per year. However, another 2.1 tcf of demand is very big relative to the big swings in natural gas demand from winter weather – residential and commercial demand, and total storage levels. The demand items that swing heavily with winter weather are residential and commercial demand. A high demand from cold weather example is the cold Jan 2014 where residential and commercial demand was 1,609 bcf or 51.9 bcf/d, compared to the warmest Jan over the past 10 years when residential and commercial demand was 1,111 bcf (35.8 bcf/d) in Jan 2006. This is a swing for 498 bcf (16.1 bcf/d) from the warmest to coldest Jan in the past 10 years. Note that the summer residential and commercial natural gas demand can be as low as 242 bcf (7.8 bcf/d) in Aug 2014. US storage is currently 2,295 bcf (down 191 bcf YoY from 2,487 bcf). An added 2.1 tcf of natural gas demand would be a very big factor relative to these two items.
Increasing US natural gas exports is a game changer for HH gas prices. Last year, HH prices were ~$1.50 at this time, yet storage was only 191 bcf higher. Natural gas price volatility is more driven by demand items than supply, with the biggest swing factor to demand being winter weather. But there is a material change happening to HH prices with the increasing US natural gas exports via pipelines to Mexico and from LNG to places around the world. One of our next blogs will deal with increasing natural gas exports to Mexico. These add to the “base” natural gas demand that is not purely weather dependent, and the higher the “base” non-weather demand should lead to better downside protection to HH prices in winter and to better expected HH prices relative to the 2018 and 2019 strip of ~$3. The primary risk to better HH prices is a return of strong US natural gas production from natural gas drilling and from associated natural gas from oil drilling. Most of all, the increasing LNG exports are based on under construction projects and do not require any “what if’s” to add >2 tcf to base non-weather demand by the end of 2019.