Its all about OPEC and oil this week, but this meant that the most bullish we have heard on the LNG market rebalancing sooner than expected from Woodside’s May 23rd investor briefing in Australia have been overlooked. Woodside is another in a growing group to forecast LNG markets get rebalanced much earlier than expected. But they are the firmest in their views, saying it multiple times in the investor briefing, and they see this happening “around 2020”. As their Executive VP Marketing, Trading and Shipping said “I am a bit more bullish than our economists, I actually talk to customers out there”. At the end of 2016, the more common view was LNG rebalancing in 2023 to 2025. That view still seems reflected in the forward strips, which are well below current prices (ie. Henry Hub HH in 2020 is $2.84 vs $3.10 today). A LNG rebalanced market in 2020 should lift mid term Henry Hub (HH), which will in turn help drag up mid term AECO prices. This means that LNG rebalancing could well be the major factor that will set the tone and valuations for Cdn natural gas in 2018 and 2019. The Woodside presentation is at [LINK], and the webcast replay is at [LINK].
Once again, Q1 earnings calls, in particular the Q&A, has provided one (mostly overlooked) emerging oil and gas development that should be thought about by every oil investor. It wasn’t a transaction, or an earnings surprise, or change in outlook. Rather it was Core Laboratories (CLB) outlining their view of “four major industry trends that will shape tomorrow’s oil field”, in particular its “second major trend is the interest in using finer proppants in the initial procedures in a hydraulic frac program”. The implication of broader success with finer proppants is that there US oil production could surprise to the upside in 2018, which should keep investor attention and capital allocation on US and Canadian shale/tight oil, condensate rich and natural gas plays that win with new technology tweaks and are proving to work at lower and lower prices. Continue reading “Will Finer Proppant Be The Next Completion Tweak That Leads To US Shale Oil Surprising To the Upside In 2018?”
There was big positive news for AECO gas prices on Wed when TransAlta announced it was accelerating its transition to clean power in Alberta [LINK]. This is their transition out of coal. Their announcement is significant because it specifically says natural gas is directly replacing coal in powering certain coal units. TransAlta says they a converting “Sundance Units 3 to 6 and Keephills Units 1 and 2 from coal-fired generation to gas-fired generation in the 2021 to 2023 timeframe, thereby extending the useful life of these units until the mid-2030s; and effective immediately, taking steps to secure the gas supply required for the converted units (expected to be up to 700 million cubic feet of gas per day at peak levels of demand), including the construction of the required pipeline.” A peak of up 0.7 bcf/d of new natural gas demand for TransAlta is a big plus for AECO starting in 2021.
Cheniere’s analyst day [LINK] provided another view that the global LNG oversupply is going to be fixed around 2020/2021 and tip into undersupply, whereas the general view coming into 2017 was that it wouldn’t be fixed until 2023 to 2025. These views on when LNG tips to undersupply are directly relevant to Cdn natural gas because global LNG markets now have a major impact on Henry Hub (HH) and AECO gas prices. This winter proved this fact, and it means there is a new way of looking at HH and AECO gas prices. The “structural” changes that started to increase as gas prices dropped in 2014, began to materially (and positively) impact gas prices this winter, and should have an increasing impact thru 2022. US natural gas exports have materially changed the dynamics in a positive way for HH and AECO gas prices, which means global natural gas and LNG markets are now new drivers of HH and AECO prices. And it is why the increasing views (such as Cheniere’s this week) for the potential that the global LNG oversupply gets fixed closer to 2020 should be noted as it could be the major factor that will set the tone and valuations for Cdn natural gas in 2018 and 2019. Plus it is timely to look at this now as we would expect analysts and investors to take a new look at their 2018 and 2019 natural gas thesis in Q3/17, ahead of going into the winter.
We weren’t surprised to see Cenovus step up to buy high quality heavy oil assets or strategic investors take control of Northern Blizzard given that the fundamentals driving narrower than expected Cdn heavy oil differentials in 2017 are likely to continue in 2018 and beyond. Cdn heavy oil is trapped and has no option but to sell to the US. But the US is effectively trapped and primarily relies on Canada, Mexico and Venezuela (to a smaller degree Colombia) for its heavy oil supply. And with Mexico and Venezuela continuing to be in decline, the basic supply demand fundamentals continue in a positive trend for Cdn heavy oil. Volatility and seasonality will still be here, but the positive trends mean it is less likely to see Cdn heavy oil differentials blow out for any extended period or to the same $/bbl magnitude as seen in 2014.
The “new” global LNG development emerging from Gastech in Tokyo is the flow of reports and announcements this week that there is significant action being taken to put LNG bunkering (refueling) in place. LNG bunkering is the needed first step for LNG to capture market share when the new Jan 1, 2020 lower sulphur rules force ships to either use low sulphur fuel, add scrubbers, or switch to LNG. This is an important development – without LNG refueling logistics, LNG fueled ships and tankers (either reconfigured or new builds) won’t grow. If LNG can capture 10% of this market, it can add ~2.6 bcf/d of demand, which would be equal to ~1 year of demand growth, and bring forward by ~1 year the expected time when LNG markets move from oversupply to undersupply.
There was information overload at the big Gastech natural gas and LNG conference in Tokyo this week. So no surprise, the initial reporting has been on the well known themes – current LNG oversupply and its impact on LNG prices and need for lowest cost liquefaction. But as always happens, once analysts get back to their offices, they then look for what has changed or emerged in the last year. Three of these changed/new themes are more calling for the LNG oversupply to be corrected sooner than expected, increasing impact of FSRUs in 2017, 2018 and 2019, and acceleration of the needed LNG fuel infrastructure for LNG to fuel tankers and ships.
It may have gone under the radar but we had to think about the potential BC LNG implications from Cheniere Energy’s efforts to source as much Montney and Horn River as possible for its Sabine Pass and Corpus Christi LNG export projects. We can see the case for more Montney natural gas producers that aren’t part of an integrated BC LNG project to commit to a GoM LNG and receive HH linked prices. Its not necessarily that BC LNG may not get going. Rather, it’s hard to see BC LNG getting a big natural gas price lift relative to HH pricing, so why not deliver Montney gas to GoM LNG today?
There is a strong logical case for oil hitting $60 before year end if OPEC/non-OPEC extend their ~1.8 million b/d and can manage reasonable (ie. >80%) compliance, even if US oil production continues to grow. Why? EVERY YEAR, oil demand is ALWAYS up strongly in H2 vs H1. Every year, oil demand follows a seasonal pattern. The low demand period every year is Q1. Then oil demand starts to pick up slightly in Q2, but the big increases in oil demand are every year in Q3 and Q4. Oil demand in H2 is expected +~1.7 million b/d, or ~50 million barrels per month of increased oil demand vs H1/17.
It looks like the HH less AECO differential will widen this summer, in part due to the NGTL planned outages this summer to expand the system capacity. This week, NGTL provided its new monthly outage forecast [LINK] and it now looks like every month this summer will have a significant outage in the key region impacting the Montney. However, it doesn’t look like any additional outages, just a shifting of some of the smaller ~0.6 bcf/d Aug outage into July. The big NGTL outage is still ~1.8 bcf/d in Aug, then ~0.6 bcf/d in June, and now, with the shift, another ~0.6 bcf/d in July. These outages are needed to allow NGTL to expand capacity on the key Upstream James River Receipt area that is the core of the Montney growth. Continue reading “Wider AECO Differentials In Q3, Its Good That The New AECO $2.50 Is The Old AECO $3.25”