Forecast ample inventories in the US should keep a cap on Henry Hub prices, particularly in injection season 2020, while winter 2019-20 prices will likely only jump up if there is colder-than-normal weather. Our base-case forecast is for an end-October storage carryout near 108 bcm (3.81 tcf) and an end-March 2020 carryout above 51 bcm (1.8 tcf), which would both be considered high by historical standards. Stocks could also be high in Europe at end-winter, which could lead to the Henry Hub-TTF arbitrage window closing in summer 2020, discouraging US LNG exports to Europe. We have raised our forecast for US piped gas exports to Mexico due to quicker-than-expected initial flows on a new pipeline, Sur de Texas-Tuxpan, and we expect growth in US production to be high, particularly over winter 2019-20. We forecast a Henry Hub price of $2.32/mmbtu for Cal-20.
Current and forecast high US stocks provide a bearish outlook for prices. Our weekly balances point to minor injection activity extending into the week ending 15 November, assuming 10-year normal weather, so we estimate US storage will peak just above 109 bcm (3.85 tcf) before withdrawals begin for winter. That translates into an end-March inventory near 51 bcm (1.8 tcf), which should effectively cap prices for injection season 2020. Those ample inventories will be difficult to work down unless there is an extreme cold event to boost weather-aided demand.
In a 5% colder-than-normal scenario, we anticipate storage would be near 40 bcm (1.4 tcf) at end-March 2020 because of higher demand from the res-com, industrial and power sectors, and production potentially being hampered by freeze-offs. A 5% milder-than-normal scenario would leave the market loose in injection season 2020, with storage near 59 bcm (2.1 tcf) and significant legwork to be done to avoid an end-October 2020 carryout above 113 bcm (4.0 tcf).
Our base case is that US LNG cargoes will get exported over heating season 2019-20. There is a risk that some cargoes will not get placed in summer 2020, particularly in Q3 20, as projected high stocks in Europe could lead to the Henry Hub-TTF arb closing. Such risk would only intensify if milder-than-normal weather is realised in Europe, and globally, over winter. We have built in just over 100 bcf of LNG maintenance in the US in our model for next injection season, which could indicate how much US LNG is at risk of potentially being shut in. This number is exposed to upside risk depending on how full European storage exits winter 2019-20.
However, the market did not send a financial signal beyond the prompt contracts to choke back supply in summer 2019, even though European storage was on track to fill before the traditional end to the injection season. The market may need to see weakness at the prompt bleed into further-dated contracts—such as M+2 or M+3, which are the contracts on which loading decisions tend to be made—for the shut-in of US LNG to materialise. The relative tightness or looseness of the global market will now be exceedingly important in determining US export demand. We project LNG feedgas demand to top 0.21 bcm/d (7.5 bcf/d) this heating season and be at least 0.25 bcm/d (9 bcf/d) on average next injection season.
We have upwardly revised our forecast for US pipeline exports to Mexico because of higher-than-anticipated initial flows on Sur de Texas-Tuxpan (STT). The line, which brings gas from the US into eastern Mexico, officially started up on 17 September. As such, we now expect cross-border pipeline exports of 0.18 bcm/d (6.4 bcf/d) this winter, compared to 0.17 bcm/d (6.0 bcf/d) previously, but we maintain there is downside risk to that figure. Altamira is still sending out 11.3 mcm/d (0.4 bcf/d) and flows from the LNG terminal do not yet appear to have been substituted by STT at all. In addition, Enbridge said that remediation works on a line on TETCO feeding Valley Crossing, a pipe which feeds into STT, should occur at some point between Q4 19 and Q2 20 due to seam weld corrosion. The maintenance could hamper flows.
The spectre of high US production is still looming, particularly for winter. We forecast Lower 48 production growth of 0.19 bcm/d (6.8 bcf/d) y/y for heating season 2019-20 and 0.13 bcm/d (4.5 bcf/d) y/y for injection season 2020. We continue to expect uplift from Appalachia tied to some liquids-directed drilling this winter, and minor Bakken gains on processing plant additions. In addition, flows through Gulf Coast Express should ramp up as the new pipeline has been fully in service since 26 September, which should debottleneck the Permian and allow Lower 48 production to rise further. However, TETCO maintenance, given how pervasive potential corrosion and remediation issues are across the entire system, could hamper deliverability. In sections where old pipe still exists (manufactured in the 1950s), flows are being restricted by 10% of capacity, pointing to some potential lower deliverability, especially on cold days.
|Fig 1: US storage carryouts, bcm||Fig 2: US production forecast, bcm/d|
|Source: EIA, Energy Aspects||Source: EIA, Energy Aspects|