Natural Gas price forecast

[dan_s]

Credit Suisse on March 2, 2017: "We have month-over-month dry gas production growth for twelve months in a row, totaling ~7 Bcf/d from December 2016 to December 2017 in our central case (p. 3). But data from PointLogic for early 2017, and apparent takeaway constraints in the Northeast are making those supply growth assumptions appear a tad aggressive. If supply does not pick up quickly, prices will need to rise to fill storage this injection season – even if at end March there’s still ~2 Ts in the ground. Our base case calls for $3.00/MMBtu Henry Hub prices in Q2 of this year, rising to $3.25/MMBtu in Q3 and $3.50/MMBtu in Q4; if supply grows less than we forecast, there should be a little more upside at the Hub near-term."

Total US dry gas production is down~3.3 Bcf/d yoy YTD according to PointLogic, which extends a consistent EIA 914 data
track featuring month-over-month declines through 2016. US dry gas production fell from ~74 Bcf/d in December 2015 to ~71.3
Bcf/d in December 2016, which PointLogic suggests has edged down further to around 70.5 Bcf/d currently. Our central scenario entails
a very quick turnaround that has yet to materialize. Granted there appears to be quite a bit of gas stuck behind pipe in the Marcellus
and Utica, with Dominion South spot basis widening to ~$0.80/MMBtu versus ~$0.30/MMBtu a month ago… what’s worse, the
Northeast gas rig count has nearly doubled off the August low. We think that the key to the summer will be how quickly that gas can
make its way to market.
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A few weeks ago we presented an alternate production forecast: Inside we further tweaked things by assuming that
the northeast production juggernaut remains constrained through June and we reduced imports from Canada – on that latter
point, in our base case we extend the rather high level of imports of the 2016 injection season, but our colleagues in Calgary don’t believe
there is much incremental supply growth in the works and that last year exports were pushed by the lack of market demand and the wildfire
related shutdowns across parts of the oil sands complexes. About the northeast, our base case assumes no constraint on production at
all, but if growth hinges on bringing on stream the first phase of Rover in July, this sets up for a more bullish injection season. In some such
alternate scenario, normal weather would leave end October storage at ~3.3 Tcf, versus ~4.0 Tcf in our central scenario. This should
incentivize higher Henry Hub prices to weigh on price elastic demand from electric power generators and push storage closer to max
heading into next winter. Obviously any delays on Rover set up all the more bullish for the Hub, and also extend the duration of upside risk
further out the strip.

In early February the market erased the 2017 HH calendar strip premium. This likely reflects the warm winter and the slew of
FERC pipeline approvals in early 2017. But given pipe constraints in the Northeast we suspect some of that premium could come back.