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.
NGTL – March 2017 Outage Actuals/Forecast For Upstream James River Receipt Area
Source: NGTL
The below graph shows the HH less AECO differential from Jan 1, 2016 to March 16, 2017 on a spot basis (the blue line) and on a prompt front month (the grey line) basis. However, with the higher natural gas productivity and other factors (ie. REX expansion), the HH less AECO differentials are expected to be wider than last summer’s differentials. Looking ahead to this summer, we couldn’t help note the well followed NBC Energy Client Coverage Team data this week that is now showing the HH less AECO differential data for the current prompt month at US$1.04, and that this increases to US$1.23 for Q3/17. This would be over $0.25 wider than Q3/16 last year. We also note that there will be the potential for big spikes up in the spot differential in and around the Aug ~1.8 bcf/d NGTL outage.
Henry Hub Less AECO Differential (US$)
Source: Bloomberg
Looking ahead, we expect the combination of weaker than expected AECO prices in Q1 and the expectation for the widening AECO differential in Q3 is likely to cause 2017 capex budget cuts in the upcoming May board meetings. Most producers based 2017 capex on AECO prices of likely $2.75 to $3.00, or slightly higher. Q1/17 Cdn drilling was at high levels reflecting the stronger outlook for oil and natural gas prices post the OPEC Nov 30 deal and pre winter expectations for better AECO prices. We see the potential for producers to move to an AECO assumption in the $2.50 to $2.75 range, which could lead to a 10% to 15% cut to capex budgets and lower industry drilling activity in Q3/17 than currently expected. The impact of a cut to a full year capex budget will be magnified as that cut is applied to the remaining H2 period only.
The wider than expected AECO differentials are likely to slow near term drilling activity as producers live within cash flow, but it is important to close with two key reminders. First, the NGTL outages are directly related to the need for expanded egress. The Cdn gas plays continue to deliver better results across a wide range of Alberta and British Columbia in the Montney and other top gas plays. Better egress provides the potential to narrow the AECO differential. Don’t forget the flip side of this strong industry success is that the Cdn natural gas producers make good returns at low AECO prices. We suspect many producers would say the old AECO $3.25 is the new AECO $2.50. The Cdn natural gas plays work and work well at AECO $2.50. Second, we believe the macro outlook for North American natural gas demand supports a view higher than 2018 and 2019 HH strip of ~$3. Our March 13, 2017 blog “Under Construction US LNG Export Projects To Add >2 Tcf Of Incremental Demand In 2017 Thru 2019” [LINK] highlighted how increasing LNG exports and pipeline exports to Mexico 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 the potential for better than expected HH prices relative to the 2018 and 2019 strip of ~$3.