Today’s report (week ended 30 Aug): EIA net change: +84 bcf, EA: +81 bcf
- Today’s EIA print was in line with our estimate, but came in above consensus. The miss versus consensus (in the high 70s bcf) is likely from an underestimation of holiday impact on demand leading into the Labor Day holiday.
Next Thursday’s report (week ending 6 Sep): EA preliminary: +86 bcf
- In spite of the holiday impact from Labor Day (which we estimate at 1 bcf/d), a 1.4 bcf/d w/w rise in power burn largely offset that weakened industrial demand and the moderate rise in production and net Canadian trade.
Most of the major Appalachian producers that have reported 2020 Capex are pointing to decreased capital outlays next year (see Fig 1). Those reductions in Capex in some cases will translate into lower rig counts and/or relying on completing DUCs given drilling costs in these are already sunk. We still see continued growth in production in the basin over the course of winter 2019-20 due to the inventory of quality DUCs and liquids-directed activity. However, there is increasing uncertainty around the rate of production growth in late 2020 given the reduction in Capex and rigs, with more cuts potentially in the offing (see E-mail alert: Earnings calls show low prices souring 2020 outlook for Appalachia producers, 8 August 2019).
Regarding support from liquids-directed production this winter, additional NGL pipeline capacity is set to come online in Q4 19 (Energy Transfer’s Mariner East 2X), so some producers have backloaded their drilling programs to the latter part of this year. Two of MPLX’s processing plants in the region have been delayed from Q2 19-Q3 19 to Q4 19. Range Resources, for instance, has drilled eight wells in the wet portion of southwest Pennsylvania in H2 19 and will drill another 33 by year-end, with the bulk occurring in late Q3 19/early Q4 19. Producers 2019 hedge books are also still at play, with volume-weighted prices far above current marks.
The pace of production growth in late 2020 is less certain, especially with rig counts falling and given the lack of guidance from several regional producers. As of the Q2 19 earnings season, Appalachian-focussed producers are less hedged for the year ahead compared to last year (see Fig 1), but are hedged at prices well above the current Henry Hub curve. That suggests that a fair amount or production is still protected at attractive pricing versus the current forward strip. August data from the Swap Data Repository indicate that the pace of hedging is picking up, but at much lower prices (average prices were near $2.40/mmbtu) (see E-mail alert: Trimming the hedge: year-ahead production less-hedged than in 2018, 12 August 2019). While that may indicate producers are catching up on how much production they are protecting, it also hints that the volume-weighted average price will fall.
|Fig 1: Appalachia producers’ hedging and capex|
|Note: EQT, Range, and Gulfport have yet to release 2020 production guidance.
Source: Company reports, Energy Aspects
Montage Resources has already cut from two gross rigs to one. Gulfport will release its one rig in the coming weeks. CNX has three rigs under contract through year-end and is guiding for two rigs and one frac crew in 2020. Southwestern has noted it will drop from six rigs in Q2 19 to two by end-Q3 19. EQT and Cabot, neither of which provided 2020 guidance, both noted their rig fleets are fully contracted through year-end.
The viability of the DUC inventory, and most importantly the vintage of wells producers can tap, will be key to keeping production afloat. With such a significant drawdown of DUCs (see Fig 4) since the beginning of 2018, we looked at how much of the current DUC inventory would be considered attractive for completion.
Producers are likely to cherry pick the most productive DUCs in their inventory. For our analysis, we considered vintage 2019 DUCs to be those drilled in Q1 19 to account for any spud-to-completion delay (which is often one to three months) and time lags in reporting completions (which can lead to an artificially high DUC inventory. Therefore, the 2019 estimate (see Fig 2) of close to 150 DUCs would pare down to 80. 2017, 2018 and 2019 DUCs, which we consider to be the most productive in the backlog, account for 62% of our estimated DUC inventory.
Wells drilled before 2017 may not merit the completion costs. Wells that commenced production in 2014 only produced around 50% as much as those that came online in 2018. Such a gap in productivity cannot be fully eliminated through more advanced completion designs and greater fracking intensity because wells drilled in the past have shorter lateral length as well as shallower vertical depth on average (see Fig 3 and 5).
|Fig 2: Distribution of DUCs by age, number of wells||Fig 3: First six-month output by vintage year, bcf/d|
|Source: FracFocus, Energy Aspects||Source: Enverus, Energy Aspects|
|Fig 4: DUC inventory by month||Fig 5: Well lateral by vintage year, thousand feet|
|Source: EIA, Energy Aspects||Source: Enverus, Energy Aspects|
|Fig 6: Output from DUCs from 2017-2019, bcf/d||Fig 7: Decline of base production, bcf/d|
|Source: Enverus, Energy Aspects||Source: Enverus, Energy Aspects|
If we eliminate wells drilled before 2017 from our inventory estimates and assume operators continue to draw down DUCs at the current pace (15-20 wells per month), DUC resources in the basin will be exhausted some time in Q4 20. The output contribution from their completion will still be significant enough to mask slower activity in the basin (see Fig 6). While the completion of the best vintages of DUC inventory is still enough to help prop up production throughout most of 2020, the decline in the base of horizontal production would be 10 bcf/d in 2020 without continued drilling or DUC completion, according to our modelling (see Fig 7). Such a decline puts a significant onus on DUC completion, and drilling efficiency, to help avoid any potential stall in production as mid-2020 progresses into late 2020 if rig counts continue to fall. Our current base case assumes a significant cooling in sequential growth as 2020 progresses.