Bakken in black

Published at 16:58 18 Apr 2019 by

Today’s report (week ended 12 Apr): EIA net change: +92 bcf, EA: +93 bcf

  • Today’s print was largely in line with expectations that hovered around 90 bcf. To bring our balances in line with the EIA figure, we adjusted our gas-heating intensity coefficient higher to bring res-com demand up by 0.1 bcf/d above our original estimate.

Next Thursday’s report (week ending 19 Apr): EA preliminary: +91 bcf

  • Our projection for next week’s injection remains slightly below this week’s figure on indications of increased demand. We increased our projection for LNG feedgas demand, as 17–18 April flow data show Sabine Pass taking 3.4 bcf/d. This would indicate all five trains are operating for the first time in over a month. We also upwardly revised our heating estimate to bring it in line with this week’s adjustment.

Bakken in black

This week’s downward shift in summer Henry Hub prices, with contracts between May-19 and Oct-19 moving down by $0.18/mmbtu w/w to $2.61/mmbtu, reflects the market’s expectation that the rest of the year will be very well supplied. Our forecast for a 3.67 tcf end-of-season carryout is fuelled both by strong April injections—this week’s 92 bcf addition to inventories is especially robust compared to a 36 bcf withdrawal in the corresponding week of 2018—and by our projection for 7.4 bcf in y/y production growth this injection season. That includes a 0.3 bcf/d growth forecast in the Bakken, matching its y/y gains from 2018. We foresee the continued growth tied to new processing plant capacity coming online this summer, allowing for North Dakota output to outcompete Canadian volumes as a key source of gas for the Midwest.

The lack of gas processing capacity has served as a ceiling on Bakken gas production in recent months, with new additions resulting in nearly instantaneous output increases. This was most recently evident in late December after a 0.20 bcf/d expansion at Oasis’s Wild Basin processing plant to 0.27 bcf/d. As soon as the expansion went into service in late November, volumes at the McKenzie, ND plant grew by 30 mmcf/d w/w to 0.1 bcf/d and Bakken output rose by the same amount w/w. A similar stepwise change in regional production occurred in February, when Wild Basin’s gas intake first topped 0.2 bcf/d. Bakken receipts were up by 0.1 bcf/d m/m to an average of 1.7 bcf/d for the month. Bakken gas output has remained above 1.85 bcf/d since early March.

With Wild Basin nearing full capacity just months after its expansion, more processing additions will be needed in 2019 if the Bakken is to rise above our 0.3 bcf/d y/y growth projection. This will require timely start-up for the 0.2 bcf/d Little Missouri Four (LM4) plant, which is due online in May 2019. LM4 was originally due to begin operations in Q4 18 but has seen several delays result from slower-than-expected construction attributed to a workforce shortage in North Dakota. After LM4, the next new processing volumes will not come online until a 0.15 bcf/d expansion to the Bear Den plant is completed in September.

While the new processing capacity in the Bakken should produce an immediate jump in gas output, much of it will also likely come from wells that are already online due to the gas capture policy put in place by the North Dakota Industrial Commission (NDIC). The state currently has an 88% gas capture target, which it has failed to meet every month since March 2018 (the target was 85% until November 2018, though the state has failed to hit that threshold since last June). Of the 12 companies which missed the 88% mandate in Q4 18, none were ordered to restrict oil production as a penalty and flaring control measure. The start-up of Wild Basin saw flaring dip below 19% of gas production in January 2019, down from 21% the prior month. While this will undoubtedly boost gas production in the basin, that will likely come from volumes that previously would have been flared rather than organic growth.

Higher Bakken gas output is crowding out gas from other regions on Northern Border. Gas from the Western Canadian Sedimentary Basin has been particularly vulnerable to dwindling market share. Imports to the US on Northern Border, measured at the Port of Morgan border point in Montana, have fallen y/y every month since Wild Basin’s expansion came online. Even when no major maintenance restrictions were present, the NGTL system that feeds Northern Border sent just 1.2 bcf/d every month between December 2018 and March 2019, well below its 2.4 bcf/d capacity and down by 0.15 bcf/d y/y. Maintenance on NGTL has restricted Port of Morgan flows to just 0.8 bcf/d in April to-date, leaving even more space for Bakken gas.

While Canada’s share of flows on Northern Border has been declining, the same volumes of gas have been reaching the Midwest on the pipe in 2019. This indicates that Bakken gas is filling the additional space. The higher production facilitated by Wild Basin produced a 0.1 bcf/d jump in Bakken’s share on Northern Border in March, to 1.3 bcf/d (also up by 0.15 bcf/d y/y, the same amount Canadian volumes lost). Given the Midwest’s 80 bcf y/y inventory deficit, Bakken volumes will likely be welcome in the region throughout the 2019 summer.

Next week’s report will be a microcosm of our summer balances, as 0.6 bcf/d w/w of production growth is pitted against rising LNG feedgas demand. Trains 1 and 2 at Sabine Pass saw a full week of flows after taking no gas for three weeks of maintenance, while Cameron T1 climbed to over 0.1 bcf/d on 16–18 April. LNG feedgas gains of 1.5 bcf/d in the current week will be slightly offset by a dip of 0.3 bcf/d w/w in Mexican exports, as work on the Agua Dulce compressor station cuts more than 0.8 bcf/d in capacity on NET Mexico between 17–18 April (with more severe restrictions likely next week). Beyond this week, we see a string of 100 bcf injections possible as shoulder season kicks into high gear, likely signalling a lack of relief for battered summer Henry Hub prices. This will test the ability of power generation to soak up incremental gas, especially in the Midcontinent, where gas units must compete with lower-cost PRB coal units. Coal generation in Midwest ISO and SPP is down more than 6 GW y/y this month, but gas burn in those markets is up by less than 2 GW due to higher wind output and lower load.

Fig 1: Bakken gas processing capacity, mmcf/d
Source: Company websites, Energy Aspects
Fig 2: Wild Basin flows, bcf/d Fig 3: Northern Border flows, bcf/d
Source: Ventyx, Energy Aspects Source: Ventyx, Energy Aspects

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