Today’s report (week ended 21 June): EIA net change: +98 bcf, EA: +99 bcf
- To align with today’s print, we made minor downward adjustments to production and Canadian trade.
Next Thursday’s report (week ending 28 June): EA preliminary: +80 bcf
- A 2.5 bcf/d boost in power burn w/w will drive down the injection rate in spite of a 0.4 bcf/d increase in domestic output.
GoM tiebacks to boost output
GoM receipts are helping drive gains in dry gas production for the week in progress as maintenance in the region comes off. The area tends to be overlooked given it has seen a falling share of US output over the last decade. However, with our view on oil production in the GoM increasingly optimistic for 2019 going into 2020, those receipts should translate into moderate gains for gas supply as well. on the order of 0.1-0.2 bcf/d y/y. Much of this growth is driven by producers’ use of cost-effective short-cycle tieback projects that utilise the mature infrastructure of existing platforms at a lower cost and in a shorter timeframe. In addition, renewed investment from BP, Shell and others should support growth into next decade.
A number of projects are starting production. BP’s 30 thousand b/d Thunder Horse Northwest expansion and Shell’s 0.18 mb/d Appomattox project are both now online. Talos Energy’s 20 thousand b/d Tornado 3 project (a tieback to Phoenix) commenced production in April, and LLOG’s 30 thousand b/d Buckskin project (a tieback to Lucius) started to produce first oil in June. Short-cycle tieback projects to boost oil output have helped drive offshore breakevens below $40 per barrel in some instances, along with a variety of improved efficiencies, including better designs and fabrication as well as expert drilling execution. In the process of boosting oil output, those tiebacks will help support gas output.
From January 2017 to March 2019 (when data is mostly complete but still preliminary), the number of existing wells in the GoM declined by 20% to around 2,500. In that time, 380 new wells have come online, accounting for around 37% of the basin’s total oil output. The vast majority of new wells are tiebacks; only 10 wells are attributable to new platforms, including La Femme, Stampede and Big Foot.
Since Q4 18, applications for drilling permits soared in the GoM (see Fig 2), suggesting deepwater activity is increasing. Of the 34 permits filed in May, 14 report the area of interest and all but one are located in mature fields, suggesting tiebacks. The remaining permit links to a new property in Mississippi Canyon 940, a block of Shell’s Vito project, which is scheduled to start production in 2021.
Not only do tieback projects require less investment (both upfront and full-lifecycle), they also have a shorter ramp-up period than traditional spars and semisubmersible platforms. The embedded value of their real optionality (to delay, suspend or expand) becomes valuable when oil volatility increases, as companies have more flexibility. According to an EIA upstream study (Trends in U.S. Oil and Natural Gas Upstream Costs) published in 2016, the cost of GoM deepwater subsea systems ranges from $100 million to $1.5 billion, mostly dependent on the distance to the platform. Larger spar projects (with associated subsea systems) could cost as much as $6.3 billion, and there are also the more expensive tension leg and semisubmersible platforms (see Fig 3). The cheaper costs of tiebacks have recently attracted the most offshore investment.
Today’s EIA print—in a departure from recent trends—was near consensus estimates. From here on (see Fig 4) we expect injection rates to fall precipitously. Our power burn models are presently calling for some daily rates near 40 bcf/d at the start of July. The predicted heat that is helping to drive those high forecast burns however, is also closely aligned with the potential demand dampening effect from the Fourth of July holiday. Though we expect record gas burn next month, production is now running above the weekly highs reached in December. With news on the arbitration process on Sur de Texas-Tuxpan, a scenario in which cross-border exports increase dramatically looks off the table. The fundamental backdrop is still looking quite loose with our estimates through the week of 12 July indicating it is running 5 bcf/d looser on average. Given the very short bias of the market, however, any massive step up in weather could leave the market exposed to an overshoot.
|Fig 1: GoM gas production forecast||Fig 2: Drilling permit applications filed|
|Source: BOEM, EIA, Energy Aspects||Source: DrillingInfo, Energy Aspects|
|Fig 3: GoM deepwater project costs, ($ billion)||Fig 4: Weekly EIA storage change, bcf|
|Source: EIA, Energy Aspects||Source: EIA, Energy Aspects|