Editorial: Stuck in the middle with crude
Oil and gas exploration and production companies managed to cut output just in time to prevent crude oil storage from running out of space. The combination of cuts, both voluntary and otherwise, and the beginnings of demand recovery averted a return to the negative oil futures pricing experienced in late April and lifted the cost of a barrel of oil back above $30/bbl from an April 2020 Brent average of $18/bbl.
The US Energy Information Administration (EIA) forecasts Brent to average $34/bbl for 2020, down $30 from 2019. The agency predicts a 4.4% decline in US crude production for 2020, to 11.7 million b/d, and another 6.8% drop in 2021. EIA’s forecast recovery in natural gas pricing is similarly gradual. Henry Hub prices averaged $1.73/MMbtu in April and are expected to average $2.14/MMbtu for 2020 and $2.89/MMbtu in 2021 on lower production. As of mid-May, 339 oil and natural gas rigs were operating in the US, a record low since Baker Hughes Co. started keeping data on the topic in 1987.
Against this backdrop, continued discipline clearly is required. The pace of post-pandemic economic recovery is uncertain and will likely vary widely from country to country. Even the notion that the world has successfully put COVID-19 in the past is open to question as economies reopen and only recently adopted social distancing norms relax.
As supply and demand patterns continue to evolve the industry’s midstream is, appropriately enough, caught in the middle. Though its fee-based revenue model makes it less exposed to commodity price swings than either the upstream or downstream, the midstream’s bottom line is directly affected by changes in volumes. Less oil and gas being shipped means less revenue.
Duck and cover
In response to these realities, midstream companies have been lowering capital expenditures; dramatically in some cases. Company reports compiled by Alerian show an average 45.6% drop from 2019, with DCP Midstream’s planned capital spend down more than 83% year on year.
Tangible examples of deferred projects include Phillips 66’s Red Oak (Permian and Cushing, Okla., to US Gulf Coast) and Liberty (Bakken and Rockies to Cushing) crude pipelines and its Sweeny Frac 4 project, all of which were part of reducing 2020 consolidated capital spending by $700 million to $3.1 billion. Phillips 66 also postponed making a final investment decision on its ACE Pipeline, connecting the St. James, La., crude hub to area refineries.
Enterprise Products Partners meanwhile cancelled or deferred spending on 13 projects, including delays to its Midland-to-Enterprise Crude Houston 4 pipeline. The 450,000 b/d pipeline, expandable to as much as much as 540,000 b/d, had been expected to enter service first-half 2021 and is now expected to do so second-half 2021. The company cancelled a planned 30,000-b/d expansion to its 116,000-b/d butane isomerization plant at its NGL fractionation and storage complex in Mont Belvieu, Tex.
This degree of spending prudence is appropriate on the part of the US midstream. The country will presumably return to being the world’s leading hydrocarbon producer. The key for the companies involved in moving these hydrocarbons to market and processing them for downstream use will be sticking around long enough to see that day.
Living within one’s means is always appropriate. The more so when one’s place in the market is that of a middleman navigating a fractured but temporary present between a great past and a bright future. Dollars not spent now will be available later and a potentially damaging overbuild of capacity can be avoided in the meantime.