Big Crude Oil Releases Can’t Help You If You Have Limited Refinery Capacity

William, a regular reader of the Morning Jolt, writes in with a few more thoughts on the shortage of oil refinery capacity, which is a major factor in the current high gas prices.ring design and EPC contracts on the project.

First, in addition to the Targa Resources Corporation’s site in Channelview, Texas, which began operating in 2019, there is one fairly sizeable refinery project underway:

The Meridian Energy Group Davis Refinery [in North Dakota] is the first new “greenfield” refinery since 1977 – the 2019 Targa Channelview refinery you referenced is what is termed a “brownfield” development in that it was adding processing capacity to a big crude oil storage and shipping terminal – it was also just a simple crude/condensate splitter that does not actually produce fully refined products, just two streams of product 1) slightly heavier crude oil and 2) condensate that would need to be further processed at a fractionation plant into products like propane and butane. The Davis refinery is currently under construction and completion is expected in 2023. With only 49,500 barrels of oil per day expected throughput (about 47 percent of that should come out as diesel) it is only a drop in the bucket, but getting it built has been a herculean effort with the permitting process starting in 2016, the planning before that, and an expected cost of $920 million dollars.

Indeed, adding capacity for nearly 50,000 barrels per day is better than nothing, but remember that the closures of refineries in 2019 and 202o reduced U.S. refinery capacity by more than a million barrels per day. And by the end of 2023, Lyondell Basell Industries will permanently close its Houston crude-oil refinery, taking another 263,000 barrels of gasoline, diesel, and jet fuel per day out of commission.

William also notes that the description of drilling costs mentioned in yesterday’s Jolt doesn’t include other costs involved in bringing the oil to the refiner.

Your reference from Tidal Petroleum does seem to be a fairly good and concise synopsis of the market and costs, but you only listed the cost of the drilling phase. Any producing well needs to be both drilled and completed.

Tidal also has a decent outline of what that phase can look like. They list broad estimates of $750,000 for casing, $3 million for well stimulation (hydraulic fracturing aka fracking), $750,000 for surface equipment, and as much as $1 million for gathering pipeline costs. I generally work the Bakken oil formation in the Williston Basin, and I think I would generally expect the average total drilling and completion cost for wells in that basin this year to be in the neighborhood of $8 or $9 million (and that does not include leasing or gathering pipeline costs).

An oil field, especially one within one of the more modern onshore discoveries in the U.S. such as all of the Shale plays (think Permian, Williston Basin, Marcellus Shale, etc…) is almost never developed by a single well. It usually takes dozens or hundreds of wells to develop a field. If it were 200 wells to develop a field at $8 million each, that is $1.6 billion in investment needed to develop a single oil-field.

That is why the massive under-investment worldwide in new development over the last few years combined with the long development timeline for bigger projects spells such an imbalance between supply and demand and why we are likely in a higher for longer period regardless of what the US industry does.

Another point I should have mentioned yesterday is that if gas prices are high because of limited capacity in the country’s remaining 129 oil refineries, it doesn’t do much good to release lots and lots crude oil from the Strategic Petroleum Reserve. Everything released from the SPR still has to go through the refining process before it can be pumped into your car.