Yes, you read that right
We re-posted Part II of our U.S. Oil Markets Independence piece to Twitter recently
The tweet led to a thread that is a full-education on refining, oil slates, product yields and the challenges the U.S. has in ever really being oil independent
With their permission and to save space, I have copied and pasted comments from @RobertAuers and a follow-up conversation between @RobertAuers and @Big_Orrin
A link to the thread is included but be forewarned it forks numerous times
Any emphasis via bolding is ours
We have included charts to amplify the discussion points
Enjoy and learn, like we did!
Note: this first section is all @RobertAuers
Overall good article, but I’m so tired of reading the below excerpt from it.
Refineries could re-configure for a lighter oil slate, but they are only 15-20 yrs removed from configuring for heavier slates. The investments are enormous and regardless the U.S. does need to run some heavier oil grades in order to produce all the product desired.
- Aside from Canada and Mexico, the whole US except for the Atlantic and pacific coasts imports very little crude and have invested considerable to expand capacity and increase lt crude capacity.
- The Canadian barrels would have to flow through the gulf coast anyways to be re-exported, because that’s the only way out of Canada. And gulf coast refiners can turn them into finished products better than anybody else, so they stay there.
- Mexican crude is readily available and exported from the Mexican gulf coast, so it makes sense for it to go to the US gulf coast. The only gulf coast refiner who runs a lot of long-haul imported crude is the one owned by Saudi Aramco - and that’s for strategic reasons.
- The Pacific and Atlantic coast refineries cannot economically access large volumes of US crude because of their lack of pipeline connections to producing basins and the Jones act, which effectively prevents them from receiving US crude by ship.
- So this idea that US refiners would not have to rely on imported crude if they just invested more is total nonsense.
- Basically, my point is that US refiners will adjust to what available and make the best economic decision. And it doesn’t ever make sense to replace Canadian or Mexican heavy barrels.
- "My LP tells me the incremental WTI barrel is worth $4 more than WCS to me, but it costs $8 more than WCS, so I'm going to run WCS."
- And refineries do have some physical limits on the amount of light crude they can run, but those really aren't that hard to remove with some investment - and you've seen USGC refiners make those investments. The bigger problem now is there just isn't much heavy left to displace.
- And you're only making those investments if LP (linear program) tells you there some incentive to run more light crude. For most USGC refiners, it doesn't make sense to run more light crude at this point.
- They've invested a lot to run more light crude w/o sacrificing efficiency. Average API to PADD 3 refineries has gone from 29.7 in 2013 to 34.1 last year, and they haven't gotten any less efficient over that time frame.
- And it's a lot easier for a heavy crude refiner to run more light crude than vice versa. That's why they've been able to do this without too many major projects. Mostly just smaller debottlenecking efforts.
- Then, at some point, it doesn't make any sense to run more light crude. PADDs 2, 3, and 4 combined only imports ~500 MBPD of crude from countries other than Mexico and Canada, and half of that goes to Motiva. So there just aren't many imports left to displace.
Note this section is @RobertAuers and & @Big_Orrin; the thread deviates at times into different forks, this was the best attempt to reconcile different points being made
The quote blocks are from @Big_Orrin and bullet points from @RobertAuers
It gets to,the point where the cost of running more light crude requires projects that will never pay back The product slate problem is exacerbated by increasingly lighter shale oil reducing ability to produce diesel. It is not helped by the low amounts of hydrocrackers @Big_Orrin
- Just depends on your price deck. You can produce a lot of diesel from shale if you want to invest in hydrocracking. It’s just expensive, especially if already optimized around an fcc. So that’s take a long time to pay back and where are margins going to be in 5-10 years? @RobertAuers
Amount of diesel you can produce from shale with an FCC is low compared to medium/heavy with a hydrocracker. It is all relative to the alternative @Big_Orrin
- Sure, but hydrocrackers are expensive and sour crude can’t make low sulfur bunker (if you don’t have a Coker) @RobertAuers
It is all relative to the alternative. US has never had a diesel shortage before. In many ways has been seen as a by-product of the desire for gasoline. The increasing slate API and the reduced refinery capacity has led to this problem. @Big_Orrin
- I agree the capacity losses are a big factor, but I don't think crude quality has actually been that big of a driver in this regard. It's more changing product demand patters, with IMO bringing a step change here. The effects were muted for 2 years bc of low jet demand. @RobertAuers
- The chart shows that U.S. refiners have been increasing diesel output, even while running a lighter crude slate. the decline in diesel output in 2020/2021 was mostly driven by economics and the temporary loss of jet fuel demand. Expect to return to the trend this year. @RobertAuers
- Obviously, diesel has been king for almost 20 years, for the most at least, but IMO has just magnified that shift, and investment was suppressed because of COVID. And refiners/blender were able to dump excess kero into the resid pool to meet sulfur with jet demand down. @RobertAuers
- Now that jet demand is coming back, there's just not enough middle distillate available. @RobertAuers
They have increased diesel output because they have had a lighter cut. Taken some of the jet fuel into the diesel balance. Now that jet coming back, you only can take so much from gasoline before you start affecting diesel yield again. @Big_Orrin
The drop in middle distillates should only be really the amount of jet forced into the gasoline production. That is unlikely to get diesel/jet back to the pre-pandemic days. Therefore I expect that the api into the refineries will increase with more imports @Big_Orrin
- gasoline was priced above diesel in a lot of 2020 and most of 2021 - so most refiners were in max gasoline mode for those time periods, trying to maximize gasoline yields for economic reasons. @RobertAuers
But the peak cannot continue and much of that peak was due to the increased use of SRFO into the system. The API in reality was lower when that is taken into account because it is likely not added into the CDU. It was injected downstream @Big_Orrin
But again how much of that yield in 2019 was created by the move to IMO. The upmove in yield likely because of the refiners playing around with that factor. @Big_Orrin
But you can produce 60%+ with around a 40% -60% light/heavy combo with a hydrocracker/Coker @Big_Orrin
- Sure. Shale crude w/hydrocracking can make 55% diesel/jet if optimized. I’m just saying even cat cracking you can probably get close to 45% on pure shale crude if you optimize for that. Build a nice MHC you can probably get above 50% and still keep the cat. @RobertAuers
- But of, course that costs money and unless you bake in a real narrow light/heavy dif, you rather just go the medium/heavy sour route @RobertAuers
- My problem is just at a few survey Twitter, I feel like half the people would think that WTI trades below Mars or something. Light crude is still more expensive, light heavy differentials are just narrow. @RobertAuers