REFINERY MARGIN TRACKER: USGC coking margins up strong demand, wider crude spreads

US Gulf Coast coking margins have been surpassing the region's cracking margins as distillate demand beats 2019 levels, European refiners seek lighter crudes and seasonal plant turnarounds begin to cut back output, sources said.

Major US refiners agreed in their fourth quarter results calls gasoline and diesel demand has rebounded since the coronavirus pandemic downturn. And lagging jet demand is on the road to recovery as more countries open borders, supporting higher coking margins.

Coking margins at the sophisticated refineries dotting the USGC for Mexican Maya rose to average $8.78/b for the week ended Feb. 11, up from the $7.81/b the week earlier, according to S&P Global Platts Analytics margin data.

Demand for gasoline and diesel are already above 2019 levels as each successive wave of the coronavirus has less of an impact to demand.

And "from a demand perspective, gasoline, diesel and jet inventories are well below 2019 levels in terms of days of forward cover," PBF Energy CEO Tom Nimbley said on a Feb. 10 Q4 results call.

"We view this as a very constructive set-up for 2022. Product inventories are low, demand continues to strengthen and lower refinery capacity due to global capacity rationalization should all support favorable refining margins," Nimbley said on the call.

Most US refiners estimate about 4.5 million b/d of global refining capacity was eliminated by the coronavirus pandemic.

"We expect demand in 2022 will continue its strong recovery and exceed 2021," he added.

Cracking margins also remain healthy as lack of storms pushed up US gasoline demand last week by 6.5% week on week, according to Patrick De Haan of GasBuddy.

USGC WTI-MEH cracking margins averaged $18.96/b for the week ended Feb. 11, Platts Analytics data showed, up from the $18.11/b the week earlier.

Stripping out RINs, the renewable energy credits used by refiners to meet US Environmental Protection Agency's Renewable Fuel Standard, the USGC WTI-MEH weekly cracking margin for the week ended Feb. 11 averaged $14.59/b, surpassing the prepandemic level of $14.52/b reached in October 2019.

And with a seasonal heavy turnaround schedule around the corner, margins are likely to rise further as refined product supply dwindles. Platts Analytics forecasts that 2.7 million b/d of US refinery capacity will be offline in February, rising to near 3 million b/d in March as refiners expect a heavy turnaround season.

Shifting crude flows of sours and sweets

The ability of the USGC's complex refining capacity to run heavier, higher sulfur crudes gives it a price advantage on the global market when it comes to coking margins.

High European natural gas prices continue to benefit USGC refiners, as European refiners are backing out medium sulfur crude like Russian Urals in lieu of lighter, less sour crudes to conserve hydrogen use.

The discount held by Russian Urals to North Sea Forties averaged $7.32/b for the week ended Feb. 11, out from the $5.60/b the week earlier and well above 2019's average discount of $2.70/b, according to Platts price assessments.

Even as the price of the Dutch benchmark TTF natural gas contract softens from the $45/MMBtu level seen in mid-December, the average price of $25.51/MMBtu for the week ended Feb. 11 remains at a multiple to 2019 and 2020 average levels of $4.43/MMBtu and $3.20 MMBtu, respectively, according to Platts assessments.

"That's over $150 equivalent oil," said Nimbley.

The skew from European and some Asian refiners for lighter, sweeter crudes has created a supply tightness for the grade, putting at an advantage US Gulf Coast refiners able to handle heavier crudes.

According to PBF's Nimbley, the high cost of natural gas is tacking on $3-$5/b to operating costs for European refiners, which is "in our view an advantage for US, or at least our system, given the size and and complexity of and the cost we incur."

Throughout the Q4 earnings period, analysts have been questioned if a structural refining shift is underway.

"My own personal view is this: it is ... maybe the first or second example of going into the energy transition with a ... set of goals, but perhaps not well-thought out strategy and execution plan," said Nimbley.

"You shut down nuclear plants, you shut down coal plants and now you are starting to shut down fossil fuel plants to rely on solar and wind. And if that's not available ... it becomes a problem," added Nimbley, noting that in his view "we will see more examples of that as we go forward."