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Oil Complex


Crude and product markets did not receive any materially negative news on Wednesday, however, all were in negative territory as of today’s close, which happened to also be expiry for the Oct WTI contract.  The October WTI contract rolled off the board slightly weaker relative to the November contract (spread was ($0.10 tighter day-over-day), but still at a healthy $0.52 premium.  On a symbolically positive note, the October WTI contract did expire over $90/barrel, which is the first monthly expiry over that mark since last September.  Today’s loss of $0.92/barrel for Oct WTI pulled that contract down to $90.28, which is coincidentally (or maybe not) just a nickel from the last $90 plus expiry last year when the Sept ’22 contract rolled off at $90.23.


For products round number crack spread levels were broken on Wednesday with the nearby diesel crack dipping back below $50/barrel, while the front gasoline crack slipped back below $20.  Oct diesel suffered a $1.98/barrel decline day-over-day, and yet for the consumer a price tag of $3.33/gallon (wholesale of course) is not exactly easy to stomach.  Like the front WTI contract, Oct diesel sits very near year ago levels.  Oct ’23 diesel at $3.33/gallon compares to Oct ’22 which expired at $3.37/gallon.  The nearby RBOB contract fared slightly better day-over-day with a loss of $1.63/barrel, with an absolute level of $2.62/gallon also not favorable to the consumer, yet easier to handle than the past 2 months which were over $2.75/gallon.


DOE inventory data issued today did differ from yesterday afternoon’s API data, but primarily in magnitude not directionally.  DOE stats showed a 2.1 million barrel draw in crude vs. the APIs which posted a draw of 5.25 million barrels.  Products were bullish relative to API data, with the DOE indicating that distillate inventory was 2.9 million barrels lower week-over-week, or about 10x the 0.25 million barrel draw reported by the API.  Gasoline inventory according to the DOE was down 0.8 million barrels, which compares to the API at +0.7 million barrels.


The numbers above in conjunction with a steep reduction in Cushing inventory (-2 million barrels) did little to thwart selling interest which appeared to step up materially yesterday morning right after a spike to 1yr highs at the front of the curve.  Cushing inventory is down to 22.9 million barrels, which nearly on top of the 5yr min established back in 2018, and thus there is plenty of spare capacity at the NYMEX benchmark location as refinery outage season begins to ramp up in the weeks ahead.


Downward pressure impacted spreads and flat price on Wednesday with it being possible that a 2-month period of material short covering, could now give way to fragile length in a market that is up roughly $25/barrel at the front of the curve over the past 3 months.  Bal 23 WTI closed $0.86 lower at $89.43, followed by a $0.63 decline for Cal 24 which finished the day at $82.32.  For producers a front Cal strip at $82 should still be quite appealing at least relative to the past decade.  There have only been 2 years in the past 10 when a producer could lock in $80+ pricing for an upcoming Cal heading into the 4thquarter.  These two years, 2013 and 2014, were at the beginning of this ten-year window and as many remember what transpired in 2014 it was all downhill for a few years.  Of course, this time around the market has a different feel with OPEC+ supporting the market through large production cuts and product inventory globally still very low, at least in places where it is reported with any consistency and transparency.


Product inventory issues, and still forecasted demand growth in the year ahead, are the primary fundamental drivers of up upside opportunity for those with crude length.  In the not too distant future there could be some promise for those with short product positions.  Two large refineries are poised to reach full operational status in the next few months, with one on the left side of the Atlantic and another on the East.  The Dos Bocas refinery in Mexico, a 340K barrel per day facility in the southern Gulf of Mexico.  Just last week Mexican Energy Minister Rocio Nahle stated that the facility would be 100% operational by year end, with gasoline already being produced but not yet to spec.  On the other side of the Atlantic the Dangote refinery in Nigeria is poised to bring 650K barrels per day of product to a global market desperately in need.  This project located in the port city of Lagos, or actually in nearby Lekki, has been delayed from an initially expected start of 2018 for various financing and siting related issues, but is now expected to being production in the 1st quarter of 2023.


In other infrastructure news, and back on the North American continent, there is a development worth considering in respect to crude flows.  The long awaited Transmountain pipeline expansion, a twinning of the existing Canadian government owned crude + product system, is staged to re-route 590K barrels per day of Canadian crude away from Midwestern U.S. refineries and instead to the coast of B.C for ultimate delivery to Asian markets.  This project has a storied history with the Canadian government first putting obstacles in front of then owner Kinder Morgan, who ultimately sold the partially completed project to the Canadian government for $4.5 billion, who has now seen the cost to complete rise from initial estimates of $7 billion to present estimates north of $30 billion.  Most recent estimates place the project in service later this year, or in early 2024.  How this projects coming online impacts global markets will be interesting to follow, and at a minimum it should be a positive sign for Western Canadian producers, and Asian consumers, while concurrently being a warning shot for Midwestern U.S. refiners who have had about a decade of periodically getting to buy stranded Canadian barrels at steep discounts.


Natural Gas


For the NYMEX natural gas market an interesting dynamic has been at play for the past few weeks, and we are one day away from seeing if a pattern is becoming entrenched.  The dynamic is one where the market spends a week to 10 days revising its estimates for an upcoming EIA inventory report lower and lower, which then increases the odds that the result could be both above market consensus and yet well below what was anticipated with reliable weather forecasts already in hand.  This highlights two items of note:  1) market expectations and subsequent reactions to weekly inventory reports are not a reflection of balance tightness (bullish) or looseness (bearish), but rather a daily dynamic to be wary of on Thursday’s and 2) if weekly storage estimates consistently trend lower with 1-5 day weather forecasts in hand, along with a few days of actual weather then supply and demand estimates should be called in to question because it is not mother nature creating the change.


All of the above is meant to help separate the wheat from the chaff in respect to day-to-day price movements and market expectations.  Another variable, which the market also considers important, that falls into this category is the 5yr average season ending storage level.  Currently, a less than studious market participant would look at the 5yr average pre-winter inventory level of near 3.6 Tcf, compare it to estimates which have fallen 300 Bcf or so from 4.1 Tcf down to 3.8 Tcf, and conclude that we will still have ‘too much in the ground’ heading into winter.  However, a closer look shows that within that 5yr history there is a datapoint which skews the average down by 100-125 Bcf.  The 2018 season ending inventory level of 3.2 Tcf, a record low in the shale era, is the driver and were that pre-winter inventory to ever be seen again it could be a harbinger of double digit per MMBtu pricing in the months ahead, if they had not already been observed.  However, we (meaning the market in general in this context) currently include that in our present view of a 5yr average without much consideration at all that such a pricing dynamic could be around the corner any time soon.


We share the above before getting to daily price changes, any fundamental news of note, and thoughts on what lies ahead because it is valuable to avoid being trapped in a narrative machine or paradigm without a clear exit strategy.  Presently, the market is convinced that risk this winter and for the majority of 2024 is skewed to the downside.  For evidence please ask your bank desk counterparties for their most recent research piece, or trust that part of our work is to understand what assumptions are generally speaking.  While market narrative and behavior are powerful forces, and weather is the undefeated heavyweight champ, tightening supply and demand can only be kept at bay for so long.  For evidence of this it is worth a short ride in a time machine back to 2021 for a look at market views on 2022, or even in early in the 2022 rally when market views on 2023 were bearish at $4.00 before that Cal strip ultimately ran up to $6.50 (and then of course mother nature threw a knockout punch).  In respect to a narrative machine or paradigm exit strategy it is valuable to look at price levels, volatility, and term structure agnostically, and focus on where value lies rather than assigning odds of certain outcomes.


Turning back to the hear and now the October contract moved $0.115/MMBtu lower today with a closing price of $2.733.  There was little change to the front spread which had been on a tear of late (tightening), as the Nov contract closed down $0.105 at $2.921.  Selling pressure was most acute once again through winter ’23-’24 and Cal ’24 which posted respective daily losses of $0.066 and $0.043.  Offsetting movements in Cals 25 and 26 left the back of the curve little changed with the ’25 strip down $0.014 v. a $0.011 gain for Cal 26.  The winter ’23-’24 strip ended the day at one year low of $3.305, while Cals 24-26 posted respective daily closing prices of $3.371, $3.934, and $3.986.


Fundamentally, the biggest change over the past couple of days has been an uptick in wind generation which appears to have hit natural gas consumption in the power sector across the middle third of the country, subsequently putting a material dent in overall coal-to-gas switching observations.  Additionally, the planned annual outage at Cove Point began cutting LNG feedgas demand and correspondingly reducing the premium in Southeastern U.S. gas markets.  Looming on the horizon is a materially warmer than normal 11-15 day weather forecast, which in early October is cause for concern re: early season heating demand.


We have gone on for a bit today so we will quickly cover market expectations for tomorrow’s EIA inventory report.  Consensus expectations call for a build in the mid to upper 60s (Bcf), which would compare to the same week last year when a build of 99 Bcf was reported.  As a result, a report near market expectations would bring the year-over-year storage surplus under 425 Bcf for the first time since February.  Importantly it also appears likely that there will be reduction in the Y/Y surplus in the South Central of near 10 Bcf, which would pull that Y/Y total down close to +125 Bcf, or 150 Bcf lower than where it stood 2 months ago.