2020 has seen the evolution of the most unprecedented energy market dynamics in the past 50 years, due to the double-black swan convergence of demand (COVID-19) and supply (OPEC, OPEC+, and potentially G-20) shocks. During this unprecedented time in the global energy market, Ahmad Atwan would like to share some of the most useful insights on the impact of the one-two punch of COVID-19 demand destruction and OPEC and other producers’ supply volatility on various parts of the energy industry, with a specific focus on the US. The segments of the US energy industry that will be examined include:
- Crude Oil
- Natural Gas
Crude Oil: US Production Outlook Amidst COVID-19 and Global Supply Volatility
Statewide shelter-in-place orders, worldwide business shutdowns, market meltdowns, medical calamities. Much of what is going on right now is unprecedented in the modern era, and there are no guideposts to help predict what happens next to the world as we knew it. But in the boom-bust energy sector, it is déjà vu all over again. We have seen steep drops in prices, drilling activity and production enough times to have some idea about how this is likely to play out. Granted, this time around it is particularly bad, but that doesn’t change the sequence of events that we are likely to experience over the coming months and years. Today, we’ll look back at what happens to Shale-Era basins after a price collapse, focusing on the inherent lag between a major reduction in activity level and the inevitable production response.
The price of CME/NYMEX Cushing WTI crude oil for April delivery (the last day of trading for the contract) fell by the end of the day to $19.46 before the settlement was posted at $22.43/bbl, down $2.79/bbl. The WTI May contract closed at $22.63, down $3.28/bbl. Forget fundamentals. Crude oil prices are now totally dependent on the next news flash, press release, rumor or stock-price shock. About the only thing we can be sure of is that it is likely to be a long while before we see the sunny side of $50/bbl crude oil again.
Producers are responding to that harsh reality by cutting their capex budgets even deeper than their initial 2020 plans. Even before last week’s price carnage, 42 E&Ps had announced that their total capital spending would be cut by 26% from previous guidance and a reduction of 36% versus 2019. No doubt we’ll see many more cuts in the coming weeks. But there are a couple of important things to note. First, with only a few minor exceptions, E&Ps are still drilling, collectively planning to spend tens of billions of dollars to bring more oil and gas to the market. Second, these companies are in survival mode. Consequently, those billions are being spent drilling the sweetest of the sweet spots using the most productive drilling and completion equipment out there, so volumes are not falling off nearly as fast as are capex dollars. For example, on March 16, EOG Resources announced a 31% capex reduction but said that it expects 2020 production to be flat compared to last year. Granted that’s down from their previous guidance of 10%-14% growth, but it is not a decline. When all the guidance comes in with first-quarter results, we expect that the universe of companies will come in collectively somewhere around a 6-8% decline in production targets. Down, but not out.
To be sure, crude prices are off sharply, and we can expect cuts in active rigs to come very quickly. On Friday, the Baker Hughes U.S. rig count was down by 20 to 722, with 19 of those being crude-focused rigs, 13 of which were out of the Permian. But even though the rig count will be withering at a record pace, that does not mean that we’ll see a steep decline in production. One reason is DUCs — drilled-but-uncompleted wells — that producers can turn on to generate revenue without the need of a drilling rig. Another is that there are still a lot of rigs out there running. And, as we said just above, the rigs and crews that remain in operation are the cream of the crop, and they are drilling in the absolute best locations.
Of course, eventually a reduced level of drilling will slow production growth, then flatten output and likely even bring it down. But even if crude oil prices stay dirt cheap for a long time, the fall in production will stretch out over months. And at some point, the decline will flatten out. That’s because of the innate production curve — or type curve — for shale wells. Steep in the front. Flat in the back. So wells drilled in the recent past will be on the steep part of the decline, and producers won’t be drilling enough new wells to offset the decline of those existing wells. But over time, the preponderance of wells will reach the flat part of the curve, and the pace of the decline will slow. That’s what we saw in the Eagle Ford and the Bakken back in 2015-16. But an even better example is what happened to Haynesville gas in 2011-14. Haynesville, located in Northwest Louisiana and Northeast Texas, is a gas play, but the way it played out is a classic. In fact, the Haynesville experience makes a great case study in which we can segment the rise, decline and recovery of a shale basin into five distinct stages.
You can start to wrap your head around the notion that, in a highly productive shale play, a ramp-up in drilling-and-completion activity can result in a relatively quick rise in production, and a ramp-down in drilling will drive a relatively swift change in the short-term trajectory of production growth, but that it takes time for a true decline in production to set in. The Haynesville’s experience over a roughly 10-year period — from 2007 to 2017 — helps to demonstrate that point. The play went through five stages:
1. Good Times – 2007 to early 2011. Spurred by Chesapeake Corp.’s discovery of extensive shale-gas reserves in the Haynesville in 2007-08, the rig count in the play (brown line, left axis) took a choppy rise from 110 to 160. During that time, Haynesville gas production (green line, right axis) was increasing fast, eventually skyrocketing from 5 Bcf/d in 2009 to 10.6 Bcf/d in 2011. Nothing like that had ever been seen before. But by 2011, the flood of incremental gas supply was overwhelming the U.S. market and natural gas prices plummeted from the $4.30/MMBtu level in the first half of 2011, sliding over the next 18 months to average $2.80/MMBtu during 2012. The Haynesville was hit hard; production there was strictly dry gas, with very little NGLs to supplement producers’ bottom lines. So the focus of U.S. drilling activity quickly shifted to shale plays that produced either crude oil (like the Bakken); “wet,” NGL- and condensate-rich streams (like the Eagle Ford); or the emerging, highly prolific Marcellus natural gas play, all of which offered higher returns.
2. Rig-Cutting Time – Mid-2011 to mid-2012. Producers abandoned the Haynesville in droves. The working rig count fell from 160 to 40 by mid-2012. But check out what happened to production. As the rig count fell, production continued to rise. And even after the rig count hit rock bottom, Haynesville production was still relatively flat. As we demonstrated above, shale’s decline curve math has a built-in inertia factor. Fewer wells were being drilled, but the wells that were being completed after the drilling cuts started focused on the best locations using technological upgrades, thus were so productive that they offset the drilling slowdown. But there is a limit to how long that can go on.
3. Production Cuts – Mid-2012 to early 2014. By mid-2012, that limit had been reached, and Haynesville production declined from 10.6 Bcf/d down to 6.5 Bcf/d in 2014, even with only 40 or so rigs running. But then, all those wells that had been drilled two, three or four years before had reached the flat spot in their type curves.
4. The Zombie Phase – Mid-2014 to late 2016. And then production flattened out. The production decline was minimal. A low price hardly makes any difference in this phase. Output from the wells in place is no longer declining rapidly. The wells are just rocking along, generating cash, and incurring only modest operating costs. Most of the capital has been invested years before. No production gets shut in. Producers need the cash to stay alive.
5. The Recovery Phase – Early 2017 on. A whole new slate of players entered the Haynesville fray, primarily private equity-backed management firms (as opposed to the publicly held producers of the early days). When they came in, they did so armed with new methods and technologies that could achieve much higher output per well. The rig count rebounded and so did production.
In fact, after 2017, the Haynesville went on to surpass its old 10.6-Bcf/d peak production in early 2019, and the play’s output now tops 12.4 Bcf/d. While natural gas prices remain sub-$2/MMBtu and the LNG export market may face COVID-19-related challenges in the months ahead, the Haynesville ironically stands to benefit from the collapse in crude oil prices. Super-cheap crude is sure to drag down the rig count — and, eventually production — in the Permian and other crude-focused shale plays that produce a lot of associated gas with their oil. When those associated gas volumes come down, natural gas prices could rise, potentially spurring a new round of drilling in East Texas and Northwest Louisiana.
The most relevant lesson from the Haynesville’s roller coaster, though, may be that while the oil price crash will result in a big decline in the rig count in the near term, it will take many months for U.S. crude oil production to drop into a significant decline phase. In fact, it is likely that Permian crude production turns out to have more inertia than did the Haynesville, due to the significant number of legacy producing wells in the basin that have been on the flat part of their type curve for decades. That, combined with Saudi Arabia and Russia’s plans to flood the global market with their crude, suggests that a lingering worldwide glut of oil is on the horizon.
Natural Gas: Impact of COVID-19 and Global Supply Volatility
While the crude oil market meltdown has taken center stage in recent weeks, and for good reason, the natural gas market is bracing for its own fallout. The CME/NYMEX Henry Hub April futures price, which was already at a multi-year low, buckled last week, falling to as low as $1.602/MMBtu on March 23, and expired Friday at $1.634/MMBtu, the lowest April expiration settle since 1995. On its first day in prompt position, the May futures contract yesterday eked out a late-day, 1.9-cent gain that brought it back up near $1.70/MMBtu as traders continued weighing competing market factors. Gas futures earlier in March were initially buoyed by the assumption that the low oil-price environment would slow associated gas production — and it will, eventually. But that initial bullish sentiment was quickly usurped by the more immediate effects of demand losses resulting from the economic slowdown caused by COVID-19, as well as from mild weather. We will now look at how these developments are shaping gas supply-demand fundamentals heading into the gas storage injection season.
Associated gas and liquids from U.S. crude production have driven much of the growth in gas and NGLs supply over the past half-decade or so, and how that dynamic will change in a post-COVID world. We turn our focus to how recent events, along with weather and storage fundamentals, are playing out in the Lower-48 natural gas market.
When we looked at the gas market in late January — well before COVID took hold in the U.S. or oil prices fell below $30/bbl — it already was under pressure and trading at multi-decade lows just under $2/MMBtu. The market had entered winter withdrawal season in November 2019 with a large surplus in storage compared with the same time in 2018, following strong production gains through the latter half of summer 2019. Demand was strong, even at or near record highs, but the growth was lagging relative to production volumes. By mid-January 2020, prospects for an extreme, cold winter to reverse the storage surplus also were fading fast, and the prompt contract that month traded as low as $1.829/MMBtu — the lowest since 1999 for January trading — and expired at $1.877/MMBtu. That was followed by balmy weather through February, which led to a still larger surplus in storage and lower prompt-month prices, though the March contract expired at the end of February still above $1.80/MMBtu.
Since then, prompt futures prices have pinballed within more than a 30-cent range, buffeted by an unprecedented confluence of factors: sub-$25/bbl crude oil prices, the resulting parade of upstream and midstream capital spending cuts and rig take-downs, and most recently, the prospect of demand destruction from widespread — and still-widening — school, entertainment and business closures, and shelter-in-place orders. (We’ll get to the impact of commercial closures vs. the increased residential consumption resulting from the stay-at-home orders in a bit.) The choppy trend in the Figure 1 inset illustrates the uncertainty gripping the market in recent weeks.
The prompt April contract initially started March near $1.70/MMBtu, more than $0.10/MMBtu below the March contract expiration. Then, as oil prices collapsed to $30/bbl levels in early March, gas prices staged a 13% rally to nearly $1.94/MMBtu on March 10. Why? Well, it goes back to what we said above: associated gas production from shale oil drilling has been a primary driver of overall gas supply growth in recent years. With oil prices tanking, the thinking by some of the market was that oil production and the associated gas volumes would fall. And sure enough, producers began sounding the alarms with severe capex cuts to their already stripped-down spending plans for 2020, signaling a dramatic slowdown in drilling activity. But the impending slowdown in production is likely to play out more like a slow-motion train wreck than an abrupt cliff-dive. There are several factors that work to delay the inevitable production slowdown, namely: completions of revenue-generating drilled-but-uncompleted wells (DUCs), a focus on the absolute best drilling locations and the resulting efficiency gains, and the number of older wells now in their steady-state decline phase. (We should note that dry gas production volumes briefly fell by more than 1 Bcf/d last week, but indications are that much or all of that was due to near-term maintenance events or unplanned outages that affected pipeline or processing capacity, and volumes rebounded over the weekend as some of those issues were resolved.)
Moreover, any immediate concerns about supply loss were overtaken by the more imminent threat of demand destruction as entertainment venues, schools and businesses shut down in nationwide efforts to curb the spread of the coronavirus. With commercial closures piling up and compounding what’s been relentlessly mild weather-related demand, the April contract in the second half of March collapsed, settling at $1.60/MMBtu three times in the past couple of weeks, the lowest daily settles seen in March trading since 1995, before expiring Friday at $1.634/MMBtu, also a 25-year low for the April contract.
While it’s too early to tell the full effects of these events or how long they’ll last, there are a few potential mitigating factors to keep in mind, at least in the near term. On the supply side, while it may take some amount of time for production to flatten or show declines, we are entering maintenance season, when midstreamers utilize the lower-demand shoulder period to conduct pipeline and other maintenance. This can result in temporary capacity reductions for production receipts. Thus, while COVID restrictions may disrupt some midstreamers’ maintenance plans, it’s possible we could see some modest and short-term supply disruptions during the spring and early-summer months due to planned or unplanned outages.
As for demand, the coronavirus-related closures, here, in Europe and elsewhere around the globe, are unparalleled in their breadth — and still mounting — and their effects on demand will start to become clearer in the coming weeks. But what we do know is that fundamentals were weak even before the commercial shutdowns hit. Moreover, we’re in the midst of a seasonal shift to the shoulder months, when weather-related demand for gas bottoms out for the year. Temperatures during this time rise enough to suppress residential/commercial (res/comm) heating demand but aren’t quite high enough to kick on substantial air conditioning demand. On top of that, March weather was exceptionally mild (i.e., much warmer than normal), which led to an early start to the shoulder season.
All of that is to say that net gas consumption from domestic sectors has been exceptionally bearish. Total Lower-48 sector demand in March was down significantly — by more than 9 Bcf/d (10%) — from the same period last year.
The biggest demand loss has come, not surprisingly, from the res/comm sector, which consumed about 34 Bcf/d in March, a whopping ~11 Bcf/d less than the same period last year (right-most graph in Figure 2). Res/comm demand slumped behind 2019 in January and February too, but outright temperatures are typically much colder in those months and thus have a bigger influence on demand than in March, when overall temperatures are already seasonally higher. And this March, as we said, was exceptionally warm. Thus, the warmer-than-normal weather had the effect of further suppressing res/comm demand this month.
Industrial demand has also trailed behind last year, but the higher temperatures and lower prices have prompted incremental gas demand for power generation, or power burn. So, the only gains in domestic-sector demand have come from power burn, which was up an average ~2 Bcf/d year-on-year in March, in part because lower gas prices have made gas-fired generation even more attractive versus coal.
Increased exports also helped offset res/comm and industrial declines. Pipeline flows to Mexico in March were up 0.7 Bcf/d from last year to 5.7 Bcf/d, while feedgas deliveries for LNG exports were up 4.1 Bcf/d from last year to 8.3 Bcf/d. But the net effect of U.S. consumption plus exports was a 4.4-Bcf/d year-on-year drop in total gas demand for March. By comparison, overall Lower-48 supplies, albeit stagnating in recent months, maintained a ~4 Bcf/d gain over March 2019, meaning the supply-demand balance this March was more than 8 Bcf/d looser (higher supply) than last year. If we look at year-to-date volumes, total demand has averaged a net 0.6 Bcf/d lower than last year, compared to a supply gain of 4.6 Bcf/d, leaving the year-to-date balance more than 5 Bcf/d higher supply than last year.
Even without the COVID shutdowns, these supply-demand trends would be enough to sink prices, given that the storage inventory already is running high and carrying a substantial surplus versus both last year and the five-year average (shaded blue area). By the end of February, the surplus in storage had climbed to 700 Bcf versus last year and 180 Bcf versus the five-year average inventory for the same week. That’s now closer to 900 Bcf above last year as of last week, and more than 300 Bcf above the five-year average. And at a five-year average injection pace from April through October, that surplus would persist into next winter.
So clearly, any demand loss from the COVID containment measures would only exacerbate what is already the most bearish scenario for gas near term that we’ve seen in years. All eyes are on the weekly EIA storage reports over the next few weeks for the first signs of demand loss after shutdowns went into effect. The question is, how bad could demand be hit during the shutdowns, not just here but also in Europe and Asia?
LNG export demand was somewhat volatile in March as foggy conditions along the Gulf Coast impeded cargo activity through much of March, particularly at the Sabine Pass LNG terminal in Louisiana. Total feedgas volumes for the month averaged 8.3 Bcf/d, about 0.5 Bcf/d lower than the 8.7 Bcf/d seen in the January-February period. Cheniere reportedly had to purchase additional storage capacity to manage excess feedgas, as the reduced cargo loadings constrained storage capacity at the terminal. As the weather warms, fog should be less of a factor and cargo activity should stabilize. That said, it’s possible that maintenance-related outages could reduce feedgas demand. Sabine Pass has had 15- to 30-day downtime periods in the spring and fall the past couple of years, indicating seasonal maintenance. Last spring, it began around late March and appeared to continue through mid- to late April. That could slow cargo activity, for a time at least. But whether the maintenance recurs this season remains to be seen, given the COVID containment measures.
The other potential downside risk to LNG exports is global demand. Europe — a primary destination for U.S. LNG — also had a mild winter, is sitting on record inventory in storage and has implemented its own commercial and industrial shutdowns to combat COVID. When parts of Asia — the other big destination for U.S. LNG — went into lockdown mode earlier this year, there were a couple of cargo cancellations (for April delivery), and at one point, China had attempted a force majeure on LNG cargoes. Now, there’s the risk of that happening in Europe, where some buyers are reportedly considering force majeure. Additionally, last week, two state-owned entities in India issued a force majeure as the nation entered a 21-day lockdown. Prices for the Japan-Korea Marker (JKM) fell sharply in the past week, but so did European prices, and Asian destinations remain the more favorable markets. Some Asian demand is beginning to recover as China and others are gradually resuming commercial activity. And in the past week, there were more cargoes moving to Asia than to Europe for the first time since November, potentially signaling the start of the shift toward Asia.
Long-term contracts for U.S. liquefaction capacity are expected to keep LNG exports from the existing and commissioning terminals flowing at steady, almost baseload-type rates regardless of global price dynamics. If cargoes are canceled by the capacity holder, so the logic goes, they would be sold in the spot market and diverted from their original destination to other ports, such as to Latin America, particularly Mexico, where summer power demand will be ramping up as well. And, we’ve seen some of that happening already. The big caveat to that, of course, is that if substantially weaker global demand does lead to more cargo cancellations, U.S. LNG producers would need to brace for sustained lower destination prices and weak spreads. This would become especially problematic down the road once the production slowdown materializes and lifts domestic gas prices.
As for U.S. sector demand, there is less certainty, given that weather tends to trump everything, and it remains the perpetual wildcard. While COVID-related shutdowns likely haven’t peaked yet, those may also be less of an influence on demand in the coming weeks than they would have been earlier this year. That’s because seasonal temperatures are now rising to levels where res/comm heating demand typically diminishes and has less influence on overall demand, and power burn for air conditioning begins to take the reins on driving domestic gas consumption. So the teleworking and shelter-in-place orders that are now keeping many more people inside their homes nearly around the clock, could actually boost power burn and help offset declines in commercial and industrial use through the shoulder months, especially if temperatures continue trending warmer than normal. (The lower gas prices mean utilities would favor gas-fired generation over coal.) Additionally, domestic consumption was also extremely weak in April 2019, due to mild weather and depressed res/comm demand, providing an already bearish backdrop for a comparison to this April. However, prolonged shutdowns that extend well into the hottest summer months could have the opposite effect and reduce overall cooling load.
The the storage withdrawals and injections reported by the EIA over the next few weeks will be critical for understanding how the COVID response is factoring into the supply-demand balance.
Refining: Impact of COVID-19 and Supply Volatility
COVID-19 And The Crude Oil Price Crash Puts The Screws On U.S. Refiners
The collapse in crude oil prices and COVID-19’s very negative effects on global gasoline, jet fuel and diesel demand are putting an unprecedented squeeze on U.S. refiners. Even before the initial coronavirus outbreak in Wuhan, China, started to grab headlines around New Year’s Day, refineries had already been incentivized to shift their refined products output toward diesel, which can be used to help make IMO 2020-compliant low-sulfur bunker. Now, with the COVID-19 pandemic spreading to Europe and North America and stifling consumer transportation fuel demand, the price signals are even stronger, pushing refineries to do everything they can to minimize their gasoline and jet fuel production and enter what you might call “max diesel mode.” We will now discuss how there are challenges and limits to what they can do, and a number of refineries may need to shut down due to lower demand, at least temporarily.
Last Monday, March 16, grumblings started among commodity traders regarding negative gasoline cracks — cracks being the price of gasoline minus the price of crude — on the NYMEX. By the end of that day’s session, crack spreads for Reformulated Gasoline Blendstock for Oxygenated Blending (RBOB) — the benchmark for gasoline trading — had fallen almost 90% to settle below $1/bbl (blue line, left graph in Figure 1). Gasoline prices crashed another whopping 30% on Monday, March 23rd. Ultra-low-sulfur diesel (ULSD) cracks remained strong at $16/bbl (right graph in Figure 1), but the jet fuel crack spread (not shown), which is usually closely tied to diesel, closed at only $8/bbl. Since then, regional crack spreads for gasoline around the U.S. hovered below $5/bbl and then moved into negative territory.
With strong price signals pushing refiners towards diesel production, they would have made immediate adjustments to tweak their refined product yields. However, as we said in our introduction, refiners through the second half of 2019 had already been given strong price signals to produce more diesel heading into the fourth quarter of 2019 and the first quarter of 2020 due to the IMO 2020-related need for low-sulfur bunker. Weekly Energy Information Administration (EIA) data released last Wednesday, March 18, indicated that the current distillate yield (diesel plus jet fuel) at U.S. refineries was around 48%, or three percentage points lower than the 51% peak over the last year. Therefore, the potential to swing from gasoline to distillate is likely limited. The larger swing that could take place would be to blend kerosene used for jet fuel production into diesel — in other words, optimize the two finished transportation fuels within the distillate pool.
To estimate this shift, we ran some simulations utilizing Baker & O’Brien’s PRISM refinery model. Figure 2 lays out a step-change analysis for the entire U.S., toggling different options to reduce jet and gasoline production. This analysis assumes that immediate changes to the crude oil slate are not taken but could be an option for refiners to consider down the road as the ongoing crisis unfolds.
- Base Case: This is our starting point; it shows aggregate refinery production of gasoline, jet fuel and diesel as it stood in the summer of 2019; U.S. refinery utilization stood just north of 90% (black diamond at top of column).
- Reduce Jet Yield: Given that jet fuel was the first commodity to experience a sharp reduction in consumption once the crisis started, we believe refiners would have adjusted their operations to maximize kerosene or jet fuel blending into the diesel pool. To do this analysis, we simulated every refinery in the U.S. using their 2019 crude slates, and eliminated the incentive to make jet fuel. This analysis yielded the maximum amount of jet fuel that we estimate can be blended into the diesel pool to produce on-spec product: about 65%, or enough to increase diesel production by approximately 20%. Despite the modeling results, though, our gut tells us that a 65% shift of jet fuel to diesel may be too high, and we therefore have held the jet fuel production cut at 50%.
- Reduce Diesel Production to 2019 Levels: This analysis tries to eliminate a problem created by moving jet fuel into diesel — namely, significantly out-producing actual demand. If we assume that U.S. demand and exports of diesel remain the same, which would be optimistic, this toggles total U.S. production and utilization downward by more than 14 percentage points.
- Reduce Gasoline Production by 30% from 2019 levels: First, a caveat: this scenario is highly speculative. Given the current requirements for social distancing, the closure of schools and non-essential businesses and the like, how much could gasoline demand be reduced by? We have chosen 30%, but as more states enact “stay-at-home” mandates, that estimate could be low. Ignoring the impacts of storage fills or draws, ratcheting down refinery throughput to put gasoline supply and demand into relative balance would lower throughput to levels not seen since 1985.
- Reduce Gasoline Production by 50% from 2019 levels: This analysis is similar to the fourth column, but assumes gasoline demand comes off by 50% for a period of time, which covers some of the sharpest reduction estimates we’ve seen forecasted.
The final column paints a very dire situation, with aggregated refinery utilization at about 45%. In our experience, crude throughput in the 60% to 70% range is approaching the minimum rates that a refinery can operate without completely shutting down units. The above analysis is focused on the U.S. in aggregate and does not account for the nuances of each refinery (or refining operator) and every region other than the analysis of the quantity of jet that could move to diesel.
In reality, not every refinery can or would ramp down to 45% or 55% under our worst-case scenario. If that situation were to come to fruition, some refineries would have to shut down while others would maintain a higher utilization. So, which refineries are at risk? We assessed this based on two primary factors (though there are many other variables that refiners would have to account for): (1) which refineries produce a higher yield of gasoline and jet fuel versus diesel, and (2) which refineries have access to outlets for their products through either excess storage or export markets.
Starting with the yields, crude slates and refinery configuration are strong influencers on the quantity of gasoline and jet produced. Figure 3 shows our estimated aggregate gasoline and jet yields for the U.S.’s 130-plus refineries by PADD after pushing all the jet possible into the diesel pool. (The width of each refinery’s bar reflects its capacity.) In this chart, the farther to the left a refinery sits, the more gasoline and jet fuel the facility makes in this scenario. The refineries in the left-most quarter of the chart would be the most at risk, since they would require huge — and possibly unfeasible — crude rate reductions to remain in gasoline/jet “containment mode.” In contrast, the refineries in the right half of the chart would appear to be in a much better position, if offtake and/or storage are available for their excess products.
The next issue relates to location — that is, if a facility can’t sell all its gasoline and jet in its immediate region, does it have sufficient access to storage and to ancillary markets for sale to keep supply and demand in relative balance? This nuance puts refineries in PADD 2 (the Midwest) and PADD 4 (the Rockies) at higher risk of reduced utilization rates or shutdowns. The current refined pipeline network in the U.S. is configured to move products from PADD 3 (Gulf Coast) into the Midwest and Rockies, but not the other way around. Therefore, if consumers in PADDs 2 and 4 severely cut back on consumption, refineries in those regions would be left at the mercy of storage capacity before their utilization rates have to be cut. Unfortunately, storage of gasoline in PADD 2 tends to peak in late February of every year, with a maximum inventory of ~63 MMbbl over the last five years. Storage of gasoline components in PADD 2 as of March 18 was ~57 MMbbl (blue bar segment in Figure 4). EIA’s 2019 estimate of total working storage capacity in PADD 2 was ~77 MMbbl, and we assume storage levels can rise to ~90% of the working storage level, or about 69.3 MMbbl (blue plus red bar segments). That would leave less than 20 days of incremental stockpiling capacity if demand were to drop by 30%. The situation is similar in PADD 4.
The three other PADDs, which are predominantly near the water and have access to export markets, have more options to place barrels, but reduced run rates and shutdowns would probably come their way as well if the situation becomes bad enough. PADD 5 (the West Coast), for example, has some of the highest gasoline and jet yields in the country — note the number of aqua bars in the left half of the Figure 2 chart — and also happens to be a region that has been hit particularly hard by COVID-19. With the entire state of California essentially in lock-down mode, refineries there will likely see widespread utilization reductions over the coming weeks. Similarly, there are a number of stay-at-home mandates in place in PADD 1 (the East Coast), another hard-hit region. That leaves PADD 3 — again, the Gulf Coast, and the location of about half of total U.S. refining capacity. If shipments on the Colonial and Plantation refined pipelines from the PADD 3 to PADD 1 drop due to dwindling East Coast demand, can those excess barrels be placed on the water? In our opinion, probably not all of them.
This is an extreme situation facing the globe and the near-term impacts may well be dire, but it’s one that will eventually end — the question is when. While some refining assets may have to throttle back utilization for a period of time and some may even shut down temporarily, we are hopeful that over time, things will return to normal for refiners, and everyone. But it’s a situation that we will continue to monitor. Join us at our upcoming School of Energy Virtual conference, during which Amy Kalt will discuss the impacts of these and other recent market events on the crude oil and refined products sectors.