U.S. Northeast natural gas producers may be on the other side of a years-long battle with perpetual pipeline constraints and oversupply conditions. But they’re now facing new challenges to supply growth, at least in the near-term, from low crude oil and gas prices and the decline of a major downstream consumer of Appalachian gas supplies: LNG exports along the Gulf Coast. Most of the U.S. well shut-ins since the recent oil price collapse are concentrated in oil-focused shale plays, and gas volumes associated with those wells will be the hardest hit. However, a number of gas-focused Marcellus/Utica producers also have announced or escalated supply curtailments in recent weeks, as they wait for associated gas declines to buoy prices enough to support drilling. The pullback has had immediate effects on the region’s production volumes and supply-demand balance. Today, we provide an update on the latest Appalachia gas supply trends using daily gas pipeline flow data.
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Daily energy Posts
Canada’s energy sector has been hit hard by the recent oil price collapse that was initially set off by the now-ended Saudi Arabia-Russia price war and made much worse by the demand-destroying effects of the global COVID-19 pandemic lockdowns. The impacts on Canada’s crude oil and natural gas sectors have been both dramatic and nuanced. For example, oil supply cutbacks have been rapid and substantial, while there has been virtually zero impact on natural gas supplies. Oil demand has been similarly affected, with refined product demand seeing a large swoon, while natural gas demand has suffered only a modest pullback. And for Canada’s energy exports, these have experienced some jolting swings in a matter of weeks, putting the whole sector under pressure to adapt where possible. Today, we highlight some of the recent market disruptions and their implications.
Through the second half of the 2010s, the Permian Basin’s crude oil supply trajectory was clear: up, up and up. From the start of 2015 to the end of last year, crude production in the world’s leading shale play increased by an amazing 3 MMb/d, from 1.7 MMb/d to 4.7 MMb/d. Three new pipelines with a combined capacity of more than 2 MMb/d were built to move a lot of those incremental barrels to Corpus Christi, which — thanks in part to newly developed storage and docks — has become the U.S.’s #1 port for crude exports in recent months. But Permian producers have trimmed their crude output by at least several hundred thousand barrels a day this spring in response to falling demand and low prices. Has the Permian been thrown off course, and if it has, what would that mean for marine terminals in Corpus? Today, we continue our series of Gulf Coast crude export facilities with a look at the three newest terminals along the Corpus Christi Ship Channel.
Crude oil markets have been anything but dull lately. After imploding to unimaginable, negative values last month, prices have been on a tear since and are now sitting in the low $30s/bbl range. That’s not great for producers, but kind of like social distancing flattens the curve, the current price level should keep production volumes in check and stave off the worst of the potential financial distress for most Permian producers, for now. So, what has been driving the price rise? Similar to the pauses in economic and social activity that many cities have taken lately, many Permian producers have recently decided to take a wait-and-see approach on crude prices and throttle back output. Today, we provide an update on the always-dynamic Permian Basin crude oil market and how producer curtailments have materialized in May.
Very Large Crude Carriers offer economies of scale and are the oil transporters of choice for shippers moving massive volumes of crude from the U.S. Gulf Coast to distant customers in Europe and Asia. VLCCs also can serve as cost-effective floating storage — in the current contango market, a growing number of these 2-MMbbl behemoths are being used to stockpile crude until its value increases in the coming months. VLCCs can be loaded to the gills through reverse lightering at a number of deepwater points off the coast of Texas, but only one facility, the Louisiana Offshore Oil Port, can fill the supertankers to the brim at the port itself. LOOP also can receive fully loaded VLCCs, of course, and another ace up its sleeve is its 72 MMbbl of cavern and tank storage a few miles inland at Clovelly, LA. Today, we continue our series on Gulf Coast export facilities with a look at LOOP.
Back in late March and early April, U.S. refineries responded to the sudden falloff in demand for jet fuel and motor gasoline by quickly ramping down their operations. Similarly, E&Ps in recent weeks have reacted to sharply lower demand for crude oil by slowing — or even suspending — their drilling activity and shutting in wells. Midstream companies’ actions have generally been more muted, though. While many midstreamers have ratcheted back their planned 2020 capital spending plans, the bulk of their major crude oil, natural gas and NGL projects already under construction are staying on-plan. Most of the rest are only being delayed by a few months, and a handful are either being reworked or deferred indefinitely. Today, we consider the midstream sector’s seemingly modest response to the crashes in crude oil prices and demand.
U.S. refinery demand for crude oil is off sharply due to COVID-related impacts on automobile and jet travel, and crude production is being slashed. Crude storage is filling up fast, both on land and on tankers at sea, and may be maxed out by June. That leaves imports and exports as the market-balancing agents, at least until demand for motor gasoline and jet fuel starts to rebound. And with significant volumes of imported heavy and medium crudes still needed by complex refineries, exports are likely to rise from their current, near-record levels this spring and summer. Longer term, though, we expect export volumes to decline, setting up a battle for barrels among export terminals. Today, we continue our series on Gulf Coast crude export terminals with a look at the three facilities in the Beaumont/Nederland area.
On April 20, that fateful day in crude oil markets when the CME May contract for WTI at Cushing collapsed to negative $37.63/bbl, the number of contracts involved in the chaos was relatively small. So you might think that most producers sat on the sidelines, watching Wall Street paper traders writhe in stunning financial pain. But not so. Almost all producers saw their crude prices that day crashing in exactly the same magnitude. That’s because the daily price of the CME WTI contract is part of the formula pricing used in a very large portion of crude oil contracts in U.S. markets, both directly and indirectly. There are two formula mechanisms that are commonly used in crude oil sale/purchase contracts that are responsible for that linkage: the CMA and WTI P-Plus. These arcane pricing mechanisms are complicated, but in order to understand U.S. crude markets, it is critically important to appreciate how they work. Today, we continue our deep dive into crude oil contract pricing mechanisms.
The Bakken Shale is being hit especially hard by production cuts this spring. Crude oil-focused producers large and small have been shutting in wells and putting well completions on hold, slashing daily crude output by more than one-sixth. The rig count is down by half in less than two months — to 26, the play’s lowest level since mid-2016 — and thousands of oilfield workers have been let go. All this is happening despite the facts that the Bakken’s four-county core has some of the best shale assets outside the Permian and that in 2017-19 the play was super-hot, with crude production increasing by 50%. That three-year growth spurt spurred the development of a number of new crude gathering systems, many of which now face a period of significant underutilization. Today, we discuss highlights from our new Drill Down report on oil production and supporting infrastructure in the U.S.’s #2 shale play.
Well, it’s happened. The first signs of crude oil and gas production curtailments in the Permian Basin materialized over the weekend. That has followed weeks of extreme oversupply conditions, growing storage constraints and distressed pricing, all to deal with the abrupt and unprecedented loss of refinery demand for crude oil due to COVID, not just along the Gulf Coast, where the lion’s share of the U.S. refineries sit, but also more locally in West Texas. The rapidly shifting supply-demand balance, first from reduced local refining demand and now also the emerging production cuts, is adding volatility to the spreads and flows between the West Texas basin’s regional hub at Midland, and downstream hubs at Cushing and Houston. Today, we look at how the Midland market has responded to the downturn in local refining demand, and how production losses will factor into the balancing act.
With a dwindling market for their crude, many U.S. producers are confronting an unavoidable choice: shutting in existing production. Just go out and flip a switch and turn a valve, right? Wrong. Like everything else in the COVID era, shutting in production is complicated. It is the alternative of last resort for producers, whose primary directive is the economic extraction of oil and gas. But with demand for their products crushed, production from some wells no longer makes economic sense. Unfortunately, the process of shutting in wells is charged with contractual, economic and operational issues that the industry is scrambling to deal with. The situation is fraught with uncertainty, and many producers’ futures depend on how decisively they manage the shut-in process. Today, we discuss the urgent need to reduce oil production and the judgments producers will be making as they take wells offline.
The global economic shut-down caused by COVID continues to wreak havoc on U.S. markets. Last week, the dynamics that resulted in negative prices for NYMEX WTI thrust crude oil, and, more specifically, storage at Cushing, OK, into the national spotlight. The extraordinary imbalance in U.S. crude oil supply and demand has been pushing record volumes of oil into storage at the Cushing crude hub and tankage along the Gulf Coast. The same fundamental factors have also driven a surge in stocks of refined products like gasoline and diesel. Now the questions on everybody’s mind are, how long until storage tanks are completely full and what will that mean? Today, we’ll discuss recent trends and consider what record storage builds mean for the oil patch.
On Monday, front-month WTI at Cushing cratered to a negative $37.63/bbl. On Tuesday, the same futures price rose by nearly $48 to close at about $10/bbl — a positive $10, that is. As for WTI to be delivered in June, it lost well over a third of its value on Tuesday, ending up at less than $12/bbl, but over the past two days it has roared back to over $16/bbl. No doubt the WTI futures market will see more wild times in the days and weeks ahead as traders look to avoid the traps that ensnared the market as the May contract approached expiry. If there’s a lesson to be learned from the past week, it’s that it really helps to understand the ins and outs of the futures market — especially when it is so volatile. Perhaps the most important thing to wrap your head around is that while the futures market mostly involves financial players who will never take physical delivery of oil, the two markets — financial and physical — are fundamentally linked. Prompt-month futures converge on spot prices over time, while physical contracts are settled in part based on NYMEX futures, so producers will feel the sting of Monday’s negative prices when physical April deliveries are invoiced. Today, we begin a two-part blog series examining U.S. spot crude pricing mechanisms.
Underlying Monday’s financially driven oil price rout are physical markets that are in extreme turmoil as they contend with severely reduced demand resulting from the COVID lockdowns and rapidly filling storage tanks. In the Permian Basin, the epicenter of U.S. shale oil, the crude benchmark price — WTI at Midland — on Monday crashed to a historical low of negative $13.13/bbl before rebounding to a positive $13.01/bbl Tuesday. The same day, prices at the Permian natural gas benchmark Waha revisited negative territory for the third time this month, with a settle of minus $4.74/MMBtu for Tuesday’s gas day. Negative supply prices aren’t new to Permian producers, at least for gas — Waha settled as low as minus-$5.75/MMBtu in early April 2019. But up until a couple months ago, oil prices were supportive enough to keep producers drilling regardless. Now, that’s all over, at least for a while. What can we expect now that negative oil prices have arrived in the Permian? Today, we’ll dissect the latest bizarre pricing event to rattle the Permian natural gas and oil markets.
We have now entered the crude oil twilight zone. Never before has crude traded below zero, much less at the absurd level of negative $37.63/bbl. There is no doubt that demand for crude and motor gasoline are far below crude production volumes, leaving the market vastly oversupplied. But could it really be this bad? When you are talking about the market for physical barrels, the answer is “no”. It is bad. Really bad. But what happened yesterday had more to do with the mechanics of futures contracts and how they transition from month to month, than a complete mega-meltdown in physical barrels. That is not to say that negative prices for physical barrels are not already a fact of life in some locations. But negative $37.63/bbl? Something else must be going on. So, to put yesterday’s bizarre market action in perspective, we need to get into a few details on futures contract mechanics, and then look forward to what may be coming over the next few weeks. In today’s blog, we discuss the factors that are driving such extraordinary crude market developments.
In an energy market filled with incalculable uncertainty, it is no surprise that most of the focus is on the short term: production shut-ins, collapsing demand, refinery unit shutdowns, ballooning storage inventories and continually weakening prices. But even in the face of such dire circumstances in the weeks just ahead, there remains a cautious optimism — relatively speaking — for the resumption of some kind of new normal on the other side of COVID. You can see that expectation in the numbers, with the WTI May 2020 contract settling on Friday at $18.27/bbl, but the May 2021 contract up to $35.52/bbl. Granted, that May 2021 price would have been catastrophic if viewed in January 2020, but now it’s a bullish 95% increase over the front month. It is that shift in perspective that underlies the fundamentals content that we developed for our two-day Spring 2020 Virtual School of Energy, held last week in the cloud: how things were viewed BEFORE the meltdown, and how things look AFTER — over the next five years. Did you miss the conference? Not to worry. The entire 14 hours of content are available online in our encore edition. It’s almost like being there! Today’s advertorial blog reviews some of the most important findings we covered at School of Energy and summarizes our overall virtual conference curriculum.