Enbridge’s proposal to have crude oil shippers on its now fully uncommitted Mainline sign long-term contracts for as much as 90% of the 2.9-MMb/d pipeline network’s capacity is a big deal — and controversial. Refiners and integrated producer/refiners generally 365手机登录网页 the plan, which is now up for consideration by the Canada Energy Regulator, while Western Canadian producers with no refining operations of their own — and, for many, no history of shipping on the Mainline — mostly oppose it. What’s driving their contrasting views? It’s complicated, of course, but what it really comes down to is that everyone wants to avoid what they see as a bad outcome. Refiners and “integrateds” fear that if the current month-to-month approach to pipeline space allocation remains in place, cost-of-365手机登录网页-based tariffs on Mainline will soar when new takeaway capacity is built on the Trans Mountain and Keystone systems and fewer barrels flow on Mainline. Producers, in turn, are wary of making multi-year, take-or-pay commitments to Enbridge if they’ll soon have other takeaway options, and are equally concerned that they’d be left in the lurch if they don’t commit to Mainline and the Trans Mountain Expansion and Keystone XL projects don’t get built. Today, we consider both sides of this important debate.
Daily energy Posts
The initial start-up of Cheniere Energy’s Midship Pipeline two weeks ago occurred in a radically different market environment than when the project was conceived. As the first greenfield, large-diameter natural gas pipeline project out of the SCOOP/STACK in years, it was meant to provide relief for the once takeaway-constrained producers in the Central Oklahoma production region and connect what was until the past year a rapidly growing supply region to emerging LNG export demand along the Gulf Coast, including at Cheniere’s own Corpus Christi, TX, terminal. Instead, SCOOP/STACK production hit the skids last fall, and rig counts since then have plunged to the lowest levels in well over a decade. On the delivery end of the pipe, U.S. LNG export demand is being challenged by a global gas glut and disappearing margins to international markets. Still, the Midship project’s initial capacity of 1.1 Bcf/d is more than 80% subscribed by firm shippers, and the new pipeline is slated to provide some of the most economic routes out of the SCOOP/STACK. Today, we provide an update on the project’s start-up and the changed market environment it’s facing.
365手机登录网页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.
Significantly reduced demand for crude oil by refineries is spurring production cuts in Alberta’s oil sands, and that could lead to a major decline in demand for Western Canadian natural gas. The oil sands are the single largest consumer of natural gas in Canada, accounting for more than half of the gas used in Alberta year-round and up to 37% of the gas used nationwide. With that kind of clout, anything that affects gas consumption in the oil sands is bound to have an outsized impact on the Alberta and overall Canadian natural gas markets. Today, we conclude our series on the effects of COVID-related disruptions on the Canadian natural gas market.
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.
The crude oil market garners all the headlines in the COVID/OPEC+ era, and understandably so. But the NGL market is also in turmoil and deserves attention too. Declining volumes of associated gas from crude-focused plays will soon be cutting into NGL supplies. Demand for natural gasoline has been hit hard, along with the crude, motor gasoline and jet fuel markets. But propane prices relative to crude oil have soared to historically high ratios, in part reflecting recent strong international demand for U.S. LPG exports. As for ethane — the lightest NGL, and the most important feedstock for the Gulf Coast petchem sector — it is going through wrenching changes, with major implications for both suppliers and steam crackers. Today, we begin a short series on the major dislocations that crude-market chaos is spurring in NGL production, ethane rejection, feedstock selection by steam crackers, and ethane/LPG exports.
365手机登录网页The market’s spotlight in recent days has been on negative prices for both Permian crude oil and natural gas, but in the shadows a powerful rally has taken place in the forward market for Permian gas at the Waha hub. Much of this month’s price weakness for gas in West Texas has been driven by pipeline maintenance. But the Waha forward curve indicates market expectations for higher prices in May, and the possibility of a summer in which Permian gas prices could be some of the strongest on a consistent basis since negative pricing first appeared in the basin back in 2018. Today, we dive into the drivers behind the rise in forward Permian gas prices.
COVID-related demand destruction and the oil price meltdown have engulfed energy markets and companies in a thick, pervasive shroud of doom and gloom. But investors and analysts have hit upon a potential bright spot for one segment of the industry: Gas-Weighted E&Ps that had been battered by the decade-long shift of upstream capital investment to crude-focused resource plays. The massive cutbacks in 2020 capital investment by oil producers triggered by the recent, dramatic decline in refinery demand for crude will reduce not only oil output, but associated gas production as well. That drop in supply raises the prospect of meaningful increases in natural gas prices in 2021 –– hence Wall Street’s new interest in Gas-Weighted producers, whose equity values have taken off in recent weeks after a big plunge earlier this year. There’s a lingering concern though, namely that LNG exports — a key driver of gas demand for U.S. producers — may be slowed by collapsing gas prices in key international markets. Today, we discuss what’s been going on.
365手机登录网页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 365手机登录网页 $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.
Sharply declining refinery demand for crude oil was a key driver in the historic collapse in near-term futures prices for WTI at Cushing earlier this week. With stay-at-365手机登录网页 directives in place in most of the industrialized world, U.S. — and global — demand for motor gasoline and jet fuel has plummeted to levels not seen in decades. These changes in refined-products demand, which may continue for months, already are having significant impacts on U.S. refineries — not just in how much crude oil they need but in operators’ decisions on whether to adjust their crude slates and ramp down or alter their operations. Their urgent challenge is to revise their yields to something close to the appropriate volumes of gasoline, diesel and jet fuel. Today, we begin a blog series on the U.S. refining sector and what refiners can — and can’t — do to adapt to these extraordinary times.
365手机登录网页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 365手机登录网页ive 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.
365手机登录网页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 365手机登录网页 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.
365手机登录网页Despite the pandemic-driven economic slowdown wreaking havoc on the global LNG market, U.S. LNG export volumes from operating terminals have proven resilient, so far. Total feedgas deliveries to the liquefaction and export facilities peaked at 9.44 Bcf/d less than a month ago and are averaging 365手机登录网页 8.3 Bcf/d in April to date. But for many of the already-struggling second wave of U.S. liquefaction projects still under development, the one-two punch of the crude oil price crash and COVID-related lockdowns has further stymied — or in some cases even reversed — their progress toward securing long-term capacity commitments and reaching final investment decisions anytime soon. Today, we provide an update on the status of the next round of prospective LNG export projects.
For most of the past three years, Western Canadian producers have had to deal with crude oil pipeline constraints — takeaway-capacity shortfalls serious enough to spur huge price discounts for the region’s benchmark Western Canadian Select (WCS) that are sufficient to 365手机登录网页 the higher cost of crude-by-rail alternatives. But things are changing, and fast. WCS prices are at or near historic lows — low enough to convince a number of producers to rein in their capital spending and production. Crude-by-rail use is down, and there’s even space available on the usually maxed-out Enbridge Mainline system, the region’s primary pipeline egress. And wouldn’t you know it, just as production is slipping and constraints are easing, real progress is being made on three big pipeline projects that had long been in limbo: the Line 3 Expansion, the Trans Mountain Expansion (TMX) and Keystone XL. Today, we provide an update on Western Canadian crude takeaway capacity and examine whether the region may — irony of ironies — end up with too much.