Crude Oil

Wednesday, 12/02/2020

There’s no question, the pressures on many U.S. midstream companies have been steadily increasing for some time now, and the past few months have really tested them. Like exploration and production companies, refiners, and others in the energy space, midstreamers have seen their well-considered plans for 2020 upended by demand destruction, commodity-price gyrations, and cutbacks in capex, drilling, and production. While it may be tempting to simply wait out the last few weeks of this crazy, unforgettable year and hope that 2021 will be better, there’s actually at least some good news out there for the midstream sector, and good reason to believe that midstreamers have been positioning themselves to financially weather whatever next year may have in store. Today, we discuss highlights from East Daley Capital’s newly issued 2021 Midstream Guidance Outlook, which focuses on key trends affecting midstream asset owners.

Tuesday, 12/01/2020

Fifteen years ago, just before the dawn of the Shale Era, more than 1.8 MMb/d of Gulf Coast and imported crude oil was being piped and barged north from PADD 3 to refineries in the Midwest. By 2019, those northbound flows had fallen by half, to less than 930 Mb/d, and in the first nine months of  this year they averaged only 550 Mb/d. Refineries in PADD 2, many now equipped with cokers and other hardware that enables them to break down heavy, sour crude into valuable refined products, have replaced those barrels — and more — with piped- and railed-in imports of favorably priced crude from Western Canada, including a lot of dilbit and railbit from Alberta’s oil sands. Today, we discuss the evolution of feedstock supply to the Midwest refinery sector.

Monday, 11/30/2020

It’s no surprise that the onset of the COVID-19 pandemic early this year shut down upstream mergers & acquisition (M&A) activity, just as it did America’s corporate offices, restaurants, entertainment venues, and schools. U.S. M&A deal flow slowed to a trickle in the first half of 2020 as companies’ valuations dropped along with bid prices and E&P executives struggled to realign expenditures with dwindling cash flows. But, as we’ve seen in the past, energy-commodity price crashes eventually spur a resurgence in M&A activity. The dam finally broke in late July, when Chevron announced a $13 billion takeover of Noble Energy, followed in short order by other, major corporate consolidations that brought the deal value total for the last five months to nearly $50 billion. This time was different in one important way, though: Instead of the strong preying on the weak, the strong merged with the strong in low-premium, all-stock transactions. Today, we analyze this new paradigm and delve into the details of the high-value deals.

Thursday, 11/26/2020

On October 25, a major consolidation of two Canadian oil and gas companies was announced with the planned merger of Cenovus Energy and Husky Energy. The prospective consolidation will offer the opportunity for corporate-level synergies and, over the longer term, for the physical integration of some of the companies’ operations, especially in Alberta’s oil sands. In today’s blog, we discuss some of the more nuanced elements of the consolidation, including potential improvement in crude oil market access and the larger presence of the combined company in PADD 2 refining, a sector that has taken a major hit during the pandemic. This blog also introduces a new weekly report from RBN and Baker & O’Brien: U.S. Refinery Billboard.

Thursday, 11/19/2020

For most of the past few years, crude oil producers in Alberta have dealt with pipeline constraints that often forced them to sell their crude at steep discounts. While the constraints eased somewhat earlier this year as producers reduced their output due to cratering oil demand and oil prices, production more recently has been rebounding, resulting in the return of takeaway concerns. The big hope is that long-planned pipeline projects like the Trans Mountain Expansion (TMX) and Keystone XL will finally be built and commissioned, but they still face legal and regulatory hurdles before being completed. Lately, a different option has gained momentum focusing on a proposed rail line linking Alaska to the immense oil sands region of northern Alberta, potentially creating another corridor for the export of oil sands crude. Today, we describe recent developments in a bold plan to build a rail line from Alberta, across northern Canada, and into Alaska.

Tuesday, 11/17/2020

Bombarded by COVID-related demand destruction and weak — sometimes dismal — crude oil pricing, producers have been pulling in their horns this year, and midstream companies have been doing the same. A number of major pipeline projects have been delayed, scrapped, or simply removed from midstreamers’ slide-deck presentations, having failed to garner the long-term shipper commitments they needed to remain viable in this era of retrenchment and fingers-crossed-we-survive. Even with the 2020 pullback in pipeline development, at least a couple of major production areas — the Permian and the Bakken — may well end up with considerably more takeaway capacity than they will need for the foreseeable future. Today, we discuss the oil pipeline projects that have stalled or died this year, and the ones that have managed to move forward despite it all.

Tuesday, 11/10/2020

On October 25, a major consolidation of two Canadian oil and gas companies was announced with the planned merger of Cenovus Energy and Husky Energy. The prospective consolidation will offer the opportunity for corporate-level synergies and, over the longer term, for the physical integration of some of the companies’ operations, especially in Alberta’s oil sands. In today’s blog, we discuss some of the more nuanced elements of the consolidation, including potential improvement in crude oil market access and the larger presence of the combined company in PADD 2 refining, a sector that has taken a major hit during the pandemic. This blog also introduces a new weekly report from RBN and Baker & O’Brien: U.S. Refinery Billboard.

Thursday, 11/05/2020

On December 1, the government of Alberta will officially end its nearly two-year-old policy of curtailing crude oil production to help shrink the massive price discounts that producers had been enduring. It would hardly be an overstatement to say that North American oil markets have changed dramatically since the production cap was implemented by Canada’s largest oil-producing province in January 2019. A short-but-bruising oil price war and a pandemic that slashed demand for crude resulted in Alberta producers making supply cuts even bigger than their government had mandated. Today, we look back at the provincial government’s policy and what has changed to motivate its suspension.

Wednesday, 11/04/2020

Ten years ago, East Coast refineries imported virtually all of the crude oil they needed — 60% from OPEC, 21% from Canada, and 19% from other non-OPEC countries. Only five years later, in 2015, the tables had turned. PADD 1 refinery demand for crude remained unchanged at 1.1 MMb/d, but only 14% of the oil refined there came from OPEC, 23% from Canada, and 21% from other non-OPEC countries — the other 42% was either railed in from the Bakken or shipped in from the Eagle Ford and Permian. But the changes didn’t end there. Imports rebounded sharply in 2016 and 2017, when new pipelines were built out of those basins that pulled barrels away from PADD 1 and into more competitive refining markets. In the fall of 2020, imports are falling back again but for a different reason — with COVID-19 demand destruction and other woes, East Coast refinery demand for oil is down by almost half, with more cuts on the way. Today, we continue a series on U.S. oil imports with a look at the East Coast.

Sunday, 11/01/2020

Condensates are quirky as heck — everyone’s got his or her own definition of what they are, for one thing — and their very quirkiness has sent condensates on a wild ride during the Shale Era. For example, the U.S. government for years categorized “conde” as a very light crude oil, and the long-standing ban on most crude exports meant you couldn’t export the stuff to anywhere but Canada. Unless, that is, you ran conde through a splitter to make NGLs, naphthas, and kerosene — those are petroleum products and they could (and still can) be exported, no questions asked. Then, as condensate production started soaring, especially in the Eagle Ford, the feds said that if you “processed” conde in special equipment to make it less volatile you could export it — no splitting required. That made the folks who invested in splitters shout in unison, “Huh?!” The roller-coaster for conde didn’t end there. The U.S. soon lifted the ban on all crude exports, and suddenly you didn’t need to process condensate at all to export it. More upheaval ensued. Today, we discuss this peculiar grouping of hydrocarbons.

Tuesday, 10/20/2020

Much has been written about the run-up in U.S. crude oil exports over the past five-plus years, and rightly so. Who would have guessed a dozen years ago that the U.S. would soon be producing as much as 13 MMb/d, and exporting one-quarter of it? Exports are only half of the story though. In fact, for every barrel of crude shipped or piped out of the U.S. today, two barrels of crude are shipped, piped, or railed in. Put simply, the U.S. refining sector still needs imported oil — or, more accurately, it can’t use all of the light, sweet crude that’s produced in the Permian and other shale/tight-oil plays in the Lower 48, and it still requires large volumes of the heavier crude that’s produced in Canada, Mexico, and overseas. Today, we begin a blog series on U.S. oil imports with a big-picture look at how crude sourcing for the refining sector has morphed in the Shale Era.

Thursday, 10/15/2020

Last week, Hurricane Delta became the latest of a string of hurricanes and tropical storms that have assaulted the Gulf Coast this year and disrupted energy production in the Gulf of Mexico — and energy exports. A number of major storms made direct hits or glancing blows to crude export centers like Corpus Christi, Houston, Beaumont, and Louisiana, forcing marine terminals to either slow down their carrier-loading operations or shut down for a few days at a time. That led to a yo-yoing of weekly export volumes: way down one week, way up the next. Despite the short-term dislocations, however, total export volumes since the hurricane season started on June 1 are actually up slightly from the first five months of 2020, a testament to the resilience not only of the export market but to the marine terminals themselves. Today, we discuss how hurricanes and tropical storms have been affecting export-terminal activity.

Tuesday, 10/13/2020

Six months on from the height of the crude oil price rout of April 2020 and the unprecedented market convulsions that followed, energy markets appear to be settling into a state of hyper-uncertainty amidst the ongoing pandemic. Crude oil prices have been downright equanimous, stabilizing near $40/bbl in recent months. Volatility has reigned in the gas market, but it has thus far managed to avoid a major collapse, and the NGLs market has dodged a complete derailment from norms, if barely. The relative calm provides the perfect opportunity to assess how COVID-era energy markets are operating and what lies ahead — which is what we’ll be doing next week at RBN’s Virtual School of Energy. There’s a new order taking shape, and we’re rolling out RBN’s freshly updated outlooks for U.S. crude oil, natural gas and NGL markets. As always, we’ll pull back the curtain on the fundamental analysis and models behind our forecasts, so you can understand how we arrived at our answers, and gain the skills and tools to adjust the assumptions as markets evolve. As you’ve gathered by now, today’s blog is an unabashed advertorial for our virtual conference, but read on if you’d like to hear more about the underlying premise behind our latest outlook.

Tuesday, 10/06/2020

Tough times in the crude oil sector generally affect all participants to some degree, but the impacts can vary widely by production basin. We saw that back in 2014-16, when the crash in oil prices battered the Eagle Ford, Bakken, and Niobrara but left the Permian unscathed — production there actually kept rising. Fast-forward to 2020, with its COVID-induced demand destruction, anemic prices, and uncertain-at-best recovery, and again the Bakken really took it on the chin. Production in the basin plummeted by 28% in one month — from April to May — and while Bakken output rebounded this summer, the rig count has been hovering at its lowest level in memory and another, albeit slower production decline may be imminent. Today, we discuss the challenges facing exploration and production companies in western North Dakota.

Monday, 09/21/2020

Western Canada’s relentless, decade-long increase in crude oil production began maxing out its export pipeline capacity in the past few years. With more supply than could be carried by pipelines, exporting crude by rail tank car became the next best alternative, leading to record amounts of rail-based exports earlier this year. However, this year’s wild swings in oil prices and COVID-led demand destruction resulted in drastic production cutbacks that freed up space on pipelines and put the kibosh on more expensive crude-by-rail, at least temporarily. Things are shifting again, though. With oil production recovering somewhat in the past couple of months and excess pipeline capacity dwindling, are we headed for a resurgence in the use of rail to export Canadian crude? Today, we conclude a series on Western Canada crude production and takeaway options with an analysis of what’s ahead for crude-by-rail.