crude slates

The looming threat of a 10% tariff on U.S. imports of Canadian crude oil hasn’t just angered Canadians — and understandably so, we might add. It’s also put a spotlight on PADD 2 — the Midwest/Great Plains region — whose pipelines transport the vast majority of Canadian exports and whose 25 refineries (combined capacity 4.3 MMb/d) are, in many cases, significant consumers of heavy and light crudes from up north. Put simply, to assess the impacts of the still-possible trade war on U.S. refiners and producers on both sides of the border, you need to understand PADD 2’s crude oil supply/demand balance and the options Midwestern refineries that currently run Canadian crude would have if a tariff were put in place. In today’s RBN blog, we’ll discuss these dynamics. 

Mexico’s state-owned Petróleos Mexicanos, the second-largest exporter of crude oil to the U.S. after Canada, said in late December that it will slash its export volumes in 2022 and eliminate them completely in 2023. The plan is premised on Pemex’s expectation that, with increased utilization of the company’s six existing refineries and the impending start-up of a new one, it will need every barrel of the Maya, Isthmus, Olmeca, and other varieties of oil it produces. While at first glance it may seem that Mexico phasing out exports of crude would pose a major challenge to some U.S. refineries, there’s good reason to believe that in reality it won’t. In fact, as we discuss in today’s RBN blog, there may be less to Pemex’s planned export phase-out than meets the eye.

For some time now, a handful of refineries in southeastern Louisiana, Mississippi, and Alabama have been able to receive steeply discounted, heavy sour crude from Western Canada by rail or barge — or, in rare cases, by pipeline from Cushing to Nederland, TX, to the St. James, LA, hub. Starting in a few months, though, this same crude also will be able to flow by pipe directly from Patoka, IL, to St. James on the soon-to-be-reversed Capline pipeline. Initially, the southbound volumes on Capline will be modest, but over time they could increase to several hundred thousand barrels a day. Will those barrels be loaded onto supertankers and shipped overseas, or will they be headed for refineries in Louisiana and its eastern neighbors? In today’s blog, we try to answer those questions.

The U.S. and Canada make quite a team. Friends for most of the past century and a half — and best buddies since World War II — the two countries have highly integrated economies, especially on the energy front. Large volumes of crude oil, natural gas, NGLs, and refined products flow across the U.S.-Canadian border, and a long list of producers, midstreamers, and refiners are active in both nations. One more thing: since the mid-2000s, the development of U.S. shale and the Canadian oil sands in particular has enabled refiners in both countries to significantly reduce their dependence on overseas oil — a big victory for North American energy independence. However, due to its smaller population and economy, Canada typically gets far less attention than its southern neighbor, so in today’s blog we try to right that wrong by discussing highlights from a new, freshly updated Drill Down Report on Canada’s refining sector.

Many countries like to talk about energy independence, but Canada is one of the few to come close to that elusive goal. For many years, Western Canada has produced more than enough crude oil to satisfy the demand of refineries in the region. More recently, a combination of rising Western Canadian oil production, and new and reworked pipelines, has enabled many of Canada’s eastern refineries to increase their intake of Western Canadian barrels. In the few remaining cases where they can’t, imported barrels from the U.S. have filled the gap, leaving crude imports from overseas accounting for just 1% of the market. Not surprisingly, Canada is also a net exporter of refined products, with refiners in Western Canada, and especially Atlantic Canada, producing far more than the country’s demand. Today, we conclude our series on Canada’s refining sector with a look at its growing reliance on Western Canadian crude oil and its ability to meet most of Canada’s need for gasoline and distillates.

In the spring of 2020, as the COVID-19 crisis started hitting the energy sector hard, many refiners made the tough decision to dramatically cut back capital spending plans and operating costs for the year in order to weather the storm. While these cuts were swift and sizeable, they were not absolute — they couldn’t be, given that refining is a capital-intensive industry with complex assets that require seemingly constant maintenance, equipment swap-outs, and upgrades. And then there’s the added pressure that refiners also need to invest in keeping their facilities in compliance with changing environmental rules, and to consider the overall impact of investments in new, “greener” fuels, such as renewable diesel, that may help them improve their profitability going forward. Today, we look at refiner capital spending in the context of recent history and highlights some of the growth projects being pursued in the sector.

PADDs 4 and 5 — the Rockies and the West Coast regions, respectively — are each outliers in the U.S. refining sector. Refineries in the Rockies, for example, are generally far smaller than those in other PADDs and, due to pipeline flows, source their crude oil from either Western Canada, the Bakken, or in-region production, including the Niobrara and Utah’s Uinta Basin. West Coast refineries, in turn, have no crude oil pipeline links with U.S. points to the east, and depend on a mix of imported crude from Canada, Latin America, and the Middle East, as well as domestic oil from California, Alaska, and rail receipts. Today, we conclude a series on region-by-region crude oil imports and refinery crude slates with a look at PADDs 4 and 5.

Back in 2005, marine terminals along the Gulf Coast were importing more than 6 MMb/d of crude oil, mostly to feed refineries within PADD 3 but also to pipe or barge north to PADD 2. By 2019, with U.S. shale production finishing up a decade-long rise, imports to the Gulf Coast had declined to less than 1.7 MMb/d. In COVID-impacted 2020, imports sagged, soared, then sagged again, recently settling in at about 1.2 MMb/d, their lowest level in — wait for it — 35 years! The 80% decline in Gulf Coast oil imports since the mid-2000s was made possible in part by big changes in the crude slates at refineries in Texas, Louisiana, and other PADD 3 states, mostly involving the swapping out of light sweet crude from overseas with favorably priced light sweet crude from the Permian and other U.S. shale plays. Today, we look at imports into PADD 3, the home of more than half of the U.S.’s total refining capacity.

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.

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.