Enbridge’s recent $200 million deal to buy two marine docks and land in Ingleside, TX, from Flint Hills Resources (FHR) may not be much of a surprise, as expanding its role in U.S. crude exports has been part of Enbridge’s strategy since it bought Moda Midstream’s big marine terminal next door nearly three years ago. The former Moda terminal, now known as the Enbridge Ingleside Energy Center (EIEC), can receive and partially load Very Large Crude Carriers (VLCCs) — a key reason why the facility is #1 in crude exports in the nation. In today’s RBN blog, we will take a closer look at Enbridge’s deal with FHR and how it might help grow its crude export volumes. 

The U.S. may be in a monthslong pause in approving new LNG exports but that doesn’t change the fact that U.S. LNG export capacity will nearly double over the next four years, that most of the new liquefaction plants are being built along the Texas coast, and that their primary source of natural gas will be the Permian Basin. That helps to explain why three big midstream players — WhiteWater/I Squared, MPLX and Enbridge — recently formed a joint venture (JV) to develop, build, own and operate gas pipeline and storage assets that link the Permian to existing and planned LNG export terminals. In today’s RBN blog, we examine the new JV and discuss the ongoing development of midstream networks for crude oil, natural gas and NGLs. 

After a roughly three-year wait for a critical state permit, Enbridge’s Great Lakes Tunnel and Pipe Replacement project for its Line 5 pipeline across the Straits of Mackinac in Michigan has taken a step forward. The Army Corps of Engineers’ permits for the tunnel project would seem to be the only major obstacle standing in the way of construction, but there may well be more challenges ahead. Like a few other oil and gas projects — namely, Mountain Valley Pipeline (MVP) and Dakota Access Pipeline (DAPL) — Line 5 has become entangled in controversy, including local opposition worried that a spill would irreparably damage their surroundings and spoil the state’s natural resources. In today’s RBN blog, we take a closer look at the Line 5 project, its next steps, and the opposition it continues to encounter. 

Wider price discounts for Western Canadian heavy crude oil have been weighing on its oil producers for the past few months. This appears to be the result of a combination of weak refinery demand, rapidly rising oil production and insufficient oil takeaway capacity from Western Canada. A more permanent solution for wider discounts might be to increase pipeline export capacity to ensure that rising oil production has more options to reach markets. In today’s RBN blog, we consider the pending startup of the Trans Mountain Expansion Project (TMX) as a means to do just that.

The price discount for Western Canada’s benchmark heavy crude oil has seen yet another widening in the past few months. Increased pipeline access to the U.S. was believed to be the key to solving this problem in the long term, but more recent fundamental developments surrounding pipeline egress, refinery demand and increasing heavy oil supplies demonstrate that larger discounts can — and do — still happen. This problem could persist for several more months until a better balance is achieved in downstream markets. In today’s RBN blog, we discuss the latest drivers of the wider price discounts for Western Canada’s heavy oil. 

Western Canada’s Trans Mountain Expansion Project, better-known as TMX, has experienced more than its share of setbacks over the past 10 years: environmental protests, legal challenges, financing issues, an ownership change, and even a serious flooding event in 2021. But it seems the 590-Mb/d expansion of the now-300-Mb/d Trans Mountain Pipeline (TMP) system will finally become a reality by early 2024, enabling large-scale exports of Alberta-sourced crude oil to Asian markets. There’s a catch, though. The project’s long delays and other issues resulted in massive cost overruns that are now being reflected in the preliminary tolls for the soon-to-be-combined Trans Mountain system. The proposed toll increase is so large that it will cost a similar amount to ship heavy crude oil to tidewater on Trans Mountain as it would on the competing Enbridge system to the U.S. Gulf Coast for “re-export,” despite the latter being three times the distance. In today’s blog, we discuss the history of the Trans Mountain expansion, its cost overruns and the calculations that went into the proposed tolls — the kicker being that those tolls could end up being even higher.

It took a while, but Enbridge and shippers on its 3.2-MMb/d Mainline system have finally reached an agreement in principle on a new tolling agreement that will lower per-barrel rates on the mammoth crude oil pipeline network between Western Canada and the U.S. Midwest — and also help ensure that Enbridge will earn a healthy rate of return on its largest asset. Assuming the Mainline Tolling Agreement (MTA) is approved by Canadian regulators later this year (and that’s seems to be a safe bet), the new rate structure should also help the Mainline system retain the vast majority of its crude volumes, even as it faces new competition from the Trans Mountain Expansion (TMX) project, which will provide 590 Mb/d of additional pipeline capacity from Edmonton, AB, to the British Columbia (BC) coast starting sometime next year. In today’s RBN blog, we discuss the MTA and what it means for Enbridge, shippers and TMX.

If you think, as we do, that (1) U.S. crude oil production is likely to increase by 1.5 to 2 MMb/d over the next five years, (2) almost all those barrels will be light-sweet crude that needs to be exported, and (3) exporters will overwhelmingly favor the marine terminals that can accommodate Very Large Crude Carriers (VLCCs), it would be hard to ignore the game-changing impacts that Enterprise Products Partners’ planned Sea Port Oil Terminal could have. SPOT, which could be completed as soon as 2026, will have robust pipeline connections from the Permian and other shale plays and be capable of fully loading a 2-MMbbl VLCC in one day, enough to handle virtually all the incremental exports we’re likely to see over the next five years. In today’s RBN blog, we discuss the fast-increasing role of VLCCs in U.S. crude oil exports and the potentially seismic impacts of the SPOT project.

In small steps and giant leaps, Enbridge has been building out two “supersystems” for transporting crude oil to refineries and the company’s own export terminals along Texas’s Gulf Coast, one moving heavy crude all the way from Alberta’s oil sands to the Houston area and the other shuttling light oil from the Permian to Enbridge’s massive terminal in Ingleside on the north side of Corpus Christi Bay. There’s nothing quite like it — first, an unbroken series of pipelines from Western Canada to Enbridge’s tank farm in Cushing, OK, (via the Midwest) and from there to Freeport, TX, on the twin Seaway pipelines; and second, the Gray Oak and Cactus II pipes from West Texas to the U.S.’s #1 crude export terminal. And the midstream giant is far from done. New projects and expansions are in the works, as we discuss in today’s RBN blog.

There finally seems to be some momentum building for additional LNG export projects on Canada’s West Coast. Major pipeline and midstream operator Enbridge announced in late July that it was making an investment in Woodfibre LNG, a smaller-scale export project that has already come a long way in terms of approvals, pipeline connections, locking up gas supplies, and initial financing. With the Enbridge announcement — and the financial and technical clout the company brings to the table — it is now looking assured that the project will commence construction next year and be exporting LNG by 2027. In today’s blog, we take a detailed look at Woodfibre LNG.

In case you hadn’t noticed, many of the largest, most successful companies in the U.S. and Canada are placing big bets on the energy transition. Take “blue” hydrogen, which is produced by breaking down natural gas into hydrogen and carbon dioxide and capturing and sequestering most of the CO2, and blue ammonia, which is made from blue hydrogen and nitrogen. Last fall, Air Products & Chemicals announced a multibillion-dollar project in Louisiana, and now it’s a joint venture of Enbridge and Humble Midstream, which is planning a large, $2.5 billion-plus blue hydrogen/ammonia project down the Texas coast, at Enbridge’s massive marine terminal in Ingleside. In today’s RBN blog, we discuss what we’ve learned about the companies’ plan.

You would expect the start-up of Enbridge’s Line 3 Replacement project early this fall to have eased the constraints on crude oil pipelines from Western Canada to the U.S. — and it did. You’d also expect that L3R coming online would narrow the price spread between Western Canadian Select and West Texas intermediate — but it didn’t. The latest widening of the WCS-WTI spread, one of many in recent years, is another reminder that oil price differentials can be affected by many factors other than pipeline capacity availability. In today’s RBN blog, we discuss the host of issues that affect this all-important Canadian oil price metric.

Late last month, the Canada Energy Regulator (CER) ruled against Enbridge’s proposal to convert as much as 90% of the capacity on its multi-pipeline, 3-MMb/d Mainline crude oil system to long-term contracts. The CER’s action leaves in place the Mainline’s current capacity-allocation process, under which every barrel-per-day of the pipeline system’s capacity is open to all shipping customers on a month-to-month basis. Although the rejection of Enbridge’s proposal is unlikely to change the volume of Western Canadian crude oil flowing on the Mainline over the next few months, the longer-term outlook for Mainline flows is less certain given that other, competing pipeline capacity out of Alberta will be coming into service by late 2022 or early 2023. In today’s RBN blog, we examine the decision to reject long-term contracting and what might be the next steps for Enbridge.

Crude oil production in Western Canada has been rising steadily for most of the past decade. Unfortunately, the same cannot be said for its oil pipeline export capacity to the U.S., which has generally failed to keep pace with the increases in production. Dogged by regulatory, legal, and environmental roadblocks, permitting and constructing additional pipeline takeaway capacity has been a slow and complicated affair, although progress continues to be made. The most recent tranche arrived last month with the start-up of Enbridge’s Line 3 Replacement pipeline, which provides an incremental 370 Mb/d of export capacity and should help to shrink the massive price discounts that have often plagued Western Canadian producers in recent years. In today’s RBN blog, we discuss the long-delayed project and how its operation is likely to affect Western Canada’s crude oil market, now and in the future.

In the three years since Moda Midstream acquired Occidental Petroleum’s marine terminal in Ingleside, TX, the company has developed millions of barrels of additional storage capacity, connected the facility to a slew of Permian-to-Corpus Christi pipelines, and increased the terminal’s ability to quickly and efficiently load crude onto the super-size Suezmaxes and VLCCs that many international shippers favor. Moda’s fast-paced efforts have paid off big-time, first by making its Ingleside facility by far the #1 exporter of U.S. crude oil and now with a $3 billion agreement to sell the terminal and related pipeline and storage assets to Enbridge. The transaction, which is scheduled to close by the end of this year, will make Enbridge — already the co-owner of the Seaway Freeport and Seaway Texas City terminals up the coast — the top dog in Gulf Coast crude exports. Today, we discuss the Moda agreement and how it advances Enbridge’s broader Gulf Coast export strategy.