Increasing global LNG supplies has become of paramount importance given Europe’s decision to move away from pipelined imports of Russian natural gas. As such, any and all LNG export projects — from the expansion of existing sites to proposals for greenfield terminals — are getting a fresh look. As always, though, only the projects that make the most economic sense are likely to advance to a final investment decision (FID), construction and operation. Which raises the question, where do things stand with the handful of LNG export terminals proposed for Eastern Canada, which offers the shortest, most direct access to Europe? In today’s RBN blog, we conclude our series on Canada’s LNG export potential by assessing several greenfield export sites on its East Coast.
Posts from Martin King
The European natural gas market has been in crisis this winter, with prices skyrocketing north of $100/MMBtu recently. Tight supplies, low storage levels, and a new gas-supply-security issue sparked by the war in Ukraine has many European nations, especially Germany, embarking on a crash course to increase supplies and diversify away from Russian gas imports. In this quest, increasing gas supplies in both the short- and long-term is a top priority and will require substantially more LNG capacity to replace — and eliminate the need for — Russian gas. With Europe’s gas-supply urgency on the rise, long-dormant prospects for exporting LNG from Canada’s East Coast are being re-examined. In today’s RBN blog, we look at the potential for repurposing the region’s only LNG import terminal into one that is geared toward exports.
Global LNG markets have been in overdrive this winter — it seems the world just can’t get enough of the super-cooled natural gas. Moreover, with long-term LNG demand growth in Asia appearing robust well into the next decade, the time would seem ripe to reconsider expanded export opportunities from Canada’s West Coast, one of the closest and potentially largest sources of LNG for Asian buyers. With one major LNG export project already under construction, at least one more awaiting the final go-ahead, and two more serious proposals having emerged last year, Canada’s outlook for additional LNG sales to Asia is clearly bright. In today’s RBN blog, we discuss recent developments regarding Canadian LNG projects.
It seems that, once again, Canada is struggling to build crude oil pipeline export capacity fast enough to keep pace with production growth. The latest setback came with the announcement that completion of the Canadian government-owned Trans Mountain Expansion (TMX) will be delayed until the third quarter of 2023 and that the 590-Mb/d project will cost almost twice as much as previously estimated. The latest six-to-nine-month delay appears to set the Canadian oil industry on a path to exhausting its spare export capacity by later this year. And that’s not good news for producers. In today’s RBN blog, we consider this latest TMX announcement and what it might mean for pipeline constraints and heavy oil price differentials.
The gradual increase in Western Canada’s natural gas production in recent years has been powered by the highly prolific Montney formation, a vast unconventional resource that straddles the Alberta/British Columbia border. With Western Canadian gas price benchmarks at multi-year highs and producers enjoying their best financial position in ages, it would seem logical to expect more gas production growth from the Montney in the future. However, a recent ruling by the BC Supreme Court could negatively affect the pace of well developments and jeopardize future growth in the Montney formation. In today’s RBN blog, we consider this possibility.
Oil sands, the workhorse of Alberta’s — and Canada’s — crude oil production growth, achieved a record production year in 2021. A steady turnaround in crude oil prices, improved market access, and the tried-and-true resilience of oil sands producers combined to drive the increase in output. With 2022 barely out of the starting blocks, the oil sands players have provided production guidance for this year that, if fulfilled, could set the oil sands on track for another year of record output. In today’s RBN blog, we consider the latest production guidance estimates and what these could mean for the availability of oil pipeline export capacity from Western Canada.
Alberta, Canada’s energy powerhouse, accounts for the vast majority of the nation’s crude oil, natural gas, and NGL production. There is a lot of hydrogen locked up in all of those hydrocarbons and Alberta’s provincial government recently laid out a seven-part plan to expand the production and use of “blue” hydrogen — produced from natural gas via steam methane reforming with carbon capture and sequestration — as part of a broader effort to bolster its existing natural gas sector and energy transition cred. In today’s RBN blog, we explore Alberta’s proposed hydrogen strategy.
With Alberta’s bitumen production rising to record levels of late, finding more ways to export this molasses-like heavy oil has become more important than ever. In early 2020, Gibson Energy and US Development Group embarked on the construction of a diluent recovery unit in Hardisty, AB, to greatly reduce the need for diluent and retain more of it for reuse. With the unit’s commercial start-up at the end of 2021, another unique pathway for transporting Canadian bitumen to the U.S. Gulf Coast — and, possibly, overseas markets — has become a reality. In today’s RBN blog, we provide an update on this venture and discuss where it might lead next.
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.
Trans Mountain Pipeline, the only pipeline that connects crude oil production areas in Alberta to Canada’s West Coast and the U.S. Pacific Northwest, has started to resume operations after a three-week shutdown. The pipeline closure — the longest in TMP’s 68-year history — began November 14 after major flooding exposed portions of the 300-Mb/d conduit, which also carries some refined products. Fortunately, Trans Mountain did not suffer any severe damage, breaks, or spills, and its operators were able to initiate a phased restart on December 5 at reduced pressures. Full service is expected to be restored soon. So what happens when a primary source of crude oil to five refineries — four in Washington state and one in British Columbia — is removed from service with little notice? In today’s RBN blog, we discuss the impacts.
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.
As the new heating season in North America gets under way, the natural gas sector in Canada, the U.S., and even globally, is experiencing a surge in gas prices to levels unseen in many years. In Canada and the U.S., you would have to go way back to 2008-09 to find the most recent instance of $5/MMBtu-plus gas heading into a heating season. As for the rest of the world, it has never experienced prices at the levels reported in the past few months — north of $30/MMBtu in some places. The big question, as always, is: where do we go from here? In today’s RBN blog, we review our 2021 pricing outlook for Canadian gas and discuss our forecast for 2022.
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.
It wasn’t that long ago that Western Canada was awash in propane, sending the vast surplus for export by railcar to the U.S. That has changed in the past two years as direct exports to Asia opened up and Canada’s domestic demand for propane rose. With supplies becoming tighter, the combined effect with increasing demand spells trouble for higher exports to the U.S. this winter, a time when they are desperately needed. In today’s RBN blog, we explore the current Western Canadian propane market and what might be next in store.
With natural gas prices reaching levels not seen in seven years, Western Canada is doing all it can to help increase gas supply, with recent data showing monthly production hitting multi-year highs. Moreover, Canadian forward gas prices are at the highest levels since 2014, gas pipeline expansions are in place or being constructed to accommodate future supply expansion, and gas-focused drilling activity remains strong — all of which may as well be a prescription for sending gas production to record levels later this year and in 2022. In today’s RBN blog, we provide an update on the recent gas production growth in Alberta and neighboring provinces and why more growth is coming.
