World Energy GH2 has canceled plans for a 1.2-GW green hydrogen and ammonia complex in Canada’s Newfoundland and Labrador province, underscoring the widening gap between hydrogen ambition and commercial reality.
As demand for data centers accelerates, developers continue to search for locations that offer the best combination of several factors, starting with the availability of uninterrupted (and affordable) power. Those variables have led to a data-center buildout in several parts of the U.S., such as Northern Virginia, Texas and California’s Silicon Valley, but Canada has its own set of positives to lure developers. In today’s RBN blog, we look at the state of data-center development in Canada, how the factors that affect site selection differ from the U.S., and how Canada is working to become a bigger player in the global market.
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.
After a year’s delay due to permit issues, Enbridge now expects the expanded and reversed 300 Mb/d Line 9B pipeline to Montreal will come online next month (November 2015). The pipeline is an important cog in Enbridge’s Eastern Access and Light Oil Market Access expansion projects and will supply mostly light crude to two refineries in Quebec. As we explain today, the payload will travel a winding route to get to Montreal.
The latest estimates from North Dakota show production edging up in March 2015 after a two-month decline. But the heady days are over for the moment - in the wake of lower crude prices - as even optimistic forecasts project flattened growth. Meanwhile combined rail and pipeline crude takeaway capacity out of North Dakota are already far higher than production – but new projects like the TransCanada Upland pipeline continue to be pitched to shippers. Today we describe how that could result in producers switching from existing routes.
Enbridge is investing close to $9 billion between 2013 and 2016 in its Eastern and Light Oil Market Access initiatives. A major goal is to improve access for Enbridge shippers – particularly shippers of light shale crude from North Dakota, to refineries in the Midwest and eastern Canada. And by the end of 2014 refineries in Illinois, Michigan and Ohio as well as in Ontario will have better access to Enbridge crude. But even when the reversal of Line 9 in Ontario is completed and Enbridge crude can flow as far as Montreal, only about 300 Mb/d will be available for Quebec refineries to process. Today we continue our review of Enbridge eastern expansion plans.
In 2013, refineries in Eastern Canada imported 642 Mb/d of light crude. Today there are no pipelines connecting western Canadian crude supplies to the East Coast. By the end of 2014 the Enbridge Line 9 pipeline will link Canadian supplies from Alberta and Bakken supplies from North Dakota to refineries in Montreal. By 2018 the Energy East pipeline could be flowing 1.1 MMb/d to Canada’s Atlantic Coast and beyond. Today we begin a new series on eastern Canadian transport options by reviewing existing crude supply.
Alberta has a serious and still-growing problem with stranded natural gas. The volumes of gas piped east and south have been declining and the amount of gas stored in-province has risen to near-record levels, despite a widening discount to US Henry Hub spot gas prices making Alberta gas cheaper than ever. U.S. shale gas is largely to blame, but Alberta gas producers need more than a scapegoat, they need new markets—new ways to either use more of their gas closer to home or move it economically to the east and south or to buyers overseas. It won’t be easy. Today we look at potential new sources of demand.
