Western Canada is blessed with extraordinary hydrocarbon resources and in recent years has been ramping up production in the Alberta oil sands and in the Duvernay and Montney shale plays. The U.S. is pretty much Canada’s only crude oil and natural gas customer, though, and there are limits to how much Canada can export to its southern neighbor — especially in the Shale Era, with the U.S. producing more oil and gas than ever and meeting an increasing share of its own needs. So Canadian producers, midstream companies and others have been working to gain access to new, overseas markets. It has not gone well. Pipeline projects to transport oil and gas to the British Columbia coast have been set back time and again, as have plans for crude and LNG export terminals. At last, there may be some good news. The Canadian government has stepped in to help push through a critically important oil pipeline to the coast, and BC’s leading LNG project just signed on a major new investor/customer. Today, we consider recent moves that could finally allow large volumes of Western Canadian oil and gas to be shipped to Asia.
On Friday, TransCanada finally secured a Presidential Permit for the U.S. portion of its Keystone XL pipeline, and the company committed to pursuing the state approvals it still needs to build the project. But three hard truths—crude oil prices below $50/bbl, the high cost of producing bitumen and moving it to market, and more attractive energy investments available elsewhere—have thrown a wet blanket on once-ambitious plans to significantly expand production in Western Canada’s oil sands, the primary source of the product that would flow through Keystone XL. Today we begin a series on stagnating production growth in the world’s premier crude bitumen area, the odds for and against a rebound any time soon, and the need (or lack thereof) for more pipelines.
It’s been a tough few years for Canadian oil producers. As they ramped up production in the oil sands, Canadian E&Ps faced pipeline takeaway constraints that drove down the price of Western Canadian Select versus Gulf Coast crudes. The Keystone XL pipeline would have largely solved things, but when that project was killed by Canada’s U.S. friends and neighbors, oil sands producers had to settle for a series of smaller, more incremental projects that provided only a partial fix. The devastating Alberta fires of May 2016 reduced production and pretty much eliminated constraints for much of this year. But volumes have recovered, and if oil sands production is to continue growing, more pipelines and new customers will be needed. Today we consider Canada’s long-running effort to ensure there’s enough capacity to move its crude to market, two major projects that just won the backing of the Canadian government, and what may be next.
The story of crude-by-rail (CBR) in North America is that of a victory of good old U.S. ingenuity over the lack of pipeline capacity that stranded booming shale oil production in 2012. The lower cost to market of “on-ramp” rail terminals allowed surging crude production a route to (mainly) coastal refineries - igniting a building boom over 4 short years that has left 82 load terminals and 44 destination terminals operating today - many of them now underutilized. Along the way monthly lease rates for rail tank cars that reached $2,750/month at the height of the boom are down to $325/month after the bust – with many lease holders paying daily rent to park their empty cars. Today we conclude our series reviewing the state of CBR today.
Our analysis shows that about 1.7 MMb/d of crude-by-rail (CBR) unload capacity has been built out and is operating in the Gulf Coast region today. According to Energy Information Administration (EIA) data for January 2016 an average of only 142 Mb/d was shipped into the region by rail in January 2016 down from a peak of just under 450 Mb/d in 2013 and an average of 235 Mb/d in 2015. In other words, the current unload capacity represents a whopping 12 times January 2016 shipments – a massive overbuild that is continuing today as new terminals are still planned. Today we look at the fate of Gulf Coast CBR terminal unload capacity.
According to our friends at Genscape at the end of March (week ending April 1, 2016) Bakken shippers could sell their crude at the railhead in North Dakota for $32.05/Bbl. Prices for Light Louisiana Sweet (LLS) crude at the Gulf Coast were about $5.40/Bbl higher than at the railhead but the rail freight to the Gulf was a few cents less than $12/Bbl. That means a Bakken producer would lose nearly $6.50/Bbl by shipping crude by rail to St. James, LA versus selling in North Dakota. Yet despite Crude-by-Rail (CBR) economics being so underwater - the volumes delivered to two St. James terminals averaged 66 Mb/d in 2016 through March. Today we continue our series on the fate of CBR with a look at inbound Gulf Coast CBR shipments.
Most Canadian oil sands crude production comes from very expensive mining or underground steam heating operations designed to produce consistently for decades that are costly to shutter in a downturn. Right now the crude netbacks (market price less transport costs) for these projects are more or less under water depending on transport routes. Yet production continues and new projects are still coming online. Today we estimate the netbacks (market price less transport cost) that Canadian producers are realizing.
Western Canadian Select (WCS) – the benchmark for Canadian crude sold at Hardisty in Alberta fetched just $32.29/Bbl on Friday (July 24, 2015) down 60% from $81.34/Bbl a year ago in July 2014. That year has seen big changes in the U.S. oil market with drilling rig cutbacks and declining new production rates. The challenges for Canadian producers have not changed much in the short term – with transport capacity to market still top of the list. Trouble is that every time transport congestion occurs it pushes price discounts higher and lowers producer returns. Today we discuss the relationship between Western Canadian crude production and prices.
Between them the TransCanada Grand Rapids, Enbridge Norlite and Devon/MEG Access pipelines currently being planned and built out will be able to deliver an extra 1 MMb/d of diluent to oil sands producers by 2017. That’s more than producers currently expect to need until 2030. The diluent will be shipped north from Edmonton terminals to production plants and blended with bitumen before making the return trip as dilbit or railbit destined for long-haul transport by pipe or rail to U.S. and Canadian markets. Today we describe the pipeline build out plans.
The Edmonton region in Alberta is home to a growing crude gathering hub that brings in bitumen crude from the oil sands region 250 miles to the north. In order to get that crude to Edmonton and to markets in the U.S., producers must first blend it with diluent range materials so that it can flow in pipelines. In the early days much of the diluent required in the oil sands was delivered by rail and truck but now a growing “parallel” pipeline network is developing to source and distribute supplies as new production comes online. Today we look at the Edmonton diluent distribution system.
Demand for diluent range light hydrocarbon materials such as natural gasoline and condensate that are used to reduce the viscosity of heavy Canadian bitumen crude so that it can flow in pipelines, is forecast to increase from 380 Mb/d in 2014 to 685 Mb/d by 2019. Increasing bitumen crude production in the Western Canadian oil sands region drives that demand. New large scale bitumen projects in Alberta requires two pipelines – one to ship crude production to market and one to ship in diluent for blending. Today we start a new series detailing the expanding western Canadian diluent distribution network.
Over the past two years the volume of crude oil shipped by rail from Canada has increased ten-fold. Data from the Canadian National Energy Board (NEB) for the whole of Canada indicates that average rail crude exports in the first quarter of 2012 were about 16 Mb/d. That volume grew to at least 160 Mb/d in the first quarter of 2014. The increase in rail exports of crude is primarily being driven by pipeline capacity constraints. Today we introduce findings from RBN Energy’s latest Drill Down Subscriber report.
Canadian producers trying to get their crude to market have come under pressure from two directions at once. US regulators have extended the deadline to make a decision on the Keystone pipeline that would relieve ongoing pipeline congestion out of Western Canada. Canadian regulators have increased pressure on crude by rail development plans, designed to bypass pipelines, by implementing new standards for rail tank cars. With no other apparent alternatives and despite some delays, rail terminal development plans in Canada are proceeding. Today we detail the progress of rail unloading terminals that can handle heavy Canadian crude at the US Gulf Coast.
With the Keystone Pipeline decision booted down the road again Friday, the challenge for Canadian oil sands producers trying to get their crude to market looms large once again. Growing volumes of Canadian crude will be carried by rail this year to bypass pipeline congestion. But although larger unit trains are beginning to operate from the oil sands region, they mostly help larger producers connected to the pipeline feeder network. Today we review continuing manifest rail shipments by small producers.
Growing Canadian production of oil sands bitumen requires diluent to blend it to pipeline flow specifications. The resulting demand for diluent exceeds local Canadian supply from plant condensate production (aka, natural gasoline) – leading to imports from the US of more than 150 Mb/d in 2013 – a figure expected to grow to 460 Mb/d by 2018. That expectation for future import growth is based on the assumption that Canadian condensate supplies would remain relatively flat at about 140 Mb/d. But could the developing Duvernay gas shale play in Western Alberta turn those estimates on their head? Today we investigate the consequences for US condensate demand.