The rise in unconventional natural gas supplies in Western Canada has forced the region to again confront a dilemma that it faced in the 1990s and early 2000s: not enough export pipeline capacity to move all that gas to market. Although demand for natural gas has been growing in Alberta’s oil sands and power generation markets, it has not kept pace with provincial gas supply growth, leading to oversupply conditions and historically low gas prices. The need to export more of the gas to other parts of Canada and the U.S. is driving some pipeline expansions in the region. The question is, will they be enough? Today, we provide an update on the utilization of existing export routes, as well as the prospects (or lack thereof) for takeaway expansions, starting with Westcoast Energy Pipeline.
Growing natural gas supplies in Western Canada have been pressuring gas prices and export pipelines in the region, but there are signs that at least some of that supply-growth pressure is being offset by rising gas demand. Though the region is pegged as primarily a winter gas market — where local demand only rises when the temperature falls into the winter extremes — non-weather-related demand for natural gas has been growing in Western Canada and looks to have further upside in the years ahead. Today, we delve into Alberta and British Columbia’s gas demand trends and their potential to help balance the region’s oversupply conditions.
Once consigned to a flat or declining profile, natural gas production in Western Canada has been increasing steadily since 2012, to the extent that it has now begun to stretch the ability of the existing pipeline network to the breaking point. Most striking is that this expansion in production has been taking place in an era of declining natural gas prices and weakening basis for Western Canada’s primary natural price marker, AECO, and rising and relentless competition from U.S. gas supplies in several of Canada’s key domestic and export markets. If the pricing, pipe egress and export situation has become so dire, why are producers still drilling for and pumping out even more natural gas? Today, we address this question in the second part of our series investigating Western Canada’s natural gas supply and demand balance.
Offer any energy commodity at a low-enough price and buyers will surface, as long as there’s a way to get that liquid or gas from where it’s being sold to where it’s being used or put on a boat for export. That’s been the recent experience of the butane market in Western Canada, where a perfect storm of events last fall caused butane prices in Edmonton, AB, to freefall to near zero. But things have turned around, at least for now. Today, we take a look at the dramatic recovery of the Edmonton butane market and what might lie ahead.
For more than six months now, the provincial government of energy-rich Alberta has been trying to mitigate the sometimes painful effects of having too little pipeline capacity to move crude oil to market. They’ve mandated production cuts by larger producers, contracted for crude-by-rail (CBR) services — then moved to undo those deals — and pressed the Canadian government to help advance long-delayed pipeline projects. Things appear to have reached a semi-happy medium for now: the price spread between Western Canadian Select (WCS) and West Texas Intermediate (WTI) has narrowed, but remains wide enough to justify sending crude out by train. Still, it’s clear that the big tranches of new pipeline capacity many had hoped would be built or at least under construction by now face more hurdles. How long will Alberta producers need to wait for unfettered pipeline access to the U.S. Midwest and Gulf Coast and to Canada’s West Coast? Today, we provide an update on WCS pricing, Alberta crude-by-rail, and the key pipeline projects that never seem to get finished.
Keyera Corp. and SemCAMS Midstream, two major midstream players in Western Canada, in mid-May announced they are proceeding with the construction of their joint-venture project — a new NGL and condensate pipeline system out of the liquids-rich Montney and Duvernay plays of Alberta. The planned Key Access Pipeline System would provide the first direct competition for the transportation of NGLs and condensate out of these producing regions, currently dominated by Pembina Pipeline Co. Any and all transportation options for the movement of condensate and other NGLs out of the Montney and surrounding plays will likely be welcomed by Western Canadian natural gas producers, who are looking to capitalize on oil-sands producers’ growing demand for homegrown sources of condensate for use as diluent in bitumen transportation. Today, we provide key details about the project and how it fits into the region’s existing condensate/NGLs market.
The AltaGas/Royal Vopak Ridley Island Propane Export Terminal in the Port of Prince Rupert, BC, is poised to receive and load its first Very Large Gas Carrier (VLGC) any day now, a milestone that will make it Western Canada’s first LPG export facility and only the second such terminal in the greater Pacific Northwest region. With a capacity of 40 Mb/d, the facility is likely to provide a healthy boost to Western Canadian propane exports in 2019, easing oversupply conditions in the region while also providing producers with enhanced access to overseas markets, particularly in Asia. Today, we take a closer look at the new Prince Rupert facility and what it means for the Western Canadian propane market.
While it’s widely known that Canada’s natural gas prices and exports have been under increasing pressure from rising gas supplies in the U.S., forcing an ever-deeper discount for AECO — Canada’s primary gas price benchmark — versus U.S. benchmark gas prices, a homegrown development is making the situation worse. Growing unconventional gas supplies from the Montney and related plays in Western Canada are bumping up against insufficient pipeline takeaway capacity from this producing region. Will Canadian gas markets be able to adapt to all of these growing supplies on both sides of the border or simply wither away as U.S. supplies take more and more market share? Today, we kick off a multi-part series examining the highly complex problems facing Western Canadian gas producers.
What a deal! Take as much butane as you want — all for the low, low price of less than 10 cents/gallon (c/gal). That was the situation in Edmonton, AB, last November and the price stayed dirt cheap until a few days ago. Given a decline in demand for butane in crude blending, along with growing NGL production, the NGL processing and storage hub in Western Canada was awash in butane as winter approached. It remains flush with product today — and the price for Alberta butane is still low. How did this happen, and how will it play out over the next few months? Today, we examine the factors that led the Edmonton NGL market to see a price fall to near zero c/gal for the second time this decade.
Crude-by-rail (CBR) has been a saving grace for many Canadian oil producers. With extremely limited pipeline takeaway capacity, rail options from Western Canada to multiple markets in the U.S. have acted as a relief valve for prices — there for producers when they need it, in the background when they don’t. In 2018, we saw a major resurgence in CBR activity from our neighbors to the north, with volumes reaching an all-time high of 330 Mb/d just this past November. But just as quickly as CBR seemed ready for takeoff, the rug got pulled out from underneath those midstream rail providers and traders who had lined up deals and railcars to take advantage of wide price spreads. When Alberta’s provincial government announced its 325-Mb/d production curtailment beginning at the start of 2019, many midstream/marketing and integrated oil companies bemoaned what it could potentially do to market opportunities. And they were spot-on. Wide price differentials for Canadian crudes to WTI disappeared quickly and eliminated most, if not all, of the economic incentive to move crude via rail, and even by pipeline. In today’s blog, we recap the recent move away from crude-by-rail by some of Canada’s largest CBR players, and discuss the risks of long-term CBR commitments in volatile times.
Well, it finally happened. After several years of assessing the possible development of a large, integrated propane dehydrogenation (PDH) plant and polypropylene (PP) upgrader unit, a joint venture of Canada’s Pembina Pipeline and Kuwait’s Petrochemical Industries Co. (PIC) earlier this week announced a final investment decision (FID) for the multibillion-dollar project in Alberta’s Industrial Heartland. The new PDH/PP complex won’t come online until 2023, but when it does, it will provide yet another new outlet for Western Canadian propane, which has been selling at a significant discount in recent years. Today, we discuss Pembina and PIC’s long-awaited PDH/PP project, Inter Pipeline’s development of a similar project nearby, Western Canadian propane export plans — and what they all mean for propane prices.
For months, the crude oil market had Canada figured out. Production was growing, bit by bit. Pipelines were maxed out. Railcars were hard to come by but were providing some incremental takeaway capacity. Midwest refineries, a big destination for Canadian crude, went in and out of turnaround season, moving prices as they ramped up runs. Overall, the supply and demand math was straightforward also, tilted towards excess production. Canadian crude prices were going to continue to be heavily discounted for the next year or two, until one of the new pipeline systems being planned was approved and completed. Western Canadian Select (WCS) — a heavy crude blend and regional benchmark — was averaging at a discount to West Texas Intermediate (WTI) near $40/bbl in November, dragging down Syncrude prices with it. As the market was settling in for a long, cold winter in Canada, a bombshell dropped: Alberta’s premier announced on December 2 (2018) that regulators would institute a mandatory production cut, taking 325 Mb/d of production offline, and that the government would invest in new crude-by-rail tankcars. That announcement has had a massive impact on prices, with WCS’s differential narrowing to $18.50/bbl most recently. In today’s blog, we look at several catalysts for the recent swing in Canadian prices, and how the recent governmental intervention will impact differentials.
The price of northeastern Alberta’s key crude oil benchmark, Western Canadian Select (WCS), has been dropping like a rock. Last week, the heavy, sour blend of crude fell to a $45/bbl discount against U.S. benchmark West Texas Intermediate (WTI) — the biggest differential in at least 10 years. With an unplanned summertime outage at a Syncrude upgrader now over, Alberta production rising and pipeline takeaway capacity static — at least for now — the value of Canada’s crude may have even bleaker days ahead, despite a recent global rally in oil prices. Today, we explain why Western Canada’s oil producers are facing the prospect of mile-wide spreads for months to come.
Despite intensifying competition from U.S. natural gas producers — or because of it — Western Canadian gas producers are ramping up their long-term commitments for intra-basin takeaway capacity from the Montney Shale, as well as for capacity at both intra-provincial and export delivery points. Not only has there been a slew of new project announcements in the region, but in some cases, commitments reportedly have exceeded proposed capacity during open seasons. Today, we provide an update of gas pipeline expansion projects in Western Canada.
This spring, TransCanada launched service for its 230-MMcf/d Sundre Crossover expansion, increasing transportation capacity for moving Alberta natural gas production to the U.S. Pacific Northwest. That may seem like a trifling volume in the big scheme of the North American gas market. But considering that Canadian and U.S. producers already are locked in a heated battle for market share of U.S. demand and pipeline capacity, it’s enough for Canadian supply to gain ground. Since the Sundre in-service date, deliveries to the Kingsgate point at the British Columbia-Idaho border have ratcheted up to the highest levels in at least a decade. As a result, Canadian exports have managed to elbow out Rockies gas from the California market, and set off a ripple effect that’s pushing more gas east to the Midcontinent. Today, we examine the shifting gas flows in the West.