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.
Western Canadian Select (WCS), a heavy crude oil blend, has been selling for about $25/bbl less than West Texas Intermediate (WTI) at the Cushing, OK, hub — a hard-to-bear experience for oil sands producers that have made big investments over the past few years to ratchet up their output. And the WCS/WTI spread is unlikely to improve much any time soon. Pipeline takeaway capacity out of Alberta has not kept pace with oil sands production growth, and existing pipes are running so full that some owners have been forced to apportion access to them. Crude-by-rail (CBR) is a relief valve, but it can be costly. Worse yet, production continues to increase and the addition of new pipeline capacity is two years away — maybe more — so deep discounts for WCS are likely to stick around. Today, we discuss highlights from our new Drill Down Report on Western Canadian crude markets.
The combination of rising Western Canadian crude oil production, little-to-no available pipeline takeaway capacity and setbacks for pipeline projects appear to be breathing new life into crude-by-rail (CBR) activity. CBR played an important supporting role earlier this decade, helping address incremental takeaway needs until new pipelines came online. And there would seem to be plenty of CBR capacity at hand this time around — the region saw some serious over-building of crude-loading terminals in 2014-15. But there may be challenges in getting some of that CBR capacity back online quickly. Today, we continue our series on Western Canadian crude, this time focusing on the crude-by-rail factor.
Three major crude oil pipeline projects now under development would add nearly 1.8 MMb/d of much-needed takeaway capacity out of the Western Canadian Sedimentary Basin (WCSB), a region hit hard by pipeline constraints and widening price differentials. But each of the three projects — Kinder Morgan’s Trans Mountain Expansion (TMX), Enbridge’s Line 3 Replacement Project and TransCanada’s Keystone XL — continues to face regulatory challenges and it remains unclear how many of the projects will advance to construction and how soon the first of them might come online. It’s also possible that one or more may go the way of Northern Gateway and Energy East, two major pipeline projects that went belly-up after years of planning. Today, we continue our blog series on Western Canadian crude oil with a look at Keystone XL and its prospects.
With Western Canadian crude oil production rising, available pipeline takeaway capacity shrinking and crude-by-rail volumes rebounding, midstream companies are ramping up their efforts to get long-planned pipeline projects built. But that’s no easy task. Virtually every plan to add new takeaway capacity out of Alberta — Canada’s #1 energy-producing province — continues to face regulatory hurdles, and it remains to be seen which of the pipeline projects will be completed, and when. We can’t just throw up our hands, though, and say, “Who knows?” With pipeline constraints out of Western Canada worsening by the month and having profound negative effects on the price of Western Canadian Select (WCS), there’s real value in reviewing in some detail what these pipeline projects are up against. Today, we discuss what’s being planned on the takeaway front and where these projects stand.
Producers in the Western Canadian Sedimentary Basin (WCSB) are in a bind. Crude oil output in the WCSB has risen by more than 50% over the past seven years to about 4 MMb/d and is expected to increase to 5 MMb/d by the mid-2020s. But there has been only a modest expansion of refinery capacity within the region and pipeline capacity out of the WCSB, and lately takeaway constraints have had a devastating effect on the price relationship between benchmark Western Canadian Select (WCS) and West Texas Intermediate (WTI). What’s ahead for WCSB producers and WCS prices? Today, we continue our series on Western Canadian crude and bitumen markets, this time focusing on WCSB refinery capacity and existing pipelines out of the region.
Canadian natural gas production has rebounded to the highest level in 10 years. At the same time, Canadian producers are facing tremendous headwinds. On the upside, regional gas demand from the Alberta oil sands is increasing too. But competition for market share in the U.S. — which currently takes about one-third of Canadian gas production — is ever-intensifying as U.S. shale gas production is itself at record highs and expected to continue growing. On the whole, net gas flows to the U.S. from Canada thus far have remained relatively steady in recent years, apart from fluctuations due to weather-driven demand. But the breakdown of those flows by U.S. region has shifted dramatically and will continue to evolve as Appalachia takeaway capacity additions allow Marcellus/Utica shale gas production to further expand market share in the Northeast and other U.S. regions. Today, we begin a series looking at what’s happening with gas flows across the U.S.-Canadian border and factors that will influence Canada’s share of the U.S. gas market over the next several years.
The Alberta natural gas market in Western Canada is in the midst of a seismic shift. Regional gas supply growth is accelerating. At the same time, export demand is eroding, but domestic demand — particularly from gas-fired power generation and oil-sands development — is on the rise. The incremental production along with the move toward intra-provincial demand has reconfigured flows and strained TransCanada’s infrastructure in the region. These factors resulted in extreme price volatility this past fall, a dynamic that’s likely to resurface in the New Year during low-demand times. Today, we continue our analysis of the Western Canadian gas market with a look at the changing transportation and flow dynamics in Alberta.
Western Canadian natural gas producers are increasingly facing oversupply conditions and price volatility. While competition and pushback from growing U.S. shale gas supply continues to be a factor, producers are now also contending with fresh problems closer to home — namely transportation constraints right where production is growing the most, in central Alberta. This fall, the Alberta market experienced extreme bottlenecks that left production stranded and sent area gas prices reeling. The ramp-up of winter heating demand has since helped ease the constraints, but the problems are likely to return in the spring when demand is lower, leaving producers exposed to the risk of severe price weakness again in 2018 and limited in their ability to grow supply. Today, we continue our look at what’s behind the local constraints and the implications for production growth and prices in Western Canada.
Western Canadian natural gas producers have long battled unrelenting competition from growing shale gas supply in the U.S. But recent price action at AECO — Canada’s benchmark natural gas hub in Alberta — suggests market conditions there have gone from bad to worse. AECO prices in recent months have fallen to the lowest levels in more than a decade, even dropping below zero at one point in intraday trading this fall. Fundamentals are increasingly bearish, given that Canadian gas production has rebounded to the highest level in close to 10 years, storage there is near to five-year highs and exports are facing further cutbacks as U.S. gas supply is itself at record highs. In addition, producers are contending with a number of transportation issues closer to home. Today, we begin a look at the factors affecting the Western Canadian gas market.