As Western Canadian natural gas production has been recovering off lows from a few years ago and pushing higher, one of the by-products of this recovery has been steadily rising production of natural gasoline, an NGL “purity product’ also known as plant condensate. Condensate production has been growing so much that Pembina Pipeline Corp. — a leading transporter of natural gasoline in the region — has been undertaking another round of expansions to its Peace Pipeline system to move more of the product to the Alberta oil sands. There, condensate is used as a diluent to allow the transportation of viscous bitumen to far-away markets via pipelines or rail. Today, we take a closer look at Pembina’s effort to expand the Peace Pipeline.
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.
Natural gas spot prices at Sumas, WA, on Friday went as high as $200/MMBtu, a record price not only for the Pacific Northwest spot gas market, but for the U.S. That level surpassed even the highest price seen in the premium Northeast market in the pre-Shale Era. Other Western prices also rose Friday but not to anywhere near Sumas, with intraday highs at the other hubs mostly staying below $10/MMBtu. This is just the latest instance of turmoil in the Pacific Northwest gas market since last fall, when a rupture on Enbridge’s Westcoast Energy/BC Pipeline system (on October 9) disrupted Canadian gas exports to Washington State at the Sumas border crossing point. Ongoing testing on the Westcoast system and the resulting capacity reductions for deliveries to Sumas, along with reduced deliverability at the region’s largest storage facility, Jackson Prairie, over the past month have made the Pacific Northwest more of a demand “island” than ever, especially as those issues coincide with this week’s polar-vortex weather. Sumas prices for today’s flows re-entered the stratosphere, averaging just under $16/MMBtu, but remained the highest price in the country. Today, we review the market conditions contributing to the sky-high prices.
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.
The recently mandated reduction in Alberta crude oil production has helped to ease takeaway constraints out of Western Canada, but only temporarily. Worse yet, it’s unclear how long it will take to add new takeaway capacity from challenged projects like the Trans Mountain Expansion Project or Keystone XL. In the midst of all this trouble and uncertainty, Enbridge is pursuing a potentially controversial plan to revamp how it allocates space — and charges for service — on its 2.8-MMb/d Mainline system, the primary conduit for heavy and light crudes from Western Canada to U.S. crude hubs and refineries. Today, we begin a series on the company’s push to shift to a system that would allocate most of the space on its multi-pipe Mainline system to shippers that sign long-term contracts.
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.
Natural gas markets in the U.S. Northwest have been in turmoil ever since a rupture on Enbridge’s BC Pipeline system over a month ago (on October 9) disrupted Canadian gas exports to Washington State at the Sumas border crossing point. Service on the affected line has been restored but at a reduced operating pressure for now, and Canadian gas deliveries to Sumas remain at about half of their pre-outage levels, creating supply shortages in the region. Spot natural gas prices at the Sumas, WA, trading hub have been volatile, soaring well above Henry Hub and rocketing to a record outright price of nearly $70/MMBtu late last week. The outage has reverberated across the Western U.S. gas market, sending regional prices reeling as gas flows adjusted to help offset supply shortages. Today, we examine the knock-on market effects of the outage on Western gas flows and prices, and potential implications for the winter gas market.
It’s been well-reported that crude oil pipeline capacity is getting maxed out in many basins across the U.S. and Canada. From Alberta, through the heart of the Bakken, all the way down to the Permian, pipeline projects are struggling to keep up with the rapid growth in some of North America’s largest oil-producing regions. Crude by rail (CBR) has frequently been the swing capacity provider when production in a basin overwhelms long-haul pipelines. While it is more expensive, more logistically challenging, and more time-intensive, CBR capacity is typically able to step in and provide a release valve for stranded volumes. But recently, CBR capacity has been tougher to come by and has taken longer than expected to ramp up. A key aspect of this issue is a new requirement for up-to-date rail cars. Today, we look at how new rail demands and uncertainty in domestic oil markets are combining to create a major hurdle for new CBR capacity.
Pipeline capacity constraints are nothing new to producers in the Bakken. Prior to the completion of the Dakota Access Pipeline (DAPL) in mid-2017, market participants had been pushing area pipeline takeaway to the max. When DAPL finally came online following a lengthy political and legal battle, producers and traders were able to breathe a sigh of relief. But with Bakken production steadily increasing over the past 18 months — and primed for future growth — new constraints are on the horizon. Over the next year or so, Bakken output could overwhelm takeaway capacity and push producers to find new market outlets. The questions now are, which midstream companies can add incremental capacity, how much crude-by-rail will be necessary, and is there a chance a major new pipeline gets built? Today, we forecast Bakken supply and demand, discuss some upcoming projects and lay out the possible headaches for Bakken producers heading into 2019.
The discount for Bakken crude prices at Clearbrook to WTI at Cushing has been on a rollercoaster in recent weeks, widening from $1.30/bbl at the beginning of September 2018 to over $10/bbl in mid-October and narrowing again most recently. There are several factors at play here. Canadian production has overwhelmed area pipelines and prices are being heavily discounted. These cheap Canadian barrels are creating oversupply issues at markets that Bakken barrels also trade into. On the demand side, Midwestern refiners are in the middle of seasonal turnarounds, reducing the demand for both Bakken and Canadian grades. Meanwhile, Bakken production growth continues to steadily chug along, increasing by over 150 Mb/d since the beginning of the year. And while this recent Bakken price angst is cause for concern, there is a looming bottleneck for pipeline space that could really shake things up sometime next year. Today, we examine the recent price phenomenon, the relationship between Canadian crude differentials and Bakken prices, and why producers should be concerned about future pipeline shortages.
The late-August decision by Canada’s Federal Court of Appeal to overturn the Canadian government’s approval of the Trans Mountain Expansion Project will delay the project’s completion to at least 2021 or 2022. And — who knows? — the unanimous ruling may ultimately lead to TMX’s undoing, despite the Canadian government’s acquisition of the existing Trans Mountain Pipeline and the expansion project and its commitment to get TMX built. As producers in the Western Canadian Sedimentary Basin (WCSB) know all too well, TMX’s 590 Mb/d of incremental pipeline capacity would help to resolve ever-worsening pipeline takeaway constraints out of the Alberta oil sands and other production areas in the WCSB. These constraints are having a major economic impact every day — as evidenced by price differentials wide enough to run a locomotive through. Speaking of trains, crude-by-rail exports out of Western Canada reached a record 205 Mb/d in June, an 86% increase from the same month last year, and with WCSB production rising as new oil sands capacity comes online and with only limited relief likely on the pipeline capacity front from the Enbridge Line 3 Replacement Project in late 2019, many producers will need to depend on rail shipments of crude well into the 2020s. Today, we discuss the recent court ruling and what it means for Western Canadian producers, price spreads and the future of crude-by-rail.
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.
Natural gas producers in Western Canada, with their share of U.S. and Eastern Canadian markets threatened by competition from producers in the Marcellus/Utica and other shale plays south of the international border, for years have seen prospective LNG exports to Asian markets as a panacea. But efforts to develop liquefaction “trains” and export terminals in British Columbia failed to advance earlier this decade — for starters, their economics weren’t nearly as favorable as those for U.S. projects like Sabine Pass LNG. Then, by 2016-17, global markets were awash in LNG as new Australian and U.S. liquefaction trains came online, and the BC LNG projects still alive were either delayed further or scrapped. Now, with LNG demand on the upswing and the need for additional LNG capacity in the early-to-mid 2020s apparent, the co-developers of LNG Canada — Shell, PetroChina, Korea Gas and Mitsubishi — have attracted a new and significant investor: Petronas, Malaysia’s state-owned oil and gas company and owner of Progress Energy Canada, which has vast gas reserves in Western Canada. Today, we continue our review of efforts to send natural gas and crude oil to Asian markets with a fresh look at the LNG project and TransCanada’s planned Coastal GasLink pipeline, which will deliver gas to it.