Western Canada Gets Its First Propane Export Terminal

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.

 

a joint venture of Canada’s Pembina Pipeline and Kuwait’s Petrochemical Industries Co. (PIC) announced a final investment decision (FID) for a multibillion-dollar, integrated propane dehydrogenation (PDH) plant and polypropylene (PP) upgrader unit in Alberta’s Industrial Heartland. The new PDH/PP complex won’t come online until 2023, but the FID signaled that another much-needed outlet for Western Canadian propane is on the way — good news for producers who have been selling the product at a significant discount in recent years.

Propane is one of the five “purity” natural gas liquids (NGLs) produced from natural gas processing plants; smaller volumes of propane are produced as a by-product of crude oil refineries and bitumen upgrader plants. Over the past decade or so, much of the natural gas production growth in Western Canada has come from the liquids-rich Montney production area along the Alberta/British Columbia border, resulting in increasing volumes of propane (and other NGLs;

For one thing, rising production of propane in the U.S. has nibbled away at a primary market for Western Canadian propane — namely, customers south of the 49th Parallel (the U.S.-Canada border out west). For another, pipeline takeaway capacity for exports has been shrinking. It used to be that the bulk of propane exports out of Alberta and British Columbia (BC) were transported via pipeline and rail, with a smaller chunk also being trucked out, all to the U.S. Some years ago, there were more options for piping NGLs out of Alberta, most of them utilizing “batching” (transporting different NGLs at different times

The one exception was Kinder Morgan’s Cochin Pipeline, the only propane-exclusive conduit, which for many years had transported as much as 60 Mb/d of propane from Edmonton, AB, to Windsor, ON, via the U.S. Midwest. However, pipeline capacity for exports has been reduced over the past decade. Most recently, in March 2014, Cochin was reversed to move condensate — used as a diluent to blend with bitumen produced in the Alberta oil sands — from Kankakee, IL, to Edmonton. With Cochin no longer a propane-takeaway option, pipeline exports have been limited to: the Enbridge Mainline system, which can batch-flow propane (and other NGLs) from Edmonton to Enbridge’s Superior Terminal in Superior, WI, and from there on to Sarnia, ON; and Pembina Pipeline’s Alliance Pipeline, which ships natural gas mixed with NGLs from Western Canada’s gas production region to Chicago, IL. Any incremental volume beyond that has needed to move out of Alberta by rail — a higher-cost alternative to pipelines that has its own logistical challenges and is also increasingly at or near capacity. And what is railed is increasingly being challenged by those growing U.S. supplies we mentioned above.

With propane prices at Alberta’s Edmonton NGL hub under pressure (and briefly sinking into negative territory in the summer of 2015, after the Cochin reversal), a flurry of projects were floated to address Alberta’s glut and find new markets. The possible fixes primarily fell into two categories: (1) creating in-region demand by building PDH/PP complexes in Alberta and supplying them with regionally produced, price-advantaged propane (that led to the Pembina-PIC joint venture project we noted above, now in the works); and (2) transporting propane westward by rail to BC, where it could be loaded onto ships and sent to Asia and other overseas markets. So far, the only way for Western Canadian producers to export LPGs — the general term used for propane and normal butane — overseas has been by railing them south across the border to (until now) the only LPG export facility in the Pacific Northwest/BC region: Petrogas’s 30-Mb/d export terminal in Ferndale, WA (red pentagon in Figure 1; operated by AltaGas). But, as we discussed in a previous series on U.S. and Canadian LPG export terminals

AltaGas’s Ridley Island Propane Terminal (RIPET; blue pentagon) near Prince Rupert, BC, is set to become the first of those to begin exporting propane from the west coast of Canada. On May 2, in its latest earnings call, AltaGas said it began introducing feedstock at the 40-Mb/d facility in mid-April and that it expected to load its first cargo by mid-May, with a second cargo expected by the end of May. And vessel tracker data indicates the VLGC Sumire Gas arrived just outside the port this week and is ready and waiting to berth at the terminal.

RIPET’s in-service will instantly more than double the capacity available for Western Canadian producers to access Asian markets (Ferndale being their only previous option) and allow the product to get there in less than half the time it would take from the Gulf Coast — 10 days from Prince Rupert, compared with 25 days from terminals near the NGL hub in Mont Belvieu, TX. But it’s not without its challenges either. Before we get to the whys and hows, though, first a quick recap of the facility and related infrastructure.

Fig1_Ridley.PNG?itok=Op0sue9Z

Figure 1. AltaGas/Vopak Ridley Island Propane Export Terminal.

The $450-500 million terminal was built on a 24-acre portion of a larger brownfield site leased from the Prince Rupert Port Authority that already has extensive rail infrastructure and a deepwater marine jetty used for exporting coal. RIPET involved building a 20-spot rail unloading rack (with the capacity to unload up to 40 propane-laden rail cars in one go); pressurized storage tanks (known as bullets); more than 500 Mbbl of storage capacity in refrigerated (unpressurized) tanks; and piping and propane loading arms to load propane onto VLGCs that will dock at the jetty. [The dock can handle ships of up to 64,220 deadweight tons (DWT), with a length of up to 755 feet, a beam of 126 feet and a draft of 45 feet.] RIPET will receive pressurized liquid propane by rail. The propane will be transferred to the pressurized storage bullets, then chilled and transferred to the refrigerated atmospheric storage tanks. The chilled propane will be loaded onto VLGCs — AltaGas expects RIPET to send out 20 to 30 VLGCs a year, or one every couple of weeks, on average, including in the winter, since Prince Rupert is an ice-free port.

By the time it announced a FID on Jan 3, 2017, AltaGas had a multiyear definitive agreement with Japanese LPG distributor Astomos Energy for 50% of the terminal’s offtake volume, while the other 50% remained in discussions. A few months after taking FID, AltaGas also signed on global storage-terminal operator Royal Vopak as a joint-venture partner, with Vopak taking a 30% ownership interest in RIPET. Vopak at the time said its stake in the project was underpinned by long-term customer contracts.

In terms of supplying propane to the terminal, AltaGas has said it would provide about half from its own facilities, including from its (for now) 10-Mb/d North Pine fractionation plant in northeastern BC that began service in December 2017, and another approximately 10 Mb/d from an unnamed Edmonton supplier. To further shore up supply for RIPET, AltaGas in summer 2018 inked two upstream deals. In August 2018, it executed an agreement with Kelt Exploration Ltd. to provide firm processing capacity for 75 MMcf/d of raw natural gas under a 10-year take-or-pay arrangement that includes gas gathering, liquids handling, field fractionation and propane marketing, including exports out of RIPET. A month later, AltaGas took a 50% stake in Black Swan Energy’s Aitken Creek natural gas processing plants. The deal also covered future processing plants. These agreements prompted AltaGas to put in motion its plan to double the capacity of the North Pine plant to 20 Mb/d later this year. The operator also was looking to lock in tolling arrangements with producers and other suppliers, of which more than 20% is secured thus far, with more expected in the coming months, according to the latest earnings call.

As we alluded to above, AltaGas expects to load two VLGCs per month at RIPET, with the possibility of a periodic additional ship, if capacity allows. Astomos is slated to take several of the first cargoes and then one per month after that, all bound for Asia (though the terminal could also easily export to Central and South America). It’s unclear if the second cargo is spoken for by Vopak’s or other customers, or if AltaGas expects to sell that in the spot market; AltaGas or Vopak have not formally announced any other specific buyers. Assuming full utilization of the export capacity, Figure 2 illustrates the prospective increase in Canada’s propane exports this year and next from RIPET (green bar segments to far right), even if the volumes through existing export outlets were to remain unchanged from 2018 this year and next (blue bar segments to far right).

Fig2_Ridley.PNG?itok=Rj3tsaOE

Figure 2. Canada’s Annual Propane Exports. Sources: NEB and RBN (Click to Enlarge)

However, there are some risks to keep in mind when it comes to those exports materializing consistently throughout the year. Supplying RIPET is a monumental challenge. The terminal is isolated from the source of its commodity by two mountain ranges. No pipelines traverse that region, and thus, the terminal will rely exclusively on rail to move propane to the facility. And there’s only one railroad serving the popular Prince Rupert port — the Canadian National Railway (CN; red line in Figure 1 map). It is tasked with moving a wide variety of products through the booming transport corridor, and AltaGas is just the newest customer.

To keep up with a two-tanker-per-month pace, CN will need to deliver an average of 50-to-60 tank cars (30,000 gallons each) per day, primarily from AltaGas and other gas processing plants in northeastern BC and in Alberta. Loaded tank cars will originate from Edmonton, as well as from Fort St. John, BC, in the Montney (see Figure 1 map). But railways have their own logistical challenges. For example, in the winter of 2017-18, the Edmonton NGL hub nearly ground to a halt because of congestion on CN’s system due to a shortage of crews, locomotives and track space. The railroad company in 2018 executed a CAD$3.2 billion capital spending program to address some of the problems, including hiring more crews, buying more than 200 locomotives and laying more track. The spending plan has helped relieve some of the congestion on CN’s sprawling system. But the railroad continues to add more sidings — low-speed side tracks that can be looped with the main line — and double tracks to keep traffic flowing.

Then, there’s also the issue of competing for rail space with other products bound for the four other existing terminals at Prince Rupert, including one container terminal — the big bucks for CN lie in moving these container trains. And the competition for space on the rails is likely to get stiffer, considering that the port is undertaking a second expansion this year that will boost the terminal’s total throughput container capacity by 450,000 TEUs (twenty-foot equivalent unit) to 1.8 million TEUs by 2022.

The good news for AltaGas is that it has the first-mover advantage on propane exports from Prince Rupert. But the other propane terminals aren’t too far behind: Pembina’s 25-Mb/d Prince Rupert LPG Export Terminal on Watson Island is due online in mid-2020; Royal Vopak has floated the Vopak Pacific Canada project, a multi-product petroleum export terminal adjacent to RIPET that, if greenlighted, would handle LPGs, methanol and refined products starting in late 2022; AltaGas in its May 2 earnings call also hinted at the prospect of a 40 Mb/d expansion of RIPET; and Pacific Traverse Energy is pursuing the development of a 40-Mb/d propane export terminal for completion in the late 2022/early 2023 timeframe.

The upshot is that it may not be all smooth sailing ahead for Western Canada’s propane producers looking to export out of Prince Rupert, given the infrastructure and logistical challenges associated with moving propane to the terminal. However, with the in-service of RIPET, the remote and chronically oversupplied Edmonton propane market will finally have a new outlet with destination markets other than the U.S., and that could help to ease the region’s propane glut and correct depressed propane prices to some extent, at least in the near term.

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Pipeline shortage cost Canada’s energy sector $20.6 billion in 2018

 

That means less investment, less job creation and ultimately less prosperity for Canadians

 

With pipeline shortages driving down the price of Canadian oil, the losses for the energy sector – and for Canada’s economy – are staggering.

According to a new study, insufficient pipeline capacity cost Canada’s energy sector $20.6 billion – or one per cent of the country’s economy – in foregone revenues last year.

Despite increased oil production in recent years, Canada has been unable to build any new major pipelines. High-profile projects including the Northern Gateway and Energy East projects have been cancelled. And the Trans Mountain expansion, Line 3 replacement and Keystone XL pipeline remain mired in delay.

Take the Trans Mountain pipeline expansion project, for example. After years of regulatory delays and political interference, the project’s future remains uncertain. The proposal to expand the existing Trans Mountain pipeline between Edmonton and Burnaby, B.C., was first approved in 2016. However, the Federal Court of Appeal rescinded that decision last year, ruling that neither the environmental review nor the Indigenous consultation were properly completed.

 

And despite a revised National Energy Board ruling that deemed the project in the public interest, the B.C. government continues to oppose the project and is pursuing legal means to block the expansion.

Such delays and political opposition raises serious concerns about whether the pipeline will ever be built.

So what are the consequences of all these delays? How is insufficient pipeline capacity affecting our economy?

We have an overdependence on the U.S. market, increased reliance on more costly modes of energy transportation, and rising oil inventories in Western Canada.

Producers are shipping their crude by rail, a higher-cost mode of transportation (and less safe – pipelines are 2.5 times less likely to experience an oil spill than rail transport). Higher rail rates are absorbed by Canadian oil producers, leading to lower profits for Canadian crude and a wider price differential between Western Canada Select (WCS) and U.S. crude West Texas Intermediate (WTI).

It hasn’t always been this way. Between 2009 and 2012, the price differential was roughly 13 per cent of the U.S. crude price. And that difference was seen by producers as one of the costs of doing business in Canada.

But recently, this price difference has skyrocketed.

In November 2018, the price differential reached almost 70 per cent of the U.S. crude price, meaning Canadian heavy oil was sold at only 30 per cent of the value of U.S. oil.

In addition to the negative impacts on oil producers, these high price differentials result in lower-than-expected royalties (the government’s cut of every barrel produced) and lower corporate income tax revenue for energy-producing provinces and the federal government.

This is revenue that could have been used for vital services such as health care and education and/or reduced taxes.

In response to the drastic price discount, in late-2018 the previous Alberta gov­ernment introduced a temporary production limit on oil producers in an attempt to address excess supply and insufficient export capac­ity.

Since this limit was implemented, the price differential has narrowed. But clearly, building new export pipe­lines remains the only long-term solution to ensure Canada’s valuable exports receive prices closer to world market prices.

The real issue is that Canadian heavy oil producers lost a staggering $20.6 billion in forgone revenues last year compared to what other producers of similar products received.

That’s roughly one per cent of our economy lost because we can’t deliver our product to international markets to secure better prices. This loss of revenue means less investment, less job creation and ultimately less prosperity for Canadians.

Unless Canadians are willing to continue to incur large losses and less investment, the federal government and several key provincial governments must co-operate to get pipelines built.

https://troymedia.com/2019/05/17/pipeline-shortage-cost-canadas-energy-sector-20-6-billion-in-2018/

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