He Ain't Heavy, He's My (Diluent), Part 4 - Assessing Future Demand And Sources Of Diluent

So far, 2020 has been another bad year for bitumen producers in Alberta’s oil sands. For the second year in a row, they have been forced to endure production curtailments, this time in response to COVID impacts on demand and the resulting record-low heavy oil prices. Still, there are at least glimmers of hope that the bitumen market will soon enter at least a modest recovery mode, and that further gains will be possible in 2021 and beyond. Moving all of that bitumen to market in pipelines and in rail cars is going to require even more diluent than the record amounts already consumed in late 2019 and early 2020. Today, we consider the outlook for bitumen production, what that outlook means for future diluent demand, and if that demand can — or cannot — be met by the various sources of diluent supply.

Over the course of this series, we have been taking a closer look at diluent, the light liquid hydrocarbons that are blended with bitumen — the extremely heavy and viscous form of crude oil from Alberta’s oil sands — to create a more fluid form that can flow in pipelines or be shipped in rail cars. With bitumen production on the rise since the start of the century and pushing Canada into the top ranks of global oil producers, an entire side industry has arisen to gather and distribute diluent to the oil sands regions of Alberta.

In Part 1, we began our analysis with a look at the shifting diluent supply and demand in Western Canada. Using a relationship known as the blend ratio — or the amount of diluent required per barrel of bitumen — we estimated that diluent demand more than doubled in the past decade or so, rising from about 300 Mb/d in 2010 to more than 750 Mb/d as of early 2020. In-region diluent supply also climbed in that time, but the homegrown sources of diluent are insufficient to meet all of the demand, necessitating imports via two dedicated import pipelines from the U.S. Midwest.

Part 2 looked more closely at the sources of diluent supply in Western Canada and the various pipeline gathering systems that move those liquids to the Edmonton/Fort Saskatchewan and Hardisty trading hubs. To sum up, a large share is sourced from mixed NGLs (referred to as y-grade) in the form of condensate (also known as natural gasoline), which is extracted from the NGLs at gas and fractionation plants. Significant volumes of diluent also come from simple processing of the liquids directly from the wellhead (called field condensate, but also called condensate in Canada, to keep it confusing). And finally, a small portion of diluent demand is met by using Alberta-sourced butane (or normal butane) as a blending agent. The biggest of the liquids pipelines facilitating movement of diluent supply out of the supply regions is the Peace Pipeline system operated by Pembina Pipeline Corp., but there are also a number of smaller pipeline gathering networks in the region operated by Keyera Energy and Plains Midstream Canada.

In Part 3, we shifted our focus to the pipelines that distribute the diluent from the primary hubs mentioned above to the oil sand regions of Alberta. The largest operator is Inter Pipeline Ltd., with its Polaris, Corridor, and Cold Lake systems. Other pipelines that distribute diluent include Norlite (Enbridge/Keyera), Rainbow II (Plains Midstream Canada), and Access (Wolf Midstream). These pipelines all distribute diluent from the Edmonton/Fort Saskatchewan hub, while two smaller pipelines into and out of the Hardisty hub are operated by Husky Energy. We concluded that blog by noting that there is more than enough in-region capacity (1.6 MMb/d) on the existing set of diluent distribution pipelines to handle current diluent demand (~750 Mb/d).

If there is plenty of spare capacity on distribution pipelines, then might the limitations on the diluent market be supplies? And will the diluent supply mix going forward be mostly met by Canadian sources or will imports still play a large role? Next, we conclude the series with a forward look at Western Canada’s diluent supply and demand picture.

To get some sense for how much diluent will be needed, either from Canadian or imported sources, we need a forecast for non-upgraded bitumen supply — the portion of bitumen production that is not processed into lighter synthetic crude oil (SCO) and that requires diluent in order to be sent to market. We are fortunate that the Alberta Energy Regulator (AER) last month released its annual forecast update of Alberta’s entire energy sector, referred to as the ST98 report, which includes the AER’s outlook for bitumen production.

The AER outlook runs through 2029, but we have chosen to focus on a shorter time span, including historical data for 2018 and 2019, along with forecasted estimates for the 2020-25 time frame. We should also point out that we are using the AER’s low-price scenario forecast, in which the average price for WTI rises to an average of $48/bbl by 2025. The lower-price scenario does appear to more accurately capture much of this year’s bitumen production curtailments in response to the recent record-low heavy oil prices and the COVID-related oil demand pullback.

According to the AER, Alberta’s (non-upgraded) bitumen production is forecast to rise from 1.6 MMb/d in 2020 to just under 2.3 MMb/d in 2025 (blue columns in Figure 1). Using the blend ratio that we discussed in Part 1, we compute that corresponding diluent demand will rise from 690 Mb/d in 2020 to 974 Mb/d by 2025 (red line and red numbers), an increase of 41% or 284 Mb/d.

Figure 1. Bitumen Production and Diluent Demand Outlook to 2025. Sources: AER and RBN Energy

The AER also provides a forecast of Alberta’s pentanes-plus supply, of which the large majority consists of condensate (see our definitions mentioned earlier). The AER has all of this supply being dedicated to diluent use in the oil sands. By utilizing this supply forecast in relation to our computed diluent demand outlook, we can get some sense for the amount of other diluent supplies that will be needed given the AER’s outlook for bitumen production.

As Figure 2 shows, Alberta’s pentanes-plus supply is forecast to rise from 359 Mb/d in 2020 to 399 Mb/d in 2025, an increase of 11%, or 40 Mb/d (green bar segments). This is a pretty modest gain in homegrown supplies of diluent when compared with the projected diluent demand gain of more than 280 Mb/d mentioned earlier (black line) for the same period. The projected amount of Alberta pentanes-plus supply in 2025 means that 575 Mb/d of diluent supply will have to come from other sources.

Figure 2: Diluent Demand and Supply to 2025. Source: AER and RBN Energy

As we discussed in more detail in Part 3, another chunk of diluent supplies comes in the form of imports from the U.S. on the Southern Lights and Cochin pipelines. Extrapolating from the first five months of data from the AER, we project that diluent imports would rise from 245 Mb/d in 2020 to a maximum of 275 Mb/d (lavender bar segments in Figure 2), that level being set by the combined diluent import capacity from the Midwest of the Southern Lights pipeline (180 Mb/d) and the Cochin pipeline (95 Mb/d). Thus, between the growth in Alberta’s pentane-plus supply and imports, that comes to a ~70-Mb/d expected increase in diluent supply by 2025. That leaves 300 Mb/d of supply (or 213 Mb/d more than in 2020) that would be needed by 2025 from other sources (teal bar segments), including field and plant condensate supplies from the neighboring provinces of British Columbia (BC) and Saskatchewan, Alberta-sourced butane and small amounts of SCO that are blended with bitumen at several upgraders. 

However, even if we assume reasonable growth estimates for these other Western Canadian sources of diluent, we expect their combined volume to get to not much more than 175 Mb/d by 2025, which still would be insufficient to fully meet that estimated 300 Mb/d of “other” diluent that likely will be needed by then. (In the here and now, the demand for diluent has already pushed a little higher with the start-up of the Marten Hills pipeline on July 7. Briefly mentioned in Part 3, this newly commissioned pipeline will use diluent shipped in from Plains Midstream Canada’s Rainbow II pipeline to dilute bitumen and extra heavy oil produced in the Marten Hills region for shipment out to the Edmonton hub and points beyond. This could add up to 10 Mb/d of diluent demand once the pipeline is running at full capacity.)

The AER’s latest forecast combined with our analysis above leads us to several important conclusions. Foremost, the expected increase in diluent demand by 2025 would strongly suggest that diluent imports are still going to be needed in large volumes, possibly at or near the maximum of what can be imported given the import pipelines’ current capacities. On that basis, the often-discussed potential for a reversal of the Southern Lights pipeline to crude-only exports seems less likely for the foreseeable future, unless there are significant increases from in-region sources of diluent beyond what we and the AER assume.

To that point, significant increases in homegrown sources of diluent — and/or ways to reduce/recover diluent use — will be needed in order to deal with the AER’s projected increase in bitumen supply. Finally, assuming enough diluent supply is available from all sources to satisfy the nearly 1 MMb/d of diluent demand expected by 2025, there appears to be more than enough diluent distribution pipeline capacity in place to move the diluent to the oil sands regions of Alberta. In other words, the existing capacity of diluent distribution pipelines is unlikely to see any major expansions or new pipelines proposals for many years, given that bitumen producers are set to boost production from existing sites, rather than develop new projects farther from the existing diluent distribution network.

In the end, the challenge for the diluent market remains as it has been for many years: sourcing enough supplies to deal with future bitumen supply growth. Regardless of whether those supplies are sourced from Western Canada or the U.S., it may still not be enough, and the market may eventually require more inventive ways of moving the bitumen in pipelines or rail cars with less diluent.

"He Ain't Heavy, He's My Brother" was written by Bobby Scott and Bob Russell. The song was originally released by Kelly Gordon in early 1969, but it was The Hollies’ release of the song as a single in September 1969 that made it a worldwide hit. “He Ain’t Heavy” was the second song on side two of the U.S. release of The Hollies’ ninth studio album of the same name. The song was recorded at Abbey Road Studios in London between June and August 1969, with Ron Richards producing. It went to #7 on the Billboard Hot 100 Singles chart. Personnel on the record were: Allan Clarke (lead vocal, harmonica), Tony Hicks (lead guitar, backing vocals), Terry Sylvester (rhythm guitar, backing vocals), Bernie Calvert (bass, keyboards), Bobby Elliott (drums), and Elton John (piano). 

The album He Ain't Heavy, He's My Brother was released in the U.S. in December 1969. It was released in the UK one month prior, under the title Hollies Sing Hollies. The re-named U.S. version included the hit single, which was not included on Hollies Sing Hollies. It would be the first Hollies album released since the departure of Graham Nash in late 1968. The album went to #32 on the Billboard Top 200 Albums chart. 

The Hollies are a British rock band formed in Manchester in 1962 by Allan Clarke and Graham Nash. They have released 21 studio albums, 22 compilation albums, seven EPs, and 67 singles. They have had 21 singles chart in the Billboard Hot 100 and 13 albums chart in the Billboard Top 200. They are members of The Rock and Roll Hall of Fame and Vocal Group Hall of Fame. The band still tours with founding members Tony Hicks and Bobby Elliot, joined by touring musicians.