What are your assumptions on the proposed pipelines (Line 3 replacement, Trans Mountain expansion and Keystone XL)? What will be the impact of each pipeline on LH differential and other western Canada crude?

The midstream implications are that through 2025, we see only the Line 3 expansion program, which we expect to successfully navigate remaining and current state-level permitting procedural challenges and delays largely on environmental and cultural review grounds, as being required to sufficiently handle oil sands crude gains through 2025. We do see the Line 3 replacement project as being the most likely to get built and commissioned during the forecast period.

How much of an effect will pipeline opposition have on getting pipelines approved and/or built in Canada and/or the U.S.? Also, how much of an impact will the inclusion of upstream and downstream emissions by the NEB have on pipeline approvals in the future? And what is the probability of KXL being built?

We hold low expectations for the completion of the TransMountain Expansion (TMX) or the Keystone XL (KXL) expansion. Pre-construction costs continue to rise and could drive anticipated developer returns too low (as signaled in the TransMountain announcement in April). The demise of the Energy East and Northern Gateway tidewater access projects came after years of delay and after various policy changes, including the pronouncement regarding the need for permits to incorporate upstream and downstream carbon emissions and potentially a national carbon levy to be decided perhaps in 2018. Permitting, adjudicating and constructing the KXL and TMX will likely be no less difficult and no more certain, in our opinion, given relentless opposition. At best, we think the TMX could start in 2021 if the developer doesn’t cancel the project at its late May drop-dead date. Also, we think the KXL expansion will take at least through 2020 to construct and start up. If the Line 3 project is completed, neither the KXL nor TMX will be needed in our opinion to meet the takeaway needs for oil sands crude production that we forecast through the 2025 end of the forecast period. If, however, these pipelines are built, we could likely see Canadian heavy displace Venezuelan and Mexican heavy crude imports and potentially lead to a buildup of exportable excess heavy crude along the US Gulf Coast.

Do you assume a certain level of rail commitments or structural rail?

We expect the Line 3 replacement pipeline to be completed during the forecast period, which will draw barrels away from higher-cost rail transit methods and potentially reduce the need for costly drag-reducing agents (DRA). As oil sands growth resumes and sets new highs in the mid- to late 2020s, or if other unplanned pipeline outages arise, we could see a resumption in significant crude-by-rail movements from ample already-existing loading terminals which could send out volumes at or above the 200,000 barrels per day (Mbbl/d) to 300 Mbbl/d run rate today.

Do you expect to see more heavy being mixed with light to be moved on light oil pipelines?

We do not expect to see a significant new requirement for mixing of light crude with bitumen (shale-bit, synbit, etc.). Accordingly, the shift of more oil sands production away from costlier rail and DRA-assisted pipeline transits to more cost-efficient new bulk pipeline movements.

What are your assumptions on pipeline and rail transportation costs?

We anticipate costs to move WCS, synbit or railbit by rail to the more distant U.S. markets such as the Gulf Coast will range between $12 to $18/bbl through the forecast period. Conversely, current pipeline tolls to the same USGC market are $4 to $6/bbl lower. The flow volume weighted operational opportunity at any given time should determine the blended WTI-WCS differential. Ultimately, if the Line 3 replacement starts up to offer an incremental 370 Mbbl/d of takeaway to interconnected markets from Alberta, we would expect this pipeline to sufficiently drive flows and more narrow differentials between WCS and US inland and coastal light and heavy crude grades through 2025. We estimate that the WTI-WCS differential should narrow to an average of $14.28/bbl in 2025 vs. $25.58/bbl in first-quarter 2018.