Prospects for Expanding Outlets for Western Canadian Gas Supply

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Prospects for Expanding Outlets for Western Canadian Gas Supply

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.

We have explored some of the increasing pressure points on Canadian natural gas in prior blogs. In our On the Border series, we extensively reviewed cross-border gas flows between the neighboring countries, examining how the growth in U.S. gas supplies has affected Canada’s primary export/import corridors to the U.S. Northeast, Midwest and Western markets. In the Northeast, the battle has been largely won by Marcellus/Utica gas supplies, which have not only pushed back Canadian gas exports, but also made the Northeast a net exporter of natural gas to Canada for most days and months of the year — the exception being when extremely cold weather necessitates an export boost from Canada to cover demand needs on the U.S. side of the border.
A similar situation is starting to emerge in the Midwest; there, Canadian market share and exports to the region are eroding thanks to the expanding pipeline footprint that is bringing increasing volumes of Marcellus/Utica gas to the Midwest. Rising supplies of associated gas from the Bakken also have contributed to limiting Canadian gas exports to the region. Canadian net gas exports into the Midwest still have the upper hand for now, but that grip is slipping as U.S. supply continues to increase. Canadian exports to the West have actually been growing, helping to keep Canada’s total net gas exports relatively stable in the past few years. But this long-term trend may also be at risk, as rising Marcellus/Utica/Bakken supplies are forcing more U.S. Rockies-sourced supplies that previously moved east to the Midwest to stay closer to home and instead compete for market share in the West. This, even as renewable energy sources and other factors dampen natural gas demand in California and other West Coast markets.

If U.S. supply growth has made life difficult for Canadian producers, then intra-provincial congestion out of the Western Canadian Sedimentary Basin (WCSB) — where nearly all of Canada’s production comes from — has made it downright untenable. The culprits are two-fold: rising production and diminishing pipeline capacity available for moving the volumes out of the region. As shown in Figure 1, WCSB production has been rising steadily, from an annual average of about 13.7 Bcf/d in 2012 to about 16.1 Bcf/d in 2018, according to Canada’s National Energy Board (NEB), with the growth led primarily by increased oil and liquids-focused drilling activity in the Montney and related plays, such as the nearby Duvernay.

Growth looks to have stalled in 2019 and is expected to remain essentially flat this year, according to the latest short-term forecast from the NEB. This is not for a lack of effort by Canada’s natural gas producers, but is almost exclusively a function of the second culprit — the lack of available pipeline takeaway capacity to accommodate additional supplies.

This can be seen more clearly in Figure 2: average gas flows at the major export points exiting Alberta and British Columbia (solid green area) fell from 11.8 Bcf/d in 2006 to a trough of 8.7 Bcf/d in 2012, before stabilizing in 2013 and 2014 at 9.7 Bcf/d. They’ve shown only some slight gains since and averaged the same 9.7 Bcf/d in 2018. At the same time, total pipeline design capacity for leaving the production basin (purple line) declined from 13.6 Bcf/d in the 2006-10 period, to 12.9 Bcf/d in 2011-13, and further to about 10.1 Bcf/d in 2014, where it has more or less stayed over the past five years. We’ll get to the reasons behind the declining capacity in a minute, but what is abundantly clear from the disappearing gap between the green area and the purple line in recent years is that, since 2014, export capacity and export volumes have been much more closely aligned, especially since 2016, underscoring the much tighter situation between the rising production volumes of Figure 1 and how much of those volumes can be exported against fixed export capacity.

Figure 2. WCSB Gas Outflows vs. Design Capacity. Source: NEB (Click to Enlarge)

TC Energy’s (formerly TransCanada, until a name change on May 3) pipeline network underwent significant changes in response to shrinking supplies during the 2000s and early 2010s, which forced the operator to reallocate some of its mainline capacity to other uses or make other modifications to address underutilization. In more recent years, there also has been a restructuring of gas flows across TC Energy’s Alberta network to deal with supply growth shifting to the more unconventional gas supply plays in northwestern Alberta and northeastern BC (Montney et al.), while intra-Alberta demand grew in the northeastern part of the province for use in the oil sands. We covered a number of these events in our Don’t Do Me Like That series. There, we noted that more recent gas supply developments in Western Canada and additional transportation and flow restrictions on TC Energy’s Alberta pipeline system starting in 2017 were likely adding to the region’s weaker prices and price volatility.

More recently, the three major pipeline operators in Western Canada — NOVA Gas Transmission Ltd. (NGTL; TC Energy’s Alberta system), Westcoast Energy and Alliance Pipeline — have proposed a number of expansions to combat this homegrown congestion . ome of these expansions have since been completed and many more are on the way (we’ll get to these in more detail later in this blog series). But keeping up with the growth in supply has proven difficult and costly, especially when measured in terms of the prices realized by producers for Canadian natural gas.   Canada’s primary gas price marker, AECO-NIT in Alberta, usually more simply referred to as AECO, is the spot and forward price benchmark that underlies a majority of the gas trading in Western Canada. Outright spot prices at AECO have been extremely nauseating for producers, trading at record lows and even settling barely above zero at times over the past 18 months or so (dashed blue oval in the left graph in Figure 3); negative AECO prices have also been reported on about a dozen occasions (mostly in trading for weekend flows, with the last instance being in early November 2018), meaning Western Canadian gas producers have some sense and sympathy for what Permian gas producers have experienced in the past couple of months (though for vastly different reasons .

The right graph in Figure 3 below plots the resulting differential (or basis) between AECO spot prices and the U.S. benchmark Henry Hub. AECO has historically traded at a discount to Henry Hub. Aside from seasonal variations and some extremes of winter weather constraints (such as in early 2014), the period from 2010 to early 2016 was marked by a fairly stable basis in which AECO averaged $0.45/MMBtu less than Henry. Since mid-2016, AECO basis has widened significantly, however, averaging minus-$0.92/MMBtu in 2016, minus-$1.30/MMBtu in 2017, and minus-$1.98/MMBtu in 2018; to date in 2019, basis is averaging an improved minus-$1.18/MMBtu, compared with minus-$1.45/MMBtu for the same period last year. That reflects the much tighter, sub-$0.50/MMBtu basis seen through much of February, when unusually cold weather blanketed most of North America. However, basis has weakened since then to as much as minus-$2.48/MMBtu and an average of minus-$1.93/MMBtu in April, 30 cents weaker than in April 2018. 

Figure 3. AECO Cash Prices and Basis. Source: Bloomberg (Click to Enlarge)

With the ever-widening basis and the cheapening of AECO prices, the Western Canadian natural gas market seems to be screaming “Get Me Out of Here” and looking for more options to escape the pipeline-constrained basin. Can we get a better picture of the dynamics driving the Canadian gas supply and export picture? What pipeline capacity additions are being constructed and proposed that will allow growing Canadian gas supplies to reach markets, wherever they might be? What is happening with domestic Canadian gas demand, especially within Alberta’s oil sands and considering the province’s transition away from coal in power generation? Will LNG exports from the BC coast provide the next great expansion path for Canadian natural gas? What will all of this mean for AECO prices and the future of natural gas in Western Canada? These are all enormously challenging questions and ones that we will examine in greater detail as we continue through this blog series.

 

 

 

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SemCAMS Midstream ULC has entered into an asset joint venture with Keyera Corp. to build an NGL and condensate pipeline system connecting the liquids-rich Montney and Duvernay shale production areas of northwestern Alberta to fractionation and condensate hubs in Fort Saskatchewan, Alta. The joint venture replaces SemCAMS Midstream’s previously announced Montney to Market (M2M) pipeline. SemCAMS Midstream and Keyera will be equal partners on the project, with Keyera acting as operator.

Current project scope includes a 16-in. OD condensate pipeline and a 12-in. PD NGL pipeline, connecting to both third-party sites and Keyera and SemCAMS Midstream sites. Keyera and SemCAMS Midstream expect to have nine gas plants operating in the area by 2022, with access to 2.25 bcfd of gas processing and 130,000 b/d of condensate handling capability between Pipestone and Kaybob, Alta. The project is targeted to become operational in first-half 2022, with most capital spending occurring second-half 2020 into 2021.

The project is supported by multiple long-term firm service agreements, averaging 14 years and representing 60% of initial pipeline capacity. The firm-service agreements are underpinned by 75% take-or-pay commitments as well as specific facility and area dedications. Discussions are under way with additional producers for incremental volumes. The pipeline can be expanded with additional pump stations to meet future capacity requirements.

SemCAMS estimates total cost for the project at $1.3 billion (Can.).

SemCAMS Midstream was formed in this year’s first quarter and continues to expand its footprint in the Montney and Duvernay shales. SemCAMS Midstream owns and operates about 1.1 bcfd of natural gas processing capacity, increasing to roughly 1.3 bcfd later this year with expected completion of its Patterson Creek Plant expansion and Smoke Lake Plant.

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Liquids yield driving Montney production growth forecast

Total production in Canada’s Montney play will likely reach 10 bcfd of natural gas equivalent this year, an increase of 16% from 2018, and is forecasted to reach 20 bcfed by 2030, driven by rising liquids yield across various sub-plays, according to Wood Mackenzie research.

Liquids production is expected to increase 26% in 2019, while gas production may increase by 14%.

Despite falling gas prices, improving sub-play economics driven by higher liquids yields have strengthened the Montney’s position and much of the play is economic at $2 (Can.)/Mcf.

“Depressed natural gas prices have caused operators to rethink Montney development,” said WoodMac senior analyst Nathan Nemeth.

“Montney specialists have made major headway on improving completion design and are being rewarded with operational performance. Liquids is driving the story,” he said.

Drilling activity during 2010-14 was led by operators with LNG export aspirations. From 2015, activity has been led by operators targeting natural gas liquids, specifically condensate.

Not all areas of the Montney are liquids-rich. The remaining value of the play is estimated to be more than $65 billion (Can.), but Nemeth noted that the value is concentrated in the best areas, with the top five sub-plays accounting for 74%.

At this stage, two sub-plays account for about 50% of the Montney's liquids production: Heritage, in British Columbia, and Kakwa, in Alberta.

Nemeth said the corporate dynamics also keep the Montney interesting, with most activity from a mix of public and private local companies.

“But you also have international players like ConocoPhillips and Murphy, as well as LNG-driven activity from Shell, Petronas, Mitsubishi, and PetroChina.

“The growing liquids production from the Montney, combined with the final investment decision for LNG Canada last year, make the Montney an important play to keep an eye on in the future,” he said.