The Battle For Dawn, Part 1: The Making Of A North American Natural Gas Super Glut

  • North America
  • 03/11/2017
The Battle For Dawn, Part 1: The Making Of A North American Natural Gas Super Glut
Author's note: All monetary figures given in Canadian dollars (CAD) unless otherwise noted

Following an unsuccessful open season earlier this, TransCanada (TRP) slashed toll rates along its underutilized portion of its mainline which delivers natural gas from Empress, Alberta to Dawn, Ontario. The intent is to send an additional 1.5 Bcf/d (~250 Mboe/d) to demand centers on the East Coast. Canadian natural gas has been previously unwilling to compete with the rapid production growth from Appalachia due to its logistical proximity with demand centers in the East Coast and Midwest.

The most recent open season last February saw a fundamental shift in market behavior. Western Canadian producers committed to send 1.42 Bcf/d in additional natural gas between Empress and Dawn on TransCanada's mainline over the next 10 years at $0.77/GJ/d. Dawn is an important market hub operated by Union Gas (a subsidiary of Enbridge (ENB)) which lies just across the Michigan border, near Detroit.

This development comes at the precipice of a rapidly stiffening battle for market share between Western Canadian producers and producers located in the Lower 48 States (L48). The reversal from last year stance comes as Western Canadian gas producers have decided to take head on Marcellus and Utica producers. Whereas Canadian producers are poised to offload billions of cubic feet of gas using TransCanada's underutilized mainline, Appalachian producers plan to unload billions more into the same demand centers utilizing under-construction projects such as Energy Transfer Partners LP's (ETE) (ETP) 3.25 Bcf/d Rover Pipeline and Enbridge's 1.5 Bcf/d Nexus pipeline project.

The battle lines drawn above indicate that growing supplies from Canada are likely to displace competing gas supplies further south toward the Gulf Coast. Expanding North American LNG capacity in this regard should be seen as a godsend for L48 producers. While Canada seems unlikely to develop its own LNG exporting facilities in the near-term, it stands to indirectly benefit by piggybacking off of this capacity (even if its molecules never reach the coast).

Producers' decisions to simultaneously ramp up competition were likely motivated by a confluence of factors including:

It is also possible that producers' concerted change of heart was a result of ongoing collaboration with one another, TransCanada, and regulators.

Or, according to CAPP's Vice President of Pipeline Regulation's recent testimony at an 11 Sept. hearing:

The battle for Dawn is the first shot fired in what will likely prove to be a particularly brutal price war to retain market share. Given some historical context, we shall see that Dawn is but a formal declaration of hostilities which was made necessary by the realization that an even greater supply glut looms large on the horizon. In the coming race to the bottom, it is clearly the consumers themselves who stand to benefit the most.

Canadian natural gas markets have been exhibiting signs of distress since August 2015 when West Coast Station 2 pricing dropped below $0.50/GJ, and has since fallen to as low as $0.105/GJ. As of last July, that carnage has spilled over into the region's primary trading hub near Calgary; since September AECO/C NIT (Alberta Energy Company, Transfer Point C, NOVA Inventory Transfer) spot prices have periodically dipped into negative territory.

Very low and negative prices could signal that either storage/logistical capacity is severely inadequate and/or the provincial markets are severely oversupplied.

A large body of opinion believes that logistical bottlenecks and lack of takeaway optionality are at the root of this volatility, as if the problem was not enough takeaway infrastructure. While flooded provincial markets are the proximate cause for low and negative commodity prices, logistical constraints are only symptomatic of a much more profound supply-demand imbalance. Indeed, a survey of Canadian producers' forward production guidance indicates that North America may be at the precipice of a renewed natural gas supply glut.

Much has been written about the causes of extremely volatile and low Western Canadian gas prices at major pricing hubs, such as at AECO and Station 2. As early as last August, it was reported that logistical bottlenecks due to summer work-overs and expansion projects, namely on TransCanada's NOVA Gas Transmission Line (NGTL), has resulted in supply interruptions even among producers who secured firm transportation agreements.

A prevailing opinion is that recent price signals from Canadian Hubs signal that infrastructure is inadequate. Ryan Ouwerkerk, an analyst, reported the following to JWN:

While seasonally recurring service outages and overhauls have contributed to price volatility, these sorts of stoppages are routine, i.e., logistical bottlenecks cannot explain the persistent basis widening between Canadian pricing benchmarks and benchmarks elsewhere. Moreover, simply due to that legacy production greatly exceeded present-day levels, we know that natural gas gathering and distribution infrastructure is adequate.

Lack of optionality is also not a significant underlying factor. TransCanada's mainline from Empress to Dawn has been underutilized since at least 2007.

Many analysts argue that significant gains in Canadian natural gas' competitiveness could be had if midstreamers cut transportation costs using existing infrastructure. The recent successful open season on TransCanada's mainline from Empress to Dawn, in which Long Term Fixed Price Contracts (LTFPs) were offered at rates as low as $0.77/GJ/d with 10-year commitments, is cited as evidence.

This viewpoint is the one canonical one, but simply cannot be accurate. These terms are not noticeably better than those previously offered. Although transportation costs clearly figure into the overall economics, they were clearly not sufficient on their own to motivate a broad-based and simultaneous about-face from last year. LTFPs as low as $0.66/GJ/d were offered at last year's open season. Even lower LTFPs of $0.61/GJ/d were offered recently. In spite of this heavy discounting, the last two open seasons were very under-subscribed.

Despite no improvement in terms, producers committed 1.4-1.5 Bcf/d in LTFPs during the most recent open season. The mainline's capacity is now almost fully committed with firm, long-term commitments.

So what changed to provoke such an overwhelming market response? The fundamental difference between this open season and previous ones are negative price signals at regional gas hubs. Lack of takeaway capacity was never the issue, but rather it was that producers were (blamelessly) holding out for better market conditions and/or transportation terms.

Negative price signals sent a clear message to producers: better conditions are not in the cards and that transporters have a clear upper hand in terms of the ability to wait things out. The clear alternative to ceding utter defeat to L48 producers was to punch back at the Dawn Hub, utilizing TransCanada's under-utilized asset.

Alternative narratives point to how a lack of storage provides an inadequate buffer to even minor imbalances. According to an ARC financial analyst, "The market does not have the shock absorber of storage". Darren Gee, Peyto's (OTCPK:PEYUF) legendary CEO, adds:

Though Gee does not explicitly finger TransCanada, it is apparent he is referring to the NGTL. However, if logistical bottlenecks are only symptomatic of other issues, then additional storage infrastructure is at best a Band-Aid.

The underlying reason for extraordinary pricing volatility rest rather on the demand side, due to an erosion of market share and competitiveness with other low-cost sources of supply which are more proximal to demand centers.

Canadian natural gas supply has exceeded regional demand since at least 1970. The broader market, however, could remain balanced as long as L48 demand could absorb excess supply. However, beginning in 2014, combined production from the United States and Canada would begin to significantly exceed combined demand.

Furthermore, Canadian natural gas production has been in secular decline since 2002 and has been losing market share since 2005 due to declines in conventional production and the boom in unconventional production from the L48. Now, the spread of the unconventional production boom has unlocked vast additional production potential from the stacked Western Canadian Sedimentary Basin (WCSB), where increasing production from both conventional and unconventional payzones has begun to reverse the course from decline to growth. As a result, legacy marketplaces for Canadian natural gas in Canada and the Northern States are now oversupplied. The situation is exacerbated by rapidly expanding production from Appalachia (i.e., Marcellus and Utica).

Sources: Canadian Marketable Gas Production: NEB - Marketable Natural Gas Production in Canada; July 2017 B.C. Production: Natural Gas & Oil Statistics - Province of British Columbia; U.S. Marketed Natural Gas Production: U.S. Natural Gas Marketed Production (Million Cubic Feet); U.S. Shale Production Estimates: via U.S. Energy Information Administration (EIA) Natural Gas Weekly Update

Sources: Canadian Marketable Gas Production: NEB - Marketable Natural Gas Production in Canada; July 2017 B.C. Production: Natural Gas & Oil Statistics - Province of British Columbia; U.S. Marketed Natural Gas Production: U.S. Natural Gas Marketed Production (Million Cubic Feet); U.S. Shale Production Estimates: via U.S. Energy Information Administration (EIA) Natural Gas Weekly Update

Simply, the legacy demand centers for Canadian natural gas no longer require tariff-heavy gas, when other low cost sources of supply are logistically more proximate. Relatively high toll rates have led to steeply discounted prices at provincial hubs where gas is backed up - not due to lack of takeaway capacity, but rather due to an erosion of market share (i.e., competitiveness).

Therefore, mild service disruptions which led to such extreme volatility are not indicative of underlying causation. They are instead simply symptomatic, exposing the fragility of the present-day supply-demand imbalances. More pipelines and lower transportation costs will not magically cause Canadian natural gas to become competitive with low-cost sources which lie in much closer proximity to demand centers.

Historical oversupply concerns are only the beginning of the story. In a recent article, Western Canadian NatGas Production Growth Creates An Illusion Of Value, I presented a bottom-up view that production growth into 2018 and beyond could utterly smash the consensus. As opposed to consensus opinions which are based on naive extrapolation, the data which led to this conclusion was sampled directly from corporate guidance. In short, a representative cross-section of WCSB producers are guiding for 50-60% production growth through 2018.

Based on my projections, Canadian production could grow by as much as 4.8 Bcf/d (800 Mboe/d) in 2018. A recent BMO assessment predicts that Western Canadian gas production will grow by 2.9 Bcf/d (from 15.8 Bcf/d in 2017 to 18.7 Bcf/d) in 2019. In September, JWN projected that Western Canada's natural gas production could grow by 19 percent, or 2.5-3 Bcf/d (from 16 Bcf/d today to 18.5-19 Bcf/d) by 2020.

Although my estimates are clearly on the high end, any of those estimates do change broader narrative. By comparison, Alberta gas consumption is projected to increase by just 2.27 Bcf/d (to 6.94 Bcf/d from 4.67 Bcf/d) by 2025.

However one decides to do that math, near-term production growth far outstrips the region's long-term demand growth. Growth of any magnitude which outstrips demand growth could lead to sustained bouts of low pricing.

In an earlier article, I argued that shut-ins were imminent because they are the logical course of action to a glutted marketplace. Upon further consideration, I now believe that large scale shut-ins are unlikely simply because many producers are unable to curtail production.

My earlier premise was that the reality of no-bid pricing at regional markets would serve as a wakeup call. However, recent rate cuts along major pipelines indicate that midstreamers can sustain additional margin compression, and thus that the broader industry can sustain even lower pricing before realizing the absolute marginal barrel. Central product midstreamers have been relatively insulated from short-term pricing changes in the current cycle, but the mere presence of midstream margins entails that the cost curve could endure another level shift down before low prices threaten supply and activity levels.

Generally, one should consider margins systematically along an entire value chain (vis-a-vis a first principles approach) if one hopes to gauge the range of plausible pricing scenarios which are fundamentally supported.

The conditions that have made producers resilient to previous market price signals are likely to hold up going forward. Most producers are subject to long-term off-take and throughput agreements with various midstream processors and shippers. Failure to deliver on minimum volumes results in both foregone revenues and penalties. Moreover, long-term off-take commitments are tied corporate guidance which - as previously detailed - currently signal massive growth.

In the October edition of the President's Monthly Report, Peyto Exploration and Development Corp.'s CEO - the legendary Darren Gee - gives several additional reasons as to why shut-ins will not scale.

Thus, producers who own and control their own processing and gathering infrastructure are slightly better positioned to control the pace of operations, but even they are exposed to long-term off-take agreements with central product midstreamers. For example, Gee boasts of being able to temporarily cut 10% of production due to lower prices, as if this were a significant quantity.

Peyto's well-above-average level of operational flexibility means that most producers have their hands tied. Midstream interests are aligned with maximizing throughput, since this is how they are paid. As long as the upstream assets operate, upstream profitability and even solvency is immaterial. As we have seen in the past few years, bankruptcies alone are insufficient to force supply-demand rationalizations, as well operators are largely unaffected by ownership restructuring.

Austerity from the capital markets provides a plausible forcing mechanism for rebalancing. An inability to tap capital markets will force producers to live with in cash flow which, for most producers, entails lowering guidance, slowing growth, and/or allowing declines to set in.

Over the past several years, it has become increasingly obvious that the shale boom was fueled by malinvestment. In previous articles, such as False Profits: A Prodigal Value Investor Returns From The Oil Patch, I have consistently lamented that over-capitalization and illusive profits make upstream value investing very difficult.

Or, in the more eloquent words of veteran oilman Steve Pruett:

Like many other upstream executives, Pruett's hands are tied. His company, Elevation Resources LLC, is contractually compelled to continue drilling operations. By Pruett's own admission, even though his company is drilling in some of the nation's hottest Permian Basin acreage, it is unlikely to turn a cash profit. In general, drilling will continue as long as capital is made available.

Yet, myself and others - such as Seeking Alpha contributor HFIR - have more recently noted a paradigm shift in which capital austerity should translate into production discipline and then higher prices. But even without higher future prices going forward, I believe that a secular downshift in the supply cost curve now justifies some upstream investments.

Capital markets' fiscal disciplinary mechanisms are already affecting Canadian markets. Relative to L48 producers, Canadian producers have a more difficult time accessing capital markets. Capital austerity - of which declining equities valuations are symptomatic - will force producers to live within cash flow. For many producers, this means that production will stop growing and even decline. In some cases, well declines in excess of well-level economic thresholds will necessitate shuttering, thereby accelerating corporate-level decline rates.

Lower spending combined with elevated effective decline rates will produce similar effects to shut-ins, albeit at a slower rate. Short life-cycles of tight oil and gas reservoirs, which come at the cost of rapid decline rates, provide supply responsiveness to price not available to large scale projects.

Even if capital markets force a rationalization of North American supply, the world is still in the early innings of an unconventional resource revolution. Efforts to curtail excess supply regionally could be quashed by international supply growth. Thus, the market themes currently at play in North America could be seen as a microcosm for global hydrocarbon production potential. Just as the Western Canadian supply glut stands poised to spill over into the U.S. markets, the North American supply glut may grow into a global phenomenon.

Although the exact conditions which led to a nascent shale boom in North America may not be present elsewhere, the question of a looming global unconventional tight oil and gas revolution is not a matter of if but simply a matter of when.

The discontinuous nature of tight oil and gas has historically favored smaller and nimbler (albeit well capitalized) wildcatter producers who were able to identify high graded acreage typically foregone by larger players and, if necessary, fail. Where these conditions are lacking provides a reasonable narrative as to why majors were late to the shale game, and why national oil companies may also prove to be unsuited to unconventional exploration and production.

Furthermore, high barriers to entry in many foreign markets are not conducive to the types of market entrants which specialize in shale: controls on foreign investment, price controls, labor unions, and subsidies are significant obstacles. Extensive market reforms may be required to promote the development of promising geologies such as Russia's Bazhenov Shale and elsewhere (see the ARI-EIA Joint Assessment, EIA's World Shale Resource Assessments, and WEC's 2016 World Energy Resources Report).

Lack of infrastructure in many promising areas, such as in Argentina's Neuqun Basin, provides additional barriers to development.

However, the eventuality of slowing productivity and efficiency gains in North America means that expertise gained here may soon find roots on foreign shores with or without market reforms. Slowing efficiency gains recently examined by Seeking Alpha contributor Blue Quadrant Capital Management (see Something Is Happening In The Eagle Ford - An Analysis Of Recent EIA Shale Basin Productivity Data and The Outlook For U.S. Natural Gas Prices 2018-2019) mean that the North America shale revolution may have reached an important technological and/or geological plateau.

Therefore, the conditions which were required to gestate a shale boom may not be required to sustain it globally. The hard-won fruits of advancing geological and technological knowledge now reside with experienced professionals. However, due to plateauing efficiency gains, domestic markets may no longer value these individuals as highly. Large independent and national operators now simply pluck these individuals.

Restated, the question is not if those individuals and operators will bring their hard-won experience elsewhere, but simply when. Economics compels this outcome.

An article from last September, Fracking Abroad - The State of Global Shale, provides a concise update on this topic.

It is superfluous to point out how prospects for a global tight oil and gas revolution further detract the prospects of long-term rebalancing.

Baseline estimates for supply and demand growth over the next two years indicate that North American markets are still trending toward oversupply, even given optimistic demand growth assumptions. Recent estimates from RBN Energy and Blue Quadrant Capital Management indicate that U.S. natural gas demand is likely to be 10 Bcf/d through 2019 (with 8 Bcf/d due to the commencement of Gulf Coast LNG operations). In contrast, L48 supply is expected to increase by 9-10 Bcf/d. The addition of my estimates for 3-5 Bcf/d in Canadian supply growth over the same period indicates that short-term supply will exceed demand by 2-5 Bcf/d.

However, I believe that low prices due to a prolonged supply glut are likely to incentivize new demand pathways including conversion of coal fired plants to natural gas, petrochemical project expansions and innovations, and even a resurgent possibility of methanol-based economies.

Growth in North American LNG capacity - while not itself the panacea of demand creation - will help rebalance regional imbalances and will furthermore facilitate broader adoption of natural gas end-uses on a global scale.

Without getting into specifics, I believe that demand growth upside potential may surprise even the most optimistic natural gas enthusiasts.

The confluence of increasing supply from both Western Canada and Appalachia competing head on at common market hubs indicates that the two supply gluts will merge to become one. The likely result is a continental super glut which could persist for years.

Given the sweeping context of the current imbalance, the recent showdown at the Dawn Terminal is nothing more than a formal declaration of a price war that began a decade ago between Western Canadian and L48 producers led by Appalachia.

The clear winners of the price war will be consumers. And if plentiful supply is indeed sustainable, national security interests could also benefit. The losers are clearly producers and transporters. Although midstream margins have held up quite well in the current downturn, that could change if and when stiffening competition compels marginal compression.

The irony of this assessment - that stiffening competition for market share which was lost due to lower prices is likely to result in even lower prices - is not lost on me. That low prices can lead to even lower prices seems contrary to conventional economic thinking that the solution for low (high) prices is low (high) prices. However, the mechanisms of classical economic equilibrium also must account for a potential demand response if and when prices get too low.

The potential for a demand response is a topic worthy of its own assessment. Please check back soon for a second installment on this topic.

Also, as assessment on the winners and losers of a natural gas super glut is forthcoming in a third installment. After all, the "so what" factor for investors is why you and I are here. Again, please check back soon for an update.

In the meantime, I intend to stick to the original plan of alternating between investing ideas and macro analysis. Readers have suggested that Advantage Oil and Gas (AAV) and Tourmaline Oil (OTCPK:TRMLF) may emerge as relatively well positioned due to their focus on liquids production. I intend to follow up with a formal assessment.

While I admit that my recent recommendation of Painted Pony Energy (OTCPK:PDPYF) is inconsistent with my fundamental views on Canadian natural gas markets, I maintain my original thesis that a long position in Painted Pony is justifiable as a very underpriced option which is levered to natural gas prices. Furthermore, even though Painted Pony may have emerged as a cyclically weak producer (due to its reliance on third-party processors and transporters), it excels at its focus on core upstream value-creating activities including regional specialization, developing immense growth potential, and low cost production. For these reasons, it is attractive both as a long-term hold and as a take-out target.

While I would love to reconcile my views on valuation and broader market forces, the reality is that when one identifies an underpriced security, one will usually find that it is underpriced for a reason (i.e., bottom fishing stinks).

I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it (other than from Seeking Alpha). I have no business relationship with any company whose stock is mentioned in this article.

Editor's Note: This article discusses one or more securities that do not trade on a major U.S. exchange. Please be aware of the risks associated with these stocks.
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