A summer of discontent for natural gas

By D. Mason Granger | June 24, 2016 | Last updated on June 24, 2016
5 min read

There have been encouraging signs in the North American natural gas supply picture of late. In fact, U.S. natural gas prices are continuing to firm up after plunging to a low of US$1.61/MMBtu in early March.

Investor sentiment towards natural gas has been improving, as major shale gas plays in the U.S. have seen production levels rolling over in the face of reduced capital budgets, as well as slowing industry activity due to weak energy commodities. Growth in production has also been a byproduct of oil drilling activity, which helps explain the disconnect between overall gas production levels and the gas rig count. We believe that associated gas production from the shale oil plays has peaked and is now in decline due to a sharp drop in drilling.

And that’s why, despite recent investor interest in the prospects for natural gas, we caution that all natural gas isn’t created equally. Canadian natural gas is fraught with its own challenges going into the summer months.


Canadian natural gas inventories are extremely high. In Western Canada, the problem is particularly acute with inventories at levels that are where they’d typically be going into colder, high-demand months. That’s too high. Once there isn’t a place to physically put the gas, what is it priced at? Hint: zero.

Another problem: analysts predicted we’d reach full storage by July, but said so before the Alberta wildfires. Those fires effectively sidelined about 1.0 bcf/day of natural gas demand from the oil sands, which were proactively taken offline out of concern for fire damage. This could not have come at a worse time for the embattled Canadian energy sector.

This race-to-the-bottom scenario has some important implications. The NYMEX quote for U.S. natural gas may seem to be benefitting from a recovery this year. After all, production is declining in major plays, and the price-insensitive associated gas from the enormous growth in shale-oil development has had the brakes slammed on it. The focus should be on the differential between the Canadian AECO benchmark and the U.S. NYMEX benchmark, or the so-called basis differential (see Chart 1, below). Eastern Canada can accommodate some of the surplus production. However, we estimate that storage would also reach capacity in Eastern Canada by the end of the summer (see Chart 3, below). This suggests that Canadian natural gas prices could come under further downward pressure this year.


The Marcellus vs. Western Canadian gas

The concern about Canadian natural gas is its location in Alberta and B.C. There are tolls to transport natural gas to the voracious consuming markets in Eastern Canada and the northeastern U.S. Chart2-Western-Gas-transmission-overviewUnfortunately, support for large scale Liquefied Natural Gas (LNG) terminals to provide access to Asian markets and diversify our customer base for Canadian gas appear to have diminished somewhat, particularly since the wonderful arbitrage opportunity between Asian natural gas and the depressed pricing in North America has largely been diminished.

The Marcellus and Utica shale plays in the U.S. present a significant challenge for Western Canadian natural gas. Not only are the two super-giant shale fields a massive source of low-cost natural gas, they are geographically on the doorstep of key markets in the colder, highly populated northeastern U.S. What’s more, incredible advances in U.S. technology have seen the Marcellus grow from 2.7 Bcf/d in 2010 to 19.4 Bcf/d in 2015.

Chart 4, below, shows the increases in productivity per rig. The disconnect between the rig count and production levels is in part due to increased drilling efficiency, high grading of locations, longer laterals and higher intensity fracks. This has been especially evident in the Marcellus. Regardless of the moderation of growth in Marcellus production recently, there is no denying that the play has a structural advantage over Canadian gas. We have long been concerned that abundant and cheap Marcellus and Utica natural gas would spill over into the Ontario market, which would affect western producers. And it’s already happening. On March 31, 2016, Enbridge told TransCanada that it had chosen to convert approximately 200,000 GJ/d of its long-haul shipping contracts on the mainline system to short-haul contracts from the Chippawa and Niagara, Ont. hubs. As such, Enbridge is now sourcing natural gas from the Marcellus instead of Western Canada to meet Ontario-based demand. This shook gas markets, and AECO spot pricing plunged by 22% overnight as a result of this announcement. Chart3-Canadian-natural-gas-storage Chart4-Natural-gas-production-per-rig

Market access

Rapidly growing gas supplies from the Deep Basin and Montney plays in Western Canada also appear to be overtaking gas transmission capacity from the Western Canadian Sedimentary Basin (WCSB). If development of Canadian gas from these nascent plays continue at the current industry-planned pace, it’s likely to lead to producer-led shut-in volumes. And further depression of AECO and upstream natural gas pricing is likely to occur and last for the foreseeable future. We’ve increasingly heard stories of producers opting to shut in volumes voluntarily, versus actually paying someone else to take their gas.

Investors should be asking questions about the pricing that producers get and where custody of natural gas changes hands (see Chart 2, above). If the producer is in B.C., do they have exposure to the volatility we have seen around the key B.C. pricing hub known as Station 2? Do they produce into the AECO system and face risk from a potentially full storage condition this summer? Does the company have firm service arrangements, or do they have pipeline access on an interruptible basis that may impair their ability to produce gas?

For instance, the red line on Chart 2 shows the Alliance Pipeline System, which operates within B.C. and Alberta and flows across the U.S. border, with delivery to Channahon (just outside Chicago, Ill.). This system has capacity to transport approximately 1.7 Bcf/d, is fully contracted long term and just completed re-contracting on December 1, 2015. This is particularly relevant because companies that have struck deals with Alliance in many cases may be getting Chicago Citygate pricing, and reduced exposure to what could prove to be rather extreme pricing volatility this summer. We highlight companies like Crew Energy Inc. and Seven Generations Energy Ltd., which are new service shippers on Alliance and have 100 MMcf/d and 500 MMcf/d, respectively. In addition, investors should focus on natural gas companies that have strong balance sheets, particularly those able to weather the storm this summer. We prefer companies that have significant hedges in place to support cash flows, assets that are on the right end of the cost curve for natural gas, and a significant amount of higher-value liquids to bolster economics. ARC Resources Ltd. stands out as such a company that will not just survive in this environment, but thrive.

by D. Mason Granger, P.Eng., MBA, CFA, is a portfolio manager in Toronto.

D. Mason Granger