Stuck in the Middle - The Woes of Alberta Gas – Part 2

Alberta has a serious and still-growing problem with stranded natural gas. The volumes of gas piped east and south have been declining and the amount of gas stored in-province has risen to near-record levels, despite a widening discount to US Henry Hub spot gas prices making Alberta gas cheaper than ever. U.S. shale gas is largely to blame, but Alberta gas producers need more than a scapegoat, they need new markets—new ways to either use more of their gas closer to home or move it economically to the east and south or to buyers overseas. It won’t be easy. Today we look at potential new sources of demand.

In Part 1 of “Stuck in the Middle – The Woes of Alberta Gas,’” we examined how U.S. shale gas has displaced large volumes of western Canadian gas in markets from Maine to California. We also looked at how a new pricing structure for moving gas east from Alberta along TransCanada’s Mainline has exacerbated the problem. This time we look at possible fixes.

If Marcellus, Utica and Bakken were cool new names for movie-star offspring, and not game-changing shale plays, Alberta would likely still be the king of North American natural gas. With more than 1,800 Tcf in potential supply—most of it shale gas and coal-bed methane—the province could have enough gas to supply the U.S.’s entire requirements for the next 60 years or more. But booming production of U.S. shale gas has undercut Alberta’s traditional markets in Ontario, Quebec, the industrial Midwest and the increasingly gas-hungry Northeast, leaving Alberta gas with fewer and fewer places to go. If anything, Marcellus and Utica shale gas is only beginning to gain a stranglehold on many of the markets Alberta gas producers had been serving. Gas pipeline infrastructure is being beefed up around the eastern Great Lakes and into eastern seaboard markets to make gas from the Appalachian shale plays increasingly accessible to buyers there, undermining the economic case for bringing gas all the way from western Canada. And, as we said in Part 1, TransCanada’s new gas-transportation pricing construct - and its plan to convert part of the Mainline to a crude-oil conveyor—aren’t helping matters.

So, how can Alberta gas fight its way back to relevance? There are a few possibilities, but none is a sure thing. If there’s one that’s seen as a real savior for Alberta gas—particularly shale gas from the province’s vast Montney play (and the nearby Horn River/Liard basin in northeastern British Columbia)—it would be the development of a robust export market for liquefied natural gas (LNG) (see “More Than a Feeling? Is Canada’s LNG Export Plan a Pipe Dream?”). A major gas pipeline or two from these plays to BC’s northern coast, plus an increasing number of LNG export terminals there, would give Alberta (and BC) gas producers access to high priced Asia-Pacific markets. The export potential is significant; if the three LNG projects that already have secured export licenses from Canada’s National Energy Board are built and come online as scheduled, by 2020 the LNG equivalent of nearly 5 Bcf/d could be headed to Japan and other Far East buyers. But that’s unlikely. The NEB said in May that developers of LNG export facilities are having trouble lining up the gas buyers they need to move their projects from plan to reality. Also, there’s tough competition from U.S. gas eager to start exporting LNG through existing and planned terminals along the Gulf of Mexico. And Alberta could face competition from its north as well: Northwest Territories would love to tap its enormous oil and gas reserves and ship them directly to Asia.

You might be forgiven for thinking that one near term fix for economically stranded Alberta gas would be for TransCanada to ratchet down the prices it has been charging lately for Interruptible Transmission (IT) and Short-Term Firm Transportation (STFT) along its Mainline, the primary mover of western Canadian gas to eastern markets. Those current rates, which TransCanada put in place earlier this summer to reflect what it says is the true cost of providing IT and STFT services, have slowed the volumes of Alberta gas moving east to a trickle, and caused stored-gas volumes in Alberta to soar.  In the past, lower Mainline transportation costs have encouraged flows out of Alberta to the East into the Midwest and the Northeast. But lower rates are unlikely to delay the development of new pipelines that threaten to make those provinces and regions Marcellus-and-Utica-only zones. TransCanada can only do so much; it needs to make Mainline profitable, even if that means converting part of it to move crude oil to eastern Canada (see “Go Your Own Way—Alberta Rail Loading Terminals”).

Are there other possible outlets for Alberta gas? Yes, at least four. All involve existing and potential gas consumers within the province taking advantage of the price differential—that is, the markedly lower price--that stranded Alberta gas now provides. There is real in-province potential here: Alberta is not only the largest gas producer in Canada, it’s also the nation’s largest gas user, and it’s expected to remain that way for the foreseeable future (see Figure 1).