Alberta has vast reserves of natural gas, and for years the gas produced there found ready, steady markets in Ontario, Quebec and the U.S. Midwest, Northeast and West. Recently, the traditional buyers of Alberta gas have been turning to other suppliers and an increasing share of the province’s production is stranded in Western Canada. This has resulted in sharply higher gas inventories in Alberta, lower prices for the province’s gas, and high discounts relative to Henry Hub, LA prices at Alberta’s gas hub, AECO. Today we examine the factors behind this quandary.
Alberta’s gas reserves are enormous: an estimated 33 Tcf of conventional gas, up to 500 Tcf of coal-bed methane gas, and up to 1,291 Tcf of shale gas, though it remains to be seen how much of that unconventional gas can be economically produced. Alberta accounts for more than 70% of Canada’s gas production, and more than 90% of Alberta’s gas comes from vertical wells. That is expected to change as the major shale plays in the province shift from exploration to production, but decisions on investing billions of dollars in unconventional gas production, new pipelines and the like will hinge on finding markets for that gas.
For as long as anyone in the North American gas business can remember, most Alberta gas has flowed east and south, much of it to Ontario and Quebec, Canada’s economic powerhouses, and to gas consumers south of the border, in the industrial Midwest and the Northeast. Some also flowed southwest, to California, and some remained in-province for a mix of uses: primarily power generation and industrial consumption, but also for residential and commercial space heating. Gas consumption within Alberta is expected to grow, particularly in the oil-sands region, which uses large volumes of gas to enhance heavy oil recovery. However, future growth in Alberta gas production depends largely on finding new buyers, not just elsewhere in North America but overseas, particularly to Asia in the form of LNG (see Lonely Gas Surplus Seeks Long Term Overseas Relationship).
All seemed to be going reasonably well for Alberta gas producers until the shale-gas revolution. Over the past five years, however, more and more gas buyers in the traditional markets for Alberta gas have switched to U.S. shale gas supplies--from the Marcellus and Utica plays in particular--and several new pipelines now under development will give U.S. producers enhanced access to those consumers. With low-cost gas from Marcellus and Utica now pushing into eastern Canadian markets and pushing imports back at Midwest border crossings, net Canadian exports to the U.S. fell to only 5.4 Bcf/d in 2012, down 45% from their 2002 peak of 9.9 Bcf/d. That downward trend will only continue; Bentek forecast Canadian gas exports to the U.S. falling to 3.1 Bcf/d by 2018. Lower exports mean oversupply in Canadian markets, oversupply means lower prices and lower prices translate directly to lower production. Canadian gas production has fallen from 17 Bcf/d in 2000 to 13 Bcf/d this year, and it’s expected to remain flat for years to come.
As if the market-share challenge posed by U.S. shale gas weren’t enough, there is a new transmission pricing structure for TransCanada’s Mainline, the inter-provincial pipeline that runs from eastern Alberta to Montreal, and it does not appear to be helping. Gas movement along the Mainline also had been falling; it averaged 3.9 Bcf/d in the first half of 2013, down from 4.4 Bcf/d in the same period last year. In May, Canada’s National Energy Board approved changes to the Mainline’s toll structure in an effort to increase the competitiveness of the pipeline. The new structure set a lower fixed toll on firm transportation from Empress, Alberta, to Dawn, Ontario, at C$1.42/GJ through 2017, or C$1.16/GJ less than the old price, but it allows TransCanada to set the prices for Interruptible Transmission (IT) service and Short-Term Firm Transportation (STFT).
The more attractive firm transportation pricing, which took effect July 1, 2013, in only a month has enabled TransCanada to nearly double the volume of Western Canadian gas it moves under one-to-three-year firm tolls; Mainline was moving 1.1 Bcf/d under firm-transportation agreements before the toll change a few weeks ago, and is moving 2.1 Bcf/d that way now. (Many of the new contracts have been for pipeline capacity from Empress, Alberta, to Emerson, Manitoba, where Mainline meets up with TransCanada’s Great Lakes Gas Transmission pipeline; that suggests that much of the gas moving under the new firm transportation tariff is headed for the Midwest and the Dawn hub in Ontario.)
But TransCanada’s IT and STFT rates are currently set at 220% and as-much-as-1,200% premiums, respectively, over the firm transportation rate. That has slowed to a trickle the volumes of western Canadian gas moving east under interruptible or short-term firm transportation tolls.
With tougher competition from U.S. shale gas producers and the new Mainline price structure, an increasing share of the gas produced in Alberta this summer is being stored in-province. Inventories in July were at record levels, up 25% from the five-year average for the month, and at about 95% capacity at the beginning of August. And, with less Alberta gas moving east, storage levels at Dawn, Ontario, in July were 36% lower than the five-year average for the month, at only 42% of capacity.
Markets have a way of responding. The spot price for gas at AECO—Alberta’s gas hub, with storage capacity of 154 Bcf-- has almost always been a tad lower than that for gas at Henry Hub (see Figure 1). But the differential between the two has been widening, and lately the gap has become substantial. At the start of December 2012, the differential was about 30 cnts/MMBtu; now it’s about $1MMBtu (see Figure 2).