After half a century as a mainstay of markets across Canada and the United States, Alberta’s role in North American natural gas will wane rapidly, says the province’s Energy Resources Conservation Board (ERCB).
Less than 20% of Alberta production will be available to out-of-province buyers by 2021, the ERCB predicts in an annual state-of-the-industry report released Wednesday. Shrinkage in the province’s role as a supplier emerged as a clear trend over the past five years, according to the 290-page document. Until five years ago, Alberta’s gas sales to the United States and the rest of Canada hovered at 72-75% of production. As of 2011, the share of production available to buyers outside the province’s borders dropped to 58%.
“In 2011 about 42% of Alberta production was used domestically,” the ERCB reports. “The remainder was sent to other Canadian provinces and the U.S. By the end of the forecast period  domestic demand will represent 81% of total Alberta natural gas production.”
The shrinkage is attributed to depletion of aging wells, reduced drilling of replacements and rising industrial consumption in the province, led by expanding thermal production projects in the northern oilsands and related gas-fired power plants. After peaking at about 14 Bcf/d in 2001 Alberta gas production hovered in a range of 12.5-13 Bcf/d for six years, ERCB records show.
A pronounced decline set in during 2008, when the Alberta industry switched drilling targets to oil after prices fell on glutted gas markets across Canada and the Lower 48 states. As of 2011, production in the province had shrunk to about 10 Bcf/d. By 2021, the ERCB predicts that output from the conventional, naturally flowing reserves that still account for almost all the province’s supplies will slump to 6.7 Bcf/d.
The only unconventional gas resource tapped to date on any significant scale in Alberta — coalbed methane (CBM) — remains relatively small and is also headed for shrinkage as a victim of glutted markets and poor prices, the ERCB reports. As of 2011 the province’s CBM production was about 840 MMcf/d, only down marginally from a peak in 2008-09 before the gas markets turned soft. By 2021, thanks to weakening field activity resulting from the current prolonged spell of poor prices, CBM output is expected to dwindle to 550 MMcf/d.
TransCanada Corp., its Mainline pipeline from Alberta to Central Canada and U.S. export connections, and the system’s shippers continue to stand out as the worst sufferers from the shrinkage of the province’s role as a national and international supplier. The headache has become more severe than expected, TransCanada senior pipeline executive Karl Johannson disclosed during hearings on a proposed restructuring of the gas transportation business before the National Energy Board (NEB).
Details are to be revealed by a new “corporate throughput forecast” scheduled to be presented to the industry and the NEB in July. However, the outlines are already clear. After falling below half of the Mainline’s capacity to transport about 7 Bcf/d, Alberta-sourced gas shipments show no sign of recovering and appear likely to keep on shrinking.
New shale gas supplies emerging in northern British Columbia (BC) are no longer expected to make up for the Alberta traffic losses. Much of the BC growth is earmarked to supply liquefied natural gas (LNG) export terminals developing on the Pacific Coast around Kitimat. The result is steeply increasing tolls on TransCanada’s gas transportation system, thanks to the Canadian regulatory practice of letting pipelines keep on collecting a revenue requirement to maintain profitable operations if traffic volumes drop.
The worsening excess capacity plague has already more than doubled tolls. TransCanada’s benchmark Mainline Eastern Zone Toll (EZT) for shipments from Alberta to Ontario and U.S. export points went from C$1.03/gigajoule (GJ) (US$1.08/MMBtu) in 2007 to C$1.40/GJ (US$1.47/MMBtu) in 2008, temporarily recovered part-way to C$1.19/GJ (US$1.25/MMBtu) in 2009, but resumed jumping to C$1.64/GJ (US$1.72/MMBtu) in 2010 and C$2.24/GJ (US$2.35/MMBtu) in 2011.
The prospect of continuing slow traffic on the Mainline — and the resulting perpetuation or even worsening of toll inflation — is keeping fires burning under a months-long regulatory duel between TransCanada and its shippers before the NEB (see Daily GPI, Sept. 26, 2011). In its business restructuring application to the NEB last fall, TransCanada set its sights on cutting the EZT back down to about C$1.40/GJ (US$1.47/MMBtu).
However, the scheme drew from Alberta gas producers and the provincial government because the savings largely were to be achieved by redrawing the pipeline map rather than cutting costs. The restructuring calls for a transfer of parts of the Mainline over to TransCanada’s Nova grid, previously just an Alberta network, for purposes of revenue and tolling regulation (see Daily GPI, June 4; March 26). The result works out to about a 25% increase in Nova tolls, or a surcharge of up to US$400-500 million a year, according to the Canadian Association of Petroleum Producers.
TransCanada’s forthcoming new forecast would increase projected tolls by about 30% even on the shortened Mainline, Johannson told the NEB. TransCanada has yet to reveal whether the lowered traffic expectations are liable to generate a further hike on the Nova network too.
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