Gas Revolution No. 2: Canadian Shale

May 2010 Vol. 237 No. 5

Gary Park

Some of the world’s largest oil companies are reinforcing analyst claims that Canada’s Horn River and Montney shale and tight gas formations have the potential to revolutionize that country’s gas future. A glut may be in the offing, but investors appear confident that gas will push aside coal in the U.S. power sector. Plans are even afoot that would see Canada join the ranks of the world’s LNG exporters.

There’s no shortage of executives from companies such as EnCana, Imperial Oil, Apache, Nexen, EOG Resources, Canadian Natural Resources and Talisman Energy ready to spread the message that Canada’s Horn River Basin could develop into North America’s best shale gas prospect yet, surpassing the Barnett, Haynesville, Fort Worth, Fayetteville and Marcellus plays of Texas, Louisiana and Pennsylvania. It is also attracting interest from majors. ExxonMobil – operating through its Canadian units – paid C$113 million ($106.3 million) in mid-2009 for eight Horn River licenses and quickly stirred interest when reports circulated of two major finds.

Just as in the U.S., Canadian shale gas is emerging as a “game changer” for gas supply on the North American continent. It has implications for LNG import demand – and potentially LNG exports – for coal-to-gas switching in the U.S. power sector and the timing of Alaskan and Arctic gas development. Even the most conservative shale resource estimates have prompted some experts to suggest that spending at least $58 billion on developing Alaskan North Slope and Mackenzie Delta gas will be pushed back 15 years or more from the projected start-up dates of 2015-2020.

Canada’s National Energy Board predicts that by 2020 shale and tight gas production will propel national output to 21 Bcf/d from 16.2 Bcf/d. BMO Capital Markets estimates that Horn River production alone could exceed 4 Bcf/d by 2015.

This contrasts with a much less optimistic short-term outlook. With conventional reserves in steep decline, 2 Bcf/d of new gas is needed annually just to hold the line, according to industry consultant Ziff Energy Group, which takes a more pessimistic view than other forecasters. Ziff Energy predicts that total gas output in the Western Canada Sedimentary Basin, the mainstay of Canada’s gas industry, will drop below 14 Bcf/d by 2020 from the current 16.2 Bcf/d, 70% of which is exported to meet 16% of U.S. demand.

The NEB estimates deliverability of Canadian gas will shrink by 9% a year over the next two years, despite an increase in gas drilling investment from C$5.76 billion in 2009 to C$8.51 billion in 2011 and an increase in gas-targeted wells from 4,170 to 6,495. Although lagging far behind the 2008 peak of C$12.89 billion on drilling and 10,179 wells, the short-term trend reflects Canada’s struggle just to slow the rate of decline. Over the next five to ten years, shale gas could turn that outlook around 180 degrees.

Reserve Estimates Balloon
Despite an exploration and development effort that has barely scratched the surface and the still-evolving use of horizontal drilling and hydraulic fracturing technologies, the guesswork on how much gas might be trapped in British Columbia’s shale gas deposits has attained stratospheric heights.

British Columbia’s Ministry of Energy, Mines and Petroleum Resources pegs the province’s shale gas potential at 500-1,000 Tcf, with an undetermined recovery percentage. In contrast, the Canadian Association of Petroleum Producers estimates Canada’s current proven conventional gas reserves at less than 60 Tcf.

According to a National Petroleum Council Global Oil and Gas Study published in 2007, but based on earlier data, for wells drilled in the U.S. Barnett shale, the per-well recovery factor averaged 7% of the gas in place, far below a potentially achievable 20%. However, recovery rates have risen since then, although they depend on a number of factors, not least the shale’s unique properties and the methods used to extract the gas. But even at a 15% recovery rate, assuming the low 500 Tcf end of the Ministry’s estimate, British Columbia’s shale gas alone would more than double Canadian gas reserves.

“There’s no question that it’s an elephant,” said Jim Artindale, vice president of an EnCana business unit in northern British Columbia, speaking of Horn River. “How big the elephant is has yet to be determined.” EnCana, an early pioneer in shale gas extraction, has snapped up more than 1 million acres of lease rights and teamed up with Apache in a substantial joint venture.

Enduring Gas Play
Canada has never seen anything to match the scramble for exploration rights in British Columbia’s shale and tight gas regions, where about C$6.3 billion has been spent on government-auctioned land in the last six years and billions more are going into exploration and development programs. The spending is a clear signal that producers believe in the long-term demand for gas, despite current weak prices.

The NEB forecasts that E&P companies will divert an increasing share of their spending from conventional and coal bed methane plays to tight and shale gas, which may accelerate the potential decline of more traditional resources. It expects the number of Horn River shale wells to rise from 40 in 2009 to 145 in 2011 and Montney shale wells to grow from 245 in 2009 to 278, making no allowance for the rapid acceleration of fracture intervals in single horizontal wells from an average of eight to 18.

Further proof of where North America’s gas sector is heading occurred in December when ExxonMobil, in bidding $41 billion for unconventional gas independent XTO Energy, declared gas would be the fuel of choice in North America by 2030, shunting aside coal and oil.

ExxonMobil CEO Rex Tillerson conceded the risks associated with absorbing XTO. “We’ll probably suffer in the near-term as we put it together,” he said. “This is really about value creation over the next many years. This is about the next 10, 20, 30 years.” ExxonMobil has set its course based on its own view, arguing unconventional gas supplies are expected to satisfy more than 50% of gas demand by 2030.

Larry Nichols, chairman of Devon Energy and chairman of the American Petroleum Institute, is on the ExxonMobil bandwagon, insisting that no matter what legislation the U.S. government might adopt to regulate carbon, “we will need a growing amount of electricity and natural gas is in an excellent position to capture a significant amount of that market.”

Interest Widens
Over the past year, the North American-based proponents of unconventional gas have been joined in the U.S. and Canada by BP, Shell, StatoilHydro, Eni and Taqa North (a subsidiary of the Abu Dhabi National Energy Company). They have invested billions in assets to answer the call by their shareholders to build reserves and production.

Taqa Managing Director Frederic Lesage said his company – which has spent C$7.5 billion on Canadian takeovers and paid C$63 million for two Horn River blocks – said the shale play is targeted as “one of our largest drilling programs over the next five to 10 years.” Taqa has also obtained 75,000 Mcf/d of space on the 1.2 Bcf/d Alliance pipeline from northern British Columbia to Chicago, which Alliance has said it is prepared to expand by 300,000 Mcf/d to handle volumes from Horn River and Montney.

Although the heaviest concentration of activity is in the Horn River and Montney basins, there are early signs that companies, including Apache, EOG Resources and Questerre Energy, are moving into new, potentially very attractive areas. The Liard basin, also in British Columbia, has attracted about C$50 million in land acquisitions over the past year, doubling the average price to C$1,500 per hectare and prompting a spokesman in the British Columbia Energy Ministry to suggest the basin is a “sleeping dog” that is being quietly aroused by some low-key exploration programs.

Quebec also holds significant promise. A Canaccord Adams equity research report said the participation of Talisman Energy and Forest Oil in probing the Utica shale of the St. Lawrence Lowlands improves Quebec’s chances of becoming commercial in the next few years. Netherland, Sewell & Associates, a Texas-based consulting firm, estimated the Utica deposit could hold 150 Bcf per square mile, 66% more than any previous calculation. Questerre Energy CEO Michael Binnion, whose company has estimated its own recoverable resources at 2.2-8 Tcf, said the consultant’s report is supported by “significant and material data” that relates only to lands that “have geology validated by successful wells.”

It is technology, pioneered by independents, that has allowed shale gas to emerge over the past decade. Michael Mazar, an oil and gas analyst with BMO Capital Markets, estimates that advances in technology have lowered the break-even price to drill in Horn River by C$1.00/Mcf in the past year alone to C$5.05/Mcf, raising his estimate of recoverable gas in the basin to as much as 50 Tcf from 250 Tcf of original-gas-in-place, a recovery rate of 20%.

BMO calculates that the average Horn River well costs C$9 million and finding and development costs are C$0.98/Mcf, with wells yielding an average 10 Bcf. Based on those numbers and assuming a gas price of C$6.00/Mcf, the after-tax internal rate of return would be 21%, according to BMO.

Risk Factors
Whatever the accuracy of the studies, years of anxiety about gas supply shortages in North America have given way to concern about insufficient demand. The long-held view that the U.S. would depend on imported LNG to cover its shortfalls has been discarded. “We need LNG like a hole in the head,” said Steve Letwin, executive vice-president at Canadian pipeline company Enbridge. “The biggest issue we now have is insufficient demand. And, in the absence of demand, you are going to see a price for gas that will be stuck between $5.00-$7.00/Mcf for a long time to come.”

Enbridge has already been awakened to this prospect when it failed to attract enough producers willing to make 20-year commitments for a $1.5 billion LaCrosse pipeline linking shale gas producers in Texas and Louisiana to the U.S. Southeast to serve as feedstock for new power plants. It has also stalled progress on its proposed Rockies Alliance pipeline from the U.S. Rocky Mountain region to Chicago markets, unable to attract 1.5 Bcf/d in 15-year shipper commitments. Both are on the “backburner for the time being,” until confidence returns to the market, said CEO Pat Daniel.

Despite a high level of producer support for feeding gas into the North American transportation network, pipeline companies are taking a cautious approach. TransCanada has delayed by at least one year to mid-2012 its plans to build feeder pipelines to handle at least 378,000 Mcf/d, and is sidestepping any forecasts for moving ahead with links for up to 1 Bcf/d from both Horn River and Montney. Spectra Energy is also keeping a low profile on its plans to carry 260,000 Mcf/d from the region.

The potential lack of North American demand has prompted one of the most daring ventures to date, spearheaded by Apache – a joint-venture partner with EnCana in Horn River. In order not to be held hostage to the domestic market, Apache has taken over the lead role in Canada’s first proposed LNG export project. The big U.S.-based independent has acquired, for an undisclosed sum, 51% of the Kitimat LNG project which is designed to ship 750,000 Mcf/d of LNG to Asian markets by 2014.

According to Apache’s Canadian president Tim Wall, the company’s “investment in Kitimat LNG demonstrates our long-term commitment to the resource development in Canada and in particular in British Columbia.” He said development of Horn River along with the Marcellus shale play in Pennsylvania sets the stage for a gas surplus in North America.

Wall argues that Kitimat LNG will provide producers in Canada with secure access to key worldwide markets. Irene Schmaltz, Kitimat LNG’s vice president of supply marketing, said exports will enable producers to “include LNG into their portfolios. It will help stimulate the development of gas reserves in Canada. For end users, it’s a new source of supply for them. They like that. They want to diversify their supply source and, from a political point of view, they consider Canada very low risk.”
EOG Resources has also signed a memorandum of understanding to contribute 100,000-200,000 Mcf/d of Horn River gas to Kitimat. Spain’s Gas Natural and Korea Gas have signed tentative deals to take unspecified volumes of the LNG.

However, not all of Canada’s gas players are sold on the notion of LNG exports. A warning note came from Russ Girling, chief operating officer of TransCanada, who said producers shipping gas to the British Columbia coast would need a netback higher than C$9.25/Mcf, assuming a wellhead price of C$5.25/Mcf, C$1.00/Mcf for pipeline transportation to the Kitimat port and C$3.00/Mcf for liquefaction.

In contrast, he said, a shipper seeking access to the Alberta gas hub and Canadian mainline would have combined costs of only C$1.85/Gigajoule (C$1.76/Mcf). TransCanada CEO Hal Kvisle said Kitimat proponents are targeting gas prices of $15/MMBtu ($15/Mcf) from Asian buyers. “If I was a Japanese utility buyer I would be asking why I should pay that price. The world has changed. There’s now lots of LNG out there.”

Further risk comes from environmental objections, most notably the issue of water supply and disposal. Now that rights to most of the leading shale prospects have been secured, companies are turning their efforts to drilling and finding ways to obtain large volumes of clean water for well fracturing – estimated at 1.5 million gallons for a single fracture – as well as disposing of the water produced from the wells.

Supported by a C$5.7 million British Columbia government grant, 11 of the 13 companies in the Horn River Basin Producers Group and government scientists, are engaged in a C$15 million joint study of sub-surface aquifers over the entire basin as they try to head off growing environmental opposition to shale development.
However, despite these obstacles, companies are still rushing to invest during a period of low prices brought about by the impact of recession on demand, and the success of unconventional gas supply in the U.S. This appears to be a long-term strategy as margins appear relatively thin in the short term. But in a carbon-constrained world, natural gas would appear to have much better prospects than its dirtier rival coal, particularly in the power sector. The not unreasonable belief is that demand will follow low prices, while on the supply side the hope is that the U.S. revolution in unconventional gas can be replicated in Canada.

Editor’s Note: Gary Park is a correspondent for Platts, a leading global energy information provider and a division of McGraw-Hill. This article was originally published in Platts’ Energy Economist.

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