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Arctic natural gas vital ingredient TransCanada CEO certain about need for northern gas within a decade; estimates Alaska project could be built for $3-$4 per mcf Gary Park For Petroleum News
TransCanada is a great believer in the need for gas of all kinds, not least from the Arctic, to meet long-term North American demand, but is also dropping some warning markers on how far its patience will extend with the Mackenzie Gas Project.
The obvious candidate to deliver gas from the Mackenzie Delta to northern Alberta, TransCanada said Nov. 3 that it is close to reassessing its role as banker for the Aboriginal Pipeline Group, which hopes to secure a one-third equity stake in the pipeline, if the project goes ahead.
TransCanada noted it has already advanced C$145 million to the APG to cover the group’s share of regulatory costs.
Chief Executive Officer Russ Girling told analysts that TransCanada and the other co-venture companies — Imperial Oil, Shell Canada, ConocoPhillips Canada and ExxonMobil Canada — are hopeful the National Energy Board will “come to a positive conclusion,” when it delivers its final verdict on the MGP application by either late this year or early 2011.
If the verdict is positive, all the stakeholders “have to sit down and determine when that gas will be economic to bring to market and when to make the investments,” Girling said. “Stay tuned.”
The company said the project timing after the NEB decision “continues to be uncertain.”
“In the event the co-venture group is unable to reach an agreement with the (Canadian) government on an acceptable fiscal framework, the parties will need to determine the appropriate steps for the project,” it said.
“For TransCanada, this may result in a reassessment of the carrying amount of the APG advances.”
Gas prices, US economy Girling also said that depressed gas prices and the depressed state of the United States economy will affect the timing of any gas pipeline out of the North Slope to the Lower 48.
However, he said 2018-20 is the “probable time frame driver” for all of the large companies that are in Alaska, based partly on expectations that North American gas consumption could rise from 80 billion cubic feet per day currently to 90 bcf or greater in another 10 years.
Also influencing decisions on Arctic gas is the annual decline of 15-20 percent in conventional production rates, meaning a replacement of about 15 bcf per day is needed “just to stay even,” he said.
Girling said that outlook accounts for the proliferation of new shale gas production, although the Barnett shale in Texas ramped up very quickly to 5 bcf per day and “appears to have leveled out.”
He noted that the decline rate for shale gas is “pretty steep in the first couple of years, once you reach a run-rate production level.”
Construction at $3-$4 per mcf Over the next decade, he said the continent will need conventional gas, shale gas and no0rthern frontier gas, with Alaska as a primary driver given that a current reinjection rate of 7-9 bcf per day means there are no additional development costs associated with developing the state’s gas resources.
Girling estimated a processing plant and pipeline to get Alaska gas to market could be built at a cost of $3-$4 per thousand cubic feet.
“So if you can land that gas in a $5 market you’re getting a $1 netback, which would make the project economic even in the current market,” he said, estimating it would take seven to 10 years to get through the regulatory process, design and build the necessary facilities.
Girling said large companies, rather than basing their decisions on today’s spot prices, are evaluating where the market is likely to be in another 10 years. “If you want to hit that date, you have to start working today.”
Shale outlook not certain The importance of Arctic gas over the long term is even gaining added momentum from its supposed competition from shale gas.
The less-than-certain outlook for shale gas, despite its immense contribution to gas resources (it has tripled Canada’s potential to 300 trillion cubic feet), has been reflected lately in British Columbia’s sizzling Horn River shales, where large operators have responded to prospects of prolonged depressed gas prices by slowing their activities.
For TransCanada, unconventional gas underpins its hopes of carrying an additional 2 billion cubic feet per day by 2014, offsetting most of the projected decline in conventional production for its mainline system.
It already has strong commitments for its Groundbirch line (capacity of 1.1 bcf per day from the Montney play), Horn River (540 million cubic feet per day from Horn River) and Bison (400 million cubic feet per day from northern Alberta).
But key operators in Horn River are showing their edginess by either cutting back spending plans for 2011, or reviewing their budgets.
CNQ pulling back Encana, Canadian Natural Resources (CNQ), Talisman Energy, EOG Resources, Apache and Devon Energy have all started pulling back from the basin without actually shutting down operations.
CNQ, which led the Canadian industry by shutting in volumes ahead of the price downturn two years ago, will direct most of its scaled-back gas spending in 2011 to preserving land tenure, said President Steve Laut.
“We believe shale gas production is real and it looks like shale gas reserves are real, but we don’t think that’s for sure yet,” he said. “Shale gas might work at prices of $4 (per thousand cubic feet) but maybe only in the sweet spots and maybe only in the liquids-rich areas,” where producers can sell gas liquids for $40-$50 per barrel.
Laut said CNQ can afford to hold its vast land base, with 8,000 drilling locations, until gas prices rebound. Neither will it ignore acquisition opportunities that can reduce operating costs once the assets are integrated into the portfolio. So far this year, the company has bought properties yielding 214 million cubic feet per day of gas and 9,000 barrels per day of liquids.
But the company will continue to lower its output from a current 1.285 billion cubic feet per day in 2011 and beyond during the low-price environment, which Laut believes could last another three to seven years.
Ditto for Talisman, Encana Similarly, Talisman is taking a less aggressive approach to its shale gas except in its newly acquired stake in the Eagle Ford play of south Texas, where a high liquids content makes gas production profitable.
Chief executive John Manzoni believes it could take the North American gas market another year to “rebalance.”
For now, he said an announcement is imminent on a “strategic” partner to share the costs of developing Talisman’s “very large shale resources” in British Columbia.
Encana chief executive Randy Eresman said Canada’s largest gas producer is slowing the near-term growth rate of its resource plays and expects to shortly offer asset packages for farm-in deals, even though he is unsure about prospects of a firm joint-venture deal with China National Petroleum Corp. for British Columbia.
Also US-based operators The three dominant U.S.-based operators in British Columbia are all in a rethinking mode as they prepare 2011 budgets.
EOG chief executive Mark Papa said his company has a “good feel” for reserves and production potential for Horn River, but will take a “minimalist approach” to spending because of “very dismal North American gas conditions.”
Apache chief executive Steve Farris said the C$370 million his company has spent in Horn River this year showed the reservoir was up to expectations, bringing 18 wells into production this year and scheduling another 12.
“Now it’s a question of how do we balance our current capital against future opportunities,” he said. “That’s one of the hardest things we’ll have to decide in 2011.”
Devon Executive Vice President Dave Hager said minimal capital will be invested in Horn River next year because the basin’s dry gas offers no liquids returns, but insisted the producing wells are performing “better than expected,” indicating ultimate recovery of about 8 bcf per well.
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