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Featured Articles
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Feb 2010
| Source: Oilweek Magazine
| | | All knotted up
| | | As Canadian gas production slips, exports to the United States are
| | | by R.P. Stastny
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| Western Canadian natural gas production enjoyed historic highs throughout the early years of the last decade and, not surprisingly, gross export volumes to the United States followed in kind. Exports peaked in 2007 at just over 10.4 billion cubic feet (bcf) a day, but then followed production declines. Analysts now expect that downward trajectory to continue even if gas production makes a comeback. The reasons are anything but simple.
At one time, natural gas forecasters would look to weather, storage levels, and North American production levels for clues. Today, a host of other significant factors need to be considered: the pace of the U.S. economic recovery, the rate of shale gas declines, the extent of the U.S. gas drilling slowdown, how much Canadian natural gas is diverted to the oilsands, the price of liquefied natural gas (LNG) imports versus Canadian gas prices, and the fluctuations of currency exchange rates.
Other considerations will also impact Canadian gas exports: TransCanada PipeLines´ pending mainline toll increase, the impact of additional volumes of natural gas to the U.S. Midwest through the newly completed Rockies Express pipeline from Montana to Ohio, the extent of power switching from coal to natural gas in both the United States and Canada, further royalty adjustments or drilling incentives in Alberta or British Columbia, the effect of service cost deflation on drilling activity levels, and how aggressively major players step up development in the Montney and Horn River shale plays. (Devon recently traded its international plays in favour of North American gas, while ExxonMobil and Imperial Oil increased their respective land holdings in those two northeast B.C. areas.)
There remain still more long-term variables driving Canada´s gas exports: the timing of Arctic pipeline approvals; the emergence of new technologies with potentially step-changing impacts such as multi-stage fracing of horizontal wells or the unlocking of methane hydrates; the ultimate accuracy of shale gas reserves estimates; and a host of potential-but unpredictable-environmental, legislative, or geopolitical changes.
Forecasting today is like navigating through a fog, fraught with uncertainty, even humbling to many who make it their life´s work.
"There was a time when I thought I understood all this," says Dave Russum, vice-president of geoscience for AJM Petroleum Consultants. "When I was younger, I felt like I could read the trends and predict what was going to happen. But as it becomes more and more complex, I think it´s the unexpected factors that´ll have the biggest impact."
By this, he means the hurricane that wipes out a portion of production in the Gulf of Mexico, or a financial meltdown that slams the world into a recession. So rather than pulling numbers, Russum simply says that natural gas exports are likely to decline in coming years.
"The biggest factor right now," he says, "is how quickly the U.S. comes out of recession, boosting industrial demand."
Russum also puts a lot of stock in the environmental factor. Large-scale switching from highly polluting coal to natural gas power generation has the potential to make a real impact on natural gas demand in North America.
As for whether stronger natural gas prices will improve Canadian gas exports, he isn´t so sure. This is because the United States, in his estimation, has a greater capacity to ramp up its natural gas production than Canada. So any increases in commodity prices will be met by an uptick in U.S. drilling, quickly depressing prices again.
"So logically [Canadian gas exports] will be coming down," he says. "The volume of gas we´re producing in Canada and certainly in Alberta is going to slip. I think even the growth in B.C. will be inadequate to make up the slide in Alberta gas production. The consumption in the oilsands and the conversion to natural gas power generation within Canada will increase demand, so that also means that there will be less to export."
Bill Gwozd, vice-president of gas services at Ziff Energy Group, shows more faith in the ability of his company´s forecasting models to generate hard numbers.
"We had about 10 bcf per day exported in 2005 and, in 2010, that´s down about 20 per cent," Gwozd says. Production growth in the Montney and Horn River, he adds, will likely be offset by the growth of natural gas demand in the oilsands and possibly by the Ontario shift to more natural gas power generation. "So by 2015, exports are expected to still be in that 7 to 8 bcf per day range."
By 2020, Ziff Energy forecast models include Mackenzie Delta gas and a whisper of Alaska gas production, but starting in 2015 it also factors in growing volumes of liquefied natural gas imports to the United States. The net effect is that by 2020, Canadian gas exports to the United States are still about 7 bcf to 8 bcf per day. And that actually is optimistic.
"Realistically optimistic," Gwozd says. "But there are a number of grey clouds on the horizon. If Alaska is delayed or Mackenzie is delayed by five years, or LNG is delayed by a few years, or the oilsands development is accelerated because of demand, then you could have the stars aligning so that gas exports are down even more."
Oilsands producers are forecasting that 6 bcf per day will be needed for projects by 2020 if all of them go ahead. Ziff, however, sees oilsands gas consumption more conservatively: 3 bcf per day by 2020, or 20 per cent of Canada´s production. (The oilsands currently consume about 1.1 bcf per day.)
"The shift from a coal-fired power generating strategy to a natural gas-fired strategy will also vacuum away incremental gas from our cousins in Boston," Gwozd says. "By 2020, 30 bcf a day is how much all of North America will consume for natural gas-fired power generation. That´s up from 20 bcf per day currently for gas power generation. So a 50 per cent jump from today."
Another variable that comes into play in the long term is where Canadian exports are destined. The United States will always be Canada´s biggest market, but Asia will become a customer as well if the Kitimat LNG project proceeds. By most accounts, this would be a win for Canada. Not so for the United States, because of the uncertainties around Arctic pipeline approvals and the resistance to LNG imports in some parts of the United States.
"Our models actually have Mackenzie and Alaska eventually proceeding," Gwozd explains. "But in the interim, until we have LNG in the Maritimes coming on, it would be a prudent strategy for our cousins in Boston, and maybe even in New York, to look into some long-term strategies such as learning how to knit or read by Braille just so they have a backup strategy for those folks who are so adamant to keep LNG off their coast."
Perhaps a more realistic backup strategy is the promise of the shale gas plays in the Lower 48. Huge initial production and massive long-life reserves have inspired much confidence in the burgeoning natural gas economy in the United States.
But these shale plays had better be as prolific as touted in light of declining Canadian exports because a controversy is now brewing over the estimated ultimate recovery (EUR) of shale gas wells in the United States. The firing of World Oil editor Perry Fischer by the publication´s parent company president and chief executive officer, John Royall, has landed this debate on the radar for many.
Fischer´s dismissal was given no formal reason, but it followed the last-minute withdrawal of a column written by geologist/consultant Arthur E. Berman questioning the EUR numbers promoted by major shale gas producers.
His doubts are shared by many in the petroleum industry, from scientists and financial analysts. The crux of the issue is that when reserves are calculated on the actual decline trends in the Barnett shales-which are now well-developed by thousands of wells-rather than on some future, model-driven expectation of flattening decline rates, these shale wells show much lower EURs than producers claim.
If it turns out that years from now the average Fayetteville shale well, for example, has a EUR of 0.59 bcf to 1.04 bcf, as calculated by the likes of Berman, rather than the 2.2 bcf to 3.3 bcf, as claimed by major operators, this could become the biggest wild card yet in the Canadian export game, especially if by then natural gas-fired power switching is already well underway in North America.
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