LNG threatens costly gas

EIA expects liquefied natural gas imports to Lower 48 will climb to 4.5 tcf by 2030

Gary Park

For Petroleum News

Not only might imports of liquefied natural gas to North America offset the anticipated loss of Canadian supplies over the next decade, they could also spell trouble for the more expensive plays that are starting to dominate the gas sector in Canada.

In its latest annual energy outlook the U.S. Energy Information Administration said shipments from Canada will start to slow at the midpoint of its forecast covering 2005-2030. The report predicts that gas from Canada will hold steady between 2.3 trillion cubic feet and 3 tcf over 2003-2015, then begin a steady descent to 900 billion cubic feet.

The EIA said the decline will stem from depletion of conventional fields in Alberta, the dominant producing region, along with rising domestic demand in Canada and a reevaluation of the potential for unconventional production from coal seams and tight gas formations.

It said LNG will be essential to deal with the shortfall, although delays in building liquefaction plants, supply constraints at a number of liquefaction facilities and fast-rising global demand for LNG will combine to keep the U.S. LNG market tight until 2012.

However, total net imports of LNG to the Lower 48 are expected to climb from 600 bcf in 2005 to 4.5 tcf in 2030.

Unconventional plays threatened by LNG

Speaking to an oil and gas market outlook conference sponsored by Canadian Enerdata, he offered a much bolder view of LNG’s role in meeting U.S. demand, suggesting that the U.S. is already launching a spate of LNG terminal construction.

He said that “without question” North America will have LNG receiving capacity of about 7.3 tcf over the next five years and that doesn’t include the stalled development by Anadarko of its planned Bear Head terminal in Nova Scotia.

Schlesinger said LNG arriving at the U.S. Gulf Coast will force the deferral of natural gas projects because LNG, regardless of where it lands, will lower prices.

Four Canadian projects planned

Schlesinger expects gas-fired power generation will continue on a growth curve, adding to Lower 48 demand, with the generation sector likely to pass the industrial sector as the largest customer for gas.

He predicted gas prices will remain on a volatile path, with Henry Hub prices fluctuating between US$4-$9 per million British thermal units over the next 12 to 18 months.

On the oil front, the EIA expects Canada’s conventional output to taper off to 1.93 million barrels per day in 2010 from 2.12 million bpd in 2005 and then rebound to 2.01 million bpd in 2015 before dropping by 1.1 percent annually over the next 15 years.

But it said Canada will play a leading role in elevating North America’s unconventional production from 1.09 million bpd in 2005 to 1.91 million bpd in 2010 and 2.32 million bpd in 2015, with oil sands leading the way, followed by liquids from energy crops, natural gas, coal and shale.

British Columbia bears brunt of Devon cutbacks

Unhappy about the high-cost operating environment in Canada, Devon Energy is reining in its 2007 spending north of the 49th parallel — and it is not alone, much to the concern of British Columbia’s booming natural gas business.

Although Devon has no plans to pull out of Canada, company President John Richels, formerly head of Devon’s Canadian subsidiary, said the budget trimming is a necessary part of fiscal discipline.

Speaking to analysts in November, he said: “I hesitate when I say (Western Canada) is the most expensive market in the world, but I think it really is.

“So we are going to constrain our spending there.”

He said competition for equipment, services and supplies has created a “highly inflationary cost environment” in Canada, while a stronger Canadian dollar has cut into Devon’s profits.

For now Devon has not released details of its expected production cuts in Canada (it has lowered its worldwide production guidance for 2006 by 1 percent).

But it plans to operate only four rigs northwest of Fort St. John, B.C., this winter, down from seven in 2005-2006 and 12 in 2004-2005.

The company also plans to focus on shallower wells of 4,000 feet or less, rather than those in the 8,200 foot range to achieve faster completion.

Devon has been joined by Canadian Natural Resources in scaling back B.C. drilling and EnCana could be next in line when its 2007 budget is released about mid-December.

The Petroleum Services Association of Canada, assuming an average gas price of C$6.25 per thousand cubic feet in 2007, is predicting a 28 percent decline in B.C. drilling next year to 1,050 wells from the 1,450 expected this year — the first reversal in the province since 2002.

Association President Roger Soucy said costs, while varying from service to service, have risen about 30-40 percent in B.C. over the past three years, driven mostly by the costs of labor and steel.

Canadian Natural is moving capital from gas to oil projects, reducing conventional drilling near Fort St. John to 71 wells from 132, suggesting the emphasis in future years will shift to more expensive, lower-yield unconventional plays.

To mirror that view, it is currently budgeting for 47 conventional wells in 2007, down 71 percent from the 164 planned for 2008 and off 75 percent from the 186 planned for 2011.

EnCana is likely to shrink its drilling programs in the prized Greater Sierra and Cutbank Ridge plays as part of an overall US$1 billion budget reduction. The company’s well count dropped by 33 percent at Greater Sierra in the first nine months of 2006 and by 28 percent at Cutbank Ridge.

—Gary Park