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U.S. energy buys stoke Canadian economy Energy exports in 2007 valued at C$90 billion, almost 1/5 of Canadian exports; U.S. shipments account for 66% of oil, 54% of gas Gary Park For Petroleum News
The extent to which energy is powering the Canadian economy — and contributing to security of supply in the United States — has been brought even more sharply into focus with the latest set of statistics from the National Energy Board.
In a nutshell, the U.S. in 2007 received 1.85 million barrels per day of Canada’s oil output of 2.8 million bpd and a net 9.1 billion cubic feet per day of natural gas from total production of 16.8 bcf per day.
That translated into 66 percent of Canada’s oil and 54 percent of its gas heading south of the 49th parallel, making Canada by far the largest external supplier of U.S. energy needs.
The returns from exports of oil, natural gas and electricity were equally impressive.
The value of total exports was C$90 billion, accounting for 19.7 percent of all Canadian exports, doubling the average through the 1990s.
Net energy export revenues rose by 8 percent from 2006 to C$50.8 billion, with revenues from natural gas and crude oil and products almost equal, ending the imbalance in favor of gas over recent years.
The energy industry represented 5.6 percent of Canada’s gross domestic product, while capital investment and spending on repairs reached C$68.9 billion, or 35 percent of Canada’s total private sector investment.
Energy consumption shifts But the NEB carefully noted that indications point to shifts in several key areas of energy consumption.
“At a general level, growing anxiety regarding U.S. macroeconomic conditions, energy price concerns, potential supply constraints and heightened environmental awareness could influence consumer spending habits and therefore energy demand trends,” the federal regulator said.
Significant energy and environment policies and a regulatory framework for greenhouse gas emissions could reduce energy consumption, along with changing consumer preferences in housing design and transportation, the NEB suggested.
The report said stubbornly flat gas prices in the first half of 2007 and further slippage in the fall, combined with rising exploration and development costs eroded the economics of some of Western Canada’s natural gas opportunities, causing investment to be either deferred or transferred to oil projects or to U.S. gas-producing regions.
Growth and escalating costs in oil sands projects, where investment rose 17 percent to C$18 billion, required increases in capital spending and “may have diverted some investment from other oil and gas operations,” the board said.
Drilling capacity expanded Although it said any pullback in Canadian gas drilling activity in a tightly balanced North American market could lower production and lead to higher commodity prices, drilling capacity in Western Canada expanded as the rig fleet reached 897 at the end of 2007, up 55 rigs from 2006.
On average 339 rigs operated per month in Western Canada compared with 473 in 2006, with the well count edging over 18,000, about 4,600 less than in 2006. Total oil wells were down 6 percent and gas wells dropped 25 percent, with the percentage of gas-targeted wells slipping to 68 percent from 73 percent.
Further reinforcing the slowdown, total land sale payments in Western Canada slumped 37 percent to C$2.66 billion, including a downturn in oil sands sales to C$650 million from C$1.96 billion and a precipitous decline in average prices per hectare (2.471 acres) to C$573 from C$1,273.
Exploratory drilling down The Canadian industry slashed its exploratory drilling by 37 percent in 2007, while the average number of active seismic crews dropped to 5.8 from 14.1, signaling that an exploration recovery in 2008 is “unlikely,” the NEB said.
Total oil and gas capital spending in Canada was off 10 percent in 2007 at C$48 billion, with the decrease in areas outside the oil sands estimated at 20 percent.
For 2008, the report expects capital spending will be down 3 percent, despite a continuing heavy outlay in the oil sands that is likely to divert some investment from conventional activities.
The NEB is counting on a drop in Canadian gas production this year, while conventional and heavy oil volumes are likely to continue a downward trend as oil sands output rises.
In addition to the oil sands, a 16 percent increase in East Coast offshore oil production, pushing the region to 369,000 bpd, was a major contributor to the 7 percent growth in crude oil and equivalent production last year.
Remaining conventional crude oil reserves ended 2006 — the latest year for which statistics are available — at 4.03 billion barrels, a loss of 349 million barrels since 2005.
Alberta’s remaining conventional reserves entering 2007 were 1.57 billion barrels of an initial estimate of 17.18 billion; Saskatchewan had 1.07 billion barrels of its initial 5.6 billion; British Columbia had 114.5 million barrels of an initial 791.3 million; the Newfoundland offshore dropped to 1.12 billion barrels from 1.88 billion; while the combined Northwest, Yukon and Nunavut territories, along with the Arctic Islands and Eastern Arctic were estimated at 92.46 million barrels of an initial 332.7 million.
Oil sands reserves consisted of 31.5 billion barrels, down from 35.2 billion, while the bitumen count was 141.7 billion barrels, off a mere 700 million barrels from the initial count.
Production from mining and in-situ operations yielded an average 1.4 million bpd in 2007, 13 percent up from 2006.
Refineries meet demand Canada’s 19 refineries had total capacity of 2 million bpd, comfortably meeting domestic demand of 1.77 million bpd. Proposed refinery expansions are scheduled to add another 920,000 bpd of capacity over the next seven years.
For 2007, Canada accounted for about one-quarter of the output in Canada and the U.S., with 98 percent coming from the Western Canada Sedimentary basin and Alberta responsible for 79 percent of the basin’s total. British Columbia is at 16 percent and Saskatchewan 5 percent.
Natural gas prices last year, as measured at the AECO hub in Alberta, opened at C$6.04 per gigajoule, slumped to C$4.11 in late August and closed the year at C$6.12, while the Dawn hub in Ontario went from US$5.94 per million British thermal units to US$5.46 and US$7.62.
In Western Canada, the impact of drilling cutbacks was seen in the second half of the year, with production dropping by an average 400 million cubic feet per day.
The Sable project, offshore Nova Scotia, stabilized in the second half at 410 million cubic feet per day, up 33 percent from the start of 2007.
Reserves, as measured in 2006, put remaining marketable gas at 58.1 tcf, with reserve additions of 7 tcf replacing 116 percent of production.
The provincial breakdown showed Alberta had 39.6 tcf remaining at the end of 2006 from initial reserves of 170.3 tcf; British Columbia dropped to 13.5 tcf from 31.9 tcf; and Saskatchewan had 3.3 tcf of an initial 9.5 tcf.
The mainland Northwest Territories and Yukon had 465 bcf.
Oil sands consumption of gas in 2007 was 1.13 bcf per day, three times that of 2001. Gas exports, averaging a gross 10.4 bcf per day, met about 17 percent of U.S. consumption, concentrated in the Central-Midwest and Pacific Northwest regions. Canada imported 1.3 bcf per day into Ontario from the U.S.
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