Analysis: First-quarter drilling numbers show this winter season in Canada was almost as strong as the boom of 2001, setting up the potential for record activity this year if commodity prices maintain their strength.
Weekly surveys conducted by the Canadian Association of Oilwell Drilling Contractors show activity peaked in February, when 606 rigs were in the field in Western Canada (including the Yukon and Northwest Territories). The maximum fell just short of the 608 under contract two years ago, the last time natural gas prices surged.
Some 578 rigs worked in January and 606 made hole in February, resulting in fleet utilization of 87 and 91 percent, respectively. March averaged 530 rigs in the field, resulting in a first-quarter average of 571 rigs under contract, or a fleet utilization of 86 percent.
During the first three months of 2001, an average of 576 rigs were active, translating into a fleet utilization of 92 percent. In the same period a year ago, 450 rigs employed gave a utilization rate of 68 percent.
The first-quarter numbers could have been even higher if drillers had found more staff to cope with demand. Winter is traditionally the busiest time in Canada since the ground in northern areas freezes, enabling it to support the weight of heavy rigs.
Precision Drilling, Canada's largest contract driller, said 70 of its 225 rigs operated with two crews of five workers instead of the usual three crews.
Competition for skilled staff is high in Alberta, where its oil-rich economy is continuing to bubble along. The talent pool is also shrinking as tough times in agriculture reduce the number of young people used to working long hours with big equipment.
While some winter-only access prospects have been lost because of staff shortages, much of the work has been merely been rescheduled to later in the year.
"As far as the second quarter looks, it looks quite strong right now," Bob Geddes, vice president of drilling at Ensign Resource Service Group Inc., said earlier this week. "This year we are expecting a very strong May and June in southern Alberta on shallow gas projects, and we also expect 20 percent of our fleet to work over (spring) breakup."
The latter figure, although it looks small, is actually significant. It's not unusual, Geddes told Oil and Gas Advisory, for only 10 or 15 percent of Ensign's fleet to work during spring, when thawing ground and weight restrictions on roads make it difficult to haul equipment around Western Canada.
High commodity prices are giving producers incentive to be more aggressive with their spring drilling plans, agreed Dale Tremblay, a senior vice president at Precision Drilling.
"We know it's going to stay steady. Producers are going to try to get out of breakup and be moving as fast as possible," he said. "It's looking very strong through the summer."
If commodity prices stay above $24 per barrel for oil and $4 per million British thermal units (mmBtu) for the year, there's a good chance that 2001's record of almost 18,000 well completions will be broken, Tremblay said.
Oil prices have averaged about $34 per barrel to date, with gas running close to $6.50 per mmBtu. However, there are several reasons to think the chance of a new Canadian drilling record is less likely than Michelle Kwan landing a medal at this week's world figure skating championship in Washington.
A big chunk of the wells in 2001 were drilled in the first half, when strong natural gas prices caused producers to chase gas prospects like bloodhounds tracking an escaped convict. Record low storage inventories will boost summer prices this year, but it could also lead to a repeat of 2001, when nosebleed-inducing gas bills wiped out between 4 and 6 billion cubic feet per day (bcf/d) of demand and eventually brought the market down.
The war with Iraq is obviously the biggest difference from two years ago. High oil prices and a low differential--the discount applied to heavy oil because it costs more to upgrade into gasoline than lighter slates--mean Canadian exploration and production (E&P) firms have wads of cash.
But not all of the money is going to be pumped into new drilling. Paying down debt and giving some of the money back to investors, in the form of higher quarterly dividends or share buybacks, are also on the agenda. E&P firms realize they get a better bang for their buck from these actions instead of pouring money into the ground by developing marginal prospects in Western Canada.
Producers may also hold back on drilling because of rising bills from service firms, which will put pressure on finding and development (F&D) costs. Producers are increasingly focusing on boosting their capital recycle ratios to ensure they do not disappear like white socks left outside during a snowstorm.
The measure of economic efficiency is determined by dividing a firm's netback, the money left after paying operating costs, royalties, and expenses, by its F&D costs. If a firm has a netback of C$22 per barrel of oil equivalent and F&D costs of C$10 per proved BOE, then its recycle ratio is 2.2. It's becoming more difficult for firms with recycle ratios under two to attract favorable opinions from analysts and buying interest from investors.
In addition, the income trust sector shows little sign of being sated from swallowing smaller E&P firms in Canada, ones that in recent years have been among the most active drillers. There are lots of private firms starting up, but it's hard to see these players overcoming the drop in money available for drilling as income trusts annually send several billion dollars into the hands of unit holders.
Even if a well completion record isn't set this year, first-quarter numbers and early signs for second-quarter activity show Canadian service companies are going to enjoy a very busy and profitable year.
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