Murphy Oil hot on the trail in B.C.

Gary Park

For Petroleum News

Following Murphy Oil’s fortunes in Canada is a bit like tracking a yo-yo.

In just the last few years, it has attained the heights as the discoverer of British Columbia’s Ladyfern gas field (ranked among Canada’s top 10 onshore finds of all time), locked horns with rival companies over the rate of Ladyfern’s exploitation, sold the bulk of its conventional assets in Alberta and Saskatchewan for C$830 million, described its Western Canadian exploration program as “not even worth mentioning,” and returned to British Columbia with a C$380 million investment in a red-hot gas play.

Consigning the past to the history books, Murphy is chasing what Chief Executive Officer Claiborne Deming called a prospect that “we believe has the potential to yield over 2 trillion cubic feet of natural gas.”

But Murphy has plenty of competition in a region which has stirred excitement amid claims that shale gas plays such as the Montney and Horn River basin could rival the vast Barnett shales of Texas.

The Arkansas-based explorer emerged as the big buyer at British Columbia’s final land sale of 2007, spending C$225 million to build its land position to 80,000 acres.

That followed its mid-2007 acquisition of assets held by Bear Ridge Resources for C$155 million. The junior company had an initial development plan for 70 gross wells after a series of successes in the Tupper Montney reservoir yielded an estimated 800 billion cubic feet of original gas in place.

2008 program C$240 million

The company has advised the National Energy Board it expects to drill 118 horizontal wells over the next six years.

Tupper Montney covers almost 6.5 million acres and Murphy figures prospects within the “economic capture” area of a C$23 million pipeline it is building have potential original gas in place of up to 13 tcf.

The pipeline, scheduled to start deliveries in September, has a projected 30-year operating life and a capacity of 240 million cubic feet per day.

Murphy said it believes additional projects — on lands that either it or third parties own — will use capacity on the pipeline.

BP Canada Energy chasing C$1B unconventional gas in B.C.

The Noel development, embracing rights built up over several years, is expected to join the production stream this fall, boosting volumes from a current 10 million-20 million cubic feet per day to 125 million cubic feet per day — a significant recovery for a company that has seen its Canadian gas output slide by 60 percent over the past decade to 400 million cubic feet per day.

A key for BP is the chance to apply horizontal drilling technology developed at a cost of about $100 million in Wyoming, where it is exploiting tight gas reservoirs, slashing carbon emissions by 80 percent compared with conventional development and shrinking its surface footprint by about one-third.

As British Columbia embarks on its latest resource play, one question hovers over the industry — will it see a replay of the feuding that accompanied Ladyfern, which peaked at 665 million cubic feet per day in early 2002, nosedived to 200 million cubic feet per day within 18 months and is virtually depleted.

In the process, Murphy tried persuading EnCana and Canadian Natural Resources to restrain the rate of production, extend the field’s lifespan and raise the profit margin.

Openly expressing his frustration, Deming said at one point that it seemed “inappropriate to sell this much gas in this great field at this low price.”

Murphy’s Canadian president at the time, Harvey Doerr, said Ladyfern became overcapitalized, denying the producers the chance of handsome profits.

“We were never able to fill the facilities that we built because by the time they were finished the decline had already set in,” he said. “It’s not a model of how you should develop something.”

He said the race to tap into the reservoirs amounted to “value destruction. … There should have been windfall profits in something that involved taking the risk we did … and there wasn’t.”