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Exxon joins shale race Says state-of-art technology will produce results from disciplined approach Gary Park For Petroleum News
ExxonMobil is stirring to life as it joins the stampede into shale gas, with an eye on using northeastern British Columbia as its springboard.
Vice President Henry Hubble told a conference call July 31 that the super-major has “leading technology in this area and that is why we are making a big entry into the non-conventional” shale, tight sands and coalbed methane arenas.
At present, ExxonMobil’s sole unconventional stake yields 55 million cubic feet per day from Colorado’s Piceance basin.
Through its wholly owned subsidiary ExxonMobil Canada and 69.6 percent-owned Imperial Oil it has downgraded its role in exploration and development in the Western Canada Sedimentary basin over the last decade beyond its extensive oil sands and heavy oil holdings.
But it emerged recently as a contender in British Columbia’s Horn River Basin, acquiring rights to explore 115,000 acres.
Richard Wyman, an analyst at Canaccord Adams, told the Financial Post that unconventional gas is all that remains in North American sedimentary basins to “move the needle for a big company.”
He said the established basins have been delivering hydrocarbons for 100 years or more and are “getting pretty tired in the conventional setting.”
But the possible rewards from unconventional plays are “large enough for large organizations to commit the full weight of their staff and expertise.”
Wyman said he would not be surprised if ExxonMobil is motivated by a desire to secure an economic hedge in unconventional gas against the rising demand for gas to extract oil sands bitumen, given delays in the Mackenzie Gas Project.
Hubble said ExxonMobil will go after unconventional plays where it can lock up “significant acreage positions,” then take a “very disciplined development approach.”
EnCana: vast shale interests Another major-leaguer, EnCana, is starting to raise the curtain on its vast shale gas play interests in North America as it develops plans to spend cash flow, now likely to reach $11 billion in 2008.
Randy Eresman, chief executive officer of the Canadian independent, said preparations are under way for a “significant increase in development activity in 2009.”
EnCana is one of the last among the majors operating in northeastern British Columbia and the Haynesville play straddling the Texas-Louisiana border to disclose results from its exploration efforts, and, like its peers in the shale sector, it is pointing to a potential bonanza.
At Haynesville, EnCana said a second horizontal well flowed an “exceptional” initial two-day rate of 15 million cubic feet per day.
“We’ve seen and some of our industry competitors have seen initial production rates which are in the order of twice that (per section) of some of the best wells ever drilled in the Barnett shale play,” he said.
“Because of its depth it’s also more over pressured which allows a lot more gas to be packed in. It’s quite thick.”
Now the challenge facing EnCana is to get costs down to a level that “can make the whole thing as economically attractive as the Barnett play. With early results, we think that’s a realistic expectation.”
The level of EnCana’s commitment to Haynesville has been reinforced lately as it expanded holdings to 370,000 acres in the second quarter and struck an agreement in July to acquire 89,000 acres from Indigo Minerals.
Rigs could double or triple in 2009 from five rigs today Jeff Wojahn, president of the United States division, said it will take some time to establish the decline rates in the play, adding he doubted EnCana is likely to add to its five rigs this year, but did not rule out going with 10 to 15 rigs in 2009, based on discussions with partner Shell and what emerges from the 2009 budget discussions.
He said the two horizontal wells drilled so far cost up to $8 million each, but he emphasized that because of the exploration factors those could not be seen as “commercial costs.”
In the fast-emerging Horn River play near the British Columbia border with the Northwest Territories, two recently completed wells yielded a “very strong” first-month average in excess of 5 million cubic feet per day and two more wells are planned in conjunction with partner Apache over the balance of 2008, Eresman said.
In the more established Montney play, where EnCana has secured 500,000 acres for a price “substantially lower” than those paid at recent blockbuster British Columbia land sales, the company is targeting 1 billion cubic feet per day by 2011.
It is currently producing more than 140 million cubic feet per day from about 70 horizontal wells and is on a fast learning curve, Eresman said, noting that EnCana can now complete eight fracs along a horizontal leg in four days, compared with 20 days a year ago.
Second quarter output up 10% North America’s third largest gas producer reported a 10 percent rise in gas output in the second quarter to 3.8 bcf per day, including a 127 percent jump in East Texas, stemming from drilling successes and incremental volumes from Deep Bossier where it paid $2.5 billion last November to buy out Leor Energy, its partner in the Amoruso field.
Despite the year-over-year gains in East Texas, production is behind schedule, forcing EnCana to reduce its 2008 guidance to 370 million cubic feet per day from 420 million.
Wojahn said Deep Bossier is probably one of the most difficult plays to predict in terms of future performance “simply because we’re not drilling that many wells.”
He said three more wells will be brought into production in August and could add 100 million cubic feet per day of volume.
In the Canadian Plains second-quarter output dropped to 856 million cubic feet per day from 874 million, but the Canadian Foothills gained 100 million cubic feet per day to 1.3 bcf.
Eresman said that should gas prices slide below $8 per thousand cubic feet there could be a cutback in EnCana’s operations in Piceance basin of Colorado and British Columbia, but he estimated that the “vast majority” of the company’s gas operations could recover capital costs with gas prices at $4.75 per mcf.
He said higher commodity prices and increased upstream activity are pointing to some cost inflation in services and materials, especially steel and fuels.
“We believe inflationary pressures may continue to climb for the rest of the year,” he said.
Eresman said plans to split EnCana into separate oil and gas entities will see a circular mailed to shareholders in mid-November, followed by a vote in mid-December.
“As we transition toward the creation of two strong independent companies, it will be business as usual and we expect the consistent and strong performance (of the second quarter) to continue,” he said.
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