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Providing coverage of Alaska and northern Canada's oil and gas industry
June 2008

Vol. 13, No. 26 Week of June 29, 2008

Industry hails the shales of B.C.

It’s turning into a stampede almost without parallel in Canada’s oil and gas industry as companies do more than just chase an alternative to Alberta’s maturing conventional basin.

In the space of less than two years, they have catapulted a resource that was scarcely known outside their world — and little valued within it — into the best chance of stretching Canada’s gas reserves well beyond the 58 trillion cubic feet of remaining established reserves.

The National Energy Board underscores the importance of new supply sources from Arctic and East Coast frontier regions, coalbed methane, liquefied natural gas and shale gas.

The regulator says that in “coming years it is expected that North American demand for natural gas will continue to outpace the growth in domestic supplies” as supplies from the Western Canada Sedimentary basin and Nova Scotia’s offshore Sable field continue their decline, while gas consumption in the Alberta oil sands and Ontario’s gas-fired electrical generation keeps rising.

Almost as an after-thought the NEB, in its latest annual energy assessment, notes that in 2007 land sales in the shale region of British Columbia were of “particular interest.”

Not just juniors involved

This is not just a scramble by adventurous junior companies to secure a toehold. EnCana, EOG Resources, Talisman Energy, Nexen, Devon Energy, Husky Energy and Apache — all experienced hands in unconventional plays — are taking a bullish view of British Columbia’s Upper Montney and Horn River prospects.

Sister companies Imperial Oil and ExxonMobil, not known for faddish behavior, have joined the ranks by acquiring combined license holdings of 115,000 acres in the Horn River play, indicating they don’t want to be left out of a “new opportunity with considerable resource potential.”

BP Canada, ConocoPhillips, Shell Canada and Duvernay Oil are rumored to be among other successful bidders at government land sales.

Robin Mann, chief executive officer of AJM Petroleum Consultants, said the advent of new technology will turn the Upper Montney into “one of the major plays of the future,” with gas-in-place estimated at more than 50 tcf.

Even if that estimate is cut in half “we have a major resource we didn’t even have two or three years ago,” he said.

Wood Mac likes Horn River

Horn River has attracted a similar rave assessment from Wood Mackenzie, the United Kingdom-based consultant.

It puts the play on a “global scale,” with recoverable resource estimated at 37 tcf, comparable in the firm’s assessment to the main fields expected to back an Alaska gas pipeline.

Wood Mackenzie analyst Fraser McKay said three Horn River announcements by EOG, Apache and Nexen point to “rock properties and well scenarios which were highly consistent; each suggesting the play could be even more prospective than Texas’ prolific Barnett Shale. The potential resources are world scale.”

McKay said that once estimates move beyond the preliminary stage, the recoverable calculations could climb to 50 tcf.

A preliminary analysis by the firm suggested economic returns would be in line with other major global gas supply projects, requiring a Henry Hub price of about $6.50 per thousand cubic feet to achieve a 10 percent rate of return.

He said Apache has announced an average resource estimate of 12.5 tcf, indicating its joint venture partner EnCana could be exposed to a similar level of resource potential, while EOG and Nexen have reported resources of 7.8 tcf and 4.5 tcf respectively.

Wood Mackenzie assumes that once more exploration work is completed, Imperial, Devon and Quicksilver Resources may all hold multi-tcf positions.

Reinforcing those conclusions, the study said British Columbia offers a “political and fiscally stable environment,” including royalty incentives that make the projected 10 percent rate of return realistic, even in a high-cost scenario.

Wood Mac also sees challenges

But John Dunn, Canadian upstream analyst for Wood Mackenzie, suggested the challenges facing development of the resource are many, including land access, limited regional infrastructure, regional price differentials and costs.

He said current resource estimates are “based on extrapolations from relatively few wells and will require to be firmed up through further drilling and analysis of long-term well performance.”

“However, with conventional Western Canadian gas production in decline, the emergence of shale gas as a future source of supply could be vital in maintaining Canada’s position as a major producer of natural gas.”

The firm said that with few exploration surprises anticipated, “gas-in-place estimates are likely to creep upwards over time rather than be revised down.”

AJM Petroleum Consultants said land prices for the Upper Montney have averaged C$2,284 per hectare (C$5,644 per acre), while the more remote Horn River near the Northwest Territories border is fetching C$1,703 per hectare, although Mann noted the Upper Montney is not a pure shale play because of its “turbidated dirty, sandy, shaley hodgepodge of everything.”

Investment dealer Peters & Co. agrees with Wood Mackenzie that many of British Columbia’s unconventional plays are economic at prices of C$6.50 per thousand cubic feet.

Shales could require C$8

RBC Dominion Securities analyst Gordon Gee has taken a tougher line, estimating B.C. shales need long-term gas prices of C$8 to be economic, although C$7 could be sufficient if there is a drop in drilling costs.

“In addition, further cost improvements due to increased operator and service company experience and a migration towards fewer yet longer wellbores with additional stimulation events per well will serve to increase already superior returns,” Peters said.

Mann noted that Horn River wells are not cheap at up to C$10 million each, but operators are pointing to a decline to C$6 million-C$8 million, although access to well sites remains a “big problem.”

ARC Energy Trust Chief Executive Officer John Dielwart, which has 76,800 gross acres (64,000 net) in the Montney play, has boosted its capital budget for the play twice this year, allocating C$125 million.

But he said ARC, which is producing about 46 million cubic feet per day from 75 wells, faces processing constraints which threaten to become a major issue as companies ramp up their production.

“We are reserving space all over the place,” he said. “There’s a bit of a race going on.”

Juniors talk plans

While the majors are mostly keeping their eventual plans under wraps, although Apache Chief Executive Officer Steven Farris, has talked of spending C$5 billion or more over the next decade, the juniors are giving an added buzz to the resource and offering a chance to track developments. Consider just a few:

• Canbriam Energy has struck an equity financing deal of up to US$300 million with Warburg Pincus and ARC Financial to acquire, explore and develop oil and gas interests, with a primary focus on shales in B.C. and Alberta.

• Terra Energy has hired Tristone Capital to help market rights in the Montney formation, including 70,000 acres in the core Fort St. John operating area. It recently offloaded 3,200 acres to an industry partner for C$5 million.

• Bellamont Exploration, although starting out on the Alberta side of the Montney formation, is gaining a toehold in British Columbia. It is typical of the high-flying juniors in the Montney play. Launched in late 2006 with an initial public offering of C$11 million, its market capitalization has cracked C$100 million, with first-quarter production averaging 340 barrels of oil equivalent per day and gross land holdings at 52,000 acres.

• Canada Energy Partners has unveiled an exploration strategy for its 41,000 acres in the Montney-Doig shale play, while director John Proist scooped up 34,000 shares for C$0.64 each in early February.

• Birchcliff Energy, which plans four Montney-Doig horizontal wells before mid-year and tie in three to four wells as part of its winter program, announced a C$115 million bought-deal financing, with prominent investor Seymour Schulich acquiring 1.8 million shares at C$7.46 each to gain a controlling interest of 18.8 million shares. The company expects to drill four to six more wells in the second half. It also holds about 13,000 acres of undeveloped land in the Pouce Coupe area, which it believes could extend the Montney-Doig play.

• Crew Energy has 7,360 net acres in the Muskwa play, where EOG made its find. A third-party evaluation estimates its potential gas-in-place at 400 bcf-1.2 tcf. CEO Dale Shwed says “everybody is looking at bidding for land up there.” Last fall, Crew completed a bought-deal financing of C$54.5 million.

• Storm Exploration reports 100 percent success from five net wells, is producing 5 million cubic feet per day from two Montney wells and expects to drill 18 more wells this year.

• Grey Wolf Exploration has budgeted C$15 million to exploit its Pouce Coupe properties this year and is weighing horizontal wells in the Montney-Doig reservoirs.

• Seaview Energy has entered into three separate farm-ins, involving a four-well commitment to earn an interest in 4,480 gross acres in Pouce Coupe, exposing the company to 30 bcf of resource potential. The focus area is in a fairway where more than 130 wells are producing. It says competitors in the area report capital costs of C$4 million-$5 million per horizontal well and expect costs to ease as activity picks up.

• Result Energy plans to acquire seismic data from its Horn River land throughout 2008 and hopes to start drilling in the first quarter of 2009. It currently has 26,000 gross acres at a 100 percent working interest. The company says royalty increases in Alberta make it difficult to justify the same levels of capital spending it has delivered over the past three years, but Horn River provides an alternative.

• Galleon Energy, described by analyst Chad Friess of UBS Securities Canada, as a “forgotten Montney name,” drilled its first horizontal well — this one at Dawson, Alberta — in the opening quarter and achieved gas flows of 4 million cubic feet per day.

•Alberta Clipper, attracted by the B .C. royalty structure, is planning a “dramatic re-entry into northeast B.C.,” said company President Kel Johnston, and expects more than half of its activity during the second half of 2008 will be in the region, where it has 50,000 net acres of undeveloped land.

—Gary Park






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