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Shrugging off woes BC Natural gas players geared for active winter; EnCana-Apache lead drilling; EnCana launches 1st phase of major processing plant Gary Park For Petroleum News
Forget weak natural gas prices and a bleak economic outlook, players in northeastern British Columbia’s sizzling Montney and Horn River plays are swinging into action, with plans for an active winter drilling season and infrastructure programs.
Having laid out more than C$3.5 billion over the past two years to secure exploration rights, producers are ready to embark on full-scale drilling efforts to establish reserves that will allow them to nominate for space on pipelines out of the region.
Calgary-based investment dealer Peters & Co. forecast in a research note that drilling, casing and completion spending will reach C$1.38 billion for 250 wells in the Montney tight gas play and C$660 million for 60 wells in the Horn River shales.
The firm suggests that despite a wave of capital spending cuts for 2009, British Columbia resource play expenditures should be better able to withstand troubled times, adding that planned spending at Montney and Horn River “remains substantial.”
Bolstering the confidence levels, EnCana — involved in a large-scale joint-venture with Apache in the region — has rolled out initial plans for what could be a multibillion-dollar gas processing facility in the Horn River basin.
In a project description for its Cabin Gas Plant, filed with the British Columbia government, EnCana estimates it could spend C$400 million on the first phase of a six-stage development, although future phases will depend on future production.
The plant, to be located 40 miles northeast of Fort Nelson, is designed to process 400 million cubic feet per day when it starts operation in 2011.
Without any fanfare, EnCana submitted the project outline in November under the province’s environmental assessment process, which is usually the forerunner to a formal regulatory application and public hearings.
EnCana is heading the project on behalf of the Horn River Basin Shale Gas Producers Group, involving seven other companies that are poised to spend hundreds of millions of dollars tapping trillions of cubic feet of gas reserves.
Technological advances Trapped in complex rock formations once thought too costly and challenging to develop, the Horn River shales — like those in the Barnett and Haynesville plays of the United States — have seized the spotlight in recent years as a result of technological advances, the prospect of higher gas prices and shrinking supplies of conventional gas.
Initial wells in British Columbia cost about C$10 million each to drill and bring on stream, but the use of multiwell pads for horizontal wells, with as many as 20 wells per pad, have dragged costs down to C$7 million per well and reduced the environmental impact.
Mike Graham, president of EnCana’s Canadian Foothills division, said his company is determined to “drill a lot of wells off a single pad and really try to get our costs down.”
So far, he said, the big independent is encouraged by the trends and its production rates are now “pretty stable,” with one well averaging about 8 million cubic feet per day over its first month.”
Graham said EnCana and Apache probably control about half the Horn River play and based on data gathered to date, he predicted production will “grow very rapidly” to more than 100 million cubic feet per day by the end of 2009.
However, he conceded that if commodity prices drop sharply it is also one play EnCana is ready to postpone.
Imperial Oil and sister company ExxonMobil Canada have accumulated about 115,000 acres in Horn River and are in the preliminary phase of developing a program, including modest winter work that could involve drilling wells to get a better fix on the resource.
Target 1 bcf per day EnCana has set an initial target of 1 billion cubic feet per day for its Horn River production, based on results from about a dozen test wells and, along with Apache, expects to drill about 40 wells this year.
The project description for the gas plant says a single facility to serve all producers is preferable, for environmental and economic reasons, to several smaller plants.
As well as processing raw gas for shipment to markets, the plant would also be available for carbon capture and sequestration opportunities “assuming appropriate fiscal programs can be implemented” — a reference to industry hopes of government financing to develop CCS technology.
Richard Neufeld, who has resigned as British Columbia’s energy minister to take a seat in the Canadian Senate, told reporters he has had no indication that companies are planning to scale back spending in Horn River.
Even though the programs have yet to reach the “massive” category, there will be some “serious” work in Horn River this winter as the region develops as a key long-term source of gas, he said.
Describing the Horn River gas as part of a long-term prospect, he said gas will be a “transitional fuel” over many decades and could eventually take a larger role in transportation based on established technology.
John Tasdemir, who heads institutional research at Tristone Capital, said plans for the current winter exploration season may have been trimmed slightly in recent weeks, but expects companies will push ahead in the belief that the economics will improve as the play is “de-risked.”
Like EnCana, Tristone anticipates full-cycle, all-in costs will decrease overtime, with Montney costs already easing and Horn River likely to follow, Tasdemir said.
Pipelines working on delivery Heating up the activities, pipeline companies TransCanada and Spectra Energy are working with potential shippers on delivery systems.
TransCanada said it plans to finalize an application with the National Energy Board in the current quarter for a new 42-inch line to serve Montney.
The Groundbirch Pipeline would be an extension of its Alberta network, provided the board approves TransCanada’s application for its wholly owned NOVA Gas Transmissions to move from Alberta to federal jurisdiction.
That attempted switch was in response to a binding open season when TransCanada sought expressions of interest from producer in northeastern British Columbia to transport about 1 billion cubic feet per day by 2012, with an in-service date of late 2010.
In competition with TransCanada, Spectra has held a binding open season for gas transmission facilities in the region, starting with 260 million cubic feet per day of incremental volumes on the east-bound Alliance pipeline, plus 135 million cubic feet per day of incremental westbound shipments expected to be in service in the final quarter of this year.
Watching these developments is the partnership of Pacific Northern Gas and Kitimat LNG, which is counting on rapid expansion of British Columbia’s gas production to support its C$4.2 billion Pacific Trail project to ship liquefied natural gas from the deepwater port at Kitimat to Asian markets.
The partnership expects to know early this year whether gas producers endorse its argument that there is a “compelling opportunity … to take advantage of the natural gas price gap between the lower prices in North America and the higher prices in Asia.”
It hopes to complete an environmental assessment by March and is in talks with 17 First Nations who have traditional land interests along the route.
The plan involves a 280-mile extension from an existing Pacific Northern Gas pipeline to a liquefaction terminal at Kitimat.
Despite global economic woes, there has been strong interest in the project said Kitimat LNG Vice President Ilene Schmaltz, partly because “the big players in the LNG business tend to be long-term thinkers.”
She said Kitimat LNG dropped its plans to import LNG because of British Columbia’s “plentiful and expanding supplies of natural gas,” including forecasts of a three-fold increase in the province’s output to 10 billion cubic feet per day by 2020 — more than 60 percent of Canada’s total current volumes — and major LNG shortfalls in global markets.
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