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Vol. 15, No. 52 Week of December 26, 2010
Providing coverage of Alaska and northern Canada's oil and gas industry

Mac approved — sort of

Mackenzie pipeline regulatory phase winds down; still a long road for project

Gary Park

For Petroleum News

Canada’s federal energy regulator has approved the Mackenzie Valley natural gas project in a decision that is viewed as more of a signpost to the long road ahead than a truly significant milestone.

No one among the proponents or critics seriously expected the National Energy Board would reject the application outright and it didn’t.

Nor was it a surprise that the approval came with a pile of conditions — 264 of them — covering engineering, safety and environmental protection.

The response from all sides was muted. There was no sense of joy or celebration that the Mackenzie Gas Project has completed a regulatory process that lasted six years, or almost a decade since the dream of reviving commercialization of Arctic gas was revived, or 37 years since a proposal was first immodestly touted as “the biggest project in the history of free enterprise.”

Project in public interest

The NEB said Dec. 16 that the plan by Imperial Oil, with a 34.4 percent stake, and its co-venturers — the Aboriginal Pipeline Group (33.3 percent), ConocoPhillips (15.7 percent), Royal Dutch Shell (11.4 percent) and ExxonMobil Canada (5.2 percent) — to build a 720-mile pipeline through the Northwest Territories to carry 1.2 billion cubic feet per day (1.8 bcf per day by adding compression) was “in the public interest,” based on current and future gas needs.

Acknowledging that the MGP would have “much larger and far reaching effects than previous developments in the North,” the NEB said the project came under a broad examination, based on how it would “affect the people, the land where they live, and the economy, now and in the future.”

But it concluded the MGP would usher in a new era of economic development in the Arctic and “contribute to strong, self-reliant communities that continue to take care of the land and the people in the North.”

The federal cabinet is now expected to decide in early 2011 whether to sign off on the NEB’s approval, said Environment Minister John Baird, who carries the MGP file, although Natural Resources Minister Christian Paradis will recommend whether the final go-ahead should be issued.

Describing the MGP as exciting for Canada’s North and the Canadian economy, Baird said the government is eager to “jump the next hurdle in getting the regulatory approvals completed.”

Unresolved issues

Even if that occurs, the MGP is left with a stack of unresolved matters and unanswered questions, which could mean the project is barely as its halfway point.

It’s taken a decade of deliberation and regulatory processes; it could now take another decade of negotiations with the Canadian government over a fiscal agreement, processing of about 6,300 permits and authorizations, investment decisions by the corporate partners and construction before gas could flow from the Mackenzie Delta, as late as 2020.

The major elements covered by the permits include the main pipeline, a separate 280-mile natural gas liquids pipeline to an existing crude oil pipeline at Norman Wells in the central NWT, and the drilling of 28 wells from six pads at the three anchor onshore gas fields which hold an estimated 6 trillion cubic feet of natural gas.

Imperial spokesman Pius Rolheiser said the NEB approval is a “positive step for the project.” Beyond that, however, “a number of steps remain and much more work remains to be done before the project can become a reality,” he said.

That includes finishing engineering work, updating the cost estimate which was last set at C$16.2 billion four years ago and acquiring the necessary permits all before an investment decision can be made by the partners, likely in 2013.

Construction start date an issue

However, the consortium is troubled by the NEB’s insistence that construction must start by the end of 2015, one year earlier than Imperial had requested.

Rolheiser said the 2015 deadline “will prove very challenging,” putting pressure on both the MGP partnership and the government to reach an agreement on the fiscal terms, opening the way to re-staffing the project team and carrying out additional work.

But the drawn-out regulatory phase, which took twice as long as originally hoped, has allowed both known and unexpected competition to intervene, turning what was once seen as a certain project into a questionable proposition.

Government and industry leaders have been largely agreed on one thing — if a 4 bcf per day overland gas pipeline from Alaska, through Canada, to the Lower 48 proceeds first, the MGP would probably be unable to compete for construction labor, materials or market share and would likely be shelved indefinitely.

Compounding the economic doubts surrounding the MGP, fast-rising output from North America’s shale plays has dragged gas prices to around $4 per thousand cubic feet, where many producers expected it will remain for at least five years. Some analysts have set $6 per thousand cubic feet as an economic threshold for the MGP.

No shortage of upbeat views

There’s no shortage of industry and government leaders who take an upbeat view of the MGP’s chances proceeding.

NWT Industry Minister Bob McLeod — one of the strongest advocates of natural gas becoming a vital transportation fuel in North America — said the NEB decision was “an early Christmas present” for a project that “could provide significant economic and environmental benefits” for the NWT and Canada.

Bob Reid, president of the Aboriginal Pipeline Group (which must arrange about 400 million cubic feet of gas supplies from independent producers to secure its one-third equity stake in the MGP), said the MGP is “truly a nation-building project. It’s going to be able to deliver the clean energy we need in an environmentally responsible way.”

Brenda Kenny, president of the Canadian Energy Pipeline Association, said the MGP could “open a brand new supply basin” in the Mackenzie Delta and Beaufort Sea and “provide thousands of jobs that would not occur otherwise.”

Dave Collyer, president of the Canadian Association of Petroleum Producers, said the MGP is a “long-term project with a long project life and I think the proponents will ultimately make their decision based on their long term view of gas prices.”

But he touched on the issue that causes the greatest doubt among industry observers by noting how much the market has changed since the MGP was proposed, adding “we have to accept that it’s a more difficult market.”

Market challenges

Rolheiser agrees that the challenge for the MGP is to “compete on a supply/cost basis with other sources of supply in the North American market. That includes liquefied natural gas, shale gas, a potential Alaska project and other sources of supply.”

Boyd Russell, of Energy Navigator, doubts the MGP will ever proceed because of the estimated 6,000 trillion cubic feet of recoverable shale gas in North America, most of it in the United States and closer to customers than pipelines from the Arctic.

Derek Evans, chief executive officer of Pengrowth Energy Trust, doubts gas producers in Western Canada would be happy to see the Canadian government give financial support to the MGP at a time when surplus gas is already beating down North American prices.

Ralph Glass, an economist and vice president with AJM Petroleum Consultants, said the companies involved in the MGP have better opportunities to put their money to work in the shale plays southern Canada and the United States.

“There’s so much gas available now, or potentially available, with the new technology that is taking hold that the Mackenzie project is not economically viable,” he argued.

But there is a solid assortment of observers who insist Mackenzie gas could take its place in the North American supply equation by displacing coal in electricity generation, which could have a positive impact on both Mackenzie and Alaska gas.



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South Korea backs Arctic

State-run Korea Gas Corp. has made a C$30 million bet on the future of Arctic energy by acquiring a minority share of a Significant Discovery License on the Mackenzie Delta from MGM Energy, the smallest, liveliest — and, in recent years, the only — explorer in the region.

The deal made through wholly owned subsidiary KOGAS Canada involves the 21,000 acres Umiak SDL, which includes both a natural gas and oil discovery.

MGM, as operator, is selling 20 percent of its 60 percent working interest in the SDL, which gives it indefinite tenure over the lease. ConocoPhillips owned the remaining 4 percent interest.

KOGAS will pay C$20 million when the transaction closes, likely by February, and C$10 million if and when a decision is made to construct the Mackenzie Valley pipeline, or some other project is approved to commercialize production from the SDL.

MGM has an estimated net mean contingent plus prospective resources of 328 billion cubic feet for its 60 percent stake in Umiak. The KOGAS acquisition represents a sale of 109 billion cubic feet, or about 12 percent of MGM’s current net mean contingent plus prospective resource base of 887 bcf.

Based on expected activity levels, proceeds from the sale will be sufficient to fund MGM’s capital and operating expenditures into 2012.

Korea Gas to invest US$1.1B

Korea Gas agreed earlier this year to invest US$1.1 billion to joint develop gas fields in Canada with Encana, taking a 50 percent stake in properties in the Montney and Horn River unconventional plays in sparsely drilled areas of northeastern British Columbia.

MGM President Henry Sykes said the deal “is an expression of confidence in the value of natural gas resources in Northern Canada, the quality of the Umiak SDL and the prospect of a Mackenzie Valley pipeline.”

MGM also said that, subject to regulatory approvals, it will drill an oil prospect in the Great Bear River area of the Central Mackenzie Valley, where it acquired seismic last winter.

It expects to spud the well in early February, with a total project cost of C$8 million (C$4 million net to MGM).

Sykes said that although the well is high risk, “the potential is great and any oil discovered can be transported on the existing Norman Wells pipeline,” an underutilized system from the Northwest Territories only commercial oil field to northern Alberta.

—Gary Park