Proponents of the Mackenzie Gas Project have extended the earliest possible startup date by another four years to 2018, largely because of regulatory delays and the Canadian government’s failure to negotiate a fiscal agreement.
In addition, lead partner Imperial Oil said in a filing with the National Energy Board, the revised launch reflects the need to restaff the project and factor in seasonal constraints before the MGP can go ahead, even if the necessary approvals are obtained from the NEB and the federal government.
“Timely actions by all parties, including the proponents, governments and regulators, will be essential” to achieve the 2018 target, the Imperial letter stated.
The filing coincided with an Arctic gas symposium, where Mike Peters, manager of northern Canada operations with the Canadian Association of Petroleum Producers, said investment in Canada’s Arctic gas sector is suffering because of the regulatory process.
He said the list of obstacles also includes: a very challenging commodity price, high inventories, currency exchange rate volatility and financial market uncertainty.
But he argued that the Arctic resource potential justifies a much greater level of activity and investment than is currently directed at the region, despite an ultimate potential conventional resource of 27.2 billion barrels of oil equivalent.
Northern Canada attracted only C$400 million in capital spending in 2008 and an expected C$500 million in each of 2009 and 2010, compared with total oil and gas expenditures across Canada of C$54 billion in 2008, C$34 billion in 2009 and an expected C$40 billion in 2010.
Decision possible in late ’13Imperial said in its filing that the partners believe a decision is possible by late 2013 on whether to proceed with the MGP, allowing site work to begin in mid-2014, setting the stage for commissioning and startup in the first quarter of 2018.
That timetable assumed that by Sept. 1, 2010, the NEB will have approved the principal project, given that the board’s last round of public hearings is scheduled for April 12-14 in the Northwest Territories.
As well, there would have to be sufficient progress on an agreement with the government covering fiscal terms, the company said.
If all of those requirements are met, a corporate decision could be made this September to restaff the project team and restart the activities leading up to a sanctioning decision.
The activities include securing permits and collecting geotechnical field data, conducting regulatory reviews and obtaining approvals for permit applications and environmental management plans, along with progress on more detailed engineering and construction planning and developing a detailed cost estimate, which has not been updated since 2007 when the proponents put a price tag of C$16.2 billion on the MGP.
Imperial told the NEB there have been confidential discussions between the federal government and the project proponents on fiscal terms for the MGP, although more progress is needed “to allow for restaffing of the project team and for resuming engineering, permitting and field work.”
Report improved understandingImperial said the release in December of the final report from the Joint Review Panel of its recommendations relating to environmental and socioeconomic matters has improved its understanding of the regulatory review and approval process associated with the permits needed before construction and operations activities can get under way.
Imperial also said benefits and access agreements have been negotiated, ratified and executed with aboriginal groups in the Northwest Territories and Alberta except for the Deh Cho, where more negotiations are planned.
Imperial told the NEB it has no fresh evidence to file for the proposed Mackenzie Valley pipeline relating to long-term gas supply, contractual commitments and project financing, although it did submit an updated gas market demand and supply analysis for Canada and the U.S. Lower 48.
The study by Angevine Economic Consulting determined that market conditions in the major North American markets would allow gas from the Mackenzie Delta to be absorbed if the pipeline was in service in 2018.
The study said northern gas would be needed because gas consumption will continue to grow because of increased demand for power generation and industrial purposes, especially for the production and upgrading of oil sands bitumen in northern Alberta, along with the need to offset the decline of conventional production from existing mature gas fields.
It said that since an application for the MGP was initially filed in 2004 and updated in 2007, “there have been significant changes to the gas market in North America. In particular, significant quantities of shale gas have been discovered and are now likely developable, which has changed the overall supply forecasts and price for natural gas. This in turn may significantly affect the economic feasibility of the MGP and the demand for its gas.”
The Angevine study forecast that gas demand in Canada and the Lower 48 will rise to 92.81 billion cubic feet per day in 2030 from 73.73 bcf per day currently.
It projected the oil sands will consume 2.01 bcf per day by 2030 compared with 800 million cubic feet per day this year, while gas-fired power generation would rise in Canada to 2.48 bcf per day.
The study conceded that the expansion of shale gas development in Canada and the United States would help meet total domestic requirements.
“However, even with the delivery of gas to the North American pipeline grid via pipelines from the Mackenzie Delta and Alaska, LNG imports will still be needed to balance supply and demand,” the consulting firm said.
‘Sticky’ cost structureImperial spokesman Pius Rolheiser told reporters said the last attempt to set a startup date for the MGP was three years ago, but that was considered uncertain at the time “because of the regulatory process.”
Peters told the Arctic gas symposium sponsored by the Canadian Institute that the industry is faced with a “sticky” cost structure as labor and material costs have not adjusted from the height of the recent boom, a changing public policy environment and decreased drilling activity.
The spotlight of public attention is also being directed at the industry’s environmental performance, while public and regulatory expectations for the industry are undergoing change, he said.
Peters said CAPP is concerned that some of the Joint Review Panel’s recommendations, if adopted, would “discourage future investment by placing these preconditions on future development.”
He urged a coordination of agencies, avoidance of regulatory overlap and duplication, and the establishment of timelines for project review, along with establishing surface rights legislation.
“Regulatory improvement is not about lowering the bar, but about creating efficiency. I’ve yet to see that a longer process is a better process,” Peters said.