Supplies from the Canadian Arctic will be the Rolls-Royce of the North American market with higher costs than even tanker cargoes of liquefied natural gas from overseas, the National Energy Board has been told.
The warning was sounded by prominent American energy consultant Andrew Safir, writing as an expert witness for the C$7-billion (US$5.6-billion) Mackenzie Gas Project’s ownership group of Imperial Oil, ConocoPhillips Canada, Shell Canada and ExxonMobil Canada.
The prediction countered requests, in exchanges of written evidence before the NEB, for changes to the design, tariffs and access rules sought by other potential northern producers the MGP’s proposed C$4.8-billion (US$3.8-billion) Mackenzie Valley Pipeline.
The project cannot afford to be more generous because it faces exceptionally high business risks by international industry standards, Safir’s written evidence suggests.
“With the possible exception of Alaska resources, Mackenzie gas production is likely to be the marginal — that is, highest cost — supplier in the North American market. As a result, Mackenzie gas suppies will be disproportionately vulnerable to shifts in market conditions,” Safir writes.
There is no counterpart for Canadian Arctic gas to “significant subsidies” developing for Alaskan supplies including loan guarantees covering 80% of pipeline costs plus federal and state tax concessions, Safir observes.
Mackenzie gas comes out tops in his calculations of supply costs – including exploration, production and transportation as far as the citygate inlets to local distribution systems — for every market from New York to California.
Getting Canadian Arctic gas to New York is expected to cost nearly C$6 per gigajoule (US$5 per MMBtu) or about C$2 (US$1.60) more than LNG. The cost of supplying Los Angeles from the Mackenzie Delta is projected to approach C$5 per GJ (US$4.20 per MMBtu) or nearly C$1 a GJ (US$0.84) more than LNG.
There is also serious risk that the expenses faced by the Mackenzie group will rise, Safir says. The expert witness points out that so far, only the proposed Arctic pipeline’s owners are firmly committed to buying delivery capacity for their own Delta production. As a result, only 830 MMcf/d or 69% of the proposed initial capacity for 1.2 Bcf/d is booked.
“Projected tolls would increase” if takers do not step forward for the unfilled 31%, Safir predicts. “The amount of the increase would vary each year, but on average tolls would rise by approximately 24% for 15-year contracts and 27% for 20-year contracts annually.”
The increased tolls “could have a significant detrimental impact on shipper costs. This has the potential to weaken the economics of development projects, thereby increasing Mackenzie Valley Pipeline market and supply risk.”
Despite conventional imagery of vast resources awaiting the industry in northern Canada, there is real and significant risk of supply disappointments, adds the project’s geology and engineering expert witness, Gilbert Laustsen Jung Associates.
The Calgary consulting firm lops about 19 Tcf off Arctic supply projections prepared by rival Sproule Associates for the voice of the MGP owners’ budding northern producer rivals, the Mackenzie Explorer Group.
Sproule just makes too much of long-standing projections of undiscovered resources in the still thinly explored Mackenzie Delta-Beaufort Sea region, Gilbert Laustsen Jung says.
The record so far suggests it will take time and new knowledge to nail down the projected undiscovered gas supplies. The biggest known fields — Taglu, Parsons Lake and Niglintgak — were discovered by 1973 with the first 23 exploration wells drilled in the region. Over the following 20 years, another 63 exploration wells failed to find any one deposit exceeding 500 Bcf. The “resource finding rate” dropped to an average 16 Bcf per well in 1973-92 from 181 Bcf in 1966-73, Gilbert Laustsen Jung calculates.
Results of 10 new exploration wells drilled since the MGP stimulated a northern drilling revival in 2001 remain largely confidential.
The MGP also remains rife with unresolved regulatory and government policy risks due to the multiple and often conflicting federal, Northwest Territories and aboriginal jurisdictions involved, writes expert witness Kathleen McShane of Foster Associates Inc.
“No other pipeline in North America has been faced with a similar level of complexity of obtaining the licenses (e.g. water licenses), permits (e.g. land use, water crossing, quarry), and access agreements required to proceed. The project estimates that it requires literally thousands of individual permits and licenses.”
Regardless of recent encouraging signs including increased federal aid commitments to territorial and aboriginal interests, the Canadian Arctic project is still a long way out of the political woods. “The complexity of the permit process, and the lack of clarity in the regulatory process, leading to the possibility of lengthy delays and unanticipated costs, raises the risk that the pipeline will not be competitive in end markets and that supply will not be developed,” McShane writes.
There are also still physical and cost risks posed by the northern natural environment. “The potential for non-completion of the Mackenzie Valley Pipeline is greater than for pipelines built in a less extreme climate. The plan calls for construction to extend over two winter seasons and accordingly lengthens the time frame for construction, leading to the possibility of a material change in market conditions between one construction season and the next,” McShane warns.
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