Arctic natural gas has become an energy counterpart to the Northwest Territories diamonds marketed as Canadian Ice as a result of steeply hiked cost estimates for the proposed northern production and pipeline system.
New details of the increased C$16.2 billion (US$13.9 billion) price tag for the Mackenzie Gas Project, filed with the National Energy Board, explain why officials of senior partner Imperial Oil have taken to calling its economics “not robust.”
Tolls projected for the proposed 1,200-kilometer (750-mile) Mackenzie Valley Pipeline alone work out to C$2.89-$3.04 per gigajoule (US$2.58-$2.71 per MMBtu). That is about triple the current rate for sending Western Canada gas east on the TransCanada system to domestic markets and export points in Ontario and Quebec.
Arctic shippers are offered the low end of the forecast toll range as an incentive for signing 20-year transportation contracts. The high end includes a penalty of C15 cents (US13 cents) for making only 15-year commitments.
Construction costs of the long-distance line from the Mackenzie Delta to the top of the TransCanada system in northern Alberta escalated to C$7.8 billion (US$6.6 billion).
The pipeline consortium of Imperial, Shell Canada, ConocoPhillips, ExxonMobil Canada and the Aboriginal Pipeline Group seeks returns of 10.67% on equity and 5.3% on debt. With the financing split set at 70% debt and 30% equity, the overall return on rate base sought comes out to 6.91%.
Over a two-decade period following the first full year of service in 2015, the tolls are projected to drop gradually into a range of C$0.93-$1.08 per GJ (US83-92 cents per MMBtu) as construction costs are paid off, shipping volumes grow and the line is depreciated.
But the Canadian North is notoriously a big place, and projected costs of transporting arctic gas to the inlet of the Mackenzie line at the chief Delta town of Inuvik are also nothing to sneeze at. From the remotest production reached by the Mackenzie project’s gathering system, transportation rates are forecast to run as high as C98 cents per GJ (US87 cents per MMBtu). There are also gas compression and processing fees.
While aboriginal rights disputes contributed to an announced three-year delay in the Mackenzie project’s earliest possible in-service date of late 2014, industry factions are also dueling over the gathering system.
Potential Arctic producers outside the Mackenzie project consortium have lodged a court appeal, seeking conversion of the gathering system into a utility with regulated rates. The network is currently structured as a private gas-field gathering joint venture led by Imperial.
The gathering network is projected to cost C$11.35 billion (US$9.6 billion). Other major costs include C$1.2 billion (US$1 billion) for an Inuvik plant, to be paid for with processing fees, plus C$950 million (US$808 million) for a liquids byproduct pipeline from the Delta south to Norman Wells in the central Mackenzie Valley, where Imperial and Enbridge have operated an oil production and delivery system since the mid-1980s.
The revised Mackenzie project plan calls for gas deliveries to start at 960 MMcf/d, rising as fast as transportation contracts can be landed to 1.2 Bcf/d and eventually to the system’s maximum capacity of 1.9 Bcf/d by adding compressors. Initial deliveries were cut below 1 Bcf/d by deferring construction of two compressor stations until new shippers step forward.
Costs of Delta production systems proposed by the Mackenzie project consortium members have also ballooned to C$4.9 billion (US$4 billion) — or as much as initial forecasts for the entire Arctic development when it was first proposed eight years ago. Participants in prolonged regulatory hearings, still under way after more than a year of sessions with no end in sight yet, observe that the consortium’s ardor dimmed as markets changed, with prices falling and prospects of liquefied natural gas proposals accelerating past the glacial pace set by the northern project.
Cost estimates mushroomed, largely as a result of changed industry conditions over long years of regulatory delays, even though project engineers found some corners to cut.
The project cut forecast labor and work camp needs by spreading construction more evenly over three full winter work seasons. Activity shuts down during Arctic summers due to soft, boggy ground and potential damage to underlying permafrost layers. The Mackenzie consortium also trimmed needs for expensive northern transportation services by increasing use of river barges and freighters capable of traversing the Beaufort Sea.
©Copyright 2007Intelligence Press Inc. All rights reserved. The preceding news reportmay not be republished or redistributed, in whole or in part, in anyform, without prior written consent of Intelligence Press, Inc.
© 2020 Natural Gas Intelligence. All rights reserved.
ISSN © 1532-1231 | ISSN © 2577-9877 |