Opportunities and Developments
Keystone is expected to deliver crude oil from Hardisty, Alberta, to U.S. Midwest markets at Wood River and Patoka in Illinois, and to Cushing, Oklahoma.
In March 2008, the U.S. Department of State issued a Presidential Permit to Keystone authorizing construction, maintenance and operations of facilities at the U.S./Canada border for the transportation of crude oil between the two countries. Construction of Keystone began in May 2008 in both Canada and the U.S. Commissioning of the Wood River and Patoka segment is expected to commence in late 2009 with commercial operations to follow in early 2010. Commissioning of the Cushing segment is expected to commence in late 2010.
In June 2008, Keystone received approval from the NEB to add new pumping facilities to accommodate an increase to approximately 590,000 Bbl/d from 435,000 Bbl/d in volumes to be delivered to the Cushing markets.
After an open season conducted during third quarter 2008, Keystone secured additional firm, long-term contracts totaling 380,000 Bbl/d for an average term of approximately 17 years. With these shipper commitments, Keystone will proceed with the necessary regulatory applications in Canada and the U.S. for approvals to construct and operate an expansion of the pipeline system that will provide additional capacity from Western Canada to the U.S. Gulf Coast in 2012 and will increase the total commercial capacity of Keystone to approximately 1.1 million Bbl/d. With the additional contracts, Keystone now has secured long-term commitments for 910,000 Bbl/d for an average term of approximately 18 years. This includes commitments made by shippers to sign transportation service agreements for 35,000 Bbl/d of capacity in an open season to be held in 2009. The commitments represent approximately 83 per cent of the commercial design of the system.
The entire Keystone project is currently expected to cost approximately US$12 billion between 2008 and 2012. In 2008, the Keystone partnerships made capital expenditures of approximately $1.7 billion on the entire project, of which $1.0 billion was contributed by TransCanada.
TransCanada has agreed to increase its equity ownership in the Keystone partnerships up to 79.99 per cent from 50 per cent with ConocoPhillips' equity ownership being reduced concurrently to 20.01 per cent. In accordance with this agreement, TransCanada will fund 100 per cent of the construction expenditures until the participants' project capital contributions are aligned with the revised ownership interests. At December 31, 2008, TransCanada's equity ownership in the Keystone partnerships was approximately 62 per cent. Certain parties that have made volume commitments to the Keystone expansion have an option to acquire up to a combined 15 per cent equity ownership in the Keystone partnerships by the end of first quarter 2009. If all of the options are exercised, TransCanada's equity ownership would be reduced to 64.99 per cent.
Keystone's tolls, tariffs and facilities are regulated by the NEB in Canada and the FERC in the U.S., and have been approved for the segments shipping to Wood River, Patoka and Cushing. The Company expects the tolls and tariffs to remain in place for the term of the initial shipper contracts, which comprise approximately 83 per cent of Keystone's commercial capacity.
In December 2008, the NEB announced that, pursuant to its formula, the 2009 allowed ROE for NEB-regulated pipelines, including the Canadian Mainline, will be 8.57 per cent, a decrease from 8.71 per cent in 2008.
In December 2008, the AUC approved the Alberta System's 2008-2009 Revenue Requirement Settlement Application. As part of the settlement, fixed costs were established for ROE, income taxes and OM&A costs. Any variances between actual costs and those agreed to in the settlement accrue to TransCanada, subject to an ROE and income tax adjustment mechanism, which accounts for variances between actual and settlement rate base, and income tax assumptions. The other cost elements of the settlement are treated on a flow-through basis.
In November 2008, an NEB hearing concluded on TransCanada's application to establish Federal jurisdiction over the Alberta System. A decision is expected from the NEB at the end of February 2009. Changing from AUC to NEB jurisdiction will allow the expansion of the Alberta System beyond Alberta provincial borders.
In October 2008, the AUC approved TransCanada's application for a permit to construct the North Central Corridor expansion at a cost of approximately $925 million. The expansion comprises a 300 km (186 miles) natural gas pipeline and associated compression facilities on the northern section of the Alberta System.
On September 8, 2008, TransCanada reached a proposed agreement with Canadian Utilities Limited (ATCO Pipelines) to provide seamless natural gas transmission service to customers. If approved by regulatory authorities, the arrangement will see the two companies combine physical assets under a single rates and services structure with a single commercial interface for customers but with each company separately managing assets within distinct operating territories in the province. TransCanada continues to work with all stakeholders to finalize this agreement.
In February 2008, the AUC initiated a Generic Cost of Capital proceeding to review the generic ROE and capital structures of AUC regulated utilities. In November 2008, TransCanada filed an application requesting an 11 per cent ROE on 40 per cent deemed common equity for the Alberta System in 2009. The hearing is scheduled to begin on May 19, 2009.
In 2008, ANR completed its STEP 2008 project, which added 14 Bcf of storage and 200 million cubic feet per day (mmcf/d) of withdrawal capacity to the Cold Springs 1 storage field located in Northern Michigan, and increased ANR's total storage capacity to 250 Bcf. The project was completed under budget and service was provided on schedule. Supply on ANR's southwest leg was increased as a result of an interconnect with the Rockies Express natural gas pipeline, which commenced service in January 2008. There is strong potential for new supply on the southeast leg from shale gas in the mid-continent region, and another interconnect with the Rockies Express pipeline is planned for the southeast leg in Indiana in mid-2009. ANR is also pursuing other supply additions on both its southwest and southeast legs.
In September 2008, certain portions of the Company's Gulf of Mexico offshore facilities were impacted by Hurricane Ike. The Company estimates its total exposure to damage costs to be approximately US$30 million to US$40 million, mainly to replace, repair and abandon capital assets, including the estimated cost to abandon an offshore platform. At December 31, 2008, capital expenditures of US$2 million and OM&A costs of US$6 million had been incurred. The remaining costs are primarily expected to be capital expenditures. Service on the majority of the offshore facilities has been restored and related throughput volumes have returned to near pre-hurricane levels. The timing of the remaining facilities' return to service is primarily dependent upon decisions to be made by upstream producers regarding their damaged facilities in the Gulf of Mexico.
In December 2008, Palomar Gas Transmission LLC filed with the FERC for a certificate to build a pipeline extending from the GTN System in central Oregon, to the Columbia River northwest of Portland. The proposed pipeline is expected to be capable of transporting up to 1.3 Bcf/d of natural gas. The project is a 50/50 joint venture of GTN and Northwest Natural Gas Co.
In September 2008, the FERC approved North Baja's application to build a natural gas pipeline to serve the Yucca Power Plant owned by Arizona Public Service Company. Three miles of the proposed pipeline are expected to be in the U.S. and owned by North Baja, and another three miles in Mexico are owned by Gasoducto Bajanorte. Pending final approval by the U.S. Government, construction is expected to commence in first quarter 2009 with a projected in-service date of May 2009.
On April 1, 2008, Portland filed a general rate case with the FERC proposing a rate increase of approximately six per cent as well as other changes to its tariffs. In accordance with a FERC order dated May 1, 2008, the proposed tariffs went into effect on September 1, 2008, subject to refund. The hearing is scheduled to begin on July 13, 2009.
In December 2008, the NEB concluded a proceeding with respect to TQM's Cost of Capital application for 2007 and 2008. The application sought an ROE of 11 per cent on deemed equity of 40 per cent. The proceeding also provided an opportunity for TQM to propose alternatives to the current ROE formula. A decision from the NEB is expected in first quarter 2009.
U.S. Rockies Pipeline Projects
The Bison pipeline project is a proposed pipeline from the Powder River Basin in Wyoming to the Northern Border system in North Dakota. The project has shipping commitments for approximately 405 mmcf/d and is expected to be in service in fourth quarter 2010. The capital cost of the Bison pipeline project is estimated at US$500 million to US$600 million. TransCanada continues to work with Bison shippers to finalize the size and design of this project.
In addition, TransCanada is proposing the Pathfinder pipeline project, a 1,006 km (625 miles) pipeline from Meeker, Colorado to the Northern Border system in North Dakota. A portion of the Pathfinder pipeline may share a common route with the Bison pipeline and may also share some common facilities. TransCanada continues to work with prospective Pathfinder shippers to advance this project.
TransCanada and Williams Gas Pipeline Company, LLC (Williams) are evaluating the development of the Sunstone pipeline, a proposed pipeline from Wyoming to Stanfield, Oregon. This project would provide Pacific Northwest and California markets with access to incremental Rockies supply. TransCanada and its partner continue to work with customers to determine the appropriate size, time and route for this project.
Mackenzie Gas Pipeline Project
The MGP is a proposed 1,200 km (746 miles) natural gas pipeline to be constructed from a point near Inuvik, Northwest Territories to the northern border of Alberta, where it is expected to connect to the Alberta System.
TransCanada's involvement with the MGP arises from a 2003 agreement between the Mackenzie Valley Aboriginal Pipeline Group (APG) and the MGP, whereby TransCanada agreed to finance the APG's one-third share of the pre-development costs associated with the project. Cumulative advances made by TransCanada totaled $140 million at December 31, 2008 and are included in Other Assets. These amounts constitute a loan to the APG, which becomes repayable only after the natural gas pipeline commences commercial operations. The total amount of the loan is expected to form part of the rate base of the pipeline and to subsequently be repaid from the APG's share of future natural gas pipeline revenues or from alternate financing. If the project does not proceed, TransCanada has no recourse against the APG for recovery of advances made. Accordingly, TransCanada's ability to recover its investment through loan repayments and/or equity ownership in the project depends upon a successful outcome of the project.
Under the terms of certain MGP agreements, TransCanada holds an option to acquire up to a five per cent equity ownership in the natural gas pipeline at the time of the decision to construct it. In addition, TransCanada gains certain rights of first refusal to acquire 50 per cent of any divestitures by existing partners and an entitlement to obtain a one-third interest in all expansion opportunities once the APG reaches a one-third ownership share, with the other natural gas pipeline owners and the APG sharing the balance.
TransCanada and the other co-venture companies involved in the MGP continue to pursue approval of the proposed project, focusing on obtaining regulatory approval and the Canadian government's support of an acceptable fiscal framework. Project timing continues to be uncertain. Detailed discussions with the Canadian government have taken place and have resulted in a proposal in January 2009 from the government to the MGP. The co-venture group is considering the proposal and is expected to respond to the government in the near future. In the event the co-venture group is unable to reach an agreement with the government on an acceptable fiscal framework, the parties will need to determine the appropriate next steps for the project. For TransCanada, this may result in a reassessment of the carrying amount of the APG advances.
Alaska Pipeline Project
In November 2007, TransCanada submitted an application to the State of Alaska for a license to construct the Alaska Pipeline Project under the AGIA. In January 2008, Alaska Governor Sarah Palin's administration determined that TransCanada's application was the only proposal that met all of the state's requirements and in December 2008 the State of Alaska issued the AGIA license to TransCanada. Under the AGIA, the State of Alaska has agreed to reimburse a share of TransCanada's eligible pre-construction costs to a maximum of US$500 million.
The Alaska Pipeline Project will be a 4.5 Bcf/d natural gas pipeline extending approximately 2,760 km (1,715 miles) from a new natural gas treatment plant at Prudhoe Bay, Alaska to Alberta. This pipeline will integrate with the Alberta System to provide access to diverse markets across North America. The application included provision for expansions up to 5.9 Bcf/d through the addition of compressor stations in Alaska and Canada. TransCanada estimated the total capital cost of the entire project to be approximately US$26 billion in 2007 dollars.
Since the AGIA license was awarded, TransCanada has moved forward with developing the project, which involves engineering, environmental, aboriginal relations and commercial work to conclude an initial binding open season by mid-2010. TransCanada continues its efforts to align with potential shippers and if sufficient firm contracts are secured in the open season, construction would begin following regulatory approvals, with an anticipated in-service date of 2018.