On February 22, 2007, TransCanada closed its acquisition of ANR and an additional 3.55 per cent interest in Great Lakes from El Paso Corporation for approximately US$3.4 billion, subject to certain post-closing adjustments, including approximately US$488 million of assumed long-term debt. This transaction will significantly expand the Company's continental natural gas pipeline and storage operations.
ANR operates one of the largest interstate natural gas pipeline systems in the U.S., providing transportation, storage, and various capacity-related services to a variety of customers in both the U.S. and Canada. The system consists of approximately 17,000 km of pipeline with a peak-day capacity of 6.8 Bcf/d. It transports natural gas from producing fields in Louisiana, Oklahoma, Texas and the Gulf of Mexico to markets in Wisconsin, Michigan, Illinois, Ohio and Indiana. The pipeline system also connects with numerous other pipelines providing customers with access to diverse sources of supply from western Canada and the Rocky Mountain region and access to a variety of end-user markets in the midwestern and northeastern U.S.
ANR also owns and operates numerous underground natural gas storage facilities in Michigan with a total capacity of approximately 230 Bcf. Its facilities offer customers a high level of service flexibility allowing them to meet peak-day delivery requirements and to capture the value resulting from changing supply and demand dynamics. As part of the acquisition, TransCanada will also obtain certain natural gas supplies contained within production and storage reservoirs in Michigan.
On February 22, 2007, PipeLines LP closed its acquisition of a 46.45 per cent interest in Great Lakes from El Paso Corporation for approximately US$962 million, subject to certain post-closing adjustments, including approximately US$212 million of assumed long-term debt. Great Lakes owns and operates a 3,402 km interstate natural gas pipeline system with a design capacity of 2.5 Bcf/d. TransCanada is the general partner of and holds a 32.1 per cent interest in PipeLines LP.
In May 2006, TransCanada filed for approval of two Canadian Mainline services designed to meet the growing needs of natural gas-fired power generators in Ontario. These services are designed to ensure that shippers can access transportation on as little as 15 minutes notice so they can better match the timing of their natural gas transportation needs with the timing of their power generation requirements. The application was the subject of an oral public hearing in September 2006 and, in December 2006, the NEB approved implementation of the services with minor modifications.
In December 2006, TransCanada applied to the NEB for approval of a new receipt point at Gros Cacouna on the Canadian Mainline. The Company is also seeking affirmation of the tolling methodology that will apply to service from that point. The new receipt point would accommodate receipts of regassified LNG at Gros Cacouna, bringing a new source of supply to the Canadian Mainline to serve markets in eastern Canada and the U.S. Northeast. The NEB has established a procedure to deal with the Gros Cacouna, Québec receipt point application which includes an oral hearing expected to begin in April 2007.
On February 21, 2006, the EUB issued its decision on the 2005 GRA Phase II. The EUB approved the 2005 rate design as applied for. With this decision, TransCanada was able to finalize the 2005 and 2006 Alberta System tolls on March 14, 2006. The 2006 final tolls were effective April 1, 2006. TransCanada had been charging interim tolls since January 1, 2006 with the EUB's approval.
TransCanada filed for a Review and Variance on the Ventures LP's Transportation by Others (TBO) costs following the EUB decision on the 2004 GRA Phase I. At the time, the EUB denied certain costs associated with the Ventures LP's new TBO contract that was replacing the old TBO contract. In its decision on November 28, 2006, (Decision 2006-069), the EUB allowed for the recovery of approximately $1 million of costs due to the timing of the termination and commencement of the TBO contracts.
On November 30, 2006, the EUB finalized the 2007 generic ROE formula results. For 2007, the Alberta System's ROE will be 8.51 per cent; down from 8.93 per cent in 2006.
On December 20, 2006, the EUB approved TransCanada's application to charge interim tolls for transportation service, effective January 1, 2007. Final tolls for 2007 will be determined in first quarter 2007 upon updating of the flow-through cost components of the revenue requirement to reflect actual costs and revenues from the prior year.
In June 2006, TransCanada filed a rate case with the FERC for its Gas Transmission Northwest System. The rate case filing was primarily driven by decreased revenues due to contract non-renewals and shipper defaults. The comprehensive filing requested a number of tariff changes including an increase in rates for transportation services that became effective January 1, 2007, subject to refund. The proposed rates include an ROE of 14.5 per cent, a common equity ratio of 62.99 per cent and a depreciation rate for the transmission plant of 2.76 per cent. The rates in effect prior to the January 2007 rate increase were based on the last rate case filed in 1994.
In January 2007, TransCanada received a procedural order from the FERC establishing a timeline for the system's rate case proceeding. The hearing into this rate case is scheduled to commence on October 31, 2007.
TransCanada filed applications with the NEB in early December 2005 for approval of 2006 tolls for Foothills and the BC System, reflecting an agreement with the Canadian Association of Petroleum Producers (CAPP) and other stakeholders to increase the deemed equity component of the capital structure of each system to 36 per cent from 30 per cent. On December 21, 2005, the NEB approved Foothills' application as filed. On February 22, 2006, the NEB finalized the BC System's 2006 tolls as filed.
In March 2006, TransCanada initiated discussions with shippers on the BC System to integrate the BC System with Foothills. The discussions culminated in a settlement agreement (Integration Settlement) between Foothills and CAPP. The Integration Settlement amended an existing settlement for Foothills and includes a sharing mechanism for anticipated cost savings through increased administrative efficiencies arising out of the integration of the two systems. TransCanada filed Foothills and BC System's integration application and related approvals with the NEB on December 21, 2006. In February 2007, the NEB approved the application as filed.
In December 2006, TransCanada commenced commercial operations of the Tamazunchale pipeline. The 36 inch, 130 km pipeline in central Mexico extends from the facilities of Pemex Gas near Naranjos, Veracruz and transports natural gas under a 26-year contract with the Comisión Federal de Electricdad to an electricity generation station near Tamazunchale, San Luis Potosi.
The pipeline is designed to transport initial volumes of 170 million cubic feet per day (mmcf/d). Under the contract, the capacity of the Tamazunchale pipeline is expected to be expanded, beginning in 2009, to approximately 430 mmcf/d to meet the needs of two additional proposed power plants near Tamazunchale.
On February 7, 2006, North Baja Pipelines LLC (North Baja) filed an application with the FERC to expand and modify its existing system to facilitate the importation of up to 2.7 Bcf/d of regassified LNG from Mexico into the California and Arizona markets. Specifically, North Baja proposes to modify its existing system to accommodate bi-directional natural gas flow, to construct a new meter station and a 36 inch pipeline to interconnect with Southern California Gas Company, to construct approximately 74 km of lateral facilities to serve electric generation facilities, and to loop its entire approximately 129 km existing system with a combination of 42 inch and 48 inch diameter pipeline. In addition to its FERC certificate of public convenience and necessity, which includes a determination on environmental issues, the project will need various permits and leases from the U.S. Bureau of Land Management, the California State Lands Commission and other agencies. On October 6, 2006, the FERC issued a preliminary determination approving all aspects of North Baja's proposal other than those related to environmental issues, which will be the subject of a future order.
In November 2005, TransCanada, ConocoPhillips Company and ConocoPhillips Pipe Line Company (CPPL) signed a Memorandum of Understanding which commits ConocoPhillips Company to ship crude oil on the proposed Keystone Pipeline, and gives CPPL the right to acquire up to a 50 per cent ownership interest in the pipeline. On January 31, 2006, TransCanada announced it has secured firm, long-term contracts totalling 340,000 barrels per day with durations averaging 18 years. The commitments were obtained through the successful completion of a binding Open Season held during fourth quarter 2005. With these commitments from shippers, TransCanada proceeded with regulatory filings for approval of the project.
At an estimated cost of approximately US$2.1 billion, the Keystone Pipeline is intended to transport approximately 435,000 barrels per day of crude oil from Hardisty, Alberta, to Patoka, Illinois through a 2,960 km pipeline system. The pipeline can be expanded to 590,000 barrels per day with additional pump stations. In addition to approximately 1,730 km of new pipeline construction in the U.S., the Canadian portion of the proposed project includes the construction of approximately 370 km of new pipeline and the conversion of approximately 860 km of TransCanada's existing pipeline facilities from natural gas to crude oil transmission. At December 31, 2006, the Company had capitalized $39 million related to Keystone.
In 2006, TransCanada and TransCanada's wholly owned subsidiary, TransCanada Keystone Pipeline GP Ltd. (Keystone), filed two regulatory applications with the NEB for the Canadian leg of the Keystone Pipeline. In June 2006, TransCanada filed the first application with the NEB seeking approval to transfer a portion of its Canadian Mainline natural gas transmission facilities to Keystone for use as part of the Keystone Pipeline. As part of the transfer application, TransCanada sought approval to reduce the Canadian Mainline's rate base by the NBV of the transferred facilities and to add the NBV of these facilities to the Keystone Pipeline rate base. Public hearings on the transfer application were completed in mid-November 2006. Approval was received from the NEB in February 2007.
In the second application, TransCanada sought approval to construct and operate new facilities in Canada including approximately 370 km of new oil pipeline, terminal facilities at Hardisty, Alberta and required pump stations. TransCanada is also seeking approval of the tolls and tariff for the pipeline. A decision on this application is anticipated from the NEB in fourth quarter 2007.
In April 2006, TransCanada filed an application with the U.S. Department of State for a Presidential Permit authorizing the construction, operation and maintenance of the U.S. portion of the Keystone Pipeline. In September 2006, the Department of State issued a formal notice of the application as well as a Notice of Intent to prepare an Environmental Impact Statement for the project.
In June 2006, TransCanada filed a petition with the Illinois Commerce Commission for a certificate authorizing the pipeline and granting authority to exercise eminent domain. The matter is expected to go to hearing in March 2007.
Shippers have also expressed interest in a proposed extension of the Keystone Pipeline to Cushing, Oklahoma. Through an Open Season, which will close at the end of first quarter 2007, binding commitments are being solicited to support the Cushing Extension, which would expand the Keystone Pipeline from a capacity of approximately 435,000 barrels per day to 590,000 barrels per day, and see the construction of a 468 km, 36 inch extension of the U.S. portion of the pipeline to Cushing. The expansion and extension would enable Keystone to provide access for increasing western Canadian crude supply to two key markets and transportation hubs at Patoka and Cushing. The expected capital cost is US$700 million and the targeted in-service date is fourth quarter 2010.
The Heartland extension is a proposed 190 km pipeline from Hardisty which would connect Keystone to the Fort Saskatchewan area. This extension would increase the Keystone Pipeline's market supply reach and provide incremental transportation service between Alberta's two major crude oil centres. The expected capital cost is approximately US$300 million. Discussions are under way with shippers to gauge the level of interest with an anticipation of moving forward with commercial arrangements later in 2007. The targeted in-service date of the Heartland extension is 2010/2011.
TransCanada is in the business of connecting energy supplies to markets and it views the Keystone opportunity as another way of providing a valuable service to its customers. Converting one of the Company's natural gas pipeline assets for oil transportation is an innovative, cost-competitive way to meet the need for pipeline expansions to accommodate anticipated growth in Canadian crude oil production during the next decade.
The MGP is a 1,200 km natural gas pipeline proposed to be constructed from near Inuvik, Northwest Territories to the northern border of Alberta, where it would then connect to the Alberta System. In June 2006, TransCanada submitted an application to the EUB for approval of the Dickins Vardie facilities, a $212 million capital project required to provide the Alberta System interconnection facilities for Mackenzie gas volumes.
Throughout 2006, the MGP proponents participated in public hearings convened by the NEB and by a Joint Review Panel (JRP) constituted to assess socio-economic and environmental aspects of the project. These latter hearings are expected to conclude in second quarter 2007, with the JRP's report ultimately being submitted into the NEB review process. Concurrently, the project proponents have been reassessing the capital cost estimate and construction schedule for the MGP, in light of overall industry cost escalations and labour shortages. A revised capital estimate for the project is expected to be filed with the NEB in first quarter 2007.
Apart from the Alberta System interconnection facilities, TransCanada's involvement with the MGP is derived from a 2003 agreement with the APG and the MGP by which TransCanada agreed to finance the APG's one-third share of the pipeline's pre-development costs associated with the project. These costs are currently forecasted to be approximately $145 million by the end of 2007. Cumulative advances made by TransCanada in this respect totalled $118 million at December 31, 2006 and are included in Other Assets. These amounts constitute a loan to the APG, which becomes repayable only after the date upon which the pipeline commences commercial operations. The total amount of the loan is expected to ultimately form part of the rate base of the pipeline, and the loan will subsequently be repaid from the APG's share of available future 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, the recovery of the advances is dependent upon a successful outcome of the project.
Under the terms of certain MGP agreements, TransCanada holds an option to acquire up to five per cent equity ownership in the pipeline at the time of the decision to construct. 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 pipeline owners and the APG sharing the balance.
In 2006, TransCanada continued its discussions with Alaska North Slope producers and the State of Alaska regarding the Alaskan portion of the proposed Alaska Highway Pipeline Project. In early 2006, Alaska's State administration reached a preliminary agreement with ConocoPhillips Alaska Inc., BP Exploration (Alaska) Inc. and ExxonMobil Alaska Production Inc. for the pipeline project. However, the State Legislature did not ratify that agreement. Alaska's new Governor, elected in November 2006, has indicated the new administration intends to introduce a different process for the pipeline project in 2007.
Foothills Pipe Lines Ltd. (Foothills) holds the priority right to build, own and operate the first pipeline through Canada for the transportation of Alaskan gas. This right was granted under the Northern Pipeline Act of Canada (NPA), following a lengthy competitive hearing before the NEB in the late 1970s, which resulted in a decision in favour of Foothills. The NPA creates a single window regulatory regime that is uniquely available to Foothills. It has been used by Foothills to construct facilities in Alberta, B.C. and Saskatchewan, which constitute a prebuild for the Alaska Highway Pipeline Project, and to expand those facilities five times, the latest of which was in 1998. Continued development under the NPA should ensure the earliest in-service date for the project.
The primary driver for infrastructure projects for the Alberta System is the development of natural gas supply and market demand in the various regions served by the Alberta System. In 2006, natural gas prices were lower than in 2005 which resulted in some slowdown in natural gas drilling activity levels. Nevertheless, activity remains strong which has resulted in supply growth in some regions of western Canada and an increased requirement for new transmission infrastructure. The primary source of supply growth has been deeper conventional drilling in western Alberta, northeastern B.C. and coalbed methane development in central Alberta.
TransCanada will continue to focus on the cost effective and timely connection of new gas production volumes so that customers can promptly access markets. As well, service flexibility will continue to be a focus to ensure TransCanada remains competitive.
TransCanada received approval from the EUB in April 2006 to construct new natural gas transmission facilities to serve the firm intra–Alberta delivery contract requirements of oil sand developers in the Fort McKay area. These facilities include 127 km of pipeline and three metering facilities at an estimated capital cost of $125 million. In addition to the proposed Fort McKay facilities, TransCanada constructed additional metering facilities to serve approximately 200 mmcf/d of firm intra–Alberta delivery contracts.
Historically, TransCanada's eastern pipeline system has been supplied by long-haul flows from western Canada and by volumes received from storage fields and interconnecting pipelines in southwestern Ontario. In the future, the eastern pipeline system may also be supplied by LNG deliveries from proposed regassification facilities in Québec and the northeastern U.S.
Power generation continues to be the primary driver for incremental gas demand in eastern Canada and the northeastern U.S. Power projects that require significant volumes of natural gas continue to be developed, supporting utilization of the eastern pipeline system. Aligned with these power project developments, TransCanada received NEB approval in 2006 for two new services targeted at attracting incremental demand for natural gas transportation on the Canadian Mainline system.
In addition, TransCanada completed construction of three NEB-approved facilities on its Canadian Mainline system in 2006. This included the Stittsville and Deux Rivières loops of approximately 38 km of 42 inch pipe with a capital cost of approximately $113 million, and the Les Cèdres loop of approximately 21 km of 36 inch pipe with a capital cost of $56 million.