DBRS Confirms TransCanada PipeLines Limited at A and R-1 (low)

DBRS has today confirmed the ratings of TransCanada PipeLines Limited (TCPL or the Company), including TCPL’s Unsecured Debentures & Notes at “A” and its Commercial Paper at R-1 (low). The rating for TCPL’s 100% parent, TransCanada Corporation’s (TCC) Preferred Shares – Cumulative (preferreds) has also been confirmed at Pfd-2 (low) based on the strength of TCPL. TCC has no other debt besides the preferreds, and holds no material assets other than the common shares of TCPL and receivables from certain of its subsidiaries. The rating confirmations reflect the Company’s continued stable earnings and cash flow from its regulated pipelines mostly on a cost-of-service basis, and its mostly contracted or low-cost base load power volumes. Furthermore, substantial growth prospects exist, underpinned by long-term contracts on project completion. Should Keystone XL crude oil pipeline project (XL – extending to the Gulf Coast) proceed, incremental capex of $5 billion to $6 billion is expected for the next two years, requiring additional debt issuance at least for the next year. This would pressure the balance sheet and particularly the interest and cash flow coverage ratios. However, financing challenges for TCPL’s $22 billion mega-projects mostly to 2012 (estimated $12 billion spent at June 30 2010) are partly mitigated by the strengthened capital base through issuance of substantial equity and debt instruments, including the recent preferreds issues at TCC, afforded quasi-equity treatment by DBRS. Completed or phased-in projects also augment incremental cash flow for future developments. DBRS believes that the Company has passed the point of maximum risk for funding and executing its growth projects compared to the previous two years.

Cash flow-to-debt has recovered to 0.16 times for the six months ended June 30, 2010 (6M 2010) (0.14 times for 6M 2009), although the 0.15 times ratio for the last 12 months to June 30, 2010 (LTM) was still below previous levels of 0.16 times to 0.18 times. Further, fixed charge coverage fell below 2 times for LTM for the first time in the last decade as a result of the increased debt load during TCPL’s growth phase. The cash flow coverages will likely not improve until 2011 (additional $1 billion EBITDA expected by TCPL) as substantial capex spent on the three largest projects, phase 1 of base Keystone crude oil pipeline (Base Keystone – the portion of the Keystone pipeline system (collectively Keystone) extending to Cushing, Oklahoma), the restart of Units 1 & 2 of Bruce Power A (Bruce Restart) and Alberta North Central Corridor (NCC – completed in June 2010), has yet to generate meaningful cash flow. However, debt-to-capital should remain satisfactory and is expected to remain at or below the 60% level (55% at June 30, 2010), going forward.

DBRS expects TCPL to manage its credit metrics consistent with the current credit ratings. In addition to cash balances of $1.2 billion at June 30, 2010, the Company maintains adequate liquidity through commercial paper programs of its own and that of TransCanada Keystone Pipeline, LP (Keystone US – the US portion of Base Keystone; rated by DBRS at R-1 (low)), totalling $3 billion, fully backed by credit lines. The U.S. operation has doubled its credit facilities to US$2.0 billion mostly available to 2013. This compares with up to $5.5 billion of capex projected for 2011 and $3.5 billion in 2012. Further, on September 23, 2010, the Company issued US$1.0 billion senior notes, which should complete its external financing requirements for 2010, including certain pre-funding for 2011. DBRS expects the Company to arrange permanent financing for Base Keystone when the project is in full operation in 2011. Alternative funding sources include issuance of preferreds, hybrids, or further asset monetization in an effort to balance its rising debt load as seen in the past. Any material deterioration from current credit metrics, whether from cost overruns, project delays or excessive throughput exposure, could have rating implications, although this is not expected by DBRS.

Despite cash flow pressure for the next one to two years as mentioned above, the staged start-up of phase 1 of Base Keystone in mid-2010 (delayed from Q1 2010) should enhance credit metrics in 2011, with the full impact felt in 2013 when XL comes onstream. Should permitting for XL (expected by late 2010) be delayed in view of the current environmental and political climate in the United States, the Company’s capital spending would be greatly reduced, near term. Keystone, including XL, is expected to generate EBITDA of about $1.2 billion based on the existing contracted volumes, which approximates nearly 30% of the Company’s 2009 EBITDA, or over 60% of the Canadian pipelines’ annualized EBITDA based on 6M 2010 operating results. Keystone is mostly supported by long-term contracts, covering about 83% of the pipeline’s design capacity on a cost-of-service basis for the variable portion of the tolling arrangements. Capital cost-sharing provisions with shippers should reduce the risks associated with cost overruns for the construction of XL and the remaining portion of Base Keystone.

The inroad into crude pipelines, such as Keystone, adds diversification to TCPL’s gas-focused pipeline operations. This should alleviate concerns about the Canadian Mainline system’s (Mainline) declining rate base and the steadily lower volumes shipped (negatively impacted by U.S. shale gas developments), resulting in much higher tolls, despite the Company’s mitigating efforts. The increased stake in Keystone (from 50% to 100% during 2008 and 2009, resulting in about $5.3 billion of additional capital commitments) also affirms the Company’s continued focus on stable regulated operations, which should enhance its business risk profile, providing more predictable earnings and cash flow. The Company also benefits from a three-year settlement with the shippers on the Alberta and the Foothills systems reached in June 2010. A higher equity return (ROE) of 9.70% on deemed equity of 40% (previously 8.75% ROE on 35% equity) on a cost-of-service basis, will become effective January 1, 2010, on receipt of regulatory approval (expected in Q3 2010). This could implicate a higher return component for the Mainline when its five-year rate settlement expires in late 2011. TCPL’s pipeline network has access to most shale gas basins as evident by the recent Alberta system expansions. The aforesaid will also diminish the merchant power component of the operation, brought on by the Key Span-Ravenswood, LLC (Ravenswood) acquisition (approximately $2.9 billion purchase price) in 2008, which bears a higher risk profile, albeit offset in part by rising capacity payments in the past few months as a state-owned power facility was retired as planned.

DBRS expects that TCPL will continue to re-balance its pipelines and energy portfolios, while maintaining its conservative credit metrics. Over time, DBRS expects that 65% to 75% of EBITDA (75% at June 30, 2010 and average for prior periods) will emanate from the more stable regulated pipelines, with the remaining 25% to 35% from energy, principally power. The Company will likely pursue higher-return power projects, which are unregulated, such as Bruce Restart and Halton Hills, principally in the growing Ontario market, all supported by long-term contracts with mostly creditworthy counterparties. Other projects, such as the Coolidge power project in Phoenix, Arizona (Coolidge), will be similarly supported by contractual arrangements. Coolidge is TCPL’s first foray in power outside its western Canada and eastern North America regions. Returns in terms of EBITDA (before extraordinary items) to net asset value are estimated at approximately 12% for energy and 8% for pipelines in 2009 (including projects under development).

As a drawback to the Company’s power developments, Bruce Restart (49% interest) is plagued by cost overruns (estimated at 45% to $2.0 billion (net to TCPL) over the original estimate in 2005 or 18% over the 2009 forecast) and potential six- to 12-month project delays to H2 2011. However, this is not expected to have a material impact on the Company’s financial metrics based on its enlarged asset base since 2005. A more favourable floor price contract was re-negotiated for Bruce B in 2009, mitigating lower power prices in a sluggish economy, with Bruce A supported by long-term contracts with Ontario Power Authority (OPA – rated A (high), Stable trend). Also, the economic life of Units 3 and 4 will be extended. In return, certain capital cost-sharing mechanisms previously established during construction were eliminated for cost beyond $3.4 billion, the estimated cost in 2009. Most of the key components of the project are complete.

Longer-term prospects include northern gas developments at Mackenzie Delta (Mackenzie) and Alaska, which are expected by late in the next decade. Both systems would interconnect with the Alberta system, supplying much of the natural gas needed for the growing oil sands production and enhancing the system’s estimated $1.0 billion expansion program into the Fort McMurray oil sands region. In 2009, TCPL signed an agreement with Exxon Mobil Corporation (Exxon Mobil) to work together to advance the Alaska project, with an open season recently concluded. International ventures should be supported by long-term contracts, as seen in the Mexican pipeline project to be completed in March 2011, so as to minimize the attendant political and other risks.

Notes:
All figures are in Canadian dollars unless otherwise noted.

The applicable methodology is Rating North American Energy Utilities (Electric, Natural Gas and Pipelines), which can be found on our website under Methodologies.