DBRS Confirms Canadian Natural Resources at BBB (high), R-2 (high); Trends Stable

DBRS has today confirmed the Commercial Paper and Unsecured Long-Term Debt ratings of Canadian Natural Resources Limited (CNRL or the Company) at R-2 (high) and BBB (high), both with Stable trends, reflective of the Company’s continued strong performance on the operational and financial fronts. All segments, including its largest-ever project, the Horizon oil sands project (Horizon), should continue to generate free cash flow, augmenting longer-term growth, principally in in-situ thermal and Horizon expansions, with incremental production growth in the interim. Credit metrics substantially restored to 2005 levels, pre-Horizon construction, could improve further as the Company continues in debt paydown mode, providing strong support for the current credit ratings. Debt-to-capital of 31% and debt-to-EBITDA of 1.36 times for the rolling 12 months to March 31, 2010 (LTM) were below or at the lower end of the Company’s targeted range of 35% to 45% and 1.0 time to 2.0 times, respectively. DBRS also expects debt-to-cash flow of 1.0 time to 2.0 times (1.49 times). Furthermore, the Company maintains financial flexibility through substantial credit facilities (about $2.5 billion available at June 30, 2010), with minimal maturities to 2012. (Operating results for the second quarter of 2010 are in line with expectations.)

In the near term, DBRS expects the Company to focus on enhancing Horizon’s plant reliability and production levels in an effort to lower its cash operating costs. The Company will likely reach the high end of its guidance range of $31/b to $37/b (45.81/b in Q1 2010 versus $37.94/b in 2009, based on net production) in 2010, which is comparable with the levels seen among its peers. Horizon achieved production of approximately 87,000 b/d (84,000 b/d net) in Q1 2010, close to 80% of the design capacity of 110,000 b/d, rising to about 90% in Q2 2010, exceeding the revised mid-range target for 2010, with full ramp-up anticipated by year-end 2010. The latter is typical of a two-year ramp-up period for most major mining oil sands projects, although it is a year later than the Company’s previous guidance (which was somewhat aggressive).

In June 2009, DBRS confirmed the Company’s ratings and changed the trends to Stable from Negative in anticipation of CNRL’s success in restoring its credit metrics and improving the operational reliability of Horizon during 2009. The Company fully repaid the substantial acquisition loan related to the Anadarko Petroleum Corporation (ACC) assets in 2009, with further debt reduction in Q1 2010. It also managed to largely finance the considerable cost overruns (up 43% to $9.7 billion) on Horizon within the confines of its cash flow, helped by robust commodity prices for most of 2008, a substantial narrowing of heavy-light crude oil differentials (Heavy Differential) and active hedging programs. CNRL also scaled back capital spending in response to the rapidly changing market conditions from Q4 2008. As all major projects are on stream, the Company has reduced its hedging requirements to close to 35% of projected volumes in 2010 using collars at higher average prices than current levels, which should provide a measure of profitability and cash flow stability in the near term.

Based on the Company’s August 2010 guidance and June 2010 corporate presentation premised on WTI of US$77.79/b, Nymex of US$4.94/mcf and midpoint gross production of 642,000 b/d (up 12% from 2009), operating cash flow (estimated at $6.8 billion to $7.2 billion) should more than suffice to cover 2010 capex at an elevated level of $5.0 billion (including $1.1 billion (21%) for property acquisitions), or about 70% higher than 2009. Excess cash flow is expected to be deployed for modest debt reduction and, potentially, for modest-sized opportunistic acquisitions. DBRS estimates that the Company could be cash flow neutral, should WTI be at US$70/b (average of US$78/b for H1 2010). All regions, except North Africa (9% of 2009 EBITDA), where a major drilling program was completed in 2009, are accorded higher capex and should continue to generate strong free cash flow, including the U.K. North Sea (13% of 2009 EBITDA) with mature basins, which should continue to contribute the highest netbacks. About 56% ($2.76 billion) of capital spending is earmarked for core North America conventional developments, with the majority for heavy crude and thermal projects in western Canada and 15% ($759 million) for natural gas, another 13% ($633 million) for Horizon and 10% for International.

The start-up of Horizon synthetic oil production in early 2009 marked a step change for the Company, which should benefit from the project’s long-lived assets, with minimal exploration risk. The inclusion of Horizon’s proved reserves contributed to an over 20-year reserve life in 2008 and 2009 (9.4 years in 2004 before project sanctioning), among the highest of CNRL’s peers. The 2009 proved reserves were adjusted to exclude only crude oil price-related negative reserve revisions. For the corresponding period, CNRL has also achieved strong growth in production and reserves (up 24% and 272%, respectively), despite capex cutback in 2009, while many of its peers are struggling to maintain their volumes and reserves. However, while both the all-in operating cost of $14.96/b and the reserve replacement cost (three-year average) of $17.93/b for conventional operations remain below peer averages, these costs have escalated since 2004. Continued cost control efforts are key to enhancing operational and capital efficiencies.

Longer-term growth prospects are underpinned by Horizon’s expansions (engineering for Phases 2 and 3 currently in process) and ongoing in-situ developments in the Primrose region. The latter could potentially reach 405,000 b/d by 2023 (about 88,000 at H1 2010), complementing the potential expansion to 250,000 b/d for Horizon in the longer term, which together would more than double CNRL’s current production volumes. The Company has no current plans to add upgrading facilities for its conventional and in-situ heavy crude oil (32% of product mix) due to cost pressures. However, it is actively involved in developing blending strategies and working with the major pipeline operators in new transportation projects, extending coverage potentially to the Gulf Coast, where refineries are best equipped to handle heavier crude to minimize the impact of the Heavy Differential. It also has a joint proposal for potential upgrading facilities for the Alberta government’s bitumen share of royalties.

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

The applicable methodology is Rating Oil & Gas Companies, which can be found on the DBRS website under Methodologies.

This is a Corporate (Energy) rating.