DBRS Confirms Encana Corp. Ratings at A (low) and R-1 (low), Stable Trends

DBRS has today confirmed the ratings of the Unsecured Senior Notes and the Medium-Term Notes & Debentures of Encana Corporation (Encana or the Company) and the Unsecured Long-Term Notes of Encana Holdings Finance Corp. (Finance) at A (low) with Stable trends. Finance’s rating is guaranteed by Encana. The Commercial Paper rating of Encana has also been confirmed at R-1 (low) with a Stable trend.

The ratings had previously been confirmed on November 30, 2009, following the closing of the spin-off (the Transaction) of the Company’s Integrated Oil and Canadian Plains divisions into a new entity, Cenovus Energy Inc. (Cenovus).

The Transaction concluded as expected. The Company’s strengthened capital structure through further debt reduction, pre-Transaction, has helped to partly offset the modestly increased business risk associated with a more natural gas weighted operation. Encana’s liquidity arrangements are also commensurate with its capital growth requirements. In addition, the rating actions are based on DBRS’s expectation and management’s commitment that current target metrics (similar to those pre-Transaction) and other key financial principles, such as hedging policies, will remain in place and future capital investment programs, share repurchases and other related activities will be managed within these credit targets.

Current credit metric targets include a debt-to-capital ratio of less than 40% (30% to 40%) and a debt-to-EBITDA ratio of less than 2.0 times (1.0 time to 2.0 times). DBRS also expects a similar range for debt-to-cash flow of 1.0 time to 2.0 times. In view of the increased concentration risk as a pure play natural gas company (96% of production in the first quarter ended March 31, 2010 (Q1 2010) versus 82% pre-Transaction), DBRS expects the Company to manage within the lower half of its guidance metric ranges in a weak economic environment in order to maintain financial flexibility for the current ratings as seen in Q1 2010. On the liquidity front, Encana had substantial unused committed credit facilities (about $5 billion) plus about $2 billion of cash on hand at March 31, 2010. Debt maturities are minimal at $200 million in 2010 and $500 million each in 2011 to 2013. While Encana resumed its share buyback program (up to 5% of common shares outstanding) in Q1 2010, DBRS expects modest activities, using mostly proceeds from modest divestitures in order to keep production per share stable. The Company has maintained $0.20/share per quarter ($600 million per annum), or a 50% share of former Encana’s dividend.

Given its gas-weighted operations, the Company’s debt-to-cash flow ratio could exceed 2.0 times on a temporary basis (1.7 times in Q1 2010), should the natural gas prices revert to the low levels seen in Q1 2009 (slightly below $4/mcf). However, any temporary aberration due to unusually weak gas prices should not have rating implications, provided that remedial measures are taken to address the issue. Cost reduction and capital efficiency efforts helped by hedges in place contributed to the solid operating results in Q1 2010. The Company’s consistent hedging programs since inception in 2002 have paid off, over time, providing a measure of cash flow stability for its substantial capex programs. At March 31, 2010, about 60% of the expected production for the remainder of 2010 is hedged at about $6.00/mcf, and about 25% of 2011 and 2012 estimated volumes based on current levels at about $6.50/mcf, compared with expected new gas supply cost of less than $4.00/mcf. Credit metrics should also improve as production ramps up under Encana’s recently announced accelerated program outlined below, and as natural gas prices rise to more sustainable levels.

Post-Transaction, Encana remains focused on being one of the lowest cost producers with operational expertise and capital discipline. It also benefits from lower fee title mineral rights than the Alberta royalty scheme on much of its Canadian acreage. Most of the Company’s projects are scalable, lower risk and in some of the most prolific gas regions, providing financial flexibility. Based on the Company’s March 2010 guidance, capex of $4.5 billion should mostly be covered by cash flow of about $4.4 billion to $4.8 billion premised on Nymex of $5.75/mcf and WTI of $75/b. Proceeds from asset sales (up to $1.0 billion) and joint venture arrangements (targeted at $1 billion to $2 billion p.a. – over $4 billion achieved in the past three years) should provide additional funding in support of the Company’s accelerated production growth plans, assuming Nymex of $6 to $7 per mcf, over time. However, the Company’s target to double production per share over the next five years is fairly aggressive, representing average growth of 15% p.a. (9% to 12% previously projected) supported by capex at the $6 billion level in future and a 2,500 wells program per year. In any event, forecast volumes of about 3.3 bcfe/d (550,000 boe/d – mid-point of guidance), or about two-thirds of the former entity’s production volumes (about 585,000 boe/d) and proved reserves of 12.8 tcfe (or 2.1 billion boe) adjusted for natural gas price-related negative revisions in 2009) should rank the Company among the largest independents in North America, providing economies of scale for its growth plans.

The Company’s U.S. assets, principally Haynesville, will be the key driver for growth (expected to more than quadruple to 325 mmcf/d in 2010 from 2009 (194 mmcf/d in Q1 2010)) with a flat production profile for the Canadian Division, partly due to non-core asset sales in August 2009 and price sensitive royalty rates in Alberta. Most of the capital spending in Canada will be directed to longer-term growth in the Horn River Basin, Montney and completion of Deep Panuke, with the latter scheduled for start-up in 2011 (see Major Resource Plays section for more details).

DBRS expects the Company to balance its aggressive growth target with prevailing market forces, which could see natural gas prices remaining relatively low in the near term. DBRS also expects the Company to maintain its key strength in growing production and reserves, primarily through the drill bit (pro forma average three-year production replaced of 132%, or adjusted 170% in 2009). Further, the hike in reserve replacement costs ($22.00/boe pro forma three-year average, or $17.45 adjusted versus $14.15/boe in 2008, pre-Transaction) should be addressed, despite the impact of the strategic land purchases and retention program. On a positive note, the Company’s vast inventory of unconventional natural gas resources are more predictable with relatively low exploration risk, potentially providing near 12-year drilling inventory. Any major acquisitions, apart from land purchases, are not expected in the near to medium term, reducing event risk seen prior to 2008.

Note:
All figures are in U.S. dollars unless otherwise noted.

The applicable methodology is Rating Oil and Gas Companies, which can be found on our website under Methodologies.

This is a Corporate (Energy) rating.