DBRS Confirms Cenovus Ratings at A (low) and R-1 (low)

On March 5, 2010, DBRS assigned an R-1 (low) rating with a Stable trend to the Commercial Paper of Cenovus Energy Inc. (Cenovus or the Company) and confirmed its Senior Unsecured Debt rating at A (low), also with a Stable trend. The long-term rating was finalized on November 30, 2009, when the spin-off of the Integrated Oil and Canadian Plains divisions of EnCana Corporation (EnCana) was concluded (the Transaction). On September 10, 2009, the long-term rating was assigned on a provisional basis to the Company’s US$3.5 billion senior notes issuance under a Rule 144A private placement, which provided funding in support of the subsequent Transaction. These private notes are expected to be exchanged on June 28, 2010 for public notes of similar terms and conditions.

The Transaction concluded as expected and the Company is appropriately capitalized for its business model and growth strategy. The assigned rating reflects Cenovus’ stated objective to initially pursue a similar financial strategy and use the same credit metric targets as EnCana had employed pre-Transaction.

The metric targets include a debt-to-capital ratio of 30% to 40% and a debt-to-EBITDA ratio of 1.0 time to 2.0 times (DBRS expects debt-to cash flow of 1.0 time to 2.0 times). DBRS expects Cenovus to manage within the lower half of these ranges as seen in the three months ended March 31, 2010 (Q1 2010 - 26% and 1.01 times (1.24 times)) in order to maintain financial flexibility for the current ratings in a weak economic environment. Post-Transaction, Cenovus has virtually maintained a 50% share of EnCana’s dividend of $0.20 per share per quarter. It also maintains sufficient liquidity through a $2.0 billion three-year revolving credit facility and a $500 million 364-day revolving credit facility (fully available at March 31, 2010), with no debt maturities until 2014.

DBRS expects Cenovus’s rating to be supported by its operational expertise, capital discipline and one of the lowest cost structures relative to its peers. There is minimal exploration risk compared with most conventional crude oil and natural gas developments. In addition, strong cash flow generating resources, emanating from mature conventional oil and gas assets in western Canada (primarily in Alberta and Saskatchewan) should augment the development of high-growth oil sands assets. The Company also benefits from its consistent and active hedging programs. Hedges in place, covering about 60% of its expected 2010 gas production at about US$6.07/mcf (average) and about 26% of oil volumes at US$76.99/b (35% hedged on gas in 2011), should provide a measure of stability to earnings and cash flow in the near term. DBRS estimates that the Company’s credit metrics should remain within the parameters of the current ratings in 2010, should WTI fall slightly below US$70 with Nymex at US$4/mcf based on flat production.

Realized after-tax hedging gains of US$692 million contributed substantially to the 2009 proforma net income (before extraordinary items) of US$1.3 billion, partly offset by US$400 million of one-time cash tax accelerated by the spin-off.

There are limiting factors. Only incremental volume growth is expected for the next few years due to the declining natural gas production. Over time, the Company is expected to be more heavily oil-weighted, (potentially over 70% versus 48% in Q1 2010). DBRS also notes Cenovus’s reduced economies of scale (relative to when it was included in EnCana) in a weak natural gas pricing environment (52% gas-weighted) and its intention to pursue a substantial capital expenditure program. Capex for 2010 (projected average of $2.3 billion) is close to 90% of the projected cash flow, although in line with pre-Transaction levels, primarily to expand its integrated oil sands and coking capacity downstream for growth beyond 2010. Downstream will likely have a cash flow deficit for the next year until the refinery expansion (CORE program) is complete, expected by 2011.

However, the Company remains of critical mass in terms of size and scope with, on an after-royalties basis, about 240,000 boe of production (net) at March 31, 2010, proved reserves of about 1.2 billion (estimated 5.4 billion barrels of bitumen contingent resources in place) and an above average reserve life of 13.3 years at year-end 2009. Production was more than 100% replaced through the drill bit in 2008 and 2009. The Company also benefits from its integrated operation through the 50/50 joint venture (JV) with ConocoPhillips (COP) on its major Steam Assisted Gravity Drainage (SAGD) oil sands properties and COP’s downstream upgrading and refining assets. This should result in relatively low capital costs, estimated by DBRS at between $50,000 and $55,000 per b/d of crude oil capacity versus the more than $100,000 per b/d estimated for projects by some other oil sands participants. The producing Foster Creek (FC) and Christina Lake (CL) fields have among the lowest steam-oil ratios (below 2.5 times) and the lowest operating costs in the industry. On completion of the Wood River refinery expansion project expected in 2011, the coking design capacity (more than double to 240,000 b/d) should be able to handle most of the JV’s bitumen volumes, barring future bitumen growth mentioned below. This should reduce capex substantially and improve refining margins.

FC and CL are key drivers for future growth. When fully developed, production on a combined basis could potentially more than triple from Q1 2010 levels to about 430,000 b/d (50% net to Cenovus) by 2017, with volumes potentially equally split between the two fields. Production is projected to increase to about 490,000 b/d (up 15%) by 2019. CL is expected to have higher accelerated growth, with per phase development at 40,000 b/d and FC at 30,000 b/d (50%), which are more scalable and manageable than large scale mining projects. The ramp-up at FC’s Phases D and E helped to propel volumes in Q1 2010, with regulatory approvals for the next three phases expected in 2010. Phase C of CL is on budget and on schedule for first production, expected in Q3 2011, with the next phase start-up potentially in 2013 (sanctioning expected in 2010). Other potential oil sands projects include Narrows Lake, Borealis and Grand Rapids, as well as light crude developments at Bakken and Shaunavon.

Based on the Company’s April 2010 guidance, operating cash flow would be in the range of $2.4 billion to $2.8 billion, compared with capex of $2.1 billion to $2.5 billion, based on WTI of $65/b to $85/b, crack spread of $7.50/b to $9.50/b and NYMEX of $5.50/mcf to $6.15/mcf. On average, about 60% ($1.4 billion) on the high side of 2010 capex is directed at growth beyond 2010, primarily FC and CL and completion of the CORE project at Wood River, with the remainder for the Canadian Plains conventional natural gas and oil production. The latter is expected to generate strong operating cash flow after capex of over $1.2 billion in 2010.

Notes:
All figures are in Canadian 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 rating.