01—Abstract
Summary
Summary of the 10-K filed February 25, 2010. Cited figures are marked; the original filing is the authoritative source.
Devon Energy's 2009 10-K marks a strategic pivot: the company is repositioning as a high-growth North American onshore E&P by divesting its U.S. Offshore (Gulf of Mexico) and International assets (Azerbaijan, Brazil, China), with expected after-tax proceeds of $4.5 to $7.5 billiona in 2010, earmarked largely for debt reduction and redeployment into onshore plays such as the Barnett, Cana-Woodford, Haynesville and Jackfish.
2009 was a difficult year financially: a net loss of $2.5 billionb ($5.58 per diluted share) driven by a $6.4 billion pre-tax full-cost ceiling impairment in the first quarter, while operating cash flow fell about 50% to $4.7 billion as realized prices per Boe dropped 50% to $26.15. Production nonetheless rose 4% to 233 MMBoe, and proved reserves reached 2,733 MMBoe, with a 99% drilling success rate and reserve replacement of roughly 213%. The balance sheet remains serviceable but leaner in liquidity.
Total debt was about $7.3 billionc at year-end, the debt-to-capitalization ratio under the credit agreement was 20.5% against a 65% covenant, and total available credit capacity was about $1.8 billion at year-end (about $2.0 billion as of February 15, 2010). Commercial paper of $1.4 billion was used to bridge capital spending beyond operating cash flow, which covered roughly 87% of cash capex. Management guided 2010 capital expenditures of $6.0 to $6.8 billion, including discontinued operations, and expects hedges and asset-sale proceeds to fund the program.
Investors should weigh the impairment-driven losses and reliance on commodity prices against a clearer, more focused onshore growth story, contingent on the timing and value of the divestitures. On governance and risk, Devon reported no material pending legal proceedings, its internal controls were rated effective by KPMG, and it maintained a stable dividend of $0.16d per quarter ($0.64 annually). The 10-K also flags risks including uncertain sale timing, Alberta's new royalty regime, reserve estimate revisions, and the exposure of Canadian operations to currency movements.
02—Key points
Key Highlights
- Net loss of $2.5 billion ($5.58 per diluted share) in 2009, driven by a $6.4 billion pre-tax (about $4.1 billion after tax) full-cost ceiling impairment recognized in Q1 2009, versus a 2008 net loss of $2.1 billion.
- Strategic repositioning announced November 2009: divest U.S. Offshore and International assets to become a high-growth North American onshore E&P, with expected 2010 after-tax proceeds of $4.5 to $7.5 billion, largely for debt reduction and onshore reinvestment.
- Production grew 4% to 233 MMBoe, and proved reserves reached 2,733 MMBoe (up from 2,299 MMBoe at year-end 2008), with reserve replacement of about 213% and a 99% success rate on 1,135 wells drilled.
- Operating cash flow fell about 50% to $4.7 billion as the combined realized price dropped 50% to $26.15 per Boe; per-unit lease operating expenses declined 14% to $7.16 per Boe.
- Balance sheet: total debt of about $7.3 billion, debt-to-capitalization of 20.5% versus a 65% covenant, and roughly $1.8 billion of available credit capacity at year-end; ratings BBB+ (Fitch and S&P) and Baa1 (Moody's), all stable.
- 2010 guidance: capital expenditures of $6.0 to $6.8 billion (including discontinued operations), production of 231 to 235 MMBoe, and a $0.16 quarterly dividend expected to total about $286 million.
- Jackfish oil sands project in Alberta reached 33.7 MBbls/d gross in late 2009 and is expected to hit 35 MBbls/d capacity in early 2010, with Jackfish 2 scheduled for 2011.
03—One dollar
04—Financials
Financial Highlights
Figures from 10-KFY2009filed February 25, 2010Financial Statements
FY2009 against FY2008
| Line item | FY2009FY2008 | Change |
|---|---|---|
| Revenue | $8.02B$13.86B | −42.2% |
| Operating Expenses | $12.54B$18.02B | −30.4% |
| Operating Income | -$2.75B-$3.04B | +9.4% |
| Interest Expense | $437.00M$426.00M | +2.6% |
| Net Income | -$2.48B-$2.15B | −15.4% |
| EPS (Basic) | $-5.58$-4.85 | −15.1% |
| EPS (Diluted) | $-5.58$-4.85 | −15.1% |
05—Questions
Frequently Asked Questions
Why did Devon post a large net loss in 2009 despite growing production?
The loss was driven mainly by noncash full-cost ceiling impairments, totaling $6.4 billion pre-tax in 2009 (recognized in Q1, mostly U.S. natural gas) and $9.9 billion in 2008. These writedowns reflected sharply lower gas and oil prices at period-end, not operating failure. Production rose 4% and reserves grew, but the ceiling test uses prices that dropped significantly, so the impairment reduced reported earnings substantially.
What is the purpose of the offshore and international divestitures, and how much cash is expected?
Devon plans to sell its Gulf of Mexico (U.S. Offshore) and international assets in Azerbaijan, Brazil and China to focus on North American onshore projects, which management says deliver its highest risk-adjusted returns. Expected after-tax proceeds are $4.5 to $7.5 billion in 2010. Management plans to use the proceeds mainly to reduce debt and fund accelerated onshore growth. Timing and value remain uncertain, and only one property had been sold as of the filing date.
Is Devon's balance sheet and liquidity sufficient to fund its plans?
At year-end 2009, Devon had about $7.3 billion of debt, a 20.5% debt-to-capitalization ratio (well inside the 65% covenant), $1.0 billion of cash and about $1.8 billion of available credit capacity. Operating cash flow funded about 87% of 2009 cash capex, with commercial paper bridging the gap. Management expects operating cash flow, existing cash, asset sale proceeds and credit facilities to fund 2010 capital spending, while noting that commodity price volatility is a key risk.
How exposed is Devon to commodity price movements in 2010?
Devon hedges a significant portion of its 2010 production. About 1.3 Bcf per day of gas (roughly 50% of estimated output) is covered by swaps or fixed-price contracts at an average of $6.16/MMBtu, and about 65% of expected oil production is covered by collars with a floor averaging $67.47 and a ceiling averaging $96.48 per barrel. Unhedged volumes remain exposed to market prices, and a 10% increase in forward curves would have raised unrealized hedge losses by about $264 million for gas and $108 million for oil at year-end 2009.
06—Continue