SM Energy Company — Q3 2010 Form 10-Q
Reporting period: Three and nine months ended September 30, 2010. SM Energy is an independent U.S. oil and gas exploration, development, and production company. Financial statements are unaudited.
Financial performance and position
| Metric | Q3 2010 | Q3 2009 | Nine months 2010 | Nine months 2009 |
|---|---|---|---|---|
| Oil and gas production revenue | $197.4m | $152.7m | $586.1m | $428.3m |
| Total operating revenues and other income | $226.9m | $185.8m | $798.7m | $590.2m |
| Net income (loss) | $15.5m | $(4.4)m | $159.7m | $(100.4)m |
| Diluted EPS | $0.24 | $(0.07) | $2.47 | $(1.61) |
- Nine-month operating cash flow was $418.4m, versus $353.1m a year earlier. Investing activities used $236.4m, including $488.7m of cash capital expenditures and $259.5m of property-sale proceeds. Financing activities used $185.6m, primarily reflecting net credit-facility repayments. Cash ended at $7.1m.
- At September 30, total debt was $275.4m: $2.0m under the credit facility and $273.4m of convertible notes, net of discount. Debt was down from $454.9m at December 31, 2009. Stockholders’ equity increased to $1.20bn from $973.6m.
- Current assets were $198.5m and current liabilities $371.1m, a $172.5m working-capital deficit. Management reported a 2.58 current ratio under the credit agreement’s definition and a 0.61 debt-to-EBITDA ratio; it was in covenant compliance.
- The credit facility’s borrowing base was raised to $1.1bn, while bank-group commitments remained $678m. Outstanding borrowings were $2m at quarter-end and $38m on October 27; available capacity was $639.5m on that date. The facility matures in 2012.
- Production was 27.5 BCFE in Q3, up 4% year over year; average daily production was 298.4 MMCFE. Nine-month production was 78.3 BCFE, down 6%, primarily due to divestitures and reduced prior-year capital spending. Production from retained properties was up 5% on an average-daily basis.
- Q3 operating profit was $31.1m, compared with $0.5m; nine-month operating profit was $275.6m, compared with an operating loss of $140.9m. The nine-month comparison includes a $132.2m divestiture gain in 2010 and a $153.2m proved-property impairment in 2009.
- Net realized price per MCFE, including hedging, was $7.51 in Q3 and $7.75 for nine months, up 9% and 16%, respectively. Operating profit per MCFE was $4.92 in Q3 and $5.03 for nine months. DD&A and asset-retirement accretion were $3.05 and $3.08 per MCFE, respectively.
Material changes and notable items
- Q3 results improved from a loss to profit as production grew and realized commodity prices strengthened. Q3 oil and gas production revenue rose 29% year over year; lower realized hedge gains partly offset the increase. Nine-month net income also benefited materially from $132.2m of divestiture gains.
- Legacy and Sequel property sales generated approximately $125.3m and $129.1m of gross cash proceeds, respectively. Estimated gains were $65.0m and $52.9m; the Sequel sale price and the Southern Rockies sale price remained subject to post-closing adjustments. The company also completed a Southern Rockies sale in July.
- In August, the company began marketing additional non-core properties across the Rocky Mountain, Mid-Continent, and Permian regions, including all Marcellus assets. The balance sheet classified $114.9m of net assets as held for sale, plus a separate $3.1m asset-retirement liability.
- The Net Profits Plan liability was $140.5m, down from $170.3m at year-end. A $29.8m nine-month non-cash benefit reflected liability remeasurement; divestiture-related participant payments also reduced the liability. The estimate is sensitive to commodity-price and discount-rate assumptions.
- Derivative positions had a net fair-value asset of $6.5m, compared with a net liability of $80.9m at year-end. Nine-month realized hedge gains fell to $20.8m from $127.2m in 2009. Q3 realized oil hedge settlements reduced revenue by $6.8m, while gas and NGL settlements increased it by $15.6m.
Outlook, risks, and contingencies
- Management expected 2010 capital investment of about $871m, up from the original $725m budget, and anticipated roughly $1.0bn of investment in 2011. The 2011 program was expected to focus mainly on rich-gas Eagle Ford projects and Williston Basin oil projects. Management expected 2010 operating cash flow and divestiture proceeds to fund most of the program, with credit-facility borrowings covering the balance; additional capital-market funding could be considered for 2011 and beyond.
- Management described Eagle Ford production results as encouraging and planned to increase development activity. Infrastructure, drilling-rig, and completion-service availability are important execution factors. The company entered a ten-year Eagle Ford gas-services agreement beginning in 2011; volume shortfalls could require deficiency payments. The filing lists $272.2m of undiscounted future gathering-throughput and drilling-rig commitments, and an additional $79.8m of fracturing-service and rig commitments entered into after quarter-end.
- Management anticipated volatile oil, gas, and NGL prices, citing possible downward pressure on gas from supply and subdued demand, and potential near-term growth in NGL supply. It also cautioned that increasing industry activity could raise operating costs. A continued decline in gas prices could trigger proved-property impairments.
- Commodity hedging reduces some price exposure but can constrain upside and carries counterparty risk. Proposed Dodd-Frank rules could increase hedging costs or collateral requirements; the eventual effect was uncertain.
- Potential regulation of hydraulic fracturing, greenhouse-gas emissions, and oil-spill liability could increase costs, restrict operations, or delay development. Tax-law proposals to reduce deductions for drilling costs, domestic production, or depletion could also reduce cash available for investment.
- The company reported an IRS audit of its 2009 tax year was expected to begin in Q4 2010. It was awaiting approval of a $5.5m 2006 refund; it received $22.9m in July 2010 related to a 2009 loss carryback. Management reported no material change to previously disclosed risk factors and stated disclosure controls were effective.
Important facts for investors to verify
- Whether marketed asset sales close on expected terms, including final post-closing adjustments and proceeds available to fund capital spending.
- Whether Eagle Ford infrastructure and contracted drilling/completion capacity support planned growth, and whether committed gas volumes avoid deficiency payments.
- Whether the planned capital program can be funded while maintaining liquidity, covenant compliance, and capacity under the credit facility as it approaches its 2012 maturity.
- How commodity prices, production, operating costs, and hedge settlements affect cash flow, earnings, and potential property impairments.
- How the Net Profits Plan liability and future payments change with commodity-price and discount-rate assumptions, and the outcome of the expected 2009 tax audit and pending refund approval.