SM Energy Company — 2011 Form 10-K
Reporting period: Fiscal year ended December 31, 2011. The filing also reports fourth-quarter results. SM Energy is an independent U.S. onshore oil and gas producer focused increasingly on oil- and liquids-rich resource plays, particularly the Eagle Ford and Bakken/Three Forks.
Financial and operating highlights
| Metric | 2011 | 2010 |
|---|---|---|
| Total operating revenues and other income | $1.603 billion | $1.093 billion |
| Oil, gas and NGL production revenue | $1.332 billion | $836.3 million |
| Net income | $215.4 million | $196.8 million |
| Diluted earnings per share | $3.19 | $3.04 |
| Net cash provided by operating activities | $760.5 million | $497.1 million |
| Net cash used in investing activities | $1.265 billion | $361.6 million |
| Capital expenditures (cash basis) | $1.633 billion | $668.3 million |
| Year-end cash and cash equivalents | $119.2 million | $5.1 million |
| Year-end long-term debt, net of discount | $985.1 million | $323.7 million |
| Year-end working capital | Deficit of $42.6 million | Deficit of $227.4 million |
Operating income was $384.4 million. Results included a $220.7 million net gain on divestitures and $219.0 million of proved-property impairments, so reported earnings and operating results reflect substantial unusual items. Fourth-quarter net loss was $120.7 million; the quarter included a $170.5 million proved-property impairment, a $25.0 million loss on divestiture activity, and $46.8 million of unrealized and realized derivative losses.
- Production: 169.7 BCFE for the year, or 465.0 MMCFE per day on average, up 54% from 2010. Eagle Ford production was 66.6 BCFE.
- Prices: Reported realized prices before derivative settlements were $88.23/Bbl for oil, $4.32/Mcf for gas, and $53.32/Bbl for NGLs. Realized gas price fell 17% from 2010; reported NGL volumes and prices began being shown separately in 2011, limiting direct comparison.
- Costs: Production costs totaled $290.1 million, up 49%, while total production cost per MCFE was $1.71, down from $1.77. Transportation cost per MCFE rose to $0.51 from $0.19, largely due to Eagle Ford growth and infrastructure constraints. DD&A was $511.1 million.
- Reserves: Proved reserves rose 28% to 1,259.2 BCFE; 67% were proved developed. Reserve PV-10 was $3.461 billion, a non-GAAP measure excluding income taxes; the standardized measure was $2.580 billion.
- Liquidity and debt: No credit-facility borrowings were outstanding at year-end; available borrowing capacity was $999.4 million against a $1.3 billion borrowing base and $1.0 billion lender commitments. Debt included $350 million of 6.625% notes due 2019, $350 million of 6.50% notes due 2021, and convertible notes with a $285.1 million carrying value. The company reported compliance with credit covenants.
Material changes versus 2010
- Production revenue increased 59%, primarily reflecting 54% production growth, led by the Eagle Ford; oil prices rose while gas prices declined.
- Operating cash flow increased 53%, but cash capital expenditures more than doubled. Divestiture proceeds were $364.5 million.
- Proved-property impairments increased sharply, from $6.1 million to $219.0 million, as lower natural gas prices impaired dry-gas assets in the ArkLaTex region.
- Debt increased following issuance of $700 million in senior notes. The company ended the year with substantially higher cash and no credit-facility borrowings.
- SM Energy transferred a 12.5% working interest in certain non-operated Eagle Ford assets to Mitsui; Mitsui agreed to carry 90% of certain remaining drilling and completion costs until it had spent $680 million on SM Energy’s behalf.
Outlook, risks and contingencies
- 2012 plan: Capital spending was forecast at approximately $1.4–$1.5 billion, including $1.2–$1.3 billion for drilling and completion. Management expected roughly 70% of drilling and completion capital to go to operated Eagle Ford and Bakken/Three Forks programs. Planned operated Eagle Ford spending was $650–$700 million; Bakken/Three Forks, $160–$185 million.
- Gas-focused activity: Management reduced planned Haynesville spending to $35–$40 million amid weak gas prices and expected to curtail further drilling after planned activity. Woodford activity was also limited by gas-price economics.
- Funding outlook: Management said operating cash flow, divestiture proceeds and available credit capacity were expected to fund the 2012 program. The $680 million Mitsui carry was expected to be used over three to four years; none had been utilized by year-end 2011.
- Convertible notes: Holders could put some or all of the 3.50% convertible notes to the company on April 1, 2012. The company could settle in cash, shares or a combination and stated it might redeem the notes, making the timing and form of settlement a liquidity and dilution consideration.
- Commodity, execution and infrastructure risks: Results and borrowing capacity are sensitive to volatile oil, gas and NGL prices, reserve estimates, drilling outcomes, service costs, and access to gathering and transport capacity. Firm delivery commitments total 1,766 Bcf of gas and 9 million barrels of oil through 2023, with potential deficiency payments if volumes fall short.
- Regulatory and environmental risks: The filing identifies possible added costs, delays or restrictions from hydraulic-fracturing, water-disposal, air-emissions and climate-related rules. Management said it was evaluating proposed EPA rules.
- Legal and transaction matters: A Texas court awarded plaintiffs approximately $5.1 million in a dispute over an asserted overriding royalty interest affecting about 22,000 Eagle Ford acres; SM Energy appealed and obtained a stay. The company also disputed a buyer’s termination of an $80 million proposed Marcellus divestiture and recorded a $27.5 million write-down associated with those assets.
Investor facts to verify
- How much of earnings and reserve value is supported by ongoing production economics rather than divestiture gains, impairment assumptions or non-GAAP PV-10 estimates.
- Whether the Eagle Ford and Bakken programs deliver planned production, well costs, spacing and returns, and how the Mitsui carry is applied.
- Actual funding for the $1.4–$1.5 billion 2012 capital plan, including divestiture proceeds, borrowing-base capacity and any financing needs.
- The outcome and settlement method for the April 2012 convertible-note put/redemption options, including potential cash use or share dilution.
- Progress toward meeting long-term delivery commitments and securing takeaway capacity, plus developments in the Sutton and Marcellus disputes.
- Comparability of production, revenue and realized-price trends given the 2011 change to separate natural gas and NGL reporting.