SM Energy Co quarterly report, Q2 FY2013

Full document

SM Energy Company — Q2 2013 Form 10-Q

Reporting period: Three and six months ended June 30, 2013. SM Energy is an onshore North American oil and gas exploration and production company focused on oil- and liquids-rich plays, including the Eagle Ford, Bakken/Three Forks, and Permian.

Financial and operating performance

  • Q2 revenue and earnings: Total operating revenues were $559.4 million, up 84% from $304.4 million in Q2 2012. Net income was $76.5 million versus $24.9 million; diluted EPS was $1.13 versus $0.37.
  • First half: Operating revenues were $1.044 billion versus $681.8 million; net income was $93.2 million versus $51.2 million; diluted EPS was $1.38 versus $0.76.
  • Production: Q2 production averaged 131.8 MBOE/day, up 42% year over year. Oil, gas, and NGL volumes rose 37%, 39%, and 62%, respectively. Production revenue increased 71% to $534.5 million.
  • Prices and costs: Q2 realized price was $44.57/BOE, up 20%. Production expense was $149.7 million, up 64%; transportation cost rose to $5.59/BOE from $3.59, while lease operating expense declined to $4.69/BOE from $5.48.
  • Cash flow and investment: First-half operating cash flow was $596.4 million, compared with $410.3 million. Investing cash outflow was $777.8 million, including $734.0 million of capital expenditures; operating cash flow less investing outflow was negative $181.4 million. Financing provided $175.7 million.
  • Debt and liquidity: June 30 debt totaled approximately $1.628 billion: $28 million drawn on the revolving facility and $1.6 billion of senior notes. Cash was $0.2 million. Available credit capacity was $1.271 billion at June 30 and $1.214 billion on July 25. Credit-facility leverage and adjusted-current ratios were 1.3 and 2.8, respectively; the company reported covenant compliance.
  • Other balance-sheet measures: Total assets were $4.591 billion and stockholders’ equity was $1.527 billion. Net derivative assets were approximately $80.6 million at June 30.

Changes versus comparable periods

  • Revenue and earnings rose substantially, driven by higher production and improved realized oil and gas prices; realized NGL prices declined.
  • Production growth was led by the Eagle Ford. Q2 average production reached a company record, compared with 92.6 MBOE/day a year earlier.
  • Production costs grew faster than volumes, particularly transportation expense, which management attributed in part to Eagle Ford growth, compression and fuel costs, and changed transportation arrangements.
  • Q2 included an $85.2 million derivative gain, primarily from unrealized fair-value changes. First-half derivative gains were $54.6 million, down from $95.9 million in 2012.
  • First-half proved-property impairments were $55.8 million, versus $38.5 million in 2012, including $34.6 million in Q2 for underperforming assets and $21.2 million in Q1 for Olmos dry-gas assets.

Outlook, risks, and unusual items

  • Management raised its 2013 capital-program estimate to approximately $1.65 billion from $1.5 billion, including Powder River Basin acreage and further testing in East Texas and the Powder River Basin. It expected remaining 2013 capital spending to be funded by operating cash flow, divestiture proceeds, and, if needed, credit-facility borrowings.
  • Plans included approximately $655 million for Eagle Ford, $295 million for Bakken/Three Forks drilling and completion, and $200 million for the Permian. Management expected production to continue growing, but noted commodity-price volatility and execution, service, and transportation risks.
  • The company issued $500 million of 5.0% senior notes due 2024, receiving $490.8 million net, and used proceeds to reduce revolving borrowings. The amended facility has $1.3 billion of lender commitments and matures in 2018; its borrowing base was reduced to $1.775 billion after the notes issuance.
  • Derivatives cover production through Q1 2016. They reduce some commodity-price exposure but can limit upside; reported earnings include significant non-cash derivative fair-value changes. Dodd-Frank rules may increase costs or collateral requirements.
  • A $14.2 million estimated liability was recorded for discussions concerning royalty-payment provisions on certain South Texas and Gulf Coast leases. The Oklahoma royalty class action remains stayed; management said the potential impact could not be estimated. The IRS proposed disallowing $4.6 million of R&D credits for 2007–2010; the company appealed.
  • Management began marketing certain Mid-Continent assets after quarter-end and engaged an advisor to market Anadarko Basin interests, including Granite Wash assets. The Mid-Continent assets were not classified as held for sale at June 30.
  • Management cautioned that results are sensitive to oil, gas, and NGL prices, reserve replacement, capital access, drilling outcomes, borrowing-base redeterminations, litigation, regulation, and infrastructure availability. It reported disclosure controls were effective at a reasonable-assurance level and no material changes in internal control over financial reporting.

Important facts for investors to verify

  1. How much of earnings and operating performance reflects production growth and realized prices versus non-cash derivative gains, impairments, divestitures, and the $14.2 million royalty-related accrual.
  2. Whether the higher $1.65 billion capital plan can be funded as planned, given first-half investing outflows exceeded operating cash flow and cash on hand was minimal.
  3. Production growth, Eagle Ford transportation costs, and realized-price differentials relative to management’s assumptions.
  4. Progress and value of the Mid-Continent and Anadarko Basin asset marketing, and the outcome of the Oklahoma royalty litigation and IRS tax-credit appeal.
  5. Debt, borrowing-base capacity, covenant compliance, and the extent to which hedges protect cash flows while constraining commodity-price upside.