SM Energy Company — Q3 2014 Form 10-Q
Reporting period: Three and nine months ended September 30, 2014. SM Energy is an independent onshore North American oil, gas, and NGL exploration and production company, focused on oil and liquids-rich plays.
Financial and operating results
| Metric | Q3 2014 | Q3 2013 | Change |
|---|---|---|---|
| Production revenue | $617.2 million | $601.8 million | +3% |
| Income from operations | $357.0 million | $137.5 million | +160% |
| Net income | $208.9 million | $70.7 million | +196% |
| Diluted EPS | $3.05 | $1.04 | +193% |
| Adjusted EBITDAX (non-GAAP) | $406.2 million | $410.4 million | −1% |
| Average daily production | 142.5 MBOE/d | 138.8 MBOE/d | +3% |
Q3 operating margin was approximately 57.7% of total revenue, versus 22.4% a year earlier; net margin was approximately 33.8%, versus 11.5%. These comparisons are substantially affected by derivative fair-value movements: Q3 2014 included a $190.7 million derivative gain, primarily a non-cash increase in contract fair value as commodity prices fell. Without treating that mark-to-market gain as operating cash generation, reported net income is not a direct indicator of underlying cash performance.
For the first nine months, production revenue was $1.895 billion, up 18%; net income was $334.3 million, up 104%; diluted EPS was $4.90, up 103%; and adjusted EBITDAX was $1.229 billion, up 14%. Operating cash flow was $1.075 billion, versus $1.001 billion in 2013.
Cash, debt, and capital spending
- At September 30, cash was $0.3 million; current assets were $371.6 million and current liabilities $669.6 million. The filing reports a $390 million revolving-credit balance and $1.6 billion of senior notes, or $1.99 billion total debt.
- At September 30, credit-facility availability was $909.2 million; the October 6 borrowing-base redetermination increased the borrowing base from $2.2 billion to $2.4 billion, with lender commitments unchanged at $1.3 billion. Availability was $740.7 million as of October 22 after additional borrowing.
- Nine-month investing cash use was $1.736 billion, including $1.318 billion of capital expenditures and $459.3 million of property acquisitions. Financing cash provided was $378.9 million. Cash fell by $282.0 million from year-end.
- Debt consists of $1.6 billion of fixed-rate senior notes and $390 million of floating-rate revolver borrowings at quarter-end. The company reported compliance with debt covenants.
Material changes and notable items
- Production grew 3% year over year in Q3 and 11% for the nine-month period, led by Eagle Ford development. Q3 oil and NGL volumes rose, while gas volumes declined.
- Q3 realized oil price before derivative settlements fell 10% to $86.56/Bbl; gas rose 18% to $4.49/Mcf and NGLs rose 2% to $34.86/Bbl. Production costs rose 12% in Q3, including higher transportation expense.
- Q3 derivative results swung from a $39.9 million loss in 2013 to a $190.7 million gain in 2014. For nine months, derivatives instead produced a $33.5 million loss, versus a $14.7 million gain in 2013.
- Exploration expense rose to $34.6 million in Q3, including $16.3 million of exploratory dry-hole expense. Unproved-property abandonment and impairment was $15.5 million. No proved-property impairment was recorded in Q3 2014, compared with $5.9 million in Q3 2013.
- The company paid $325.2 million for approximately 61,000 net acres in its Gooseneck prospect in North Dakota and made other Rocky Mountain acquisitions. A further Gooseneck acquisition for approximately $84.8 million closed after quarter-end. The company also received $50.2 million from a second-quarter divestiture.
Outlook, risks, and contingencies
- Management expected remaining 2014 capital needs to be funded by operating cash flow, divestiture proceeds, and revolver borrowings, with capital-market access or further asset sales as possible alternatives. It provided no specific full-year production or earnings guidance in the text.
- Plans included increased Bakken/Three Forks and Powder River Basin activity in Q4, adding a fourth operated Powder River Basin rig, and completing an East Texas gathering system. Management said it expected production to increase and anticipated production growth to outpace absolute LOE and G&A growth.
- Management cited recent declines in oil strip prices and risks from volatile commodity prices, weaker global growth, ample supply, and growing U.S. NGL supply. October 22 12-month strip prices were below September 30 levels: WTI $79.31/Bbl versus $88.68; Henry Hub gas $3.68/MMBtu versus $4.01; NGLs $32.44/Bbl versus $37.75.
- Outstanding commodity hedges extended through Q2 2018. They mitigate price exposure but can limit upside; potential changes in derivatives regulation could increase costs or collateral requirements.
- Commitments included $72.3 million of remaining drilling-rig obligations at September 30, with $42.5 million in early-termination penalties. A gas purchase agreement assumed in the Gooseneck acquisition could require deficiency payments; the stated undiscounted amount was $42.6 million as of filing if no product were delivered. Management expected to meet minimum volumes.
- The Chieftain Oklahoma royalty class action remained unresolved; the company said it could not estimate the potential impact. Management stated pending litigation and claims were not expected to have a material effect overall. The Endeavour litigation was settled in April 2014, producing a $10.7 million gain.
Important facts for investors to verify
- How much of the reported Q3 earnings increase reflects derivative fair-value gains rather than realized cash flows, and how the hedge book performs as prices change.
- Whether planned production growth and improved well results materialize, including the impact of Eagle Ford shut-ins, weather delays, and increased transportation and operating costs.
- Capital-spending and acquisition requirements relative to operating cash flow, revolver availability, borrowing-base redeterminations, and covenant headroom.
- Final purchase-price adjustments and integration results for the Gooseneck and Powder River Basin acquisitions, including the added gas-throughput obligations.
- Potential exposure and developments in the Chieftain royalty litigation, and any changes to the company’s broader legal or regulatory risks.