SM Energy Company — Q3 2019 Form 10-Q
Business context and period: Independent oil and gas producer focused on the Midland Basin and South Texas. This unaudited report covers the three and nine months ended September 30, 2019; comparisons are with the corresponding 2018 periods unless noted. The company reported approximately 80,000 net acres in the Midland Basin and 163,000 net acres in South Texas.
Financial and operating results
- Q3 revenue: Oil, gas, and NGL production revenue was $389.4 million, down 15% from $458.4 million. Average daily production increased 4% to 134.9 thousand BOE, but realized prices before derivative settlements fell 5% for oil, 39% for gas, and 49% for NGLs.
- Q3 earnings: Net income was $42.2 million, or $0.37 per diluted share, compared with a $135.9 million net loss, or $1.21 loss per diluted share, in Q3 2018. Operating income was $99.5 million versus an operating loss of $108.6 million. Q3 adjusted EBITDAX, a non-GAAP measure, was $257.8 million versus $256.1 million.
- Nine-month results: Revenue was $1.14 billion, down 9%. Net loss was $84.9 million, or $0.76 per diluted share, compared with net income of $198.7 million, or $1.75 per diluted share. Adjusted EBITDAX was $707.2 million versus $691.2 million.
- Costs and margins: Q3 production expense was $129.0 million, up 1%; DD&A and asset-retirement accretion was $211.1 million, up 5%; and G&A was $32.6 million, up 11%. DD&A was $17.02 per BOE. The filing does not present a single adjusted operating-margin measure.
- Cash flow and investment: Q3 operating cash flow was $203.2 million versus $229.7 million. For the first nine months, operating cash flow was $581.6 million; capital expenditures were $788.6 million; and investing cash use was $778.7 million. Cash, cash equivalents, and restricted cash totaled $3.5 million at September 30, including $3.5 million of restricted cash.
- Debt and liquidity: At September 30, the company had $129.0 million outstanding on its revolving facility and approximately $2.61 billion principal of senior and convertible notes; debt carrying value was approximately $2.74 billion in total. Revolver availability was $1.071 billion under $1.2 billion of lender commitments. The company reported compliance with debt covenants. Current assets were $311.1 million and current liabilities were $491.0 million.
- Dividends: The quarterly dividend was $0.05 per share; $0.10 per share was declared during the first nine months.
Material changes and drivers
- Production growth was led by the Midland Basin: Q3 Midland output rose 11% year over year; total daily production rose 4%. Nine-month total daily production rose 9% (13% on a retained-asset basis).
- Lower commodity prices drove weaker production revenue despite higher volumes. Midland gas takeaway constraints and third-party midstream force majeure events also pressured realized prices; management expected gas differentials to remain adverse into 2020 pending additional takeaway capacity.
- Q3 results included a $100.9 million net derivative gain, versus a $178.0 million loss in Q3 2018. For the first nine months, derivative results were a $3.5 million gain versus a $249.3 million loss. These fair-value-sensitive items materially affected reported earnings.
- Nine-month 2018 results included $425.7 million of divestiture gains, principally from the Powder River Basin sale, and a $26.7 million debt-extinguishment loss. These sizable prior-period items affect year-over-year comparisons.
- Production costs per BOE decreased 2% for Q3, but lease operating expense per BOE increased 7%. DD&A per BOE increased 13% for the nine-month period, reflecting a higher share of production from the more oil-focused Midland Basin.
Outlook, risks, and unusual items
- Management expected 2019 capital spending, excluding acquisitions, of $1.00–$1.05 billion, with approximately 80% of drilling and completion capital allocated to the Midland Basin and 20% to South Texas. It expected full-year production and oil mix to increase versus 2018; South Texas production was expected to remain broadly flat year over year.
- Management stated that available liquidity and expected cash sources were sufficient to execute its business plan for the foreseeable future. The next scheduled borrowing-base redetermination was April 1, 2020; a subsequent redetermination reaffirmed existing borrowing-base and lender-commitment levels.
- After quarter-end, the company reorganized certain functions to reduce overhead and eliminate duplicative regional operations. It expected $7.0–$8.5 million of related charges, including $3.0–$5.0 million in Q4 2019, and anticipated lower G&A in future years.
- Commodity prices remain volatile. Management cited oversupplied NGL markets, near-term gas supply exceeding demand, and regional takeaway constraints. Derivatives reduce some price exposure but introduce counterparty risk and can limit upside; the company’s Q3 derivative gains were materially influenced by fair-value changes.
- Commitments included $57.1 million for drilling-rig and completion-service contracts, with $38.1 million of potential early termination fees; up to $10.0 million of potential sand-agreement penalties; and $55.1 million of remaining electrical-power purchase obligations through 2027. Management did not expect material penalties under the service agreements.
- Management said pending litigation was not expected to have a material effect. No material risk-factor changes were reported; disclosure controls were deemed effective at a reasonable assurance level, with no material Q3 changes in internal control over financial reporting.
Important facts for investors to verify
- Whether production growth and the planned $1.00–$1.05 billion capital program can be funded while maintaining covenant compliance and adequate liquidity.
- How much reported earnings and cash generation depend on derivative settlements and unrealized fair-value movements, and the remaining hedge coverage and terms.
- Whether Midland Basin takeaway capacity improves as expected and how regional differentials affect realized prices into 2020.
- The maturity and refinancing implications of the 2022 Senior Notes, including the credit-facility provision that could accelerate facility maturity to August 2022 if specified actions are not completed.
- Actual reorganization charges, future G&A savings, and fulfillment or termination costs for drilling, completion, sand, and power commitments.