SM Energy Company — Q2 2019 Form 10-Q
Reporting period: Three and six months ended June 30, 2019. Unaudited consolidated results. SM Energy is an independent oil, gas, and NGL producer, with operations focused in the Permian Basin and South Texas.
Financial and operating results
- Second-quarter revenue: Oil, gas, and NGL production revenue was $406.9 million, up 1% from $402.6 million a year earlier. Total operating revenue and other income was $407.2 million, versus $443.9 million, which included $39.5 million of divestiture gains in Q2 2018.
- Profit: Q2 net income was $50.4 million ($0.45 per diluted share), compared with $17.2 million ($0.15) in Q2 2018. First-half net loss was $127.2 million ($1.13 per share), compared with net income of $334.6 million ($2.95 diluted) in first-half 2018.
- Cash flow and investment: First-half operating cash flow was $378.4 million, compared with $311.5 million. Capital expenditures were $576.1 million; operating cash flow less capital expenditures was approximately negative $197.7 million. Investing cash outflow was $563.3 million, and financing cash inflow was $113.3 million.
- Production and costs: Q2 production averaged 136.5 MBOE/day, up 19% year over year; oil volumes rose 24%. Production expense was $123.1 million, up 5%, while production costs per BOE declined 12% year over year. DD&A and asset-retirement accretion rose 36% to $206.3 million.
- Prices and derivatives: Realized prices before derivative settlements fell 15% per BOE year over year. Q2 net derivative gain was $79.7 million, versus a $63.7 million loss in Q2 2018; the first-half result was a $97.4 million derivative loss. These fair-value changes materially affected reported earnings.
- Margins: The filing does not provide a single operating-margin measure. Per-BOE production costs and realized prices are reported above.
Balance sheet, debt, and liquidity
- At June 30, cash and cash equivalents were $12,000; the company also reported $6.4 million of restricted cash, included in other noncurrent assets. Cash, cash equivalents, and restricted cash totaled $6.4 million.
- Revolver borrowings were $118.0 million, with $1.082 billion of available borrowing capacity under $1.2 billion of lender commitments. The borrowing base was $1.6 billion. The next scheduled redetermination was October 1, 2019.
- Debt carrying values were $2.451 billion of Senior Notes, $152.5 million of Senior Convertible Notes, and $118.0 million of revolver borrowings—approximately $2.72 billion combined. Senior Notes principal was $2.477 billion; convertible-note principal was $172.5 million.
- Current assets were $288.7 million and current liabilities were $503.9 million. The company reported compliance with its debt covenants at June 30 and through the filing date.
Changes versus comparable periods
- Production growth, led by a 37% increase in Midland Basin volumes, largely offset lower commodity prices in Q2; first-half production revenue nevertheless fell 5% to $747.3 million.
- Q2 earnings improved year over year largely because derivative results swung to a gain. First-half earnings fell sharply versus 2018, which included $424.9 million of divestiture gains; 2019 also included a substantial first-quarter derivative loss.
- Interest expense declined to $77.6 million for the first half from $84.7 million, mainly reflecting the 2018 redemption of 6.50% Senior Notes due 2021, partly offset by revolver interest.
- Investing cash outflow increased versus first-half 2018, when substantial asset-sale proceeds were received. No material divestitures occurred in first-half 2019.
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. The program was expected to be funded by operating cash flow, year-end 2018 cash, and revolver borrowings.
- Management expected full-year 2019 production and oil’s share of the product mix to increase versus 2018, primarily from the Midland Basin; South Texas production was expected to remain flat year over year. The company expected six Midland Basin rigs and three completion crews on average, and one to two rigs and one completion crew in South Texas.
- Management anticipated near-term commodity-price volatility. Midland Basin takeaway constraints and third-party midstream force majeure events had pressured realized prices; additional takeaway capacity was expected during Q3 2019. Derivatives partially reduced price and location-differential exposure but also create counterparty and fair-value risks.
- Key risks include commodity-price declines, reduced borrowing capacity or borrowing-base redeterminations, leverage and covenant limits, service and infrastructure availability, operational and environmental hazards, and reserve and development uncertainty. A 10% decrease in realized prices before derivatives would have reduced first-half production revenue by approximately $74.7 million in aggregate; derivative settlements would have offset about $37.1 million.
- Commitments included $77.8 million for drilling and completion contracts, with $43.5 million of potential early-termination fees; potential penalties under certain sand and completion arrangements were up to $10.0 million and $15.1 million, respectively, though management did not expect to incur them. Remaining power-purchase obligations totaled $57.1 million through 2027.
- The company adopted lease accounting on January 1, 2019, recognizing approximately $50.0 million of operating-lease right-of-use assets and liabilities. It reported no material pending litigation expected to adversely affect its financial condition, results, or cash flows, and no material changes to previously disclosed risk factors.
Most important facts for investors to verify
- Whether production growth and the planned $1.00–$1.05 billion capital program are achievable within forecast operating cash flow and available borrowing capacity.
- How commodity prices, Midland Basin differentials, and the scheduled borrowing-base redetermination affect revenue, liquidity, and covenant headroom.
- The distinction between GAAP earnings and derivative mark-to-market movements, including the first-half derivative loss and Q2 gain.
- Debt maturities and refinancing requirements, particularly the 2022 Senior Notes and the convertible notes due July 2021.
- Whether reported production, costs per BOE, and expected takeaway improvements support management’s production and cost outlook.