SM Energy Company — 2018 Form 10-K
Reporting period: Fiscal year ended December 31, 2018. This is an annual report, not a standalone fourth-quarter filing; quarterly data are included. SM Energy is an onshore U.S. oil and gas exploration and production company focused on the Midland Basin and Eagle Ford shale.
Business context and operating results
Following a portfolio transformation, the company concentrated operations on its Texas core assets and sold substantially all remaining non-core producing properties. The Powder River Basin sale generated $492.2 million of net proceeds; sales of Divide County and Halff East assets generated another $252.2 million.
- Average production was 120.3 MBOE per day, down 1% year over year; on a retained-asset basis, production rose 11%. Permian production increased 91%, while Eagle Ford production declined 26%.
- Year-end proved reserves rose 8% to 503.4 MMBOE, or 18% on a retained-asset basis. Reserve additions of 188.0 MMBOE were partly offset by 40.3 MMBOE divested and net downward revisions of 68.8 MMBOE, primarily reflecting Eagle Ford development-plan changes. Proved developed reserves were 49% of total.
Financial and liquidity highlights
| Metric | 2018 | 2017 |
|---|---|---|
| Oil, gas and NGL production revenue | $1.636 billion | $1.254 billion |
| Total operating revenues and other income | $2.067 billion | $1.129 billion |
| Net income (loss) | $508.4 million | $(160.8) million |
| Diluted earnings (loss) per share | $4.48 | $(1.44) |
| Net cash from operating activities | $720.6 million | $515.4 million |
| Adjusted EBITDAX (non-GAAP) | $900.4 million | $663.2 million |
| Capital expenditures | $1.303 billion | $888.4 million |
Production revenue increased 31%, supported by higher oil volumes and realized prices. Before derivative settlements, realized prices per BOE rose 32% to $37.27; oil was $56.80 per barrel, gas $3.43 per Mcf, and NGLs $27.22 per barrel. Production expense declined 4% overall, although lease operating expense increased 7% per BOE to $4.74. DD&A rose 19% to $665.3 million.
Reported earnings also reflected a $426.9 million net gain on asset divestitures and a $161.8 million net derivative gain, including non-cash fair-value effects. Cash settlements on derivatives were a $135.8 million loss, versus a $21.2 million gain in 2017. The filing does not provide a single company-defined operating margin figure.
- Debt: Long-term debt principal declined to approximately $2.6 billion from $3.0 billion at year-end 2017. The company had no revolving-credit borrowings and $999.8 million of available capacity at year-end. Debt was 47% of book capitalization.
- Liquidity: Cash was $78.0 million; reported working capital was a deficit of $36.8 million. Cash plus available credit capacity was approximately $1.1 billion.
- Cash uses and capital structure: Investing cash outflow was $587.9 million, after $748.5 million of net property-sale proceeds and $1.303 billion of capital expenditures. Financing cash outflow was $368.7 million, reflecting debt retirements partly offset by the 2027 notes issuance. Dividends paid were $11.2 million, or $0.10 per share.
- Reserves valuation: The GAAP standardized measure of discounted future net cash flows was $4.654 billion, up from $3.024 billion. Non-GAAP PV-10 was $5.104 billion. These reserve-based estimates are not presented as current market value.
Material changes versus 2017
- Net income swung from a $160.8 million loss to $508.4 million of income. The comparison is affected by 2018 divestiture gains, derivative fair-value changes, and 2017 asset write-downs.
- Operating cash flow increased 40%; production revenue rose 31%, while equivalent production fell 1% as the company exited Rocky Mountain assets and reduced Eagle Ford investment.
- Capital expenditures increased 47% as development activity accelerated, particularly in the Midland Basin.
- Debt principal fell by about $0.4 billion. The company redeemed its 2021 notes and used a new $500 million 2027 notes issuance to refinance 2023 notes and part of its 2022 notes, extending average debt maturity; debt extinguishment losses totaled $26.7 million.
- Proved reserves increased 8%, but performance and plan-related downward revisions totaled 68.8 MMBOE. The reserve life index increased to 11.5 years from 10.5 years.
Outlook, risks and contingencies
- 2019 plan: Capital spending, excluding acquisitions, was expected to be $1.00–$1.07 billion, with approximately 80% allocated to the Midland Basin. Management anticipated higher production than in 2018 and planned about 100 net Midland Basin wells, plus approximately 28 net Eagle Ford wells drilled and 18 completed.
- Management said it expected adequate liquidity to fund the 2019 program from operating cash flow, prior divestiture proceeds and, if needed, credit-facility borrowings. It expected no material borrowing-base change at the scheduled April 2019 redetermination.
- Key exposures include volatile commodity prices, reserve-estimation and development risks, infrastructure and takeaway constraints, service availability and cost, borrowing-base and covenant risk, and environmental, hydraulic-fracturing, water, flaring and climate-related regulation.
- Minimum delivery commitments through 2027 cover 29 MMbbl of oil, 595 Bcf of gas and 21 MMbbl of produced water. If no product were delivered, estimated undiscounted deficiency payments would be $287.8 million; the company did not expect material shortfalls. A separate drilling and completion agreement could carry penalties of up to $60 million if minimum development requirements are not met by March 31, 2020; management expected to meet them.
- The Chieftain royalty case remains pending; the company said it would defend the case and did not believe the proposed class should be certified. Management stated pending litigation was not expected to have a material financial effect. No material control weakness was reported; the auditor issued unqualified opinions on the financial statements and internal control over financial reporting.
Important facts for investors to verify
- How much 2018 net income and the fourth-quarter result depended on divestiture gains and derivative fair-value movements. Fourth-quarter net income was $309.7 million, with a reported $411.1 million net derivative gain for the quarter.
- Whether Midland Basin production growth, well performance and costs support the 2019 capital plan and management’s production outlook.
- Reserve revisions, proved-undeveloped reserve conversion progress, and the approximately $2.6 billion estimated capital requirement to develop proved-undeveloped reserves.
- Debt reduction, refinancing terms, liquidity, covenant headroom and the effect of commodity prices on the borrowing base and operating cash flow.
- Delivery-commitment exposure, the Eagle Ford development agreement, and the status and potential costs of the royalty litigation.