SM Energy Company — Q2 2016 Form 10-Q
Reporting period: Three and six months ended June 30, 2016; filed August 3, 2016. SM Energy is an independent onshore North American oil, gas, and NGL producer focused on the Eagle Ford, Bakken/Three Forks, and Permian Basin.
Financial and operating performance
| Metric | Q2 2016 | Q2 2015 | Six months 2016 | Six months 2015 |
|---|---|---|---|---|
| Oil, gas, and NGL production revenue | $291.1 million | $441.3 million | $503.0 million | $834.6 million |
| Net loss | $168.7 million | $57.5 million | $515.9 million | $110.6 million |
| Diluted loss per share | $2.48 | $0.85 | $7.58 | $1.64 |
| Adjusted EBITDAX (non-GAAP) | $217.1 million | $337.3 million | $399.4 million | $649.1 million |
| Cash from operating activities | $138.6 million | $265.6 million | $256.9 million | $549.5 million |
Q2 equivalent production averaged 157.2 MBOE/day, down 13% year over year; first-half average was 152.4 MBOE/day, down 17%. Realized prices before derivative settlements fell 24% per BOE in Q2 and 28% in the first half. Q2 production expense declined 14% to $148.6 million, while lease operating expense was $3.31/BOE. Q2 reported total operating revenues and other income of $341.8 million included a $50.0 million divestiture gain; operating loss was $230.5 million.
For the first half, investing cash outflow was $351.3 million, including $345.6 million of capital expenditures. Financing provided $94.4 million, principally reflecting $128.5 million of net credit-facility borrowings. Cash was $18,000 at June 30.
Balance sheet, debt, and liquidity
At June 30, total assets were $5.04 billion and stockholders’ equity was $1.35 billion. Debt comprised $2.27 billion of Senior Notes, net of financing costs, and $330.5 million outstanding on the revolving facility. The facility’s $1.25 billion borrowing base left $919.3 million available, after letters of credit. The borrowing base and lender commitments were reduced from prior levels in April, principally reflecting lower proved reserves amid commodity-price declines. The facility matures in December 2019. The company reported compliance with its debt covenants through the filing date.
Changes, outlook, and key risks
- Results versus prior year: Revenue and operating cash flow fell substantially as both production volumes and realized prices declined. Lower activity and service costs reduced capital spending; first-half capital expenditures were down 65% year over year. Production declines also reflect the 2015 Mid-Continent asset sale and reduced drilling and completion activity.
- Impairments and asset sales: First-half proved-property impairment was $269.8 million, mainly on outside-operated Eagle Ford assets following lower expected cash flows. A first-quarter $68.3 million write-down on assets held for sale was partly offset by a Q2 $49.5 million gain as estimated sale values improved. Assets held for sale totaled $173.0 million, with associated asset-retirement obligations of $32.1 million. Agreements to sell certain Permian and Rocky Mountain assets were signed after quarter-end; closings remained subject to customary conditions.
- Capital and production outlook: Management expected 2016 capital expenditures of approximately $670 million, reduced from approximately $705 million, with about 85% directed to drilling and completion. The stated aim was to spend below adjusted EBITDAX and preserve liquidity. Management expected production to be relatively flat quarter over quarter for the rest of 2016, but lower for full-year 2016 than 2015. Drilling and completion activity remained curtailed in several programs.
- Commodity outlook and hedging: Management expected volatile prices, near then-current levels for the remainder of 2016 and higher in 2017, while identifying supply and demand uncertainty. As of July 27, 12-month strip prices were $45.07/ barrel for WTI, $3.02/MMBtu for Henry Hub gas, and $20.48/barrel for NGLs. Derivatives provided near-term protection but can limit upside; the net derivative asset declined to $90.5 million from $488.4 million at year-end. Derivative fair-value changes contributed a $163.4 million Q2 loss and a $149.1 million first-half loss.
- Commitments and other risks: Gathering, processing, and transportation agreements require minimum deliveries of 1,590 Bcf of gas, 72 million barrels of oil, and 14 million barrels of NGLs through 2034. If no product were delivered, disclosed aggregate deficiency payments would be approximately $1.0 billion, before expected operating income from certain systems; management did not expect material shortfalls. A water-disposal agreement could entail approximately $23 million of deficiency payments if no volumes are delivered. The company also cited commodity-price volatility, possible further borrowing-base reductions, ratings downgrades, and the risk of future impairments. It accrued $4.4 million for estimated royalty claims and reported no material expected impact from pending litigation.
Important facts for investors to verify
- Whether announced asset sales close on schedule and at values consistent with the held-for-sale estimates.
- How the October 2016 borrowing-base redetermination affects facility availability, covenant headroom, and liquidity.
- Whether operating cash flow and derivative settlements can support the $670 million capital program as hedges roll off.
- Actual production trends, realized prices, and the potential for additional reserve revisions or property impairments.
- The terms and expected utilization of long-term minimum-volume commitments, especially if production or throughput falls short.