Diamondback Energy, Inc. — 2013 Form 10-K Summary
Reporting period: Fiscal year ended December 31, 2013; filed February 19, 2014. The filing reports full-year results and quarterly data, including fourth-quarter 2013. Diamondback is an independent oil and gas producer focused on the Permian Basin in West Texas. Comparisons require care because acquisitions, including Gulfport properties added in October 2012, materially changed the company’s scale.
Financial and operating performance
| Metric | 2013 | 2012 |
|---|---|---|
| Revenue | $208.0 million | $75.0 million |
| Income from operations | $95.2 million | $17.3 million |
| Net income (loss) | $54.6 million | ($36.5 million) |
| Diluted earnings per share | $1.29 | Not presented on the same reported basis |
| Net cash from operating activities | $155.8 million | $49.7 million |
| Net cash used in investing activities | $940.1 million | $183.1 million |
| Net cash from financing activities | $773.6 million | $152.8 million |
| Cash and cash equivalents at year-end | $15.6 million | $26.4 million |
- Revenue rose 177%, principally from production growth and the full-year contribution of acquired Gulfport assets. Average production increased 149% to 7,321 BOE/day; 76% of 2013 production was oil, 13% natural gas liquids and 11% natural gas.
- Average realized prices before derivatives were $93.32/Bbl for oil and $77.84/BOE for combined production; after derivatives, the combined price was $75.14/BOE. Lease operating expense fell to $7.92/BOE from $14.14, while DD&A was $24.92/BOE and production taxes were $4.83/BOE.
- Fourth-quarter 2013 revenue was $75.9 million and net income was $20.1 million; diluted EPS was $0.42. Revenue and net income increased from the prior quarters of 2013.
- Adjusted EBITDA, a non-GAAP measure, was $164.8 million versus $48.2 million. It should not be treated as a substitute for GAAP earnings or cash flow.
- Year-end current assets were $62.0 million against current liabilities of $121.3 million. Cash was $15.6 million; $215 million was available under the $225 million borrowing base. The filing does not provide a current ratio as a headline metric.
- Total debt was $460 million: $450 million of 7.625% senior notes due 2021 and $10 million drawn on the revolving facility. The notes were issued to fund the Midland County mineral-interest acquisition. The company reported compliance with credit-facility covenants.
Material changes versus prior period
- Full-year production and revenue expanded sharply with drilling, acquisitions and the Gulfport properties’ full-year contribution. Revenue growth was driven mainly by volumes; management attributed about $119.3 million of the $133.0 million increase to production volumes and $13.8 million to price changes.
- Net income improved from a 2012 loss, but the comparison is affected by a $54.9 million 2012 income-tax provision, including a one-time tax charge associated with the company’s conversion to a taxable corporation. 2013 income-tax expense was $31.8 million.
- Operating cash flow increased, but investment spending rose substantially, including $297.7 million for drilling, completion and infrastructure and $444.1 million for mineral interests. Net investing cash outflow was $940.1 million.
- Lease operating costs per BOE declined as production grew and operating changes took effect; by year-end, 70% of produced water was transported by pipeline to disposal wells.
- Proved reserves increased to 63.6 million BOE from 40.2 million BOE. Proved developed reserves were 47.2% of the total, compared with 30.7% in 2012; approximately 53% remained proved undeveloped.
Outlook, risks and unusual items
- Management expected 2014 capital expenditures of $425–$475 million, excluding acquisitions, and planned 65–75 gross horizontal wells and 20–25 gross vertical wells. It intended to add a fifth horizontal rig in the second quarter of 2014. Management said operating cash flow and revolver borrowings were expected to fund operations through year-end 2014, based on then-current price expectations.
- A February 2014 agreement to acquire 6,450 gross (2,825 net) Martin County acres for approximately $174 million remained subject to due diligence and customary closing conditions. The company expected to use revolver borrowings and new debt and/or equity; completion was not assured. Its reserve estimate for these assets was internal, not independently reviewed.
- Commodity prices, drilling results, access to water, rigs and infrastructure, lease expirations, reserve-estimation uncertainty and environmental or hydraulic-fracturing regulation could affect returns and the planned development program. The business and proved reserves are concentrated in the Permian Basin and Wolfberry play.
- Two purchasers—Plains Marketing and Shell Trading—each accounted for 37% of 2013 revenue. The company also disclosed significant receivables from joint-interest owners and production buyers.
- The Minnesota sand-property lawsuit had a jury finding of intentional interference with contract, but the jury found the interference did not prevent the plaintiff from obtaining permits before a county moratorium. Damages and a punitive-damages claim remained unresolved; management assessed the possibility of loss as remote and could not estimate any loss.
- The company used oil swaps to reduce price exposure, targeting hedges on 40%–70% of production. Derivatives were not designated as accounting hedges, so fair-value changes affected reported earnings. No proved-property ceiling-test impairment was recorded in 2013.
- Management and the auditor reported effective internal control over financial reporting; the financial-statement audit opinion was unqualified. The company did not expect to pay cash dividends in the foreseeable future.
Important facts for investors to verify
- Whether the Martin County acquisition closed, its final purchase price and financing, and the performance and independently validated reserves of the acquired properties.
- Whether 2014 capital spending and drilling plans were funded without materially increasing leverage or diluting shareholders.
- Production growth, realized prices after hedges, per-BOE operating costs and the durability of reported well results.
- Reserve revisions, PUD conversion progress and required future development spending; the filing estimated $201 million of PUD development costs for 2014.
- Revolver borrowing-base redeterminations, covenant headroom and the effect of debt service and acquisition funding on liquidity.
- Customer concentration, pending litigation, related-party transactions and any changes in environmental or hydraulic-fracturing requirements.