Diamondback Energy, Inc. — Q3 2013 Form 10-Q
Reporting period: Quarter and nine months ended September 30, 2013. Diamondback is an independent oil and gas company focused on developing and acquiring Permian Basin assets in West Texas. Comparisons with 2012 are affected by acquisitions, increased drilling, and the company’s 2012 transition to a public company; the filing cautions that historical comparisons may not indicate future results.
Financial and operating performance
| Metric | Q3 2013 | Q3 2012 | Nine months 2013 | Nine months 2012 |
|---|---|---|---|---|
| Revenue | $57.8 million | $16.8 million | $132.1 million | $49.2 million |
| Income from operations | $29.4 million | $4.1 million | $57.5 million | $15.1 million |
| Net income | $14.6 million | $0.5 million | $34.5 million | $15.6 million |
| Net cash from operating activities | — | $91.6 million | $33.5 million |
Q3 diluted EPS was $0.33; nine-month diluted EPS was $0.85. 2013 results include deferred income tax expense of $9.1 million for Q3 and $20.1 million for the nine months. The 2012 operating entities were not subject to federal income tax before the October 2012 IPO, so reported net income comparisons are affected by tax status.
- Average production rose 178% year over year to 7,419 BOE/day in Q3 and 154% to 6,275 BOE/day for the nine months. Q3 production was approximately 75% oil.
- Q3 realized average price was $84.67/BOE before derivatives and $79.96/BOE after derivatives. Nine-month averages were $77.11/BOE and $73.83/BOE, respectively.
- Q3 net derivative loss was $4.9 million; the nine-month loss was $1.9 million. Derivatives are not designated as accounting hedges, so fair-value changes are recognized in earnings.
- Cash was $53.1 million at September 30. Current assets were $91.9 million and current liabilities $109.5 million. Operating cash flow was outweighed by investing outflows.
- Net cash used in investing was $830.2 million, including $190.1 million for drilling and infrastructure, $440.0 million for mineral interests, and $166.6 million for leasehold acquisitions. Financing provided $765.3 million, principally from equity offerings and senior notes.
- The company issued $450 million of 7.625% senior unsecured notes due 2021. Long-term debt was $450.1 million at quarter-end; no revolving-credit borrowings were outstanding at September 30. The company reported compliance with its then-effective revolver covenants.
Material changes and management commentary
- Revenue growth primarily reflected higher volumes from drilling and the Gulfport property contribution; Q3 production-volume increases accounted for most of the revenue increase. Nine-month price effects were mixed.
- September acquisitions added approximately 15,000 gross acres of mineral interests in Midland County for $440 million, carrying an average 19.5% royalty interest with no additional operating or capital costs, and leasehold interests in Martin and Dawson Counties for approximately $165 million.
- Management attributed lower lease operating expense per BOE to improved gas gathering and moving more produced water by pipeline. It intended to continue shifting water disposal and oil transportation from trucks to pipelines.
- The 2013 drilling and infrastructure capital budget was estimated at $290–$320 million. In October, the board approved a 2014 budget of $425–$475 million, with most allocated to operated wells. Management expected operating cash flow, the senior-note proceeds, and revolver availability to fund operations through year-end 2014, based on its commodity-price assumptions. The budget excludes acquisitions.
Risks, contingencies, and unusual items
- Oil and gas prices, production, capital availability, drilling results, infrastructure, permits, and acquisition costs could affect cash flow and planned spending. Management said additional capital may be needed and cannot be assured on acceptable terms.
- Two purchasers accounted for 72% of nine-month revenue: Plains Marketing (52%) and Shell Trading (20%). The filing notes customer concentration and unsecured receivables as credit risks.
- A Minnesota jury found that defendants, including a company subsidiary, intentionally interfered with a plaintiff’s contract, but found the interference did not prevent the plaintiff from obtaining mining permits before a county moratorium. A damages phase was expected in 2014. Management considered loss remote, but could not estimate any potential loss.
- The November 1, 2013 amended credit agreement set a $225 million borrowing base within a $600 million facility, subject to redetermination and covenants. This was subsequent to quarter-end.
- Management reported disclosure controls were effective and no material change in internal control over financial reporting during the quarter. It reported no material change in previously disclosed risk factors.
Important facts for investors to verify
- Confirm production growth, well results, and the contribution and economics of the recent acquisitions.
- Review the 2014 spending plan against operating cash generation, commodity-price sensitivity, available revolver capacity, and borrowing-base redeterminations.
- Assess the cost and terms of the $450 million notes, covenant headroom, and future financing needs.
- Evaluate exposure to derivative settlements and fair-value volatility, as well as customer concentration and receivable collection.
- Monitor the Minnesota litigation and any resulting damages determination; the filing provides no clear estimate of potential loss.