01—Abstract
Summary
Summary of the 10-K filed February 20, 2015. Cited figures are marked; the original filing is the authoritative source.
Diamondback Energy's FY2014 10-K shows a company transformed by scale.
Revenue rose 138% to $495.7 milliona on production that grew 166% to 19,474 BOE/d, driven by drilling in the Permian Basin's Wolfberry play and roughly $1.35 billion of acquisitions in 2014 (including $845.8 million of leasehold purchases and a $523.3 million September deal). Net income attributable to Diamondback was $193.8 million ($3.64 diluted EPS), though much of the swing reflects a $127.5 million derivative gain tied to the late-2014 fall in oil prices rather than operating cash generation alone. Operating cash flow of $356.4 million covered only about a quarter of the $1.48 billion investing outflow, so the gap was filled by equity offerings (about $1.6 billion raised across 2014 including Viper) and borrowings.
Proved reserves reached 112.8 MMBOE at year-end 2014, up from 63.6 MMBOE, with about 67% oil and 58.9% proved developed. The reserve base is concentrated in one geographic area and a small number of horizons, and 41% of proved reserves are undeveloped. Management also disclosed that it would cut its 2015 rig count and hold the capital budget at $400b-450 million, citing the collapse in oil prices from over $105 in June 2014 to below $50 by February 2015.
Balance sheet leverage is moderate: long-term debt was $673.5 millionc, including $450 million of 7.625% senior notes due 2021, against a revolver with $276.5 million of availability. The company is also heavily reliant on Shell Trading (64% of 2014 revenue) and carries full-cost accounting exposure to future ceiling-test write-downs if prices stay low.
For investors, the central question is whether the company can sustain returns and production growth with a shrinking drilling program and weaker prices. The filing shows strong 2014 momentum, a clean audit with an unqualified internal-control opinion, and no impairment recorded to date, but it also shows that 2015 economics depend heavily on oil prices and service-cost deflation that the company itself describes as uncertain.
02—Key points
Key Highlights
- Revenue up 138% to $495.7M and production up 166% to 19,474 BOE/d, primarily from new horizontal drilling and acquisitions in the Permian Basin.
- Net income attributable to Diamondback of $193.8M ($3.64 diluted EPS) includes a $127.5M gain on derivatives, which benefited from falling oil prices and is not recurring operating income.
- Proved reserves rose to 112.8 MMBOE (about 67% oil) from 63.6 MMBOE at year-end 2013, with 58.9% classified as proved developed.
- Operating cash flow of $356.4M funded only about a quarter of the $1.48B investing outflow, requiring roughly $1.1B of net financing, including equity raises and debt.
- 2015 capital budget cut to $400-450M (a 6% reduction from 2014) with the rig count reduced from five horizontal rigs to three, reflecting weaker oil prices.
- Long-term debt of $673.5M, including $450M of 7.625% senior notes due 2021, and $276.5M of undrawn revolver capacity at year-end 2014.
- Customer and asset concentration: Shell Trading accounted for 64% of 2014 revenue, and all proved reserves sit in the Wolfberry play in West Texas.
03—One dollar
04—Financials
Financial Highlights
Figures from 10-KFY2014filed February 20, 2015Financial Statements
FY2014 against FY2013
| Line item | FY2014FY2013 | Change |
|---|---|---|
| SG&A Expenses | $21.27M$9.87M | +115.5% |
| Operating Expenses | $283.05M$112.81M | +150.9% |
| Operating Income | $212.67M$95.19M | +123.4% |
| Interest Expense | $34.52M$8.06M | +328.3% |
| Net Income | $193.75M$54.59M | +254.9% |
| EPS (Basic) | $3.67$1.30 | +182.3% |
| EPS (Diluted) | $3.64$1.29 | +182.2% |
| Shares Outstanding (Basic) | 52.83M42.02M | +25.7% |
| Shares Outstanding (Diluted) | 53.30M42.26M | +26.1% |
05—Questions
Frequently Asked Questions
What drove the large increase in Diamondback's 2014 revenue and production?
Revenue rose about $287.7M, to $495.7M, mainly because production volumes increased substantially (19,474 BOE/d vs. 7,321 BOE/d in 2013). Drilling 82 gross horizontal wells and acquiring acreage in Martin, Midland, and Glasscock counties contributed to the volume growth. Lower average realized prices offset about $58M of the increase.
How much of 2014 net income came from operations versus commodity derivative gains?
Income from operations was $212.7M. A $127.5M net gain on derivative instruments, most of it an unrealized fair-value gain of $117.1M from falling oil prices, pushed pre-tax income to $305.0M. Investors should treat the derivative gain as non-cash and largely non-recurring, since it reverses as hedges settle or prices recover.
Is Diamondback at risk of impairment or of losing acreage?
No impairment was recorded in 2014, but the company uses full-cost accounting, so lower prices could trigger ceiling-test write-downs in future periods. Separately, about 15,000 net acres were scheduled to expire in 2015 (7,689 of them expired in February 2015), and holding the 2015-2016 acreage requires at least a one-rig program. Reduced drilling could therefore lead to lease losses.
How is the company financing its growth, and how much debt capacity remains?
Growth has been funded by equity offerings (including about $208M in February 2014 and $485M in July 2014), Viper's IPO and follow-on offering, the $450M senior notes issued in 2013, and revolver borrowings. At year-end 2014, the revolver had $223.5M drawn, a $500M elected commitment (of a $750M borrowing base), and $276.5M available. Total debt-to-EBITDAX covenant is capped at 4.0x. The company also said it expects cash flow plus revolver borrowings to fund operations through 2015.
What are the main risks to the 2015 outlook?
The biggest risk is oil price weakness: WTI fell from above $105 in June 2014 to below $50 in February 2015. The company has hedged about 10,700 Bbl/d of 2015 production at roughly $88 per Bbl, but has not hedged 2016 meaningfully. Other risks include service-cost deflation that could cause deferred completions, concentrated customer exposure to Shell Trading, geographic concentration in the Permian Basin, and the reserve uncertainty inherent in 41% PUD reserves.
06—Continue