HAL Halliburton
Best-run cyclical frac leader, but a commodity-tied service business; the price already pays for growth it likely won't deliver.
The business
Halliburton sells oilfield services to oil and gas producers: hydraulic fracturing, cementing, drilling fluids, completion tools, wireline, and reservoir software. It is paid per job or per contract, so revenue tracks how much its customers spend on drilling and completions. That spending moves with oil and gas prices. About 40% of revenue comes from North America, where it is the leading pressure pumper, and the rest from international and offshore markets.
Quality gate · 70/100
Moat & management
| Moat | narrow moat |
| Source | scale |
| Trajectory | stable |
| Management | adequate |
Scale in North American fracturing, an integrated service offering, and proprietary technology (e-fleets, automation) give Halliburton cost and execution advantages, so it earns more than its smaller peers through the cycle. These advantages do not protect it from industry-wide pricing collapses. Customers can switch providers when contracts end, and returns depend on the commodity cycle and on oil producers' capital discipline.
Since 2020 management has been disciplined: lower capex intensity, debt paid down to about 1.5x EBITDA, and steady buybacks (share count shrinking 2.6% a year). It has also passed on chasing frac market share. Its record over earlier cycles was weaker, including empire-building (the failed Baker Hughes deal and its $3.5B breakup fee) and buybacks near cycle peaks.
Owner-earnings inputs
| Owner earnings (TTM) | 1.60B |
| Owner-earnings yield | 5.4% |
| Free-cash-flow yield | 5.4% |
| Growth used (normalized) | 3.0% |
| Market-implied growth (reverse DCF) | 4.7% |
| Terminal growth | 3.0% |
| Discount rate (hurdle) | 9.0% |
Projected owner earnings
| Yr | Owner earnings | Growth | PV |
|---|---|---|---|
| 1 | 1.65B | 3.0% | 1.51B |
| 2 | 1.70B | 3.0% | 1.43B |
| 3 | 1.75B | 3.0% | 1.35B |
| 4 | 1.80B | 3.0% | 1.28B |
| 5 | 1.85B | 3.0% | 1.21B |
| 6 | 1.91B | 3.0% | 1.14B |
| 7 | 1.97B | 3.0% | 1.08B |
| 8 | 2.03B | 3.0% | 1.02B |
| 9 | 2.09B | 3.0% | 961.21M |
| 10 | 2.15B | 3.0% | 908.30M |
Key risks
- North American shale activity is past its peak; operators are consolidating, demanding efficiency gains, and pushing back on pricing, so frac fleet demand and margins are falling
- Commodity cycle: an oil price downturn cuts customer capex quickly, and current owner earnings may be near cyclical highs, not normalized
- Long-term energy transition pressure on upstream spending, while competitors in pressure pumping keep adding capacity
Catalysts
- Growth in international and offshore activity, plus gas demand driven by LNG exports and data centers, supporting North American gas drilling
- Continued buybacks at a roughly 5% FCF yield, along with technology-driven margin gains (automated e-fleets, Zeus)
⚠ maintenance capex ≈ min(capex, D&A), capped at FCF · Price pays for ~5%/yr owner-earnings growth over 10y (reverse DCF); model credits 3%.