Patterson-UTI Energy, Inc. — FY 2012 Form 10-K
Reporting period: Fiscal year ended December 31, 2012; includes fourth-quarter results. Amounts are in U.S. dollars. Comparisons are with FY 2011 unless noted.
Business context
Patterson-UTI provides land-based contract drilling and pressure pumping services, primarily in the United States and Canada, and holds non-operating oil and natural gas working interests. At year-end it had 314 marketable drilling rigs and approximately 758,000 hydraulic horsepower of pressure-pumping equipment. Contract drilling generated 67% of annual revenue and pressure pumping 31%.
Financial performance and liquidity
| Metric | FY 2012 | FY 2011 | Change |
|---|---|---|---|
| Revenue | $2,723.4 million | $2,565.9 million | +6.1% |
| Operating income | $497.4 million | $525.6 million | -5.4% |
| Operating margin | 18.3% | 20.5% | -2.2 percentage points |
| Net income | $299.5 million | $322.4 million | -7.1% |
| Diluted EPS | $1.96 | $2.06 | -4.9% |
| Cash from operations | $1,005.3 million | $868.6 million | +15.7% |
| Capital expenditures | $974.0 million | $1,011.6 million | -3.7% |
Revenue growth was driven by drilling, while pressure-pumping revenue was nearly flat. Drilling operating income rose to $349.4 million from $346.1 million; pressure-pumping operating income fell to $132.8 million from $193.4 million. Oil and natural gas segment operating income was $27.2 million, up from $24.0 million. Higher depreciation and impairment expense—$526.6 million versus $437.3 million—was a major pressure on earnings. The company recorded $33.8 million of net gains on asset disposals, including gains from selling flowback operations and excess drilling assets.
Fourth-quarter revenue was $652.8 million, operating income $100.2 million, and net income $58.9 million, compared with $724.6 million, $143.9 million, and $87.6 million, respectively, in Q4 2011. Average drilling rigs operating in Q4 2012 were 206 versus 232 a year earlier.
Operating cash flow was strong, but capital spending was also substantial; operating cash flow less property-and-equipment purchases was approximately $31.4 million. Year-end cash was $110.7 million and working capital was $340.1 million. Total debt was $698.8 million, comprising $600 million of senior notes and $98.8 million under the term loan; there were no revolving borrowings. Approximately $460 million of revolving capacity remained available, subject to facility terms. The company paid $0.20 per share in dividends and spent approximately $170 million on share repurchases during 2012.
Material changes and outlook
- Drilling revenue increased 9.1%, supported by more operating days and higher day rates. Annual average operating rigs rose to 221 from 216, and average revenue per operating day increased to $22,540 from $21,200.
- Pressure-pumping revenue declined 0.5% and operating income fell 31.4%. Total jobs declined 19.4%; higher average revenue per job, reflecting more large multi-stage fracturing work, did not offset higher costs and sharply higher depreciation and impairment.
- Natural gas averaged $2.75 per Mcf in 2012 versus $4.00 in 2011, while oil averaged $94.12 per barrel versus $94.86. Management reported low gas-directed activity and noted that oil-rich basins partially offset the decline.
- Year-end contract-drilling backlog was approximately $1.24 billion, of which management expected about $766 million to be realized in 2013. Backlog is based on remaining term-contract day rates and is subject to assumptions, rate adjustments and customer termination rights.
- The company planned to complete 13 additional APEX drilling rigs in 2013. Management stated that cash, working capital, borrowing availability and expected operating cash flow should support planned equipment investment, debt service and dividends. The filing provides no specific 2013 revenue or earnings guidance.
Risks, contingencies, and unusual items
- Results are sensitive to commodity prices, customer spending, rig and pressure-pumping capacity, service pricing, utilization, labor costs, and supply availability. Management cited industry-wide excess capacity in both conventional drilling rigs and pressure-pumping equipment.
- Hydraulic-fracturing and environmental regulation could raise costs, delay work or reduce customer activity. The filing discusses proposed or developing rules and studies; it does not report a quantified financial impact.
- Operational hazards, including well-control events, weather, pollution and equipment damage, may create liabilities beyond insurance or contractual indemnities. The company disclosed self-insured retentions of $1.0 million per occurrence for workers’ compensation and equipment coverage and $2.0 million for general liability.
- Commitments included approximately $171 million for major equipment purchases and $26.7 million of minimum proppant purchases. Failure to meet purchase minimums could trigger liquidated damages. Letters of credit totaled $39.8 million, with none drawn.
- The company reported ordinary-course legal proceedings and did not believe their outcomes would materially adversely affect results, cash flows or financial condition. It reported no off-balance-sheet arrangements and no goodwill impairment in 2012; it cautioned that weaker markets could lead to future impairment.
Most important facts for investors to verify
- Whether the $766 million of expected 2013 backlog converts to revenue, given customer termination rights and potential rate or operating-day reductions.
- Whether drilling activity and day rates can offset pressure-pumping margin pressure and persistently weak natural-gas-related demand.
- Whether planned rig investment and other capital commitments can be funded while sustaining cash flow, dividends and repurchases; monitor debt and covenant headroom.
- Whether equipment impairment, environmental or operational liabilities, and regulatory developments produce costs beyond those disclosed or estimated.