Patterson-UTI Energy, Inc. — 2015 Form 10-K
Reporting period: Fiscal year ended December 31, 2015. The filing also reports fourth-quarter results. Patterson-UTI provides land-based contract drilling and pressure pumping services, and holds non-operating oil and natural gas interests.
Business context and reporting period
The business faced a sharp industry contraction following the sustained decline in oil and natural gas prices. U.S. industry rig counts fell more than 60% during 2015. Patterson-UTI averaged 124 rigs operating per day for the year, versus 211 in 2014; at December 31, 2015, 80 rigs were operating in the United States, down 63% from the October 2014 peak.
Financial performance and liquidity
| Metric | 2015 | 2014 |
|---|---|---|
| Revenue | $1.891 billion | $3.182 billion |
| Operating income (loss) | ($407.0 million) | $283.1 million |
| Net income (loss) | ($294.5 million) | $162.7 million |
| Diluted EPS | ($2.00) | $1.11 |
| Operating cash flow | $999.4 million | $728.7 million |
| Capital expenditures | $743.8 million | $1.052 billion |
| Adjusted EBITDA | $582.4 million | $1.002 billion |
Revenue declined 40.6% year over year. Operating margin was approximately (21.5)% and net margin (15.6)%. Operating cash flow less capital expenditures was approximately $255.7 million; cash generation benefited substantially from a $440.9 million reduction in accounts receivable, so it should not be viewed as solely reflecting earnings strength.
Contract drilling revenue was $1.154 billion, down 37.2%; its direct-cost margin was $545.0 million, or approximately 47.2% of revenue. Pressure pumping revenue was $712.5 million, down 44.9%; its direct-cost margin fell to $100.4 million, or 14.1% of revenue, from 19.9%. Oil and natural gas revenue declined 50.3% to $24.9 million.
Fourth-quarter revenue was $338.6 million, versus $901.2 million in the fourth quarter of 2014. The quarter recorded an operating loss of $76.8 million and a net loss of $58.7 million, compared with prior-year-quarter operating income of $106.8 million and net income of $57.6 million.
At year-end, cash and cash equivalents were $113.3 million, working capital was $178.4 million, and total debt was $855 million. The company had no revolver borrowings and reported $500 million of available revolving capacity. Net debt was approximately $741.7 million. Debt included $70 million under the credit-agreement term loan, $185 million under the 2015 term loan, and $600 million of senior notes. The company reported compliance with its debt covenants at year-end.
Material changes versus prior comparable period
- Contract drilling operating days fell 41.4% year over year; average revenue per operating day rose 7.0% to $25,560, partly reflecting higher dayrates and $69.4 million of early-termination revenue.
- Pressure pumping jobs declined 50.9%; pressure pumping margin contracted as direct operating costs rose relative to revenue.
- All three operating segments reported losses in 2015, compared with profitable contract drilling and pressure pumping segments in 2014.
- The company recorded approximately $288 million of pretax non-cash impairment and equipment write-down charges, including $124.6 million for all pressure-pumping goodwill, $131 million for drilling equipment and components, $22 million for pressure-pumping equipment and closed facilities, and $10.7 million for oil and gas properties. A separate $12.3 million charge related to settlement of an EEOC lawsuit.
- Contract drilling backlog fell to $710 million at December 31, 2015, from $1.5 billion a year earlier; approximately 40% of year-end backlog was expected to remain after 2016.
Outlook, risks, contingencies and unusual items
- Management said it did not expect industry activity to improve until commodity prices recovered. Oil prices reached a 12-year low of $26.68 per barrel in January 2016.
- Based on contracts then in place, management expected an average of 59 rigs operating under term contracts in the first quarter of 2016 and 46 on average during 2016. Operating rigs averaged 78 in the United States in January 2016.
- At year-end, approximately 38% of fracturing horsepower was stacked; since the start of 2016, the company had stacked an additional approximately 140,000 horsepower, leaving slightly more than half of its fleet stacked.
- Management expected 2016 capital spending to focus primarily on maintenance, inspections and potential upgrades, with no new rigs or fracturing horsepower purchases planned. It planned to continue aligning costs with activity levels.
- Management’s long-lived-asset cash-flow assessments assumed activity recovery beginning in the first quarter of 2017. If low commodity prices persisted into 2017 or beyond, additional material impairments could result. Contract-drilling goodwill fair value exceeded carrying value by approximately 16% at year-end, leaving sensitivity to forecast assumptions.
- Key risks include further declines in activity and pricing, excess equipment and asset impairment, contract cancellations or renegotiations, customer concentration (the ten largest customers generated 49% of 2015 revenue; one customer generated 13%), environmental and hydraulic-fracturing regulation, operational hazards and limits on insurance or indemnification.
- The 2015 term loan includes a restricted-payment test that may constrain dividends later in 2016. The board declared a $0.10-per-share dividend for March 2016; future dividends remain discretionary. The company also had $73.5 million of equipment purchase commitments and $26.6 million of minimum proppant and chemical purchase obligations, including $9.5 million due in 2016.
Most important facts for investors to verify
- Whether operating rig counts, dayrates, fracturing utilization and pricing continued to deteriorate after the January 2016 disclosures.
- How much of the $710 million drilling backlog was ultimately realized, and whether early-termination payments or contract renegotiations materially affected it.
- Whether operating cash flow remains supported by recurring operations as receivables and other working-capital balances normalize.
- Whether the company maintained covenant compliance and sufficient liquidity, and whether the term-loan restricted-payment provision affected subsequent dividends.
- Whether management’s assumed 2017 recovery and impairment-test forecasts proved reasonable, particularly for contract drilling assets and goodwill.