PrimeEnergy Corporation — Q3 2012 Form 10-Q
Reporting period: Quarter and nine months ended September 30, 2012. The interim financial statements are unaudited. PrimeEnergy is an independent U.S. oil and natural gas producer, with oilfield services operations and properties across several states and the Gulf of Mexico.
Financial performance
| Metric | Three months ended September 30 | Nine months ended September 30 |
|---|---|---|
| Total revenue | $26.3 million (2011: $46.1 million) | $90.4 million (2011: $100.4 million) |
| Oil and gas sales | $21.8 million (2011: $21.8 million) | $65.7 million (2011: $65.2 million) |
| Operating income | $2.9 million (2011: $7.3 million) | $17.9 million (2011: $11.8 million) |
| Net income attributable to PrimeEnergy | $1.3 million (2011: $4.3 million) | $10.1 million (2011: $5.1 million) |
| Basic / diluted EPS | $0.51 / $0.40 (2011: $1.56 / $1.23) | $3.81 / $2.98 (2011: $1.85 / $1.46) |
| Operating cash flow | Not presented quarterly | $33.4 million (2011: $31.1 million) |
| Capital expenditures, including exploration | Not presented quarterly | $68.6 million (2011: $26.9 million) |
Q3 revenue and earnings were affected by derivative mark-to-market results: unrealized derivatives were a $2.6 million loss in Q3 2012, versus a $12.5 million gain in Q3 2011. For the first nine months, unrealized derivatives were a $2.4 million gain, versus a $9.0 million gain in 2011. Operating income as a share of reported revenue was approximately 11% for Q3 and 20% year to date; these ratios reflect volatile derivative-related revenue.
Balance sheet and liquidity
- At September 30, cash and cash equivalents were $10.6 million; restricted cash was $4.9 million. Current assets were $37.2 million and current liabilities were $37.8 million.
- Total assets were $221.2 million, versus $184.8 million at December 31, 2011. Net property and equipment increased to $183.0 million from $144.7 million.
- Bank debt was $110.0 million, up from $69.8 million at year-end. The $250 million revolving facility had a $125 million borrowing base and $15 million available at quarter-end. Weighted-average borrowing rate was 3.62%; the company reported compliance with covenants.
- Operating cash flow less capital expenditures was approximately negative $35.2 million for the nine-month period; net cash from financing was $36.3 million. Cash increased $2.0 million to $10.6 million.
- Asset retirement obligations totaled $10.0 million. The company settled $14.8 million of obligations during the period and completed contracted plugging and abandonment work on a substantial portion of its offshore properties by September 30.
Changes and operating developments
- Oil and gas sales were nearly flat for Q3 and up 1% year to date. Crude production rose 19% in Q3 and 18% year to date; natural gas production fell 8% and 6%, respectively.
- Oil volumes and revenue benefited from West Texas drilling and Gulf Coast activity. Gas production and revenue declined amid natural decline in offshore properties and lower gas prices.
- Depreciation, depletion, amortization and accretion expense fell 74% in Q3 and 52% year to date, primarily because of lower depletion rates on offshore properties late in their productive lives. This helped lift nine-month net income despite lower derivative gains and higher lease operating costs.
- Nine-month lease operating expense increased 9% to $28.8 million, and general and administrative expense increased 13% to $11.5 million. Management cited higher operating costs on new wells and increased personnel costs, respectively.
- In February, the company acquired additional working interests in Gulf Coast producing properties for a net $6.32 million. Through October 31, it had drilled 36 gross (27.25 net) wells; 33 gross (26 net) were successfully completed, two were under evaluation, and two were drilling.
- The company repurchased 107,734 treasury shares during the first nine months for $2.7 million. The board authorized another 500,000 shares for the repurchase program on October 31, 2012.
Outlook, risks and contingencies
- Management planned approximately 40 gross (29 net) wells in 2012, primarily in West Texas, and said it continued to pursue producing-property acquisitions and development opportunities. Spending levels remain discretionary and depend on business conditions and available prospects.
- Liquidity depends on operating cash flow and the credit facility. Borrowing-base redeterminations depend on reserve estimates; a reduction could limit availability or require repayment if borrowings exceed the revised base.
- Key stated risks include oil and gas price volatility, drilling cost overruns and technical difficulties, operational risks, uncertain reserve and geological estimates, and the ability to replace or expand reserves. Commodity derivatives reduce some price exposure but may limit upside; mark-to-market accounting can make reported earnings volatile. Derivative fair values use Level 3 inputs.
- The company is responsible for certain liabilities of affiliated partnerships if their assets are insufficient; management said partnership cash reserves were expected to cover their obligations. Management did not expect environmental matters or ordinary-course legal actions to materially affect financial condition or results. Legal proceedings were reported as none.
- No specific earnings or production guidance beyond the drilling plan was provided. The company said interim results may not indicate full-year results.
Investor verification priorities
- Reconcile earnings with derivative effects, including Q3’s $2.6 million unrealized loss and the prior-year $12.5 million unrealized gain.
- Verify the nine-month EPS figure: the financial statements report basic EPS of $3.81, while the MD&A text gives $3.79.
- Assess the funding and execution of the elevated drilling and capital program, given $68.6 million of capital expenditures, negative operating-cash-flow-less-capex, and higher bank borrowings.
- Monitor borrowing-base redeterminations, the $15 million remaining availability, covenant compliance, and sensitivity to reserve revisions.
- Review production trends, especially declining natural gas volumes and offshore property depletion, alongside the company’s drilling and acquisition results.
- Consider uncertainty in asset-retirement estimates and the completion and cost of plugging and abandonment work.