PrimeEnergy Corporation — Form 10-Q Summary
Reporting period: Quarter and nine months ended September 30, 2014; unaudited interim financial statements. The filing identifies the registrant as PrimeEnergy Corporation.
Business and financial performance
The company is an independent U.S. oil and natural gas producer, with oilfield servicing operations and properties primarily in Texas, Oklahoma, West Virginia, the Gulf of Mexico, New Mexico, Colorado and Louisiana. Unless noted otherwise, dollar amounts below are in millions.
| Metric | Q3 2014 | Q3 2013 | Nine months 2014 | Nine months 2013 |
|---|---|---|---|---|
| Total revenue | $40.7 | $30.0 | $100.5 | $94.2 |
| Oil and gas sales | $23.4 | $25.9 | $73.6 | $71.4 |
| Operating income | $17.9 | $4.8 | $30.5 | $20.6 |
| Net income attributable to PrimeEnergy | $10.8 | $2.2 | $16.8 | $10.6 |
| Basic / diluted EPS | $4.58 / $3.47 | $0.92 / $0.71 | $7.11 / $5.40 | $4.32 / $3.32 |
Total revenue includes derivative gains and losses. Q3 included an $8.4 million unrealized derivative gain, compared with a $3.9 million unrealized loss in Q3 2013. Nine-month unrealized derivative gains were $2.4 million versus losses of $1.5 million in 2013. The company also recorded gains on asset sales of $1.6 million in Q3 and $5.6 million year to date, and a $1.8 million gain from settling asset retirement obligations in Q3. These items materially affected reported earnings.
For the first nine months, oil and gas sales rose 3% as oil production increased 3% to 577,000 barrels, while gas production decreased 3% to 3.551 million Mcf. Q3 oil and gas sales fell 10%, principally reflecting a 14% decline in the average realized oil price to $89.79 per barrel; oil production rose 3%, and gas production fell 3%. Lease operating costs increased 3% year to date, and depreciation, depletion, amortization and accretion increased 3%. The reported income tax rate was 34% for both 2014 periods.
Cash flow, liquidity and debt
- Cash from operations was $44.3 million for the nine months, up from $30.7 million. Capital expenditures were $25.2 million; cash from operations less capital expenditures was approximately $19.0 million. Net investing cash use was $18.9 million, including $6.3 million of asset-sale proceeds.
- Cash and cash equivalents were $9.2 million at September 30, 2014, plus $3.5 million of restricted cash. Current assets were $33.4 million and current liabilities $39.4 million.
- Balance-sheet bank debt was approximately $99.3 million, comprising $96.4 million of long-term debt and $2.8 million current debt, down from approximately $121.9 million at December 31, 2013. The revolving facility had an $160.0 million borrowing base, $86.5 million drawn and $73.5 million available; the facility’s stated maximum was $250 million. Equipment loans totaled approximately $12.8 million at quarter-end.
- Stockholders’ equity attributable to PrimeEnergy was $60.0 million, compared with $45.4 million at year-end 2013. The company repurchased 44,799 common shares for $2.6 million during the nine months.
Outlook, risks and notable disclosures
- Management planned approximately 25 gross (11.5 net) wells in 2014 at a net cost of about $30 million, and reported a shift toward horizontal drilling. As of November 10, 23 gross (10.9 net) wells had been drilled or were in progress; 14 were producing.
- Management expected seven additional Mid-Continent horizontal wells in Q4 2014 and Q1 2015. A planned Upton County, Texas, first phase of up to nine wells was expected to begin in Q1 2015 at an estimated net cost of $35 million. A broader Apache-partner program was described as about 60 wells over 18–24 months, with estimated total cost of $470 million and PrimeEnergy’s expected share about $150 million. These are plans and estimates, not guarantees.
- Management said it was complying with credit-facility covenants and expected to remain compliant over the following 12 months. Borrowing availability depends on semiannual reserve-based borrowing-base reviews; lenders may reduce the base. The company’s oil and gas properties secure the facility.
- Risks discussed include volatile oil and gas prices, drilling cost overruns and technical difficulties, uncertainty in seismic interpretation and reserve estimates, and the ability to replace or expand reserves. Derivatives can limit participation in price increases, expose the company to counterparty risk, and create mark-to-market earnings volatility.
- Asset retirement obligations depend on estimates of abandonment costs, well lives, inflation and discount rates. Management stated that environmental and ordinary-course legal matters were not expected to have a material adverse effect; the filing reported no legal proceedings. Disclosure controls were concluded effective, with no material quarterly change in internal controls over financial reporting.
Important facts for investors to verify
- How much of the earnings increase reflects recurring production and operating performance versus derivative mark-to-market gains, asset-sale gains and the insurance-related asset-retirement settlement gain.
- Current and subsequent-period oil and gas prices, production trends, and the effect of hedges, including the impact of early derivative settlements.
- Updated borrowing-base determinations, covenant headroom, debt repayments and liquidity available to fund planned drilling.
- Actual costs, timing, partner funding and realized results for the horizontal drilling programs, especially the projected $150 million company share of the broader West Texas development.
- Changes in reserve estimates and asset-retirement assumptions, and whether working-capital increases—particularly accrued liabilities—are sustained or timing-related.