Northern Oil & Gas, Inc. — Q3 2011 Form 10-Q
Reporting period: Three and nine months ended September 30, 2011; filed November 9, 2011. Northern is a non-operating oil and gas producer focused primarily on the Bakken and Three Forks formations in the Williston Basin. At quarter-end it reported approximately 158,000 net Williston Basin acres and 527 gross producing wells.
Financial performance
| Metric | Q3 2011 | Q3 2010 | Nine months 2011 | Nine months 2010 |
|---|---|---|---|---|
| Oil and gas sales | $43.7 million | $15.5 million | $106.2 million | $35.6 million |
| Total revenue | $69.1 million | $9.9 million | $122.4 million | $33.3 million |
| Net income | $28.6 million | $1.0 million | $42.0 million | $8.7 million |
| Diluted EPS | $0.46 | $0.02 | $0.68 | $0.18 |
| Operating cash flow | Not separately stated for quarter | Not separately stated for quarter | $49.4 million | $26.3 million |
- Revenue and earnings growth reflected higher production, improved realized oil prices, and substantial derivative fair-value gains. Q3 included a $27.1 million mark-to-market derivative gain; nine-month results included a $26.7 million gain. These non-cash valuation changes materially affect reported results.
- Production was 528,362 BOE in Q3, up 111% year over year; nine-month production was 1.286 million BOE, up 135%. Q3 average production was about 5,900 BOE/day, and September averaged about 7,000 BOE/day. Q3 production was approximately 93% oil.
- Q3 oil price after settled derivatives averaged $81.53/bbl, versus $69.64/bbl a year earlier. Q3 production cost averaged $6.57/BOE, up from $4.19.
- Nine-month investing cash outflow was $209.5 million, including $239.8 million for oil and gas properties and development capital expenditures. Cash fell by $143.8 million to $8.3 million from year-end 2010.
- At September 30, current assets were $90.1 million, current liabilities $58.0 million, and working capital $32.0 million. Total assets were $596.0 million and stockholders’ equity $494.5 million.
- Debt consisted of $15.0 million drawn on the revolving facility, compared with no borrowings at year-end 2010. The outstanding amount was fixed at 2.73%; the facility’s current maximum credit amount was $100 million, with a $150 million borrowing base. Obligations and Macquarie swap agreements are secured by a first-priority interest in company assets.
- Nine-month income tax provision was $25.7 million, predominantly deferred tax expense. No oil and gas property impairment was recorded.
Changes, outlook, and risks
- Year-over-year growth was accompanied by sharply higher operating costs: nine-month operating expenses rose to $55.0 million from $18.9 million, including depletion of $26.0 million versus $8.3 million. Management attributed increases to more producing wells, production costs and taxes, and higher depletion and corporate expenses.
- Management expected 2011 drilling capital expenditures of approximately $260 million, compared with about $182 million spent through September, and reaffirmed a target to spud at least 40 net wells in 2011. It reported 31 net wells spud through November 4.
- Management said it believed liquidity was sufficient for drilling commitments and expected overhead for the next 12 months, but noted that further acquisitions or accelerated drilling could require additional capital. It cautioned that financing may not be available on favorable terms, or at all.
- Frac-stimulation delays, attributed to earlier weather disruption, a growing backlog, and occasional supply-transport constraints, delayed production additions. Management did not expect these delays to slow drilling.
- At September 30, open oil swaps covered 1.222 million barrels at a weighted average price of about $89.29/bbl; 108,000 barrels were subject to collars at $85–$101.75 through December 2011. Additional collars were entered into after quarter-end. Derivative gains and losses can cause significant earnings volatility and do not necessarily reflect operating cash generation.
- Material risks include volatile commodity prices, access to capital, drilling and completion execution, and the conversion of undeveloped acreage into producing reserves. The filing reported a shareholder derivative lawsuit; the company disputed the claims and intended to defend itself. Management considered ordinary-course legal matters not likely to have a material financial impact. Disclosure controls were assessed as effective.
- The board authorized a stock repurchase program of up to $150 million; no shares had been repurchased through the filing date. Management also accrued approximately $2.9 million in discretionary bonuses, expected to be paid in shares, subject to Compensation Committee approval.
Key facts for investors to verify
- Underlying operating performance excluding derivative mark-to-market gains, and the cash settlement effects of hedges.
- Funding capacity for the planned drilling and acquisition program given low cash, substantial capital spending, and potential need for external financing.
- Whether completion delays ease and production growth meets management’s drilling and production expectations.
- Hedge volumes, prices, settlement periods, counterparty exposure, and the effect of later collars on future realized prices.
- Reserve growth, depletion per BOE, acreage lease expirations, and the outcome of the pending shareholder litigation.