Northern Oil and Gas, Inc. — Q2 2011 Form 10-Q
Reporting period: Three and six months ended June 30, 2011. The company is an independent, non-operating oil and gas producer focused primarily on acquiring acreage and participating in Bakken and Three Forks development in the Williston Basin. Financial statements are unaudited.
Financial and operating results
| Metric | Q2 2011 | Q2 2010 | Six months 2011 | Six months 2010 |
|---|---|---|---|---|
| Oil and gas sales | $35.5 million | $11.7 million | $62.5 million | $20.0 million |
| Total revenues, including derivative results | $50.8 million | $16.2 million | $53.4 million | $23.5 million |
| Net income | $20.4 million | $6.1 million | $13.4 million | $7.7 million |
| Diluted EPS | $0.33 | $0.12 | $0.22 | $0.16 |
| Operating cash flow | Not stated separately | Not stated separately | $35.5 million | $15.0 million |
- Q2 production was 400,928 BOE, up 132% year over year; average daily production was approximately 4,400 BOE, reaching approximately 5,200 BOE per day in June. Six-month production increased 154% to 757,550 BOE.
- Q2 oil sales price averaged $95.69 per barrel before settled hedges and $80.78 after hedges. Settled oil hedges reduced the Q2 average by $14.91 per barrel. Q2 average production cost was $5.94 per BOE; depletion was $20.83 per BOE.
- Operating expenses rose to $17.1 million in Q2 and $32.0 million for the first half, chiefly due to greater production, taxes, depletion and G&A. Q2 depletion was $8.3 million; six-month depletion was $15.2 million.
- GAAP revenue and earnings were materially affected by non-hedge-accounted derivative mark-to-market results: Q2 included a $20.8 million gain, while the first half included a $0.4 million loss. Settled derivatives produced losses of $5.6 million in Q2 and $8.9 million in the first half. The filing’s non-GAAP net income excluding unrealized mark-to-market effects was $7.7 million for Q2 and $13.6 million for the first half; these are company-defined non-GAAP measures.
- At June 30, cash and cash equivalents were $77.4 million, down from $152.1 million at year-end 2010. Working capital was $63.5 million. Current assets were $135.7 million and current liabilities $72.2 million.
- Cash flow from operations of $35.5 million was outweighed by $111.7 million of investing outflows, including $154.4 million for oil and gas property purchases and development capital expenditures. The resulting cash decrease was $74.7 million.
- No revolving credit borrowings were outstanding at quarter-end. The then-existing facility had $25 million available, within a $100 million maximum, and was secured by a first-priority interest in company assets. Total derivative liabilities were $16.0 million net of derivative assets.
Changes, outlook and key risks
- Compared with Q2 2010, Q2 oil and gas sales more than tripled and net income increased; growth reflected more producing wells and higher oil prices. For the first half, net income rose despite substantial growth in sales, in part because derivative mark-to-market results shifted from a gain in 2010 to a loss in 2011.
- The company held approximately 155,353 net Williston Basin acres targeting Bakken and Three Forks. It reported 439 gross producing wells and 161 gross wells drilling, awaiting completion or completing at June 30.
- Management expected 2011 drilling capital expenditures of approximately $260 million, with average well costs of approximately $6.5 million. It expected to spud approximately 40 net wells by year-end and projected roughly 50% of current acreage would be held by production or under the bit by year-end.
- Management reported fracture-stimulation delays, with delays between stimulation and completion potentially averaging six to nine weeks in the following quarter. Delays could postpone production additions, although management did not expect them to slow drilling.
- On August 8, 2011, after quarter-end, the company amended its Macquarie credit agreement. It disclosed a $150 million initial borrowing base, but an initial maximum borrowing amount of $25 million; the maximum could increase in $20 million increments, subject to conditions and additional lender commitments, up to $500 million.
- In May, the board authorized repurchases of up to $150 million of common stock; none had been made by the filing date. Management said it believed capital was sufficient for expected drilling commitments and G&A for the next 12 months, but acquisitions or accelerated drilling could require additional financing. Funding may not be available on favorable terms or at all.
- Key risks include volatile oil and gas prices, access to capital, development and completion delays, reserve and cost estimates, and the company’s ability to manage rapid growth. Management reported no material property impairment at June 30. A shareholder derivative lawsuit was dismissed without prejudice in June; the plaintiff filed an amended action in July. The company said it intended to defend the claims.
Important facts for investors to verify
- How much of GAAP earnings reflects realized production economics versus noncash derivative mark-to-market movements, and how the hedge portfolio settles against production.
- Whether drilling, completion timing, well costs and production growth meet management’s 2011 expectations, including the planned $260 million capital program.
- How cash balances and operating cash flow support capital spending and acquisitions, and what borrowing capacity is actually available under the amended facility’s limits and conditions.
- Whether acreage is held by production or brought under the bit as projected, and how expiring leases, reserve estimates and depletion costs affect asset value.
- The status and potential consequences of the amended shareholder litigation, and whether the authorized repurchase program is implemented.