Northern Oil and Gas, Inc. — Q1 2013 Form 10-Q
Reporting period: Three months ended March 31, 2013; interim financial statements are unaudited. Northern is a non-operated oil and gas producer focused on the Bakken and Three Forks formations in North Dakota and Montana. At quarter-end, it held 181,823 net acres, approximately 53% developed.
Financial and operating performance
| Metric | Q1 2013 | Q1 2012 / comparison |
|---|---|---|
| Oil and gas sales | $83.2 million | $65.1 million; up 28% |
| Total revenue, including derivative losses | $67.9 million | $50.5 million; up 34% |
| Operating income | $20.7 million | $14.8 million |
| Net income / diluted EPS | $9.0 million / $0.14 | $8.8 million / $0.14 |
| Adjusted EBITDA (non-GAAP) | $63.5 million | $44.8 million |
| Operating cash flow | $56.4 million | $38.6 million |
| Investing cash flow | $(76.1) million | $(145.1) million |
| Financing cash flow | $14.8 million | $104.0 million |
| Ending cash | $8.5 million | $3.8 million at March 31, 2012 |
| Total debt | $439 million | $424 million at December 31, 2012 |
Production averaged 11,115 Boe per day, up 30% year over year; total production was 1.00 million Boe, up 29%. Average realized price including settled derivatives was $82.78/Boe, up 7%. Production expense was $8.64/Boe and depletion was $26.66/Boe. The filing reports a 42% debt-to-total-capitalization ratio.
At March 31, cash was $8.5 million, the revolving facility balance was $139 million, and reported availability was $261 million. The $300 million 8% senior notes mature in 2020; the revolver matures in 2017. Total current assets of $94.1 million were below current liabilities of $134.9 million. The company reported compliance with its credit-facility covenants.
Material changes versus the prior-year quarter
- Higher production drove oil and gas sales growth; the company completed 128 gross (9.6 net) wells during the quarter.
- The oil price differential to WTI narrowed to $3.62/Bbl from $14.09/Bbl, supporting realized prices. Average NYMEX oil was lower, at $94.36/Bbl versus $103.03/Bbl.
- Net income was nearly unchanged despite higher operating income: interest expense rose to $6.1 million from $0.2 million, principally reflecting the 8% notes issued in 2012.
- Depletion rose 46% in total and 13% per Boe, reflecting increased production and higher estimated future development costs. Production expenses increased 33% in total and 3% per Boe.
- Unrealized derivative losses increased to $14.9 million from $9.4 million. Settled derivative losses declined to $0.4 million from $5.3 million.
- Operating cash flow improved, while cash investing outflows fell year over year. The filing attributes the lower cash investment outflow partly to fewer well completions and notes that capital expenditures in accounts payable increased $23 million from year-end.
Outlook, risks and contingencies
- Capital plan: 2013 capital expenditure budget was $420–$440 million, including $370–$390 million for drilling and completion, $20 million for acreage, and approximately $30 million for other activities. Q1 incurred $88.7 million for drilling and completion, $7.4 million for acreage and related activities, and $4.4 million for other capital expenditures. Management may adjust spending with commodity prices, cash flows and expected returns.
- Liquidity outlook: Management expected cash, operating cash flow and revolver availability to fund budgeted capital expenditures and operating costs for at least the current year. Significant acquisitions or increased drilling could require additional capital; availability and terms are not assured.
- Hedging: At quarter-end, derivative agreements covered approximately 2.6 million barrels for 2013, 3.9 million for 2014 and 0.4 million for 2015. The company uses swaps and collars to reduce price volatility, but hedges can limit gains from rising prices. Derivatives are marked to market through earnings and were a net liability of approximately $11.6 million.
- Operating and market risks: Results depend on oil and gas prices, differentials, drilling and completion costs, operator activity, production, and access to capital. Management also cites Williston Basin weather, transportation capacity and infrastructure constraints, and potentially rising service and labor costs.
- Litigation: A North Dakota quiet-title action concerns certain leases. An adverse final judgment could require reversal of approximately $1.4 million of accrued revenue, including $0.1 million from Q1 2013. The company says it is vigorously defending its interest. Other routine legal matters were not expected by management to materially affect results, though outcomes are uncertain.
- Other items: No oil and gas property impairment was recorded. Management reported effective disclosure controls and no material change in internal control over financial reporting. The filing provides no specific earnings or production guidance.
Important facts for investors to verify
- Whether production growth and improved oil differentials persist, and how well-level declines and operator schedules affect future volumes.
- Actual 2013 capital spending versus the $420–$440 million budget, including payment timing for the substantial capital costs recorded in accounts payable.
- Hedge volumes, floor and ceiling prices, derivative fair values and the resulting limits on upside or exposure to price declines.
- Liquidity and covenant headroom after planned investment, including the revolver borrowing-base redetermination and access to additional capital.
- Resolution and potential financial effect of the quiet-title litigation.
- How future development-cost and reserve estimates affect depletion expense and the full-cost ceiling test.