Northern Oil and Gas, Inc. — Q1 2012 Form 10-Q
Business context and reporting period. This unaudited filing covers the three months ended March 31, 2012, with balance-sheet comparisons to December 31, 2011. Northern is primarily 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 174,248 net mineral acres, approximately 37% developed, and had 793 gross (71.8 net) producing wells.
Financial and operating performance
- Production: Average production was 8,517 Boe per day, up 115% year over year. Quarterly net production was 775,089 Boe, up 117%; oil represented approximately 93% of average daily production. The company participated in completing 129 gross (13.9 net) wells, reporting a 100% success rate in its Bakken and Three Forks activity.
- Revenue and prices: Oil and gas sales were $65.1 million, up 141% from $27.0 million. Realized price including settled derivative effects was $77.16 per Boe, up 16%. GAAP total revenue, after $5.3 million of settled derivative losses and $9.4 million of mark-to-market losses, was $50.5 million versus $2.5 million a year earlier. The year-over-year total-revenue comparison is substantially affected by non-cash derivative valuation losses.
- Profit and expenses: Operating income was $14.8 million, versus an operating loss of $12.3 million. Net income was $8.8 million ($0.14 per diluted share), compared with a $7.1 million net loss ($0.11 per diluted share). Depletion was $18.3 million, or $23.62 per Boe, versus $6.9 million, or $19.25 per Boe. Production expense rose to $8.40 per Boe from $5.65, largely reflecting higher water disposal and workover costs. Adjusted EBITDA, a company-defined non-GAAP measure, was $44.8 million versus $18.6 million; net income excluding unrealized derivative losses, also non-GAAP, was $14.4 million versus $5.9 million.
- Cash flow and investment: Operating cash flow was $38.6 million, compared with $7.2 million used in Q1 2011. Investing cash outflow was $145.1 million, principally for property acquisition and development; cash purchases of oil and gas properties and development totaled $145.0 million. Financing provided $104.0 million, including net revolving-credit advances of $107.6 million. Cash declined $2.4 million to $3.8 million. Capital expenditures of approximately $107.4 million were included in accounts payable at quarter-end.
- Liquidity and debt: Total assets were $869.8 million and stockholders’ equity was $510.0 million. Revolver borrowings increased to $177.5 million from $69.9 million at year-end. The new facility had a $250 million borrowing base, leaving $72.5 million available at March 31; it matures January 1, 2017. Current assets were $85.8 million versus current liabilities of $130.9 million. The company reported covenant compliance at quarter-end. Average borrowing interest rate was 2.7%; management estimated a 1 percentage-point rate increase would add about $1.8 million in annual interest expense.
Material changes versus the prior comparable period
- Production more than doubled, and oil and gas sales rose 141%, driven mainly by new wells and higher realized prices after settled hedges.
- GAAP results turned profitable, although reported revenue and earnings remain affected by mark-to-market derivative losses. Unrealized derivative losses narrowed to $9.4 million from $21.3 million.
- Production costs per Boe increased, as did depletion per Boe, reflecting higher operating costs and updated future development cost estimates.
- Capital spending and borrowing increased substantially to support drilling, development, and acreage acquisitions; cash on hand decreased.
- On February 28, 2012, the company replaced its prior revolving facility with a syndicated facility featuring a $750 million facility size, a $250 million borrowing base, and a January 2017 maturity. Actual availability was limited to the borrowing base less borrowings.
Outlook, commentary, risks and contingencies
- Capital plan: Management expected approximately $360 million in 2012 drilling and completion expenditures and an additional $60–$80 million for acreage acquisitions. Approximately $150 million of the 2012 capital budget had been spent by March 31. Development and acquisition spending is discretionary and may be adjusted for commodity prices, cash flows, and returns. Typical Williston Basin well drilling and completion costs were estimated at $7–$9 million.
- Hedges: At March 31, the company reported hedges covering approximately 2.4 million barrels for 2012, 1.9 million for 2013, and 0.2 million for 2014. Derivatives are not designated as accounting hedges, so fair-value changes flow through earnings. They can reduce exposure to falling prices but also limit gains in rising markets; production shortfalls or price differentials could create liquidity pressure. Net derivative fair value was reported as a $21.2 million liability.
- Market and operating risks: Management cited volatile commodity prices, Williston Basin transportation constraints and oil-price differentials, weather, rising drilling and service costs, and dependence on third-party operators. The Q1 oil differential to WTI was $14.09 per barrel versus $9.34 a year earlier; management said it had subsequently declined and expected infrastructure improvements to help, but this outlook is uncertain.
- Financing and other risks: Borrowing-base redeterminations, covenant restrictions, variable interest rates, and the high capital needs of reserve replacement could constrain spending or liquidity. Approximately half of acreage was estimated not to be held by production or operations, exposing some leases to expiration. Environmental, regulatory, hydraulic-fracturing, title, and decommissioning risks are also disclosed.
- Contingencies and unusual items: A shareholder derivative suit remained pending; a motion to dismiss had been heard, but no ruling had issued. The company said it considered the claims without merit and intended to defend them. Management stated ordinary-course legal matters were not expected to materially affect financial position, results, or cash flows. No property impairment was recorded, and the filing reported no subsequent events requiring disclosure. Disclosure controls were assessed as effective.
Important facts for investors to verify
- Whether production growth and well completions continue at a pace sufficient to support the planned 2012 capital program.
- Actual capital spending, accounts payable for capital expenditures, and remaining borrowing capacity as the borrowing base is redetermined.
- Realized oil prices after transportation differentials and hedge settlements, alongside derivative fair-value changes and hedge coverage relative to production.
- Whether higher production, water-disposal costs, and depletion rates affect unit economics and cash generation.
- Lease acreage expiration exposure, operator drilling schedules, and the status and potential outcome of the pending shareholder litigation.