Northern Oil & Gas, Inc. — Q2 2017 Form 10-Q
Reporting period: Three and six months ended June 30, 2017; unaudited. Northern is a non-operated oil and gas producer focused on the Bakken and Three Forks formations in North Dakota and Montana. It reported average Q2 production of 13,794 Boe/day, approximately 84% oil, and held 148,571 net acres, about 83% developed.
Financial and operating performance
| Metric | Q2 2017 | Q2 2016 | Six months 2017 | Six months 2016 |
|---|---|---|---|---|
| Oil and gas sales | $48.4 million | $42.5 million | $97.2 million | $70.9 million |
| Net derivative gain (loss) | $16.5 million | $(10.5) million | $33.5 million | $(7.1) million |
| Total revenue | $64.9 million | $32.0 million | $130.7 million | $63.9 million |
| Net income (loss) | $13.8 million | $(109.0) million | $30.7 million | $(235.5) million |
| Net income (loss) per diluted share | $0.22 | $(1.78) | $0.50 | $(3.86) |
| Adjusted EBITDA (non-GAAP) | $30.7 million | $44.3 million | $60.4 million | $80.4 million |
| Operating cash flow | Not separately presented | Not separately presented | $29.7 million | $58.5 million |
Q2 total revenue and GAAP earnings benefited substantially from derivative gains, including $14.2 million of non-cash mark-to-market gain. In contrast, settled derivatives added $2.3 million in Q2 2017 versus $20.0 million in Q2 2016. Adjusted net loss was $0.2 million in Q2 and for the first half, versus adjusted income of $6.5 million and $7.1 million, respectively, in the comparable 2016 periods. These adjusted measures are non-GAAP.
Q2 production was 1.255 million Boe, down 1% year over year; first-half production was 2.452 million Boe, down 2%. Q2 realized price including settled derivatives was $40.41/Boe versus $49.30/Boe a year earlier; first-half realized price was $40.57/Boe versus $46.51/Boe. Q2 production expense was $9.67/Boe, up from $8.74; DD&A was $10.90/Boe, down from $12.76. No oil-and-gas property impairment was recorded in 2017; 2016 included $88.9 million in Q2 and $193.2 million in the first half.
First-half investing cash outflow was $42.6 million, chiefly for oil and gas property spending; financing provided $10.2 million, mainly net revolver borrowings. Cash declined $2.7 million to $3.8 million. Cash capital spending was $42.7 million, while capitalized costs incurred were $58.0 million; $65.2 million of oil and gas properties were included in accounts payable at quarter-end.
Balance sheet, debt and liquidity
- At June 30, 2017, total debt, net, was $845.3 million, up from $832.6 million at year-end 2016. This included $155.0 million drawn on the revolving credit facility and $690.3 million net carrying value of the 8% senior notes; the notes had $700 million aggregate principal outstanding and mature June 1, 2020.
- The revolver borrowing base was $325.0 million, with $170.0 million available. The facility matures September 30, 2018. The company was in compliance with its financial covenants at quarter-end.
- Working capital deficit was $22.7 million, improving from $30.5 million at December 31, 2016. Current assets were $60.7 million and current liabilities $83.3 million. Stockholders’ deficit was $455.5 million.
- Interest expense, net of capitalization, was $16.4 million for Q2 and $32.7 million for the first half. A 1 percentage-point increase in short-term rates on quarter-end floating-rate debt would add about $1.6 million of annual interest expense.
Changes, outlook and material risks
- Revenue improvement primarily reflected stronger commodity prices and derivative mark-to-market gains, not stronger production. Oil and gas sales excluding settled derivatives rose 14% in Q2 and 37% in the first half, while production fell 1% and 2%, respectively.
- Management expects 2017 capital expenditures to rise from 2016 levels as rig activity and higher-intensity completions increase. It expects average well costs to rise 5–10% in 2017; first-half elected-well average AFE was $7.1 million versus $6.9 million for 2016 wells.
- Management believed operating cash flow and revolver availability would cover budgeted spending and operating costs for at least the next 12 months, but said significant acquisitions or increased drilling could require additional capital. The company expects to amend and extend or replace the revolver before its September 2018 maturity; financing may not be available on acceptable terms.
- Northern was discussing potential exchanges of senior notes, potentially for secured notes and equity, to reduce debt and interest expense. Any equity exchange could substantially dilute common shareholders. No completed exchange was reported.
- Commodity prices, production declines, well costs, transportation capacity and borrowing-base redeterminations could impair cash flow, liquidity and covenant headroom. The company warned that lower prices could cause future full-cost ceiling impairments; the prior-year impairment was non-cash.
- Open oil hedges at June 30 included 1.264 million barrels of 2017 swaps at a weighted average $53.36/bbl and 1.717 million barrels of 2018 swaps at $53.52/bbl, plus collars covering 0.15 million barrels in the remainder of 2017 and 0.36 million in 2018. Derivatives are not designated for hedge accounting, so fair-value changes flow through earnings.
- Contingencies include a North Dakota riverbed mineral-title dispute; an adverse decision could require reversal of approximately $6.8 million of accrued revenue. Former CEO Michael Reger’s employment and defamation suit could involve at least $1.6 million in asserted severance and vesting claims, among other unspecified relief. A federal securities class action was amended July 6, 2017. Management stated ordinary-course proceedings were not expected to materially affect the company, while outcomes remain uncertain.
- A $329.7 million valuation allowance was maintained against deferred tax assets, reflecting uncertainty about realization and cumulative book losses over the three-year period. No income tax expense or benefit was recorded in reported net income for the periods shown.
Investor verification priorities
- Separate cash-settled hedge results from non-cash mark-to-market gains when assessing recurring earnings and cash generation.
- Track revolver borrowing-base redeterminations, covenant compliance, the September 2018 maturity and the plan for refinancing or extending the facility.
- Assess the terms, feasibility and potential dilution of any proposed senior-note exchange, and the company’s ability to fund development without materially increasing leverage.
- Monitor production trends, realized oil prices after hedges, per-well costs and capital spending relative to operating cash flow.
- Follow the riverbed title dispute and litigation developments, including any effect on accrued revenue or potential obligations.