Northern Oil and Gas, Inc. — Q3 2017 Form 10-Q
Business and period: Unaudited results for the quarter and nine months ended September 30, 2017. Northern is a non-operated oil and gas producer focused on the Bakken and Three Forks formations in North Dakota and Montana. About 85% of its 145,749 net acres were developed; Q3 average production was approximately 15,321 Boe per day, 84% oil.
Financial and operating performance
- Q3 revenue: $41.6 million, down 8% from $45.1 million. Oil and gas sales rose to $54.3 million from $41.7 million, but a $12.7 million net derivative loss (versus a $3.4 million gain) reduced reported revenue.
- Q3 earnings: Operating income was $0.6 million; net loss was $16.1 million, or $0.26 per diluted share, compared with a $45.6 million net loss, or $0.74 per share, in Q3 2016. Adjusted net income, a non-GAAP measure, was $2.2 million versus $2.4 million; Adjusted EBITDA was $35.7 million versus $33.0 million.
- Nine-month results: Revenue was $172.3 million, up 58%; net income was $14.7 million versus a $281.2 million loss in 2016. The comparison was affected by 2016 non-cash impairment charges of $237.0 million. Adjusted net income was $1.9 million versus $9.5 million, and Adjusted EBITDA was $96.1 million versus $113.4 million.
- Production and prices: Q3 production increased 14% year over year; nine-month production increased 3%. Q3 realized price including settled derivatives was $40.90 per Boe, approximately unchanged from $41.03. Nine-month realized price was $40.69 per Boe, down from $44.70, as lower hedge settlements offset higher benchmark prices.
- Costs: Q3 production expense was $12.6 million ($8.94/Boe); G&A was $8.0 million, including a $3.6 million charge related to the former CEO settlement. Nine-month DD&A was $41.9 million, down from $47.7 million, partly because the 2016 impairment lowered the depletion base. No oil and gas ceiling-test impairment was recorded in 2017 through Q3.
- Cash flow and investment: Nine-month operating cash flow was $65.6 million, down from $97.7 million. Investing cash outflow was $75.4 million, including $75.6 million of cash spending on development and acquisitions; reported cash spending exceeded operating cash flow by about $10 million. Ending cash was $6.8 million.
- Debt and liquidity at September 30: Total debt was $846.1 million: $700 million principal of 8% senior notes due 2020 and $155 million drawn on the revolving facility. The revolver had $170 million of remaining borrowing availability but was classified as current because it matured in September 2018. Working capital deficit was $57.0 million excluding current debt maturities. Stockholders’ deficit was $470.6 million.
Changes, outlook and material matters
- Production growth reflected increased development activity and enhanced completions; weather-related shut-ins and curtailments partly offset gains. Management expected 2017 costs per well to rise 5–10%, with higher-intensity completions contributing to the increase.
- Management stated it expected operating cash flow and existing borrowings to fund budgeted capital expenditures and operating costs for at least the next 12 months, while warning that lower commodity prices could reduce liquidity, borrowing capacity, and covenant headroom. It may curtail capital spending if cash flows weaken; reduced drilling could lower future production. No specific production or earnings guidance was provided.
- At September 30, oil swaps covered approximately 0.6 million barrels for the remainder of 2017 at a weighted average $53.36/barrel and 2.4 million barrels in 2018 at $52.58/barrel. Collars covered about 0.1 million barrels in 2017 and 0.4 million in 2018, with $50/barrel floors and ceilings near $60. These derivatives reduce price exposure but also limit gains from higher prices. Fair-value changes are recognized in earnings, creating volatility; the net derivative position was a $3.4 million asset at quarter-end.
- Subsequent refinancing: On November 1, 2017, the company repaid the revolver with $300 million of initial term loans under a new facility permitting up to $500 million in total commitments, including conditional delayed-draw and uncommitted incremental amounts. The facility matures in 2022 and bears interest at adjusted LIBOR (subject to a 1% floor) plus 7.75%. It includes restrictive covenants, mandatory prepayment provisions and prepayment protections; it also requires the 2020 notes’ principal to be no more than $30 million by March 1, 2020.
- Legal and other risks: A September 2017 settlement with former CEO Michael Reger included $750,000 cash and 3 million common shares. A securities class action remains pending; the company’s motion to dismiss had not been decided. A dispute over North Dakota riverbed mineral rights could require reversal of approximately $5.6 million of accrued revenue if resolved adversely. The company reported compliance with its revolver covenants at September 30. A $335.6 million deferred-tax valuation allowance reflects uncertainty about realizing tax assets.
Important facts for investors to verify
- Current debt terms, covenant compliance, liquidity and the timing and feasibility of reducing the 2020 notes as required under the new term loan agreement.
- Whether production growth, commodity prices and hedge settlements generate enough cash to fund development, interest and debt obligations.
- The extent of dilution from the 3 million shares issued in the former CEO settlement and the reported common shares outstanding after the settlement.
- Developments in the securities class action and the riverbed mineral-rights dispute, including any potential financial impact.
- The assumptions underlying reserve values and future impairment exposure, particularly if oil and gas prices decline.