Northern Oil and Gas, Inc. — Q3 2018 Form 10-Q
Reporting period: Quarter and nine months ended September 30, 2018. 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’s Williston Basin.
Financial and operating performance
| Metric | Q3 2018 | Q3 2017 | Nine months 2018 | Nine months 2017 |
|---|---|---|---|---|
| Oil, gas and NGL sales, before derivative gains/losses | $145.4 million | $54.3 million | $341.3 million | $151.5 million |
| Total revenue, including derivative results | $102.3 million | $41.6 million | $235.7 million | $172.3 million |
| Operating income | $35.6 million | $0.6 million | $77.8 million | $64.2 million |
| Net income (loss) | $19.0 million | $(16.1) million | $(74.6) million | $14.7 million |
| Net cash from operations | Not separately stated for the quarter | $126.4 million | $65.6 million | |
| Net cash used in investing | Not separately stated for the quarter | $310.1 million | $75.4 million | |
| Net cash from financing | Not separately stated for the quarter | $194.5 million | $10.2 million |
- Q3 production averaged approximately 26,708 Boe per day; oil was about 84% of production. Total Q3 production rose 74% year over year to 2.46 million Boe. Nine-month production increased 55% to 5.99 million Boe.
- Q3 realized price including settled derivative effects was $53.96 per Boe, up 32% year over year. Nine-month realized price was $51.45 per Boe, up 26%. Q3 oil differential to NYMEX WTI narrowed to $4.16 per barrel from $6.22.
- Derivative losses were $43.1 million in Q3 and $105.6 million for the nine months, including noncash mark-to-market losses of $30.2 million and $72.3 million, respectively. At quarter-end, derivative liabilities, net of derivative assets, were $102.5 million.
- Q3 operating expenses were $66.7 million, including $18.2 million production expense, $13.6 million production taxes and $30.3 million DD&A. Production expense per Boe improved to $7.39 from $8.94; DD&A per Boe increased to $12.31 from $10.90.
- Q3 adjusted net income, a non-GAAP measure, was $34.5 million, or $0.11 per diluted share; adjusted EBITDA was $97.9 million. For the nine months, adjusted net income was $63.9 million, or $0.34 per diluted share, and adjusted EBITDA was $224.4 million. These measures exclude specified items and should be considered alongside GAAP results.
- At September 30, cash and cash equivalents were $113.0 million; working capital surplus was $9.4 million. Long-term debt, net, was $789.5 million, against $979.3 million at December 31, 2017. Stockholders’ equity was $11.2 million, versus a $490.8 million deficit at year-end.
Material changes and significant transactions
- Salt Creek and Pivotal acquisitions closed in June and September, respectively, for estimated consideration of $60.0 million and $146.1 million. Consideration included cash, common shares and, for Pivotal, contingent consideration.
- In May, Northern exchanged approximately $496.7 million of 8% notes due 2020 held by participating noteholders for about $155.0 million of common stock and $344.3 million of 8.5% second-lien notes due 2023. Further negotiated exchanges reduced unsecured notes by another $100.5 million in principal for 32.8 million common shares. Equity offerings also raised approximately $141.7 million net.
- These debt exchanges contributed to a $100.4 million noncash loss on extinguishment of debt during the first nine months. The company also recorded a $13.1 million debt-exchange derivative gain. The sharp increase in shares outstanding—from 66.8 million at year-end to 334.2 million at September 30—reflects equity issuance, debt exchanges and acquisition consideration.
- After quarter-end, Northern closed the W Energy acquisition on October 1 for estimated consideration of $341.6 million, including cash, 51.5 million shares and potential contingent consideration.
- On October 5, Northern issued an additional $350 million of 8.5% second-lien notes and entered a $750 million revolving credit facility, initially subject to a $425 million borrowing base. Proceeds and revolver borrowings repaid the prior term loan in full. On October 11, the remaining $102.8 million principal of 8% unsecured notes was redeemed and repaid.
Outlook, risks and contingencies
- Management stated that cash on hand, operating cash flow and borrowing capacity were expected to fund budgeted capital expenditures and operating expenses for at least the next 12 months, while noting that acquisitions and higher drilling activity could lead the company to seek additional capital. No formal earnings or production guidance is provided in the filing.
- Management expected 2018 well costs to rise approximately 5–10% amid higher activity and more intensive completions; it also said it anticipated a future cash-flow surplus excluding acquisitions. Development and acquisition spending is discretionary and may be reduced if prices or cash flows weaken.
- Commodity prices, Williston Basin transportation capacity and differentials, weather, operating-partner drilling activity, service-cost inflation, acquisition execution, access to capital and debt covenant compliance are key risks. Management said it was in compliance with term-loan financial covenants at September 30, but gave no assurance of future compliance.
- The company had hedged approximately 9.7 million barrels of oil with price swaps at a weighted-average price of about $58.98 per barrel, including 4.8 million barrels in 2019 at $59.56. Derivatives limit some downside exposure but also constrain gains from higher prices and create reported earnings volatility.
- A full valuation allowance was maintained against deferred tax assets; the filing cites cumulative losses over the preceding three years and commodity-price uncertainty. A May ownership change triggered potential Section 382 limits on tax attributes; the analysis was still being evaluated.
- Contingencies include an ongoing dispute over certain Missouri River bed mineral rights, with approximately $5.2 million of accrued revenue at risk if the outcome is adverse, and a pending securities class action. Management said ordinary-course legal matters were not expected to have a material financial effect, but outcomes remain uncertain.
- The filing’s MD&A states cash on hand of $200.9 million at September 30, whereas the balance sheet reports cash and cash equivalents of $113.0 million. The filing text does not clearly reconcile these figures; investors should verify whether the MD&A amount includes other liquidity sources or is an error.
Most important facts for investors to verify
- Reconcile reported September 30 cash of $113.0 million with the MD&A statement of $200.9 million cash on hand, and confirm actual liquidity and revolver availability after the October refinancing.
- Review the post-quarter W Energy acquisition’s final purchase accounting, contingent-consideration terms and resulting dilution, as the filing says required acquisition disclosures were not yet included due to timing.
- Assess the costs, covenants, borrowing-base redeterminations and maturity terms of the new revolving facility and enlarged second-lien debt, including the continuing PIK interest component.
- Evaluate hedge volumes and prices against expected production, derivative settlement cash requirements and the effect of mark-to-market changes on reported results.
- Track production growth and unit costs against higher development spending, acquisition integration and the company’s expectation of future cash-flow surplus.
- Monitor the mineral-rights dispute, securities litigation and potential Section 382 limits on tax attributes.