Northern Oil and Gas, Inc. — 2018 Form 10-K
Reporting period: Fiscal year ended December 31, 2018. The filing also reports fourth-quarter results. Northern is a non-operated oil and natural gas producer focused on the Bakken and Three Forks formations in North Dakota and Montana.
Business context and operating performance
The company participated in 4,792 gross (325.1 net) producing wells and held 157,083 net acres at year-end. Three 2018 acquisitions—W Energy, Pivotal, and Salt Creek—were a major source of expansion and together contributed approximately 11,503 Boe per day, or 32% of fourth-quarter average production.
- 2018 average production was 25,555 Boe per day, up 73% from 14,800 in 2017. Annual production was 9.33 million Boe.
- Year-end proved reserves rose 79% to 135.5 million Boe; 83% were oil and 56% were proved developed. Proved undeveloped reserves were 59.3 million Boe, or 44% of proved reserves.
- Oil price differentials averaged $7.12 per barrel below NYMEX for 2018 and widened to approximately $10.13 per barrel in the fourth quarter.
Financial results and liquidity
| Metric | 2018 | 2017 |
|---|---|---|
| Oil and gas sales | $493.9 million | $224.0 million |
| Total revenues, including derivative gains/losses | $678.9 million | $209.3 million |
| Net income (loss) | $143.7 million | $(9.2) million |
| Diluted EPS | $0.61 | $(0.15) |
| Adjusted EBITDA (non-GAAP) | $349.3 million | $144.7 million |
| Cash from operating activities | $244.3 million | $73.0 million |
| Cash used in investing activities | $(474.5) million | $(119.2) million |
Reported revenue and earnings were materially affected by derivative accounting: the company recorded a $185.0 million net derivative gain, including a $207.9 million non-cash mark-to-market gain and a $22.9 million loss on settled derivatives. Oil and gas sales exclude these derivative effects. Adjusted EBITDA and Adjusted Net Income are non-GAAP measures and should be considered alongside GAAP results.
- Production expense declined to $7.15 per Boe from $9.21; production taxes were $45.3 million and DD&A was $119.8 million. Interest expense was $86.0 million.
- Cash capital spending was $216.0 million for drilling and development and $257.8 million for acquisitions. Operating cash flow exceeded drilling and development cash spending by $27.6 million, excluding acquisitions.
- At year-end, cash was $2.4 million and working capital was a $3.1 million deficit. The company reported $285.0 million of available borrowing capacity under its revolving facility.
- Debt principal was approximately $835.1 million: $695.1 million of 8.5% second-lien notes due 2023 and $140.0 million drawn on the revolver. The notes also had a 1% payment-in-kind interest component accruing under leverage terms. The company reported $830.2 million of debt net of unamortized premium and issuance costs.
- Fourth-quarter net income was $218.3 million. Quarterly results included a $290.6 million derivative gain; the filing’s quarterly table also reports $136.6 million of other expense.
Material changes, outlook, and risks
- Acquisitions and financing: The company completed three significant acquisitions and substantially refinanced its debt. It issued equity, exchanged unsecured notes for shares and second-lien notes, retired its term loan and remaining 2020 unsecured notes, and established a $750 million revolving facility with a $425 million initial borrowing base.
- Share count: Shares outstanding increased substantially during 2018 through equity offerings, debt exchanges, and acquisition consideration. The company reported 378.3 million shares outstanding at year-end; 376.98 million were outstanding as of March 14, 2019.
- Capital outlook: Management expected 2019 development capital spending at similar levels to 2018 and planned to drill 30.9 net PUD wells during 2019. The filing does not provide a clear dollar amount for the 2019 capital budget. Spending remains discretionary and may be reduced if commodity prices weaken or costs rise.
- Liquidity and covenants: Management said cash, operating cash flow, and revolver availability should fund budgeted spending and operating needs for at least 12 months. The revolver includes a maximum 4.0x total-net-debt-to-EBITDAX covenant and a minimum 1.0x current ratio; the company reported covenant compliance at year-end. Borrowing availability depends on lender redeterminations and reserve values.
- Hedges and price exposure: At year-end, open oil swaps covered 6.85 million barrels for 2019 at $63.32 per barrel, 4.19 million for 2020 at $61.01, and 1.31 million for 2021 and beyond at $61.18. 2019 basis swaps covered 3.65 million barrels at a weighted differential of $(2.41). Hedges reduce, but do not eliminate, price exposure and can create earnings volatility.
- Key risks: Commodity-price volatility, regional transportation capacity and differentials, dependence on third-party operators, reserve-estimation and development uncertainty, potential borrowing-base or covenant pressure, and environmental, regulatory, weather, and decommissioning obligations. About 44% of proved reserves were undeveloped and scheduled for development over five years at estimated costs of $736.3 million.
- Unusual items and contingencies: The company recorded a $173.4 million loss on debt extinguishment and a $29.0 million contingent-consideration fair-value loss. Year-end fair-value liabilities included $58.1 million of acquisition contingent consideration and $18.2 million of debt-exchange derivatives, both sensitive to the company’s share price. A Missouri Riverbed mineral-title dispute could require reversal of approximately $5.1 million of accrued revenue if resolved adversely. A securities class action was dismissed with prejudice and was not appealed.
- The company reported a $370.5 million federal NOL carryforward, subject to Section 382 limitations following a 2018 ownership change, and maintained a substantial valuation allowance against deferred tax assets. No impairment was recorded in 2018 or 2017; a $237.0 million non-cash property impairment was recorded in 2016.
Important facts for investors to verify
- Separate cash-generating operating performance from non-cash mark-to-market derivative gains and other significant fair-value or debt-extinguishment charges.
- Review acquisition economics, post-closing adjustments, contingent consideration terms, and the substantial equity issuance and resulting dilution.
- Track borrowing-base redeterminations, covenant headroom, interest costs, and the cash-versus-PIK treatment of second-lien interest.
- Assess whether the planned PUD drilling schedule and estimated $736.3 million development cost are achievable given operator decisions, commodity prices, and available liquidity.
- Monitor realized oil differentials, transportation capacity, hedge volumes and settlements, and reserve revisions under changing price assumptions.
- Confirm the status and potential financial impact of the Missouri Riverbed title dispute and other environmental, regulatory, and abandonment exposures.
The 2018 financial statements received an unqualified audit opinion, and management and the independent auditor reported effective internal control over financial reporting as of December 31, 2018.