Northern Oil and Gas, Inc. — 2019 Form 10-K
Business context and reporting period. This annual report covers the fiscal year ended December 31, 2019. Northern is an independent oil and gas producer focused on non-operated working interests in the Bakken and Three Forks formations of the Williston Basin, principally in North Dakota and Montana. Its results depend on third-party operators and are concentrated in one region and commodity sector.
Financial and operating performance
| Metric | 2019 | 2018 |
|---|---|---|
| Oil and gas sales, excluding derivative gains/losses | $601.2 million | $493.9 million |
| Total revenue, including derivative gains/losses | $472.4 million | $678.9 million |
| Operating income | $55.5 million | $432.6 million |
| Net income (loss) | ($76.3 million) | $143.7 million |
| Adjusted net income (non-GAAP) | $120.9 million | $140.7 million |
| Adjusted EBITDA (non-GAAP) | $454.2 million | $349.3 million |
| Cash from operating activities | $339.8 million | $244.3 million |
| Cash used in investing activities | $569.1 million | $474.5 million |
| Cash from financing activities | $243.1 million | $130.4 million |
Average daily production rose 51% to 38,604 Boe per day. Oil and gas production sales increased 22%, largely on higher volumes, while lower commodity prices and sharply lower realized gas prices weighed on unit realizations. Average realized oil price after settled derivatives was $54.66 per barrel versus $54.84; realized gas and NGL price was $1.60 per Mcf versus $4.74. Production expense increased to $8.44 per Boe from $7.15. The filing does not provide a single reported operating-margin measure; operating income was approximately 11.7% of total revenue.
Derivative accounting materially affected reported results: the company recorded a net derivative loss of $128.8 million, including a $173.2 million unrealized mark-to-market loss, partly offset by $44.4 million of settled gains. The 2018 comparison included a $185.0 million net derivative gain. Derivatives are not designated for hedge accounting, so fair-value changes flow through earnings.
At December 31, 2019, cash was $16.1 million and working capital was negative $70.4 million. The company reported $236.1 million of liquidity: $220.0 million of revolver availability and $16.1 million of cash. Debt principal totaled approximately $1.128 billion: $580.0 million drawn on the revolving facility, $417.7 million of 8.5% second-lien notes, and a $130.0 million unsecured VEN Bakken note. Long-term debt, net of discounts and issuance costs, was $1.118 billion. Stockholders’ equity was $558.6 million.
Proved reserves increased 21% to 163.3 MMBoe; 81% were oil, 59% developed, and 41% proved undeveloped. SEC-case PV-10 was $1.822 billion, a non-GAAP, pre-tax reserve measure; the GAAP standardized measure was $1.678 billion. The year-end reserve price assumptions were lower than in 2018.
Material changes versus 2018
- Production and sales volumes expanded, supported by acquisitions and development; the July 2019 VEN Bakken acquisition added 90.1 net producing wells and contributed an estimated 7,912 Boe per day, or 18% of fourth-quarter production.
- Oil and gas sales rose, but total revenue and GAAP earnings fell because the derivative result swung from a large gain to a loss, and depletion, production costs, and financing-related charges increased.
- Net loss included a $23.2 million debt-extinguishment loss, a $29.5 million contingent-consideration loss, and a $6.4 million impairment of other current assets. No full-cost impairment of oil and gas properties was recorded in 2019.
- November refinancing increased the revolver borrowing base from $425 million to $800 million and included repayment of second-lien notes funded partly by revolver borrowings and issuance of $150 million liquidation preference of Series A preferred stock. The company also issued the $130 million VEN Bakken note in connection with the acquisition.
Outlook, risks, and contingencies
Management said it expected sufficient cash flow and liquidity to fund budgeted capital expenditures and operating expenses for at least the next 12 months, while noting that additional capital might be sought. Capital spending is discretionary and may be reduced or deferred if prices, costs, financing, or returns weaken. Management expected development capital spending in 2020 to remain similar to 2019, but the filing does not state a clear dollar amount for the 2020 capital budget. The development plan contemplated 107.5 net PUD wells through 2024 at estimated costs of $782 million.
Management reported that gas gathering and processing constraints caused curtailments, shut-ins, and completion delays in 2019 and expected challenges to persist into 2020. Key risks include commodity-price volatility, reserve-estimate uncertainty, dependence on third-party operators, transportation and processing capacity, substantial leverage and borrowing-base redeterminations, environmental and regulatory requirements, and the ability to finance development and acquisitions. The filing also identifies the early-2020 COVID-19 outbreak as a potential source of market and operating uncertainty.
In January 2020, the company retired $76.7 million of second-lien notes in exchange for $2.5 million cash and preferred shares with a $79.5 million liquidation preference. The company’s $341.7 million federal NOL carryforward is subject to Section 382 limitations following a 2018 ownership change; substantially all deferred tax assets were offset by a valuation allowance. An ongoing Missouri River bed mineral-rights dispute could require reversal of approximately $4.7 million of accrued revenue if resolved adversely. Management stated that ordinary-course litigation was not expected to have a material financial impact.
Fourth-quarter 2019 results were especially volatile: revenue was $59.0 million and net loss was $107.9 million, including a $101.7 million net derivative loss. Management reported effective disclosure controls and internal control over financial reporting; the auditor issued an unqualified opinion on the financial statements and internal controls.
Most important facts for investors to verify
- Whether operating cash flow and revolver availability can sustain planned development while meeting debt service and the VEN note repayment schedule.
- How much production is curtailed by gas gathering and processing constraints, and whether realized gas prices and production costs improve.
- Derivative coverage, settlement prices, counterparty exposure, and the effect of mark-to-market volatility on reported earnings and liquidity.
- Whether the 41% PUD reserve share can be developed on schedule and within the estimated $782 million cost; reserve values are sensitive to prices and assumptions.
- Preferred-stock dividend and conversion terms, potential common-share dilution, and the effects of refinancing and future financing needs.
- Resolution and financial exposure from the Missouri River title dispute, along with lease expirations and other environmental, regulatory, and decommissioning obligations.