Northern Oil and Gas, Inc. — Q1 2020 Form 10-Q
Reporting period: Three months ended March 31, 2020. The unaudited interim results cover an independent, non-operated oil and gas producer focused on the Bakken and Three Forks formations in the Williston Basin.
Financial and operating performance
- Revenue: $506.8 million, versus a loss of $6.9 million in reported total revenue in Q1 2019. Oil and gas sales themselves were $130.2 million, down from $132.7 million. The sharp reported revenue swing mainly reflects a $376.6 million net commodity-derivative gain, compared with a $139.6 million loss in Q1 2019; the 2020 gain included $345.1 million of unrealized mark-to-market gains.
- Profit: GAAP net income was $368.3 million ($0.90 per basic share; $0.74 diluted), versus a $107.2 million net loss ($0.29 per share) a year earlier. Adjusted net income, excluding specified items including unsettled commodity derivatives, was $21.7 million ($0.04 diluted share), compared with $27.8 million ($0.07) in Q1 2019. Adjusted EBITDA was $108.0 million, versus $104.8 million.
- Production and realized prices: Production averaged approximately 43,735 Boe per day and totaled 3.98 million Boe, up 28% year over year; oil was 79% of production. Oil sales volumes rose 24%, while natural gas and NGL volumes rose 47%. Realized oil price after settled derivatives was $47.11 per barrel, down 12%; realized price across products including settled derivatives was $40.63 per Boe, down 13%.
- Expenses and margins: Production expense increased 51% to $37.3 million, or $9.38 per Boe versus $7.92. DD&A rose 37% to $61.8 million, or $15.53 per Boe. GAAP operating income was $390.9 million, but this result was substantially affected by derivative gains and is not representative of underlying production profitability.
- Cash flow: Operating cash flow was $100.7 million, compared with $98.9 million. Investing cash outflow was $104.5 million, including $79.0 million in drilling and development and $25.5 million in acquisitions. Operating cash flow less investing outflow was approximately negative $3.8 million. Financing cash outflow was $3.7 million, and quarter-end cash was $8.5 million, down from $16.1 million at year-end.
- Liquidity: Working capital was positive $119.8 million, compared with a $70.4 million deficit at December 31, 2019; the improvement was largely driven by the fair value of commodity derivatives. The company reported $218.5 million of liquidity: $210.0 million of revolver availability and $8.5 million of cash.
- Debt and capital: Debt principal totaled $1.047 billion at quarter-end: $590.0 million under the revolver, $327.5 million of 8.5% second-lien notes, and a $130.0 million unsecured acquisition note. Balance-sheet debt carrying value was $1.040 billion, including a $65.0 million current portion of the acquisition note due January 1, 2021. The company repurchased or retired second-lien notes, including $76.7 million exchanged in January for preferred stock and cash. It had 2.29 million Series A preferred shares outstanding, with a $229.5 million liquidation preference and $5.3 million in undeclared accumulated dividends.
Material changes versus Q1 2019
- Production grew 28%, reflecting acquisitions and development, including the 2019 VEN Bakken acquisition; net producing wells increased 40% to 464.8.
- Lower oil prices and a wider oil differential weighed on unhedged realizations: the average NYMEX oil price was $45.57 per barrel, 17% below the prior-year quarter, and the company’s oil differential widened to $8.50 from $6.19 per barrel.
- Cash gains on settled commodity derivatives increased to $31.5 million from $12.5 million, while large unrealized derivative gains reversed the prior-year mark-to-market loss and drove GAAP earnings volatility.
- Production expense per Boe rose, while G&A declined 19% to $4.9 million. Interest expense declined to $16.6 million from $19.5 million; Q1 2020 also included a $5.5 million debt-extinguishment loss.
Outlook, risks, and unusual items
- Management cut its 2020 developmental capital-spending forecast to $175–$200 million, 53%–59% below 2019 actual development spending. It anticipated lower production as operators curtailed or shut in wells and deferred development amid COVID-19, weak demand, and the oil-price collapse.
- Management expected cash flow, including derivative settlements, and revolver availability to meet liquidity needs for at least 12 months, including the $65.0 million January 2021 note payment. It also expected the revolver borrowing base to decline if market conditions persisted; the April 2020 redetermination was still in process. Management reported compliance with financial covenants at March 31.
- The company had 15.1 million barrels of open crude-oil swaps at a weighted average price of approximately $56.45 per barrel. For the remainder of 2020 it reported approximately 27,000 barrels per day hedged at $58.05 per barrel on average. Derivative fair value was a net asset of $339.2 million at quarter-end, but these mark-to-market gains are not equivalent to cash received.
- No full-cost ceiling-test impairment was recorded in Q1, using SEC-prescribed trailing-average prices. Management expected a noncash impairment in Q2 as lower prices entered the calculation. Its illustrative sensitivity indicated impairment in excess of approximately $600 million under specified lower-price assumptions; this was not a forecast of the final charge.
- Key risks include prolonged low prices, reduced operator activity and production, storage or takeaway constraints, potential borrowing-base reductions and liquidity pressure, reserve and property impairments, and dependence on third-party operators. All wells are operated by third parties, and the company’s properties are concentrated in the Williston Basin.
- A dispute over mineral ownership beneath the Missouri River within the Fort Berthold Reservation could require reversal of approximately $4.6 million of previously accrued revenue if resolved adversely. Management stated ordinary-course legal matters were not expected to have a material impact.
Important facts for investors to verify
- How subsequent oil prices, production curtailments, and operator activity affected realized volumes, cash generation, and hedge coverage after March 31.
- The outcome and terms of the revolver borrowing-base redetermination, available liquidity, covenant headroom, and ability to meet the January 2021 $65 million payment.
- The size and accounting treatment of any subsequent full-cost impairment, and the underlying reserve and price assumptions.
- Cash settlements and counterparty exposure on derivatives, distinguishing realized cash flows from unrealized gains and losses.
- Preferred-stock dividend accumulation, conversion and dilution implications, and progress on debt reduction.