NORTHERN OIL & GAS, INC. quarterly report, Q2 FY2020

Northern Oil and Gas, Inc. — Q2 2020 Form 10-Q

Reporting period: Three and six months ended June 30, 2020. The company is a non-operating oil and gas producer focused primarily on the Bakken and Three Forks formations in the Williston Basin. All figures below are U.S. dollars; financial statement amounts are in millions unless noted.

Financial performance and position

Metric	Q2 2020	Q2 2019	Six months 2020	Six months 2019
Oil and gas sales	$20.7	$149.8	$150.9	$282.5
Derivative gain (loss), net	$(72.6)	$36.6	$303.9	$(103.0)
Total revenue	$(52.0)	$186.4	$454.8	$179.5
Net income (loss)	$(899.2)	$44.4	$(530.9)	$(62.8)
Operating cash flow	Not separately provided for the quarter	$202.2	$198.3

• Q2 production averaged approximately 23,804 Boe per day, down 46% from Q1 2020; reported Q2 production was 2.17 million Boe, down 32% year over year. Oil was approximately 77% of Q2 production.
• The Q2 net loss included a $762.7 million non-cash full-cost ceiling impairment. Management said the charge reduced reported earnings, not cash flow, and expected further non-cash write-downs if weak pricing persisted.
• Six-month investing cash outflow was $190.5 million and financing cash outflow was $26.0 million. Cash declined by $14.2 million to $1.8 million at June 30.
• At June 30, working capital was positive $25.9 million. Current assets of $205.1 million included $156.4 million of current derivative assets; current liabilities were $179.2 million.
• Debt principal totaled $995.3 million: $568.0 million under the revolver, $297.3 million of 8.5% second-lien notes, and $130.0 million under the VEN Bakken note. The balance sheet reported $989.2 million debt net of discounts and costs, including $65.0 million classified as current.
• Stockholders’ equity was $140.7 million. The company had 436.4 million common shares and 2.29 million Series A preferred shares outstanding at period end; preferred shares carry a 6.5% cumulative dividend, and $9.1 million of dividends had accumulated but none had been declared or paid.
• Per-unit Q2 production expense rose to $12.30/Boe from $8.21; DD&A was $16.97/Boe versus $14.49. The filing does not provide a directly comparable operating margin figure.

Material changes and drivers

• Q2 oil and gas sales excluding settled derivatives fell sharply amid lower commodity prices and production. Average NYMEX oil was $27.95/barrel versus $59.89 a year earlier; natural gas was $1.70/Mcf versus $2.56.
• Cash gains on settled commodity derivatives were $77.4 million in Q2, but unsettled mark-to-market losses were $150.1 million, producing a net derivative loss of $72.6 million. For the first half, derivative gains totaled $303.9 million, including $195.0 million of unsettled gains. Management cautions that unsettled fair-value movements create earnings volatility and are generally offset by future realized pricing effects.
• Q2 realized oil price including settled derivatives was $63.54/barrel; realized natural gas and NGL price including settled derivatives was negative $2.41/Mcf, reflecting storage constraints and processing charges. Total realized price including settled derivatives was $45.29/Boe, down 7% year over year.
• Six-month GAAP revenue increased largely because of derivative accounting gains, while adjusted EBITDA declined to $174.7 million from $215.6 million. Q2 adjusted EBITDA was $66.1 million versus $110.8 million. These are company-defined non-GAAP measures.
• The company retired $76.7 million of second-lien principal in Q1 through cash and preferred-stock consideration, and $30.2 million in Q2 in exchange for 28.5 million common shares. Debt reduction was accompanied by equity dilution and preferred obligations.

Outlook, liquidity, risks, and contingencies

• Management cut its 2020 capital-spending forecast to $175–$200 million, 53%–59% below 2019 development capital expenditures. Q2 capital expenditures were $34.5 million, down 60% from Q1.
• Management expected 2020 production to be significantly below its original expectations because operators curtailed or shut in wells and deferred completions. It estimated these actions reduced Q2 average daily production by about 16,800 Boe/day, with some effects expected to continue into the second half.
• Management expected hedging gains, lower capital spending, and revolver availability to meet liquidity needs for at least 12 months, including the $65 million VEN Bakken note payment due January 1, 2021. This outlook is subject to significant commodity, operating, and financing uncertainty.
• The revolver borrowing base was $800 million at June 30. A July 8 redetermination reduced it to $660 million; pro forma availability was $92 million, plus $1.8 million cash, or total liquidity of $93.8 million. The amendment also restricted retaining excess cash rather than applying it to revolver borrowings. The next redetermination was scheduled for October 1, 2020.
• The company reported compliance with revolver financial covenants at June 30, including maximum net debt/EBITDAX of 3.50x and a minimum current ratio of 1.00x. The filing warns that lower commodity prices, a reduced borrowing base, cash-flow pressure, and covenant requirements could affect liquidity and debt service capacity.
• Open swaps at June 30 covered 12.7 million barrels of oil at a weighted average price of about $56.05/barrel and 12.8 million MMBtu of natural gas at about $2.41/MMBtu. The company also had $200 million of interest-rate swaps. Hedge volumes can exceed production, as they did in Q2 when hedges covered approximately 154% of crude oil production.
• COVID-19, weak demand and oversupply, OPEC-related volatility, operator curtailments, storage and transport constraints, and the all-Williston Basin geographic concentration are material risks. DAPL shutdown litigation could raise oil differentials; a shutdown order had been temporarily stayed, but further closure remained possible.
• The company disclosed an ongoing dispute over certain Missouri Riverbed mineral rights in North Dakota. An adverse final judgment could require reversal of approximately $4.5 million in accrued revenue. Management said ordinary-course legal proceedings were not expected to have a material financial impact, while noting litigation outcomes are uncertain.

Most important facts for investors to verify

• Whether production curtailments, operator activity, commodity prices, and the $175–$200 million capital plan evolve as management expected.
• Actual revolver availability and covenant headroom following the $660 million borrowing-base reduction and subsequent redeterminations.
• The timing and funding of the $65 million VEN Bakken note repayment, alongside remaining debt service and preferred dividends.
• Hedge settlement cash flows versus mark-to-market earnings movements, and the extent to which hedge volumes align with actual production.
• Whether lower trailing-12-month prices trigger additional ceiling-test impairments, and the status of DAPL litigation and the mineral-rights dispute.