Northern Oil and Gas Announces Third Quarter 2020 Results

Source: 11/6/2020, Location: North America

- Third quarter production of 29,051 Boe per day, at the high end of guidance, up 22% from the second quarter
- Third quarter cash flow from operations of $69.0 million, excluding $12.6 million spent to reduce net working capital, up 30% from the second quarter
- Total capital expenditures of $43.8 million in the third quarter
- Operating expenses down 9% in total, and down 27% on a per unit basis, from the second quarter
- Total debt reduced by $6.5 million in the third quarter, and an additional $21.0 million since the end of the third quarter, for a total of $160.0 million year-to-date
- Approximately 25,800 barrels per day of fourth quarter 2020 oil hedged at an average price of $58.03 per barrel
- Approximately 19,400 barrels per day of 2021 oil hedged at an average price of $55.68 per Bbl
5,000 barrels per day of first quarter 2022 oil hedged at an average price of $51.77 per Bbl

Northern Oil and Gas, Inc. announced the company’s third quarter results.

“Northern’s business model continues to deliver on its 2020 plan,” commented Nick O’Grady, Northern’s Chief Executive Officer. “Costs were down, production was up and we generated meaningful free cash flow while continuing to strategically bolt on high return assets. As of November 6, 2020, our debt is already down $160 million year-to-date, and our 2021 outlook continues to be focused on delivering more free cash flow, debt reduction and taking advantage of market distress. Despite the industry challenges, we continue to work through a great pipeline of deal flow at some of the most compelling valuations seen in energy in decades.”

Third quarter Adjusted Net Income was $27.5 million or $0.51 per diluted share. Third quarter GAAP net loss was $233.0 million or $5.44 per diluted share, driven in large part by non-cash items: a $199.5 million impairment expense and a $70.2 million mark-to-market loss on unsettled commodity derivatives. Cash flow from operations was $69.0 million in the third quarter, excluding $12.6 million spent to reduce net working capital. Adjusted EBITDA in the third quarter was $82.7 million. (See “Non-GAAP Financial Measures” below.)

Third quarter production was 29,051 Boe per day, a 22% increase from the second quarter. Oil production represented 77% of total production at 22,335 Bbls per day. Production increased due to an increase in net completions and a partial return of curtailed production by many of Northern’s operating partners. Northern estimates that curtailments, shut-ins and delayed well completions still reduced the Company’s average daily production by over 11,000 Boe per day in the third quarter. Northern had 3.4 net wells turned online during the third quarter, compared to 1.3 net wells turned online in the second quarter of 2020.

During the third quarter, NYMEX West Texas Intermediate (“WTI”) crude oil averaged $40.90 per Bbl, and NYMEX natural gas at Henry Hub averaged $1.97 per million cubic feet (“Mcf”). Northern’s unhedged net realized oil price in the third quarter was $34.36, representing a $6.54 differential to WTI prices. Oil differentials narrowed from significantly higher levels in the second quarter. Northern’s third quarter unhedged net realized gas price was $0.83 per Mcf, representing approximately 42% realizations compared with Henry Hub pricing.

Lease operating costs were $24.2 million in the third quarter of 2020, or $9.04 per boe, down 9% on a total basis and down 27% on a per unit basis compared to the second quarter. Third quarter general and administrative (“G&A”) costs totaled $4.6 million, which includes non-cash stock-based compensation. Cash G&A expense totaled $3.7 million or $1.39 per Boe in the third quarter, down 14% on a per unit basis compared to the second quarter.

Capital spending for the third quarter was $43.8 million, made up of $27.7 million of organic drilling and completion (“D&C”) capital and $16.1 million of total acquisition spending and other items, inclusive of ground game D&C spending. Northern added 3.4 net wells to production in the third quarter, and wells in process increased to 28.3 net wells, up 1.6 net wells from the prior quarter. On the ground game acquisition front, Northern closed on 10 transactions during the third quarter totaling 4.6 net wells, 653 net mineral acres and 141 net royalty acres (standardized to a 1/8 royalty interest).

On November 2, 2020, Northern’s borrowing base under its revolving credit facility was reaffirmed at $660 million. As of November 6, 2020, Northern has $550.0 million of borrowings outstanding on its revolving credit facility, with $110.0 million of current borrowing capacity. Northern expects an additional $15 - 30 million reduction in borrowings under the revolving credit facility by the end of 2020, but will continue to defer payment of any dividends on its Perpetual Preferred Stock due to the current environment.

As of September 30, 2020, Northern had $1.8 million in cash and $571.0 million of borrowings outstanding on its revolving credit facility. Northern had total liquidity of $90.8 million as of September 30, 2020, consisting of cash and borrowing availability under the revolving credit facility.

As of September 30, 2020, Northern had additional debt outstanding consisting of a $130.0 million 6% Senior Unsecured Note and $287.8 million of 8.5% Senior Secured Notes. During the third quarter, Northern strengthened its balance sheet through two negotiated agreements with noteholders, which resulted in $9.5 million in principal amount of the 8.5% Senior Secured Notes being retired, capturing $0.8 million in discounts to par value. In addition, Northern executed an agreement to retire approximately $7.6 million in liquidation value of its Perpetual Preferred Stock, capturing a discount to liquidation value of approximately $3.6 million.

Northern is providing WTI price based capital spending and production guidance for 2021. Northern allocates its capital budget based on rate of return. Northern’s 2021 base case is unchanged from the second quarter and predicated upon $40+ average WTI oil price for 2021. In this scenario, Northern expects total capital expenditures of $190 – $240 million and production of 37,500 – 42,500 Boe per day for 2021. A significant portion of capital allocated in this scenario would be for wells in process that would turn to sales in 2022 and beyond. If oil prices are greater than $35 but less than $40, Northern anticipates continued curtailments, limited new drilling, and the bulk of its capital going towards the completion of wells in process. If WTI prices average less than $35, Northern anticipates additional curtailments, minimal new drilling, and potentially only a portion of wells in process being completed and turned to sales. However, in scenarios where WTI averages below $40, Northern anticipates significantly higher free cash flow due to the reduced capital spending.

Northern expects to enter 2021 with nearly 9.0 net wells drilled and completed but delayed from being turned to sales. Northern conservatively projects in its base case that the bulk of its wells will be turned to sales in the second quarter through the fourth quarter in 2021. As is typical in the Williston basin, Northern expects the first quarter of 2021 to be seasonally lower than the annual range due to winter weather restrictions for the completions of new wells.

Northern hedges portions of its expected production volumes to increase the predictability of its cash flow and to help maintain a strong financial position. The following table summarizes Northern’s open crude oil commodity derivative contracts scheduled to settle after September 30, 2020.

Capitalized costs are a function of the number of net well additions during the period, and changes in wells in process from the prior year-end. Capital expenditures attributable to the increase of 2.6 in net wells in process during the nine months ended September 30, 2020 are reflected in the amounts incurred year-to-date for drilling and development capital expenditures.

As of September 30, 2020, Northern controlled leasehold of approximately 183,222 net acres primarily targeting the Bakken and Three Forks formations of the Williston Basin, and approximately 90% of this total acreage position was developed, held by production, or held by operations. As previously disclosed, Northern made its first Permian Basin acquisition in the third quarter, acquiring acreage with proposed wells in Lea County, NM.

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