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| 8-K - 8-K - NORTHERN OIL & GAS, INC. | nog-20201106.htm |
Exhibit 99.1
Northern Oil and Gas, Inc. Announces Third Quarter 2020 Results and 2021 Guidance
HIGHLIGHTS
•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
MINNEAPOLIS (BUSINESS WIRE) - November 6, 2020 - Northern Oil and Gas, Inc. (NYSE American: NOG) (“Northern”) today announced the company’s third quarter results.
MANAGEMENT COMMENTS
“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 FINANCIAL RESULTS
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.)
PRODUCTION
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.
PRICING
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.
OPERATING COSTS
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 EXPENDITURES AND ACQUISITIONS
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).
LIQUIDITY AND CAPITAL RESOURCES
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.
2021 ESTIMATED GUIDANCE RANGES
| Full Year 2021 | ||||||||||||||||||||
| Base Case $40+ WTI | $35-$40 WTI | Sub-$35 WTI | ||||||||||||||||||
| Production (Boe/day) | 37,500 - 42,500 | 32,500 - 37,500* | 27,500 - 32,500** | |||||||||||||||||
| Total Capital Expenditures | $190 - $240 million | $100 - $175 million | $50 - $100 million | |||||||||||||||||
____________
* Assumes approximately 2,500-5,000 Boe per day of production is shut-in or curtailed for low prices
** Assumes approximately 3,500-5,500 Boe per day of production is shut-in or curtailed for low prices
Northern reiterates its 2020 total capital spending and production guidance. Northern continues to closely monitor oil pricing with its operating partners to best determine the appropriate cadence to return remaining curtailments to sales.
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.
THIRD QUARTER 2020 RESULTS
The following tables set forth selected operating and financial data for the periods indicated.
| Three Months Ended September 30, | |||||||||||||||||
| 2020 | 2019 | % Change | |||||||||||||||
| Net Production: | |||||||||||||||||
| Oil (Bbl) | 2,054,847 | 3,002,789 | (32) | % | |||||||||||||
| Natural Gas and NGLs (Mcf) | 3,706,853 | 4,496,860 | (18) | % | |||||||||||||
| Total (Boe) | 2,672,656 | 3,752,266 | (29) | % | |||||||||||||
| Average Daily Production: | |||||||||||||||||
| Oil (Bbl) | 22,335 | 32,639 | (32) | % | |||||||||||||
| Natural Gas and NGLs (Mcf) | 40,292 | 48,879 | (18) | % | |||||||||||||
| Total (Boe) | 29,051 | 40,786 | (29) | % | |||||||||||||
| Average Sales Prices: | |||||||||||||||||
| Oil (per Bbl) | $ | 34.36 | $ | 50.90 | (33) | % | |||||||||||
| Effect of Gain on Settled Oil Derivatives on Average Price (per Bbl) | 21.11 | 6.12 | |||||||||||||||
| Oil Net of Settled Oil Derivatives (per Bbl) | 55.47 | 57.02 | (3) | % | |||||||||||||
| Natural Gas and NGLs (per Mcf) | 0.83 | 1.15 | (28) | % | |||||||||||||
| Effect of Gain on Settled Natural Gas Derivatives on Average Price (per Mcf) | 0.13 | — | |||||||||||||||
| Natural Gas and NGLs Net of Settled Natural Gas Derivatives (per Mcf) | 0.96 | 1.15 | (17) | % | |||||||||||||
| Realized Price on a Boe Basis Excluding Settled Commodity Derivatives | 27.57 | 42.10 | (35) | % | |||||||||||||
| Effect of Gain on Settled Commodity Derivatives on Average Price (per Boe) | 16.40 | 4.90 | |||||||||||||||
| Realized Price on a Boe Basis Including Settled Commodity Derivatives | 43.97 | 47.00 | (6) | % | |||||||||||||
| Costs and Expenses (per Boe): | |||||||||||||||||
| Production Expenses | $ | 9.04 | $ | 8.62 | 5 | % | |||||||||||
| Production Taxes | 2.60 | 4.10 | (37) | % | |||||||||||||
| General and Administrative Expenses | 1.72 | 1.12 | 54 | % | |||||||||||||
| Depletion, Depreciation, Amortization and Accretion | 11.52 | 14.81 | (22) | % | |||||||||||||
| Net Producing Wells at Period End | 468.8 | 444.0 | 6 | % | |||||||||||||
HEDGING
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.
Crude Oil Commodity Derivative Swaps(1) | ||||||||||||||||||||
| Contract Period | Volume (Bbls) | Volume (Bbls/Day) | Weighted Average Price (per Bbl) | |||||||||||||||||
| 2020: | ||||||||||||||||||||
| 4Q | 2,372,362 | 25,787 | $58.03 | |||||||||||||||||
| 2021: | ||||||||||||||||||||
| 1Q | 2,021,250 | 22,458 | $56.48 | |||||||||||||||||
| 2Q | 1,815,458 | 19,950 | $56.99 | |||||||||||||||||
| 3Q | 1,625,410 | 17,668 | $54.44 | |||||||||||||||||
| 4Q | 1,616,506 | 17,571 | $54.45 | |||||||||||||||||
| 2022: | ||||||||||||||||||||
| 1Q | 450,000 | 5,000 | $51.77 | |||||||||||||||||
| 2Q | 91,000 | 1,000 | $50.05 | |||||||||||||||||
| 3Q | 92,000 | 1,000 | $50.05 | |||||||||||||||||
| 4Q | 92,000 | 1,000 | $50.05 | |||||||||||||||||
_____________
(1)This table does not reflect additional potential hedged volumes under “swaption” contracts, which are crude oil derivative contracts entered into by Northern that give counterparties the option to extend certain current derivative contracts for additional periods. Based on current pricing, none of these swaptions would be expected to be exercised.
The following table summarizes Northern’s open natural gas commodity derivative contracts scheduled to settle after September 30, 2020.
| Natural Gas Commodity Derivative Swaps | ||||||||||||||||||||
| Contract Period | Gas (MMBTU) | Volume (MMBTU/Day) | Weighted Average Price (per Mcf) | |||||||||||||||||
| 2020: | ||||||||||||||||||||
| 4Q | 2,760,000 | 30,000 | $2.44 | |||||||||||||||||
| 2021: | ||||||||||||||||||||
| 1Q | 3,375,000 | 37,500 | $2.47 | |||||||||||||||||
| 2Q | 3,185,000 | 35,000 | $2.51 | |||||||||||||||||
| 3Q | 3,220,000 | 35,000 | $2.51 | |||||||||||||||||
| 4Q | 3,220,000 | 35,000 | $2.51 | |||||||||||||||||
| 2022: | ||||||||||||||||||||
| Q1 | 900,000 | 10,000 | $2.61 | |||||||||||||||||
| Q2 | 910,000 | 10,000 | $2.61 | |||||||||||||||||
| Q3 | 920,000 | 10,000 | $2.61 | |||||||||||||||||
| Q4 | 920,000 | 10,000 | $2.61 | |||||||||||||||||
CAPITAL EXPENDITURES & DRILLING ACTIVITY
| (In millions, except for net well data) | Three Months Ended September 30, 2020 | Nine Months Ended September 30, 2020 | ||||||||||||
| Capital Expenditures Incurred: | ||||||||||||||
| Organic Drilling and Development Capital Expenditures | $ | 27.7 | $ | 125.3 | ||||||||||
| Ground Game Drilling and Development Capital Expenditures | $ | 10.1 | $ | 24.4 | ||||||||||
| Ground Game Acquisition Capital Expenditures | $ | 5.5 | $ | 12.9 | ||||||||||
| Other | $ | 0.5 | $ | 2.4 | ||||||||||
| Net Wells Added to Production | 3.4 | 12.0 | ||||||||||||
| Net Producing Wells (Period-End) | — | 468.8 | ||||||||||||
| Net Wells in Process (Period-End) | — | 28.3 | ||||||||||||
| Increase in Wells in Process over Prior Period | 1.6 | 2.6 | ||||||||||||
| Weighted Average AFE for Wells Elected to | $7.0 million | $7.5 million | ||||||||||||
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.
ACREAGE
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.
THIRD QUARTER 2020 EARNINGS RELEASE CONFERENCE CALL
In conjunction with Northern’s release of its financial and operating results, investors, analysts and other interested parties are invited to listen to a conference call with management on Friday, November 6, 2020 at 9:00 a.m. Central Time.
Those wishing to listen to the conference call may do so via the company’s website, www.northernoil.com, or by phone as follows:
Website: https://78449.themediaframe.com/dataconf/productusers/nog/mediaframe/41688/indexl.html
Dial-In Number: (866) 373-3407 (US/Canada) and (412) 902-1037 (International)
Conference ID: 13712449 - Northern Oil and Gas, Inc. Third Quarter 2020 Earnings Call
Replay Dial-In Number: (877) 660-6853 (US/Canada) and (201) 612-7415 (International)
Replay Access Code: 13712449 - Replay will be available through November 16, 2020
UPCOMING CONFERENCE SCHEDULE
Bank of America Leveraged Finance Conference
November 30, 2020
Capital One Annual Energy Conference
December 7-8, 2020
ABOUT NORTHERN OIL AND GAS
Northern Oil and Gas, Inc. is a company with a primary strategy of investing in non-operated minority working and mineral interests in oil & gas properties, with a core area of focus in the Williston Basin Bakken and Three Forks play in North Dakota and Montana. More information about Northern Oil and Gas, Inc. can be found at www.northernoil.com.
SAFE HARBOR
This press release contains forward-looking statements regarding future events and future results that are subject to the safe harbors created under the Securities Act of 1933 (the “Securities Act”) and the Securities Exchange Act of 1934 (the “Exchange Act”). All statements other than statements of historical facts included in this release regarding Northern’s financial position, operating and financial performance, business strategy, plans and objectives of management for future operations, industry conditions, and indebtedness covenant compliance are forward-looking statements. When used in this release, forward-looking statements are generally accompanied by terms or phrases such as “estimate,” “project,” “predict,” “believe,” “expect,” “continue,” “anticipate,” “target,” “could,” “plan,” “intend,” “seek,” “goal,” “will,” “should,” “may” or other words and similar expressions that convey the uncertainty of future events or outcomes. Items contemplating or making assumptions about actual or potential future sales, market size, collaborations, and trends or operating results also constitute such forward-looking statements.
Forward-looking statements involve inherent risks and uncertainties, and important factors (many of which are beyond our company’s control) that could cause actual results to differ materially from those set forth in the forward-looking statements, including the following: the effects of the COVID-19 pandemic and related economic slowdown, changes in crude oil and natural gas prices, the pace of drilling and completions activity on Northern’s current properties, infrastructure constraints and related factors affecting Northern’s properties, ongoing legal disputes over and potential shutdown of the Dakota Access Pipeline, Northern’s ability to acquire additional development opportunities, Northern’s ability to consummate any pending acquisition transactions, other risks and uncertainties related to the closing of pending acquisition transactions, changes in Northern’s reserves estimates or the value thereof, general economic or industry conditions, nationally and/or in the communities in which Northern conducts business, changes in the interest rate environment, legislation or regulatory requirements, conditions of the securities markets, Northern’s ability to raise or access capital, changes in accounting principles, policies or guidelines, financial or political instability, health-related epidemics, acts of war or terrorism, and other economic, competitive, governmental, regulatory and technical factors affecting Northern’s operations, products and prices.
Northern has based these forward-looking statements on its current expectations and assumptions about future events. While management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond Northern’s control. Northern does not undertake any duty to update or revise any forward-looking statements, except as may be required by the federal securities laws.
CONTACT:
Mike Kelly, CFA
EVP Finance
952-476-9800
mkelly@northernoil.com
CONDENSED STATEMENTS OF OPERATIONS
(UNAUDITED)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (In thousands, except share and per share data) | 2020 | 2019 | 2020 | 2019 | |||||||||||||||||||
| Revenues | |||||||||||||||||||||||
| Oil and Gas Sales | $ | 73,680 | $ | 157,989 | $ | 224,541 | $ | 440,519 | |||||||||||||||
| Gain (Loss) on Commodity Derivatives, Net | (26,361) | 75,892 | 277,582 | (27,139) | |||||||||||||||||||
| Other Revenue | 3 | 3 | 12 | 10 | |||||||||||||||||||
| Total Revenues | 47,322 | 233,883 | 502,135 | 413,389 | |||||||||||||||||||
| Operating Expenses | |||||||||||||||||||||||
| Production Expenses | 24,159 | 32,347 | 88,132 | 83,146 | |||||||||||||||||||
| Production Taxes | 6,936 | 15,391 | 20,750 | 41,944 | |||||||||||||||||||
| General and Administrative Expense | 4,605 | 4,206 | 14,185 | 15,506 | |||||||||||||||||||
| Depletion, Depreciation, Amortization and Accretion | 30,786 | 55,566 | 129,350 | 146,791 | |||||||||||||||||||
| Impairment of Other Current Assets | — | 5,275 | — | 7,969 | |||||||||||||||||||
| Impairment Expense | 199,489 | — | 962,205 | — | |||||||||||||||||||
| Total Operating Expenses | 265,975 | 112,784 | 1,214,622 | 295,355 | |||||||||||||||||||
| Income (Loss) From Operations | (218,653) | 121,100 | (712,487) | 118,034 | |||||||||||||||||||
| Other Income (Expense) | |||||||||||||||||||||||
| Interest Expense, Net of Capitalization | (14,637) | (21,510) | (45,145) | (58,836) | |||||||||||||||||||
| Write-off of Debt Issuance Costs | (1,543) | — | (1,543) | — | |||||||||||||||||||
| Gain (Loss) on Unsettled Interest Rate Derivatives, Net | 224 | — | (1,205) | — | |||||||||||||||||||
| Gain (Loss) on Extinguishment of Debt, Net | 1,592 | — | (3,718) | (425) | |||||||||||||||||||
| Debt Exchange Derivative Gain/(Loss) | — | (23) | — | 1,390 | |||||||||||||||||||
| Contingent Consideration Loss | — | (5,262) | — | (28,633) | |||||||||||||||||||
| Other Income (Expense) | 13 | 75 | 14 | 88 | |||||||||||||||||||
| Total Other Income (Expense) | (14,351) | (26,719) | (51,597) | (86,416) | |||||||||||||||||||
| Income (Loss) Before Income Taxes | (233,004) | 94,381 | (764,084) | 31,619 | |||||||||||||||||||
| Income Tax Provision (Benefit) | — | — | (166) | — | |||||||||||||||||||
| Net Income (Loss) | $ | (233,004) | $ | 94,381 | $ | (763,918) | $ | 31,619 | |||||||||||||||
| Cumulative Preferred Stock Dividend | (3,718) | — | (10,986) | — | |||||||||||||||||||
| Net Income (Loss) Attributable to Common Shareholders | $ | (236,722) | $ | 94,381 | $ | (774,904) | $ | 31,619 | |||||||||||||||
| Net Income (Loss) Per Common Share – Basic* | $ | (5.44) | $ | 2.38 | $ | (18.53) | $ | 0.83 | |||||||||||||||
| Net Income (Loss) Per Common Share – Diluted* | $ | (5.44) | $ | 2.38 | $ | (18.53) | $ | 0.83 | |||||||||||||||
| Weighted Average Common Shares Outstanding – Basic* | 43,517,074 | 39,604,482 | 41,812,553 | 38,204,403 | |||||||||||||||||||
| Weighted Average Common Shares Outstanding – Diluted* | 43,517,074 | 39,653,070 | 41,812,553 | 38,274,426 | |||||||||||||||||||
___________
*Adjusted for the 1-for-10 reverse stock split.
CONDENSED BALANCE SHEETS
| (In thousands, except par value and share data) | September 30, 2020 | December 31, 2019 | |||||||||
| Assets | (Unaudited) | ||||||||||
| Current Assets: | |||||||||||
| Cash and Cash Equivalents | $ | 1,803 | $ | 16,068 | |||||||
| Accounts Receivable, Net | 60,067 | 108,274 | |||||||||
| Advances to Operators | 714 | 893 | |||||||||
| Prepaid Expenses and Other | 1,697 | 1,964 | |||||||||
| Derivative Instruments | 119,468 | 5,628 | |||||||||
| Income Tax Receivable | — | 210 | |||||||||
| Total Current Assets | 183,749 | 133,037 | |||||||||
| Property and Equipment: | |||||||||||
| Oil and Natural Gas Properties, Full Cost Method of Accounting | |||||||||||
| Proved | 4,344,346 | 4,178,605 | |||||||||
| Unproved | 10,328 | 11,047 | |||||||||
| Other Property and Equipment | 2,215 | 2,157 | |||||||||
| Total Property and Equipment | 4,356,889 | 4,191,809 | |||||||||
| Less – Accumulated Depreciation, Depletion and Impairment | (3,533,887) | (2,443,216) | |||||||||
| Total Property and Equipment, Net | 823,002 | 1,748,593 | |||||||||
| Derivative Instruments | 6,826 | 8,554 | |||||||||
| Deferred Income Taxes | — | 210 | |||||||||
| Acquisition Deposit | 225 | — | |||||||||
| Other Noncurrent Assets, Net | 11,722 | 15,071 | |||||||||
| Total Assets | $ | 1,025,524 | $ | 1,905,465 | |||||||
| Liabilities and Stockholders' Equity (Deficit) | |||||||||||
| Current Liabilities: | |||||||||||
| Accounts Payable | $ | 20,372 | $ | 69,395 | |||||||
| Accrued Liabilities | 70,203 | 110,374 | |||||||||
| Accrued Interest | 8,442 | 11,615 | |||||||||
| Derivative Instruments | 5,438 | 11,298 | |||||||||
| Current Portion of Long-term Debt | 65,000 | — | |||||||||
| Other Current Liabilities | 1,000 | 795 | |||||||||
| Total Current Liabilities | 170,455 | 203,477 | |||||||||
| Long-term Debt | 918,327 | 1,118,161 | |||||||||
| Derivative Instruments | 2,456 | 8,079 | |||||||||
| Asset Retirement Obligations | 17,891 | 16,759 | |||||||||
| Other Noncurrent Liabilities | 126 | 345 | |||||||||
| Total Liabilities | $ | 1,109,255 | $ | 1,346,822 | |||||||
| Commitments and Contingencies (Note 8) | |||||||||||
| Stockholders’ Equity (Deficit) | |||||||||||
Preferred Stock, Par Value $.001; 5,000,000 Shares Authorized; 2,218,732 Series A Shares Outstanding at 9/30/2020 1,500,000 Series A Shares Outstanding at 12/31/2019 | 2 | 2 | |||||||||
Common Stock, Par Value $.001; 135,000,000* Shares Authorized; 45,556,326* Shares Outstanding at 9/30/2020 40,608,518* Shares Outstanding at 12/31/2019 | 448 | 406 | |||||||||
| Additional Paid-In Capital | 1,554,053 | 1,431,438 | |||||||||
| Retained Deficit | (1,638,234) | (873,203) | |||||||||
| Total Stockholders’ Equity (Deficit) | (83,731) | 558,643 | |||||||||
| Total Liabilities and Stockholders’ Equity (Deficit) | $ | 1,025,524 | $ | 1,905,465 | |||||||
__________
*Adjusted for the 1-for-10 reverse stock split.
Non-GAAP Financial Measures
Adjusted Net Income and Adjusted EBITDA are non-GAAP measures. Northern defines Adjusted Net Income (Loss) as net income (loss) excluding (i) (gain) loss on unsettled commodity derivatives, net of tax, (ii) (gain) loss on extinguishment of debt, net of tax, (iii) debt exchange derivative (gain) loss, net of tax, (iv) contingent consideration loss, net of tax, (v) acquisition transaction costs, net of tax, (vi) impairment of other current assets, net of tax, (vii) impairment expense, net of tax, (viii) (gain) loss on unsettled interest rate derivatives, net of tax, and (ix) write-off of debt issuance costs, net of tax. Northern defines Adjusted EBITDA as net income (loss) before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion, amortization and accretion, (iv) non-cash stock-based compensation expense, (v) (gain) loss on extinguishment of debt, (vi) debt exchange derivative (gain) loss, (vii) contingent consideration loss, (viii) (gain) loss on unsettled commodity derivatives, (ix) (gain) loss on unsettled interest rate derivatives, (x) impairment of other current assets, (xi) impairment expense, and (xii) write-off of debt issuance costs. A reconciliation of each of these measures to the most directly comparable GAAP measure is included below. Where references are pro forma, forward-looking or prospective in nature, and not based on historical fact, the table does not provide a reconciliation. Northern could not provide such reconciliation without undue hardship because such Adjusted EBITDA numbers are estimations, approximations and/or ranges. In addition, it would be difficult for Northern to present a detailed reconciliation on account of many unknown variables for the reconciling items, including without limitation future income taxes, full-cost ceiling impairments, and unrealized gains or losses on commodity derivatives. For the same reasons, Northern is unable to address the probable significance of the unavailable information, which could be material to future results.
Management believes the use of these non-GAAP financial measures provides useful information to investors to gain an overall understanding of current financial performance. Specifically, management believes the non-GAAP financial measures included herein provide useful information to both management and investors by excluding certain expenses and unrealized commodity gains and losses that management believes are not indicative of Northern’s core operating results. In addition, these non-GAAP financial measures are used by management for budgeting and forecasting as well as subsequently measuring Northern’s performance, and management believes it is providing investors with financial measures that most closely align to its internal measurement processes.
Reconciliation of Adjusted Net Income
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (In thousands, except share and per share data) | 2020 | 2019 | 2020 | 2019 | |||||||||||||||||||
| Net Income (Loss) | $ | (233,004) | $ | 94,381 | $ | (763,918) | $ | 31,619 | |||||||||||||||
| Add: | |||||||||||||||||||||||
| Impact of Selected Items: | |||||||||||||||||||||||
| (Gain) Loss on Unsettled Commodity Derivatives | 70,198 | (57,506) | (124,800) | 62,806 | |||||||||||||||||||
| Impairment of Other Current Assets | — | 5,275 | — | 7,969 | |||||||||||||||||||
| Write-off of Debt Issuance Costs | 1,543 | — | 1,543 | — | |||||||||||||||||||
| (Gain) Loss on Extinguishment of Debt | (1,592) | — | 3,718 | 425 | |||||||||||||||||||
| Debt Exchange Derivative (Gain) Loss | — | 23 | — | (1,390) | |||||||||||||||||||
| Contingent Consideration Loss | — | 5,262 | — | 28,633 | |||||||||||||||||||
| Acquisition Transaction Costs | — | 1,250 | — | 1,763 | |||||||||||||||||||
| (Gain) Loss on Unsettled Interest Rate Derivatives | (224) | — | 1,205 | — | |||||||||||||||||||
| Impairment Expense | 199,489 | — | 962,205 | — | |||||||||||||||||||
| Selected Items, Before Income Taxes | 269,414 | (45,696) | 843,871 | 100,204 | |||||||||||||||||||
Income Tax of Selected Items(1) | (8,920) | (12,380) | (19,588) | (32,401) | |||||||||||||||||||
| Selected Items, Net of Income Taxes | 260,494 | (58,077) | 824,283 | 67,803 | |||||||||||||||||||
| Adjusted Net Income | $ | 27,490 | $ | 36,304 | $ | 60,365 | $ | 99,422 | |||||||||||||||
| Weighted Average Shares Outstanding – Basic | 43,517,074 | 39,604,482 | 41,812,553 | 38,204,403 | |||||||||||||||||||
| Weighted Average Shares Outstanding – Diluted | 53,582,333 | 39,653,070 | 51,707,412 | 38,274,426 | |||||||||||||||||||
| Net Income (Loss) Per Common Share – Basic | $ | (5.35) | $ | 2.38 | $ | (18.27) | $ | 0.83 | |||||||||||||||
| Add: | |||||||||||||||||||||||
| Impact of Selected Items, Net of Income Taxes | 5.98 | (1.46) | 19.71 | 1.77 | |||||||||||||||||||
| Adjusted Net Income Per Common Share – Basic | $ | 0.63 | $ | 0.92 | $ | 1.44 | $ | 2.60 | |||||||||||||||
| Net Income (Loss) Per Common Share – Diluted | $ | (4.35) | $ | 2.38 | $ | (14.77) | $ | 0.83 | |||||||||||||||
| Add: | |||||||||||||||||||||||
| Impact of Selected Items, Net of Income Taxes | 4.86 | (1.46) | 15.94 | 1.77 | |||||||||||||||||||
| Adjusted Net Income Per Common Share – Diluted | $ | 0.51 | $ | 0.92 | $ | 1.17 | $ | 2.60 | |||||||||||||||
______________
(1)For the three and nine months ended September 30, 2020, this represents a tax impact using an estimated tax rate of 24.5%, which includes an adjustment of $57.1 million and $187.2 million, respectively, for a change in valuation allowance. For the three and nine months ended September 30, 2019, this represents a tax impact using an estimated tax rate of 24.5%, which includes an adjustment of $23.6 million and $7.9 million, respectively, for a change in valuation allowance.
Reconciliation of Adjusted EBITDA
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (In thousands) | 2020 | 2019 | 2020 | 2019 | |||||||||||||||||||
| Net Income (Loss) | $ | (233,004) | $ | 94,381 | $ | (763,918) | $ | 31,619 | |||||||||||||||
| Add: | |||||||||||||||||||||||
| Interest Expense | 14,637 | 21,510 | 45,145 | 58,836 | |||||||||||||||||||
| Income Tax Provision (Benefit) | — | — | (166) | — | |||||||||||||||||||
| Depreciation, Depletion, Amortization and Accretion | 30,786 | 55,566 | 129,350 | 146,791 | |||||||||||||||||||
| Impairment of Other Current Assets | — | 5,275 | — | 7,969 | |||||||||||||||||||
| Non-Cash Stock-Based Compensation | 890 | (114) | 3,183 | 4,280 | |||||||||||||||||||
| Write-off of Debt Issuance Costs | 1,543 | — | 1,543 | — | |||||||||||||||||||
| (Gain) Loss on Extinguishment of Debt | (1,592) | — | 3,718 | 425 | |||||||||||||||||||
| Debt Exchange Derivative (Gain) Loss | — | 23 | — | (1,390) | |||||||||||||||||||
| Contingent Consideration Loss | — | 5,262 | — | 28,633 | |||||||||||||||||||
| (Gain) Loss on Unsettled Interest Rate Derivatives | (224) | — | 1,205 | — | |||||||||||||||||||
| (Gain) Loss on Unsettled Commodity Derivatives | 70,198 | (57,506) | (124,800) | 62,806 | |||||||||||||||||||
| Impairment Expense | 199,489 | — | 962,205 | — | |||||||||||||||||||
| Adjusted EBITDA | $ | 82,723 | $ | 124,396 | $ | 257,465 | $ | 339,968 | |||||||||||||||