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| 8-K - 8-K - NORTHERN OIL & GAS, INC. | a8k-march2020earningsr.htm |
Exhibit 99.1
Northern Oil and Gas, Inc. Announces Fourth Quarter and Full Year 2019 Results
HIGHLIGHTS
•Fourth quarter production increased 8% over the third quarter, averaging a record 43,941 barrels of oil equivalent (“Boe”) per day. Production approximated the midpoint of guidance despite higher than forecasted curtailments
•Full year 2019 production increased 51% over 2018, averaging 38,604 Boe per day
•Fourth quarter capital expenditures of $134.6 million, including $45.3 million in ground game and associated D&C capital
•2019 year-end proved reserves of 163.3 million Boe, up 21% from 2018 year-end
•Senior Secured Notes balance reduced to $341.0 million as of March 10, 2020, down from $695.1 million at 2018 year-end
•Revolving Credit Facility borrowing base increased to $800 million, from $425 million
•2020 oil production expected to be over 75% hedged at $58 per barrel (“Bbl”) average price in the current environment
•2020 capital expenditures anticipated at approximately $200 million in the current environment, down over 55% vs. 2019
•2020 free cash flow projected to be significant even assuming $30 per barrel WTI price
•Due to current macro environment, Northern delaying decision on commencing common stock dividend and will reassess in the second quarter
MINNEAPOLIS (BUSINESS WIRE) - March 12, 2020 - Northern Oil and Gas, Inc. (NYSE American: NOG) (“Northern”) today announced the company’s fourth quarter and full year 2019 results.
MANAGEMENT COMMENTS
“2019 was another transformational year in terms of scaling our business and the consummation of our plan driven to reduce interest expense and increase capital flexibility,” commented Nick O’Grady, Northern’s Chief Executive Officer. “We enter into 2020 already delivering on those goals regardless of current depressed commodity prices. Continued weak commodity pricing will create even more opportunity for Northern, given our strong oil price hedge book, balance sheet, and free cash flow profile.”
“As we move into 2020, we will adhere to our strict hurdle rates necessary to deploy capital,” commented Adam Dirlam, Northern’s Chief Operating Officer. “While the current macro environment is undoubtedly challenging, we are optimistic that it will also provide opportunities specific to Northern’s business model as a minority working interest owner to invest capital into value accretive projects for the benefit of our shareholders.”
FOURTH QUARTER AND FULL YEAR FINANCIAL RESULTS
FINANCIAL RESULTS
Fourth quarter net loss was $107.9 million or $0.27 per diluted share. Fourth quarter Adjusted Net Income was $21.5 million or $0.05 per diluted share, down from $94.8 million or $0.25 per diluted share in the prior year. Adjusted EBITDA in the fourth quarter was $114.2 million compared to $124.9 million in the fourth quarter of 2018, driven by 14% lower average realized prices and higher lease operating expense, offset partially by a 21% increase in production volumes.
Full year 2019 net loss was $76.3 million or $0.20 per diluted share. Full year 2019 Adjusted Net Income was $120.9 million or $0.31 per diluted share, down from $140.7 million or $0.59 per diluted share in 2018. Full year 2019 Adjusted EBITDA was $454.2 million compared to $349.3 million in 2018. Average realized prices were down approximately 9% year over year, offset by a 51% increase in production volumes. (See “Non-GAAP Financial Measures” below.)
PRODUCTION
Fourth quarter production increased 21% from the prior year and 8% from the prior quarter to 4.0 million Boe or 43,941 Boe per day, toward the middle of the guidance range. Shut-ins and curtailments, which Northern had forecasted would be approximately 2,400 barrels per day in the fourth quarter, were significantly higher at approximately 3,650 barrels per day. Strong fourth quarter well performance largely offset the negative impact from shut-ins. Full year 2019 production increased 51% from 2018 to 14.1 million Boe or 38,604 Boe per day.
PRICING
During the fourth quarter, NYMEX West Texas Intermediate (“WTI”) crude oil averaged $56.85 per Bbl, and NYMEX natural gas at Henry Hub averaged $2.40 per million cubic feet (“Mcf”). Northern’s unhedged net realized oil price in the fourth quarter was $49.20, representing a $7.65 differential to WTI prices. For the year, Northern’s realized oil differential was $6.28 per Bbl, within the stated guidance range. Northern’s fourth quarter unhedged net realized gas price was $0.47 per Mcf, representing approximately 20% realizations compared with Henry Hub pricing. For the year, Northern’s realized gas price was $1.60, which was 63% of the average Henry Hub price.
OPERATING AND G&A COSTS
Unit LOE costs came in slightly higher quarter over quarter, at $8.84 per Boe, which was driven by higher than expected curtailments as well as higher work over expense. Fourth quarter general and administrative (“G&A”) costs totaled $8.1 million, including stock-based compensation. Fourth quarter cash G&A expenses of $4.4 million included $0.8 million of costs related to the departure of Northern’s former chief executive officer. Excluding these amounts, cash G&A costs were approximately $3.6 million, or $0.91 per Boe.
CAPITAL EXPENDITURES
Capital spending for the fourth quarter was $134.6 million, made up of $85.6 million of organic D&C capital and $45.3 million of total acquisition and other spending, inclusive of ground game D&C spending. Northern added 14.6 net wells to production in the fourth quarter, approximately 2.0 net wells above guidance. These additional net well additions came online in late December and had a minimal impact on fourth quarter production. In addition, Northern’s wells in process rose to 25.8 net wells, up over 1.5 wells from the prior quarter. The accelerated development, driven by rising pricing in the fourth quarter, was the primary driver of Northern’s higher than forecast capital spending. On the ground game acquisition front, Northern closed on 14 transactions and committed to an additional nine during the fourth quarter. The majority of fourth quarter commitments that were not closed during 2019 will be closed in the first quarter, after which, Northern expects ground game activity to moderate significantly in 2020 as it moves to cash harvesting.
LIQUIDITY AND CAPITAL RESOURCES
As of December 31, 2019, Northern had $16.1 million in cash and $580.0 million outstanding on its revolving credit facility. Northern had total liquidity of $236.1 million as of December 31, 2019, consisting of cash and $220.0 million of borrowing availability under the revolving credit facility. Total debt net of cash was reduced by $31.9 during the fourth quarter.
As of December 31, 2019, Northern had additional debt outstanding consisting of a $130.0 million Senior Unsecured Note due 2022 and $417.7 million of Senior Secured Notes due 2023.
As previously announced, in the fourth quarter of 2019, Northern completed a consent solicitation, exchange, subscription, and partial tender process. Northern issued 1,500,000 shares of newly issued 6.50% Perpetual Cumulative Convertible Preferred Stock (“Preferred Stock”), and retired $270.8 million of its 8.5% Senior Secured Notes due 2023. Northern also expanded its senior secured revolving credit facility from $425 million to $800 million and extended the term one year to November 2024. The terms of these transactions served, among other things, to improve hedging flexibility, modify certain covenants in the Senior Secured Notes to allow for expanded restricted payments, and substantially reduce interest expense.
Also as previously announced, in January 2020, Northern executed on additional transactions to further reduce debt. In aggregate, Northern retired an additional $76.7 million of Senior Secured Notes for 794,702 shares of Preferred Stock and $2.5 million in cash. The current outstanding principal amount on the Senior Secured Notes as of March 10, 2020 is $341.0 million.
PROVED RESERVES AS OF DECEMBER 31, 2019
SEC Pricing Proved Reserves(1) | ||||||||||||||||||||||||||||||||||||||
| Reserve Volumes | PV-10(3) | |||||||||||||||||||||||||||||||||||||
| Reserve Category | Oil (MBbls) | Natural Gas (MMcf) | Total (MBoe)(2) | % | Amount (In thousands) | % | ||||||||||||||||||||||||||||||||
| PDP Properties | 71,276 | 109,503 | 89,527 | 55 | % | $ | 1,251,429 | 69 | % | |||||||||||||||||||||||||||||
| PDNP Properties | 5,884 | 7,342 | 7,107 | 4 | 109,093 | 6 | ||||||||||||||||||||||||||||||||
| PUD Properties | 54,594 | 72,473 | 66,673 | 41 | 461,502 | 25 | ||||||||||||||||||||||||||||||||
| Total | 131,754 | 189,318 | 163,307 | 100 | % | $ | 1,822,024 | 100 | % | |||||||||||||||||||||||||||||
_____ ___________
(1)The SEC Pricing Proved Reserves table above values oil and natural gas reserve quantities and related discounted future net cash flows as of December 31, 2019 based on average prices of $55.69 per barrel of oil and $2.58 per MMbtu of natural gas. Under SEC guidelines, these prices represent the average prices per barrel of oil and per MMbtu of natural gas at the beginning of each month in the 12-month period prior to the end of the reporting period. The average resulting price used as of December 31, 2019, after adjustment to reflect applicable transportation and quality differentials, was $50.53 per barrel of oil and $2.12 per Mcf of natural gas.
(2) Boe are computed based on a conversion ratio of one Boe for each barrel of oil and one Boe for every 6,000 cubic feet (i.e., 6 Mcf) of natural gas.
(3) Pre-tax PV10%, or “PV-10,” may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP measure. See “Non-GAAP Financial Measures” below.
2020 GUIDANCE COMMENTARY
Given the rapid deterioration and volatility in commodity prices, Northern has elected to defer its formal 2020 guidance. At the latest, Northern will provide this on its first quarter conference call. Assuming oil prices remain under $40 per Bbl for the majority of 2020, Northern anticipates a total capital budget of approximately $200 million, which represents more than a 55% decrease year-over-year. In this scenario Northern would expect to have more than 75% of its oil production hedged at an average price above $58 per Bbl. This capital plan, and the likely production range associated with it, would likely deliver even higher levels of free cash flow for 2020 than Northern’s previously anticipated $45-50 WTI base plan. Additionally, in an environment where uncertainty prevails and preserving capital is a priority, Northern is delaying its decision on commencing a common stock dividend and will reassess in the second quarter.
FOURTH QUARTER 2019 RESULTS
The following table sets forth selected operating and financial data for the periods indicated.
| Three Months Ended December 31, | |||||||||||||||||
| 2019 | 2018 | % Change | |||||||||||||||
| Net Production: | |||||||||||||||||
| Oil (Bbl) | 3,218,885 | 2,745,700 | 17 | % | |||||||||||||
| Natural Gas and NGLs (Mcf) | 4,942,194 | 3,540,439 | 40 | % | |||||||||||||
| Total (Boe) | 4,042,584 | 3,335,773 | 21 | % | |||||||||||||
| Average Daily Production: | |||||||||||||||||
| Oil (Bbl) | 34,988 | 29,845 | 17 | % | |||||||||||||
| Natural Gas and NGL (Mcf) | 53,720 | 38,483 | 40 | % | |||||||||||||
| Total (Boe) | 43,941 | 36,258 | 21 | % | |||||||||||||
| Average Sales Prices: | |||||||||||||||||
| Oil (per Bbl) | $ | 49.20 | $ | 49.15 | — | % | |||||||||||
| Effect of Gain on Settled Derivatives on Average Price (per Bbl) | 2.71 | 3.80 | |||||||||||||||
| Oil Net of Settled Derivatives (per Bbl) | 51.91 | 52.95 | (2) | % | |||||||||||||
| Natural Gas and NGLs (per Mcf) | 0.47 | 4.97 | (91) | % | |||||||||||||
| Realized Price on a Boe Basis Including all Realized Derivative Settlements | 41.91 | 48.86 | (14) | % | |||||||||||||
| Costs and Expenses (per Boe): | |||||||||||||||||
| Production Expenses | $ | 8.84 | $ | 6.43 | 37 | % | |||||||||||
| Production Taxes | 3.92 | 4.10 | (4) | % | |||||||||||||
| General and Administrative Expense | 2.01 | 1.49 | 35 | % | |||||||||||||
| Depletion, Depreciation, Amortization and Accretion | 15.69 | 14.48 | 8 | % | |||||||||||||
| Net Producing Wells at Period End | 458.7 | 325.1 | 41 | % | |||||||||||||
FULL YEAR 2019 RESULTS
The following table sets forth selected operating and financial data for the periods indicated.
| Years Ended December 31, | |||||||||||||||||
| 2019 | 2018 | % Change | |||||||||||||||
| Net Production: | |||||||||||||||||
| Oil (Bbl) | 11,325,418 | 7,790,182 | 45 | % | |||||||||||||
| Natural Gas and NGLs (Mcf) | 16,590,774 | 9,224,766 | 80 | % | |||||||||||||
| Total (Boe) | 14,090,547 | 9,327,643 | 51 | % | |||||||||||||
| Average Daily Production: | |||||||||||||||||
| Oil (Bbl) | 31,029 | 21,343 | 45 | % | |||||||||||||
| Natural Gas and NGL (Mcf) | 45,454 | 25,273 | 80 | % | |||||||||||||
| Total (Boe) | 38,604 | 25,555 | 51 | % | |||||||||||||
| Average Sales Prices: | |||||||||||||||||
| Oil (per Bbl) | $ | 50.74 | $ | 57.78 | (12) | % | |||||||||||
| Effect of Gain (Loss) on Settled Derivatives on Average Price (per Bbl) | 3.92 | (2.94) | |||||||||||||||
| Oil Net of Settled Derivatives (per Bbl) | 54.66 | 54.84 | — | % | |||||||||||||
| Natural Gas and NGLs (per Mcf) | 1.60 | 4.74 | (66) | % | |||||||||||||
| Realized Price on a Boe Basis Including all Realized Derivative Settlements | 45.82 | 50.50 | (9) | % | |||||||||||||
| Costs and Expenses (per Boe): | |||||||||||||||||
| Production Expenses | $ | 8.44 | $ | 7.15 | 18 | % | |||||||||||
| Production Taxes | 4.10 | 4.86 | (16) | % | |||||||||||||
| General and Administrative Expenses | 1.68 | 1.56 | 8 | % | |||||||||||||
| Depletion, Depreciation, Amortization and Accretion | 14.92 | 12.84 | 16 | % | |||||||||||||
| Net Producing Wells at Period-End | 458.7 | 325.1 | 41 | % | |||||||||||||
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 derivative contracts scheduled to settle after December 31, 2019.
| Crude Oil Derivative Price Swaps | |||||||||||
| Contract Period | Volume (Bbls) | Weighted Average Price (per Bbl) | |||||||||
| 2020: | |||||||||||
| 1Q | 2,664,356 | $57.93 | |||||||||
| 2Q | 2,568,278 | $57.67 | |||||||||
| 3Q | 2,501,348 | $58.47 | |||||||||
| 4Q | 2,372,362 | $58.03 | |||||||||
2021(1): | |||||||||||
| 1Q | 1,712,550 | $56.74 | |||||||||
| 2Q | 1,610,708 | $57.24 | |||||||||
| 3Q | 1,418,410 | $54.35 | |||||||||
| 4Q | 1,409,506 | $54.37 | |||||||||
2022(2): | |||||||||||
| 1Q | 453,780 | $53.07 | |||||||||
| 2Q | 312,280 | $52.30 | |||||||||
| 3Q | 306,576 | $52.33 | |||||||||
| 4Q | 300,230 | $52.35 | |||||||||
_____________
(1)We have entered into crude oil derivative contracts that give counterparties the option to extend certain current derivative contracts for additional periods. Options covering a notional volume of 0.3 million barrels for 2021 are exercisable on or about December 31, 2020. If the counterparties exercise all such options, the notional volume of our existing crude oil derivative contracts will increase as follows for 2021: (i) for the first quarter of 2021, by 112,500 barrels at a weighted average price of $57.78 per barrel, (ii) for the second quarter of 2021, by 113,750 barrels at a weighted average price of $57.78 per barrel, (iii) for the third quarter of 2021, by 46,000 barrels at a weighted average price of $58.00 per barrel, and (iv) for the fourth quarter of 2021, by 46,000 barrels at a weighted average price of $58.00 per barrel.
(2)We have entered into crude oil derivative contracts that give counterparties the option to extend certain current derivative contracts for additional periods. Options covering a notional volume of 2.4 million barrels for 2022 are exercisable on or about December 31, 2021. If the counterparties exercise all such options, the notional volume of our existing crude oil derivative contracts will increase as follows for 2022: (i) for the first quarter of 2022, by 830,250 barrels at a weighted average price of $55.01 per barrel, (ii) for the second quarter of 2022, by 839,475 barrels at a weighted average price of $55.01 per barrel, (iii) for the third quarter of 2022, by 365,700 barrels at a weighted average price of $55.15 per barrel, and (iv) for the fourth quarter of 2022, by 365,700 barrels at a weighted average price of $55.15 per barrel.
CAPITAL EXPENDITURES & DRILLING ACTIVITY
| Fourth Quarter 2019 | Full Year 2019 | |||||||||||||
| Capital Expenditures Incurred: | ||||||||||||||
| Organic Drilling and Development Capital Expenditures | $85.6 million | $313.6 million | ||||||||||||
| Ground Game Drilling and Development Capital Expenditures | $40.5 million | $77.5 million | ||||||||||||
| Ground Game Acquisition Capital Expenditures | $4.8 million | $29.8 million | ||||||||||||
| Acquisition of Oil and Natural Gas Properties and Other | $3.7 million | $333.0 million | ||||||||||||
| Net Organic Wells Added to Production | 14.6 | 43.0 | ||||||||||||
| Net Producing Wells (Period-End) | 458.7 | |||||||||||||
| Net Wells in Process (Period-End) | 25.8 | |||||||||||||
| Increase in Wells in Process over Prior Period | 1.5 | 3.0 | ||||||||||||
| Weighted Average AFE for Wells Elected to Year-to-Date | $8.1 million | $8.0 million | ||||||||||||
Capitalized costs are a function of the number of net well additions during the period as well as changes in wells in process from beginning to end of period. Capital expenditures attributable to the 1.5 and 3.0 increase in net wells in process for the fourth quarter and year, respectively, are reflected in the amounts included for “Drilling and Development Capital Expenditures” in the table above.
ACREAGE
As of December 31, 2019, Northern controlled leasehold of approximately 182,854 net acres targeting the Williston Basin Bakken and Three Forks formations, and approximately 91% of its total acreage position was developed, held by production or held by operations.
FOURTH QUARTER 2019 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 Thursday, March 12, 2020 at 10:00 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:
Dial-In Number: (866) 373-3407 (US/Canada) and (412) 902-1037 (International)
Conference ID: 13699346 - Northern Oil and Gas, Inc. Fourth Quarter and Year-End 2019 Earnings Call
Replay Dial-In Number: (877) 660-6853 (US/Canada) and (201) 612-7415 (International)
Replay Access Code: 13699346 - Replay will be available through March 19, 2020
UPCOMING CONFERENCE SCHEDULE
32nd Annual Roth Conference
March 15 - 17, 2020, Laguna Niquel, CA. (Now Virtual)
48th Annual Scotia Howard Weil Energy Conference
March 23 - 26, 2020, New Orleans, LA (Now Virtual)
IPAA OGIS New York
April 20-21, 2020, New York, NY
UBS Global Oil and Gas Conference
May 18-20, 2020, Dallas, TX
RBC Global Energy and Power Executive Conference
June 2-3, 2020, New York, NY
ABOUT NORTHERN OIL AND GAS
Northern Oil and Gas, Inc. is an exploration and production company 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, 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: changes in crude oil and natural gas prices, the pace of drilling and completions activity on Northern’s properties, Northern’s ability to acquire additional development opportunities, 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, acts of war or terrorism, and other economic, competitive, governmental, regulatory and technical factors affecting our company’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
NORTHERN OIL AND GAS, INC.
STATEMENTS OF OPERATIONS
Three Months Ended December 31, | Years Ended December 31, | ||||||||||||||||||||||
| (In thousands, except share and per share data) | 2019 | 2018 | 2019 | 2018 | |||||||||||||||||||
| REVENUES | |||||||||||||||||||||||
| Oil and Gas Sales | $ | 160,698 | $ | 152,566 | $ | 601,218 | $ | 493,909 | |||||||||||||||
| Gain (Loss) on Derivative Instruments, Net | (101,697) | 290,628 | (128,837) | 185,006 | |||||||||||||||||||
| Other Revenue | 11 | 2 | 21 | 9 | |||||||||||||||||||
| Total Revenues | 59,012 | 443,196 | 472,402 | 678,924 | |||||||||||||||||||
| OPERATING EXPENSES | |||||||||||||||||||||||
| Production Expenses | 35,754 | 21,448 | 118,899 | 66,646 | |||||||||||||||||||
| Production Taxes | 15,827 | 13,669 | 57,771 | 45,302 | |||||||||||||||||||
| General and Administrative Expenses | 8,118 | 4,976 | 23,624 | 14,568 | |||||||||||||||||||
| Depletion, Depreciation, Amortization and Accretion | 63,411 | 48,295 | 210,201 | 119,780 | |||||||||||||||||||
| Impairment of Other Current Assets | (1,571) | — | 6,398 | — | |||||||||||||||||||
| Total Expenses | 121,539 | 88,388 | 416,893 | 246,296 | |||||||||||||||||||
| INCOME (LOSS) FROM OPERATIONS | (62,527) | 354,808 | 55,509 | 432,628 | |||||||||||||||||||
| OTHER INCOME (EXPENSE) | |||||||||||||||||||||||
| Interest Expense, Net of Capitalization | (20,393) | (20,057) | (79,229) | (86,005) | |||||||||||||||||||
| Loss on the Extinguishment of Debt | (22,762) | (73,055) | (23,187) | (173,430) | |||||||||||||||||||
| Debt Exchange Derivative Gain (Loss) | — | (13,661) | 1,390 | (598) | |||||||||||||||||||
| Contingent Consideration Loss | (879) | (28,968) | (29,512) | (28,968) | |||||||||||||||||||
| Financing Expense | (1,447) | (884) | (1,447) | (884) | |||||||||||||||||||
| Other Income | 69 | 53 | 158 | 891 | |||||||||||||||||||
| Total Other Income (Expense) | (45,412) | (136,572) | (131,827) | (288,994) | |||||||||||||||||||
| INCOME (LOSS) BEFORE INCOME TAXES | (107,939) | 218,236 | (76,318) | 143,634 | |||||||||||||||||||
| INCOME TAX BENEFIT | — | (55) | — | (55) | |||||||||||||||||||
| NET INCOME (LOSS) | $ | (107,939) | $ | 218,291 | (76,318) | $ | 143,689 | ||||||||||||||||
| Net Income (Loss) Per Common Share – Basic | $ | (0.27) | $ | 0.58 | $ | (0.20) | $ | 0.61 | |||||||||||||||
| Net Income (Loss) Per Common Share – Diluted | $ | (0.27) | $ | 0.58 | $ | (0.20) | $ | 0.61 | |||||||||||||||
| Weighted Average Shares Outstanding – Basic | 402,042,034 | 378,799,871 | 387,084,651 | 236,206,457 | |||||||||||||||||||
| Weighted Average Shares Outstanding – Diluted | 402,042,034 | 379,401,105 | 387,084,651 | 236,773,911 | |||||||||||||||||||
NORTHERN OIL AND GAS, INC.
BALANCE SHEETS
| (In thousands, except par value and share data) | December 31, 2019 | December 31, 2018 | |||||||||
| ASSETS | |||||||||||
| Current Assets: | |||||||||||
| Cash and Cash Equivalents | $ | 16,068 | $ | 2,358 | |||||||
| Accounts Receivable, Net | 108,274 | 96,353 | |||||||||
| Advances to Operators | 893 | 268 | |||||||||
| Prepaid Expenses and Other | 1,964 | 12,361 | |||||||||
| Derivative Instruments | 5,628 | 115,870 | |||||||||
| Income Tax Receivable | 210 | 1,205 | |||||||||
| Total Current Assets | 133,037 | 228,415 | |||||||||
| Property and Equipment: | |||||||||||
| Oil and Natural Gas Properties, Full Cost Method of Accounting | |||||||||||
| Proved | 4,178,605 | 3,431,428 | |||||||||
| Unproved | 11,047 | 4,307 | |||||||||
| Other Property and Equipment | 2,157 | 997 | |||||||||
| Total Property and Equipment | 4,191,809 | 3,436,732 | |||||||||
| Less – Accumulated Depreciation, Depletion and Impairment | (2,443,216) | (2,233,987) | |||||||||
| Total Property and Equipment, Net | 1,748,593 | 1,202,745 | |||||||||
| Derivative Instruments | 8,554 | 61,843 | |||||||||
| Deferred Income Taxes | 210 | 420 | |||||||||
| Other Noncurrent Assets, Net | 15,071 | 10,222 | |||||||||
| Total Assets | $ | 1,905,465 | $ | 1,503,645 | |||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||||||
| Current Liabilities: | |||||||||||
| Accounts Payable | $ | 69,395 | $ | 55,015 | |||||||
| Accrued Liabilities | 110,374 | 83,237 | |||||||||
| Accrued Interest | 11,615 | 16,468 | |||||||||
| Debt Exchange Derivative | — | 18,183 | |||||||||
| Derivative Instruments | 11,298 | — | |||||||||
| Contingent Consideration | — | 58,069 | |||||||||
| Asset Retirement Obligations | 795 | 554 | |||||||||
| Total Current Liabilities | 203,477 | 231,526 | |||||||||
| Long-term Debt, Net | 1,118,161 | 830,203 | |||||||||
| Derivative Instruments | 8,079 | — | |||||||||
| Asset Retirement Obligations | 16,759 | 11,946 | |||||||||
| Other Noncurrent Liabilities | 345 | 105 | |||||||||
| TOTAL LIABILITIES | 1,346,822 | 1,073,780 | |||||||||
| COMMITMENTS AND CONTINGENCIES | |||||||||||
| STOCKHOLDERS’ EQUITY | |||||||||||
| Preferred Stock, Par Value $.001; 5,000,000 Authorized (12/31/2019 – 1,500,000 Shares Outstanding and 12/31/2018 – No Shares Outstanding) | 2 | — | |||||||||
| Common Stock, Par Value $.001; 675,000,000 Authorized (12/31/2019 – 406,085,183 Shares Outstanding and 12/31/2018 – 378,333,070 Shares Outstanding) | 406 | 378 | |||||||||
| Additional Paid-In Capital | 1,431,438 | 1,226,371 | |||||||||
| Retained Deficit | (873,203) | (796,884) | |||||||||
| Total Stockholders’ Equity | 558,643 | 429,865 | |||||||||
| TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY | $ | 1,905,465 | $ | 1,503,645 | |||||||
Non-GAAP Financial Measures
Adjusted Net Income and Adjusted EBITDA are non-GAAP measures. Net income (loss) is the most directly comparable GAAP measure for both Adjusted Net Income and Adjusted EBITDA, and tabular reconciliations for these measures are included below. Northern defines Adjusted Net Income (Loss) as net income (loss) excluding (i) unrealized (gain) loss on derivatives, net of tax, (ii) financing expense, net of tax, (iii) impairment of other current assets, net of tax, (iv) loss on the extinguishment of debt, net of tax, (v) debt exchange derivative (gain) loss, net of tax, (vi) contingent consideration loss, net of tax, and (vii) acquisition transaction 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) impairment of other current assets, (v) non-cash stock based compensation expense, (vi) loss on the extinguishment of debt, (vii) debt exchange derivative (gain) loss (viii) contingent consideration loss, (ix) cash severance expense, (x) financing expense, and (xi) unrealized (gain) loss on derivatives. A reconciliation of each of these measures to the most directly comparable GAAP measure is included below. 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 items 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.
Pre-tax PV10%, or PV-10, may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP measure for proved reserves calculated using SEC pricing. PV-10 is a computation of the Standardized Measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the Standardized Measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. Management believes that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to Northern’s estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of Northern’s oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of Northern’s reserves to other companies. Management uses this measure when assessing the potential return on investment related to Northern’s oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure of discounted future net cash flows. A reconciliation of PV-10 to the Standardized Measure is included below.
Reconciliation of Adjusted Net Income
Three Months Ended December 31, | Years Ended December 31, | ||||||||||||||||||||||
| (In thousands, except share and per share data) | 2019 | 2018 | 2019 | 2018 | |||||||||||||||||||
| Net Income (Loss) | $ | (107,937) | $ | 218,292 | $ | (76,318) | $ | 143,689 | |||||||||||||||
| Add: | |||||||||||||||||||||||
| Impact of Selected Items: | |||||||||||||||||||||||
| Unrealized (Gain) Loss on Derivatives | 110,408 | (280,195) | 173,214 | (207,892) | |||||||||||||||||||
| Financing Expense | 1,447 | 884 | 1,447 | 884 | |||||||||||||||||||
| Impairment of Other Current Assets | (1,571) | — | 6,398 | — | |||||||||||||||||||
| Loss on the Extinguishment of Debt | 22,762 | 73,055 | 23,187 | 173,430 | |||||||||||||||||||
| Debt Exchange Derivative (Gain) Loss | — | 13,661 | (1,390) | 598 | |||||||||||||||||||
| Contingent Consideration Loss | 879 | 28,968 | 29,512 | 28,968 | |||||||||||||||||||
| Acquisition Transaction Costs | — | — | 1,763 | — | |||||||||||||||||||
| Selected Items, Before Income Taxes | 133,925 | (163,627) | 234,130 | (4,012) | |||||||||||||||||||
| Income Tax of Selected Items(1) | (4,497) | 40,089 | (36,898) | 983 | |||||||||||||||||||
| Selected Items, Net of Income Taxes | 129,429 | (123,538) | 197,232 | (3,029) | |||||||||||||||||||
| Adjusted Net Income | $ | 21,492 | $ | 94,754 | $ | 120,914 | $ | 140,660 | |||||||||||||||
| Weighted Average Shares Outstanding – Basic | 402,042,034 | 378,799,871 | 387,084,651 | 236,206,457 | |||||||||||||||||||
| Weighted Average Shares Outstanding – Diluted | 430,565,265 | 379,401,105 | 394,805,513 | 236,773,911 | |||||||||||||||||||
| Net Income (Loss) Per Common Share – Basic | $ | (0.27) | $ | 0.58 | $ | (0.20) | $ | 0.61 | |||||||||||||||
| Add: | |||||||||||||||||||||||
| Impact of Selected Items, Net of Income Taxes | 0.32 | (0.33) | 0.51 | (0.01) | |||||||||||||||||||
| Adjusted Net Income Per Common Share – Basic | $ | 0.05 | $ | 0.25 | $ | 0.31 | $ | 0.60 | |||||||||||||||
| Net Income (Loss) Per Common Share – Diluted | $ | (0.25) | $ | 0.58 | $ | (0.19) | $ | 0.61 | |||||||||||||||
| Add: | |||||||||||||||||||||||
| Impact of Selected Items, Net of Income Taxes | 0.30 | (0.33) | 0.50 | (0.02) | |||||||||||||||||||
| Adjusted Net Income Per Common Share – Diluted | $ | 0.05 | $ | 0.25 | $ | 0.31 | $ | 0.59 | |||||||||||||||
_______________
(1)For the 2019 columns, this represents a tax impact using an estimated tax rate of 24.5% for the three and twelve months ended December 31, 2019 and includes an adjustment of $28.3 million and $20.5 million, respectively, for changes in our valuation allowance. For the 2018 columns, this represents a tax impact using an estimated tax rate of 24.5% for the three and twelve months ended December 31, 2018 and does not include any adjustments for changes in our valuation allowance.
Reconciliation of Adjusted EBITDA
Three Months Ended December 31, | Years Ended December 31, | ||||||||||||||||||||||
| 2019 | 2018 | 2019 | 2018 | ||||||||||||||||||||
| (in thousands) | |||||||||||||||||||||||
| Net Income (Loss) | $ | (107,937) | $ | 218,292 | $ | (76,318) | $ | 143,689 | |||||||||||||||
| Add: | |||||||||||||||||||||||
| Interest Expense | 20,393 | 20,057 | 79,229 | 86,005 | |||||||||||||||||||
| Income Tax Provision (Benefit) | — | (55) | — | (55) | |||||||||||||||||||
| Depreciation, Depletion, Amortization and Accretion | 63,411 | 48,295 | 210,201 | 119,780 | |||||||||||||||||||
| Impairment of Other Current Assets | (1,571) | — | 6,398 | — | |||||||||||||||||||
| Non-Cash Stock-Based Compensation | 3,674 | 1,903 | 7,955 | 3,876 | |||||||||||||||||||
| Loss on the Extinguishment of Debt | 22,762 | 73,055 | 23,187 | 173,430 | |||||||||||||||||||
| Debt Exchange Derivative (Gain) Loss | — | 13,661 | (1,390) | 598 | |||||||||||||||||||
| Contingent Consideration Loss | 879 | 28,968 | 29,512 | 28,968 | |||||||||||||||||||
| Financing Expense | 1,447 | 884 | 1,447 | 884 | |||||||||||||||||||
| Cash Severance Expense | 759 | — | 759 | — | |||||||||||||||||||
| Unrealized (Gain) Loss on Derivatives | 110,408 | (280,195) | 173,214 | (207,892) | |||||||||||||||||||
| Adjusted EBITDA | $ | 114,225 | $ | 124,865 | $ | 454,193 | $ | 349,283 | |||||||||||||||
Reconciliation of PV-10
The following table reconciles the PV-10 value of our SEC Pricing Proved Reserves as of December 31, 2019 to the Standardized Measure of discounted future net cash flows.
SEC Pricing Proved Reserves (In thousands) | |||||
| Standardized Measure Reconciliation | |||||
| Pre-Tax Present Value of Estimated Future Net Revenues (Pre-Tax PV10%) | $ | 1,822,024 | |||
Future Income Taxes, Discounted at 10%(1) | (143,964) | ||||
| Standardized Measure of Discounted Future Net Cash Flows | $ | 1,678,060 | |||
____________
(1)The expected tax benefits to be realized from utilization of the net operating loss and tax credit carryforwards are used in the computation of future income tax cash flows. As a result of available net operating loss carryforwards and the remaining tax basis of our assets at December 31, 2019, our future income taxes were reduced.