8-K
NORTHERN OIL & GAS, INC. (NOG)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): February 19, 2025
NORTHERN OIL AND GAS, INC.
(Exact name of Registrant as specified in its charter)
| Delaware | 001-33999 | 95-3848122 |
|---|---|---|
| (State or other jurisdiction<br><br>of incorporation) | (Commission File Number) | (IRS Employer<br><br>Identification No.) |
| 4350 Baker Road, Suite 400<br><br>Minnetonka, Minnesota | 55343 | |
| --- | --- | |
| (Address of principal executive offices) | (Zip Code) |
Registrant’s telephone number, including area code (952) 476-9800
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
☐ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
☐ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17CFR 240.14a-12)
☐ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
☐ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered |
|---|---|---|
| Common Stock, par value $0.001 | NOG | New York Stock Exchange |
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).
Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Item 2.02. Results of Operations and Financial Condition.
On February 19, 2025, Northern Oil and Gas, Inc. issued a press release announcing 2024 fourth quarter and full year financial and operating results. A copy of the press release is furnished as Exhibit 99.1 hereto.
Item 9.01. Financial Statements and Exhibits.
(d) Exhibits.
| Exhibit Number | Description |
|---|---|
| 99.1 | Press release of Northern Oil and Gas, Inc., dated February 19, 2025 |
| 104 | The cover page from this Current Report on Form 8-K, formatted in inline XBRL |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned hereunto duly authorized.
| Date: February 19, 2025 | NORTHERN OIL AND GAS, INC.<br><br>By /s/ Erik J. Romslo<br><br>Erik J. Romslo<br><br>Chief Legal Officer and Secretary |
|---|
Document
Exhibit 99.1
NOG Announces Fourth Quarter and Full Year 2024 Results; Provides Detailed 2025 Guidance
FOURTH QUARTER HIGHLIGHTS
•Production of 131,777 Boe per day (59.9% oil), a 15% increase from the fourth quarter of the prior year
•GAAP cash flow from operations of $290.3 million. Excluding changes in net working capital, cash flow from operations was $358.9 million
•Capital expenditures of $258.9 million, excluding previously-announced non-budgeted acquisitions and other items
•Free Cash Flow (non-GAAP) was $96.4 million in the fourth quarter. See “Non-GAAP Financial Measures” below
•Closed previously announced acquisition of Uinta Basin assets from XCL Resources, LLC (“XCL”) on October 1, 2024 for $511.3 million in cash
•Declared $0.45 per share common dividend for the first quarter of 2025, an increase of 12.5% from the first quarter of 2024
•Repurchased 693,658 shares of common stock at an average price of $36.28 per share
SUBSEQUENT EVENTS
•In February 2025, signed definitive agreement to acquire 2,275 net acres in Upton County, TX in Midland Basin joint development with a private operating partner for an unadjusted purchase price of $40 million.
MINNEAPOLIS (BUSINESS WIRE) - February 19, 2025 - Northern Oil and Gas, Inc. (NYSE: NOG) (“NOG”) today announced the company’s fourth quarter and full year 2024 results and provided 2025 guidance.
MANAGEMENT COMMENTS
“NOG continues to raise the bar, delivering another year of cash flow, production and reserve growth, strategic investments in high-value assets, and the deliberate expansion of our internal infrastructure—all reinforcing our long-term ability to create shareholder value,” commented Nick O’Grady, NOG’s Chief Executive Officer.
Mr. O’Grady continued, “Building on the strong foundation laid in 2024, we have meticulously crafted a 2025 capital plan designed to drive growth in 2025, 2026 and beyond. We expect to execute a record number of SPUDs, building momentum throughout the year. Our diversified model positions NOG with substantial external opportunities to create additional value, further solidifying our commitment to delivering both top-tier relative and absolute returns.”
FINANCIAL RESULTS
Oil and natural gas sales for the fourth quarter were $545.5 million, as compared to $543.4 million for the prior year period. Fourth quarter GAAP net income was $71.7 million or $0.71 per diluted share. Fourth quarter Adjusted Net Income was $111.8 million or $1.11 per adjusted diluted share. Adjusted EBITDA in the fourth quarter was $406.6 million.
Oil and natural gas sales for full year 2024 were $2.2 billion. Full year 2024 GAAP net income was $520.3 million or $5.14 per diluted share. Full year 2024 Adjusted Net Income was $531.2 million or $5.26 per adjusted diluted share. Full year 2024 Adjusted EBITDA was $1.6 billion, an increase of 13% over the prior year. (See “Non-GAAP Financial Measures” below.)
PRODUCTION
Fourth quarter production was 131,777 Boe per day, a 15% increase from the prior year period. Oil production was a record 78,939 Bbl per day, an 11% sequential increase over the third quarter, and represented 59.9% of production in the fourth quarter. NOG had 25.8 net wells turned in line during the fourth quarter, compared to 9.5 net wells turned in line in the third quarter of 2024. NOG’s fourth quarter benefited from a full contribution of the Point acquisition as well as the contribution from the XCL acquisition and an increase in turn-in-line activity, offset by shut-ins and disruptions from forest fires, curtailments and numerous deferrals on completed wells from price-sensitive private operators in the Williston Basin, as well as material downtime from third-party crude takeaway in the Uinta Basin. Full year 2024 production was 124,108 Boe per day, a 26% increase from the prior year.
PRICING
During the fourth quarter, NYMEX West Texas Intermediate (“WTI”) crude oil averaged $70.32 per Bbl, and NYMEX natural gas at Henry Hub averaged $2.98 per Mcf. NOG’s unhedged net realized oil price in the fourth quarter was $65.40 per Bbl, representing a $3.86 differential to WTI prices (as adjusted). NOG’s fourth quarter unhedged net realized gas price was $2.42
per Mcf, representing approximately 81% realizations compared with Henry Hub pricing. In the fourth quarter, overall oil differentials were largely in-line with prior periods, with the higher average takeaway costs in the Uinta Basin increasing NOG’s corporate average modestly. Natural gas realizations benefited from a slight quarter-over-quarter improvement in pricing and a seasonal uplift in NGL prices due to winter demand. The Company also benefited from seasonally stronger natural gas differentials in Appalachia.
For full year 2024, NOG’s realized oil price differential was $3.88 per Bbl (as adjusted). NOG’s full year unhedged net realized gas price was $2.24 per Mcf, representing approximately 93% realizations compared with Henry Hub pricing.
OPERATING COSTS
Lease operating costs were $116.6 million in the fourth quarter of 2024, or $9.62 per Boe, a 1% increase on a per unit basis compared to the third quarter. The increase in unit costs was primarily driven by fixed cost absorption from the wildfires and deferrals in the Williston which was partially offset by lower operating costs from our Uinta Basin properties.
Fourth quarter general and administrative (“G&A”) costs totaled $15.5 million, which includes non-cash stock-based compensation. Cash G&A costs totaled $12.0 million or $0.99 per Boe in the fourth quarter. Excluding approximately $0.8 million of transaction costs, remaining cash G&A was $11.2 million, or $0.93 per Boe.
CAPITAL EXPENDITURES
Capital spending for the fourth quarter, excluding non-budgeted acquisitions and other items, was $258.9 million. This was comprised of $197.3 million of organic drilling and completion (“D&C”) capital and $61.6 million of total acquisition spending, inclusive of ground game D&C spending. NOG had 25.8 net wells turned in line in the fourth quarter. Wells in process totaled 50.4 net wells as of December 31, 2024. Total 2024 capital expenditures, excluding non-budgeted acquisitions were $990.1 million, above expectations driven by significant ground game opportunities executed and continued elevated workover activity.
LIQUIDITY, CAPITAL RESOURCES AND RECENT ACQUISITIONS
As of December 31, 2024, NOG had $8.9 million in cash and $690.0 million of borrowings outstanding on its revolving credit facility. NOG had total liquidity of $818.9 million as of December 31, 2024, consisting of cash and committed borrowing availability under the revolving credit facility.
On October 2, 2024, NOG announced the closing of its acquisition of Uinta Basin assets from XCL Resources, LLC (“XCL”) The closing included the assets previously owned by Altamont Energy, LLC (“Altamont”). These transactions provide NOG with over a decade of Tier 1 inventory across ~15,800 net acres in the Uinta Basin with ~116 net underwritten undeveloped locations and additional exploration upside potential. At closing, NOG paid $511.3 million in cash. The closing settlement included the purchase of the Altamont assets. NOG jointly acquired the assets with SM Energy, Inc. (“SM”), which will become the operator of substantially all the assets. In connection with the transaction, NOG and SM entered into cooperation and long-term joint development agreements.
On February 11, 2025, NOG entered into a definitive agreement to acquire assets in Upton County, TX with one of NOG’s existing private operating partners for an unadjusted purchase price of $40 million in cash, subject to customary closing adjustments. These assets include approximately 2,275 net acres in the Midland Basin. NOG has entered into a joint development agreement on the properties. The Company expects to close the transaction within 60 days. The obligations of the parties to complete the transactions contemplated by the purchase agreement are subject to the satisfaction or waiver of customary closing conditions. The associated 2025 development costs post-closing for these assets have been included in NOG’s initial capital expenditure guidance.
SHAREHOLDER RETURNS
In November 2024, NOG’s Board of Directors declared a regular quarterly cash dividend for NOG’s common stock of $0.42 per share for stockholders of record as of December 30, 2024, which was paid on January 31, 2025. In January 2025, NOG’s Board of Directors declared a regular quarterly cash dividend for NOG’s common stock of $0.45 per share for stockholders of record as of March 28, 2025, which will be paid on April 30, 2025.
In the fourth quarter of 2024, NOG repurchased 693,658 shares of its common stock in the fourth quarter at a weighted average price of $36.28 per share, inclusive of commissions. In 2024, the Company repurchased a total of 2,535,391 shares at a weighted average price of $37.27, inclusive of commissions. In total, the Company delivered nearly $260 million in shareholder returns to investors for 2024 comprised of share repurchases and dividends.
2025 ANNUAL GUIDANCE
NOG anticipates approximately 130,000 - 135,000 Boe per day of production in 2025. NOG currently expects total capital spending in the range of $1,050 - $1,200 million for 2025, with approximately 66% of its 2025 budget to be spent on the Permian, 20% on the Williston, 7% on the Appalachian and 7% on the Uinta.
| 2025 Guidance | |
|---|---|
| Annual Production (Boe per day) | 130,000 - 135,000 |
| Annual Oil Production (Bbls per day) | 75,000 - 79,000 |
| Total Capital Expenditures ($ in millions) | $1,050 - $1,200 |
| Net Wells Turned-in-Line | 87.0 - 91.0 |
| Net Wells Spud | 106.0 - 110.0 |
| Operating Expenses and Differentials | |
| --- | --- |
| Production Expenses (per Boe) | $9.15 - $9.40 |
| Production Taxes (as a percentage of Oil & Gas Sales) | 8.5% - 9.0% |
| Average Differential to NYMEX WTI (per Bbl) | ($4.75) - ($5.50) |
| Average Realization as a Percentage of NYMEX Henry Hub (per Mcf) | 85% - 90% |
| DD&A (per Boe) | $16.50 - $17.50 |
| General and Administrative Expense (per Boe): | |
| --- | --- |
| Non-Cash | $0.25 - $0.30 |
| Cash (excluding transaction costs on non-budgeted acquisitions) | $0.85 - $0.90 |
PROVED RESERVES AS OF DECEMBER 31, 2024
Total proved reserves at December 31, 2024, increased 11% from year-end 2023 to 378.5 million barrels of oil equivalent (73% proved developed) with an associated pre-tax PV-10 value of $5.1 billion (80% proved developed) at SEC Pricing. The reserves are calculated under SEC guidelines relating to both commodity price assumptions and a maximum five year drill schedule. See “Non-GAAP Financial Measures” below regarding PV-10 value.
| SEC Pricing Proved Reserves(1) | |||||||
|---|---|---|---|---|---|---|---|
| Reserve Volumes | PV-10(3) | ||||||
| Reserve Category | Oil<br>(MBbls) | Natural Gas<br>(MMcf) | Total<br><br>(MBoe)(2) | % | Amount<br>(In thousands) | % | |
| PDP Properties | 128,508 | 728,333 | 249,897 | 66 | $ | 3,791,530 | 75 |
| PDNP Properties | 7,049 | 127,227 | 28,254 | 7 | 259,341 | 5 | |
| PUD Properties | 59,554 | 244,677 | 100,333 | 27 | 1,018,980 | 20 | |
| Total | 195,111 | 1,100,237 | 378,484 | 100 | $ | 5,069,851 | 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, 2024, based on average prices of $75.48 per barrel of oil and $2.13 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, 2024, after adjustment to reflect applicable transportation and quality differentials, was $70.60 per barrel of oil and $2.02 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. See “Non-GAAP Financial Measures” below.
FOURTH QUARTER 2024 RESULTS
The following table sets forth selected operating and financial data for the periods indicated.
| Three Months Ended <br>December 31, | ||||||
|---|---|---|---|---|---|---|
| 2024 | 2023 | % Change | ||||
| Net Production: | ||||||
| Oil (MBbl) | 7,262 | 6,336 | 15 | % | ||
| Natural Gas (MMcf) | 29,167 | 25,111 | 16 | % | ||
| Total (MBoe) | 12,123 | 10,521 | 15 | % | ||
| Average Daily Production: | ||||||
| Oil (MBbl) | 79 | 69 | 15 | % | ||
| Natural Gas (MMcf) | 317 | 273 | 16 | % | ||
| Total (MBoe) | 132 | 114 | 15 | % | ||
| Average Sales Prices: | ||||||
| Oil (per Bbl) | $ | 65.40 | $ | 74.51 | (12) | % |
| Effect of Loss on Settled Derivatives on Average Price (per Bbl) | 2.17 | (0.85) | ||||
| Oil Net of Settled Derivatives (per Bbl) | 67.57 | 73.66 | (8) | % | ||
| Natural Gas and NGLs (per Mcf) | $ | 2.42 | $ | 2.84 | (15) | % |
| Effect of Gain (Loss) on Settled Derivatives on Average Price (per Mcf) | 0.33 | 0.68 | ||||
| Natural Gas Net of Settled Derivatives (per Mcf) | 2.75 | 3.52 | (22) | % | ||
| Realized Price on a Boe Basis Excluding Settled Commodity Derivatives | $ | 44.99 | $ | 51.65 | (13) | % |
| Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Boe) | 2.10 | 1.12 | ||||
| Realized Price on a Boe Basis Including Settled Commodity Derivatives | 47.09 | 52.77 | (11) | % | ||
| Costs and Expenses (per Boe): | ||||||
| Production Expenses | $ | 9.62 | $ | 9.70 | (1) | % |
| Production Taxes | 3.52 | 4.36 | (19) | % | ||
| General and Administrative Expense | 1.28 | 0.91 | 41 | % | ||
| Depletion, Depreciation, Amortization and Accretion | 16.88 | 14.37 | 17 | % | ||
| Net Producing Wells at Period End | 1,108.0 | 951.6 | 16 | % |
FULL YEAR 2024 RESULTS
The following table sets forth selected operating and financial data for the periods indicated.
| Years Ended December 31, | ||||||
|---|---|---|---|---|---|---|
| 2024 | 2023 | % Change | ||||
| Net Production: | ||||||
| Oil (MBbl) | 26,511 | 22,013 | 20 | % | ||
| Natural Gas (MMcf) | 113,476 | 84,342 | 35 | % | ||
| Total (MBoe) | 45,423 | 36,070 | 26 | % | ||
| Average Daily Production (in thousands): | ||||||
| Oil (MBbl) | 72 | 60 | 20 | % | ||
| Natural Gas (MMcf) | 310 | 231 | 34 | % | ||
| Total (Boe) | 124 | 99 | 26 | % | ||
| Average Sales Prices: | ||||||
| Oil (per Bbl) | $ | 71.59 | $ | 74.78 | (4) | % |
| Effect of Loss on Settled Oil Derivatives on Average Price (per Bbl) | (0.11) | (0.90) | ||||
| Oil, Net of Settled Oil Derivatives (per Bbl) | 71.48 | 73.88 | (3) | % | ||
| Natural Gas and NGLs (per Mcf) | 2.24 | 2.98 | (25) | % | ||
| Effect of Gain on Settled Natural Gas Derivatives on Average Price (per Mcf) | 0.76 | 0.92 | ||||
| Natural Gas and NGLs, Net of Settled Natural Gas and NGL Derivatives (per Mcf) | 3.00 | 3.90 | (23) | % | ||
| Realized Price on a Boe Basis Excluding Settled Commodity Derivatives | 47.38 | 52.61 | (10) | % | ||
| Effect of Gain on Settled Commodity Derivatives on Average Price (per Boe) | 1.83 | 1.61 | ||||
| Realized Price on a Boe Basis Including Settled Commodity Derivatives | 49.21 | 54.22 | (9) | % | ||
| Costs and Expenses (per Boe): | ||||||
| Production Expenses | $ | 9.46 | $ | 9.62 | (2) | % |
| Production Taxes | 3.46 | 4.44 | (22) | % | ||
| General and Administrative Expenses | 1.11 | 1.30 | (15) | % | ||
| Depletion, Depreciation, Amortization and Accretion | 16.31 | 13.47 | 21 | % | ||
| Net Producing Wells at Period-End | 1,108.0 | 951.6 | 16 | % |
HEDGING
NOG 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 NOG’s open crude oil commodity derivative swap contracts scheduled to settle after December 31, 2024.
| Crude Oil Commodity Derivative Swaps(1) | Crude Oil Commodity Derivative Collars and Puts | |||||
|---|---|---|---|---|---|---|
| Contract Period | Volume (Bbls/Day) | Weighted Average Price ($/Bbl) | Collar Call Volume (Bbls/Day) | Weighted Average Collar Call Prices <br>($/Bbl) | Collar Put Volume (Bbls/Day) | Weighted Average Collar Put Prices<br>($/Bbl) |
| 2025(1): | ||||||
| Q1 | 32,791 | $74.82 | 25,592 | $78.25 | 20,998 | $69.68 |
| Q2 | 29,623 | $74.57 | 27,502 | $77.45 | 22,189 | $69.41 |
| Q3 | 26,413 | $73.62 | 25,054 | $77.43 | 19,761 | $69.15 |
| Q4 | 28,433 | $73.34 | 24,766 | $77.55 | 19,473 | $69.15 |
| 2026(1): | ||||||
| Q1 | 5,430 | $71.79 | 17,230 | $74.75 | 12,437 | $66.42 |
| Q2 | 2,930 | $70.31 | 14,730 | $74.41 | 9,937 | $66.15 |
| Q3 | 2,930 | $70.24 | 14,730 | $74.41 | 9,937 | $66.15 |
| Q4 | 2,930 | $70.15 | 14,730 | $74.41 | 9,937 | $66.15 |
_____________
(1)Includes derivative contracts entered into through February 18, 2025. This table does not include volumes subject to swaptions and call options, which are crude oil derivative contracts NOG has entered into which may increase swapped volumes at the option of NOG’s counterparties. This table also does not include basis swaps. For additional information, see Note 11 to our financial statements included in our Form 10-K filed with the SEC for the year ended December 31, 2024.
The following table summarizes NOG’s open natural gas commodity derivative swap contracts scheduled to settle after December 31, 2024.
| Natural Gas Commodity Derivative Swaps(1) | Natural Gas Commodity Derivative Collars | |||||
|---|---|---|---|---|---|---|
| Contract Period | Volume <br>(MMBTU/Day) | Weighted Average Price ($/MMBTU) | Collar Call Volume<br>(MMBTU/Day) | Weighted Average Collar Call Prices ($/MMBTU) | Collar Put Volume <br>(MMBTU/Day) | Weighted Average Collar Put Prices ($/MMBTU) |
| 2025(1): | ||||||
| Q1 | 74,167 | $3.45 | 113,738 | $4.98 | 113,738 | $3.12 |
| Q2 | 40,495 | $3.53 | 111,553 | $4.71 | 111,553 | $3.13 |
| Q3 | 51,685 | $3.68 | 106,387 | $4.74 | 106,387 | $3.13 |
| Q4 | 51,576 | $3.82 | 97,812 | $4.85 | 97,812 | $3.14 |
| 2026(1): | ||||||
| Q1 | 41,222 | $4.00 | 74,647 | $5.02 | 74,647 | $3.16 |
| Q2 | 33,681 | $3.80 | 76,315 | $5.02 | 76,315 | $3.16 |
| Q3 | 30,000 | $3.88 | 75,486 | $5.02 | 75,486 | $3.16 |
| Q4 | 21,522 | $3.86 | 53,420 | $4.94 | 53,420 | $3.15 |
| 2027(1): | ||||||
| Q1 | 1,722 | $3.20 | 9,889 | $3.83 | 9,889 | $3.00 |
| Q2 | — | — | 10,110 | $3.83 | 10,110 | $3.00 |
| Q3 | — | — | 10,000 | $3.83 | 10,000 | $3.00 |
| Q4 | — | — | 6,630 | $3.83 | 6,630 | $3.00 |
_____________
(1)Includes derivative contracts entered into through February 18, 2025. This table does not include volumes subject to swaptions and call options, which are natural gas derivative contracts NOG has entered into which may increase swapped volumes at the option of NOG’s counterparties. This table also does not include basis swaps. For additional information, see Note 11 to our financial statements included in our Form 10-K filed with the SEC for the year ended December 31, 2024.
The following table summarizes NOG’s open NGL commodity derivative swap contracts scheduled to settle after December 31, 2024.
| NGL Contracts | ||
|---|---|---|
| Swaps | ||
| Contract Period | Volume<br>(BBL) | Weighted Average Price (/BBL) |
| 2025: | ||
| Q1 | — | |
| Q2 | 4,550 | 37.03 |
| Q3 | 29,900 | 36.39 |
| Q4 | 66,700 | 36.75 |
| 2026: | ||
| Q1 | 92,250 | |
| Q2 | 106,925 | 33.32 |
| Q3 | 96,600 | 33.03 |
| Q4 | 80,500 | 33.32 |
| 2027: | ||
| Q1 | 65,250 | |
| Q2 | 59,150 | 30.73 |
| Q3 | 57,500 | 30.69 |
| Q4 | 52,900 | 30.87 |
All values are in US Dollars.
The following table presents NOG’s settlements on commodity derivative instruments and unsettled gains and losses on open commodity derivative instruments for the periods presented, which is included in the revenue section of NOG’s statement of operations:
| Three Months Ended<br><br>December 31, | Twelve Months Ended<br><br>December 31, | |||||||
|---|---|---|---|---|---|---|---|---|
| (In thousands) | 2024 | 2023 | 2024 | 2023 | ||||
| Cash Received on Settled Derivatives | $ | 25,504 | $ | 11,820 | $ | 83,225 | $ | 57,919 |
| Non-Cash Mark-to-Market Gain (Loss) on Derivatives | (59,728) | 235,553 | (21,258) | 201,331 | ||||
| Gain (Loss) on Commodity Derivatives, Net | $ | (34,224) | $ | 247,373 | $ | 61,967 | $ | 259,250 |
CAPITAL EXPENDITURES & DRILLING ACTIVITY
| (In millions, except for net well data) | Three Months Ended December 31, 2024 | Year Ended December 31, 2024 |
|---|---|---|
| Capital Expenditures Incurred: | ||
| Organic Drilling and Development Capital Expenditures | $197.3 | $862.3 |
| Ground Game Drilling and Development Capital Expenditures | $34.4 | $74.7 |
| Ground Game Acquisition Capital Expenditures | $27.2 | $53.1 |
| Other | $3.5 | $11.2 |
| Non-Budgeted Acquisitions | $539.8 | $883.5 |
| Net Wells Turned In Line | 25.8 | 90.7 |
| Net Producing Wells (Period-End) | 1,108.0 | 1,108.0 |
| Net Wells in Process (Period-End) | 50.4 | 50.4 |
| Change in Wells in Process over Prior Period | (1.9) | (16.1) |
| Weighted Average AFE for Wells Elected to | $10.1 | $9.4 |
Capitalized costs reflect ongoing development activities and are primarily influenced by the number of net wells-in-process additions and net well turn-in-lines during the reporting period. Additionally, capital can be incurred via workover activity for enhancement of existing producing wells.
FOURTH QUARTER 2024 EARNINGS RELEASE CONFERENCE CALL
In conjunction with NOG’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, February 20, 2025 at 8:00 a.m. Central Time.
Those wishing to listen to the conference call may do so via the company’s website, www.noginc.com, or by phone as follows:
Webcast: https://events.q4inc.com/attendee/150317474
Dial-In Number: (800) 715-9871 (US/Canada) and (646) 307-1963 (International)
Conference ID: 4503139 - Fourth Quarter and Year-End 2024 Earnings Conference Call
Replay Dial-In Number: (800) 770-2030 (US/Canada) and (647) 362-9199 (International)
Replay Access Code: 4503139 - Replay will be available through March 8, 2024
ABOUT NORTHERN OIL AND GAS
NOG is a real asset company with a primary strategy of acquiring and investing in non-operated minority working and mineral interests in the premier hydrocarbon producing basins within the contiguous United States. More information about NOG can be found at www.noginc.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 NOG’s financial position, operating and financial performance, business strategy, dividend plans and practices, 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 production and 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 NOG’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 NOG’s current properties and properties pending acquisition, infrastructure constraints and related factors affecting NOG’s properties; cost inflation or supply chain disruptions, ongoing legal disputes over and potential shutdown of the Dakota Access Pipeline; NOG’s ability to acquire additional development opportunities, potential or pending acquisition transactions, the projected capital efficiency savings and other operating efficiencies and synergies resulting from NOG’s acquisition transactions, integration and benefits of property acquisitions, or the effects of such acquisitions on NOG’s cash position and levels of indebtedness; changes in NOG’s reserves estimates or the value thereof, disruption to NOG’s business due to acquisitions and other significant transactions; general economic or industry conditions, nationally and/or in the communities in which NOG conducts business; changes in the interest rate environment, legislation or regulatory requirements; conditions of the securities markets; risks associated with NOG’s Convertible Notes, including the potential impact that the Convertible Notes may have NOG’s financial position and liquidity, potential dilution, and that provisions of the Convertible Notes could delay or prevent a beneficial takeover of NOG; the potential impact of the capped call transaction undertaken in tandem with the Convertible Notes issuance, including counterparty risk; increasing attention to environmental, social and governance matters; NOG’s ability to consummate any pending acquisition transactions; other risks and uncertainties related to the closing of pending acquisition transactions; NOG’s ability to raise or access capital; cyber-incidents could have a material adverse effect NOG’s business, financial condition or results of operations; changes in accounting principles, policies or guidelines; events beyond NOG’s control, including a global or domestic health crisis, acts of terrorism, political or economic instability or armed conflict in oil and gas producing regions; and other economic, competitive, governmental, regulatory and technical factors affecting NOG’s operations, products and prices. Additional information concerning potential factors that could affect future results is included in the section entitled “Item 1A. Risk Factors” and other sections of NOG’s more recent Annual Report on Form 10-K and Quarterly Report on Form 10-Q, as updated from time to time in amendments and subsequent reports filed with the SEC, which describe factors that could cause NOG’s actual results to differ from those set forth in the forward-looking statements.
NOG 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 NOG’s control. NOG does not undertake any duty to update or revise any forward-looking statements, except as may be required by the federal securities laws.
CONTACT:
Evelyn Infurna
Vice President of Investor Relations
952-476-9800
ir@northernoil.com
Source: Northern Oil and Gas, Inc.
NORTHERN OIL AND GAS, INC.
STATEMENTS OF OPERATIONS
| Three Months Ended<br>December 31, | Year Ended<br>December 31, | |||||||
|---|---|---|---|---|---|---|---|---|
| (In thousands, except share and per share data) | 2024 | 2023 | 2024 | 2023 | ||||
| Revenues | ||||||||
| Oil and Gas Sales | $ | 545,472 | $ | 543,403 | $ | 2,152,079 | $ | 1,897,779 |
| Gain (Loss) on Commodity Derivatives, Net | (34,224) | 247,373 | 61,967 | 259,250 | ||||
| Other Revenue | 3,729 | 2,741 | 11,682 | 9,230 | ||||
| Total Revenues | 514,977 | 793,517 | 2,225,728 | 2,166,259 | ||||
| Operating Expenses | ||||||||
| Production Expenses | 116,583 | 102,061 | 429,792 | 347,006 | ||||
| Production Taxes | 42,621 | 45,903 | 157,091 | 160,118 | ||||
| General and Administrative Expenses | 15,528 | 9,553 | 50,463 | 46,801 | ||||
| Depletion, Depreciation, Amortization and Accretion | 204,674 | 151,188 | 740,901 | 486,024 | ||||
| Other Expenses | 2,937 | 768 | 9,650 | 4,448 | ||||
| Total Operating Expenses | 382,343 | 309,473 | 1,387,897 | 1,044,397 | ||||
| Income From Operations | 132,634 | 484,044 | 837,831 | 1,121,862 | ||||
| Other Income (Expense) | ||||||||
| Interest Expense, Net of Capitalization | (45,259) | (36,513) | (157,717) | (135,664) | ||||
| Gain (Loss) on Interest Rate Derivatives, Net | 283 | — | 263 | (1,017) | ||||
| Gain on the Extinguishment of Debt, Net | — | — | — | 659 | ||||
| Contingent Consideration Gain | — | — | — | 10,107 | ||||
| Other Income | 180 | 83 | 440 | 4,795 | ||||
| Total Other Income (Expense) | (44,796) | (36,430) | (157,014) | (121,120) | ||||
| Income Before Income Taxes | 87,838 | 447,614 | 680,817 | 1,000,742 | ||||
| Income Tax Expense | 16,140 | 58,761 | 160,509 | 77,773 | ||||
| Net Income Attributable to Common Shareholders | $ | 71,698 | $ | 388,853 | $ | 520,308 | $ | 922,969 |
| Net Income Per Common Share – Basic | $ | 0.72 | $ | 3.92 | $ | 5.21 | $ | 10.09 |
| Net Income Per Common Share – Diluted | $ | 0.71 | $ | 3.90 | $ | 5.14 | $ | 10.03 |
| Weighted Average Common Shares Outstanding – Basic | 99,217,821 | 99,278,050 | 99,852,539 | 91,483,687 | ||||
| Weighted Average Common Shares Outstanding – Diluted | 100,934,410 | 99,814,411 | 101,267,625 | 92,060,947 |
NORTHERN OIL AND GAS, INC.
BALANCE SHEETS
| (In thousands, except par value and share data) | December 31, 2024 | December 31, 2023 | ||
|---|---|---|---|---|
| Assets | ||||
| Current Assets: | ||||
| Cash and Cash Equivalents | $ | 8,933 | $ | 8,195 |
| Accounts Receivable, Net | 389,673 | 370,531 | ||
| Advances to Operators | 12,291 | 49,210 | ||
| Prepaid Expenses and Other | 5,271 | 2,489 | ||
| Derivative Instruments | 46,525 | 75,733 | ||
| Income Tax Receivable | 38,050 | 3,249 | ||
| Total Current Assets | 500,743 | 509,407 | ||
| Property and Equipment: | ||||
| Oil and Natural Gas Properties, Full Cost Method of Accounting | ||||
| Proved | 10,307,376 | 8,428,518 | ||
| Unproved | 42,702 | 36,785 | ||
| Other Property and Equipment | 8,197 | 8,069 | ||
| Total Property and Equipment | 10,358,275 | 8,473,372 | ||
| Less – Accumulated Depreciation, Depletion and Impairment | (5,276,105) | (4,541,808) | ||
| Total Property and Equipment, Net | 5,082,170 | 3,931,563 | ||
| Derivative Instruments | 9,832 | 10,725 | ||
| Acquisition Deposit | — | 17,094 | ||
| Other Noncurrent Assets, Net | 11,077 | 15,466 | ||
| Total Assets | $ | 5,603,822 | $ | 4,484,255 |
| Liabilities and Stockholders’ Equity | ||||
| Current Liabilities: | ||||
| Accounts Payable | $ | 202,866 | $ | 192,672 |
| Accrued Liabilities | 290,792 | 147,943 | ||
| Accrued Interest | 25,992 | 26,219 | ||
| Derivative Instruments | 19,915 | 16,797 | ||
| Other Current Liabilities | 4,705 | 2,130 | ||
| Total Current Liabilities | 544,270 | 385,761 | ||
| Long-term Debt, Net | 2,369,294 | 1,835,554 | ||
| Derivative Instruments | 93,606 | 105,831 | ||
| Deferred Tax Liability | 228,038 | 68,488 | ||
| Asset Retirement Obligations | 45,907 | 38,203 | ||
| Other Noncurrent Liabilities | 2,272 | 2,741 | ||
| Total Liabilities | $ | 3,283,387 | $ | 2,436,578 |
| Commitments and Contingencies | ||||
| Stockholders’ Equity | ||||
| Common Stock, Par Value $0.001;<br><br>270,000,000 authorized; 99,113,645 Shares Outstanding at 12/31/2024<br><br>135,000,000 Authorized; 100,761,148 Shares Outstanding at 12/31/2023 | 501 | 503 | ||
| Additional Paid-In Capital | 1,877,416 | 2,124,963 | ||
| Retained Earnings (Deficit) | 442,518 | (77,790) | ||
| Total Stockholders’ Equity | 2,320,435 | 2,047,676 | ||
| Total Liabilities and Stockholders’ Equity | $ | 5,603,822 | $ | 4,484,255 |
Non-GAAP Financial Measures
Adjusted Net Income, Adjusted EBITDA and Free Cash Flow are non-GAAP measures. Net income (loss) is the most directly comparable GAAP measure for both Adjusted Net Income and Adjusted EBITDA. Cash flows from operations is the most directly comparable GAAP measure for Free Cash Flow. NOG defines Adjusted Net Income (Loss) as net income (loss) excluding (i) (gain) loss on unsettled commodity derivatives, net of tax, (ii) (gain) loss on the extinguishment of debt, net of tax, (iii) (gain) loss on unsettled interest rate derivatives, net of tax, (iv) contingent consideration (gain) loss, net of tax, and (v) acquisition transaction costs, net of tax. NOG 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 the extinguishment of debt, (vi) contingent consideration (gain) loss, (vii) acquisition transaction expense, (viii) (gain) loss on unsettled interest rate derivatives, (ix) (gain) loss on unsettled commodity derivatives, and (x) other non-cash adjustments. NOG defines Free Cash Flow as cash flows from operations before changes in working capital and other items, less (i) capital expenditures, excluding non-budgeted acquisitions and (ii) preferred stock dividends. A reconciliation of each of these measures to the most directly comparable GAAP measure is included below.
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 NOG’s core operating results. In addition, these non-GAAP financial measures are used by management for budgeting and forecasting as well as subsequently measuring NOG’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 NOG’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 NOG’s oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of NOG’s reserves to other companies. Management uses this measure when assessing the potential return on investment related to NOG’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<br>December 31, | Year Ended <br>December 31, | |||||||
|---|---|---|---|---|---|---|---|---|
| (In thousands, except share and per share data) | 2024 | 2023 | 2024 | 2023 | ||||
| Income Before Taxes | $ | 87,838 | $ | 447,614 | $ | 680,817 | $ | 1,000,742 |
| Add: | ||||||||
| Impact of Selected Items: | ||||||||
| (Gain) Loss on Unsettled Commodity Derivatives | 59,728 | (235,553) | 21,258 | (201,331) | ||||
| Gain on the Extinguishment of Debt | — | — | — | (659) | ||||
| (Gain) Loss on Unsettled Interest Rate Derivatives | (283) | — | (263) | 1,017 | ||||
| Contingent Consideration Gain | — | — | — | (10,107) | ||||
| Acquisition Transaction Costs | 760 | 765 | 1,742 | 11,243 | ||||
| Adjusted Income Before Adjusted Income Tax Expense | 148,043 | 212,827 | 703,554 | 800,905 | ||||
| Adjusted Income Tax Expense (1) | 36,271 | 52,143 | 172,371 | 196,222 | ||||
| Adjusted Net Income (non-GAAP) | $ | 111,772 | $ | 160,684 | $ | 531,184 | $ | 604,683 |
| Weighted Average Shares Outstanding – Basic | 99,217,821 | 99,278,050 | 99,852,539 | 91,483,687 | ||||
| Weighted Average Shares Outstanding – Diluted | 100,934,410 | 99,814,411 | 101,267,625 | 92,060,947 | ||||
| Less: | ||||||||
| Dilutive Effect of Convertible Notes (2) | (521,596) | — | (343,860) | (108,564) | ||||
| Weighted Average Shares Outstanding – Adjusted Diluted | 100,412,814 | 99,814,411 | 100,923,765 | 91,952,383 | ||||
| Income Before Income Taxes Per Common Share – Basic | $ | 0.89 | $ | 4.51 | $ | 6.82 | $ | 10.94 |
| Add: | ||||||||
| Impact of Selected Items | 0.61 | (2.36) | 0.23 | (2.18) | ||||
| Impact of Income Tax | (0.37) | (0.53) | (1.73) | (2.15) | ||||
| Adjusted Net Income Per Common Share – Basic | $ | 1.13 | $ | 1.62 | $ | 5.32 | $ | 6.61 |
| Income Before Income Taxes Per Common Share – Adjusted Diluted | $ | 0.87 | $ | 4.48 | $ | 6.75 | $ | 10.88 |
| Add: | ||||||||
| Impact of Selected Items | 0.60 | (2.35) | 0.23 | (2.17) | ||||
| Impact of Income Tax | (0.36) | (0.52) | (1.72) | (2.13) | ||||
| Adjusted Net Income Per Common Share – Adjusted Diluted | $ | 1.11 | $ | 1.61 | $ | 5.26 | $ | 6.58 |
_______________
(1)This represents a tax impact using an estimated tax rate of 24.5% for the three and twelve months ended December 31, 2024 and 2023.
(2)Weighted average shares outstanding - diluted, on a GAAP basis, includes diluted shares attributable to the Company’s Convertible Notes due 2029. However, the offsetting impact of the capped call transactions that the Company entered into in connection therewith is not recognized on a GAAP basis. As a result, for purposes of this calculation, the Company excludes the dilutive shares to the extent they would be offset by the capped calls.
Reconciliation of Adjusted EBITDA
| Three Months Ended<br>December 31, | Year Ended <br>December 31, | |||||||
|---|---|---|---|---|---|---|---|---|
| (In thousands) | 2024 | 2023 | 2024 | 2023 | ||||
| Net Income | $ | 71,698 | $ | 388,853 | $ | 520,308 | $ | 922,969 |
| Add: | ||||||||
| Interest Expense | 45,259 | 36,513 | 157,717 | 135,664 | ||||
| Income Tax Expense | 16,140 | 58,761 | 160,509 | 77,773 | ||||
| Depreciation, Depletion, Amortization and Accretion | 204,674 | 151,188 | 740,901 | 486,024 | ||||
| Non-Cash Stock-Based Compensation | 3,539 | 1,181 | 11,858 | 5,660 | ||||
| Gain on the Extinguishment of Debt | — | — | — | (659) | ||||
| Contingent Consideration Gain | — | — | — | (10,107) | ||||
| Other Adjustments | 5,116 | — | 5,116 | — | ||||
| Acquisition Transaction Costs | 760 | 765 | 1,742 | 11,243 | ||||
| (Gain) Loss on Unsettled Interest Rate Derivatives | (283) | — | (263) | 1,017 | ||||
| (Gain) Loss on Unsettled Commodity Derivatives | 59,728 | (235,553) | 21,258 | (201,331) | ||||
| Adjusted EBITDA | $ | 406,631 | $ | 401,708 | $ | 1,619,146 | $ | 1,428,254 |
Reconciliation of Free Cash Flow
| Three Months Ended<br>December 31, | ||
|---|---|---|
| (In thousands) | 2024 | |
| Net Cash Provided by Operating Activities | $ | 290,278 |
| Exclude: Changes in Working Capital and Other Items | 68,581 | |
| Less: Capital Expenditures (1) | (262,477) | |
| Free Cash Flow | $ | 96,382 |
_______________
(1) Capital expenditures are calculated as follows:
| Three Months Ended<br>December 31, | ||
|---|---|---|
| (In thousands) | 2024 | |
| Cash Paid for Capital Expenditures | $ | 662,623 |
| Less: Non-Budgeted Acquisitions | (508,147) | |
| Plus: Change in Accrued Capital Expenditures and Other | 108,001 | |
| Capital Expenditures | $ | 262,477 |
Reconciliation of PV-10
The following table reconciles the pre-tax PV10% value of our SEC Pricing Proved Reserves as of December 31, 2024 to the Standardized Measure of discounted future net cash flows.
| SEC Pricing Proved Reserves<br><br>(In thousands) | ||
|---|---|---|
| Standardized Measure Reconciliation | ||
| Pre-Tax Present Value of Estimated Future Net Revenues (Pre-Tax PV10%) | $ | 5,069,851 |
| Future Income Taxes, Discounted at 10%(1) | (838,931) | |
| Standardized Measure of Discounted Future Net Cash Flows | $ | 4,230,920 |
_______________
(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, 2024, our future income taxes were significantly reduced.