NOG Announces Fourth Quarter and Full Year 2021 Results
HIGHLIGHTS
- Fourth quarter production of 64,155 Boe per day (59.2% oil), an increase of 11% from the third quarter of 2021
- Fourth quarter GAAP cash flow from operations of $133.1 million. Excluding changes in net working capital, cash flow from operations was $158.0 million, an increase of 29% from the third quarter of 2021
- Total capital expenditures of $83.7 million during the fourth quarter, excluding previously-announced non-budgeted acquisitions
- Free Cash Flow (non-GAAP) of $70.7 million during the fourth quarter, post-preferred stock dividends, increased 28% from the third quarter of 2021. See “Non-GAAP Financial Measures” below
- Initiates 2022 production guidance of 70,000 – 75,000 Boe per day, with $350 – $415 million total planned capital expenditures
- Closed Veritas acquisition in the Permian Basin, largest acquisition in NOG’s history, on January 27, 2022
- Announced a Base Dividend Growth plan in December 2021, highlighted by planned 20% average dividend growth per quarter through 2023
- Retired $7.2 million in face value of Convertible Preferred Stock
MINNEAPOLIS–(BUSINESS WIRE)–Northern Oil and Gas, Inc. (NYSE: NOG) (“Northern,” or “NOG”) today announced the company’s fourth quarter and full year 2021 results.
MANAGEMENT COMMENTS
“2021 was a truly transformational year for NOG,” commented Nick O’Grady, NOG’s Chief Executive Officer. “We enter 2022 with a stronger asset base and balance sheet, and with a formalized plan of increasing shareholder returns. We are an increasingly diversified, balanced business, with opportunities to self-fund accretive growth while steadily increasing returns to our shareholders.”
FINANCIAL RESULTS
Oil and natural gas sales for the fourth quarter were $332.4 million, an increase of 28% over the third quarter. Fourth quarter GAAP net income was $171.1 million or $2.13 per diluted share. Fourth quarter Adjusted Net Income was $87.0 million or $1.06 per diluted share, an increase of $35.7 million or $0.64 per diluted share over the prior year. Adjusted EBITDA in the fourth quarter was $175.3 million, an increase of 29% over the third quarter.
Oil and natural gas sales for full year 2021 were $975.1 million, an increase of 201% over full year 2020. Full year 2021 Adjusted Net Income was $256.3 million or $3.49 per diluted share. Full year 2021 GAAP net loss was $8.4 million or $0.13 per diluted share. Full year 2021 Adjusted EBITDA was $543.0 million, an increase of 54% over the prior year. (See “Non-GAAP Financial Measures” below.)
PRODUCTION
Fourth quarter production was 64,155 Boe per day, an 11% increase from the third quarter. Oil represented 59.2% of production in the fourth quarter. NOG had 12.1 net wells turned online during the fourth quarter, compared to 6.5 net wells turned online in the third quarter of 2021. NOG saw production outperform internal expectations in the fourth quarter, most notably in its Appalachian properties. Full year 2021 production was 53,792 Boe per day, above the high end of NOG’s 2021 guidance.
PRICING
During the fourth quarter, NYMEX West Texas Intermediate (“WTI”) crude oil averaged $77.31 per Bbl, and NYMEX natural gas at Henry Hub averaged $4.74 per Mcf. NOG’s unhedged net realized oil price in the fourth quarter was $71.67 per Bbl, representing a $5.64 differential to WTI prices. NOG’s fourth quarter unhedged net realized gas price was $5.68 per Mcf, representing approximately 120% realizations compared with Henry Hub pricing.
For full year 2021, NOG’s realized oil differential was $5.15 per Bbl. NOG’s full year unhedged net realized gas price was $4.57 per Mcf, representing approximately 119% realizations compared with Henry Hub pricing.
OPERATING COSTS
Lease operating costs were $50.6 million in the fourth quarter of 2021, or $8.57 per Boe, an increase of 5% on a per unit basis compared to the third quarter. The increase in unit costs was primarily driven by the acquisition of higher unit cost production in the Williston Basin. Continued high NGL prices, which results in higher processing charges, also increased unit costs, but was more than offset by higher natural gas revenues.
Fourth quarter general and administrative (“G&A”) costs totaled $10.5 million, which includes non-cash stock-based compensation. Cash G&A costs totaled $9.1 million or $1.54 per Boe in the fourth quarter, which included certain transaction costs associated with our Permian and Williston acquisitions. Excluding approximately $2.0 million of such transaction costs, remaining cash G&A was $7.1 million, or $1.20 per Boe.
CAPITAL EXPENDITURES AND ACQUISITIONS
Capital spending for the fourth quarter, excluding non-budgeted acquisitions, was $83.7 million. This was comprised of $49.1 million of organic drilling and completion (“D&C”) capital and $34.6 million of total acquisition spending and other items, inclusive of ground game D&C spending. NOG had 12.1 net wells turned online in the fourth quarter. Wells in process totaled 42.5 net wells as of December 31, 2021. On the ground game acquisition front, NOG closed on 9 transactions during the fourth quarter totaling 9.6 net wells, and 317 net mineral acres. Total 2021 capital expenditures, excluding non-budgeted acquisitions, were $253.4 million, slightly above NOG’s guidance for 2021 driven by significant ground game opportunities executed and an acceleration of completion activity in the fourth quarter.
RESERVES
Total proved reserves at December 31, 2021, increased 135% from year-end 2020 to 287.7 million barrels of oil equivalent (59% proved developed) with an associated pre-tax PV-10 value of $3.3 billion (72% proved developed) at SEC Pricing. Total reserve replacement ratio was 270%, excluding acquired reserves. NOG’s PV-10 and proved reserve values at year-end 2021 do not include the recently closed Veritas transaction. The Veritas assets had an audited year-end 2021 proved reserve PV-10 value of $428 million at SEC Pricing. NOG’s year-end 2021 proforma PV-10 inclusive of Veritas was $3.8 billion. The reserves are calculated under SEC guidelines relating to both commodity price assumptions and a maximum five year drill schedule. The SEC Pricing used as of December 31, 2021, after adjustment to reflect applicable transportation and quality differentials, was $62.25 per barrel of oil and $3.37 per Mcf of natural gas, significantly below current price levels. See “Non-GAAP Financial Measures” below regarding PV-10 value.
LIQUIDITY, CAPITAL RESOURCES, AND RECENT ACQUISITIONS
As of December 31, 2021, NOG had $9.5 million in cash and $55.0 million of borrowings outstanding on its revolving credit facility. NOG had total liquidity of $704.5 million as of December 31, 2021, consisting of cash and committed borrowing availability under the revolving credit facility. Additionally, NOG had $40.7 million in an escrow account as of December 31, 2021, as a deposit on the Veritas acquisition that was signed in November 2021 and closed in January 2022.
In November 2021, NOG executed both common equity and senior debt offerings. NOG issued 11.0 million shares of common equity for gross proceeds of $220.0 million. NOG also raised $213.5 million of gross proceeds, plus accrued interest, by issuing $200 million of principal amount of 8.125% Senior Unsecured Notes due 2028 at 106.75% of par value. With the net proceeds from these transactions, NOG retired debt under its existing revolving credit facility and, ultimately, closed on the Comstock and Veritas acquisitions described below.
On November 16, 2021, NOG paid the adjusted cash purchase price of $154.0 million to close its Comstock acquisition, funded by the $7.7 million deposit previously paid, cash on hand and borrowings on its revolving credit facility. The cash consideration included typical closing adjustments, and remains subject to final post-closing settlement between NOG and the seller.
On January 27, 2022, NOG paid the adjusted cash purchase price of $419.4 million to close its Veritas acquisition, funded by the $40.7 million deposit previously paid, cash on hand and borrowings on its revolving credit facility. The cash consideration included typical closing adjustments, and remains subject to final post-closing settlement between NOG and the seller. NOG also issued approximately 1.9 million common stock warrants to Veritas as additional purchase consideration.
STOCKHOLDER RETURNS
On November 11, 2021, NOG’s Board of Directors declared a regular quarterly cash dividend for NOG’s common stock of $0.08 per share for stockholders of record as of December 30, 2021, which was paid on January 31, 2022. This represented a 78% increase from the prior quarter.
On February 1, 2022, NOG’s Board of Directors declared a regular quarterly cash dividend for NOG’s common stock of $0.14 per share for stockholders of record as of March 30, 2022, which will be paid on April 29, 2022. This represented a 75% increase from the fourth quarter.
In February 2022, NOG repurchased $7.2 million of liquidation preference value of its 6.500% Series A Perpetual Cumulative Convertible Preferred Stock from three separate holders. These repurchases are expected to reduce NOG’s annual preferred dividend payments by approximately $467,000 and additionally reduce NOG’s diluted common stock share count by approximately 316,000 shares.
2022 ANNUAL GUIDANCE
NOG anticipates approximately 70,000 – 75,000 Boe per day of production in 2022, an increase of approximately 35% at the midpoint from 2021 levels. NOG currently expects total capital spending in the range of $350 – $415 million for 2022. NOG expects approximately 45% of its 2022 budget to be spent on the Williston, 45% on the Permian, and the remaining 10% on the Appalachian and other.
|
|
2022 Guidance |
|
Annual Production (Boe per day) |
70,000 – 75,000 |
|
Oil as a Percentage of Sales Volumes |
59.5 – 61.5% |
|
Total Capital Expenditures ($ in millions) |
$350 – $415 |
|
Net Wells Added to Production |
48 – 52 |
|
Operating Expenses and Differentials |
|
|
Production Expenses (per Boe) |
$8.50 – $8.85 |
|
Production Taxes (as a percentage of Oil & Gas Sales) |
8.0 – 9.0% |
|
Average Differential to NYMEX WTI (per Bbl) |
($5.75) – ($6.25) |
|
Average Realization as a Percentage of NYMEX Henry Hub (per Mcf) |
100% – 110% |
|
General and Administrative Expense (per Boe): |
|
|
Non-Cash |
$0.20 – $0.30 |
|
Cash (excluding transaction costs on non-budgeted acquisitions) |
$0.80 – $0.85 |
PROVED RESERVES AS OF DECEMBER 31, 2021
|
|
SEC Pricing Proved Reserves(1) |
||||||||||||
|
|
Reserve Volumes |
|
PV-10(3) |
||||||||||
|
Reserve Category |
Oil |
|
Natural Gas |
|
Total |
|
% |
|
Amount |
|
% |
||
|
PDP Properties |
84,920 |
|
491,852 |
|
166,895 |
|
58 |
|
|
$ |
2,328,766 |
|
70 |
|
PDNP Properties |
2,585 |
|
6,706 |
|
3,703 |
|
1 |
|
|
|
71,209 |
|
2 |
|
PUD Properties |
43,890 |
|
439,165 |
|
117,084 |
|
41 |
|
|
|
941,114 |
|
28 |
|
Total |
131,395 |
|
937,723 |
|
287,682 |
|
100 |
|
$ |
3,341,089 |
|
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, 2021 based on average prices of $66.56 per barrel of oil and $3.60 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, 2021, after adjustment to reflect applicable transportation and quality differentials, was $62.25 per barrel of oil and $3.37 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 2021 RESULTS
The following table sets forth selected operating and financial data for the periods indicated.
|
|
Three Months Ended |
|||||||||
|
|
2021 |
|
2020 |
|
% Change |
|||||
|
Net Production: |
|
|
|
|
|
|||||
|
Oil (Bbl) |
|
3,492,556 |
|
|
|
2,508,618 |
|
|
39 |
% |
|
Natural Gas and NGLs (Mcf) |
|
14,458,119 |
|
|
|
4,675,896 |
|
|
209 |
% |
|
Total (Boe) |
|
5,902,243 |
|
|
|
3,287,934 |
|
|
80 |
% |
|
|
|
|
|
|
|
|||||
|
Average Daily Production: |
|
|
|
|
|
|||||
|
Oil (Bbl) |
|
37,963 |
|
|
|
27,268 |
|
|
39 |
% |
|
Natural Gas and NGL (Mcf) |
|
157,153 |
|
|
|
50,825 |
|
|
209 |
% |
|
Total (Boe) |
|
64,155 |
|
|
|
35,738 |
|
|
80 |
% |
|
|
|
|
|
|
|
|||||
|
Average Sales Prices: |
|
|
|
|
|
|||||
|
Oil (per Bbl) |
$ |
71.67 |
|
|
$ |
35.69 |
|
|
101 |
% |
|
Effect of Gain on Settled Derivatives on Average Price (per Bbl) |
|
(15.71 |
) |
|
|
14.51 |
|
|
|
|
|
Oil Net of Settled Derivatives (per Bbl) |
|
55.96 |
|
|
|
50.20 |
|
|
11 |
% |
|
|
|
|
|
|
|
|||||
|
Natural Gas and NGLs (per Mcf) |
|
5.68 |
|
|
|
2.13 |
|
|
167 |
% |
|
Effect of Gain (Loss) on Settled Derivatives on Average Price (per Mcf) |
|
(1.33 |
) |
|
|
(0.20 |
) |
|
|
|
|
Natural Gas Net of Settled Derivatives (per Mcf) |
|
4.35 |
|
|
|
1.93 |
|
|
125 |
% |
|
|
|
|
|
|
|
|||||
|
Realized Price on a Boe Basis Excluding Settled Commodity Derivatives |
|
56.31 |
|
|
|
30.27 |
|
|
86 |
% |
|
Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Boe) |
|
(12.60 |
) |
|
|
10.79 |
|
|
|
|
|
Realized Price on a Boe Basis Including Settled Commodity Derivatives |
|
43.72 |
|
|
|
41.06 |
|
|
6 |
% |
|
|
|
|
|
|
|
|||||
|
|
|
|
|
|
|
|||||
|
Costs and Expenses (per Boe): |
|
|
|
|
|
|||||
|
Production Expenses |
$ |
8.57 |
|
|
$ |
8.58 |
|
|
— |
% |
|
Production Taxes |
|
4.25 |
|
|
|
2.75 |
|
|
55 |
% |
|
General and Administrative Expense |
|
1.77 |
|
|
|
1.33 |
|
|
33 |
% |
|
Depletion, Depreciation, Amortization and Accretion |
|
7.25 |
|
|
|
9.97 |
|
|
(27 |
)% |
|
|
|
|
|
|
|
|||||
|
Net Producing Wells at Period End |
|
680.8 |
|
|
|
475.1 |
|
|
43 |
% |
FULL YEAR 2021 RESULTS
The following table sets forth selected operating and financial data for the periods indicated.
|
|
Years Ended December 31, |
||||||||
|
|
2021 |
|
2020 |
|
% Change |
||||
|
Net Production: |
|
|
|
|
|
||||
|
Oil (Bbl) |
|
12,288,358 |
|
|
|
9,361,138 |
|
31 |
% |
|
Natural Gas and NGLs (Mcf) |
|
44,073,941 |
|
|
|
16,473,287 |
|
168 |
% |
|
Total (Boe) |
|
19,634,015 |
|
|
|
12,106,686 |
|
62 |
% |
|
|
|
|
|
|
|
||||
|
Average Daily Production: |
|
|
|
|
|
||||
|
Oil (Bbl) |
|
33,667 |
|
|
|
25,577 |
|
32 |
% |
|
Natural Gas and NGL (Mcf) |
|
120,751 |
|
|
|
45,009 |
|
168 |
% |
|
Total (Boe) |
|
53,792 |
|
|
|
33,078 |
|
63 |
% |
|
|
|
|
|
|
|
||||
|
Average Sales Prices: |
|
|
|
|
|
||||
|
Oil (per Bbl) |
$ |
62.94 |
|
|
$ |
32.61 |
|
93 |
% |
|
Effect of Gain (Loss) on Settled Oil Derivatives on Average Price (per Bbl) |
|
(10.17 |
) |
|
|
20.08 |
|
|
|
|
Oil Net of Settled Oil Derivatives (per Bbl) |
|
52.77 |
|
|
|
52.69 |
|
— |
% |
|
|
|
|
|
|
|
||||
|
Natural Gas and NGLs (per Mcf) |
|
4.57 |
|
|
|
1.14 |
|
301 |
% |
|
Effect of Gain (Loss) on Settled Natural Gas Derivatives on Average Price (per Mcf) |
|
(0.92 |
) |
|
|
0.02 |
|
|
|
|
Natural Gas and NGLs Net of Settled Natural Gas Derivatives (per Mcf) |
|
3.65 |
|
|
|
1.16 |
|
215 |
% |
|
|
|
|
|
|
|
||||
|
Realized Price on a Boe Basis Excluding Settled Commodity Derivatives |
|
49.66 |
|
|
|
26.77 |
|
86 |
% |
|
Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Boe) |
|
(8.45 |
) |
|
|
15.55 |
|
|
|
|
Realized Price on a Boe Basis Including Settled Commodity Derivatives |
|
41.21 |
|
|
|
42.32 |
|
(9 |
)% |
|
|
|
|
|
|
|
||||
|
Costs and Expenses (per Boe): |
|
|
|
|
|
||||
|
Production Expenses |
$ |
8.70 |
|
|
$ |
9.61 |
|
(9 |
)% |
|
Production Taxes |
|
3.92 |
|
|
|
2.46 |
|
59 |
% |
|
General and Administrative Expenses |
|
1.55 |
|
|
|
1.53 |
|
1 |
% |
|
Depletion, Depreciation, Amortization and Accretion |
|
7.17 |
|
|
|
13.39 |
|
(46 |
)% |
|
|
|
|
|
|
|
||||
|
Net Producing Wells at Period-End |
|
680.8 |
|
|
|
475.1 |
|
43 |
% |
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, 2021.
|
Crude Oil Commodity Derivative Swaps |
||||||
|
Contract Period |
|
Volume (Bbls) |
|
Volume (Bbls/Day) |
|
Weighted Average Price |
|
2022: |
|
|
|
|
|
|
|
Q1 |
|
2,690,980 |
|
29,900 |
|
$60.68 |
|
Q2 |
|
2,598,000 |
|
28,549 |
|
$60.80 |
|
Q3 |
|
2,559,900 |
|
27,825 |
|
$60.02 |
|
Q4 |
|
2,398,900 |
|
26,075 |
|
$59.54 |
|
2023(1): |
|
|
|
|
|
|
|
Q1 |
|
1,131,750 |
|
12,575 |
|
$64.07 |
|
Q2 |
|
923,650 |
|
10,150 |
|
$65.38 |
|
Q3 |
|
581,900 |
|
6,325 |
|
$66.96 |
|
Q4 |
|
572,700 |
|
6,225 |
|
$66.57 |
|
2024(1): |
|
|
|
|
|
|
|
Q1 |
|
136,500 |
|
1,500 |
|
$64.65 |
|
Q2 |
|
136,500 |
|
1,500 |
|
$64.19 |
|
Q3 |
|
138,000 |
|
1,500 |
|
$63.51 |
|
Q4 |
|
138,000 |
|
1,500 |
|
$62.96 |
_____________
|
(1) |
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. For additional information, see Note 12 to our financial statements included in our Form 10-K filed with the SEC for the year ended December 31, 2021. |
The following table summarizes NOG’s open natural gas commodity derivative swap contracts scheduled to settle after December 31, 2021.
|
Natural Gas Commodity Derivative Swaps |
||||||
|
Contract Period |
|
Gas (MMBTU) |
|
Volume (MMBTU/Day) |
|
Weighted Average Price |
|
|
|
|
|
|
|
|
|
2022(1): |
|
|
|
|
|
|
|
Q1 |
|
6,814,132 |
|
75,713 |
|
$3.25 |
|
Q2 |
|
8,715,000 |
|
95,769 |
|
$3.11 |
|
Q3 |
|
9,660,000 |
|
105,000 |
|
$3.18 |
|
Q4 |
|
8,880,000 |
|
96,522 |
|
$3.48 |
|
2023: |
|
|
|
|
|
|
|
Q1 |
|
5,690,000 |
|
63,222 |
|
$3.78 |
|
Q2 |
|
1,840,000 |
|
20,220 |
|
$3.34 |
|
Q3 |
|
1,840,000 |
|
20,000 |
|
$3.43 |
|
Q4 |
|
1,437,000 |
|
15,620 |
|
$3.50 |
|
2024: |
|
|
|
|
|
|
|
Q1 |
|
630,000 |
|
6,923 |
|
$3.22 |
|
Q2 |
|
644,000 |
|
7,077 |
|
$3.22 |
|
Q3 |
|
644,000 |
|
7,000 |
|
$3.22 |
|
Q4 |
|
427,000 |
|
4,641 |
|
$3.22 |
_____________
|
(1) |
This table does not include volumes subject to collars. This table also does not include basis swaps. For additional information, see Note 12 to our financial statements included in our Form 10-K filed with the SEC for the year ended December 31, 2021. |
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 |
|
Twelve Months Ended |
|||||||||||
|
(In thousands) |
2021 |
|
2020 |
|
2021 |
|
2020 |
|||||||
|
Cash Received (Paid) on Derivatives |
$ |
(74,353 |
) |
|
$ |
35,482 |
|
|
$ |
(165,823 |
) |
|
$ |
188,234 |
|
Non-Cash Gain (Loss) on Derivatives |
|
61,170 |
|
|
|
(84,923 |
) |
|
|
(312,370 |
) |
|
|
39,878 |
|
Gain (Loss) on Derivative Instruments, Net |
$ |
(13,183 |
) |
|
$ |
(49,441 |
) |
|
$ |
(478,193 |
) |
|
$ |
228,112 |
CAPITAL EXPENDITURES & DRILLING ACTIVITY
|
(In millions, except for net well data) |
|
Three Months Ended |
|
Year Ended December 31, |
|
Capital Expenditures Incurred: |
|
|
|
|
|
Organic Drilling and Development Capital Expenditures |
|
$49.1 |
|
$161.8 |
|
Ground Game Drilling and Development Capital Expenditures |
|
$26.7 |
|
$50.8 |
|
Ground Game Acquisition Capital Expenditures |
|
$8.8 |
|
$37.9 |
|
Other |
|
$(0.9) |
|
$2.9 |
|
Non-Budgeted Acquisitions |
|
$146.8 |
|
$402.8 |
|
|
|
|
|
|
|
Net Wells Added to Production |
|
12.1 |
|
35.8 |
|
|
|
|
|
|
|
Net Producing Wells (Period-End) |
|
|
|
680.8 |
|
|
|
|
|
|
|
Net Wells in Process (Period-End) |
|
|
|
42.5 |
|
Change in Wells in Process over Prior Period |
|
(0.6) |
|
14.5 |
|
|
|
|
|
|
|
Weighted Average AFE for Wells Elected to |
|
$7.1 |
|
$6.9 |
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 14.5 in net wells in process during the year ended December 31, 2021 are reflected in the annual amounts incurred for drilling and development capital expenditures.
ACREAGE
As of December 31, 2021, NOG controlled leasehold of approximately 245,431 net acres in the Williston, Permian and Appalachian Basins in the United States, and approximately 88% of this total acreage position was developed, held by production, or held by operations.
FOURTH QUARTER 2021 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 Friday, February 25, 2022 at 8:00 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://themediaframe.com/mediaframe/webcast.html?webcastid=EctAX0qH
Dial-In Number: (866) 373-3407 (US/Canada) and (412) 902-1037 (International)
Conference ID: 13726752 – Fourth Quarter 2021 Earnings Call
Replay Dial-In Number: (877) 660-6853 (US/Canada) and (201) 612-7415 (International)
Replay Access Code: 13726752 – Replay will be available through March 4, 2022
ABOUT NORTHERN OIL AND GAS
NOG 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 premier basins within the United States. More information about NOG 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 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 properties and properties pending acquisition; NOG’s ability to acquire additional development opportunities; potential or pending acquisition transactions; NOG’s ability to consummate pending acquisitions, and the anticipated timing of such consummation; 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; disruptions to NOG’s business due to acquisitions and other significant transactions; infrastructure constraints and related factors affecting NOG’s properties; cost inflation or supply chain disruption; ongoing legal disputes over and potential shutdown of the Dakota Access Pipeline; the COVID-19 pandemic and its related economic repercussions and effect on the oil and natural gas industry; 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; NOG’s ability to raise or access capital; cyber-related risks; changes in accounting principles, policies or guidelines; and financial or political instability, health-related epidemics, acts of war or terrorism, 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.
Contacts
Mike Kelly, CFA
Chief Strategy Officer
952-476-9800
ir@northernoil.com
