- Second quarter production increased 66% over the prior year,
averaging 34,965 barrels of oil equivalent (“Boe”) per day.
- Cash flow from operations, excluding a $5.8 million net
increase from changes in working capital, was $93.6 million in the
second quarter, a 7% increase versus the first quarter.
- Organic drilling and development capital expenditures totaled
$71.9 million during the second quarter, a 3% decrease versus the
first quarter.
- Northern spent $10.5 million on senior note repurchases and
$22.0 million on ground game acquisitions and associated
development during the second quarter.
Northern Oil and Gas, Inc. (NYSE American: NOG) (“Northern”)
today announced the company’s second quarter results and provided
updated 2019 guidance.
Second quarter 2019 production totaled 3.2 million Boe and
averaged 34,965 Boe per day, a 66% increase from the prior year.
Oil and gas sales in the second quarter increased 37% from the
prior year to $149.8 million. Net income in the second quarter was
$44.4 million or $0.12 per diluted share. Adjusted Net Income in
the second quarter was $45.5 million or $0.12 per diluted share.
Adjusted EBITDA totaled $110.8 million in the second quarter, a 57%
increase from the prior year or 6% increase sequentially. (See
“Non-GAAP Financial Measures” below.)
“We continue to execute on our 2019 capital allocation plan,
focusing on the highest returns available to us including our
organic well opportunities and ground game acquisitions. This
approach allowed us to remain within our production guidance
despite approximately 2,500 Boe per day of curtailments due to
continued basin-level infrastructure constraints,” commented
Brandon Elliott, Chief Executive Officer. “Strong well performance,
the closing of our VEN Bakken acquisition and continued success in
our ground game are expected to expand our free cash flow profile
to support additional debt reduction along with a stable and
consistent return of capital to shareholders.”
Production and Operating Costs
Total second quarter production was 3.2 million Boe, driven by
an additional 8.1 net wells added to production during the quarter,
offset in part by continued infrastructure-driven curtailments.
Midstream system expansions scheduled to come online in the second
half of 2019 and early 2020 are expected to alleviate curtailments
late in 2019. Oil price differentials of $5.29 per barrel are
trending as expected, a 15% improvement from the first quarter of
2019. Ongoing production curtailments resulted in an increase in
lease operating expenses (“LOE”) to $8.21 per Boe in the second
quarter. Cash general and administrative expenses were $1.13 per
Boe in the second quarter, up 7% from the first quarter primarily
due to transaction and legal costs associated with the VEN Bakken
acquisition. Northern anticipates a one-time expense of $1.3
million for advisory fees for this transaction to be expensed in
the third quarter of 2019.
2019 Cash Flow Allocation
Northern continues to closely manage its discretionary cash flow
allocation in an effort to produce the highest returns on capital
employed. Northern spent, in aggregate, $22.0 million in the second
quarter on ground game acquisitions and associated development
capital. “Ground game” refers to Northern’s regular acquisition
activity excluding larger, separately announced transactions such
as the recent VEN Bakken acquisition. These transactions and wells
in process will serve to increase Northern’s production and cash
flows in 2019 and 2020, and bring forth additional future drilling
opportunities. Northern spent $10.5 million on Senior Note
repurchases in the second quarter. Northern expects sequential
production, cash flow and net income growth throughout the
remainder of 2019 and into 2020, due to the strong success of the
ground game, the closing of the VEN Bakken acquisition, and relief
from infrastructure constraints.
2019 Production Guidance Updated for Ground Game
Acquisitions, VEN Bakken and Continued Curtailments
Current Williston Basin activity levels remain stable, and
Northern now expects, on an organic basis combined with VEN Bakken,
to drill 33 – 34 net wells in 2019. In addition, Northern expects
to add an additional 3 – 5 net wells during the year through its
ground game acquisition strategy, for a total of 36 – 39 total net
wells added to production during 2019. Northern now expects
production (inclusive of six months of production from the VEN
Bakken acquisition that closed on July 1, 2019) to average between
38,650 – 39,150 Boe per day for the full year of 2019. Northern’s
previous cost and capital spending plan are being adjusted as well.
LOE guidance is being adjusted to account for higher unit costs
driven by curtailments and the higher LOE per unit costs associated
with the VEN Bakken assets. Production taxes are being raised
modestly, due to weaker overall gas and NGL prices in relation to
crude oil prices, as a percentage of sales. Cash G&A per Boe
guidance is being lowered to reflect higher expected production
volumes, but partially offset by an estimated $1.9 million in
transaction costs and fees incurred or expected to be incurred in
connection with the VEN Bakken acquisition.
Additional information regarding Northern’s current expectations
are included in the tables below.
2019 Production (Boe per day):
Current
Previous
1st Quarter – Actual
34,568
–
2nd Quarter – Actual
34,965
34,500 – 35,500
3rd Quarter – Estimate
41,500 – 42,500
–
4th Quarter – Estimate
43,500 – 44,500
–
Annual – Estimate
38,650 – 39,150
35,000 – 36,000
2019 Guidance Ranges (in millions,
except for net well data):
Current
Previous
Organic(1) Net Wells Added to
Production
33 – 34
28 – 32
Organic(1) Drilling & Completion
(D&C) Capital
$265 – $285
$227 – $260
Ground Game 2019E Net Wells Added to
Production
3 – 5
–
Ground Game Acquisition Capital
$25 – $50
$20 – $25
Ground Game D&C Capital
$30 – $60
–
(1) Organic includes estimated net wells
and D&C capital from recently acquired VEN Bakken assets
(post-closing).
2019 Full Year Operating Expenses
Guidance:
Current
Previous
Production Expenses (per Boe)
$8.00 – $8.50
$6.75 – $7.75
Production Taxes (% of Oil & Gas
Sales)
~ 9.3%
~ 9.1%
General and Administrative Expense (per
Boe):
Cash(2)
$0.95 – $1.15
$1.00 – $1.25
Non-Cash
$0.50
$0.50
Average Differential to NYMEX WTI
$4.50 – $6.50
$4.50 – $6.50
(2) Inclusive of approximately $1.9
million of transaction costs and fees incurred or expected to be
incurred in connection with the VEN Bakken acquisition.
SECOND QUARTER 2019 RESULTS
The following tables set forth selected operating and financial
data for the periods indicated.
Three Months Ended June
30,
2019
2018
% Change
Net Production:
Oil (Bbl)
2,562,513
1,625,788
58
%
Natural Gas and NGLs (Mcf)
3,715,936
1,736,651
114
%
Total (Boe)
3,181,835
1,915,230
66
%
Average Daily Production:
Oil (Bbl)
28,159
17,866
58
%
Natural Gas and NGLs (Mcf)
40,834
19,084
114
%
Total (Boe)
34,965
21,046
66
%
Average Sales Prices:
Oil (per Bbl)
$
54.56
$
62.20
(12
)%
Effect of Gain (Loss) on Settled
Derivatives on Average Price (per Bbl)
1.85
(7.55
)
Oil Net of Settled Derivatives (per
Bbl)
56.41
54.65
3
%
Natural Gas and NGLs (per Mcf)
2.70
4.61
(41
)%
Realized Price on a Boe Basis Including
all Realized Derivative Settlements
48.58
50.58
(4
)%
Costs and Expenses (per Boe):
Production Expenses
$
8.21
$
7.60
8
%
Production Taxes
4.41
5.29
(17
)%
General and Administrative Expense
1.65
1.70
(3
)%
Depletion, Depreciation, Amortization and
Accretion
14.49
11.80
23
%
Net Producing Wells at Period
End
340.6
248.3
37
%
Second Quarter Discretionary Capital
Summary (in millions):
Q2 2019
Senior Note Repurchases
$10.5
Ground Game Acquisition Capital
$8.0
Ground Game D&C Capital
$14.0
Total
$32.5
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 tables summarize
Northern’s open crude oil derivative and basis swap contracts
scheduled to settle after June 30, 2019.
Crude Oil Derivative
Swaps
Contract Period
Volume (Bbls)
Weighted Average Price (per
Bbl)
2019:
3Q
2,430,444
$61.89
4Q
2,460,411
$62.01
2020:
1Q
2,476,456
$59.16
2Q
2,390,828
$58.48
3Q
2,340,348
$58.48
4Q
2,165,362
$58.00
2021:
1Q
1,375,050
$57.09
2Q
1,269,458
$57.75
3Q
636,410
$53.64
4Q
627,506
$53.67
2022:
1Q
453,780
$53.07
2Q
312,280
$52.30
3Q
306,576
$52.33
4Q
300,230
$52.35
Crude Oil Derivative Basis
Swaps(1)
Contract Period
Total Volumes (Bbls)
Weighted Average
Differential ($/Bbl)
07/01/2019 - 12/31/2019
1,840,000
($2.41)
(1) Basis swaps are settled using the TMX
UHC 1a index, as published by NGX.
LIQUIDITY
As of June 30, 2019, Northern had $2.8 million in cash, $31.0
million in a restricted acquisition deposit, and $173.0 million
outstanding on its revolving credit facility. Northern had total
liquidity of $254.8 million as of June 30, 2019, consisting of cash
and borrowing availability under the revolving credit facility.
Northern repurchased $10.1 million in principal amount of its
Senior Notes in the second quarter, offset partially by $1.7
million for the final anticipated PIK interest payment. The total
amount of Senior Notes outstanding was $688.5 million as of June
30, 2019. Net of cash and the restricted acquisition deposit,
Northern’s total debt was reduced by $12.2 million from the prior
quarter.
CAPITAL EXPENDITURES & DRILLING ACTIVITY
(in millions, except for net well
data)
Three Months Ended June 30,
2019
Capital Expenditures Incurred:
Organic Drilling and Development Capital
Expenditures
$
71.9
Ground Game Acquisition Capital
Expenditures
$
8.0
Ground Game Drilling and Development
Capital Expenditures
$
14.0
Acquisition of Oil and Natural Gas
Properties and Other
$
4.0
Net Wells Added to Production
8.1
Net Producing Wells (Period-End)
340.6
Net Wells in Process (Period-End)
25.0
Increase in Wells in Process over 2018
Year-End
2.2
Weighted Average AFE for Wells Elected to
During the Second Quarter
$
7.7
Weighted Average AFE for Wells Elected to
Year-to-Date
$
8.0
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 2.2
well increase in net wells in process during the six months ended
June 30, 2019 are reflected in the amounts incurred year-to-date
for drilling and development capital expenditures.
ACREAGE
As of June 30, 2019, Northern controlled leasehold of
approximately 163,558 net acres targeting the Bakken and Three
Forks formations of the Williston Basin, and approximately 90% of
this total acreage position was developed, held by production, or
held by operations.
SECOND 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
Friday, August 2, 2019 at 11:00 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: 13692790 - Northern Oil
and Gas, Inc. Second Quarter 2019 Conference Call Replay Dial-In Number: (877) 660-6853 (US/Canada)
and (201) 612-7415 (International) Replay
Access Code: 13692790 - Replay will be available through
August 9, 2019
UPCOMING CONFERENCE SCHEDULE
EnerCom’s The Oil & Gas Conference August 12 - 13, 2019,
Denver, CO
8th Annual Intellisight Conference August 14, 2019, Minneapolis,
MN
Seaport Global Energy & Industrials Conference August 27 -
28, 2019, Chicago, IL
2019 Midwest IDEAS Investor Conference August 28 - 29, 2019,
Chicago IL
Johnson Rice & Company 2019 Energy Conference September 23-
29, 2019, New Orleans, LA
Friess Associates Research Round-Up October 3, 2019, Jackson
WY
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
current properties and any properties pending acquisition,
infrastructure constraints and related factors affecting 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 consummate any pending acquisition transactions, other
risks and uncertainties related to the closing of pending
acquisition transactions, 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 Northern’s operations, products and prices.
Northern has based these forward-looking statements on its
current expectations and assumptions about future events. While
management considers these expectations and assumptions to be
reasonable, they are inherently subject to significant business,
economic, competitive, regulatory and other risks, contingencies
and uncertainties, most of which are difficult to predict and many
of which are beyond Northern’s control. Northern does not undertake
any duty to update or revise any forward-looking statements, except
as may be required by the federal securities laws.
CONDENSED STATEMENTS OF
OPERATIONS
FOR THE THREE AND SIX MONTHS
ENDED JUNE 30, 2019 AND 2018
(UNAUDITED)
Three Months Ended June
30,
Six Months Ended June
30,
(In thousands, except share and per
share data)
2019
2018
2019
2018
REVENUES
Oil and Gas Sales
$
149,847
$
109,047
$
282,530
$
195,928
Gain (Loss) on Derivative Instruments,
Net
36,591
(42,203
)
(103,031
)
(62,474
)
Other Revenue
2
2
7
5
Total Revenues
186,440
66,846
179,506
133,459
OPERATING EXPENSES
Production Expenses
26,132
14,549
50,799
27,037
Production Taxes
14,034
10,132
26,553
18,054
General and Administrative Expenses
5,250
3,251
11,300
4,918
Depletion, Depreciation, Amortization and
Accretion
46,091
22,596
91,225
41,227
Impairment of Other Current Assets
2,694
—
2,694
—
Total Operating Expenses
94,200
50,528
182,571
91,236
INCOME (LOSS) FROM OPERATIONS
92,239
16,318
(3,065
)
42,223
OTHER INCOME (EXPENSE)
Interest Expense, Net of
Capitalization
(17,778
)
(22,403
)
(37,327
)
(45,510
)
Loss on the Extinguishment of Debt
(425
)
(90,833
)
(425
)
(90,833
)
Debt Exchange Derivative Gain/(Loss)
(4,873
)
—
1,413
—
Contingent Consideration Loss
(24,763
)
—
(23,371
)
—
Other Income (Expense)
(1
)
371
14
538
Total Other Income (Expense)
(47,840
)
(112,865
)
(59,697
)
(135,805
)
INCOME (LOSS) BEFORE INCOME
TAXES
44,399
(96,547
)
(62,762
)
(93,582
)
INCOME TAX PROVISION (BENEFIT)
—
—
—
—
NET INCOME (LOSS)
$
44,399
$
(96,547
)
$
(62,762
)
$
(93,582
)
Net Income (Loss) Per Common Share –
Basic
$
0.12
$
(0.49
)
$
(0.17
)
$
(0.71
)
Net Income (Loss) Per Common Share –
Diluted
$
0.12
$
(0.49
)
$
(0.17
)
$
(0.71
)
Weighted Average Shares Outstanding –
Basic
378,368,462
196,140,610
374,927,630
131,039,552
Weighted Average Shares Outstanding –
Diluted
378,724,511
196,140,610
374,927,630
131,039,552
CONDENSED BALANCE
SHEETS
JUNE 30, 2019 AND DECEMBER 31,
2018
(In thousands, except par value and
share data)
June 30, 2019
December 31, 2018
ASSETS
(Unaudited)
Current Assets:
Cash and Cash Equivalents
$
2,794
$
2,358
Accounts Receivable, Net
87,697
96,353
Advances to Operators
1,425
268
Prepaid Expenses and Other
8,226
12,360
Derivative Instruments
32,531
115,870
Income Tax Receivable
395
1,205
Total Current Assets
133,068
228,415
Property and Equipment:
Oil and Natural Gas Properties, Full Cost
Method of Accounting
Proved
3,607,214
3,431,428
Unproved
9,249
4,307
Other Property and Equipment
1,609
998
Total Property and Equipment
3,618,072
3,436,732
Less – Accumulated Depreciation, Depletion
and Impairment
(2,324,790
)
(2,233,987
)
Total Property and Equipment, Net
1,293,282
1,202,745
Derivative Instruments
26,610
61,843
Deferred Income Taxes
420
420
Acquisition Deposit
31,000
—
Other Noncurrent Assets, Net
10,012
10,223
Total Assets
$
1,494,391
$
1,503,645
LIABILITIES AND STOCKHOLDERS’
EQUITY
Current Liabilities:
Accounts Payable
$
175,164
$
135,483
Accrued Expenses
2,070
2,769
Accrued Interest
15,050
16,468
Debt Exchange Derivative
2,791
18,183
Derivative Instruments
95
—
Contingent Consideration
36,992
58,069
Other Current Liabilities
566
555
Total Current Liabilities
232,726
231,526
Long-term Debt, Net
857,198
830,203
Derivative Instruments
1,644
—
Asset Retirement Obligations
12,845
11,946
Other Noncurrent Liabilities
329
105
TOTAL LIABILITIES
$
1,104,742
$
1,073,780
COMMITMENTS AND CONTINGENCIES (NOTE
8)
STOCKHOLDERS’ EQUITY
Preferred Stock, Par Value $.001;
5,000,000 Authorized, No Shares Outstanding
—
—
Common Stock, Par Value $.001; 675,000,000
Shares Authorized; 389,435,991 Shares Outstanding at 6/30/2019
378,333,070 Shares Outstanding at 12/31/2018
389
378
Additional Paid-In Capital
1,248,906
1,226,371
Retained Deficit
(859,647
)
(796,884
)
Total Stockholders’ Equity
389,649
429,865
TOTAL LIABILITIES AND STOCKHOLDERS’
EQUITY
$
1,494,391
$
1,503,645
Non-GAAP Financial Measures
Adjusted Net Income and Adjusted EBITDA are non-GAAP measures.
Northern defines Adjusted Net Income (Loss) as net income (loss)
excluding (i) (gain) loss on the mark-to-market of derivative
instruments, net of tax, (ii) impairment of other current assets,
net of tax, (iii) loss on the extinguishment of debt, net of tax,
(iv) debt exchange derivative (gain) loss, net of tax, (v)
contingent consideration (gain) loss, net of tax, and (vi) certain
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 (gain) loss, and (ix) (gain) loss on the
mark-to-market of derivative instruments. 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 expenses and unrealized commodity
gains and losses that management believes are not indicative of
Northern’s core operating results. In addition, these non-GAAP
financial measures are used by management for budgeting and
forecasting as well as subsequently measuring Northern’s
performance, and management believes it is providing investors with
financial measures that most closely align to its internal
measurement processes.
Reconciliation of Adjusted Net Income
Three Months Ended June
30,
Six Months Ended June
30,
(In thousands, except share and per
share data)
2019
2018
2019
2018
Net Income (Loss)
$
44,399
$
(96,547
)
$
(62,762
)
$
(93,582
)
Add:
Impact of Selected Items:
(Gain) Loss on the Mark-to-Market of
Derivative Instruments
(31,857
)
29,936
120,311
42,077
Impairment of Other Current Assets
2,694
—
2,694
—
Loss on the Extinguishment of Debt
425
90,833
425
90,833
Debt Exchange Derivative (Gain) Loss
4,873
—
(1,413
)
—
Contingent Consideration (Gain) Loss
24,763
—
23,371
—
Acquisition Transaction Costs
513
—
513
—
Selected Items, Before Income Taxes
1,411
120,769
145,901
132,910
Income Tax of Selected Items(1)
(346
)
(6,180
)
(20,696
)
(9,912
)
Selected Items, Net of Income Taxes
$
1,065
$
114,589
$
125,205
$
122,998
Adjusted Net Income
$
45,465
$
18,042
$
62,443
$
29,417
Weighted Average Shares Outstanding –
Basic
378,368,462
196,140,610
374,927,630
131,039,552
Weighted Average Shares Outstanding –
Diluted
378,724,511
196,413,013
375,736,820
131,248,726
Net Income (Loss) Per Common Share –
Basic
$
0.12
$
(0.49
)
$
(0.17
)
$
(0.71
)
Add:
Impact of Selected Items, Net of Income
Taxes
—
0.58
0.33
0.93
Adjusted Net Income Per Common Share –
Basic
$
0.12
$
0.09
$
0.16
$
0.22
Net Income (Loss) Per Common Share –
Diluted
$
0.12
$
(0.49
)
$
(0.17
)
$
(0.71
)
Add:
Impact of Selected Items, Net of Income
Taxes
—
0.58
0.33
0.93
Adjusted Net Income Per Common Share –
Diluted
$
0.12
$
0.09
$
0.16
$
0.22
- For the three months ended June 30, 2019, this represents a tax
impact using an estimated tax rate of 24.5%, which does not include
an adjustment for a change in valuation allowance. For the six
months ended June 30, 2019, this represents a tax impact using an
estimated tax rate of 24.5%, and includes a $15.1 million
adjustment for an increase in valuation allowance. For the three
and six months ended June 30, 2018, this represents a tax impact
using an estimated tax rate of 24.5%, which includes an adjustment
of $23.4 million and $22.7 million, respectively, for a reduction
in valuation allowance.
Reconciliation of Adjusted EBITDA
Three Months Ended June
30,
Six Months Ended June
30,
(In thousands)
2019
2018
2019
2018
Net Income (Loss)
$
44,399
$
(96,547
)
$
(62,762
)
$
(93,582
)
Add:
Interest Expense
17,778
22,403
37,327
45,510
Income Tax Provision (Benefit)
—
—
—
—
Depreciation, Depletion, Amortization and
Accretion
46,091
22,596
91,225
41,227
Impairment of Other Current Assets
2,694
—
2,694
—
Non-Cash Stock-Based Compensation
1,643
1,324
4,394
438
Loss on the Extinguishment of Debt
425
90,833
425
90,833
Debt Exchange Derivative (Gain) Loss
4,873
—
(1,413
)
—
Contingent Consideration (Gain) Loss
24,763
—
23,371
—
(Gain) Loss on the Mark-to-Market of
Derivative Instruments
(31,857
)
29,936
120,311
42,077
Adjusted EBITDA
$
110,810
$
70,546
$
215,572
$
126,504
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version on businesswire.com: https://www.businesswire.com/news/home/20190801006037/en/
Nicholas O'Grady Chief Financial Officer 952-476-9800
ir@northernoil.com
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