HIGHLIGHTS
- Second quarter total production of 54,623 Boe per day, up 42%
sequentially from the first quarter of 2021
- Oil production of 33,346 Bbl per day, up 14% sequentially from
the first quarter of 2021
- Second quarter GAAP cash flow from operations of $106.2
million. Excluding changes in net working capital, cash flow from
operations was $118.4 million, up 42% from the first quarter of
2021
- Total capital expenditures of $68.4 million during the second
quarter, excluding the closing of the Marcellus acquisition on
April 1, 2021
- Free Cash Flow (non-GAAP) of $46.2 million, post-preferred
stock dividends. See “Non-GAAP Financial Measures” below
- Completed a 5.75 million share common stock offering to fund
the acquisition of over $100 million in core Permian Basin
acquisitions that signed during the second quarter, the last and
largest of which closed on August 2, 2021
- The Board of Directors has declared Northern’s second quarterly
common stock dividend of $0.045 per share, a 50% increase from the
prior quarter, payable October 29, 2021 to stockholders of record
on September 30, 2021
- Updated 2021 guidance includes increased annual production and
reduced capital expenditures
Northern Oil and Gas, Inc. (NYSE American: NOG) (“Northern”)
today announced the company’s second quarter results.
MANAGEMENT COMMENTS
“This was one of the strongest operational and financial
quarters on record for the Company,” commented Nick O’Grady,
Northern’s Chief Executive Officer. “Year-to-date Northern has
executed on several large bolt-on acquisitions and significantly
improved its balance sheet. With the active management of our
portfolio, we have driven substantial production and cash flow
growth. Our focus on return on capital and high-quality operators
and acreage is showing up directly on the bottom line. Our long
term plan remains unchanged: building a diversified, low-leverage
entity with the ability to deliver substantial cash returns. The
opportunity set for value creation in front of us is stronger than
ever.”
SECOND QUARTER FINANCIAL RESULTS
Oil and natural gas sales for the second quarter were $225.7
million, up 43% over the first quarter. Second quarter GAAP net
loss, inclusive of a $173.1 million non-cash net mark-to-market
loss on derivatives, was $90.6 million or $1.49 per diluted share.
Second quarter Adjusted Net Income was $65.0 million or $0.92 per
diluted share, up from $10.7 million or $0.21 per diluted share in
the prior year. Adjusted EBITDA in the second quarter was $132.8
million, up 35% from the first quarter of 2021. See “Non-GAAP
Financial Measures” below.
PRODUCTION
Second quarter production was 54,623 Boe per day, a 42% increase
from the first quarter of 2021. Oil represented 61% of total
production in the second quarter. Oil production was 33,346 Bbl per
day, a 14% increase over the first quarter. Northern has continued
to see stellar well performance above target and accelerated
development, with wells turning in-line ahead of schedule due to
strong strip prices. Northern had 10.5 net wells turned in-line
during the second quarter, compared to 6.7 net wells turned in-line
in the first quarter of 2021. Northern’s Marcellus properties
produced 63.0 MMcf per day in the second quarter, consistent with
expectations. The first EQT-operated wells came online in early
July 2021.
PRICING
During the second quarter, NYMEX West Texas Intermediate (“WTI”)
crude oil averaged $66.19 per Bbl, and NYMEX natural gas at Henry
Hub averaged $2.92 per million cubic feet (“Mcf”). Northern’s
unhedged net realized oil price in the second quarter was $60.73,
representing a $5.46 differential to WTI prices. Northern’s
unhedged net realized gas price in the second quarter was $3.57 per
Mcf, representing approximately 122% realizations compared with
Henry Hub pricing.
OPERATING COSTS
Lease operating costs were $42.7 million in the second quarter
of 2021, or $8.59 per Boe, down 13% on a per unit basis compared to
the first quarter of 2021. Reductions in costs were driven by the
closing of the Marcellus acquisition, partially offset by workover
costs and higher processing costs associated with the ramp in
overall production. Second quarter general and administrative
(“G&A”) costs totaled $7.6 million or $1.53 per Boe. This
includes $3.0 million of legal and other transaction expenses in
connection with the Marcellus acquisition and $0.8 million of
non-cash stock-based compensation. Northern’s G&A costs
excluding these amounts totaled $3.8 million or $0.77 per Boe in
the second quarter, record low unit costs for the Company.
CAPITAL EXPENDITURES AND ACQUISITIONS
Capital spending for the second quarter was $68.4 million, made
up of $41.9 million of organic drilling and completion (“D&C”)
capital and $26.5 million of total acquisition spending and other
items, inclusive of ground game D&C spending. Northern added
10.5 net wells to production in the second quarter. Wells in
process increased to 43.8 net wells at the end of the second
quarter, compared to 22.7 at the end of the first quarter, driven
by the acquisition of the Marcellus properties. On the ground game
acquisition front, Northern closed on 11 transactions during the
second quarter totaling 2.8 net wells, 624 net mineral acres, and
107 net royalty acres (standardized to a 1/8 royalty interest).
PERMIAN BASIN ACQUISITIONS
On June 16, 2021, Northern announced that it entered into three
definitive agreements to acquire non-operated interests across
approximately 2,900 net acres located in the heart of Lea and Eddy
Counties, New Mexico and Reeves County, Texas. The assets include
5.3 net producing wells, 5.0 net wells in process and an additional
23.1 net undrilled locations ascribed to the core zones including
the Wolfcamp A, Wolfcamp B and 1st through 3rd Bone Springs. The
assets are operated primarily by Mewbourne Oil Company, Colgate
Energy, ConocoPhillips and EOG Resources. The acquisitions were all
closed by August 2, 2021. Northern has updated corporate guidance
for the acquired assets in the guidance section below.
LIQUIDITY AND CAPITAL RESOURCES
Northern had total liquidity of $411.2 million as of June 30,
2021, consisting of cash of $4.8 million, the Permian acquisition
deposit of $9.4 million, and $397.0 million of committed borrowing
availability under the revolving credit facility.
In June 2021, Northern additionally strengthened its balance
sheet through a common equity transaction alongside of its
announcement of a series of Permian Basin acquisitions. Northern
issued 5.75 million shares of common equity for gross proceeds of
$100.2 million. On May 17, 2021, Northern redeemed and retired the
remaining $15.7 million of its 2023 Senior Notes.
On August 2, 2021, Northern funded the purchase price, including
typical closing adjustments, of $105.6 million for the largest of
its recently announced Permian acquisitions, funded in part by the
$9.4 million deposit made during the second quarter, and borrowings
under its credit facility.
STOCKHOLDER RETURNS
In April 2021, Northern’s Board of Directors declared all
current and accrued cash dividends for Northern’s Series A
Preferred Stock, paid on May 15, 2021 in the total amount of $22.0
million.
In May 2021, Northern’s Board of Directors declared its first
ever regular quarterly cash dividend for Northern’s common stock of
$0.03 per share for stockholders of record as of June 30, 2021,
payable July 30, 2021.
On August 3, 2021, Northern’s Board of Directors declared a
regular quarterly cash dividend for Northern’s common stock of
$0.045 per share for stockholders of record as of September 30,
2021, payable October 29, 2021. This represents a 50% increase from
the prior quarter.
2021 FULL YEAR GUIDANCE
(all forecasts are provided on a 2-stream production
basis)
Prior
Current
Annual Production (Boe per day)
47,167 - 53,424 (1)
49,500 - 54,250
Oil as a Percentage of Sales Volumes
62% - 64% (1)
63% - 64%
Net Wells Added to Production
35.5 - 37.8 (1)
38 - 40
Total Capital Expenditures (in millions)
(2)
$215 - $270
$215 - $260
_______________
(1)
Prior guidance did not include Permian
acquisitions which closed on August 2, 2021, and is calculated
based on April 1, 2021 closing of the Marcellus acquisition.
(2)
Excludes non-budgeted acquisitions of
Marcellus and Permian properties, but includes post-closing capital
expenditures.
Operating Expenses and
Differentials:
Prior
Current
Production Expenses (per Boe)
- (3)
$8.60 - $8.90
Production Taxes
10% of Net Oil Revenues, $0.06
per Mcf for Natural Gas
9% - 10% of Oil & Gas
Sales
Average Differential to NYMEX WTI (per
Bbl)
$6.50 - $8.50
$6.25 - $7.25
Average Realization as a Percentage of
NYMEX Henry Hub (per Mcf)
- (3)
80% - 100%
_______________
(3)
Northern did not previously provide full
corporate operating cost and gas realization guidance including the
Marcellus, Permian and Williston Properties.
Prior
Current
General and Administrative Expense (per
Boe):
Cash (excluding Marcellus and Permian
transaction costs)
$0.80 - $0.90
$0.80 - $0.85
Non-Cash
$0.20
$0.18
SECOND QUARTER 2021 RESULTS
The following tables set forth selected operating and financial
data for the periods indicated.
Three Months Ended June
30,
2021
2020
% Change
Net Production:
Oil (Bbl)
3,034,442
1,659,293
83
%
Natural Gas and NGLs (Mcf)
11,617,308
3,041,418
282
%
Total (Boe)
4,970,660
2,166,196
129
%
Average Daily Production:
Oil (Bbl)
33,346
18,234
83
%
Natural Gas and NGLs (Mcf)
127,663
33,422
282
%
Total (Boe)
54,623
23,804
129
%
Average Sales Prices:
Oil (per Bbl)
$
60.73
$
17.35
250
%
Effect of Gain (Loss) on Settled Oil
Derivatives on Average Price (per Bbl)
(8.16
)
46.19
Oil Net of Settled Oil Derivatives (per
Bbl)
52.57
63.54
(17
)%
Natural Gas and NGLs (per Mcf)
3.57
(2.67
)
Effect of Gain (Loss) on Settled Natural
Gas Derivatives on Average Price (per Mcf)
(0.27
)
0.26
Natural Gas and NGLs Net of Settled
Natural Gas Derivatives (per Mcf)
3.30
(2.41
)
Realized Price on a Boe Basis Excluding
Settled Commodity Derivatives
45.41
9.54
376
%
Effect of Gain (Loss) on Settled Commodity
Derivatives on Average Price (per Boe)
(5.60
)
35.75
Realized Price on a Boe Basis Including
Settled Commodity Derivatives
39.81
45.29
(12
)%
Costs and Expenses (per Boe):
Production Expenses
$
8.59
$
12.30
(30
)%
Production Taxes
3.72
0.89
318
%
General and Administrative Expenses
1.53
2.17
(29
)%
Depletion, Depreciation, Amortization and
Accretion
6.22
16.97
(63
)%
Net Producing Wells at Period
End
588.6
466.0
26
%
HEDGING
Northern hedges portions of its expected production volumes to
increase the predictability of its cash flow and to help maintain a
strong financial position. The following table summarizes
Northern’s open crude oil commodity derivative swap contracts
scheduled to settle after June 30, 2021.
Crude Oil Commodity Derivative
Swaps(1)
Contract Period
Volume (Bbls)
Volume (Bbls/Day)
Weighted Average Price (per
Bbl)
2021:
Q3
2,197,260
23,883
$54.63
Q4
2,200,706
23,921
$54.26
2022:
Q1
1,968,730
21,875
$55.80
Q2
1,865,500
20,500
$56.42
Q3
1,886,000
20,500
$55.89
Q4
1,748,000
19,000
$55.48
2023:
Q1
472,500
5,250
$57.92
Q2
295,750
3,250
$60.54
_______________
(1)
This table does not include volumes
subject to swaptions and call options, which could increase the
amount of volumes hedged at the option of Northern’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-Q filed with the SEC for the quarter ended
June 30, 2021.
The following table summarizes Northern’s open natural gas
commodity derivative swap contracts scheduled to settle after June
30, 2021.
Natural Gas Commodity
Derivative Swaps
Contract Period
Gas (MMBTU)
Volume (MMBTU/Day)
Weighted Average Price (per
Mcf)
2021:
Q3
8,979,028
97,598
$2.82
Q4
8,784,210
95,481
$2.82
2022:
Q1
6,257,291
69,525
$3.07
Q2
5,460,000
60,000
$2.95
Q3
5,520,000
60,000
$2.95
Q4
4,300,000
46,739
$2.94
The following table presents Northern’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 Northern’s statement of
operations:
Three Months Ended June
30,
Six Months Ended June
30,
(In thousands)
2021
2020
2021
2020
Cash Received (Paid) on Derivatives:
$
(27,855)
$
77,439
$
(35,152)
$
108,944
Non-Cash Gain (Loss) on Derivatives:
(173,057)
(150,077)
(301,695)
194,999
Gain (Loss) on Derivative Instruments,
Net
$
(200,912)
$
(72,638)
$
(336,847)
$
303,943
CAPITAL EXPENDITURES & DRILLING ACTIVITY
(In millions, except for net well
data)
Three Months Ended June 30,
2021
Capital Expenditures Incurred:
Organic Drilling and Development Capital
Expenditures
$
41.9
Ground Game Drilling and Development
Capital Expenditures
$
7.0
Ground Game Acquisition Capital
Expenditures
$
17.7
Other
$
1.9
Marcellus Acquisition
$
149.7
Net Wells Added to Production
10.5
Net Producing Wells (Period-End)
588.6
Net Wells in Process (Period-End)
43.8
Increase in Wells in Process over Prior
Period
21.0
Weighted Average Gross AFE for Wells
Elected to
$6.4 million
SECOND QUARTER 2021 EARNINGS RELEASE CONFERENCE CALL
In conjunction with Northern’s release of its financial and
operating results, investors, analysts and other interested parties
are invited to listen to a conference call with management on
Thursday, August 5, 2021 at 10:00 a.m. Central Time.
Those wishing to listen to the conference call may do so via
webcast or phone as follows:
Webcast:
https://78449.themediaframe.com/dataconf/productusers/nog/mediaframe/46117/indexl.html
Dial-In Number: (866) 373-3407
(US/Canada) and (412) 902-1037 (International) Conference ID: 13721948 - Northern Oil and Gas,
Inc. Second Quarter 2021 Earnings Call Replay
Dial-In Number: (877) 660-6853 (US/Canada) and (201)
612-7415 (International) Replay Access
Code: 13721948 - Replay will be available through August 12,
2021
UPCOMING CONFERENCE SCHEDULE
Enercom
Denver, CO
August 16-17, 2021
Bank of America E&P Bus Tour
August 24, 2021
ABOUT NORTHERN OIL AND GAS
Northern Oil and Gas, Inc. is a company with a primary strategy
of investing in non-operated minority working and mineral interests
in oil & gas properties, with a core area of focus in the
premier basins within the United States. More information about
Northern Oil and Gas, Inc. can be found at www.northernoil.com.
SAFE HARBOR
This press release contains forward-looking statements regarding
future events and future results that are subject to the safe
harbors created under the Securities Act of 1933 (the “Securities
Act”) and the Securities Exchange Act of 1934 (the “Exchange Act”).
All statements other than statements of historical facts included
in this release regarding Northern’s financial position, operating
and financial performance, business strategy, plans and objectives
of management for future operations, industry conditions, and
indebtedness covenant compliance are forward-looking statements.
When used in this release, forward-looking statements are generally
accompanied by terms or phrases such as “estimate,” “project,”
“predict,” “believe,” “expect,” “continue,” “anticipate,” “target,”
“could,” “plan,” “intend,” “seek,” “goal,” “will,” “should,” “may”
or other words and similar expressions that convey the uncertainty
of future events or outcomes. Items contemplating or making
assumptions about actual or potential future 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
Northern’s control) that could cause actual results to differ
materially from those set forth in the forward-looking statements,
including the following: changes in crude oil and natural gas
prices; the pace of drilling and completions activity on Northern’s
properties and properties pending acquisition; Northern’s ability
to acquire additional development opportunities; potential or
pending acquisition transactions; Northern’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 Northern’s
acquisition transactions; integration and benefits of property
acquisitions, or the effects of such acquisitions on Northern’s
cash position and levels of indebtedness; changes in Northern’s
reserves estimates or the value thereof; disruptions to Northern’s
business due to acquisitions and other significant transactions;
infrastructure constraints and related factors affecting Northern’s
properties; 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 Northern conducts business;
changes in the interest rate environment, legislation or regulatory
requirements; conditions of the securities markets; Northern’s
ability to raise or access capital; changes in accounting
principles, policies or guidelines; and financial or political
instability, health-related epidemics, acts of war or terrorism,
and other economic, competitive, governmental, regulatory and
technical factors affecting Northern’s operations, products and
prices.
Northern has based these forward-looking statements on its
current expectations and assumptions about future events. While
management considers these expectations and assumptions to be
reasonable, they are inherently subject to significant business,
economic, competitive, regulatory and other risks, contingencies
and uncertainties, most of which are difficult to predict and many
of which are beyond Northern’s control. Northern does not undertake
any duty to update or revise any forward-looking statements, except
as may be required by the federal securities laws.
CONDENSED STATEMENTS OF
OPERATIONS
(UNAUDITED)
Three Months Ended June
30,
Six Months Ended June
30,
(In thousands, except share and per
share data)
2021
2020
2021
2020
Revenues
Oil and Gas Sales
$
225,717
$
20,664
$
383,048
$
150,860
Gain (Loss) on Commodity Derivatives,
Net
(200,912
)
(72,638
)
(336,847
)
303,943
Other Revenue
—
3
1
12
Total Revenues
24,805
(51,971
)
46,202
454,815
Operating Expenses
Production Expenses
42,699
26,638
77,010
63,974
Production Taxes
18,514
1,917
31,967
13,813
General and Administrative Expense
7,604
4,710
14,388
9,580
Depletion, Depreciation, Amortization and
Accretion
30,908
36,756
62,128
98,565
Impairment Expense
—
762,716
—
762,716
Total Operating Expenses
99,725
832,737
185,493
948,648
Loss From Operations
(74,920
)
(884,708
)
(139,291
)
(493,833
)
Other Income (Expense)
Interest Expense, Net of
Capitalization
(15,024
)
(13,957
)
(28,534
)
(30,508
)
Gain (Loss) on Unsettled Interest Rate
Derivatives, Net
121
(752
)
362
(1,429
)
Gain (Loss) on Extinguishment of Debt,
Net
(494
)
217
(13,087
)
(5,310
)
Contingent Consideration Loss
(250
)
—
(375
)
—
Other Income (Expense)
4
—
5
—
Total Other Income (Expense)
(15,643
)
(14,492
)
(41,629
)
(37,247
)
Loss Before Income Taxes
(90,563
)
(899,200
)
(180,920
)
(531,080
)
Income Tax Provision (Benefit)
—
—
—
(166
)
Net Loss
$
(90,563
)
$
(899,200
)
$
(180,920
)
$
(530,914
)
Cumulative Preferred Stock Dividend
(3,719
)
(3,788
)
(7,550
)
(7,517
)
Net Loss Attributable to Common
Stockholders
$
(94,282
)
$
(902,988
)
$
(188,470
)
$
(538,431
)
Net Loss Per Common Share – Basic*
$
(1.55
)
$
(21.74
)
$
(3.27
)
$
(13.15
)
Net Loss Per Common Share – Diluted*
$
(1.55
)
$
(21.74
)
$
(3.27
)
$
(13.15
)
Weighted Average Common Shares Outstanding
– Basic*
60,694,795
41,535,601
57,633,454
40,950,927
Weighted Average Common Shares Outstanding
– Diluted*
60,694,795
41,535,601
57,633,454
40,950,927
_______________
*Adjusted for the 1-for-10 reverse stock
split.
CONDENSED BALANCE
SHEETS
(In thousands, except par value and
share data)
June 30, 2021
December 31, 2020
Assets
(Unaudited)
Current Assets:
Cash and Cash Equivalents
$
4,843
$
1,428
Accounts Receivable, Net
131,165
71,015
Advances to Operators
433
476
Prepaid Expenses and Other
2,705
1,420
Derivative Instruments
518
51,290
Total Current Assets
139,664
125,629
Property and Equipment:
Oil and Natural Gas Properties, Full Cost
Method of Accounting
Proved
4,638,415
4,393,533
Unproved
21,347
10,031
Other Property and Equipment
2,501
2,451
Total Property and Equipment
4,662,263
4,406,015
Less – Accumulated Depreciation, Depletion
and Impairment
(3,732,183
)
(3,670,811
)
Total Property and Equipment, Net
930,080
735,204
Derivative Instruments
32
111
Acquisition Deposit
9,400
—
Other Noncurrent Assets, Net
12,634
11,145
Total Assets
$
1,091,810
$
872,089
Liabilities and Stockholders' Equity
(Deficit)
Current Liabilities:
Accounts Payable
$
49,186
$
35,803
Accrued Liabilities
91,724
68,673
Accrued Interest
16,877
8,341
Derivative Instruments
140,694
3,078
Contingent Consideration
513
493
Current Portion of Long-term Debt
—
65,000
Other Current Liabilities
1,843
1,087
Total Current Liabilities
300,837
182,475
Long-term Debt
801,998
879,843
Derivative Instruments
127,526
14,659
Asset Retirement Obligations
26,176
18,366
Other Noncurrent Liabilities
3,490
50
Total Liabilities
$
1,260,027
$
1,095,393
Commitments and Contingencies (Note
8)
Stockholders’ Equity (Deficit)
Preferred Stock, Par Value $.001;
5,000,000 Shares Authorized;
2,218,732 Series A Shares Outstanding at
6/30/2021
2,218,732 Series A Shares Outstanding at
12/31/2020
2
2
Common Stock, Par Value $.001;
135,000,000* Shares Authorized;
66,164,399* Shares Outstanding at
6/30/2021
45,908,779* Shares Outstanding at
12/31/2020
468
448
Additional Paid-In Capital
1,792,589
1,556,602
Retained Deficit
(1,961,276
)
(1,780,356
)
Total Stockholders’ Equity (Deficit)
(168,217
)
(223,304
)
Total Liabilities and Stockholders’
Equity (Deficit)
$
1,091,810
$
872,089
_______________
*Adjusted for the 1-for-10 reverse stock
split.
Non-GAAP Financial Measures
Adjusted Net Income, Adjusted EBITDA and Free Cash Flow are
non-GAAP measures. Northern defines Adjusted Net Income (Loss) as
net income (loss) excluding (i) (gain) loss on unsettled commodity
derivatives, net of tax, (ii) loss on extinguishment of debt, net
of tax, (iii) contingent consideration loss, net of tax, (iv)
acquisition transaction costs, net of tax, and (v) gain on
unsettled interest rate derivatives, net of tax. Northern defines
Adjusted EBITDA as net income (loss) before (i) interest expense,
(ii) income taxes, (iii) depreciation, depletion, amortization and
accretion, (iv) non-cash stock-based compensation expense, (v) loss
on extinguishment of debt, (vi) contingent consideration loss,
(vii) acquisition transaction costs, (viii) (gain) loss on
unsettled commodity derivatives, (ix) gain (loss) on unsettled
interest rate derivatives, and (x) impairment expense. Northern
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.
Management believes the use of these non-GAAP financial measures
provides useful information to investors to gain an overall
understanding of current financial performance. Management believes
Adjusted Net Income and Adjusted EBITDA 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. Management
believes that Free Cash Flow is useful to investors as a measure of
a company’s ability to internally fund its budgeted capital
expenditures, to service or incur additional debt, and to measure
success in creating stockholder value. 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. The non-GAAP financial measures included
herein may be defined differently than similar measures used by
other companies and should not be considered an alternative to, or
more meaningful than, the comparable GAAP measures. From time to
time Northern provides forward-looking Free Cash Flow estimates or
targets; however, Northern is unable to provide a quantitative
reconciliation of the forward looking non-GAAP measure to its most
directly comparable forward looking GAAP measure because management
cannot reliably quantify certain of the necessary components of
such forward looking GAAP measure. The reconciling items in future
periods could be significant.
Reconciliation of Adjusted Net
Income
Three Months Ended June
30,
Six Months Ended June
30,
(In thousands, except share and per
share data)
2021
2020
2021
2020
Net Loss
$
(90,563
)
$
(899,200
)
$
(180,920
)
$
(530,914
)
Add:
Impact of Selected Items:
(Gain) Loss on Unsettled Commodity
Derivatives
173,057
150,077
301,695
(194,999
)
(Gain) Loss on Extinguishment of Debt
494
(217
)
13,087
5,310
Contingent Consideration Loss
250
—
375
—
Acquisition Transaction Costs
3,016
—
5,527
—
(Gain) Loss on Unsettled Interest Rate
Derivatives
(121
)
752
(362
)
1,429
Selected Items, Before Income Taxes
176,695
913,328
320,323
574,456
Income Tax of Selected Items(1)
(21,102
)
(3,461
)
(34,154
)
(10,668
)
Selected Items, Net of Income Taxes
155,593
909,866
286,169
563,788
Adjusted Net Income
$
65,030
$
10,667
$
105,249
$
32,874
Weighted Average Shares Outstanding –
Basic
60,694,795
41,535,601
57,633,454
40,950,927
Weighted Average Shares Outstanding –
Diluted
70,526,168
51,556,972
67,457,298
50,989,784
Net Income (Loss) Per Common Share –
Basic
$
(1.49
)
$
(21.65
)
$
(3.14
)
$
(12.96
)
Add:
Impact of Selected Items, Net of Income
Taxes
2.56
21.91
4.97
13.76
Adjusted Net Income Per Common Share –
Basic
$
1.07
$
0.26
$
1.83
$
0.80
Net Income (Loss) Per Common Share –
Diluted
$
(1.28
)
$
(17.44
)
$
(2.68
)
$
(10.41
)
Add:
Impact of Selected Items, Net of Income
Taxes
2.20
17.65
4.24
11.05
Adjusted Net Income Per Common Share –
Diluted
$
0.92
$
0.21
$
1.56
$
0.64
_______________
(1)
For the three and six months ended June
30, 2021, this represents a tax impact using an estimated tax rate
of 24.5%, which includes an adjustment of $22.2 million and $44.3
million, respectively, for a change in valuation allowance. For the
three and six months ended June 30, 2020, this represents a tax
impact using an estimated tax rate of 24.5%, which includes an
adjustment of $220.3 million and $130.1 million, respectively, for
a change in valuation allowance.
Reconciliation of Adjusted
EBITDA
Three Months Ended June
30,
Six Months Ended June
30,
(In thousands)
2021
2020
2021
2020
Net Loss
$
(90,563
)
$
(899,200
)
$
(180,920
)
$
(530,914
)
Add:
Interest Expense
15,024
13,957
28,534
30,508
Income Tax Provision (Benefit)
—
—
—
(166
)
Depreciation, Depletion, Amortization and
Accretion
30,908
36,756
62,128
98,565
Non-Cash Stock-Based Compensation
779
1,214
—
2,293
(Gain) Loss on Extinguishment of Debt
494
(217
)
13,087
5,310
Contingent Consideration Loss
250
—
375
—
Acquisition Transaction Costs
3,016
—
5,527
—
(Gain) Loss on Unsettled Interest Rate
Derivatives
(121
)
752
(362
)
1,429
(Gain) Loss on Unsettled Commodity
Derivatives
173,057
150,077
301,695
(194,999
)
Impairment Expense
—
762,716
—
762,716
Adjusted EBITDA
$
132,844
$
66,055
$
231,614
$
174,742
Reconciliation of Free Cash
Flow
Three Months Ended June
30,
(In thousands)
2021
Net Cash Provided by Operating
Activities
$
106,186
Exclude: Changes in Working Capital and
Other Items
12,204
Less: Capital Expenditures (1)
(68,445
)
Less: Series A Preferred Dividends
(3,719
)
Free Cash Flow
$
46,226
_______________
(1) Capital expenditures are calculated as
follows:
Three Months Ended June
30,
(In thousands)
2021
Cash Paid for Capital Expenditures
$
169,679
Less: Non-Budgeted Acquisitions
(119,207
)
Plus: Change in Accrued Capital
Expenditures and Other
17,973
Capital Expenditures
$
68,445
View source
version on businesswire.com: https://www.businesswire.com/news/home/20210805005258/en/
Mike Kelly, CFA Chief Strategy Officer 952-476-9800
mkelly@northernoil.com
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