HIGHLIGHTS
- Total debt reduced by $52.2 million in the second quarter,
resulting in over $3 million in interest savings per annum
- Strong risk management drove realized commodity hedge gains of
$77.4 million in the second quarter
- Cash flow from operations totaled $53.1 million, excluding
$48.5 million received from changes in working capital
- Total capital expenditures were $34.5 million in the second
quarter
- Wells in process remain near record levels at 26.7 net
wells
- Production averaged 23,804 barrels of oil equivalent (“Boe”)
per day, driven by material curtailments and shut-ins
- Approximately 26,500 barrels per day of remaining 2020 oil
hedged at over $58 per barrel (“Bbl”) average prices
- Approximately 21,500 barrels per day of 2021 oil hedged at over
$54.50 per Bbl average prices
Northern Oil and Gas, Inc. (NYSE American: NOG) (“Northern”)
today announced the company’s second quarter results.
MANAGEMENT COMMENTS
“In one of the most challenging quarters for the oil industry in
decades, Northern’s unique, actively managed working-interest
business model continues to deliver,” commented Nick O’Grady,
Northern’s Chief Executive Officer. “Hedges protected cash flows
despite the turmoil, and capital spending reductions were
instituted rapidly. We continued to reduce our debt levels, and
carefully and methodically have added to our portfolio to build for
future growth and returns.”
SECOND QUARTER FINANCIAL RESULTS
Second quarter Adjusted Net Income was $10.7 million or $0.02
per diluted share. Second quarter GAAP net loss was $899.2 million
or $2.17 per diluted share, driven in large part by non-cash items:
a $762.7 million impairment expense and a $150.1 million
mark-to-market loss on unsettled commodity derivatives. Cash flow
from operations was $53.1 million in the second quarter, excluding
$48.5 million received from changes in working capital. Adjusted
EBITDA in the second quarter was $66.1 million. (See “Non-GAAP
Financial Measures” below.)
PRODUCTION
Second quarter production was 23,804 Boe per day. Oil production
represented 77% of total production at 18,234 Bbls per day.
Production declined due to decisions by many of Northern’s
operating partners to shut-in or curtail production and defer
development plans as a result of the low commodity price
environment. Northern estimates that curtailments, shut-ins and
delayed well completions reduced the Company’s average daily
production by approximately 16,800 Boe per day in the second
quarter. Northern had only 1.3 net wells turned online during the
second quarter, compared to 7.3 net wells turned online in the
first quarter of 2020.
PRICING
During the second quarter, NYMEX West Texas Intermediate (“WTI”)
crude oil averaged $27.95 per Bbl, and NYMEX natural gas at Henry
Hub averaged $1.70 per million cubic feet (“Mcf”). Northern’s
unhedged net realized oil price in the second quarter was $17.35,
representing a $10.60 differential to WTI prices. Oil differentials
were extremely wide in the month of May, but improved significantly
in June. Northern’s second quarter unhedged net realized gas price
was $(2.67) per Mcf, representing approximately (157)% realizations
compared with Henry Hub pricing. The dislocation in natural gas and
NGL prices was due to physical storage constraints, which created
negative pricing for NGL products as demand collapsed due primarily
to the COVID-19 pandemic. Higher compression, gathering, and
processing charges that were in excess of natural gas and NGL sales
prices additionally contributed to negative realized pricing.
OPERATING COSTS
Lease operating costs were $26.6 million in the second quarter
of 2020 compared to $37.3 million in the first quarter of 2020
driven by a 46% reduction in production volumes, partially offset
by increased processing and salt water disposal costs. Northern
expects further cost reductions will be realized in the third
quarter. Second quarter general and administrative (“G&A”)
costs totaled $4.7 million, which includes non-cash stock-based
compensation. Cash G&A expense totaled $3.5 million or $1.61
per Boe in the second quarter versus $3.8 million in the first
quarter of 2020, primarily due to lower professional fees.
CAPITAL EXPENDITURES AND ACQUISITIONS
Capital spending for the second quarter was $34.5 million, made
up of $32.7 million of organic D&C capital and $1.8 million of
total acquisition spending and other, inclusive of ground game
D&C spending. As mentioned above, Northern added 1.3 net wells
to production in the second quarter, and wells in process ended at
26.7 net wells. On the ground game acquisition front, Northern
closed on three transactions during the second quarter totaling 0.2
net wells and 124 net mineral acres.
Northern has previously announced several third quarter
acquisitions. Subsequent to the closing of the second quarter,
Northern has agreed to acquire or acquired 0.7 net producing wells,
3.9 net wells in process, and approximately 763 net acres for a
total consideration of $4.6 million and 2.95 million shares of
common stock, with an additional 0.45 million shares contingent on
continued operation of the Dakota Access Pipeline. Pro forma for
the closing of these transactions, Northern anticipates wells in
process as of July 31, 2020, to total 30.3 net wells. Year to date,
Northern’s ground game acquisitions that have been committed to or
closed have contributed a total of 8.4 net wells that are either
producing or in process, and added 1,852 net acres.
LIQUIDITY AND CAPITAL RESOURCES
As of June 30, 2020, Northern had $1.8 million in cash and
$568.0 million outstanding on its revolving credit facility. As
previously announced, Northern completed a semi-annual borrowing
base redetermination under its revolving credit facility on July 8,
2020, with the borrowing base set at $660.0 million. Pro forma for
the new borrowing base, Northern had total liquidity of $93.8
million as of June 30, 2020, consisting of cash and borrowing
availability under the revolving credit facility.
As of June 30, 2020, Northern had additional debt outstanding
consisting of a $130.0 million 6% Senior Unsecured Note and $297.3
million of 8.5% Senior Secured Notes. During the second quarter,
Northern strengthened its balance sheet through several agreements
with noteholders, which resulted in $30.2 million in principal
amount of the 8.5% Senior Secured Notes being retired.
Since the end of the second quarter, Northern has entered into
additional agreements that, when closed, will reduce the principal
amount of the 8.5% Senior Secured Notes by an additional $4.0
million and reduce the liquidation value of its outstanding
Preferred Stock by $7.6 million.
2020 GUIDANCE
3Q:20
4Q:20
Production (Boe/day)
22,500 - 30,000
30,000 - 40,000
Capital Expenditures (2H:20)
$50 - $75 million
Northern is beginning to see a slow but steady return of
curtailed and shut-in production to sales since the end of the
second quarter. Northern projects production of 22,500 - 30,000 Boe
per day in the third quarter and 30,000 - 40,000 Boe per day in the
fourth quarter. Total capital expenditures are currently expected
to be approximately $50 - 75 million in the second half of 2020,
inclusive of ground game and acquisitions. This guidance assumes
only 3.6 net wells turned in line in the second half of 2020.
Northern reiterates its previous guidance for total 2020 capital
spending of $175 - 200 million, with a reserve completion budget of
$50 million.
2021 COMMENTARY
Looking out to 2021, Northern expects to benefit from carrying a
near record number of wells in process (“WIP”). As of July 31,
2020, Northern had 28.6 net WIPs including approximately 6 net
wells completed but not turned in line, and management projects its
WIP count to exceed 30 net wells by year-end 2020. Northern’s
ability as a non-operator to continue to build high quality
inventory, despite an 80% reduction in the Williston rig count, is
a testament to the active management of its capital development
program.
Northern’s base case for 2021 presupposes that production
curtailments will continue to subside and that completion activity
will steadily increase starting late in the fourth quarter of 2020.
Under this scenario, Northern expects to see production approaching
40,000 Boe per day by early 2021, nearing volume levels seen in
early 2020. Furthermore, given the Company’s continued success on
the ground game front, which continues to build the number of wells
in process to near record levels, Northern forecasts that this
level of production should be maintained throughout the remainder
of 2021 on a capital budget of approximately $190 - 240 million.
Under this scenario, Northern sees both Adjusted EBITDA and free
cash flow at similar or higher levels to 2020, despite lower hedge
values at recent strip prices.
Given the volatility in the sector, significant uncertainty
remains and actual results will be driven by the timing of
curtailments and shut-ins returning to sales, completed wells
turned to sales and wells in process being completed and producing.
Northern’s downside case, which assumes a slower WIP completion
pace and little new drilling activity, would be expected to drive
$40 - $60 million of lower capital spending but still generate
production in excess of 35,000 Boe per day for 2021.
SECOND QUARTER 2020 RESULTS
The following tables set forth selected operating and financial
data for the periods indicated.
Three Months Ended June
30,
2020
2019
% Change
Net Production:
Oil (Bbl)
1,659,293
2,562,513
(35)
%
Natural Gas and NGLs (Mcf)
3,041,418
3,715,936
(18)
%
Total (Boe)
2,166,196
3,181,835
(32)
%
Average Daily Production:
Oil (Bbl)
18,234
28,159
(35)
%
Natural Gas and NGLs (Mcf)
33,422
40,834
(18)
%
Total (Boe)
23,804
34,965
(32)
%
Average Sales Prices:
Oil (per Bbl)
$
17.35
$
54.56
(68)
%
Effect of Gain on Settled Oil Derivatives
on Average Price (per Bbl)
46.19
1.85
Oil Net of Settled Oil Derivatives (per
Bbl)
63.54
56.41
13
%
Natural Gas and NGLs (per Mcf)
(2.67)
2.70
Effect of Gain on Settled Natural Gas
Derivatives on Average Price (per Mcf)
0.26
—
Natural Gas and NGLs Net of Settled
Natural Gas Derivatives (per Mcf)
(2.41)
2.70
Realized Price on a Boe Basis Excluding
Settled Commodity Derivatives
9.54
47.09
(80)
%
Effect of Gain on Settled Commodity
Derivatives on Average Price (per Boe)
35.75
1.49
Realized Price on a Boe Basis Including
Settled Commodity Derivatives
45.29
48.58
(7)
%
Costs and Expenses (per Boe):
Production Expenses
$
12.30
$
8.21
50
%
Production Taxes
0.89
4.41
(80)
%
General and Administrative Expenses
2.17
1.65
32
%
Depletion, Depreciation, Amortization and
Accretion
16.97
14.49
17
%
Net Producing Wells at Period
End
466.0
340.6
37
%
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 contracts scheduled
to settle after June 30, 2020.
Crude Oil Commodity Derivative
Swaps(1)
Contract Period
Volume (Bbls)
Volume (Bbls/Day)
Weighted Average Price (per
Bbl)
2020:
3Q
2,501,348
27,189
$58.47
4Q
2,372,362
25,787
$58.03
2021:
1Q
2,201,250
24,458
$55.53
2Q
1,997,458
21,950
$55.88
3Q
1,809,410
19,668
$53.46
4Q
1,800,506
19,571
$53.47
_____________
(1)
This table does not reflect additional
potential hedged volumes under “swaption” contracts, which are
crude oil derivative contracts entered into by Northern that give
counterparties the option to extend certain current derivative
contracts for additional periods. Based on current pricing, none of
these swaptions would be expected to be exercised.
The following table summarizes Northern’s open natural gas
commodity derivative contracts scheduled to settle after June 30,
2020.
Natural Gas Commodity
Derivative Swaps
Contract Period
Gas (MMBTU)
Volume (MMBTU/Day)
Weighted Average Price (per
Mcf)
2020:
3Q
1,610,000
17,500
$2.35
4Q
1,610,000
17,500
$2.35
2021:
1Q
2,700,000
30,000
$2.43
2Q
2,275,000
25,000
$2.43
3Q
2,300,000
25,000
$2.43
4Q
2,300,000
25,000
$2.43
CAPITAL EXPENDITURES & DRILLING ACTIVITY
(In millions, except for net well
data)
Three Months Ended June 30,
2020
Six Months Ended June
30, 2020
Capital Expenditures Incurred:
Organic Drilling and Development Capital
Expenditures
$
32.7
$
97.5
Ground Game Drilling and Development
Capital Expenditures
$
0.3
$
14.3
Ground Game Acquisition Capital
Expenditures
$
0.3
$
7.5
Other
$
1.1
$
1.9
Net Wells Added to Production
1.3
8.6
Net Producing Wells (Period-End)
—
466.0
Net Wells in Process (Period-End)
—
26.7
Increase in Wells in Process over Prior
Period
(0.5)
0.9
Weighted Average AFE for Wells Elected to
Year-to-Date
$7.7 million
$7.6 million
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 0.9 in net wells in process during the six months ended
June 30, 2020 are reflected in the amounts incurred year-to-date
for drilling and development capital expenditures.
ACREAGE
As of June 30, 2020, Northern controlled leasehold of
approximately 182,899 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 2020 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 7, 2020 at 10:00 a.m. Central Time.
Those wishing to listen to the conference call may do so via the
company’s website, www.northernoil.com, or by phone as follows:
Website:
https://78449.themediaframe.com/dataconf/productusers/nog/mediaframe/39975/indexl.html
Dial-In Number: (866) 373-3407
(US/Canada) and (412) 902-1037 (International) Conference ID: 13707746 - Northern Oil and Gas,
Inc. Second Quarter 2020 Earnings Call Replay
Dial-In Number: (877) 660-6853 (US/Canada) and (201)
612-7415 (International) Replay Access
Code: 13707746 - Replay will be available through August 14,
2020
UPCOMING CONFERENCE SCHEDULE
CFA Society Minnesota Intellisight Investor Day August 12,
2020
Enercom Oil and Gas Conference August 17, 2020
Seaport Global Summer Investor Conference August 26, 2020
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
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, 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 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: the effects of the COVID-19 pandemic and
related economic slowdown, changes in crude oil and natural gas
prices, the pace of drilling and completions activity on Northern’s
current properties, infrastructure constraints and related factors
affecting Northern’s properties, ongoing legal disputes over and
potential shutdown of the Dakota Access Pipeline, Northern’s
ability to acquire additional development opportunities, Northern’s
ability to consummate any pending acquisition transactions, other
risks and uncertainties related to the closing of pending
acquisition transactions, changes in Northern’s reserves estimates
or the value thereof, general economic or industry conditions,
nationally and/or in the communities in which Northern conducts
business, changes in the interest rate environment, legislation or
regulatory requirements, conditions of the securities markets,
Northern’s ability to raise or access capital, changes in
accounting principles, policies or guidelines, financial or
political instability, 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)
2020
2019
2020
2019
Revenues
Oil and Gas Sales
$
20,664
$
149,847
$
150,860
$
282,530
Gain (Loss) on Commodity Derivatives,
Net
(72,638)
36,591
303,943
(103,031)
Other Revenue
3
2
12
7
Total Revenues
(51,971)
186,440
454,815
179,506
Operating Expenses
Production Expenses
26,638
26,132
63,974
50,799
Production Taxes
1,917
14,034
13,813
26,553
General and Administrative Expense
4,710
5,250
9,580
11,300
Depletion, Depreciation, Amortization and
Accretion
36,756
46,091
98,565
91,225
Impairment of Other Current Assets
—
2,694
—
2,694
Impairment Expense
762,716
—
762,716
—
Total Operating Expenses
832,737
94,200
948,648
182,571
Income (Loss) From Operations
(884,708)
92,239
(493,833)
(3,065)
Other Income (Expense)
Interest Expense, Net of
Capitalization
(13,957)
(17,778)
(30,508)
(37,327)
Loss on Unsettled Interest Rate
Derivatives, Net
(752)
—
(1,429)
—
Gain (Loss) on Extinguishment of Debt,
Net
217
(425)
(5,310)
(425)
Debt Exchange Derivative Gain/(Loss)
—
(4,873)
—
1,413
Contingent Consideration Loss
—
(24,763)
—
(23,371)
Other Income (Expense)
—
(1)
—
14
Total Other Income (Expense)
(14,492)
(47,840)
(37,247)
(59,696)
Income (Loss) Before Income
Taxes
(899,200)
44,399
(531,080)
(62,762)
Income Tax Provision (Benefit)
—
—
(166)
—
Net Income (Loss)
$
(899,200)
$
44,399
$
(530,914)
$
(62,762)
Cumulative Preferred Stock Dividend
(3,788)
—
(7,517)
—
Net Income (Loss) Attributable to
Common Shareholders
$
(902,988)
$
44,399
$
(538,431)
$
(62,762)
Net Income (Loss) Per Common Share –
Basic
$
(2.17)
$
0.12
$
(1.31)
$
(0.17)
Net Income (Loss) Per Common Share –
Diluted
$
(2.17)
$
0.12
$
(1.31)
$
(0.17)
Weighted Average Common Shares Outstanding
– Basic
415,356,043
378,368,462
409,509,292
374,927,630
Weighted Average Common Shares Outstanding
– Diluted
415,356,043
378,724,511
409,509,292
374,927,630
CONDENSED BALANCE
SHEETS
(In thousands, except par value and
share data)
June 30, 2020
December 31, 2019
Assets
(Unaudited)
Current Assets:
Cash and Cash Equivalents
$
1,838
$
16,068
Accounts Receivable, Net
43,408
108,274
Advances to Operators
788
893
Prepaid Expenses and Other
2,204
1,964
Derivative Instruments
156,436
5,628
Income Tax Receivable
420
210
Total Current Assets
205,094
133,037
Property and Equipment:
Oil and Natural Gas Properties, Full Cost
Method of Accounting
Proved
4,300,151
4,178,605
Unproved
10,681
11,047
Other Property and Equipment
2,164
2,157
Total Property and Equipment
4,312,996
4,191,809
Less – Accumulated Depreciation, Depletion
and Impairment
(3,303,913)
(2,443,216)
Total Property and Equipment, Net
1,009,083
1,748,593
Derivative Instruments
34,566
8,554
Deferred Income Taxes
—
210
Acquisition Deposit
774
—
Other Noncurrent Assets, Net
13,756
15,071
Total Assets
$
1,263,273
$
1,905,465
Liabilities and Stockholders'
Equity
Current Liabilities:
Accounts Payable
$
50,005
$
69,395
Accrued Liabilities
54,216
110,374
Accrued Interest
7,895
11,615
Derivative Instruments
1,198
11,298
Current Portion of Long-term Debt
65,000
—
Other Current Liabilities
906
795
Total Current Liabilities
179,220
203,477
Long-term Debt
924,171
1,118,161
Derivative Instruments
1,428
8,079
Asset Retirement Obligations
17,526
16,759
Other Noncurrent Liabilities
199
345
Total Liabilities
$
1,122,544
$
1,346,822
Commitments and Contingencies (Note
8)
Stockholders’ Equity
Preferred Stock, Par Value $.001;
5,000,000 Shares Authorized;
2,294,702 Series A Shares Outstanding at
6/30/2020
1,500,000 Series A Shares Outstanding at
12/31/2019
2
2
Common Stock, Par Value $.001; 675,000,000
Shares Authorized;
436,439,915 Shares Outstanding at
6/30/2020
406,085,183 Shares Outstanding at
12/31/2019
436
406
Additional Paid-In Capital
1,544,407
1,431,438
Retained Deficit
(1,404,117)
(873,203)
Total Stockholders’ Equity
140,729
558,643
Total Liabilities and Stockholders’
Equity
$
1,263,273
$
1,905,465
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 unsettled commodity derivatives, net
of tax, (ii) (gain) loss on extinguishment of debt, net of tax,
(iii) debt exchange derivative (gain) loss, net of tax, (iv)
contingent consideration loss, net of tax, (v) acquisition
transaction costs, net of tax, (vi) impairment of other current
assets, net of tax, (vii) impairment expense, net of tax, and
(viii) loss 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) (gain) loss on extinguishment of debt, (vi) debt
exchange derivative (gain) loss, (vii) contingent consideration
loss, (viii) (gain) loss on unsettled commodity derivatives, (ix)
loss on unsettled interest rate derivatives, (x) impairment of
other current assets, and (xi) impairment expense. A reconciliation
of each of these measures to the most directly comparable GAAP
measure is included below. Where references are pro forma,
forward-looking or prospective in nature, and not based on
historical fact, the table does not provide a reconciliation.
Northern could not provide such reconciliation without undue
hardship because such Adjusted EBITDA numbers are estimations,
approximations and/or ranges. In addition, it would be difficult
for Northern to present a detailed reconciliation on account of
many unknown variables for the reconciling items, including without
limitation future income taxes, full-cost ceiling impairments, and
unrealized gains or losses on commodity derivatives. For the same
reasons, Northern is unable to address the probable significance of
the unavailable information, which could be material to future
results.
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)
2020
2019
2020
2019
Net Income (Loss)
$
(899,200)
$
44,399
$
(530,914)
$
(62,762)
Add:
Impact of Selected Items:
(Gain) Loss on Unsettled Commodity
Derivatives
150,077
(31,857)
(194,999)
120,311
Impairment of Other Current Assets
—
2,694
—
2,694
(Gain) Loss on Extinguishment of Debt
(217)
425
5,310
425
Debt Exchange Derivative (Gain) Loss
—
4,873
—
(1,413)
Contingent Consideration Loss
—
24,763
—
23,371
Acquisition Transaction Costs
—
513
—
513
Loss on Unsettled Interest Rate
Derivatives
752
—
1,429
—
Impairment Expense
762,716
—
762,716
—
Selected Items, Before Income Taxes
913,328
1,411
574,456
145,901
Income Tax of Selected Items(1)
(3,461)
(346)
(10,668)
(20,696)
Selected Items, Net of Income Taxes
909,866
1,065
563,788
125,205
Adjusted Net Income
$
10,667
$
45,465
$
32,874
$
62,443
Weighted Average Shares Outstanding –
Basic
415,356,043
378,368,462
409,509,292
374,927,630
Weighted Average Shares Outstanding –
Diluted
515,569,721
378,724,511
509,897,841
375,736,820
Net Income (Loss) Per Common Share –
Basic
$
(2.16)
$
0.12
$
(1.30)
$
(0.17)
Add:
Impact of Selected Items, Net of Income
Taxes
2.19
—
1.38
0.33
Adjusted Net Income Per Common Share –
Basic
$
0.03
$
0.12
$
0.08
$
0.16
Net Income (Loss) Per Common Share –
Diluted
$
(1.74)
$
0.12
$
(1.04)
$
(0.17)
Add:
Impact of Selected Items, Net of Income
Taxes
1.76
—
1.10
0.33
Adjusted Net Income Per Common Share –
Diluted
$
0.02
$
0.12
$
0.06
$
0.16
______________
(1)
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. 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 a change in valuation allowance.
Reconciliation of Adjusted
EBITDA
Three Months Ended June
30,
Six Months Ended June
30,
(In thousands)
2020
2019
2020
2019
Net Income (Loss)
$
(899,200)
$
44,399
$
(530,914)
$
(62,762)
Add:
Interest Expense
13,957
17,778
30,508
37,327
Income Tax Provision (Benefit)
—
—
(166)
—
Depreciation, Depletion, Amortization and
Accretion
36,756
46,091
98,565
91,225
Impairment of Other Current Assets
—
2,694
—
2,694
Non-Cash Stock-Based Compensation
1,214
1,643
2,293
4,394
(Gain) Loss on Extinguishment of Debt
(217)
425
5,310
425
Debt Exchange Derivative (Gain) Loss
—
4,873
—
(1,413)
Contingent Consideration Loss
—
24,763
—
23,371
Loss on Unsettled Interest Rate
Derivatives
752
—
1,429
—
(Gain) Loss on Unsettled Commodity
Derivatives
150,077
(31,857)
(194,999)
120,311
Impairment Expense
762,716
—
762,716
—
Adjusted EBITDA
$
66,055
$
110,810
$
174,742
$
215,572
View source
version on businesswire.com: https://www.businesswire.com/news/home/20200807005096/en/
Mike Kelly, CFA EVP Finance 952-476-9800
mkelly@northernoil.com
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