- Third quarter production increased 53% over the prior year, and
17% sequentially, averaging 40,786 barrels of oil equivalent
(“Boe”) per day.
- Cash flow from operations, excluding a $32.5 million net
decrease from changes in working capital and other items, was
$103.5 million for the third quarter, an 11% increase versus the
second quarter.
- Organic drilling and development capital expenditures totaled
$80.1 million during the third quarter.
- Northern closed the VEN Bakken acquisition and also added
another 13.3 net wells to production during the third quarter,
which helped offset the curtailments, shut-ins and completion
delays that negatively impacted production by an estimated 4,500
Boe per day during the quarter.
- Ground Game success continued in the third quarter, with $9.9
million of acquisition capital and an additional $23.0 million of
associated development capital allocated to drive cash flow for
shareholder returns in 2020.
Northern Oil and Gas, Inc. (NYSE American: NOG) (“Northern”)
today announced the company’s third quarter results.
Third quarter 2019 production totaled 3.8 million Boe and
averaged 40,786 Boe per day, a 53% increase from the prior year and
a 17% increase sequentially. Oil and gas sales in the third quarter
totaled $158.0 million. Net income in the third quarter was $94.4
million or $0.24 per diluted share. Adjusted Net Income in the
third quarter was $36.3 million or $0.09 per diluted share.
Adjusted EBITDA totaled $124.4 million in the third quarter, a 27%
increase from the prior year. (See “Non-GAAP Financial Measures”
below.)
“Strong net well additions from our organic well opportunities
and the success we have had in our ground game acquisitions
generated strong production growth during the quarter,” commented
Brandon Elliott, Chief Executive Officer. “While well performance
and net well additions have remained robust, they did not
completely offset 4,500 Boe per day of shut-ins and curtailments
during the quarter. The good news is we expect the well performance
and net well additions to remain strong while we expect the
infrastructure issues to begin to subside as we close out 2019.
Future cash flows will support plans to reduce debt ratios and
return capital to shareholders in 2020.”
Production and Operating Costs
Total third quarter production was 3.8 million Boe, driven by
the closing of the VEN Bakken acquisition and an additional 13.3
net wells added to production during the quarter. Strong well
results were offset by continued infrastructure-driven constraints.
Midstream system expansions, while beginning to come online, did
not offset the negative effects on production and natural gas and
NGL prices during the quarter. Oil price differentials averaged
$5.48 per barrel, a 4% increase from the second quarter of 2019.
Ongoing production curtailments resulted in a 5% sequential
increase in lease operating expenses (“LOE”) to $8.62 per Boe in
the third quarter. General and administrative expenses were $1.12
per Boe in the third quarter.
2019 Capital Allocation and Ground Game Activity
Northern continues to focus capital to the highest returns on
capital employed in an effort to grow cash flow as it prepares to
begin returning capital to shareholders in 2020. During the third
quarter, Northern spent $80.1 million on organic development
capital and an additional $32.9 million related to its ground game
acquisition strategy (“Ground Game”), which is Northern's regular
acquisition activity excluding larger, separately announced deals
such as the recent VEN Bakken acquisition. Of the total Ground Game
spend, $9.9 million was acquisition capital and an additional $23.0
million was associated development capital.
The third quarter was extremely active for Northern’s Ground
Game. With many operators and non-operating participants seeking to
reduce their short term capital obligations, the landscape for high
return opportunities, particularly for near term drilling, has been
robust. In the third quarter, Northern acquired approximately 3,100
net acres and 4.4 net wells in process. Of those net wells in
process, approximately 2.0 net wells came online in the third
quarter, 1.1 of which came online ahead of schedule late in the
quarter. Northern's Ground Game success in 2019 will allow it to
moderate its acquisition activity in 2020, as the Company looks to
harvest cash flows from its 2019 acquisitions. Northern will,
however, continue to monitor and evaluate potential acquisitions
for distressed and high-return opportunities.
2019 Production Guidance Updated for Ground Game Acquisitions
and Continued Curtailments
Northern expects to add 33 – 34 net organic wells to production
in 2019. Due to Ground Game success over the last 12 months and an
acceleration in development activity, Northern expects to add an
additional 5 – 7 net wells to production from the Ground Game, for
a total of 38 – 41 total net wells added to production during
2019.
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
3rd Quarter – Actual
40,786
4th Quarter – Estimate
43,500 – 44,500
43,500 – 44,500
Annual – Estimate
38,500 – 38,750
38,650 – 39,150
2019 Guidance Ranges (in millions,
except for net well data):
Current
Previous
Organic(1) Net Wells Added to
Production
33 – 34
33 – 34
Organic(1) Drilling & Completion
(D&C) Capital
$265 – $285
$265 – $285
Ground Game 2019E Net Wells Added to
Production
5 – 7
3 – 5
Ground Game Acquisition Capital
$30 – $40
$25 – $50
Ground Game D&C Capital
$40 – $70
$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
$8.00 – $8.50
Production Taxes
10% of crude oil
~ 9.3% of oil and
sales; $0.075 per
gas sales
mcf of gas
General and Administrative Expense (per
Boe):
Cash
$0.95 – $1.15
$0.95 – $1.15
Non-Cash
$0.50
$0.50
Average Differential to NYMEX WTI
$4.50 – $6.50
$4.50 – $6.50
THIRD QUARTER 2019 RESULTS
The following tables set forth selected operating and financial
data for the periods indicated.
Three Months Ended September
30,
2019
2018
% Change
Net Production:
Oil (Bbl)
3,002,789
2,064,092
45
%
Natural Gas and NGLs (Mcf)
4,496,860
2,358,162
91
%
Total (Boe)
3,752,266
2,457,119
53
%
Average Daily Production:
Oil (Bbl)
32,639
22,436
45
%
Natural Gas and NGLs (Mcf)
48,879
25,632
91
%
Total (Boe)
40,786
26,708
53
%
Average Sales Prices:
Oil (per Bbl)
$
50.90
$
65.45
(22)
%
Effect of Gain (Loss) on Settled
Derivatives on Average Price (per Bbl)
6.12
(6.26)
Oil Net of Settled Derivatives (per
Bbl)
57.02
59.19
(4)
%
Natural Gas and NGLs (per Mcf)
1.15
4.41
(74)
%
Realized Price on a Boe Basis Including
all Realized Derivative Settlements
47.00
53.96
(13)
%
Costs and Expenses (per Boe):
Production Expenses
$
8.62
$
7.39
17
%
Production Taxes
4.10
5.53
(26)
%
General and Administrative Expense
1.12
1.90
(41)
%
Depletion, Depreciation, Amortization and
Accretion
14.81
12.31
20
%
Net Producing Wells at Period
End
444.0
284.3
56
%
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 September 30, 2019.
Crude Oil Derivative
Swaps
Contract Period
Volume (Bbls)
Weighted Average Price (per
Bbl)
2019:
4Q
2,460,411
$58.96
2020:
1Q
2,490,106
$59.15
2Q
2,431,778
$58.44
3Q
2,340,348
$58.48
4Q
2,165,362
$58.00
2021:
1Q
1,690,050
$56.73
2Q
1,587,958
$57.24
3Q
1,418,410
$54.35
4Q
1,409,506
$54.37
2022(1):
1Q
453,780
$53.07
2Q
312,280
$52.30
3Q
306,576
$52.33
4Q
300,230
$52.35
_____________
(1)
The Company has entered into
crude oil derivative contracts that give counterparties the option
to extend certain current derivative contracts for additional
periods. Options covering a notional volume of 2.4 million barrels
for 2022 are exercisable on or about December 31, 2021. If the
counterparties exercise all such options, the notional volume of
the Company’s existing crude oil derivative contracts will increase
as follows for 2022: (i) for the first quarter of 2022, by 807,750
barrels at a weighted average price of $54.89 per barrel, (ii) for
the second quarter of 2022, by 816,725 barrels at a weighted
average price of $54.89 per barrel, (iii) for the third quarter of
2022, by 365,700 barrels at a weighted average price of $55.04 per
barrel, and (iv) for the fourth quarter of 2022, by 365,700 barrels
at a weighted average price of $55.04 per barrel.
Crude Oil Derivative Basis
Swaps(1)
Weighted Average
Differential
Contract Period
Total Volumes (Bbls)
($/Bbl)
10/01/2019 - 12/31/2019
951,000
($2.40)
_____________
(1)
Basis swaps are settled using the TMX UHC
1a index, as published by NGX.
LIQUIDITY
As of September 30, 2019, Northern had $1.9 million in cash and
$327.0 million outstanding on its revolving credit facility.
Northern had total liquidity of $99.9 million as of September 30,
2019, consisting of cash and borrowing availability under the
revolving credit facility.
CAPITAL EXPENDITURES & DRILLING ACTIVITY
Three Months Ended
(in millions, except for net well
data)
September 30, 2019
Capital Expenditures Incurred:
Organic Drilling and Development Capital
Expenditures
$
80.1
Ground Game Acquisition Capital
Expenditures
$
9.9
Ground Game Drilling and Development
Capital Expenditures
$
23.0
Acquisition of Oil and Natural Gas
Properties and Other
$
325.7
Net Wells Added to Production
13.3
Net Producing Wells (Period-End)
444.0
Net Wells in Process (Period-End)
24.2
Increase in Wells in Process over 2018
Year-End
1.4
Weighted Average AFE for Wells Elected to
During the Third Quarter
$
7.7
Weighted Average AFE for Wells Elected to
Year-to-Date
$
7.9
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 1.4
well increase in net wells in process during the nine months ended
September 30, 2019 are reflected in the amounts incurred
year-to-date for drilling and development capital expenditures.
ACREAGE
As of September 30, 2019, Northern controlled leasehold of
approximately 183,518 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.
THIRD 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
Tuesday, November 12, 2019 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:
Dial-In Number:
(866) 373-3407 (US/Canada) and (412) 902-1037 (International)
Conference ID: 13696040 - Northern Oil
and Gas, Inc. Third Quarter 2019 Conference Call Replay Dial-In Number: (877) 660-6853 (US/Canada)
and (201) 612-7415 (International) Replay
Access Code: 13696040 - Replay will be available through
November 19, 2019
UPCOMING CONFERENCE SCHEDULE
Bank of America 2019 Leveraged Finance Conference
December 2 - 4, 2019, Boca Raton, FL
Capital One Securities 14th Annual Energy Conference
December 10 - 12, 2019, Houston, TX
Piper Jaffray 20th Annual Energy Conference
March 23 - 25, 2020, Las Vegas, NV
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, 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 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
(UNAUDITED)
Three Months Ended
Nine Months Ended
September 30,
September 30,
(In thousands, except share and per
share data)
2019
2018
2019
2018
REVENUES
Oil and Gas Sales
$
157,989
$
145,416
$
440,519
$
341,343
Gain (Loss) on Derivative Instruments,
Net
75,892
(43,148)
(27,139)
(105,622)
Other Revenue
3
2
10
5
Total Revenues
233,883
102,269
413,389
235,729
OPERATING EXPENSES
Production Expenses
32,347
18,161
83,146
45,198
Production Taxes
15,391
13,579
41,944
31,633
General and Administrative Expenses
4,206
4,674
15,506
9,593
Depletion, Depreciation, Amortization and
Accretion
55,566
30,258
146,791
71,485
Impairment of Other Current Assets
5,275
—
7,969
—
Total Operating Expenses
112,784
66,673
295,355
157,909
INCOME FROM OPERATIONS
121,100
35,597
118,034
77,820
OTHER INCOME (EXPENSE)
Interest Expense, Net of
Capitalization
(21,510)
(20,438)
(58,836)
(65,948)
Loss on the Extinguishment of Debt
—
(9,542)
(425)
(100,375)
Debt Exchange Derivative Gain/(Loss)
(23)
13,063
1,390
13,063
Contingent Consideration Loss
(5,262)
—
(28,633)
—
Other Income (Expense)
75
299
88
838
Total Other Income (Expense)
(26,719)
(16,618)
(86,416)
(152,423)
INCOME (LOSS) BEFORE INCOME
TAXES
94,381
18,979
31,619
(74,603)
INCOME TAX PROVISION (BENEFIT)
—
—
—
—
NET INCOME (LOSS)
$
94,381
$
18,979
$
31,619
$
(74,603)
Net Income (Loss) Per Common Share –
Basic
$
0.24
$
0.06
$
0.08
$
(0.40)
Net Income (Loss) Per Common Share –
Diluted
$
0.24
$
0.06
$
0.08
$
(0.40)
Weighted Average Shares Outstanding –
Basic
396,044,887
300,517,497
382,044,068
188,152,998
Weighted Average Shares Outstanding –
Diluted
396,530,767
301,755,419
382,744,304
188,152,998
CONDENSED BALANCE
SHEETS
(In thousands, except par value and
share data)
September 30, 2019
December 31, 2018
ASSETS
(Unaudited)
Current Assets:
Cash and Cash Equivalents
$
1,901
$
2,358
Accounts Receivable, Net
103,226
96,353
Advances to Operators
1,314
268
Prepaid Expenses and Other
2,717
12,360
Derivative Instruments
62,531
115,870
Income Tax Receivable
420
1,205
Total Current Assets
172,110
228,415
Property and Equipment:
Oil and Natural Gas Properties, Full Cost
Method of Accounting
Proved
4,043,897
3,431,428
Unproved
11,145
4,307
Other Property and Equipment
1,999
998
Total Property and Equipment
4,057,041
3,436,732
Less – Accumulated Depreciation, Depletion
and Impairment
(2,380,086)
(2,233,987)
Total Property and Equipment, Net
1,676,955
1,202,745
Derivative Instruments
42,682
61,843
Deferred Income Taxes
420
420
Other Noncurrent Assets, Net
9,842
10,223
Total Assets
$
1,902,009
$
1,503,645
LIABILITIES AND STOCKHOLDERS’
EQUITY
Current Liabilities:
Accounts Payable
$
112,698
$
55,015
Accrued Liabilities
90,114
83,237
Accrued Interest
17,567
16,468
Debt Exchange Derivative
—
18,183
Contingent Consideration
10,058
58,069
Other Current Liabilities
387
555
Total Current Liabilities
230,824
231,526
Long-term Debt, Net
1,140,072
830,203
Asset Retirement Obligations
16,582
11,946
Other Noncurrent Liabilities
417
105
TOTAL LIABILITIES
$
1,387,894
$
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; 404,346,470 Shares Outstanding at 9/30/2019
378,333,070 Shares Outstanding at 12/31/2018
404
378
Additional Paid-In Capital
1,278,976
1,226,371
Retained Deficit
(765,266)
(796,884)
Total Stockholders’ Equity
514,114
429,865
TOTAL LIABILITIES AND STOCKHOLDERS’
EQUITY
$
1,902,009
$
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
Nine Months Ended
September 30,
September 30,
(In thousands, except share and per
share data)
2019
2018
2019
2018
Net Income (Loss)
$
94,381
$
18,979
$
31,619
$
(74,603)
Add:
Impact of Selected Items:
(Gain) Loss on the Mark-to-Market of
Derivative Instruments
(57,506)
30,225
62,806
72,303
Impairment of Other Current Assets
5,275
—
7,969
—
Loss on the Extinguishment of Debt
—
9,542
425
100,375
Debt Exchange Derivative (Gain) Loss
23
(13,063)
(1,390)
(13,063)
Contingent Consideration Loss
5,262
—
28,633
—
Acquisition Transaction Costs
1,250
—
1,763
—
Selected Items, Before Income Taxes
(45,696)
26,705
100,204
159,615
Income Tax of Selected Items(1)
(12,380)
(11,195)
(32,401)
(21,107)
Selected Items, Net of Income Taxes
$
(58,077)
$
15,510
$
67,803
$
138,508
Adjusted Net Income
$
36,304
$
34,489
$
99,422
$
63,905
Weighted Average Shares Outstanding –
Basic
396,044,887
300,517,497
374,927,630
188,152,998
Weighted Average Shares Outstanding –
Diluted
396,530,767
301,755,419
375,736,820
188,709,068
Net Income (Loss) Per Common Share –
Basic
$
0.24
$
0.06
$
0.08
$
(0.40)
Add:
Impact of Selected Items, Net of Income
Taxes
(0.15)
0.05
0.19
0.74
Adjusted Net Income Per Common Share –
Basic
$
0.09
$
0.11
$
0.27
$
0.34
Net Income (Loss) Per Common Share –
Diluted
$
0.24
$
0.06
$
0.08
$
(0.40)
Add:
Impact of Selected Items, Net of Income
Taxes
(0.15)
0.05
0.18
0.74
Adjusted Net Income Per Common Share –
Diluted
$
0.09
$
0.11
$
0.26
$
0.34
_____________
(1)
For the three and nine months ended September 30, 2019, this
represents a tax impact using an estimated tax rate of 24.5%, which
includes an adjustment of $23.6 million and $7.9 million,
respectively, for a change in valuation allowance. For the three
and nine months ended September 30, 2018, this represents a tax
impact using an estimated tax rate of 24.5%, which includes an
adjustment of $4.7 million and $18.0 million, respectively, for a
reduction in valuation allowance.
Reconciliation of Adjusted
EBITDA
Three Months Ended
Nine Months Ended
September 30,
September 30,
(In thousands)
2019
2018
2019
2018
Net Income (Loss)
$
94,381
$
18,979
$
31,619
$
(74,603)
Add:
Interest Expense
21,510
20,438
58,836
65,948
Income Tax Provision (Benefit)
—
—
—
—
Depreciation, Depletion, Amortization and
Accretion
55,566
30,258
146,791
71,485
Impairment of Other Current Assets
5,275
—
7,969
—
Non-Cash Stock-Based Compensation
(114)
1,535
4,280
1,973
Loss on the Extinguishment of Debt
—
9,542
425
100,375
Debt Exchange Derivative (Gain) Loss
23
(13,063)
(1,390)
(13,063)
Contingent Consideration Loss
5,262
—
28,633
—
(Gain) Loss on the Mark-to-Market of
Derivative Instruments
(57,506)
30,225
62,806
72,303
Adjusted EBITDA
$
124,396
$
97,914
$
339,968
$
224,418
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Nicholas O’Grady President and Chief Financial Officer
952-476-9800 ir@northernoil.com
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