MINNEAPOLIS--(BUSINESS WIRE)--
Northern Oil and Gas, Inc. (NYSE American: NOG) today announced 2017
fourth quarter and full year results and provided 2018 guidance.
HIGHLIGHTS
-
Northern raises 2018 annual production guidance and now expects a 16 -
20% increase over 2017
-
Year-end 2017 proved reserve volumes increased 40% year over year from
54.1 million barrels of oil equivalent (“Boe”) in 2016 to 75.8 million
Boe
-
The SEC PV-10 value of year-end proved reserves increased 100% year
over year
-
Fourth quarter production increased 22% year over year and 9.3%
sequentially to 1,540,237 Boe. Production averaged 16,742 Boe per day
in the fourth quarter
-
Fourth quarter oil differential was $3.51 per barrel, an improvement
of $2.71 per barrel compared to the third quarter
-
Northern added 16.9 net wells to production during 2017 and ended the
year with an additional 18.3 net wells in process
Adjusted EBITDA for the fourth quarter was $48.5 million. Northern’s
adjusted net income for the fourth quarter was $6.6 million, or $0.10
per diluted share. GAAP net loss for the quarter was $23.8 million, or a
loss of $0.37 per diluted share, primarily due to a non-cash
mark-to-market loss on its hedge portfolio. See “Non-GAAP Financial
Measures” below for additional information on these measures.
MANAGEMENT COMMENT
“Strong fourth quarter results, including 9.3% sequential production
growth, provided an excellent finish to the year and outstanding
momentum as we enter 2018,” commented Northern’s Interim President,
Brandon Elliott. “We are seeing excellent results from wells added to
production during 2017, suggesting significant upside to the value from
enhanced completions that resides within the entirety of our acreage
position. Our investment approach and our Williston Basin asset base,
combined with the steps we are taking to strengthen our balance sheet,
are setting the stage for us to accelerate our growth strategy as the
natural consolidator of non-operated working interest in the Williston
Basin.”
2018 GUIDANCE
Northern is raising guidance and now expects 2018 total annual
production to increase by 16 - 20% over 2017 levels, based on the
expectation of adding between 20 and 22 net wells to production during
the year. Due to winter weather and the potential for road restrictions
during the spring, net well additions are expected to be weighted to the
second half of 2018. Capital expenditures are expected to total between
$165 - $180 million. This budget is comprised of $152 - $167 million in
drilling and completions capital assuming the addition of 20 - 22 net
wells to production during the year and approximately $13 million in
workover, acreage and other capitalized costs. Management’s current
expectations for 2018 operating metrics are as follows:
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2018
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Operating Expenses:
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|
|
|
Production Expenses (per Boe)
|
|
$8.75 - $9.25
|
|
Production Taxes (% of Oil & Gas Sales)
|
|
9.2% - 9.5%
|
|
General and Administrative Expense (per Boe)
|
|
$2.00 - $2.50
|
|
|
|
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Average Differential to NYMEX WTI
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$3.50 - $4.50
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LIQUIDITY
At December 31, 2017, Northern had available liquidity of approximately
$202.2 million, comprised of $102.2 million in cash on hand and $100
million of delayed draw term loan availability.
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CAPITAL EXPENDITURES & DRILLING ACTIVITY
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Fourth Quarter
2017
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Full Year
2017
|
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Capital Expenditures Incurred:
|
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|
|
|
|
Drilling, Completion & Capitalized Workover Expense
|
|
$56.2 million
|
|
$148.8 million
|
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Acreage
|
|
$0.6 million
|
|
$4.9 million
|
|
Other
|
|
$0.5 million
|
|
$2.3 million
|
|
|
|
|
|
|
|
Net Wells Added to Production
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|
7.1
|
|
16.9
|
|
Net Producing Wells (Period-End)
|
|
|
|
229.0
|
|
|
|
|
|
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Net Wells in Process (Period-End)
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18.3
|
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Increase in Wells in Process Year-over-Year
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4.9
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Weighted Average AFE for In-Process Wells (Period-End)
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$7.6 million
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Capitalized costs incurred (e.g. drilling and completion costs and other
capital expenditures) for the fourth quarter and full year 2017 totaled
$57.3 million and $156.0 million, respectively. Capitalized costs are a
function of the number of net well additions during the period as well
as changes in wells in process from beginning to end of period. Capital
expenditures attributable to the 4.9 increase in net wells in process
are reflected in the amounts included for “Drilling, Completion &
Capitalized Workover Expense” in the table above.
ELECTION ACTIVITY AND ACREAGE
Higher well productivity from enhanced completions on Northern’s acreage
position drove a 100% increase in net well elections from 8.0 net wells
in 2016 to 16.0 net wells in 2017. Northern consented to 93% of well
proposals in 2017 compared to 77% in 2016. As a result of increased
activity levels and higher consent rates during the year, Northern’s
wells in process increased by 4.9 net wells to 18.3 net wells compared
to year-end 2016 levels.
As of December 31, 2017, Northern controlled 143,253 net acres targeting
the Bakken and Three Forks formations in the Williston Basin. As of
December 31, 2017, approximately 89% of Northern’s North Dakota acreage
position, and approximately 88% of Northern’s total acreage position,
was developed, held by production or held by operations.
2017 YEAR-END RESERVES
Based on reports prepared by Ryder Scott Company, L.P., Northern’s
estimated proved reserves at December 31, 2017 totaled 75.8 million
barrels of oil equivalent (MMBoe), a 40% increase as compared to 54.1
MMBoe at December 31, 2016, driven by higher commodity prices and
increased activity levels. Approximately 61% of Northern’s proved
reserves at December 31, 2017 were categorized as proved developed and
approximately 39% were classified as proved undeveloped. Crude oil
represented 83% of year-end 2017 proved reserves.
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2017 Boe
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2016 Boe
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% Change
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(in thousands)
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Reserve Category
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Proved Developed Producing
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40,050
|
|
|
35,676
|
|
|
12
|
%
|
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Proved Developed Non-Producing
|
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6,295
|
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|
2,037
|
|
|
209
|
%
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Proved Undeveloped
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29,487
|
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16,368
|
|
|
80
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%
|
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Total Proved
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|
75,832
|
|
|
54,081
|
|
|
40
|
%
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The table that follows compares Northern's proved reserves from the 2017
SEC case prepared by Ryder Scott to an alternative pricing case that
utilizes a $60 flat WTI price. Other than commodity prices, all
assumptions in the “$60 WTI Flat” case have been held constant with the
SEC case, and as a result both cases reflect the inclusion of just 52.1
proved undeveloped net well locations due to SEC guidelines (including
the 5 year PUD limitation rule) applicable to booking proved undeveloped
reserves. Early next week, Northern plans to post an updated investor
presentation at www.northernoil.com,
which will include additional reserve information based on internal
management estimates.
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Price Cases (including the 5 year PUD limitation rule)
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SEC Case(1)
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$60 WTI Flat(2)
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(in thousands)
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Net Proved Reserves (December 31, 2017)
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Developed (Boe)
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46,345
|
|
|
48,069
|
|
Undeveloped (Boe)
|
|
29,487
|
|
|
32,107
|
|
Total Proved Reserves (Boe)
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|
75,832
|
|
|
80,176
|
|
|
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Pre-Tax Present Value of Estimated Future Net Revenues
(Pre-Tax
PV10%)(3)
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|
$
|
758,000
|
|
|
$
|
1,015,881
|
_________________
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(1)
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Prices prescribed by SEC based on $51.34 per Bbl of oil and $2.98
per MMbtu for natural gas, which were then adjusted for
transportation and quality differentials to arrive at prices of
$45.90 per Bbl of oil and $3.34 per Mcf for natural gas.
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(2)
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Prices based on $60.00 per Bbl of oil and $3.00 per MMbtu for
natural gas, which were then adjusted for transportation and quality
differentials to arrive at prices of $54.56 per Bbl of oil and $3.36
per Mcf for natural gas.
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(3)
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Pre-tax PV10%, or “PV-10,” may be considered a non-GAAP financial
measure as defined by the SEC and is derived from the standardized
measure of discounted future net cash flows, which is the most
directly comparable GAAP measure. See “Reconciliation of PV-10”
below.
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FOURTH QUARTER 2017 RESULTS
The following table sets forth selected operating and financial data for
the periods indicated.
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Three Months Ended
December 31,
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2017
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2016
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% Change
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|
Net Production:
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|
|
|
|
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Oil (Bbl)
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|
1,282,122
|
|
|
1,063,535
|
|
|
21
|
%
|
|
Natural Gas and NGLs (Mcf)
|
|
1,548,688
|
|
|
1,174,434
|
|
|
32
|
%
|
|
Total (Boe)
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|
1,540,237
|
|
|
1,259,274
|
|
|
22
|
%
|
|
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|
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|
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Average Daily Production:
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|
|
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Oil (Bbl)
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|
13,936
|
|
|
11,560
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|
|
21
|
%
|
|
Natural Gas and NGL (Mcf)
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|
16,834
|
|
|
12,766
|
|
|
32
|
%
|
|
Total (Boe)
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|
16,742
|
|
|
13,688
|
|
|
22
|
%
|
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|
|
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Average Sales Prices:
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Oil (per Bbl)
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|
$
|
51.79
|
|
|
$
|
41.83
|
|
|
24
|
%
|
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Effect of Gain on Settled Derivatives on Average Price (per Bbl)
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|
(1.45
|
)
|
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6.65
|
|
|
(122
|
)%
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|
Oil Net of Settled Derivatives (per Bbl)
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|
50.34
|
|
|
48.48
|
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|
4
|
%
|
|
Natural Gas and NGLs (per Mcf)
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|
3.92
|
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|
2.21
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|
|
77
|
%
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|
Realized Price on a Boe Basis Including all Realized Derivative
Settlements
|
|
45.85
|
|
|
43.00
|
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|
7
|
%
|
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|
|
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|
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Costs and Expenses (per Boe):
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|
|
|
|
|
|
|
Production Expenses
|
|
$
|
8.65
|
|
|
$
|
9.31
|
|
|
(7
|
)%
|
|
Production Taxes
|
|
4.31
|
|
|
3.56
|
|
|
21
|
%
|
|
General and Administrative Expense
|
|
2.00
|
|
|
2.97
|
|
|
(33
|
)%
|
|
Depletion, Depreciation, Amortization and Accretion
|
|
11.45
|
|
|
10.74
|
|
|
7
|
%
|
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|
|
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|
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Net Producing Wells at Period End
|
|
229.0
|
|
|
213.1
|
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|
7
|
%
|
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Oil and Natural Gas Sales
In the fourth quarter of 2017, oil, natural gas and NGL sales, excluding
the effect of settled derivatives, increased 54% as compared to the
fourth quarter of 2016, driven by a 24% increase in average oil sales
prices and a 22% increase in production levels. The higher average
realized price per Boe, excluding the effect of settled derivatives, in
the fourth quarter of 2017 as compared to the fourth quarter of 2016 was
primarily driven by higher NYMEX oil and natural gas prices and a lower
oil differential. Oil price differential during the fourth quarter of
2017 was $3.51 per barrel, as compared to $7.46 per barrel in the fourth
quarter of 2016.
Derivative Instruments (Hedges)
Northern enters into derivative instruments to manage the price risk
attributable to future oil production. Gain (loss) on derivative
instruments, net is comprised of (i) cash gains and losses recognized on
settled derivatives during the period, and (ii) non-cash mark-to-market
gains and losses incurred on derivative instruments outstanding at
period-end.
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Three Months Ended
December 31,
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2017
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2016
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(in millions)
|
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Derivative Instruments (Hedges):
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Cash Derivative Settlements
|
|
$
|
(1.9
|
)
|
|
$
|
7.1
|
|
|
Non-Cash Mark-to-Market of Derivative Instruments
|
|
(33.6
|
)
|
|
(18.2
|
)
|
|
Gain (Loss) on Derivative Instruments, Net
|
|
$
|
(35.5
|
)
|
|
$
|
(11.1
|
)
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Northern’s average realized price, including all cash derivative
settlements, received during the fourth quarter of 2017 was $45.85 per
Boe compared to $43.00 per Boe in the fourth quarter of 2016. The gain
(loss) on settled derivatives decreased Northern’s average realized
price per Boe by $1.21 in the fourth quarter of 2017 and increased the
average realized price per Boe by $5.62 in the fourth quarter of 2016.
As a result of forward oil price changes, Northern recognized a non-cash
mark-to-market derivative loss of $33.6 million in the fourth quarter of
2017, compared to a loss of $18.2 million in the fourth quarter of 2016.
Production Expenses
Production expenses were $13.3 million in the fourth quarter of 2017
compared to $11.7 million in the fourth quarter of 2016. On a per unit
basis, production expenses decreased to $8.65 per Boe in the fourth
quarter of 2017, compared to $9.31 per Boe in the fourth quarter of
2016. On an absolute dollar basis, the increase in production expenses
in the fourth quarter of 2017 as compared to the fourth quarter of 2016
was primarily due to higher processing costs and salt water disposal
costs, a 22% increase in production levels, and a 7% increase in the
total number of net producing wells.
Production Taxes
Production taxes were $6.6 million in the fourth quarter of 2017
compared to $4.5 million in the fourth quarter of 2016. The increase is
due to higher commodity prices and higher production levels, which
increased oil and natural gas sales in the fourth quarter of 2017 as
compared to the fourth quarter of 2016. As a percentage of oil and
natural gas sales, production taxes were 9.2% and 9.5% in the fourth
quarter of 2017 and 2016, respectively. This decrease in production tax
rates as a percentage of oil and natural gas sales is due to a change in
sales mix, as production taxes on natural gas and NGL sales are at a
lower percentage than that of crude oil sales. Crude oil sales
represented 92% of oil and natural gas sales in the fourth quarter of
2017 compared to 94% in the fourth quarter of 2016.
General and Administrative Expense
General and administrative expenses were $3.1 million in the fourth
quarter of 2017 compared to $3.7 million in the fourth quarter of 2016.
The decrease was primarily due to a $0.9 million decrease in legal and
other professional expenses, partially offset by a $0.2 million increase
in compensation expenses.
Depletion, Depreciation, Amortization and Accretion
Depletion, depreciation, amortization and accretion (“DD&A”) was $17.6
million in the fourth quarter of 2017 compared to $13.5 million in the
fourth quarter of 2016. Depletion expense, the largest component of
DD&A, was $17.5 million in the fourth quarter of 2017 compared to $13.4
million in the fourth quarter of 2016. The aggregate increase in
depletion expense was driven by a 22% increase in production levels
coupled with a 7% increase in the depletion rate per Boe. On a per unit
basis, depletion expense was $11.33 per Boe in the fourth quarter of
2017 compared to $10.61 per Boe in the fourth quarter of 2016.
Depreciation, amortization and accretion was $0.2 million in the fourth
quarter of 2017 and 2016.
Interest Expense
Interest expense, net of capitalized interest, was $20.9 million in the
fourth quarter of 2017, compared to $16.2 million in the fourth quarter
of 2016. The increase in interest expense was driven primarily by an
increase in average borrowings outstanding and a higher interest rate on
the new term loan credit agreement that replaced Northern’s prior
revolving credit facility in November 2017.
Income Tax Provision
Northern recognized a $1.6 million income tax benefit during the fourth
quarter of 2017 as compared to a $1.4 million income tax benefit in the
fourth quarter of 2016. In 2017 and 2016, Northern utilized $1.6 million
and $1.4 million, respectively, of its alternative minimum tax credit as
a result of favorable tax incentives.
Net Loss
Northern recorded a net loss of $23.8 million, or a loss of $0.37 per
diluted share, for the fourth quarter of 2017, compared to a net loss of
$12.3 million, or a loss of $0.20 per diluted share, for the fourth
quarter of 2016. The net loss in the fourth quarter of 2017 was impacted
by a non-cash loss on the mark-to-market of derivative instruments of
$33.6 million that was partially offset by a $1.6 million income tax
benefit.
Non-GAAP Financial Measures
Adjusted Net Income for the fourth quarter of 2017 was $6.6 million
(representing $0.10 per diluted share), compared to $2.4 million
(representing $0.04 per diluted share) for the fourth quarter of 2016.
Northern defines Adjusted Net Income as net income excluding (i) (gain)
loss on the mark-to-market of derivative instruments, net of tax, (ii)
restructuring costs, net of tax, (iii) impairment of oil and natural gas
properties, net of tax, and (iv) write-off of debt issuance costs, net
of tax. The increase in Adjusted Net Income in the fourth quarter of
2017 compared to the fourth quarter of 2016 was primarily due to higher
realized commodity prices and production volumes, which were partially
offset by higher depletion expense.
Adjusted EBITDA for the fourth quarter of 2017 was $48.5 million,
compared to Adjusted EBITDA of $35.1 million for the fourth quarter of
2016. The increase in Adjusted EBITDA in the fourth quarter of 2017 as
compared to the fourth quarter of 2016 is primarily due to higher
realized commodity prices and production volumes. Northern defines
Adjusted EBITDA as net income before (i) interest expense, (ii) income
taxes, (iii) depreciation, depletion, amortization and accretion, (iv)
(gain) loss on the mark-to-market of derivative instruments, (v)
non-cash share based compensation expense, (vi) write-off of debt
issuance costs and (vii) impairment of oil and natural gas properties.
Adjusted Net Income and Adjusted EBITDA are non-GAAP measures. A
reconciliation of these measures to the most directly comparable GAAP
measure is included in the accompanying financial tables found later in
this release. 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 results included herein provide useful information
to both management and investors by excluding certain expenses and
unrealized derivatives 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.
FULL YEAR 2017 RESULTS
The following table sets forth selected operating and financial data for
the periods indicated.
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2017
|
|
2016
|
|
% Change
|
|
|
Net Production:
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
4,537,295
|
|
|
4,325,919
|
|
|
5
|
%
|
|
Natural Gas and NGLs (Mcf)
|
|
5,187,886
|
|
|
4,026,899
|
|
|
29
|
%
|
|
Total (Boe)
|
|
5,401,943
|
|
|
4,997,069
|
|
|
8
|
%
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production:
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
12,431
|
|
|
11,819
|
|
|
5
|
%
|
|
Natural Gas and NGL (Mcf)
|
|
14,213
|
|
|
11,002
|
|
|
29
|
%
|
|
Total (Boe)
|
|
14,800
|
|
|
13,653
|
|
|
8
|
%
|
|
|
|
|
|
|
|
|
|
|
Average Sales Prices:
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
45.09
|
|
|
$
|
35.22
|
|
|
28
|
%
|
|
Effect of Gain (Loss) on Settled Derivatives on Average Price (per
Bbl)
|
|
0.83
|
|
|
14.22
|
|
|
(94
|
)%
|
|
Oil Net of Settled Derivatives (per Bbl)
|
|
45.92
|
|
|
49.44
|
|
|
(7
|
)%
|
|
Natural Gas and NGLs (per Mcf)
|
|
3.74
|
|
|
1.82
|
|
|
105
|
%
|
|
Realized Price on a Boe Basis Including all Realized Derivative
Settlements
|
|
42.16
|
|
|
44.27
|
|
|
(5
|
)%
|
|
|
|
|
|
|
|
|
|
|
Costs and Expenses (per Boe):
|
|
|
|
|
|
|
|
|
Production Expenses
|
|
$
|
9.21
|
|
|
$
|
9.14
|
|
|
1
|
%
|
|
Production Taxes
|
|
3.81
|
|
|
3.10
|
|
|
23
|
%
|
|
General and Administrative Expense
|
|
3.51
|
|
|
2.95
|
|
|
19
|
%
|
|
Depletion, Depreciation, Amortization and Accretion
|
|
11.01
|
|
|
12.26
|
|
|
(10
|
)%
|
|
|
|
|
|
|
|
|
|
|
Net Producing Wells at Period End
|
|
229.0
|
|
|
213.1
|
|
|
7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Natural Gas Sales
In 2017, oil, natural gas and NGL sales, excluding the effect of settled
derivatives, increased 40% from 2016, driven primarily by an 8% increase
in production levels and a 28% increase in average oil sales price. The
higher average realized price per Boe, excluding the effect of settled
derivatives, in 2017 as compared to 2016 was primarily driven by higher
average NYMEX oil and gas prices, as well as a lower oil price
differential. Oil price differential during 2017 averaged $5.87 per
barrel, as compared to $8.25 per barrel in 2016.
Derivative Instruments (Hedges)
Northern enters into derivative instruments to manage the price risk
attributable to future oil production. Gain (loss) on derivative
instruments, net is comprised of (i) cash gains and losses recognized on
settled derivatives during the period, and (ii) non-cash mark-to-market
gains and losses incurred on derivative instruments outstanding at
period-end.
|
|
|
|
|
|
|
Years Ended
December 31,
|
|
|
|
2017
|
|
2016
|
|
|
|
(in millions)
|
|
Derivative Instruments:
|
|
|
|
|
|
Cash Derivative Settlements
|
|
$
|
3.8
|
|
|
$
|
61.5
|
|
|
Non-Cash Mark-to-Market of Derivative Instruments
|
|
(18.4
|
)
|
|
(76.3
|
)
|
|
Gain (Loss) on Derivative Instruments, Net
|
|
$
|
(14.7
|
)
|
|
$
|
(14.8
|
)
|
|
|
|
|
|
|
|
|
|
|
Northern’s average realized price, including all cash derivative
settlements, received during 2017 was $42.16 per Boe compared to $44.27
per Boe in 2016. The gain (loss) on settled derivatives increased
Northern’s average realized price per Boe by $0.70 in 2017 and increased
average realized price per Boe by $12.31 in 2016.
As a result of forward oil price changes, Northern recognized a non-cash
mark-to-market derivative loss of $18.4 million in 2017 compared to a
loss of $76.3 million in 2016. At December 31, 2017, all derivative
contracts were recorded at their fair value, which was a net liability
of $30.2 million, an increase of $18.4 million from the $11.7 million
net liability recorded as of December 31, 2016.
Production Expenses
Production expenses were $49.7 million in 2017 compared to $45.7 million
in 2016. On a per unit basis, production expenses were relatively flat
from $9.14 per Boe in 2016 to $9.21 per Boe in 2017. On an absolute
dollar basis, production expenses in 2017 were 9% higher when compared
to 2016 due primarily to higher processing and maintenance costs, as
well as a 7% increase in the total number of net wells.
Production Taxes
Northern pays production taxes based on realized oil and natural gas
sales. These costs were $20.6 million in 2017 compared to $15.5 million
in 2016. The $5.1 million increase in production taxes in 2017 compared
to 2016 is due to higher commodity prices and higher production levels,
which increased oil and natural gas sales in 2017 as compared to 2016.
As a percentage of oil and natural gas sales, average production tax
rates were 9.2% in 2017 compared to 9.7% in 2016. This decrease in
production tax rates as a percentage of oil and natural gas sales is due
to a change in sales mix, as production taxes on natural gas and NGL
sales are at a lower percentage than that of crude oil sales. Crude oil
sales represented 91% of oil and natural gas sales in 2017 compared to
95% in 2016.
General and Administrative Expense
General and administrative expense was $19.0 million for 2017 compared
to $14.8 million for 2016. The increase in 2017 compared to 2016 was due
in part to a $3.6 million charge in the third quarter of 2017 in
connection with a settlement agreement with our former chief executive
officer, pursuant to which we agreed to pay him $750,000 in cash and
issue him 3,000,000 shares of our common stock. In addition, legal and
professional expense was $1.3 million higher in 2017 compared to 2016,
partially offset by a $0.2 million decrease in cash compensation expense
due primarily to reduced incentive compensation.
Depletion, Depreciation, Amortization and Accretion
Depletion, depreciation, amortization and accretion (“DD&A”) was $59.5
million in 2017 compared to $61.2 million in 2016. Depletion expense,
the largest component of DD&A, was $10.89 per Boe in 2017 compared to
$12.13 per Boe in 2016. The aggregate decrease in depletion expense for
2017 compared to 2016 was driven by a 10% decrease in the depletion rate
per Boe, partially offset by an 8% increase in production levels. The
2017 depletion rate per Boe was lower due to the impairment of oil and
natural gas properties throughout 2016, which lowered the depletable
base.
Impairment of Oil and Natural Gas Properties
Northern did not have any impairment of proved oil and gas properties in
2017. As a result of low prevailing commodity prices during 2016 and
their effect on the proved reserve values of properties, Northern
recorded a non-cash ceiling test impairment of $237.0 million in 2016.
The impairment charge affected our reported net income but did not
reduce our cash flow.
Interest Expense
Interest expense, net of capitalized interest, was $70.3 million in 2017
compared to $64.5 million in 2016. The increase in interest expense for
2017 as compared to 2016 was primarily due to an increase in average
borrowings outstanding between periods, a lower amount of capitalized
interest cost and a higher interest rate on the new term loan credit
agreement that was completed in November 2017 as compared to borrowings
under our prior revolving credit facility (which was repaid with
proceeds from the term loan credit agreement).
Income Tax
The income tax benefit recognized during 2017 was $1.6 million as
compared to an income tax benefit of $1.4 million in 2016. The effective
tax rate in 2017 was 14.6% compared to an effective tax rate of 0.5% in
2016. In 2017 and 2016, the tax benefits recognized related to the
utilization of its alternative minimum tax credit as a result of
favorable tax incentives. Northern recorded a valuation allowance
against certain of its net deferred tax assets due to uncertainty
regarding realization in 2017 and 2016.
Net Loss
Northern recorded a net loss of $9.2 million, or approximately $0.15 per
diluted share, for 2017, compared to a net loss of $293.5 million, or
approximately $4.80 per diluted share, for 2016. In 2017, the net loss
was impacted by a loss on the extinguishment of debt, legal settlement
with the Company’s former chief executive officer, and a non-cash loss
on the mark-to-market of derivative instruments. In 2016, the net loss
was impacted by the non-cash impairment of oil and natural gas
properties and a non-cash loss on the mark-to-market of derivative
instruments.
Non-GAAP Financial Measures
Northern defines Adjusted Net Income as net income (loss) excluding (i)
(gain) loss on the mark-to-market of derivative instruments, net of tax,
(ii) restructuring costs, net of tax, (iii) impairment of oil and
natural gas properties, net of tax, (iv) write-off of debt issuance
costs, net of tax, (v) loss on the extinguishment of debt, net of tax,
and (vi) certain legal settlements, net of tax. Adjusted Net Income for
2017 was $8.5 million (representing $0.14 per diluted share) as compared
to Adjusted Net Income for 2016 of $12.2 million (representing $0.20 per
diluted share). The decrease in Adjusted Net Income in 2017 compared to
2016 was primarily due to lower realized commodity prices, and higher
general and administrative expenses, production expenses and interest
costs, which were partially offset by lower depletion expense and higher
production volumes.
Northern defines Adjusted EBITDA as net income before (i) interest
expense, (ii) income taxes, (iii) depreciation, depletion, amortization,
and accretion, (iv) (gain) loss on the mark-to-market of derivative
instruments, (v) non-cash share based compensation expense, (vi)
write-off of debt issuance costs, (vii) loss on the extinguishment of
debt, and (viii) impairment of oil and natural gas properties. Adjusted
EBITDA for 2017 was $144.7 million, compared to Adjusted EBITDA of
$148.5 million in 2016. The decrease in Adjusted EBITDA in 2017 as
compared to 2016 is primarily due to lower realized commodity prices and
increased general and administrative expenses, partially offset by
higher production volumes.
Adjusted Net Income and Adjusted EBITDA are non-GAAP measures. A
reconciliation of these measures to the most directly comparable GAAP
measure is included in the accompanying financial tables found later in
this release.
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 derivative contracts scheduled to settle after December 31, 2017.
|
|
|
|
|
|
|
Swaps
|
|
Contract Period
|
|
Volume (Bbls)
|
|
Weighted Average Price (per Bbl)
|
|
2018:
|
|
|
|
|
|
1Q
|
|
860,400
|
|
$53.42
|
|
2Q
|
|
829,000
|
|
$53.09
|
|
3Q
|
|
753,000
|
|
$53.42
|
|
4Q
|
|
643,000
|
|
$53.54
|
|
2019:
|
|
|
|
|
|
1Q
|
|
621,000
|
|
$53.01
|
|
2Q
|
|
600,600
|
|
$52.89
|
|
3Q
|
|
524,400
|
|
$52.30
|
|
4Q
|
|
469,200
|
|
$52.22
|
|
2020:
|
|
|
|
|
|
1Q
|
|
327,600
|
|
$50.49
|
|
2Q
|
|
309,400
|
|
$50.41
|
|
3Q
|
|
303,600
|
|
$50.37
|
|
4Q
|
|
303,600
|
|
$50.37
|
|
|
|
|
|
|
FOURTH QUARTER 2017 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, February 23, 2018
at 9:30 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: (855) 638-5677 (US/Canada)
and (262) 912-4762 (International)
Conference ID: 3458237 - Northern Oil and
Gas, Inc. Fourth Quarter and Year-End 2017 Conference Call
Replay Dial-In Number: (855) 859-2056
(US/Canada) and (404) 537-3406 (International)
Replay Access Code: 3458237 - Replay will
be available through March 2, 2018
UPCOMING CONFERENCE SCHEDULE
47th Annual Scotia Howard Weil Energy Conference
March 25 - 28, 2018, New Orleans LA
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 Northern’s control) that
could cause actual results to differ materially from those set forth in
the forward-looking statements, including the following: Northern’s
ability to consummate any transaction with its bondholders, including
the final terms of any such transaction, which could result in the
issuance of a significant amount of equity, changes in crude oil and
natural gas prices, the pace of drilling and completions activity on
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, including as a condition to any transaction
with its bondholders, 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, services
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 any forward-looking statements, except as may
be required by the federal securities laws.
|
|
|
NORTHERN OIL AND GAS, INC.
|
|
STATEMENTS OF OPERATIONS
|
|
|
|
|
|
Three Months Ended
December 31,
|
|
Years Ended
December 31,
|
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
Oil and Gas Sales
|
|
$
|
72,476,191
|
|
|
$
|
47,076,502
|
|
|
$
|
223,963,010
|
|
|
$
|
159,690,883
|
|
|
Gain (Loss) on Derivative Instruments, Net
|
|
(35,477,317
|
)
|
|
(11,141,233
|
)
|
|
(14,666,655
|
)
|
|
(14,818,734
|
)
|
|
Other Revenue
|
|
3,407
|
|
|
8,359
|
|
|
23,314
|
|
|
31,347
|
|
|
Total Revenues
|
|
37,002,281
|
|
|
35,943,628
|
|
|
209,319,669
|
|
|
144,903,496
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING EXPENSES
|
|
|
|
|
|
|
|
|
|
Production Expenses
|
|
13,315,460
|
|
|
11,718,227
|
|
|
49,732,861
|
|
|
45,680,110
|
|
|
Production Taxes
|
|
6,638,456
|
|
|
4,480,705
|
|
|
20,604,256
|
|
|
15,513,608
|
|
|
General and Administrative Expense
|
|
3,076,000
|
|
|
3,735,671
|
|
|
18,987,801
|
|
|
14,757,641
|
|
|
Depletion, Depreciation, Amortization and Accretion
|
|
17,631,875
|
|
|
13,523,186
|
|
|
59,500,155
|
|
|
61,244,158
|
|
|
Impairment of Oil and Natural Gas Properties
|
|
—
|
|
|
—
|
|
|
—
|
|
|
237,012,834
|
|
|
Total Expenses
|
|
40,661,791
|
|
|
33,457,789
|
|
|
148,825,073
|
|
|
374,208,351
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME (LOSS) FROM OPERATIONS
|
|
(3,659,510
|
)
|
|
2,485,839
|
|
|
60,494,596
|
|
|
(229,304,855
|
)
|
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME (EXPENSE)
|
|
|
|
|
|
|
|
|
|
Interest Expense, Net of Capitalization
|
|
(20,881,740
|
)
|
|
(16,195,176
|
)
|
|
(70,286,341
|
)
|
|
(64,485,623
|
)
|
|
Write-off of Debt Issuance Costs
|
|
—
|
|
|
—
|
|
|
(95,135
|
)
|
|
(1,089,507
|
)
|
|
Loss on the Extinguishment of Debt
|
|
(992,950
|
)
|
|
—
|
|
|
(992,950
|
)
|
|
—
|
|
|
Other Income (Expense)
|
|
115,497
|
|
|
(23,240
|
)
|
|
116,042
|
|
|
(15,902
|
)
|
|
Total Other Income (Expense)
|
|
(21,759,193
|
)
|
|
(16,218,416
|
)
|
|
(71,258,384
|
)
|
|
(65,591,032
|
)
|
|
|
|
|
|
|
|
|
|
|
|
LOSS BEFORE INCOME TAXES
|
|
(25,418,703
|
)
|
|
(13,732,577
|
)
|
|
(10,763,788
|
)
|
|
(294,895,887
|
)
|
|
|
|
—
|
|
|
|
|
|
|
|
|
INCOME TAX BENEFIT
|
|
(1,570,016
|
)
|
|
(1,402,179
|
)
|
|
(1,570,016
|
)
|
|
(1,402,179
|
)
|
|
|
|
|
|
|
|
|
|
|
|
NET LOSS
|
|
$
|
(23,848,687
|
)
|
|
$
|
(12,330,398
|
)
|
|
$
|
(9,193,772
|
)
|
|
$
|
(293,493,708
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net Loss Per Common Share – Basic
|
|
$
|
(0.37
|
)
|
|
$
|
(0.20
|
)
|
|
$
|
(0.15
|
)
|
|
$
|
(4.80
|
)
|
|
Net Loss Per Common Share – Diluted
|
|
$
|
(0.37
|
)
|
|
$
|
(0.20
|
)
|
|
$
|
(0.15
|
)
|
|
$
|
(4.80
|
)
|
|
Weighted Average Shares Outstanding – Basic
|
|
64,672,781
|
|
|
61,310,458
|
|
|
62,408,855
|
|
|
61,173,547
|
|
|
Weighted Average Shares Outstanding – Diluted
|
|
64,672,781
|
|
|
61,310,458
|
|
|
62,408,855
|
|
|
61,173,547
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NORTHERN OIL AND GAS, INC.
|
|
BALANCE SHEETS
|
|
|
|
|
December 31, 2017
|
|
December 31, 2016
|
|
ASSETS
|
|
|
|
|
Current Assets:
|
|
|
|
|
Cash and Cash Equivalents
|
$
|
102,183,191
|
|
|
$
|
6,486,098
|
|
|
Accounts Receivable, Net
|
46,851,682
|
|
|
35,840,042
|
|
|
Advances to Operators
|
604,977
|
|
|
1,577,204
|
|
|
Prepaid and Other Expenses
|
2,333,288
|
|
|
1,584,129
|
|
|
Derivative Instruments
|
—
|
|
|
4,517
|
|
|
Income Tax Receivable
|
785,016
|
|
|
1,402,179
|
|
|
Total Current Assets
|
152,758,154
|
|
|
46,894,169
|
|
|
|
|
|
|
|
Property and Equipment
|
|
|
|
|
Oil and Natural Gas Properties, Full Cost Method of Accounting
|
|
|
|
|
Proved
|
2,585,490,133
|
|
|
2,428,595,048
|
|
|
Unproved
|
1,699,344
|
|
|
2,623,802
|
|
|
Other Property and Equipment
|
981,303
|
|
|
977,349
|
|
|
Total Property and Equipment
|
2,588,170,780
|
|
|
2,432,196,199
|
|
|
Less – Accumulated Depreciation, Depletion and Impairment
|
(2,114,951,189
|
)
|
|
(2,055,987,766
|
)
|
|
Total Property and Equipment, Net
|
473,219,591
|
|
|
376,208,433
|
|
|
|
|
|
|
|
Deferred Income Taxes
|
785,000
|
|
|
—
|
|
|
Other Noncurrent Assets, Net
|
5,490,934
|
|
|
8,430,359
|
|
|
|
|
|
|
|
Total Assets
|
$
|
632,253,679
|
|
|
$
|
431,532,961
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS’ DEFICIT
|
|
|
|
|
Current Liabilities:
|
|
|
|
|
Accounts Payable
|
$
|
93,152,297
|
|
|
$
|
56,146,847
|
|
|
Accrued Expenses
|
6,339,425
|
|
|
6,094,938
|
|
|
Accrued Interest
|
4,836,112
|
|
|
4,682,894
|
|
|
Derivative Instruments
|
18,681,891
|
|
|
10,001,564
|
|
|
Asset Retirement Obligations
|
565,521
|
|
|
517,423
|
|
|
Total Current Liabilities
|
123,575,246
|
|
|
77,443,666
|
|
|
|
|
|
|
|
Long-term Debt, Net
|
979,324,222
|
|
|
832,625,125
|
|
|
Derivative Instruments
|
11,496,929
|
|
|
1,738,329
|
|
|
Asset Retirement Obligations
|
8,562,607
|
|
|
6,990,877
|
|
|
Other Noncurrent Liabilities
|
135,225
|
|
|
156,632
|
|
|
|
|
|
|
|
TOTAL LIABILITIES
|
1,123,094,229
|
|
|
918,954,629
|
|
|
|
|
|
|
|
COMMITMENTS AND CONTINGENCIES (NOTE 8)
|
|
|
|
|
|
|
|
|
|
STOCKHOLDERS’ DEFICIT
|
|
|
|
|
Preferred Stock, Par Value $.001; 5,000,000 Authorized, No Shares
Outstanding
|
—
|
|
|
—
|
|
Common Stock, Par Value $.001; 142,500,000 Authorized (12/31/2017 –
66,791,633
Shares Outstanding and 12/31/2016 – 63,259,781
Shares Outstanding)
|
66,792
|
|
|
63,260
|
|
|
Additional Paid-In Capital
|
449,666,390
|
|
|
443,895,032
|
|
|
Retained Deficit
|
(940,573,732
|
)
|
|
(931,379,960
|
)
|
|
Total Stockholders’ Deficit
|
(490,840,550
|
)
|
|
(487,421,668
|
)
|
|
TOTAL LIABILITIES AND STOCKHOLDERS’ DEFICIT
|
$
|
632,253,679
|
|
|
$
|
431,532,961
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Adjusted Net Income
|
|
|
|
|
|
Three Months Ended
December 31,
|
|
Years Ended
December 31,
|
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
|
(in thousands, except share and per common share data)
|
|
Net Loss
|
|
$
|
(23,849
|
)
|
|
$
|
(12,330
|
)
|
|
$
|
(9,194
|
)
|
|
$
|
(293,494
|
)
|
|
Add:
|
|
|
|
|
|
|
|
|
|
Impact of Selected Items:
|
|
|
|
|
|
|
|
|
|
(Gain) Loss on the Mark-to-Market of Derivative Instruments
|
|
33,614
|
|
|
18,212
|
|
|
18,443
|
|
|
76,347
|
|
|
Impairment of Oil and Natural Gas Properties
|
|
—
|
|
|
—
|
|
|
—
|
|
|
237,013
|
|
|
Write-off of Debt Issuance Costs
|
|
—
|
|
|
—
|
|
|
95
|
|
|
1,090
|
|
|
Loss on the Extinguishment of Debt
|
|
993
|
|
|
—
|
|
|
993
|
|
|
—
|
|
|
Legal Settlements
|
|
—
|
|
|
—
|
|
|
3,589
|
|
|
—
|
|
|
Selected Items, Before Income Taxes (Benefit)
|
|
34,607
|
|
|
18,212
|
|
|
23,121
|
|
|
314,449
|
|
|
Income Tax (Benefit) of Selected Items(1)
|
|
(4,119
|
)
|
|
(3,491
|
)
|
|
(5,388
|
)
|
|
(8,723
|
)
|
|
Selected Items, Net of Income Taxes (Benefit)
|
|
30,487
|
|
|
14,721
|
|
|
17,733
|
|
|
305,726
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Net Income
|
|
$
|
6,639
|
|
|
$
|
2,391
|
|
|
$
|
8,539
|
|
|
$
|
12,233
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Shares Outstanding – Basic
|
|
64,672,781
|
|
|
61,310,458
|
|
|
62,408,855
|
|
|
61,173,547
|
|
|
Weighted Average Shares Outstanding – Diluted
|
|
65,077,695
|
|
|
61,823,433
|
|
|
62,769,234
|
|
|
61,824,749
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Loss Per Common Share – Basic
|
|
$
|
(0.37
|
)
|
|
$
|
(0.20
|
)
|
|
$
|
(0.15
|
)
|
|
$
|
(4.80
|
)
|
|
Add:
|
|
|
|
|
|
|
|
|
|
Impact of Selected Items, Net of Income Taxes (Benefit)
|
|
0.47
|
|
|
0.24
|
|
|
0.29
|
|
|
5.00
|
|
|
Adjusted Net Income Per Common Share – Basic
|
|
$
|
0.10
|
|
|
$
|
0.04
|
|
|
$
|
0.14
|
|
|
$
|
0.20
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Loss Per Common Share – Diluted
|
|
$
|
(0.37
|
)
|
|
$
|
(0.20
|
)
|
|
$
|
(0.15
|
)
|
|
$
|
(4.75
|
)
|
|
Add:
|
|
|
|
|
|
|
|
|
|
Impact of Selected Items, Net of Income Taxes (Benefit)
|
|
0.47
|
|
|
0.24
|
|
|
0.29
|
|
|
4.95
|
|
|
Adjusted Net Income Per Common Share – Diluted
|
|
$
|
0.10
|
|
|
$
|
0.04
|
|
|
$
|
0.14
|
|
|
$
|
0.20
|
|
_______________
|
(1)
|
|
For the years ended 2017 and 2016 columns, this represents tax
impact using an estimated tax rate of 39.1% for 2017 and 37.4% for
2016, respectively, and includes adjustments for changes in our
valuation allowance of $3.7 million for 2017, excluding the impact
for the Tax Cuts and Jobs Act that was enacted on December 22, 2017
and $341.3 million for 2016, respectively. For the three months
ended 2017 and 2016 columns, this represents a tax impact using an
estimated tax rate of 38.8% and 46.6%, respectively, and includes
adjustments for changes in our valuation allowance of $9.3 million,
excluding the impact for the Tax Cuts and Jobs Act and $5.0 million
for the three months ended 2017 and 2016, respectively.
|
|
|
|
|
|
|
|
Reconciliation of Adjusted EBITDA
|
|
|
|
|
|
Three Months Ended
December 31,
|
|
Years Ended
December 31,
|
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
|
(in thousands)
|
|
Net Loss
|
|
$
|
(23,849
|
)
|
|
$
|
(12,330
|
)
|
|
$
|
(9,194
|
)
|
|
$
|
(293,494
|
)
|
|
Add:
|
|
|
|
|
|
|
|
|
|
Interest Expense
|
|
20,882
|
|
|
16,195
|
|
|
70,286
|
|
|
64,486
|
|
|
Income Tax Benefit
|
|
(1,570
|
)
|
|
(1,402
|
)
|
|
(1,570
|
)
|
|
(1,402
|
)
|
|
Depreciation, Depletion, Amortization and Accretion
|
|
17,632
|
|
|
13,523
|
|
|
59,500
|
|
|
61,244
|
|
|
Impairment of Oil and Natural Gas Properties
|
|
—
|
|
|
—
|
|
|
—
|
|
|
237,013
|
|
|
Non-Cash Share Based Compensation
|
|
841
|
|
|
873
|
|
|
6,107
|
|
|
3,182
|
|
|
Write-off of Debt Issuance Costs
|
|
—
|
|
|
—
|
|
|
95
|
|
|
1,090
|
|
|
Loss on the Extinguishment of Debt
|
|
993
|
|
|
—
|
|
|
993
|
|
|
—
|
|
|
Loss on the Mark-to-Market of Derivative Instruments
|
|
33,614
|
|
|
18,212
|
|
|
18,443
|
|
|
76,347
|
|
|
Adjusted EBITDA
|
|
$
|
48,542
|
|
|
$
|
35,071
|
|
|
$
|
144,660
|
|
|
$
|
148,466
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of PV-10
PV-10 may be considered a non-GAAP financial measure and is derived from
the Standardized Measure of discounted future net cash flows, which is
the most directly comparable GAAP financial measure. PV-10 is a
computation of the Standardized Measure of discounted future net cash
flows on a pre-tax basis. PV-10 is equal to the Standardized Measure of
discounted future net cash flows at the applicable date, before
deducting future income taxes, discounted at 10 percent. We believe that
the presentation of PV-10 is relevant and useful to investors because it
presents the discounted future net cash flows attributable to our
estimated net proved reserves prior to taking into account future
corporate income taxes, and it is a useful measure for evaluating the
relative monetary significance of our oil and natural gas properties.
Further, investors may utilize the measure as a basis for comparison of
the relative size and value of our reserves to other companies. We use
this measure when assessing the potential return on investment related
to our oil and natural gas properties. PV-10, however, is not a
substitute for the Standardized Measure of discounted future net cash
flows. Our PV-10 measure and the Standardized Measure of discounted
future net cash flows do not purport to represent the fair value of our
oil and natural gas reserves.
The following table provides the estimated pre-tax PV10% value as of
December 31, 2017, of our proved reserves under the SEC case and the $60
WTI Flat case described elsewhere in this press release, and also
reconciles these amounts to the standardized measure of discounted
future net cash flows.
|
|
|
|
|
|
|
|
|
SEC Case(1)
|
|
$60 WTI Flat(2)
|
|
Standardized Measure Reconciliation
(in thousands)
|
|
|
|
|
Pre-Tax Present Value of Estimated Future Net Revenues
(Pre-Tax
PV10%)
|
|
$
|
758,000
|
|
|
$
|
1,015,881
|
|
|
Future Income Taxes, Discounted at 10%(3)
|
|
(4,014
|
)
|
|
(34,808
|
)
|
|
Standardized Measure of Discounted Future Net Cash Flows
|
|
$
|
753,986
|
|
|
$
|
981,073
|
|
|
|
|
|
|
|
|
|
|
|
____________
|
(1)
|
|
Prices prescribed by SEC based on $51.34 per Bbl of oil and $2.98
per MMbtu for natural gas, which were then adjusted for
transportation and quality differentials to arrive at prices of
$45.90 per Bbl of oil and $3.34 per Mcf for natural gas.
|
|
(2)
|
|
Prices based on $60.00 per Bbl of oil and $3.00 per MMbtu for
natural gas, which were then adjusted for transportation and quality
differentials to arrive at prices of $54.56 per Bbl of oil and $3.36
per Mcf for natural gas.
|
|
(3)
|
|
The expected tax benefits to be realized from utilization of the net
operating loss and tax credit carryforwards are used in the
computation of future income tax cash flows. As a result of
available net operating loss carryforwards and the remaining tax
basis of our assets at December 31, 2017, our future income taxes
were significantly reduced.
|
|
|
|
|
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View source version on businesswire.com: http://www.businesswire.com/news/home/20180222006411/en/
Northern Oil and Gas, Inc.
Brandon Elliott, CFA, 952-476-9800
Interim
President
belliott@northernoil.com
Source: Northern Oil and Gas, Inc.
Released February 22, 2018