Northern Oil and Gas, Inc. Announces 2017 Fourth Quarter and Full Year Results, Provides 2018 Guidance

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:

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.

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.

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.

_________________

FOURTH QUARTER 2017 RESULTS

The following table sets forth selected operating and financial data for
the periods indicated.

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.

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.

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.

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.

Contacts

Northern Oil and Gas, Inc.
Brandon Elliott, CFA, 952-476-9800
Interim
President
[email protected]

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