Document


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 8-K
 

CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): February 22, 2018
 

NORTHERN OIL AND GAS, INC.
(Exact name of Registrant as specified in its charter)
Minnesota
001-33999
95-3848122
(State or other jurisdiction
of incorporation)
(Commission File Number)
(IRS Employer
Identification No.)

601 Carlson Parkway, Suite 990 
Minnetonka, Minnesota
55305
(Address of principal executive offices)
(Zip Code)
Registrant’s telephone number, including area code   (952) 476-9800
 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):
o
Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
o
Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17CFR 240.14a-12)
o
Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
o
Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (17CFR §230.405) or Rule 12b-2 of the Securities Exchange Act of 1934 (17CFR §240.12b-2).
Emerging growth company ¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨







Item 2.02     Results of Operations and Financial Condition.

On February 22, 2018, Northern Oil and Gas, Inc. issued a press release announcing 2017 fourth quarter and full year financial and operating results. A copy of the press release is furnished as Exhibit 99.1 hereto.


Item 9.01.    Financial Statements and Exhibits.

Exhibit Number
 
Description
  
  
  
  
Press release of Northern Oil and Gas, Inc., dated February 22, 2018







SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned hereunto duly authorized.

Date: February 22, 2018
NORTHERN OIL AND GAS, INC.
By /s/ Erik J. Romslo                                 
Erik J. Romslo
Executive Vice President, General Counsel and Secretary





Exhibit


Exhibit 99.1

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

MINNEAPOLIS, MINNESOTA - February 22, 2018 - 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:
 
 
2018
Operating Expenses:
 
 
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
 
 
 
Average Differential to NYMEX WTI
 
$3.50 - $4.50

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.






CAPITAL EXPENDITURES & DRILLING ACTIVITY
 
 
Fourth Quarter
2017
 
Full Year
2017
Capital Expenditures Incurred:
 
 
 
 
Drilling, Completion & Capitalized Workover Expense
 
$56.2 million
 
$148.8 million
Acreage
 
  $0.6 million
 
  $4.9 million
Other
 
  $0.5 million
 
  $2.3 million
 
 
 
 
 
Net Wells Added to Production
 
7.1
 
16.9
Net Producing Wells (Period-End)
 
 
 
229.0
 
 
 
 
 
Net Wells in Process (Period-End)
 
 
 
18.3
Increase in Wells in Process Year-over-Year
 
 
 
4.9
Weighted Average AFE for In-Process Wells (Period-End)
 
 
 
$7.6 million

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.
 
 
2017 Boe
 
2016 Boe
 
% Change
 
 
(in thousands)
 
 
Reserve Category
 
 
 
 
 
 
Proved Developed Producing
 
40,050

 
35,676

 
12
%
Proved Developed Non-Producing
 
6,295

 
2,037

 
209
%
Proved Undeveloped
 
29,487

 
16,368

 
80
%
Total Proved
 
75,832

 
54,081

 
40
%

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.





 
Price Cases (includes 5 year PUD limitation rule)
 
SEC Case(1)
 
$60 WTI Flat(2)
 
(in thousands)
Net Proved Reserves (December 31, 2017)
 
 
 
Developed (Boe)
46,345

 
48,069

Undeveloped (Boe)
29,487

 
32,107

Total Proved Reserves (Boe)
75,832

 
80,176

 
 
 
 
Pre-Tax Present Value of Estimated Future Net Revenues
(Pre-Tax PV10%)
(3)
$
758,000

 
$
1,015,881

_________________

(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)
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.











FOURTH QUARTER 2017 RESULTS

The following table sets forth selected operating and financial data for the periods indicated.
 
Three Months Ended
December 31,
 
2017
 
2016
 
% Change
Net Production:
 
 
 
 
 
Oil (Bbl)
1,282,122

 
1,063,535

 
21
 %
Natural Gas and NGLs (Mcf)
1,548,688

 
1,174,434

 
32
 %
Total (Boe)
1,540,237

 
1,259,274

 
22
 %
 
 
 
 
 
 
Average Daily Production:
 
 
 
 
 
Oil (Bbl)
13,936

 
11,560

 
21
 %
Natural Gas and NGL (Mcf)
16,834

 
12,766

 
32
 %
Total (Boe)
16,742

 
13,688

 
22
 %
 
 
 
 
 
 
Average Sales Prices:
 
 
 
 
 
Oil (per Bbl)
$
51.79

 
$
41.83

 
24
 %
Effect of Gain on Settled Derivatives on Average Price (per Bbl)
(1.45
)
 
6.65

 
(122
)%
Oil Net of Settled Derivatives (per Bbl)
50.34

 
48.48

 
4
 %
Natural Gas and NGLs (per Mcf)
3.92

 
2.21

 
77
 %
Realized Price on a Boe Basis Including all Realized Derivative Settlements
45.85

 
43.00

 
7
 %
 
 
 
 
 
 
Costs and Expenses (per Boe):
 
 
 
 
 
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
 %
 
 
 
 
 
 
Net Producing Wells at Period End
229.0

 
213.1

 
7
 %

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.
 
Three Months Ended
December 31,
 
2017
 
2016
 
(in millions)
Derivative Instruments (Hedges):
 
 
 
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
)





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.
  

CONTACT:

Brandon Elliott, CFA
Interim President
952-476-9800
belliott@northernoil.com








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

 
314,450

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

 
305,727


 
 
 
 


 


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.