MINNEAPOLIS, Nov. 8, 2017 /PRNewswire/ -- Northern Oil
and Gas, Inc. (NYSE American: NOG) today announced 2017 third
quarter results, increased annual production guidance and lowered
operating expense expectations for the fourth quarter.
HIGHLIGHTS
- Daily production increased 11% sequentially to average 15,321
barrels of oil equivalent ("Boe") per day in the third quarter, for
a total of 1,409,501 Boe.
- 3.6 net wells were added to production during the third quarter
and wells in process ended the quarter at 18.0 net wells, the
highest level since 2014.
- Northern now expects average daily production for 2017 to
increase between 5% - 6% compared to 2016 and expects to add
approximately 14.0 net wells to production for the year.
- Northern closed a new credit facility on November 1st that provides liquidity of
approximately $235 million, comprised
of $135 million of cash on hand and
$100 million of delayed draw term
loan availability.
Northern's GAAP net loss for the third quarter of 2017 was
$16.1 million. Adjusted net
income for the quarter was $2.2
million. Adjusted EBITDA for the quarter was
$35.7 million. See "Non-GAAP
Financial Measures" below for additional information on these
measures.
MANAGEMENT COMMENT
"It is validating to see our efforts over the last year come to
fruition and to see the momentum we have generated as we approach
2018," commented Northern's Interim CEO and CFO, Tom Stoelk. "Our focus on capital
allocation is showing up in better well productivity and increased
production levels, and our wells in process are concentrated among
operators getting some of the best results in the basin. Our
new credit facility with TPG Sixth Street Partners has extended our
debt maturity and increased our access to capital. This
additional liquidity combined with Northern's high-quality assets
and returns-focused capital allocation strategy provides a solid
foundation to increase shareholder value."
GUIDANCE
Northern is increasing its 2017 guidance and now expects average
daily production for 2017 to increase between 5% - 6% compared to
2016. As a result of increased activity on its acreage
Northern now expects to add approximately 14 net wells to
production for the year. This coupled with the growth in
Northern's wells in process inventory resulted in a revised annual
capital budget of $130 million for
2017.
Management's current expectations for fourth quarter of 2017
operating metrics are as follows:
Operating
Expenses:
|
|
Fourth Quarter
2017
|
Production Expenses (per Boe)
|
|
$9.00 -
$9.25
|
Production Taxes (% of Oil & Gas Sales)
|
|
9.4%
|
General and Administrative Expense (per Boe)
|
|
$3.00 -
$3.25
|
|
|
|
Average
Differential to NYMEX WTI
|
|
$6.00 -
$7.00
|
LIQUIDITY
At September 30, 2017, Northern had $155.0 million in outstanding borrowings under
its revolving credit facility. On November 1, 2017, Northern announced that it had
closed an agreement with TPG Sixth Street Partners for a new five
year $400 million first lien credit
facility. At closing, an initial amount of $300 million was funded and a portion of these
proceeds were used to retire and repay the old revolving credit
facility. Based on this new credit facility, Northern had
available liquidity of approximately $235
million as of November 1,
2017, comprised of $135
million of cash on hand and $100
million of delayed draw term loan availability.
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 September 30, 2017.
|
|
Swaps
|
|
Collars
|
Contract
Period
|
|
Volume
(Bbls)
|
|
Weighted
Average
Price (per Bbl)
|
|
Volume
(Bbls)
|
|
Weighted
Average
Floor - Ceiling
Prices (per Bbl)
|
2017:
|
|
|
|
|
|
|
|
|
4Q
|
|
629,500
|
|
$53.61
|
|
75,000
|
|
$50.00 -
$60.06
|
2018:
|
|
|
|
|
|
|
|
|
1Q
|
|
825,000
|
|
$53.08
|
|
—
|
|
—
|
2Q
|
|
829,000
|
|
$53.09
|
|
—
|
|
—
|
3Q
|
|
753,000
|
|
$53.42
|
|
—
|
|
—
|
4Q
|
|
643,000
|
|
$53.54
|
|
—
|
|
—
|
2019:
|
|
|
|
|
|
|
|
|
1Q
|
|
315,000
|
|
$51.21
|
|
—
|
|
—
|
2Q
|
|
318,500
|
|
$51.21
|
|
—
|
|
—
|
3Q
|
|
322,000
|
|
$51.21
|
|
—
|
|
—
|
4Q
|
|
322,000
|
|
$51.21
|
|
—
|
|
—
|
2020:
|
|
|
|
|
|
|
|
|
1Q
|
|
182,000
|
|
$49.76
|
|
—
|
|
—
|
2Q
|
|
182,000
|
|
$49.76
|
|
—
|
|
—
|
3Q
|
|
184,000
|
|
$49.76
|
|
—
|
|
—
|
4Q
|
|
184,000
|
|
$49.76
|
|
—
|
|
—
|
CAPITAL
EXPENDITURES & DRILLING ACTIVITY
|
|
|
|
Three Months Ended
September 30, 2017
|
Capital
Expenditures Incurred:
|
|
|
Drilling, Completion
& Capitalized Workover Expense
|
|
$38.2
million
|
Acreage
|
|
$2.1
million
|
Other
|
|
$0.4
million
|
|
|
|
Net Wells Added to
Production
|
|
3.6
|
Net Producing
Wells (Period-End)
|
|
222.3
|
|
|
|
Net Wells in
Process (Period-End)
|
|
18.0
|
|
|
|
Weighted Average
AFE for In-Process Wells (Period-End)
|
|
$7.4
million
|
The weighted average authorization for expenditure (or AFE) cost
for wells that Northern elected to participate in (consented) was
$7.6 million for the third quarter of
2017, and $7.3 million for the first
nine months of 2017.
ACREAGE
As of September 30, 2017, Northern has leased approximately
145,749 net acres targeting the Williston Basin Bakken and Three Forks
formations. As of September 30, 2017, approximately 87%
of Northern's North Dakota acreage
position, and approximately 86% of Northern's total acreage
position was developed, held by production or held by
operations.
THIRD QUARTER 2017 RESULTS
The following table sets forth selected operating and financial
data for the periods indicated.
|
Three Months Ended
September 30,
|
|
2017
|
|
2016
|
|
%
Change
|
Net
Production:
|
|
|
|
|
|
Oil (Bbl)
|
1,186,814
|
|
|
1,066,684
|
|
|
11
|
%
|
Natural Gas and NGLs
(Mcf)
|
1,336,124
|
|
|
1,020,143
|
|
|
31
|
%
|
Total
(Boe)
|
1,409,501
|
|
|
1,236,708
|
|
|
14
|
%
|
|
|
|
|
|
|
Average Daily
Production:
|
|
|
|
|
|
Oil (Bbl)
|
12,900
|
|
|
11,594
|
|
|
11
|
%
|
Natural Gas and NGLs
(Mcf)
|
14,523
|
|
|
11,089
|
|
|
31
|
%
|
Total
(Boe)
|
15,321
|
|
|
13,442
|
|
|
14
|
%
|
|
|
|
|
|
|
Net
Sales:
|
|
|
|
|
|
Oil Sales
|
$
|
50,309,088
|
|
|
$
|
39,747,741
|
|
|
27
|
%
|
Natural Gas and NGL
Sales
|
3,948,503
|
|
|
1,971,453
|
|
|
100
|
%
|
Gain (Loss) on
Derivative Instruments, Net
|
(12,663,253)
|
|
|
3,381,564
|
|
|
(474)
|
%
|
Other
Revenue
|
4,321
|
|
|
8,650
|
|
|
(50)
|
%
|
Total
Revenues
|
41,598,659
|
|
|
45,109,408
|
|
|
(8)
|
%
|
|
|
|
|
|
|
Average Sales
Prices:
|
|
|
|
|
|
Oil (per
Bbl)
|
$
|
42.39
|
|
|
$
|
37.26
|
|
|
14
|
%
|
Effect of Gain on
Settled Derivatives on Average Price (per Bbl)
|
2.86
|
|
|
8.46
|
|
|
(66)
|
%
|
Oil Net of Settled
Derivatives (per Bbl)
|
45.25
|
|
|
45.72
|
|
|
(1)
|
%
|
Natural Gas and NGLs
(per Mcf)
|
2.96
|
|
|
1.93
|
|
|
53
|
%
|
Realized Price on a
Boe Basis Including all Realized Derivative Settlements
|
40.90
|
|
|
41.03
|
|
|
—
|
%
|
|
|
|
|
|
|
Operating
Expenses:
|
|
|
|
|
|
Production
Expenses
|
$
|
12,605,513
|
|
|
$
|
10,920,651
|
|
|
15
|
%
|
Production
Taxes
|
5,064,761
|
|
|
4,045,291
|
|
|
25
|
%
|
General and
Administrative Expense
|
7,985,719
|
|
|
2,098,293
|
|
|
281
|
%
|
Depletion,
Depreciation, Amortization and Accretion
|
15,357,685
|
|
|
13,698,020
|
|
|
12
|
%
|
|
|
|
|
|
|
Costs and Expenses
(per Boe):
|
|
|
|
|
|
Production
Expenses
|
$
|
8.94
|
|
|
$
|
8.83
|
|
|
1
|
%
|
Production
Taxes
|
3.59
|
|
|
3.27
|
|
|
10
|
%
|
General and
Administrative Expense
|
5.67
|
|
|
1.70
|
|
|
234
|
%
|
Depletion,
Depreciation, Amortization and Accretion
|
10.90
|
|
|
11.08
|
|
|
(2)
|
%
|
|
|
|
|
|
|
Net Producing
Wells at Period End
|
222.3
|
|
|
208.9
|
|
|
6
|
%
|
Oil and Natural Gas Sales
In the third quarter of 2017, oil, natural gas and NGL sales,
excluding the effect of settled derivatives, increased 30% as
compared to the third quarter of 2016, driven by a 14% increase in
realized prices, excluding the effect of settled derivatives, and a
14% increase in production. The higher average realized price
in the third quarter of 2017 as compared to the same period in 2016
was principally driven by higher average NYMEX oil and natural gas
prices and a lower oil price differential. Oil price
differential during the third quarter of 2017 was $6.22 per barrel, as compared to $7.68 per barrel in the third 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 was a loss of $12.7 million in the third quarter of 2017,
compared to a gain of $3.4 million in
the third quarter of 2016. 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
September 30,
|
|
2017
|
|
2016
|
Cash Received (Paid)
on Derivatives
|
$
|
3,395,117
|
|
|
$
|
9,027,150
|
|
Non-Cash Gain (Loss)
on Derivatives
|
(16,058,370)
|
|
|
(5,645,586)
|
|
Gain (Loss) on
Derivative Instruments, Net
|
$
|
(12,663,253)
|
|
|
$
|
3,381,564
|
|
The average NYMEX oil price for the third quarter of 2017 was
$48.20 compared to $44.94 for the third quarter of 2016.
Northern's average realized price (including all cash derivative
settlements) in the third quarter of 2017 was $40.90 per Boe compared to $41.03 per Boe in the third quarter of
2016. The gain (loss) on settled derivatives increased the
average realized price per Boe by $2.41 in the third quarter of 2017 and increased
the average realized price per Boe by $7.30 in the third quarter of 2016.
Production Expenses
Production expenses were $12.6
million in the third quarter of 2017 compared to
$10.9 million in the third quarter of
2016. On a per unit basis, production expenses increased to
$8.94 per Boe in the third quarter of
2017, compared to $8.83 per Boe in
the third quarter of 2016. On an absolute dollar basis, the
increase in production expenses in the third quarter of 2017 as
compared to the third quarter of 2016 was primarily due to higher
processing costs and salt water disposal costs and a 14% increase
in production, as well as a 6% increase in the total number of net
producing wells.
Production Taxes
Production taxes were $5.1 million
in the third quarter of 2017 compared to $4.0 million in the third quarter of 2016.
The increase is due to higher commodity prices and higher
production levels, which increased oil and natural gas sales in the
third quarter of 2017 as compared to the third quarter of
2016. As a percentage of oil and natural gas sales,
production taxes were 9.3% and 9.7% in the third 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. Production taxes on natural gas and NGL sales are
at a lower percentage than that of crude oil sales. Crude oil
sales represented 93% of oil and natural gas sales in the third
quarter of 2017 compared to 95% in the third quarter of 2016.
General and Administrative Expense
General and administrative expenses were $8.0 million in the third quarter of 2017
compared to $2.1 million in the third
quarter of 2016. The increase was due in part to a
$3.6 million charge in connection
with a settlement agreement with our former chief executive officer
in the third quarter of 2017, and a $0.9
million increase in legal and professional expenses compared
to the third quarter of 2016, partially offset by a $0.4 million decrease in cash compensation
expense due primarily to reduced incentive compensation. In
addition, general and administrative expense in the third quarter
of 2016 was reduced by a $1.8 million
reversal of non-cash share based compensation expense in connection
with the termination of the employment of our former chief
executive officer.
Depletion, Depreciation, Amortization and Accretion
Depletion, depreciation, amortization and accretion ("DD&A")
was $15.4 million in the third
quarter of 2017 compared to $13.7
million in the third quarter of 2016. Depletion
expense, the largest component of DD&A, increased by
$1.6 million in the third quarter of
2017 compared to the third quarter of 2016. The aggregate
increase in depletion expense was driven by a 14% increase in
production levels which was partially offset by a 2% decrease in
the depletion rate per Boe. On a per unit basis, depletion expense
was $10.77 per Boe in the third
quarter of 2017 compared to $10.96
per Boe in the third quarter of 2016. The 2017 depletion rate
per Boe was lower due to the impairment of oil and natural gas
properties in 2016, which lowered the depletable base.
Depreciation, amortization and accretion was $0.2 million and $0.1
million in the third quarter of 2017 and 2016,
respectively.
Impairment of Oil and Natural Gas Properties
No impairment of oil and natural gas properties was recorded in
the third quarter of 2017. As a result of low prevailing
commodity prices and their effect on the proved reserve values of
its properties, Northern recorded a non-cash ceiling test
impairment of $43.8 million for the
third quarter of 2016. The impairment charge affected
Northern's reported net income in 2016 but did not reduce cash
flow.
Interest Expense
Interest expense, net of capitalized interest, was $16.7 million for the third quarter of 2017
compared to $16.1 million in the
third quarter of 2016. The increase in interest expense for
the third quarter of 2017 compared to the third quarter of 2016 was
primarily due to higher levels of debt between periods.
Income Tax Provision
During the third quarter of 2017 and 2016, no income tax expense
(benefit) was recorded on the income (loss) before income taxes due
to the valuation allowance placed on the net deferred tax
asset.
Non-GAAP Financial Measures
Adjusted Net Income for the third quarter of 2017 was
$2.2 million (representing
approximately $0.04 per diluted
share), compared to $2.4 million
(representing approximately $0.04 per
diluted share) for the third quarter of 2016. The decrease in
Adjusted Net Income is primarily due to higher operating expenses
which was partially offset by higher production levels.
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) impairment of oil and natural gas properties, net
of tax, (iii) write-off of debt issuance costs, net of tax, and
(iv) certain legal settlements, net of tax.
Adjusted EBITDA for the third quarter of 2017 was $35.7 million, compared to Adjusted EBITDA of
$33.0 million for the third quarter
of 2016. The increase in Adjusted EBITDA is due to
significantly higher production levels which were partially offset
by higher operating expenses. Northern defines Adjusted
EBITDA as net income (loss) 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.
THIRD 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
Thursday, November 9, 2017 at
9:00 a.m. Central Time.
Those wishing to listen to the conference call may do so via the
company's website, www.northernoil.com, or by phone as follows:
Dial-In Number: (855)
638-5677 (US/Canada) and (262)
912-4762 (International)
Conference ID: 3696446 - Northern Oil and Gas, Inc. Third
Quarter 2017 Conference Call
Replay Dial-In Number: (855) 859-2056 (US/Canada) and (404) 537-3406 (International
Replay Access Code: 3696446 - Replay will be available
through November 16, 2017
UPCOMING CONFERENCE SCHEDULE
Capital One Securities, Inc. 12th Annual Energy Conference
December 5
- 7, 2017, 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: 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, 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.
CONTACT:
Brandon Elliott, CFA
Executive Vice President,
Corporate Development and Strategy
952-476-9800
belliott@northernoil.com
CONDENSED
STATEMENTS OF OPERATIONS
|
FOR THE THREE AND
NINE MONTHS ENDED SEPTEMBER 30, 2017 AND 2016
|
(UNAUDITED)
|
|
|
Three Months
Ended
September 30,
|
|
Nine Months
Ended
September 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
REVENUES
|
|
|
|
|
|
|
|
Oil and Gas
Sales
|
$
|
54,257,591
|
|
|
$
|
41,719,194
|
|
|
$
|
151,486,819
|
|
|
$
|
112,614,382
|
|
Gain (Loss) on
Derivative Instruments, Net
|
(12,663,253)
|
|
|
3,381,564
|
|
|
20,810,662
|
|
|
(3,677,502)
|
|
Other
Revenue
|
4,321
|
|
|
8,650
|
|
|
19,911
|
|
|
22,989
|
|
Total
Revenues
|
41,598,659
|
|
|
45,109,408
|
|
|
172,317,392
|
|
|
108,959,869
|
|
|
|
|
|
|
|
|
|
OPERATING
EXPENSES
|
|
|
|
|
|
|
|
Production
Expenses
|
12,605,513
|
|
|
10,920,651
|
|
|
36,417,402
|
|
|
33,961,883
|
|
Production
Taxes
|
5,064,761
|
|
|
4,045,291
|
|
|
13,965,800
|
|
|
11,032,903
|
|
General and
Administrative Expenses
|
7,985,719
|
|
|
2,098,293
|
|
|
15,911,802
|
|
|
11,021,970
|
|
Depletion,
Depreciation, Amortization and Accretion
|
15,357,685
|
|
|
13,698,020
|
|
|
41,868,280
|
|
|
47,720,972
|
|
Impairment of Oil and
Natural Gas Properties
|
—
|
|
|
43,820,791
|
|
|
—
|
|
|
237,012,834
|
|
Total Operating
Expenses
|
41,013,678
|
|
|
74,583,046
|
|
|
108,163,284
|
|
|
340,750,562
|
|
|
|
|
|
|
|
|
|
INCOME (LOSS) FROM
OPERATIONS
|
584,981
|
|
|
(29,473,638)
|
|
|
64,154,108
|
|
|
(231,790,693)
|
|
|
|
|
|
|
|
|
|
OTHER INCOME
(EXPENSE)
|
|
|
|
|
|
|
|
Interest Expense, Net
of Capitalization
|
(16,672,632)
|
|
|
(16,145,440)
|
|
|
(49,404,601)
|
|
|
(48,290,447)
|
|
Write-off of Debt
Issuance Costs
|
—
|
|
|
—
|
|
|
(95,135)
|
|
|
(1,089,507)
|
|
Other
Income
|
184
|
|
|
183
|
|
|
545
|
|
|
7,337
|
|
Total Other Income
(Expense)
|
(16,672,448)
|
|
|
(16,145,257)
|
|
|
(49,499,191)
|
|
|
(49,372,617)
|
|
|
|
|
|
|
|
|
|
INCOME (LOSS)
BEFORE INCOME TAXES
|
(16,087,467)
|
|
|
(45,618,895)
|
|
|
14,654,917
|
|
|
(281,163,310)
|
|
|
|
|
|
|
|
|
|
INCOME TAX
PROVISION (BENEFIT)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
NET INCOME
(LOSS)
|
$
|
(16,087,467)
|
|
|
$
|
(45,618,895)
|
|
|
$
|
14,654,917
|
|
|
$
|
(281,163,310)
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) Per
Common Share – Basic
|
$
|
(0.26)
|
|
|
$
|
(0.74)
|
|
|
$
|
0.24
|
|
|
$
|
(4.60)
|
|
Net Income (Loss) Per
Common Share – Diluted
|
$
|
(0.26)
|
|
|
$
|
(0.74)
|
|
|
$
|
0.24
|
|
|
$
|
(4.60)
|
|
Weighted Average
Shares Outstanding – Basic
|
61,843,377
|
|
|
61,237,627
|
|
|
61,645,920
|
|
|
61,127,577
|
|
Weighted Average
Shares Outstanding – Diluted
|
61,843,377
|
|
|
61,237,627
|
|
|
61,991,292
|
|
|
61,127,577
|
|
CONDENSED BALANCE
SHEETS
|
SEPTEMBER 30,
2017 AND DECEMBER 31, 2016
|
|
|
September 30,
2017
(unaudited)
|
|
December 31,
2016
|
ASSETS
|
|
|
|
Current
Assets:
|
|
|
|
Cash and Cash
Equivalents
|
$
|
6,776,667
|
|
|
$
|
6,486,098
|
|
Accounts
Receivable, Net
|
39,179,206
|
|
|
35,840,042
|
|
Advances to
Operators
|
1,211,517
|
|
|
1,577,204
|
|
Prepaid and
Other Expenses
|
2,278,674
|
|
|
1,584,129
|
|
Derivative
Instruments
|
2,622,120
|
|
|
4,517
|
|
Income Tax
Receivable
|
1,402,179
|
|
|
1,402,179
|
|
Total Current
Assets
|
53,470,363
|
|
|
46,894,169
|
|
|
|
|
|
Property and
Equipment:
|
|
|
|
Oil and
Natural Gas Properties, Full Cost Method of Accounting
|
|
|
|
Proved
|
2,527,686,215
|
|
|
2,428,595,048
|
|
Unproved
|
2,204,991
|
|
|
2,623,802
|
|
Other Property
and Equipment
|
981,303
|
|
|
977,349
|
|
Total Property and
Equipment
|
2,530,872,509
|
|
|
2,432,196,199
|
|
Less –
Accumulated Depreciation, Depletion and Impairment
|
(2,097,463,246)
|
|
|
(2,055,987,766)
|
|
Total Property and
Equipment, Net
|
433,409,263
|
|
|
376,208,433
|
|
|
|
|
|
Derivative
Instruments
|
817,418
|
|
|
—
|
|
Deferred Income Taxes
(Note 9)
|
—
|
|
|
—
|
|
Other Noncurrent
Assets, Net
|
6,668,836
|
|
|
8,430,359
|
|
|
|
|
|
Total
Assets
|
$
|
494,365,880
|
|
|
$
|
431,532,961
|
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS' DEFICIT
|
Current
Liabilities:
|
|
|
|
Accounts
Payable
|
$
|
81,150,980
|
|
|
$
|
56,146,847
|
|
Accrued
Expenses
|
10,041,145
|
|
|
6,094,938
|
|
Accrued
Interest
|
18,693,327
|
|
|
4,682,894
|
|
Derivative
Instruments
|
4,741
|
|
|
10,001,564
|
|
Asset
Retirement Obligations
|
577,886
|
|
|
517,423
|
|
Current
Maturities of Long-term Debt
|
155,000,000
|
|
|
—
|
|
Total Current
Liabilities
|
265,468,079
|
|
|
77,443,666
|
|
|
|
|
|
Long-term Debt,
Net
|
691,118,074
|
|
|
832,625,125
|
|
Derivative
Instruments
|
—
|
|
|
1,738,329
|
|
Asset Retirement
Obligations
|
8,243,001
|
|
|
6,990,877
|
|
Other Noncurrent
Liabilities
|
141,152
|
|
|
156,632
|
|
|
|
|
|
Total
Liabilities
|
$
|
964,970,306
|
|
|
$
|
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 (9/30/2017 – 63,822,028
Shares Outstanding and 12/31/2016 – 63,259,781 Shares
Outstanding)
|
63,822
|
|
|
63,260
|
|
Additional
Paid-In Capital
|
446,056,796
|
|
|
443,895,032
|
|
Retained
Deficit
|
(916,725,044)
|
|
|
(931,379,960)
|
|
Total Stockholders'
Deficit
|
(470,604,426)
|
|
|
(487,421,668)
|
|
TOTAL LIABILITIES
AND STOCKHOLDERS' DEFICIT
|
$
|
494,365,880
|
|
|
$
|
431,532,961
|
|
Reconciliation of
Adjusted Net Income
|
|
|
Three Months
Ended
September 30,
|
|
Nine Months
Ended
September 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Net Income
(Loss)
|
$
|
(16,087,467)
|
|
|
$
|
(45,618,895)
|
|
|
$
|
14,654,917
|
|
|
$
|
(281,163,310)
|
|
Add:
|
|
|
|
|
|
|
|
Impact of
Selected Items:
|
|
|
|
|
|
|
|
(Gain) Loss on
the Mark-to-Market of Derivative
Instruments
|
16,058,370
|
|
|
5,645,586
|
|
|
(15,170,174)
|
|
|
58,135,302
|
|
Write-off of
Debt Issuance Costs
|
—
|
|
|
—
|
|
|
95,135
|
|
|
1,089,507
|
|
Impairment of
Oil and Natural Gas Properties
|
—
|
|
|
43,820,791
|
|
|
—
|
|
|
237,012,834
|
|
Legal
Settlements
|
3,589,431
|
|
|
—
|
|
|
3,589,431
|
|
|
—
|
|
Selected Items,
Before Income Taxes
|
19,647,801
|
|
|
49,466,377
|
|
|
(11,485,608)
|
|
|
296,237,643
|
|
Income Tax of
Selected Items(1)
|
(1,316,686)
|
|
|
(1,494,741)
|
|
|
(1,222,555)
|
|
|
(5,572,304)
|
|
Selected Items,
Net of Income Taxes
|
18,331,115
|
|
|
47,971,636
|
|
|
(12,708,163)
|
|
|
290,665,339
|
|
Adjusted Net
Income
|
$
|
2,243,648
|
|
|
$
|
2,352,741
|
|
|
$
|
1,946,754
|
|
|
$
|
9,502,029
|
|
|
|
|
|
|
|
|
|
Weighted Average
Shares Outstanding – Basic
|
61,843,377
|
|
|
61,237,627
|
|
|
61,645,920
|
|
|
61,127,577
|
|
Weighted Average
Shares Outstanding – Diluted
|
62,114,238
|
|
|
61,771,363
|
|
|
61,991,292
|
|
|
61,825,191
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) Per
Common Share – Basic
|
$
|
(0.26)
|
|
|
$
|
(0.74)
|
|
|
$
|
0.24
|
|
|
$
|
(4.60)
|
|
Add:
|
|
|
|
|
|
|
|
Impact of
Selected Items, Net of Income Taxes
|
0.30
|
|
|
0.78
|
|
|
(0.21)
|
|
|
4.76
|
|
Adjusted Net Income
Per Common Share – Basic
|
$
|
0.04
|
|
|
$
|
0.04
|
|
|
$
|
0.03
|
|
|
$
|
0.16
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) Per
Common Share – Diluted
|
$
|
(0.26)
|
|
|
$
|
(0.74)
|
|
|
$
|
0.24
|
|
|
$
|
(4.55)
|
|
Add:
|
|
|
|
|
|
|
|
Impact of
Selected Items, Net of Income Taxes
|
0.30
|
|
|
0.78
|
|
|
(0.21)
|
|
|
4.70
|
|
Adjusted Net Income
Per Common Share – Diluted
|
$
|
0.04
|
|
|
$
|
0.04
|
|
|
$
|
0.03
|
|
|
$
|
0.15
|
|
|
|
|
|
|
|
|
|
(1)
|
For the 2017 columns,
this represents a tax impact using an estimated tax rate of 37.0%
and 38.6% for the three and nine months ended September 30,
2017, respectively, which includes a reduction of $6.0 million and
an increase of $5.7 million in our valuation allowance for the
three and nine months ended September 30, 2017,
respectively. For the 2016 columns, this represents a tax
impact using an estimated tax rate of 38.8% and 37.0% for the three
and nine months ended September 30, 2016, respectively, which
includes a $17.7 million and $104.0 million adjustment for a change
in valuation allowance for the three and nine months ended
September 30, 2016, respectively.
|
Reconciliation of
Adjusted EBITDA
|
|
|
Three Months
Ended
September 30,
|
|
Nine Months
Ended
September 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Net Income
(Loss)
|
$
|
(16,087,467)
|
|
|
$
|
(45,618,895)
|
|
|
$
|
14,654,917
|
|
|
$
|
(281,163,310)
|
|
Add:
|
|
|
|
|
|
|
|
Interest
Expense
|
16,672,632
|
|
|
16,145,440
|
|
|
49,404,601
|
|
|
48,290,447
|
|
Income Tax
Benefit
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Depreciation,
Depletion, Amortization and Accretion
|
15,357,685
|
|
|
13,698,020
|
|
|
41,868,280
|
|
|
47,720,972
|
|
Impairment of Oil and
Natural Gas Properties
|
—
|
|
|
43,820,791
|
|
|
—
|
|
|
237,012,834
|
|
Non-Cash Share Based
Compensation
|
3,732,509
|
|
|
(712,677)
|
|
|
5,265,868
|
|
|
2,308,793
|
|
Write-off of Debt
Issuance Costs
|
—
|
|
|
—
|
|
|
95,135
|
|
|
1,089,507
|
|
(Gain) Loss on the
Mark-to-Market of Derivative
Instruments
|
16,058,370
|
|
|
5,645,586
|
|
|
(15,170,174)
|
|
|
58,135,302
|
|
Adjusted
EBITDA
|
$
|
35,733,729
|
|
|
$
|
32,978,265
|
|
|
$
|
96,118,627
|
|
|
$
|
113,394,545
|
|
View original
content:http://www.prnewswire.com/news-releases/northern-oil-and-gas-inc-announces-2017-third-quarter-results-300552198.html
SOURCE Northern Oil and Gas, Inc.