WAYZATA, Minn., Feb. 26, 2015
/PRNewswire/ -- Northern Oil and Gas, Inc. (NYSE MKT: NOG) today
announced 2014 fourth quarter and full year results, year-end
proved reserves, and 2015 production and capital budget
guidance.
2014 HIGHLIGHTS
- Annual production increased 29% to 5.8 million barrels of oil
equivalent ("Boe"), or 15,794 average Boe per day
- Fourth quarter production increased 29% year-over-year to
17,985 average Boe per day
- 2014 oil and gas sales increased 17% to $431.6 million
- Proved reserves increased 20% to 100.7 million Boe and pre-tax
PV-10 reached $1.7 billion
- Added 589 gross (41.6 net) producing wells, bringing total
producing wells to 2,338 gross (185.7 net)
- Year-end liquidity totaled approximately $261.3 million, comprised of $252 million of revolving credit facility
availability and $9.3 million in
cash
- Exited 2014 with 4.9 million total barrels hedged for 2015 and
the first half of 2016 at an average swap price of $89.53 per barrel
Northern's 2014 GAAP net income was $163.7 million, or $2.69 per diluted share, compared to $53.1 million, or $0.85 per diluted share in 2013. Adjusted
Net Income for 2014 was $57.5
million, or $0.95 per diluted
share, as compared to $66.4 million,
or $1.06 per diluted share, for
2013. Adjusted EBITDA for 2014 was $309.6 million, an increase of 16% when compared
to 2013. See "Non-GAAP Financial Measures" below for
additional information on these measures.
MANAGEMENT COMMENT
"I am very proud of our accomplishments during 2014," commented
Northern's Chairman and Chief Executive Officer, Michael Reger. "Over the course of the
year, we achieved 29% year-over-year production growth and 20%
growth in our proved reserves, while maintaining a strong financial
position. Our continued focus on capital discipline has
driven improvements in our overall well productivity and the growth
of our proved reserve base. That capital discipline, combined
with our hedging position in 2015 and the first half of 2016, puts
Northern in a strong liquidity position to weather the current
downturn in commodity prices. We will continue to be
judicious with our capital in this environment and plan to increase
our investments as commodity prices improve."
2015 CAPITAL PROGRAM AND PRODUCTION GUIDANCE
Northern currently expects total 2015 capital expenditures to be
approximately $140 million, down
approximately 74% versus 2014 levels. This capital
expenditure budget is comprised of approximately $120 million of drilling and completion capital
and approximately $20 million of
acreage acquisitions, workovers and other capitalized costs.
This budget reflects approximately 20 net wells added to production
in 2015, a portion of which were in process at the end of 2014 and
partially accrued for in the 2014 capital budget. Northern
will continue to high-grade its planned capital program for 2015
through concentration of its investment in its highest return
projects. Northern has seen and expects to continue to see
operators delaying drilling and completion operations while they
wait for a reduction in service costs or an increase in commodity
prices. With these expected delays, coupled with the reduced
capital budget, Northern estimates 2015 total production will be
flat with 2014 levels.
ACREAGE AND DRILLING UPDATE
As of December 31, 2014, Northern
controlled approximately 185,018 net acres targeting the
Williston Basin Bakken and Three
Forks. In 2014, Northern acquired leasehold interests
covering an aggregate of approximately 22,668 net mineral acres,
for an average cost of $1,534 per net
acre. In the fourth quarter of 2014, Northern acquired
leasehold interests covering an aggregate of approximately 5,618
net mineral acres, for an average cost of $1,373 per net acre.
As of December 31, 2014,
approximately 76% of Northern's North
Dakota acreage position, and approximately 65% of Northern's
total acreage position, was developed, held by production or held
by operations.
In 2014, Northern added 41.6 net wells to production, bringing
its total producing well count to 185.7 net wells as of
December 31, 2014. Northern added 8.7
net wells to production in the fourth quarter of 2014.
2014 CAPITAL EXPENDITURES
During 2014, Northern's capital expenditures included
approximately $479.5 million of
drilling, completion and capitalized workover costs. This
amount includes percentage of completion accrual amounts that are
attributable to the current wells in process. In addition,
during the year Northern spent $49.9
million on acreage and other acquisition activities in the
Williston Basin and incurred
$7.5 million of other capitalized
costs.
LIQUIDITY UPDATE
Northern ended the year with $298
million drawn on its revolving credit facility, which has a
total borrowing capacity of $550
million. Northern also ended the year with
$9.3 million in cash, resulting in
liquidity of approximately $261.3
million.
2014 YEAR-END RESERVES
Based on reports prepared by Ryder Scott Company, L.P.,
Northern's estimated total proved reserves at December 31, 2014 were approximately 100.7
million barrels of oil equivalent (MMBoe), a 20% increase as
compared to 84.2 MMBoe at December
31, 2013. Pre-Tax PV-10 of the proved reserves as of
December 31, 2014 is approximately
$1.7 billion. The
year-over-year increase in reserves relative to Northern's 2014
production reflects a reserve replacement ratio of 388%.
Approximately 51% of Northern's reserves at December 31, 2014 are categorized as proved
developed, and the reserves were 88% oil.
Additional information regarding Northern's proved reserves,
including estimated future cash flows, discounted at an annual rate
of 10 percent before giving effect to income taxes (commonly known
as Pre-Tax PV-10 value, which may be considered a non-GAAP
measure), is attached at the end of this release.
HEDGING UPDATE
The following table summarizes Northern's open crude oil swap
derivative contracts as of December 31,
2014, by quarter with associated volumes.
|
Contract
Period
|
|
Volumes
(Bbl)
|
|
Weighted
Average
Price
($ per
Bbl)
|
|
2015:
|
|
|
|
|
|
Q1
|
|
990,000
|
|
89.03
|
|
Q2
|
|
990,000
|
|
89.03
|
|
Q3
|
|
990,000
|
|
89.82
|
|
Q4
|
|
990,000
|
|
89.82
|
|
2016:
|
|
|
|
|
|
Q1
|
|
450,000
|
|
90.00
|
|
Q2
|
|
450,000
|
|
90.00
|
FULL YEAR 2014 RESULTS
The following table summarizes the full year operating and
financial results for 2014 as compared to 2013:
|
Year Ended
December 31,
|
|
2014
|
|
2013
|
|
Change
|
|
Net
Production:
|
|
|
|
|
|
|
Oil (Bbl)
|
5,150,913
|
|
4,046,701
|
|
27%
|
|
Natural Gas and NGLs
(Mcf)
|
3,682,781
|
|
2,572,251
|
|
43%
|
|
Total
(Boe)
|
5,764,710
|
|
4,475,409
|
|
29%
|
|
|
|
|
|
|
|
Average Daily
Production:
|
|
|
|
|
|
|
Oil (Bbl)
|
14,112
|
|
11,087
|
|
27%
|
|
Natural Gas and NGLs
(Mcf)
|
10,090
|
|
7,047
|
|
43%
|
|
Total
(Boe)
|
15,794
|
|
12,261
|
|
29%
|
|
|
|
|
|
|
|
Average Sales
Prices:
|
|
|
|
|
|
|
Oil (per
Bbl)
|
$ 79.23
|
|
$ 87.90
|
|
(10)%
|
|
Effect of loss on
settled derivatives (per Bbl)
|
(1.53)
|
|
(3.01)
|
|
(49)%
|
|
Oil net of settled
derivatives (per Bbl)
|
77.70
|
|
84.89
|
|
(8)%
|
|
Natural Gas and NGLs
(per Mcf)
|
6.38
|
|
5.24
|
|
22%
|
|
Realized price per
Boe(a)
|
73.51
|
|
79.77
|
|
(8)%
|
|
|
|
|
|
|
|
Average Production
Costs (per Boe of production):
|
|
|
|
|
|
|
Production
Expenses
|
$ 9.66
|
|
$ 9.35
|
|
3%
|
|
Production
Taxes
|
7.58
|
|
7.81
|
|
(3)%
|
|
General and
Administrative Expense
|
3.05
|
|
3.70
|
|
(18)%
|
|
Depletion,
Depreciation, Amortization and Accretion
|
29.99
|
|
27.79
|
|
8%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Realized prices
include realized gains or losses on cash settlements for commodity
derivatives.
|
Oil and Natural Gas Sales
In 2014, oil, natural gas and natural gas liquids ("NGL") sales,
including the effect of settled derivatives, increased 19% from
2013 to $423.7 million, driven by
average production of 15,794 Boe per day, a 29% increase
year-over-year. Northern's average oil price differential to
the NYMEX WTI benchmark during 2014 was $13.67 per barrel, as compared to $8.68 per barrel in 2013.
Derivative Instruments
For 2014, Northern incurred a loss on settled derivatives of
$7.9 million, compared to a loss of
$12.2 million in 2013. Northern
had a non-cash mark-to-market derivative gain of $171.3 million in 2014 compared to a $21.3 million loss in 2013.
Production Expenses
Production expenses were $55.7
million in 2014, compared to $41.9
million in 2013. Northern experiences an increase in
aggregate operating expenses as it adds new wells and maintains
production from existing properties. On a per unit basis,
production expenses increased 3% from $9.35 per Boe in 2013 to $9.66 per Boe in 2014.
Production Taxes
Northern pays production taxes based on realized oil and natural
gas sales. These costs were $43.7
million in 2014 compared to $35.0
million in 2013. Average production tax rates were
10.1% and 9.5% in 2014 and 2013, respectively. The 2014
average production tax rate was higher than the 2013 average due to
fewer wells that qualified for reduced rates or tax exemptions
during 2014.
General and Administrative Expense
General and administrative expense was $17.6 million for 2014 compared to $16.6 million for 2013. On a per unit basis,
general and administrative expense decreased 18% to $3.05 per Boe in 2014, compared to $3.70 per Boe in 2013.
Depletion, Depreciation, Amortization and Accretion
Depletion, depreciation, amortization and accretion ("DD&A")
was $172.9 million in 2014, compared
to $124.4 million in 2013.
Depletion expense, the largest component of DD&A, averaged
$29.86 per Boe in 2014, compared to
$27.62 per Boe in 2013. The
increase in aggregate DD&A expense for 2014 compared to 2013
was driven by a 29% increase in production and an 8% increase in
our depletion rate per Boe.
Interest Expense
Interest expense was $42.1 million
for 2014 compared to $32.7 million in
2013. The increase in interest expense for 2014 as compared
to 2013 was primarily due to higher weighted average debt amounts
outstanding in 2014.
Income Tax Provision
The provision for income taxes was $99.4
million in 2014, compared to $31.8
million in 2013. The effective tax rate in 2014 was
37.8%, compared to an effective tax rate of 37.4% in 2013.
Net Income
Net income was $163.7 million in
2014, compared to $53.1 million in
2013. The increase in net income in 2014 as compared to 2013
was driven by a $171.3 million gain
on the mark-to-market of derivative instruments, as well as higher
oil and gas sales due to increased production levels. Diluted
net income per common share was $2.69
in 2014, compared to $0.85 in
2013.
Non-GAAP Financial Measures
Adjusted Net Income for 2014 was $57.5
million, or $0.95 per diluted
share, as compared to $66.4 million,
or $1.06 per diluted share, for
2013. Northern defines Adjusted Net Income as net income
excluding (i) loss (gain) on the mark-to-market of derivative
instruments, net of tax, (ii) certain legal settlements, net of tax
and (iii) severance expenses in connection with the 2012 departures
of Northern's former president and former chief operating officer,
net of tax.
Adjusted EBITDA for 2014 was $309.6
million, which represents a 16% increase over Adjusted
EBITDA of $268.0 million for
2013. Northern defines Adjusted EBITDA as net income before
(i) interest expense, (ii) income taxes, (iii) depreciation,
depletion, amortization, and accretion, (iv) loss (gain) on the
mark-to-market of derivative instruments and (v) non-cash share
based compensation expense.
Adjusted Net Income and Adjusted EBITDA are non-GAAP
measures. A reconciliation of these measures to their 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.
FOURTH QUARTER 2014 RESULTS
The following tables summarize Northern's fourth quarter
operating and financial results for 2014 as compared to 2013:
|
Quarter Ended
December 31,
|
|
2014
|
|
2013
|
|
Change
|
|
Net
Production:
|
|
|
|
|
|
|
Oil (Bbl)
|
1,467,212
|
|
1,155,495
|
|
27%
|
|
Natural Gas and NGLs
(Mcf)
|
1,124,427
|
|
765,154
|
|
47%
|
|
Total
(Boe)
|
1,654,617
|
|
1,283,021
|
|
29%
|
|
|
|
|
|
|
|
Average Daily
Production:
|
|
|
|
|
|
|
Oil (Bbl)
|
15,948
|
|
12,560
|
|
27%
|
|
Natural Gas and NGLs
(Mcf)
|
12,222
|
|
8,317
|
|
47%
|
|
Total
(Boe)
|
17,985
|
|
13,946
|
|
29%
|
|
|
|
|
|
|
|
Average Sales
Prices:
|
|
|
|
|
|
|
Oil (per
Bbl)
|
$ 60.30
|
|
$ 82.35
|
|
(27)%
|
|
Effect of (loss) gain
on settled derivatives (per Bbl)
|
11.74
|
|
(2.80)
|
|
|
|
Oil net of settled
derivatives (per Bbl)
|
72.04
|
|
79.55
|
|
(9)%
|
|
Natural Gas and NGLs
(per Mcf)
|
5.32
|
|
5.23
|
|
2%
|
|
Realized price per
Boe(a)
|
67.49
|
|
74.77
|
|
(10)%
|
|
|
|
|
|
|
|
Average Production
Costs (per Boe of production):
|
|
|
|
|
|
|
Production
Expenses
|
$ 9.83
|
|
$ 8.85
|
|
11%
|
|
Production
Taxes
|
5.80
|
|
7.53
|
|
(23)%
|
|
General and
Administrative Expense
|
2.98
|
|
3.51
|
|
(15)%
|
|
Depletion,
Depreciation, Amortization and Accretion
|
29.57
|
|
30.34
|
|
(3)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Realized prices
include realized gains or losses on cash settlements for commodity
derivatives.
|
Oil and Natural Gas Sales
In the fourth quarter of 2014, oil, natural gas and NGL sales,
including the effect of settled derivatives, increased 16%
year-over-year to $111.7 million,
driven by a 29% year-over-year increase in average daily production
to 17,985 Boe per day. Northern's average oil price
differential to the NYMEX WTI benchmark during the fourth quarter
of 2014 was $12.89 per barrel, as
compared to $14.98 per barrel in the
fourth quarter of 2013.
Derivative Instruments
For the fourth quarter of 2014, Northern incurred a net cash
settlement gain of $17.2 million,
compared to a loss of $3.2 million in
the fourth quarter of 2013. Northern had a non-cash
mark-to-market derivative gain of $145.8
million in the fourth quarter of 2014 compared to non-cash
gain of $6.0 million in the fourth
quarter of 2013.
Production Expenses
Production expenses were $16.3
million in the fourth quarter of 2014, compared to
$11.3 million in the fourth quarter
of 2013. Northern experiences an increase in aggregate
operating expenses as it adds new wells and maintains production
from existing properties. On a per unit basis, production expenses
increased from $8.85 per Boe in the
fourth quarter of 2013 to $9.83 per
Boe in the fourth quarter of 2014.
Production Taxes
Northern pays production taxes based on realized oil and gas
sales. These costs were $9.6
million in the fourth quarter of 2014, compared to
$9.7 million in the fourth quarter of
2013. Average production tax rates were 10.2% in the fourth
quarter of 2014 and 9.7% in the fourth quarter of 2013. The
2014 average production tax rate was higher than the 2013 average
due to fewer wells that qualified for reduced rates or tax
exemptions during 2014.
General and Administrative Expense
General and administrative expense was $4.9 million for the fourth quarter of 2014,
compared to $4.5 million for the
fourth quarter of 2013. On a per unit basis, general and
administrative expense decreased 15% to $2.98 per Boe in the fourth quarter of 2014,
compared to $3.51 per Boe in the
fourth quarter of 2013.
Depletion, Depreciation, Amortization and Accretion
DD&A was $48.9 million in the
fourth quarter of 2014, compared to $38.9
million in the fourth quarter of 2013. Depletion
expense, the largest component of DD&A, was $29.45 per Boe in the fourth quarter of 2014,
compared to $30.02 per Boe in the
fourth quarter of 2013. Northern's depletion rate for the fourth
quarter was adjusted in connection with completion of Northern's
2014 year-end reserve report.
Income Tax Provision
The provision for income taxes was $63.0
million in the fourth quarter of 2014, compared to
$10.5 million in the fourth quarter
of 2013. The effective tax rate in the fourth quarter of 2014
was 37.8%, compared to an effective tax rate of 37.6% in the fourth
quarter of 2013.
Net Income
Net income was $103.6 million in
the fourth quarter of 2014, compared to $17.4 million in the fourth quarter of
2013. The increase in net income in the fourth quarter of
2014 was primarily driven by a $90.8
million gain on the mark-to-market of derivative
instruments, net of tax. Diluted net income per common share
was $1.71 in the fourth quarter of
2014, compared to $0.28 in the fourth
quarter of 2013.
Non-GAAP Financial Measures
Adjusted Net Income for the fourth quarter of 2014 was
$12.8 million, or $0.21 per diluted share, as compared to
$13.7 million, or $0.22 per diluted share, for the fourth quarter
of 2013. Northern defines Adjusted Net Income as net income
excluding (i) loss (gain) on the mark-to-market of derivative
instruments, net of tax, (ii) certain legal settlements, net of tax
and (iii) severance expenses in connection with the 2012 departures
of Northern's former president and former chief operating officer,
net of tax.
Northern's Adjusted EBITDA for the fourth quarter of 2014 was
$81.6 million, which represents a 14%
increase over Adjusted EBITDA of $71.7
million for the fourth quarter of 2013. Northern
defines Adjusted EBITDA as net income before (i) interest expense,
(ii) income taxes, (iii) depreciation, depletion, amortization, and
accretion, (iv) (loss) gain on the mark-to-market of derivative
instruments and (v) non-cash share based compensation
expense.
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.
FOURTH QUARTER AND FULL-YEAR 2014 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 27, 2015 at
10:00 a.m. Central Standard
Time. Details for the conference call are as
follows:
|
Conference Call
and Webcast Details:
|
|
|
|
|
Date:
|
Friday, February, 27,
2015
|
|
Time:
|
10:00 a.m. Central
Time
|
|
Webcast:
|
www.northernoil.com
|
|
Dial-In:
|
855-638-5677
|
|
International
Dial-In:
|
262-912-4762
|
|
Conference
ID:
|
88433362
|
|
|
|
|
|
Replay
Information:
|
|
|
|
|
Dial-In:
|
855-859-2056
|
|
International
Dial-In:
|
404-537-3406
|
|
Conference
ID:
|
88433362
|
A replay of the conference call will be available through
March 13, 2015.
UPCOMING CONFERENCE SCHEDULE
43rd Annual Howard Weil Energy Conference
March 22 – March 26, 2015, New
Orleans, LA
IPAA Oil and Gas Investment Symposium
April 7 – April 9, 2015, New
York, NY
ABOUT NORTHERN OIL AND GAS, INC.
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," "anticipate," "target," "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 our 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.
INVESTOR RELATIONS CONTACT:
Brandon Elliott
EVP, Corporate Development and Strategy
952-476-9800
belliott@northernoil.com
Erik Nerhus
VP, Business Development
952-476-9800
enerhus@northernoil.com
|
NORTHERN OIL AND
GAS, INC.
|
|
STATEMENTS OF
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Year
Ended
|
|
|
|
|
|
|
|
|
December
31,
|
|
December
31,
|
|
|
|
|
|
|
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
Oil and Gas
Sales
|
|
$ 94,455,404
|
|
$ 99,160,226
|
|
$ 431,605,015
|
|
$ 369,187,120
|
|
Gain (Loss) on
Settled Derivatives
|
|
17,221,245
|
|
(3,232,459)
|
|
(7,863,104)
|
|
(12,198,633)
|
|
Gains (Losses)
on the Mark-to-Market of Derivative
Instruments
|
|
145,842,035
|
|
5,995,130
|
|
171,275,719
|
|
(21,259,018)
|
|
Other
Revenue
|
|
3,249
|
|
6,888
|
|
9,112
|
|
44,402
|
|
Total
Revenue
|
|
257,521,933
|
|
101,929,785
|
|
595,026,742
|
|
335,773,871
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
EXPENSES
|
|
|
|
|
|
|
|
|
|
Production
Expenses
|
|
16,267,608
|
|
11,348,887
|
|
55,695,615
|
|
41,859,135
|
|
Production
Taxes
|
|
9,600,928
|
|
9,655,169
|
|
43,674,010
|
|
34,958,975
|
|
General and
Administrative Expense
|
|
4,924,823
|
|
4,507,001
|
|
17,602,306
|
|
16,575,440
|
|
Depletion,
Depreciation, Amortization and Accretion
|
|
48,924,152
|
|
38,927,949
|
|
172,883,554
|
|
124,383,374
|
|
Total
Expenses
|
|
79,717,511
|
|
64,439,006
|
|
289,855,485
|
|
217,776,924
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME FROM
OPERATIONS
|
|
177,804,422
|
|
37,490,779
|
|
305,171,257
|
|
117,996,947
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME
(EXPENSE)
|
|
|
|
|
|
|
|
|
|
Other Income
(Expense)
|
|
1,573
|
|
(16,210)
|
|
47,364
|
|
(453,241)
|
|
Interest
Expense, Net of Capitalization
|
|
(11,255,673)
|
|
(9,568,631)
|
|
(42,105,676)
|
|
(32,709,056)
|
|
Total Other
Income (Expense)
|
|
(11,254,100)
|
|
(9,584,841)
|
|
(42,058,312)
|
|
(33,162,297)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
166,550,322
|
|
27,905,938
|
|
263,112,945
|
|
84,834,650
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME TAX
PROVISION
|
|
62,967,000
|
|
10,505,000
|
|
99,367,000
|
|
31,767,614
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ 103,583,322
|
|
$ 17,400,938
|
|
$ 163,745,945
|
|
$ 53,067,036
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME, NET OF TAX
|
|
-
|
|
-
|
|
-
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE INCOME
|
|
$ 103,583,322
|
|
$ 17,400,938
|
|
$ 163,745,945
|
|
$ 53,067,036
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Per
Common Share – Basic
|
|
$
1.71
|
|
$
0.28
|
|
$
2.70
|
|
$
0.85
|
|
Net Income Per
Common Share – Diluted
|
|
$
1.71
|
|
$
0.28
|
|
$
2.69
|
|
$
0.85
|
|
Weighted
Average Shares Outstanding – Basic
|
|
60,507,569
|
|
61,219,556
|
|
60,691,701
|
|
62,364,957
|
|
Weighted
Average Shares Outstanding – Diluted
|
|
60,594,083
|
|
61,575,358
|
|
60,860,769
|
|
62,747,298
|
|
NORTHERN OIL AND
GAS, INC.
|
|
BALANCE
SHEETS
|
|
|
|
December
31,
|
|
2014
|
|
2013
|
|
CURRENT
ASSETS
|
|
|
|
|
Cash and Cash
Equivalents
|
$
9,337,512
|
|
$
5,687,166
|
|
Trade
Receivables
|
85,931,719
|
|
86,816,981
|
|
Advances to
Operators
|
930,034
|
|
618,786
|
|
Prepaid and
Other Expenses
|
895,088
|
|
770,740
|
|
Derivative
Instruments
|
128,893,220
|
|
62,890
|
|
Deferred Tax
Asset
|
-
|
|
10,431,000
|
|
Total Current
Assets
|
225,987,573
|
|
104,387,563
|
|
|
|
|
|
PROPERTY AND
EQUIPMENT
|
|
|
|
|
Oil and Natural
Gas Properties, Full Cost Method of Accounting
|
|
|
|
|
|
|
Proved
|
2,167,452,297
|
|
1,611,073,747
|
|
|
|
Unproved
|
50,642,433
|
|
70,148,348
|
|
|
|
Other Property
and Equipment
|
1,870,369
|
|
1,701,366
|
|
Total Property
and Equipment
|
2,219,965,099
|
|
1,682,923,461
|
|
Less -
Accumulated Depreciation and Depletion
|
(458,038,546)
|
|
(285,616,752)
|
|
Total Property
and Equipment, Net
|
1,761,926,553
|
|
1,397,306,709
|
|
|
|
|
|
DERIVATIVE
INSTRUMENTS
|
25,013,011
|
|
1,745,405
|
|
|
|
|
|
DEBT
ISSUANCE COSTS
|
13,819,195
|
|
16,160,283
|
|
|
|
|
|
TOTAL
ASSETS
|
$
2,026,746,332
|
|
$
1,519,599,960
|
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS' EQUITY
|
|
CURRENT
LIABILITIES
|
|
|
|
|
Accounts
Payable
|
$
231,557,547
|
|
$
168,936,785
|
|
Accrued
Expenses
|
6,653,124
|
|
2,645,178
|
|
Accrued
Interest
|
3,585,536
|
|
3,386,409
|
|
Derivative
Instruments
|
-
|
|
19,119,646
|
|
Deferred Tax
Liability
|
43,938,000
|
|
-
|
|
Total Current
Liabilities
|
285,734,207
|
|
194,088,018
|
|
|
|
|
|
LONG-TERM
LIABILITIES
|
|
|
|
|
Revolving
Credit Facility
|
298,000,000
|
|
75,000,000
|
|
8% Senior
Notes
|
508,053,097
|
|
509,539,823
|
|
Derivative
Instruments
|
579,070
|
|
637,208
|
|
Other
Noncurrent Liabilities
|
5,105,762
|
|
3,832,550
|
|
Deferred Tax
Liability
|
158,412,555
|
|
116,674,000
|
|
Total Long-Term
Liabilities
|
970,150,484
|
|
705,683,581
|
|
|
|
|
|
TOTAL
LIABILITIES
|
1,255,884,691
|
|
899,771,599
|
|
|
|
|
|
COMMITMENTS
AND CONTINGENCIES (NOTE 8)
|
|
|
|
|
|
|
|
|
STOCKHOLDERS' EQUITY
|
|
|
|
|
Preferred
Stock, Par Value $.001; 5,000,000 Authorized, No Shares
Outstanding
|
-
|
|
-
|
|
Common Stock,
Par Value $.001; 95,000,000 Authorized (12/31/2014 –
61,066,712 Shares
Outstanding and 12/31/2013 – 61,858,199 Shares
Outstanding)
|
61,067
|
|
61,858
|
|
Additional
Paid-In Capital
|
433,332,285
|
|
446,044,159
|
|
Retained
Earnings
|
337,468,289
|
|
173,722,344
|
|
Total
Stockholders' Equity
|
770,861,641
|
|
619,828,361
|
|
|
|
|
|
TOTAL
LIABILITIES AND STOCKHOLDERS' EQUITY
|
$
2,026,746,332
|
|
$ 1,519,599,960
|
|
|
|
|
|
Reconciliation of
Adjusted Net Income
|
|
|
|
|
|
Three Months
Ended
December
31,
|
|
Year
Ended
December
31,
|
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
|
|
(in thousands,
except share and per common share data)
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$ 103,583
|
|
$ 17,401
|
|
$ 163,746
|
|
$ 53,067
|
|
Add:
|
|
|
|
|
|
|
|
|
|
(Gain) Loss on the
Mark-to-Market of Derivative
Instruments, Net of
Tax(a)
|
|
(90,757)
|
|
(3,753)
|
|
(106,585)
|
|
13,300
|
|
Severance Expense, Net
of Tax(b)
|
|
-
|
|
-
|
|
-
|
|
-
|
|
Legal Settlements, Net
of Tax(c)
|
|
-
|
|
-
|
|
360
|
|
-
|
|
Adjusted Net
Income
|
|
$
12,826
|
|
$ 13,648
|
|
$ 57,521
|
|
$ 66,367
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
Shares Outstanding – Basic
|
|
60,507,569
|
|
61,219,556
|
|
60,691,701
|
|
62,364,957
|
|
Weighted Average
Shares Outstanding – Diluted
|
|
60,594,083
|
|
61,575,358
|
|
60,860,769
|
|
62,747,298
|
|
|
|
|
|
|
|
|
|
|
Net Income Per Common
Share – Basic
|
|
$
1.71
|
|
$
0.28
|
|
$
2.70
|
|
$
0.85
|
|
Add:
|
|
|
|
|
|
|
|
|
|
Change due to (Gain)
Loss on the Mark-to-Market of
Derivative Instruments, Net of
Tax
|
|
(1.50)
|
|
(0.06)
|
|
(1.76)
|
|
0.21
|
|
Change due to
Severance Expense, Net of Tax
|
|
-
|
|
-
|
|
-
|
|
-
|
|
Change due to Legal
Settlements, Net of Tax
|
|
-
|
|
-
|
|
.01
|
|
|
|
Adjusted Net Income
Per Common Share – Basic
|
|
0.21
|
|
$
0.22
|
|
$
0.95
|
|
$
1.06
|
|
|
|
|
|
|
|
|
|
|
Net Income Per Common
Share – Diluted
|
|
$
1.71
|
|
$
0.28
|
|
$
2.69
|
|
$
0.85
|
|
Add:
|
|
|
|
|
|
|
|
|
|
Change due to (Gain)
Loss on the Mark-to-Market of
Derivative Instruments, Net of
Tax
|
|
(1.50)
|
|
(0.06)
|
|
(1.75)
|
|
0.21
|
|
Change due to
Severance Expense, Net of Tax
|
|
-
|
|
-
|
|
-
|
|
-
|
|
Change due to Legal
Settlements, Net of Tax
|
|
-
|
|
-
|
|
.01
|
|
-
|
|
Adjusted Net Income
Per Common Share – Diluted
|
|
0.21
|
|
$
0.22
|
|
$
0.95
|
|
$
1.06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Adjusted to
reflect related tax benefit (expense) of $55.1 million and $2.2
million for the three months ended December 31, 2014 and 2013,
respectively and $64.7 million and ($8.0 million) for the years
ended December 31, 2014 and 2013 respectively.
|
|
(b) Reflects
severance expense recognized in connection with the departures
during 2012 of our former president and former chief operating
officer. Adjusted to reflect related tax benefit of $2.0 million,
for the year ended December 31, 2012.
|
|
(c) Reflects legal
expense recognized in connection with legal settlement for the year
ended December 31, 2014. Adjusted to reflect related tax benefit of
$0.2 million.
|
|
Reconciliation of
Adjusted EBITDA
|
|
|
|
|
|
|
|
Three Months
Ended
December
31,
|
|
Year
Ended
December
31,
|
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
|
|
(in
thousands)
|
|
Net Income
|
|
$ 103,583
|
|
$ 17,401
|
|
$ 163,746
|
|
$ 53,067
|
|
Add Back:
|
|
|
|
|
|
|
|
|
|
Interest
Expense
|
|
11,256
|
|
9,569
|
|
42,106
|
|
32,709
|
|
Income Tax
Provision
|
|
62,967
|
|
10,505
|
|
99,367
|
|
31,768
|
|
Depreciation,
Depletion, Amortization and Accretion
|
|
48,924
|
|
38,928
|
|
172,884
|
|
124,383
|
|
Non-Cash Share Based
Compensation
|
|
737
|
|
1,251
|
|
2,759
|
|
4,799
|
|
Loss (Gain) on the
Mark-to-Market of Derivative Instruments
|
|
(145,842)
|
|
(5,995)
|
|
(171,276)
|
|
21,259
|
|
Adjusted EBITDA
|
|
$ 81,625
|
|
$ 71,659
|
|
$ 309,586
|
|
$ 267,985
|
|
Proved Reserve
Summary at December 31, 2014(1)
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(MBbl)
|
|
Natural Gas
(MMcf)
|
|
Total
(MBoe)(2)
|
|
Pre-Tax
PV10% Value $M(3)
|
|
PDP
Properties
|
|
35,084
|
|
30,502
|
|
40,167
|
|
$
1,129,152
|
|
PDNP
Properties
|
|
9,582
|
|
7,776
|
|
10,879
|
|
117,144
|
|
PUD
Properties
|
|
44,247
|
|
32,657
|
|
49,690
|
|
455,928
|
|
Total Proved
Properties:
|
|
88,913
|
|
70,935
|
|
100,736
|
|
$
1,702,224
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) The SEC Pricing
Proved Reserves table above values oil and natural gas reserve
quantities and related discounted future net cash flows as of
December 31, 2014 assuming constant realized prices of $83.11 per
barrel of oil and $7.37 per Mcf of natural gas, which includes an
uplift factor of 1.7 to reflect liquids and condensates (natural
gas liquids are included with natural gas). Under SEC guidelines,
these prices represent the average prices per barrel of oil and per
Mcf of natural gas at the beginning of each month in the 12-month
period prior to the end of the reporting period, which averages are
then adjusted to reflect applicable transportation and quality
differentials.
|
|
(2) Boe are computed
based on a conversion ratio of one Boe for each barrel of oil and
one Boe for every 6,000 cubic feet (i.e., 6 Mcf) of 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.
|
The table above assumes prices and costs discounted using an
annual discount rate of 10% without future escalation, without
giving effect to non-property related expenses such as general and
administrative expenses, debt service and depreciation, depletion
and amortization, or federal income taxes. The information in
the table above does not give any effect to or reflect our
commodity derivatives.
The "Pre-tax PV10%" values of our proved reserves presented in
the foregoing table may be considered a non-GAAP financial measure
as defined by the SEC. PV-10 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 reconciles the pre-tax PV10%
value of our SEC Pricing Proved Reserves to the Standardized
Measure of discounted future net cash flows.
|
SEC Pricing Proved
Reserves
|
|
Standardized
Measure Reconciliation
|
|
Pre-Tax Present Value
of Estimated Future Net Revenues (Pre-Tax PV10%)
|
$
1,702,223,625
|
|
Future Income Taxes,
Discounted at 10%
|
296,844,082
|
|
Standardized Measure
of Discounted Future Net Cash Flows
|
$
1,405,379,543
|
Uncertainties are inherent in estimating quantities of proved
reserves, including many risk factors beyond our control.
Reserve engineering is a subjective process of estimating
subsurface accumulations of oil and natural gas that cannot be
measured in an exact manner. As a result, estimates of proved
reserves may vary depending upon the engineer valuing the
reserves. Further, our actual realized price for our oil and
natural gas is not likely to average the pricing parameters used to
calculate our proved reserves. As such, the oil and natural
gas quantities and the value of those commodities ultimately
recovered from our properties will vary from reserve estimates.
To view the original version on PR Newswire,
visit:http://www.prnewswire.com/news-releases/northern-oil-and-gas-inc-announces-2014-fourth-quarter-and-full-year-results-300042244.html
SOURCE Northern Oil and Gas, Inc.