Northern Oil and Gas, Inc. Announces 2015 Fourth Quarter and Full Year Results

02 Mar, 2016, 16:15 ET from Northern Oil and Gas, Inc.

WAYZATA, Minn., March 2, 2016 /PRNewswire/ -- Northern Oil and Gas, Inc. (NYSE MKT: NOG) today announced 2015 fourth quarter and full year results.

2015 HIGHLIGHTS

  • Oil and gas sales, including cash from settled derivatives, totaled $363.7 million for 2015 and $86.5 million for the fourth quarter of 2015
  • Reduced capital expenditures by 76% compared to 2014, while still growing total production by 3% year-over-year to 16,285 barrels of oil equivalent ("Boe") per day, above stated guidance
  • Reduced cash general and administrative expenses by $2.1 million or 14% compared to 2014
  • Ended the year with $403.4 million of liquidity, composed of $3.4 million in cash and $400 million of revolving credit facility availability
  • Participated in the completion of 292 gross (18.6 net) wells
  • 1.8 million barrels of oil are hedged for 2016 at an average price of $77.50 per barrel

Northern's adjusted net income for the year was $47.6 million, or $0.78 per diluted share.  GAAP net loss for the year, which was impacted by a $1.2 billion non-cash impairment charge, was $975.4 million, or a loss of $16.08 per diluted share.  Adjusted EBITDA for the year was $277.3 million.  See "Non-GAAP Financial Measures" below for additional information on these measures.

MANAGEMENT COMMENT

"Our strategic business model and capital discipline allowed Northern to reduce spending and generate free cash flow in the second half of 2015, while others were struggling to reach cash flow neutrality.  Despite cutting our capital expenditures by 76% this year, we were still able to exceed guidance and grow production by 3%," commented Northern's Chief Executive Officer, Michael Reger.  "We will continue to focus on protecting our balance sheet and maintaining a strong liquidity position through a disciplined and returns-based capital allocation approach."

LIQUIDITY

At December 31, 2015, Northern had $150 million in outstanding borrowings under its revolving credit facility, down from $188 million at June 30, 2015.  With a $550 million borrowing base under the revolving credit facility, Northern had approximately $403.4 million of available liquidity at year-end, including cash on-hand.  As of March 1, 2016, outstanding borrowings under the revolving credit facility had been further reduced to $125 million.  As of March 1, 2016, the estimated cash settlement value of all of Northern's derivative instruments scheduled for settlement during 2016 was $74.0 million.

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 swap derivative contracts scheduled to settle after December 31, 2015.

 

Contract
Period


Volume
(Bbls)


Weighted
Average Price
(per Bbl)

2016:





Q1


450,000


$90.00

Q2


450,000


$90.00

Q3


450,000


$65.00

Q4


450,000


$65.00

 

 

CAPITAL EXPENDITURES & DRILLING ACTIVITY





Fourth Quarter

2015


Full Year

2015

Capital Expenditures Incurred:





Drilling, Completion & Capitalized Workover Expense


$18.9 million


$116.3 million

Acreage


$2.9 million


$7.8 million

Other


$1.5 million


$4.6 million






Net Wells Added to Production


2.4


18.6

Net Producing Wells (Period-End)


204.3


NA






Net Wells in Process (Period-End)


9.7


NA






Weighted Average AFE for In-Process Wells (Period End)


$7.9 million


NA

 

Capital expenditures continued to trend lower throughout 2015.  For the year, the weighted average authorization for expenditure (or AFE) cost for wells that Northern elected to participate in (consented) was $7.7 million; however, these costs were based on original AFE estimates and actual costs may be lower. 

2016 CAPITAL BUDGET

Northern has approved a 2016 capital expenditure budget of up to $99.8 million for development and acreage acquisitions.  The amount, timing and allocation of capital expenditures are highly discretionary and subject to a variety of factors, including commodity prices and the timing of drilling and completion activities on Northern's properties. 

ACREAGE

As of December 31, 2015, Northern controlled approximately 165,908 net acres targeting the Williston Basin Bakken and Three Forks formations.  In 2015, Northern acquired leasehold interests covering an aggregate of approximately 4,355 net acres, for an average cost of $1,314 per net acre.  In the fourth quarter, Northern acquired leasehold interests covering an aggregate of approximately 1,198 net acres, for an average cost of $1,970 per net acre.  As of December 31, 2015, approximately 80% of Northern's North Dakota acreage position, and approximately 73% of Northern's total acreage position, was developed, held by production or held by operations.

2015 YEAR-END RESERVES

Based on reports prepared by Ryder Scott Company, L.P., Northern's estimated total proved reserves at December 31, 2015 were approximately 65.3 million barrels of oil equivalent (MMBoe).  Pre-Tax PV-10 of the proved reserves as of December 31, 2015 is approximately $575.7 million, with 90% of that value categorized as proved developed.  The reserves were 87% 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.

FOURTH QUARTER 2015 RESULTS

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


Three Months Ended

December 31,


2015


2014


% Change

Net Production:






Oil (Bbl)

1,263,864


1,467,212


(14)

Natural Gas and NGLs (Mcf)

1,092,022


1,124,427


(3)

Total (Boe)

1,445,867


1,654,617


(13)







Average Daily Production:






Oil (Bbl)

13,738


15,948


(14)

Natural Gas and NGL (Mcf)

11,870


12,222


(3)

Total (Boe)

15,716


17,985


(13)







Average Sales Prices:






Oil (per Bbl)

$              29.96


$              60.30


(50)

Effect of Gain on Settled Derivatives on Average Price (per Bbl)

37.32


11.74


218

Oil Net of Settled Derivatives (per Bbl)

67.28


72.04


(7)

Natural Gas and NGLs (per Mcf)

1.35


5.32


(75)

Realized Price on a Boe Basis Including all Realized Derivative Settlements

59.83


67.49


(11)







Costs and Expenses (per Boe):






Production Expenses

$                8.15


$                9.83


(17)

Production Taxes

2.93


5.80


(49)

General and Administrative Expense

4.02


2.98


35

Depletion, Depreciation, Amortization and Accretion

16.70


29.57


(44)







Net Producing Wells at Period End

204.3


185.7


10

 

Oil and Natural Gas Sales

In the fourth quarter of 2015, oil, natural gas and NGL sales, excluding the effect of settled derivatives, decreased 58% as compared to the fourth quarter of 2014, driven by a 52% decrease in realized prices and a 13% decrease in production.  The lower average realized price in the fourth quarter of 2015 as compared to the same period in 2014 was principally driven by lower average NYMEX oil and gas prices, which were partially offset by a lower oil price differential.  Oil price differential during the fourth quarter of 2015 was $8.30 per barrel, as compared to $12.89 per barrel in the fourth quarter of 2014. 

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,


2015


2014


(in millions)

Derivative Instruments (Hedges):




Cash Derivative Settlements

$                47.2


$            17.2

Non-Cash Mark-to-Market of Derivative Instruments

(29.6)


145.8

Gain on Derivative Instruments, Net

$                17.6


$          163.0

 

Northern's average realized price (including all cash derivative settlements) received during the fourth quarter of 2015 was $59.83 per Boe compared to $67.49 per Boe in the fourth quarter of 2014.  The gain (loss) on settled derivatives increased Northern's average realized price per Boe by $32.62 in the fourth quarter of 2015 and by $10.40 in the fourth quarter of 2014.

As a result of forward oil price changes, Northern recognized a non-cash mark-to-market derivative loss of $29.6 million in the fourth quarter of 2015, compared to a $145.8 million gain in the fourth quarter of 2014. 

Production Expenses

Production expenses decreased from $16.3 million in the fourth quarter of 2014 to $11.8 million in the fourth quarter of 2015.  On a per unit basis, production expenses decreased 17% from the fourth quarter of 2014 to $8.15 per Boe in the fourth quarter of 2015 primarily as a result of lower contract labor and maintenance costs.

Production Taxes

Northern pays production taxes based on realized crude oil and natural gas sales.  These costs were $4.2 million in the fourth quarter of 2015 compared to $9.6 million in the fourth quarter of 2014.  The $5.4 million decrease in production taxes in 2015 compared to 2014 was due to the decline in oil, natural gas and NGL sales, excluding the effect of settled derivatives.  As a percentage of oil and natural gas sales, production taxes increased slightly to 10.8% in the fourth quarter of 2015. 

General and Administrative Expense

General and administrative expense was $5.8 million for the fourth quarter of 2015 compared to $4.9 million for the fourth quarter of 2014.  General and administrative expenses for the fourth quarter of 2015 were comprised of $2.8 million of cash expense and $3.0 million of non-cash expense.  The increase in 2015 was primarily due to $1.8 million in higher compensation expense which was partially offset by lower legal and professional expenses ($0.5 million) and travel costs ($0.3 million).  The higher compensation costs during the quarter were primarily driven by $1.9 million in non-cash stock-based compensation expense recognized in connection with a new employment agreement with Northern's chief executive officer that was partially offset by Northern's workforce reduction.

Depletion, Depreciation, Amortization and Accretion

Depletion, depreciation, amortization and accretion ("DD&A") was $24.1 million in the fourth quarter of 2015 compared to $48.9 million in the fourth quarter of 2014.  Depletion expense, the largest component of DD&A, was $16.59 per Boe in the fourth quarter of 2015 compared to $29.45 per Boe in the fourth quarter of 2014.  The decrease in 2015 was due to impairment of oil and gas properties, which lowered the depletable base.

Impairment of Oil and Natural Gas Properties

As a result of current low commodity prices and their effect on the proved reserve values of properties in 2015, Northern recorded a non-cash ceiling test impairment of $167.1 million in the fourth quarter of 2015.  Northern did not have any impairment of its proved oil and gas properties in the fourth quarter of 2014.  The impairment charge affected reported net income but did not reduce cash flow.

Interest Expense

Interest expense, net of capitalized interest, was $16.1 million in the fourth quarter of 2015 compared to $11.3 million in the fourth quarter of 2014.  The increase in interest expense for 2015 as compared to 2014 was primarily due to different weighted average debt amounts outstanding between periods, as well as the higher interest rate applicable to the senior notes, compared to borrowings under the revolving credit facility. 

Income Tax Provision

Northern recognized no income tax benefit during the fourth quarter of 2015 due to a valuation allowance placed on its deferred tax asset.  This compares to an income tax provision of $63.0 million or 37.8% of income before income taxes in the fourth quarter of 2014. 

Net Income

Northern recorded a net loss of $172.3 million, or approximately $2.84 per diluted share, for the fourth quarter of 2015, compared to a net gain of $103.6 million, or approximately $1.71 per diluted share, for the fourth quarter of 2014.  Net loss in the fourth quarter of 2015 was impacted by the non-cash impairment of oil and natural gas properties, the valuation allowance placed on the net deferred tax asset, and a non-cash loss on the mark-to-market of derivative instruments.

Non-GAAP Financial Measures

Adjusted Net Income for the fourth quarter of 2015 was $15.6 million (representing approximately $0.25 per diluted share), compared to $12.8 million (representing approximately $0.21 per diluted share) for the fourth quarter of 2014.  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) certain legal settlements, net of tax. 

Adjusted EBITDA for the fourth quarter of 2015 was $67.7 million, compared to Adjusted EBITDA of $81.6 million for the fourth quarter of 2014.  The decrease in Adjusted EBITDA is primarily due to lower realized commodity prices in 2015 compared to 2014.  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 and (vi) 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 2015 RESULTS

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


Year Ended December 31,


2015


2014


% Change

Net Production:






Oil (Bbl)

5,168,687


5,150,913


0

Natural Gas and NGLs (Mcf)

4,651,583


3,682,781


26

Total (Boe)

5,943,950


5,764,710


3







Average Daily Production:






Oil (Bbl)

14,161


14,112


0

Natural Gas and NGL (Mcf)

12,744


10,090


26

Total (Boe)

16,285


15,794


3







Average Sales Prices:






Oil (per Bbl)

$             37.77


$          79.23


(52)

Effect of Gain (Loss) on Settled Derivatives on Average Price (per Bbl)

31.17


(1.53)



Oil Net of Settled Derivatives (per Bbl)

68.94


77.70


(11)

Natural Gas and NGLs (per Mcf)

1.60


6.38


(75)

Realized Price on a Boe Basis Including all Realized Derivative Settlements

61.19


73.51


(17)







Costs and Expenses (per Boe):






Production Expenses

$               8.77


$            9.66


(9)

Production Taxes

3.63


7.58


(52)

General and Administrative Expense

3.20


3.05


5

Depletion, Depreciation, Amortization and Accretion

23.18


29.99


(23)







Net Producing Wells at Period End

204.3


185.7


10

 

Oil and Natural Gas Sales

In 2015, oil, natural gas and NGL sales, excluding the effect of settled derivatives, decreased 53% as compared to 2014, driven by a 54% decrease in realized prices, partially offset by a 3% increase in production.  Oil price differential during 2015 was $9.42 per barrel, as compared to $13.67 per barrel in 2014.

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. 


Year Ended

December 31,


2015


2014


(in millions)

Derivative Instruments (Hedges):




Cash Derivative Settlements

$              161.1


$           (7.9)

Non-Cash Mark-to-Market of Derivative Instruments

(88.7)


171.3

Gain on Derivative Instruments, Net

$                72.4


$         163.4

 

Northern's average realized price (including all cash derivative settlements) received during 2015 was $61.19 per Boe compared to $73.51 per Boe in 2014.  The gain (loss) on settled derivatives increased Northern's average realized price per Boe by $27.10 in 2015 and decreased average realized price per Boe by $1.36 in 2014.

As a result of forward oil price changes, Northern recognized a non-cash mark-to-market derivative loss of $88.7 million in 2015 compared to a gain of $171.3 million in 2014.  At December 31, 2015, all derivative contracts were recorded at their fair value, which was a net asset of $64.6 million, a decrease of $88.7 million from the $153.3 million net asset recorded as of December 31, 2014.

Production Expenses

Production expenses decreased from $55.7 million in 2014 to $52.1 million in 2015.  On a per unit basis, production expenses decreased 9% or $0.89 per Boe to $8.77 per Boe in 2015 compared to 2014.  The lower cost on a per unit basis in 2015 is primarily due to reduced contract labor and maintenance costs. 

Production Taxes

Northern pays production taxes based on realized crude oil and natural gas sales.  These costs were $21.6 million in 2015 compared to $43.7 million in 2014.  The $22.1 million decrease in production taxes in 2015 compared to 2014 was due to the decline in oil, natural gas and NGL sales, excluding the effect of settled derivatives.  As a percentage of oil and natural gas sales, production taxes increased slightly to 10.6% in 2015 compared to 10.1% in 2014. 

General and Administrative Expense

General and administrative expense was $19.0 million for 2015 compared to $17.6 million for 2014.  General and administrative expenses in 2015 as compared to 2014 included higher compensation expenses of $3.9 million that included $0.5 million of restructuring expenses incurred in connection with workforce reductions in response to the current low commodity price environment and $1.9 million of non-cash stock-based compensation expense recognized in connection with a new employment agreement with Northern's chief executive officer.  Partially offsetting the higher compensation amounts were cost reductions in legal and professional expenses ($1.4 million), travel expenses ($0.6 million) and insurance expenses ($0.5 million).  General and administrative expenses for 2015 were comprised of $12.8 million of cash expense and $6.2 million of non-cash expense. 

Depletion, Depreciation, Amortization and Accretion

Depletion, depreciation, amortization and accretion ("DD&A") was $137.8 million in 2015 compared to $172.9 million in 2014.  Depletion expense, the largest component of DD&A, was $23.07 per Boe in 2015 compared to $29.86 per Boe in 2014. 

Impairment of Oil and Natural Gas Properties

As a result of currently prevailing low commodity prices and their effect on the proved reserve values of properties in 2015, Northern recorded a non-cash ceiling test impairment of $1.2 billion in 2015.  Northern did not have any impairment of its proved oil and gas properties in 2014.  The impairment charge affected reported net income but did not reduce cash flow.

Interest Expense

Interest expense was $58.4 million in 2015 compared to $42.1 million in 2014.  The increase in interest expense for 2015 as compared to 2014 was primarily due to different weighted average debt amounts outstanding between periods, as well as the higher interest rate applicable to the senior notes, compared to borrowings under the revolving credit facility. 

Income Tax Provision

The income tax benefit recognized during 2015 was $202.4 million or 17.2% of the loss before income taxes, as compared to an income tax provision of $99.4 million or 37.8% of income before income taxes in 2014.  The lower effective tax rate in 2015 relates to the $232.3 million valuation allowance placed on the net deferred tax asset in 2015, in addition to state income taxes and estimated permanent differences.

Net Income

Northern recorded a net loss of $975.4 million, or approximately $16.08 per diluted share, for 2015, compared to a net gain of $163.7 million, or approximately $2.69 per diluted share, for 2014.  Net loss in 2015 was impacted by the non-cash impairment of oil and natural gas properties, the valuation allowance placed on the net deferred tax asset, and a non-cash loss on the mark-to-market of derivative instruments.

Non-GAAP Financial Measures

Adjusted Net Income for 2015 was $47.6 million (representing approximately $0.78 per diluted share) as compared to Adjusted Net Income for 2014 of $57.5 million (representing approximately $0.95 per diluted share).  For 2015, the decrease in Adjusted Net Income is primarily due to lower realized commodity prices as well as higher interest expense, which were partially offset by lower depletion expense.  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) certain legal settlements, net of tax. 

Adjusted EBITDA for 2015 was $277.3 million, compared to Adjusted EBITDA of $309.6 million for 2014.  The decrease in Adjusted EBITDA in 2015 as compared to 2014 is primarily due to lower realized commodity prices.  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 and (vi) 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. 

FOURTH QUARTER AND FULL-YEAR 2015 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, March 3, 2016 at 10:00 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:  50772234 - Northern Oil and Gas, Inc. Year End 2015 Earnings Call
Replay Dial-In Number: (855) 859-2056 (US/Canada) and (404) 537-3406 (International)
Replay Access Code:  50772234 - Replay will be available through March 10, 2016

UPCOMING CONFERENCE SCHEDULE

44th Annual Scotia Howard Weil Energy Conference 
         March 20March 23, 2016, New Orleans, LA  
IPAA Oil and Gas Investment Symposium 
         April 11April 12, 2016, New York, NY        

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," "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 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 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
EVP, Corporate Development and Strategy
952-476-9800
belliott@northernoil.com



NORTHERN OIL AND GAS, INC.

STATEMENTS OF OPERATIONS




Three Months Ended


Year Ended



December 31,


December 31,



2015


2014


2015


2014

REVENUES










Oil and Gas Sales


$  39,340,256


$  94,455,404


$   202,638,640


$ 431,605,015


Gain on Derivative Instruments, Net


17,563,910


163,063,280


72,382,907


163,412,615


Other Revenue


8,863


3,249


35,866


9,112


Total Revenues


56,913,029


257,521,933


275,057,413


595,026,742











OPERATING EXPENSES










Production Expenses


11,776,670


16,267,608


52,107,984


55,695,615


Production Taxes


4,233,511


9,600,928


21,566,634


43,674,010


General and Administrative Expense


5,817,991


4,924,823


19,042,004


17,602,306


Depletion, Depreciation, Amortization and Accretion


24,140,489


48,924,152


137,769,812


172,883,554


Impairment


167,143,533


-


1,163,959,246


-


Total Expenses


213,112,194


79,717,511


1,394,445,680


289,855,485











INCOME (LOSS) FROM OPERATIONS


(156,199,165)


177,804,422


(1,119,388,267)


305,171,257











OTHER INCOME (EXPENSE)










Other Income (Expense)


(32,218)


1,573


(30,091)


47,364


Interest Expense, Net of Capitalization


(16,081,987)


(11,255,673)


(58,360,387)


(42,105,676)


Total Other Income (Expense)


(16,114,205)


(11,254,100)


(58,390,478)


(42,058,312)











INCOME (LOSS) BEFORE INCOME TAXES


(172,313,370)


166,550,322


(1,177,778,745)


263,112,945










INCOME TAX PROVISION (BENEFIT)


(50)


62,967,000


(202,424,204)


99,367,000










NET INCOME (LOSS)


$(172,313,320)


$103,583,322


$  (975,354,541)


$ 163,745,945










Net Income (Loss) Per Common Share – Basic


$            (2.84)


$             1.71


$             (16.08)


$              2.70

Net Income (Loss) Per Common Share – Diluted


$            (2.84)


$             1.71


$             (16.08)


$              2.69

Weighted Average Shares Outstanding – Basic


60,727,536


60,507,569


60,652,447


60,691,701

Weighted Average Shares Outstanding – Diluted


60,727,536


60,594,083


60,652,447


60,860,769










 


NORTHERN OIL AND GAS, INC.

BALANCE SHEETS



December 31,


2015


2014

CURRENT ASSETS





Cash and Cash Equivalents

$              3,390,389


$              9,337,512


Trade Receivables

58,230,113


85,931,719


Advances to Operators

1,689,879


930,034


Prepaid and Other Expenses

892,867


895,088


Derivative Instruments

64,611,558


128,893,220

Total Current Assets

128,814,806


225,987,573





PROPERTY AND EQUIPMENT





Oil and Natural Gas Properties, Full Cost Method of Accounting






Proved


2,336,757,089


2,167,452,297



Unproved


10,007,529


50,642,433



Other Property and Equipment


1,837,469


1,870,369

Total Property and Equipment

2,348,602,087


2,219,965,099


Less - Accumulated Depreciation, Depletion, and Impairment

(1,759,281,704)


(458,038,546)

Total Property and Equipment, Net

589,320,383


1,761,926,553





DERIVATIVE INSTRUMENTS

-


25,013,011

DEBT ISSUANCE COSTS, NET

15,810,259


13,819,195





TOTAL ASSETS

$          733,945,448


$       2,026,746,332





LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)

CURRENT LIABILITIES





Accounts Payable

$            65,319,170


$          231,557,547


Accrued Expenses

7,893,975


6,653,124


Accrued Interest

4,713,232


3,585,536


Asset Retirement Obligations

188,770


-


Deferred Taxes

-


43,938,000

Total Current Liabilities

78,115,147


285,734,207





LONG-TERM LIABILITIES





Revolving Credit Facility

150,000,000


298,000,000


8% Senior Notes

697,804,829


508,053,097


Derivative Instruments

-


579,070


Asset Retirement Obligations

5,627,586


5,105,762


Deferred Taxes

-


158,412,555

Total Long-Term Liabilities

853,432,415


970,150,484





TOTAL LIABILITIES

931,547,562


1,255,884,691





COMMITMENTS AND CONTINGENCIES (NOTE 8)








STOCKHOLDERS' EQUITY (DEFICIT)





Preferred Stock, Par Value $.001; 5,000,000 Authorized, No Shares Outstanding

-


-


Common Stock, Par Value $.001; 95,000,000 Authorized (12/31/2015 –

     63,120,384 Shares Outstanding and 12/31/2014 – 61,066,712 Shares

     Outstanding)

63,120


61,067


Additional Paid-In Capital

440,221,018


433,332,285


Retained Earnings (Deficit)

(637,886,252)


337,468,289

Total Stockholders' Equity (Deficit)

(197,602,114)


770,861,641





TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)

$          733,945,448


$       2,026,746,332





 

 

Reconciliation of Adjusted Net Income




Three Months Ended

December 31,


Years Ended

December 31,



2015


2014


2015


2014



(in thousands, except share and per common share data)










Net Income (Loss)


$   (172,313)


$   103,583


$       (975,355)


$         163,746

Add:









Impact of Selected Items:









(Gain) Loss on the Mark-to-Market of Derivative Instruments


29,599


(145,842)


88,716


(171,276)

Restructuring Costs


-


-


523


-

Impairment of Oil and Natural Gas Properties


167,144


-


1,163,959


-

Legal Settlements


-


-


-


577

Selected Items, Before Income Taxes (Benefit)


196,743


(145,842)


1,253,198


(170,699)

Income Tax (Benefit) of Selected Items(1)


(8,821)


55,085


(230,259)


64,474

Selected Items, Net of Income Taxes (Benefit)


187,922


(90,757)


1,022,939


(106,225)










Adjusted Net Income


$      15,609


$     12,826


$          47,584


$           57,521










Weighted Average Shares Outstanding – Basic 


60,727,536


60,507,569


60,652,447


60,691,701

Weighted Average Shares Outstanding – Diluted


61,394,762


60,594,083


60,887,698


60,860,769










Net Income (Loss) Per Common Share – Basic


$         (2.84)


$         1.71


$           (16.08)


$               2.70

Add:









Impact of Selected Items, Net of Income Taxes (Benefit)


3.10


1.50


16.86


(1.75)

Adjusted Net Income Per Common Share – Basic


$          0.26


$         0.21


$              0.78


$               0.95










Net Income (Loss) Per Common Share – Diluted


$         (2.81)


$         1.71


$           (16.02)


$               2.69

Add:









Impact of Selected Items, Net of Income Taxes (Benefit)


3.06


1.50


16.80


(1.74)

Adjusted Net Income Per Common Share – Diluted


$          0.25


$         0.21


$              0.78


$               0.95

_______________

(1)

For the years ended 2015 and 2014 columns, this represents a tax impact using an estimated tax rate of 36.9% and 37.8%, respectively.  The 2015 column includes a $232.3 million adjustment for a change in valuation allowance for the year ended December 31, 2015.  For the three months ended 2015 and 2014 columns, this represents a tax impact using an estimated tax rate of 36.1% and 37.8%, respectively.  The three months ended 2015 column includes a $62.2 million adjustment for a change in valuation allowance.

 

 

Reconciliation of Adjusted EBITDA




Three Months Ended

December 31,


Year Ended

December 31,



2015


2014


2015


2014



(in thousands)

Net (Loss) Income


$  (172,313)


$   103,583


$   (975,355)


$     163,746

Add:









Interest Expense


16,082


11,256


58,360


42,106

Income Tax Provision (Benefit)


-


62,967


(202,424)


99,367

Depreciation, Depletion, Amortization and Accretion


24,140


48,924


137,770


172,884

Impairment of Oil and Natural Gas Properties


167,144


-


1,163,959


-

Non-Cash Share Based Compensation


3,052


737


6,273


2,759

(Gain) Loss on the Mark-to-Market of Derivative Instruments


29,599


(145,842)


88,716


(171,276)

          Adjusted EBITDA


$     67,704


$     81,625


$     277,299


$     309,586

 

 

Proved Reserve Summary at December 31, 2015



















SEC Pricing Proved Reserves(1)



Reserve Volumes


PV-10(3)

Reserve Category


Oil

(MBbls)


Natural Gas

(MMcf)


Total

(MBoe)(2)


%


Amount

(In thousands)


%

PDP Properties


35,229


32,414


40,632


62


$          501,806


87

PDNP Properties


1,345


1,206


1,545


3


16,822


3

PUD Properties


20,241


17,281


23,121


35


57,066


10

Total


56,815


50,901


65,298


100


$          575,694


100


















___________________

(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, 2015 assuming constant realized prices of $50.28 per barrel of oil and $2.58 per Mcf of natural gas, which includes an uplift factor of 0.6 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.  The average resulting price used as of December 31, 2015 was $42.03 per barrel of oil and $1.63 per Mcf of natural gas.

(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.

Reconciliation of PV-10 to Standardized Measure

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 as of December 31, 2015 to the Standardized Measure of discounted future net cash flows.

 

SEC Pricing Proved Reserves

(in thousands)

Standardized Measure Reconciliation

Pre-Tax Present Value of Estimated Future Net Revenues (Pre-Tax PV10%)

$                 575,694

Future Income Taxes, Discounted at 10%(1)

(895)

Standardized Measure of Discounted Future Net Cash Flows

$                 574,799

____________

(1)

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, 2015, our future income taxes were significantly reduced.

 

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.

 

SOURCE Northern Oil and Gas, Inc.



RELATED LINKS

http://www.northernoil.com