NORTHERN OIL & GAS, INC. - FORM 8-K - EX-99.1 - NORTHERN OIL AND GAS, INC. PRESS RELEASE DATED AUGUST 9, 2012

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8-K - NORTHERN OIL AND GAS, INC. FORM 8-K DATED AUGUST 9, 2012 - NORTHERN OIL & GAS, INC.	nog8k_08092012.htm

Exhibit 99.1

Northern Oil and Gas, Inc. Announces 2012 Second Quarter Results of Operations and an Updated 2012 Drilling and Acreage Plan

WAYZATA, MINNESOTA — August 9, 2012 — Northern Oil and Gas, Inc. (NYSE MKT: NOG) (“Northern Oil”) today announced 2012 second quarter results of operations and an updated 2012 drilling and acreage plan.

2012 SECOND QUARTER HIGHLIGHTS

·	Quarterly production of 947,468 barrels of oil equivalent (“Boe”), or 10,412 average Boe per day

·	Oil and Gas Sales of $70.4 million, representing a 99% year-over-year increase

·	Net Income of $43.6 million, or $0.70 per diluted share

·	Adjusted EBITDA of $53.1 million, representing a 134% year-over-year increase

·	136% year-over-year production growth compared to 2011 second quarter

·	22% sequential quarter-over-quarter production growth compared to 2012 first quarter

·	15.8 net wells completed and placed into production during 2012 second quarter, resulting in 87.6 total net producing wells as of June 30, 2012

ACREAGE UPDATE

As of June 30, 2012, Northern Oil controlled approximately 180,000 net acres in the Williston Basin Bakken and Three Forks plays. During the second quarter of 2012, Northern Oil acquired or earned through farm-in arrangements leasehold interests covering an aggregate of 7,060 net mineral acres in its key prospect areas, for an average cost of approximately $2,184 per net acre.

As of June 30, 2012, Northern Oil controlled approximately 109,000 net acres that were developed, held by production, held by operations or permitted, which represented approximately 61% of Northern Oil’s total Bakken and Three Forks position.

During the second quarter of 2012, Northern Oil had leases expire covering approximately 1,400 net acres. Northern Oil currently controls approximately 865 undeveloped net acres that are prospective for the Bakken and Three Forks and could potentially expire in the remainder of 2012, representing approximately 0.5% of Northern Oil’s overall Williston Basin position.

DRILLING AND COMPLETIONS UPDATE

During the second quarter of 2012, Northern Oil participated in 162 gross (15.8 net) wells that were completed and placed into production. As a result, Northern Oil’s producing wells totaled 955 gross (87.6 net) as of June 30, 2012. In addition to these wells, Northern Oil was participating in 150 gross (10.8 net) Bakken or Three Forks wells drilling or awaiting completion at June 30, 2012. Northern Oil participated in approximately 266 gross (22.5 net) wells that were spud during the first half of 2012.

UPDATED 2012 DRILLING AND ACREAGE PLAN

In the first half of 2012, Northern Oil participated in the spudding of 22.5 net wells and reaffirms its expectation to participate in the spudding of approximately 44 net wells for the year. Based on current drilling and completion costs reflected on authorizations for expenditures received from operating partners, Northern Oil estimates the average completed well cost will be $8.8 million during 2012, which represents an increase from a previously estimated $8.2 million per well. As a result, Northern Oil expects capital expenditures related to 2012 spud wells will approximate $387 million, an increase of approximately $27 million from previous estimates.

In the first half of 2012, Northern Oil spent $25.1 million on acreage acquisitions and expects to spend a total of $50 million throughout 2012 on acreage acquisitions. This represents a reduction in previous guidance of $60-$80 million in acreage acquisition costs for 2012.

Northern Oil expects to fund future capital expenditures through cash flow and its available borrowing capacity. Northern Oil ended the second quarter of 2012 with approximately $25 million in cash and no borrowings under its $300 million revolving credit facility.

MASTER LIMITED PARTNERSHIP UPDATE

Based on the current profile of Northern Oil’s production base and the decline in oil prices, management has determined that the present time is not appropriate to achieve optimal valuation through utilization of a master limited partnership structure. As such, Northern Oil has determined to re-evaluate this strategy in mid-2013 and continue at this time to focus on executing its existing business plan.

SECOND QUARTER 2012 OPERATING AND FINANCIAL RESULTS

The following tables summarize Northern Oil’s second quarter operating and financial results for 2012 as compared to 2011:

	Quarter Ended June 30,
	2012			2011			Change
Net Production:
Oil (Bbl)		883,645			376,170			135	%
Natural Gas and other liquids (Mcf)		382,940			148,547			158	%
Total (Boe)		947,468			400,928			136	%

Average Daily Production:
Oil (Bbl)		9,710			4,134
Natural Gas and other liquids (Mcf)		4,208			1,632
Total (Boe)		10,412			4,406

Average Sales Prices:
Oil (per Bbl)	$	77.51		$	91.85
Effect of oil hedges on average price (per Bbl)		(1.24	)		(14.91	)
Oil net of hedging (per Bbl)		76.27			76.94			(1	)%
Natural Gas and other liquids (per Mcf)		5.09			6.27			(19	)%
Realized price per Boe(a)		73.19			74.51			(2	)%

Average Production Costs (per Boe of production):
Production Expenses	$	7.70		$	6.52			18	%
Production Taxes		7.03			8.26			(15	)%
General and Administrative, including non-cash share based compensation		4.66			6.86			(32	)%
Depletion		26.93			20.83			29	%

(a)	Realized prices include realized gains or losses on cash settlements for commodity derivatives.

In the second quarter of 2012, oil, natural gas and natural gas liquids (i.e., NGL) sales increased 99% as compared to the second quarter of 2011, driven primarily by a 136% increase in production and partially offset by a 2% decrease in realized prices taking into account the effect of settled crude oil derivatives. Higher oil differentials in the second quarter of 2012 lowered the average realized price in the second quarter of 2012 as compared to the same period in 2011. Oil differential during the second quarter of 2012 was $13.72 per barrel, as compared to $7.42 per barrel in the second quarter of 2011.

As a result of forward oil price changes, Northern Oil recognized mark-to-market non-cash derivative gains of $49.8 million in the second quarter of 2012 compared to non-cash gains of $20.8 million in the second quarter of 2011. Additionally, as a result of crude oil derivative settlements, Northern Oil incurred a net cash loss of $1.1 million in the second quarter of 2012, compared to a loss of $5.6 million in the second quarter of 2011.

Production expenses were $7.3 million in the second quarter of 2012 compared to $2.6 million in the second quarter of 2011. Northern Oil experiences increases in aggregate operating expenses as it adds new wells and maintains production from existing properties. On a per unit basis, production expenses per Boe increased from $6.52 per barrel sold in the second quarter of 2011 to $7.70 in the second quarter of 2012. This increase was primarily due to increased water production and increased costs associated with water trucking and disposal.

Northern Oil pays production taxes based on realized oil and gas sales. These costs were $6.7 million in the second quarter of 2012, compared to $3.3 million in the second quarter of 2011. Production taxes were 9.5% in the second quarter of 2012 and 9.3% in the second quarter of 2011. The second quarter of 2012 average production tax rate was higher than the second quarter of 2011 average due to greater levels of production from properties that did not qualify for reduced rates or tax exemptions during 2012.

Total general and administrative expense (including non-cash share based compensation) was $4.4 million for the second quarter of 2012, compared to $2.7 million for the second quarter of 2011. General and administrative expense net of non-cash share based compensation was approximately $2.3 million for the second quarter of 2012, compared to $1.2 million for the second quarter of 2011. This increase was primarily a result of increased staffing to support Northern Oil’s growth.

Depletion, depreciation, amortization and accretion (“DD&A”) was $25.6 million in the second quarter of 2012, compared to $8.4 million in the second quarter of 2011. The increase in aggregate DD&A expense for the second quarter of 2012 compared to the second quarter of 2011 was driven by a 136% increase in production. Depletion expense, the largest component of DD&A, was $26.93 per Boe in the second quarter of 2012, compared to $20.83 per Boe in the second quarter of 2011, which increase was primarily due to increased estimates of future drilling and operating costs.

The provision for income taxes was $28.8 million in the second quarter of 2012, compared to $13.1 million in the second quarter of 2011. The effective tax rate in the second quarter of 2012 was 39.8% compared to an effective tax rate of 39.0% in the second quarter of 2011.

Net income was $43.6 million in the second quarter of 2012, compared to net income of $20.4 million in the second quarter of 2011. Net income per fully diluted share was $0.70 in the second quarter of 2012, compared to $0.33 in the second quarter of 2011.

Non-GAAP net income, excluding unrealized gain (loss) on derivative instruments net of tax, was $13.6 million (representing approximately $0.22 per diluted share) for the second quarter of 2012, as compared to $7.7 million (representing approximately $0.12 per diluted share) for the second quarter of 2011. The increase in non-GAAP net income is primarily due to Northern Oil’s continued addition of crude oil and natural gas production from new wells, which was partially offset by a higher depletion rate in the second quarter of 2012 compared to the second quarter of 2011.

Northern Oil’s Adjusted EBITDA for the second quarter of 2012 was $53.1 million, which represents a 134% increase over Adjusted EBITDA of $22.7 million for the second quarter of 2011.

Northern Oil defines Adjusted EBITDA as net income (loss) before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion, amortization and accretion, (iv) unrealized gain (loss) on derivative instruments and (v) non-cash share based compensation expense. Net income excluding unrealized gain (loss) on derivative instruments net of tax 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 Oil’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 Oil’s performance, and management believes it is providing investors with financial measures that most closely align to its internal measurement processes.

DERIVATIVES UPDATE

The following table summarizes Northern Oil’s current oil derivative contracts, by fiscal quarter:

	COSTLESS COLLARS		SWAPS
Contract Period	Volume (Bbls)	Weighted Average Floor/Ceiling Price (per Bbl)	Volume (Bbls)	Weighted Average Price (per Bbl)
2012:
Q3	370,313	$91.41 - $107.16	337,500	$95.87
Q4	324,140	$91.42 - $107.31	502,500	$93.17
2013:
Q1	535,550	$89.62 - $104.27	150,000	$91.00
Q2	496,481	$89.71 - $104.38	195,000	$90.65
Q3	513,374	$90.29 - $104.72	225,000	$92.21
Q4	487,864	$90.39 - $104.81	270,000	$91.76
2014:
Q1	-	-	540,000	$92.42
Q2	-	-	600,000	$92.13
Q3	-	-	240,000	$90.70
Q4	-	-	240,000	$90.70

RESERVES UPDATE

Northern Oil’s internally estimated total proved reserves at June 30, 2012 were approximately 57.0 million barrels of oil equivalent (MMBoe), a 22% increase as compared to 46.8 MMBoe at December 31, 2011. Approximately 48% of Northern Oil’s proved reserves at June 30, 2012 were categorized as either proved developed producing or proved developed non-producing, meaning behind pipe. Approximately 52% of Northern Oil’s reserves were classified as proved undeveloped at June 30, 2012.

Northern Oil’s estimated future cash flows, discounted at an annual rate of 10 percent before giving effect to income taxes (commonly known as Pre-Tax PV10% value), for proved reserves at June 30, 2012 was $1.2 billion, a increase of 5% from 2011 year-end. Please see below for further information regarding the Pre-Tax PV10% value.

Proved Reserves Summary

	June 30, 2012(1)
Reserve Category	Crude Oil (MBbls)		Natural Gas (MMcf)		MBOE(2)		December 31, 2011 MBOE(2)(3)		% Change			June 30, 2012 Pre-Tax PV10% ($MM)(4)
Proved Developed Producing		20,850		12,548		22,941		14,605		57	%	$	725
Proved Developed Non-Producing		4,023		2,599		4,456		1,143		290	%		100
Proved Undeveloped		26,446		18,983		29,610		31,074		(5	)%		328
Total Proved		51,319		34,130		57,007		46,822		22	%	$	1,153

_________________

(1)

Northern Oil’s reserves estimates as of June 30, 2012 have not been reviewed by Northern Oil’s independent reservoir engineering firm, Ryder Scott Company, LP (“Ryder Scott”). However, such estimates were prepared by Northern Oil’s internal reserve engineer using methodologies consistent with those used by Ryder Scott in estimating Northern Oil’s 2011 year-end reserves, as disclosed in Northern Oil’s Annual Report on Form 10-K for the fiscal year ended December 31, 2011. Crude oil and natural gas reserve quantities and related discounted future net cash flows as of June 30, 2012 are estimated assuming a constant realized price of $85.92 per barrel of crude oil and a constant realized price of $6.25 per Mcf of natural gas (natural gas liquids are included with natural gas). Under SEC guidelines, these crude oil and natural gas prices were based on an unweighted arithmetic average of the applicable first-day-of-the-month price for each month from July 2011 to June 2012.

(2)	Barrels of crude oil equivalent (“BOE”) are computed based on a conversion ratio of one BOE for each barrel of crude oil and one BOE for every 6,000 cubic feet (i.e., 6 Mcf) of natural gas.

(3)

Northern Oil’s reserves estimates as of December 31, 2011 are based on reports prepared by Ryder Scott, as disclosed in Northern Oil’s Annual Report on Form 10-K for the fiscal year ended December 31, 2011. Crude oil and natural gas reserve quantities and related discounted future net cash flows as of December 31, 2011 were estimated assuming a constant realized price of $90.17 per barrel of crude oil and a constant realized price of $6.18 per Mcf of natural gas (natural gas liquids are included with natural gas). Under SEC guidelines, these crude oil and natural gas prices were based on an unweighted arithmetic average of the applicable first-day-of-the-month price for each month from January 2011 to December 2011.

(4)

Pre-tax PV10% value may be considered a non-GAAP financial measure as defined by the Securities and Exchange Commission and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable standardized financial measure. Pre-tax PV10% value is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting future income taxes. See below for a reconciliation of these measures as of June 30, 2012. Management believes pre-tax PV10% value is a useful measure for investors for evaluating the relative monetary significance of Northern Oil’s crude oil and natural gas properties. Management further believes investors may utilize pre-tax PV10% value as a basis for comparison of the relative size and value of Northern Oil’s reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid. Management uses this measure when assessing the potential return on investment related to crude oil and natural gas properties and acquisitions. However, pre-tax PV10% value is not a substitute for the standardized measure of discounted future net cash flows. Pre-tax PV10% value and the standardized measure of discounted future net cash flows do not purport to present the fair value of Northern Oil’s crude oil and natural gas reserves.

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 “Pre-tax PV10%” values of proved reserves presented in the foregoing table may be considered a non-GAAP financial measure as defined by the SEC. The following table reconciles the pre-tax PV10% value of Northern Oil’s estimated proved reserves as of June 30, 2012 to the standardized measure of discounted future net cash flows.


Standardized Measure Reconciliation (in thousands)
Pre-tax present value of estimated future net revenues (Pre-tax PV10%)	$	1,153,457
Future income taxes, discounted at 10%		213,093
Standardized measure of discounted future net cash flows	$	940,364

Uncertainties are inherent in estimating quantities of proved reserves, including many risk factors beyond Northern Oil’s control. Reserve engineering is a subjective process of estimating subsurface accumulations of crude 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, Northern Oil’s actual realized price for crude oil and natural gas is not likely to average the pricing parameters used to calculate proved reserves. As such, the crude oil and natural gas quantities and the value of those commodities ultimately recovered from Northern Oil’s properties will vary from reserve estimates.

MANAGEMENT COMMENT

Michael Reger, CEO, commented: “We continue to see an increased pace of completion activity and a shortening of spud to sales time as a result of an improvement in the availability of completion services in the Williston Basin. As many of our operating partners have mentioned, operational efficiencies and lower service costs are expected to drive enhanced returns in this play.”

SECOND QUARTER 2012 EARNINGS RELEASE CONFERENCE CALL

In conjunction with Northern Oil’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, August 9, 2012 at 9:00 a.m. Central Standard Time. Details for the conference call are as follows:

Dial-In Number: (800) 753-0487 (US/Canada) and (913) 312-1375 (International)

Conference ID: 4834530 - Northern Oil and Gas, Inc. Second Quarter 2012 Earnings Call

Replay Dial-In Number: (888) 203-1112 (US/Canada) and (719) 457-0820 (International)

Replay Access Code: 4834530 - Replay will be available through August 24, 2012

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 Oil’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 Oil’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, general economic or industry conditions, nationally and/or in the communities in which Northern Oil conducts business, changes in the interest rate environment, legislation or regulatory requirements, conditions of the securities markets, Northern Oil’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 Oil’s operations, products, services and prices.

Northern Oil 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 Oil’s control.

CONTACT:

Investor Relations

Erik Nerhus

952-476-9800

NORTHERN OIL AND GAS, INC.

STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2012 AND 2011

(UNAUDITED)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
REVENUES
Oil and Gas Sales	$	70,439,015		$	35,481,664		$	135,578,411		$	62,523,285
Loss on Settled Derivatives		(1,094,885	)		(5,608,231	)		(6,430,482	)		(8,870,287	)
Unrealized Gain (Loss) on Derivative Instruments		49,799,311			20,848,232			40,434,398			(430,397	)
Other Revenue		64,160			104,433			148,266			130,246
Total Revenues		119,207,601			50,826,098			169,730,593			53,352,847

OPERATING EXPENSES
Production Expenses		7,292,253			2,615,546			13,805,601			4,631,902
Production Taxes		6,658,004			3,311,037			12,736,889			5,926,901
General and Administrative Expense		4,419,607			2,749,418			9,100,985			6,040,007
Depletion of Oil and Gas Properties		25,519,809			8,349,600			43,829,309			15,213,079
Depreciation and Amortization		102,307			70,295			199,396			138,608
Accretion of Discount on Asset Retirement Obligations		21,821			7,794			37,453			12,524
Total Expenses		44,013,801			17,103,690			79,709,633			31,963,021

INCOME FROM OPERATIONS		75,193,800			33,722,408			90,020,960			21,389,826

OTHER INCOME (EXPENSE)
Interest Expense		(2,728,104	)		(122,546	)		(2,924,403	)		(243,188	)
Interest Income		700			137,944			1,100			565,629
(Loss) Gain on Available for Sale Securities		-			(244,906	)		-			215,091
Total Other Income (Expense)		(2,727,404	)		(229,508	)		(2,923,303	)		537,532

INCOME BEFORE INCOME TAXES		72,466,396			33,492,900			87,097,657			21,927,358

INCOME TAX PROVISION		28,840,000			13,060,000			34,665,350			8,552,300

NET INCOME	$	43,626,396		$	20,432,900		$	52,432,307		$	13,375,058

OTHER COMPREHENSIVE INCOME NET OF TAX
Unrealized Gains on Marketable Securities (Net of Tax of $404,000 and $109,000 for the three and six months ended June 30, 2011, respectively)		-			630,761			-			173,846
		-			630,761			-			173,846
Reclassification of Derivative Instruments Included in Income (Net of Tax of $111,000 for the Three Months Ended June 30, 2011 and $39,000 and $212,000 for the Six Months June 30, 2012 and 2011, respectively)		-			172,800			62,309			341,950
Total Other Comprehensive Income	$	-		$	803,561		$	62,309		$	515,796

COMPREHENSIVE INCOME	$	43,626,396	$	21,236,461	$	52,494,616	$	13,890,854

Net Income Per Common Share - Basic	$	0.70	$	0.33	$	0.84	$	0.22
Net Income Per Common Share - Diluted	$	0.70	$	0.33	$	0.84	$	0.22
Weighted Average Shares Outstanding - Basic		62,399,869		61,686,463		62,319,553		61,586,603
Weighted Average Shares Outstanding - Diluted		62,705,473		62,053,888		62,687,814		62,028,292

NORTHERN OIL AND GAS, INC.

BALANCE SHEETS

JUNE 30, 2012 AND DECEMBER 31, 2011

	June 30, 2012		December 31,
	(UNAUDITED)		2011
CURRENT ASSETS
Cash and Cash Equivalents	$	25,171,675	$	6,279,587
Trade Receivables		66,063,522		51,418,830
Advances to Operators		7,023,970		17,530,474
Prepaid Expenses		875,212		486,421
Other Current Assets		240,551		317,460
Derivative Instruments		17,732,562		-
Deferred Tax Asset		-		4,472,000
Total Current Assets		117,107,492		80,504,772

PROPERTY AND EQUIPMENT
Oil and Natural Gas Properties, Full Cost Method of Accounting
Proved		939,211,344		566,195,321
Unproved		98,102,110		137,784,903
Other Property and Equipment		3,161,246		2,988,641
Total Property and Equipment		1,040,474,700		706,968,865
Less - Accumulated Depreciation and Depletion		107,294,624		63,265,919
Total Property and Equipment, Net		933,180,076		643,702,946

DERIVATIVE INSTRUMENTS		10,865,174		-

DEBT ISSUANCE COSTS		12,444,823		1,386,201

TOTAL ASSETS	$	1,073,597,565	$	725,593,919

LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts Payable	$	143,061,879	$	110,133,286
Accrued Expenses		4,848,262		164,241
Derivative Instruments		-		9,363,068
Deferred Tax Liability		6,029,000		-
Total Current Liabilities		153,939,141		119,660,595

LONG-TERM LIABILITIES
Revolving Credit Facility		-		69,900,000
8% Senior Notes Due 2020		300,000,000		-
Derivative Instruments		-		2,574,903
Other Noncurrent Liabilities		1,291,844		959,366
Deferred Tax Liability		60,127,000		35,929,000
Total Long-Term Liabilities		361,418,844		109,363,269

TOTAL LIABILITIES		515,357,985		229,023,864

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, (6/30/2012 - 63,612,352
Shares Outstanding and 12/31/2011 – 63,330,421 Shares Outstanding)		63,612		63,330
Additional Paid-In Capital		457,372,977		448,198,350
Retained Earnings		100,802,991		48,370,684
Accumulated Other Comprehensive Loss		-		(62,309	)
Total Stockholders' Equity		558,239,580		496,570,055

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	1,073,597,565	$	725,593,919

NORTHERN OIL AND GAS, INC.

Reconciliation of Adjusted EBITDA

(UNAUDITED)

	Three Months Ended						Six Months Ended
	June 30, 2012			June 30, 2011			June 30, 2012			June 30, 2011

Net Income	$	43,626,396		$	20,432,900		$	52,432,307		$	13,375,058
Add Back:
Interest Expense		2,728,104			122,546			2,924,403			243,188
Income Tax Provision		28,840,000			13,060,000			34,665,350			8,552,300
Depreciation, Depletion, Amortization, and Accretion		25,643,937			8,427,689			44,066,158			15,364,211
Non- Cash Share Based Compensation		2,091,972			1,505,174			4,296,899			3,363,345
Unrealized (Gain) Loss on Derivative Instruments		(49,799,311	)		(20,848,232	)		(40,434,398	)		430,397
Adjusted EBITDA	$	53,131,098		$	22,700,077		$	97,950,719		$	41,328,499

NORTHERN OIL AND GAS, INC.

Reconciliation of Net Income to Non-GAAP Net Income Excluding

Unrealized (Gain) Loss on Derivative Instruments, Net of Tax

(UNAUDITED)

	Three Months Ended						Six Months Ended
	June 30, 2012			June 30, 2011			June 30, 2012			June 30, 2011

Net Income	$	43,626,396		$	20,432,900		$	52,432,307		$	13,375,058
Add:
Unrealized (Gain) Loss on Derivative Instruments		(49,799,311	)		(20,848,232	)		(40,434,398	)		430,397
Tax Impact		19,820,000			8,131,000			16,093,000			(168,000	)
Net Income without Effect of Certain Items	$	13,647,085		$	7,715,668		$	28,090,909		$	13,637,455

Weighted Average Shares Outstanding - Basic		62,399,869			61,686,463			62,319,553			61,586,603
Weighted Average Shares Outstanding - Diluted		62,705,473			62,053,888			62,687,814			62,028,292

Net Income Per Common Share - Basic	$	0.70		$	0.33		$	0.84		$	0.22
Add:
Change due to Unrealized (Gain) Loss on Derivative Instruments		(0.80	)		(0.34	)		(0.65	)		0.01
Change due to Tax Impact		0.32			0.14			0.26			(0.01	)
Net Income without Effect of Certain Items Per Common Share - Basic	$	0.22		$	0.13		$	0.45		$	0.22

Net Income Per Common Share - Diluted	$	0.70		$	0.33		$	0.84		$	0.22
Add:
Change due to Unrealized (Gain) Loss on Derivative Instruments		(0.80	)		(0.34	)		(0.65	)		0.01
Change due to Tax Impact		0.32			0.13			0.26			(0.01	)
Net Income without Effect of Certain Items Per Common Share - Diluted	$	0.22		$	0.12		$	0.45		$	0.22

NORTHERN OIL & GAS, INC. - FORM 8-K - EX-99.1 - NORTHERN OIL AND GAS, INC. PRESS RELEASE DATED AUGUST 9, 2012 - August 9, 2012

Attached files

NORTHERN OIL & GAS, INC. Reports