- Quarterly Report (10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2012

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File No. 1-35097

Voyager Oil & Gas, Inc.

(Exact name of registrant as specified in its charter)

Montana	77-0639000
(State or other jurisdiction	(I.R.S. Employer
of incorporation or organization)	Identification No.)

2718 Montana Ave., Suite 220
Billings, Montana	59101
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (406) 245-4901

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ¨	Accelerated filer x

Non-accelerated filer ¨	Smaller reporting company ¨
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

As of August 6, 2012, there were 70,103,645 shares of Common Stock, $0.001 par value per share, outstanding.

VOYAGER OIL & GAS, INC.

INDEX

			Page of
			Form 10-Q

PART I.	FINANCIAL INFORMATION		1

	ITEM 1.	FINANCIAL STATEMENTS (UNAUDITED)	1

		Condensed Balance Sheets as of June 30, 2012 and December 31, 2011	1

		Condensed Statements of Operations for the three and six months ended June 30, 2012 and 2011	2

		Condensed Statements of Cash Flows for the six months ended June 30, 2012 and 2011	3

		Notes to Condensed Financial Statements	4

	ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	17

	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	31

	ITEM 4.	CONTROLS AND PROCEDURES	32

PART II.	OTHER INFORMATION		32

	ITEM 1.	LEGAL PROCEEDINGS	32

	ITEM 1A.	RISK FACTORS	32

	ITEM 6.	EXHIBITS	36

SIGNATURES			37

PART 1 — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

VOYAGER OIL & GAS, INC.

CONDENSED BALANCE SHEETS

(UNAUDITED)

	June 30, 2012			December 31, 2011
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	4,113,794		$	13,927,267
Trade Receivables		7,529,588			3,247,412
Fair Value of Commodity Derivatives		609,147			—
Prepaid Expenses		188,151			48,330
Total Current Assets		12,440,680			17,223,009
PROPERTY AND EQUIPMENT
Oil and Natural Gas Properties, Full Cost Method
Proved Oil and Natural Gas Properties		102,678,532			60,425,243
Unproved Oil and Natural Gas Properties		31,211,108			32,180,217
Other Property and Equipment		177,735			176,238
Total Property and Equipment		134,067,375			92,781,698
Less – Accumulated Depreciation, Depletion and Amortization		(20,877,163	)		(5,505,288	)
Total Property and Equipment, Net		113,190,212			87,276,410
Prepaid Drilling Costs		36,742			33,163
Fair Value of Commodity Derivatives		668,936			—
Debt Issuance Costs, Net of Amortization		427,879			306,839
Total Assets	$	126,764,449		$	104,839,421
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts Payable	$	35,457,693		$	10,375,239
Accrued Expenses		29,425			206,122
Total Current Liabilities		35,487,118			10,581,361
LONG-TERM LIABILITIES
Revolving Credit Facility		18,030,730			—
Senior Secured Promissory Notes		—			15,000,000
Asset Retirement Obligations		198,293			116,119
Total Liabilities		53,716,141			25,697,480

COMMITMENTS AND CONTINGENCIES

STOCKHOLDERS’ EQUITY
Preferred Stock – Par Value $.001; 20,000,000 Shares Authorized; None Issued or Outstanding		—			—
Common Stock, Par Value $.001; 200,000,000 Shares Authorized, 58,468,428 and 57,848,428 Shares Issued and Outstanding, respectively		58,468			57,848
Additional Paid-In Capital		88,081,199			86,958,174
Accumulated Deficit		(15,091,359	)		(7,874,081	)
Total Stockholders’ Equity		73,048,308			79,141,941
Total Liabilities and Stockholders’ Equity	$	126,764,449		$	104,839,421

The accompanying notes are an integral part of these unaudited condensed financial statements

VOYAGER OIL & GAS, INC.

CONDENSED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
REVENUES
Oil and Natural Gas Sales	$	6,763,429		$	1,666,535		$	11,861,762		$	2,499,156
Gain on Commodity Derivatives		2,251,543			—			1,339,108			—
		9,014,972			1,666,535			13,200,870			2,499,156
OPERATING EXPENSES
Production Expenses		484,829			148,335			951,459			198,313
Production Taxes		728,588			167,417			1,234,609			247,381
General and Administrative Expenses		1,215,218			706,617			2,157,349			1,400,931
Depletion of Oil and Natural Gas Properties		3,160,368			560,344			5,158,427			968,328
Impairment of Oil and Natural Gas Properties		10,191,234			—			10,191,234			—
Depreciation and Amortization		11,144			8,125			22,214			8,912
Accretion of Discount on Asset Retirement Obligations		3,423			1,328			5,990			1,589
Total Expenses		15,794,804			1,592,166			19,721,282			2,825,454

INCOME (LOSS) FROM OPERATIONS		(6,779,832	)		74,369			(6,520,412	)		(326,298	)

OTHER INCOME (EXPENSE)
Interest Expense		(169,445	)		(506,096	)		(685,235	)		(1,001,575	)
Other Income (Expense), Net		(11,631	)		(33,330	)		(11,631	)		(26,958	)
Total Other Expense, Net		(181,076	)		(539,426	)		(696,866	)		(1,028,533	)

LOSS BEFORE INCOME TAXES		(6,960,908	)		(465,057	)		(7,217,278	)		(1,354,831	)

INCOME TAX EXPENSE		—			—			—			—

NET LOSS	$	(6,960,908	)	$	(465,057	)	$	(7,217,278	)	$	(1,354,831	)

Net Loss Per Common Share — Basic and Diluted	$	(0.12	)	$	(0.01	)	$	(0.12	)	$	(0.02	)
Weighted Average Shares Outstanding — Basic and Diluted		57,994,582			57,379,515			57,927,550			54,753,703

The accompanying notes are an integral part of these unaudited condensed financial statements.

VOYAGER OIL & GAS, INC.

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Six Months Ended June 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$	(7,217,278	)	$	(1,354,831	)
Adjustments to Reconcile Net Loss to Net Cash Provided By (Used For) Operating Activities:
Depletion of Oil and Natural Gas Properties		5,158,427			968,328
Impairment of Oil and Natural Gas Properties		10,191,234			—
Depreciation and Amortization		22,214			8,912
Amortization of Debt Discount		—			111,575
Amortization of Finance Costs		278,776			—
Accretion of Discount on Asset Retirement Obligations		5,990			1,589
Unrealized Gain on Derivative Instruments		(1,278,083	)		—
Share-Based Compensation Expense		727,877			409,769
Changes in Assets and Liabilities:
Increase in Trade Receivables		(4,282,176	)		(1,291,411	)
Increase in Prepaid Expenses		(139,821	)		(47,959	)
Increase (Decrease) in Accounts Payable		46,454			(365,434	)
Decrease in Accrued Expenses		(176,697	)		(225,498	)
Net Cash Provided By (Used For) Operating Activities		3,336,917			(1,784,960	)
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of Other Property and Equipment		(1,497	)		(152,349	)
Prepaid Drilling Costs		(3,579	)		(727,017	)
Proceeds from Sales of Available for Sale Securities		—			242,070
Investment in Oil and Natural Gas Properties		(15,776,228	)		(23,959,151	)
Net Cash Used For Investing Activities		(15,781,304	)		(24,596,447	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Issuance of Common Stock – Net of Issuance Costs		—			46,602,251
Advances on Revolving Credit Facility and Term Loan		18,030,730			—
Payments on Senior Secured Promissory Notes		(15,000,000	)		—
Cash Paid for Finance Costs		(399,816	)		—
Proceeds from Exercise of Stock Options and Warrants		—			16,960
Net Cash Provided by Financing Activities		2,630,914			46,619,211
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(9,813,473	)		20,237,804
CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD		13,927,267			11,358,520
CASH AND CASH EQUIVALENTS – END OF PERIOD	$	4,113,794		$	31,596,324
Supplemental Disclosure of Cash Flow Information
Cash Paid During the Period for Interest	$	613,814		$	900,000
Cash Paid During the Period for Income Taxes	$	—		$	—
Non-Cash Financing and Investing Activities:
Oil and Natural Gas Properties Property Accrual in Accounts Payable	$	35,288,407		$	4,079,967
Stock-Based Compensation Capitalized to Oil and Natural Gas Properties	$	395,768		$	134,216
Capitalized Asset Retirement Obligations	$	76,184		$	50,485

The accompanying notes are an integral part of these unaudited condensed financial statements.

VOYAGER OIL & GAS, INC.

Notes to Condensed Financial Statements

Unaudited

NOTE 1 ORGANIZATION AND NATURE OF BUSINESS

Description of Operations — Voyager Oil & Gas, Inc., a Montana corporation (the “Company”), is an independent oil and natural gas exploration and production company engaged in the business of acquiring acreage in prospective natural resource plays within the continental United States, primarily focused on the Williston Basin located in North Dakota and Montana. The Company also holds acreage in other emerging oil plays in Colorado, Wyoming and Montana. The Company seeks to accumulate acreage that builds net asset value by growing reserves and converting undeveloped assets into producing wells in repeatable and scalable shale oil plays.

The Company participates in well development as a non-operator and is in the process of building operations to plan and design well development as an operator on acreage where a controlling interest is held. The Company had six employees as of June 30, 2012 and retains independent contractors to assist in operating and managing its prospects as well as to carry out the principal and necessary functions incidental to the oil and natural gas business. With the acquisition of Emerald Oil, Inc. during third quarter 2012 (see Note 14 – Subsequent Events), the Company has added executive management that is experienced in well development and intends to build on these capabilities internally and through partnering with others to leverage best practices. Production from oil wells has increased significantly, and the Company intends to add to this production by operating its own wells, while continuing to participate as a non-operator in wells managed by other operators.

Liquidity - As of June 30, 2012, the Company had cash and cash equivalents and accounts receivable of approximately $11.6 million and accounts payable and accrued expenses of approximately $35.5 million. In addition, as a part of the acquisition of Emerald Oil, Inc. the Company assumed $20.2 million of debt that matures in November 2012. Concurrent with the Emerald Oil, Inc. acquisition the Company entered into an amended and restated credit agreement with Macquarie Bank expanding the Company’s outstanding borrowings by $15.0 million which is due and payable in November 2012. The additional $15.0 million drawn under the credit facility was used to offset a portion of the $35.5 million of current liabilities.

As a result of the payments due on the Company’s current liabilities and the outstanding borrowings that are due and payable in 2012, the Company expects to have significant cash requirements in the next twelve months. The Company will need to secure financing or access the capital markets to sell equity or debt, or otherwise, in order to fund future operations and satisfy our obligations. There is no guarantee that any such required financing or equity will be available on terms satisfactory to us or available at all.

NOTE 2 SIGNIFICANT ACCOUNTING POLICIES

The accompanying condensed financial statements have been prepared on the accrual basis of accounting whereby revenues are recognized when earned, and expenses are recognized when incurred. These condensed financial statements as of June 30, 2012 and for the three and six months ended June 30, 2012 and 2011 are unaudited. In the opinion of management, such financial statements include the adjustments and accruals, all of which are of a normal recurring nature, which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results for a full year. Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles (GAAP) have been condensed or omitted in these financial statements for and as of the three and six months ended June 30, 2012 and 2011.

Interim financial results should be read in conjunction with the audited financial statements and footnotes for the year ended December 31, 2011, which were included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2011.

Cash and Cash Equivalents

The Company considers highly liquid investments with insignificant interest rate risk and original maturities of three months or less to be cash equivalents. Cash equivalents consist primarily of interest-bearing bank accounts and money market funds. The Company’s cash positions represent assets held in checking and money market accounts. These assets are generally available to the Company on a daily or weekly basis and are highly liquid in nature. All of the Company’s non-interest bearing cash accounts were fully insured at June 30, 2012 due to a temporary federal program in effect from December 31, 2010 through December 31, 2012. Under the program, there is no limit to the amount of insurance for eligible accounts. Beginning 2013, insurance coverage will revert to $250,000 per depositor at each financial institution, and the Company’s non-interest bearing cash balances may then exceed federally insured limits. In addition, the Company is subject to Security Investor Protection Corporation (SIPC) protection on a vast majority of its financial assets in the event one of the brokerage firms that the Company utilizes for its investments fails.

Other Property and Equipment

Property and equipment that are not oil and natural gas properties are recorded at cost and depreciated using the straight-line method over their estimated useful lives of three to seven years. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Depreciation expense was $11,144 and $8,125 for the three month periods ended June 30, 2012 and 2011, respectively. Depreciation expense was $22,214 and $8,912 for the six-month periods ended June 30, 2012 and 2011, respectively.

FASB Accounting Standards Codification (ASC) 360-10-35-21 requires that long-lived assets, other than oil and natural gas properties, be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The determination of impairment is based upon expectations of undiscounted future cash flows, before interest, of the related asset. If the carrying value of the asset exceeds the undiscounted future cash flows, the impairment would be computed as the difference between the carrying value of the asset and the fair value. There was no impairment identified at June 30, 2012 and December 31, 2011 for long-lived assets not classified as oil and natural gas properties.

Asset Retirement Obligations

The Company records the fair value of a liability for an asset retirement obligation in the period in which the well is spud or the asset is acquired and a corresponding increase in the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

Revenue Recognition and Natural Gas Balancing

The Company recognizes oil and natural gas revenues from its interests in producing wells when production is delivered and title has transferred to the purchaser, to the extent the selling price is reasonably determinable. The Company uses the sales method of accounting for balancing of natural gas production and would recognize a liability if the existing proven reserves were not adequate to cover the current imbalance situation. As of June 30, 2012 and December 31, 2011, the Company’s natural gas production was in balance, i.e., its cumulative portion of natural gas production taken and sold from wells in which it has an interest equaled the Company’s entitled interest in natural gas production from those wells.

Stock-Based Compensation

The Company has accounted for stock-based compensation under the provisions of ASC 718-10-55. The Company recognizes stock-based compensation expense in the financial statements over the vesting period of equity-classified employee stock-based compensation awards based on the grant date fair value of the awards, net of estimated forfeitures. For options and warrants, the Company uses the Black-Scholes option valuation model to calculate the fair value of stock based compensation awards at the date of grant. Option pricing models require the input of highly subjective assumptions, including the expected price volatility. For the stock options and warrants granted the Company has used a variety of comparable and peer companies to determine the expected volatility input based on the expected term of the options. The Company believes the use or peer company data fairly represents the expected volatility it would experience if it were in the oil and natural gas industry over the expected term of the options. The Company used the simplified method to determine the expected term of the options due to the lack of historical data. Changes in these assumptions can materially affect the fair value estimate.

On May 27, 2011, the shareholders of the Company approved the Voyager Oil & Gas, Inc. 2011 Equity Incentive Plan (the “2011 Plan”), under which 5,000,000 shares of common stock have been reserved. The purpose of the 2011 Plan is to promote the success of the Company by facilitating the employment and retention of competent personnel and by furnishing incentives to those employees, directors and consultants upon whose efforts the success of the Company will depend to a large degree. It is the intention of the Company to carry out the 2011 Plan through the granting of incentive stock options, nonqualified stock options, restricted stock awards, restricted stock unit awards, performance awards and stock appreciation rights. As of June 30, 2012, 1,520,000 of the common stock reserved were issued to directors, officers and employees under the 2011 Plan.

Income Taxes

The Company accounts for income taxes under FASB ASC 740-10-30 . Deferred income tax assets and liabilities are determined based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized.

The tax effects from an uncertain tax position can be recognized in the financial statements only if the position is more likely than not of being sustained if the position were to be challenged by a taxing authority. The Company has examined the tax positions taken in its tax returns and determined that there are no uncertain tax positions. As a result, the Company has recorded no uncertain tax liabilities in its condensed balance sheet.

Net Income (Loss) Per Common Share

Basic net income (loss) per common share is based on the net income (loss) divided by the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average number of common shares plus dilutive common share equivalents outstanding during the period using the treasury stock method. In the computation of diluted earnings per share, excess tax benefits that would be created upon the assumed vesting of unvested restricted shares or the assumed exercise of stock options (i.e., hypothetical excess tax benefits) are included in the assumed proceeds component of the treasury share method to the extent that such excess tax benefits are more likely than not to be realized. When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. As the Company had a loss for the three- and six- month periods ended June 30, 2012 and 2011, the potentially dilutive shares are anti-dilutive and are thus not added into the earnings per share calculation.

The following stock options, warrants and restricted stock, which would be potentially dilutive in future periods, were not included in the computation of diluted net loss per share for the three and six months ended June 30, 2012 because the effect would have been anti-dilutive:

Restricted Stock			420,005
Stock Options			1,800,000
Stock Warrants			7,813,051
Total Potentially Anti-Dilutive Shares			10,033,056

Full Cost Method

The Company follows the full cost method of accounting for oil and natural gas operations whereby all costs related to the exploration and development of oil and natural gas properties are initially capitalized into a single cost center (“full cost pool”). Such costs include land acquisition costs, a portion of employee salaries related to property development, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities. For the three- and six-month periods ended June 30, 2012, the Company capitalized $234,484 and $473,099 of internal salaries, which included $194,497 and $395,768 of stock-based compensation. For the three- and six-month periods ended June 30, 2011, the Company capitalized $153,208 of internal salaries, which included $134,216 of stock-based compensation. Internal salaries are capitalized based on employee time allocated to the acquisition of leaseholds and development of oil and natural gas properties. The Company capitalized interest of $57,098 for the three- and six-month periods ended June 30 2012. The Company did not capitalize interest for the three- and six-month periods ended June 30, 2011.

Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. As of June 30, 2012, the Company has had no property sales since inception.

The Company assesses all items classified as unevaluated property on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. For the three- and six-month periods ended June 30, 2012 the Company had no costs that were transferred to the full cost pool related to impairment. For the year ended December 31, 2011, the Company included $6,983,125 related to expiring leases within costs subject to the depletion calculation.

Capitalized costs associated with impaired properties and properties having proved reserves, estimated future development costs, and asset retirement costs under FASB ASC 410-20-25 are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves. The costs of unproved properties are withheld from the depletion base until such time as they are either developed, impaired, or abandoned.

Capitalized costs (net of related deferred income taxes) are limited to a ceiling based on the present value of future net revenues using the 12-month unweighted average of first-day-of-the-month price (the “12-month average price”), discounted at 10%, plus the lower of cost or fair market value of unproved properties. If the ceiling is not greater than or equal to the total capitalized costs, the Company is required to write down capitalized costs to the ceiling. The Company performs this ceiling test calculation each quarter. Any required write downs are included in the condensed statements of operations as an impairment charge. The Company recognized an impairment expense in the three- and six-month periods ended June 30, 2012 in the amount of $10,191,234. There was no impairment expense recognized in the three- and six-month periods ended June 30, 2011.

Commodity Derivative Instruments

The Company has entered into commodity derivative instruments, utilizing "no premium" collars to reduce the effect of price changes on a portion of future oil production. The Company's commodity derivative instruments are measured at fair value and are included in the condensed balance sheet as derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses resulting from the contract settlement of derivatives are recorded in the gain on derivatives line on the condensed statement of operations. The Company's valuation estimate takes into consideration the counterparties' credit worthiness, the Company's credit worthiness, and the time value of money. The consideration of the factors results in an estimated exit-price for each derivative asset or liability under a market place participant's view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments. For additional discussion on commodity derivative instruments see Note 13.

New Accounting Pronouncements

From time to time, new accounting pronouncements are issued by FASB that are adopted by the Company as of the specified effective date. If not discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s financial statements upon adoption.

Joint Ventures

The condensed financial statements as of June 30, 2012 and 2011 include the accounts of the Company and its proportionate share of the assets, liabilities, and results of operations of the joint ventures it is involved in.

Use of Estimates

The preparation of financial statements under GAAP in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates relate to proved oil and natural gas reserve volumes, future development costs, estimates relating to certain oil and natural gas revenues and expenses, fair value of derivative instruments, valuation of share based compensation and the valuation of deferred income taxes. Actual results may differ from those estimates.

NOTE 3 OIL AND NATURAL GAS PROPERTIES

Major Joint Venture

In May 2008, the Company entered into the Major Joint Venture Agreement with a third-party partner to acquire certain oil and natural gas leases in the Tiger Ridge Gas Field in Blaine, Hill, and Choteau Counties of Montana. Under the terms of the joint venture agreement, the Company is responsible for all lease acquisition costs. The third-party joint venture partner is responsible for coordinating the geology, acquiring the leases in its name, preparing and disseminating assignments, accounting for the project costs and administration of the well operator. The Company controls an 87.5% working interest on all future production and reserves, while the third-party joint venture partner controls a 12.5% working interest. The joint venture had accumulated oil and natural gas leases totaling 74,706 net mineral acres as of June 30, 2012. The Company initially committed to a minimum of $1,000,000 toward this joint venture. An amendment to the joint venture agreement was executed in April 2011 to remove the maximum amount committed under the joint venture. The Company is not committed to any further capital obligations under the joint venture. The third-party joint venture partner issues cash calls during the year to replenish the joint venture cash account. The Company’s contributions to the joint venture totaled $4,214,441 as of June 30, 2012, consisting of $1,940,054 in leasing costs, $1,346,925 in seismic costs and $804,155 in drilling costs. The unutilized cash balance was $123,307 as of June 30, 2012.

Tiger Ridge Joint Venture

In November 2009, the Company entered into the Tiger Ridge Joint Venture Agreement with a third-party and a well operator to develop and exploit a drilling program in two certain blocks of acreage in the Major Joint Venture, which is an area of mutual interest. The Company controls a 70% working interest, while a third-party investor and the well operator control a 10% working interest and 20% working interest, respectively. The joint venture agreement requires that all parties contribute in cash their proportional share to cover all costs incurred in developing these blocks of acreage for drilling. The Company participated in the drilling of two wells with Devon Energy Corporation, both of which were drilled and shut-in in 2010. The Company conducted 3-D seismic testing throughout 2010 and drilled and completed six exploratory wells in the fourth quarter of 2011 with our joint venture partners, Hancock Enterprises and MCR, LLC, as operators. These wells are currently awaiting pipeline hook-up.

Big Snowy Joint Venture

In October 2008, the Company entered into the Big Snowy Joint Venture Agreement with an administrator third-party to acquire certain oil and natural gas leases in the Heath shale oil play in Musselshell, Petroleum, Garfield, Rosebud and Fergus Counties of Montana, and another third party to perform as the operator. Under the terms of the agreement, the Company is responsible for 72.5% of lease acquisition costs, and the other parties are individually responsible for 2.5% and 25% of the lease acquisition costs. Each party controls the same respective working interest on all future production and reserves. The administrator third-party joint venture partner is responsible for coordinating the geology, acquiring the leases in its name, preparing and disseminating assignments, accounting for the project costs and administration of the well operator. The joint venture had accumulated oil and natural gas leases totaling 33,562 net mineral acres as of June 30, 2012. The Company is committed to a minimum of $1,000,000 and up to $1,993,750 toward this joint venture, with all partners, including the Company, committing a minimum of $2,750,000. The administrator third-party joint venture partner issues cash calls during the year to replenish the joint venture cash account. The Company’s contributions to the joint venture totaled $724,744 as of June 30, 2012. The unutilized cash balance was $11,790 as of June 30, 2012.

Niobrara Development with Slawson Exploration Company, Inc.

The Company announced the Niobrara development program with Slawson Exploration Company, Inc. on June 28, 2010. The Company participated on a heads-up, or pro rata, basis for a 50% working interest in six exploratory wells in Weld County, Colorado targeting the Niobrara formation in the Denver Julesburg Basin (“DJ Basin”). Following the results of the initial three test wells, the Company allowed approximately 7,500 acres of its initial 17,000 acres of state leases in Weld County, Colorado to expire on November 15, 2010. Three additional wells were drilled during the quarter ended March 31, 2011 and were in production as of June 30, 2012. The Company allowed approximately 7,100 additional acres to expire on November 15, 2011. As of June 30, 2012, the Company held approximately 2,400 net acres in Weld County, Colorado and Laramie County, Wyoming. The Company currently has no plans for drilling any additional development wells under this development program during 2012.

Other Property Acquisitions

On May 24, 2011, the Company purchased certain leases consisting of approximately 1,680 net acres in Williams County, North Dakota and Richland County, Montana for a total purchase price of $2,514,863. On May 27, 2011 the Company purchased certain leases consisting of approximately 1,195 net acres in Richland County, Montana for a total purchase price of $1,792,950. The Company has also completed other miscellaneous acquisitions in the Williston Basin of Montana and North Dakota during the year ended December 31, 2011 totaling $13,541,730, and totaling $2,398,143 during the six months ended June 30, 2012.

NOTE 4 RELATED PARTY TRANSACTIONS

On September 22, 2010, Steven Lipscomb and Michael Reger subscribed for $500,000 and $1,000,000 of senior secured promissory notes, respectively. The issuance of the senior secured promissory notes is described in Note 7 to the financial statements. Mr. Lipscomb is formerly a director of the Company. Mr. Reger is a brother of J.R. Reger, who is the Chief Executive Officer and a director of the Company. The Company’s Audit Committee, which consists solely of independent directors, reviewed and approved this transaction. The senior secured promissory notes were paid in full on February 10, 2012.

On November 2, 2011, the Company purchased certain leases consisting of approximately 256 net acres in Dunn County, North Dakota for a total purchase price of $768,000. The leases were purchased from Ante5, Inc. (“Seller”), a related party. The Seller and its assets were spun off from the Company and became a separate public reporting U.S. company on June 24, 2010. The Chairman of the Board of the Seller is Bradley Berman, who is the son of the Company’s Chairman of the Board and was the beneficial owner of approximately 5.4% of the Company’s outstanding common stock as of June 30, 2012. The Company’s Audit Committee reviewed and approved this transaction prior to its completion. In approving this transaction, the Audit Committee, which consisted solely of independent directors, took into account, among other factors, that due diligence performed by the Company evidenced that the leases were purchased by the Company at the Seller’s original cost per acre and on terms no less favorable than terms generally available to an unaffiliated third party under the same or similar circumstances.

NOTE 5 PREFERRED AND COMMON STOCK

Stock Awards

In March 2012, the Company issued an aggregate of 99,999 shares of common stock to executives of the Company as compensation for their services. The shares were fully vested on the date of the grant. The fair value of the stock issued was approximately $294,000 or $2.94 per share, the market value of a share of common stock on the date the stock was issued. The Company expensed $160,718 in share-based compensation related to these grants in the six-month period ended June 30, 2012. The remainder of the fair value of these grants was capitalized into the full cost pool.

During the six-month period ended June 30, 2012, the Company issued an aggregate 520,001 shares of restricted common stock as compensation to its officers and an employee. Unvested restricted shares vest over various terms with all restricted shares vesting no later than December 2014, and 99,996 of the restricted shares were vested as of June 30, 2012. As of June 30, 2012, there was approximately $1.2 million of total unrecognized compensation expense related to unvested restricted stock. The Company will recognize compensation expense over the remaining vesting period of the restricted stock grants. The Company has assumed a 0% forfeiture rate for the restricted stock.

The Company incurred compensation expense associated with restricted stock granted in 2012 of $164,744 and $191,531 for the three and six months ended June 30, 2012, respectively. The Company incurred compensation expense associated with restricted stock granted prior to 2012 of $57,376 and $114,754 for the three and six months ended June 30, 2011, respectively. For the three and six months ended June 30, 2012, the Company capitalized compensation expense associated with the restricted stock of $131,869 and $154,082 to oil and natural gas properties, respectively.

NOTE 6 STOCK OPTIONS AND WARRANTS

Stock Options

On January 6, 2012, the Company granted stock options to an employee to purchase a total of 25,000 shares of common stock exercisable at $2.65 per share. The total fair value of the options was calculated using the Black-Scholes valuation model based on factors present at the time the options were granted. The Company has assumed a 10% forfeiture rate on these options. The options vest over one year with all of the options vesting on the anniversary date of the grant.

On March 30, 2012, the Company granted stock options to an employee to purchase a total of 350,000 shares of common stock exercisable at $2.43 per share. The total fair value of the options was calculated using the Black-Scholes valuation model based on factors present at the time the options were granted. The Company has assumed a 10% forfeiture rate on these options. The options vest over one year with all of the options vesting on the anniversary date of the grant.

On May 23, 2012, the Company granted stock options to an employee to purchase a total of 250,000 shares of common stock exercisable at $1.77 per share. The total fair value of the options was calculated using the Black-Scholes valuation model based on factors present at the time the options were granted. The Company has assumed a 10% forfeiture rate on these options. The options vest over 36 months with 100,000 options vesting on May 23, 2013 and 2014 and 50,000 options vesting in November 23, 2014.

On May 24, 2012, the Company granted stock options to non-employee directors to purchase a total of 125,000 shares of common stock exercisable at $1.90 per share. The total fair value of the options was calculated using the Black-Scholes valuation model based on factors present at the time the options were granted. The Company has assumed a 10% forfeiture rate on these options. The options vest over four years with 25% of the options vesting on each anniversary date of the grant.

The impact on our condensed statement of operations of stock-based compensation expense related to options granted for the three month periods ended June 30, 2012 and 2011 was $235,408 and $109,100, respectively, net of $0 tax. The impact on our condensed statement of operations of stock-based compensation expense related to options granted for the six-month periods ended June 30, 2012 and 2011 was $375,629 and $187,692, respectively, net of $0 tax. The Company capitalized $62,628 and $108,406 in compensation related to outstanding options for the three and six months ended June 30, 2012, respectively.

The following assumptions were used for the Black-Scholes model to value the options granted during the six months ended June 30, 2012.

Risk free rates			0.86% to 1.20%
Dividend yield			0%
Expected volatility			72.48% to 78.18%
Weighted average expected life			5.5 to 7 years

The following summarizes activities concerning outstanding options to purchase shares of the Company’s common stock as of and for the three and six months ended June 30, 2012:

No options were exercised.

No options were forfeited.

No options expired.

The Company will recognize approximately $1.4 million of compensation expense in future periods relating to options that have been granted but have not vested as of June 30, 2012.

There were 1,187,500 unvested options at June 30, 2012.

Warrants

The table below reflects the status of warrants outstanding at June 30, 2012:

	Warrants		Exercise Price		Expiration Date
December 1, 2009		260,509	$	0.98	December 1, 2019
December 31, 2009		1,302,542	$	0.98	December 31, 2019
February 8, 2011		6,250,000	$	7.10	February 8, 2016
		7,813,051

No warrants expired or were forfeited during the six months ended June 30, 2012. The Company recorded no expense related to these warrants for the six months ended June 30, 2012. As of June 30, 2012, all of the compensation expense related to these vested warrants has been expensed by the Company. All warrants outstanding were exercisable at June 30, 2012.

NOTE 7 SENIOR SECURED PROMISSORY NOTES

In September 2010, the Company issued senior secured promissory notes in the principal amount of $15 million (the “Notes”) in order to finance future drilling and development activities. Proceeds of the Notes were used primarily to fund developmental drilling on the Company’s significant acreage positions targeting the Williston Basin — Bakken/Three Forks area and the Niobrara formation located in the Denver-Julesburg (D-J) Basin through the joint venture with Slawson.

The Notes were paid in full on February 10, 2012 in conjunction with the Company entering into a credit facility with Macquarie Bank Limited (“MBL”) (see Note 8). The remaining unamortized finance costs of $217,809 were written off to interest expense in the six months ended June 30, 2012.

NOTE 8 REVOLVING CREDIT FACILITY

On February 10, 2012, the Company entered into a credit facility (“Facility”) with MBL. The Facility provides up to a maximum of $150 million in principal amount of borrowings to be used as working capital for exploration and production operations. Initially, $15 million of financing was available under the Facility based on reserves (Tranche A), with an additional $50 million available under a development tranche (Tranche B). As of June 30, 2012, the Company had borrowed $15 million under Tranche A and approximately $3 million under Tranche B. As of June 30, 2012, $7.7 million was undrawn and available pursuant to an approved development plan.

The borrowing base of funds available to the Company under Tranche A is redetermined semi-annually based upon the net present value, discounted at 10% per annum, of the future net revenues expected to accrue from the Company’s interests in proved reserves estimated to be produced from its crude oil and natural gas properties. The Facility terminates on February 10, 2015. Tranche B is uncommitted; however, MLB may, in its sole discretion and subject to an approved revised development plan and the satisfaction of certain conditions, commit additional funds under Tranche B. Outstanding borrowings under Tranche B are due in six equal monthly installments beginning on August 10, 2015.

The Company has the option to designate the reference rate of interest for each specific borrowing under the Facility as amounts are advanced. Under Tranche A, borrowings designated to be based upon the London Interbank Offered Rate (LIBOR) bear interest at a rate equal to LIBOR plus a spread ranging from 2.75% to 3.25%, depending on the percentage of borrowing base that is currently advanced. Any borrowings not designated LIBOR-based will bear interest at a rate equal to the current prime rate published by the Wall Street Journal plus a spread ranging from 1.75% to 2.25%, depending on the percentage of borrowing base that is currently advanced. The Company has the option to designate either pricing mechanism. The Company’s interest rate on Tranche A is 3.489% as of June 30, 2012. Tranche B borrowing bears interest at a rate equal to LIBOR plus 7.5%. The Company’s interest rate on Tranche B is 7.739% as of June 30, 2012. Interest payments are due under the Facility in arrears; in the case of a LIBOR-based loan, on the last day of the specified interest period and in the case of all other loans on the last day of each March, June, September and December. All outstanding principal is due and payable upon termination of the Facility.

Upon an event of default, the applicable interest rate under the Facility will increase, and the lenders may accelerate payments under the Facility or call all obligations due under certain circumstances. The Facility references various events constituting a default, including, but not limited to, failure to pay interest on any loan under the Facility, any material violation of any representation or warranty under the Facility, failure to observe or perform certain covenants, conditions or agreements under the Facility, a change in control of the Company, default under any other material indebtedness of the Company, bankruptcy and similar proceedings and failure to pay disbursements from lines of credit issued under the Facility.

The Facility requires that the Company enter into hedging agreements with MBL for each month of the 36-month period following the date on which each such hedge agreement is executed, the notional volumes for which, when aggregated with other commodity derivative agreements and additional fixed-price physical off-take contracts then in effect are not less than 50%, nor greater than 90%, of the reasonably anticipated projected production from our proved developed producing reserves. The Facility also requires the Company to maintain certain financial ratios, including current ratio (at least 1.00 to 1.00), debt coverage ratio (no more than 3.50 to 1.00), interest coverage ratio (at least 2.50 to 1.00) and a ceiling on general and administrative expenses (no more than $500,000 per fiscal quarter, excluding certain non-cash, audit and engineering-related expenses), commencing on March 31, 2012. The Company was not in compliance with the current ratio and general and administrative expenses ceiling covenants as of June 30, 2012, and a waiver was obtained from MBL. The current ratio shortfall and resulting working capital deficit of $23,046,438 as of June 30, 2012 was in part due to $10,454,305 of accrued capitalized costs associated with development of oil and natural gas properties in the Williston Basin not yet invoiced to the Company. The Company intends to partially finance these capitalized costs through the Facility upon receipt of associating invoices from the respective well operators. The Company intends to fund the remaining current working capital deficit through interim redetermination of reserves under the Facility and cash provided from operating activities, although we may have to access the capital markets or seek other financing arrangements. Exceeding the general and administrative expense ceiling was primarily attributable to professional fees related to the preparation and filing of the annual proxy statement, the Emerald acquisition and expenses related to the Company’s annual meeting of shareholders.

All of our obligations under the Facility and the derivative agreements with MBL are secured by a first priority security interest in any and all of the Company’s assets.

Subsequent to June 30, 2012, the Company amended the Facility to expand availability on a short-term basis (See Note 15 – Subsequent Events).

NOTE 9 ASSET RETIREMENT OBLIGATION

The Company has asset retirement obligations associated with the future plugging and abandonment of proved properties and related facilities. Under the provisions of FASB ASC 410-20-25, the fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred and a corresponding increase in the carrying amount of the related long lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. The Company has no assets that are legally restricted for purposes of settling asset retirement obligations.

The following table summarizes the Company’s asset retirement obligation transactions recorded in accordance with the provisions of FASB ASC 410-20-25 for the six months ended June 30, 2012 and the year ended December 31:

	June 30, 2012		December 31, 2011
Beginning Asset Retirement Obligation	$	116,119	$	10,522
Liabilities Incurred for New Wells Placed in Production		76,184		100,715
Accretion of Discount on Asset Retirement Obligations		5,990		4,882
Ending Asset Retirement Obligation	$	198,293	$	116,119

NOTE 10 INCOME TAXES

Deferred income tax assets and liabilities are determined based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. The Company does not expect to pay any federal or state income tax for 2012 as a result of net operating loss carry forwards from prior years. Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized. As of June 30, 2012, the Company maintains a full valuation allowance for all deferred tax assets. Based on these requirements no provision or benefit for income taxes has been recorded for deferred taxes. There were no recorded unrecognized tax benefits at the end of the reporting period.

NOTE 11 FAIR VALUE

FASB ASC 820-10-55 defines fair value, establishes a framework for measuring fair value under GAAP and enhances disclosures about fair value measurements. Fair value is defined under FASB ASC 820-10-55 as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs. The standard describes a fair value hierarchy based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value which are the following:

Level 1 – Unadjusted quoted prices in active markets that are accessible at measurement date for identical assets or liabilities.

Level 2 - Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets of liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.

Level 3 - Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities and less observable from objective sources.

The following schedule summarizes the valuation of financial instruments measured at fair value on a recurring basis in the condensed balance sheet as of June 30, 2012:

	Fair Value Measurements at June 30, 2012 Using
	Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity Derivatives – Current Asset (crude oil collars)	$	—	$	609,147	$	—
Commodity Derivatives – Long Term Asset (crude oil collars)		—		668,936		—
Total	$		$	1,278,083	$

There were no financial instruments measured at fair value on a recurring basis as of December 31, 2011.

Level 2 assets consist of commodity derivative assets (see Note 13). The fair value of the commodity derivative assets is estimated by the Company by utilizing an option pricing model which takes into account notional quantities, market volatility, market prices, contract parameters and discount rates based on published LIBOR rates. Significant changes in the quoted forward prices for commodities and changes in market volatility generally leads to corresponding changes in the fair value measurement of our oil derivative contracts. The fair value of all derivative contracts is reflected on the condensed balance sheet.

NOTE 12 FINANCIAL INSTRUMENTS

The Company’s non-derivative financial instruments include cash and cash equivalents, accounts receivable, accounts payable and the revolving credit facility. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximate fair value because of their immediate or short-term maturities. The book value of the revolving credit facility approximates fair value because of its floating rate structure. The Company has classified the revolving credit facility as a Level 2 item within the fair value hierarchy.

NOTE 13 DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT

The Company utilizes commodity costless collars (purchased put options and written call options) to (i) reduce the effects of volatility in price changes on the oil commodities it produces and sells, (ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure it can execute at least a portion of its capital spending.

All derivative positions are carried at their fair value on the condensed balance sheet and are marked-to-market at the end of each period. Both the unrealized and realized gains and losses resulting from the contract settlement of derivatives are recorded in the gain on derivatives line on the condensed statement of operations.

The Company has a master netting agreement on each of the individual oil contracts and therefore the current asset and liability are netted on the condensed balance sheet and the non-current asset and liability are netted on the condensed balance sheet.

The Company realized a gain on settled derivatives of $88,568 and $61,025 and a gain on mark-to-market of derivatives instruments of $2,162,975 and $1,278,083 for the three and six months ended June 30, 2012, respectively. The Company did not enter into derivative instruments prior to 2012.

Costless collars are used to establish floor and ceiling prices on anticipated oil and natural gas production. There were no premiums paid or received by the Company related to the costless collar agreements. The following table reflects open costless collar agreements as of June 30, 2012.

Term	Oil (Barrels)	Price	Basis
Costless Collars
July 1, 2012 – February 28, 2015	189,095	$90.00–$103.50	NYMEX

At June 30, 2012, the Company had derivative financial instruments recorded on the condensed balance sheet as set forth below:

Type of Contract	Balance Sheet Location
Derivative Assets:
Costless Collars	Current assets	$	786,411
Costless Collars	Non-current assets		1,247,240
Total Derivative Assets		$	2,033,651

Derivative Liabilities:
Costless Collars	Current liabilities		(177,264	)
Costless Collars	Non-current liabilities		(578,304	)
Total Derivative Liabilities		$	(755,568	)
Net Derivative Position		$	1,278,083

The use of derivative transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. The Company has netting arrangements with MBL that provide for offsetting payables against receivables from separate derivative instruments.

NOTE 14 COMMITMENTS AND CONTINGENCIES

We are subject to litigation claims and governmental and regulatory proceedings arising in the ordinary course of business. We believe that all such litigation matters are not likely to have a material adverse effect on the Company’s financial position, cash flows or results of operations.

NOTE 15 SUBSEQUENT EVENTS

Emerald Oil, Inc. Acquisition

On July 9, 2012, the Company entered into a Securities Purchase Agreement (the “Purchase Agreement”) with Emerald Oil & Gas NL (the “Parent”) and Emerald Oil, Inc. (“Emerald Oil”), a wholly owned subsidiary of the Parent pursuant to which the Company purchased all of the outstanding capital stock of Emerald Oil for approximately 19.9% of the total shares of Voyager common stock outstanding as of the closing date. The Company completed the acquisition of Emerald Oil on July 26, 2012. The Company issued a number of shares equal to19.9% of its common stock outstanding on the closing date, or approximately 11.6 million unregistered shares to the Parent, of which 0.5 million shares are being held in escrow pending resolution of certain title defects. The Company will maintain Emerald Oil’s liabilities, including approximately $20.2 million in debt owed by Emerald Oil. Included in the acquisition are approximately 10,600 net acres located in Dunn County, North Dakota and approximately 45,000 net acres in the Sandwash Basin Niobrara shale oil play in northwestern Colorado and southwestern Wyoming.

In connection with the closing of the acquisition, five existing members of the Company’s board of directors resigned, and their vacancies were filled with directors selected by the remaining members of Voyager’s board of directors. Also in connection with the closing of the Emerald acquisition, the Company entered into employment agreements with six officers, J.R. Reger (Executive Chairman—formerly Chief Executive Officer), Mike Krzus (Chief Executive Officer), McAndrew Rudisill (President), Paul Wiesner (Chief Financial Officer), Karl Osterbuhr (Vice President of Exploration and Business Development) and Mitchell R. Thompson (Chief Accounting Officer—formerly Chief Financial Officer).

The Company is currently determining the appropriate purchase price allocation for this transaction.

MBL Credit Facility Amendment

On July 26, 2012, the Company entered into an amended and restated credit agreement with MBL to expand the existing availability and outstanding balance under its existing credit facility. In addition to the $20.2 million of debt obligations related to the acquisition of Emerald Oil that remain outstanding through existing agreements, the Company obtained additional availability from its credit facility and drew $15 million of additional debt on a new third tranche at an initial rate of 9% above the applicable London Interbank Borrowing Rate (LIBOR) and has the potential to draw a maximum of $20 million. The $15 million drawn was used for existing development activities. The new tranche matures on November 15, 2012, while Tranche A and Tranche B continue to mature on February 10, 2015. Tranche B is uncommitted, however, MBL may, in its sole discretion and subject to an approved revised development plan and the satisfaction of certain conditions commit additional funds under Tranche B.

On July 26, 2012, in conjunction with the closing of the amended and restated credit agreement with MBL, the Company executed a NYMEX West Texas Intermediate crude oil derivative swap contract. The following table reflects the opened commodity swap contract with the associated volumes and fixed price.

			Fixed
Calendar Year	Volumes (Bbls)		Price
August - December 2012		51,136	$	88.00
2013		73,370	$	88.00
2014		48,742	$	88.00
2015		6,404	$	88.00

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

The following discussion and analysis of our financial condition and results of operations should be read together with our financial statements appearing in this Form 10-Q. This discussion contains forward-looking statements that involve risks and uncertainties because they are based on current expectations and relate to future events and future financial performance. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of many important factors, including those set forth in Part II, Item 1A of this Form 10-Q and in our Annual Report on Form 10-K under the heading “Risk Factors”.

Overview

Voyager Oil & Gas, Inc., a Montana corporation (“Voyager,” the “Company,” “we,” “us,” or “our”), was formed for the purpose of acquiring acreage and participating in the production of crude oil, primarily focusing on acquiring working interests in scalable, repeatable shale oil and natural gas plays where established oil and natural gas companies have operations.

Our business focuses on shale oil and natural gas properties primarily located in North Dakota and Montana and, to a lesser extent, Colorado and Wyoming. We do not intend to limit our focus to any single geographic area because we want to remain flexible and intend to pursue the best opportunities available to us. Our required capital commitments may grow as our opportunities grow and depend upon the results of wells and development activities in our focus areas.

Our primary focus is to acquire high value leasehold interests specifically targeting shale resource prospects in the continental United States. Because of our size and maneuverability, we are able to deploy our land acquisition personnel into specific areas based on the latest industry information. We generate revenue by and through the conversion of our leaseholds into working interests in multiple wells primarily located in the Bakken and Three Forks oil shale.

To date our focus has been to participate in wells as a non-operating partner, primarily on a heads-up, or pro rata, basis proportionate to our working interest, allowing us to participate with established operators in well economics that have high return potential with relatively low overhead cost. On July 9, 2012, we entered into a Securities Purchase Agreement (the “Purchase Agreement”) with Emerald Oil & Gas NL (the “Parent”) and Emerald Oil, Inc. (“Emerald Oil”), a wholly owned subsidiary of the Parent, pursuant to which we purchased all of the outstanding capital stock of Emerald Oil for approximately 19.9% of the total shares of our common stock outstanding as of the closing date. We completed the acquisition of Emerald Oil on July 26, 2012 and issued approximately 11.6 million of our shares of common stock to the Parent of which 0.5 million shares are being held in escrow by the Company pending resolution of certain title defects. As part of the acquisition, we agreed to maintain Emerald Oil’s liabilities, including approximately $20.2 million in debt owed by Emerald Oil. Included in the acquisition are approximately 10,600 net acres located in Dunn County, North Dakota and approximately 45,000 net acres in the Sandwash Basin Niobrara shale oil play in northwestern Colorado and southwestern Wyoming. In connection with the closing of the acquisition, five existing members of our board of directors resigned, and their vacancies were filled with directors selected by the remaining members of our board of directors. Also in connection with the closing of the Emerald acquisition, we entered into employment agreements with six officers, J.R. Reger (Executive Chairman—formerly our Chief Executive Officer), Mike Krzus (Chief Executive Officer), McAndrew Rudisill (President), Paul Wiesner (Chief Financial Officer), Karl Osterbuhr (Vice President of Exploration and Business Development) and Mitchell R. Thompson (Chief Accounting Officer—formerly our Chief Financial Officer).

We intend to enhance our return on capital and growth potential by adding operating capabilities with our recent acquisition of Emerald Oil. We believe adding operating capabilities provides increased control over the planning and designing of well development and increases our long-term growth prospects and attractiveness to partner with others. The delineation of the Williston Basin continues to expand and evolve as development activity increases and well designs improve to enhance production and well economics.

We intend to trade or swap our acreage with other operators to increase our operating acreage or potential working interests in areas where we have existing acreage. Most trades are for comparable acreage and mutually beneficial for both parties as we consolidate and increase our working interests. We are also engaged in top-leasing in targeted areas of the Williston Basin where we believe there is a great likelihood that the current lease with a third party will expire before the acreage is developed and held by production. When we top-lease, we enter into a lease with a third party prior to the expiration of an existing lease, which only becomes effective when the current lease with the third party expires. We believe top-leasing may provide us access to quality acreage in the Williston Basin in areas that have the potential to be developed into economical Bakken and Three Forks oil wells.

Assets and Acreage Holdings

As of June 30, 2012, we controlled approximately 144,000 net acres in the following five primary prospect areas:

33,000 net acres in the Williston Basin targeting the Bakken and Three Forks shale oil formations in North Dakota and Montana;

33,500 net acres in a joint venture targeting the Heath shale oil formation in Musselshell, Petroleum, Garfield and Fergus Counties of Montana;

2,400 net acres in the Denver-Julesburg Basin targeting the Niobrara shale oil formation in Colorado and Wyoming; and

74,700 net acres in a joint venture in and around the Tiger Ridge natural gas field in Blaine, Hill and Chouteau Counties of Montana.

Williston Basin — Bakken and Three Forks

As of June 30, 2012, we own an interest in approximately 33,000 net acres in the Williston Basin. During 2011, we acquired approximately 8,354 net acres primarily in Williams and McKenzie Counties, North Dakota and Richland County, Montana. On May 24, 2011, we purchased certain leases consisting of approximately 1,680 net acres in Williams County, North Dakota and Richland County, Montana for a total purchase price of $2,514,863. On May 27, 2011, we purchased certain leases consisting of approximately 1,195 net acres in Richland County, Montana for a total purchase price of $1,792,950. We also completed other acquisitions in the Williston Basin of Montana and North Dakota totaling $13,541,730 during the year ended December 31, 2011, and totaling $2,398,143 during the six months ended June 30, 2012.

During the six months ended June 30, 2012, we acquired 1,118 net acres in the Williston Basin at an average lease bonus cost of $2,000 per acre. 100% of the acreage acquired during the six months ended June 30, 2012 either had an authorization for expenditure (“AFE”) from a well operator attached to the lease, or we subsequently received an AFE. We have participated in 180 gross (7.66 net) Bakken and Three Forks oil wells, including 150 gross (6.56 net) wells that are producing as of June 30, 2012. The remaining 30 gross (1.10 net) wells are in the process of being drilled, awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation as of June 30, 2012. We continue to lease prospective acreage targeting delineated areas of high quality production.

DJ Basin — Niobrara

We announced the Niobrara development program with Slawson Exploration Company, Inc. on June 28, 2010. We participated on a heads-up, or pro rata, basis for a 50% working interest in six exploratory wells in Weld County, Colorado targeting the Niobrara formation in the DJ Basin. Following the results of the initial three test wells, we allowed approximately 7,500 acres of our initial 17,000 acres of state leases in Weld County, Colorado to expire on November 15, 2010. Three additional wells were drilled during the first quarter of 2011 and in production as of December 31, 2011. We allowed approximately 7,100 additional acres to expire on November 15, 2011. We currently hold approximately 2,400 net acres in Weld County, Colorado and Laramie County, Wyoming. We currently have no plans for drilling any additional development wells in the DJ Basin under this development program during 2012.

Major Joint Venture — Tiger Ridge Natural Gas

As of June 30, 2012, we own an interest in approximately 74,700 net acres in and around the Tiger Ridge natural gas field in Montana. We participated in the drilling of two wells with Devon Energy Corporation, both of which were drilled and shut-in in 2010. We conducted 3-D seismic testing throughout 2010 and drilled and completed six exploratory wells in the fourth quarter of 2011 with our joint venture partners, Hancock Enterprises and MCR, LLC, as operators. We have an average working interest of 70% in these initial wells. These wells are currently awaiting pipeline hook-up.

Big Snowy Joint Venture — Heath Shale Oil

As of June 30, 2012, we own an interest in approximately 33,500 net acres located in central Montana as part of a joint venture targeting the Heath shale oil. We have begun to see substantial permitting activity and drilling in the area. We believe the Heath shale has similar characteristics to the Bakken and Three Forks formations, and several of the same development partners are operating in the area.

Productive Wells

The following table summarizes gross and net productive oil wells by state at June 30, 2012 and 2011. A net well represents our fractional working ownership interest of a gross well. The following table also does not include 30 gross (1.10 net) Bakken and Three Forks wells that were in the process of being drilled, awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation as of June 30, 2012 and 39 gross (2.00 net) Bakken and Three Forks wells as of June 30, 2011.

	June 30,
	2012				2011
	Gross		Net		Gross		Net
North Dakota Bakken and Three Forks		132		5.25		22		0.72
Montana Bakken and Three Forks		18		1.31		2		0.41
Colorado Niobrara in DJ Basin		5		2.50		4		2.00
Total:		155		9.06		28		3.13

Exploratory Wells

In 2012, we participated in the drilling of the Johnson 31-17 SWH well in an undeveloped area of Mountrail County, North Dakota with a 3.13% working interest. The well was abandoned after experiencing poor oil shows during the drilling process. The dry hole costs associated this well were $149,714. The costs associated with this well were included in the full cost pool and subject to the depletion base. Of the 155 gross productive wells that we have participated in we have only participated in two dry holes.

Results of Operations

Comparison of the Three and Six Months Ended June 30, 2012 with the Three and Six Months Ended June 30, 2011.

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
REVENUES
Oil and Natural Gas Sales	$	6,763,429		$	1,666,535		$	11,861,762		$	2,499,156
Gain on Commodity Derivatives		2,251,543			—			1,339,108			—
		9,014,972			1,666,535			13,200,870			2,499,156
OPERATING EXPENSES
Production Expenses		484,829			148,335			951,459			198,313
Production Taxes		728,588			167,417			1,234,609			247,381
General and Administrative Expenses		1,215,218			706,617			2,157,349			1,400,931
Depletion of Oil and Natural Gas Properties		3,160,368			560,344			5,158,427			968,328
Impairment of Oil and Natural Gas Properties		10,191,234			—			10,191,234			—
Depreciation and Amortization		11,144			8,125			22,214			8,912
Accretion of Discount on Asset Retirement Obligations		3,423			1,328			5,990			1,589
Total Expenses		15,794,804			1,592,166			19,721,282			2,825,454

INCOME (LOSS) FROM OPERATIONS		(6,779,832	)		74,369			(6,520,412	)		(326,298	)

OTHER INCOME (EXPENSE)
Interest Expense		(169,445	)		(506,096	)		(685,235	)		(1,001,575	)
Other Income (Expense), Net		(11,631	)		(33,330	)		(11,631	)		(26,958	)
Total Other Expense, Net		(181,076	)		(539,426	)		(696,866	)		(1,028,533	)

LOSS BEFORE INCOME TAXES		(6,960,908	)		(465,057	)		(7,217,278	)		(1,354,831	)

INCOME TAX EXPENSE		—			—			—			—

NET LOSS	$	(6,960,908	)	$	(465,057	)	$	(7,217,278	)	$	(1,354,831	)

Revenues

The following table presents information about our revenues and produced oil and natural gas volumes during the three and six months ended June 30, 2012, compared to the three and six months ended June 30, 2011. As of June 30, 2012, we were selling oil and natural gas from a total of 155 gross wells (approximately 9.06 net wells), compared to 28 gross wells (3.13 net wells) at June 30, 2011. Revenues from sales of oil and natural gas were $6,763,429 and $11,861,762 during the three and six months ended June 30, 2012, respectively, compared to $1,666,535 and $2,499,156 during the three and six months ended June 30, 2011, respectively. Our production volumes increased 378% and 406% in the three and six months ended June 30, 2012, respectively, as compared to the three and six months ended June 30, 2011, respectively. The production primarily increased due to the addition of 5.43 net productive Bakken and Three Forks wells from July 1, 2011 to June 30, 2012. During the three and six months ended June 30, 2012, we realized $82.34 and $86.14 average price per barrel of oil, respectively, before the effect of settled oil derivatives compared to $93.88 and $89.42 average price per barrel of oil during the three and six months ended June 30, 2011, respectively. For the three and six months ended June 30, 2012, crude oil represented 99% of revenues and 95% of production volume.

All data presented below is derived from accrued revenue and production volumes for the relevant period indicated.

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Net Oil and Natural Gas Revenues:
Oil	$	6,696,034	$	1,661,096	$	11,720,133	$	2,491,215
Natural Gas and Other Liquids		67,395		5,439		141,629		7,941
Total Oil and Natural Gas Sales		6,763,429		1,666,535		11,861,762		2,499,156

Net Production:
Oil (Bbl)		81,323		17,695		136,058		27,860
Natural Gas and Other Liquids (Mcf)		24,237		1,027		37,014		1,603
Barrel of Oil Equivalent (Boe)		85,363		17,866		142,227		28,127

Average Sales Prices:
Oil (per Bbl)	$	82.34	$	93.88	$	86.14	$	89.42
Effect of settled oil derivatives on average price (per Bbl)	$	1.09	$	—	$	0.45	$	—
Oil net of settled derivatives (per Bbl)	$	83.43	$	93.88	$	86.59	$	89.42

Natural Gas and Other Liquids (per Mcf)	$	2.78	$	5.30	$	3.83	$	4.95

Barrel of Oil Equivalent with realized derivatives (per Boe)	$	80.27	$	93.28	$	83.83	$	88.85

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Net Revenues:
Total Oil and Natural Gas Sales	$	6,763,429	$	1,666,535	$	11,861,762	$	2,499,156
Realized Gain on Commodity Derivatives		88,568		—		61,025		—
Unrealized Gain on Commodity Derivatives		2,162,975		—		1,278,083		—
Revenues	$	9,014,972	$	1,666,535	$	13,200,870	$	2,499,156

Gain on Commodity Derivatives

Realized commodity derivative gains were $88,568 and $61,025, for the three and six months ended June 30, 2012, respectively. Unrealized commodity derivative gains were $2,162,975 and $1,278,083, for the three and six months ended June 30, 2012, respectively. There were no commodity derivates losses during the three and six months ended June 30, 2011. Our derivatives are not designated for hedge accounting and are accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings. Mark-to-market accounting treatment creates volatility in our revenues as unrealized gains and losses from derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying balance sheets. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives. Future derivatives gains will be offset by lower future wellhead revenues. Conversely, future derivatives losses will be offset by higher future wellhead revenues based on the value at the settlement date. At June 30, 2012, all of our derivative contracts are recorded at their fair value, which was a net asset of $1,278,083. We did not incur any net asset or liability with respect to derivative contracts prior to January 1, 2012.

Expenses

All data presented below is derived from costs and production volumes for the relevant period indicated.

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Costs and Expenses Per Boe of Production :
Production Expenses	$	5.68	$	8.30	$	6.69	$	7.05
Production Taxes		8.54		9.37		8.68		8.80
G&A Expenses (Excluding Share-Based Compensation)		9.55		30.99		10.05		35.24
Shared-Based Compensation		4.69		8.57		5.12		14.57
Depletion of Oil & Natural Gas Properties		37.02		31.36		36.27		34.43
Impairment of Oil and Natural Gas Properties		119.39		—		71.65		—
Depreciation and Amortization		0.13		0.45		0.16		0.32
Accretion of Discount on Asset Retirement Obligation		0.04		0.07		0.04		0.06

Production Expenses

Production expenses were $ 484,829 and $951,459 during the three and six months ended June 30, 2012, respectively, compared to $148,335 and $198,313 during the three and six months ended June 30, 2011. We experience increases in operating expenses as we add new wells and maintain production from existing properties. On a per unit basis, production expenses per Boe decreased from $8.30 and $7.05 per barrel of oil equivalent, or Boe, sold during the three and six months ended June 30, 2011, respectively, to $5.68 and $6.69 during the three and six months ended June 30, 2012, respectively. These decreases were related to lower operating costs primarily in our Williston Basin wells. The severe weather conditions that increased production expenses relative to production volumes during the three and six months ended June 30, 2011 were not experienced during the three and six months ended June 30, 2012. The largest cost component in our Williston Basin wells is the disposal of water.

Production Taxes

We pay production taxes based on realized crude oil and natural gas sales. Production taxes were $728,588 and $1,234,609 during the three and six months ended June 30, 2012, respectively, compared to $167,417 and $247,381 in the three and six months ended June 30, 2011, respectively. Our production taxes during the three and six months ended June 30, 2012 were 10.8% and 10.4%, respectively, compared to 10.0% and 9.9% for the the three and six months ended June 30, 2011. The slightly higher production taxes in 2012 relates to the mix of wells added to production and the growing mix of producing wells that no longer qualify for reduced rates/or tax exemptions. Certain portions of our production occurs in North Dakota and Montana jurisdictions that have lower initial tax rates for an established period of time or until an established threshold of production is exceeded, after which the tax rates are increased to the standard tax rate.

General and Administrative Expense

General and administrative expenses were $1,215,218 and $2,157,349 during the three and six months ended June 30, 2012, respectively, compared to $706,617 and $1,400,931 during the three and six months ended June 30, 2011, respectively. General and administrative expenses excluding share-based compensation were $815,066 and $1,429,472 during the three and six months ended June 30, 2012, respectively, compared to $553,587 and $991,162 during the three and six months ended June 30, 2011, respectively. The increase is primarily due to increased legal, engineering, audit and other professional expenses (increased $270,565 and $389,367 for the three and six months ended June 30, 2012, compared to the three and six months ended June 30, 2011, respectively) and the addition of employees and related employment expenses (increased $122,937 and $192,087 for the three and six months ended June 30, 2012, compared to the three and six months ended June 30, 2011, respectively). Increases in legal, engineering, audit, other professional expenses and employment-related expenses for the three and six months ended June 30, 2012 compared to the three and six months ended June 30, 2011 were primarily the result of growth in infrastructure. On a per unit basis, general and administrative expenses per Boe decreased significantly as we were able to leverage our costs over a higher level of production. Share-based compensation expenses totaled $400,152 and $727,877 for the three and six months ended June 30, 2012, respectively, compared to $153,030 and $409,769 for the three and six months ended June 30, 2011, respectively.

Depletion Expense

Our depletion expense is driven by many factors, including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. Depletion expense was $ 3,160,368 and $5,158,427 for the three and six months ended June 30, 2012, respectively, compared to $560,344 and $968,328 for the three and six months ended June 30, 2011, respectively. On a per-unit basis, depletion expense was $37.02 and $36.27 per Boe for the three and six months ended June 30, 2012, respectively, compared to $31.36 and $34.43 per Boe for the three and six months ended June 30, 2011, respectively. Our depletion expense is based on the capitalized costs related to properties having proved reserves, plus the estimated future development costs and asset retirement costs which are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves determined by independent petroleum engineers. This increase in depletion expense for the three and six months ended June 30, 2012 compared to the three and six months ended June 30, 2011 was due primarily to the addition of 5.93 net productive wells from July 1, 2011 to June 30, 2012.

Impairment of Oil and Natural Gas Properties

We follow the full cost method of accounting for oil and natural gas operations whereby all costs related to the exploration and development of oil and natural gas properties are initially capitalized into a single cost center (“full cost pool”). Capitalized costs (net of related deferred income taxes) are limited to a ceiling based on the present value of future net revenues using the 12-month unweighted average of first-day-of-the-month price (the “12-month average price”), discounted at 10%, plus the lower of cost or fair market value of unproved properties. If the ceiling is not greater than or equal to the total capitalized costs, then we are required to write down capitalized costs to the ceiling. We perform this ceiling test calculation each quarter. Any required write downs are included in the condensed statements of operations as an impairment charge. We recognized an impairment expense in the three- and six-month periods ended June 30, 2012 in the amount of $10,191,234. Included in the full cost pool at June 30, 2012 were costs incurred in 2010 and 2011 associated with our interest in the Niobrara development program in the DJ Basin. We incurred approximately $23.6 million in development costs to acquire acreage and develop the program, with insufficient oil and natural gas reserves established as a result of the development program in the third-party reserve engineer’s reserve report to offset the costs of the development program. While the costs were incurred in 2010 and 2011, we did not fail the ceiling test until June 30, 2012. The failure was primarily due to a decrease in the 12-month average commodity price and an increase in the local differential to NYMEX on Williston Basin properties on the June 30, 2012 reserve report compared to March 31, 2012 and December 31, 2011 reserve reports. We did not recognize any impairment expense in the three- and six-month periods ended June 30, 2011.

Other Expense

Other expense was $181,076 and $696,866 for the three and six months ended June 30, 2012, respectively, compared to $539,426 and $1,028,533 for the three and six months ended June 30, 2011, respectively. Interest expense, the largest component of other expense, was $169,445 and $685,235 for the three and six months ended June 30, 2012, respectively, compared to $ 506,096 and $1,001,575 for the three and six months ended June 30, 2011, respectively. The decrease in interest expense resulted from utilization of the credit facility’s lower cost of capital compared to the senior secured notes outstanding during 2011. Interest expense for the six months ended June 30, 2012 included a $217,809 expense of unamortized financing costs related to the outstanding senior secured notes that were paid in full on February 10, 2012.

Net Loss

We had a net loss of $6,960,908 and $7,217,278 for the three and six months ended June 30, 2012, respectively (representing $(0.12) and $(0.12) per share-basic and diluted, respectively) compared to a net loss of $465,057 and $1,354,831 for the three and six months ended June 30, 2011, respectively (representing $(0.01) and $(0.02) per share-basic and diluted, respectively). The improvement in our period-over-period results due to revenue and production from oil and natural gas properties growing at a faster rate than general and administrative and other expenses, lower interest expense, and unrealized gains on commodity derivatives were more than offset by the $10,191,234 of impairment of oil and natural gas properties charge taken during the three and six months ended June 30, 2012.

Non-GAAP Financial Measures

Adjusted EBITDA

In addition to reporting net income (loss) as defined under GAAP, we also present net earnings before interest, income taxes, depreciation, depletion, and amortization, accretion of discount on asset retirement obligations, impairment of oil and natural gas properties, unrealized gain (loss) from mark-to-market on commodity derivatives and non-cash expenses relating to share based payments recognized under ASC Topic 718 (“adjusted EBITDA”), which is a non-GAAP performance measure. Adjusted EBITDA consists of net earnings after adjustment for those items described in the table below. Adjusted EBITDA does not represent, and should not be considered an alternative to GAAP measurements, such as net income (loss) (its most directly comparable GAAP measure), and our calculations thereof may not be comparable to similarly titled measures reported by other companies. By eliminating the items described below, we believe the measure is useful in evaluating its fundamental core operating performance. We also believe that adjusted EBITDA is useful to investors because similar measures are frequently used by securities analysts, investors, and other interested parties in their evaluation of companies in similar industries. Our management uses adjusted EBITDA to manage our business, including in preparing our annual operating budget and financial projections. Our management does not view adjusted EBITDA in isolation and also uses other measurements, such as net income (loss) and revenues to measure operating performance. The following table provides a reconciliation of net income (loss) to adjusted EBITDA for the periods presented:

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Net loss	$	(6,960,908	)	$	(465,057	)	$	(7,217,278	)	$	(1,354,831	)
Impairment of oil and natural gas properties		10,191,234			—			10,191,234			—
Interest expense		169,445			506,096			685,235			1,001,575
Accretion of discount on asset retirement obligations		3,423			1,328			5,990			1,589
Depreciation, depletion and amortization		3,171,512			568,469			5,180,641			977,240
Stock-based compensation		400,152			153,030			727,877			409,769
Unrealized gain on commodity derivatives		(2,162,975	)		—			(1,278,083	)		—
Adjusted EBITDA	$	4,811,883		$	763,866		$	8,295,616		$	1,035,342

Adjusted Income (Loss)

In addition to reporting net income (loss) as defined under GAAP, we also present net earnings before the impairment of oil and natural gas properties and the effect of unrealized gain (loss) from mark-to-market on commodity derivatives (“adjusted income (loss)”), which is a non-GAAP performance measure. Adjusted income (loss) consists of net earnings after adjustment for those items described in the table below. Adjusted income (loss) does not represent, and should not be considered an alternative to GAAP measurements, such as net income (loss), and our calculations thereof may not be comparable to similarly titled measures reported by other companies. By eliminating the items described below, we believe the measure is useful in evaluating our fundamental core operating performance. We also believe that adjusted income (loss) is useful to investors because similar measures are frequently used by securities analysts, investors, and other interested parties in their evaluation of companies in similar industries. Our management uses adjusted income to manage our business, including in preparing our annual operating budget and financial projections. Our management does not view adjusted income (loss) in isolation and also uses other measurements, such as net income (loss) and revenues to measure operating performance. The following table provides a reconciliation of net income (loss), to adjusted income (loss) for the periods presented:

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Net loss	$	(6,960,908	)	$	(465,057	)	$	(7,217,278	)	$	(1,354,831	)
Impairment of oil and natural gas properties		10,191,234			—			10,191,234			—
Unrealized gain on commodity derivatives		(2,162,975	)		—			(1,278,083	)		—
Adjusted income (loss)	$	1,067,351		$	(465,057	)	$	1,695,873		$	(1,354,831	)
Adjusted income (loss) per share – basic	$	0.02		$	(0.01	)	$	0.03		$	(0.02	)
Adjusted income (loss) per share – diluted	$	0.02		$	(0.01	)	$	0.03		$	(0.02	)
Weighted average shares outstanding – basic		57,994,582			57,379,515			57,927,550			54,753,703
Weighted average shares outstanding – diluted		58,814,046			57,379,515			58,856,127			54,753,703

Liquidity and Capital Resources

Liquidity is a measure of a company’s ability to meet potential cash requirements. We have historically met our capital requirements through the issuance of common stock and by long-term and short-term borrowings. In the future, we anticipate we will be able to provide the necessary liquidity from the revenues generated from the sales of our oil and natural gas reserves in our existing properties and availability under our credit facility; however, if we do not generate sufficient cash flow from operations or do not have availability under our credit facility we may attempt to continue to finance our operations through equity and/or debt financings.

As of June 30, 2012, we had cash and cash equivalents and accounts receivable of approximately $11.6 million and accounts payable and accrued expenses of approximately $35.5 million. In addition, as a part of the acquisition of Emerald Oil, Inc. we assumed $20.2 million of debt that matures in November 2012. Concurrent with the Emerald Oil, Inc. acquisition we entered into an amended and restated credit agreement with Macquarie Bank expanding our outstanding borrowings by $15.0 million with a third tranche, which is due and payable in November 2012. The additional $15.0 million drawn under the credit facility was used to pay a portion of the $35.5 million of current liabilities. As a result of the payments due on our current liabilities and the outstanding borrowings that are due and payable in November 2012, we expect to have significant cash requirements in the next twelve months. We will need to secure financing or access the capital markets to sell equity or debt, or otherwise, in order to fund future operations and satisfy our obligations. There is no guarantee that any such required financing or equity will be available on terms satisfactory to us or available at all.

The following table summarizes total current assets, total current liabilities and working capital at June 30, 2012.

Current assets	$	12,440,680
Current liabilities		35,487,118
Working capital (deficit)	$	(23,046,438	)

Equity Offerings

On February 8, 2011, we completed a private placement to accredited investors of 12,500,000 shares of common stock. The net proceeds from this sale of common stock were approximately $46.6 million after deducting placement agent fees and estimated offering expenses. We also issued 6,250,000 warrants to subscribers of the private placement concurrently with the sale of shares. The warrants have an exercise price of $7.10, and a five-year term from the date of the closing. We used the proceeds from this private placement to pursue acquisition opportunities, develop our accelerated drilling program in the Williston Basin and other working capital purposes.

Macquarie Credit Facility

On February 10, 2012, we entered into a credit facility with Macquarie Bank Limited (“MBL”). Concurrent with the closing, we paid in full the $15 million in outstanding senior secured promissory notes.

The facility provides up to a maximum of $150 million in principal amount of borrowings to be used as working capital for exploration and production operations. Initially, $15 million of financing was available under the facility based on reserves (Tranche A), with an additional $50 million maximum under a development tranche (Tranche B). As of June 30, 2012, we had $15 million borrowed under Tranche A and $3,030,730 borrowed under Tranche B. As of June 30, 2012, $7.7 million was undrawn and available pursuant to an approved development plan.

The borrowing base of funds available to us under Tranche A is redetermined semi-annually based upon the net present value, discounted at 10% per annum, of the future net revenues expected to accrue from our interests in proved reserves estimated to be produced from our oil and natural gas properties. The facility terminates on February 10, 2015. Tranche B may be committed and drawn upon developing properties approved by MBL.

We have the option to designate the reference rate of interest for each specific borrowing under the facility as amounts are advanced. Under Tranche A, borrowings based upon the London Interbank Offered Rate (LIBOR) will bear interest at a rate equal to LIBOR plus a spread ranging from 2.75% to 3.25%, depending on the percentage of borrowing base that is currently advanced. Any borrowings not designated as being based upon LIBOR will bear interest at a rate equal to the current prime rate published by the Wall Street Journal plus a spread ranging from 1.75% to 2.25%, depending on the percentage of borrowing base that is currently advanced. We have the option to designate either pricing mechanism. Tranche B borrowings bear interest at a rate equal to LIBOR plus 7.5%. Interest payments are due under the facility in arrears, in the case of a LIBOR-based loan on the last day of the specified interest period and in the case of all other loans on the last day of each March, June, September and December. All outstanding principal is due and payable upon termination of the facility, or February 10, 2015.

Upon the event of default, the applicable interest rate increases under the facility and the lenders may accelerate payments under the facility, or call all obligations due under certain circumstances. The facility references various events constituting a default, including, but not limited to, failure to pay interest on any loan under the facility, any material violation of any representation or warranty under the credit facility, failure to observe or perform certain covenants, conditions or agreements under the credit facility, a change in control, default under any other material indebtedness, bankruptcy and similar proceedings and failure to pay disbursements from lines of credit issued under the facility.

The facility requires that we enter into hedging agreements with MBL for each month of the 36-month period following the date on which each such hedge agreement is executed, the notional volumes for which (when aggregated with other commodity derivative agreements and additional fixed-price physical off-take contracts then in effect, as of the date such hedging agreement is executed, is not less than 50%, nor greater than 90%, of the reasonably anticipated projected production from our proved developed producing reserves. The facility also requires us to maintain certain financial ratios, including current ratio (at least 1.00 to 1.00), debt coverage ratio (no more than 3.50 to 1.00) and interest coverage ratio (at least 2.50 to 1.00), commencing on March 31, 2012. We were not in compliance with the current ratio covenant as of June 30, 2012, and a waiver was obtained from MBL. The current ratio shortfall and resulting working capital deficit of $23,046,438 as of June 30, 2012 is in part due to $10,454,305 of accrued capitalized costs associated with development of oil and natural gas properties in the Williston Basin not yet invoiced us. These capitalized costs will be financed through the facility upon receipt of associating invoices from the respective well operators. We intend to fund the remaining current working capital deficit through interim redetermination of reserves under the facility and cash provided from operating activities.

All of our obligations under the facility and the derivative agreements with MBL are secured by a first priority security interest in any and all of our assets.

On July 26, 2012, we entered into an amended and restated credit agreement with MBL to expand the existing availability and outstanding balance under our existing credit facility. In addition to the $20.2 million of debt obligations related to the acquisition of Emerald Oil that remain outstanding through existing agreements, we obtained additional availability from our credit facility and drew $15 million of additional debt on a new third tranche at an initial rate of 9% above the applicable London Interbank Borrowing Rate (LIBOR) and have the potential to draw a maximum of $20 million. The $15 million drawn was used for existing development activities. The new tranche matures on November 15, 2012, while Tranche A and Tranche B continue to mature on February 10, 2015. Tranche B is uncommitted; however, MBL may, in its sole discretion and subject to an approved revised development plan and the satisfaction of certain conditions commit additional funds under Tranche B.

Satisfaction of Our Cash Obligations for the Next Twelve Months

With increasing production from wells that are increasing cash flow from operations and increasing reserves, we believe we have sufficient capital to meet our drilling commitments and expected general and administrative expenses for the next twelve months. However, we may continue to pursue strategic acquisitions and employ an aggressive well development program. In addition, we have approximately $35.2 million in debt outstanding that will be due and payable in November 2012, $20.2 of which is owed by Emerald Oil. Unless we are able to increase the availability under the MBL credit facility, refinance our debt obligations or increase our cash flow from operations, we may be required to access the capital markets at some point in 2012. We may also choose to access the equity capital markets rather than a debt instrument to fund accelerated or continued drilling at the discretion of management and depending on prevailing market conditions. We will evaluate any potential opportunities for acquisitions as they arise. Given our asset base and anticipated growing cash flows, we believe we are in a position to take advantage of any appropriately priced sales that may occur. However, there can be no assurance that any additional capital will be available to us on favorable terms or at all.

Our prospects must be considered in light of the risks, expenses and difficulties frequently encountered by companies in their early stage of operations, particularly companies in the oil and natural gas exploration industry. Such risks include, but are not limited to, an evolving and unpredictable business model and the management of growth. To address these risks we must, among other things, implement and successfully execute our business and marketing strategy, respond to competitive developments, and attract, retain and motivate qualified personnel. There can be no assurance that we will be successful in addressing such risks, and the failure to do so can have a material adverse effect on our business prospects, financial condition and results of operations.

Effects of Inflation and Pricing

The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion. Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. While we do not currently expect business costs to materially increase, higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel.

Cash and Cash Equivalents

Our total cash resources as of June 30, 2012 were $4,113,794, compared to $13,927,267 as of December 31, 2011. The decrease in our cash balance was primarily attributable to the acquisition and development of oil and natural gas properties.

Net Cash Provided By (Used For) Operating Activities

Net cash provided by (used for) operating activities was $3,336,917 for the six months ended June 30, 2012 compared to $(1,784,960) for the six months ended June 30, 2011. The change in the net cash used in operating activities is primarily attributable to higher production revenue in 2012.

Net Cash Used In Investment Activities

Net cash used in investment activities was $15,781,304 for the six months ended June 30, 2012 compared to $24,596,447 for the six months ended June 30, 2011. The cash used in investment activities is primarily attributable to the purchase and development of oil and natural gas properties in the Williston Basin during the periods.

Net Cash Provided By Financing Activities

Net cash provided by financing activities was $2,630,914 for the six months ended June 30, 2012 compared to $46,619,211 for the six months ended June 30, 2011. The change in net cash provided by financing activities for the six months ended June 30, 2012 is primarily attributable to proceeds from the new credit facility and payment of the senior secured promissory notes. The change in net cash provided by financing activities for the six months ended June 30, 2011 is primarily attributable to proceeds from the private placement described in Item 2. Management’s Discuss and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Equity Offerings above.

Off-Balance Sheet Arrangements

We currently do not have any off-balance sheet arrangements.

2012 Drilling Projects

Subsequent to the second quarter ended June 30, 2012, we acquired Emerald and made a strategic decision to add operating capabilities and focus on growing operating acreage in the Williston Basin. Considering that we recently closed on the acquisition of Emerald, we are still evaluating our capital expenditure plans and evaluating how much of an effect our strategy, which includes swapping non-operating acreage for operating acreage that we intend to develop in future years, will have on our 2012 development plans. With the increased return on capital opportunities of participating in our own developed wells, we may encounter situations where we swap out of non-operated acreage for operated acreage and forgo the opportunity to participate in non-operated wells developed on the acreage. Additionally, as we evaluate return on capital potentially of wells developed by other operators, we may decide to not participate in the development of the first well developed on our non-operated acreage, and go non-consent, but could have the opportunity to participate in future well development on future in-fill wells in the leased area that are held by production with an existing producing well. We believe adding operating capabilities will provide us more control over our capital budget and ultimately will result in a higher return on capital over the long-term. We expect to fund all of our 2012 capital expenditures using cash-on-hand, cash flow from operations, borrowings under our revolving credit facility and equity and/or debt financings.

Our future financial results will depend primarily on: (i) the ability to continue to source and screen potential projects; (ii) the ability to discover commercial quantities of crude oil and natural gas; (iii) the market price for crude oil and natural gas; and (iv) the ability to fully implement our exploration and development program, which is dependent on the availability of capital resources. There can be no assurance that we will be successful in any of these respects, that the prices of crude oil and natural gas prevailing at the time of production will be at a level allowing for profitable production, or that we will be able to obtain additional funding, if necessary.

Critical Accounting Policies

Revenue Recognition and Natural Gas Balancing

We recognize oil and natural gas revenues from our interests in producing wells when production is delivered, and title has transferred to the purchaser and to the extent the selling price is reasonably determinable. We use the sales method of accounting for natural gas balancing of natural gas production and would recognize a liability if the existing proven reserves were not adequate to cover the current imbalance situation. As of June 30, 2012 and December 31, 2011, our natural gas production was in balance, i.e., our cumulative portion of natural gas production taken and sold from wells in which we have an interest equaled our entitled interest in natural gas production from those wells.

Full Cost Method

We assess all items classified as unevaluated property on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. For the six months ended June 30, 2012 we had no costs that were transferred to the full cost pool related to impairment. For the year ended December 31, 2011, we included $6,983,125 related to expiring leases within costs subject to the depletion calculation.

Capitalized costs (net of related deferred income taxes) are limited to a ceiling based on the present value of future net revenues using the 12-month unweighted average of first-day-of-the-month price (the “12-month average price”), discounted at 10%, plus the lower of cost or fair market value of unproved properties. If the ceiling is not greater than or equal to the total capitalized costs, we are required to write down capitalized costs to the ceiling. We perform this ceiling test calculation each quarter. Any required write downs are included in the condensed statements of operations as an impairment charge. There was no impairment for the six months ended June 30, 2012 and 2011.

Joint Ventures

The condensed financial statements as of June 30, 2012 and 2011 include our accounts and our proportionate share of the assets, liabilities, and results of operations of the joint ventures in which we are involved.

Stock-Based Compensation

We have accounted for stock-based compensation under the provisions of ASC 718-10-55. We recognize stock-based compensation expense in the financial statements over the vesting period of equity-classified employee stock-based compensation awards based on the grant date fair value of the awards, net of estimated forfeitures. For options and warrants we use the Black-Scholes option valuation model to calculate the fair value of stock based compensation awards at the date of grant. Option pricing models require the input of highly subjective assumptions, including the expected price volatility. For the stock options and warrants granted we have used a variety of comparable and peer companies to determine the expected volatility input based on the expected term of the options. We believe the use or peer company data fairly represents the expected volatility it would experience if it were in the oil and natural gas industry over the expected term of the options. We used the simplified method to determine the expected term of the options due to the lack of historical data. Changes in these assumptions can materially affect the fair value estimate.

On May 27, 2011, our shareholders approved the Voyager Oil & Gas, Inc. 2011 Equity Incentive Plan (the “2011 Plan”), under which 5,000,000 shares of common stock have been reserved. The purpose of the 2011 Plan is to promote the success of the Company by facilitating the employment and retention of competent personnel and by furnishing incentives to those employees, directors and consultants upon whose efforts the success of the Company will depend to a large degree. It is our intention to carry out the 2011 Plan through the granting of incentive stock options, nonqualified stock options, restricted stock awards, restricted stock unit awards, performance awards and stock appreciation rights. As of June 30, 2012, we had issued 1,520,000 shares of common stock reserved under the 2011 Plan.

Cautionary Factors That May Affect Future Results

This Quarterly Report on Form 10-Q contains, and we may from time to time otherwise make in other public filings, press releases and presentations, forward-looking statements within the meaning of the federal securities laws. All statements other than statements of historical facts are forward-looking statements. Such statements can be identified by the use of forward-looking terminology such as “believe,” “expect,” “may,” “should,” “seek,” “on-track,” “plan,” “project,” “forecast,” “intend” or “anticipate,” or the negative thereof or comparable terminology, or by discussions of vision, strategy or outlook, including statements related to our beliefs and intentions with respect to our growth strategy, including the amount we may invest, the location, and the scale of the drilling projects in which we intend to participate; our beliefs with respect to the potential value of drilling projects; our beliefs with regard to the impact of environmental and other regulations on our business; our beliefs with respect to the strengths of our business model; our assumptions, beliefs, and expectations with respect to future market conditions; our plans for future capital expenditures; and our capital needs, the adequacy of our capital resources, and potential sources of capital. You are cautioned that our business and operations are subject to a variety of risks and uncertainties, many of which are beyond our control and, consequently, our actual results may differ materially from those projected by any forward-looking statements. You should consider carefully the statements under the “Risk Factors” section of this report and in our Annual Report on Form 10-K for the year ended December 31, 2011 and the other disclosures contained herein and therein, which describe factors that could cause our actual results to differ from those anticipated in the forward-looking statements, including, but not limited to, the following factors:

our ability to diversify our operations in terms of both the nature and geographic scope of our business;

our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fully develop our undeveloped acreage positions;

our ability to successfully acquire additional properties, to discover reserves, to participate in exploration opportunities and to identify and enter into commercial arrangements with customers;

competition, including competition for acreage in resource play areas;

our ability to retain key members of management;

volatility in commodity prices for oil and natural gas;

the possibility that our industry may be subject to future regulatory or legislative actions (including any additional taxes and changes in environmental regulation);

the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;

the timing of and our ability to obtain financing on acceptable terms;

interest payment requirements of our debt obligations;

restrictions imposed by our debt instruments and compliance with our debt covenants;

substantial impairment write-downs;

our ability to replace oil and natural gas reserves;

environmental risks;

drilling and operating risks;

exploration and development risks;

general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business, may be less favorable than expected, including the possibility that the economic conditions in the United States will worsen and that capital markets are disrupted, which could adversely affect demand for oil and natural gas and make it difficult to access financial markets; and

other economic, competitive, governmental, legislative, regulatory, geopolitical and technological factors that may negatively impact our business, operations or pricing.

All forward-looking statements speak only as of the date of this report and are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this report. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Crude oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile, and these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. Our revenues during the three and six months ended June 30, 2012 and June 30, 2011 generally have increased or decreased along with any increases or decreases in crude oil or natural gas prices, but the exact impact on our income is indeterminable given the variety of expenses associated with producing and selling crude oil and natural gas that also increase and decrease along with crude oil and natural gas prices.

We entered into a facility with MBL on February 10, 2012 that requires us to enter into commodity derivative instruments for each month of the 36-month period following the date on which each such hedge agreement is executed, the notional volumes for which when aggregated with other commodity swap agreements and additional fixed-price physical off-take contracts then in effect, as of the date such instrument is executed, is not less than 50%, nor greater than 90%, of the reasonably anticipated projected production from our proved developed producing reserves. We intend to use of these commodity derivative instruments as a means of managing our exposure to price changes in the future. For additional discussion, see Item 2. Management’s Discuss and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Macquarie Credit Facility above.

Interest Rate Risk

As of June 30, 2012, we had borrowed $15 million under Tranche A and $3,030,730 under Tranche B under our credit facility.

Our credit facility with MBL subjects us to interest rate risk on borrowings. The credit facility allows us to fix the interest rate of borrowings under it for all or a portion of the principal balance for a period up to six months. To the extent the interest rate is fixed, interest rate changes affect the instrument’s fair market value but do not impact results of operations or cash flows. Conversely, for the portion of our borrowings that has a floating interest rate, interest rate changes will not affect the fair market value but will impact future results of operations and cash flows.

ITEM 4. CONTROLS AND PROCEDURES

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of our disclosure controls and procedures, as such term is defined under Rules 13a-15(e) or 15d-15(e) promulgated under the Exchange Act, as of the end of the period covered by this report. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective.

There have been no changes (including corrective actions with regard to significant deficiencies of material weaknesses) in our internal control over financial reporting that occurred during our most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

ITEM 1A. RISK FACTORS

In addition to the other information set forth in this Quarterly Report on Form 10-Q, you should carefully consider the risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2011, including those listed under the heading “Item 1A. Risk Factors,” which risks could materially affect our business, financial condition or future results. There have been no material changes to the risk factors described in our Annual Report on Form 10-K for the year ended December 31, 2011 and our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2012,except as stated below.

Acquisitions, such as the Emerald Oil purchase, may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities.

Our recent growth is due in large part to acquisitions of producing properties and undeveloped leasehold, especially the Emerald Oil acquisition. We expect acquisitions, such as the Emerald Oil purchase, will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, operating costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform a review of the acquired properties which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems, and does not involve a review of seismic data or independent environmental testing, including for the Emerald Oil purchase. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities, including any structural, subsurface and environmental problems that may exist or arise. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete future acquisitions on terms that we believe are acceptable or, even if completed, that do not contain problems that reduce the value of acquired property.

We may have difficulty integrating and managing the growth associated with the Emerald Oil acquisition.

The Emerald Oil acquisition has resulted in a significant growth in our assets, reserves and revenues and may place a significant strain on our financial, technical, operational and administrative resources. We may not be able to integrate the operations of the acquired assets without increases in costs, losses in revenues or other difficulties. In addition, we may not be able to realize the operating efficiencies, synergies, costs savings or other benefits expected from the Emerald Oil acquisition. Any unexpected costs or delays incurred in connection with the integration could have an adverse effect on our business, results of operations or financial condition. Our ability to continue to grow after the Emerald Oil acquisition will depend upon a number of factors, including our ability to identify and acquire new exploratory prospects, other acquisition targets, our ability to develop then existing prospects, our ability to continue to retain and attract skilled personnel, the results of our drilling program and acquisition efforts, hydrocarbon prices and access to capital. We may not be successful in achieving or managing growth and any such failure could have a material adverse effect on us.

Properties that we acquire may not produce as projected, and we may not have identified all liabilities associated with the properties.

Our assessment of the properties in acquisitions may not reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well. Inspections may not reveal structural or environmental problems. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

If we are not able to generate sufficient funds from our operations and other financing sources, we may not be able to finance our planned development activity, acquisitions or service our debt .

We have been dependent on debt and equity financing to fund our cash needs that are not funded from operations or the sale of assets. In addition, low commodity prices, production problems, disappointing drilling results and other factors beyond our control could reduce our funds from operations and may restrict our ability to obtain additional financing or to pay interest and principal on our debt obligations. Furthermore, we have incurred losses in the past that may affect our ability to obtain financing. Quantifying or predicting the likelihood of any or all of these occurring is difficult in the current domestic and world economy. For these reasons, financing may not be available to us in the future on acceptable terms or at all. In the event additional capital is required but not available on acceptable terms, we would curtail our acquisition, drilling, development and other activities or could be forced to sell some of our assets on an untimely or unfavorable basis.

We have significant debt, trade payables, other long-term obligations .

Our trade payables, other long-term obligations and related interest payment requirements and scheduled debt maturities may have important negative consequences. For instance, they could:

make it more difficult or render us unable to satisfy these or our other financial obligations;

require us to dedicate a substantial portion of any cash flow from operations to the payment of overriding royalties or interest and principal due under our debt, which will reduce funds available for other business purposes;

increase our vulnerability to general adverse economic and industry conditions;

limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

place us at a competitive disadvantage compared to some of our competitors that have less financial leverage; and

limit our ability to obtain additional financing required to fund working capital and capital expenditures and for other general corporate purposes.

Our ability to overcome our negative working capital and to satisfy our financial obligations and commitments depends on our future operating performance and on economic, financial, competitive and other factors, many of which are beyond our control. We cannot provide assurance that our business will generate sufficient cash flow or that future financings will be available to provide sufficient proceeds to meet these obligations. The inability to meet our financial obligations and commitments will impede the successful execution of our business strategy and the maintenance of our economic viability. Oil and natural gas prices are volatile, and low prices have had in the past and could have in the future a material adverse impact on our business. Our revenues, profitability and future growth and the carrying value of our properties depend substantially on the prices we realize for our oil and natural gas production. Our realized prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital.

Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

Our bank credit facility contains a number of significant covenants that, among other things, restrict or limit our ability to:

pay dividends or distributions on our capital stock;

make certain loans and investments;

enter into certain transactions with affiliates;

create or assume certain liens on our assets;

merge or to enter into other business combination transactions;

enter into transactions that would result in a change of control of us; or

engage in certain other corporate activities.

Also, our bank credit facility requires us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control, and we cannot assure you that we will meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general or otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our bank credit facility impose on us.

A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under our bank credit facility. A default, if not cured or waived, could result in all indebtedness outstanding under our bank credit facility to become immediately due and payable. If that should occur, we may not be able to pay all such debt or borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us. If we were unable to repay those amounts, the lenders could accelerate the maturity of the debt or proceed against any collateral granted to them to secure such defaulted debt.

We have limited control over activities on properties that we do not operate.

We are not the operator on a significant portion of our properties. Because we are not the operator for these properties, our ability to exercise influence over the operations of these properties or their associated costs is limited. Our dependence on the operators and other working interest owners of these projects and our limited ability to influence operations and associated costs or control the risks could materially and adversely affect the realization of our targeted returns on capital in drilling or acquisition activities. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors, including:

timing and amount of capital expenditures;

the operator’s expertise and financial resources;

the rate of production of reserves, if any;

approval of other participants in drilling wells; and

selection of technology.

In areas where we do not have the right to propose the drilling of wells, we may have limited influence on when, how and at what pace our properties in those areas are developed. Further, the operators of those properties may experience financial problems in the future or may sell their rights to another operator not of our choosing, both of which could limit our ability to develop and monetize the underlying natural gas reserves. In addition, the operators of these properties may elect to curtail the oil or natural gas production or to shut in the wells on these properties during periods of low oil or natural gas prices, and we may receive less than anticipated or no production and associated revenues from these properties until the operator elects to return them to production.

Delays in the development of or production curtailment at our material properties may adversely affect our financial position and results of operations.

The size of our operations and our capital expenditures budget limit the number of properties that we can develop in any given year. Complications in the development of any single major well or infrastructure installation may result in a material adverse effect on our financial condition and results of operations. In addition, relatively few wells contribute a substantial portion of our production. If we were to experience operational problems or adverse commodity prices resulting in the curtailment of production in any of these wells, our total production levels would be adversely affected, which would have a material adverse effect on our financial condition and results of operations.

Federal legislation regarding derivatives could have an adverse effect on our ability and cost of entering into derivative transactions.

On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Reform Act”), which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The new legislation requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. On October 1, 2010, the CFTC introduced its first series of proposed rules coming out of the Dodd-Frank Reform Act. In July 2011, the CFTC granted temporary exemptive relief from certain swap regulation provisions of the legislation until December 31, 2011, or until the agency finalized the corresponding rules. In December 2011, the CFTC extended the potential latest expiration date of the exemptive relief to July 16, 2012. In May 2012, the CFTC proposed an amendment to further extend the potential latest expiration date until December 31, 2012.

In its rulemaking under the new legislation, the CFTC has issued a final rule on position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions are exempt from these position limits. The CFTC has also issued final rules further defining “swap dealer” and “major swap participant.” It is not possible at this time to predict when the CFTC will finalize other regulations, including critical rulemaking on the definition of “swap.” Depending on our classification under the regulations, the financial reform legislation may require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities. The financial reform legislation may also require our counterparties to the derivative contracts to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure existing derivative contracts, and increase our potential exposure to less creditworthy counterparties. If we reduce our use of derivatives or commodity prices decline as a result of the legislation and regulations, our results of operations may become more volatile and cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures, our results of operations, or our cash flows.

ITEM 6. EXHIBITS

The following documents are included as exhibits to this Quarterly Report on Form 10-Q. Those exhibits incorporated by reference are so indicated by the information supplied with respect thereto. Those exhibits which are not incorporated by reference are attached hereto.

2.1

Securities Purchase Agreement, dated July 9, 2012, among Voyager Oil & Gas, Inc., Emerald Oil & Gas NL and Emerald Oil, Inc. (incorporated by reference to Exhibit 2.1 to our current report on Form 8-K filed on July 10, 2012)

10.1

Amended and Restated Credit Agreement, dated July 26, 2012, among Voyager Oil & Gas, Inc., as Borrower, Macquarie Bank Limited, as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.1 to our current report on Form 8-K filed on July 31, 2012)

10.2

Employment Agreement, dated July 26, 2012, between Voyager Oil & Gas, Inc. and J.R. Reger (incorporated by reference to Exhibit 10.2 to our current report on Form 8-K filed on July 31, 2012)

10.3

Employment Agreement, dated July 26, 2012, between Voyager Oil & Gas, Inc. and McAndrew Rudisill (incorporated by reference to Exhibit 10.3 to our current report on Form 8-K filed on July 31, 2012)

10.4

Employment Agreement, dated July 26, 2012, between Voyager Oil & Gas, Inc. and Mike Krzus (incorporated by reference to Exhibit 10.4 to our current report on Form 8-K filed on July 31, 2012)

10.5

Employment Agreement, dated July 26, 2012, between Voyager Oil & Gas, Inc. and Mitchell R. Thompson (incorporated by reference to Exhibit 10.5 to our current report on Form 8-K filed on July 31, 2012)

10.6

Employment Agreement, dated July 26, 2012, between Voyager Oil & Gas, Inc. and Paul Wiesner (incorporated by reference to Exhibit 10.6 to our current report on Form 8-K filed on July 31, 2012)

10.7

Employment Agreement, dated July 26, 2012, between Voyager Oil & Gas, Inc. and Karl Osterbuhr (incorporated by reference to Exhibit 10.7 to our current report on Form 8-K filed on July 31, 2012)

10.8

Employment Agreement dated March 30, 2012 by and between Martin J. Beskow and Voyager Oil & Gas, Inc. (incorporated by reference to Exhibit 10.1 to our current report on Form 8-K filed on April 5, 2012)

31.1*

Certification of Chief Executive Officer pursuant to Securities Exchange Act Rules 13a-15(e) and 15d-15(e) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2*

Certification of Chief Financial Officer pursuant to Securities Exchange Act Rules 13a-15(e) and 15d-15(e) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1*

Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101.INS ¹

XBRL Instance Document

101.SCH ¹

XBRL Schema Document

101.CAL ¹

XBRL Calculation Linkbase Document

101.LAB ¹

XBRL Label Linkbase Document

101.PRE ¹

XBRL Presentation Linkbase Document

Attached hereto.

To be filed by amendment.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report on Form 10-Q to be signed on its behalf by the undersigned, thereunto duly authorized.

Dated: August 6, 2012	VOYAGER OIL & GAS, INC.

	/s/ Michael Krzus
	Michael Krzus
	Chief Executive Officer (principal executive officer)

	/s/ Paul Wiesner
	Paul Wiesner
	Chief Financial Officer (principal financial officer)