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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

For the quarterly period ended June 30, 2011

OR

For the transition period from                  to                 

Commission File No. 0-50848

Voyager Oil & Gas, Inc.

(Exact name of registrant as specified in its charter)

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 o

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 o

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):

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

As of August 8, 2011, there were 57,848,431 shares of Common Stock, $0.001 par value per share, outstanding.

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VOYAGER OIL & GAS, INC.

INDEX

PART 1 — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

VOYAGER OIL & GAS, INC.

CONDENSED BALANCE SHEETS

AS OF JUNE 30, 2011 (UNAUDITED) AND DECEMBER 31, 2010

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

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VOYAGER OIL & GAS, INC.

UNAUDITED CONDENSED STATEMENTS OF OPERATIONS

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2011 AND 2010

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

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VOYAGER OIL & GAS, INC.

UNAUDITED CONDENSED STATEMENTS OF CASH FLOWS

FOR THE SIX MONTHS ENDED JUNE 30, 2011 AND 2010

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

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VOYAGER OIL & GAS, INC.

Notes to Unaudited Condensed Financial Statements

June 30, 2011

NOTE 1 ORGANIZATION AND NATURE OF BUSINESS

Description of Operations—Voyager Oil & Gas, Inc., a Montana corporation (the “Company” or “Voyager”), is an independent non-operator oil and natural gas company engaged in the business of acquiring acreage in prospective natural resource plays primarily within the Williston Basin located in Montana and North Dakota and within the Denver-Julesburg (D-J) Basin located in Colorado and Wyoming. The Company seeks to accumulate acreage blocks on a non-operated basis and build net asset value via the production of hydrocarbons in repeatable and scalable opportunities.

As an independent oil and gas producer, the Company’s revenue, profitability and future rate of growth are substantially dependent on prevailing prices of natural gas and crude oil. Historically, the energy markets have been very volatile and it is likely that oil and gas prices will continue to be subject to wide fluctuations in the future. A substantial or extended decline in natural gas and oil prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows and access to capital, and on the quantities of natural gas and oil reserves that can be economically produced.

As a non-operator, Voyager focuses on maintaining a relatively small amount of overhead. The Company engages in the drilling process through operators’ drilling units that include the Company’s acreage position. By eliminating the fixed staffing required to manage this process internally, the Company reduces its fixed employee cost structure and overhead.  The Company had five employees as of June 30, 2011 and seeks to retain 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 gas business. With the continued acquisition of oil and gas properties, the Company intends to continue to establish itself with industry partners best suited to the areas of operation. As the Company continues to establish a revenue base with cash flow, it may seek opportunities more aggressive in nature.

Organization of the Company—On April 16, 2010, Voyager (formerly known as ante4, Inc.), Plains Energy Acquisition, Inc. (“Acquisition Sub”) and Plains Energy Investments, Inc. (“the Target Company”) entered into an Agreement and Plan of Merger (the “Merger Agreement”), pursuant to which Acquisition Sub merged with and into the Target Company, with the Target Company remaining as the surviving corporation and a wholly-owned subsidiary of the Company and subsequently dissolved.  Following the merger, the Company changed its name from ante4, Inc. to Voyager Oil & Gas, Inc.  As part of the merger, ante4, Inc. transferred all assets other than specific assets set forth in the Merger Agreement into a wholly owned subsidiary, which assets were primarily related to ante4 Inc.’s prior unrelated entertainment and consumer products business, and spun that subsidiary to its pre-merger stockholders.  Effective May 31, 2011, the Company reincorporated from Delaware to Montana.

NOTE 2 SIGNIFICANT ACCOUNTING POLICIES

The condensed financial information included herein is unaudited, except the condensed balance sheet as of December 31, 2010, which has been derived from the Company’s audited financial statements as of December 31, 2010.  However, such information includes all adjustments (consisting of normal recurring adjustments) that are necessary in the opinion of management to fairly present the Company’s financial position, results of operations and cash flows for the interim periods.  The results of operations for interim periods are not necessarily indicative of the results to be expected for an entire year.

Certain information, accounting policies, and footnote disclosures normally included in the financial statements prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) have been condensed or omitted pursuant to certain rules and regulations of the Securities and Exchange Commission.  Interim financial results should be read in conjunction with the

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audited financial statements and footnotes for the year ended December 31, 2010, which were included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

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. Due to the balances being greater than $250,000, the Company does not have FDIC coverage on the entire amount of its bank deposits. The Company believes this risk is minimal. 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

Restricted Cash

At June 30, 2011, the Company had $51,000 of restricted cash. The restricted cash served as collateral for an irrevocable standby letter of credit that provides financial assurance that the Company fulfilled its obligations with respect to an office lease. The cash was held in custody by the issuing bank, was restricted as to withdrawal or use, and was invested in interest-bearing money market funds. Income from these investments was paid to the Company and recognized in other income.  In July 2011 the Company completed its obligations under the office lease, and the restricted cash was released to the Company and transferred to unrestricted cash.

Short-Term Investments

All marketable debt, equity securities and certificates of deposit that were included in short-term investments as of December 31, 2010 were considered available-for-sale and were carried at fair value. The short-term investments were considered current assets as of December 31, 2010 due to the Company’s ability and intent to use them to fund current operations. The unrealized gains and losses related to these securities were included in accumulated other comprehensive income (loss). When securities were sold, their cost was determined based on specific identification. The realized gains and losses related to these securities were included in other income in the statements of operations.

For the six months ended June 30, 2010 there were realized gains of $10,138 recognized on the sale of investments.  There were no realized gains or losses recognized on the sale of investments for the six months ended June 30, 2011.

Other Property and Equipment

Property and equipment that are not oil and 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. Long-lived assets, other than oil and gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. The Company has not recognized any impairment losses on non-oil and gas long-lived assets. Depreciation expense was $8,912 for the six months ended June 30, 2011.

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

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recorded amount, a gain or loss is recognized. Asset retirement obligations are included in other noncurrent liabilities on the condensed balance sheet.

Revenue Recognition and Gas Balancing

The Company recognizes oil and gas revenues from its interests in producing wells when production is delivered to 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 gas balancing of 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, 2011, the Company’s natural gas production was in balance, i.e., its cumulative portion of gas production taken and sold from wells in which it has an interest equaled the Company’s entitled interest in gas production from those wells.

Stock-Based Compensation

The Company has accounted for stock-based compensation under the provisions of FASB Accounting Standards Codification (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 in 2011, 2010 and 2009 the Company 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 of peer company data fairly represents the expected volatility it would experience if it were in the oil and 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”).  The purpose of the Plan is to promote the success of the Company and its Affiliates 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 and its Affiliates will depend to a large degree. It is the intention of the Company to carry out the Plan through the granting of Incentive Stock Options, Nonqualified Stock Options, Restricted Stock Awards, Restricted Stock Unit Awards, Performance Awards and Stock Appreciation Rights. 5,000,000 shares of common stock are reserved. As of June 30, 2011 150,000 unvested stock options were issued to employees under the 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.

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

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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 months ended June 30, 2011, the potentially dilutive shares are anti-dilutive and are thus not added into the earnings per share calculation.

As of June 30, 2011, there were (i) 468,916 shares of restricted stock that were issued and vest in December 2012 and represent potentially dilutive shares; (ii) 375,000 stock options that were issued and presently exercisable and represent potentially dilutive shares; (iii) 600,000 stock options that were granted but are not presently exercisable and represent potentially dilutive shares; (iv) 1,563,051 warrants that were issued but not presently exercisable, which have an exercise price of $0.98 and vest in December 2011; and (v) 6,250,000 warrants that were issued and presently exercisable, which have an exercise price of $7.10.

Full Cost Method

The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and 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 six month period 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 gas properties.

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. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool. As of June 30, 2011, the Company has had no property sales.

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 six months ended June 30, 2011, the Company included $211,176 related to expired leases in Wyoming 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 as determined by independent petroleum engineers. The costs of unproved properties are withheld from the depletion base until such time as they are developed, impaired or abandoned.

Capitalized costs of oil and gas properties (net of related deferred income taxes) may not exceed an amount equal to the present value, discounted at 10% per annum, of the estimated future net cash flows from proved oil and gas reserves plus the cost of unproved properties (adjusted for related income tax effects). Should capitalized costs exceed this ceiling, impairment is recognized. The present value of estimated future net cash flows is computed by applying the arithmetic average first day price of oil and natural gas for the preceding 12-months to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions. Such present value of proved reserves’ future net cash flows excludes future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet. Should this comparison indicate an excess carrying value, the excess is

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charged to earnings as an impairment expense. There was no impairment of oil and gas properties recorded for the six months ended June 30, 2011.

Joint Ventures

The condensed financial statements as of June 30, 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 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, valuation of share based compensation and the valuation of deferred income taxes. Actual results may differ from those estimates.

Reclassifications

Certain reclassifications have been made to prior periods’ reported amounts in order to conform with the current period presentation. These reclassifications did not impact the Company’s net income, stockholders’ equity or cash flows.

Impairment

FASB ASC 360-10-35-21 requires that long-lived assets to be held and used be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Oil and gas properties accounted for using the full cost method of accounting (which the Company uses) are excluded from this requirement but continue to be subject to the full cost method’s impairment rules. There was no impairment identified at June 30, 2011.

Recent 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.

Change in Reporting Period End

On July 29, 2010, the Company’s Board of Directors approved a change in the Company’s fiscal year end to a traditional calendar year from that of a last Sunday of quarter end period. The change in reporting period has been reflected in this Quarterly Report on Form 10-Q. The Company’s fiscal year end is December 31, and the quarters end on March 31, June 30 and September 30.

NOTE 3 OIL AND 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 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

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production and reserves, while the third-party joint venture partner controls a 12.5% working interest. The joint venture had accumulated oil and gas leases totaling 67,384 net mineral acres as of June 30, 2011. 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 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 $3,910,917 as of June 30, 2011, consisting of $2,150,496 in leasing costs, $1,610,434 in seismic costs and $149,987 in drilling costs. The unutilized cash balance was $296,347 as of June 30, 2011.

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 the third-party investor and 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.

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 gas leases in the Heath 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 two third-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 gas leases totaling 33,562 net mineral acres as of June 30, 2011. 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, 2011. The unutilized cash balance was $11,799 as of June 30, 2011.

Niobrara Development with Slawson Exploration Company, Inc.

On June 28, 2010, the Company entered into an exploration and development agreement with Slawson Exploration Company, Inc. to develop Slawson’s 48,000 net acres in the Niobrara formation of the Denver-Julesberg (D-J) Basin in Weld County, Colorado, which included approximately 34,000 net acres leased from the State of Colorado. Slawson commenced the continuous drilling program in early July 2010 with an initial series of three test wells. Beginning in October 2010, Slawson commenced drilling operations on 15 spacing units and an additional 10 spacing units’ leases which were granted extensions to November 2011 by the state of Colorado due to access restrictions. Voyager purchased a 50% working interest in the approximately 48,000 acre block for $7.5 million to participate on a heads-up basis on all wells drilled, as well as participate for its proportionate working interest in all additional acreage acquired in an Area of Mutual Interest consisting of Weld and Laramie Counties. Following the results of the initial three test wells, Voyager and Slawson allowed approximately 15,000 acres of the initial 34,000 acres of state leases in Weld County, Colorado to expire on November 15, 2010. The Company currently holds approximately 10,000 net acres. Three additional wells were drilled during the quarter ended March 31, 2011, two of which were in production and the third was in the process of being completed as of June 30, 2011.

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Other 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 six months ended June 30, 2011.

The risk that the Company will experience a ceiling test write-down increases when oil and gas prices are depressed or if the Company has substantial downward revisions in its estimated proved reserves. Based on calculated reserves at December 31, 2010 the unamortized costs of the Company’s oil and gas properties exceeded the ceiling limit by $1,377,188. As a result, the Company was required to record a write-down of the net capitalized costs of its oil and gas properties in the amount of $1,377,188 at December 31, 2010.  The Company analyzed the need of a further ceiling test write-down for the six months ended June 30, 2011 and determined that an additional write-down was not required as a result of increased production and related proved developed reserves during the six months ended June 30, 2011, as well as increased oil prices used in the ceiling test.

NOTE 4 RELATED PARTY TRANSACTIONS

On March 10, 2010, the Company purchased leasehold interests from South Fork Exploration, LLC (“SFE”) for $1,374,375 and 2,234,600 shares of restricted common stock with a fair value of $2,358,900. J.R. Reger, the Chief Executive Officer and a director of the Company, is also the president of SFE. Following the sale of the leasehold interests to the Company, SFE no longer had any active leasing operations. In connection with this purchase, the Company obtained a fairness opinion from an independent, third-party geologist.

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.

NOTE 5 PREFERRED AND COMMON STOCK

The Company has 200,000,000 shares of common stock and 20,000,000 shares of preferred stock authorized. No shares of preferred stock have been issued as of June 30, 2011.

In February 2011, the Company completed a private placement of 12,500,000 units, which consisted of one share of common stock and a warrant to purchase one-half of a share of common stock, at a subscription price of $4.00 per unit for total gross proceeds of $50 million. The exercise price of the warrants is $7.10 per whole share of common stock for a period of five years from the date of the closing.  The total number of shares that are issuable upon exercise of warrants is 6,250,000.  The Company incurred costs of $3,397,749 related to this transaction, which costs were netted against the proceeds of the transaction through additional paid-in capital.

Restricted Stock Awards

During the year ended December 31, 2009, the Company issued 468,916 restricted shares of common stock as compensation to its officers. The restricted shares vest on December 1, 2011 and December 31, 2011. As of June 30, 2011, there was approximately $112,000 of total unrecognized compensation expense related to unvested restricted stock. This compensation expense will be recognized over the remaining vesting period of the grants. The Company has assumed a 0% forfeiture rate for the restricted stock, and there were no changes to the outstanding restricted common stock during the six month period ended June 30, 2011.

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NOTE 6 STOCK OPTIONS AND WARRANTS

Stock Options Granted May 2011

In May 2011, the Company granted stock options to two employees to purchase a total of 100,000 and 50,000 shares of common stock exercisable at $3.02 and $3.55 per share, respectively. 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 options vest over one year with all of the options vesting on the anniversary date of the grant.

The following assumptions were used for the Black-Scholes model:

The “fair market value” at the date of grant for stock options granted is as follows:

Stock Options

The following summarizes activities concerning outstanding options to purchase shares of the Company’s common stock as of and for the period ending June 30, 2011:

Currently Outstanding Options

· Options covering 4,000 shares were exercised during the six months ended June 30, 2011.

· Options covering 150,000 shares were forfeited during the six months ended June 30, 2011.

· No options expired during the six months ended June 30, 2011.

· The Company recognized $153,040 of expense and capitalized $34,652 related to outstanding options for the six-month period ended June 30, 2011.

· The Company will recognize $925,812 of compensation expense in future periods relating to options that have been granted as of June 30, 2011.

· There were 600,000 unvested options at June 30, 2011.

Warrants

Warrants Granted February 2011

In February 2011, in conjunction with the sale of 12,500,000 shares of common stock (see Note 5), the Company issued investors warrants to purchase a total of 6,250,000 shares of common stock exercisable at $7.10 per share.

The table below reflects the status of warrants outstanding at June 30, 2011:

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Outstanding Warrants:

· No warrants were forfeited or expired during the six month period ended June 30, 2011.

· The Company recorded expense related to these warrants of $164,997 and capitalized $76,564 for the six-month period ended June 30, 2011. The Company will recognize $234,895 of compensation expense in future periods relating to warrants that have been granted as of June 30, 2011.

· There were 6,250,000 warrants exercisable at June 30, 2011, and 1,563,051 that become exercisable during December 2011.

NOTE 7 SENIOR SECURED PROMISSORY NOTES

In September 2010, the Company issued 12% 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 are being used primarily to fund developmental drilling on the Company’s significant acreage positions targeting the Denver-Julesberg Basin Niobrara through its joint venture with Slawson Exploration and the Williston Basin Bakken/Three Forks area.

The Notes bear interest at the rate of 12% per annum, with interest payable monthly beginning October 1, 2010. The Notes are secured by a first priority security interest on all of the Company’s assets, on a pari passu basis with each other. The Notes mature one year from the date of issuance. The Company has the option to extend the term for one year by making an extension payment equal to two percent (2%) of the principal amount, or $300,000. The Company may pre-pay the Notes at a price of one hundred two percent (102%) of face value during the initial twelve months, and may pre-pay the Notes at anytime without penalty during the extended term.

The Notes were sold at a discount and yielded cash proceeds of $14,775,000. The discount amount of $225,000 is being amortized to interest expense over twelve months, the initial term of the Notes, using the effective interest method. The amortization of the discount for the six months ended June 30, 2011 was $111,575.

NOTE 8 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 during the six month period ended June 30, 2011:

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NOTE 9 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 2011 as a result of the losses recorded during the six months ended June 30, 2011 as well as additional losses expected for the remainder of 2011.  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, 2011, 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 10 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 under FASB ASC 820-10-55 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—Quoted prices in active markets 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 or 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.

The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the nonfinancial assets and liabilities and their placement in the fair value hierarchy levels. The fair value of the Company’s asset retirement obligations at their inception are determined using discounted cash flow methodologies based on inputs that are not readily available in public markets. The fair value of the asset retirement obligations incurred during the period is reflected on the balance sheet as follows.

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See Note 8 for a rollforward of the Asset Retirement Obligation.

NOTE 11 FINANCIAL INSTRUMENTS

The Company’s financial instruments include cash and cash equivalents, short-term investments, restricted cash, accounts receivable, accounts payable and senior secured promissory notes. The carrying amount of cash and cash equivalents, short-term investments, restricted cash, accounts receivable, accounts payable, and senior secured promissory notes approximate fair value because of their immediate or short-term maturities.

The Company’s accounts receivable relate to oil and natural gas sold to various industry companies. Credit terms, typical of industry standards, are of a short-term nature and the Company does not require collateral. Management believes the Company’s accounts receivable at June 30, 2011 do not represent significant credit risks as they are dispersed across many counterparties.

NOTE 12 COMPREHENSIVE INCOME

The Company follows the provisions of FASB ASC 220-10-55, which establishes standards for reporting comprehensive income. In addition to net income, comprehensive income includes all changes in equity during a period, except those resulting from investments and distributions to stockholders of the Company.

For the periods indicated, comprehensive income (loss) consisted of the following:

NOTE 13 SUBSEQUENT EVENTS

On July 7, 2011, the Company purchased 1,208 net mineral acres in Richland County, Montana for $891,850.

On July 1, 2011 the Company purchased approximately 507 net mineral acres in McKenzie County, North Dakota and Richland County, Montana for $856,030.

On July 8, 2011 the Company purchased approximately 440 net mineral acres in McKenzie County, North Dakota for $864,000.

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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 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 providing capital investments on a non-operated basis for acreage acquisitions and working interests in existing or planned hydrocarbon production, primarily focusing on acquiring working interests in scalable, repeatable oil and natural gas plays where established oil and gas companies have operations. Our business currently focuses on properties in Montana, North Dakota, 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 commitment may grow if the opportunity presents itself and depending upon the results of initial testing of wells and development activities.

Our primary focus is to acquire high value leasehold interests specifically targeting oil shale resource prospects in the continental United States. Although our acreage is primarily located in Montana, North Dakota, 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. We believe our competitive advantage is our ability to continue to acquire leases directly from the mineral owners through “organic leasing.” Because of our size and maneuverability, we are able to deploy our land acquisition teams into specific areas based on the latest industry information. We generate revenue by and through the conversion of our leasehold into non-operated working interests in multiple Bakken, Three Forks, Niobrara and other oil shale wells. We believe our drilling participation, primarily on a heads-up basis proportionate to our working interest, will allow us to deliver high value with low cost.

We are also currently engaged in a top-leasing program in targeted areas of the Williston Basin. A top-lease is a lease acquired prior to and commencing immediately upon the expiration of the current lease. We believe this approach allows us to access the most prolific areas of the Bakken oilfields. Existing lease terms vary significantly once an area initially becomes productive. We continue to see this approach met with success, as the Williston Basin delineates given the rapidly expanding nature of the productive area of the play.

We explore, develop and produce oil and natural gas through a non-operated business model. We participate in the drilling process through the inclusion of our acreage within operators’ drilling units. As a non-operator, we rely on our operating partners to propose, permit and engage in the drilling process. Before a well is spud, the operator is required to provide all oil and gas interest owners in the designated well unit the opportunity to participate in the drilling costs and revenues of the well on a pro-rata basis. After the well is completed, our operating partners also transport, market and account for all production. It is our policy and goal to engage and participate on a heads-up basis in substantially all, if not all, wells proposed. This model provides us with diversification across operators and geologic areas. It also allows us to continue to add production at a low marginal cost and maintain general and administrative costs at minimal levels.

Assets and Acreage Holdings

As of August 8, 2011, we control approximately 141,000 net acres in the following five primary prospect areas:

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·30,000 core net acres targeting the Bakken/Three Forks formation in North Dakota and Montana;

·10,000 net acres targeting the Niobrara formation in Colorado and Wyoming;

·800 net acres targeting a Red River prospect in Montana;

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

·67,000 net acres in a joint venture in the Tiger Ridge gas field in Blaine, Hill and Chouteau Counties of Montana.

With the exception of the leases targeting the Niobrara formation, the non-producing leases we control have a minimum term of three years and many have extensions effectively giving us control of lands for up to ten years.

We presently control approximately 9,000 net acres in Colorado and 1,000 net acres in Wyoming targeting the Niobrara formation.  For the six months ended June 30, 2011, the Company included $211,176 related to expired leases in Wyoming within costs subject to the depletion calculation.

As described in Note 2 in the footnotes to the financial statements, capitalized costs of oil and gas properties (net of related deferred income taxes) may not exceed an amount equal to the present value, discounted at 10% per annum, of the estimated future net cash flows from proved oil and gas reserves plus the cost of unevaluated properties (adjusted for related income tax effects).  Should capitalized costs exceed this ceiling, impairment is recognized.  The results of the ceiling test based on the reserve report at December 31, 2010 resulted in an impairment of $1,377,188 for the year ended December 31, 2010.  The Company analyzed the need of a further ceiling test write-down as of June 30, 2011 and noted one was not required due to the increase of producing wells and related proven developed reserves during the quarter and increased oil prices used in the ceiling test.

2011 Drilling Projects

We are engaged in several drilling activities on properties presently owned, and we intend to drill or develop additional properties acquired in the future.  As of June 30, 2011, we had interests in a total of 63 gross (3.13 net) Bakken-Three Forks wells that were in the process of being drilled or completed or currently producing, including 24 gross (1.13 net) producing Bakken-Three Forks wells.  Permits continue to be issued for drilling units in which we have acreage interests within North Dakota and Montana.  We expect to participate in 6 net Bakken-Three Forks wells in 2011.

We have completed the preliminary development of the acreage position we acquired in the Denver-Julesberg (D-J) Basin of Weld County, Colorado in 2010 with our operating partner, Slawson Exploration.  The initial development program consisted of three gross test wells, which were commenced in July 2010.  The results of the initial three test wells have provided data points on our acreage position and ultimately how many wells will be drilled in 2011.  Two of the three test wells were actively producing as of June 30, 2011.  Beginning in October 2010, Slawson commenced drilling operations on 15 spacing units and an additional 12 spacing units’ leases which were granted extensions to November 2011 by the state of Colorado due to access restrictions.  Slawson Exploration drilled three additional wells during the quarter ended March 31, 2011.  As of June 30, 2011 two of the wells are producing and the third is in process of being completed.

Production History

The following table presents information about our produced oil and gas volumes during the three and six months ended June 30, 2011, compared to the three and six months ended June 30, 2010.  As of June 30, 2011, we were selling oil and natural gas from a total of 28 gross wells (approximately 3.13 net wells), compared to two gross wells (0.07 net wells) at June 30, 2010.  All data presented below is derived from accrued revenue and production volumes for the relevant period indicated.

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Depletion of oil and natural gas properties

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.  The following table presents our depletion expenses for the three and six month periods ended June 30, 2011 compared to the three and six month periods ended June 30, 2010.

Productive Oil Wells

The following table summarizes gross and net productive oil wells by state at June 30, 2011 and June 30, 2010. A net well represents our fractional working ownership interest of a gross well. No wells have been permitted or drilled on any of our Big Snowy Joint Venture acreage in Montana. The following table also does not include wells that were awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation.

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Exploratory Oil Wells

Voyager is participating with a 50% working interest in exploratory oil wells in the Denver-Julesberg (D-J) Basin of Colorado with drilling partner Slawson Exploration. As of June 30, 2011, six wells had been drilled. Four of the wells were producing and included in the productive oil well table. The other two wells were in various stages of completion, and the costs incurred are included in unevaluated oil and gas properties on our balance sheet.  The Bushwacker #1-24H experienced geosteering issues while drilling and is being evaluated for rework.  The Moonshine #1-36H, Outlaw #16-11-66H, Joker #36-9-62H and Smuggler #16-10-62H were completed as producers. The Birds of Prey #36-10-61 is in the completion stage.  Slawson’s delineation of the more prospective acreage and additional 2011 well locations will be determined by the results of the three most recent wells.

Results of Operations

Comparison of the Three and Six Months Ended June 30, 2011 with the Three and Six Months Ended June 30, 2010.

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Revenues

We recognized $1,666,535 and $2,499,156 in revenues from sales of oil and natural gas for the three and six months ended June 30, 2011, compared to $162,548 and $185,045 for the three and six months ended June 30, 2010.  Revenues are a function of oil and natural gas volumes sold and average sales prices. We produced 17,866 and 28,127 barrels of oil equivalent (Boe) and averaged realized sales at $93.88 and $89.42 per Boe for the three and six months ended June 30, 2011 compared to 2,351 and 2,658 Boe with average realized sales price of $69.15 and $69.55 per Boe for the three and six months ended June 30, 2010.  This increase in revenue is due primarily to production from 24 gross (1.13 net) producing Bakken and Three Forks wells in the Williston Basin as of June 30, 2011, compared to production from two gross (0.07 net) wells as of June 30, 2010, as well as increased oil prices.  We report our revenues on wells in which we have a working interest based on information received from operators.  The recognition of revenues in this manner is in accordance with GAAP.

General and Administrative Expense

We recognized $706,617 and $1,400,931 in general and administrative expense for the three and six months ended June 30, 2011 compared to $440,000 and $695,710 for the three and six months ended June 30, 2010.  This increase resulted primarily from $216,197 and $457,109 of professional fees for the three and six months ended June 30, 2011, compared to $83,592 and $112,992 for the three and six months ended June 30, 2010.

Depreciation, Depletion and Amortization Expense

We recognized $568,469 and $977,240 in depreciation, depletion and amortization expense for the three and six months ended June 30, 2011, compared to $62,733 and $71,965 for the three and six months ended June 30, 2010.  This increase in expenses resulted from $560,344 and $968,328 of depletion of oil and gas properties for the three and six months ended June 30, 2011, compared to $62,000 and $70,500 for the three and six months ended June 30, 2010.

Net loss

We had a net loss of $465,057 and $1,354,831 (representing ($0.01) and ($0.02) per share) for the three and six months ended June 30, 2011, compared to a net loss of $1,114,577 and $1,348,618 (representing ($0.03) and ($0.04)  per share) for the three and six months ended June 30, 2010.  We recognized $1,666,535 and $2,499,156 in revenues from sales of oil and natural gas for the three and six months ended June 30, 2011, compared to $162,548 and $185,045 for the three and six months ended June 30, 2010.  Total operating expenses were $1,592,166 and $2,825,454 for the three and six months ended June 30, 2011, compared to operating expenses of $506,721 and $774,250 for the three and six months ended June 30, 2010.  Interest expense was $506,096 and $1,001,575 for the three and six months ended June 30, 2011, compared to $-0- for the three and six months ended June 30, 2010.  The increase in interest expense is due to the issuance of senior secured promissory notes in September 2010 described in Note 7 in the footnotes to the financial statements.

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Non-GAAP Financial Measures

Adjusted EBITDA

In addition to reporting net earnings (loss) as defined under GAAP, we also present net earnings before interest, income taxes, depreciation, depletion, and amortization (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 earnings (loss) (its most comparable GAAP financial measure), and Voyager’s calculations thereof may not be comparable to similarly titled measures reported by other companies. By eliminating the items described below, Voyager believes the measure is useful in evaluating its fundamental core operating performance. Voyager also believes 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. Voyager’s management uses adjusted EBITDA to manage its business, including in preparing its annual operating budget and financial projections. Voyager’s management does not view adjusted EBITDA in isolation and also uses other measurements, such as net earnings (loss) and revenues to measure operating performance. The following table provides a reconciliation of net earnings (loss), the most directly comparable GAAP measure, to adjusted EBITDA for the periods presented:

Liquidity and Capital Resources

Senior Secured Note Offering

On September 22, 2010, we received aggregate commitments for a $15,000,000 loan in the form of 12.00% Senior Secured Promissory Notes provided by certain accredited investors for the purpose of financing future drilling and development activities.  Proceeds from the Notes were used and will be used primarily to fund developmental drilling on our significant acreage positions targeting the Niobrara formation located in the Denver-Julesberg (D-J) Basin through our joint venture with Slawson Exploration and the Williston Basin Bakken/Three Forks formation.

The Notes bear interest at the rate of 12.00% per annum.  The Notes mature one year from their date of issuance, with an optional one-year extended term and are subject to the usual and customary financial covenants.  In order to enter the extension term, we will be required to pay an extension payment equal to two percent (2%) of the principal amount. We may pre-pay the Notes at a price of one hundred two percent (102%) of face value during the initial twelve months, and may pre-pay the Notes at any time without penalty during the extended term. The Notes yielded cash proceeds of $14,775,000 net of fees.  We paid a success fee equal to one percent (1.0%) of the proceeds raised from the Note offering to unrelated finders.  The holders of the Notes have a first priority security interest on all of our assets, on a pari passu basis with each other.

February 2011 Private Placement