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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549



 

FORM 10-K



 

 
(Mark One)     
x   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

or

 
o   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. — 001-35097



 

VOYAGER OIL & GAS, INC.

(Exact Name of Registrant as Specified in Its Charter)

 
Montana   77-0639000
(State or Other Jurisdiction of
Incorporation or Organization)
  (I.R.S. Employer
Identification No.)

2718 Montana Avenue, Suite 220, Billings, MT 59101

(Address of Principal Executive Offices) (Zip Code)

406-245-4901

(Registrant’s Telephone Number, Including Area Code)



 

Securities registered pursuant to Section 12(b) of the Act:

 
Title of Each Class   Name of Each Exchange On Which Registered
Common Stock, $0.001 par value   NYSE Amex

Securities registered pursuant to Section 12(g) of the Act:

None

(Title of Class)



 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes o No x

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 (§232.405 of this chapter) 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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

     
Large Accelerated Filer o   Accelerated Filer x   Non-Accelerated Filer o
(Do not check if a smaller reporting company)
  Smaller Reporting Company o

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

The aggregate market value of the registrant’s voting and non-voting common equity held by non-affiliates of the registrant on the last business day of the registrant’s most recently completed second fiscal quarter (based on the closing sale price as reported by the NYSE Amex Equities) was approximately $172 million.

As of March 13, 2012, the registrant had 57,848,431 shares of common stock issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the proxy statement related to the registrant’s 2012 Annual Meeting of Shareholders to be held on May 24, 2012, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2011, are incorporated by reference into Part III of this report.

 

 


 
 

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CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect our company and to take advantage of the “safe harbor” protection for forward-looking statements that applicable federal securities law affords.

From time to time, our management or persons acting on our behalf may make forward-looking statements to inform existing and potential security holders about our company. All statements other than statements of historical facts included in this report regarding our financial position, business strategy, plans and objectives of management for future operations, industry conditions, and indebtedness covenant compliance are forward-looking statements. When used in this report, forward-looking statements are generally accompanied by terms or phrases such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “target,” “plan,” “intend,” “seek,” “goal,” “will,” “should,” “may” or other words and similar expressions that convey the uncertainty of future events or outcomes. Items contemplating or making assumptions about, actual or potential future sales, market size, collaborations, and trends or operating results also constitute such forward-looking statements.

Forward-looking statements involve inherent risks and uncertainties, and important factors (many of which are beyond our company’s control) that could cause actual results to differ materially from those set forth in the forward-looking statements, including the following: general economic or industry conditions, nationally and/or in the communities in which our company conducts business, changes in the interest rate environment, legislation or regulatory requirements, conditions of the securities markets, our ability to raise capital, changes in accounting principles, policies or guidelines, financial or political instability, acts of war or terrorism, other economic, competitive, governmental, regulatory and technical factors affecting our company’s operations, products, services and prices.

We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. Accordingly, results actually achieved may differ materially from expected results in these statements. Forward-looking statements speak only as of the date they are made. You should consider carefully the statements in Item 1A. Risk Factors and other sections of this report, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements. We do not undertake, and specifically disclaim, any obligation to update any forward-looking statements to reflect events or circumstances occurring after the date of such statements.

Readers are urged not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. We assume no obligation to update any forward-looking statements in order to reflect any event or circumstance that may arise after the date of this report, other than as may be required by applicable law or regulation. Readers are urged to carefully review and consider the various disclosures made by us in our reports filed with the United States Securities and Exchange Commission (the “SEC”) which attempt to advise interested parties of the risks and factors that may affect our business, financial condition, results of operation and cash flows. If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those expected or projected.


 
 

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GLOSSARY OF OIL AND NATURAL GAS TERMS

The definitions set forth below apply to the indicated terms as used in this report. All volumes of natural gas referred to herein are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.

3-D seismic.  The method by which a three dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, exploitation and production.

Bbl.  One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

Boe.  Barrels of oil equivalent in which six Mcf of natural gas equals one Bbl of oil.

Boe/d.  Boe per day.

BTU.  British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Completion.  The installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Development well.  A well drilled within the proved areas of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well.  A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Exploratory well.  A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

Field.  An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells.  The total acres or wells, as the case may be, in which a working interest is owned.

Held by production.  A provision in an oil and gas lease that extends a company’s right to operate a lease as long as the property produces a minimum quantity of crude oil and natural gas.

Mcf.  One thousand cubic feet of natural gas.

Net acres or net wells.  The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

NYMEX.  The New York Mercantile Exchange, which is a designated contract market that facilitates and regulates the trading of crude oil and natural gas contracts subject to NYMEX rules and regulations.

Operator.  The individual or company responsible for the exploration, exploitation and production of an oil or natural gas well or lease.

PV10%.  The estimated future net revenue, discounted at a rate of 10% per annum, before income taxes and with no price or cost escalation or de-escalation in accordance with guidelines promulgated by the SEC.

Productive well.  A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Proved developed producing reserves (PDP).  Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and capable of production.


 
 

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Proved Developed Non-Producing reserves (PDNP).  Proved crude oil and natural gas reserves that are developed behind pipe, shut-in or that can be recovered through improved recovery only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells that were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells that will require additional completion work or future recompletion prior to the start of production.

Proved developed reserves.  Proved reserves that are expected to be recovered from existing wellbores, whether or not currently producing, without drilling additional wells. Production of such reserves may require a recompletion.

Proved reserves.  Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for estimation.

Proved undeveloped reserves (PUD).  Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Recompletion.  The completion for production of an existing wellbore in another formation from that in which the well has been previously completed.

Reservoir.  A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Spud.  Start (or restart) drilling a new well.

Standardized Measure.  The estimated future net revenue, discounted at a rate of 10% per annum, after income taxes and with no price or cost escalation, calculated in accordance with Accounting Standards Codification (“ASC”) 932, formerly Statement of Financial Accounting Standards No. 69 “Disclosures About Oil and Gas Producing Activities

Undeveloped acreage.  Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Working interest.  An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce crude oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.


 
 

TABLE OF CONTENTS

VOYAGER OIL & GAS, INC.

TABLE OF CONTENTS

 
  Page
Part I
        

Item 1.

Business

    1  

Item 1A.

Risk Factors

    10  

Item 1B.

Unresolved Staff Comments

    17  

Item 2.

Properties

    18  

Item 3.

Legal Proceedings

    22  

Item 4.

Mine Safety Disclosures

    22  
Part II
        

Item 5.

Market For Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

    23  

Item 6.

Selected Financial Data

    25  

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

    26  

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

    34  

Item 8.

Financial Statements and Supplementary Data

    34  

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

    34  

Item 9A.

Controls and Procedures

    35  

Item 9B.

Other Information

    37  
Part III
        

Item 10.

Directors, Executive Officers and Corporate Governance

    37  

Item 11.

Executive Compensation

    37  

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters

    37  

Item 13.

Certain Relationships and Related Transactions, and Director Independence

    37  

Item 14.

Principal Accountant Fees and Services

    37  
Part IV
        

Item 15.

Exhibits and Financial Statement Schedules

    37  
Signatures     41  
Index to Financial Statements     F-1  

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VOYAGER OIL & GAS, INC.
  
ANNUAL REPORT ON FORM 10-K
  
FOR FISCAL YEAR ENDED DECEMBER 31, 2011
  
PART I

Item 1.  Business

Overview

Voyager Oil & Gas, Inc., a Montana corporation (“Voyager,” the “Company,” “we,” “us,” or “our”), was formed for the purpose of providing capital investments for acreage acquisitions and non-operated 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 natural gas companies have operations.

On April 16, 2010, Voyager (formerly known as ante4, Inc., a Delaware corporation), 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 Acquisition Sub was 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 to the Company other than specific assets that were primarily related to ante4, Inc.’s prior unrelated entertainment and consumer products business, which were spun off to ante4, Inc.’s pre-merger stockholders. Effective May 31, 2011, the Company reincorporated from Delaware to Montana.

Our business currently focuses on oil and natural gas properties primarily located in Montana and North Dakota 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 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 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 leasehold into non-operated working interests in multiple wells primarily located in the Bakken and Three Forks oil shale. We believe our drilling participation, primarily on a heads-up, or pro rata, 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 and Three Forks oilfields. Existing lease terms vary significantly once an area initially becomes productive. We continue to see this approach met with success, as the delineation of the Williston Basin continues to evolve 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 natural 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, or pro rata, basis in substantially all, if not all, proposed wells. 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.

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Reserves

We recently completed our most current reservoir engineering calculations as of December 31, 2011. Based on the results of our December 31, 2011 reserve analysis, our proved reserves increased approximately 845% during 2011 primarily as a result of increased drilling activity involving our acreage and our acquisition of acreage subject to specific drilling projects or included in permitted or drilling spacing units. We incurred approximately $36.4 million of capital expenditures for drilling activities and $18.3 million for acreage acquisitions during the year ended December 31, 2011, which directly contributed to the increase in our proved developed reserves. No other expenditures materially contributed to the development of proved developed reserves in 2011. Our proved undeveloped reserves increased by approximately 777% during 2011 primarily as a result of drilling activity and our acquisitions of acreage. Based on our independent reservoir engineering firm’s calculations of proved undeveloped reserves as of December 31, 2010, 271,000 Boe in proved undeveloped reserves were converted to proved developed reserves during 2011. Approximately 2.1 million Boe were added to proved undeveloped reserves during 2011. We expect that our proved undeveloped reserves will continue to be converted to proved developed producing reserves as additional wells are drilled. We do not have any material amounts of proved undeveloped reserves that have remained undeveloped for five years or more.

SEC Pricing Proved Reserves(1)

           
  Gross Wells   Net Wells   Crude Oil
(Bbl)
  Natural Gas
(cubic feet)
  Total
(Boe)(2)
  PV10%
Value
PDP Properties     75       2.92       706,483       247,475       747,729     $ 26,608,309  
PDNP Properties     32       1.18       360,021       162,617       387,124       9,714,588  
PUD Properties     169       7.00       2,160,518       1,328,953       2,382,010       23,302,105  
Total Proved Properties:     276       11.10       3,227,022       1,739,045       3,516,863     $ 59,625,002  

(1) The SEC Pricing Proved Reserves table above values crude oil and natural gas reserve quantities and related discounted future net cash flows as of December 31, 2011 assuming average constant realized prices of $88.81 per Bbl of crude oil and $6.34 per Mcf of natural gas. The average natural gas price reflects the value of processed natural gas sales and natural gas liquids. Under SEC guidelines, these prices represent the average prices per Bbl of crude oil and per Mcf of natural gas at the beginning of each month in the 12-month period prior to the end of the reporting period, which averages are then adjusted to reflect applicable transportation and quality differentials. The values presented in the table above were calculated by Pressler Petroleum Consultants, Inc. and audited by Netherland Sewell & Associates, Inc. (“NSAI”).
(2) Barrels of oil equivalent (Boe) are computed based on a conversion ratio of one Boe for each barrel of crude oil and one Boe for every 6,000 cubic feet (i.e., 6 Mcf) of natural gas.

The table above assumes prices and costs discounted using an annual discount rate of 10% without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, or federal income taxes. The “PV10%” values of our proved reserves presented in the foregoing table may be considered a non-GAAP financial measure as defined by the SEC.

Uncertainties are inherent in estimating quantities of proved reserves, including many risk factors beyond our control. Reserve engineering is a subjective process of estimating subsurface accumulations of crude oil and natural gas that cannot be measured in an exact manner. As a result, estimates of proved reserves may vary depending upon the engineer valuing the reserves. Further, our actual realized price for our crude oil and natural gas is not likely to average the pricing parameters used to calculate our proved reserves. As such, the crude oil and natural gas quantities and the value of those commodities ultimately recovered from our properties will vary from reserve estimates.

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Controls Over Reserve Report Preparation, Technical Qualifications and Technologies Used

Preparation of our reserve report is outlined in our Sarbanes-Oxley Act Section 404 internal control procedures. Our procedures require that our reserve report be prepared by an independent reservoir engineering firm and then audited by a third-party registered independent engineering firm at the end of every year. The preparation and audit of our reservoir engineering report is based on information we provide to such engineer. We accumulate historical production data for our wells, calculate historical lease operating expenses and differentials, update working interests and net revenue interests, obtain updated authorizations for expenditure (“AFEs”) from our operations department and obtain geological and geophysical information from operators. This data is forwarded to our third-party engineering firm for review and calculation. Our Chief Executive Officer and Chief Financial Officer provide a final review of our reserve report and the assumptions relied upon in such report.

We have utilized Pressler Petroleum Consultants, Inc. (“Pressler”), an independent reservoir engineering firm, for the preparation of our December 31, 2011 reserve report. Pressler is a professional reservoir-evaluation consulting firm and has substantial experience calculating the reserves of various other companies with operations targeting the Bakken and Three Forks formations and several other resource plays of the Northern Rockies. As such, we believe Pressler has sufficient experience to appropriately determine our reserves. Pressler utilizes proprietary technology, systems and data to calculate our reserves commensurate with this experience.

The reserves estimates shown herein have been independently audited by Netherland, Sewell & Associates, Inc. (“NSAI”), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-002699. The lead technical person at NSAI primarily responsible for overseeing the audit of our reserves has 31 years of industry experience, and has been practicing consulting petroleum engineering at NSAI since 1989. He is a Registered Professional Engineer in the State of Texas, and has in excess of 20 years of practical experience in petroleum engineering studies and evaluation of reserves. NSAI meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. NSAI is proficient in applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

The proved reserves tables above summarize our estimated proved reserves as of December 31, 2011, based upon reports prepared by Pressler and audited by NSAI. Our audit procedures require NSAI to prepare their own estimates of proved reserves for fields comprising at least 80% of the aggregate net present value of our year-end proved reserves, discounted at 10% per annum.

In accordance with applicable requirements of the SEC, estimates of our net proved reserves and future net revenues are made using average prices at the beginning of each month in the 12-month period prior to the date of such reserve estimates and are held constant throughout the life of the properties (except to the extent a contract specifically provides for escalation).

The reserves set forth in the NSAI audit letter for the properties are estimated by performance methods or analogy. In general, reserves attributable to producing wells and/or reservoirs are estimated by performance methods such as decline curve analysis which utilizes extrapolations of historical production data. Reserves attributable to non-producing and undeveloped reserves included in our report are estimated by analogy.

To estimate economically recoverable crude oil and natural gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future of production rates. Under Rules 210.4-10(a)(22)(v) and (26) of Regulation S-X, proved reserves must be demonstrated to be economically producible based on existing economic conditions including the prices and costs at which those reserves can be economically produced from a reservoir, determined as of the effective date of the report. With respect to the property interests we own, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, production

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taxes, recompletion and development costs and product prices are based on the SEC regulations, geological maps, well logs, core analyses, and pressure measurements.

The reserve data set forth in the NSAI audit letter represent only estimates, and should not be construed as being exact quantities. The estimates of reserves may or may not be actually recovered, and if recovered, the actual revenues and costs could be more or less than the estimated amounts. Moreover, estimates of reserves may increase or decrease as a result of future operations.

Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values, including many factors beyond our control. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geologic interpretation and judgment. As a result, estimates of different engineers, including those used by us, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future development and exploration activities, prevailing crude oil and natural gas prices, operating costs and other factors. The revisions may be material. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. Our estimated net proved reserves, included in our SEC filings, have not been filed with or included in reports to any other federal agency. See Item 1A. Risk Factors — Estimates of oil and natural gas reserves that we make may be inaccurate and actual revenues may be lower than financial projections.

Additional discussion of our proved reserves is set forth under the heading Supplemental Oil and Gas Reserve Information (Unaudited) following our audited financial statements for the years ended December 31, 2011, 2010 and 2009.

Recent Developments

During 2011, we continued to focus our operations on acquiring leaseholds and drilling exploratory and developmental wells in the Williston Basin. We acquired an aggregate of 8,354 additional net mineral acres during 2011, at an average cost of $2,100 per net acre, primarily in Williams and McKenzie Counties of North Dakota and Richland County of Montana. During 2011, we participated in the completion of 76 gross (2.75 net) wells with a 100% success rate in the Bakken and Three Forks formations. As of December 31, 2011, we had an interest in 144 gross (5.95 net) wells in the Bakken and Three Forks formations. As of December 31, 2011, our principal assets included approximately 143,000 net acres across four prospects primarily located in Montana and North Dakota, as more fully described under the Item 2. Properties —  Leasehold Properties of this report.

In February 2012, we entered into a $150 million credit facility with Macquarie Bank Limited (“MBL”). Borrowings under this new credit facility will be used to further develop our undeveloped Williston Basin acreage into proven developed producing properties. A complete discussion of the credit facility is included in Item 7. Management’s Discuss and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Macquarie Credit Facility below.

Production Methods

We primarily engage in oil and natural gas exploration and production by participating on a heads-up basis alongside third-party interests in wells drilled and completed in spacing units that include our acreage. We typically depend on our drilling partners to propose, permit and initiate the drilling of wells. Prior to commencing drilling, our partners are required to provide all owners of oil, gas and mineral interests within the designated spacing unit the opportunity to participate in the drilling costs and revenues of the well to the extent of their pro-rata share of such interest within the spacing unit. In 2011, we participated in the drilling of all proposed wells that included any of our acreage. We will assess each drilling opportunity on a case-by-case basis going forward and participate in wells that we expect to meet our return thresholds based upon our estimates of ultimate recoverable oil and natural gas, expertise of the operator and completed well cost from each project, as well as other factors. At the present time we expect to participate pursuant to our working interest in substantially all, if not all, of the wells proposed to us.

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We do not manage our commodities marketing activities internally, but our operating partners generally market and sell oil and natural gas produced from wells in which we have an interest. Our operating partners coordinate the transportation of our oil production from our wells to appropriate pipelines pursuant to arrangements that such partners negotiate and maintain with various parties purchasing the production. We understand that our partners generally sell our production to a variety of purchasers at prevailing market prices under separately negotiated short-term contracts. The price at which production is sold generally is tied to the spot market for crude oil. Williston Basin Light Sweet Crude from the Bakken and Three Forks source rock is generally 41-42 API oil and is readily accepted into the pipeline infrastructure. Our average differential during 2011 was $7.38 per Bbl below New York Mercantile Exchange (“NYMEX”) pricing. This differential represents the imbedded transportation costs in moving the oil from wellhead to refinery.

Competition

The oil and natural gas industry is intensely competitive, and we compete with numerous other oil and natural gas exploration and production companies. Some of these companies have substantially greater resources than we have. Not only do they explore for and produce oil and natural gas, but many also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. Other companies may be able to pay more for exploratory prospects and productive oil and natural gas properties. These companies also may have more resources to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit.

Our larger or integrated competitors may have the resources to be better able to absorb the burden of existing, and any changes to, federal, state, and local laws and regulations more easily than we can, which could adversely affect our competitive position. Our ability to discover reserves and acquire additional properties in the future will be dependent upon our ability and resources to evaluate and select suitable properties and to consummate transactions in this highly competitive industry. In addition, we may be at a disadvantage in producing oil and natural gas properties and bidding for development prospects, because we have fewer financial and human resources than other companies in our industry. Should a larger and better financed company decide to directly compete with us, and be successful in its efforts, our business could be adversely affected. See Item 1A. Risk Factors — Competition in obtaining rights to explore and develop oil and natural gas reserves and to market our production may impair our business.

Marketing and Customers

The market for oil and natural gas that we produce depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

Our oil production is expected to be sold at prices tied to the spot oil markets. Our natural gas production is expected to be sold under short-term contracts and priced based on first of the month index prices or on daily spot market prices. We rely on our operating partners to market and sell our production. Our operating partners involve a variety of exploration and production companies, from large publicly-traded companies to small, privately-owned companies. See Item 1A. Risk Factors — As a non-operator, our development of successful operations relies extensively on third-parties who, if not successful, could have a material adverse affect on our results of operation and We may have difficulty distributing our production, which could harm our financial condition.

Principal Agreements Affecting Our Ordinary Business

We do not own any physical real estate, but, instead, our acreage is comprised of leasehold interests subject to the terms and provisions of lease agreements that provide us the right to drill and maintain wells in specific geographic areas. All lease arrangements that comprise our acreage positions are established using standard terms used in the oil and natural gas industry for many years. Some of our leases may be assigned by other parties that originally obtained the leasehold interest prior to us.

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In general, our lease agreements stipulate three to five-year terms. Bonuses and royalty rates are negotiated on a case-by-case basis consistent with industry standard pricing. Once a well is drilled and production established, the well is considered held by production, meaning the lease continues as long as hydrocarbons are being produced. Other locations within the drilling unit created for a well may also be drilled at any time with no time limit as long as the lease is held by production. Given the current pace of drilling in the Bakken play at this time, we do not believe lease expiration issues will materially affect our acreage positions.

Governmental Regulation and Environmental Matters

Our operations are subject to various rules, regulations and limitations impacting the oil and natural gas exploration and production industry as whole.

Regulation of Oil and Natural Gas Production

Our oil and natural gas exploration, production and related operations, when developed, are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies. For example, North Dakota, Montana and Colorado require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and natural gas. Such states may also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of such wells. Failure to comply with any such rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry will most likely increase our cost of doing business and may affect our profitability. Although we believe we are currently in substantial compliance with all applicable laws and regulations, because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Significant expenditures may be required to comply with governmental laws and regulations and may have a material adverse effect on our financial condition and results of operations. See Item 1A. Risk Factors — Environmental risks may adversely affect our business.

Environmental Matters

Our operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue. These laws and regulations may:

require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities;
limit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and
impose substantial liabilities for pollution resulting from our operations.

The permits required for our operations may be subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce their regulations, and violations are subject to fines, injunctions, or both. In management’s opinion, we are in substantial compliance with current applicable environmental laws and regulations, and have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on us, as well as the oil and natural gas industry in general.

The Comprehensive Environmental, Response, Compensation, and Liability Act (“CERCLA”) and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Federal

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Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the disposal of “solid waste” and “hazardous waste” and authorize the imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations may impose clean-up liability relating to petroleum and petroleum related products. In addition, although RCRA classifies certain oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements.

The Endangered Species Act (“ESA”) seeks to ensure that activities do not jeopardize endangered or threatened animal, fish and plant species, nor destroy or modify the critical habitat of such species. Under ESA, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize the species or its habitat. ESA provides for criminal penalties for willful violations of ESA. Other statutes that provide protection to animal and plant species and that may apply to our operations include, but are not necessarily limited to, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. Although we believe that our operations are in substantial compliance with such statutes, any change in these statutes or any reclassification of a species as endangered could subject us to significant expenses to modify our operations or could force us to discontinue certain operations altogether.

Hydraulic Fracturing

Concerns

The practice of hydraulic fracturing has recently become the subject of significant focus among some environmentalists, regulators and the general public. Concerns over potential hazards associated with the use of hydraulic fracturing and its impact on the environment have been raised at all levels, including federal, state and local. There have been reports associating hydraulic fracturing with groundwater contamination, improper waste disposal, poor air quality and earthquakes.

Hydraulic fracturing requires the use and disposal of significant quantities of water, and public concern has been growing over its possible effects on drinking water supplies, as well as the adequacy of supply. Recently, there have been reports alleging contamination of drinking water supplies by chemicals linked to the hydraulic fracturing process. For example, in December 2011, the EPA issued a draft report which indicated that studies of a hydraulic fracturing site in Pavillion, Wyoming, not a well in which we have an interest, reportedly found hydraulic fracturing fluids and chemicals associated with natural gas production in deep water monitoring wells. The findings are not conclusive, and the EPA intends to submit its draft report to an independent scientific review panel.

Hydraulic fracturing techniques have been used by the industry for many years, and, currently, more than 90% of all oil and natural gas wells drilled in the U.S. employ hydraulic fracturing. Our operating partners strive to adopt best practices and industry standards and comply with all regulatory requirements regarding well construction and operation. We believe our operating partners have established processes to help ensure that hydraulic fracturing does not pose a meaningful risk to water supplies.

Potential Rulemaking

Although hydraulic fracturing is regulated primarily at the state level, governments and agencies at all levels from federal to municipal are conducting studies and considering regulations. For example, in 2011, the U.S. Secretary of Energy formed the Shale Gas Production Subcommittee, a subcommittee of the Secretary of Energy Advisory Board. The Subcommittee was charged with making recommendations to improve the safety and environmental performance of hydraulic fracturing. On August 18, 2011, the Subcommittee issued its Ninety Day Report (the “Report”), which focused exclusively on the production of natural gas (and some liquid hydrocarbons) from shale formations with hydraulic fracturing stimulation in either vertical or horizontal wells. The Subcommittee identified four primary areas of concern including possible water pollution, air pollution, disruption of the community during production, and potential for adverse impact on communities and ecosystems. The Subcommittee also set forth a list of recommendations addressing, among other areas, communications, air quality, protection of water supply and quality, disclosure of fracturing fluid composition, reduction of diesel fuel use, continuous development of best practices, and federal sponsorship of research and development with respect to unconventional gas. The Subcommittee issued its Final Report in

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November 2011, which recommended implementation of the Subcommittee’s recommendations by federal and state agencies. We will continue to monitor the impact the Subcommittee’s recommendations, and any resulting rule-making activities evolving at federal and state levels, could have on our exploration and development activities.

The EPA’s Office of Research and Development has commenced a study of the potential environmental impact of hydraulic fracturing, with initial results of the study anticipated to be available by late 2012. In addition, the EPA’s recently-issued proposed rules subjecting oil and natural gas operations to regulation under the New Source Performance Standards will be applicable to newly drilled and fractured wells as well as existing wells that are refractured.

We continue to monitor new and proposed legislation and regulations to assess the potential impact on our business. Any additional federal, state or local restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could result in substantial incremental operating, capital and compliance costs as well as delay our ability to develop oil and natural gas reserves. For additional discussion, see Item 1A. Risk Factors — Federal or state hydraulic fracturing legislation could increase our costs or restrict our access to oil and natural gas reserves.

Climate Change

Significant studies and research have been devoted to climate change and global warming, and climate change has developed into a major political issue in the United States and globally. Certain research suggests that greenhouse gas emissions contribute to climate change and pose a threat to the environment. Recent scientific research and political debate has focused in part on carbon dioxide and methane incidental to oil and natural gas exploration and production. Many states and the federal government have enacted legislation directed at controlling greenhouse gas emissions, and future legislation and regulation could impose additional restrictions or requirements in connection with our drilling and production activities and favor use of alternative energy sources, which could increase operating costs and demand for oil products. As such, our business could be materially adversely affected by domestic and international legislation targeted at controlling climate change.

Employees

We currently have five full time employees. Our Chief Executive Officer, J.R. Reger, and our Chief Financial Officer, Mitchell Thompson, are responsible for all material policy-making decisions. None of our employees are subject to a collective bargaining agreement, and we consider our relations with our employees to be very good. If drilling production activities continue to increase, we may hire additional technical or administrative personnel as appropriate. We are using and will continue to use the services of independent consultants and contractors to perform various professional services, particularly in the area of land services and reservoir engineering. We believe that this use of third-party service providers enhances our ability to contain general and administrative expenses.

Office Locations

Our executive offices are located at 2718 Montana Avenue, Suite 220, Billings, MT 59101. The space consists of 2,981 square feet leased pursuant to a three-year office lease agreement that commenced on April 1, 2011. We believe the new office space will be sufficient to meet our needs for the foreseeable future.

Financial Information about Segments and Geographic Areas

We focus on four separate and distinct natural resource plays in the Rocky Mountain Region of the United States. We have segregated each area for the developed and undeveloped acreage and productive and exploratory wells tables in Item 2. Properties below. All of our oil and natural gas properties and related operations are located onshore in the United States and management has determined that we have one reportable segment.

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Available Information — Reports to Security Holders

Our website address is www.voyageroil.com. Available on this website under “Investor Relations,” free of charge, are our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, Section 16 reports for officers and directors, and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC. These filings are also available to the public at the SEC’s Public Reference Room at 100 F Street, NE, Room 1580, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Electronic filings with the SEC are also available on the SEC website at www.sec.gov.

We have also posted to our website our Audit Committee Charter, Compensation Committee Charter, Nominating Committee Charter and our Code of Business Conduct and Ethics, in addition to all pertinent contact information.

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Item 1A.  Risk Factors

You should carefully consider the risks, uncertainties and other factors described below. Any of the factors could materially and adversely affect our business, financial condition, operating results and prospects and could negatively impact the market price of our common stock. Also, you should be aware that the risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties, of which we are not yet aware, or that we currently consider to be immaterial may also impair our business operations. You should also refer to the other information contained in and incorporated by reference into this report.

Risks Related To Our Business

We have a limited operating history, and may not be successful in sustaining profitable business operations.

We have a limited operating history. The business of acquiring, exploring for, developing and producing hydrocarbon reserves is inherently risky. We have a limited operating history for you to consider in evaluating our business and prospects. Our operations are therefore subject to all of the risks inherent in acquiring, exploring for, developing and producing hydrocarbon reserves, particularly in light of our limited experience in undertaking such activities. We may never overcome these obstacles.

Our business is speculative and dependent upon the implementation of our business plan and our ability to enter into agreements with third parties for the rights to exploit potential oil and natural gas reserves on terms that will be commercially viable for us.

Our lack of diversification will increase the risk of an investment in us and our financial condition and results of operations may deteriorate if we fail to diversify.

Our business is focused on a limited number of properties in Montana and North Dakota. 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, which may be outside Montana and North Dakota. We have committed and expect to continue to commit funds to joint ventures with Hancock Enterprises and other parties to acquire and develop acreage. Our required capital commitment may grow if the opportunity presents itself and depends upon the results of initial testing and development activities. Larger companies have the ability to manage their risk by diversification. However, we will lack diversification in terms of both the nature and geographic scope of our business. As a result, we will likely be impacted more acutely by factors affecting our industry or the regions in which we operate than if our business were more diversified enhancing our risk profile. If we cannot diversify our operations, our financial condition and results of operations could deteriorate.

We have a history of losses which may continue and negatively impact our ability to achieve our business objectives.

We incurred net losses of $(1,345,054), $(4,268,569) and $(2,277,192) for the fiscal years ended December 31, 2011, 2010 and 2009, respectively. We cannot assure you that we can achieve or sustain profitability on a quarterly or annual basis in the future. Our operations are subject to the risks and competition inherent in the oil and natural gas industry. We cannot assure you that future operations will be profitable. Revenues and profits, if any, will depend upon various factors, including whether we will be able to expand our revenues. We may not achieve our business objectives and the failure to achieve such goals would have an adverse impact on our business, financial condition and result of operations.

Strategic relationships upon which we may rely are subject to change, which may diminish our ability to conduct our operations.

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 depend on developing and maintaining close working relationships with industry participants, our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment. These realities are subject to change and may impair our ability to grow.

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To further develop our business, we will endeavor to use the business relationships of our management to enter into strategic relationships, which may take the form of joint ventures with other private parties and contractual arrangements with other oil and natural gas companies, including those that supply equipment and other resources that we will use in our business. Our ability to successfully operate joint ventures depends on a variety of factors, many of which will be entirely outside our control. We may not be able to establish this and other strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to undertake in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.

As a non-operator, our development of successful operations relies extensively on third-parties who, if not successful, could have a material adverse affect on our results of operation.

We have only participated in wells operated by third parties. Our current ability to develop successful business operations depends on the success of our consultants and drilling partners. As a result, we do not control the timing or success of the development, exploitation, production and exploration activities relating to our leasehold interests. If our consultants and drilling partners are not successful in such activities relating to our leasehold interests or are unable or unwilling to perform, our financial condition and results of operation would be materially adversely affected.

Competition in obtaining rights to explore and develop oil and natural gas reserves and to market our production may impair our business.

The oil and natural gas industry is highly competitive. Other oil and natural gas companies may seek to acquire oil and natural gas leases and other properties and services we intend to target with our investments. This competition is increasingly intense as prices of oil and natural gas on the commodities markets have risen in recent years. Additionally, other companies engaged in our line of business may compete with us from time to time in obtaining capital from investors or in funding joint ventures with our prospective partners. Competitors include a variety of potential investors and larger companies, which, in particular, may have access to greater resources, may be more successful in the recruitment and retention of qualified employees and may conduct their own refining and petroleum marketing operations, which may give them a competitive advantage. In addition, actual or potential competitors may be strengthened through the acquisition of additional assets and interests. If we are unable to compete effectively or adequately respond to competitive pressures, this inability may materially adversely affect our results of operation and financial condition.

We may not be able to effectively manage our growth, which may harm our profitability.

Our strategy envisions expanding our business. If we fail to effectively manage our growth, our financial results could be adversely affected. Growth may place a strain on our management systems and resources. We must continue to refine and expand our business development capabilities, our systems and processes and our access to financing sources. As we grow, we must continue to hire, train, supervise and manage new employees. We may not be able to:

meet our capital needs;
expand our systems effectively or efficiently or in a timely manner;
allocate our human resources optimally;
identify and hire qualified employees or retain valued employees; or
incorporate effectively the components of any business that we may acquire in our effort to achieve growth.

If we are unable to manage our growth, our operations and our financial results could be adversely affected by inefficiency, which could diminish our profitability.

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Our business may suffer if we do not attract and retain talented personnel.

Our success will depend in large measure on the abilities, expertise, judgment, discretion, integrity and good faith of our management and other personnel in conducting our business. We have a small management team, and the loss of key individuals or the inability to attract suitably qualified staff could materially adversely impact our business.

Our success depends on the ability of our management, employees and exploration partners to interpret market and geological data correctly and to interpret and respond to economic market and other conditions in order to locate and adopt appropriate investment opportunities, monitor such investments, and ultimately, if required, to successfully divest such investments. We currently do not have an employment agreement in effect with either J.R. Reger, our chief executive officer and a director, or Mitchell R. Thompson, our chief financial officer and a director, and we can provide no assurances that we will execute employment agreement with Mr. Reger or Mr. Thompson. Therefore, these key personnel do not have any contractual obligation to fulfill such capacities as officers and directors for any specified period of time, and they may not continue their association or employment with us, and replacement personnel with comparable skills may not be found. If we are unable to attract and retain key personnel, our business will be adversely affected.

Lower oil and natural gas prices may cause us to record ceiling test write-downs.

We use the full cost method of accounting to account for our oil and natural gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized costs of oil and natural gas properties may not exceed a “full cost ceiling” which is based upon the present value of estimated future net cash flows from proved reserves, including the effect of hedges in place, discounted at 10%, plus the lower of cost or fair market value of unproved properties. If at the end of any fiscal period we determine that the net capitalized costs of oil and natural gas properties exceed the full cost ceiling, we must charge the amount of the excess to earnings in the period then ended. This is called a “ceiling test write-down.” This charge does not impact cash flow from operating activities, but does reduce our net income and stockholders’ equity. While we did not recognize any ceiling test write-downs for the year ended December 31, 2011, we may recognize write-downs in the future if commodity prices continue to decline or if we experience substantial downward adjustments to our estimated proved reserves.

Our hedging activities could result in financial losses or could reduce our net income or increase our net loss, which may adversely affect our business.

In order to manage our exposure to price risks in the marketing of our oil and natural gas production, we may enter into oil and natural gas price hedging arrangements with respect to a portion of expected production that we fund.

Such transactions may limit our potential gains and increase our potential losses if oil and natural gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which:

production is less than expected;
there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement; or
the counterparties to our hedging agreements fail to perform under the contracts.

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Risks Related To Our Industry

Exploration for oil and natural gas is risky and may not be commercially successful, and the advanced technologies we and our operating partners use cannot eliminate exploration risk, which could impair our ability to generate revenues from our operations.

Our future success will depend on the success of our exploration program. Oil and natural gas exploration involves a high degree of risk. These risks are more acute in the early stages of exploration. Our ability to generate a return on our investments, revenues and our resulting financial performance are significantly affected by the prices we receive for oil and natural gas produced from wells on our acreage. Especially in recent years, the prices at which oil and natural gas trade in the open market have experienced significant volatility, and will likely continue to fluctuate in the foreseeable future due to a variety of influences including, but not limited to, the following:

domestic and foreign demand for oil and natural gas by both refineries and end users;
the introduction of alternative forms of fuel to replace or compete with oil and natural gas;
domestic and foreign reserves and supply of oil and natural gas;
competitive measures implemented by our competitors and domestic and foreign governmental bodies;
weather conditions; and
domestic and foreign economic volatility and stability.

A significant decrease in oil and natural gas prices could also adversely impact our ability to raise additional capital to pursue future drilling activities.

Our expenditures on exploration may not result in new discoveries of oil or natural gas in commercially viable quantities. It is difficult to project the costs of implementing an exploratory drilling program due to the inherent uncertainties of drilling in unknown formations, the costs associated with encountering various drilling conditions, such as over-pressured zones and tools lost in the hole, and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof.

Even when used and properly interpreted, three-dimensional (3-D) seismic data and visualization techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. In addition, the use of 3-D seismic data becomes less reliable when used at increasing depths. We could incur losses as a result of expenditures on unsuccessful wells. If exploration costs exceed estimates, or if exploration efforts do not produce results which meet expectations, the exploration efforts may not be commercially successful, which could adversely impact our ability to generate revenues from our operations.

We may not be able to develop oil and natural gas reserves on an economically viable basis, and our reserves and production may decline as a result.

If, together with our partners, we succeed in discovering oil and/or natural gas reserves, these reserves may not be capable of the production levels we project or in sufficient quantities to be commercially viable. On a long-term basis, our viability depends on our ability to find or acquire, develop and commercially produce additional oil and natural gas reserves. Without the addition of reserves through acquisition, exploration or development activities, our reserves and production will decline over time as reserves are produced. Our future reserves will depend not only on our ability to develop then-existing properties, but also on our operating partners’ ability to identify and acquire additional suitable producing properties or prospects, to find markets for the oil and natural gas we may develop and to effectively distribute our production.

Future oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from

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successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-downs of connected wells resulting from extreme weather conditions, problems in storage and distribution and adverse geological and mechanical conditions. We will not be able to eliminate these conditions completely in any case. Therefore, these conditions could diminish our revenue and cash flow levels and result in the impairment of our oil and natural gas interests.

Estimates of oil and natural gas reserves that we make may be inaccurate and actual revenues may be lower than financial projections.

We make estimates of oil and natural gas reserves that we target, upon which we base financial projections. We make these reserve estimates using various assumptions, including assumptions as to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Some of these assumptions are inherently subjective, and the accuracy of the reserve estimates relies in part on the ability of our management team, engineers and other advisors to make accurate assumptions. Economic factors beyond our control, such as interest rates, will also impact the value of our reserves. The process of estimating oil and natural gas reserves is complex, and will require us to use significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each property. As a result, the reserve estimates will be inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from estimates. If actual production results vary substantially from reserve estimates, this could materially reduce revenues and result in the impairment of our oil and natural gas interests.

Prices and markets for oil and natural gas are unpredictable and tend to fluctuate significantly, which could reduce profitability, growth and the value of our business.

Oil and natural gas are commodities whose prices are determined based on world demand, supply and other factors, all of which are beyond our control. World prices for oil and natural gas have fluctuated widely in recent years, and we expect that prices will fluctuate in the future. Price fluctuations will have a significant impact upon our revenue, the return from our reserves and on our financial condition generally. Price fluctuations for oil and natural gas commodities may also impact the investment market for companies engaged in the oil and natural gas industry. Prices may not remain at current levels. Decreases in the prices of oil and natural gas may have a material adverse effect on our financial condition, the future results of our operations and quantities of reserves recoverable on an economic basis.

Penalties we may incur could impair our business.

Failure to comply with government regulations could subject us to civil and criminal penalties, could require us to forfeit property rights, and may affect the value of our assets. We may also be required to take corrective actions, such as installing additional equipment or taking other actions, each of which could require us to make substantial capital expenditures. We could also be required to indemnify our employees in connection with any expenses or liabilities that they may incur individually in connection with regulatory action against them. As a result, our future business prospects could deteriorate due to regulatory constraints, and our profitability could be impaired by our obligation to provide such indemnification to our employees.

Our operating partners may have difficulty distributing our production, which could harm our financial condition.

In order to sell the oil and natural gas that we are able to produce, the operators of our wells may have to make arrangements for storage and distribution to the market. We will rely on local infrastructure and the availability of transportation for storage and shipment of our products, but infrastructure development and storage and transportation facilities may be insufficient for our needs at commercially acceptable terms in the localities in which we operate. This situation could be particularly problematic to the extent that our operations are conducted in remote areas that are difficult to access, such as areas that are distant from shipping and/or pipeline facilities. These factors may affect our ability to explore and develop properties and to store and transport our oil and natural gas production and may increase our expenses.

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Furthermore, weather conditions or natural disasters, actions by companies doing business in one or more of the areas in which we will operate, or labor disputes may impair the distribution of oil and/or natural gas and in turn diminish our financial condition or ability to maintain our operations.

We may be unable to obtain additional capital that we will require to implement our business plan, which could restrict our ability to grow.

We expect that our cash position, our new credit facility and revenues from crude oil and natural gas sales will be sufficient to fund our 2012 drilling program. However, those funds may not be sufficient to fund both our continuing operations and our planned growth. We may require additional capital to continue to grow our business via acquisitions and to further expand our exploration and development programs. We may be unable to obtain additional capital if and when required.

Future acquisitions and future exploration, development, production and marketing activities, as well as our administrative requirements (such as salaries, insurance expenses and general overhead expenses, as well as legal compliance costs and accounting expenses) will require a substantial amount of capital and cash flow.

We may pursue sources of additional capital through various financing transactions or arrangements, including joint venturing of projects, debt financing, equity financing or other means. We may not be successful in identifying suitable financing transactions in the time period required or at all, and we may not obtain the capital we require by other means. If we do not succeed in raising additional capital, our resources may not be sufficient to fund our planned expansion of operations in the future.

Any additional capital raised through the sale of equity may dilute the ownership percentage of our shareholders. Raising any such capital could also result in a decrease in the fair market value of our equity securities because our assets would be owned by a larger pool of outstanding equity. The terms of securities we issue in future capital transactions may be more favorable to our new investors, and may include preferences, superior voting rights and the issuance of other derivative securities. In addition, we have granted and will continue to grant equity incentive awards under our equity incentive plans, which may have a further dilutive effect.

Our ability to obtain financing, if and when necessary, may be impaired by such factors as the capital markets (both generally and in the crude oil and natural gas industry in particular), our limited operating history, the location of our crude oil and natural gas properties and prices of crude oil and natural gas on the commodities markets (which will impact the amount of asset-based financing available to us) and the departure of key employees. Further, if crude oil or natural gas prices on the commodities markets decline, our revenues will likely decrease and such decreased revenues may increase our requirements for capital. If the amount of capital we are able to raise from financing activities, together with our revenues from operations, is not sufficient to satisfy our capital needs (even to the extent that we reduce our operations), we may be required to cease our operations, divest our assets at unattractive prices or obtain financing on unattractive terms.

We may incur substantial costs in pursuing future capital financing, including investment banking fees, legal fees, accounting fees, securities law compliance fees, printing and distribution expenses and other costs. We may also be required to recognize non-cash expenses in connection with certain securities we may issue, which may adversely impact our financial condition.

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Drilling for and producing crude oil and natural gas are high risk activities with many uncertainties.

Our future success will depend on the success of our development, exploitation, production and exploration activities. Our crude oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable crude oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling, including the following:

delays imposed by or resulting from compliance with regulatory requirements;
pressure or irregularities in geological formations;
shortages of or delays in obtaining qualified personnel or equipment, including drilling rigs, CO2 and water;
equipment failures or accidents; and
adverse weather conditions, such as freezing temperatures and storms.

The presence of one or a combination of these factors at our properties could adversely affect our business, financial condition or results of operations.

Environmental risks may adversely affect our business.

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, state and municipal laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and natural gas operations. Legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner in which we expect may result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy such discharge. The application of environmental laws to our business may cause us to curtail our production or increase the costs of our production, development or exploration activities.

Federal or state hydraulic fracturing legislation could increase our costs or restrict our access to oil and natural gas reserves.

Hydraulic fracturing using fluids other than diesel is currently exempt from regulation under the federal Safe Drinking Water Act, but opponents of hydraulic fracturing have called for further study of the technique’s environmental effects and, in some cases, a moratorium on the use of the technique. Several proposals have been submitted to Congress that, if implemented, would subject all hydraulic fracturing to regulation under the Safe Drinking Water Act. Further, the EPA’s Office of Research and Development (ORD) is conducting a scientific study to investigate the possible relationships between hydraulic fracturing and drinking water. The ORD expects to have the initial study results available by late 2012. Several states are considering legislation to regulate hydraulic fracturing practices, including restrictions on its use in environmentally sensitive areas. Some municipalities have significantly limited or prohibited drilling activities, or are considering doing so.

Although it is not possible at this time to predict the final outcome of the ORD’s study or the requirements of any additional federal or state legislation or regulation regarding hydraulic fracturing, any new federal or state, or local restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business, such as the Bakken and Three Forks areas, could significantly increase our operating,

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capital and compliance costs as well as delay or halt our ability to develop oil and natural gas reserves. See Item 1. Business — Governmental Regulation and Environmental Matters — Hydraulic Fracturing.

Challenges to our properties may impact our financial condition.

Title to oil and natural gas interests is often not capable of conclusive determination without incurring substantial expense. Title defects may exist in many of our oil and natural gas interests. In addition, we may be unable to obtain adequate insurance for title defects, on a commercially reasonable basis or at all. If title defects do exist, it is possible that we may lose all or a portion of our right, title and interests in and to the properties to which the title defects relate. If our property rights are reduced, our ability to conduct our exploration, development and production activities may be impaired.

We will rely on technology to conduct our business and our technology could become ineffective or obsolete.

We rely on technology, including geographic and seismic analysis techniques and economic models, to develop our reserve estimates and to guide our exploration, development and production activities. We will be required to continually enhance and update our technology to maintain our efficacy and to avoid obsolescence. The costs of doing so may be substantial, and may be higher than the costs that we anticipated for technology maintenance and development. If we are unable to maintain the efficacy of our technology, our ability to manage our business and to compete may be impaired. Further, even if we are able to maintain technical effectiveness, our technology may not be the most efficient means of reaching our objectives, in which case we may incur higher operating costs than we would were our technology more efficient.

Our acreage price assumptions may not be accurate.

We use estimates for acreage prices. These numbers may not accurately represent the market. Actual acreage prices may be higher or lower by significant amounts. The market for acreage has traditionally been illiquid and non-transparent as well as volatile.

Risks Related to Owning Voyager Common Stock

Our ability to issue undesignated preferred stock and the existence of anti-takeover provisions may depress the value of our common stock.

Our authorized capital includes 20 million shares of undesignated preferred stock. Our board of directors has the power to issue any or all of the shares of preferred stock, including the authority to establish one or more series and to fix the powers, preferences, rights and limitations of such class or series, without seeking shareholder approval. Further, as a Montana corporation, we are subject to provisions of the Montana General Corporation Law regarding “business combinations.” Our board of directors may, in the future, consider adopting additional anti-takeover measures. The authority of our board to issue undesignated stock and the anti-takeover provisions of Montana law, as well as any future anti-takeover measures adopted by us, may, in certain circumstances, delay, deter or prevent takeover attempts and other changes in control that are not approved by our board of directors. As a result, our shareholders may lose opportunities to dispose of their shares at favorable prices generally available in takeover attempts or that may be available under a merger proposal and the market price, voting and other rights of the holders of common stock may also be affected.

We do not expect to pay dividends in the foreseeable future.

We do not intend to declare dividends for the foreseeable future, as we anticipate that we will reinvest any future earnings in the development and growth of our business. Therefore, our shareholders will not receive any funds unless they sell their common stock or warrants, and our shareholders may be unable to sell their shares and warrants on favorable terms or at all.

Item 1B.  Unresolved Staff Comments

None.

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Item 2.  Properties

Leasehold Properties

As of December 31, 2011, we control approximately 143,000 net acres in the following five primary prospect areas:

32,000 net acres targeting the Bakken and Three Forks formations in North Dakota and Montana;
2,400 net acres targeting the Niobrara formation in Colorado and Wyoming;
800 net acres targeting a Red River prospect in Montana;
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; and
33,500 net acres in a joint venture targeting the Heath shale formation in Musselshell, Petroleum, Garfield and Fergus Counties of Montana.

Williston Basin — Bakken and Three Forks

We currently control approximately 32,000 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. We have participated in 144 gross (5.95 net) Bakken and Three Forks oil wells, including 82 gross (2.99 net) wells that are producing as of December 31, 2011. The remaining 62 gross (2.96 net) wells are in the process of being drilled or completed. We continue to lease prospective acreage targeting non-operated working interests in delineated areas of high quality production.

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 during the year ended December 31, 2011.

D-J 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. 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 in 2012.

Major Joint Venture — Tiger Ridge Natural Gas

We control 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 Oil Shale

We own approximately 33,500 net acres located in central Montana as part of a joint venture targeting the Heath oil shale. 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.

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Developed and Undeveloped Acreage

As of December 31, 2011, our principal assets included approximately 143,467 net acres located in the northern Rocky Mountain region of the United States. Net acreage represents our percentage ownership of gross acreage. The following table summarizes our estimated gross and net developed and undeveloped acreage by resource play at December 31, 2011.

           
  Developed Acreage   Undeveloped Acreage   Total Acreage
     Gross   Net   Gross   Net   Gross   Net
Bakken and Three Forks     21,594       3,465       116,455       28,503       138,049       31,968  
Red River                 800       800       800       800  
Heath JV                 85,811       33,562       85,811       33,562  
Tiger Ridge JV                 96,460       74,706       96,460       74,706  
Niobrara     3,520       1,760       2,961       671       6,481       2,431  
Total:     25,114       5,225       302,487       138,242       327,601       143,467  

The following table summarizes our estimated gross and net developed and undeveloped acreage by state at December 31, 2011.

           
  Developed Acreage   Undeveloped Acreage   Total Acreage
     Gross   Net   Gross   Net   Gross   Net
North Dakota     18,599       2,278       61,466       13,050       80,065       15,328  
Montana     2,995       1,187       238,060       124,521       241,055       125,708  
Colorado     3,520       1,760       1,282       192       4,802       1,952  
Wyoming                 1,679       479       1,679       479  
Total:     25,114       5,225       302,487       138,242       327,601       143,467  

The following table summarized our estimated gross and net developed and undeveloped acreage by county across the Bakken and Three Forks prospect at December 31, 2011.

           
  Developed Acreage   Undeveloped Acreage   Total Acreage
     Gross   Net   Gross   Net   Gross   Net
Burke County, ND     120       7       480       21       600       27  
Divide County, ND                 320       184       320       184  
Dunn County, ND     220       2       715       74       935       76  
McKenzie County, ND     3,036       502       24,421       4,686       27,457       5,188  
McLean County, ND                 864       164       864       164  
Mountrail County, ND     4,676       399       6,130       798       10,805       1,197  
Stark County, ND     160       15       800       120       960       135  
Williams County, ND     10,387       1,353       27,354       7,003       37,742       8,357  
Richland County, MT     1,837       653       52,851       14,474       54,688       15,127  
Roosevelt County, MT     1,158       534       1,864       323       3,022       857  
Sheridan County, MT                 656       656       656       656  
Total:     21,594       3,465       116,455       28,503       138,049       31,968  

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Undeveloped Acreage

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2011 that will expire over the next three years and thereafter by project area unless production is established within the spacing units covering the acreage prior to the expiration dates:

               
  Expiring 2012   Expiring 2013   Expiring 2014   Expiring 2015
and thereafter
     Gross   Net   Gross   Net   Gross   Net   Gross   Net
North Dakota Bakken and Three Forks     14,285       1,430       10,657       3,973       29,114       6,793       7,410       854  
Montana Bakken and Three Forks     2,528       490       12,724       4,275       35,496       8,932       4,241       1,756  
Montana Red River                             640       640       160       160  
Montana Heath JV                 34,260       17,203       51,551       16,359              
Montana Tiger Ridge JV     6,165       1,908       11,653       4,741       37,345       28,165       41,297       39,892  
Colorado Niobrara     320       96       962       96                          
Wyoming Niobrara     323       97       556       167       640       192       160       23  
Total     23,621       4,021       70,812       30,455       154,786       61,081       53,268       42,685  

The table above includes approximately 3,353 net acres in North Dakota and Montana targeting the Bakken and Three Forks formations currently in the process of being drilled or completed as of December 31, 2011. We anticipate these wells will be productive resulting in such acres being held by production. Additionally, many of our leases include options to extend the lease from one to five additional years beyond the initial lease term. Of the 28,503 undeveloped net acres in North Dakota and Montana targeting the Bakken and Three Forks formations, approximately 8,051 net acres carry an option to extend the lease.

During 2011, leases expired in Weld County, Colorado and Laramie County, Wyoming covering approximately 14,600 net acres. The cost associated with the abandoned acreage totaling $6,983,125 is included in the full cost pool and subject to the depletion base. Given the results of the exploratory wells drilled in 2010 and 2011 targeting the Niobrara formation with Slawson Exploration Company, Inc. and our core focus on the Bakken and Three Forks formations in key areas of Montana and North Dakota, we determined it was not in our best interest to re-lease any expiring acreage in Colorado or Wyoming targeting the Niobrara formation.

Unproved Properties

We historically have acquired our properties by purchasing individual or small groups of leases directly from mineral owners or from landmen or lease brokers, which leases historically have not been subject to specified drilling projects, and by purchasing lease packages in identified project areas controlled by specific operators. We generally participate in drilling activities on a heads-up, or pro rata, basis based on our ownership percentage by electing whether to participate in each well on a well-by-well basis at the time wells are proposed for drilling.

We believe that the majority of our unproved properties will become subject to depletion within the next five years by proving up reserves relating to its acreage through exploration and development activities, by impairing the acreage that will expire before we can explore or develop it further, or by determining that further exploration and development activity will not occur. The timing by which all other properties will become subject to depletion will depend upon the timing of future drilling activities and delineation of our reserves.

Production History

The following table presents information about our produced oil and natural gas volumes year ended December 31, 2011 and 2010. As of December 31, 2011, we sold oil and natural gas from a total of 87 gross wells, 82 of which are located within the Williston Basin and five are located with the Denver-Julesberg Basin. All data presented below is derived from accrued revenue and production volumes for the relevant period indicated.

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  Year Ended
December 31,
     2011   2010
Net Production:
                 
Oil (Bbl)     95,517       13,198  
Natural Gas (Mcf)     14,962       3,489  
Barrel of Oil Equivalent (Boe)     98,011       13,780  
Average Sales Prices:
                 
Oil (per Bbl)   $ 86.86     $ 70.26  
Natural Gas (per Mcf)   $ 8.66     $ 4.44  
Average Production Costs:
                 
Oil (per Bbl)   $ 7.51     $ 2.05  
Natural Gas (per Mcf)   $ 0.65     $ 0.04  
Barrel of Oil Equivalent (Boe)   $ 7.42     $ 1.98  

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 during 2011 and 2010.

   
  Year Ended December 31,
     2011   2010
Depletion of oil and natural gas properties   $ 3,546,466     $ 547,844  

Productive Wells

The following table summarizes gross and net productive oil wells by state at December 31, 2011 and 2010. A net well represents our fractional working ownership interest of a gross well. The following table also does not include 62 gross (2.96 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 December 31, 2011.

       
  December 31,
     2011   2010
     Gross   Net   Gross   Net
North Dakota Bakken and Three Forks       75       2.32         6       0.24  
Montana Bakken and Three Forks       7       0.67         —        
Colorado Niobrara       5       2.50         1       0.50  
Total:     87       5.49         7       0.74  

Exploratory Wells

We control approximately 74,000 net acres in and around the Tiger Ridge gas field in Montana. 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 the initial wells. These wells are currently awaiting pipeline hook-up and the costs incurred are included in unevaluated oil and natural gas properties on our balance sheets as of December 31, 2011 and 2010.

In 2010, we participated in the drilling of the Bushwhacker #1-24H well, which was the first well drilled in our Niobrara development program. The well was abandoned after experiencing geosteering issues during the drilling process and completion was suspended indefinitely. The dry hole costs associated with this well were $1,521,853 and were included in the full cost pool and subject to the depletion base. Of the 150 gross wells that we have participated in, this has been the only well that we have participated in that was a dry hole.

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As of December 31, 2011, we were participating in 62 gross (2.96 net) Bakken and Three Forks wells in the process of being drilled or completed. The wells in process that are not considered PDNP properties are included as exploratory wells in the table below.

           
  December 31,
     2011   2010   2009
     Gross   Net   Gross   Net   Gross   Net
North Dakota Bakken and Three Forks       30       1.78         —         —         —         —  
Montana Tiger Ridge JV – Natural Gas       6       4.20         —         —         —         —  
Colorado Niobrara       —               2       1.00         —         —  
Total:       36       5.98         2       1.00         —         —  

Research and Development

We do not anticipate performing any significant product research and development under our current plan of operations.

Reserves

We completed our most recent reservoir engineering calculation as of December 31, 2011. Tables summarizing the results of our most recent reserve report are included in Item 1. Business — Reserves. A complete discussion of our proved reserves is set forth in Supplemental Oil and Gas Reserve Information (Unaudited) following our audited financial statements for the years ended December 31, 2011, 2010 and 2009.

Delivery Commitments

We do not currently have any delivery commitments for products obtained from our wells.

Item 3.  Legal Proceedings

On August 23, 2010, plaintiff Donald Rensch filed a three count shareholder derivative action in the United States District Court for the District of Minnesota against nominal defendant Northern Oil & Gas, Inc. (“Northern”), certain officers and directors of Northern, James Randall Reger, Weldon Gilbertson and J.R. Reger (all current or former officers of Voyager), and Voyager. Count I of the complaint alleged breach of fiduciary duty of loyalty and usurpation of corporate opportunities by certain of Northern’s officers and directors. Count II asserts allegations against James Randall Reger, Weldon Gilbertson, and J.R. Reger of aiding and abetting officers of Northern in breaching their fiduciary duties and usurpation of Northern’s corporate opportunities in connection with the formation, capitalization, and operation of Plains Energy, which operations and activities largely became those of Voyager’s. Count III asserts a claim against Voyager for tortious interference with a prospective business relationship. The plaintiff seeks injunctive relief and damages, including imposing on Voyager and all of its assets a constructive trust for the benefit of Northern. We filed a motion to dismiss the lawsuit in the United States District Court for the District of Minnesota on September 23, 2010. A hearing on our motion was heard on February 23, 2011, and the Court granted the motion to dismiss without prejudice on June 20, 2011. The plaintiff filed an amended complaint on July 20, 2011. The Amended Complaint has dropped claims against James Randall Reger, Weldon Gilbertson, and James Russell Reger. Voyager has again filed a motion to dismiss the lawsuit for failure to state a claim. A hearing on this motion was held in the United States District Court for the District of Minnesota on December 20, 2011. The parties are awaiting the Court’s decision on this motion.

Item 4.  Mine Safety Disclosures

Not applicable.

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PART II

Item 5.  Market For Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

Market Information

Voyager’s common stock is currently listed for trading on the NYSE Amex under the symbol “VOG.” From December 29, 2009 until March 1, 2011, Voyager’s common stock was listed for trading on the over-the-counter bulletin board under the symbol “VYOG.OB.” Prior to December 29, 2009, Voyager’s common stock was traded on the Nasdaq Global Market under the symbol “WPTE.”

The high and low sales prices per share of Voyager’s common stock for each quarterly period within the two most recent fiscal years are indicated below, as reported on the NYSE Amex, the Nasdaq Global Market and over-the-counter bulletin board, as appropriate:

       
  First Quarter   Second Quarter   Third Quarter   Fourth Quarter
Year Ended December 31, 2011
                                   
High   $ 7.54     $ 4.65     $ 3.95     $ 3.03  
Low   $ 3.89     $ 2.27     $ 2.02     $ 1.57  
Year Ended December 31, 2010
                                   
High   $ 1.22     $ 4.28     $ 4.40     $ 5.40  
Low   $ 0.90     $ 1.18     $ 3.35     $ 3.07  

Holders

As of March 13, 2012, we had 57,848,431 shares of our common stock outstanding, held by approximately 1,800 shareholders of record. The number of record holders does not necessarily bear any relationship to the number of beneficial owners of our common stock.

Voyager Dividend Policy

We have never paid a cash dividend, and the current policy of our board of directors is to retain any earnings to provide for our growth. The payment of cash dividends in the future, if any, will be at the discretion of our board of directors and will depend on such factors as earnings levels, capital requirements, our overall financial condition and any other factors deemed relevant by our board of directors.

Equity Compensation Plan Information

The following table summarizes information regarding the number of shares of our common stock that are available for issuance under all of our existing equity compensation plan as of December 31, 2011.

     
Plan Category   Number of
Securities to be
Issued upon
Exercise of
Outstanding
Options, Warrants
and Rights
  Weighted Average
Exercise Price of
Outstanding
Options, Warrants
and Rights
  Number of
Securities Remaining
Available for Future
Issuance Under
Equity Compensation
Plans (Excluding
Securities Reflected
in Column (a))
     (a)   (b)   (c)
Equity Compensation Plans Approved by Security Holders(1)     375,000     $ 2.78       4,850,000  
Equity Compensation Plans Not Approved by Security Holders(2)     2,113,051     $ 1.51        
Total     2,488,051     $ 1.70       4,850,000  

(1) Includes stock options to purchase 225,000 shares of common stock issued pursuant to equity plans of the pre-merger entity, ante4, Inc. prior to the merger date, April 16, 2010. See Note 6 to our financial statements for additional discussion.
(2) On December 1, 2009, we issued our Chief Financial Officer warrants to purchase a total of 260,509 shares of common stock exercisable at $0.98 per share pursuant to the terms of his employment

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agreement. On December 31, 2009, we issued our Chief Executive Officer warrants to purchase a total of 1,302,542 shares of common stock exercisable at $0.98 per share pursuant to the terms of his employment agreement. On April 21, 2010, we granted our outside directors stock options to purchase a total of 700,000 shares of common stock exercisable at $2.76 per share for serving as outside directors, 300,000 of which have been forfeited or have expired. On November 12, 2010, we granted a newly appointed outside director stock options to purchase a total of 150,000 shares of common stock exercisable at $3.70 per share for serving as an outside director. In May 2011, we 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, pursuant to the terms of their employment agreements. None of the officers, directors or employees had exercised any of the warrants or options as of December 31, 2011.

Stock Performance Graph

This graph shows our cumulative total shareholder return over the period from April 16, 2010, the date of our merger with ante4, Inc., to December 31, 2011, relative to the cumulative total returns of the Amex Index and the Standard & Poor’s Composite 500 Index. The comparison assumes an investment of $100 (with reinvestment of all dividends) was made in our common stock on April 16, 2010, and in each of the indexes and its relative performance is tracked quarterly through December 31, 2011.

Voyager Oil & Gas, Inc.
Total Return Performance

[GRAPHIC MISSING]

The following table sets forth the total returns utilized to generate the foregoing graph.

               
  4/16/2010   6/30/2010   9/30/2010   12/31/2010   3/31/2011   6/30/2011   9/30/2011   12/31/2011
Voyager Oil & Gas, Inc.   $ 100.00     $ 271.43     $ 246.43     $ 385.71     $ 314.29     $ 212.14     $ 150.00     $ 183.57  
Standard & Poor’s Composite 500 Index   $ 100.00     $ 86.46     $ 95.73     $ 105.50     $ 111.22     $ 110.78     $ 94.91     $ 105.49  
Amex Oil Index   $ 100.00     $ 79.48     $ 92.88     $ 109.11     $ 124.02     $ 117.31     $ 92.80     $ 110.55  

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Item 6.  Selected Financial Data

The financial statement information set forth below is derived from our balance sheets as of December 31, 2011 and 2010, and the related statements of operations, stockholders’ equity, and cash flows for the years ended December 31, 2011, 2010, and 2009 beginning on page F-1 of this report.

     
  Year Ended December 31,
     2011   2010(1)   2009(1)
Statements of Income Information:
                          
Revenues
                          
Oil and Natural Gas Sales   $ 8,426,129     $ 942,840     $  
Operating Expenses
                          
Production Expenses     726,946       26,686        
Production Taxes     717,440       102,743        
General and Administrative Expense     2,686,176       1,778,161       2,308,199  
Depletion of Oil and Natural Gas Properties     3,546,466       547,844        
Impairment of Oil and Natural Gas Properties           1,377,188        
Depreciation and Amortization     30,831       2,929       30  
Accretion of Discount on Asset Retirement Obligations     4,882       358        
Total Expenses     7,712,741       3,835,909       2,308,229  
Income (Loss) from Operations     713,388       (2,893,069 )      (2,308,229 ) 
Other Income (Expense)     (2,058,442 )      (1,310,260 )      31,037  
Loss Before Income Taxes     (1,345,054 )      (4,203,329 )      (2,277,192 ) 
Income Tax Provision           65,240        
Net Loss   $ (1,345,054 )    $ (4,268,569 )    $ (2,227,192 ) 
Net Loss Per Common Share – Basic and Diluted   $ (0.02 )    $ (0.11 )    $ (0.14 ) 
Weighted Average Shares Outstanding – Basic and Diluted     56,085,108       38,038,591       15,768,998  
Balance Sheet Information:
                          
Total Assets   $ 104,839,421     $ 48,495,426     $ 5,469,149  
Long-term Liabilities   $ 15,116,119     $ 10,522     $  
Total Liabilities   $ 25,697,480     $ 15,774,602     $ 36,545  
Stockholder’s Equity   $ 79,141,941     $ 32,720,824     $ 5,432,604  
Statement of Cashflow Information:
                          
Net cash used for operating activities   $ (153,156 )    $ (1,165,635 )    $ (25,161 ) 
Net cash used for investing activities   $ (43,508,278 )    $ (3,745,202 )    $ (3,876,471 ) 
Net cash provided by financing activities   $ 46,230,181     $ 15,578,094     $ 2,817,472  

(1) We did not have oil and natural gas operations prior to April 16, 2010. For further discussion, see “Organization of the Company” in Note 1 to the Financial Statements.

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Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read in conjunction with Item 6. Selected Financial Data and Item 8. Financial Statements and Supplementary Data appearing elsewhere in this report. A discussion of our financial results before April 16, 2010 is not pertinent to our business plan on a going forward basis, due to the change in our business which occurred upon consummation of the merger on April 16, 2010. See Item 1. Business — Overview.

Overview and Outlook

We are an oil and natural gas exploration and production company. Our properties are located in Montana, North Dakota, Colorado and Wyoming. Our corporate strategy is to build shareholder value through the development and acquisition of oil and natural gas assets that exhibit economically producible hydrocarbons.

As of December 31, 2011, we controlled the rights to mineral leases covering approximately 143,000 net acres. Our business currently focuses on our properties in Montana and North Dakota. Our goals are to continue to explore for and develop hydrocarbons within the mineral leases we control as well as continue to expand our acreage position should opportunities present themselves. In order to accomplish our objectives we will need to achieve the following:

continue to develop our substantial inventory of high quality core Bakken and Three Forks acreage with results consistent with those to-date;
retain and attract talented personnel;
continue to be a low-cost producer of hydrocarbons; and
continue to manage our financial obligations to access the appropriate capital needed to develop our position of primarily undrilled acreage.

The following table sets forth selected operating data for the periods indicated. Production volumes and average sales prices are derived from accrued accounting data for the relevant period indicated.

   
  Year End December 31,
     2011   2010
Net Production:
                 
Oil (Bbl)     95,517       13,198  
Natural Gas (Mcf)     14,962       3,489  
Net Sales:
                 
Oil   $ 8,296,607     $ 927,339  
Natural Gas     129,522       15,501  
Total Revenues   $ 8,426,129     $ 942,840  
Average Sales Prices:
                 
Oil (per Bbl)   $ 86.86     $ 70.26  
Natural Gas (per Mcf)   $ 8.66     $ 4.44  
Operating Expenses:
                 
Production Expenses   $ 726,946     $ 26,686  
Production Taxes   $ 717,440     $ 102,743  
General and Administrative Expense (Including Share Based Compensation)   $ 2,686,176     $ 1,778,161  
Depletion of Oil and Natural Gas Properties   $ 3,546,466     $ 547,844  

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Results of Operations for the periods ended December 31, 2011, 2010 and 2009

Revenues

Revenues from sales of oil and natural gas were $8,426,149 in 2011 compared to $942,840 in 2010. For 2011, our production volumes increased 611% as compared to 2010. The production primarily increased due to the addition of 4.75 and 0.74 net productive wells in 2011 and 2010, respectively. During 2011, we realized a $86.86 average price per barrel of oil compared to a $70.26 average price per barrel of oil during 2010. We recognized no production volumes in 2009.

Production Expenses

Production expenses were $726,946 in 2011 compared to $26,686 in 2010. 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 increased from $2.05 per barrel sold in 2010 to $7.51 in 2011. These increases are related to higher operating costs primarily in our Williston Basin wells. The largest cost driver in our Williston Basin wells is the disposal of water. We recognized no production expenses in 2009 due to no production volumes.

Production Taxes

Production taxes were $717,440 in 2011 compared to $102,743 in 2010. We pay production taxes based on realized crude oil and natural gas sales. Our production taxes were 8.5% in 2011 compared to 10.8% in 2010. The 2011 average production tax rate was lower than the 2010 average due to well additions that qualified for reduced rates/or tax exemptions during 2011. Certain portions of our production occurs in Montana and North Dakota 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. We recognized no production taxes in 2009.

General and Administrative Expense

General and administrative expenses were $2,686,176 in 2011 compared to $1,778,161 in 2010 and $2,308,199 in 2009. The 2011 increase of $908,105 when compared to 2010 is due to increased professional and legal expenses ($480,254), the addition of employees and related employment expenses ($225,890), as well as exchange listing expenses ($110,366). Increases in professional, legal, employment-related and exchange listing expenses in 2011 compared to 2010 were the result of growth in infrastructure.

The 2010 decrease of $530,038 in 2010 when compared to 2009 is due to decreased share-based compensation ($1,361,700) offset by increased professional and legal fees ($365,474), insurance expense ($163,434) and employee and related employment expenses ($85,349). Share-based compensation expense represents the amortization of restricted stock grants and stock options granted to our employees and directors as part of compensation. Increases in professional, legal, insurance and employment-related expenses in 2010 compared to 2009 were the result of growth in infrastructure from a development stage company into an exploration and production company.

Depletion Expense

Depletion expense was $3,546,466 in 2011 compared to $547,844 in 2010. On a per-unit basis, depletion expense was $36.18 per Boe in 2011 compared to $39.75 per Boe in 2010. 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 in 2011 compared to 2010 was due primarily to the addition of 4.75 and 0.74 net productive wells in 2011 and 2010, respectively. We recognized no depletion expense in 2009 due to no production volumes.

Other Income (Expense)

Other income (expense) was $(2,058,442) in 2011 compared to $(1,310,260) in 2010 and $31,037 in 2009. Interest expense, the largest component of other income (expense) was $(2,036,032) in 2011 compared to $(629,026) in 2010. The increase in interest expense resulted from the outstanding senior secured notes incurring interest for the full year of 2011, while the notes were outstanding for four months of 2010. We incurred no interest expense in 2009 because we had no debt.

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Net loss

We had net loss of $(1,345,054) in 2011 compared to $(4,268,569) in 2010 and $(2,277,192) in 2009 (representing $(0.02), $(0.11) and $(0.14) per share, respectively). The improvement in our period-over-period results was driven by revenue and production from oil and gas properties growing at a faster rate than general and administrative and other expenses.

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 (“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 comparable GAAP financial 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), the most directly comparable GAAP measure, to adjusted EBITDA for the periods presented:

     
  Year Ended December 31,
     2011   2010   2009
Net loss   $ (1,345,054 )    $ (4,268,569 )    $ (2,277,192 ) 
Interest expense     2,036,032       629,026        
Accretion of asset retirement obligations     4,882       358        
Depreciation, depletion and amortization     3,577,297       550,773       30  
Impairment of oil and natural gas properties           1,377,188        
Stock-based compensation     728,546       882,804       2,244,504  
Adjusted EBITDA   $ 5,001,703     $ (828,420 )    $ (32,658 ) 

Operation Plan

We expect to participate in the drilling of approximately 10.0 net Bakken and Three Forks wells in 2012 with drilling capital expenditures approximating $70.0 million, assuming four net wells in process of being drilled, completed or awaiting completion at year end 2012. During 2012, we expect to drill wells at an average completed cost of $9.0 million per Bakken and Three Forks net well. Based on evolving conditions in the field, we expect to deploy approximately $10 million towards further strategic acreage acquisitions in these formations during 2012. We expect to fund all of our 2012 commitments using cash-on-hand, cash flow from operations and borrowings under the new credit facility. For additional discussion, see Item 7. Management’s Discuss and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Macquarie Credit Facility below.

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 oil and natural gas; (iii) the market price for 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 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.

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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 short term borrowings. In the future, we anticipate we will be able to provide the necessary liquidity by the revenues generated from the sales of our oil and natural gas reserves in our existing properties; however, if we do not generate sufficient sales revenues we will continue to finance our operations through equity and/or debt financings.

The following table summarizes total current assets, total current liabilities and working capital at December 31, 2011.

 
Current Assets   $ 17,223,009  
Current Liabilities   $ 10,581,361  
Working Capital   $ 6,641,648  

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 continue to use 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, outstanding senior secured promissory notes totaling $15 million were paid in full.

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 March 13, 2012, we had $15 million borrowed under Tranche A and none borrowed under Tranche B.

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 offering 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 borrowing 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 loan based on LIBOR 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.

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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, upon an event of default. 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.

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.

Satisfaction of Our Cash Obligations for the Next Twelve Months

With the addition of available funds under the credit facility subsequent to the year ended December 31, 2011, we believe we have sufficient capital to meet our drilling commitments and expected general and administrative expenses for the next twelve months at a minimum. Nonetheless, any strategic acquisition of assets may require us 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 non-leveraged 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, continue to develop and upgrade technology and products, 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. See Item 1A. Risk Factors — We are an early stage company. We may never attain profitability.

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, excluding short-term investments, as of December 31, 2011 were $13,927,267, compared to $11,358,520 as of December 31, 2010. The increase in our cash balance was primarily attributable to the private placement in February 2011 described in Note 5 to the financial statements, offset by the acquisition and development of oil and natural gas properties.

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Net Cash Used In Operating Activities

Net cash used in operating activities was $153,156 for the year ended December 31, 2011 compared to $1,165,634 for the year ended December 31, 2010. The change in the net cash used in operating activities is primarily attributable to lower net loss driven by higher production revenue, offset by an increase in accounts receivable.

Net Cash Used In Investment Activities

Net cash used in investment activities was $43,508,278 for the year ended December 31, 2011 compared to $3,745,203 for the year ended December 31, 2010. The increase in 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 $46,230,181 for the year ended December 31, 2011 compared to $15,578,094 for the year ended December 31, 2010. The change in net cash provided by financing activities is primarily attributable to proceeds from the private placement described in Note 5 to the financial statements.

Contractual Obligations and Commitments

As of December 31, 2011, our $15 million in senior secured promissory notes were our only material debt obligations. These notes were paid on February 10, 2012 concurrent with the closing of the credit facility with MBL. See — Liquidity and Capital Resources — Macquarie Credit Facility. We have no other material capital lease obligations, operating lease obligations or purchase obligations requiring future payments other than our office lease that expires on April 1, 2014. The following table illustrates our contractual obligations as of December 31, 2011.

         
  Payment due by period
Contractual Obligations   Total   Less than
1 year
  1 – 3 years   3 – 5 years   More than
5 years
Senior Secured Promissory Notes(1)   $ 15,000,000     $     $ 15,000,000     $   —     $   —  
Office Lease(2)     103,923       46,188       57,735              
Automobile Leases(3)     36,802       20,074       16,728              
     $ 15,140,725     $ 66,262     $ 15,074,463     $     $  

(1) In September 2010, we completed the closing on the issuance of $15 million principal amount of 12% senior secured promissory notes (the “Notes”) for the purpose of financing future drilling and development activities. 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 our assets, on a pari passu basis with each other. The Notes matured one year from the date of issuance. We opted to extend the term one year. In order to enter the extension term, we were required to pay an extension payment equal to 2% of the principal amount. We had the right to pre-pay the Notes at anytime without penalty during the extended term. On February 10, 2012, the Notes were paid in full concurrent with the closing of the credit facility with Macquarie Bank Limited. The term of the credit facility is 36 months. See — Liquidity and Capital Resources — Macquarie Credit Facility.
(2) Our office lease at 2718 Montana Avenue, Suite 220, Billings, MT 59101 commenced on April 1, 2011 and has a term of three years.
(3) In November 2010, we entered into automobile leases for vehicles utilized by two of our employees, which expire in November 2013.

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Product Research and Development

We do not anticipate performing any significant product research and development given our current plan of operation.

Expected Purchase or Sale of Any Significant Equipment

We do not anticipate the purchase or sale of any plant or significant equipment as such items are not required by us at this time or anticipated to be needed in the next twelve months.

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 to, 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 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.

Reserves

All of the reserves data in this Form 10-K are estimates. Estimates of our oil and natural gas reserves are prepared by our qualified petroleum engineers in accordance with guidelines established by the SEC, including rule revisions designed to modernize the oil and natural gas company reserves reporting requirements, which we implemented effective December 31, 2009. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Uncertainties include the projection of future production rates and the expected timing of development expenditures. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserves estimates may be different from the quantities of oil and natural gas that are ultimately recovered. In addition, economic producibility of reserves is dependent on the oil and natural gas prices used in the reserves estimate. Our reserve estimates are based on 12-month average commodity prices, unless contractual arrangements designate the price to be used, in accordance with SEC rules. However, oil and natural gas prices are volatile and, as a result, our reserves estimates will change in the future. See Item 1A. Risk Factors — Estimates of oil and natural gas reserves that we make may be inaccurate and actual revenues may be lower than financial projections.

Estimates of proved oil and natural gas reserves significantly affect our depreciation, depletion and amortization expense. For example, if estimates of proved reserves decline, the depreciation, depletion and amortization rate will increase, resulting in a decrease in net income. A decline in estimates of proved reserves could also cause us to perform an impairment analysis to determine if the carrying amount of oil and natural gas properties exceeds fair value and could result in an impairment charge, which would reduce earnings. In addition, a decline in estimates of proved reserves could prompt a goodwill impairment analysis. See Item 8. Financial Statements and Supplementary Data — Supplemental Oil and Natural Gas Information (Unaudited).

Full Cost Method

We utilize 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 year ended December 31, 2011, we capitalized $526,630 of internal salaries, which included $418,414 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. We did not capitalize internal salaries for the years ended December 31, 2010 and 2009.

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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 December 31, 2011, we had no property sales since inception.

Impairment of Oil and Natural Gas Properties and Other Investments

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 years ended December 31, 2011 and 2010, we included $6,983,125 and $8,280, respectively, 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, 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 statements of operations as an impairment charge. Based on calculated reserves at December 31, 2010, the unamortized costs of our oil and natural gas properties exceeded the ceiling limit by $1,377,188. As a result, we were required to record an impairment of the net capitalized costs of its oil and natural gas properties in the amount of $1,377,188 at December 31, 2010. There was no impairment for the year ended December 31, 2011.

Joint Ventures

The financial statements as of December 31, 2011, 2010, and 2009 include our accounts and our proportionate share of the assets, liabilities, and results of operations of the joint ventures we are involved in. For further discussion of our joint venture arrangements, see Note 3 to our financial statements accompanying this report.

Note 2 to the Financial Statements and accompanying notes appearing elsewhere in this report describe various accounting policies critical to an understanding of our financial condition.

Stock-Based Compensation

We have accounted for stock-based compensation under the provisions of FASB Accounting Standards Codification (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 utilize 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, we 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 of peer company data fairly represents the expected volatility we would experience if we 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.

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Off-Balance Sheet Arrangements

As of December 31, 2011, we did not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors. See Note 14 to the financial statements for a discussion of certain derivative agreements initiated with MBL subsequent to year end.

Item 7A.  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 2011 and 2010 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. See Item 1A. Risk Factors — Prices and markets for oil and natural gas are unpredictable and tend to fluctuate significantly, which could reduce profitability, growth and the value of our business.

We entered into a facility with Macquarie Bank Limited (“MBL”) on February 10, 2012 which requires us to enter into hedging agreements 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 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. We intend to use of these derivative instruments as a means of managing our exposure to price changes in the future. For additional discussion, see Item 7. 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 December 31, 2011, we had $15 million in secured promissory notes at 12% interest rate outstanding, which have a fixed interest rate.

Our credit facility with MBL will subject us to interest rate risk on borrowings under that facility. 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 8.  Financial Statements and Supplementary Data

Our Financial Statements required by this item are included on the pages immediately following the Index to Financial Statements appearing on page F-1.

Item 9.  Changes In and Disagreements with Accountants on Accounting and Financial Disclosure

None.

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Item 9A.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We maintain a system of disclosure controls and procedures that is designed to ensure that information required to be disclosed by us in the reports we file or furnish to the SEC under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

As of December 31, 2011, our management, consisting of our Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) pursuant to Rule 13a-15(b) under the Exchange Act. Based upon and as of the date of the evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are designed and effective to ensure that information required to be disclosed is recorded, processed, summarized and reported within the specified periods and is accumulated and communicated to management, consisting of our Chief Executive Officer and Chief Financial Officer, to allow for timely decisions regarding required disclosure of material information required to be included in our periodic SEC reports. Based on the foregoing, our management determined that our disclosure controls and procedures were effective as of December 31, 2011.

In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that our controls will succeed in achieving their goals under all potential future conditions.

Management’s Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions, regardless of how remote. All internal control systems, no matter how well designed, have inherent limitations. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

We carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our internal controls over financial reporting as of December 31, 2011. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in “Internal Control — Integrated Framework.” Based on this assessment, management believes that, as of December 31, 2011, our internal control over financial reporting was effective based on those criteria. There have been no changes in internal control over financial reporting since December 31, 2011 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

The effectiveness of our internal control over financial reporting as of December 31, 2011 has been audited by BDO USA, LLP, an independent registered public accounting firm, as stated in their report which is included in this annual report on Form 10-K.

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Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders
Voyager Oil & Gas, Inc.
Billings, Montana

We have audited Voyager Oil & Gas, Inc.’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Voyager Oil & Gas, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying “Item 9A, Management’s Annual Report on Internal Control Over Financial Reporting.” Our responsibility is to express an opinion on Voyager Oil & Gas, Inc.’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Voyager Oil & Gas, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheet of Voyager Oil & Gas, Inc. as of December 31, 2011, and the related statements of operations, stockholders’ equity, and cash flows for the year then ended and our report dated March 13, 2012 expressed an unqualified opinion thereon.

/s/ BDO USA, LLP

Houston, Texas
March 13, 2012

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Item 9B.  Other Information

None.

PART III

Item 10.  Directors, Executive Officers and Corporate Governance

The information required by this item is incorporated herein by reference to the 2012 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2011.

Item 11.  Executive Compensation

The information required by this item is incorporated herein by reference to the 2012 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2011.

Item 12.  Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters

The information required by this item is incorporated herein by reference to the 2012 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2011.

Item 13.  Certain Relationships and Related Transactions, and Director Independence

The information required by this item is incorporated herein by reference to the 2012 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2011.

Item 14.  Principal Accountant Fees and Services

The information required by this item is incorporated herein by reference to the 2012 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2011.

PART IV

Item 15.  Exhibits and Financial Statement Schedules

(a) Documents filed as Part of this Report:

1.  Financial Statements

See Index to Financial Statements on page F-1.

2.  Financial Statement Schedules

All schedules are omitted because they are either not applicable or required information is shown in the financial statements or notes thereto.

3.  Exhibits

The exhibits set forth in the accompanying Exhibit Index are filed or incorporated by reference as part of this Form 10-K.

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Exhibit Index

   
Exhibit No.   Description   Reference
2.1   Articles of Merger, dated as of May 31, 2011, by and between Voyager Oil & Gas, Inc., a Delaware corporation, and Voyager Oil & Gas 1, Inc., a Montana corporation.   Exhibit 2.1 to the current report on Form 8-K of the registrant filed on June 2, 2011.
2.2   Asset Purchase Agreement dated as of July 28, 2009 by and between Gamynia Limited and WPT Enterprises, Inc.   Exhibit 2.1 to the current report on Form 8-K of the registrant filed on August 3, 2009.
2.3   Guaranty Agreement dated as of July 28, 2009 made by Borucoral Limited in favor of WPT Enterprises, Inc.   Exhibit 2.2 to the current report on Form 8-K of the registrant filed on August 3, 2009.
2.4   Asset Purchase Agreement dated August 24, 2009 by and among Peerless Media Ltd. and WPT Enterprises, Inc.   Exhibit 2.1 to the current report on Form 8-K of the registrant filed on August 24, 2009.
2.4   Guaranty Agreement dated as of August 24, 2009 made by ElectraWorks Ltd. in favor of WPT Enterprises, Inc.   Exhibit 2.2 to the current report on Form 8-K of the registrant filed on August 24, 2009.
2.5   Agreement and Plan of Merger dated as of April 16, 2010, by and among ante4, Inc., a Delaware corporation, Plains Energy Investments, Inc., a Nevada corporation, and Plains Energy Acquisition Corp., a Delaware corporation.   Exhibit 2.1 to the amended current report on Form 8-K/A of the registrant filed on July 22, 2010.
3.1   Articles of Incorporation of Voyager Oil & Gas, Inc.   Exhibit 3.1 to our current report on Form 8-K filed on June 2, 2011.
3.2   Bylaws of Voyager Oil & Gas, Inc.   Exhibit 3.2 to our current report on Form 8-K filed on June 2, 2011.
4.1   Specimen Certificate of Common Stock, par value $0.001 per share of Voyager Oil & Gas, Inc.   Exhibit 4.1 to our current report on Form 8-K filed on June 2, 2011.
4.2   Form of Vesting Warrant.   Exhibit 4.2 to the Form S-3 registration statement of the registrant filed on April 30, 2010 (File No. 333-166402).
4.3   Form of Warrant.   Exhibit 4.3 to the Form S-3 registration statement of the registrant filed on April 30, 2010 (File No. 333-166402).
4.4   Form of Restricted Stock Award Agreement.   Exhibit 4.4 to the Form S-3 registration statement of the registrant filed on April 30, 2010 (File No. 333-166402).
4.5   Form of Lock-Up Agreement.   Exhibit 4.5 to the Form S-3 registration statement of the registrant filed on April 30, 2010 (File No. 333-166402).
4.6   Form of 12.00% Senior Secured Promissory Notes issued to certain investors.   Exhibit 4.1 to the current report on Form 8-K of the registrant filed on September 23, 2010.

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Exhibit No.   Description   Reference
4.7   Form of Warrant issued to investors in the February 2011 private placement.   Exhibit 5.1 to the Form S-3 registration statement of the registrant filed on February 11, 2011 (File No. 333-172210).
10.1   Distribution Agreement dated April 16, 2010 between Ante4, Inc. and Ante5, Inc.   Exhibit 10.1 to the current report on Form 8-K of the registrant filed on April 19, 2010.
10.2   Amended and Restated Employment Agreement with James Russell Reger dated April 16, 2010.   Exhibit 10.1 to the current report on Form 8-K of the registrant filed on April 22, 2010.
10.3   Amended and Restated Employment Agreement with Mitchell R. Thompson dated April 16, 2010.   Exhibit 10.2 to the current report on Form 8-K of the registrant filed on April 22, 2010.
10.4   Letter Agreement to Purchase Oil, Gas and Mineral Leases dated March 10, 2010 by and between South Fork Exploration, LLC and Plains Energy Investments, Inc.   Exhibit 10.1 to the quarterly report on Form 10-Q/A of the registrant filed on July 23, 2010.
10.5   Exploration and Development Agreement with Area of Mutual Interest, dated effective as of May 1, 2010 between the Company and Slawson Exploration Company Inc.   Exhibit 10.1 to the quarterly report on Form 10-Q of the registrant filed on August 11, 2010.
10.6   Security Agreement dated September 22, 2010.   Exhibit 10.1 to the current report on Form 8-K of the registrant filed on September 23, 2010.
10.7   Mortgage, Collateral Real Estate Mortgage, Deed of Trust, Assignment of As-Extracted Collateral, Security Agreement, Fixture Filing and Financing Statement dated September 22, 2010.   Exhibit 10.2 to the current report on Form 8-K of the registrant filed on September 23, 2010.
10.8   Securities Purchase Agreement dated February 1, 2011.   Exhibit 10.1 to the current report on Form 8-K of the registrant filed on February 7, 2011.
10.9   Voyager Oil & Gas, Inc. 2011 Equity Incentive Plan.   Exhibit 10.1 to the quarterly report on Form 10-Q of the registrant filed on August 9, 2011.
10.10   Form of Incentive Stock Option Agreement under the Voyager Oil & Gas, Inc. 2011 Equity Incentive Plan.   Exhibit 10.1 to the quarterly report on Form 10-Q of the registrant filed on November 8, 2011.
10.11   Form of Nonqualified Stock Option Agreement under the Voyager Oil & Gas, Inc. 2011 Equity Incentive Plan.   Exhibit 10.2 to the quarterly report on Form 10-Q of the registrant filed on November 8, 2011.
10.12   Form of Restricted Stock Agreement under the Voyager Oil & Gas, Inc. 2011 Equity Incentive Plan.   Exhibit 10.3 to the quarterly report on Form 10-Q of the registrant filed on November 8, 2011.

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Exhibit No.   Description   Reference
10.13   Form of Restricted Stock Unit Agreement under the Voyager Oil & Gas, Inc. 2011 Equity Incentive Plan.   Exhibit 10.4 to the quarterly report on Form 10-Q of the registrant filed on November 8, 2011.
10.14   Credit Agreement dated as of February 10, 2012, among Voyager Oil & Gas, Inc., as Borrower, Macquarie Bank Limited, as Administrative Agent, and the Lenders party thereto.   Exhibit 10.1 to the current report on Form 8-K of the registrant filed on February 15, 2012.
14.1   Code of Ethics.   Filed herewith.
16.1   Letter from Piercy Bowler Taylor & Kern dated April 27, 2010.   Exhibit 16.1 to the current report on Form 8-K of the registrant filed on April 27, 2010.
16.2   Letter from Mantyla McReyonlds, LLC dated October 6, 2011.   Exhibit 16.1 to the current report on Form 8-K of the registrant filed on October 7, 2011.
21.1   List of Subsidiaries.   Filed herewith.
23.1   Consent of Independent Registered Public Accounting Firm BDO USA, LLP.   Filed herewith.
23.2   Consent of Independent Registered Public Accounting Firm Mantyla McReyonlds LLC.   Filed herewith.
23.3   Consent of Netherland, Sewell & Associates, Inc.   Filed herewith.
24.1   Power of Attorney (included on signature page).   Filed herewith.
31.1   Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.   Filed herewith.
31.2   Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.   Filed herewith.
32.1   Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.   Filed herewith.
32.2   Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.   Filed herewith.
99.1   Report of Netherland, Sewell & Associates, Inc.   Filed herewith.
101.INS   XBRL Instance Document.   Filed herewith.
101.SCH   XBRL Schema Document.   Filed herewith.
101.CAL   XBRL Calculation Linkbase Document.   Filed herewith.
101.DEF   XBRL Definition Linkbase Document.   Filed herewith.
101.LAB   XBRL Label Linkbase Document.   Filed herewith.
101.PRE   XBRL Presentation Linkbase Document.   Filed herewith.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 
  VOYAGER OIL & GAS, INC.
Date: March 13, 2012  

By:

/s/ JAMES RUSSELL (J.R.) REGER

James Russell (J.R.) Reger
Chief Executive Officer

POWER OF ATTORNEY

Each person whose signature appears below constitutes and appoints, James Russell (J.R.) Reger and Mitchell R. Thompson, or either of them, his true and lawful attorney-in-fact and agent, acting alone, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Annual Report on Form 10-K and to file the same, with all exhibits thereto, and other documents in connection wherewith, with the Commission, granting unto said attorney-in-fact and agent, each acting alone, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all said attorney-in-fact and agent, acting alone, or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacity and on the dates indicated:

   
Signature   Title   Date
/s/ JAMES RUSSELL (J.R.) REGER

James Russell (J.R.) Reger
  Chief Executive Officer, Director and Secretary   March 13, 2012
/s/ MITCHELL R. THOMPSON

Mitchell R. Thompson
  Chief Financial Officer, Director and Treasurer   March 13, 2012
/s/ LYLE BERMAN

Lyle Berman
  Director; Chairman of Board   March 13, 2012
/s/ JOSEPH LAHTI

Joseph Lahti
  Director   March 13, 2012
/s/ MYRNA PATTERSON MCLEROY

Myrna Patterson McLeroy
  Director   March 13, 2012
/s/ LOREN J. O’TOOLE II

Loren J. O’Toole II
  Director   March 13, 2012
/s/ JOSH SHERMAN

Josh Sherman
  Director   March 13, 2012

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Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders
Voyager Oil & Gas, Inc.
Billings, Montana

We have audited the accompanying balance sheet of Voyager Oil & Gas, Inc. as of December 31, 2011 and the related statement of operations, stockholders’ equity, and cash flows for the year then ended. These financial statements are the responsibility of Voyager Oil & Gas, Inc.’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Voyager Oil & Gas, Inc. at December 31, 2011, and the results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Voyager Oil & Gas, Inc.’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 13, 2012, expressed an unqualified opinion thereon.

/s/ BDO USA, LLP

Houston, Texas
March 13, 2012

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders
Voyager Oil & Gas, Inc.:

We have audited the accompanying balance sheet of Voyager Oil & Gas, Inc. (the Company) as of December 31, 2010, and the related statements of operations, stockholders’ equity, and cash flows for each of the years in the two-year period ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2010, and the results of their operations and their cash flows for each of the years in the two-year period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America.

/s/ Mantyla McReynolds LLC

Mantyla McReynolds LLC
Salt Lake City, Utah
March 14, 2011

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VOYAGER OIL & GAS, INC.
  
BALANCE SHEETS
  
DECEMBER 31, 2011 AND 2010

   
  2011   2010
ASSETS
                 
CURRENT ASSETS
                 
Cash and Cash Equivalents   $ 13,927,267     $ 11,358,520  
Trade Receivables     3,247,412       295,821  
Prepaid Expenses     48,330       85,988  
Other Current Assets           294,535  
Total Current Assets     17,223,009       12,034,864  
PROPERTY AND EQUIPMENT
                 
Oil and Natural Gas Properties, Full Cost Method
                 
Proved Oil and Natural Gas Properties     60,425,243       6,700,438  
Unproved Oil and Natural Gas Properties     32,180,217       31,176,109  
Other Property and Equipment     176,238       18,346  
Total Property and Equipment     92,781,698       37,894,893  
Less – Accumulated Depreciation, Depletion and Amortization     (5,505,288 )      (1,927,991 ) 
Total Property and Equipment, Net     87,276,410       35,966,902  
Prepaid Drilling Costs     33,163       493,660  
Debt Issuance Costs, Net of Amortization     306,839        
Total Assets   $ 104,839,421     $ 48,495,426  
LIABILITIES AND STOCKHOLDERS’ EQUITY
                 
CURRENT LIABILITIES
                 
Accounts Payable   $ 10,375,239     $ 537,757  
Accrued Expenses     206,122       389,679  
Senior Secured Promissory Notes           14,836,644  
Total Current Liabilities     10,581,361       15,764,080  
LONG-TERM LIABILITIES
                 
Senior Secured Promissory Notes     15,000,000        
Asset Retirement Obligations     116,119       10,522  
Total Liabilities     25,697,480       15,774,602  
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, 57,848,431 and 45,344,431 Shares Issued and Outstanding, respectively     57,848       45,344  
Additional Paid-In Capital     86,958,174       39,204,507  
Accumulated Deficit     (7,874,081 )      (6,529,027 ) 
Total Stockholders’ Equity     79,141,941       32,720,824  
Total Liabilities and Stockholders’ Equity   $ 104,839,421     $ 48,495,426  

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

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VOYAGER OIL & GAS, INC.
  
STATEMENTS OF OPERATIONS
  
FOR THE YEARS ENDED DECEMBER 31, 2011, 2010 AND 2009

     
  Year Ended December 31,
     2011   2010   2009
REVENUES
                          
Oil and Natural Gas Sales   $ 8,426,129     $ 942,840     $  
OPERATING EXPENSES
                          
Production Expenses     726,946       26,686        
Production Taxes     717,440       102,743        
General and Administrative Expenses     2,686,176       1,778,161       2,308,199  
Depletion of Oil and Natural Gas Properties     3,546,466       547,844        
Impairment of Oil and Natural Gas Properties           1,377,188        
Depreciation and Amortization     30,831       2,929       30  
Accretion of Discount on Asset Retirement Obligations     4,882       358        
       7,712,741       3,835,909       2,308,229  
INCOME (LOSS) FROM OPERATIONS     713,388       (2,893,069 )      (2,308,229 ) 
OTHER INCOME (EXPENSE)
                          
Merger Costs           (735,942 )       
Interest Expense     (2,036,032 )      (629,026 )       
Other Income (Expense)     (22,410 )      54,708       31,037  
Total Other Income (Expense), Net     (2,058,442 )      (1,310,260 )      31,037  
LOSS BEFORE INCOME TAXES     (1,345,054 )      (4,203,329 )      (2,277,192 ) 
INCOME TAX PROVISION           65,240        
NET LOSS   $ (1,345,054 )    $ (4,268,569 )    $ (2,277,192 ) 
Net Loss Per Common Share – Basic and Diluted   $ (0.02 )    $ (0.11 )    $ (0.14 ) 
Weighted Average Shares Outstanding – Basic and Diluted     56,085,108       38,038,591       15,768,988  

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

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VOYAGER OIL & GAS, INC.
  
STATEMENTS OF CASH FLOWS
  
FOR THE YEARS ENDED DECEMBER 31, 2011, 2010 AND 2009

     
  Year Ended December 31,
     2011   2010   2009
CASH FLOWS FROM OPERATING ACTIVITIES
                          
Net Loss   $ (1,345,054 )    $ (4,268,569 )    $ (2,277,192 ) 
Adjustments to Reconcile Net Loss to Net Cash Used For Operating Activities:
                          
Depletion of Oil and Natural Gas Properties     3,546,466       547,844        
Impairment of Oil and Natural Gas Properties           1,377,188        
Depreciation and Amortization     30,831       2,929       30  
Amortization of Premium on Bonds           46,448        
Amortization of Debt Discount     163,356       61,664        
Amortization of Finance Costs     82,191              
Loss on Disposal of Property and Equipment           34,305        
Accretion of Discount on Asset Retirement Obligations     4,882       358        
Gain on Sale of Available for Sale Securities           (1,520 )      (14,803 ) 
Share-Based Compensation Expense     728,546       882,804       2,244,504  
Changes in Assets and Liabilities:
                          
Increase in Trade Receivables     (2,951,591 )      (295,821 )       
Decrease in Prepaid Expenses     37,658       9,821        
Decrease (Increase) in Other Current Assets     52,465       188,529       (7,781 ) 
Increase (Decrease) in Accounts Payable     (319,349 )      411,469       30,712  
Decrease in Accrued Expenses     (183,557 )      (163,083 )      (631 ) 
Net Cash Used For Operating Activities     (153,156 )      (1,165,634 )      (25,161 ) 
CASH FLOWS FROM INVESTING ACTIVITIES
                          
Cash Received from Merger Agreement           17,413,845        
Cash Received on Note Receivable           500,000        
Purchases of Other Property and Equipment     (157,892 )      (598 )      (17,748 ) 
Prepaid Drilling Costs     460,497       (493,660 )       
Purchase of Available for Sale Securities                 (569,321 ) 
Proceeds from Sales of Available for Sale Securities     242,070       9,769,881       315,459  
Acquisition of Oil and Natural Gas Properties     (44,052,953 )      (30,934,671 )      (3,604,861 ) 
Net Cash Used For Investing Activities     (43,508,278 )      (3,745,203 )      (3,876,471 ) 
CASH FLOWS FROM FINANCING ACTIVITIES
                          
Proceeds from Issuance of Common Stock – Net of Issuance Costs     46,602,251       779,240       2,817,472  
Proceeds from Issuance of Senior Secured Promissory Notes           14,775,000        
Cash Paid for Finance Costs     (389,030 )             
Proceeds from Exercise of Stock Options and Warrants     16,960       23,854        
Net Cash Provided by Financing Activities     46,230,181       15,578,094       2,817,472  
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS     2,568,747       10,667,257       (1,084,160 ) 
CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD     11,358,520       691,263       1,775,423  
CASH AND CASH EQUIVALENTS – END OF PERIOD   $ 13,927,267     $ 11,358,520     $ 691,263  
Supplemental Disclosure of Cash Flow Information
                          
Cash Paid During the Period for Interest   $ 1,800,000     $ 380,933     $  
Cash Paid During the Period for Income Taxes   $     $ 65,240     $  
Non-Cash Financing and Investing Activities:
                          
Oil and Natural Gas Properties Property Accrual in Accounts Payable   $ 10,252,407     $ 95,576     $  
Purchase of Oil and Natural Gas Properties through Issuance of Common Stock   $     $ 2,358,900     $  
Payment of Capital Raise Costs with Issuance of Common Stock   $     $     $ 171,771  
Stock-Based Compensation Capitalized to Oil and Natural Gas Properties   $ 418,414     $     $  
Capitalized Asset Retirement Obligations   $ 100,715     $ 10,164     $  

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

F-6


 
 

TABLE OF CONTENTS

VOYAGER OIL & GAS, INC.
  
STATEMENT OF STOCKHOLDERS’ EQUITY (DEFICIT)
  
FOR THE YEARS ENDED DECEMBER 31, 2011, 2010 AND 2009

           
           
    
  
Common Stock
  Additional
Paid-In
Capital
  Accumulated
Other
Comprehensive
Income (Loss)
  Retained
Earnings
(Accumulated
Deficit)
  Total
Stockholders’
Equity
(Deficit)
     Shares   Amount
Balance – December 31, 2008     14,579,825     $ 14,580     $ 2,610,020     $     $ 16,734     $ 2,641,334  
Sale of 2,947,157 Common Shares at $.98 Per Share     2,947,157       2,947       2,881,886                   2,884,833  
Issued 37,774 Common Shares as Consulting Fees     37,774       38       36,937                   36,975  
Issued 175,481 Common Shares related to Capital Raise     175,481       175       (175 )                   
Private Placement Costs Net of Common Shares Issued                 (67,361 )                  (67,361 ) 
Fair Value of Warrants Issued                 2,076,841                   2,076,841  
Issued 130,255 Common Shares as Compensation     130,255       130       127,370                   127,500  
Issued 468,916 Common Shares of Restricted Stock     468,916       469       (469 )                         
Restricted Stock Grant Compensation                 3,188                   3,188  
Unrealized Gain on Available for Sale Investments