UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

 

x

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

 

For the quarterly period ended March 31, 2012

 

OR

 

¨

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

 

For the transition period from                  to

 

Commission File No. 1-35097

 

Voyager Oil & Gas, Inc.

(Exact name of registrant as specified in its charter)

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

As of May 8, 2012, there were 58,448,431 shares of Common Stock, $0.001 par value per share, outstanding.

 

 

VOYAGER OIL & GAS, INC.

 

INDEX

 

		Page of
		Form 10-Q
PART I. FINANCIAL INFORMATION		1
ITEM 1. FINANCIAL STATEMENTS (UNAUDITED)		1
Condensed Balance Sheets as of March 31, 2012 and December 31, 2011		1
Condensed Statements of Operations for the three months ended March 31, 2012 and 2011		2
Condensed Statements of Cash Flows for the three months ended March 31, 2012 and 2011		3
Notes to Condensed Financial Statements		4
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		14
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		25
ITEM 4. CONTROLS AND PROCEDURES		26
PART II. OTHER INFORMATION		26
ITEM 1. LEGAL PROCEEDINGS		26
ITEM 1A. RISK FACTORS		27
ITEM 6. EXHIBITS		27
SIGNATURES		28

 

 

PART 1 — FINANCIAL INFORMATION

 

ITEM 1. FINANCIAL STATEMENTS

VOYAGER OIL & GAS, INC.

CONDENSED BALANCE SHEETS

(UNAUDITED)

 

 

		March 31, 2012				December 31, 2011
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents		$	4,939,616			$	13,927,267
Trade Receivables			5,421,851				3,247,412
Prepaid Expenses			70,673				48,330
Total Current Assets			10,432,140				17,223,009
PROPERTY AND EQUIPMENT
Oil and Natural Gas Properties, Full Cost Method
Proved Oil and Natural Gas Properties			87,354,450				60,425,243
Unproved Oil and Natural Gas Properties			31,562,587				32,180,217
Other Property and Equipment			177,735				176,238
Total Property and Equipment			119,094,772				92,781,698
Less – Accumulated Depreciation, Depletion and Amortization			(7,514,417	)			(5,505,288	)
Total Property and Equipment, Net			111,580,355				87,276,410
Prepaid Drilling Costs			422,487				33,163
Debt Issuance Costs, Net of Amortization			429,460				306,839
Total Assets		$	122,864,442			$	104,839,421
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts Payable		$	24,841,342			$	10,375,239
Accrued Expenses			15,972				206,122
Fair Value of Commodity Derivatives			549,251				—
Total Current Liabilities			25,406,565				10,581,361
LONG-TERM LIABILITIES
Revolving Credit Facility			17,545,779				—
Senior Secured Promissory Notes			—				15,000,000
Fair Value of Commodity Derivatives			335,641				—
Asset Retirement Obligations			161,890				116,119
Total Liabilities			43,449,875				25,697,480
STOCKHOLDERS’ EQUITY
Preferred Stock – Par Value $.001; 20,000,000 Shares Authorized; None Issued or Outstanding			—				—
Common Stock, Par Value $.001; 200,000,000 Shares Authorized, 58,448,431 and 57,848,431 Shares Issued and Outstanding, respectively			58,448				57,848
Additional Paid-In Capital			87,486,570				86,958,174
Accumulated Deficit			(8,130,451	)			(7,874,081	)
Total Stockholders’ Equity			79,414,567				79,141,941
Total Liabilities and Stockholders’ Equity		$	122,864,442			$	104,839,421

 

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

 

 

VOYAGER OIL & GAS, INC.

CONDENSED STATEMENTS OF OPERATIONS

(UNAUDITED) 

 

		Three Months Ended March 31,
		2012				2011
REVENUES
Oil and Natural Gas Sales		$	5,098,333			$	832,621
Loss on Commodity Derivatives			(912,435	)			—
			4,185,898				832,621
OPERATING EXPENSES
Production Expenses			466,630				49,978
Production Taxes			506,021				79,964
General and Administrative Expenses			942,131				694,314
Depletion of Oil and Natural Gas Properties			1,998,059				407,984
Depreciation and Amortization			11,070				787
Accretion of Discount on Asset Retirement Obligations			2,567				261
Total Expenses			3,926,478				1,233,288
INCOME (LOSS) FROM OPERATIONS			259,420				(400,667	)
OTHER INCOME (EXPENSE)
Interest Expense			(515,790	)			(495,479	)
Other Income (Expense), Net			—				6,372
Total Other Expense, Net			(515,790	)			(489,107	)
LOSS BEFORE INCOME TAXES			(256,370	)			(889,774	)
INCOME TAX EXPENSE			—				—
NET LOSS			(256,370	)			(889,774	)
Net Loss Per common Share – Basic and Diluted			(0.00	)			(0.02	)
Weighted Average Shares Outstanding – Basic and Diluted			57,860,519				52,567,631

 

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

 

 

VOYAGER OIL & GAS, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(UNAUDITED) 

 

		Three Months Ended March 31,
		2012				2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss		$	(256,370	)		$	(889,774	)
Adjustments to Reconcile Net Loss to Net Cash Provided By Operating Activities:
Depletion of Oil and Natural Gas Properties			1,998,059				407,984
Depreciation and Amortization			11,070				787
Amortization of Debt Discount			—				55,479
Amortization of Finance Costs			241,591				—
Accretion of Discount on Asset Retirement Obligations			2,567				261
Unrealized Loss on Derivative Instruments			884,892				—
Share-Based Compensation Expense			327,725				256,739
Changes in Assets and Liabilities:
Increase in Trade Receivables			(2,174,439	)			(181,042	)
Decrease (Increase) in Prepaid Expenses			(22,343	)			39,864
Increase in Accounts Payable			184,496				2,112,370
Decrease in Accrued Expenses			(190,150	)			(108,727	)
Net Cash Provided By Operating Activities			1,007,098				1,693,941
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of Other Property and Equipment			(1,497	)			(65,082	)
Prepaid Drilling Costs			(389,324	)			(2,575,907	)
Proceeds from Sales of Available for Sale Securities			—				242,070
Investment in Oil and Natural Gas Properties			(11,785,495	)			(10,393,074	)
Net Cash Used For Investing Activities			(12,176,316	)			(12,791,993	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Issuance of Common Stock – Net of Issuance Costs			—				46,602,251
Advances on Revolving Credit Facility and Term Loan			17,545,779				—
Payments on Senior Secured Promissory Notes			(15,000,000	)			—
Cash Paid for Finance Costs			(364,212	)			—
Proceeds from Exercise of Stock Options and Warrants			—				16,960
Net Cash Provided by Financing Activities			2,181,567				46,619,211
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS			(8,987,651	)			35,521,159
CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD			13,927,267				11,358,520
CASH AND CASH EQUIVALENTS – END OF PERIOD		$	4,939,616			$	46,879,679
Supplemental Disclosure of Cash Flow Information
Cash Paid During the Period for Interest		$	424,402			$	450,000
Cash Paid During the Period for Income Taxes		$	—			$	—
Non-Cash Financing and Investing Activities:
Oil and Natural Gas Properties Property Accrual in Accounts Payable		$	24,534,014			$	84,818
Stock-Based Compensation Capitalized to Oil and Natural Gas Properties		$	201,271			$	—
Capitalized Asset Retirement Obligations		$	43,204			$	5,221

 

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

 

 

VOYAGER OIL & GAS, INC. 
Notes to Condensed Financial Statements
Unaudited

 

NOTE 1  ORGANIZATION AND NATURE OF BUSINESS

 

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

 

As a non-operator, Voyager focuses on maintaining a relatively small amount of overhead. The Company engages in the drilling process through operators’ drilling units that include the Company’s acreage position. By eliminating the fixed staffing required to manage this process internally, the Company reduces its fixed employee cost structure and overhead. The Company had six employees as of March 31, 2012 and seeks to retain independent contractors to assist in operating and managing its prospects as well as to carry out the principal and necessary functions incidental to the oil and natural gas business. With the continued acquisition of oil and natural gas properties, the Company intends to continue engaging industry partners best suited to the areas of operation. As the Company continues to establish a revenue base with cash flow, it may seek opportunities more aggressive in nature.

 

NOTE 2  SIGNIFICANT ACCOUNTING POLICIES

 

The accompanying condensed financial statements have been prepared on the accrual basis of accounting whereby revenues are recognized when earned, and expenses are recognized when incurred. These condensed financial statements as of March 31, 2012 and for the three months ended March 31, 2012 and 2011 are unaudited. In the opinion of management, such financial statements include the adjustments and accruals, all of which are of a normal recurring nature, which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results for a full year. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles (GAAP) have been condensed or omitted in these financial statements for and as of the three months ended March 31, 2012 and 2011.

 

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

 

Cash and Cash Equivalents

 

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

 

Other Property and Equipment

 

Property and equipment that are not oil and natural gas properties are recorded at cost and depreciated using the straight-line method over their estimated useful lives of three to seven years. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Depreciation expense was $11,070 and $787 for the three month periods ended March 31, 2012 and 2011, respectively.

 

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

 

 

Asset Retirement Obligations

 

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

 

Revenue Recognition and Natural Gas Balancing

 

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

 

Stock-Based Compensation

 

 

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

 

 

On May 27, 2011, the shareholders of the Company approved the Voyager Oil & Gas, Inc. 2011 Equity Incentive Plan (the “2011 Plan”), under which 5,000,000 shares of common stock have been reserved. The purpose of the 2011 Plan is to promote the success of the Company by facilitating the employment and retention of competent personnel and by furnishing incentives to those employees, directors and consultants upon whose efforts the success of the Company will depend to a large degree. It is the intention of the Company to carry out the 2011 Plan through the granting of incentive stock options, nonqualified stock options, restricted stock awards, restricted stock unit awards, performance awards and stock appreciation rights. As of March 31, 2012, 1,125,000 of the common stock reserved were issued to employees under the 2011 Plan.

 

Income Taxes

 

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

 

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

 

 

Net Income (Loss) Per Common Share

 

Basic net income (loss) per common share is based on the net income (loss) divided by the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average number of common shares plus dilutive common share equivalents outstanding during the period using the treasury stock method. In the computation of diluted earnings per share, excess tax benefits that would be created upon the assumed vesting of unvested restricted shares or the assumed exercise of stock options (i.e., hypothetical excess tax benefits) are included in the assumed proceeds component of the treasury share method to the extent that such excess tax benefits are more likely than not to be realized. When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. As the Company had a loss for the three month periods ended March 31, 2012 and 2011, the potentially dilutive shares are anti-dilutive and are thus not added into the earnings per share calculation.

 

The following stock options, warrants and restricted stock, which would be potentially dilutive in future periods, were not included in the computation of diluted net loss per share for the three months ended March 31, 2012 because the effect would have been anti-dilutive:

 

Restricted Stock			500,001
Stock Options			1,425,000
Stock Warrants			7,813,051
Total Potentially Dilutive Shares			9,738,052

 

Full Cost Method

 

The Company follows the full cost method of accounting for oil and natural gas operations whereby all costs related to the exploration and development of oil and natural gas properties are initially capitalized into a single cost center (“full cost pool”). Such costs include land acquisition costs, a portion of employee salaries related to property development, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities. For the three month period ended March 31, 2012, the Company capitalized $238,615 of internal salaries, which included $201,271 of stock-based compensation. Internal salaries are capitalized based on employee time allocated to the acquisition of leaseholds and development of oil and natural gas properties. The Company did not capitalize internal salaries for the three month period ended March 31, 2011.

 

Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. As of March 31, 2012, the Company has had no property sales since inception.

 

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

 

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

 

Capitalized costs (net of related deferred income taxes) are limited to a ceiling based on the present value of future net revenues using the 12-month unweighted average of first-day-of-the-month price (the “12-month average price”), discounted at 10%, plus the lower of cost or fair market value of unproved properties. If the ceiling is not greater than or equal to the total capitalized costs, the Company is required to write down capitalized costs to the ceiling. The Company performs this ceiling test calculation each quarter. Any required write downs are included in the condensed statements of operations as an impairment charge. There was no impairment for the three month periods ended March 31, 2012 and 2011.

 

 

Commodity Derivative Instruments

 

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

 

New Accounting Pronouncements  

 

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

 

Joint Ventures

 

The condensed financial statements as of March 31, 2012 and 2011 include the accounts of the Company and its proportionate share of the assets, liabilities, and results of operations of the joint ventures it is involved in.

  

Use of Estimates

  

 

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

 

Reclassifications

 

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

 

NOTE 3  OIL AND NATURAL GAS PROPERTIES

 

Major Joint Venture

 

In May 2008, the Company entered into the Major Joint Venture Agreement with a third-party partner to acquire certain oil and natural gas leases in the Tiger Ridge Gas Field in Blaine, Hill, and Choteau Counties of Montana. Under the terms of the joint venture agreement, the Company is responsible for all lease acquisition costs. The third-party joint venture partner is responsible for coordinating the geology, acquiring the leases in its name, preparing and disseminating assignments, accounting for the project costs and administration of the well operator. The Company controls an 87.5% working interest on all future production and reserves, while the third-party joint venture partner controls a 12.5% working interest. The joint venture had accumulated oil and natural gas leases totaling 74,706 net mineral acres as of March 31, 2012. The Company initially committed to a minimum of $1,000,000 toward this joint venture. An amendment to the joint venture agreement was executed in April 2011 to remove the maximum amount committed under the joint venture. The Company is not committed to any further capital obligations under the joint venture. The third-party joint venture partner issues cash calls during the year to replenish the joint venture cash account. The Company’s contributions to the joint venture totaled $4,214,441 as of March 31, 2012, consisting of $1,940,054 in leasing costs, $1,346,925 in seismic costs and $804,155 in drilling costs. The unutilized cash balance was $123,307 as of March 31, 2012.

 

 

Tiger Ridge Joint Venture

 

 

In November 2009, the Company entered into the Tiger Ridge Joint Venture Agreement with a third-party and a well operator to develop and exploit a drilling program in two certain blocks of acreage in the Major Joint Venture, which is an area of mutual interest. The Company controls a 70% working interest, while a third-party investor and the well operator control a 10% working interest and 20% working interest, respectively. The joint venture agreement requires that all parties contribute in cash their proportional share to cover all costs incurred in developing these blocks of acreage for drilling. 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. These wells are currently awaiting pipeline hook-up.

 

 

Big Snowy Joint Venture

 

In October 2008, the Company entered into the Big Snowy Joint Venture Agreement with an administrator third-party to acquire certain oil and natural gas leases in the Heath oil play in Musselshell, Petroleum, Garfield, Rosebud and Fergus Counties of Montana, and another third-party to perform as the operator. Under the terms of the agreement, the Company is responsible for 72.5% of lease acquisition costs, and the other parties are individually responsible for 2.5% and 25% of the lease acquisition costs. Each party controls the same respective working interest on all future production and reserves. The administrator third-party joint venture partner is responsible for coordinating the geology, acquiring the leases in its name, preparing and disseminating assignments, accounting for the project costs and administration of the well operator. The joint venture had accumulated oil and natural gas leases totaling 33,562 net mineral acres as of March 31, 2012. The Company is committed to a minimum of $1,000,000 and up to $1,993,750 toward this joint venture, with all partners, including the Company, committing a minimum of $2,750,000. The administrator third-party joint venture partner issues cash calls during the year to replenish the joint venture cash account. The Company’s contributions to the joint venture totaled $724,744 as of March 31, 2012. The unutilized cash balance was $11,790 as of March 31, 2012.

 

Niobrara Development with Slawson Exploration Company, Inc.

 

The Company announced the Niobrara development program with Slawson Exploration Company, Inc. on June 28, 2010. The Company participated on a heads-up, or pro rata, basis for a 50% working interest in six exploratory wells in Weld County, Colorado targeting the Niobrara formation. Following the results of the initial three test wells, the Company 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 quarter ended March 31, 2011 and in production as of March 31, 2012. The Company allowed approximately 7,100 additional acres to expire on November 15, 2011. The Company currently holds approximately 2,400 net acres in Weld County, Colorado and Laramie County, Wyoming. The Company currently has no plans for drilling any additional development wells in 2012.

 

Other Property Acquisitions

 

On May 24, 2011, the Company purchased certain leases consisting of approximately 1,680 net acres in Williams County, North Dakota and Richland County, Montana for a total purchase price of $2,514,863. On May 27, 2011 the Company purchased certain leases consisting of approximately 1,195 net acres in Richland County, Montana for a total purchase price of $1,792,950. The Company has also completed other miscellaneous acquisitions in the Williston Basin of Montana and North Dakota during the year ended December 31, 2011 totaling approximately $13,541,730, and totaling $1,957,246 during the three months ended March 31, 2012.

 

NOTE 4  RELATED PARTY TRANSACTIONS

 

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

 

 

On November 2, 2011, the Company purchased certain leases consisting of approximately 256 net acres in Dunn County, North Dakota for a total purchase price of $768,000. The leases were purchased from Ante5, Inc., (“Seller”) a related party. The Seller and its assets were spun off from the Company and became a separate publicly reporting U.S. company on June 24, 2010. The Chairman of the Board of the Seller is Bradley Berman, who is the son of the Company’s Chairman of the Board and was the beneficial owner of approximately 6.1% of the Company’s outstanding common stock as of March 31, 2012. The Company’s Audit Committee reviewed and approved this transaction prior to its completion. In approving this transaction, the Audit Committee, which consisted solely of independent directors, took into account, among other factors, that due diligence performed by the Company evidenced that the leases were purchased by the Company at the Seller’s original cost per acre and on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances.

 

NOTE 5  PREFERRED AND COMMON STOCK

 

Stock Awards

 

 

During the three month period ended March 31, 2012, the Company issued 600,000 shares of common stock with a fair value of $2.94 per share as compensation to its officers, of which 99,999 shares vested immediately and the remaining 500,001 shares are restricted and subject to vesting requirements. The restricted shares vest over various terms with all restricted shares vesting no later than December 2014. The fair value of the stock issued that immediately vested was $293,997 or $2.94 per share, the market value of a share of common stock on the date the stock was issued, and the Company expensed $160,718 in share-based compensation in the three month period ended March 31, 2012. The remainder of the fair value of the fully vested stock granted was capitalized into the full cost pool. As of March 31, 2012, there was approximately $1.4 million of total unrecognized compensation expense related to unvested restricted stock. The Company will recognize compensation expense over the remaining vesting period of the restricted stock grants. The Company has assumed a 0% forfeiture rate for the restricted stock.

 

 

The Company incurred compensation expense associated with restricted stock granted in 2012 of $26,787 for the three months ended March 31, 2012. The Company incurred compensation expense associated with restricted stock granted prior to 2012 of $57,378 for the three months ended March 31, 2011. For the three months ended March 31, 2012, the Company capitalized compensation expense associated with the restricted stock of $22,213 to oil and natural gas properties.

 

 

NOTE 6  STOCK OPTIONS AND WARRANTS

 

Stock Options

 

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

 

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

 

The impact on our condensed statement of operations of stock-based compensation expense related to options granted for the three month periods ended March 31, 2012 and 2011 was $140,220 and $78,592, respectively, net of $0 tax. The Company capitalized $45,779 in compensation related to outstanding options for the three months ended March 31, 2012.

 

 

The following assumptions were used for the Black-Scholes model to value the options granted during the three months ended March 31, 2012.

 

Risk free rates	0.86% to 1.04%
Dividend yield	0%
Expected volatility	78.06% to 78.18%
Weighted average expected life	5.5 years

 

 

The following summarizes activities concerning outstanding options to purchase shares of the Company’s common stock as of and for the three months ended March 31, 2012:

 

·   No options were exercised.

·   No options were forfeited.

·   No options expired.

·   The Company will recognize approximately $1.3 million of compensation expense in future periods relating to options that have been granted as of March 31, 2012.

· There were 1,062,500 unvested options at March 31, 2012.

 

Warrants

 

 

The table below reflects the status of warrants outstanding at March 31, 2012:

 

 

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

 

No warrants expired or were forfeited during the three months ended March 31, 2012. The Company recorded no expense related to these warrants for the three months ended March 31, 2012. As of March 31, 2012, all of the compensation expense related to these vested warrants has been expensed by the Company. All warrants outstanding were exercisable at March 31, 2012.

 

NOTE 7  SENIOR SECURED PROMISSORY NOTES

 

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

 

The Notes were paid in full on February 10, 2012 in conjunction with the Company entering into a credit facility with Macquarie Bank Limited (“MBL”) (see Note 8). The remaining unamortized finance costs of $217,809 were written off to interest expense in the three months ended March 31, 2012.

 

NOTE 8 REVOLVING CREDIT FACILITY

 

On February 10, 2012, the Company entered into a credit facility (“Facility”) with Macquarie Bank Limited. 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 31, 2012, the Company had borrowed $15 million under Tranche A and $2,545,779 under Tranche B.

 

The borrowing base of funds available to the Company under Tranche A is redetermined semi-annually based upon the net present value, discounted at 10% per annum, of the future net revenues expected to accrue from the Company’s interests in proved reserves estimated to be produced from its crude oil and natural gas properties. The Facility terminates on February 10, 2015. Tranche B may be committed and drawn upon approved developing properties by MBL. Outstanding borrowings under Tranche B are due in six equal monthly installments beginning on August 10, 2015.

 

The Company has the option to designate the reference rate of interest for each specific borrowing under the Facility as amounts are advanced. Under Tranche A, borrowings designated to be based upon the London Interbank Offered Rate (LIBOR) bear interest at a rate equal to LIBOR plus a spread ranging from 2.75% to 3.25%, depending on the percentage of borrowing base that is currently advanced. The 30-day LIBOR was 0.2406% as of March 31, 2012. Any borrowings not designated LIBOR-based will bear interest at a rate equal to the current prime rate published by the Wall Street Journal plus a spread ranging from 1.75% to 2.25%, depending on the percentage of borrowing base that is currently advanced. The prime rate was 3.25% as of March 31, 2012. The Company has the option to designate either pricing mechanism. Tranche B borrowing bears interest at a rate equal to LIBOR plus 7.5%. Interest payments are due under the Facility in arrears; in the case of a LIBOR-based loan, on the last day of the specified interest period and in the case of all other loans on the last day of each March, June, September and December. All outstanding principal is due and payable upon termination of the Facility.

 

 

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

 

The Facility requires that the Company enter into hedging agreements with MBL for each month of the 36-month period following the date on which each such hedge agreement is executed, the notional volumes for which, when aggregated with other commodity derivative agreements and additional fixed-price physical off-take contracts then in effect are not less than 50%, nor greater than 90%, of the reasonably anticipated projected production from our proved developed producing reserves. The Facility also requires the Company to maintain certain financial ratios, including current ratio (1.00 to 1.00), debt coverage ratio (3.50 to 1.00) and interest coverage ratio (2.50 to 1.00), commencing on March 31, 2012. The Company was not in compliance with the current ratio covenant as of March 31, 2012, and a waiver was obtained from MBL. The current ratio shortfall and resulting working capital deficit of $14,974,425 as of March 31, 2012 is primarily due to $9,651,838 of accrued capitalized costs associated with development of oil and natural gas properties in the Williston Basin not yet invoiced to the Company. These capitalized costs will be financed through Tranche B under the Facility upon receipt of associating invoices from the respective well operators. The remaining current working capital deficit will be funded through interim redetermination of reserves under the Facility and cash provided from operating activities.

 

 

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

 

NOTE 9  ASSET RETIREMENT OBLIGATION

 

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

 

 

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

 

		March 31, 2012				December 31, 2011
Beginning Asset Retirement Obligation		$	116,119			$	10,522
Liabilities Incurred for New Wells Placed in Production			43,204				100,715
Accretion of Discount on Asset Retirement Obligations			2,567				4,882
Ending Asset Retirement Obligation		$	161,890			$	116,119

 

NOTE 10  INCOME TAXES

 

Deferred income tax assets and liabilities are determined based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse.  The Company does not expect to pay any federal or state income tax for 2012 as a result of net operating loss carry forwards from prior years.  Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized.  As of March 31, 2012, the Company maintains a full valuation allowance for all deferred tax assets.  Based on these requirements no provision or benefit for income taxes has been recorded for deferred taxes. There were no recorded unrecognized tax benefits at the end of the reporting period.

 

 

NOTE 11 FAIR VALUE

 

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

 

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

 

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

 

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

 

The following schedule summarizes the valuation of financial instruments measured at fair value on a recurring basis in the condensed balance sheet as of March 31, 2012:

 

		Fair Value Measurements at March 31, 2012 Using
			Quoted Prices In Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
Commodity Derivatives – Current Liability (crude oil collars)		$	—			$	(549,251	)		$	—
Commodity Derivatives – Long Term Liability (crude oil collars)			—				(336,641	)			—
Total		$	—			$	(884,892	)		$	—

 

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

 

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

 

NOTE 12 FINANCIAL INSTRUMENTS

 

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

 

 

The Company’s accounts receivable relate to oil and natural gas sold to various industry companies.  Credit terms, typical of industry standards, are of a short-term nature and the Company does not require collateral. Management believes the Company’s accounts receivable at March 31, 2012 and December 31, 2011 do not represent significant credit risks as they are dispersed across many counterparties.  The Company has determined that no allowance for doubtful accounts is necessary at March 31, 2012 and December 31, 2011.  As of March 31, 2012, outstanding derivative contracts with MBL represent all of the Company’s oil volumes hedged.  MBL has investment-grade ratings from Moody’s and Standard & Poor and is the lender under the Company’s credit facility and management believes this does not represent a significant credit risk.

 

NOTE 13 DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT

 

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

 

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

 

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

 

The Company realized a loss on settled derivatives of $27,543 and a loss on mark-to-market of derivatives instruments of $884,892 for the three months ended March 31, 2012. The Company did not enter into derivative instruments prior to 2012.

 

Costless collars are used to establish floor and ceiling prices on anticipated oil and natural gas production. There were no premiums paid or received by the Company related to the costless collar agreements.  The following table reflects open costless collar agreements as of March 31, 2012.

 

Term

Oil (Barrels)

Price

Basis

Costless Collars

April 1, 2012 – February 28, 2015

225,542

$90.00-$103.50

NYMEX

 

At March 31, 2012, the Company had derivative financial instruments recorded on the condensed balance sheet as set forth below:

 

Type of Contract		Balance Sheet Location		Amount
Derivative Assets:
Costless Collars		Current liabilities		$	278,032
Costless Collars		Non-current liabilities			977,651
Total Derivative Assets				$	1,255,683
Derivative Liabilities:
Costless Collars		Current liabilities		$	(827,283	)
Costless Collars		Non-current liabilities			(1,313,292	)
Total Derivative Liabilities				$	(2,140,575	)

 

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

 

 

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

 

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

 

Overview

 

Voyager Oil & Gas, Inc., a Montana corporation (“Voyager,” the “Company,” “we,” “us,” or “our”), was formed for the purpose of acquiring acreage 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.

 

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.

 

Assets and Acreage Holdings

 

As of March 31, 2012, we controlled approximately 144,000 net acres in the following five primary prospect areas:

•

33,000 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 33,000 net acres in the Williston Basin. During 2011, we acquired approximately 8,354 net acres primarily in Williams and McKenzie Counties, North Dakota and Richland County, Montana. On May 24, 2011, we purchased certain leases consisting of approximately 1,680 net acres in Williams County, North Dakota and Richland County, Montana for a total purchase price of $2,514,863. On May 27, 2011, we purchased certain leases consisting of approximately 1,195 net acres in Richland County, Montana for a total purchase price of $1,792,950. We also completed other acquisitions in the Williston Basin of Montana and North Dakota during the year ended December 31, 2011, and totaling $1,957,246 during the three months ended March 31, 2012.

 

During the first quarter 2012, we acquired 899 net acres in the Williston Basin at an average lease bonus cost of $2,100 per acre. 100% of the acreage acquired during the quarter either had an authorization for expenditure (“AFE”) from a well operator attached to the lease, or we subsequently received an AFE. We have participated in 160 gross (7.05 net) Bakken and Three Forks oil wells, including 118 gross (5.03 net) wells that are producing as of March 31, 2012. The remaining 42 gross (2.02 net) wells are in the process of being drilled, awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation as of March 31, 2012. We continue to lease prospective acreage targeting non-operated working interests in delineated areas of high quality production.

 

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.

 

Productive Wells

 

The following table summarizes gross and net productive oil wells by state at March 31, 2012 and 2011. A net well represents our fractional working ownership interest of a gross well. The following table also does not include 42 gross (2.02 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 March 31, 2012 and 35 gross (1.24 net) Bakken and Three Forks wells as of March 31, 2011.

 

 

 

		March 31,
		2012								2011
			Gross				Net				Gross				Net
North Dakota Bakken and Three Forks			108				4.06				11				0.48
Montana Bakken and Three Forks			10				0.97				—				—
Colorado Niobrara			5				2.50				1				0.50
Total:			123				7.53				12				0.98

 

Exploratory Wells

 

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. In 2012, we participated in the drilling of the Johnson 31-17 SWH well in an undeveloped area of Mountrail County, North Dakota with a 3.13% working interest. The well was abandoned after experiencing poor oil shows during the drilling process. The dry hole costs associated this well were $149,714. The costs associated with each of these wells were included in the full cost pool and subject to the depletion base. Of the 123 gross productive wells that we have participated in, these have been the only wells that we have participated in that were dry holes.

 

Results of Operations

 

Comparison of the Three Months Ended March 31, 2012 with the Three Months Ended March 31, 2011.

 

		Three Months Ended March 31, 2012				Three Months Ended March 31, 2011
REVENUES
Oil Sales		$	5,024,099			$	830,123
Natural Gas Sales			74,234				2,498
Total Oil and Natural Gas Sales			5,098,333				832,621
Realized Loss on Commodity Derivatives			(27,543	)			—
Unrealized Loss on Commodity Derivatives			(884,892	)			—
Revenues			4,185,898				832,621
OPERATING EXPENSES
Production Expenses			466,630				49,978
Production Taxes			506,021				79,964
General and Administrative Expenses			942,131				694,314
Depletion of Oil and Natural Gas Properties			1,998,059				407,984
Depreciation and Amortization			11,070				787
Accretion of Discount on Asset Retirement Obligation			2,567				261
Total Operating Expenses			3,926,478				1,233,288
INCOME (LOSS) FROM OPERATIONS			259,420				(400,667	)
OTHER INCOME (EXPENSE)
Interest Expense			(515,790	)			(495,479	)
Other Income (Expense), Net			—				6,372
Total Other Expense, Net			(515,790	)			(489,107	)
LOSS BEFORE INCOME TAXES			(256,370	)			(889,774	)
INCOME TAX EXPENSE			—				—
NET LOSS		$	(256,370	)		$	(889,774	)

 

 

Revenues

 

The following table presents information about our revenues and produced oil and natural gas volumes during the three months ended March 31, 2012, compared to the three months ended March 31, 2011.  As of March 31, 2012, we were selling oil and natural gas from a total of 123 gross wells (approximately 7.53 net wells), compared to 12 gross wells (0.98 net wells) at March 31, 2011.  Revenues from sales of oil and natural gas were $5,098,333 during the three months ended March 31, 2012 compared to $832,621 during the three months ended March 31, 2011. Our production volumes increased 454% in the three months ended March 31, 2012, as compared to the three months ended March 31, 2011. The production primarily increased due to the addition of 4.55 net productive Bakken and Three Forks wells from April 1, 2011 to March 31, 2012. During the three months ended March 31, 2012, we realized a $91.79 average price per barrel of oil before the effect of settled oil derivatives compared to $81.66 average price per barrel of oil during the three months ended March 31, 2011. For the three months ended March 31, 2012, crude oil represented 99% of revenues and 96% of production.

 

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

 

		Three Months Ended March 31,
		2012				2011
Oil and Natural Gas Revenues:
Oil		$	5,024,099			$	830,123
Natural Gas			74,234				2,498
Total Oil and Natural Gas Sales			5,098,333				832,621
Production:
Oil (Bbl)			54,735				10,165
Natural Gas (Mcf)			12,777				577
Barrel of Oil Equivalent (Boe)			56,865				10,262
Average Sales Prices:
Oil (per Bbl)		$	91.79			$	81.66
Effect of settled oil derivatives on average price (per Bbl)			(0.50	)			—
Oil net of settled derivatives (per Bbl)			91.29				81.66
Natural Gas and Other Liquids (per Mcf)			5.81				4.33
Barrel of Oil Equivalent (per Boe net of settled derivatives)			89.17				81.13

 

 

		Three Months Ended March 31,
		2012				2011
Revenues:
Total Oil and Natural Gas Sales		$	5,098,333			$	832,621
Realized Loss on Commodity Derivatives			(27,543	)			—
Unrealized Loss on Commodity Derivatives			(884,892	)			—
Revenues		$	4,185,898			$	832,621

 

Loss on Commodity Derivatives

 

Realized and unrealized commodity derivative losses were $27,543 and $884,892, respectively, for the three months ended March 31, 2012. There were no commodity derivates losses were during the three months ended March 31, 2011. Our derivatives are not designated for hedge accounting and are accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings.  Mark-to-market accounting treatment creates volatility in our revenues as unrealized gains and losses from derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying balance sheets.  As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives.  Any gains on our derivatives will be offset by lower wellhead revenues in the future or any losses will be offset by higher future wellhead revenues based on the value at the settlement date.  At March 31, 2012, all of our derivative contracts are recorded at their fair value, which was a net liability of $884,892. There was no net liability prior to March 31, 2012.

 

Expenses

		Three Months Ended March 31,
		2012				2011
Costs and Expenses Per Boe of Production:
Production Expenses		$	8.21			$	4.87
Production Taxes			8.90				7.79
G&A Expenses (Excluding Share-Based Compensation)			10.80				42.64
Shared-Based Compensation			5.76				25.02
Depletion of Oil & Natural Gas Properties			35.14				39.76
Depreciation and Amortization			0.19				0.08
Accretion of Discount on Asset Retirement Obligation			0.05				0.03

 

Production Expenses

 

Production expenses were $466,630 during the three months ended March 31, 2012 compared to $49,978 during the three months ended March 31, 2011. We experience increases in operating expenses as we add new wells and maintain production from existing properties. On a per unit basis, production expenses per Boe increased from $4.87 per barrel of oil equivalent, or Boe, sold during the three months ended March 31, 2011 to $8.21 during the three months ended March 31, 2012. 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.

 

Production Taxes

 

Production taxes were $506,021 during the three months ended March 31, 2012 compared to $79,964 in the three months ended March 31, 2011. We pay production taxes based on realized crude oil and natural gas sales. Our production taxes were comparable at 9.9% during the three months ended March 31, 2012 compared to 9.6% in the three months ended March 31, 2011. Some well additions qualify for reduced rates/or tax exemptions during 2011 and 2012. 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.

 

 

General and Administrative Expense

 

General and administrative expenses were $942,131 during the three months ended March 31, 2012 compared to $694,314 during the three months ended March 31, 2011. General and administrative expenses excluding share-based compensation were $614,406 during the three months ended March 31, 2012 compared to $437,575 during the three months ended March 31, 2011. The increase is primarily due to increased professional, engineering, audit and legal expenses ($98,004) and the addition of employees and related employment expenses ($82,284). Increases in professional, audit, legal, and employment-related expenses for the three months ended March 31, 2012 compared to the three months ended March 31, 2011 were the result of growth in infrastructure. On a per unit basis, general and administrative expenses per Boe decreased significantly as we were able to leverage our costs over a higher level of production. Share-based compensation expenses totaled $327,725 for the three months ended March 31, 2012 compared to $256,739 for the three months ended March 31, 2011.

 

Depletion Expense

 

Our depletion expense is driven by many factors, including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. Depletion expense was $1,998,059 for the three months ended March 31, 2012 compared to $407,984 for the three months ended March 31, 2011. On a per-unit basis, depletion expense was $35.14 per Boe for the three months ended March 31, 2012 compared to $39.76 per Boe for the three months ended March 31, 2011. Our depletion expense is based on the capitalized costs related to properties having proved reserves, plus the estimated future development costs and asset retirement costs which are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves determined by independent petroleum engineers. This increase in depletion expense for the three months ended March 31, 2012 compared to the three months ended March 31, 2011 was due primarily to the addition of 6.55 net productive wells from April 1, 2011 to March 31, 2012.

 

Other Expense

 

 

Other expense was $515,790 for the three months ended March 31, 2012 compared to $489,107 for the three months ended March 31, 2011. Interest expense, the largest component of other expense, was $515,790 for the three months ended March 31, 2012 compared to $495,479 for the three months ended March 31, 2011. The increase in interest expense resulted from the payment in full of the outstanding senior secured notes on February 10, 2012 and the resulting expense of unamortized financing costs associated with the notes, which totaled $217,809 for the three months ended March 31, 2012.

 

 

Net loss

 

We had a net loss of $256,370 for the three months ended March 31, 2012 compared to a net loss of $889,774 for the three months ended March 31, 2011 (representing $(0.00) and $(0.02) per share, respectively). The improvement in our period-over-period results was driven by revenue and production from oil and natural gas properties growing at a faster rate than general and administrative and other expenses, including interest and financing costs.

  

Non-GAAP Financial Measures

 

Adjusted EBITDA

 

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

 

 

		Three Months Ended March 31,
		2012				2011
Net loss		$	(256,370	)		$	(889,774	)
Interest expense			515,790				495,479
Accretion of asset retirement obligations			2,567				261
Depreciation, depletion and amortization			2,009,129				408,771
Stock-based compensation			327,725				256,739
Unrealized loss on commodity derivatives			884,892				—
Adjusted EBITDA		$	3,483,733			$	271,476

 

Adjusted Income

 

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

 

		Three Months Ended March 31,
		2012				2011
Net loss		$	(256,370	)		$	(889,774	)
Unrealized loss on commodity derivatives			884,892				—
Adjusted income (loss)		$	628,522			$	(889,774	)
Adjusted income (loss) per share – basic		$	0.01			$	(0.02	)
Weighted average shares outstanding – basic			57,860,519				52,567,631

 

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 from the revenues generated from the sales of our oil and natural gas reserves in our existing properties and availability under our credit facility; however, if we do not generate sufficient cash flow from operations or do not have availability under our credit facility we may attempt to continue to finance our operations through equity and/or debt financings.

 

 

The following table summarizes total current assets, total current liabilities and working capital at March 31, 2012.

 

Current assets		$	10,432,140
Current liabilities		$	25,406,565
Working capital (deficit)		$	(14,974,425	)

 

Equity Offerings

 

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

 

Macquarie Credit Facility

 

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

 

The facility provides up to a maximum of $150 million in principal amount of borrowings to be used as working capital for exploration and production operations. Initially, $15 million of financing was available under the facility based on reserves (Tranche A), with an additional $50 million available under a development tranche (Tranche B). As of March 31, 2012, we had $15 million borrowed under Tranche A and $2,545,779 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 Offered Rate (LIBOR) will bear interest at a rate equal to LIBOR plus a spread ranging from 2.75% to 3.25%, depending on the percentage of borrowing base that is currently advanced. Any borrowings not designated as being based upon LIBOR will bear interest at a rate equal to the current prime rate published by the Wall Street Journal plus a spread ranging from 1.75% to 2.25%, depending on the percentage of borrowing base that is currently advanced. We have the option to designate either pricing mechanism. Tranche B borrowings bear interest at a rate equal to LIBOR plus 7.5%. Interest payments are due under the facility in arrears, in the case of a LIBOR-based loan on the last day of the specified interest period and in the case of all other loans on the last day of each March, June, September and December. All outstanding principal is due and payable upon termination of the facility.

 

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

 

The facility requires that we enter into hedging agreements with MBL for each month of the 36-month period following the date on which each such hedge agreement is executed, the notional volumes for which (when aggregated with other commodity derivative agreements and additional fixed-price physical off-take contracts then in effect, as of the date such hedging agreement is executed, is not less than 50%, nor greater than 90%, of the reasonably anticipated projected production from our proved developed producing reserves. The facility also requires us to maintain certain financial ratios, including current ratio (1.00 to 1.00), debt coverage ratio (3.50 to 1.00) and interest coverage ratio (2.50 to 1.00), commencing on March 31, 2012. We were not in compliance with the current ratio covenant as of March 31, 2012, and a waiver was obtained from MBL. The current ratio shortfall and resulting working capital deficit of $14,974,425 as of March 31, 2012 is primarily due to $9,651,838 of accrued capitalized costs associated with development of oil and natural gas properties in the Williston Basin not yet invoiced to us. These capitalized costs will be financed through Tranche B under the facility upon receipt of associating invoices from the respective well operators. The remaining current working capital deficit will be funded through interim redetermination of reserves under the facility and cash provided from operating activities.

 

 

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

 

Satisfaction of Our Cash Obligations for the Next Twelve Months

 

With the addition of available funds under the MBL credit facility, 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, respond to competitive developments, and attract, retain and motivate qualified personnel. There can be no assurance that we will be successful in addressing such risks, and the failure to do so can have a material adverse effect on our business prospects, financial condition and results of operations.

 

Effects of Inflation and Pricing

 

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

 

Cash and Cash Equivalents

  

Our total cash resources as of March 31, 2012 were $4,939,616, compared to $13,927,267 as of December 31, 2011. The decrease in our cash balance was primarily attributable to the acquisition and development of oil and natural gas properties.

 

Net Cash Provided By Operating Activities

 

Net cash provided by operating activities was $1,007,098 for the three months ended March 31, 2012 compared to $1,693,941 for the three months ended March 31, 2011. The change in the net cash used in operating activities is primarily attributable to lower net loss driven by higher production revenue, offset by larger increase in accounts receivable.

 

Net Cash Used In Investment Activities

 

Net cash used in investment activities was $12,176,316 for the three months ended March 31, 2012 compared to $12,791,993 for the three months ended March 31, 2011. The cash used in investment activities is primarily attributable to the purchase and development of oil and natural gas properties in the Williston Basin during the periods.

 

Net Cash Provided By Financing Activities

 

 

Net cash provided by financing activities was $2,181,567 for the three months ended March 31, 2012 compared to $46,619,211 for the three months ended March 31, 2011. The change in net cash provided by financing activities for the three months ended March 31, 2012 is primarily attributable to proceeds from the new credit facility and payment of the senior secured promissory notes. The change in net cash provided by financing activities for the three months ended March 31, 2011 is primarily attributable to proceeds from the private placement described in Item 2. Management’s Discuss and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Equity Offerings above.

 

Off-Balance Sheet Arrangements

 

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

 

2012 Drilling Projects

 

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.

 

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.

 

Critical Accounting Policies

 

Revenue Recognition and Natural Gas Balancing

 

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

 

Full Cost Method

  

We follow the full cost method of accounting for oil and natural gas operations whereby all costs related to the exploration and development of oil and natural gas properties are initially capitalized into a single cost center (“full cost pool”). Such costs include land acquisition costs, a portion of employee salaries related to property development, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities. For the three month period ended March 31, 2012, we capitalized $238,615 of internal salaries, which included $201,271 of stock-based compensation. Internal salaries are capitalized based on employee time allocated to the acquisition of leaseholds and development of oil and natural gas properties. The Company did not capitalize internal salaries for the three month period ended March 31, 2011.

 

Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. As of March 31, 2012, we had no property sales since inception.

 

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 three month period ended March 31, 2012 we had no costs that were transferred to the full cost pool related to impairment. For the year ended December 31, 2011, we included $6,983,125 related to expiring leases within costs subject to the depletion calculation.

 

 

Capitalized costs 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 condensed statements of operations as an impairment charge. There was no impairment for the three month periods ended March 31, 2012 and 2011.

 

Joint Ventures

 

The condensed financial statements as of March 31, 2012 and 2011 include our accounts and our proportionate share of the assets, liabilities, and results of operations of the joint ventures in which we are involved.

  

Stock-Based Compensation

 

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

 

On May 27, 2011, our shareholders approved the Voyager Oil & Gas, Inc. 2011 Equity Incentive Plan (the “2011 Plan”), under which 5,000,000 shares of common stock have been reserved. The purpose of the 2011 Plan is to promote the success of the Company by facilitating the employment and retention of competent personnel and by furnishing incentives to those employees, directors and consultants upon whose efforts the success of the Company will depend to a large degree. It is our intention to carry out the 2011 Plan through the granting of incentive stock options, nonqualified stock options, restricted stock awards, restricted stock unit awards, performance awards and stock appreciation rights. As of March 31, 2012, we had issued 1,125,000 shares of common stock reserved under the 2011 Plan.

 

Cautionary Factors That May Affect Future Results

 

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

 

 

·

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

 

·

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

 

·

competition, including competition for acreage in resource play areas;

 

·

our ability to retain key members of management;

 

·

volatility in commodity prices for oil and natural gas;

 

·

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

 

·

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

 

·

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

 

·

our ability to replace oil and natural gas reserves;

 

·

environmental risks;

 

·

drilling and operating risks;

 

·

exploration and development risks;

 

·

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

 

·

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

 

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

 

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

Commodity Price Risk

 

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Crude oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile, and these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. Our revenues during the three months ended March 31, 2012 and March 31, 2011 generally have increased or decreased along with any increases or decreases in crude oil or natural gas prices, but the exact impact on our income is indeterminable given the variety of expenses associated with producing and selling crude oil and natural gas that also increase and decrease along with crude oil and natural gas prices.

 

 

We entered into a facility with 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 2. Management’s Discuss and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Macquarie Credit Facility above.

 

Interest Rate Risk

 

As of March 31, 2012, we had borrowed $15 million under Tranche A and $2,545,779 under Tranche B under our credit facility.

 

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

 

ITEM 4. CONTROLS AND PROCEDURES

 

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

 

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

 

PART II — OTHER INFORMATION

 

ITEM 1. LEGAL PROCEEDINGS

 

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 dropped all claims against James Randall Reger, Weldon Gilbertson, and James Russell Reger. Voyager 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. On May 7, 2012, the Court granted the motion to dismiss the case with prejudice.

 

 

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

 

ITEM 1A. RISK FACTORS

 

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

 

Recently approved final rules regulating air emissions from natural gas production operations could cause us to incur increased capital expenditures and operating costs, which may be significant.

 

On April 17, 2012, the Environmental Protection Agency (“EPA”) approved final regulations under the Clean Air Act that, among other things, require additional emissions controls for natural gas and natural gas liquids production, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with such production activities.  The final regulations require the reduction of VOC emissions from natural gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015.  For well completion operations occurring at such well sites before January 1, 2015, the final regulations allow operators to capture and direct flowback emissions to completion combustion devices, such as flares, in lieu of performing green completions.  These regulations also establish specific new requirements regarding emissions from dehydrators, storage tanks and other production equipment.  We are currently reviewing this new rule and assessing its potential impacts.  Compliance with these requirements could increase our costs of development and production, though we do not expect these requirements to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities.

 

ITEM 6. EXHIBITS

 

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

 

10.1		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 (incorporated by reference to Exhibit 10.1 to our current report on Form 8-K filed on February 15, 2012)
31.1*		Certification of Chief Executive Officer pursuant to Securities Exchange Act Rules 13a-15(e) and 15d-15(e) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*		Certification of Chief Financial Officer pursuant to Securities Exchange Act Rules 13a-15(e) and 15d-15(e) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1*		Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*		XBRL Instance Document
101.SCH*		XBRL Schema Document
101.CAL*		XBRL Calculation Linkbase Document
101.LAB*		XBRL Label Linkbase Document
101.PRE*		XBRL Presentation Linkbase Document

* Attached hereto.

 

 

SIGNATURES

 

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

 

Dated: May 8, 2012

 

	VOYAGER OIL & GAS, INC.
	/s/ James Russell (J.R.) Reger
	James Russell (J.R.) Reger
	Chief Executive Officer (principal executive officer)
	/s/ Mitchell R. Thompson
	Mitchell R. Thompson
	Chief Financial Officer (principal financial officer)