UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 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

Emerald Oil, 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.)

1600 Broadway, Suite 1040
Denver, CO	80202
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (303) 323-0008

Voyager Oil & Gas, Inc.

2718 Montana Ave., Suite 220

Billings, MT 59101

(Former name, former address and former fiscal year, if changed since the last report)

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:

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 November 8, 2012, there were 23,874,347 shares of Common Stock, $0.001 par value per share, outstanding.

EMERALD OIL, INC.

INDEX

			Page of
			Form 10-Q
PART I.	FINANCIAL INFORMATION		1
	ITEM 1.	FINANCIAL STATEMENTS (UNAUDITED)	1
		Condensed Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011	1
		Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2012 and 2011	2
		Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2012 and 2011	3
		Notes to Condensed Consolidated Financial Statements	4
	ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	20
	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	37
	ITEM 4.	CONTROLS AND PROCEDURES	37
PART II.	OTHER INFORMATION		37
	ITEM 1.	LEGAL PROCEEDINGS	37
	ITEM 1A.	RISK FACTORS	37
	ITEM 6.	EXHIBITS	45
SIGNATURES			46

PART 1 — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EMERALD OIL, INC.

(FORMERLY VOYAGER OIL & GAS, INC.)

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	September 30, 2012			December 31, 2011
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	33,282,601		$	13,927,267
Trade Receivables		6,215,270			3,247,412
Prepaid Expenses		137,804			48,330
Total Current Assets		39,635,675			17,223,009
PROPERTY AND EQUIPMENT
Oil and Natural Gas Properties, Full Cost Method
Proved Oil and Natural Gas Properties		128,411,987			60,425,243
Unproved Oil and Natural Gas Properties		67,562,346			32,180,217
Other Property and Equipment		277,415			176,238
Total Property and Equipment		196,251,748			92,781,698
Less – Accumulated Depreciation, Depletion and Amortization		(23,708,158	)		(5,505,288	)
Total Property and Equipment, Net		172,543,590			87,276,410
Prepaid Drilling Costs		315,986			33,163
Fair Value of Commodity Derivatives		61,794			—
Debt Issuance Costs, Net of Amortization		389,334			306,839
Other Assets		75,000			—
Total Assets	$	213,021,379		$	104,839,421
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts Payable	$	37,057,965		$	10,375,239
Fair Value of Commodity Derivatives		298,440			—
Accrued Expenses		9,911			206,122
Total Current Liabilities		37,366,316			10,581,361
LONG-TERM LIABILITIES
Revolving Credit Facility		15,000,000			—
Senior Secured Promissory Notes		—			15,000,000
Asset Retirement Obligations		238,315			116,119
Total Liabilities		52,604,631			25,697,480
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS’ EQUITY
Preferred Stock – Par Value $.001; 20,000,000 Shares Authorized; None Issued or Outstanding		—			—
Common Stock, Par Value $.001; 200,000,000 Shares Authorized, 23,389,649 and 8,264,061 Shares Issued and Outstanding, respectively		23,390			8,264
Additional Paid-In Capital		173,489,875			87,007,758
Accumulated Deficit		(13,096,517	)		(7,874,081	)
Total Stockholders’ Equity		160,416,748			79,141,941
Total Liabilities and Stockholders’ Equity	$	213,021,379		$	104,839,421

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

1

EMERALD OIL, INC.

(FORMERLY VOYAGER OIL & GAS, INC.)

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
REVENUES
Oil and Natural Gas Sales	$	7,111,569		$	2,872,674		$	18,973,331		$	5,371,830
Loss on Commodity Derivatives		(1,635,435	)		—			(296,327	)		—
		5,476,134			2,872,674			18,677,004			5,371,830
OPERATING EXPENSES
Production Expenses		687,646			221,509			1,639,105			419,822
Production Taxes		809,062			241,412			2,043,671			488,793
General and Administrative Expenses		3,503,273			509,893			5,660,622			1,910,824
Depletion of Oil and Natural Gas Properties		2,818,650			1,324,771			7,977,077			2,293,099
Impairment of Oil and Natural Gas Properties		—			—			10,191,234			—
Depreciation and Amortization		12,345			10,849			34,559			19,761
Accretion of Discount on Asset Retirement Obligations		4,037			1,717			10,027			3,306
Total Expenses		7,835,013			2,310,151			27,556,295			5,135,605
INCOME (LOSS) FROM OPERATIONS		(2,358,879	)		562,523			(8,879,291	)		236,225
OTHER INCOME (EXPENSE)
Interest Expense		(1,388,912	)		(508,841	)		(2,074,147	)		(1,510,416	)
Gain on Acquisition of Business, Net		5,769,679			—			5,758,048			—
Other Income (Expense), Net		(27,046	)		2,192			(27,046	)		(24,766	)
Total Other Income (Expense), Net		4,353,721			(506,649	)		3,656,855			(1,535,182	)
INCOME (LOSS) BEFORE INCOME TAXES		1,994,842			55,874			(5,222,436	)		(1,298,957	)
INCOME TAX EXPENSE		—			—			—			—
NET INCOME (LOSS)	$	1,994,842		$	55,874		$	(5,222,436	)	$	(1,298,957	)
Net Income (Loss) Per Common Share — Basic and Diluted	$	0.20		$	0.01		$	(0.59	)	$	(0.16	)
Weighted Average Shares Outstanding — Basic		9,969,005			8,197,074			8,844,032			7,948,370
Weighted Average Shares Outstanding — Diluted		10,027,934			8,402,238			8,844,032			7,948,370

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

2

EMERALD OIL, INC.

(FORMERLY VOYAGER OIL & GAS, INC.)
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Nine Months Ended September 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$	(5,222,436	)	$	(1,298,957	)
Adjustments to Reconcile Net Loss to Net Cash Provided By (Used For) Operating Activities:
Depletion of Oil and Natural Gas Properties		7,977,077			2,293,099
Impairment of Oil and Natural Gas Properties		10,191,234			—
Depreciation and Amortization		34,559			19,761
Amortization of Debt Discount		—			163,356
Amortization of Finance Costs		1,494,013			6,575
Accretion of Discount on Asset Retirement Obligations		10,027			3,306
Unrealized Loss on Derivative Instruments		236,646			—
Gain on Acquisition of Business		(7,213,835	)
Share-Based Compensation Expense		2,770,849			561,114
Changes in Assets and Liabilities, net of impact of acquisitions:
Increase in Trade Receivables		(2,967,858	)		(2,091,660	)
(Increase) Decrease in Prepaid Expenses		(89,474	)		36,323
Increase (Decrease) in Accounts Payable		998,360			(499,607	)
Decrease in Accrued Expenses		(196,211	)		(225,237	)
Net Cash Provided By (Used For) Operating Activities		8,022,951			(1,031,927	)
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of Other Property and Equipment		(65,177	)		(154,770	)
Prepaid Drilling Costs		(282,823	)		(264,264	)
Proceeds from Sales of Available for Sale Securities		—			242,070
Investment in Oil and Natural Gas Properties		(36,292,015	)		(34,242,379	)
Net Cash Used For Investing Activities		(36,640,015	)		(34,419,343	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Issuance of Common Stock – Net of Issuance Costs		69,852,809			46,602,251
Advances on Revolving Credit Facility and Term Loan		33,030,730			—
Payments on Revolving Credit Facility and Term Loan		(18,030,730	)		—
Payments of Senior Secured Promissory Notes		(15,000,000	)		—
Payment of Assumed Debt		(20,303,903	)		—
Cash Paid for Finance Costs		(1,576,508	)		(300,000	)
Proceeds from Exercise of Stock Options and Warrants		—			16,960
Net Cash Provided by Financing Activities		47,972,398			46,319,211
NET INCREASE IN CASH AND CASH EQUIVALENTS		19,355,334			10,867,941
CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD		13,927,267			11,358,520
CASH AND CASH EQUIVALENTS – END OF PERIOD	$	33,282,601		$	22,226,461
Supplemental Disclosure of Cash Flow Information
Cash Paid During the Period for Interest	$	1,107,293		$	1,350,000
Cash Paid During the Period for Income Taxes	$	—		$	—
Non-Cash Financing and Investing Activities:
Oil and Natural Gas Properties Property Accrual in Accounts Payable	$	35,936,773		$	4,327,968
Stock-Based Compensation Capitalized to Oil and Natural Gas Properties	$	493,085		$	289,277
Capitalized Asset Retirement Obligations	$	112,169		$	72,365
Non-Cash Business Acquisitions
Oil and Natural Gas Properties	$	40,787,238		$	—
Other Property and Equipment	$	36,000		$	—
Other Assets	$	75,000		$	—
Fair Market Value of Common Stock Issued	$	13,380,500		$	—
Debt Assumed	$	20,303,903		$	—

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

3

EMERALD OIL, INC.

 (FORMERLY VOYAGER OIL & GAS, INC.)
Notes to Condensed Consolidated Financial Statements
Unaudited

NOTE 1  ORGANIZATION AND NATURE OF BUSINESS

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

The Company has historically participated in well development as a non-operator and is in the process of building operations to plan and design well development as an operator on acreage where a controlling interest is held. The Company had 12 employees as of September 30, 2012 and retains independent contractors to assist in operating and managing its prospects as well as to carry out the principal and necessary functions incidental to the oil and natural gas business. With the acquisition of Emerald Oil, Inc. (“Target”) on July 26, 2012 (see Note 3 – Acquisition of Business), the Company has added executive management that is experienced in well development and intends to build on these capabilities internally and through partnering with others to leverage best practices. Production from oil wells has increased significantly, and the Company intends to add to this production by operating its own wells, while continuing to participate as a non-operator in wells managed by other operators.

NOTE 2  SIGNIFICANT ACCOUNTING POLICIES

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

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

Reverse Stock Split

The Company’s board of directors approved, subject to shareholder approval, a 1-for-7 reverse stock split pursuant to which all shareholders of record received one share of common stock for each seven shares of common stock owned (subject to minor adjustments as a result of fractional shares). On October 22, 2012, a majority of the Company’s shareholders approved the reverse stock split. This reverse stock split decreased the issued and outstanding shares by approximately 140,339,000, the outstanding warrants by approximately 6,700,000 and the outstanding stock options by approximately 4,100,000. GAAP requires that the reverse stock split be applied retrospectively to all periods presented. As a result, all stock, warrant and option transactions described herein have been adjusted to reflect the 1-for-7 reverse stock split.

4

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 September 30, 2012 due to a temporary federal program in effect from December 31, 2010 through December 31, 2012. Under the program, there is no limit to the amount of insurance for eligible accounts. Beginning 2013, insurance coverage will revert to $250,000 per depositor at each financial institution, and the Company’s non-interest bearing cash balances may then exceed federally insured limits. In addition, the Company is subject to Security Investor Protection Corporation 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 $12,345 and $10,849 for the three-month periods ended September 30, 2012 and 2011, respectively. Depreciation expense was $34,559 and $19,761 for the nine-month periods ended September 30, 2012 and 2011, respectively.

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

Asset Retirement Obligations

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

Revenue Recognition and Natural Gas Balancing

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

Stock-Based Compensation

The Company has accounted for stock-based compensation under the provisions of ASC 718-10-55. The Company recognizes stock-based compensation expense in the financial statements over the vesting period of equity-classified employee stock-based compensation awards based on the grant date fair value of the awards, net of estimated forfeitures. For options and warrants, the Company uses the Black-Scholes option valuation model to calculate the fair value of stock based compensation awards at the date of grant. Option pricing models require the input of highly subjective assumptions, including the expected price volatility. For the stock options and warrants granted the Company has used a variety of comparable and peer companies to determine the expected volatility input based on the expected term of the options. The Company believes the use of 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.

5

On May 27, 2011, the shareholders of the Company approved the Voyager Oil & Gas, Inc. 2011 Equity Incentive Plan (the “2011 Plan”) under which 714,286 shares of common stock were 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 September 30, 2012, 624,281 of the 714,286 shares of common stock reserved were issued to directors, officers and employees under the 2011 Plan. As of September 30, 2012, the Company had granted 107,144 options to officers and employees contingent on the shareholders of the Company approving an amendment to the 2011 Plan for an additional 2,785,714 shares to be reserved under the 2011 Plan. An amendment was approved by our shareholders on October 22, 2012.

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 nine-month periods ended September 30, 2012 and September 30, 2011, the potentially dilutive shares were anti-dilutive and were thus not added into the earnings per share calculation.

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

Restricted Stock and Restricted Stock Units	110,000
Stock Options	686,286
Stock Warrants	1,116,150
Total Potentially Anti-Dilutive Shares	1,912,436

6

Full Cost Method

The Company follows the full cost method of accounting for oil and natural gas operations whereby all costs related to the exploration and development of oil and natural gas properties are initially capitalized into a single cost center (“full cost pool”). Such costs include land acquisition costs, a portion of employee salaries related to property development, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities. For the three- and nine-month periods ended September 30, 2012, the Company capitalized $151,719 and $624,818, respectively, of internal salaries, which included $97,317 and $493,085, respectively, of stock-based compensation. For the three- and nine-month periods ended September 30, 2011, the Company capitalized $192,836 and $346,044, respectively, of internal salaries, which included $155,061 and $289,277, respectively, of stock-based compensation. Internal salaries are capitalized based on employee time allocated to the acquisition of leaseholds and development of oil and natural gas properties. The Company capitalized interest of $305,590 and $362,688 for the three- and nine-month periods ended September 30, 2012, respectively. The Company did not capitalize interest for the three- and nine-month periods ended September 30, 2011.

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

The Company assesses all items classified as unevaluated property on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. For the three- and nine-month periods ended September 30, 2012, the Company had no costs that were transferred to the full cost pool related to impairment. For the year ended December 31, 2011, the Company transferred $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 consolidated statements of operations as an impairment charge. The Company recognized an impairment expense in the three- and nine-month periods ended September 30, 2012 in the amount of $0 and $10,191,234, respectively. There was no impairment expense recognized in the three- and nine-month periods ended September 30, 2011.

Commodity Derivative Instruments

The Company has entered into commodity derivative instruments utilizing “no premium” collars and price swaps 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 consolidated 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 commodity derivatives line on the condensed consolidated 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 (see Note 14 – Derivative Instruments and Price Risk Management).

7

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

Use of Estimates

The preparation of consolidated 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.

Principles of Consolidation

The accompanying condensed consolidated financial statements include the accounts of Emerald Oil, Inc. and its direct and indirect wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated.

NOTE 3 ACQUISITION OF BUSINESS

On July 9, 2012, the Company entered into a Securities Purchase Agreement (the “Purchase Agreement”) with Emerald Oil & Gas NL (the “Parent”) and Target, a wholly owned subsidiary of the Parent pursuant to which the Company purchased all of the outstanding capital stock of Target for approximately 19.9% of the total shares of Voyager common stock outstanding as of the closing date. The Company completed the acquisition of Target on July 26, 2012 and issued approximately 1.66 million shares to the Parent, of which 71,428 shares are being held in escrow pending resolution of certain title defects. The Company assumed Target’s liabilities, including approximately $20.2 million in debt owed by Target. The acquisition included approximately 10,600 net acres located in Dunn County, North Dakota and approximately 45,000 net acres in the Sandwash Basin Niobrara shale oil play in northwestern Colorado and southwestern Wyoming.

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

Target’s $20.2 million in debt obligations assumed by the Company was comprised of $17.7 million to Hartz Energy Capital, LLC (“Hartz”) and $2.5 million plus accrued interest to Parent. Both were paid in full on September 28, 2012.

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Interest on the Hartz credit agreement was in the form of an overriding royalty interest in and to all of the oil, gas and other liquid hydrocarbons produced and saved from certain of the Company’s oil and natural gas properties, free of any and all expenses of development, production, transportation, marketing and any other related or similar expenses. The initial credit agreement included a 2.15% overriding royalty interest on Target’s properties in the Williston Basin of North Dakota. In accordance with the amended credit agreement, interest on the credit agreement was expanded to include a 0.9% overriding royalty interest in and to all of the oil, gas and other liquid hydrocarbons produced and saved from the Company’s properties in the Green River Basin of Colorado and Wyoming. 

The acquisition has been accounted for using the acquisition method. Assets acquired and liabilities assumed were recorded at their estimated fair values as of the acquisition date. The allocation of the purchase price is based upon a valuation of certain assets acquired and liabilities assumed. A summary of the acquisition is below:

	(in thousands)
Proved Oil and Natural Gas Properties	$	6,839
Unproved Oil and Natural Gas Properties		33,948
Other Assets		111
Total Assets		40,898
Debt Assumed		(20,303	)
Equity Issued to Emerald Oil NL		(13,381	)
Total Liabilities Assumed and Equity Issued		(33,684	)
Gain on Acquisition		7,214
Less: Acquisition Costs		(1,444	)
Gain on Acquisition, net	$	5,770

Pro Forma Operating Results

From July 26, 2012 to September 30, 2012, the Company recognized $39,398 in revenues and $58,451 of expenses relating to Target, resulting in a net loss effect during the three and nine months ended September 30, 2012 of $19,053.

The following table reflects the unaudited pro forma results of operations as though the acquisition had occurred on January 1, 2011. The pro forma amounts are not necessarily indicative of the results that may be reported in the future:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Revenues	$	5,476,134		$	2,935,862		$	18,781,520		$	5,464,447
Net income (loss)	$	(4,070,652	)	$	(221,699	)	$	(13,503,967	)	$	3,950,809
Net income (loss) per share - basic	$	(0.39	)	$	(0.02	)	$	(1.34	)	$	0.41
Net income (loss) per share – diluted	$	(0.39	)	$	(0.02	)	$	(1.34	)	$	0.40
Weighted Average Shares Outstanding:
Basic		10,420,683			9,859,248			10,099,762			9,610,544
Diluted		10,420,683			9,859,248			10,099,762			9,824,616

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NOTE 4  OIL AND NATURAL GAS PROPERTIES

The value of the Company’s oil and natural gas properties consists of all acreage acquisition costs (including cash expenditures and the value of stock consideration), drilling costs and other associated capitalized costs.  Acquisitions are accounted for as purchases and, accordingly, the results of operations are included in the accompanying condensed consolidated statements of operations from the closing date of the acquisition.  Purchase prices are allocated to acquired assets based on their estimated fair value at the time of the acquisition.  In the past, acquisitions have been funded with internal cash flow and the issuance of equity securities.

Acquisitions

For the nine months ended September 30, 2012, the Company acquired approximately 12,416 net mineral acres in the Williston Basin targeting the Bakken and Three Forks formations for an average cost of approximately $1,340 per net acre including the acreage acquired as a result of the acquisition of Target.

The Company also acquired approximately 45,100 net mineral acres in the Sandwash Basin of northwestern Colorado and southwestern Wyoming targeting the Niobrara as a result of the acquisition of Target (See Note 3 – Acquisition of Business).

Sandwash Basin – Niobrara

The Company owns approximately 45,100 net mineral acres in the Sand Wash Basin of the Greater Green River Basin prospective for the Niobrara oil shale and other secondary target formations known to contain oil and natural gas. The assets include certain existing oil and gas wells and a 6-inch diameter natural gas gathering pipeline extending approximately 18.5 miles in length from our natural gas production facilities located in Moffat County, Colorado, to a Questar pipeline connection located near the town of Baggs in Carbon County, Wyoming. These assets were acquired in conjunction with the acquisition of Target on July 26, 2012 (see Note 3 – Acquisition of Business).

The assets are governed by a participation agreement (the “Participation Agreement”) with Entek GRB LLC, a subsidiary of Entek Energy Ltd, a publicly traded Australian exploration and production company. Under the Participation Agreement, the Company and Entek have agreed to jointly develop each party’s respective leasehold interests within a designated area of mutual interest, referred to as the Green River Basin AMI. The collective leasehold interest of the Company and Entek in the Green River Basin AMI is owned 45% by the Company and 55% by Entek, and Entek is the operator of the properties.

The leasehold interests owned by Emerald and Entek in the Green River Basin AMI cover two main areas: the Focus Ranch Unit, a federal oil and gas exploratory unit covering approximately 45,100 gross acres in Routt County, Colorado; and an area extending to the northwest known as the Fly Creek Prospect, covering approximately 67,000 gross acres in Moffat County, Colorado and Carbon County, Wyoming. We own approximately 14,500 net mineral acres in the Focus Ranch Unit and approximately 26,100 net mineral acres in the remaining area.

Big Snowy Joint Venture

In October 2008, the Company entered into the Big Snowy Joint Venture Agreement with an administrator third-party to acquire certain oil and natural gas leases in the Heath shale oil play in Musselshell, Petroleum, Garfield, Rosebud and Fergus Counties in 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 September 30, 2012. The Company is committed to a minimum of $1,000,000 and a maximum of $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 September 30, 2012. The unutilized cash balance was $11,790 as of September 30, 2012.

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Niobrara Development with Slawson Exploration Company, Inc.

As of September 30, 2012, the Company held approximately 2,100 net acres in Weld County, Colorado and Laramie County, Wyoming, with 1,440 net acres currently held by production with Slawson Exploration Company, Inc. (“Slawson”). The Company currently has no plans for drilling any additional development wells under this development program during 2012.

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 September 30, 2012. The Company initially committed to a minimum of $1,000,000 toward this joint venture. An amendment to the joint venture agreement was executed in April 2011 to remove the maximum amount committed under the joint venture. The Company is not committed to any further capital obligations under the joint venture. The third-party joint venture partner issues cash calls during the year to replenish the joint venture cash account. The Company’s contributions to the joint venture totaled $4,214,441 as of September 30, 2012, consisting of $1,940,054 in leasing costs, $1,346,925 in seismic costs and $804,155 in drilling costs. The unutilized cash balance was $123,307 as of September 30, 2012.

Tiger Ridge Joint Venture

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

NOTE 5  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 consolidated financial statements. Mr. Lipscomb is a former director of the Company. Mr. Reger is a brother of J.R. Reger, who is Executive Chairman of the Company and formerly the Chief Executive Officer. The Company’s Audit Committee, which consisted solely of independent directors, reviewed and approved this transaction. The senior secured promissory notes were paid in full on February 10, 2012.

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

NOTE 6  PREFERRED AND COMMON STOCK

Stock Awards and Stock Unit Awards

In March 2012, the Company issued an aggregate of 14,286 shares of common stock to executives of the Company as compensation for their services. The shares were fully vested on the date of the grant. The fair value of the stock issued was approximately $294,000 or $20.58 per share, the market value of a share of common stock on the date the stock was issued. The Company expensed $160,718 in share-based compensation related to these grants in the nine-month period ended September 30, 2012. The remainder of the fair value of these grants was capitalized into the full cost pool.

In July 2012, the Company issued an aggregate of 35,714 shares of common stock to executives of the Company as compensation for their services. The shares were fully vested on the date of the grant. The fair value of the stock issued was approximately $280,000 or $7.84 per share, the market value of a share of common stock on the date the stock was issued. The Company expensed $265,767 in share-based compensation related to these grants in the three- and nine-month periods ended September 30, 2012. The remainder of the fair value of these grants was capitalized into the full cost pool.

In March 2012, the Company issued an aggregate 85,714 shares of restricted common stock as compensation to its officers, of which 32,142 restricted shares had vested prior to the acquisition of Target. The officers forfeited the remaining 53,572 shares of restricted common stock as part of the acquisition of Target.

In May 2012, the Company issued 2,858 shares of restricted common stock as compensation to an employee, which shares vest equally over two years on May 11, 2013 and May 11, 2014. As of September 30, 2012, there was approximately $34,000 of unrecognized compensation expense related to unvested restricted stock. The Company will recognize compensation expense over the remaining vesting period of the restricted stock grant. The Company has assumed a 0% forfeiture rate for the restricted stock.

In July 2012, the Company issued 107,142 restricted stock units as compensation to its officers and certain employees. Unvested restricted stock units vest 35,714 on each of July 26, 2013, 2014 and 2015. As of September 30, 2012, there was approximately $793,000 of unrecognized compensation expense related to unvested restricted stock units. The Company will recognize compensation expense over the remaining vesting period of the restricted stock units. The Company has assumed a 0% forfeiture rate for the restricted stock units.

The Company incurred compensation expense associated with restricted stock and restricted stock units granted in 2012 of $335,240 and $526,771 for the three and nine months ended September 30, 2012, respectively. The Company incurred compensation expense associated with restricted stock granted prior to 2012 of $21,707 and $100,791 for the three and nine months ended September 30, 2011, respectively. For the three and nine months ended September 30, 2012, the Company capitalized compensation expense associated with the restricted stock and restricted stock units of $21,137 and $175,219 to oil and natural gas properties, respectively.

Equity Offering

On September 28, 2012, the Company completed a public offering of 13,392,857 shares of common stock at a price of $5.60 per share for total gross proceeds of $75 million.  The Company incurred costs of approximately $5.1 million related to this transaction, which costs were netted against the proceeds of the transaction through additional paid-in capital. The underwriters elected to exercise the over-allotment option to sell an additional 484,698 shares of common stock at $5.60 per share. The gross proceeds from the over-allotment exercise were $2.7 million, and the net proceeds are approximately $2.5 million after deducting underwriting discounts and commissions. The over-allotment exercise closed on October 26, 2012.

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NOTE 7  STOCK OPTIONS AND WARRANTS

Stock Options

On January 6, 2012, the Company granted stock options to an employee to purchase a total of 3,571 shares of common stock exercisable at $18.55 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 50,000 shares of common stock exercisable at $17.01 per share. The total fair value of the options was calculated using the Black-Scholes valuation model based on factors present at the time the options were granted. The Company has assumed a 10% forfeiture rate on these options. The options vest over one year with all of the options vesting on the anniversary date of the grant.

On May 23, 2012, the Company granted stock options to an employee to purchase a total of 35,714 shares of common stock exercisable at $12.39 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 30 months with 14,286 options vesting on May 23, 2013 and 2014 and 7,142 options vesting on November 23, 2014.

On May 24, 2012, the Company granted stock options to non-employee directors to purchase a total of 17,857 shares of common stock exercisable at $13.30 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 fully vested on the closing date of the acquisition of Target.

On July 26, 2012, the Company granted stock options to officers and certain employees to purchase a total of 428,572 shares of common stock exercisable at $7.84 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 forfeiture rate of 0% to 15% on these options. Twenty-five percent, or options to purchase 107,143 shares of common stock, vested immediately on the grant date, and the remaining options vest equally over 36 months with 107,143 options vesting on July 26, 2013 and 2014 and 2015.

On July 26, 2012 upon closing the acquisition of Target, 80,353 options granted to the former non-employee directors of the Company became fully vested. The vesting of these options is considered a modification under GAAP. The fair value of the options calculated on the modification date was less than the remaining unamortized expense to be reported on the options. The Company expensed the remaining grant date fair value in the three month period ended September 30, 2012.

The impact on our condensed consolidated statement of operations of stock-based compensation expense related to options granted for the three-month periods ended September 30, 2012 and 2011 was $1,707,732 and $62,719, respectively, net of $0 tax. The impact on our condensed consolidated statement of operations of stock-based compensation expense related to options granted for the nine-month periods ended September 30, 2012 and 2011 was $2,083,360 and $250,411, respectively, net of $0 tax. The Company capitalized $76,180 and $184,586 in compensation related to outstanding options for the three and nine months ended September 30, 2012, respectively.

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

Risk free rates	0.58% to 1.20%
Dividend yield	0%
Expected volatility	72.48% to 78.99%
Weighted average expected life	5 to 7 years

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

· No options were exercised.

· No options were forfeited.

· No options expired.

· The Company will recognize approximately $1.8 million of compensation expense in future periods relating to options that have been granted but have not vested as of September 30, 2012.

· There were 410,714 unvested options at September 30, 2012.

Warrants

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

	Warrants		Exercise Price		Expiration Date
December 1, 2009		37,216	$	6.86		December 1, 2019
December 31, 2009		186,077	$	6.86		December 31, 2019
February 8, 2011		892,857	$	49.70		February 8, 2016
		1,116,150

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

NOTE 8  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 DJ 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 (“Facility”) with Macquarie Bank Limited (“MBL”) (see Note 9 – Revolving Credit Facility). The remaining unamortized finance costs of $217,809 were written off to interest expense in the nine months ended September 30, 2012.

NOTE 9 REVOLVING CREDIT FACILITY

On February 10, 2012, the Company entered into the Facility. 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 September 30, 2012, the Company had borrowed $15 million under Tranche A. As of September 30, 2012, $7.7 million was undrawn and available under Tranche B.

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

The Company has the option to designate the reference rate of interest for each specific borrowing under the Facility as amounts are advanced. Under Tranche A, borrowings designated to be based upon the London Interbank Offered Rate (“LIBOR”) bear interest at a rate equal to LIBOR plus a spread ranging from 2.75% to 3.25%, depending on the percentage of borrowing base that is currently advanced. Any borrowings not designated LIBOR-based will bear interest at a rate equal to the current prime rate published by the Wall Street Journal plus a spread ranging from 1.75% to 2.25%, depending on the percentage of borrowing base that is currently advanced. The Company has the option to designate either pricing mechanism. The Company’s interest rate on Tranche A is 3.482% as of September 30, 2012. Tranche B borrowing bears interest at a rate equal to LIBOR plus 7.5%. The Company’s interest rate on Tranche B is 7.732% as of September 30, 2012. Interest payments are due under the Facility in arrears; in the case of a LIBOR-based loan, on the last day of the specified interest period and in the case of all other loans on the last day of each March, June, September and December. All outstanding principal is due and payable upon termination of the Facility.

On July 26, 2012, the Company entered into an amended and restated credit agreement with MBL to expand the existing availability and outstanding balance under its existing credit facility. In addition to the $20.2 million of debt obligations related to the acquisition of Target that remained outstanding through existing agreements, the Company obtained additional availability from its Facility and drew $15 million of additional debt on a new third tranche at an initial rate of 9% above the applicable LIBOR and has the potential to draw a maximum of $20 million. The $15 million drawn was used for existing development activities and was paid in full with proceeds from the equity offering completed on September 28, 2012. There are no borrowings under Tranche B and C as of September 30, 2012.

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

The Facility requires that the Company enter into hedging agreements with MBL for each month of the 36-month period following the date on which each such hedge agreement is executed, the notional volumes for which, when aggregated with other commodity derivative agreements and additional fixed-price physical off-take contracts then in effect are not less than 50%, nor greater than 90%, of the reasonably anticipated projected production from our proved developed producing reserves. The Facility also requires the Company to maintain certain financial ratios, including current ratio (at least 1.00 to 1.00), debt coverage ratio (no more than 3.50 to 1.00), interest coverage ratio (at least 2.50 to 1.00) and a ceiling on general and administrative expenses (no more than $500,000 per fiscal quarter, excluding certain non-cash, audit and engineering-related expenses), commencing on March 31, 2012. The Company was not in compliance with the general and administrative expenses ceiling covenants as of September 30, 2012, and a waiver was obtained from MBL. Exceeding the general and administrative expense ceiling was primarily attributable to the addition of executives through the acquisition of Target and building operations to plan and design well development as an operator.

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.

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NOTE 10  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 nine months ended September 30, 2012 and the year ended December 31, 2011:

	September 30, 2012		December 31, 2011
Beginning Asset Retirement Obligation	$	116,119	$	10,522
Liabilities Incurred for New Wells Placed in Production		112,169		100,715
Accretion of Discount on Asset Retirement Obligations		10,027		4,882
Ending Asset Retirement Obligation	$	238,315	$	116,119

NOTE 11  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 September 30, 2012, the Company maintains a full valuation allowance for all deferred tax assets.  Based on these requirements no provision or benefit for income taxes has been recorded for deferred taxes. There were no recorded unrecognized tax benefits at the end of the reporting period.

NOTE 12 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 or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.

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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 consolidated balance sheet as of September 30, 2012:

	Fair Value Measurements at September 30, 2012 Using
	Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity Derivatives – Current Liability (crude oil swaps and collars)	$	—	$	(298,440	)	$	—
Commodity Derivatives – Long Term Asset (crude oil swaps and collars)		—		61,794			—
Total	$		$	(236,646	)	$

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

Level 2 assets consist of commodity derivative assets and liabilities (See Note 14 – Derivative Instruments and Price Risk Management).  The fair value of the commodity derivative assets and liabilities are 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 consolidated balance sheet.

NOTE 13 FINANCIAL INSTRUMENTS

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

NOTE 14 DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT

The Company utilizes commodity swap contracts and 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 consolidated 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 commodity derivatives line on the condensed consolidated 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 consolidated balance sheet and the non-current asset and liability are netted on the condensed consolidated balance sheet.

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The Company realized a loss on settled derivatives of $120,706 and $59,681 and a loss on mark-to-market of derivatives instruments of $1,514,729 and $236,646 for the three and nine months ended September 30, 2012, respectively. The Company did not enter into derivative instruments prior to 2012.

The following table reflects open commodity swap contracts as of September 30, 2012, the associated volumes and the corresponding weighted average NYMEX reference price.

Settlement Period	Oil (Barrels)		Fixed Price		Weighted Avg NYMEX Reference Price
Oil Swaps
October 1, 2012  - January 31, 2015		157,205		88.00		92.70

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 September 30, 2012.

Term	Oil (Barrels)		Price		Basis
Costless Collars
October 1, 2012 – February 28, 2015		159,722	$	90.00–$103.50	NYMEX

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

Type of Contract	Balance Sheet Location
Derivative Assets:
Costless Collars	Current assets	$	462,602
Costless Collars	Non-current assets		867,737
Total Derivative Assets		$	1,330,339
Derivative Liabilities:
Costless Collars	Current liabilities	$	(284,506	)
Costless Collars	Non-current liabilities		(543,307	)
Swap Contracts	Current liabilities		(476,536	)
Swap Contracts	Non-current liabilities		(262,636	)
Total Derivative Liabilities		$	(1,566,985	)
Net Derivative Position		$	(236,646	)

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

NOTE 15 COMMITMENTS AND CONTINGENCIES

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

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NOTE 16 SUBSEQUENT EVENTS

In addition to the 1-for-7 reserve stock split noted in Note 2 – Acquisition of Business, the following events and transactions occurred subsequent to September 30, 2012.

Special Shareholder Meeting

On October 22, 2012, the Company held a special meeting of its shareholders. The Company’s shareholders approved the Articles of Amendment to the Articles of Incorporation of the Company to (i) effect a name change of the Company to Emerald Oil, Inc., (ii) effect a 1-for-7 reverse stock split of the Company’s common stock, and (iii) increase the aggregate number of authorized shares of common stock available for issuance to 500,000,000.

On October 22, 2012, the Company filed the Articles of Amendment with the Montana Secretary of State to effect the name change, the reverse stock split and the authorized share increase. The Articles of Amendment became effective upon its filing with the Montana Secretary of State. As a result of the reverse stock split, every seven outstanding shares of the Company’s common stock combined automatically into one share of common stock. Each shareholder’s percentage ownership in the Company and proportional voting power remains unchanged after the reverse stock split, except for minor changes and adjustments resulting from the treatment of fractional shares. As a result of the reverse stock split, adjustments were automatically made to certain terms of certain of the Company’s outstanding securities, including its outstanding options, restricted stock, restricted stock units and warrants.

The Company’s shareholders also approved a proposal to amend the 2011 Plan to increase the number of shares of the Company’s common stock authorized for issuance under the 2011 Plan to 24,500,000 shares. As a result of the reverse stock split, the number of shares of common stock now available for issuance under the 2011 Plan is 3,500,000 shares.

McKenzie Acquisition

On October 5, 2012 the Company acquired 4,453 net acres in McKenzie County, North Dakota for $3,200 per acre from Slawson, under which the Company agreed to acquire certain oil and natural gas leaseholds, and various other related rights, interests, equipment and other assets. The effective time for the transfer of the leases was September 1, 2012. The purchase included operating permits for additional wells and a recently constructed well pad and tank battery at an additional cost of $1.18 million, for a total cash purchase price of $15.4 million.

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

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

Overview

Emerald Oil, Inc., a Montana corporation (“Emerald,” the “Company,” “we,” “us,” or “our”), is a Denver-based independent exploration and production company focused primarily on the development of our approximately 48,800 net acres in the Williston Basin in North Dakota and Montana. We have identified approximately 267 net potential drilling locations on this acreage prospective for oil in the Bakken and Three Forks formations. The majority of our capital expenditures in 2012 and 2013 are expected to be directed toward drilling operated and non-operated Bakken and Three Forks wells. We plan to leverage our management team’s collective extensive technical, land, financial, and industry operating experience to transition from our historical non-operated strategy to a balanced operated and non-operated approach that we believe provides superior risk-adjusted returns on capital while enhancing the strategic value of our company.

In addition to our Williston Basin position, we have also assembled significant positions in two emerging Rocky Mountain oil plays. We have approximately 45,100 net acres in the Sandwash Basin in northwest Colorado and southwest Wyoming prospective for oil in the Niobrara formation. We also have approximately 33,500 net acres in central Montana prospective for oil in the Heath formation. We do not plan to allocate substantial capital to either of these areas in 2012 or 2013. However, we may increase Sandwash Basin appraisal activity in 2013 in areas with demonstrated production potential. With our multi-year lease terms in both areas, we believe we are well-positioned to monitor the significant offset operator activity that we believe may ultimately mitigate geologic risk and further evaluate the prospectivity of both oil plays. In addition to these emerging oil plays, we also have approximately 74,700 net acres in the Tiger Ridge Field located in Blaine, Hill, and Chouteau Counties, Montana, prospective for natural gas, and another approximately 2,100 net acres in the Denver-Julesburg Basin (“DJ Basin”) in Weld County, Colorado.

As of September 30, 2012 our oil and natural gas production is derived from participation in wells as a non-operating partner, primarily on a heads-up, or pro rata, basis proportionate to our working interest, allowing us to participate with established operators in well economics that have high return potential with relatively low overhead cost. On July 9, 2012, we entered into a Securities Purchase Agreement (the “Purchase Agreement”) with Emerald Oil & Gas NL (the “Parent”) and Emerald Oil, Inc. (“Target”), a wholly owned subsidiary of the Parent, pursuant to which we purchased all of the outstanding capital stock of Target for approximately 19.9% of the total shares of our common stock outstanding as of the closing date. We completed the acquisition of Target on July 26, 2012 and issued approximately 1.66 million of our shares of common stock to the Parent of which 71,428 shares are being held in escrow by the Company pending resolution of certain title defects. As part of the acquisition, we agreed to maintain Target’s liabilities, including approximately $20.2 million in debt owed by Target. Included in the acquisition were approximately 10,600 net acres located in Dunn County, North Dakota and approximately 45,000 net acres in the Sandwash Basin Niobrara shale oil play in northwestern Colorado and southwestern Wyoming. In connection with the closing of the acquisition, five existing members of our board of directors resigned, and their vacancies were filled with directors selected by the remaining members of our board of directors. Also in connection with the closing of the Emerald acquisition, we entered into employment agreements with six officers, J.R. Reger (Executive Chairman—formerly our Chief Executive Officer), Mike Krzus (Chief Executive Officer), McAndrew Rudisill (President), Paul Wiesner (Chief Financial Officer), Karl Osterbuhr (Vice President of Exploration and Business Development) and Mitchell R. Thompson (Chief Accounting Officer—formerly our Chief Financial Officer).

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

We intend to trade or swap our acreage with other operators to increase our operating acreage or potential working interests in areas where we have existing acreage. Most trades are for comparable acreage and mutually beneficial for both parties as we consolidate and increase our working interests.

Recent Events

Equity Offering

On September 28, 2012, we completed a public offering of 13,392,857 shares of common stock to the public at $5.60 per share. The gross proceeds from the offering were $75 million, and the net proceeds were approximately $69.9 million, after deducting underwriting discounts and commissions and other offering expenses. The sale of the shares of common stock closed on September 28, 2012. The underwriters elected to exercise the over-allotment option to sell an additional 484,698 shares of common stock at $5.60 per share. The gross proceeds from the over-allotment exercise were $2.7 million, and the net proceeds are approximately $2.5 million after deducting underwriting discounts and commissions. The over-allotment exercise closed on October 26, 2012.

We used a portion of the net proceeds from this offering, along with cash on hand, to repay a portion of outstanding indebtedness and for additional operable leasehold acquisitions. We intend to use the remaining proceeds to fund drilling and development expenditures in the Williston Basin and for general corporate purposes, including working capital.

McKenzie County Acquisition

On October 5, 2012 we acquired 4,453 net acres in McKenzie County, North Dakota for $3,200 per acre from Slawson Exploration Company, Inc. (“Slawson”). Under the terms of the purchase agreement, we agreed to acquire certain oil and gas leaseholds, and various other related rights, interests, equipment and other assets. The effective time for the transfer of the leases was September 1, 2012. The purchase included operating permits for four wells and a recently constructed well pad and tank battery at an additional cost of $1.18 million, for a total cash purchase price of $15.4 million.

Special Shareholder Meeting

On October 22, 2012, we held a special meeting of our shareholders. Our shareholders approved the Articles of Amendment to the Articles of Incorporation of the Company to (i) effect a name change of the Company to Emerald Oil, Inc., (ii) effect a 1-for-7 reverse stock split of our common stock, and (iii) increase the aggregate number of authorized shares of common stock available for issuance to 500,000,000.

On October 22, 2012, we filed the Articles of Amendment with the Montana Secretary of State to effect the name change, the reverse stock split and the authorized share increase. The Articles of Amendment became effective upon its filing with the Montana Secretary of State. As a result of the reverse stock split, every seven outstanding shares of our common stock combined automatically into one share of common stock. Each shareholder’s percentage ownership and proportional voting power remains unchanged after the reverse stock split, except for minor changes and adjustments resulting from the treatment of fractional shares. As a result of the reverse stock split, adjustments were automatically made to certain terms of certain of our outstanding securities, including its outstanding options, restricted stock, restricted stock units and warrants.

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Our shareholders also approved a proposal to amend our 2011 Equity Incentive Plan (the “2011 Plan”) to increase the number of shares of our common stock authorized for issuance under the 2011 Plan to 24,500,000 shares. As a result of the reverse stock split, the number of shares of common stock now available for issuance under the 2011 Plan is 3,500,000 shares.

Assets and Acreage Holdings

We currently controlled approximately 200,000 net acres in the following five primary prospect areas:

· 48,800 net acres in the Williston Basin targeting the Bakken and Three Forks shale oil formations in North Dakota and Montana;

· 45,100 net acres in the Green River Basin targeting the Niobrara shale oil formations in Colorado and Wyoming;

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

· 2,100 net acres in the Denver-Julesburg Basin targeting the Niobrara shale oil formation in Colorado and Wyoming; and

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

Williston Basin — Bakken and Three Forks

The Williston Basin is one of the largest oil resource plays in North America and has been the focus of extensive industry activity over the last several years. As of November 1, 2012, according to the North Dakota Industrial Commission, 186 rigs were drilling in the basin, and since the application of modern horizontal drilling techniques began in 2007, thousands of Bakken and Three Forks wells have been drilled throughout the basin. We believe that this industry activity, including drilling activity, in close proximity to our leasehold, has substantially mitigated the geologic risks of our anticipated drilling locations. The Williston Basin is geologically and aerially well-defined, and almost all of our approximately 48,800 net acres are positioned within McKenzie, Dunn, Williams and Mountrail Counties, North Dakota, and Richland County, Montana, which are all generally recognized as being prospective for both the Bakken and Three Forks formations.

At present, our Williston Basin acreage position consists of approximately 16,000 net operated acres in McKenzie and Dunn Counties, North Dakota and Richland County, Montana where we have either secured operatorship through approved drilling permits or we believe we have sufficient working interests to claim operatorship in individual drilling spacing units pending approval of drilling permit applications. In addition, we hold approximately 2,200 net acres in Williams and McKenzie Counties in North Dakota and Richland County in Montana, with working interests that we believe are sufficient to enable us to claim operatorship if we can achieve modest increases through continued acreage acquisitions and swaps. Our remaining acreage position consists of approximately 30,600 net acres in Williams, McKenzie, Dunn and Mountrail Counties in North Dakota, and Richland County, Montana, where we hold relatively low working interests and expect to continue to maintain our non-operated working interests or to utilize such leasehold to consolidate our operated working interests in current or future selected core focus areas.

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We are currently in the process of optimizing our participation in our non-operated acreage. While we cannot control the timing of capital expenditures for our non-operated properties, we may choose to selectively participate in proposed wells, based on our internal capital return criteria and our internal geologic knowledge. We consider the experience gained from our non-operated interests to be valuable due to the high quality of the operators. These interests have allowed and will continue to allow us to leverage valuable technical data across the basin in order to analyze our election to participate in what we believe to be the most economic wells. The amount of detailed, well-specific data we have acquired as a result of our participation in approximately 200 gross non-operated wells to date, together with publicly available information, has allowed us to compile a valuable database of well information that we use to select our operated development areas and formulate optimal well designs.

Using industry-accepted well down-spacing assumptions, we believe there could be over 267 net potential drilling locations on our acreage prospective for oil in the Bakken and Three Forks formations. Consistent with such assumptions, we believe that each 1,280-acre unit can support approximately four Bakken and three Three Forks well locations. We plan to embark on an aggressive drilling program to convert our substantial undeveloped operated leasehold position to production, cash flow and reserves. For the 15-month period ending December 31, 2013, we plan to spend approximately $72.5 million on well development in the Williston Basin. Specifically, we plan to spend approximately $55.0 million to drill 5.0 net operated wells at an average estimated cost of $11.0 million per well and approximately $17.5 million to participate in 1.9 net non-operated wells at an average estimated cost of $9.2 million per well.

The following table presents summary data for our Williston Basin project area as of November 8, 2012:

					Planned Capital Expenditures*
	Net Acres		Net Identified Drilling Locations		Net Wells		Drilling Capex
Operated		16,000		88		5.0	$	55.0
Non-Operated		32,800		179		1.9	$	17.5
Total Williston Basin		48,800		267		6.9	$	72.5

* October 1, 2012 through December 31, 2013

Sandwash Basin – Niobrara

As of September 30, 2012, we own an interest in approximately 45,100 net acres in the Sandwash Basin prospective for the Niobrara formation in northwestern Colorado and southwestern Wyoming. Four experimental single-stage fracturing treatments were completed with limited success in three tightly-spaced appraisal wells drilled in 2011, using various well completion designs during 2012. Appraisal activities for the 2013 program will focus on areas that have historically demonstrated significant oil and gas flows. With our multi-year lease terms, we believe we are well-positioned to monitor the significant offset operator activity that we believe will enable us to further mitigate geologic risk and assist us to evaluate the prospectivity of the oil play. Most of our leases in the Sandwash Basin expire after 2014, providing the opportunity to monitor offset operator drilling activity and well results before committing capital to a significant drilling program. We are encouraged by competitor announcements of substantial drilling plans and initial production rates in the Sandwash Basin over 500 Boe/d in one horizontal well and vertical well completions producing over 100 Boe/d.

Big Snowy Joint Venture — Heath Shale Oil

As of September 30, 2012, we own an interest in approximately 33,500 net acres located in central Montana as part of a joint venture targeting the Heath shale oil. We have begun to see substantial permitting activity and drilling in the area. We believe the Heath shale has similar characteristics to the Bakken and Three Forks formations, and several of the same development partners are operating in the area. Our five-year primary term leases have three-year extension options that will allow us to hold our leases with minimal incremental capital into 2017.

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DJ Basin — Niobrara

As of September 30, 2012, we own an interest in approximately 2,100 net acres in Weld County, Colorado and Laramie County, Wyoming, with 1,400 net acres currently held by production as we continue to monitor the performance and characteristics of the producing wells. We have no plans for drilling any additional development wells in the DJ Basin under this development program during 2012.

Major Joint Venture — Tiger Ridge Natural Gas

As of September 30, 2012, we own an interest in approximately 74,700 net acres in and around the Tiger Ridge natural gas field in Montana. We participated in the drilling of two wells with Devon Energy Corporation, both of which were drilled and shut-in in 2010. We conducted a 3-D seismic program during 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 shut-in and awaiting pipeline hook-up.

Productive Wells

The following table summarizes gross and net productive oil wells by state at September 30, 2012 and 2011. A net well represents our fractional working ownership interest of a gross well. The following table also does not include 21 gross (1.08 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 September 30, 2012 and 56 gross (1.79 net) Bakken and Three Forks wells as of September 30, 2011.

	September 30,
	2012				2011
	Gross		Net		Gross		Net
North Dakota Bakken and Three Forks		160		6.39		43		1.00
Montana Bakken and Three Forks		21		1.86		3		0.66
Colorado Niobrara in DJ Basin		4		2.00		5		2.50
Total:		185		10.25		51		4.16

Exploratory Wells

In 2012, we participated in the drilling of the Johnson 31-17 SWH well in an undeveloped area of Mountrail County, North Dakota with a 3.13% working interest. The well was abandoned after experiencing poor oil shows during the drilling process. The dry hole costs associated with this well were $149,714. The costs associated with this well were included in the full cost pool and subject to the depletion base. Of the 185 gross productive wells that we have participated in we have participated in only two dry holes.

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Results of Operations

Comparison of the Three and Nine Months Ended September 30, 2012 with the Three and Nine Months Ended September 30, 2011.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
REVENUES
Oil and Natural Gas Sales	$	7,111,569		$	2,872,674		$	18,973,331		$	5,371,830
Loss on Commodity Derivatives		(1,635,435	)		—			(296,327	)		—
		5,476,134			2,872,674			18,677,004			5,371,830
OPERATING EXPENSES
Production Expenses		687,646			221,509			1,639,105			419,822
Production Taxes		809,062			241,412			2,043,671			488,793
General and Administrative Expenses		3,503,273			509,893			5,660,622			1,910,824
Depletion of Oil and Natural Gas Properties		2,818,650			1,324,771			7,977,077			2,293,099
Impairment of Oil and Natural Gas Properties		—			—			10,191,234			—
Depreciation and Amortization		12,345			10,849			34,559			19,761
Accretion of Discount on Asset Retirement Obligations		4,037			1,717			10,027			3,306
Total Expenses		7,835,013			2,310,151			27,556,295			5,135,605
INCOME (LOSS) FROM OPERATIONS		(2,358,879	)		562,523			(8,879,291	)		236,225
OTHER INCOME (EXPENSE)		4,353,721			(506,649	)		3,656,855			(1,535,182	)
INCOME (LOSS) BEFORE INCOME TAXES		1,994,842			55,874			(5,222,436	)		(1,298,957	)
INCOME TAX EXPENSE		—			—			—			—
NET INCOME (LOSS)	$	1,994,842		$	55,874		$	(5,222,436	)	$	(1,298,957	)

Revenues

The following table presents information about our revenues and produced oil and natural gas volumes during the three and nine months ended September 30, 2012, compared to the three and nine months ended September 30, 2011.  As of September 30, 2012, we were selling oil and natural gas from a total of 185 gross wells (approximately 10.25 net wells), compared to 51 gross wells (4.16 net wells) at September 30, 2011.  Revenues from sales of oil and natural gas were $7,111,569 and $18,973,331 during the three and nine months ended September 30, 2012, respectively, compared to $2,872,674 and $5,371,830 during the three and nine months ended September 30, 2011, respectively. Our production volumes increased 168% and 277% in the three and nine months ended September 30, 2012, respectively, as compared to the three and nine months ended September 30, 2011, respectively. The production primarily increased due to the addition of 6.59 net productive Bakken and Three Forks wells from October 1, 2011 to September 30, 2012. During the three and nine months ended September 30, 2012, we realized $83.56 and $85.16 average price per barrel of oil, respectively, before the effect of settled oil derivatives compared to $87.83 and $88.57 average price per barrel of oil during the three and nine months ended September 30, 2011, respectively. For the three and nine months ended September 30, 2012, crude oil represented 97% and 98% of revenues, respectively, and 93% and 94% of production volume, respectively.

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

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	Three Months Ended September 30,					Nine Months Ended September 30,
	2012			2011		2012			2011
Net Oil and Natural Gas Revenues:
Oil	$	6,916,704		$	2,818,383	$	18,636,837		$	5,309,598
Natural Gas and Other Liquids		194,865			54,291		336,494			62,232
Total Oil and Natural Gas Sales		7,111,569			2,872,674		18,973,331			5,371,830
Net Production:
Oil (Bbl)		82,775			32,088		218,833			59,948
Natural Gas and Other Liquids (Mcf)		39,648			7,387		76,662			8,990
Barrel of Oil Equivalent (Boe)		89,383			33,319		231,610			61,446
Average Sales Prices:
Oil (per Bbl)	$	83.56		$	87.83	$	85.16		$	88.57
Effect of Settled Oil Derivatives on Average Price (per Bbl)		(1.46	)		—		(0.27	)		—
Oil Net of Settled Derivatives (per Bbl)	$	82.10		$	87.83	$	84.89		$	88.57
Natural Gas and Other Liquids (per Mcf)	$	4.91		$	7.35	$	4.39		$	6.92
Barrel of Oil Equivalent with Realized Derivatives (per Boe)	$	78.21		$	86.22	$	81.66		$	87.42

	Three Months Ended September 30,					Nine Months Ended September 30,
	2012			2011		2012			2011
Net Revenues:
Total Oil and Natural Gas Sales	$	7,111,569		$	2,872,674	$	18,973,331		$	5,371,830
Realized Loss on Commodity Derivatives		(120,706	)		—		(59,681	)		—
Unrealized Loss on Commodity Derivatives		(1,514,729	)		—		(236,646	)		—
Revenues	$	5,476,134		$	2,872,674	$	18,677,004		$	5,371,830

Loss on Commodity Derivatives

Realized commodity derivative losses were $120,706 and $59,681, for the three and nine months ended September 30, 2012, respectively. Unrealized commodity derivative losses were $1,514,729 and $236,646, for the three and nine months ended September 30, 2012, respectively. There were no commodity derivates losses during the three and nine months ended September 30, 2011. Our derivatives are not designated for hedge accounting and are accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings.  Mark-to-market accounting treatment creates volatility in our revenues as unrealized gains and losses from derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying balance sheets.  As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives.  Future derivatives gains will be offset by lower future wellhead revenues. Conversely, future derivatives losses will be offset by higher future wellhead revenues based on the value at the settlement date.  At September 30, 2012, all of our derivative contracts are recorded at their fair value, which was a net liability of $236,646. We did not incur any net asset or liability with respect to derivative contracts prior to January 1, 2012.

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Expenses

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Costs and Expenses Per Boe of Production :
Production Expenses	$	7.69	$	6.65	$	7.08	$	6.83
Production Taxes		9.05		7.25		8.82		7.95
G&A Expenses (Excluding Share-Based Compensation)		16.34		10.76		12.48		21.97
Shared-Based Compensation		22.86		4.54		11.96		9.13
Depletion of Oil and Natural Gas Properties		31.53		39.76		34.44		37.32
Impairment of Oil and Natural Gas Properties		—		—		44.00		—
Depreciation and Amortization		0.14		0.33		0.15		0.32
Accretion of Discount on Asset Retirement Obligation		0.05		0.05		0.04		0.05

Production Expenses

Production expenses were $687,646 and $1,639,105 during the three and nine months ended September 30, 2012, respectively, compared to $221,509 and $419,822 during the three and nine months ended September 30, 2011. We experience increases in operating expenses as we add new wells and maintain production from existing properties. On a per unit basis, production expenses per Boe increased from $6.65 and $6.83 per barrel of oil equivalent, or Boe, sold during the three and nine months ended September 30, 2011, respectively, to $7.69 and $7.08 during the three and nine months ended September 30, 2012, respectively. These increases were related to normal operating cost fluctuations recognized in our Williston Basin wells. The largest cost component in our Williston Basin wells is the hauling and disposal of salt water.

Production Taxes

We pay production taxes based on realized crude oil and natural gas sales. Production taxes were $809,062 and $2,043,671 during the three and nine months ended September 30, 2012, respectively, compared to $241,412 and $488,793 in the three and nine months ended September 30, 2011, respectively. Our production taxes during the three and nine months ended September 30, 2012 were 11.4% and 10.8%, respectively, compared to 8.4% and 9.1% for the three and nine months ended September 30, 2011. The slightly higher production taxes in 2012 relates to the mix of wells added to production and the growing mix of producing wells that no longer qualify for reduced rates/or tax exemptions. Certain portions of our production occurs in North Dakota and Montana jurisdictions that have lower initial tax rates for an established period of time or until an established threshold of production is exceeded, after which the tax rates are increased to the standard tax rate.

General and Administrative Expense

General and administrative expenses were $3,503,273 and $5,660,622 during the three and nine months ended September 30, 2012, respectively, compared to $509,893 and $1,910,824 during the three and nine months ended September 30, 2011, respectively. General and administrative expenses excluding share-based compensation were $1,460,301 and $2,889,773 during the three and nine months ended September 30, 2012, respectively, compared to $358,548 and $1,349,710 during the three and nine months ended September 30, 2011, respectively. The increase is primarily due to the addition of officers and employees resulting from the acquisition of Target, increasing employee compensation and related employment expenses (increased $767,520 and $887,769 for the three and nine months ended September 30, 2012 compared to the three and nine months ended September 30, 2011, respectively). The increase is also due to increased legal, engineering, audit and other professional expenses (increased $149,765 and $450,838 for the three and nine months ended September 30, 2012, compared to the three and nine months ended September 30, 2011, respectively). Increases in legal, engineering, audit, other professional expenses and employment-related expenses for the three and nine months ended September 30, 2012 compared to the three and nine months ended September 30, 2011 were primarily the result of the acquisition of Target on July 26, 2012 and growth in infrastructure. Share-based compensation expenses totaled $2,042,972 and $2,770,849 for the three and nine months ended September 30, 2012, respectively, compared to $151,343 and $561,112 for the three and nine months ended September 30, 2011, respectively. The increase is primarily due to the modified vesting non-officer director awards resulting from the acquisition of Target, as well as the additional restricted stock units and options awarded to newly-appointed officers during the quarter.

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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 $2,818,650 and $7,977,077 for the three and nine months ended September 30, 2012, respectively, compared to $1,324,771 and $2,293,099 for the three and nine months ended September 30, 2011, respectively. On a per-unit basis, depletion expense was $31.53 and $34.44 per Boe for the three and nine months ended September 30, 2012, respectively, compared to $39.76 and $37.32 per Boe for the three and nine months ended September 30, 2011, respectively. Our depletion expense is based on the capitalized costs related to properties having proved reserves, plus the estimated future development costs and asset retirement costs which are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves determined by independent petroleum engineers. This increase in depletion expense for the three and nine months ended September 30, 2012 compared to the three and nine months ended September 30, 2011 was due primarily to the addition of 6.59 net productive Bakken and Three Forks wells from October 1, 2011 to September 30, 2012.

Impairment of Oil and Natural Gas Properties

We follow the full cost method of accounting for oil and natural gas operations whereby all costs related to the exploration and development of oil and natural gas properties are initially capitalized into a single cost center (“full cost pool”). Capitalized costs (net of related deferred income taxes) are limited to a ceiling based on the present value of future net revenues using the 12-month unweighted average of first-day-of-the-month price (the “12-month average price”), discounted at 10%, plus the lower of cost or fair market value of unproved properties. If the ceiling is not greater than or equal to the total capitalized costs, then we are required to write down capitalized costs to the ceiling. We perform this ceiling test calculation each quarter. Any required write downs are included in the condensed statements of operations as an impairment charge. We recognized an impairment expense in the three- and nine-month periods ended September 30, 2012 in the amount of $0 and $10,191,234, respectively. Included in the full cost pool at September 30, 2012 were costs incurred in 2010 and 2011 associated with our interest in the Niobrara development program in the DJ Basin. We incurred approximately $23.6 million in development costs to acquire acreage and develop the program with insufficient oil and natural gas reserves established as a result of the development program in the third-party reserve engineer’s reserve report to offset the costs of the development program. While the costs were incurred in 2010 and 2011, we did not fail the ceiling test until June 30, 2012. The failure was primarily due to a decrease in the 12-month average commodity price and an increase in the local differential to NYMEX on Williston Basin properties on the June 30, 2012 reserve report compared to March 31, 2012 and December 31, 2011 reserve reports. We did not recognize any impairment expense in the three- and nine-month periods ended September 30, 2011.

Other Income (Expense)

Other income (expense) was $4,353,721 and $3,656,855 for the three and nine months ended September 30, 2012, respectively, compared to $(506,649) and $(1,535,182) for the three and nine months ended September 30, 2011, respectively. The other income recognized during the three and nine months ended September 30, 2012 is a result of a $7,213,835 gain recognized, offset by $1,444,156 of acquisition costs incurred in the acquisition of Target on July 26, 2012 in accordance with GAAP. The gain is a result of the decrease in share price between the announcement date and closing date of the acquisition. Interest expense was $1,388,912 and $2,074,147 for the three and nine months ended September 30, 2012, respectively, compared to $508,841 and $1,510,416 for the three and nine months ended September 30, 2011, respectively. The increase in interest expense resulted from financing costs incurred as a result of amendment to the credit facility and utilization of Tranche C. Interest expense for the three and nine months ended September 30, 2012 included $1,215,238 and $1,494,031, respectively, of amortized financing costs related to the amended credit facility. 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 below.

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Net Income (Loss)

We had net income (loss) of $1,994,842 and $(5,222,436) for the three and nine months ended September 30, 2012, respectively (representing $0.20 and $(0.59) per share-basic and diluted, respectively) compared to a net income (loss) of $55,874 and $(1,298,957) for the three and nine months ended September 30, 2011, respectively (representing $0.01 and $(0.16) per share-basic and diluted, respectively). The net income recognized during the three months ended September 30, 2012 is primarily due to the gain recognized in the acquisition of Target on July 26, 2012, offset by acquisition costs, new officer equity awards, accelerated share-based compensation expenses and increased employment and employment-related expenses. The net loss for the nine months ended September 30, 2012 is primarily due to the impairment of oil and natural gas properties charge taken on June 30, 2012.

Non-GAAP Financial Measures

Adjusted EBITDA

In addition to reporting net income (loss) as defined under GAAP, we also present net earnings before interest, income taxes, depreciation, depletion, and amortization, accretion of discount on asset retirement obligations, impairment of oil and natural gas properties, net gain on acquisition of business, 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 September 30,					Nine Months Ended September 30,
	2012			2011		2012			2011
Net income (loss)	$	1,994,842		$	55,874	$	(5,222,436	)	$	(1,298,957	)
Add:      Impairment of oil and natural gas properties		—			—		10,191,234			—
Interest expense		1,388,912			508,841		2,074,147			1,510,416
Accretion of discount on asset retirement obligations		4,037			1,717		10,027			3,306
Depletion, depreciation and amortization		2,830,995			1,335,620		8,011,636			2,312,860
Stock-based compensation		2,042,972			151,345		2,770,849			561,114
Unrealized loss on commodity derivatives		1,514,729			—		236,646			—
Less:      Gain on acquisition of business, net		(5,769,679	)				(5,758,048	)
Adjusted EBITDA	$	4,006,808		$	2,053,397	$	12,314,055		$	3,088,739

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Adjusted Income (Loss)

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2012			2011		2012			2011
Net income (loss)	$	1,994,842		$	55,874	$	(5,222,436	)	$	(1,298,957	)
Impairment of oil and natural gas properties		—			—		10,191,234			—
Gain on acquisition of business, net		(5,769,679	)		—		(5,758,048	)		—
Unrealized loss on commodity derivatives		1,514,729			—		236,646			—
Adjusted income (loss)	$	(2,260,108	)	$	55,874	$	(552,604	)	$	(1,298,957	)
Adjusted income (loss) per share – basic	$	(0.23	)	$	0.01	$	(0.06	)	$	(0.16	)
Adjusted income (loss) per share – diluted	$	(0.23	)	$	0.01	$	(0.06	)	$	(0.16	)
Weighted average shares outstanding – basic		9,969,005			8,197,074		8,844,032			7,948,370
Weighted average shares outstanding – diluted		9,969,005			8,402,238		8,844,032			7,948,370

Liquidity and Capital Resources

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

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

Current assets	$	39,635,675
Current liabilities		37,366,316
Working capital	$	2,269,359

Equity Offerings

On September 28, 2012, we completed a public offering of 13,392,857 shares of common stock at $5.60 per share. The gross proceeds from the offering were $75 million, and the net proceeds were approximately $69.1 million, after deducting underwriting discounts and commissions and other offering expenses. The sale of the shares of common stock closed on September 25, 2012. The underwriters elected to exercise the over-allotment option to sell an additional 484,698 shares of common stock at $5.60 per share. The gross proceeds from the over-allotment exercise were $2.7 million, and the net proceeds are approximately $2.5 million after deducting underwriting discounts and commissions. The over-allotment exercise closed on October 26, 2012.

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We used a portion of the net proceeds from this offering, along with cash on hand, to repay a portion of outstanding indebtedness and for additional operable leasehold acquisitions. We intend to use the remaining proceeds to fund drilling and development expenditures in the Williston Basin and for general corporate purposes, including working capital.

On February 8, 2011, we completed a private placement to accredited investors of 1,785,714 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 892,857 warrants to subscribers of the private placement concurrently with the sale of shares. The warrants have an exercise price of $49.70, 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 (“Facility”) with Macquarie Bank Limited (“MBL”). Concurrent with the closing, we paid in full the $15 million in outstanding senior secured promissory notes.

The Facility provides up to a maximum of $150 million in principal amount of borrowings to be used as working capital for exploration and production operations. Initially, $15 million of financing was available under the Facility based on reserves (Tranche A), with an additional $50 million maximum under a development tranche (Tranche B). As of September 30, 2012, we had $15 million borrowed under Tranche A and $0 borrowed under Tranche B. As of September 30, 2012, $7.7 million was undrawn and available 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, or February 10, 2015.

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

The Facility requires that we enter into hedging agreements with MBL for each month of the 36-month period following the date on which each such hedge agreement is executed, the notional volumes for which (when aggregated with other commodity derivative agreements and additional fixed-price physical off-take contracts then in effect, as of the date such hedging agreement is executed, is not less than 50%, nor greater than 90%, of the reasonably anticipated projected production from our proved developed producing reserves. The Facility also requires us to maintain certain financial ratios, including current ratio (at least 1.00 to 1.00), debt coverage ratio (no more than 3.50 to 1.00) and interest coverage ratio (at least 2.50 to 1.00), commencing on March 31, 2012. We were not in compliance with the general and administrative expenses ceiling covenants as of September 30, 2012, and a waiver was obtained from MBL. Exceeding the general and administrative expense ceiling was primarily attributable to the addition of executives through the acquisition of Target and building operations to plan and design well development as an operator.

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

On July 26, 2012, we entered into an amended and restated credit agreement with MBL to expand the existing availability and outstanding balance under the Facility. In addition to the $20.2 million of debt obligations related to the acquisition of Target that was outstanding at the time through existing agreements, we obtained additional availability from the Facility and drew $15 million of additional debt on a new third tranche at an initial rate of 9% above LIBOR and had the potential to draw a maximum of $20 million. The $15 million drawn was used for existing development activities and was paid in full with proceeds from the equity offering completed on September 28, 2012.

Satisfaction of Our Cash Obligations for the Next Twelve Months

We project we will have sufficient capital to accomplish our development plan and forecasted general and administrative expenses for the next twelve months. Our projections are based on increasing cash flow from operations, increased borrowing capacity based on reserve growth and cash provided by the equity offering completed in September 2012. However, we may scale back our development plan should our projections of cash flow and borrowing capacity fall short of expectation. We may also choose to access the equity capital markets rather than a debt instrument to fund accelerated or continued drilling at the discretion of management and depending on prevailing market conditions. We will evaluate any potential opportunities for acquisitions as they arise. Given our asset base and anticipated growing cash flows, we believe we are in a position to take advantage of any appropriately priced sales that may occur. However, there can be no assurance that any additional capital will be available to us on favorable terms or at all.

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

Effects of Inflation and Pricing

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

Cash and Cash Equivalents

Our total cash resources as of September 30, 2012 were $33,282,601, compared to $13,927,267 as of December 31, 2011. The increase in our cash balance was primarily attributable to proceeds from the equity offering on September 28, 2012, offset by the development of oil and natural gas properties and repayment of debt.

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Net Cash Provided By (Used For) Operating Activities

Net cash provided by (used for) operating activities was $8,022,951 for the nine months ended September 30, 2012 compared to $(1,031,927) for the nine months ended September 30, 2011. The change in the net cash provided by operating activities is primarily attributable to higher production revenue in 2012, offset by net loss.

Net Cash Used In Investment Activities

Net cash used in investment activities was $36,640,015 for the nine months ended September 30, 2012 compared to $34,419,343 for the nine months ended September 30, 2011. The cash used in investment activities is primarily attributable to the purchase and development of oil and natural gas properties in the Williston Basin during the periods.

Net Cash Provided By Financing Activities

Net cash provided by financing activities was $47,972,398 for the nine months ended September 30, 2012 compared to $46,319,211 for the nine months ended September 30, 2011. The change in net cash provided by financing activities for the nine months ended September 30, 2012 is primarily attributable to proceeds from the equity offering completed on September 28, 2012 and the credit facility amended in July 2012, offset by repayment of borrowings under the amended credit facility and of liabilities, assumed resulting from the acquisition of Emerald Oil, Inc. and repayment of the senior secured promissory notes. The change in net cash provided by financing activities for the nine months ended September 30, 2011 is primarily attributable to proceeds from the private placement described in Item 2. Management’s Discuss and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Equity Offerings above.

Off-Balance Sheet Arrangements

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

2012 and 2013 Drilling Projects

On July 26, 2012, we acquired Emerald Oil, Inc. and made a strategic decision to add operating capabilities and focus on growing operating acreage in the Williston Basin. Considering that we recently closed on the acquisition, we are still evaluating how much of an effect our strategy, which includes swapping non-operating acreage for operating acreage that we intend to develop in future years, will have on our 2012 and 2013 development plans. With the increased return on capital opportunities of participating in our own developed wells, we may encounter situations where we swap out of non-operated acreage for operated acreage and forgo the opportunity to participate in non-operated wells developed on the acreage. Additionally, as we evaluate return on capital potentially of wells developed by other operators, we may decide to not participate in the development of the first well developed on our non-operated acreage, and go non-consent, but could have the opportunity to participate in future well development on future in-fill wells in the leased area that are held by production with an existing producing well. We believe adding operating capabilities will provide us more control over our capital budget and ultimately will result in a higher return on capital over the long-term. We expect to fund all of our 2012 and 2013 capital expenditures using cash-on-hand, cash flow from operations, borrowings under our revolving credit facility and equity and/or debt financings.

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

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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, to the extent the selling price is reasonably determinable. We use 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 September 30, 2012 and December 31, 2011, our 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 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- and nine-month periods ended September 30, 2012, we capitalized $151,719 and $624,818, respectively, of internal salaries, which included $97,317 and $493,085, respectively, of stock-based compensation. For the three- and nine-month periods ended September 30, 2011, we capitalized $192,836 and $346,044, respectively, of internal salaries, which included $155,061 and $289,277, respectively, of stock-based compensation. Internal salaries are capitalized based on employee time allocated to the acquisition of leaseholds and development of oil and natural gas properties. We capitalized interest of $305,590 and $362,688 for the three- and nine-month periods ended September 30, 2012, respectively. We did not capitalize interest for the three- and nine-month periods ended September 30, 2011.

Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. As of September 30, 2012, we have 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- and nine-month periods ended September 30, 2012, we had no costs that were transferred to the full cost pool related to impairment. For the year ended December 31, 2011, we transferred $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 consolidated statements of operations as an impairment charge. We recognized an impairment expense in the three- and nine-month periods ended September 30, 2012 in the amount of $0 and $10,191,234, respectively. There was no impairment expense recognized in the three- and nine-month periods ended September 30, 2011.

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Joint Ventures

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

Stock-Based Compensation

We have accounted for stock-based compensation under the provisions of ASC 718-10-55. We recognize stock-based compensation expense in the financial statements over the vesting period of equity-classified employee stock-based compensation awards based on the grant date fair value of the awards, net of estimated forfeitures. For options and warrants, we use the Black-Scholes option valuation model to calculate the fair value of stock based compensation awards at the date of grant. Option pricing models require the input of highly subjective assumptions, including the expected price volatility. For the stock options and warrants granted we have used a variety of comparable and peer companies to determine the expected volatility input based on the expected term of the options. We believe the use of 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 2011 Plan, under which 714,286 shares of common stock were reserved. The purpose of the 2011 Plan is to promote success by facilitating the employment and retention of competent personnel and by furnishing incentives to those employees, directors and consultants upon whose efforts our success 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 September 30, 2012, 624,281 of the 714,286 shares of common stock reserved were issued to directors, officers and employees under the 2011 Plan. As of September 30, 2012, we had granted 107,144 options to officers and employees contingent on our shareholders approving an amendment to the 2011 Plan for an additional 2,785,714 shares to be reserved under the 2011 Plan. The Company’s shareholders approved the amendment on October 22, 2012.

Cautionary Factors That May Affect Future Results

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

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

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

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

· competition, including competition for acreage in resource play areas;

· our ability to retain key members of management; 

· volatility in commodity prices for oil and natural gas;

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

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

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

· interest payment requirements of our debt obligations;

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

· substantial impairment write-downs;

· our ability to replace oil and natural gas reserves;

· environmental risks;

· drilling and operating risks;

· exploration and development risks;

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

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

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

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

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

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

Interest Rate Risk

As of September 30, 2012, we had borrowed $15 million under Tranche A under the Facility.

Our 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 Securities and Exchange Act of 1934, as amended, 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

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 our Annual Report on Form 10-K for the year ended December 31, 2011 and our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012,except as stated below.

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

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

We may have difficulty integrating and managing the growth associated with our recent acquisitions.

Our recent acquisitions, including the Emerald acquisition and the McKenzie County acreage are expected to result in a significant growth in our assets, reserves and revenues and may place a significant strain on our financial, technical, operational and administrative resources. We may not be able to integrate the operations of the acquired assets without increases in costs, losses in revenues or other difficulties. In addition, we may not be able to realize the operating efficiencies, synergies, costs savings or other benefits expected from such acquisitions, particularly as we transition from our historical non-operated strategy to a balanced operated and non-operated approach. Any unexpected costs or delays incurred in connection with such integration could have an adverse effect on our business, results of operations or financial condition. Our general and administrative expenses excluding share-based compensation increased by approximately $1.1 million and $1.5 million during the respective three and nine months ended September 30, 2012 over the respective three and nine months ended September 30, 2011, due in part to the addition of officers and employees resulting from the Emerald acquisition. We have hired or intend to hire approximately two new employees that we expect will be required to manage our operations and plan to add resources as needed as we scale up our business. However, we may experience difficulties in finding the additional qualified personnel. In an effort to stay on schedule with our planned activities, we intend to supplement our staff with contract and consultant personnel until we are able to hire new employees. Our ability to continue to grow after these acquisitions will depend upon a number of factors, including our ability to identify and acquire new exploratory prospects and other acquisition targets, our ability to develop then existing prospects, our ability to successfully adopt a balanced operated and non-operated approach, our ability to continue to retain and attract skilled personnel, the results of our drilling program and acquisition efforts, hydrocarbon prices and access to capital. We may not be successful in achieving or managing growth and any such failure could have a material adverse effect on us.

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

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

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

We expect that our cash position, our credit facility and revenues from crude oil and natural gas sales should provide sufficient capital to meet our drilling commitments and expected general and administrative expenses for the next twelve months. However, those funds may not be sufficient to fund both our continuing operations and our planned growth. We may require additional capital to continue to grow our business via acquisitions and to further expand our exploration and development programs. We may be unable to obtain additional capital if and when required.

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

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

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

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

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

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

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

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

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

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

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

· increase our vulnerability to general adverse economic and industry conditions;

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

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

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

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

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

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

· pay dividends or distributions on our capital stock;

· make certain loans and investments;

· enter into certain transactions with affiliates;

· create or assume certain liens on our assets;

· merge or to enter into other business combination transactions;

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

· engage in certain other corporate activities.

Also, our credit facility requires us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. We were not in compliance with the general and administrative expense ceiling covenant as of September 30, 2012, and a waiver was obtained from the administrative agent. Exceeding the general and administrative expense ceiling was primarily attributable to the addition of executives through the acquisition of Target and building operations to plan and design well development as an operator. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control, and we cannot assure you that we will meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general or otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our bank credit facility impose on us.

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

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

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

· timing and amount of capital expenditures;

· the operator’s expertise and financial resources;

· the rate of production of reserves, if any;

· approval of other participants in drilling wells; and

· selection of technology.

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

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

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

The Williston Basin oil price differential could have adverse impacts on our revenues.

Generally, crude oil produced from the Bakken formation in North Dakota is high quality (36 to 44 degrees API, which is comparable to West Texas Intermediate Crude). However, due to takeaway constraints, oil prices in the Williston Basin generally have been from $8.00 to $10.00 less per barrel than prices for other areas in the United States, and earlier this year as much as $22.00 less per barrel. This discount, or differential, may widen in the future, which would reduce the price we would receive for our production.

Drilling and completion costs for the wells we drill in the Williston Basin are comparable to other areas where there is no price differential. As a result of this reverse leverage effect, a significant, prolonged downturn in oil prices on a national basis could result in a ceiling limitation write-down of the oil and natural gas properties we hold. Such a price downturn also could reduce cash flow from our Williston Basin properties and adversely impact our ability to participate fully in other drilling. Our production in other areas could also be affected by adverse changes in differentials. In addition, changes in differentials could make it more difficult for us to effectively hedge our exposure to changes in commodity prices.

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Shortages of equipment, services and qualified personnel could reduce our cash flow and adversely affect results of operations.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers, and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices and activity levels in new regions, causing periodic shortages. These problems can be particularly severe in certain regions such as the Williston Basin and the Sandwash Basin. During periods of high oil and natural gas prices, the demand for drilling rigs and equipment has increased along with increased activity levels, and this may result in shortages of equipment. In addition, there has been a shortage of hydraulic fracturing capacity in many of the areas in which we operate. This shortage in hydraulic fracturing capacity could occur in the future. Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, oilfield equipment and services, and personnel in our exploration, production and midstream operations. These types of shortages and subsequent price increases could significantly decrease our profit margin, cash flow and operating results and/or restrict or delay our ability to drill those wells and conduct those operations that we currently have planned and budgeted, causing us to miss our forecasts and projections.

Successful exploitation of the Williston Basin is subject to risks related to horizontal drilling and completion techniques.

Operations in the Williston Basin involve utilizing the latest drilling and completion techniques, including horizontal drilling and completion techniques, to generate the highest possible cumulative recoveries and therefore generate the highest possible returns. Risks that are encountered while drilling include, but are not limited to, landing the well bore in the desired drilling zone, staying in the zone while drilling horizontally through the formation, running casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Completion risks include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations, and successfully cleaning out the well bore after completion of the final fracture stimulation stage. Ultimately, the success of these latest drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period.

The drilling and completion of a well in the Williston Basin frequently costs between $7.5 million and $13.0 million on a gross basis, which is significantly more expensive than a typical onshore conventional well. Accordingly, unsuccessful exploration or development activity affecting even a small number of wells could have a significant impact on our results of operations.

Losses and liabilities from uninsured or underinsured drilling and operating activities could have a material adverse effect on our financial condition and operations.

We maintain several types of insurance to cover our operations, including worker’s compensation and comprehensive general liability. Amounts over base coverages are provided by primary and excess umbrella liability policies. We also expect to maintain operator’s extra expense coverage, which covers the control of drilling or producing wells as well as redrilling expenses and pollution coverage for wells out of control.

We may not be able to maintain adequate insurance in the future at rates we consider reasonable, or we could experience losses that are not insured or that exceed the maximum limits under our insurance policies. If a significant event that is not fully insured or indemnified occurs, it could materially and adversely affect our financial condition and results of operations.

We are subject to various governmental regulations and environmental risks that may cause us to incur substantial costs.

From time to time, in varying degrees, political developments and federal and state laws and regulations affect our operations. In particular, price controls, taxes, and other laws relating to the oil and natural gas industry, changes in these laws, and changes in administrative regulations have affected and in the future could affect crude oil and natural gas production, operations, and economics. We cannot predict how agencies or courts will interpret existing laws and regulations or the effect these adoptions and interpretations may have on our business or financial condition.

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Our business is subject to laws and regulations promulgated by federal, state, and local authorities, including but not limited to the U.S. Congress, the U.S. Environmental Protection Agency (the “EPA”), the Bureau of Land Management, the Industrial Commission of North Dakota, and the Montana Board of Oil and Gas Conservation, relating to the exploration for, and the development, production, and marketing of, crude oil and natural gas, as well as safety matters. Legal requirements are frequently changed and subject to interpretation, and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. We may be required to make significant expenditures to comply with governmental laws and regulations. The discharge of crude oil, natural gas, or other pollutants into the air, soil, or water may give rise to significant liabilities on our part to the government and third parties and may require us to incur substantial costs of remediation.

On April 17, 2012, the EPA approved final regulations under the U.S. Federal Clean Air Act (the “CAA”) 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 (“VOC”) 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.

The adoption of climate change legislation by Congress could result in increased operating costs, create delays in our obtaining air pollution permits for new or modified facilities, and result in reduced demand for the oil and natural gas we produce.

According to certain scientific studies, emissions of carbon dioxide, methane, nitrous oxide, and other gases commonly known as greenhouse gases (“GHG”) may be contributing to global warming of the earth’s atmosphere and to global climate change. In response to the scientific studies, legislative and regulatory initiatives have been underway to limit GHG emissions. The U.S. Supreme Court determined that GHG emissions fall within the definition of an “air pollutant,” and in response, the EPA promulgated an endangerment finding paving the way for regulation of GHG emissions under the CAA. The EPA has also promulgated rules requiring owners or operators of certain petroleum and natural gas systems that emit 25,000 metric tons or more of GHG per year from a facility to report such emissions, and we are subject to this reporting requirement. In addition, the EPA promulgated rules that significantly increase the GHG emission threshold that would identify major stationary sources of GHG subject to CAA permitting programs. As currently written and based on our current operations, we are not subject to federal GHG permitting requirements. Regulation of GHG emissions is new and highly controversial, and further regulatory, legislative, and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact us. Further, apart from these developments, recent judicial decisions that have allowed certain tort claims alleging property damage to proceed against GHG emissions sources may increase our litigation risk for such claims. Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial impact of related developments on us.

Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher GHG emitting energy sources, such as coal, our products could become more desirable in a market with more stringent limitations on GHG emissions. To the extent that our products are competing with lower GHG emitting energy sources, such as solar and wind, our products could become less desirable in the market with more stringent limitations on GHG emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations. Any laws or regulations that may be adopted to restrict or reduce emissions of GHG could require us to incur increased operating costs and could have an adverse effect on demand for the oil and natural gas we produce, depending on the applicability to our operations and the refining, processing, and use of oil and natural gas.

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Seasonal weather conditions and other factors could adversely affect our ability to conduct drilling activities.

Our operations could be adversely affected by weather conditions and wildlife restrictions on federal leases. In the Williston Basin and the Sandwash Basin, drilling and other oil and natural gas activities cannot be conducted as effectively during the winter months. Winter and severe weather conditions limit and may temporarily halt the ability to operate during such conditions. These constraints and the resulting shortages or high costs could delay or temporarily halt our oil and natural gas operations and materially increase our operating and capital costs, which could have a material adverse effect on our business, financial condition, and results of operations.

We may have difficulty distributing our oil and natural gas production, which could harm our financial condition.

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

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

On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Reform Act”), which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. Many of the statutory provisions require implementing regulations of the Commodities Futures Trading Commission (the “CFTC”) and the SEC. The CFTC has issued final rules further defining the terms “swap dealer,” “major swap participant” and “swap.” The completion of this definitional rulemaking satisfies prerequisites for certain substantive components of the legislation and regulations to take effect, including registration and other requirements applicable to swap dealers.

The CFTC has issued a final rule on position limits for certain futures and option contracts in the major energy markets and for swaps that are economically related. Certain bona fide hedging transactions or positions are exempt from these position limits. The financial reform legislation may require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities. The financial reform legislation will impose significant new regulation on those of our derivatives counterparties that are swap dealers, which may increase their costs and in certain cases may cause or require them to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure existing derivative contracts, and increase our potential exposure to less creditworthy counterparties. If we reduce our use of derivatives or commodity prices prices become more volatile and hedging markets become less liquid as a result of the legislation and regulations, our results of operations may become more volatile and cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures, our results of operations, or our cash flows.

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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.

1.1 Underwriting Agreement dated as of September 24, 2012, among Voyager Oil & Gas, Inc., Johnson Rice & Company L.L.C., as representative of the several underwriters, and Global Hunter Securities, L.L.C., as the qualified independent underwriter (incorporated by reference to Exhibit 1.1 to our current report on Form 8-K filed on September 26, 2012)

2.1 Purchase and Sale Agreement, dated as of September 6, 2012, by and between Emerald WB LLC and Slawson Exploration Company, Inc. (incorporated by reference to Exhibit 2.1 to our current report on Form 8-K filed on September 10, 2012)

3.1 Articles of Amendment to the Articles of Incorporation (incorporated by reference to Exhibit 3.1 to our current report on Form 8-K filed on October 24, 2012)

3.2* Amended Bylaws

4.1 Specimen Stock Certificate for the common stock, par value $0.001 per share, of Voyager Oil & Gas, Inc. (incorporated by reference to Exhibit 4.1 to our current report on Form 8-K filed on October 24, 2012)

10.1 Credit Agreement, dated as of February 21, 2012, by and between Borrower, Emerald GRB, Emerald Oil and Lender (incorporated by reference to Exhibit 10.1 to our current report on Form 8-K/A filed on August 8, 2012)

10.2 Amendment No. 1 and Reaffirmation, dated as of June 7, 2012, by and between Borrower, Emerald GRB, Emerald Oil and Lender (incorporated by reference to Exhibit 10.2 to our current report on Form 8-K/A filed on August 8, 2012)

10.3 Amendment to the 2011 Equity Incentive Plan (incorporated by reference to Exhibit 10.1 to our current report on Form 8-K filed on October 24, 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.

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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: November 8, 2012	EMERALD OIL, INC.
	/s/ Michael Krzus
	Michael Krzus
	Chief Executive Officer (principal executive officer)
	/s/ Paul Wiesner
	Paul Wiesner
	Chief Financial Officer (principal financial officer)

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