Emerald Oil 10Q 2013 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2013

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 1360
Denver, CO		80202
(Address of principal executive offices)		(Zip Code)

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

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 May 9, 2013, there were 25,899,658 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 March 31, 2013 and December 31, 2012	1

		Condensed Consolidated Statements of Operations for the three months ended March 31, 2013 and 2012	2

		Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2013 and 2012	3

		Notes to Condensed Consolidated Financial Statements	4

	ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	23

	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	40

	ITEM 4.	CONTROLS AND PROCEDURES	40

PART II.	OTHER INFORMATION		41

	ITEM 1.	LEGAL PROCEEDINGS	41

	ITEM 1A.	RISK FACTORS	41

	ITEM 6.	EXHIBITS	42

SIGNATURES			44

PART 1 — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EMERALD OIL, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	March 31, 2013			December 31, 2012
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	35,794,375		$	10,192,379
Trade Receivables		18,266,020			12,573,156
Other Receivables		230,651			1,133,849
Prepaid Expenses and Other Current Assets		128,986			103,173
Total Current Assets		54,420,032			24,002,557
PROPERTY AND EQUIPMENT
Oil and Natural Gas Properties, Full Cost Method
Proved Oil and Natural Gas Properties		186,386,298			167,618,422
Unproved Oil and Natural Gas Properties		55,426,520			61,454,831
Other Property and Equipment		458,503			385,023
Total Property and Equipment		242,271,321			229,458,276
Less – Accumulated Depreciation, Depletion and Amortization		(83,410,491	)		(80,230,517	)
Total Property and Equipment, Net		158,860,830			149,227,759
Prepaid Drilling Costs		2,038			100,193
Fair Value of Commodity Derivatives		—			25,397
Debt Issuance Costs, Net of Amortization		247,478			269,681
Other Non-Current Assets		175,100			260,775
Total Assets	$	213,705,478		$	173,886,362
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts Payable	$	32,512,315		$	39,169,037
Fair Value of Commodity Derivatives		699,490			206,645
Accrued Expenses		827,938			420,521
Deposits Received for Sale of Assets		664,862			—
Advances from Joint Interest Partners		1,414,686			—
Total Current Liabilities		36,119,291			39,796,203
LONG-TERM LIABILITIES
Revolving Credit Facility		15,176,350			23,500,000
Fair Value of Commodity Derivatives		100,120			—
Asset Retirement Obligations		349,427			296,074
Warrant Liability		12,065,000			—
Total Liabilities		63,810,188			63,592,277

COMMITMENTS AND CONTINGENCIES

Preferred Stock – Par Value $.001; 20,000,000 Shares Authorized;
Series A Perpetual Preferred Stock – 500,000 and 0 issued and outstanding at March 31, 2013 and December 31, 2012, respectively. Liquidation preference value of $56,250,000 and $0, as of March 31, 2013 and December 31, 2012, respectively.		38,552,994			—
Series B Voting Preferred Stock – 5,114,633 and 0 issued and outstanding at March 31, 2013 and December 31, 2012, respectively. Liquidation preference value of $5,115 and $0, as of March 31, 2013 and December 31, 2012, respectively.		5,000			—

STOCKHOLDERS’ EQUITY
Common Stock, Par Value $.001; 500,000,000 Shares Authorized, 25,899,658 and 24,734,643 Shares Issued and Outstanding at March 31, 2013 and December 31, 2012, respectively		25,900			24,735
Additional Paid-In Capital		187,966,399			180,439,530
Accumulated Deficit		(76,655,003	)		(70,170,180	)
Total Stockholders’ Equity		111,337,296			110,294,085
Total Liabilities and Stockholders’ Equity	$	213,705,478		$	173,886,362

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

EMERALD OIL, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended March 31,
	2013			2012
REVENUES
Oil and Natural Gas Sales	$	8,216,981		$	5,098,333
Realized and Unrealized Loss on Commodity Derivatives		(767,604	)		(912,435	)
		7,449,377			4,185,898
OPERATING EXPENSES
Production Expenses		1,039,532			466,630
Production Taxes		701,856			506,021
General and Administrative Expenses		5,388,813			942,131
Depletion of Oil and Natural Gas Properties		3,156,978			1,998,059
Depreciation and Amortization		22,995			11,070
Accretion of Discount on Asset Retirement Obligations		6,212			2,567
Total Expenses		10,316,386			3,926,478

INCOME (LOSS) FROM OPERATIONS		(2,867,009	)		259,420

OTHER INCOME (EXPENSE)
Interest Expense		(179,490	)		(515,790	)
Warrant Revaluation Expense		(3,439,000	)		—
Other Income, Net		676			—
Total Other Expense, Net		(3,617,814	)		(515,790	)

LOSS BEFORE INCOME TAXES		(6,484,823	)		(256,370	)

INCOME TAX EXPENSE		—			—

NET LOSS		(6,484,823	)		(256,370	)
Less: Preferred Stock Dividends		(616,438	)		—
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(7,101,261	)	$	(256,370	)

Net Loss Per Common Share - Basic and Diluted	$	(0.28	)	$	(0.03	)

Weighted Average Shares Outstanding — Basic and Diluted		25,692,532			8,265,788

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

EMERALD OIL, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Three Months Ended March 31,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$	(6,484,823	)	$	(256,370	)
Adjustments to Reconcile Net Loss to Net Cash Provided By Operating Activities:
Depletion of Oil and Natural Gas Properties		3,156,978			1,998,059
Depreciation and Amortization		22,995			11,070
Amortization of Debt Issuance Costs		22,203			241,591
Accretion of Discount on Asset Retirement Obligations		6,212			2,567
Unrealized Loss on Commodity Derivatives		618,396			884,892
Warrant Revaluation Expense		3,439,000			—
Share-Based Compensation Expense		1,307,986			327,725
Changes in Assets and Liabilities:
Increase in Trade Receivables		(5,692,864	)		(2,174,439	)
Decrease in Other Receivables		903,198			—
Increase in Prepaid Expenses and Other Current Assets		(25,813	)		(22,343	)
Decrease in Other Non-Current Assets		85,675			—
Increase in Accounts Payable		531,714			184,496
Increase (Decrease) in Accrued Expenses		407,417			(190,150	)
Advances from Joint Interest Partners		1,414,686			—
Increase in Deposits Received for Assets Available for Sale		664,862			—
Net Cash Provided By Operating Activities		377,822			1,007,098
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of Other Property and Equipment		(73,480	)		(1,497	)
Use of (Payments for) Prepaid Drilling Costs		98,155			(389,324	)
Proceeds from Sale of Oil and Natural Gas Properties, Net of Transaction Costs		9,673,953			—
Investment in Oil and Natural Gas Properties		(22,718,360	)		(11,785,495	)
Net Cash Used For Investing Activities		(13,019,732	)		(12,176,316	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Issuance of Preferred Stock and Warrants, Net of Transaction Costs		47,183,994			—
Advances on Revolving Credit Facility and Term Loan		—			17,545,779
Payments on Revolving Credit Facility		(8,323,650	)		—
Payments on Senior Secured Promissory Notes		—			(15,000,000	)
Cash Paid for Finance Costs		—			(364,212	)
Preferred Stock Dividends		(616,438	)		—
Net Cash Provided by Financing Activities		38,243,906			2,181,567
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		25,601,996			(8,987,651	)
CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD		10,192,379			13,927,267
CASH AND CASH EQUIVALENTS – END OF PERIOD	$	35,794,375		$	4,939,616
Supplemental Disclosure of Cash Flow Information
Cash Paid During the Period for Interest	$	163,663		$	424,402
Cash Paid During the Period for Income Taxes	$	—		$	—
Non-Cash Financing and Investing Activities:
Oil and Natural Gas Properties Property included in Accounts Payable	$	31,784,701		$	24,534,014
Stock-Based Compensation Capitalized to Oil and Natural Gas Properties	$	99,552		$	201,271
Capitalized Asset Retirement Obligations	$	47,141		$	43,204

Common Stock Issued for Oil and Natural Gas Properties	$	6,736,935		$	—

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

EMERALD OIL, INC.
Notes to Condensed Consolidated Financial Statements
Unaudited

NOTE 1 ORGANIZATION AND NATURE OF BUSINESS

Description of Operations — Emerald Oil, 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 (“U.S.”), 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 built an operations team to plan and design well development as an operator on acreage where it holds a controlling interest. The Company currently has 22 employees and retains independent contractors to assist in operating and managing its prospects as well as to carry out the principal and necessary functions to manage the oil and natural gas development. With the acquisition of Emerald Oil North America, Inc., formerly known as Emerald Oil, Inc. (“Emerald Oil North America”), on July 26, 2012 (see Note 3 – Acquisition of Business), the Company added executive management that is experienced in well development. Since the acquisition, the Company has significantly added to these internal capabilities and leveraged best practices through partnering with industry experts. Production from oil wells has increased significantly, and the Company is in the process of adding to this production by operating its own wells, while continuing to selectively 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 March 31, 2013 and for the three months ended March 31, 2013 and 2012 are unaudited. In the opinion of management, such financial statements include the adjustments and accruals, 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 March 31, 2013 and for the three month periods ended March 31, 2013 and 2012.

Interim financial results should be read in conjunction with the audited financial statements and footnotes for the year ended December 31, 2012, which were included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012.

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 common 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.

Cash and Cash Equivalents

The Company considers highly liquid investments with insignificant interest rate risk and original maturities of three months or less to be cash equivalents. Cash equivalents consist primarily of interest-bearing bank accounts and money market funds. The Company’s cash positions represent assets held in checking and money market accounts. These assets are generally available to the Company on a daily or weekly basis and are highly liquid in nature. Due to the balances being greater than their $250,000 insurance coverage, the Company does not have FDIC coverage on the entire amount of its bank deposits. The Company believes this risk to be minimal. 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.

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 acquisitions, and exploration activities. For the three month periods ended March 31, 2013 and 2012, the Company capitalized $315,792 and $238,615, respectively, of internal salaries, which included $99,552 and $201,271, respectively, of stock-based compensation. Internal salaries are capitalized based on employee time allocated to the acquisitions of leaseholds and development of oil and natural gas properties.

Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. The Company closed a property sale during the three months ended March 31, 2013 in the Sand Wash Basin (see Note 4 – Oil and Natural Gas Properties). No gain or loss was recognized as the sale did not significantly alter the relationship between capitalized costs and proved reserves attributable to the Sand Wash Basin. The Company engages in acreage trades in the Williston Basin, but these trades are for similar acreage both in terms of geographic location and potential resource value.

The Company assesses all items classified as unevaluated property for possible impairment or reduction in value on a quarterly basis. 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 depletion and amortization. For the three month period ended March 31, 2013 and the year ended December 31, 2012, the Company reclassified $0 and $3,625,209, respectively, relating to expiring leases to 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 Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“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.

Under the full cost method of accounting, capitalized oil and natural gas property costs less accumulated depletion, net of deferred income taxes, may not exceed a ceiling amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are subject to amortization. Should capitalized costs exceed this ceiling, an impairment is recognized. The present value of estimated future net revenues was computed by applying prices based on a 12-month arithmetic average of the oil and natural gas prices in effect on the first day of each month, less estimated future expenditures to be incurred in developing and producing the proved reserves (assuming the continuation of existing economic conditions), less any applicable future taxes. The Company performs this ceiling calculation each quarter. Any required write-downs are included in the consolidated statement of operations as an impairment charge. No ceiling test impairment was required during the three months ended March 31, 2013 or 2012.

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 $22,995 and $11,070 for the three-month periods ended March 31, 2013 and 2012, respectively.

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. The Company has not recognized any impairment losses on non-oil and natural gas long-lived assets.

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 depleted using the units of production method. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

Revenue Recognition and Natural Gas Balancing

The Company recognizes oil and natural gas revenues from its interests in producing wells when production is delivered and title has transferred to the purchaser, to the extent the selling price is reasonably determinable. The Company uses the sales method of accounting for balancing of natural gas production and would recognize a liability if the existing proven reserves were not adequate to cover the current imbalance situation. As of March 31, 2013 and December 31, 2012, the Company’s 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. 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 and warrants granted. The Company believes the use or peer company data fairly represents the expected volatility it would experience if it were in the oil and natural gas industry over the expected term of the options. Changes in these assumptions can materially affect the fair value estimate.

On May 27, 2011, the shareholders of the Company approved the 2011 Equity Incentive Plan (the “2011 Plan”), under which 714,286 shares of common stock were reserved. On October 22, 2012, the shareholders of the Company approved an amendment to the 2011 Plan to increase the number of shares available for issuance under the 2011 Plan to 3,500,000 shares. The purpose of the 2011 Plan is to promote the success of the Company and its affiliates by facilitating the employment and retention of competent personnel and by furnishing incentives to those officers, directors and employees upon whose efforts the success of the Company and its affiliates will depend to a large degree. It is the intention of the Company to carry out the 2011 Plan through the granting of incentive stock options, nonqualified stock options, restricted stock awards, restricted stock unit awards, performance awards and stock appreciation rights. As of March 31, 2013, 671,568 stock options and 2,758,737 shares of common stock and restricted stock units had been issued to officers, directors and employees under the 2011 Plan, including 1,830,584 unvested restricted stock units. As of March 31, 2013, there were 69,695 shares available for issuance under the 2011 Plan.

Income Taxes

The Company accounts for income taxes under 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 stock 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 losses for the three month periods ended March 31, 2013, and 2012, the potentially dilutive shares were anti-dilutive and were thus not included in the net loss per share calculation.

As of March 31, 2013, (i) 1,830,584 unvested restricted stock units were issued and outstanding and represent potentially dilutive shares; (ii) 428,557 stock options were issued and presently exercisable and represent potentially dilutive shares; (iii) 375,145 stock options were granted but are not presently exercisable and represent potentially dilutive shares; (iv) 5,114,633 warrants were issued and presently exercisable, which have an exercise price of $5.77 and represent potentially dilutive shares; (v) 223,293 warrants were issued and presently exercisable, which have an exercise price of $6.86 and represent potentially dilutive shares; and (vi) 892,858 warrants were issued and presently exercisable, which have an exercise price of $49.70 and represent potentially dilutive shares.

Derivative and Other Financial Instruments

Commodity Derivative Instruments

The Company has entered into commodity derivative instruments utilizing an oil derivative swap contract 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 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 consolidated statements 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 13– Derivative Instruments and Price Risk Management).

Warrant Liability

From time to time the Company may have financial instruments such as warrants that may be classified as liabilities when either (a) the holders possess rights to net cash settlement, (b) physical or net equity settlement is not in the Company’s control, or (c) the instruments contain other provisions that causes the Company to conclude that they are not indexed to the Company’s equity. Such instruments are initially recorded at fair value and subsequently adjusted to fair value at the end of each reporting period through earnings.

As a part of the Securities Purchase Agreement with White Deer Energy (see Note 6 – Preferred and Common Stock), the Company issued warrants that contain a put and other liability type provisions. Accordingly, these warrants are accounted for as a liability. This warrant liability is accounted for at fair value with changes in fair value reported in earnings.

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 March 31, 2013 and 2012 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, fair value of warrant liability, valuation of share-based compensation and the valuation of deferred income taxes. Actual results may differ from those estimates.

Industry Segment and Geographic Information

The Company operates in one industry segment, which is the exploration, development and production of oil and natural gas with all of the Company’s operational activities having been conducted in the U.S. The Company’s current operational activities and the Company’s consolidated revenues are generated from markets exclusively in the U.S., and the Company has no long-lived assets located outside the U.S.

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 Emerald Oil North America, Inc., a wholly owned subsidiary of the Parent, pursuant to which the Company purchased all of the outstanding capital stock of Emerald Oil North America for approximately 19.9% of the total shares of the Company’s common stock outstanding as of the closing date. The Company completed the acquisition of Emerald Oil North America on July 26, 2012 and issued approximately 1.66 million shares to the Parent. The Company assumed Emerald Oil North America’s liabilities, including approximately $20.3 million in debt owed by Emerald Oil North America. The acquisition included approximately 10,600 net acres located in Dunn County, North Dakota and approximately 45,000 net acres in the Sand Wash Basin Niobrara shale oil play in northwestern Colorado and southwestern Wyoming.

In connection with the closing of the Emerald Oil North America 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 the Company’s board of directors. Also in connection with the closing of the Emerald Oil North America 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). On May 8, 2013, McAndrew Rudisill transitioned into the role of Chief Executive Officer and Mike Krzus transitioned into the role of President. This transition is intended to more closely align each officer’s position with his day to day responsibilities. Following the Emerald Oil North America acquisition, each of the Company’s directors and executive officers entered into indemnification agreements with the Company.

Emerald Oil North America’s $20.3 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.

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 Emerald Oil North America’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 Sand Wash 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. The Company recorded a gain on the bargain purchase of Emerald Oil North America as a result of the decrease in the Company’s share price between the announcement date (July 10, 2012) and closing date (July 26, 2012) of the acquisition in accordance with GAAP. 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
Debt Assumed		(20,303	)
Net Assets Acquired		20,595
Equity Issued to Emerald Oil & Gas NL		(13,381	)
Gain on Acquisition		7,214
Less: Acquisition Costs		(1,456	)
Gain on Acquisition, net	$	5,758

Pro Forma Operating Results

For the three month period ended March 31, 2013, the Company recognized $111,789 in revenues, and $17,906 of expenses relating to Emerald Oil North America, resulting in a net income during the three month period ended March 31, 2013 of $93,883. For the three month period ended March 31, 2012, the Company recognized $56,663 in revenues, and $1,648,608 of expenses relating to Emerald Oil North America, resulting in a net loss during the three month period ended March 31, 2012 of $1,591,608.

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 March 31,
	2013			2012

Revenues	$	7,449,377		$	4,242,561
Net Loss Available to Common Shareholders	$	(7,101,261	)	$	(1,847,978	)

Net Loss Per Share – Basic and Diluted	$	(0.28	)	$	(0.19	)

Weighted Average Shares Outstanding – Basic and Diluted		25,692,532			9,927,962

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

On January 9, 2013, the Company entered into a purchase and sale agreement with a third party pursuant to which the Company acquired leases of oil and natural gas properties in McKenzie County, North Dakota. Pursuant to the purchase and sale agreement and as consideration for the approximate $4.7 million purchase price of the acquired leases, the Company issued 851,315 shares of its common stock at a per share value of $5.50 per share, based on the five-day trading volume-weighted average price of the Company’s common stock prior to closing. The Company issued the shares of common stock in reliance upon an exemption from the registration requirements under the Securities Act of 1933, as amended, provided by Section 4(2) thereof. Under the terms of the purchase and sale agreement, the Company agreed to register the shares issued to the seller for resale from time to time.

On February 4, 2013, the Company entered into a purchase and sale agreement with a third party pursuant to which the Company acquired leases of oil and natural gas properties in McKenzie County, North Dakota. Pursuant to the purchase and sale agreement and as consideration for the approximate $1.9 million purchase price of the acquired leases, the Company issued 313,700 shares of its common stock at a per share value of $6.058 per share, based on the five-day trading volume-weighted average price of the Company’s common stock prior to closing. The Company issued the shares of common stock in reliance upon an exemption from the registration requirements under the Securities Act of 1933, as amended, provided by Section 4(2) thereof. Under the terms of the purchase and sale agreement, the Company agreed to register the shares issued to the seller for resale from time to time.

Leasehold Sales

On January 7, 2013, the Company entered into a definitive agreement with East Management Services, LP (“East”), under which the Company agreed to sell to East its undivided 45% working interest in and to certain oil and natural gas leaseholds in the Sand Wash Basin, comprising approximately 31,000 net acres located in Routt and Moffatt Counties, Colorado and Carbon County, Wyoming. On March 28, 2013, the Company completed the transaction for an aggregate sale price of approximately $10.1 million in cash.

Sand Wash Basin

Following the sale of certain oil and natural gas leaseholds to East, the Company owns approximately 14,500 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 the Company’s natural gas production facilities located in Moffat County, Colorado to a Questar pipeline connection located near Baggs, Wyoming in Carbon County. These assets were acquired in conjunction with the acquisition of EmeraldOil North America 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 Limited (“Entek”), 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.

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 March 31, 2013. 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 March 31, 2013. The unutilized cash balance was $11,790 as of March 31, 2013.

Niobrara Development with Slawson Exploration Company, Inc.

As of March 31, 2013, the Company held approximately 1,700 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 2013.

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.

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 the Company’s joint venture partners. These wells are currently under evaluation for economical production at current natural gas prices.

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 9 to the condensed 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.

NOTE 6 PREFERRED AND COMMON STOCK

Preferred Stock

The Company has authorized 20,000,000 shares of preferred stock. No shares of preferred stock were issued as of December 31, 2012.

On February 19, 2013, the Company completed a private offering with affiliates of White Deer Energy L.P. (“White Deer Energy”) pursuant to the terms of a securities purchase agreement (“Securities Purchase Agreement”), to which, in exchange for a cash investment of $50 million, the Company issued the following to White Deer Energy ( “Investor”):

500,000 shares of Series A Perpetual Preferred Stock, $0.001 par value per share (the “Series A Preferred Stock”);

5,114,633 shares of Series B Voting Preferred Stock, $0.001 par value per share (the “Series B Preferred Stock”); and

warrants to purchase an initial aggregate 5,114,633 shares of the Company’s common stock, $0.001 par value per share, at an initial exercise price of $5.77 per share. These warrants are exercisable until December 31, 2019.

The Series A Preferred Stock has a cumulative dividend rate of 10% per annum, payable quarterly on each March 31, June 30, September 30 and December 31, commencing on March 31, 2013. If the Company voluntarily or involuntarily liquidates, dissolves or winds up its affairs, the Series A Preferred Stock will be entitled to receive out of available assets, after satisfaction of liabilities to creditors, if any, and before any distribution of assets is made on the Company’s common stock or any other shares of junior stock, a liquidating distribution in the amount, with respect to each share of Series A Preferred Stock, equal to the sum of (a)(1) on or prior February 19, 2015, $112.50, (2) from February 20, 2015 through February 19, 2016, $110.00, (3) from February 20, 2016 through February 19, 2017, $105.00 and (4) thereafter, $100.00 and (b) the accrued and unpaid dividends thereon (the “Liquidation Preference”). Prior to April 1, 2015, the Company may pay dividends on the Series A Preferred Stock either (x) in cash or (y) by issuance of (A) additional shares of Series A Preferred Stock valued at the same value as the initial per share purchase price of the Series A Preferred Stock and (B) an additional warrant to purchase shares of common stock; provided that such dividends must be paid in cash unless and until the shareholder approval is obtained to authorize the issuance of any additional warrants and any shares of common stock issuable upon exercise of such additional warrants. The Company has the option to redeem shares of Series A Preferred Stock in whole or in part at any time at the aggregate Liquidation Preference, subject to a minimum redemption amount equal to the lesser of 50,000 shares or the number of shares then outstanding. Upon a change of control, the Investor has the right to require the Company to purchase the Series A Preferred Stock at the Liquidation Preference. The Series A Preferred Stock does not vote generally with the Company’s common stock, but has specified approval rights with respect to, among other things, changes to organizational documents that affect the Series A Preferred Stock, payment of dividends on the Company’s common stock or other junior stock, redemptions or repurchases of common stock or other capital stock and incurrence of certain indebtedness. Upon the occurrence of certain events of default under the credit facility with Wells Fargo Bank, N.A., the Investor has additional specified approval rights with respect to, among other things, the incurrence or guarantee by the Company of any indebtedness, any change in compensation or benefits of employment or severance agreements with officers and any agreement or arrangement pursuant to which the Company or any of its subsidiaries would pay or incur liability in excess of $1,000,000 over the term of such agreement or arrangement. In addition, upon an event of default, the Investor has the right to require the Company to purchase the Series A Preferred Stock at the Liquidation Preference.

For the three-months ended March 31, 2013 and 2012, the Company paid dividends on the Series A Preferred Stock of $616,438, and $0, respectively.

The Series B Preferred Stock is entitled to vote, until January 1, 2020, in the election of directors and on all other matters submitted to a vote of the holders of common stock as a single class. Each share of Series B Preferred Stock has one vote. The Series B Preferred Stock has no dividend rights and a liquidation preference of $0.001 per share. On and from time to time after January 1, 2020 the Company may redeem, in whole or in part, the then-outstanding shares of Series B Preferred Stock, at a redemption price per share equal to $0.001. Each share of Series B Preferred Stock was issued as part of a unit with a warrant to purchase one share of common stock and will be surrendered to the Company upon exercise of a warrant.

The warrants entitle the Investor to acquire a number of shares of common stock equal to approximately 19.75% of the Company’s shares of common stock outstanding as of February 19, 2013, or approximately 16.49% of outstanding common stock on a diluted basis taking into account the exercise of the warrants. The warrants may be exercised by the Investor through the surrender of an equal number of shares of Series B Preferred Stock and tendering the $5.77 per share exercise price to the Company. In lieu of exercising the warrants for cash, the Investor may deliver for cancellation a number of shares of Series A Preferred Stock equal to the exercise price. See Note 13 for further discussion on the warrants.

Upon a change of control or Liquidation Event, as defined in the Securities Purchase Agreement, the Investor has the right, but not the obligation, to elect to receive from the Company, in exchange for all, but not less than all, shares of Series A and Series B Preferred Stock and the warrants issued pursuant to the Securities Purchase Agreement and shares of common stock issued upon exercise thereof that are then held by the Investor,an additional cash payment necessary to achieve a minimum internal rate of return of 25% as calculated as defined. The calculation will take into account all cash inflows from and cash outflows to the Investor.

The Company recorded the transaction by recognizing the fair value of the Series A Preferred Stock at $38,552,994 (net of offering costs of $2,816,006), Series B Preferred Stock at $5,000 and a warrant liability of $8,626,000 at time of issuance. The Company analyzed the terms of the issuance and has determined the components of the agreement are properly reflected in the accounting treatment. The Company will accrete the Series A Preferred Stock to the liquidation or redemption value when it becomes probable that the event or events underlying the liquidation or redemption are probable.

Stock Awards and Stock Unit Awards

The Company did not grant any restricted stock or restricted stock units during the three months ended March 31, 2013. The Company incurred compensation expense associated with restricted stock granted prior to 2013 of $913,298 and $26,787 for the three months ended March 31, 2013 and 2012, respectively. For the three months ended March 31, 2013, the Company capitalized compensation expense associated with the restricted stock and restricted stock units of $37,954 to oil and natural gas properties. As of March 31, 2013, there was $6,371,008 of total unrecognized compensation cost related to restricted stock and restricted stock units, which is expected to be amortized over a weighted-average period of 1.2 years. The Company recognizes compensation cost for performance based grants on a tranche level basis over the requisite service period for the entire award. The fair value of restricted stock units granted is based on the stock price on the grant date and the Company assumed no annual forfeiture rate.

As of March 31, 2013, there were 1,827,727 unvested restricted stock units and 2,857 unvested restricted stock shares with a combined weighted average grant date fair value of $4.31 per share. No vesting occurred during the three months ended March 31, 2013. A summary of the restricted stock units and restricted stock shares outstanding is as follows:

	Number of Shares			Weighted Average Grant Date Fair Value
Non-vested restricted stock and restricted stock units at January 1, 2013		1,847,701		$	4.31

Granted		—			—
Canceled		(17,117	)		4.67
Vested		—			—

Non-vested restricted stock and restricted stock units at March 31, 2013		1,830,584		$	4.31

The Company estimated that $1,196,577 in federal and state withholding taxes was due on restricted stock granted to officers that vested during 2012. Of this amount, the Company estimated that it was responsible for $62,728, which was included in general and administrative expenses for the year ended December 31, 2012 with the remaining $1,133,849 recorded as a receivable from officers as of December 31, 2012. The Company’s officers remitted payment on the receivable to the Company in February and March 2013.

Equity Issuances

The Company issued 851,315 and 313,700 shares of its common stock related to two acreage acquisitions completed on January 9, 2013 and February 4, 2013, respectively. See Note 4 – Oil and Natural Gas Properties – Acquisitions for additional details.

NOTE 7 STOCK OPTIONS AND WARRANTS

Stock Options

On March 22, 2013, the Company granted stock options to certain employees to purchase a total of 18,000 shares of common stock exercisable at $6.59 per share. The options vest equally over 36 months with 6,000 options vesting on March 22, 2014, 2015 and 2016.

The impact on the Company’s statement of operations of stock-based compensation expense related to options granted for the three months ended March 31, 2013 and 2012 was $394,688 and $140,220, respectively, net of $0 tax. The Company capitalized $61,598 of compensation to oil and natural gas properties related to outstanding options for the three months ended March 31, 2013. The Company will recognize approximately $985,000 of compensation expense in future periods relating to options that have been granted but have not vested as of March 31, 2013.

The following assumptions were used for the Black-Scholes model to value the options granted during the three months ended March 31, 2013.

Risk free rates	0.14	%
Dividend yield	0	%
Expected volatility	66.74	%
Weighted average expected life	4 years

A summary of the stock options outstanding as of January 1, 2013 and March 31, 2013 is as follows:

	Number of Options			Weighted Average Exercise Price
Balance outstanding at January 1, 2013		835,702		$	10.43

Granted		18,000			6.59
Canceled
Exercised		(50,000	)		4.43

Balance outstanding at March 31, 2013		803,702		$	10.81

Options exercisable at March 31, 2013		428,557		$	13.08

At March 31, 2013, stock options outstanding were as follows:

	Options Outstanding						Options Exercisable
Year of Grant	Number of Options Outstanding		Weighted Average Remaining Contract Life (years)		Weighted Average Exercise Price		Number of Options Exercisable		Weighted Average Remaining Contract Life (years)		Weighted Average Exercise Price
2013		18,000		7.98	$	6.59		—		—	$	—
2012		635,713		4.67		8.49		278,568		4.48		8.75
Prior		149,989		3.64		21.11		149,989		3.64		21.11

Total		803,702		4.55	$	10.81		428,557		4.19	$	13.08

Warrants

The table below reflects the status of warrants outstanding at March 31, 2013:

	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
February 19, 2013		5,114,633	$	5.77	December 31, 2019
		6,230,783

No warrants expired or were forfeited during the three months ended March 31, 2013. The Company recorded no expense related to these warrants for the three months ended March 31, 2013. As of March 31, 2013, all of the compensation expense related to the applicable vested warrants has been expensed by the Company. All warrants outstanding were exercisable at March 31, 2013. See Note 13 for details on the treatment of the warrants issued on February 19, 2013.

NOTE 8 REVOLVING CREDIT FACILITY

Wells Fargo

On November 20, 2012, the Company entered into a credit agreement (the “Credit Agreement”) with Wells Fargo Bank, N.A. (“Wells Fargo”), as administrative agent, and the lenders party thereto. The Credit Agreement is a senior secured reserve-based revolving credit facility with a maximum commitment of $400 million and an initial borrowing base of $27.5 million (the “Wells Fargo Facility”).

Amounts borrowed under the Wells Fargo Facility will mature on November 20, 2017, and upon such date, any amounts outstanding under the Wells Fargo Facility are due and payable. Redeterminations of the borrowing base will be on a semi-annual basis, with an option to elect an additional redetermination every six months between the semi-annual redeterminations.

The annual interest cost, which is dependent upon the percentage of the borrowing base utilized, is, at the Company’s option, based on either the Alternate Base Rate (as defined in the Credit Agreement) plus 0.75% to 1.75% or the London Interbank Offer Rate (LIBOR) plus 1.75% to 2.75%; provided, in no event may the interest exceed the maximum interest rate allowed by any current or future law. As of March 31, 2013, the annual interest rate on the Wells Fargo Facility was 2.81%, which is based on LIBOR plus 2.25%. Interest on ABR Loans is due and payable on a quarterly basis, and interest on Eurodollar Loans is due and payable, at the Company’s option, at one-, two-, three-, six- (or in some cases nine- or twelve-) month intervals. The Company will also pay a commitment fee ranging from 0.375% to 0.5%, depending on the percentage of the borrowing base utilized.

A portion of the Wells Fargo Facility not in excess of $5 million will be available for the issuance of letters of credit by Wells Fargo. The Company will pay a rate per annum ranging from 1.75% to 2.75% on the face amount of each letter of credit issued and will pay a fronting fee equal to the greater of $500 and 0.125% of the face amount of each letter of credit issued. As of March 31, 2013, the Company has not obtained any letters of credit under the Wells Fargo Facility.

Each of the Company’s subsidiaries is a guarantor under the Wells Fargo Facility. The Wells Fargo Facility is secured by first priority, perfected liens and security interests on substantially all assets of the Company and the guarantors, including a pledge of their ownership in their respective subsidiaries.

The Credit Agreement contains customary covenants that include, among other things: limitations on the ability of the Company to incur or guarantee additional indebtedness; create liens; pay dividends on or repurchase stock; make certain types of investments; enter into transactions with affiliates; and sell assets or merge with other companies. The Credit Agreement also requires compliance with certain financial covenants, including, (a) a ratio of current assets to current liabilities of at least 1.00 to 1.00, (b) a maximum ratio of debt to EBITDA for the preceding four fiscal quarters of no more than 3.50 to 1.00, and (c) a fixed charge coverage ratio for any four fiscal quarters of at least 3.00 to 1.00. The Company was in compliance for all covenants as of March 31, 2013.

The Company had approximately $12.3 million and $4.0 million available under the Wells Fargo Facility as of March 31, 2013 and December 31, 2012, respectively. The principal balance amount on the Credit Agreement was approximately $15.2 million and $23.5 million at March 31, 2013 and December 31, 2012, respectively.

Macquarie Bank Limited

On February 10, 2012, the Company entered into a credit facility (the “Macquarie Facility”) with Macquarie Bank Limited (“MBL”). The Macquarie Facility provided 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 Macquarie Facility based on reserves (Tranche A), with an additional $50 million available under a development tranche (Tranche B).

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 Macquarie Facility and drew $15 million of additional debt on a new third tranche at an initial rate of 9% above the applicable 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. The Macquarie Facility was paid in full on November 20, 2012.

NOTE 9 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 the Macquarie Facility (see Note 8 – Revolving Credit Facility).

NOTE 10 ASSET RETIREMENT OBLIGATION

The Company has asset retirement obligations associated with the future plugging and abandonment of its proved oil and natural gas properties and related facilities. Under the provisions of 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 depleted using the units of production method. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors (2.5% for each of the years in the three-year period ended March 31, 2013); and (iv) a credit-adjusted risk-free interest rate (average of 7.0% for each of the years in the three-year period ended March 31, 2013). These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change. 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 ASC 410-20-25 for the three month period ended March 31, 2013 and the year ended December 31, 2012:

	March 31, 2013		December 31, 2012
Beginning Asset Retirement Obligation	$	296,074	$	116,119
Liabilities Incurred or Acquired		47,141		164,967
Accretion of Discount on Asset Retirement Obligations		6,212		14,988
Ending Asset Retirement Obligation	$	349,427	$	296,074

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. Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized. As of March 31, 2013, 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

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 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.

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 level in the fair value hierarchy within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The Company’s policy is to recognize transfer in and/or out of fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Company has consistently applied the valuation techniques discussed below for the periods presented. These valuation policies are determined by the Company’s Chief Accounting Officer and approved by the Chief Financial Officer. They are discussed with the Company’s Audit Committee as deemed appropriate. Each quarter, the Chief Accounting Officer and Chief Financial Officer update the inputs used in the fair value measurement and internally review the changes from period to period for reasonableness. The Company uses data from peers as well as external sources in the determination of the volatility and risk free rates used in the Company’s fair value calculations. A sensitivity analysis is performed as well to determine the impact of inputs on the ending fair value estimate.

Fair Value on a Recurring Basis

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 March 31, 2013:

	Fair Value Measurements at March 31, 2013 Using
	Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Warrant Liability – Long Term Liability	$	—	$	—		$	(12,065,000	)
Commodity Derivatives – Current Liability (oil swaps)		—		(699,490	)		—
Commodity Derivatives – Long Term Liability (oil swaps)		—		(100,120	)		—
Total	$	—	$	(799,610	)	$	(12,065,000	)

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 December 31, 2012:

	Fair Value Measurements at December 31, 2012 Using
	Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity Derivatives – Current Liability (oil swaps and collars)	$	—	$	(206,645	)	$	—
Commodity Derivatives – Long Term Asset (oil swaps and collars)		—		25,397			—
Total	$	—	$	(181,248	)	$	—

Level 2 assets consist of commodity derivative assets and liabilities (See Note 13 – Derivative Instruments and Price Risk Management). The fair value of the commodity derivative assets and liabilities are estimated by the Company using the income valuation techniques utilizing an option pricing or discounted cash flow model, as appropriate, which take into account notional quantities, market volatility, market prices, contract parameters and discount rates based on published LIBOR rates. The Company validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets. Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads, are applied to the Company’s commodity derivatives. Significant changes in the quoted forward prices for commodities andchanges in market volatility generally leads to corresponding changes in the fair value measurement of the Company’s oil derivative contracts. The fair value of all derivative contracts is reflected on the consolidated balance sheets.

Level 3 warrant liabilities – See Note 13 – Derivative Instruments and Price Risk Management for discussion of the valuation method and assumptions used.

A rollforward of Level 3 warrants liability measured at fair value using level 3 on a recurring basis is as follows (in thousands):

Balance, at December 31, 2012	$	—
Purchases, issuances, and settlements		(8,626,000	)
Change in Fair Value of Warrant Liability		(3,439,000	)
Transfers		—
Balance, at March 31, 2013	$	(12,065,000	)

The change in in fair value of warrant liabilities at March 31, 2013 was $3,439,000 for the three months ended March 31, 2013, and is included in other income/expense on the accompanying condensed consolidated statements of operations. See discussion of assumptions used in valuing the warrants at Note 13 – Derivative Instruments and Price Risk Management.

Nonrecurring Fair Value Measurements

The Company follows the provisions of ASC 820-10 for nonfinancial assets and liabilities measured at fair value on a nonrecurring basis. As it relates to the Company, ASC 820-10 applies to certain nonfinancial assets and liabilities as may be acquired in a business combination and thereby measured at fair value and the initial recognition of asset retirement obligations for which fair value is used.

The asset retirement obligation estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3. A reconciliation of the beginning and ending balances of the Company’s asset retirement obligation is presented in Note 10.

The Company’s non-derivative financial instruments include cash and cash equivalents, accounts receivable, accounts payable, the revolving credit facility and the Series A and Series B Preferred Stock. 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 Series A Preferred Stock had a fair value $41,518,000 and a carrying value of $38,552,994 as of March 31, 2013. The fair value was determined by discounting the cash flows over the remaining life of the preferred stock utilizing the LIBOR interest rates. The Series B Preferred Stock’s carrying value approximated its fair value. The Company has classified the valuations of the credit facility and the preferred stock under Level 2 item of the fair value hierarchy.

NOTE 13 DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT

Commodity

The Company utilizes commodity swap contracts 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.

The Company realized a loss on settled derivatives of $149,208 and $27,543 and a loss on mark-to-market of derivatives instruments of $618,396 and $884,892 for the three month periods ended March 31, 2013 and 2012, respectively.

The following table reflects open commodity swap contracts as of March 31, 2013, the associated volumes and the corresponding weighted average NYMEX reference price:

Settlement Period	Oil (Barrels)		Fixed Price		Weighted Avg NYMEX Reference Price
Oil Swaps
April 1, 2013 – December 31, 2013		102,884	$	91.00	$	93.12
January 1, 2014 – December 31, 2014		103,267	$	91.00	$	93.12
January 1, 2015 – February 28, 2015		13,876	$	91.00	$	93.12
Total		220,027

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 Wells Fargo Bank, N.A. that provide for offsetting payables against receivables from separate derivative instruments.

Warrant Liability

The warrants issued with the Securities Purchase Agreement are classified as liabilities on the consolidated balance sheets because the warrants contain a contingent put and other liability type provisions (see Note 6 – Preferred and Common Stock). The shares underlying the warrants are contingently redeemable and are subject to remeasurement at each balance sheet date, and any changes in fair value will be recognized as a component of other (expense) income on the accompanying consolidated statements of operations.

The Company estimated the value of the warrants issued with the Securities Purchase Agreement on the date of issuance to be $8,626,000, or $1.69 per warrant, using the Monte Carlo model with the following assumptions: a term of 1,798 trading days, exercise price of $5.77, volatility rate of 40%, and a risk-free interest rate of 1.38%. The Company remeasured the warrants as of March 31, 2013, using the same Monte Carlo model, using the following assumptions: a term of 1,757 trading days, exercise price of $5.77, stock price of $7.04, volatility rate of 40%, and a risk-free interest rate of 1.2%. As of March 31, 2013, the fair value of the warrants was $12,065,000, and was recorded as a liability on the accompanying consolidated balance sheets. An increase in the volatility would cause an increase in the fair value of the warrants. Likewise, a decrease in the volatility would cause a decrease in the value of the Warrants.

At March 31, 2013, the Company had derivative financial instruments recorded on the condensed consolidated balance sheet as set forth below:

Type of Contract	Balance Sheet Location
Derivative Liabilities:
Swap Contracts	Current liabilities	$	(699,490	)
Swap Contracts	Non-current liabilities		(100,120	)
Warrant Liability	Non-current liabilities		(12,065,000	)
Total Derivative Liabilities		$	(12,864,610	)

For the three-months ended March 31, 2013, the Company recorded the change in values for the derivative instruments as set forth below:

Type of Contract	Statement of Operation Location
Unrealized Losses:
Swap Commodity Contracts	Loss on Commodity Derivatives	$	(618,396	)
Warrant Liability	Warrant Revaluation Expense		(3,439,000	)
Total Unrealized Losses		$	(4,057,396	)

Realized Losses:
Swap Commodity Contracts	Loss on Commodity Derivatives	$	(149,208	)
Total Realized Losses		$	(149,208	)

For the three-months ended March 31, 2012, the Company recorded the change in values for the derivative instruments as set forth below:

Type of Contract	Statement of Operation Location
Unrealized Losses:
Costless Commodity Collars	Loss on Commodity Derivatives	$	(884,892	)
Total Unrealized Losses		$	(884,892	)

Realized Losses:
Costless Commodity Collars	Loss on Commodity Derivatives	$	(27,543	)
Total Realized Losses		$	(27,543	)

NOTE 14 COMMITMENTS AND CONTINGENCIES

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

NOTE 15 SUBSEQUENT EVENTS

Non-Operated Acreage Sale

On April 17, 2013, the Company sold its interest in approximately 970 net mineral acres in the Williston Basin for a total sale price of approximately $5,900,000, including sales price adjustments for development costs and production revenue previously recognized by the Company. The acreage was associated with working interests in Williston Basin Bakken and Three Forks wells not operated by the Company. The Company is currently determining the appropriate sales allocation for this transaction.

Derivative Instrument

On April 26, 2013, the Company executed the following NYMEX West Texas Intermediate oil derivative swap contract with a total notional quantity of 75,000 barrels of crude oil for a price of $90.05 with Wells Fargo beginning May 1, 2013 through February 28, 2015 as indicated below:

Settlement Period	Oil (Barrels)		Fixed Price
Oil Swaps
May 1, 2013 – December 31, 2013		39,000	$	90.05
January 1, 2014 – December 31, 2014		31,000	$	90.05
January 1, 2015 – February 28, 2015		5,000	$	90.05
Total		75,000

Acreage Acquisition

On April 29, 2013, the Company entered into a purchase and sale agreement with a third party to acquire approximately 5,874 net acres of undeveloped leasehold in McKenzie County, North Dakota for approximately $6.5 million, or approximately $1,100 per net acre. The purchase is expected to close on May 10, 2013. The Company is currently determining the appropriate purchase allocation for this transaction.

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 on the development of operated wells in the Williston Basin in North Dakota and Montana.

On July 26, 2012, we completed the acquisition of Emerald Oil North America, Inc., formerly Emerald Oil, Inc., from Emerald Oil & Gas NL for approximately 1.66 million of our shares of common stock, which represented approximately 19.9% of our outstanding common stock as of the closing date. As part of the acquisition, we agreed to retain Emerald Oil North America’s liabilities, including approximately $20.3 million in debt. Following the close of the acquisition, we changed our name from Voyager Oil & Gas, Inc. to Emerald Oil, Inc. and began our transition to an operator in the Williston Basin.

Since the acquisition of Emerald Oil North America, we established an operated drilling program in McKenzie County, North Dakota. We added experienced operating personnel during this period to insure successful execution of our operated program. The addition of 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. We monitor and plan to continue to monitor offset operator drilling activity in the Williston Basin, and as development activity increases and well designs improve to enhance production and well economics, we plan to replicate and improve upon the well designs and drilling and completion techniques that we believe represent best practices in the area.

As of March 31, 2013, we had approximately 49,000 net acres in the Williston Basin. Pro forma for closed and pending acquisitions in 2013, we currently hold approximately 54,000 net acres. We have identified approximately 285 net potential drilling locations on this acreage prospective for oil in the Bakken and Three Forks formations. The majority of our capital expenditures in 2013 are expected to be directed toward drilling operated Bakken and Three Forks wells. We plan to leverage our management team’s collective technical, land, financial, and industry operating experience to execute our operated well development program in the Williston Basin that we believe will provide significant risk-adjusted returns on capital while enhancing the strategic value of our company.

In addition to our Williston Basin position, we hold positions in the following Rocky Mountain oil and natural gas plays. We have approximately 14,500 net acres in the Sand Wash Basin in northwest Colorado prospective for oil in the Niobrara formation. We have approximately 33,500 net acres in central Montana prospective for oil in the Heath formation. We have approximately 72,800 net acres in the Tiger Ridge Field located in Blaine, Hill, and Chouteau Counties, Montana, prospective for natural gas, and another approximate 1,700 net acres in the Denver-Julesburg (or DJ) Basin in Weld County, Colorado, prospective for oil in the Niobrara formation. We plan to continue to monetize these non-core acreage positions when possible. Through March 31, 2013 the majority of our oil and natural gas production was 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. As we bring our operated wells onto production during second quarter of 2013 and beyond, we expect our operated well production to grow significantly and our non-operated well production to decline as a percentage of the overall production mix.

As of December 31, 2012 our oil and natural gas production was 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. We have been actively trading and expect to continue to trade or swap our non-operated acreage to increase our operated acreage and working interests in areas where we have existing acreage. Most trades are for comparable acreage and mutually beneficial for both us and the other party, as we consolidate and increase our working interests. We also intend to acquire more operated acreage through a variety of means, including cash purchases and the issuance of common stock as purchase price consideration.

Recent Developments

White Deer Energy Securities Purchase Agreement

On February 19, 2013, we completed a private offering with affiliates of White Deer Energy L.P. (“White Deer Energy”), pursuant to which, in exchange for a cash investment of $50 million, we issued the following to White Deer Energy:

500,000 shares of Series A Perpetual Preferred Stock, $0.001 par value per share (the “Series A Preferred Stock”);

5,114,633 shares of Series B Voting Preferred Stock, $0.001 par value per share (the “Series B Preferred Stock”); and

warrants to purchase an initial aggregate 5,114,633 shares of our common stock, $0.001 par value per share, at an initial exercise price of $5.77 per share.

The Series A Preferred Stock has a cumulative dividend rate of 10% per annum, payable quarterly on each March 31, June 30, September 30 and December 31, commencing on March 31, 2013. If we voluntarily or involuntarily liquidate, dissolve or wind up our affairs, the Series A Preferred Stock will be entitled to receive out of our available assets, after satisfaction of liabilities to creditors, if any, and before any distribution of assets is made on our common stock or any other shares of our junior stock, a liquidating distribution in the amount, with respect to each share of Series A Preferred Stock, equal to the sum of (a)(1) on or prior February 19, 2015, $112.50, (2) from February 20, 2015 through February 19, 2016, $110.00, (3) from February 20, 2016 through February 19, 2017, $105.00 and (4) thereafter, $100.00 and (b) the accrued and unpaid dividends thereon (the “Liquidation Preference”). Prior to April 1, 2015, we may pay dividends on the Series A Preferred Stock either (x) in cash or (y) by issuance of (A) additional shares of Series A Preferred Stock valued at the same value as the initial per share purchase price of the Series A Preferred Stock and (B) an additional warrant to purchase shares of common stock; provided that such dividends must be paid in cash unless and until we obtain shareholder approval to authorize the issuance of any additional warrants and any shares of common stock issuable upon exercise of such additional warrants. We have the option to redeem shares of Series A Preferred Stock in whole or in part at any time at the aggregate Liquidation Preference, subject to a minimum redemption amount equal to the lesser of 50,000 shares or the number of shares then outstanding. Upon a change of control or liquidation, the holders of the Series A Preferred Stock have the right, but not the obligation, to require us to purchase all of the Series A Preferred Stock, the Series B Preferred Stock and the warrants at the Liquidation Preference and an additional cash payment necessary to achieve an internal rate of return of 25%. The Series A Preferred Stock does not vote generally with our common stock, but has specified approval rights with respect to, among other things, changes to our organizational documents that affect the Series A Preferred Stock, payment of dividends on our common stock or other junior stock, redemptions or repurchases of common stock or other capital stock and incurrence of certain indebtedness. Upon the occurrence of certain events of default under our credit facility with Wells Fargo Bank, N.A., the holders of the Series A Preferred Stock have additional specified approval rights with respect to, among other things, the incurrence or guarantee by us of any indebtedness, any change in compensation or benefits of or employment or severance agreements with our officers and any agreement or arrangement pursuant to which we or our subsidiaries would pay or incur liability in excess of $1,000,000 over the term of such agreement or arrangement.

The Series B Preferred Stock is entitled to vote, until January 1, 2020, in the election of directors and on all other matters submitted to a vote of the holders of common stock as a single class. Each share of Series B Preferred Stock has one vote. The Series B Preferred Stock has no dividend rights and a liquidation preference of $0.001 per share. On and from time to time after January 1, 2020 we may redeem, in whole or in part, the then-outstanding shares of Series B Preferred Stock, at a redemption price per share equal to $0.001. Each share of Series B Preferred Stock was issued as part of a unit with a warrant to purchase one share of common stock and will be surrendered to us upon exercise of a warrant.

The warrants entitle the holders thereof to acquire a number of shares of common stock equal to approximately 19.75% of our shares of common stock outstanding as of February 19, 2013, or approximately 16.49% of our outstanding common stock on a diluted basis taking into account the exercise of the warrants.

Amendment to Our Credit Facility

In connection with the White Deer Energy investment, we amended our credit facility with Wells Fargo Bank, N.A. to allow for the payment of dividends on the preferred stock we issued to White Deer Energy and include additional definitions related to the issuance of the Series A and Series B Preferred Stock and warrants.

Acreage Acquisitions

On January 9, 2013, we entered into a purchase and sale agreement with a third party pursuant to which we acquired leases of oil and natural gas properties in McKenzie County, North Dakota. As consideration for the approximate $4.7 million purchase price of the acquired leases, we issued 851,315 shares of our common stock at a per share value of $5.50 per share, based on the five-day trading volume-weighted average price of our common stock prior to the closing of the acquisition.

On February 4, 2013, we entered into a purchase and sale agreement with a third party pursuant to which we acquired leases of oil and natural gas properties in McKenzie County, North Dakota. Pursuant to the purchase and sale agreement and as consideration for the approximate $1.9 million purchase price of the acquired leases, we issued 313,700 shares of our common stock at a per share value of $6.058 per share, based on the five-day trading volume-weighted average price of our common stock prior to closing.

For both acquisitions, we issued the shares of common stock in reliance upon the exemption from the registration requirements under the Securities Act of 1933, as amended, provided by Section 4(2) thereof. Under the terms of each purchase and sale agreement, we granted registration rights to the seller.

On April 29, 2013, we entered into a purchase and sale agreement with a third party to acquire approximately 5,874 net acres of undeveloped leasehold in McKenzie County, North Dakota for approximately $6.5 million or approximately $1,100 per net acre. The acquired acreage is directly south and contiguous to the Company’s existing operated area in McKenzie County, North Dakota. The acquisition will add six additional operated drilling spacing units providing the Company with a total of 15 operated drilling spacing units in the area of operation in McKenzie County, North Dakota.

Sand Wash Basin Sale

On January 7, 2013, we entered into a definitive agreement with a third party to sell our undivided 45% working interest in and to certain oil and natural gas leaseholds in the Sand Wash Basin, comprising approximately 31,000 net acres located in Routt and Moffatt Counties, Colorado and Carbon County, Wyoming. On March 28, 2013, we completed the transaction for an aggregate sale price of approximately $10.1 million in cash.

Non-Operated Acreage Sale

On April 17, 2013, we sold our interest in approximately 970 net mineral acres in the Williston Basin for a total sale price of approximately $5,900,000, including sales price adjustments for development costs and production revenue previously recognized. The acreage was associated with working interest in Williston Basin Bakken and Three Forks wells not operated by us. The proceeds from the sale will be used to fund our 2013 drilling program and acreage acquisitions in and around our operated wells.

Assets and Acreage Holdings

As of March 31, 2013, we controlled approximately 171,500 net acres in the following five primary prospect areas:

49,000 net acres in the Williston Basin targeting the Bakken and Three Forks shale oil formations in North Dakota and Montana;

14,500 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;

1,700 net acres in the Denver-Julesburg Basin targeting the Niobrara shale oil formation in Colorado and Wyoming; and

72,800 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

On a pro forma basis for closed and pending transactions in 2013, our Williston Basin acreage position consists of approximately 23,500 net operated acres in McKenzie, Dunn, and Williams 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. Our remaining Williston Basin acreage position consists of approximately 30,500 net acres in Williams, McKenzie, Dunn and Mountrail Counties in North Dakota, and Richland County, Montana, where we hold relatively low working interests. We intend to keep most of our non-operated working interests in leaseholds that contain producing wells in which we are a participant, but will explore means in which we can trade or monetize this acreage as opportunities arise. In non-operated leaseholds that are not yet producing, we intend to trade or swap such leasehold to consolidate our operated working interests in current or future selected core focus areas, sell our interests to help fund our operated program, or maintain our interests to participate in future well development. We may continue to sell some or all of our non-operated leaseholds if we believe that the proceeds can be redeployed into further operated acreage acquisitions or our ongoing drilling program.

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 we expect that they will continue to allow us to leverage valuable technical data across the basin in order 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 over 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 approximately 285 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 12-month period ending December 31, 2013, we plan to spend approximately $90 million on well development in the Williston Basin. Specifically, we plan to spend approximately $82.7 million to drill 8.2 net operated wells at an average estimated cost of $10.0 million per well and approximately $7.4 million to participate in 0.8 net non-operated wells at an average estimated cost of $9.2 million per well. We expect to fund our current 2013 capital expenditure budget using cash-on-hand, cash flow from operations, proceeds from our preferred equity transaction, proceeds from oil and natural gas assets sales, and borrowings under our revolving credit facility.

The following table presents summary data for our Williston Basin project area as of March 31, 2013 for the year ended December 31, 2013:

					Planned Capital Expenditures
	Net Acres		Net Identified Drilling Locations		Net Wells		Drilling Capex
Operated		23,500		129		8.2	$	82.7
Non-Operated		30,500		156		0.8	$	7.4
Total Williston Basin		54,000		285		9.0	$	90.1

Sand Wash Basin

As of March 31, 2013, we owned approximately 14,500 net acres in the Sand Wash Basin prospective for oil in the Niobrara formation in northwestern Colorado and southern Wyoming. On March 28, 2013, we completed the sale of approximately 31,000 net acres in the Sand Wash Basin in southwest Wyoming. In addition to our remaining acreage, we hold a 45% interest in the Slater Dome Gas Gathering pipeline, which extends 18.5 miles from the edge of the Focus Ranch Federal Unit to a gas sales point in Baggs, Wyoming. We intend to sell the balance of our acreage in the Sand Wash Basin contingent upon the resolution of ongoing access right issues. If our operating partner elects to drill appraisal wells in the area, we will analyze their program proposal, but remain focused on deploying capital to the Williston Basin.

Big Snowy Joint Venture — Heath Shale Oil

As of March 31, 2013, we owned an interest in approximately 33,500 net acres located in central Montana as part of a joint venture targeting the Heath shale oil play. During 2012, the number of drilling permits issued and amount of drilling in the area have increased compared with 2011. We believe the Heath shale has similar characteristics to the Bakken and Three Forks formations. 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.

DJ Basin — Niobrara

As of March 31, 2013, we owned an interest in approximately 1,700 net acres in Weld County, Colorado and Laramie County, Wyoming, prospective for the Niobrara formation with 1,400 net acres currently held by production as we continue to monitor the performance and characteristics of the producing wells. We currently have no plans for drilling any additional development wells in the DJ Basin.

Major Joint Venture — Tiger Ridge Natural Gas

As of March 31, 2013, we owned an interest in approximately 72,800 net acres in and around the Tiger Ridge natural gas field in Montana. We participated in drilling two wells with Devon Energy Corporation, both of which were 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. We and our joint venture partners are assessing whether further development is economic at current natural gas prices.

Productive Wells

The following table summarizes gross and net productive operated and non-operated oil wells by state at March 31, 2013 and March 31, 2012. A net well represents our fractional working ownership interest of a gross well. The following table does not include 32 gross (1.02 net) non-operated Bakken and Three Forks wells and 4 gross (2.07 net) operated Bakken wells that were in the process of being drilled, awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation as of March 31, 2013 and 42 gross (2.02 net) non-operated Bakken and Three Forks wells as of March 31, 2012.

	March 31,
	2013				2012
	Gross		Net		Gross		Net
North Dakota Bakken and Three Forks – operated		—		—		—		—
North Dakota Bakken and Three Forks – non-operated		191		7.68		108		4.06
Montana Bakken and Three Forks – non-operated		26		2.26		10		0.97
Colorado Niobrara in DJ Basin – non-operated		4		2.00		5		2.50
Total:		221		11.94		123		7.53

Results of Operations

Comparison of the Three Months Ended March 31, 2013 with the Three Months Ended March 31, 2012.

	Three Months Ended March 31,
	2013			2012
REVENUES
Oil and Natural Gas Sales	$	8,216,981		$	5,098,333
Loss on Commodity Derivatives		(767,604	)		(912,435	)
		7,449,377			4,185,898
OPERATING EXPENSES
Production Expenses		1,039,532			466,630
Production Taxes		701,856			506,021
General and Administrative Expenses		5,388,813			942,131
Depletion of Oil and Natural Gas Properties		3,156,978			1,998,059
Depreciation and Amortization		22,995			11,070
Accretion of Discount on Asset Retirement Obligations		6,212			2,567
Total Expenses		10,316,386			3,926,478

INCOME (LOSS) FROM OPERATIONS		(2,867,009	)		259,420

OTHER INCOME, NET		(3,617,814	)		(515,790	)

LOSS BEFORE INCOME TAXES		(6,484,823	)		(256,370	)

INCOME TAX EXPENSE		—			—

NET LOSS		(6,484,823	)		(256,370	)
Less: Preferred Stock Dividends		(616,438	)		—
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(7,101,261	)	$	(256,370	)

Revenues

Revenues from sales of oil and natural gas were $8.2 million for the three months ended March 31, 2013 compared to $5.1 million for the three months ended March 31, 2012. For the three months ended March 31, 2013, our total production volumes on a Boe basis increased 68% as compared to the three months ended March 31, 2012. Production primarily increased due to the addition of 4.91 net productive non-operated wells in the Williston Basin in from April 1, 2012 to March 31, 2013. During the three months ended March 31, 2013, we realized an $88.04 average price per barrel of oil (including realized derivatives) compared to a $91.29 average price per barrel of oil during the three months ended March 31, 2012.

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

	Three Months Ended March 31,
	2013			2012
Net Oil and Natural Gas Revenues:
Oil	$	7,993,902		$	5,024,099
Natural Gas and Other Liquids		223,079			74,234
Total Oil and Natural Gas Sales Before Derivatives		8,216,981			5,098,333
Realized Loss on Commodity Derivatives		(149,208	)		(27,543	)
Unrealized Loss on Commodity Derivatives		(618,396	)		(884,892	)
Total Oil and Natural Gas Sales Net of Derivatives		7,449,377			4,185,898

Net Production:
Oil (Bbl)		89,112			54,735
Natural Gas and Other Liquids (Mcf)		40,195			12,777
Barrel of Oil Equivalent (Boe)		95,811			56,865

Average Sales Prices:
Oil (per Bbl)	$	89.71		$	91.79
Effect of Settled Oil Derivatives on Average Price (per Bbl)		(1.67	)		(0.50	)
Oil Net of Settled Derivatives (per Bbl)	$	88.04		$	91.29

Natural Gas and Other Liquids (per Mcf)	$	5.55		$	5.81

Barrel of Oil Equivalent with Realized Derivatives (per Boe)	$	84.21		$	89.17

Loss on Commodity Derivatives

Realized commodity derivative losses were $149,208 and $27,543 for the three months ended March 31, 2013 and 2012, respectively. Unrealized commodity derivative losses were $618,396 and $884,892 for the three months ended March 31, 2013 and 2012, respectively. 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 March 31, 2013, all of our derivative contracts are recorded at their fair value, which was a net liability of $799,610.

Expenses

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

	Three Months Ended March 31,
	2013		2012
Costs and Expenses Per Boe of Production :
Production Expenses	$	10.85	$	8.21
Production Taxes		7.33		8.90
G&A Expenses (Excluding Share-Based Compensation)		42.59		10.80
Shared-Based Compensation		13.65		5.76
Depletion of Oil and Natural Gas Properties		32.95		35.14
Depreciation and Amortization		0.24		0.19
Accretion of Discount on Asset Retirement Obligation		0.06		0.05

Production Expenses

Production expenses were $1,039,532 for the three months ended March 31, 2013 compared to $466,630 for the three months ended March 31, 2012. 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 were $10.85 per barrel sold for the three months ended March 31, 2013 compared to $8.21 for the three months ended March 31, 2012. These increases are related to higher operating costs primarily in our Williston Basin wells. The largest cost driver in our Williston Basin wells is the disposal of water.

Production Taxes

Production taxes were $701,856 for the three months ended March 31, 2013 compared to $506,021 for the three months ended March 31, 2012. We pay production taxes based on realized oil and natural gas sales. Our production taxes were 8.5% for the three months ended March 31, 2013 compared to 9.9% for the three months ended March 31, 2012. Certain portions of our production occur 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 of 11.5%.

General and Administrative Expense

General and administrative expenses were $5,388,813 for the three months ended March 31, 2013 compared to $942,131 for the three months ended March 31, 2012. The increase is due to our change in corporate strategy to add operating capabilities to develop our own operated wells in the Williston Basin. We added substantial operating personnel while we increased our operating drilling activities. This strategic change allows us the opportunity to significantly grow production by using industry best practices and to control well design and capital expenditures to maximize our return on capital. Specifically, expenses for the three months ended March 31, 2013 increased on a period-over-period basis compared to the three months ended March 31, 2012 due to an increase of $1,791,637 for employee compensation and related expense and an increase of $876,751 related to professional and legal expense. During the three months ended March 31, 2013, we incurred increased fees to banks and attorneys for work on closed acquisitions and divestitures during the period. Share-based compensation expenses are included in the employee compensation and related expenses, totaling $1,307,986 for the three months ended March 31, 2013 compared to $327,725 for the three months ended March 31, 2012. As we implement our operating strategy, expenses have increased to attract and retain experienced personnel that can execute on building our operating capabilities.

Depletion Expense

Our depletion expense is driven by many factors, including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. Depletion expense was $3,156,978 for the three months ended March 31, 2013 compared to $1,998,059 for the three months ended March 31, 2012. On a per-unit basis, depletion expense was $32.95 per Boe for the three months ended March 31, 2013 compared to $35.14 per Boe for the three months ended March 31, 2012. 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 was due primarily to the addition of 4.91 net productive non-operated wells in the Williston Basin from April 1, 2012 to March 31, 2013.

Other Expense, net

Other expense, net was $(3,617,814) for the three months ended March 31, 2013 compared to $(515,790) for the three months ended March 31, 2012. We recognized an unrealized loss of $3,439,000 on the warrant liability during the three months ended March 31, 2013. Our warrant liability is 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. Interest expense was $(179,400) for the three months ended March 31, 2013, compared to $(515,790) for the three months ended March 31, 2012. The decrease in interest expense is primarily due to the payoff of the senior secured notes and the write-off of all remaining debt issuance costs attributable to the senior secured notes during the three months ended March 31, 2012.

Net Loss Attributable to Common Stockholders

We had net loss attributable to common stockholders of $7,101,261 for the three ended March 31, 2013 (representing $(0.28) per share-basic and diluted) compared to a net loss of $256,370 for the three months ended March 31, 2012 (representing $(0.03) per share-basic and diluted). The increase in net loss available to common shareholders in our period-over-period results is primarily due to unrealized losses on mark-to-market derivatives totaling $4,057,396, preferred stock dividends of $616,438 and increased employment and employment-related expenses during the three months ended March 31, 2013.

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

	Three Months Ended March 31,
	2013			2012
Net loss	$	(6,484,823	)	$	(256,370	)
Less: Preferred stock dividends		(616,438	)		—
Net loss attributable to common stockholders		(7,101,261	)		(256,370	)
Add: Interest expense		179,490			515,790
Accretion of discount on asset retirement obligations		6,212			2,567
Depletion, depreciation and amortization		3,179,973			2,009,129
Stock-based compensation		1,307,986			327,725
Unrealized loss on commodity derivatives		618,396			884,892
Warrant revaluation expense		3,439,000			—
Preferred stock dividends		616,438			—
Adjusted EBITDA	$	2,246,234		$	3,483,733

Adjusted Income (Loss)

In addition to reporting net income (loss) as defined under GAAP, we also present net earnings before the effect of unrealized gain (loss) from mark-to-market on commodity derivatives and mark-to-market on our warrant liability (“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 March 31,
	2013			2012
Net loss	$	(6,484,823	)	$	(256,370	)
Less: Preferred stock dividends		(616,438	)		—
Net loss attributable to common stockholders		(7,101,261	)		(256,370	)
Unrealized loss on commodity derivatives		618,396			884,892
Warrant revaluation expense		3,439,000			—
Adjusted income (loss)	$	(3,043,865	)	$	628,522

Adjusted income (loss) per share – basic	$	(0.12	)	$	0.08

Weighted average shares outstanding – basic		25,692,532			8,265,788

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 and preferred stock and by long-term and short-term borrowings. In the future, we anticipate we will be able to provide the necessary liquidity from our cash on hand, the revenues generated from the sales of our oil and natural gas reserves in our existing properties, proceeds from the sale of oil and natural gas assets and availability under our credit facility; however, if we do not generate sufficient cash flow from operations or do not have availability under our credit facility, we may attempt to continue to finance our operations through equity and/or debt financings.

The following table summarizes total current assets, total current liabilities and working capital at March 31, 2013.

Current assets	$	54,420,032
Current liabilities		36,119,291
Working capital	$	18,300,741

Series A Preferred Stock Transaction

During the quarter ended March 31, 2013, wecompleted a private offering with affiliates of White Deer Energy L.P. (“White Deer Energy”) pursuant to a securities purchase agreement (“Securities Purchase Agreement”), pursuant to which, in exchange for a cash investment of $50 million, we issued the following to White Deer Energy:

500,000 shares of Series A Perpetual Preferred Stock, $0.001 par value per share (the “Series A Preferred Stock”);

5,114,633 shares of Series B Voting Preferred Stock, $0.001 par value per share (the “Series B Preferred Stock”); and

warrants to purchase an initial aggregate 5,114,633 shares of our common stock, $0.001 par value per share, at an initial exercise price of $5.77 per share. These warrants are exercisable until December 31, 2019.

The Series A Preferred Stock accumulates dividends at 10% per annum, which requires us to make quarterly payments in either (i) cash or (ii) until April 1, 2015 and subject to obtaining prior shareholder approval to issue such shares and warrants,by issuance of (A) additional shares of Series A Preferred Stock valued at the same value as the initial per share purchase price of the Series A Preferred Stock and (B) an additional warrant to purchase shares of common stock.

Upon a change of control or event of default, the holders of the Series A Preferred Stock have the right to require us to purchase the Series A Preferred Stock at the liquidation preference. The liquidation preference specifies the Series A Preferred Stock will be entitled to receive out of our available assets, after satisfaction of liabilities to creditors, if any, and before any distribution of assets is made on our common stock or any other shares of our junior stock, a liquidating distribution in the amount, with respect to each share of Series A Preferred Stock, equal to the sum of (a)(1) on or prior February 19, 2015, $112.50, (2) from February 20, 2015 through February 19, 2016, $110.00, (3) from February 20, 2016 through February 19, 2017, $105.00 and (4) thereafter, $100.00 and (b) the accrued and unpaid dividends thereon. The holders also have the right, but not the obligation, to elect to receive from the Company, in exchange for all, but not less than all, shares of Series A and Series B Preferred Stock and the warrants issued pursuant to the Purchase Agreement and shares of Common Stock issued upon exercise thereof that are then held by the holders,an additional cash payment necessary to achieve a minimum internal rate of return of 25% as calculated as defined. The calculation will take into account all cash inflows from and cash outflows to the holders.

Credit Facility

On November 20, 2012, we entered into a credit agreement (the “Credit Agreement”) with Wells Fargo Bank, N.A. (“Wells Fargo”), as administrative agent, and the lenders party thereto. The Credit Agreement is a senior secured reserve-based revolving credit facility with a maximum commitment of $400 million and an initial borrowing base of $27.5 million (the “Wells Fargo Facility”).

Amounts borrowed under the Wells Fargo Facility will mature on November 20, 2017, and upon such date, any amounts outstanding under the Wells Fargo Facility are due and payable. Redeterminations of the borrowing base are made on a semi-annual basis, with an option to elect an additional redetermination every six months between the semi-annual redeterminations.

The annual interest cost, which is dependent upon the percentage of the borrowing base utilized, is, at our option, based on either the Alternate Base Rate (as defined in the Credit Agreement) plus 0.75% to 1.75% or the London Interbank Offer Rate (LIBOR) plus 1.75% to 2.75%; provided, in no event may the interest exceed the maximum interest rate allowed by any current or future law. As of March 31, 2013, the annual interest rate on the Wells Fargo Facility was 2.81%, which is based on LIBOR plus 2.25%. Interest on ABR Loans is due and payable on a quarterly basis, and interest on Eurodollar Loans is due and payable, at our option, at one-, two-, three-, six- (or in some cases nine- or twelve-) month intervals. We will also pay a commitment fee ranging from 0.375% to 0.5%, depending on the percentage of the borrowing base utilized.

A portion of the Wells Fargo Facility not in excess of $5 million will be available for the issuance of letters of credit by Wells Fargo. We will pay a rate per annum ranging from 1.75% to 2.75% on the face amount of each letter of credit issued and will pay a fronting fee equal to the greater of $500 and 0.125% of the face amount of each letter of credit issued. As of March 31, 2013, we have not obtained any letters of credit under the Wells Fargo Facility.

Each of our subsidiaries is a guarantor under the Wells Fargo Facility. The Wells Fargo Facility is secured by first priority, perfected liens and security interests on substantially all of our assets and our guarantors, including a pledge of their ownership in their respective subsidiaries.

The Credit Agreement contains customary covenants that include, among other things: limitations on our ability to incur or guarantee additional indebtedness; create liens; pay dividends on or repurchase stock; make certain types of investments; enter into transactions with affiliates; and sell assets or merge with other companies. The Credit Agreement also requires compliance with certain financial covenants, including, (a) a ratio of current assets to current liabilities of at least 1.00 to 1.00, (b) a maximum ratio of debt to EBITDA for the preceding four fiscal quarters of no more than 3.50 to 1.00, and (c) a fixed charge coverage ratio for any four fiscal quarters of at least 3.00 to 1.00. We are in compliance with all covenants as of March 31, 2013.

We had approximately $12.3 million and $4.0 million available under the Wells Fargo Facility as of March 31, 2013 and December 31, 2012, respectively. The principal balance amount on the Credit Agreement was approximately $15.2 million and $23.5 million at March 31, 2013 and December 31, 2012, respectively.

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 cash on hand, increasing cash flow from operations, proceeds from the issuance of preferred stock to White Deer Energy, and increased borrowing capacity based on reserve growth. However, we may scale back our development plan should our projections of cash flow and borrowing capacity fall short of expectations or commodity prices fall substantially. We may also choose to access the equity capital markets to fund acreage acquisitions and/or accelerated drilling at the discretion of management, depending on prevailing market conditions. We will evaluate any potential opportunities for acquisitions as they arise. Given our asset base and anticipated increasing cash flows, we believe we are in a position to take advantage of any appropriately priced acquisition opportunities that may arise. 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 cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion. Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. While we do not currently expect business costs to materially increase, higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel.

Cash and Cash Equivalents

Our total cash resources as of March 31, 2013 were $35,794,375, compared to $10,192,379 as of December 31, 2012. The increase in our cash balance was primarily attributable to the preferred stock issuance described atItem 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Recent Developments, offset by development of oil and natural gas properties and principal payments made under our revolving credit facility.

Net Cash Provided By Operating Activities

Net cash provided by operating activities was $377,822 for the three months ended March 31, 2013 compared to $1,007,098 for the three months ended March 31, 2012. The change in the net cash provided by operating activities is primarily attributable to higher production revenue during the three months ended March 31, 2013, offset by higher general and administrative expenses.

Net Cash Used For Investment Activities

Net cash used in investment activities was $13,019,732 for the three months ended March 31, 2013 compared to $12,176,316 for the three months ended March 31, 2012. The change in net cash used in investment activities is primarily attributable to increased purchase and development of oil and natural gas properties in the Williston Basin, offset by the sale proceeds of approximately $9.7 million.

Net Cash Provided By Financing Activities

Net cash provided by financing activities was $38,243,906 for the three months ended March 31, 2013 compared to $2,181,567 for the three months ended March 31, 2012. The change in net cash provided by financing activities for the three months ended March 31, 2013 is primarily attributable to proceeds from the preferred stock issuance completed on February 19, 2013, offset by repayment of borrowings under the revolving credit facility and payment of preferred stock dividends. The change in net cash provided by financing activities for the three months ended March 31, 2012 is primarily attributable to proceeds from our credit facility completed in February 2012, offset by repayment of senior secured promissory notes.

Off-Balance Sheet Arrangements

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

2013 Drilling Projects

For the 12-month period ending December 31, 2013, we plan to spend approximately $90 million on well development in the Williston Basin. Specifically, we plan to spend approximately $82.7 million to drill 8.2 net operated wells at an average estimated cost of $10.0 million per gross well and approximately $7.4 million to participate in 0.8 net non-operated wells at an average estimated cost of $9.2 million per well. We expect to fund our current 2013 capital expenditure budget using cash-on-hand, cash flow from operations, proceeds from the preferred stock issuance to White Deer Energy, proceeds from assets sales, and borrowings under our revolving credit facility.

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

Critical Accounting Policies

Revenue Recognition and Natural Gas Balancing

We recognize oil and natural gas revenues from our interests in producing wells when production is delivered and title has transferred to the purchaser, 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 March 31, 2013 and December 31, 2012, our natural gas production was in balance,i.e., the cumulative portion of natural gas production taken and sold from wells in which we have an interest equaled our entitled interest in natural gas production from those wells.

Full Cost Method

We follow the full cost method of accounting for oil and natural gas operations whereby all costs related to the exploration and development of oil and natural gas properties are initially capitalized into a single cost center (“full cost pool”). Such costs include land acquisition costs, a portion of employee salaries related to property development, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities. For the three month periods ended March 31, 2013 and 2012, we capitalized $315,792 and $238,615, respectively, of internal salaries, which included $99,552 and $201,271, 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 did not capitalize interest for the three month periods ended March 31, 2013 and 2012.

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. We closed a property sale during the three months ended March 31, 2013 in the Sand Wash Basin (seeItem 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Recent Developments). No gain or loss was recognized and the sale did not significantly alter the relationship between capitalized costs and proved reserves attributable to the Sand Wash Basin. We engage in acreage trades in the Williston Basin, but these trades are for similar acreage both in terms of geographic location and potential resource value.

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 depletion and amortization. For the three month period ended March 31, 2013 and the year ended December 31, 2012, the Company reclassified $0 and $3,625,209, respectively, relating to expiring leases within costs subject to the depletion calculation.

Under the full cost method of accounting, capitalized oil and natural gas property costs less accumulated depletion, net of deferred income taxes, may not exceed a ceiling amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are subject to amortization. Should capitalized costs exceed this ceiling, which is tested on a quarterly basis, an impairment is recognized. The present value of estimated future net revenues was computed by applying prices based on a 12-month arithmetic average of the oil and natural gas prices in effect on the first day of each month, less estimated future expenditures to be incurred in developing and producing the proved reserves (assuming the continuation of existing economic conditions), less any applicable future taxes. Based on calculated reserves at March 31, 2013 and March 31, 2012, the unamortized costs of our oil and natural gas properties did not exceed the ceiling test limit and no impairment expense was recognized.

Joint Ventures

The condensed consolidated financial statements as of March 31, 2013 and 2012 include our accounts and our proportionate share of the assets, liabilities, and results of operations of the joint ventures we are involved in.

Stock-Based Compensation

We have accounted for stock-based compensation under the provisions of ASC 718-10-55. We recognize stock-based compensation expense in the financial statements over the vesting period of equity-classified employee stock-based compensation awards based on the grant date fair value of the awards, net of estimated forfeitures. For options and warrants we use the Black-Scholes option valuation model to calculate the fair value of stock based compensation awards at the date of grant. Option pricing models require the input of highly subjective assumptions, including the expected price volatility. For the stock options and warrants granted we have used a variety of comparable and peer companies to determine the expected volatility input based on the expected term of the options. We believe the use or peer company data fairly represents the expected volatility it would experience if it were in the oil and natural gas industry over the expected term of the options. We use 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 Equity Incentive Plan (the “2011 Plan”), under which 714,286 shares of common stock were reserved. On October 22, 2012, our shareholders approved an amendment to the 2011 Plan to increase the number of shares available for issuance under the 2011 Plan to 3,500,000 shares. The purpose of the 2011 Plan is to promote our success and the success of our affiliates by facilitating the employment and retention of competent personnel and by furnishing incentives to those officers, directors and employees 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 March 31, 2013, 671,568 stock options and 2,758,737 shares of common stock and restricted stock units had been issued to officers, directors and employees under the 2011 Plan, including 1,830,584 unvested restricted stock units. As of March 31, 2013, there are 69,695 shares available for issuance under the 2011 Plan.

Derivative and Other Financial Instruments

Commodity

We have entered into commodity derivative instruments utilizing an oil derivative swap contract to reduce the effect of price changes on a portion of future oil production. Our commodity derivative instruments are measured at fair value and are included in the 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 consolidated statements of operations. Our valuation estimate takes into consideration the counterparties’ credit-worthiness, our 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.

Warrant Liability

From time to time we may have financial instruments such as warrants that may be classified as liabilities when either (a) the holders possess rights to net cash settlement, (b) physical or net equity settlement is not in our control, or (c) the instruments contain other provisions that cause us to conclude that they are not indexed to our equity. Such instruments are initially recorded at fair value and subsequently adjusted to fair value at the end of each reporting period through earnings.

As a part of the Securities Purchase Agreement with White Deer Energy (seeItem 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Recent Developments), we issued warrants that contain a put provision. Accordingly, these warrants are accounted for as a liability. This warrant liability is accounted for at fair value with changes in fair value reported in earnings.

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, 2012 and the other disclosures contained herein and therein, which describe factors that could cause our actual results to differ from those anticipated in the forward-looking statements, including, but not limited to, the following factors:

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

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

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

competition, including competition for acreage in resource play areas;

our ability to retain key members of management;

volatility in commodity prices for oil and natural gas;

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

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

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

interest payment requirements of our debt obligations;

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

substantial impairment write-downs;

our ability to replace oil and natural gas reserves;

environmental risks;

drilling and operating risks;

exploration and development risks;

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

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

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile, and these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. Our revenues during the three months ended March 31, 2013 and 2012 generally have increased or decreased along with any increases or decreases in oil or natural gas prices, but the exact impact on our income is indeterminable given the variety of expenses associated with producing and selling oil and natural gas that also increase and decrease along with oil and natural gas prices.

We entered into our credit facility on November 20, 2012, which allows us to enter into commodity derivative instruments, 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 greater than 80% of the reasonably anticipated projected production from our proved developed producing reserves. We use of these commodity derivative instruments as a means of managing our exposure to price changes. While we structure these derivatives to reduce our exposure to changes in price associated with the derivative commodity, they also may limit the benefit we might otherwise have received from market price increases.

The following table reflects open commodity swap contracts as of March 31, 2013, the associated volumes and the corresponding weighted average NYMEX reference price:

Settlement Period	Oil (Barrels)		Fixed Price		Weighted Avg NYMEX Reference Price
Oil Swaps
April 1, 2013 – December 31, 2013		102,884	$	91.00	$	93.12
January 1, 2014 – December 31, 2014		103,267	$	91.00	$	93.12
January 1, 2015 – February 28, 2015		13,876	$	91.00	$	93.12
Total		220,027

Interest Rate Risk

As of March 31, 2013, we had outstanding borrowings of approximately $15.2 million under our credit facility. Our credit facility with Wells Fargo 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. A 1% increase in short-term interest rates on the floating-rate debt during the first three months of 2013 would result in approximately $171,000 in additional annual interest expense.

ITEM 4. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, or the “Exchange Act”) that are designed to ensure that information required to be disclosed in Exchange Act reports is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure. Any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives.

Our management, with the participation of our chief executive officer and chief financial officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of March 31, 2013. Based upon that evaluation and subject to the foregoing, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures were effective to accomplish their objectives.

Our chief executive officer and chief financial officer do not expect that our disclosure controls or our internal controls will prevent all error and all fraud. The design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be considered relative to their cost. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that we have detected all of our control issues and all instances of fraud, if any. The design of any system of controls also is based partly on certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving our stated goals under all potential future conditions.

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 controls 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. These claims and proceedings are subject to uncertainties inherent in any litigation. However, we believe that all such litigation matters are not likely to have a material adverse effect on our financial position, cash flows or results of operations.

ITEM 1A. RISK FACTORS

Our business is subject to a number of risks, some of which are beyond our control. In addition to the other information set forth in this report, you should carefully consider the factors discussed in Item 1A. - “Risk Factors” of our Annual Report on Form 10-K for the fiscal year endedDecember 31, 2012, as filed with the SEC onMarch 18, 2013, that could have a material adverse effect on our business, results of operations, financial condition and/or liquidity and that could cause our operating results to vary significantly from period to period. As ofMarch 31, 2013, there have been no material changes to the risk factors disclosed in our most recent Annual Report on Form 10-K, except as follows. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition, or operating results.

The dividend and liquidation rights of the holders of our Series A Perpetual Preferred Stock and anti-dilution provisions of our warrants may adversely affect our financial position and the rights of the holders of our common stock.

We have shares of Series A Perpetual Preferred Stock outstanding. We have the obligation to pay to the holders of our Series A Preferred Stock dividends at a per annum rate of 10% on the accrued principal amount of the outstanding shares of Series A Preferred Stock, payable quarterly in cash or, prior to April 1, 2015 and upon prior approval of our shareholders, in-kind in the form of (i) additional shares of Series A Perpetual Preferred Stock valued at the same value as the initial per share purchase price and (ii) a warrant to purchase additional shares of common stock the amount of any unpaid and accrued dividends divided by the 10-day volume weighted average price of our common stock. The payment of dividends in-kind would have a dilutive effect on our common shareholders (as any warrants paid in-kind and issued as dividends will be exercisable into common shares). We are current on dividends through the quarterly period ended March 31, 2013. In the event we are liquidated while any shares of Series A Perpetual Preferred Stock are outstanding, holders of the Series A Perpetual Preferred Stock will be entitled to receive a preferred liquidation distribution, plus any accumulated and unpaid dividends, before holders of common stock receive any distributions. In addition, upon a change of control or liquidation event, the investors have the right, but not the obligation, to receive in exchange for all of the shares of Series A Perpetual Preferred Stock, Series B Voting Preferred Stock, warrants and all shares of common stock issued upon exercise of the warrants, an additional cash payment necessary to achieve an internal rate of return of 25%. Our warrants also contain certain anti-dilution provisions that are triggered in the event we issue equity for consideration below the exercise price of the warrants, which would result in the warrants becoming exercisable into more shares of common stock, thereby potentially further diluting our common shareholders.

Holders of our Series A Perpetual Preferred Stock and Series B Voting Preferred Stock have certain voting and other rights that may adversely affect holders of our common stock, and the holders of our Series A Perpetual Preferred Stock and Series B Voting Preferred Stock may have different interests from, and vote their shares in a manner deemed adverse to, holders of our common stock.

While the holders of Series A Perpetual Preferred Stock are not entitled to vote at shareholder meetings with the holders of the common shares, these shareholders do have certain voting rights including, among other things, the approval of amendments to our articles of incorporation that adversely affect the rights of the Series A Perpetual Preferred Stock, the issuance of debt securities or incurrence of indebtedness for borrowed money, the issuance of any shares of any class or series of capital stock of the Company and the declaration or payment of dividends on our common stock. The holders of the Series B Voting Preferred Stock are entitled to vote at any meeting of the shareholders with the holders of the common shares and to cast the number of votes equal to the number of shares of Series B Voting Preferred Stock held by such holders. As of March 31, 2013, the Series B Preferred Stock holders are entitled to 5,114,633 votes resulting from their ownership of Series B Voting Preferred Stock. The holders of Series A Perpetual Preferred Stock and Series B Voting Preferred Stock may have different interests from the holders of our common stock and could vote their shares in a manner deemed adverse to the holders of common stock.

Our strategy includes acquisitions of oil and natural gas properties, and our failure to identify or complete future acquisitions successfully could reduce our earnings and hamper our growth.

We may be unable to identify properties for acquisition or to make acquisitions on terms that we consider economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. The completion and pursuit of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to grow through acquisitions will require us to continue to invest in operations, financial and management information systems and to attract, retain, motivate and effectively manage our employees. The inability to manage the integration of acquisitions effectively could reduce our focus on subsequent acquisitions and current operations, and could negatively impact our results of operations and growth potential. Our financial position and results of operations may fluctuate significantly from period to period as a result of the completion of significant acquisitions during particular periods. If we are not successful in identifying or acquiring any material property interests, our earnings could be reduced and our growth could be restricted.

We may engage in bidding and negotiating to complete successful acquisitions. We may be required to alter or increase substantially our capitalization to finance these acquisitions through the use of cash on hand, the issuance of debt or equity securities, the sale of production payments, the sale of non-strategic assets, the borrowing of funds or otherwise. If we were to proceed with one or more acquisitions involving the issuance of our common stock, our shareholders would suffer dilution of their interests. Furthermore, our decision to acquire properties that are substantially different in operating or geologic characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in such areas.

ITEM 6. EXHIBITS

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

	2.1	Letter Agreement dated as of January 7, 2013, by and between Emerald Oil, Inc. and East Management Services, LP (incorporated by reference to Exhibit 2.1 to our current report on Form 8-K filed on January 8, 2013)

	3.4	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 February 19, 2013)

	4.1	Form of Warrant issued to investors in the February 2013 private placement (incorporated by reference to Exhibit 4.1 to our current report on Form 8-K filed on February 19, 2013)

	10.1	Second Amendment to Employment Agreement with Mike Krzus effective as of March 16, 2013 (incorporated by reference to Exhibit 10.1 to our current report on Form 8-K filed on March 14, 2013)

	10.2	Second Amendment to Employment Agreement with McAndrew Rudisill effective as of March 16, 2013 (incorporated by reference to Exhibit 10.2 to our current report on Form 8-K filed on March 14, 2013)

	10.3	Second Amendment to Employment Agreement with J.R. Reger effective as of March 16, 2013 (incorporated by reference to Exhibit 10.3 to our current report on Form 8-K filed on March 14, 2013)

	10.4	Second Amendment to Employment Agreement with Paul Wiesner effective as of March 16, 2013 (incorporated by reference to Exhibit 10.4 to our current report on Form 8-K filed on March 14, 2013)

	10.5	Second Amendment to Employment Agreement with Karl Osterbuhr effective as of March 16, 2013 (incorporated by reference to Exhibit 10.5 to our current report on Form 8-K filed on March 14, 2013)

	10.7	First Amendment to Credit Agreement dated as of February 18, 2013, among Emerald Oil, Inc., the Guarantors, the Lenders and Wells Fargo Bank, N.A., as administrative agent for the Lenders (incorporated by reference to Exhibit 10.3 to our current report on Form 8-K filed on February 19, 2013)

	10.8	Securities Purchase Agreement dated February 1, 2013, among Emerald Oil, Inc., WDE Emerald Holdings LLC and White Deer Energy FI L.P. (incorporated by reference to Exhibit 10.1 to our current report on Form 8-K filed on February 6, 2013)

	10.9	Registration Rights Agreement dated February 19, 2013, among Emerald Oil, Inc., WDE Emerald Holdings LLC and White Deer Energy FI L.P. (incorporated by reference to Exhibit 10.1 to our current report on Form 8-K filed on February 19, 2013)

	10.10	Form of Indemnification Agreement (incorporated by reference to Exhibit 10.2 to our current report on Form 8-K filed on February 19, 2013)

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

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

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

	101.INS*	XBRL Instance Document

	101.SCH*	XBRL Schema Document

	101.CAL*	XBRL Calculation Linkbase Document

	101.LAB*	XBRL Label Linkbase Document

	101.PRE*	XBRL Presentation Linkbase Document

* Attached hereto.

SIGNATURES

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

Dated: May 9, 2013	EMERALD OIL, INC.

	/s/ McAndrew Rudisill
	McAndrew Rudisill
	Chief Executive Officer (principal executive officer)

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

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Emerald Oil (EOGSF) Inactive 10-Q2013 Q1 Quarterly report

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