UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2013

OR

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

For the transition period from                  to

Commission File No. 1-35097

Emerald Oil, Inc.

(Exact name of registrant as specified in its charter)

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

1600 Broadway, Suite 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 November 5, 2013, there were 65,297,104 shares of Common Stock, $0.001 par value per share, outstanding.

EMERALD OIL, INC.

INDEX

			Page of
			Form 10-Q
PART I.	FINANCIAL INFORMATION		1
	ITEM 1.	FINANCIAL STATEMENTS (UNAUDITED)	1
		Condensed Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012	1
		Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2013 and 2012	2
		Condensed Consolidated Statement of Stockholders’ Equity for the nine months ended September 30, 2013	3
		Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2013 and 2012	4
		Notes to Condensed Consolidated Financial Statements	5
	ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	26
	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	45
	ITEM 4.	CONTROLS AND PROCEDURES	46
PART II.	OTHER INFORMATION		47
	ITEM 1.	LEGAL PROCEEDINGS	47
	ITEM 1A.	RISK FACTORS	47
	ITEM 6.	EXHIBITS	48
SIGNATURES			49

PART 1 — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EMERALD OIL, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	September 30, 2013			December 31, 2012
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	69,527,908		$	10,192,379
Restricted Cash		15,000,000			—
Accounts Receivable – Oil and Natural Gas Sales		4,537,655			12,573,156
Accounts Receivable – Joint Interest Partners		22,481,032			—
Other Receivables		72,548			1,133,849
Prepaid Expenses and Other Current Assets		435,891			103,173
Total Current Assets		112,055,034			24,002,557
PROPERTY AND EQUIPMENT
Oil and Natural Gas Properties, Full Cost Method
Proved Oil and Natural Gas Properties		149,069,872			167,618,422
Unproved Oil and Natural Gas Properties		49,838,769			61,454,831
Equipment and Facilities		682,230			—
Other Property and Equipment		728,310			385,023
Total Property and Equipment		200,319,181			229,458,276
Less – Accumulated Depreciation, Depletion and Amortization		(42,055,419	)		(80,230,517	)
Total Property and Equipment, Net		158,263,762			149,227,759
Restricted Cash		6,000,000			—
Prepaid Drilling Costs		1,628			100,193
Fair Value of Commodity Derivatives		25,017			25,397
Debt Issuance Costs, Net of Amortization		431,563			269,681
Deposits on Acquisitions		2,500,000			—
Other Non-Current Assets		566,047			260,775
Total Assets	$	279,843,051		$	173,886,362
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts Payable	$	40,473,700		$	39,169,037
Fair Value of Commodity Derivatives		1,431,091			206,645
Accrued Expenses		6,015,432			420,521
Advances from Joint Interest Partners		1,452,969			—
Series A Perpetual Preferred Stock Redemption Liability		16,875,000			—
Total Current Liabilities		66,248,192			39,796,203
LONG-TERM LIABILITIES
Revolving Credit Facility		—			23,500,000
Asset Retirement Obligations		434,109			296,074
Warrant Liability		13,213,000			—
Total Liabilities		79,895,301			63,592,277
COMMITMENTS AND CONTINGENCIES
Preferred Stock – Par Value $.001; 20,000,000 Shares Authorized;
Series B Voting Preferred Stock – 5,114,633 and 0 issued and outstanding at September 30, 2013 and December 31, 2012, respectively.  Liquidation preference value of $5,115 and $0, as of September 30, 2013 and December 31, 2012, respectively.		5,000			—
STOCKHOLDERS’ EQUITY
Common Stock, Par Value $.001; 500,000,000 Shares Authorized, 42,954,252 and 24,734,643 Shares Issued and Outstanding at September 30, 2013 and December 31, 2012, respectively		42,954			24,735
Additional Paid-In Capital		270,019,428			180,439,530
Accumulated Deficit		(70,119,632	)		(70,170,180	)
Total Stockholders’ Equity		199,942,750			110,294,085
Total Liabilities and Stockholders’ Equity	$	279,843,051		$	173,886,362

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

1

EMERALD OIL, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
REVENUES
Oil and Natural Gas Sales	$	17,316,558		$	7,111,569		$	36,108,357		$	18,973,331
Realized and Unrealized Loss on Commodity Derivatives		(2,720,160	)		(1,635,435	)		(2,822,427	)		(296,327	)
		14,596,398			5,476,134			33,285,930			18,677,004
OPERATING EXPENSES
Production Expenses		2,087,635			687,646			4,723,520			1,639,105
Production Taxes		1,879,160			809,062			3,629,557			2,043,671
General and Administrative Expenses		6,194,202			3,503,273			17,562,754			5,660,622
Depletion of Oil and Natural Gas Properties		4,497,002			2,818,650			11,238,783			7,977,077
Impairment of Oil and Natural Gas Properties		—			—			—			10,191,234
Depreciation and Amortization		40,631			12,345			94,665			34,559
Accretion of Discount on Asset Retirement Obligations		7,502			4,037			21,564			10,027
Gain on Sale of Oil and Natural Gas Properties		(8,892,344	)		—			(8,892,344	)		—
Total Operating Expenses		5,813,788			7,835,013			28,378,499			27,556,295
INCOME (LOSS) FROM OPERATIONS		8,782,610			(2,358,879	)		4,907,431			(8,879,291	)
OTHER INCOME (EXPENSE)
Interest Expense		(21,437	)		(1,388,912	)		(276,113	)		(2,074,147	)
Warrant Revaluation Expense		(506,000	)		—			(4,587,000	)		—
Gain on Acquisition of Business, Net		—			5,769,679			—			5,758,048
Other Income (Expense), Net		3,332			(27,046	)		6,230			(27,046	)
Total Other Income (Expense), Net		(524,105	)		4,353,721			(4,856,883	)		3,656,855
INCOME (LOSS) BEFORE INCOME TAXES		8,258,505			1,994,842			50,548			(5,222,436	)
INCOME TAX EXPENSE		—			—			—			—
NET INCOME (LOSS)		8,258,505			1,994,842			50,548			(5,222,436	)
Less: Preferred Stock Dividends and Deemed Dividends		(13,997,089	)		—			(20,279,197	)		—
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(5,738,584	)	$	1,994,842		$	(20,228,649	)	$	(5,222,436	)
Net Income (Loss) Per Common Share –  Basic and Diluted	$	(0.13	)	$	0.20		$	(0.60	)	$	(0.59	)
Weighted Average Shares Outstanding — Basic		42,725,711			9,969,005			33,738,417			8,844,032
Weighted Average Shares Outstanding — Diluted		42,725,711			10,027,934			33,738,417			8,844,032

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

2

EMERALD OIL, INC.

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(UNAUDITED)

	Common Stock				Preferred Stock
	Shares		Amount		Series A - Shares			Series A - Amount			Series B - Shares		Series B – Amount		Additional Paid-in Capital			Accumulated Deficit			Total Stockholders’ Equity
Balance as of December 31, 2012		24,734,643	$	24,735		—		$	—			—	$	—	$	180,439,530		$	(70,170,180	)	$	110,294,085
Common shares issued for oil and natural gas properties		1,165,015		1,165		—			—			—		—		6,735,770			—			6,736,935
Stock-based compensation		468,994		469		—			—			—		—		7,162,148			—			7,162,617
Equity offering		16,585,600		16,585		—			—			—		—		95,961,178			—			95,977,763
Issuance of Preferred Stock		—		—		500,000			38,552,993			5,114,633		5,000		—			—			—
Redemption of Preferred Stock		—		—		(350,000	)		(21,620,459	)		—		—		(17,697,007	)		—			(17,697,007	)
Preferred Stock Dividends Paid and Accrued		—		—		—			—			—		—		(2,582,191	)		—			(2,582,191	)
Net income		—		—		—			—			—		—		—			50,548			50,548
Balance as of September 30, 2013		42,954,252	$	42,954		150,000		$	16,932,534			5,114,633	$	5,000	$	270,019,428		$	(70,119,632	)	$	199,942,750

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

3

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

	Nine Months Ended September 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	50,548		$	(5,222,436	)
Adjustments to Reconcile Net Loss to Net Cash Provided By Operating Activities:
Depletion of Oil and Natural Gas Properties		11,238,783			7,977,077
Impairment of Oil and Natural Gas Properties		—			10,191,234
Depreciation and Amortization		94,665			34,559
Amortization of Debt Issuance Costs		75,618			1,494,013
Accretion of Discount on Asset Retirement Obligations		21,564			10,027
Unrealized Loss on Commodity Derivatives		1,224,891			236,646
Gain on Sale of Oil and Natural Gas Properties, Net		(8,892,344	)		—
Gain on Acquisition of Business		—			(7,213,835	)
Warrant Revaluation Expense		4,587,000			—
Share-Based Compensation Expense		6,538,319			2,770,849
Changes in Assets and Liabilities:
Decrease (Increase) in Accounts Receivable – Oil and Natural Gas Revenues		7,650,021			(2,967,858	)
Increase in Accounts Receivable – Joint Interest Partners		(22,095,552	)		—
Decrease in Other Receivables		1,061,301			—
Increase in Prepaid Expenses and Other Current Assets		(332,718	)		(89,474	)
Increase in Other Non-Current Assets		(305,272	)		—
Increase  in Accounts Payable		1,631,558			998,360
Increase (Decrease) in Accrued Expenses		5,537,377			(196,211	)
Increases in Advances from Joint Interest Partners		1,452,969			—
Net Cash Provided By Operating Activities		9,538,728			8,022,951
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of Other Property and Equipment		(343,287	)		(65,177	)
Restricted Cash Received		(21,000,000	)
Increase in Deposits for Acquisitions		(2,500,000	)		—
Use of (Payments for) Prepaid Drilling Costs		98,565			(282,823	)
Proceeds from Sale of Oil and Natural Gas Properties, Net of Transaction Costs		134,627,306			—
Investment in Oil and Natural Gas Properties		(138,610,383	)		(36,292,015	)
Net Cash Used For Investing Activities		(27,727,799	)		(36,640,015	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the Issuance of Common Stock, Net of Transaction Costs		95,977,763			69,852,809
Proceeds from Issuance of Preferred Stock and Warrants, Net of Transaction Costs		47,183,994			—
Payments on Preferred Stock		(35,000,000	)		—
Advances on Revolving Credit Facility and Term Loan		—			33,030,730
Payments on Revolving Credit Facility		(23,500,000	)		(18,030,730	)
Payments on Senior Secured Promissory Notes		—			(15,000,000	)
Payment of Assumed Debt		—			(20,303,903	)
Cash Paid for Finance Costs		(237,500	)		(1,576,508	)
Preferred Stock Dividends and Deemed Dividends		(6,899,657	)		—
Net Cash Provided by Financing Activities		77,524,600			47,972,398
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		59,335,529			19,355,334
CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD		10,192,379			13,927,267
CASH AND CASH EQUIVALENTS – END OF PERIOD	$	69,527,908		$	33,282,601
Supplemental Disclosure of Cash Flow Information
Cash Paid During the Period for Interest	$	255,776		$	1,107,293
Cash Paid During the Period for Income Taxes	$	—		$	—
Non-Cash Financing and Investing Activities:
Oil and Natural Gas Properties Property Included in Accounts Payable	$	38,646,242		$	35,936,773
Stock-Based Compensation Capitalized to Oil and Natural Gas Properties	$	624,325		$	493,085
Accretion on Preferred Stock Issuance Discount	$	8,626,000		$	—
Accretion of Preferred Stock Issuance Costs	$	2,816,006		$	—
Accrued Preferred Stock Dividend and Deemed Dividend	$	1,932,534		$	—
Capitalized Asset Retirement Obligations, Net	$	116,471		$	112,169
Common Stock Issued for Oil and Natural Gas Properties	$	6,736,935		$	—
Non-Cash Business Acquisitions
Oil and Natural Gas Properties	$	—		$	40,787,238
Other Property and Equipment	$	—		$	36,000
Other Assets	$	—		$	75,000
Fair Market Value of Common Stock Issued	$	—		$	13,380,500
Debt Assumed	$	—		$	20,303,903

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

4

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, primarily focused on the Williston Basin located in North Dakota and Montana. The Company builds net asset value by growing reserves and converting undeveloped assets into producing wells in repeatable and scalable shale oil plays.

The Company designs, drills and operates oil and natural gas wells on acreage where it holds a controlling working interest. The Company also participates in the drilling of oil and natural gas wells operated by other companies.

The Company added executive management that is experienced in exploration and production of oil and natural gas resources 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 continues to add to these internal capabilities and leveraged best practices through partnering with industry experts. Currently, the Company has 23 employees and retains independent contractors to assist in operating and managing oil and natural gas development.

NOTE 2  BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

The accompanying condensed consolidated financial statements have been prepared on the accrual basis of accounting whereby revenues are recognized when earned and expenses are recognized when incurred. The condensed consolidated financial statements as of September 30, 2013 and for the three and nine months ended September 30, 2013 and 2012 are unaudited. In the opinion of management, such financial statements include the adjustments and accruals that are of a normal recurring nature and 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 consolidated financial statements as of September 30, 2013 and for the three and nine month periods ended September 30, 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

On October 22, 2012, a majority of the Company’s shareholders approved 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). 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.

5

Restricted Cash

Restricted cash included in current and long-term assets on the condensed consolidated balance sheets totaled $21 million and $0 at September 30, 2013 and December 31, 2012, respectively.  At September 30, 2013, $11 million of restricted cash relates to cash held in escrow to meet certain post-closing requirements related to the sale of oil and natural gas properties during the period (see Note 4 – Oil and Natural Gas Properties). The remaining $10 million relate to a drilling commitment agreement entered into pursuant to oil and natural gas leases acquired during the period.

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 September 30, 2013 and 2012, the Company capitalized $905,631 and $151,719, respectively, of internal salaries, which included $314,061 and $97,317, respectively, of stock-based compensation. For the nine-month periods ended September 30, 2013 and 2012, the Company capitalized $2,124,585 and $624,818, respectively, of internal salaries, which included $624,325 and $493,085, 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 property sales during the nine months ended September 30, 2013 in the Williston Basin and Sand Wash Basin (see Note 4 – Oil and Natural Gas Properties). A gain was recognized on one transaction that resulted in the sale of a significant portion of proved reserves as of the transaction date and significantly altered the relationship between capitalized costs and proved reserves attributable to the Williston Basin. No gain or loss was recognized on any other sales during the period. The Company engages in acreage trades in the Williston Basin, but these trades are generally for acreage that is similar 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 nine-month period ended September 30, 2013 and the year ended December 31, 2012, the Company reclassified unevaluated properties with associated costs of $1,630,740 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.

6

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 is 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 and nine-month periods ended September 30, 2013. The Company recognized an impairment expense in the three- and nine-month periods ended September 30, 2012 in the amount of $0 and $10,191,234, respectively. 

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 $40,631 and $12,345 for the three-month periods ended September 30, 2013 and 2012, respectively. Depreciation expense was $94,665 and $34,559 for the nine-month periods ended September 30, 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 September 30, 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 of peer company data fairly represents the expected volatility it would experience if the Company 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.

7

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 authorized for issuance under the 2011 Plan to 3,500,000 shares. On July 10, 2013, the shareholders of the Company approved an amendment to the 2011 Plan to increase the number of shares authorized for issuance under the 2011 Plan to 9,800,000 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 September 30, 2013, 1,006,573 stock options and 3,702,254 shares of common stock and restricted stock units had been issued to officers, directors and employees under the 2011 Plan, including 2,391,051 restricted stock units that were unvested at the time of the grant. As of September 30, 2013, there were 5,091,173 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) attributable to common stockholders 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- and nine-month periods ended September 30, 2013 and 2012, the potentially dilutive shares were anti-dilutive and were thus not included in the net loss per share calculation.

As of September 30, 2013: (i) 2,281,096 unvested restricted stock units were issued and outstanding and represent potentially dilutive shares; (ii) 521,416 stock options were issued and presently exercisable and represent potentially dilutive shares; (iii) 592,287 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.

8

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 affiliates of White Deer Energy L.P. (“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 September 30, 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 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 being 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. The Company has no long-lived assets located outside the U.S.

9

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 members of management. 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 overriding royalty interest was comprised of a 2.15% overriding royalty interest on Emerald Oil North America’s properties in the Williston Basin of North Dakota with a guaranteed 215 net mineral acres underlying the overriding royalty for a period of five years and a 0.09% 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 with a guaranteed 382.5 net mineral acres underlying the overriding royalty for five years. On August 2, 2013, the Company terminated all surviving provisions of the credit agreement including the five year guarantee of providing net mineral acres that underlie the overriding royalty interest by assigning Hartz the Company’s working interest in certain leases of Emerald Oil North America.

The Emerald Oil North America acquisition was 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 was 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

10

Pro Forma Operating Results

For the three and nine-month periods ended September 30, 2013, the Company recognized $68,930 and $282,876 in revenues, respectively, and $3,337 and $40,948 of expenses, respectively, relating to Emerald Oil North America, resulting in a net income during the three and nine-month periods ended September 30, 2013 of $65,593 and $241,927, respectively.

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

	Three Months Ended September 30, 2012			Nine Months Ended September 30, 2012
Revenues	$	5,476,134		$	18,781,520
Net Loss Available to Common Shareholders	$	(4,070,652	)	$	(13,503,967	)
Net Loss Per Share – Basic and Diluted	$	(0.39	)	$	(1.34	)
Weighted Average Shares Outstanding – Basic and Diluted		10,420,683			10,099,762

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.  The Company has historically funded acquisitions 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.

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.

11

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 in cash, or approximately $1,100 per net acre. The purchase closed on May 8, 2013.

On August 2, 2013, the Company closed a transaction with a third party to acquire approximately 3,500 net acres of partially developed leasehold in McKenzie County, North Dakota for approximately $10.4 million or approximately $3,000 per net acre.

On August 30, 2013, the Company closed a transaction with a third party to acquire approximately 3,600 net undeveloped operated acres in McKenzie County, North Dakota for approximately $3.6 million, or approximately $1,000 per net acre.

On September 17, 2013, the Company leased approximately 30,672 net undeveloped leasehold acres in McKenzie, Billings and Stark Counties, North Dakota, for approximately $20.2 million, or approximately $660 per net acre. Pursuant to the lease acquired, the Company entered into an agreement with a third party in which the Company will drill at least five gross wells within the prospect area prior to September 17, 2015. The Company placed $10 million with an escrow agent, of which $2 million per well will be returned to the Company with each well drilled within the term of the escrow agreement. As of September 30, 2013, $4 million of the escrowed funds are classified as a current asset on the condensed combined balance sheet, with the remaining $6 million classified as a long-term asset.

On September 19, 2013, the Company entered into a purchase and sale agreement with a third party to acquire approximately 2,866 net acres of undeveloped leasehold in Williams County, North Dakota for approximately $3.2 million, or approximately $1,100 per net acre. The acquisition closed on October 9, 2013. On September 20, 2013, the Company leased an additional 313 net acres of undeveloped lease hold in the same area in Williams County, North Dakota for approximately $1.3 million, or approximately $4,100 per net acre.

As of September 30, 2013, the Company held a $2.5 million deposit with a third party lease broker to be used for lease acquisitions within parameters provided by the Company.

Leasehold Sales

On January 7, 2013, the Company entered into a definitive agreement with a third party, under which the Company agreed to sell 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. No gain or loss was recognized as the sale did not significantly alter the relationship between capitalized costs and proved reserves.

On April 17, 2013, the Company sold its interest in approximately 970 net mineral acres in the Williston Basin to a third party for a total sale price of approximately $7.1 million, including sales price adjustments for development costs and production revenue and operating expenses during the effective period. The acreage was associated with non-operated working interests in Williston Basin Bakken and Three Forks wells. No gain or loss was recognized as the sale did not significantly alter the relationship between capitalized costs and proved reserves.

On September 6, 2013, the Company sold its interest in 413 non-operated net acres located in the Williston Basin for approximately $5.2 million in cash. The acreage was associated with non-operated working interests in Williston Basin Bakken and Three Forks wells. No gain or loss was recognized as the sale did not significantly alter the relationship between capitalized costs and proved reserves.

12

On September 6, 2013, the Company sold its interest in 26,579 non-operated net acres located in the Williston Basin and the associated oil and natural gas production to a third party for a total sales price of approximately $111.0 million in cash, including sales price adjustments for development costs and production revenue and operating expenses during the effective period and subject to certain post-closing adjustments. $11.0 million of the sales price will remain in escrow until December 31, 2013 upon finalization of standard due diligence procedures. The acreage was associated with non-operated working interests in Williston Basin Bakken and Three Forks wells. The transaction was accounted for under the full cost method of accounting for oil and natural gas operations, in accordance with Accounting Standard Codification 932 relating to “Extractive Activities – Oil and Gas”. Under the full cost method, sales of oil and natural gas properties, whether or not being amortized, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center. The sale represents greater than 25 percent of the Company’s proved reserves of oil and gas attributable to the full cost pool. As a result, there is a significant alteration in the relationship between capitalized costs and proved reserves of oil and gas attributable to the full cost pool. Total capitalized costs within the full cost pool are allocated on the basis of the relative fair values of the properties sold and those retained due to substantial economic differences between the properties sold and those retained. Following this methodology, the following table represents a net sales price allocation of the transaction (in thousands):

Sale price	$	111,090
Add: disposition of asset retirement obligations		309
Less: sale expenses		(1,168	)
Sale price, net	$	110,231
Proved oil and natural gas properties	$	137,279
Accumulated depletion		(49,508	)
Unproved oil and natural gas properties		13,568
Gain on sale		8,892
Sale price, net	$	110,231

NOTE 5  RELATED PARTY TRANSACTIONS

Senior Secured Promissory Notes

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.

White Deer Energy Investment

In February 2013, the Company entered into a securities purchase agreement with affiliates of White Deer Energy L.P. (“White Deer Energy”), pursuant to which the Company issued to White Deer Energy 500,000 shares of Series A Perpetual Preferred Stock (“Series A Preferred Stock”), 5,114,633 shares of Series B Voting Preferred Stock (“Series B Preferred Stock”) and warrants to purchase an initial aggregate amount of 5,114,633 shares of the Company’s common stock at an initial exercise price of $5.77 per share, or an aggregate $50 million. Pursuant to the purchase agreement, White Deer Energy obtained the right to designate one member of the Company’s Board, and White Deer Energy has designated Thomas J. Edelman as its initial director. For additional information regarding the securities purchase agreement with White Deer Energy, see Note 6 — Preferred and Common Stock.

On May 13, 2013, the Company entered into a securities purchase agreement with White Deer Energy. The transactions contemplated by the purchase agreement were consummated on June 4, 2013. At the closing, the Company issued 2,785,600 shares of common stock to White Deer Energy for approximately $16.2 million after deducting placement agent fees. The Company’s Audit Committee, which consisted solely of independent directors, reviewed and approved this transaction.

On October 17, 2013, the Company entered into a securities and purchase agreement with White Deer Energy. For additional information, see Note 15 – Subsequent Events.

13

In connection with both closings, the Company granted White Deer Energy certain registration rights. The registration rights agreement requires the Company to file a resale registration statement to register the shares of the Company’s common stock and the shares of common stock issuable upon exercise of the warrants held by White Deer Energy if, at any time on or after 90 days from the closing, White Deer Energy makes a written request to the Company for registration of the securities. Under the registration rights agreement, the Company is required to use its commercially reasonable efforts to cause such resale registration statement to become effective within 120 days after its filing.

NOTE 6  PREFERRED AND COMMON STOCK

Preferred Stock

The Company has 20,000,000 shares of preferred stock authorized. 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 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:

o 500,000 shares of Series A Preferred Stock, $0.001 par value per share;

o 5,114,633 shares of Series B Preferred Stock, $0.001 par value per share; and

o 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. On July 10, 2013, the shareholders of the Company authorized the Company to issue at its option additional warrants and shares of common stock issuable upon exercise of such additional warrants as dividends on the Series A Preferred Stock prior to April 1, 2015.

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, White Deer Energy 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 revolving credit facility with Wells Fargo Bank, N.A., White Deer Energy 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, White Deer Energy has the right to require the Company to purchase the Series A Preferred Stock at the Liquidation Preference.

14

On June 20, 2013, the Company redeemed 150,000 shares of the Series A Preferred Stock for $17,203,767 including $1,875,000 of redemption premium and $328,767 in accrued dividends on the redeemed shares. On August 30, 2013, the Company redeemed 200,000 shares of the Series A Preferred Stock for $22,828,767 including $2,500,000 of redemption premium and $328,767 of accrued dividends on the redeemed shares. On September 15, 2013, the Company provided notice that it would redeem the remaining 150,000 shares of the Series A Preferred Stock on October 15, 2013 for $16,932,534 including $1,875,000 of redemption premium and $57,534 in accrued dividends on the redeemed shares. The redemption and dividend are accrued for and the Series A Preferred Stock is included as a current liability at its liquidation preference value of $16,875,000 as of September 30, 2013. For each redemption, the redemption premium is treated as a dividend and recorded as a return of equity to White Deer Energy through a charge to the Company’s additional paid-in capital.

For the three and nine-month periods ended September 30, 2013, the Company paid dividends on the Series A Preferred Stock of $706,849, and $2,524,658, respectively. No dividends were paid prior to 2013.

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 White Deer Energy to acquire 5,114,633 shares of common stock at $5.77 per share and surrendering an equal number of shares of Series B Preferred Stock to the Company. In lieu of exercising the warrants for cash, White Deer Energy may deliver for cancellation a number of shares of Series A Preferred Stock equal to the exercise price. See Note 13 – Derivative Instruments and Price Risk Management – Warrant Liability for further discussion of 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. Upon the final Series A Preferred Stock redemption on October 15, 2013, the minimum internal rate of return was achieved and no additional cash payment was necessary.

15

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 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. The Company recognized all remaining issuance discount accretion of $6,041,700 as of September 30, 2013 related to the partial redemption of preferred stock on August 30, 2013 and the accrual of the final redemption of preferred stock on October 15, 2013. There is no issuance discount remaining as of September 30, 2013.

A summary of the preferred stock transaction components as of September 30, 2013 and the issuance date is provided below:

	September 30, 2013		February 19, 2013 (issuance date)
Series A Preferred Stock	$	16,875,000	$	41,369,000
Series B Preferred Stock		5,000		5,000
Warrant Liability		13,213,000		8,626,000
Total	$	30,093,000	$	50,000,000

Restricted Stock Awards and Restricted Stock Unit Awards

The Company granted 997,042 restricted stock and restricted stock units pursuant to the 2011 Equity Incentive Plan during the three and nine-month periods ended September 30, 2013. The Company incurred compensation expense associated with restricted stock granted during 2013 of $2,856,568 for the three and nine months ended September 30, 2013. The Company incurred compensation expense associated with restricted stock granted prior to 2013 of $931,824 and $356,947 for the three months ended September 30, 2013 and 2012, respectively, and $2,721,549 and $627,562 for the nine-month periods ended September 30, 2013 and 2012, respectively. For the three and nine months ended September 30, 2013, the Company capitalized compensation expense associated with the restricted stock and restricted stock units of $285,148 and $374,250 to oil and natural gas properties, respectively. As of September 30, 2013, there was $8,142,929 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 1.1 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 September 30, 2013, there were 2,281,096 unvested restricted stock units outstanding with a weighted average grant date fair value of $5.00 per share. 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		596,131			7.01
Canceled		(70,642	)		4.19
Vested		(92,094	)		5.39
Non-vested restricted stock and restricted stock units at September 30, 2013		2,281,096		$	5.00

16

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.

On May 22, 2013, the Company completed a public offering of 12,000,000 shares of common stock at a price of $6.10 per share for total net proceeds of approximately $69.3 million.  The Company incurred costs of approximately $4.3 million related to this transaction, which costs were netted against the proceeds of the transaction through additional paid-in capital. The underwriters elected to exercise the over-allotment option to sell an additional 1,800,000 shares of common stock at $6.10 per share. The net proceeds from the over-allotment exercise were approximately $10.5 million after deducting underwriting discounts and commissions.

On June 4, 2013, the Company completed a private placement of 2,785,600 shares of common stock at a price of $5.93 per share for net proceeds of approximately $16.2 million after deducting placement agent fees of approximately $0.2 million. The issuance of the common stock was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(2) thereof, which exempts transactions by an issuer not involving any public offering. 

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 on an annual basis over 36 months with 6,000 options vesting on March 22, 2014, 2015 and 2016.

On April 8, 2013, the Company granted stock options to certain employees to purchase a total of 69,667 shares of common stock exercisable at $6.41 per share. 25,000 of the options vest in November 2013 with the remainder vesting in March 2014.

In July 2013, the Company granted stock options to certain employees to purchase a total of 315,334 shares of common stock exercisable at a weighted average price of $7.37 per share. The options vest incrementally at various dates between April 2014 and September 2016.

The impact on the Company’s statement of operations of stock-based compensation expense related to options granted for the three-month periods ended September 30, 2013 and 2012 was $384,130 and $1,707,732, respectively, net of $0 tax. The impact on the Company’s statement of operations of stock-based compensation expense related to options granted for the nine-month periods ended September 30, 2013 and 2012 was $960,202 and $2,083,360, respectively, net of $0 tax. The Company capitalized $28,913 and $250,074 of compensation to oil and natural gas properties related to outstanding options for the three- and nine-month period ended September 30, 2013, respectively. The Company will recognize approximately $1,820,000 amortized over a weighted-average period of 1.5 years relating to options that have been granted but have not vested as of September 30, 2013.

The following assumptions were used for the Black-Scholes model to value the options granted during the nine- month period ended September 30, 2013.

Risk free rates	0.71% -2.12%
Dividend yield	0%
Expected volatility	73.1% - 79.5%
Weighted average expected life	5.8 years

17

A summary of the stock options outstanding as of January 1, 2013 and September 30, 2013 is as follows:

	Number of Options			Weighted Average Exercise Price
Balance outstanding at January 1, 2013		835,702		$	10.43
Granted		403,001			7.17
Canceled		(50,000	)		14.89
Exercised		(75,000	)		4.43
Balance outstanding at September 30, 2013		1,113,703		$	9.52
Options exercisable at September 30, 2013		521,416		$	11.57

At September 30, 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		403,001		7.73	$	7.17		—		—	$	—
2012		574,999		3.24		8.43		385,713		2.72		8.50
Prior		135,703		2.27		21.11		135,703		2.27		21.11
Total		1,113,703		4.75	$	9.52		521,416		2.60	$	11.57

Warrants

The table below reflects the status of warrants outstanding at September 30, 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 nine-month period ended September 30, 2013. All of the compensation expense related to the applicable vested warrants issued to employees has been expensed by the Company prior to 2012. All warrants outstanding were exercisable at September 30, 2013. See Note 13 – Derivative Instruments and Price Risk Management 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”). As of September 30, 2013, the borrowing base was $75.0 million.

18

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.  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 also pays a commitment fee ranging from 0.375% to 0.5%, depending on the percentage of the borrowing base utilized. As of September 30, 2013, the annual interest rate on the Wells Fargo Facility was 0.375% which is the minimum commitment fee, as no funds were drawn against the Wells Fargo Facility.

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 September 30, 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 September 30, 2013.

The principal balance amount on the Credit Agreement was approximately $0 and $23.5 million at September 30, 2013 and December 31, 2012, respectively. The Company had approximately $75.0 million available under the Wells Fargo Facility as of September 30, 2013.

Macquarie Bank Limited

On February 10, 2012, the Company entered into a revolving 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, with an additional $50 million available under a development tranche.

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 remaining balance on the Macquarie Facility was paid in full on November 20, 2012.

19

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 September 30, 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 September 30, 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 nine-month period ended September 30, 2013 and the year ended December 31, 2012:

	September 30, 2013			December 31, 2012
Beginning Asset Retirement Obligation	$	296,074		$	116,119
Liabilities Incurred or Acquired		429,096			164,967
Accretion of Discount on Asset Retirement Obligations		21,564			14,988
Liabilities Associated with Properties Sold		(312,625	)		—
Ending Asset Retirement Obligation	$	434,109		$	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 September 30, 2013 and December 31, 2012, the Company maintains a full valuation allowance for all deferred tax assets.  Based on these requirements no provision or benefit for income taxes has been recorded for deferred taxes. There were no recorded unrecognized tax benefits at the end of the reporting period.

20

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 Vice President of Accounting 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 September 30, 2013:

	Fair Value Measurements at September 30, 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	$	—	$	—		$	(13,213,000	)
Commodity Derivatives – Current Liability (oil swaps)				(1,431,091	)
Commodity Derivatives – Long Term Asset (oil swaps)		—		25,017			—
Total	$	—	$	(1,406,074	)	$	(13,213,000	)

21

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 and changes 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.

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		(4,587,000	)
Transfers		—
Balance, at September 30, 2013	$	(13,213,000	)

The fair value of the warrants upon issuance to White Deer Energy on February 19, 2013 was recorded at $8,626,000. The warrant revaluation expense was $506,000 and $4,587,000 for the three- and nine-month periods ended September 30, 2013, respectively, 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.

22

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 – Asset Retirement Obligation.

The Company’s non-derivative financial instruments include cash and cash equivalents, accounts receivable, accounts payable, the Wells Fargo Facility and the Series A 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 Wells Fargo Facility approximates fair value because of its floating rate structure. The Series A Preferred Stock had a fair value and carrying value of $16,875,000 as of September 30, 2013. The carrying value approximated its fair value and liquidation preference value due to the redemption of the remaining outstanding shares of Series A Preferred Stock on October 15, 2013. The Company has classified the valuations of the Wells Fargo Facility and the Series A 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 following table reflects open commodity swap contracts as of September 30, 2013, the associated volumes and the corresponding weighted average NYMEX reference price:

Settlement Period	Oil (Bbls)		Fixed Price
Oil Swaps
October 1, 2013 – December 31, 2013		30,870	$	91.00
October 1, 2013  – December 31, 2013		12,000		90.05
October 1, 2013 – December 31, 2013		30,000		94.30
2013 Total/Average		72,870	$	92.20
January 1, 2014 – December 31, 2014		103,267	$	91.00
January 1, 2014 – December 31, 2014		31,000		90.05
January 1, 2014 – December 31, 2014		79,000		94.30
2014 Total/Average		213,267	$	92.08
January 1, 2015 – February 28, 2015		13,876	$	91.00
January 1, 2015 – February 28, 2015		5,000		90.05
January 1, 2015 – February 28, 2015		10,000		94.30
2015 Total/Average		28,876	$	91.98

23

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 to White Deer Energy pursuant to 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 September 30, 2013, using the same Monte Carlo model, using the following assumptions: a term of 1,626 trading days, exercise price of $5.77, stock price of $7.19, volatility rate of 40%, and a risk-free interest rate of 2.0%. As of September 30, 2013, the fair value of the warrants was $13,213,000, and was recorded as a liability on the accompanying consolidated balance sheets. An increase in any of the variables would cause an increase in the fair value of the warrants. Likewise, a decrease in any variable would cause a decrease in the value of the warrants.

At September 30, 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 Assets (Liabilities):
Swap Contracts	Current liabilities	$	(1,431,091	)
Swap Contracts	Non-current assets		25,017
Warrant Liability	Non-current liabilities		(13,213,000	)
Total Derivative Liabilities		$	(14,619,074	)

For the three and nine-month periods ended September 30, 2013, the Company recorded the change in values for the derivative instruments as set forth below:

Type of Contract	Statement of Operation Location	Three Months Ended September 30, 2013			Nine Months Ended September 30, 2013
Unrealized Losses:
Swap Commodity Contracts	Loss on Commodity Derivatives	$	(1,455,405	)	$	(1,224,891	)
Warrant Liability	Warrant Revaluation Expense		(506,000	)		(4,587,000	)
Total Unrealized Losses, Net		$	(1,961,405	)	$	(5,811,891	)
Realized Losses:
Swap Commodity Contracts	Loss on Commodity Derivatives	$	(1,264,755	)	$	(1,597,536	)
Total Realized Losses		$	(1,264,755	)	$	(1,597,536	)

24

For the three and nine-month periods ended September 30, 2012, the Company recorded the change in values for the derivative instruments as set forth below:

Type of Contract	Statement of Operation Location	Three Months Ended September 30, 2012			Nine Months Ended September 30, 2012
Unrealized Losses:
Costless Commodity Collars	Loss on Commodity Derivatives	$	(1,514,729	)	$	(236,646	)
Total Unrealized Losses		$	(1,514,729	)	$	(236,646	)
Realized Losses:
Costless Commodity Collars	Loss on Commodity Derivatives	$	(120,706	)	$	(59,681	)
Total Realized Losses		$	(120,706	)	$	(59,681	)

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

On October 2, 2013, the Company completed a public offering of 15,000,000 shares of common stock at a price of $6.70 per share for total net proceeds of approximately $95.5 million.  The Company incurred costs of approximately $5.0 million related to this transaction, which costs were netted against the proceeds of the transaction through additional paid-in capital. The underwriters elected to exercise the over-allotment option to sell an additional 2,250,000 shares of common stock at $6.70 per share. The net proceeds from the over-allotment exercise were approximately $14.4 million after deducting underwriting discounts and commissions.

On September 19, 2013, the Company entered into a purchase and sale agreement with a third party to acquire approximately 2,866 net acres of undeveloped leasehold in Williams County, North Dakota for approximately $3.2 million. The purchase closed on October 9, 2013.

On October 15, 2013, the Company redeemed the remaining 150,000 shares outstanding of the Series A Preferred Stock for $16,932,534 including $1,875,000 of redemption premium and $57,534 in accrued dividends on the redeemed shares. The redemption premium is treated as a dividend and recorded as a return of equity to the investor through a charge to the Company’s additional paid-in capital. The redemption and dividend are accrued for and the Series A Preferred Stock is included as a current liability at its liquidation preference value of $16,875,000 as of September 30, 2013

On October 17, 2013, the Company completed a private placement of 5,092,852 shares of common stock at a price of $6.39 per share for net proceeds of approximately $32.5 million. The Company’s Audit Committee, which consisted solely of independent directors, reviewed and approved this transaction. The issuance of the common stock was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(2) thereof, which exempts transactions by an issuer not involving any public offering. 

25

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.

As of September 30, 2013, we had approximately 66,000 net acres in the Williston Basin, pro forma for closed and pending acquisitions. We operate approximately 60,000 net acres, or 91% of our total net acreage. We have identified approximately 313 net potential drilling locations on this acreage prospective for oil in the Bakken, Three Forks and Pronghorn Sand formations, based on industry accepted well down-spacing assumptions. Consistent with such assumptions, we believe that each 1,280-acre unit can support up to approximately four Bakken, three Three Forks and four Pronghorn Sand horizontal well locations. We expect to direct the majority of our capital expenditures in 2013 and in 2014 toward drilling operated Bakken, Three Forks and Pronghorn Sand 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.

Assets and Acreage Holdings

As of September 30, 2013 we controlled approximately 66,000 net acres, pro forma for closed and pending acquisitions in our core operating area of the Williston Basin targeting the Bakken, Three Forks and Pronghorn Sand formations in North Dakota and Montana, comprised of the operating areas below:

· 36,000 net acres in the Low Rider area of McKenzie County, North Dakota;

· 3,000 net acres in the Easy Rider area of Williams County, North Dakota in the West Nesson area of the Williston Basin;

· 11,000 net acres in the Richland area of Richland County, Montana;

· 3,000 net acres in the Pronghorn in Stark and Billings Counties, North Dakota in the core of the Pronghorn field; and

· 13,000 net acres in the Lewis & Clark area of McKenzie County of North Dakota south of the Low Rider area.

26

Capital Development Plan

For the 12-month period ending December 31, 2013, we plan to spend approximately $127.2 million to drill 12.0 net operated and 0.5 net non-operated wells in the Williston Basin, of which we have spent approximately $76.5 million through September 30, 2013. For the 12-month period ending December 31, 2013, we have also budgeted approximately $20.0 million to increase our operated acreage position in our core operated area in McKenzie County, North Dakota, which we refer to as the Low Rider area, and elsewhere in the Williston Basin, with a specific focus on increasing the net working interest position in our operated wells. We added a high specification drilling rig to accelerate development of our Williston Basin operated leasehold, which commenced drilling in June 2013. The rig is a 1,200 horsepower top drive long-reach horizontal-capable rig with the potential to upgrade with a “walking package” for infill efficiency. We expect to add a third horizontal-capable rig in 2014. For the 12-month period ending December 31, 2014, we plan to spend approximately $182.0 million to drill 18.2 net operated wells in the Williston Basin at an average cost per net well of approximately $10.0 million. We have also budgeted approximately $25.0 million to increase our operated acreage position in our core operated areas.

The following table presents summary data for our Williston Basin project area for the years ended December 31, 2013 and 2014:

					Planned Capital Expenditures
					2013				2014
	Net Acres		Net Identified Drilling Locations		Net Wells		Drilling Capex (in millions)		Net Wells		Drilling Capex (in millions)
Low Rider		36,000		196		12.5	$	127.2		12.2	$	122.0
Easy Rider		3,000		17		—		—		2.0		20.0
Richland		11,000		61		—		—		2.0		20.0
Pronghorn		3,000		9		—		—		2.0		20.0
Lewis & Clark		13,000		30		—		—		—		—
Total		66,000		313		12.5	$	127.2		18.2	$	182.0

The Low Rider area, which is our core operated area, consists of approximately 36,000 net acres that are primarily located in McKenzie County, North Dakota. Our average working interest in our operated wells in the Low Rider area as of September 30, 2013 was approximately 68%, and we continue to work toward increasing our average working interest towards 75%. As of September 30, 2013, we had approximately eight gross (6.1 net) producing operated wells in the Williston Basin. As of September 30, 2013, we were running a two-rig horizontal development program in the Low Rider area. Since we began operations in the Low Rider area in November 2012, we have drilled 14 horizontal wells, of which eight are producing and six are awaiting completion, completing or drilling. During 2013, we expect to drill and complete approximately 16 gross (12.0 net) Low Rider horizontal wells.

Through June 30, 2013 the majority of our oil and natural gas production was derived from participation in wells in the Williston Basin as a non-operating partner, primarily on a heads-up, or pro rata, basis proportionate to our working interest with established operators. With the sale of substantially all of our non-operated oil and natural gas properties in the Williston Basin in September 2013 (see Recent Developments – Non-Operated Acreage Sales) our capital is focused on development of our core operated areas.  

Recent Developments

Non-Operated Acreage Sales

On September 6, 2013, we sold 26,579 non-operated net acres located in the Williston Basin and the associated oil and natural gas production for approximately $111.0 million in cash, subject to certain post-closing adjustments, which sale we refer to as the “Non-Operated Asset Sale.” Under the purchase agreement, the Non-Operated Asset Sale was given economic effect as of April 1, 2013 such that all proceeds and certain operational costs and expenses attributable to the properties sold were apportioned between the purchaser and Emerald based on such date. On September 6, 2013, we also sold 413 non-operated net acres located in the Williston Basin for approximately $5.2 million in cash. In addition, we sold 970 non-operated net acres in the Williston Basin in April 2013 for approximately $7.1 million in cash. We have used and intend to use the proceeds from these divestitures to fund a portion of our 2013 and 2014 capital budgets.

27

Acreage Acquisitions

On August 2, 2013, we closed a transaction with a third party to acquire approximately 3,500 net acres of partially developed leasehold in McKenzie County, North Dakota, for approximately $10.4 million or approximately $3,000 per net acre. The acquired acreage is directly southeast and contiguous to our existing Low Rider Area in McKenzie County, North Dakota. The acquisition added eight potentially operated DSUs in our Low Rider Area.

On August 30, 2013, we closed a transaction with a third party to acquire approximately 3,600 net acres of undeveloped leasehold in McKenzie County, North Dakota for approximately $3.6 million or approximately $1,000 per net acre. The acquired acreage is directly south and contiguous to our existing operated area in McKenzie County, North Dakota. The acquisition added six potentially operated drilling spacing units in our Low Rider Prospect in McKenzie County, North Dakota.

On September 17, 2013, we leased approximately 30,672 net undeveloped leasehold acres in McKenzie, Billings and Stark Counties, North Dakota, for approximately $20.2 million. The lease acquisitions added 38 potentially operated drilling spacing units in our Low Rider, Easy Rider, Pronghorn and Lewis & Clark Prospect areas. Pursuant to the lease acquired, we entered into an agreement with a third party in which the Company will drill at least five gross wells within the prospect area prior to September 17, 2015. We placed $10 million with an escrow agent, of which $2 million per well will be returned to us with each well drilled within the term of the escrow agreement.

On September 19, 2013, we entered into a purchase and sale agreement with a third party to acquire approximately 2,866 net acres of undeveloped leasehold in Williams County, North Dakota for approximately $3.2 million. The acquisition adds seven potentially operated DSUs in our Low Rider and Easy Rider Prospect Areas. The purchase closed on October 9, 2013. On September 20, 2013, the Company leased an additional 313 net acres of undeveloped lease hold in the same area in Williams County, North Dakota for approximately $1.3 million.

Operational Update

The following table provides production results by well for all Emerald-operated wells drilled and completed through November 5, 2013:

	Well Results (Boe/d)
		24 Hour	30 Day	60 Day	90 Day
Pirate 1-2-11H		1,801	1,025	782	621
Arsenal 1-17-20H		1,638	768	753	570
Caper 1-15-22H		2,063	994	780	678
Mongoose 1-8-5H		1,523	892	706	619
Talon 1-9-4H		1,311	818	662	—
Slugger 1-16-21H		1,342	782	593	—
Hot Rod 1-27-26H		1,589	661	—	—
Hot Rod 4-27-26H		1,780	530	—	—
Excalibur 5-25-36H		1,842	—	—	—

Finance Update

In August 2013, we completed the semi-annual borrowing base redetermination of our revolving credit facility. As a result, we entered into an amendment to our credit agreement with Wells Fargo Bank, N.A., which increased our borrowing base from $27.5 million to $75.0 million. Following the sale of substantially all of our non-operated North Dakota and Montana oil and gas properties, Wells Fargo elected to maintain our borrowing base at $75.0 million. As of September 30, 2013, we had no borrowings outstanding under our revolving credit facility.

28

With cash received in the Non-Operated Asset Sale and reconfirmed borrowing base, we elected to redeem an additional $20 million of Series A Preferred Stock on August 30, 2013 and the remaining $15 million on October 15, 2013. See “Liquidity and Capital Resources – Series A Preferred Stock Transaction”.

Public Offering and Private Placement

On October 2, 2013, we completed a public offering of 15,000,000 shares of common stock at a price of $6.70 per share for total net proceeds of approximately $95.5 million. The underwriters elected to exercise the over-allotment option to sell an additional 2,250,000 shares of common stock at $6.70 per share. The net proceeds from the over-allotment exercise were approximately $14.4 million after deducting underwriting discounts and commissions.

On October 17, 2013, we completed a private placement of 5,092,852 shares of common stock at a price of $6.39 per share for net proceeds of approximately $32.5 million with affiliates of White Deer Energy L.P.

Producing Wells

The following table summarizes gross and net productive operated and non-operated oil wells at September 30, 2013 and September 30, 2012. A net well represents our fractional working ownership interest of a gross well. The following table does not include 6 gross (3.4 net) operated Bakken wells and 5 gross (0.9 net) and 21 gross (1.1 net) non-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 September 30, 2013 and September 30, 2012, respectively.

	September 30,
	2013				2012
	Gross		Net		Gross		Net
North Dakota Bakken and Three Forks – operated		8		6.1		—		—
North Dakota Vertical Production  – operated 1		11		7.6
North Dakota Bakken and Three Forks – non-operated		8		0.8		160		6.4
Montana Bakken and Three Forks – non-operated		—		—		21		1.9
Total:		27		14.5		181		8.3

¹ Vertical producing wells relate to existing wells included within an acreage acquisition on August 2, 2013. Operatorship was transferred to Emerald upon closing the acquisition. The wells are producing from the Birdbear, Duprow and Red River formations.

29

Results of Operations

Comparison of the Three Months Ended September 30, 2013 with the Three Months Ended September 30, 2012.

	Three Months Ended September 30,
	2013			2012
REVENUES
Oil and Natural Gas Sales	$	17,316,558		$	7,111,569
Realized and Unrealized Loss on Commodity Derivatives		(2,720,160	)		(1,635,435	)
		14,596,398			5,476,134
OPERATING EXPENSES
Production Expenses		2,087,635			687,646
Production Taxes		1,879,160			809,062
General and Administrative Expenses		6,194,202			3,503,273
Depletion of Oil and Natural Gas Properties		4,497,002			2,818,650
Impairment of Oil and Natural Gas Properties		—			—
Depreciation and Amortization		40,631			12,345
Accretion of Discount on Asset Retirement Obligations		7,502			4,037
Gain on Sale of Oil and Natural Gas Properties		(8,892,344	)		—
Total Operating Expenses		5,813,788			7,835,013
INCOME (LOSS) FROM OPERATIONS		8,782,610			(2,358,879	)
OTHER INCOME (EXPENSE), NET		(524,105	)		4,353,721
INCOME BEFORE INCOME TAXES		8,258,505			1,994,842
INCOME TAX EXPENSE		—			—
NET INCOME		8,258,505			1,994,842
Less: Preferred Stock Dividends and Deemed Dividends		(13,997,089	)		—
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(5,738,584	)	$	1,994,842

Revenues

Revenues from sales of oil and natural gas increased 143% for the three months ended September 30, 2013 compared to the three months ended September 30, 2012, driven primarily by a 93% increase in production by volume as well as higher oil prices. Production increased due to the development of 6.1 net productive operated wells in the Williston Basin from October 1, 2012 to September 30, 2013, partially offset by the sale of substantially all non-operated Williston Basin properties on September 6, 2013. During the three months ended September 30, 2013, we realized a $95.32 average price per barrel of oil (including realized derivatives) compared to an $82.10 average price per barrel of oil during the three months ended September 30, 2012. The average oil price differential during the three months ended September 30, 2013 was $8.34 per barrel, as compared to $10.08 per barrel in the three months ended September 30, 2012. Our price differential between our Williston Basin well head price and the NYMEX WTI benchmark price is driven by the additional cost to transport oil from the Williston Basin via train, pipeline or truck to refineries.

30

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

	Three Months Ended September 30,
	2013			2012
Net Oil and Natural Gas Revenues:
Oil	$	16,952,644		$	6,916,704
Natural Gas and Other Liquids		363,914			194,865
Total Oil and Natural Gas Sales Before Derivatives		17,316,558			7,111,569
Realized Loss on Commodity Derivatives		(1,264,755	)		(120,706	)
Unrealized Loss on Commodity Derivatives		(1,455,405	)		(1,514,729	)
Total Oil and Natural Gas Sales Net of Derivatives	$	14,596,398		$	5,476,134
Net Production:
Oil (Bbl)		164,570			82,775
Natural Gas and Other Liquids (Mcf)		48,648			39,648
Barrel of Oil Equivalent (Boe)		172,678			89,383
Average Sales Prices:
Oil (per Bbl)	$	103.01		$	83.56
Effect of Settled Oil Derivatives on Average Price (per Bbl)		(7.69	)		(1.46	)
Oil Net of Settled Derivatives (per Bbl)	$	95.32		$	82.10
Natural Gas and Other Liquids (per Mcf)	$	7.48		$	4.91
Barrel of Oil Equivalent with Realized Derivatives (per Boe)	$	92.96		$	78.21

Realized and Unrealized Loss on Commodity Derivatives

Realized commodity derivative losses were $1,264,755 for the three months ended September 30, 2013 compared to $120,706 for the three months ended September 30, 2012. Unrealized commodity derivative losses were $1,455,405 for the three months ended September 30, 2013 compared to $1,514,729 for the three months ended September 30, 2012. Our derivatives are not designated for hedge accounting and are accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings.  Mark-to-market accounting treatment creates volatility in our revenues as unrealized gains and losses from derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying balance sheets.  As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives.  Future derivatives gains will be offset by lower future wellhead revenues. Conversely, future derivatives losses will be offset by higher future wellhead revenues based on the value at the settlement date.  At September 30, 2013, all of our derivative contracts are recorded at their fair value, which was a net liability of $1,406,074.

Expenses

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

	Three Months Ended September 30,
	2013		2012
Costs and Expenses Per Boe of Production:
Production Expenses	$	12.09	$	7.69
Production Taxes		10.88		9.05
G&A Expenses (Excluding Share-Based Compensation)		11.71		16.34
Non-Cash Shared-Based Compensation		24.16		22.86
Depletion of Oil and Natural Gas Properties		26.04		31.53
Impairment of Oil and Natural Gas Properties		—		—
Depreciation and Amortization		0.24		0.14
Accretion of Discount on Asset Retirement Obligation		0.04		0.05

31

Production Expenses

Production expenses were $2,087,635 for the three months ended September 30, 2013 compared to $687,646 for the three months ended September 30, 2012. We experience increases in operating expenses as we add new operated wells and maintain production from existing properties. On a per unit basis, production expenses per Boe were $12.09 for the three months ended September 30, 2013 compared to $7.69 for the three months ended September 30, 2012. These increases are related to initial operated production expenses such as installation of production infrastructure, gas lifting equipment and other fixed productions assets that will be leveraged on future downspacing wells.

Production Taxes

Production taxes were $1,879,160 for the three months ended September 30, 2013 compared to $809,062 for the three months ended September 30, 2012. We pay production taxes based on realized oil and natural gas sales. Our average production tax rates were 10.85% for the three months ended September 30, 2013 compared to 11.4% for the three months ended September 30, 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 $6,194,202 for the three months ended September 30, 2013 compared to $3,503,273 for the three months ended September 30, 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 September 30, 2013 increased on a period-over-period basis compared to the three months ended September 30, 2012 due to an increase of $2,049,144 for employee compensation and related expense and an increase of $321,577 related to professional and legal expense. Share-based and restricted stock compensation expenses are included in the employee compensation and related expenses, totaling $4,172,521 for the three months ended September 30, 2013 compared to $2,042,972 for the three months ended September 30, 2012. As we implement our operating strategy, expenses have increased to attract and retain experienced personnel that can deliver production growth and create a scalable field infrastructure.

Depletion Expense

Our depletion expense is driven by many factors, including certain exploration costs involved in the development of producing reserves, sales of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. Depletion expense was $4,497,002 for the three months ended September 30, 2013 compared to $2,818,650 for the three months ended September 30, 2012. On a per-unit basis, depletion expense was $26.04 per Boe for the three months ended September 30, 2013 compared to $31.53 per Boe for the three months ended September 30, 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 development of 8 gross, 6.1 net productive operated wells in the Williston Basin from October 1, 2012 to September 30, 2013, partially offset by the sale of substantially all non-operated Williston Basin properties on September 6, 2013.

Gain on Sale of Oil and Natural Gas Properties

We recognized a gain of $8,892,344 relating to the sale of oil and natural gas properties for the three months ended September 30, 2013. We sold our interest in 26,579 non-operated net acres located in the Williston Basin to a third party for a total sales price of approximately $111.0 million in cash, including sales price adjustments for development costs and production revenue and operating expenses during the effective period and subject to certain post-closing adjustments. $11.0 million of the sales price will remain in escrow until December 31, 2013 upon finalization of standard due diligence procedures. The acreage was associated with non-operated working interests in Williston Basin Bakken and Three Forks wells. The transaction was accounted for under the full cost method of accounting for oil and natural gas operations, in accordance with Accounting Standard Codification 932 relating to “Extractive Activities – Oil and Gas”. Under the full cost method, sales of oil and natural gas properties, whether or not being amortized, shall be accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the full cost pool. The sale represented greater than 25 percent of our proved reserves of oil and gas attributable to the cost center at the time of the sale. As a result, there was a significant alteration in the relationship between capitalized costs and proved reserves of oil and gas attributable to the full cost pool. Total capitalized costs within the full cost pool are allocated on the basis of the relative fair values of the properties sold and those retained due to substantial economic differences between the properties sold and those retained. 

32

Other Income (Expense), Net

Other income (expense), net was $(524,105) for the three months ended September 30, 2013 compared to $4,353,721 for the three months ended September 30, 2012. We recognized an unrealized loss of $506,000 on the warrant liability during the three months ended September 30, 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 $21,437 for the three months ended September 30, 2013, compared to $1,388,912 for the three months ended September 30, 2012. The decrease in interest expense is due to the pay-off of our revolving credit facility balance during the second quarter of 2013. The other income recognized during the three months ended September 30, 2012 is a result of a $7,213,835 gain recognized, offset by $1,444,156 of acquisition costs incurred in the acquisition of Emerald Oil North America on July 26, 2012 in accordance with GAAP. The gain was the result of the decrease in the share price of our common stock, which was the primary form of consideration for the acquisition, between the announcement date and closing date of the acquisition. 

Net Loss Attributable to Common Stockholders

We had net income (loss) attributable to common stockholders of $(5,738,584) for the three months ended September 30, 2013 (representing $(0.13) per share-basic and diluted) compared to net income of $1,994,842 for the three months ended September 30, 2012 (representing $0.20 per share-basic and diluted). The increase in net loss available to common shareholders in our period-over-period results is primarily due to the net gain recognized in the acquisition of Emerald Oil North America for the three months ended September 30, 2012. For the three months ended September 30, 2013, the net loss was primarily due to higher general and administrative expenses, unrealized losses on the warrant liability, preferred stock dividends and deemed dividends. Deemed dividends include the $4,375,000 premium paid on the redemption of the Series A Preferred Stock and $6,041,700 non-cash accretion of the Series A Preferred Stock issuance discount and $2,816,006 accretion of Series A Preferred Stock issuance costs for the three months ended September 30, 2013.

Comparison of the Nine Months Ended September 30, 2013 with the Nine Months Ended September 30, 2012.

	Nine Months Ended September 30,
	2013			2012
REVENUES
Oil and Natural Gas Sales	$	36,108,357		$	18,973,331
Realized and Unrealized Loss on Commodity Derivatives		(2,822,427	)		(296,327	)
		33,285,930			18,677,004
OPERATING EXPENSES
Production Expenses		4,723,520			1,639,105
Production Taxes		3,629,557			2,043,671
General and Administrative Expenses		17,562,754			5,660,622
Depletion of Oil and Natural Gas Properties		11,238,783			7,977,077
Impairment of Oil and Natural Gas Properties		—			10,191,234
Depreciation and Amortization		94,665			34,559
Accretion of Discount on Asset Retirement Obligations		21,564			10,027
(Gain) on Sale of Oil and Natural Gas Properties		(8,892,344	)		—
Total Operating Expenses		28,378,499			27,556,295
INCOME (LOSS) FROM OPERATIONS		4,907,431			(8,879,291	)
OTHER INCOME (EXPENSE), NET		(4,856,883	)		3,656,855
INCOME (LOSS) BEFORE INCOME TAXES		50,548			(5,222,436	)
INCOME TAX EXPENSE		—			—
NET INCOME (LOSS)		50,548			(5,222,436	)
Less: Preferred Stock Dividends and Deemed Dividends		(20,279,197	)		—
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(20,228,649	)	$	(5,222,436	)

33

Revenues

Revenues from sales of oil and natural gas increased 90% for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012, driven primarily by a 71% increase in production by volume and higher realized oil prices. Production increased due to the development of 8 gross, 6.1 net productive operated wells in the Williston Basin from October 1, 2012 to September 30, 2013, partially offset by the sale of substantially all non-operated Williston Basin properties on September 6, 2013. During the nine months ended September 30, 2013, we realized a $90.31 average price per barrel of oil (including realized derivatives) compared to an $84.89 average price per barrel of oil during the nine months ended September 30, 2012. The oil average price differential during the nine months ended September 30, 2013 was $8.20 per barrel, as compared to $11.27 per barrel in the nine months ended September 30, 2012. Our price differential between our Williston Basin well head price and the NYMEX WTI benchmark price is driven by the additional cost to transport oil from the Williston Basin via train, pipeline or truck to refineries.

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

	Nine Months Ended
	September 30,
	2013			2012
Net Oil and Natural Gas Revenues:
Oil	$	35,287,288		$	18,636,837
Natural Gas and Other Liquids		821,069			336,494
Total Oil and Natural Gas Sales Before Derivatives		36,108,357			18,973,331
Realized Loss on Commodity Derivatives		(1,597,536	)		(59,681	)
Unrealized Loss on Commodity Derivatives		(1,224,891	)		(236,646	)
Total Oil and Natural Gas Sales Net of Derivatives	$	33,285,930		$	18,677,004
Net Production:
Oil (Bbl)		373,048			218,833
Natural Gas and Other Liquids (Mcf)		133,343			76,662
Barrel of Oil Equivalent (Boe)		395,272			231,610
Average Sales Prices:
Oil (per Bbl)	$	94.59		$	85.16
Effect of Settled Oil Derivatives on Average Price (per Bbl)		(4.28	)		(0.27	)
Oil Net of Settled Derivatives (per Bbl)	$	90.31		$	84.89
Natural Gas and Other Liquids (per Mcf)	$	6.16		$	4.39
Barrel of Oil Equivalent with Realized Derivatives (per Boe)	$	87.31		$	81.66

34

Realized and Unrealized Loss on Commodity Derivatives

Realized commodity derivative losses were $1,597,536 for the nine months ended September 30, 2013 compared to $59,681 for the nine months ended September 30, 2012. Unrealized commodity derivative losses were $1,224,891 for the nine months ended September 30, 2013 compared to $236,646 for the nine months ended September 30, 2012. Our derivatives are not designated for hedge accounting and are accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings.  Mark-to-market accounting treatment creates volatility in our revenues as unrealized gains and losses from derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying balance sheets.  As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives.  Future derivatives gains will be offset by lower future wellhead revenues. Conversely, future derivatives losses will be offset by higher future wellhead revenues based on the value at the settlement date.  At September 30, 2013, all of our derivative contracts are recorded at their fair value, which was a net liability of $1,406,074.

Expenses

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

	Nine Months Ended
	September 30,
	2013		2012
Costs and Expenses Per Boe of Production:
Production Expenses	$	11.95	$	7.08
Production Taxes		9.18		8.82
G&A Expenses (Excluding Share-Based Compensation)		27.89		12.48
Non-Cash Shared-Based Compensation		16.54		11.96
Depletion of Oil and Natural Gas Properties		28.43		34.44
Impairment of Oil and Natural Gas Properties		—		44.00
Depreciation and Amortization		0.24		0.15
Accretion of Discount on Asset Retirement Obligation		0.05		0.04

Production Expenses

Production expenses were $4,723,520 for the nine months ended September 30, 2013 compared to $1,639,105 for the nine months ended September 30, 2012. We experience increases in operating expenses as we add new operated wells and maintain production from existing properties. On a per unit basis, production expenses per Boe were $11.95 for the nine months ended September 30, 2013 compared to $7.08 for the nine months ended September 30, 2012. These increases were related to initial operated production expenses such as installation of production infrastructure, gas lifting equipment and other fixed productions assets that will be leveraged on future downspacing wells.

Production Taxes

Production taxes were $3,629,557 for the nine months ended September 30, 2013 compared to $2,043,671 for the nine months ended September 30, 2012. We pay production taxes based on realized oil and natural gas sales. Our average production tax rates were 10.05% for the nine months ended September 30, 2013 compared to 10.8% for the nine months ended September 30, 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%.

35

General and Administrative Expense

General and administrative expenses were $17,562,754 for the nine months ended September 30, 2013 compared to $5,660,622 for the nine months ended September 30, 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 nine months ended September 30, 2013 increased on a period-over-period basis compared to the nine months ended September 30, 2012 due to an increase of $9,194,793 for employee compensation and related expense, an increase of $1,865,419 related to professional and legal expense, and an increase of $525,577 in general office expenses. Share-based and restricted stock compensation expenses are included in the employee compensation and related expenses, totaling $6,538,318 for the nine months ended September 30, 2013 compared to $2,770,849 for the nine months ended September 30, 2012. As we implement our operating strategy, expenses have increased to attract and retain experienced personnel that can deliver production growth and create a scalable field infrastructure.

Depletion Expense

Our depletion expense is driven by many factors, including certain exploration costs involved in the development of producing reserves, sales of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. Depletion expense was $11,238,783 for the nine months ended September 30, 2013 compared to $7,977,077 for the nine months ended September 30, 2012. On a per-unit basis, depletion expense was $28.43 per Boe for the nine months ended September 30, 2013 compared to $34.44 per Boe for the nine months ended September 30, 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 development of 6.1 net productive operated wells in the Williston Basin from October 1, 2012 to September 30, 2013, partially offset by the sale of substantially all non-operated Williston Basin properties on September 6, 2013.

Impairment of Oil and Natural Gas Properties

We follow the full cost method of accounting for oil and natural gas operations whereby all costs related to the exploration and development of oil and natural gas properties are initially capitalized into a single cost center (“full cost pool”). Capitalized costs (net of related deferred income taxes) are limited to a ceiling based on the present value of future net revenues using the 12-month unweighted average of first-day-of-the-month price (the “12-month average price”), discounted at 10%, plus the lower of cost or fair market value of unproved properties. If the ceiling is not greater than or equal to the total capitalized costs, then we are required to write down capitalized costs to the ceiling. We perform this ceiling test calculation each quarter. Any required write downs are included in the condensed statements of operations as an impairment charge. We recognized no impairment expense for the nine months ended September 30, 2013 and an impairment expense in the amount of $10,191,234 in the nine months ended September 30, 2012. Included in the full cost pool at September 30, 2012 were costs incurred in 2010 and 2011 associated with our interest in the Niobrara development program in the DJ Basin. We incurred approximately $23.6 million in development costs to acquire acreage and develop the program, with insufficient oil and natural gas reserves established as a result of the development program in the third-party reserve engineer’s reserve report to offset the costs of the development program. While the costs were incurred in 2010 and 2011, we did not fail the ceiling test until June 30, 2012. The failure was primarily due to a decrease in the 12-month average commodity price and an increase in the local differential to NYMEX on Williston Basin properties on the June 30, 2012 reserve report compared to March 31, 2012 and December 31, 2011 reserve reports.

36

Gain on Sale of Oil and Natural Gas Properties

We recognized a gain of $8,892,344 relating to the sale of oil and natural gas properties for the nine months ended September 30, 2013. On September 6, 2013, we sold our interest in 26,579 non-operated net acres located in the Williston Basin and the associated oil and natural gas production to a third party for a total sales price of approximately $111.0 million in cash, including sales price adjustments for development costs and production revenue and operating expenses during the effective period and subject to certain post-closing adjustments. $11.0 million of the sales price will remain in escrow until December 31, 2013 upon finalization of standard due diligence procedures. The acreage was associated with non-operated working interests in Williston Basin Bakken and Three Forks wells. The transaction was accounted for under the full cost method of accounting for oil and natural gas operations, in accordance with Accounting Standard Codification 932 relating to “Extractive Activities – Oil and Gas”. Under the full cost method, sales of oil and natural gas properties, whether or not being amortized, shall be accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center. The sale represents greater than 25 percent of our proved reserves of oil and gas attributable to the cost center. As a result, there is a significant alteration in the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center. Total capitalized costs within the cost center are allocated on the basis of the relative fair values of the properties sold and those retained due to substantial economic differences between the properties sold and those retained. 

Other Income (Expense), Net

Other income (expense), net was $(4,856,883) for the nine months ended September 30, 2013 compared to $3,656,855 for the nine months ended September 30, 2012. We recognized an unrealized loss of $4,587,000 on the warrant liability during the nine months ended September 30, 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 $276,113 for the nine months ended September 30, 2013, compared to $2,074,147 for the nine months ended September 30, 2012. The decrease in interest expense is due to the pay-off of our revolving credit facility balance during the nine months ended September 30, 2013. The other income recognized during the nine months ended September 30, 2012 is a result of a $7,213,835 gain recognized, offset by $1,444,156 of acquisition costs incurred in the acquisition of Emerald Oil North America on July 26, 2012 in accordance with GAAP. The gain is a result of the decrease in the share price of our common stock, which was the primary form of consideration for the acquisition, between the announcement date and closing date of the acquisition.

Net Loss Attributable to Common Stockholders

We had net loss attributable to common stockholders of $20,228,649 for the nine months ended September 30, 2013 (representing $(0.60) per share-basic and diluted) compared to a net loss of $5,222,436 for the nine months ended September 30, 2012 (representing $(0.59) per share-basic and diluted). The increase in net loss available to common shareholders in our period-over-period results is primarily due to the net gain recognized in the acquisition of Emerald Oil North America for the nine months ended September 30, 2012. For the nine months ended September 30, 2013, the net loss was primarily due to higher general and administrative expenses including employment and employment-related expenses, unrealized losses on the preferred stock warrant liability, preferred stock dividends and deemed dividends. Deemed dividends include the $6,250,000 premium paid on the redemption of the Series A Preferred Stock and $8,631,000 non-cash accretion of the Series A Preferred Stock issuance discount and $2,816,006 accretion of the Series A Preferred Stock issuance costs during the nine months ended September 30, 2013.

37

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, preferred stock dividends, depletion, depreciation and amortization, impairment of oil and natural gas properties, accretion of discount on asset retirement obligations, gains on acquisitions and divestitures, 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 September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Net income (loss)	$	8,258,505		$	1,994,842		$	50,548		$	(5,222,436	)
Less: Preferred stock dividends and deemed dividends		(13,997,089	)		—			(20,279,197	)		—
Net income (loss) attributable to common stockholders		(5,738,584	)		1,994,842			(20,228,649	)		(5,222,436	)
Add:       Impairment of oil and natural gas properties		—			—			—			10,191,234
Interest expense		21,437			1,388,912			276,113			2,074,147
Accretion of discount on asset retirement obligations		7,502			4,037			21,564			10,027
Depletion, depreciation and amortization		4,537,633			2,830,995			11,333,448			8,011,636
Stock-based compensation		4,172,522			2,042,972			6,538,318			2,770,849
Warrant revaluation expense		506,000			—			4,587,000			—
Preferred stock dividends		764,383			—			2,582,191			—
Preferred stock redemption premium		4,375,000			—			6,250,000			—
Accretion of preferred stock issuance discount		8,857,706			—			11,447,006			—
Unrealized loss on commodity derivatives		1,455,405			1,514,729			1,224,891			236,646
Less:      Gain on sale of oil and natural gas properties, net		(8,892,344	)		—			(8,892,344	)		—
Gain on acquisition of business, net		—			(5,769,679	)		—			(5,758,048	)
Adjusted EBITDA	$	10,066,660		$	4,006,808		$	15,139,538		$	12,314,055

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:

38

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Net income (loss)	$	8,258,505		$	1,994,842		$	50,548		$	(5,222,436	)
Less: Preferred stock dividends and deemed dividends		(13,997,089	)		—			(20,279,197	)		—
Net income (loss) attributable to common stockholders		(5,738,584	)		1,994,842			(20,228,649	)		(5,222,436	)
Impairment of oil and natural gas properties		—			—			—			10,191,234
Gain on acquisition of business, net		—			(5,769,679	)		—			(5,758,048	)
Gain on sale of oil and natural gas properties, net		(8,892,344	)		—			(8,892,344	)
Unrealized loss on commodity derivatives		1,455,405			1,514,729			1,224,891			236,646
Warrant revaluation expense		506,000			—			4,587,000			—
Adjusted loss	$	(12,669,523	)	$	(2,260,108	)	$	(23,309,102	)		(552,604	)
Adjusted loss per share – basic and diluted	$	(0.29	)	$	(0.23	)	$	(0.69	)		(0.06	)
Weighted average shares outstanding – basic and diluted		42,725,711			9,969,005			33,738,417			8,844,032

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 revolving credit facility; however, if we do not generate sufficient cash flow from operations or do not have availability under our revolving credit facility, we may attempt to continue to finance our operations through equity and/or debt financings.

The following table summarizes total current assets, total current liabilities and working capital at September 30, 2013:

Current assets	$	112,055,034
Current liabilities		66,248,192
Working capital	$	45,806,842

Public Offerings and Private Placements

On May 22, 2013, we completed a public offering of 12,000,000 shares of common stock at a price of $6.10 per share for total gross proceeds of approximately $69.3 million. The underwriters elected to exercise the over-allotment option to sell an additional 1,800,000 shares of common stock at $6.10 per share. The net proceeds from the over-allotment exercise were $10.5 million.

39

On June 4, 2013, we completed a private placement of 2,785,600 shares of common stock at a price of $5.93 per share for total net proceeds of approximately $16.2 million. The issuance of the common stock was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(2) thereof, which exempts transactions by an issuer not involving any public offering.

On October 2, 2013, we completed a public offering of 15,000,000 shares of common stock at a price of $6.70 per share for total net proceeds of approximately $95.5 million. The underwriters elected to exercise the over-allotment option to sell an additional 2,250,000 shares of common stock at $6.70 per share. The net proceeds from the over-allotment exercise were approximately $14.4 million.

On October 17, 2013, we completed a private placement of 5,092,852 shares of common stock at a price of $6.39 per share for net proceeds of approximately $32.5 million. The issuance of the common stock was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(2) thereof, which exempts transactions by an issuer not involving any public offering. 

We have used and intend to further use the net proceeds from these offerings, along with cash on hand, cash flow from operations, proceeds from the sale of assets and additional borrowings under our revolving credit facility, to fund our capital budget in 2013 and 2014. Any remaining net proceeds will be used for general corporate purposes, including working capital.

Series A Preferred Stock Transaction

During the first quarter of 2013, we completed a private offering with 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. On July 10, 2013, our shareholders authorized us to issue at our option additional warrants and shares of common stock issuable upon exercise of such additional warrants as dividends on the Series A Preferred Stock until April 2, 2015.

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 us, 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.

40

On June 20, 2013 we redeemed 150,000 shares of the Series A Preferred Stock for $17,203,767 including $1,875,000 of redemption premium and $328,767 in accrued dividends on the redeemed shares. On August 30, 2013, we redeemed 200,000 shares of the Series A Preferred Stock for $22,828,767 including $2,250,000 of redemption premium and $328,767 of accrued dividends on the redeemed shares. On September 15, 2013, we provided notice that we would redeem the remaining 150,000 shares of the Series A Preferred Stock on October 15, 2013 for $16,932,534 including $1,875,000 of redemption premium and $57,534 in accrued dividends on the redeemed shares. The redemption and dividend are accrued for and the Series A Preferred Stock is included as a current liability at its liquidation preference value of $16,875,000 as of September 30, 2013. For each redemption, the redemption premium was treated as a dividend and recorded as a return of equity to the investor through a charge to additional paid-in capital.

For the three- and nine-month periods ended September 30, 2013, we paid cash dividends on the Series A Preferred Stock of $706,849, and $2,524,658, respectively. No dividends were paid prior to 2013.

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”). As of September 30, 2013, the borrowing base was $75.0 million.

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. Interest on ABR Loans is due and payable on a quarterly basis, and interest on Eurodollar Loans is due and payable, at the 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. As of September 30, 2013, the annual interest rate on the Wells Fargo Facility was 0.375% which is the minimum commitment fee as no funds were drawn against the Wells Fargo Credit Facility.

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 September 30, 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 September 30, 2013.

41

The principal balance amount on the Credit Agreement was $0 and approximately $23.5 million at September 30, 2013 and December 31, 2012, respectively. We had approximately $75.0 million available under the Wells Fargo Facility as of September 30, 2013.

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, the equity offerings completed in October 2013, increasing cash flow from operations, 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 or debt 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 September 30, 2013 were $69,527,908, compared to $10,192,379 as of December 31, 2012. The increase in our cash balance was primarily attributable to the public offering completed on May 22, 2013, the private placement completed on June 4, 2013, the preferred stock issuance to White Deer Energy completed during the first quarter of 2013 and the sale of substantially all of our non-operated Williston Basin properties on September 6, 2013, offset by acquisitions and development of oil and natural gas properties, principal payments made under the Wells Fargo Facility and redemption of preferred stock.

42

Net Cash Provided By Operating Activities

Net cash provided by operating activities was $9,538,728 for the nine months ended September 30, 2013 compared to $8,022,951 for the nine months ended September 30, 2012. The change in the net cash provided by operating activities is primarily attributable to higher production revenue during the nine months ended September 30, 2013, offset by higher general and administrative expenses including employment and employment-related expenses.

Net Cash Used For Investment Activities

Net cash used in investment activities was $27,727,799 for the nine months ended September 30, 2013 compared to $36,640,015 for the nine months ended September 30, 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 proceeds from the sale of non-operated oil and natural gas properties of approximately $134.6 million.

Net Cash Provided By Financing Activities

Net cash provided by financing activities was $77,524,600 for the nine months ended September 30, 2013 compared to $47,972,398 for the nine months ended September 30, 2012. The change in net cash provided by financing activities for the nine months ended September 30, 2013 is primarily attributable to proceeds from the public offering completed on May 22, 2013, proceeds from the private placement completed on June 4, 2013 and proceeds from the preferred stock issuance completed on February 19, 2013, offset by repayment of borrowings under the Wells Fargo Facility and payment of preferred stock dividends and deemed dividends. Deemed dividends include the $6,250,000 premium paid on the preferred stock redemption for the nine months ended September 30, 2013. The change in net cash provided by financing activities for the nine months ended September 30, 2012 is primarily attributable to proceeds from our revolving 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 $127.2 million to drill 12.0 net operated and 0.5 net non-operated wells in the Williston Basin, of which we have spent approximately $76.5 million through September 30, 2013. For the 12-month period ending December 31, 2013, we have also budgeted approximately $20.0 million to increase our operated acreage position in our core operated area We expect to fund our current 2013 capital expenditure budget using cash-on-hand, cash flow from operations, 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

The preparation of financial statements in accordance with generally accepted accounting principles requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Certain of our accounting policies are considered critical, as these policies are the most important to the depiction of our financial statements and require significant, difficult or complex judgments, often employing the use of estimates about the effects of matters that are inherently uncertain. A summary of our significant accounting policies is included in Note 2—Basis of Presentation and Significant Accounting Policies to our consolidated financial statements included in our annual report on Form 10-K for the year ended December 31, 2012, as well as in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section in such Form 10-K. There have been no significant changes in the application of our critical accounting policies during the nine-month period ended September 30, 2013.

43

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, in our Quarterly Reports on Form 10-Q for the three months ended March 31, 2013 and June 30, 2013 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;

44

· 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 and nine- month periods ended September 30, 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 Wells Fargo 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. Based on the September 30, 2013 published commodity futures price curves for crude oil, a hypothetical price increase or decrease of $1.00 per Bbl for crude oil would increase or decrease the fair value of our net commodity derivative liability by approximately $317,000.

45

The following table reflects open commodity swap contracts as of September 30, 2013, the associated volumes and the corresponding weighted average NYMEX reference price:

Settlement Period	Oil (Bbls)		Fixed Price
Oil Swaps
July 1, 2013 – December 31, 2013		30,870	$	91.00
July 1, 2013  – December 31, 2013		12,000		90.05
July 1, 2013 – December 31, 2013		30,000		94.30
2013 Total/Average		72,870	$	92.20
January 1, 2014 – December 31, 2014		103,267	$	91.00
January 1, 2014 – December 31, 2014		31,000		90.05
January 1, 2014 – December 31, 2014		79,000		94.30
2014 Total/Average		213,267	$	92.08
January 1, 2015 – February 28, 2015		13,876	$	91.00
January 1, 2015 – February 28, 2015		5,000		90.05
January 1, 2015 – February 28, 2015		10,000		94.30
2015 Total/Average		28,876	$	91.98

Interest Rate Risk

As of September 30, 2013, we had no outstanding borrowings under our Wells Fargo Facility. Our Wells Fargo Facility subjects us to interest rate risk on borrowings. This revolving credit facility allows us to fix the interest rate of borrowings under it for all or a portion of the principal balance for a period up to six months. To the extent the interest rate is fixed, interest rate changes affect the instrument’s fair market value but do not impact results of operations or cash flows. Conversely, for the portion of our borrowings that has a floating interest rate, interest rate changes will not affect the fair market value but will impact future results of operations and cash flows.

ITEM 4. CONTROLS AND PROCEDURES

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 September 30, 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.

Effective July 1, 2013, we transitioned our back-office accounting functions in-house from an outsourced third-party. While these transitions have changed the physical location within the accounting process where certain internal control points occur, the nature and extent of such internal controls remain unchanged. Therefore, there have been no changes in our internal control over financial reporting that occurred during our fiscal quarter ended September 30, 2013, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

46

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 that may arise in the ordinary course 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 ended December 31, 2012, as filed with the SEC on March 18, 2013 and Item 1A. –“Risk Factors” of our Quarterly Reports on Form 10-Q for the three months ended March 31, 2013, as filed with the SEC on May 9, 2013, and June 30, 2013, as filed with the SEC on August 6, 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 of September 30, 2013, there have been no material changes to the risk factors disclosed in our most recent Annual Report on Form 10-K and Quarterly Reports on Form 10-Q, except as stated below. 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.

Our identified potential drilling locations, which are part of our anticipated future drilling plans, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

As of September 30, 2013, we have identified approximately 313 net potential drilling locations on our acreage prospective for oil in the Bakken, Three Forks and Pronghorn Sand formations, based on industry accepted well down-spacing assumptions, including 1,280-acre DSUs in the Williston Basin, and inclusive of pending acreage acquisitions. These drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil and natural gas prices, costs, drilling results and the availability of water. Further, our identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. We cannot predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

One of our existing shareholders beneficially owns common stock and warrants to purchase a significant percentage of our common stock, and its interests may conflict with those of our other shareholders.

As of November 5, 2013, White Deer Energy L.P. beneficially owned approximately 18.5% of our outstanding common stock on a fully diluted basis, consisting of 7,878,452 shares of our common stock and a warrant to purchase 5,114,633 shares of our common stock. White Deer Energy owns 5,114,633 shares of our Series B Voting Preferred Stock, which have one vote per share and vote together with shares of our common stock. In addition, as the holder of our outstanding Series A Perpetual Preferred Stock, White Deer is entitled to appoint one member to our board of directors. As a result, White Deer Energy is able to exercise significant influence over matters requiring shareholder approval, including the election of directors, the adoption or amendment of provisions in our charter and bylaws, the approval of mergers and other significant corporate transactions. The interests of White Deer Energy with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities, may conflict with the interests of our other shareholders.

47

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 Purchase and Sale Agreement, dated September 6, 2013, by and among Emerald Oil, Inc., Emerald WB LLC, and USG Properties Bakken II, LLC (incorporated by reference to Exhibit 2.1 to our current report on Form 8-K filed on September 12, 2013)

10.1 Emerald Oil, Inc. Second Amended and Restated 2011 Equity Incentive Plan (incorporated by reference to Exhibit 10.1 to our current report on Form 8-K filed on July 12, 2013)

10.2 Borrowing Base Letter Agreement between Emerald Oil, Inc. and Wells Fargo, National Association, dated August 9, 2013 (incorporated by reference to Exhibit 10.1 to our current report on Form 8-K filed on August 13, 2013)

10.3 Employment Agreement between McAndrew Rudisill and Emerald Oil, Inc., dated September 18, 2013 (incorporated by reference to Exhibit 10.1 to our current report on Form 8-K filed on September 18, 2013)

10.4 Employment Agreement between James Russell (J.R.) Reger and Emerald Oil, Inc., dated September 18, 2013. (incorporated by reference to Exhibit 10.2 to our current report on Form 8-K filed on September 18, 2013)

10.5 Employment Agreement between Paul Wiesner and Emerald Oil, Inc., dated September 18, 2013 (incorporated by reference to Exhibit 10.3 to our current report on Form 8-K filed on September 18, 2013)

10.6 Employment Agreement between David Veltri and Emerald Oil, Inc., dated September 18, 2013 (incorporated by reference to Exhibit 10.4 to our current report on Form 8-K filed on September 18, 2013)

10.7 Second Amended and Restated Employment Agreement between Michael Krzus and Emerald Oil, Inc., dated September 18, 2013 (incorporated by reference to Exhibit 10.5 to our current report on Form 8-K filed on September 18, 2013)

10.8 Securities Purchase Agreement, dated September 23, 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 September 23, 2013)

10.9 Amendment No. 2 to the Registration Rights Agreement, dated October 17, 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 October 17, 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

48

101.INS* XBRL Instance Document

101.SCH*  XBRL Schema Document

101.CAL*  XBRL Calculation Linkbase Document

101.DEF*  XBRL Definition 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: November 5, 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)

49