10-Q

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 June 30, 2014

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)

Delaware	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) 595-5600

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 August 4, 2014, there were 66,477,468 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 June 30, 2014 and December 31, 2013	1
		Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2014 and 2013	2
		Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2014 and 2013	3
		Notes to Condensed Consolidated Financial Statements	4
	ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	19
	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	33
	ITEM 4.	CONTROLS AND PROCEDURES	34
PART II.	OTHER INFORMATION		34
	ITEM 1.	LEGAL PROCEEDINGS	34
	ITEM 1A.	RISK FACTORS	34
	ITEM 2.	UNREGISTERED SALES OR EQUITY SECURITIES AND USE OF PROCEEDS	35
	ITEM 5.	OTHER INFORMATION	35
	ITEM 6.	EXHIBITS	35
SIGNATURES			35

PART 1 — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EMERALD OIL, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	June 30, 2014			December 31, 2013
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	134,171,667		$	144,255,438
Restricted Cash		6,000,000			15,000,512
Accounts Receivable – Oil and Natural Gas Sales		9,352,780			8,715,821
Accounts Receivable – Joint Interest Partners		36,396,745			31,523,204
Other Receivables		1,600,141			577,409
Prepaid Expenses and Other Current Assets		534,430			206,299
Total Current Assets		188,055,763			200,278,683
PROPERTY AND EQUIPMENT
Oil and Natural Gas Properties, Full Cost Method, at cost:
Proved Oil and Natural Gas Properties		378,486,735			211,015,067
Unproved Oil and Natural Gas Properties		122,067,454			57,015,315
Equipment and Facilities		4,109,546			1,837,744
Other Property and Equipment		1,645,303			890,811
Total Property and Equipment		506,309,038			270,758,937
Less – Accumulated Depreciation, Depletion and Amortization		(63,201,890	)		(48,176,522	)
Total Property and Equipment, Net		443,107,148			222,582,415
Restricted Cash		4,000,000			6,000,000
Fair Value of Commodity Derivatives		—			68,396
Debt Issuance Costs, Net of Amortization		6,204,848			475,157
Deposits on Acquisitions		304,335			125,368
Other Non-Current Assets		227,207			357,644
Total Assets	$	641,899,301		$	429,887,663
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts Payable	$	91,416,789		$	63,168,422
Fair Value of Commodity Derivatives		5,852,801			921,401
Accrued Expenses		13,238,341			11,821,729
Advances from Joint Interest Partners		3,723,910			2,205,538
Total Current Liabilities		114,231,841			78,117,090
LONG-TERM LIABILITIES
Convertible Senior Notes		172,500,000			—
Asset Retirement Obligations		1,243,136			692,137
Warrant Liability		17,670,000			15,703,000
Other Non-Current Liabilities		265,660			56,327
Total Liabilities		305,910,637			94,568,554
COMMITMENTS AND CONTINGENCIES
Preferred Stock – Par Value $.001; 20,000,000 Shares Authorized;
Series B Voting Preferred Stock – 5,114,633 issued and outstanding at June 30, 2014 and December 31, 2013. Liquidation preference value of $5,115 as of June 30, 2014 and December 31, 2013.		5,000			5,000
STOCKHOLDERS’ EQUITY
Common Stock, Par Value $.001; 500,000,000 Shares Authorized, 66,471,276 and 65,840,370 Shares Issued and Outstanding, respectively		66,471			65,840
Additional Paid-In Capital		420,571,408			416,301,344
Accumulated Deficit		(84,654,215	)		(81,053,075	)
Total Stockholders’ Equity		335,983,664			335,314,109
Total Liabilities and Stockholders’ Equity	$	641,899,301		$	429,887,663

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 June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
REVENUES
Oil Sales	$	30,288,128		$	10,340,742		$	48,722,936		$	18,334,644
Natural Gas Sales		966,280			234,076			1,600,344			457,155
Net Gains (Losses) on Commodity Derivatives		(6,663,083	)		665,337			(7,461,936	)		(102,267	)
Total Revenues		24,591,325			11,240,155			42,861,344			18,689,532
OPERATING EXPENSES
Production Expenses		3,897,482			1,596,353			6,514,726			2,635,885
Production Taxes		3,400,874			1,048,541			5,489,610			1,750,397
General and Administrative Expenses		7,633,559			5,979,739			16,125,563			11,368,552
Depletion of Oil and Natural Gas Properties		8,600,878			3,584,803			14,878,110			6,741,781
Depreciation and Amortization		81,497			31,039			147,257			54,034
Accretion of Discount on Asset Retirement Obligations		20,080			7,850			35,800			14,062
Total  Operating Expenses		23,634,370			12,248,325			43,191,066			22,564,711
INCOME (LOSS) FROM OPERATIONS		956,955			(1,008,170	)		(329,722	)		(3,875,179	)
OTHER INCOME (EXPENSE)
Interest Expense		(1,136,377	)		(75,186	)		(1,308,463	)		(254,676	)
Warrant Revaluation Expense		(1,771,000	)		(642,000	)		(1,967,000	)		(4,081,000	)
Other Income		371			2,222			4,047			2,898
Total Other Expense, Net		(2,907,006	)		(714,964	)		(3,271,416	)		(4,332,778	)
LOSS BEFORE INCOME TAXES		(1,950,051	)		(1,723,134	)		(3,601,138	)		(8,207,957	)
INCOME TAX PROVISION		—			—			—			—
NET LOSS		(1,950,051	)		(1,723,134	)		(3,601,138	)		(8,207,957	)
Less: Preferred Stock Dividends and Deemed Dividends		—			(5,665,670	)		—			(6,282,108	)
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(1,950,051	)	$	(7,388,804	)	$	(3,601,138	)	$	(14,490,065	)
Net Income (Loss) Per Common Share – Basic and Diluted	$	(0.03	)	$	(0.23	)	$	(0.05	)	$	(0.50	)
Weighted Average Shares Outstanding – Basic and Diluted		66,323,228			32,602,115			66,251,632			29,166,411

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

2

EMERALD OIL, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Six Months Ended June 30,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$	(3,601,138	)	$	(8,207,957	)
Adjustments to Reconcile Net Loss to Net Cash Provided By Operating Activities:
Depletion of Oil and Natural Gas Properties		14,878,110			6,741,781
Depreciation and Amortization		147,257			54,034
Amortization of Debt Issuance Costs		377,463			44,573
Accretion of Discount on Asset Retirement Obligations		35,800			14,062
Net Losses on Commodity Derivatives		7,461,936			102,267
Net Cash Settlements Paid on Commodity Derivatives		(2,462,140	)		(332,781	)
Warrant Revaluation Expense		1,967,000			4,081,000
Share-Based Compensation Expense		6,678,883			2,365,797
Changes in Assets and Liabilities:
Increase in Trade Receivables – Oil and Natural Gas Revenues		(636,959	)		(755,866	)
Increase in Accounts Receivable – Joint Interest Partners		(4,873,541	)		(4,976,709	)
Increase in Other Receivables		(1,022,732	)		(246,392	)
Increase in Prepaid Expenses and Other Current Assets		(328,131	)		(214,497	)
Decrease in Other Non-Current Assets		130,437			85,675
Increase in Accounts Payable		1,888,872			1,069,554
Increase (Decrease) in Accrued Expenses		(2,474,083	)		1,557,119
Increase in Other Non-Current Liabilities		209,333			—
Increases in Advances from Joint Interest Partners		1,518,372			834,639
Net Cash Provided By Operating Activities		19,894,739			2,216,299
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of Other Property and Equipment		(754,492	)		(201,657	)
Restricted Cash Released		11,000,512			—
Payments of Restricted Cash		(2,648,721	)		—
Increase in Deposits for Acquisitions		(178,967	)		(1,050,000	)
Use of Prepaid Drilling Costs		—			98,565
Proceeds from Sale of Oil and Natural Gas Properties, Net of Transaction Costs		238,069			15,160,206
Investment in Oil and Natural Gas Properties		(204,113,902	)		(54,689,661	)
Net Cash Used For Investing Activities		(196,457,501	)		(40,682,547	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Issuance of Common Stock, Net of Transaction Costs		—			95,973,701
Proceeds from Issuance of Preferred Stock, Net of Transaction Costs		—			47,183,994
Proceeds from Issuance of Convertible Senior Notes, Net of Transaction Costs		166,893,211			—
Advances on Revolving Credit Facility		35,000,000			—
Payments on Preferred Stock		—			(15,000,000	)
Payments on Revolving Credit Facility		(35,000,000	)		(23,500,000	)
Preferred Stock Dividends and Deemed Dividends		—			(3,692,808	)
Proceeds from Exercise of Stock Options and Warrants		110,750			—
Cash Paid for Debt Issuance Costs		(500,365	)		—
Cash Paid for Finance Costs		(24,605	)		—
Net Cash Provided by Financing Activities		166,478,991			100,964,887
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(10,083,771	)		62,498,639
CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD		144,255,438			10,192,379
CASH AND CASH EQUIVALENTS – END OF PERIOD	$	134,171,667		$	72,691,018
Supplemental Disclosure of Cash Flow Information
Cash Paid During the Period for Interest	$	84,933		$	255,776
Cash Paid During the Period for Income Taxes	$	—		$	—
Non-Cash Financing and Investing Activities:
Oil and Natural Gas Properties Included in Account Payable	$	86,500,675		$	37,344,286
Stock-Based Compensation Capitalized to Oil and Natural Gas Properties	$	1,396,362		$	310,264
Accretion on Preferred Stock Issuance Discount	$	—		$	2,589,300
Asset Retirement Obligation Costs and Liabilities	$	515,199		$	122,013
Common Stock Issued for Oil and Natural Gas Properties	$	—		$	6,736,935

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

3

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

NOTE 1  ORGANIZATION AND NATURE OF BUSINESS

Description of Operations —  Emerald Oil, Inc., a Delaware corporation (“Emerald,” the “Company,” “we,” “us,” or “our”), is a Denver-based independent exploration and production company that is focused on acquiring acreage and developing wells in the Williston Basin of North Dakota and Montana. We believe the location, size and concentration of our acreage in our core project areas create an opportunity for us to achieve cost, recovery and production efficiencies through the large-scale development of our project inventory. The Company designs, drills and operates oil and natural gas wells on acreage where it holds a controlling working interest.

On June 11, 2014, the shareholders of the Company approved a measure to change our state of incorporation from Montana to Delaware. On June 11, 2014, the Company consummated a merger with our wholly owned subsidiary and, as a result, reincorporated as a Delaware corporation.

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 June 30, 2014 and for the three and six months ended June 30, 2014 and 2013 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 June 30, 2014 and for the three and six months ended June 30, 2014 and 2013.

Interim financial results should be read in conjunction with the audited financial statements and footnotes for the year ended December 31, 2013, which were included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2013.

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.

Restricted Cash

Restricted cash included in current and long-term assets on the condensed consolidated balance sheets totaled $10 million and $21 million at June 30, 2014 and December 31, 2013, respectively.  At June 30, 2014, the $10 million balance related to a drilling commitment agreement entered into pursuant to oil and natural gas leases. As of December 31, 2013, there was an additional $11.0 million of restricted cash related to a portion of proceeds from a leasehold sale held in escrow until finalization of standard due diligence procedures. On February 21, 2014, $8.6 million was released to the Company, with the remaining $2.4 million returned to the buyer for purchase price adjustments.

4

Accounts Receivable

The Company records estimated oil and natural gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. Management periodically reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables under the specific identification method. The Company did not record any allowance for uncollectible receivables during the three and six months ended June 30, 2014 and 2013.

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 months ended June 30, 2014 and 2013, the Company capitalized $1,538,567 and $903,162, respectively, of internal salaries, which included $735,393, and $210,712, respectively, of stock-based compensation. For the six months ended June 30, 2014 and 2013, the Company capitalized $2,923,549 and $1,218,954, respectively, of internal salaries, which included $1,396,362, and $310,264, respectively, of stock-based compensation. Internal salaries are capitalized based on employee time allocated to the acquisition of leaseholds and development of oil and natural gas properties. The Company capitalized no interest in the three and six months ended June 30, 2014 and 2013.

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. No gain or loss was recognized on any sales during the three and six months ended June 30, 2014 and 2013. 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 unproved property on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and amortization. For the six months ended June 30, 2014 and the year ended December 31, 2013, the Company included $2,440,918 and $3,020,485, respectively, related to expiring leases within costs subject to the depletion calculation.

Capitalized costs associated with impaired properties and properties having proved reserves, estimated future development costs, and asset retirement costs under 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 developed, impaired, or abandoned.

Under the full cost method of accounting, capitalized oil and natural gas property costs less accumulated depletion, net of deferred income taxes, may not exceed a ceiling amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are subject to amortization. Should capitalized costs exceed this ceiling, which is tested on a quarterly basis, an impairment is recognized. The present value of estimated future net revenues is computed by applying prices based on a 12-month unweighted 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 six months ended June 30, 2014 or 2013.

5

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 expense as incurred.

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 proved reserves were not adequate to cover the current imbalance situation. As of June 30, 2014 and December 31, 2013, the Company’s natural gas production was in balance, i.e., its cumulative portion of natural gas production taken and sold from wells in which it has an interest equaled the Company’s entitled interest in natural gas production from those wells.

Stock-Based Compensation

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

On May 27, 2011, the stockholders 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 and July 10, 2013, the stockholders of the Company approved an amendment to the 2011 Plan to increase the number of shares available for issuance under the 2011 Plan to 3,500,000 shares and 9,800,000 shares, respectively. 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 June 30, 2014, 1,471,597 stock options and 4,204,000 shares of common stock and restricted stock units had been issued to officers, directors and employees under the 2011 Plan net of cancelations and forfeitures, including 1,611,792 nonvested restricted stock units. As of June 30, 2014, there were 4,124,403 shares available for issuance under the 2011 Plan.

6

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 consolidated balance sheet.

Net Income (Loss) Per Common Share

Basic net income (loss) per common share is based on the net income (loss) divided by the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average number of common shares plus dilutive common share equivalents outstanding during the period using the treasury stock method. In the computation of diluted earnings per share, excess tax benefits that would be created upon the assumed vesting of nonvested 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 six months ended June 30, 2014 and 2013, the potentially dilutive shares were anti-dilutive and were thus not included in the net loss per share calculation.

 As of June 30, 2014, (i) 1,611,792 nonvested restricted stock units were issued and outstanding and represented potentially dilutive shares; (ii) 482,360 stock options were issued and exercisable and represented potentially dilutive shares; (iii) 999,942 stock options were granted but were not exercisable and represented potentially dilutive shares; (iv) 5,114,633 warrants were issued and exercisable at an exercise price of $5.77 and represented dilutive shares; (v) 223,293 warrants were issued and exercisable at an exercise price of $6.86 and represented potentially dilutive shares; (vi) 892,858 warrants were issued and exercisable at an exercise price of $49.70 and represented potentially dilutive shares; and (vii) $172.5 million of convertible senior notes convertible into approximately 19,658,120 common shares as of June 30, 2014 and represented potentially dilutive shares.

Derivative and Other Financial Instruments

Commodity Derivative Instruments

The Company has entered into commodity derivative instruments, utilizing oil derivative swap contracts 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. Net gains and losses are recorded based on the changes in the fair values of the derivative instruments. 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 12 – 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 (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.

7

As a part of a securities purchase agreement entered into in February 2013 with affiliates of White Deer Energy L.P. (see Note 5 – 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 the consolidated statements of operations.

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 consolidated financial statements upon adoption.

Use of Estimates

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

Industry Segment and Geographic Information

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

Reclassifications

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

NOTE 3  OIL AND NATURAL GAS PROPERTIES

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, the issuance of equity or debt securities and short-term borrowings under its revolving credit facility.

Acquisitions

In February 2014, the Company acquired approximately 19,500 net acres located in Williams and McKenzie Counties, North Dakota from an unrelated third party for approximately $69.2 million in cash. Net daily production from the acreage was approximately 300 Boe/d as of January 1, 2014, the effective date of the transaction. The acquisition was accounted for as an asset purchase. Related transaction costs were capitalized to oil and natural gas properties.

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In February 2014, the Company acquired approximately 5,900 net acres of undeveloped leasehold located in McKenzie and Billings Counties, North Dakota from an unrelated third party for approximately $10.3 million in cash.

NOTE 4  RELATED PARTY TRANSACTIONS

In February 2013, the Company entered into a securities purchase agreement (the “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, for an aggregate $50 million. Pursuant to the purchase agreement, White Deer Energy obtained the right to designate one member of the Company’s board of directors as long as White Deer Energy held any shares of Series A Preferred Stock. White Deer Energy designated Thomas J. Edelman as its initial director. Following the redemption of the Series A Preferred Stock, the Governance and Nominating Committee of the Company nominated Mr. Edelman to continue to serve as a director of the Company, and Mr. Edelman was elected to serve on the board of directors of the Company for another term at the annual stockholders meeting of the Company held in June 2014. For additional information regarding the Securities Purchase Agreement with White Deer Energy, see Note 5 — Preferred and Common Stock.

The transaction was subject to customary closing conditions, as well as the execution and delivery of certain other agreements, including a registration rights agreement. Under the terms of the registration rights agreement, as amended, the Company agreed to file with the Securities and Exchange Commission (the “SEC”), within 30 days upon receipt of notice from White Deer Energy, a shelf registration statement covering resales of the 5,114,633 shares of Company common stock issuable upon exercise of the warrants and use commercially reasonable efforts to cause such registration statement to be declared effective within 120 days after the filing thereof. In June 2013 and October 2013, the Company amended the registration rights agreement to include 2,785,600 shares of Company common stock and 5,092,852 shares of Company common stock, respectively, issued to White Deer Energy in connection with subsequent private placements. On April 19, 2014, the Company received a request from White Deer Energy to register the shares of Company common stock and the shares of Company common stock underlying the warrants held by White Deer Energy.  On May 16, 2014, the Company filed with the SEC a registration statement on Form S-3 to register for resale the 7,878,452 shares of common stock and 5,114,633 shares of common stock underlying the warrants held by White Deer, and the SEC declared the registration statement effective on May 30, 2014.

NOTE 5  PREFERRED AND COMMON STOCK

Preferred Stock

On February 19, 2013, the Company issued to White Deer Energy 500,000 shares of Series A Preferred Stock, 5,114,633 shares of Series B Preferred Stock and warrants to purchase an initial aggregate 5,114,633 shares of the Company’s common stock at an initial exercise price of $5.77 per share, in exchange for an aggregate $50 million. The warrants are exercisable until December 31, 2019.

On various dates throughout 2013, the Company redeemed all of the outstanding shares of Series A Preferred Stock, including principal of $50,000,000 and redemption premiums of $6,250,000, and no shares of Series A Preferred Stock remain outstanding as of June 30, 2014. For each redemption, the redemption premium was 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. The Company paid no dividends during the three and six months ended June 30, 2014. For the three and six months ended June 30, 2013, the Company paid dividends on the Series A Preferred Stock of $1,201,370 and $1,817,808, respectively.

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

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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. See Note 12 – 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, White Deer Energy had 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 Preferred Stock, Series B Preferred Stock and the warrants, as well as shares of common stock issued upon exercise of the warrant that were then held by White Deer Energy, an additional cash payment necessary to achieve a minimum internal rate of return of 25%. Upon the final redemption of the shares Series A Preferred Stock on October 15, 2013, the Company and White Deer Energy agreed the minimum internal rate of return had been achieved and no additional cash payment to White Deer Energy would be necessary upon a change of control or liquidation event.

The Company recorded the private placement 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 accreted the Series A Preferred Stock to the liquidation or redemption value when it became probable that the event or events underlying the liquidation or redemption of the Series A Preferred Stock were probable. The Company recognized all issuance discount accretion related to the partial redemptions of preferred stock on June 20, 2013, August 30, 2013 and October 15, 2013. There was no issuance discount remaining as of June 30, 2014.

A summary of the preferred stock transaction components as of June 30, 2014 and December 31, 2013 is provided below:

	June 30, 2014		December 31, 2013
Series A Preferred Stock	$	—	$	—
Series B Preferred Stock		5,000		5,000
Warrant Liability		17,670,000		15,703,000
Total	$	17,675,000	$	15,708,000

Restricted Stock Awards and Restricted Stock Unit Awards

The Company incurred compensation expense associated with restricted stock and restricted stock units granted of $2,746,344 and $876,427 for the three months ended June 30, 2014 and 2013, respectively, and $6,206,274 and $1,789,725 for the six months ended June 30, 2014 and 2013, respectively. As of June 30, 2014, there were 1,611,792 non-vested restricted stock units and $5,962,785 associated remaining unrecognized compensation expense, which is expected to be recognized over the weighted-average period of 0.80 years. The Company capitalized compensation expense associated with the restricted stock and restricted stock units of $548,036 and $51,148 to oil and natural gas properties for the three months ended June 30, 2014 and 2013, respectively, and $987,751 and $89,102 for the six months ended June 30, 2014 and 2013, respectively.

A summary of the restricted stock units and restricted stock shares activity during the six months ended June 30, 2014 is as follows:

	Number of Shares			Weighted Average Grant Date Fair Value
Non-vested restricted stock and restricted stock units at January 1, 2014		2,082,187		$	5.73
Granted		264,134			7.48
Canceled		—			—
Vested and forfeited for taxes		(293,813	)		5.85
Vested and issued		(440,716	)		5.85
Non-vested restricted stock and restricted stock units at June 30, 2014		1,611,792		$	5.96

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NOTE 6  STOCK OPTIONS AND WARRANTS

Stock Options

On January 10, 2014, the Company granted stock options to certain employees to purchase a total of 295,800 shares of common stock exercisable at $7.48 per share. The options vest on an annual basis over 36 months with 98,600 options vesting on January 10, 2015, 2016 and 2017.

On April 1, 2014, the Company granted stock options to certain employees to purchase a total of 255,499 shares of common stock exercisable at $6.69 per share. The options vest on an annual basis over 36 months with 85,166 options vesting on April 1, 2015, 2016 and 2017.

The total fair value of stock options granted during the three and six months ended June 30, 2014 was calculated using the Black-Scholes valuation model based on factors present at the time the options were granted. The following assumptions were used for the Black-Scholes model to value the options granted during the six-month period ended June 30, 2014.

Risk free rates	0.77% to 1.32%
Dividend yield	0%
Expected volatility	62.08% to 67.70%
Weighted average expected life	3.5 years

The impact on the Company’s statement of operations of stock-based compensation expense related to options granted for the three months ended June 30, 2014 and 2013 was $237,236 and $181,384, 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 six-month periods ended June 30, 2014 and 2013 was $472,609 and $576,072, respectively, net of $0 tax. The Company capitalized $187,357, and $159,563 in compensation to oil and natural gas properties related to outstanding options for the three months ended June 30, 2014 and 2013, respectively, and $408,611 and $221,161 for the six months ended June 30, 2014 and 2013, respectively. The Company had $1,819,202 of total unrecognized compensation cost related to nonvested stock options granted as of June 30, 2014. The remaining cost is expected to be recognized over a weighted-average period of 1.44 years. These estimates are subject to change based on a variety of future events which include, but are not limited to, changes in estimated forfeiture rates, cancellations and the issuance of new options.

A summary of the stock options activity during the six months ended June 30, 2014 is as follows:

	Number of Options			Weighted Average Exercise Price
Balance outstanding at January 1, 2014		1,158,860		$	8.90
Granted		551,299			7.11
Canceled		(202,857	)		7.77
Exercised		(25,000	)		4.43
Balance outstanding at June 30, 2014		1,482,302		$	7.33
Options exercisable at June 30, 2014		482,360		$	10.91

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At June 30, 2014, 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
2014		529,499		4.64	$	7.11		—		—	$	—
2013		417,101		5.78		7.14		116,301		4.71		6.78
2012		407,142		2.78		7.66		237,499		2.57		7.53
Prior		128,560		1.64		20.90		128,560		1.64		20.90
Total		1,482,302		4.19	$	7.33		482,360		2.84	$	10.91

Warrants

The table below reflects the status of warrants outstanding at June 30, 2014:

	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		892,858	$	49.70	February 8, 2016
February 19, 2013		5,114,633	$	5.77	December 31, 2019
Total		6,230,784

No warrants expired or were forfeited during the six months ended June 30, 2014. 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 June 30, 2014. See Note 12 – Derivative Instruments and Price Risk Management for details on the treatment of the warrants issued on February 19, 2013.

NOTE 7 REVOLVING CREDIT FACILITY

On November 20, 2012, the Company entered into a senior secured revolving credit facility (the “Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent (“Wells Fargo”), and the lenders party thereto. On May 1, 2014, the Company amended the Credit Facility with Wells Fargo as administrative agent for the lenders party to the Credit Facility. The Credit Facility is a senior secured reserve-based revolving credit facility with a maximum commitment of $400 million. As of June 30, 2014, the Credit Facility was undrawn and had a borrowing base of $100.0 million.

Amounts borrowed under the Credit Facility will mature on September 30, 2018, and upon such date, any amounts outstanding under the Credit Facility are due and payable in full. 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 the Company’s option, based on either the Alternate Base Rate (as defined under the terms of the Credit Facility) 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 rate 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 June 30, 2014, the annual interest rate on the Credit Facility was 0.375% which is the minimum commitment fee, as no funds were drawn against the Credit Facility.

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A portion of the Credit 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 June 30, 2014, the Company has not obtained any letters of credit under the existing facility.

Each of the Company’s subsidiaries is a guarantor under the Credit Facility. The Credit 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 Facility 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 Facility 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 total debt to EBITDA for the preceding four fiscal quarters of no more than 3.50 to 1.00. For any fiscal quarter ending in calendar year 2014, total debt is reduced by cash equivalents less $10,000,000 for purposes of calculating the total debt to EBITDA ratio. The Company was in compliance with all covenants as of June 30, 2014.

The Credit Facility allows the Company to hedge up to 60% of proved reserves for the first 24 months and 80% of projected production from proved developed producing reserves from 24 months up to 60 months later provided that in no event shall the aggregate amount of hedges exceed 100% of actual production in the current period.

The principal balance amount on the Credit Agreement was undrawn as of June 30, 2014 and December 31, 2013.

NOTE 8 CONVERTIBLE NOTES

On March 24, 2014, the Company completed a private placement of $172.5 million in aggregate principal amount of 2.0% Convertible Notes (the “Convertible Notes”), and entered into an indenture (the “Indenture”) governing the Convertible Notes, with U.S. Bank National Association, as trustee (the “Trustee”). The Convertible Notes accrue interest at a rate of 2.00% per year, payable semiannually in arrears on April 1 and October 1 of each year, beginning on October 1, 2014. The Convertible Notes mature on April 1, 2019. The Convertible Notes are the Company’s unsecured senior obligations and are equal in right of payment to the Company’s existing and future senior indebtedness. The Convertible Notes were convertible as of June 30, 2014. However, the Company does not believe conversion will take place as the market price of the Convertible Notes is currently above the estimated conversion value, and in the event of conversion, holders would forgo all future interest payments and the possibility of further stock price appreciation. As a result, the Convertible Notes have been classified as long-term debt as of June 30, 2014.

The net proceeds from the Convertible Notes were $166.9 million, after deducting commissions and the offering expenses payable by the Company. The Company’s transaction costs in conjunction with the transaction will be amortized to interest expense over the five-year term of the Convertible Notes.

The Convertible Notes and the common stock issuable upon conversion of the Convertible Notes have not been registered under the Securities Act of 1933, as amended (the “Securities Act”), or the securities laws of any other jurisdiction, and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements. The Convertible Notes were offered and sold to the initial purchasers in a private placement exempt from the registration requirements of the Securities Act pursuant to Section 4(a)(2). The Convertible Notes were resold by the initial purchasers to qualified institutional buyers in reliance on Rule 144A under the Securities Act.

Holders may convert their Convertible Notes at their option at any time prior to the close of business on the business day immediately preceding the maturity date of the Convertible Notes. The conversion rate for the Convertible Notes is initially 113.9601 shares of the Company’s common stock per $1,000 principal amount of Convertible Notes (which represents an initial conversion price of approximately $8.78 per share of the Company’s common stock), subject to certain anti-dilution adjustments as provided in the Indenture. A holder that surrenders its Convertible Notes for conversion in connection with a Make-Whole Fundamental Change (as defined in the Indenture) that occurs before the maturity date may in certain circumstances be entitled to an increased conversion rate. If the Company undergoes a Fundamental Change (as defined in the Indenture), subject to certain conditions, the holder of the Convertible Notes will have the option to require the Company to repurchase all or any portion of its Convertible Notes for cash. The fundamental change purchase price will be 100% of the principal amount of the Convertible Notes to be purchased, plus any accrued and unpaid interest, including additional interest, if any, to, but excluding, the fundamental change purchase date. The Company may not redeem the Convertible Notes prior to their maturity, and no sinking fund is provided for the Convertible Notes.

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The Company does not intend to file a shelf registration statement for resale of the Convertible Notes or the shares of its common stock issuable upon conversion of the Convertible Notes. The Company will, however, be required to pay additional interest in respect of the Convertible Notes under specified circumstances. As a result, holders may only resell the Convertible Notes or shares of the Company’s common stock issued upon conversion of the Convertible Notes, if any, pursuant to an exemption from the registration requirements of the Securities Act and other applicable securities laws.

The Indenture contains customary terms and covenants and events of default. If an Event of Default (as defined in the Indenture) occurs and is continuing, the Trustee or the holders of at least 25% in aggregate principal amount of the then outstanding Convertible Notes may declare by written notice all the Convertible Notes to be immediately due and payable in full. The Company was in compliance with all covenants as of June 30, 2014.

NOTE 9  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 periods presented); and (iv) a credit-adjusted risk-free interest rate (average of 7.0% for each of the periods presented). 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 six months ended June 30, 2014 and the year ended December 31, 2013:

	Six Months Ended June 30, 2014		Year Ended December 31, 2013
Beginning Asset Retirement Obligation	$	692,137	$	296,074
Revision of Previous Estimates		—		165,968
Liabilities Incurred or Acquired		515,199		510,271
Accretion of Discount on Asset Retirement Obligations		35,800		32,449
Liabilities Associated with Properties Sold		—		(312,625	)
Ending Asset Retirement Obligation	$	1,243,136	$	692,137

NOTE 10  INCOME TAXES

Deferred income tax assets and liabilities are determined based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. 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 June 30, 2014 and December 31, 2013, the Company maintained 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.

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NOTE 11 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 Vice President of Accounting and approved by the Chief Financial Officer. The valuation policies 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 June 30, 2014:

	Fair Value Measurements at June 30, 2014 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	$	—	$	—		$	(17,670,000	)
Commodity Derivatives – Current Liability (oil swaps)		—		(5,852,801	)		—
Total	$	—	$	(5,852,801	)	$	(17,670,000	)

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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, 2013:

	Fair Value Measurements at December 31, 2013 Using
	Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Warrant Liability – Long Term Liability	$	—	$	—		$	(15,703,000	)
Commodity Derivatives – Current Liability (oil swaps)		—		(921,401	)		—
Commodity Derivatives – Long Term Asset (oil swaps)		—		68,396			—
Total	$	—	$	(853,005	)	$	(15,703,000	)

Level 2 assets consist of commodity derivative assets and liabilities (see Note 12 – 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 warrant liability measured at fair value using Level 3 on a recurring basis is as follows (in thousands):

Balance, at January 1, 2013	$	—
Purchases, issuances, and settlements		(8,626,000	)
Change in Fair Value of Warrant Liability		(7,077,000	)
Balance, at December 31, 2013		(15,703,000	)
Change in Fair Value of Warrant Liability		(1,967,000	)
Balance, at June 30, 2014	$	(17,670,000	)

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 $1,771,000 and $642,000 for the three months ended June 30, 2014 and 2013, respectively, and $1,967,000 and $4,081,000 for the six months ended June 30, 2014 and 2013, respectively. The warrant revaluation expense 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 12 – 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.

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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 9 – Asset Retirement Obligation.

The Company’s non-derivative financial instruments include cash and cash equivalents, accounts receivable, accounts payable, the Convertible Notes and the Credit Facility. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximate fair value because of their immediate or short-term maturities. The book value of the Credit Facility approximates fair value because of its floating rate structure. The Company estimated the fair value of the Convertible Notes to be approximately $190.5 million at June 30, 2014 based on observed prices for the same or similar types of debt instruments. The Company has classified the valuations of the Convertible Notes and Credit Facility under Level 2 of the fair value hierarchy.

NOTE 12 DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT

Commodity

The Company utilizes oil 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.

The Company has a master netting agreement on each of the individual oil contracts. Therefore, the current asset and liability are netted on the 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 June 30, 2014, the associated volumes and the corresponding weighted average NYMEX reference price:

Settlement Period	Oil (Bbls)		Fixed Price Range
Oil Swaps
July 1, 2014 – December 31, 2014		61,330	$	90.00 – 93.00
July 1, 2014 – December 31, 2014		47,300		93.01 – 96.00
July 1, 2014 – December 31, 2014		503,970		96.01 – 99.00
July 1, 2014 – December 31, 2014		82,612		99.01 – 102.00
2014 Total/Average		695,212	$	96.70
January 1, 2015 – April 30, 2015		18,876	$	90.00 – 93.00
January 1, 2015 – April 30, 2015		93,100		93.01 – 96.00
January 1, 2015 – April 30, 2015		341,251		96.01 – 99.00
2015 Total/Average		453,227	$	96.24

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The following table sets forth a reconciliation of the changes in fair value of the Company’s commodity derivatives for the three and six months ended June 30, 2014 and 2013.

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Beginning fair value of commodity derivatives	$	(1,098,474	)	$	(799,610	)	$	(853,005	)	$	(181,248	)
Total gains (losses) on commodity derivatives		(6,663,083	)		665,337			(7,461,936	)		(102,267	)
Cash settlements paid on commodity derivatives		1,908,756			183,539			2,462,140			332,781
Ending fair value of commodity derivatives	$	(5,852,801	)	$	49,266		$	(5,852,801	)	$	49,266

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 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 5 – 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 June 30, 2014, using the following assumptions: a term of 1,381 trading days, exercise price of $5.77, a 15-day volume weighted average stock price of $7.22, volatility rate of 40%, and a risk-free interest rate of 2.5%. As of June 30, 2014, the fair value of the warrants was $17,670,000, 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.

NOTE 13 COMMITMENTS AND CONTINGENCIES

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

NOTE 14 SUBSEQUENT EVENTS

Acquisition and Divestiture

On August 1, 2014 the Company entered into a material definitive agreement to acquire approximately 31,500 net acres located in McKenzie, Billings and Dunn Counties of North Dakota from an unrelated third party. The total consideration expected to be paid by the Company is approximately $78.4 million in cash and the assignment of 4,175 net acres located in Williams County, North Dakota. Net daily production from the acquired acreage was approximately 400 Boe/day as of May 1, 2014, the effective date of the transaction. The Company did not have any production associated with the 4,175 net acres to be assigned as a part of the purchase price consideration. The agreement is subject to customary closing conditions and adjustments, including allocating all costs and revenue prior to and after the effective date. The transaction is expected to close in the third quarter of 2014.

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

The following discussion and analysis of our financial condition and results of operations should be read together with our financial statements appearing in this Form 10-Q.  This discussion contains forward-looking statements that involve risks and uncertainties because they are based on current expectations and relate to future events and future financial performance.  Our actual results may differ materially from those anticipated in these forward-looking statements as a result of many important factors, including those set forth in Part II, Item 1A of this Form 10-Q, in our Annual Report on Form 10-K for the year ended December 31, 2013 and in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2014 under the heading “Risk Factors”.

Overview

Emerald Oil, Inc., a Delaware corporation (“Emerald,” the “Company,” “we,” “us,” or “our”), is a Denver-based independent exploration and production company that is focused on acquiring acreage and developing wells in the Williston Basin of North Dakota and Montana. We believe the location, size and concentration of our acreage in our core project areas create an opportunity for us to achieve cost, recovery and production efficiencies through the large-scale development of our project inventory.

Our Williston Basin acreage is located primarily in McKenzie and Williams counties of North Dakota and Richland County of Montana. Our primary geologic targets are the Bakken Pool where our primary objectives are the dolomitic, sandy interval between the two Bakken Shales at an approximate vertical depth of 10,600 to 11,300 feet and the Three Forks that is present immediately below the lower Bakken Shale. We also target the Pronghorn Sand formation, located primarily in Billings and Stark counties of North Dakota and run along the Bakken shale pinch-out in the Southern Williston Basin. Our operations are in an area that we believe has high reservoir pressure and a high degree of thermal maturity, which is prospective for both the Middle Bakken and multiple benches within the Three Forks. We currently operate a three-rig drilling program.

Assets and Acreage Holdings

As of June 30, 2014, we had approximately 93,000 net acres in the Williston Basin. We operate approximately 70,000 net acres, or 75% of our total net acreage.

Our acreage holdings are comprised of the operating areas below:

· 57,000 net acres in the Low Rider area of McKenzie County, North Dakota;

· 4,000 net acres in the Easy Rider area of Williams County, North Dakota in the West Nesson area of the Williston Basin;

· 8,000 net acres in the Richland area of Richland County, Montana;

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

· 21,000 net acres in the Lewis & Clark area of McKenzie County, North Dakota south of the Low Rider area.

2014 Capital Development Plan

Our operated drilling program creates higher rate of return opportunities while allowing us to control the deployment of our capital development budget. We expect to fund the remainder of our current 2014 capital expenditure budget using cash on hand, cash flow from operations and borrowings under our revolving credit facility. We may consider funding growth opportunities beyond our current 2014 capital expenditure budget with future capital markets activity if we believe the transaction to be accretive to our stockholders.

Our future financial results will depend primarily on: (i) the ability to fully implement our exploration and development program, which is dependent on the availability of capital resources; (ii) the ability to continue to source and evaluate potential projects; (iii) the ability to discover commercial quantities of oil and natural gas; and (iv) the market price for oil and natural gas. 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. See Item 1A. Risk Factors.

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We added a third high specification drilling rig in March 2014 to accelerate development of our Williston Basin operated leasehold. For the 12-month period ending December 31, 2014, we plan to spend approximately $250.0 million to drill 25.2 net operated wells in the Williston Basin. We had incurred $127.4 million in drilling and completion costs in our operating well program through June 30, 2014. We had budgeted approximately $150.0 million in 2014 to increase our working interests in our core operated areas along with continuing to grow our overall operated acreage position in the Williston Basin. The land acquisition budget will be increased to $200 million for 2014 following the acquisition of approximately 31,500 net acres in North Dakota expected to close in the third quarter of 2014 as described under Item 2. - Recent Developments – Acreage Acquisitions and Divestitures below. We had incurred $95.2 million toward our acquisition budget through June 30, 2014 and $173.6 million pro forma for the pending acquisition.

The Low Rider area, which is our core operated area, consists of approximately 57,000 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 June 30, 2014 was approximately 75%, and we continue to work toward increasing our average working interest in the area. As of June 30, 2014, we had approximately 28 gross (20.91 net) producing operated wells in the Williston Basin, excluding producing wells included in acreage acquisitions in 2013 and the first half of 2014 developed outside of our operated well program. We had 12 gross (8.57 net) operated Bakken and Three Forks wells that were in the process of being drilled, awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation as of June 30, 2014. As of June 30, 2014, we were running a two-rig horizontal development program in the Low Rider area. Our third rig commenced operations during the second quarter of 2014 targeting the Easy Rider and Pronghorn Sand operating areas.

Recent Developments

Acreage Acquisitions and Divestitures

On August 1, 2014 we entered into a material definitive agreement to acquire approximately 31,500 net acres located in McKenzie, Billings and Dunn Counties of North Dakota from an unrelated third party. The total consideration expected to be paid is approximately $78.4 million in cash and the assignment of approximately 4,175 net acres located in Williams County, North Dakota. Net daily production from the acquired acreage was approximately 400 Boe/day as of May 1, 2014, the effective date of the transaction. The acquisition will increase our interest in 12 existing operated DSUs in our Low Rider area, add six potentially operated DSUs in our Low Rider area, increase our working interest in one existing operated DSU in our Lewis & Clark area and add 17 potentially operated DSUs in our Lewis & Clark area while divesting our acreage position in our Easy Rider area. We did not have any production associated with the 4,175 acres to be assigned as part of the purchase price consideration. The agreement is subject to customary closing conditions and adjustments, including allocating all costs and revenues prior to and after the effective date. The transaction is expected to close in the third quarter of 2014.

Finance Update

On May 1, 2014, we amended and restated our senior secured revolving credit facility (“Credit Facility”) with Wells Fargo Bank N.A. as administrative agent for the lenders party to the credit agreement. The Credit Facility provides a maximum commitment of $400 million with an initial borrowing base of $100 million, which represented an increase of $25 million from the last borrowing base determination. The maturity date of the Credit Facility is September 30, 2018, and upon such date, any amounts outstanding under the Credit Facility are due and payable in full. 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. In connection with the closing of the acquisition described in Acreage Acquisitions and Divestitures above, we expect our borrowing base to be increased to $200 million.

The Credit Facility allows us to hedge up to 60% of proved reserves for the first 24 months and 80% of projected production from proved developed producing reserves from 24 months up to 60 months later provided that in no event shall the aggregate amount of hedges exceed 100% of actual production in the current period.

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Productive Wells

The following table summarizes gross and net productive operated and non-operated oil wells at June 30, 2014 and June 30, 2013. A net well represents our fractional working ownership interest of a gross well. The following table does not include 12 gross (8.57 net) operated Bakken and Three Forks wells and 4 gross (0.45 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 June 30, 2014, and it does not include 4 gross (2.62 net) operated Bakken and Three Forks wells and 23 gross (0.33 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 June 30, 2013.

	June 30,
	2014				2013
	Gross		Net		Gross		Net
North Dakota Bakken and Three Forks – operated		28		20.91		4		2.84
North Dakota acquired production – operated (1)		21		15.02		—		—
North Dakota Bakken and Three Forks – non-operated		16		2.13		189		7.50
Montana Bakken and Three Forks – non-operated		—		—		26		2.18
Total		65		38.06		219		12.52

(1) 11 gross (7.85 net) vertical wells relate to producing properties included within an acreage acquisition completed on August 2, 2013. The wells are producing from the Birdbear, Duperow and Red River formations. 10 gross (7.17 net) wells relate to producing properties included within an acquisition completed on February 13, 2014 and the wells are producing from the Bakken formation. Operatorship was transferred to us upon closing both acquisitions.

Results of Operations

Comparison of the Three Months Ended June 30, 2014 with the Three Months Ended June 30, 2013

	Three Months Ended June 30,
	2014			2013
REVENUES
Oil Sales	$	30,288,128		$	10,340,742
Natural Gas Sales		966,280			234,076
Net Gains (Losses) on Commodity Derivatives		(6,663,083	)		665,337
		24,591,325			11,240,155
OPERATING EXPENSES
Production Expenses		3,897,482			1,596,353
Production Taxes		3,400,874			1,048,541
General and Administrative Expenses		7,633,559			5,979,739
Depletion of Oil and Natural Gas Properties		8,600,878			3,584,803
Depreciation and Amortization		81,497			31,039
Accretion of Discount on Asset Retirement Obligations		20,080			7,850
Total Operating Expenses		23,634,370			12,248,325
INCOME (LOSS) FROM OPERATIONS		956,955			(1,008,170	)
OTHER EXPENSE, NET		(2,907,006	)		(714,964	)
LOSS BEFORE INCOME TAXES		(1,950,051	)		(1,723,134	)
INCOME TAX EXPENSE		—			—
NET LOSS		(1,950,051	)		(1,723,134
Less: Preferred Stock Dividends and Deemed Dividends		—			(5,665,670	)
NET INCOME LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(1,950,051	)	$	(7,338,804	)

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

	Three Months Ended June 30,
	2014			2013
Net Oil and Natural Gas Revenues:
Oil	$	30,288,128		$	10,340,742
Natural Gas and Other Liquids		966,280			234,076
Total Oil and Natural Gas Sales		31,254,408			10,574,818
Net Gains (Losses) on Commodity Derivatives		(6,663,083	)		665,337
Total Revenues		24,591,325			11,240,155
Oil Derivative Net Cash Settlements Paid		1,908,756			183,539
Net Production:
Oil (Bbl)		324,617			119,366
Natural Gas and Other Liquids (Mcf)		94,217			44,500
Barrel of Oil Equivalent (Boe)		340,320			126,783
Average Sales Prices:
Oil (per Bbl)	$	93.30		$	86.63
Effect of Settled Oil Derivatives on Average Price (per Bbl)		(5.88	)		(1.54	)
Oil Net of Settled Derivatives (per Bbl)	$	87.42		$	85.09
Natural Gas and Other Liquids (per Mcf)	$	10.26		$	5.26
Barrel of Oil Equivalent with Net Cash Settlements Paid on Commodity Derivatives (per Boe)	$	86.23		$	81.96

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Production costs incurred, presented on a per Boe basis, for the three months ended June 30, 2014 and 2013 are summarized in the following table:

	Three Months Ended June 30,
	2014		2013
Costs and Expenses Per Boe of Production:
Production Expenses	$	11.45	$	12.59
Production Taxes		9.99		8.27
G&A Expenses (Excluding Non-Cash Share-Based Compensation)		13.66		38.82
Non-Cash Shared-Based Compensation		8.77		8.34
Depletion of Oil and Natural Gas Properties		25.27		28.28
Depreciation and Amortization		0.24		0.24
Accretion of Discount on Asset Retirement Obligation		0.06		0.06

Revenues

Revenues from sales of oil and natural gas were $31.3 million for the second quarter of 2014 compared to $10.6 million for the second quarter of 2013. Our total production volumes on a Boe basis increased 168% from 126,783 Boe to 340,320 Boe in the second quarter of 2014 as compared to the second quarter of 2013. Production primarily increased due to the addition of 18.29 net productive operated Bakken/Three Forks wells since July 1, 2013, offset by the sale of 9.13 net productive non-operated wells in the Williston Basin in 2013. During the second quarter of 2014, we realized an $87.42 average price per Bbl of oil (including settled derivatives) compared to an $85.09 average price per Bbl of oil during the second quarter of 2013.

Net Gains (Losses) on Commodity Derivatives

Net losses on commodity derivatives were $6,663,083 during the second quarter of 2014 compared to a gain of $665,337 in the second quarter of 2013. Net cash settlements paid on commodity derivatives were $1,908,756 in the second quarter of 2014 compared to $183,539 in the second quarter of 2013. During the second quarter of 2014, we added swaps contracts for 852,113 Bbls of oil at an average fixed price of $97.08 NYMEX West Texas Intermediate. 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 unsettled 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 June 30, 2014 and June 30, 2013, all of our derivative contracts were recorded at their fair value, which was a net liability of $5,852,801, and a net asset of $49,266, respectively.

Production Expenses

Production expenses were $3,897,482 for the second quarter of 2014 compared to $1,596,353 for the second quarter of 2013. We experience increases in production expenses as we add new wells and maintain production from existing properties. On a per unit basis, production expenses decreased from $12.59 per Boe in the second quarter of 2013 compared to $11.45 per Boe for the second quarter of 2014. This decrease on a per unit basis compared to 2013 was primarily due to efficiencies gained as we further developed wells and associated production infrastructure in the Low Rider area. The use of power generators and associated fuel costs, as well as the disposal of produced water, are large cost drivers in our Williston Basin wells.

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Production Taxes

Production taxes were $3,400,874 for the second quarter of 2014 compared to $1,048,541 for the second quarter of 2013. We pay production taxes based on realized oil and natural gas sales. Our average production tax rates were 10.9% for the second quarter of 2014 compared to 9.9% for the second quarter of 2013. 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%. The 2014 average production tax rate was higher than 2013 due to expirations of production tax holidays during the year and the disposition of non-operated wells in jurisdictions that had lower initial tax rates.

General and Administrative Expense

General and administrative expenses were $7,633,559 during the second quarter of 2014 compared to $5,979,739 during the second quarter of 2013. The increase of $1,653,820 was due to increases in personnel and infrastructure to accelerate our operated well program in the Williston Basin. Specifically, during the second quarter of 2014 an increase of $1,207,767 was related to share-based compensation expense and employee cash compensation and related expenses, an increase of $278,654 related to office rent, and an increase of $175,513 related to liability insurance.

Depletion Expense

Our depletion expense is driven by many factors, including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. Depletion expense was $8,600,878 during the second quarter of 2014 compared to $3,584,803 during the second quarter of 2013. On a per-unit basis, depletion expense was $25.27 per Boe during the second quarter of 2014 compared to $28.28 per Boe during the second quarter of 2013. 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 our petroleum engineers. This increase in depletion expense during the second quarter of 2014 was due primarily to the addition of 18.29 net productive operated Bakken/Three Forks wells since July 1, 2013, offset by the sale of 9.13 net productive non-operated wells in the Williston Basin in 2013.

Other Expense, Net

Other expense, net was $2,907,006 for the second quarter of 2014 compared to $714,964 for the second quarter of 2013. We recognized a loss of $1,771,000 on the warrant liability for the second quarter of 2014 compared to an unrealized loss of $642,000 for the second quarter of 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 $1,136,377 for the second quarter of 2014, compared to $75,186 for the second quarter of 2013. This increase in interest expense during the second quarter of 2014 was primarily related to the Convertible Notes issued in March 2014 and outstanding at June 30, 2014.

Net Loss Attributable to Common Stockholders

We had net loss attributable to common stockholders of $1,950,051 for the second quarter of 2014 compared to $7,388,804 for the second quarter of 2013 (representing $(0.03) and $(0.23) per share-basic, respectively). The change in net loss attributable to common stockholders in our period-over-period results was driven by increased revenue and production from our oil and natural gas properties, partially offset by higher general and administrative expenses, commodity derivative losses and warrant revaluation expense.

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Comparison of the Six Months Ended June 30, 2014 with the Six Months Ended June 30, 2013

	Six Months Ended June 30,
	2014			2013
REVENUES
Oil Sales	$	48,722,936		$	18,334,644
Natural Gas Sales		1,600,344			457,155
Net Losses on Commodity Derivatives		(7,461,936	)		(102,267	)
		42,861,344			18,689,532
OPERATING EXPENSES
Production Expenses		6,514,726			2,635,885
Production Taxes		5,489,610			1,750,397
General and Administrative Expenses		16,125,563			11,368,552
Depletion of Oil and Natural Gas Properties		14,878,110			6,741,781
Depreciation and Amortization		147,257			54,034
Accretion of Discount on Asset Retirement Obligations		35,800			14,062
Total Operating Expenses		43,191,066			22,564,711
LOSS FROM OPERATIONS		(329,722	)		(3,875,179	)
OTHER EXPENSE, NET		(3,271,416	)		(4,332,778	)
LOSS BEFORE INCOME TAXES		(3,601,138	)		(8,207,957	)
INCOME TAX EXPENSE		—			—
NET LOSS		(3,601,138	)		(8,207,957	)
Less: Preferred Stock Dividends and Deemed Dividends		—			(6,282,108	)
NET INCOME LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(3,601,138	)	$	(14,490,065	)

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

	Six Months Ended June 30,
	2014			2013
Net Oil and Natural Gas Revenues:
Oil	$	48,722,936		$	18,334,644
Natural Gas and Other Liquids		1,600,344			457,155
Total Oil and Natural Gas Sales		50,323,280			18,791,799
Net Losses on Commodity Derivatives		(7,461,936	)		(102,267	)
Total Revenues		42,861,344			18,689,532
Oil Derivative Net Cash Settlements Paid		2,462,140			332,781
Net Production:
Oil (Bbl)		538,595			208,478
Natural Gas and Other Liquids (Mcf)		165,778			84,695
Barrel of Oil Equivalent (Boe)		566,225			222,594
Average Sales Prices:
Oil (per Bbl)	$	90.46		$	87.95
Effect of Settled Oil Derivatives on Average Price (per Bbl)		(4.57	)		(1.60	)
Oil Net of Settled Derivatives (per Bbl)	$	85.89		$	86.35
Natural Gas and Other Liquids (per Mcf)	$	9.65		$	5.40
Barrel of Oil Equivalent with Net Cash Settlements Paid on Commodity Derivatives (per Boe)	$	84.53		$	82.93

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Production costs incurred, presented on a per Boe basis, for the six months ended June 30, 2014 and 2013 are summarized in the following table:

	Six Months Ended June 30,
	2014		2013
Costs and Expenses Per Boe of Production:
Production Expenses	$	11.51	$	11.84
Production Taxes		9.70		7.86
G&A Expenses (Excluding Non-Cash Share-Based Compensation)		16.68		40.44
Non-Cash Shared-Based Compensation		11.80		10.63
Depletion of Oil and Natural Gas Properties		26.28		30.29
Depreciation and Amortization		0.26		0.24
Accretion of Discount on Asset Retirement Obligation		0.06		0.06

Revenues

Revenues from sales of oil and natural gas were $50.3 million for the first half of 2014 compared to $18.8 million for the first half of 2013. Our total production volumes on a Boe basis increased 154% from 222,594 Boe to 566,225 Boe in the first half of 2014 as compared to the first half of 2013. Production primarily increased due to the addition of 18.29 net productive operated Bakken/Three Forks wells since July 1, 2013, offset by the sale of 9.13 net productive non-operated wells in the Williston Basin in 2013. During the first half of 2014, we realized an $85.89 average price per Bbl of oil (including settled derivatives) compared to an $86.35 average price per Bbl of oil during the first half of 2013.

Net Losses on Commodity Derivatives

Net losses on commodity derivatives were $7,461,936 during the first half of 2014 compared to $102,267 in the first half of 2013. Net cash settlements paid on commodity derivatives were $2,462,140 in the first half of 2014 compared to $332,781 in the first half of 2013. During the first half of 2014, we added swaps contracts for 1,002,833 Bbls of oil at an average fixed price of $97.12 NYMEX West Texas Intermediate. 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 unsettled 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 June 30, 2014 and June 30, 2013, all of our derivative contracts were recorded at their fair value, which was a net liability of $5,852,801 and a net asset of $49,266, respectively.

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Production Expenses

Production expenses were $6,514,726 for the first half of 2014 compared to $2,635,885 for the first half of 2013. We experience increases in production expenses as we add new wells and maintain production from existing properties. On a per unit basis, production expenses decreased from $11.84 per Boe in the first half of 2013 compared to $11.51 per Boe for the first half of 2014. This decrease on a per unit basis compared to 2013 was primarily due to efficiencies gained as we further developed wells and associated production infrastructure in the Low Rider area. The use of power generators and associated fuel costs, as well as the disposal of produced water, are large cost drivers in our Williston Basin wells.

Production Taxes

Production taxes were $5,489,610 for the first half of 2014 compared to $1,750,397 for the first half of 2013. We pay production taxes based on realized oil and natural gas sales. Our average production tax rates were 10.9% for the first half of 2014 compared to 9.3% for the first half of 2013. 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%. The 2014 average production tax rate was higher than 2013 due to expirations of production tax holidays during the year and the disposition of non-operated wells in jurisdictions that had lower initial tax rates.

General and Administrative Expense

General and administrative expenses were $16,125,563 during the first half of 2014 compared to $11,368,552 during the first half of 2013. The increase of $4,757,011 was due to increases in personnel and infrastructure to accelerate our operated well program in the Williston Basin. Specifically, during the first half of 2014 an increase of $4,708,016 was related to share-based compensation expense and employee cash compensation and related expenses, an increase of $317,456 related to office rent, partially offset by a decrease of $193,336 in professional and legal expense.

Depletion Expense

Our depletion expense is driven by many factors, including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. Depletion expense was $14,878,110 during the first half of 2014 compared to $6,741,781 during the first half of 2013. On a per-unit basis, depletion expense was $26.28 per Boe during the first half of 2014 compared to $30.29 per Boe during the first half of 2013. 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 our petroleum engineers. This increase in depletion expense during the first half of 2014 was due primarily to the addition of 18.29 net productive operated Bakken/Three Forks wells since July 1, 2013, offset by the sale of 9.13 net productive non-operated wells in the Williston Basin in 2013.

Other Expense, Net

Other expense, net was $3,271,416 for the first half of 2014 compared to $4,332,778 for the first half of 2013. We recognized a loss of $1,967,000 on the warrant liability for the first half of 2014 compared to an unrealized loss of $4,081,000 for the first half of 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 $1,308,463 for the first half of 2014, compared to $254,676 for the first half of 2013. This increase in interest expense during the second quarter of 2014 was primarily related to the Convertible Notes issued in March 2014 and outstanding at June 30, 2014.

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Net Loss Attributable to Common Stockholders

We had net loss attributable to common stockholders of $3,601,138 for the first half of 2014 compared to $14,490,065 for the first half of 2013 (representing $(0.05) and $(0.50) per share-basic, respectively). The change in net loss attributable to common stockholders in our period-over-period results was driven by increased revenue and production from our oil and natural gas properties, partially offset by higher general and administrative expenses and increased commodity derivative losses.

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 our 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 June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Net income (loss)	$	(1,950,051	)	$	(1,723,134	)	$	(3,601,138	)	$	(8,207,957	)
Less: Preferred stock dividends and deemed dividends		—			(5,665,670	)		—			(6,282,108	)
Net income (loss) attributable to common stockholders		(1,950,051	)		(7,388,804	)		(3,601,138	)		(14,490,065	)
Add:       Interest expense		1,136,377			75,186			1,308,463			254,676
Accretion of discount on asset retirement obligations		20,080			7,850			35,800			14,062
Depletion, depreciation and amortization		8,682,375			3,615,842			15,025,367			6,795,815
Stock-based compensation		2,983,580			1,057,811			6,678,883			2,365,797
Warrant revaluation expense		1,771,000			642,000			1,967,000			4,081,000
Preferred stock dividends		—			1,201,370			—			1,817,808
Preferred stock redemption premium		—			1,875,000			—			1,875,000
Accretion of preferred stock issuance discount		—			2,589,300			—			2,589,300
Net losses on commodity derivatives		6,663,083			—			7,461,936			102,267
Less:      Net cash settlements paid on commodity derivatives		(1,908,756	)		(183,539	)		(2,462,140	)		(332,781	)
Net gains on commodity derivatives		—			(665,337	)		—			—
Adjusted EBITDA	$	17,397,688		$	2,826,679		$	26,414,171		$	5,072,879

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Liquidity and Capital Resources

Liquidity is a measure of a company’s ability to meet potential cash requirements. We have historically met our capital requirements through the issuance of common and preferred stock, debt securities and by short-term and long-term borrowings. In the future, we anticipate we will be able to provide the necessary liquidity from our cash on hand, cash flow from operations 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 June 30, 2014:

Current assets	$	188,055,763
Current liabilities		114,231,841
Working capital	$	73,823,922

Private Placement

On March 24, 2014, we completed a private placement of $172.5 million in aggregate principal amount of 2.0% Convertible Notes, and entered into an indenture governing the Convertible Notes, with U.S. Bank National Association, as trustee. The Convertible Notes accrue interest at a rate of 2.00% per year, payable semiannually in arrears on April 1 and October 1 of each year, beginning on October 1, 2014. The Convertible Notes mature on April 1, 2019. The Convertible Notes are our unsecured senior obligations and are equal in right of payment to our existing and future senior indebtedness.

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

Credit Facility

On November 20, 2012, we entered into a senior secured revolving credit facility (the “Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent (“Wells Fargo”), and the lenders party thereto. On May 1, 2014, we amended and restated our Credit Facility with Wells Fargo Bank as administrative agent for the lenders party thereto. The Credit Facility is a senior secured reserve-based revolving credit facility with a maximum commitment of $400 million. As of June 30, 2014, the Credit Facility was undrawn and had a borrowing base of $100.0 million.

Amounts borrowed under the Credit Facility will mature on September 30, 2018, and upon such date, any amounts outstanding under the Credit Facility are due and payable in full. 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 our option, based on either the Alternate Base Rate (as defined under the terms of the Credit Facility) 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 our option, at one-, two-, three-, six- (or in some cases nine- or twelve-) month intervals. We also pay a commitment fee ranging from 0.375% to 0.5%, depending on the percentage of the borrowing base utilized. As of June 30, 2014, the annual interest rate on the Credit Facility was 0.375% which is the minimum commitment fee, as no funds were drawn against the Credit Facility.

A portion of the Credit 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 June 30, 2014, we have not obtained any letters of credit under the existing facility.

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Each of our subsidiaries is a guarantor under the Credit 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 Facility 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 Facility 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 total debt to EBITDA for the preceding four fiscal quarters of no more than 3.50 to 1.00. For any fiscal quarter ending in calendar year 2014, total debt is reduced by cash equivalents less $10,000,000 for purposes of calculating the total debt to EBITDA ratio.

The Credit Facility allows us to hedge up to 60% of proved reserves for the first 24 months and 80% of projected production from proved developed producing reserves from 24 months up to 60 months later provided that in no event shall the aggregate amount of hedges exceed 100% of actual production in the current period.

The principal balance amount on the Credit Facility was undrawn as of June 30, 2014 and December 31, 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, 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. However, there can be no assurance that any additional capital will be available to us on favorable terms or at all. 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.

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 June 30, 2014 were $134,171,667, compared to $144,255,438 as of December 31, 2013. The decrease in our cash balance was primarily attributable to acquisitions and development of oil and natural gas properties, offset by the Convertible Notes offering completed during the first quarter of 2014.

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Net Cash Provided By Operating Activities

Net cash provided by operating activities was $19,894,739 for the first half of 2014 compared to $2,216,299 for the first half of 2013. The change in the net cash provided by operating activities is primarily attributable to higher production revenue during 2014, partially 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 $196,457,501 for the first half of 2014 compared to $40,682,547 for the first half of 2013. 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.

Net Cash Provided By Financing Activities

Net cash provided by financing activities was $166,478,991 for the first half of 2014 compared to $100,964,887 for the first half of 2013. The change in net cash provided by financing activities for the first half of 2014 is primarily attributable to proceeds from the Convertible Note offering completed on March 24, 2014. The change in net cash provided by financing activities for the first half of 2013 is primarily attributable to proceeds from the preferred stock issuance completed on February 19, 2013, offset by repayment of borrowings under the Credit Facility and payment of preferred stock dividends.

Off-Balance Sheet Arrangements

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

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, 2013, 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 six-month period ended June 30, 2014.

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 Annual Report on Form 10-K for the year ended December 31, 2013, in our Quarterly Report on Form 10-Q for the three months ended March 31, 2014 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:

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

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

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

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

· our ability to retain key members of management; 

· volatility in commodity prices for oil and natural gas;

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

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

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

· interest payment requirements of our debt obligations;

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

· substantial impairment write-downs;

· our ability to replace oil and natural gas reserves;

· environmental risks;

· drilling and operating risks;

· exploration and development risks;

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

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

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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 six months ended June 30, 2014 and 2013 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.

As of June 30, 2014, our Credit Facility allowed 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, was not greater than 60% of the reasonably anticipated projected production from proved reserves. We use 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 June 30, 2014 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 $1,156,000. 

The following table reflects open commodity swap contracts as of June 30, 2014, the associated volumes and the corresponding weighted average NYMEX reference price:

Settlement Period	Oil (Bbls)		Fixed Price Range
Oil Swaps
July 1, 2014 – December 31, 2014		61,330	$	90.00 – 93.00
July 1, 2014 – December 31, 2014		47,300		93.01 – 96.00
July 1, 2014 – December 31, 2014		503,970		96.01 – 99.00
July 1, 2014 – December 31, 2014		82,612		99.01 – 102.00
2014 Total/Average		695,212	$	96.70
January 1, 2015 – April 30, 2015		18,876	$	90.00 – 93.00
January 1, 2015 – April 30, 2015		93,100		93.01 – 96.00
January 1, 2015 – April 30, 2015		341,251		96.01 – 99.00
2015 Total/Average		453,227	$	96.24

Interest Rate Risk

As of June 30, 2014, we had no outstanding borrowings under our Credit Facility. Our Credit Facility subjects us to interest rate risk on borrowings. Our 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.

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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 June 30, 2014. Based upon that evaluation and subject to the foregoing, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective to accomplish their objectives.

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

There have been no changes in our internal control over financial reporting that occurred during our most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We may be 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 matters and proceedings. However, we believe that all such litigation matters and proceedings 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, 2013, as filed with the SEC on March 12, 2014 and Item 1A. – “Risk Factors” of our Quarterly Reports on Form 10-Q for the three months ended March 31, 2014, as filed with the SEC on May 5, 2014, 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 June 30, 2014, there have been no material changes to the risk factors disclosed in our most recent Annual Report on Form 10-K and our Quarterly Report on Form 10-Q for the three months ended March 31, 2014, 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.

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Requirements to reduce natural gas flaring may have an adverse effect on our operations.

All of our current oil and natural gas production is presently located in the Williston Basin of North Dakota and Montana. Lack of infrastructure to adequately gather and process the natural gas that is produced primarily as a byproduct from our oil wells, as well as bottlenecks in the current natural gas gathering network, in the Williston Basin, have resulted in much of the natural gas that is produced being flared instead of processed and sold. The North Dakota Industrial Commission (NDIC), the chief energy regulator in North Dakota, recently issued an order to reduce the volume of natural gas flared from oil wells in the Williston Basin. The NDIC’s objectives are to capture 74% of the natural gas by the fourth quarter 2014, 77% by the first quarter 2015, 85% by the first quarter 2016, and 90% (potentially 95%) by the fourth quarter 2020. In addition, the NDIC is requiring well operators to develop gas capture plans that describe how much natural gas is expected to be produced, how the natural gas will be delivered to a processor and where the natural gas will be processed. Production caps or penalties will be imposed on certain wells that cannot meet the capture goals. These capture requirements, and any similar future obligations in North Dakota or our other locations, may increase our operational costs or restrict our production.

ITEM 2. UNREGISTERED SALES OR EQUITY SECURITIES AND USE OF PROCEEDS

The following table summarizes repurchases of our common stock during the three months ended June 30, 2014.

Period	Total Number of Shares Purchased (1)		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
4/1/2014-4/30/2014		—	$	—		—		—
5/1/2014-5/31/2014		—		—		—		—
6/1/2014-6/30/2014		104,051		6.69		—		—
Total		104,051	$	6.69		—		—

(1) Stock repurchases during the period related to common stock received by us from employees for the payment of withholding taxes due on shares of restricted common stock issued under our equity compensation plan.

ITEM 5. OTHER INFORMATION

On August 1, 2014, we entered into a material definitive agreement to acquire approximately 31,500 net acres located in McKenzie, Billings and Dunn Counties of North Dakota from an unrelated third party. The total consideration paid is expected to be approximately $78.4 million in cash and the assignment of 4,175 net acres located in Williams County, North Dakota. Net daily production from the acquired acreage was approximately 400 Boe/day as of May 1, 2014, the effective date of the transaction. The acquisition will increase interest in 12 existing operated DSUs in our Low Rider area, add six potentially operated DSUs in our Low Rider area, increase our working interest in one existing operated DSU in our Lewis & Clark area and add 17 potentially operated DSUs in our Lewis & Clark area, while divesting our acreage position in our Easy Rider area. We did not have any production associated with the 4,175 acres to be assigned as part of the purchase price consideration. The agreement is subject to customary closing conditions and purchase price adjustments, including allocating all costs and revenues prior to and after the effective date. The transaction is expected to close in the third quarter of 2014. In connection with the closing of the acquisition, we expect our borrowing base to be increased to $200 million.

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 Agreement and Plan of Merger, dated as of June 11, 2014, between Emerald Oil, Inc., a Montana corporation, and Emerald Oil, Inc., a Delaware corporation (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on June 12, 2014, and incorporated herein by reference)

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3.1 Certificate of Incorporation of Emerald Oil, Inc., a Delaware corporation (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 12, 2014, and incorporated herein by reference)

3.2 Bylaws of Emerald Oil, Inc., a Delaware corporation (filed as Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on June 12, 2014, and incorporated herein by reference)

3.3 Certificate of Ownership and Merger of Emerald Oil, Inc., a Montana corporation, with and into Emerald Oil, Inc., a Delaware corporation (filed as Exhibit 3.3 to the Company’s Current Report on Form 8-K filed on June 12, 2014, and incorporated herein by reference)

3.4 Articles of Merger of Emerald Oil, Inc., a Montana corporation, with and into Emerald Oil, Inc., a Delaware corporation (filed as Exhibit 3.4 to the Company’s Current Report on Form 8-K filed on June 12, 2014, and incorporated herein by reference)

4.1 Form of Stock Certificate of Emerald Oil, Inc., a Delaware corporation (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on June 12, 2014, and incorporated herein by reference)

10.1 Amended and Restated Credit Agreement, dated as of May 1, 2014, among Emerald Oil, Inc., Wells Fargo Bank, N.A., as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q filed on May 5, 2014, and incorporated herein by reference)

10.2* Purchase and Sale Agreement, dated as of August 1, 2014, between Emerald Oil, Inc. Emerald WB LLC, Liberty Resources Management Company, LLC, Liberty Resources Bakken Operating, LLC, and Liberty Resources II, LLC

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 pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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

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.

36

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: August 4, 2014	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)

37

EX-10.2

Exhibit 10.2

Execution Version

PURCHASE AND SALE AGREEMENT

BY AND BETWEEN

LIBERTY RESOURCES MANAGEMENT COMPANY, LLC

LIBERTY RESOURCES BAKKEN OPERATING, LLC

(Liberty)

AND

EMERALD OIL, INC.

EMERALD WB LLC

(Emerald)

AND

LIBERTY RESOURCES II, LLC

(Guarantor)

Dated August 1, 2014

TABLE OF CONTENTS

		Page
ARTICLE 1 DEFINITIONS AND REFERENCES		1
1.1	Certain Defined Terms	1
1.2	References and Construction	10
ARTICLE 2 PURCHASE AND SALE		11
2.1	Purchase and Sale	11
2.2	Consideration	11
2.3	Allocation of the Purchase Price	11
2.4	Adjustments to Purchase Price and Preliminary Settlement Statement	13
2.5	Proration of Costs and Revenues	15
2.6	Escrow Amount	16
ARTICLE 3 Due Diligence Review		16
3.1	Due Diligence Review	16
3.2	Access to Transferor Records	16
3.3	Access to the Transferor Assets	17
ARTICLE 4 TITLE MATTERS		18
4.1	Transferor’s Title	18
4.2	Purchase Price Adjustment Procedures	20
4.3	Title Dispute Resolution	24
4.4	Preferential Rights and Consents	25
ARTICLE 5 ENVIRONMENtAL MATTERS		26
5.1	Exclusive Remedy	26
5.2	Environmental Defect Notice	26
5.3	Remedies for Environmental Defects	26
5.4	Environmental Threshold; Deductible	27
5.5	Environmental Dispute Resolution	27
5.6	Transfer of Burgundy Wellbore Interests	28
ARTICLE 6 LIBERTY’S REPRESENTATIONS AND WARRANTIES		29
6.1	Organization and Standing	29
6.2	Power	29
6.3	Authorization and Enforceability	30
6.4	Liability for Brokers’ Fees	30
6.5	Litigation	30
6.6	Material Agreements	30
6.7	Capital Projects	30

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TABLE OF CONTENTS
(continued)

		Page
6.8	Taxes	31
6.9	Audits	31
6.10	Judgments	31
6.11	Compliance with Law And Government Authorizations	31
6.12	Lease Status/Rentals/Royalties	31
6.13	Well Status	31
6.14	Calls on Production	32
6.15	Imbalances	32
6.16	No Other Representations or Warranties; Disclosed Materials	32
6.17	Disclaimer	32
6.18	Liberty’s Evaluation	33
ARTICLE 7 EMERALD’S REPRESENTATIONS AND WARRANTIES		33
7.1	Organization and Standing	34
7.2	Power	34
7.3	Authorization and Enforceability	34
7.4	Liability for Brokers’ Fees	34
7.5	Litigation	34
7.6	Financial Resources	34
7.7	Material Agreements	35
7.8	Capital Projects	35
7.9	Taxes	35
7.10	Audits	35
7.11	Judgments	35
7.12	Compliance with Law And Government Authorizations	36
7.13	Lease Status/Rentals/Royalties	36
7.14	Well Status	36
7.15	Calls on Production	36
7.16	Imbalances	36
7.17	No Other Representations or Warranties; Disclosed Materials	37
7.18	Disclaimer	37
7.19	Emerald’s Evaluation	38
ARTICLE 8 COVENANTS AND AGREEMENTS		38
8.1	Covenants and Agreements of Transferor	38
8.2	Covenants and Agreements of Transferee	39
8.3	Covenants and Agreements of the Parties	40
ARTICLE 9 TAX MATTERS		41
9.1	Production Tax Liability	41

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TABLE OF CONTENTS
(continued)

		Page
9.2	Transfer Taxes	41
9.3	Tax Reports and Returns	42
9.4	Tax Cooperation	42
ARTICLE 10 CONDITIONS PRECEDENT TO CLOSING		42
10.1	Liberty’s Conditions	42
10.2	Emerald’s Conditions	42
ARTICLE 11 RIGHT OF TERMINATION		43
11.1	Termination	43
11.2	Liabilities Upon Termination	43
ARTICLE 12 CLOSING		44
12.1	Date of Closing	44
12.2	Place of Closing	44
12.3	Closing Obligations	44
ARTICLE 13 POST-CLOSING OBLIGATIONS		45
13.1	Post-Closing Adjustments	45
13.2	Records	46
13.3	Further Assurances	46
13.4	Successor Operator	46
ARTICLE 14 INDEMNIFICATION		46
14.1	Emerald’s Assumption of Liabilities and Obligations	46
14.2	Liberty’s Assumption of Liabilities and Obligations	47
14.3	Retained Obligations	47
14.4	Indemnification	47
14.5	Procedure	49
14.6	Survival of Warranties, Representations and Covenants	50
14.7	Reservation as to Non-Parties	51
14.8	Reductions in Losses	51
14.9	Waiver	51
ARTICLE 15 MISCELLANEOUS		51
15.1	Exhibits and Schedules	51
15.2	Expenses	51
15.3	Notices	51

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TABLE OF CONTENTS
(continued)

		Page
15.4	Amendments	52
15.5	Assignment	53
15.6	Headings	53
15.7	Counterparts/Fax Signatures	53
15.8	Governing Law	53
15.9	Entire Agreement	53
15.10	Binding Effect	53
15.11	No Third-Party Beneficiaries	53
15.12	No Vicarious Liability	53
15.13	Dispute Resolution and Arbitration	54
15.14	Publicity	54
15.15	Severability	55
15.16	Liberty Resources Guaranty	55

-iv-

Defined Terms	Section Reference
Affiliate	1.1
Aggregate Environmental Deductible	5.4
Aggregate Title Deductible	4.2(e)
Agreement	Preamble
Assets	1.1
Burgundy Liabilities	5.6(a)
Burgundy Property Expenses	1.1
Burgundy Remediation Costs	5.6(d)
Burgundy Wellbore Interests	5.6(a)
Business Day	1.1
Cap	14.4(c)
Casualty Loss	8.3(b)
Claim	14.5(b)
Claim Notice	14.5(a)
Closing	12.1
Closing Amount	2.2(c)
Closing Date	12.1
Code	1.1
Condition	1.1
Deductible	14.4(c)
Defect Notice Date	3.1
Defensible Title	4.1(a)
Dispute	1.1
Due Diligence Review	3.1
Due Diligence Period	3.1
Effective Time	1.1
Emerald	Preamble
Emerald Allocated Value	2.3(a)
Emerald Assets	1.1
Emerald Assets Preliminary Adjusted Purchase Price	2.4
Emerald Assets Preliminary Settlement Statement	2.4
Emerald Assets Purchase Price	2.2(b)
Emerald Assignment	12.3(b)
Emerald Assumed Liabilities	14.1
Emerald Capital Expenditures	7.8
Emerald Contracts	1.1
Emerald Disclosed Materials	Article 7
Emerald Hydrocarbons	1.1
Emerald Indemnified Parties	14.4(a)
Emerald Lands	1.1
Emerald Leases	1.1

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Emerald Material Agreements	7.7
Emerald Oil	Preamble
Emerald Records	1.1
Emerald WB	Preamble
Emerald Wells	1.1
Environmental Assessment	3.3(a)(1)
Environmental Defect	1.1
Environmental Defect Notice	5.2
Environmental Defect Property	5.2
Environmental Disputed Matters	5.5
Environmental Laws	1.1
Environmental Liabilities	1.1
Escrow Agent	2.6
Escrow Agreement	2.6
Escrow Amount	1.1
Excluded Assets	1.1
Exclusivity Payment	1.1
Final Emerald Section 1060 Allocation Schedule	2.3(d)
Final Liberty Section 1060 Allocation Schedule	2.3(c)
Final Net Purchase Price	13.1(a)
Final Settlement Date	13.1(a)
Final Settlement Statement	13.1(a)
Force Majeure	1.1
Fundamental Representations	14.6
Governmental Entity	1.1
Hazardous Materials	1.1
Indebtedness	1.1
Indemnified Party	14.5(a)
Indemnifying Party	14.5(a)
Individual Environmental Threshold	5.4
Individual Title Threshold	4.2(e)
Knowledge	1.1
Landowner Release	5.6(c)
Law	1.1
Liberty	Preamble
Liberty Allocated Value	2.3(a)
Liberty Assets	1.1
Liberty Assets Preliminary Settlement Statement	2.4
Liberty Assets Preliminary Adjusted Settlement Statement	2.4
Liberty Assets Purchase Price	2.2(a)
Liberty Assignment	12.3(a)

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Liberty Assumed Liabilities	14.2
Liberty Bakken	Preamble
Liberty Capital Expenditures	6.7
Liberty Contracts	1.1
Liberty Disclosed Materials	Article 6
Liberty Hydrocarbons	1.1
Liberty Indemnified Parties	14.4(b)
Liberty Lands	1.1
Liberty Leases	1.1
Liberty Management	Preamble
Liberty Material Agreements	6.6
Liberty Records	1.1
Liberty Wells	1.1
Lien	1.1
Losses	1.1
Material Adverse Effect	1.1
NDIC	5.6(b)
Net Acre	1.1
Net Casualty Loss	8.3(b)
Net Revenue Interest	4.1(a)(1)
Notice of Defective Interests	4.2(b)
Obligations	14.1
Party; Parties	Preamble
Permitted Encumbrances	4.1(b)
Person	1.1
Plugging and Abandonment Obligations	1.1
Production Taxes	1.1
Property Expenses	1.1
Proposed Emerald Section 1060 Allocation Schedule	2.3(d)
Proposed Liberty Section 1060 Allocation	2.3(c)
Release	1.1
Retained Obligations	14.3
Remediate; Remediation	1.1
Remediation Costs	1.1
Representatives	1.1
Survival Period	14.6
Taxes	1.1
Tax Proceeding	9.4
Tax Return	1.1
Termination Date	11.1(b)
Term Sheet	1.1
Title Benefit	4.2(g)
Title Benefit Amount	4.2(i)

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Title Defect	4.2(a)
Title Defect Amount	4.2(d)
Title Defect Property	4.2(b)
Title Disputed Matters	4.3
Transfer Taxes	9.2
Transferee	1.1
Transferee Indemnified Parties	1.1
Transferor	1.1
Transferor Allocated Value	1.1
Transferor Assets	1.1
Transferor Contracts	1.1
Transferor Indemnified Parties	1.1
Transferor Purchase Price	1.1
Transferor Records	1.1
Transferor Well	1.1
Working Interest	4.1(a)(2)

-viii-

List of Exhibits
Exhibit A-1	Liberty Leases
Exhibit A-2	Emerald Leases
Exhibit B-1	Liberty Wells
Exhibit B-2	Emerald Wells
Exhibit C-1	Liberty Surface Agreements
Exhibit C-2	Emerald Surface Agreements
Exhibit D-1	Liberty Material Agreements
Exhibit D-2	Emerald Material Agreements
Exhibit E-1	Form of Assignment, Bill of Sale and Conveyance (Liberty Assets)
Exhibit E-2	Form of Assignment, Bill of Sale and Conveyance (Emerald Assets)
Exhibit F-1	Form of Assignment and Assumption Agreement (Liberty Contracts)
Exhibit F-2	Form of Assignment and Assumption Agreement (Emerald Contracts)
Exhibit G	Affidavit of Non-Foreign Status
List of Schedules
Schedule 1.1(a)	Emerald’s Knowledge Representatives
Schedule 1.1(b)	Liberty’s Knowledge Representatives
Schedule 1.1(c)	Excluded Assets
Schedule 2.3(c)	Final Liberty Section 1060 Allocation Schedule
Schedule 2.3(d)	Final Emerald Section 1060 Allocation Schedule
Schedule 2.4(a)	Liberty Assets Preliminary Settlement Statement
Schedule 2.4(b)	Emerald Assets Preliminary Settlement Statement
Schedule 4.4	Preferential Rights and Consents
Schedule 6.5	Pending or Threatened Litigation
Schedule 6.7	Liberty Capital Expenditures
Schedule 6.9	Audits
Schedule 6.13	Well Status
Schedule 6.14	Calls on Production
Schedule 7.5	Pending or Threatened Litigation
Schedule 7.8	Emerald Capital Expenditures
Schedule 7.10	Audits
Schedule 7.14	Well Status
Schedule 7.15	Calls on Production
Schedule 8.1(b)	Existing Drilling Plan

-ix-

PURCHASE AND SALE AGREEMENT

This Purchase and Sale Agreement (this “Agreement”), dated as of this 1^st day of August, 2014, is entered into by and between Liberty Resources Management Company, LLC, a Delaware limited liability company (“Liberty Management”) and Liberty Resources Bakken Operating, LLC, a Delaware limited liability company (“Liberty Bakken” and together with Liberty Management, “Liberty”), and Emerald Oil, Inc., a Delaware corporation (“Emerald Oil”) and Emerald WB LLC, a Colorado limited liability company (“Emerald WB” and together with Emerald Oil, “Emerald”), and Liberty Resources II, LLC, a Delaware limited liability company (“Liberty Resources”), as guarantor. Each of the foregoing entities are collectively referred to as the “Parties” and individually as a “Party”.

RECITALS

WHEREAS, Liberty Bakken desires to sell and Emerald desires to purchase Liberty’s interest in the Liberty Assets (as defined below) upon the terms and conditions set forth in this Agreement; and

WHEREAS, Emerald desires to sell and Liberty Bakken desires to purchase Emerald’s interest in the Emerald Assets (as defined below) upon the terms and conditions set forth in this Agreement.

NOW THEREFORE, in consideration of the mutual promises contained herein and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties agree as follows:

AGREEMENTS

ARTICLE 1

DEFINITIONS AND REFERENCES

1.1           Certain Defined Terms. In addition to the terms defined elsewhere herein, the following terms will have the respective meanings assigned to them in this Section 1.1 when used in this Agreement with initial capital letters:

“Affiliate” means, with respect to any Person, any other Person that directly or indirectly controls, is controlled by or is under common control with such Person. For purposes of the immediately preceding sentence, the term “control” (including, with correlative meanings, the terms “controlling,” “controlled by” and “under common control with”), as used with respect to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of such Person, whether through ownership of voting securities, by contract or otherwise.

“Assets” means the Liberty Assets or Emerald Assets, as applicable.

“Burgundy Property Expenses” is defined in the definition of “Property Expenses.”

“Business Day” means a day other than a Saturday, Sunday or a day on which commercial banks in Denver, Colorado, or New York, New York, are authorized or required by applicable Law to be closed for business.

“Code” means the Internal Revenue Code of 1986, as amended.

“Condition” means any circumstance, status or defect that requires Remediation to comply with Environmental Laws.

“Dispute” means any dispute, claim or controversy of any kind or nature related to, arising under, or connected with this Agreement (including disputes as to the creation, validity, interpretation, breach or termination of this Agreement).

“Effective Time” means May 1, 2014, at 7:00 a.m. Mountain Time.

“Emerald Assets” means all of Emerald’s right, title, and interest, whether present, contingent, or reversionary, in and to the following, but not including the Excluded Assets:

(a)          all oil and gas leases specifically described in Exhibit A-2, together with all amendments, renewals, extensions, top leases, and ratifications thereof (collectively, the “Emerald Leases”);

(b)          the lands covered by the Emerald Leases or pooled or unitized therewith (the “Emerald Lands”);

(c)          the oil, gas, casinghead gas, coal bed methane, condensate and other gaseous and liquid hydrocarbons or any combination thereof that may be produced from under the Emerald Leases or the Emerald Lands (the “Emerald Hydrocarbons”);

(d)          all oil, gas, water or injection wells located on or associated with the Emerald Lands, whether producing, shut-in, or temporarily abandoned, including the wells described in Exhibit B-2 (the “Emerald Wells”), together with all of the personal property, equipment, fixtures and improvements used in connection therewith;

(e)          the unitization, pooling and communitization agreements, declarations, spacing orders, and the pools, units, or spacing units created thereby, in each case, relating to the properties and interests described in Clauses (a) through (d) and to the production of Emerald Hydrocarbons, if any, attributable to said properties and interests, and the force-pooled and non-consent interests associated therewith;

(f)          all equipment, machinery, fixtures and other tangible personal property and improvements located on or used or held for use solely in connection with the operation of the interests described in Clauses (a) through (e) including any tanks, boilers, buildings, fixtures, injection facilities, saltwater disposal facilities, compression facilities, pumping units and engines, platforms, flow lines, pipelines, gathering systems, gas and oil treating facilities, machinery, power lines, telephone and telegraph lines, roads, and other appurtenances, improvements and facilities;

-2-

(g)          all surface leases, permits, rights-of-way, licenses, easements and other surface rights agreements used in connection with the production, gathering, treatment, processing, storage, sale or disposal of Emerald Hydrocarbons or produced water from the interests described in Clauses (a) through (f), including those described on Exhibit C-2, but excluding, in all such instances, any items the transfer of which is prohibited by applicable Law;

(h)          all existing contracts and effective sales and purchase contracts, operating agreements, exploration agreements, development agreements, balancing agreements, farmout agreements, service agreements, transportation, processing, treatment or gathering agreements, equipment leases and other contracts, agreements and instruments, insofar as they are listed on Exhibit D-2 and directly relate to the properties and interests described in Clauses (a) through (g) and not to other properties of Emerald or Emerald’s corporate overhead, but excluding any contracts, agreements and instruments the transfer of which is prohibited by applicable Law (collectively, the “Emerald Contracts”); and

(i)          to the extent transferable without payment of additional consideration, originals, to the extent available, or copies of all the files, records, and data relating primarily to the items described in Clauses (a) through (h) above, which records shall include, without limitation: lease records; well records; division order records; well files; title records (including abstracts of title, title opinions and memoranda, and title curative documents); engineering records; geological and geophysical data (including seismic data) and all technical evaluations, interpretive data and technical data and information relating primarily to the properties and interests described in Clauses (a) through (h); correspondence; electronic data files (if any); maps; production records; electric logs; core data; pressure data; decline curves and graphical production curves; reserve reports; appraisals and accounting records (collectively, the “Emerald Records”).

“Environmental Defect” means a Condition in, on, under or relating to the air, land, soil, surface and subsurface strata, surface water, groundwater, or sediments of, or at, a particular Transferor Asset, including, without limitation, the presence of Hazardous Materials, but excluding any Plugging and Abandonment Obligations (which shall not constitute an Environmental Defect).

“Environmental Laws” means all federal, tribal, state, local or foreign law (including common law), statute, rule, regulation, requirement, ordinance and any writ, decree, bond, authorization, approval, license, permit, registration, binding criteria, standard, consent decree, settlement agreement, judgment, order, directive or binding policy issued by or entered into with a Governmental Entity pertaining or relating to: (a) pollution or pollution control, including, without limitation, storm water regulation; (b) protection of human health and the environment from the Release of Hazardous Materials; and/or (c) the management, presence, use, generation, processing, extraction, treatment, recycling, refining, reclamation, labeling, transport, storage, collection, distribution, or Release or threat of Release of Hazardous Materials. “Environmental Laws” shall include, without limitation, the Comprehensive Environmental Response, Compensation, and Liability Act, 42 U.S.C. § 9601 et seq.; the Solid Waste Disposal Act (as amended by the Resource Conservation and Recovery Act), 42 U.S.C. § 6901 et seq.; the Hazardous Materials Transportation Act, 49 U.S.C. § 1801 et seq.; the Toxic Substances Control Act, 15 U.S.C. § 2601 et seq.; the Federal Water Pollution Control Act, 33 U.S.C. § 1251 et seq.; the federal Safe Drinking Water Act, 42 U.S.C. §§ 300f-300; the Clean Air Act, 42 U.S.C. § 7401 et seq.; the Oil Pollution Act, 33 U.S.C. § 2701 et seq.; the Occupational Safety and Health Act, 29 U.S.C. § 651 et seq.; the Endangered Species Act, 16 U.S.C. § 1531 et seq.; the National Historic Preservation Act, 16 U.S.C. §470 et seq.; the Emergency Planning and Community Right-to-Know Act, 42 U.S.C. § 11001 et seq., the National Environmental Policy Act, 42 U.S.C. § 4321 et. seq. and the regulations and orders respectively promulgated thereunder, each as amended, or any equivalent or analogous state or local statutes, laws or ordinances, any regulation promulgated thereunder and any amendments or reauthorizations thereof or thereto.

-3-

“Environmental Liabilities” means all Losses (including any civil fines, penalties, Remediation Costs, any personal injury, illness or death, any damage to, destruction or loss of property, and any damage to natural resources (including soil, air, surface water or groundwater) and expenses for the modification, repair or replacement of facilities on the Lands) brought or assessed by any and all Persons, including any Governmental Entity, to the extent any of the foregoing directly or indirectly involves any Condition relating to the Assets, including Plugging and Abandonment Obligations, the presence, disposal or release of any Hazardous Material of any kind in, on or under the Assets, created or attributable to any period of time, whether before or after Transferor acquired ownership of the Assets, including any period of time prior to or after the Effective Time, but not including any Losses relating to offsite disposal of Hazardous Materials by Transferor or its Affiliates prior to the Effective Time.

“Escrow Amount” means the sum of (i) the aggregate Title Escrow Amounts, if any, and (ii) the aggregate Environmental Escrow Amounts, if any.

“Excluded Assets” means, with respect to either Liberty or Emerald, (a) (i) all corporate, financial, income, Tax and legal records of such Party that relate to such Party’s business generally (whether or not relating to the Assets) and (ii) all books, records and files that relate to the Excluded Assets or this Agreement and the transactions contemplated hereby; (b) (i) equipment, inventory, machinery, fixtures and other tangible personal property and improvements that are leased by such Party or located at or used in connection with any field office or yard of such Party that are not used solely in connection with the Assets, (ii) any computers and related peripheral equipment that are not located on the Assets, and (iii) communications equipment that is not located on the Assets and not used solely in connection with the Assets; (c) all rights to any refunds for Taxes or other costs or expenses borne by such Party or such Party’s predecessors in interest and title attributable to periods prior to the Effective Time in accordance with the principles of Section 9.1; (d) such Party’s area-wide bonds, permits and licenses or other permits, licenses or authorizations used in the conduct of such Party’s business generally; (e) all geophysical and other seismic and related technical data and information that is not transferrable without the payment of a fee or other penalty or is otherwise not transferrable pursuant to a third party agreement or applicable Law; (f) all data that cannot be disclosed to by a Party to the other Party as a result of confidentiality arrangements under agreements with third parties; (g) all trade credits, account receivables, note receivables, take or pay amounts receivable, and other receivables attributable to the Assets with respect to any period of time prior to the Effective Time; (h) any refunds due to either Party by a third party for any overpayment of rentals, royalties, excess royalty interests or production payments attributable to the Assets with respect to any period of time prior to the Effective Time; (i) any causes of action, claims, rights, indemnities or defenses with respect to the Assets, whether arising before or after the Effective Time, that relate to any indemnification obligation of either Party hereunder as more fully described in Article 14 below; (j) all rights and interests of either Party (i) under any policy or agreement of insurance or indemnity agreement, (ii) under any bond and (iii) to any insurance or condemnation proceeds or awards arising, in each case, from acts, omission or events, or damage to or destruction of property prior to the Effective Time; (k) the assets listed on Schedule 1.1(c); and (l) until the conditions set forth in Section 5.6 are met, the Burgundy Wellbore Interests.

-4-

“Exclusivity Payment” means the exclusivity payment of $1,000,000 paid by Emerald to Liberty pursuant to the terms of the Term Sheet.

“Force Majeure” means acts of terrorism, fire, explosion, earthquake, storm, flood, freezing of wells or pipelines, delays in obtaining rights-of-way, shutting-in facilities for repair or maintenance, strike, lock out, activities of a combination of workmen or other labor difficulties, wars, insurrection, riot, Law, act, order, export or import control regulations, proclamation, decree, regulation, ordinance, or instructions of a Governmental Entity, judgment or decree of a court of competent jurisdiction or any other cause not reasonably within the control of the party claiming force majeure.

“Governmental Entity” means any national, state, local, native, or tribal government or any subdivision, agency, court, commission, department, board, bureau, regulatory authority or other division or instrumentality thereof.

“Hazardous Materials” means, without limitation, any waste, substance, product, or other material (whether solid, liquid, gas or mixed), which is or becomes identified, listed, published, or defined as a hazardous substance, hazardous waste, hazardous material, toxic substance, pollutant, contaminant, radioactive material, oil, or petroleum waste under any Environmental Law.

“Indebtedness” means, without duplication, with respect to the Emerald Assets or the Liberty Assets, the outstanding principal amount of, accrued and unpaid interest on, discounts and fees on, and any other payment obligations relating to the Emerald Assets or the Liberty Assets, as applicable, existing under any and all of the following, whether or not contingent: (i) indebtedness for borrowed money and (ii) obligations evidenced by notes, bonds, debentures or any other contractual arrangements, including any guarantees or other commitments or obligations by which Emerald or Liberty, as applicable, assures a creditor against loss.

“Knowledge” means, with respect to Emerald, the actual knowledge of Emerald’s representatives listed on Schedule 1.1(a) and with respect to Liberty, the actual knowledge of Liberty’s representatives listed on Schedule 1.1(b).

“Law” means any statute, law, principle of common law, rule, regulation, judgment, order, ordinance, requirement, code, writ, injunction, or decree of any Governmental Entity.

“Liberty Assets” means all of Liberty’s right, title, and interest, whether present, contingent, or reversionary, in and to the following, but not including the Excluded Assets:

-5-

(a)          all oil and gas leases specifically described in Exhibit A-1, together with all amendments, renewals, extensions, top leases, and ratifications thereof (collectively, the “Liberty Leases”);

(b)          the lands covered by the Liberty Leases or pooled or unitized therewith (the “Liberty Lands”);

(c)          the oil, gas, casinghead gas, coal bed methane, condensate and other gaseous and liquid hydrocarbons or any combination thereof that may be produced from under the Liberty Leases or the Liberty Lands (the “Liberty Hydrocarbons”);

(d)          all oil, gas, water or injection wells located on or associated with the Liberty Lands, whether producing, shut-in, or temporarily abandoned, including the wells described in Exhibit B-1 (the “Liberty Wells”), together with all of the personal property, equipment, fixtures and improvements used in connection therewith;

(e)          the unitization, pooling and communitization agreements, declarations, spacing orders, and the pools, units, or spacing units created thereby, in each case, relating to the properties and interests described in Clauses (a) through (d) and to the production of Liberty Hydrocarbons, if any, attributable to said properties and interests, and the force-pooled and non-consent interests associated therewith;

(f)          all equipment, machinery, fixtures and other tangible personal property and improvements located on or used or held for use solely in connection with the operation of the interests described in Clauses (a) through (e) including any tanks, boilers, buildings, fixtures, injection facilities, saltwater disposal facilities, compression facilities, pumping units and engines, platforms, flow lines, pipelines, gathering systems, gas and oil treating facilities, machinery, power lines, telephone and telegraph lines, roads, and other appurtenances, improvements and facilities;

(g)          all surface leases, permits, rights-of-way, licenses, easements and other surface rights agreements used in connection with the production, gathering, treatment, processing, storage, sale or disposal of Liberty Hydrocarbons or produced water from the interests described in Clauses (a) through (f) including those described on Exhibit C-1, but excluding, in all such instances, any items the transfer of which is prohibited by applicable Law;

(h)          all existing contracts and effective sales and purchase contracts, operating agreements, exploration agreements, development agreements, balancing agreements, farmout agreements, service agreements, transportation, processing, treatment or gathering agreements, equipment leases and other contracts, agreements and instruments, insofar as they are listed on Exhibit D-1 and directly relate to the properties and interests described in Clauses (a) through (g) and not to other properties of Liberty or Liberty’s corporate overhead, but excluding any contracts, agreements and instruments the transfer of which is prohibited by applicable Law (collectively, the “Liberty Contracts”); and

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(i)          to the extent transferable without payment of additional consideration, originals, to the extent available, or copies of all the files, records, and data relating primarily to the items described in Clauses (a) through (h) above, which records shall include, without limitation: lease records; well records; division order records; well files; title records (including abstracts of title, title opinions and memoranda, and title curative documents); engineering records; geological and geophysical data (including seismic data) and all technical evaluations, interpretive data and technical data and information relating primarily to the properties and interests described in Clauses (a) through (h); correspondence; electronic data files (if any); maps; production records; electric logs; core data; pressure data; decline curves and graphical production curves; reserve reports; appraisals and accounting records (collectively, the “Liberty Records”).

“Lien” means any of the following: mortgage, lien (statutory or other), other security agreement, arrangement or interest, hypothecation, pledge or other deposit arrangement, assignment, charge, levy, executory seizure, attachment, garnishment, encumbrance (including any easement, exception, reservation or limitation, right of way, and the like), conditional sale, title retention, voting agreement or other similar agreement, arrangement, device or restriction, preemptive or similar right, the filing of any financial statement under the Uniform Commercial Code or comparable Law of any jurisdiction, or any option, equity, claim or right of or obligation to any other Person of whatever kind and character; provided, however, that the term “Lien” shall not include any of the foregoing to the extent created by this Agreement.

“Losses” means any actual losses, costs, expenses (including court costs, reasonable fees and expenses of attorneys, technical experts and expert witnesses and the cost of investigation), liabilities, damages, demands, suits, claims, and sanctions of every kind and character (including civil fines) arising from, related to or reasonably incident to matters indemnified against; excluding, however, (x) any special, consequential, punitive or exemplary damages, diminution of value of any Transferor Assets, loss of profits incurred by a Party or loss incurred as a result of the indemnified party indemnifying a third party and (y) any increase in liability, loss, cost, expense, claim, award or judgment to the extent such increase is caused by the actions or omissions of any indemnified party after the Closing Date.

“Material Adverse Effect” means any state of facts, change, event, effect or occurrence (when taken together with all other states of fact, changes, events, effects or occurrences), that is (i) materially adverse to the ownership, operations or value of the applicable Party’s Assets, or (ii) materially adverse to the ability of the applicable Party to consummate the transactions contemplated by this Agreement on a timely basis; provided, however, that no state of facts, change, event, effect or occurrence arising or related to any of the following shall be deemed to constitute, and none of the following shall be taken into account in determining whether there has been a “Material Adverse Effect”: (a) national or international business, economic or political conditions, including the engagement by the United States of America in hostilities, whether or not pursuant to the declaration of a national emergency or war, or the occurrence of any military or terrorist attack upon the United States of America or any of its respective territories, possessions or diplomatic or consular offices or upon any military installation, equipment or personnel of the United States of America; (b) events affecting the financial, banking or securities markets (including any disruption thereof or any decline in the price of securities generally or any market or index); (c) conditions (or changes in such conditions) generally affecting the oil and gas industry or the natural gas liquids industry in any area or areas where the Assets are located; (d) increases in energy, electricity, natural gas, oil, or other raw materials or operating costs; (e) changes in generally accepted accounting principles or Law; (f) the taking of any action required by this Agreement; (g) changes as a result of the negotiation, announcement, pendency or performance of this Agreement, including by reason of the identity of the Parties or any communication by either Party or any of their respective Affiliates of their plans or intentions regarding the operation of the applicable Assets; (h) any actions taken or omitted to be taken by or at the request or with the written consent of a Party; (i) any event of Force Majeure; (j) changes in oil or natural gas prices, including changes in price differentials; (k) effects or changes that are cured or no longer exist by the earlier of the Closing and the termination of this Agreement pursuant to Article 11; or (l) changes resulting from the performance of the covenants set forth in Section 8.1 hereof (solely to the extent that such changes are a result of a Party’s refusal to give its written approval to the other Party’s written request to take any action restricted therein).

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“Net Acre” means, as computed separately with respect to each Transferor Lease, the (x) lessor’s percentage interest in the leasehold estate created by the Transferor Lease multiplied by (y) the number of gross acres covered by the Transferor Lease multiplied by (z) the Transferor’s Working Interest in such Lease.

“Person” means any individual or entity, including, without limitation, any corporation, limited liability company, partnership (general or limited), joint venture, association, joint stock company, trust, unincorporated organization or Governmental Entity.

“Plugging and Abandonment Obligations” means any and all responsibility and liability for the following, arising out of or relating to the Transferor Assets, whether before, on, or after the Effective Time: (a) the necessary and proper plugging, replugging, and abandonment of all Transferor Wells; (b) the necessary and proper removal, abandonment, and disposal of all structures, pipelines, equipment, operating inventory, abandoned property, trash, refuse, and junk located on or comprising part of the Transferor Assets; (c) the necessary and proper capping and burying of all associated flow lines located on or comprising part of the Transferor Assets; and (d) the necessary and proper restoration of the surface and subsurface to the condition required by applicable Laws, permits, orders, and contracts, except for interim reclamation previously required to be performed under any Environmental Law.

“Production Taxes” means all ad valorem, property, production, excise, net proceeds, severance, windfall profit and all other Taxes and similar obligations assessed against the Emerald Assets or the Liberty Assets, as applicable, or based upon or measured by the ownership of the Emerald Assets or the Liberty Assets, as applicable, or the production of Hydrocarbons or the receipt of proceeds therefrom, provided that Production Taxes shall not include income, franchise, or margin Taxes, and Transfer Taxes, but shall include any interest, penalties, additions to tax and fines assessed or due in respect of any Production Taxes, whether disputed or not.

“Property Expenses” means all (i) capital expenses (including all capital expenditures permitted by Section 8.1(a) and bonuses, broker fees, and other lease acquisition costs, costs of drilling and completing wells and costs of acquiring equipment), Production Taxes (as apportioned as of the Effective Time pursuant to Article 9) and operating and production expenses (including costs of insurance, rentals, shut-in payments and royalty payments; title examination and curative actions; and gathering, processing and transportation costs in respect of Hydrocarbons produced from the Assets), incurred in the ownership, development and operation of the Assets in the ordinary course of business, (ii) general and administrative costs with respect to the Assets and (iii) overhead costs charged to the Assets under the applicable operating agreement; provided however, that with respect to the Emerald Assets, (1) the Burgundy Remediation Costs shall not constitute Property Expenses, and (2) the aggregate Property Expenses related to the Burgundy Wellbore Interests (the “Burgundy Property Expenses”) shall not exceed $5,000,000, regardless of the actual amount incurred by Emerald in excess of that threshold.

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“Release” means any “release” or “disposal” as defined by or under any Environmental Law.

“Remediation” or “Remediate” means investigation, assessment, characterization, delineation, monitoring, sampling, analysis, removal action, remedial action, response action, corrective action, mitigation, treatment, cleanup, reporting, or permitting of (a) any Release of Hazardous Materials or other similar actions as required by any applicable Environmental Law from soil, land surface, groundwater, sediment, surface water, or subsurface strata or otherwise or (b) any failure of Transferor to operate the Transferor’s Assets in compliance with all applicable Environmental Laws where such noncompliance would have, individually or in the aggregate, a Material Adverse Effect.

“Remediation Costs” means all costs to Remediate an Environmental Defect to the extent required to bring an Environmental Defect Property into compliance with all applicable Environmental Laws, including the costs of any fines, penalties, judgments, or similar amounts assessed or alleged against Transferor.

“Representatives” means each Party’s stockholders, members, managers, officers, directors, employees, agents, and representatives.

“Taxes” means any taxes and assessments imposed by any Governmental Entity, including net income, gross income, profits, gross receipts, license, employment, stamp, occupation, premium, alternative or add-on minimum, ad valorem, real property, personal property, transfer, real property transfer, value added, sales, use, environmental (including taxes under Code Section 59A), customs, duties, capital stock, franchise, excise, withholding, social security (or similar), unemployment, disability, payroll, fuel, excess profits, windfall profit, severance, estimated or other tax, including any interest, penalty or addition thereto, whether disputed or not, and any expenses incurred in connection with the determination, settlement or litigation of the Tax liability, and “Tax” means any one of these.

“Tax Return” means any return, report or similar statement required to be filed with respect to any Tax (including any attached schedules), including, without limitation, any information return, claim for refund, amended return and declaration of estimated Tax.

“Term Sheet” means the Term Sheet dated July 11, 2014 entered into between Liberty and Emerald.

“Transferee” means Emerald with respect to Liberty’s conveyance of the Liberty Assets to Emerald, and Liberty, with respect to Emerald’s conveyance of the Emerald Assets to Liberty.

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“Transferee Indemnified Parties” means the Transferee, its affiliates, and its and their Representatives.

“Transferor” means Emerald, with respect to Emerald’s conveyance of the Emerald Assets to Liberty, and Liberty, with respect to Liberty’s conveyance of the Liberty Assets to Emerald.

“Transferor Allocated Value” means the Emerald Allocated Value if Emerald is the Transferor or the Liberty Allocated Value if Liberty is the Transferor.

“Transferor Assets” means the Emerald Assets if Emerald is the Transferor or the Liberty Assets if Liberty is the Transferor.

“Transferor Contracts” means the Emerald Contracts if Emerald is the Transferor or the Liberty Contracts if Liberty is the Transferor.

“Transferor Indemnified Parties” means the Transferor, its affiliates, and its and their Representatives.

“Transferor Purchase Price” means the Emerald Assets Purchase Price if Emerald is the Transferor or the Liberty Assets Purchase Price if Liberty is the Transferor.

“Transferor Records” means the Emerald Records if Emerald is the Transferor or the Liberty Records if Liberty is the Transferor.

“Transferor Well” means the Emerald Wells if Emerald is the Transferor or the Liberty Wells if Liberty is the Transferor.

1.2          References and Construction.

(a)          When a reference is made in this Agreement to Articles, Sections, Exhibits or Schedules, such reference will be to an Article, Section, Exhibit or Schedules to this Agreement unless otherwise indicated. Whenever the words “include,” “includes” or “including” are used in this Agreement, they will be deemed to be followed by the words “without limitation.” Unless the context otherwise requires, (i) ”or” is disjunctive but not necessarily exclusive, (ii) words in the singular include the plural and vice versa, (iii) the words “herein,” “hereof,” “hereby,” “hereunder” and words of similar nature refer to this Agreement as a whole and not to any particular subdivision unless expressly so limited, and (iv) the use in this Agreement of a pronoun in reference to a Party hereto includes the masculine, feminine or neuter, as the context may require.

(b)          The Parties have participated jointly in negotiating and drafting this Agreement. In the event that an ambiguity or a question of intent or interpretation arises, this Agreement will be construed as if drafted jointly by the Parties, and no presumption or burden of proof will arise favoring or disfavoring any Party by virtue of the authorship of any provision of this Agreement.

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ARTICLE 2

PURCHASE AND SALE

2.1          Purchase and Sale. Subject to the terms and conditions of this Agreement, at the Closing, (i) Emerald agrees to purchase from Liberty and Liberty agrees to sell, assign and deliver to Emerald all of Liberty’s right, title and interest in the Liberty Assets, and (ii) Liberty agrees to purchase from Emerald and Emerald agrees to sell, assign and deliver to Liberty all of Emerald’s right, title and interest in the Emerald Assets, in each case, for the consideration specified in this Article 2.

2.2          Consideration.

(a)          Subject to the terms and conditions of this Agreement, at the Closing, as consideration for the purchase of the Liberty Assets, Emerald shall assume and agree to discharge the Emerald Assumed Liabilities and pay to Liberty the sum of $109,031,314 in immediately available funds (the “Liberty Assets Purchase Price”), as adjusted pursuant to Section 2.4.

(b)          Subject to the terms and conditions of this Agreement, at the Closing, as consideration for the purchase of the Emerald Assets, Liberty shall assume and agree to discharge the Liberty Assumed Liabilities and pay to Emerald the sum of $30,589,000 in immediately available funds (the “Emerald Assets Purchase Price”) as adjusted pursuant to Section 2.4.

(c)          At Closing, Emerald shall pay to Liberty in immediately available funds to an account designated by Liberty an amount equal to the Emerald Assets Preliminary Adjusted Purchase Price, less the Liberty Assets Preliminary Adjusted Purchase Price, less the Exclusivity Payment (such amount being referred to as the “Closing Amount”).

(d)          After Closing, final adjustments to the Emerald Assets Preliminary Adjusted Purchase Price and the Liberty Assets Preliminary Adjusted Purchase Price shall be made pursuant to the Final Settlement Statement to be delivered pursuant to Section 13.1(a) and payments made by Emerald or Liberty as provided in Section 13.1(a).

2.3          Allocation of the Purchase Price.

(a)          For purposes of adjusting the Emerald Assets Purchase Price or the Liberty Assets Purchase Price due to the existence of any title matters under Article 4 or environmental matters under Article 5, (1) Emerald has allocated the Liberty Assets Purchase Price among the Liberty Leases and Liberty Wells in the amounts set forth on Exhibit A-1 and Exhibit B-1, as applicable; and (2) Liberty has allocated the Emerald Assets Purchase Price among the Emerald Leases and Emerald Wells in the amounts set forth on Exhibit A-2 and Exhibit B-2, as applicable. The value allocated to each Emerald Asset is the “Emerald Allocated Value,” and the value allocated to each Liberty Asset is the “Liberty Allocated Value.”

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(b)          Emerald and Liberty have agreed on the Allocated Values for the Assets, but neither Emerald nor Liberty otherwise makes any representation or warranty as to the accuracy of such values.

(c)          Liberty shall prepare an allocation of the Liberty Assets Purchase Price on a schedule (the “Proposed Liberty Section 1060 Allocation Schedule”) for purposes of, and in accordance with, Section 1060 of the Code and the regulations promulgated thereunder within thirty (30) days after the Final Settlement Date. Emerald shall notify Liberty in writing of any objections to the Proposed Liberty Section 1060 Allocation Schedule within fifteen (15) days of receipt thereof and if, within thirty (30) days after delivery of notice of such objection, Emerald and Liberty cannot agree to a final allocation schedule to be used for income Tax reporting purposes, Emerald and Liberty shall submit the Disputed matters to binding arbitration pursuant to Section 15.13 to finally determine the proper allocation of the Liberty Assets Purchase Price for purposes of Section 1060 of the Code, and shall request that the arbitrator issue a final allocation schedule (the “Final Liberty Section 1060 Allocation Schedule”) within thirty (30) days of the submission of the Dispute. Liberty and Emerald agree that the allocation of the Liberty Assets Purchase Price as set forth on the Final Liberty Section 1060 Allocation Schedule shall be used by Liberty and Emerald as the basis for reporting asset values and other items for purposes of all federal, state and local Tax Returns, including without limitation Internal Revenue Service Form 8594. Liberty and Emerald further agree that each will take no position inconsistent with such allocations on any applicable Tax Return, in any audit or proceeding before any Governmental Entity related to Taxes, in any report made for Tax, financial accounting or any other purpose, or otherwise. In the event that the allocation described herein is disputed by any Governmental Entity, the Party receiving notice of the dispute shall promptly notify the other Party concerning resolution of the dispute.

(d)          Emerald shall prepare an allocation of the Emerald Assets Purchase Price on a schedule (the “Proposed Emerald Section 1060 Allocation Schedule”) for purposes of, and in accordance with, Section 1060 of the Code and the regulations promulgated thereunder within thirty (30) days after the Final Settlement Date. Liberty shall notify Emerald in writing of any objections to the Proposed Emerald Section 1060 Allocation Schedule within fifteen (15) days of receipt thereof and if, within thirty (30) days after delivery of notice of such objection, Liberty and Emerald cannot agree to a final allocation schedule to be used for income Tax reporting purposes, Liberty and Emerald shall submit the Disputed matters to binding arbitration pursuant to Section 15.13 to finally determine the proper allocation of the Emerald Assets Purchase Price for purposes of Section 1060 of the Code, and shall request that the arbitrator issue a final allocation schedule (the “Final Emerald Section 1060 Allocation Schedule”) within thirty (30) days of the submission of the Dispute. Emerald and Liberty agree that the allocation of the Emerald Assets Purchase Price as set forth on the Final Emerald Section 1060 Allocation Schedule shall be used by Emerald and Liberty as the basis for reporting asset values and other items for purposes of all federal, state and local Tax Returns, including without limitation Internal Revenue Service Form 8594. Emerald and Liberty further agree that each will take no position inconsistent with such allocations on any applicable Tax Return, in any audit or proceeding before any Governmental Entity related to Taxes, in any report made for Tax, financial accounting or any other purpose, or otherwise. In the event that the allocation described herein is disputed by any Governmental Entity, the Party receiving notice of the dispute shall promptly notify the other Party concerning resolution of the dispute.

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2.4          Adjustments to Purchase Price and Preliminary Settlement Statement. The Liberty Assets Purchase Price and the Emerald Assets Purchase Price shall be adjusted according to this Section 2.4, without duplication. Such adjustment shall be set out in (i) the “Liberty Assets Preliminary Settlement Statement” that shall be delivered by Liberty to Emerald at least three (3) Business Days prior to Closing, or (ii) the “Emerald Assets Preliminary Settlement Statement” that shall be delivered by Emerald to Liberty at least three (3) Business Days prior to Closing. The Liberty Assets Purchase Price, as adjusted pursuant to this Section 2.4, is referred to as the “Liberty Assets Preliminary Adjusted Purchase Price” and the Emerald Assets Purchase Price, as adjusted pursuant to this Section 2.4, is referred to as the “Emerald Assets Preliminary Adjusted Purchase Price”. No adjustment to the Emerald Assets Purchase Price shall be made with respect to the Burgundy Wellbore Interests or the Burgundy Property Expenses unless and until the conditions in Section 5.6 are satisfied and the Burgundy Wellbore Interests are conveyed to Liberty.

(a)         Upward Adjustments. The Liberty Assets Purchase Price and the Emerald Assets Purchase Price, as applicable, shall be adjusted upward by the following:

(1)         (i) With respect to the Liberty Assets Purchase Price, the proceeds received by Emerald, net of royalties, overriding royalties, profit payments and similar burdens, from the sale of any Hydrocarbons that were produced from the Liberty Assets prior to the Effective Time, and (ii) with respect to the Emerald Assets Purchase Price, the proceeds received by Liberty, net of royalties, overriding royalties, profit payments and similar burdens, from the sale of any Hydrocarbons that were produced from the Emerald Assets prior to the Effective Time;

(2)         (i) With respect to the Liberty Assets Purchase Price, an amount equal to all Property Expenses attributable to the Liberty Assets from and after the Effective Time that were paid by Liberty (all to be apportioned as of the Effective Time except as otherwise provided), and (ii) with respect to the Emerald Assets Purchase Price, an amount equal to all Property Expenses attributable to the Emerald Assets from and after the Effective Time that were paid by Emerald (all to be apportioned as of the Effective Time except as otherwise provided);

(3)         With respect to the Liberty Assets Purchase Price, the Transfer Taxes paid by Liberty with respect to the transactions contemplated by this Agreement;

(4)         With respect to the Emerald Assets Purchase Price, the Transfer Taxes paid by Emerald with respect to the transactions contemplated by this Agreement;

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(5)         (i) With respect to the Liberty Assets Purchase Price, an amount equal to the unbilled costs, as of the date hereof, for the joint interest billings paid by Liberty on behalf of third party working interest owners in the Leases, Wells or Units that are contained within the Liberty Assets, and (ii) with respect to the Emerald Assets Purchase Price, an amount equal to the unbilled cost, as of the date hereof, for the joint interest billings paid by Emerald on behalf of third party working interest owners in the Leases, Wells or Units that are contained within the Emerald Assets;

(6)         an amount equal to the aggregate of the Title Benefit Amounts with respect to any Title Benefits; and

(7)         Any other amount agreed to by Emerald and Liberty.

(b)         Downward Adjustments. The Liberty Assets Purchase Price and the Emerald Assets Purchase Price, as applicable, shall be adjusted downward by the following:

(1)         An amount equal to the Title Defect Amounts for all Title Defect Properties to be delivered at Closing under Section 4.2(c)(1);

(2)         An amount equal to the Remediation Costs for all Environmental Defect Properties, which downward adjustment shall be made at Closing under Section 5.3(a);

(3)         An amount equal to the Allocated Values of all Transferor Assets excluded from this transaction under Sections 4.2(c)(2) and 5.3(b);

(4)         The Allocated Value of those Assets not conveyed at Closing due to the failure to obtain a Material Consent in accordance with Section 4.4(a), or the exercise of any preferential rights to purchase in accordance with Section 4.4(b);

(5)         (i) With respect to the Liberty Assets Purchase Price, any proceeds of Hydrocarbons produced from and after the Effective Time, net of royalties, overriding royalties, net profit payments and similar burdens and Production Taxes, received by Liberty between the Effective Time and Closing relating to the Liberty Assets, and (ii) with respect to the Emerald Assets Purchase Price, any proceeds of Hydrocarbons produced from and after the Effective Time, net of royalties, overriding royalties, net profit payments and similar burdens and Production Taxes, received by Emerald between the Effective Time and Closing relating to the Emerald Assets;

(6)         (i) With respect to the Liberty Assets Purchase Price, an amount equal to the revenue held in suspense by Liberty, as of the date hereof, for royalties, overriding royalties and similar leasehold burdens, and (ii) with respect to the Emerald Assets Purchase Price, an amount equal to the revenue held in suspense by Emerald, as of the date hereof, for royalties, overriding royalties and similar leasehold burdens; and

(7)         Any other amount agreed to by Emerald and Liberty.

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2.5          Proration of Costs and Revenues.

(a)          For purposes of determining the amounts of the adjustments to the Liberty Assets Purchase Price and Emerald Assets Purchase Price provided for in Section 2.4, the principles set forth in this Section 2.5(a) shall apply. Transferee shall be entitled to all production of Hydrocarbons from or attributable to the Leases, Lands, and Wells relating to those Assets of the Transferor at and after the Effective Time (and all products and proceeds attributable thereto), and to all other income, proceeds, receipts and credits earned with respect to such Assets at or after the Effective Time, and shall be responsible for (and entitled to any refunds with respect to) all Property Expenses relating to those Assets of the Transferor incurred at and after the Effective Time. Transferor shall be entitled to all Hydrocarbon production from or attributable to Leases, Lands, and Wells relating to those Assets of the Transferee prior to the Effective Time (and all products and proceeds attributable thereto), and to all other income, proceeds, receipts and credits earned with respect to such Assets prior to the Effective Time, and shall be responsible for (and entitled to any refunds with respect to) all Property Expenses relating to those Assets of the Transferor incurred prior to the Effective Time. “Earned” and “incurred”, as used in the Agreement shall be interpreted in accordance with generally accepted accounting principles and Council of Petroleum Accountants Society standards, and expenditures that are incurred pursuant to an operating agreement, unit agreement or similar agreement shall be deemed incurred when expended by the operator of the applicable Lease, Land or Well, in accordance with the applicable Transferor’s then current practice. For purposes of allocating production (and accounts receivable with respect thereto), under this Section 2.5(a), (i) liquid Hydrocarbons shall be deemed to be “from or attributable to” the Leases, Lands, and Wells when they pass through the inlet flange of the pipeline connecting into the storage facilities into which they are run or, if there are no such storage facilities, when they pass through the LACT meters or similar meters at the initial point of entry into the pipelines through which they are transported from the field, and (ii) gaseous Hydrocarbons shall be deemed to be “from or attributable to” the Leases, Lands, and Wells when they pass through the royalty measurement meters, delivery point sales meters or custody transfer meters on the gathering lines or pipelines through which they are transported (whichever meter is closest to the well). Transferor shall utilize reasonable interpolative procedures, consistent with industry practice, to arrive at an allocation of production when exact meter readings or gauging and strapping data are not available.

(b)          Should Transferee receive after Closing any proceeds, income or other amounts to which Transferor is entitled under Section 2.5(a), Transferee shall fully disclose, account for and promptly remit the same to Transferor. If, after Closing, Transferor receives any proceeds, income or other amounts to which Transferor is not entitled pursuant to Section 2.5(a), Transferor shall fully disclose, account for, and promptly remit the same to Transferee.

(c)          Should Transferee pay after Closing any Property Expenses for which Transferor is responsible under Section 2.5(a), Transferor shall reimburse Transferee promptly after receipt of an invoice with respect to such Property Expenses, accompanied by copies of the relevant vendor or other invoice and proof of payment. Should Transferor pay after Closing any Property Expenses for which Transferor is not responsible under Section 2.5(a), Transferee shall reimburse Transferor promptly after receipt of an invoice with respect to such Property Expenses, accompanied by copies of relevant vendor or other invoice and proof of payment.

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(d)          After Closing, Transferee shall handle all joint interest audits and other audits of Property Expenses covering the period for which Transferor is in whole or in part responsible under Section 2.5(a), provided that Transferee shall not agree to any adjustments to previously assessed costs for which Transferor is liable without the prior written consent of Transferor. Transferee shall provide Transferor with a copy of all applicable audit reports and written audit agreements received by Transferee and relating to periods for which Transferor is wholly or partially responsible.

2.6           Escrow Amount. The Escrow Amount, from time to time, together with the interest earned thereon, shall be deposited and held in an escrow account and paid out by an “Escrow Agent” in accordance with the provisions of this Section 2.6 and an escrow agreement to be agreed upon by the Parties (the “Escrow Agreement”) if such Escrow Agreement is necessary under Articles 4 or 5 upon final resolution of any Title Disputed Matters or any Environmental Disputed Matters in accordance with Articles 4 and 5, respectively, and which Escrow Agreement will require the joint written instruction of the Parties to the Escrow Agreement for any distributions. The full amount of any Escrow Amount held under the Escrow Agreement shall be released upon final resolution of the Title Disputed Matter or any Environmental Disputed Matter underlying such Escrow Amount in accordance with Articles 4 and 5, respectively.

ARTICLE 3

Due Diligence Review

3.1           Due Diligence Review. Each of Liberty and Emerald will make their respective Records and Assets available to the other Party and its Representatives for inspection and review, at Transferee’s sole cost, to permit Transferee to perform its due diligence (“Due Diligence Review”) pursuant to the terms and conditions of Sections 3.2 and 3.3, respectively. The notices pertaining to the Due Diligence Review for the Notice of Defective Interest (as defined in Section 4.2(b)) and the Environmental Defect Notice (as defined in Section 5.2) must be received by Transferor no later than 5:00 p.m. Mountain Time on August 22, 2014 (the “Defect Notice Date”). Each of Liberty and Emerald shall be entitled to conduct its Due Diligence Review until the Defect Notice Date (such period from the Effective Date through the Defect Notice Date, the “Due Diligence Period”).

3.2           Access to Transferor Records. Upon reasonable advance notice, the Transferor will make the Transferor Records available to Transferee at the offices of Transferor during Transferor’s normal business hours to the extent the Transferor Records can be provided without unreasonable effort or expense and are not subject to non-disclosure or confidentiality obligations to a third party, so Transferee and its Representatives may conduct, during the Due Diligence Period, at Transferee’s sole risk and expense, on-site inspections of all or any portion of the Transferor Records.

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3.3         Access to the Transferor Assets.

(a)          Access.

(1)         To the extent that Transferor may do so as an operator or non-operator of Transferor Assets, Transferor will grant Transferee and its Representatives access to the Transferor Assets upon reasonable prior notice during Transferor’s normal business hours, so Transferee and its Representatives may conduct, during the Due Diligence Period, at Transferee’s sole risk and expense, on-site inspections and an ASTM Phase I environmental review of all or any portion of the Transferor Assets (each, an “Environmental Assessment”). Transferee shall not conduct an ASTM Phase II environmental assessment or any physical sampling, boring, drilling, or other invasive investigation activities without the prior notice and consent of Transferor, which consent Transferor may withhold in its sole and absolute discretion.

(2)          If Transferee or its agents prepares an Environmental Assessment of any Transferor Asset, Transferee agrees to keep such assessment confidential and to furnish final copies thereof to Transferor only upon request; provided, however, that to the extent Transferee reasonably believes based on the advice of legal counsel that disclosure to a Governmental Entity is required for any matter identified by an Environmental Assessment in order for Transferee to comply with Environmental Laws, Transferee may after prior written notice to Transferor containing a brief analysis of why such Transferee disclosure is required by the Environmental Laws, disclose such matter to the Governmental Entity to which notice is required. In connection with any on-site inspections, if any, prior to Closing, Transferee (1) agrees not to interfere with, and will cause its Representatives not to interfere with, the normal operation of the Transferor Assets, (2) agrees to comply with, and will cause its Representatives to comply with, all requirements of the operators of the Transferor Assets (to the extent such requirements are disclosed to Transferee prior to such on-site inspections) and (3) agrees to maintain adequate insurance and to confirm to Transferor that it and its Representatives are adequately insured.

(b)        Indemnity. Except to the extent caused by the gross negligence or willful misconduct of any member of the Transferor Indemnified Parties, Transferee waives, releases and agrees to defend, indemnify, and hold harmless the Transferor Indemnified Parties from and against any and all losses arising out of, resulting from, or relating to the access afforded to Transferee and its Representatives under this Agreement or the activities of Transferee and its Representatives related to such access or any Environmental Assessment; even if such Losses arise out of or result from the active, passive, concurrent, or comparative negligence, strict liability, or other fault or violation of Law of or by a member of the Transferor Indemnified Parties; provided, however, that such indemnity shall not extend to Remediation Costs required as a result of disclosure to a Governmental Entity pursuant to Section 3.3(a)(2).

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(c)        Clean-Up. As soon as is reasonably practicable following completion of Transferee’s due diligence, Transferee shall, at its sole cost and expense and without any cost or expense to the Transferor Indemnified Parties (1) repair all damage done to the Transferor Assets in connection with any Environmental Assessment, (2) restore the Transferor Assets to the approximate same or better condition in existence prior to commencement of any Environmental Assessment, and (3) remove all equipment, tools or other property brought onto the Transferor Assets in connection with any Environmental Assessment.

ARTICLE 4

TITLE MATTERS

4.1         Transferor’s Title.

(a)       Defensible Title. The term “Defensible Title” means such ownership of record to the Transferor Leases and Transferor Wells that is deducible from the applicable county, state and federal records such that a reasonably prudent person engaged in the business of the ownership, development and operation of oil and gas leaseholds and properties and having knowledge of all of the facts and their legal bearing would be willing to accept the same, and that, subject to and except for Permitted Encumbrances as defined in Section 4.1(b):

(1)         entitles Transferor to receive a share of the Hydrocarbons produced, saved and marketed from any Transferor Lease or Transferor Well throughout the duration of the productive life of such Transferor Lease or Transferor Well, only insofar as to the specified formation(s) shown on Exhibit A-1, Exhibit A-2, Exhibit B-1, or Exhibit B-2 for such Transferor Lease or Transferor Well, as applicable, and if there are no such specified formation(s), then as to all formations, after satisfaction of all royalties, overriding royalties, nonparticipating royalties, net profits interests or other similar burdens on or measured by production of Hydrocarbons (a “Net Revenue Interest”), of not less than the Net Revenue Interest share shown in Exhibit A-1 or Exhibit A-2, as applicable for such Transferor, for such Transferor Lease (on an 8/8ths basis), or Exhibit B-1 or Exhibit B-2, as applicable for such Transferor, for such Transferor Well;

(2)         obligates Transferor to bear a percentage of the costs and expenses for the maintenance, development, operation and the production relating to any Transferor Well throughout the productive life of such Transferor Well (“Working Interest”) not greater than the Working Interest shown in Exhibit B-1 or Exhibit B-2, as applicable for such Transferor, from the currently producing formations for such Transferor Well, without increase, except increases to the extent that they are accompanied by a proportionate increase in Transferor’s Net Revenue Interest;

(3)         enables such Transferor Lease to cover the Net Acre interest set forth in Exhibit A-1 or Exhibit A-2, as applicable for such Transferor, only insofar as to the specified formation(s) shown on Exhibit A-1 or Exhibit A-2 for such Transferor Lease, as applicable, and if there are no such specified formation(s), then as to all formations for such Transferor Lease; and

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(4)         is free and clear of Liens.

(b)          Permitted Encumbrances. The term “Permitted Encumbrances” shall mean:

(1)         lessors’ royalties, overriding royalties, net profits interests, production payments, reversionary interests and similar burdens if the net cumulative effect of such burdens does not operate to reduce the Net Revenue Interests below those set forth in Exhibit A-1 or Exhibit A-2, as applicable for such Transferor, for such Transferor Lease, or Exhibit B-1 or Exhibit B-2, as applicable for such Transferor, for such Transferor Well, only insofar as to the specified formation(s) shown on Exhibit A-1, Exhibit A-2, Exhibit B-1, or Exhibit B-2 for such Transferor Lease or Transferor Well, as applicable, and if there are no such specified formation(s), then as to all formations;

(2)         statutory Liens for taxes that are not yet due and payable or that are being contested in good faith in the normal course of business;

(3)         all rights to consent by, required notices to, filings with, or other actions by Governmental Entities, in connection with the conveyance of the applicable Transferor Asset if the same are customarily sought after such conveyance;

(4)         rights of reassignment contained in any Transferor Leases, or assignments thereof, providing for reassignment upon the surrender or expiration of any Transferor Leases;

(5)         easements, rights of way, servitudes, permits, surface leases and other rights with respect to surface operations, pipelines, grazing, logging, canals, ditches, reservoirs or the like, and easements for streets, alleys, highways, pipelines, telephone lines, power lines, railways and other easements and rights-of-way, on, over or in respect of any of the Transferor Assets or any restriction on access thereto that do not materially interfere with the operation of the affected Transferor Asset;

(6)         the terms and conditions of the Transferor Contracts listed in Exhibit C-1 or Exhibit C-2, as applicable for each Transferor, or any compulsory pooling order of the North Dakota Industrial Commission; provided, however, that the effect of any such items do not cause (i) the Net Revenue Interest to be less than as set forth in Exhibit A-1, Exhibit A-2, Exhibit B-1, or Exhibit B-2 respectively, only insofar as to the specified formation(s) shown on Exhibit A-1, Exhibit A-2, Exhibit B-1, or Exhibit B-2, as applicable, and if there are no such specified formation(s), then as to all formations, for the applicable Transferor Asset, or (ii) the Working Interest to be more than as set forth in in Exhibit B-1 or Exhibit B-2, as applicable, from the currently producing formations;

(7)         materialmen’s, mechanics’, operators’ or other similar Liens arising in the ordinary course of business (i) if such Liens have not been filed pursuant to Law and the time for filing such Liens has expired, (ii) if filed, such Liens have not yet become due and payable or payment is being withheld as provided by Law, or (iii) if their validity is being contested in good faith by appropriate action;

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(8)         such Title Defects as Transferee has waived;

(9)         any Liens or encumbrances burdening the Transferor Assets which will be released at or before Closing;

(10)        any defects, irregularities or deficiencies in title to easements, rights-of-way or surface use agreements that do not materially adversely affect the value of any Transferor Asset; and

(11)        all other Liens, contracts, agreements, instruments, obligations, defects and irregularities affecting the Transferor Assets that do not (or would not upon foreclosure or other enforcement) reduce the Net Revenue Interest set forth in Exhibit A-1, Exhibit A-2, Exhibit B-1, or Exhibit B-2 respectively, only insofar as to the specified formation(s) shown on Exhibit A-1, Exhibit A-2, Exhibit B-1, or Exhibit B-2, as applicable, and if there are no such specified formation(s), then as to all formations, nor prevent the receipt of proceeds of production therefrom, nor increase the share of costs above the Working Interest set forth in Exhibit B-1 or Exhibit B-2 respectively, from the currently producing formations, nor materially adversely interfere with or detract from the ownership, operation, value or use of the Transferor Assets.

4.2         Purchase Price Adjustment Procedures.

(a)          Title Defect. The term “Title Defect” means any Lien, obligation (including contract obligation), defect, or other matter (including without limitation a discrepancy in Net Revenue Interest or Working Interest) that causes the Transferor not to have Defensible Title to any Transferor Lease or Transferor Well. Notwithstanding the foregoing, the following shall not be considered Title Defects:

(1)         defects based solely on lack of information in connection with documents filed of record not contained in Transferor’s files;

(2)         defects in the chain of title consisting of the mere failure to recite marital status in a document or omissions of successions of heirship or estate proceedings, unless Transferee provides clear and convincing evidence that such failure or omission has resulted in another Person’s actual and superior claim of title to the relevant Transferor Asset;

(3)         defects arising out of lack of corporate or other entity authorization unless Transferee provides affirmative evidence that such corporate or other entity action was not authorized and results in another Person’s actual and superior claim of title to the relevant Transferor Asset;

(4)         defects arising out of lack of survey, unless a survey is expressly required by applicable Laws;

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(5)         Liens created under deeds of trust, mortgages and similar instruments by the lessor under a Transferor Lease covering the lessor’s surface and mineral interests in the land covered thereby which would customarily be accepted in taking oil and gas leases or purchasing undeveloped oil and gas leases and for which the lessee would customarily seek a subordination of such Lien to the oil and gas leasehold estate prior to conducting drilling activities on the Transferor Lease;

(6)         defects based on failure to record a Transferor Lease issued by the Bureau of Land Management or the North Dakota Board of University and School Lands, or any assignments of record title or operating rights in such Transferor Leases, in the real property, conveyance or other records of the county in which such Transferor Lease is located; and

(7)         defects that have been cured by applicable Laws of limitations, prescription or otherwise.

(b)          Notice of Defective Interest. On or before the Defect Notice Date, Transferee may formally advise Transferor in writing of any matters that in Transferee’s reasonable opinion constitute a Title Defect with respect to Transferor’s title to all or any portion of the Transferor Leases and Transferor Wells (“Notice of Defective Interests”). The Notice of Defective Interests shall be in writing and contain the following: (1) a clear, complete and accurate description of the alleged Title Defect(s), (2) the Transferor Leases or Transferor Wells (and the applicable zone(s) therein) affected by the alleged Title Defect(s) (each a “Title Defect Property”), (3) the Transferor Allocated Value of each Transferor Lease or Transferor Well subject to the alleged Title Defect(s), (4) supporting documents reasonably necessary for Transferor (as well as any title attorney or examiner hired by Transferor) to verify the existence of the alleged Title Defect(s), and (5) the amount by which Transferee reasonably believes the Transferor Allocated Value of each Title Defect Property is reduced by the alleged Title Defect(s) and the computations and information upon which Transferee’s belief is based. To give Transferor an opportunity to commence reviewing and curing Title Defects, Transferee agrees to give Transferor written notice of all Title Defects discovered by Transferee at the end of each calendar week during the Due Diligence Period; provided, however, any such written notice may be preliminary in nature and supplemented prior to the Defect Notice Date. Any matters that may otherwise constitute a Title Defect, but of which Transferor has not been notified by Transferee in accordance with this Section 4.2(b) prior to the Defect Notice Date, shall be deemed to have been waived by Transferee.

(c)          Remedies for Title Defects. Subject to (x) Transferor’s continuing right to title Dispute resolution under Section 4.3, (y) the Individual Title Threshold and (z) the Aggregate Title Deductible, in the event that any Title Defect timely asserted by Transferee in accordance with Section 4.2(b) actually exists and is not waived by Transferee or cured on or before Closing, the Transferor shall, with the prior written consent of Transferee, take one of the following options with respect to such Title Defect prior to Closing:

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(1)         Transferor may convey the Title Defect Property to Transferee at Closing and reduce the Transferor Purchase Price by the Title Defect Amount and retain the right to cure the Title Defect after Closing;

(2)         Transferor may exclude the Title Defect Property from the transaction and reduce the Transferor Purchase Price by an amount equal to the Transferor Allocated Value of the Title Defect Property; or

(3)         Transferor may convey the Title Defect Property to Transferee at Closing, make no adjustment to the Transferor Purchase Price, and indemnify Transferee against all Losses resulting from such Title Defect, pursuant to the terms and conditions of an indemnification agreement to be agreed to between the Parties.

In the event that the Transferor elects one of the remedies set forth in this Section 4.2(c) as of the Closing but the Transferee does not consent on or before Closing to such election, then the Parties will be deemed to have elected the remedy in Section 4.2(c)(2).

(d)          Title Defect Amount. The “Title Defect Amount” means the amount by which the Transferor Allocated Value of the Title Defect Property affected by such Title Defect is reduced as a result of the existence of such Title Defect and shall be determined in accordance with the following methodology, terms and conditions:

(1)         if Transferee and Transferor agree on the Title Defect Amount, that amount shall be the Title Defect Amount;

(2)         if the Title Defect is a Lien that is undisputed and liquidated in amount, then the Title Defect Amount shall be the amount of the payment necessary to remove such Title Defect from the Title Defect Property; and

(3)         if the Title Defect represents an obligation, encumbrance, burden or charge upon or other defect in title to the Title Defect Property of a type not described in subsections (1) or (2) above, the Title Defect Amount shall be determined by taking into account the following factors: (i) any discrepancy between (A) the Net Revenue Interest or Working Interest for any Title Defect Property and (B) the Net Revenue Interest or Working Interest stated in Exhibit A-1, Exhibit A-2, Exhibit B-1, or Exhibit B-2, respectively; (ii) the Transferor Allocated Value of the Title Defect Property; (iii) the portion of the Title Defect Property affected by the Title Defect; (iv) the legal effect of the Title Defect; (v) the values placed upon the Title Defect by Transferee and Transferor; (vi) any discrepancy between (A) the Net Acre interest covered by a Transferor Lease and (B) the Net Acre interest covered by such Transferor Lease stated in Exhibit A-1 or Exhibit A-2; and (vii) such other reasonable factors as are necessary to make a proper evaluation.

Notwithstanding anything to the contrary in this Agreement, the aggregate Title Defect Amounts attributable to the effects of all Title Defects upon any Title Defect Property shall not exceed the Transferor Allocated Value of the Title Defect Property.

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(e)          Title Threshold and Deductible. Notwithstanding anything to the contrary, (1) in no event shall there be any adjustments to the Transferor Purchase Price or other remedies provided by (i) Transferor for any individual Title Defect, or (ii) Transferee for any individual Title Benefit for which the Title Defect Amount or Title Benefit Amount, as applicable, does not exceed $50,000 (“Individual Title Threshold”); and (2) in no event shall there be any adjustments to the Transferor Purchase Price or other remedies provided by (i) Transferor for any Title Defect that exceeds the Individual Title Threshold or (ii) Transferee for any individual Title Benefit unless the Title Defect Amounts of all such Title Defects or Title Benefit Amounts of all such Title Benefits, in the aggregate, excluding any Title Defects cured by Transferor (with respect to Title Defects), exceeds a deductible in an amount equal to 2.5% of the Transferor Purchase Price (the “Aggregate Title Deductible”), after which point Transferor or Transferee shall be entitled to adjustments to the Transferor Purchase Price or other remedies only with respect to such Title Defects or Title Benefits, as applicable, in excess of such Aggregate Title Deductible.

(f)          Transferor’s Right to Cure.

(1)         Transferor shall have the right, but not the obligation, to attempt, at its sole cost, to cure or remove at any time prior to Closing any Title Defects of which it has been advised by Transferee.

(2)         Subject to the provisions of this Article 4, if there is a reduction in the Transferor Purchase Price pursuant to Section 4.2(c), then Transferor shall retain the right but not the obligation for 180 days after the Closing Date to attempt to cure any such Title Defects at Transferor’s sole cost. If Transferor cures any such Title Defect to Transferee’s reasonable satisfaction, then Transferee shall promptly pay Transferor the Title Defect Amount with respect to the Title Defect that is so cured.

(g)          Title Benefits. The term “Title Benefit” means any right, circumstance, or condition that operates to increase:

(1)         the Transferor’s Net Revenue Interest in any Transferor Lease or Transferor Well throughout the duration of the productive life of such Transferor Lease or Transferor Well, only insofar as to the specified formation(s) shown on Exhibit A-1, Exhibit A-2, Exhibit B-1, or Exhibit B-2 for such Transferor Lease or Transferor Well, as applicable, and if there are no such specified formation(s), then as to all formations, above the Net Revenue Interest share shown in Exhibit A-1 or Exhibit A-2, as applicable for such Transferor, for such Transferor Lease (on an 8/8ths basis), or Exhibit B-1 or Exhibit B-2, as applicable for such Transferor, for such Transferor Well, to the extent the same does not cause a greater than proportionate increase in Transferor’s Working Interest; or

(2)         the Transferor’s Net Acres in each such Transferor Lease above the Net Acres set forth in Exhibit A-1 or Exhibit A-2, as applicable for such Transferor, only insofar as to the specified formation(s) shown on Exhibit A-1 or Exhibit A-2 for such Transferor Lease, as applicable, and if there are no such specified formation(s), then as to all formations for such Transferor Lease.

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(h)          Title Benefit Notice. If Transferor or Transferee discovers any Title Benefit, then such Party may (but shall have no obligation to, other than with respect to any Title Benefit discovered by Transferee, with respect to which Transferee shall be obligated to) deliver to the other Party, prior to the Defect Notice Date, a notice with respect to such Title Benefit. The notice must be in writing and be asserted in good faith and include (1) a description of the Title Benefit, (2) the Transferor Leases and/or Transferor Wells affected by the Title Benefit, (3) the Transferor Allocated Values of the Transferor Leases and/or Transferor Wells subject to such Title Benefit, and (4) the amount by which Transferor or Transferee, as applicable, reasonably believes the Transferor Allocated Value of those Transferor Leases and/or Transferor Wells is increased by the Title Benefit, and the computations and information upon which such Party’s belief is based.

(i)          Title Benefit Amount. The amount by which the Transferor Allocated Value of any Transferor Lease or Transferor Well is increased as a result of the existence of a Title Benefit with respect thereto is the “Title Benefit Amount.” The Title Benefit Amount shall be determined in accordance with the same methodology, terms, and conditions for determining the Title Defect Amount.

4.3           Title Dispute Resolution. The Parties shall resolve Disputes concerning the following matters pursuant to this Section 4.3: (a) the existence and scope of a Title Defect, Title Benefit, Title Defect Amount, or Title Benefit Amount, (b) the Title Defect Amount or Title Benefit Amount of that portion of the Transferor Asset affected by a Title Defect or Title Benefit, respectively, and (c) the adequacy of Transferor’s Title Defect curative materials and Transferee’s reasonable satisfaction thereof (the “Title Disputed Matters”). The Parties agree to attempt to initially resolve all Disputes through good faith negotiations. If the Parties cannot resolve the Title Disputed Matters on or before Closing, then (y) with respect to all Title Defects subject to a Title Disputed Matter, the Transferor Purchase Price shall be reduced by the Allocated Value of the affected Transferor Asset and the Title Defect Property shall not be conveyed at Closing, and (z) with respect to all Title Benefits subject to a Title Disputed Matter, the Transferor Purchase Price shall not be adjusted at Closing but the Title Defect Property shall be conveyed at Closing, and, at Closing, Transferee shall pay the Title Escrow Amount to the Escrow Agent to be held as part of the Escrow Amount. The term “Title Escrow Amount” means (I) with respect to all Title Defects subject to a Title Disputed Matter, the Allocated Value of the affected Transferor Asset, and (II) with respect to all Title Benefits subject to a Title Disputed Matter, the Title Benefit Amount associated with such Title Benefit. Further, the Title Disputed Matters will be finally determined by binding arbitration before an independent arbitrator appointed by the Parties, who shall be an oil and gas title attorney licensed in North Dakota with a minimum of 10 years’ experience with title issues affecting the types of properties which are the subject of the Title Disputed Matters. The arbitrator shall employ such independent attorneys, petroleum engineers and/or other consultants as deemed necessary. On or before thirty (30) days after Closing, Transferee and Transferor shall present their respective positions in writing to the arbitrator, together with such evidence as each Party deems appropriate. The arbitrator shall be instructed to resolve the Dispute through a final decision within twenty (20) days after submission of the matters in Dispute and the final decision may be reflected in the Final Settlement Statement. Upon final resolution of any Title Disputed Matters with respect to any Title Defects that are subject to such Title Disputed Matters, the Parties shall make the election of remedies under Section 4.2(c) and take such further actions as are necessary to carry out such election including executing the Liberty Assignment or Emerald Assignment, as applicable, and delivering joint written instructions to the Escrow Agent directing the distribution of the Title Escrow Amount. Upon final resolution of any Title Disputed Matters with respect to any Title Benefits that are subject to such Title Disputed Matters, the Parties shall take such further actions as are necessary to carry out the arbitrator’s decision including executing the Liberty Assignment or Emerald Assignment, as applicable, and delivering joint written instructions to the Escrow Agent directing the distribution of the Title Escrow Amount. All of Transferor’s covenants under Article 8 will apply to the Title Defect Property until such time as the Parties have taken such actions as are required based on the arbitrator’s decision.

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4.4           Preferential Rights and Consents Except for Permitted Encumbrances, all preferential rights to purchase and consents to assign relating to the Assets are listed on Schedule 4.4. The remedies set forth in this Section 4.4 are the exclusive remedies under this Agreement for consents to assign and preferential rights to purchase that are disclosed on Schedule 4.4 or are discovered prior to Closing. A Transferor Asset affected by a Material Consent or preferential right to purchase that is outstanding at Closing shall be referred to as an “Affected Asset”.

(a)          Consents. Promptly after the date hereof, Transferor shall use commercially reasonable efforts to send notices to those Persons necessary to request all consents to assignment of the Assets. If prior to Closing, Transferor fails to obtain a consent to assign that would invalidate the conveyance of the Asset affected by the consent to assign or materially affect the value or use of the Asset (a “Material Consent”) and the failure to obtain such Material Consent has not been waived by Transferee, then Transferor shall retain the Affected Asset and the Transferor Purchase Price shall be reduced by the Transferor Allocated Value of the Affected Asset. If such Material Consent has been obtained as of the Final Settlement Date, Transferor shall convey the Affected Asset to Transferee effective as of the Effective Time and Transferee shall pay Transferor the Transferor Allocated Value of the Affected Asset in accordance with the terms and conditions of this Agreement. If such Material Consent has not been obtained as of the Final Settlement Date, the Affected Asset shall be permanently excluded from the sale and the Transferor Purchase Price shall be deemed to be permanently reduced by an amount equal to the Transferor Allocated Value of the Affected Asset. Transferee shall reasonably cooperate with Transferor in obtaining any Material Consent, including providing assurances of reasonable financial conditions, but Transferee shall not be required to expend funds or make any other type of financial commitments as a condition of obtaining such Material Consent.

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(b)          Preferential Purchase Rights.  Transferor shall use commercially reasonable efforts to give notices required in connection with preferential purchase rights prior to Closing.  If any preferential right to purchase any portion of the Assets is exercised prior to the Closing Date, then the Affected Assets shall be excluded from the sale and the Transferor Purchase Price shall be adjusted downward by an amount equal to the Transferor Allocated Value of such Affected Assets.  If by Closing, either (1) the time frame for the exercise of a preferential purchase right has not expired and Transferor has not received notice of an intent not to exercise or a waiver of the preferential purchase right, or (2) a third Person exercises its preferential right to purchase, but the time frame for consummation of the preferential purchase right has not expired prior to the Closing, then Transferor shall retain the Affected Assets and the Transferor Purchase Price shall be adjusted downward by an amount equal to the Transferor Allocated Value of such Affected Assets.  As to any Affected Assets retained by Transferor hereunder, following Closing if a preferential right to purchase is not consummated by the Final Settlement Date, then the Affected Asset shall be permanently excluded from the sale, and the Transferor Purchase Price shall be deemed to be permanently reduced by an amount equal to the Transferor Allocated Value of the Affected Asset, provided, however, that with respect to any Affected Assets retained by Transferor hereunder, if a preferential right to purchase is not consummated within the time frame specified in the preferential purchase right following Closing and before the Final Settlement Date, or if the time frame for exercise of the preferential purchase right expires without exercise after the Closing and before the Final Settlement Date, then Transferor shall promptly convey the Affected Assets to Transferee, effective as of the Effective Time, and Transferee shall pay the Transferor Allocated Value thereof pursuant to the terms of this Agreement.

ARTICLE 5

ENVIRONMENtAL MATTERS

5.1           Exclusive Remedy. This Article V shall be the exclusive right and remedy of Transferor with respect to the existence of any Condition or Transferee’s failure to comply with Environmental Laws with respect to the Transferor Assets.

5.2           Environmental Defect Notice. On or before the Defect Notice Date, Transferee may formally advise Transferor in writing of any matters that in Transferee’s reasonable opinion constitute an Environmental Defect (“Environmental Defect Notice”). The Environmental Defect Notice shall be in writing and contain the following: (a) a clear, complete and accurate description of the alleged Environmental Defect(s), (b) the Transferor Assets affected by the alleged Environmental Defect(s) (each an “Environmental Defect Property”), (c) the Transferor Allocated Value of each Environmental Defect Property, (d) supporting documents reasonably necessary for Transferor (as well as any consultant hired by Transferor) to verify the existence of the alleged Environmental Defect(s), and (e) an estimate of Remediation Costs and the amount by which Transferee reasonably believes the Transferor Allocated Value of each Environmental Defect Property is reduced by the alleged Environmental Defect(s) and the computations and information upon which Transferee’s belief is based.

5.3           Remedies for Environmental Defects. Subject to (x) Transferor’s continuing right to environmental Dispute resolution under Section 5.5, (y) the Individual Environmental Threshold as defined in Section 5.4 and (z) the Aggregate Environmental Deductible as defined in Section 5.4, in the event that any Environmental Defect timely asserted by Transferee in accordance with Section 5.2 actually exists and is not waived by Transferee or cured on or before Closing, the Transferor shall, with the prior written consent of Transferee, take one of the following options with respect to such Environmental Defect prior to Closing:

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(a)          Transferor may convey the Environmental Defect Property to Transferee at Closing and reduce the Transferor Purchase Price by the Remediation Costs of the Environmental Defect Property;

(b)          Transferor may exclude the Environmental Defect Property from the transaction and reduce the Transferor Purchase Price by an amount equal to the Transferor Allocated Value of the Environmental Defect Property; or

(c)          Transferor may convey the Environmental Defect Property to Transferee at Closing, make no adjustment to the Transferor Purchase Price, and indemnify Transferee against all Losses resulting from such Environmental Defect, pursuant to the terms and conditions of an indemnification agreement to be agreed to between the Parties.

In the event that the Transferor elects one of the remedies set forth in this Section 5.3 as of the Closing but the Transferee does not consent on or before Closing to such election, then the Parties will be deemed to have elected the remedy in Section 5.3(b).

5.4           Environmental Threshold; Deductible. Notwithstanding anything to the contrary, (a) in no event shall there be any adjustments to the Transferor Purchase Price or other remedies provided by Transferor for any individual Environmental Defect for which the Remediation Costs does not exceed $50,000 (“Individual Environmental Threshold”); and (b) in no event shall there be any adjustments to the Transferor Purchase Price or other remedies provided by Transferor for any Environmental Defect that exceeds the Individual Environmental Threshold unless the Remediation Costs of all Environmental Defects, in the aggregate, excluding any Environmental Defects cured by Transferor, exceed a deductible in an amount equal to 2.5% of the Transferor Purchase Price (the “Aggregate Environmental Deductible”), after which point Transferee shall be entitled to adjustments to the Transferor Purchase Price or other remedies only with respect to such Remediation Costs in excess of such Aggregate Environmental Deductible.

5.5           Environmental Dispute Resolution. The Parties shall resolve Disputes concerning the following matters pursuant to this Section 5.5: (a) the existence and scope of an Environmental Defect or the Remediation Costs, (b) the Remediation Costs of that portion of the Transferor Asset affected by an Environmental Defect and (c) the adequacy of Transferor’s cure of an Environmental Defect and Transferee’s reasonable satisfaction thereof (the “Environmental Disputed Matters”). The Parties agree to attempt to initially resolve all Disputes through good faith negotiations. If the Parties cannot resolve the Environmental Disputed Matters on or before Closing, then the Purchase Price shall be reduced by the Allocated Value of such Environmental Defect Property (such amount, the “Environmental Escrow Amount”), such Environmental Defect Property shall not be conveyed at Closing, and, at Closing, Transferee shall pay such Environmental Escrow Amount to the Escrow Agent as part of the Escrow Amount. The Environmental Disputed Matters will be finally determined by binding arbitration before an independent arbitrator appointed by the Parties, provided that the independent arbitrator shall be qualified by education, knowledge of, and experience with environmental defects affecting the types of properties which are subject to or relate to the disputed Environmental Defect or Environmental Disputed Matters. The arbitrator shall employ such independent attorneys and/or other consultants as the arbitrator deems necessary, with the costs of such employment to be shared equally by the Transferor and Transferee. On or before thirty (30) days after Closing, Transferor and Transferee shall present their respective positions in writing to the arbitrator, together with such evidence as each Party deems appropriate. The arbitrator shall be instructed to resolve the Dispute through a final decision within twenty (20) days after submission of the matters in dispute, and the final decision may be reflected in the Final Settlement Statement. Upon final resolution of any Environmental Disputed Matters with respect to any Environmental Defects that are subject to such Environmental Disputed Matters, the Parties shall make the election of remedies under Section 5.3 and take such further actions as are necessary to carry out such election including executing the Liberty Assignment or Emerald Assignment, as applicable, and delivering joint written instructions to the Escrow Agent directing the distribution of the Environmental Escrow Amount. All of Transferor’s covenants under Article 8 will apply to the Environmental Defect Property until such time as the Parties have taken such actions as are required based on the arbitrator’s decision.

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5.6         Transfer of Burgundy Wellbore Interests.

(a)          Notwithstanding any other provision of this Agreement, Emerald shall retain ownership, and shall not convey the Ron Burgundy 3-23-14H well identified on Exhibit A-1 together with (1) all associated facilities and equipment and (2) the applicable Leases in the unit for such well only insofar as such Leases cover the wellbore of such Well (such assets, properties, and wellbore interest in the Leases are, collectively, the “Burgundy Wellbore Interests”) to Liberty, and the Liberty Assumed Obligations shall not include any Obligations arising from or related to the Burgundy Wellbore Interests (the “Burgundy Liabilities”), unless and until the conditions set forth in this Section 5.6 are satisfied.

(b)          On or prior to the Final Settlement Date, Emerald shall take all action necessary and appropriate to Remediate the Burgundy Wellbore Interests to the extent required to comply with Environmental Laws and industry standards generally followed in the upstream oil extraction business in the Bakken formation. Emerald shall manage, supervise and administer the Remediation in accordance with industry standards generally followed in the upstream oil extraction business in the Bakken formation, and applicable Environmental Laws, including applicable regulations of the North Dakota Industrial Commission (“NDIC”), and Emerald shall provide Liberty prompt advance notice of the status, and intended plan, of the Remediation, and shall provide Liberty prompt notice of any notice from or discussions with the NDIC or any other Governmental Entity concerning the Remediation.

(c)          On or prior to the Final Settlement Date, Emerald shall obtain, at its sole cost and expense, a comprehensive waiver, release and settlement of claims in a form satisfactory to Liberty in its reasonable discretion, from each Person that owns surface rights on or adjacent to the Burgundy Wellbore Interests (each, a “Landowner Release”).

(d)          All expenses related to, arising from or incurred in connection with the Remediation or the Landowner Releases (collectively, the “Burgundy Remediation Costs”) shall be borne Emerald. Liberty shall not be required to pay or incur any cost or make any other type of financial or operational commitment in connection with the obligations of Emerald under this Section 5.6.

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(e)          If the Remediation is completed and the Landowner Releases are delivered on or prior to the Final Settlement Date, in each case, to the satisfaction of Liberty in its reasonable discretion (provided that Liberty shall not be permitted to assert it is dissatisfied with the completion of the Remediation if Liberty has received verbal or written notice from the NDIC and the North Dakota Department of Health, to the extent each such agency asserts jurisdiction over the Remediation, that the Burgundy Well is in compliance with applicable Environmental Laws and that no further action is required), then (1) Emerald shall convey to Liberty the Burgundy Wellbore Interests in exchange for the payment by Liberty of the Burgundy Property Expenses, and (2) Liberty shall assume the Burgundy Liabilities, including Environmental Liabilities associated with the Burgundy Wellbore Interests (but not including the payment of any Burgundy Remediation Costs).

(f)          If the Remediation is not completed or the Landowner Releases are not delivered on or prior to the Final Settlement Date, then unless Liberty delivers written notice electing to acquire the Burgundy Wellbore Interests within ten (10) days following the Final Settlement Date, the Burgundy Wellbore Interests shall be permanently excluded from the Emerald Assets acquired pursuant to this Agreement.

(g)          In no event shall any expenses incurred by Emerald be counted toward the Aggregate Environmental Deductible for purposes of Section 5.4.

ARTICLE 6

LIBERTY’S REPRESENTATIONS AND WARRANTIES

Except as set forth in the schedule delivered to Emerald prior to the execution of this Agreement setting forth specific exceptions to Liberty’s representations and warranties set forth in this Agreement (each section of which qualifies the correspondingly numbered representation and warranty by Liberty) (the “Liberty Disclosed Materials”), Liberty represents and warrants to Emerald as of the date hereof and as of the Closing Date as follows:

6.1           Organization and Standing. Each of Liberty Resources, Liberty Management and Liberty Bakken is a limited liability company duly formed, validly existing and in good standing under the Laws of the State of Delaware and is duly qualified to carry on its business in such other jurisdictions as may be necessary, except where the failure to be so qualified would not have a Material Adverse Effect.

6.2           Power. Liberty has all requisite limited liability company power and authority to carry on its business as presently conducted, to enter into this Agreement, and to perform its obligations hereunder. The execution and delivery of this Agreement does not, and the fulfillment of and compliance with the terms and conditions hereof will not, violate, or be in conflict with, any material provision of Liberty’s governing documents, or any judgment, decree, order, statute, rule or regulation applicable to Liberty.

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6.3           Authorization and Enforceability. Assuming the due authorization, execution and delivery by Emerald, this Agreement constitutes Liberty’s legal, valid and binding obligation, enforceable in accordance with its terms, subject, however, to the effects of bankruptcy, insolvency, reorganization, moratorium, fraudulent transfer and other Laws for the protection of creditors, as well as to general principles of equity, regardless whether such enforceability is considered in a proceeding in equity or at law.

6.4           Liability for Brokers’ Fees. Liberty has not incurred any liability, contingent or otherwise, for investment bankers’, brokers’ or finders’ fees relating to the transactions contemplated by this Agreement for which Emerald shall have any responsibility whatsoever.

6.5           Litigation. Except as provided on Schedule 6.5, there are no actions, suits or proceedings pending or, to the Knowledge of Liberty, threatened, against Liberty (with respect to the Liberty Assets) or any of the Liberty Assets, in any court or by or before any Governmental Entity that would have a Material Adverse Effect on Liberty (with respect to the Liberty Assets) or the Liberty Assets or impair Liberty’s ability to consummate the transactions contemplated by this Agreement and to assume the liabilities to be assumed by Liberty under this Agreement.

6.6           Material Agreements. Except for the Leases, Exhibit D-1 includes the following types of contracts (the “Liberty Material Agreements”) by which any of the Liberty Assets are bound as of the date hereof: (a) any agreement with any Affiliate of Liberty; (b) any agreement or contract for the sale, exchange, or other disposition of Hydrocarbons produced from or attributable to Liberty’s interest in the Liberty Assets or for the purchase, processing or transportation of any Hydrocarbons, in each case that is not cancelable without penalty or other payment on not more than ninety (90) days prior written notice; (c) any agreement of or binding upon Liberty to sell, lease, farmout, or otherwise dispose of any interest in any of the Liberty Assets after the date hereof, other than nonconsent penalties for nonparticipation in operations under operating agreements, conventional rights of reassignment arising in connection with Liberty’s surrender or release of any of the Liberty Assets; (d) any Tax partnership agreement of or binding upon Liberty affecting any of the Liberty Assets; and (e) any agreement that creates any area of mutual interest or similar provision with respect to the Liberty Assets. To Liberty’s Knowledge, Liberty is not (and to Liberty’s Knowledge, no other Person is) in material default (or with the giving of notice or the lapse of time or both, would not be in default) under any Liberty Material Agreement except as disclosed on Exhibit D-1. Prior to execution of this Agreement, Liberty has provided Emerald or made available to Emerald, true, correct and complete copies of the Liberty Material Agreements. To Liberty’s Knowledge, the Liberty Material Agreements are in full force and effect in accordance with their terms, are valid and binding obligations of Liberty, and to Liberty’s Knowledge, are enforceable in accordance with their terms, except as may be limited by bankruptcy, insolvency, reorganization, fraudulent transfer, moratorium and similar Laws affecting creditor’s rights generally and by equitable principles.

6.7           Capital Projects. Except as described on Schedule 6.7 (“Liberty Capital Expenditures”), (i) Liberty has incurred no expenses, and has made no commitments to make expenditures in connection with the ownership or operation of the Liberty Assets after the Effective Time (other than with respect to routine operations performed in the ordinary course of operating the existing Wells), which expenditures are, individually or in the aggregate, estimated to exceed five hundred thousand dollars ($500,000), net to Liberty’s interest, and (ii) no contractual obligations, proposals or authorities for expenditures are currently outstanding (whether made by Liberty or by any other party) to drill additional wells, or to deepen, plug back, rework any Well, to abandon any Well, or to conduct any other operation on the Liberty Assets for which the estimated cost exceeds five hundred thousand dollars ($500,000), net to Liberty’s interest.

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6.8           Taxes. All material Taxes pertaining to the Liberty Assets based on or measured by Liberty’s ownership of the Liberty Assets for all taxable periods prior to the taxable period in which this Agreement is executed that were required to be paid prior to the Effective Time have been paid. All income Taxes pertaining to Liberty’s ownership of the Liberty Assets that, if unpaid, could give rise to a Lien or other claim against any of the Liberty Assets have been properly paid. Liberty has not received written notice of any pending claim against or audit of Liberty from any taxing authority for the assessment of any material Tax pertaining to the Liberty Assets that, if unpaid, could give rise to a Lien or other claim against any of the Liberty Assets.

6.9           Audits. Except as provided on Schedule 6.9, there are no audits currently being conducted by Liberty of the joint account under any operating agreements related to the Liberty Assets nor are there any such audits of Liberty currently underway.

6.10         Judgments. There are no unsatisfied judgments or injunctions issued by a court of competent jurisdiction or other Governmental Entity outstanding against Liberty related to the Liberty Assets.

6.11         Compliance with Law And Government Authorizations. To Liberty’s Knowledge, the Liberty Assets are being operated in compliance with all applicable Laws except for such noncompliance that would not have, individually or in the aggregate, a Material Adverse Effect. Notwithstanding the foregoing, this Section 6.11 does not relate to Taxes or Environmental Laws, which are addressed in Section 6.8 and Article V, respectively.

6.12         Lease Status/Rentals/Royalties. To Liberty’s Knowledge, all rentals, royalties and operating expenses payable with respect to the Liberty Assets prior to the Effective Time, have been duly and properly paid in all material respects, except as would not, individually or in the aggregate, have a Material Adverse Effect. To Liberty’s Knowledge, there are no currently pending requests or demands for payments, adjustments of payments or performance pursuant to obligations under the Leases, to the extent that non-compliance with the forgoing would have a Material Adverse Effect on any of the Assets.

6.13         Well Status. Except as set forth in Schedule 6.13, to the Knowledge of Liberty, there are no wells located on the Liberty Assets that: (a) Liberty is obligated by Law or contract to currently plug and abandon; or (b) to the extent plugged and abandoned, have not been plugged in accordance with applicable material requirements of each Governmental Entity having jurisdiction over the Liberty Assets.

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6.14         Calls on Production. Except as set forth on Schedule 6.14, Liberty has not (i)  received any material advance, “take-or-pay” or other similar payments under production sales contracts that entitle the purchasers to “make up” or otherwise receive deliveries of Hydrocarbons without paying at such time the contract price therefore or (ii)  taken or received any amount of Hydrocarbons under any gas balancing agreements or any similar arrangements not accounted for in a purchase price adjustment that permit any Person thereafter to receive any portion of the interest of Liberty to “balance” any disproportionate allocation of Hydrocarbons. Except as set forth on Schedule 6.14, no Hydrocarbons attributable to the Liberty Assets are subject to a sales contract (other than contracts terminable on no more than thirty (30) days’ notice or in accordance with rights of termination by non-operators under the applicable joint operating agreement) and no Person has any call upon, option to purchase or similar rights with respect to the production from the Liberty Assets; production from the Liberty Assets is not bound by any gas dedications or subject to any monetary or in kind through-put fees or charges in connection with gathering or transportation; and the Liberty Assets are not bound by futures, hedge, swap, collar, put, call, floor, cap, option or other contracts that are intended to benefit from, relate to or reduce or eliminate the risk of fluctuations in the price of commodities, including Hydrocarbons, securities, foreign exchange rates or interest rates that will continue after Closing. To Liberty’s Knowledge, proceeds from the sale of oil, condensate, and gas from the Liberty Assets are being received by Liberty, as applicable, in a timely manner and are not being held in suspense for any reason.

6.15         Imbalances. There are no well or pipeline imbalances affecting the Liberty Assets.

6.16         No Other Representations or Warranties; Disclosed Materials. Except for the representations and warranties contained in this Article 6 (as qualified by the Liberty Disclosed Materials), neither Liberty nor any other Person makes (and Emerald is not relying upon) any other express or implied representation or warranty with respect to Liberty (including the value, condition or use of any Liberty Asset) or the transactions contemplated by this Agreement, and Liberty disclaims any other representations or warranties not contained in this Article 6, whether made by Liberty, any Affiliate of Liberty or any of their respective officers, directors, managers, employees or agents. The disclosure of any matter or item in the Liberty Disclosed Materials shall not be deemed to constitute an acknowledgment that any such matter is required to be disclosed or is material or that such matter would or would reasonably be expected to result in a Material Adverse Effect

6.17         Disclaimer. EXCEPT AS EXPRESSLY WARRANTED, REPRESENTED OR COVENANTED OTHERWISE IN THIS AGREEMENT OR IN THE SPECIAL WARRANTY OF TITLE CONTAINED IN THE ASSIGNMENT, WITHOUT LIMITING THE GENERALITY OF THE FOREGOING AND WITHOUT LIMITING IN ANY RESPECT EMERALD INDEMNIFIED PARTIES’ RIGHTS TO DEFENSE AND INDEMNIFICATION UNDER ARTICLE 14, LIBERTY EXPRESSLY DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS OR IMPLIED, AS TO (I) LIBERTY’S TITLE TO ANY OF THE LIBERTY ASSETS, (II) THE CONTENTS, CHARACTER OR NATURE OF ANY DESCRIPTIVE MEMORANDUM, OR ANY REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT, OR ANY GEOLOGICAL OR SEISMIC DATA OR INTERPRETATION, RELATING TO THE LIBERTY ASSETS, (III) THE QUANTITY, QUALITY OR RECOVERABILITY OF PETROLEUM SUBSTANCES IN OR FROM THE LIBERTY ASSETS, (IV) ANY ESTIMATES OF THE VALUE OF THE LIBERTY ASSETS OR FUTURE REVENUES GENERATED BY THE LIBERTY ASSETS, (V) THE PRODUCTION OF PETROLEUM SUBSTANCES FROM THE LIBERTY ASSETS, OR WHETHER PRODUCTION HAS BEEN CONTINUOUS OR IN PAYING QUANTITIES, (VI) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF THE LIBERTY ASSETS, OR (VII) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE OR COMMUNICATED TO EMERALD OR ITS AFFILIATES, OR ITS OR THEIR EMPLOYEES, AGENTS, CONSULTANTS, REPRESENTATIVES OR ADVISORS IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO, AND EXCEPT AS STATED IN THIS AGREEMENT, FURTHER DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS OR IMPLIED, OF MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE OR CONFORMITY TO MODELS OR SAMPLES OF MATERIALS OF ANY OF THE LIBERTY ASSETS, IT BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES THAT EMERALD SHALL BE DEEMED TO BE OBTAINING THE LIBERTY ASSETS IN THEIR PRESENT STATUS, CONDITION AND STATE OF REPAIR, “AS IS” AND “WHERE IS” WITH ALL FAULTS AND THAT EMERALD HAS MADE OR CAUSED TO BE MADE SUCH INSPECTIONS AS EMERALD DEEMS APPROPRIATE.

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6.18       Liberty’s Evaluation.

(a)          Review. Liberty is an experienced and knowledgeable investor in the oil and gas industry or is an owner of oil, gas and mineral properties and is aware of its risks. Liberty has been afforded the opportunity to examine the Records and materials made available to it by Emerald in Emerald’s offices with respect to the Emerald Assets. Liberty acknowledges that Emerald has not made any representations or warranties as to the Records or otherwise except as expressly and specifically provided herein and that Liberty may not rely on any of Emerald’s estimates with respect to reserves, the value of the Emerald Assets, projections as to future events or other internal analyses or forward looking statements.

(b)          Independent Evaluation. In entering into this Agreement, Liberty acknowledges and affirms that it has relied and will rely solely on the terms of this Agreement and upon its independent analysis, evaluation and investigation of, and judgment with respect to, the business, economic, legal, tax or other consequences of this transaction including without limitation its own estimate and appraisal of the extent and value of the Hydrocarbon reserves of the Emerald Assets.

ARTICLE 7

EMERALD’S REPRESENTATIONS AND WARRANTIES

Except as set forth in the schedule delivered to Liberty prior to the execution of this Agreement setting forth specific exceptions to Emerald’s representations and warranties set forth in this Agreement (each section of which qualifies the correspondingly numbered representation and warranty by Emerald)(the “Emerald Disclosed Materials”), Emerald represents and warrants to Liberty as of the date hereof and as of the Closing Date as follows:

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7.1           Organization and Standing. Emerald Oil is a corporation duly organized, validly existing and in good standing under the Laws of Delaware, (ii) Emerald WB is a limited liability company duly organized, validly existing and in good standing under the Laws of Colorado, and (iii) each of Emerald Oil and Emerald WB is duly qualified to carry on its business in such other jurisdictions as may be necessary, except where the failure to be so qualified would not have a Material Adverse Effect.

7.2           Power. Emerald has all requisite power and authority to carry on its business as presently conducted, to enter into this Agreement, and to perform its obligations hereunder. The execution and delivery of this Agreement does not, and the fulfillment of and compliance with the terms and conditions hereof will not, as of Closing, violate, or be in conflict with, any material provision of Emerald’s governing documents, or, to Emerald’s Knowledge, any judgment, decree, order, statute, rule or regulation applicable to Emerald.

7.3           Authorization and Enforceability. Assuming the due authorization, execution and delivery by Liberty, this Agreement constitutes Emerald’s legal, valid and binding obligation, enforceable in accordance with its terms, subject, however, to the effects of bankruptcy, insolvency, reorganization, moratorium and other Laws for the protection of creditors, as well as to general principles of equity, regardless whether such enforceability is considered in a proceeding in equity or at law.

7.4           Liability for Brokers’ Fees. Emerald has not incurred any liability, contingent or otherwise, for investment bankers’, brokers’ or finders’ fees relating to the transactions contemplated by this Agreement for which Liberty shall have any responsibility whatsoever.

7.5           Litigation. Except as provided on Schedule 7.5, there are no actions, suits, or proceedings pending or, to Emerald’s Knowledge, threatened against Emerald (with respect to the Emerald Assets) or any of the Emerald Assets, in any court or by or before any Governmental Entity that would have a Material Adverse Effect on Emerald (with respect to the Emerald Assets) or the Emerald Assets or impair Emerald’s ability to consummate the transactions contemplated by this Agreement and to assume the liabilities to be assumed by Emerald under this Agreement.

7.6           Financial Resources. Emerald has the financial resources available to consummate the transactions contemplated by this Agreement and to pay the Closing Amount and any and all fees and expenses incurred by Emerald in connection with the transactions contemplated by this Agreement.

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7.7           Material Agreements. Except for the Leases, Exhibit D-2 includes the following types of contracts (the “Emerald Material Agreements”) by which any of the Emerald Assets are bound as of the date hereof: (a) any agreement with any Affiliate of Emerald; (b) any agreement or contract for the sale, exchange, or other disposition of Hydrocarbons produced from or attributable to Emerald’s interest in the Emerald Assets or for the purchase, processing or transportation of any Hydrocarbons, in each case that is not cancelable without penalty or other payment on not more than ninety (90) days prior written notice, (c) any agreement of or binding upon Emerald to sell, lease, farmout, or otherwise dispose of any interest in any of the Emerald Assets after the date hereof, other than nonconsent penalties for nonparticipation in operations under operating agreements, conventional rights of reassignment arising in connection with Emerald’s surrender or release of any of the Emerald Assets; (d) any Tax partnership agreement of or binding upon Emerald affecting any of the Emerald Assets; and (e) any agreement that creates any area of mutual interest or similar provision with respect to the Emerald Assets. To Emerald’s Knowledge, Emerald is not (and to Emerald’s Knowledge, no other Person is) in material default (or with the giving of notice or the lapse of time or both, would not be in default) under any Emerald Material Agreement except as disclosed on Exhibit D-2. Prior to execution of this Agreement, Emerald has provided Liberty or made available to Liberty, true, correct and complete copies of the Emerald Material Agreements. To Emerald’s Knowledge, the Emerald Material Agreements are in full force and effect in accordance with their terms, are valid and binding obligations of Emerald, and to Emerald’s Knowledge, are enforceable in accordance with their terms, except as may be limited by bankruptcy, insolvency, reorganization, fraudulent transfer, moratorium and similar Laws affecting creditor’s rights generally and by equitable principles.

7.8           Capital Projects. Except as described on Schedule 7.8 (“Emerald Capital Expenditures”), (i) Emerald has incurred no expenses, and has made no commitments to make expenditures in connection with the ownership or operation of the Emerald Assets after the Effective Time (other than with respect to routine operations performed in the ordinary course of operating the existing Wells), which expenditures are, individually, or in the aggregate, estimated to cost exceeds five hundred thousand dollars ($500,000), net to Emerald’s interest, and (ii) no contractual obligations, proposals or authorities for expenditures are currently outstanding (whether made by Emerald or by any other party) to drill additional wells, or to deepen, plug back, rework any Well, to abandon any Well, or to conduct any other operation on the Emerald Assets for which the estimated cost exceeds five hundred thousand dollars ($500,000), net to Emerald’s interest.

7.9           Taxes. All material Taxes pertaining to the Emerald Assets based on or measured by Emerald’s ownership of the Emerald Assets for all taxable periods prior to the taxable period in which this Agreement is executed that were required to be paid prior to the Effective Time have been paid. All income Taxes pertaining to Emerald’s ownership of the Emerald Assets that, if unpaid, could give rise to a Lien or other claim against any of the Emerald Assets have been properly paid. Emerald has not received written notice of any pending claim against or audit of Emerald from any taxing authority for the assessment of any material Tax pertaining to the Emerald Assets that, if unpaid, could give rise to a Lien or other claim against any of the Emerald Assets.

7.10         Audits. Except as provided on Schedule 7.10, there are no audits currently being conducted by Emerald of the joint account under any operating agreements related to the Emerald Assets nor are there any such audits of Emerald currently underway.

7.11         Judgments. There are no unsatisfied judgments or injunctions issued by a court of competent jurisdiction or other Governmental Entity outstanding against Emerald related to the Emerald Assets.

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7.12         Compliance with Law And Government Authorizations. To Emerald’s Knowledge, the Emerald Assets are being operated in compliance with all applicable Laws except for such noncompliance that would not have, individually or in the aggregate, a Material Adverse Effect. Notwithstanding the foregoing, this Section 7.12 does not relate to Taxes or Environmental Laws, which are addressed in Section 7.9 and Article V, respectively.

7.13         Lease Status/Rentals/Royalties. To Emerald’s Knowledge, all rentals, royalties and operating expenses payable with respect to the Emerald Assets prior to the Effective Time, have been duly and properly paid in all material respects, except as would not, individually or in the aggregate, have a Material Adverse Effect. To Emerald’s Knowledge, there are no currently pending requests or demands for payments, adjustments of payments or performance pursuant to obligations under the Leases, to the extent that non-compliance with the forgoing would have a Material Adverse Effect on any of the Emerald Assets.

7.14         Well Status. Except as set forth in Schedule 7.14, to the Knowledge of Emerald, there are no wells located on the Emerald Assets that: (a) Emerald is obligated by Law or contract to currently plug and abandon; or (b) to the extent plugged and abandoned, have not been plugged in accordance with applicable material requirements of each Governmental Entity having jurisdiction over the Emerald Assets.

7.15         Calls on Production. Except as set forth on Schedule 7.15, Emerald has not (i)  received any material advance, “take-or-pay” or other similar payments under production sales contracts that entitle the purchasers to “make up” or otherwise receive deliveries of Hydrocarbons without paying at such time the contract price therefore or (ii)  taken or received any amount of Hydrocarbons under any gas balancing agreements or any similar arrangements not accounted for in a purchase price adjustment that permit any Person thereafter to receive any portion of the interest of Emerald to “balance” any disproportionate allocation of Hydrocarbons. Except as set forth on Schedule 7.15, no Hydrocarbons attributable to the Emerald Assets are subject to a sales contract (other than contracts terminable on no more than thirty (30) days’ notice or in accordance with rights of termination by non-operators under the applicable joint operating agreement) and no Person has any call upon, option to purchase or similar rights with respect to the production from the Emerald Assets; production from the Emerald Assets is not bound by any gas dedications or subject to any monetary or in kind through-put fees or charges in connection with gathering or transportation; and the Emerald Assets are not bound by futures, hedge, swap, collar, put, call, floor, cap, option or other contracts that are intended to benefit from, relate to or reduce or eliminate the risk of fluctuations in the price of commodities, including Hydrocarbons, securities, foreign exchange rates or interest rates that will continue after Closing. To Emerald’s Knowledge, proceeds from the sale of oil, condensate, and gas from the Emerald Assets are being received by Emerald, as applicable, in a timely manner and are not being held in suspense for any reason.

7.16         Imbalances. There are no well or pipeline imbalances affecting the Emerald Assets.

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7.17         No Other Representations or Warranties; Disclosed Materials. Except for the representations and warranties contained in this Article 7 (as qualified by the Emerald Disclosed Materials), neither Emerald nor any other Person makes (and Liberty is not relying upon) any other express or implied representation or warranty with respect to Emerald (including the value, condition or use of any Emerald Asset) or the transactions contemplated by this Agreement, and Emerald disclaims any other representations or warranties not contained in this Article 7, whether made by Emerald, any Affiliate of Emerald or any of their respective officers, directors, managers, employees or agents. Except for the representations and warranties contained in this Article 7 (as qualified by the Emerald Disclosed Materials), Emerald disclaims all liability and responsibility for any representation, warranty, projection, forecast, statement or information made, communicated or furnished (orally or in writing) to Liberty or any of its Affiliates or any of its officers, directors, managers, employees or agents (including any opinion, information, projection or advice that may have been or may be provided to Liberty by any director, officer, employee, agent, consultant or representative of Emerald or any of its Affiliates). The disclosure of any matter or item in the Emerald Disclosed Materials shall not be deemed to constitute an acknowledgment that any such matter is required to be disclosed or is material or that such matter would or would reasonably be expected to result in a Material Adverse Effect.

7.18         Disclaimer. EXCEPT AS EXPRESSLY WARRANTED, REPRESENTED OR COVENANTED OTHERWISE IN THIS AGREEMENT OR IN THE SPECIAL WARRANTY OF TITLE CONTAINED IN THE ASSIGNMENT, WITHOUT LIMITING THE GENERALITY OF THE FOREGOING AND WITHOUT LIMITING IN ANY RESPECT LIBERTY INDEMNIFIED PARTIES’ RIGHTS TO DEFENSE AND INDEMNIFICATION UNDER ARTICLE 14, EMERALD EXPRESSLY DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS OR IMPLIED, AS TO (I) EMERALD’S TITLE TO ANY OF THE ASSETS, (II) THE CONTENTS, CHARACTER OR NATURE OF ANY DESCRIPTIVE MEMORANDUM, OR ANY REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT, OR ANY GEOLOGICAL OR SEISMIC DATA OR INTERPRETATION, RELATING TO THE EMERALD ASSETS, (III) THE QUANTITY, QUALITY OR RECOVERABILITY OF PETROLEUM SUBSTANCES IN OR FROM THE EMERALD ASSETS, (IV) ANY ESTIMATES OF THE VALUE OF THE EMERALD ASSETS OR FUTURE REVENUES GENERATED BY THE EMERALD ASSETS, (V) THE PRODUCTION OF PETROLEUM SUBSTANCES FROM THE EMERALD ASSETS, OR WHETHER PRODUCTION HAS BEEN CONTINUOUS OR IN PAYING QUANTITIES, (VI) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF THE EMERALD ASSETS, OR (VII) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE OR COMMUNICATED TO LIBERTY OR ITS AFFILIATES, OR ITS OR THEIR EMPLOYEES, AGENTS, CONSULTANTS, REPRESENTATIVES OR ADVISORS IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO, AND EXCEPT AS STATED IN THIS AGREEMENT, FURTHER DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS OR IMPLIED, OF MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE OR CONFORMITY TO MODELS OR SAMPLES OF MATERIALS OF ANY OF THE EMERALD ASSETS, IT BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES THAT LIBERTY SHALL BE DEEMED TO BE OBTAINING THE EMERALD ASSETS IN THEIR PRESENT STATUS, CONDITION AND STATE OF REPAIR, “AS IS” AND “WHERE IS” WITH ALL FAULTS AND THAT LIBERTY HAS MADE OR CAUSED TO BE MADE SUCH INSPECTIONS AS LIBERTY DEEMS APPROPRIATE.

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7.19       Emerald’s Evaluation.

(a)          Review. Emerald is an experienced and knowledgeable investor in the oil and gas industry or is an owner of oil, gas and mineral properties and is aware of its risks. Emerald has been afforded the opportunity to examine the Records and materials made available to it by Liberty in Liberty’s offices with respect to the Liberty Assets. Emerald acknowledges that Liberty has not made any representations or warranties as to the Records or otherwise except as expressly and specifically provided herein and that Emerald may not rely on any of Liberty’s estimates with respect to reserves, the value of the Liberty Assets, projections as to future events or other internal analyses or forward looking statements.

(b)          Independent Evaluation. In entering into this Agreement, Emerald acknowledges and affirms that it has relied and will rely solely on the terms of this Agreement and upon its independent analysis, evaluation and investigation of, and judgment with respect to, the business, economic, legal, tax or other consequences of this transaction including without limitation its own estimate and appraisal of the extent and value of the Hydrocarbon reserves of the Liberty Assets.

ARTICLE 8
COVENANTS AND AGREEMENTS

8.1         Covenants and Agreements of Transferor. Transferor covenants and agrees with Transferee as follows:

(a)          Operations Prior to Closing. Except as otherwise consented to in writing by Transferee or provided in this Agreement, from the date of execution of this Agreement to the Closing Date, where Transferor is the operator, Transferor will operate the Assets or cause the Assets to be operated in a manner consistent in all material respects with past practice. From the date of execution of this Agreement to the Closing Date, Transferor shall pay or cause to be paid its proportionate share of all costs and expenses incurred in connection with such operations. Transferor will notify Transferee of capital expenditures anticipated to cost in excess of two hundred fifty thousand dollars ($250,000) per operation, net to Transferor’s interest, conducted on the Assets, exclusive of the Capital Projects listed on Schedule 6.7. All costs and expenses incurred by the Parties with respect to the Capital Projects will be apportioned between the Parties as of the Effective Time, with Transferee assuming all post-Effective Time costs and expenses and Transferor retaining all pre-Effective Time costs and expenses.

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(b)          Restriction on Operations. Subject to Section 8.1(a) and except as otherwise provided in this Section 8.1(b), unless Transferor obtains the prior written consent of Transferee to act otherwise, which consent shall not be unreasonably withheld, conditioned or delayed, Transferor will use commercially reasonable efforts within the constraints of the applicable operating agreements and other applicable agreements not to: (i) abandon any part of the Assets (except in the ordinary course of business, Leases that have terminated in the ordinary course of business based upon the expiration of their primary terms, or Leases that are no longer capable of production in paying quantities); (ii) except for the Capital Projects listed on Schedule 6.7 and operations consistent with the existing drilling plan attached hereto as Schedule 8.1(b), approve any operations on the Assets anticipated in any instance to cost more than two hundred fifty thousand dollars ($250,000) per activity, net to Transferor’s interest (excepting emergency operations required under presently existing contractual obligations, ongoing commitments under existing AFEs and operations undertaken to avoid a monetary penalty or forfeiture provision of any applicable agreement or order all of which shall be deemed to be approved, provided Transferor immediately notifies Transferee of any emergency operation or operation to avoid monetary penalty or forfeiture excepted herein); or (iii) convey or dispose of any part of the Assets (other than replacement of equipment or sale of Hydrocarbons produced from the Assets in the ordinary course of business).

(c)          Consents. For the purposes of obtaining the written consents for AFEs required in this Section 8.1, Liberty designates the following contact person: Paul Vitek, and Emerald designates the following contact person Ryan Smith, in each case, at the address and telephone number for Transferee set forth in Section 15.3. Such consents may be obtained in writing by overnight courier or given by .pdf or facsimile transmission.

(d)          Notices of Claims. Transferor shall promptly notify Transferee, if, between the date of execution of this Agreement and the Closing Date, Transferor receives verbal or written notice of any claim, suit, action or other proceeding or verbal or written notice of any material default under any Material Agreement affecting the Assets.

(e)          Notices of Changes in Unit Sizes. Transferor shall promptly notify Transferee, if, between the date of execution of this Agreement and the Closing Date, Transferor receives verbal or written notice of any purported change in drilling and spacing units, tract allocation, or other changes in pool or unit participation occurring by a Person other than the Transferor;

(f)          Suspense Accounts. Prior to Closing, Transferor will provide to Transferee (a) information regarding all of Transferor’s accounts holding moneys in suspense together with a written explanation (as contained in Transferor’s files) of why such moneys are held in suspense or other information identifying the proper disposition of such moneys and (b) Transferor’s division of interest and all supporting documentation regarding those royalty owners and working interest owners in the Leases for whom Transferor disburses proceeds of production. After Closing, Transferee shall be solely responsible for the proper distribution of such moneys held in suspense to the party or parties which or who are entitled to receive payment of the same, and hereby agrees to indemnify, defend and hold Transferor harmless from any Claims therefor.

8.2          Covenants and Agreements of Transferee. Transferee covenants and agrees with Transferor that Transferee shall use all reasonable efforts to assure that as of the Closing Date it will not be under any material legal or contractual restriction that would prohibit or delay the timely consummation of the transactions contemplated hereby.

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8.3          Covenants and Agreements of the Parties.

(a)          Communication Between the Parties Regarding Breach. If Transferee or Transferor acquires Knowledge during its due diligence that leads either Party to believe that the other Party has materially breached a representation or warranty under this Agreement, the non-breaching Party shall inform the alleged breaching Party in writing of such potential breach as soon as possible, but in any event, at or prior to Closing.

(b)          Casualty Loss. Prior to Closing, if a portion of the Assets is destroyed by fire or other casualty or if a portion of the Assets is taken or threatened to be taken in condemnation or under the right of eminent domain (“Casualty Loss”), Transferee shall not be obligated to purchase such Asset. If Transferee declines to purchase such Asset, the Purchase Price shall be reduced by the Allocated Value of such Asset. If Transferee elects to purchase such Asset, the Purchase Price shall be reduced by the estimated cost to repair such Asset (with equipment of similar utility), less all insurance proceeds which shall be payable to Transferee, up to the Allocated Value thereof (the reduction being the “Net Casualty Loss”). Transferor, at its sole option, may elect to cure such Casualty Loss and, in such event, Transferor shall be entitled to all insurance proceeds. If Transferor elects to cure such Casualty Loss, Transferor may replace any personal property that is the subject of a Casualty Loss with equipment of similar grade and utility, or replace any real property with real property of similar nature and kind if such property is acceptable to Transferee in its sole discretion. If Transferor elects to cure the Casualty Loss, Transferee shall purchase the affected Asset at Closing for the Allocated Value thereof.

(c)          Cooperation and Good Faith. Upon the terms and subject to the conditions set forth in this Agreement, Transferee and Transferor will use their respective reasonable efforts to take, or cause to be taken, all actions, and to do, or cause to be done, and to assist and cooperate with the other Party or Parties hereto in doing, all things reasonably necessary, proper or advisable to consummate and make effective, in the most expeditious manner practicable, the transactions, including using reasonable efforts to: (i) cause the conditions set forth in Article 10 to be satisfied and (ii) execute or deliver any additional instruments reasonably necessary to consummate the transactions contemplated by this Agreement and to fully carry out the purposes of this Agreement; provided, however, that the foregoing provisions of this Section 8.3(d) will not require (y) any Party to perform, satisfy or discharge any obligations of any other Party under this Agreement or otherwise or (z) Transferor or Transferee to pay any money or other consideration or grant forbearances to any third party in order to perform, satisfy or discharge any of its obligations under this Agreement.

(d)          Successor Operator. Promptly after Closing, Transferor shall send notices (in form mutually agreed to by Transferee) to co-owners, if any, of those Assets that Transferor currently operates stating that Liberty Management (in the case of Liberty) and Emerald WB (in the case of Emerald), is resigning as operator, effective upon the Closing Date, and providing notice that Transferee or one of its Affiliates shall become (or to the extent governed by an operating agreement or similar agreement, recommending that Transferee be elected) successor operator for the Assets operated by Transferor. Transferor makes no representations or warranties to Transferee as to the transferability of operatorship of any Assets which Transferor currently operates. Rights and obligations associated with operatorship of the Assets may be governed by operating agreements or similar agreements and will be decided in accordance with the terms of such agreements.

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ARTICLE 9

TAX MATTERS

9.1           Production Tax Liability. Subject to the treatment of ad valorem Taxes provided below, all Production Taxes shall be allocated between Transferor and Transferee as of the Effective Time for all taxable periods that include the Effective Time. All Production Taxes that are not ad valorem taxes shall be allocated to Transferor to the extent they relate to production prior to the Effective Time and to Transferee to the extent they relate to production on or after the Effective Time. No liability for Production Taxes shall duplicate an adjustment to the Liberty Assets Preliminary Adjusted Purchase Price or the Emerald Assets Preliminary Adjusted Purchase Price, as applicable, made pursuant to Section 2.4. Ad valorem Taxes for each assessment period shall be allocated to Transferor based on the percentage of the assessment period occurring before the Effective Time and to Transferee based on the percentage of the assessment period occurring on or after the Effective Time. Each Party shall promptly furnish to the other copies of any Production Tax assessments and statements (or invoices therefor from the operator of the applicable Assets) received by it to the extent such assessment, statement, or invoice relates to a Production Tax allocable to the other Party under this Section. Each Party shall timely pay all Production Taxes subject to allocation under this Section and shall furnish to the other Party evidence of such payment. The Parties shall estimate all Taxes (excluding Transferor’s income, franchise, or margin Taxes) attributable to the ownership or operation of the Assets to the extent they relate to the period on and after the Effective Time and through the date hereof and all Transfer Taxes and incorporate such estimates into the Preliminary Settlement Statement. The actual amounts (to the extent the actual amounts differ from the estimates included in the Preliminary Settlement Statement and are known at the time of the Final Settlement Statement) shall be accounted for in the Final Settlement Statement. If the actual amounts are not known at the time of the Final Settlement Statement, the amounts shall be re-estimated based on the best information available at the time of the Final Settlement Statement. When the actual amounts are known, Emerald and Liberty shall make such payments to the other (if any) as are necessary to effect the allocation of Taxes described in this Section 9.1.

9.2           Transfer Taxes. All sales, use or other Taxes (other than Taxes on gross income, net income or gross receipts) and duties, levies, recording fees or other governmental charges incurred by or imposed with respect to the property transfers undertaken pursuant to this Agreement (“Transfer Taxes”) shall be the responsibility of, and shall be paid by, Emerald provided that, in the event that Liberty pays any Transfer Tax, Emerald shall promptly reimburse Liberty for such payment (without duplication to any adjustment to the Liberty Assets Purchase Price or the Emerald Assets Purchase Price, as applicable). The Parties shall reasonably cooperate in taking steps that would minimize or eliminate any Transfer Taxes.

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9.3           Tax Reports and Returns. For Tax periods in which the Effective Time occurs, Transferor agrees to forward to Transferee within five (5) days of receipt copies of any Tax reports and returns received or filed by Transferor after Closing and provide Transferee with any information Transferor has that is reasonably necessary for Transferee to file any required Tax Return related to the Assets. Transferee agrees to file all Tax Returns and reports applicable to the Assets that Transferee is required to file after the Closing and, subject to the provisions of Section 9.1, to pay all required Production Taxes payable with respect to the Assets.

9.4           Tax Cooperation. The Parties shall cooperate fully as and to the extent reasonably requested by the other party, in connection with the filing of any Tax Returns and any audit, litigation or other proceeding (each, a “Tax Proceeding”) with respect to Taxes relating to or in connection with the Assets. Such cooperation shall include the retention and (upon the other Party’s request) the provision of such records and information which are reasonably relevant to any such Tax Return or Tax Proceeding and making employees available on a mutually convenient basis to provide additional information and explanation of any material provided hereunder.

ARTICLE 10

CONDITIONS PRECEDENT TO CLOSING

10.1       Liberty’s Conditions. The obligations of Liberty to consummate the transactions contemplated in this Agreement are subject, to the satisfaction (or waiver in writing by Liberty) at or prior to the Closing of the following conditions precedent:

(a)          All representations and warranties of Emerald contained in this Agreement will be true and correct in all material respects as of the Closing Date as though made on and as of the Closing Date (except to the extent such representations and warranties are made as of a specified date, in which case such representations and warranties shall be true and correct as of the specified date).

(b)          Emerald shall have performed and satisfied in all material respects all covenants and agreements required by this Agreement to be performed and satisfied by Emerald at or prior to the Closing.

(c)          No temporary restraining order, preliminary or permanent injunction, or other order issued by any court of competent jurisdiction or other legal restraint or prohibition preventing the consummation of the transactions contemplated by this Agreement will be in effect.

(d)          All authorizations, consents, orders, or approvals of, or declarations or filings with, or expirations of waiting periods imposed by, any Governmental Entity necessary for the consummation of the transactions contemplated by this Agreement will have been filed, occurred, or been obtained.

10.2        Emerald’s Conditions. The obligations of Emerald at the Closing are subject, at the option of Emerald, to the satisfaction or waiver at or prior to the Closing of the following conditions precedent:

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(a)          All representations and warranties of Liberty contained in this Agreement will be true and correct in all material respects as of the Closing Date as though made on and as of the Closing Date (except to the extent such representations and warranties are made as of a specified date, in which case such representations and warranties shall be true and correct as of the specified date).

(b)          Liberty shall have performed and satisfied in all material respects all covenants and agreements required by this Agreement to be performed and satisfied by Liberty at or prior to the Closing.

(c)          No temporary restraining order, preliminary or permanent injunction, or other order issued by any court of competent jurisdiction or other legal restraint or prohibition preventing the consummation of the transactions contemplated by this Agreement will be in effect.

(d)          All authorizations, consents, orders, or approvals of, or declarations or filings with, or expirations of waiting periods imposed by, any Governmental Entity necessary for the consummation of the transactions contemplated by this Agreement will have been filed, occurred, or been obtained.

ARTICLE 11

RIGHT OF TERMINATION

11.1       Termination. This Agreement may be terminated in accordance with the following provisions:

(a)          by mutual consent of Liberty and Emerald; or

(b)          by Liberty or Emerald if the Closing has not occurred on or before October 15, 2014 (the “Termination Date”); provided that the right to terminate this Agreement under this Section 11.1(b) shall not be available to the Party requesting termination if the Closing has failed to occur because of such Party’s breach of representation, warranty or covenant;

(c)          by Liberty or Emerald, if the sum of (i) the Title Defect Amounts and (ii) the Remediation Costs with respect to the Liberty Assets exceeds 15% of the Liberty Assets Purchase Price;

(d)          by Liberty or Emerald, if the sum of (i) the Title Defect Amounts and (ii) the Remediation Costs with respect to the Emerald Assets exceeds 15% of the Emerald Assets Purchase Price.

11.2       Liabilities Upon Termination.

(a)          Liberty’s Default. If Closing does not occur because of Liberty’s failure to act in good faith toward the consummation of the transaction, Emerald shall be entitled to, in its sole discretion, require that Liberty return the Exclusivity Payment as its sole remedy for Liberty’s failure.

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(b)          Other Termination; Specific Performance. If Closing does not occur because either Party has breached any representation, warranty or covenant set forth in this Agreement, and such breach has caused a failure of any condition in Section 10.1 or 10.2 to be satisfied, each Party shall be entitled to pursue any and all other rights and remedies to which such Party may be entitled at law or in equity, including without limitation the remedy of specific performance.

ARTICLE 12

CLOSING

12.1         Date of Closing. Subject to the satisfaction of the conditions to Closing set forth in Article 10, the “Closing” of the transactions contemplated hereby shall be held on September 2, 2014, or a later date prior to the Termination Date agreed to by Emerald and Liberty. The date the Closing actually occurs is called the “Closing Date.”

12.2         Place of Closing. Subject to the satisfaction of the conditions to Closing set forth in Article 10, the Closing shall be held at the offices of Davis Graham & Stubbs LLP at 9:00 a.m. Denver, Colorado time or at such other time and place as Emerald and Liberty may agree in writing.

12.3         Closing Obligations. Subject to the satisfaction of the conditions to Closing set forth in Article 10, at Closing, the following events shall occur, each being a condition precedent to the others and each being deemed to have occurred simultaneously with the others:

(a)          Liberty shall execute, acknowledge and deliver to Emerald (i) an Assignment, Bill of Sale and Conveyance of Liberty Assets effective as of the Effective Time substantially in the form of Exhibit E-1 (the “Liberty Assignment”) with a special warranty of title by, through and under Liberty but not otherwise and with no warranties, express or implied, as to the personal property, fixtures or condition of the Liberty Assets which are conveyed “as is, where is”; (ii) such other assignments, bills of sale, certificates of title, or deeds necessary to transfer the Liberty Assets to Emerald including, without limitation, federal and state forms of assignment; and (iii) an Assignment and Assumption Agreement in the form attached as Exhibit F-1 under which Emerald assigns and Liberty assumes Emerald’s interest in the Contracts in accordance with the terms of this Agreement;

(b)          Emerald shall execute, acknowledge and deliver to Liberty (i) an Assignment, Bill of Sale and Conveyance of Emerald Assets effective as of the Effective Time substantially in the form of Exhibit E-2 (the “Emerald Assignment”)with a special warranty of title by, through and under Emerald but not otherwise and with no warranties, express or implied, as to the personal property, fixtures or condition of the Emerald Assets which are conveyed “as is, where is”; (ii) such other assignments, bills of sale, certificates of title, or deeds necessary to transfer the Emerald Assets to Liberty including, without limitation, federal and state forms of assignment; and (iii) an Assignment and Assumption Agreement in the form attached as Exhibit F-2 under which Liberty assigns and Emerald assumes Liberty’s interest in the Contracts in accordance with the terms of this Agreement;

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(c)          Liberty and Emerald shall each deliver a certificate duly executed by an officer thereof confirming that the closing conditions set forth in Sections 10.1(a) and (b) and 10.2(a) and (b), respectively, have been satisfied;

(d)          Liberty and Emerald shall execute and deliver the Preliminary Settlement Statement;

(e)          Emerald shall cause the Closing Amount to be paid by wire transfer of immediately available funds;

(f)          Each Party shall execute, acknowledge and deliver transfer orders or letters in lieu thereof notifying all purchasers of production of the change in ownership of the Assets and directing all purchasers of production to make payment to Emerald or Liberty, as applicable, of proceeds attributable to production from the Assets;

(g)          Each Party shall execute and deliver to the other Party an affidavit of non-foreign status and no requirement for withholding under Section 1445 of the Code in the form of Exhibit G;

(h)          Each Party shall deliver, or cause to be delivered to the other Party, a recordable form of release of any pledges, mortgages, financing statements, fixture filings and security agreements, if any, affecting the Assets; and

(i)          Liberty and Emerald shall take such other actions and deliver such other documents as are contemplated by this Agreement.

ARTICLE 13

POST-CLOSING OBLIGATIONS

13.1       Post-Closing Adjustments.

(a)          Final Settlement Statements. As soon as practicable after the Closing, but in no event later than ninety (90) days after Closing, Liberty, with the assistance of Emerald’s staff and with access to such records as necessary, will cause to be prepared and delivered to Emerald, in accordance with customary industry accounting practices, (i) the final settlement statement (the “Final Settlement Statement”) setting forth each adjustment to the Liberty Assets Preliminary Adjusted Purchase Price and the Emerald Assets Preliminary Adjusted Purchase Price, respectively, in accordance with Section 2.4 and showing the calculation of such adjustments and the resulting final purchase price (the “Final Net Purchase Price”). As soon as practicable after receipt of the Final Settlement Statement but in no event later than on or before forty-five (45) days after receipt of such statement, Emerald shall deliver to Liberty a written report containing any changes that Emerald proposes to make to the Final Settlement Statement. Emerald’s failure to deliver to Liberty a written report detailing proposed changes to the Final Settlement Statement by that date shall be deemed an acceptance by Emerald of the Final Settlement Statement as submitted by Liberty. The Parties shall engage in good faith efforts to agree with respect to the changes proposed by Emerald, if any, no later than forty-five (45) days after Emerald’s delivery to Liberty of its proposed changes to the Final Settlement Statement. The date upon which such agreement is reached or upon which the Final Net Purchase Price is established shall be herein called the “Final Settlement Date.” If the Final Net Purchase Price is more than the Closing Amount, Emerald shall pay to Liberty the amount of such difference by wire transfer of immediately available funds no later than five (5) days after the Final Settlement Date. If the Final Net Purchase Price is less than the Closing Amount, Liberty shall pay the amount of such difference to Emerald by wire transfer in immediately available funds no later than five (5) days after the Final Settlement Date.

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(b)          Dispute Resolution. If the Parties are unable to resolve a dispute as to the Final Purchase Price within sixty (60) days after Emerald’s receipt of Liberty’s proposed Final Settlement Statement, the Parties shall submit the dispute to binding arbitration to be conducted in accordance with the provisions of Section 15.13.

13.2         Records. Transferor shall make the Records available for pick up by Transferee at Closing to the extent possible, but in any event, within thirty (30) days after Closing. Transferor may retain copies of the Records and Transferor shall have the right to review and copy the Records during standard business hours upon reasonable notice for so long as Transferee retains the Records. Transferee agrees that the Records will be maintained in compliance with all applicable Laws governing document retention.

13.3         Further Assurances. From time to time after Closing, each Party shall each execute, acknowledge and deliver to the other such further instruments and take such other action as may be reasonably requested in order to accomplish more effectively the purposes of the transactions contemplated by this Agreement.

13.4         Successor Operator. Promptly after Closing, Transferor shall send notices (in form mutually agreed to by Transferee) to co-owners, if any, of those Assets that Transferor currently operates stating that Transferor is resigning as operator, effective upon the Closing Date, and providing notice that Transferee shall become (or to the extent governed by an operating agreement or similar agreement, recommending that Transferee be elected) successor operator for the Assets operated by Transferor. Transferor makes no representations or warranties to Transferee as to the transferability of operatorship of any Assets which Transferor currently operates. Rights and obligations associated with operatorship of the Assets may be governed by operating agreements or similar agreements and will be decided in accordance with the terms of such agreements.

ARTICLE 14

INDEMNIFICATION

14.1         Emerald’s Assumption of Liabilities and Obligations Upon Closing, Emerald shall assume and pay, perform, fulfill and discharge all claims, costs, expenses, liabilities and obligations (“Obligations”) accruing or relating to the following, but not including the Retained Obligations: (a) ownership and operation of the Liberty Assets after the Effective Time including owning, developing, exploring, operating or maintaining the Liberty Assets or the producing, transporting and marketing of Hydrocarbons from the Liberty Assets, the payment of Property Expenses, the make-up and balancing obligations for overproduction of gas from the Wells, and all liability for royalty and overriding royalty payments and Production Taxes (allocated in accordance with Article 9) made with respect to the Liberty Assets; and (b) all Environmental Liabilities accruing or relating to the ownership or operation of the Liberty Assets, whether accruing before or after the Effective Time except to the extent that Liberty elects to indemnify Emerald against such Environmental Liabilities pursuant to Section 5.3 (subsections (a) and (b) of this Section 14.1, collectively, the “Emerald Assumed Liabilities”).

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14.2         Liberty’s Assumption of Liabilities and Obligations. Upon Closing, Liberty shall assume and pay, perform, fulfill and discharge all Obligations accruing or relating to the following, but not including the Retained Obligations: (a) ownership and operation of the Emerald Assets after the Effective Time including owning, developing, exploring, operating or maintaining the Emerald Assets or the producing, transporting and marketing of Hydrocarbons from the Emerald Assets, the payment of Property Expenses, the make-up and balancing obligations for overproduction of gas from the Wells, and all liability for royalty and overriding royalty payments and Production Taxes (allocated in accordance with Article 9) made with respect to the Emerald Assets; and (b) all Environmental Liabilities accruing or relating to the ownership or operation of the Emerald Assets, whether accruing before or after the Effective Time (except to the extent that Emerald elects to indemnify Liberty against such Environmental Liabilities pursuant to Section 5.3 (subsections (a) and (b) of this Section 14.2, collectively, the “Liberty Assumed Liabilities”); provided that the Liberty Assumed Liabilities shall not include the Burgundy Liabilities unless and until the conditions set forth in Section 5.6 are satisfied and the Burgundy Wellbore Interests are conveyed to Liberty.

14.3         Retained Obligations. Other than with respect to the Emerald Assumed Liabilities and the Liberty Assumed Liabilities, the treatment of which is set forth in Sections 14.1 and 14.2, each Party shall retain and shall pay, perform, fulfill and discharge all Obligations accruing or relating to the following (the “Retained Obligations”): (a) the ownership and operation of such Party’s Assets prior to the Effective Time including owning, developing, exploring, operating or maintaining such Assets or producing, transporting and marketing Hydrocarbons from such Assets, the payment of Property Expenses, the make-up and balancing obligations for overproduction of gas from the Wells, all liability for royalty and overriding royalty payments and Production Taxes (allocated in accordance with Article 11) made with respect thereto, (b) offsite disposal of Hazardous Materials by Transferor or its Affiliates prior to the Closing Date, and (c) with respect to Emerald, the Burgundy Liabilities, unless and until the conditions set forth in Section 5.6 are satisfied and the Burgundy Wellbore Interests are conveyed to Liberty.

14.4         Indemnification. After the Closing, Emerald and Liberty shall indemnify each other as follows:

(a)          Liberty’s Indemnification. Liberty shall defend, indemnify and save and hold harmless Emerald and its Affiliates and their respective members, managers, shareholders, officers, directors, employees and agents (the “Emerald Indemnified Parties”), from and against all Losses which arise directly or indirectly from or in connection with (i) the Liberty Assumed Liabilities, (ii) any breach by Liberty of any of Liberty’s representations and warranties contained in this Agreement or in the certificate delivered pursuant to Section 12.3, or (iii) any breach of Liberty’s covenants or agreements contained in this Agreement.

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(b)          Emerald’s Indemnification. Emerald shall defend, indemnify and save and hold harmless Liberty and its Affiliates and their respective members, managers, shareholders, officers, directors, employees and agents (the “Liberty Indemnified Parties”), from and against all Losses which arise directly or indirectly from or in connection with (i) the Emerald Assumed Liabilities, (ii) any breach by Emerald of any of Emerald’s representations and warranties contained in this Agreement or in the certificate delivered pursuant to Section 12.3, or (iii) any breach of Emerald’s covenants or agreements contained in this Agreement.

(c)          Limitations on Indemnity. Notwithstanding anything to the contrary set forth herein, each of Liberty and Emerald shall have no liability for indemnification hereunder or for any Losses pursuant to Section 14.4(a)(ii) or (b)(ii), as applicable, until the total of all Losses with respect to such matters exceed (i) with respect to Liberty’s obligations under Section 14.4(a)(ii), 2% of the Liberty Assets Purchase Price, and (ii) with respect to Emerald’s obligations under Section 14.4(b)(ii), 2% of the Emerald Assets Purchase Price (as to each of (i) and (ii), the “Deductible”), after which point the Emerald Indemnified Parties or the Liberty Indemnified Parties, as applicable, shall be entitled to indemnification only in excess of the Deductible. The aggregate liability of Liberty or Emerald, as applicable for indemnification pursuant to Section 14.4(a)(ii) or (b)(ii), as applicable, with respect to Losses suffered by the Emerald Indemnified Parties or the Liberty Indemnified Parties, as applicable shall not exceed (I) with respect to Liberty’s obligations under Section 14.4(a)(ii), 10% of the Liberty Assets Purchase Price, and (ii) with respect to Emerald’s obligations under Section 14.4(b)(ii), 10% of the Emerald Assets Purchase Price (as to each of (I) and (II), the “Cap”). Notwithstanding the foregoing, the Deductible and the Cap will not apply to a breach of the Fundamental Representations.

(d)          Notwithstanding anything to the contrary contained in this Agreement, from and after Closing, the Parties’ sole and exclusive remedy against each other with respect to breaches of the representations, warranties, covenants and agreements of the Parties contained in this Agreement is set forth in this Section 14.4, and if no such right of indemnification is expressly provided, then such claims are hereby waived to the fullest extent permitted by Law; provided however, that each Party shall retain the right to seek injunctive or other equitable relief, including specific performance for breaches of this Agreement. Except as set forth in the preceding sentence, upon Closing, each Party releases, remises, and forever discharges the other Party from any and all suits, legal or administrative proceedings, claims, demands, damages, Losses, costs, liabilities, interest, or causes of action whatsoever, in law or in equity, known or unknown, which such Parties might now or subsequently may have, based on, relating to, or arising out of this Agreement or such Party’s ownership, use, or operation of the Assets, or the condition, quality, status, or nature of the Assets, INCLUDING RIGHTS TO CONTRIBUTION OR COST RECOVERY UNDER THE COMPREHENSIVE ENVIRONMENTAL RESPONSE, COMPENSATION AND LIABILITY ACT OF 1980, AS AMENDED, BREACHES OF STATUTORY AND IMPLIED WARRANTIES, NUISANCE OR OTHER TORT ACTIONS, RIGHTS TO PUNITIVE DAMAGES, COMMON LAW RIGHTS OF CONTRIBUTION, ANY RIGHTS UNDER INSURANCE POLICIES ISSUED OR UNDERWRITTEN BY THE OTHER PARTY OR ANY OF ITS AFFILIATES, even if caused in whole or in part by the negligence (whether sole, joint, or concurrent), strict liability, or other legal fault of any released person, invitee, or third Person, and whether or not caused by a preexisting condition.

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(e)          EACH PARTY CONFIRMS THAT IT IS NOT RELYING ON ANY REPRESENTATION OR WARRANTY OTHER THAN THOSE EXPRESSLY SET FORTH IN THIS AGREEMENT, AND EACH PARTY ACKNOWLEDGES THAT THIS NO RELIANCE CONFIRMATION IS A MATERIAL INDUCEMENT TO THE OTHER PARTY’S WILLINGNESS TO ENTER INTO THIS AGREEMENT AND CONSUMMATE THE TRANSACTIONS CONTEMPLATED HEREBY.

14.5         Procedure. The indemnifications contained in Section 14.4 shall be implemented as follows:

(a)          Claim Notice. The Party seeking indemnification under the terms of this Agreement (“Indemnified Party”) shall submit a written “Claim Notice” to the other Party (“Indemnifying Party”) which, to be effective, must be delivered prior to the end of the Survival Period applicable under Section 14.6 to the representation or warranty that is the subject of such Claim Notice and must state: (i) the amount of each payment claimed by an Indemnified Party to be owing, (ii) the basis for such claim, with supporting documentation, and (iii) a list identifying to the extent reasonably possible each separate item of Loss for which payment is so claimed. Unless, within sixty days of receipt of a Claim Notice, the Indemnifying Party provides written notice to the Indemnified Party that it contests the Losses identified in such Claim Notice, the Indemnifying Party shall, subject to the other terms of this Section 14.5, pay to the Indemnified Party the amount of the Losses related to such indemnification claim or the uncontested portion thereof. If the Indemnifying Party objects to a Claim Notice on the basis that it lacks sufficient information, it shall promptly request from the Indemnified Party any specific additional information reasonably necessary for it to assess such indemnification claim, and the Indemnified Party shall provide the additional information reasonably requested. Upon receipt of such additional information, the Indemnifying Party shall notify the Indemnified Party of any withdrawal or modification of the objection. All disputed indemnification claims shall be resolved by Emerald and Liberty in accordance with either (A) a mutual agreement between Emerald and Liberty, which shall be memorialized in writing, or (B) final arbitration in accordance with Section 15.13.

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(b)          Information. Promptly after the Indemnified Party receives notice of a claim or legal action by a third party that may result in a Loss for which indemnification may be sought under this Article 14 (a “Claim”), the Indemnified Party shall give written notice of such Claim to the Indemnifying Party. If the Indemnifying Party or its counsel so requests, the Indemnified Party shall furnish the Indemnifying Party with copies of all pleadings and other information with respect to such Claim. At the election of the Indemnifying Party made within sixty (60) days after receipt of such notice, the Indemnified Party shall permit the Indemnifying Party to assume control of such Claim (to the extent only that such Claim, legal action or other matter relates to a Loss for which the Indemnifying Party is liable), including the determination of all appropriate actions, the negotiation of settlements on behalf of the Indemnified Party, and the conduct of litigation through attorneys of the Indemnifying Party’s choice; provided, however, that no such settlement can result in any liability or cost to the Indemnified Party for which it is entitled to be indemnified hereunder without its consent. If the Indemnifying Party elects to assume control, (i) any expense incurred by the Indemnified Party thereafter for investigation or defense of the matter shall be borne by the Indemnified Party, and (ii) the Indemnified Party shall give all reasonable information and assistance, other than pecuniary, that the Indemnifying Party shall deem necessary to the proper defense of such Claim, legal action, or other matter. In the absence of such an election, the Indemnified Party will use its best efforts to defend, at the Indemnifying Party’s expense, any claim, legal action or other matter to which such other Party’s indemnification under this Article 14 applies until the Indemnifying Party assumes such defense, and, if the Indemnifying Party fails to assume such defense within the time period provided above, settle the same in the Indemnified Party’s reasonable discretion at the Indemnifying Party’s expense with the Indemnifying Party’s consent which shall not be unreasonably withheld. If such a Claim requires immediate action, both the Indemnified Party and the Indemnifying Party will cooperate in good faith to take appropriate action so as not to jeopardize defense of such Claim or either Party’s position with respect to such Claim. If the Indemnifying Party is entitled to, and does, assume the defense of any such Claim, the Indemnified Party shall have the right to employ separate counsel at its own expense and to participate in the defense thereof; provided, however, that notwithstanding the foregoing, the Indemnifying Party shall pay the reasonable attorneys’ fees of the Indemnified Party if the Indemnified Party’s counsel shall have advised the Indemnified Party that there is a conflict of interest that could make it inappropriate under applicable standards of professional conduct to have common counsel for the Indemnifying Party and the Indemnified Party (provided that the Indemnifying Party shall not be responsible for paying for more than one separate firm of attorneys and one local counsel to represent all of the Indemnified Parties subject to such Claim).

14.6         Survival of Warranties, Representations and Covenants. All representations and warranties contained in Articles 3 and 4 of this Agreement shall survive the Closing and remain in full force and effect until 5:00 p.m., Denver, Colorado time, on the date that is six (6) months after the date hereof, at which time they shall terminate, except that those representations and warranties set forth in Sections 6.1 (Status), 6.2 (Power) and 6.3 (Authorization and Enforceability) made by Liberty, and Sections 7.1 (Organization and Standing), 7.2 (Power) and 7.3 (Authorization and Enforceability) made by Emerald (those representations made by Liberty and Emerald, collectively the “Fundamental Representations”), will survive indefinitely (the applicable period, being referred to herein as the “Survival Period”). The covenants and performance obligations contained in this Agreement that contemplate performance after the Closing shall survive the Closing and shall continue until all obligations with respect thereto shall have been performed or satisfied or shall have been terminated in accordance with their terms. Both Parties acknowledge that the limitations on survival in this Section 14.6 are a contractual statute of limitations that limits such Party’s ability to make a claim against the other Party that such Party may otherwise have available under Law.

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14.7         Reservation as to Non-Parties. Nothing herein is intended to limit or otherwise waive any recourse Emerald or Liberty may have against any non-party for any obligations or liabilities that may be incurred with respect to the Assets.

14.8         Reductions in Losses. The amount of any Losses for which an Indemnified Person is entitled to indemnity under this Article 14 shall be reduced by the amount of insurance proceeds realized by the Indemnified Person or its Affiliates with respect to such Losses (net of any collection costs, and excluding the proceeds of any insurance policy issued or underwritten by the Indemnified Person or its insurance captive or other Affiliate), and by the amount of any net Tax benefit actually realized by either Party as a result of the events giving rise to the Losses in question.

14.9         Waiver. Neither Party shall have any obligation or liability under this Agreement or in connection with or with respect to the transactions contemplated by this Agreement for any breach, misrepresentation, or noncompliance with respect to any representation, warranty, covenant, indemnity, or obligation if such breach, misrepresentation, or noncompliance shall have been waived by the other Party, or if the other Party had knowledge of the relevant facts at or before Closing.

ARTICLE 15

MISCELLANEOUS

15.1         Exhibits and Schedules. The Exhibits and Schedules to this Agreement are hereby incorporated in this Agreement by reference and constitute a part of this Agreement.

15.2         Expenses. Except as otherwise specifically provided, all fees, costs and expenses incurred by Emerald or Liberty in negotiating this Agreement or in consummating the transactions contemplated by this Agreement shall be paid by the Party incurring the same, including, without limitation, engineering, land, title, legal and accounting fees, costs and expenses.

15.3         Notices. All notices and communications required or permitted under this Agreement shall be in writing and addressed as set forth below. Any communication or delivery hereunder shall be deemed to have been duly made and the receiving Party charged with notice (i) if personally delivered, when received, (ii) if sent by facsimile transmission, when received, (iii) if mailed, five (5) Business Days after mailing, certified mail, return receipt requested, or (iv) if sent by overnight courier, one (1) Business Day after sending. All notices shall be addressed as follows:

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If to Liberty:

Liberty Resources LLC
1200 17^th Street, Suite 2050
Denver, CO 80202
Attn: Paul Vitek
Telephone: (303) 749-5714
Fax: (303) 749-5759

With a copy to:

Davis Graham & Stubbs LLP
1550 17^th Street, Suite 500
Denver, CO 80202
Attn: Brian Boonstra
Telephone: (303) 892-7334
Fax: (303) 893-1379

If to Emerald:

Emerald Oil, Inc.
1600 Broadway, Suite 1360
Denver, CO 80202
Attn: Ryan Smith
Telephone: 303-595-5600

With a copy to:

Husch Blackwell LLP
1700 Lincoln, Suite 4700
Denver, CO 80203
Attn: James Muchmore
Telephone: 303-749-7264
Fax: 303-749-7272

Any Party may, by written notice so delivered to the other Party, change the address or individual to which delivery shall thereafter be made.

15.4         Amendments. This Agreement may not be amended except by an instrument expressly modifying this Agreement signed by each of the Parties. Except for waivers specifically provided for in this Agreement, no waiver by either Party of any breach of any provision of this Agreement shall be binding unless made expressly in writing. No waiver of any of the provisions of this Agreement shall be deemed or shall constitute a waiver of any other provision hereof (regardless of whether similar), nor shall any such waiver constitute a continuing waiver unless expressly so provided. Delay in the exercise, or non-exercise, of any such right is not a waiver of that right.

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15.5         Assignment. Neither Party shall assign all or any portion of its respective rights or delegate all or any portion of its respective duties hereunder without the written consent of the other Party.

15.6         Headings. The headings of the Articles and Sections of this Agreement are for guidance and convenience of reference only and shall not limit or otherwise affect any of the terms or provisions of this Agreement.

15.7         Counterparts/Fax Signatures. This Agreement may be executed and delivered in one or more counterparts, each of which when executed and delivered shall be an original, and all of which when executed shall constitute one and the same instrument. The exchange of copies of this Agreement and of signature pages by facsimile or by electronic image scan transmission in .pdf format shall constitute effective execution and delivery of this Agreement as to the Parties and may be used in lieu of the original Agreement for all purposes. Signatures of the Parties transmitted by facsimile or electronic image scan transmission in .pdf format shall be deemed to be their original signatures for all purposes. Any Party that delivers an executed counterpart signature page by facsimile or by electronic scan transmission in .pdf format shall promptly thereafter deliver a manually executed counterpart signature page to each of the other Parties; provided, however, that the failure to do so shall not affect the validity, enforceability, or binding effect of this Agreement.

15.8         Governing Law. This Agreement and the transactions contemplated hereby and any arbitration or dispute resolution conducted pursuant hereto shall be construed in accordance with, and governed by, the Laws of the State of Colorado, without regards to conflicts of Laws principles.

15.9         Entire Agreement. This Agreement constitutes the entire understanding among the Parties, their respective partners, members, trustees, shareholders, officers, directors and employees with respect to the subject matter hereof, superseding all negotiations, prior discussions and prior agreements and understandings relating to such subject matter, including the Term Sheet.

15.10         Binding Effect. This Agreement shall be binding upon, and shall inure to the benefit of, the Parties hereto, and their respective successors and assigns. Notwithstanding anything to the contrary herein, this Agreement is not a binding agreement between the Parties hereto unless and until this Agreement is duly executed in writing by representatives of the Parties and delivered by the Parties.

15.11         No Third-Party Beneficiaries. This Agreement is intended only to benefit the Parties hereto and their respective permitted successors and assigns

15.12         No Vicarious Liability. Emerald and Liberty shall not, and shall cause the Emerald Indemnified Parties and the Liberty Indemnified Parties not to, assert or threaten any claim or other method of recovery, in contract, in tort or under statute, against any Person other than Liberty or Emerald. Liberty and Emerald, as applicable shall be liable for all attorneys’ fees and court costs arising from a breach of this Section 15.12.

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15.13      Dispute Resolution and Arbitration. All Disputes between the Parties related to this Agreement shall be resolved by arbitration, pursuant to the following procedures:

(a)          The parties to any arbitration pursuant to this Section 15.13 shall select an arbitrator or arbitrators as follows:

(1)         Each side to such arbitration shall each select a single, independent arbitrator within ten (10) days after written demand for such arbitration by any Party. The two (2) arbitrators selected by the respective sides shall, in turn, select the third neutral and independent arbitrator. For any Dispute concerning Section 9.4 (with respect to the preparation of Tax Returns and the payment of Taxes), each of the three (3) arbitrators shall be a tax accountant with a minimum of ten years’ experience with the types of Taxes in question.

(b)          The arbitration shall be governed by Colorado Law but the specific procedure to be followed shall be determined by the arbitrator(s). It is the intent of the Parties that the arbitration be conducted as efficiently and inexpensively as possible, with only limited discovery as determined by the arbitrator without regard to the discovery permitted under the Colorado or Federal Rules of Civil Procedure.

(c)          The arbitration proceeding shall be held in the City and County of Denver, Colorado, and a hearing shall be held no later than sixty (60) days after submission of the matter to arbitration, and a written decision shall be rendered by the arbitrators within thirty (30) days of the hearing.

(d)          At the hearing, the Parties shall present such evidence and witnesses as they may choose, with or without counsel. Adherence to formal rules of evidence shall not be required but the arbitrator shall consider any evidence and testimony that he or she determines to be relevant, in accordance with procedures that it determines to be appropriate.

(e)          Any award entered in the arbitration shall be made by a written opinion stating the reasons and basis for the award made.

(f)          The costs incurred in employing the arbitrators, including the arbitrators’ retention of any independent qualified experts, shall be borne 50% by Liberty and 50% by Emerald.

(g)          The arbitrator’s award may be filed in any court of competent jurisdiction and may be enforced by any Party as a final judgment of such court.

(h)          IN ENTERING INTO THIS AGREEMENT, THE PARTIES ARE KNOWINGLY AND VOLUNTARILY WAIVING THEIR RIGHTS TO A TRIAL BY JURY.

15.14      Publicity. Neither Emerald or Liberty nor any of their respective Affiliates or representatives shall issue or cause the publication of any press release or other announcement with respect to the transactions contemplated by this Agreement without the prior consultation of the other Party, except as may be required by applicable Law, and each Party shall use its reasonable efforts to provide copies of such release or other announcement to the other Party hereto, and give due consideration to such comments as each such other Party may have, prior to such release or other announcement.

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15.15         Severability. Any provision of this Agreement which is prohibited or unenforceable in any jurisdiction will, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions of this Agreement, and any such prohibition or unenforceability in any jurisdiction will not invalidate or render unenforceable such provision in any other jurisdiction. Should any provision of this Agreement be or become invalid or unenforceable as a whole or in part, this Agreement shall be reformed to come closest to the original intent and purposes of the parties hereto.

15.16         Liberty Resources Guaranty. Liberty Resources hereby irrevocably and unconditionally guarantees the full and prompt payment and performance of all obligations of Liberty to pay any amounts and perform any obligations under this Agreement prior to or concurrent with the Closing when and if such payment as performance obligations become due and payable prior to or concurrent with the Closing in accordance with the terms of the Agreement. Liberty Resources acknowledges that valuable consideration supports this guaranty and that it executed this guaranty as an inducement to Emerald to enter into this Agreement and consummate the transactions contemplated herein on the terms and subject to the conditions contained herein.

[Signature page follows.]

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IN WITNESS WHEREOF, the Parties hereto have duly executed this Agreement as of the day and year first above written.

LIBERTY RESOURCES MANAGEMENT COMPANY, LLC
By:	/s/ Christopher A Wright
Name:	Christopher A Wright
Title:	CEO
LIBERTY RESOURCES BAKKEN OPERATING LLC
By:	/s/ Christopher A Wright
Name:	Christopher A Wright
Title:	CEO
EMERALD OIL, INC.
By:	/s/ McAndrew A. Rudisill
Name:	McAndrew A. Rudisill
Title:	CEO and President
EMERALD WB, LLC
By:	/s/ McAndrew A. Rudisill
Name:	McAndrew A. Rudisill
Title:	CEO

Executing this Agreement solely with
respect to Section 15.16 hereof:
LIBERTY RESOURCES II, LLC
By:	/s/ Christopher A Wright
Name:	Christopher A Wright
Title:	CEO

[Signature Page – Purchase and Sale Agreement]

EX-31.1

EXHIBIT 31.1

Certification Pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
(18 U.S.C. Section 7241)

I, McAndrew Rudisill, Chief Executive Officer, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Emerald Oil, Inc., referred to as the registrant;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions);

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

August 4, 2014	/s/ McAndrew Rudisill
	McAndrew Rudisill
	Chief Executive Officer
	(principal executive officer)

EX-31.2

EXHIBIT 31.2

Certification Pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
(18 U.S.C. Section 7241)

I, Paul Wiesner, Chief Financial Officer, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Emerald Oil, Inc., referred to as the registrant;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions);

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

August 4, 2014	/s/ Paul Wiesner
	Paul Wiesner
	Chief Financial Officer
	(principal financial officer)

EX-32.1

EXHIBIT 32.1

Certification Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
(18 U.S.C. Section 1350)

In connection with the accompanying quarterly report of Emerald Oil, Inc., referred to as the Company, on Form 10-Q for the period ended June 30, 2013, referred to as the report, I, McAndrew Rudisill, Chief Executive Officer of the Company, hereby certify that, to the best of my knowledge:

(a) the report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(b) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of the Company.

August 4, 2014	/s/ McAndrew Rudisill
	McAndrew Rudisill
	Chief Executive Officer
	(principal executive officer)

EX-32.2

EXHIBIT 32.2

Certification Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
(18 U.S.C. Section 1350)

In connection with the accompanying quarterly report of Emerald Oil, Inc., referred to as the Company, on Form 10-Q for the period ended June 30, 2014, referred to as the report, I, Paul Wiesner, Chief Financial Officer of the Company, hereby certify that, to the best of my knowledge:

(a) the report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(b) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of the Company.

August 4, 2014	/s/ Paul Wiesner
	Paul Wiesner
	Chief Financial Officer
	(principal financial officer)

XML

ASSET RETIREMENT OBLIGATION (Schedule of Change in Asset Retirement Obligation) (Details) (USD $)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013
Asset Retirement Obligation [Abstract]
Beginning Asset Retirement Obligation			$ 692,137	$ 296,074	$ 296,074
Revision of previous estimate					165,968
Liabilities Incurred or Acquired			515,199		510,271
Accretion of Discount on Asset Retirement Obligations	20,080	7,850	35,800	14,062	32,449
Liabilities Associated with Properties Sold					(312,625)
Ending Asset Retirement Obligation	$ 1,243,136		$ 1,243,136		$ 692,137

XML

DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT (Schedule of Reconciliation of the Changes in Fair Value of Commodity Derivatives) (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Derivative Instruments and Price Risk Management [Abstract]
Beginning fair value of commodity derivatives	$ (1,098,474)	$ (799,610)	$ (853,005)	$ (181,248)
Total gains (losses) on commodity derivatives	(6,663,083)	665,337	(7,461,936)	(102,267)
Cash settlements paid on commodity derivatives	1,908,756	183,539	2,462,140	332,781
Ending fair value of commodity derivatives	$ (5,852,801)	$ 49,266	$ (5,852,801)	$ 49,266

XML

STOCK OPTIONS AND WARRANTS (Schedule of Stock Options Outstanding Roll Forward) (Details) (USD $)	0 Months Ended		6 Months Ended
	Apr. 03, 2014	Jan. 10, 2014	Jun. 30, 2014
Deferred Compensation Arrangement With Individual Share Based Payments [Line Items]
Stock options outstanding at beginning of period (in Shares)			1,158,860
Stock options granted (in Shares)	255,499	295,800	551,299
Stock options canceled (in Shares)			(202,857)
Stock options exercised (in Shares)			(25,000)
Stock options outstanding at end of period (in Shares)			1,482,302
Stock options exercisable at end of period (in Shares)			482,360
Stock options outstanding weighted average exercise price at beginning of period (in Dollars per Share)			$ 8.90
Stock options granted weighted average exercise price (in Dollars per Share)	$ 6.69	$ 7.48	$ 7.11
Stock options canceled weighted average exercise price (in Dollars per Share)			$ 7.77
Stock options exercised weighted average exercise price (in Dollars per Share)			$ 4.43
Stock options outstanding weighted average exercise price at end of period (in Dollars per Share)			$ 7.33
Stock options exercisable, weighted average exercise price at end of period (in Dollars per Share)			$ 10.91

XML

DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT (Tables)

6 Months Ended

Jun. 30, 2014

Derivative Instruments and Price Risk Management [Abstract]

Schedule of Open Commodity Swap Contracts

The following table reflects open commodity swap contracts as of June 30, 2014, the associated volumes and the corresponding weighted average NYMEX reference price:

Settlement Period	Oil (Bbls)		Fixed Price  Range
Oil Swaps
July 1, 2014 – December 31, 2014		61,330	$	90.00 – 93.00
July 1, 2014 – December 31, 2014		47,300		93.01 – 96.00
July 1, 2014 – December 31, 2014		503,970		96.01 – 99.00
July 1, 2014 – December 31, 2014		82,612		99.01 – 102.00
2014 Total/Average		695,212	$	96.70
January 1, 2015 – April 30, 2015		18,876	$	90.00 – 93.00
January 1, 2015 – April 30, 2015		93,100		93.01 – 96.00
January 1, 2015 – April 30, 2015		341,251		96.01 – 99.00
2015 Total/Average		453,227	$	96.24

Schedule of Reconciliation of Commodity Derivatives

The following table sets forth a reconciliation of the changes in fair value of the Company’s commodity derivatives for the three and six months ended June 30, 2014 and 2013.

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Beginning fair value of commodity derivatives	$	(1,098,474	)	$	(799,610	)	$	(853,005	)	$	(181,248	)
Total gains (losses) on commodity derivatives		(6,663,083	)		665,337			(7,461,936	)		(102,267	)
Cash settlements paid on commodity derivatives		1,908,756			183,539			2,462,140			332,781
Ending fair value of commodity derivatives	$	(5,852,801	)	$	49,266		$	(5,852,801	)	$	49,266

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FAIR VALUE (Schedule of Fair Value of Financial Instruments Measured on Recurring Basis) (Details) (USD $)	Jun. 30, 2014	Dec. 31, 2013
Quoted Prices In Active Markets for Identical Assets (Level 1) [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Warrant Liability - Long Term Liability
Commodity Derivatives - Current Liability (oil swaps)
Commodity Derivatives - Long Term Asset (oil swaps)
Fair value, net asset (liability), total
Significant Other Observable Inputs (Level 2) [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Warrant Liability - Long Term Liability
Commodity Derivatives - Current Liability (oil swaps)	5,852,801	921,401
Commodity Derivatives - Long Term Asset (oil swaps)		68,396
Fair value, net asset (liability), total	5,852,801	(853,005)
Significant Unobservable Inputs (Level 3) [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Warrant Liability - Long Term Liability	(17,670,000)	(15,703,000)
Commodity Derivatives - Current Liability (oil swaps)
Fair value, net asset (liability), total	$ (17,670,000)	$ (15,703,000)

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CONVERTIBLE NOTES (Narrative) (Details) (Convertible Debt [Member], USD $)	6 Months Ended
	Jun. 30, 2014
Convertible Debt [Member]
Debt Instrument [Line Items]
Notes issuance date (Date)	Mar. 24, 2014
Notes, amount issued	$ 172,500,000
Notes stated percentage (in Percent)	2.00%
Notes maturity date (in Date)	Apr. 01, 2019
Private placement, proceeds	166,900,000
Period of amortization of note issuance costs to interest expense (in Duration)	5 years
Convertible notes, conversion rate, shares per $1,000 principal amount (in Shares)	$ 113.9601
Convertible notes, conversion rate, principal amount per 113.9601 shares	$ 1,000
Convertible notes, conversion rate, price per share (in Dollars per Share)	$ 8.78
Convertible notes, change purchase price percentage (in Percent)	100.00%
Convertible notes, event of default, percent of principal amount outstanding to be immediately due (in Percent)	25.00%

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SUBSEQUENT EVENTS (Narrative) (Details) (Subsequent Event [Member], USD $)	0 Months Ended
	Aug. 02, 2014 acre	May 01, 2014 Boe
Subsequent Event [Member]
Subsequent Event [Line Items]
Subsequent event, date (Date)	Aug. 01, 2014
Net acreage to be acquired under material definitive agreement entered into (in Acres)	31,500
Cash considertion to be paid for net acreage to be acquired under material definitive agreement entered into		$ 78,400,000
Acreage consideraton to be assigned for prospective acreage acquisition under material definative agreement (in Acres)	4,175
Net daily production from the acquired acreage (in Boe/day)		400

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RELATED PARTY TRANSACTIONS

6 Months Ended

Jun. 30, 2014

Related Party Transactions [Abstract]

RELATED PARTY TRANSACTIONS

NOTE 4  RELATED PARTY TRANSACTIONS

In February 2013, the Company entered into a securities purchase agreement (the “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, for an aggregate $50 million. Pursuant to the purchase agreement, White Deer Energy obtained the right to designate one member of the Company’s board of directors as long as White Deer Energy held any shares of Series A Preferred Stock. White Deer Energy designated Thomas J. Edelman as its initial director. Following the redemption of the Series A Preferred Stock, the Governance and Nominating Committee of the Company nominated Mr. Edelman to continue to serve as a director of the Company, and Mr. Edelman was elected to serve on the board of directors of the Company for another term at the annual stockholders meeting of the Company held in June 2014. For additional information regarding the Securities Purchase Agreement with White Deer Energy, see Note 5 — Preferred and Common Stock.

The transaction was subject to customary closing conditions, as well as the execution and delivery of certain other agreements, including a registration rights agreement. Under the terms of the registration rights agreement, as amended, the Company agreed to file with the Securities and Exchange Commission (the “SEC”), within 30 days upon receipt of notice from White Deer Energy, a shelf registration statement covering resales of the 5,114,633 shares of Company common stock issuable upon exercise of the warrants and use commercially reasonable efforts to cause such registration statement to be declared effective within 120 days after the filing thereof. In June 2013 and October 2013, the Company amended the registration rights agreement to include 2,785,600 shares of Company common stock and 5,092,852 shares of Company common stock, respectively, issued to White Deer Energy in connection with subsequent private placements. On April 19, 2014, the Company received a request from White Deer Energy to register the shares of Company common stock and the shares of Company common stock underlying the warrants held by White Deer Energy.  On May 16, 2014, the Company filed with the SEC a registration statement on Form S-3 to register for resale the 7,878,452 shares of common stock and 5,114,633 shares of common stock underlying the warrants held by White Deer, and the SEC declared the registration statement effective on May 30, 2014.

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FAIR VALUE (Schedule of Fair Value of Warrants Liability Measured on Recurring Basis, Unobservable Inputs) (Details) (USD $)	0 Months Ended	6 Months Ended	12 Months Ended
	Feb. 19, 2013	Jun. 30, 2014	Dec. 31, 2013
Rollforward of Level 3 warrants liability measured at fair value using level 3 on a recurring basis
Warrants liability, balance at beginning of period		$ 15,703,000	$ 0
Purchases, issuances, and settlements	8,626,000		(8,626,000)
Change in Fair Value of Warrant Liability		1,967,000	7,077,000
Warrants liability, balance at end of period		$ 17,670,000	$ 15,703,000

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PREFERRED AND COMMON STOCK (Narrative) (Details) (USD $)	0 Months Ended	3 Months Ended	6 Months Ended				3 Months Ended		6 Months Ended		0 Months Ended	3 Months Ended	6 Months Ended	0 Months Ended	6 Months Ended
	Feb. 19, 2013	Jun. 30, 2014	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013	Jun. 30, 2014 Restricted Stock Units [Member]	Jun. 30, 2014 Restricted Stock and Restricted Stock Units [Member]	Jun. 30, 2013 Restricted Stock and Restricted Stock Units [Member]	Jun. 30, 2014 Restricted Stock and Restricted Stock Units [Member]	Jun. 30, 2013 Restricted Stock and Restricted Stock Units [Member]	Feb. 19, 2013 Series A Preferred Stock [Member]	Jun. 30, 2014 Series A Preferred Stock [Member]	Jun. 30, 2013 Series A Preferred Stock [Member]	Feb. 19, 2013 Series B Preferred Stock [Member]	Jun. 30, 2014 Series B Preferred Stock [Member]
Schedule Of Capitalization Equity [Line Items]
Shares of stock issued in private placement (in Shares)											500,000			5,114,633
Warrants to purchase common stock issued in private placement (in Shares)	5,114,633
Exercise price of warrants issued in private placement (in Dollars per Unit)	5.77
Proceeds from issuance of equity in private placement	$ 50,000,000
Payment for redemption of stock				15,000,000							50,000,000
Preferred stock, redemption premium											6,250,000
Preferred stock - shares outstanding (in Shares)		5,114,633	5,114,633		5,114,633
Dividends paid		0	0									1,201,370	1,817,808
Dividend rights (in Dollars per Share)															$ 0
Liquidation preference (in Dollars per Share)															$ 0.001
Redemption price (in Dollars per Share)															$ 0.001
Share of common stock issuable under warrant issued as part of unit with each share of preferred stock (in Shares)															1
Investor option, under change of control or liquidating event, to receive cash payment in exchange for all then held stock for cash payment necessary for investor to achieve a minimum IRR, minimum IRR specified (in Percent)			25.00%
Additional cash payment remaining due upon a change of control or liquidating event		0	0
Fair value recognized from private placement, net of offering costs											38,552,994			5,000
Payments of stock issuance costs											2,816,006
Warrant liability recognized	8,626,000
Issuance discount outstanding		0	0
Share-Based Compensation Expense			6,678,883	2,365,797			2,746,344	876,427	6,206,274	1,789,725
Stock-based compensation, equity incentive plan, unvested shares (in Shares)						1,611,792
Unrecognized share-based compensation cost						5,962,785
Share-based compensation capitalized							$ 548,036	$ 51,148	$ 987,751	$ 89,102

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RELATED PARTY TRANSACTIONS (Narrative) (Details) (USD $)	0 Months Ended	1 Months Ended			0 Months Ended	1 Months Ended
	May 16, 2014	Oct. 31, 2013	Jun. 30, 2013	Feb. 28, 2013	May 16, 2014 White Deer Energy [Member]	Feb. 28, 2013 White Deer Energy [Member]
Related Party Transaction [Line Items]
Related party transaction, Series A Preferred stock issued (in Shares)						500,000
Related party transaction, Series B Preferred stock issued (in Shares)						5,114,633
Related party transaction, common stock purchasable with warrants issued (in Shares)				5,114,633
Related party transaction, initial exercise price of common stock purchasable with warrants issued (in Dollars per Share)				$ 5.77
Related party transaction, proceeds from the issuance of equity						$ 50,000,000
Related party transaction, number of board members purchaser obtained the right to designate (in Integer)						1
Related party transaction, period after notice receipt from related party within which company has agreed to file a shelf registration statement covering resale of common stock purchasable with warrant issue (in Duration)						30 days
Related party transaction, shares covered under shelf registration statement which company has agreed to file (in Shares)				5,114,633
Related party transaction, period over which Company has agreed to use commerically reasonable efforts to effect registration statement (in Duration)						120 days
Additional company shares included under amended registratration rights agreement (in Shares)		5,092,852	2,785,600
Related party transaction and company, shares registered for resale with the SEC under registration statement Form S-3 (in Shares)	7,878,452				5,114,633

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DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT (Narrative) (Details) (USD $)	0 Months Ended	6 Months Ended
	Feb. 19, 2013	Jun. 30, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments and Price Risk Management [Abstract]
Warrant liability recognized	$ 8,626,000
Warrants issued, price per warrant (in Dollars per Unit)	1.69
Expected volatility rate (in Percent)	40.00%	40.00%
Risk-free interest rate (in Percent)	1.38%	2.50%
Expected term (in Duration)	1798 days	1381 days
Exercise price of warrants (in Dollars per Unit)	$ 5.77	$ 5.77
Fair value of warrants		$ 17,670,000	$ 15,703,000	$ 0
Average stock price valuation assumption (in Dollars per Share)		$ 7.22

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PREFERRED AND COMMON STOCK (Schedule of Components of Preferred Stock Transaction) (Details) (USD $)	Jun. 30, 2014	Dec. 31, 2013
Total	$ 17,675,000	$ 15,708,000
Series B Voting Preferred Stock [Member]
Total	5,000	5,000
Warrant Liability [Member]
Total	$ 17,670,000	$ 15,703,000

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PREFERRED AND COMMON STOCK (Schedule of Restricted Stock Units and Restricted Stock Shares Outstanding) (Details) (USD $)	6 Months Ended
	Jun. 30, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Restricted stock units and restricted stock shares, Canceled (in Shares)
Non-vested restricted stock units, Weighted Average Grant Date Fair Value, Canceled (in Dollars per Share)
Restricted Stock Units and Restricted Stock Shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Non-vested restricted stock and restricted stock units, at beginning of period (in Shares)	2,082,187
Restricted stock units and restricted stock shares, Granted (in Shares)	264,134
Restricted stock units and restricted stock shares, Vested and forfeited for taxes (in Shares)	(293,813)
Restricted stock units and restricted stock shares, Vested and issued (in Shares)	(440,716)
Non-vested restricted stock and restricted stock units, at end of period (in Shares)	1,611,792
Non-vested restricted stock units, Weighted Average Grant Date Fair Value, at beginning of period (in Dollars per Share)	$ 5.73
Non-vested restricted stock units, Weighted Average Grant Date Fair Value, Granted (in Dollars per Share)	$ 7.48
Non-vested restricted stock units, Weighted Average Grant Date Fair Value, Vested and forfeited for taxes (in Dollars per Share)	$ 5.85
Non-vested restricted stock units, Weighted Average Grant Date Fair Value, Vested and issued (in Dollars per Share)	$ 5.85
Non-vested restricted stock units, Weighted Average Grant Date Fair Value, at end of period (in Dollars per Share)	$ 5.96

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OIL AND NATURAL GAS PROPERTIES

6 Months Ended

Jun. 30, 2014

Oil and Natural Gas Properties [Abstract]

OIL AND NATURAL GAS PROPERTIES

NOTE 3  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, the issuance of equity or debt securities and short-term borrowings under its revolving credit facility.

Acquisitions

In February 2014, the Company acquired approximately 19,500 net acres located in Williams and McKenzie Counties, North Dakota from an unrelated third party for approximately $69.2 million in cash. Net daily production from the acreage was approximately 300 Boe/d as of January 1, 2014, the effective date of the transaction. The acquisition was accounted for as an asset purchase. Related transaction costs were capitalized to oil and natural gas properties.

In February 2014, the Company acquired approximately 5,900 net acres of undeveloped leasehold located in McKenzie and Billings Counties, North Dakota from an unrelated third party for approximately $10.3 million in cash.

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STOCK OPTIONS AND WARRANTS (Narrative) (Details) (USD $)	0 Months Ended		6 Months Ended	12 Months Ended						3 Months Ended		6 Months Ended
	Apr. 03, 2014	Jan. 10, 2014	Jun. 30, 2014	Apr. 01, 2017	Jan. 10, 2017	Apr. 01, 2016	Jan. 10, 2016	Apr. 01, 2015	Jan. 10, 2015	Jun. 30, 2014 Stock Option [Member]	Jun. 30, 2013 Stock Option [Member]	Jun. 30, 2014 Stock Option [Member]	Jun. 30, 2013 Stock Option [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock options granted (in Shares)	255,499	295,800	551,299
Stock options granted weighted average exercise price (in Dollars per Share)	$ 6.69	$ 7.48	$ 7.11
Vesting period (in Duration)	36 months	36 months
Number of options vesting each period (in Shares)				85,166	98,600	85,166	98,600	85,166	98,600
Share based compensation, net of tax										$ 237,236	$ 181,384	$ 472,609	$ 576,072
Share based compensation, tax										0	0	0	0
Share-based compensation capitalized										187,357	159,563	408,611	221,161
Unrecognized compensation relating to options granted										$ 1,819,202		$ 1,819,202
Period for recognition of unrecognized compensation costs related to nonvested share based compensation (Duration)												1 year 5 months 9 days
Warrants expired or forfeited (in Shares)												0

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INCOME TAXES (Narrative) (Details) (USD $)	6 Months Ended	12 Months Ended
	Jun. 30, 2014	Dec. 31, 2013
Income Taxes [Abstract]
Deferred income tax provision or benefit	$ 0	$ 0
Unrecognized tax benefits	$ 0	$ 0

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) (USD $)	Jun. 30, 2014	Dec. 31, 2013
CURRENT ASSETS
Cash and Cash Equivalents	$ 134,171,667	$ 144,255,438
Restricted Cash	6,000,000	15,000,512
Accounts Receivable - Oil and Natural Gas Sales	9,352,780	8,715,821
Accounts Receivable - Joint Interest Partners	36,396,745	31,523,204
Other Receivables	1,600,141	577,409
Prepaid Expenses and Other Current Assets	534,430	206,299
Total Current Assets	188,055,763	200,278,683
Oil and Natural Gas Properties, Full Cost Method, at cost:
Proved Oil and Natural Gas Properties	378,486,735	211,015,067
Unproved Oil and Natural Gas Properties	122,067,454	57,015,315
Equipment and Facilities	4,109,546	1,837,744
Other Property and Equipment	1,645,303	890,811
Total Property and Equipment	506,309,038	270,758,937
Less - Accumulated Depreciation, Depletion and Amortization	(63,201,890)	(48,176,522)
Total Property and Equipment, Net	443,107,148	222,582,415
Restricted Cash	4,000,000	6,000,000
Fair Value of Commodity Derivatives		68,396
Debt Issuance Costs, Net of Amortization	6,204,848	475,157
Deposits on Acquisitions	304,335	125,368
Other Non-Current Assets	227,207	357,644
Total Assets	641,899,301	429,887,663
CURRENT LIABILITIES
Accounts Payable	91,416,789	63,168,422
Fair Value of Commodity Derivatives	5,852,801	921,401
Accrued Expenses	13,238,341	11,821,729
Advances from Joint Interest Partners	3,723,910	2,205,538
Total Current Liabilities	114,231,841	78,117,090
LONG-TERM LIABILITIES
Convertible Senior Notes	172,500,000
Asset Retirement Obligations	1,243,136	692,137
Warrant Liability	17,670,000	15,703,000
Other Non-Current Liabilities	265,660	56,327
Total Liabilities	305,910,637	94,568,554
COMMITMENTS AND CONTINGENCIES
Preferred Stock - Par Value $.001; 20,000,000 Shares Authorized;
Series B Voting Preferred Stock - 5,114,633 issued and outstanding at June 30, 2014 and December 31, 2013. Liquidation preference value of $5,115 as of June 30, 2014 and December 31, 2013.	5,000	5,000
STOCKHOLDERS' EQUITY
Common Stock, Par Value $.001; 500,000,000 Shares Authorized, 66,471,276 and 65,840,370 Shares Issued and Outstanding, respectively	66,471	65,840
Additional Paid-In Capital	420,571,408	416,301,344
Accumulated Deficit	(84,654,215)	(81,053,075)
Total Stockholders' Equity	335,983,664	335,314,109
Total Liabilities and Stockholders' Equity	$ 641,899,301	$ 429,887,663

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DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT (Schedule of Open Commodity Swap Contracts) (Details) (Oil [Member], Swap [Member])	6 Months Ended
	Jun. 30, 2014 bbl
Group 1 Settlement Period July 1, 2014 - December 31, 2014 [Member]
Derivative [Line Items]
Oil (Barrels)	61,330
Group 2 Settlement Period July 1, 2014 - December 31, 2014 [Member]
Derivative [Line Items]
Oil (Barrels)	47,300
Group 3 Settlement Period July 1, 2014 - December 31, 2014 [Member]
Derivative [Line Items]
Oil (Barrels)	503,970
Group 4 Settlement Period July 1, 2014 - December 31, 2014 [Member]
Derivative [Line Items]
Oil (Barrels)	82,612
2014 Total/Average [Member]
Derivative [Line Items]
Oil (Barrels)	695,212
Fixed Price (Dollars per Unit)	96.70
Group 1 Settlement Period January 1, 2015 - February 28, 2015 [Member]
Derivative [Line Items]
Oil (Barrels)	18,876
Group 2 Settlement Period January 1, 2015 - February 28, 2015 [Member]
Derivative [Line Items]
Oil (Barrels)	93,100
Group 3 Settlement Period January 1, 2015 - February 28, 2015 [Member]
Derivative [Line Items]
Oil (Barrels)	341,251
2015 Total/Average [Member]
Derivative [Line Items]
Oil (Barrels)	453,227
Fixed Price (Dollars per Unit)	96.24
Minimum [Member] | Group 1 Settlement Period July 1, 2014 - December 31, 2014 [Member]
Derivative [Line Items]
Fixed Price (Dollars per Unit)	90.00
Minimum [Member] | Group 2 Settlement Period July 1, 2014 - December 31, 2014 [Member]
Derivative [Line Items]
Fixed Price (Dollars per Unit)	93.01
Minimum [Member] | Group 3 Settlement Period July 1, 2014 - December 31, 2014 [Member]
Derivative [Line Items]
Fixed Price (Dollars per Unit)	96.01
Minimum [Member] | Group 4 Settlement Period July 1, 2014 - December 31, 2014 [Member]
Derivative [Line Items]
Fixed Price (Dollars per Unit)	99.01
Minimum [Member] | Group 1 Settlement Period January 1, 2015 - February 28, 2015 [Member]
Derivative [Line Items]
Fixed Price (Dollars per Unit)	90.00
Minimum [Member] | Group 2 Settlement Period January 1, 2015 - February 28, 2015 [Member]
Derivative [Line Items]
Fixed Price (Dollars per Unit)	93.01
Minimum [Member] | Group 3 Settlement Period January 1, 2015 - February 28, 2015 [Member]
Derivative [Line Items]
Fixed Price (Dollars per Unit)	96.01
Maximum [Member] | Group 1 Settlement Period July 1, 2014 - December 31, 2014 [Member]
Derivative [Line Items]
Fixed Price (Dollars per Unit)	93.00
Maximum [Member] | Group 2 Settlement Period July 1, 2014 - December 31, 2014 [Member]
Derivative [Line Items]
Fixed Price (Dollars per Unit)	96.00
Maximum [Member] | Group 3 Settlement Period July 1, 2014 - December 31, 2014 [Member]
Derivative [Line Items]
Fixed Price (Dollars per Unit)	99.00
Maximum [Member] | Group 4 Settlement Period July 1, 2014 - December 31, 2014 [Member]
Derivative [Line Items]
Fixed Price (Dollars per Unit)	102.00
Maximum [Member] | Group 1 Settlement Period January 1, 2015 - February 28, 2015 [Member]
Derivative [Line Items]
Fixed Price (Dollars per Unit)	93.00
Maximum [Member] | Group 2 Settlement Period January 1, 2015 - February 28, 2015 [Member]
Derivative [Line Items]
Fixed Price (Dollars per Unit)	96.00
Maximum [Member] | Group 3 Settlement Period January 1, 2015 - February 28, 2015 [Member]
Derivative [Line Items]
Fixed Price (Dollars per Unit)	99.00

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ORGANIZATION AND NATURE OF BUSINESS

6 Months Ended

Jun. 30, 2014

Organization and Nature of Business [Abstract]

ORGANIZATION AND NATURE OF BUSINESS

NOTE 1  ORGANIZATION AND NATURE OF BUSINESS

Description of Operations —  Emerald Oil, Inc., a Delaware corporation (“Emerald,” the “Company,” “we,” “us,” or “our”), is a Denver-based independent exploration and production company that is focused on acquiring acreage and developing wells in the Williston Basin of North Dakota and Montana. We believe the location, size and concentration of our acreage in our core project areas create an opportunity for us to achieve cost, recovery and production efficiencies through the large-scale development of our project inventory. The Company designs, drills and operates oil and natural gas wells on acreage where it holds a controlling working interest.

On June 11, 2014, the shareholders of the Company approved a measure to change our state of incorporation from Montana to Delaware. On June 11, 2014, the Company consummated a merger with our wholly owned subsidiary and, as a result, reincorporated as a Delaware corporation.

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STOCK OPTIONS AND WARRANTS (Schedule of Warrants Outstanding) (Details)			6 Months Ended
	Jun. 30, 2014	Feb. 19, 2013	Jun. 30, 2014 Issued December 1, 2009 [Member]	Jun. 30, 2014 Issued December 31, 2009 [Member]	Jun. 30, 2014 Issued February 8, 2011 [Member]	Jun. 30, 2014 Issued February 19, 2013 [Member]
Class of Warrant or Right [Line Items]
Warrants outstanding (in Shares)	6,230,784		37,216	186,077	892,858	5,114,633
Weighted-average exercise price of warrants outstanding (in Dollars per Unit)		5.77	6.86	6.86	49.70	5.77
Expiration date of warrants outstanding (in Date)			Dec. 01, 2019	Dec. 31, 2019	Feb. 08, 2016

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STOCK OPTIONS AND WARRANTS (Tables)

6 Months Ended

Jun. 30, 2014

Stock Options and Warrants [Abstract]

Schedule of Stock Options Granted, Valuation Assumptions

The total fair value of stock options granted during the three and six months ended June 30, 2014 was calculated using the Black-Scholes valuation model based on factors present at the time the options were granted. The following assumptions were used for the Black-Scholes model to value the options granted during the six-month period ended June 30, 2014.

Risk free rates	0.77% to 1.32%
Dividend yield	0%
Expected volatility	62.08% to 67.70%
Weighted average expected life	3.5 years

Schedule of Stock Options Outstanding Roll Forward

A summary of the stock options activity during the six months ended June 30, 2014 is as follows:

	Number of  Options			Weighted  Average  Exercise Price
Balance outstanding at January 1, 2014		1,158,860		$	8.90
Granted		551,299			7.11
Canceled		(202,857	)		7.77
Exercised		(25,000	)		4.43
Balance outstanding at June 30, 2014		1,482,302		$	7.33
Options exercisable at June 30, 2014		482,360		$	10.91

Schedule of Stock Options Outstanding

At June 30, 2014, 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
2014		529,499		4.64	$	7.11		—		—	$	—
2013		417,101		5.78		7.14		116,301		4.71		6.78
2012		407,142		2.78		7.66		237,499		2.57		7.53
Prior		128,560		1.64		20.90		128,560		1.64		20.90
Total		1,482,302		4.19	$	7.33		482,360		2.84	$	10.91

Schedule of Warrants Outstanding

Warrants

The table below reflects the status of warrants outstanding at June 30, 2014:

	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		892,858	$	49.70	February 8, 2016
February 19, 2013		5,114,633	$	5.77	December 31, 2019
Total		6,230,784

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REVOLVING CREDIT FACILITY (Narrative) (Details) (USD $)	6 Months Ended	3 Months Ended				6 Months Ended
	Jun. 30, 2014	Jun. 30, 2014 Wells Fargo Credit Agreement [Member] Minimum [Member] Alternate Base rate Under Credit Facility [Member]	Jun. 30, 2014 Wells Fargo Credit Agreement [Member] Minimum [Member] LIBOR Rate [Member]	Jun. 30, 2014 Wells Fargo Credit Agreement [Member] Maximum [Member] Alternate Base rate Under Credit Facility [Member]	Jun. 30, 2014 Wells Fargo Credit Agreement [Member] Maximum [Member] LIBOR Rate [Member]	Jun. 30, 2014 Wells Fargo Credit Agreement Letters of Credit [Member]	Jun. 30, 2014 Wells Fargo Credit Agreement Letters of Credit [Member] Minimum [Member]	Jun. 30, 2014 Wells Fargo Credit Agreement Letters of Credit [Member] Maximum [Member]
Line Of Credit Facility [Line Items]
Date credit facility was entered into (in Date)	Nov. 20, 2012
Maximum amount available under credit facility	$ 400,000,000					$ 5,000,000
Current borrowing base under credit facility	100,000,000
Maturity date of credit facility (in Date)	Sep. 30, 2018
Interest rate spread (in Percent)		0.75%	1.75%	1.75%	2.75%
Commitment fee percentage (in Percent)	0.50%
Interest rate per annum (in Percent)	0.375%						1.75%	2.75%
Fronting fee to be paid if this value exceeds point one two five percent of the face amount of the letter of credit to be issued						500
Fronting fee to be paid if this value times the Letter of credit face amount exceeds five hundred dollars (in Percent)						0.125%
Facility covenant, minimum current ratio (in Ratio)	1.00
Facility covenant, maximum debt to EBITDA (in percent)	3.50
Facility covenant, 2014 fiscal quarter applicability, amount of reduction to total debt is equal to value of cash equivalents less this amount	$ 10,000,000
Facility covenant, maximum amount of proved reserves permitted to be hedged for up to 24 months from facility initiation (in Percent)	60.00%
Facility covenant, maximum amount of proved reserves permitted to be hedged for 24 to 60 months from facility initiation (in Percent)	80.00%
Facility covenant, maximum value of proved reserves hedging as a percent of actual current period production (in Percent)	100.00%

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FAIR VALUE (Tables)

6 Months Ended

Jun. 30, 2014

Fair Value [Abstract]

Schedule of Fair Value of Financial Instruments Measured on 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 June 30, 2014:

	Fair Value Measurements at  June 30, 2014 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	$	—	$	—		$	(17,670,000	)
Commodity Derivatives – Current Liability (oil swaps)		—		(5,852,801	)		—
Total	$	—	$	(5,852,801	)	$	(17,670,000	)

15

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, 2013:

	Fair Value Measurements at  December 31, 2013 Using
	Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other  Observable Inputs  (Level 2)			Significant Unobservable  Inputs  (Level 3)
Warrant Liability – Long Term Liability	$	—	$	—		$	(15,703,000	)
Commodity Derivatives – Current Liability (oil swaps)		—		(921,401	)		—
Commodity Derivatives – Long Term Asset (oil swaps)		—		68,396			—
Total	$	—	$	(853,005	)	$	(15,703,000	)

Schedule of Fair Value of Warrants Liability Measured on Recurring Basis, Unobservable Inputs

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

Balance, at January 1, 2013	$	—
Purchases, issuances, and settlements		(8,626,000	)
Change in Fair Value of Warrant Liability		(7,077,000	)
Balance, at December 31, 2013		(15,703,000	)
Change in Fair Value of Warrant Liability		(1,967,000	)
Balance, at June 30, 2014	$	(17,670,000	)

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BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

6 Months Ended

Jun. 30, 2014

Basis of Presentation and Significant Accounting Policies [Abstract]

BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

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 June 30, 2014 and for the three and six months ended June 30, 2014 and 2013 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 June 30, 2014 and for the three and six months ended June 30, 2014 and 2013.

Interim financial results should be read in conjunction with the audited financial statements and footnotes for the year ended December 31, 2013, which were included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2013.

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.

Restricted Cash

Restricted cash included in current and long-term assets on the condensed consolidated balance sheets totaled $10 million and $21 million at June 30, 2014 and December 31, 2013, respectively.  At June 30, 2014, the $10 million balance related to a drilling commitment agreement entered into pursuant to oil and natural gas leases. As of December 31, 2013, there was an additional $11.0 million of restricted cash related to a portion of proceeds from a leasehold sale held in escrow until finalization of standard due diligence procedures. On February 21, 2014, $8.6 million was released to the Company, with the remaining $2.4 million returned to the buyer for purchase price adjustments.

Accounts Receivable

The Company records estimated oil and natural gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. Management periodically reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables under the specific identification method. The Company did not record any allowance for uncollectible receivables during the three and six months ended June 30, 2014 and 2013.

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 months ended June 30, 2014 and 2013, the Company capitalized $1,538,567 and $903,162, respectively, of internal salaries, which included $735,393, and $210,712, respectively, of stock-based compensation. For the six months ended June 30, 2014 and 2013, the Company capitalized $2,923,549 and $1,218,954, respectively, of internal salaries, which included $1,396,362, and $310,264, respectively, of stock-based compensation. Internal salaries are capitalized based on employee time allocated to the acquisition of leaseholds and development of oil and natural gas properties. The Company capitalized no interest in the three and six months ended June 30, 2014 and 2013.

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. No gain or loss was recognized on any sales during the three and six months ended June 30, 2014 and 2013. 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 unproved property on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and amortization. For the six months ended June 30, 2014 and the year ended December 31, 2013, the Company included $2,440,918 and $3,020,485, respectively, related to expiring leases within costs subject to the depletion calculation.

Capitalized costs associated with impaired properties and properties having proved reserves, estimated future development costs, and asset retirement costs under 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 developed, impaired, or abandoned.

Under the full cost method of accounting, capitalized oil and natural gas property costs less accumulated depletion, net of deferred income taxes, may not exceed a ceiling amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are subject to amortization. Should capitalized costs exceed this ceiling, which is tested on a quarterly basis, an impairment is recognized. The present value of estimated future net revenues is computed by applying prices based on a 12-month unweighted 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 six months ended June 30, 2014 or 2013.

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 expense as incurred.

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 proved reserves were not adequate to cover the current imbalance situation. As of June 30, 2014 and December 31, 2013, the Company’s natural gas production was in balance, i.e., its cumulative portion of natural gas production taken and sold from wells in which it has an interest equaled the Company’s entitled interest in natural gas production from those wells.

Stock-Based Compensation

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

On May 27, 2011, the stockholders 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 and July 10, 2013, the stockholders of the Company approved an amendment to the 2011 Plan to increase the number of shares available for issuance under the 2011 Plan to 3,500,000 shares and 9,800,000 shares, respectively. 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 June 30, 2014, 1,471,597 stock options and 4,204,000 shares of common stock and restricted stock units had been issued to officers, directors and employees under the 2011 Plan net of cancelations and forfeitures, including 1,611,792 nonvested restricted stock units. As of June 30, 2014, there were 4,124,403 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 consolidated balance sheet.

Net Income (Loss) Per Common Share

Basic net income (loss) per common share is based on the net income (loss) divided by the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average number of common shares plus dilutive common share equivalents outstanding during the period using the treasury stock method. In the computation of diluted earnings per share, excess tax benefits that would be created upon the assumed vesting of nonvested 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 six months ended June 30, 2014 and 2013, the potentially dilutive shares were anti-dilutive and were thus not included in the net loss per share calculation.

 As of June 30, 2014, (i) 1,611,792 nonvested restricted stock units were issued and outstanding and represented potentially dilutive shares; (ii) 482,360 stock options were issued and exercisable and represented potentially dilutive shares; (iii) 999,942 stock options were granted but were not exercisable and represented potentially dilutive shares; (iv) 5,114,633 warrants were issued and exercisable at an exercise price of $5.77 and represented dilutive shares; (v) 223,293 warrants were issued and exercisable at an exercise price of $6.86 and represented potentially dilutive shares; (vi) 892,858 warrants were issued and exercisable at an exercise price of $49.70 and represented potentially dilutive shares; and (vii) $172.5 million of convertible senior notes convertible into approximately 19,658,120 common shares as of June 30, 2014 and represented potentially dilutive shares.

Derivative and Other Financial Instruments

Commodity Derivative Instruments

The Company has entered into commodity derivative instruments, utilizing oil derivative swap contracts 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. Net gains and losses are recorded based on the changes in the fair values of the derivative instruments. 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 12 – 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 (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 a securities purchase agreement entered into in February 2013 with affiliates of White Deer Energy L.P. (see Note 5 – 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 the consolidated statements of operations.

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 consolidated financial statements upon adoption.

Use of Estimates

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

Industry Segment and Geographic Information

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

Reclassifications

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) (USD $)	Jun. 30, 2014	Dec. 31, 2013
LIABILITIES AND STOCKHOLDERS' EQUITY
Preferred Stock - Par Value (in Dollars per Share)	$ 0.001	$ 0.001
Preferred Stock - Shares Authorized (in Shares)	20,000,000	20,000,000
Preferred Stock - Shares Issued (in Shares)	5,114,633	5,114,633
Preferred stock - shares outstanding (in Shares)	5,114,633	5,114,633
Preferred Stock - Liquidation Preference Value	$ 5,115	$ 5,115
STOCKHOLDERS' EQUITY
Common Stock, Par Value (in Dollars per Share)	$ 0.001	$ 0.001
Common Stock, Shares Authorized (in Shares)	500,000,000	500,000,000
Common Stock, Shares Issued (in Shares)	66,471,276	65,840,370
Common Stock, Shares Outstanding (in Shares)	66,471,276	65,840,370

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DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT

6 Months Ended

Jun. 30, 2014

Derivative Instruments and Price Risk Management [Abstract]

DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT

NOTE 12 DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT

Commodity

The Company utilizes oil 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.

The Company has a master netting agreement on each of the individual oil contracts. Therefore, the current asset and liability are netted on the 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 June 30, 2014, the associated volumes and the corresponding weighted average NYMEX reference price:

Settlement Period	Oil (Bbls)		Fixed Price  Range
Oil Swaps
July 1, 2014 – December 31, 2014		61,330	$	90.00 – 93.00
July 1, 2014 – December 31, 2014		47,300		93.01 – 96.00
July 1, 2014 – December 31, 2014		503,970		96.01 – 99.00
July 1, 2014 – December 31, 2014		82,612		99.01 – 102.00
2014 Total/Average		695,212	$	96.70
January 1, 2015 – April 30, 2015		18,876	$	90.00 – 93.00
January 1, 2015 – April 30, 2015		93,100		93.01 – 96.00
January 1, 2015 – April 30, 2015		341,251		96.01 – 99.00
2015 Total/Average		453,227	$	96.24

The following table sets forth a reconciliation of the changes in fair value of the Company’s commodity derivatives for the three and six months ended June 30, 2014 and 2013.

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Beginning fair value of commodity derivatives	$	(1,098,474	)	$	(799,610	)	$	(853,005	)	$	(181,248	)
Total gains (losses) on commodity derivatives		(6,663,083	)		665,337			(7,461,936	)		(102,267	)
Cash settlements paid on commodity derivatives		1,908,756			183,539			2,462,140			332,781
Ending fair value of commodity derivatives	$	(5,852,801	)	$	49,266		$	(5,852,801	)	$	49,266

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 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 5 – 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 June 30, 2014, using the following assumptions: a term of 1,381 trading days, exercise price of $5.77, a 15-day volume weighted average stock price of $7.22, volatility rate of 40%, and a risk-free interest rate of 2.5%. As of June 30, 2014, the fair value of the warrants was $17,670,000, 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.

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Document and Entity Information	6 Months Ended
	Jun. 30, 2014	Aug. 04, 2014
Document and Entity Information [Abstract]
Entity Registrant Name	Emerald Oil, Inc.
Entity Central Index Key	0001283843
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Document Type	10-Q
Document Period End Date	Jun. 30, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock Shares Outstanding		66,477,468
Entity Well Known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filer	No

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COMMITMENTS AND CONTINGENCIES

6 Months Ended

Jun. 30, 2014

Commitments and Contingencies [Abstract]

COMMITMENTS AND CONTINGENCIES

NOTE 13 COMMITMENTS AND CONTINGENCIES

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

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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
REVENUES
Oil Sales	$ 30,288,128	$ 10,340,742	$ 48,722,936	$ 18,334,644
Natural Gas Sales	966,280	234,076	1,600,344	457,155
Net Gains (Losses) on Commodity Derivatives	(6,663,083)	665,337	(7,461,936)	(102,267)
Total Revenues	24,591,325	11,240,155	42,861,344	18,689,532
OPERATING EXPENSES
Production Expenses	3,897,482	1,596,353	6,514,726	2,635,885
Production Taxes	3,400,874	1,048,541	5,489,610	1,750,397
General and Administrative Expenses	7,633,559	5,979,739	16,125,563	11,368,552
Depletion of Oil and Natural Gas Properties	8,600,878	3,584,803	14,878,110	6,741,781
Depreciation and Amortization	81,497	31,039	147,257	54,034
Accretion of Discount on Asset Retirement Obligations	20,080	7,850	35,800	14,062
Total Operating Expenses	23,634,370	12,248,325	43,191,066	22,564,711
INCOME (LOSS) FROM OPERATIONS	956,955	(1,008,170)	(329,722)	(3,875,179)
OTHER INCOME (EXPENSE)
Interest Expense	(1,136,377)	(75,186)	(1,308,463)	(254,676)
Warrant Revaluation Expense	(1,771,000)	(642,000)	(1,967,000)	(4,081,000)
Other Income	371	2,222	4,047	2,898
Total Other Expense, Net	(2,907,006)	(714,964)	(3,271,416)	(4,332,778)
LOSS BEFORE INCOME TAXES	(1,950,051)	(1,723,134)	(3,601,138)	(8,207,957)
INCOME TAX PROVISION
NET LOSS	(1,950,051)	(1,723,134)	(3,601,138)	(8,207,957)
Less: Preferred Stock Dividends and Deemed Dividends		(5,665,670)		(6,282,108)
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$ (1,950,051)	$ (7,388,804)	$ (3,601,138)	$ (14,490,065)
Net Income (Loss) Per Common Share - Basic and Diluted (in Dollars per Share)	$ (0.03)	$ (0.23)	$ (0.05)	$ (0.50)
Weighted Average Shares Outstanding - Basic and Diluted (in Shares)	66,323,228	32,602,115	66,251,632	29,166,411

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REVOLVING CREDIT FACILITY

6 Months Ended

Jun. 30, 2014

Revolving Credit Facility [Abstract]

REVOLVING CREDIT FACILITY

NOTE 7 REVOLVING CREDIT FACILITY

On November 20, 2012, the Company entered into a senior secured revolving credit facility (the “Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent (“Wells Fargo”), and the lenders party thereto. On May 1, 2014, the Company amended the Credit Facility with Wells Fargo as administrative agent for the lenders party to the Credit Facility. The Credit Facility is a senior secured reserve-based revolving credit facility with a maximum commitment of $400 million. As of June 30, 2014, the Credit Facility was undrawn and had a borrowing base of $100.0 million.

Amounts borrowed under the Credit Facility will mature on September 30, 2018, and upon such date, any amounts outstanding under the Credit Facility are due and payable in full. 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 the Company’s option, based on either the Alternate Base Rate (as defined under the terms of the Credit Facility) 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 rate 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 June 30, 2014, the annual interest rate on the Credit Facility was 0.375% which is the minimum commitment fee, as no funds were drawn against the Credit Facility.

A portion of the Credit 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 June 30, 2014, the Company has not obtained any letters of credit under the existing facility.

Each of the Company’s subsidiaries is a guarantor under the Credit Facility. The Credit 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 Facility 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 Facility 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 total debt to EBITDA for the preceding four fiscal quarters of no more than 3.50 to 1.00. For any fiscal quarter ending in calendar year 2014, total debt is reduced by cash equivalents less $10,000,000 for purposes of calculating the total debt to EBITDA ratio. The Company was in compliance with all covenants as of June 30, 2014.

The Credit Facility allows the Company to hedge up to 60% of proved reserves for the first 24 months and 80% of projected production from proved developed producing reserves from 24 months up to 60 months later provided that in no event shall the aggregate amount of hedges exceed 100% of actual production in the current period.

The principal balance amount on the Credit Agreement was undrawn as of June 30, 2014 and December 31, 2013.

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STOCK OPTIONS AND WARRANTS

6 Months Ended

Jun. 30, 2014

Stock Options and Warrants [Abstract]

STOCK OPTIONS AND WARRANTS

NOTE 6  STOCK OPTIONS AND WARRANTS

Stock Options

On January 10, 2014, the Company granted stock options to certain employees to purchase a total of 295,800 shares of common stock exercisable at $7.48 per share. The options vest on an annual basis over 36 months with 98,600 options vesting on January 10, 2015, 2016 and 2017.

On April 1, 2014, the Company granted stock options to certain employees to purchase a total of 255,499 shares of common stock exercisable at $6.69 per share. The options vest on an annual basis over 36 months with 85,166 options vesting on April 1, 2015, 2016 and 2017.

The total fair value of stock options granted during the three and six months ended June 30, 2014 was calculated using the Black-Scholes valuation model based on factors present at the time the options were granted. The following assumptions were used for the Black-Scholes model to value the options granted during the six-month period ended June 30, 2014.

Risk free rates	0.77% to 1.32%
Dividend yield	0%
Expected volatility	62.08% to 67.70%
Weighted average expected life	3.5 years

The impact on the Company’s statement of operations of stock-based compensation expense related to options granted for the three months ended June 30, 2014 and 2013 was $237,236 and $181,384, 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 six-month periods ended June 30, 2014 and 2013 was $472,609 and $576,072, respectively, net of $0 tax. The Company capitalized $187,357, and $159,563 in compensation to oil and natural gas properties related to outstanding options for the three months ended June 30, 2014 and 2013, respectively, and $408,611 and $221,161 for the six months ended June 30, 2014 and 2013, respectively. The Company had $1,819,202 of total unrecognized compensation cost related to nonvested stock options granted as of June 30, 2014. The remaining cost is expected to be recognized over a weighted-average period of 1.44 years. These estimates are subject to change based on a variety of future events which include, but are not limited to, changes in estimated forfeiture rates, cancellations and the issuance of new options.

A summary of the stock options activity during the six months ended June 30, 2014 is as follows:

	Number of  Options			Weighted  Average  Exercise Price
Balance outstanding at January 1, 2014		1,158,860		$	8.90
Granted		551,299			7.11
Canceled		(202,857	)		7.77
Exercised		(25,000	)		4.43
Balance outstanding at June 30, 2014		1,482,302		$	7.33
Options exercisable at June 30, 2014		482,360		$	10.91

At June 30, 2014, 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
2014		529,499		4.64	$	7.11		—		—	$	—
2013		417,101		5.78		7.14		116,301		4.71		6.78
2012		407,142		2.78		7.66		237,499		2.57		7.53
Prior		128,560		1.64		20.90		128,560		1.64		20.90
Total		1,482,302		4.19	$	7.33		482,360		2.84	$	10.91

Warrants

The table below reflects the status of warrants outstanding at June 30, 2014:

	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		892,858	$	49.70	February 8, 2016
February 19, 2013		5,114,633	$	5.77	December 31, 2019
Total		6,230,784

No warrants expired or were forfeited during the six months ended June 30, 2014. 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 June 30, 2014. See Note 12 – Derivative Instruments and Price Risk Management for details on the treatment of the warrants issued on February 19, 2013.

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ASSET RETIREMENT OBLIGATION (Tables)

6 Months Ended

Jun. 30, 2014

Asset Retirement Obligation [Abstract]

Schedule of Change in Asset Retirement Obligation

The following table summarizes the Company’s asset retirement obligation transactions recorded in accordance with the provisions of ASC 410-20-25 for the six months ended June 30, 2014 and the year ended December 31, 2013:

	Six Months Ended  June 30, 2014		Year Ended  December 31, 2013
Beginning Asset Retirement Obligation	$	692,137	$	296,074
Revision of Previous Estimates		—		165,968
Liabilities Incurred or Acquired		515,199		510,271
Accretion of Discount on Asset Retirement Obligations		35,800		32,449
Liabilities Associated with Properties Sold		—		(312,625	)
Ending Asset Retirement Obligation	$	1,243,136	$	692,137

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SUBSEQUENT EVENTS

6 Months Ended

Jun. 30, 2014

Subsequent Events [Abstract]

SUBSEQUENT EVENTS

NOTE 14 SUBSEQUENT EVENTS

Acquisition and Divestiture

On August 1, 2014 the Company entered into a material definitive agreement to acquire approximately 31,500 net acres located in McKenzie, Billings and Dunn Counties of North Dakota from an unrelated third party. The total consideration expected to be paid by the Company is approximately $78.4 million in cash and the assignment of 4,175 net acres located in Williams County, North Dakota. Net daily production from the acquired acreage was approximately 400 Boe/day as of May 1, 2014, the effective date of the transaction. The Company did not have any production associated with the 4,175 net acres to be assigned as a part of the purchase price consideration. The agreement is subject to customary closing conditions and adjustments, including allocating all costs and revenue prior to and after the effective date. The transaction is expected to close in the third quarter of 2014.

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INCOME TAXES

6 Months Ended

Jun. 30, 2014

Income Taxes [Abstract]

INCOME TAXES

NOTE 10  INCOME TAXES

Deferred income tax assets and liabilities are determined based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. 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 June 30, 2014 and December 31, 2013, the Company maintained 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.

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CONVERTIBLE NOTES

6 Months Ended

Jun. 30, 2014

Convertible Notes [Abstract]

CONVERTIBLE NOTES

NOTE 8 CONVERTIBLE NOTES

On March 24, 2014, the Company completed a private placement of $172.5 million in aggregate principal amount of 2.0% Convertible Notes (the “Convertible Notes”), and entered into an indenture (the “Indenture”) governing the Convertible Notes, with U.S. Bank National Association, as trustee (the “Trustee”). The Convertible Notes accrue interest at a rate of 2.00% per year, payable semiannually in arrears on April 1 and October 1 of each year, beginning on October 1, 2014. The Convertible Notes mature on April 1, 2019. The Convertible Notes are the Company’s unsecured senior obligations and are equal in right of payment to the Company’s existing and future senior indebtedness. The Convertible Notes were convertible as of June 30, 2014. However, the Company does not believe conversion will take place as the market price of the Convertible Notes is currently above the estimated conversion value, and in the event of conversion, holders would forgo all future interest payments and the possibility of further stock price appreciation. As a result, the Convertible Notes have been classified as long-term debt as of June 30, 2014.

The net proceeds from the Convertible Notes were $166.9 million, after deducting commissions and the offering expenses payable by the Company. The Company’s transaction costs in conjunction with the transaction will be amortized to interest expense over the five-year term of the Convertible Notes.

The Convertible Notes and the common stock issuable upon conversion of the Convertible Notes have not been registered under the Securities Act of 1933, as amended (the “Securities Act”), or the securities laws of any other jurisdiction, and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements. The Convertible Notes were offered and sold to the initial purchasers in a private placement exempt from the registration requirements of the Securities Act pursuant to Section 4(a)(2). The Convertible Notes were resold by the initial purchasers to qualified institutional buyers in reliance on Rule 144A under the Securities Act.

Holders may convert their Convertible Notes at their option at any time prior to the close of business on the business day immediately preceding the maturity date of the Convertible Notes. The conversion rate for the Convertible Notes is initially 113.9601 shares of the Company’s common stock per $1,000 principal amount of Convertible Notes (which represents an initial conversion price of approximately $8.78 per share of the Company’s common stock), subject to certain anti-dilution adjustments as provided in the Indenture. A holder that surrenders its Convertible Notes for conversion in connection with a Make-Whole Fundamental Change (as defined in the Indenture) that occurs before the maturity date may in certain circumstances be entitled to an increased conversion rate. If the Company undergoes a Fundamental Change (as defined in the Indenture), subject to certain conditions, the holder of the Convertible Notes will have the option to require the Company to repurchase all or any portion of its Convertible Notes for cash. The fundamental change purchase price will be 100% of the principal amount of the Convertible Notes to be purchased, plus any accrued and unpaid interest, including additional interest, if any, to, but excluding, the fundamental change purchase date. The Company may not redeem the Convertible Notes prior to their maturity, and no sinking fund is provided for the Convertible Notes.

The Company does not intend to file a shelf registration statement for resale of the Convertible Notes or the shares of its common stock issuable upon conversion of the Convertible Notes. The Company will, however, be required to pay additional interest in respect of the Convertible Notes under specified circumstances. As a result, holders may only resell the Convertible Notes or shares of the Company’s common stock issued upon conversion of the Convertible Notes, if any, pursuant to an exemption from the registration requirements of the Securities Act and other applicable securities laws.

The Indenture contains customary terms and covenants and events of default. If an Event of Default (as defined in the Indenture) occurs and is continuing, the Trustee or the holders of at least 25% in aggregate principal amount of the then outstanding Convertible Notes may declare by written notice all the Convertible Notes to be immediately due and payable in full. The Company was in compliance with all covenants as of June 30, 2014.

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ASSET RETIREMENT OBLIGATION

6 Months Ended

Jun. 30, 2014

Asset Retirement Obligation [Abstract]

ASSET RETIREMENT OBLIGATION

NOTE 9  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 periods presented); and (iv) a credit-adjusted risk-free interest rate (average of 7.0% for each of the periods presented). 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 six months ended June 30, 2014 and the year ended December 31, 2013:

	Six Months Ended  June 30, 2014		Year Ended  December 31, 2013
Beginning Asset Retirement Obligation	$	692,137	$	296,074
Revision of Previous Estimates		—		165,968
Liabilities Incurred or Acquired		515,199		510,271
Accretion of Discount on Asset Retirement Obligations		35,800		32,449
Liabilities Associated with Properties Sold		—		(312,625	)
Ending Asset Retirement Obligation	$	1,243,136	$	692,137

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FAIR VALUE

6 Months Ended

Jun. 30, 2014

Fair Value [Abstract]

FAIR VALUE

NOTE 11 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 Vice President of Accounting and approved by the Chief Financial Officer. The valuation policies 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 June 30, 2014:

	Fair Value Measurements at  June 30, 2014 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	$	—	$	—		$	(17,670,000	)
Commodity Derivatives – Current Liability (oil swaps)		—		(5,852,801	)		—
Total	$	—	$	(5,852,801	)	$	(17,670,000	)

The following schedule summarizes the valuation of financial instruments measured at fair value on a recurring basis in the condensed consolidated balance sheet as of December 31, 2013:

	Fair Value Measurements at  December 31, 2013 Using
	Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other  Observable Inputs  (Level 2)			Significant Unobservable  Inputs  (Level 3)
Warrant Liability – Long Term Liability	$	—	$	—		$	(15,703,000	)
Commodity Derivatives – Current Liability (oil swaps)		—		(921,401	)		—
Commodity Derivatives – Long Term Asset (oil swaps)		—		68,396			—
Total	$	—	$	(853,005	)	$	(15,703,000	)

Level 2 assets consist of commodity derivative assets and liabilities (see Note 12 – 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 warrant liability measured at fair value using Level 3 on a recurring basis is as follows (in thousands):

Balance, at January 1, 2013	$	—
Purchases, issuances, and settlements		(8,626,000	)
Change in Fair Value of Warrant Liability		(7,077,000	)
Balance, at December 31, 2013		(15,703,000	)
Change in Fair Value of Warrant Liability		(1,967,000	)
Balance, at June 30, 2014	$	(17,670,000	)

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 $1,771,000 and $642,000 for the three months ended June 30, 2014 and 2013, respectively, and $1,967,000 and $4,081,000 for the six months ended June 30, 2014 and 2013, respectively. The warrant revaluation expense 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 12 – Derivative Instruments and Price Risk Management.

Nonrecurring Fair Value Measurements

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

The asset retirement obligation estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3. A reconciliation of the beginning and ending balances of the Company’s asset retirement obligation is presented in Note 9 – Asset Retirement Obligation.

The Company’s non-derivative financial instruments include cash and cash equivalents, accounts receivable, accounts payable, the Convertible Notes and the Credit Facility. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximate fair value because of their immediate or short-term maturities. The book value of the Credit Facility approximates fair value because of its floating rate structure. The Company estimated the fair value of the Convertible Notes to be approximately $190.5 million at June 30, 2014 based on observed prices for the same or similar types of debt instruments. The Company has classified the valuations of the Convertible Notes and Credit Facility under Level 2 of the fair value hierarchy.

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STOCK OPTIONS AND WARRANTS (Schedule of Stock Options Outstanding) (Details) (USD $)	6 Months Ended
	Jun. 30, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of options outstanding (in Shares)	1,482,302	1,158,860
Stock options outstanding, weighted average remaining contract life (years) (in Duration)	4 years 2 months 9 days
Stock options outstanding weighted average exercise price (in Dollars per Share)	$ 7.33	$ 8.90
Number of options exercisable (in Shares)	482,360
Stock options exercisable, weighted average remaining contract life (years) (in Duration)	2 years 10 months 2 days
Stock options exercisable, weighted average exercise price (in Dollars per Share)	$ 10.91
Year of Grant 2014 [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of options outstanding (in Shares)	529,499
Stock options outstanding, weighted average remaining contract life (years) (in Duration)	4 years 7 months 21 days
Stock options outstanding weighted average exercise price (in Dollars per Share)	$ 7.11
Number of options exercisable (in Shares)
Stock options exercisable, weighted average remaining contract life (years) (in Duration)
Stock options exercisable, weighted average exercise price (in Dollars per Share)
Year of Grant 2013 [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of options outstanding (in Shares)	417,101
Stock options outstanding, weighted average remaining contract life (years) (in Duration)	5 years 9 months 11 days
Stock options outstanding weighted average exercise price (in Dollars per Share)	$ 7.14
Number of options exercisable (in Shares)	116,301
Stock options exercisable, weighted average remaining contract life (years) (in Duration)	4 years 8 months 16 days
Stock options exercisable, weighted average exercise price (in Dollars per Share)	$ 6.78
Year of Grant 2012 [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of options outstanding (in Shares)	407,142
Stock options outstanding, weighted average remaining contract life (years) (in Duration)	2 years 9 months 11 days
Stock options outstanding weighted average exercise price (in Dollars per Share)	$ 7.66
Number of options exercisable (in Shares)	237,499
Stock options exercisable, weighted average remaining contract life (years) (in Duration)	2 years 6 months 26 days
Stock options exercisable, weighted average exercise price (in Dollars per Share)	$ 7.53
Year of Grant Prior to 2012 [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of options outstanding (in Shares)	128,560
Stock options outstanding, weighted average remaining contract life (years) (in Duration)	1 year 7 months 21 days
Stock options outstanding weighted average exercise price (in Dollars per Share)	$ 20.90
Number of options exercisable (in Shares)	128,560
Stock options exercisable, weighted average remaining contract life (years) (in Duration)	1 year 7 months 21 days
Stock options exercisable, weighted average exercise price (in Dollars per Share)	$ 20.90

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PREFERRED AND COMMON STOCK (Tables)

6 Months Ended

Jun. 30, 2014

Preferred and Common Stock [Abstract]

Schedule of Components of Preferred Stock Transaction

A summary of the preferred stock transaction components as of June 30, 2014 and December 31, 2013 is provided below:

	June 30, 2014		December 31, 2013
Series A Preferred Stock	$	—	$	—
Series B Preferred Stock		5,000		5,000
Warrant Liability		17,670,000		15,703,000
Total	$	17,675,000	$	15,708,000

Schedule of Restricted Stock Units and Restricted Stock Shares Outstanding

A summary of the restricted stock units and restricted stock shares activity during the six months ended June 30, 2014 is as follows:

	Number of Shares			Weighted  Average Grant  Date Fair Value
Non-vested restricted stock and restricted stock units at January 1, 2014		2,082,187		$	5.73
Granted		264,134			7.48
Canceled		—			—
Vested and forfeited for taxes		(293,813	)		5.85
Vested and issued		(440,716	)		5.85
Non-vested restricted stock and restricted stock units at June 30, 2014		1,611,792		$	5.96

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BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES (Narrative) (Details) (USD $)	0 Months Ended	3 Months Ended		6 Months Ended		12 Months Ended
	Feb. 21, 2014	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013	Jul. 12, 2013	Feb. 19, 2013	Oct. 22, 2012	May 27, 2011
Basis of Presentation and Significant Accounting Policies [Abstract]
Cash FDIC insured amount		$ 250,000		$ 250,000
Restricted cash and cash equivalents, current and non-current		10,000,000	21,000,000	10,000,000	21,000,000
Restricted cash held in escrow to meet post-closing requirements on the sale of oil and gas properties			11,000,000		11,000,000
Restricted cash related to drilling commitment on oil and gas leases acquired		10,000,000	10,000,000	10,000,000	10,000,000
Restricted cash released to the Company	8,600,000
Restricted cash released to buyer for purchase price adjustments	2,400,000
Internal Salaries Capitalized		1,538,567	903,162	2,923,549	1,218,954
Stock-based Compensation included in internal salaries capitalized		735,393	210,712	1,396,362	310,264
Capitalized interest		0	0	0	0
Gain on sale of oil and natural gas properties		0	0	0	0
Amount related to expiring leases included in the costs subject to depletion calculation			0	2,440,918		3,020,485
Impairment losses recognized on non oil and gas long lived assets		0	0	0	0	0
Number of uncertain tax positions (in Integer)		0		0		0
Uncertain tax liabilities recorded in balance sheet		0		0		0
Number of reportable segments				1
Number of long lived assets located outside the United States (in Integer)		0		0
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation, equity incentive plan, common stock reserved (in Shares)							9,800,000		3,500,000
Stock-based compensation, equity incentive plan, shares authorized for issuance (in Shares)										714,286
Number of options outstanding (in Shares)		1,482,302		1,482,302		1,158,860
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Weighted-average exercise price of warrants outstanding (in Dollars per Unit)								5.77
Stock Options Presently Exercisable [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share (in Shares)				482,360
Stock Options Not Presently Exercisable [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share (in Shares)				999,942
Restricted Stock Units [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share (in Shares)				1,611,792
Warrants - Group 1 [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share (in Shares)				5,114,633
Weighted-average exercise price of warrants outstanding (in Dollars per Unit)		5.77		5.77
Warrants - Group 2 [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share (in Shares)				223,293
Weighted-average exercise price of warrants outstanding (in Dollars per Unit)		6.86		6.86
Warrants - Group 3 [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share (in Shares)				892,858
Weighted-average exercise price of warrants outstanding (in Dollars per Unit)		49.70		49.70
Convertible Notes [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share (in Shares)				19,658,120
Value of notes convertible into common shares		$ 172,500,000		$ 172,500,000
Restricted Stock Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation, equity incentive plan, unvested shares (in Shares)		1,611,792		1,611,792
2011 Equity Incentive Plan (the "2011 Plan") [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation, equity incentive plan, shares available for issuance (in Shares)		4,124,403		4,124,403
2011 Equity Incentive Plan (the "2011 Plan") [Member] | Stock Option [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of options outstanding (in Shares)		1,471,597		1,471,597
2011 Equity Incentive Plan (the "2011 Plan") [Member] | Common Stock and Restricted Stock Units [Memeber]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Nonoption units outstanding (in Shares)		4,204,000		4,204,000
2011 Equity Incentive Plan (the "2011 Plan") [Member] | Restricted Stock Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation, equity incentive plan, unvested shares (in Shares)		1,611,792		1,611,792

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FAIR VALUE (Narrative) (Details) (USD $)	0 Months Ended	3 Months Ended		6 Months Ended		12 Months Ended
	Feb. 19, 2013	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013
Fair Value [Abstract]
Fair value of warrants issued to White Deer Energy	$ 8,626,000					$ (8,626,000)
Warrant Revaluation Expense		1,771,000	642,000	1,967,000	4,081,000
Fair value of convertible notes		$ 190,500,000		$ 190,500,000

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (USD $)	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$ (3,601,138)	$ (8,207,957)
Adjustments to Reconcile Net Loss to Net Cash Provided By Operating Activities:
Depletion of Oil and Natural Gas Properties	14,878,110	6,741,781
Depreciation and Amortization	147,257	54,034
Amortization of Debt Issuance Costs	377,463	44,573
Accretion of Discount on Asset Retirement Obligations	35,800	14,062
Net Losses on Commodity Derivatives	7,461,936	102,267
Net Cash Settlements Paid on Commodity Derivatives	(2,462,140)	(332,781)
Warrant Revaluation Expense	1,967,000	4,081,000
Share-Based Compensation Expense	6,678,883	2,365,797
Changes in Assets and Liabilities:
Increase in Trade Receivables - Oil and Natural Gas Revenues	(636,959)	(755,866)
Increase in Accounts Receivable - Joint Interest Partners	(4,873,541)	(4,976,709)
Increase in Other Receivables	(1,022,732)	(246,392)
Increase in Prepaid Expenses and Other Current Assets	(328,131)	(214,497)
Decrease in Other Non-Current Assets	130,437	85,675
Increase in Accounts Payable	1,888,872	1,069,554
Increase (Decrease) in Accrued Expenses	(2,474,083)	1,557,119
Increase in Other Non-Current Liabilities	209,333
Increases in Advances from Joint Interest Partners	1,518,372	834,639
Net Cash Provided By Operating Activities	19,894,739	2,216,299
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of Other Property and Equipment	(754,492)	(201,657)
Restricted Cash Released	11,000,512
Payments of Restricted Cash	(2,648,721)
Increase in Deposits for Acquisitions	(178,967)	(1,050,000)
Use of Prepaid Drilling Costs		98,565
Proceeds from Sale of Oil and Natural Gas Properties, Net of Transaction Costs	238,069	15,160,206
Investment in Oil and Natural Gas Properties	(204,113,902)	(54,689,661)
Net Cash Used For Investing Activities	(196,457,501)	(40,682,547)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Issuance of Common Stock, Net of Transaction Costs		95,973,701
Proceeds from Issuance of Preferred Stock, Net of Transaction Costs		47,183,994
Proceeds from Issuance of Convertible Senior Notes, Net of Transaction Costs	166,893,211
Advances on Revolving Credit Facility	35,000,000
Payments on Preferred Stock		(15,000,000)
Payments on Revolving Credit Facility	(35,000,000)	(23,500,000)
Preferred Stock Dividends and Deemed Dividends		(3,692,808)
Proceeds from Exercises of Stock Options and Warrants	110,750
Cash Paid for Debt Issuance Costs	(500,365)
Cash Paid for Finance Costs	(24,605)
Net Cash Provided by Financing Activities	166,478,991	100,964,887
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(10,083,771)	62,498,639
CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD	144,255,438	10,192,379
CASH AND CASH EQUIVALENTS - END OF PERIOD	134,171,667	72,691,018
Supplemental Disclosure of Cash Flow Information
Cash Paid During the Period for Interest	84,933	255,776
Cash Paid During the Period for Income Taxes
Non-Cash Financing and Investing Activities:
Oil and Natural Gas Properties Included in Account Payable	86,500,675	37,344,286
Stock-Based Compensation Capitalized to Oil and Natural Gas Properties	1,396,362	310,264
Accretion on Preferred Stock Issuance Discount		2,589,300
Asset Retirement Obligation Costs and Liabilities	515,199	122,013
Common Stock Issued for Oil and Natural Gas Properties		$ 6,736,935

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PREFERRED AND COMMON STOCK

6 Months Ended

Jun. 30, 2014

Preferred and Common Stock [Abstract]

PREFERRED AND COMMON STOCK

NOTE 5  PREFERRED AND COMMON STOCK

Preferred Stock

On February 19, 2013, the Company issued to White Deer Energy 500,000 shares of Series A Preferred Stock, 5,114,633 shares of Series B Preferred Stock and warrants to purchase an initial aggregate 5,114,633 shares of the Company’s common stock at an initial exercise price of $5.77 per share, in exchange for an aggregate $50 million. The warrants are exercisable until December 31, 2019.

On various dates throughout 2013, the Company redeemed all of the outstanding shares of Series A Preferred Stock, including principal of $50,000,000 and redemption premiums of $6,250,000, and no shares of Series A Preferred Stock remain outstanding as of June 30, 2014. For each redemption, the redemption premium was 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. The Company paid no dividends during the three and six months ended June 30, 2014. For the three and six months ended June 30, 2013, the Company paid dividends on the Series A Preferred Stock of $1,201,370 and $1,817,808, respectively.

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

The warrants entitle 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. See Note 12 – 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, White Deer Energy had 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 Preferred Stock, Series B Preferred Stock and the warrants, as well as shares of common stock issued upon exercise of the warrant that were then held by White Deer Energy, an additional cash payment necessary to achieve a minimum internal rate of return of 25%. Upon the final redemption of the shares Series A Preferred Stock on October 15, 2013, the Company and White Deer Energy agreed the minimum internal rate of return had been achieved and no additional cash payment to White Deer Energy would be necessary upon a change of control or liquidation event.

The Company recorded the private placement 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 accreted the Series A Preferred Stock to the liquidation or redemption value when it became probable that the event or events underlying the liquidation or redemption of the Series A Preferred Stock were probable. The Company recognized all issuance discount accretion related to the partial redemptions of preferred stock on June 20, 2013, August 30, 2013 and October 15, 2013. There was no issuance discount remaining as of June 30, 2014.

A summary of the preferred stock transaction components as of June 30, 2014 and December 31, 2013 is provided below:

	June 30, 2014		December 31, 2013
Series A Preferred Stock	$	—	$	—
Series B Preferred Stock		5,000		5,000
Warrant Liability		17,670,000		15,703,000
Total	$	17,675,000	$	15,708,000

Restricted Stock Awards and Restricted Stock Unit Awards

The Company incurred compensation expense associated with restricted stock and restricted stock units granted of $2,746,344 and $876,427 for the three months ended June 30, 2014 and 2013, respectively, and $6,206,274 and $1,789,725 for the six months ended June 30, 2014 and 2013, respectively. As of June 30, 2014, there were 1,611,792 non-vested restricted stock units and $5,962,785 associated remaining unrecognized compensation expense, which is expected to be recognized over the weighted-average period of 0.80 years. The Company capitalized compensation expense associated with the restricted stock and restricted stock units of $548,036 and $51,148 to oil and natural gas properties for the three months ended June 30, 2014 and 2013, respectively, and $987,751 and $89,102 for the six months ended June 30, 2014 and 2013, respectively.

A summary of the restricted stock units and restricted stock shares activity during the six months ended June 30, 2014 is as follows:

	Number of Shares			Weighted  Average Grant  Date Fair Value
Non-vested restricted stock and restricted stock units at January 1, 2014		2,082,187		$	5.73
Granted		264,134			7.48
Canceled		—			—
Vested and forfeited for taxes		(293,813	)		5.85
Vested and issued		(440,716	)		5.85
Non-vested restricted stock and restricted stock units at June 30, 2014		1,611,792		$	5.96

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OIL AND NATURAL GAS PROPERTIES (Narrative) (Details) (USD $)	1 Months Ended
	Feb. 28, 2014 Boe
Williams and McKenzie Counties [Member]
Oil and Gas in Process Activities [Line Items]
Number of acres acquired (in Acres)	19,500
Purchase price of acquired oil and natural gas property leases	$ 69,200,000
Net daily production of acquired acreage (in Boe/d)	300
McKenzie and Billings Counties [Member]
Oil and Gas in Process Activities [Line Items]
Number of acres acquired (in Acres)	5,900
Purchase price of acquired oil and natural gas property leases	$ 10,300,000

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ASSET RETIREMENT OBLIGATION (Narrative) (Details) (USD $)	6 Months Ended
	Jun. 30, 2014
Asset Retirement Obligation [Abstract]
Significant input to assumption, asset retirement obligation valuation, future inflation factor (in Percent)	2.50%
Significant input to assumption, asset retirement obligation valuation, interest rate credit-adjusted risk-free (in Percent)	7.00%
Assets legally restricted for purposes of settling asset retirement obligtions

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BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES (Policies)

6 Months Ended

Jun. 30, 2014

Basis of Presentation and Significant Accounting Policies [Abstract]

Cash and Cash Equivalents, Policy

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.

Restricted Cash

Restricted Cash

Restricted cash included in current and long-term assets on the condensed consolidated balance sheets totaled $10 million and $21 million at June 30, 2014 and December 31, 2013, respectively.  At June 30, 2014, the $10 million balance related to a drilling commitment agreement entered into pursuant to oil and natural gas leases. As of December 31, 2013, there was an additional $11.0 million of restricted cash related to a portion of proceeds from a leasehold sale held in escrow until finalization of standard due diligence procedures. On February 21, 2014, $8.6 million was released to the Company, with the remaining $2.4 million returned to the buyer for purchase price adjustments.

Accounts Receivable

Accounts Receivable

The Company records estimated oil and natural gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. Management periodically reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables under the specific identification method. The Company did not record any allowance for uncollectible receivables during the three and six months ended June 30, 2014 and 2013.

Full Cost Method, Policy

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 months ended June 30, 2014 and 2013, the Company capitalized $1,538,567 and $903,162, respectively, of internal salaries, which included $735,393, and $210,712, respectively, of stock-based compensation. For the six months ended June 30, 2014 and 2013, the Company capitalized $2,923,549 and $1,218,954, respectively, of internal salaries, which included $1,396,362, and $310,264, respectively, of stock-based compensation. Internal salaries are capitalized based on employee time allocated to the acquisition of leaseholds and development of oil and natural gas properties. The Company capitalized no interest in the three and six months ended June 30, 2014 and 2013.

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. No gain or loss was recognized on any sales during the three and six months ended June 30, 2014 and 2013. 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 unproved property on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and amortization. For the six months ended June 30, 2014 and the year ended December 31, 2013, the Company included $2,440,918 and $3,020,485, respectively, related to expiring leases within costs subject to the depletion calculation.

Capitalized costs associated with impaired properties and properties having proved reserves, estimated future development costs, and asset retirement costs under 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 developed, impaired, or abandoned.

Under the full cost method of accounting, capitalized oil and natural gas property costs less accumulated depletion, net of deferred income taxes, may not exceed a ceiling amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are subject to amortization. Should capitalized costs exceed this ceiling, which is tested on a quarterly basis, an impairment is recognized. The present value of estimated future net revenues is computed by applying prices based on a 12-month unweighted 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 six months ended June 30, 2014 or 2013.

Other Property and Equipment, Policy

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 expense as incurred.

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, Policy

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, Policy

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 proved reserves were not adequate to cover the current imbalance situation. As of June 30, 2014 and December 31, 2013, the Company’s natural gas production was in balance, i.e., its cumulative portion of natural gas production taken and sold from wells in which it has an interest equaled the Company’s entitled interest in natural gas production from those wells.

Stock-Based Compensation, Policy

Stock-Based Compensation

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

On May 27, 2011, the stockholders 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 and July 10, 2013, the stockholders of the Company approved an amendment to the 2011 Plan to increase the number of shares available for issuance under the 2011 Plan to 3,500,000 shares and 9,800,000 shares, respectively. 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 June 30, 2014, 1,471,597 stock options and 4,204,000 shares of common stock and restricted stock units had been issued to officers, directors and employees under the 2011 Plan net of cancelations and forfeitures, including 1,611,792 nonvested restricted stock units. As of June 30, 2014, there were 4,124,403 shares available for issuance under the 2011 Plan.

Income Taxes, Policy

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 consolidated balance sheet.

Net Income (Loss) Per Common Share, Policy

Net Income (Loss) Per Common Share

Basic net income (loss) per common share is based on the net income (loss) divided by the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average number of common shares plus dilutive common share equivalents outstanding during the period using the treasury stock method. In the computation of diluted earnings per share, excess tax benefits that would be created upon the assumed vesting of nonvested 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 six months ended June 30, 2014 and 2013, the potentially dilutive shares were anti-dilutive and were thus not included in the net loss per share calculation.

 As of June 30, 2014, (i) 1,611,792 nonvested restricted stock units were issued and outstanding and represented potentially dilutive shares; (ii) 482,360 stock options were issued and exercisable and represented potentially dilutive shares; (iii) 999,942 stock options were granted but were not exercisable and represented potentially dilutive shares; (iv) 5,114,633 warrants were issued and exercisable at an exercise price of $5.77 and represented dilutive shares; (v) 223,293 warrants were issued and exercisable at an exercise price of $6.86 and represented potentially dilutive shares; (vi) 892,858 warrants were issued and exercisable at an exercise price of $49.70 and represented potentially dilutive shares; and (vii) $172.5 million of convertible senior notes convertible into approximately 19,658,120 common shares as of June 30, 2014 and represented potentially dilutive shares.

Derivative and Other Financial Instruments, Policy

Derivative and Other Financial Instruments

Commodity Derivative Instruments

The Company has entered into commodity derivative instruments, utilizing oil derivative swap contracts 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. Net gains and losses are recorded based on the changes in the fair values of the derivative instruments. 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 12 – 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 (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 a securities purchase agreement entered into in February 2013 with affiliates of White Deer Energy L.P. (see Note 5 – 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 the consolidated statements of operations.

New Accounting Pronouncements, Policy

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 consolidated financial statements upon adoption.

Use of Estimates, Policy

Use of Estimates

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

Industry Segment and Geographic Information, Policy

Industry Segment and Geographic Information

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

Reclassifications, Policy

Reclassifications

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